CNX GAS CORPORATION 110-K
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934.
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For the fiscal year ended
December 31, 2007;
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OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to
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Commission file number:
001-32723
CNX GAS CORPORATION
(Exact name of registrant as
specified in its charter)
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Delaware
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20-3170639
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(State or Other Jurisdiction
of
Incorporation or Organization)
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(I.R.S. Employer
Identification No.)
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5 Penn Center West, Suite 401
Pittsburgh, PA
15276-0102
(412) 200-6700
(Address, including zip code,
and telephone number,
including area code, of
registrants principal executive offices)
Securities registered pursuant to Section 12(b) of the
Act:
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Stock ($.01 par value)
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New York Stock Exchange
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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 þ No o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
(Section 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrants
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this
Form 10-K
or any amendment to this
Form 10-K. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in Rule
12b-2 of the Exchange Act. (Check One):
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Large accelerated
filer þ
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Accelerated
filer o
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Non-accelerated
filer o
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Smaller reporting
company o
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(Do not check if a smaller reporting company)
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Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2)
of the
Act). Yes o No þ
The aggregate market value of voting stock held by nonaffiliates
of the registrant as of June 30, 2007, based on the closing
price of the common stock on the New York Stock Exchange on such
date ($30.60 per share), was $853,531,828. For purposes of
determining this amount, affiliates include directors and
executive officers, who, as of June 30, 2007, in the
aggregate held 85,062 shares (including shares held in
401(k) plans, shares held by trusts with respect to which the
director or executive officer was trustee, and shares held
jointly with a spouse, but not including shares underlying
vested options or vested restricted stock units), and CONSOL
Energy Inc., which held 122,896,667 shares.
The number of shares outstanding of the registrants common
stock as of January 31, 2008 is 150,916,698 shares.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of CNX Gas Corporations Proxy Statement for the
Annual Meeting of Stockholders to be held on April 21,
2008, are incorporated by reference in Items 10, 11, 12, 13
and 14 of Part III
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:
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our business strategy;
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our financial position, cash flow and liquidity;
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declines in the prices we receive for our gas affecting our
operating results and cash flow;
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uncertainties in estimating our gas reserves and replacing our
gas reserves;
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uncertainties in exploring for and producing gas;
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our inability to obtain additional financing necessary in order
to fund our operations, capital expenditures and to meet our
other obligations;
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disruptions to, capacity constraints in or other limitations on
the pipeline systems which deliver our gas;
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the availability of personnel and equipment, including our
inability to retain and attract key personnel;
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increased costs;
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the effects of government regulation and permitting and other
legal requirements;
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legal uncertainties regarding the ownership of the coalbed
methane estate, and costs associated with perfecting title for
gas rights in some of our properties;
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litigation concerning real property rights, intellectual
property rights, royalty calculations and other matters;
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our relationships and arrangements with CONSOL Energy; and
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other factors discussed under Risk Factors.
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PART I
Except as otherwise noted or unless the context otherwise
requires, (i) the information in this Annual Report on
Form 10-K
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 Energys gas business, and
(iv) reserve and operating data are as of December 31,
2007 unless otherwise indicated. The estimates of our proved
reserves as of December 31, 2007, 2006, and 2005 included
in this Annual Report are based on reserve reports prepared by
Schlumberger Data and Consulting Services. The estimates of our
proved reserves as of December 31, 2004 and 2003 (set forth
in Item 6, Selected Financial Data Other
Financial Data) are based on reserve reports prepared by
Ralph E. Davis Associates, Inc. and Schlumberger Data and
Consulting Services. Unless otherwise noted, we discuss
production, per unit revenue and per unit costs net of any
royalty owners interest. With respect to production and
reserves, we use the word net to indicate when a
number does not include the royalty owners interest. With
respect to acres, we use the word net to describe
our aggregate fractional interest in property that we control by
deed or lease. With the exception of earnings per share data, we
discuss dollars in thousands throughout this
Form 10-K.
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, 2007,
2006 and 2005 is included in Note 18 to the Consolidated
Financial Statements included as Item 8 in Part II of
this Annual Report on
Form 10-K.
General
We are engaged in the exploration, development, production and
gathering of natural gas primarily in the Appalachian and
Illinois Basins. In particular, we are a leading developer of
coalbed methane (CBM) and are beginning to assess multiple shale
plays in emerging areas. CONSOL Energy Inc. (CONSOL Energy) owns
81.7% of our outstanding common stock. In August 2005, we
acquired all of CONSOL Energys 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, 2007, we had 1.343 Tcfe of net proved
reserves, including our portion of equity affiliates, with a
PV-10 value
of $2,287,427 and a standardized measure of discounted after tax
future net cash flows attributable to our proved reserves of
$1,389,540. Our proved reserves are approximately 99% CBM and
50% proved developed. We are one of the largest gas producers in
the Appalachian Basin with net sales of 58.2 Bcf for the
twelve months ended December 31, 2007. Our proved reserves
are long-lived with a reserve life index of 23.1 years.
History
of CNX Gas
We began extracting CBM in the early 1980s from coal seams in
Virginia 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 Energys mining operations.
Typically, the gas was vented to the atmosphere. 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.
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.
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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.
CNX Gas Corporation (CNX Gas) was formed on June 30, 2005.
CONSOL Energy contributed its gas assets to CNX Gas effective
August 8, 2005.
Our common stock commenced trading on the New York Stock
Exchange (NYSE) under the symbol CXG on
January 19, 2006.
On January 29, 2008, CONSOL Energy announced an intention
to commence an exchange offer to acquire the 18.3% of
outstanding shares of CNX Gas that CONSOL Energy does not
currently own.
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 NYSE under the symbol
CNX. Those companies include: CNX Gas Company, LLC;
Cardinal States Gathering Company (CSGC); a 50.0%
interest in Coalfield Pipeline Company; a working interest in
Knox Energy, LLC; a 50.0% interest in Buchanan Generation, LLC;
and various other joint ventures. These are the companies
primarily responsible for the exploration, production, gathering
and sale of our gas, with the exception of Buchanan Generation,
LLC, which uses our gas to generate electricity from a
generating facility located near our Virginia gas field. CONSOL
Energy owned 81.7% of the outstanding common stock of CNX Gas as
of December 31, 2007.
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 Energys ownership or rights to CBM, natural gas,
oil, and certain related surface rights. 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 under
which CONSOL Energy 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 Energys 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 Energys mines.
These additional sources of gas enhance our overall recovery
rates for CBM.
Coordination
with Mining Activities
Approximately 27% of our current gas production is produced in
connection with coal extraction by CONSOL Energy. It is
essential that gas liberated by the mining process be 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, we prepare an annual drilling program 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 development and exploration
drilling and the number of wells proposed to be drilled in the
following calendar year, and (ii) the approximate location
of all production, treatment and gathering related systems
proposed to be installed by CNX Gas.
Gas
Operations
We primarily 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
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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 for CNX
Gas than those incurred by producers that operate in deeper,
less defined formations; however, we intend to increase our
exploration efforts in the shale and deeper formations.
Areas
of Operation
In the Appalachian Basin we operate principally in Central
Appalachia and Northern Appalachia, which represent our two
reportable segments. We also operate in the Illinois Basin. The
five areas we see playing prominent roles in our portfolio in
the near future are as follows:
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first, in Central Appalachia, Virginia Operations CBM, our
traditional and largest area of operation, where we have
typically produced CBM from vertical wells which we drill ahead
of mining and gob gas wells;
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second, in Northern Appalachia, the Mountaineer CBM play in
northwestern West Virginia and southwestern Pennsylvania where
our first major drilling program using vertical-to-horizontal
well designs is into full scale development;
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third, in Northern Appalachia, the Nittany CBM play in central
Pennsylvania where we have substantial holdings and transitioned
initial exploratory testing activities into full scale
development;
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fourth, in the Illinois Basin, Cardinal, the New Albany shale
play in western Kentucky, Indiana and Illinois which has
economic potential where we are in the midst of exploratory
testing activities; and
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last, in addition to the above areas, we believe we have
Appalachian shale potential in the Marcellus, Huron, and
Chattanooga shales. Additional potential exists in the Trenton
Black River formation which is thought to underlie nearly all of
the Appalachian shales. We will continue to evaluate our acreage
position in these areas, with the commencement of an exploration
program in 2008.
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Central
Appalachia
Virginia
Operations CBM
We have the right to extract CBM in this region from
approximately 368,000 net CBM acres, which cover a portion
of coal reserves owned or controlled by CONSOL Energy in Central
Appalachia. We acquired CONSOL Energys rights associated
with CBM in this region upon inception. 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 is typically
between 400 and 600 cubic feet of gas per ton of coal in place.
In addition, there 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 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. In 2007, frac wells account for approximately 73.0%
of our daily Virginia 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
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opportunity to gain insight into the efficiency 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 that are 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
formed 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 coal seams that cannot be mined, 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 26% of our
Virginia gas production comes in the form of gob gas.
We also drill 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 desorption of CBM from the coal seam. As of
December 31, 2007, we have drilled 15 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, we believe production at offsetting frac
wells has actually increased due to the further reductions 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 accounted for approximately 1% of Virginia
production in 2007, while it is estimated to account for
approximately 1.5% of future daily production.
Virginia
Operations Shale and Tight Sands
We have 193,000 net acres of Huron shale potential in
Kentucky and Virginia; a portion of this acreage has tight sands
potential. Our 2008 exploration program includes projected
expenditures for testing the Huron shale.
Tennessee
Through a joint venture known as Knox Energy, LLC, in which we
have a working interest, we control oil and gas rights
(including the Chattanooga shale) and CBM rights on
approximately 102,000 net leasehold acres in Anderson,
Campbell, Morgan, Scott, and Roane Counties, Tennessee. Knox
Energy farmed out limited drilling rights on this acreage to a
third party through January 31, 2008; we are currently
negotiating an extension through December 31, 2012. Under
the extension being negotiated, Knox Energy retains the right to
participate up to a 50% working interest in wells drilled by the
third party. Knox Energy also retains the right to propose and
drill horizontal wells in the Chattanooga shale formation,
subject to the third partys right to participate at a 25%
working interest. As of December 31, 2007, we have
34.875 net wells that we are operating, while we also
participate in another 22.125 net wells operated by a third
party. In total, we have an inventory of approximately 2,900
drilling locations on this acreage, none of which are proved
undeveloped locations. At December 31, 2007, we had
3.6 Bcfe of proved reserves in this area. Our overall
Chattanooga shale acreage position is 132,000 net acres.
Our 2008 exploration program includes projected expenditures for
testing the Chattanooga shale.
We also control other property in east Kentucky and Tennessee
that represents approximately 225,000 net CBM acres.
Northern
Appalachia
Mountaineer
CBM
We have the right to extract CBM in this region from
approximately 684,000 net CBM acres, which contain most of
the recoverable coal reserves owned or controlled by CONSOL
Energy in Northern Appalachia. We have acquired all of CONSOL
Energys rights associated with CBM in this region. We
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produce gas primarily from the Pittsburgh #8 coal seam.
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 typically between 100 and
250 cubic feet of gas per ton of coal in place. There are
additional coal seams above and below the Pittsburgh #8
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.
Due to the significant geological differences between the
Pittsburgh #8 seam in Mountaineer and the
Pocahontas #3 seam in Virginia, we have found that
alternative extraction techniques are more effective than
vertical frac wells in this area. Instead of using frac wells,
we utilize well designs that rely on the application of
vertical-to-horizontal drilling techniques. This well design
includes a vertical wellbore that is intersected by a second
well that has up to four horizontal lateral sections in the
coal. Together, this well system facilitates extraction of CBM
and water from the coal seam. The horizontal wellbores,
extending up to 5,000 feet from the point of intersection
with the vertical wellbore, expose large amounts of coal surface
area allowing for the migration of water and CBM from the coal
seam. This design creates up to 12,000 feet of total
productive wellbore. The wells are spaced in sections up to a
square mile. 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 associated with CONSOL
Energys mines.
In 2007, we drilled 62 vertical-to-horizontal CBM wells in
Mountaineer. We expect to achieve peak production rates of
nearly 4 Mcf/d per 100 feet of lateral exposure in the
development of the Pittsburgh #8 seam area of this play. As
of December 31, 2007, wells that have been de-watered are
meeting this expectation.
Nittany
CBM
We have the right to extract CBM in this region of Pennsylvania
from approximately 248,000 net CBM acres. We have acquired
all of CONSOL Energys rights associated with CBM in this
region. In 2007, we drilled 14 wells and connected
10 wells, which are currently producing CBM. Our 2008
program includes expenditures for 100 development wells.
Marcellus
Shale
We have 161,000 net acres of Marcellus shale potential in
Ohio, Pennsylvania, West Virginia, and New York. Our 2008
exploration program includes projected expenditures for testing
the Marcellus shale.
Shallow
Oil
We have approximately 61,200 acres with shallow oil
potential in Ohio that we are currently assessing.
Others
Cardinal
Shale
As of December 31, 2007, we controlled approximately
300,000 net acres of rights to gas in the New Albany
shale in Kentucky, Illinois, and Indiana. The New Albany shale
is a formation containing gaseous hydrocarbons and our acreage
position has thickness of
50-300 feet
at an average depth of 2,500-4,000 feet. As of
December 31, 2007, we have identified test well locations
and we have spudded several exploratory wells. We are using a
standard drilling rig to drill up to 4,000 vertical feet. We
also have identified the potential for shallow oil and CBM in
this area and will continue to evaluate.
Illinois
Basin CBM
We also control 573,000 net CBM acres, including 92,000
net CBM acres which contain most of the recoverable coal
reserves owned or controlled by CONSOL Energy in Illinois.
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Other
Acreage
We have the right to extract CBM on 139,000 net acres in
the San Juan Basin, 38,000 net acres in the Powder
River Basin, 41,000 net acres in eastern Ohio, and
51,000 net acres in central West Virginia. We also have the
right to extract Oil and Gas on 43,000 net acres in the
San Juan Basin, 9,000 net acres in the Powder River
Basin, and 53,000 net acres in various other areas.
Summary
of Properties as of December 31, 2007
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Central
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Northern
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Appalachia
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Appalachia
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Other
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Total
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Estimated Net Proved Reserves (Bcfe)
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1,242.4
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87.3
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13.8
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1,343.5
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Percent Developed
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48.8
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%
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58.1
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%
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100
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%
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50.0
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%
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Net Producing Wells
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2,650
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195
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144
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2,989
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Net Proved Developed CBM Acres
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134,968
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52,760
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187,728
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Net Proved Undeveloped CBM Acres
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33,370
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35,980
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69,350
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Net Unproved CBM Acres(1)
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425,431
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934,822
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749,902
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2,110,155
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Total Net CBM Acres
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593,769
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|
|
1,023,562
|
|
|
|
749,902
|
|
|
|
2,367,233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Proved Developed Oil & Gas Acres
|
|
|
6,104
|
|
|
|
|
|
|
|
34,737
|
|
|
|
40,841
|
|
Net Proved Undeveloped Oil & Gas Acres
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Unproved Oil & Gas Acres(1)
|
|
|
314,959
|
|
|
|
177,255
|
|
|
|
358,414
|
|
|
|
850,628
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Net Oil & Gas Acres
|
|
|
321,063
|
|
|
|
177,255
|
|
|
|
393,151
|
|
|
|
891,469
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes areas leased to others or participation interests in
third party wells as well as small acreage in other areas. |
Drilling
During the twelve months ended December 31, 2007, 2006 and
2005, we drilled 370, 272, and 184 net development wells,
respectively, all of which were productive. Gob wells and wells
drilled by other operators that we participate in are excluded.
As of December 31, 2007, we had no dry development wells,
and 32 wells are still in process. The following table
illustrates the wells referenced above by geographic region:
Development
Wells (Net)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Twelve Months Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
Wells
|
|
|
Wells
|
|
|
Wells
|
|
|
Central Appalachia
|
|
|
294
|
|
|
|
253
|
|
|
|
176
|
|
Northern Appalachia
|
|
|
76
|
|
|
|
19
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
370
|
|
|
|
272
|
|
|
|
184
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
During the twelve months ended December 31, 2007, 2006 and
2005, we drilled in the aggregate 9, 4, and 15 net
exploratory wells, respectively. The following table illustrates
the exploratory wells by geographic region:
Exploratory
Wells (Net)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
Producing
|
|
|
Dry
|
|
|
Still Eval.
|
|
|
Producing
|
|
|
Dry
|
|
|
Still Eval.
|
|
|
Producing
|
|
|
Dry
|
|
|
Still Eval.
|
|
|
Central Appalachia
|
|
|
3
|
|
|
|
0
|
|
|
|
0
|
|
|
|
2
|
|
|
|
0
|
|
|
|
0
|
|
|
|
2
|
|
|
|
0
|
|
|
|
0
|
|
Northern Appalachia
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
2
|
|
|
|
13
|
|
|
|
0
|
|
|
|
0
|
|
Other
|
|
|
1
|
|
|
|
0
|
|
|
|
5
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
4
|
|
|
|
0
|
|
|
|
5
|
|
|
|
2
|
|
|
|
0
|
|
|
|
2
|
|
|
|
15
|
|
|
|
0
|
|
|
|
0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Summary
of Other Operating Data
Production
The following table sets forth net sales volume produced for the
periods indicated, including our portion of equity affiliates.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Twelve Months
|
|
|
Ended December 31,
|
|
|
2007
|
|
2006
|
|
2005
|
|
Total Produced (Mmcf)
|
|
|
58,249
|
|
|
|
56,135
|
|
|
|
48,390
|
|
Average
Sales Prices and Lifting Costs
The following table sets forth the average sales price,
including 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Twelve Months
|
|
|
Ended December 31,
|
|
|
2007
|
|
2006
|
|
2005
|
|
Average Gas Sales Price Including Effects of Financial
Settlements (per Mcf)
|
|
$
|
7.20
|
|
|
$
|
7.04
|
|
|
$
|
5.90
|
|
Average Lifting Cost (per Mcf)
|
|
$
|
0.68
|
|
|
$
|
0.60
|
|
|
$
|
0.64
|
|
Productive
Wells and Acreage
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. The following table
sets forth, at December 31, 2007, the number of CNX Gas
producing wells, developed acreage and undeveloped acreage:
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
Net(1)
|
|
|
Producing Wells
|
|
|
3,800
|
|
|
|
2,989
|
|
Proved Developed Acreage
|
|
|
230,545
|
|
|
|
228,569
|
|
Proved Undeveloped Acreage
|
|
|
71,434
|
|
|
|
69,350
|
|
Unproven Acreage
|
|
|
3,505,970
|
|
|
|
2,960,783
|
|
|
|
|
|
|
|
|
|
|
Total Acreage
|
|
|
3,807,949
|
|
|
|
3,258,702
|
|
|
|
|
|
|
|
|
|
|
10
|
|
|
(1) |
|
Net acres do not include acreage attributable to the working
interests of our principal joint venture partners and the
portions of certain proved developed acreage attributable to
property we have leased to third-party producers. Additional
adjustments (either increases or decreases) may be required as
we further develop title to and further confirm our rights with
respect to our various properties in anticipation of
development. We believe that our assumptions and methodology in
this regard are reasonable. |
Sales
CNX Gas enters into physical gas sales transactions with various
counterparties for terms varying in length. Reserves and
production estimates are believed to be sufficient to satisfy
these obligations. In the past, other than interstate 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 and represented
approximately 18.4 Bcf of our produced gas sales volumes
for the twelve months ended December 31, 2007 at an average
price of $8.01 per Mcf. As of December 31, 2007, we expect
these transactions will cover approximately 24.5 Bcf of our
estimated 2008 production at an average price of $8.30 per Mcf.
CNX Gas has purchased firm transportation capacity on various
interstate pipelines to ensure gas production flows to market.
As of December 31, 2007, CNX Gas has secured firm
transportation capacity to cover more than its 2008 hedged
production.
The hedging strategy and information regarding derivative
instruments used are outlined in Managements
Discussion and Analysis of Results of Operations and Financial
Condition Qualitative and Quantitative Disclosures
About Market Risk, and in Note 16 to the Consolidated
Financial Statements.
Reserves
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,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
Consolidated
|
|
|
|
|
|
Consolidated
|
|
|
|
|
|
Consolidated
|
|
|
|
|
|
|
Operations
|
|
|
Affiliates
|
|
|
Operations
|
|
|
Affiliates
|
|
|
Operations
|
|
|
Affiliates
|
|
|
Estimated proved developed reserves
|
|
|
667,726
|
|
|
|
3,584
|
|
|
|
609,700
|
|
|
|
2,200
|
|
|
|
549,574
|
|
|
|
2,672
|
|
Estimated proved undeveloped reserves
|
|
|
672,183
|
|
|
|
|
|
|
|
653,593
|
|
|
|
|
|
|
|
578,150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total estimated proved developed and undeveloped reserves
|
|
|
1,339,909
|
|
|
|
3,584
|
|
|
|
1,263,293
|
|
|
|
2,200
|
|
|
|
1,127,724
|
|
|
|
2,672
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11
Discounted
Future Net Cash Flows
The following table shows our estimated future net cash flows
and total standardized measure of discounted future net cash
flows at 10%:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discounted Future Net Cash Flows
|
|
|
|
As of December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands)
|
|
|
Future net cash flows (net of tax)
|
|
$
|
3,609,195
|
|
|
$
|
2,483,887
|
|
|
$
|
5,149,938
|
|
Total PV-10
measure of pre tax discounted future net cash flows(1)
|
|
$
|
2,287,427
|
|
|
$
|
1,499,664
|
|
|
$
|
3,051,866
|
|
Total standardized measure of after tax discounted future net
cash flows
|
|
$
|
1,389,540
|
|
|
$
|
934,891
|
|
|
$
|
1,870,794
|
|
|
|
|
(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 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,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands)
|
|
|
Future cash inflows
|
|
$
|
9,509,665
|
|
|
$
|
7,105,265
|
|
|
$
|
11,675,551
|
|
Future Production Costs
|
|
|
(3,004,619
|
)
|
|
|
(2,568,731
|
)
|
|
|
(2,852,033
|
)
|
Future Development Costs (including abandonments)
|
|
|
(636,436
|
)
|
|
|
(552,114
|
)
|
|
|
(422,315
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows (pre-tax)
|
|
|
5,868,610
|
|
|
|
3,984,420
|
|
|
|
8,401,203
|
|
10% discount factor
|
|
|
(3,581,183
|
)
|
|
|
(2,484,756
|
)
|
|
|
(5,349,337
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PV-10
(Non-GAAP measure)
|
|
|
2,287,427
|
|
|
|
1,499,664
|
|
|
|
3,051,866
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Undiscounted Income Taxes
|
|
|
(2,259,415
|
)
|
|
|
(1,500,533
|
)
|
|
|
(3,251,265
|
)
|
10% discount factor
|
|
|
1,361,528
|
|
|
|
935,760
|
|
|
|
2,070,193
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discounted Income Taxes
|
|
|
(897,887
|
)
|
|
|
(564,773
|
)
|
|
|
(1,181,072
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized GAAP measure
|
|
$
|
1,389,540
|
|
|
$
|
934,891
|
|
|
$
|
1,870,794
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Competition
We operate primarily 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 operating cost and the
proximity of gas fields to customers.
Employee
and Labor Relations
As of December 31, 2007, CNX Gas had 281 employees.
None of our employees is represented by a union.
12
Available
Information
We file annual reports on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K,
and proxy statements and other documents with the Securities and
Exchange Commission (SEC) pursuant to the Securities Exchange
Act of 1934. All documents that we file with the SEC are
available for reading and copying in the SECs public
reference room located at 100 F Street, N.E.,
Washington, D.C. 20549. Please contact the SEC at
1-800-SEC-0330
for further information regarding the operations of the public
reference room. These SEC filings are also available over the
Internet at the SECs website, www.sec.gov.
We make copies of these documents available on our own Internet
website, www.cnxgas.com, as soon as reasonably possible
after we have furnished such information to the SEC. Information
contained on or connected to our website which is not directly
incorporated by reference into this
Form 10-K
should not be considered part of this report or any other filing
that we make with the SEC.
In addition, charters for the committees of our Board of
Directors and our Code of Ethics and Business Conduct, one for
directors and the other for employees, can be found on our
Internet website under the heading Corporate
Governance. Stockholders may request copies of these
documents by writing to the Investor Relations Department at 5
Penn Center West, Suite 401, Pittsburgh, Pennsylvania
15276-0102.
Our Code of Employee Business Conduct and Ethics applies to CNX
Gas Chief Executive Officer (Principal Executive Officer),
Chief Financial Officer (Principal Financial Officer), principal
accounting officer or controller and persons performing similar
functions. If CNX Gas makes any amendments to the code other
than technical, administrative, or other non-substantive
amendments, or grants any waivers, including implicit waivers,
from a provision of the code applicable to its principal
executive officer, principal financial officer, principal
accounting officer or controller or persons performing similar
functions, CNX Gas will disclose the nature of the amendment or
waiver, its effective date and to whom it applies on its website
or in a report on
Form 8-K
filed with the Securities and Exchange Commission.
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 atmosphere and the environment, and the effects of gas
well operations on groundwater quality and availability.
Additional regulations, including regulations applicable to mine
safety, may also be applicable to gas operations producing
coalbed methane in relation to active mining. 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.
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.
13
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 2007, 2006 and 2005. 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 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 and regulations 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 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 liabilities: 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.
14
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. 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. 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.
Regulations and orders set forth by the Federal Energy
Regulatory Commission also impact the business of CNX to a
certain degree. Although the Federal Energy Regulatory
Commission does not directly regulate CNX Gas production
activities, the Federal Energy Regulatory Commission has stated
that it intends for certain of its orders to foster increased
competition within all phases of the natural gas industry.
Additionally, the Federal Energy Regulatory Commission continues
to review its transportation regulations, including 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. Additional Federal Energy Regulatory
Commission orders were adopted based on this review with the
goal of increasing competition for natural gas markets and
transportation.
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. In addition, the Federal Energy Regulatory
Commissions 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 we
believe meet the traditional tests which the Federal Energy
Regulatory Commission has used to establish a pipelines
status as a gatherer not subject to the Federal Energy
Regulatory Commission jurisdiction.
Additional proposals and proceedings that might affect the gas
industry may be 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, the disposal of fluids used in
connection with operations, and gas operations producing coalbed
methane in relation to active mining. 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, 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, and generally prohibit the venting or
flaring of gas and impose certain requirements regarding the
ratability of
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production. A number of states have either enacted new laws or
may be 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.
However, 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 Energys coal holdings. Our
existing rights are often dependent on CONSOL Energy having
obtained valid title to its properties.
CONSOL Energys past practice has been to acquire ownership
or leasehold rights to its coal properties prior to conducting
its coal mining operations. Given CONSOL Energys 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 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
traditional 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 proved
reserves are 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.
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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 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, 2007, 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.
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 Virginias 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 for and
develop Northern Appalachian CBM in 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 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 Energys rights to CBM, we expect in accordance with
our existing procedures to have a title examination performed of
CONSOL Energys rights to CBM. If we believe we need to
obtain additional rights from the holders of other real estate
interests, we have developed 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 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. The ownership of CBM in these other states may
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.
17
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, Tennessee, east
Kentucky 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.
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.
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Gross acres or gross wells. The total acres or
wells, as the case may be, in which a working interest is owned.
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 Pennsylvania, northern West
Virginia, and southern New York.
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.
Pipeline imbalance (imbalance). We 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.
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 SECs 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.
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.
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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.
Tcfe. Trillion cubic feet equivalent,
determined using the ratio of six Mcf of natural gas to one bbl
of crude oil, condensate or natural gas liquids.
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 Executive Officers of CNX Gas Corporation
(included herein pursuant to Item 401(b) of
Regulation S-K).
In addition to the trends and uncertainties described in
Item I of this Annual Report and in Managements
Discussion and Analysis of Financial Condition and Results of
Operations, CNX Gas is subject to the trends and
uncertainties set forth below.
General
Risk Factors
Natural
gas prices are volatile, and a decline in natural gas 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. 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 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. If we
choose not to engage in, or reduce our use of hedging
arrangements in the future, we may be more adversely affected by
changes in natural gas and oil prices than our competitors who
engage in hedging arrangements to a greater extent than we do.
Prices for natural gas may fluctuate widely in response to
relatively minor changes in the supply of and demand for natural
gas, market uncertainty and a variety of additional factors that
are beyond our control, such as:
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the domestic and foreign supply of natural gas;
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the price of foreign imports;
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overall domestic and global economic conditions;
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the consumption pattern of industrial consumers, electricity
generators and residential users;
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weather conditions;
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technological advances affecting energy consumption;
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domestic and foreign governmental regulations;
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proximity and capacity of gas pipelines and other transportation
facilities; and
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the price and availability of alternative fuels.
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Many of these factors may be beyond our control. Earlier in this
decade, natural gas prices were lower than they are today. Lower
natural gas prices may not only decrease our revenues on a per
unit basis, but may also limit our access to capital. A
significant decrease in price levels for an extended period
would negatively affect us in several ways including:
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our cash flow would be reduced, decreasing funds available for
capital expenditures employed to replace reserves or increase
production; and
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access to other sources of capital, such as equity or long-term
debt markets, could be severely limited or unavailable.
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Additionally, lower natural gas prices 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 natural gas properties. 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 carrying amount may not be recoverable or whenever
managements 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 proved 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 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:
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geological conditions;
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changes in governmental regulations and taxation;
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assumptions governing future prices;
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the amount and timing of actual production;
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future operating costs; and
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capital costs of drilling new wells.
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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, 2007 would decrease from
$2,287,427 to $2,239,746. The standardized GAAP measure
associated with this decline of $0.10 per Mcf, would be
approximately $1,359,939.
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, 2007, 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:
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unexpected drilling conditions;
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title problems;
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pressure or irregularities in geologic formations;
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equipment failures or repairs;
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fires or other accidents;
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adverse weather conditions;
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reductions in natural gas prices;
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pipeline ruptures; and
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unavailability or high cost of drilling rigs, other field
services and equipment.
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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.
We
have a limited operating history in certain of our operating
areas, and our increased focus on new development projects in
these and other unexplored areas increases the risks inherent in
our gas and oil activities.
In 2008 and beyond we plan to conduct testing and development
activities in areas where we have little or no proved reserves,
such as certain areas in Pennsylvania and Kentucky. These
exploration, drilling and production activities will be subject
to many risks, including the risk that CBM or natural gas is not
present in sufficient quantities in the coal seam or target
strata, or that sufficient permeability does not exist for the
gas to be produced economically. We have invested in property,
and will continue to invest in property, including undeveloped
leasehold acreage, that we believe will result in projects that
will add value over time. Drilling
22
for CBM, natural gas and oil may involve unprofitable efforts,
not only from dry wells but also from wells that are productive
but do not produce sufficient net reserves to return a profit
after deducting drilling, operating and other costs. We cannot
be certain that the wells we drill in these new areas will be
productive or that we will recover all or any portion of our
investments.
Our
business depends on transportation facilities owned by others.
Disruption of, capacity constraints in, or proximity to pipeline
systems could limit sales of 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, 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. If our sales are reduced because of
transportation constraints, our revenues will be reduced, which
will also increase our unit costs. If we cannot obtain
transportation capacity and we do not have the ability to store
gas, we may have to reduce production. If pipeline quality
tariffs change, we might be required to install additional
processing equipment which could increase our costs. The
pipeline could curtail our flows until the gas delivered to
their pipeline is in compliance.
Increased
industry activity may create shortages of field services,
equipment and personnel, which may increase our costs and may
limit our ability to drill and produce from our natural gas
properties
Due to current industry demands, well service providers and
related equipment are in short supply. The demand for qualified
and experienced field personnel to drill wells and conduct field
operations, including geologists, geophysicists, engineers and
other professionals in the natural gas and oil industry can
fluctuate significantly, often in correlation with natural gas
and oil prices, causing periodic shortages. These shortages may
lead to escalating prices, the possibility of poor services,
inefficient drilling operations, and personnel injuries. Such
pressures will likely increase the actual cost of services,
extend the time to secure such services and add costs for
damages due to accidents sustained from the over use of
equipment and inexperienced personnel. Higher oil and natural
gas prices generally stimulate increased demand and result in
increased prices for drilling equipment, crews and associated
supplies, equipment and services. We believe that these
shortages could continue. In addition, the costs and delivery
times of equipment and supplies are substantially greater in
periods of peak demand. Accordingly, we cannot assure that we
will be able to obtain necessary drilling equipment and supplies
in a timely manner or on satisfactory terms, and we may
experience shortages of, or material increases in the cost of,
drilling equipment, crews and associated supplies, equipment and
services in the future. Any such delays and price increases
could adversely affect our ability to pursue our drilling
program and our results of operations.
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.
23
Acquisitions
are subject to the risks and uncertainties of evaluating
reserves and potential liabilities and may be disruptive and
difficult to integrate into our business
From time to time we consider various acquisition opportunities.
We could be subject to significant liabilities related to any
completed acquisition. Generally, it is not feasible to review
in detail every individual property included in an acquisition.
Ordinarily, a review is focused on higher valued properties.
However, even a detailed review of all properties and records
may not reveal existing or potential problems in all of the
properties, nor will it permit us to become sufficiently
familiar with the properties to assess fully their deficiencies
and capabilities prior to acquisition. We will not always
inspect every well we acquire, and environmental problems, such
as groundwater contamination, are not necessarily observable
even when an inspection is performed.
In addition, there is intense competition for acquisition
opportunities in our industry. Competition for acquisitions may
increase the cost of, or cause us to refrain from, completing
acquisitions. Our acquisition strategy is dependent upon, among
other things, our ability to obtain debt and equity financing
and, in some cases, regulatory approvals. Our ability to pursue
our acquisition strategy may be hindered if we are not able to
obtain financing on terms acceptable to us or regulatory
approvals.
Acquisitions often pose integration risks and difficulties. In
connection with future acquisitions, the process of integrating
acquired operations into our existing operations may result in
unforeseen operating difficulties and may require significant
management attention and financial resources that would
otherwise be available for the ongoing development or expansion
of existing operations. Future acquisitions could result in our
incurring additional debt, contingent liabilities, expenses and
diversion of resources, all of which could have a material
adverse effect on our financial condition and operating results.
The
coal shale and other strata from which we produce gas frequently
contain water and the gas often contains impurities, both of
which may hamper our ability to produce gas in commercial
quantities or economically.
Coal shale and other strata frequently contain water that must
be removed in order for the gas to detach from the coal and flow
to the wellbore. 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. Further, a
substantial amount of our gas needs to be processed in order to
make it salable to our intended customers. At times, the cost of
processing this gas relative to the quantity of gas from a
particular well, or group of wells, may outweigh the economic
benefit of selling that gas, and our profitability may decrease
due to the reduced production and sale of gas.
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, Chief
Executive Officer and President, 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.
24
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
including New River Energy, LLC with respect to Knox Energy
(exploration and production) (as described above, we have a
working interest in the properties controlled by Knox Energy
which are further subject to a farm-out agreement with Atlas
America) and Coalfield Pipeline Company (Coalfield Pipeline)
(gas pipeline), and Allegheny Energy Supply with respect to
Buchanan Generation, LLC (Buchanan Generation) (peaker
electrical power generation plant); we are parties to a joint
exploration agreement with Kelly Oil & Gas, Inc.
(Kelly Oil), Excelsior Exploration Corporation, Ceja Corporation
(exploration and production), and a third-party operator. We may
also enter into other arrangements like these in the future. 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 Energys 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, 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
Energys 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.
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
25
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 and delays to produce gas because we have
to acquire additional property rights to perfect our title to
the gas estate.
Some of the gas rights we believe we control are in areas where
we have not yet done any exploratory or production drilling.
Most of these properties were acquired by CONSOL Energy
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 perform a thorough title
examination of the gas estate before we commence drilling
activities and to acquire any additional rights needed to
perfect our ownership of the gas estate for development and
production purposes. We may incur substantial costs to acquire
these additional property rights and the acquisition of the
necessary rights may not be feasible in some cases. Our
inability to obtain these rights may adversely impact our
ability to develop those properties. Some states permit us to
produce the gas without perfected ownership under an
administrative process known as forced pooling,
which require us to give notice to all potential claimants and
pay royalties into escrow until the undetermined rights are
resolved. As a result, we may have to pay royalties to produce
gas on acreage that we control and these costs may be material.
Further, the forced pooling process is time-consuming and may
delay our drilling program in the affected areas.
In addition, although CONSOL Energy has conveyed to us all of
their rights 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 Energys 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
Energys transfer of those assets to us. Our assumption of
these liabilities is subject to the following allocation: we
will be responsible for the first $10,000 of aggregate unknown
liabilities; CONSOL Energy will be responsible for the next
$40,000 of aggregate unknown liabilities; and we will be
responsible for any additional unknown liabilities over $50,000.
We will also be responsible for any unknown liabilities which
were not asserted in writing by August 7, 2010.
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 has
asserted that several of our drilling techniques infringed
several patents that they hold. 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.
26
We
must coordinate some of our gas production activities with coal
mining activities in the same area, which could adversely affect
our operations and financial results.
In many places where we extract CBM, the coal estate is
dominant. In those cases, the coal operator, including, for
example, CONSOL Energy and other entities, could exercise its
rights to determine when and where certain drilling can take
place in order to ensure the safety of the mine or to protect
the mineability of the coal.
Currently
the majority of our producing properties are located in three
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 three 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,
subject to certain rights and indemnifications, 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 delays in the payment of insurance
proceeds could have a material adverse effect on our financial
condition and results of operations.
Proposed
legislation that seeks to regulate greenhouse gas emissions
could increase our costs and reduce the value of our
assets.
Methane, the primary gas which we produce, is a greenhouse gas
which is approximately 20 times more potent than carbon dioxide.
Most of the coalbed methane we produce would otherwise be vented
into the atmosphere in connection with coal mining activities,
so our business could be viewed as a significant contributor to
the reduction of greenhouse gas emissions and we may get credit
for those reductions. We have voluntarily reported those
reductions of greenhouse gas emissions to the Environmental
Protection Agency for several years. Absent final determination
by law, the master cooperation and safety agreement leaves open
for negotiation ownership as between us and CONSOL Energy of the
greenhouse gas reduction benefits of our production activities
both prior to and subsequent to the 2005 separation; we have an
oral agreement with CONSOL Energy pursuant to which we and
CONSOL Energy each receive 50% of any such benefits.
The U.S. Congress is considering climate change legislation
that proposes to restrict greenhouse gas emissions. Moreover,
several states have already adopted, and other states are
considering the adoption of, legislation or regulations to
reduce emissions of greenhouse gases. If any Federal or state
legislation or regulations that are ultimately adopted do not
exempt coalbed methane from their coverage, we could have to
curtail production, pay higher taxes or incur costs to purchase
allowances that permit us to continue our operations. If any
Federal or state legislation or regulations that are ultimately
adopted do not give us credits
27
for capturing methane that would otherwise be vented, thereby
reducing greenhouse gas emissions, the value of our historical
and future credits would be reduced or eliminated.
Our
hedging activities may prevent us from benefiting from price
increases and may expose us to other risks.
To manage our exposure to fluctuations in the price of natural
gas, we enter into hedging arrangements with respect to a
portion of our expected production. As of December 31,
2007, we had hedges on approximately 24.5 Bcf of our
targeted 2008 natural gas production. To the extent that we
engage in hedging activities, we may be prevented from realizing
the benefits of price increases above the levels of the hedges.
In addition, such transactions may expose us to the risk of
financial loss in certain circumstances, including instances in
which:
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our production is less than expected; or
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the counterparties to our futures contracts fail to perform the
contracts.
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If our gas hedges would no longer qualify for hedge accounting,
we will be required to mark them to market. This may result in
more volatility in our income in future periods.
Our
future level of indebtedness and the terms of our financing
arrangements may adversely affect operations and limit our
growth.
At December 31, 2007, we had no borrowings under our
revolving credit facility. However, we have significantly
increased our planned capital expenditures for 2008 and may
incur significant indebtedness in order to fund a portion of
these expenditures. We may incur additional indebtedness in the
future.
Our level of indebtedness and off-balance sheet obligations, and
the covenants contained in our financing agreements, could have
important consequences for our operations, including:
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requiring us to dedicate a portion of our cash flow from
operations to required payments, thereby reducing the
availability of cash flow for working capital, capital
expenditures and other general business activities;
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limiting our ability to obtain additional financing in the
future for working capital, capital expenditures, acquisitions
and general corporate and other activities;
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making us vulnerable to increases in interest rates, because our
revolving credit facility provides for variable rates of
interest;
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limiting our flexibility in planning for, or reacting to,
changes in our business and the industry in which we
operate; and
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reducing our ability to successfully withstand a downturn in our
business or the economy generally.
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Our revolving credit facility contains numerous financial and
other restrictive covenants. See Note 8 to the Consolidated
Financial Statements for more detail. Our ability to comply with
the covenants and other restrictions may be affected by events
beyond our control, including prevailing economic and financial
conditions. If we fail to comply with the covenants and other
restrictions, it could lead to an event of default and the
acceleration of our obligations under those agreements. We may
not have sufficient funds to make such payments. If we are
unable to satisfy our obligations with cash on hand, we could
attempt to refinance such debt, sell assets or repay such debt
with the proceeds from an equity offering. We cannot assure that
we will be able to generate sufficient cash flow to pay the
interest on our debt or that future borrowings, equity
financings or proceeds from the sale of assets will be available
to pay or refinance such debt. The terms of our financing
agreements may also prohibit us from taking such actions.
Factors that will affect our ability to raise cash through an
offering of our capital stock, a refinancing of our debt or a
sale of assets include financial market conditions and our
market value and operating performance at the time of such
offering or other
28
financing. We cannot assure that any such proposed offering,
refinancing or sale of assets can be successfully completed or,
if completed, that the terms will be favorable to us.
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 81.7% 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:
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the election and removal of directors;
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mergers or other business combinations involving us;
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future issuances of our common stock or other
securities; and
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amendments to our certificate of incorporation and bylaws.
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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 Energys
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
Energys 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
arms-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
arms-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
29
may be more favorable 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 Energys
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
guaranteed CONSOL Energys $250,000 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.
Approximately 14% of our gas production is associated with
CONSOL Energys active mining operations. 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 operations and financial results. For example, in
2005 and 2007, CONSOL Energy was forced to idle its Buchanan
Mine in southwest Virginia. As a result, we estimate that our
total gas production was 4.0 Bcf and 3.7 Bcf less than
it otherwise would have been in those years.
Further, CONSOL Energys coal mining activities at its
Buchanan Mine require the removal of water from the mine and the
ventilation of the mine. Several lawsuits and permit appeals
have been filed that could affect the removal of water from the
mine. Separately, a lawsuit has been filed with respect to a
ventilation fan that could affect the ventilation of the mine.
If operations at CONSOL Energys Buchanan Mine are
adversely affected as a result of these legal proceedings, our
gas production relating to mining activities would be adversely
affected.
CONSOL
Energy has announced its intention to make an offer to the
acquire all of the outstanding shares of CNX Gas that CONSOL
Energy does not already own.
On January 29, 2008, CONSOL Energy announced that it
intends to make an offer to the stockholders of CNX Gas to
acquire all of the outstanding shares of CNX Gas that it does
not currently own, in a stock-for-stock transaction that is
intended to be tax-free to the stockholders of CNX Gas.
Consummation of the offer could result in certain stockholders
being required to exchange their shares of CNX Gas stock for the
consideration paid by CONSOL Energy in the transaction.
30
We may
lose certain synergistic advantages if CONSOL divests its
ownership stake.
Because approximately 27% of our gas production is associated
with mining activities, coordination between mining and gas
operations can optimize overall energy production. If CONSOL
Energy were to divest of a significant interest in us,
coordination between us and CONSOL Energys mining
subsidiaries may be more difficult to accomplish.
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ITEM 1B.
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UNRESOLVED
STAFF COMMENTS
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None.
Our corporate headquarters are located at 5 Penn Center West,
Suite 401, Pittsburgh, Pennsylvania
15276-0102.
Our other properties are described under Gas
Operations Areas of Operation in ITEM 1.
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ITEM 3.
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LEGAL
PROCEEDINGS
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The second through seventh paragraphs of
Note 17 Commitments and Contingent Liabilities
in the Notes to the Consolidated Financial Statements included
in Part II of this
Form 10-K
are incorporated herein by reference.
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ITEM 4.
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SUBMISSION
OF MATTERS TO A VOTE OF SECURITY HOLDERS
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None.
PART II
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ITEM 5.
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MARKET
FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
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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.
The quarterly high and low share price for CNX Gas stock was as
follows for the 2007 and 2006 quarters ended:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
High
|
|
|
Low
|
|
|
High
|
|
|
Low
|
|
|
March 31
|
|
$
|
28.69
|
|
|
$
|
22.90
|
|
|
$
|
26.50
|
|
|
$
|
20.13
|
|
June 30
|
|
$
|
32.69
|
|
|
$
|
27.14
|
|
|
$
|
32.99
|
|
|
$
|
24.50
|
|
September 30
|
|
$
|
32.24
|
|
|
$
|
23.47
|
|
|
$
|
30.10
|
|
|
$
|
21.84
|
|
December 31
|
|
$
|
33.20
|
|
|
$
|
28.50
|
|
|
$
|
28.47
|
|
|
$
|
22.12
|
|
As of December 31, 2007 there were 9 holders of record of
the Companys common stock; we believe that there are
significantly more beneficial holders of our stock.
31
STOCK
PERFORMANCE GRAPH
The following performance graph compares the cumulative
shareholders return on the common stock of CNX Gas
Corporation (CXG) to the cumulative return for the same period
of the S&P Oil and Gas Exploration and Production index and
the S&P MidCap 400 Index. The chart below was structured in
a quarterly format rather than yearly because CNX Gas has only
been a public company since January 2006.
The graph assumes that the value of the investment in CNX Gas
common stock and each index was $100 at January 19, 2006
(the date CNX Gas shares were listed on the NYSE). The
graph also assumes that all dividends, if any, were reinvested
and that investments were held through December 31, 2007.
COMPARISON
OF CUMULATIVE TOTAL RETURN
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Base Period
|
|
|
Quarter Ending
|
|
Company/Index
|
|
Jan-19-06
|
|
|
Mar-06
|
|
|
Jun-06
|
|
|
Sep-06
|
|
|
Dec-06
|
|
|
Mar-07
|
|
|
Jun-07
|
|
|
Sep-07
|
|
|
Dec-07
|
|
|
CNX Gas Corporation
|
|
|
100
|
|
|
|
115.56
|
|
|
|
133.33
|
|
|
|
102.98
|
|
|
|
113.33
|
|
|
|
125.91
|
|
|
|
136.00
|
|
|
|
127.87
|
|
|
|
142.00
|
|
S&P MidCap 400 Index
|
|
|
100
|
|
|
|
102.89
|
|
|
|
99.66
|
|
|
|
98.58
|
|
|
|
105.47
|
|
|
|
111.58
|
|
|
|
118.10
|
|
|
|
117.08
|
|
|
|
113.88
|
|
S&P Oil & Gas Exploration &
Production
|
|
|
100
|
|
|
|
93.20
|
|
|
|
96.25
|
|
|
|
92.46
|
|
|
|
95.84
|
|
|
|
102.53
|
|
|
|
115.69
|
|
|
|
121.28
|
|
|
|
138.41
|
|
The foregoing graph shall not be deemed to be filed as part of
the
Form 10-K
and does not constitute soliciting material and should not be
deemed filed or incorporated by reference into any other filing
of CNX Gas under the Securities Act of 1933 or the Securities
Exchange Act of 1934, except to the extent CNX specifically
incorporates the graph by reference.
We currently 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 $420,200 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 of 2005, we issued 100 shares of common
stock to Consolidation Coal Company in exchange for one hundred
dollars in connection with the incorporation of CNX Gas. We
relied on the
32
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 Companys 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 to 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 was $365,363. 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, 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 to
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 was $54,804. 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.
33
|
|
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, 2007, 2006, 2005, 2004, and 2003 are derived
from our audited consolidated financial statements, including
the consolidated balance sheets at December 31, 2007, 2006,
2005, 2004, and 2003 and the related consolidated statements of
income and cash flows for each of the twelve months ended
December 31, 2007, 2006, 2005, 2004, and 2003, and the
related notes. 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
Managements 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Twelve Months Ended December 31,
|
|
STATEMENTS OF INCOME DATA
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(Dollars in thousands)
|
|
|
RESULTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outside Sales
|
|
$
|
404,835
|
|
|
$
|
385,056
|
|
|
$
|
277,031
|
|
|
$
|
214,721
|
|
|
$
|
145,884
|
|
Related Party Sales
|
|
|
11,618
|
|
|
|
8,490
|
|
|
|
6,052
|
|
|
|
22,036
|
|
|
|
32,572
|
|
Royalty Interest Gas Sales
|
|
|
46,586
|
|
|
|
51,054
|
|
|
|
45,351
|
|
|
|
41,858
|
|
|
|
32,442
|
|
Purchased Gas Sales
|
|
|
7,628
|
|
|
|
43,973
|
|
|
|
275,148
|
|
|
|
112,005
|
|
|
|
|
|
Other Income
|
|
|
6,641
|
|
|
|
25,286
|
|
|
|
9,859
|
|
|
|
6,916
|
|
|
|
4,485
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL REVENUE AND OTHER INCOME
|
|
|
477,308
|
|
|
|
513,859
|
|
|
|
613,441
|
|
|
|
397,536
|
|
|
|
215,383
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lifting Costs
|
|
|
38,721
|
|
|
|
33,357
|
|
|
|
30,399
|
|
|
|
27,250
|
|
|
|
22,792
|
|
Gathering and Compression Costs
|
|
|
61,798
|
|
|
|
58,102
|
|
|
|
43,903
|
|
|
|
40,422
|
|
|
|
31,997
|
|
Royalty Interest Gas Costs
|
|
|
40,011
|
|
|
|
41,998
|
|
|
|
36,641
|
|
|
|
32,914
|
|
|
|
24,200
|
|
Purchased Gas Costs
|
|
|
7,162
|
|
|
|
44,843
|
|
|
|
278,720
|
|
|
|
113,063
|
|
|
|
|
|
Other
|
|
|
79
|
|
|
|
1,082
|
|
|
|
2,878
|
|
|
|
3,009
|
|
|
|
10,788
|
|
General and Administrative
|
|
|
54,825
|
|
|
|
39,168
|
|
|
|
19,129
|
|
|
|
15,303
|
|
|
|
11,995
|
|
Depreciation, Depletion and Amortization
|
|
|
48,961
|
|
|
|
37,999
|
|
|
|
35,039
|
|
|
|
32,889
|
|
|
|
33,600
|
|
Interest Expense
|
|
|
5,606
|
|
|
|
870
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL COSTS AND EXPENSES
|
|
|
257,163
|
|
|
|
257,419
|
|
|
|
446,723
|
|
|
|
264,850
|
|
|
|
135,372
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Before Income Taxes, Minority Interest, and Cumulative
Effect of Change in Accounting Principle
|
|
|
220,145
|
|
|
|
256,440
|
|
|
|
166,718
|
|
|
|
132,686
|
|
|
|
80,011
|
|
Minority Interest
|
|
|
494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Before Income Taxes, and Cumulative Effect of Change in
Accounting Principle
|
|
|
220,639
|
|
|
|
256,440
|
|
|
|
166,718
|
|
|
|
132,686
|
|
|
|
80,011
|
|
Income Taxes
|
|
|
84,961
|
|
|
|
96,573
|
|
|
|
64,550
|
|
|
|
51,898
|
|
|
|
31,202
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Before Cumulative Effect of Change in Accounting
Principle
|
|
|
135,678
|
|
|
|
159,867
|
|
|
|
102,168
|
|
|
|
80,788
|
|
|
|
48,809
|
|
Cumulative Effect of Change in Accounting for Asset Retirement
Obligations (Net of Tax Impact of $1,879)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,905
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
135,678
|
|
|
$
|
159,867
|
|
|
$
|
102,168
|
|
|
$
|
80,788
|
|
|
$
|
51,714
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Twelve Months Ended December 31,
|
|
STATEMENTS OF INCOME DATA
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(Dollars in thousands)
|
|
|
Earnings Per Share Before Cumulative Effect of Change in
Accounting Principle
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.90
|
|
|
$
|
1.06
|
|
|
$
|
0.76
|
|
|
$
|
0.66
|
|
|
$
|
0.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.90
|
|
|
$
|
1.06
|
|
|
$
|
0.76
|
|
|
$
|
0.66
|
|
|
$
|
0.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Per Share from Net Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.90
|
|
|
$
|
1.06
|
|
|
$
|
0.76
|
|
|
$
|
0.66
|
|
|
$
|
0.42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.90
|
|
|
$
|
1.06
|
|
|
$
|
0.76
|
|
|
$
|
0.66
|
|
|
$
|
0.42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Number of Common Shares Outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
150,886,433
|
|
|
|
150,845,518
|
|
|
|
134,071,334
|
|
|
|
122,896,667
|
|
|
|
122,896,667
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dilutive
|
|
|
151,133,520
|
|
|
|
151,017,456
|
|
|
|
134,137,219
|
|
|
|
122,988,359
|
|
|
|
122,988,359
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
BALANCE SHEETS DATA
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(Dollars in thousands)
|
|
|
Working Capital (Deficiency) (Unaudited)
|
|
$
|
25,303
|
|
|
$
|
115,824
|
|
|
$
|
3,720
|
|
|
$
|
(35,030
|
)
|
|
$
|
(7,971
|
)
|
Total Assets
|
|
|
1,380,703
|
|
|
|
1,155,001
|
|
|
|
859,167
|
|
|
|
718,859
|
|
|
|
664,635
|
|
Long Term Debt (Including current portion)
|
|
|
72,768
|
|
|
|
66,470
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Deferred Credits and Other Liabilities
|
|
|
227,153
|
|
|
|
153,977
|
|
|
|
109,226
|
|
|
|
205,614
|
|
|
|
170,520
|
|
Stockholders Equity
|
|
|
1,023,237
|
|
|
|
880,215
|
|
|
|
679,472
|
|
|
|
462,556
|
|
|
|
464,232
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Twelve Months
|
|
|
|
Ended December 31,
|
|
CASH FLOW STATEMENTS DATA
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(Dollars in thousands)
|
|
|
Net Cash Provided by Operating Activities
|
|
$
|
272,448
|
|
|
$
|
243,569
|
|
|
$
|
144,997
|
|
|
$
|
175,350
|
|
|
$
|
143,133
|
|
Net Cash Used in Investing Activities
|
|
|
(354,227
|
)
|
|
|
(156,020
|
)
|
|
|
(108,287
|
)
|
|
|
(93,114
|
)
|
|
|
(90,605
|
)
|
Net Cash Provided by (Used in) Financing Activities
|
|
|
6,654
|
|
|
|
(449
|
)
|
|
|
(16,640
|
)
|
|
|
(82,237
|
)
|
|
|
(52,526
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Twelve Months
|
|
|
|
Ended December 31,
|
|
OTHER OPERATING DATA
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(Unaudited)
|
|
|
Net Sales Volumes (Bcf)(1)
|
|
|
58.25
|
|
|
|
56.14
|
|
|
|
48.39
|
|
|
|
48.56
|
|
|
|
44.46
|
|
Average Sales Price Including Effects of Financial Settlements
($ per Mcf)(1)(2)
|
|
$
|
7.20
|
|
|
$
|
7.04
|
|
|
$
|
5.90
|
|
|
$
|
4.90
|
|
|
$
|
4.03
|
|
Total Average Costs ($ Per Mcf)(1)
|
|
$
|
3.55
|
|
|
$
|
3.02
|
|
|
$
|
2.72
|
|
|
$
|
2.45
|
|
|
$
|
2.43
|
|
Net Estimated Proved Reserves (Bcfe)(1)(3)
|
|
|
1,343
|
|
|
|
1,265
|
|
|
|
1,130
|
|
|
|
1,045
|
|
|
|
1,004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Twelve Months
|
|
|
|
Ended December 31,
|
|
OTHER FINANCIAL DATA
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(Dollars in thousands)
|
|
|
Capital Expenditures(4)
|
|
$
|
357,199
|
|
|
$
|
154,243
|
|
|
$
|
110,752
|
|
|
$
|
89,753
|
|
|
$
|
83,869
|
|
EBIT(5) (Unaudited)
|
|
|
222,452
|
|
|
|
253,857
|
|
|
|
166,314
|
|
|
|
132,686
|
|
|
|
80,011
|
|
EBITDA(5) (Unaudited)
|
|
|
271,413
|
|
|
|
291,856
|
|
|
|
201,353
|
|
|
|
165,575
|
|
|
|
113,611
|
|
35
|
|
|
(1) |
|
For entities that are not wholly owned but in which CNX Gas owns
a working interest, includes a percentage of their net
production, sales or reserves equal to the CNX Gas percentage
equity ownership. Knox Energy is included in the equity earnings
data in 2007, 2006, 2005, 2004 and 2003. Sales of gas produced
by equity affiliates were 0.32 Bcf for the twelve months
ended December 31, 2007, 0.22 Bcf for the twelve
months ended December 2006, 0.23 Bcf for the twelve months
ended December 31, 2005, 0.20 Bcf for the twelve
months ended December 31, 2004, and 0.08 Bcf for the
twelve months ended December 31, 2003. |
|
(2) |
|
Represents average net sales price including the effect of
derivative transactions. |
|
(3) |
|
Represents proved developed and proved undeveloped gas reserves
at period end for total operations including equity affiliates,
of 3.6 Bcfe. |
|
(4) |
|
Capital expenditures for 2007 include those related to Knox
Energy. |
|
(5) |
|
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 companys 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 other similarly titled measures of other
companies. Managements 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Twelve Months
|
|
|
|
Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(Dollars in thousands)
|
|
|
Net Income
|
|
$
|
135,678
|
|
|
$
|
159,867
|
|
|
$
|
102,168
|
|
|
$
|
80,788
|
|
|
$
|
51,714
|
|
Add: Interest Expense
|
|
|
5,606
|
|
|
|
870
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
Less: Interest Income
|
|
|
3,793
|
|
|
|
3,453
|
|
|
|
418
|
|
|
|
|
|
|
|
|
|
Less: Cumulative Effect of Changes in Accounting for Asset
Retirement Obligations, Net of Income Taxes of $1,879
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,905
|
|
Add: Income Tax Expense
|
|
|
84,961
|
|
|
|
96,573
|
|
|
|
64,550
|
|
|
|
51,898
|
|
|
|
31,202
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Before Net Interest and Taxes (EBIT)
|
|
|
222,452
|
|
|
|
253,857
|
|
|
|
166,314
|
|
|
|
132,686
|
|
|
|
80,011
|
|
Add: Depreciation, Depletion and Amortization
|
|
|
48,961
|
|
|
|
37,999
|
|
|
|
35,039
|
|
|
|
32,889
|
|
|
|
33,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Before Net Interest, Taxes and Depreciation, Depletion
and Amortization (EBITDA)
|
|
$
|
271,413
|
|
|
$
|
291,856
|
|
|
$
|
201,353
|
|
|
$
|
165,575
|
|
|
$
|
113,611
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36
|
|
ITEM 7.
|
MANAGEMENTS
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 1A
Risk Factors.
Overview
We are a natural gas exploration, development, production and
gathering company, operating primarily in the Appalachian Basin.
We are largely a CBM gas producer with industry-leading
expertise in this type of gas extraction; however, in 2008, we
intend to undertake a more significant exploration program in
the shale formations we control.
The success of our operations substantially depends upon rights
we received from CONSOL Energy as a part of our separation.
CONSOL Energy transferred to CNX Gas various subsidiaries and
joint venture interests as well as all of their 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 $420,200) were used to pay a special
dividend to CONSOL Energy. CONSOL Energy currently owns 81.7% of
our outstanding common stock.
We do not currently have any plans to pay dividends; rather, we
intend to invest available cash into the expansion 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 low cost leader in
the industry.
Significant
Developments
During 2007, we achieved the following:
|
|
|
|
|
completed another year with no employee-related lost time
accidents. We have accumulated over 2.7 million man hours
without a lost time accident;
|
|
|
|
drilled a record 294 wells in our Virginia CBM operations;
|
|
|
|
expanded operations in our Mountaineer CBM play in Northern
Appalachia with a record 62 new wells drilled in 2007;
|
|
|
|
drilled 14 wells in Nittany, our CBM play in Central
Pennsylvania and the first entirely new step-out opportunity for
CNX Gas since its inception in 2005;
|
|
|
|
began exploratory drilling in Cardinal, a New Albany shale play
in the Illinois Basin;
|
|
|
|
increased our 2007 production by 3.8% from 2006 to 58 Bcf,
despite a roof collapse at CONSOL Energys Buchanan Mine;
|
|
|
|
increased our proved reserve base by replacing 234% of our
production;
|
|
|
|
generated net income of $135,678;
|
|
|
|
maintained our low cost structure relative to our peer group;
|
37
|
|
|
|
|
continued investing in the infrastructure necessary for
continued growth; and
|
|
|
|
acquired additional expertise to begin a significant exploration
program.
|
In July 2007 CONSOL Energy idled the Buchanan coal mine after
several roof falls in previously mined areas damaged some of the
ventilation controls inside the mine. This incident resulted in
the deferral of approximately 3.7 Bcf of gob gas in 2007.
CONSOL Energy re-entered the mine in January 2008, and we expect
to resume normal levels of gob gas production in the first
quarter of 2008.
Outlook
We intend to transition from a CBM producing company to a
natural gas exploration and production company.
Our 2008 capital expenditures are projected to be $470,000,
including $88,000 in exploratory capital. This capital budget
includes significant infrastructure capital that is required for
the company to achieve its strategic vision of producing
100 Bcf per year by 2010. CNX Gas will continue to
re-invest in its core business as long as it can achieve
expected rates of return that exceed its weighted average cost
of capital.
In 2008, we also expect to drill a total of 500 wells that
consist of 300 in Virginia, 100 in Mountaineer, and 100 in
Nittany.
CNX Gas became a registered offset provider on the Chicago
Climate Exchange (CCX) during the fourth quarter 2007. CCX
is a rules-based Greenhouse Gas (GhG) allowance trading system.
CCX emitting members make a voluntary but legally binding
commitment to meet annual GhG emission reduction targets. Those
emitting members who exceed their targets have surplus
allowances to sell or bank; those who fall short of their
targets comply by purchasing offsets which are called CCX Carbon
Financial Instruments (CFI) contracts. As a CCX offset provider,
CNX Gas is not bound to any emission reduction targets. An
offset provider is an owner of an offset project that registers
and sells offsets on its own behalf. In order to sell or trade
CFIs, approval must be received by the CCX Committee on
Offsets and approved projects must then be validated by an
independent CCX verifier. Once verified, CCX then issues
CFIs for each specific project. As of December 31,
2007, we are awaiting verification for several projects to
convert captured coal mine methane into tradable credits.
Credits are granted on the basis of avoiding methane emissions
by diverting gas into gas pipelines for commercial sale. No
CFIs have been issued or received as of December 31,
2007; however, we expect approval for these projects will be
received during the first quarter 2008. Sales of these credits
will be reflected in income as they occur.
On January 29, 2008, CONSOL Energy announced an intention
to commence an exchange offer to acquire the 18.3% of
outstanding shares of CNX Gas that CONSOL Energy does not
currently own.
38
Results
of Operations
Twelve
Months Ended December 31, 2007 compared with Twelve Months
Ended December 31, 2006 (Amounts reported in
thousands)
Net
Income
Net income changed primarily due to the following items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dollar
|
|
|
Percentage
|
|
|
|
2007
|
|
|
2006
|
|
|
Variance
|
|
|
Change
|
|
|
Revenue and Other Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outside Sales
|
|
$
|
404,835
|
|
|
$
|
385,056
|
|
|
$
|
19,779
|
|
|
|
5.1
|
%
|
Related Party Sales
|
|
|
11,618
|
|
|
|
8,490
|
|
|
|
3,128
|
|
|
|
36.8
|
%
|
Royalty Interest Gas Sales
|
|
|
46,586
|
|
|
|
51,054
|
|
|
|
(4,468
|
)
|
|
|
(8.8
|
)%
|
Purchased Gas Sales
|
|
|
7,628
|
|
|
|
43,973
|
|
|
|
(36,345
|
)
|
|
|
(82.7
|
)%
|
Other Income
|
|
|
6,641
|
|
|
|
25,286
|
|
|
|
(18,645
|
)
|
|
|
(73.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenue and Other Income
|
|
|
477,308
|
|
|
|
513,859
|
|
|
|
(36,551
|
)
|
|
|
(7.1
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lifting Costs
|
|
|
38,721
|
|
|
|
33,357
|
|
|
|
5,364
|
|
|
|
16.1
|
%
|
Gathering and Compression Costs
|
|
|
61,798
|
|
|
|
58,102
|
|
|
|
3,696
|
|
|
|
6.4
|
%
|
Royalty Interest Gas Costs
|
|
|
40,011
|
|
|
|
41,998
|
|
|
|
(1,987
|
)
|
|
|
(4.7
|
)%
|
Purchased Gas Costs
|
|
|
7,162
|
|
|
|
44,843
|
|
|
|
(37,681
|
)
|
|
|
(84.0
|
)%
|
Other
|
|
|
79
|
|
|
|
1,082
|
|
|
|
(1,003
|
)
|
|
|
(92.7
|
)%
|
General and Administrative
|
|
|
54,825
|
|
|
|
39,168
|
|
|
|
15,657
|
|
|
|
40.0
|
%
|
Depreciation, Depletion and Amortization
|
|
|
48,961
|
|
|
|
37,999
|
|
|
|
10,962
|
|
|
|
28.8
|
%
|
Interest Expense
|
|
|
5,606
|
|
|
|
870
|
|
|
|
4,736
|
|
|
|
544.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Costs and Expenses
|
|
|
257,163
|
|
|
|
257,419
|
|
|
|
(256
|
)
|
|
|
(0.1
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Before Income Taxes and Minority Interest
|
|
|
220,145
|
|
|
|
256,440
|
|
|
|
(36,295
|
)
|
|
|
(14.2
|
)%
|
Minority Interest
|
|
|
494
|
|
|
|
|
|
|
|
494
|
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Before Income Taxes
|
|
|
220,639
|
|
|
|
256,440
|
|
|
|
(35,801
|
)
|
|
|
(14.0
|
)%
|
Income Taxes
|
|
|
84,961
|
|
|
|
96,573
|
|
|
|
(11,612
|
)
|
|
|
(12.0
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
135,678
|
|
|
$
|
159,867
|
|
|
$
|
(24,189
|
)
|
|
|
(15.1
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income for 2007 was lower primarily due to deferred
production resulting from the Buchanan mine incident, lower
insurance proceeds in the current year compared to 2006 and
higher administrative and operating costs. The decreased net
income was offset in part by additional sales revenue from new
wells being brought on-line in 2007.
39
Revenue
and Other Income
Revenue and other income decreased due to the following items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dollar
|
|
|
Percentage
|
|
|
|
2007
|
|
|
2006
|
|
|
Variance
|
|
|
Change
|
|
|
Revenue and Other Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outside Sales
|
|
$
|
404,835
|
|
|
$
|
385,056
|
|
|
$
|
19,779
|
|
|
|
5.1
|
%
|
Related Party Sales
|
|
|
11,618
|
|
|
|
8,490
|
|
|
|
3,128
|
|
|
|
36.8
|
%
|
Royalty Interest Gas Sales
|
|
|
46,586
|
|
|
|
51,054
|
|
|
|
(4,468
|
)
|
|
|
(8.8
|
)%
|
Purchased Gas Sales
|
|
|
7,628
|
|
|
|
43,973
|
|
|
|
(36,345
|
)
|
|
|
(82.7
|
)%
|
Other Income
|
|
|
6,641
|
|
|
|
25,286
|
|
|
|
(18,645
|
)
|
|
|
(73.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenue and Other Income
|
|
$
|
477,308
|
|
|
$
|
513,859
|
|
|
$
|
(36,551
|
)
|
|
|
(7.1
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The decrease in total revenue and other income was primarily due
to the accounting change related to purchased gas sales
discussed below, as well as lower business interruption
insurance in the current year compared to 2006. This was offset
by increases in outside sales and related party sales, which
resulted from an increased average sales price in 2007 compared
to 2006 and increased production related to additional wells
being brought on-line in the current year.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
2007
|
|
2006
|
|
Variance
|
|
Change
|
|
Sales Volumes (Bcf)
|
|
|
57.9
|
|
|
|
55.9
|
|
|
|
2.0
|
|
|
|
3.6
|
%
|
Average Sales Price (per Mcf)
|
|
$
|
7.19
|
|
|
$
|
7.04
|
|
|
$
|
0.15
|
|
|
|
2.1
|
%
|
The increase in average sales price is the result of CNX Gas
realizing general price increases and higher hedging gains in
the current year. CNX Gas periodically enters 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 hedges represented
approximately 18.4 Bcf of our produced gas sales volumes
for the twelve months ended December 31, 2007 at an average
price of $8.01 per Mcf. In the prior year, these financial
hedges represented approximately 17.0 Bcf at an average
price of $7.42 per Mcf. Sales volumes increased as a result of
additional wells coming online from our on-going drilling
program. Also included in 2007 are the non-operated net revenue
interest volumes and revenues associated with royalty and
working interests. These volumes were not available in 2006, and
the associated revenues were included in other income. Partially
offsetting these increases was the deferral of production
related to the Buchanan Mine issue at CONSOL Energy.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
2007
|
|
2006
|
|
Variance
|
|
Change
|
|
Royalty Interest Gas Sales Volumes (Bcf)
|
|
|
7.2
|
|
|
|
7.6
|
|
|
|
(0.4
|
)
|
|
|
(5.3
|
)%
|
Average Sales Price (per Mcf)
|
|
$
|
6.44
|
|
|
$
|
6.76
|
|
|
$
|
(0.32
|
)
|
|
|
(4.7
|
)%
|
Included in royalty interest gas sales are the revenues related
to the portion of production belonging to royalty interest
owners sold by CNX Gas on their behalf. The decrease in average
sales price relates primarily to reductions in a provision for
royalty settlements. The volatility in the monthly volumes and
contractual differences among leases, as well as the mix of
average and index prices used in calculating royalties also
contributes to the variance.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
2007
|
|
2006
|
|
Variance
|
|
Change
|
|
Purchased Gas Sales Volumes (Bcf)
|
|
|
1.1
|
|
|
|
6.1
|
|
|
|
(5.0
|
)
|
|
|
(82.0
|
)%
|
Average Sales Price (per Mcf)
|
|
$
|
7.19
|
|
|
$
|
7.20
|
|
|
$
|
(0. 01
|
)
|
|
|
(0.1
|
)%
|
Purchased gas sales volumes in the current year represent
volumes of gas we sell at market prices that were purchased from
third party producers, less our gathering and marketing fees. In
the 2006 period, purchased gas sales and volumes represented
volumes of gas we simultaneously purchased from and sold to the
same counterparties under contracts that were committed prior to
January 1, 2006. Accordingly, Emerging
40
Issues Task Force Issue
No. 04-13
(EITF 04-13),
which we adopted on January 1, 2006, did not apply to these
transactions. All contracts entered into prior to
January 1, 2006 expired in 2006, while all activity related
to 2007 is reflected in transportation expense on a net basis.
Other income consists of the following items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dollar
|
|
|
Percentage
|
|
|
|
2007
|
|
|
2006
|
|
|
Variance
|
|
|
Change
|
|
|
Royalty Income
|
|
$
|
|
|
|
$
|
10,230
|
|
|
$
|
(10,230
|
)
|
|
|
(100.0
|
)%
|
Business Interruption Insurance
|
|
|
1,600
|
|
|
|
10,165
|
|
|
|
(8,565
|
)
|
|
|
(84.3
|
)%
|
Third Party Gathering Revenue
|
|
|
1,077
|
|
|
|
1,341
|
|
|
|
(264
|
)
|
|
|
(19.7
|
)%
|
Other Miscellaneous
|
|
|
171
|
|
|
|
97
|
|
|
|
74
|
|
|
|
76.3
|
%
|
Interest Income
|
|
|
3,793
|
|
|
|
3,453
|
|
|
|
340
|
|
|
|
9.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Other Income
|
|
$
|
6,641
|
|
|
$
|
25,286
|
|
|
$
|
(18,645
|
)
|
|
|
(73.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty income received from third parties, which is calculated
as a percentage of the third parties sales price, is now
classified in outside sales. In the prior period, the volumes
were not available nor were they considered in the prior period
reserve report. In the current year, these volumes are included
in both sales production and reserves.
Insurance proceeds in 2007 related to an advance on the
settlement of claims under our business interruption insurance
policy for losses we sustained related to a CONSOL Energy mining
incident at Buchanan Mine which adversely affected our gob gas
production in the current year. Insurance proceeds in 2006
related to a CONSOL Energy mining incident in 2005 which
negatively impacted our gas production in that year.
Third party gathering revenue was lower in 2007 due to the
termination in June of our principal third party gathering
agreement along with an actualization related to the final
settlement.
Other miscellaneous income consists of various items, none of
which are material period over period.
Interest income increased in 2007 as a result of a higher cash
balance throughout a majority of the reporting period. CNX Gas
anticipates utilizing the credit facility in 2008 due to our
increased capital expenditures program.
Costs and
Expenses
Costs and expenses decreased due to the following items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dollar
|
|
|
Percentage
|
|
|
|
2007
|
|
|
2006
|
|
|
Variance
|
|
|
Change
|
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lifting Costs
|
|
$
|
38,721
|
|
|
$
|
33,357
|
|
|
$
|
5,364
|
|
|
|
16.1
|
%
|
Gathering and Compression Costs
|
|
|
61,798
|
|
|
|
58,102
|
|
|
|
3,696
|
|
|
|
6.4
|
%
|
Royalty Interest Gas Costs
|
|
|
40,011
|
|
|
|
41,998
|
|
|
|
(1,987
|
)
|
|
|
(4.7
|
)%
|
Purchased Gas Costs
|
|
|
7,162
|
|
|
|
44,843
|
|
|
|
(37,681
|
)
|
|
|
(84.0
|
)%
|
Other
|
|
|
79
|
|
|
|
1,082
|
|
|
|
(1,003
|
)
|
|
|
(92.7
|
)%
|
General and Administrative
|
|
|
54,825
|
|
|
|
39,168
|
|
|
|
15,657
|
|
|
|
40.0
|
%
|
Depreciation, Depletion and Amortization
|
|
|
48,961
|
|
|
|
37,999
|
|
|
|
10,962
|
|
|
|
28.8
|
%
|
Interest Expense
|
|
|
5,606
|
|
|
|
870
|
|
|
|
4,736
|
|
|
|
544.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Costs and Expenses
|
|
$
|
257,163
|
|
|
$
|
257,419
|
|
|
$
|
(256
|
)
|
|
|
(0.1
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41
Total costs and expenses decreased due to the accounting change
related to purchased gas costs, partially offset by increased
depreciation and administrative costs.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
2007
|
|
2006
|
|
Variance
|
|
Change
|
|
Sales Volumes (Bcf)
|
|
|
57.9
|
|
|
|
55.9
|
|
|
|
2.0
|
|
|
|
3.6
|
%
|
Average Lifting Costs (per Mcf)
|
|
$
|
0.67
|
|
|
$
|
0.60
|
|
|
$
|
0.07
|
|
|
|
11.7
|
%
|
Lifting costs per unit sold increased in the current year due to
additional staffing, increased service and maintenance costs due
to the additional number of wells on-line, increased water
disposal costs, higher road maintenance, and the deferral of low
cost gob production related to the CONSOL Energy Buchanan Mine.
These unit cost increases were partially offset by a decrease in
unit costs due to an adjustment in the well plugging liability,
as a result of the increase in the estimated average life of our
wells.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
2007
|
|
2006
|
|
Variance
|
|
Change
|
|
Sales Volumes (Bcf)
|
|
|
57.9
|
|
|
|
55.9
|
|
|
|
2.0
|
|
|
|
3.6
|
%
|
Average Gathering and Compression Costs (per Mcf)
|
|
$
|
1.07
|
|
|
$
|
1.04
|
|
|
$
|
0.03
|
|
|
|
2.9
|
%
|
The increase in gathering and compression unit costs was
attributable to additional treating expenses related to the
start up of Mountaineer, compressor rentals related to the
increased number of wells in the year, and higher power expenses
related to increased megawatt hour rates charged by the power
company. These increases were partially offset by lower firm
transportation costs related to the in-service of the Jewell
Ridge lateral in October 2006. These cost increases were
proportionately higher than the increase in volumes, which
increased our unit cost.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
2007
|
|
2006
|
|
Variance
|
|
Change
|
|
Royalty Interest Gas Sales Volumes (Bcf)
|
|
|
7.2
|
|
|
|
7.6
|
|
|
|
(0.4
|
)
|
|
|
(5.3
|
)%
|
Average Cost (per Mcf)
|
|
$
|
5.53
|
|
|
$
|
5.56
|
|
|
$
|
(0.03
|
)
|
|
|
(0.5
|
)%
|
Included in royalty interest gas costs are the expenses related
to the portion of production belonging to royalty interest
owners sold by CNX Gas on their behalf. The decrease in volumes
and price relates to the volatility and contractual differences
among leases, as well as the mix of average and index prices
used in calculating royalties.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
2007
|
|
2006
|
|
Variance
|
|
Change
|
|
Purchased Gas Cost Volumes (Bcf)
|
|
|
1.1
|
|
|
|
6.1
|
|
|
|
(5.0
|
)
|
|
|
(82.0
|
)%
|
Average Purchased Gas Costs (per Mcf)
|
|
$
|
6.66
|
|
|
$
|
7.34
|
|
|
$
|
(0.68
|
)
|
|
|
(9.3
|
)%
|
Purchased gas cost volumes in the current year represent volumes
of gas we sell at market prices that were purchased from third
party producers, less our gathering and marketing fees. In the
2006 period, purchased gas costs and volumes represented volumes
of gas we simultaneously purchased from and sold to the same
counterparties under contracts that were committed prior to
January 1, 2006. Accordingly, Emerging Issues Task Force
Issue
No. 04-13
(EITF 04-13),
which we adopted on January 1, 2006, did not apply to these
transactions. All contracts entered into prior to
January 1, 2006 expired in 2006, while all activity related
to 2007 is reflected in transportation expense on a net basis.
Other costs and expenses decreased due to the following items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dollar
|
|
|
Percentage
|
|
|
|
2007
|
|
|
2006
|
|
|
Variance
|
|
|
Change
|
|
|
Exploration
|
|
$
|
2,253
|
|
|
$
|
2,708
|
|
|
$
|
(455
|
)
|
|
|
(16.8
|
)%
|
Pipeline Imbalance
|
|
|
|
|
|
|
(648
|
)
|
|
|
648
|
|
|
|
100.0
|
%
|
Equity in Earnings of Affiliates
|
|
|
(2,174
|
)
|
|
|
(978
|
)
|
|
|
(1,196
|
)
|
|
|
(122.3
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Other Costs and Expenses
|
|
$
|
79
|
|
|
$
|
1,082
|
|
|
$
|
(1,003
|
)
|
|
|
(92.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42
Exploration costs decreased primarily as a result of less
unsuccessful broker fees in the current year as compared to the
prior year. CNX Gas anticipates higher exploration costs in 2008
as the transformation to a full fledged Exploration and
Production company is realized. The pipeline imbalance is now
included in either outside sales or purchased gas costs.
Additionally, equity in earnings of affiliates increased in 2007
compared to 2006, primarily due to increased production of
approximately 0.1 Bcf from our Knox Energy joint venture.
General and Administrative expenses increased due to the
following items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dollar
|
|
|
Percentage
|
|
|
|
2007
|
|
|
2006
|
|
|
Variance
|
|
|
Change
|
|
|
Employee Wages and Related Costs
|
|
$
|
19,255
|
|
|
$
|
16,582
|
|
|
$
|
2,673
|
|
|
|
16.1
|
%
|
Professional Fees
|
|
|
15,621
|
|
|
|
8,879
|
|
|
|
6,742
|
|
|
|
75.9
|
%
|
Short Term Incentive
|
|
|
5,659
|
|
|
|
4,702
|
|
|
|
957
|
|
|
|
20.4
|
%
|
Stock Based Compensation
|
|
|
5,491
|
|
|
|
4,502
|
|
|
|
989
|
|
|
|
22.0
|
%
|
Facilities
|
|
|
5,049
|
|
|
|
2,805
|
|
|
|
2,244
|
|
|
|
80.0
|
%
|
Other
|
|
|
3,750
|
|
|
|
1,698
|
|
|
|
2,052
|
|
|
|
120.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
54,825
|
|
|
$
|
39,168
|
|
|
$
|
15,657
|
|
|
|
40.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee Wages and Related Costs have increased due to the
continued increase in staffing as a result of the on-going
growth of the company. CNX Gas has gone from 192 employees
on December 31, 2006 to 281 employees on
December 31, 2007.
Professional Fees have increased primarily related to additional
legal fees associated with the CDX and GeoMet litigation. CNX
Gas also incurred additional consulting expense related the
information management software platform that was implemented in
2006. In the prior year these costs were capitalized as part of
the implementation, however these costs are expensed in the
current year.
Short Term Incentive and Stock Based Compensation costs have
increased also as a result of the on-going growth of the company
as previously mentioned.
The increase in Facilities in the current year relates to the
establishment of a new company headquarters, and various other
offices associated with the continued growth of the company and
our entrance into other regions.
The increase in Other costs is due primarily to increases in
insurance premiums as well as various other items that are not
individually significant.
Depreciation, depletion and amortization have increased due to
the following items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dollar
|
|
|
Percentage
|
|
|
|
2007
|
|
|
2006
|
|
|
Variance
|
|
|
Change
|
|
|
Production
|
|
$
|
30,945
|
|
|
$
|
24,668
|
|
|
$
|
6,277
|
|
|
|
25.4
|
%
|
Gathering
|
|
|
18,016
|
|
|
|
13,331
|
|
|
|
4,685
|
|
|
|
35.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Depreciation, Depletion and Amortization
|
|
$
|
48,961
|
|
|
$
|
37,999
|
|
|
$
|
10,962
|
|
|
|
28.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The increase in production related depreciation, depletion and
amortization was primarily due to increased production combined
with an increase in the units of production rates from period to
period. These rates increased due to the higher proportion of
capital assets placed in service versus the proportion of proved
developed reserve additions. These rates are generally
calculated using the net book value of assets at the end of the
previous year divided by either proved or proved developed
reserves. Gathering depreciation, depletion and amortization is
recorded using the straight-line method and increased primarily
as a result of realizing a full year of the capital lease
treatment of the Jewell Ridge lateral, which went into service
on October 28, 2006.
Interest expense primarily increased as a result of our capital
lease obligation on the Jewell Ridge lateral. CNX Gas expects
interest expense to increase in 2008 due to the increase in
capital spending as compared to the current year.
43
Income
Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
|
2007
|
|
|
2006
|
|
|
Variance
|
|
|
Change
|
|
|
Earnings Before Income Taxes
|
|
$
|
220,639
|
|
|
$
|
256,440
|
|
|
$
|
(35,801
|
)
|
|
|
(14.0
|
)%
|
Tax Expense
|
|
$
|
84,961
|
|
|
$
|
96,573
|
|
|
$
|
(11,612
|
)
|
|
|
(12.0
|
)%
|
Effective Income Tax Rate
|
|
|
38.5
|
%
|
|
|
37.7
|
%
|
|
|
0.8
|
%
|
|
|
|
|
CNX Gas effective tax rate increased in 2007 primarily due
to an increase in state tax rates, discussed further in
Note 5 to the Consolidated Financial Statements.
Twelve
Months Ended December 31, 2006 compared with Twelve Months
Ended December 31, 2005
(Amounts
reported in thousands)
Net
Income
Net income changed primarily due to the following items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dollar
|
|
|
Percentage
|
|
|
|
2006
|
|
|
2005
|
|
|
Variance
|
|
|
Change
|
|
|
Revenue and Other Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outside Sales
|
|
$
|
385,056
|
|
|
$
|
277,031
|
|
|
$
|
108,025
|
|
|
|
39.0
|
%
|
Related Party Sales
|
|
|
8,490
|
|
|
|
6,052
|
|
|
|
2,438
|
|
|
|
40.3
|
%
|
Royalty Interest Gas Sales
|
|
|
51,054
|
|
|
|
45,351
|
|
|
|
5,703
|
|
|
|
12.6
|
%
|
Purchased Gas Sales
|
|
|
43,973
|
|
|
|
275,148
|
|
|
|
(231,175
|
)
|
|
|
(84.0
|
)%
|
Other Income
|
|
|
25,286
|
|
|
|
9,859
|
|
|
|
15,427
|
|
|
|
156.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenue and Other Income
|
|
|
513,859
|
|
|
|
613,441
|
|
|
|
(99,582
|
)
|
|
|
(16.2
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lifting Costs
|
|
|
33,357
|
|
|
|
30,399
|
|
|
|
2,958
|
|
|
|
9.7
|
%
|
Gathering and Compression Costs
|
|
|
58,102
|
|
|
|
43,903
|
|
|
|
14,199
|
|
|
|
32.3
|
%
|
Royalty Interest Gas Costs
|
|
|
41,998
|
|
|
|
36,641
|
|
|
|
5,357
|
|
|
|
14.6
|
%
|
Purchased Gas Costs
|
|
|
44,843
|
|
|
|
278,720
|
|
|
|
(233,877
|
)
|
|
|
(83.9
|
)%
|
Other
|
|
|
1,082
|
|
|
|
2,878
|
|
|
|
(1,796
|
)
|
|
|
(62.4
|
)%
|
General and Administrative
|
|
|
39,168
|
|
|
|
19,129
|
|
|
|
20,039
|
|
|
|
104.8
|
%
|
Depreciation, Depletion and Amortization
|
|
|
37,999
|
|
|
|
35,039
|
|
|
|
2,960
|
|
|
|
8.4
|
%
|
Interest Expense
|
|
|
870
|
|
|
|
14
|
|
|
|
856
|
|
|
|
6,114.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Costs and Expenses
|
|
|
257,419
|
|
|
|
446,723
|
|
|
|
(189,304
|
)
|
|
|
(42.4
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Before Income Taxes
|
|
|
256,440
|
|
|
|
166,718
|
|
|
|
89,722
|
|
|
|
53.8
|
%
|
Income Taxes
|
|
|
96,573
|
|
|
|
64,550
|
|
|
|
32,023
|
|
|
|
49.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
159,867
|
|
|
$
|
102,168
|
|
|
$
|
57,699
|
|
|
|
56.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income for 2006 was improved primarily due to increases in
average sales price and production.
44
Revenue
and Other Income
Revenue and other income decreased due to the following items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dollar
|
|
|
Percentage
|
|
|
|
2006
|
|
|
2005
|
|
|
Variance
|
|
|
Change
|
|
|
Revenue and Other Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outside Sales
|
|
$
|
385,056
|
|
|
$
|
277,031
|
|
|
$
|
108,025
|
|
|
|
39.0
|
%
|
Related Party Sales
|
|
|
8,490
|
|
|
|
6,052
|
|
|
|
2,438
|
|
|
|
40.3
|
%
|
Royalty Interest Gas Sales
|
|
|
51,054
|
|
|
|
45,351
|
|
|
|
5,703
|
|
|
|
12.6
|
%
|
Purchased Gas Sales
|
|
|
43,973
|
|
|
|
275,148
|
|
|
|
(231,175
|
)
|
|
|
(84.0
|
)%
|
Other Income
|
|
|
25,286
|
|
|
|
9,859
|
|
|
|
15,427
|
|
|
|
156.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenue and Other Income
|
|
$
|
513,859
|
|
|
$
|
613,441
|
|
|
$
|
(99,582
|
)
|
|
|
(16.2
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The decrease in total revenue and other income was primarily due
to the accounting change related to purchased gas sales,
partially offset by increased outside sales.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
2006
|
|
2005
|
|
Variance
|
|
Change
|
|
Sales Volumes (Bcf)
|
|
|
55.9
|
|
|
|
48.2
|
|
|
|
7.7
|
|
|
|
16.0
|
%
|
Average Sales Price (per Mcf)
|
|
$
|
7.04
|
|
|
$
|
5.88
|
|
|
$
|
1.16
|
|
|
|
19.7
|
%
|
The increase in average sales price is the result of CNX Gas
realizing higher hedging gains. CNX Gas periodically enters 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 17 Bcf of our produced gas
sales volumes for the twelve months ended December 31, 2006
at an average price of $7.42 per Mcf. In the prior year these
hedges represented approximately 38.2 Bcf at an average
price of $4.77 per Mcf.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
2006
|
|
2005
|
|
Variance
|
|
Change
|
|
Royalty Interest Gas Sales Volumes (Bcf)
|
|
|
7.6
|
|
|
|
6.6
|
|
|
|
1.0
|
|
|
|
15.2
|
%
|
Average Sales Price (per Mcf)
|
|
$
|
6.76
|
|
|
$
|
6.92
|
|
|
$
|
(0.16
|
)
|
|
|
(2.3
|
)%
|
Included in royalty interest gas sales are the revenues related
to the portion of production belonging to royalty interest
owners sold by CNX Gas on their behalf. The decrease in sales
price is a function of the average CNX Gas price, before the
effects of financial swap transactions, being higher in the
prior year than in the current year. Volumes increased as a
result of our current year drilling program.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
2006
|
|
2005
|
|
Variance
|
|
Change
|
|
Purchased Gas Sales Volumes (Bcf)
|
|
|
6.1
|
|
|
|
28.7
|
|
|
|
(22.6
|
)
|
|
|
(78.7
|
)%
|
Average Sales Price (per Mcf)
|
|
$
|
7.20
|
|
|
$
|
9.59
|
|
|
$
|
(2.39
|
)
|
|
|
(24.9
|
)%
|
Included in purchased gas sales revenue are volumes of gas we
simultaneously purchased from and sold to the same
counterparties between the segmentation and interruptible pools
on the Columbia Gas Transmission Corporation (TCO) pipeline in
order to satisfy obligations to certain customers. In accordance
with Emerging Issues Task Force Issue
No. 99-19
Reporting Revenue Gross as a Principal versus Net as an
Agent
(EITF 99-19),
we have historically recorded our revenues and our costs on a
gross basis. However, because we adopted
EITF 04-13
on January 1, 2006, purchased gas sales and volumes have
decreased. The net result for transactions that meet the above
criteria is reflected in transportation expense in the current
year. Additionally, there are small volumes of gas we purchase
from third party producers at market prices less our gathering
charge, which we then resell.
45
Other income consists of the following items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dollar
|
|
|
Percentage
|
|
|
|
2006
|
|
|
2005
|
|
|
Variance
|
|
|
Change
|
|
|
Royalty Income
|
|
$
|
10,230
|
|
|
$
|
8,158
|
|
|
$
|
2,072
|
|
|
|
25.4
|
%
|
Business Interruption Insurance
|
|
|
10,165
|
|
|
|
|
|
|
|
10,165
|
|
|
|
100.0
|
%
|
Interest Income
|
|
|
3,453
|
|
|
|
418
|
|
|
|
3,035
|
|
|
|
726.1
|
%
|
Third Party Gathering Revenue
|
|
|
1,341
|
|
|
|
1,110
|
|
|
|
231
|
|
|
|
20.8
|
%
|
Other Miscellaneous
|
|
|
97
|
|
|
|
173
|
|
|
|
(76
|
)
|
|
|
(43.9
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Other Income
|
|
$
|
25,286
|
|
|
$
|
9,859
|
|
|
$
|
15,427
|
|
|
|
156.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty income increased in 2006 compared to 2005 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.
Insurance proceeds relate to the settlement of claims for losses
we sustained from CONSOL Energy mining incidents that adversely
affected our gob gas production in 2005.
Interest income increased in 2006 as a result of increased
earnings and the fact that CNX Gas retained cash collections as
a separate stand alone company for the entire year. For most of
2005, CNX Gas was part of CONSOL Energy and only retained cash
after separation from CONSOL Energy.
Costs and
Expenses
Costs and expenses decreased due to the following items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dollar
|
|
|
Percentage
|
|
|
|
2006
|
|
|
2005
|
|
|
Variance
|
|
|
Change
|
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lifting Costs
|
|
$
|
33,357
|
|
|
$
|
30,399
|
|
|
$
|
2,958
|
|
|
|
9.7
|
%
|
Gathering and Compression Costs
|
|
|
58,102
|
|
|
|
43,903
|
|
|
|
14,199
|
|
|
|
32.3
|
%
|
Royalty Interest Gas Costs
|
|
|
41,998
|
|
|
|
36,641
|
|
|
|
5,357
|
|
|
|
14.6
|
%
|
Purchased Gas Costs
|
|
|
44,843
|
|
|
|
278,720
|
|
|
|
(233,877
|
)
|
|
|
(83.9
|
)%
|
Other
|
|
|
1,082
|
|
|
|
2,878
|
|
|
|
(1,796
|
)
|
|
|
(62.4
|
)%
|
General and Administrative
|
|
|
39,168
|
|
|
|
19,129
|
|
|
|
20,039
|
|
|
|
104.8
|
%
|
Depreciation, Depletion and Amortization
|
|
|
37,999
|
|
|
|
35,039
|
|
|
|
2,960
|
|
|
|
8.4
|
%
|
Interest Expense
|
|
|
870
|
|
|
|
14
|
|
|
|
856
|
|
|
|
6,114.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Costs and Expenses
|
|
$
|
257,419
|
|
|
$
|
446,723
|
|
|
$
|
(189,304
|
)
|
|
|
(42.4
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The decrease in total costs and expenses was primarily due to
the accounting change related to purchased gas costs.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
2006
|
|
2005
|
|
Variance
|
|
Change
|
|
Sales Volumes (Bcf)
|
|
|
55.9
|
|
|
|
48.2
|
|
|
|
7.7
|
|
|
|
16.0
|
%
|
Average Lifting Costs (per Mcf)
|
|
$
|
0.60
|
|
|
$
|
0.63
|
|
|
$
|
(0.03
|
)
|
|
|
(4.8
|
)%
|
46
Lifting costs per unit sold decreased due to increased
production from our ongoing drilling program and savings in well
service costs, which were partially offset by higher production
taxes as a result of higher pricing.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
2006
|
|
2005
|
|
Variance
|
|
Change
|
|
Sales Volumes (Bcf)
|
|
|
55.9
|
|
|
|
48.2
|
|
|
|
7.7
|
|
|
|
16.0
|
%
|
Average Gathering and Compression Costs (per Mcf)
|
|
$
|
1.04
|
|
|
$
|
0.91
|
|
|
$
|
0.13
|
|
|
|
14.3
|
%
|
The increase in gathering and compression costs per unit was
attributable to an additional $0.07 per Mcf charge for the
purchase of firm transportation capacity on the Columbia
pipeline acquired to ensure deliverability of our gas. Due to
the application of
EITF 04-13,
the combining of matching buy/sell transactions accounts for an
additional $0.06 per Mcf increase in the current year. Although
the net costs associated with similar buy/sell transactions were
incurred during the prior period, they were not recorded as part
of gathering and compression costs. Instead, they were recorded
on a gross basis as purchased gas sales and purchased gas costs.
Gathering and compression costs have also increased
approximately $0.05 per Mcf due to additional power expenses
related to both increased megawatt hour rates charged by our
power provider and the use of more electric compressors during
the current year that were previously powered by gas for most of
the prior year. Maintenance and various other related
transactions have decreased $0.03 per Mcf as a result of
increased production and the compressor conversions. The sales
production used to calculate this unit cost does not include
volumes from third parties flowing on our lines.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
2006
|
|
2005
|
|
Variance
|
|
Change
|
|
Royalty Interest Gas Sales Volumes (Bcf)
|
|
|
7.6
|
|
|
|
6.6
|
|
|
|
1.0
|
|
|
|
15.2
|
%
|
Average Cost (per Mcf)
|
|
$
|
5.56
|
|
|
$
|
5.59
|
|
|
$
|
(0.03
|
)
|
|
|
(0.5
|
)%
|
Included in royalty interest gas costs are the expenses related
to the portion of production belonging to royalty interest
owners sold by CNX Gas on their behalf. The decrease in sales
price is a function of the average CNX Gas price, before the
effects of financial swap transactions, being higher in the
prior year than in the current year. Volumes increased as a
result of additional wells coming online from our on-going
drilling program.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
2006
|
|
2005
|
|
Variance
|
|
Change
|
|
Purchased Gas Cost Volumes (Bcf)
|
|
|
6.1
|
|
|
|
28.7
|
|
|
|
(22.6
|
)
|
|
|
(78.7
|
)%
|
Average Purchased Gas Costs (per Mcf)
|
|
$
|
7.34
|
|
|
$
|
9.71
|
|
|
$
|
(2.37
|
)
|
|
|
(24.4
|
)%
|
Included in purchased gas costs are volumes of gas we
simultaneously purchased from and sold to the same
counterparties between the segmentation and interruptible pools
on the Columbia pipeline in order to satisfy obligations to
certain customers. In accordance with Emerging Issues Task Force
Issue
No. 99-19
Reporting Revenue Gross as a Principal versus Net as an
Agent
(EITF 99-19),
we have historically recorded our revenues and our costs on a
gross basis. However, because we adopted
EITF 04-13
on January 1, 2006, purchased gas costs and volumes have
decreased. The net result for transactions that meet the above
criteria is reflected in transportation expense in the current
year.
Other costs and expenses decreased due to the following items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dollar
|
|
|
Percentage
|
|
|
|
2006
|
|
|
2005
|
|
|
Variance
|
|
|
Change
|
|
|
Exploration
|
|
$
|
2,708
|
|
|
$
|
1,830
|
|
|
$
|
878
|
|
|
|
48.0
|
%
|
Imbalance
|
|
|
(648
|
)
|
|
|
899
|
|
|
|
(1,547
|
)
|
|
|
(172.1
|
)%
|
Equity in (Earnings) Loss of Affiliates
|
|
|
(978
|
)
|
|
|
149
|
|
|
|
(1,127
|
)
|
|
|
(756.4
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Other Costs and Expenses
|
|
$
|
1,082
|
|
|
$
|
2,878
|
|
|
$
|
(1,796
|
)
|
|
|
(62.4
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration costs increased due to our on-going drilling program.
47
The gas imbalance has shifted from an under-delivered position
in 2005 to an over-delivered position in 2006, and therefore
resulted in income for 2006 compared to expense in 2005. 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 decrease in
imbalance cost was offset by corresponding decreases in gas
sales revenue.
Equity in (earnings) loss of affiliates improved in 2006
compared to 2005 because Knox Energy had higher earnings in 2006
compared to 2005 primarily due to production increases at the
joint venture and additional service revenue. Buchanan
Generation incurred losses that were higher in the current year
primarily due to the facility being run for less megawatt hours
in 2006 compared to 2005.
General and administrative costs increased to $39,168 in 2006
from $19,129 in 2005 primarily due to additional costs related
to becoming a separate publicly traded company as a result of
the separation of CNX Gas from CONSOL Energy. These increased
costs include additional staffing and facilities, incentive
compensation plans, stock option plans, legal and accounting
fees, Sarbanes-Oxley compliance fees, implementation fees for
the information management software platform and various other
service costs.
Depreciation, depletion and amortization have increased due to
the following items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dollar
|
|
|
Percentage
|
|
|
|
2006
|
|
|
2005
|
|
|
Variance
|
|
|
Change
|
|
|
Production
|
|
$
|
24,668
|
|
|
$
|
23,531
|
|
|
$
|
1,137
|
|
|
|
4.8
|
%
|
Gathering
|
|
|
13,331
|
|
|
|
11,508
|
|
|
|
1,823
|
|
|
|
15.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Depreciation, Depletion and Amortization
|
|
$
|
37,999
|
|
|
$
|
35,039
|
|
|
$
|
2,960
|
|
|
|
8.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The increase in production related depreciation, depletion and
amortization is due to the net effect of additional volumes in
the current year and a slightly lower unit-of-production rate in
2006 compared to 2005. Rates are generally calculated using the
net book value of assets on January 1st divided by
proved developed reserves. Gathering depreciation, depletion and
amortization is recorded on the straight-line method and
increased due to additional assets being placed in service in
2006, including the effect of the Jewell Ridge lateral.
Interest expense increased as a result of the imputed interest
associated with recording the Jewell Ridge lateral arrangement
as a capital lease for financial accounting and reporting
purposes.
Income
Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
|
2006
|
|
|
2005
|
|
|
Variance
|
|
|
Change
|
|
|
Earnings Before Income Taxes
|
|
$
|
256,440
|
|
|
$
|
166,718
|
|
|
$
|
89,722
|
|
|
|
53.8
|
%
|
Tax Expense
|
|
$
|
96,573
|
|
|
$
|
64,550
|
|
|
$
|
32,023
|
|
|
|
49.6
|
%
|
Effective Income Tax Rate
|
|
|
37.7
|
%
|
|
|
38.7
|
%
|
|
|
(1.0
|
)%
|
|
|
|
|
CNX Gas effective tax rate decreased in 2006 primarily due
to a reduction in state tax rates, discussed further in
Note 5 to the Consolidated Financial Statements.
Issues
Regarding Coal Mining Activities
A portion of our gas production is associated with coal mining
activities at CONSOL Energys Buchanan Mine. These mining
activities require the removal of water from the mine and the
ventilation of the mine. Several lawsuits and permit appeals
have been filed that could affect the removal of water from the
mine. Separately, a lawsuit has been filed with respect to a
ventilation fan that could affect the ventilation of the mine.
If operations at CONSOL Energys Buchanan Mine are
adversely affected as a result of these legal proceedings, our
gas production relating to mining activities would be adversely
affected.
48
Critical
Accounting Policies
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of
America 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.
Derivative
Instruments
CNX Gas enters into financial derivative instruments to manage
our exposure to natural gas and oil price volatility. Our
derivatives are accounted for under Statement of Financial
Accounting Standards No. 133, Accounting for
Derivative Instruments and Hedging Activities
(SFAS 133), as amended by Statement of Financial Accounting
Standards No. 138, Accounting for Certain Derivative
Instruments and Certain Hedging Activities-an amendment of FASB
Statement No. 133 (SFAS 138) and Statement
of Financial Accounting Standards No. 149, Amendment
of Statement 133 on Derivative Instruments and Hedging
Activities (SFAS 149).
We therefore measure every derivative instrument at fair value
and record them on the balance sheet as either an asset or
liability. Changes in fair value of derivatives are recorded
currently in earnings unless special hedge accounting criteria
are met. For derivatives designated as fair value hedges, the
changes in fair value of both the derivative instrument and the
hedged item are recorded in earnings. For derivatives designated
as cash flow hedges, the effective portions of changes in fair
value of the derivative are reported in other comprehensive
income or loss and reclassified into earnings in the same period
or periods which the forecasted transaction affects earnings.
The ineffective portions of hedges are recognized in earnings in
the current year. CNX Gas currently utilizes only cash flow
hedges that are considered highly effective.
CNX Gas formally assesses, both at inception of the hedge and on
an ongoing basis, whether each derivative is highly effective in
offsetting changes in fair values or cash flows of the hedged
item. If it is determined that a derivative is not highly
effective as a hedge or if a derivative ceases to be a highly
effective hedge, CNX Gas will discontinue hedge accounting
prospectively.
Stock-Based
Compensation
Effective January 1, 2006, CNX Gas adopted the fair value
recognition provisions of Statement of Financial Accounting
Standards No. 123(R), Share-Based Payment
(SFAS 123R), which requires the measurement and recognition
of compensation expense for all share-based payment awards based
on estimated fair values. We have selected the Black-Scholes
option pricing model to measure the fair value of our stock
options. This option pricing model takes into account variables
such as the Companys stock price, as well as assumptions
including the projected stock option exercise behaviors.
We adopted SFAS 123R using the modified prospective
transition method and therefore have not restated results for
prior periods. Under this transition method, stock-based
compensation expense for the year ended December 31, 2006
includes compensation expense for all stock-based compensation
awards granted prior to, but not yet vested as of
January 1, 2006, based on the grant date fair value
estimated in accordance with the original provisions of
SFAS No. 123, Accounting for Stock-Based
Compensation(SFAS 123). Stock-based
compensation expense for all stock-based compensation awards
granted after January 1, 2006 is based on the grant-date
fair value estimated in accordance with the provisions of
SFAS 123R.
In accordance with SFAS 123R, the value of the portion of
the award that is ultimately expected to vest is expensed by CNX
Gas on a straight-line basis over the requisite service period
of the award, which is
49
generally the option vesting term. The portion of the award that
is expected to vest is determined by employing an estimated
forfeiture rate at the time of the grant and revising such
estimate in future periods if actual forfeitures differ from
those estimates.
Prior to the adoption of SFAS 123R, CNX Gas recognized
stock-based compensation expense in accordance with Accounting
Principles Board Opinion No. 25. Accounting for Stock
Issued to Employees, (APB 25). In March 2005, the
Securities and Exchange Commission (the SEC) issued Staff
Accounting Bulletin No. 107
(SAB 107) regarding the SECs interpretation of
SFAS 123R and the valuation of share-based payments for
public companies. CNX Gas has applied the provisions of
SAB 107 in its adoption of SFAS 123R. See Note 13
to the Consolidated Financial Statements for a further
discussion on stock-based compensation.
CNX Gas also implemented a long-term incentive program effective
October 11, 2006. This program allows for the award of
performance share units (PSUs). A PSU represents a contingent
right to receive a cash payment, determined by reference to the
value of one share of the companys common stock. The total
number of units earned, if any, by a participant will be based
on the companys total stockholder return relative to the
stockholder return of a pre-determined peer group of companies.
The performance period is from October 11, 2006 to
December 31, 2009. CNX Gas recognizes compensation costs on
a straight-line basis over the requisite service period, based
on the fair value of the PSUs. The fair value of the PSUs will
be re-valued quarterly using a Monte Carlo lattice model.
Estimated
Net Recoverable Reserves
CNX Gas uses the successful efforts method to
account for its exploration and production activities. Under
this method, costs are accumulated on a field by field basis
with certain exploratory expenditures and exploratory dry holes
being expensed as incurred. Costs of productive wells and
development dry holes are capitalized and amortized on the
unit-of-production method. We use this accounting policy instead
of the full cost method because it provides a more
timely accounting of the success or failure of our exploration
and production activities.
Proved oil and gas reserves are defined by SEC
Regulation S-X
Rule 4-10(a)
2(i), 2(ii), 2(iii), (3), and (4) as the estimated
quantities of oil and natural gas that current geological and
engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions. These reserve estimates are
disclosed in accordance with SFAS No. 69,
Disclosures about Oil and Gas Producing Activities.
Our estimation of net recoverable reserves is a highly technical
process performed by in-house teams of reservoir engineers and
geoscience professionals. A third party consultant is also
engaged to prepare an independent reserve estimate for 100% of
our reserves. 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.
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.
Any significant variance in these assumptions could materially
affect the estimated quantity of our reserves. Likewise, because
estimates of reserves significantly impact the Companys
depreciation, depletion, and amortization (DD&A) expense, a
change in such estimates could have an impact on net income.
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
50
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.
Income
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, 2007, CNX Gas had deferred
tax liabilities in excess of deferred tax assets of
approximately $189,684. 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.
CNX Gas adopted the provisions of FASB Interpretation (FIN)
No. 48, Accounting for Uncertainty in Income
Taxes, on January 1, 2007. As a result of the
implementation of FIN No. 48, CNX Gas recognized
approximately a $53 net increase in the liability for
unrecognized tax benefits, which was accounted for as a
reduction to the January 1, 2007 balance of retained
earnings. As of December 31, 2007, CNX Gas does not
anticipate a significant change in our uncertain tax positions
or unrecognized tax benefits.
Asset
Retirement Obligations
We have significant obligations related to the closure of gas
wells upon exhaustion of gas reserves. We are required to
dismantle and remove equipment and restore land at the end of
our oil and gas production activities. Statement of Financial
Accounting Standards No. 143, Accounting for Asset
Retirement 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 fair value that is recorded is 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. Changes in the variables used to calculate the
liabilities can have a significant effect on the gas well
closing liabilities.
The present value of the estimated asset retirement costs is
capitalized as part of the carrying amount of the long-lived
asset. 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
$200,000 credit facility. Our credit agreement provides for a
revolving credit facility in an initial aggregate outstanding
principal amount of up to $200,000 (with the ability to request
an increase in the aggregate outstanding principal amount up to
$300,000), including borrowings and letters of credit. We may
use borrowings under the credit agreement for general corporate
purposes, including transaction fees, letters of credit,
acquisitions, capital expenditures and working capital. Our
obligations under our credit agreement are not secured by a lien
on our assets.
As a result of our status as a majority-owned subsidiary of
CONSOL Energy and having entered into a credit agreement with
third party commercial lenders, CNX Gas and its subsidiaries are
guarantors of CONSOL Energys 7.875% notes due
March 1, 2012 in the principal amount of approximately
$250,000,
51
which require all subsidiaries of CONSOL Energy that incur third
party debt to also guarantee the 7.875% notes. In addition,
if CNX Gas were to grant liens to a lender as part of a future
borrowing, the indenture governing the 7.875% notes
requires CNX Gas to ratably secure the notes.
We believe that cash generated from operations and borrowings
under our 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 asset of $9,619 at December 31, 2007.
The ineffective portion of the changes in the fair value of
these contracts was insignificant for the twelve months ended
December 31, 2007, 2006 and 2005, respectively.
Cash
Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Change
|
|
|
Cash provided by operating activities
|
|
$
|
272,448
|
|
|
$
|
243,569
|
|
|
$
|
28,879
|
|
Cash used in investing activities
|
|
$
|
(354,227
|
)
|
|
$
|
(156,020
|
)
|
|
$
|
(198,207
|
)
|
Cash provided by (used in) financing activities
|
|
$
|
6,654
|
|
|
$
|
(449
|
)
|
|
$
|
7,103
|
|
Our principal source of cash is our operating cash flow. Because
our operating cash flow is highly dependent on oil and gas
prices, as of December 31, 2007, we entered into hedging
agreements covering 24.5 Bcf, 12.7 Bcf, and
1.8 Bcf for 2008, 2009, and 2010, respectively. Capital
expenditures of $295,422 and the acquisition of mineral rights
of $61,777 in the year ended December 31, 2007 were funded
without using our credit facility. Based on anticipated oil and
gas futures prices and our current hedge position, the 2008
capital program is expected to be funded with internal cash flow
and our credit facility.
|
|
|
|
|
Cash provided by operating activities increased primarily
due to increased production and higher realized prices. These
increases are partially offset by increased operating costs and
various other working capital requirements.
|
|
|
|
Cash used in investing activities increased primarily due
to higher capital expenditures, which is a result of our
continuously expanding drilling program. The 2007 year also
included a $61,777 acquisition of mineral rights, as detailed
further in Note 2 to the Consolidated Financial Statements,
as well as capital expenditures of $8,034 related to our
variable interest entity.
|
|
|
|
Cash provided by (used in) financing activities increased
primarily due to $8,851 of debt proceeds from our variable
interest entity, partially offset by capital lease payments of
$2,552 related to the Jewell Ridge pipeline.
|
52
Contractual
Commitments
The following is a summary of our significant contractual
obligations at December 31, 2007 (in thousands). We
estimate payments related to these items, net of any applicable
reimbursements, at December 31, 2007 to be as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Within
|
|
|
1-3
|
|
|
3-5
|
|
|
More Than
|
|
|
|
|
|
|
1 Year
|
|
|
Years
|
|
|
Years
|
|
|
5 Years
|
|
|
Total
|
|
|
|
(Dollars in thousands)
|
|
|
Long Term Debt Obligations
|
|
$
|
3,051
|
|
|
$
|
5,800
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
8,851
|
|
Capital Lease Obligations
|
|
|
2,768
|
|
|
|
6,185
|
|
|
|
7,162
|
|
|
|
47,802
|
|
|
|
63,917
|
|
Interest on Capital Lease Obligation
|
|
|
4,612
|
|
|
|
8,575
|
|
|
|
7,598
|
|
|
|
17,333
|
|
|
|
38,118
|
|
Operating Lease Obligations
|
|
|
1,515
|
|
|
|
2,633
|
|
|
|
1,838
|
|
|
|
1,104
|
|
|
|
7,090
|
|
Gas Firm Transportation Obligations
|
|
|
7,870
|
|
|
|
14,379
|
|
|
|
9,948
|
|
|
|
17,095
|
|
|
|
49,292
|
|
Other Long-Term Liabilities(a)
|
|
|
118
|
|
|
|
582
|
|
|
|
936
|
|
|
|
19,058
|
|
|
|
20,694
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Contractual Obligations
|
|
$
|
19,934
|
|
|
$
|
38,154
|
|
|
$
|
27,482
|
|
|
$
|
102,392
|
|
|
$
|
187,962
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
This item includes asset retirement obligations, pension,
postretirement benefits other than pension and legal
contingencies, which are reflected on the balance sheet for the
potential settlements of the two cases referenced in
Note 17 to the Consolidated Financial Statements. Due to
the uncertainty surrounding these settlements, it is difficult
to predict if and when a payout may take place. |
|
(b) |
|
The significant obligation table does not include obligations to
taxing authorities due to the uncertainty surrounding the
ultimate settlement of amounts and timing of these obligations. |
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.
$200,000
Credit Facility
As described above, we and our wholly-owned subsidiaries are
party to a credit agreement dated as of October 7, 2005
with a group of commercial lenders. This credit agreement
provides for a revolving credit facility in an initial aggregate
outstanding principal amount of up to $200,000 with the ability
to request an increase in the aggregate outstanding principal
amount up to $300,000, 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. At December 31, 2007, our borrowing base is
reduced by $14,933 related to outstanding letters of credit,
leaving $185,067 of unused capacity.
Our ability to borrow and obtain letters of credit under the
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.
Stockholders
Equity
CNX Gas had stockholders equity of $1,023,000 at
December 31, 2007 and $880,000 at December 31, 2006.
The increase was primarily attributable to net income for the
year ended December 31, 2007, hedging gains, the
amortization of stock-based compensation awards, and the tax
benefit from stock-based compensation. This increase was
partially offset by changes to the actuarial long-term liability
gains and losses, and the cumulative effect of adopting FASB
Interpretation No. 48, Accounting for Uncertainty in
Income Taxes an interpretation of FASB Statement
109 (FIN 48). See Consolidated Statements of
Stockholders Equity in the Audited Consolidated Financial
Statements in Item 8 of this
Form 10-K.
53
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 December 2007, the Financial Accounting Standards Board
(FASB) issued Statement of Financial Accounting Standards
No. 141®,
Business Combinations (SFAS 141R), and
Statement of Financial Accounting Standards No. 160,
Accounting and Reporting of Noncontrolling Interest in
Consolidated Financial Statements, an amendment of ARB
No. 51 (SFAS 160). SFAS 141R and
SFAS 160 will significantly change the accounting for and
reporting of business combination transactions and
noncontrolling (minority) interests in consolidated financial
statements. SFAS 141R retains the fundamental requirements
in Statement 141 Business Combinations while
providing additional definitions, such as the definition of the
acquirer in a purchase and improvements in the application of
how the acquisition method is applied. SFAS 160 will change
the accounting and reporting for minority interests, which will
be recharacterized as noncontrolling interests, and classified
as a component of equity. These Statements become simultaneously
effective January 1, 2009. Early adoption is not permitted.
We are currently evaluating the impact this guidance will have
on our consolidated financial statements.
In February 2007, the Financial Accounting Standards Board
Issued Statement No. 159, The Fair Value Option for
Financial Assets and Financial Liabilities Including
an Amendment of FAS 115 (SFAS 159). This
Statement permits entities to choose to measure many financial
instruments and certain other items at fair value. The objective
is to improve financial reporting by providing entities with the
opportunity to mitigate volatility in reported earnings caused
by measuring related assets and liabilities differently without
having to apply complex hedge accounting provisions. This
Statement is effective as of the beginning of an entitys
first fiscal year that begins after November 15, 2007.
Early adoption is permitted as of the beginning of a fiscal year
that begins on or before November 15, 2007, provided the
entity also elects to apply the provisions of FASB Statement
No. 157, Fair Value Measurements. We do not expect
this guidance to have a significant impact on CNX Gas; however
management is currently assessing the impact of adopting
SFAS No. 159.
In September 2006, the FASB issued Statement of Financial
Accounting Standards No. 157, Fair Value
Measurements (SFAS 157), which defines fair value,
establishes a framework for measuring fair value in accordance
with accounting principles generally accepted in the United
States of America, and requires additional disclosures about
fair value measurements. SFAS 157 aims to improve the
consistency and comparability of fair value measurements by
creating a single definition of fair value. The Statement
emphasizes that fair value is not entity-specific, but instead
is a market-based measurement of an asset or liability.
SFAS 157 upholds the requirements of previously issued
pronouncements concerning fair value measurements and expands
the required disclosures. This Statement is effective for
financial statements issued for fiscal years beginning after
November 15, 2007, however earlier application is permitted
provided the reporting entity has not yet issued financial
statements for that fiscal year. We do not expect that this
guidance will have a significant impact on CNX Gas; however
management is currently assessing the impact of adopting
SFAS 157.
In September 2006, the FASB issued Statement of Financial
Accounting Standards No. 158, Employers
Accounting for Defined Benefit Pension and Other Postretirement
Plans (SFAS 158), which requires the recognition of
the funded status of defined benefit postretirement plans and
related disclosures. SFAS 158 was issued to address
concerns that prior standards on employers accounting for
defined benefit postretirement plans failed to communicate the
funded status of those plans in a complete and understandable
way and to require an employer to recognize completely in
earnings or other comprehensive income the financial impact of
certain events affecting the plans funded status when
those events occurred. This Statement is effective for financial
statements issued for fiscal years ending after
December 15, 2006. Additionally, SFAS 158 requires an
employer to measure the funded status of each of its plans as of
the date of its year-end statement of
54
financial position. This provision becomes effective for CNX Gas
for its December 31, 2008 year-end. The funded status
of CNX Gas pension and other postretirement benefit plans
are currently measured as of September 30.
|
|
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 purposes.
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 do 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 to the Consolidated Financial
Statements.
Sensitivity analyses of the incremental effects on pre-tax
income for the twelve months ended December 31, 2007 of a
hypothetical 10% and 25% change in natural gas prices for open
derivative instruments as of December 31, 2007 are provided
in the following table:
|
|
|
|
|
|
|
|
|
|
|
Incremental
|
|
|
Decrease
|
|
|
Assuming a
|
|
|
Hypothetical
|
|
|
Price Increase
|
|
|
of:
|
|
|
10%
|
|
25%
|
|
|
(Dollars in millions)
|
|
Pre-Tax Income(1)
|
|
$
|
25.4
|
|
|
$
|
64.1
|
|
|
|
|
(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 2008 through 2009
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, 2007, the fair value of these contracts was a
net gain of $5,881 (net of $3,738 deferred tax). We will
continually evaluate the portfolio of derivative commodity
instruments and adjust the strategy to anticipated market
conditions and risks accordingly. |
55
Hedging
Volumes
As of February 15, 2008, our hedged volumes for the periods
indicated are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Three Months
|
|
|
Three Months
|
|
|
Three Months
|
|
|
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
|
|
|
March 31,
|
|
|
June 30,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
Total Year
|
|
|
2008 Fixed Price Volumes Hedged Mcf
|
|
|
6,097,938
|
|
|
|
6,097,938
|
|
|
|
6,164,948
|
|
|
|
6,164,948
|
|
|
|
24,525,772
|
|
Weighted Average Hedge Price/Mcf
|
|
$
|
8.39
|
|
|
$
|
8.24
|
|
|
$
|
8.29
|
|
|
$
|
8.29
|
|
|
$
|
8.30
|
|
2009 Fixed Price Volumes Hedged Mcf
|
|
|
4,175,258
|
|
|
|
2,814,433
|
|
|
|
2,845,361
|
|
|
|
2,845,361
|
|
|
|
12,680,413
|
|
Weighted Average Hedge Price/Mcf
|
|
$
|
8.82
|
|
|
$
|
8.35
|
|
|
$
|
8.39
|
|
|
$
|
8.52
|
|
|
$
|
8.55
|
|
2010 Fixed Price Volumes Hedged Mcf
|
|
|
1,824,742
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,824,742
|
|
Weighted Average Hedge Price/Mcf
|
|
$
|
8.78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
8.78
|
|
CNX Gas is exposed to credit risk in the event of nonperformance
by counterparties. The creditworthiness of counterparties is
subject to continuing review.
All CNX Gas transactions are denominated in U.S. dollars,
and as a result, we do not have material exposure to currency
exchange-rate risks.
A change in interest rates does not have a material impact on
CNX Gas as a result of no borrowings against the credit facility.
56
|
|
ITEM 8.
|
FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
|
|
|
|
|
|
|
|
Page
|
|
Financial Statements
|
|
|
|
|
|
|
|
58
|
|
|
|
|
59
|
|
|
|
|
60
|
|
|
|
|
61
|
|
|
|
|
62
|
|
|
|
|
63
|
|
57
Report of
Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of CNX Gas
Corporation:
In our opinion, the consolidated financial statements listed in
the accompanying index present fairly, in all material respects,
the financial position of CNX Gas Corporation and its
subsidiaries (CNX Gas) at December 31, 2007 and
2006, and the results of their operations and their cash flows
for each of the three years in the period ended
December 31, 2007 in conformity with accounting principles
generally accepted in the United States of America. Also in our
opinion, CNX Gas maintained, in all material respects, effective
internal control over financial reporting as of
December 31, 2007, based on criteria established in
Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). CNX Gas management is responsible for
these financial statements, for maintaining effective internal
control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting,
included in Managements Report on Internal Control Over
Financial Reporting appearing under Item 9A. Our
responsibility is to express opinions on these financial
statements and on CNX Gas internal control over financial
reporting based on our audits which were integrated audits in
2007 and 2006. We conducted our audits in accordance with the
standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and
perform the audits to obtain reasonable assurance about whether
the financial statements are free of material misstatement and
whether effective internal control over financial reporting was
maintained in all material respects. Our audits of the financial
statements included 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. Our audit of internal
control over financial reporting included obtaining an
understanding of internal control over financial reporting,
assessing the risk that a material weakness exists, and testing
and evaluating the design and operating effectiveness of
internal control based on the assessed risk. Our audits also
included performing such other procedures as we considered
necessary in the circumstances. We believe that our audits
provide a reasonable basis for our opinions.
As discussed in Note 1 to the consolidated financial
statements, CNX Gas changed the manner in which it accounts for
stock based compensation; defined benefit pension, other
postretirement benefit plans, and other employee benefits; and
purchases and sales of gas with the same counterparty in 2006.
A companys internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A companys
internal control over financial reporting includes those
policies and procedures that (i) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (ii) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the
company are being made only in accordance with authorizations of
management and directors of the company; and (iii) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers
LLP
Pittsburgh, Pennsylvania
February 15, 2008
58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Twelve Months Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands, except per share data)
|
|
|
Revenue and Other Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Outside Sales
|
|
$
|
404,835
|
|
|
$
|
385,056
|
|
|
$
|
277,031
|
|
Related Party Sales
|
|
|
11,618
|
|
|
|
8,490
|
|
|
|
6,052
|
|
Royalty Interest Gas Sales
|
|
|
46,586
|
|
|
|
51,054
|
|
|
|
45,351
|
|
Purchased Gas Sales
|
|
|
7,628
|
|
|
|
43,973
|
|
|
|
275,148
|
|
Other Income
|
|
|
6,641
|
|
|
|
25,286
|
|
|
|
9,859
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenue and Other Income
|
|
|
477,308
|
|
|
|
513,859
|
|
|
|
613,441
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lifting Costs
|
|
|
38,721
|
|
|
|
33,357
|
|
|
|
30,399
|
|
Gathering and Compression Costs
|
|
|
61,798
|
|
|
|
58,102
|
|
|
|
43,903
|
|
Royalty Interest Gas Costs
|
|
|
40,011
|
|
|
|
41,998
|
|
|
|
36,641
|
|
Purchased Gas Costs
|
|
|
7,162
|
|
|
|
44,843
|
|
|
|
278,720
|
|
Other
|
|
|
79
|
|
|
|
1,082
|
|
|
|
2,878
|
|
General and Administrative
|
|
|
54,825
|
|
|
|
39,168
|
|
|
|
19,129
|
|
Depreciation, Depletion and Amortization
|
|
|
48,961
|
|
|
|
37,999
|
|
|
|
35,039
|
|
Interest Expense
|
|
|
5,606
|
|
|
|
870
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Costs and Expenses
|
|
|
257,163
|
|
|
|
257,419
|
|
|
|
446,723
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Before Income Taxes and Minority Interest
|
|
|
220,145
|
|
|
|
256,440
|
|
|
|
166,718
|
|
Minority Interest
|
|
|
494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Before Income Taxes
|
|
|
220,639
|
|
|
|
256,440
|
|
|
|
166,718
|
|
Income Taxes
|
|
|
84,961
|
|
|
|
96,573
|
|
|
|
64,550
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
135,678
|
|
|
$
|
159,867
|
|
|
$
|
102,168
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.90
|
|
|
$
|
1.06
|
|
|
$
|
0.76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.90
|
|
|
$
|
1.06
|
|
|
$
|
0.76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Number of Common Shares Outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
150,886,433
|
|
|
|
150,845,518
|
|
|
|
134,071,334
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dilutive
|
|
|
151,133,520
|
|
|
|
151,017,456
|
|
|
|
134,137,219
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
59
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars in thousands)
|
|
|
ASSETS
|
Current Assets:
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents
|
|
$
|
32,048
|
|
|
$
|
107,173
|
|
Accounts Receivable:
|
|
|
|
|
|
|
|
|
Trade
|
|
|
38,680
|
|
|
|
46,062
|
|
Net Related Party
|
|
|
1,022
|
|
|
|
2,745
|
|
Other
|
|
|
1,406
|
|
|
|
2,291
|
|
Derivatives
|
|
|
10,711
|
|
|
|
10,548
|
|
Recoverable Income Taxes
|
|
|
972
|
|
|
|
|
|
Other Current Assets
|
|
|
3,148
|
|
|
|
3,917
|
|
|
|
|
|
|
|
|
|
|
Total Current Assets
|
|
|
87,987
|
|
|
|
172,736
|
|
Property, Plant and Equipment, Net
|
|
|
1,254,906
|
|
|
|
918,162
|
|
Other Assets
|
|
|
9,526
|
|
|
|
11,820
|
|
Investments in Equity Affiliates
|
|
|
28,284
|
|
|
|
52,283
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
1,380,703
|
|
|
$
|
1,155,001
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
Accounts Payable
|
|
$
|
30,263
|
|
|
$
|
27,872
|
|
Accrued Royalties Payable
|
|
|
12,896
|
|
|
|
11,960
|
|
Accrued Severance Taxes
|
|
|
2,620
|
|
|
|
2,576
|
|
Accrued Income Taxes
|
|
|
|
|
|
|
2,191
|
|
Deferred Taxes
|
|
|
1,269
|
|
|
|
3,091
|
|
Current Portion of Long-term Debt
|
|
|
5,819
|
|
|
|
2,573
|
|
Other Current Liabilities
|
|
|
9,817
|
|
|
|
6,649
|
|
|
|
|
|
|
|
|
|
|
Total Current Liabilities
|
|
|
62,684
|
|
|
|
56,912
|
|
Long-Term Debt
|
|
|
66,949
|
|
|
|
63,897
|
|
Deferred Credits and Other Liabilities:
|
|
|
|
|
|
|
|
|
Deferred Taxes
|
|
|
188,415
|
|
|
|
120,008
|
|
Other Liabilities
|
|
|
30,965
|
|
|
|
15,977
|
|
Asset Retirement Obligations
|
|
|
3,981
|
|
|
|
9,214
|
|
Derivatives
|
|
|
1,092
|
|
|
|
6,465
|
|
Postretirement Benefits Other Than Pension
|
|
|
2,700
|
|
|
|
2,313
|
|
|
|
|
|
|
|
|
|
|
Total Deferred Credits and Other Liabilities
|
|
|
227,153
|
|
|
|
153,977
|
|
Minority Interest
|
|
|
680
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Minority Interest
|
|
|
357,466
|
|
|
|
274,786
|
|
|
|
|
|
|
|
|
|
|
Stockholders Equity
|
|
|
|
|
|
|
|
|
Common Stock, $.01 par value; 200,000,000 Shares
Authorized, 150,915,198 Issued and Outstanding at
December 31, 2007 and 150,864,075 Issued and Outstanding at
December 31, 2006
|
|
|
1,509
|
|
|
|
1,508
|
|
Capital in Excess of Par Value
|
|
|
785,575
|
|
|
|
781,960
|
|
Retained Earnings
|
|
|
229,962
|
|
|
|
94,337
|
|
Accumulated Other Comprehensive Income
|
|
|
6,191
|
|
|
|
2,410
|
|
|
|
|
|
|
|
|
|
|
Total Stockholders Equity
|
|
|
1,023,237
|
|
|
|
880,215
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND STOCKHOLDERS EQUITY
|
|
$
|
1,380,703
|
|
|
$
|
1,155,001
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
Unearned
|
|
|
|
|
|
|
|
|
|
Capital In
|
|
|
Retained
|
|
|
Other
|
|
|
Compensation
|
|
|
Total
|
|
|
|
Common
|
|
|
Excess of
|
|
|
Earnings
|
|
|
Comprehensive
|
|
|
on Restricted
|
|
|
Stockholders
|
|
|
|
Stock
|
|
|
Par Value
|
|
|
(Deficit)
|
|
|
Income (Loss)
|
|
|
Stock Units
|
|
|
Equity
|
|
|
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
|
|
|
|
|
|
Balance at December 31, 2004
|
|
$
|
|
|
|
$
|
215,710
|
|
|
$
|
252,469
|
|
|
$
|
(5,623
|
)
|
|
$
|
|
|
|
$
|
462,556
|
|
Net Income
|
|
|
|
|
|
|
|
|
|
|
102,168
|
|
|
|
|
|
|
|
|
|
|
|
102,168
|
|
Gas Cash Flow Hedge (Net of $18,542 tax)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(29,110
|
)(a)
|
|
|
|
|
|
|
(29,110
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
102,168
|
|
|
|
(29,110
|
)
|
|
|
|
|
|
|
73,058
|
|
Issuance of Common Stock
|
|
|
1,508
|
|
|
|
418,659
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
420,167
|
|
Effect of Tax Basis
Step-up
|
|
|
|
|
|
|
165,042
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
165,042
|
|
Issuance of Restricted Stock units under the Equity Incentive
Plan (92,969 units)
|
|
|
|
|
|
|
1,487
|
|
|
|
|
|
|
|
|
|
|
|
(1,487
|
)
|
|
|
|
|
Stock-Based Compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
205
|
|
|
|
205
|
|
Dividends paid
|
|
|
|
|
|
|
|
|
|
|
(420,167
|
)
|
|
|
|
|
|
|
|
|
|
|
(420,167
|
)
|
Return of Capital to Parent
|
|
|
|
|
|
|
(21,389
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(21,389
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2005
|
|
|
1,508
|
|
|
|
779,509
|
|
|
|
(65,530
|
)
|
|
|
(34,733
|
)
|
|
|
(1,282
|
)
|
|
|
679,472
|
|
Net Income
|
|
|
|
|
|
|
|
|
|
|
159,867
|
|
|
|
|
|
|
|
|
|
|
|
159,867
|
|
Gas Cash Flow Hedge (Net of $23,859 tax)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36,382
|
(b)
|
|
|
|
|
|
|
36,382
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
159,867
|
|
|
|
36,382
|
|
|
|
|
|
|
|
196,249
|
|
Initial adjustment upon adoption of FAS 158 (net of $485
tax)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
761
|
|
|
|
|
|
|
|
761
|
|
Elimination of Unearned Compensation on Restricted Stock Units
|
|
|
|
|
|
|
(1,282
|
)
|
|
|
|
|
|
|
|
|
|
|
1,282
|
|
|
|
|
|
Stock-Based Compensation
|
|
|
|
|
|
|
3,733
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,733
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2006
|
|
|
1,508
|
|
|
|
781,960
|
|
|
|
94,337
|
|
|
|
2,410
|
(c)
|
|
|
|
|
|
|
880,215
|
|
Net Income
|
|
|
|
|
|
|
|
|
|
|
135,678
|
|
|
|
|
|
|
|
|
|
|
|
135,678
|
|
Gas Cash Flow Hedge (Net of $2,145 tax)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,214
|
(d)
|
|
|
|
|
|
|
4,214
|
|
FAS 158 OPEB Adjustment (Net of $190 tax)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(296
|
)
|
|
|
|
|
|
|
(296
|
)
|
FAS 158 Pension Adjustment (Net of $88 tax)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(137
|
)
|
|
|
|
|
|
|
(137
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
135,678
|
|
|
|
3,781
|
|
|
|
|
|
|
|
139,459
|
|
FASB Interpretation No. 48 Adoption
|
|
|
|
|
|
|
|
|
|
|
(53
|
)
|
|
|
|
|
|
|
|
|
|
|
(53
|
)
|
Stock Options Exercised
|
|
|
1
|
|
|
|
302
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
303
|
|
Tax Benefit from Stock-Based Compensation
|
|
|
|
|
|
|
53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
53
|
|
Amortization of Restricted Stock Unit Grants
|
|
|
|
|
|
|
653
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
653
|
|
Amortization of Stock Option Grants
|
|
|
|
|
|
|
2,607
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,607
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007
|
|
$
|
1,509
|
|
|
$
|
785,575
|
|
|
$
|
229,962
|
|
|
$
|
6,191
|
(e)
|
|
$
|
|
|
|
$
|
1,023,237
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Of the ($29,110) net change in accumulated other comprehensive
income (loss) in the period, ($30,948) represents the
settlements recognized in net income. |
|
(b) |
|
Of the $36,382 net change in accumulated other
comprehensive income (loss) in the period, $18,148 represents
the settlements recognized in net income. |
|
(c) |
|
Comprised of unrealized transition adjustments of $592 OPEB
revaluation and $169 Pension revaluation. Also, $1,649 of
deferred net gains on financial instruments. |
|
(d) |
|
Of the $4,214 net change in accumulated other comprehensive
income in the period, $18,904 represents the settlements
recognized in net income. |
|
(e) |
|
Comprised of unrealized transition adjustments of $296 OPEB
revaluation and $32 Pension revaluation. Also, $5,863 of
deferred net gains on financial instruments. |
The accompanying notes are an integral part of these
consolidated financial statements.
61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Twelve Months
|
|
|
|
Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands)
|
|
|
Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
135,678
|
|
|
$
|
159,867
|
|
|
$
|
102,168
|
|
Adjustments to Reconcile Net Income to Net Cash Provided By
Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, Depletion and Amortization
|
|
|
48,961
|
|
|
|
37,999
|
|
|
|
35,039
|
|
Compensation from Restricted Stock Unit Grants
|
|
|
653
|
|
|
|
529
|
|
|
|
205
|
|
Compensation from Stock Option Grants
|
|
|
2,607
|
|
|
|
3,204
|
|
|
|
|
|
Minority Interest
|
|
|
494
|
|
|
|
|
|
|
|
|
|
Deferred Income Taxes
|
|
|
70,352
|
|
|
|
60,358
|
|
|
|
46,779
|
|
Equity in (Income) Loss of Affiliates
|
|
|
(2,174
|
)
|
|
|
(978
|
)
|
|
|
149
|
|
Changes in Operating Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts and Notes Receivable
|
|
|
8,267
|
|
|
|
(6,682
|
)
|
|
|
(40,236
|
)
|
Related Party Receivable
|
|
|
1,723
|
|
|
|
(2,017
|
)
|
|
|
(728
|
)
|
Other Current Assets
|
|
|
770
|
|
|
|
(2,284
|
)
|
|
|
3,542
|
|
Changes in Other Assets
|
|
|
2,294
|
|
|
|
83
|
|
|
|
(4,951
|
)
|
Changes in Operating Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts Payable
|
|
|
2,732
|
|
|
|
(7,343
|
)
|
|
|
(8,936
|
)
|
Income Taxes
|
|
|
(4,171
|
)
|
|
|
(3,327
|
)
|
|
|
5,650
|
|
Other Current Liabilities
|
|
|
3,193
|
|
|
|
2,552
|
|
|
|
14,861
|
|
Changes in Other Liabilities
|
|
|
1,474
|
|
|
|
1,668
|
|
|
|
(8,600
|
)
|
Other
|
|
|
(405
|
)
|
|
|
(60
|
)
|
|
|
55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by Operating Activities
|
|
|
272,448
|
|
|
|
243,569
|
|
|
|
144,997
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures
|
|
|
(357,199
|
)
|
|
|
(154,243
|
)
|
|
|
(110,752
|
)
|
Investment in Equity Affiliates
|
|
|
2,785
|
|
|
|
(1,777
|
)
|
|
|
2,465
|
|
Proceeds from Sales of Assets
|
|
|
187
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used in Investing Activities
|
|
|
(354,227
|
)
|
|
|
(156,020
|
)
|
|
|
(108,287
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Lease Payments
|
|
|
(2,552
|
)
|
|
|
(449
|
)
|
|
|
|
|
Debt Proceeds
|
|
|
8,851
|
|
|
|
|
|
|
|
|
|
Exercise of Stock Options
|
|
|
302
|
|
|
|
|
|
|
|
|
|
Tax Benefit from Stock Based Compensation
|
|
|
53
|
|
|
|
|
|
|
|
|
|
Issuance of Common Stock
|
|
|
|
|
|
|
|
|
|
|
420,167
|
|
Dividends Paid
|
|
|
|
|
|
|
|
|
|
|
(420,167
|
)
|
Payments to Parent
|
|
|
|
|
|
|
|
|
|
|
(16,640
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by (Used in) Financing Activities
|
|
|
6,654
|
|
|
|
(449
|
)
|
|
|
(16,640
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(75,125
|
)
|
|
|
87,100
|
|
|
|
20,070
|
|
Cash and Cash Equivalents at Beginning of Year
|
|
|
107,173
|
|
|
|
20,073
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents at Year End
|
|
$
|
32,048
|
|
|
$
|
107,173
|
|
|
$
|
20,073
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
See Note 14 Supplemental Cash Flow Information
62
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL STATEMENTS
(Dollars
in thousands)
|
|
Note 1
|
Significant
Accounting Policies:
|
As of December 31, 2004, CNX Gas was not a legal entity and
there were no outstanding shares of common stock. However,
carved out financial statements were prepared in accordance with
Regulation S-X Article 3 General instructions as to
financial statements and SAB Topic 1-B1 Costs
reflected in historical financial statements and are
presented for comparative purposes. Shares of CNX Gas common
stock were not issued until 2005. As of January 19, 2006,
CNX Gas became a publicly traded company (trading under the
symbol CXG on the NYSE) operating in the energy sector.
A summary of the significant accounting policies of CNX Gas is
presented below. These, together with the other notes that
follow, are an integral part of the consolidated financial
statements.
Basis
of Consolidation
The consolidated financial statements of CNX Gas include the
accounts of majority-owned and controlled subsidiaries. As
defined by FASB Interpretation (FIN) No. 46,
Consolidation of Variable Interest Entities-an
Interpretation of ARB No. 51, and related
interpretations, the accounts of variable interest entities
(VIEs) where CNX Gas is the primary beneficiary are included in
the consolidated financial statements. We are the primary
beneficiary of one variable interest entity, a third party
drilling contractor, where CNX Gas guarantees certain debt and
is the primary customer of that entity. For further information
regarding this VIE, see our disclosures within Note 17 to
the Consolidated Financial Statements. Investments in business
entities in which CNX Gas does not have control, but has the
ability to exercise significant influence over the operating and
financial policies, are either proportionately consolidated or
accounted for under the equity method. All significant
intercompany transactions and accounts have been eliminated in
consolidation.
CNX Gas uses the equity method of accounting for our 50%
ownership in Coalfield Pipeline Company and Buchanan Generation,
LLC. As of December 2007, we proportionately consolidate our
working interest in Knox Energy.
Use of
Estimates
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions
that affect the reported amounts of assets, liabilities,
revenues and expenses, and various disclosures. Actual results
could differ from those estimates. The most significant
estimates included in the preparation of the financial
statements are related to derivative instruments, contingencies,
net recoverable reserves, asset retirement obligations, income
taxes, and stock based compensation.
Cash
and Cash Equivalents
Cash and cash equivalents include cash on hand and in financial
institutions as well as all highly liquid short-term securities
with original maturities of three months or less. As indicated
on the cash flow statement, all cash transactions prior to
separation from CONSOL Energy were considered either capital
contributions or return of capital.
Trade
Accounts Receivable
Trade accounts receivable are recorded at the invoiced amount
and do not bear interest. CNX Gas reserves for specific accounts
receivable when it is probable that all or a part of an
outstanding balance will not be collected. CNX Gas regularly
reviews collectibility and establishes or adjusts the allowance
as necessary using the specific identification method. Account
balances are charged off against the allowance
63
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
after all means of collection have been exhausted and the
potential for recovery is considered remote. There were no
reserves for uncollectible amounts in the periods presented.
Property,
Plant and Equipment
CNX Gas follows the successful efforts method of accounting for
gas properties. Accordingly, costs of property acquisitions,
successful exploratory wells, development wells and related
support equipment and facilities are capitalized. Costs of
unsuccessful exploratory wells are expensed when such wells are
determined to be non-productive, or if the determination cannot
be made after finding sufficient quantities of reserves to
continue evaluating the viability of the project. Planned
maintenance costs which do not extend the useful lives of
existing plant and equipment are expensed as incurred.
Upon the sale or retirement of a complete or partial unit of
proved property, the cost and related accumulated depletion are
eliminated from the property accounts, and the resultant gain or
loss is recognized in other income.
CNX Gas computes depreciation on gathering assets using the
straight line method over their estimated economic lives, which
range from
30-40 years.
CNX Gas amortizes acquisition costs on proved gas properties and
mineral interests using the ratio of current production to the
estimated aggregate proved gas reserves. Wells and related
equipment and intangible drilling costs are amortized on a units
of production method using the ratio of current production to
the estimated aggregate proved developed gas reserves.
Units-of-production amortization rates are revised whenever
there is an indication of the need for revision, but at least
once a year, and accounted for prospectively.
Costs for purchased and internally developed software are
expensed until it has been determined that the software will
result in probable future economic benefits and management has
committed to funding the project. Thereafter, all direct costs
of materials and services incurred in developing or obtaining
software, including certain payroll and benefit costs of
employees associated with the project, are capitalized and
amortized using the straight-line method over the estimated
useful life which does not exceed 7 years.
Impairment
of Long-Lived Assets
Impairment of long-lived assets is recorded when indicators of
impairment are present and the undiscounted cash flows estimated
to be generated by those assets are less than the assets
carrying value. The carrying value of the assets is then reduced
to their estimated fair value which is usually measured based on
an estimate of future discounted cash flows. Impairment of
equity investments is recorded when indicators of impairment are
present and the estimated fair value of the investment is less
than the assets carrying value. There were no impairment
losses during the periods presented in the Consolidated
Financial Statements.
Income
Taxes
CNX Gas is included in the consolidated federal income tax
return of CONSOL Energy. Income taxes are calculated as if CNX
Gas files a tax return on a separate company basis. Deferred tax
assets and liabilities are recognized for the expected future
tax consequences of events that have been recognized in CNX
Gas financial statements or separate tax return that would
be filed on a separate company basis. Deferred taxes result from
differences between the financial and tax bases of CNX Gas
assets and liabilities and are adjusted for changes in tax rates
and tax laws when changes are enacted. Valuation allowances are
recorded to reduce deferred tax assets where it is more likely
than not that a deferred tax benefit will not be realized.
Separate company state tax returns are filed in those states in
which CNX Gas is registered to do business.
In July 2006, the Financial Accounting Standards Board (FASB)
released FASB Interpretation No. 48, Accounting for
Uncertainty in Income Taxes an interpretation of
FASB Statement 109 (FIN 48). FIN 48 provides a
model for how a company should recognize, measure, present and
disclose in its financial
64
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
statements uncertain tax positions that it has taken or expects
to take on a tax return. FIN 48 was effective for CNX Gas
on January 1, 2007. The adoption of FIN 48 did not
have a material impact on CNX Gas consolidated financial
statements.
Asset
Retirement Obligations
CNX Gas accrues for dismantling and removing costs of gas
related facilities using the accounting treatment prescribed by
Statement of Financial Accounting Standards No. 143,
Accounting for Asset Retirement Obligations
(SFAS No. 143). This statement requires 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. Depreciation of the capitalized asset
retirement cost is generally determined on a units-of-production
basis. Accretion of the asset retirement obligation is
recognized over time and generally will escalate over the life
of the producing asset, typically as production declines. Asset
retirement obligations primarily relate to the plugging of gas
wells upon exhaustion of the gas reserves.
Accrued costs of dismantling and removing gas related facilities
are regularly reviewed by management and are revised for changes
in future estimated costs and regulatory requirements.
Revenue
Recognition
Sales are recognized when title passes to the customers. This
occurs at the contractual point of delivery.
We have an operational gas balancing agreement with Columbia
pipeline. 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.
Included in royalty interest gas sales are the revenues related
to the portion of production associated with royalty interest
owners.
CNX Gas sells gas to accommodate the delivery points of its
customers. In general, this gas is purchased at market price and
re-sold on the same day at market price less a small transaction
fee. Matching buy/sell gas transactions settled in cash which do
not meet the requirements for netting under EITF No. 04-13,
Accounting for Purchases and Sales of Inventory with the
Same Counter-Party, are recorded in both revenues and
costs of revenues as separate sales and purchase transactions.
CNX Gas also provides gathering services to third parties by way
of matching buy/sell transactions. These revenues and expenses
are recorded gross in the consolidated statement of income and
recognized immediately in earnings.
Royalty
Recognition
Royalty costs for gas rights are included in royalty interest
gas costs when the related revenue for the gas sale is
recognized. These royalty costs are paid in cash in accordance
with the terms of each agreement. Revenues for gas sold related
to production under royalty contracts, versus owned by CNX Gas,
are separately identified and recorded on a gross basis. The
recognized revenues for these transactions are not net of
related royalty fees.
Contingencies
CNX Gas and our subsidiaries from time to time are subject to
various lawsuits and claims with respect to such matters as
personal injury, wrongful death, damage to property, exposure to
hazardous substances, governmental regulations including
environmental remediation, employment and contract disputes, and
other claims and actions, arising out of the normal course of
business. Liabilities are recorded when it is probable that
obligations have been incurred and the amounts can be reasonably
estimated. Estimates are developed
65
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
through consultation with legal counsel involved in the defense
and are based upon an analysis of potential results, assuming a
combination of litigation and settlement strategies.
Environmental liabilities are not discounted or reduced by
possible recoveries from third parties. Legal fees associated
with defending these various lawsuits and claims are expensed
when incurred.
Derivative
Instruments
CNX Gas accounts for derivative instruments in accordance with
Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging
Activities, (SFAS No. 133) and its
corresponding amendments under SFAS No. 138,
Accounting for Certain Derivative Instruments and Certain
Hedging Activities an amendment of FASB Statement
No. 133 (SFAS No. 133). CNX Gas measures
every derivative instrument (including certain derivative
instruments embedded in other contracts) at fair value and
records them on the balance sheet as either an asset or
liability. Changes in fair value of derivatives are recorded
currently in earnings unless special hedge accounting criteria
are met. For derivatives designated as cash flow hedges, the
effective portions of changes in fair value of the derivative
are reported in other comprehensive income or loss and
reclassified into earnings in the same period or periods which
the forecasted transaction affects earnings. The ineffective
portions of hedges are recognized in earnings in the current
year. CNX Gas only engages in cash flow hedges.
CNX Gas formally assesses, both at inception of the hedge and on
an ongoing basis, whether each derivative is highly effective in
offsetting changes in fair values or cash flows of the hedged
item. If it is determined that a derivative is not highly
effective as a hedge or if a derivative ceases to be a highly
effective hedge, CNX Gas will discontinue hedge accounting
prospectively.
Stock-Based
Compensation
Effective January 1, 2006, CNX Gas adopted the fair value
recognition provisions of Statement of Financial Accounting
Standards No. 123(R), Share-Based Payment
(SFAS 123R), using the modified prospective transition
method and therefore has not restated results for prior periods.
Under this transition method, stock-based compensation expense
for the year ended December 31, 2007 and 2006 includes
compensation expense for all stock-based compensation awards
granted prior to, but not yet vested as of January 1, 2006,
based on the grant date fair value estimated in accordance with
the original provisions of SFAS No. 123,
Accounting for Stock-Based Compensation
(SFAS 123). Stock-based compensation expense for all
stock-based compensation awards granted after January 1,
2006 is based on the grant-date fair value estimated in
accordance with the provisions of SFAS 123R. CNX Gas
recognizes these compensation costs on a straight-line basis
over the requisite service period of the award, which is
generally the option vesting term. Prior to the adoption of
SFAS 123R, CNX Gas recognized stock-based compensation
expense in accordance with Accounting Principles Board Opinion
No. 25. Accounting for Stock Issued to
Employees, (APB 25). In March 2005, the Securities and
Exchange Commission (the SEC) issued Staff Accounting
Bulletin No. 107 (SAB 107) regarding the
SECs interpretation of SFAS 123R and the valuation of
share-based payments for public companies. CNX Gas has applied
the provisions of SAB 107 in its adoption of
SFAS 123R. See Note 13 to the Consolidated Financial
Statements for a further discussion on stock-based compensation.
Earnings
Per Share
On June 21, 2005, the Board of Directors of CONSOL Energy
authorized the incorporation of CNX Gas. On June 30, 2005,
CNX Gas was incorporated and issued 100 shares of its
$0.01 par value common stock to Consolidation Coal Company,
a wholly-owned subsidiary of CONSOL Energy. CNX Gas was
incorporated to conduct CONSOL Energys gas exploration and
production activities. In August 2005, CONSOL Energy contributed
or leased substantially all of the assets of its gas business,
including all of CONSOL Energys rights to CBM associated
with 4.5 billion tons of coal reserves owned or controlled
by CONSOL Energy as
66
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
well as all of CONSOL Energys rights to conventional gas.
In exchange for its contribution of assets, CONSOL Energy
received approximately 122.9 million shares of CNX Gas
common stock. CNX Gas entered into various agreements with
CONSOL Energy that will define various operating and service
relationships between the two companies.
In August 2005, CNX Gas entered into an agreement to sell
approximately 24.3 million shares in a private transaction
and granted a
30-day
option to purchase an additional 3.6 million shares. In
August 2005, CNX Gas closed on the sale of all 27.9 million
shares. The shares were sold to qualified institutional, foreign
and accredited investors in a private transaction exempt from
registration under Rule 144A, Regulation S and
Regulation D. The proceeds (approximately $420,167, which
includes proceeds from the additional 3.6 million shares) were
used to pay a special dividend to Consolidation Coal Company. In
addition, CONSOL Energy paid approximately $6,000 in expenses
related to this transaction. Later, in August 2005, a
Registration Statement on
Form S-1
was filed with the SEC with respect to those shares. The
registration statement was declared effective on
January 18, 2006. A post-effective amendment to the
registration statement was declared effective on
September 11, 2007, which amendment deregistered all shares
remaining unsold pursuant to that registration statement.
Basic earnings per share are computed by dividing net income by
the weighted average shares outstanding during the twelve months
ended December 31, 2007, 2006 and 2005. Diluted earnings
per share are calculated using the treasury stock method, which
assumes outstanding stock options were exercised and restricted
stock units were converted into shares and the proceeds from
such activity were used to acquire shares of common stock at the
average market price during the reporting period. The dilutive
effect is calculated in a manner similar to the calculation of
basic earnings per share, except that the weighted average
shares outstanding are increased to include additional shares
from the assumed exercise of stock options, if dilutive, and the
assumed redemption of restricted stock units. Options to
purchase 490,056 and 479,065 shares of common stock
outstanding for the twelve month periods ending
December 31, 2007 and 2006, respectively, were not included
in the computation of diluted earnings per share because the
effect would be anti-dilutive.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Twelve Months
|
|
|
|
Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Net Income
|
|
$
|
135,678
|
|
|
$
|
159,867
|
|
|
$
|
102,168
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Number of Common Shares Outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
150,886,433
|
|
|
|
150,845,518
|
|
|
|
134,071,334
|
|
Effect of stock-based compensation awards
|
|
|
247,087
|
|
|
|
171,938
|
|
|
|
65,885
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dilutive
|
|
|
151,133,520
|
|
|
|
151,017,456
|
|
|
|
134,137,219
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.90
|
|
|
$
|
1.06
|
|
|
$
|
0.76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.90
|
|
|
$
|
1.06
|
|
|
$
|
0.76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recent
Accounting Pronouncements
In December 2007, the Financial Accounting Standards Board
(FASB) issued Statement of Financial Accounting Standards
No. 141(R), Business Combinations
(SFAS 141R), and Statement of Financial Accounting
Standards No. 160, Accounting and Reporting of
Noncontrolling Interest in Consolidated Financial Statements, an
amendment of ARB No. 51 (SFAS 160).
SFAS 141R and SFAS 160 will significantly change the
accounting for and reporting of business combination
transactions and noncontrolling (minority) interests in
consolidated financial statements. SFAS 141R retains the
fundamental requirements in
67
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
Statement 141 Business Combinations while providing
additional definitions, such as the definition of the acquirer
in a purchase and improvements in the application of how the
acquisition method is applied. SFAS 160 will change the
accounting and reporting for minority interests, which will be
recharacterized as noncontrolling interests, and classified as a
component of equity. These Statements become simultaneously
effective January 1, 2009. Early adoption is not permitted.
We are currently evaluating the impact this guidance will have
on our consolidated financial statements.
In February 2007, the Financial Accounting Standards Board
Issued Statement No. 159, The Fair Value Option for
Financial Assets and Financial Liabilities Including
an Amendment of FAS 115 (SFAS 159). This
Statement permits entities to choose to measure many financial
instruments and certain other items at fair value. The objective
is to improve financial reporting by providing entities with the
opportunity to mitigate volatility in reported earnings caused
by measuring related assets and liabilities differently without
having to apply complex hedge accounting provisions. This
Statement is effective as of the beginning of an entitys
first fiscal year that begins after November 15, 2007.
Early adoption is permitted as of the beginning of a fiscal year
that begins on or before November 15, 2007, provided the
entity also elects to apply the provisions of FASB Statement
No. 157, Fair Value Measurements. We do not expect
this guidance to have a significant impact on CNX Gas; however
management is currently assessing the impact of adopting
SFAS No. 159.
In September 2006, the FASB issued Statement of Financial
Accounting Standards No. 157, Fair Value
Measurements (SFAS 157), which defines fair value,
establishes a framework for measuring fair value in accordance
with accounting principles generally accepted in the United
States of America, and requires additional disclosures about
fair value measurements. SFAS 157 aims to improve the
consistency and comparability of fair value measurements by
creating a single definition of fair value. The Statement
emphasizes that fair value is not entity-specific, but instead
is a market-based measurement of an asset or liability.
SFAS 157 upholds the requirements of previously issued
pronouncements concerning fair value measurements and expands
the required disclosures. This Statement is effective for
financial statements issued for fiscal years beginning after
November 15, 2007, however earlier application is permitted
provided the reporting entity has not yet issued financial
statements for that fiscal year. We do not expect that this
guidance will have a significant impact on CNX Gas; however
management is currently assessing the impact of adopting SFAS
157.
In September 2006, the FASB issued Statement of Financial
Accounting Standards No. 158, Employers
Accounting for Defined Benefit Pension and Other Postretirement
Plans (SFAS 158), which requires the recognition of
the funded status of defined benefit postretirement plans and
related disclosures. SFAS 158 was issued to address
concerns that prior standards on employers accounting for
defined benefit postretirement plans failed to communicate the
funded status of those plans in a complete and understandable
way and to require an employer to recognize completely in
earnings or other comprehensive income the financial impact of
certain events affecting the plans funded status when
those events occurred. This Statement is effective for financial
statements issued for fiscal years ending after
December 15, 2006. Additionally, SFAS 158 requires an
employer to measure the funded status of each of its plans as of
the date of its year-end statement of financial position. This
provision becomes effective for CNX Gas for its
December 31, 2008 year-end. The funded status of CNX
Gas pension and other postretirement benefit plans are
currently measured as of September 30.
Reclassifications
Certain amounts in prior periods have been reclassified to
conform with the report classifications of the year ended
December 31, 2007 with no effect on previously reported net
income or stockholders equity. These reclassifications
include amounts related to lifting, gathering, other, and
general administrative costs.
68
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
|
|
Note 2
|
Significant
Acquisitions:
|
In April 2007, CNX Gas acquired by lease 20,000 acres in
southwestern Pennsylvania from a subsidiary of Massey Energy
Company. The acreage has no proved gas reserves and is in close
proximity to our Mountaineer and Nittany plays. Under the
agreement, CNX Gas and the Massey subsidiary will jointly
develop the property, with CNX Gas serving as the operator and
majority interest partner.
In May 2007, CNX Gas acquired by lease approximately
70,000 acres of oil and gas reserves in western Kentucky
from a subsidiary of Atmos Energy Corporation and Teal Royalties
LLC. The acreage has no proved gas reserves and is in close
proximity to our existing acreage in the New Albany shale.
In June 2007, CNX Gas entered into a three-way transaction with
Peabody Energy and majority shareholder CONSOL Energy Inc.
(CONSOL or CONSOL Energy) to acquire certain oil and gas,
coalbed methane, and other gas interests. Pursuant to the
transaction, CNX Gas acquired certain coal assets from CONSOL
for $45,000 cash, plus $1,777 of miscellaneous acquisition
costs, plus a future payment with an estimated present value of
$6,688, which we approximate to be the fair value of the assets.
CNX Gas then exchanged those assets plus $15,000 cash for
Peabodys oil and gas, coalbed methane, and other gas
rights to approximately 985,000 acres, including
603,000 acres in the Illinois Basin, 2,000 acres in
Central Appalachia, 151,000 acres in Northern Appalachia,
171,000 acres in the San Juan Basin, 47,000 acres
in the Powder River Basin, and 11,000 acres in the Rockies.
This acreage has no proved gas reserves.
|
|
Note 3
|
Transactions
with Related Parties:
|
CNX Gas sells gas to CONSOL Energy on a basis reflecting the
monthly average price received by CNX Gas from third party
sales. CNX Gas also sells gas to Buchanan Generation, LLC, in
which CNX Gas has a 50% interest, on both a market and
discounted basis, depending upon the circumstances. CNX Gas also
purchases various supplies from CONSOL Energys wholly
owned subsidiary, Fairmont Supply. The cost of these items
reflect current market prices and are included in cost of goods
sold as arms-length transactions. The following table reflects
the amounts of these transactions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Twelve Months
|
|
|
|
Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Sales of Gas-Related Party
|
|
$
|
11,618
|
|
|
$
|
8,490
|
|
|
$
|
6,052
|
|
Supply Purchases
|
|
$
|
699
|
|
|
$
|
210
|
|
|
$
|
135
|
|
CNX Gas utilizes certain services and engages in operating
transactions in the normal course of business with CONSOL
Energy. The following represents a summary of the significant
transactions of this nature:
General and administrative expenses contain fees of $1,635,
$3,954, and $5,669 for the twelve months ended December 31,
2007, 2006, and 2005, respectively, for certain accounting and
administrative services provided by CONSOL Energy. These fees
are allocated to CNX Gas based on annual estimated hours worked
on CNX Gas versus total hours available.
CNX Gas also paid $200, $200, and $21 of rent for the twelve
months ended December 31, 2007, 2006, and 2005,
respectively, for one of our facilities.
CNX Gas paid CONSOL Energy $18,676, $35,646 and $12,121 for
federal and state taxes related to income for the twelve months
ended December 31, 2007, 2006 and 2005, respectively.
CONSOL Energy currently incurs drilling costs related to gob gas
production due to the necessity to
de-gas coal
mines prior to production for safety reasons. The cost to CONSOL
Energy for drilling these wells was as follows: $7,101 in 2007,
$8,917 in 2006, and $6,200 in 2005. CNX Gas captures and markets
the gas from these wells and, therefore, benefits from this
drilling activity, although CNX Gas is not burdened with the
cost to drill gob wells. CNX Gas is responsible for the costs
incurred to gather and deliver the gob gas to
69
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
market. All gob well drilling costs are borne by CONSOL Energy
and only the collection and processing costs are recorded in CNX
Gas financial statements. CNX Gas master cooperation
and safety agreement with CONSOL Energy retained this cost
structure after its separation from CONSOL Energy in August 2005.
CNX Gas employees may also participate in certain benefit
programs administered by CONSOL Energy, which are discussed
further in Note 12 to the Consolidated Financial
Statements. Our allocation of pension expense was $526 up to the
point of separation in 2005.
Employees may also participate in a defined contribution
investment plan administered by CONSOL Energy. CONSOL Energy
charges CNX Gas the actual amounts contributed by CONSOL Energy
on behalf of CNX Gas employees. Amounts charged to expense
by CNX Gas for the investment plan were $1,233, $646, and $442
for the twelve months ended December 31, 2007, 2006, and
2005, respectively. For all years noted, this expense includes a
matching contribution of up to 6% of an individuals
eligible pay contributed to the plan. For the year-end
December 31, 2007, the charge to expense also includes an
additional 3% company contribution for those employees hired on
or after January 1, 2006, as well as those employees hired
prior to December 31, 2005 who elected to freeze their
defined benefit accruals as of January 1, 2007. Please see
Note 12 to the Consolidated Financial Statements for
further information regarding changes to the plan.
Eligible employees may also participate in a long-term
disability plan administered by CONSOL Energy. Benefits for this
plan are based on a percentage of monthly earnings, offset by
all other income benefits available to the disabled. CNX
Gas allocation of the long-term disability plan expense
under this plan was $493, $321, and $228 for the twelve months
ended December 31, 2007, 2006, and 2005, respectively.
Allocation of the expense for this plan is based on the
percentage of CNX Gas active salary employees compared to
the total active salary employees covered by the plan.
CNX Gas also 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 health 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 one thousand dollars 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 postretirement benefit plan in 2008 and instead
expects to pay benefit claims as they become due.
CNX Gas is insured through CONSOL Energy for workers
compensation claims in several states and is self-insured for
these claims in Virginia. Workers compensation expense for
these benefits was $21, $16, and $34 for the twelve months ended
December 31, 2007, 2006, and 2005, respectively.
CONSOL Energy has provided financial guarantees on behalf of CNX
Gas. As discussed in Note 17 to the Consolidated Financial
Statements, CNX Gas anticipates that these parental guarantees
will be transferred from CONSOL Energy to CNX Gas over time. We
also believe that these parental guarantees will expire without
being funded, and therefore will not have a material adverse
effect on the financial statements.
CNX Gas is insured through CONSOL Energys business
interruption insurance, and pays allocated premiums directly to
CONSOL Energy. As of December 31, 2007, CNX Gas has a
related party receivable of $1,600 related to a CONSOL Energy
mine incident in the current year. During 2006, CNX Gas also
received $10,165 related to CONSOL Energy mine incidents which
occurred in 2005.
70
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Twelve Months
|
|
|
|
Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Interest Income
|
|
$
|
3,793
|
|
|
$
|
3,453
|
|
|
$
|
418
|
|
Business Interruption Insurance
|
|
|
1,600
|
|
|
|
10,165
|
|
|
|
|
|
Third Party Gathering Revenue
|
|
|
1,077
|
|
|
|
1,341
|
|
|
|
1,110
|
|
Miscellaneous
|
|
|
171
|
|
|
|
97
|
|
|
|
173
|
|
Royalty Income
|
|
|
|
|
|
|
10,230
|
|
|
|
8,158
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Other Income
|
|
$
|
6,641
|
|
|
$
|
25,286
|
|
|
$
|
9,859
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Business interruption insurance in 2007 related to an advance on
the settlement of claims under our business interruption
insurance policy for losses we sustained related to a CONSOL
Energy mining incident at Buchanan Mine which adversely affected
our gob gas production in the current year. Business
interruption insurance in 2006 related to a CONSOL Energy mining
incident in 2005 which negatively impacted our gas production in
that year. Business interruption insurance is included in
related party receivables as of December 31, 2007. There
was no receivable outstanding as of December 31, 2006.
Royalty income is included in outside sales for the year ended
December 31, 2007.
The following is a reconciliation, stated as a percentage of
pretax income, of the U.S. statutory federal income tax
rate to CNX Gas effective tax rate:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Twelve Months
|
|
|
|
Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
Dollars
|
|
|
Rate
|
|
|
Dollars
|
|
|
Rate
|
|
|
Dollars
|
|
|
Rate
|
|
|
Statutory U.S. Federal Income Tax Rate
|
|
$
|
77,223
|
|
|
|
35.0
|
%
|
|
$
|
89,754
|
|
|
|
35.0
|
%
|
|
$
|
58,351
|
|
|
|
35.0
|
%
|
Net Effect of State Income Tax
|
|
|
9,108
|
|
|
|
4.1
|
%
|
|
|
9,032
|
|
|
|
3.5
|
%
|
|
|
7,072
|
|
|
|
4.2
|
%
|
Other
|
|
|
(1,370
|
)
|
|
|
(0.6
|
)%
|
|
|
(2,213
|
)
|
|
|
(0.8
|
)%
|
|
|
(873
|
)
|
|
|
(0.5
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax Expense/ Effective Rate
|
|
$
|
84,961
|
|
|
|
38.5
|
%
|
|
$
|
96,573
|
|
|
|
37.7
|
%
|
|
$
|
64,550
|
|
|
|
38.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CNX Gas is included in the consolidated federal income tax
return of CONSOL Energy. Income taxes are calculated as if CNX
Gas files a tax return on a separate company basis. CNX Gas is
no longer subject to U.S. federal, state, and local, or
non-U.S. income
tax examinations by tax authorities for tax years prior to 2002.
The Internal Revenue Service (IRS) commenced an examination of
CONSOL Energys U.S. income tax returns for 2004 and
2005. This examination is anticipated to be completed by the end
of 2008. As of December 31, 2007, the IRS has not proposed
any significant adjustments relating to any tax position taken
by CNX Gas as part of CONSOL Energys consolidated federal
income tax return.
71
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
Income taxes provided on earnings consisted of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Twelve Months
|
|
|
|
Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
13,836
|
|
|
$
|
30,032
|
|
|
$
|
14,713
|
|
State
|
|
|
2,755
|
|
|
|
6,183
|
|
|
|
3,058
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
57,112
|
|
|
|
52,646
|
|
|
|
38,957
|
|
State
|
|
|
11,258
|
|
|
|
7,712
|
|
|
|
7,822
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Tax Expense
|
|
$
|
84,961
|
|
|
$
|
96,573
|
|
|
$
|
64,550
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The components of the net deferred tax liabilities are as
follows:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Deferred Tax Assets:
|
|
|
|
|
|
|
|
|
Capital Lease Obligations
|
|
$
|
25,043
|
|
|
$
|
25,896
|
|
Derivatives
|
|
|
428
|
|
|
|
|
|
Asset Retirement Obligations
|
|
|
1,560
|
|
|
|
3,590
|
|
Other Postretirement Benefits
|
|
|
1,058
|
|
|
|
901
|
|
Stock-Based Compensation
|
|
|
1,176
|
|
|
|
300
|
|
Other
|
|
|
9,724
|
|
|
|
2,738
|
|
|
|
|
|
|
|
|
|
|
Total Deferred Tax Assets
|
|
|
38,989
|
|
|
|
33,425
|
|
|
|
|
|
|
|
|
|
|
Deferred Tax Liabilities:
|
|
|
|
|
|
|
|
|
Property, Plant and Equipment
|
|
|
(216,554
|
)
|
|
|
(145,179
|
)
|
Investment in Equity Affiliates
|
|
|
(6,936
|
)
|
|
|
(8,501
|
)
|
Derivatives
|
|
|
(4,197
|
)
|
|
|
(1,906
|
)
|
Other
|
|
|
(986
|
)
|
|
|
(938
|
)
|
|
|
|
|
|
|
|
|
|
Total Deferred Tax Liabilities
|
|
|
(228,673
|
)
|
|
|
(156,524
|
)
|
|
|
|
|
|
|
|
|
|
Net Deferred Tax Liabilities
|
|
$
|
(189,684
|
)
|
|
$
|
(123,099
|
)
|
|
|
|
|
|
|
|
|
|
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 6% of qualified production
activities income as limited by taxable income and may not
exceed 50 percent of the employers
W-2 wages
for the tax year. CNX Gas has estimated the deduction to be
$2,215 for 2007.
72
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
CNX Gas adopted the provisions of FASB Interpretation (FIN)
No. 48, Accounting for Uncertainty in Income
Taxes, on January 1, 2007. As a result of the
implementation of FIN No. 48, CNX Gas recognized
approximately a $53 net increase in the liability for
unrecognized tax benefits, which was accounted for as a
reduction to the January 1, 2007 balance of retained
earnings. A reconciliation of the beginning and ending
unrecognized tax benefits is as follows:
|
|
|
|
|
Balance at January 1, 2007
|
|
$
|
3,116
|
|
Additions related to current year tax positions
|
|
|
1,417
|
|
Additions related to prior year tax positions
|
|
|
|
|
Reductions related to prior year tax positions
|
|
|
|
|
Settlements
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007
|
|
$
|
4,533
|
|
|
|
|
|
|
Included in the balance at December 31, 2007 are $4,533 of
tax positions for which the ultimate deductibility is highly
certain but for which there is uncertainty about the timing of
such deductibility. The amounts included in FIN 48 are
temporary differences and therefore would not impact the
effective rate.
CNX Gas recognizes interest accrued related to unrecognized tax
benefits in its interest expense. For the twelve month period
ended December 31, 2007, CNX Gas recognized interest
expense of approximately $90. Total FIN No. 48 accrued
interest was $182 as of December 31, 2007.
CNX Gas recognizes penalties accrued related to unrecognized tax
benefits in its income tax expense. No penalties have been
accrued during the twelve month period ended December 31,
2007. CNX Gas has historically not paid penalties relating to
unrecognized tax benefits.
Note 6
Asset Retirement Obligations:
CNX Gas accrues for asset retirement obligations using the
accounting treatment prescribed by Statement of Financial
Accounting Standards No. 143, Accounting for Asset
Retirement Obligations (SFAS No. 143). CNX Gas
recognizes capitalized asset retirement costs by increasing the
carrying amount of related long-lived assets, net of the
associated accumulated depreciation.
The reconciliation of changes in the asset retirement
obligations at December 31, 2007 and 2006 is as follows:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Balance at beginning of year
|
|
$
|
9,214
|
|
|
$
|
10,908
|
|
Accretion expense
|
|
|
267
|
|
|
|
517
|
|
Payments
|
|
|
(144
|
)
|
|
|
(183
|
)
|
Liabilities incurred
|
|
|
1,180
|
|
|
|
1,348
|
|
Revisions in estimated cash flows
|
|
|
(6,536
|
)
|
|
|
(3,376
|
)
|
|
|
|
|
|
|
|
|
|
Balance at end of period
|
|
$
|
3,981
|
|
|
$
|
9,214
|
|
|
|
|
|
|
|
|
|
|
The revisions in estimated cash flows are due primarily to the
effect on the present value of an increase in the estimated
average life of our wells.
73
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
|
|
Note 7
|
Property,
Plant and Equipment:
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Leasehold Improvements
|
|
$
|
1,351
|
|
|
$
|
|
|
Proved Properties
|
|
|
125,118
|
|
|
|
91,913
|
|
Unproved Properties
|
|
|
81,078
|
|
|
|
765
|
|
Wells and Related Equipment
|
|
|
166,468
|
|
|
|
112,009
|
|
Intangible Drilling
|
|
|
531,098
|
|
|
|
383,605
|
|
Gathering Assets
|
|
|
596,171
|
|
|
|
520,906
|
|
Asset Retirement Obligations
|
|
|
1,035
|
|
|
|
5,652
|
|
Capitalized Internal Software
|
|
|
6,741
|
|
|
|
6,433
|
|
|
|
|
|
|
|
|
|
|
Total Property, Plant and Equipment
|
|
|
1,509,060
|
|
|
|
1,121,283
|
|
Accumulated Depreciation, Depletion and Amortization
|
|
|
(254,154
|
)
|
|
|
(203,121
|
)
|
|
|
|
|
|
|
|
|
|
Property and Equipment, net
|
|
$
|
1,254,906
|
|
|
$
|
918,162
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment includes gross assets acquired
under capital leases of $66,919 at December 31, 2007 and
2006 with related amounts in accumulated depreciation, depletion
and amortization of $5,242 and $781 at December 31, 2007
and 2006, respectively.
|
|
Note 8
|
Credit
Facility:
|
In 2005, CNX Gas entered into a credit agreement for a revolving
credit facility in an initial aggregate outstanding principal
amount of up to $200,000 with the ability to request an increase
in the aggregate outstanding principal amount up to $300,000,
including borrowings and letters of credit. CNX Gas may use
borrowings under the new credit agreement for general corporate
purposes, including transaction fees, letters of credit,
acquisitions, capital expenditures and working capital. The
$200,000 credit agreement for CNX Gas is unsecured, however it
does contain a negative pledge provision providing that CNX Gas
assets cannot be used to secure any other obligations. Fees and
interest rate spreads are based on the percentage of facility
utilization, measured quarterly. Covenants in the facility limit
our ability to dispose of assets, make investments, purchase or
redeem CNX Gas stock and merge with another corporation. The
facility includes a maximum leverage ratio covenant of not more
than 3.0 to 1.0, measured quarterly. The leverage ratio was 0.17
to 1.0 at December 31, 2007. The facility also includes a
minimum interest coverage ratio of no less than 3.0 to 1.0
measured quarterly. The interest coverage ratio covenant was
51.19 to 1.0 at December 31, 2007.
At December 31, 2007, the CNX Gas credit agreement had no
borrowings outstanding and $14,933 of letters of credit
outstanding, leaving $185,067 of capacity available for
borrowings and the issuance of letters of credit.
As a result of entering into the $200,000 credit agreement, CNX
Gas and subsidiaries have executed a Supplemental Indenture and
are guarantors of CONSOL Energys 7.875% notes due
March 1, 2012 in the principal amount of approximately
$250,000. In addition, if CNX Gas were to grant liens to a
lender as part of a future borrowing, the indenture and the
agreement governing CONSOL Energys 7.875% notes would
require CNX Gas to ratably secure the notes.
74
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
|
|
Note 9
|
Other
Current Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Short Term Incentive Compensation Plan
|
|
$
|
5,241
|
|
|
$
|
3,944
|
|
Purchased Gas
|
|
|
1,815
|
|
|
|
249
|
|
Accrued Payroll and Benefits
|
|
|
644
|
|
|
|
1,583
|
|
Accrued Property Taxes
|
|
|
577
|
|
|
|
249
|
|
Accrued Firm Transportation
|
|
|
474
|
|
|
|
336
|
|
Other
|
|
|
1,066
|
|
|
|
288
|
|
|
|
|
|
|
|
|
|
|
Total Other Current Liabilities
|
|
$
|
9,817
|
|
|
$
|
6,649
|
|
|
|
|
|
|
|
|
|
|
CNX Gas uses various leased facilities and equipment in our
operations, which qualify as operating leases. CNX Gas also
recorded a pipeline transportation arrangement as a capital
lease in 2006. Future minimum lease payments under these leases
are as follows:
|
|
|
|
|
|
|
|
|
|
|
Capital
|
|
|
Operating
|
|
|
|
Leases
|
|
|
Leases
|
|
|
2008
|
|
$
|
7,380
|
|
|
$
|
1,515
|
|
2009
|
|
|
7,380
|
|
|
|
1,310
|
|
2010
|
|
|
7,380
|
|
|
|
1,323
|
|
2011
|
|
|
7,380
|
|
|
|
1,041
|
|
2012
|
|
|
7,380
|
|
|
|
797
|
|
Thereafter
|
|
|
65,135
|
|
|
|
1,104
|
|
|
|
|
|
|
|
|
|
|
Total Minimum Lease Payments
|
|
|
102,035
|
|
|
$
|
7,090
|
|
|
|
|
|
|
|
|
|
|
Less Imputed Interest
|
|
|
38,118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Present Value of Minimum Lease Payments
|
|
|
63,917
|
|
|
|
|
|
Less Amount Due in One Year
|
|
|
2,768
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Long-term Capital Lease Obligation
|
|
$
|
61,149
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We are a party to a
15-year
capital lease obligation through October 2021. Under this
agreement, we are guaranteed approximately 197,500 mcf of
capacity daily on the Jewell Ridge lateral pipeline. This lease
does not transfer ownership at the end of the term.
Rental expense under operating leases was $6,675, $4,650, and
$4,247 for the twelve months ended December 31, 2007, 2006,
and 2005, respectively.
75
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
|
|
Note 11
|
Long-Term
Debt:
|
CNX Gas has debt outstanding related to a capital lease
obligation, detailed in Note 10, and to our consolidation
of a variable interest entity in the current year, detailed in
Note 1 to the Consolidated Financial Statements. The
following represents the total debt outstanding as of
December 31, 2007:
|
|
|
|
|
|
|
As of December 31, 2007
|
|
|
Debt:
|
|
|
|
|
Note Payable Huntington National Bank, due 2010 at
8.16%
|
|
$
|
7,648
|
|
Members loans payable, due various dates through 2010
|
|
|
823
|
|
Other notes payable, due various dates through 2010
|
|
|
380
|
|
|
|
|
|
|
Total Debt
|
|
|
8,851
|
|
Less amounts due in one year
|
|
|
3,051
|
|
|
|
|
|
|
Total Long-term Debt
|
|
$
|
5,800
|
|
|
|
|
|
|
Outside of our capital lease obligation, outstanding debt is
primarily related to the procurement of two drilling rigs by our
VIE dedicated to serve CNX Gas. We are the guarantor of this
loan with Huntington National Bank, which had an original
principal balance of $9,000. This guaranty is detailed further
in Note 17 to the Consolidated Financial Statements. The
remaining notes payable have interest rates ranging from 7.350%
to 9.240% and have maturity dates between 2008 and 2010.
Maturities on long-term debt in each of the next five years are
as follows:
|
|
|
|
|
2008
|
|
$
|
3,051
|
|
2009
|
|
|
4,098
|
|
2010
|
|
|
1,702
|
|
2011
|
|
|
|
|
2012
|
|
|
|
|
Thereafter
|
|
|
|
|
|
|
|
|
|
Total Long-Term Debt Maturities
|
|
$
|
8,851
|
|
|
|
|
|
|
|
|
Note 12
|
Pension
and Other Postretirement Benefits:
|
Defined
Benefit Pension Plan
As of December 31, 2005, CNX Gas participated 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, as a result of service after August 1, 2005, is
the obligation of CNX Gas. The benefits for this plan are based
primarily on years of service and employees compensation
near retirement. On 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, the CNX Gas Corporation Employee
Retirement Plan (Pension Plan), was created and sponsored by CNX
Gas to provide a benefit for all defined benefit accruals going
forward. As of that date, the lump sum benefits formula was
frozen for service and salaries and prospectively the lump sum
option will not be offered for any benefits earned after
January 1, 2006. Also the amount of future benefit accruals
was reduced and early retirement subsidies were eliminated.
Effective January 1, 2007, employees hired by CNX Gas will
not be eligible to participate in the non-contributory defined
benefit retirement plan. In lieu of participation in the
non-contributory defined benefit
76
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
plan, these employees will begin receiving an additional 3%
company contribution into their defined contribution plan. CNX
Gas employees who were hired prior to December 31, 2005 or
who were full time salaried employees of CONSOL Energy
immediately prior to their date of transfer were given a one
time opportunity to elect to remain in the defined benefit plan
or to freeze their defined benefit accruals and participate in
the additional 3% company contribution into their defined
contribution plan. All employees, regardless of the hire date or
plan election, will continue to receive up to a 6% company match
of eligible pay contributed to the defined contribution plan. In
addition, any employees hired on or after January 1, 2006
had their pension benefit frozen as of December 31, 2006
and were automatically enrolled into the additional 3% company
contribution into their defined contribution effective
January 1, 2007. The company intends to freeze all defined
benefit accruals after ten years for employees that elected to
remain in the defined benefit plan.
The CNX Gas Pension Plan uses a measurement period of October 1
through September 30 to determine components of net periodic
pension expense. Census data is gathered annually as of January
1 and projected to September 30. The reconciliation of
changes in the benefit obligation and funded status of this plan
at December 31, 2007 and 2006 is as follows:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Change in benefit obligation:
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of the year
|
|
$
|
207
|
|
|
$
|
88
|
|
Service cost
|
|
|
262
|
|
|
|
282
|
|
Interest cost
|
|
|
12
|
|
|
|
5
|
|
Actuarial loss/(gain)
|
|
|
150
|
|
|
|
(164
|
)
|
Benefits paid
|
|
|
(16
|
)
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
Benefit obligation at end of the year
|
|
$
|
615
|
|
|
$
|
207
|
|
|
|
|
|
|
|
|
|
|
Change in plan assets:
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of period
|
|
$
|
18
|
|
|
$
|
|
|
Actual return on plan assets
|
|
|
(51
|
)
|
|
|
2
|
|
Company contributions
|
|
|
337
|
|
|
|
20
|
|
Benefits paid
|
|
|
(16
|
)
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at end of period
|
|
$
|
288
|
|
|
$
|
18
|
|
|
|
|
|
|
|
|
|
|
Funded Status:
|
|
|
|
|
|
|
|
|
Noncurrent liabilities
|
|
$
|
(327
|
)
|
|
$
|
(189
|
)
|
|
|
|
|
|
|
|
|
|
Net obligation recognized
|
|
$
|
(327
|
)
|
|
$
|
(189
|
)
|
|
|
|
|
|
|
|
|
|
Amounts recognized in accumulated other comprehensive income
consist of:
|
|
|
|
|
|
|
|
|
Net Gain
|
|
$
|
(50
|
)
|
|
$
|
(276
|
)
|
|
|
|
|
|
|
|
|
|
Net amount recognized (before tax effect)
|
|
$
|
(50
|
)
|
|
$
|
(276
|
)
|
|
|
|
|
|
|
|
|
|
The accumulated benefit obligation for the Pension Plan at
December 31, 2007 and 2006 was $470 and $160, respectively.
We do not expect to recognize a gain or loss related to the net
actuarial results in 2008.
77
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
The components of net periodic benefit costs are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Twelve Months Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Components of Net Periodic Benefit Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Service costs
|
|
$
|
262
|
|
|
$
|
282
|
|
|
$
|
219
|
|
Interest costs
|
|
|
12
|
|
|
|
5
|
|
|
|
|
|
Expected return on plan assets
|
|
|
(2
|
)
|
|
|
(9
|
)
|
|
|
|
|
Recognized net actuarial gain
|
|
|
(23
|
)
|
|
|
(12
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit costs
|
|
$
|
249
|
|
|
$
|
266
|
|
|
$
|
219
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted-average assumptions used to determine benefit
obligations are as follows:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Discount rate
|
|
|
6.57
|
%
|
|
|
6.00
|
%
|
Expected long-term return on plan assets
|
|
|
8.00
|
%
|
|
|
8.00
|
%
|
Rate of compensation increase
|
|
|
5.46
|
%
|
|
|
4.36
|
%
|
The company calculates net periodic pension cost for a given
fiscal year based on the assumptions developed at the end of the
previous fiscal year. The weighted-average assumptions used to
determine net periodic benefit cost are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Discount rate
|
|
|
6.00
|
%
|
|
|
5.75
|
%
|
|
|
6.00
|
%
|
Expected long-term return on plan assets
|
|
|
8.00
|
%
|
|
|
8.00
|
%
|
|
|
|
|
Rate of compensation increase
|
|
|
4.36
|
%
|
|
|
4.11
|
%
|
|
|
4.12
|
%
|
The long-term rate of return is the sum of the portion of total
assets in each asset class held multiplied by the expected
return for that class, adjusted for expected expenses to be paid
from the assets. The expected return for each class is
determined using the plan asset allocation at the measurement
date and a distribution of compound average returns over a
20-year time
horizon. The model uses asset class returns, variances and
correlation assumptions to produce the expected return for each
portfolio. The return assumptions used forward-looking gross
returns influenced by the current Treasury yield curve. These
returns recognize current bond yields, corporate bond spreads
and equity risk premiums based on current market conditions. In
general, the long-term rate of return is the sum of the portion
of total assets in each asset class multiplied by the expected
return for that class, adjusted for expected expenses to be paid
from the assets.
We expect to contribute $400 to the Pension Plan in 2008. As of
December 31, 2007, all of the plan assets were held in cash
and cash equivalents.
78
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
The following benefit payments reflecting future service are
expected to be paid as follows:
|
|
|
|
|
|
|
Pension
|
|
|
|
Payments
|
|
|
2008
|
|
$
|
4
|
|
2009
|
|
|
8
|
|
2010
|
|
|
13
|
|
2011
|
|
|
18
|
|
2012
|
|
|
25
|
|
Year
2013-2017
|
|
|
404
|
|
Postretirement
Benefit Plans
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 health 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. The plan structure includes a cost
sharing arrangement where essentially all participants
contribute 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 postretirement benefit plan in
2008. CNX Gas expects to pay benefit claims as they become due.
CNX Gas uses a September 30 measurement date for its other
postretirement benefit plans.
The reconciliation of changes in the benefit obligation and
funded status of these plans as of December 31, 2007 and
2006 is as follows:
|
|
|
|
|
|
|
|
|
|
|
Other Benefits as of
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Change in benefit obligation:
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year
|
|
$
|
2,325
|
|
|
$
|
1,760
|
|
Service cost
|
|
|
124
|
|
|
|
91
|
|
Interest cost
|
|
|
139
|
|
|
|
101
|
|
Actuarial loss
|
|
|
335
|
|
|
|
466
|
|
Plan amendments
|
|
|
|
|
|
|
|
|
Benefits paid
|
|
|
(109
|
)
|
|
|
(93
|
)
|
|
|
|
|
|
|
|
|
|
Benefit obligation at end of year
|
|
$
|
2,814
|
|
|
$
|
2,325
|
|
|
|
|
|
|
|
|
|
|
Funded Status:
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
(114
|
)
|
|
$
|
(12
|
)
|
Noncurrent liabilities
|
|
|
(2,700
|
)
|
|
|
(2,313
|
)
|
|
|
|
|
|
|
|
|
|
Net obligation recognized
|
|
$
|
(2,814
|
)
|
|
$
|
(2,325
|
)
|
|
|
|
|
|
|
|
|
|
Amounts recognized in accumulated other comprehensive income
consist of:
|
|
|
|
|
|
|
|
|
Net Loss
|
|
$
|
803
|
|
|
$
|
489
|
|
Prior Service Cost
|
|
|
(1,287
|
)
|
|
|
(1,459
|
)
|
|
|
|
|
|
|
|
|
|
Net amount recognized (before tax effect)
|
|
$
|
(484
|
)
|
|
$
|
(970
|
)
|
|
|
|
|
|
|
|
|
|
79
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
Of amounts currently included in accumulated other comprehensive
income, we expect to recognize a gain of $172 related to prior
service costs, and a loss of $36 related to the net actuarial
loss in earnings in 2008.
The components of net periodic benefit costs are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Twelve Months Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Components of Net Periodic Benefit Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Service costs
|
|
$
|
124
|
|
|
$
|
91
|
|
|
$
|
160
|
|
Interest costs
|
|
|
139
|
|
|
|
101
|
|
|
|
170
|
|
Amortization of prior service costs credit
|
|
|
(172
|
)
|
|
|
(172
|
)
|
|
|
(113
|
)
|
Recognized net actuarial loss
|
|
|
21
|
|
|
|
|
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit costs
|
|
$
|
112
|
|
|
$
|
20
|
|
|
$
|
259
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The company calculates net periodic benefit cost for a given
fiscal year based on the assumptions developed at the end of the
previous fiscal year. The weighted-average assumptions used to
determine benefit obligations are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2007
|
|
2006
|
|
2005
|
|
Discount rate
|
|
|
6.63
|
%
|
|
|
6.00
|
%
|
|
|
5.75
|
%
|
The weighted-average assumptions used to determine net periodic
benefit cost are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2007
|
|
2006
|
|
2005
|
|
Discount rate
|
|
|
6.00
|
%
|
|
|
5.75
|
%
|
|
|
6.00
|
%
|
The assumed health care cost trend rates are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Healthcare cost trend rate for next year
|
|
|
8.00
|
%
|
|
|
8.50
|
%
|
|
|
9.25
|
%
|
Rate to which the cost trend rate is assumed to decline
(ultimate trend rate)
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
|
4.75
|
%
|
Year that the rate reaches ultimate trend rate
|
|
|
2014
|
|
|
|
2011
|
|
|
|
2011
|
|
Assumed health care cost trend rates have a significant effect
on the amounts reported for the medical plans. A
one-percentage-point change in assumed health care cost trend
rates would have the following effects:
|
|
|
|
|
|
|
|
|
|
|
1-Percentage
|
|
1-Percentage
|
|
|
Point Increase
|
|
Point Decrease
|
|
Effect on total of service and interest costs components
|
|
$
|
43
|
|
|
$
|
(36
|
)
|
Effect on accumulated postretirement benefit obligation
|
|
$
|
380
|
|
|
$
|
(322
|
)
|
80
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
CNX Gas had no plan assets as of December 31, 2007 and 2006
for other postretirement benefits. The company intends to pay
benefit claims as they are due. The following benefit payments
reflecting future service are expected to be paid as follows:
|
|
|
|
|
|
|
Other Benefits
|
|
|
|
Payments
|
|
|
2008
|
|
$
|
114
|
|
2009
|
|
|
120
|
|
2010
|
|
|
126
|
|
2011
|
|
|
149
|
|
2012
|
|
|
174
|
|
Year
2013-2017
|
|
|
1,080
|
|
|
|
Note 13
|
Stock-Based
Compensation:
|
CNX Gas adopted the CNX Gas Equity Incentive Plan on
June 30, 2005, and amended the plan on August 1, 2005
and again on October 11, 2006. The August 1 amended plan
was approved by the sole stockholder of CNX Gas, CONSOL Energy,
on August 4, 2005. The October 11, 2006 amendment was
approved by the Board. The plan is administered by our board of
directors and the board of directors may delegate administration
of the plan to a committee of the board of directors. Our
directors and employees, and our affiliates (which include
CONSOL Energy) directors and employees, are eligible to receive
awards under the plan. Some of our employees including our
executive officers and non-employee directors have participated
in or have been eligible to participate in and, will continue to
be eligible to participate in, CNX Gas Equity Incentive
Plan.
The CNX Gas Equity Incentive Plan consists of the following
components: stock options, stock appreciation rights, restricted
stock units, performance awards, cash awards and other
stock-based awards. The total number of shares of CNX Gas common
stock with respect to which awards may be granted under CNX
Gas plan is 2,500,000.
The total stock-based compensation expense was $3,260, $3,733
and $205 for the years ended December 31, 2007, 2006 and
2005, respectively, and the related deferred tax benefit totaled
$1,277, $1,455 and $81, respectively. Prior to January 1,
2006, CNX Gas accounted for stock-based compensation under the
recognition and measurement provisions of Accounting Principles
Board Opinion (APB) No. 25, Accounting for Stock
Issued to Employees, as amended. Generally, no stock-based
employee compensation cost for stock options is reflected in net
income, as all options granted under the plans had an exercise
price equal to the market value of the underlying common stock
on the date of the grant. CNX Gas also provided pro forma
disclosure amounts in accordance with Statement of Financial
Accounting Standards No. 148, Accounting for
Stock-Based Compensation Transition and Disclosure
an Amendment of SFAS No. 123 (SFAS 148), as
if the SFAS 123 provisions for income statement recognition
had been applied to its stock-based compensation.
Effective January 1, 2006, CNX Gas adopted the fair value
recognition provisions of SFAS 123R, Share-Based
Payment (SFAS 123R), using the modified prospective
transition method, and therefore has not restated results for
prior periods. Under this transition method, stock-based
compensation expense for the years ended December 31, 2007
and 2006 included compensation expense for all stock-based
compensation awards granted prior to, but not yet vested as of,
January 1, 2006, based on the grant date fair value
estimated in accordance with the original provisions of
SFAS 123. Share-based compensation expense for all
share-based payment awards granted after January 1, 2006 is
based on the grant date fair value in accordance with the
provisions of FAS 123R. CNX Gas recognizes compensation
costs net of an estimated forfeiture rate and recognizes the
compensation cost for only those shares expected to vest on a
straight-line basis over the
81
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
requisite service period of the award, which is generally the
option vesting term, or to an employees eligible
retirement date, if earlier and applicable.
The pro forma table below reflects net earnings as well as basic
and diluted earnings per share for the year ended
December 31, 2005, had CNX Gas applied the fair value
recognition provisions of SFAS 123:
|
|
|
|
|
|
|
For the Twelve Months Ended
|
|
|
|
December 31, 2005
|
|
|
Net Income as reported
|
|
$
|
102,168
|
|
Add: Stock-based compensation expense for restricted stock units
|
|
|
205
|
|
Deduct: Total stock-based compensation expense determined under
Black-Scholes option pricing model and stock-based compensation
expense for restricted stock units, net of tax
|
|
|
(423
|
)
|
|
|
|
|
|
Pro forma net income
|
|
$
|
101,950
|
|
|
|
|
|
|
Earnings per share:
|
|
|
|
|
Basic as reported
|
|
$
|
0.76
|
|
Basic pro forma
|
|
$
|
0.76
|
|
Dilutive as reported
|
|
$
|
0.76
|
|
Dilutive pro forma
|
|
$
|
0.76
|
|
As part of its SFAS 123R adoption, CNX Gas continues to use
the Black-Scholes option pricing model to value its options. The
risk free interest rate was determined for each vesting tranche
of an award based upon the calculated yield on U.S Treasury
obligations for the expected term of the award. The expected
volatility and expected term of the awards were developed by
examining the stock option activity for a peer group of
companies. The expected forfeiture rate is based upon historical
forfeiture activity of the peer group. The fair value of share
based payment awards was estimated using the Black-Scholes
option pricing model with the following assumptions and weighted
average fair values:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the
|
|
|
For the
|
|
|
For the
|
|
|
|
Twelve Months Ended
|
|
|
Twelve Months Ended
|
|
|
Twelve Months Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Weighted Average Fair Value of Grants
|
|
$
|
9.61
|
|
|
$
|
9.83
|
|
|
$
|
5.34
|
|
Risk Free Interest Rate
|
|
|
4.58
|
%
|
|
|
4.65
|
%
|
|
|
4.28
|
%
|
Dividend Yield
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Volatility
|
|
|
34.50
|
%
|
|
|
32.39
|
%
|
|
|
36.54
|
%
|
Expected Forfeiture Rate
|
|
|
2.0
|
%
|
|
|
2.0
|
%
|
|
|
|
|
Expected Term
|
|
|
4.5 years
|
|
|
|
4.5 years
|
|
|
|
4.5 years
|
|
Stock
Options Awards
There are 996,292 employee stock options that vest 25% per
year, beginning one year after the grant date and
467,826 employee stock options that vest 100%, three years
after the grant date. There are 24,989 non-employee director
stock options outstanding which vest 33% per year, beginning one
year after the grant date. The vesting of the options will
accelerate in the event of death, disability or retirement and
may accelerate upon a change of control of CNX Gas. These stock
options will terminate ten years after the date on which they
were granted.
82
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
A summary of the status of stock options granted is presented
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
Remaining
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Contractual
|
|
|
Aggregate Intrinsic
|
|
|
|
Shares
|
|
|
Exercise Price
|
|
|
Term
|
|
|
Value
|
|
|
|
|
|
|
|
|
|
(In years)
|
|
|
(Dollars in thousands)
|
|
|
Balance at December 31, 2006
|
|
|
1,497,319
|
|
|
$
|
20.01
|
|
|
|
8.83
|
|
|
|
|
|
Granted
|
|
|
15,750
|
|
|
|
26.78
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
(18,337
|
)
|
|
|
16.37
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(5,625
|
)
|
|
|
20.02
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007
|
|
|
1,489,107
|
|
|
$
|
20.13
|
|
|
|
7.85
|
|
|
$
|
17,603
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested and expected to vest at December 31, 2007
|
|
|
1,479,251
|
|
|
$
|
20.07
|
|
|
|
7.85
|
|
|
$
|
17,568
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at December 31, 2007
|
|
|
506,392
|
|
|
$
|
16.24
|
|
|
|
7.60
|
|
|
$
|
7,956
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash received from option exercises for the year ended
December 31, 2007 was $302. The excess tax benefit realized
for the tax deduction from option exercises totaled $53 for the
year ended December 31, 2007. This excess tax benefit is
included in cash flows from financing activities in the
Consolidated Statement of Cash Flows.
The aggregate intrinsic value in the table above represents the
total pretax intrinsic value (the difference between CNX Gas
closing stock price on the last trading day of the year ended
December 31, 2007 and the exercise price, multiplied by the
number of in-the-money options) that would have been received by
the option holders had all option holders exercised their
options on December 31, 2007. This amount changes based on
the fair market value of CNX Gas stock. The total intrinsic
value of options exercised for the year ended December 31,
2007 was $286.
As of December 31, 2007, $3,921 of total unrecognized
compensation cost related to unvested options awards is expected
to be recognized over a weighted-average period of
1.52 years.
Restricted
Stock Units
Under the Equity Incentive Plan, CNX Gas granted certain
employees and certain directors restricted stock unit awards.
These awards entitle the holder to receive shares of common
stock as the award vests. A total of 52,310 restricted stock
units were outstanding at December 31, 2007. Compensation
expense will be recognized over the vesting period of the units.
The total fair value of restricted stock unit awards that vested
during the year was $922.
The following represents the unvested restricted stock units and
corresponding fair value (based upon the closing share price) at
the date of the grant:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Grant Date Fair
|
|
|
|
Shares
|
|
|
Value
|
|
|
Non-vested at December 31, 2006
|
|
|
68,371
|
|
|
$
|
17.12
|
|
Granted
|
|
|
16,725
|
|
|
|
28.70
|
|
Vested
|
|
|
(32,786
|
)
|
|
|
16.78
|
|
|
|
|
|
|
|
|
|
|
Non-Vested at December 31, 2007
|
|
|
52,310
|
|
|
$
|
21.04
|
|
|
|
|
|
|
|
|
|
|
83
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
As of December 31, 2007, $742 of total unrecognized
compensation cost related to unvested Restricted Stock Unit
(RSU) awards is expected to be recognized over a
weighted-average period of 1.23 years.
Prior to the adoption of SFAS 123R on January 1, 2006,
CNX Gas followed the nominal vesting period approach under APB
No. 25 for awards with retirement eligible provisions. Upon
adoption of SFAS 123R, CNX Gas changed to the
non-substantive vesting period approach for awards with
retirement eligible provisions. If CNX Gas would have followed
the non-substantive vesting period approach for awards with
retirement eligible provisions, we would have disclosed
approximately $959 of additional expense, net of tax, for stock
options for the year ended December 31, 2005.
Long
Term Incentive Compensation
Effective October 11, 2006, CNX Gas adopted a long-term
incentive program. This program allows for the award of
performance share units (PSUs). A PSU represents a contingent
right to receive a cash payment, determined by reference to the
value of one share of the companys common stock. The total
number of units earned, if any, by a participant will be based
on the companys total stockholder return relative to the
stockholder return of a pre-determined peer group of companies.
The performance period is from October 11, 2006 to
December 31, 2009. CNX Gas will recognize compensation
costs over the requisite service period. The basis of the
compensation costs will be re-valued quarterly. As of
December 31, 2007, there are 218,012 PSUs issued with a
fair value of approximately $7,803. CNX Gas recognized
approximately $2,231 in compensation costs in the current year.
CNX Gas intends to grant these awards on an annual basis.
84
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
|
|
Note 14
|
Supplemental
Cash Flow Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Twelve Months
|
|
|
|
Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Net Cash provided from operating activities included:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest paid
|
|
$
|
5,328
|
|
|
$
|
870
|
|
|
$
|
14
|
|
Income Taxes paid
|
|
$
|
19,220
|
|
|
$
|
37,241
|
|
|
$
|
12,233
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of Property, Plant and Equipment
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Assets
|
|
$
|
(341
|
)
|
|
$
|
(12,674
|
)
|
|
$
|
|
|
Change in Liabilities
|
|
$
|
(341
|
)
|
|
$
|
(12,674
|
)
|
|
$
|
|
|
Tenant Improvement Allowance
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Assets
|
|
$
|
(1,109
|
)
|
|
$
|
|
|
|
$
|
|
|
Change in Liabilities
|
|
$
|
(1,109
|
)
|
|
$
|
|
|
|
$
|
|
|
Accounting for Gas Well Closing Costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Assets
|
|
$
|
3,563
|
|
|
$
|
2,027
|
|
|
$
|
(3,591
|
)
|
Change in Liabilities
|
|
$
|
3,563
|
|
|
$
|
2,027
|
|
|
$
|
(3,591
|
)
|
Adoption of FIN 48
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Assets
|
|
$
|
(4,572
|
)
|
|
$
|
|
|
|
$
|
|
|
Change in Liabilities
|
|
$
|
(4,572
|
)
|
|
$
|
|
|
|
$
|
|
|
Acquisition of Mineral Rights
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Assets
|
|
$
|
(6,500
|
)
|
|
$
|
|
|
|
$
|
|
|
Change in Liabilities
|
|
$
|
(6,500
|
)
|
|
$
|
|
|
|
$
|
|
|
Consolidation of VIE
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Assets
|
|
$
|
(870
|
)
|
|
$
|
|
|
|
$
|
|
|
Change in Liabilities
|
|
$
|
(870
|
)
|
|
$
|
|
|
|
$
|
|
|
Capital Lease Obligation
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Assets
|
|
$
|
|
|
|
$
|
(66,919
|
)
|
|
$
|
|
|
Change in Liabilities
|
|
$
|
|
|
|
$
|
(66,919
|
)
|
|
$
|
|
|
Tax basis
step-up
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(165,041
|
)
|
Assumed ownership of joint venture assets
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(4,769
|
)
|
85
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
|
|
Note 15
|
Concentration
of Credit Risk:
|
CNX Gas markets methane gas for sale primarily to gas
wholesalers. Credit is extended based on an evaluation of the
customers financial condition, and generally collateral is
not required. A table illustrating sales to individual customers
constituting 10% or more of outside sales is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Twelve
|
|
|
|
|
|
|
|
|
|
|
|
|
Months Ended
|
|
|
|
|
|
|
|
Percent of
|
|
|
AR Balance
|
|
December 31
|
|
|
Customer
|
|
Amount
|
|
|
Outside Sales
|
|
|
December 31
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
Atmos Energy Marketing, LLC
|
|
$
|
39,121
|
|
|
|
10
|
%
|
|
$
|
2,325
|
|
|
|
|
|
B.P. Energy Company
|
|
|
110,517
|
|
|
|
27
|
%
|
|
|
7,525
|
|
|
|
|
|
Eagle Energy Partners I, L.P.
|
|
|
51,116
|
|
|
|
13
|
%
|
|
|
3,867
|
|
|
|
|
|
Interstate Gas Supply, Inc.
|
|
|
63,489
|
|
|
|
16
|
%
|
|
|
6,531
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total 2007
|
|
|
|
|
$
|
264,243
|
|
|
|
65
|
%
|
|
$
|
20,248
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
Conoco-Phillips
|
|
$
|
45,920
|
|
|
|
12
|
%
|
|
$
|
|
|
|
|
|
|
B.P. Energy Company
|
|
|
89,118
|
|
|
|
23
|
%
|
|
|
8,950
|
|
|
|
|
|
Interstate Gas Supply, Inc.
|
|
|
55,647
|
|
|
|
14
|
%
|
|
|
6,767
|
|
|
|
|
|
Eagle Energy Partners I, L.P.
|
|
|
54,258
|
|
|
|
14
|
%
|
|
|
5,742
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total 2006
|
|
|
|
|
$
|
244,943
|
|
|
|
63
|
%
|
|
$
|
21,459
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
Conoco-Phillips
|
|
$
|
68,179
|
|
|
|
25
|
%
|
|
$
|
5,210
|
|
|
|
|
|
Dominion Field Services, Inc.
|
|
|
102,685
|
|
|
|
37
|
%
|
|
|
7,841
|
|
|
|
|
|
Columbia Distribution Companies
|
|
|
36,725
|
|
|
|
13
|
%
|
|
|
4,584
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total 2005
|
|
|
|
|
$
|
207,589
|
|
|
|
75
|
%
|
|
$
|
17,635
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 16
|
Derivative
Instruments:
|
CNX Gas has entered into derivative financial instruments, for
purposes other than trading, to convert the market prices
related to these anticipated sales of natural gas to fixed
prices. These instruments are designated as cash flow hedges and
extend through 2010. The net fair values of the outstanding
instruments are an asset of $9,619 and an asset of $4,083 at
December 31, 2007 and 2006, respectively.
CNX Gas entered into cash flow hedges for natural gas in 2007,
2006 and 2005. Gains or losses related to these derivative
instruments were recognized when the sale of the natural gas
affected earnings. The ineffective portion of the changes in the
fair value of these contracts was insignificant in 2007, 2006
and 2005.
For these cash flow hedge strategies, the fair values of the
derivatives are recorded on the balance sheet. The effective
portions of the changes in fair values of the derivatives are
recorded in accumulated other comprehensive income and loss and
are reclassified to sales in the period in which earnings are
impacted by the hedged items or in the period that the
transaction no longer qualifies as a cash flow hedge. There were
no transactions that ceased to qualify as a cash flow hedge in
2007, 2006 or 2005. CNX Gas consolidated balance sheet is
reflected on a net asset/(liability) basis for each counterparty.
Assuming market prices remain constant with prices at
December 31, 2007, $4,173 of the net $5,863 gain included
in other comprehensive income is expected to be recognized in
earnings over the next 12 months. The remaining net gain is
expected to be recognized through 2010.
CNX Gas did not have any derivatives designated as fair value
hedges in 2007, 2006 or 2005.
86
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
|
|
Note 17
|
Commitments
and Contingent Liabilities:
|
CNX Gas has various purchase commitments for materials, supplies
and items of permanent investment incidental to the ordinary
conduct of business. Such commitments are not at prices in
excess of current market value.
CNX Gas is a party to a case captioned GeoMet Operating Company,
Inc. and Pocahontas Mining Limited Liability Company v. CNX
Gas Company LLC in the Circuit Court for Buchanan County,
Virginia (Case
No. 337-06).
CNX Gas has a coal seam gas lease with Pocahontas Mining in
southwest Virginia and southern West Virginia. With the
agreement of Pocahontas Mining, GeoMet constructed a pipeline on
the property. CNX Gas sought a judicial determination that under
the terms of the lease, CNX Gas has the exclusive right to
construct and operate pipelines on the property. On May 23,
2007, the circuit court entered an Order granting CNX Gas
motion for summary judgment against GeoMet and Pocahontas
Mining. The order provided that CNX Gas has exclusive rights to
construct and operate pipelines on the property and prohibited
GeoMet from owning, operating, or maintaining its pipeline on
the property. The court stayed the portion of its order that
required GeoMet to remove its pipeline, pending GeoMets
appeal of the decision to the Virginia Supreme Court. GeoMet
filed an emergency appeal to the Virginia Supreme Court, which
on June 20, 2007, overturned the provision of the circuit
courts order requiring GeoMet to remove its pipeline, as
well as the related stay and the conditions thereof. The
remaining portions of the May 23, 2007 order have been
certified for interlocutory appeal to the Virginia Supreme
Court. Pocahontas Mining has amended its complaint to seek
rescission or reformation of the lease. We cannot predict the
ultimate outcome of this litigation; however, payments in the
future with respect to this lawsuit may be material to the
financial position, results of operations or cash flows of CNX
Gas.
On February 14, 2007, GeoMet, Inc. and certain of its
affiliates filed a lawsuit against CNX Gas Company LLC and
Island Creek Coal Company, a subsidiary of CONSOL Energy, in the
Circuit Court for the County of Tazewell, Virginia (Case
No. CL07000065-00).
The lawsuit alleges that CNX Gas conspired with Island Creek and
has violated the Virginia Antitrust Act and tortiously
interfered with GeoMets contractual relations, prospective
contracts and business expectancies. GeoMet seeks injunctive
relief, actual damages of $561,000, treble damages and punitive
damages in the amount of $350. CNX Gas and Island Creek filed
motions to dismiss all counts of the complaint. On
December 19, 2007, the court granted CNX Gas and
Island Creeks motions to dismiss all counts, with leave
for GeoMet to file an amended complaint. GeoMet has not filed an
amended complaint at this time, but they have indicated their
intention to do so. CNX Gas continues to believe this lawsuit to
be without merit and intends to vigorously defend it. However,
it is reasonably possible that the ultimate liabilities in the
future with respect to these lawsuits and claims may be material
to the financial position, results of operations, or cash flows
of CNX Gas.
In April 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 CNX Gas Company LLC in
the Circuit Court of the County of Buchanan (At Law
No. CL05000149-00)
for the year 2002; the county has since filed and served two
substantially similar cases for years 2003, 2004 and 2005. The
complaint alleges that our calculation of the license tax on the
basis of the wellhead price (sales price less post production
costs) rather than the sales price is improper. For the period
from 1999 through mid 2002, we paid the tax on the basis of the
sales price, but we have filed a claim for a refund for these
years. Since 2002, 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 Countys 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. However, it is reasonably
possible that the ultimate liabilities in the future with
respect to these lawsuits and claims may be material to the
financial position, results of operations, or cash flows of CNX
Gas.
87
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
In October 2005, CDX Gas, LLC (CDX) alleged that certain of
our vertical-to-horizontal CBM drilling methods infringe several
patents which they own. CDX demanded that we enter into a
business arrangement with CDX to use its patented technology.
Alternatively, CDX 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. A
number of our wells, particularly in Northern Appalachia, could
be covered by their claim. We deny all of these allegations and
we are vigorously contesting them. On November 14, 2005, we
filed a complaint for declaratory judgment in the
U.S. District Court for the Western District of
Pennsylvania (C.A.
No. 05-1574),
seeking a judicial determination that we do not infringe any
claim of any valid and enforceable CDX patent. CDX filed an
answer and counterclaim denying our allegations of invalidity
and alleging that we infringe certain claims of their patents. A
hearing was held before a court-appointed Special Master with
regard to the scope of the asserted CDX patents and the Special
Masters report and recommendations was adopted by order of
the court on October 13, 2006. As a result of that order
and subject to appellate review, certain of our wells may be
found to infringe certain of the CDX claims of the patents in
suit, if those patents are ultimately determined to be valid and
enforceable. The report of CDXs damages expert suggests
that CDX will seek (i) reasonable royalty damages on
production from allegedly infringing wells at a royalty rate of
10%, or approximately $1,900 based on projected production
through June 2007, and (ii) lost profits damages of
approximately $23,600 for allegedly infringing wells drilled
though August 2006, which assumes that CNX Gas would have no
choice but to have entered into a joint operating arrangement
with CDX. We believe that there is no valid basis in the law as
applied to the facts of this case for this lost
profits theory. Further, if infringement were to be found
of a valid, enforceable claim of a CDX patent, the report of
CNX Gas damages expert indicates that any potential
damages award would be based on a royalty of 5%, or
approximately $400. An updated damages report was recently
provided by CDX to CNX to account for additional accused wells
that have been drilled by CNX, the details of which are
currently being reviewed by CNX Gas damages expert.
Cross-motions for summary judgment as to infringement,
invalidity and unenforceability have been filed and briefed by
CNX Gas and CDX and were before a Special Master for decision in
the form of a report and recommendation to the District Court.
The Special Master issued his report and recommendation on
November 19, 2007, denying both the CNX Gas and CDX motions
for summary judgment in view of what he identified as genuine
issues of material fact. The Special Master did, however, find
that CNX had produced sufficient evidence to call into
serious question the validity and enforceability of the
CDX
patents-in-suit.
Both CNX Gas and CDX subsequently filed objections to the report
and recommendation, which are presently pending for decision by
the Court. We continue to believe that we do not infringe any
properly construed claim of any valid, enforceable patent.
However, it is reasonably possible that the ultimate liabilities
in the future with respect to these lawsuits and claims may be
material to the financial position, results of operations, or
cash flows of CNX Gas.
In 2004, Yukon Pocahontas Coal Company, Buchanan Coal Company,
and Sayers-Pocahontas Coal Company filed a complaint against
Consolidation Coal Company (CCC), a subsidiary of
CONSOL Energy in the Circuit Court of Buchanan County, Virginia,
seeking damages and injunctive relief in connection with the
deposit of untreated water from mining activities at CCCs
Buchanan Mine into nearby void spaces in the mine of one of
CONSOL Energys other subsidiaries, Island Creek Coal
Company (ICCC). CCC believes that it had, and
continues to have, the right to store water in these void areas.
On September 21, 2006, the plaintiffs filed an amended
complaint in the Circuit Court of Buchanan County, Virginia
(Case
No. CL04-91)
which, among other things, added CONSOL Energy, ICCC and CNX Gas
Company LLC as additional defendants. The amended complaint
alleges, among other things, that CNX Gas Company LLC, as lessee
and operator under certain coalbed methane gas leases from
plaintiffs, had a duty to prevent CCC from depositing water into
the mine voids and failed to do so. The proposed amended
complaint seeks $150,000 in damages from the additional
defendants, plus costs, interest and attorneys fees. CNX
Gas Company LLC denies that it has any liability in this matter
and intends to vigorously defend this action. However, it is
reasonably possible that the ultimate liabilities in the future
with respect to these lawsuits and claims may be material to the
financial position, results of operations, or cash flows of CNX
Gas.
88
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
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 owners. 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 pay, and subsequently
paid, damages to the group of royalty owners that brought the
suit and for the period. A final payment was subsequently made
to the plaintiffs to adjust all royalties owed to the plaintiffs
for subsequent periods, which effectively settled this case. CNX
Gas recognized an estimated liability for other similarly
situated plaintiffs who could bring similar claims. This amount
is included in other liabilities on the balance sheet and is
evaluated quarterly. CNX Gas 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.
At December 31, 2007, CNX Gas has provided the following
financial guarantees and letters of credit to certain third
parties. CNX Gas management believes that these guarantees will
expire without being funded, and therefore the commitments will
not have a material adverse effect on financial condition. The
fair value of all liabilities associated with these guarantees
have been properly recorded and reported in the financial
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts
|
|
|
Less Than
|
|
|
|
|
|
|
|
|
Beyond
|
|
|
|
Committed
|
|
|
1 Year
|
|
|
1-3 Years
|
|
|
3-5 Years
|
|
|
5 Years
|
|
|
Letters of Credit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
$
|
14,933
|
|
|
$
|
14,913
|
|
|
$
|
20
|
|
|
$
|
0
|
|
|
$
|
0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Letters of Credit
|
|
$
|
14,933
|
|
|
$
|
14,913
|
|
|
$
|
20
|
|
|
$
|
0
|
|
|
$
|
0
|
|
Surety Bonds:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Environmental
|
|
$
|
1,201
|
|
|
$
|
1,201
|
|
|
$
|
0
|
|
|
$
|
0
|
|
|
$
|
0
|
|
Other
|
|
|
1,780
|
|
|
|
1,720
|
|
|
|
60
|
|
|
|
0
|
|
|
|
0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Surety Bonds
|
|
$
|
2,981
|
|
|
$
|
2,921
|
|
|
$
|
60
|
|
|
$
|
0
|
|
|
$
|
0
|
|
Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm Transportation
|
|
$
|
49,292
|
|
|
$
|
7,870
|
|
|
$
|
14,379
|
|
|
$
|
9,948
|
|
|
$
|
17,095
|
|
Guarantees
|
|
|
16,270
|
|
|
|
16,270
|
|
|
|
0
|
|
|
|
0
|
|
|
|
0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Other
|
|
$
|
65,562
|
|
|
$
|
24,140
|
|
|
$
|
14,379
|
|
|
$
|
9,948
|
|
|
$
|
17,095
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Commitments
|
|
$
|
83,476
|
|
|
$
|
41,974
|
|
|
$
|
14,459
|
|
|
$
|
9,948
|
|
|
$
|
17,095
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Letters
of Credit
On December 28, 2006, CNX Gas obtained the issuance of a
letter of credit to the Commonwealth of Pennsylvania in the
amount of $20 to serve as collateral for a one year period for a
permit issued by PENNDOT.
On May 2, 2007, CNX amended a letter of credit to East
Tennessee Natural Gas, LLC which serves as collateral for a
fifteen year firm transportation contract on the Jewell Ridge
lateral, which had an in-service date of October 2006. The
amount of the letter of credit at December 31, 2007 is
$14,761.
89
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
On April 15, 2005, CNX Gas obtained the issuance of a
letter of credit to Allegheny Energy Supply Co. to serve as
collateral for a period of two years to cover a potential tax
liability of $152.
Surety
Bonds
CNX Gas has issued surety bonds totaling $2,981. CNX Gas
guarantees the performance of these obligations.
Other
Guarantees
CNX Gas is the guarantor of an agreement with Washington Gas
Energy Services, Inc. for $5,000, an agreement with
Constellation Energy Commodities Group, Inc. for $1,000, an
agreement with Dominion Transmission, Inc. for $155, and an
agreement with Columbia Gas Transmission Corp. for $115.
CONSOL Energy has also provided certain parental guarantees
related to activity associated with CNX Gas. CNX Gas
anticipates that these parental guarantees will be transferred
from CONSOL Energy to CNX Gas over time. CNX Gas management
believes these parental guarantees will also expire without
being funded, and therefore the commitments will not have a
material adverse effect on our financial condition.
Variable
Interest
CNX Gas is a guarantor of the obligations for a CNX Gas
contractor (debtor) under a loan agreement with Huntington
National Bank (lender) dated November 27, 2006. This
guarantee causes the debtor to be characterized as a variable
interest entity for purposes of FASB Interpretation (FIN)
No. 46, Consolidation of Variable Interest
Entities-an Interpretation of ARB No. 51. This
guarantee is related to the debtors procurement of two
drilling rigs dedicated to serve CNX Gas and is capped at
$10,000. We are the primary beneficiary of the variable interest
as CNX Gas guarantees the debt and is the sole customer of that
entity. FIN 46 requires us to consolidate their financial
results into our financial statements as a variable interest
entity at their fair value as of the date CNX Gas became the
primary beneficiary, which was in April 2007. As of
December 31, 2007, the outstanding balance on the loan
agreement was $7,648, of which $2,874 is current and $4,774 is
long term.
The guaranty continues until the indebtedness has been fully
satisfied, but does not extend beyond the maturity date of
December 31, 2010. The loan is collateralized by the
drilling rigs. CNX Gas holds a position in the collateral second
to the bank. Any failure of the CNX Gas contractor to satisfy
this obligation would require CNX Gas to make payment in full to
Huntington National Bank.
Under a separate security agreement with the contractor, upon
default CNX Gas may require re-payment by the contractor, sell
the assets, or retain them for its own use.
Firm
Transportation
We hold firm transportation on various interstate pipelines.
90
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
|
|
Note 18
|
Segment
Information:
|
The principal activity of CNX Gas is to produce methane gas for
sale primarily to gas wholesalers. CNX Gas has two
reportable segments: Central Appalachia and Northern Appalachia.
All sales to customers in excess of 10% of outside sales relate
to the Central Appalachia segment for the twelve months ended
December 31, 2007, 2006 and 2005.
Reportable segment results for the twelve months ended
December 31, 2007 are:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Central
|
|
|
Northern
|
|
|
|
|
|
|
|
|
Adjustments &
|
|
|
|
|
|
|
Appalachia
|
|
|
Appalachia
|
|
|
Total
|
|
|
Corporate
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
Sales outside
|
|
$
|
374,765
|
|
|
$
|
30,070
|
|
|
$
|
404,835
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
404,835
|
|
Sales related parties
|
|
|
11,564
|
|
|
|
54
|
|
|
|
11,618
|
|
|
|
|
|
|
|
|
|
|
|
11,618
|
|
Sales royalty interest gas
|
|
|
46,169
|
|
|
|
417
|
|
|
|
46,586
|
|
|
|
|
|
|
|
|
|
|
|
46,586
|
|
Sales purchased gas
|
|
|
7,628
|
|
|
|
|
|
|
|
7,628
|
|
|
|
|
|
|
|
|
|
|
|
7,628
|
|
Other revenue
|
|
|
2,848
|
|
|
|
21
|
|
|
|
2,869
|
|
|
|
3,772
|
|
|
|
|
|
|
|
6,641
|
|
Intersegment revenues
|
|
|
77,335
|
|
|
|
4,005
|
|
|
|
81,340
|
|
|
|
|
|
|
|
(81,340
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenue and Other Income
|
|
$
|
520,309
|
|
|
$
|
34,567
|
|
|
$
|
554,876
|
|
|
$
|
3,772
|
|
|
$
|
(81,340
|
)
|
|
$
|
477,308
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Before Income Taxes(A)
|
|
$
|
212,521
|
|
|
$
|
5,241
|
|
|
$
|
217,762
|
|
|
$
|
2,877
|
|
|
$
|
|
|
|
$
|
220,639
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment assets(B)(C)
|
|
$
|
1,113,107
|
|
|
$
|
209,700
|
|
|
$
|
1,322,807
|
|
|
$
|
57,896
|
|
|
$
|
|
|
|
$
|
1,380,703
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
$
|
42,809
|
|
|
$
|
6,152
|
|
|
$
|
48,961
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
48,961
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
220,795
|
|
|
$
|
136,404
|
|
|
$
|
357,199
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
357,199
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(A) |
|
Includes equity in income of affiliates of $2,058 for Central
Appalachia. Corporate Segment includes $3,772 of interest
income, $1,011 of bank fees, and $116 of equity in income of
affiliates. |
|
(B) |
|
Includes investments in unconsolidated equity affiliates of
$3,408 for Central Appalachia. Corporate segment includes
investment in unconsolidated equity affiliates of $24,876 and
$972 of recoverable income taxes. |
|
(C) |
|
Includes cash of $376 in the Northern Appalachia, related to our
variable interest entity, and $31,672 in Corporate Segments,
respectively. |
91
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
Reportable segment results for the twelve months ended
December 31, 2006 are:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Central
|
|
|
Northern
|
|
|
|
|
|
|
|
|
Adjustments &
|
|
|
|
|
|
|
Appalachia
|
|
|
Appalachia
|
|
|
Total
|
|
|
Corporate
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
Sales outside
|
|
$
|
364,025
|
|
|
$
|
21,031
|
|
|
$
|
385,056
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
385,056
|
|
Sales related parties
|
|
|
8,392
|
|
|
|
98
|
|
|
|
8,490
|
|
|
|
|
|
|
|
|
|
|
|
8,490
|
|
Sales royalty interest gas
|
|
|
50,878
|
|
|
|
176
|
|
|
|
51,054
|
|
|
|
|
|
|
|
|
|
|
|
51,054
|
|
Sales purchased gas
|
|
|
43,973
|
|
|
|
|
|
|
|
43,973
|
|
|
|
|
|
|
|
|
|
|
|
43,973
|
|
Other revenue
|
|
|
21,048
|
|
|
|
785
|
|
|
|
21,833
|
|
|
|
3,453
|
|
|
|
|
|
|
|
25,286
|
|
Intersegment revenues
|
|
|
67,326
|
|
|
|
1,452
|
|
|
|
68,778
|
|
|
|
|
|
|
|
(68,778
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenue and Other Income
|
|
$
|
555,642
|
|
|
$
|
23,542
|
|
|
$
|
579,184
|
|
|
$
|
3,453
|
|
|
$
|
(68,778
|
)
|
|
$
|
513,859
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Before Income Taxes(D)
|
|
$
|
250,607
|
|
|
$
|
3,825
|
|
|
$
|
254,432
|
|
|
$
|
2,008
|
|
|
$
|
|
|
|
$
|
256,440
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment assets(E)
|
|
$
|
949,472
|
|
|
$
|
73,596
|
|
|
$
|
1,023,068
|
|
|
$
|
131,933
|
|
|
$
|
|
|
|
$
|
1,155,001
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
$
|
35,190
|
|
|
$
|
2,809
|
|
|
$
|
37,999
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
37,999
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
122,287
|
|
|
$
|
31,956
|
|
|
$
|
154,243
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
154,243
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(D) |
|
Includes equity in earnings of affiliates of $1,405 for Central
Appalachia. Corporate segment includes $3,453 of interest
income, $1,018 of bank fees, and equity in loss of affiliates of
$427. |
|
(E) |
|
Includes investments in unconsolidated equity affiliates of
$27,523 for Central Appalachia. Corporate segment includes
investments in unconsolidated equity affiliates of $24,760 and
cash of $107,173. |
Reportable segment results for the twelve months ended
December 31, 2005 are:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Central
|
|
|
Northern
|
|
|
|
|
|
|
|
|
Adjustments &
|
|
|
|
|
|
|
Appalachia
|
|
|
Appalachia
|
|
|
Total
|
|
|
Corporate
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
Sales outside
|
|
$
|
256,967
|
|
|
$
|
20,064
|
|
|
$
|
277,031
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
277,031
|
|
Sales related parties
|
|
|
5,969
|
|
|
|
83
|
|
|
|
6,052
|
|
|
|
|
|
|
|
|
|
|
|
6,052
|
|
Sales royalty interest gas
|
|
|
45,128
|
|
|
|
223
|
|
|
|
45,351
|
|
|
|
|
|
|
|
|
|
|
|
45,351
|
|
Sales purchased gas
|
|
|
275,148
|
|
|
|
|
|
|
|
275,148
|
|
|
|
|
|
|
|
|
|
|
|
275,148
|
|
Other revenue
|
|
|
9,620
|
|
|
|
54
|
|
|
|
9,674
|
|
|
|
185
|
|
|
|
|
|
|
|
9,859
|
|
Intersegment revenues
|
|
|
46,680
|
|
|
|
795
|
|
|
|
47,475
|
|
|
|
|
|
|
|
(47,475
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenue and Other Income
|
|
$
|
639,512
|
|
|
$
|
21,219
|
|
|
$
|
660,731
|
|
|
$
|
185
|
|
|
$
|
(47,475
|
)
|
|
$
|
613,441
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (Loss) Before Income Taxes(F)
|
|
$
|
162,769
|
|
|
$
|
4,339
|
|
|
$
|
167,108
|
|
|
$
|
(390
|
)
|
|
$
|
|
|
|
$
|
166,718
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment assets(G)
|
|
$
|
763,432
|
|
|
$
|
41,135
|
|
|
$
|
804,567
|
|
|
$
|
54,600
|
|
|
$
|
|
|
|
$
|
859,167
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
$
|
31,619
|
|
|
$
|
3,420
|
|
|
$
|
35,039
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
35,039
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
87,508
|
|
|
$
|
23,244
|
|
|
$
|
110,752
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
110,752
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
92
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
|
|
|
(F) |
|
Includes equity in earnings of unconsolidated affiliates of $138
for Central Appalachia. Corporate segment includes $185 of
interest income, $288 of bank fees, and equity in loss of
unconsolidated affiliates of $287. |
|
(G) |
|
Includes investments in unconsolidated equity affiliates of
$24,340 for Central Appalachia. Corporate segment includes
investments in unconsolidated equity affiliates of $25,188,
deferred taxes of $9,339 and cash of $20,073. |
|
|
Note 19
|
Subsequent
Event:
|
On January 29, 2008, CONSOL Energy announced an intention
to commence an exchange offer to acquire the 18.3% of
outstanding shares of CNX Gas that CONSOL Energy does not
currently own.
Other
Supplemental Information Supplemental Gas Data
(unaudited):
The following information was prepared in accordance with
Statement of Financial Accounting Standards No. 69,
Disclosures About Oil and Gas Producing Activities
and related accounting rules:
Capitalized
Costs:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Proved Properties
|
|
$
|
125,118
|
|
|
$
|
91,913
|
|
Unproved Properties
|
|
|
81,078
|
|
|
|
765
|
|
Wells and Related Equipment
|
|
|
599,382
|
|
|
|
402,200
|
|
Gathering Assets
|
|
|
595,137
|
|
|
|
520,906
|
|
Uncompleted Wells and Related Equipment
|
|
|
72,858
|
|
|
|
93,414
|
|
|
|
|
|
|
|
|
|
|
Total Property, Plant and Equipment
|
|
|
1,473,573
|
|
|
|
1,109,198
|
|
Accumulated Depreciation, Depletion and Amortization
|
|
|
(251,367
|
)
|
|
|
(200,755
|
)
|
|
|
|
|
|
|
|
|
|
Net Capitalized Costs
|
|
$
|
1,222,206
|
|
|
$
|
908,443
|
|
|
|
|
|
|
|
|
|
|
Proportionate Share of Gas Producing Net Property, Plant and
Equipment of Unconsolidated Equity Affiliates
|
|
$
|
30,364
|
|
|
$
|
22,139
|
|
|
|
|
|
|
|
|
|
|
Costs incurred for Property Acquisition, Exploration and
Development (*):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Twelve Months Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
Consolidated
|
|
|
Equity
|
|
|
Consolidated
|
|
|
Equity
|
|
|
Consolidated
|
|
|
Equity
|
|
|
|
Operations
|
|
|
Affiliates
|
|
|
Operations
|
|
|
Affiliates
|
|
|
Operations
|
|
|
Affiliates
|
|
|
Property acquisitions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Properties
|
|
$
|
33,205
|
|
|
$
|
|
|
|
$
|
8,797
|
|
|
$
|
|
|
|
$
|
7,666
|
|
|
$
|
20
|
|
Unproved Properties
|
|
|
80,313
|
|
|
|
|
|
|
|
765
|
|
|
|
|
|
|
|
667
|
|
|
|
|
|
Development
|
|
|
257,935
|
|
|
|
|
|
|
|
151,774
|
|
|
|
|
|
|
|
86,273
|
|
|
|
|
|
Exploration
|
|
|
16,503
|
|
|
|
|
|
|
|
832
|
|
|
|
2,334
|
|
|
|
19,370
|
|
|
|
412
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
387,956
|
|
|
$
|
|
|
|
$
|
162,168
|
|
|
$
|
2,334
|
|
|
$
|
113,976
|
|
|
$
|
432
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(*) |
|
Includes costs incurred whether capitalized or expensed |
93
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
Results
of Operations for Producing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Twelve Months Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
Consolidated
|
|
|
Equity
|
|
|
Consolidated
|
|
|
Equity
|
|
|
Consolidated
|
|
|
Equity
|
|
|
|
Operations
|
|
|
Affiliates
|
|
|
Operations
|
|
|
Affiliates
|
|
|
Operations
|
|
|
Affiliates
|
|
|
Production Revenue
|
|
$
|
416,452
|
|
|
$
|
2,755
|
|
|
$
|
393,649
|
|
|
$
|
1,913
|
|
|
$
|
283,137
|
|
|
$
|
2,406
|
|
Royalty Interest Gas Revenue
|
|
|
46,586
|
|
|
|
294
|
|
|
|
51,054
|
|
|
|
446
|
|
|
|
45,351
|
|
|
|
408
|
|
Purchased Gas Revenue
|
|
|
7,628
|
|
|
|
201
|
|
|
|
43,973
|
|
|
|
356
|
|
|
|
275,148
|
|
|
|
2,561
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenue
|
|
|
470,666
|
|
|
|
3,250
|
|
|
|
488,676
|
|
|
|
2,715
|
|
|
|
603,636
|
|
|
|
5,375
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lifting Costs
|
|
|
38,721
|
|
|
|
679
|
|
|
|
33,357
|
|
|
|
480
|
|
|
|
30,399
|
|
|
|
623
|
|
Gathering Costs
|
|
|
61,798
|
|
|
|
630
|
|
|
|
58,102
|
|
|
|
359
|
|
|
|
43,903
|
|
|
|
168
|
|
Royalty Expense
|
|
|
40,011
|
|
|
|
294
|
|
|
|
41,998
|
|
|
|
446
|
|
|
|
36,641
|
|
|
|
408
|
|
Other Costs
|
|
|
19,772
|
|
|
|
646
|
|
|
|
12,876
|
|
|
|
541
|
|
|
|
10,339
|
|
|
|
915
|
|
Purchased Gas Costs
|
|
|
7,162
|
|
|
|
165
|
|
|
|
44,843
|
|
|
|
299
|
|
|
|
278,720
|
|
|
|
2,434
|
|
DD&A
|
|
|
48,961
|
|
|
|
294
|
|
|
|
37,999
|
|
|
|
512
|
|
|
|
35,039
|
|
|
|
870
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Costs
|
|
|
216,425
|
|
|
|
2,708
|
|
|
|
229,175
|
|
|
|
2,637
|
|
|
|
435,041
|
|
|
|
5,418
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-tax Operating Income
|
|
|
254,241
|
|
|
|
542
|
|
|
|
259,501
|
|
|
|
78
|
|
|
|
168,595
|
|
|
|
(43
|
)
|
Income Taxes
|
|
|
98,595
|
|
|
|
210
|
|
|
|
97,728
|
|
|
|
29
|
|
|
|
65,280
|
|
|
|
(17
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of Operations for Producing Activities excluding
Corporate and Interest Costs
|
|
$
|
155,646
|
|
|
$
|
332
|
|
|
$
|
161,773
|
|
|
$
|
49
|
|
|
$
|
103,315
|
|
|
$
|
(26
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Reserve Quantity (Mcfe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning Reserves(a)
|
|
|
1,263,293
|
|
|
|
2,200
|
|
|
|
1,127,724
|
|
|
|
2,672
|
|
|
|
1,042,403
|
|
|
|
2,385
|
|
Revisions(b)
|
|
|
(25,036
|
)
|
|
|
221
|
|
|
|
109,116
|
|
|
|
(584
|
)
|
|
|
57,575
|
|
|
|
521
|
|
Extensions and Discoveries
|
|
|
145,834
|
|
|
|
1,484
|
|
|
|
82,363
|
|
|
|
337
|
|
|
|
77,917
|
|
|
|
|
|
Production
|
|
|
(57,928
|
)
|
|
|
(321
|
)
|
|
|
(55,910
|
)
|
|
|
(225
|
)
|
|
|
(50,171
|
)
|
|
|
(234
|
)
|
Purchases of Reserves In-Place
|
|
|
13,746
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of Reserves In-Place
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending Reserves
|
|
|
1,339,909
|
|
|
|
3,584
|
|
|
|
1,263,293
|
|
|
|
2,200
|
|
|
|
1,127,724
|
|
|
|
2,672
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of Period
|
|
|
609,700
|
|
|
|
2,200
|
|
|
|
549,574
|
|
|
|
2,672
|
|
|
|
395,152
|
|
|
|
2,385
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of Period
|
|
|
667,726
|
|
|
|
3,584
|
|
|
|
609,700
|
|
|
|
2,200
|
|
|
|
549,574
|
|
|
|
2,672
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Proved developed and proved undeveloped gas reserves are defined
by the Securities and Exchange Commission Rule 4.10(a) of
Regulation S-X.
Generally, these reserves would be commercially recovered under
current economic conditions, operating methods and government
regulations. CNX Gas cautions that there are many inherent
uncertainties in estimating proved reserve quantities,
projecting future production rates, and timing of development
expenditures. Accordingly, these estimates are likely to change
as future information becomes available. Proved oil and gas
reserves are estimated quantities of natural gas and CBM gas
which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating
conditions. Proved developed reserves are those reserves
expected to be recovered through existing wells, with existing
equipment and operating methods. |
94
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
|
|
|
(b) |
|
2007 revisions are based upon our review of production curves of
over 6,000 wells. Revisions were both upward and downward and no
well was individually material. Production optimization is an
ongoing effort. |
CNX Gas proved gas reserves are located in the United States.
Standardized
Measure of Discounted Future Net Cash Flows:
The following information has been prepared in accordance with
the provisions of Statement of Financial Accounting Standards
No. 69, Disclosures about Oil and Gas Producing
Activities. This statement requires the standardized
measure of discounted future net cash flows to be based on
year-end sales prices, costs and statutory income tax rates and
a 10 percent annual discount rate. Because prices used in
the calculation are as of the end of the period, the
standardized measure could vary significantly from year to year
based on the market conditions at that specific date.
The projections should not be viewed as realistic estimates of
future cash flows, nor should the standardized
measure be interpreted as representing current value to
CNX Gas. Material revisions to estimates of proved reserves may
occur in the future; development and production of the reserves
may not occur in the periods assumed; actual prices realized are
expected to vary significantly from those used; and actual costs
may vary. CNX Gas investment and operating decisions are
not based on the information presented, but on a wide range of
reserve estimates that include probable as well as proved
reserves, and on different price and cost assumptions.
The standardized measure is intended to provide a better means
for comparing the value of CNX Gas proved reserves at a
given time with those of other gas producing companies than is
provided by a comparison of raw proved reserve quantities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Future Cash Flows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
9,509,665
|
|
|
$
|
7,105,265
|
|
|
$
|
11,675,551
|
|
Production costs
|
|
|
(3,004,619
|
)
|
|
|
(2,568,731
|
)
|
|
|
(2,852,033
|
)
|
Development costs
|
|
|
(636,436
|
)
|
|
|
(552,114
|
)
|
|
|
(422,315
|
)
|
Income tax expense
|
|
|
(2,259,415
|
)
|
|
|
(1,500,533
|
)
|
|
|
(3,251,265
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Net Cash Flows
|
|
|
3,609,195
|
|
|
|
2,483,887
|
|
|
|
5,149,938
|
|
Discounted to present value at a 10% annual rate
|
|
|
(2,219,655
|
)
|
|
|
(1,548,996
|
)
|
|
|
(3,279,144
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total standardized measure of discounted net cash flows
|
|
$
|
1,389,540
|
|
|
$
|
934,891
|
|
|
$
|
1,870,794
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
95
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
The following are the principal sources of change in the
standardized measure of discounted future net cash flows during:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Balance at Beginning of Period
|
|
$
|
934,891
|
|
|
$
|
1,870,794
|
|
|
$
|
1,029,538
|
|
Net changes in sales prices and production costs
|
|
|
1,688,906
|
|
|
|
(5,341,525
|
)
|
|
|
3,539,448
|
|
Sales net of production costs
|
|
|
(208,810
|
)
|
|
|
(438,174
|
)
|
|
|
(234,526
|
)
|
Net change due to revisions in quantity estimates
|
|
|
485,577
|
|
|
|
1,492,654
|
|
|
|
632,547
|
|
Net change due to acquisition
|
|
|
2,840
|
|
|
|
|
|
|
|
|
|
Development costs incurred, previously estimated
|
|
|
295,422
|
|
|
|
169,169
|
|
|
|
110,916
|
|
Changes in estimated future development costs
|
|
|
(379,744
|
)
|
|
|
(298,968
|
)
|
|
|
(267,691
|
)
|
Net change in future income taxes
|
|
|
(758,882
|
)
|
|
|
1,750,732
|
|
|
|
(1,505,484
|
)
|
Accretion of discount and other
|
|
|
(670,660
|
)
|
|
|
1,730,209
|
|
|
|
(1,433,954
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Discounted Cash Flow at End of Period
|
|
$
|
1,389,540
|
|
|
$
|
934,891
|
|
|
$
|
1,870,794
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Supplemental Information Selected Quarterly
Data (unaudited)($ in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
June 30,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2007
|
|
|
2007
|
|
|
2007*
|
|
|
Total Revenue and Other Income
|
|
$
|
115,132
|
|
|
$
|
133,471
|
|
|
$
|
109,805
|
|
|
$
|
118,900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Costs and Expense
|
|
$
|
61,894
|
|
|
$
|
66,539
|
|
|
$
|
57,808
|
|
|
$
|
70,428
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Earnings Before Minority Interest
|
|
$
|
53,238
|
|
|
$
|
66,932
|
|
|
$
|
51,997
|
|
|
$
|
47,978
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Earnings Before Income Tax
|
|
$
|
53,238
|
|
|
$
|
66,932
|
|
|
$
|
51,997
|
|
|
$
|
48,472
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
32,996
|
|
|
$
|
41,488
|
|
|
$
|
31,296
|
|
|
$
|
29,898
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per Share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.22
|
|
|
$
|
0.27
|
|
|
$
|
0.21
|
|
|
$
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.22
|
|
|
$
|
0.27
|
|
|
$
|
0.21
|
|
|
$
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Shares Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
150,864,825
|
|
|
|
150,870,810
|
|
|
|
150,895,233
|
|
|
|
150,914,225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dilutive
|
|
|
151,068,089
|
|
|
|
151,145,174
|
|
|
|
151,149,432
|
|
|
|
151,241,316
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Included in the fourth quarter are out-of-period year-to-date
adjustments made in the fourth quarter. |
96
CNX GAS
CORPORATION AND SUBSIDIARIES
NOTES TO
AUDITED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
June 30,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2006
|
|
|
2006
|
|
|
2006
|
|
|
Total Revenue and Other Income
|
|
$
|
148,223
|
|
|
$
|
122,852
|
|
|
$
|
123,567
|
|
|
$
|
119,217
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Costs and Expense
|
|
$
|
73,286
|
|
|
$
|
60,532
|
|
|
$
|
61,770
|
|
|
$
|
61,831
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Earnings Before Income Tax
|
|
$
|
74,937
|
|
|
$
|
62,320
|
|
|
$
|
61,797
|
|
|
$
|
57,386
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
45,876
|
|
|
$
|
38,153
|
|
|
$
|
37,593
|
|
|
$
|
38,245
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per Share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.30
|
|
|
$
|
0.25
|
|
|
$
|
0.25
|
|
|
$
|
0.25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.30
|
|
|
$
|
0.25
|
|
|
$
|
0.25
|
|
|
$
|
0.25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Shares Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
150,833,334
|
|
|
|
150,833,334
|
|
|
|
150,850,930
|
|
|
|
150,864,075
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dilutive
|
|
|
150,931,545
|
|
|
|
151,060,061
|
|
|
|
151,029,192
|
|
|
|
151,062,622
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
97
|
|
ITEM 9.
|
CHANGES
IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
|
None.
|
|
ITEM 9A.
|
CONTROLS
AND PROCEDURES
|
Disclosure
controls and procedures
CNX Gas, under the supervision and with the participation of its
management, including the Companys principal executive
officer and principal financial officer, evaluated the
effectiveness of its disclosure controls and
procedures, as such term is defined in
Rule 13a-15(e)
under the Securities Act of 1934, as amended (the Exchange
Act), as of the end of the period covered by this annual
report on
Form 10-K.
Based on that evaluation, our principal executive officer and
principal financial officer have concluded that CNX Gas
disclosure controls and procedures are effective to ensure that
information required to be disclosed by CNX Gas in reports that
we file or submit under the Exchange Act is recorded, processed,
summarized and reported within the time periods specified in
Securities and Exchange Commission rules and forms, and include
controls and procedures designed to ensure that information
required to be disclosed by us in such reports is accumulated
and communicated to our management, including our principal
executive officer and principal financial officer, as
appropriate to allow timely decisions regarding required
disclosure.
Managements
Report on Internal Control Over Financial Reporting
CNX Gas management is responsible for establishing and
maintaining adequate internal control over financial reporting.
CNX Gas internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and preparation of financial
statements for external purposes in accordance with accounting
principles generally accepted in the United States of America.
CNX Gas internal control over financial reporting included
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect transactions and dispositions of assets;
(2) provide reasonable assurances that transactions are
recorded as necessary to permit preparation of financial
statements in accordance with accounting principles generally
accepted in the United States of America, and that receipts and
expenditures are being made only in accordance with
authorizations of management and the directors of CNX Gas; and
(3) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use or disposition
of CNX Gas assets that could have a material effect on our
financial statements.
Because of its inherent limitation, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of CNX Gas internal
control over financial reporting as of December 31, 2007.
In making this assessment, management used the criteria set
forth by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO) in Internal Control-Integrated
Framework. Based on its assessment and those criteria,
management has concluded that CNX Gas maintained effective
internal control over financial reporting as of
December 31, 2007. The effectiveness of CNX Gas
internal control over financial reporting as of
December 31, 2007 has been audited by
PricewaterhouseCoopers LLP, an independent registered public
accounting firm, as stated in their report which appears herein.
Changes
in Internal Controls Over Financial Reporting
None.
|
|
ITEM 9B.
|
OTHER
INFORMATION
|
None.
98
PART III
|
|
ITEM 10.
|
DIRECTORS
AND EXECUTIVE OFFICERS OF THE REGISTRANT
|
The information required by this Item is incorporated herein by
reference to the information under the captions
Proposal #1 Nominations for Election of
Directors, General Information The Board
of Directors and Its Committees The Board of
Directors, General Information The Board
of Directors and Its Committees Membership and
Meetings of the Board of Directors and Its Committees and
Section 16(a) Beneficial Ownership Reporting
Compliance in the Proxy Statement for the annual meeting
of shareholders to be held on April 21, 2008 (the
Proxy Statement). The third paragraph of the section
titled available information on page 12 is
incorporated herein by reference.
Executive
Officers of CNX Gas Corporation
The following is a list of CNX Gas executive officers, their
ages as of February 15, 2008 and their positions and
offices held with CNX Gas.
|
|
|
|
|
|
|
Name
|
|
Age
|
|
Position
|
|
Nicholas J. DeIuliis
|
|
|
39
|
|
|
President and Chief Executive Officer and Director
|
Stephen W. Johnson
|
|
|
49
|
|
|
Executive Vice President, Secretary and General Counsel
|
Mark D. Gibbons
|
|
|
49
|
|
|
Senior Vice President and Chief Financial Officer
|
Randall M. Albert
|
|
|
50
|
|
|
Senior Vice President Emerging Business Units
|
Dr. DeAnn Craig
|
|
|
56
|
|
|
Senior Vice President Asset Assessment
|
J. Michael Onifer
|
|
|
51
|
|
|
Senior Vice President Established Business Units
|
Nicholas J. DeIuliis, 39, has been President and Chief
Executive Officer and a Director of CNX Gas since its formation
on June 30, 2005. Prior to that, Mr. DeIuliis was
Senior Vice President Strategic Planning of CONSOL
Energy from November 1, 2004 until August 8, 2005.
Prior to that time, Mr. DeIuliis served as Vice President
Strategic Planning from April 1, 2002 until
November 1, 2004, Director Corporate Strategy
from October 1, 2001 to April 1, 2002,
Manager Strategic Planning from January 1, 2001
to October 1, 2001 and Supervisor Process
Engineering from April 1, 1999 to January 1, 2001, all
of which positions he held at CONSOL Energy. Mr. DeIuliis
is also a member of the Board of Directors of the Independent
Petroleum Association of America and the Carnegie Science
Center. Mr. DeIuliis is also a registered engineer in the
Commonwealth of Pennsylvania and a member of the Pennsylvania
Bar. He received a bachelors degree in chemical
engineering from Pennsylvania State University and a
masters of business administration and juris doctorate
from Duquesne University.
Stephen W. Johnson, 49, has been General Counsel of CNX
Gas since September 1, 2005. He was named Executive Vice
President as of December 5, 2005. Prior to joining CNX Gas,
he was a partner since 2001 in the Business and Regulatory Group
at Reed Smith LLP, an international law firm with about 1,000
lawyers. From 1984 to 2001, Mr. Johnson was with the law
firm of Buchanan Ingersoll Professional Corporation.
Mr. Johnson has served as corporate, securities and mergers
and acquisitions counsel to both public and privately held
companies for his entire professional career. Mr. Johnson
is Vice Chairman of NEED, a non-profit organization that
provides college scholarships to minority students, and a
director of Concordia Lutheran Ministries, a non-profit
continuing care retirement community serving thousands of
elderly persons each year. Mr. Johnson received a
bachelors degree in history from the University of
Virginia and a juris doctor degree from the University of
Pittsburgh School of Law.
Mark D. Gibbons, 49, is Senior Vice President and Chief
Financial Officer of CNX Gas Corporation. He attained that
position on March 1, 2007. Previously, he was a director of
Protiviti, an international risk consulting firm, where he
focused on providing Sarbanes-Oxley consulting advice for
clients that included CNX Gas, and on providing outsource
internal audit services. A CPA and Certified Internal Auditor,
Mr. Gibbons has 22 years of experience in the
accounting and auditing fields. From 1999 to 2004, Mark was vice
president of finance for MARC USA, a national integrated
marketing and communications company. He
99
is experienced with accounting, auditing, and financial
reporting and has led audit engagements as an audit senior
manager at Deloitte Touche, LLP. Mr. Gibbons received his
bachelors degree in accounting from Franciscan University
of Steubenville.
Randall Albert, 50, was named Senior Vice
President Emerging Business Units in July of 2007.
Prior to that, he had been Vice President Emerging
Business Units. In his current position, he is responsible for
developing coalbed methane (CBM) in southwestern Pennsylvania
and northern West Virginia (Mountaineer), exploring for CBM in
central Pennsylvania (Nittany), and exploring for gas in the New
Albany Shale formation in western Kentucky (Cardinal). Earlier,
he held the position of General Manager Technical
Services and Administration. He joined CNX Gas in 1990. From
1980 to 1990 Mr. Albert held various mining positions
including Mine Engineer. He is a registered professional
engineer in Virginia and West Virginia. Mr. Albert
graduated from Virginia Tech with a B.S. degree in mining
engineering.
Dr. DeAnn Craig, 56, was named Senior Vice
President Asset Assessment in July of 2007. In this
capacity, Dr. Craig will play a key role in helping CNX Gas
determine how to best deploy capital to more quickly and
efficiently monetize its asset base. Prior to joining CNX Gas,
she was most recently employed by Chevron North America
Exploration and Production (Chevron), where her duties included
assisting in capital budget preparation and analysis.
Dr. Craig is also a prior president of the Society of
Petroleum Engineers. While at Chevron North America
headquarters, Dr. Craig worked with appropriations and
expenditures and the requests for authorizations to make such
expenditures. She was an internal expert on project economic
evaluation and also led a team that worked on improving
probabilistic reporting of production and capital and
expenditures. Dr. Craig began her career at Phillips
Petroleum as a petroleum engineer, where she rose to the
position of Manager, Worldwide Drilling and Production. Later,
she became president of Phillips Canadian exploration and
development operations. This was followed by a tour in
Washington, D.C., where she was a government affairs
representative for Phillips, while also serving as president of
the Society of Petroleum Engineers. Dr. Craig earned her
Ph.D., two masters degrees, and two B.S. degrees from the
Colorado School of Mines, where she is also a member of the
Board of Trustees. Dr. Craig holds an MBA from Regis
University in Denver and is also a registered professional
engineer in Colorado.
Michael Onifer, 51, was named Senior Vice
President Established Business Units in July of
2007. Prior to that, he had been Vice President
Virginia Operations & Administration. In his current
position, he is responsible for annual production in excess of
50 billion cubic feet (Bcf) and the wholly-owned Cardinal
States Gathering System. Mr. Onifer started his career as a
project engineer at CONSOL Energy and held various coal-related
positions, including Superintendent Buchanan Mine.
He joined CNX Gas in late 2000 as a production foreman and
advanced through various management positions. Mr. Onifer
graduated from Virginia Tech with a B.S. degree in mining
engineering. In 2004, he attended the Program for Management
Development at the Harvard Business School.
|
|
ITEM 11.
|
EXECUTIVE
COMPENSATION.
|
The information required by this Item is incorporated by
reference to the information under the captions General
Information Compensation of Directors,
General Information Understanding our Director
Compensation, Executive Compensation and Stock
Option Information Compensation Discussion and
Analysis, Executive Compensation and Stock Option
Information Executive Compensation,
Executive Compensation and Stock Option
Information Compensation Committee Report,
General Information The Board of Directors and
its Committees Compensation Committee Interlocks and
Insider Participation, and Potential Payments Upon
Termination or
Change-In-Control,
in the Proxy Statement.
|
|
ITEM 12.
|
SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT.
|
The information requested by this Item is incorporated by
reference to the information under the captions Equity
Compensation Plan Information, and General
Information Beneficial Ownership of Securities
in the Proxy Statement.
100
|
|
ITEM 13.
|
CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS.
|
The information requested by this Item is incorporated by
reference to the information under the captions Certain
Relationships and Related Transactions and General
Information The Board of Directors and its
Committees in the Proxy Statement.
|
|
ITEM 14.
|
PRINCIPAL
ACCOUNTING FEES AND SERVICES.
|
The information required by this Item is incorporated by
reference to the information in the table found in the section
captioned Accountants and Audit Committee and the
information under the caption Accountants and Audit
Committee Audit Committee Pre-Approval of Audit and
Permissible Non-audit Services in the Proxy Statement.
PART IV
|
|
ITEM 15.
|
EXHIBITS AND
FINANCIAL STATEMENT SCHEDULES.
|
(a)(1) Financial Statements:
The financial statements included in Part II, Item 8
above are filed as part of this annual report.
(a)(2) Financial Statement Schedules:
No schedules are required to be presented by CNX Gas.
(a)(3) and (b) Exhibits:
The exhibits listed on the Exhibit Index which follows the
Signatures hereto are filed as part of this annual report.
101
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of
the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized, as of the 15th day
of February, 2008.
CNX Gas Corporation
|
|
|
|
By:
|
/s/ Nicholas
J. DeIuliis
|
Nicholas J. DeIuliis
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act
of 1934, this report has been signed as of the 15th day of
February, 2008, by the following persons on behalf of the
Registrant in the capacities indicated:
|
|
|
|
|
Signature
|
|
Title
|
|
|
|
|
/s/ Philip
W. Baxter
Philip
W. Baxter
|
|
Chairman of the Board
|
|
|
|
/s/ Nicholas
J. DeIuliis
Nicholas
J. DeIuliis
|
|
President, Chief Executive Officer and Director (Principal
Executive Officer)
|
|
|
|
/s/ Mark
D. Gibbons
Mark
D. Gibbons
|
|
Chief Financial Officer (Principal Financial and Accounting
Officer)
|
|
|
|
/s/ J.
Brett Harvey
J.
Brett Harvey
|
|
Director
|
|
|
|
/s/ James
E. Altmeyer, Sr.
James
E. Altmeyer, Sr.
|
|
Director
|
|
|
|
/s/ Raj
K. Gupta
Raj
K. Gupta
|
|
Director
|
|
|
|
/s/ John
R. Pipski
John
R. Pipski
|
|
Director
|
|
|
|
/s/ William
J. Lyons
William
J. Lyons
|
|
Director
|
|
|
|
/s/ Joseph
T. Williams
Joseph
T. Williams
|
|
Director
|
102
EXHIBIT INDEX
|
|
|
|
|
|
3
|
.1
|
|
Amended and Restated Certificate of Incorporation of CNX Gas
Corporation(1)
|
|
3
|
.2
|
|
Second Amended and Restated Bylaws of CNX Gas Corporation(23)
|
|
4
|
.1
|
|
Form of stock certificate(1)
|
|
10
|
.1
|
|
Summary of Employment Terms for Nicholas J. DeIuliis(2)*
|
|
10
|
.2
|
|
Offer letter for Ronald Smith(2)*
|
|
10
|
.3
|
|
Offer letter for Gary J. Bench(1)*
|
|
10
|
.4
|
|
Offer letter for Stephen W. Johnson(1)*
|
|
10
|
.5
|
|
Form of Change in Control Agreement for DeIuliis, Bench, Albert
and Onifer(1)(26)*
|
|
10
|
.6
|
|
Form of Change in Control Agreement for Johnson, Smith, Gibbons
and Craig(1)*
|
|
10
|
.7
|
|
Master Separation Agreement dated as of August 1, 2005 by
and among CONSOL Energy Inc. and each of the its subsidiaries
(other than CNX Gas Corporation and its subsidiaries) and CNX
Gas Corporation and its subsidiaries(3)
|
|
10
|
.8
|
|
Master Cooperation and Safety Agreement dated as of
August 1, 2005 by and among CONSOL Energy Inc. and each CEI
Subsidiary (as defined therein) and CNX Gas Corporation and each
CNX Subsidiary (as defined therein)(3)
|
|
10
|
.9
|
|
Tax Sharing Agreement dated August 1, 2005 between CONSOL
Energy Inc. and CNX Gas Corporation(3)
|
|
10
|
.10
|
|
Services Agreement dated August 1, 2005 by and among CONSOL
Energy Inc., CNX Land Resources Inc. and CNX Gas Corporation and
its subsidiaries that become a party to the agreement(3)
|
|
10
|
.11
|
|
Intercompany Revolving Credit Agreement between CONSOL Energy
Inc. and CNX Gas Corporation(3)
|
|
10
|
.12
|
|
Master Lease dated August 1, 2005 by and between CONSOL
Energy Inc. and each of its subsidiaries made a party thereto
and CNX Gas Company, LLC(3)
|
|
10
|
.13
|
|
Summary sheet regarding director compensation(1)
|
|
10
|
.14
|
|
Credit Agreement dated October 7, 2005 between CNX Gas
Corporation, certain of its subsidiaries, and the Lender parties
thereto(4)
|
|
10
|
.15
|
|
Indenture, dated March 7, 2002, among CONSOL Energy Inc.,
certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova
Scotia Trust Company of New York, as trustee(5)
|
|
10
|
.16
|
|
Supplemental Indenture No. 1, dated March 7, 2002,
among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy
Inc. and The Bank of Nova Scotia Trust Company of New York,
as trustee(6)
|
|
10
|
.17
|
|
Supplemental Indenture No. 2, dated as of
September 30, 2003, among CONSOL Energy Inc., certain
subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia
Trust Company of New York, as trustee(7)
|
|
10
|
.18
|
|
Supplemental Indenture No. 3, dated as of April 15,
2005, among CONSOL Energy Inc., certain subsidiaries of CONSOL
Energy Inc. and The Bank of Nova Scotia Trust Company of
New York, as trustee(8)
|
|
10
|
.19
|
|
Supplemental Indenture No. 4, dated as of August 8,
2005, among CONSOL Energy Inc., certain subsidiaries of CONSOL
Energy Inc. and The Bank of Nova Scotia Trust Company of
New York, as trustee(3)
|
|
10
|
.20
|
|
Supplemental Indenture No. 5, dated as of October 21,
2005, among CONSOL Energy Inc., certain subsidiaries of CONSOL
Energy Inc. and The Bank of Nova Scotia Trust Company of
New York, as trustee(9)
|
|
10
|
.21
|
|
Precedent Agreement dated July 29, 2005 by and between East
Tennessee Natural Gas, LLC and CNX Gas Company, LLC.(10)
|
|
10
|
.22
|
|
Description of the CNX Gas Corporation 2006 Short-Term Incentive
Compensation Program(11)*
|
|
10
|
.23
|
|
Firm Transportation Agreement, dated as of
April 27th , 2006, between CNX Gas Company, LLC, a
wholly-owned subsidiary of CNX Gas, and East Tennessee Natural
Gas, LLC.(12)
|
|
10
|
.24
|
|
Firm Lateral Transportation Agreement, dated as of
April 27th , 2006, between CNX Gas Company, LLC, a
wholly-owned subsidiary of CNX Gas, and East Tennessee Natural
Gas, LLC.(13)
|
|
10
|
.25
|
|
The summary description of the base compensation and short-term
incentive opportunities for the executive officers of CNX Gas
Corporation for 2006.(14)*
|
103
|
|
|
|
|
|
10
|
.26
|
|
The initial election grant of options to purchase common stock
of CNX Gas Corporation to Joseph T. Williams, upon his election
to the Board of Directors on July 10, 2006(15)*
|
|
10
|
.27
|
|
CNX Gas Corporation Long-Term Incentive Program for the
performance period from October 11, 2006 to
December 31, 2009 and Form of Award Agreement
thereunder(16)*
|
|
10
|
.28
|
|
CNX Gas Corporation Equity Incentive Plan, as amended(22)*
|
|
10
|
.29
|
|
Form of Award Agreements under CNX Gas Corporation Equity
Incentive Plan(1)
|
|
10
|
.30
|
|
Summary of Non-Employee Director Compensation effective as of
November 1, 2006(16)*
|
|
10
|
.31
|
|
Summary of the awards to CNX Gas Corporations executive
officers under the CNX Gas Corporation Long-Term Incentive
Program for the performance period from October 11, 2006 to
December 31, 2009(16)*
|
|
10
|
.32
|
|
Offer letter of Mark D. Gibbons(17)*
|
|
10
|
.33
|
|
Summary description of CNX Gas 2007 Short-term incentive
program(18)*
|
|
10
|
.34
|
|
Transfer Agreement dated as of January 24, 2007, between
the registrant and Gary J. Bench(19)
|
|
10
|
.35
|
|
Summary description of the base compensation and short-term
incentive opportunities for the executive officers of CNX Gas
for 2007(20)*
|
|
10
|
.36
|
|
Agreement of Sale entered into on June 8, 2007, by and
between CNX Gas Company LLC, as purchaser, and Consolidation
Coal Company, as seller(21)
|
|
10
|
.37
|
|
Asset Exchange Agreement entered into on June 20, 2007, but
effective as of April 1, 2007, among American Land Holdings
of Indiana, LLC, et al and CNX Gas Company LLC(21)
|
|
10
|
.38
|
|
Form Oil and Gas Deed, Assignment, And Assumption, which is
Exhibit F to Asset Exchange Agreement that is
Exhibit 10.37, above(21)
|
|
10
|
.39
|
|
Asset Purchase Agreement entered into on June 20, 2007, but
effective as of April 1, 2007, among American Land Holdings
of Indiana, LLC, et al., as seller, and CNX Gas Company LLC, as
buyer(21)
|
|
10
|
.40
|
|
Form Oil and Gas Deed, Assignment, Assumption and Bill of
Sale, which is Exhibit D to Asset Purchase Agreement that
is Exhibit 10.39, above(21)
|
|
10
|
.41
|
|
Asset Purchase Agreement entered into on June 20, 2007, but
effective as of April 1, 2007, among CNX Gas Company LLC,
as seller, and Cyprus Creek Land Resources, LLC, as buyer(21)
|
|
10
|
.42
|
|
Asset Purchase Agreement entered into on June 20, 2007, but
effective as of April 1, 2007, among CNX Gas Company LLC,
as seller, and Eastern Associated Coal, LLC, as buyer(21)
|
|
10
|
.43
|
|
Offer letter to Dr. DeAnn Craig dated June 18,
2007(24)*
|
|
10
|
.44
|
|
Schedule of Compensation of Non-Employee Directors, effective
August 2007(24)*
|
|
10
|
.45
|
|
2008 CNX Gas Long-Term Incentive Program and the Form of Award
Agreement thereunder*
|
|
10
|
.46
|
|
Summary of awards under the 2008 CNX Gas Long-Term Incentive
Program(25)*
|
|
21
|
|
|
Subsidiaries of CNX Gas Corporation(1)
|
|
23
|
.1
|
|
Consent of PricewaterhouseCoopers LLP
|
|
23
|
.2
|
|
Consent of Ralph E. Davis Associates, Inc.
|
|
23
|
.3
|
|
Consent of Schlumberger Data and Consulting Services
|
|
31
|
.1
|
|
Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
|
|
31
|
.2
|
|
Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
|
|
32
|
.1
|
|
Certification of Chief Executive Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
|
|
32
|
.2
|
|
Certification of Chief Financial Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
|
|
|
|
(1) |
|
Incorporated by reference from the Amendment No. 1 to the
Registration Statement on
Form S-1
(file
no. 333-127483)
filed on September 29, 2005 |
|
(2) |
|
Incorporated by reference from the Current Report on
Form 8-K
filed by CONSOL Energy Inc. on August 19, 2005 (SEC File
No. 001-14901) |
104
|
|
|
(3) |
|
Incorporated by reference from the Current Report on
Form 8-K
filed by CONSOL Energy Inc. on August 12, 2005 (SEC File
No. 001-14901) |
|
(4) |
|
Incorporated by reference from the Current Report on
Form 8-K
filed by CONSOL Energy Inc. on October 13, 2005 |
|
(5) |
|
Incorporated by reference from Exhibit 4.1 to
Form 10-K
filed by CONSOL Energy Inc. on March 29, 2002 |
|
(6) |
|
Incorporated by reference from Exhibit 4.2 to
Form 10-K
filed by CONSOL Energy Inc. on March 29, 2002 |
|
(7) |
|
Incorporated by reference from Exhibit 4.2 to
Form 10-Q
filed by CONSOL Energy Inc. on November 19, 2003 |
|
(8) |
|
Incorporated by reference from Exhibit 4.2 to
Form 10-Q
filed by CONSOL Energy Inc. on August 3, 2005 |
|
(9) |
|
Incorporated by reference from the Amendment No. 2 to the
Registration Statement on
Form S-1
(file no. 333-127483)
filed on October 27, 2005 |
|
(10) |
|
Incorporated by reference from the Amendment No. 4 to the
Registration Statement on
Form S-1
(file no. 333-127483)
filed on December 17, 2005 |
|
(11) |
|
Incorporated by reference from the second paragraph of
Item 1.01 of the Current Report on
Form 8-K
filed by CNX Gas Corporation on February 10, 2006 |
|
(12) |
|
Incorporated by reference from Exhibit 10.1 to
Form 10-Q
filed by CNX Gas Corporation on August 2, 2006 |
|
(13) |
|
Incorporated by reference from Exhibit 10.2 to
Form 10-Q
filed by CNX Gas Corporation on August 2, 2006 |
|
(14) |
|
Incorporated by reference from Item 1.01 of the Current
Report on
Form 8-K
filed by the CNX Gas Corporation on May 1, 2006 (SEC File
No. 001-32723) |
|
(15) |
|
Incorporated by reference from Item 1.01 of the Current
Report on
Form 8-K
filed by CNX Gas Corporation on July 11, 2006 (SEC File
No. 001-32723) |
|
(16) |
|
Incorporated by reference from the Current Report on
Form 8-K
filed by CNX Gas Corporation on October 17, 2006 (SEC File
No. 001-32723) |
|
(17) |
|
Incorporated by reference from the Current Report on
Form 8-K
filed by CNX Gas on January 26, 2007 |
|
(18) |
|
Incorporated by reference from the Current Report on
Form 8-K
filed by CNX Gas on March 1, 2007 |
|
(19) |
|
Incorporated by reference from the
Form 10-Q
filed by CNX Gas on April 27, 2007 |
|
(20) |
|
Incorporated by reference from the Current Report on
Form 8-K
filed by CNX Gas on April 27, 2007 |
|
(21) |
|
Incorporated by reference from the
Form 10-Q
filed by CNX Gas on July 31, 2007 |
|
(22) |
|
Incorporated by reference from the Definitive Proxy Statement on
Schedule 14A, filed by CNX Gas on March 19, 2007 |
|
(23) |
|
Incorporated by reference from the Current Report on
Form 8-K
filed by CNX Gas on August 16, 2007 |
|
(24) |
|
Incorporated by reference from the
Form 10-Q
filed by CNX Gas on October 30, 2007 |
|
(25) |
|
Incorporated by reference from the Current Report on
Form 8-K
filed by CNX Gas on December 14, 2007 |
|
(26) |
|
With respect to Messrs. Onifer and Albert, the change in
control agreements have a 2-times multiplier and do not contain
a Section 280G gross up. |
|
|
|
In accordance with SEC Release
33-8238,
Exhibits 32.1 and 32.2 are being furnished and not filed. |
|
* |
|
Management compensatory contract or arrangement. |
105