|
|
|
|
|
|
|
|
2007
Period
|
|
|
|
Three
Months Ended
|
|
|
Compared
to 2006 Period
|
|
|
|
September
30,
|
|
|
Increase
|
|
|
%
Increase
|
|
|
|
2007
|
|
|
2006
|
|
|
(Decrease)
|
|
|
(Decrease)
|
|
Production
volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and condensate (MBbls)
|
|
|
59
|
|
|
|
69
|
|
|
|
(10
|
)
|
|
|
(14
|
)%
|
Natural
gas (MMcf)
|
|
|
4,080
|
|
|
|
2,443
|
|
|
|
1,637
|
|
|
|
67
|
%
|
Average
sales prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and condensate (per Bbl)
|
|
$
|
75.40
|
|
|
$
|
68.46
|
|
|
$
|
6.94
|
|
|
|
10
|
%
|
Natural
gas (per Mcf)
|
|
|
6.33
|
|
|
|
6.39
|
|
|
|
(0.06
|
)
|
|
|
(1
|
)%
|
Operating
revenues (In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and condensate
|
|
$
|
4,457
|
|
|
$
|
4,716
|
|
|
$
|
(259
|
)
|
|
|
(5
|
)%
|
Natural
gas
|
|
|
25,848
|
|
|
|
15,617
|
|
|
|
10,231
|
|
|
|
66
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Operating Revenues
|
|
$
|
30,305
|
|
|
$
|
20,333
|
|
|
$
|
9,972
|
|
|
|
49
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and
natural gas operating expenses for the three months ended September
30, 2007
increased 78% to $6.9 million from $3.9 million for the same period
in 2006
primarily as a result of (1) higher lifting costs of $0.9 million
primarily
attributable to increased production and the increased number of
producing
wells, (2) increased workover expense of $0.3 million, (3) increased
ad valorem
taxes of $0.4 million and (4) increased transportation and other
product costs
of $1.3 million mainly attributable to the Barnett Shale area.
Depreciation,
depletion and amortization (DD&A) expense for the three months ended
September 30, 2007 increased 34% to $10.2 million ($2.30 per Mcfe)
from $7.6
million ($2.66 per Mcfe) for the same period in 2006. This increase
was primarily due to an increase in production volumes partially
offset by a
decrease in the DD&A rate attributable to the increase in the reserve
base.
General
and administrative expense for the three months ended September
30, 2007
increased by $1.3 million to $4.4 million from $3.1 million for
the
corresponding period in 2006 primarily as a result of (1) an increase
in staff
and related costs, (2) increased stock-based compensation, (3)
increased legal
and consulting fees and (4) higher rent expense as a result of
office
expansion.
The
net
gain on derivatives of $3.7 million in the third quarter of 2007
was comprised
of (1) $2.8 million of realized gain on net cash settled derivatives
and (2)
$0.9 million of net unrealized mark-to-market gain on
derivatives. The net gain on derivatives of $3.7 million in the third
quarter of 2006 was comprised of (1) $1.5 million of realized gain
on net cash
settled derivatives and (2) $2.2 million of net unrealized mark-to-market
gain
on derivatives.
Interest
expense and capitalized interest for the three months ended September
30, 2007
were $7.0 million and ($2.9) million, respectively, as compared
to $4.9 million
and $(2.7) million for the same period in 2006. The increases in 2007
were largely attributable to the $75.0 million increase in our Second
Lien Credit Facility in January 2007, the borrowings under the
Senior Secured
Credit Facility and higher effective interest rates.
Income
tax expense increased to $3.1 million for the three months ended
September 30,
2007 from the $2.7 million expense for the same period in 2006
as a result of
higher taxable income.
Nine
Months Ended September 30, 2007,
Compared
to the Nine Months Ended September 30, 2006
Oil
and
natural gas revenues for the nine months ended September 30, 2007
increased 46%
to $85.8 million from $58.7 million for the same period in
2006. Production volumes for natural gas for the nine months ended
September 30, 2007 increased to 10.8 Bcf from 7.0 Bcf for the same
period in
2006. Average natural gas prices excluding the impact of the gain
from our cash settled derivatives of $5.4 million and $3.6 million
for the nine
months ended September 30, 2007 and 2006, respectively, increased
2% to $6.88
per Mcf from $6.74 per Mcf in the same period in 2006. Average oil
prices for the nine months ended September 30, 2007 decreased 1%
to $65.22 from
$65.54 per barrel in the same period in 2006. The increase in natural
gas production volume was due primarily to new
Barnett
Shale wells and increased production in the Gulf Coast from the
addition of the
Doberman #1 and Baby Ruth wells and the recompletion of the Galloway
Gas Unit #1
well #1.
The
following table summarizes production volumes, average sales prices
and
operating revenues (excluding the impact of derivatives) for the
nine months
ended September 30, 2007 and 2006:
|
|
|
|
|
|
|
|
2007
Period
|
|
|
|
Nine
Months Ended
|
|
|
Compared
to 2006 Period
|
|
|
|
September
30,
|
|
|
Increase
|
|
|
%
Increase
|
|
|
|
2007
|
|
|
2006
|
|
|
(Decrease)
|
|
|
(Decrease)
|
|
Production
volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and condensate (MBbls)
|
|
|
182
|
|
|
|
179
|
|
|
|
3
|
|
|
|
2
|
%
|
Natural
gas (MMcf)
|
|
|
10,753
|
|
|
|
6,976
|
|
|
|
3,777
|
|
|
|
54
|
%
|
Average
sales prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and condensate (per Bbl)
|
|
$
|
65.22
|
|
|
$
|
65.54
|
|
|
$
|
(0.32
|
)
|
|
|
(1
|
)%
|
Natural
gas (per Mcf)
|
|
|
6.88
|
|
|
|
6.74
|
|
|
|
0.14
|
|
|
|
2
|
%
|
Operating
revenues (In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and condensate
|
|
$
|
11,881
|
|
|
$
|
11,734
|
|
|
$
|
147
|
|
|
|
1
|
%
|
Natural
gas
|
|
|
73,927
|
|
|
|
46,993
|
|
|
|
26,934
|
|
|
|
57
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Operating Revenues
|
|
$
|
85,808
|
|
|
$
|
58,727
|
|
|
$
|
27,081
|
|
|
|
46
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and
natural gas operating expenses for the nine months ended September
30, 2007
increased 56% to $17.2 million from $11.0 million for the same
period in 2006
primarily as a result of (1) higher lifting costs of $2.5 million
primarily
attributable to increased production, the increased number of producing
wells
and the rising costs of oilfield services, (2) higher workover
expenses of $0.4
million, (3) increased ad valorem taxes of $0.9 million and (4)
increased
transportation and other product costs of $2.3 million mainly attributable
to
the Barnett Shale area.
DD&A
expense for the nine months ended September 30, 2007 increased
34% to $29.0
million ($2.45 per Mcfe) from $21.6 million ($2.69 per Mcfe) for
the same period
in 2006. This increase was primarily due to an increase in production
volumes partially offset by a decrease in the DD&A rate attributable to the
increase in the reserve base.
General
and administrative expense for the nine months ended September
30, 2007
increased by $3.1 million to $13.6 million from $10.5 million for
the
corresponding period in 2006 due primarily to (1) an increase in
staff and
related costs, (2) increased stock-based compensation, (3) higher
rent and
office expense due to office expansion and (4) increased legal
and consulting
fees.
The
net
gain on derivatives of $2.1 million in the first nine months of
2007 was
comprised of (1) $5.6 million of realized gain on net cash settled
derivatives
and (2) $(3.5) million of net unrealized mark-to-market loss on
derivatives. The net gain on derivatives of $12.1 million in the
first nine months of 2006 was comprised of (1) $4.3 million of
realized gain on
net cash settled derivatives and (2) $7.8 million of net unrealized
mark-to-market gain on derivatives.
Interest
expense and capitalized interest for the nine months ended September
30, 2007
were $19.7 million and $(8.3) million, respectively, as compared
to $13.8
million and $(7.2) million for the same period in 2006. The increases
in 2007 were largely attributable to the $75.0 million increase
in
our Second Lien Credit Facility in January 2007, borrowings under the
Senior Secured Credit Facility beginning mid-2006 and higher effective
interest
rates.
Income
tax expense decreased to $6.3 million for the nine months ended
September 30,
2007 from the $7.8 million for the same period in 2006 as a result
of lower
taxable income.
Liquidity
and Capital Resources
Sources
and Uses of Cash.
During the nine months ended September 30,
2007, capital expenditures, net of proceeds for property sales,
exceeded our net
cash. During 2007, we have used cash generated from operations,
additional borrowings under our Second Lien Credit Facility and
the Senior
Credit Facility and proceeds from the issuance of our common
stock. Potential primary sources of future liquidity include the
following:
·
|
Cash
on hand and cash generated by operations. Cash flows from
operations are highly dependent on commodity prices and
market conditions
for oil and gas field services. We hedge a portion of our
production to reduce the downside risk of declining natural
gas
prices.
|
·
|
Available
draws on the Senior Credit Facility. During the third quarter
of 2007, we requested a borrowing base re-determination
for the Senior
Credit Facility and in September of 2007, the borrowing
base availability
increased from $74.8 million to $117.0 million. At November 1,
2007, cash available under the Senior Credit Facility
was $105.0
million. The next borrowing base redetermination is scheduled
for December 2007.
|
·
|
Other
debt and equity offerings. As situations or conditions arise,
we may issue debt or equity instruments to supplement
our cash
flows.
|
·
|
Asset
sales. In order to fund our drilling program, we may consider
the sale of certain properties or assets no longer deemed
core to our
future growth.
|
Our
primary use of cash is capital expenditures related to our drilling
program. We plan to spend approximately $145 million to $165 million
on our 2007 drilling program. For the nine months ended September 30,
2007, we have incurred approximately $151 million in capital
expenditures.
Overview
of Cash Flow Activities.
Cash flows provided by operating
activities were $49.5 million and $37.2 million for the nine months
ended
September 30, 2007 and 2006, respectively. The increase was primarily
due to an increase in income largely attributable to increased
production.
Cash
flows used in investing activities were $152.2 million for the
nine months ended
September 30, 2007 and related primarily to oil and gas property
expenditures. Cash flows used in investing activities were $114.9
million for the nine months ended September 30, 2006 as capital
expenditures for
oil and gas properties of $146.2 million were partially offset
by proceeds from
the sale of properties of $33.6 million.
Net
cash
provided by financing activities for the nine months ended September
30, 2007
was $101.9 million and related primarily to the additional borrowings
of $75.0
million under the Second Lien Credit Facility in January 2007 and
net proceeds
of $72.0 million from the issuance of common stock in September
2007 (see Notes
2 and 6 in the Notes to Consolidated Financial Statements for further
discussion
of these transactions). These cash proceeds were partially offset by
the paydown of the Senior Credit Facility. Net cash provided by
financing activities for the nine months ended September 30, 2006
was $50.3
million and related primarily to the additional borrowings under
the Senior
Credit Facility and the net proceeds of $33.6 million from the
issuance of
common stock, partially offset by $36.2 million of debt repayments.
Liquidity/Cash
Flow Outlook.
We believe that the cash generated from operations
along with cash on hand and the cash available under the Senior
Credit Facility
is sufficient to meet our immediate needs but we may need to seek
other
financing alternatives, including additional debt or equity financings,
to fully
fund our 2007 and 2008 capital program, especially if there are
additional
capital needs in our Floyd Shale or North Sea plays.
We
may
not be able to obtain financing needed in the future on terms that
would be
acceptable to us. If we cannot obtain adequate financing, we may be
required to limit or defer our planned oil and natural gas exploration
and
development program, thereby adversely affecting the recoverability
and ultimate
value of our oil and natural gas properties.
Contractual
Obligations
During
the third quarter of 2007, we entered into a firm drilling agreement
for one rig
over a three-year term scheduled to begin in the first quarter
of
2008. The estimated obligation is approximately $8 million per year
through 2010.
Financing
Arrangements
Senior
Secured Revolving Credit Facility
During
the third quarter of 2007, we amended our Senior Credit Facility
as discussed in
Note 2 in the Notes to Consolidated Financial Statements.
Effects
of Inflation and Changes in Price
Our
results of operations and cash flows are affected by changing oil
and natural
gas prices. If the price of oil and natural gas increases
(decreases), there could be a corresponding increase (decrease)
in the operating
cost that we are required to bear for operations, as well as an
increase
(decrease) in revenues. Inflation has had a minimal effect on
us.
Recently
Adopted Accounting Pronouncements
We
adopted the Financial Accounting Standards Board's Interpretation
No. 48,
“Accounting for Uncertainty in Income Taxes, an Interpretation
of FASB
Statement No. 109”
(“FIN 48”), effective January 1, 2007. FIN 48
clarifies the accounting for uncertainty in income taxes recognized
in financial
statements and requires the impact of a tax position to be recognized
in the
financial statements if that position is more likely than not of
being sustained
by the taxing authority. The adoption of FIN 48 did not have a material
effect on our consolidated financial position or results of
operations.
Critical
Accounting Policies
The
following summarizes several of our critical accounting policies:
Use
of Estimates
The
preparation of financial statements in conformity with U.S. generally
accepted
accounting principles requires management to make estimates and
assumptions that
affect the reported amounts of assets and liabilities and disclosure
of
contingent assets and liabilities at the date of the financial
statements and
the reported amounts of revenues and expenses during the periods
reported. Actual results could differ from these
estimates. The use of these estimates significantly affects our
natural gas and oil properties through depletion and the full cost
ceiling test,
as discussed in more detail below.
Significant
estimates include volumes of oil and natural gas reserves used
in calculating
depletion of proved oil and natural gas properties, future net
revenues and
abandonment obligations, impairment of undeveloped properties,
future income
taxes and related assets/liabilities, the collectability of outstanding
accounts
receivable, fair values of derivatives, stock-based compensation
expense,
contingencies and the results of current and future litigation. Oil
and natural gas reserve estimates, which are the basis for unit-of-production
depletion and the ceiling test, have numerous inherent
uncertainties. The accuracy of any reserve estimate is a function of
the quality of available data and of engineering and geological
interpretation
and judgment. Subsequent drilling, testing and production may justify
revision of such estimate. Accordingly, reserve estimates are often
different from the quantities of oil and natural gas that are ultimately
recovered. In addition, reserve estimates are vulnerable to changes
in wellhead prices of crude oil and natural gas. Such prices have
been volatile in the past and can be expected to be volatile in
the
future.
The
significant estimates are based on current assumptions that may
be materially
effected by changes to future economic conditions such as the market
prices
received for sales of volumes of oil and natural gas, interest
rates, the market
value of our common stock and corresponding volatility and our
ability to
generate future taxable income. Future changes to these assumptions
may materially affect these significant estimates in the near term.
Oil
and Natural Gas Properties
We
account for investments in natural gas and oil properties using
the full-cost
method of accounting. All costs directly associated with the
acquisition, exploration and development of natural gas and oil
properties are
capitalized. These costs include lease acquisitions, seismic surveys,
and drilling and completion equipment. We proportionally consolidate
our interests in natural gas and oil properties. We capitalized
compensation costs for employees working directly on exploration
activities of
$3.3 million and $2.2 million for the nine months ended September
30, 2007 and
2006, respectively. We expense maintenance and repairs as they are
incurred.
We
amortize natural gas and oil properties based on the unit-of-production
method
using estimates of proved reserve quantities. We do not amortize
investments in unproved properties until proved reserves associated
with the
projects can be determined or until these investments are
impaired. We periodically evaluate, on a property-by-property basis,
unevaluated properties for impairment. If the results of an
assessment indicate that the properties are impaired, we add the
amount of
impairment to the proved natural gas and oil property costs to
be
amortized. The amortizable base includes estimated future development
costs and, where significant, dismantlement, restoration and abandonment
costs,
net of estimated salvage values. The depletion rate per Mcfe for the
three months ended September 30, 2007 and 2006 was $2.26 and $2.59,
respectively.
We
account for dispositions of natural gas and oil properties as adjustments
to
capitalized costs with no gain or loss recognized, unless such
adjustments would
significantly alter the relationship between capitalized costs
and proved
reserves. We have not had any transactions that significantly alter
that relationship.
Net
capitalized costs of proved oil and natural gas properties are
limited to a
“ceiling test” based on the estimated future net revenues, discounted at 10% per
annum, from proved oil and natural gas reserves based on current
economic and
operating conditions (“Full Cost Ceiling”). If net capitalized costs
exceed this limit, the excess is charged to earnings through depreciation,
depletion and amortization.
In
connection with our September 30, 2007 Full Cost Ceiling test computation,
a
price sensitivity study also indicated that a 10% increase or decrease
in
commodity prices at September 30, 2007 would have increased or
decreased the
Full Cost Ceiling test cushion by approximately $52 million. The
aforementioned price sensitivity is as of September 30, 2007 and,
accordingly,
does not include any potential changes in reserve values due to
subsequent
performance or events, such as commodity prices, reserve revisions
and drilling
results.
The
Full
Cost Ceiling cushion at the end of September 2007 of approximately
$113.7
million was based upon average realized oil and natural gas prices
of $76.79 per
Bbl and $6.48 per Mcf, respectively, or a volume weighted average
price of
$45.63 per BOE. This cushion, however, would have been zero on such
date at an estimated volume weighted average price of $35.61 per
BOE. A BOE means one barrel of oil equivalent, determined using the
ratio of six Mcf of natural gas to one Bbl of oil, condensate or
natural gas
liquids, which approximates the relative energy content of oil,
condensate and
natural gas liquids as compared to natural gas. Prices have
historically been higher or substantially higher, more often for
oil than
natural gas on an energy equivalent basis, although there have
been periods in
which they have been lower or substantially lower.
Under
the
full cost method of accounting, the depletion rate is the current
period
production as a percentage of the total proved reserves. Total proved
reserves include both proved developed and proved undeveloped
reserves. The depletion rate is applied to the net book value of our
oil and natural gas properties, excluding unevaluated costs, plus
estimated
future development costs and salvage value, to calculate the depletion
expense. Proved reserves materially impact depletion
expense. If the proved reserves decline, then the depletion rate (the
rate at which we record depletion expense) increases, reducing
net
income.
We
have a
significant amount of proved undeveloped reserves. We had 116.9 Bcfe
and 126.2 Bcfe of proved undeveloped reserves at September 30,
2007 and December
31, 2006, respectively, representing 48% and 60% of our total proved
reserves. As of September 30, 2007 and December 31, 2006, a large
portion of these proved undeveloped reserves, or approximately
32.8 Bcfe, are
attributable to our Camp Hill properties that we acquired in
1994. The estimated future development costs to develop our proved
undeveloped reserves on our Camp Hill properties are relatively
low, on a per
Mcfe basis, when compared to the estimated future development costs
to develop
our proved undeveloped reserves on our other oil and natural gas
properties. Furthermore, the average depletable life (the estimated
time that it will take to produce all recoverable reserves) of
our Camp Hill
properties is considerably longer, or approximately 15 years, when
compared to
the depletable life of our remaining oil and natural gas properties
of
approximately 10 years. Accordingly, the combination of a relatively
low ratio of future development costs and a relatively long depletable
life on
our Camp Hill properties has resulted in a relatively low overall
historical
depletion rate and DD&A expense. This has resulted in a
capitalized cost basis associated with producing properties being
depleted over
a longer period than the associated production and revenue stream,
causing the
build-up of nondepleted capitalized costs associated with properties
that have
been completely depleted. This combination of factors, in turn, has
had a favorable impact on our earnings, which have been higher
than they would
have been had the Camp Hill properties not resulted in a relatively
low overall
depletion rate and DD&A expense and longer depletion period. As a
hypothetical illustration of this impact, the removal of our Camp
Hill proved
undeveloped reserves starting January 1, 2002 would have reduced
our earnings by
(1) an estimated $11.2 million in 2002 (comprised of after-tax
charges for a
$7.1 million full cost ceiling impairment and a $4.1 million depletion
expense
increase), (2) an estimated $5.9 million in 2003 (due to higher
depletion
expense), (3) an estimated $3.4 million in 2004 (due to higher
depletion
expense) (4) an estimated $6.9 million in 2005 (due to higher depletion
expense)
and (5) an estimated $0.7 million in 2006 (due to higher depletion
expense).
We
expect
our relatively low historical depletion rate to continue until
the high level of
nonproducing reserves to total proved reserves is reduced and the
life of our
proved developed reserves is extended through development drilling
and/or the
significant addition of new proved producing reserves through acquisition
or
exploration. If our level of total proved reserves, finding costs and
current prices were all to remain constant, this continued build-up
of
capitalized cost increases the probability of a ceiling test write-down
in the
future.
We
depreciate other property and equipment using the straight-line
method based on
estimated useful lives ranging from five to ten years.
Oil
and Natural Gas Reserve Estimates
Proved
reserve data as of December 31, 2006 were estimates prepared by
Ryder Scott
Company, LaRoche Petroleum Consultants, Ltd., and Fairchild & Wells, Inc.,
Independent Petroleum Engineers. We estimated the reserve data for
all other dates. Reserve engineering is a subjective process of
estimating underground accumulations of hydrocarbons that cannot
be measured in
an exact manner. The process relies on judgment and the
interpretation of available geologic, geophysical, engineering
and production
data. The extent, quality and reliability of this data can
vary. The process also requires certain economic assumptions
regarding drilling and operating expense, capital expenditures,
taxes and
availability of funds. The SEC mandates some of these assumptions
such as oil and natural gas prices and the present value discount
rate.
Proved
reserve estimates prepared by others may be substantially higher
or lower than
our estimates. Because these estimates depend on many assumptions,
all of which may differ from actual results, reserve quantities
actually
recovered may be significantly different than estimated. Material
revisions to reserve estimates may be made depending on the results
of drilling,
testing, and rates of production.
You
should not assume that the present value of future net cash flows
is the current
market value of our estimated proved reserves. In accordance with SEC
requirements, we based the estimated discounted future net cash
flows from
proved reserves on prices and costs on the date of the estimate
using a discount
rate of 10%.
Our
rate
of recording depreciation, depletion and amortization expense for
proved
properties depends on our estimate of proved reserves. If these
reserve estimates decline, the rate at which we record these expenses
will
increase. A 10% increase or decrease in our proved reserves would
have increased or decreased our depletion expense by 9% for the
three months
ended September 30, 2007.
At
December 31, 2006, approximately 75% of our proved reserves were
proved
undeveloped and proved nonproducing. Moreover, some of the producing
wells included in our reserve reports as of December 31, 2006 had
produced for a
relatively short period of time as of that date. Because most of our
reserve estimates are calculated using volumetric analysis, those
estimates are
less reliable than estimates based on a lengthy production
history. Volumetric analysis involves estimating the volume of a
reservoir based on the net feet of pay of the structure and an
estimation of the
area covered by the structure based on seismic analysis. In addition,
realization or recognition of our proved undeveloped reserves will
depend on our
development schedule and plans. Lack of certainty with respect to
development plans for proved undeveloped reserves could cause the
discontinuation of the classification of these reserves as proved. We
have from time to time chosen to delay development of our proved
undeveloped
reserves in the Camp Hill field in East Texas in favor of pursuing
shorter-term
exploration projects with higher potential rates of return, adding
to our lease
position in this field and further evaluating additional economic
enhancements
for this field's development. The average life of the Camp Hill
proved undeveloped reserves is approximately 15 years, with 50%
of these
reserves being booked over eight years ago. Although we have
increased the pace of the development of the Camp Hill project,
there can be no
assurance that the aforementioned discontinuance will not occur. For
more information on the development of the Camp Hill field, see
“Outlook”
above.
Derivative
Instruments
We
use
derivatives to manage price and interest rate risk underlying our
oil and
natural gas production and the variable interest rate on the Second
Lien Credit
Facility. We have elected to account for our derivative contracts as
non-designated derivatives that will be marked-to-market. For a
discussion of the impact of changes in the prices of oil and gas
on our hedging
transactions, see “Volatility of Oil and Natural Gas Prices” below.
During
2007, we entered into interest rate swap agreements with respect
to amounts
outstanding under the amended Second Lien Credit Facility. These
arrangements are designed to manage our exposure to interest rate
fluctuations
through December 31, 2008 by effectively exchanging existing obligations
to pay
interest based on floating rates for obligations to pay interest
based on fixed
LIBOR. These derivatives will be marked-to-market at the end of each
period and the realized and unrealized gain or loss will be recorded
as gain
(loss) on derivatives, net within Other Income and Expenses on
our Consolidated
Statements of Income.
Our
Board
of Directors sets all of our risk management policies and reviews
volume
limitations, types of instruments and counterparties, on a quarterly
basis. These policies require that derivative instruments be executed
only by either the President or Chief Financial Officer after consultation
and
concurrence by the President, Chief Financial Officer and Chairman
of the
Board. The
master
contracts with the approved counterparties identify the President
and Chief
Financial Officer as the only representatives authorized to execute
trades. The Board of Directors also reviews the status and results of
derivative activities quarterly.
Income
Taxes
Under
Statement of Financial Accounting Standards No. 109 (“SFAS No. 109”),
“Accounting for Income Taxes,”
deferred income taxes are recognized at
each year end for the future tax consequences of differences between
the tax
bases of assets and liabilities and their financial reporting amounts
based on
tax laws and statutory tax rates applicable to the periods in which
the
differences are expected to affect taxable income. We routinely
assess the realizability of our deferred tax assets. We consider
future taxable income in making such assessments. If we conclude that
it is more likely than not that some portion or all of the deferred
tax assets
will not be realized under accounting standards, it is reduced
by a valuation
allowance. However, despite our attempt to make an accurate estimate,
the ultimate utilization of our deferred tax assets is highly dependent
upon our
actual production and the realization of taxable income in future
periods.
Contingencies
Liabilities
and other contingencies are recognized upon determination of an
exposure, which
when analyzed indicates that it is both probable that an asset
has been impaired
or that a liability has been incurred and that the amount of such
loss is
reasonably estimable.
Volatility
of Oil and Natural Gas Prices
Our
revenues, future rate of growth, results of operations, financial
condition and
ability to borrow funds or obtain additional capital, as well as
the carrying
value of our properties, are substantially dependent upon prevailing
prices of
oil and natural gas.
We
periodically review the carrying value of our oil and natural gas
properties
under the full cost method of accounting rules. See “—Critical Accounting
Policies—Oil and Natural Gas Properties.”
To
mitigate some of our commodity price risk, we engage periodically
in certain
other limited derivative activities including price swaps, costless
collars and,
occasionally, put options, in order to establish some price floor
protection.
The
following table includes oil and natural gas positions settled
during the three
and nine-months period ended September 30, 2007 and 2006, and the
unrealized
gain/(loss) associated with the outstanding oil and natural gas
derivatives at
September 30, 2007 and 2006.
|
|
Three
months ended
|
|
|
Nine
months ended
|
|
|
|
September
30,
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
Oil
positions settled (Bbls)
|
|
|
18,300
|
|
|
|
27,600
|
|
|
|
18,300
|
|
|
|
63,800
|
|
Natural
gas positions settled (MMBtu)
|
|
|
1,898,000
|
|
|
|
1,163,000
|
|
|
|
5,332,000
|
|
|
|
3,520,000
|
|
Realized
gain ($ millions)
(1)
|
|
$
|
2.8
|
|
|
$
|
1.1
|
|
|
$
|
5.4
|
|
|
$
|
3.6
|
|
Unrealized
gain/(loss) ($ millions)
(1)
|
|
$
|
1.0
|
|
|
$
|
2.9
|
|
|
$
|
(3.5
|
)
|
|
$
|
7.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
__________
(1)
Included in gain
(loss) on derivatives, net in the Consolidated Statements of
Income.
At
September 30, 2007, we had the following outstanding natural gas
derivative
positions:
|
|
Natural
Gas
|
|
|
Natural
Gas
|
|
|
|
Swaps
|
|
|
Collars
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
Average
|
|
Quarter
|
|
MMbtu
|
|
|
Fixed
Price
(1)
|
|
|
MMBtu
|
|
|
Floor
Price
(1)
|
|
|
Ceiling
Price
(1)
|
|
Fourth
Quarter 2007
|
|
|
828,000
|
|
|
$
|
7.44
|
|
|
|
644,000
|
|
|
$
|
7.24
|
|
|
$
|
8.84
|
|
First
Quarter 2008
|
|
|
273,000
|
|
|
|
7.94
|
|
|
|
1,456,000
|
|
|
|
7.49
|
|
|
|
9.26
|
|
Second
Quarter 2008
|
|
|
273,000
|
|
|
|
7.94
|
|
|
|
1,092,000
|
|
|
|
7.23
|
|
|
|
8.97
|
|
Third
Quarter 2008
|
|
|
276,000
|
|
|
|
7.94
|
|
|
|
920,000
|
|
|
|
7.22
|
|
|
|
8.97
|
|
Fourth
Quarter 2008
|
|
|
276,000
|
|
|
|
7.94
|
|
|
|
1,103,000
|
|
|
|
7.18
|
|
|
|
8.83
|
|
First
Quarter 2009
|
|
|
-
|
|
|
|
-
|
|
|
|
1,080,000
|
|
|
|
7.09
|
|
|
|
8.81
|
|
Second
Quarter 2009
|
|
|
-
|
|
|
|
-
|
|
|
|
1,092,000
|
|
|
|
7.09
|
|
|
|
8.81
|
|
Third
Quarter 2009
|
|
|
-
|
|
|
|
-
|
|
|
|
1,104,000
|
|
|
|
7.09
|
|
|
|
8.81
|
|
Fourth
Quarter 2009
|
|
|
-
|
|
|
|
-
|
|
|
|
1,104,000
|
|
|
|
7.09
|
|
|
|
8.81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|