CARRIZO
OIL & GAS, INC.
CONS
OLIDATED
BALANCE SHEETS
|
|
September
30,
|
|
|
December
31,
|
|
ASSETS
|
|
2007
|
|
|
2006
|
|
|
|
(Restated)
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
(In
thousands, except per share
amount)
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash
equivalents
|
|
$
|
4,576
|
|
|
$
|
5,408
|
|
Accounts
receivable, trade (net of
allowance for doubtful accounts of $1,395 and
$1,639
|
|
|
|
|
|
at
September 30, 2007 and December
31, 2006, respectively)
|
|
|
29,391
|
|
|
|
25,871
|
|
Advances
to
operators
|
|
|
2,757
|
|
|
|
2,107
|
|
Fair
value of derivative financial
instruments
|
|
|
2,848
|
|
|
|
5,737
|
|
Other
current
assets
|
|
|
4,894
|
|
|
|
1,934
|
|
Total
current
assets
|
|
|
44,466
|
|
|
|
41,057
|
|
|
|
|
|
|
|
|
|
|
PROPERTY
AND EQUIPMENT, net
full-cost method of accounting for oil
|
|
|
|
|
|
|
|
|
and
natural gas properties
(including unevaluated costs of properties of $117,398
and
|
|
|
|
|
|
$95,136
at September 30, 2007 and
December 31, 2006, respectively)
|
|
|
567,152
|
|
|
|
445,447
|
|
DEFERRED
FINANCING COSTS,
NET
|
|
|
6,244
|
|
|
|
4,817
|
|
INVESTMENT
IN PINNACLE GAS
RESOURCES, INC.
|
|
|
11,941
|
|
|
|
2,771
|
|
OTHER
ASSETS
|
|
|
824
|
|
|
|
703
|
|
TOTAL
ASSETS
|
|
$
|
630,627
|
|
|
$
|
494,795
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
AND SHAREHOLDERS'
EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Accounts
payable,
trade
|
|
$
|
29,069
|
|
|
$
|
32,570
|
|
Accrued
liabilities
|
|
|
22,464
|
|
|
|
20,885
|
|
Advances
for joint
operations
|
|
|
2,063
|
|
|
|
1,100
|
|
Current
maturities of long-term
debt
|
|
|
2,253
|
|
|
|
1,508
|
|
Other
current
liabilities
|
|
|
2,258
|
|
|
|
2,008
|
|
Total
current
liabilities
|
|
|
58,107
|
|
|
|
58,071
|
|
|
|
|
|
|
|
|
|
|
LONG-TERM
DEBT, NET OF CURRENT
MATURITIES
|
|
|
218,813
|
|
|
|
187,250
|
|
ASSET
RETIREMENT
OBLIGATION
|
|
|
5,370
|
|
|
|
3,625
|
|
FAIR
VALUE OF DERIVATIVE FINANCIAL
INSTRUMENTS
|
|
|
851
|
|
|
|
-
|
|
DEFERRED
INCOME
TAXES
|
|
|
43,004
|
|
|
|
32,738
|
|
DEFERRED
CREDITS
|
|
|
724
|
|
|
|
837
|
|
|
|
|
|
|
|
|
|
|
COMMITMENTS
AND
CONTINGENCIES
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
SHAREHOLDERS'
EQUITY:
|
|
|
|
|
|
|
|
|
Common
stock, par value $0.01
(40,000 shares authorized with 27,979 and
|
|
|
|
|
|
|
|
|
25,981
issued and outstanding at
September 30, 2007 and
|
|
|
|
|
|
|
|
|
December
31, 2006,
respectively)
|
|
|
280
|
|
|
|
260
|
|
Additional
paid-in
capital
|
|
|
246,008
|
|
|
|
168,469
|
|
Retained
earnings
|
|
|
59,700
|
|
|
|
49,875
|
|
Accumulated
other comprehensive
income, net of tax
|
|
|
5,991
|
|
|
|
-
|
|
Unearned
compensation - restricted
stock
|
|
|
(8,221
|
)
|
|
|
(6,330
|
)
|
Total
shareholders'
equity
|
|
|
303,758
|
|
|
|
212,274
|
|
TOTAL
LIABILITIES AND
SHAREHOLDERS' EQUITY
|
|
$
|
630,627
|
|
|
$
|
494,795
|
|
|
|
|
|
|
|
|
|
|
CARRIZO
OIL & GAS, INC.
CON
SOLIDATED
STATEMENTS OF INCOME
(Unaudited)
|
|
Three
Months
Ended
|
|
|
Nine
Months
Ended
|
|
|
|
September
30,
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(Restated)
|
|
|
|
|
|
(Restated)
|
|
|
|
|
|
|
(In
thousands, except per share
amounts)
|
|
OIL
AND NATURAL GAS
REVENUES
|
|
$
|
30,305
|
|
|
$
|
20,333
|
|
|
$
|
85,808
|
|
|
$
|
58,727
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COSTS
AND
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and natural gas operating
expenses (exclusive of depreciation, depletion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and
amortization shown
separately below)
|
|
|
6,940
|
|
|
|
3,893
|
|
|
|
17,203
|
|
|
|
10,980
|
|
Depreciation,
depletion and
amortization
|
|
|
10,190
|
|
|
|
7,594
|
|
|
|
29,033
|
|
|
|
21,630
|
|
General
and administrative
(inclusive of stock-based compensation expense of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$1,058
and $810 for the three
months ended September 30, 2007 and 2006,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
respectively,
and $3,050 and
$1,999 for the nine months ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
30, 2007 and 2006,
respectively)
|
|
|
4,360
|
|
|
|
3,118
|
|
|
|
13,577
|
|
|
|
10,469
|
|
Accretion
expense related to asset
retirement obligations
|
|
|
89
|
|
|
|
79
|
|
|
|
265
|
|
|
|
237
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
COSTS AND
EXPENSES
|
|
|
21,579
|
|
|
|
14,684
|
|
|
|
60,078
|
|
|
|
43,316
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
8,726
|
|
|
|
5,649
|
|
|
|
25,730
|
|
|
|
15,411
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME AND
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain
on derivatives,
net
|
|
|
1,917
|
|
|
|
3,684
|
|
|
|
286
|
|
|
|
12,087
|
|
Equity
in income of Pinnacle Gas
Resources, Inc.
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
35
|
|
Other
income and expenses,
net
|
|
|
6
|
|
|
|
29
|
|
|
|
262
|
|
|
|
202
|
|
Loss
on early extinguishment of
debt
|
|
|
-
|
|
|
|
(12
|
)
|
|
|
-
|
|
|
|
(294
|
)
|
Interest
income
|
|
|
131
|
|
|
|
199
|
|
|
|
585
|
|
|
|
843
|
|
Interest
expense
|
|
|
(7,018
|
)
|
|
|
(4,883
|
)
|
|
|
(19,701
|
)
|
|
|
(13,752
|
)
|
Capitalized
interest
|
|
|
2,921
|
|
|
|
2,740
|
|
|
|
8,326
|
|
|
|
7,234
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME
TAXES
|
|
|
6,683
|
|
|
|
7,406
|
|
|
|
15,488
|
|
|
|
21,766
|
|
INCOME
TAXES
|
|
|
(2,450
|
)
|
|
|
(2,655
|
)
|
|
|
(5,663
|
)
|
|
|
(7,793
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
4,233
|
|
|
$
|
4,751
|
|
|
$
|
9,825
|
|
|
$
|
13,973
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC
EARNINGS PER COMMON
SHARE
|
|
$
|
0.16
|
|
|
$
|
0.19
|
|
|
$
|
0.38
|
|
|
$
|
0.57
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DILUTED
EARNINGS PER COMMON
SHARE
|
|
$
|
0.16
|
|
|
$
|
0.18
|
|
|
$
|
0.37
|
|
|
$
|
0.55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE COMMON SHARES
OUTSTANDING:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC
|
|
|
26,142
|
|
|
|
25,254
|
|
|
|
25,836
|
|
|
|
24,549
|
|
DILUTED
|
|
|
26,982
|
|
|
|
25,987
|
|
|
|
26,668
|
|
|
|
25,272
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CARRIZO
OIL & GAS, INC.
CONSO
LIDATED
STATEMENTS OF CASH FLOWS
(Unaudited)
|
|
For
the
Nine
|
|
|
|
Months
Ended
|
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Restated)
|
|
|
|
(In
thousands)
|
|
CASH
FLOWS FROM OPERATING
ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$
|
9,825
|
|
|
$
|
13,973
|
|
Adjustment
to reconcile net income
to net cash provided by operating activities-
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and
amortization
|
|
|
29,033
|
|
|
|
21,630
|
|
Fair
value loss (gain) of
derivative financial instruments
|
|
|
5,311
|
|
|
|
(7,734
|
)
|
Accretion
of discounts on asset
retirement obligations and debt
|
|
|
265
|
|
|
|
237
|
|
Stock-based
compensation
|
|
|
3,050
|
|
|
|
1,999
|
|
Provision
for allowance for
doutbful accounts
|
|
|
(243
|
)
|
|
|
-
|
|
Loss
on extinguishment of
debt
|
|
|
-
|
|
|
|
294
|
|
Equity
in income of Pinnacle Gas
Resources, Inc.
|
|
|
-
|
|
|
|
(35
|
)
|
Deferred
income
taxes
|
|
|
5,290
|
|
|
|
7,503
|
|
Other
|
|
|
1,169
|
|
|
|
1,129
|
|
Changes
in operating assets and
liabilities
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
(3,276
|
)
|
|
|
(3,766
|
)
|
Other
assets
|
|
|
(2,514
|
)
|
|
|
1,705
|
|
Accounts
payable
|
|
|
1,897
|
|
|
|
(778
|
)
|
Accrued
liabilities
|
|
|
(308
|
)
|
|
|
1,087
|
|
Net
cash provided by operating
activities
|
|
|
49,499
|
|
|
|
37,244
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(150,514
|
)
|
|
|
(146,196
|
)
|
Change
in capital expenditure
accrual
|
|
|
(3,484
|
)
|
|
|
1,376
|
|
Proceeds
from the sale of
properties
|
|
|
1,405
|
|
|
|
33,604
|
|
Advances
to
operators
|
|
|
963
|
|
|
|
(1,454
|
)
|
Advances
for joint
operations
|
|
|
(651
|
)
|
|
|
(1,894
|
)
|
Other
|
|
|
64
|
|
|
|
(342
|
)
|
Net
cash used in investing
activities
|
|
|
(152,217
|
)
|
|
|
(114,906
|
)
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
Proceeds
from debt issuance and
borrowings
|
|
|
129,000
|
|
|
|
53,000
|
|
Debt
repayments
|
|
|
(96,693
|
)
|
|
|
(36,159
|
)
|
Common
stock offering, net of
costs
|
|
|
72,003
|
|
|
|
33,593
|
|
Stock
options
exercised
|
|
|
790
|
|
|
|
585
|
|
Deferred
loan costs and
other
|
|
|
(3,214
|
)
|
|
|
(676
|
)
|
Net
cash provided by financing
activities
|
|
|
101,886
|
|
|
|
50,343
|
|
|
|
|
|
|
|
|
|
|
NET
DECREASE IN CASH AND CASH
EQUIVALENTS
|
|
|
(832
|
)
|
|
|
(27,319
|
)
|
|
|
|
|
|
|
|
|
|
CASH
AND CASH EQUIVALENTS,
beginning of period
|
|
|
5,408
|
|
|
|
28,725
|
|
|
|
|
|
|
|
|
|
|
CASH
AND CASH EQUIVALENTS, end of
period
|
|
$
|
4,576
|
|
|
$
|
1,406
|
|
|
|
|
|
|
|
|
|
|
CASH
PAID FOR INTEREST (NET OF
AMOUNTS CAPITALIZED)
|
|
$
|
9,867
|
|
|
$
|
5,381
|
|
|
|
|
|
|
|
|
|
|
CARRIZO
OIL & GAS, INC.
NOTE
S
TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
The
consolidated financial statements included herein have been prepared by Carrizo
Oil & Gas, Inc. (the “Company”), and are unaudited. The financial
statements reflect the accounts of the Company and its subsidiaries after
elimination of all significant intercompany transactions and
balances. The financial statements reflect necessary adjustments, all
of which are of a recurring nature, and are in the opinion of management
necessary for a fair presentation. Certain information and footnote
disclosures normally included in financial statements prepared in accordance
with U.S. generally accepted accounting principles have been omitted pursuant
to
the rules and regulations of the Securities and Exchange Commission
(“SEC”). The Company believes that the disclosures included herein
are adequate to allow the information presented not to be
misleading. The financial statements included herein should be read
in conjunction with the audited financial statements and notes thereto included
in the Company’s Annual Report on Form
10-K
for
the year ended December 31, 2006 (the “2006 Form 10-K”).
Reclassifications
Certain
reclassifications have been made to the prior period’s financial statements to
conform to the current presentation.
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 disclosures of
contingent assets and liabilities at the date of the consolidated financial
statements and the reported amounts of revenues and expenses during the periods
reported. Actual results could differ from these
estimates.
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 collectibility 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 estimates is a function of
the quality of available data and of engineering and geological interpretation
and judgment. Subsequent drilling results, testing and production may
justify revision of such estimates. 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 the Company’s common stock and corresponding volatility and the
Company’s ability to generate future taxable income. Future changes
in these assumptions may materially affect these significant estimates in
the
near term.
Oil
and Natural Gas Properties
Investments
in oil and natural gas properties are accounted for using the full-cost method
of accounting. All costs directly associated with the acquisition,
exploration and development of oil and natural gas properties are
capitalized. Such costs include lease acquisitions, seismic surveys,
and drilling and completion equipment. The Company proportionally
consolidates its interests in oil and natural gas properties. The
Company 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. Maintenance and
repairs are expensed as incurred.
Depreciation,
depletion and amortization (“DD&A”) of proved oil and natural gas properties
is based on the unit-of-production method using estimates of proved reserve
quantities. Investments in unproved properties are not subject to
DD&A until proved reserves associated with the projects can be determined or
until they are impaired. Unevaluated properties are evaluated
periodically for impairment on a property-by-property basis. If the
results of an assessment indicate that the properties have been impaired,
the
amount
of
such impairment is determined and added to the proved oil and natural gas
property costs subject to DD&A. The depletable 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 quarters ended September
30, 2007 and 2006 was $2.26 and $2.59, respectively.
Dispositions
of oil and natural gas properties are accounted for 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.
Net
capitalized costs 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. For the three-month periods ended September 30,
2007 and 2006, the Company did not have any charges associated with its ceiling
test.
Depreciation
of other property and equipment is provided using the straight-line method
based
on estimated useful lives ranging from five to 10 years.
Supplemental
Cash Flow Information
The
adjustment of the investment in Pinnacle of $6.0 million, net of tax and
the
capitalization of $1.7 million net of tax related to stock-based compensation
associated with the adoption of the Statement of Financial Accounting Standards
No. 123 (revised) (“SFAS No. 123 (R)”) are excluded from the Statement of Cash
Flows for the nine months ended September 30, 2007 and 2006,
respectively. The Company paid no income taxes during the nine months
ended September 30, 2007 and 2006.
Stock-Based
Compensation
The
Company records stock-based compensation as prescribed by the SFAS No. 123
(R). The compensation expense associated with stock options is based
on the grant-date fair value of the options and recognized over the vesting
period. Restricted stock is recorded as deferred compensation based
on the closing price of the Company’s stock on the issuance date and is
amortized to stock-based compensation expense ratably over the vesting period
of
the restricted shares (generally one to three years).
The
Company recognized the following stock-based compensation expense:
|
|
Three
Months
|
|
|
Nine
Months
|
|
|
|
Ended
September
30,
|
|
|
Ended
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
Stock
Option
Expense
|
|
$
|
0.1
|
|
|
$
|
0.2
|
|
|
$
|
0.3
|
|
|
$
|
0.4
|
|
Restricted
Stock
Expense
|
|
|
1.0
|
|
|
|
0.6
|
|
|
|
2.8
|
|
|
|
1.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Stock-Based Compensation
Expense
|
|
$
|
1.1
|
|
|
$
|
0.8
|
|
|
$
|
3.1
|
|
|
$
|
2.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative
Instruments
The
Company uses derivatives to manage price and interest rate risk underlying
its
oil and gas production and the variable interest rate on its Second Lien
Credit
Facility.
Upon
entering into a derivative contract, the Company either designates the
derivative instrument as a hedge of the variability of cash flow to be received
(cash flow hedge) or the derivative must be accounted for as a non-designated
derivative. All of the Company’s derivative instruments presented
herein were treated as non-designated derivatives and the unrealized gain/(loss)
related to the mark-to-market valuation was included in the Company’s
earnings.
The
Company typically uses fixed-rate swaps and costless collars to hedge its
exposure to material changes in the price of oil and natural gas and variable
interest rates on long-term debt.
The
Company’s Board of Directors sets all risk management policies and reviews
volumes, types of instruments and counterparties on a quarterly
basis. These policies require that derivative instruments be executed
only by 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 approved counterparties identify the
President and Chief Financial Officer as the only Company representatives
authorized to execute trades. The Board of Directors also reviews the
status and results of derivative activities quarterly.
Major
Customers
The
Company sold oil and natural gas production representing more than 10% of
its
oil and natural gas revenues as follows:
|
|
Three
Months
|
|
|
Nine
Months
|
|
|
|
Ended
September
30,
|
|
|
Ended
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
Chevron/Texaco
|
|
|
-
|
|
|
|
11
|
%
|
|
|
-
|
|
|
|
12
|
%
|
Reichmann
Petroleum
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
11
|
%
|
Cokinos
Natural Gas
Company
|
|
|
17
|
%
|
|
|
-
|
|
|
|
10
|
%
|
|
|
-
|
|
Houston
Pipeline
Co.
|
|
|
14
|
%
|
|
|
-
|
|
|
|
13
|
%
|
|
|
-
|
|
Crosstex
Energy
Services
|
|
|
15
|
%
|
|
|
-
|
|
|
|
15
|
%
|
|
|
-
|
|
Energy
Transfer
|
|
|
16
|
%
|
|
|
10
|
%
|
|
|
12
|
%
|
|
|
-
|
|
Partner
Energy
Services
|
|
|
-
|
|
|
|
10
|
%
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
Per Share
Supplemental
earnings per share information is provided below:
|
|
Three
Months
|
|
|
Nine
Months
|
|
|
|
Ended
September
30,
|
|
|
Ended
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(Restated)
|
|
|
|
|
(Restated)
|
|
|
|
|
|
|
(In
thousands,
except
|
|
|
|
per
share
amounts)
|
|
Net
income
|
|
$
|
4,233
|
|
|
$
|
4,751
|
|
|
$
|
9,825
|
|
|
$
|
13,973
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
common shares
outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average common shares
outstanding
|
|
|
26,142
|
|
|
|
25,254
|
|
|
|
25,836
|
|
|
|
24,549
|
|
Stock
options and
warrants
|
|
|
840
|
|
|
|
733
|
|
|
|
832
|
|
|
|
723
|
|
Diluted
weighted average common
shares outstanding
|
|
|
26,982
|
|
|
|
25,987
|
|
|
|
26,668
|
|
|
|
25,272
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per common
share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.16
|
|
|
$
|
0.19
|
|
|
$
|
0.38
|
|
|
$
|
0.57
|
|
Diluted
|
|
$
|
0.16
|
|
|
$
|
0.18
|
|
|
$
|
0.37
|
|
|
$
|
0.55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
earnings per common share is based on the weighted average number of
shares of
common stock outstanding during the periods. Diluted earnings per
common share is based on the weighted average number of common shares
and all
dilutive potential common shares issuable during the periods. The
Company had 2,500 stock options that were excluded in the calculation
of
dilutive shares for the three-month period ended September 30, 2006 because
the
exercise price of these instruments exceeded the underlying market value
of the
options.
2.
FINANCIAL RESTATEMENT
In
connection with our annual disclosure and reporting procedures related
to our
interest rate derivatives, the Company determined that its unrealized
mark-to-market adjustment for its open interest rate derivative positions
at September 30, 2007 was incomplete. In the original adjustment,
the Company
did not include the impact of a 2008 interest rate derivative which was
valued as a liability of $ 1.8 million on September 30, 2007. The
impact of this
adjustment is presented below:
|
|
Three
Months
Ended
|
|
|
Nine
Months
Ended
|
|
|
|
September
30,
2007
|
|
|
September
30,
2007
|
|
|
|
As
|
|
|
As
|
|
|
As
|
|
|
As
|
|
|
|
Reported
|
|
Restated
|
|
|
Reported
|
|
|
Restated
|
|
|
|
(In
thousands, except per share
amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain
on derivatives,
net
|
|
$
|
3,676
|
|
|
$
|
1,917
|
|
|
$
|
2,045
|
|
|
$
|
286
|
|
Income
taxes
|
|
|
3,066
|
|
|
|
2,450
|
|
|
|
6,279
|
|
|
|
5,663
|
|
Net
income
|
|
|
5,376
|
|
|
|
4,233
|
|
|
|
10,968
|
|
|
|
9,825
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
earnings per
share
|
|
$
|
0.21
|
|
|
$
|
0.16
|
|
|
$
|
0.42
|
|
|
$
|
0.38
|
|
Diluted
earnings per
share
|
|
|
0.20
|
|
|
|
0.16
|
|
|
|
0.41
|
|
|
|
0.37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
current
assets
|
|
|
|
|
|
|
|
|
|
$
|
44,035
|
|
|
$
|
44,466
|
|
Total
assets
|
|
|
|
|
|
|
|
|
|
|
630,012
|
|
|
|
630,627
|
|
Total
current
liabilities
|
|
|
|
|
|
|
|
|
|
|
56,876
|
|
|
|
58,107
|
|
Total
shareholders' equity
|
|
|
|
|
|
|
|
|
|
|
304,901
|
|
|
|
303,758
|
|
Total
liabilities and
shareholders' equity
|
|
|
|
|
|
|
630,012
|
|
|
|
630,627
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt consisted of the following at September 30, 2007 and December 31,
2006:
|
|
September
30,
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Second
Lien Credit
Facility
|
|
$
|
221,063
|
|
|
$
|
147,750
|
|
Senior
Secured Revolving Credit
Facility
|
|
|
-
|
|
|
|
41,000
|
|
Other
|
|
|
3
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
221,066
|
|
|
|
188,758
|
|
Current
maturities
|
|
|
(2,253
|
)
|
|
|
(1,508
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
218,813
|
|
|
$
|
187,250
|
|
|
|
|
|
|
|
|
|
|
Second
Lien Credit Facility
On
December 20, 2006, the Company amended its second lien credit agreement (the
“Second Lien Credit Facility”) to increase the principal amount of the term loan
agreement, lower the interest rate and provide flexibility in the debt
covenants. The amended Second Lien Credit Facility provides for a
term loan facility in an aggregate principal amount of $225.0 million that
matures in July 2010. It is secured by substantially all of the
Company’s assets and is guaranteed by the Company’s subsidiaries. The
liens securing the Second Lien Credit Facility are second in priority to the
liens securing the Senior Secured Revolving Credit Facility (discussed
below).
In
January 2007, the Company drew the additional $75.0 million then available
under
the amended agreement. The net proceeds of $72.1 million were used to
repay the $41.0 million of borrowings then outstanding under the Senior Secured
Revolving Credit Facility and to fund a portion of the Company’s capital
expenditure program and for general corporate purposes.
The
interest rate on each base rate loan will be (1) the greater of the Agent’s
prime rate and the federal funds effective rate plus 0.5%, plus (2) a margin
of
3.75%. The interest rate on each Eurodollar loan will be the adjusted
LIBOR rate plus a margin of 4.75%. Interest on Eurodollar loans is
payable on either the last day of each period or every three months, whichever
is earlier. Interest on base rate loans is payable
quarterly. On September 30, 2007, the interest rate was approximately
9.9%, excluding the impact of interest rate swaps.
Under
this agreement, the Company is subject to certain covenants and restrictions
on
additional financing and other matters. See the 2006 Form 10-K for
further discussion.
Senior
Secured Revolving Credit Facility
On
May
25, 2006, the Company entered into a Senior Secured Revolving Credit Facility
(“Senior Credit Facility”) with JPMorgan Chase Bank, National Association, as
administrative agent, that matures May 25, 2010. The Senior Credit
Facility provides for a revolving credit facility up to the lesser of the
borrowing base and $200.0 million. It is secured by substantially all
of the Company’s assets and is guaranteed by the Company’s
subsidiaries. The liens securing the Senior Credit Facility are first
in priority to the liens securing the Second Lien Credit Facility.
On
September 11, 2007, the Company entered into the Second Amendment (the “Second
Amendment”) to the Senior Credit Facility. The Second Amendment
further provides that in the event the scheduled redetermination of the
Borrowing Base is not made on or prior to January 1, 2008 as a result of the
Company’s failure to comply with the requirement to deliver required engineering
reports, the Borrowing Base will be reduced by $3 million commencing on January
1, 2008 and continuing on the first day of each month thereafter until the
Borrowing Base is redetermined. The Conforming Borrowing Base (as
defined in the Senior Credit Facility) has been amended to be $100
million. In connection with the Second Amendment, JPMorgan Chase Bank
has assigned 44.4% of its commitment to Guaranty Bank. In addition,
the Second Amendment increases the amount of investments in others that the
Company may make.
As
of
September 30, 2007, the Company had no outstanding borrowings under the Senior
Credit Facility.
The
borrowing base will be determined by the lenders at least semi-annually on
each
May 1 and November 1, beginning November 1, 2006. The Company may
request one unscheduled borrowing base determination subsequent to each
scheduled determination, and the lenders may request unscheduled determinations
at any time. At September 30, 2007, the borrowing base was $117.0
million. Because of the recent borrowing base redetermination, the
next scheduled redetermination will be in December 2007.
The
annual interest rate on each base rate borrowing will be (1) the greatest of
the
Agent’s Prime Rate, the Base CD Rate plus 1.0% and the Federal Funds Effective
Rate plus 0.5%, plus (2) a margin between 0.25% and 1.75% (depending on the
current level of borrowing base usage). The interest rate on each
Eurodollar loan will be the adjusted LIBOR Rate plus a margin between 1.5%
to
3.0% (depending on the current level of borrowing base usage).
The
Company is subject to certain covenants and customary events of default under
the terms of the Senior Credit Facility. See the Company’s 2006 Form
10-K for further discussion.
4.
|
INVESTMENT
IN PINNACLE GAS RESOURCES, INC.:
|
In
2003,
the Company and its wholly-owned subsidiary CCBM, Inc. (“CCBM”) contributed
their interests in certain natural gas and oil leases in Wyoming and Montana
in
areas prospective for coalbed methane to a newly formed entity, Pinnacle Gas
Resources, Inc. (“Pinnacle”). At September 30, 2007, the Company
owned less than ten percent of Pinnacle’s outstanding equity and accounted for
the investment under the cost method. Prior to April 2006, the
Company accounted for its interest in Pinnacle using the equity
method.
During
the second quarter of 2007, Pinnacle became a publicly traded entity on the
Nasdaq Global Market. For accounting purposes, the Pinnacle stock now
has a readily determinable fair value. Carrizo classifies the
Pinnacle investment as available-for-sale and adjusts the investment to fair
value through other comprehensive income. At September 30, 2007,
Carrizo increased the book value of its Pinnacle investment by $9.2 million,
$6.0 million net of tax, and reported the fair value of the stock at $11.9
million (based on the closing price of Pinnacle’s common stock on September 30,
2007).
In
June
of 2007, Carrizo sold 41,894 shares of Pinnacle stock for net proceeds of $0.4
million and recognized a $0.3 million gain, which is included in Other income
and expenses, net on the Consolidated Statements of Income. As of
September 30, 2007, Carrizo owned 2,417,208 shares of Pinnacle common
stock.
On
October 15, 2007, Pinnacle, Quest Resource Corporation (“Quest”), and Quest
Merger Sub, Inc., a wholly owned subsidiary of Quest (“Merger Sub”), entered
into an agreement and plan of merger whereby Merger Sub will merge with and
into
Pinnacle. The merger agreement provides for Quest’s acquisition of all of the
issued and outstanding shares of Pinnacle’s common stock for aggregate
consideration of approximately 19.1 million shares of Quest’s common stock, or
approximately $207 million based on the closing price of Quest’s common stock on
October 15, 2007. Upon completion of the merger, each share of
Pinnacle’s common stock will be converted into the right to receive 0.6584 of a
share of common stock of Quest. Completion of the merger transaction
is
conditioned
upon, among other things, adoption of the merger agreement by both Pinnacle’s
and Quest’s stockholders and consummation of an initial public offering of
common units by Quest Energy Partners, L.P. (an affiliate of
Quest). Quest and Pinnacle have stated that they anticipate the
closing of the merger will occur in the first or second quarter of
2008. This transaction does not impact the accounting method for the
Pinnacle investment.
The
Company provided deferred federal income taxes at the rate of 35% (which also
approximates its statutory rate) that amounted to a tax expense of $2.3 million
and $2.6 million for the three-month periods ended September 30, 2007 and 2006,
respectively, and $5.3 million and $7.5 million for the nine-month periods
ended
September 30, 2007 and 2006, respectively.
On
January 1, 2007, the Company adopted FASB Interpretation No. 48,
“Accounting for Uncertainty
in
Income Taxes – an interpretation of FASB Statement No. 109”
(“FIN
48”). FIN 48 prescribes a measurement process for recording in the
financial statements uncertain tax positions taken or expected to be taken
in a
tax return. Additionally, FIN 48 provides guidance regarding
uncertain tax positions relating to derecognition, classification, interest
and
penalties, accounting in interim periods, disclosure and
transition. Carrizo classifies interest and penalties associated with
income taxes as interest expense. At September 30, 2007, the Company
had no material uncertain tax positions and the tax years 2003 through 2006
remained open to review by federal and various state tax
jurisdictions.
6.
|
COMMITMENTS
AND CONTINGENCIES:
|
From
time
to time, the Company is party to certain legal actions and claims arising in
the
ordinary course of business. While the outcome of these events cannot
be predicted with certainty, management does not expect these matters to have
a
materially adverse effect on the financial position of the Company.
The
operations and financial position of the Company continue to be affected from
time to time in varying degrees by domestic and foreign political developments
as well as legislation and regulations pertaining to restrictions on oil and
natural gas production, imports and exports, natural gas regulation, tax
increases, environmental regulations and cancellation of contract
rights. Both the likelihood and overall effect of such occurrences on
the Company vary greatly and are not predictable.
The
Company issued 1,998,020 and 1,686,531 net shares of common stock during the
nine months ended September 30, 2007 and 2006, respectively. Shares
issued during the nine months ended September 30, 2007 consisted of 1,800,000
shares issued in the September 2007 registered direct offering, 116,482 shares
issued, net of 7,301 shares forfeited, as restricted stock awards to employees
and 85,732 shares through the exercise of options granted under the Company’s
Incentive Plan. Shares issued during the nine months ended September
30, 2006 consisted of 1,350,000 shares issued in the July 2006 private
placement, 236,351 shares issued, net of 23,292 shares forfeited, as restricted
stock awards to employees, 99,800 shares issued through the exercise of options
granted under the Company’s Incentive Plan and 2,000 shares issued in exchange
for oil and gas properties in the Barnett Shale. The Company also
purchased and retired 4,194 and 1,620 shares to satisfy employee tax withholding
obligations in connection with the vesting of the restricted stock during the
nine months ended September 30, 2007 and 2006, respectively.
In
September 2007, the Company sold 1,800,000 shares of its common stock to certain
qualified investors in a registered direct offering at a price of $41.40 per
share. The number of shares sold was approximately 6.8% of the
Company’s fully diluted shares outstanding before the offering.
The
Company expects to use substantially
all of the net proceeds to fund in part its capital expenditure program,
including its drilling and leasing programs in the Barnett Shale and appraisal
well drilling in the
North
Sea
, and for other
corporate purposes. Pending those uses, the Company used a portion of the net
proceeds of approximately $72.0 million to repay $54 million of outstanding
borrowings under the Senior Credit Facility.
8.
|
DERIVATIVE
INSTRUMENTS:
|
The
Company enters into swaps, options, collars and other derivative contracts
to
hedge the price risks associated with a portion of anticipated future oil and
natural gas production. The Company also uses interest rate swap
agreements to manage the Company’s exposure to interest rate fluctuations on the
Second Lien Credit Facility.
The
Company accounts for its oil and natural gas derivatives and interest rate
swap
agreements as non-designated hedges. These derivatives are
marked-to-market at each balance sheet date and the unrealized gains (losses)
along with the realized gains (losses) associated with the cash settlements
of
derivative instruments are reported as gain (loss) on derivatives, net in Other
Income and Expenses in the Consolidated Statements of Income. For the
three and nine-month periods ended September 30, 2007 and 2006, the Company
recorded the following related to its derivatives:
|
|
Three
Months
|
|
|
Nine
Months
|
|
|
|
Ended
September
30,
|
|
|
Ended
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(Restated)
|
|
|
|
|
|
(Restated)
|
|
|
|
|
|
|
(In
millions)
|
|
Realized
gains:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas and oil
derivatives
|
|
$
|
2.8
|
|
|
$
|
1.1
|
|
|
$
|
5.4
|
|
|
$
|
3.6
|
|
Interest
rate
swaps
|
|
|
-
|
|
|
|
0.4
|
|
|
|
0.2
|
|
|
|
0.7
|
|
|
|
|
2.8
|
|
|
|
1.5
|
|
|
|
5.6
|
|
|
|
4.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gains
(losses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas and oil
derivatives
|
|
$
|
1.0
|
|
|
$
|
2.9
|
|
|
$
|
(3.5
|
)
|
|
$
|
7.5
|
|
Interest
rate
swaps
|
|
|
(1.9
|
)
|
|
|
(0.7
|
)
|
|
|
(1.8
|
)
|
|
|
0.3
|
|
|
|
|
(0.9
|
)
|
|
|
2.2
|
|
|
|
(5.3
|
)
|
|
|
7.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain
on derivatives,
net
|
|
$
|
1.9
|
|
|
$
|
3.7
|
|
|
$
|
0.3
|
|
|
$
|
12.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
fair
value of the outstanding derivatives at September 30, 2007 and December 31,
2006
was an asset of $0.7 million and $6.0 million, respectively.
At
September 30, 2007, the Company had the following outstanding 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
Collars
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Average
|
|
Quarter
|
|
Bbls
|
|
|
Floor
Price
(2)
|
|
|
Ceiling
Price
(2)
|
|
Fourth
Quarter
2007
|
|
|
27,600
|
|
|
$
|
70.00
|
|
|
$
|
75.90
|
|
First
Quarter
2008
|
|
|
18,200
|
|
|
|
70.00
|
|
|
|
76.20
|
|
Second
Quarter
2008
|
|
|
9,100
|
|
|
|
70.00
|
|
|
|
76.75
|
|
Third
Quarter
2008
|
|
|
9,200
|
|
|
|
70.00
|
|
|
|
76.75
|
|
Fourth
Quarter
2008
|
|
|
9,200
|
|
|
|
70.00
|
|
|
|
76.75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
__________
(1)
|
Based
on Houston Ship Channel spot
prices.
|
(2)
|
Based
on West Texas intermediate index
prices.
|
During
the first and second quarter of 2007, the Company entered into interest swap
agreements covering amounts outstanding under the Second Lien Credit Facility
as
amended in December 2006. These arrangements are designed to manage
the Company’s exposure to interest rate fluctuations through December 31, 2008
by effectively exchanging existing obligations to pay interest based on floating
rates with obligations to pay interest based on fixed LIBOR. The
Company’s outstanding positions under interest rate swap agreements at September
30, 2007 were as follows (dollars in thousands):
|
|
Notional
|
|
|
Fixed
|
|
Quarter
|
|
Amount
|
|
|
LIBOR
Rate
|
|
Fourth
Quarter
2007
|
|
$
|
221,063
|
|
|
|
5.25
|
%
|
First
Quarter
2008
|
|
|
220,500
|
|
|
|
5.32
|
%
|
Second
Quarter
2008
|
|
|
219,938
|
|
|
|
5.32
|
%
|
Third
Quarter
2008
|
|
|
219,375
|
|
|
|
5.31
|
%
|
Fourth
Quarter
2008
|
|
|
218,813
|
|
|
|
5.31
|
%
|
|
|
|
|
|
|
|
|
|
ITEM
2. MANAGEMENT'S
DISCUSSION AND
ANALYSIS
OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The
following is management’s discussion and analysis of certain significant factors
that have affected certain aspects of the Company’s financial position and
results of operations during the periods included in the accompanying unaudited
financial statements. You should read this in conjunction with the
discussion under “Management’s Discussion and Analysis of Financial Condition
and Results of Operations” and the audited financial statements included in our
Annual Report on Form 10-K for the year ended December 31, 2006 and the
unaudited financial statements included elsewhere herein.
General
Overview
Our
third
quarter 2007 included revenues of $30.3 million and record production of
4.4
Bcfe. The key drivers to our success for the three and nine-month
periods ended September 30, 2007 include the following:
Drilling
program
. Our success is largely dependent on the results of
our drilling program. During the nine months ended September 30,
2007, we drilled 56 gross wells (38.4 net wells) with an apparent success
rate
of 96% that was comprised of: (1) 39 of 39 gross wells (31.3 net wells) in
the
Barnett Shale area, (2) five of six gross wells (1.5 of 1.8 net wells) in
the
onshore Gulf Coast area, (3) one of one gross well (0.2 net well) in the
North
Sea, (4) three of four gross wells (3.0 of 4.0 net wells) in the Camp Hill
field
and (5) six of six gross wells (1.1 net wells) in other areas. We
also drilled eight gross service wells (8.0 net wells) in the Camp Hill
area. At September 30, 2007, we had 15 gross wells that were awaiting
completion or pipeline connections.
Production.
Our
third quarter production of 4.4 Bcfe, or 48.2 MMcfe/d was a record
high. The third quarter production increased 55% from the third
quarter 2006 production of 2.9 Bcfe and increased 6% from the second quarter
2007 production of 4.2 Bcfe. The increase between second and third
quarter of 2007 was due primarily to production from nine new wells in the
Barnett Shale area and production for the entire third quarter of 2007 from
the
Doberman #1 in the Gulf Coast. The increase from the third quarter of
2006 to the third quarter of 2007 was primarily due to new Barnett Shale
wells,
the addition of the Baby Ruth and Doberman wells in the Gulf Coast and the
recompletion of the Galloway Gas Unit well #1 and the LL&E #1.
Commodity
prices.
Natural gas prices during the third quarter of 2007
were $6.33 per Mcf (excluding the impact of our hedges), $0.06 per Mcf less
than
the price in the third quarter of 2006 and $1.21 per Mcf, or 16% lower than
the
price in the second quarter of 2007. The decline in natural gas price
from the second quarter of 2007 to the third quarter of 2007 was largely
responsible for the decline in total revenues from $32.9 million in the second
quarter of 2007 to $30.3 million in the third quarter of 2007.
Capital
funding.
In order to fund our growth, we have taken steps to
enhance our liquidity. During the first quarter of 2007, we received
$72.1 million of net proceeds under the amended Second Lien
Facility. During the third quarter of 2007, we received approximately
$72.0 million in net proceeds from a registered direct offering of 1.8 million
shares of our common stock. The proceeds were used to retire
borrowings under the Senior Credit Facility and to fund our drilling program
and
general corporate purposes. In September 2007, our borrowing base
availability on our Senior Credit Facility increased from $74.8 million to
$117.0 million. The next borrowing base redetermination is scheduled
for December 2007.
Outlook
Our
outlook for the future remains positive. To continue our
success:
·
|
We
plan to continue with the 2007 drilling program to drill 53 gross
wells in
the Barnett Shale area, ten gross wells in the Gulf Coast area,
25 to 30
gross wells in our Camp Hill field (which includes approximately
14
service wells) and five wells in other areas. In the Barnett
Shale, we plan to utilize two drillings rigs in SE Tarrant County,
Texas
through the third quarter 2008 with each rig scheduled to drill
one
horizontal well each month. Our other two drilling rigs will be
dedicated to drilling horizontal wells in Tarrant, Denton and Parker
counties. We expect to spend between $145 million and $165
million on our 2007 drilling program. The actual number of
wells drilled will vary depending upon various factors, including
the
availability and cost of drilling rigs, land and industry partner
issues,
our cash flow, success of drilling programs, weather delays and
other
factors. If we drill the number of wells we have budgeted for
2007, depreciation, depletion and amortization, oil and natural
gas
operating expenses and production are expected to increase over
levels
incurred in 2006. Our ability to drill this number of wells is
heavily dependent upon the timely access to oilfield services,
particularly drilling rigs.
|
·
|
We
expect to continue our efforts to grow production. Our
estimated daily production for the month of October 2007 was approximately
53 Mcfe/day.
|
·
|
We
plan to continue the development of other new drilling programs
in the Floyd Shale in Mississippi, the Fayetteville Shale in Arkansas
and
the North Sea. We fracture stimulated our horizontal well in
the Floyd Shale and are swabbing back frac fluid currently. We
are assessing development plans for the Huntington discovery in
Block
22-14b in the North Sea. An appraisal well was spud on August
30, 2007 with expected drilling and testing time of approximately
five
months. As a result of our recent experience in the North Sea,
we currently expect that we will seek to significantly expand our
expenditures in that area over the next several years. We may
seek project financing or other financing alternatives for the
development
of the North Sea assets.
|
·
|
We
expect to hedge production to decrease commodity price
fluctuations. At September 30, 2007, we had hedged
approximately 11,521,000 MMBtus of natural gas production through
2009 and
73,300 Bbls of oil production through
2008.
|
·
|
During
2007, we experienced unexpected delays in the development of the
Camp Hill
field. Our 2007 drilling program in the Camp Hill field has
been delayed primarily due to the unavailability of the rig we
use to
drill in the field. However, we recently received a firm
commitment from our drilling contractor to drill exclusively for
us for
the remainder of 2007 and through February 2008. We believe
that we are on track to drill 27 to 30 wells in 2007 (including
14 service
wells). We also experienced operational and administrative
problems with our steam injection process. The steam generators
expected to be used were not available due to delays in repair
work and/or
permit issues. We injected steam in the Camp Hill field through
one of our generators until it encountered operational damage in
January
2007. We expect to receive a replacement generator in December
2007 and to commence steam injection as soon thereafter as
possible. Our other two generators have not been available for
injection due to unexpected permitting issues and the need for
repair
work. We currently expect that these two generators will
be ready to inject steam by the end of March 2008 with respect
to one
generator and by the end of June 2008, with respect to the
other. We recently received the permits for these two
generators to recommence injection. Although these permits will
only allow us to inject steam at 64% of the rate that we had anticipated,
based upon the rate under the prior permits for these same generators,
we
expect to continue to appeal to the regulatory authorities to reinstate
the 100 % rate of generation allowed under the original
permits. Even if we are unsuccessful in increasing the
generation rates under our permits, our proved reserve volumes
for the
Camp Hill field are not expected to decrease as a result. A
lower generation rate assumption (incorporated into our internal
September
30, 2007 proved reserve estimate), however, does extend the productive
life of the field by approximately 33% with a corresponding 19%,
or $31.2
million, reduction in the present value of the estimated future
net
revenues discounted at 10% per annum attributable to these proved
reserves. Prospectively, we expect to continue to use the lower
generation rate assumption in our proved reserve estimates, unless
and
until such time that we are successful in increasing the generation
rates
in our permits.
|
Results
of Operations
Three
Months Ended September 30, 2007,
Compared
to the Three Months Ended September 30, 2006
Oil
and
natural gas revenues for the three months ended September 30, 2007 increased
to
$30.3 million from $20.3 million for the same period in
2006. Production volumes for natural gas for the three months ended
September 30, 2007 increased to 4.1 Bcf from 2.4 Bcf for the same period
in
2006. Average natural gas prices, excluding the impact of the gain
from our cash settled derivatives of $2.8 million and $1.1 million for the
quarters ended September 30, 2007 and 2006, respectively, decreased to $6.33
per
Mcf in the third quarter of 2007 from $6.39 per Mcf in the same period in
2006. Average oil prices for the quarter ended September 30, 2007
increased 10% to $75.40 from $68.46 per barrel in the same period in
2006. The increase in natural gas production volume was due primarily
to the addition of new Barnett Shale wells, production from the Baby Ruth
and
Doberman #1 wells in the Gulf Coast region and increased production from
the
recompleted Galloway Gas Unit 1 well #1 and LL&E #1 in the Gulf Coast
area.
The
following table summarizes production volumes, average sales prices and
operating revenues (excluding the impact of derivatives) for the three
months
ended September 30, 2007 and 2006:
|
|
|
|
|
|
|
|
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 $1.9 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 loss 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 decreased to $2.5 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
lower 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 $0.3 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) $(5.3) 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 $5.7 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
3 and 7 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 3 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
Collars
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Average
|
|
Quarter
|
|
Bbls
|
|
|
Floor
Price
(2)
|
|
|
Ceiling
Price
(2)
|
|
Fourth
Quarter
2007
|
|
|
27,600
|
|
|
$
|
70.00
|
|
|
$
|
75.90
|
|
First
Quarter
2008
|
|
|
18,200
|
|
|
|
70.00
|
|
|
|
76.20
|
|
Second
Quarter
2008
|
|
|
9,100
|
|
|
|
70.00
|
|
|
|
76.75
|
|
Third
Quarter
2008
|
|
|
9,200
|
|
|
|
70.00
|
|
|
|
76.75
|
|
Fourth
Quarter
2008
|
|
|
9,200
|
|
|
|
70.00
|
|
|
|
76.75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
__________
(1)
|
Based
on Houston Ship Channel spot
prices.
|
(2)
|
Based
on West Texas intermediate index
prices.
|
While
the
use of hedging arrangements limits the downside risk of adverse price movements,
it may also limit our ability to benefit from increases in the prices of natural
gas and oil. We enter into the majority of our derivatives
transactions with two counterparties and have a netting agreement in place
with
those counterparties. We do not obtain collateral to support the
agreements but monitor the financial viability of counterparties and believe
our
credit risk is minimal on these transactions. Under these
arrangements, payments are received or made based on the differential between
a
fixed and a variable commodity price. These agreements are settled in
cash at expiration or exchanged for physical delivery contracts. In
the event of nonperformance, we would be exposed again to price
risk. We have additional risk of financial loss because the price
received for the product at the actual physical delivery point may differ from
the prevailing price at the delivery point required for settlement of the
hedging transaction. Moreover, our derivatives arrangements generally
do not apply to all of our production and thus provide only partial price
protection against declines in commodity prices. We expect that the
amount of our hedges will vary from time to time.
Our
natural gas derivative transactions are generally settled based upon the average
of the reporting settlement prices on the Houston Ship Channel index for the
last three trading days of a particular contract month. Our oil
derivative transactions are generally settled based on the average reporting
settlement prices on the West Texas Intermediate index for each trading day
of a
particular calendar month. For the third quarter of 2007, a 10%
change in the price per Mcf of natural gas sold would have changed revenue
by
$2.6 million. A 10% change in the price per barrel of oil would have
changed revenue by $0.4 million.
Forward
Looking Statements
The
statements contained in all parts of this document, including, but not limited
to, those relating to our schedule, targets, estimates or results of future
drilling, including the number, timing and results of wells, budgeted wells,
increases in wells, the timing and risk involved in drilling follow-up wells,
expected working or net revenue interests, planned expenditures, prospects
budgeted and other future capital expenditures, risk profile of oil and natural
gas exploration, acquisition of 3-D seismic data (including number, timing
and
size of projects), planned evaluation of prospects, probability of prospects
having oil and natural gas, expected production or reserves, increases in
reserves, acreage, working capital requirements, hedging activities, the
ability
of expected sources of liquidity to
implement
the Company’s business strategy, future exploration activity, production rates,
2007 drilling program, growth in production, development of new drilling
programs, hedging of production and exploration and development expenditures,
Camp Hill development and all and any other statements regarding future
operations, financial results, business plans and cash needs, and the absence
of
a material weakness in our internal control over financial reporting as of
December 31, 2007, and other statements that are not historical facts are
forward looking statements. When used in this document, the words
“anticipate,” “estimate,” “expect,” “may,” “project,” “believe” and similar
expressions are intended to be among the statements that identify forward
looking statements. Such statements involve risks and uncertainties,
including, but not limited to, those relating to the Company's dependence
on its
exploratory drilling activities, the volatility of oil and natural gas prices,
the need to replace reserves depleted by production, operating risks of oil
and
natural gas operations, the Company's dependence on its key personnel, factors
that affect the Company's ability to manage its growth and achieve its business
strategy, risks relating to limited operating history, technological changes,
significant capital requirements of the Company, the potential impact of
government regulations, litigation, competition, the uncertainty of reserve
information and future net revenue estimates, property acquisition risks,
availability of equipment, weather, availability of financing, ability to
obtain
permits, the results of audits and assessments, the results of the final
review
and analysis of our internal controls as of December 31, 2007 by management
and
our auditors and other factors detailed in the “Risk Factors” and other sections
of the Company's Annual Report on Form 10-K for the year ended December 31,
2006
and other filings with the Securities and Exchange Commission. Should
one or more of these risks or uncertainties materialize, or should underlying
assumptions prove incorrect, actual outcomes may vary materially from those
indicated. All subsequent written and oral forward-looking statements
attributable to us or persons acting on our behalf are expressly qualified
in
their entirety by reference to these risks and uncertainties. You
should not place undue reliance on forward-looking statements. Each
forward-looking statement speaks only as of the date of the particular statement
and the Company undertakes no obligation to update or revise any forward-looking
statement.