Attached files
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-Q
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the
quarterly period ended September
30, 2009
[ ]
TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the
transition period from ________ to _________
Commission
File Number 000-29187-87
CARRIZO
OIL & GAS, INC.
(Exact
name of registrant as specified in its charter)
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Texas
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76-0415919
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(State
or other jurisdiction of
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(IRS
Employer Identification No.)
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incorporation
or organization)
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1000 Louisiana Street, Suite 1500, Houston,
TX
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77002
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(Address
of principal executive offices)
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(Zip
Code)
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(713)
328-1000
(Registrant's
telephone number)
Indicate by check mark whether the
registrant (1) has filed all reports required to be filed by Section 13 or
15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports)
and (2) has been subject to such filing requirements for the past 90
days.
YES
[X] NO [
]
Indicate by check mark whether the
registrant has submitted electronically and posted on its corporate Web site, if
any, every Interactive Data File required to be submitted and posted pursuant to
Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter
period that the registrant was required to submit and post such
files).
YES [
] NO [ ]
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company. See
the definitions of “large accelerated filer,” “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act (Check one):
Large
accelerated filer [X] Accelerated
filer []
| Non-accelerated filer [ ] | Smaller reporting company [ ] |
| (Do not check if a smaller reporting company) |
Indicate by check mark whether the
registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act).
YES [
] NO [X]
The
number of shares outstanding of the registrant's common stock, par value $0.01
per share, as of November 2, 2009, the latest practicable date, was
31,072,006.
CARRIZO OIL & GAS, INC.
FORM
10-Q
FOR
THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2009
INDEX
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PART
I. FINANCIAL INFORMATION
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PAGE
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Item
1.
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As
of September 30, 2009 (Unaudited) and December 31,
2008
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2
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For
the three and nine months ended September 30, 2009 and
2008
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3
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For
the nine months ended September 30, 2009 and 2008
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4
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5
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Item
2.
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19
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Item
3.
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31
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Item
4.
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32
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PART
II. OTHER INFORMATION
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33
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41
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CARRIZO OIL & GAS, INC.
CONSOLIDATED
BALANCE SHEETS
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September
30,
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December
31,
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|||||||
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ASSETS
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2009
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2008
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(Unaudited)
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(In
thousands, except par value amount)
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||||||||
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CURRENT
ASSETS:
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||||||||
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Cash
and cash equivalents
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$ | 3,576 | $ | 5,184 | ||||
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Accounts
receivable, trade (net of allowance for doubtful accounts of $1,552 and
$1,264
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||||||||
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at
September 30, 2009 and December 31, 2008, respectively)
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21,228 | 24,675 | ||||||
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Advances
to operators
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325 | 336 | ||||||
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Fair
value of derivative financial instruments
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6,062 | 22,791 | ||||||
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Other
current assets
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5,567 | 3,335 | ||||||
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Total
current assets
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36,758 | 56,321 | ||||||
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PROPERTY
AND EQUIPMENT, net full-cost method of accounting for oil
and
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||||||||
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natural
gas properties (including costs not subject to amortization of $371,558
and
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||||||||
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$378,634
at September 30, 2009 and December 31, 2008, respectively)
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878,646 | 986,629 | ||||||
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DEFERRED
FINANCING COSTS, NET
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9,620 | 8,430 | ||||||
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INVESTMENTS
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3,577 | 3,274 | ||||||
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FAIR
VALUE OF DERIVATIVE FINANCIAL INSTRUMENTS
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- | 15,876 | ||||||
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DEFERRED
INCOME TAXES
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32,371 | - | ||||||
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OTHER
ASSETS
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964 | 1,172 | ||||||
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TOTAL
ASSETS
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$ | 961,936 | $ | 1,071,702 | ||||
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LIABILITIES
AND SHAREHOLDERS' EQUITY
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CURRENT
LIABILITIES:
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||||||||
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Accounts
payable, trade
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$ | 50,922 | $ | 46,683 | ||||
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Accrued
liabilities
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30,632 | 54,149 | ||||||
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Advances
for joint operations
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5,674 | 3,815 | ||||||
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Current
maturities of long-term debt
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148 | 173 | ||||||
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Deferred
tax liability
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2,197 | 9,103 | ||||||
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Total
current liabilities
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89,573 | 113,923 | ||||||
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LONG-TERM
DEBT, NET OF CURRENT MATURITIES AND DEBT DISCOUNT
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541,713 | 475,788 | ||||||
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ASSET
RETIREMENT OBLIGATION
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9,902 | 6,503 | ||||||
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FAIR
VALUE OF DERIVATIVE FINANCIAL INSTRUMENTS
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5,915 | - | ||||||
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DEFERRED
INCOME TAXES
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- | 34,778 | ||||||
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OTHER
LIABILITIES
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1,387 | 625 | ||||||
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COMMITMENTS
AND CONTINGENCIES
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- | |||||||
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SHAREHOLDERS'
EQUITY:
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Common
stock, par value $0.01 (90,000 shares authorized; 31,056
and
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30,860
issued and outstanding at September 30, 2009 and
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December
31, 2008, respectively)
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311 | 309 | ||||||
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Additional
paid-in capital
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428,960 | 420,778 | ||||||
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Retained
earnings (deficit)
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(116,060 | ) | 20,297 | |||||
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Accumulated
other comprehensive income (loss), net of tax
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235 | (1,299 | ) | |||||
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Total
shareholders' equity
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313,446 | 440,085 | ||||||
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TOTAL
LIABILITIES AND SHAREHOLDERS' EQUITY
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$ | 961,936 | $ | 1,071,702 | ||||
The
accompanying notes are an integral part of these consolidated financial
statements.
CARRIZO OIL & GAS, INC.
CONSOLIDATED
STATEMENTS OF OPERATIONS
(Unaudited)
(As
Adjusted (See Note 2))
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Three
Months Ended
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Nine
Months Ended
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September
30,
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September
30,
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|||||||||||||||
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2009
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2008
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2009
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2008
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(In
thousands except per share amounts)
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OIL
AND NATURAL GAS REVENUES
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$ | 23,847 | $ | 58,527 | $ | 81,221 | $ | 179,475 | ||||||||
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COSTS
AND EXPENSES:
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Oil
and natural gas operating expenses (exclusive of depreciation,
depletion
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and
amortization shown separately below)
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5,213 | 10,427 | 22,837 | 28,047 | ||||||||||||
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Third
party gas purchases
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272 | 2,980 | 1,139 | 5,576 | ||||||||||||
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Depreciation,
depletion and amortization
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12,524 | 13,922 | 40,049 | 41,874 | ||||||||||||
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Impairment
of oil and gas properties
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- | - | 216,391 | - | ||||||||||||
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General
and administrative (inclusive of stock-based compensation
expense
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of
$2,780 and $1,560 for the three months ended September 30, 2009
and
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2008,
respectively, and $8,514 and $4,547 for the nine months
ended
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September
30, 2009 and 2008, respectively)
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7,633 | 5,809 | 21,894 | 17,908 | ||||||||||||
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Accretion
expense related to asset retirement obligations
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79 | 58 | 225 | 173 | ||||||||||||
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TOTAL
COSTS AND EXPENSES
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25,721 | 33,196 | 302,535 | 93,578 | ||||||||||||
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OPERATING
INCOME (LOSS)
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(1,874 | ) | 25,331 | (221,314 | ) | 85,897 | ||||||||||
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OTHER
INCOME AND EXPENSES:
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Net
gain (loss) on derivatives
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(1,986 | ) | 77,686 | 25,802 | (357 | ) | ||||||||||
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Loss
on early extinguishment of debt
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- | 16 | - | (5,689 | ) | |||||||||||
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Interest
income
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1 | 43 | 13 | 251 | ||||||||||||
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Interest
expense
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(9,903 | ) | (8,491 | ) | (28,617 | ) | (20,950 | ) | ||||||||
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Capitalized
interest
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4,996 | 6,315 | 15,065 | 14,479 | ||||||||||||
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Impairment
of investment in Pinnacle Gas Resources, Inc.
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- | - | (2,091 | ) | - | |||||||||||
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Other
income (expenses), net
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(23 | ) | 15 | 16 | 64 | |||||||||||
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INCOME
(LOSS) BEFORE INCOME TAXES
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(8,789 | ) | 100,915 | (211,126 | ) | 73,695 | ||||||||||
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INCOME
TAX (EXPENSE) BENEFIT
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3,994 | (35,200 | ) | 74,769 | (26,056 | ) | ||||||||||
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NET
INCOME (LOSS)
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$ | (4,795 | ) | $ | 65,715 | $ | (136,357 | ) | $ | 47,639 | ||||||
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OTHER
COMPREHENSIVE INCOME (LOSS), NET OF TAXES:
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Increase
(decrease) in market value of investment in Pinnacle Gas Resources,
Inc.
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64 | (3,684 | ) | 179 | (5,228 | ) | ||||||||||
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Reclassification
of cumulative decrease in market value of investment in
Pinnacle
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Gas
Resources, Inc.
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- | - | 1,359 | - | ||||||||||||
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COMPREHENSIVE
INCOME (LOSS)
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$ | (4,731 | ) | $ | 62,031 | $ | (134,819 | ) | $ | 42,411 | ||||||
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BASIC
INCOME (LOSS) PER COMMON SHARE
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$ | (0.15 | ) | $ | 2.15 | $ | (4.40 | ) | $ | 1.59 | ||||||
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DILUTED
INCOME (LOSS) PER COMMON SHARE
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$ | (0.15 | ) | $ | 2.12 | $ | (4.40 | ) | $ | 1.56 | ||||||
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WEIGHTED
AVERAGE COMMON SHARES OUTSTANDING:
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BASIC
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31,053 | 30,531 | 30,980 | 30,005 | ||||||||||||
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DILUTED
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31,053 | 30,973 | 30,980 | 30,452 | ||||||||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
CARRIZO OIL & GAS, INC.
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(Unaudited)
(As
Adjusted (See Note 2))
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For
the Nine
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||||||||
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Months
Ended
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||||||||
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September
30,
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||||||||
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2009
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2008
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(In
thousands)
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CASH
FLOWS FROM OPERATING ACTIVITIES:
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Net
income (loss)
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$ | (136,357 | ) | $ | 47,639 | |||
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Adjustment
to reconcile net income (loss) to net cash provided by operating
activities-
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Depreciation,
depletion and amortization
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40,049 | 41,874 | ||||||
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Impairment
of oil and gas properties
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216,391 | - | ||||||
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Fair
value (gain) loss of derivative financial instruments
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38,519 | (13,933 | ) | |||||
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Accretion
of discounts on asset retirement obligations and debt
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225 | 173 | ||||||
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Stock-based
compensation
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8,514 | 4,547 | ||||||
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Provision
for allowance for doutbful accounts
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288 | (166 | ) | |||||
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Deferred
income taxes
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(74,834 | ) | 25,652 | |||||
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Loss
on extenguishment of debt
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- | 4,601 | ||||||
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Amortization
of equity premium associated with Convertible Senior Notes
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4,296 | 988 | ||||||
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Impairment
of investment in Pinnacle Gas Resources, Inc.
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2,091 | - | ||||||
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Other
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4,857 | 3,550 | ||||||
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Changes
in operating assets and liabilities
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Accounts
receivable
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3,158 | (1,394 | ) | |||||
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Other
assets
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(1,548 | ) | (3,015 | ) | ||||
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Accounts
payable
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(2,053 | ) | 6,847 | |||||
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Accrued
liabilities
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4,242 | 8,995 | ||||||
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Net
cash provided by operating activities
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107,838 | 126,358 | ||||||
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CASH
FLOWS FROM INVESTING ACTIVITIES:
|
||||||||
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Capital
expenditures
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(143,036 | ) | (456,696 | ) | ||||
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Change
in capital expenditure accrual
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(21,309 | ) | (1,573 | ) | ||||
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Proceeds
from the sale of properties
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6 | 2,280 | ||||||
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Advances
to operators
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12 | (83 | ) | |||||
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Advances
for joint operations
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1,859 | (453 | ) | |||||
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Other
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(69 | ) | (2,771 | ) | ||||
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Net
cash used in investing activities
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(162,537 | ) | (459,296 | ) | ||||
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CASH
FLOWS FROM FINANCING ACTIVITIES:
|
||||||||
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Net
proceeds from debt issuance and borrowings
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100,037 | 590,034 | ||||||
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Debt
repayments
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(43,886 | ) | (382,156 | ) | ||||
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Proceeds
from common stock offering, net of offering costs
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- | 135,077 | ||||||
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Proceeds
from stock options exercised
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9 | 240 | ||||||
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Deferred
loan costs and other
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(3,069 | ) | (9,260 | ) | ||||
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Net
cash provided by financing activities
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53,091 | 333,935 | ||||||
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NET
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
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(1,608 | ) | 997 | |||||
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CASH
AND CASH EQUIVALENTS, beginning of period
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5,184 | 8,026 | ||||||
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CASH
AND CASH EQUIVALENTS, end of period
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$ | 3,576 | $ | 9,023 | ||||
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CASH
PAID FOR INTEREST (NET OF AMOUNTS CAPITALIZED)
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$ | 2,659 | $ | 1,872 | ||||
The
accompanying notes are an integral part of these consolidated financial
statements.
CARRIZO OIL & GAS, INC.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
Principles
of Consolidation
The
consolidated financial statements are presented in accordance with U.S.
generally accepted accounting principles. The consolidated financial
statements include the accounts of the Company and its wholly-owned subsidiaries
after elimination of all significant intercompany transactions and
balances. The financial statements reflect necessary adjustments, all
of which were 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 presented 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/A for the year ended December 31, 2008.
Unconsolidated
Investments
The
Company accounts for its investment in Oxane Materials, Inc. using the cost
method of accounting and adjusts the carrying amount of its investment for
contributions to and distributions from the entity.
The
Company’s investment in Pinnacle Gas Resources, Inc. is classified as
available-for-sale. The Company adjusts the book value to fair market
value through other comprehensive income (loss), net of taxes. If the
impairment of the investment is considered other than temporary, the loss will
be reclassified to the Statements of Operations from Other Comprehensive
Income/Loss. Subsequent recoveries in fair value are reflected as increases to
the Investments line item and Other Comprehensive Income (Loss).
Reclassifications
Certain
reclassifications have been made to prior periods’ financial statements to
conform to the current presentation. These reclassifications had no
effect on total assets, total liabilities, shareholders’ equity or net income
(loss).
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 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, and also factor into the Company’s borrowing
base and evaluation of the recoverability of deferred tax assets, have numerous
inherent uncertainties. The accuracy of any reserve estimate is a
function of the quality and quantity of available data and the application of
engineering and geological interpretation and judgment to available
data. Subsequent drilling, 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 may be affected by 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
affected by changes to future economic conditions such as the market prices
received for sales of oil and natural gas volumes, interest rates, the market
value and volatility 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. In particular, the Company owns interests in
approximately 2,630 gross acres in the Camp Hill Field in Anderson
County, Texas, for which the Company reported approximately 8.2 MMBbls of proved
reserves, including 5.0 MMBbls of proved undeveloped reserves (which represents
approximately 6% of our total proved reserves) as of December 31, 2008. In
connection with an ongoing review by the SEC’s staff of the Company’s Annual
Report on Form 10-K for the year ended December 31, 2008, the staff has raised
various issues regarding the classification of some of these reserves as
proved. The Company’s position that the Camp Hill proved reserves met
the SEC’s definition of proved reserves continues to be subject to review.
In late
2008, the SEC adopted new rules regarding the classification of reserves that
will become effective for the Company as of year-end of 2009, which, among other
things, generally require proved undeveloped reserves to be developed within
five years, unless specific circumstances justify a longer time. As a
result of various factors, including these new rules and our discussions with
the SEC’s staff regarding their applicability to the Camp Hill Field, the
Company may be required under applicable SEC rules to reclassify as unproved
substantially all of our proved undeveloped reserves in the Camp Hill Field at
year-end 2009 because these reserves will not be developed within the next five
years. The Company may also be required under applicable SEC rules to
write-off or reclassify to proved undeveloped, a portion of our proved developed
reserves. This possible write-off of the reserves could significantly
impact depletion expense, ceiling test impairment and the realizability of the
net deferred tax asset.
The
Company evaluates its estimates and assumptions on an ongoing basis using
historical experience and other factors, including the current economic
environment, which the Company believes to be reasonable under the
circumstances. The Company adjusts such estimates and assumptions
when facts and circumstances dictate. The Company has evaluated
subsequent events for recording and disclosure through November 9, 2009 – see
Note 10.
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, including the
Company’s gas gathering systems, 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
employee-related costs for employees working directly on exploration activities
of $4.1 million and $5.2 million for the nine months ended September 30, 2009
and 2008, 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. Costs not subject to amortization include costs of
unevaluated leaseholds, seismic costs associated with specific unevaluated
properties and exploratory wells in progress. These costs 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 dismantlement,
restoration and abandonment costs, net of estimated salvage
values. The depletion rate per Mcfe for the quarters ended September
30, 2009 and 2008 was $1.50 and $2.24, 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. If net
capitalized costs exceed this limit, the excess is charged to
earnings. During the nine-month period ended September 30, 2009, the
Company incurred an impairment charge of $216.4 million ($138.0 million net of
tax). For the first quarter of 2009, the Company elected to use a
pricing date subsequent to the balance sheet date, as allowed by current SEC
guidelines, to measure the full cost ceiling test impairment. Using
prices as of May 6, 2009, the Company incurred an impairment charge of $216.4
million ($138.0 million net of tax). Had the Company used prices in
effect as of March 31, 2009, an impairment of $323.2 million ($206.1 million net
of tax) would have been recorded for the first quarter of 2009. The
option to use a pricing date subsequent to the balance sheet will no longer be
available to the Company starting December 31, 2009 due to the adoption of the
new oil and natural gas reporting requirements as described below under
“Recently Issued Accounting Pronouncements.”
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
Company paid less than $100,000 in income taxes during the nine months ended
September 30, 2009 and 2008.
Stock-Based
Compensation
The
Company issues restricted stock and stock options, including stock appreciation
rights (“SAR”), as compensation to employees, directors and certain
contractors. Restricted stock is measured at grant date fair value
and recorded as deferred compensation based on the average of the high and low
prices 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). Stock option
compensation, including SAR, is based on the grant-date fair value of the
options and is recognized over the vesting period.
The
Company recognized the following stock-based compensation expense for the three
and nine months ended September 30:
|
Three
Months
|
NineMonths
|
|||||||||||||||
|
Ended
September 30,
|
Ended
September 30,
|
|||||||||||||||
|
2009(1)
|
2008
|
2009(1)
|
2008
|
|||||||||||||
|
(In
millions)
|
||||||||||||||||
|
Stock
Option Expense
|
$ | 0.3 | $ | - | $ | 0.4 | $ | 0.2 | ||||||||
|
Restricted
Stock Expense
|
2.5 | 1.5 | 8.1 | 4.3 | ||||||||||||
|
Total
Stock-Based Compensation Expense
|
$ | 2.8 | $ | 1.5 | $ | 8.5 | $ | 4.5 | ||||||||
__________
|
(1)
|
In
2009, the Company issued stock-based awards that vested in less than six
months from grant date in lieu of annual and quarter cash
bonuses.
|
General
and Administrative Expenses
The
Company recognizes and classifies general and administrative expenses as
incurred and as required by accounting guidelines, including infrequent and/or
non-cash items. The table below identifies the non-cash and/or
unusual items included in general and administrative expenses:
|
Three
months ended
|
Nine months
ended
|
|||||||||||||||
|
September
30,
|
September
30,
|
|||||||||||||||
|
2009
|
2008
|
2009
|
2008
|
|||||||||||||
|
(In
millions)
|
||||||||||||||||
|
Stock-based
compensation
|
$ | 2.8 | $ | 1.5 | $ | 8.5 | $ | 4.5 | ||||||||
|
Non-cash
charitable contribution(1)
|
0.9 | - | 0.9 | - | ||||||||||||
|
Bad
debt expnse
|
- | - | 0.3 | (0.2 | ) | |||||||||||
| $ | 3.7 | $ | 1.5 | $ | 9.7 | $ | 4.3 | |||||||||
__________
|
(1)
|
During
the third quarter of 2009, the Company pledged $1.0 million to the
University of Texas at Arlington, of which it paid $0.1 million in
cash. The Company recognized the entire pledge in the period
incurred.
|
Derivative
Instruments
The
Company uses derivatives to manage price risk underlying its oil and natural gas
production. The Company also used derivatives to manage the variable
interest rate on its borrowings under the second lien credit facility, which was
terminated in May 2008.
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 are treated
as non-designated derivatives and the unrealized gain (loss) related to the
mark-to-market valuation is included in the Company’s earnings.
The
Company typically uses fixed-rate swaps, costless collars, puts and calls to
hedge its exposure to material changes in the price of oil and natural
gas.
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 at least 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,
|
|||||||||||||||
|
2009
|
2008
|
2009
|
2008
|
|||||||||||||
|
Cokinos
Natural Gas Company
|
10 | % | 11 | % | 10 | % | 11 | % | ||||||||
|
Crosstex
Energy Services, Ltd.
|
- | 10 | % | - | 11 | % | ||||||||||
|
DTE
Energy Trading, Inc.
|
48 | % | 37 | % | 53 | % | 36 | % | ||||||||
Earnings
Per Share
Supplemental
earnings per share information is provided below:
|
Three
Months
|
Nine
Months
|
|||||||||||||||
|
Ended
September 30,
|
Ended
September 30,
|
|||||||||||||||
|
2009
|
2008
|
2009
|
2008
|
|||||||||||||
|
(In
thousands, except
|
||||||||||||||||
|
per
share amounts)
|
||||||||||||||||
|
Net
income (loss)
|
$ | (4,795 | ) | $ | 65,715 | $ | (136,357 | ) | $ | 47,639 | ||||||
|
Average
common shares outstanding
|
||||||||||||||||
|
Weighted
average common shares outstanding(1)
|
31,053 | 30,531 | 30,980 | 30,005 | ||||||||||||
|
Stock
options and warrants
|
- | 442 | - | 447 | ||||||||||||
|
Diluted
weighted average common shares outstanding
|
31,053 | 30,973 | 30,980 | 30,452 | ||||||||||||
|
Net
income (loss) per common share(1)
|
||||||||||||||||
|
Basic
|
$ | (0.15 | ) | $ | 2.15 | $ | (4.40 | ) | $ | 1.59 | ||||||
|
Diluted
|
$ | (0.15 | ) | $ | 2.12 | $ | (4.40 | ) | $ | 1.56 | ||||||
__________
|
(1)
|
In
January 2009, the Company adopted and retroactively applied new accounting
guidelines associated with restricted stock and participating
securities. The Company determined that all of its shares of
restricted stock are participating securities and should be included in
the basic earnings per share calculation (see Note 2 for additional
details).
|
Basic
earnings per common share is based on the weighted average number of shares of
common stock (including restricted 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 did not include options to
purchase 893,837 shares in the calculation of dilutive shares for the three and
nine months ended September 30, 2009 due to the net loss reported in the
periods. Shares of common stock subject to issuance pursuant to the
conversion features of the 4.375% Convertible Senior Notes due 2028 (the
“Convertible Senior Notes”) did not have an effect on the calculation of
dilutive shares for the three and nine months ended September 30, 2009 and
2008.
Asset
Retirement Obligation
The
following table is a reconciliation of the asset retirement obligation
liability:
|
Nine
Months Ended
|
Year
Ended
|
|||||||
|
September
30,
|
December
31,
|
|||||||
|
|
2009
|
2008
|
||||||
|
|
(In
thousands)
|
|||||||
|
Asset
retirement obligation at beginning of year
|
$ | 6,503 | $ | 5,869 | ||||
|
Liabilities
incurred
|
239 | 1,004 | ||||||
|
Liabilities
settled
|
(12 | ) | (177 | ) | ||||
|
Accretion
expense
|
225 | 154 | ||||||
|
Revisions
to previous estimates
|
2,947 | (347 | ) | |||||
|
Asset
retirement obligation at end of year
|
$ | 9,902 | $ | 6,503 | ||||
The $2.9
million revision to previous estimates relates primarily to location clean up
costs in the Barnett Shale area.
Income
Taxes
Deferred
income taxes are recognized at each reporting period 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. The Company routinely assesses the realizability of its deferred
tax assets and considers future taxable income based upon the Company’s
estimated production of proved reserves at estimated future pricing in making
such assessments. If the Company concludes that it is more likely than not that
some portion or all of the deferred tax assets will not be realized under
accounting standards, the deferred tax assets are reduced by a valuation
allowance.
Recently
Adopted Accounting Pronouncements
On
January 1, 2009, the Company adopted new accounting guidelines related to
convertible debt instruments that may be settled in cash (including partial cash
settlement) upon conversion. Under the accounting guidelines, issuers
of convertible debt are required to separately account for the liability and
equity components in a manner that reflects the entity’s nonconvertible debt
borrowing rate when interest cost is recognized in subsequent
periods. The new accounting guidelines require retrospective
application to the terms of instruments as they existed for periods
presented. The Company retrospectively applied the accounting
guidelines to the Convertible Senior Notes. The Company valued the
conversion premium of the convertible debt at $64.2 million and accordingly
restated its balance sheet as of December 31, 2008 for the carrying value of
debt and equity and restated its results of operations for interest expense,
capitalized interest, and income taxes for the year ended December 31,
2008. See Note 2 for a discussion of the restatement related to the
adoption of this accounting pronouncement.
On
January 1, 2009, the Company adopted and retroactively applied new accounting
guidelines related to restricted stock and participating
securities. Under the new accounting treatment, unvested share-based
payment awards that contain non-forfeitable rights to dividends or dividend
equivalents, whether paid or unpaid, are participating securities and shall be
included in the computation of both basic and diluted earnings per
share. These new guidelines require retroactive application for all
periods presented. The Company determined that its restricted shares
of common stock are participating securities and applied the new accounting
treatment retrospectively to all periods presented. See Note 2 for a
discussion of the restatement related to the adoption of this accounting
pronouncement.
In March
2008, new guidance for derivative disclosures was issued and requires
transparency about the location and amounts of derivative instruments in an
entity’s financial statements, how derivative instruments and related hedged
items are accounted for, and how derivative instruments and related hedged items
affect an entity’s financial position, financial performance and cash
flows. The Company adopted these requirements effective January 1,
2009 and they did not have a significant effect on the Company’s consolidated
financial position, results of operations or cash flows.
In April
2009, additional guidance for estimating fair value was
finalized. The Company adopted this pronouncement effective June 30,
2009, and it had no material impact on the Company’s consolidated financial
statements.
In April
2009, guidance on the recognition of other-than-temporary impairments of
investments in debt securities was issued and provides new presentation and
disclosure requirements for other-than-temporary impairments of investments in
debt and equity
securities. The
Company adopted the requirements of this pronouncement effective June 30, 2009,
and it had no material impact on the Company’s consolidated financial
statements.
In April
2009, accounting rules were amended to require disclosure about fair value of
financial instruments in interim reporting periods, as well as in annual
financial statements. The Company adopted the requirements of this
pronouncement effective June 30, 2009, and included the additional disclosures
in the Company’s Notes to Consolidated Financial Statements.
In
May 2009, general standards of accounting for and disclosure of events that
occur after the balance sheet date but before financial statements are issued
were established to set forth (1) the period after the balance sheet date during
which management of a reporting entity should evaluate events or transactions
that may occur for potential recognition or disclosure in the financial
statements; (2) the circumstances under which an entity should recognize events
or transactions occurring after the balance sheet date in its financial
statements; and (3) the disclosures that an entity should make about events or
transactions that occurred after the balance sheet date. The Company
applied the requirement of this pronouncement effective June 30, 2009, and
included additional disclosures in the Company’s Notes to Consolidated Financial
Statements.
In
June 2009, the Financial Accounting Standards Board established the
Accounting Standards Codification (Codification), which became effective
July 1, 2009, as the single source of authoritative U.S. GAAP to be applied
by nongovernmental entities. Rules and interpretive releases of the SEC under
authority of federal securities laws are also sources of authoritative U.S. GAAP
for SEC registrants. All other accounting literature excluded from the
Codification will be considered nonauthoritative. The subsequent issuances of
new standards will be in the form of Accounting Standards Updates that will be
included in the Codification. Generally, the Codification is not expected to
change U.S. GAAP. The Company adopted the Codification effective
September 30, 2009 and updated its disclosure references
accordingly.
Recently
Issued Accounting Pronouncements
On
December 31, 2008, the SEC adopted major revisions to its rules governing oil
and gas company reporting requirements. These new rules will permit the use of
new technologies to determine proved reserves and allow companies to disclose
their probable and possible reserves to investors. The current rules limit
disclosure to only proved reserves. The new rules require companies to report
the independence and qualification of the person primarily responsible for the
preparation or audit of its reserve estimates, and to file reports when a third
party is relied upon to prepare or audit its reserves estimates. The new rules
also require that the net present value of oil and gas reserves reported and
used in the full cost ceiling test calculation be based upon an average price
for the prior 12-month period. The new oil and gas reporting requirements are
effective for annual reports on Form 10-K for fiscal years ending on or after
December 31, 2009, with early adoption not permitted. The Company is in the
process of assessing the impact of these new requirements on its financial
position, results of operations and financial disclosures. Changes in
reserve amounts could significantly impact depletion expense, ceiling test
impairment and recoverability of deferred tax assets. For more
information, see “Use of
Estimates,” discussed above.
|
2.
|
ADJUSTMENT
FOR IMPLEMENTATION OF NEW ACCOUNTING
PRONOUNCEMENT
|
On
January 1, 2009, the Company adopted new accounting guidelines related to
convertible debt instruments that may be settled in cash (including partial cash
settlement) upon conversion. Under these guidelines, issuers of
convertible debt are required to separately account for the liability and equity
components in a manner that reflects the entity’s nonconvertible debt borrowing
rate when interest cost is recognized in subsequent periods. The new
accounting treatment requires retrospective application to the terms of
instruments as they existed for periods presented. The retrospective
application of this accounting pronouncement affects the Company’s results of
operations for the periods during December 31, 2008 as it relates to the
Company’s Convertible Senior Notes.
On
January 1, 2009, the Company adopted and retroactively applied new accounting
guidelines related to restricted stock and participating
securities. Under the new accounting treatment, unvested share-based
payment awards that contain non-forfeitable rights to dividends or dividend
equivalents, whether paid or unpaid, are participating securities and will be
included in the computation of both basic and diluted earnings per
share. The Company determined that its restricted shares of common
stock are participating securities and applied this accounting treatment
retroactively to all periods presented.
The
following table sets forth the effect of the retrospective application of the
new accounting guidelines for convertible debt and unvested share-based payment
awards on certain previously reported items.
Consolidated
Statement of Income:
|
For
the three months
|
For
the nine months
|
|||||||||||||||
|
ended
September 30, 2008
|
ended
September 30, 2008
|
|||||||||||||||
|
Originally
|
As
|
Originally
|
As
|
|||||||||||||
|
Reported
|
Adjusted
|
Reported
|
Adjusted
|
|||||||||||||
|
(In
thousands, except per share amounts)
|
||||||||||||||||
|
Interest
expense
|
5,297 | 8,491 | 16,694 | 20,950 | ||||||||||||
|
Capitalized
interest
|
3,866 | 6,315 | 11,211 | 14,479 | ||||||||||||
|
Income
tax expense
|
35,461 | 35,200 | 26,402 | 26,056 | ||||||||||||
|
Net
income (loss)
|
66,199 | 65,715 | 48,281 | 47,639 | ||||||||||||
|
Basic
Income Per Share
|
$ | 2.18 | $ | 2.15 | $ | 1.62 | $ | 1.59 | ||||||||
|
Diluted
Income Per Share
|
$ | 2.14 | $ | 2.12 | $ | 1.59 | $ | 1.56 | ||||||||
|
Weighted
Average Common Shares Oustanding
|
||||||||||||||||
|
Basic
|
30,424 | 30,531 | 29,842 | 30,005 | ||||||||||||
|
Diluted
|
30,973 | 30,973 | 30,452 | 30,452 | ||||||||||||
|
3.
|
LONG-TERM
DEBT
|
Long-term
debt consisted of the following at September 30, 2009 and December 31,
2008:
|
September
30,
|
December
31,
|
|||||||
|
2009
|
2008
|
|||||||
|
(In
thousands)
|
||||||||
|
Convertible
Senior Notes
|
$ | 373,750 | $ | 373,750 | ||||
|
Unamortized
discount for Convertible Senior Notes
|
(48,197 | ) | (57,269 | ) | ||||
|
Senior
Secured Revolving Credit Facility
|
216,000 | 159,000 | ||||||
|
Other
|
308 | 480 | ||||||
| 541,861 | 475,961 | |||||||
|
Current
maturities
|
(148 | ) | (173 | ) | ||||
| $ | 541,713 | $ | 475,788 | |||||
Convertible
Senior Notes
In May
2008, the Company issued $373.8 million aggregate principal amount of the
Convertible Senior Notes. Interest is payable on June 1 and December
1 each year, commencing December 1, 2008. The notes will be convertible, using a
net share settlement process, into a combination of cash and Carrizo common
stock that entitles holders of the Convertible Senior Notes to receive cash up
to the principal amount ($1,000 per note) and common stock in respect of the
remainder, if any, of the Company’s conversion obligation in excess of such
principal amount.
The notes
are convertible into the Company’s common stock at a ratio of 9.9936 shares per
$1,000 principal amount of notes, equivalent to a conversion price of
approximately $100.06. This conversion rate is subject to adjustment upon
certain corporate events. In addition, if certain fundamental changes occur on
or before June 1, 2013, the Company will in some cases increase the conversion
rate for a holder electing to convert notes in connection with such fundamental
change; provided, that in no event will the total number of shares issuable upon
conversion of a note exceed 14.7406 per $1,000 principal amount of notes
(subject to adjustment in the same manner as the conversion rate).
Holders
may convert the notes only under the following conditions: (a) during any
calendar quarter if the last reported sale price of Carrizo common stock exceeds
130 percent of the conversion price for at least 20 trading days in a period of
30 consecutive trading days ending on the last trading day of the immediately
preceding calendar quarter, (b) during the five business days after any five
consecutive trading day period in which the trading price per $1,000 principal
amount of the notes is equal to or less than 97% of the conversion value of such
notes, (c) during specified periods if specified distributions to holders of
Carrizo common stock are made or
specified
corporate transactions occur, (d) prior to the close of business on the business
day preceding the redemption date if the notes are called for redemption or (e)
on or after June 30, 2028 and prior to the close of business on the business day
prior to the maturity date of June 1, 2028.
The
holders of the Convertible Senior Notes may require the Company to repurchase
the notes on June 1, 2013, 2018 and 2023, or upon a fundamental corporate change
at a repurchase price in cash equal to 100 percent of the principal amount of
the notes to be repurchased plus accrued and unpaid interest, if any. The
Company may redeem notes at any time on or after June 1, 2013 at a redemption
price equal to 100 percent of the principal amount of the notes to be redeemed
plus accrued and unpaid interest, if any.
The
Convertible Senior Notes are subject to customary non-financial covenants and
events of default, including a cross default under the Senior Credit Facility
(defined below), the occurrence and continuation of which could result in the
acceleration of amounts due under the Convertible Senior Notes.
The
Convertible Senior Notes are unsecured obligations of the Company and rank equal
to all future senior unsecured debt but rank second in priority to the Senior
Credit Facility.
In
accordance with the accounting guidelines for convertible debt, the Company
valued the Convertible Senior Notes at May 21, 2008, as $309.6 million of debt
and $64.2 million of equity representing the fair value of the conversion
premium. The resulting debt discount will be amortized to interest
expense through June 1, 2013, the first date on which the holders may require
the Company to repurchase the Convertible Senior Notes, and will result in an
effective interest rate of approximately 8% for the Convertible Senior
Notes.
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. The Senior Credit Facility provided 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 proved oil & gas assets and is
currently guaranteed by certain of the Company’s subsidiaries: CCBM,
Inc.; CLLR, Inc.; Carrizo (Marcellus), LLC; Carrizo Marcellus Holdings, Inc.;
Chama Pipeline Holding, LLC and Hondo Pipeline Inc.
In the
fourth quarter of 2008, the Company amended the Senior Credit Facility to, among
other things, (a) extend the maturity date to October 29, 2012; (b) change the
semi-annual borrowing base redetermination dates to March 31 and September 30;
and (c) replace JPMorgan Chase Bank with Guaranty Bank as the administrative
agent bank.
In April
2009, the Company amended the Senior Credit Facility to, among other things,
(a) adjust the maximum ratio of total net debt to Consolidated EBITDAX;
(b) modify the calculation of total net debt for purposes of determining
the ratio of total net debt to Consolidated EBITDAX to exclude the following
amounts, which represent a portion of the Convertible Senior Notes deemed to be
an equity component under the accounting guidelines related to convertible debt
that may be settled in cash (including partial cash settlement) upon
conversion: $51,252,980 during 2009, $38,874,756 during 2010,
$26,021,425 during 2011 and $12,674,753 during 2012 until the maturity date;
(c) add a new senior leverage ratio; (d) modify the interest rate
margins applicable to Eurodollar loans; (e) modify the interest rate
margins applicable to base rate loans; and (f) establish new procedures
governing the modification of swap agreements.
In May
2009, the Company amended the Senior Credit Facility to, among other things, (1)
replace Guaranty Bank with Wells Fargo Bank, N.A. as administrative agent, (2)
provide that the aggregate notional volume of oil and natural gas subject to
swap agreements may not exceed 80% of “forecasted production from proved
producing reserves,” (as that term is defined in the Senior Credit Facility),
for any month, (3) remove a provision that limited the maximum duration of swap
agreements permitted under the Senior Credit Facility to five years, and (4)
provide that the aggregate notional amount under interest rate swap agreements
may not exceed the amount of borrowings then outstanding under the Senior Credit
Facility. Also in April 2009, the Company amended the Senior Credit
Facility to increase the borrowing base to $290,000,000 and, in May 2009, the
total commitment of the lenders was increased from $250,000,000 to
$259,400,000. On June 5, 2009, the total commitment was increased by
$25,000,000 to $284,400,000 with the addition of a new lender to the bank
syndicate.
If the
outstanding principal balance of the revolving loans under the Senior Credit
Facility exceeds the borrowing base at any time, the Company has the option
within 30 days to take any of the following actions, either individually or in
combination: make a lump sum payment curing the deficiency, pledge additional
collateral sufficient in the lenders’ opinion to increase the borrowing base and
cure the deficiency or begin making equal monthly principal payments that will
cure the deficiency within the ensuing six-month period.
Those
payments would be in addition to any payments that may come due as a result of
the quarterly borrowing base reductions. Otherwise, any unpaid principal or
interest will be due at maturity.
The
annual interest rate on each base rate borrowing is (a) 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 (b) a margin between 1.00% and 2.00% (depending on the
then-current level of borrowing base usage), but such interest rate can never be
lower than the adjusted Daily LIBO rate on such day plus a margin between 2.25%
to 3.25% (depending on the current level of borrowing base usage). The interest
rate on each Eurodollar loan will be the adjusted daily LIBO rate plus a margin
between 2.25% to 3.25% (depending on the then-current level of borrowing base
usage). At September 30, 2009, the average interest rate for amounts outstanding
under the Senior Credit Facility was 3.3%.
The
Company is subject to certain covenants under the amended terms of the Senior
Credit Facility which include, but are not limited to, the maintenance of the
following financial ratios: (1) a minimum current ratio of 1.00 to 1.00; and (2)
a maximum total net debt to Consolidated EBITDAX (as defined in the Senior
Credit Facility) of (a) 4.25 to 1.00 for the quarter ending June 30,
2009, (b) 4.50 to 1.00 for the quarter ending September 30, 2009,
(c) 4.75 to 1.00 for each quarter ending on or after December 31, 2009
and on or before September 30, 2010, (d) 4.25 to 1.00 for the quarter
ending December 31, 2010, and (e) 4.00 to 1.00 for each quarter ending
on or after March 31, 2011; and (3) a maximum ratio of senior debt (which
excludes debt attributable to the Convertible Senior Notes) to Consolidated
EBITDAX of 2.25 to 1.00.
Although
the Company currently believes that it can comply with all of the financial
covenants with the business plan that it has put in place, the business plan is
based on a number of assumptions, the most important of which is a relatively
stable, natural gas price at economically sustainable levels. If the price that
the Company receives for our natural gas production deteriorates significantly
from current levels, it could lead to lower revenues, cash flow and earnings,
which in turn could lead to a default under certain financial covenants in the
Senior Credit Facility, including the financial covenants discussed above. In
order to provide a further margin of comfort with regards to these financial
covenants, the Company may seek to further reduce its capital and exploration
budget, sell non-strategic assets, opportunistically modify or increase its
natural gas hedges or approach the lenders under our Senior Credit Facility for
modifications of either or both of the financial covenants discussed above.
There can be no assurance that the Company will be able to successfully execute
any of these strategies, or if executed, that they will be sufficient to avoid a
default under our Senior Credit Facility if a precipitous decline in natural gas
prices were to occur in the future. The Senior Credit Facility also places
restrictions on indebtedness, dividends to shareholders, liens, investments,
mergers, acquisitions, asset dispositions, repurchase or redemption of our
common stock, speculative commodity transactions, transactions with affiliates
and other matters.
The
Senior Credit Facility is subject to customary events of default, the occurrence
and continuation of which could result in the acceleration of amounts due under
the facility by the agent or the lenders.
At
September 30, 2009, the Company had $216.0 million of borrowings outstanding
under the Senior Credit Facility and the amount available for borrowings was
$68.4 million.
|
4.
|
INVESTMENTS
|
Investments
consisted of the following at September 30, 2009 and December 31,
2008:
|
September
30,
|
December
31,
|
|||||||
|
2009
|
2008
|
|||||||
|
(In
thousands)
|
||||||||
|
Pinnacle
Gas Resources, Inc.
|
$ | 1,054 | $ | 751 | ||||
|
Oxane
Materials, Inc.
|
2,523 | 2,523 | ||||||
| $ | 3,577 | $ | 3,274 | |||||
Pinnacle
Gas Resources, Inc.
In 2003,
the Company and its wholly-owned subsidiary CCBM, Inc. 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”). As of September 30, 2009, the Company
owned 2,510,324 shares of Pinnacle common stock.
The
Company classifies the Pinnacle investment as available-for-sale and adjusts the
investment to fair value through other comprehensive income. At
September 30, 2009, the Company reported the fair value of the stock at $1.1
million (based on the closing price of Pinnacle’s common stock on September 30,
2009). At March 31, 2009, the market value of the Company’s
investment in Pinnacle had consistently remained below its original book basis
since October 2008. The Company determined that the impairment was
other than temporary, and accordingly, recorded an impairment expense of $2.1
million at March 31, 2009.
Oxane
Materials, Inc.
In May
2008, the Company entered into a strategic alliance agreement with Oxane
Materials, Inc. (“Oxane”) in connection with the development of a proppant
product to be used in the Company’s exploration and production
program. The Company contributed approximately $2.0 million to Oxane
in exchange for warrants to purchase Oxane common stock and for certain
exclusive use and preferential purchase rights with respect to the
proppant. The Company simultaneously invested an additional $500,000
in a convertible promissory note from Oxane. The convertible
promissory note accrued interest at a rate of 6% per annum. During
the fourth quarter of 2008, the Company converted the promissory note into
630,371 shares of Oxane preferred stock. The Company accounts for the
investment using the cost method.
|
5.
|
INCOME
TAXES
|
The
income tax expense (benefit) for the indicated periods was different than the
amount computed using the federal statutory rate (35%) for the following
reasons:
|
Three
Months Ended
|
Nine
Months Ended
|
|||||||||||||||
|
September
30,
|
September
30,
|
|||||||||||||||
|
2009
|
2008
|
2009
|
2008
|
|||||||||||||
|
Amount
computed using the statutory rate
|
$ | (3,076 | ) | $ | 35,320 | $ | (73,894 | ) | $ | 25,793 | ||||||
|
Increase
(decrease) in taxes resulting from:
|
||||||||||||||||
|
State
and local income taxes, net of federal effect
|
(109 | ) | 21 | (2,618 | ) | 399 | ||||||||||
|
Other(1)
|
(809 | ) | (141 | ) | 1,743 | (136 | ) | |||||||||
|
Total
income tax expense (benefit)
|
$ | (3,994 | ) | $ | 35,200 | $ | (74,769 | ) | $ | 26,056 | ||||||
__________
|
(1)
|
Includes
a tax benefit of $0.9 million and a tax expense of $1.7 million for the
three and nine months ended September 30, 2009, respectively, related to
prior period state income taxes that were not recorded. The
Company has concluded these amounts are not material to the current or
prior financial statements.
|
At September 30, 2009, the Company had a net deferred tax asset of $30.2 million. The Company has determined it is more likely than not that its deferred tax assets are fully realizable based on projections of future taxable income which included estimated production of proved reserves at estimated future pricing. No valuation allowance for the net asset is currently needed.
The
Company classifies interest and penalties associated with income taxes as
interest expense. At September 30, 2009, the Company had no material
uncertain tax positions and the tax years since 1999 remain 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 currently expect these matters
to have a material adverse effect on the operations or 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.
|
7.
|
SHAREHOLDERS’
EQUITY
|
The
following is a summary of changes in the Company’s common stock for the
nine-month periods ended September 30:
|
2009
|
2008
|
|||||||
|
(In
thousands)
|
||||||||
|
Shares
outstanding at January 1
|
30,860 | 28,009 | ||||||
|
Equity
offering
|
- | 2,588 | ||||||
|
Restricted
stock issued, net of forfeitures
|
179 | 98 | ||||||
|
Employee
stock options exercised
|
5 | 58 | ||||||
|
Common
stock issued for oil and gas properties
|
10 | - | ||||||
|
Common
stock repurchased and retired for tax withholding
obligation
|
- | (6 | ) | |||||
|
Shares
outstanding at September 30
|
31,054 | 30,747 | ||||||
In
February 2008, the Company completed an underwritten public offering of
2,587,500 shares of its common stock at a price of $54.50 per
share. The number of shares sold was approximately 9.2% of the
Company’s outstanding shares before the offering. The Company
received proceeds of approximately $135.1 million, net of expenses.
|
8.
|
DERIVATIVE
INSTRUMENTS
|
The
Company enters into swaps, options, collars and other derivative contracts to
manage price risks associated with a portion of anticipated future oil and
natural gas production. Under these agreements, payments are received
or made based on the differential between a fixed and a variable product price.
These agreements are settled in cash at termination, expiration or exchanged for
physical delivery contracts. The Company enters into the majority of its
derivative transactions with three counterparties and netting agreements are in
place with those counterparties. The Company does not obtain collateral to
support the agreements but monitors the financial viability of counterparties
and believes its credit risk is minimal on these transactions. In the event of
nonperformance, the Company would be exposed to price risk. The Company has some
risk of accounting loss since 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 financial instruments. The Company also
used interest rate swap agreements to manage the Company’s exposure to interest
rate fluctuations on borrowings under the Company’s second lien credit facility,
which was terminated in May 2008.
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 settlements of
derivative instruments are reported as net gain (loss) on derivatives, in other
income and expenses in the Consolidated Statements of Operations. For
the three and nine months ended September 30, 2009 and 2008, the Company
recorded the following related to its derivatives:
|
Three
Months
|
Nine
Months
|
|||||||||||||||
|
Ended
September 30,
|
Ended
September 30,
|
|||||||||||||||
|
2009
|
2008
|
2009
|
2008
|
|||||||||||||
|
(In
millions)
|
||||||||||||||||
|
Realized
gains (losses):
|
||||||||||||||||
|
Natural
gas and oil derivatives
|
$ | 18.7 | $ | 1.3 | $ | 64.3 | $ | (9.0 | ) | |||||||
|
Interest
rate swaps - Second Lien Debt Outstanding
|
- | - | - | (1.2 | ) | |||||||||||
|
Loss
on interest rate swap settlement related to
|
||||||||||||||||
|
Second
Lien Credit Facility
|
- | - | - | (3.3 | ) | |||||||||||
| 18.7 | 1.3 | 64.3 | (13.5 | ) | ||||||||||||
|
Unrealized
gains (losses):
|
||||||||||||||||
|
Natural
gas and oil derivatives
|
(20.7 | ) | 76.4 | (38.5 | ) | 10.4 | ||||||||||
|
Interest
rate swaps
|
- | - | - | 2.8 | ||||||||||||
| (20.7 | ) | 76.4 | (38.5 | ) | 13.2 | |||||||||||
|
Net
gain (loss) on derivatives
|
$ | (2.0 | ) | $ | 77.7 | $ | 25.8 | $ | (0.3 | ) | ||||||
At
September 30, 2009, the Company had the following outstanding derivative
positions:
|
Natural
Gas
|
Natural
Gas
|
|||||||||||||||||||
|
Swaps
|
Collars
|
|||||||||||||||||||
|
Average
|
Average
|
Average
|
||||||||||||||||||
|
Quarter
|
MMBtus(1)
|
Fixed
Price(2)
|
MMBtus(1)
|
Floor
Price(2)
|
Ceiling
Price(2)
|
|||||||||||||||
|
Fourth
Quarter 2009
|
3,680,000 | 5.58 | 2,576,000 | 7.17 | 8.90 | |||||||||||||||
|
First
Quarter 2010
|
3,150,000 | 5.45 | 1,620,000 | 7.92 | 9.63 | |||||||||||||||
|
Second
Quarter 2010
|
3,185,000 | 5.50 | 637,000 | 5.84 | 7.30 | |||||||||||||||
|
Third
Quarter 2010
|
1,840,000 | 5.57 | 1,104,000 | 6.07 | 7.62 | |||||||||||||||
|
Fourth
Quarter 2010
|
1,840,000 | 5.57 | 1,380,000 | 6.49 | 7.90 | |||||||||||||||
|
First
Quarter 2011
|
1,800,000 | 5.64 | 450,000 | 9.70 | 11.70 | |||||||||||||||
|
Second
Quarter 2011
|
1,820,000 | 5.64 | 455,000 | 8.25 | 10.25 | |||||||||||||||
|
Third
Quarter 2011
|
1,840,000 | 5.64 | 460,000 | 8.65 | 10.65 | |||||||||||||||
|
Fourth
Quarter 2011
|
1,840,000 | 5.64 | 460,000 | 8.85 | 10.85 | |||||||||||||||
|
First
Quarter 2012
|
910,000 | 5.88 | 455,000 | 9.55 | 11.55 | |||||||||||||||
|
Second
Quarter 2012
|
910,000 | 5.88 | 455,000 | 8.35 | 10.35 | |||||||||||||||
|
Third
Quarter 2012
|
920,000 | 5.88 | - | - | - | |||||||||||||||
|
Fourth
Quarter 2012
|
920,000 | 5.88 | - | - | - | |||||||||||||||
| 24,655,000 | 10,052,000 | |||||||||||||||||||
__________
|
(1)
|
During
2009, the Company entered into (i) a $5.35 put, a $6.20 long-call and an
$8.00 short-call with respect to a portion of the Company’s production
hedged with swaps (10,000 MMBtus per day) in 2011 and 2012 and (ii) a
$4.35 put, a $6.00 long-call and a $6.50 short-call with respect to a
portion of the Company’s production hedged with swaps (20,000 MMBtus per
day) for April through October of 2010. The table below
presents additional put positions the Company has entered into associated
with a portion of hedged volumes presented
above:
|
|
Quarter
|
MMBtus
|
Put
Price(2)
|
||||||
|
Fourth
Quarter 2009
|
1,530,000 | 2.39 | ||||||
|
Second
Quarter 2010
|
455,000 | 3.74 | ||||||
|
Third
Quarter 2010
|
920,000 | 4.31 | ||||||
|
Fourth
Quarter 2010
|
1,196,000 | 4.61 | ||||||
|
First
Quarter 2011
|
900,000 | 5.90 | ||||||
|
Second
Quarter 2011
|
910,000 | 5.90 | ||||||
|
Third
Quarter 2011
|
920,000 | 5.90 | ||||||
|
Fourth
Quarter 2011
|
920,000 | 5.90 | ||||||
|
First
Quarter 2012
|
455,000 | 6.80 | ||||||
|
Second
Quarter 2012
|
455,000 | 6.80 | ||||||
__________
|
(1)
|
Based
on Houston Ship Channel (“HSC”) and WAHA spot
prices.
|
At
September 30, 2009, approximately 53% of the Company’s open natural gas hedged
volumes were with Credit Suisse, and the remaining 47% were with Shell Energy
North America (US), L.P. In addition, the Company entered into put
options for 2,745,000 MMBtus with Calyon Credit Agricole CIB covering certain
production from October through December 2009 and January through December
2011.
The fair
value of the outstanding derivatives at September 30, 2009 and December 31, 2008
was a net asset of $0.2 million and $38.7 million, respectively.
|
9.
|
FAIR
VALUE MEASUREMENTS
|
Accounting
guidelines for measuring fair value establish a three-level valuation hierarchy
for disclosure of fair value measurements. The valuation hierarchy
categorizes assets and liabilities measured at fair value into one of three
different levels depending on the observability of the inputs employed in the
measurement. The three levels are defined as follows:
Level 1 –
Observable inputs such as quoted prices in active markets at the measurement
date for identical, unrestricted assets or liabilities.
Level 2 –
Other inputs that are observable directly or indirectly such as quoted prices in
markets that are not active, or inputs which are observable, either directly or
indirectly, for substantially the full term of the asset or
liability.
Level 3 –
Unobservable inputs for which there is little or no market data and which the
Company makes its own assumptions about how market participants would price the
assets and liabilities.
The
following table presents information about the Company’s assets and liabilities
measured at fair value on a recurring basis as of September 30, 2009, and
indicates the fair value hierarchy of the valuation techniques utilized by the
Company to determine such fair value:
|
Level
1
|
Level
2
|
Level
3
|
Total
|
|||||||||||||
|
(in
thousands)
|
||||||||||||||||
|
Assets:
|
||||||||||||||||
|
Investment
in Pinnacle Gas Resources, Inc.
|
$ | 1,054 | $ | - | $ | - | $ | 1,054 | ||||||||
|
Oil
and natural gas derivatives
|
- | 6,062 | - | 6,062 | ||||||||||||
|
Liabilities:
|
||||||||||||||||
|
Oil
and natural gas derivatives
|
- | (5,915 | ) | - | (5,915 | ) | ||||||||||
|
Total
|
$ | 1,054 | $ | 147 | $ | - | $ | 1,201 | ||||||||
Oil and
natural gas derivatives are valued by using valuation models that are primarily
industry-standard models that consider various inputs including: (a) quoted
forward prices for commodities, (b) time value, (c) volatility factors
and (d) current market and contractual prices for the underlying
instruments, as well as other relevant economic measures.
Fair
Value of Other Financial Instruments
The
Company’s other financial instruments consist of cash and cash equivalents,
accounts receivable, accounts payable and bank borrowings, including borrowings
under the Senior Credit Facility. The carrying amounts of cash and cash
equivalents, accounts receivable and accounts payable approximate fair value due
to the highly liquid nature of these short-term instruments. The fair values of
the bank and vendor borrowings approximate the carrying amounts as of September
30, 2009 and December 31, 2008, and were determined based upon interest rates
currently available to the Company for borrowings with similar
terms. The fair value of the Convertible Senior Notes at September
30, 2009 was estimated at approximately $303.7 million.
|
10.
|
SUBSEQUENT
EVENTS
|
In October 2009, the Company sold its Mansfield pipeline and gathering system in the Barnett Shale play for approximately $34.7 million, including a working capital adjustment of approximately $1.2 million. The net proceeds were used to reduce the debt outstanding under the Senior Credit Facility.
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/A for the year ended December 31, 2008 and the
unaudited financial statements included in this quarterly report.
General
Overview
Our third
quarter 2009 included revenues of $23.8 million and production of 8.2
Bcfe. The key drivers to our results for the three and nine months
ended September 30, 2009 included the following:
Drilling
program. Our success is largely dependent on the results of
our drilling program. During the nine months ended September 30,
2009, we drilled (1) 37 gross wells (26.4 net wells) in the Barnett Shale area
with an apparent success rate of 100%, (2) one of two gross (0.3 net) wells in
the Gulf Coast and (3) two gross (0.6 net) wells in the Marcellus
Shale. At September 30, 2009 we had an inventory of 42 gross wells
(31.6 net) in the Barnett Shale that have been drilled and are waiting on
hydraulic fracturing, completion or hook-up to sales.
Production. Our
third quarter 2009 production of 8.2 Bcfe, or 89.2 MMcfe/d was a 37% increase
from the third quarter 2008 production of 6.0 Bcfe, or 65.0
MMcfe/d. The third quarter 2009 production increased 4% from the
second quarter 2009 production of 7.9 Bcfe primarily due to new
production.
Commodity
prices. Our average natural gas price during the third quarter
of 2009 was $2.60 per Mcf (excluding the impact of our hedges), $6.17 per Mcf,
or 70%, lower than the price in the third quarter of 2008 and $0.47 per Mcf, or
15%, lower than the price in the second quarter of
2009.
Financial
flexibility. In April 2009, we improved our financial
flexibility through an amendment to our senior secured revolving credit facility
(the “Senior Credit Facility”) that (a) increased the maximum total debt
leverage ratio under the Senior Credit Facility through 2010 to as high as 4.75
to 1, (b) refined the definition of Net Debt in the leverage ratio to exclude a
portion of our 4.375% Senior Convertible Notes due 2028 (the “Senior Convertible
Notes”) (starting at $51 million in 2009) and (c) added a senior debt leverage
covenant with a maximum ratio of 2.25 to 1. In addition, the
borrowing base under the Senior Credit Facility was increased to $290 million
and, on June 5, 2009, the total commitments of the lenders were increased to
$284.4 million. See “Senior Credit Facility” for more
information. In October 2009, we sold certain of our pipeline
gathering systems in the Barnett Shale for approximately $34.7
million. The net proceeds from the sale of this pipeline system were
used to reduce the debt outstanding under the Senior Credit
Facility. See “Recent Events – Mansfield Pipeline Sale.”
Recent
Events
Camp
Hill Field Operational Update
Development
activities continued at our Camp Hill Field during the course of the third
quarter of 2009. Consistent with our prior disclosure in our Annual
Report on Form 10-K/A for the year-ended December 31, 2008, we have completed
the refurbishment of one steam generator for use in the field and continue to
refurbish two others. Over the last three months, eight injection and
seven production wells drilled in 2008 were completed and eight new steam lines
were laid to injection wells.
Steam
injection from one generator recommenced in the Camp Hill Field on September 14,
2009, with steam flowing into six newly completed injection wells in an area of
the field that has never been previously steam flooded, as well as in seven
existing patterns that were steamed on a pilot basis in the latter half of
2008. We expect to complete and connect 11 additional injector wells
to steam lines during the fourth quarter of 2009. Heavy oil production from the
Camp Hill Field for the month of August was 1,405 barrels, and we expect October
production to be approximately 1,800 barrels, with additional improvement in
production rates expected as the reservoir heats up in response to the
steaming.
Mansfield
Pipeline Sale
We sold
our Mansfield pipeline and gathering system in the Barnett Shale play to Delphi
Midstream Partners, LLC (“Delphi”) for net proceeds of $34.7 million, including
a working capital adjustment of approximately $1.2 million. Net
proceeds from the sale were used to reduce the debt outstanding under the Senior
Credit Facility. We constructed the Mansfield pipeline system to
gather and transport natural gas from our Southeast Tarrant County operating
area. The pipeline consists of 19 miles of 6, 8 and 10 inch diameter
pipe with a current maximum takeaway capacity of 70 MMcf/day. The
system also includes an associated compression/dehydration facility that was
included in the transaction. Over the 30 days preceding the date of
sale, the pipeline transported an average of 55 MMcf/day. We have
also entered into an agreement to continue to operate the Mansfield pipeline
system on Delphi’s behalf.
Northeast
Pennsylvania Alliance
We have
entered into an alliance with Delphi through which the parties have agreed to
cooperate in solving gathering and mid-stream pipeline related issues for our
Marcellus production in certain Northeast Pennsylvania counties including, among
others, Bradford, Susquehanna, Tioga, Wayne and Wyoming counties. We
have granted Delphi a right of first offer with respect to Northeast
Pennsylvania if we seek to find a third party to develop and construct a
gathering or intrastate pipeline and a right of first refusal with respect to
Wyoming County if a third party other than Delphi makes a development
proposal. This alliance will terminate on the earlier to occur of
October 19, 2014 or the date that Delphi invests $100 million to develop and
construct pipelines under the alliance.
Outlook
Our
outlook for 2009 remains challenging as near-term natural gas futures prices for
the remainder of 2009 remain low and possibly could decline further but the
outlook for our long-term future remains positive. Production growth,
preservation of liquidity and stable upward movement in commodity prices are key
to our future success. We believe the following measures will
continue to have a positive impact on our 2009 results:
|
·
|
We
plan to continue efforts to control capital costs. During the
first nine months of 2009, excluding capitalized interest and overhead, we
spent approximately $105 million of capital expenditures on our drilling
program and $21.1 million on leasehold and seismic
costs. Based upon our current outlook for operational
performance in the remainder of 2009, we have revised our 2009 capital and
exploration plan to approximately $155.0 million, which we currently
expect to fund through cash generated from our operations, cash available
under the Senior Credit Facility or from sales of assets, including our
Mansfield pipeline system. For a further discussion of our 2009
capital budget and funding strategy, see “Liquidity and Capital
Resources—2009 Capital Budget and Funding Strategy” and “Liquidity and
Capital Resources—Sources and Uses of
Cash.”
|
|
·
|
We
plan to continue the exploration and development activities in the
Marcellus Shale in the Northeastern United States, primarily through joint
ventures with ACP II Marcellus, LLC and with other industry
partners. Among other activities, we currently plan to drill
five gross (2.4 net) vertical wells in the Virginia and West Virginia
parts of the Marcellus Shale to test the prospectivity of that
area. In the later part of 2009, we started drilling two wells
in Pennsylvania and plan to drill a third well pending further seismic
data interpretation.
|
|
·
|
We
expect to continue to hedge production to limit our exposure to reductions
in natural gas prices. At September 30, 2009, we had hedged
approximately 34,707,000 MMBtus of natural gas production through
2012.
|
Results
of Operations
Three
Months Ended September 30, 2009,
Compared
to the Three Months Ended September 30, 2008
Revenues
from oil and natural gas production for the three months ended September 30,
2009 decreased 57% to $23.6 million from $55.4 million for the same period in
2008 due to declining oil and natural gas prices. Production volumes
for natural gas for the three months ended September 30, 2009 increased 39% to
7.9 Bcf from 5.7 Bcf for the same period in 2008. Average natural gas
prices, excluding the impact of our cash-settled derivatives comprised of a
$18.7 million and a $1.6 million gain for the quarters ended September 30, 2009
and 2008, respectively, decreased to $2.60 per Mcf in the third quarter of 2009
from $8.78 per Mcf in the same period in 2008. Average oil prices,
excluding the impact of our settled derivative loss of $0.3 million for the
quarter ended September 30, 2008, decreased 45% to $66.25 per barrel from
$120.09 per barrel in the same period in 2008. The increase in
natural gas production volume was due primarily to new production contributions
from Barnett Shale development.
The
following table summarizes production volumes, average sales prices (excluding
the impact of derivatives) and operating revenues for the three months ended
September 30, 2009 and 2008:
|
2009
Period
|
||||||||||||||||
|
Three
Months Ended
|
Compared
to 2008 Period
|
|||||||||||||||
|
September
30,
|
Increase
|
%
Increase
|
||||||||||||||
|
2009
|
2008
|
(Decrease)
|
(Decrease)
|
|||||||||||||
|
Production
volumes
|
||||||||||||||||
|
Oil
and condensate (MBbls)
|
44 | 43 | 1 | 1 | % | |||||||||||
|
Natural
gas (MMcf)
|
7,947 | 5,724 | 2,223 | 39 | % | |||||||||||
|
Average
sales prices
|
||||||||||||||||
|
Oil
and condensate (per Bbl)
|
$ | 66.25 | $ | 120.09 | $ | (53.84 | ) | (45 | )% | |||||||
|
Natural
gas (per Mcf)
|
2.60 | 8.78 | (6.18 | ) | (70 | )% | ||||||||||
|
Operating
revenues (In thousands)
|
||||||||||||||||
|
Oil
and condensate
|
$ | 2,886 | $ | 5,194 | $ | (2,308 | ) | (44 | )% | |||||||
|
Natural
gas
|
20,698 | 50,233 | (29,535 | ) | (59 | )% | ||||||||||
|
Other(1)
|
263 | 3,100 | (2,837 | ) | (92 | )% | ||||||||||
|
Total
Operating Revenues
|
$ | 23,847 | $ | 58,527 | $ | (34,680 | ) | (59 | )% | |||||||
__________
|
(1)
|
Includes
gathering income and third party gas sales that is also included as
third-party purchases in operating
expense.
|
Oil and
natural gas operating expenses for the three months ended September 30, 2009
decreased 50% to $5.2 million from $10.4 million for the same period in 2008,
primarily as a result of decreased transportation and other product costs of
$2.9 million mainly attributable to a change in pricing and transportation
contractual arrangements, a $1.3 million decrease in severance taxes associated
with decreased revenues and a decrease of $1.0 million due to a general decline
in oil field services.
Depreciation,
depletion and amortization (DD&A) expense for the three months ended
September 30, 2009 decreased 10% to $12.5 million ($1.53 per Mcfe) from $13.9
million ($2.33 per Mcfe) for the same period in 2008. This decrease
in DD&A was primarily due to a lower depletion rate resulting from
impairment charges that reduced the depletable full-cost pool in the fourth
quarter of 2008 and the first quarter of 2009, partially offset by increased
production.
General
and administrative expense increased to $7.6 million for the three months ended
September 30, 2009 from $5.8 million for the corresponding period in
2008. The increase was due primarily to an increase in non-cash,
stock-based compensation of $1.2 million as a result of additional compensation
awards. In addition, during the third quarter of 2009, we made the
first $100,000 cash payment of a $1.0 million pledge to establish a Carrizo Oil
& Gas, Inc. endowed scholarship fund at the University of Texas at Arlington
(“UTA”), a university which is located within the area of our significant
operations in the Barnett Shale. We
have the option to pay the remaining portion of this pledge in shares of our
common stock.
The net
loss on derivatives of $2.0 million in the third quarter of 2009 was comprised
of $20.7 million of unrealized mark-to-market loss on derivatives and $18.7
million of realized gain on net settled oil and natural gas
derivatives. The net gain on derivatives of $77.7 million in the
third quarter of 2008 was comprised of a $76.4 million net unrealized
mark-to-market gain on derivatives and a $1.3 million realized gain on
cash-settled derivatives.
Interest
expense and capitalized interest for the three months ended September 30, 2009
were $9.9 million and $5.0 million, respectively, as compared to $8.5 million
and $6.3 million for the same period in 2008 primarily attributable to an
increase of approximately $2.0 million in cash interest expense associated with
higher debt levels on the Senior Credit Facility.
Nine
Months Ended September 30, 2009,
Compared
to the Nine Months Ended September 30, 2008
Revenues
from oil and natural gas production for the nine months ended September 30, 2009
decreased 54% to $80.2 million from $173.7 million for the same period in 2008
due to declining oil and natural gas prices. Production volumes for
natural gas for the nine months ended September 30, 2009 increased 34% to 23.6
Bcf from 17.6 Bcf for the same period in 2008. Average natural gas
prices,
excluding
the impact of our settled derivatives gain of $61.5 million and loss of $7.9
million for the nine months ended September 30, 2009 and 2008, respectively,
decreased to $3.10 per Mcf for the nine months ended September 30, 2009 from
$8.98 per Mcf in the same period in 2008. Average oil prices,
excluding the impact of our settled derivative gain of $2.8 million and loss of
$1.1 million for the nine months ended September 30, 2009 and 2008,
respectively, decreased 52% to $54.08 per barrel from $112.19 per barrel in the
same period in 2008. The increase in natural gas production volume
was due primarily to new production in the Barnett Shale
development.
The
following table summarizes production volumes, average sales prices (excluding
the impact of derivatives) and operating revenues for the nine months ended
September 30, 2009 and 2008:
|
2009
Period
|
||||||||||||||||
|
Nine
Months Ended
|
Compared
to 2008 Period
|
|||||||||||||||
|
September
30,
|
Increase
|
%
Increase
|
||||||||||||||
|
2009
|
2008
|
(Decrease)
|
(Decrease)
|
|||||||||||||
|
Production
volumes
|
||||||||||||||||
|
Oil
and condensate (MBbls)
|
129 | 144 | (15 | ) | 11 | % | ||||||||||
|
Natural
gas (MMcf)
|
23,589 | 17,555 | 6,033 | 34 | % | |||||||||||
|
Average
sales prices
|
||||||||||||||||
|
Oil
and condensate (per Bbl)
|
$ | 54.08 | $ | 112.19 | $ | (58.11 | ) | (52 | )% | |||||||
|
Natural
gas (per Mcf)
|
3.10 | 8.98 | (5.88 | ) | (65 | )% | ||||||||||
|
Operating
revenues (In thousands)
|
||||||||||||||||
|
Oil
and condensate
|
$ | 6,952 | $ | 16,131 | $ | (9,179 | ) | (57 | )% | |||||||
|
Natural
gas
|
73,235 | 157,564 | (84,329 | ) | (54 | )% | ||||||||||
|
Other(1)
|
1,034 | 5,780 | (4,746 | ) | (82 | )% | ||||||||||
|
Total
Operating Revenues
|
$ | 81,221 | $ | 179,475 | $ | (98,254 | ) | (55 | )% | |||||||
__________
|
(1)
|
Includes
gathering income and third party gas sales that is also included as
third-party purchases in operating
expense.
|
Oil and
natural gas operating expense for the nine months ended September 30, 2009
decreased 19% to $22.8 million from $28