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 $28.0 million for the same period in 2008,
primarily as a result of decreased severance tax expense of $5.1 million
associated with refunds from certain wells that qualified for a tight-gas sands
tax credit for prior production periods and decreased revenues and increased
workover expenses of $0.4 million, partially offset by $0.8 million in decreased
transportation costs mainly attributable to a change in the pricing and
transportation contractual arrangements beginning in the third quarter of
2009.
Depreciation,
depletion and amortization (DD&A) expense for the nine months ended
September 30, 2009 decreased 4% to $40.0 million ($1.64 per Mcfe) from $41.9
million ($2.27 per Mcfe) for the same period in 2008. This decrease
in DD&A was primarily due to impairment charges in the fourth quarter of
2008 and the first quarter of 2009 that reduced the depletable full-cost pool,
partially offset by increased production.
The
significant decline in oil and natural gas prices since December 31, 2008,
indicated by average posted prices of $3.17 per Mcf for natural gas and $51.76
per Bbl for oil on May 6, 2009, caused the discounted present value (discounted
at ten percent) of future net cash flows from our proved oil and gas reserves to
fall below our net book basis in the proved oil and gas properties at March 31,
2009. This resulted in a non-cash, ceiling test write-down of $216.4
million ($138.0 million after tax).
General
and administrative expense for the nine months ended September 30, 2009
increased by $4.0 million to $21.9 million from $17.9 million for the
corresponding period in 2008 primarily as a result of an increase in non-cash,
stock-based compensation of $4.0 million as a result of additional deferred
compensation awards. In addition, 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 UTA, a university which is located within the area
of our significant operations in the Barnett Shale.
The net
gain on derivatives of $25.8 million in the first nine months of 2009 was
comprised of a $64.3 million realized gain on cash-settled oil and natural gas
derivatives and a $38.5 million of net unrealized mark-to-market loss on
derivatives. The net loss on derivatives of $0.4 million in the first
nine months of 2008 was comprised of $10.2 million of realized loss on net
settled derivatives,
$13.1
million of net unrealized mark-to-market gain on derivatives and $3.3 million of
realized loss on interest rate derivatives associated with the early termination
of the interest rate swaps.
In May
2008, we repaid our outstanding borrowings under the Second Lien Facility and
terminated the facility. As a result, we recorded a $5.7 million loss associated
with the early extinguishment of debt consisting of a $4.6 million non-cash
write-off of deferred loan costs and $1.1 million in penalties paid for early
retirement.
Interest
expense and capitalized interest for the nine months ended September 30, 2009
were $28.6 million and $15.1 million, respectively, as compared to $21.0 million
and $14.5 million for the same period in 2008 primarily attributable to an
increase of approximately $5.1 million in non-cash interest expense associated
with the amortization of the debt discount on the Senior Convertible Notes and
higher debt levels on the Senior Credit Facility.
Liquidity
and Capital Resources
2009 Capital Budget and Funding
Strategy. For 2009, management estimates a capital and exploration
expenditures plan (excluding capitalized overhead and interest) of approximately
$155 million including $130 million for our drilling program of which $125
million is designated for Barnett Shale drilling and development, and $10
million for our share of capital expenditures related to Marcellus Shale joint
venture. We intend to finance our 2009 capital and exploration budget
primarily from cash flows from operations, the possible selective sale or
monetization of non-core assets and available borrowings under the Senior Credit
Facility. We may be required to reduce or defer part of our 2009 capital
expenditures program if we are unable to obtain sufficient financing from these
sources.
Sources and Uses of Cash.
During the nine months ended September 30, 2009, capital expenditures,
net of proceeds from property sales, exceeded our net cash provided by
operations. During 2009, we have funded our capital expenditures with cash
generated from operations and net additional borrowings under the Senior Credit
Facility. Potential sources of future liquidity include the
following:
|
·
|
Cash
on hand and cash generated by operations. Cash flows from operations are
highly dependent on commodity prices and market conditions for oil and gas
field services. We hedge a portion of our production to reduce the
downside risk of declining natural gas and oil
prices.
|
|
·
|
Borrowings
under the Senior Credit Facility. At November 2, 2009, $89.0
million was available for borrowing under the Senior Credit
Facility. The next redetermination of our borrowing base is
currently scheduled to occur in November 2009. A negative
adjustment could occur if the estimate of future prices used by the banks
in calculating the borrowing base are significantly lower than those used
in the last redetermination which occurred earlier this
year.
|
|
·
|
Asset
sales. In order to fund our capital and exploration budget, we may
consider the sale of certain properties or assets that are not part of our
core business, can be monetized at a price we find acceptable, or are no
longer deemed essential to our future growth. To this end, in
October 2009, we completed the sale of our Mansfield pipelines and
gathering system located in the Barnett Shale play for approximately $34.7
million, including a working capital adjustment of approximately $1.2
million. The net proceeds from the sale were used to reduce the
debt outstanding under the Senior Credit Facility. We may
consider the sale of additional non-core assets including the possible
sale of our interest in the Huntington Field located in the North Sea,
provided that we can obtain an acceptable
price.
|
|
·
|
Debt
and equity offerings. As situations or conditions arise, we may need to
issue debt, equity or other instruments to supplement our cash flows.
However, we may not be able to obtain such financing on terms that are
acceptable to us, or at all.
|
|
·
|
Project
financing in certain limited
circumstances.
|
|
·
|
Lease
option agreements and land banking arrangements, such as those we have
entered into in the past regarding the Marcellus Shale, the Barnett Shale
and other plays.
|
|
·
|
Joint
ventures with third parties in the Marcellus Shale, the Barnett Shale and
other plays including those through which such third parties fund a
portion of our land acquisition and exploration activities to earn an
interest in our exploration acreage, such as our joint venture in the
Marcellus Shale play.
|
|
·
|
We
may consider sale/leaseback transactions of certain capital assets, such
as pipelines and compressors, which are not part of our core oil and gas
exploration and production
business.
|
Our
primary use of cash is capital expenditures to fund our drilling and development
programs and, to a lesser extent, our lease and seismic acquisition
programs. Our current 2009 capital expenditures plan provides for
approximately $130 million for drilling, and approximately $25 million for
leasing, land costs, seismic acquisitions and other capital
expenses. During the second quarter of 2009, our partner in the
Marcellus Shale joint venture completed its initial contribution of cash related
to the formation of the joint venture. At that point, we became
obligated to fund our share of the Marcellus joint venture costs and
expenses. We expect to pay approximately $5 million for our share of
the remaining Marcellus 2009 joint venture capital expenditure program,
primarily to drill wells in Virginia and West Virginia.
Overview of Cash Flow Activities.
Cash flows provided by operating activities were $107.8 million and
$126.4 million for the nine months ended September 30, 2009 and 2008,
respectively. The decrease was primarily due to declining natural gas
prices. Natural gas prices have fallen since the third quarter of
2008 and have continued to decline in 2009, having a negative impact on our cash
flow from operations and on our 2009 drilling plans. Despite our increase in
natural gas production, further decreases in natural gas prices could have a
further negative impact on our cash flow from operations and on our 2009
drilling plans.
Cash
flows used in investing activities were $162.5 million and $459.3 million for
the nine months ended September 30, 2009 and 2008, respectively, and related
primarily to oil and gas property expenditures.
Net cash
provided by financing activities for the nine months ended September 30, 2009
was $53.1 million and related primarily to net borrowings under the Senior
Credit Facility. Net cash provided by financing activities for the
nine months ended September 30, 2008 was $333.9 million and related primarily to
net proceeds of $135.1 million from the issuance of common stock in February
2008, net proceeds of $365.3 million in additional borrowings under the Senior
Convertible Notes and $214.0 million in additional borrowings under the Senior
Credit Facility. The cash proceeds were partially offset by the
payoff and termination of the Second Lien Credit Facility and partial paydown of
the Senior Credit Facility.
Liquidity/Cash Flow
Outlook.
We
currently believe that cash generated from operations, supplemented by
borrowings under the Senior Credit Facility and selected assets sales, will be
sufficient to fund our immediate needs. Cash generated from operations is
primarily driven by production and commodity prices. While we have steadily
increased production over the last few years, oil and natural gas prices have
declined since the levels reached in July 2008. In an effort to mitigate
declining prices, we hedge a portion of our production and, as of September 30,
2009, we had hedged approximately 6,256,000 MMBtus (74% of our estimated
production from October through December 2009) of our 2009 natural gas
production at a weighted average floor or swap price of $6.24 per MMBtu relative
to WAHA and HSC prices. $89.0 million was available to us at November 2, 2009
under the Senior Credit Facility.
If cash
from operations, the sale of material non-core assets, including our Mansfield
pipeline system, and funds available under the Senior Credit Facility are
insufficient to fund our 2009 capital and exploration budget, we may need to
reduce our capital and exploration budget or seek other financing alternatives
to fund it, including those described above. We may not be able to obtain
financing needed in the future on terms that would be acceptable to us, or at
all. If we cannot obtain adequate financing, we may be required to limit or
defer our planned 2009 natural gas and oil exploration and development program,
thereby adversely affecting the recoverability and ultimate value of our natural
gas and oil properties. The recent worldwide financial and credit crisis has
adversely affected our ability to access the capital markets.
Contractual
Obligations
In 2009,
we entered into a two-year and one-year term lease agreements for compressor
rentals with an estimated obligation of approximately $2.4 million and $0.5
million, respectively. Effective October 19, 2009, these lease
agreements were conveyed along with entities owning the Mansfield pipeline
system to Delphi. See “Recent Events – Mansfield Pipeline
Sale,”
Financing
Arrangements
Senior
Credit Facility
In April
2009, we amended the Senior Credit Facility to, among other things,
(1) adjust the maximum ratio of total net debt to Consolidated EBITDAX to a
maximum ratio 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; (2) 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 APB 14-1: $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; (3) add a new senior leverage ratio, which
requires that our ratio of senior debt (which excludes debt attributable to the
Convertible Senior Notes) to Consolidated EBITDAX not exceed 2.25 to 1.00;
(4) modify the interest rate margins applicable to Eurodollar loans to a
range of between 2.25% and 3.25% (depending on the then-current level of
borrowing base usage); (5) modify the interest rate margins applicable to
base rate loans to a range of between 1.00% and 2.00% (depending on the
then-current level of borrowing base usage); and (6) establish new
procedures governing the modification of swap agreements.
In May
2009, we 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.
As of
November 2, 2009, we had $195.4 million of borrowings outstanding and a
borrowing base availability of $89.0 million. The next borrowing base
redetermination is scheduled for November 2009.
Effects
of Inflation and Changes in Price
Our
results of operations and cash flows are affected by changing natural gas and
oil prices. The drop in natural gas and oil prices since the third quarter of
2008 has resulted in a significant drop in revenue per unit of production.
Although operating costs have also declined, the rate of decline in natural gas
and oil prices has been substantially greater. Historically, inflation has had a
minimal effect on us. However, with interest rates at historic lows and the
government attempting to stimulate the economy through rapid expansion of the
money supply in recent months, inflation could become a significant issue in the
future.
Recently
Adopted Accounting Pronouncements
On
January 1, 2009, we 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. We applied this
accounting pronouncement to the Convertible Senior Notes. We valued
the conversion premium of the convertible debt at $64.2 million and accordingly
restated our balance sheet as of December 31, 2008 for the carrying value of
debt and equity and restated our results of operations for interest expense,
capitalized interest, and income taxes for the year ended December 31,
2008. See Item 1, Notes to Consolidated Financial Statements, Note 2
for a discussion of the restatement related to the adoption of this accounting
pronouncement.
On
January 1, 2009, we 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. We
determined that our restricted shares of common stock are participating
securities and applied the new accounting treatment retroactively to all periods
presented. See Item 1, Notes to Consolidated Financial Statements,
Note 2 for a discussion of the restatement related to the adoption of this
accounting pronouncement.
In March
2008, new guidance for derivative disclosure 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. We adopted this pronouncement effective January 1, 2009 and
they did not have a significant effect on our consolidated financial position,
results of operations or cash flows.
In April
2009, additional guidance for estimating fair value was finalized. We
adopted this pronouncement effective June 30, 2009, and it had no material
impact on our 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. We adopted the requirements of this
pronouncement effective June 30, 2009, and it had no material impact on our
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. We adopted the requirements of
this pronouncement effective June 30, 2009 and included additional disclosures
in our Notes to Consolidated Financial Statement.
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. We
applied the requirement of this pronouncement effective June 30, 2009 and
included additional disclosures in our 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, to become the single source of authoritative U.S. GAAP
recognized by the FASB to be applied by nongovernmental entities. Rules and
interpretive releases of the SEC under authority of federal securities laws are
also sources of authoritative 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. We adopted the
Codification effective September 30, 2009 and updated disclosures.
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 permit the use of new
technologies to determine proved reserves and that 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. We are in the
process of assessing the impact of these new requirements on our financial
position, results of operations and financial disclosures. For more
information, please read Part II, Item 1A. “Risk Factors ─ As a result of an
ongoing SEC staff review, we may be required to reclassify or write-off
reserves.”
Critical
Accounting Policies
The
following summarizes our critical accounting policies:
Oil
and Natural Gas Properties
We
account for investments in natural gas and oil properties using the full-cost
method of accounting. All costs directly associated with the
acquisition, exploration and development of natural gas and oil properties are
capitalized. These costs include lease acquisitions, seismic surveys,
and drilling and completion equipment. We proportionally consolidate
our interests in natural gas and oil properties. We capitalized
compensation costs for employees working directly on exploration activities of
$4.1 million and $5.2 million for the nine months ended September 30, 2009 and
2008, respectively. We expense maintenance and repairs as they are
incurred.
We
amortize natural gas and oil properties based on the unit-of-production method
using estimates of proved reserve quantities. Costs not subject to
amortization includes costs of unevaluated leaseholds, seismic costs associated
with specific unevaluated properties and wells in progress. These
costs are periodically evaluated on a property-by-property basis for
impairment. If the results of an assessment indicate that the
properties are impaired, we add the amount of impairment to the proved natural
gas and oil property costs to be amortized. The amortizable base
includes estimated future development costs and, where significant,
dismantlement, restoration
and
abandonment costs, net of estimated salvage values. The depletion
rate per Mcfe for the three months ended September 30, 2009 and 2008 was $1.50
and $2.24, respectively.
We
account for dispositions of natural gas and oil properties as adjustments to
capitalized costs with no gain or loss recognized, unless such adjustments would
significantly alter the relationship between capitalized costs and proved
reserves. We have not had any transactions that significantly alter
that relationship.
Net
capitalized costs of proved oil and natural gas properties are limited to a
“ceiling test” based on the estimated future net revenues, discounted at 10% per
annum, from proved oil and natural gas reserves based on current economic and
operating conditions (“Full Cost Ceiling”). If net capitalized costs
exceed this limit, the excess is charged to earnings.
The Full
Cost Ceiling test cushion at September 30, 2009 of $5.1 million was based upon
average realized oil, natural gas liquids and natural gas prices of $66.03 per
Bbl, $31.69 per Bbl and $3.26 per Mcf, respectively, or a volume weighted
average price of $26.28 per BOE. This cushion, however, would have
been zero at such date at an estimated volume weighted average price of $26.12
per BOE. A BOE means one barrel of oil equivalent, determined using
the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas
liquids, which approximates the relative energy content of oil, condensate and
natural gas liquids as compared to natural gas. In connection with
our September 30, 2009 Full Cost Ceiling test computation, a price sensitivity
study also indicated that a 10% increase in commodity prices at September 30,
2009 would have increased the Full Cost Ceiling test cushion by approximately
$85.9 million and a 10% decrease in commodity prices would have resulted in a
$80.4 million ceiling test impairment. The aforementioned price
sensitivity is as of September 30, 2009 and, accordingly, does not include any
potential changes in reserve values due to subsequent performance or events,
such as commodity prices, reserve revisions and drilling
results. Prices have historically been higher or substantially
higher, more often for oil than natural gas on an energy equivalent basis,
although there have been periods in which they have been lower or substantially
lower.
Under the
full cost method of accounting, the depletion rate is the current period
production as a percentage of the total proved reserves. Total proved
reserves include both proved developed and proved undeveloped
reserves. The depletion rate is applied to the net book value of our
oil and natural gas properties, excluding the costs not subject to amortization
as discussed above, plus estimated future development costs and salvage value,
to calculate the depletion expense. Proved reserves materially impact
depletion expense. If the proved reserves decline, then the depletion
rate (the rate at which we record depletion expense) increases, reducing net
income.
We have a
significant amount of proved undeveloped reserves. We had 239.1 Bcfe
of proved undeveloped reserves at December 31, 2008, representing 48% of our
total proved reserves. As of December 31, 2008, a portion of these
proved undeveloped reserves, or approximately 29.9 Bcfe, were attributable to
our Camp Hill properties that we acquired in 1994. The estimated
future development costs to develop our proved undeveloped reserves on our Camp
Hill properties are relatively low, on a per Mcfe basis, when compared to the
estimated future development costs to develop our proved undeveloped reserves on
our other oil and natural gas properties. Furthermore, the average
depletable life (the estimated time that it will take to produce all recoverable
reserves) of our Camp Hill properties is considerably longer, or approximately
15 years, when compared to the depletable life of our remaining oil and natural
gas properties of approximately 10 years. Accordingly, the
combination of a relatively low ratio of future development costs and a
relatively long depletable life on our Camp Hill properties has resulted in a
relatively low overall historical depletion rate and DD&A
expense. This has resulted in a capitalized cost basis associated
with producing properties being depleted over a longer period than the
associated production and revenue stream, causing the build-up of nondepleted
capitalized costs associated with properties that have been completely
depleted. This combination of factors, in turn, has had a favorable
impact on our earnings, which have been higher than they would have been had the
Camp Hill properties not resulted in a relatively low overall depletion rate and
DD&A expense and longer depletion period. As a hypothetical
illustration of this impact, the removal of our Camp Hill proved undeveloped
reserves starting January 1, 2002 and through December 31, 2008 would have
reduced our earnings by (a) an estimated $11.2 million in 2002 (comprised of
after-tax charges for a $7.1 million full cost ceiling impairment and a $4.1
million depletion expense increase), (b) an estimated $5.9 million in 2003 (due
to higher depletion expense), (c) an estimated $3.4 million in 2004 (due to
higher depletion expense), (d) an estimated $6.9 million in 2005 (due to higher
depletion expense), (e) an estimated $0.7 million in 2006 (due to higher
depletion expense), (f) an estimated $2.0 million in 2007 (due to higher
depletion expense), and (g) an estimated $9.2 million in 2008 (comprised of
after tax charges for an $8.5 million full cost ceiling test impairment and a
$0.7 million depletion expense increase).
We expect
our relatively low historical depletion rate to continue until the high level of
nonproducing reserves to total proved reserves is reduced and the life of our
proved developed reserves is extended through development drilling and/or the
significant addition of new proved producing reserves through acquisition or
exploration. If our level of total proved reserves, finding costs and
current prices were all to remain constant, this continued build-up of
capitalized cost increases the probability of a ceiling test write-down in the
future. Additionally, a removal of nonproducing reserves could
significantly affect this depletion rate as well as increase the chance of a
non-cash ceiling test impairment and the realizability of the net deferred tax
asset. Please read Part II, Item 1A. “Risk
Factors ─
As a result of an ongoing SEC staff review, we may be required to reclassify or
write-off reserves” and “─ Our reserve data and estimated discounted future net
cash flows are estimates based on assumptions that may be inaccurate and are
based on existing economic and operating conditions that may change in the
future.”
We
depreciate other property and equipment using the straight-line method based on
estimated useful lives ranging from five to ten years.
Income
Taxes
Under
accounting guidelines for income taxes, deferred income taxes are recognized at
each year end for the future tax consequences of differences between the tax
bases of assets and liabilities and their financial reporting amounts based on
tax laws and statutory tax rates applicable to the periods in which the
differences are expected to affect taxable income. We routinely assess the
realizability of our deferred tax assets based upon our estimated production of
proved reserves at estimated future pricing. We consider future taxable income
in making such assessments. If we conclude that it is more likely than not that
some portion or all of the deferred tax assets will not be realized under
accounting standards, it is reduced by a valuation allowance. However, despite
our attempt to make an accurate estimate, the ultimate utilization of our
deferred tax assets is highly dependent upon our actual production and the
realization of taxable income in future periods.
For
information regarding our other critical accounting policies, see our Annual
Report on Form 10-K/A for the year ended December 31, 2008.
Volatility
of Oil and Natural Gas Prices
Our
revenues, future rate of growth, results of operations, financial condition and
ability to borrow funds or obtain additional capital, as well as the carrying
value of our properties, are substantially dependent upon prevailing prices of
oil and natural gas.
We
periodically review the carrying value of our oil and natural gas properties
under the full cost method of accounting rules. See “—Critical Accounting
Policies—Oil and Natural Gas Properties.”
To
mitigate some of our commodity price risk, we engage periodically in certain
other limited derivative activities including price swaps, costless collars and,
occasionally, put and call options, in order to establish some price floor
protection.
The
following table includes oil and natural gas positions settled during the three
and nine-month periods ended September 30, 2009 and 2008, and the unrealized
gain/(loss) associated with the outstanding oil and natural gas derivatives at
September 30, 2009 and 2008.
|
Three
Months Ended
|
Nine
Months Ended
|
|||||||||||||||
|
September
30,
|
September
30,
|
|||||||||||||||
|
2009
|
2008
|
2009
|
2008
|
|||||||||||||
|
Oil
positions settled (Bbls)
|
- | 18,400 | 5,900 | 45,700 | ||||||||||||
|
Natural
gas positions settled (MMBtus)
|
6,256,000 | 3,312,000 | 19,934,000 | 11,026,000 | ||||||||||||
|
Realized
gain/(loss) ($ millions) (1)
|
$ | 18.7 | $ | 1.3 | $ | 64.3 | $ | (9.0 | ) | |||||||
|
Unrealized
gain/(loss) ($ millions) (1)
|
$ | (20.7 | ) | $ | 76.4 | $ | (38.5 | ) | $ | 10.4 | ||||||
__________
(1)
Included in net gain (loss) on derivatives in the Consolidated Statements of
Operations.
At
September 30, 2009, we had the following outstanding natural gas 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.
While the
use of hedging arrangements limits the downside risk of adverse price movements,
it may also limit our ability to benefit from increases in the prices of natural
gas and oil. We enter into the majority of our derivatives
transactions with two counterparties and have a netting agreement in place with
those counterparties. We do not obtain collateral to support the
agreements but monitor the financial viability of counterparties and believe our
credit risk is minimal on these transactions. Under these
arrangements, payments are received or made based on the differential between a
fixed and a variable commodity price. These agreements are
settled
in cash at expiration or exchanged for physical delivery
contracts. In the event of nonperformance, we would be exposed again
to price risk. We have additional risk of financial loss because the
price received for the product at the actual physical delivery point may differ
from the prevailing price at the delivery point required for settlement of the
hedging transaction. Moreover, our derivatives arrangements generally
do not apply to all of our production and thus provide only partial price
protection against declines in commodity prices. We expect that the
amount of our hedges will vary from time to time.
Our
natural gas derivative transactions are generally settled based upon the average
of the reported settlement prices on the HSC or WAHA indices for the last three
trading days of a particular contract month. Our oil derivative
transactions are generally settled based on the average reported settlement
prices on the West Texas Intermediate index for each trading day of a particular
calendar month.
Forward
Looking Statements
The
statements contained in all parts of this document, including, but not limited
to, those relating to the Company’s or management’s intentions, beliefs,
expectations, hopes, projections, assessment of risks, estimations, plans or
predictions for the future, including our schedule, targets, estimates or
results of future drilling, including the number, timing and results of wells,
budgeted wells, increases in wells, the timing and risk involved in drilling
follow-up wells, expected working or net revenue interests, planned
expenditures, prospects budgeted and other future capital expenditures, efforts
to control capital costs, risk profile of oil and natural gas exploration,
acquisition of 3-D seismic data (including number, timing and size of projects),
planned evaluation of prospects, probability of prospects having oil and natural
gas, expected production or reserves, increases in reserves, acreage, working
capital requirements, hedging activities, credit risk of hedging counterparties,
the ability of expected sources of liquidity to implement the Company’s business
strategy, future exploration activity, production rates, 2009 drilling program,
growth in production, development of new drilling programs, hedging of
production and exploration and development expenditures, Camp Hill reserves
development and production, borrowing base redeterminations under the Senior
Credit Facility, fair value of our investment in Pinnacle, the results of the
SEC’s staff’s review of our filings, the impact of new SEC rules regarding oil
and gas reserves, the results of the alliance with Delphi and all and any other
statements regarding future operations, financial results, business plans and
cash needs, and other statements that are not historical facts are forward
looking statements. When used in this document, the words
“anticipate,” “estimate,” “expect,” “may,” “project,” “believe” and similar
expressions are intended to be among the statements that identify forward
looking statements. Such statements involve risks and uncertainties,
including, but not limited to, those relating to our dependence on exploratory
drilling activities, the volatility of oil and natural gas prices, the need to
replace reserves depleted by production, operating risks of oil and natural gas
operations, our dependence on our key personnel, factors that affect our ability
to manage our growth and achieve our business strategy, results, delays and
uncertainties that may be encountered in drilling, development or production,
outcome of the SEC’s staff’s review of our filings, interpretations and impact
of new SEC rules regarding oil and gas reserves, activities and approvals of our
partners and parties with whom we have alliances, technological changes,
significant capital requirements, borrowing base determinations and availability
under the Senior Credit Facility, evaluations of the Company by potential
lenders under the Senior Credit Facility, results of operation of Pinnacle, the
potential impact of government regulations, including proposed legislation and
adverse regulatory determinations, litigation, competition, the uncertainty of
reserve information and future net revenue estimates, property acquisition
risks, availability of equipment, weather, availability of financing, actions by
lenders, ability to obtain permits, the results of audits and assessments, and
other factors detailed in the “Risk Factors” and other sections of our Annual
Report on Form 10-K/A for the year ended December 31, 2008 and in this and our
other filings with the SEC. Should one or more of these risks or
uncertainties materialize, or should underlying assumptions prove incorrect,
actual outcomes may vary materially from those indicated. All
subsequent written and oral forward-looking statements attributable to us or
persons acting on our behalf are expressly qualified in their entirety by
reference to these risks and uncertainties. You should not place
undue reliance on forward-looking statements. Each forward-looking
statement speaks only as of the date of the particular statement and we
undertake no obligation to update or revise any forward-looking
statement.
ITEM 3 - QUANTITATIVE AND
QUALITATIVE DISCLOSURES ABOUT MARKET RISK
For
information regarding our exposure to certain market risks, see “Quantitative
and Qualitative Disclosures about Market Risk” in Item 7A of our Annual Report
on Form 10-K/A for the year ended December 31, 2008. There have been
no material changes to the disclosure regarding our exposure to certain market
risks made in our Annual Report on Form 10-K/A for the year ended December 31,
2008. For additional information regarding our long-term debt, see
Note 3 of the Notes to Consolidated Financial Statements (Unaudited) in Item 1
of Part I of this Quarterly Report on Form 10-Q.
ITEM 4 - CONTROLS AND
PROCEDURES
Evaluation of Disclosure
Controls and Procedures. Our Chief Executive Officer and Chief
Financial Officer performed an evaluation of our disclosure controls and
procedures, which have been designed to provide reasonable assurance that the
information required to be disclosed by the Company in the reports it files or
submits under the Exchange Act is accumulated and communicated to the Company's
management, including our Chief Executive Officer and Chief Financial Officer,
to allow timely decisions regarding required disclosure. As described
in more detail in our Form10-K/A filed on August 17, 2009, we identified a
material weakness in our internal controls over financial reporting (as defined
in Exchange Act Rules 13a-15(f) and 15d-15(f) in connection with further review
of our ceiling test impairments as of December 31, 2008 and March 31,
2009. We have implemented a number of initiatives, as discussed
below, designed to remediate the material weakness. Based upon these
changes and the evaluation of disclosure controls and procedures, our Chief
Executive Officer and Chief Financial Officer have concluded that the controls
were effective as of September 30, 2009 to provide reasonable assurance that the
information required to be disclosed by us in the reports that we file or submit
to the SEC under the Exchange Act, is recorded, processed, summarized and
reported within the time periods specified by the SEC’s rules and forms and that
such information is accumulated and communicated to our management, including
our Chief Executive Officer and Chief Financial Officer , as appropriate to
allow timely decisions regarding required disclosure.
Changes in Internal
Controls. As described in more detail in our Annual Report on
Form 10-K/A for the year ended December 31, 2008, our Quarterly Report on Form
10-Q/A for the quarter ended March 31, 2009 and our Quarterly Report on Form
10-Q for the quarter ended June 30, 2009, we identified material weaknesses in
our internal control over financial reporting and described a number of planned
procedures designed to remediate these weaknesses. The following
initiatives were effected in the quarter ended September 30,
2009: (1) delegated preparation of certain critical workpapers to our
financial reporting staff allowing our financial reporting manager to perform
more qualitative review analysis, (2) removed the computational deficiencies
from our standard ceiling test workpaper format, (3) improved workpaper formats
and implement comparative analysis within these critical workpapers to enhance
qualitative analysis and (4) prepared a reconciliation of the quarter-to-quarter
changes in costs associated with unevaluated property and proved undeveloped
locations that will be used to determine the reclassification of costs to the
full cost pool.
This Item
4 should be read in conjunction with Part II, Item 9A in our Annual Report on
Form 10-K/A for the year ended December 31, 2008, Part II, Item 4 in our
Quarterly Report on Form 10-Q/A for the quarter ended March 31, 2009 and Part
II, Item 4 in our Quarterly Report on Form 10-Q for the quarter ended June 30,
2009.
PART II. OTHER INFORMATION
Item 1 -
Legal Proceedings
From time to time, the Company is party
to certain legal actions and claims arising in the ordinary course of
business. While the outcome of these events cannot be predicted with
certainty, management does not expect these matters to have a materially adverse
effect on the financial position or results of operations of the
Company.
Item 1A –
Risk Factors
In
addition to the risk factor set forth below and the other information set forth
in this report, you should carefully consider the factors discussed in Part I,
“Item 1A. Risk Factors” in our Annual Report on Form 10-K/A for the year ended
December 31, 2008, which could materially affect our business, financial
condition or future results. Additional risks and uncertainties not
currently known to us or that we currently deem to be immaterial also may
materially adversely affect our business, financial condition and/or operating
results.
The
global financial and credit crisis may have impacts on our liquidity and
financial condition that we currently cannot predict.
The
continued credit crisis and related turmoil in the global financial system may
have a material impact on our liquidity and our financial condition, and we may
ultimately face major challenges if conditions in the financial markets do not
continue to improve from their lows in early 2009. Our ability to access the
capital markets or borrow money may be restricted or made more expensive at a
time when we would like, or need, to raise capital, which could have an adverse
impact on our flexibility to react to changing economic and business conditions
and on our ability to fund our operations and capital expenditures in the
future. The economic situation could have an impact on our lenders or customers,
causing them to fail to meet their obligations to us, and on the liquidity of
our operating partners, resulting in delays in operations or their failure to
make required payments. Also, market conditions could have an impact on our
natural gas and oil derivatives transactions if our counterparties are unable to
perform their obligations or seek bankruptcy protection. Additionally, the
current economic situation could lead to further reductions in the demand for
natural gas and oil, or further reductions in the prices of natural gas and oil,
or both, which could have a negative impact on our financial position, results
of operations and cash flows. While the ultimate outcome and impact of the
current financial crisis cannot be predicted, it may have a material adverse
effect on our future liquidity, results of operations and financial
condition.
Natural
gas and oil prices are highly volatile and have declined significantly since
mid-2008, and lower prices will negatively affect our financial condition,
planned capital expenditures and results of operations.
Since
July 2008, publicly quoted spot natural gas and oil prices have declined
significantly from the record levels reached at that time. In the past, some oil
and gas companies have reduced or curtailed production to mitigate the impact of
low natural gas and oil prices. We have made similar decisions on selected
properties during the last year and may decide to curtail
additional production as a result of a decrease in prices in the
future. The decrease in natural gas prices has had a significant impact on our
financial condition, planned capital expenditures and results of operations.
Further volatility in natural gas and oil prices or a prolonged period of low
natural gas and oil prices may materially adversely affect our financial
condition, liquidity (including our borrowing capacity under our senior credit
facility), ability to finance planned capital expenditures and results of
operations.
Our
revenue, profitability, cash flow, future growth and ability to borrow funds or
obtain additional capital, as well as the carrying value of our properties, are
substantially dependent on prevailing prices of natural gas and oil.
Historically, the markets for natural gas and oil prices have been volatile, and
those markets are likely to continue to be volatile in the future. It is
impossible to predict future natural gas and oil price movements with certainty.
Prices for natural gas and oil are subject to wide fluctuation in response to
relatively minor changes in the supply of and demand for natural gas and oil,
market uncertainty and a variety of additional factors beyond our control. These
factors include:
· the level
of consumer product demand;
· overall
economic conditions;
· weather
conditions;
· domestic
and foreign governmental relations, regulations and taxes;
· the price
and availability of alternative fuels;
· political
conditions;
· the level
and price of foreign imports of oil and liquefied natural gas; and
· the
ability of the members of the Organization of Petroleum Exporting Countries to
agree upon and maintain production constraints and oil price
controls.
As
a result of an ongoing SEC staff review, we may be required to reclassify or
write-off reserves.
We own
interests in approximately 2,630 gross acres in the Camp Hill Field in Anderson
County, Texas, for which we 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 our 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. In late
2008, the SEC adopted new rules regarding the classification of reserves that
will become effective with our reserve report 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, we 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. We may also be required under applicable SEC rules to
write-off or reclassify to proved undeveloped, a portion of our proved developed
reserves. The removal or reclassification of these reserves may be effective as
of December 31, 2009, but could also involve removal of reserves in prior
periods. A downward revision to our proved reserves in prior periods would
likely result in amendments to our previously filed reports with the SEC to
reflect a restatement of our financial statements, including a non-cash
reduction in our historic net income. As an illustration, if we had removed all
8.2 MMBbls of our proved reserves in the Camp Hill Field, including both proved
developed and proved undeveloped reserves, effective as of December 31, 2008, it
would have resulted in a restatement of our financial statements to reflect an
additional pre-tax non-cash ceiling test impairment of approximately $70.8
million.
As of
September 30, 2009, using the unweighted arithmetic average of the first day of
the month price for each month from January through November 2009 (similar to
the pricing methodology that will be required under the new SEC rules discussed
below), the PV-10 value of the proved reserves in Camp Hill was approximately
$150.9 million (including a PV-10 value of approximately $58.7 million
attributable to the proved undeveloped reserves). PV-10 is the
present value of estimated future revenues to be generated from the production
of proved reserves calculated in accordance with Commission guidelines, net of
estimated production and future development costs, using prices and costs as of
the date of estimation without future escalation, without giving effect to
non-property related expenses such as general and administrative expenses, debt
service, future income tax expense and depreciation, depletion and amortization,
and discounted using an annual discount rate of 10%.
We have
actively engaged with and responded to the SEC throughout this review process.
The staff continues to request, and we continue to provide, information
regarding our reserves, including our proved developed nonproducing reserves and
the economics of our proved reserves in the Camp Hill Field. However, we cannot
predict the timing or final result of the staff’s review, and there can be no
assurance that our determination following such review will not result in
material changes to the classification of our reserves in the Camp Hill Field,
and other adverse effects on our historic financial results.
Our
reserve data and estimated discounted future net cash flows are estimates based
on assumptions that may be inaccurate and are based on existing economic and
operating conditions that may change in the future.
There are
uncertainties inherent in estimating natural gas and oil reserves and their
estimated value, including many factors beyond the control of the producer. The
reserve data included in our filings with the SEC represent only estimates.
Reservoir engineering is a subjective and inexact process of estimating
underground accumulations of natural gas and oil that cannot be measured in an
exact manner and is based on assumptions that may vary considerably from actual
results.
Accordingly,
reserve estimates may be subject to upward or downward adjustment, and actual
production, revenue and expenditures with respect to our reserves likely will
vary, possibly materially, from estimates. Additionally, there recently has been
increased debate and disagreement over the classification of reserves, with
particular focus on proved undeveloped reserves. In late
2008, the
SEC adopted new rules regarding the classification of
reserves. However, the interpretation of these rules and their
applicability in different situations remains unclear in many
respects. Changing interpretations of the classification standards or
disagreements with our interpretations could cause us to write-down
reserves. Please read “─ As a result of an ongoing SEC staff review,
we may be required to reclassify or write-off reserves.” In addition, the new
SEC rules regarding classification of reserves require that in calculating
economic producibility of proved reserves, a company must generally use a
12-month average price, calculated as the unweighted arithmetic average of the
first-day-of-the-month price for each month within the 12-month period prior to
the end of the reporting period. Natural gas prices on the first day of each
month in 2009 have been historically low and, as a result, when the applying the
new rules, we may be required to reclassify certain proved reserves as of
year-end 2009.
As of
December 31, 2008, approximately 58.6% of our proved reserves were proved
undeveloped and proved nonproducing. Moreover, some of the producing wells
included in our reserve reports as of December 31, 2008 had produced for a
relatively short period of time as of that date. Because most of our reserve
estimates are calculated using volumetric analysis, those estimates are less
reliable than estimates based on a lengthy production history. Volumetric
analysis involves estimating the volume of a reservoir based on the net feet of
pay of the structure and an estimation of the area covered by the structure
based on seismic analysis. In addition, realization or recognition of our proved
undeveloped reserves will depend on our development schedule and plans. Lack of
certainty with respect to development plans for proved undeveloped reserves
could cause the discontinuation of the classification of these reserves as
proved.
The
discounted future net cash flows included our filings with the SEC are not
necessarily the same as the current market value of our estimated natural gas
and oil reserves. As required by the SEC, the estimated discounted future net
cash flows from proved reserves are currently based on prices and costs as of
the date of the estimate and soon will be based on monthly averages. Actual
future net cash flows also will be affected by factors such as:
· the
actual prices we receive for natural gas and oil;
· our
actual operating costs in producing natural gas and oil;
· the
amount and timing of actual production;
· supply
and demand for natural gas and oil;
· increases
or decreases in consumption of natural gas and oil; and
· changes
in governmental regulations or taxation.
In
addition, the 10% discount factor we use when calculating discounted future net
cash flows for reporting requirements in compliance with the Financial
Accounting Standards Board Statement of Financial Accounting Standards No. 69
may not be the most appropriate discount factor based on interest rates in
effect from time to time and risks associated with us or the natural gas and oil
industry in general.
We
participate in oil and natural gas leases with third parties and these third
parties may not be able to fulfill their commitments to our
projects.
We
frequently own less than 100% of the working interest in the oil and natural gas
leases on which we conduct operations, and other parties will own the remaining
portion of the working interest. Financial risks are inherent in any operation
where the cost of drilling, equipping, completing and operating wells is shared
by more than one person. We could be held liable for joint activity obligations
of the other working interest owners such as nonpayment of costs and liabilities
arising from the actions of the other working interest owners. In addition, the
current economic downturn, the credit crisis and the volatility in natural gas
and oil prices may increase the likelihood that some of these working interest
owners, particularly those that are smaller and less established, are not able
to fulfill their joint activity obligations. Many of our project partners are
experiencing liquidity and cash flow problems. These problems may lead our
partners to attempt to delay the pace of drilling or project development in
order to preserve cash. A partner may be unable or unwilling to pay its share of
project costs. In some cases,, a partner may declare bankruptcy. In the event
any of our project partners do not pay their share of such costs, we would
likely have to pay those costs, and we may be unsuccessful in any efforts to
recover these costs from our partners, which could materially adversely affect
our financial condition.
Our
senior credit facility contains operating restrictions and financial covenants,
and we may have difficulty obtaining additional credit.
Over the
past few years, increases in commodity prices and our successful drilling
program led to increased proved reserve amounts, and the resulting increase in
our estimated discounted future net revenue allowed us to increase the borrowing
base under our senior credit facility. However, as a result of the significant
decline in natural gas and oil prices, or other factors, the lenders under our
senior credit facility may adjust our borrowing base downward, thereby reducing
our borrowing capacity. Our senior credit facility is secured by a pledge of
substantially all of our producing natural gas and oil properties and assets,
guaranteed by our subsidiaries CCBM, Inc., CLLR, Inc., Hondo Pipeline, Inc.,
Carrizo (Marcellus) LLC, Carrizo Marcellus Holding Inc. and Chama Pipeline
Holding LLC and contains covenants that limit additional borrowings, dividends,
the incurrence of liens, investments, sales or pledges of assets, changes in
control, repurchases or redemptions for cash of our common stock, speculative
commodity transactions and other matters. The senior credit facility also
requires that specified financial ratios be maintained. Although we currently
believe that we can meet all of our financial covenants with the business plan
that we have put in place, our 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 we receive 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 contained in our senior credit
facility, including the covenants related to working capital, the ratio of
EBITDA to debt coverage and the ratio of senior debt to EBITDA. In order to
provide a further margin of comfort with regards to these financial covenants,
we may seek to further reduce our capital and exploration budget, sell
additional non-strategic assets or opportunistically modify or increase our
natural gas hedges. There can be no assurance that we 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. We may not be able to
refinance our debt or obtain additional financing, particularly in view of the
restrictions of our senior credit facility on our ability to incur additional
debt and the fact that substantially all of our assets are currently pledged to
secure obligations under the senior credit facility. The restrictions of our
senior credit facility and our difficulty in obtaining additional debt financing
may have adverse consequences on our operations and financial results
including:
· our
ability to obtain financing for working capital, capital expenditures, our
drilling program, purchases of new technology or other purposes may be
impaired;
· the
covenants in our senior credit facility that limit our ability to borrow
additional funds and dispose of assets may affect our flexibility in planning
for, and reacting to, changes in business conditions;
· because
our indebtedness is subject to variable interest rates, we are vulnerable to
increases in interest rates;
· any
additional financing we obtain may be on unfavorable terms;
· we may be
required to use a substantial portion of our cash flow to make debt service
payments, which will reduce the funds that would otherwise be available for
operations and future business opportunities;
· a
substantial decrease in our operating cash flow or an increase in our expenses
could make it difficult for us to meet debt service requirements and could
require us to modify our operations, including by curtailing portions of our
drilling program, selling assets, reducing our capital expenditures, refinancing
all or a portion of our existing debt or obtaining additional financing;
and
· we may
become more vulnerable to downturns in our business or the economy.
In
addition, under the terms of our senior credit facility, our borrowing base is
subject to redeterminations at least semi-annually based in part on prevailing
natural gas and oil prices. The next redetermination of our borrowing base is
currently scheduled to occur in November 2009. Although we do not know at this
time whether the borrowing base will be adjusted upwards or downwards, a
negative adjustment could occur if the estimate of future prices used by the
banks in calculating the borrowing base are significantly lower than those used
in the last redetermination which occurred earlier this year. In the event the
amount outstanding under our senior credit facility exceeds the redetermined
borrowing base, we could be forced to repay a portion of our borrowings. We may
not have sufficient funds to make any required repayment. If we do not have
sufficient funds and are otherwise unable to negotiate renewals of our
borrowings or arrange new financing, we may have to sell a portion of our
assets.
We
have limited experience drilling wells in the Marcellus Shale and less
information regarding reserves and decline rates in the Marcellus Shale than in
other areas of our operations. We may face difficulties in securing and
operating under authorizations and permits to drill and/or operate our Marcellus
Shale wells.
We have
limited exploration experience and no development experience in the Marcellus
Shale. As of October 21, 2009, we have participated or are participating in the
drilling of only seven wells in the Marcellus Shale area. Other operators in the
Marcellus Shale area also have limited experience drilling in the area. As a
result, we have less information with respect to the ultimate recoverable
reserves and the production decline rate in the Marcellus Shale than we have in
other areas in which we operate. Moreover, the recent growth in exploration in
the Marcellus Shale has drawn intense scrutiny from environmental interest
groups, regulatory agencies and other governmental entities. As a result, we may
face significant opposition to our operations that may make it difficult or
impossible to obtain permits and other needed authorizations to operate or
otherwise make operating more costly or difficult than operating
elsewhere.
If we are unable to acquire adequate
supplies of water for our Marcellus Shale drilling operations or are unable to
dispose of the water we use at a reasonable cost and within applicable
environmental rules, our ability to produce gas commercially and in commercial
quantities could be impaired.
We use a
substantial amount of water in our Marcellus Shale drilling operations. Our
inability to locate sufficient amounts of water, or dispose of water after
drilling, could adversely impact our Marcellus Shale operations. Moreover, the
imposition of new environmental initiatives and regulations could include
restrictions on our ability to conduct certain operations such as hydraulic
fracturing or disposal of waste, including, but not limited to, produced water,
drilling fluids and other wastes associated with the exploration, development or
production of natural gas. Furthermore, new environmental regulations and permit
requirements governing the withdrawal, storage and use of surface water or
groundwater necessary for hydraulic fracturing of wells may also increase
operating costs and cause delays, interruptions or termination of operations,
the extent of which cannot be predicted, all of which could have an adverse
affect on our operations and financial performance.
We
cannot control the activities on properties we do not operate.
We do not
operate all of the properties in which we have an interest. As a result, we have
limited ability to exercise influence over, and control the risks associated
with, operations of these properties. The failure of an operator of our wells to
adequately perform operations, an operator’s breach of the applicable agreements
or an operator’s failure to act in ways that are in our best interests could
reduce our production and revenues or could create liability for us for the
operator’s failure to properly maintain the well and facilities and to adhere to
applicable safety and environmental standards. With respect to properties that
we do not operate:
· the
operator could refuse to initiate exploration or development
projects;
· if we
proceed with any of those projects the operator has refused to initiate, we may
not receive any funding from the operator with respect to that
project;
· the
operator may initiate exploration or development projects on a different
schedule than we would prefer;
· the
operator may propose greater capital expenditures than we wish, including
expenditures to drill more wells or build more facilities on a project than we
have funds for, which may mean that we cannot participate in those projects or
participate in a substantial amount of the revenues from those projects;
and
· the
operator may not have sufficient expertise or resources.
Any of
these events could significantly and adversely affect our anticipated
exploration and development activities.
If our access to markets is
restricted, it could negatively impact our production, our income and ultimately
our ability to retain our leases. Our ability to sell natural gas and/or receive
market prices for our natural gas may be adversely affected by pipeline and
gathering system capacity constraints.
Market
conditions or the unavailability of satisfactory oil and natural gas
transportation arrangements may hinder our access to oil and natural gas markets
or delay our production. The availability of a ready market for our oil and
natural gas production depends on a number of factors, including the demand for
and supply of oil and natural gas and the proximity of reserves to pipelines and
terminal facilities. Our ability to market our production depends in substantial
part on the availability and capacity of gathering
systems,
pipelines and processing facilities owned and operated by third parties. Our
failure to obtain such services on acceptable terms could materially harm our
business. Our productive properties may be located in areas with limited or no
access to pipelines, thereby necessitating delivery by other means, such as
trucking, or requiring compression facilities. Such restrictions on our ability
to sell our oil or natural gas may have several adverse affects, including
higher transportation costs, fewer potential purchasers (thereby potentially
resulting in a lower selling price) or, in the event we were unable to market
and sustain production from a particular lease for an extended time, possibly
causing us to lose a lease due to lack of production.
Historically,
we have generally delivered natural gas through gas gathering systems and gas
pipelines that we do not own under interruptible or short-term transportation
agreements. Under the interruptible transportation agreements, the
transportation of our gas may be interrupted due to capacity constraints on the
applicable system, for maintenance or repair of the system, or for other reasons
as dictated by the particular agreements. Due to the lack of available pipeline
capacity in the Barnett Shale, we have recently begun entering into firm
transportation agreements in the Barnett Shale, which are more costly to us than
the interruptible or short-term transportation agreements.
If
production in the Marcellus Shale by oil and has companies continues to expand,
the amount of natural gas being produced by us and others could exceed the
capacity of the various gathering and intrastate or interstate transportation
pipelines currently available in these areas. If this occurs, it will be
necessary for new pipelines and gathering systems to be built. Because of the
current economic climate, certain pipeline projects that are planned for the
Marcellus Shale may not occur for lack of financing. In addition, capital
constraints could limit our ability to build intrastate gathering systems
necessary to transport our gas to interstate pipelines. In such event, we might
have to shut in our wells awaiting a pipeline connection or capacity and/or sell
natural gas production at significantly lower prices than those quoted on NYMEX
or than we currently project, which would adversely affect our results of
operations.
A portion
of our natural gas and oil production in any region may be interrupted, or shut
in, from time to time for numerous reasons, including as a result of weather
conditions, accidents, loss of pipeline or gathering system access, field labor
issues or strikes, or we might voluntarily curtail production in response to
market conditions. If a substantial amount of our production is interrupted at
the same time, it could temporarily adversely affect our cash flow.
We
may record ceiling limitation write-downs that would reduce our shareholders’
equity.
We use
the full-cost method of accounting for investments in natural gas and oil
properties. Accordingly, we capitalize all the direct costs of acquiring,
exploring for and developing natural gas and oil properties. Under the full-cost
accounting rules, the net capitalized cost of natural gas and oil properties may
not exceed a “ceiling limit” that is based on the present value of estimated
future net revenues from proved reserves, discounted at 10%, plus the lower of
the cost or the fair market value of unproved properties. If net capitalized
costs of natural gas and oil properties exceed the ceiling limit, we must charge
the amount of the excess to operations through depreciation, depletion and
amortization expense. This charge is called a “ceiling limitation write-down.”
This charge does not impact cash flow from operating activities but does reduce
our shareholders’ equity. The risk that we will be required to write down the
carrying value of our natural gas and oil properties increases when natural gas
and oil prices are low or volatile. In addition, write-downs would occur if we
were to experience sufficient downward adjustments to our estimated proved
reserves or the present value of estimated future net revenues, as further
discussed under “Our reserve data and estimated discounted future net cash flows
are estimates based on assumptions that may be inaccurate and are based on
existing economic and operating conditions that may change in the future.” Once
incurred, a write-down of natural gas and oil properties is not reversible at a
later date. We recorded non-cash ceiling test limitation write-downs at the end
of 2008 and the end of the first quarter of 2009. We could incur additional
write-downs in the future, particularly as a result of a decline of natural gas
and oil prices or as a write-off of reserves.
There
is recently proposed legislation that could adversely affect our
business.
Congress
is currently considering legislation to amend the federal Safe Drinking Water
Act to subject hydraulic fracturing operations to regulation under that Act and
to require the disclosure of chemicals used by the oil and gas industry in the
hydraulic fracturing process. Hydraulic fracturing involves the injection of
water, sand and chemicals under pressure into rock formations to stimulate gas
production. Sponsors of bills currently pending before the Senate and House of
Representatives have asserted that chemicals used in fracturing process could
adversely affect drinking water supplies. In addition, these bills,
if adopted, could establish an additional level of regulation at the federal
level that could lead to operational delays or increased operating costs and
could result in additional regulatory burdens that could make it more difficult
to perform hydraulic fracturing and increase the Company’s costs of compliance
and doing business. In addition, various states are also studying or
considering various regulatory measures relating to hydraulic fracturing,
including a moratorium on drilling in the Marcellus Shale that has been
instituted in New York until the completion of a study by state officials
regarding the potential environmental impact of Marcellus Shale
development. We make
extensive
use of hydraulic fracturing in our shale play operations and any federal, state
or local increased regulation could increase our costs, limit our ability to
conduct operations or otherwise adversely affect our business.
In
addition to various other federal, regional, state and local greenhouse gas
legislation and regulations that are currently in effect or under development,
the United States Congress is currently considering legislation that would
significantly curtail national greenhouse gas emissions. The United States
Environmental Protection Agency has also taken steps to declare that certain
greenhouse gas emissions are contributing to air pollution which is an
endangerment to human health, and may regulate greenhouse gas emissions under
the federal Clean Air Act. Any laws or regulations that may be
adopted to restrict or reduce emissions of greenhouse gases could require us to
incur increased operating costs and could have an adverse affect on the price or
demand of the oil and gas we produce.
President
Obama’s Proposed 2010 Fiscal Year Budget includes proposed legislation that
would, if enacted into law, make significant changes to United States tax laws,
including the elimination of certain key U.S. federal income tax incentives
currently available to oil and natural gas exploration and production companies.
The passage of any legislation as a result of these proposals or any other
similar changes in U.S. federal income tax laws could defer or eliminate certain
tax deductions that are currently available with respect to oil and gas
exploration and development, and any such change could negatively affect our
financial condition and results of operations.
Enactment of a Pennsylvania severance
tax on natural gas could adversely impact our results of operations and the
economic viability of exploiting natural gas drilling and production
opportunities in Pennsylvania.
As a
result of a funding gap in the state budget, the governor of the Commonwealth of
Pennsylvania has proposed to its legislature the adoption of a severance tax on
the production of natural gas in Pennsylvania. The amount of the proposed tax is
5% of the value of the natural gas at wellhead, plus 4.7 cents per 1,000 cubic
feet of natural gas severed. A substantial portion of our Marcellus Shale
acreage is located in the Commonwealth of Pennsylvania. If Pennsylvania adopts
such a severance tax, it could adversely impact our results of operations and
the economic viability of exploiting natural gas drilling and production
opportunities in Pennsylvania.
As
of December 31, 2008, March 31, 2009 and June 30, 2009, we
had material weaknesses in our internal controls, and our internal control over
financial reporting was not effective as of those dates. If we fail to maintain
an effective system of internal controls, we may not be able to provide timely
and accurate financial statements.
As more
fully described in our Annual Report on Form 10-K/A for the year ended
December 31, 2008 under Item 9A, “Controls and Procedures,” in our
Quarterly Report on Form 10-Q/A for the quarter ended March 31, 2009 and in our
Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, our
management identified material weaknesses related to the ceiling test impairment
and the classification of proved costs. As a result of the material weaknesses,
management concluded that, as of December 31, 2008, March 31,
2009 and June 30, 2009 we did not maintain effective internal control over
financial reporting.
Management
identified the material weaknesses referred to above in August of 2009 in a
subsequent review of the December 31, 2008 and March 31, 2009 ceiling test
calculations.
The
Public Company Accounting Oversight Board has defined a material weakness as a
control deficiency, or combination of control deficiencies, that results in a
reasonable possibility that a material misstatement of the annual or interim
statements will not be prevented or detected on a timely basis. Accordingly, a
material weakness increases the risk that the financial information we report
contains material errors.
We
implemented initiatives to remediate the material weaknesses in our internal
controls. The steps we have taken to address the material weaknesses may not be
effective. However, any failure to effectively address a material weakness or
other control deficiency or implement required new or improved controls, or
difficulties encountered in their implementation, could limit our ability to
obtain financing, harm our reputation, disrupt our ability to process key
components of our result of operations and financial condition timely and
accurately and cause us to fail to meet our reporting obligations under rules of
the SEC and NASDAQ and our various debt arrangements.
Item 2 -
Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3 -
Defaults Upon Senior Securities
None.
Item 4 -
Submission of Matters to a Vote of Security Holders
None.
Item 5 -
Other Information
None.
Item 6 -
Exhibits
Exhibits required by Item 601 of
Regulation S-K are as follows:
|
Exhibit
Number
|
Description
|
|
|
31.1
|
—
|
|
|
31.2
|
—
|
|
|
32.1
|
—
|
|
|
32.2
|
—
|
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act
of 1934, the Registrant has duly caused this Report to be signed on its behalf
by the undersigned, thereunto duly authorized.
|
Carrizo
Oil & Gas, Inc.
|
|
|
(Registrant)
|
|
|
Date: November
9, 2009
|
By: /s/S. P. Johnson,
IV
|
|
President
and Chief Executive Officer
|
|
|
(Principal
Executive Officer)
|
|
|
Date: November
9, 2009
|
By: /s/Paul F.
Boling
|
|
Chief
Financial Officer
|
|
|
(Principal
Financial and Accounting Officer)
|
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