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 March 31,
2008
[ ]
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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|||
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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 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 [ ]
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 May 1, 2008, the latest practicable date, was
30,628,724.
CARRIZO
OIL & GAS, INC.
FORM
10-Q
FOR
THE QUARTERLY PERIOD ENDED MARCH 31, 2008
INDEX
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PART
I. FINANCIAL INFORMATION
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PAGE
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Item
1.
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|||
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As
of March 31, 2008 (Unaudited) and December 31, 2007
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2
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For
the three-month periods ended March 31, 2008 and 2007
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3
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For
the three-month periods ended March 31, 2008 and 2007
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4
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5
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Item
2.
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13
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Item
3.
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20
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Item
4.
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21
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PART
II. OTHER INFORMATION
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|||
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22
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23
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CARRIZO
OIL & GAS, INC.
CONSOLIDATED BALANCE SHEETS
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March
31,
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December
31,
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|||||||
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ASSETS
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2008
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2007
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||||||
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(Unaudited)
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||||||||
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(In
thousands, except share 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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$ | 24,769 | $ | 8,026 | ||||
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Accounts
receivable, trade (net of allowance for doubtful accounts of $1,359 and
$1,430
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||||||||
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at
March 31, 2008 and December 31, 2007, respectively)
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32,601 | 26,411 | ||||||
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Advances
to operators
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1,167 | 1,113 | ||||||
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Fair
value of derivative financial instruments
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- | 1,829 | ||||||
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Prepayments
and deposits
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1,659 | 3,913 | ||||||
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Deferred
income taxes
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8,246 | 324 | ||||||
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Total
current assets
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68,442 | 41,616 | ||||||
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PROPERTY
AND EQUIPMENT, net full-cost method of accounting for oil
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||||||||
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and
natural gas properties (including unevaluated costs of properties of
$170,216 and
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||||||||
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$124,373
at March 31, 2008 and December 31, 2007, respectively)
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750,240 | 646,810 | ||||||
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DEFERRED
FINANCING COSTS, NET
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5,351 | 5,921 | ||||||
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INVESTMENT
IN PINNACLE GAS RESOURCES, INC.
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6,173 | 11,071 | ||||||
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OTHER
ASSETS
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3,181 | 3,245 | ||||||
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TOTAL
ASSETS
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$ | 833,387 | $ | 708,663 | ||||
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LIABILITIES
AND SHAREHOLDERS' EQUITY
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||||||||
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CURRENT
LIABILITIES:
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||||||||
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Accounts
payable, trade
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46,363 | $ | 49,700 | |||||
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Accrued
liabilities
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39,409 | 36,091 | ||||||
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Advances
for joint operations
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651 | 872 | ||||||
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Current
maturities of long-term debt
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2,250 | 2,251 | ||||||
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Fair
value of derivative financial instruments
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23,561 | 2,755 | ||||||
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Total
current liabilities
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112,234 | 91,669 | ||||||
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LONG-TERM
DEBT, NET OF CURRENT MATURITIES
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217,688 | 252,250 | ||||||
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ASSET
RETIREMENT OBLIGATION
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6,478 | 5,869 | ||||||
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FAIR
VALUE OF DERIVATIVE FINANCIAL INSTRUMENTS
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7,483 | 1,050 | ||||||
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DEFERRED
INCOME TAXES
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49,781 | 46,321 | ||||||
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DEFERRED
CREDITS
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762 | 783 | ||||||
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COMMITMENTS
AND CONTINGENCIES
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- | - | ||||||
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SHAREHOLDERS'
EQUITY:
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||||||||
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Common
stock, par value $0.01 (40,000 shares authorized; 30,620
and
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||||||||
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28,009
issued and outstanding at March 31, 2008 and
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||||||||
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December
31, 2007, respectively)
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306 | 280 | ||||||
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Additional
paid-in capital
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381,922 | 246,099 | ||||||
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Retained
earnings
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60,048 | 65,344 | ||||||
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Accumulated
other comprehensive income, net of tax
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2,229 | 5,425 | ||||||
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Unearned
compensation - restricted stock
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(5,544 | ) | (6,427 | ) | ||||
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Total
shareholders' equity
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438,961 | 310,721 | ||||||
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TOTAL
LIABILITIES AND SHAREHOLDERS' EQUITY
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$ | 833,387 | $ | 708,663 | ||||
The
accompanying notes are an integral part of these consolidated financial
statements.
CARRIZO
OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
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For
the Three
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||||||||
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Months
Ended
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||||||||
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March
31,
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||||||||
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2008
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2007
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|||||||
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(In
thousands except
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||||||||
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per
share amounts)
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||||||||
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OIL
AND NATURAL GAS REVENUES
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$ | 53,560 | $ | 22,612 | ||||
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COSTS
AND EXPENSES:
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||||||||
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Oil
and natural gas operating expenses (exclusive of depreciation,
depletion
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||||||||
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and
amortization shown separately below)
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8,391 | 4,703 | ||||||
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Depreciation,
depletion and amortization
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14,087 | 8,038 | ||||||
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General
and administrative (inclusive of stock-based compensation expense
of
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||||||||
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$1,480
and $979 for the three months ended March 31, 2008 and
2007,
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||||||||
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respectively)
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6,519 | 4,878 | ||||||
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Accretion
expense related to asset retirement obligations
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58 | 88 | ||||||
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TOTAL
COSTS AND EXPENSES
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29,055 | 17,707 | ||||||
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OPERATING
INCOME
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24,505 | 4,905 | ||||||
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OTHER
INCOME AND EXPENSES:
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||||||||
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Net
loss on derivatives (Note 7)
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(29,816 | ) | (5,711 | ) | ||||
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Other
income and expenses, net
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69 | 116 | ||||||
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Interest
income
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148 | 344 | ||||||
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Interest
expense
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(6,455 | ) | (6,154 | ) | ||||
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Capitalized
interest
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3,718 | 2,686 | ||||||
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LOSS
BEFORE INCOME TAXES
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(7,831 | ) | (3,814 | ) | ||||
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INCOME
TAX BENEFIT (Note 4)
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2,535 | 1,269 | ||||||
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NET
LOSS
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$ | (5,296 | ) | $ | (2,545 | ) | ||
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BASIC
LOSS PER SHARE
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$ | (0.18 | ) | $ | (0.10 | ) | ||
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DILUTED
LOSS PER SHARE
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$ | (0.18 | ) | $ | (0.10 | ) | ||
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WEIGHTED
AVERAGE COMMON SHARES OUTSTANDING:
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||||||||
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BASIC
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28,799 | 25,658 | ||||||
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DILUTED
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28,799 | 25,658 | ||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
CARRIZO
OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
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For
the Three
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||||||||
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Months
Ended
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||||||||
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March
31,
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||||||||
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2008
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2007
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|||||||
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(In
thousands)
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||||||||
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CASH
FLOWS FROM OPERATING ACTIVITIES:
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||||||||
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Net
loss
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$ | (5,296 | ) | $ | (2,545 | ) | ||
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Adjustment
to reconcile net loss to net
|
||||||||
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cash
provided by operating activities-
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||||||||
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Depreciation,
depletion and amortization
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14,087 | 8,038 | ||||||
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Fair
value loss of derivative financial instruments
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29,069 | 8,062 | ||||||
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Accretion
of discounts on asset retirement obligations
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58 | 88 | ||||||
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Stock-based
compensation
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1,480 | 979 | ||||||
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Deferred
income taxes
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(2,740 | ) | (1,370 | ) | ||||
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Other
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145 | 12 | ||||||
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Changes
in operating assets and liabilities
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||||||||
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Accounts
receivable
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(6,121 | ) | 3,384 | |||||
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Other
assets
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922 | 430 | ||||||
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Accounts
payable
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7,258 | 1,539 | ||||||
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Accrued
liabilities
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2,335 | 553 | ||||||
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Net
cash provided by operating activities
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41,197 | 19,170 | ||||||
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CASH
FLOWS FROM INVESTING ACTIVITIES:
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||||||||
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Capital
expenditures
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(115,571 | ) | (47,815 | ) | ||||
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Change
in capital expenditure accrual
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(9,289 | ) | 1,709 | |||||
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Proceeds
from the sale of properties
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5 | 1,363 | ||||||
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Advances
to operators
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(55 | ) | 747 | |||||
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Advances
for joint operations
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(220 | ) | (80 | ) | ||||
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Other
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(5 | ) | (74 | ) | ||||
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Net
cash used in investing activities
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(125,135 | ) | (44,150 | ) | ||||
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CASH
FLOWS FROM FINANCING ACTIVITIES:
|
||||||||
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Net
proceeds from debt issuance and borrowings
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51,000 | 75,000 | ||||||
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Debt
repayments
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(85,563 | ) | (41,564 | ) | ||||
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Proceeds
from common stock offering, net of offering costs
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135,233 | - | ||||||
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Proceeds
from stock options exercised
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76 | 65 | ||||||
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Deferred
loan costs and other
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(65 | ) | (2,867 | ) | ||||
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Net
cash provided by financing activities
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100,681 | 30,634 | ||||||
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NET
INCREASE IN CASH AND CASH EQUIVALENTS
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16,743 | 5,654 | ||||||
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CASH
AND CASH EQUIVALENTS, beginning of period
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8,026 | 5,408 | ||||||
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CASH
AND CASH EQUIVALENTS, end of period
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$ | 24,769 | $ | 11,062 | ||||
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CASH
PAID FOR INTEREST (NET OF AMOUNTS CAPITALIZED)
|
$ | 2,466 | $ | 3,251 | ||||
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 for the year ended December 31, 2007 (the “2007 Form
10-K”).
Investment
in Unconsolidated Subsidiary
The
Company accounts for its investment in Pinnacle Gas Resources, Inc. (“Pinnacle”)
using the cost method of accounting and adjusts the carrying amount of its
investment for contributions to and distributions from the
subsidiary.
Pinnacle
became a publicly traded entity on the Nasdaq Global Market in May
2007. For accounting purposes, the Pinnacle common stock now has a
readily determinable fair market value. The Company classifies this
investment as available-for-sale and adjusts the book value to fair market value
through Other Comprehensive Income, net of taxes.
Reclassifications
Certain
reclassifications have been made to the prior period’s financial statements to
conform to the current presentation. These reclassifications had no
effect on total assets, shareholders’ equity or net income.
Use
of Estimates
The
preparation of financial statements in conformity with U.S. generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosures of
contingent assets and liabilities at the date of the consolidated financial
statements and the reported amounts of revenues and expenses during the periods
reported. Actual results could differ from these
estimates.
Significant
estimates include volumes of oil and natural gas reserves used in calculating
depletion of proved oil and natural gas properties, future net revenues and
abandonment obligations, impairment of undeveloped properties, future income
taxes and related assets/liabilities, the collectibility of outstanding accounts
receivable, fair values of derivatives, stock-based compensation expense,
contingencies and the results of current and future litigation. Oil
and natural gas reserve estimates, which are the basis for unit-of-production
depletion and the ceiling test, have numerous inherent
uncertainties. The accuracy of any reserve estimates is a function of
the quality 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
effected 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.
Oil
and Natural Gas Properties
Investments
in oil and natural gas properties are accounted for using the full-cost method
of accounting. All costs directly associated with the acquisition,
exploration and development of oil and natural gas properties are
capitalized. Such costs include lease acquisitions, seismic surveys,
and drilling and completion equipment. The Company proportionally
consolidates its interests in oil and natural gas properties. The
Company capitalized compensation costs for employees working directly on
exploration activities of $2.1 million and $1.4 million for the three months
ended March 31, 2008 and 2007, respectively. Maintenance and repairs
are expensed as incurred.
Depreciation,
depletion and amortization (“DD&A”) of proved oil and natural gas properties
is based on the unit-of-production method using estimates of proved reserve
quantities. Investments in unproved properties are not subject to
DD&A until proved reserves associated with the projects can be determined or
until they are impaired. Unevaluated properties are evaluated
periodically for impairment on a property-by-property basis. If the
results of an assessment indicate that the properties have been impaired, the
amount of such impairment is determined and added to the proved oil and natural
gas property costs subject to DD&A. The depletable base includes
estimated future development costs and, where significant, dismantlement,
restoration and abandonment costs, net of estimated salvage
values. The depletion rate per Mcfe for the quarters ended March 31,
2008 and 2007 was $2.19 and $2.47, respectively.
Dispositions
of oil and natural gas properties are accounted for as adjustments to
capitalized costs with no gain or loss recognized, unless such adjustments would
significantly alter the relationship between capitalized costs and proved
reserves.
Net
capitalized costs are limited to a “ceiling-test” based on the estimated future
net revenues, discounted at 10% per annum, from proved oil and natural gas
reserves, based on current economic and operating conditions (“Full Cost
Ceiling”). If net capitalized costs exceed this limit, the excess is
charged to earnings. For the three-month periods ended March 31, 2008
and 2007, the Company did not have any charges associated with its ceiling
test.
Depreciation
of other property and equipment is provided using the straight-line method based
on estimated useful lives ranging from five to 10 years.
Supplemental
Cash Flow Information
The
adjustment of the investment in Pinnacle of $3.2 million, net of tax is excluded
from the Statement of Cash Flows for the three months ended March 31,
2008. The Company paid no income taxes during the three months ended
March 31, 2008 and 2007.
Stock-Based
Compensation
The
Company records stock-based compensation as prescribed by the SFAS No. 123
(R). The compensation expense associated with stock options is based
on the grant-date fair value of the options and recognized over the vesting
period. Restricted stock is recorded as deferred compensation based
on the closing price of the Company’s stock on the issuance date and is
amortized to stock-based compensation expense ratably over the vesting period of
the restricted shares (generally one to three years).
The
Company recognized the following stock-based compensation expense for the three
months ended March 31:
|
2008
|
2007
|
|||||||
|
(In
millions)
|
||||||||
|
Stock
Option Expense
|
$ | 0.1 | $ | 0.1 | ||||
|
Restricted
Stock Expense
|
1.4 | 0.9 | ||||||
|
Total
Stock-Based Compensation Expense
|
$ | 1.5 | $ | 1.0 | ||||
Derivative
Instruments
The
Company uses derivatives to manage price risk underlying its oil and natural gas
production. The Company also uses derivatives to manage the variable
interest rate on its Second Lien Credit Facility.
Upon
entering into a derivative contract, the Company either designates the
derivative instrument as a hedge of the variability of cash flow to be received
(cash flow hedge) or the derivative must be accounted for as a non-designated
derivative. All of the Company’s derivative instruments presented
herein were treated as non-designated derivatives and the unrealized gain/(loss)
related to the mark-to-market valuation was included in the Company’s
earnings.
The
Company typically uses fixed-rate swaps and costless collars to hedge its
exposure to material changes in the price of oil and natural gas and variable
interest rates on long-term debt.
The
Company’s Board of Directors sets all risk management policies and reviews
volumes, types of instruments and counterparties on a quarterly
basis. These policies require that derivative instruments be executed
only by the President or Chief Financial Officer after consultation and
concurrence by the President, Chief Financial Officer and Chairman of the
Board. The master contracts with approved counterparties identify the
President and Chief Financial Officer as the only Company representatives
authorized to execute trades. The Board of Directors also reviews the
status and results of derivative activities quarterly.
Major
Customers
The
Company sold oil and natural gas production representing more than 10% of its
oil and natural gas revenues as follows:
|
For
the Three Months
|
||||||||
|
Ended
March 31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Cimarex
Energy Co.
|
- | 14 | % | |||||
|
Houston
Pipeline Co.
|
13 | % | 20 | % | ||||
|
Crosstex
Energy Services, Ltd.
|
13 | % | - | |||||
|
DTE
Energy Trading, Inc.
|
34 | % | - | |||||
Loss
Per Share
Supplemental
loss per share information is provided below:
|
Three
Months
|
||||||||
|
Ended
March 31,
|
||||||||
|
2008
|
2007
|
|||||||
|
(In
thousands, except
|
||||||||
|
per
share amounts)
|
||||||||
|
Net
loss
|
$ | (5,296 | ) | $ | (2,545 | ) | ||
|
Average
common shares outstanding
|
||||||||
|
Weighted
average common shares outstanding
|
28,799 | 25,658 | ||||||
|
Stock
options
|
- | - | ||||||
|
Diluted
weighted average common shares outstanding
|
28,799 | 25,658 | ||||||
|
Loss
per common share
|
||||||||
|
Basic
|
$ | (0.18 | ) | $ | (0.10 | ) | ||
|
Diluted
|
$ | (0.18 | ) | $ | (0.10 | ) | ||
Basic
loss per common share is based on the weighted average number of shares of
common stock outstanding during the periods. Diluted loss per common
share is based on the weighted average number of common shares and all dilutive
potential common shares issuable during the periods. The Company had
outstanding 453,962 stock options and 353,094 shares of restricted stock that
were excluded in the calculation of dilutive shares for the three-month period
ended March 31, 2008 due to the net loss reported for the
quarter. The Company had outstanding 885,069 stock options and
329,412 shares of restricted stock that were excluded in the calculation of
dilutive shares for the three-month period ended March 31, 2007 due to the net
loss for the quarter.
2. LONG-TERM
DEBT
Long-term
debt consisted of the following at March 31, 2008 and December 31,
2007:
|
March
31,
|
December
31,
|
|||||||
|
2008
|
2007
|
|||||||
|
(In
thousands)
|
||||||||
|
Second
Lien Credit Facility
|
$ | 219,938 | $ | 220,500 | ||||
|
Senior
Secured Revolving Credit Facility
|
- | 34,000 | ||||||
|
Other
|
- | 1 | ||||||
| 219,938 | 254,501 | |||||||
|
Current
maturities
|
(2,250 | ) | (2,251 | ) | ||||
| $ | 217,688 | $ | 252,250 | |||||
Second
Lien Credit Facility
On July
21, 2005, the Company entered into a Second Lien Credit Agreement with Credit
Suisse, as administrative agent and collateral agent and the lenders party
thereto (the “Second Lien Credit Facility”) that matures on July 21,
2010. The Second Lien Credit Facility, as amended, provides for a
term loan facility in an aggregate principal amount of $225.0
million. It is secured by substantially all of the Company’s assets
and is guaranteed by the Company’s subsidiaries. The liens securing
the Second Lien Credit Facility are second in priority to the liens securing the
Senior Secured Revolving Credit Facility (discussed below).
The
interest rate on each base rate loan will be the greater of the agent’s prime
rate and the federal funds effective rate plus 0.5%, plus a margin of
3.75%. The interest rate on each Eurodollar loan will be the adjusted
LIBOR rate plus a margin of 4.75%. Interest on Eurodollar loans is
payable on either the last day of each period or every three months, whichever
is earlier. Interest on the Company’s outstanding borrowings under
the Second Lien Credit Facility is currently payable quarterly on the last day
of each quarter. On March 31, 2008, the interest rate was
approximately 7.4%, excluding the effect of interest rate swaps.
Under
this agreement, the Company is subject to certain covenants and restrictions on
additional financing and other matters. See the 2007 Form 10-K for
further discussion.
Senior
Secured Revolving Credit Facility
On May
25, 2006, the Company entered into a Senior Secured Revolving Credit Facility
(“Senior Credit Facility”) with JPMorgan Chase Bank, National Association, as
administrative agent, that matures May 25, 2010. The Senior Credit
Facility provides for a revolving credit facility up to the lesser of the
borrowing base and $200.0 million. It is secured by
substantially all of the Company’s assets and is guaranteed by the Company’s
subsidiaries. The liens securing the Senior Credit Facility are first
in priority to the liens securing the Second Lien Credit Facility.
The
borrowing base will be determined by the lenders at least semi-annually on each
May 1 and November 1. The Company may request one unscheduled
borrowing base determination subsequent to each scheduled determination and the
lenders may request unscheduled determinations at any time. At March
31, 2008, the conforming and non-conforming base was $125.0 million and $20.0
million, respectively, as determined in December 2007.
As of
March 31, 2008, the Company had no borrowings outstanding under the Senior
Credit Facility.
The
annual interest rate on each base rate borrowing will be (1) the greatest of the
agent’s Prime Rate, the Base CD Rate plus 1.0% and the Federal Funds Effective
Rate plus 0.5%, plus (2) a margin between 0.25% and 1.75% (depending on the
current level of borrowing base usage). The interest rate on each
Eurodollar loan will be the adjusted LIBOR Rate plus a margin between 1.5% to
3.0% (depending on the current level of borrowing base usage).
The
Company is subject to certain covenants and customary events of default under
the terms of the Senior Credit Facility. See the Company’s 2007 Form
10-K for further discussion.
3. INVESTMENT
IN PINNACLE GAS RESOURCES, INC.
In 2003,
the Company and its wholly-owned subsidiary CCBM, Inc. (“CCBM”) contributed
their interests in certain natural gas and oil leases in Wyoming and Montana in
areas prospective for coalbed methane to a newly formed entity, Pinnacle Gas
Resources, Inc. (“Pinnacle”). At March 31, 2008, the Company owned
less than ten percent of Pinnacle’s outstanding equity and accounted for its
investment in Pinnacle using the cost method.
During
the second quarter of 2007, Pinnacle became a publicly traded entity on the
Nasdaq Global Market. For accounting purposes, the Pinnacle stock now
has a readily determinable fair value. As a result, the Company
classifies the Pinnacle investment as available-for-sale and adjusts the
investment to fair value through Other Comprehensive Income. For the
three months ended March 31, 2008, Carrizo decreased the book value of its
Pinnacle investment by $4.9 million, $3.2 million net of tax, and reported the
fair value of the stock at $6.2 million (based on the closing price of
Pinnacle’s common stock on March 31, 2008).
In June
2007, the Company sold 41,894 shares of Pinnacle stock for net proceeds of $0.4
million and recognized a $0.3 million gain, which is included in Other income
and expenses, net on the Consolidated Statements of Operations. As of
March 31, 2008, the Company owned 2,420,723 shares of Pinnacle common
stock.
On
October 15, 2007, Pinnacle, Quest Resource Corporation (“Quest”), and Quest
Merger Sub, Inc., a wholly owned subsidiary of Quest (“Merger Sub”), entered
into an agreement and plan of merger whereby Merger Sub will merge with and into
Pinnacle. The merger agreement provides for Quest’s acquisition of all of the
issued and outstanding shares of Pinnacle’s common stock for aggregate
consideration of approximately 15.5 million shares of Quest’s common stock, or
approximately $100 million based on the closing price of Quest’s common stock on
March 31, 2008. Upon completion of the merger, each share of
Pinnacle’s common stock will be converted into the right to receive 0.5278
shares of Quest’s common stock. Completion of the merger transaction
is conditioned upon, among other things, adoption of the merger agreement by
both Pinnacle’s and Quest’s stockholders.
4. INCOME
TAXES
The
Company provided deferred federal income taxes at the rate of 35% (which also
approximates its statutory rate) that amounted to a tax benefit of $2.7 million
and $1.3 million for the three-month periods ended March 31, 2008 and 2007,
respectively.
On
January 1, 2007, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in
Income Taxes – an interpretation of FASB Statement No. 109” (“FIN
48”). FIN 48 prescribes a measurement process for recording in the
financial statements uncertain tax positions taken or expected to be taken in a
tax return. Additionally, FIN 48 provides guidance regarding
uncertain tax positions relating to derecognition, classification, interest and
penalties, accounting in interim periods, disclosure and
transition. The Company classifies interest and penalties associated
with income taxes as interest expense. At March 31, 2008, the Company
had no material uncertain tax positions and the tax years 2003 through 2007
remained open to review by federal and various state tax
jurisdictions.
5. 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.
6. SHAREHOLDERS’
EQUITY
The
following is a summary of changes in the Company’s common stock for the
three-month periods ended March 31:
|
2008
|
2007
|
|||||||
|
(In
thousands)
|
||||||||
|
Shares
outstanding at January 1
|
28,009 | 25,981 | ||||||
|
Equity
offering
|
2,588 | - | ||||||
|
Restricted
stock issued, net of forfeitures
|
9 | 5 | ||||||
|
Employee
stock options exercised
|
15 | 6 | ||||||
|
Common
stock repurchased and retired for tax withholding
obligation
|
(1 | ) | (1 | ) | ||||
|
Shares
outstanding at March 31
|
30,620 | 25,991 | ||||||
In
February 2008, the Company completed an underwritten public offering of
2,587,500 shares of its common stock under an effective shelf registration
statement 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 $135.2
million, net of expenses, and plans to use the proceeds to fund, in part, its
capital expenditure program for 2008, including its Barnett Shale drilling and
land acquisition programs, and for other corporate purposes. Pending
those uses, the Company used a portion of the net proceeds to repay $85.0
million outstanding under the Senior Credit Facility.
7. 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. The Company also uses interest rate swap
agreements to manage the Company’s exposure to interest rate fluctuations on the
Second Lien Credit Facility.
The
Company accounts for its oil and natural gas derivatives and interest rate swap
agreements as non-designated hedges. These derivatives are
marked-to-market at each balance sheet date and the unrealized gains (losses)
along with the realized gains (losses) associated with the cash settlements of
derivative instruments are reported as gain (loss) on derivatives, net in Other
Income and Expenses in the Consolidated Statements of Operations. For
the three month periods ended March 31, 2008 and 2007, the Company recorded the
following related to its derivatives:
|
Three
Months
|
||||||||
|
Ended
March 31,
|
||||||||
|
2008
|
2007
|
|||||||
|
(In
millions)
|
||||||||
|
Realized
gains (losses):
|
||||||||
|
Natural
gas and oil derivatives
|
$ | (0.5 | ) | $ | 2.3 | |||
|
Interest
rate swaps
|
(0.2 | ) | 0.1 | |||||
| (0.7 | ) | 2.4 | ||||||
|
Unrealized
losses:
|
||||||||
|
Natural
gas and oil derivatives
|
$ | (26.9 | ) | $ | (8.0 | ) | ||
|
Interest
rate swaps
|
(2.2 | ) | (0.1 | ) | ||||
| (29.1 | ) | (8.1 | ) | |||||
|
Loss
on derivatives, net
|
$ | (29.8 | ) | $ | (5.7 | ) | ||
At March
31, 2008, the Company had the following outstanding derivative
positions:
|
Natural
Gas
|
Natural
Gas
|
|||||||||||||||||||
|
Swaps
|
Collars
|
|||||||||||||||||||
|
Average
|
Average
|
Average
|
||||||||||||||||||
|
Quarter
|
MMbtu
|
Fixed
Price(1)
|
MMBtu
|
Floor
Price(1)
|
Ceiling
Price(1)
|
|||||||||||||||
|
Second
Quarter 2008
|
273,000 | $ | 7.94 | 3,185,000 | $ | 7.14 | $ | 8.83 | ||||||||||||
|
Third
Quarter 2008
|
276,000 | 7.94 | 3,036,000 | 7.13 | 8.82 | |||||||||||||||
|
Fourth
Quarter 2008
|
276,000 | 7.94 | 3,036,000 | 7.13 | 8.82 | |||||||||||||||
|
First
Quarter 2009
|
- | - | 2,520,000 | 7.37 | 9.10 | |||||||||||||||
|
Second
Quarter 2009
|
- | - | 2,548,000 | 7.12 | 8.85 | |||||||||||||||
|
Third
Quarter 2009
|
- | - | 2,576,000 | 7.16 | 8.88 | |||||||||||||||
|
Fourth
Quarter 2009
|
- | - | 2,576,000 | 7.17 | 8.90 | |||||||||||||||
|
First
Quarter 2010
|
- | - | 1,170,000 | 7.55 | 9.27 | |||||||||||||||
|
Second
Quarter 2010
|
- | - | 1,183,000 | 7.07 | 8.79 | |||||||||||||||
|
Third
Quarter 2010
|
- | - | 1,196,000 | 7.19 | 8.90 | |||||||||||||||
|
Fourth
Quarter 2010
|
- | - | 1,196,000 | 7.25 | 8.96 | |||||||||||||||
|
Oil
Collars
|
||||||||||||
|
Average
|
Average
|
|||||||||||
|
Quarter
|
Bbls
|
Floor
Price(2)
|
Ceiling
Price (2)
|
|||||||||
|
Second
Quarter 2008
|
9,100 | $ | 70.00 | $ | 76.75 | |||||||
|
Third
Quarter 2008
|
9,200 | 70.00 | 76.75 | |||||||||
|
Fourth
Quarter 2008
|
9,200 | 70.00 | 76.75 | |||||||||
__________
|
(1)
|
Based
on Houston Ship Channel and Waha spot
prices.
|
|
(2)
|
Based
on West Texas intermediate index
prices.
|
During
the first and second quarter of 2007, the Company entered into interest swap
agreements covering amounts outstanding under the Second Lien Credit
Facility. These arrangements are designed to manage the Company’s
exposure to interest rate fluctuations through December 31, 2008 by effectively
exchanging existing obligations to pay interest based on floating rates with
obligations to pay interest based on fixed LIBOR. The Company’s
outstanding positions under interest rate swap agreements at March 31, 2008 were
as follows (dollars in thousands):
|
Notional
|
Fixed
|
|||||||
|
Quarter
|
Amount
|
LIBOR
Rate
|
||||||
|
Second
Quarter 2008
|
219,938 | 5.32 | % | |||||
|
Third
Quarter 2008
|
219,375 | 5.31 | % | |||||
|
Fourth
Quarter 2008
|
218,813 | 5.31 | % | |||||
The fair
value of the outstanding derivatives at March 31, 2008 and December 31, 2007 was
a liability of $31.1 million and $2.0 million, respectively.
8. FAIR
VALUE MEASUREMENTS
Effective
January 1, 2008, the Company adopted Financial Accounting Standards Board
(“FASB”) Statement No. 157, “Fair Value
Measurements” (“SFAS No. 157”), which defines fair value,
establishes a framework for measuring fair value, establishes a fair value
hierarchy based on the quality of inputs used to measure fair value and enhances
disclosure requirements for fair value measurements. The
implementation of SFAS No. 157 did not cause a change in the method of
calculating fair value of assets or liabilities, with the exception of
incorporating a measure of the Company’s own nonperformance risk or that of its
counterparties as appropriate, which was not material. The primary
impact from adoption was additional disclosures.
The
Company elected to implement SFAS 157 with the one-year deferral permitted by
FASB Staff Position No. FAS 157-2, “Effective Date of FASB Statement
No. 157”, issued February 2008, which defers the effective date of SFAS
No. 157 for one year for certain nonfinancial assets and nonfinancial
liabilities measured at fair value, except those that are recognized or
disclosed at fair value in the financial statements on a recurring
basis.
SFAS No.
157 establishes 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 March 31, 2008, 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.
|
$ | 6,173 | $ | - | $ | - | $ | 6,173 | ||||||||
|
Liabilities:
|
||||||||||||||||
|
Oil
and natural gas derivatives
|
- | (26,125 | ) | - | $ | (26,125 | ) | |||||||||
|
Interest
rate swaps
|
- | (4,919 | ) | - | $ | (4,919 | ) | |||||||||
|
Total
|
$ | 6,173 | $ | (31,044 | ) | $ | - | $ | (24,871 | ) | ||||||
Oil and
natural gas derivatives are valued by a third-party consultant
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. Interest rate swaps are
valued by a third-party consultant using modling techniques that include market
inputs such as interest rate yield curves.
Effective
January 1, 2008 the Company adopted SFAS No. 159, “The Fair Value Option for Financial
Assets and Financial Liabilities, including an amendment of SFAS No. 115”
(“SFAS No. 159”). SFAS No. 159 allows companies to choose to measure
financial instruments and other items at fair value that previously were not
required to be measured at fair value. The Company elected not to
present any financial instruments or other items at fair value that were not
required to be at fair value prior to the adoption of SFAS No.
159.
ITEM 2. MANAGEMENT'S DISCUSSION AND
ANALYSIS
OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The
following is management’s discussion and analysis of certain significant factors
that have affected certain aspects of the Company’s financial position and
results of operations during the periods included in the accompanying unaudited
financial statements. You should read this in conjunction with the
discussion under “Management’s Discussion and Analysis of Financial Condition
and Results of Operations” and the audited financial statements included in our
Annual Report on Form 10-K for the year ended December 31, 2007 and the
unaudited financial statements included elsewhere herein.
General
Overview
Our first
quarter 2008 included record revenues of $53.6 million and record production of
6.3 Bcfe. The key drivers to our success for the three months ended
March 31, 2008 included the following:
Drilling
program. Our success is largely dependent on the results of
our drilling program. During the three months ended March 31, 2008,
we drilled 19 gross wells (14.0 net wells) with an apparent success rate of 100%
that was comprised of: (1) 15 gross wells (11.2 net wells) in the Barnett Shale
area and (2) four gross wells (2.8 net wells) in the onshore Gulf Coast
area. We also drilled three gross service wells (3.0 net wells) in
the Camp Hill area and one gross appraisal well (0.2 net wells) in the North
Sea.
Production. Our
first quarter production of 6.3 Bcfe, or 69.6 MMcfe/d was a record
high. The first quarter 2008 production increased 12% from the fourth
quarter 2007 production of 5.6 Bcfe and nearly doubled from the first quarter
2007 production of 3.2 Bcfe. The increase between first quarter 2008
and fourth quarter 2007 was due primarily to production from eight new wells
brought on line in the Barnett Shale during the first quarter
2008. The increase in the first quarter 2008 production compared to
the first quarter of 2007 was primarily attributable to 36 new company-operated
wells in the Barnett Shale that have commenced production since the first
quarter of 2007 and additional production from two new wells in the Gulf Coast
area, which began production in late first quarter 2007 and in the mid-second
quarter 2007, respectively. These increases were partially offset by
the natural decline of other properties.
Commodity
prices. Natural gas prices during the first quarter of 2008
were $8.06 per Mcf (excluding the impact of our hedges), $1.30 per Mcf, or 19%
higher than the price in the first quarter of 2007.
Capital
funding. In order to fund our growth, we have taken steps to
enhance our liquidity. In February 2008, we received approximately
$135.2 million in net proceeds from an underwritten public offering of 2.59
million shares of our common stock. The net proceeds were used in
part to pay down the outstanding debt of $85.0 million under the Senior Credit
Facility. As a result, we had borrowing capacity of $145.0 million
under the Senior Credit Facility at March 31, 2008.
Outlook
Our
outlook for the future remains positive. Production growth and strong
commodity prices are key to our future success and to continue our
success:
|
·
|
In the
last three quarters of 2008 we plan to drill 53 gross wells (50.9
net) in the Barnett Shale area, eleven gross wells (3.1 net) in the Gulf
Coast area, 37 gross wells (37.0 net) in our Camp Hill field (which
includes approximately 14 service wells), one gross (0.2 net) U.K. North
Sea appraisal wells and 29 gross wells (14.5 net) in other
areas. The actual number of wells drilled will vary depending
upon various factors, including the availability and cost of drilling
rigs, land and industry partner issues, our cash flow, success of drilling
programs, weather delays and other factors. If we drill the
number of wells we have budgeted for 2008, depreciation, depletion and
amortization, oil and natural gas operating expenses and production are
expected to increase over levels incurred in 2007. Our ability
to drill this number of wells is heavily dependent upon the timely access
to oilfield services, particularly drilling
rigs.
|
|
·
|
We
plan to continue the development of the Barnett Shale. We
currently have 25 gross (21.8 net) wells awaiting completion or pipeline
connections. We expect to bring these wells online in the
second and third quarter of 2008.
|
|
·
|
We
plan to continue the development of other new drilling programs in the
Floyd Shale in Mississippi, the Fayetteville Shale in Arkansas, the
Marcellus Shale in New York and Pennsylvania and the North
Sea.
|
|
·
|
We
expect to continue to hedge production to decrease our exposure to
reductions in natural gas and oil prices. At March 31, 2008, we
had hedged approximately 25,047,000 MMBtus of natural gas production
through 2010 and 27,500 Bbls of oil production through
2008.
|
Results
of Operations
Three
Months Ended March 31, 2008,
Compared
to the Three Months Ended March 31, 2007
Oil and
natural gas revenues for the three months ended March 31, 2008 increased 137% to
$53.6 million from $22.6 million for the same period in
2007. Production volumes for natural gas for the three months ended
March 31, 2008 increased 111% to 6.0 Bcf from 2.8 Bcf for the same period in
2007. Average natural gas prices, excluding the impact of the loss
from our cash settled derivatives of $0.1 million and gain of $2.3 million for
the quarters ended March 31, 2008 and 2007, respectively, increased to $8.06 per
Mcf in the first quarter of 2008 from $6.76 per Mcf in the same period in
2007. Average oil prices for the quarter ended March 31, 2008
increased 71% to $96.10 from $56.23 per barrel in the same period in
2007. The increase in natural gas production volume was due primarily
to new production from 36 company-operated wells in the Barnett Shale that
commenced production since the first quarter of 2007 and additional production
from two new wells in the Gulf Coast area which were brought online in late
first quarter 2007 and second quarter 2007, respectively. These
increases were partially offset by the natural decline of the
properties.
The
following table summarizes production volumes, average sales prices and
operating revenues (excluding the impact of derivatives) for the three months
ended March 31, 2008 and 2007:
|
For
the Three
|
2008
Period
|
|||||||||||||||
|
Months
Ended
|
Compared
to 2007 Period
|
|||||||||||||||
|
March
31,
|
Increase
|
%
Increase
|
||||||||||||||
|
2008
|
2007
|
(Decrease)
|
(Decrease)
|
|||||||||||||
|
Production
volumes
|
||||||||||||||||
|
Oil
and condensate (MBbls)
|
53 | 60 | (7 | ) | (12 | )% | ||||||||||
|
Natural
gas (MMcf)
|
6,014 | 2,845 | 3,169 | 111 | % | |||||||||||
|
Average
sales prices
|
||||||||||||||||
|
Oil
and condensate (per Bbl)
|
$ | 96.10 | $ | 56.23 | $ | 39.87 | 71 | % | ||||||||
|
Natural
gas (per Mcf)
|
8.06 | 6.76 | 1.30 | 19 | % | |||||||||||
|
Operating
revenues (In thousands)
|
||||||||||||||||
|
Oil
and condensate
|
$ | 5,095 | $ | 3,383 | $ | 1,712 | 51 | % | ||||||||
|
Natural
gas
|
48,465 | 19,229 | 29,236 | 152 | % | |||||||||||
|
Total
Operating Revenues
|
$ | 53,560 | $ | 22,612 | $ | 30,948 | 137 | % | ||||||||
Oil and
natural gas operating expenses for the three months ended March 31, 2008
increased 78% to $8.4 million from $4.7 million for the same period in 2007
primarily as a result of (1) higher lifting costs of $1.5 million primarily
attributable to increased production and the increased number of producing
wells, (2) increased transportation and other product costs of $1.5 million
mainly attributable to the Barnett Shale area and (3) increased severance tax
expense of $0.5 million associated with increased production.
Depreciation,
depletion and amortization (DD&A) expense for the three months ended March
31, 2008 increased 77% to $14.1 million ($2.22 per Mcfe) from $8.0 million
($2.51 per Mcfe) for the same period in 2007. This increase was
primarily due to an increase in production volumes partially offset by a
decrease in the DD&A rate attributable to lower overall finding costs of new
reserves.
General
and administrative expense for the three months ended March 31, 2008 increased
by $1.6 million to $6.5 million from $4.9 million for the corresponding period
in 2007 primarily as a result of (1) an increase of $0.7 million for
compensation and other employee-related expenses, (2) increased stock-based
compensation of $0.5 million due to increased issuance of stock awards and
higher stock prices and (3) increased legal and consulting fees of $0.3
million.
The net
loss on derivatives of $29.8 million in the first quarter of 2008 was comprised
of (1) $0.7 million of realized loss on net cash settled derivatives and (2)
$29.1 million of net unrealized mark-to-market loss on
derivatives. The net loss on derivatives of $5.7
million
in the first quarter of 2007 was comprised of (1) $2.4 million of realized gain
on net cash settled derivatives and (2) $8.1 million of net unrealized
mark-to-market loss on derivatives.
Interest
expense and capitalized interest for the three months ended March 31, 2008 were
$6.5 million and ($3.7) million, respectively, as compared to $6.2 million and
$(2.7) million for the same period in 2007.
Income
tax benefit increased to $2.5 million for the three months ended March 31, 2008
from $1.3 million for the same period in 2007 due to the change in net
loss.
Liquidity
and Capital Resources
Sources and Uses of
Cash. During the three months ended March 31, 2008, capital
expenditures, net of proceeds from property sales, exceeded our net cash
provided by operations. During the first quarter of 2008, we have
funded our capital expenditures with cash generated from operations, additional
borrowings under our Senior Credit Facility and proceeds from the issuance of
our common stock. Potential primary sources of future liquidity
include the following:
|
·
|
Cash
on hand and cash generated by operations. Cash flows from
operations are highly dependent on commodity prices and market conditions
for oil and gas field services. We hedge a portion of our
production to reduce the downside risk of declining natural gas and oil
prices.
|
|
·
|
Available
borrowings under the Senior Credit Facility. On December 20,
2007, the borrowing base availability under the Senior Credit Facility
increased from $117.0 million to $145.0 million. At April 30,
2008, cash available under the Senior Credit Facility was $106.0
million. The next borrowing base redetermination is scheduled
for May 2008 at which time we currently expect our borrowing base to
increase by a yet undetermined
amount.
|
|
·
|
Other
debt and equity offerings. In February 2008, we received $135.2
million from an underwritten public offering of 2,587,500 shares of our
common stock priced at $54.50 per share. As situations or
conditions arise, we may issue debt, equity or other instruments to
supplement our cash flows.
|
|
·
|
Asset
sales. In order to fund our drilling program, we may consider
the sale of certain properties or assets no longer deemed core to our
future growth.
|
Our
primary use of cash is capital expenditures related to our drilling
program. We have budgeted approximately $250 million on our 2008
drilling program and $50 million from lease and seismic
acquisitions. For the three months ended March 31, 2008, we have
incurred approximately $115.6 million in capital expenditures.
Overview of Cash Flow
Activities. Cash flows provided by operating activities were
$41.2 million and $19.2 million for the three months ended March 31, 2008 and
2007, respectively. The increase was primarily due to increased
production and higher oil and natural gas commodity prices.
Cash
flows used in investing activities were $125.1 and $44.2 million for the three
months ended March 31, 2008 and 2007, respectively, and related primarily to oil
and gas property expenditures. During the first quarter of 2008, we
invested approximately $115 million in oil and gas properties, including $58
million related to drilling activities and $53 million related to leasehold
acquisitions.
Net cash
provided by financing activities for the three months ended March 31, 2008 was
$100.7 million and related primarily to net proceeds of $135.2 million from the
issuance of common stock in February 2008 (see Note 6 of the Notes to
Consolidated Financial Statements for further discussion of this
transaction). These cash proceeds were partially offset by the
paydown of the Senior Credit Facility. Net cash provided by financing
activities for the three months ended March 31, 2007 was $30.6 million and
related primarily to the additional borrowings of $75.0 million under the Second
Lien Credit Facility in January 2007, partially offset by $41.6 million of debt
repayments.
Liquidity/Cash Flow
Outlook. We currently believe that the proceeds from the
February 2008 equity offering, cash generated from operations along with cash on
hand and the cash available under the Senior Credit Facility is sufficient to
fund our immediate needs but we may need to seek other financing alternatives,
including additional debt or equity financings, to fully fund our current 2008
capital expenditures budget, especially if there are additional capital needs in
connection with our Marcellus Shale or U.K. North Sea operations or new
opportunities in our Other Shale areas.
We may
not be able to obtain financing needed in the future on terms that would be
acceptable to us. If we cannot obtain adequate financing, we may be
required to limit or defer our planned oil and natural gas exploration and
development program, thereby adversely affecting the recoverability and ultimate
value of our oil and natural gas properties.
Contractual
Obligations
During
the first quarter of 2008, we entered into a firm drilling agreement for one rig
over a three-year term scheduled to begin in the second quarter of
2008. The estimated obligation is approximately $25 million per year
through 2010.
Effects
of Inflation and Changes in Price
Our
results of operations and cash flows are affected by changing oil and natural
gas prices. If the price of oil and natural gas increases
(decreases), there could be a corresponding increase (decrease) in
revenues. In addition, we are affected by increases in the costs of
services and equipment that we employ to explore for and produce oil and natural
gas due to high activity and a relative scarcity of equipment. We
generally expect these costs and expenses to continue to increase if oil and
natural gas prices remain strong and drilling activity remains
high. In the recent historical past, inflation has had a minimal
effect on us.
Recently
Adopted Accounting Pronouncements
We
adopted the Financial Accounting Standards Statement No. 157, “Fair Value Measurement”
(“SFAS No. 157”), effective January 1, 2008. SFAS No. 157 provides a
framework for measuring fair value and enhances related
disclosures. The implementation of SFAS No. 157 did not change our
current valuation method and did not have a material effect on our consolidated
financial position or results in operations. We included additional
disclosures in the Notes to Consolidated Financial Statements around our assets
and liabilities measured at fair value on the balance sheet
date.
Recently
Issued Accounting Pronouncements
In March
2008, the FASB issued SFAS No. 161, Disclosures about Derivative
Instruments and Hedging Activities (“SFAS No. 161”). This
standard is intended to improve financial reporting by requiring 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 under SFAS No. 133; and how derivative instruments and related
hedged items affect its financial position, financial performance and cash
flows. The provisions of SFAS No. 161 are effective for financial
statements issued for fiscal years and interim periods beginning after November
15, 2008. We do not believe the adoption of SFAS No. 161 will have a
significant effect on our consolidated financial position, results of operations
or cash flows.
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
$2.1 million and $1.4 million for the three months ended March 31, 2008 and
2007, respectively. We expense maintenance and repairs as they are
incurred.
We
amortize natural gas and oil properties based on the unit-of-production method
using estimates of proved reserve quantities. We do not amortize
investments in unproved properties until proved reserves associated with the
projects can be determined or until these investments are
impaired. We periodically evaluate, on a property-by-property basis,
unevaluated properties for impairment. If the results of an
assessment indicate that the properties are impaired, we add the amount of
impairment to the proved natural gas and oil property costs to be
amortized. The amortizable base includes estimated future development
costs and, where significant, dismantlement, restoration and abandonment costs,
net of estimated salvage values. The depletion rate per Mcfe for the
three months ended March 31, 2008 and 2007 was $2.19 and $2.47,
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.
In
connection with our March 31, 2008 Full Cost Ceiling test computation, a price
sensitivity study also indicated that a 10% increase or decrease in commodity
prices at March 31, 2008 would have increased or decreased the Full Cost Ceiling
test cushion by approximately $97 million. The aforementioned price
sensitivity is as of March 31, 2008 and, accordingly, does not include any
potential changes in reserve values due to subsequent performance or events,
such as commodity prices, reserve revisions and drilling results.
The Full
Cost Ceiling cushion at the end of March 31, 2008 of approximately $395 million
was based upon average realized oil, natural gas liquids and natural gas prices
of $97.28 per Bbl, $55.93 per Bbl and $8.15 per Mcf, respectively, or a volume
weighted average price of $57.06 per BOE. This cushion, however,
would have been zero on such date at an estimated volume weighted average price
of $33.85 per BOE. A BOE means one barrel of oil equivalent,
determined using the ratio of six Mcf of natural gas to one Bbl of oil,
condensate or natural gas liquids, which approximates the relative energy
content of oil, condensate and natural gas liquids as compared to natural
gas. Prices have historically been higher or substantially higher,
more often for oil than natural gas on an energy equivalent basis, although
there have been periods in which they have been lower or substantially
lower.
Under the
full cost method of accounting, the depletion rate is the current period
production as a percentage of the total proved reserves. Total proved
reserves include both proved developed and proved undeveloped
reserves. The depletion rate is applied to the net book value of our
oil and natural gas properties, excluding unevaluated costs, plus estimated
future development costs and salvage value, to calculate the depletion
expense. Proved reserves materially impact depletion
expense. If the proved reserves decline, then the depletion rate (the
rate at which we record depletion expense) increases, reducing net
income.
We have a
significant amount of proved undeveloped reserves. We had 185.8 Bcfe
of proved undeveloped reserves at December 31, 2007, representing 53% of our
total proved reserves. As of December 31, 2007, a portion of these
proved undeveloped reserves, or approximately 38.1 Bcfe, are attributable to our
Camp Hill properties that we acquired in 1994. The estimated future
development costs to develop our proved undeveloped reserves on our Camp Hill
properties are relatively low, on a per Mcfe basis, when compared to the
estimated future development costs to develop our proved undeveloped reserves on
our other oil and natural gas properties. Furthermore, the average
depletable life (the estimated time that it will take to produce all recoverable
reserves) of our Camp Hill properties is considerably longer, or approximately
15 years, when compared to the depletable life of our remaining oil and natural
gas properties of approximately 10 years. Accordingly, the
combination of a relatively low ratio of future development costs and a
relatively long depletable life on our Camp Hill properties has resulted in a
relatively low overall historical depletion rate and DD&A
expense. This has resulted in a capitalized cost basis associated
with producing properties being depleted over a longer period than the
associated production and revenue stream, causing the build-up of nondepleted
capitalized costs associated with properties that have been completely
depleted. This combination of factors, in turn, has had a favorable
impact on our earnings, which have been higher than they would have been had the
Camp Hill properties not resulted in a relatively low overall depletion rate and
DD&A expense and longer depletion period. As a hypothetical
illustration of this impact, the removal of our Camp Hill proved undeveloped
reserves starting January 1, 2002 would have reduced our earnings by (1) an
estimated $11.2 million in 2002 (comprised of after-tax charges for a $7.1
million full cost ceiling impairment and a $4.1 million depletion expense
increase), (2) an estimated $5.9 million in 2003 (due to higher depletion
expense), (3) an estimated $3.4 million in 2004 (due to higher depletion
expense), (4) an estimated $6.9 million in 2005 (due to higher depletion
expense), (5) an estimated $0.7 million in 2006 (due to higher depletion
expense) and (6) an estimated $2.0 million in 2007 (due to higher depletion
expense).
We expect
our relatively low historical depletion rate to continue until the high level of
nonproducing reserves to total proved reserves is reduced and the life of our
proved developed reserves is extended through development drilling and/or the
significant addition of new proved producing reserves through acquisition or
exploration. If our level of total proved reserves, finding costs and
current prices were all to remain constant, this continued build-up of
capitalized cost increases the probability of a ceiling test write-down in the
future.
We
depreciate other property and equipment using the straight-line method based on
estimated useful lives ranging from five to ten years.
For
information regarding our other critical accounting policies, see the 2007 Form
10-K.
Volatility
of Oil and Natural Gas Prices
Our
revenues, future rate of growth, results of operations, financial condition and
ability to borrow funds or obtain additional capital, as well as the carrying
value of our properties, are substantially dependent upon prevailing prices of
oil and natural gas.
We
periodically review the carrying value of our oil and natural gas properties
under the full cost method of accounting rules. See “—Critical Accounting
Policies—Oil and Natural Gas Properties.”
To
mitigate some of our commodity price risk, we engage periodically in certain
other limited derivative activities including price swaps, costless collars and,
occasionally, put options, in order to establish some price floor
protection.
The
following table includes oil and natural gas positions settled during the
three-month periods ended March 31, 2008 and 2007, and the unrealized
gain/(loss) associated with the outstanding oil and natural gas derivatives at
March 31, 2008 and 2007.
|
Three
months ended
|
||||||||
|
March
31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Oil
positions settled (Bbls)
|
18,200 | - | ||||||
|
Natural
gas positions settled (MMBtu)
|
4,132,000 | 1,887,000 | ||||||
|
Realized
gain/(loss) ($ millions) (1)
|
$ | (0.5 | ) | $ | 2.3 | |||
|
Unrealized
loss ($ millions) (1)
|
$ | (26.9 | ) | $ | (8.0 | ) | ||
__________
(1)
Included in net loss on derivatives, net in the Consolidated Statements of
Operations.
At March
31, 2008, we had the following outstanding natural gas derivative
positions:
|
Natural
Gas
|
Natural
Gas
|
|||||||||||||||||||
|
Swaps
|
Collars
|
|||||||||||||||||||
|
Average
|
Average
|
Average
|
||||||||||||||||||
|
Quarter
|
MMbtu
|
Fixed
Price(1)
|
MMBtu
|
Floor
Price(1)
|
Ceiling
Price(1)
|
|||||||||||||||
|
Second
Quarter 2008
|
273,000 | $ | 7.94 | 3,185,000 | $ | 7.14 | $ | 8.83 | ||||||||||||
|
Third
Quarter 2008
|
276,000 | 7.94 | 3,036,000 | 7.13 | 8.82 | |||||||||||||||
|
Fourth
Quarter 2008
|
276,000 | 7.94 | 3,036,000 | 7.13 | 8.82 | |||||||||||||||
|
First
Quarter 2009
|
- | - | 2,520,000 | 7.37 | 9.10 | |||||||||||||||
|
Second
Quarter 2009
|
- | - | 2,548,000 | 7.12 | 8.85 | |||||||||||||||
|
Third
Quarter 2009
|
- | - | 2,576,000 | 7.16 | 8.88 | |||||||||||||||
|
Fourth
Quarter 2009
|
- | - | 2,576,000 | 7.17 | 8.90 | |||||||||||||||
|
First
Quarter 2010
|
- | - | 1,170,000 | 7.55 | 9.27 | |||||||||||||||
|
Second
Quarter 2010
|
- | - | 1,183,000 | 7.07 | 8.79 | |||||||||||||||
|
Third
Quarter 2010
|
- | - | 1,196,000 | 7.19 | 8.90 | |||||||||||||||
|
Fourth
Quarter 2010
|
- | - | 1,196,000 | 7.25 | 8.96 | |||||||||||||||
|
Oil
Collars
|
||||||||||||
|
Average
|
Average
|
|||||||||||
|
Quarter
|
Bbls
|
Floor
Price(2)
|
Ceiling
Price (2)
|
|||||||||
|
Second
Quarter 2008
|
9,100 | $ | 70.00 | $ | 76.75 | |||||||
|
Third
Quarter 2008
|
9,200 | 70.00 | 76.75 | |||||||||
|
Fourth
Quarter 2008
|
9,200 | 70.00 | 76.75 | |||||||||
__________
|
(1)
|
Based
on Houston Ship Channel and Waha spot
prices.
|
|
(2)
|
Based
on West Texas intermediate index
prices.
|
While the
use of hedging arrangements limits the downside risk of adverse price movements,
it may also limit our ability to benefit from increases in the prices of natural
gas and oil. We enter into the majority of our derivatives
transactions with two counterparties and have a netting agreement in place with
those counterparties. We do not obtain collateral to support the
agreements but monitor the financial viability of counterparties and believe our
credit risk is minimal on these transactions. Under these
arrangements, payments are received or made based on the differential between a
fixed and a variable commodity price. These agreements are settled in
cash at expiration or exchanged for physical delivery contracts. In
the event of nonperformance, we would be exposed again to price
risk. We have additional risk of financial loss because the price
received for the product at the actual physical delivery point may differ from
the prevailing price at the delivery point required for settlement of the
hedging transaction. Moreover, our derivatives arrangements generally
do not apply to all of our production and thus provide only partial price
protection against declines in commodity prices. We expect that the
amount of our hedges will vary from time to time.
Our
natural gas derivative transactions are generally settled based upon the average
of the reporting settlement prices on the Houston Ship Channel and Waha indices
for the last three trading days of a particular contract month. Our
oil derivative transactions are generally settled based on the average reporting
settlement prices on the West Texas Intermediate index for each trading day of a
particular calendar month. For the first quarter of 2008, a 10%
change in the price per Mcf of natural gas sold would have changed revenue by
$4.8 million. A 10% change in the price per barrel of oil would have
changed revenue by $0.5 million.
Forward
Looking Statements
The
statements contained in all parts of this document, including, but not limited
to, those relating to our schedule, targets, estimates or results of future
drilling, including the number, timing and results of wells, budgeted wells,
increases in wells, the timing and risk involved in drilling follow-up wells,
expected working or net revenue interests, planned expenditures, prospects
budgeted and other future capital expenditures, risk profile of oil and natural
gas exploration, acquisition of 3-D seismic data (including number, timing and
size of projects), planned evaluation of prospects, probability of prospects
having oil and natural gas, expected production or reserves, increases in
reserves, acreage, working capital requirements, hedging activities, the ability
of expected sources of liquidity to implement the Company’s business strategy,
future exploration activity, production rates, 2008 drilling program, growth in
production, development of new drilling programs, hedging of production and
exploration and development expenditures, Camp Hill development and all and any
other statements regarding future operations, financial results, business plans
and cash needs, potential borrowing base increases and other statements that are
not historical facts are forward looking statements. When used in
this document, the words “anticipate,” “estimate,” “expect,” “may,” “project,”
“believe” and similar expressions are intended to be among the statements that
identify forward looking statements. Such statements involve risks
and uncertainties, including, but not limited to, those relating to the
Company's dependence on its exploratory drilling activities, the volatility of
oil and natural gas prices, the need to replace reserves depleted by production,
operating risks of oil and natural gas operations, the Company's dependence on
its key personnel, factors that affect the Company's ability to manage its
growth and achieve its business strategy, risks relating to limited operating
history, technological changes, significant capital requirements of the Company,
the potential impact of government regulations, litigation, competition, the
uncertainty of reserve information and future net revenue estimates, property
acquisition risks, availability of equipment, weather, availability of
financing, 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 the Company's Annual Report on Form 10-K for the year ended December
31, 2007 and other filings with the Securities and Exchange
Commission. Should one or more of these risks or uncertainties
materialize, or should underlying assumptions prove incorrect, actual outcomes
may vary materially from those indicated. All subsequent written and
oral forward-looking statements attributable to us or persons acting on our
behalf are expressly qualified in their entirety by reference to these risks and
uncertainties. You should not place undue reliance on forward-looking
statements. Each forward-looking statement speaks only as of the date
of the particular statement and the Company undertakes no obligation to update
or revise any forward-looking statement.
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 for the year ended December 31, 2007. There have been no
material changes to the disclosure regarding our exposure to certain market
risks made in the Annual Report on Form 10-K. For additional
information regarding our long-term debt, see Note 2 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. They
concluded that the controls and procedures were effective as of March 31, 2008
to provide reasonable assurance that the information required to be disclosed by
the Company in reports it files under the Exchange Act is recorded, processed,
summarized and reported within the time periods specified in the rules and forms
of the SEC. While our disclosure controls and procedures provide
reasonable assurance that the appropriate information will be available on a
timely basis, this assurance is subject to limitations inherent in any control
system, no matter how well it may be designed or administered.
Changes in Internal
Controls. There was no change in our internal control over
financial reporting during the quarter ended March 31, 2008, that materially
affected, or is reasonably likely to materially affect, our internal control
over financial reporting.
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 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 for the year ended December 31, 2007, 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.
Item 2 -
Unregistered Sales of Equity Securities and Use of Proceeds
The
following table presents information regarding the Company’s purchases of its
common stock on a monthly basis during the first quarter of 2008:
|
(c)
Total Number of
|
(d)
Maximum Number
|
|||||||||||||||
|
Shares
Purchased as
|
(or
Appropriate Dollar
|
|||||||||||||||
|
(a)
Total Number
|
Part
of Publicly
|
Value)
of Shares that May
|
||||||||||||||
|
of
Shares
|
(b)
Average Price
|
Announced
Plans or
|
Yet
Be Purchased Under
|
|||||||||||||
|
Period
|
Purchased(1)
|
Paid
Per Share
|
Programs
|
the
Plan or Programs
|
||||||||||||
|
January
2008
|
285 | $ | 46.61 | - | - | |||||||||||
|
February
2008
|
459 | 48.83 | - | - | ||||||||||||
|
March
2008
|
354 | 59.85 | - | - | ||||||||||||
|
Total
|
1,098 | $ | 51.81 | - | - | |||||||||||
__________
|
|
(1) The
1,098 shares related to the surrender of shares of common stock to satisfy
tax withholding obligations in connection with the vesting of restricted
stock issued to employees under our long-term incentive
plan.
|
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
|
—
|
|
†
|
Incorporated
herein by reference as indicated.
|
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: May
8, 2008
|
By: /s/S. P. Johnson,
IV
|
|
President
and Chief Executive Officer
|
|
|
(Principal
Executive Officer)
|
|
|
Date: May
8, 2008
|
By: /s/Paul F.
Boling
|
|
Chief
Financial Officer
|
|
|
(Principal
Financial and Accounting Officer)
|
-23-