UNITED
STATES
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, 2009
or
[ ]
|
TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
|
For the
transition period from _______________ to _______________
|
Commission
file number: 001-31899
WHITING
PETROLEUM CORPORATION
|
|
|
(Exact
name of registrant as specified in its charter)
|
|
|
|
|
Delaware
|
|
20-0098515
|
(State
or other jurisdiction
of
incorporation or organization)
|
|
(I.R.S.
Employer
Identification
No.)
|
|
|
|
1700
Broadway, Suite 2300
Denver,
Colorado
|
|
80290-2300
|
(Address
of principal executive offices)
|
|
(Zip
code)
|
|
|
|
|
(303)
837-1661
|
|
|
(Registrant’s
telephone number, including area code)
|
|
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 T 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 (§232.405 of this
chapter) 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 T
|
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 T
Number of
shares of the registrant’s common stock outstanding at April 15,
2009: 50,841,400 shares.
Unless
the context otherwise requires, the terms “we,” “us,” “our” or “ours” when used
in this report refer to Whiting Petroleum Corporation, together with its
consolidated subsidiaries. When the context requires, we refer to
these entities separately.
We have
included below the definitions for certain terms used in this
report:
“Bbl” - One stock tank
barrel, or 42 U.S. gallons liquid volume, used in this report in reference to
oil and other liquid hydrocarbons.
“Bcf” - One billion cubic
feet of natural gas.
“BOE” - One stock tank barrel
equivalent of oil, calculated by converting natural gas volumes to equivalent
oil barrels at a ratio of six Mcf to one Bbl of oil.
“MBbl” - One thousand barrels
of oil or other liquid hydrocarbons.
“MBOE” - One thousand
BOE.
“MBOE/d” - One thousand BOE
per day.
“Mcf” - One thousand cubic
feet of natural gas.
“MMBbl” - One million barrels
of oil or other liquid hydrocarbons.
“MMBOE” - One million
BOE.
“MMBtu” - One million British
Thermal Units.
“MMcf” - One million cubic
feet of natural gas.
“MMcf/d” - One MMcf of
natural gas per day.
“plugging and abandonment” -
Refers to the sealing off of fluids in the strata penetrated by a well so that
the fluids from one stratum will not escape into another or to the
surface. Regulations of many states require plugging of abandoned
wells.
“working interest” - The
interest in a crude oil and natural gas property (normally a leasehold interest)
that gives the owner the right to drill, produce and conduct operations on the
property; to share in production, subject to all royalties, overriding royalties
and other burdens; and to share in all costs of exploration, development,
operations and all risks in connection therewith.
PART I –
FINANCIAL INFORMATION
|
Consolidated Financial
Statements
|
WHITING PETROLEUM CORPORATION
CONSOLIDATED
BALANCE SHEETS (Unaudited)
(In
thousands)
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
7,013 |
|
|
$ |
9,624 |
|
Accounts
receivable trade, net
|
|
|
94,225 |
|
|
|
123,386 |
|
Derivative
assets
|
|
|
44,647 |
|
|
|
46,780 |
|
Deposits
on oil field equipment
|
|
|
11,317 |
|
|
|
17,170 |
|
Prepaid
expenses and other
|
|
|
17,035 |
|
|
|
20,114 |
|
Total
current assets
|
|
|
174,237 |
|
|
|
217,074 |
|
PROPERTY
AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
Oil
and gas properties, successful efforts method:
|
|
|
|
|
|
|
|
|
Proved
properties
|
|
|
4,604,617 |
|
|
|
4,423,197 |
|
Unproved
properties
|
|
|
104,109 |
|
|
|
106,436 |
|
Other
property and equipment
|
|
|
106,813 |
|
|
|
91,099 |
|
Total
property and equipment
|
|
|
4,815,539 |
|
|
|
4,620,732 |
|
Less
accumulated depreciation, depletion and amortization
|
|
|
(984,652 |
) |
|
|
(886,065 |
) |
Total
property and equipment, net
|
|
|
3,830,887 |
|
|
|
3,734,667 |
|
DEBT
ISSUANCE COSTS
|
|
|
9,741 |
|
|
|
10,779 |
|
DERIVATIVE
ASSETS
|
|
|
39,214 |
|
|
|
38,104 |
|
OTHER
LONG-TERM ASSETS
|
|
|
26,116 |
|
|
|
28,457 |
|
TOTAL
|
|
$ |
4,080,195 |
|
|
$ |
4,029,081 |
|
|
|
|
|
|
|
|
|
|
See
notes to consolidated financial statements.
|
|
|
|
|
|
(Continued)
|
|
WHITING
PETROLEUM CORPORATION
CONSOLIDATED
BALANCE SHEETS (Unaudited)
(In
thousands, except share and per share data)
|
|
|
|
|
|
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
Accounts
payable
|
|
$ |
46,752 |
|
|
$ |
64,610 |
|
Accrued
capital expenditures
|
|
|
47,592 |
|
|
|
84,960 |
|
Accrued
liabilities
|
|
|
47,107 |
|
|
|
45,359 |
|
Accrued
interest
|
|
|
19,919 |
|
|
|
9,673 |
|
Oil
and gas sales payable
|
|
|
23,045 |
|
|
|
35,106 |
|
Accrued
employee compensation and benefits
|
|
|
4,958 |
|
|
|
41,911 |
|
Production
taxes payable
|
|
|
14,487 |
|
|
|
20,038 |
|
Deferred
gain on sale
|
|
|
14,017 |
|
|
|
14,650 |
|
Derivative
liabilities
|
|
|
13,456 |
|
|
|
17,354 |
|
Deferred
income taxes
|
|
|
15,835 |
|
|
|
15,395 |
|
Tax
sharing liability
|
|
|
2,112 |
|
|
|
2,112 |
|
Total
current liabilities
|
|
|
249,280 |
|
|
|
351,168 |
|
NON-CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
1,189,556 |
|
|
|
1,239,751 |
|
Deferred
income taxes
|
|
|
376,625 |
|
|
|
390,902 |
|
Deferred
gain on sale
|
|
|
69,834 |
|
|
|
73,216 |
|
Production
Participation Plan liability
|
|
|
66,562 |
|
|
|
66,166 |
|
Asset
retirement obligations
|
|
|
59,838 |
|
|
|
47,892 |
|
Tax
sharing liability
|
|
|
21,984 |
|
|
|
21,575 |
|
Derivative
liabilities
|
|
|
23,884 |
|
|
|
28,131 |
|
Other
long-term liabilities
|
|
|
3,411 |
|
|
|
1,489 |
|
Total
non-current liabilities
|
|
|
1,811,694 |
|
|
|
1,869,122 |
|
COMMITMENTS
AND CONTINGENCIES
|
|
|
|
|
|
|
|
|
STOCKHOLDERS’
EQUITY:
|
|
|
|
|
|
|
|
|
Common
stock, $0.001 par value; 75,000,000 shares authorized, 51,352,981 and
42,582,100 shares issued as of March 31, 2009 and December 31, 2008,
respectively
|
|
|
51 |
|
|
|
43 |
|
Additional
paid-in capital
|
|
|
1,206,227 |
|
|
|
971,310 |
|
Accumulated
other comprehensive income
|
|
|
36,535 |
|
|
|
17,271 |
|
Retained
earnings
|
|
|
776,408 |
|
|
|
820,167 |
|
Total
stockholders’ equity
|
|
|
2,019,221 |
|
|
|
1,808,791 |
|
TOTAL
|
|
$ |
4,080,195 |
|
|
$ |
4,029,081 |
|
|
|
|
|
|
|
|
|
|
See
notes to consolidated financial statements.
|
|
|
|
|
|
(Concluded)
|
|
WHITING PETROLEUM CORPORATION
CONSOLIDATED
STATEMENTS OF INCOME (Unaudited)
(In
thousands, except per share data)
|
|
Three
Months Ended
|
|
|
|
|
|
|
|
|
REVENUES
AND OTHER INCOME:
|
|
|
|
|
|
|
Oil
and natural gas sales
|
|
$ |
146,175 |
|
|
$ |
286,731 |
|
Gain
(loss) on oil and natural gas hedging activities
|
|
|
13,450 |
|
|
|
(22,912 |
) |
Amortization
of deferred gain on sale
|
|
|
4,099 |
|
|
|
- |
|
Interest
income and other
|
|
|
115 |
|
|
|
231 |
|
Total
revenues and other income
|
|
|
163,839 |
|
|
|
264,050 |
|
COSTS
AND EXPENSES:
|
|
|
|
|
|
|
|
|
Lease
operating
|
|
|
60,954 |
|
|
|
55,706 |
|
Production
taxes
|
|
|
9,519 |
|
|
|
17,686 |
|
Depreciation,
depletion and amortization
|
|
|
100,034 |
|
|
|
50,511 |
|
Exploration
and impairment
|
|
|
17,314 |
|
|
|
10,984 |
|
General
and administrative
|
|
|
8,980 |
|
|
|
11,615 |
|
Interest
expense
|
|
|
14,680 |
|
|
|
15,546 |
|
Change
in Production Participation Plan liability
|
|
|
396 |
|
|
|
6,157 |
|
(Gain)
loss on mark-to-market derivatives
|
|
|
21,765 |
|
|
|
(2,937 |
) |
Total
costs and expenses
|
|
|
233,642 |
|
|
|
165,268 |
|
INCOME
(LOSS) BEFORE INCOME TAXES
|
|
|
(69,803 |
) |
|
|
98,782 |
|
INCOME
TAX EXPENSE (BENEFIT):
|
|
|
|
|
|
|
|
|
Current
|
|
|
(539 |
) |
|
|
1,709 |
|
Deferred
|
|
|
(25,505 |
) |
|
|
34,759 |
|
Total
income tax expense (benefit)
|
|
|
(26,044 |
) |
|
|
36,468 |
|
NET
INCOME (LOSS)
|
|
$ |
(43,759 |
) |
|
$ |
62,314 |
|
NET
INCOME (LOSS) PER COMMON SHARE, BASIC AND DILUTED
|
|
$ |
(0.92 |
) |
|
$ |
1.47 |
|
WEIGHTED
AVERAGE SHARES OUTSTANDING, BASIC
|
|
|
47,600 |
|
|
|
42,272 |
|
WEIGHTED
AVERAGE SHARES OUTSTANDING, DILUTED
|
|
|
47,600 |
|
|
|
42,406 |
|
|
|
|
|
|
|
|
|
|
See
notes to consolidated financial statements.
|
|
|
|
|
|
|
|
|
WHITING PETROLEUM CORPORATION
CONSOLIDATED
STATEMENTS OF CASH FLOWS (Unaudited)
(In
thousands)
|
|
Three
Months Ended
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income (loss)
|
|
$ |
(43,759 |
) |
|
$ |
62,314 |
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
100,034 |
|
|
|
50,511 |
|
Deferred
income tax (benefit) expense
|
|
|
(25,505 |
) |
|
|
34,759 |
|
Amortization
of debt issuance costs and debt discount
|
|
|
1,173 |
|
|
|
1,217 |
|
Accretion
of tax sharing liability
|
|
|
409 |
|
|
|
311 |
|
Stock-based
compensation
|
|
|
1,142 |
|
|
|
1,432 |
|
Amortization
of deferred gain on sale
|
|
|
(4,099 |
) |
|
|
- |
|
Unproved
leasehold and oil and gas property impairments
|
|
|
4,681 |
|
|
|
2,572 |
|
Change
in Production Participation Plan liability
|
|
|
396 |
|
|
|
6,157 |
|
Unrealized
(gain) loss on mark-to-market derivatives
|
|
|
23,295 |
|
|
|
(2,937 |
) |
Other
non-current
|
|
|
1,496 |
|
|
|
(3,316 |
) |
Changes
in current assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts
receivable trade
|
|
|
30,521 |
|
|
|
(28,687 |
) |
Prepaid
expenses and other
|
|
|
8,932 |
|
|
|
(10,287 |
) |
Accounts
payable and accrued liabilities
|
|
|
(19,507 |
) |
|
|
8,771 |
|
Accrued
interest
|
|
|
10,246 |
|
|
|
8,857 |
|
Other
current liabilities
|
|
|
(55,208 |
) |
|
|
(9,221 |
) |
Net
cash provided by operating activities
|
|
|
34,247 |
|
|
|
122,453 |
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Cash
acquisition capital expenditures
|
|
|
(20,733 |
) |
|
|
(9,747 |
) |
Drilling
and development capital expenditures
|
|
|
(201,151 |
) |
|
|
(160,988 |
) |
Proceeds
from sale of oil and gas properties
|
|
|
- |
|
|
|
234 |
|
Other
|
|
|
84 |
|
|
|
- |
|
Net
cash used in investing activities
|
|
|
(221,800 |
) |
|
|
(170,501 |
) |
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Issuance
of common stock
|
|
|
234,942 |
|
|
|
- |
|
Long-term
borrowings under credit agreement
|
|
|
150,000 |
|
|
|
130,000 |
|
Repayments
of long-term borrowings under credit agreement
|
|
|
(200,000 |
) |
|
|
(90,000 |
) |
Net
cash provided by financing activities
|
|
|
184,942 |
|
|
|
40,000 |
|
NET
CHANGE IN CASH AND CASH EQUIVALENTS
|
|
|
(2,611 |
) |
|
|
(8,048 |
) |
CASH
AND CASH EQUIVALENTS:
|
|
|
|
|
|
|
|
|
Beginning
of period
|
|
|
9,624 |
|
|
|
14,778 |
|
End
of period
|
|
$ |
7,013 |
|
|
$ |
6,730 |
|
SUPPLEMENTAL
CASH FLOW DISCLOSURES:
|
|
|
|
|
|
|
|
|
Cash
paid (refunded) for income taxes
|
|
$ |
94 |
|
|
$ |
(3 |
) |
Cash
paid for interest
|
|
$ |
2,852 |
|
|
$ |
5,161 |
|
NONCASH
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Accrued
capital expenditures during the period
|
|
$ |
47,592 |
|
|
$ |
74,556 |
|
|
|
|
|
|
|
|
|
|
See
notes to consolidated financial statements.
|
|
|
|
|
|
|
|
|
WHITING PETROLEUM CORPORATION
CONSOLIDATED
STATEMENTS OF STOCKHOLDERS’ EQUITY
AND
COMPREHENSIVE INCOME (Unaudited)
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
Paid-in Capital
|
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
|
|
|
Total
Stockholders’ Equity
|
|
|
Comprehensive
Income
(Loss)
|
|
BALANCES-January
1, 2008
|
|
|
42,480 |
|
|
$ |
42 |
|
|
$ |
968,876 |
|
|
$ |
(46,116 |
) |
|
$ |
568,024 |
|
|
$ |
1,490,826 |
|
|
|
|
Net
income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
252,143 |
|
|
|
252,143 |
|
|
$ |
252,143 |
|
Change
in derivative fair values, net of taxes of $1,812
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(3,072 |
) |
|
|
- |
|
|
|
(3,072 |
) |
|
|
(3,072 |
) |
Realized
loss on settled derivative contracts, net of taxes of
$39,903
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
67,652 |
|
|
|
- |
|
|
|
67,652 |
|
|
|
67,652 |
|
Ineffectiveness
gain on hedging activities, net of taxes of $703
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1,193 |
) |
|
|
- |
|
|
|
(1,193 |
) |
|
|
(1,193 |
) |
Restricted
stock issued
|
|
|
139 |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
Restricted
stock forfeited
|
|
|
(7 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Restricted
stock used for tax withholdings
|
|
|
(30 |
) |
|
|
- |
|
|
|
(1,743 |
) |
|
|
- |
|
|
|
- |
|
|
|
(1,743 |
) |
|
|
- |
|
Stock-based
compensation
|
|
|
- |
|
|
|
- |
|
|
|
4,177 |
|
|
|
- |
|
|
|
- |
|
|
|
4,177 |
|
|
|
- |
|
BALANCES-December
31, 2008
|
|
|
42,582 |
|
|
|
43 |
|
|
|
971,310 |
|
|
|
17,271 |
|
|
|
820,167 |
|
|
|
1,808,791 |
|
|
$ |
315,530 |
|
Net
loss
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(43,759 |
) |
|
|
(43,759 |
) |
|
|
(43,759 |
) |
Change
in derivative fair values, net of taxes of $7,706
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
13,302 |
|
|
|
- |
|
|
|
13,302 |
|
|
|
13,302 |
|
Realized
gain on settled derivative contracts, net of taxes of
$4,933
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(8,517 |
) |
|
|
- |
|
|
|
(8,517 |
) |
|
|
(8,517 |
) |
Ineffectiveness
loss on hedging activities, net of taxes of $8,387
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
14,479 |
|
|
|
- |
|
|
|
14,479 |
|
|
|
14,479 |
|
Issuance
of stock, secondary offering
|
|
|
8,450 |
|
|
|
8 |
|
|
|
234,934 |
|
|
|
- |
|
|
|
- |
|
|
|
234,942 |
|
|
|
- |
|
Restricted
stock issued
|
|
|
351 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Restricted
stock forfeited
|
|
|
(3 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Restricted
stock used for tax withholdings
|
|
|
(27 |
) |
|
|
- |
|
|
|
(644 |
) |
|
|
- |
|
|
|
- |
|
|
|
(644 |
) |
|
|
- |
|
Tax
effect from restricted stock vesting
|
|
|
- |
|
|
|
- |
|
|
|
(515 |
) |
|
|
- |
|
|
|
- |
|
|
|
(515 |
) |
|
|
- |
|
Stock-based
compensation
|
|
|
- |
|
|
|
- |
|
|
|
1,142 |
|
|
|
- |
|
|
|
- |
|
|
|
1,142 |
|
|
|
- |
|
BALANCES-March
31, 2009
|
|
|
51,353 |
|
|
$ |
51 |
|
|
$ |
1,206,227 |
|
|
$ |
36,535 |
|
|
$ |
776,408 |
|
|
$ |
2,019,221 |
|
|
$ |
(24,495 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE-March
31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
63,337 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See
notes to consolidated financial statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WHITING PETROLEUM CORPORATION
NOTES
TO CONSOLIDATED
FINANCIAL
STATEMENTS (Unaudited)
Description of
Operations—Whiting Petroleum Corporation, a Delaware corporation, is an
independent oil and gas company that acquires, exploits, develops and explores
for crude oil, natural gas and natural gas liquids primarily in the Permian
Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the
United States. Unless otherwise specified or the context otherwise
requires, all references in these notes to “Whiting” or the “Company” are to
Whiting Petroleum Corporation and its consolidated subsidiaries.
Consolidated
Financial Statements—The unaudited consolidated financial statements
include the accounts of Whiting Petroleum Corporation, its consolidated
subsidiaries, all of which are wholly owned, and Whiting’s pro rata share of the
accounts of Whiting USA Trust I pursuant to Whiting’s 15.8% ownership
interest. Investments in entities which give Whiting significant
influence, but not control, over the investee are accounted for using the equity
method. Under the equity method, investments are stated at cost plus
the Company’s equity in undistributed earnings and losses. All intercompany
balances and transactions have been eliminated upon
consolidation. These financial statements have been prepared in
accordance with U.S. generally accepted accounting principles for interim
financial reporting. In the opinion of management, the accompanying
financial statements include all adjustments (consisting of normal recurring
accruals and adjustments) necessary to present fairly, in all material respects,
the Company’s interim results. Whiting’s 2008 Annual Report on Form
10-K includes certain definitions and a summary of significant accounting
policies and should be read in conjunction with this Form
10-Q. Except as disclosed herein, there has been no material change
to the information disclosed in the notes to the consolidated financial
statements included in Whiting’s 2008 Annual Report on
Form 10-K. Operating results for the periods presented are not
necessarily indicative of the results that may be expected for the full
year.
Earnings Per
Share—Basic net income per common share is calculated by dividing net
income by the weighted average number of common shares outstanding during each
year. Diluted net income per common share is calculated by dividing
adjusted net income by the weighted average number of diluted common shares
outstanding, which includes the effect of potentially dilutive
securities. Potentially dilutive securities for the diluted earnings
per share calculations consist of unvested restricted stock awards and
in-the-money outstanding options to purchase the Company’s common
stock. All potentially dilutive securities are anti-dilutive when a
loss from continuing operations exists and are excluded from the computation of
diluted earnings per share accordingly.
2.
|
ACQUISITIONS
AND DIVESTITURES
|
2009
Activity
There
were no significant acquisitions or divestitures during the first quarter of
2009.
2008
Acquisition
Flat Rock Natural
Gas Field—On
May 30, 2008, Whiting acquired interests in 31 producing gas wells,
development acreage and gas gathering and processing facilities on 22,000 gross
(11,500 net) acres in the Flat Rock field in Uintah County, Utah for an
aggregate acquisition price of $365.0 million.
This
acquisition was recorded using the purchase method of accounting. The
table below summarizes the allocation of the $359.4 adjusted purchase price,
based on the acquisition date fair value of the assets acquired and the
liabilities assumed (in thousands).
|
|
|
|
|
|
|
|
Purchase
price
|
|
$ |
359,380 |
|
|
|
|
|
|
Allocation
of purchase price:
|
|
|
|
|
Proved
properties
|
|
$ |
251,895 |
|
Unproved
properties
|
|
|
79,498 |
|
Gas
gathering and processing facilities
|
|
|
35,736 |
|
Liabilities
assumed
|
|
|
(7,749 |
) |
Total
|
|
$ |
359,380 |
|
Acquisition Pro
Forma—In
the Company’s consolidated statements of income for the year ended December 31,
2008, Flat Rock’s results of operations are included with the Company’s results
beginning May 31, 2008. The following table, however, reflects the
unaudited pro forma results of operations for the three months ended March 31,
2008, as though the Flat Rock acquisition had occurred on the first day of the
period. The pro forma information below includes numerous assumptions
and is not necessarily indicative of what historical results would have been or
what future results of operations will be.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
months ended March 31, 2008:
|
|
|
|
|
|
|
|
|
|
Total
revenues
|
|
$ |
264,050 |
|
|
$ |
9,882 |
|
|
$ |
273,932 |
|
Net
income
|
|
|
62,314 |
|
|
|
294 |
|
|
|
62,608 |
|
Net
income per common share – basic and diluted
|
|
$ |
1.47 |
|
|
$ |
0.01 |
|
|
$ |
1.48 |
|
2008
Divestiture
Whiting USA Trust
I—On April 30, 2008, the Company completed an initial public
offering of units of beneficial interest in Whiting USA Trust I (the
“Trust”), selling 11,677,500 Trust units at $20.00 per Trust unit, providing net
proceeds of $193.8 million after underwriters’ fees, offering expenses, and
post-close adjustments. The Company used the net offering proceeds to
reduce a portion of the debt outstanding under its credit
agreement. The net proceeds from the sale of Trust units to the
public resulted in a deferred gain on sale of $100.1
million. Immediately prior to the closing of the offering, Whiting
conveyed a term net profits interest in certain of its oil and gas properties to
the Trust in exchange for 13,863,889 Trust units. The Company has
retained 15.8%, or 2,186,389 Trust units, of the total Trust units issued and
outstanding.
The net
profits interest entitles the Trust to receive 90% of the net proceeds from the
sale of oil and natural gas production from the underlying
properties. The net profits interest will terminate at the time when
9.11 MMBOE have been produced and sold from the underlying
properties. This is the equivalent of 8.2 MMBOE in respect of the
Trust’s right to receive 90% of the net proceeds from such production pursuant
to the net profits interest, and these reserve quantities are projected to be
produced by December 31, 2021, based on the reserve report for the
underlying properties as of December 31, 2008.
Long-term
debt consisted of the following at March 31, 2009 and December 31, 2008 (in
thousands):
|
|
|
|
|
|
|
Credit
Agreement
|
|
$ |
570,000 |
|
|
$ |
620,000 |
|
7%
Senior Subordinated Notes due 2014
|
|
|
250,000 |
|
|
|
250,000 |
|
7.25%
Senior Subordinated Notes due 2013, net of unamortized debt discount of
$1,440 and $1,541, respectively
|
|
|
218,560 |
|
|
|
218,459 |
|
7.25%
Senior Subordinated Notes due 2012, net of unamortized debt discount of
$364 and $397, respectively
|
|
|
150,996 |
|
|
|
151,292 |
|
Total debt
|
|
$ |
1,189,556 |
|
|
$ |
1,239,751 |
|
Credit
Agreement—As of March 31, 2009, the Company’s wholly-owned subsidiary,
Whiting Oil and Gas Corporation (“Whiting Oil and Gas”) had a $1.2 billion
credit agreement with a syndicate of banks that had a borrowing base of $900.0
million with $327.2 million of available borrowing capacity, which is net of
$570.0 million in borrowings and $2.8 million in letters of credit
outstanding. The credit agreement provides for interest only payments
until August 2010, when the entire amount borrowed is due. In April
2009, Whiting Oil and Gas entered into a Fourth Amended and Restated Credit
Agreement with its bank syndicate, which replaced the existing credit
facility. This amended credit agreement increased the Company’s
borrowing base under the facility to $1.1 billion and extended the principal
repayment date to April 2012. Further information on the terms of the
new credit agreement is discussed in the note on Subsequent Events.
The
borrowing base under the credit agreement is determined at the discretion of the
lenders, based on the collateral value of the proved reserves that have been
mortgaged to the lenders, and is subject to regular redeterminations on May 1
and November 1 of each year, as well as special redeterminations described in
the credit agreement. Whiting Oil and Gas may, throughout the term of
the credit agreement, borrow, repay and reborrow up to the borrowing base in
effect at any given time. The lenders under the credit agreement have
also committed to issue letters of credit for the account of Whiting Oil and Gas
or other designated subsidiaries of the Company in an aggregate amount not to
exceed $50.0 million. As of March 31, 2009, $47.2 million was
available for additional letters of credit under the agreement.
Interest
accrues, at Whiting Oil and Gas’ option, at either (i) the base rate plus a
margin, where the base rate is defined as the higher of the prime rate or the
federal funds rate plus 0.5% and the margin varies from 0% to 0.5% depending on
the utilization percentage of the borrowing base, or (ii) at the LIBOR rate plus
a margin, where the margin varies from 1.00% to 1.75% depending on the
utilization percentage of the borrowing base. Commitment fees of
0.25% to 0.375% accrue on the unused portion of the borrowing base, depending on
the utilization percentage, and are included as a component of interest
expense. At March 31, 2009, the weighted average interest rate on the
outstanding principal balance under the credit agreement was 1.8%.
The
credit agreement contains restrictive covenants that may limit the Company’s
ability to, among other things, pay cash dividends, incur additional
indebtedness, sell assets, make loans to others, make investments, enter into
mergers, enter into hedging contracts, change material agreements, incur liens
and engage in certain other transactions without the prior consent of the
lenders. The credit agreement requires the Company to maintain a debt
to EBITDAX ratio (as defined in the agreement) of less than 3.5 to 1 and a
working capital ratio (as defined in the credit agreement and which includes an
add back of the available borrowing capacity under the credit facility) of
greater than 1 to 1. Except for limited exceptions,
including the payment of interest on the senior notes, the credit agreement
restricts the ability of Whiting Oil and Gas and Whiting Petroleum Corporation’s
wholly-owned subsidiary, Equity Oil Company, to make any dividends,
distributions, principal payments on senior notes, or other payments to Whiting
Petroleum Corporation. The restrictions apply to all of the net
assets of these subsidiaries. The Company was in compliance with its
covenants under the credit agreement as of March 31, 2009. The credit
agreement is secured by a first lien on all of Whiting Oil and Gas’ properties
included in the borrowing base for the agreement. Whiting Petroleum
Corporation and Equity Oil Company have guaranteed the obligations of Whiting
Oil and Gas under the credit agreement. Whiting Petroleum Corporation
has pledged the stock of Whiting Oil and Gas and Equity Oil Company as security
for its guarantee, and Equity Oil Company has mortgaged all of its properties,
that are included in the borrowing base for the credit agreement, as security
for its guarantee.
Senior
Subordinated Notes—In October 2005, the Company issued at par
$250.0 million of 7% Senior Subordinated Notes due 2014. The
estimated fair value of these notes was $187.5 million as of March 31,
2009, based on quoted market prices for these same debt securities.
In
April 2005, the Company issued $220.0 million of 7.25% Senior
Subordinated Notes due 2013. These notes were issued at 98.507% of
par, and the associated discount of $3.3 million is being amortized to interest
expense over the term of these notes, yielding an effective interest rate of
7.4%. The estimated fair value of these notes was $174.9 million as
of March 31, 2009, based on quoted market prices for these same debt
securities.
In
May 2004, the Company issued $150.0 million of 7.25% Senior
Subordinated Notes due 2012. These notes were issued at 99.26% of
par, and the associated discount of $1.1 million is being amortized to interest
expense over the term of these notes, yielding an effective interest rate of
7.3%. The estimated fair value of these notes was $123.0 million
as of March 31, 2009, based on quoted market prices for these same debt
securities.
The notes
are unsecured obligations of Whiting Petroleum Corporation and are subordinated
to all of the Company’s senior debt, which currently consists of Whiting Oil and
Gas’ credit agreement. The indentures governing the notes restrict
the Company from incurring additional indebtedness, subject to certain
exceptions, unless its fixed charge coverage ratio (as defined in the
indentures) is at least 2.0 to 1. If the Company were in violation of
this covenant, then it may not be able to incur additional indebtedness,
including under Whiting Oil and Gas Corporation’s credit
agreement. Additionally, the indentures governing the notes contain
various restrictive covenants that are substantially identical and may limit the
Company’s ability to, among other things, pay cash dividends, redeem or
repurchase the Company’s capital stock or the Company’s subordinated debt, make
investments or issue preferred stock, sell assets, consolidate, merge or
transfer all or substantially all of the assets of the Company and its
restricted subsidiaries taken as a whole, and enter into hedging
contracts. These covenants may potentially limit the discretion of
the Company’s management in certain respects. The Company was in
compliance with these covenants as of March 31, 2009. The
Company’s obligations under the notes are fully, unconditionally, jointly and
severally guaranteed by all of the Company’s wholly-owned operating
subsidiaries, Whiting Oil and Gas, Whiting Programs, Inc. and Equity Oil Company
(the “Guarantors”). Any subsidiaries other than the Guarantors are minor
subsidiaries as defined by Rule 3-10(h)(6) of Regulation S-X of the
Securities and Exchange Commission. Whiting Petroleum Corporation has
no assets or operations independent of this debt and its investments in
guarantor subsidiaries.
Interest Rate
Swap—In August 2004, the Company entered into an interest rate swap
contract to hedge the fair value of $75.0 million of its 7.25% Senior
Subordinated Notes due 2012. The interest rate swap is a fixed for
floating swap in that the Company receives the fixed rate of 7.25% and pays the
floating rate. The floating rate is redetermined every six months
based on the LIBOR rate in effect at the contractual reset date. When
LIBOR plus the Company’s margin of 2.345% is less than 7.25%, the Company
receives a payment from the counterparty equal to the difference in rate times
$75.0 million for the six month period. When LIBOR plus the Company’s
margin of 2.345% is greater than 7.25%, the Company pays the counterparty an
amount equal to the difference in rate times $75.0 million for the six month
period.
The
Company designated this swap contract as a fair value hedge, and because this
swap meets the conditions to qualify for the “short cut” method of assessing
effectiveness, the change in fair value of the debt is assumed to equal the
change in the fair value of the interest rate swap. As such, there is
no ineffectiveness assumed to exist between the interest rate swap and the
notes.
In March
2009, the counterparty exercised its option to cancel the swap contract
effective May 1, 2009, resulting in a cancellation fee of $1.4 million due to
the Company. Accordingly, the Company has recorded a current asset of
$1.4 million related to the interest rate swap as of March 31, 2009, with an
offsetting increase to the fair value of the 7.25% Senior Subordinated Notes due
2012.
4.
|
ASSET
RETIREMENT OBLIGATIONS
|
The
Company’s asset retirement obligations represent the estimated future costs
associated with the plugging and abandonment of oil and gas wells, removal of
equipment and facilities from leased acreage, and land restoration (including
removal of certain onshore and offshore facilities in California), in accordance
with applicable local, state and federal laws. The Company determines
asset retirement obligations by calculating the present value of estimated cash
flows related to plug and abandonment obligations. The current
portions at March 31, 2009 and December 31, 2008 were $9.9 million and $6.5
million, respectively, and were recorded in accrued liabilities. The
following table provides a reconciliation of the Company’s asset retirement
obligations for the three months ended March 31, 2009 (in
thousands):
Asset
retirement obligation, January 1, 2009
|
|
$ |
54,348 |
|
Additional
liability incurred
|
|
|
99 |
|
Revisions
in estimated cash flows
|
|
|
14,121 |
|
Accretion
expense
|
|
|
2,198 |
|
Liabilities
settled
|
|
|
(1,075 |
) |
Asset
retirement obligation, March 31, 2009
|
|
$ |
69,691 |
|
5.
|
DERIVATIVE
FINANCIAL INSTRUMENTS
|
The
Company is exposed to certain risks relating to its ongoing business
operations. The primary risks managed by using derivative instruments
are commodity price risk and interest rate risk.
Commodity
derivative contracts—Historically, prices
received for crude oil and natural gas production have been volatile because of
seasonal weather patterns, supply and demand factors, worldwide political
factors and general economic conditions. Whiting enters into
derivative contracts, primarily costless collars, to achieve a more predictable
cash flow by reducing its exposure to commodity price
volatility. Commodity derivative contracts are also used to ensure
adequate cash flow to fund our capital programs and manage price risks and
returns on acquisitions and drilling programs. Costless collars are
designed to establish floor and ceiling prices on anticipated future oil and gas
production. While the use of these derivative instruments limits the
downside risk of adverse price movements, they may also limit future revenues
from favorable price movements. The Company does not enter into
derivative contracts for speculative or trading purposes.
Whiting derivatives—The table
below details the Company’s costless collar derivatives, including its
proportionate share of Trust hedges, entered into to hedge forecasted crude oil
and natural gas production revenues, as of April 1, 2009.
|
|
Whiting
Petroleum Corporation
|
|
|
|
|
|
|
NYMEX
Price Collar Ranges
|
|
|
|
Crude
Oil
|
|
|
|
|
|
Crude
Oil
|
|
|
Natural
Gas
|
|
Apr
– Dec 2009
|
|
|
4,579,487 |
|
|
|
420,763 |
|
|
$59.28
- $75.73
|
|
|
$6.32
- $15.10
|
|
Jan
– Dec 2010
|
|
|
5,046,289 |
|
|
|
495,390 |
|
|
$62.34
- $83.00
|
|
|
$6.50
- $15.06
|
|
Jan
– Dec 2011
|
|
|
4,435,039 |
|
|
|
436,510 |
|
|
$61.68
- $86.26
|
|
|
$6.50
- $14.62
|
|
Jan
– Dec 2012
|
|
|
4,065,091 |
|
|
|
384,002 |
|
|
$61.70
- $87.63
|
|
|
$6.50
- $14.27
|
|
Jan
– Nov 2013
|
|
|
3,090,000 |
|
|
|
- |
|
|
$60.33
- $81.46
|
|
|
n/a
|
|
Total
|
|
|
21,215,906 |
|
|
|
1,736,665 |
|
|
|
|
|
|
|
Derivatives conveyed to Whiting USA
Trust I—In connection with the Company’s conveyance on April 30, 2008 of
a term net profits interest to the Trust and related sale of 11,677,500 Trust
units to the public (as further explained in the note on Acquisitions and
Divestitures), the right to any future hedge payments made or received by
Whiting on certain of its derivative contracts have been conveyed to the Trust,
and therefore such payments will be included in the Trust’s calculation of net
proceeds. Under the terms of the aforementioned conveyance, Whiting
retains 10% of the net proceeds from the underlying
properties. Whiting’s retention of 10% of these net proceeds,
combined with its ownership of 2,186,389 Trust units, results in third-party
public holders of Trust units receiving 75.8%, and Whiting retaining 24.2%, of
the future economic results of commodity derivative contracts conveyed to the
Trust. The relative ownership of the future economic results of such
commodity derivatives is reflected in the tables below. No additional
hedges are allowed to be placed on Trust assets.
The 24.2%
portion of Trust derivatives that Whiting has retained the economic rights to
(and which are also included in the table above) are as follows:
|
|
Whiting
Petroleum Corporation
|
|
|
|
|
|
|
NYMEX
Price Collar Ranges
|
|
|
|
Crude
Oil
|
|
|
|
|
|
Crude
Oil
|
|
|
Natural
Gas
|
|
Apr
– Dec 2009
|
|
|
103,487 |
|
|
|
420,763 |
|
|
$76.00
- $136.57
|
|
|
$6.32
- $15.10
|
|
Jan
– Dec 2010
|
|
|
126,289 |
|
|
|
495,390 |
|
|
$76.00
- $134.98
|
|
|
$6.50
- $15.06
|
|
Jan
– Dec 2011
|
|
|
115,039 |
|
|
|
436,510 |
|
|
$74.00
- $140.15
|
|
|
$6.50
- $14.62
|
|
Jan
– Dec 2012
|
|
|
105,091 |
|
|
|
384,002 |
|
|
$74.00
- $141.72
|
|
|
$6.50
- $14.27
|
|
Total
|
|
|
449,906 |
|
|
|
1,736,665 |
|
|
|
|
|
|
|
The
75.8% portion of Trust derivative contracts for which Whiting has transferred
the economic rights to third-party public holders of Trust units (and which have
not been reflected in the above tables) are as follows:
|
|
Third-party
Public Holders of Trust Units
|
|
|
|
|
|
|
NYMEX
Price Collar Ranges
|
|
|
|
Crude
Oil
|
|
|
Natural
|
|
|
Crude
Oil
|
|
|
Natural
Gas
|
|
Apr
– Dec 2009
|
|
|
324,145 |
|
|
|
1,317,926 |
|
|
$76.00
- $136.57
|
|
|
$6.32
- $15.10
|
|
Jan
– Dec 2010
|
|
|
395,567 |
|
|
|
1,551,678 |
|
|
$76.00
- $134.98
|
|
|
$6.50
- $15.06
|
|
Jan
– Dec 2011
|
|
|
360,329 |
|
|
|
1,367,249 |
|
|
$74.00
- $140.15
|
|
|
$6.50
- $14.62
|
|
Jan
– Dec 2012
|
|
|
329,171 |
|
|
|
1,202,785 |
|
|
$74.00
- $141.72
|
|
|
$6.50
- $14.27
|
|
Total
|
|
|
1,409,212 |
|
|
|
5,439,638 |
|
|
|
|
|
|
|
Discontinuance of
cash flow hedge accounting—Prior to April 1, 2009, the
Company designated a portion of its commodity derivative contracts as cash flow
hedges, whose unrealized fair value gains and losses were
recorded to other comprehensive income, while the Company’s remaining commodity
derivative contracts were not designated as hedges, with gains and losses from
changes in fair value recognized immediately in earnings. Effective
April 1, 2009, however, the Company has elected to de-designate all of its
commodity derivative contracts that had been previously designated as cash flow
hedges as of March 31, 2009 and has elected to discontinue hedge accounting
prospectively. As a result, the Company will recognize all future
gains and losses from prospective changes in commodity derivative fair values
immediately in earnings rather than deferring any such amounts in accumulated
other comprehensive income.
At March
31 2009, accumulated other comprehensive income consisted of $59.8 million
($36.5 million after tax) of unrealized gains, representing the mark-to-market
value of the Company’s open commodity contracts designated as cash flow hedges
as of the balance sheet date, less any ineffectiveness recognized. As
a result of discontinuing hedge accounting on April 1, 2009, such mark-to-market
values at March 31, 2009 are frozen in accumulated other comprehensive income as
of the de-designation date and will be reclassified into earnings in future
periods as the original hedged transactions affect earnings. The
Company expects to reclassify into earnings from accumulated other comprehensive
income net after-tax gains of $20.6 million related to de-designated commodity
hedges during the next twelve months.
Interest rate
derivative contract—The Company has entered into
an interest rate swap agreement to manage its exposure to interest rate risk on
a portion of its fixed-rate borrowings. The interest rate swap
effectively modifies the Company’s exposure to interest rate risk by converting
the fixed rate on $75.0 million of the Company’s Senior Subordinated Notes due
2012 to a floating rate. This agreement involves the receipt of fixed
rate amounts in exchange for floating rate interest payments over the life of
the agreement without an exchange of the underlying notional
amount. The interest rate swap is designated as a fair value
hedge. Further information on the terms of the swap is discussed in
the note above on Long-Term Debt.
SFAS
161—Effective January 1, 2009, the Company adopted Financial Accounting
Standard Board (“FASB”) Statement No. 161, Disclosure about Derivative
Instruments and Hedging Activities – an amendment to FASB Statement No. 133
(“SFAS 161”). SFAS 161 expands interim and annual disclosures about
derivative and hedging activities that are intended to better convey the purpose
of derivative use and the risks managed. The adoption of SFAS 161 did
not have an impact on the Company’s consolidated financial statements, other
than additional disclosures which are set forth below.
All
derivative instruments are recorded on the consolidated balance sheet at fair
value. The following tables summarize the location and fair value
amounts of all derivative instruments in the consolidated balance sheets (in
thousands).
|
|
|
|
|
Derivatives
designated as SFAS 133 hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
contracts
|
Current
derivative assets
|
|
$ |
27,911 |
|
|
$ |
30,198 |
|
Current
derivative liabilities
|
|
$ |
769 |
|
|
$ |
4,784 |
|
Commodity
contracts
|
Non-current
derivative assets
|
|
|
16,199 |
|
|
|
13,163 |
|
Non-current
derivative liabilities
|
|
|
6,437 |
|
|
|
9,224 |
|
Interest
rate swap contract
|
Accounts
receivable trade, net (1)
|
|
|
1,360 |
|
|
|
1,690 |
|
|
|
|
|
|
|
|
|
|
Total
derivatives designated as SFAS 133 hedges
|
|
|
$ |
45,470 |
|
|
$ |
45,051 |
|
|
|
$ |
7,206 |
|
|
$ |
14,008 |
|
(1) Amount
was recorded in other long-term assets at December 31, 2008.
|
|
|
|
|
|
|
Derivatives
not designated as SFAS 133 hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
contracts
|
Current
derivative assets
|
|
$ |
16,736 |
|
|
$ |
16,582 |
|
Current
derivative liabilities
|
|
$ |
12,687 |
|
|
$ |
12,570 |
|
Commodity
contracts
|
Non-current
derivative assets
|
|
|
23,015 |
|
|
|
24,941 |
|
Non-current
derivative liabilities
|
|
|
17,447 |
|
|
|
18,907 |
|
Total
derivatives not designated as SFAS 133 hedges
|
|
|
|
39,751 |
|
|
|
41,523 |
|
|
|
$ |
30,134 |
|
|
$ |
31,477 |
|
Total
derivatives
|
|
|
$ |
85,221 |
|
|
$ |
86,574 |
|
|
|
$ |
37,340 |
|
|
$ |
45,485 |
|
Commodity
derivative contracts—The following tables summarize the effects of
commodity derivatives instruments on the consolidated statements of income for
the three months ended March 31, 2009 and 2008 (in thousands).
Derivatives
in SFAS 133 Cash Flow Hedging Relationships
|
|
Amount
of Gain or (Loss) Recognized in OCI on Derivative (Effective
Portion)
|
|
Location
of Gain or (Loss) Reclassified from AOCI into Income (Effective
Portion)
|
|
Amount
of Gain or (Loss) Reclassified from AOCI into Income (Effective
Portion)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
contracts
|
|
$ |
21,008 |
|
|
$ |
(21,377 |
) |
Gain
(loss) on oil and natural gas hedging activities
|
|
$ |
13,450 |
|
|
$ |
(22,912 |
) |
Derivatives
in SFAS 133 Cash Flow Hedging Relationships
|
|
Location
of (Gain) or Loss Recognized in Income on Derivative (Ineffective
Portion)
|
|
Amount
of (Gain) or Loss Recognized in Income on Derivative (Ineffective
Portion)
|
|
|
|
|
|
|
|
|
|
|
Commodity
contracts
|
|
(Gain)
loss on mark-to-market derivatives
|
|
$ |
22,866 |
|
|
$ |
- |
|
Derivatives
Not Designated as SFAS 133 Hedges
|
|
Location
of (Gain) or Loss
Recognized
in Income on Derivative
|
|
Amount
of (Gain) or Loss Recognized in Income on Derivative
|
|
|
|
|
|
|
|
|
|
|
Realized
cash settlements on commodity contracts
|
|
(Gain)
loss on mark-to-market derivatives
|
|
$ |
(1,530 |
) |
|
$ |
- |
|
Unrealized
(gains) losses on commodity contracts
|
|
(Gain)
loss on mark-to-market derivatives
|
|
|
429 |
|
|
|
(2,937 |
) |
Total
|
|
$ |
(1,101 |
) |
|
$ |
(2,937 |
) |
Fair value hedge—The gain or
loss on the hedged item ($75.0 million
of fixed-rate borrowings under the Company’s Senior Subordinated Notes due 2012)
attributable to the hedged benchmark interest rate risk (risk of changes in the
LIBOR swap rate) and the offsetting gain or loss on the related interest rate
swap for the three months ended March 31, 2009 and 2008 are as follows (in
thousands):
Income
Statement Classification
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
$ |
(330 |
) |
|
$ |
1,605 |
|
|
$ |
330 |
|
|
$ |
(1,605 |
) |
There is
no difference, or therefore ineffectiveness, between the gain (loss) on swap and
gain (loss) on borrowing amounts in the above table because this swap meets the
criteria to qualify for the “short cut” method of assessing
effectiveness. Accordingly, the change in fair value of the debt is
assumed to equal the change in the fair value of the interest rate
swap. In addition, the net swap settlements that accrue each period
are also reported in interest expense.
As of
March 31, 2009, the total notional amount of the Company’s
receive-fixed/pay-variable interest rate swap was $75.0 million.
Contingent features in derivative
instruments—None of the Company’s derivative instruments contain
credit-risk-related contingent features. Counterparties to the
Company’s derivative contracts are high credit quality financial institutions
that are lenders under Whiting’s credit agreement. Whiting uses only
credit agreement participants to hedge with, since these institutions are
secured equally with the holders of Whiting’s bank debt which eliminates the
potential need to post collateral when Whiting is in a large derivative
liability position. As a result, the Company is not required to post
letters of credit or corporate guarantees for the counterparty to secure
contract performance obligations.
6.
|
FAIR
VALUE DISCLOSURES
|
Effective
January 1, 2008, the Company adopted FASB Statement No. 157, Fair Value Measurements
(“SFAS 157”) which established 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: Quoted Prices in Active Markets for Identical Assets – inputs to the
valuation methodology are quoted prices (unadjusted) for identical
assets or liabilities in active
markets.
|
·
|
Level
2: Significant Other Observable Inputs – inputs to the valuation
methodology include quoted prices for similar assets and liabilities in
active markets, and inputs that are observable for the asset or liability,
either directly or indirectly, for substantially the full term of the
financial instrument.
|
·
|
Level
3: Significant Unobservable Inputs – inputs to the valuation methodology
are unobservable and significant to the fair value
measurement.
|
A
financial instrument’s categorization within the valuation hierarchy is based
upon the lowest level of input that is significant to the fair value
measurement. The Company’s assessment of the significance of a
particular input to the fair value measurement in its entirety requires judgment
and considers factors specific to the asset or liability. The
following table presents information about the Company’s financial assets and
liabilities measured at fair value on a recurring basis as of March 31, 2009,
and indicates the fair value hierarchy of the valuation techniques utilized by
the Company to determine such fair value (in thousands):
Fair
Value of Financial Assets and Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
receivable, net (1)
|
|
$ |
- |
|
|
$ |
1,360 |
|
|
$ |
- |
|
|
$ |
1,360 |
|
Current
portion of commodity derivative assets
|
|
|
- |
|
|
|
44,647 |
|
|
|
- |
|
|
|
44,647 |
|
Non-current
commodity derivative assets
|
|
|
- |
|
|
|
39,214 |
|
|
|
- |
|
|
|
39,214 |
|
Total
|
|
$ |
- |
|
|
$ |
85,221 |
|
|
$ |
- |
|
|
$ |
85,221 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
portion of derivative liabilities
|
|
$ |
- |
|
|
$ |
13,456 |
|
|
$ |
- |
|
|
$ |
13,456 |
|
Non-current
commodity derivative liabilities
|
|
|
- |
|
|
|
23,884 |
|
|
|
- |
|
|
|
23,884 |
|
Long-term
debt (1)
|
|
|
- |
|
|
|
1,360 |
|
|
|
- |
|
|
|
1,360 |
|
Total
|
|
$ |
- |
|
|
$ |
38,700 |
|
|
$ |
- |
|
|
$ |
38,700 |
|
___________________
(1)
|
Amount
represents interest rate swap (see note on Long-Term
Debt).
|
Fair Value of Financial Assets and
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
portion of commodity derivative assets
|
|
$ |
- |
|
|
$ |
46,780 |
|
|
$ |
- |
|
|
$ |
46,780 |
|
Non-current
commodity derivative assets
|
|
|
- |
|
|
|
38,104 |
|
|
|
- |
|
|
|
38,104 |
|
Other
long-term assets (1)
|
|
|
- |
|
|
|
1,690 |
|
|
|
- |
|
|
|
1,690 |
|
Total
|
|
$ |
- |
|
|
$ |
86,574 |
|
|
$ |
- |
|
|
$ |
86,574 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
portion of commodity derivative liabilities
|
|
$ |
- |
|
|
$ |
17,354 |
|
|
$ |
- |
|
|
$ |
17,354 |
|
Non-current
commodity derivative liabilities
|
|
|
- |
|
|
|
28,131 |
|
|
|
- |
|
|
|
28,131 |
|
Long-term
debt (1)
|
|
|
- |
|
|
|
1,690 |
|
|
|
- |
|
|
|
1,690 |
|
Total
|
|
$ |
- |
|
|
$ |
47,175 |
|
|
$ |
- |
|
|
$ |
47,175 |
|
__________________
(1)
|
Amount
represents interest rate swap (see note on Long-Term
Debt).
|
FSP
157-2—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 (“FSP 157-2”), issued February 2008, which defers the effective
date of SFAS 157 for one year for certain nonfinancial assets and nonfinancial
liabilities measured at fair value. Accordingly, the Company adopted
SFAS 157 on January 1, 2009 for its nonfinancial assets and nonfinancial
liabilities measured at fair value on a non-recurring basis. As it
relates to the Company, this delayed adoption applies to certain nonfinancial
assets and liabilities as may be acquired in a business combination and thereby
measured at fair value; impaired oil and gas property assessments; and the
initial recognition of asset retirement obligations for which fair value is
used. This deferred adoption of SFAS 157, however, did not have an
impact on the Company’s consolidated financial statements or its
disclosures.
Common Stock
Offering—In February 2009, the Company completed a public offering of its
common stock under its existing shelf registration statement, selling 8,450,000
shares of common stock at a price of $29.00 per share and providing net proceeds
of $234.9 million after underwriters’ fees and offering expenses. The
Company used the net offering proceeds to repay a portion of the debt
outstanding under Whiting Oil and Gas’ credit agreement. Whiting
plans to use the increased credit availability to fund a portion of the planned
capital expenditures in its 2009 capital budget.
Equity Incentive
Plan—The Company maintains the Whiting Petroleum Corporation 2003 Equity
Incentive Plan (the “Equity Plan”), pursuant to which two million shares of the
Company’s common stock have been reserved for issuance. No employee
or officer participant may be granted options for more than 300,000 shares of
common stock, stock appreciation rights relating to more than 300,000 shares of
common stock, or more than 150,000 shares of restricted stock during any
calendar year. As of March 31, 2009, 1,070,452 shares of common stock
remained available for grant under the Plan.
Restricted Shares—Restricted
stock awards for executive officers, directors and employees generally vest
ratably over three years. The Company uses historical data and
projections to estimate expected employee behaviors related to restricted stock
forfeitures. The expected forfeitures are then included as part of
the grant date estimate of compensation cost. For service-based
restricted stock awards, the grant date fair value is determined based on the
closing bid price of the Company’s common stock on the grant date.
In
February 2007, 79,227 shares of restricted stock, subject to certain internal
performance metrics in addition to the standard three-year service condition,
were granted to executive officers under the Equity Plan. These
internal performance conditions must be met in order for the stock awards to
vest. It is therefore possible that no shares could vest in one or
more of the three-year vesting periods. The Company recognizes
compensation expense for awards subject to performance conditions when it
becomes probable that these conditions will be achieved. However, any
such compensation expense recognized is reversed if vesting does not actually
occur.
In
February 2009 and 2008, 209,649 shares and 74,542 shares, respectively, of
restricted stock, subject to certain market-based vesting criteria in addition
to the standard three-year service condition, were granted to executive officers
under the Equity Plan. The market-based conditions must be met in
order for the stock awards to vest, and it is therefore possible that no shares
could vest in one or more of the three-year vesting periods. However,
the Company recognizes compensation expense for awards subject to market
conditions regardless of whether it becomes probable that these conditions will
be achieved or not, and compensation expense is not reversed if vesting does not
actually occur.
For these
awards subject to market conditions, the grant date fair value was estimated
using a Monte Carlo valuation model. The Monte Carlo model is based
on random projections of stock price paths and must be repeated numerous times
to achieve a probabilistic assessment. Expected volatility was
calculated based on the historical volatility of Whiting’s common stock, and the
risk-free interest rate is based on U.S. Treasury yield curve rates with
maturities consistent with the three-year vesting period. The key
assumptions used in valuing the market-based restricted shares were as
follows:
|
|
|
|
|
|
|
Number
of simulations
|
|
|
100,000 |
|
|
|
100,000 |
|
Expected
volatility
|
|
|
70.0 |
% |
|
|
36.3 |
% |
Risk-free
interest rate
|
|
|
1.33 |
% |
|
|
2.24 |
% |
The total
grant date fair value of the market-based restricted stock as determined by the
Monte Carlo valuation model was $1.4 million in February 2009 and $1.8 million
in February 2008 and is recognized ratably over the three-year vesting
period.
The
following table shows a summary of the Company’s nonvested restricted stock as
of March 31, 2009 as well as activity during the three months then ended (share
and per share data, not presented in thousands):
|
|
Number
of
|
|
|
Weighted
Average Grant Date Fair Value
|
|
Restricted
stock awards nonvested, January 1, 2009
|
|
|
258,764 |
|
|
$ |
42.41 |
|
Granted
|
|
|
350,824 |
|
|
$ |
14.39 |
|
Vested
|
|
|
(94,874 |
) |
|
$ |
40.99 |
|
Forfeited
|
|
|
(3,133 |
) |
|
$ |
42.90 |
|
Restricted
stock awards nonvested, March 31, 2009
|
|
|
511,581 |
|
|
$ |
21.16 |
|
As of
March 31, 2009, there was $6.8 million of total unrecognized compensation cost
related to unvested restricted stock granted under the stock incentive
plans. That cost is expected to be recognized over a weighted average
period of 2.5 years.
Stock Options—In February
2009, 120,607 stock options were granted under the Equity Plan to certain
executive officers of the Company with exercise prices equal to the closing
market price of the Company’s common stock on the grant date. These
stock options vest ratably over a three-year service period from the grant date
and are exercisable immediately upon vesting through the tenth anniversary of
the grant date.
The
Company uses a Black-Scholes option-pricing model to estimate the fair value of
stock option awards. Because the Company has not previously granted
stock options, it does not have historical exercise data upon which to estimate
the expected term of the options. As such, the Company has elected to
estimate the expected term of the stock options granted using the “simplified”
method for “plain vanilla” options. The expected volatility at the
grant date is based on the historical volatility of Whiting’s common stock, and
the risk-free interest rate is determined using the U.S. Treasury yield curve
rates with maturities similar to those of the expected term of the stock
options. The following table summarizes the assumptions used in the
estimate the grant date fair value of stock options awarded in February
2009:
|
|
|
|
Risk-free
interest
rate
|
|
|
2.0%
|
|
Expected
volatility
|
|
|
58.1%
|
|
Expected
term
|
|
6.0
yrs.
|
|
Dividend
yield
|
|
|
-
|
|
The grant
date fair value of the stock options awarded, as determined by the Black-Scholes
valuation model, was $1.4 million and will be recognized ratably over the
three-year vesting period.
The
following table shows a summary of the Company’s stock options outstanding as of
March 31, 2009 as well as activity during the three months then ended (share and
per share data, not presented in thousands):
|
|
|
|
|
Weighted
Average Exercise Price per Share
|
|
Options
outstanding at January 1, 2009
|
|
|
- |
|
|
|
- |
|
Granted
|
|
|
120,607 |
|
|
$ |
25.51 |
|
Exercised
|
|
|
- |
|
|
|
- |
|
Forfeited
or expired
|
|
|
- |
|
|
|
- |
|
Options
outstanding at March 31, 2009
|
|
|
120,607 |
|
|
$ |
25.51 |
|
At March
31, 2009, no options were eligible for exercise. The weighted average
grant-date fair value of options granted during 2009 was $11.85 per
share. The 120,607 options outstanding in the table above have a
remaining contractual term of 9.9 years and an aggregate intrinsic value of
$0.04 million. Unrecognized compensation cost as of March 31,
2009 related to unvested stock option awards was $1.4 million, which is expected
to be recognized over a period of 2.9 years.
Rights
Agreement—In 2006, the Board of Directors of the Company declared a
dividend of one preferred share purchase right (a “Right”) for each outstanding
share of common stock of the Company payable to the stockholders of record as of
March 2, 2006. Each Right entitles the registered holder to
purchase from the Company one one-hundredth of a share of Series A Junior
Participating Preferred Stock, par value $0.001 per share (“Preferred Shares”),
of the Company at a price of $180.00 per one one-hundredth of a Preferred Share,
subject to adjustment. If any person becomes a 15% or more
stockholder of the Company, then each Right (subject to certain limitations)
will entitle its holder to purchase, at the Right’s then current exercise price,
a number of shares of common stock of the Company or of the acquirer having a
market value at the time of twice the Right’s per share exercise
price. The Company’s Board of Directors may redeem the Rights for
$0.001 per Right at any time prior to the time when the Rights become
exercisable. Unless the Rights are redeemed, exchanged or terminated
earlier, they will expire on February 23, 2016.
8.
|
EMPLOYEE
BENEFIT PLANS
|
Production
Participation Plan—The Company has a Production Participation Plan (the
“Plan”) in which all employees participate. On an annual basis,
interests in oil and gas properties acquired, developed or sold during the year
are allocated to the Plan as determined annually by the Compensation
Committee. Once allocated, the interests (not legally conveyed) are
fixed. Interest allocations prior to 1995 consisted of 2%-3%
overriding royalty interests. Interest allocations since 1995 have
been 2%-5% of oil and gas sales less lease operating expenses and production
taxes.
Payments
of 100% of the year’s Plan interests to employees and the vested percentages of
former employees in the year’s Plan interests are made annually in cash after
year-end. Accrued compensation expense under the Plan for the three
months ended March 31, 2009 and 2008 amounted to $2.0 million and $5.5 million,
respectively, charged to general and administrative expense and $0.3 million and
$0.9 million, respectively, charged to exploration expense.
Employees
vest in the Plan ratably at 20% per year over a five year
period. Pursuant to the terms of the Plan, (i) employees who
terminate their employment with the Company are entitled to receive their vested
allocation of future Plan year payments on an annual basis; (ii) employees will
become fully vested at age 62, regardless of when their interests would
otherwise vest; and (iii) any forfeitures inure to the benefit of the
Company.
The
Company uses average historical prices to estimate the vested long-term
Production Participation Plan liability. At March 31, 2009, the
Company used three-year average historical NYMEX prices of $78.62 for crude oil
and $7.56 for natural gas to estimate this liability. If the Company
were to terminate the Plan or upon a change in control (as defined in the Plan),
all employees fully vest, and the Company would distribute to each Plan
participant an amount based upon the valuation method set forth in the Plan in a
lump sum payment twelve months after the date of termination or within one month
after a change in control event. Based on prices at March 31, 2009,
if the Company elected to terminate the Plan or if a change of control event
occurred, it is estimated that the fully vested lump sum cash payment to
employees would approximate $80.1 million. This amount includes $12.9
million attributable to proved undeveloped oil and gas properties and $2.3
million relating to the short-term portion of the Plan liability, which has been
accrued as a current payable to be paid in February 2010. The
ultimate sharing contribution for proved undeveloped oil and gas properties will
be awarded in the year of Plan termination or change of
control. However, the Company has no intention to terminate the
Plan.
The
following table presents changes in the estimated long-term liability related to
the Plan for the three months ended March 31, 2009 (in thousands):
Production
Participation Plan liability, January 1, 2009
|
|
$ |
66,166 |
|
Change
in liability for accretion, vesting and changes in
estimates
|
|
|
2,672 |
|
Reduction
in liability for cash payments accrued and recognized as compensation
expense
|
|
|
(2,276 |
) |
Production
Participation Plan liability, March 31, 2009
|
|
$ |
66,562 |
|
The
Company records the expense associated with changes in the present value of
estimated future payments under the Plan as a separate line item in the
consolidated statements of income. The amount recorded is not
allocated to general and administrative expense or exploration expense because
the adjustment of the liability is associated with the future net cash flows
from the oil and gas properties rather than current period
performance. The table below presents the estimated allocation of the
change in the liability if the Company did allocate the adjustment to these
specific line items (in thousands).
|
|
Three
Months Ended
March
31,
|
|
|
|
|
|
|
|
|
General
and administrative expense
|
|
$ |
345 |
|
|
$ |
5,277 |
|
Exploration
expense
|
|
|
51 |
|
|
|
880 |
|
Total
|
|
$ |
396 |
|
|
$ |
6,157 |
|
401(k)
Plan—The Company has a defined contribution retirement plan for all
employees. The plan is funded by employee contributions and
discretionary Company contributions. Employees vest in employer
contributions at 20% per year of completed service.
Income
tax expense during interim periods is based on applying an estimated annual
effective income tax rate to year-to-date income, plus any significant unusual
or infrequently occurring items which are recorded in the interim period. The
provision for income taxes for the three months ended March
31, 2009 and 2008 differs from the amount that would be provided by applying the
statutory U.S. federal income tax rate of 35% to income before income taxes
primarily related to state income taxes and estimated permanent
differences.
The
following table summarizes the components of the provision for income taxes (in
thousands):
|
|
Three
Months Ended
March
31,
|
|
|
|
|
|
|
|
|
Current
portion of income tax expense:
|
|
|
|
|
|
|
Federal
|
|
$ |
- |
|
|
$ |
1,642 |
|
State
|
|
|
(539 |
) |
|
|
67 |
|
Deferred
portion of income tax expense
|
|
|
(25,505 |
) |
|
|
34,759 |
|
Total
income tax expense
|
|
$ |
(26,044 |
) |
|
$ |
36,468 |
|
Effective
tax rates
|
|
|
37.3 |
% |
|
|
36.9 |
% |
The
computation of the annual estimated effective tax rate at each interim period
requires certain estimates and significant judgment including, but not limited
to, the expected operating income for the year, projections of the proportion of
income earned and taxed in various jurisdictions, permanent and temporary
differences, and the likelihood of recovering deferred tax assets generated in
the current year. The accounting estimates used to compute the
provision for income taxes may change as new events occur, more experience is
acquired, additional information is obtained or as the tax environment
changes.
10.
|
RELATED
PARTY TRANSACTIONS
|
Whiting USA Trust
I—As a result of
Whiting’s retained ownership of 15.8%, or 2,186,389 units in Whiting USA Trust
I, the Trust is a related party of the Company. The following table
summarizes the related party receivable and payable balances between the Company
and the Trust as of March 31, 2009 and December 31, 2008 (in
thousands):
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
Unit
distributions due from Trust (1)
|
|
$ |
1,323 |
|
|
$ |
1,596 |
|
Total
|
|
$ |
1,323 |
|
|
$ |
1,596 |
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
Unit
distributions payable to Trust (2)
|
|
$ |
8,388 |
|
|
$ |
10,120 |
|
Current
portion of derivative liability
|
|
|
12,687 |
|
|
|
12,570 |
|
Non-current
derivative liability
|
|
|
17,447 |
|
|
|
18,907 |
|
Total
|
|
$ |
38,522 |
|
|
$ |
41,597 |
|
_______________
(1)
|
This
amount represents Whiting’s 15.8% interest in the net proceeds due from
the Trust and is included within accounts receivable trade, net in the
Company’s consolidated balance
sheets.
|
(2)
|
This
amount represents net proceeds from the Trust’s underlying properties as
well as realized cash settlements on Trust derivatives, that the Company
has received between the last Trust distribution date and period end, but
which the Company has not yet distributed to the Trust as of period
end. Due to ongoing processing of Trust revenues and expenses
after the respective period ends, the amount of Whiting’s next scheduled
distribution to the Trust, and the related distribution by the Trust to
its unit holders, will differ from this amount. This amount is
included within accounts payable in the Company’s consolidated balance
sheet.
|
For the
three months ended March 31, 2009 and year ended December 31, 2008, Whiting paid
$11.1 million and $57.8 million, respectively, net of state tax withholdings, in
distributions to the Trust under the net profits interest and received $1.7
million and $9.0 million, respectively, in distributions back from the Trust
pursuant to its retained ownership in 2,186,389 Trust units.
Tax Sharing
Liability—Prior to Whiting’s initial public offering in November 2003, it
was a wholly-owned indirect subsidiary of Alliant Energy Corporation (“Alliant
Energy”), a holding company whose primary businesses are utility
companies. When the transactions discussed below were entered into,
Alliant Energy was a related party of the Company. As of December 31,
2004 and thereafter, Alliant Energy was no longer a related party.
In
connection with Whiting’s initial public offering in November 2003, the Company
entered into a Tax Separation and Indemnification Agreement with Alliant
Energy. Pursuant to this agreement, the Company and Alliant Energy
made a tax election with the effect that the tax bases of Whiting’s assets were
increased to the deemed purchase price immediately prior to such initial public
offering. Whiting has adjusted deferred taxes on its balance sheet to
reflect the new tax bases of its assets. The additional bases are
expected to result in increased future income tax deductions and, accordingly,
may reduce income taxes otherwise payable by Whiting.
Under
this agreement, the Company has agreed to pay to Alliant Energy 90% of the
future tax benefits the Company realizes annually as a result of this step-up in
tax basis for the years ending on or prior to December 31, 2013. Such
tax benefits will generally be calculated by comparing the Company’s actual
taxes to the taxes that would have been owed by the Company had the increase in
basis not occurred. In 2014, Whiting will be obligated to pay Alliant
Energy the present value of the remaining tax benefits, assuming all such tax
benefits will be realized in future years. The Company has estimated
total payments to Alliant will approximate $34.5 million on an undiscounted
basis.
During
the first quarter of 2009, the Company did not make any payments under this
agreement but did recognize $0.4 million of interest
expense. The Company’s estimated payment of $2.1 million to be
made in 2009 under this agreement is reflected as a current liability at March
31, 2009 and December 31, 2008.
The Tax
Separation and Indemnification Agreement provides that if tax rates were to
increase or decrease, the resulting tax benefit or detriment would cause a
corresponding adjustment of the tax sharing liability. For purposes
of this calculation, management has assumed that no such future changes will
occur during the term of this agreement.
The
Company periodically evaluates its estimates and assumptions as to future
payments to be made under this agreement. If non-substantial changes
(less than 10% on a present value basis) are made to the anticipated payments
owed to Alliant Energy, a new effective interest rate is determined for this
debt based on the carrying amount of the liability as of the modification date
and based on the revised payment schedule. However, if there are
substantial changes to the estimated payments owed under this agreement, then a
gain or loss is recognized in the consolidated statements of income during the
period in which the modification has been made.
Alliant Energy
Guarantee—The Company holds a 6% working interest in three offshore
platforms in California and the related onshore plant and
equipment. Alliant Energy has guaranteed the Company’s obligation in
the abandonment of these assets.
11.
|
COMMITMENTS
AND CONTINGENCIES
|
Non-cancelable
Leases—The Company leases 107,400 square feet of administrative office
space in Denver, Colorado under an operating lease arrangement through 2013 and
an additional 46,700 square feet of office space in Midland, Texas until
2012. Rental expense for the first quarter of 2009 and 2008 was $0.7
million and $0.5 million, respectively.
Minimum lease payments
under the terms of non-cancelable operating leases as of March 31, 2009 are as
follows (in thousands):
2009
|
|
$ |
1,893 |
|
2010
|
|
|
2,677 |
|
2011
|
|
|
3,383 |
|
2012
|
|
|
2,931 |
|
2013
|
|
|
2,382 |
|
Total
|
|
$ |
13,266 |
|
Purchase
Contracts—The Company has entered into two take-or-pay purchase
agreements, one agreement expiring in March 2014 and one agreement expiring in
December 2014, whereby the Company has committed to buy certain volumes of
CO2
for a fixed fee subject to annual escalation. The purchase agreements
are with different suppliers, and the CO2 is for use
in the Company’s enhanced recovery projects in Oklahoma and
Texas. Under the terms of the agreements, the Company is obligated to
purchase a minimum daily volume of CO2 (as
calculated on an annual basis) or else pay for any deficiencies at the price in
effect when delivery was to have occurred. The CO2 volumes
planned for use in the Company’s enhanced recovery projects currently exceed the
minimum daily volumes provided in these take-or-pay purchase
agreements. Therefore, the Company expects to avoid any payments for
deficiencies. As of March 31, 2009, future commitments under the
purchase agreements amounted to $143.6 million through 2014.
Drilling
Contracts—The Company currently has seven drilling rigs under long-term
contract, of which two drilling rigs expire in 2009, two in 2010, one in 2011,
one in 2012 and one in 2013. All of these rigs are operating in the
Rocky Mountains region. As of March 31, 2009, these drilling
contracts had total commitments of $117.1 million. Included in this
total obligation of $117.1 million is $3.7 million of rig termination fees that
the Company accrued as a current payable at March 31, 2009 for the cancellation
of long-term contracts on three drilling rigs and one workover
rig. As of March 31, 2009, early termination of the remaining
contracts would require additional termination penalties of $68.3 million, which
would be in lieu of paying the remaining drilling commitments of $113.4
million. Other drilling rigs working for the Company are not under
long-term contracts but instead are under contracts that can be terminated at
the end of the well that is currently being drilled.
Litigation—The
Company is subject to litigation, claims and governmental and regulatory
proceedings arising in the ordinary course of business. It is the
opinion of the Company’s management that all claims and litigation involving the
Company are not likely to have a material adverse effect on its consolidated
financial position, cash flows or results of operations.
12.
|
RECENTLY
ISSUED ACCOUNTING PRONOUNCEMENTS
|
On
December 31, 2008, the SEC published the final rules and interpretations
updating its oil and gas reporting requirements. Many of the revisions are
updates to definitions in the existing oil and gas rules to make them consistent
with the petroleum resource management system, which is a widely accepted
standard for the management of petroleum resources that was developed by several
industry organizations. Key revisions include the ability to include
nontraditional resources in reserves, the use of new technology for determining
reserves, permitting disclosure of probable and possible reserves, and changes
to the pricing used to determine reserves in that companies must use a 12-month
average price. The average is calculated using the
first-day-of-the-month price for each of the 12 months that make up the
reporting period. The SEC will require companies to comply with the
amended disclosure requirements for registration statements filed after January
1, 2010, and for annual reports for fiscal years ending on or after December 31,
2009. Early adoption is not permitted. We are currently assessing
the impact that the adoption will have on our disclosures, operating results,
statement of financial position and statement of cash flows.
In April
2009, the FASB issued Staff Position (“FSP”) No. FAS 157-4, Determining Fair Value When the
Volume or Level of Activity for the Asset or Liability Have Significantly
Decreased and Identifying Transactions That Are Not Orderly ("FSP
157-4"). The adoption of FSP 157-4 is not expected to have an impact
on the Company’s consolidated financial statements, other than additional
disclosures. FSP 157-4 provides additional guidance for estimating
fair value in accordance with SFAS No. 157 when the volume and level of activity
for the asset or liability have significantly decreased and requires that
companies provide interim and annual disclosures of the inputs and valuation
technique(s) used to measure fair value. FSP 157-4 is effective for
interim and annual reporting periods ending after June 15, 2009 and is to be
applied prospectively.
In April
2009, the FASB issued FSP No. 107-1 and APB 28-1, Interim Disclosures about Fair Value
of Financial Instruments (“FSP 107-1”). The adoption of FSP
107-1 is not expected to have an impact on the Company’s consolidated financial
statements, other than additional disclosures. FSP 107-1 requires
disclosures about fair value of financial instruments for interim reporting
periods of publicly traded companies as well as in annual financial
statements. FSP 107-1 is effective for interim and annual reporting
periods ending after June 15, 2009.
On April
28, 2009, Whiting Oil and Gas entered into a Fourth Amended and Restated Credit
Agreement with its bank syndicate, which replaced the existing credit
facility. This amended credit agreement increased the Company’s
borrowing base under the facility from $900.0 million to $1.1 billion and
extended the principal repayment date to April 2012. The borrowing
base under the credit agreement is determined at the discretion of the lenders,
based on the collateral value of the Company’s proved reserves that have been
mortgaged to its lenders, and is subject to regular redeterminations on May 1
and November 1 of each year, as well as special redeterminations described in
the credit agreement, in each case which may reduce the amount of the borrowing
base. A portion of the revolving credit facility in an aggregate
amount not to exceed $50.0 million may be used to issue letters of credit for
the account of Whiting Oil and Gas or other designated subsidiaries of the
Company.
The
credit agreement provides for interest only payments until April 2012, when the
entire amount borrowed is due. Interest accrues at the Company’s
option at either (i) a base rate for a base rate loan plus the margin in the
table below, where the base rate is defined as the greatest of the prime rate,
the federal funds rate plus 0.50% or an adjusted LIBOR rate plus 1.00%, or (ii)
an adjusted LIBOR rate for a Eurodollar loan plus the margin in the table
below.
Ratio of Outstanding Borrowings to Borrowing
Base
|
|
Applicable
Margin for Base Rate
Loans
|
|
Applicable
Margin for Eurodollar
Loans
|
Less
than 0.25 to 1.0
|
|
1.1250%
|
|
2.00%
|
Greater
than or equal to 0.25 to 1.0 but less than 0.50 to 1.0
|
|
1.1375%
|
|
2.25%
|
Greater
than or equal to 0.50 to 1.0 but less than 0.75 to 1.0
|
|
1.6250%
|
|
2.50%
|
Greater
than or equal to 0.75 to 1.0 but less than 0.90 to 1.0
|
|
1.8750%
|
|
2.75%
|
Greater
than or equal to 0.90 to 1.0
|
|
2.1250%
|
|
3.00%
|
Under the
credit agreement, the Company also incurs commitment fees of 0.50% on the unused
portion of the lesser of the aggregate commitments of the lenders or the
borrowing base.
The
credit agreement contains restrictive covenants that may limit the Company’s
ability to, among other things, incur additional indebtedness, sell assets, make
loans to others, make investments, enter into mergers, enter into hedging
contracts, incur liens and engage in certain other transactions without the
prior consent of its lenders. The credit agreement requires the
Company, as of the last day of any quarter, (i) to not exceed a total debt to
EBITDAX ratio (as defined in the credit agreement) for the last four quarters of
4.5 to 1.0 for quarters ending prior to and on September 30, 2010, 4.25 to 1.0
for quarters ending December 31, 2010 to June 30, 2011 and 4.0 to 1.0 for
quarters ending September 30, 2011 and thereafter, (ii) to have a consolidated
current assets to consolidated current liabilities ratio (as defined in the
credit agreement) of not less than 1.0 to 1.0 and (iii) to not exceed a senior
secured debt to EBITDAX ratio (as defined in the credit agreement) for the last
four quarters of 2.75 to 1.0 for quarters ending prior to and on December 31,
2009 and 2.5 to 1.0 for quarters ending March 31, 2010 and
thereafter. Except for limited exceptions, the credit agreement
restricts the Company’s ability to make any dividends or distributions on its
common stock or principal payments on its senior notes.
The
obligations of Whiting Oil and Gas under the credit agreement are secured by a
first lien on substantially all of Whiting Oil and Gas’ properties included in
the borrowing base for the credit agreement. Whiting Petroleum
Corporation and its wholly-owned subsidiary, Equity Oil Company, have guaranteed
the obligations of Whiting Oil and Gas under the credit
agreement. Whiting Petroleum Corporation has pledged the stock of
Whiting Oil and Gas and Equity Oil Company as security for its guarantee, and
Equity Oil Company has mortgaged substantially all of its properties included in
the borrowing base for the credit agreement as security for its
guarantee.
|
Management’s Discussion and Analysis of Financial
Condition and Results of
Operations
|
Unless
the context otherwise requires, the terms “Whiting,” “we,” “us,” “our” or “ours”
when used in this Item refer to Whiting Petroleum Corporation, together with its
consolidated subsidiaries, Whiting Oil and Gas Corporation, Equity Oil Company
and Whiting Programs, Inc. When the context requires, we refer to
these entities separately. This document contains forward-looking
statements, which give our current expectations or forecasts of future
events. Please refer to “Forward-Looking Statements” at the end of
this Item for an explanation of these types of statements.
Overview
We are an
independent oil and gas company engaged in oil and gas acquisition, development,
exploitation, production and exploration activities primarily in the Permian
Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the
United States. Prior to 2006, we generally emphasized the acquisition
of properties that increased our production levels and provided upside potential
through further development. Since 2006, we have focused primarily on
organic drilling activity and on the development of previously acquired
properties, specifically on projects that we believe provide the opportunity for
repeatable successes and production growth. We believe the
combination of acquisitions, subsequent development and organic drilling
provides us a broad set of growth alternatives and allows us to direct our
capital resources to what we believe to be the most advantageous
investments.
As
demonstrated by our recent capital expenditure programs, we are increasingly
focused on a balance between exploration and development programs and continuing
to selectively pursue acquisitions that complement our existing core
properties. We believe that our significant drilling inventory,
combined with our operating experience and cost structure, provides us with
meaningful organic growth opportunities. Our growth plan is centered
on the following activities:
|
•
|
pursuing
the development of projects that we believe will generate attractive rates
of return;
|
|
•
|
maintaining
a balanced portfolio of lower risk, long-lived oil and gas properties that
provide stable cash flows;
|
|
•
|
seeking
property acquisitions that complement our core
areas; and
|
|
•
|
allocating
a portion of our capital budget to leasing and exploring prospect
areas.
|
We have
historically acquired operated and non-operated properties that exceed our rate
of return criteria. For acquisitions of properties with additional
development, exploitation and exploration potential, our focus has been on
acquiring operated properties so that we can better control the timing and
implementation of capital spending. In some instances, we have been
able to acquire non-operated property interests at attractive rates of return
that established a presence in a new area of interest or that have complemented
our existing operations. We intend to continue to acquire both
operated and non-operated interests to the extent we believe they meet our
return criteria. In addition, our willingness to acquire non-operated
properties in new geographic regions provides us with geophysical and geologic
data in some cases that leads to further acquisitions in the same region,
whether on an operated or non-operated basis. We sell properties when
we believe that the sales price realized will provide an above average rate of
return for the property or when the property no longer matches the profile of
properties we desire to own.
Oil and
natural gas prices have fallen significantly since their third quarter 2008
levels. For example, the daily average NYMEX oil price was $118.13 per Bbl
for the third quarter of 2008, $58.75 per Bbl for the fourth quarter of 2008,
and $43.21 per Bbl for the first quarter of
2009. Similarly, daily average NYMEX natural gas prices have
declined from $10.27 per Mcf for the third quarter of 2008 to $6.96 per Mcf
for the fourth quarter of 2008 and $4.92 for the first quarter of 2009.
Lower oil and natural gas prices may not only decrease our revenues, but may
also reduce the amount of oil and natural gas that we can produce economically
and therefore potentially lower our reserve bookings. A substantial or
extended decline in oil or natural gas prices may result in impairments of our
proved oil and gas properties and may materially and adversely affect our future
business, financial condition, cash flows, results of operations, liquidity or
ability to finance planned capital expenditures. Lower oil and gas
prices may also reduce the amount of our borrowing base under our credit
agreement, which is determined at the discretion of the lenders based on the
collateral value of our proved reserves that have been mortgaged to the
lenders.
First
Quarter 2009 Highlights and Future Considerations
Common Stock
Offering. In February 2009, we completed a public offering of
our common stock under our existing shelf registration statement, selling
8,450,000 shares of common stock at a price of $29.00 per share and providing
net proceeds of $234.9 million after underwriters’ fees and offering
expenses. We used the net offering proceeds to repay a portion of the
debt outstanding under Whiting Oil and Gas’ credit agreement, and we plan to use
the increased credit availability to fund a portion of the planned capital
expenditures in our 2009 capital budget.
Operational
Highlights. Our Sanish and Parshall fields in Mountrail
County, North Dakota target the Bakken formation. Production in this
area was affected by winter weather during the first quarter of 2009, which
caused delays in trucking operations and well completion activity. In
the Parshall field, net production averaged 5.4 MBOE/d in the first quarter of
2009, a 27% decrease from 7.3 MBOE/d in the fourth quarter of
2008. Net production in the Parshall field increased 70% from a net
3.0 MBOE/d in March 2008 to a net 5.1 MBOE/d in March 2009. Despite
these weather issues, first quarter 2009 net production in the Sanish field
averaged 8.9 MBOE/d, an 11% increase from 8.0 MBOE/d in the fourth quarter of
2008. Net production in the Sanish field increased 740% from a net
1.2 MBOE/d in March 2008 to a net 9.9 MBOE/d in March 2009.
We
continue to have significant development and related infrastructure activity on
the Postle and North Ward Estes fields acquired in 2005, which have resulted in
reserve and production increases. Our expansion of the CO2 flood at
both fields continues to generate positive results. During the first
quarter of 2009, we incurred $53.0 million of development expenditures on these
two projects.
The
Postle field is located in Texas County, Oklahoma. Four of our five
producing units are currently under active CO2 enhanced
recovery projects. As of April 20, 2009, we were injecting 147 MMcf/d
of CO2
in this field. Production from the field has increased 27% from a net
6.2 MBOE/d in March 2008 to a net 7.9 MBOE/d in March
2009. Operations are under way to expand CO2 injection
into the northern part of the fourth unit, HMU, and to optimize flood patterns
in the existing CO2
floods. These expansion projects include the restoration of shut-in
wells and the drilling of new producing and injection wells.
The North
Ward Estes field is responding positively to our water and CO2 floods,
which we initiated in Phase I during May 2007. In early March 2009,
we began Phase II of the project. As of April 20, 2009, we were
injecting 170 MMcf/d of CO2 in this
field. Production from the field has increased 23% from a net 5.2
MBOE/d in March 2008 to a net 6.4 MBOE/d in March 2009. In this
field, we are developing new and reactivated wells for water and CO2 injection
and production purposes. Additionally, we plan to install oil, gas
and water processing facilities in five phases through 2015, and we estimate
that the first three phases will be substantially complete by December
2009.
2009 Capital Budget and Major
Development Areas. Our current 2009 capital budget for
exploration and development expenditures is $420.6 million, which we expect to
fund with net cash provided by our operating activities and a portion of the
proceeds from the common stock offering we completed in February
2009. To the extent net cash provided by operating activities or oil
and natural gas prices are lower than currently anticipated, we would adjust our
capital budget accordingly. If net cash provided by operating
activities is higher than currently anticipated, we plan to reduce debt
levels. Our 2009 capital budget currently is allocated among our
major development areas as indicated in the chart below.
Development Area
|
|
2009
Planned Capital Expenditures
(In
millions)
|
|
Northern
Rockies
|
|
$ |
227.9 |
|
Enhanced
Oil Recovery Projects (1)
|
|
|
122.9 |
|
Central
Rockies
|
|
|
26.0 |
|
Permian
Basin
|
|
|
13.5 |
|
Exploration
and early rig termination (2)
|
|
|
30.3 |
|
Total
|
|
$ |
420.6 |
|
(1)
|
2009
planned capital expenditures at our CO2
projects include $36.9 million for purchased CO2 at
North Ward Estes and $15.3 million for Postle CO2
purchases.
|
(2)
|
Comprised
primarily of exploration salaries, $6.2 million of early rig termination
fees, lease delay rentals and seismic
surveys.
|
Results
of Operations
Three
Months Ended March 31, 2009 Compared to Three Months Ended March 31,
2008
Selected
Operating Data:
|
|
Three
Months Ended
March
31,
|
|
|
|
|
|
|
|
|
Net
production:
|
|
|
|
|
|
|
Oil
(MMBbls)
|
|
|
3.6 |
|
|
|
2.6 |
|
Natural
gas (Bcf)
|
|
|
7.9 |
|
|
|
6.9 |
|
Total
production (MMBOE)
|
|
|
4.9 |
|
|
|
3.7 |
|
|
|
|
|
|
|
|
|
|
Net
sales (in millions):
|
|
|
|
|
|
|
|
|
Oil
(1)
|
|
$ |
116.3 |
|
|
$ |
232.4 |
|
Natural
gas (1)
|
|
|
29.9 |
|
|
|
54.3 |
|
Total
oil and natural gas sales
|
|
$ |
146.2 |
|
|
$ |
286.7 |
|
|
|
|
|
|
|
|
|
|
Average
sales prices:
|
|
|
|
|
|
|
|
|
Oil
(per Bbl)
|
|
$ |
32.55 |
|
|
$ |
89.58 |
|
Effect
of oil hedges on average price (per Bbl)
|
|
|
4.10 |
|
|
|
(8.83 |
) |
Oil
net of hedging (per Bbl)
|
|
$ |
36.65 |
|
|
$ |
80.75 |
|
Average
NYMEX price
|
|
$ |
43.21 |
|
|
$ |
97.96 |
|
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$ |
3.78 |
|
|
$ |
7.89 |
|
Effect
of natural gas hedges on average price (per Mcf)
|
|
|
0.05 |
|
|
|
- |
|
Natural
gas net of hedging (per Mcf)
|
|
$ |
3.83 |
|
|
$ |
7.89 |
|
Average
NYMEX price
|
|
$ |
4.92 |
|
|
$ |
8.03 |
|
|
|
|
|
|
|
|
|
|
Cost
and expense (per BOE):
|
|
|
|
|
|
|
|
|
Lease
operating expenses
|
|
$ |
12.47 |
|
|
$ |
14.89 |
|
Production
taxes
|
|
$ |
1.95 |
|
|
$ |
4.73 |
|
Depreciation,
depletion and amortization expense
|
|
$ |
20.46 |
|
|
$ |
13.50 |
|
General
and administrative expenses
|
|
$ |
1.84 |
|
|
$ |
3.10 |
|
(1) Before
consideration of hedging transactions.
Oil and Natural Gas
Sales. Our oil and natural gas sales revenue decreased $140.6
million to $146.2 million in the first quarter of 2009 compared to the first
quarter of 2008. Sales are a function of volumes sold and average
sales prices. Our oil sales volumes increased 38% between periods,
while our natural gas sales volumes increased 15%. The oil volume
increase resulted primarily from drilling success in the North Dakota Bakken
area in addition to increased production at our two large CO2 projects,
Postle and North Ward Estes. Oil production from the Bakken increased
940 MBbl compared to the first quarter of 2008, while Postle oil production
increased 120 MBbl and North Ward Estes oil production increased 130 MBbl over
the same prior year period. These production increases were partially
offset by the Whiting USA Trust I (the “Trust”) divestiture, which
decreased oil production by 205 MBbl, as well as normal field production
decline. The gas volume increase between periods was primarily the
result of incremental gas production of 1,220 MMcf from the Flat Rock
acquisition, which we completed on May 30, 2008, higher production in the Boies
Ranch area of 840 MMcf, and new production of 700 MMcf from wells drilled in the
Gulf Coast region. These production increases were partially offset
by the Trust divestiture, which decreased gas production by 1,015 MMcf, as well
as normal field production decline. Offsetting the production
increases were decreases in average sales prices. Our average price
for oil before effects of hedging decreased 64% between periods, and our average
price for natural gas before effects of hedging decreased 52%.
Gain (Loss) on Oil and Natural Gas
Hedging Activities. Realized cash settlements on commodity
derivatives that we have designated as cash flow hedges are recognized as gain
(loss) on oil and natural gas hedging activities. During the first
quarter of 2009, we incurred cash settlement gains of $13.5 million on such
crude oil hedges. During the first quarter of 2008, we incurred
realized cash settlement losses of $22.9 million on crude oil derivatives
designated as cash flow hedges. None of our natural gas derivatives were
designated as cash flow hedges during the first quarter of 2009 or 2008.
Effective April 1, 2009, we elected to de-designate all of our commodity
derivative contracts that had been previously designated as cash flow hedges as
of March 31, 2009 and have elected to discontinue hedge accounting
prospectively. See Item 3, “Qualitative and Quantitative Disclosures About
Market Risk” for a list of our outstanding oil and natural gas derivatives as of
April 1, 2009.
Amortization of Deferred Gain on
Sale. In connection with the sale of 11,677,500 Trust units to the
public and related oil and gas property conveyance on April 30, 2008, we
recognized a deferred gain on sale of $100.1 million. This deferred gain
is amortized to income over the life of the Trust on a units-of-production
basis. For the three months ended March 31, 2009, we recognized $4.1
million in income as amortization of deferred gain on sale.
Lease Operating
Expenses. Our lease operating expenses during the first
quarter of 2009 were $61.0 million, a $5.2 million or 9% increase over the same
period in 2008. Our lease operating expenses per BOE decreased from
$14.89 during the first quarter of 2008 to $12.47 during the first quarter of
2009. The decrease of 16% on a BOE basis was primarily caused by
increased production during the first quarter of 2009, partially offset by a
high level of workover activity. Workovers amounted to $14.1 million
in the first quarter of 2009, as compared to $3.9 million in the first
quarter of 2008. The increase in workover activity primarily relates
to our two CO2 projects,
which are evolving past the construction and start-up phases and moving into an
ongoing maintenance and repair phase that involves a significantly higher number
of producing and injection wells.
Production
Taxes. The production taxes we pay are generally calculated as
a percentage of oil and natural gas sales revenue before the effects of
hedging. We take advantage of all credits and exemptions allowed in
our various taxing jurisdictions. Our production taxes for the first
quarter of 2009 and 2008 were 6.5% and 6.2%, respectively, of oil and natural
gas sales. Our production tax rate for the first quarter of 2009 was
greater than the rate for same period in 2008 mainly due to successful wells
completed in the North Dakota Bakken area during 2008, which carry an 11.5%
production tax rate.
Depreciation, Depletion and
Amortization. Our depreciation, depletion and amortization
(“DD&A”) expense increased $49.5 million as compared to the first quarter of
2008. The components of our DD&A expense were as follows (in
thousands):
|
|
Three
Months Ended
March
31,
|
|
|
|
|
|
|
|
|
Depletion
|
|
$ |
97,005 |
|
|
$ |
49,044 |
|
Depreciation
|
|
|
831 |
|
|
|
751 |
|
Accretion
of asset retirement obligations
|
|
|
2,198 |
|
|
|
716 |
|
Total
|
|
$ |
100,034 |
|
|
$ |
50,511 |
|
DD&A
increased $49.5 million primarily due to $48.0 million in higher depletion
expense between periods. Of this $48.0 million increase in depletion,
$15.0 million related to higher oil and gas volumes produced during the first
quarter of 2009, while $33.0 million related to our higher depletion rate in
2009. On a BOE basis, our DD&A rate increased by 52% from $13.50
for the first quarter of 2008 to $20.46 for the first quarter of
2009. The primary factors causing this rate increase were (i) $902.4
million in drilling expenditures incurred during the past twelve months, (ii)
net oil and natural gas reserve reductions of 11.6 MMBOE during 2008, which were
primarily attributable to a 39.0 MMBOE downward revision for lower oil and
natural gas prices at December 31, 2008, and (iii) the significant expenditures
necessary to develop proved undeveloped reserves, particularly related to the
enhanced oil recovery projects in the Postle and North Ward Estes fields,
whereby the development of proved undeveloped reserves does not increase
existing quantities of proved reserves. Under the successful efforts
method of accounting, costs to develop proved undeveloped reserves are added
into the DD&A rate when incurred.
Exploration and Impairment
Costs. Our exploration and impairment costs increased $6.3
million, as compared to the first quarter of 2008. The components of
exploration and impairment costs were as follows (in thousands):
|
|
Three
Months Ended
March
31,
|
|
|
|
|
|
|
|
|
Exploration
|
|
$ |
12,633 |
|
|
$ |
8,412 |
|
Impairment
|
|
|
4,681 |
|
|
|
2,572 |
|
Total
|
|
$ |
17,314 |
|
|
$ |
10,984 |
|
Exploration
costs increased $4.2 million during the first quarter of 2009 as compared to the
same period in 2008 primarily due to rig termination fees recognized in the
first quarter of 2009, partially offset by a decrease in geological and
geophysical (“G&G”) activity. Rig termination fees totaled $6.2
million during the first quarter of 2009, while we did not pay any rig
termination fees in the first quarter of 2008. G&G costs amounted
to $3.3 million during the first quarter of 2009, as compared to $5.1 million
during the first quarter of 2008. We did not drill any exploratory
dry holes during the first quarter of 2009 or 2008. The impairment
charges in the first quarter of 2009 and 2008 were primarily related to the
amortization of leasehold costs associated with individually insignificant
unproved properties. As of March 31, 2009, the amount of unproved
properties being amortized totaled $81.6 million, as compared to $55.0 million
as of March 31, 2008.
General and Administrative
Expenses. We report general and administrative expenses net of
third party reimbursements and internal allocations. The components
of our general and administrative expenses were as follows (in
thousands):
|
|
Three
Months Ended
March
31,
|
|
|
|
|
|
|
|
|
General
and administrative expenses
|
|
$ |
20,996 |
|
|
$ |
21,112 |
|
Reimbursements
and allocations
|
|
|
(12,016 |
) |
|
|
(9,497 |
) |
General
and administrative expense, net
|
|
$ |
8,980 |
|
|
$ |
11,615 |
|
General
and administrative expense before reimbursements and allocations decreased $0.1
million to $21.0 million during the first quarter of 2009. The
largest component of the decrease related to $4.1 million in lower accrued
distributions under our Production Participation Plan (“Plan”) between periods
due to a lower level of Plan net revenues (which have been reduced by lease
operating expenses and production taxes pursuant to the Plan formula) resulting
from lower oil and natural gas prices during the first quarter of 2009 as
compared to the same period of 2008. These lower accrued Plan
distributions were partially offset by $2.6 million in additional employee
compensation for personnel hired during the past twelve months as well as
general pay increases. The increase in reimbursements and allocations
in 2009 was caused by higher salary costs. Our general and
administrative expenses as a percentage of oil and natural gas sales increased
from 4% for the first quarter of 2008 to 6% for the first quarter of
2009. This increase was primarily due to decreased oil and gas sales
revenue as a result of lower oil and natural gas prices.
Interest
Expense. The components of our interest expense were as
follows (in thousands):
|
|
Three
Months Ended
March
31,
|
|
|
|
|
|
|
|
|
Senior
Subordinated Notes
|
|
$ |
10,768 |
|
|
$ |
11,080 |
|
Credit
Agreement
|
|
|
3,213 |
|
|
|
3,917 |
|
Amortization
of debt issue costs and debt discount
|
|
|
1,173 |
|
|
|
1,217 |
|
Other
|
|
|
450 |
|
|
|
353 |
|
Capitalized
interest
|
|
|
(924 |
) |
|
|
(1,021 |
) |
Total
interest expense
|
|
$ |
14,680 |
|
|
$ |
15,546 |
|
The
decrease in interest expense of $0.9 million between periods was mainly due to
lower interest rates on borrowings under our credit facility, partially offset
by a higher level of debt outstanding under our credit facility during the first
quarter of 2009. Our weighted average effective cash interest rate
was 4.6% during the first quarter of 2009 compared to 6.6% during the first
quarter of 2008. Our weighted average debt outstanding during the
first quarter of 2009 was $1,215.8 million versus $901.8 million for the first
quarter of 2008. After inclusion of non-cash interest costs for the
amortization of debt issue costs, debt discount and the accretion of the tax
sharing liability, our weighted average effective all-in interest rate was 5.0%
during the first quarter of 2009 compared to 7.1% during the first quarter of
2008.
Change in Production Participation
Plan Liability. For the three months ended March 31, 2009,
this non-cash expense was $0.4 million, a decrease of $5.8 million as compared
to the same period in 2008. This expense represents the change in the
vested present value of estimated future payments to be made to participants
after 2010 under our Plan. Although payments take place over the life
of the Plan’s oil and gas properties, which for some properties is over 20
years, we expense the present value of estimated future payments over the Plan’s
five-year vesting period. This expense in 2009 and 2008 primarily
reflected (i) changes to future cash flow estimates stemming from the volatile
commodity price environment during the past year, (ii) recent drilling activity
and property acquisitions, and (iii) employees’ continued vesting in the
Plan. The average NYMEX prices used to estimate this liability
decreased by $0.82 for crude oil and $0.22 for natural gas for the three months
ended March 31, 2009, as compared to increases of $3.23 for crude oil and $0.19
for natural gas over the same period in 2008. Assumptions that are
used to calculate this liability are subject to estimation and will vary from
year to year based on the current market for oil and gas, discount rates and
overall market conditions.
(Gain) Loss on Mark-to-Market
Derivatives. During 2008, we entered into commodity derivative
contracts that we did not designate as cash flow hedges. Accordingly,
these derivative contracts are marked-to-market each quarter with fair value
gains and losses recognized immediately in earnings. Cash flow is
only impacted to the extent that actual cash settlements under these contracts
result in making or receiving a payment from the counterparty, and such cash
settlement gains and losses are also recorded immediately to earnings as (gain)
loss on mark-to-market derivatives. During the first quarter of 2009,
we recognized $0.4 million in unrealized mark-to-market derivative losses and
$1.5 million in realized cash settlement gains. We also recognized a
loss of $22.9 million for the ineffective portion of changes in fair value on
our commodity derivatives designated as cash flow hedges. During the
first quarter of 2008, we recognized $2.9 million in unrealized mark-to-market
derivative gains on contracts not designated as cash flow hedges.
Income Tax Expense
(Benefit). Income tax benefit totaled $26.0 million for the
first quarter of 2009, versus $36.5 million of income tax expense for the first
quarter of 2008. Our effective income tax rate increased from 36.9%
for the first quarter of 2008 to 37.3% for the first quarter of
2009. Our effective income tax rate was higher in 2009 due to tax
benefits resulting from changes to state apportionment.
Net Income
(Loss). Net income (loss) decreased from $62.3 million in
income during the first quarter of 2008 to a $43.8 million loss during the first
quarter of 2009. The primary reasons for this decrease include a 55%
decrease in oil prices (net of hedging); a 51% decrease in natural gas prices
(net of hedging); higher lease operating expenses, DD&A, and exploration and
impairment; and unrealized losses on commodity derivatives. These
negative factors were partially offset by a 31% increase in equivalent volumes
sold; lower production taxes, general and administrative expenses, interest
expense, Production Participation Plan expense and income taxes; and
amortization of deferred gain on sale during the first quarter of
2009.
Liquidity
and Capital Resources
Overview. At March
31, 2009, our debt to total capitalization ratio was 37.1%, we had $7.0 million
of cash on hand and $2,019.2 million of stockholders’ equity. At
December 31, 2008, our debt to total capitalization ratio was 40.7%, we had
$9.6 million of cash on hand and $1,808.8 million of stockholders’
equity. In the first quarter of 2009, we generated $34.2 million of
cash provided by operating activities, a decrease of $88.2 million over the same
period in 2008. Cash provided by operating activities decreased
primarily due to lower average sales prices for both crude oil and natural gas,
partially offset by higher oil and gas volumes produced in the first quarter of
2009. We also generated $184.9 million from financing activities
consisting of $234.9 million in net proceeds received from the issuance of our
common stock, offset by net repayments under our credit agreement totaling $50.0
million. Cash flows from operating and financing activities were used
to finance $201.2 million of drilling and development expenditures paid in the
first quarter of 2009 and $20.7 million of cash acquisition capital
expenditures. The following chart details our exploration and
development expenditures incurred by region during the first quarter of 2009 (in
thousands):
|
|
Drilling
and Development Expenditures
|
|
|
|
|
|
|
|
|
|
|
Rocky
Mountains
|
|
$ |
101,266 |
|
|
$ |
7,463 |
|
|
$ |
108,729 |
|
|
|
62 |
% |
Permian
Basin
|
|
|
48,133 |
|
|
|
3,584 |
|
|
|
51,717 |
|
|
|
29 |
% |
Mid-Continent
|
|
|
12,476 |
|
|
|
266 |
|
|
|
12,742 |
|
|
|
7 |
% |
Gulf
Coast
|
|
|
1,069 |
|
|
|
1,320 |
|
|
|
2,389 |
|
|
|
1 |
% |
Michigan
|
|
|
839 |
|
|
|
- |
|
|
|
839 |
|
|
|
1 |
% |
Total incurred
|
|
|
163,783 |
|
|
|
12,633 |
|
|
|
176,416 |
|
|
|
100 |
% |
Decrease
in accrued capital expenditures
|
|
|
37,368 |
|
|
|
- |
|
|
|
37,368 |
|
|
|
|
|
Total paid
|
|
$ |
201,151 |
|
|
$ |
12,633 |
|
|
$ |
213,784 |
|
|
|
|
|
We
continually evaluate our capital needs and compare them to our capital
resources. Our current 2009 capital budget for exploration and
development expenditures is $420.6 million, which we expect to fund with net
cash provided by our operating activities and a portion of the proceeds from the
common stock offering we completed in February 2009. Our 2009 capital
budget of $420.6 million, however, represents a significant decrease from the
$947.4 million incurred on exploration and development expenditures during
2008. This reduced capital budget is in response to significantly
lower oil and natural gas prices experienced during the fourth quarter of 2008
and continuing into 2009. Although we have no specific budget for
property acquisitions in 2009, we will continue to selectively pursue property
acquisitions that complement our existing core property base. We
believe that should attractive acquisition opportunities arise or exploration
and development expenditures exceed $420.6 million, we will be able to finance
additional capital expenditures with cash on hand, cash flows from operating
activities, borrowings under our credit agreement, issuances of additional debt
or equity securities, or agreements with industry partners. Our level
of exploration and development expenditures is largely discretionary, and the
amount of funds devoted to any particular activity may increase or decrease
significantly depending on available opportunities, commodity prices, cash flows
and development results, among other factors. We believe that we have
sufficient liquidity and capital resources to execute our business plans over
the next 12 months and for the foreseeable future.
Credit
Agreement. As of March 31, 2009, Whiting Oil and Gas
Corporation, (“Whiting Oil and Gas”), our wholly-owned subsidiary, had a $1.2
billion credit agreement with a syndicate of banks that had a borrowing base of
$900.0 million with $327.2 million of available borrowing capacity, which is net
of $570.0 million in borrowings and $2.8 million in letters of credit
outstanding. At March 31, 2009, the effective weighted average
interest rate on the outstanding principal balance under the credit facility was
1.8% and we were in compliance with our covenants under the credit
agreement.
On April
28, 2009, we entered into a Fourth Amended and Restated Credit Agreement with
our bank syndicate, which replaced the existing credit facility. This
amended credit agreement increased our borrowing base under the facility from
$900.0 million to $1.1 billion and extended the principal repayment date to
April 2012. The borrowing base under the credit agreement is
determined at the discretion of the lenders, based on the collateral value of
our proved reserves that have been mortgaged to our lenders, and is subject to
regular redeterminations on May 1 and November 1 of each year, as well as
special redeterminations described in the credit agreement, in each case which
may reduce the amount of the borrowing base. A portion of the
revolving credit facility in an aggregate amount not to exceed $50.0 million may
be used to issue letters of credit for the account of Whiting Oil and Gas or
other designated subsidiaries of ours. As of April 27, 2009, Whiting
Oil and Gas had borrowed $610.0 million and had $2.8 million of letters of
credit outstanding under the credit agreement.
The
credit agreement provides for interest only payments until April 2012, when the
entire amount borrowed is due. Interest accrues at our option at
either (i) a base rate for a base rate loan plus the margin in the table below,
where the base rate is defined as the greatest of the prime rate, the federal
funds rate plus 0.50% or an adjusted LIBOR rate plus 1.00%, or (ii) an adjusted
LIBOR rate for a Eurodollar loan plus the margin in the table
below.
Ratio of Outstanding Borrowings to Borrowing
Base
|
|
Applicable
Margin for Base Rate
Loans
|
|
Applicable
Margin for Eurodollar
Loans
|
Less
than 0.25 to 1.0
|
|
1.1250%
|
|
2.00%
|
Greater
than or equal to 0.25 to 1.0 but less than 0.50 to 1.0
|
|
1.1375%
|
|
2.25%
|
Greater
than or equal to 0.50 to 1.0 but less than 0.75 to 1.0
|
|
1.6250%
|
|
2.50%
|
Greater
than or equal to 0.75 to 1.0 but less than 0.90 to 1.0
|
|
1.8750%
|
|
2.75%
|
Greater
than or equal to 0.90 to 1.0
|
|
2.1250%
|
|
3.00%
|
Under the
credit agreement, we also incur commitment fees of 0.50% on the unused portion
of the lesser of the aggregate commitments of the lenders or the borrowing
base.
The
credit agreement contains restrictive covenants that may limit our ability to,
among other things, incur additional indebtedness, sell assets, make loans to
others, make investments, enter into mergers, enter into hedging contracts,
incur liens and engage in certain other transactions without the prior consent
of our lenders. The credit agreement requires us, as of the last day
of any quarter, (i) to not exceed a total debt to EBITDAX ratio (as defined in
the credit agreement) for the last four quarters of 4.5 to 1.0 for quarters
ending prior to and on September 30, 2010, 4.25 to 1.0 for quarters ending
December 31, 2010 to June 30, 2011 and 4.0 to 1.0 for quarters ending September
30, 2011 and thereafter, (ii) to have a consolidated current assets to
consolidated current liabilities ratio (as defined in the credit agreement) of
not less than 1.0 to 1.0 and (iii) to not exceed a senior secured debt to
EBITDAX ratio (as defined in the credit agreement) for the last four quarters of
2.75 to 1.0 for quarters ending prior to and on December 31, 2009 and 2.5 to 1.0
for quarters ending March 31, 2010 and thereafter. Except for limited
exceptions, the credit agreement restricts our ability to make any dividends or
distributions on our common stock or principal payments on our senior
notes.
The
obligations of Whiting Oil and Gas under the credit agreement are secured by a
first lien on substantially all of Whiting Oil and Gas’ properties included in
the borrowing base for the credit agreement. We and our subsidiary
Equity Oil Company have guaranteed the obligations of Whiting Oil and Gas under
the credit agreement. We have pledged the stock of Whiting Oil and
Gas and Equity Oil Company as security for our guarantee, and Equity Oil Company
has mortgaged substantially all of its properties included in the borrowing base
for the credit agreement as security for its guarantee.
Senior Subordinated
Notes. In October 2005, we issued at par
$250.0 million of 7% Senior Subordinated Notes due 2014. In
April 2005, we issued $220.0 million of 7.25% Senior Subordinated Notes due
2013. These notes were issued at 98.507% of par, and the associated
discount is being amortized to interest expense over the term of these
notes. In May 2004, we issued $150.0 million of 7.25%
Senior Subordinated Notes due 2012. These notes were issued at 99.26%
of par, and the associated discount is being amortized to interest expense over
the term of these notes.
The notes
are unsecured obligations of ours and are subordinated to all of our senior
debt, which currently consists of Whiting Oil and Gas’ credit
agreement. The indentures governing the notes restrict us from
incurring additional indebtedness, subject to certain exceptions, unless our
fixed charge coverage ratio (as defined in the indentures) is at least 2.0 to
1. If we were in violation of this covenant, then we may not be able
to incur additional indebtedness, including under Whiting Oil and Gas
Corporation’s credit agreement. Additionally, the indentures
governing the notes contain restrictive covenants that may limit our ability to,
among other things, pay cash dividends, redeem or repurchase our capital stock
or our subordinated debt, make investments or issue preferred stock, sell
assets, consolidate, merge or transfer all or substantially all of the assets of
ours and our restricted subsidiaries taken as a whole and enter into hedging
contracts. These covenants may potentially limit the discretion of
our management in certain respects. We were in compliance with these
covenants as of March 31, 2009. However, a substantial or extended
decline in oil or natural gas prices may adversely affect our ability to comply
with these covenants in the future. Our wholly-owned operating
subsidiaries, Whiting Oil and Gas Corporation, Whiting Programs, Inc. and Equity
Oil Company, have fully, unconditionally, jointly and severally guaranteed our
obligations under the notes.
Shelf Registration
Statement. We have on file with the SEC a universal shelf
registration statement to allow us to offer an indeterminate amount of
securities in the future. Under the registration statement, we may
periodically offer from time to time debt securities, common stock, preferred
stock, warrants and other securities or any combination of such securities in
amounts, prices and on terms announced when and if the securities are
offered. However, we recognize that the issuance of additional
securities in periods of market volatility may be less likely. The
specifics of any future offerings, along with the use of proceeds of any
securities offered, will be described in detail in a prospectus supplement at
the time of any such offering.
Schedule of Contractual
Obligations. The table below does not include our Production
Participation Plan liabilities since we cannot determine with accuracy the
timing or amounts of future payments. The following table summarizes
our obligations and commitments as of March 31, 2009 to make future payments
under certain contracts, aggregated by category of contractual obligation, for
specified time periods (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt (a)
|
|
$ |
1,190,000 |
|
|
$ |
- |
|
|
$ |
570,000 |
|
|
$ |
620,000 |
|
|
$ |
- |
|
Cash
interest expense on debt (b)
|
|
|
198,064 |
|
|
|
54,786 |
|
|
|
93,009 |
|
|
|
50,269 |
|
|
|
- |
|
Asset
retirement obligation (c)
|
|
|
69,691 |
|
|
|
9,853 |
|
|
|
2,929 |
|
|
|
8,812 |
|
|
|
48,097 |
|
Tax
sharing liability (d)
|
|
|
24,096 |
|
|
|
2,112 |
|
|
|
3,787 |
|
|
|
3,261 |
|
|
|
14,936 |
|
Derivative
contract liability fair value (e)
|
|
|
37,340 |
|
|
|
13,456 |
|
|
|
16,214 |
|
|
|
7,670 |
|
|
|
- |
|
Purchasing
obligations (f)
|
|
|
143,588 |
|
|
|
27,074 |
|
|
|
63,536 |
|
|
|
47,040 |
|
|
|
5,938 |
|
Drilling
rig contracts (g)
|
|
|
117,052 |
|
|
|
48,142 |
|
|
|
58,479 |
|
|
|
10,431 |
|
|
|
- |
|
Operating
leases (h)
|
|
|
13,266 |
|
|
|
2,525 |
|
|
|
6,245 |
|
|
|
4,496 |
|
|
|
- |
|
Total
|
|
$ |
1,793,097 |
|
|
$ |
157,948 |
|
|
$ |
814,199 |
|
|
$ |
751,979 |
|
|
$ |
68,971 |
|
________________
(a)
|
Long-term
debt consists of the 7.25% Senior Subordinated Notes due 2012 and 2013,
the 7% Senior Subordinated Notes due 2014 and the outstanding borrowings
under our credit agreement, and assumes no principal repayment until the
due date of the instruments. In April 2009, we entered into a
Fourth Amended and Restated Credit Agreement, which replaces our existing
credit facility and extends the principal repayment due date to April
2012.
|
(b)
|
Cash
interest expense on the 7.25% Senior Subordinated Notes due 2012 and 2013
and the 7% Senior Subordinated Notes due 2014 is estimated assuming no
principal repayment until the due date of the instruments. Cash
interest expense on the credit agreement is estimated assuming no
principal repayment until the instrument due date and is estimated at a
fixed interest rate of 1.8%.
|
(c)
|
Asset
retirement obligations represent the present value of estimated amounts
expected to be incurred in the future to plug and abandon oil and gas
wells, remediate oil and gas properties and dismantle their related
facilities.
|
(d)
|
Amounts
shown represent the present value of estimated payments due to Alliant
Energy based on projected future income tax benefits attributable to an
increase in our tax bases. As a result of the Tax Separation
and Indemnification Agreement signed with Alliant Energy, the increased
tax bases are expected to result in increased future income tax deductions
and, accordingly, may reduce income taxes otherwise payable by
us. Under this agreement, we have agreed to pay Alliant Energy
90% of the future tax benefits we realize annually as a result of this
step up in tax basis for the years ending on or prior to December 31,
2013. In 2014, we will be obligated to pay Alliant Energy the
present value of the remaining tax benefits assuming all such tax benefits
will be realized in future years.
|
(e)
|
The
above derivative obligation at March 31, 2009 consists of a $30.1 million
payable to Whiting USA Trust I (“Trust”) for derivative contracts that we
have entered into but have in turn conveyed to the
Trust. Although these derivatives are in a fair value asset
position at quarter end, 75.8% of such derivative assets are due to the
Trust under the terms of the conveyance. The above derivative
obligation at March 31, 2009 also consists of a $7.2 million fair value
liability for derivative contracts we have entered into on our own behalf,
primarily in the form of costless collars, to hedge our exposure to crude
oil and natural gas price fluctuations. With respect to our
open derivative contracts at March 31, 2009 with certain counterparties,
the forward price curves for crude oil and natural gas generally exceeded
the price curves that were in effect when these contracts were entered
into, resulting in a derivative fair value liability. If
current market prices are higher than a collar’s price ceiling when the
cash settlement amount is calculated, we are required to pay the contract
counterparties. The ultimate settlement amounts under our
derivative contracts are unknown, however, as they are subject to
continuing market and commodity price
risk.
|
(f)
|
We
have two take-or-pay purchase agreements, one agreement expiring in March
2014 and one agreement expiring in December 2014, whereby we have
committed to buy certain volumes of CO2, for
use in enhanced recovery projects in our Postle field in Oklahoma and our
North Ward Estes field in Texas. The purchase agreements are
with different suppliers. Under the terms of the agreements, we
are obligated to purchase a minimum daily volume of CO2 (as
calculated on an annual basis) or else pay for any deficiencies at the
price in effect when the minimum delivery was to have
occurred. The CO2
volumes planned for use on the enhanced recovery projects in the Postle
and North Ward Estes fields currently exceed the minimum daily volumes
provided in these take-or-pay purchase agreements. Therefore,
we expect to avoid any payments for
deficiencies.
|
(g)
|
We
currently have seven drilling rigs under long-term contract, of which two
drilling rigs expire in 2009, two in 2010, one in 2011, one in 2012 and
one in 2013. All of these rigs are operating in the Rocky
Mountains region. Included in the above obligation is $3.7
million of rig termination fees that we accrued as a current payable at
March 31, 2009 for the cancellation of long-term contracts on three
drilling rigs and one workover rig. As of March 31, 2009, early
termination of the remaining contracts would require additional
termination penalties of $68.3 million, which would be in lieu of paying
the remaining drilling commitments of $113.4 million. No other
drilling rigs working for us are currently under long-term contracts or
contracts that cannot be terminated at the end of the well that is
currently being drilled. Due to the short-term and
indeterminate nature of the drilling time remaining on rigs drilling on a
well-by-well basis, such obligations have not been included in this
table.
|
(h)
|
We
lease 107,400 square feet of administrative office space in Denver,
Colorado under an operating lease arrangement expiring in 2013, and an
additional 46,700 square feet of office space in Midland,
Texas expiring in 2012.
|
Based on
current oil and natural gas prices and anticipated levels of production, we
believe that the estimated net cash generated from operations, together with
cash on hand and amounts available under our credit agreement, will be adequate
to meet future liquidity needs, including satisfying our financial obligations
and funding our operations and exploration and development
activities.
New
Accounting Pronouncements
On
December 31, 2008, the SEC published the final rules and interpretations
updating its oil and gas reporting requirements. Many of the revisions are
updates to definitions in the existing oil and gas rules to make them consistent
with the petroleum resource management system, which is a widely accepted
standard for the management of petroleum resources that was developed by several
industry organizations. Key revisions include the ability to include
nontraditional resources in reserves, the use of new technology for determining
reserves, permitting disclosure of probable and possible reserves, and changes
to the pricing used to determine reserves in that companies must use a 12-month
average price. The average is calculated using the
first-day-of-the-month price for each of the 12 months that make up the
reporting period. The SEC will require companies to comply with the
amended disclosure requirements for registration statements filed after January
1, 2010, and for annual reports for fiscal years ending on or after December 31,
2009. Early adoption is not permitted. We are currently assessing
the impact that the adoption will have on our disclosures, operating results,
statement of financial position and statement of cash flows.
In April
2009, the FASB issued Staff Position (“FSP”) No. FAS 157-4, Determining Fair Value When the
Volume or Level of Activity for the Asset or Liability Have Significantly
Decreased and Identifying Transactions That Are Not Orderly ("FSP
157-4"). The adoption of FSP 157-4 is not expected to have an impact
on our consolidated financial statements, other than additional
disclosures. FSP 157-4 provides additional guidance for estimating
fair value in accordance with SFAS No. 157 when the volume and level of activity
for the asset or liability have significantly decreased and requires that
companies provide interim and annual disclosures of the inputs and valuation
technique(s) used to measure fair value. FSP 157-4 is effective for
interim and annual reporting periods ending after June 15, 2009 and is to be
applied prospectively.
In April
2009, the FASB issued FSP No. 107-1 and APB 28-1, Interim Disclosures about Fair Value
of Financial Instruments (“FSP 107-1”). The adoption of FSP
107-1 is not expected to have an impact on our consolidated financial
statements, other than additional disclosures. FSP 107-1 requires disclosures
about fair value of financial instruments for interim reporting periods of
publicly traded companies as well as in annual financial
statements. FSP 107-1 is effective for interim and annual reporting
periods ending after June 15, 2009.
Critical
Accounting Policies and Estimates
Information
regarding critical accounting policies and estimates is contained in Item 7
of our Annual Report on Form 10-K for the fiscal year ended December 31,
2008.
Effects
of Inflation and Pricing
We
experienced increased costs during 2008 due to increased demand for oil field
products and services. The oil and gas industry is very cyclical and
the demand for goods and services of oil field companies, suppliers and others
associated with the industry put extreme pressure on the economic stability and
pricing structure within the industry. Typically, as prices for oil
and natural gas increase, so do all associated costs. Conversely, in
a period of declining prices, associated cost declines are likely to lag and
have not adjusted downward in proportion. Material changes in prices
also impact the current revenue stream, estimates of future reserves, borrowing
base calculations of bank loans, impairment assessments of oil and gas
properties, and values of properties in purchase and sale
transactions. Material changes in prices can impact the value of oil
and gas companies and their ability to raise capital, borrow money and retain
personnel. While we do not currently expect business costs to
materially increase, higher prices for oil and natural gas could result in
increases in the costs of materials, services and personnel.
Forward-Looking
Statements
This
report contains statements that we believe to be “forward-looking statements”
within the meaning of the Private Securities Litigation Reform Act of
1995. All statements other than historical facts, including, without
limitation, statements regarding our future financial position, business
strategy, projected revenues, earnings, costs, capital expenditures and debt
levels, and plans and objectives of management for future operations, are
forward-looking statements. When used in this report, words such as
we “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe” or “should”
or the negative thereof or variations thereon or similar terminology are
generally intended to identify forward-looking statements. Such
forward-looking statements are subject to risks and uncertainties that could
cause actual results to differ materially from those expressed in, or implied
by, such statements.
These
risks and uncertainties include, but are not limited to: declines in
oil or natural gas prices; impacts of the global recession and financial crisis;
our level of success in exploitation, exploration, development and production
activities; adverse weather conditions that may negatively impact development or
production activities; the timing of our exploration and development
expenditures, including our ability to obtain CO2;
inaccuracies of our reserve estimates or our assumptions underlying them;
revisions to reserve estimates as a result of changes in commodity prices; risks
related to our level of indebtedness and periodic redeterminations of Whiting
Oil and Gas Corporation’s borrowing base under our credit agreement; our ability
to generate sufficient cash flows from operations to meet the internally funded
portion of our capital expenditures budget; our ability to obtain external
capital to finance exploration and development operations and acquisitions; our
ability to identify and complete acquisitions, and to successfully integrate
acquired businesses; unforeseen underperformance of or liabilities associated
with acquired properties; our ability to successfully complete potential asset
dispositions; failure of our properties to yield oil or gas in commercially
viable quantities; uninsured or underinsured losses resulting from our oil and
gas operations; our inability to access oil and gas markets due to market
conditions or operational impediments; the impact and costs of compliance with
laws and regulations governing our oil and gas operations; our ability to
replace our oil and natural gas reserves; any loss of our senior management or
technical personnel; competition in the oil and gas industry in the regions in
which we operate; risks arising out of our hedging transactions; and other risks
described under the caption “Risk Factors” in our Annual Report on Form 10-K for
the fiscal year ended December 31, 2008. We assume no obligation, and
disclaim any duty, to update the forward-looking statements in this
report.
|
Quantitative and Qualitative Disclosures about
Market Risk
|
Our
quantitative and qualitative disclosures about market risk for changes in
commodity prices and interest rates are included in Item 7A of our Annual Report
on Form 10-K for the fiscal year ended December 31, 2008 and have not
materially changed since that report was filed.
Our
outstanding hedges as of April 1, 2009 are summarized below:
Whiting
Petroleum Corporation
|
|
|
|
|
|
Weighted
Average NYMEX Floor/Ceiling
|
Crude
Oil
|
|
04/2009
to 06/2009
|
|
518,000
|
|
$55.12/$65.68
|
Crude
Oil
|
|
07/2009
to 09/2009
|
|
496,000
|
|
$57.12/$69.55
|
Crude
Oil
|
|
10/2009
to 12/2009
|
|
478,000
|
|
$61.04/$74.89
|
Crude
Oil
|
|
01/2010
to 03/2010
|
|
430,000
|
|
$60.27/$74.81
|
Crude
Oil
|
|
04/2010
to 06/2010
|
|
415,000
|
|
$62.69/$80.09
|
Crude
Oil
|
|
07/2010
to 09/2010
|
|
405,000
|
|
$60.28/$76.98
|
Crude
Oil
|
|
10/2010
to 12/2010
|
|
390,000
|
|
$60.29/$78.23
|
Crude
Oil
|
|
01/2011
to 03/2011
|
|
360,000
|
|
$60.32/$80.33
|
Crude
Oil
|
|
04/2011
to 06/2011
|
|
360,000
|
|
$60.32/$80.33
|
Crude
Oil
|
|
07/2011
to 09/2011
|
|
360,000
|
|
$60.32/$80.33
|
Crude
Oil
|
|
10/2011
to 12/2011
|
|
360,000
|
|
$60.32/$80.33
|
Crude
Oil
|
|
01/2012
to 03/2012
|
|
330,000
|
|
$60.35/$81.70
|
Crude
Oil
|
|
04/2012
to 06/2012
|
|
330,000
|
|
$60.35/$81.70
|
Crude
Oil
|
|
07/2012
to 09/2012
|
|
330,000
|
|
$60.35/$81.70
|
Crude
Oil
|
|
10/2012
to 12/2012
|
|
330,000
|
|
$60.35/$81.70
|
Crude
Oil
|
|
01/2013
to 03/2013
|
|
290,000
|
|
$60.40/$81.66
|
Crude
Oil
|
|
04/2013
to 06/2013
|
|
290,000
|
|
$60.40/$81.66
|
Crude
Oil
|
|
07/2013
to 09/2013
|
|
290,000
|
|
$60.40/$81.66
|
Crude
Oil
|
|
10/2013
|
|
290,000
|
|
$60.40/$81.66
|
Crude
Oil
|
|
11/2013
|
|
190,000
|
|
$59.29/$78.43
|
In
connection with our conveyance on April 30, 2008 of a term net profits interest
to Whiting USA Trust I (as further explained above in the note on Acquisitions
and Divestitures), the rights to any future hedge payments we make or receive on
certain of our derivative contracts, representing 1,859 MBbls of crude oil and
7,176 MMcf of natural gas from 2009 through 2012, have been conveyed to the
Trust, and therefore such payments will be included in the Trust’s calculation
of net proceeds. Under the terms of the aforementioned conveyance, we
retain 10% of the net proceeds from the underlying properties. Our
retention of 10% of these net proceeds combined with our ownership of 2,186,389
Trust units, results in third-party public holders of Trust units receiving
75.8%, while we retain 24.2%, of future economic results of such
hedges. No additional hedges are allowed to be placed on Trust
assets.
The table
below summarizes all of the costless collars that we entered into and then in
turn conveyed, as described in the preceding paragraph, to Whiting USA Trust I
(of which we retain 24.2% of the future economic results and third-party public
holders of Trust units receive 75.8% of the future economic
results):
Conveyed
to Whiting USA Trust I
|
|
|
|
Monthly
Volume
(Bbl)/(MMBtu)
|
|
Weighted
Average NYMEX Floor/Ceiling
|
Crude
Oil
|
|
04/2009
to 06/2009
|
|
48,794
|
|
$76.00/$137.55
|
Crude
Oil
|
|
07/2009
to 09/2009
|
|
47,510
|
|
$76.00/$136.41
|
Crude
Oil
|
|
10/2009
to 12/2009
|
|
46,240
|
|
$76.00/$135.72
|
Crude
Oil
|
|
01/2010
to 03/2010
|
|
45,084
|
|
$76.00/$135.09
|
Crude
Oil
|
|
04/2010
to 06/2010
|
|
43,978
|
|
$76.00/$134.85
|
Crude
Oil
|
|
07/2010
to 09/2010
|
|
42,966
|
|
$76.00/$134.89
|
Crude
Oil
|
|
10/2010
to 12/2010
|
|
41,924
|
|
$76.00/$135.11
|
Crude
Oil
|
|
01/2011
to 03/2011
|
|
40,978
|
|
$74.00/$139.68
|
Crude
Oil
|
|
04/2011
to 06/2011
|
|
40,066
|
|
$74.00/$140.08
|
Crude
Oil
|
|
07/2011
to 09/2011
|
|
39,170
|
|
$74.00/$140.15
|
Crude
Oil
|
|
10/2011
to 12/2011
|
|
38,242
|
|
$74.00/$140.75
|
Crude
Oil
|
|
01/2012
to 03/2012
|
|
37,412
|
|
$74.00/$141.27
|
Crude
Oil
|
|
04/2012
to 06/2012
|
|
36,572
|
|
$74.00/$141.73
|
Crude
Oil
|
|
07/2012
to 09/2012
|
|
35,742
|
|
$74.00/$141.70
|
Crude
Oil
|
|
10/2012
to 12/2012
|
|
35,028
|
|
$74.00/$142.21
|
Natural
Gas
|
|
04/2009
to 06/2009
|
|
201,263
|
|
$6.00/$14.85
|
Natural
Gas
|
|
07/2009
to 09/2009
|
|
192,870
|
|
$6.00/$15.60
|
Natural
Gas
|
|
10/2009
to 12/2009
|
|
185,430
|
|
$7.00/$14.85
|
Natural
Gas
|
|
01/2010
to 03/2010
|
|
178,903
|
|
$7.00/$18.65
|
Natural
Gas
|
|
04/2010
to 06/2010
|
|
172,873
|
|
$6.00/$13.20
|
Natural
Gas
|
|
07/2010
to 09/2010
|
|
167,583
|
|
$6.00/$14.00
|
Natural
Gas
|
|
10/2010
to 12/2010
|
|
162,997
|
|
$7.00/$14.20
|
Natural
Gas
|
|
01/2011
to 03/2011
|
|
157,600
|
|
$7.00/$17.40
|
Natural
Gas
|
|
04/2011
to 06/2011
|
|
152,703
|
|
$6.00/$13.05
|
Natural
Gas
|
|
07/2011
to 09/2011
|
|
148,163
|
|
$6.00/$13.65
|
Natural
Gas
|
|
10/2011
to 12/2011
|
|
142,787
|
|
$7.00/$14.25
|
Natural
Gas
|
|
01/2012
to 03/2012
|
|
137,940
|
|
$7.00/$15.55
|
Natural
Gas
|
|
04/2012
to 06/2012
|
|
134,203
|
|
$6.00/$13.60
|
Natural
Gas
|
|
07/2012
to 09/2012
|
|
130,173
|
|
$6.00/$14.45
|
Natural
Gas
|
|
10/2012
to 12/2012
|
|
126,613
|
|
$7.00/$13.40
|
The
collared hedges shown above have the effect of providing a protective floor
while allowing us to share in upward pricing movements. Consequently,
while these hedges are designed to decrease our exposure to price decreases,
they also have the effect of limiting the benefit of price increases above the
ceiling. For the 2009 crude oil contracts listed in both tables
above, a hypothetical $1.00 change in the NYMEX price above the ceiling price or
below the floor price applied to the notional amounts would cause a change in
our gain (loss) on mark-to-market derivatives in 2009 of $4.6
million. For the 2009 natural gas contracts listed above, a
hypothetical $0.10 change in the NYMEX price above the ceiling price or below
the floor price applied to the notional amounts would cause a change in our gain
(loss) on mark-to-market derivatives in 2009 of $0.04 million.
In a 1997
acquisition of non-operated properties, we became subject to the operator’s
fixed price gas sales contract with end users for a portion of the natural gas
we produce in Michigan. This contract has built-in pricing escalators
of 4% per year. Our estimated future production volumes to be sold
under the fixed pricing terms of this contract as of April 1, 2009 are
summarized below:
|
|
|
|
|
|
|
Natural
Gas
|
|
04/2009
to 05/2011
|
|
23,000
|
|
$
5.14
|
Natural
Gas
|
|
04/2009
to 09/2012
|
|
67,000
|
|
$
4.56
|
Evaluation of disclosure controls
and procedures. In accordance with Rule 13a-15(b) of the
Securities Exchange Act of 1934 (the “Exchange Act”), our management evaluated,
with the participation of our Chairman, President and Chief Executive Officer
and our Chief Financial Officer, the effectiveness of the design and operation
of our disclosure controls and procedures (as defined in Rule 13a-15(e) under
the Exchange Act) as of March 31, 2009. Based upon their evaluation
of these disclosures controls and procedures, the Chairman, President and Chief
Executive Officer and the Chief Financial Officer concluded that the disclosure
controls and procedures were effective as of March 31, 2009 to ensure that
information required to be disclosed by us in the reports that we file or submit
under the Exchange Act is recorded, processed, summarized and reported within
the time periods specified in the rules and forms of the Securities and Exchange
Commission, and to ensure that information required to be disclosed by us in the
reports we file or submit under the Exchange Act is accumulated and communicated
to our management, including our principal executive and principal financial
officers, as appropriate, to allow timely decisions regarding required
disclosure.
Changes in internal control over
financial reporting. There was no change in our internal
control over financial reporting that occurred during the quarter ended March
31, 2009 that has materially affected, or is reasonably likely to materially
affect, our internal control over financial reporting.
PART II –
OTHER INFORMATION
Whiting
is subject to litigation claims and governmental and regulatory proceedings
arising in the ordinary course of business. It is management’s
opinion that all claims and litigation we are involved in are not likely to have
a material adverse effect on our consolidated financial position, cash flows or
results of operations.
Risk
factors relating to us are contained in Item 1A of our Annual Report on Form
10-K for the fiscal year ended December 31, 2008. No material change
to such risk factors has occurred during the three months ended March 31,
2009.
The
exhibits listed in the accompanying index to exhibits are filed as part of this
Quarterly Report on Form 10-Q.
SIGNATURES
Pursuant
to the requirements 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, on this 30th day of April, 2009.
|
|
WHITING
PETROLEUM CORPORATION
|
|
|
|
|
|
|
|
By
|
/s/
James J. Volker
|
|
|
James
J. Volker
|
|
|
Chairman,
President and Chief Executive Officer
|
|
|
|
|
|
|
|
By
|
/s/
Michael J. Stevens
|
|
|
Michael
J. Stevens
|
|
|
Vice
President and Chief Financial Officer
|
|
|
|
|
|
|
|
By
|
/s/
Brent P. Jensen
|
|
|
Brent
P. Jensen
|
|
|
Controller
and Treasurer
|
Exhibit
Number
|
Exhibit Description
|
(4.1)
|
Fourth
Amended and Restated Credit Agreement, dated as of April 28, 2009, among
Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, the
lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent,
and the various other agents party thereto [Incorporated by reference to
Exhibit 4 to Whiting Petroleum Corporation’s Current Report on Form 8-K
dated April 28, 2009 (File No. 001-31899)].
|
(31.1)
|
Certification
by the Chairman, President and Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act.
|
(31.2)
|
Certification
by the Vice President and Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act.
|
(32.1)
|
Written
Statement of the Chairman, President and Chief Executive Officer pursuant
to 18 U.S.C. Section 1350.
|
(32.2)
|
Written
Statement of the Vice President and Chief Financial Officer pursuant to 18
U.S.C. Section 1350.
|
46