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, 2007
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 is a large accelerated filer, an
accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of
the
Exchange Act).
Large
accelerated filer T Accelerated
filer £ Non-accelerated
filer £
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 16,
2007: 37,053,071 shares.
PART
I – FINANCIAL INFORMATION
Item 1.
|
Consolidated Financial Statements
(Unaudited)
|
WHITING
PETROLEUM CORPORATION
CONDENSED
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In
thousands)
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
8,188
|
|
|
$ |
10,372
|
|
Accounts
receivable trade, net
|
|
|
90,194
|
|
|
|
97,831
|
|
Deferred
income taxes
|
|
|
5,208
|
|
|
|
3,025
|
|
Prepaid
expenses and other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
current assets
|
|
|
117,134
|
|
|
|
121,712
|
|
|
|
|
|
|
|
|
|
|
PROPERTY
AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
Oil
and gas properties, successful efforts method:
|
|
|
|
|
|
|
|
|
Proved
properties
|
|
|
2,952,031
|
|
|
|
2,828,282
|
|
Unproved
properties
|
|
|
60,696
|
|
|
|
55,297
|
|
Other
property and equipment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
property and equipment
|
|
|
3,056,374
|
|
|
|
2,928,481
|
|
|
|
|
|
|
|
|
|
|
Less
accumulated depreciation, depletion and amortization
|
|
|
(535,682 |
) |
|
|
(495,820 |
) |
|
|
|
|
|
|
|
|
|
Total
property and equipment, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEBT
ISSUANCE COSTS
|
|
|
18,233
|
|
|
|
19,352
|
|
|
|
|
|
|
|
|
|
|
OTHER
LONG-TERM ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
$ |
|
|
|
$ |
|
|
See
notes
to condensed consolidated financial statements.
WHITING
PETROLEUM CORPORATION
CONDENSED
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In
thousands, except share and per share data)
|
|
|
|
|
|
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
Accounts
payable
|
|
$ |
31,797
|
|
|
$ |
21,077
|
|
Accrued
liabilities
|
|
|
53,319
|
|
|
|
58,504
|
|
Accrued
interest
|
|
|
20,687
|
|
|
|
9,124
|
|
Oil
and gas sales payable
|
|
|
17,634
|
|
|
|
19,064
|
|
Accrued
employee compensation and benefits
|
|
|
4,159
|
|
|
|
17,800
|
|
Production
taxes payable
|
|
|
6,088
|
|
|
|
9,820
|
|
Current
portion of tax sharing liability
|
|
|
3,565
|
|
|
|
3,565
|
|
Current
portion of derivative liability
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
current liabilities
|
|
|
147,320
|
|
|
|
143,042
|
|
|
|
|
|
|
|
|
|
|
NON-CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
1,055,975
|
|
|
|
995,396
|
|
Asset
retirement obligations
|
|
|
39,735
|
|
|
|
36,982
|
|
Production
Participation Plan liability
|
|
|
27,535
|
|
|
|
25,443
|
|
Tax
sharing liability
|
|
|
23,987
|
|
|
|
23,607
|
|
Deferred
income taxes
|
|
|
169,942
|
|
|
|
165,031
|
|
Long-term
derivative liability
|
|
|
7,175
|
|
|
|
5,248
|
|
Other
long-term liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
non-current liabilities
|
|
|
1,328,560
|
|
|
|
1,255,691
|
|
|
|
|
|
|
|
|
|
|
COMMITMENTS
AND CONTINGENCIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STOCKHOLDERS’
EQUITY:
|
|
|
|
|
|
|
|
|
Common
stock, $0.001 par value; 75,000,000 shares authorized,
37,053,071 and
36,947,681 shares issued and outstanding as of
March 31, 2007 and
December 31, 2006, respectively
|
|
|
37
|
|
|
|
37
|
|
Additional
paid-in capital
|
|
|
754,977
|
|
|
|
754,788
|
|
Accumulated
other comprehensive loss
|
|
|
(10,199 |
) |
|
|
(5,902 |
) |
Retained
earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
stockholders’ equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
$ |
|
|
|
$ |
|
|
See
notes
to condensed consolidated financial statements.
WHITING
PETROLEUM CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(In
thousands, except per share data)
|
|
Three
Months Ended
March
31,
|
|
|
|
|
|
|
|
|
REVENUES
AND OTHER INCOME:
|
|
|
|
|
|
|
Oil
and natural gas sales
|
|
$ |
159,714
|
|
|
$ |
189,865
|
|
Loss
on oil and natural gas hedging activities
|
|
|
-
|
|
|
|
(9,524 |
) |
Interest
income and other
|
|
|
|
|
|
|
|
|
Total
revenues and other income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COSTS
AND EXPENSES:
|
|
|
|
|
|
|
|
|
Lease
operating
|
|
|
49,057
|
|
|
|
44,398
|
|
Production
taxes
|
|
|
9,612
|
|
|
|
11,935
|
|
Depreciation,
depletion and amortization
|
|
|
44,571
|
|
|
|
35,300
|
|
Exploration
and impairment
|
|
|
9,176
|
|
|
|
7,042
|
|
General
and administrative
|
|
|
8,285
|
|
|
|
9,611
|
|
Change
in Production Participation Plan liability
|
|
|
2,092
|
|
|
|
2,074
|
|
Interest
expense
|
|
|
19,497
|
|
|
|
16,973
|
|
Unrealized
derivative loss
|
|
|
|
|
|
|
|
|
Total
costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES
|
|
|
16,519
|
|
|
|
53,297
|
|
|
|
|
|
|
|
|
|
|
INCOME
TAX EXPENSE:
|
|
|
|
|
|
|
|
|
Current
|
|
|
626
|
|
|
|
2,031
|
|
Deferred
|
|
|
|
|
|
|
|
|
Total
income tax expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME PER COMMON SHARE, BASIC AND DILUTED
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE SHARES OUTSTANDING, BASIC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED
AVERAGE SHARES OUTSTANDING, DILUTED
|
|
|
|
|
|
|
|
|
See
notes
to condensed consolidated financial statements.
WHITING
PETROLEUM CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(In
thousands)
|
|
Three
Months Ended
March
31,
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
Net
income
|
|
$ |
10,666
|
|
|
$ |
32,990
|
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
44,571
|
|
|
|
35,300
|
|
Deferred
income taxes
|
|
|
5,227
|
|
|
|
18,276
|
|
Amortization
of debt issuance costs and debt discount
|
|
|
1,276
|
|
|
|
1,323
|
|
Accretion
of tax sharing liability
|
|
|
380
|
|
|
|
525
|
|
Stock-based
compensation
|
|
|
1,119
|
|
|
|
779
|
|
Unproved
leasehold impairments
|
|
|
2,316
|
|
|
|
140
|
|
Change
in Production Participation Plan liability
|
|
|
2,092
|
|
|
|
2,074
|
|
Unrealized
derivative loss
|
|
|
1,114
|
|
|
|
-
|
|
Other
non-current
|
|
|
(1,558 |
) |
|
|
(2,053 |
) |
Changes
in current assets and liabilities:
|
|
|
|
|
|
|
Accounts
receivable trade
|
|
|
7,637
|
|
|
|
8,866
|
|
Prepaid
expenses and other
|
|
|
(3,060 |
) |
|
|
(4,655 |
) |
Accounts
payable and accrued liabilities
|
|
|
(953 |
) |
|
|
20,872
|
|
Accrued
interest
|
|
|
11,563
|
|
|
|
7,772
|
|
Other
current liabilities
|
|
|
(20,029 |
) |
|
|
(10,921 |
) |
Net
cash provided by operating activities
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
Cash
acquisition capital expenditures
|
|
|
(16,718 |
) |
|
|
(15,773 |
) |
Drilling
and development capital expenditures
|
|
|
(109,402 |
) |
|
|
(118,788 |
) |
Proceeds
from sale of oil and gas properties
|
|
|
|
|
|
|
|
|
Net
cash used in investing activities
|
|
|
(124,839 |
) |
|
|
(134,561 |
) |
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
Long-term
borrowings under credit agreement
|
|
|
100,000
|
|
|
|
30,000
|
|
Repayments
of long-term borrowings under credit agreement
|
|
|
(40,000 |
) |
|
|
(10,000 |
) |
Tax
effect from restricted stock vesting
|
|
|
|
|
|
|
|
|
Net
cash provided by financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
CHANGE IN CASH AND CASH EQUIVALENTS
|
|
|
(2,184 |
) |
|
|
(3,013 |
) |
CASH
AND CASH EQUIVALENTS:
|
|
|
|
|
|
|
Beginning
of period
|
|
|
|
|
|
|
|
|
End
of period
|
|
$ |
|
|
|
$ |
|
|
SUPPLEMENTAL
CASH FLOW DISCLOSURES:
|
|
|
|
|
|
|
Cash
(refunded) paid for income taxes
|
|
$ |
(73 |
) |
|
$ |
|
|
Cash
paid for interest
|
|
$ |
|
|
|
$ |
|
|
NONCASH
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
(Increase)
decrease in accrued capital expenditures
|
|
$ |
(6,427 |
) |
|
$ |
|
|
See
notes
to condensed consolidated financial statements.
WHITING
PETROLEUM CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
AND
COMPREHENSIVE INCOME (Unaudited)
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
Paid-in Capital
|
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
|
|
|
|
|
|
Total
Stockholders’ Equity
|
|
|
|
|
BALANCES—January
1, 2006
|
|
|
36,842
|
|
|
$ |
37
|
|
|
$ |
753,093
|
|
|
$ |
(34,620 |
) |
|
$ |
(2,031 |
) |
|
$ |
281,383
|
|
|
$ |
997,862
|
|
|
|
|
|
Net
income
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
156,364
|
|
|
|
156,364
|
|
|
|
156,364
|
|
Change
in derivative fair values, net of taxes
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
24,140
|
|
|
|
-
|
|
|
|
-
|
|
|
|
24,140
|
|
|
|
24,140
|
|
Realized
loss on settled derivative contracts, net of related
taxes
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4,578
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4,578
|
|
|
|
4,578
|
|
Restricted
stock issued
|
|
|
126
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Restricted
stock forfeited
|
|
|
(10 |
) |
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Restricted
stock used for tax withholdings
|
|
|
(10 |
) |
|
|
-
|
|
|
|
(440 |
) |
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(440 |
) |
|
|
-
|
|
Tax
effect from restricted stock vesting
|
|
|
-
|
|
|
|
-
|
|
|
|
288
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
288
|
|
|
|
-
|
|
Adoption
of SFAS 123R
|
|
|
-
|
|
|
|
-
|
|
|
|
(2,122 |
) |
|
|
-
|
|
|
|
2,031
|
|
|
|
-
|
|
|
|
(91 |
) |
|
|
-
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCES—December
31, 2006
|
|
|
36,948
|
|
|
|
37
|
|
|
|
754,788
|
|
|
|
(5,902 |
) |
|
|
-
|
|
|
|
437,747
|
|
|
|
1,186,670
|
|
|
$ |
|
|
Net
income
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
10,666
|
|
|
|
10,666
|
|
|
|
10,666
|
|
Change
in derivative fair values, net of taxes
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(5,001 |
) |
|
|
-
|
|
|
|
-
|
|
|
|
(5,001 |
) |
|
|
(5,001 |
) |
Unrealized
derivative loss, net of related taxes
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
704
|
|
|
|
-
|
|
|
|
-
|
|
|
|
704
|
|
|
|
704
|
|
Restricted
stock issued
|
|
|
142
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Restricted
stock forfeited
|
|
|
(10 |
) |
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Restricted
stock used for tax withholdings
|
|
|
(27 |
) |
|
|
-
|
|
|
|
(1,224 |
) |
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1,224 |
) |
|
|
-
|
|
Tax
effect from restricted stock vesting
|
|
|
-
|
|
|
|
-
|
|
|
|
294
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
294
|
|
|
|
-
|
|
Stock-based
compensation
|
|
|
-
|
|
|
|
-
|
|
|
|
1,119
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,119
|
|
|
|
-
|
|
Adoption
of FIN 48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(323 |
) |
|
|
(323 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCES—March
31, 2007
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(10,199 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
See
notes
to condensed consolidated financial statements.
WHITING
PETROLEUM CORPORATION
NOTES
TO CONDENSED 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
subsidiaries.
Consolidated
Financial Statements—The unaudited condensed consolidated
financial statements include the accounts of Whiting Petroleum Corporation
and
its subsidiaries, all of which are wholly owned. The financial statements
have
been prepared in accordance with U.S. generally accepted accounting principles
for interim financial reporting. All significant intercompany balances and
transactions have been eliminated in consolidation. In the opinion of
management, all material adjustments considered necessary for a fair
presentation of the Company’s interim results have been reflected. Whiting’s
2006 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 consolidated financial statements
included in Whiting’s 2006 Annual Report on Form 10-K.
Earnings
Per Share—Basic net income per common share of stock is calculated
by dividing net income by the weighted average number of common shares
outstanding during each period. Diluted net income per common share of stock
is
calculated by dividing net income by the weighted average number of common
shares and other dilutive securities outstanding. The only securities considered
dilutive are the Company’s unvested restricted stock awards. The
dilutive effect of these securities was immaterial to the
calculation.
Reclassifications—
Certain prior period balances were reclassified to conform to the current
year
presentation, and such reclassifications had no impact on net income or
stockholders’ equity previously reported.
Change
in Accounting Principle— In June 2006, the Financial
Accounting Standards Board (“FASB”) issued Interpretation No. 48,
Accounting for Uncertainty in Income Taxes, an interpretation of
Statement of Financial Accounting Standards No. 109, Accounting for Income
Taxes (“FIN 48”). The interpretation creates a single model to address
accounting for uncertainty in tax positions. Specifically, the pronouncement
prescribes a recognition threshold and a measurement attribute for the financial
statement recognition and measurement of a tax position taken or expected
to be
taken in a tax return. The interpretation also provides guidance on
derecognition, classification, interest and penalties, accounting in interim
periods, disclosure and transition of certain tax positions.
The
Company adopted the provisions of FIN 48 on January 1, 2007. As a result
of the implementation of FIN 48, the Company recognized a $0.3 million increase
in the liability for unrecognized tax benefits, which was accounted for as
a
reduction to the January 1, 2007 balance of retained earnings and a
corresponding increase in other long-term liabilities. As of the
adoption date and after the impact of recognizing the increase in liability
noted above, the Company’s unrecognized tax benefits totaled $0.4 million, and
there were no additions or reductions to the Company’s unrecognized tax benefits
during the three months ended March 31, 2007. Included in the balance at
January
1, 2007, are $0.1 million of tax positions, the allowance of which would
positively affect the annual effective income tax rate. It is reasonably
possible that unrecognized tax benefits in the amount of $0.3 million relating
to gas imbalances will decrease within the next 12 months, as Whiting is
in the
process of applying for a change in the method of accounting to a method
prescribed by the Internal Revenue Service (“IRS”).
The
Company files income tax returns in the U.S. Federal jurisdiction, in various
states, and two foreign jurisdictions. The following is a listing of tax
years that remain subject to examination by major jurisdiction:
U.S.
Federal
|
11/23/2003
– 12/31/2006
|
U.S.
states
|
11/23/2003
– 12/31/2006
|
Canada
|
01/01/2002
– 12/31/2006
|
Province
of Alberta
|
01/01/2002
–
12/31/2006
|
Prior
to
November 23, 2003, Whiting was owned 100% by Alliant Energy Corporation
(“Alliant Energy”). Alliant Energy is presently under audit by the
IRS for the years 1999 through 2003. Based on discussions with
Alliant Energy, the Company believes that there are no issues that would
require
adjustment to Whiting’s tax liability for the periods 1999 to
2001. Information is not yet available for the 2002 to 2003
periods.
The
Company’s policy is to recognize potential interest and penalties accrued
related to unrecognized tax benefits within income tax expense. For the
quarter ended March 31, 2007, the Company did not recognize any interest
or
penalties in the condensed consolidated statements of income, nor did the
Company have any interest or penalties accrued in its condensed consolidated
balance sheet at March 31, 2007 relating to unrecognized tax
benefits.
2.
|
ACQUISITIONS
AND DIVESTITURES
|
2007
Acquisitions
There
were no significant acquisitions during the first quarter of 2007.
2006
Acquisitions
Utah
Hingeline—On August 29, 2006, the Company
acquired a 15% working interest in approximately 170,000 acres of unproved
properties in the central Utah Hingeline play for $25.0 million. No
producing properties or proved reserves were associated with this acquisition.
As part of this transaction, the operator agreed to pay 100% of the Company’s
drilling and completion costs for the first three wells in the
project. The first of these three wells was drilled in the fourth
quarter of 2006 but did not find commercial quantities of
hydrocarbons. The remaining two wells are planned to be drilled
during the remainder of 2007.
Michigan
Properties—On August 15, 2006, the Company acquired 65
producing properties, a gathering line, gas processing plant and 30,437 net
acres of leasehold held by production in Michigan. The purchase price was
$26.0 million for estimated proved reserves of 1.4 MMBOE as of the
acquisition effective date of May 1, 2006, resulting in a cost of $18.55
per BOE of estimated proved reserves. Proved developed reserve quantities
represented 99% of the total proved reserves acquired. The average
daily production from the properties was 0.6 MBOE/d as of the acquisition
effective date. The Company operates 85% of the properties
acquired.
The
Company funded its 2006 acquisitions with cash on hand as well as through
borrowings under its credit agreement.
2006
Divestitures
During
2006, the Company sold its interests in several non-core properties for an
aggregate amount of $24.4 million in cash, which consisted of total
estimated proved reserves of 1.4 MMBOE as of the divestitures’ effective dates.
The divested properties included interests in the Cessford field in Alberta,
Canada; Permian Basin of West Texas and New Mexico; and the Ashley Valley
field
in Uintah County, Utah. The average net production from the divested property
interests was 0.4 MBOE/d as of the dates of disposition, and the Company
recognized a pre-tax gain of $12.1 million in the fourth quarter of 2006 on
the sale of these properties.
Long-term
debt consisted of the following at March 31, 2007 and December 31, 2006 (in
thousands):
|
|
|
|
|
|
|
Credit
Agreement
|
|
$ |
440,000
|
|
|
$ |
380,000
|
|
7.25%
Senior Subordinated Notes due 2012, net of unamortized
debt discount of
$648 and $687, respectively
|
|
|
148,281
|
|
|
|
147,820
|
|
7.25%
Senior Subordinated Notes due 2013, net of unamortized
debt discount of
$2,306 and $2,424, respectively
|
|
|
217,694
|
|
|
|
217,576
|
|
7%
Senior Subordinated Notes due 2014
|
|
|
250,000
|
|
|
|
250,000
|
|
Total
debt
|
|
$ |
1,055,975
|
|
|
$ |
995,396
|
|
Credit
Agreement—The Company’s wholly-owned subsidiary, Whiting Oil and
Gas Corporation (“Whiting Oil and Gas”) has a $1.2 billion credit agreement with
a syndicate of banks that, as of March 31, 2007, had a borrowing base of
$875.0
million. 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. As of March 31, 2007,
the outstanding principal balance under the credit agreement was $440.0
million.
The
credit agreement provides for interest only payments until August 31, 2010,
when
the entire amount borrowed is due. Whiting Oil and Gas may, throughout the
five-year 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, 2007, letters
of
credit totaling $0.3 million were outstanding under the credit
agreement.
Interest
accrues, at Whiting Oil and Gas’ option, at either (1) 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 (2) 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. Whiting Oil and Gas has
consistently chosen the LIBOR rate option since it delivers the lowest effective
interest rate. 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, 2007, weighted
average interest rate on the outstanding principal balance under the credit
agreement was 6.7%.
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 and requires the Company to maintain a debt
to
EBITDAX (as defined in the credit agreement) ratio of less than 3.5 to 1
and a
working capital ratio (as defined in the credit agreement) 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, 2007. The credit
agreement is secured by a first lien on all of Whiting Oil and Gas’ properties
included in the borrowing base for the credit 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 $250.0 million of 7% Senior Subordinated Notes due 2014 at par. The
estimated fair value of these notes was $242.8 million as of March 31,
2007.
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 7.5%. The estimated fair
value of these notes was $215.3 million as of March 31, 2007.
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 7.4%.
The
estimated fair value of these notes was $146.8 million as of March 31,
2007.
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 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, incur additional indebtedness 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. In addition, Whiting Oil and Gas’
credit agreement restricts the ability of the Company’s subsidiaries to make
certain payments, including principal on the notes, to Whiting Petroleum
Corporation. The Company was in compliance with these covenants as of March
31,
2007. Three of the Company’s wholly-owned operating subsidiaries, Whiting Oil
and Gas, Whiting Programs, Inc. and Equity Oil Company (the “Guarantors”),
have
fully,
unconditionally, jointly and severally guaranteed the Company’s obligations
under the notes. The Company does not have any subsidiaries other than the
Guarantors, minor or otherwise, within the meaning of Rule 3-10(h)(6) of
Regulation S-X of the Securities and Exchange Commission, and 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. 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.
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. As of March 31,
2007, the Company has recorded a long-term liability of $1.1 million related
to
the interest rate swap, which has been designated as a fair value hedge,
with an
offsetting reduction in 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 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 following table provides a reconciliation
of the Company’s asset retirement obligations for the three months ended March
31, 2007 (in thousands):
Asset
retirement obligation, January 1, 2007
|
|
$ |
37,534
|
|
Additional
liability incurred
|
|
|
407
|
|
Revisions
in estimated cash flows
|
|
|
2,821
|
|
Accretion
expense
|
|
|
607
|
|
Obligations
on sold properties
|
|
|
(185 |
) |
Liabilities
settled
|
|
|
(837 |
) |
Asset
retirement obligation, March 31, 2007
|
|
$ |
|
|
5.
|
DERIVATIVE
FINANCIAL INSTRUMENTS
|
Whiting
enters into derivative contracts, primarily costless collars, to hedge future
crude oil and natural gas production in order to mitigate the risk of market
price fluctuations.
Historically,
prices received for oil and gas production have been volatile because of
seasonal weather patterns, supply and demand factors, worldwide political
factors and general economic conditions. Costless collars are designed to
establish floor and ceiling prices on anticipated future oil and gas production.
The Company has designated these contracts as cash flow hedges designed to
achieve a more predictable cash flow, as well as to reduce its exposure to
price
volatility. 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
instruments for speculative or trading purposes.
All
derivative instruments, other than those that meet the normal purchase and
sales
exceptions, are recorded on the balance sheet as either an asset or liability
measured at fair value. Changes in fair value are recognized
currently in earnings unless specific hedge accounting criteria are
met. Hedge accounting treatment allows unrealized gains and losses on
effective cash flow hedges to be deferred in accumulated other comprehensive
income (loss) until the hedged transactions occur. Realized gains and losses
on
cash flow hedges are transferred from accumulated other comprehensive income
(loss) and recognized in earnings as gain (loss) on oil and natural gas hedging
activities. Realized gains and losses on interest hedge derivatives are recorded
as adjustments to interest expense. Gains and losses from the change
in the fair value of derivative instruments that do not qualify as a hedge
or
that are not designated as a hedge, as well as the ineffective portion of
hedge
derivatives, if any, are reported in the condensed consolidated statements
of
income as unrealized derivative (gain) loss. Derivative settlements are included
in cash flows from operating activities.
At
March
31, 2007, accumulated other comprehensive loss consisted of $17.2 million
($10.2
million after tax) of unrealized losses, representing the mark-to-market
value
of the Company’s open commodity contracts, designated as cash flow hedges, as of
the balance sheet date. For the quarter ended March 31, 2007, Whiting
recognized no realized gains or losses on commodity derivative settlements.
For
the quarter ended March 31, 2006, Whiting recognized realized losses of $9.5
million on commodity derivative settlements. Based on the estimated
fair value of the derivative contracts at March 31, 2007, the Company expects
to
reclassify net losses of $9.0 million into earnings related to derivative
contracts during the next twelve months; however, actual gains and losses
recognized may differ materially. The Company has hedged 3.7 MMBbl of
crude oil volumes through 2007 and 2.8 MMBbl of crude oil volumes through
2008.
During
the first quarter of 2007, the Company determined that the forecasted
transactions, to which certain crude oil collars had been designated, were
no
longer probable of occurring within the specified time periods. The
Company therefore reclassified the net loss attributable to these hedges
out of
accumulated other comprehensive loss and recognized $1.1 million in unrealized
derivative losses in the condensed consolidated statements of income as of
March
31, 2007. The Company also discontinued hedge accounting prospectively for
these
collars.
The
Company has also entered into an interest rate swap designated as a fair
value
hedge as further explained in Long-Term Debt.
Equity
Incentive Plan—The Company maintains the Whiting Petroleum
Corporation 2003 Equity Incentive Plan, pursuant to which two million shares
of
the Company’s common stock have been reserved for issuance. No
participating employee may be granted options for more than 300,000 shares
of
common stock, stock appreciation rights with respect to more than 300,000
shares
of common stock or more than 150,000 shares of restricted stock during any
calendar year.
Restricted
stock awards for executive officers and employees generally vest ratably
over
three years. In February 2007, however, restricted stock awards
granted to executive officers included certain performance conditions, in
addition to the standard three-year service condition, that must be met in
order
for the stock awards to vest. The Company believes that it is
probable that such performance conditions will be achieved and has accrued
compensation cost accordingly for its 2007 restricted stock grants to
executives.
The
following table shows a summary of the Company’s nonvested restricted stock as
of March 31, 2007 as well as activity during the three months then ended
(share
and per share data, not presented in thousands):
|
|
Number
of
Shares
|
|
|
Weighted
Average Grant Date Fair Value
|
|
Restricted
stock awards nonvested, January 1, 2006
|
|
|
203,264
|
|
|
$ |
39.33
|
|
Granted
|
|
|
142,066
|
|
|
$ |
45.42
|
|
Vested
|
|
|
(90,711 |
) |
|
$ |
36.50
|
|
Forfeited
|
|
|
(9,719 |
) |
|
$ |
|
|
Restricted
stock awards nonvested, March 31, 2007
|
|
|
|
|
|
$ |
|
|
The
grant
date fair value of restricted stock is determined based on the closing bid
price
of the Company’s common stock on the grant date. 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.
As
of
March 31, 2007, there was $7.0 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
2.3
years.
Rights
Agreement - On February 23, 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.
7.
|
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, 2007 and 2006 amounted to $2.5 million and $3.0 million,
respectively, charged to general and administrative expense and $0.5 million
and
$0.6 million, respectively, charged to exploration expense.
Pursuant
to the terms of the Plan, (1) employees who terminate their employment with
the
Company vest at a rate of 20% per year in future Plan year payments, which
are
attributable to their interests in the income allocated to the Plan for such
year; (2) employees will become fully vested at age 65, regardless of when
their
interests would otherwise vest; and (3) any forfeitures for Plan years after
2003 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, 2007, the Company
used five-year average historical NYMEX prices of $48.25 for crude oil and
$6.28
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, 2007, 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
$73.5 million. This amount includes $11.4 million attributable to
proved undeveloped oil and gas properties and $3.0 million relating to the
short-term portion of the Production Participation Plan liability, which
has
been accrued as a current payable for 2007 plan-year payments owed to employees.
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, 2007 (in thousands):
Production
Participation Plan liability, January 1, 2007
|
|
$ |
25,443
|
|
Change
in liability for accretion, vesting and change in estimate
|
|
|
5,128
|
|
Reduction
in liability for cash payments accrued and recognized as
compensation
expense
|
|
|
(3,036 |
) |
Production
Participation Plan liability, March 31, 2007
|
|
$ |
|
|
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
condensed 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
|
|
$ |
1,755
|
|
|
$ |
1,742
|
|
Exploration
expense
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
|
|
|
$ |
|
|
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. Employer contributions vest ratably at 20% per year
over
a five year period.
8.
|
RELATED
PARTY TRANSACTIONS
|
Prior
to
Whiting’s initial public offering in November 2003, it was a wholly owned
indirect subsidiary of 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 not a related
party.
Tax
Sharing Liability - 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 of their
assets 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 $38.6 million on an undiscounted basis, with a present value
of
$26.2 million.
During
the first three months of 2007, the Company did not make any payments under
this
agreement but did recognize $0.4 million of accretion expense, which is
included as a component of interest expense. The Company’s estimated payment of
$3.6 million to be made in 2007 under this agreement is reflected as a
current liability at March 31, 2007.
The
Tax
Separation and Indemnification Agreement provides that if tax rates were
to
change (increase or decrease), the tax benefit or detriment would result
in 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.
Receivable
from Alliant Energy—Prior to the Company’s initial public
offering, the Company was included in the consolidated federal income tax
return
of Alliant Energy and calculated its income tax expense on a separate return
basis at Alliant Energy’s effective tax rate less any research or Section 29 tax
credits generated by the Company. Current tax due under this calculation
was
paid to Alliant Energy, and current refunds were received from Alliant
Energy. Section 29 tax credits were generated in 2002 and are
expected to be utilized by Alliant Energy in 2007. However, on a stand-alone
basis Whiting would have been unable to use the credits in its 2002 tax return.
The Company expects to be paid during 2007 for the Section 29 credits, which
is
when Alliant Energy expects to receive the benefit for them. The Company
has a
current receivable in the amount of $4.1 million as of March 31, 2007 for
these
credits.
Alliant
Energy Guarantee—The Company holds a 6% working interest in four
federal offshore platforms and related onshore plant and equipment in
California. Alliant Energy has guaranteed the Company’s obligation
for the abandonment of these assets.
9.
|
COMMITMENTS
AND CONTINGENCIES
|
Non-cancelable
Leases—The Company leases 87,000 square feet of administrative
office space in Denver, Colorado under an operating lease arrangement through
October 31, 2010 and an additional 26,500 square feet of office space in
Midland, Texas through February 15, 2012. Rental expense for the
first three months of 2007 and 2006 was $0.6 million and $0.5 million,
respectively. Minimum lease payments under the terms of non-cancelable operating
leases as of March 31, 2007 are as follows (in thousands):
2007
|
|
$ |
1,310
|
|
2008
|
|
|
1,759
|
|
2009
|
|
|
1,772
|
|
2010
|
|
|
1,540
|
|
2011
|
|
|
329
|
|
Thereafter
|
|
|
|
|
Total
|
|
$ |
|
|
Purchase
Contract— The Company has entered into two take-or-pay purchase
agreements, one agreement in July 2005 for 9.5 years and one agreement
in March 2006 for 8 years, 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
enhanced recovery projects in the Postle field in Texas County, Oklahoma
and the
North Ward Estes field in Ward County, 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 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, the Company expects to avoid any payments
for
deficiencies. As of March 31, 2007, future commitments under the purchase
agreements amounted to $303.9 million through 2014.
Drilling
Contracts—The Company entered into three separate three-year
agreements in 2005 for drilling rigs, a two-year agreement in February 2006
for a workover rig, and a three-year agreement in September 2006 for an
additional drilling rig, all operating in the Rocky Mountains
region. As of March 31, 2007, these agreements had total commitments
of $43.3 million and early termination would require maximum penalties of
$30.2
million. No other drilling rigs working for the Company are currently
under long-term contracts or contracts which cannot be terminated at the
end of
the well that is currently being drilled.
Price-sharing
Agreement—The Company, as part of a 2002 purchase transaction,
agreed to share with the seller 50% of the actual price received for certain
crude oil production in excess of $19.00 per barrel. The agreement
runs through December 31, 2009 and contains a 2% price escalation per
year. As a result, the sharing amount at January 1, 2007 increased to
50% of the actual price received in excess of $20.98 per barrel. As
of March 31, 2007, approximately 34,900 net barrels of crude oil per month
(5%
of March 2007 net crude oil production) are subject to this sharing agreement.
The terms of the agreement do not provide for a maximum amount to be
paid. For the three month periods ended March 31, 2007 and 2006, the
Company paid $1.8 million and $2.2 million, respectively, under this
agreement. As of March 31, 2007 and 2006, the Company had accrued an
additional $0.5 million and $0.7 million, respectively, as a current
payable.
Litigation—The
Company is subject to litigation claims and governmental and regulatory controls
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.
10.
|
RECENTLY
ISSUED ACCOUNTING
PRONOUNCEMENTS
|
In
September 2006, the FASB issued Statement No. 157, Fair Value
Measurements (“SFAS 157”). The adoption of SFAS 157 is not expected to have
a material impact on the Company’s consolidated financial position or results of
operations. However, additional disclosures may be required about the
information used to develop certain fair value measurements. SFAS 157
establishes a single authoritative definition of fair value, sets out a
framework for measuring fair value and requires additional disclosures about
fair value measurements. This Standard requires companies to disclose the
fair
value of their financial instruments according to a fair value hierarchy.
SFAS
157 does not require any new fair value measurements, but will remove
inconsistencies in fair value measurements between various accounting
pronouncements. SFAS 157 is effective for financial statements issued for
fiscal
years beginning after November 15, 2007 and interim periods within those
fiscal years.
|
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
operating subsidiaries, Whiting Oil and Gas Corporation and Equity Oil
Company. When the context requires, we refer to these entities
separately.
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. Some, but not all, of
the
risks and uncertainties include: declines in oil or gas prices; 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 drilling rigs; our ability to obtain external
capital to finance acquisitions; our ability to identify and complete
acquisitions and to successfully integrate acquired businesses, including
our
ability to realize cost savings from completed acquisitions; unforeseen
underperformance of or liabilities associated with acquired properties;
inaccuracies of our reserve estimates or our assumptions underlying them;
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; risks related to our level of indebtedness
and periodic redeterminations of our borrowing base under our credit agreement;
our ability to replace our oil and gas reserves; any loss of our senior
management or technical personnel; competition in the oil and gas industry;
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, 2006. We assume no obligation, and disclaim any duty,
to
update the forward-looking statements in this report.
Overview
We
are
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. Over
the
last six years, we have emphasized the acquisition of properties that provided
current production and upside potential through further development. Our
drilling activity is directed at this development, specifically on projects
that
we believe provide repeatable successes in particular fields. Our combination
of
acquisitions and development allows us to direct our capital resources to
what
we believe to be the most advantageous investments.
We
have
historically acquired operated and non-operated properties that meet or 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
provided a foothold 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 sale 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.
Our
revenue, profitability and future growth rate depend on factors beyond our
control, such as economic, political and regulatory developments and competition
from other sources of energy. Oil and gas prices historically have been volatile
and may fluctuate widely in the future. Sustained periods of low prices for
oil
or gas could materially and adversely affect our financial position, our
results
of operations, the quantities of oil and gas reserves that we can economically
produce and our access to capital.
Although
independent engineers estimated probable and possible reserves relating to
certain 2006 and prior year producing property acquisitions, we, consistent
with
our present acquisition practices, have associated substantially all acquisition
costs with proved reserves. Because of our recent acquisition activity, our
discussion and analysis of our historical financial condition and results
of
operations for the periods discussed below may not necessarily be comparable
with or applicable to our future results of operations.
Results
of Operations
Three
Months Ended March 31, 2007 Compared to Three Months Ended March 31,
2006
Selected
Operating Data:
|
|
Three
Months Ended
March
31,
|
|
|
|
|
|
|
|
|
Net
production:
|
|
|
|
|
|
|
Oil
(MMbls)
|
|
|
2.2
|
|
|
|
2.4
|
|
Natural
gas (Bcf)
|
|
|
7.7
|
|
|
|
7.8
|
|
Total
production (MMBOE)
|
|
|
3.5
|
|
|
|
3.7
|
|
|
|
|
|
|
|
|
|
|
Net
sales (in millions):
|
|
|
|
|
|
|
|
|
Oil(1)
|
|
$ |
110.8
|
|
|
$ |
130.5
|
|
Natural
gas(1)
|
|
|
|
|
|
|
|
|
Total
oil and natural gas sales
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
Average
sales prices:
|
|
|
|
|
|
|
|
|
Oil
(per Bbl)
|
|
$ |
49.33
|
|
|
$ |
55.02
|
|
Effect
of oil hedges on average price (per Bbl)
|
|
|
|
|
|
|
(3.79 |
) |
Oil
net of hedging (per Bbl)
|
|
$ |
|
|
|
$ |
|
|
Average
NYMEX
price
|
|
$ |
58.12
|
|
|
$ |
63.53
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$ |
6.33
|
|
|
$ |
7.62
|
|
Effect
of natural gas hedges on average price (per Mcf)
|
|
|
|
|
|
|
(0.07 |
) |
Natural
gas net of hedging (per Mcf)
|
|
$ |
|
|
|
$ |
|
|
Average
NYMEX
price
|
|
$ |
6.77
|
|
|
$ |
9.01
|
|
|
|
|
|
|
|
|
|
|
Cost
and expense (per BOE):
|
|
|
|
|
|
|
|
|
Lease
operating expenses
|
|
$ |
13.88
|
|
|
$ |
12.09
|
|
Production
taxes
|
|
$ |
2.72
|
|
|
$ |
3.25
|
|
Depreciation,
depletion and amortization expense
|
|
$ |
12.62
|
|
|
$ |
9.62
|
|
General
and administrative expenses
|
|
$ |
2.34
|
|
|
$ |
2.62
|
|
(1) Before
consideration of hedging transactions.
Oil
and Natural Gas Sales. Our oil and natural gas sales revenue decreased
$30.2 million to $159.7 million in the first quarter of 2007 compared to
the
first quarter of 2006. Sales are a function of volumes sold and average sales
prices. Our oil sales volumes decreased 5% and our gas sales volumes decreased
1% between periods. The volume declines resulted primarily from production
shut-ins due to a fire at a third-party refinery and normal field production
decline, which was partially offset by production increases from 12 months
of
drilling activity and recent acquisitions. As a result of the
refinery fire, approximately 34,000 BOE of production from the Postle field
was
shut-in or restricted from February 19 through March 8, 2007. Our
average price for oil before effects of hedging decreased 10% and our average
price for natural gas before effects of hedging decreased 17% between
periods.
Loss
on Oil and Natural Gas Hedging Activities. We hedged 60% of our oil volumes
during the first quarter of 2007, incurring no realized hedging gains or
losses,
and 52% of our oil
volumes
during the first quarter of 2006 incurring derivative
settlement losses of $9.0 million. We hedged 62% of our gas volumes
during the first quarter of 2007, incurring no realized hedging gains or
losses
and 58% of our gas volumes during the first quarter of 2006 incurring derivative
settlement losses of $0.5 million. See Item 3, “Qualitative and
Quantitative Disclosures About Market Risk” for a list of our outstanding oil
hedges as of April 1, 2007.
Lease
Operating Expenses. Our lease operating expenses increased $4.7 million to
$49.1 million in the first quarter of 2007 compared to the first quarter
of
2006. Our lease operating expense as a percentage of oil and gas
sales increased from 23% during the first quarter of 2006 to 31% during the
first quarter of 2007. Our lease operating expenses per BOE increased from
$12.09 during the first quarter of 2006 to $13.88 during the first quarter
of
2007. The increase of 15% on a BOE basis was primarily caused by inflation
in
the cost of oil field goods and services, a high level of workover activity,
and
a change in labor billing practices. The cost of oil field goods and
services increased due to a higher demand in the industry. Workovers amounted
to
$3.0 million in the first quarter of 2007, as compared to $2.1 million
of workover activity in the first quarter of 2006. In addition,
during the fourth quarter of 2006, we revised our labor billing practices
to
better conform to Council of Petroleum Accountants Societies (“COPAS”)
guidelines. This change in labor billing practices resulted in lower general
and
administrative expense to us and higher amounts of lease operating expense
being
charged to us and our joint interest owners on properties we
operate.
Production
Taxes. The production taxes we pay are generally calculated as a percentage
of oil and gas sales revenue before the effects of hedging. We take full
advantage of all credits and exemptions allowed in the various taxing
jurisdictions. Our production taxes for the first quarters of 2007 and 2006
were
6.0% and 6.3%, respectively, of oil and gas sales.
Depreciation,
Depletion and Amortization. Depreciation, depletion and amortization
expense (“DD&A”) increased $9.3 million to $44.6 million during
the first quarter of 2007, as compared to the first quarter of
2006. On a BOE basis, our DD&A rate increased from $9.62 during
the first quarter of 2006 to $12.62 in the first quarter of 2007. The primary
factors causing this rate increase were higher drilling expenditures, downward
oil and gas reserve revisions, and the amount of expenditures necessary to
develop proved undeveloped reserves, particularly related to the enhanced
oil
recovery projects in the Postle and North Ward Estes fields where the
development of undeveloped reserves does not increase existing proved reserves.
Under the successful efforts method of accounting, costs to develop proved
undeveloped reserves are added into the DD&A rate when incurred. Changes to
the pricing environment can also impact our DD&A rate. Price increases allow
for longer economic production lives and corresponding increased proved reserve
quantities and, as a result, lower depletion rates. Price decreases have
the
opposite effect. The components of our DD&A expense were as follows (in
thousands):
|
|
Three
Months Ended
March
31,
|
|
|
|
|
|
|
|
|
Depletion
|
|
$ |
43,224
|
|
|
$ |
34,221
|
|
Depreciation
|
|
|
740
|
|
|
|
531
|
|
Accretion
of asset retirement
obligations
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
|
|
|
$ |
|
|
Exploration
and Impairment Costs. Our exploration and impairment costs increased $2.1
million to $9.2 million in the first quarter of 2007 compared to the first
quarter of 2006. The components of exploration and impairment costs
were as follows (in thousands):
|
|
Three
Months Ended
March
31,
|
|
|
|
|
|
|
|
|
Exploration
|
|
$ |
6,860
|
|
|
$ |
6,902
|
|
Impairment
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
|
|
|
$ |
|
|
During
the first quarter of 2007, we did not drill any exploratory dry holes, as
compared to the first quarter of 2006, whereby we drilled one exploratory
dry
hole totaling $2.8 million. This reduction in exploratory dry hole expense
was offset by an increase in geological and geophysical expenses during the
first quarter of 2007. The impairment charge in 2007 and 2006 is related
to the
amortization of leasehold costs associated with individually insignificant
unproved properties. As of March 31, 2007, the amount of unproved
properties being amortized increased by $39.5 million as a result of significant
undeveloped acreage and unproved reserves purchased primarily during
2006.
General
and Administrative Expenses. We report general and
administrative expenses net of reimbursements. The components of our general
and
administrative expenses were as follows (in thousands):
|
|
Three
Months Ended
March
31,
|
|
|
|
|
|
|
|
|
General
and administrative
expenses
|
|
$ |
15,843
|
|
|
$ |
14,119
|
|
Reimbursements
and
allocations
|
|
|
(7,558 |
) |
|
|
(4,508 |
) |
General
and administrative expense,
net
|
|
$ |
|
|
|
$ |
|
|
General
and administrative expense before reimbursements and allocations increased
$1.7
million to $15.8 million during the first quarter of 2007. The largest
components of the increase related to higher costs for personnel salaries,
benefits and related taxes of $1.3 million. The increase in
reimbursements and allocations in the first quarter of 2007 was caused by
increased salary expenses and a higher number of field workers on operated
properties. In addition during the fourth quarter of 2006, we revised our
labor
billing practices to better conform to COPAS guidelines. These changes in
labor
billing practices resulted in higher reimbursements and allocations to us
and
higher amounts of lease operating expense being allocated to us and charged
to
our
joint
interest owners on properties we operate. Our general and
administrative expenses remained consistent at 5% of oil and gas sales during
the first quarter of 2006 compared to the first quarter of 2007.
Change
in Production Participation Plan Liability. For the three months ended
March 31, 2007, this non-cash expense remained consistent at $2.1 million.
This
expense represents the change in the vested present value of estimated future
payments to be made to participants after 2008 under our Production
Participation Plan (“Plan”). Although payments take place over the life of oil
and gas properties contributed to the Plan, which for some properties is
over 20
years, we must expense the present value of estimated future payments over
the
Plan’s five year vesting period. This expense in 2007 and in 2006 primarily
reflects changes to future cash flow estimates and related Plan liability
due to
the effect of a sustained higher price environment, recent acquisitions,
and
employees’ continued vesting in the Plan. During the three months ended March
31, 2007, the five-year average historical NYMEX prices used to estimate
this
liability increased $2.05 for crude oil and $0.30 for natural gas from December
31, 2006, as compared to increases of $1.25 for crude oil and $0.29 for natural
gas for the three months ended March 31, 2006. 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.
Interest
Expense. The components of our interest expenses were as follows
(in thousands):
|
|
Three
Months Ended
March
31,
|
|
|
|
|
|
|
|
|
Credit
Agreement
|
|
$ |
7,023
|
|
|
$ |
4,115
|
|
Senior
Subordinated
Notes
|
|
|
11,180
|
|
|
|
11,010
|
|
Amortization
of debt issue costs and debt discount
|
|
|
1,276
|
|
|
|
1,323
|
|
Accretion
of tax sharing
liability
|
|
|
380
|
|
|
|
525
|
|
Other
|
|
|
100
|
|
|
|
-
|
|
Capitalized
interest
|
|
|
(462 |
) |
|
|
|
|
Total
interest
expense
|
|
$ |
|
|
|
$ |
|
|
The
increase in interest expense was mainly due to additional borrowings outstanding
in 2007 under our credit agreement. We also experienced higher weighted average
interest rates on our debt during the first quarter of 2007.
Our
weighted average debt outstanding during the first quarter of 2007 was $1,030.0
million versus $901.8 million in the first quarter of 2006. Our weighted
average
effective cash interest rate was 6.9% during the first quarter of 2007 versus
6.7% during the first quarter of 2006. After inclusion of non-cash interest
costs related to the amortization of debt issue costs and debt discount and
the
accretion of the tax sharing liability, our weighted average effective all-in
interest rate was 7.4% during the first quarter of 2007 and the first quarter
of
2006.
Unrealized
Derivative Loss. During the first quarter of 2007, we determined
that the forecasted transactions, to which certain crude oil collars had
been
designated, were no longer probable of occurring within the specified time
periods. We therefore reclassified the net loss attributable to these
hedges out of accumulated other comprehensive loss and recognized $1.1 million
in unrealized derivative losses in the condensed consolidated statements
of
income as of
March
31,
2007. We also discontinued hedge accounting prospectively for these
collars. During the first quarter of 2006, we did not recognize any
unrealized derivative losses.
Income
Tax Expense. Income tax expense totaled $5.9 million for the first
quarter of 2007 and $20.3 million for the first quarter of
2006. Our effective income tax rate decreased from 38.1% for the
first quarter 2006 to 35.4% for the first quarter of 2007 primarily due to
a
change in our state effective rate in the latter half of 2006.
Net
Income. Net income decreased from $33.0 million during the first
quarter of 2006 to $10.7 million during the first quarter of 2007. The primary
reasons for this decrease included a 4% decrease in equivalent volumes sold,
a
4% decrease in oil prices (net of hedging) and a 16% decrease in gas prices
(net
of hedging) between periods, higher lease operating expense, DD&A,
exploration and impairment, interest expense and unrealized derivative
loss. The decreased production and pricing and increased expenses
were partially offset by lower production taxes and general and administrative
expenses in the first quarter of 2007.
Liquidity
and Capital Resources
Overview.
At December 31, 2006, our debt to total capitalization ratio was 45.4%, we
had $10.4 million of cash on hand and $1,186.7 million of
stockholders’ equity. At March 31, 2007, our debt to total capitalization ratio
was 46.8%, we had $8.2 million of cash on hand and $1,192.9 million of
stockholders’ equity. In the first quarter of 2007, we generated $62.4 million
of cash provided by operating activities, a decrease of $48.9 million over
the
same period in 2006. Cash provided by operating activities decreased
primarily because of lower production and lower average sales prices for
crude
oil and natural gas as well as higher cash costs and expenses. We also generated
$60.3 million from financing activities primarily consisting of $60.0 million
in
net borrowings against our credit agreement. Cash on hand and cash flows
from
operating and financing activities were primarily used to finance $109.4
million
of drilling and development capital expenditures paid in the first quarter
of
2007 and $16.7 million of cash acquisition capital expenditures to acquire
the
Parshall Prospect in North Dakota. The chart below details our
drilling and development capital expenditures incurred by region during the
first quarter of 2007 (in thousands).
|
|
Drilling
Capex
|
|
|
%
of Total
|
|
Permian
Basin
|
|
$ |
36,289
|
|
|
|
31 |
% |
Rocky
Mountains
|
|
|
36,212
|
|
|
|
31 |
% |
Mid-Continent
|
|
|
32,161
|
|
|
|
28 |
% |
Gulf
Coast
|
|
|
7,464
|
|
|
|
7 |
% |
Michigan
|
|
|
|
|
|
|
3 |
% |
Total
drilling and development
capital expenditures incurred
|
|
|
115,829
|
|
|
|
100 |
% |
Increase
in accrued capital
expenditures
|
|
|
(6,427 |
) |
|
|
|
|
Total
drilling and development
capital expenditures paid
|
|
$ |
|
|
|
|
|
|
We
continually evaluate our capital needs and compare them to our capital
resources. Our 2007 budgeted capital expenditures for the further development
of
our property base are $400.0 million, a decrease from the $455.0 million
incurred on capitalized drilling and development during 2006. Although we
have
no specific budget for property acquisitions in 2007, we will continue to
seek
property acquisition opportunities that complement our existing core property
base. We expect
to
fund
our 2007 development expenditures from internally generated cash flow and
cash
on hand. We believe that should attractive acquisition opportunities arise
or
development expenditures exceed $400.0 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
capital
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.
Credit
Agreement. Our
wholly-owned subsidiary, Whiting Oil and Gas Corporation (“Whiting Oil and Gas”)
has a $1.2 billion credit agreement with a syndicate of banks that, as of
March
31, 2007, had a borrowing base of $875.0 million with $440.0 million
outstanding, leaving $435.0 million of available borrowing capacity. 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.
The
credit agreement provides for
interest only payments until August 31, 2010, when the entire amount
borrowed is due. Whiting Oil and Gas may, throughout the five-year term of
the
credit agreement, borrow, repay and re-borrow up to the borrowing base in
effect
from 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 ours in an aggregate amount not to exceed
$50.0 million. As of March 31, 2007, letters of credit totaling
$0.3 million were outstanding under the credit agreement.
Interest
accrues, at Whiting Oil and Gas’ option, at either (1) 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 (2) 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. Whiting Oil and Gas has
consistently chosen the LIBOR rate option since it delivers the lowest effective
interest rate. 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. As of March 31, 2007, the effective weighted
average interest rate on the outstanding principal balance under the credit
agreement was 6.7%.
The
credit agreement contains restrictive covenants that may limit our 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 and requires
us to
maintain a debt to EBITDAX (as defined in the credit agreement) ratio of
less
than 3.5 to 1 and a working capital ratio (as defined in the credit agreement)
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 our wholly owned subsidiary, Equity Oil Company,
to make
any dividends, distributions or other payments to Whiting Petroleum Corporation.
The restrictions apply to all of the net assets of these subsidiaries. We
were
in compliance with our covenants under the credit agreement as of March 31,
2007. The credit agreement is secured by a first lien on all of Whiting Oil
and
Gas’ properties included in the borrowing base for the credit 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 our guarantee,
and
Equity Oil Company has mortgaged all of its properties, which are included
in
the borrowing base for the credit agreement, as security for its
guarantee.
Senior
Subordinated Notes. In October 2005, we issued $250.0 million of 7%
Senior Subordinated Notes due 2014 at par.
In
April
2005, we issued $220.0 million of 7.25% Senior Subordinated Notes due 2013.
The notes were issued at 98.507% of par and the associated discount is being
amortized to interest expense over the term of the notes.
In
May 2004, we issued $150.0 million of 7.25% Senior Subordinated Notes
due 2012. The notes were issued at 99.26% of par and the associated discount
is
being amortized to interest expense over the term of the 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 Corporation’s credit
agreement. 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,
incur
additional indebtedness 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. In addition, Whiting Oil and Gas Corporation’s credit agreement
restricts the ability of our subsidiaries to make certain payments, including
principal on the notes, to us. We were in compliance with these covenants
as of
March 31, 2007. Three of 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. In May 2006, we filed a universal shelf
registration statement with the SEC 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.
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.
Tax
Sharing Liability. In connection with our initial public offering in
November 2003, we entered into a tax separation and indemnification
agreement with our former parent, Alliant Energy Corporation (“Alliant Energy”).
Pursuant to this agreement, we and Alliant Energy made a tax election with
the
effect that the tax bases of the assets of Whiting Oil and Gas Corporation
and
its subsidiaries were increased to the deemed purchase price of their assets
immediately prior to such initial public offering. We have adjusted deferred
taxes on our balance sheet to reflect the new tax bases of our assets. These
additional 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. Such tax benefits will generally be calculated by comparing our actual
taxes to the taxes that would have been owed by us had the increase in bases
not
occurred. 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. We have estimated that total payments to Alliant will approximate
$38.6 million on an undiscounted basis, with a present value of $26.2
million. During the first quarter of 2007, we did not make any payments under
this agreement but did recognize $0.4 million of accretion expense, which
is
included as a component of interest expense. Our estimate of payments to
be made
under this agreement of $3.6 million in 2007 is reflected as a current
liability at March 31, 2007.
Schedule
of Contractual Obligations. The following table summarizes our obligations
and commitments as of March 31, 2007 to make future payments under certain
contracts, aggregated by category of contractual obligation, for specified
time
periods. This table does not include Production Participation Plan liabilities
since we cannot determine with accuracy the timing of future payment amounts
(in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt (a)
|
|
$ |
1,055,975
|
|
|
$ |
-
|
|
|
$ |
-
|
|
|
$ |
440,000
|
|
|
$ |
615,975
|
|
Cash
interest expense on debt (b)
|
|
|
381,589
|
|
|
|
66,901
|
|
|
|
148,610
|
|
|
|
101,716
|
|
|
|
64,362
|
|
Asset
retirement obligation (c)
|
|
|
40,347
|
|
|
|
612
|
|
|
|
1,121
|
|
|
|
2,990
|
|
|
|
35,624
|
|
Tax
sharing liability (d)
|
|
|
27,552
|
|
|
|
3,565
|
|
|
|
5,988
|
|
|
|
5,044
|
|
|
|
12,955
|
|
Derivative
contract liability fair value (e)
|
|
|
17,246
|
|
|
|
10,071
|
|
|
|
7,175
|
|
|
|
-
|
|
|
|
-
|
|
Purchasing
obligations (f)
|
|
|
303,914
|
|
|
|
24,767
|
|
|
|
101,040
|
|
|
|
101,329
|
|
|
|
76,778
|
|
Drilling
rig contracts (g)
|
|
|
43,342
|
|
|
|
16,936
|
|
|
|
23,994
|
|
|
|
2,412
|
|
|
|
-
|
|
Operating
leases (h)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
________________
(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 debt
under
our credit agreement, and assumes no principal repayment until
the due
date of the instruments.
|
(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. The
interest
rate swap on the $75.0 million of our $150.0 million fixed rate
7.25% Senior Subordinated Notes due 2012 is assumed to equal 7.7%
until
the due date of the instrument. Cash interest expense on the credit
agreement is estimated assuming no principal repayment until the
instrument due date, and a fixed interest rate of
6.7%.
|
(c)
|
Asset
retirement obligations represent the estimated present value of
amounts
expected to be incurred to plug, abandon and remediate oil and
gas
properties.
|
(d)
|
Amounts
shown are the estimated payments due based on projected future
income tax
benefits from the increase in tax bases described under “Tax Sharing
Liability” above.
|
(e)
|
We
have entered into derivative contracts, primarily costless collars,
to
hedge our exposure to crude oil and natural gas price fluctuations.
As of
March 31, 2007, the forward price curves for crude oil 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
risk.
|
(f)
|
We
entered into two take-or-pay purchase agreements, one agreement
in
July 2005 for 9.5 years and one agreement in March 2006 for
8 years, whereby we have committed to buy certain volumes of CO2
for
a fixed fee, subject to annual escalation, for use in enhanced
recovery
projects in our Postle field in Texas County, Oklahoma and our
North Ward
Estes field in Ward County, 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
entered into three separate three-year agreements in 2005 for drilling
rigs, a two-year agreement in February 2006 for a workover rig, and a
three-year agreement in September 2006 for an additional drilling
rig, all operating in the Rocky Mountains region. As of March 31,
2007,
early termination of these contracts would have required maximum
penalties
of $30.2 million. No other drilling rigs working for us are currently
under long-term contracts or contracts which 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 87,000 square feet of administrative office space in Denver,
Colorado under an operating lease arrangement through October 31,
2010, and an additional 26,500 square feet of office space in Midland,
Texas through February 15,
2012.
|
Based
on
current oil and 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.
Price-sharing
Arrangement. As part of a 2002 purchase transaction, we agreed to share
with the seller 50% of the actual price received for certain crude oil
production in excess of $19.00 per barrel. The agreement runs through
December 31, 2009 and contains a 2% price escalation per year. As a result,
the sharing amount at January 1, 2007 increased to 50% of the actual price
received in excess of $20.98 per barrel. As of March 31, 2007, approximately
34,900 net barrels of crude oil per month (5% of March 2007 net crude oil
production) are subject to this sharing agreement. The terms of the agreement
do
not provide for a maximum amount to be paid. During the first quarter of
2007,
we paid $1.8 million under this agreement. As of March 31, 2007, we have
accrued an additional $0.5 million as currently payable.
New
Accounting Policies
In
June 2006, the Financial Accounting Standards Board (“FASB”) issued
Interpretation No. 48, Accounting for Uncertainty in Income Taxes,
an interpretation of Statement of Financial Accounting Standards No. 109,
Accounting for Income Taxes (“FIN 48”). The interpretation creates a single
model to address accounting for uncertainty in tax positions. Specifically,
the
pronouncement prescribes a recognition threshold and a measurement attribute
for
the financial statement recognition and measurement of a tax position taken
or
expected to be taken in a tax return. The interpretation also provides guidance
on derecognition, classification, interest and penalties, accounting in interim
periods, disclosure and transition of certain tax positions.
We
adopted the provisions of FIN 48 on January 1, 2007. As a result of the
implementation of FIN 48, we recognized a $0.3 million increase in the liability
for unrecognized tax benefits, which was accounted for as a reduction to
the
January 1, 2007, balance of retained earnings. The total amount of
unrecognized tax benefits as of the adoption date was $0.4 million, and there
were no additions or reductions to our unrecognized tax benefits during the
three months ended March 31, 2007. Our policy is to recognize
interest and penalties accrued related to unrecognized tax benefits within
income tax expense.
New
Accounting Pronouncements
In
September 2006, the FASB issued
Statement No. 157, Fair Value Measurements (“SFAS 157”). The
adoption of SFAS 157 is not expected to have a material impact on our
consolidated financial position or results of operations. However, additional
disclosures may be required about the information used to develop the
measurements. SFAS 157 establishes a single authoritative definition of fair
value, sets out a framework for measuring fair value and requires additional
disclosures about fair value measurements. This Standard requires companies
to
disclose the fair value of their financial instruments according to a fair
value
hierarchy. SFAS 157 does not require any new fair value measurements, but
will
remove inconsistencies in fair value measurements between various accounting
pronouncements. SFAS 157 is effective for financial statements issued for
fiscal
years beginning after November 15, 2007 and interim periods within those
fiscal years.
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,
2006.
Effects
of Inflation and Pricing
We
experienced increased costs during 2006 and the first quarter of 2007 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 gas increase, so do all associated costs. Conversely,
in a
period of declining prices, associated cost declines are likely to lag and
may
not adjust downward in proportion. Material changes in prices also
impact the current revenue stream, estimates of future reserves, borrowing
base
calculations of bank loans 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,
continued high prices for oil and gas could result in increases in the costs
of
materials, services and personnel.
|
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, 2006 and have not
materially changed since that report was filed.
Our
outstanding hedges as of April 1, 2007 are summarized below:
Commodity
|
Period
|
Monthly
Volume (MMBtu)/(Bbl)
|
NYMEX
Floor/Ceiling
|
Crude
Oil
|
04/2007
to 06/2007
|
110,000
|
$50.00/$72.00
|
Crude
Oil
|
04/2007
to 06/2007
|
300,000
|
$50.00/$78.50
|
Crude
Oil
|
07/2007
to 09/2007
|
110,000
|
$50.00/$70.90
|
Crude
Oil
|
07/2007
to 09/2007
|
300,000
|
$50.00/$77.55
|
Crude
Oil
|
10/2007
to 12/2007
|
110,000
|
$49.00/$71.50
|
Crude
Oil
|
10/2007
to 12/2007
|
300,000
|
$50.00/$76.50
|
Crude
Oil
|
01/2008
to 03/2008
|
110,000
|
$49.00/$70.65
|
Crude
Oil
|
01/2008
to 03/2008
|
120,000
|
$60.00/$73.90
|
Crude
Oil
|
04/2008
to 06/2008
|
110,000
|
$48.00/$71.60
|
Crude
Oil
|
04/2008
to 06/2008
|
120,000
|
$60.00/$74.65
|
Crude
Oil
|
07/2008
to 09/2008
|
110,000
|
$48.00/$70.85
|
Crude
Oil
|
07/2008
to 09/2008
|
120,000
|
$60.00/$75.60
|
Crude
Oil
|
10/2008
to 12/2008
|
110,000
|
$48.00/$70.20
|
Crude
Oil
|
10/2008
to 12/2008
|
120,000
|
$60.00/$75.85
|
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 beyond the ceiling.
For the 2007 crude oil contracts listed above, a hypothetical $1.00 change
in
the NYMEX price would cause a change in the gain (loss) on hedging
activities in 2007 of $3.7 million.
In
a 1997
non-operated property acquisition, 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, 2007 are summarized
below:
|
|
|
|
Natural
Gas
|
04/2007
to 05/2011
|
29,000
|
$4.75
|
Natural
Gas
|
04/2007
to 09/2012
|
66,000
|
$4.21
|
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
Vice President and 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 the end of the quarter ended
March 31, 2007. Based upon their evaluation of these disclosures controls
and
procedures, the Chairman, President and Chief Executive Officer and the Vice
President and Chief Financial Officer concluded that the disclosure controls
and
procedures were effective as of the end of the quarter ended March 31, 2007
to
ensure that information required to be disclosed by us in the reports we
file or
submit under the Exchange Act is recorded, processed, summarized and reported,
within the time periods specified in the Securities and Exchange Commission’s
rules and forms, 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, 2007
that
has materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting.
PART
II – OTHER INFORMATION
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, 2006. No material change to such
risk factors has occurred during the three months ended March 31,
2007.
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 27th day of April, 2007.
|
|
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
INDEX
Exhibit
Number
|
Exhibit
Description
|
|
|
|
|
|
|
|
|
|
|
*
A
management contract or compensatory plan or arrangement.