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 June 30,
2008
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, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,”
“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one):
|
Large
accelerated filer T
|
Accelerated
filer £
|
Non-accelerated
filer £
|
|
Smaller
reporting company £
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).Yes £No T
Number of
shares of the registrant’s common stock outstanding at July 15,
2008: 42,321,401 shares.
TABLE OF CONTENTS
CERTAIN DEFINITIONS
Unless
the context otherwise requires, the terms “we,” “us,” “our” or “ours” when used
in this report refer to Whiting Petroleum Corporation, together with its
consolidated subsidiaries. When the context requires, we refer to
these entities separately.
We have
included below the definitions for certain terms used in this
report:
“Bbl” One stock tank barrel,
or 42 U.S. gallons liquid volume, used in this report in reference to oil and
other liquid hydrocarbons.
“Bbl/d” One stock tank
barrel, or 42 U.S. gallons liquid volume, used in this report in reference to
oil and other liquid hydrocarbons per day.
“Bcf” One billion cubic feet
of natural gas.
“Bcfe” One billion cubic feet
of natural gas equivalent.
“BOE” One stock tank barrel
equivalent of oil, calculated by converting natural gas volumes to equivalent
oil barrels at a ratio of six Mcf to one Bbl of oil.
“flush production” The high
rate of flow from a well during initial production immediately after it is
brought on-line.
“Mbbl” One thousand barrels
of oil or other liquid hydrocarbons.
“MBOE” One thousand
BOE.
“MBOE/d” One thousand BOE per
day.
“Mcf” One thousand cubic feet
of natural gas.
“Mcfe” One thousand cubic
feet of natural gas equivalent.
“MMbbl” One million barrels of
oil or other liquid hydrocarbons.
“MMBOE” One million
BOE.
“MMbtu” One million British
Thermal Units.
“MMcf” One million cubic feet
of natural gas.
“MMcfe/d” One million cubic
feet of natural gas equivalent per day.
“plugging and abandonment”
Refers to the sealing off of fluids in the strata penetrated by a well so that
the fluids from one stratum will not escape into another or to the
surface. Regulations of many states require plugging of abandoned
wells.
“working interest” The
interest in a crude oil and natural gas property (normally a leasehold interest)
that gives the owner the right to drill, produce and conduct operations on the
property and to share in production, subject to all royalties, overriding
royalties and other burdens and to share in all costs of exploration,
development, operations and all risks in connection therewith.
PART I –
FINANCIAL INFORMATION
|
Item 1.
|
Consolidated Financial
Statements
|
WHITING PETROLEUM CORPORATION
CONDENSED
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In
thousands)
|
June 30,
2008
|
December 31,
2007
|
|||||||
|
ASSETS
|
||||||||
|
CURRENT
ASSETS:
|
||||||||
|
Cash
and cash equivalents
|
$ | 25,205 | $ | 14,778 | ||||
|
Accounts
receivable trade, net
|
199,782 | 110,437 | ||||||
|
Deferred
income taxes
|
39,890 | 27,720 | ||||||
|
Prepaid
expenses and other
|
33,152 | 9,232 | ||||||
|
Total
current assets
|
298,029 | 162,167 | ||||||
|
PROPERTY
AND EQUIPMENT:
|
||||||||
|
Oil
and gas properties, successful efforts method:
|
||||||||
|
Proved
properties
|
3,874,820 | 3,313,777 | ||||||
|
Unproved
properties
|
131,430 | 55,084 | ||||||
|
Other
property and equipment
|
51,456 | 37,778 | ||||||
|
Total
property and equipment
|
4,057,706 | 3,406,639 | ||||||
|
Less
accumulated depreciation, depletion and amortization
|
(715,426 | ) | (646,943 | ) | ||||
|
Total
property and equipment, net
|
3,342,280 | 2,759,696 | ||||||
|
DEBT
ISSUANCE COSTS
|
12,881 | 15,016 | ||||||
|
OTHER
LONG-TERM ASSETS
|
52,006 | 15,132 | ||||||
|
TOTAL
|
$ | 3,705,196 | $ | 2,952,011 | ||||
|
See
notes to condensed consolidated financial statements.
|
(Continued)
|
|||||||
WHITING
PETROLEUM CORPORATION
CONDENSED
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In
thousands, except share and per share data)
|
June 30,
2008
|
December 31,
2007
|
|||||||
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
||||||||
|
CURRENT
LIABILITIES:
|
||||||||
|
Accounts
payable
|
$ | 50,366 | $ | 19,280 | ||||
|
Accrued
capital expenditures
|
79,096 | 59,441 | ||||||
|
Accrued
liabilities
|
41,188 | 29,098 | ||||||
|
Accrued
interest
|
10,633 | 11,240 | ||||||
|
Oil
and gas sales payable
|
39,425 | 26,205 | ||||||
|
Accrued
employee compensation and benefits
|
25,756 | 21,081 | ||||||
|
Production
taxes payable
|
25,193 | 12,936 | ||||||
|
Current
portion of deferred gain on sale
|
16,070 | - | ||||||
|
Current
portion of tax sharing liability
|
2,587 | 2,587 | ||||||
|
Current
portion of derivative liability
|
139,268 | 72,796 | ||||||
|
Total
current liabilities
|
429,582 | 254,664 | ||||||
|
NON-CURRENT
LIABILITIES:
|
||||||||
|
Long-term
debt
|
1,118,411 | 868,248 | ||||||
|
Asset
retirement obligations
|
41,067 | 35,883 | ||||||
|
Production
Participation Plan liability
|
51,889 | 34,042 | ||||||
|
Tax
sharing liability
|
23,693 | 23,070 | ||||||
|
Deferred
income taxes
|
317,889 | 242,964 | ||||||
|
Long-term
derivative liability
|
37,871 | - | ||||||
|
Deferred
gain on sale
|
82,418 | - | ||||||
|
Other
long-term liabilities
|
2,290 | 2,314 | ||||||
|
Total
non-current liabilities
|
1,675,528 | 1,206,521 | ||||||
|
COMMITMENTS
AND CONTINGENCIES
|
||||||||
|
STOCKHOLDERS’
EQUITY:
|
||||||||
|
Common
stock, $0.001 par value; 75,000,000 shares authorized, 42,586,046 and
42,480,497 shares issued as of June 30, 2008 and December 31,
2007, respectively
|
43 | 42 | ||||||
|
Additional
paid-in capital
|
970,387 | 968,876 | ||||||
|
Accumulated
other comprehensive loss
|
(81,131 | ) | (46,116 | ) | ||||
|
Retained
earnings
|
710,787 | 568,024 | ||||||
|
Total
stockholders’ equity
|
1,600,086 | 1,490,826 | ||||||
|
TOTAL
|
$ | 3,705,196 | $ | 2,952,011 | ||||
|
See
notes to condensed consolidated financial statements.
|
(Concluded)
|
|||||||
WHITING PETROLEUM CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(In
thousands, except per share data)
|
Three
Months Ended June 30,
|
Six
Months Ended June 30,
|
|||||||||||||||
|
2008
|
2007
|
2008
|
2007
|
|||||||||||||
|
REVENUES
AND OTHER INCOME:
|
||||||||||||||||
|
Oil
and natural gas sales
|
$ | 390,536 | $ | 192,646 | $ | 677,267 | $ | 352,359 | ||||||||
|
Loss
on oil hedging activities
|
(48,111 | ) | - | (71,023 | ) | - | ||||||||||
|
Amortization
of deferred gain on sale
|
2,957 | - | 2,957 | - | ||||||||||||
|
Interest
income and other
|
393 | 258 | 624 | 467 | ||||||||||||
|
Total
revenues and other income
|
345,775 | 192,904 | 609,825 | 352,826 | ||||||||||||
|
COSTS
AND EXPENSES:
|
||||||||||||||||
|
Lease
operating
|
57,470 | 51,983 | 113,176 | 101,037 | ||||||||||||
|
Production
taxes
|
26,057 | 12,079 | 43,743 | 21,690 | ||||||||||||
|
Depreciation,
depletion and amortization
|
54,811 | 49,335 | 105,322 | 93,906 | ||||||||||||
|
Exploration
and impairment
|
8,643 | 6,643 | 19,627 | 15,820 | ||||||||||||
|
General
and administrative
|
23,007 | 8,876 | 34,622 | 17,161 | ||||||||||||
|
Change
in Production Participation Plan liability
|
11,690 | 2,058 | 17,847 | 4,150 | ||||||||||||
|
Interest
expense
|
15,671 | 20,754 | 31,217 | 40,253 | ||||||||||||
|
Loss
(gain) on mark-to-market derivatives
|
20,562 | (423 | ) | 17,625 | 691 | |||||||||||
|
Total
costs and expenses
|
217,911 | 151,305 | 383,179 | 294,708 | ||||||||||||
|
INCOME
BEFORE INCOME TAXES
|
127,864 | 41,599 | 226,646 | 58,118 | ||||||||||||
|
INCOME
TAX EXPENSE:
|
||||||||||||||||
|
Current
|
(837 | ) | 1,515 | 872 | 2,141 | |||||||||||
|
Deferred
|
48,252 | 13,613 | 83,011 | 18,840 | ||||||||||||
|
Total
income tax expense
|
47,415 | 15,128 | 83,883 | 20,981 | ||||||||||||
|
NET
INCOME
|
$ | 80,449 | $ | 26,471 | $ | 142,763 | $ | 37,137 | ||||||||
|
NET
INCOME PER COMMON SHARE, BASIC
|
$ | 1.90 | $ | 0.72 | $ | 3.38 | $ | 1.01 | ||||||||
|
NET
INCOME PER COMMON SHARE, DILUTED
|
$ | 1.90 | $ | 0.72 | $ | 3.37 | $ | 1.01 | ||||||||
|
WEIGHTED
AVERAGE SHARES OUTSTANDING, BASIC
|
42,320 | 36,808 | 42,296 | 36,789 | ||||||||||||
|
WEIGHTED
AVERAGE SHARES OUTSTANDING, DILUTED
|
42,446 | 36,905 | 42,416 | 36,936 | ||||||||||||
|
See
notes to condensed consolidated financial statements.
|
||||||||||||||||
WHITING PETROLEUM CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(In
thousands)
|
Six
Months Ended
June
30,
|
||||||||
|
2008
|
2007
|
|||||||
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
||||||||
|
Net
income
|
$ | 142,763 | $ | 37,137 | ||||
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
||||||||
|
Depreciation,
depletion and amortization
|
105,322 | 93,906 | ||||||
|
Deferred
income taxes
|
83,011 | 18,840 | ||||||
|
Amortization
of debt issuance costs and debt discount
|
2,423 | 2,542 | ||||||
|
Accretion
of tax sharing liability
|
623 | 761 | ||||||
|
Stock-based
compensation
|
3,245 | 2,378 | ||||||
|
Amortization
of deferred gain on sale
|
(2,957 | ) | - | |||||
|
Unproved
leasehold and oil and gas property impairments
|
5,400 | 4,642 | ||||||
|
Change
in Production Participation Plan liability
|
17,847 | 4,150 | ||||||
|
Loss
on mark-to-market derivatives
|
17,625 | 691 | ||||||
|
Other
non-current
|
(11,757 | ) | (1,984 | ) | ||||
|
Changes
in current assets and liabilities:
|
||||||||
|
Accounts
receivable trade
|
(80,853 | ) | 551 | |||||
|
Prepaid
expenses and other
|
(24,472 | ) | (1,783 | ) | ||||
|
Accounts
payable and accrued liabilities
|
43,060 | (3,027 | ) | |||||
|
Accrued
interest
|
(607 | ) | 204 | |||||
|
Other
current liabilities
|
28,418 | (9,055 | ) | |||||
|
Net
cash provided by operating activities
|
329,091 | 149,953 | ||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
||||||||
|
Cash
acquisition capital expenditures
|
(388,457 | ) | (13,624 | ) | ||||
|
Drilling
and development capital expenditures
|
(376,410 | ) | (230,396 | ) | ||||
|
Proceeds
from sale of oil and gas properties
|
311 | 1,291 | ||||||
|
Proceeds
from sale of marketable securities
|
764 | - | ||||||
|
Net
proceeds from sale of 11,677,500 units in Whiting USA Trust
I
|
195,128 | - | ||||||
|
Net
cash used in investing activities
|
(568,664 | ) | (242,729 | ) | ||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
||||||||
|
Long-term
borrowings under credit agreement
|
735,000 | 190,000 | ||||||
|
Repayments
of long-term borrowings under credit agreement
|
(485,000 | ) | (100,000 | ) | ||||
|
Tax
effect from restricted stock vesting
|
- | 294 | ||||||
|
Net
cash provided by financing activities
|
250,000 | 90,294 | ||||||
|
NET
CHANGE IN CASH AND CASH EQUIVALENTS
|
10,427 | (2,482 | ) | |||||
|
CASH
AND CASH EQUIVALENTS:
|
||||||||
|
Beginning
of period
|
14,778 | 10,372 | ||||||
|
End
of period
|
$ | 25,205 | $ | 7,890 | ||||
|
SUPPLEMENTAL
CASH FLOW DISCLOSURES:
|
||||||||
|
Cash
paid for income taxes
|
$ | 832 | $ | 1,743 | ||||
|
Cash
paid for interest
|
$ | 28,778 | $ | 36,746 | ||||
|
NONCASH
INVESTING ACTIVITIES:
|
||||||||
|
Accrued
capital expenditures during the period
|
$ | 79,096 | $ | 39,672 | ||||
|
See
notes to condensed consolidated financial statements.
|
||||||||
WHITING PETROLEUM CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
AND
COMPREHENSIVE INCOME (Unaudited)
(In
thousands)
|
Common
Stock
|
Additional
Paid-in
|
Accumulated
Other Comprehensive
|
Retained
|
Total
Stockholders’
|
Comprehensive
|
|||||||||||||||||||||||
|
Shares
|
Amount
|
Capital
|
Income
(Loss)
|
Earnings
|
Equity
|
Income
|
||||||||||||||||||||||
|
BALANCES-January
1, 2007
|
36,948 | $ | 37 | $ | 754,788 | $ | (5,902 | ) | $ | 437,747 | $ | 1,186,670 | ||||||||||||||||
|
Adoption
of FIN 48
|
- | - | - | - | (323 | ) | (323 | ) | $ | - | ||||||||||||||||||
|
Net
income
|
- | - | - | - | 130,600 | 130,600 | 130,600 | |||||||||||||||||||||
|
Change
in derivative fair values, net of taxes of $31,012
|
- | - | - | (53,637 | ) | - | (53,637 | ) | (53,637 | ) | ||||||||||||||||||
|
Realized
loss on settled derivative contracts, net of taxes of
$7,766
|
- | - | - | 13,423 | - | 13,423 | 13,423 | |||||||||||||||||||||
|
Issuance
of stock, secondary offering
|
5,425 | 5 | 210,389 | - | - | 210,394 | - | |||||||||||||||||||||
|
Restricted
stock issued
|
150 | - | - | - | - | - | - | |||||||||||||||||||||
|
Restricted
stock forfeited
|
(12 | ) | - | - | - | - | - | - | ||||||||||||||||||||
|
Restricted
stock used for tax withholdings
|
(31 | ) | - | (1,403 | ) | - | - | (1,403 | ) | - | ||||||||||||||||||
|
Tax
effect from restricted stock vesting
|
- | - | 45 | - | - | 45 | - | |||||||||||||||||||||
|
Stock-based
compensation
|
- | - | 5,057 | - | - | 5,057 | - | |||||||||||||||||||||
|
BALANCES-December
31, 2007
|
42,480 | $ | 42 | $ | 968,876 | $ | (46,116 | ) | $ | 568,024 | $ | 1,490,826 | $ | 90,386 | ||||||||||||||
|
Net
income
|
- | - | - | - | 142,763 | 142,763 | 142,763 | |||||||||||||||||||||
|
Change
in derivative fair values, net of taxes of $46,279
|
- | - | - | (79,993 | ) | - | (79,993 | ) | (79,993 | ) | ||||||||||||||||||
|
Realized
loss on settled derivative contracts, net of taxes of
$26,021
|
- | - | - | 44,978 | - | 44,978 | 44,978 | |||||||||||||||||||||
|
Restricted
stock issued
|
139 | 1 | - | - | - | 1 | - | |||||||||||||||||||||
|
Restricted
stock forfeited
|
(3 | ) | - | - | - | - | - | - | ||||||||||||||||||||
|
Restricted
stock used for tax withholdings
|
(30 | ) | - | (1,734 | ) | - | - | (1,734 | ) | - | ||||||||||||||||||
|
Stock-based
compensation
|
- | - | 3,245 | - | - | 3,245 | - | |||||||||||||||||||||
|
BALANCES-June
30, 2008
|
42,586 | $ | 43 | $ | 970,387 | $ | (81,131 | ) | $ | 710,787 | $ | 1,600,086 | $ | 107,748 | ||||||||||||||
|
See
notes to condensed consolidated financial statements.
|
||||||||||||||||||||||||||||
WHITING PETROLEUM CORPORATION
NOTES
TO CONDENSED CONSOLIDATED
FINANCIAL
STATEMENTS (Unaudited)
|
1.
|
BASIS
OF PRESENTATION
|
Description of
Operations—Whiting Petroleum Corporation, a Delaware corporation, is an
independent oil and gas company that acquires, exploits, develops and explores
for crude oil, natural gas and natural gas liquids primarily in the Permian
Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the
United States. Unless otherwise specified or the context otherwise
requires, all references in these notes to “Whiting” or the “Company” are to
Whiting Petroleum Corporation and its consolidated subsidiaries.
Consolidated
Financial Statements—The unaudited condensed consolidated financial
statements include the accounts of Whiting Petroleum Corporation and its
consolidated 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 intercompany
balances and transactions have been eliminated in consolidation. In
the opinion of management, the accompanying financial statements include all
adjustments (consisting of normal recurring accruals and adjustments) necessary
to present fairly, in all material respects, the Company’s interim
results. Whiting’s 2007 Annual Report on Form 10-K includes certain
definitions and a summary of significant accounting policies and should be read
in conjunction with this Form 10-Q. Except as disclosed herein, there
has been no material change to the information disclosed in the notes to the
consolidated financial statements included in Whiting’s 2007 Annual Report on
Form 10-K. Operating results for the periods presented are not
necessarily indicative of the results that may be expected for the full
year.
Earnings Per
Share—Basic net income per common share is calculated by dividing net
income by the weighted average number of common shares outstanding during each
period. Diluted net income per common share is calculated by dividing
net income by the weighted average number of common shares outstanding and other
dilutive securities. The only securities considered dilutive are the
Company’s unvested restricted stock awards.
|
2.
|
ACQUISITIONS
AND DIVESTITURES
|
2008
Acquisition
Flat Rock Natural
Gas Field—On
May 30, 2008, Whiting acquired interests in 31 producing gas wells,
development acreage and gas gathering and processing facilities on 22,029 gross
acres (11,533 net acres) in the Flat Rock field in Uintah County, Utah for an
aggregate acquisition price of $364.4 million. After allocating the
purchase price of $79.1 million to unproved property and $35.7 million to the
gas gathering and processing facilities, the remaining $256.8 million results in
an acquisition cost for proved reserves of $2.23 per Mcfe. Of the
estimated 115.2 Bcfe of proved reserves acquired as of the January 1, 2008
acquisition effective date, 98% are natural gas and 22% are proved developed
producing. The average daily net production from the properties was
18.1 MMcfe/d in June 2008. Whiting funded the acquisition with borrowings
under its credit agreement.
This
acquisition was recorded using the purchase method of accounting. The
table below summarizes the preliminary allocation of purchase price based on the
acquisition date fair value of the assets acquired and the liabilities assumed
(in thousands).
|
Flat
Rock
|
||||
|
Cash
paid
|
$ | 364,414 | ||
|
Allocation
of Purchase Price:
|
||||
|
Proved
properties
|
$ | 256,760 | ||
|
Unproved
properties
|
79,115 | |||
|
Gas
gathering and processing facilities
|
35,735 | |||
|
Liabilities
assumed
|
(7,196 | ) | ||
|
Total
|
$ | 364,414 | ||
Acquisition Pro
Forma
In the
Company’s condensed consolidated statements of income, Flat Rock’s results of
operations are included with the Company’s results beginning May 31, 2008, the
closing date of the acquisition. The following table, however,
reflects the unaudited pro forma results of operations for the three and six
months ended June 30, 2008 and 2007 as though the Flat Rock acquisition had
occurred on the first day of each period presented. The pro forma
information below includes numerous assumptions and is not necessarily
indicative of future results of operations.
|
Pro
Forma
|
||||||||||||
|
Whiting
(As
reported)
|
Flat
Rock
|
Consolidated
|
||||||||||
|
Three
months ended June 30, 2008:
|
||||||||||||
|
Total
revenues
|
$ | 345,775 | $ | 7,879 | $ | 353,654 | ||||||
|
Net
income
|
80,449 | 850 | 81,299 | |||||||||
|
Net
income per common share – basic and diluted
|
1.90 | 0.02 | 1.92 | |||||||||
|
Three
months ended June 30, 2007:
|
||||||||||||
|
Total
revenues
|
$ | 192,904 | $ | 4,905 | $ | 197,809 | ||||||
|
Net
income
|
26,471 | (1,615 | ) | 24,856 | ||||||||
|
Net
income per common share – basic
|
0.72 | (0.04 | ) | 0.68 | ||||||||
|
Net
income per common share – diluted
|
0.72 | (0.05 | ) | 0.67 | ||||||||
|
Six
months ended June 30, 2008:
|
||||||||||||
|
Total
revenues
|
$ | 609,825 | $ | 17,761 | $ | 627,586 | ||||||
|
Net
income
|
142,763 | 1,144 | 143,907 | |||||||||
|
Net
income per common share – basic
|
3.38 | 0.02 | 3.40 | |||||||||
|
Net
income per common share – diluted
|
3.37 | 0.02 | 3.39 | |||||||||
|
Six
months ended June 30, 2007:
|
||||||||||||
|
Total
revenues
|
$ | 352,826 | $ | 14,735 | $ | 367,561 | ||||||
|
Net
income
|
37,137 | (1,091 | ) | 36,046 | ||||||||
|
Net
income per common share – basic and diluted
|
1.01 | (0.03 | ) | 0.98 | ||||||||
2008
Divestiture
Whiting USA Trust
I—On April 30, 2008, the Company completed an initial public
offering of units of beneficial interest in Whiting USA Trust I (the
“Trust”), selling 11,677,500 Trust units, at $20.00 per Trust unit, providing
net proceeds of $215.1 million after underwriters’ discount and commissions and
offering related expenses. Whiting’s net profits from the Trust’s
underlying oil and gas properties received between the effective date and the
closing date of the Trust unit sale were due to the Trust and thereby further
reduced net proceeds to $195.1 million. The Company used the offering
net proceeds to reduce the debt outstanding under its credit
agreement. The aggregate proceeds from the sale of Trust units to the
public resulted in a deferred gain on sale of $101.4
million. Immediately prior to the closing of the offering, Whiting
conveyed a term net profits interest in certain of its oil and natural gas
properties to the Trust in exchange for 13,863,889 Trust units. The
Company has retained 15.8%, or 2,186,389 Trust units, of the total Trust units
issued and outstanding.
The net
profits interest entitles the Trust to receive 90% of the net proceeds from the
sale of oil and natural gas production from the underlying
properties. The net profits interest will terminate at the time when
9.11 MMBOE have been produced and sold from the underlying
properties. This is the equivalent of 8.2 MMBOE in respect of the
Trust’s right to receive 90% of the net proceeds from such production pursuant
to the net profits interest, and these reserve quantities are projected to be
produced by December 31, 2017, based on the reserve report for the
underlying properties as of December 31, 2007. The conveyance of
the net profits interest to the Trust consisted entirely of proved developed
producing reserves of 8.2 MMBOE, as of the January 1, 2008 effective
date, representing 3.3% of Whiting’s proved reserves as of December 31,
2007, and 10.0%, or 4.2 MBOE/d, of its March 2008 average daily net
production. After netting the Company’s ownership of 2,186,389 Trust
units, third-party public Trust unit holders receive 6.9 MMBOE of proved
producing reserves, or 2.75% of the Company’s total year-end 2007 proved
reserves, and 7.4%, or 3.1 MBOE/d, of its March 2008 average daily net
production.
2007
Acquisitions
There
were no significant acquisitions during the year ended December 31,
2007.
2007
Divestitures
On
July 17, 2007, the Company sold its approximate 50% non-operated working
interest in several gas fields located in the LaSalle and Webb Counties of Texas
for total cash proceeds of $40.1 million, resulting in a pre-tax gain on sale of
$29.7 million. The divested properties had estimated proved reserves
of 2.3 MMBOE as of December 31, 2006, and when adjusted to the July 1,
2007 divestiture effective date, the divested property reserves yielded a sale
price of $17.77 per BOE. The June 2007 average daily net production
from these fields was 0.8 MBOE/d.
During
2007, the Company sold its interests in several additional non-core oil and gas
producing properties for an aggregate amount of $12.5 million in cash for
total estimated proved reserves of 0.6 MMBOE as of the divestitures’ effective
dates. The divested properties are located in Colorado, Louisiana,
Michigan, Montana, New Mexico, North Dakota, Oklahoma, Texas and
Wyoming. The average daily net production from the divested property
interests was 0.3 MBOE/d as of the dates of disposition.
|
3.
|
LONG-TERM
DEBT
|
Long-term
debt consisted of the following at June 30, 2008 and December 31, 2007 (in
thousands):
|
June
30,
2008
|
December
31,
2007
|
|||||||
|
Credit
Agreement
|
$ | 500,000 | $ | 250,000 | ||||
|
7%
Senior Subordinated Notes due 2014
|
250,000 | 250,000 | ||||||
|
7.25%
Senior Subordinated Notes due 2013, net of unamortized debt discount of
$1,750 and $1,966, respectively
|
218,250 | 218,034 | ||||||
|
7.25%
Senior Subordinated Notes due 2012, net of unamortized debt discount of
$465 and $537, respectively
|
150,161 | 150,214 | ||||||
|
Total debt
|
$ | 1,118,411 | $ | 868,248 | ||||
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 June 30, 2008, had a borrowing base of $900.0
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 June 30,
2008, the outstanding borrowings under the credit agreement totaled $500.0
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 June 30, 2008, letters of credit totaling $0.2 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 June 30,
2008, the weighted average interest rate on the outstanding principal balance
under the credit agreement was 3.8%.
The
credit agreement contains restrictive covenants that may limit the Company’s
ability to, among other things, pay cash dividends, incur additional
indebtedness, sell assets, make loans to others, make investments, enter into
mergers, enter into hedging contracts, change material agreements, incur liens
and engage in certain other transactions without the prior consent of the
lenders and requires the Company to maintain a debt to EBITDAX ratio (as defined
in the credit agreement) of less than 3.5 to 1 and a working capital ratio (as
defined in the credit agreement, which includes an add back of the available
borrowing capacity under the credit facility) of greater than
1 to 1. Except for limited exceptions, including the
payment of interest on the senior notes, the credit agreement restricts the
ability of Whiting Oil and Gas and Whiting Petroleum Corporation’s wholly-owned
subsidiary, Equity Oil Company, to make any dividends, distributions, principal
payments on senior notes, or other payments to Whiting Petroleum
Corporation. The restrictions apply to all of the net assets of these
subsidiaries. The Company was in compliance with its covenants under
the credit agreement as of June 30, 2008. 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 at par
$250.0 million of 7% Senior Subordinated Notes due 2014. The
estimated fair value of these notes was $244.7 million as of June 30,
2008.
In
April 2005, the Company issued $220.0 million of 7.25% Senior
Subordinated Notes due 2013. These notes were issued at 98.507% of
par, and the associated discount of $3.3 million is being amortized to interest
expense over the term of these notes, yielding an effective interest rate of
7.4%. The estimated fair value of these notes was $217.8 million as
of June 30, 2008.
In
May 2004, the Company issued $150.0 million of 7.25% Senior
Subordinated Notes due 2012. These notes were issued at 99.26% of
par, and the associated discount of $1.1 million is being amortized to interest
expense over the term of these notes, yielding an effective interest rate of
7.3%. The estimated fair value of these notes was $148.7 million
as of June 30, 2008.
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. The
Company was in compliance with these covenants as of June 30,
2008. 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 June 30,
2008, the Company has recorded a long term asset of $0.6 million related to the
interest rate swap, which has been designated as a fair value hedge, with an
offsetting increase to the fair value of the 7.25% Senior Subordinated Notes due
2012.
|
4.
|
ASSET
RETIREMENT OBLIGATIONS
|
The
Company’s asset retirement obligations represent the estimated future costs
associated with the plugging and abandonment of oil and gas wells, removal of
equipment and facilities from leased acreage, and land restoration (including
removal of certain onshore and offshore facilities in California), in accordance
with applicable local, state and federal laws. The Company determines
asset retirement obligations by calculating the present value of estimated cash
flows related to plug and abandonment obligations. The current
portions at June 30, 2008 and December 31, 2007 were $1.4 million and $1.3
million, respectively, and were recorded in accrued liabilities. The
following table provides a reconciliation of the Company’s asset retirement
obligations for the six months ended June 30, 2008 (in thousands):
|
Asset
retirement obligation, January 1, 2008
|
$ | 37,192 | ||
|
Additional
liability incurred
|
2,235 | |||
|
Revisions
in estimated cash flows
|
5,359 | |||
|
Accretion
expense
|
1,477 | |||
|
Obligations
on sold or conveyed properties
|
(486 | ) | ||
|
Liabilities
settled
|
(3,313 | ) | ||
|
Asset
retirement obligation, June 30, 2008
|
$ | 42,464 |
|
5.
|
DERIVATIVE
FINANCIAL INSTRUMENTS
|
Whiting
has entered into derivative contracts, primarily costless collars, to achieve a
more predictable cash flow by reducing its exposure to price
volatility. 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. 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 has designated several of its derivative
contracts as cash flow hedges, while the remaining portion of its derivative
contracts are not designated as hedges, with gains and losses from changes in
fair value recognized immediately in earnings. The Company does not
enter into derivative instruments for speculative or trading
purposes.
At June
30, 2008, accumulated other comprehensive loss consisted of $128.1 million
($81.1 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 three and six months ended June
30, 2008, Whiting recognized realized cash settlement losses of $48.1 million
and $71.0 million, respectively, on commodity derivative
settlements. For the three and six months ended June 30, 2007,
Whiting recognized no realized cash settlement gains or losses on commodity
derivative settlements. Based on the estimated fair value of the
Company’s derivative contracts designated as hedges at June 30, 2008, the
Company expects to reclassify into earnings from accumulated other comprehensive
income net after-tax losses of $81.1 million during the next six months and no
derivative gains or losses in the subsequent six months. However,
actual cash settlement gains and losses recognized may differ
materially.
At
July 1, 2008, the Company had hedged its exposure to the variability in
future cash flows from forecasted oil and gas production volumes, including
Whiting’s proportionate share of the Trust, as follows:
|
Whiting
Petroleum Corporation
|
||||||||||||||||
|
Contracted
Volumes
|
NYMEX
Price Collar Ranges
|
|||||||||||||||
|
Period
|
Crude
Oil
(Bbl)
|
Natural
Gas
(Mcf)
|
Crude
Oil
(per
Bbl)
|
Natural
Gas
(per
Mcf)
|
||||||||||||
|
July
2008 – December 2008
|
2,055,761 | 341,675 |
$58.42
- $ 77.73
|
$7.00
- $17.38
|
||||||||||||
|
January
2009 – December 2009
|
139,873 | 577,820 |
$76.00
- $137.43
|
$6.50
- $17.11
|
||||||||||||
|
January
2010 – December 2010
|
126,289 | 495,390 |
$76.00
- $134.98
|
$6.50
- $15.06
|
||||||||||||
|
January
2011 – December 2011
|
115,039 | 436,510 |
$74.00
- $140.15
|
$6.50
- $14.62
|
||||||||||||
|
January
2012 – December 2012
|
105,091 | 384,002 |
$74.00
- $141.72
|
$6.50
- $14.27
|
||||||||||||
|
Total
|
2,542,053 | 2,235,397 | ||||||||||||||
|
Third-party
Public Holders of Trust Units
|
||||||||||||||||
|
Contracted
Volumes
|
NYMEX
Price Collar Ranges
|
|||||||||||||||
|
Period
|
Crude
Oil
(Bbl)
|
Natural
Gas
(Mcf)
|
Crude
Oil
(per
Bbl)
|
Natural
Gas
(per
Mcf)
|
||||||||||||
|
July
2008 – December 2008
|
237,301 | 1,070,206 |
$82.00
- $132.81
|
$7.00
- $17.38
|
||||||||||||
|
January
2009 – December 2009
|
438,113 | 1,809,868 |
$76.00
- $137.43
|
$6.50
- $17.11
|
||||||||||||
|
January
2010 – December 2010
|
395,567 | 1,551,678 |
$76.00
- $134.98
|
$6.50
- $15.06
|
||||||||||||
|
January
2011 – December 2011
|
360,329 | 1,367,249 |
$74.00
- $140.15
|
$6.50
- $14.62
|
||||||||||||
|
January
2012 – December 2012
|
329,171 | 1,202,785 |
$74.00
- $141.72
|
$6.50
- $14.27
|
||||||||||||
|
Total
|
1,760,481 | 7,001,786 | ||||||||||||||
In
connection with the Company’s conveyance on April 30, 2008 of a term net profits
interest to the Trust and related sale of 11,677,500 Trust units to the public
(as further explained in the note on Acquisitions and Divestitures), the right
to any future hedge payments made or received by Whiting on certain of its
derivative contracts have been conveyed to the Trust, and therefore such
payments will be included in the Trust’s calculation of net
proceeds. Under the Trust, Whiting retains 10% of the net proceeds
from the underlying properties. Whiting’s retention of 10% of these
net proceeds combined with its ownership of 2,186,389 Trust units results in
third-party public holders of Trust units receiving 75.8%, and Whiting retaining
24.2%, of the future economic results of hedge contracts conveyed to the
Trust. The relative ownership of the future economic results of such
hedge contracts is reflected in the table above. No additional hedges
are allowed to be placed on Trust assets.
With
respect to derivatives entered into by Whiting for which the economic benefits
and detriments were conveyed to the Trust, the Company has recorded a current
derivative liability of $11.2 million and a non-current liability of $37.9
million, with a corresponding current derivative asset of $8.5 million and
non-current asset of $28.7 million. The current portion of the
derivative asset is recorded in prepaid expense and other, while the non-current
portion is recorded in other long-term assets.
The
Company has also entered into an interest rate swap designated as a fair value
hedge as further explained in the note on Long-Term Debt.
|
6.
|
FAIR
VALUE DISCLOSURES
|
SFAS
157—Effective January 1, 2008, the Company adopted Financial
Accounting Standards Board (“FASB”) Statement No. 157, Fair Value Measurements
(“SFAS 157”), which defines fair value, establishes a framework for
measuring fair value, establishes a fair value hierarchy based on the quality of
inputs used to measure fair value and enhances disclosure requirements for fair
value measurements. The implementation of SFAS 157 did not cause a
change in the method of calculating fair value of assets or liabilities, with
the exception of incorporating a measure of the Company’s own nonperformance
risk or that of its counterparties as appropriate, which was not
material. The primary impact from adoption was additional
disclosures.
The
Company elected to implement SFAS 157 with the one-year deferral permitted by
FASB Staff Position No. FAS 157-2, Effective Date of FASB Statement
No. 157
(“FSP 157-2”), issued February 2008, which defers the effective date
of SFAS 157 for one year for certain nonfinancial assets and nonfinancial
liabilities measured at fair value, except those that are recognized or
disclosed at fair value in the financial statements on a recurring
basis. As it relates to the Company, the deferral applies to certain
nonfinancial assets and liabilities as may be acquired in a business combination
and thereby measured at fair value; impaired oil and gas property assessments;
and the initial recognition of asset retirement obligations for which fair value
is used.
Fair Value
Hierarchy—SFAS 157 establishes a three-level valuation hierarchy for
disclosure of fair value measurements. The valuation hierarchy
categorizes assets and liabilities measured at fair value into one of three
different levels depending on the observability of the inputs employed in the
measurement. The three levels are defined as follows:
|
·
|
Level
1: Quoted Prices in Active Markets for Identical Assets – inputs to the
valuation methodology are quoted prices (unadjusted) for identical
assets or liabilities in active
markets.
|
|
·
|
Level
2: Significant Other Observable Inputs – inputs to the valuation
methodology include quoted prices for similar assets and liabilities in
active markets, and inputs that are observable for the asset or liability,
either directly or indirectly, for substantially the full term of the
financial instrument.
|
|
·
|
Level
3: Significant Unobservable Inputs – inputs to the valuation methodology
are unobservable and significant to the fair value
measurement.
|
A
financial instrument’s categorization within the valuation hierarchy is based
upon the lowest level of input that is significant to the fair value
measurement. The Company’s assessment of the significance of a
particular input to the fair value measurement in its entirety requires judgment
and considers factors specific to the asset or liability. The
following table presents information about the Company’s assets and liabilities
measured at fair value on a recurring basis as of June 30, 2008, and indicates
the fair value hierarchy of the valuation techniques utilized by the Company to
determine such fair value (in thousands):
|
Level
1
|
Level
2
|
Level
3
|
June
30, 2008
|
|||||||||||||
|
Assets
|
||||||||||||||||
|
Prepaid expenses and
other (1)
|
$ | - | $ | 8,491 | $ | - | $ | 8,491 | ||||||||
|
Other long-term
assets (2)(3)
|
- | 29,335 | - | 29,335 | ||||||||||||
|
Total
|
$ | - | $ | 37,826 | $ | - | $ | 37,826 | ||||||||
|
Liabilities
|
||||||||||||||||
|
Current
portion of derivative liability
|
$ | - | $ | 139,268 | $ | - | $ | 139,268 | ||||||||
|
Long-term
derivative liability
|
- | 37,871 | - | 37,871 | ||||||||||||
|
Long-term debt (2)
|
- | 626 | - | 626 | ||||||||||||
|
Total
|
$ | - | $ | 177,765 | $ | - | $ | 177,765 | ||||||||
_______________
|
(1)
|
Amount
represents current portion of derivative assets.
|
| (2) | Amount includes $626 related to interest rate swap (see note on Long-Term Debt). |
| (3) | Amount includes $28,709 related to non-current derivative assets. |
The
following methods and assumptions were used to estimate the fair values of the
assets and liabilities in the table above:
Commodity Derivative
Instruments—Commodity derivative instruments consist of costless collars
for crude oil and natural gas. The Company’s costless collars are
valued based on the counterparty’s marked-to-market statements, which are
validated by observable transactions for the same or similar commodity options
using the NYMEX futures index, and are designated as Level 2 within the
valuation hierarchy. The discount rate used in the fair values of
these instruments includes a measure of nonperformance risk.
Interest Rate Swap—The
Company’s interest rate swap is valued using the counterparty’s marked-to-market
statement, which can be validated using modeling techniques that include market
inputs such as publicly available interest rate yield curves, and is designated
as Level 2 within the valuation hierarchy.
SFAS
159—In February 2007, the FASB issued Statement No. 159, The Fair Value Option for Financial
Assets and Financial Liabilities – Including an amendment of FASB Statement
No. 115 (“SFAS 159”). SFAS 159 expands the use of fair
value accounting but does not affect existing standards which require assets or
liabilities to be carried at fair value. On January 1, 2008, the
Company adopted SFAS 159 and did not elect fair value accounting for any of its
eligible items. The adoption of SFAS 159 therefore had no impact on
the Company’s consolidated financial position, cash flows or results of
operations. If the use of fair value is elected (the fair value
option), however, any upfront costs and fees related to the item must be
recognized in earnings and cannot be deferred, e.g., debt issue
costs. The fair value election is irrevocable and generally made on
an instrument-by-instrument basis, even if a company has similar instruments
that it elects not to measure based on fair value. Subsequent to the
adoption of SFAS 159, changes in fair value are recognized in
earnings.
|
7.
|
STOCKHOLDERS’
EQUITY
|
Equity Incentive
Plan—The Company maintains the Whiting Petroleum Corporation 2003 Equity
Incentive Plan (the “Plan”), pursuant to which two million shares of the
Company’s common stock have been reserved for issuance. No employee
or officer participant may be granted options for more than 300,000 shares of
common stock, stock appreciation rights 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, directors and employees generally vest
ratably over three years. However, restricted stock awards granted to
executive officers in February 2007 and 2008 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 and 2008 restricted stock
grants to executives.
The
following table shows a summary of the Company’s nonvested restricted stock as
of June 30, 2008 as well as activity during the six 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, 2008
|
239,656 | $ | 44.15 | |||||
|
Granted
|
138,518 | $ | 58.35 | |||||
|
Vested
|
(110,347 | ) | $ | 43.47 | ||||
|
Forfeited
|
(3,182 | ) | $ | 51.27 | ||||
|
Restricted
stock awards nonvested, June 30, 2008
|
264,645 | $ | 51.78 | |||||
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
June 30, 2008, there was $8.0 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 2.4 years.
Rights
Agreement—In 2006, the Board of Directors of the Company declared a
dividend of one preferred share purchase right (a “Right”) for each outstanding
share of common stock of the Company payable to the stockholders of record as of
March 2, 2006. Each Right entitles the registered holder to
purchase from the Company one one-hundredth of a share of Series A Junior
Participating Preferred Stock, par value $0.001 per share (“Preferred Shares”),
of the Company at a price of $180.00 per one one-hundredth of a Preferred Share,
subject to adjustment. If any person becomes a 15% or more
stockholder of the Company, then each Right (subject to certain limitations)
will entitle its holder to purchase, at the Right’s then current exercise price,
a number of shares of common stock of the Company or of the acquirer having a
market value at the time of twice the Right’s per share exercise
price. The Company’s Board of Directors may redeem the Rights for
$0.001 per Right at any time prior to the time when the Rights become
exercisable. Unless the Rights are redeemed, exchanged or terminated
earlier, they will expire on February 23, 2016.
|
8.
|
EMPLOYEE
BENEFIT PLANS
|
Production
Participation Plan—The Company has a Production Participation Plan (the
“Plan”) in which all employees participate. On an annual basis,
interests in oil and gas properties acquired, developed or sold during the year
are allocated to the Plan as determined annually by the Compensation
Committee. Once allocated, the interests (not legally conveyed) are
fixed. Interest allocations prior to 1995 consisted of 2%-3%
overriding royalty interests. Interest allocations since 1995 have
been 2%-5% of oil and gas sales less lease operating expenses and production
taxes.
Payments
of 100% of the year’s Plan interests to employees and the vested percentages of
former employees in the year’s Plan interests are made annually in cash after
year-end. Accrued compensation expense under the Plan for the six
months ended June 30, 2008 and 2007 amounted to $20.5 million and $5.9 million,
respectively, charged to general and administrative expense and $3.3 million and
$1.0 million, respectively, charged to exploration expense.
Employees
vest in the Plan ratably at 20% per year over a five year
period. Pursuant to the terms of the Plan, (1) employees who
terminate their employment with the Company are entitled to receive their vested
allocation of future Plan year payments on an annual basis; (2) employees will
become fully vested at age 62, regardless of when their interests would
otherwise vest; and (3) any forfeitures inure to the benefit of the
Company.
The
Company uses average historical prices to estimate the vested long-term
Production Participation Plan liability. At June 30, 2008, the
Company used three-year average historical NYMEX prices of $70.33 for crude oil
and $7.47 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 June 30, 2008, 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 $245.1 million. This amount includes
$58.6 million attributable to proved undeveloped oil and gas properties and
$23.8 million relating to the short-term portion of the Plan liability, which
has been accrued as a current payable to be paid in February
2009. 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 six months ended June 30, 2008 (in thousands):
|
Production
Participation Plan liability, January 1, 2008
|
$ | 34,042 | ||
|
Change
in liability for accretion, vesting and changes in
estimates
|
41,670 | |||
|
Reduction
in liability for cash payments accrued and recognized as compensation
expense
|
(23,823 | ) | ||
|
Production
Participation Plan liability, June 30, 2008
|
$ | 51,889 |
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).
|
Six
Months Ended
June
30,
|
||||||||
|
2008
|
2007
|
|||||||
|
General
and administrative expense
|
$ | 15,349 | $ | 3,528 | ||||
|
Exploration
expense
|
2,498 | 622 | ||||||
|
Total
|
$ | 17,847 | $ | 4,150 | ||||
401(k)
Plan—The Company has a defined contribution retirement plan for all
employees. The plan is funded by employee contributions and
discretionary Company contributions. Employees vest in employer
contributions at 20% per year of completed service.
|
9.
|
RELATED
PARTY TRANSACTIONS
|
Whiting USA Trust
I—As a result of
Whiting’s retained ownership of 15.8%, or 2,186,389 units in Whiting USA Trust I
during the second quarter of 2008, the Trust is a related party of the Company
as of June 30, 2008. The following table summarizes the related party
receivable and payable balances between the Company and the Trust as of June 30,
2008 and December 31, 2007 (in thousands):
|
June
30, 2008
|
December
31, 2007
|
|||||||
|
Assets
|
||||||||
|
Current
portion of derivative asset
|
$ | 8,491 | $ | - | ||||
|
Unit
distributions due from Trust
|
1,830 | - | ||||||
|
Non-current
derivative asset
|
28,709 | - | ||||||
|
Total
|
$ | 39,030 | $ | - | ||||
|
Liabilities
|
||||||||
|
Unit
distributions payable to Trust (1)
|
$ | 11,895 | $ | - | ||||
|
Total
|
$ | 11,895 | $ | - | ||||
_______________
|
(1)
|
This
amount primarily represents net proceeds from the Trust’s underlying
properties, that the Company has received between the last Trust
distribution date and June 30, 2008, but which the Company has not yet
distributed to the Trust as of June 30, 2008. Due to ongoing
processing of Trust revenues and expenses after June 30, 2008, the amount
of Whiting’s next scheduled distribution to the Trust, and the related
distribution by the Trust to its unit holders, will differ from this
amount.
|
For the
three and six months ended June 30, 2008, Whiting paid $14.7 million, net of
state tax withholdings, in unit distributions to the Trust and received $2.3
million in distributions back from the Trust pursuant to its retained ownership
in 2,186,389 Trust units.
Tax Sharing
Liability— Prior to Whiting’s initial public offering in November 2003,
it was a wholly-owned indirect subsidiary of Alliant Energy Corporation
(“Alliant Energy”), a holding company whose primary businesses are utility
companies. When the transactions discussed below were entered into,
Alliant Energy was a related party of the Company. As of December 31,
2004 and thereafter, Alliant Energy was no longer a related party.
In
connection with Whiting’s initial public offering in November 2003, the Company
entered into a Tax Separation and Indemnification Agreement with Alliant
Energy. Pursuant to this agreement, the Company and Alliant Energy
made a tax election with the effect that the tax bases of Whiting’s assets were
increased to the deemed purchase price 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 $34.7 million on an undiscounted
basis.
During
the first six months of 2008, the Company did not make any payments under this
agreement but did recognize $0.6 million of discount accretion, which is
included as a component of interest expense. The Company’s estimated
payment of $2.6 million to be made in 2008 under this agreement is
reflected as a current liability at June 30, 2008.
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.
Alliant Energy
Guarantee—The Company holds a 6% working interest in three offshore
platforms and related onshore plant and equipment in
California. Alliant Energy has guaranteed the Company’s obligation in
the abandonment of these assets.
|
10.
|
COMMITMENTS
AND CONTINGENCIES
|
Non-cancelable
Leases—The Company leases 107,400 square feet of administrative office
space in Denver, Colorado under an operating lease arrangement through October
31, 2013 and an additional 46,700 square feet of office space in Midland, Texas
through March 7, 2012. Rental expense for the first six months of
2008 and 2007 was $1.0 million and $1.1 million,
respectively. Minimum lease payments under the terms of
non-cancelable operating leases as of June 30, 2008 are as follows (in
thousands):
|
2008
|
$ | 1,125 | ||
|
2009
|
2,520 | |||
|
2010
|
2,677 | |||
|
2011
|
3,383 | |||
|
2012
|
2,931 | |||
|
Thereafter
|
2,383 | |||
|
Total
|
$ | 15,019 |
Purchase
Contracts—The Company has entered into two take-or-pay purchase
agreements, one agreement expiring in March 2014 and one agreement expiring in
December 2014, whereby the Company has committed to buy certain volumes of
CO2
for a fixed fee subject to annual escalation. The purchase agreements
are with different suppliers, and the CO2 is for use
in 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 June 30, 2008, future
commitments under the purchase agreements amounted to $324.8 million through
2014.
Drilling
Contracts—The
Company has one drilling rig under contract through 2008, five drilling rigs
through 2009, four drilling rigs through 2010, and a workover rig under contract
through 2009, all of which are operating in the Rocky Mountains
region. As of June 30, 2008, these agreements had total commitments
of $114.0 million and early termination would require maximum penalties of $54.7
million. Other drilling rigs working for the Company are not under
long-term contracts but instead are under contracts that can be terminated at
the end of the well that is currently being drilled.
Litigation—The
Company is subject to litigation, claims and governmental and regulatory
proceedings arising in the ordinary course of business. It is the
opinion of the Company’s management that all claims and litigation involving the
Company are not likely to have a material adverse effect on its consolidated
financial position, cash flows or results of operations.
|
11.
|
RECENTLY
ISSUED ACCOUNTING PRONOUNCEMENTS
|
In March
2008, the FASB issued Statement No. 161, Disclosure about Derivative
Instruments and Hedging Activities – an amendment to FASB Statement No.
133 (“SFAS 161”). The adoption of SFAS 161 is not expected to
have an impact on the Company’s consolidated financial statements, other than
additional disclosures. SFAS 161 expands interim and annual
disclosures about derivative and hedging activities that are intended to better
convey the purpose of derivative use and the risks managed. SFAS 161
is effective for fiscal years and interim periods beginning after November 15,
2008.
In
December 2007, the FASB issued Statement No. 160, Noncontrolling Interests in
Consolidated Financial Statements – an amendment of ARB No. 51 (“SFAS
160”). As Whiting currently does not have any minority interests, the
Company does not expect the adoption of SFAS 160 to have an impact on its
consolidated financial statements. This statement amends ARB No. 51
and intends to improve the relevance, comparability, and transparency of the
financial information that a reporting entity provides in its consolidated
financial statements by establishing accounting and reporting standards of the
portion of equity in a subsidiary not attributable, directly or indirectly, to a
parent. SFAS 160 is effective for fiscal years, and interim periods,
beginning on or after December 15, 2008.
In
December 2007, the FASB issued Statement No. 141R, Business Combinations (“SFAS
141R”). SFAS 141R may have an impact on the Company’s consolidated
financial statements when effective, but the nature and magnitude of the
specific effects will depend upon the nature, terms and size of the acquisitions
the Company consummates after the effective date. SFAS 141R
establishes principles and requirements for how the acquirer of a business
recognizes and measures in its financial statements the identifiable assets
acquired, the liabilities assumed, and any noncontrolling interest in the
acquiree. The statement also provides guidance for recognizing and
measuring the goodwill acquired in business combinations and determines what
information to disclose to enable users of the financial statement to evaluate
the nature and financial effects of the business combination. SFAS
141R is effective for financial statements issued for fiscal years beginning
after December 15, 2008.
|
Item 2.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
|
Unless
the context otherwise requires, the terms “Whiting,” “we,” “us,” “our” or “ours”
when used in this Item refer to Whiting Petroleum Corporation, together with its
consolidated subsidiaries, Whiting Oil and Gas Corporation, Equity Oil Company
and Whiting Programs, Inc. When the context requires, we refer to
these entities separately. This document contains forward-looking
statements, which give our current expectations or forecasts of future
events. Please refer to “Forward-Looking Statements” at the end of
this item for an explanation of these types of statements.
Overview
We are an
independent oil and gas company engaged in oil and gas acquisition, development,
exploitation, production and exploration activities primarily in the Permian
Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the
United States. Prior to 2006, we generally emphasized the acquisition
of properties that increased our current production levels and provided upside
potential through further development. Since 2006, we have focused
our drilling activity on the development of these acquired properties,
specifically on projects that we believe provide repeatable successes in
particular fields. Our combination of acquisitions and subsequent
development allows us to direct our capital resources to what we believe to be
the most advantageous investments.
As
demonstrated by our recent capital expenditures, we are increasingly focused on
a balanced exploration and development program while continuing to selectively
pursue acquisitions that complement our existing core properties. We
believe that our significant drilling inventory, combined with our operating
experience and cost structure, provides us with meaningful organic growth
opportunities. Our growth plan is centered on the following
activities:
|
•
|
pursuing
the development of projects that we believe will generate attractive rates
of return;
|
|
|
•
|
maintaining
a balanced portfolio of lower risk, long-lived oil and gas properties that
provide stable cash flows;
|
|
|
•
|
seeking
property acquisitions that complement our core
areas; and
|
|
|
•
|
allocating
an increasing percentage of our capital budget to leasing and testing new
areas.
|
We have
historically acquired operated and non-operated properties that exceed our rate
of return criteria. For acquisitions of properties with additional
development, exploitation and exploration potential, our focus has been on
acquiring operated properties so that we can better control the timing and
implementation of capital spending. In some instances, we have been
able to acquire non-operated property interests at attractive rates of return
that established a presence in a new area of interest or that have complemented
our existing operations. We intend to continue to acquire both
operated and non-operated interests to the extent we believe they meet our
return criteria. In addition, our willingness to acquire non-operated
properties in new geographic regions provides us with geophysical and geologic
data in some cases that leads to further acquisitions in the same region,
whether on an operated or non-operated basis. We sell properties when
we believe that the sales price realized will provide an above average rate of
return for the property or when the property no longer matches the profile of
properties we desire to own.
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 crude oil or natural gas could materially and
adversely affect our financial position, cash flows, results of operations,
access to capital, and the quantities of oil and gas reserves that we can
economically produce.
Second
Quarter 2008 Highlights and Future Considerations
On April
30, 2008, we completed an initial public offering of units of beneficial
interest in Whiting USA Trust I (the “Trust”), selling 11,677,500 Trust
units at $20.00 per Trust unit, and providing net proceeds of $215.1 million
after underwriters’ discount and commissions and offering related
expenses. Our net profits from the Trust’s underlying oil and gas
properties received between the effective date and the closing date of the Trust
unit sale were due to the Trust and thereby further reduced net proceeds to
$195.1 million. We used the offering net proceeds to reduce the debt
outstanding under our credit agreement. The aggregate proceeds from
the sale of Trust units to the public resulted in a deferred gain on sale of
$101.4 million. Immediately prior to the closing of the offering, we
conveyed a term net profits interest in certain of our oil and natural gas
properties to the Trust in exchange for 13,863,889 Trust units. We
have retained 15.8%, or 2,186,389 Trust units, of the total Trust units issued
and outstanding.
The net
profits interest entitles the Trust to receive 90% of the net proceeds from the
sale of oil and natural gas production from the underlying
properties. The net profits interest will terminate at the time when
9.11 MMBOE have been produced and sold from the underlying
properties. This is the equivalent of 8.2 MMBOE in respect of the
Trust’s right to receive 90% of the net proceeds from such production pursuant
to the net profits interest, and these reserve quantities are projected to be
produced by December 31, 2017, based on the reserve report for the underlying
properties as of December 31, 2007. The conveyance of the net profits
interest to the Trust consisted entirely of proved developed producing reserves
of 8.2 MMBOE, as of the January 1, 2008 effective date, representing 3.3%
of our proved reserves as of December 31, 2007, and 10.0%, or 4.2 MBOE/d,
of our March 2008 average daily net production. After netting our
ownership of 2,186,389 Trust units, third-party public Trust unit holders
receive 6.9 MMBOE of proved producing reserves, or 2.75% of our total year-end
2007 proved reserves, and 7.4%, or 3.1 MBOE/d, of our March 2008 average daily
net production.
On
May 30, 2008, we acquired interests in 31 producing gas wells, development
acreage and gas gathering and processing facilities on 22,029 gross acres
(11,533 net acres) in the Flat Rock field in Uintah County, Utah for an
aggregate acquisition price of $364.4 million. After allocating the purchase
price of $79.1 million to unproved property and $35.7 million to the gas
gathering and processing facilities, the remaining $256.8 million results in an
acquisition cost for the proved reserves of $2.23 per Mcfe. Of the estimated 115.2
Bcfe of proved reserves acquired as of the January 1, 2008 acquisition effective
date, 98% are natural gas, and 22% are proved developed
producing. The average daily net production from the properties was
18.1 MMcfe/d in June 2008. We funded the acquisition with borrowings
under our credit agreement.
Our
Sanish field in Mountrail County, North Dakota encompasses 118,571 gross acres
(83,310 net acres). June 2008 production averaged 3.4 MBOE/d, an
increase from 1.2 MBOE/d produced in March 2008. We are currently
drilling or completing seven operated wells in the Sanish field with an average
working interest of 82%. There are currently five rigs working in the
field and we expect to have nine rigs drilling in the area by year-end
2008. We have completed nine operated wells in the Sanish field in
2008 and expect to complete an additional 20 to 25 wells during the balance of
the year.
We
completed construction of the first phase of a natural gas processing plant that
will separate the natural gas liquids from the natural gas produced from Sanish
field and allow the natural gas to be transported by pipeline to
market. At the end of July 2008, we were selling approximately 170
Bbl/d of natural gas liquids. Upon installation of a gas pipeline in
August 2008, we expect gas sales from the Sanish field to be approximately 1.0
MMcf/d
Immediately
east of the Sanish field is the Parshall field, where we own interests in 72,790
gross acres (14,982 net acres). We have participated in the drilling
and completion of 48 wells that produce from the Bakken formation, 24 of which
were drilled in 2008. We expect to participate in the drilling of
approximately 60 to 70 wells in the Parshall field during 2008, with an average
working interest of 25%. At the end of July 2008, there were eight
rigs working in the Parshall field. Our net production from the
Parshall field averaged 5.0 MBOE/d in June 2008, up from 3.0 MBOE/d in March
2008.
Our Boies
Ranch and Jimmy Gulch properties in the Piceance Basin of Rio Blanco County,
Colorado, hold 16,893 gross acres (4,071 net acres). In the Piceance,
we have 13 wells that were producing at a combined average net daily rate of 6.1
MMcf of gas during June 2008. Whiting holds an average working
interest of 71%, and an average net revenue interest of 62% in the 13 gas
wells. In addition, two wells are being drilled and eight wells are
being completed or waiting on completion. Of these eight wells, we
expect five to be completed and producing into a sales line by the end of August
2008. We plan to drill a total of 110 wells in the Piceance, 24 of
which are planned for 2008.
We
recently completed a pipeline at our Boies Ranch prospect, and the newly
completed line connects to a supply trunk line, which in turn feeds a treating
and processing facility that is ultimately connected to the Rockies Express
pipeline (REX). REX gives us access to multiple intrastate and
interstate markets, and our new pipeline connection will allow us to market all
of our gas at Boies Ranch without restriction.
We
continue to have significant development and related infrastructure activity on
the Postle and North Ward Estes fields acquired in 2005, which have resulted in
reserve and production increases. During the first six months of
2008, we incurred $90.6 million of development expenditures on these two
projects.
Our
expansion of the CO2 flood at
the Postle field, located in Texas County, Oklahoma, continues to generate
positive results. Production from the field has increased from a net
4.2 MBOE/d at the time of its acquisition in August 2005 to a net 6.3 MBOE/d in
June 2008, an increase of 50%. This project is part of the Company’s
plan to expand the existing water and CO2 flood from
the eastern half of the Postle field to the western half of the
field.
In 2007,
we initiated our CO2 flood in
the North Ward Estes field, located in Ward and Winkler Counties,
Texas. Net production from North Ward Estes in June 2008 averaged 5.4
MBOE/d, up from 3.6 MBOE/d during the first quarter of 2005, which was just
prior to our July 2005 agreement to acquire the North Ward Estes
field.
Results
of Operations
Six
Months Ended June 30, 2008 Compared to Six Months Ended June 30,
2007
|
Selected
Operating Data:
|
Six
Months Ended
June
30,
|
|||||||
|
2008
|
2007
|
|||||||
|
Net
production:
|
||||||||
|
Oil
(MMbbls)
|
5.4 | 4.6 | ||||||
|
Natural
gas (Bcf)
|
14.2 | 15.8 | ||||||
|
Total
production (MMBOE)
|
7.8 | 7.3 | ||||||
|
Net
sales (in millions):
|
||||||||
|
Oil(1)
|
$ | 549.4 | $ | 247.4 | ||||
|
Natural
gas(1)
|
127.9 | 105.0 | ||||||
|
Total
oil and natural gas sales
|
$ | 677.3 | $ | 352.4 | ||||
|
Average
sales prices:
|
||||||||
|
Oil
(per Bbl)
|
$ | 101.88 | $ | 53.48 | ||||
|
Effect
of oil hedges on average price (per Bbl)
|
(13.17 | ) | - | |||||
|
Oil
net of hedging (per Bbl)
|
$ | 88.71 | $ | 53.48 | ||||
|
Average
NYMEX price
|
$ | 110.98 | $ | 61.59 | ||||
|
Natural
gas (per Mcf)
|
$ | 8.99 | $ | 6.65 | ||||
|
Effect
of natural gas hedges on average price (per Mcf)
|
- | - | ||||||
|
Natural
gas net of hedging (per Mcf)
|
$ | 8.99 | $ | 6.65 | ||||
|
Average
NYMEX price
|
$ | 9.49 | $ | 7.16 | ||||
|
Cost
and expense (per BOE):
|
||||||||
|
Lease
operating expenses
|
$ | 14.58 | $ | 13.92 | ||||
|
Production
taxes
|
$ | 5.63 | $ | 2.99 | ||||
|
Depreciation,
depletion and amortization expense
|
$ | 13.56 | $ | 12.94 | ||||
|
General
and administrative expenses
|
$ | 4.46 | $ | 2.36 | ||||
(1) Before
consideration of hedging transactions.
Oil and Natural Gas
Sales. Our oil and natural gas sales revenue increased $324.9
million to $677.3 million in the first six months of 2008 compared to the same
period in 2007. Sales are a function of volumes sold and average
sales prices. Our oil sales volumes increased 17% between periods,
while our gas sales volumes decreased 10%. The oil volume increase
resulted primarily from drilling success in the North Dakota Bakken area, in
addition to increased production at our two large CO2 projects,
Postle and North Ward Estes. Oil production from the Bakken increased
825 MBOE compared to the first six months of 2007, while Postle oil production
increased 270 MBOE and North Ward Estes oil production increased 165 MBOE over
the same period in 2007. These production increases were partially
offset by the Whiting USA Trust I (the “Trust”) divestiture, which decreased oil
production by 375 MBOE. The gas volume decline between periods was
primarily the result of the Trust divestiture, which decreased gas production by
1,710 MMcf, and property dispositions in the second half of 2007, which
decreased gas production by 700 MMcf. These decreases were partially
offset by gas production increases from the Flat Rock acquisition of 560 MMcf
and in the Boies Ranch area of 320 MMcf. Our average price for oil
before effects of hedging increased 91% between periods, and our average price
for natural gas before effects of hedging increased 35%.
Loss on Oil Hedging
Activities. We hedged 37% of our oil volumes during the first
six months of 2008, incurring cash settlement losses of $71.0 million, and 56%
of our oil volumes during the first six months of 2007, incurring no realized
hedging gains or losses. We hedged 1% of our gas volumes during the
first six months of 2008, incurring no cash settlement gains or losses, and 30%
of our gas volumes during the first six months of 2007, incurring no realized
hedging gains or losses. See Item 3, “Qualitative and Quantitative
Disclosures About Market Risk” for a list of our outstanding oil and natural gas
hedges as of July 1, 2008.
Amortization of Deferred Gain on
Sale. On April 30, 2008, in connection with the sale of 11,677,500
Trust units to the public and related oil and gas property conveyance, we
recognized a deferred gain on sale of $101.4 million. This deferred gain
is amortized over the life of the Trust on a unit-of-production
basis. For the six months ended June 30, 2008, we recognized $3.0
million in income as amortization of deferred gain on sale.
Lease Operating
Expenses. Our lease operating expenses during the first six
months of 2008 were $113.2 million, a $12.1 million (12%) increase over the same
period in 2007. Our lease operating expenses per BOE increased from
$13.92 during the first six months of 2007 to $14.58 during the first six months
of 2008. The increase of 5% on a BOE basis was primarily caused by
inflation in the cost of oil field goods and services and a high level of
workover activity, partially offset by flush production from Bakken
drilling. The cost of oil field goods and services increased due to
higher demand in the industry. Workovers amounted to
$8.4 million in the first six months of 2008, as compared to
$6.5 million in the first six months of 2007.
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 our various taxing jurisdictions. Our production taxes for the
first six months of 2008 and 2007 were 6.5% and 6.2%, respectively, of oil and
gas sales. Our production tax rate for the first six months of 2008
was greater than the rate for same period in 2007 due to the change in property
mix associated with recent divestitures in low tax rate jurisdictions and
drilling successes in higher tax rate jurisdictions.
Depreciation, Depletion and
Amortization. Depreciation, depletion and amortization expense
(“DD&A”) increased $11.4 million to $105.3 million during the
first six months of 2008, as compared to $93.9 million for the same period in
2007. On a BOE basis, our DD&A rate increased from $12.94 for the
first six months of 2007 to $13.56 for the first six months of
2008. The primary factors causing this rate increase were higher
drilling expenditures 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. The
components of our DD&A expense were as follows (in thousands):
|
Six
Months Ended
June
30,
|
||||||||
|
2008
|
2007
|
|||||||
|
Depletion
|
$ | 102,251 | $ | 91,049 | ||||
|
Depreciation
|
1,594 | 1,503 | ||||||
|
Accretion
of asset retirement obligations
|
1,477 | 1,354 | ||||||
|
Total
|
$ | 105,322 | $ | 93,906 | ||||
Exploration and Impairment
Costs. Our exploration and impairment costs increased $3.8
million, as compared to the first six months of 2007. The components
of exploration and impairment costs were as follows (in thousands):
|
Six
Months Ended
June
30,
|
||||||||
|
2008
|
2007
|
|||||||
|
Exploration
|
$ | 14,227 | $ | 11,178 | ||||
|
Impairment
|
5,400 | 4,642 | ||||||
|
Total
|
$ | 19,627 | $ | 15,820 | ||||
During
the first six months of 2008 and 2007, we did not drill any exploratory dry
holes. Exploration costs increased $3.0 million during the first six
months of 2008 as compared to the same period in 2007 primarily due
to higher accrued Production Participation Plan payments of $2.3
million for exploration personnel and additional geological and geophysical
personnel hired during the past twelve months. The impairment charge
in the first six months of 2008 and 2007 is related to the amortization of
leasehold costs associated with individually insignificant unproved
properties. As of June 30, 2008, the amount of unproved properties
being amortized totaled $72.8 million, as compared to $49.3 million as of June
30, 2007.
General and Administrative
Expenses. We report general and administrative expenses net of
third party reimbursements and internal allocations. The components
of our general and administrative expenses were as follows (in
thousands):
|
Six
Months Ended
June
30,
|
|||||||||
|
2008
|
2007
|
||||||||
|
General
and administrative expenses
|
$ | 54,314 | $ | 32,998 | |||||
|
Reimbursements
and allocations
|
(19,692 | ) | (15,837 | ) | |||||
|
General
and administrative expense, net
|
$ | 34,622 | $ | 17,161 | |||||
General
and administrative expense before reimbursements and allocations increased $21.3
million to $54.3 million during the first six months of 2008. The
largest components of the increase related to $16.9 million in higher accrued
distributions under our Production Participation Plan between periods, resulting
from increased oil and gas sales less lease operating expense and production
taxes, and $4.5 million of additional employee compensation for personnel hired
during the past twelve months and general pay increases. The increase
in reimbursements and allocations in 2008 was caused by higher salary expenses
and a greater number of field workers on operated properties. Our
general and administrative expenses as a percentage of oil and gas sales
remained constant at 5% for the first six months of 2008 and 2007.
Change in Production Participation
Plan Liability. For the six months ended June 30, 2008,
this non-cash expense increased $13.7 million as compared to the same period in
2007. This expense represents the change in the vested present value
of estimated future payments to be made to participants after 2009 under our
Production Participation Plan (“Plan”). Although payments take place
over the life of the Plan’s oil and gas properties, which for some properties is
over 20 years, we must expense the present value of estimated future payments
over the Plan’s five year vesting period. This expense in 2008 and
2007 primarily reflects i) changes to future cash flow estimates stemming from a
sustained higher commodity price environment, ii) recent drilling activity, and
iii) employees’ continued vesting in the Plan. Due to the recent
higher commodity price environment, during the six months ended June 30, 2008 we
moved from using a five-year average of historical NYMEX prices to a three-year
average when estimating the future payments to be made pursuant to this
liability. This change to a three-year historical NYMEX average
increased the prices used to estimate this liability by $15.51 for crude oil and
$0.74 for natural gas for the six months ended June 30, 2008, as compared to
increases of $3.77 for crude oil and $0.38 for natural gas over the same period
in 2007. 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):
|
Six
Months Ended
June
30,
|
||||||||
|
2008
|
2007
|
|||||||
|
Credit
Agreement
|
$ | 7,652 | $ | 15,440 | ||||
|
Senior
Subordinated Notes
|
21,943 | 22,373 | ||||||
|
Amortization
of debt issue costs and debt discount
|
2,423 | 2,542 | ||||||
|
Accretion
of tax sharing liability
|
623 | 761 | ||||||
|
Other
|
110 | 200 | ||||||
|
Capitalized
interest
|
(1,534 | ) | (1,063 | ) | ||||
|
Total
interest expense
|
$ | 31,217 | $ | 40,253 | ||||
The
decrease in interest expense was mainly due to reduced borrowings outstanding
under our credit agreement in 2008 and increased capitalized interest related to
construction and expansion of processing facilities. We also
experienced lower effective interest rates on our debt during the first six
months of 2008.
Our
weighted average debt outstanding during the first six months of 2008 was $929.2
million versus $1,060.8 million for the first six months of 2007. Our
weighted average effective cash interest rate was 6.4% during the first six
months of 2008 versus 7.2% during the first six months of 2007. 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 6.9% during the first six
months of 2008 versus 7.6% during the first six months of 2007.
Loss (Gain) on Mark-to-Market
Derivatives. During the first half of 2008, we entered into
derivative contracts that we did not designate as cash flow
hedges. Accordingly, these derivative contracts are marked-to-market
each quarter with fair value gains and losses, both realized and unrealized,
recognized immediately in earnings. Cash flow is only impacted to the
extent the actual cash settlements under the contracts result in making or
receiving a payment from the counterparty. As a result of significant
increases in oil prices, we recognized $17.6 million in unrealized
mark-to-market derivative losses for the first six months of
2008. 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 $0.7 million
in unrealized mark-to-market derivative losses during the first six months of
2007.
Income Tax
Expense. Income tax expense totaled $83.9 million for the
first six months of 2008 and $21.0 million for the first six months of
2007. Our effective income tax rate increased from 36.1% for the
first six months 2007 to 37.0% for the first six months of 2008. Our
effective income tax rate was higher for 2008 primarily due to a decrease in
estimated deductions for statutory depletion.
Net Income. Net
income increased from $37.1 million during the first six months of 2007 to
$142.8 million during the first six months of 2008. The primary
reasons for this increase include a 7% increase in equivalent volumes sold, a
66% increase in oil prices (net of hedging) and a 35% increase in gas prices
between periods, amortization of deferred gain on sale, and lower interest
expense. The increased production and pricing, deferred gain income,
and decreased interest expense were partially offset by higher lease operating
expenses, production taxes, DD&A, exploration and impairment, general and
administrative expenses, production participation plan expense and unrealized
derivative losses during the first six months of 2008.
Three
Months Ended June 30, 2008 Compared to Three Months Ended June 30,
2007
|
Selected
Operating Data:
|
Three
Months Ended
June
30,
|
|||||||
|
2008
|
2007
|
|||||||
|
Net
production:
|
||||||||
|
Oil
(MMbbls)
|
2.8 | 2.4 | ||||||
|
Natural
gas (Bcf)
|
7.3 | 8.1 | ||||||
|
Total
production (MMBOE)
|
4.0 | 3.7 | ||||||
|
Net
sales (in millions):
|
||||||||
|
Oil(1)
|
$ | 316.9 | $ | 136.6 | ||||
|
Natural
gas(1)
|
73.6 | 56.0 | ||||||
|
Total
oil and natural gas sales
|
$ | 390.5 | $ | 192.6 | ||||
|
Average
sales prices:
|
||||||||
|
Oil
(per Bbl)
|
$ | 113.28 | $ | 57.38 | ||||
|
Effect
of oil hedges on average price (per Bbl)
|
(17.19 | ) | - | |||||
|
Oil
net of hedging (per Bbl)
|
$ | 96.09 | $ | 57.38 | ||||
|
Average
NYMEX price
|
$ | 124.00 | $ | 65.02 | ||||
|
Natural
gas (per Mcf)
|
$ | 10.02 | $ | 6.95 | ||||
|
Effect
of natural gas hedges on average price (per Mcf)
|
- | - | ||||||
|
Natural
gas net of hedging (per Mcf)
|
$ | 10.02 | $ | 6.95 | ||||
|
Average
NYMEX price
|
$ | 10.94 | $ | 7.55 | ||||
|
Cost
and expense (per BOE):
|
||||||||
|
Lease
operating expenses
|
$ | 14.29 | $ | 13.96 | ||||
|
Production
taxes
|
$ | 6.48 | $ | 3.24 | ||||
|
Depreciation,
depletion and amortization expense
|
$ | 13.63 | $ | 13.25 | ||||
|
General
and administrative expenses
|
$ | 5.72 | $ | 2.38 | ||||
(1) Before
consideration of hedging transactions.
Oil and Natural Gas
Sales. Our oil and natural gas sales revenue increased $197.9
million to $390.5 million in the second quarter of 2008 compared to the second
quarter of 2007. Sales are a function of volumes sold and average
sales prices. Our oil sales volumes increased 18% between periods,
while our gas sales volumes decreased 9%. The oil volume increase
resulted primarily from drilling success in the North Dakota Bakken area, in
addition to increased production at our two large CO2 projects,
Postle and North Ward Estes. Oil production from the Bakken increased
525 MBOE compared to the second quarter of 2007, while Postle oil production
increased 95 MBOE and North Ward Estes oil production increased 115 MBOE over
the same period in 2007. These production increases were partially
offset by the Trust divestiture, which decreased oil production by 190
MBOE. The gas volume decline between periods was primarily the result
of the Trust divestiture, which decreased gas production by 855 MMcf, and
property dispositions in the second half of 2007, which decreased gas production
by 345 MMcf. These decreases were partially offset by gas production
increases from the Flat Rock acquisition of 560 MMcf and in the Boies Ranch area
of 235 MMcf. Our average price for oil before effects of hedging
increased 97% between periods, and our average price for natural gas before
effects of hedging increased 44%.
Loss on Oil Hedging
Activities. We hedged 37% of our oil volumes during the second
quarter of 2008, incurring cash settlement losses of $48.1 million, and 52% of
our oil volumes during the second quarter of 2007, incurring no realized hedging
gains or losses. We hedged 2% of our gas volumes during the second
quarter of 2008, incurring no cash settlement gains or losses, and we did not
hedge any of our gas volumes during the second quarter of 2007. See
Item 3, “Qualitative and Quantitative Disclosures About Market Risk” for a list
of our outstanding oil and natural gas hedges as of July 1, 2008.
Amortization of Deferred Gain on
Sale. On April 30, 2008, in connection with the sale of 11,677,500
Trust units to the public and related oil and gas property conveyance, we
recognized a deferred gain on sale of $101.4 million. This deferred gain
is amortized over the life of the Trust on a unit-of-production
basis. For the three months ended June 30, 2008, we recognized $3.0
million in income as amortization of deferred gain on sale.
Lease Operating
Expenses. Our lease operating expenses during the second
quarter of 2008 were $57.5 million, a $5.5 million (11%) increase over the
second quarter of 2007. Our lease operating expenses per BOE
increased from $13.96 during the second quarter of 2007 to $14.29 during the
second quarter of 2008. The increase of 2% on a BOE basis was
primarily caused by inflation in the cost of oil field goods and services and a
high level of workover activity, partially offset by flush production from
Bakken drilling. The cost of oil field goods and services increased
due to higher demand in the industry. Workovers amounted to
$4.5 million in the second quarter of 2008, as compared to
$3.6 million in the second quarter of 2007.
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 our various taxing jurisdictions. Our production taxes for the
second quarter of 2008 and 2007 were 6.7% and 6.3%, respectively, of oil and gas
sales. Our production tax rate for the second quarter of 2008 was
greater than the rate for same period in 2007 due to the change in property mix
associated with recent divestitures in low tax rate jurisdictions and drilling
successes in higher tax rate jurisdictions.
Depreciation, Depletion and
Amortization. Depreciation, depletion and amortization expense
(“DD&A”) increased $5.5 million to $54.8 million during the second
quarter of 2008, as compared to $49.3 million for the same period in
2007. On a BOE basis, our DD&A rate increased from $13.25 for the
second quarter of 2007 to $13.63 for the second quarter of 2008. The
primary factors causing this rate increase were higher drilling expenditures 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. The components of our DD&A
expense were as follows (in thousands):
|
Three
Months Ended
June
30,
|
||||||||
|
2008
|
2007
|
|||||||
|
Depletion
|
$ | 53,207 | $ | 47,825 | ||||
|
Depreciation
|
843 | 763 | ||||||
|
Accretion
of asset retirement obligations
|
761 | 747 | ||||||
|
Total
|
$ | 54,811 | $ | 49,335 | ||||
Exploration and Impairment
Costs. Our exploration and impairment costs increased $2.0
million, as compared to the second quarter of 2007. The components of
exploration and impairment costs were as follows (in thousands):
|
Three
Months Ended
June
30,
|
||||||||
|
2008
|
2007
|
|||||||
|
Exploration
|
$ | 5,815 | $ | 4,318 | ||||
|
Impairment
|
2,828 | 2,325 | ||||||
|
Total
|
$ | 8,643 | $ | 6,643 | ||||
During
the second quarter of 2008 and 2007, we did not drill any exploratory dry
holes. Exploration costs increased $1.5 million for the second
quarter of 2008 as compared to the same period in 2007 primarily due to higher
accrued Production Participation Plan payments of $1.8 million
for exploration personnel and additional geological and geophysical
personnel hired during the past twelve months, partially offset by a $0.9
million decrease in geological and geophysical expense. The
impairment charge in the second quarter of 2008 and 2007 is related to the
amortization of leasehold costs associated with individually insignificant
unproved properties. As of June 30, 2008, the amount of unproved
properties being amortized totaled $72.8 million, as compared to $49.3 million
as of June 30, 2007.
General and Administrative
Expenses. We report general and administrative expenses net of
third party reimbursements and internal allocations. The components
of our general and administrative expenses were as follows (in
thousands):
|
Three
Months Ended
June
30,
|
|||||||||
|
2008
|
2007
|
||||||||
|
General
and administrative expenses
|
$ | 33,203 | $ | 17,155 | |||||
|
Reimbursements
and allocations
|
(10,196 | ) | (8,279 | ) | |||||
|
General
and administrative expense, net
|
$ | 23,007 | $ | 8,876 | |||||
General
and administrative expense before reimbursements and allocations increased $16.0
million to $33.2 million during the second quarter of 2008. The
largest components of the increase related to $13.6 million in higher accrued
distributions under our Production Participation Plan between periods, resulting
from increased oil and gas sales less lease operating expense and production
taxes, and $2.6 million of additional employee compensation for personnel hired
during the past twelve months and general pay increases. The increase
in reimbursements and allocations in 2008 was caused by higher salary expenses
and a greater number of field workers on operated properties. Our
general and administrative expenses as a percentage of oil and gas sales
increased from 5% for the second quarter of 2007 to 6% for the second quarter of
2008.
Change in Production Participation
Plan Liability. For the three months ended June 30, 2008,
this non-cash expense increased $9.6 million to $11.7 million, as compared to
the same period in 2007. This expense represents the change in the
vested present value of estimated future payments to be made to participants
after 2009 under our Production Participation Plan (“Plan”). Although
payments take place over the life of the Plan’s oil and gas properties, which
for some properties is over 20 years, we must expense the present value of
estimated future payments over the Plan’s five year vesting
period. This expense in 2008 and 2007 primarily reflects i) changes
to future cash flow estimates stemming from a sustained higher commodity price
environment, ii) recent drilling activity, and iii) employees’ continued vesting
in the Plan. Due to the recent higher commodity price environment,
during the three months ended June 30, 2008 we moved from using a five-year
average of historical NYMEX prices to a three-year average when estimating the
future payments to be made pursuant to this liability. This change to
a three-year historical NYMEX average increased the prices used to estimate this
liability by $12.28 for crude oil and $0.55 for natural gas for the three months
ended June 30, 2007, as compared to increases of $1.72 for crude oil and $0.08
for natural gas over the same period in 2007. 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
June
30,
|
||||||||
|
2008
|
2007
|
|||||||
|
Credit
Agreement
|
$ | 3,735 | $ | 8,417 | ||||
|
Senior
Subordinated Notes
|
10,863 | 11,192 | ||||||
|
Amortization
of debt issue costs and debt discount
|
1,206 | 1,265 | ||||||
|
Accretion
of tax sharing liability
|
311 | 381 | ||||||
|
Other
|
68 | 100 | ||||||
|
Capitalized
interest
|
(512 | ) | (601 | ) | ||||
|
Total
interest expense
|
$ | 15,671 | $ | 20,754 | ||||
The
decrease in interest expense was mainly due to reduced borrowings outstanding
under our credit agreement in 2008. We also experienced lower
effective interest rates on our debt during the second quarter of
2008.
Our
weighted average debt outstanding during the second quarter of 2008 was $956.7
million versus $1,091.3 million for the second quarter of 2007. Our
weighted average effective cash interest rate was 6.1% during the second quarter
of 2008 versus 7.2% during the second quarter of 2007. 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 6.6% during the second
quarter of 2008 versus 7.6% during the second quarter of 2007.
Loss (Gain) on Mark-to-Market
Derivatives. During the first half of 2008, we entered into
derivative contracts that we did not designate as cash flow
hedges. Accordingly, these derivative contracts are marked-to-market
each quarter with fair value gains and losses, both realized and unrealized,
recognized immediately in earnings. Cash flow is only impacted to the
extent the actual cash settlements under the contracts result in making or
receiving a payment from the counterparty. As a result of significant
increases in oil prices, we recognized $20.6 million in unrealized
mark-to-market derivative losses in the second quarter of
2008. 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. Therefore, we discontinued hedge accounting prospectively
for these collars and recognized $0.4 million in unrealized mark-to-market
derivative gains during the second quarter of 2007.
Income Tax
Expense. Income tax expense totaled $47.4 million for the
second quarter of 2008 and $15.1 million for the second quarter of
2007. Our effective income tax rate increased from 36.4% for the
second quarter 2007 to 37.1% for the second quarter of 2008. Our
effective income tax rate was higher for 2008 primarily due to a decrease in
estimated deductions for statutory depletion.
Net Income. Net
income increased from $26.5 million during the second quarter of 2007 to $80.4
million during the second quarter of 2008. The primary reasons for
this increase include an 8% increase in equivalent volumes sold, a 67% increase
in oil prices (net of hedging) and a 44% increase in gas prices between periods,
amortization of deferred gain on sale, and lower interest
expense. The increased production and pricing, deferred gain income,
and decreased interest expense were partially offset by higher lease operating
expenses, production taxes, DD&A, exploration and impairment, general and
administrative expenses, production participation plan expense and unrealized
derivative losses during the second quarter of 2008.
Liquidity
and Capital Resources
Overview. At June
30, 2008, our debt to total capitalization ratio was 41.1%, we had $25.2 million
of cash on hand and $1,600.1 million of stockholders’ equity. At
December 31, 2007, our debt to total capitalization ratio was 36.8%, we had
$14.8 million of cash on hand and $1,490.8 million of stockholders’
equity. In the first half of 2008, we generated $329.1 million of
cash provided by operating activities, an increase of $179.1 million over the
same period in 2007. Cash provided by operating activities increased
primarily because of higher oil volumes produced in 2008 and higher average
sales prices for both crude oil and natural gas. We also generated
$250.0 million from financing activities consisting entirely of net borrowings
against our credit agreement. Cash flows from operating and financing
activities, as well as $195.1 million in net proceeds from the sale of Trust
units, were used to finance $390.6 million of exploration and development
expenditures paid in the first half of 2008 and $388.5 million of cash
acquisition capital expenditures. The following chart details our
exploration and development expenditures incurred by region during the first
half of 2008 (in thousands):
|
Drilling
and Development Expenditures
|
Exploration
Expenditures
|
Total
Expenditures
|
%
of Total
|
|||||||||||||
|
Rocky
Mountains
|
$ | 185,957 | $ | 3,173 | $ | 189,130 | 46 | % | ||||||||
|
Permian
Basin
|
129,564 | 3,781 | 133,345 | 33 | % | |||||||||||
|
Mid-Continent
|
52,659 | 1,257 | 53,916 | 13 | % | |||||||||||
|
Gulf
Coast
|
19,363 | 267 | 19,630 | 5 | % | |||||||||||
|
Michigan
|
8,522 | 5,749 | 14,271 | 3 | % | |||||||||||
|
Total incurred
|
396,065 | 14,227 | 410,292 | 100 | % | |||||||||||
|
Increase
in accrued capital expenditures
|
(19,655 | ) | - | (19,655 | ) | |||||||||||
|
Total paid
|
$ | 376,410 | $ | 14,227 | $ | 390,637 | ||||||||||
We
continually evaluate our capital needs and compare them to our capital
resources. Our current 2008 budgeted capital expenditures for the
further development of our property base are $850.0 million, an increase from
the $556.6 million incurred on exploration and development expenditures
during 2007. We have increased our budget for exploration and
development in 2008 from $765.0 million to $850.0 million, due primarily to
additional exploration and development activities across our regions. In the
first half of 2008, we spent $13.7 million on tubulars and $374.8 million on oil
and gas property acquisitions, including the Flat Rock acquisition of $364.4
million which was primarily funded by borrowings under Whiting Oil and Gas
Corporation’s (“Whiting Oil and Gas”) credit agreement. Although we
have no specific budget for property acquisitions in 2008, we will continue to
selectively pursue property acquisitions that complement our existing core
property base. We expect to fund our 2008 exploration and development
expenditures from internally generated cash flow, cash on hand, and borrowings
under our credit agreement. We believe that should attractive
acquisition opportunities arise or exploration and development expenditures
exceed $850.0 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 exploration and
development expenditures is largely discretionary, and the amount of funds
devoted to any particular activity may increase or decrease significantly
depending on available opportunities, commodity prices, cash flows and
development results, among other factors.
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 June 30, 2008, had a borrowing base of $900.0
million with $500.0 million in borrowings outstanding, leaving $400.0
million of available borrowing capacity. The borrowing base under the
credit agreement is determined at the discretion of our 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 term of the
credit agreement, borrow, repay and re-borrow 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 ours in an aggregate amount not to exceed
$50.0 million. As of June 30, 2008, letters of credit totaling
$0.2 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. We have 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 June 30, 2008, the effective
weighted average interest rate on the outstanding principal balance under the
credit agreement was 3.8%.
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 ratio (as defined in the credit agreement) of less
than 3.5 to 1 and a working capital ratio (as defined in the credit agreement,
which includes an add back of the available borrowing capacity under the credit
facility) of greater than 1 to 1. Except for limited exceptions,
including the payment of interest on the senior notes, the credit agreement
restricts the ability of Whiting Oil and Gas and 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 June 30, 2008. 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 the 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 at par
$250.0 million of 7% Senior Subordinated Notes due 2014.
In
April 2005, we issued $220.0 million of 7.25% Senior Subordinated Notes due
2013. These notes were issued at 98.507% of par, and the associated
discount is being amortized to interest expense over the term of these
notes.
In
May 2004, we issued $150.0 million of 7.25% Senior Subordinated Notes
due 2012. These notes were issued at 99.26% of par, and the
associated discount is being amortized to interest expense over the term of
these notes.
The notes
are unsecured obligations of ours and are subordinated to all of our senior
debt, which currently consists of Whiting Oil and Gas’ credit
agreement. The indentures governing the notes 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. We were in compliance with these
covenants as of June 30, 2008. Our wholly-owned operating
subsidiaries, Whiting Oil and Gas Corporation, Whiting Programs, Inc. and Equity
Oil Company, have fully, unconditionally, jointly and severally guaranteed our
obligations under the notes.
Shelf Registration
Statement. We have on file with the SEC a universal shelf
registration statement to allow us to offer an indeterminate amount of
securities in the future. Under the registration statement, we may
periodically offer from time to time debt securities, common stock, preferred
stock, warrants and other securities or any combination of such securities in
amounts, prices and on terms announced when and if the securities are
offered. The specifics of any future offerings, along with the use of
proceeds of any securities offered, will be described in detail in a prospectus
supplement at the time of any such offering.
Schedule of Contractual
Obligations. The table below does not include our Production
Participation Plan liabilities since we cannot determine with accuracy the
timing or amounts of future payments. The following table summarizes
our obligations and commitments as of June 30, 2008 to make future payments
under certain contracts, aggregated by category of contractual obligation, for
specified time periods (in thousands):
|
Payments
due by period
|
||||||||||||||||||||
|
Contractual
Obligations
|
Total
|
Less
than 1 year
|
1-3
years
|
3-5
years
|
More
than 5 years
|
|||||||||||||||
|
Long-term
debt (a)
|
$ | 1,120,000 | $ | - | $ | 500,000 | $ | 370,000 | $ | 250,000 | ||||||||||
|
Cash
interest expense on debt (b)
|
266,014 | 61,870 | 107,920 | 72,891 | 23,333 | |||||||||||||||
|
Asset
retirement obligation (c)
|
42,464 | 1,398 | 623 | 3,499 | 36,944 | |||||||||||||||
|
Tax
sharing liability (d)
|
26,280 | 2,587 | 4,408 | 3,699 | 15,586 | |||||||||||||||
|
Derivative
contract liability fair value (e)
|
177,139 | 139,268 | 24,262 | 13,609 | - | |||||||||||||||
|
Purchasing
obligations (f)
|
324,819 | 57,380 | 125,239 | 108,304 | 33,896 | |||||||||||||||
|
Drilling
rig contracts (g)
|
114,041 | 63,229 | 50,812 | - | - | |||||||||||||||
|
Operating
leases (h)
|
15,019 | 2,383 | 5,624 | 6,059 | 953 | |||||||||||||||
|
Total
|
$ | 2,085,776 | $ | 328,115 | $ | 818,888 | $ | 578,061 | $ | 360,712 | ||||||||||
________________
|
(a)
|
Long-term
debt consists of the 7.25% Senior Subordinated Notes due 2012 and 2013,
the 7% Senior Subordinated Notes due 2014 and the outstanding borrowings
under our credit agreement, and assumes no principal repayment until the
due date of the instruments.
|
|
(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 5.3% 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 is estimated at a fixed interest rate of
3.8%.
|
|
(c)
|
Asset
retirement obligations represent the present value of estimated amounts
expected to be incurred in the future to plug and abandon oil and gas
wells, remediate oil and gas properties and dismantle their related
facilities.
|
|
(d)
|
Amounts
shown represent the present value of estimated payments due to Alliant
Energy based on projected future income tax benefits attributable to an
increase in our tax bases. As a result of the Tax Separation
and Indemnification Agreement signed with Alliant Energy, the increased
tax bases are expected to result in increased future income tax deductions
and, accordingly, may reduce income taxes otherwise payable by
us. Under this agreement, we have agreed to pay Alliant Energy
90% of the future tax benefits we realize annually as a result of this
step up in tax basis for the years ending on or prior to December 31,
2013. In 2014, we will be obligated to pay Alliant Energy the
present value of the remaining tax benefits assuming all such tax benefits
will be realized in future years.
|
|
(e)
|
We
have entered into derivative contracts in the form of costless collars to
hedge our exposure to crude oil and natural gas price
fluctuations. As of June 30, 2008, 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
have two take-or-pay purchase agreements, one agreement expiring in March
2014 and one agreement expiring in December 2014, whereby we have
committed to buy certain volumes of CO2 for
a fixed fee, subject to annual escalation, for use in enhanced recovery
projects in our Postle field in Oklahoma and our North Ward Estes field in
Texas. The purchase agreements are with different
suppliers. Under the terms of the agreements, we are obligated
to purchase a minimum daily volume of CO2 (as
calculated on an annual basis) or else pay for any deficiencies at the
price in effect when the minimum delivery was to have
occurred. The CO2
volumes planned for use on the enhanced recovery projects in the Postle
and North Ward Estes fields currently exceed the minimum daily volumes
provided in these take-or-pay purchase agreements. Therefore,
we expect to avoid any payments for
deficiencies.
|
|
(g)
|
We
currently have one drilling rig under contract through 2008, five drilling
rigs through 2009, four drilling rigs through 2010, and a workover rig
under contract through 2009, all of which are operating in the Rocky
Mountains region. As of June 30, 2008, early termination of
these contracts would have required maximum penalties of $54.7
million. No other drilling rigs working for us are currently
under long-term contracts or contracts that cannot be terminated at the
end of the well that is currently being drilled. Due to the
short-term and indeterminate nature of the drilling time remaining on rigs
drilling on a well-by-well basis, such obligations have not been included
in this table.
|
|
(h)
|
We
lease 107,400 square feet of administrative office space in Denver,
Colorado under an operating lease arrangement through October 31,
2013, and an additional 46,700 square feet of office space in Midland,
Texas through March 7, 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.
New
Accounting Pronouncements
In March
2008, the FASB issued Statement No. 161, Disclosure about Derivative
Instruments and Hedging Activities – an amendment to FASB Statement No.
133 (“SFAS 161”). The adoption of SFAS 161 is not expected to
have an impact on our consolidated financial statements, other than additional
disclosures. SFAS 161 expands interim and annual disclosures about
derivative and hedging activities that are intended to better convey the purpose
of derivative use and the risks managed. SFAS 161 is effective for
fiscal years and interim periods beginning after November 15, 2008.
In
December 2007, the FASB issued Statement No. 160, Noncontrolling Interests in
Consolidated Financial Statements – an amendment of ARB No. 51 (“SFAS
160”). As we currently do not have any minority interests, we do not
expect the adoption of SFAS 160 to have an impact on our consolidated financial
statements. This statement amends ARB No. 51 and intends to improve
the relevance, comparability, and transparency of the financial information that
a reporting entity provides in its consolidated financial statements by
establishing accounting and reporting standards of the portion of equity in a
subsidiary not attributable, directly or indirectly, to a
parent. SFAS 160 is effective for fiscal years, and interim periods,
beginning on or after December 15, 2008.
In
December 2007, the FASB issued Statement No. 141R, Business Combinations (“SFAS
141R”). SFAS 141R may have an impact on our consolidated financial
statements when effective, but the nature and magnitude of the specific effects
will depend upon the nature, terms and size of the acquisitions we consummate
after the effective date. SFAS 141R establishes principles and
requirements for how the acquirer of a business recognizes and measures in its
financial statements the identifiable assets acquired, the liabilities assumed,
and any noncontrolling interest in the acquiree. The statement also
provides guidance for recognizing and measuring the goodwill acquired in
business combinations and determines what information to disclose to enable
users of the financial statement to evaluate the nature and financial effects of
the business combination. SFAS 141R is effective for financial
statements issued for fiscal years beginning after December 15,
2008.
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,
2007.
Effects
of Inflation and Pricing
We
experienced increased costs during 2007 and the first half of 2008 due to
increased demand for oil field products and services. The oil and gas
industry is very cyclical and the demand for goods and services of oil field
companies, suppliers and others associated with the industry put extreme
pressure on the economic stability and pricing structure within the
industry. Typically, as prices for oil and 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.
Forward-Looking
Statements
This
report contains statements that we believe to be “forward-looking statements”
within the meaning of the Private Securities Litigation Reform Act of
1995. All statements other than historical facts, including, without
limitation, statements regarding our future financial position, business
strategy, projected revenues, earnings, costs, capital expenditures and debt
levels, and plans and objectives of management for future operations, are
forward-looking statements. When used in this report, words such as
we “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe” or “should”
or the negative thereof or variations thereon or similar terminology are
generally intended to identify forward-looking statements. Such
forward-looking statements are subject to risks and uncertainties that could
cause actual results to differ materially from those expressed in, or implied
by, such statements.
These
risks and uncertainties include, but are not limited to: declines in
oil or 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 and CO2; our
ability to obtain external capital to finance acquisitions; our ability to
identify and complete acquisitions, and to successfully integrate acquired
businesses, including the properties acquired from Chicago Energy; unforeseen
underperformance of or liabilities associated with acquired properties,
including the properties acquired from Chicago Energy; our ability to
successfully complete potential asset dispositions; 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 in the regions in
which we operate; risks arising out of our hedging transactions; and other risks
described under the caption “Risk Factors” in our Annual Report on Form 10-K for
the fiscal year ended December 31, 2007. We assume no obligation, and
disclaim any duty, to update the forward-looking statements in this
report.
|
Item 3.
|
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, 2007 and have not
materially changed since that report was filed.
Our
outstanding hedges as of July 1, 2008 are summarized below:
Whiting
Petroleum Corporation:
|
Commodity
|
Period
|
Monthly
Volume
(Bbl)/(MMBtu)
|
NYMEX
Floor/Ceiling
|
|
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
|
07/2008
to 09/2008
|
100,000
|
$65.00/$81.00
|
|
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
|
|
Crude
Oil
|
10/2008
to 12/2008
|
100,000
|
$65.00/$81.20
|
In
connection with our conveyance on April 30, 2008 of a term net profits interest
to Whiting USA Trust I (as further explained above in Second Quarter 2008
Highlights and Future Considerations and in the note on Acquisitions and
Divestitures), the rights to any future hedge payments we make or receive on
certain of our derivative contracts, representing 2,323 Mbbls of crude oil and
9,237 MMcf of natural gas from 2008 through 2012, have been conveyed to the
Trust, and therefore such payments will be included in the Trust’s calculation
of net proceeds. Under the Trust, we retain 10% of the net proceeds from the
underlying properties. Our retention of 10% of these net proceeds
combined with our ownership of 2,186,389 Trust units, results in third-party
public holders of Trust units receiving 75.8%, while we retain 24.2%, of future
economic results of such hedges. No additional hedges are allowed to
be placed on Trust assets.
Whiting
USA Trust I:
|
Commodity
|
Period
|
Monthly
Volume
(Bbl)/(MMBtu)
|
NYMEX
Floor/Ceiling
|
|
Crude
Oil
|
07/2008
to 09/2008
|
26,459
|
$82.00/$130.45
|
|
Crude
Oil
|
07/2008
to 09/2008
|
26,459
|
$82.00/$137.57
|
|
Crude
Oil
|
10/2008
to 12/2008
|
25,718
|
$82.00/$128.30
|
|
Crude
Oil
|
10/2008
to 12/2008
|
25,718
|
$82.00/$134.85
|
|
Crude
Oil
|
01/2009
to 03/2009
|
25,059
|
$76.00/$136.70
|
|
Crude
Oil
|
01/2009
to 03/2009
|
25,059
|
$76.00/$142.99
|
|
Crude
Oil
|
04/2009
to 06/2009
|
24,397
|
$76.00/$134.70
|
|
Crude
Oil
|
04/2009
to 06/2009
|
24,397
|
$76.00/$140.39
|
|
Crude
Oil
|
07/2009
to 09/2009
|
23,755
|
$76.00/$133.70
|
|
Crude
Oil
|
07/2009
to 09/2009
|
23,755
|
$76.00/$139.12
|
|
Crude
Oil
|
10/2009
to 12/2009
|
23,120
|
$76.00/$132.90
|
|
Crude
Oil
|
10/2009
to 12/2009
|
23,120
|
$76.00/$138.54
|
|
Crude
Oil
|
01/2010
to 03/2010
|
22,542
|
$76.00/$132.35
|
|
Crude
Oil
|
01/2010
to 03/2010
|
22,542
|
$76.00/$137.82
|
|
Commodity
|
Period
|
Monthly
Volume
(Bbl)/(MMBtu)
|
NYMEX Floor/Ceiling |
|
Crude
Oil
|
04/2010
to 06/2010
|
21,989
|
$76.00/$132.10
|
|
Crude
Oil
|
04/2010
to 06/2010
|
21,989
|
$76.00/$137.60
|
|
Crude
Oil
|
07/2010
to 09/2010
|
21,483
|
$76.00/$131.90
|
|
Crude
Oil
|
07/2010
to 09/2010
|
21,483
|
$76.00/$137.88
|
|
Crude
Oil
|
10/2010
to 12/2010
|
20,962
|
$76.00/$131.90
|
|
Crude
Oil
|
10/2010
to 12/2010
|
20,962
|
$76.00/$138.32
|
|
Crude
Oil
|
01/2011
to 03/2011
|
20,489
|
$74.00/$136.00
|
|
Crude
Oil
|
01/2011
to 03/2011
|
20,489
|
$74.00/$143.35
|
|
Crude
Oil
|
04/2011
to 06/2011
|
20,033
|
$74.00/$136.20
|
|
Crude
Oil
|
04/2011
to 06/2011
|
20,033
|
$74.00/$143.95
|
|
Crude
Oil
|
07/2011
to 09/2011
|
19,585
|
$74.00/$136.10
|
|
Crude
Oil
|
07/2011
to 09/2011
|
19,585
|
$74.00/$144.19
|
|
Crude
Oil
|
10/2011
to 12/2011
|
19,121
|
$74.00/$136.55
|
|
Crude
Oil
|
10/2011
to 12/2011
|
19,121
|
$74.00/$144.94
|
|
Crude
Oil
|
01/2012
to 03/2012
|
18,706
|
$74.00/$136.95
|
|
Crude
Oil
|
01/2012
to 03/2012
|
18,706
|
$74.00/$145.59
|
|
Crude
Oil
|
04/2012
to 06/2012
|
18,286
|
$74.00/$137.30
|
|
Crude
Oil
|
04/2012
to 06/2012
|
18,286
|
$74.00/$146.15
|
|
Crude
Oil
|
07/2012
to 09/2012
|
17,871
|
$74.00/$137.30
|
|
Crude
Oil
|
07/2012
to 09/2012
|
17,871
|
$74.00/$146.09
|
|
Crude
Oil
|
10/2012
to 12/2012
|
17,514
|
$74.00/$137.80
|
|
Crude
Oil
|
10/2012
to 12/2012
|
17,514
|
$74.00/$146.62
|
|
Natural
Gas
|
07/2008
to 09/2008
|
241,797
|
$7.00/$15.85
|
|
Natural
Gas
|
10/2008
to 12/2008
|
228,830
|
$7.00/$19.00
|
|
Natural
Gas
|
01/2009
to 03/2009
|
216,333
|
$7.00/$22.50
|
|
Natural
Gas
|
04/2009
to 06/2009
|
201,263
|
$6.00/$14.85
|
|
Natural
Gas
|
07/2009
to 09/2009
|
192,870
|
$6.00/$15.60
|
|
Natural
Gas
|
10/2009
to 12/2009
|
185,430
|
$7.00/$14.85
|
|
Natural
Gas
|
01/2010
to 03/2010
|
178,903
|
$7.00/$18.65
|
|
Natural
Gas
|
04/2010
to 06/2010
|
172,873
|
$6.00/$13.20
|
|
Natural
Gas
|
07/2010
to 09/2010
|
167,583
|
$6.00/$14.00
|
|
Natural
Gas
|
10/2010
to 12/2010
|
162,997
|
$7.00/$14.20
|
|
Natural
Gas
|
01/2011
to 03/2011
|
157,600
|
$7.00/$17.40
|
|
Natural
Gas
|
04/2011
to 06/2011
|
152,703
|
$6.00/$13.05
|
|
Natural
Gas
|
07/2011
to 09/2011
|
148,163
|
$6.00/$13.65
|
|
Natural
Gas
|
10/2011
to 12/2011
|
142,787
|
$7.00/$14.25
|
|
Natural
Gas
|
01/2012
to 03/2012
|
137,940
|
$7.00/$15.55
|
|
Natural
Gas
|
04/2012
to 06/2012
|
134,203
|
$6.00/$13.60
|
|
Natural
Gas
|
07/2012
to 09/2012
|
130,173
|
$6.00/$14.45
|
|
Natural
Gas
|
10/2012
to 12/2012
|
126,613
|
$7.00/$13.40
|
The
collared hedges shown above have the effect of providing a protective floor
while allowing us to share in upward pricing movements. Consequently,
while these hedges are designed to decrease our exposure to price decreases,
they also have the effect of limiting the benefit of price increases beyond the
ceiling. For the 2008 crude oil contracts listed in both tables
above, a hypothetical $1.00 change in the NYMEX price above the ceiling price or
below the floor price applied to the notional amounts would cause a change in
our gain (loss) on hedging activities in 2008 of $2.1
million. For the 2008 natural gas contracts listed above, a
hypothetical $0.10 change in the NYMEX price above the ceiling price or below
the floor price applied to the notional amounts would cause a change in our gain
(loss) on hedging activities in 2008 of $0.03 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 July 1, 2008 are summarized
below:
|
Commodity
|
Period
|
Monthly
Volume
(MMBtu)
|
2008
Price
Per
MMBtu
|
|
Natural
Gas
|
07/2008
to 05/2011
|
25,000
|
$4.94
|
|
Natural
Gas
|
07/2008
to 09/2012
|
67,000
|
$4.38
|
|
Item 4.
|
Controls and
Procedures
|
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 June 30,
2008. 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 June 30, 2008 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 June 30,
2008 that has materially affected, or is reasonably likely to materially affect,
our internal control over financial reporting.
PART II –
OTHER INFORMATION
|
Item 1.
|
Legal
Proceedings
|
Whiting
is subject to litigation claims and governmental and regulatory proceedings
arising in the ordinary course of business. It is management’s
opinion that all claims and litigation we are involved in are not likely to have
a material adverse effect on our consolidated financial position, cash flows or
results of operations.
|
Item 1A.
|
Risk
Factors
|
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, 2007. No material change
to such risk factors has occurred during the six months ended June 30,
2008.
|
Item 4.
|
Submission of Matters
to a Vote of Security
Holders
|
Whiting
Petroleum Corporation held its annual meeting of stockholders on May 6,
2008. At such meeting, Palmer L. Moe and D. Sherwin Artus were
reelected as directors for terms to expire at the 2011 annual meeting of
stockholders and until their successors are duly elected and qualified pursuant
to the following votes:
|
Shares
Voted
|
||||||||
|
Name
of Nominee
|
For
|
Withheld
|
||||||
|
Palmer
L. Moe
|
37,935,918 | 980,302 | ||||||
|
D.
Sherwin Artus
|
33,119,410 | 5,796,810 | ||||||
The other
directors of Whiting Petroleum Corporation whose terms of office continued after
the 2008 annual meeting of stockholders are as follows: terms
expiring at the 2009 annual meeting: William N. Hahne, Graydon D.
Hubbard and James J. Volker; and terms expiring at the 2010 annual
meeting: Thomas L. Aller and Thomas P. Briggs.
The
following other matter brought for vote at the 2008 annual meeting of
stockholders passed by the vote indicated:
|
Shares
Voted
|
||||||||||||||||
|
For
|
Against
|
Abstain
|
Broker
Non-Vote
|
|||||||||||||
|
Approval
of performance goals and related matters under the 2003 Equity Incentive
Plan
|
37,468,278 | 1,388,367 | 59,575 | - | ||||||||||||
|
Ratification
of the appointment of Deloitte & Touche LLP as independent registered
public accounting firm
|
38,806,172 | 80,589 | 29,459 | - | ||||||||||||
|
Item 5.
|
Other
Information
|
On July
29, 2008, the Board of Directors of Whiting Petroleum Corporation amended the
Amended and Restated By-laws of Whiting Petroleum Corporation to extend the
mandatory retirement age for Graydon D. Hubbard, a director of Whiting Petroleum
Corporation, from 75 to 78. A copy of the Amended and Restated
By-laws of Whiting Petroleum Corporation including such amendment is filed as
Exhibit 3.1 to this Quarterly Report on Form 10-Q and incorporated by reference
herein.
|
Item 6.
|
Exhibits
|
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 31st day of July, 2008.
|
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
|
|
(2.1)
|
Purchase
and Sale Agreement, between Chicago Energy Associates, LLC and Whiting Oil
and Gas Corporation [Incorporated by reference to Exhibit 2.1 to Whiting
Petroleum Corporation’s Current Report on Form 8-K dated May 4, 2008 (File
No. 001-31899)].*
|
|
(2.2)
|
Purchase
and Sale Agreement, between Comet Resources LLC and Whiting Oil and Gas
Corporation [Incorporated by reference to Exhibit 2.2 to Whiting Petroleum
Corporation’s Current Report on Form 8-K dated May 4, 2008 (File
No. 001-31899)].*
|
|
(3.1)
|
Amended
and Restated By-laws of Whiting Petroleum Corporation, effective July 29,
2008.
|
|
(31.1)
|
Certification
by the Chairman, President and Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act.
|
|
(31.2)
|
Certification
by the Vice President and Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act.
|
|
(32.1)
|
Written
Statement of the Chairman, President and Chief Executive Officer pursuant
to 18 U.S.C. Section 1350.
|
|
(32.2)
|
Written
Statement of the Vice President and Chief Financial Officer pursuant to 18
U.S.C. Section 1350.
|
* All
schedules and exhibits to this Exhibit have been omitted in accordance with
Regulation S-K Item 601(b)(2). The Company agrees to furnish
supplementally a copy of all omitted schedules and exhibits to the Securities
and Exchange Commission upon its request.
51