form10-q.htm
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 September 30,
2009
or
[ ]
|
TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
|
For the
transition period from _______________ to _______________
|
Commission
file number: 001-31899
WHITING
PETROLEUM CORPORATION
|
|
|
(Exact
name of registrant as specified in its charter)
|
|
|
|
|
Delaware
|
|
20-0098515
|
(State
or other jurisdiction
of
incorporation or organization)
|
|
(I.R.S.
Employer
Identification
No.)
|
|
|
|
1700
Broadway, Suite 2300
Denver,
Colorado
|
|
80290-2300
|
(Address
of principal executive offices)
|
|
(Zip
code)
|
|
|
|
|
(303)
837-1661
|
|
|
(Registrant’s
telephone number, including area code)
|
|
Indicate
by check mark whether the registrant (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past
90 days. Yes T
No £
Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such
files). Yes £
No £
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,”
“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one):
Large
accelerated
filer T
|
Accelerated
filer
£
|
Non-accelerated
filer £
|
Smaller
reporting company £
|
|
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).Yes £
No T
Number of
shares of the registrant’s common stock outstanding at October 15,
2009: 50,845,106 shares.
Unless
the context otherwise requires, the terms “we,” “us,” “our” or “ours” when used
in this report refer to Whiting Petroleum Corporation, together with its
consolidated subsidiaries. When the context requires, we refer to
these entities separately.
We have
included below the definitions for certain terms used in this
report:
“Bbl” - One stock tank
barrel, or 42 U.S. gallons liquid volume, used in this report in reference to
oil and other liquid hydrocarbons.
“Bcf” - One billion cubic
feet of natural gas.
“BOE” - One stock tank barrel
equivalent of oil, calculated by converting natural gas volumes to equivalent
oil barrels at a ratio of six Mcf to one Bbl of oil.
“FASB ASC” - the Financial
Accounting Standards Board Accounting Standards Codification.
“GAAP” - Generally accepted
accounting principles in the United States of America.
“MBbl” - One thousand barrels
of oil or other liquid hydrocarbons.
“MBOE” - One thousand
BOE.
“MBOE/d” - One thousand BOE
per day.
“Mcf” - One thousand cubic
feet of natural gas.
“MMBbl” - One million barrels
of oil or other liquid hydrocarbons.
“MMBOE” - One million
BOE.
“MMBtu” - One million British
Thermal Units.
“MMcf” - One million cubic
feet of natural gas.
“MMcf/d” - One MMcf of
natural gas per day.
“plugging and abandonment” -
Refers to the sealing off of fluids in the strata penetrated by a well so that
the fluids from one stratum will not escape into another or to the
surface. Regulations of many states require plugging of abandoned
wells.
“working interest” - The
interest in a crude oil and natural gas property (normally a leasehold interest)
that gives the owner the right to drill, produce and conduct operations on the
property; to share in production, subject to all royalties, overriding royalties
and other burdens; and to share in all costs of exploration, development,
operations and all risks in connection therewith.
PART I –
FINANCIAL INFORMATION
|
Consolidated Financial
Statements
|
WHITING PETROLEUM CORPORATION
CONSOLIDATED
BALANCE SHEETS (Unaudited)
(In
thousands)
ASSETS
|
|
|
|
|
|
|
|
|
September
30, 2009 |
|
|
December
31, 2008 |
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
15,860 |
|
|
$ |
9,624 |
|
Accounts
receivable trade, net
|
|
|
127,063 |
|
|
|
123,386 |
|
Derivative
assets
|
|
|
7,803 |
|
|
|
46,780 |
|
Prepaid
expenses and other
|
|
|
7,222 |
|
|
|
37,284 |
|
Total
current assets
|
|
|
157,948 |
|
|
|
217,074 |
|
PROPERTY
AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
Oil
and gas properties, successful efforts method:
|
|
|
|
|
|
|
|
|
Proved
properties
|
|
|
4,708,604 |
|
|
|
4,423,197 |
|
Unproved
properties
|
|
|
99,135 |
|
|
|
106,436 |
|
Other
property and equipment
|
|
|
112,920 |
|
|
|
91,099 |
|
Total
property and equipment
|
|
|
4,920,659 |
|
|
|
4,620,732 |
|
Less
accumulated depreciation, depletion and amortization
|
|
|
(1,178,667 |
) |
|
|
(886,065 |
) |
Total
property and equipment, net
|
|
|
3,741,992 |
|
|
|
3,734,667 |
|
DEBT
ISSUANCE COSTS
|
|
|
27,186 |
|
|
|
10,779 |
|
DERIVATIVE
ASSETS
|
|
|
12,778 |
|
|
|
38,104 |
|
OTHER
LONG-TERM ASSETS
|
|
|
23,585 |
|
|
|
28,457 |
|
TOTAL
|
|
$ |
3,963,489 |
|
|
$ |
4,029,081 |
|
|
|
|
|
|
|
|
|
|
See
notes to consolidated financial statements.
|
|
|
|
|
|
(Continued)
|
|
WHITING
PETROLEUM CORPORATION
CONSOLIDATED
BALANCE SHEETS (Unaudited)
(In
thousands, except share and per share data)
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
September
30, 2009 |
|
|
December
31, 2008 |
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
Accounts
payable
|
|
$ |
18,326 |
|
|
$ |
64,610 |
|
Accrued
capital expenditures
|
|
|
23,372 |
|
|
|
84,960 |
|
Accrued
liabilities
|
|
|
61,858 |
|
|
|
45,359 |
|
Accrued
interest
|
|
|
20,285 |
|
|
|
9,673 |
|
Oil
and gas sales payable
|
|
|
35,990 |
|
|
|
35,106 |
|
Accrued
employee compensation and benefits
|
|
|
15,461 |
|
|
|
41,911 |
|
Production
taxes payable
|
|
|
21,568 |
|
|
|
20,038 |
|
Deferred
gain on sale
|
|
|
13,195 |
|
|
|
14,650 |
|
Derivative
liabilities
|
|
|
25,050 |
|
|
|
17,354 |
|
Deferred
income taxes
|
|
|
10,305 |
|
|
|
15,395 |
|
Tax
sharing liability
|
|
|
2,112 |
|
|
|
2,112 |
|
Total
current liabilities
|
|
|
247,522 |
|
|
|
351,168 |
|
NON-CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
769,604 |
|
|
|
1,239,751 |
|
Deferred
income taxes
|
|
|
351,409 |
|
|
|
390,902 |
|
Deferred
gain on sale
|
|
|
62,181 |
|
|
|
73,216 |
|
Production
Participation Plan liability
|
|
|
69,168 |
|
|
|
66,166 |
|
Asset
retirement obligations
|
|
|
67,176 |
|
|
|
47,892 |
|
Derivative
liabilities
|
|
|
86,197 |
|
|
|
28,131 |
|
Tax
sharing liability
|
|
|
22,802 |
|
|
|
21,575 |
|
Other
long-term liabilities
|
|
|
2,980 |
|
|
|
1,489 |
|
Total
non-current liabilities
|
|
|
1,431,517 |
|
|
|
1,869,122 |
|
COMMITMENTS
AND CONTINGENCIES
|
|
|
|
|
|
|
|
|
STOCKHOLDERS’
EQUITY:
|
|
|
|
|
|
|
|
|
Preferred
stock, $0.001 par value, 5,000,000 shares authorized;
6.25%
convertible perpetual preferred stock, 3,450,000 and 0 shares
issued and outstanding as of September 30, 2009 and December 31, 2008,
respectively, aggregate liquidation preference of
$345,000,000
|
|
|
3 |
|
|
|
- |
|
Common
stock, $0.001 par value, 75,000,000 shares authorized;
51,363,728
issued and 50,845,106 outstanding as of September 30, 2009, 42,582,100
issued and 42,323,336 outstanding as of December 31,
2008
|
|
|
51 |
|
|
|
43 |
|
Additional
paid-in capital
|
|
|
1,543,037 |
|
|
|
971,310 |
|
Accumulated
other comprehensive income
|
|
|
27,170 |
|
|
|
17,271 |
|
Retained
earnings
|
|
|
714,189 |
|
|
|
820,167 |
|
Total
stockholders’ equity
|
|
|
2,284,450 |
|
|
|
1,808,791 |
|
TOTAL
|
|
$ |
3,963,489 |
|
|
$ |
4,029,081 |
|
See
notes to consolidated financial statements.
|
|
|
|
|
|
(Concluded)
|
|
WHITING PETROLEUM CORPORATION
CONSOLIDATED
STATEMENTS OF INCOME (Unaudited)
(In
thousands, except per share data)
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
AND OTHER INCOME:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and natural gas sales
|
|
$ |
256,074 |
|
|
$ |
425,392 |
|
|
$ |
616,552 |
|
|
$ |
1,102,658 |
|
Gain
(loss) on hedging activities
|
|
|
7,774 |
|
|
|
(41,879 |
) |
|
|
28,072 |
|
|
|
(112,902 |
) |
Amortization
of deferred gain on sale
|
|
|
4,222 |
|
|
|
4,720 |
|
|
|
12,595 |
|
|
|
7,677 |
|
Gain
on sale of properties
|
|
|
1,101 |
|
|
|
- |
|
|
|
5,709 |
|
|
|
- |
|
Interest
income and other
|
|
|
156 |
|
|
|
201 |
|
|
|
396 |
|
|
|
825 |
|
Total
revenues and other income
|
|
|
269,327 |
|
|
|
388,434 |
|
|
|
663,324 |
|
|
|
998,258 |
|
COSTS
AND EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating
|
|
|
58,807 |
|
|
|
64,690 |
|
|
|
177,343 |
|
|
|
177,866 |
|
Production
taxes
|
|
|
18,792 |
|
|
|
28,245 |
|
|
|
43,225 |
|
|
|
71,988 |
|
Depreciation,
depletion and amortization
|
|
|
101,273 |
|
|
|
74,233 |
|
|
|
301,622 |
|
|
|
179,555 |
|
Exploration
and impairment
|
|
|
12,422 |
|
|
|
10,939 |
|
|
|
39,528 |
|
|
|
30,566 |
|
General
and administrative
|
|
|
11,314 |
|
|
|
17,281 |
|
|
|
30,576 |
|
|
|
51,903 |
|
Interest
expense
|
|
|
15,647 |
|
|
|
17,543 |
|
|
|
49,020 |
|
|
|
48,760 |
|
Change
in Production Participation Plan liability
|
|
|
(678 |
) |
|
|
9,117 |
|
|
|
3,002 |
|
|
|
26,964 |
|
Commodity
derivative (gain) loss, net
|
|
|
(10,391 |
) |
|
|
(10,561 |
) |
|
|
171,906 |
|
|
|
7,064 |
|
Total
costs and expenses
|
|
|
207,186 |
|
|
|
211,487 |
|
|
|
816,222 |
|
|
|
594,666 |
|
INCOME
(LOSS) BEFORE INCOME TAXES
|
|
|
62,141 |
|
|
|
176,947 |
|
|
|
(152,898 |
) |
|
|
403,592 |
|
INCOME
TAX EXPENSE (BENEFIT):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
(507 |
) |
|
|
481 |
|
|
|
(1,046 |
) |
|
|
1,353 |
|
Deferred
|
|
|
26,793 |
|
|
|
64,049 |
|
|
|
(50,785 |
) |
|
|
147,060 |
|
Total
income tax expense (benefit)
|
|
|
26,286 |
|
|
|
64,530 |
|
|
|
(51,831 |
) |
|
|
148,413 |
|
NET
INCOME (LOSS)
|
|
|
35,855 |
|
|
|
112,417 |
|
|
|
(101,067 |
) |
|
|
255,179 |
|
Preferred
stock dividends declared
|
|
|
(4,911 |
) |
|
|
- |
|
|
|
(4,911 |
) |
|
|
- |
|
NET
INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS
|
|
$ |
30,944 |
|
|
$ |
112,417 |
|
|
$ |
(105,978 |
) |
|
$ |
255,179 |
|
NET
INCOME (LOSS) PER COMMON SHARE, BASIC
|
|
$ |
0.59 |
|
|
$ |
2.66 |
|
|
$ |
(2.15 |
) |
|
$ |
6.03 |
|
NET
INCOME (LOSS) PER COMMON SHARE, DILUTED
|
|
$ |
0.59 |
|
|
$ |
2.65 |
|
|
$ |
(2.15 |
) |
|
$ |
6.01 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See
notes to consolidated financial statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WHITING PETROLEUM CORPORATION
CONSOLIDATED
STATEMENTS OF CASH FLOWS (Unaudited)
(In
thousands)
|
|
Nine
Months Ended
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income (loss)
|
|
$ |
(101,067 |
) |
|
$ |
255,179 |
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
301,622 |
|
|
|
179,555 |
|
Deferred
income tax (benefit) expense
|
|
|
(50,785 |
) |
|
|
147,060 |
|
Amortization
of debt issuance costs and debt discount
|
|
|
6,916 |
|
|
|
3,618 |
|
Accretion
of tax sharing liability
|
|
|
1,227 |
|
|
|
934 |
|
Stock-based
compensation
|
|
|
4,047 |
|
|
|
4,917 |
|
Amortization
of deferred gain on sale
|
|
|
(12,595 |
) |
|
|
(7,677 |
) |
Gain
on sale of properties
|
|
|
(5,709 |
) |
|
|
- |
|
Undeveloped
leasehold and oil and gas property impairments
|
|
|
14,743 |
|
|
|
9,016 |
|
Change
in Production Participation Plan liability
|
|
|
3,002 |
|
|
|
26,964 |
|
Unrealized
loss on derivative contracts
|
|
|
145,650 |
|
|
|
7,021 |
|
Other
non-current
|
|
|
646 |
|
|
|
(14,744 |
) |
Changes
in current assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts
receivable trade
|
|
|
(2,317 |
) |
|
|
(77,398 |
) |
Prepaid
expenses and other
|
|
|
30,062 |
|
|
|
(17,836 |
) |
Accounts
payable and accrued liabilities
|
|
|
(33,544 |
) |
|
|
26,683 |
|
Accrued
interest
|
|
|
10,612 |
|
|
|
9,982 |
|
Other
current liabilities
|
|
|
(24,693 |
) |
|
|
58,178 |
|
Net
cash provided by operating activities
|
|
|
287,817 |
|
|
|
611,452 |
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Cash
acquisition capital expenditures
|
|
|
(31,475 |
) |
|
|
(413,219 |
) |
Drilling
and development capital expenditures
|
|
|
(401,227 |
) |
|
|
(638,400 |
) |
Proceeds
from sale of oil and gas properties
|
|
|
80,308 |
|
|
|
1,445 |
|
Proceeds
from sale of marketable securities
|
|
|
- |
|
|
|
764 |
|
Net
proceeds from sale of 11,677,500 units in Whiting USA Trust
I
|
|
|
- |
|
|
|
193,824 |
|
Net
cash used in investing activities
|
|
|
(352,394 |
) |
|
|
(855,586 |
) |
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Issuance
of 6.25% convertible perpetual preferred stock
|
|
|
334,112 |
|
|
|
- |
|
Issuance
of common stock
|
|
|
234,753 |
|
|
|
- |
|
Preferred
stock dividends paid
|
|
|
(4,911 |
) |
|
|
- |
|
Long-term
borrowings under credit agreement
|
|
|
310,000 |
|
|
|
925,000 |
|
Repayments
of long-term borrowings under credit agreement
|
|
|
(780,000 |
) |
|
|
(675,000 |
) |
Debt
issuance costs
|
|
|
(23,141 |
) |
|
|
- |
|
Net
cash provided by financing activities
|
|
|
70,813 |
|
|
|
250,000 |
|
NET
CHANGE IN CASH AND CASH EQUIVALENTS
|
|
|
6,236 |
|
|
|
5,866 |
|
CASH
AND CASH EQUIVALENTS:
|
|
|
|
|
|
|
|
|
Beginning
of period
|
|
|
9,624 |
|
|
|
14,778 |
|
End
of period
|
|
$ |
15,860 |
|
|
$ |
20,644 |
|
|
|
|
|
|
|
|
|
|
See
notes to consolidated financial statements.
|
|
|
|
|
|
(Continued)
|
|
WHITING
PETROLEUM CORPORATION
CONSOLIDATED
STATEMENTS OF CASH FLOWS (Unaudited)
(In
thousands)
|
|
Nine
Months Ended
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL
CASH FLOW DISCLOSURES:
|
|
|
|
|
|
|
Cash
paid (refunded) for income taxes
|
|
$ |
(2,484 |
) |
|
$ |
1,175 |
|
Cash
paid for interest
|
|
$ |
30,265 |
|
|
$ |
34,227 |
|
NONCASH
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Accrued
capital expenditures during the period
|
|
$ |
23,372 |
|
|
$ |
82,840 |
|
|
|
|
|
|
|
|
|
|
See
notes to consolidated financial statements.
|
|
|
|
|
|
(Concluded)
|
|
WHITING PETROLEUM CORPORATION
CONSOLIDATED
STATEMENTS OF STOCKHOLDERS’ EQUITY
AND
COMPREHENSIVE INCOME (Unaudited)
(In
thousands)
|
|
|
|
|
|
|
|
Additional
Paid-in
|
|
|
Accumulated
Other
Comprehensive
|
|
|
Retained |
|
|
Total
Stockholders’
|
|
|
Comprehensive
Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCES-January
1, 2008
|
|
|
- |
|
|
$ |
- |
|
|
|
42,480 |
|
|
$ |
42 |
|
|
$ |
968,876 |
|
|
$ |
(46,116 |
) |
|
$ |
568,024 |
|
|
$ |
1,490,826 |
|
|
|
|
Net
income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
255,179 |
|
|
|
255,179 |
|
|
$ |
255,179 |
|
Change
in derivative fair values, net of taxes of $23,878
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(41,274 |
) |
|
|
- |
|
|
|
(41,274 |
) |
|
|
(41,274 |
) |
Realized
loss on settled derivative contracts, net of taxes of
$41,379
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
71,523 |
|
|
|
- |
|
|
|
71,523 |
|
|
|
71,523 |
|
Total
comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
285,428 |
|
Restricted
stock issued
|
|
|
- |
|
|
|
- |
|
|
|
139 |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
|
|
Restricted
stock forfeited
|
|
|
- |
|
|
|
- |
|
|
|
(4 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
Restricted
stock used for tax withholdings
|
|
|
- |
|
|
|
- |
|
|
|
(30 |
) |
|
|
- |
|
|
|
(1,743 |
) |
|
|
- |
|
|
|
- |
|
|
|
(1,743 |
) |
|
|
|
|
Stock-based
compensation
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4,917 |
|
|
|
- |
|
|
|
- |
|
|
|
4,917 |
|
|
|
|
|
BALANCES-September
30, 2008
|
|
|
- |
|
|
$ |
- |
|
|
|
42,585 |
|
|
$ |
43 |
|
|
$ |
972,050 |
|
|
$ |
(15,867 |
) |
|
$ |
823,203 |
|
|
$ |
1,779,429 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCES-December
31, 2008
|
|
|
- |
|
|
$ |
- |
|
|
|
42,582 |
|
|
$ |
43 |
|
|
$ |
971,310 |
|
|
$ |
17,271 |
|
|
$ |
820,167 |
|
|
$ |
1,808,791 |
|
|
|
|
|
Net
loss
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(101,067 |
) |
|
|
(101,067 |
) |
|
$ |
(101,067 |
) |
Change
in derivative fair values, net of taxes of $7,799
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
13,348 |
|
|
|
- |
|
|
|
13,348 |
|
|
|
13,348 |
|
Realized
gain on settled derivatives, net of taxes of $4,933
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(8,517 |
) |
|
|
- |
|
|
|
(8,517 |
) |
|
|
(8,517 |
) |
Ineffectiveness
loss on hedging activities, net of taxes of $8,355
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
14,300 |
|
|
|
- |
|
|
|
14,300 |
|
|
|
14,300 |
|
OCI
amortization on de-designated hedges, net of taxes of
$5,390
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(9,232 |
) |
|
|
- |
|
|
|
(9,232 |
) |
|
|
(9,232 |
) |
Total
comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(91,168 |
) |
Issuance
of 6.25% convertible perpetual preferred stock
|
|
|
3,450 |
|
|
|
3 |
|
|
|
- |
|
|
|
- |
|
|
|
334,109 |
|
|
|
- |
|
|
|
- |
|
|
|
334,112 |
|
|
|
|
|
Issuance
of stock, secondary offering
|
|
|
- |
|
|
|
- |
|
|
|
8,450 |
|
|
|
8 |
|
|
|
234,745 |
|
|
|
- |
|
|
|
- |
|
|
|
234,753 |
|
|
|
|
|
Restricted
stock issued
|
|
|
- |
|
|
|
- |
|
|
|
364 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
Restricted
stock forfeited
|
|
|
- |
|
|
|
- |
|
|
|
(5 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
Restricted
stock used for tax withholdings
|
|
|
- |
|
|
|
- |
|
|
|
(27 |
) |
|
|
- |
|
|
|
(659 |
) |
|
|
- |
|
|
|
- |
|
|
|
(659 |
) |
|
|
|
|
Tax
effect from restricted stock vesting
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(515 |
) |
|
|
- |
|
|
|
- |
|
|
|
(515 |
) |
|
|
|
|
Stock-based
compensation
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4,047 |
|
|
|
- |
|
|
|
- |
|
|
|
4,047 |
|
|
|
|
|
Preferred
dividends paid
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(4,911 |
) |
|
|
(4,911 |
) |
|
|
|
|
BALANCES-September
30, 2009
|
|
|
3,450 |
|
|
$ |
3 |
|
|
|
51,364 |
|
|
$ |
51 |
|
|
$ |
1,543,037 |
|
|
$ |
27,170 |
|
|
$ |
714,189 |
|
|
$ |
2,284,450 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See
notes to consolidated financial statements.
|
|
|
|
|
|
|
|
|
|
WHITING PETROLEUM CORPORATION
NOTES
TO CONSOLIDATED
FINANCIAL
STATEMENTS (Unaudited)
Description of
Operations—Whiting Petroleum Corporation, a Delaware corporation, is an
independent oil and gas company that acquires, exploits, develops and explores
for crude oil, natural gas and natural gas liquids primarily in the Permian
Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the
United States. Unless otherwise specified or the context otherwise
requires, all references in these notes to “Whiting” or the “Company” are to
Whiting Petroleum Corporation and its consolidated subsidiaries.
Consolidated
Financial Statements—The unaudited consolidated financial statements
include the accounts of Whiting Petroleum Corporation, its consolidated
subsidiaries, all of which are wholly owned, and Whiting’s pro rata share of the
accounts of Whiting USA Trust I pursuant to Whiting’s 15.8% ownership
interest. Investments in entities which give Whiting significant
influence, but not control, over the investee are accounted for using the equity
method. Under the equity method, investments are stated at cost plus
the Company’s equity in undistributed earnings and losses. All intercompany
balances and transactions have been eliminated upon
consolidation. These financial statements have been prepared in
accordance with GAAP for interim financial reporting. In the opinion
of management, the accompanying financial statements include all adjustments
(consisting of normal recurring accruals and adjustments) necessary to present
fairly, in all material respects, the Company’s interim
results. Whiting’s 2008 Annual Report on Form 10-K includes certain
definitions and a summary of significant accounting policies and should be read
in conjunction with this Form 10-Q. Except as disclosed herein, there
has been no material change to the information disclosed in the notes to the
consolidated financial statements included in Whiting’s 2008 Annual Report on
Form 10-K. Operating results for the periods presented are not
necessarily indicative of the results that may be expected for the full
year.
Earnings Per
Share—Basic net income per common share is calculated by dividing
adjusted net income available to common shareholders by the weighted average
number of common shares outstanding during each period. Diluted net
income per common share is calculated by dividing adjusted net income by the
weighted average number of diluted common shares outstanding, which includes the
effect of potentially dilutive securities. Potentially dilutive
securities for the diluted earnings per share calculations consist of unvested
restricted stock awards and outstanding stock options using the treasury method,
and convertible perpetual preferred stock using the if-converted
method. When a loss from continuing operations exists, all
potentially dilutive securities are anti-dilutive and are therefore excluded
from the computation of diluted earnings per share accordingly.
Subsequent
Events—The Company has evaluated subsequent events through October 29,
2009 and has no material subsequent events to report.
2.
|
ACQUISITIONS
AND DIVESTITURES
|
2009
Acquisitions
There
were no significant acquisitions during the first nine months of
2009.
2009 Participation
Agreement
On June
4, 2009, Whiting entered into a participation agreement with a privately held
independent oil company covering twenty-five 1,280-acre units and one 640-acre
unit located primarily in the western portion of the Sanish field in Mountrail
County, North Dakota. Under the terms of the agreement, the private
company agreed to pay 65% of Whiting’s net drilling and well completion costs to
receive 50% of Whiting’s working interest and net revenue interest in the first
and second wells planned for each of the units. Pursuant to the
agreement, Whiting will remain the operator for each unit.
At the
closing of the agreement, the private company paid Whiting $107.3 million,
representing $6.4 million for acreage costs, $65.8 million for 65% of Whiting’s
cost in 18 wells drilled or drilling and $35.1 million for a 50% interest in
Whiting’s Robinson Lake gas plant and oil and gas gathering
system. Whiting used these proceeds to repay a portion of the debt
outstanding under its credit agreement. Estimated proved reserves of
2.8 MMBOE, as of June 1, 2009, were sold by the Company as a result of this
divestiture.
2008
Acquisition
Flat Rock Natural
Gas Field—On
May 30, 2008, Whiting acquired interests in 31 producing gas wells,
development acreage and gas gathering and processing facilities on 22,000 gross
(11,500 net) acres in the Flat Rock field in Uintah County, Utah for an
aggregate acquisition price of $365.0 million.
This
acquisition was recorded using the purchase method of accounting. The
table below summarizes the allocation of the $359.4 million adjusted purchase
price, based on the acquisition date fair value of the assets acquired and the
liabilities assumed (in thousands).
|
|
|
|
|
|
|
|
Purchase
price
|
|
$ |
359,380 |
|
|
|
|
|
|
Allocation
of purchase price:
|
|
|
|
|
Proved
properties
|
|
$ |
251,895 |
|
Unproved
properties
|
|
|
79,498 |
|
Gas
gathering and processing facilities
|
|
|
35,736 |
|
Liabilities
assumed
|
|
|
(7,749 |
) |
Total
|
|
$ |
359,380 |
|
Acquisition Pro
Forma—In
the Company’s consolidated statements of income for the year ended December 31,
2008, Flat Rock’s results of operations are included with the Company’s results
beginning May 31, 2008. The following table, however, reflects the
unaudited pro forma results of operations for the nine months ended September
30, 2008, as though the Flat Rock acquisition had occurred on the first day of
that period. The pro forma information below includes numerous
assumptions and is not necessarily indicative of what historical results would
have been or what future results of operations will be.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
months ended September 30, 2008:
|
|
|
|
|
|
|
|
|
|
Total
revenues
|
|
$ |
998,258 |
|
|
$ |
17,761 |
|
|
$ |
1,016,019 |
|
Net
income
|
|
$ |
255,179 |
|
|
$ |
1,144 |
|
|
$ |
256,323 |
|
Net
income per common share – basic
|
|
$ |
6.03 |
|
|
$ |
0.03 |
|
|
$ |
6.06 |
|
Net
income per common share – diluted
|
|
$ |
6.01 |
|
|
$ |
0.03 |
|
|
$ |
6.04 |
|
2008
Divestiture
Whiting USA Trust
I—On April 30, 2008, the Company completed an initial public
offering of units of beneficial interest in Whiting USA Trust I (the
“Trust”), selling 11,677,500 Trust units at $20.00 per Trust unit, providing net
proceeds of $193.8 million after underwriters’ fees, offering expenses, and
post-close adjustments. The Company used the net proceeds to repay a
portion of the debt outstanding under its credit agreement. The net
proceeds from the sale of Trust units to the public resulted in a deferred gain
on sale of $100.1 million. Immediately prior to the closing of the
offering, Whiting conveyed a term net profits interest in certain of its oil and
gas properties to the Trust in exchange for 13,863,889 Trust
units. The Company has retained 15.8%, or 2,186,389 Trust units, of
the total Trust units issued and outstanding.
The net
profits interest entitles the Trust to receive 90% of the net proceeds from the
sale of oil and natural gas production from the underlying
properties. The net profits interest will terminate at the time when
9.11 MMBOE have been produced and sold from the underlying
properties. This is the equivalent of 8.2 MMBOE in respect of the
Trust’s right to receive 90% of the net proceeds from such production pursuant
to the net profits interest, and these reserve quantities are projected to be
produced by December 31, 2021, based on the reserve report for the
underlying properties as of December 31, 2008.
Long-term
debt consisted of the following at September 30, 2009 and December 31, 2008 (in
thousands):
|
|
|
|
|
|
|
Credit
Agreement
|
|
$ |
150,000 |
|
|
$ |
620,000 |
|
7%
Senior Subordinated Notes due 2014
|
|
|
250,000 |
|
|
|
250,000 |
|
7.25%
Senior Subordinated Notes due 2013, net of unamortized debt discount of
$1,243 and $1,541, respectively
|
|
|
218,757 |
|
|
|
218,459 |
|
7.25%
Senior Subordinated Notes due 2012, net of unamortized debt discount of
$299 and $397, respectively
|
|
|
150,847 |
|
|
|
151,292 |
|
Total debt
|
|
$ |
769,604 |
|
|
$ |
1,239,751 |
|
Credit
Agreement—As of September 30, 2009, Whiting Oil and Gas Corporation
(“Whiting Oil and Gas”), the Company’s wholly-owned subsidiary, had a credit
agreement with a syndicate of banks, and this credit facility has a borrowing
base of $1.1 billion with $947.2 million of available borrowing capacity, which
is net of $150.0 million in borrowings and $2.8 million in letters of credit
outstanding. The credit agreement provides for interest only payments
until April 2012, when the agreement expires and all outstanding borrowings are
due.
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, in each case which may reduce the amount of the borrowing
base. Whiting Oil and Gas may, throughout the term of the credit
agreement, borrow, repay and reborrow up to the borrowing base in effect at any
given time. A portion of the revolving credit agreement in an
aggregate amount not to exceed $50.0 million may be used to issue letters of
credit for the account of Whiting Oil and Gas or other designated subsidiaries
of the Company. As of September 30, 2009, $47.2 million was available
for additional letters of credit under the agreement.
Interest
accrues at the Company’s option at either (i) a base rate for a base rate loan
plus the margin in the table below, where the base rate is defined as the
greatest of the prime rate, the federal funds rate plus 0.50% or an adjusted
LIBOR rate plus 1.00%, or (ii) an adjusted LIBOR rate for a Eurodollar loan plus
the margin in the table below. The Company also incurs commitment
fees of 0.50% on the unused portion of the lesser of the aggregate commitments
of the lenders or the borrowing base, and are included as a component of
interest expense. At September 30, 2009, the weighted average
interest rate on the outstanding principal balance under the credit agreement
was 2.3%.
Ratio of Outstanding Borrowings to Borrowing
Base
|
|
Applicable
Margin for Base Rate
Loans
|
|
Applicable
Margin for Eurodollar
Loans
|
Less
than 0.25 to 1.0
|
|
1.1250%
|
|
2.00%
|
Greater
than or equal to 0.25 to 1.0 but less than 0.50 to 1.0
|
|
1.1375%
|
|
2.25%
|
Greater
than or equal to 0.50 to 1.0 but less than 0.75 to 1.0
|
|
1.6250%
|
|
2.50%
|
Greater
than or equal to 0.75 to 1.0 but less than 0.90 to 1.0
|
|
1.8750%
|
|
2.75%
|
Greater
than or equal to 0.90 to 1.0
|
|
2.1250%
|
|
3.00%
|
The
credit agreement contains restrictive covenants that may limit the Company’s
ability to, among other things, incur additional indebtedness, sell assets, make
loans to others, make investments, enter into mergers, enter into hedging
contracts, incur liens and engage in certain other transactions without the
prior consent of its lenders. The credit agreement requires the
Company, as of the last day of any quarter, (i) to not exceed a total debt to
EBITDAX ratio (as defined in the credit agreement) for the last four quarters of
4.5 to 1.0 for quarters ending prior to and on September 30, 2010, 4.25 to 1.0
for quarters ending December 31, 2010 to June 30, 2011 and 4.0 to 1.0 for
quarters ending September 30, 2011 and thereafter, (ii) to have a consolidated
current assets to consolidated current liabilities ratio (as defined in the
credit agreement and which includes an add back of the available borrowing
capacity under the credit agreement) of not less than 1.0 to 1.0 and (iii) to
not exceed a senior secured debt to EBITDAX ratio (as defined in the credit
agreement) for the last four quarters of 2.75 to 1.0 for quarters ending prior
to and on December 31, 2009 and 2.5 to 1.0 for quarters ending March 31, 2010
and thereafter. Except for limited exceptions, which include the
payment of dividends on the Company’s 6.25% convertible perpetual preferred
stock, the credit agreement restricts its ability to make any dividends or
distributions on its common stock or principal payments on its senior
notes. The Company was in compliance with its covenants under the
credit agreement as of September 30, 2009.
The
obligations of Whiting Oil and Gas under the credit agreement are secured by a
first lien on substantially all of Whiting Oil and Gas’ properties included in
the borrowing base for the credit agreement. Whiting Petroleum
Corporation has guaranteed the obligations of Whiting Oil and Gas under the
credit agreement and pledged the stock of Whiting Oil and Gas 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 $245.6 million as of September 30,
2009, based on quoted market prices for these same debt securities.
In
April 2005, the Company issued $220.0 million of 7.25% Senior
Subordinated Notes due 2013. These notes were issued at 98.507% of
par, and the associated discount of $3.3 million is being amortized to interest
expense over the term of these notes, yielding an effective interest rate of
7.4%. The estimated fair value of these notes was $217.8 million as
of September 30, 2009, based on quoted market prices for these same debt
securities.
In
May 2004, the Company issued $150.0 million of 7.25% Senior
Subordinated Notes due 2012. These notes were issued at 99.26% of
par, and the associated discount of $1.1 million is being amortized to interest
expense over the term of these notes, yielding an effective interest rate of
7.3%. The estimated fair value of these notes was $149.3 million
as of September 30, 2009, based on quoted market prices for these same debt
securities.
The notes
are unsecured obligations of Whiting Petroleum Corporation and are subordinated
to all of the Company’s senior debt, which currently consists of Whiting Oil and
Gas’ credit agreement. The Company’s obligations under the notes are
fully, unconditionally, jointly and severally guaranteed by all of the Company’s
wholly-owned operating subsidiaries, Whiting Oil and Gas and Whiting Programs,
Inc. (the “Guarantors”). Any subsidiaries other than the Guarantors are
minor subsidiaries as defined by Rule 3-10(h)(6) of Regulation S-X of
the Securities and Exchange Commission (“SEC”). Whiting Petroleum
Corporation has no assets or operations independent of this debt and its
investments in guarantor subsidiaries.
Interest Rate
Swap—In August 2004, the Company entered into an interest rate swap
contract to hedge the fair value of $75.0 million of its 7.25% Senior
Subordinated Notes due 2012. The interest rate swap was a fixed for
floating swap in that the Company received the fixed rate of 7.25% and paid the
floating rate. In March 2009, the counterparty exercised its option
to cancel the swap contract effective May 1, 2009, resulting in a
cancellation fee of $1.4 million paid to the Company.
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
its asset retirement obligation amounts by calculating the present value of the
estimated future cash outflows associated with its plug and abandonment
obligations. The current portions at September 30, 2009 and December
31, 2008 were $10.2 million and $6.5 million, respectively, and were recorded in
accrued liabilities. The following table provides a reconciliation of
the Company’s asset retirement obligations for the nine months ended September
30, 2009 (in thousands):
Asset
retirement obligation, January 1, 2009
|
|
$ |
54,348 |
|
Additional
liability incurred
|
|
|
499 |
|
Revisions
in estimated cash flows
|
|
|
20,751 |
|
Accretion
expense
|
|
|
5,383 |
|
Obligations
on sold properties
|
|
|
(93 |
) |
Liabilities
settled
|
|
|
(3,497 |
) |
Asset
retirement obligation, September 30, 2009
|
|
$ |
77,391 |
|
5.
|
DERIVATIVE
FINANCIAL INSTRUMENTS
|
The
Company is exposed to certain risks relating to its ongoing business
operations. The risks managed by using derivative instruments are
commodity price risk and interest rate risk.
Commodity
derivative contracts—Historically, prices
received for crude oil and natural gas production have been volatile because of
seasonal weather patterns, supply and demand factors, worldwide political
factors and general economic conditions. Whiting enters into
derivative contracts, primarily costless collars, to achieve a more predictable
cash flow by reducing its exposure to commodity price
volatility. Commodity derivative contracts are also used to ensure
adequate cash flow to fund our capital programs and to manage price risks and
returns on acquisitions and drilling programs. Costless collars are
designed to establish floor and ceiling prices on anticipated future oil and gas
production. While the use of these derivative instruments limits the
downside risk of adverse price movements, they may also limit future revenues
from favorable price movements. The Company does not enter into
derivative contracts for speculative or trading purposes.
Whiting derivatives—The table
below details the Company’s costless collar derivatives, including its
proportionate share of Trust hedges, entered into to hedge forecasted crude oil
and natural gas production revenues, as of October 1, 2009.
|
|
Whiting
Petroleum Corporation
|
|
|
|
|
|
|
NYMEX
Price Collar Ranges
|
|
|
|
Crude
Oil
|
|
|
|
|
|
Crude
Oil
|
|
|
Natural
Gas
|
|
Oct
– Dec 2009
|
|
|
1,467,570 |
|
|
|
134,622 |
|
|
|
$61.39
- $76.28 |
|
|
|
$7.00
- $14.85 |
|
Jan
– Dec 2010
|
|
|
5,046,289 |
|
|
|
495,390 |
|
|
|
$62.34
- $83.00 |
|
|
|
$6.50
- $15.06 |
|
Jan
– Dec 2011
|
|
|
4,435,039 |
|
|
|
436,510 |
|
|
|
$58.01
- $89.37 |
|
|
|
$6.50
- $14.62 |
|
Jan
– Dec 2012
|
|
|
4,065,091 |
|
|
|
384,002 |
|
|
|
$57.70
- $91.02 |
|
|
|
$6.50
- $14.27 |
|
Jan
– Nov 2013
|
|
|
3,090,000 |
|
|
|
- |
|
|
|
$55.30
- $85.68 |
|
|
|
n/a |
|
Total
|
|
|
18,103,989 |
|
|
|
1,450,524 |
|
|
|
|
|
|
|
|
|
Derivatives conveyed to Whiting USA
Trust I—In connection with the Company’s conveyance on April 30, 2008 of
a term net profits interest to the Trust and related sale of 11,677,500 Trust
units to the public (as further explained in the note on Acquisitions and
Divestitures), the right to any future hedge payments made or received by
Whiting on certain of its derivative contracts have been conveyed to the Trust,
and therefore such payments will be included in the Trust’s calculation of net
proceeds. Under the terms of the aforementioned conveyance, Whiting
retains 10% of the net proceeds from the underlying
properties. Whiting’s retention of 10% of these net proceeds,
combined with its ownership of 2,186,389 Trust units, results in third-party
public holders of Trust units receiving 75.8%, and Whiting retaining 24.2%, of
the future economic results of commodity derivative contracts conveyed to the
Trust. The relative ownership of the future economic results of such
commodity derivatives is reflected in the tables below. No additional
hedges are allowed to be placed on Trust assets.
The 24.2%
portion of Trust derivatives that Whiting has retained the economic rights to
(and which are also included in the table above) are as follows:
|
|
Whiting
Petroleum Corporation
|
|
|
|
|
|
|
NYMEX
Price Collar Ranges
|
|
|
|
Crude
Oil
|
|
|
|
|
|
Crude
Oil
|
|
|
Natural
Gas
|
|
Oct
– Dec 2009
|
|
|
33,570 |
|
|
|
134,622 |
|
|
|
$76.00
- $135.72 |
|
|
|
$7.00
- $14.85 |
|
Jan
– Dec 2010
|
|
|
126,289 |
|
|
|
495,390 |
|
|
|
$76.00
- $134.98 |
|
|
|
$6.50
- $15.06 |
|
Jan
– Dec 2011
|
|
|
115,039 |
|
|
|
436,510 |
|
|
|
$74.00
- $140.15 |
|
|
|
$6.50
- $14.62 |
|
Jan
– Dec 2012
|
|
|
105,091 |
|
|
|
384,002 |
|
|
|
$74.00
- $141.72 |
|
|
|
$6.50
- $14.27 |
|
Total
|
|
|
379,989 |
|
|
|
1,450,524 |
|
|
|
|
|
|
|
|
|
The 75.8%
portion of Trust derivative contracts for which Whiting has transferred the
economic rights to third-party public holders of Trust units (and which have not
been reflected in the above tables) are as follows:
|
|
Third-party
Public Holders of Trust Units
|
|
|
|
|
|
|
NYMEX
Price Collar Ranges
|
|
|
|
Crude
Oil
|
|
|
Natural
|
|
|
Crude
Oil
|
|
|
Natural
Gas
|
|
Oct
– Dec 2009
|
|
|
105,150 |
|
|
|
421,668 |
|
|
|
$76.00
- $135.72 |
|
|
|
$7.00
- $14.85 |
|
Jan
– Dec 2010
|
|
|
395,567 |
|
|
|
1,551,678 |
|
|
|
$76.00
- $134.98 |
|
|
|
$6.50
- $15.06 |
|
Jan
– Dec 2011
|
|
|
360,329 |
|
|
|
1,367,249 |
|
|
|
$74.00
- $140.15 |
|
|
|
$6.50
- $14.62 |
|
Jan
– Dec 2012
|
|
|
329,171 |
|
|
|
1,202,785 |
|
|
|
$74.00
- $141.72 |
|
|
|
$6.50
- $14.27 |
|
Total
|
|
|
1,190,217 |
|
|
|
4,543,380 |
|
|
|
|
|
|
|
|
|
Discontinuance of
cash flow hedge accounting—Prior to April 1, 2009, the
Company designated a portion of its commodity derivative contracts as cash flow
hedges, whose unrealized fair value gains and losses were recorded to other
comprehensive income, while the Company’s remaining commodity derivative
contracts were not designated as hedges, with gains and losses from changes in
fair value recognized immediately in earnings. Effective April 1,
2009, however, the Company elected to de-designate all of its commodity
derivative contracts that had been previously designated as cash flow hedges as
of March 31, 2009 and has elected to discontinue hedge accounting
prospectively. As a result, subsequent to March 31, 2009 the Company
recognizes all gains and losses from prospective changes in commodity derivative
fair values immediately in earnings rather than deferring any such amounts in
accumulated other comprehensive income.
At March
31, 2009, accumulated other comprehensive income consisted of $59.8 million
($36.5 million net of tax) of unrealized gains, representing the mark-to-market
value of the Company’s open commodity contracts designated as cash flow hedges
as of that balance sheet date, less any ineffectiveness
recognized. As a result of discontinuing hedge accounting on April 1,
2009, such mark-to-market values at March 31, 2009 are frozen in accumulated
other comprehensive income as of the de-designation date and reclassified into
earnings as the original hedged transactions affect income. During
the three months ended September 30, 2009, $7.8 million ($4.8 million net of
tax) of derivative gains relating to de-designated commodity hedges were
reclassified from accumulated other comprehensive income into
earnings. During the nine months ended September 30, 2009, $14.6
million ($9.2 million net of tax) of derivative gains relating to de-designated
commodity hedges were reclassified from accumulated other comprehensive income
into earnings. As of September 30, 2009, accumulated other
comprehensive income amounted to $43.0 million ($27.2 million net of tax), which
consisted entirely of unrealized deferred gains on commodity derivative
contracts that had been previously designated as cash flow
hedges. The Company expects to reclassify into earnings from
accumulated other comprehensive income net after-tax gains of $19.2 million
related to de-designated commodity hedges during the next twelve
months.
Interest rate
derivative contract—In August 2004, the Company
entered into an interest rate swap agreement to manage its exposure to interest
rate risk on a portion of its fixed-rate borrowings. The interest
rate swap effectively modified the Company’s exposure to interest rate risk by
converting the fixed rate on $75.0 million of the Company’s Senior Subordinated
Notes due 2012 to a floating rate. This agreement involved the
receipt of fixed rate amounts in exchange for floating rate interest payments
over the life of the agreement without an exchange of the underlying notional
amount. The interest rate swap was designated as a fair value
hedge. In March 2009, the counterparty exercised its option to cancel
the swap contract effective May 1, 2009, resulting in a cancellation fee of
$1.4 million paid to the Company.
SFAS
161—Effective January 1, 2009, the Company adopted Financial Accounting
Standard Board (“FASB”) Statement No. 161, Disclosure about Derivative
Instruments and Hedging Activities – an amendment to FASB Statement No.
133 (“SFAS 161”), as codified in FASB ASC topic 815, Derivatives and Hedges (“FASB
ASC 815”). SFAS 161 expands interim and annual disclosures about
derivative and hedging activities that are intended to better convey the purpose
of derivative use and the risks managed. The adoption of SFAS 161 did
not have an impact on the Company’s consolidated financial statements, other
than additional disclosures which are set forth below.
All
derivative instruments are recorded on the consolidated balance sheet at fair
value. The following tables summarize the location and fair value
amounts of all derivative instruments in the consolidated balance sheets (in
thousands).
|
|
|
|
|
|
Designated
as ASC 815 Hedges
|
|
Balance
Sheet Classification
|
|
|
|
|
|
|
Derivative
assets
|
|
|
|
|
|
|
|
|
Commodity
contracts
|
|
Current
derivative assets
|
|
$ |
- |
|
|
$ |
30,198 |
|
Commodity
contracts
|
|
Non-current
derivative assets
|
|
|
- |
|
|
|
13,163 |
|
Interest
rate swap contract
|
|
Other
long-term assets
|
|
|
- |
|
|
|
1,690 |
|
Total
derivative assets
|
|
$ |
- |
|
|
$ |
45,051 |
|
Derivative
liabilities
|
|
|
|
|
|
|
|
|
|
|
Commodity
contracts
|
|
Current
derivative liabilities
|
|
$ |
- |
|
|
$ |
4,784 |
|
Commodity
contracts
|
|
Non-current
derivative liabilities
|
|
|
- |
|
|
|
9,224 |
|
Total
derivative liabilities
|
|
$ |
- |
|
|
$ |
14,008 |
|
|
|
|
|
|
|
|
|
|
|
|
Not
Designated as ASC 815 Hedges
|
|
|
|
|
|
|
|
|
|
|
Derivative
assets
|
|
|
|
|
|
|
|
|
|
|
Commodity
contracts
|
|
Current
derivative assets
|
|
$ |
7,803 |
|
|
$ |
16,582 |
|
Commodity
contracts
|
|
Non-current
derivative assets
|
|
|
12,778 |
|
|
|
24,941 |
|
Total
derivative assets
|
|
|
20,581 |
|
|
|
41,523 |
|
Derivative
liabilities
|
|
|
|
|
|
|
|
|
|
|
Commodity
contracts
|
|
Current
derivative liabilities
|
|
$ |
25,050 |
|
|
$ |
12,570 |
|
Commodity
contracts
|
|
Non-current
derivative liabilities
|
|
|
86,197 |
|
|
|
18,907 |
|
Total
derivative liabilities
|
|
$ |
111,247 |
|
|
$ |
31,477 |
|
Commodity derivative
contracts—The following tables summarize the effects of commodity
derivatives instruments on the consolidated statements of income for the three
and nine months ended September 30, 2009 and 2008 (in thousands).
|
|
|
|
Gain
(Loss) Recognized in OCI
(Effective
Portion)
|
|
ASC
815 Cash Flow
|
|
Location
of Gain (Loss) Not
|
|
Nine
Months Ended September 30,
|
|
|
|
|
|
|
|
|
|
|
Commodity
contracts
|
|
Other
comprehensive income
|
|
$ |
21,147 |
|
|
$ |
(65,152 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended September 30,
|
|
|
|
|
|
|
2009 |
|
|
|
2008 |
|
Commodity
contracts
|
|
Other
comprehensive income
|
|
$ |
- |
|
|
$ |
61,120 |
|
|
|
|
|
Gain
(Loss) Reclassified from AOCI into Income
(Effective
Portion)
|
|
ASC
815 Cash Flow
|
|
|
|
Nine
Months Ended September 30,
|
|
|
|
Income
Statement Classification
|
|
|
|
|
|
|
Commodity
contracts
|
|
Gain
(loss) on hedging activities
|
|
$ |
28,072 |
|
|
$ |
(112,902 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended September 30,
|
|
|
|
|
|
|
2009 |
|
|
|
2008 |
|
Commodity
contracts
|
|
Gain
(loss) on hedging activities
|
|
$ |
7,774 |
|
|
$ |
(41,879 |
) |
|
|
|
|
(Gain)
Loss Recognized in Income
(Ineffective
Portion)
|
|
ASC
815 Cash Flow
|
|
|
|
Nine
Months Ended September 30,
|
|
|
|
Income
Statement Classification
|
|
|
|
|
|
|
Commodity
contracts
|
|
Commodity
derivative (gain) loss, net
|
|
$ |
22,655 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended September 30,
|
|
|
|
|
|
|
2009 |
|
|
|
2008 |
|
Commodity
contracts
|
|
Commodity
derivative (gain) loss, net
|
|
$ |
- |
|
|
$ |
- |
|
|
|
|
|
(Gain)
Loss Recognized in Income
|
|
Not
Designated as
|
|
|
|
Nine
Months Ended September 30,
|
|
|
|
Income
Statement Classification
|
|
|
|
|
|
|
Commodity
contracts
|
|
Commodity
derivative (gain) loss, net
|
|
$ |
149,251 |
|
|
$ |
7,064 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended September 30,
|
|
|
|
|
|
|
2009 |
|
|
|
2008 |
|
Commodity
contracts
|
|
Commodity
derivative (gain) loss, net
|
|
$ |
(10,391 |
) |
|
$ |
(10,561 |
) |
Fair value hedge—In March
2009, the Company’s derivative counterparty exercised its option to cancel the
Company’s interest rate swap contract effective May 1, 2009. Prior to
the cancellation, the gain or loss on the hedged item ($75.0 million of
fixed-rate borrowings under the Company’s Senior Subordinated Notes due 2012)
attributable to the hedged benchmark interest rate risk (risk of changes in the
LIBOR swap rate) and the offsetting gain or loss on the related interest rate
swap for the three and nine months ended September 30, 2009 and 2008 were as
follows (in thousands):
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30,
|
|
|
Nine
Months Ended September 30,
|
|
Income
Statement Classification
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
$ |
(330 |
) |
|
$ |
(115 |
) |
|
$ |
330 |
|
|
$ |
115 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended September 30,
|
|
|
Three
Months Ended September 30,
|
|
|
|
|
2009 |
|
|
|
2008 |
|
|
|
2009 |
|
|
|
2008 |
|
Interest
expense
|
|
$ |
- |
|
|
$ |
10 |
|
|
$ |
- |
|
|
$ |
(10 |
) |
There was
no difference, or therefore ineffectiveness, between the gain (loss) on swap and
gain (loss) on borrowing amounts in the above table because this swap met the
criteria to qualify for the “short cut” method of assessing
effectiveness. Accordingly, the change in fair value of the debt was
assumed to equal the change in the fair value of the interest rate
swap. In addition, the net swap settlements that accrued each period
were also reported in interest expense.
Contingent features in derivative
instruments—None of the Company’s derivative instruments contain
credit-risk-related contingent features. Counterparties to the
Company’s derivative contracts are high credit quality financial institutions
that are lenders under Whiting’s credit agreement. Whiting uses only
credit agreement participants to hedge with, since these institutions are
secured equally with the holders of Whiting’s bank debt, which eliminates the
potential need to post collateral when Whiting is in a large derivative
liability position. As a result, the Company is not required to post
letters of credit or corporate guarantees for the counterparty to secure
contract performance obligations.
6.
|
FAIR
VALUE MEASUREMENTS
|
The
Company follows the Fair Value
Measurement and Disclosure topic of the FASB ASC, which 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 financial assets and
liabilities measured at fair value on a recurring basis as of September 30,
2009, and indicates the fair value hierarchy of the valuation techniques
utilized by the Company to determine such fair values (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
Total
Fair Value
September
30, 2009
|
|
Financial
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivatives - current
|
|
$ |
- |
|
|
$ |
7,803 |
|
|
$ |
- |
|
|
$ |
7,803 |
|
Commodity
derivatives - non-current
|
|
|
- |
|
|
|
12,778 |
|
|
|
- |
|
|
|
12,778 |
|
Total
financial assets
|
|
$ |
- |
|
|
$ |
20,581 |
|
|
$ |
- |
|
|
$ |
20,581 |
|
Financial
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivatives - current
|
|
$ |
- |
|
|
$ |
25,050 |
|
|
$ |
- |
|
|
$ |
25,050 |
|
Commodity
derivatives - non-current
|
|
|
- |
|
|
|
86,197 |
|
|
|
- |
|
|
|
86,197 |
|
Total
financial liabilities
|
|
$ |
- |
|
|
$ |
111,247 |
|
|
$ |
- |
|
|
$ |
111,247 |
|
Commodity Derivative
Instruments—Commodity derivative instruments consist primarily of
costless collars for crude oil and natural gas. The Company’s
costless collars are valued using industry-standard modeling techniques that
consider the contractual prices for the underlying instruments as well as other
relevant economic measures. Substantially all of these assumptions
are observable in the marketplace throughout the full term of the contract, can
be derived from observable data or are supported by observable levels at which
transactions are executed in the marketplace, and are therefore 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. The Company utilizes the counterparties’ valuations to assess
the reasonableness of its own valuations.
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 nine
months ended September 30, 2009 and 2008 amounted to $10.4 million and $30.0
million, respectively, charged to general and administrative expense and $1.5
million and $4.7 million, respectively, charged to exploration
expense.
Employees
vest in the Plan ratably at 20% per year over a five year
period. Pursuant to the terms of the Plan, (i) employees who
terminate their employment with the Company are entitled to receive their vested
allocation of future Plan year payments on an annual basis; (ii) employees will
become fully vested at age 62, regardless of when their interests would
otherwise vest; and (iii) any forfeitures inure to the benefit of the
Company.
The
Company uses average historical prices to estimate the vested long-term
Production Participation Plan liability. At September 30, 2009, the
Company used three-year average historical NYMEX prices of $78.04 for crude oil
and $6.95 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 September 30,
2009, if the Company elected to terminate the Plan or if a change of control
event occurred, it is estimated that the fully vested lump sum cash payment to
employees would approximate $120.5 million. This amount includes
$19.1 million attributable to proved undeveloped oil and gas properties and
$11.9 million relating to the short-term portion of the Plan liability, which
has been accrued as a current payable to be paid in February
2010. The ultimate sharing contribution for proved undeveloped oil
and gas properties will be awarded in the year of Plan termination or change of
control. However, the Company has no intention to terminate the
Plan.
The
following table presents changes in the estimated long-term liability related to
the Plan for the nine months ended September 30, 2009 (in
thousands):
Production
Participation Plan liability, January 1, 2009
|
|
$ |
66,166 |
|
Change
in liability for accretion, vesting and changes in
estimates
|
|
|
14,903 |
|
Reduction
in liability for cash payments accrued and recognized as compensation
expense
|
|
|
(11,901 |
) |
Production
Participation Plan liability, September 30, 2009
|
|
$ |
69,168 |
|
6.25% Convertible
Perpetual Preferred Stock Offering—In June 2009, the Company completed a
public offering of 6.25% convertible perpetual preferred stock, selling
3,450,000 shares at a price of $100.00 per share and providing net proceeds of
$334.1 million after underwriters’ fees and offering expenses. The
Company used the net proceeds to repay a portion of the debt outstanding under
its credit agreement.
Each
holder of the convertible perpetual preferred stock is entitled to an annual
dividend of $6.25 per share to be paid quarterly in cash, common stock or a
combination thereof on March 15, June 15, September 15 and December 15, when and
if such dividend has been declared by Whiting’s board of
directors. Whiting paid the first dividend of $4.9 million on
September 15, 2009. Each share of convertible perpetual preferred
stock has a liquidation preference of $100.00 per share plus accumulated and
unpaid dividends and is convertible, at a holder’s option, into shares of
Whiting’s common stock based on an initial conversion price of $43.4163, subject
to adjustment upon the occurrence of certain events. The convertible
perpetual preferred stock is not redeemable by the Company. At any
time on or after June 15, 2013, the Company may cause all outstanding shares of
this preferred stock to be converted into shares of common stock if certain
conditions are met. The holders of convertible preferred stock have
no voting rights unless dividends payable on the convertible preferred stock are
in arrears for six or more quarterly periods.
Common Stock
Offering—In February 2009, the Company completed a public offering of its
common stock, selling 8,450,000 shares of common stock at a price of $29.00 per
share and providing net proceeds of $234.8 million after underwriters’ fees and
offering expenses. The Company used the net proceeds to repay a
portion of the debt outstanding under its credit agreement.
Income
tax expense during interim periods is based on applying an estimated annual
effective income tax rate to year-to-date income, plus any significant unusual
or infrequently occurring items which are recorded in the interim
period. The provision for income taxes for the nine months ended
September 30, 2009 and 2008 differs from the amount that would be provided by
applying the statutory U.S. federal income tax rate of 35% to pre-tax income
primarily because of state income taxes and estimated permanent
differences.
The
computation of the annual estimated effective tax rate at each interim period
requires certain estimates and significant judgment including, but not limited
to, the expected operating income for the year, projections of the proportion of
income earned and taxed in various jurisdictions, permanent and temporary
differences, and the likelihood of recovering deferred tax assets generated in
the current year. The accounting estimates used to compute the
provision for income taxes may change as new events occur, more experience is
acquired, additional information is obtained or as the tax environment
changes.
The
reconciliations between basic and diluted net income per share are as follows
(in thousands, except per share data):
|
|
Three
Months Ended
September
30, 2009
|
|
|
Three
Months Ended
September
30, 2008
|
|
|
|
|
|
|
Weighted
Avg Shares Outstanding
|
|
|
|
|
|
|
|
|
Weighted
Avg Shares Outstanding
|
|
|
|
|
Net
income
|
|
$ |
35,855 |
|
|
|
|
|
|
|
|
$ |
112,417 |
|
|
|
|
|
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
stock dividends declared
|
|
|
(4,911 |
) |
|
|
|
|
|
|
|
|
- |
|
|
|
|
|
|
|
Preferred
stock dividends accumulated
|
|
|
(886 |
) |
|
|
|
|
|
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted
net income available to common stockholders
|
|
$ |
30,058 |
|
|
|
50,845 |
|
|
$ |
0.59 |
|
|
$ |
112,417 |
|
|
|
42,322 |
|
|
$ |
2.66 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect
of dilutive securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted
stock and stock options
|
|
|
- |
|
|
|
329 |
|
|
|
|
|
|
|
- |
|
|
|
143 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted
net income available to common stockholders plus assumed
conversions
|
|
$ |
30,058 |
|
|
|
51,174 |
|
|
$ |
0.59 |
|
|
$ |
112,417 |
|
|
|
42,465 |
|
|
$ |
2.65 |
|
For the
three months ended September 30, 2009, the diluted earnings per share
calculation excludes the effect of 7,946,324 common shares issuable upon the
assumed conversion of the 6.25% perpetual preferred stock because their effect
was anti-dilutive.
|
|
Nine
Months Ended
September
30, 2009
|
|
|
Nine
Months Ended
September
30, 2008
|
|
|
|
|
|
|
Weighted
Avg Shares Outstanding
|
|
|
|
|
|
|
|
|
Weighted
Avg Shares Outstanding
|
|
|
|
|
Net
income (loss)
|
|
$ |
(101,067 |
) |
|
|
|
|
|
|
|
$ |
255,179 |
|
|
|
|
|
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
stock dividends declared
|
|
|
(4,911 |
) |
|
|
|
|
|
|
|
|
- |
|
|
|
|
|
|
|
Preferred
stock dividends accumulated
|
|
|
(886 |
) |
|
|
|
|
|
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted
net income available to common stockholders
|
|
$ |
(106,864 |
) |
|
|
49,774 |
|
|
$ |
(2.15 |
) |
|
$ |
255,179 |
|
|
|
42,305 |
|
|
$ |
6.03 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect
of dilutive securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted
stock and stock options
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
- |
|
|
|
159 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted
net income available to common stockholders plus assumed
conversions
|
|
$ |
(106,864 |
) |
|
|
49,774 |
|
|
$ |
(2.15 |
) |
|
$ |
255,179 |
|
|
|
42,464 |
|
|
$ |
6.01 |
|
For the
nine months ended September 30, 2009 the Company had a net
loss. Therefore, the diluted earnings per share calculation for that
period excludes the effect of 292,675 shares of restricted stock and stock
options because their effect was anti-dilutive, as well as 2,881,634 weighted
average common shares issuable upon the assumed conversion of the 6.25%
perpetual preferred stock.
11.
|
ADOPTED
AND RECENTLY ISSUED ACCOUNTING
PRONOUNCEMENTS
|
On
December 31, 2008, the SEC published the final rules and interpretations
updating its oil and gas reporting requirements. Many of the revisions are
updates to definitions in the existing oil and gas rules to make them consistent
with the petroleum resource management system, which is a widely accepted
standard for the management of petroleum resources that was developed by several
industry organizations. Key revisions include the ability to include
nontraditional resources in reserves, the use of new technology for determining
reserves, permitting disclosure of probable and possible reserves, and changes
to the pricing used to determine reserves in that companies must use a 12-month
average price. The average is calculated using the
first-day-of-the-month price for each of the 12 months that make up the
reporting period. The SEC will require companies to comply with the
amended disclosure requirements for registration statements filed after January
1, 2010, and for annual reports for fiscal years ending on or after December 31,
2009. Early adoption is not permitted. The Company is currently
assessing the impact that the adoption will have on our disclosures, operating
results, statement of financial position and statement of cash
flows.
In June
2009, the FASB issued SFAS No. 168, The FASB Accounting Standards
Codification and the Hierarchy of Generally Accepted Accounting
Principles, as codified in FASB ASC topic Generally Accepted Accounting
Principles, a replacement of FASB Statement No.
162. This standard establishes only two levels of GAAP,
authoritative and nonauthoritative. The FASB ASC was not intended to
change or alter existing GAAP, and the Company’s adoption effective July 1, 2009
did not therefore have any impact on its consolidated financial statements other
than to modify certain existing disclosures. The FASB ASC will become
the source of authoritative, nongovernmental GAAP, except for rules and
interpretive releases of the SEC, which are sources of authoritative GAAP for
SEC registrants. All other nongrandfathered, non-SEC accounting
literature not included in the FASB ASC will become
nonauthoritative. FASB ASC is effective for financial statements for
interim or annual reporting periods ending after September 15,
2009. Upon adoption the Company began to use the new guidelines and
numbering system prescribed by the FASB ASC when referring to GAAP in the third
quarter of fiscal 2009.
In May
2009, the FASB issued SFAS No. 165, Subsequent Events (“SFAS
165”), as codified in FASB ASC topic Subsequent
Events. This standard is intended to establish general
standards of accounting for and disclosure of events that occur after the
balance sheet date but before financial statements are issued or are available
to be issued. Specifically, this standard sets forth the period after
the balance sheet date during which management of a reporting entity should
evaluate events or transactions that may occur for potential recognition or
disclosure in the financial statements, the circumstances under which an entity
should recognize events or transactions occurring after the balance sheet date
in its financial statements, and the disclosures that an entity should make
about events or transactions that occurred after the balance sheet
date. SFAS 165 is effective for fiscal years and interim periods
ended after June 15, 2009. The Company adopted SFAS 165 effective
April 1, 2009, which did not have an impact on its consolidated financial
statements, other than additional disclosures.
In April
2009, the FASB issued two FASB Staff Positions (“FSP”) intended to provide
additional application guidance and enhanced disclosures regarding fair value
measurements and impairments of securities. FSP No. FAS 157-4, Determining Fair Value When the
Volume or Level of Activity for the Asset or Liability Have Significantly
Decreased and Identifying Transactions That Are Not Orderly, as codified
in FASB ASC topic Fair Value
Measurement and Disclosure, provides additional guidelines for estimating
fair value in accordance with FASB SFAS No. 157, Fair Value Measurements (“SFAS
157”). FSP No. 107-1 and APB 28-1, Interim Disclosures about Fair Value
of Financial Instruments, increases the frequency of fair value
disclosures. These FSPs are effective for fiscal years and interim
periods ended after June 15, 2009. The Company adopted these FSPs
effective April 1, 2009, which did not have an impact on its consolidated
financial statements, other than additional disclosures.
The
Company elected to implement SFAS 157 with the one-year deferral permitted by
FSP No. FAS 157-2, Effective
Date of FASB Statement No. 157 (“FSP 157-2”), issued February 2008
and codified in FASB ASC topic Fair Value Measurement and
Disclosure. FSP 157-2 deferred the effective date of SFAS 157
for one year for certain nonfinancial assets and nonfinancial liabilities
measured at fair value. Accordingly, the Company adopted SFAS 157 on
January 1, 2009 for its nonfinancial assets and nonfinancial liabilities
measured at fair value on a non-recurring basis. This deferred
adoption of SFAS 157, however, did not have an impact on the Company’s
consolidated financial statements nor its disclosures. As it relates
to the Company, this delayed adoption applies to certain nonfinancial assets and
liabilities as may be acquired in a business combination and thereby measured at
fair value; impaired oil and gas property assessments; and the initial
recognition of asset retirement obligations for which fair value is
used.
In
December 2007, the FASB issued SFAS No. 141(R), Business Combinations (“SFAS
141(R)”), which replaces SFAS No. 141, as codified in FASB ASC topic Business
Combinations. SFAS 141(R) is effective for business
combinations with acquisition dates on or after fiscal years beginning after
December 15, 2008, and the Company adopted SFAS 141(R) effective January 1,
2009. As the Company has not entered into any business combinations
during the first nine months of 2009, the adoption of SFAS 141(R) has not had
any impact on the Company’s consolidated financial statements. SFAS
141(R) establishes principles and requirements for how an acquirer recognizes
and measures in its financial statements the identifiable assets acquired, the
liabilities assumed, any noncontrolling interest in the acquiree and the
goodwill acquired. SFAS 141(R) also establishes disclosure
requirements that will enable users to evaluate the nature and financial effects
of the business combination.
|
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 and Whiting Programs,
Inc. When the context requires, we refer to these entities
separately. This document contains forward-looking statements, which
give our current expectations or forecasts of future events. Please
refer to “Forward-Looking Statements” at the end of this Item for an explanation
of these types of statements.
Overview
We are an
independent oil and gas company engaged in oil and gas acquisition, development,
exploitation, production and exploration activities primarily in the Permian
Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the
United States. Prior to 2006, we generally emphasized the acquisition
of properties that increased our production levels and provided upside potential
through further development. Since 2006, we have focused primarily on
organic drilling activity and on the development of previously acquired
properties, specifically on projects that we believe provide the opportunity for
repeatable successes and production growth. We believe the
combination of acquisitions, subsequent development and organic drilling
provides us a broad set of growth alternatives and allows us to direct our
capital resources to what we believe to be the most advantageous
investments.
As
demonstrated by our recent capital expenditure programs, we are increasingly
focused on a 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
a portion of our capital budget to leasing and exploring prospect
areas.
|
We have
historically acquired operated and non-operated properties that exceed our rate
of return criteria. For acquisitions of properties with additional
development, exploitation and exploration potential, our focus has been on
acquiring operated properties so that we can better control the timing and
implementation of capital spending. In some instances, we have been
able to acquire non-operated property interests at attractive rates of return
that established a presence in a new area of interest or that have complemented
our existing operations. We intend to continue to acquire both
operated and non-operated interests to the extent we believe they meet our
return criteria. In addition, our willingness to acquire non-operated
properties in new geographic regions provides us with geophysical and geologic
data in some cases that leads to further acquisitions in the same region,
whether on an operated or non-operated basis. We sell properties when
we believe that the sales price realized will provide an above average rate of
return for the property or when the property no longer matches the profile of
properties we desire to own.
Oil and
natural gas prices have fallen significantly since their third quarter 2008
levels. For example, the daily average NYMEX oil price was $118.13 per Bbl
for the third quarter of 2008, $58.75 per Bbl for the fourth quarter of 2008,
and $57.13 per Bbl for the first nine months of 2009. Similarly,
daily average NYMEX natural gas prices have declined from $10.27 per Mcf for the
third quarter of 2008 to $6.96 per Mcf for the fourth quarter of 2008 and $3.93
for the first nine months of 2009. Lower oil and natural gas prices
may not only decrease our revenues, but may also reduce the amount of oil and
natural gas that we can produce economically and therefore potentially lower our
reserve bookings. A substantial or extended decline in oil or natural gas
prices may result in impairments of our proved oil and gas properties and may
materially and adversely affect our future business, financial condition, cash
flows, results of operations, liquidity or ability to finance planned capital
expenditures. Lower oil and gas prices may also reduce the amount of
our borrowing base under our credit agreement, which is determined at the
discretion of the lenders based on the collateral value of our proved reserves
that have been mortgaged to the lenders. Alternatively, higher oil
and natural gas prices may result in significant non-cash mark-to-market losses
being recognized on our commodity derivatives, which may in turn cause us to
experience net losses, on a non-cash basis.
2009
Highlights and Future Considerations
6.25% Convertible Perpetual
Preferred Stock Offering. In June 2009, we completed a public
offering of 6.25% convertible perpetual preferred stock, selling 3,450,000
shares at a price of $100.00 per share and providing net proceeds of $334.1
million after underwriters’ fees and offering expenses. We used the
net proceeds to repay a portion of the debt outstanding under our credit
agreement.
Each
holder of the convertible perpetual preferred stock is entitled to an annual
dividend of $6.25 per share to be paid quarterly in cash, common stock or a
combination thereof on March 15, June 15, September 15 and December 15, when and
if such dividends are declared by our board of directors. We paid the
first dividend of $4.9 million on September 15, 2009. Each share of
convertible perpetual preferred stock has a liquidation preference of $100.00
per share plus accumulated and unpaid dividends and is convertible, at a
holder’s option, into shares of our common stock based on an initial conversion
price of $43.4163, subject to adjustment upon the occurrence of certain
events. The convertible perpetual preferred stock is not redeemable
by us. At any time on or after June 15, 2013, we may cause all
outstanding shares of convertible preferred stock to be automatically converted
into shares of common stock if certain conditions are met. The
holders of convertible preferred stock have no voting rights unless dividends
payable on the convertible preferred stock are in arrears for six or more
quarterly periods.
Sanish Field
Transaction. On June 4, 2009, we entered into a participation
agreement with a privately held independent oil company covering twenty-five
1,280-acre units and one 640-acre unit located primarily in the western portion
of the Sanish field in Mountrail County, North Dakota. Under the
terms of the agreement, the private company agreed to pay 65% of our net working
interest drilling and well completion costs to receive 50% of our working
interest and net revenue interest in the first and second wells planned for each
of the units. Pursuant to the agreement, we will remain the operator
for each unit.
At the
closing of the agreement, the private company paid us $107.3 million,
representing $6.4 million for acreage costs, $65.8 million for 65% of our cost
in 18 wells drilled or drilling and $35.1 million for a 50% interest in our
Robinson Lake gas plant and oil and gas gathering system. We used the
proceeds to repay a portion of the debt outstanding under our credit
agreement. We sold estimated proved reserves of 2.8 MMBOE as of June
1, 2009, as a result of this transaction.
Common Stock
Offering. In February 2009, we completed a public offering of
our common stock, selling 8,450,000 shares of common stock at a price of $29.00
per share and providing net proceeds of $234.8 million after underwriters’ fees
and offering expenses. We used the net proceeds to repay a portion of
the debt outstanding under our credit agreement.
Operational
Highlights. Our Sanish and Parshall fields in Mountrail
County, North Dakota target the Bakken formation. Net production in
the Sanish field increased 80% from a net 5.9 MBOE/d in September 2008 to a net
10.6 MBOE/d in September 2009. Net production in the Parshall field
increased 4% from a net 6.6 MBOE/d in September 2008 to a net 6.8 MBOE/d in
September 2009.
We
continue to have significant development and related infrastructure activity on
the Postle and North Ward Estes fields acquired in 2005, which have resulted in
reserve and production increases. Our expansion of the CO2 flood at
both fields continues to generate positive results. During the first
nine months of 2009, we incurred $122.5 million of development expenditures on
these two projects.
The
Postle field is located in Texas County, Oklahoma. Four of our five
producing units are currently under active CO2 enhanced
recovery projects. As of October 16, 2009, we were injecting 140
MMcf/d of CO2 in this
field. Production from the field has increased 32% from a net 6.8
MBOE/d in September 2008 to a net 9.0 MBOE/d in September 2009.
The North
Ward Estes field is located in Ward and Winkler Counties, Texas and is
responding positively to our water and CO2 floods,
which we initiated in Phase I during May 2007. In early March 2009,
we began CO2
injection in Phase II of the project. As of October 16, 2009,
we were injecting 199 MMcf/d of CO2 in this
field. Production from the field remained consistent at a net 6.6
MBOE/d from September 2008 to September 2009. In this field, we are
developing new and reactivated wells for water and CO2 injection
and production purposes. Additionally, we plan to install oil, gas
and water processing facilities in four phases through 2015, and we estimate
that the first three phases will be substantially complete by December
2009.
Results
of Operations
Nine
Months Ended September 30, 2009 Compared to Nine Months Ended September 30,
2008
Selected
Operating Data:
|
|
Nine
Months Ended
September
30,
|
|
|
|
|
|
|
|
|
Net
production:
|
|
|
|
|
|
|
Oil
(MMBbls)
|
|
|
11.3 |
|
|
|
8.7 |
|
Natural
gas (Bcf)
|
|
|
22.6 |
|
|
|
22.4 |
|
Total
production (MMBOE)
|
|
|
15.1 |
|
|
|
12.4 |
|
|
|
|
|
|
|
|
|
|
Net
sales (in millions):
|
|
|
|
|
|
|
|
|
Oil
(1)
|
|
$ |
539.6 |
|
|
$ |
904.1 |
|
Natural
gas (1)
|
|
|
77.0 |
|
|
|
198.6 |
|
Total
oil and natural gas sales
|
|
$ |
616.6 |
|
|
$ |
1,102.7 |
|
|
|
|
|
|
|
|
|
|
Average
sales prices:
|
|
|
|
|
|
|
|
|
Oil
(per Bbl)
|
|
$ |
47.79 |
|
|
$ |
104.21 |
|
Effect
of oil hedges on average price (per Bbl)
|
|
|
0.07 |
|
|
|
(13.01 |
) |
Oil
net of hedging (per Bbl)
|
|
$ |
47.86 |
|
|
$ |
91.20 |
|
Average
NYMEX price
|
|
$ |
57.13 |
|
|
$ |
113.38 |
|
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$ |
3.41 |
|
|
$ |
8.87 |
|
Effect
of natural gas hedges on average price (per Mcf)
|
|
|
0.05 |
|
|
|
- |
|
Natural
gas net of hedging (per Mcf)
|
|
$ |
3.46 |
|
|
$ |
8.87 |
|
Average
NYMEX price
|
|
$ |
3.93 |
|
|
$ |
9.75 |
|
|
|
|
|
|
|
|
|
|
Cost
and expense (per BOE):
|
|
|
|
|
|
|
|
|
Lease
operating expenses
|
|
$ |
11.78 |
|
|
$ |
14.33 |
|
Production
taxes
|
|
$ |
2.87 |
|
|
$ |
5.80 |
|
Depreciation,
depletion and amortization expense
|
|
$ |
20.04 |
|
|
$ |
14.47 |
|
General
and administrative expenses
|
|
$ |
2.03 |
|
|
$ |
4.18 |
|
(1) Before
consideration of hedging transactions.
Oil and Natural Gas
Sales. Our oil and natural gas sales revenue decreased $486.1
million to $616.6 million in the first nine months of 2009 compared to the same
period in 2008. Sales are a function of volumes sold and average
sales prices. Our oil sales volumes increased 30% between periods,
while our natural gas sales volumes increased 1%. 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 area
increased 2,300 MBbl compared to the first nine months of 2008, while Postle oil
production increased 490 MBbl and North Ward Estes oil production increased 330
MBbl over the same prior year period. These production increases were
partially offset by the Whiting USA Trust I (the “Trust”) divestiture,
which decreased oil production by 205 MBbl, as well as normal field production
decline. The gas volume increase between periods was primarily the
result of incremental gas production of 1,450 MMcf from the Flat Rock
acquisition, which we completed on May 30, 2008, and higher production volumes
of 1,300 MMcf, 1,150 MMcf and 990 MMcf due to well completions in the Boies
Ranch area, North Dakota Bakken area and Gulf Coast region,
respectively. These production increases were partially offset by the
Trust divestiture, which decreased gas production by 1,035 MMcf, as well as
normal field production decline. Offsetting the production increases
were declines in average sales prices. Our average price for oil
before the effects of hedging decreased 54% between periods, and our average
price for natural gas before the effects of hedging decreased 62%.
Gain (Loss) on Hedging
Activities. Realized cash settlements on commodity derivatives that
we have designated as cash flow hedges are recognized as gain (loss) on hedging
activities. During the first nine months of 2009, we incurred cash
settlement gains of $13.4 million on such crude oil hedges. During
the first nine months of 2008, we incurred realized cash settlement losses of
$112.9 million on crude oil derivatives designated as cash flow hedges.
None of our natural gas derivatives were designated as cash flow hedges during
the first nine months of 2009 or 2008. Effective April 1, 2009, we elected
to de-designate all of our commodity derivative contracts that had been
previously designated as cash flow hedges as of March 31, 2009 and have elected
to discontinue hedge accounting prospectively. As a result, we
reclassified from accumulated other comprehensive income into earnings $14.6
million in unrealized non-cash gains upon the expiration of these de-designated
crude oil hedges from April 1 to September 30, 2009. See Item 3,
“Qualitative and Quantitative Disclosures About Market Risk” for a list of our
outstanding oil and natural gas derivatives as of October 1, 2009.
Amortization of Deferred Gain on
Sale. In connection with the sale of 11,677,500 Trust units to the
public and related oil and gas property conveyance on April 30, 2008, we
recognized a deferred gain on sale of $100.1 million. This deferred gain
is amortized to income over the life of the Trust on a units-of-production
basis. For the nine months ended September 30, 2009 and 2008, we
recognized $12.6 million and $7.7 million, respectively, in income as
amortization of deferred gain on sale.
Gain on Sale of
Properties.
During the nine months ended September 30, 2009, we entered into a
participation agreement with a privately held independent oil company covering
acreage located primarily in the western portion of the Sanish field in
Mountrail County, North Dakota. At the closing of the agreement, the
private company paid us $107.3 million, resulting in a pre-tax gain on sale of
$4.6 million. In addition, we sold our interest in several non-core
properties for an aggregate amount of $1.3 million in cash and recognized a
pre-tax gain on sale of $1.1 million. There was no gain or loss on
the sale of properties during the nine months ended September 30,
2008.
Lease Operating
Expenses. Our lease operating expenses during the first nine
months of 2009 were $177.3 million, a $0.5 million decrease over the same period
in 2008. Our lease operating expenses per BOE decreased from $14.33
during the first nine months of 2008 to $11.78 during the first nine months of
2009. The decrease of 18% on a BOE basis was primarily caused by
increased production and a decrease of $11.3 million in electric power and fuel
costs during the first nine months of 2009 as compared to the same period in
2008, partially offset by a high level of workover
activity. Workovers amounted to $37.8 million in the first nine
months of 2009, as compared to $17.8 million in the same period of
2008. The increase in workover activity primarily relates to our two
CO2
projects, which are evolving past the construction and start-up phases and
moving into an ongoing maintenance and repair phase that involves a
significantly higher number of producing wells and injection wells.
Production
Taxes. The production taxes we pay are generally calculated as
a percentage of oil and natural gas sales revenue before the effects of
hedging. We take advantage of all credits and exemptions allowed in
our various taxing jurisdictions. Our production taxes during the
first nine months of 2009 were $43.2 million, a $28.8 million decrease over the
same period in 2008, primarily due to lower oil and natural gas
sales. For the first nine months of 2009 and 2008, our production
taxes were 7.0% and 6.5%, respectively, of oil and natural gas
sales. Our production tax rate for the first nine months of 2009 was
greater than the rate for same period in 2008 mainly due to successful wells
that were completed in the North Dakota Bakken area during the latter half of
2008 and first nine months of 2009 and that carry an 11.5% production tax
rate.
Depreciation, Depletion and
Amortization. Our depreciation, depletion and amortization
(“DD&A”) expense increased $122.1 million as compared to the first nine
months of 2008. The components of our DD&A expense were as
follows (in thousands):
|
|
Nine
Months Ended
September
30,
|
|
|
|
|
|
|
|
|
Depletion
|
|
$ |
293,869 |
|
|
$ |
174,715 |
|
Depreciation
|
|
|
2,370 |
|
|
|
2,499 |
|
Accretion
of asset retirement obligations
|
|
|
5,383 |
|
|
|
2,341 |
|
Total
|
|
$ |
301,622 |
|
|
$ |
179,555 |
|
DD&A
increased $122.1 million primarily due to $119.2 million in higher depletion
expense between periods. Of this $119.2 million increase in
depletion, $37.2 million related to higher oil and gas volumes produced during
the first nine months of 2009, while $82.0 million related to our higher
depletion rate in 2009. On a BOE basis, our DD&A rate increased
by 38% from $14.47 for the first nine months of 2008 to $20.04 for the first
nine months of 2009. The primary factors causing this rate increase
were (i) $595.5 million in drilling expenditures incurred during the past twelve
months, (ii) net oil and natural gas reserve reductions of 11.6 MMBOE during
2008, which were primarily attributable to a 39.0 MMBOE downward revision for
lower oil and natural gas prices at December 31, 2008, and (iii) the significant
expenditures necessary to develop proved undeveloped reserves, particularly
related to the enhanced oil recovery projects in the Postle and North Ward Estes
fields, whereby the development of proved undeveloped reserves does not increase
existing quantities of proved reserves. Under the successful efforts
method of accounting, costs to develop proved undeveloped reserves are added
into the DD&A rate when incurred.
Exploration and Impairment
Costs. Our exploration and impairment costs increased $9.0
million, as compared to the first nine months of 2008. The components
of exploration and impairment costs were as follows (in thousands):
|
|
Nine
Months Ended
September
30,
|
|
|
|
|
|
|
|
|
Exploration
|
|
$ |
24,785 |
|
|
$ |
21,550 |
|
Impairment
|
|
|
14,743 |
|
|
|
9,016 |
|
Total
|
|
$ |
39,528 |
|
|
$ |
30,566 |
|
Exploration
costs increased $3.2 million during the first nine months of 2009 as compared to
the same period in 2008 primarily due to rig termination fees recognized during
2009, partially offset by decreased accrued Production Participation Plan
payments for geological and geophysical (“G&G”) personnel. Rig
termination fees totaled $6.5 million during the first nine months of 2009,
while we did not pay any rig termination fees in the first nine months of
2008. Accrued Production Participation Plan distributions for
exploration personnel were $3.2 million lower during the first nine months of
2009 as compared to the same prior year period primarily due to decreased net
oil and gas sales. During the first nine months of 2009, we drilled
one exploratory dry hole in the Rocky Mountain region totaling $2.3 million,
while during the same period in 2008 we drilled one exploratory dry hole in the
Permian region totaling $1.5 million. The impairment charges in the
first nine months of 2009 and 2008 were primarily related to the amortization of
leasehold costs associated with individually insignificant unproved
properties. As of September 30, 2009, the amount of unproved
properties being amortized totaled $81.6 million, as compared to $72.2 million
as of September 30, 2008. Also lending to the increase in impairment
expense during the 2009 period was $3.1 million in non-cash impairment charges
for the partial write-down of certain proved properties whose net book values
exceeded their undiscounted future cash flows.
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):
|
|
Nine
Months Ended
September
30,
|
|
|
|
|
|
|
|
|
General
and administrative expenses
|
|
$ |
68,100 |
|
|
$ |
82,411 |
|
Reimbursements
and allocations
|
|
|
(37,524 |
) |
|
|
(30,508 |
) |
General
and administrative expense, net
|
|
$ |
30,576 |
|
|
$ |
51,903 |
|
General
and administrative expense before reimbursements and allocations decreased $14.3
million to $68.1 million during the first nine months of 2009. The
largest component of the decrease related to $22.8 million in lower accrued
distributions under our Production Participation Plan (“Plan”) between periods
due to (i) a lower level of Plan net revenues (which have been reduced by lease
operating expenses and production taxes pursuant to the Plan formula) resulting
from lower oil and natural gas prices during the first nine months of 2009 as
compared to the same period of 2008, and (ii) the Trust divestiture completed in
April 2008 which increased 2008 accrued distributions under the
Plan. These lower accrued Plan distributions were partially offset by
$4.8 million in additional employee compensation for personnel hired during the
past twelve months as well as general pay increases. The increase in
reimbursements and allocations in 2009 was primarily caused by higher salary
costs and a greater number of field workers on operated
properties. Our general and administrative expense, net as a
percentage of oil and natural gas sales remained constant at 5% for the first
nine months of 2009 and 2008.
Interest
Expense. The components of our interest expense were as
follows (in thousands):
|
|
Nine
Months Ended
September
30,
|
|
|
|
|
|
|
|
|
Senior
Subordinated Notes
|
|
$ |
32,826 |
|
|
$ |
32,698 |
|
Credit
Agreement
|
|
|
10,589 |
|
|
|
13,410 |
|
Amortization
of debt issue costs and debt discount
|
|
|
6,916 |
|
|
|
3,618 |
|
Other
|
|
|
1,366 |
|
|
|
1,090 |
|
Capitalized
interest
|
|
|
(2,677 |
) |
|
|
(2,056 |
) |
Total
|
|
$ |
49,020 |
|
|
$ |
48,760 |
|
The
increase in interest expense of $0.3 million between periods was mainly due to
higher debt issue cost amortization associated with additional issuance costs
incurred in April 2009 when renewing our credit agreement. This
increase in interest expense was partially offset by lower effective interest
rates on our credit agreement. Our weighted average effective cash
interest rate was 5.4% during the first nine months of 2009 compared to 6.2%
during the first nine months of 2008. Our weighted average debt
outstanding during the first nine months of 2009 was $1,080.8 million versus
$1,002.6 million for the first nine months of 2008. After inclusion
of non-cash interest costs for the amortization of debt issue costs, debt
discounts and the accretion of the tax sharing liability, our weighted average
effective all-in interest rate was 6.2% during the first nine months of 2009
compared to 6.6% during the first nine months of 2008.
Change in Production Participation
Plan Liability. For the nine months ended September 30, 2009,
this non-cash expense was $3.0 million, a decrease of $24.0 million as compared
to the same period in 2008. This expense represents the change in the
vested present value of estimated future payments to be made after 2010 to
participants under our Plan. Although payments take place over the
life of the Plan’s oil and gas properties, which for some properties is over 20
years, we expense the present value of estimated future payments over the Plan’s
five-year vesting period. This expense in 2009 and 2008 primarily
reflected (i) changes to future cash flow estimates stemming from the
volatile commodity price environment during the first nine months of each
respective year, (ii) recent drilling activity and property acquisitions, and
(iii) employees’ continued vesting in the Plan. The average
NYMEX prices used to estimate this liability decreased by $1.40 for crude oil
and $0.69 for natural gas for the nine months ended September 30, 2009, as
compared to increases of $20.95 for crude oil and $0.71 for natural gas over the
same period in 2008. Assumptions that are used to calculate this
liability are subject to estimation and will vary from year to year based on the
current market for oil and gas, discount rates and overall market
conditions.
Commodity Derivative (Gain) Loss,
Net. During 2008, we entered into certain commodity derivative
contracts that we did not designate as cash flow hedges. In addition,
effective April 1, 2009, we elected to de-designate all of our commodity
derivative contracts that had been previously designated as cash flow hedges as
of March 31, 2009 and have elected to discontinue hedge accounting
prospectively. Accordingly, beginning April 1, 2009 all of our
derivative contracts are marked-to-market each quarter with fair value gains and
losses recognized immediately in earnings. Cash flow is only impacted
to the extent that actual cash settlements under these contracts result in
making or receiving a payment from the counterparty, and such cash settlement
gains and losses are also recorded immediately to earnings as commodity
derivative (gain) loss, net. The components of our commodity
derivative (gain) loss, net were as follows (in thousands):
|
|
Nine
Months Ended
September
30,
|
|
|
|
|
|
|
|
|
Change
in unrealized losses on derivative contracts
|
|
$ |
137,616 |
|
|
$ |
7,021 |
|
Realized
cash settlement losses
|
|
|
11,635 |
|
|
|
43 |
|
Loss
on hedging ineffectiveness
|
|
|
22,655 |
|
|
|
- |
|
Total
|
|
$ |
171,906 |
|
|
$ |
7,064 |
|
The
increase of $130.6 million in unrealized losses on derivative contracts during
the first nine months of 2009 as compared to the same prior year period was due
to the fact that (i) we averaged 20.5 MMBbls of crude oil hedged during the nine
months ended September 30, 2009, while we only averaged 2.7 MMBbls of crude oil
hedged during the nine months ended September 30, 2008, and (ii) there was
a more significant upward shift in the forward price curve for NYMEX
crude oil during the nine months ended September 30, 2009 as compared to the
upward shift in the same price curve during the nine months ended September 30,
2008.
Income Tax Expense
(Benefit). Income tax benefit totaled $51.8 million for the
first nine months of 2009, versus $148.4 million of income tax expense for the
first nine months of 2008. Our effective income tax rate decreased
from 36.8% for the first nine months of 2008 to 33.9% for the first nine months
of 2009. Our pre-tax book loss when taken together with our permanent
items resulted in a decrease in our overall effective tax rate. This
decrease, however, was partially offset by an increase in our effective tax rate
caused by a change in our drilling activity in various states.
Net Income (Loss) Available to
Common Shareholders. Net income (loss) available to common
shareholders decreased from $255.2 million in income during the first nine
months of 2008 to a $106.0 million loss during the first nine months of
2009. The primary reasons for this decrease include a 48% decrease in
oil prices (net of hedging); a 61% decrease in natural gas prices (net of
hedging); higher unrealized commodity derivative losses, DD&A, exploration
and impairment, interest expense and dividends paid on preferred
stock. These negative factors were partially offset by a 21% increase
in equivalent volumes sold; lower lease operating expenses, production taxes,
general and administrative expenses, Production Participation Plan expense and
income taxes; and higher amortization of deferred gain on sale, as well as the
gain on sale of properties during the first nine months of 2009.
Three
Months Ended September 30, 2009 Compared to Three Months Ended September 30,
2008
Selected
Operating Data:
|
|
Three
Months Ended
September
30,
|
|
|
|
|
|
|
|
|
Net
production:
|
|
|
|
|
|
|
Oil
(MMBbls)
|
|
|
3.9 |
|
|
|
3.3 |
|
Natural
gas (Bcf)
|
|
|
7.1 |
|
|
|
8.2 |
|
Total
production (MMBOE)
|
|
|
5.1 |
|
|
|
4.6 |
|
|
|
|
|
|
|
|
|
|
Net
sales (in millions):
|
|
|
|
|
|
|
|
|
Oil
(1)
|
|
$ |
232.3 |
|
|
$ |
354.8 |
|
Natural
gas (1)
|
|
|
23.8 |
|
|
|
70.6 |
|
Total
oil and natural gas sales
|
|
$ |
256.1 |
|
|
$ |
425.4 |
|
|
|
|
|
|
|
|
|
|
Average
sales prices:
|
|
|
|
|
|
|
|
|
Oil
(per Bbl)
|
|
$ |
58.86 |
|
|
$ |
108.04 |
|
Effect
of oil hedges on average price (per Bbl)
|
|
|
(2.42 |
) |
|
|
(12.76 |
) |
Oil
net of hedging (per Bbl)
|
|
$ |
56.44 |
|
|
$ |
95.28 |
|
Average
NYMEX price
|
|
$ |
68.29 |
|
|
$ |
118.13 |
|
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$ |
3.35 |
|
|
$ |
8.65 |
|
Effect
of natural gas hedges on average price (per Mcf)
|
|
|
0.05 |
|
|
|
- |
|
Natural
gas net of hedging (per Mcf)
|
|
$ |
3.40 |
|
|
$ |
8.65 |
|
Average
NYMEX price
|
|
$ |
3.40 |
|
|
$ |
10.27 |
|
|
|
|
|
|
|
|
|
|
Cost
and expense (per BOE):
|
|
|
|
|
|
|
|
|
Lease
operating expenses
|
|
$ |
11.46 |
|
|
$ |
13.93 |
|
Production
taxes
|
|
$ |
3.66 |
|
|
$ |
6.08 |
|
Depreciation,
depletion and amortization expense
|
|
$ |
19.74 |
|
|
$ |
15.99 |
|
General
and administrative expenses
|
|
$ |
2.21 |
|
|
$ |
3.72 |
|
(1) Before
consideration of hedging transactions.
Oil and Natural Gas
Sales. Our oil and natural gas sales revenue decreased $169.3
million to $256.1 million in the third quarter of 2009 compared to the same
period in 2008. Sales are a function of volumes sold and average
sales prices. Our oil sales volumes increased 20% between periods,
while our natural gas sales volumes decreased 13%. 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
480 MBbl compared to the third quarter of 2008, while Postle oil production
increased 195 MBbl and North Ward Estes oil production increased 95 MBbl over
the same prior year period. These production increases were partially
offset by normal field production decline. The gas volume decrease
between periods was primarily the result of normal field production decline
across all of our regions. These production decreases were partially
offset by higher production volumes in the North Dakota Bakken area of 495 MMcf
due to new wells drilled. Offsetting the overall production increases
were lower average sales prices. Our average price for oil before the
effects of hedging decreased 46% between periods, and our average price for
natural gas before the effects of hedging decreased 61%.
Gain (Loss) on Hedging
Activities. Realized cash settlements on commodity derivatives that
we have designated as cash flow hedges are recognized as gain (loss) on hedging
activities. Effective April 1, 2009, we elected to de-designate
all of our commodity derivative contracts that had been previously designated as
cash flow hedges as of March 31, 2009 and have elected to discontinue hedge
accounting prospectively. As a result, we reclassified from accumulated
other comprehensive income into earnings $7.8 million in unrealized non-cash
gains upon the expiration of these de-designated crude oil hedges during the
third quarter of 2009. None of our oil derivatives were designated as
cash flow hedges during the third quarter of 2009. During the third
quarter of 2008, we incurred realized cash settlement losses of $41.9 million on
crude oil derivatives designated as cash flow hedges. None of our natural
gas derivatives were designated as cash flow hedges during the third quarter of
2009 or 2008. See Item 3, “Qualitative and Quantitative Disclosures
About Market Risk” for a list of our outstanding oil and natural gas derivatives
as of October 1, 2009.
Amortization of Deferred Gain on
Sale. In connection with the sale of 11,677,500 Trust units to the
public and related oil and gas property conveyance on April 30, 2008, we
recognized a deferred gain on sale of $100.1 million. This deferred gain
is amortized to income over the life of the Trust on a units-of-production
basis. For the three months ended September 30, 2009 and 2008, we
recognized $4.2 million and $4.7 million, respectively, in income as
amortization of deferred gain on sale.
Gain on Sale of
Properties.
During the three months ended September 30, 2009, we sold our interest in
several non-core properties for an aggregate amount of $0.7 million in cash and
recognized a pre-tax gain on sale of $1.1 million. There was no gain
or loss on the sale of properties during the three months ended
September 30, 2008.
Lease Operating
Expenses. Our lease operating expenses during the third
quarter of 2009 were $58.8 million, a $5.9 million decrease over the same period
in 2008. Our lease operating expenses per BOE decreased from $13.93
during the third quarter of 2008 to $11.46 during the third quarter of
2009. The decrease of 18% on a BOE basis was primarily caused by
increased production and decreased electric power and fuel costs of $5.0 million
during the third quarter of 2009 as compared to the same period in 2008,
partially offset by a high level of workover activity. Workovers
amounted to $11.6 million in the third quarter of 2009, as compared to
$9.4 million in the third quarter of 2008. The increase in
workover activity primarily relates to our two CO2 projects,
which are evolving past the construction and start-up phases and moving into an
ongoing maintenance and repair phase that involves a significantly higher number
of producing wells and injection wells.
Production
Taxes. The production taxes we pay are generally calculated as
a percentage of oil and natural gas sales revenue before the effects of
hedging. We take advantage of all credits and exemptions allowed in
our various taxing jurisdictions. Our production taxes during the
third quarter of 2009 were $18.8 million, a $9.5 million decrease over the same
period in 2008, primarily due to lower oil and natural gas sales. For
the third quarter of 2009 and 2008, our production taxes were 7.3% and 6.6%,
respectively, of oil and natural gas sales. Our production tax rate
for the third quarter of 2009 was greater than the rate for same period in 2008
mainly due to successful wells that were completed in the North Dakota Bakken
area during the latter half of 2008 and first nine months of 2009 and that carry
an 11.5% production tax rate.
Depreciation, Depletion and
Amortization. Our depreciation, depletion and amortization
(“DD&A”) expense increased $27.0 million as compared to the third quarter of
2008. The components of our DD&A expense were as follows (in
thousands):
|
|
Three
Months Ended
September
30,
|
|
|
|
|
|
|
|
|
Depletion
|
|
$ |
98,876 |
|
|
$ |
72,464 |
|
Depreciation
|
|
|
771 |
|
|
|
905 |
|
Accretion
of asset retirement obligations
|
|
|
1,626 |
|
|
|
864 |
|
Total
|
|
$ |
101,273 |
|
|
$ |
74,233 |
|
DD&A
increased $27.0 million primarily due to $26.4 million in higher depletion
expense between periods. Of this $26.4 million increase in depletion,
$7.6 million related to higher oil and gas volumes produced during the third
quarter of 2009, while $18.8 million related to our higher depletion rate in
2009. On a BOE basis, our DD&A rate increased by 23% from $15.99
for the third quarter of 2008 to $19.74 for the third quarter of
2009. The primary factors causing this rate increase were (i) $595.5
million in drilling expenditures incurred during the past twelve months, (ii)
net oil and natural gas reserve reductions of 11.6 MMBOE during 2008, which were
primarily attributable to a 39.0 MMBOE downward revision for lower oil and
natural gas prices at December 31, 2008, and (iii) the significant expenditures
necessary to develop proved undeveloped reserves, particularly related to the
enhanced oil recovery projects in the Postle and North Ward Estes fields,
whereby the development of proved undeveloped reserves does not increase
existing quantities of proved reserves. Under the successful efforts
method of accounting, costs to develop proved undeveloped reserves are added
into the DD&A rate when incurred.
Exploration and Impairment
Costs. Our exploration and impairment costs increased $1.5
million, as compared to the third quarter of 2008. The components of
exploration and impairment costs were as follows (in thousands):
|
|
Three
Months Ended
September
30,
|
|
|
|
|
|
|
|
|
Exploration
|
|
$ |
5,973 |
|
|
$ |
7,323 |
|
Impairment
|
|
|
6,449 |
|
|
|
3,616 |
|
Total
|
|
$ |
12,422 |
|
|
$ |
10,939 |
|
Exploration
costs decreased $1.4 million during the third quarter of 2009 as compared to the
same period in 2008 primarily due to a decrease in accrued Production
Participation Plan payments for exploration personnel, partially offset by an
increase in exploratory dry hole costs. Accrued Production
Participation Plan distributions for exploration personnel were $0.7 million
lower during the third quarter of 2009 as compared to the same prior year
period. During the third quarter of 2009, we drilled one exploratory
dry hole in the Rocky Mountain region totaling $2.3 million, while during the
same period in 2008 we drilled one exploratory dry hole in the Permian region
totaling $1.5 million. The impairment charges in the third quarter of
2009 and 2008 were primarily related to the amortization of leasehold costs
associated with individually insignificant unproved properties. As of
September 30, 2009, the amount of unproved properties being amortized totaled
$81.6 million, as compared to $72.2 million as of September 30,
2008. Also lending to the increase in impairment expense during the
2009 period was $2.3 million in non-cash impairment charges for the partial
write-down of certain proved properties whose net book values exceeded their
undiscounted future cash flows.
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
September
30,
|
|
|
|
|
|
|
|
|
General
and administrative expenses
|
|
$ |
24,417 |
|
|
$ |
28,096 |
|
Reimbursements
and allocations
|
|
|
(13,103 |
) |
|
|
(10,815 |
) |
General
and administrative expense, net
|
|
$ |
11,314 |
|
|
$ |
17,281 |
|
General
and administrative expense before reimbursements and allocations decreased $3.7
million to $24.4 million during the third quarter of 2009. The
largest component of the decrease related to $5.5 million in lower accrued
distributions under our Production Participation Plan (“Plan”) between periods
due to a lower level of Plan net revenues (which have been reduced by lease
operating expenses and production taxes pursuant to the Plan formula) resulting
from lower oil and natural gas prices during the third quarter of 2009 as
compared to the same period of 2008. These lower accrued Plan
distributions were partially offset by $1.2 million in additional employee
compensation for personnel hired during the past twelve months as well as
general pay increases. The increase in reimbursements and allocations
in 2009 was primarily caused by higher salary costs and a greater number of
field workers on operated properties. Our general and administrative
expense, net as a percentage of oil and natural gas sales remained constant at
4% for the third quarter of 2009 and 2008.
Interest
Expense. The components of our interest expense were as
follows (in thousands):
|
|
Three
Months Ended
September
30,
|
|
|
|
|
|
|
|
|
Senior
Subordinated Notes
|
|
$ |
11,081 |
|
|
$ |
10,755 |
|
Credit
Agreement
|
|
|
2,436 |
|
|
|
5,757 |
|
Amortization
of debt issue costs and debt discount
|
|
|
2,561 |
|
|
|
1,195 |
|
Other
|
|
|
433 |
|
|
|
358 |
|
Capitalized
interest
|
|
|
(864 |
) |
|
|
(522 |
) |
Total
|
|
$ |
15,647 |
|
|
$ |
17,543 |
|
The
decrease in interest expense of $1.9 million between periods was mainly due to a
lower level of debt outstanding and lower interest rates on borrowings under our
credit agreement during the third quarter of 2009, partially offset by an
increase in debt issue cost amortization associated with additional issuance
costs incurred in April 2009 when renewing our credit agreement. Due
to lower borrowings outstanding under our credit agreement during the third
quarter 2009, our weighted average effective cash interest rate was 6.6%
compared to 5.8% during the third quarter of 2008. Our weighted
average debt outstanding during the third quarter of 2009 was $824.9 million
versus $1,147.6 million for the third quarter of 2008. After
inclusion of non-cash interest costs for the amortization of debt issue costs,
debt discounts and the accretion of the tax sharing liability, our weighted
average effective all-in interest rate was 7.8% during the third quarter of 2009
compared to 6.2% during the third quarter of 2008.
Change in Production Participation
Plan Liability. For the three months ended September 30, 2009,
the Production Participation Plan liability decreased $0.7 million, while the
liability increased $9.1 million in the same period in 2008. This
expense represents the change in the vested present value of estimated future
payments to be made after 2010 to participants under our
Plan. Although payments take place over the life of the Plan’s oil
and gas properties, which for some properties is over 20 years, we expense the
present value of estimated future payments over the Plan’s five-year vesting
period. This expense in 2009 and 2008 primarily reflected (i) changes
to future cash flow estimates stemming from the volatile commodity price
environment during the third quarter of each respective year, (ii) recent
drilling activity and property acquisitions, and (iii) employees’ continued
vesting in the Plan. The average NYMEX prices used to estimate this
liability decreased by $0.59 for crude oil and $0.22 for natural gas for the
three months ended September 30, 2009, as compared to increases of $5.44
for crude oil and $0.03 for natural gas over the same period in
2008. Assumptions that are used to calculate this liability are
subject to estimation and will vary from year to year based on the current
market for oil and gas, discount rates and overall market
conditions.
Commodity Derivative (Gain) Loss,
Net. During 2008, we entered into certain commodity derivative
contracts that we did not designate as cash flow hedges. In addition,
effective April 1, 2009, we elected to de-designate all of our commodity
derivative contracts that had been previously designated as cash flow hedges as
of March 31, 2009 and have elected to discontinue hedge accounting
prospectively. Accordingly, beginning April 1, 2009 all of our
derivative contracts are marked-to-market each quarter with fair value gains and
losses recognized immediately in earnings. Cash flow is only impacted
to the extent that actual cash settlements under these contracts result in
making or receiving a payment from the counterparty, and such cash settlement
gains and losses are also recorded immediately to earnings as commodity
derivative (gain) loss, net. The components of our commodity
derivative (gain) loss, net were as follows (in thousands):
|
|
Three
Months Ended
September
30,
|
|
|
|
|
|
|
|
|
Change
in unrealized (gains) losses on derivative contracts
|
|
$ |
(19,567 |
) |
|
$ |
(10,604 |
) |
Realized
cash settlement losses
|
|
|
9,176 |
|
|
|
43 |
|
Total
|
|
$ |
(10,391 |
) |
|
$ |
(10,561 |
) |
The
increase of $9.0 million in unrealized gains on derivative contracts during the
third quarter of 2009 as compared to the same prior year period was due to the
fact that (i) we averaged 18.9 MMBbls of crude oil hedged during the three
months ended September 30, 2009, while we only averaged 2.0 MMBbls of crude oil
hedged during the three months September 30, 2008, and (ii) there was a larger
downward shift in the forward price curve for NYMEX crude oil during the three
months ended September 30, 2009 as compared to the downward shift in the same
price curve during the third quarter of 2008.
Income Tax Expense
(Benefit). Income tax expense totaled $26.3 million for the
third quarter of 2009, versus $64.5 million for the third quarter of
2008. Our effective income tax rate increased from 36.5% for the
third quarter of 2008 to 42.3% for the third quarter of 2009. Losses
in the first two quarters and increased earnings in the third quarter resulted
in an increase in our effective tax rate in the third quarter of
2009. In addition, a change in our drilling activity in various
states resulted in an increase in our effective income tax rate in the third
quarter of 2009.
Net Income (Loss) Available to
Common Shareholders. Net income available to common
shareholders decreased from $112.4 million during the third quarter of 2008 to
$30.9 million during the third quarter of 2009. The primary reasons
for this decrease include a 41% decrease in oil prices (net of hedging); a 61%
decrease in natural gas prices (net of hedging); higher DD&A, exploration
and impairment and dividends paid on preferred stock; lower commodity derivative
gains; and lower unrealized amortization of deferred gain on
sale. These negative factors were partially offset by a 10% increase
in equivalent volumes sold; lower lease operating expenses, production taxes,
general and administrative expenses, interest expense, Production Participation
Plan expense and income taxes; and the gain on sale of properties during the
third quarter of 2009.
Liquidity
and Capital Resources
Overview. At
September 30, 2009, our debt to total capitalization ratio was 25.2%, we had
$15.9 million of cash on hand and $2,284.4 million of stockholders’
equity. At December 31, 2008, our debt to total capitalization
ratio was 40.7%, we had $9.6 million of cash on hand and $1,808.8 million of
stockholders’ equity. In the first nine months of 2009, we generated
$287.8 million of cash provided by operating activities, a decrease of $323.6
million over the same period in 2008. Cash provided by operating
activities decreased primarily due to lower average sales prices for both crude
oil and natural gas, partially offset by higher oil and gas volumes produced in
the first nine months of 2009 as well as realized cash settlement gains on
hedging activities during 2009 rather than the significant cash settlement
losses on hedging activities that were incurred during the first nine months of
2008. We also generated $70.8 million from financing activities
consisting of $334.1 million in net proceeds received from the issuance of our
preferred stock and $234.8 million in net proceeds received from the issuance of
our common stock, partially offset by net repayments under our credit agreement
totaling $470.0 million, $23.1 million in debt issuance costs related to our new
credit agreement, and payment of preferred stock dividends totaling $4.9
million. Cash flows from operating and financing activities, as well
as $80.3 million in net proceeds from the sale of interests in certain
properties primarily in the Sanish field, were used to finance $401.2 million of
drilling and development expenditures paid in the first nine months of 2009 and
$31.5 million of cash acquisition capital expenditures. The following
chart details our exploration and development expenditures incurred by region
during the first nine months of 2009 (in thousands):
|
|
Drilling
and Development Expenditures
|
|
|
|
|
|
|
|
|
|
|
Rocky
Mountains
|
|
$ |
199,910 |
|
|
$ |
12,462 |
|
|
$ |
212,372 |
|
|
|
58% |
|
Permian
Basin
|
|
|
108,963 |
|
|
|
7,302 |
|
|
|
116,265 |
|
|
|
32% |
|
Mid-Continent
|
|
|
28,861 |
|
|
|
822 |
|
|
|
29,683 |
|
|
|
8% |
|
Gulf
Coast
|
|
|
758 |
|
|
|
4,167 |
|
|
|
4,925 |
|
|
|
1% |
|
Michigan
|
|
|
1,147 |
|
|
|
32 |
|
|
|
1,179 |
|
|
|
1% |
|
Total
incurred
|
|
|
339,639 |
|
|
|
24,785 |
|
|
|
364,424 |
|
|
|
100% |
|
Decrease
in accrued capital expenditures
|
|
|
61,588 |
|
|
|
- |
|
|
|
61,588 |
|
|
|
|
|
Total
paid
|
|
$ |
401,227 |
|
|
$ |
24,785 |
|
|
$ |
426,012 |
|
|
|
|
|
We
continually evaluate our capital needs and compare them to our capital
resources. Our current 2009 capital budget for exploration and
development expenditures is $470.0 million, of which we had invested $364.4
million as of September 30, 2009. We expect the remaining $105.6
million to be funded with net cash provided by our operating activities in the
fourth quarter of 2009 based on prevailing oil and natural gas
prices. Our 2009 capital budget of $470.0 million, however,
represents a significant decrease from the $947.4 million incurred on
exploration and development expenditures during 2008. This reduced
capital budget is in response to significantly lower oil and natural gas prices
experienced during the fourth quarter of 2008 and continuing into
2009. Although we have no specific budget for property acquisitions
in 2009, we will continue to selectively pursue property acquisitions that
complement our existing core property base. We believe that should
attractive acquisition opportunities arise or exploration and development
expenditures exceed $470.0 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. We believe that we have
sufficient liquidity and capital resources to execute our business plans over
the next 12 months and for the foreseeable future.
Credit
Agreement. As of September 30, 2009, Whiting Oil and Gas
Corporation, (“Whiting Oil and Gas”), our wholly-owned subsidiary, had a credit
agreement with a syndicate of banks, and this credit facility has a borrowing
base of $1.1 billion with $947.2 million of available borrowing capacity, which
is net of $150.0 million in borrowings and $2.8 million in letters of credit
outstanding. The credit agreement provides for interest only payments
until April 2012, when the agreement expires and all outstanding borrowings are
due.
The
borrowing base under the renewed 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, in each case which may
reduce the amount of the borrowing base. Whiting Oil and Gas may,
throughout the term of the credit agreement, borrow, repay and reborrow up to
the borrowing base in effect at any given time. A portion of the
revolving credit agreement in an aggregate amount not to exceed $50.0 million
may be used to issue letters of credit for the account of Whiting Oil and Gas or
other designated subsidiaries of ours. As of September 30, 2009,
$47.2 million was available for additional letters of credit under the
agreement.
The
credit agreement contains restrictive covenants that may limit our ability to,
among other things, incur additional indebtedness, sell assets, make loans to
others, make investments, enter into mergers, enter into hedging contracts,
incur liens and engage in certain other transactions without the prior consent
of our lenders. The credit agreement requires us, as of the last day
of any quarter, (i) to not exceed a total debt to EBITDAX ratio (as defined in
the credit agreement) for the last four quarters of 4.5 to 1.0 for quarters
ending prior to and on September 30, 2010, 4.25 to 1.0 for quarters ending
December 31, 2010 to June 30, 2011 and 4.0 to 1.0 for quarters ending September
30, 2011 and thereafter, (ii) to have a consolidated current assets to
consolidated current liabilities ratio (as defined in the credit agreement and
which includes an add back of the available borrowing capacity under the credit
agreement) of not less than 1.0 to 1.0 and (iii) to not exceed a senior secured
debt to EBITDAX ratio (as defined in the credit agreement) for the last four
quarters of 2.75 to 1.0 for quarters ending prior to and on December 31, 2009
and 2.5 to 1.0 for quarters ending March 31, 2010 and
thereafter. Except for limited exceptions, which include the payment
of dividends on our 6.25% convertible perpetual preferred stock, the credit
agreement restricts our ability to make any dividends or distributions on our
common stock or principal payments on our senior notes. We were in
compliance with our covenants under the credit agreement as of September 30,
2009.
For
further information on the interest rates and loan security related to our
credit agreement, refer to the Long-Term Debt footnote in the Notes to
Consolidated Financial Statements.
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
indentures governing the notes restrict us from incurring additional
indebtedness, subject to certain exceptions, unless our fixed charge coverage
ratio (as defined in the indentures) is at least 2.0 to 1. If we were
in violation of this covenant, then we may not be able to incur additional
indebtedness, including under Whiting Oil and Gas Corporation’s credit
agreement. Additionally, the indentures governing the notes contain
restrictive covenants that may limit our ability to, among other things, pay
cash dividends, redeem or repurchase our capital stock or our subordinated debt,
make investments or issue preferred stock, sell assets, consolidate, merge or
transfer all or substantially all of the assets of ours and our restricted
subsidiaries taken as a whole and enter into hedging contracts. These
covenants may potentially limit the discretion of our management in certain
respects. We were in compliance with these covenants as of September
30, 2009. However, a substantial or extended decline in oil or
natural gas prices may adversely affect our ability to comply with these
covenants in the future.
Schedule of Contractual
Obligations. The table below does not include our Production
Participation Plan liabilities since we cannot determine with accuracy the
timing of future payment amounts. The following table summarizes our
obligations and commitments as of September 30, 2009 to make future payments
under certain contracts, aggregated by category of contractual obligation, for
specified time periods (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt (a)
|
|
$ |
770,000 |
|
|
$ |
- |
|
|
$ |
300,000 |
|
|
$ |
470,000 |
|
|
$ |
- |
|
Cash
interest expense on debt (b)
|
|
|
170,043 |
|
|
|
47,804 |
|
|
|
89,601 |
|
|
|
32,638 |
|
|
|
- |
|
Asset
retirement obligation (c)
|
|
|
77,391 |
|
|
|
10,215 |
|
|
|
3,063 |
|
|
|
8,337 |
|
|
|
55,776 |
|
Tax
sharing liability (d)
|
|
|
24,914 |
|
|
|
2,112 |
|
|
|
3,787 |
|
|
|
3,261 |
|
|
|
15,754 |
|
Derivative
liability fair value (e)
|
|
|
111,247 |
|
|
|
25,050 |
|
|
|
57,468 |
|
|
|
28,729 |
|
|
|
- |
|
Purchasing
obligations (f)
|
|
|
148,467 |
|
|
|
35,017 |
|
|
|
71,395 |
|
|
|
39,877 |
|
|
|
2,178 |
|
Drilling
rig contracts (g)
|
|
|
89,624 |
|
|
|
44,248 |
|
|
|
42,567 |
|
|
|
2,809 |
|
|
|
- |
|
Operating
leases (h)
|
|
|
12,005 |
|
|
|
2,536 |
|
|
|
6,375 |
|
|
|
3,094 |
|
|
|
- |
|
Total
|
|
$ |
1,403,691 |
|
|
$ |
166,982 |
|
|
$ |
574,256 |
|
|
$ |
588,745 |
|
|
$ |
73,708 |
|
________________
(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 due April 2012, 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. 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 2.3%.
|
(c)
|
Asset
retirement obligations represent the present value of estimated amounts
expected to be incurred in the future to plug and abandon oil and gas
wells, remediate oil and gas properties and dismantle their related
facilities.
|
(d)
|
Amounts
shown represent the present value of estimated payments due to Alliant
Energy based on projected future income tax benefits attributable to an
increase in our tax bases. As a result of the Tax Separation
and Indemnification Agreement signed with Alliant Energy, the increased
tax bases are expected to result in increased future income tax deductions
and, accordingly, may reduce income taxes otherwise payable by
us. Under this agreement, we have agreed to pay Alliant Energy
90% of the future tax benefits we realize annually as a result of this
step up in tax basis for the years ending on or prior to December 31,
2013. In 2014, we will be obligated to pay Alliant Energy the
present value of the remaining tax benefits assuming all such tax benefits
will be realized in future years.
|
(e)
|
The
above derivative obligation at September 30, 2009 consists of a $15.6
million payable to Whiting USA Trust I (“Trust”) for derivative contracts
that we have entered into but have in turn conveyed to the
Trust. Although these derivatives are in a fair value asset
position at quarter end, 75.8% of such derivative assets are due to the
Trust under the terms of the conveyance. The above derivative
obligation at September 30, 2009 also consists of a $95.6 million fair
value liability for derivative contracts we have entered into on our own
behalf, primarily in the form of costless collars, to hedge our exposure
to crude oil price fluctuations. With respect to our open
derivative contracts at September 30, 2009 with certain counterparties,
the forward price curves for crude oil and natural gas generally exceeded
the price curves that were in effect when these contracts were entered
into, resulting in a derivative fair value liability. If
current market prices are higher than a collar’s price ceiling when the
cash settlement amount is calculated, we are required to pay the contract
counterparties. The ultimate settlement amounts under our
derivative contracts are unknown, however, as they are subject to
continuing market and commodity price
risk.
|
(f)
|
We
have two take-or-pay purchase agreements, one agreement expiring in March
2014 and one agreement expiring in December 2014, whereby we have
committed to buy certain volumes of CO2 for
use in enhanced recovery projects in our Postle field in Oklahoma and our
North Ward Estes field in Texas. The purchase agreements are
with different suppliers. Under the terms of the agreements, we
are obligated to purchase a minimum daily volume of CO2 (as
calculated on an annual basis) or else pay for any deficiencies at the
price in effect when the minimum delivery was to have
occurred. The CO2
volumes planned for use on the enhanced recovery projects in the Postle
and North Ward Estes fields currently exceed the minimum daily volumes
provided in these take-or-pay purchase agreements. Therefore,
we expect to avoid any payments for
deficiencies.
|
(g)
|
We
currently have six drilling rigs under long-term contract, of which three
drilling rigs expire in 2010, one in 2011, one in 2012 and one in
2013. All of these rigs are operating in the Rocky Mountains
region. As of September 30, 2009, early termination of the
remaining contracts would require termination penalties of $57.1 million,
which would be in lieu of paying the remaining drilling commitments of
$89.6 million. No other drilling rigs working for us are
currently under long-term contracts or contracts that cannot be terminated
at the end of the well that is currently being drilled. Due to
the short-term and indeterminate nature of the drilling time remaining on
rigs drilling on a well-by-well basis, such obligations have not been
included in this table.
|
(h)
|
We
lease 107,400 square feet of administrative office space in Denver,
Colorado under an operating lease arrangement expiring in 2013, and an
additional 46,700 square feet of office space in Midland, Texas expiring
in 2012.
|
Based on
current oil and natural gas prices and anticipated levels of production, we
believe that the estimated net cash generated from operations, together with
cash on hand and amounts available under our credit agreement, will be adequate
to meet future liquidity needs, including satisfying our financial obligations
and funding our operations and exploration and development
activities.
New
Accounting Pronouncements
For
further information on the effects of recently adopted accounting pronouncements
and the potential effects of new accounting pronouncements, refer to the Adopted
and Recently Issued Accounting Pronouncements footnote in the Notes to
Consolidated Financial Statements.
Critical
Accounting Policies and Estimates
Information
regarding critical accounting policies and estimates is contained in Item 7
of our Annual Report on Form 10-K for the fiscal year ended December 31,
2008.
Effects
of Inflation and Pricing
We
experienced increased costs during 2008 due to increased demand for oil field
products and services. The oil and gas industry is very cyclical and
the demand for goods and services of oil field companies, suppliers and others
associated with the industry put extreme pressure on the economic stability and
pricing structure within the industry. Typically, as prices for oil
and natural gas increase, so do all associated costs. Conversely, in
a period of declining prices, associated cost declines are likely to lag and not
adjust downward in proportion to prices. Material changes in prices
also impact the current revenue stream, estimates of future reserves, borrowing
base calculations of bank loans, impairment assessments of oil and gas
properties, and values of properties in purchase and sale
transactions. Material changes in prices can impact the value of oil
and gas companies and their ability to raise capital, borrow money and retain
personnel. While we do not currently expect business costs to
materially increase, higher prices for oil and natural gas could result in
increases in the costs of materials, services and personnel.
Forward-Looking
Statements
This
report contains statements that we believe to be “forward-looking statements”
within the meaning of the Private Securities Litigation Reform Act of
1995. All statements other than historical facts, including, without
limitation, statements regarding our future financial position, business
strategy, projected revenues, earnings, costs, capital expenditures and debt
levels, and plans and objectives of management for future operations, are
forward-looking statements. When used in this report, words such as
we “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe” or “should”
or the negative thereof or variations thereon or similar terminology are
generally intended to identify forward-looking statements. Such
forward-looking statements are subject to risks and uncertainties that could
cause actual results to differ materially from those expressed in, or implied
by, such statements.
These
risks and uncertainties include, but are not limited to: declines in
oil or natural gas prices; impacts of the global recession and tight credit
markets; our level of success in exploitation, exploration, development and
production activities; adverse weather conditions that may negatively impact
development or production activities; the timing of our exploration and
development expenditures, including our ability to obtain CO2;
inaccuracies of our reserve estimates or our assumptions underlying them;
revisions to reserve estimates as a result of changes in commodity prices; risks
related to our level of indebtedness and periodic redeterminations of the
borrowing base under our credit agreement; our ability to generate sufficient
cash flows from operations to meet the internally funded portion of our capital
expenditures budget; our ability to obtain external capital to finance
exploration and development operations and acquisitions; our ability to identify
and complete acquisitions and to successfully integrate acquired businesses;
unforeseen underperformance of or liabilities associated with acquired
properties; our ability to successfully complete potential asset dispositions;
the impacts of hedging on our results of operations; failure of our properties
to yield oil or gas in commercially viable quantities; uninsured or underinsured
losses resulting from our oil and gas operations; our inability to access oil
and gas markets due to market conditions or operational impediments; the impact
and costs of compliance with laws and regulations governing our oil and gas
operations; our ability to replace our oil and natural gas reserves; any loss of
our senior management or technical personnel; competition in the oil and gas
industry in the regions in which we operate; risks arising out of our hedging
transactions; and other risks described under the caption “Risk Factors” in our
Quarterly Report on Form 10-Q for the period ended June 30, 2009. We
assume no obligation, and disclaim any duty, to update the forward-looking
statements in this report.
|
Quantitative and Qualitative Disclosures about
Market Risk
|
Our
quantitative and qualitative disclosures about market risk for changes in
commodity prices and interest rates are included in Item 7A of our Annual Report
on Form 10-K for the fiscal year ended December 31, 2008 and have not
materially changed since that report was filed.
Our
outstanding hedges as of October 1, 2009 are summarized below:
Whiting
Petroleum Corporation
|
|
|
|
|
|
Weighted
Average
NYMEX
Floor/Ceiling
|
Crude
Oil
|
|
10/2009
to 12/2009
|
|
478,000
|
|
$61.04/$74.89
|
Crude
Oil
|
|
01/2010
to 03/2010
|
|
430,000
|
|
$60.27/$74.81
|
Crude
Oil
|
|
04/2010
to 06/2010
|
|
415,000
|
|
$62.69/$80.09
|
Crude
Oil
|
|
07/2010
to 09/2010
|
|
405,000
|
|
$60.28/$76.98
|
Crude
Oil
|
|
10/2010
to 12/2010
|
|
390,000
|
|
$60.29/$78.23
|
Crude
Oil
|
|
01/2011
to 03/2011
|
|
360,000
|
|
$56.25/$83.78
|
Crude
Oil
|
|
04/2011
to 06/2011
|
|
360,000
|
|
$56.25/$83.78
|
Crude
Oil
|
|
07/2011
to 09/2011
|
|
360,000
|
|
$56.25/$83.78
|
Crude
Oil
|
|
10/2011
to 12/2011
|
|
360,000
|
|
$56.25/$83.78
|
Crude
Oil
|
|
01/2012
to 03/2012
|
|
330,000
|
|
$55.91/$85.46
|
Crude
Oil
|
|
04/2012
to 06/2012
|
|
330,000
|
|
$55.91/$85.46
|
Crude
Oil
|
|
07/2012
to 09/2012
|
|
330,000
|
|
$55.91/$85.46
|
Crude
Oil
|
|
10/2012
to 12/2012
|
|
330,000
|
|
$55.91/$85.46
|
Crude
Oil
|
|
01/2013
to 03/2013
|
|
290,000
|
|
$55.34/$85.94
|
Crude
Oil
|
|
04/2013
to 06/2013
|
|
290,000
|
|
$55.34/$85.94
|
Crude
Oil
|
|
07/2013
to 09/2013
|
|
290,000
|
|
$55.34/$85.94
|
Crude
Oil
|
|
10/2013
|
|
290,000
|
|
$55.34/$85.94
|
Crude
Oil
|
|
11/2013
|
|
190,000
|
|
$54.59/$81.75
|
In
connection with our conveyance on April 30, 2008 of a term net profits interest
to Whiting USA Trust I (as further explained above in the note on Acquisitions
and Divestitures), the rights to any future hedge payments we make or receive on
certain of our derivative contracts, representing 1,570 MBbls of crude oil and
5,994 MMcf of natural gas from 2009 through 2012, have been conveyed to the
Trust, and therefore such payments will be included in the Trust’s calculation
of net proceeds. Under the terms of the aforementioned conveyance, we
retain 10% of the net proceeds from the underlying properties. Our
retention of 10% of these net proceeds combined with our ownership of 2,186,389
Trust units, results in third-party public holders of Trust units receiving
75.8%, while we retain 24.2%, of future economic results of such
hedges. No additional hedges are allowed to be placed on Trust
assets.
The table
below summarizes all of the costless collars that we entered into and then in
turn conveyed, as described in the preceding paragraph, to Whiting USA Trust I
(of which we retain 24.2% of the future economic results and third-party public
holders of Trust units receive 75.8% of the future economic
results):
Conveyed
to Whiting USA Trust I
|
|
|
|
Monthly
Volume
(Bbl)/(MMBtu)
|
|
Weighted
Average
NYMEX
Floor/Ceiling
|
Crude
Oil
|
|
10/2009
to 12/2009
|
|
46,240
|
|
$76.00/$135.72
|
Crude
Oil
|
|
01/2010
to 03/2010
|
|
45,084
|
|
$76.00/$135.09
|
Crude
Oil
|
|
04/2010
to 06/2010
|
|
43,978
|
|
$76.00/$134.85
|
Crude
Oil
|
|
07/2010
to 09/2010
|
|
42,966
|
|
$76.00/$134.89
|
Crude
Oil
|
|
10/2010
to 12/2010
|
|
41,924
|
|
$76.00/$135.11
|
Crude
Oil
|
|
01/2011
to 03/2011
|
|
40,978
|
|
$74.00/$139.68
|
Crude
Oil
|
|
04/2011
to 06/2011
|
|
40,066
|
|
$74.00/$140.08
|
Crude
Oil
|
|
07/2011
to 09/2011
|
|
39,170
|
|
$74.00/$140.15
|
Crude
Oil
|
|
10/2011
to 12/2011
|
|
38,242
|
|
$74.00/$140.75
|
Crude
Oil
|
|
01/2012
to 03/2012
|
|
37,412
|
|
$74.00/$141.27
|
Crude
Oil
|
|
04/2012
to 06/2012
|
|
36,572
|
|
$74.00/$141.73
|
Crude
Oil
|
|
07/2012
to 09/2012
|
|
35,742
|
|
$74.00/$141.70
|
Crude
Oil
|
|
10/2012
to 12/2012
|
|
35,028
|
|
$74.00/$142.21
|
Natural
Gas
|
|
10/2009
to 12/2009
|
|
185,430
|
|
$7.00/$14.85
|
Natural
Gas
|
|
01/2010
to 03/2010
|
|
178,903
|
|
$7.00/$18.65
|
Natural
Gas
|
|
04/2010
to 06/2010
|
|
172,873
|
|
$6.00/$13.20
|
Natural
Gas
|
|
07/2010
to 09/2010
|
|
167,583
|
|
$6.00/$14.00
|
Natural
Gas
|
|
10/2010
to 12/2010
|
|
162,997
|
|
$7.00/$14.20
|
Natural
Gas
|
|
01/2011
to 03/2011
|
|
157,600
|
|
$7.00/$17.40
|
Natural
Gas
|
|
04/2011
to 06/2011
|
|
152,703
|
|
$6.00/$13.05
|
Natural
Gas
|
|
07/2011
to 09/2011
|
|
148,163
|
|
$6.00/$13.65
|
Natural
Gas
|
|
10/2011
to 12/2011
|
|
142,787
|
|
$7.00/$14.25
|
Natural
Gas
|
|
01/2012
to 03/2012
|
|
137,940
|
|
$7.00/$15.55
|
Natural
Gas
|
|
04/2012
to 06/2012
|
|
134,203
|
|
$6.00/$13.60
|
Natural
Gas
|
|
07/2012
to 09/2012
|
|
130,173
|
|
$6.00/$14.45
|
Natural
Gas
|
|
10/2012
to 12/2012
|
|
126,613
|
|
$7.00/$13.40
|
The
collared hedges shown above have the effect of providing a protective floor
while allowing us to share in upward pricing movements. Consequently,
while these hedges are designed to decrease our exposure to price decreases,
they also have the effect of limiting the benefit of price increases above the
ceiling. For the crude oil contracts listed in both tables above, a
hypothetical $5.00 change in the NYMEX forward curve as of September 30, 2009
applied to the notional amounts would cause a change in our commodity derivative
(gain) loss of $63.4 million. For the natural gas contracts listed
above, a hypothetical $0.50 change in the NYMEX forward curve as of September
30, 2009 applied to the notional amounts would cause a change in our commodity
derivative (gain) loss of $0.3 million.
We have
various fixed price gas sales contracts with end users for a portion of the
natural gas we produce in Colorado, Michigan and Utah. Our estimated
future production volumes to be sold under these fixed price contracts as of
October 1, 2009 are summarized below:
|
|
|
|
|
|
Weighted
Average
Price
Per MMBtu
|
Natural
Gas
|
|
10/2009
to 12/2009
|
|
496,333
|
|
$5.32
|
Natural
Gas
|
|
01/2010
to 03/2010
|
|
688,000
|
|
$5.36
|
Natural
Gas
|
|
04/2010
to 06/2010
|
|
694,667
|
|
$5.36
|
Natural
Gas
|
|
07/2010
to 09/2010
|
|
701,333
|
|
$5.36
|
Natural
Gas
|
|
10/2010
to 12/2010
|
|
701,333
|
|
$5.36
|
Natural
Gas
|
|
01/2011
to 03/2011
|
|
658,000
|
|
$5.39
|
Natural
Gas
|
|
04/2011
to 06/2011
|
|
664,333
|
|
$5.38
|
Natural
Gas
|
|
07/2011
to 09/2011
|
|
648,667
|
|
$5.38
|
Natural
Gas
|
|
10/2011
to 12/2011
|
|
648,667
|
|
$5.38
|
Natural
Gas
|
|
01/2012
to 03/2012
|
|
456,000
|
|
$5.41
|
Natural
Gas
|
|
04/2012
to 06/2012
|
|
460,333
|
|
$5.41
|
Natural
Gas
|
|
07/2012
to 09/2012
|
|
464,667
|
|
$5.41
|
Natural
Gas
|
|
10/2012
to 12/2012
|
|
398,667
|
|
$5.46
|
Natural
Gas
|
|
01/2013
to 03/2013
|
|
360,000
|
|
$5.47
|
Natural
Gas
|
|
04/2013
to 06/2013
|
|
364,000
|
|
$5.47
|
Natural
Gas
|
|
07/2013
to 09/2013
|
|
368,000
|
|
$5.47
|
Natural
Gas
|
|
10/2013
to 12/2013
|
|
368,000
|
|
$5.47
|
Natural
Gas
|
|
01/2014
to 03/2014
|
|
330,000
|
|
$5.49
|
Natural
Gas
|
|
04/2014
to 06/2014
|
|
333,667
|
|
$5.49
|
Natural
Gas
|
|
07/2014
to 09/2014
|
|
337,333
|
|
$5.49
|
Natural
Gas
|
|
10/2014
to 12/2014
|
|
337,333
|
|
$5.49
|
Evaluation of disclosure controls
and procedures. In accordance with Rule 13a-15(b) of the
Securities Exchange Act of 1934 (the “Exchange Act”), our management evaluated,
with the participation of our Chairman, President and Chief Executive Officer
and our Chief Financial Officer, the effectiveness of the design and operation
of our disclosure controls and procedures (as defined in Rule 13a-15(e) under
the Exchange Act) as of September 30, 2009. Based upon their
evaluation of these disclosures controls and procedures, the Chairman, President
and Chief Executive Officer and the Chief Financial Officer concluded that the
disclosure controls and procedures were effective as of September 30, 2009 to
ensure that information required to be disclosed by us in the reports that we
file or submit under the Exchange Act is recorded, processed, summarized and
reported within the time periods specified in the rules and forms of the
Securities and Exchange Commission, and to ensure that information required to
be disclosed by us in the reports we file or submit under the Exchange Act is
accumulated and communicated to our management, including our principal
executive and principal financial officers, as appropriate, to allow timely
decisions regarding required disclosure.
Changes in internal control over
financial reporting. There was no change in our internal
control over financial reporting that occurred during the quarter ended
September 30, 2009 that has materially affected, or is reasonably likely to
materially affect, our internal control over financial reporting.
PART II –
OTHER INFORMATION
Whiting
is subject to litigation claims and governmental and regulatory proceedings
arising in the ordinary course of business. It is management’s
opinion that all claims and litigation we are involved in are not likely to have
a material adverse effect on our consolidated financial position, cash flows or
results of operations.
Risk
factors relating to us are contained in Part II, Item 1A of our Quarterly Report
on Form 10-Q for the period ended June 30, 2009. No material change
to such risk factors has occurred during the three months ended September 30,
2009.
The
exhibits listed in the accompanying index to exhibits are filed as part of this
Quarterly Report on Form 10-Q.
SIGNATURES
Pursuant
to the requirements of the Securities Exchange Act of 1934, the Registrant has
duly caused this report to be signed on its behalf by the undersigned thereunto
duly authorized, on this 29th day of October, 2009.
|
|
WHITING
PETROLEUM CORPORATION
|
|
|
|
|
|
|
|
By
|
/s/
James J. Volker
|
|
|
James
J. Volker
|
|
|
Chairman,
President and Chief Executive Officer
|
|
|
|
|
|
|
|
By
|
/s/
Michael J. Stevens
|
|
|
Michael
J. Stevens
|
|
|
Vice
President and Chief Financial Officer
|
|
|
|
|
|
|
|
By
|
/s/
Brent P. Jensen
|
|
|
Brent
P. Jensen
|
|
|
Controller
and Treasurer
|
EXHIBIT
INDEX
Exhibit
Number
|
Exhibit Description
|
(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.
|