UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM 10-Q
[X]
|
QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
|
For the
quarterly period ended June 30,
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 July 15,
2009: 50,841,572 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.
“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
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
13,178 |
|
|
$ |
9,624 |
|
Accounts
receivable trade, net
|
|
|
106,880 |
|
|
|
123,386 |
|
Derivative
assets
|
|
|
8,714 |
|
|
|
46,780 |
|
Prepaid
expenses and other
|
|
|
10,978 |
|
|
|
37,284 |
|
Total
current assets
|
|
|
139,750 |
|
|
|
217,074 |
|
PROPERTY
AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
Oil
and gas properties, successful efforts method:
|
|
|
|
|
|
|
|
|
Proved
properties
|
|
|
4,632,721 |
|
|
|
4,423,197 |
|
Unproved
properties
|
|
|
99,773 |
|
|
|
106,436 |
|
Other
property and equipment
|
|
|
125,534 |
|
|
|
91,099 |
|
Total
property and equipment
|
|
|
4,858,028 |
|
|
|
4,620,732 |
|
Less
accumulated depreciation, depletion and amortization
|
|
|
(1,081,323 |
) |
|
|
(886,065 |
) |
Total
property and equipment, net
|
|
|
3,776,705 |
|
|
|
3,734,667 |
|
DEBT
ISSUANCE COSTS
|
|
|
29,708 |
|
|
|
10,779 |
|
DERIVATIVE
ASSETS
|
|
|
13,520 |
|
|
|
38,104 |
|
OTHER
LONG-TERM ASSETS
|
|
|
26,273 |
|
|
|
28,457 |
|
TOTAL
|
|
$ |
3,985,956 |
|
|
$ |
4,029,081 |
|
|
|
|
|
|
|
|
|
|
See
notes to consolidated financial statements.
|
|
|
|
|
|
(Continued)
|
|
WHITING
PETROLEUM CORPORATION
CONSOLIDATED
BALANCE SHEETS (Unaudited)
(In
thousands, except share and per share data)
|
|
|
|
|
|
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
Accounts
payable
|
|
$ |
25,359 |
|
|
$ |
64,610 |
|
Accrued
capital expenditures
|
|
|
22,462 |
|
|
|
84,960 |
|
Accrued
liabilities
|
|
|
63,879 |
|
|
|
45,359 |
|
Accrued
interest
|
|
|
11,101 |
|
|
|
9,673 |
|
Oil
and gas sales payable
|
|
|
30,579 |
|
|
|
35,106 |
|
Accrued
employee compensation and benefits
|
|
|
9,566 |
|
|
|
41,911 |
|
Production
taxes payable
|
|
|
17,755 |
|
|
|
20,038 |
|
Deferred
gain on sale
|
|
|
13,543 |
|
|
|
14,650 |
|
Derivative
liabilities
|
|
|
34,362 |
|
|
|
17,354 |
|
Deferred
income taxes
|
|
|
13,115 |
|
|
|
15,395 |
|
Tax
sharing liability
|
|
|
2,112 |
|
|
|
2,112 |
|
Total
current liabilities
|
|
|
243,833 |
|
|
|
351,168 |
|
NON-CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
839,565 |
|
|
|
1,239,751 |
|
Deferred
income taxes
|
|
|
325,002 |
|
|
|
390,902 |
|
Deferred
gain on sale
|
|
|
66,028 |
|
|
|
73,216 |
|
Production
Participation Plan liability
|
|
|
69,846 |
|
|
|
66,166 |
|
Asset
retirement obligations
|
|
|
60,898 |
|
|
|
47,892 |
|
Derivative
liabilities
|
|
|
97,894 |
|
|
|
28,131 |
|
Tax
sharing liability
|
|
|
22,393 |
|
|
|
21,575 |
|
Other
long-term liabilities
|
|
|
3,217 |
|
|
|
1,489 |
|
Total
non-current liabilities
|
|
|
1,484,843 |
|
|
|
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 June 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;
|
|
|
|
|
|
|
|
|
51,365,790
issued and 50,843,532 outstanding as of June 30, 2009 and 42,582,100
issued and 42,323,336 outstanding as of December 31,
2008
|
|
|
51 |
|
|
|
43 |
|
Additional
paid-in capital
|
|
|
1,542,022 |
|
|
|
971,310 |
|
Accumulated
other comprehensive income
|
|
|
31,959 |
|
|
|
17,271 |
|
Retained
earnings
|
|
|
683,245 |
|
|
|
820,167 |
|
Total
stockholders’ equity
|
|
|
2,257,280 |
|
|
|
1,808,791 |
|
TOTAL
|
|
$ |
3,985,956 |
|
|
$ |
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 June 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
AND OTHER INCOME:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and natural gas sales
|
|
$ |
214,303 |
|
|
$ |
390,536 |
|
|
$ |
360,478 |
|
|
$ |
677,267 |
|
Gain
(loss) on oil hedging activities
|
|
|
6,848 |
|
|
|
(48,111 |
) |
|
|
20,298 |
|
|
|
(71,023 |
) |
Amortization
of deferred gain on sale
|
|
|
4,274 |
|
|
|
2,957 |
|
|
|
8,373 |
|
|
|
2,957 |
|
Gain
on sale of properties
|
|
|
4,608 |
|
|
|
- |
|
|
|
4,608 |
|
|
|
- |
|
Interest
income and other
|
|
|
125 |
|
|
|
393 |
|
|
|
240 |
|
|
|
624 |
|
Total
revenues and other income
|
|
|
230,158 |
|
|
|
345,775 |
|
|
|
393,997 |
|
|
|
609,825 |
|
COSTS
AND EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating
|
|
|
57,582 |
|
|
|
57,470 |
|
|
|
118,536 |
|
|
|
113,176 |
|
Production
taxes
|
|
|
14,914 |
|
|
|
26,057 |
|
|
|
24,433 |
|
|
|
43,743 |
|
Depreciation,
depletion and amortization
|
|
|
100,315 |
|
|
|
54,811 |
|
|
|
200,349 |
|
|
|
105,322 |
|
Exploration
and impairment
|
|
|
9,792 |
|
|
|
8,643 |
|
|
|
27,106 |
|
|
|
19,627 |
|
General
and administrative
|
|
|
10,282 |
|
|
|
23,007 |
|
|
|
19,262 |
|
|
|
34,622 |
|
Interest
expense
|
|
|
18,693 |
|
|
|
15,671 |
|
|
|
33,373 |
|
|
|
31,217 |
|
Change
in Production Participation Plan liability
|
|
|
3,284 |
|
|
|
11,690 |
|
|
|
3,680 |
|
|
|
17,847 |
|
Loss
on mark-to-market derivatives
|
|
|
160,532 |
|
|
|
20,562 |
|
|
|
182,297 |
|
|
|
17,625 |
|
Total
costs and expenses
|
|
|
375,394 |
|
|
|
217,911 |
|
|
|
609,036 |
|
|
|
383,179 |
|
INCOME
(LOSS) BEFORE INCOME TAXES
|
|
|
(145,236 |
) |
|
|
127,864 |
|
|
|
(215,039 |
) |
|
|
226,646 |
|
INCOME
TAX EXPENSE (BENEFIT):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
- |
|
|
|
(837 |
) |
|
|
(539 |
) |
|
|
872 |
|
Deferred
|
|
|
(52,073 |
) |
|
|
48,252 |
|
|
|
(77,578 |
) |
|
|
83,011 |
|
Total
income tax expense (benefit)
|
|
|
(52,073 |
) |
|
|
47,415 |
|
|
|
(78,117 |
) |
|
|
83,883 |
|
NET
INCOME (LOSS)
|
|
|
(93,163 |
) |
|
|
80,449 |
|
|
|
(136,922 |
) |
|
|
142,763 |
|
Preferred
stock dividends
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
NET
INCOME (LOSS) AVAILABLE (APPLICABLE) TO COMMON
SHAREHOLDERS
|
|
$ |
(93,163 |
) |
|
$ |
80,449 |
|
|
$ |
(136,922 |
) |
|
$ |
142,763 |
|
NET
INCOME (LOSS) PER COMMON SHARE, BASIC
|
|
$ |
(1.83 |
) |
|
$ |
1.90 |
|
|
$ |
(2.78 |
) |
|
$ |
3.38 |
|
NET
INCOME (LOSS) PER COMMON SHARE, DILUTED
|
|
$ |
(1.83 |
) |
|
$ |
1.90 |
|
|
$ |
(2.78 |
) |
|
$ |
3.37 |
|
WEIGHTED
AVERAGE SHARES OUTSTANDING, BASIC
|
|
|
50,842 |
|
|
|
42,320 |
|
|
|
49,230 |
|
|
|
42,296 |
|
WEIGHTED
AVERAGE SHARES OUTSTANDING, DILUTED
|
|
|
50,842 |
|
|
|
42,446 |
|
|
|
49,230 |
|
|
|
42,416 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See
notes to consolidated financial statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WHITING PETROLEUM CORPORATION
CONSOLIDATED
STATEMENTS OF CASH FLOWS (Unaudited)
(In
thousands)
|
|
Six
Months Ended June 30,
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income (loss)
|
|
$ |
(136,922 |
) |
|
$ |
142,763 |
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
200,349 |
|
|
|
105,322 |
|
Deferred
income tax (benefit) expense
|
|
|
(77,578 |
) |
|
|
83,011 |
|
Amortization
of debt issuance costs and debt discount
|
|
|
4,355 |
|
|
|
2,423 |
|
Accretion
of tax sharing liability
|
|
|
819 |
|
|
|
623 |
|
Stock-based
compensation
|
|
|
2,577 |
|
|
|
3,245 |
|
Amortization
of deferred gain on sale
|
|
|
(8,373 |
) |
|
|
(2,957 |
) |
Gain
on sale of properties
|
|
|
(4,608 |
) |
|
|
- |
|
Undeveloped
leasehold and oil and gas property impairments
|
|
|
8,295 |
|
|
|
5,400 |
|
Change
in Production Participation Plan liability
|
|
|
3,680 |
|
|
|
17,847 |
|
Unrealized
loss on derivative contracts
|
|
|
172,991 |
|
|
|
17,625 |
|
Other
non-current
|
|
|
(2,754 |
) |
|
|
(11,757 |
) |
Changes
in current assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts
receivable trade
|
|
|
17,866 |
|
|
|
(80,853 |
) |
Prepaid
expenses and other
|
|
|
26,306 |
|
|
|
(24,472 |
) |
Accounts
payable and accrued liabilities
|
|
|
(24,321 |
) |
|
|
43,060 |
|
Accrued
interest
|
|
|
1,428 |
|
|
|
(607 |
) |
Other
current liabilities
|
|
|
(39,808 |
) |
|
|
28,418 |
|
Net
cash provided by operating activities
|
|
|
144,302 |
|
|
|
329,091 |
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Cash
acquisition capital expenditures
|
|
|
(38,691 |
) |
|
|
(388,457 |
) |
Drilling
and development capital expenditures
|
|
|
(327,840 |
) |
|
|
(376,410 |
) |
Proceeds
from sale of oil and gas properties
|
|
|
79,609 |
|
|
|
311 |
|
Proceeds
from sale of marketable securities
|
|
|
- |
|
|
|
764 |
|
Net
proceeds from sale of 11,677,500 units in Whiting USA Trust
I
|
|
|
- |
|
|
|
195,128 |
|
Net
cash used in investing activities
|
|
|
(286,922 |
) |
|
|
(568,664 |
) |
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Issuance
of 6.25% convertible perpetual preferred stock
|
|
|
334,562 |
|
|
|
- |
|
Issuance
of common stock
|
|
|
234,753 |
|
|
|
- |
|
Long-term
borrowings under credit agreement
|
|
|
260,000 |
|
|
|
735,000 |
|
Repayments
of long-term borrowings under credit agreement
|
|
|
(660,000 |
) |
|
|
(485,000 |
) |
Debt
issuance costs
|
|
|
(23,141 |
) |
|
|
- |
|
Net
cash provided by financing activities
|
|
|
146,174 |
|
|
|
250,000 |
|
NET
CHANGE IN CASH AND CASH EQUIVALENTS
|
|
|
3,554 |
|
|
|
10,427 |
|
CASH
AND CASH EQUIVALENTS:
|
|
|
|
|
|
|
|
|
Beginning
of period
|
|
|
9,624 |
|
|
|
14,778 |
|
End
of period
|
|
$ |
13,178 |
|
|
$ |
25,205 |
|
SUPPLEMENTAL
CASH FLOW DISCLOSURES:
|
|
|
|
|
|
|
|
|
Cash
paid (refunded) for income taxes
|
|
$ |
(2,484 |
) |
|
$ |
832 |
|
Cash
paid for interest
|
|
$ |
26,771 |
|
|
$ |
28,778 |
|
NONCASH
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Accrued
capital expenditures during the period
|
|
$ |
22,462 |
|
|
$ |
73,658 |
|
|
|
|
|
|
|
|
|
|
See
notes to consolidated financial statements.
|
|
|
|
|
|
|
|
|
WHITING PETROLEUM CORPORATION
CONSOLIDATED
STATEMENTS OF STOCKHOLDERS’ EQUITY
AND
COMPREHENSIVE INCOME (Unaudited)
(In
thousands)
|
|
|
|
|
|
|
|
Additional
Paid-in
|
|
|
Accumulated
Other Comprehensive
|
|
|
Retained
|
|
|
Total
Stockholders’
|
|
|
Comprehensive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCES-January
1, 2008
|
|
|
- |
|
|
$ |
- |
|
|
|
42,480 |
|
|
$ |
42 |
|
|
$ |
968,876 |
|
|
$ |
(46,116 |
) |
|
$ |
568,024 |
|
|
$ |
1,490,826 |
|
|
|
|
Net
income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
142,763 |
|
|
|
142,763 |
|
|
$ |
142,763 |
|
Change
in derivative fair values, net of taxes of $46,279
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(79,993 |
) |
|
|
- |
|
|
|
(79,993 |
) |
|
|
(79,993 |
) |
Realized
loss on settled derivative contracts, net of taxes of
$26,021
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
44,978 |
|
|
|
- |
|
|
|
44,978 |
|
|
|
44,978 |
|
Total
comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
107,748 |
|
Restricted
stock issued
|
|
|
- |
|
|
|
- |
|
|
|
139 |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
|
|
Restricted
stock forfeited
|
|
|
- |
|
|
|
- |
|
|
|
(3 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
Restricted
stock used for tax withholdings
|
|
|
- |
|
|
|
- |
|
|
|
(30 |
) |
|
|
- |
|
|
|
(1,734 |
) |
|
|
- |
|
|
|
- |
|
|
|
(1,734 |
) |
|
|
|
|
Stock-based
compensation
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,245 |
|
|
|
- |
|
|
|
- |
|
|
|
3,245 |
|
|
|
|
|
BALANCES-June
30, 2008
|
|
|
- |
|
|
|
- |
|
|
|
42,586 |
|
|
$ |
43 |
|
|
$ |
970,387 |
|
|
$ |
(81,131 |
) |
|
$ |
710,787 |
|
|
$ |
1,600,086 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCES-December
31, 2008
|
|
|
- |
|
|
$ |
- |
|
|
|
42,582 |
|
|
$ |
43 |
|
|
$ |
971,310 |
|
|
$ |
17,271 |
|
|
$ |
820,167 |
|
|
$ |
1,808,791 |
|
|
|
|
|
Net
loss
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(136,922 |
) |
|
|
(136,922 |
) |
|
$ |
(136,922 |
) |
Change
in derivative fair values, net of taxes of $7,706
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
13,302 |
|
|
|
- |
|
|
|
13,302 |
|
|
|
13,302 |
|
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 $8,387
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
14,479 |
|
|
|
- |
|
|
|
14,479 |
|
|
|
14,479 |
|
OCI
amortization on de-designated hedges, net of taxes of
$2,272
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(4,576 |
) |
|
|
- |
|
|
|
(4,576 |
) |
|
|
(4,576 |
) |
Total
comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(122,234 |
) |
Issuance
of 6.25% convertible perpetual preferred stock
|
|
|
3,450 |
|
|
|
3 |
|
|
|
- |
|
|
|
- |
|
|
|
334,559 |
|
|
|
- |
|
|
|
- |
|
|
|
334,562 |
|
|
|
|
|
Issuance
of stock, secondary offering
|
|
|
- |
|
|
|
- |
|
|
|
8,450 |
|
|
|
8 |
|
|
|
234,745 |
|
|
|
- |
|
|
|
- |
|
|
|
234,753 |
|
|
|
|
|
Restricted
stock issued
|
|
|
- |
|
|
|
- |
|
|
|
364 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
Restricted
stock forfeited
|
|
|
- |
|
|
|
- |
|
|
|
(3 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
Restricted
stock used for tax withholdings
|
|
|
- |
|
|
|
- |
|
|
|
(27 |
) |
|
|
- |
|
|
|
(654 |
) |
|
|
- |
|
|
|
- |
|
|
|
(654 |
) |
|
|
|
|
Tax
effect from restricted stock vesting
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(515 |
) |
|
|
- |
|
|
|
- |
|
|
|
(515 |
) |
|
|
|
|
Stock-based
compensation
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,577 |
|
|
|
- |
|
|
|
- |
|
|
|
2,577 |
|
|
|
|
|
BALANCES-June
30, 2009
|
|
|
3,450 |
|
|
$ |
3 |
|
|
|
51,366 |
|
|
$ |
51 |
|
|
$ |
1,542,022 |
|
|
$ |
31,959 |
|
|
$ |
683,245 |
|
|
$ |
2,257,280 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 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. All
potentially dilutive securities are anti-dilutive when a loss from continuing
operations exists and are excluded from the computation of diluted earnings per
share accordingly.
Subsequent
Events—The Company has evaluated subsequent events through the date the
financial statements were issued and has no material subsequent events to
report.
2.
|
ACQUISITIONS
AND DIVESTITURES
|
2009
Acquisitions
There
were no significant acquisitions during the first half 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.
As of
June 4, 2009, there were 18 wells drilled or in the process of being drilled on
the 26 units covered by the agreement and 12 more wells planned in 2009 on these
units. 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 the 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 three and six months ended
June 30, 2008, as though the Flat Rock acquisition had occurred on the first day
of each period. The pro forma information below includes numerous
assumptions and is not necessarily indicative of what historical results would
have been or what future results of operations will be.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
months ended June 30, 2008:
|
|
|
|
|
|
|
|
|
|
Total
revenues
|
|
$ |
345,775 |
|
|
$ |
7,879 |
|
|
$ |
353,654 |
|
Net
income
|
|
|
80,449 |
|
|
|
850 |
|
|
|
81,299 |
|
Net
income per common share – basic and diluted
|
|
$ |
1.90 |
|
|
$ |
0.02 |
|
|
$ |
1.92 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
months ended June 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
revenues
|
|
$ |
609,825 |
|
|
$ |
17,761 |
|
|
$ |
627,586 |
|
Net
income
|
|
|
142,763 |
|
|
|
1,144 |
|
|
|
143,907 |
|
Net
income per common share – basic
|
|
$ |
3.38 |
|
|
$ |
0.02 |
|
|
$ |
3.40 |
|
Net
income per common share – diluted
|
|
$ |
3.37 |
|
|
$ |
0.02 |
|
|
$ |
3.39 |
|
2008
Divestiture
Whiting USA Trust
I—On April 30, 2008, the Company completed an initial public
offering of units of beneficial interest in Whiting USA Trust I (the
“Trust”), selling 11,677,500 Trust units at $20.00 per Trust unit, providing net
proceeds of $193.8 million after underwriters’ fees, offering expenses, and
post-close adjustments. The Company used the net offering proceeds to
reduce a portion of the debt outstanding under its credit
agreement. The net proceeds from the sale of Trust units to the
public resulted in a deferred gain on sale of $100.1
million. Immediately prior to the closing of the offering, Whiting
conveyed a term net profits interest in certain of its oil and gas properties to
the Trust in exchange for 13,863,889 Trust units. The Company has
retained 15.8%, or 2,186,389 Trust units, of the total Trust units issued and
outstanding.
The net
profits interest entitles the Trust to receive 90% of the net proceeds from the
sale of oil and natural gas production from the underlying
properties. The net profits interest will terminate at the time when
9.11 MMBOE have been produced and sold from the underlying
properties. This is the equivalent of 8.2 MMBOE in respect of the
Trust’s right to receive 90% of the net proceeds from such production pursuant
to the net profits interest, and these reserve quantities are projected to be
produced by December 31, 2021, based on the reserve report for the
underlying properties as of December 31, 2008.
Long-term
debt consisted of the following at June 30, 2009 and December 31, 2008 (in
thousands):
|
|
|
|
|
|
|
Credit
Agreement
|
|
$ |
220,000 |
|
|
$ |
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
$1,341 and $1,541, respectively
|
|
|
218,659 |
|
|
|
218,459 |
|
7.25%
Senior Subordinated Notes due 2012, net of unamortized debt discount of
$331 and $397, respectively
|
|
|
150,906 |
|
|
|
151,292 |
|
Total debt
|
|
$ |
839,565 |
|
|
$ |
1,239,751 |
|
Credit
Agreement—As of June 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 that had a borrowing base of $1.1 billion with $877.2
million of available borrowing capacity, which is net of $220.0 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
entire amount is due. In April 2009, Whiting Oil and Gas entered into
a Fourth Amended and Restated Credit Agreement with its bank syndicate, which
replaced the existing credit agreement. This amended credit agreement
increased the Company’s borrowing base under the facility from $900.0 million to
$1.1 billion and extended the principal repayment date from August 2010 to April
2012.
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 the Company. As of June 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 June 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 June 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 and its wholly-owned subsidiary, Equity Oil Company, have guaranteed
the obligations of Whiting Oil and Gas under the credit
agreement. Whiting Petroleum Corporation has pledged the stock of
Whiting Oil and Gas and Equity Oil Company as security for its guarantee, and
Equity Oil Company has mortgaged substantially all of its properties included in
the borrowing base for the credit agreement as security for its
guarantee.
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 $230.0 million as of June 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 $207.9 million as
of June 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 $143.3 million
as of June 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, Whiting Programs, Inc.
and Equity Oil Company (the “Guarantors”). Any subsidiaries other than the
Guarantors are minor subsidiaries as defined by Rule 3-10(h)(6) of
Regulation S-X of the Securities and Exchange
Commission. Whiting Petroleum Corporation has no assets or operations
independent of this debt and its investments in guarantor
subsidiaries.
Interest Rate
Swap—In August 2004, the Company entered into an interest rate swap
contract to hedge the fair value of $75.0 million of its 7.25% Senior
Subordinated Notes due 2012. The interest rate swap 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
asset retirement obligations by calculating the present value of estimated cash
flows related to plug and abandonment obligations. The current
portions at June 30, 2009 and December 31, 2008 were $10.0 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 six months ended June 30, 2009 (in thousands):
Asset
retirement obligation, January 1, 2009
|
|
$ |
54,348 |
|
Additional
liability incurred
|
|
|
334 |
|
Revisions
in estimated cash flows
|
|
|
16,195 |
|
Accretion
expense
|
|
|
3,757 |
|
Obligations
on sold properties
|
|
|
(94 |
) |
Liabilities
settled
|
|
|
(3,596 |
) |
Asset
retirement obligation, June 30, 2009
|
|
$ |
70,944 |
|
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 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 July 7, 2009.
|
|
Whiting
Petroleum Corporation
|
|
|
|
|
|
|
NYMEX
Price Collar Ranges
|
|
|
|
Crude
Oil
|
|
|
|
|
|
Crude
Oil
|
|
|
Natural
Gas
|
|
Jul
– Dec 2009
|
|
|
2,990,063 |
|
|
|
274,646 |
|
|
|
$
60.53 - $ 77.78
|
|
|
|
$
6.49 - $ 15.23
|
|
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
|
|
|
19,626,482 |
|
|
|
1,590,548 |
|
|
|
|
|
|
|
|
|
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
|
|
Jul
– Dec 2009
|
|
|
68,063 |
|
|
|
274,646 |
|
|
|
$
76.00 - $ 136.07
|
|
|
|
$
6.49 - $ 15.23
|
|
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
|
|
|
414,482 |
|
|
|
1,590,548 |
|
|
|
|
|
|
|
|
|
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
Gas
(Mcf)
|
|
|
Crude
Oil
|
|
|
Natural
Gas
|
|
Jul
– Dec 2009
|
|
|
213,188 |
|
|
|
860,254 |
|
|
|
$
76.00 - $ 136.07
|
|
|
|
$
6.49 - $ 15.23
|
|
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
|
|
|
1,298,255 |
|
|
|
4,981,966 |
|
|
|
|
|
|
|
|
|
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 after tax) of unrealized gains, representing the mark-to-market
value of the Company’s open commodity contracts designated as cash flow hedges
as of 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 and six months ended June 30, 2009, $6.8 million ($4.6 million net of
tax) of derivative gains were reclassified from accumulated other comprehensive
income into earnings relating to de-designated commodity hedges. As
of June 30, 2009, accumulated other comprehensive income amounted to $50.6
million ($32.0 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
$21.2 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”). 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 SFAS 133 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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
Value |
|
Not
Designated as SFAS 133 Hedges
|
Balance
Sheet Classification
|
|
|
June
30, 2009 |
|
|
|
December 31, 2008 |
|
Derivative
assets
|
|
|
|
|
|
|
|
|
|
Commodity
contracts
|
Current
derivative assets
|
|
$ |
8,714 |
|
|
$ |
16,582 |
|
Commodity
contracts
|
Non-current
derivative assets
|
|
|
13,520 |
|
|
|
24,941 |
|
Total
derivative assets
|
|
|
22,234 |
|
|
|
41,523 |
|
Derivative
liabilities
|
|
|
|
|
|
|
|
|
|
Commodity
contracts
|
Current
derivative liabilities
|
|
$ |
34,362 |
|
|
$ |
12,570 |
|
Commodity
contracts
|
Non-current
derivative liabilities
|
|
|
97,894 |
|
|
|
18,907 |
|
Total
derivative liabilities
|
|
$ |
132,256 |
|
|
$ |
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 six months ended June 30, 2009 and 2008 (in thousands).
|
|
|
Gain
(Loss) Recognized in OCI
(Effective
Portion)
|
|
|
|
|
Six
Months Ended June 30,
|
|
SFAS
133 Cash
Flow Hedging Relationships
|
Location
of Gain
(Loss) Not Recognized in
Income
|
|
|
|
|
|
|
Commodity
contracts
|
Other
comprehensive income
|
|
$ |
21,008 |
|
|
$ |
(126,272 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
Commodity
contracts
|
Other
comprehensive income
|
|
$ |
- |
|
|
$ |
(104,895 |
) |
|
|
|
Gain
(Loss) Reclassified from AOCI into Income (Effective
Portion)
|
|
|
|
|
Six
Months Ended June 30,
|
|
SFAS
133 Cash Flow Hedging
Relationships
|
Income
Statement Classification
|
|
|
|
|
|
|
Commodity
contracts
|
Gain
(loss) on oil hedging activities
|
|
$ |
20,298 |
|
|
$ |
(71,023 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
Commodity
contracts
|
Gain
(loss) on oil hedging activities
|
|
$ |
6,848 |
|
|
$ |
(48,111 |
) |
|
|
|
(Gain)
Loss Recognized in Income (Ineffective Portion)
|
|
|
|
|
Six
Months Ended June 30,
|
|
SFAS
133 Cash Flow
Hedging
Relationships
|
Income
Statement Classification
|
|
|
|
|
|
|
Commodity
contracts
|
Loss
on mark-to-market derivatives
|
|
$ |
22,866 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
Commodity
contracts
|
Loss
on mark-to-market derivatives
|
|
$ |
- |
|
|
$ |
- |
|
|
|
|
(Gain)
Loss Recognized in Income
|
|
|
|
|
Six
Months Ended June 30,
|
|
Not
Designated as
SFAS 133 Hedges
|
Income
Statement Classification
|
|
|
|
|
|
|
Commodity
contracts
|
Loss
on mark-to-market derivatives
|
|
$ |
159,431 |
|
|
$ |
17,625 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
Commodity
contracts
|
Loss
on mark-to-market derivatives
|
|
$ |
160,532 |
|
|
$ |
20,562 |
|
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 six months ended June 30, 2009 and 2008 were as follows
(in thousands):
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30,
|
|
|
Six
Months Ended June 30,
|
|
Income
Statement Classification
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
$ |
(330 |
) |
|
$ |
(125 |
) |
|
$ |
330 |
|
|
$ |
125 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended June 30,
|
|
|
Three
Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
$ |
- |
|
|
$ |
(1,730 |
) |
|
$ |
- |
|
|
$ |
1,730 |
|
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
|
Effective
January 1, 2008, the Company adopted FASB Statement No. 157, Fair Value Measurements
(“SFAS 157”) which established a three-level valuation hierarchy for
disclosure of fair value measurements. The valuation hierarchy
categorizes assets and liabilities measured at fair value into one of three
different levels depending on the observability of the inputs employed in the
measurement. The three levels are defined as follows:
·
|
Level
1: Quoted Prices in Active Markets for Identical Assets – inputs to the
valuation methodology are quoted prices (unadjusted) for identical
assets or liabilities in active
markets.
|
·
|
Level
2: Significant Other Observable Inputs – inputs to the valuation
methodology include quoted prices for similar assets and liabilities in
active markets, and inputs that are observable for the asset or liability,
either directly or indirectly, for substantially the full term of the
financial instrument.
|
·
|
Level
3: Significant Unobservable Inputs – inputs to the valuation methodology
are unobservable and significant to the fair value
measurement.
|
A
financial instrument’s categorization within the valuation hierarchy is based
upon the lowest level of input that is significant to the fair value
measurement. The Company’s assessment of the significance of a
particular input to the fair value measurement in its entirety requires judgment
and considers factors specific to the asset or liability. The
following table presents information about the Company’s financial assets and
liabilities measured at fair value on a recurring basis as of June 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
June
30, 2009
|
|
Financial
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivatives - current
|
|
$ |
- |
|
|
$ |
8,714 |
|
|
$ |
- |
|
|
$ |
8,714 |
|
Commodity
derivatives - non-current
|
|
|
- |
|
|
|
13,520 |
|
|
|
- |
|
|
|
13,520 |
|
Total
financial assets
|
|
$ |
- |
|
|
$ |
22,234 |
|
|
$ |
- |
|
|
$ |
22,234 |
|
Financial
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivatives - current
|
|
$ |
- |
|
|
$ |
34,362 |
|
|
$ |
- |
|
|
$ |
34,362 |
|
Commodity
derivatives - non-current
|
|
|
- |
|
|
|
97,894 |
|
|
|
- |
|
|
|
97,894 |
|
Total
financial liabilities
|
|
$ |
- |
|
|
$ |
132,256 |
|
|
$ |
- |
|
|
$ |
132,256 |
|
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 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 six
months ended June 30, 2009 and 2008 amounted to $5.7 million and $20.5 million,
respectively, charged to general and administrative expense and $0.8 million and
$3.3 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 June 30, 2009, the
Company used three-year average historical NYMEX prices of $78.63 for crude oil
and $7.17 for natural gas to estimate this liability. If the Company
were to terminate the Plan or upon a change in control (as defined in the Plan),
all employees fully vest, and the Company would distribute to each Plan
participant an amount based upon the valuation method set forth in the Plan in a
lump sum payment twelve months after the date of termination or within one month
after a change in control event. Based on prices at June 30, 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 $108.2 million. This amount includes
$17.7 million attributable to proved undeveloped oil and gas properties and $6.5
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 six months ended June 30, 2009 (in thousands):
Production
Participation Plan liability, January 1, 2009
|
|
$ |
66,166 |
|
Change
in liability for accretion, vesting and changes in
estimates
|
|
|
10,225 |
|
Reduction
in liability for cash payments accrued and recognized as compensation
expense
|
|
|
(6,545 |
) |
Production
Participation Plan liability, June 30, 2009
|
|
$ |
69,846 |
|
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
$334.6 million after underwriters’ fees and offering expenses. The
Company used the net offering proceeds to repay a portion of the debt
outstanding under Whiting Oil and Gas’ credit agreement.
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 with the
first dividend payment 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 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.
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 offering proceeds to
repay a portion of the debt outstanding under Whiting Oil and Gas’ credit
agreement. Whiting plans to use the increased credit availability to
fund a portion of the planned capital expenditures in its 2009 capital
budget.
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 six months ended June
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.
10.
|
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
(“SFAS 168”). This standard
replaces SFAS No. 162, The
Hierarchy of Generally Accepted Accounting Principles, and establishes
only two levels of GAAP, authoritative and nonauthoritative. The FASB
Accounting Standards Codification (the “Codification”) was not intended to
change or alter existing GAAP, and it therefore will not have any impact on the
Company’s consolidated financial statements other than to modify certain
existing disclosures. The Codification 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 Codification will become
nonauthoritative. SFAS 168 is effective for financial statements for
interim or annual reporting periods ending after September 15,
2009. The Company will begin to use the new guidelines and numbering
system prescribed by the Codification when referring to GAAP in the third
quarter of fiscal 2009.
In May
2009, the FASB issued SFAS No. 165, Subsequent Events (“SFAS
165”). 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. The
adoption of SFAS 165 did not have an impact on the Company’s 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 ("FSP
157-4"), provides additional guidelines for estimating fair value in accordance
with SFAS No. 157, Fair Value
Measurements. FSP No. 107-1 and APB 28-1, Interim Disclosures about Fair Value
of Financial Instruments (“FSP 107-1”), 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. The adoption of these FSPs did not have
an impact on the Company’s 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,
which 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. 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 half 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, Equity Oil Company
and Whiting Programs, Inc. When the context requires, we refer to
these entities separately. This document contains forward-looking
statements, which give our current expectations or forecasts of future
events. Please refer to “Forward-Looking Statements” at the end of
this Item for an explanation of these types of statements.
Overview
We are an
independent oil and gas company engaged in oil and gas acquisition, development,
exploitation, production and exploration activities primarily in the Permian
Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the
United States. Prior to 2006, we generally emphasized the acquisition
of properties that increased our production levels and provided upside potential
through further development. Since 2006, we have focused primarily on
organic drilling activity and on the development of previously acquired
properties, specifically on projects that we believe provide the opportunity for
repeatable successes and production growth. We believe the
combination of acquisitions, subsequent development and organic drilling
provides us a broad set of growth alternatives and allows us to direct our
capital resources to what we believe to be the most advantageous
investments.
As
demonstrated by our recent capital expenditure programs, we are increasingly
focused on a balance between exploration and development programs and continuing
to selectively pursue acquisitions that complement our existing core
properties. We believe that our significant drilling inventory,
combined with our operating experience and cost structure, provides us with
meaningful organic growth opportunities. Our growth plan is centered
on the following activities:
|
•
|
pursuing
the development of projects that we believe will generate attractive rates
of return;
|
|
•
|
maintaining
a balanced portfolio of lower risk, long-lived oil and gas properties that
provide stable cash flows;
|
|
•
|
seeking
property acquisitions that complement our core
areas; and
|
|
•
|
allocating
a portion of our capital budget to leasing and exploring prospect
areas.
|
We have
historically acquired operated and non-operated properties that exceed our rate
of return criteria. For acquisitions of properties with additional
development, exploitation and exploration potential, our focus has been on
acquiring operated properties so that we can better control the timing and
implementation of capital spending. In some instances, we have been
able to acquire non-operated property interests at attractive rates of return
that established a presence in a new area of interest or that have complemented
our existing operations. We intend to continue to acquire both
operated and non-operated interests to the extent we believe they meet our
return criteria. In addition, our willingness to acquire non-operated
properties in new geographic regions provides us with geophysical and geologic
data in some cases that leads to further acquisitions in the same region,
whether on an operated or non-operated basis. We sell properties when
we believe that the sales price realized will provide an above average rate of
return for the property or when the property no longer matches the profile of
properties we desire to own.
Oil and
natural gas prices have fallen significantly since their third quarter 2008
levels. For example, the daily average NYMEX oil price was $118.13 per Bbl
for the third quarter of 2008, $58.75 per Bbl for the fourth quarter of 2008,
and $51.46 per Bbl for the first six 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 $4.21 for
the first six 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 income and operating result 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 $334.6
million after underwriters’ fees and offering expenses. We used the
net offering proceeds to repay a portion of the debt outstanding under Whiting
Oil and Gas’ credit agreement.
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 with the first dividend
payment 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 has 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.
As of
June 4, 2009, there were 18 wells drilled or in the process of being drilled on
the 26 units covered by the agreement and 12 more wells planned in 2009 on these
units. 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 the 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 offering proceeds to repay a
portion of the debt outstanding under Whiting Oil and Gas’ credit agreement, and
we plan to use the increased credit availability to fund a portion of the
planned capital expenditures in our 2009 capital budget.
Operational
Highlights. Our Sanish and Parshall fields in Mountrail
County, North Dakota target the Bakken formation. Net production in
the Sanish field increased 200% from a net 3.4 MBOE/d in June 2008 to a net 10.2
MBOE/d in June 2009. Net production in the Parshall field increased
6% from a net 5.0 MBOE/d in June 2008 to a net 5.3 MBOE/d in June
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
half of 2009, we incurred $98.5 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 July 17, 2009, we were injecting 130 MMcf/d
of CO2
in this field. Production from the field has increased 39% from a net
6.3 MBOE/d in June 2008 to a net 8.7 MBOE/d in June 2009. Operations
are under way to expand CO2 injection
into the northern part of the fourth unit, HMU, and to optimize flood patterns
in the existing CO2
floods. These expansion projects include the restoration of shut-in
wells and the drilling of new producing and injection wells.
The North
Ward Estes field is 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 July 17, 2009, we
were injecting 144 MMcf/d of CO2 in this
field. Production from the field has increased 22% from a net 5.4
MBOE/d in June 2008 to a net 6.5 MBOE/d in June 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
Six
Months Ended June 30, 2009 Compared to Six Months Ended June 30,
2008
Selected
Operating Data:
|
|
Six
Months Ended June
30,
|
|
|
|
|
|
|
|
|
Net
production:
|
|
|
|
|
|
|
Oil
(MMBbls)
|
|
|
7.3 |
|
|
|
5.4 |
|
Natural
gas (Bcf)
|
|
|
15.5 |
|
|
|
14.2 |
|
Total
production (MMBOE)
|
|
|
9.9 |
|
|
|
7.8 |
|
|
|
|
|
|
|
|
|
|
Net
sales (in millions):
|
|
|
|
|
|
|
|
|
Oil
(1)
|
|
$ |
307.3 |
|
|
$ |
549.4 |
|
Natural
gas (1)
|
|
|
53.2 |
|
|
|
127.9 |
|
Total
oil and natural gas sales
|
|
$ |
360.5 |
|
|
$ |
677.3 |
|
|
|
|
|
|
|
|
|
|
Average
sales prices:
|
|
|
|
|
|
|
|
|
Oil
(per Bbl)
|
|
$ |
41.85 |
|
|
$ |
101.88 |
|
Effect
of oil hedges on average price (per Bbl)
|
|
|
1.40 |
|
|
|
(13.17 |
) |
Oil
net of hedging (per Bbl)
|
|
$ |
43.25 |
|
|
$ |
88.71 |
|
Average
NYMEX price
|
|
$ |
51.46 |
|
|
$ |
110.98 |
|
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$ |
3.44 |
|
|
$ |
8.99 |
|
Effect
of natural gas hedges on average price (per Mcf)
|
|
|
0.04 |
|
|
|
- |
|
Natural
gas net of hedging (per Mcf)
|
|
$ |
3.48 |
|
|
$ |
8.99 |
|
Average
NYMEX price
|
|
$ |
4.21 |
|
|
$ |
9.49 |
|
|
|
|
|
|
|
|
|
|
Cost
and expense (per BOE):
|
|
|
|
|
|
|
|
|
Lease
operating expenses
|
|
$ |
11.95 |
|
|
$ |
14.58 |
|
Production
taxes
|
|
$ |
2.46 |
|
|
$ |
5.63 |
|
Depreciation,
depletion and amortization expense
|
|
$ |
20.19 |
|
|
$ |
13.56 |
|
General
and administrative expenses
|
|
$ |
1.94 |
|
|
$ |
4.46 |
|
(1) Before
consideration of hedging transactions.
Oil and Natural Gas
Sales. Our oil and natural gas sales revenue decreased $316.8
million to $360.5 million in the first half 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 36% between periods, while
our natural gas sales volumes increased 9%. The oil volume increase
resulted primarily from drilling success in the North Dakota Bakken area in
addition to increased production at our two large CO2 projects,
Postle and North Ward Estes. Oil production from the Bakken area
increased 1,775 MBbl compared to the first half of 2008, while Postle oil
production increased 295 MBbl and North Ward Estes oil production increased 250
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 230 MBbl, as well as normal field production
decline. The gas volume increase between periods was primarily the
result of incremental gas production of 1,795 MMcf from the Flat Rock
acquisition, which we completed on May 30, 2008, and higher production due to
well completions in the Boies Ranch area of 1,315 MMcf, in the Gulf Coast region
of 995 MMcf and in the North Dakota Bakken area of 585 MMcf. These
production increases were partially offset by the Trust divestiture, which
decreased gas production by 1,155 MMcf, as well as normal field production
decline. Offsetting the production increases were decreases in
average sales prices. Our average price for oil before effects of
hedging decreased 59% between periods, and our average price for natural gas
before effects of hedging decreased 62%.
Gain (Loss) on Oil Hedging
Activities. Realized cash settlements on commodity derivatives that
we have designated as cash flow hedges are recognized as gain (loss) on oil
hedging activities. During the first half of 2009, we incurred cash
settlement gains of $13.5 million on such crude oil hedges. During
the first half of 2008, we incurred realized cash settlement losses of $71.0
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
six 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 $6.8 million in
unrealized noncash gains upon the expiration of these de-designated crude oil
hedges during the second quarter of 2009. See Item 3,
“Qualitative and Quantitative Disclosures About Market Risk” for a list of our
outstanding oil and natural gas derivatives as of July 7, 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 six months ended June 30, 2009 and 2008, we recognized
$8.4 million and $3.0 million, respectively, in income as amortization of
deferred gain on sale.
Gain on Sale of
Properties.
During the six months ended June 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. There was no gain or loss on the sale of properties during
the six months ended June 30, 2008.
Lease Operating
Expenses. Our lease operating expenses during the first half
of 2009 were $118.5 million, a $5.4 million or 5% increase over the same period
in 2008. Our lease operating expenses per BOE, however, decreased
from $14.58 during the first half of 2008 to $11.95 during the first half of
2009. The decrease of 18% on a BOE basis was primarily caused by
increased production and a decrease of $6.3 million in electric power and fuel
costs during the first half of 2009 as compared to the first half of 2008,
partially offset by a high level of workover activity. Workovers
amounted to $26.3 million in the first half of 2009, as compared to
$8.4 million in the first half of 2008. The increase in workover
activity primarily relates to our two CO2 projects,
which are evolving past the construction and start-up phases and moving into an
ongoing maintenance and repair phase that involves a significantly higher number
of producing and injection wells.
Production
Taxes. The production taxes we pay are generally calculated as
a percentage of oil and natural gas sales revenue before the effects of
hedging. We take advantage of all credits and exemptions allowed in
our various taxing jurisdictions. Our production taxes for the first
half of 2009 and 2008 were 6.8% and 6.5%, respectively, of oil and natural gas
sales. Our production tax rate for the first half of 2009 was greater
than the rate for same period in 2008 mainly due to successful wells completed
in the North Dakota Bakken area during the latter half of 2008, which carry an
11.5% production tax rate.
Depreciation, Depletion and
Amortization. Our depreciation, depletion and amortization
(“DD&A”) expense increased $95.0 million as compared to the first half of
2008. The components of our DD&A expense were as follows (in
thousands):
|
|
Six
Months Ended June
30,
|
|
|
|
|
|
|
|
|
Depletion
|
|
$ |
194,993 |
|
|
$ |
102,251 |
|
Depreciation
|
|
|
1,599 |
|
|
|
1,594 |
|
Accretion
of asset retirement obligations
|
|
|
3,757 |
|
|
|
1,477 |
|
Total
|
|
$ |
200,349 |
|
|
$ |
105,322 |
|
DD&A
increased $95.0 million primarily due to $92.7 million in higher depletion
expense between periods. Of this $92.7 million increase in depletion,
$28.4 million related to higher oil and gas volumes produced during the first
half of 2009, while $64.3 million related to our higher depletion rate in
2009. On a BOE basis, our DD&A rate increased by 49% from $13.56
for the first half of 2008 to $20.19 for the first half of 2009. The
primary factors causing this rate increase were (i) $787.3 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 $7.5
million, as compared to the first half of 2008. The components of
exploration and impairment costs were as follows (in thousands):
|
|
Six
Months Ended June
30,
|
|
|
|
|
|
|
|
|
Exploration
|
|
$ |
18,811 |
|
|
$ |
14,227 |
|
Impairment
|
|
|
8,295 |
|
|
|
5,400 |
|
Total
|
|
$ |
27,106 |
|
|
$ |
19,627 |
|
Exploration
costs increased $4.6 million during the first half of 2009 as compared to the
same period in 2008 primarily due to rig termination fees recognized in the
first quarter of 2009, partially offset by decreased accrued Production
Participation Plan payments for geological and geophysical (“G&G”)
personnel. Rig termination fees totaled $7.5 million during the first
half of 2009, while we did not pay any rig termination fees in the first half of
2008. Accrued Production Participation Plan distributions for
exploration personnel were $2.5 million lower during the first half of 2009 as
compared to the same prior year period. The impairment charges in the
first half of 2009 and 2008 were primarily related to the amortization of
leasehold costs associated with individually insignificant unproved
properties. As of June 30, 2009, the amount of unproved
properties being amortized totaled $81.6 million, as compared to $72.8 million
as of June 30, 2008.
General and Administrative
Expenses. We report general and administrative expenses net of
third party reimbursements and internal allocations. The components
of our general and administrative expenses were as follows (in
thousands):
|
|
Six
Months Ended June
30,
|
|
|
|
|
|
|
|
|
General
and administrative expenses
|
|
$ |
43,683 |
|
|
$ |
54,314 |
|
Reimbursements
and allocations
|
|
|
(24,421 |
) |
|
|
(19,692 |
) |
General
and administrative expense, net
|
|
$ |
19,262 |
|
|
$ |
34,622 |
|
General
and administrative expense before reimbursements and allocations decreased $10.6
million to $43.7 million during the first half of 2009. The largest
component of the decrease related to $17.3 million in lower accrued
distributions under our Production Participation Plan (“Plan”) between periods
due to a lower level of Plan net revenues (which have been reduced by lease
operating expenses and production taxes pursuant to the Plan formula) resulting
from lower oil and natural gas prices during the first half of 2009 as compared
to the same period of 2008, as well as the Trust divestiture completed in April
2008. These lower accrued Plan distributions were partially offset by
$3.6 million in additional employee compensation for personnel hired during the
past twelve months as well as general pay increases. The increase in
reimbursements and allocations in 2009 was primarily caused by higher salary
costs and a greater number of field workers on operated
properties. Our general and administrative expenses as a percentage
of oil and natural gas sales remained constant at 5% for the first half of 2009
and 2008.
Interest
Expense. The components of our interest expense were as
follows (in thousands):
|
|
Six
Months Ended June
30,
|
|
|
|
|
|
|
|
|
Senior
Subordinated Notes
|
|
$ |
21,745 |
|
|
$ |
21,943 |
|
Credit
Agreement
|
|
|
8,153 |
|
|
|
7,652 |
|
Amortization
of debt issue costs and debt discount
|
|
|
4,355 |
|
|
|
2,423 |
|
Other
|
|
|
933 |
|
|
|
733 |
|
Capitalized
interest
|
|
|
(1,813 |
) |
|
|
(1,534 |
) |
Total
interest expense
|
|
$ |
33,373 |
|
|
$ |
31,217 |
|
The
increase in interest expense of $2.2 million between periods was mainly due to
increased amortization of $23.1 million in additional debt issue costs, which
were incurred in April 2009 in connection with renewing our credit
agreement. Our weighted average effective cash interest rate was 5.0%
during the first half of 2009 compared to 6.4% during the first half of
2008. Our weighted average debt outstanding during the first half of
2009 was $1,210.9 million versus $929.2 million for the first half of
2008. After inclusion of non-cash interest costs for the amortization
of debt issue costs, debt discount and the accretion of the tax sharing
liability, our weighted average effective all-in interest rate was 5.7% during
the first half of 2009 compared to 6.9% during the first half of
2008.
Change in Production Participation
Plan Liability. For the six months ended June 30, 2009, this
non-cash expense was $3.7 million, a decrease of $14.2 million as compared to
the same period in 2008. This expense represents the change in the
vested present value of estimated future payments to be made to participants
after 2010 under our Plan. Although payments take place over the life
of the Plan’s oil and gas properties, which for some properties is over 20
years, we expense the present value of estimated future payments over the Plan’s
five-year vesting period. This expense in 2009 and 2008 primarily
reflected (i) changes to future cash flow estimates stemming from the volatile
commodity price environment during the first half 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 $0.81 for crude oil and $0.43 for natural
gas for the six months ended June 30, 2009, as compared to increases of $15.51
for crude oil and $0.74 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.
Loss on Mark-to-Market
Derivatives. 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 (gain) loss on mark-to-market
derivatives. The components of our loss on mark-to-market derivatives
were as follows (in thousands):
|
|
Six
Months Ended June
30,
|
|
|
|
|
|
|
|
|
Unrealized
mark-to-market derivative losses
|
|
$ |
156,973 |
|
|
$ |
17,625 |
|
Realized
cash settlement losses
|
|
|
2,458 |
|
|
|
- |
|
Loss
on hedging ineffectiveness
|
|
|
22,866 |
|
|
|
- |
|
Total
loss on mark-to-market derivatives
|
|
$ |
182,297 |
|
|
$ |
17,625 |
|
The
increase of $139.3 million in unrealized mark-to-market derivative losses during
the first half of 2009 as compared to the same prior year period was due to the
fact that (i) we averaged 21.3 MMBbls of crude oil hedged during the six months
ended June 30, 2009, while we only averaged 3.3 MMBbls of crude oil hedged
during the six months ended June 30, 2008, and (ii) there was a significant
upward shift in the forward price curve for NYMEX crude oil during the six
months ended June 30, 2009.
Income Tax Expense
(Benefit). Income tax benefit totaled $78.1 million for the
first half of 2009, versus $83.9 million of income tax expense for the first
half of 2008. Our effective income tax rate decreased from 37.0% for
the first half of 2008 to 36.3% for the first half of 2009.
Net Income
(Loss). Net income (loss) decreased from $142.8 million in
income during the first half of 2008 to a $136.9 million loss during the first
half of 2009. The primary reasons for this decrease include a 51%
decrease in oil prices (net of hedging); a 61% decrease in natural gas prices
(net of hedging); higher losses on mark-to-market derivatives, lease operating
expenses, DD&A, exploration and impairment and interest
expense. These negative factors were partially offset by a 28%
increase in equivalent volumes sold; lower 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 half of 2009.
Three
Months Ended June 30, 2009 Compared to Three Months Ended June 30,
2008
Selected
Operating Data:
|
|
Three
Months Ended June
30,
|
|
|
|
|
|
|
|
|
Net
production:
|
|
|
|
|
|
|
Oil
(MMBbls)
|
|
|
3.8 |
|
|
|
2.8 |
|
Natural
gas (Bcf)
|
|
|
7.6 |
|
|
|
7.3 |
|
Total
production (MMBOE)
|
|
|
5.0 |
|
|
|
4.0 |
|
|
|
|
|
|
|
|
|
|
Net
sales (in millions):
|
|
|
|
|
|
|
|
|
Oil
(1)
|
|
$ |
191.0 |
|
|
$ |
316.9 |
|
Natural
gas (1)
|
|
|
23.3 |
|
|
|
73.6 |
|
Total
oil and natural gas sales
|
|
$ |
214.3 |
|
|
$ |
390.5 |
|
|
|
|
|
|
|
|
|
|
Average
sales prices:
|
|
|
|
|
|
|
|
|
Oil
(per Bbl)
|
|
$ |
50.66 |
|
|
$ |
113.28 |
|
Effect
of oil hedges on average price (per Bbl)
|
|
|
(1.15 |
) |
|
|
(17.19 |
) |
Oil
net of hedging (per Bbl)
|
|
$ |
49.51 |
|
|
$ |
96.09 |
|
Average
NYMEX price
|
|
$ |
59.62 |
|
|
$ |
124.00 |
|
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$ |
3.08 |
|
|
$ |
10.02 |
|
Effect
of natural gas hedges on average price (per Mcf)
|
|
|
0.05 |
|
|
|
- |
|
Natural
gas net of hedging (per Mcf)
|
|
$ |
3.13 |
|
|
$ |
10.02 |
|
Average
NYMEX price
|
|
$ |
3.50 |
|
|
$ |
10.94 |
|
|
|
|
|
|
|
|
|
|
Cost
and expense (per BOE):
|
|
|
|
|
|
|
|
|
Lease
operating expenses
|
|
$ |
11.44 |
|
|
$ |
14.29 |
|
Production
taxes
|
|
$ |
2.96 |
|
|
$ |
6.48 |
|
Depreciation,
depletion and amortization expense
|
|
$ |
19.93 |
|
|
$ |
13.63 |
|
General
and administrative expenses
|
|
$ |
2.04 |
|
|
$ |
5.72 |
|
(1) Before
consideration of hedging transactions.
Oil and Natural Gas
Sales. Our oil and natural gas sales revenue decreased $176.2
million to $214.3 million in the second quarter of 2009 compared to the second
quarter of 2008. Sales are a function of volumes sold and average
sales prices. Our oil sales volumes increased 35% between periods,
while our natural gas sales volumes increased 3%. 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
785 MBbl compared to the second quarter of 2008, while Postle oil production
increased 165 MBbl and North Ward Estes oil production increased 125 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 55 MBbl, as well as normal field production
decline. The gas volume increase between periods was primarily the
result of incremental gas production of 610 MMcf from the Flat Rock acquisition,
which we completed on May 30, 2008, and higher production due to well
completions in the Boies Ranch area of 435 MMcf, in the Gulf Coast region of 345
MMcf, and in the North Dakota Bakken area of 325 MMcf. These
production increases were partially offset by the Trust divestiture, which
decreased gas production by 260 MMcf, as well as normal field production
decline. Offsetting the production increases were lower average sales
prices. Our average price for oil before effects of hedging decreased
55% between periods, and our average price for natural gas before effects of
hedging decreased 69%.
Gain (Loss) on Oil Hedging
Activities. Realized cash settlements on commodity derivatives that
we have designated as cash flow hedges are recognized as gain (loss) on oil
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 $6.8 million in
unrealized noncash gains upon the expiration of these de-designated crude oil
hedges during the second quarter of 2009. None of our oil derivatives
were designated as cash flow hedges during the second quarter of
2009. During the second quarter of 2008, we incurred realized cash
settlement losses of $48.1 million on crude oil derivatives designated as cash
flow hedges. None of our natural gas derivatives were designated as cash
flow hedges during the second 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 July 7, 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 June 30, 2009 and 2008, we
recognized $4.3 million and $3.0 million, respectively, in income as
amortization of deferred gain on sale.
Gain on Sale of
Properties.
During the three months ended June 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. There was no gain or loss on the sale of properties during
the three months ended June 30, 2008.
Lease Operating
Expenses. Our lease operating expenses during the second
quarter of 2009 were $57.6 million, a $0.1 million increase over the same period
in 2008. Our lease operating expenses per BOE, however, decreased
from $14.29 during the second quarter of 2008 to $11.44 during the second
quarter of 2009. The decrease of 20% on a BOE basis was primarily
caused by increased production and decreased electric power and fuel costs of
$5.7 million during the second quarter of 2009 as compared to the same period in
2008, partially offset by a high level of workover
activity. Workovers amounted to $12.2 million in the second quarter
of 2009, as compared to $4.5 million in the second quarter of
2008. The increase in workover activity primarily relates to our two
CO2
projects, which are evolving past the construction and start-up phases and
moving into an ongoing maintenance and repair phase that involves a
significantly higher number of producing and injection wells.
Production
Taxes. The production taxes we pay are generally calculated as
a percentage of oil and natural gas sales revenue before the effects of
hedging. We take advantage of all credits and exemptions allowed in
our various taxing jurisdictions. Our production taxes for the second
quarter of 2009 and 2008 were 7.0% and 6.7%, respectively, of oil and natural
gas sales. Our production tax rate for the second quarter of 2009 was
greater than the rate for same period in 2008 mainly due to successful wells
completed in the North Dakota Bakken area during the latter half of 2008, which
carry an 11.5% production tax rate.
Depreciation, Depletion and
Amortization. Our depreciation, depletion and amortization
(“DD&A”) expense increased $45.5 million as compared to the second quarter
of 2008. The components of our DD&A expense were as follows (in
thousands):
|
|
Three
Months Ended June
30,
|
|
|
|
|
|
|
|
|
Depletion
|
|
$ |
97,989 |
|
|
$ |
53,207 |
|
Depreciation
|
|
|
767 |
|
|
|
843 |
|
Accretion
of asset retirement obligations
|
|
|
1,559 |
|
|
|
761 |
|
Total
|
|
$ |
100,315 |
|
|
$ |
54,811 |
|
DD&A
increased $45.5 million primarily due to $44.8 million in higher depletion
expense between periods. Of this $44.8 million increase in depletion,
$13.4 million related to higher oil and gas volumes produced during the second
quarter of 2009, while $31.4 million related to our higher depletion rate in
2009. On a BOE basis, our DD&A rate increased by 46% from $13.63
for the second quarter of 2008 to $19.93 for the second quarter of
2009. The primary factors causing this rate increase were (i) $787.3
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 $1.1
million, as compared to the second quarter of 2008. The components of
exploration and impairment costs were as follows (in thousands):
|
|
Three
Months Ended June
30,
|
|
|
|
|
|
|
|
|
Exploration
|
|
$ |
6,178 |
|
|
$ |
5,815 |
|
Impairment
|
|
|
3,614 |
|
|
|
2,828 |
|
Total
|
|
$ |
9,792 |
|
|
$ |
8,643 |
|
Exploration
costs increased $0.4 million during the second quarter of 2009 as compared to
the same period in 2008 primarily due to rig termination fees recognized in the
second quarter of 2009 and increased G&G activity, partially offset by a
decrease in accrued Production Participation Plan payments for exploration
personnel. Rig termination fees totaled $1.3 million during the
second quarter of 2009, while we did not pay any rig termination fees in the
second quarter of 2008. G&G costs increased as a result of $1.3
million in additional seismic related costs incurred during the second quarter
of 2009, as compared to the second quarter of 2008. Accrued
Production Participation Plan distributions for exploration personnel were $0.6
million lower during the second quarter of 2009 as compared to the same prior
year period. The impairment charges in the second quarter of 2009 and
2008 were primarily related to the amortization of leasehold costs associated
with individually insignificant unproved properties. As of
June 30, 2009, the amount of unproved properties being amortized totaled
$81.6 million, as compared to $72.8 million as of June 30, 2008.
General and Administrative
Expenses. We report general and administrative expenses net of
third party reimbursements and internal allocations. The components
of our general and administrative expenses were as follows (in
thousands):
|
|
Three
Months Ended June
30,
|
|
|
|
|
|
|
|
|
General
and administrative expenses
|
|
$ |
22,687 |
|
|
$ |
33,203 |
|
Reimbursements
and allocations
|
|
|
(12,405 |
) |
|
|
(10,196 |
) |
General
and administrative expense, net
|
|
$ |
10,282 |
|
|
$ |
23,007 |
|
General
and administrative expense before reimbursements and allocations decreased $10.5
million to $22.7 million during the second quarter of 2009. The
largest component of the decrease related to $13.1 million in lower accrued
distributions under our Production Participation Plan (“Plan”) between periods
due to a lower level of Plan net revenues (which have been reduced by lease
operating expenses and production taxes pursuant to the Plan formula) resulting
from lower oil and natural gas prices during the second quarter of 2009 as
compared to the same period of 2008, as well as the Trust divestiture completed
in April 2008. These lower accrued Plan distributions were partially
offset by $1.0 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 expenses as a percentage
of oil and natural gas sales decreased from 6% for the second quarter of 2008 to
5% for the second quarter of 2009.
Interest
Expense. The components of our interest expense were as
follows (in thousands):
|
|
Three
Months Ended June
30,
|
|
|
|
|
|
|
|
|
Senior
Subordinated Notes
|
|
$ |
10,977 |
|
|
$ |
10,863 |
|
Credit
Agreement
|
|
|
4,940 |
|
|
|
3,735 |
|
Amortization
of debt issue costs and debt discount
|
|
|
3,183 |
|
|
|
1,206 |
|
Other
|
|
|
482 |
|
|
|
379 |
|
Capitalized
interest
|
|
|
(889 |
) |
|
|
(512 |
) |
Total
interest expense
|
|
$ |
18,693 |
|
|
$ |
15,671 |
|
The
increase in interest expense of $3.0 million between periods was mainly due to a
higher level of debt outstanding under our credit agreement and increased
amortization of incremental debt issue costs that were added during the second
quarter of 2009, partially offset by lower interest rates on borrowings under
our credit agreement during the second quarter of 2009. As a result
of our renewing our credit agreement, we incurred debt issue costs of $23.1
million. Our weighted average effective cash interest rate was 5.6%
during the second quarter of 2009 compared to 6.1% during the second quarter of
2008. Our weighted average debt outstanding during the second quarter
of 2009 was $1,206.0 million versus $956.7 million for the second quarter of
2008. After inclusion of non-cash interest costs for the amortization
of debt issue costs, debt discount and the accretion of the tax sharing
liability, our weighted average effective all-in interest rate was 6.7% during
the second quarter of 2009 compared to 6.6% during the second quarter of
2008.
Change in Production Participation
Plan Liability. For the three months ended June 30, 2009, this
non-cash expense was $3.3 million, a decrease of $8.4 million as compared to the
same period in 2008. This expense represents the change in the vested
present value of estimated future payments to be made to participants after 2010
under our Plan. Although payments take place over the life of the
Plan’s oil and gas properties, which for some properties is over 20 years, we
expense the present value of estimated future payments over the Plan’s five-year
vesting period. This expense in 2009 and 2008 primarily reflected (i)
changes to future cash flow estimates stemming from the volatile commodity price
environment during the second 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 increased by $0.01 for crude oil and decreased by $0.21 for natural
gas for the three months ended June 30, 2009, as compared to increases of $12.28
for crude oil and $0.55 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.
Loss on Mark-to-Market
Derivatives. 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 (gain) loss on mark-to-market derivatives. The
components of our loss on mark-to-market derivatives were as follows (in
thousands):
|
|
Three
Months Ended June
30,
|
|
|
|
|
|
|
|
|
Unrealized
mark-to-market derivative losses
|
|
$ |
156,544 |
|
|
$ |
20,562 |
|
Realized
cash settlement losses
|
|
|
3,988 |
|
|
|
- |
|
Total
loss on mark-to-market derivatives
|
|
$ |
160,532 |
|
|
$ |
20,562 |
|
The
increase of $136.0 million in unrealized mark-to-market derivative losses during
the second quarter of 2009 as compared to the same prior year period was due to
the fact that (i) we averaged 20.4 MMBbls of crude oil hedged during the three
months ended June 30, 2009, while we only averaged 3.1 MMBbls of crude oil
hedged during the three months June 30, 2008, and (ii) there was a significant
upward shift in the forward price curve for NYMEX crude oil during the three
months ended June 30, 2009.
Income Tax Expense
(Benefit). Income tax benefit totaled $52.1 million for the
second quarter of 2009, versus $47.4 million of income tax expense for the
second quarter of 2008. Our effective income tax rate decreased from
37.1% for the second quarter of 2008 to 35.9% for the second quarter of
2009.
Net Income
(Loss). Net income (loss) decreased from $80.4 million in
income during the second quarter of 2008 to a $93.2 million loss during the
second quarter of 2009. The primary reasons for this decrease include
a 48% decrease in oil prices (net of hedging); a 69% decrease in natural gas
prices (net of hedging); higher losses on mark-to-market derivatives, lease
operating expenses, DD&A, exploration and impairment and interest
expense. These negative factors were partially offset by a 25%
increase in equivalent volumes sold; lower 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 second quarter of 2009.
Liquidity
and Capital Resources
Overview. At June
30, 2009, our debt to total capitalization ratio was 27.1%, we had $13.2 million
of cash on hand and $2,257.3 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 half of 2009, we generated $144.3 million of
cash provided by operating activities, a decrease of $184.8 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 half of
2009. We also generated $146.2 million from financing activities
consisting of $334.6 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 $400.0 million. Cash flows from operating and financing
activities, as well as $79.6 million in net proceeds from the sale of interests
in certain properties in the Sanish field, were used to finance $327.8 million
of drilling and development expenditures paid in the first half of 2009 and
$38.7 million of cash acquisition capital expenditures. The following
chart details our exploration and development expenditures incurred by region
during the first half of 2009 (in thousands):
|
|
Drilling
and Development Expenditures
|
|
|
|
|
|
|
|
|
|
|
Rocky
Mountains
|
|
$ |
152,032 |
|
|
$ |
9,652 |
|
|
$ |
161,684 |
|
|
|
57% |
|
Permian
Basin
|
|
|
87,551 |
|
|
|
5,604 |
|
|
|
93,155 |
|
|
|
33% |
|
Mid-Continent
|
|
|
23,782 |
|
|
|
522 |
|
|
|
24,304 |
|
|
|
9% |
|
Gulf
Coast
|
|
|
1,069 |
|
|
|
3,028 |
|
|
|
4,097 |
|
|
|
1% |
|
Michigan
|
|
|
908 |
|
|
|
5 |
|
|
|
913 |
|
|
|
0% |
|
Total
incurred
|
|
|
265,342 |
|
|
|
18,811 |
|
|
|
284,153 |
|
|
|
100% |
|
Decrease
in accrued capital expenditures
|
|
|
62,498 |
|
|
|
- |
|
|
|
62,498 |
|
|
|
|
|
Total
paid
|
|
$ |
327,840 |
|
|
$ |
18,811 |
|
|
$ |
346,651 |
|
|
|
|
|
We
continually evaluate our capital needs and compare them to our capital
resources. Our current 2009 capital budget for exploration and
development expenditures is $440.0 million, which we expect to fund with net
cash provided by our operating activities and a portion of the proceeds from the
common stock offering we completed in February 2009. Our 2009 capital
budget of $440.0 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 $440.0 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 June 30, 2009, Whiting Oil and Gas
Corporation, (“Whiting Oil and Gas”), our wholly-owned subsidiary, had a credit
agreement with a syndicate of banks that had a borrowing base of $1.1 billion
with $877.2 million of available borrowing capacity, which is net of $220.0
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 entire amount is 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 June 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 June 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 June 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 or amounts of future payments. The following table summarizes
our obligations and commitments as of June 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)
|
|
$ |
840,000 |
|
|
$ |
- |
|
|
$ |
370,000 |
|
|
$ |
470,000 |
|
|
$ |
- |
|
Cash
interest expense on debt (b)
|
|
|
186,608 |
|
|
|
49,429 |
|
|
|
96,179 |
|
|
|
41,000 |
|
|
|
- |
|
Asset
retirement obligation (c)
|
|
|
70,944 |
|
|
|
10,046 |
|
|
|
2,996 |
|
|
|
8,999 |
|
|
|
48,903 |
|
Tax
sharing liability (d)
|
|
|
24,505 |
|
|
|
2,112 |
|
|
|
3,787 |
|
|
|
3,261 |
|
|
|
15,345 |
|
Derivative
fair value liability (e)
|
|
|
132,256 |
|
|
|
34,362 |
|
|
|
59,585 |
|
|
|
38,309 |
|
|
|
- |
|
Purchasing
obligations (f)
|
|
|
158,366 |
|
|
|
34,539 |
|
|
|
72,878 |
|
|
|
46,570 |
|
|
|
4,379 |
|
Drilling
rig contracts (g)
|
|
|
102,958 |
|
|
|
45,524 |
|
|
|
50,174 |
|
|
|
7,260 |
|
|
|
- |
|
Operating
leases (h)
|
|
|
12,636 |
|
|
|
2,531 |
|
|
|
6,310 |
|
|
|
3,795 |
|
|
|
- |
|
Total
|
|
$ |
1,528,273 |
|
|
$ |
178,543 |
|
|
$ |
661,909 |
|
|
$ |
619,194 |
|
|
$ |
68,627 |
|
________________
(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 June 30, 2009 consists of a $16.9 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 June 30, 2009 also consists of a $115.4 million fair value
liability for derivative contracts we have entered into on our own behalf,
primarily in the form of costless collars, to hedge our exposure to crude
oil and natural gas price fluctuations. With respect to our
open derivative contracts at June 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 one
drilling rig expires in 2009, two in 2010, one in 2011,
one in 2012 and one in 2013. All of these rigs are
operating in the Rocky Mountains region. Included in the above
obligation is $3.0 million of rig termination fees that we accrued as a
current payable at June 30, 2009 for the cancellation of long-term
contracts on one drilling rig. As of June 30, 2009, early
termination of the remaining contracts would require additional
termination penalties of $63.7 million, which would be in lieu of paying
the remaining drilling commitments of $100.0 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
have not adjusted downward in proportion. Material changes in prices
also impact the current revenue stream, estimates of future reserves, borrowing
base calculations of bank loans, impairment assessments of oil and gas
properties, and values of properties in purchase and sale
transactions. Material changes in prices can impact the value of oil
and gas companies and their ability to raise capital, borrow money and retain
personnel. While we do not currently expect business costs to
materially increase, higher prices for oil and natural gas could result in
increases in the costs of materials, services and personnel.
Forward-Looking
Statements
This
report contains statements that we believe to be “forward-looking statements”
within the meaning of the Private Securities Litigation Reform Act of
1995. All statements other than historical facts, including, without
limitation, statements regarding our future financial position, business
strategy, projected revenues, earnings, costs, capital expenditures and debt
levels, and plans and objectives of management for future operations, are
forward-looking statements. When used in this report, words such as
we “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe” or “should”
or the negative thereof or variations thereon or similar terminology are
generally intended to identify forward-looking statements. Such
forward-looking statements are subject to risks and uncertainties that could
cause actual results to differ materially from those expressed in, or implied
by, such statements.
These
risks and uncertainties include, but are not limited to: declines in
oil or natural gas prices; impacts of the global recession and financial crisis;
our level of success in exploitation, exploration, development and production
activities; adverse weather conditions that may negatively impact development or
production activities; the timing of our exploration and development
expenditures, including our ability to obtain CO2;
inaccuracies of our reserve estimates or our assumptions underlying them;
revisions to reserve estimates as a result of changes in commodity prices; risks
related to our level of indebtedness and periodic redeterminations of Whiting
Oil and Gas Corporation’s borrowing base under our credit agreement; our ability
to generate sufficient cash flows from operations to meet the internally funded
portion of our capital expenditures budget; our ability to obtain external
capital to finance exploration and development operations and acquisitions; our
ability to identify and complete acquisitions and to successfully integrate
acquired businesses; unforeseen underperformance of or liabilities associated
with acquired properties; our ability to successfully complete potential asset
dispositions; 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 this Quarterly Report on Form 10-Q. 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 July 7, 2009 are summarized below:
Whiting
Petroleum Corporation
|
|
|
|
|
|
Weighted
Average
NYMEX
Floor/Ceiling
|
Crude
Oil
|
|
07/2009
to 09/2009
|
|
496,000
|
|
$
57.12/$ 69.55
|
Crude
Oil
|
|
10/2009
to 12/2009
|
|
478,000
|
|
$
61.04/$ 74.89
|
Crude
Oil
|
|
01/2010
to 03/2010
|
|
430,000
|
|
$
60.27/$ 74.81
|
Crude
Oil
|
|
04/2010
to 06/2010
|
|
415,000
|
|
$
62.69/$ 80.09
|
Crude
Oil
|
|
07/2010
to 09/2010
|
|
405,000
|
|
$
60.28/$ 76.98
|
Crude
Oil
|
|
10/2010
to 12/2010
|
|
390,000
|
|
$
60.29/$ 78.23
|
Crude
Oil
|
|
01/2011
to 03/2011
|
|
360,000
|
|
$
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/$ 81.78
|
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 1,713 MBbls of crude oil and
6,573 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
|
|
07/2009
to 09/2009
|
|
47,510
|
|
$
76.00/$ 136.41
|
Crude
Oil
|
|
10/2009
to 12/2009
|
|
46,240
|
|
$
76.00/$ 135.72
|
Crude
Oil
|
|
01/2010
to 03/2010
|
|
45,084
|
|
$
76.00/$ 135.09
|
Crude
Oil
|
|
04/2010
to 06/2010
|
|
43,978
|
|
$
76.00/$ 134.85
|
Crude
Oil
|
|
07/2010
to 09/2010
|
|
42,966
|
|
$
76.00/$ 134.89
|
Crude
Oil
|
|
10/2010
to 12/2010
|
|
41,924
|
|
$
76.00/$ 135.11
|
Crude
Oil
|
|
01/2011
to 03/2011
|
|
40,978
|
|
$
74.00/$ 139.68
|
Crude
Oil
|
|
04/2011
to 06/2011
|
|
40,066
|
|
$
74.00/$ 140.08
|
Crude
Oil
|
|
07/2011
to 09/2011
|
|
39,170
|
|
$
74.00/$ 140.15
|
Crude
Oil
|
|
10/2011
to 12/2011
|
|
38,242
|
|
$
74.00/$ 140.75
|
Crude
Oil
|
|
01/2012
to 03/2012
|
|
37,412
|
|
$
74.00/$ 141.27
|
Crude
Oil
|
|
04/2012
to 06/2012
|
|
36,572
|
|
$
74.00/$ 141.73
|
Crude
Oil
|
|
07/2012
to 09/2012
|
|
35,742
|
|
$
74.00/$ 141.70
|
Crude
Oil
|
|
10/2012
to 12/2012
|
|
35,028
|
|
$
74.00/$ 142.21
|
Natural
Gas
|
|
07/2009
to 09/2009
|
|
192,870
|
|
$ 6.00/$
15.60
|
Natural
Gas
|
|
10/2009
to 12/2009
|
|
185,430
|
|
$
7.00/$ 14.85
|
Natural
Gas
|
|
01/2010
to 03/2010
|
|
178,903
|
|
$
7.00/$ 18.65
|
Natural
Gas
|
|
04/2010
to 06/2010
|
|
172,873
|
|
$
6.00/$ 13.20
|
Natural
Gas
|
|
07/2010
to 09/2010
|
|
167,583
|
|
$
6.00/$ 14.00
|
Natural
Gas
|
|
10/2010
to 12/2010
|
|
162,997
|
|
$
7.00/$ 14.20
|
Natural
Gas
|
|
01/2011
to 03/2011
|
|
157,600
|
|
$
7.00/$ 17.40
|
Natural
Gas
|
|
04/2011
to 06/2011
|
|
152,703
|
|
$
6.00/$ 13.05
|
Natural
Gas
|
|
07/2011
to 09/2011
|
|
148,163
|
|
$
6.00/$ 13.65
|
Natural
Gas
|
|
10/2011
to 12/2011
|
|
142,787
|
|
$
7.00/$ 14.25
|
Natural
Gas
|
|
01/2012
to 03/2012
|
|
137,940
|
|
$
7.00/$ 15.55
|
Natural
Gas
|
|
04/2012
to 06/2012
|
|
134,203
|
|
$
6.00/$ 13.60
|
Natural
Gas
|
|
07/2012
to 09/2012
|
|
130,173
|
|
$
6.00/$ 14.45
|
Natural
Gas
|
|
10/2012
to 12/2012
|
|
126,613
|
|
$
7.00/$ 13.40
|
The
collared hedges shown above have the effect of providing a protective floor
while allowing us to share in upward pricing movements. Consequently,
while these hedges are designed to decrease our exposure to price decreases,
they also have the effect of limiting the benefit of price increases above the
ceiling. For the crude oil contracts listed in both tables above, a
hypothetical $5.00 change in the NYMEX forward curve as of June 30, 2009 applied
to the notional amounts would cause a change in our gain (loss) on
mark-to-market derivatives of $66.2 million. For the natural gas
contracts listed above, a hypothetical $0.50 change in the NYMEX forward curve
as of June 30, 2009 applied to the notional amounts would cause a change in our
gain (loss) on mark-to-market derivatives of $0.4 million.
In a 1997
acquisition of non-operated properties, we became subject to the operator’s
fixed price gas sales contract with end users for a portion of the natural gas
we produce in Michigan. This contract has built-in pricing escalators
of 4% per year. Our estimated future production volumes to be sold
under the fixed pricing terms of this contract as of July 1, 2009 are summarized
below:
|
|
|
|
|
|
|
Natural
Gas
|
|
07/2009
to 05/2011
|
|
23,000
|
|
$
5.14
|
Natural
Gas
|
|
07/2009
to 09/2012
|
|
67,000
|
|
$
4.56
|
Evaluation of disclosure controls
and procedures. In accordance with Rule 13a-15(b) of the
Securities Exchange Act of 1934 (the “Exchange Act”), our management evaluated,
with the participation of our Chairman, President and Chief Executive Officer
and our Chief Financial Officer, the effectiveness of the design and operation
of our disclosure controls and procedures (as defined in Rule 13a-15(e) under
the Exchange Act) as of June 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 June 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 June 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.
Each of
the risks described below should be carefully considered, together with all of
the other information contained in this Quarterly Report on Form 10-Q and our
Annual Report on Form 10-K for the year ended December 31, 2008, before making
an investment decision with respect to our securities. If any of the
following risks develop into actual events, our business, financial condition or
results of operations could be materially and adversely affected, and you may
lose all or part of your investment.
Oil
and natural gas prices are very volatile. An extended period of low
oil and natural gas prices may adversely affect our business, financial
condition, results of operations or cash flows.
The oil
and gas markets are very volatile, and we cannot predict future oil and natural
gas prices. The price we receive for our oil and natural gas
production heavily influences our revenue, profitability, access to capital and
future rate of growth. The prices we receive for our production and
the levels of our production depend on numerous factors beyond our
control. These factors include, but are not limited to, the
following:
·
|
changes
in global supply and demand for oil and
gas;
|
·
|
the
actions of the Organization of Petroleum Exporting
Countries;
|
·
|
the
price and quantity of imports of foreign oil and
gas;
|
·
|
political
and economic conditions, including embargoes, in oil-producing countries
or affecting other oil-producing
activity;
|
·
|
the
level of global oil and gas exploration and production
activity;
|
·
|
the
level of global oil and gas
inventories;
|
·
|
technological
advances affecting energy
consumption;
|
·
|
domestic
and foreign governmental
regulations;
|
·
|
proximity
and capacity of oil and gas pipelines and other transportation
facilities;
|
·
|
the
price and availability of competitors’ supplies of oil and gas in captive
market areas; and
|
·
|
the
price and availability of alternative
fuels.
|
Furthermore,
the recent worldwide financial and credit crisis has reduced the availability of
liquidity and credit to fund the continuation and expansion of industrial
business operations worldwide. The shortage of liquidity and credit
combined with recent substantial losses in worldwide equity markets has led to a
worldwide economic recession. The slowdown in economic activity
caused by such recession has reduced worldwide demand for energy and resulted in
lower oil and natural gas prices. 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 $51.46 per
Bbl for the first six 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 $4.21 for the first six
months of 2009.
Lower oil
and natural gas prices may not only decrease our revenues on a per unit basis
but also may 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, results of
operations, liquidity or ability to finance planned capital
expenditures. To the extent commodity prices received from production
are insufficient to fund planned capital expenditures, we will be required to
reduce spending or borrow any such shortfall. Lower oil and natural
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,
and is subject to regular redeterminations on May 1 and November 1 of each year,
as well as special redeterminations described in the credit
agreement.
The
global financial crisis and recession may have impacts on our business and
financial condition that we currently cannot predict.
The
continued turmoil in the global financial system and the current global
recession may have an impact on our business and our financial condition, and we
may face challenges if conditions in the financial markets do not
improve. Our ability to access the capital markets may be restricted
at a time when we would like, or need, to raise financing, which could have an
impact on our flexibility to react to changing economic and business
conditions. The economic situation could have an impact on our
lenders or customers, causing them to fail to meet their obligations to
us. Additionally, market conditions could have an impact on our
commodity hedging arrangements if our counterparties are unable to perform their
obligations or seek bankruptcy protection.
Drilling
for and producing oil and natural gas are high risk activities with many
uncertainties that could adversely affect our business, financial condition or
results of operations.
Our
future success will depend on the success of our development, exploitation,
production and exploration activities. Our oil and natural gas
exploration and production activities are subject to numerous risks beyond our
control, including the risk that drilling will not result in commercially viable
oil or natural gas production. Our decisions to purchase, explore,
develop or otherwise exploit prospects or properties will depend in part on the
evaluation of data obtained through geophysical and geological analyses,
production data and engineering studies, the results of which are often
inconclusive or subject to varying interpretations. Please read “—
Reserve estimates depend on many assumptions that may turn out to be inaccurate
.. . .” later in these Risk Factors for a discussion of the uncertainty involved
in these processes. Our cost of drilling, completing and operating
wells is often uncertain before drilling commences. Overruns in
budgeted expenditures are common risks that can make a particular project
uneconomical. Further, many factors may curtail, delay or cancel
drilling, including the following:
·
|
delays
imposed by or resulting from compliance with regulatory
requirements;
|
·
|
pressure
or irregularities in geological
formations;
|
·
|
shortages
of or delays in obtaining qualified personnel or equipment, including
drilling rigs and CO2;
|
·
|
equipment
failures or accidents;
|
·
|
adverse
weather conditions, such as freezing temperatures, hurricanes and
storms;
|
·
|
reductions
in oil and natural gas prices; and
|
Prospects
that we decide to drill may not yield oil or gas in commercially viable
quantities.
We
describe some of our current prospects and our plans to explore those prospects
in this Quarterly Report on Form 10-Q for the quarter ended June 30, 2009 and
our Annual Report on Form 10-K for the year ended December 31,
2008. A prospect is a property on which we have identified what our
geoscientists believe, based on available seismic and geological information, to
be indications of oil or gas. Our prospects are in various stages of
evaluation, ranging from a prospect which is ready to drill to a prospect that
will require substantial additional seismic data processing and
interpretation. There is no way to predict in advance of drilling and
testing whether any particular prospect will yield oil or gas in sufficient
quantities to recover drilling or completion costs or to be economically
viable. The use of seismic data and other technologies and the study
of producing fields in the same area will not enable us to know conclusively
prior to drilling whether oil or gas will be present or, if present, whether oil
or gas will be present in commercial quantities. In addition, because
of the wide variance that results from different equipment used to test the
wells, initial flowrates may not be indicative of sufficient oil or gas
quantities in a particular field. The analogies we draw from
available data from other wells, from more fully explored prospects, or from
producing fields may not be applicable to our drilling prospects. We
may terminate our drilling program for a prospect if results do not merit
further investment.
Our
identified drilling locations are scheduled out over several years, making them
susceptible to uncertainties that could materially alter the occurrence or
timing of their drilling.
We have
specifically identified and scheduled drilling locations as an estimation of our
future multi-year drilling activities on our existing acreage. As of
December 31, 2008, we had identified a drilling inventory of over 1,400 gross
drilling locations. These scheduled drilling locations represent a
significant part of our growth strategy. Our ability to drill and
develop these locations depends on a number of uncertainties, including oil and
natural gas prices, the availability of capital, costs of oil field goods and
services, drilling results, ability to extend drilling acreage leases beyond
expiration, regulatory approvals and other factors. Because of these
uncertainties, we do not know if the numerous potential drilling locations we
have identified will ever be drilled or if we will be able to produce oil or gas
from these or any other potential drilling locations. As such, our
actual drilling activities may materially differ from those presently
identified, which could adversely affect our business.
We
have been an early entrant into new or emerging plays. As a result, our drilling
results in these areas are uncertain, and the value of our undeveloped acreage
will decline and we may incur impairment charges if drilling results are
unsuccessful.
While our
costs to acquire undeveloped acreage in new or emerging plays have generally
been less than those of later entrants into a developing play, our drilling
results in these areas are more uncertain than drilling results in areas that
are developed and producing. Since new or emerging plays have limited
or no production history, we are unable to use past drilling results in those
areas to help predict our future drilling results. Therefore, our
cost of drilling, completing and operating wells in these areas may be higher
than initially expected, and the value of our undeveloped acreage will decline
if drilling results are unsuccessful. Furthermore, if drilling
results are unsuccessful, we may be required to write down the carrying value of
our undeveloped acreage in new or emerging plays. For example, during
the fourth quarter of 2008, we recorded a $10.9 million non-cash charge for the
partial impairment of unproved properties in the central Utah Hingeline
play. We may also incur such impairment charges in the future, which
could have a material adverse effect on our results of operations in the period
taken. Additionally, our rights to develop a portion of our
undeveloped acreage may expire if not successfully developed or
renewed. Out of a total of 892,130 gross (420,776 net) undeveloped
acreage as of December 31, 2008, the portion that is subject to expiration over
the next three years, if not successfully developed or renewed, is approximately
17% in 2009, 16% in 2010, and 16% in 2011.
Our
use of enhanced recovery methods creates uncertainties that could adversely
affect our results of operations and financial condition.
One of
our business strategies is to commercially develop oil reservoirs using enhanced
recovery technologies. For example, we inject water and CO2 into
formations on some of our properties to increase the production of oil and
natural gas. The additional production and reserves attributable to
the use of these enhanced recovery methods are inherently difficult to
predict. If our enhanced recovery programs do not allow for the
extraction of oil and gas in the manner or to the extent that we anticipate, our
future results of operations and financial condition could be materially
adversely affected. Additionally, our ability to utilize CO2 as an
enhanced recovery technique is subject to our ability to obtain sufficient
quantities of CO2. Under
our CO2 contracts,
if the supplier suffers an inability to deliver its contractually required
quantities of CO2 to us and
other parties with whom it has CO2 contracts,
then the supplier may reduce the amount of CO2 on a pro
rata basis it provides to us and such other parties. If this occurs,
we may not have sufficient CO2 to produce
oil and natural gas in the manner or to the extent that we
anticipate. These contracts are also structured as “take-or-pay”
arrangements, which require us to continue to make payments even if we decide to
terminate or reduce our use of CO2 as part of
our enhanced recovery techniques.
The
development of the proved undeveloped reserves in the North Ward Estes and
Postle fields may take longer and may require higher levels of capital
expenditures than we currently anticipate.
As of
December 31, 2008, undeveloped reserves comprised 46.5% of the North Ward Estes
field’s total estimated proved reserves and 16.8% of the Postle field’s total
estimated proved reserves. To fully develop these reserves, we expect
to incur future development costs of $410.1 million at the North Ward Estes
field and $84.5 million at the Postle field as of December 31,
2008. Together, these fields encompass 58% of our total estimated
future development costs of $857.1 million related to proved undeveloped
reserves. Development of these reserves may take longer and require
higher levels of capital expenditures than we currently
anticipate. In addition, the development of these reserves will
require the use of enhanced recovery techniques, including water flood and
CO2
injection installations, the success of which is less predictable than
traditional development techniques. Therefore, ultimate recoveries
from these fields may not match current expectations.
If
oil and natural gas prices decrease, we may be required to take write-downs of
the carrying values of our oil and gas properties.
Accounting
rules require that we review periodically the carrying value of our oil and gas
properties for possible impairment. Based on specific market factors
and circumstances at the time of prospective impairment reviews, which may
include depressed oil and natural gas prices, and the continuing evaluation of
development plans, production data, economics and other factors, we may be
required to write down the carrying value of our oil and gas
properties. A write-down constitutes a non-cash charge to
earnings. We may incur impairment charges in the future, which could
have a material adverse effect on our results of operations in the period
taken.
Reserve
estimates depend on many assumptions that may turn out to be
inaccurate. Any material inaccuracies in these reserve estimates or
underlying assumptions will materially affect the quantities and present value
of our reserves.
The
process of estimating oil and natural gas reserves is complex. It
requires interpretations of available technical data and many assumptions,
including assumptions relating to economic factors. Any significant
inaccuracies in these interpretations or assumptions could materially affect the
estimated quantities and present value of reserves referred to our Annual Report
on Form 10-K for the year ended December 31, 2008.
In order
to prepare our estimates, we must project production rates and timing of
development expenditures. We must also analyze available geological,
geophysical, production and engineering data. The extent, quality and
reliability of this data can vary. The process also requires economic
assumptions about matters such as oil and natural gas prices, drilling and
operating expenses, capital expenditures, taxes and availability of
funds. Therefore, estimates of oil and natural gas reserves are
inherently imprecise.
Actual
future production, oil and natural gas prices, revenues, taxes, exploration and
development expenditures, operating expenses and quantities of recoverable oil
and natural gas reserves most likely will vary from our
estimates. Any significant variance could materially affect the
estimated quantities and present value of reserves referred to in our Annual
Report on Form 10-K for the year ended December 31, 2008. In
addition, we may adjust estimates of proved reserves to reflect production
history, results of exploration and development, prevailing oil and natural gas
prices and other factors, many of which are beyond our control.
You
should not assume that the present value of future net revenues from our proved
reserves, as referred to in our the Annual Report on Form 10-K for the year
ended December 31, 2008, is the current market value of our estimated oil and
natural gas reserves. In accordance with SEC requirements, we
generally base the estimated discounted future net cash flows from our proved
reserves on prices and costs on the date of the estimate. Actual
future prices and costs may differ materially from those used in the present
value estimate. If natural gas prices decline by $0.10 per Mcf, then
the standardized measure of discounted future net cash flows of our estimated
proved reserves as of December 31, 2008 would have decreased from $1,376.4
million to $1,366.0 million. If oil prices decline by $1.00 per Bbl,
then the standardized measure of discounted future net cash flows of our
estimated proved reserves as of December 31, 2008 would have decreased from
$1,376.4 million to $1,326.1 million.
Our
debt level and the covenants in the agreements governing our debt could
negatively impact our financial condition, results of operations, cash flows and
business prospects.
As of
June 30, 2009, we had $220.0 million in borrowings and $2.8 million in letters
of credit outstanding under Whiting Oil and Gas Corporation’s credit agreement
with $877.2 million of available borrowing capacity, as well as $620.0 million
of senior subordinated notes outstanding. We are permitted to incur
additional indebtedness, provided we meet certain requirements in the indentures
governing our senior subordinated notes and Whiting Oil and Gas Corporation’s
credit agreement.
Our level
of indebtedness and the covenants contained in the agreements governing our debt
could have important consequences for our operations, including:
·
|
requiring
us to dedicate a substantial portion of our cash flow from operations to
required payments on debt, thereby reducing the availability of cash flow
for working capital, capital expenditures and other general business
activities;
|
·
|
potentially
limiting our ability to pay dividends in cash on our convertible perpetual
preferred stock;
|
·
|
limiting
our ability to obtain additional financing in the future for working
capital, capital expenditures, acquisitions and general corporate and
other activities;
|
·
|
limiting
our flexibility in planning for, or reacting to, changes in our business
and the industry in which we
operate;
|
·
|
placing
us at a competitive disadvantage relative to other less leveraged
competitors; and
|
·
|
making
us vulnerable to increases in interest rates, because debt under Whiting
Oil and Gas Corporation’s credit agreement may be at variable
rates.
|
We may be
required to repay all or a portion of our debt on an accelerated basis in
certain circumstances. If we fail to comply with the covenants and
other restrictions in the agreements governing our debt, it could lead to an
event of default and the acceleration of our repayment of outstanding
debt. In addition, if we are in default under the agreements
governing our indebtedness, we will not be able to pay dividends on our capital
stock. Our ability to comply with these covenants and other
restrictions may be affected by events beyond our control, including prevailing
economic and financial conditions. Moreover, the borrowing base
limitation on Whiting Oil and Gas Corporation’s credit agreement is periodically
redetermined based on an evaluation of our reserves. Upon a
redetermination, if borrowings in excess of the revised borrowing capacity were
outstanding, we could be forced to repay a portion of our debt under the credit
agreement.
We may
not have sufficient funds to make such repayments. If we are unable
to repay our debt out of cash on hand, we could attempt to refinance such debt,
sell assets or repay such debt with the proceeds from an equity
offering. We may not be able to generate sufficient cash flow to pay
the interest on our debt or future borrowings, and equity financings or proceeds
from the sale of assets may not be available to pay or refinance such
debt. The terms of our debt, including Whiting Oil and Gas
Corporation’s credit agreement, may also prohibit us from taking such
actions. Factors that will affect our ability to raise cash through
an offering of our capital stock, a refinancing of our debt or a sale of assets
include financial market conditions and our market value and operating
performance at the time of such offering or other financing. We may
not be able to successfully complete any such offering, refinancing or sale of
assets.
The
instruments governing our indebtedness contain various covenants limiting the
discretion of our management in operating our business.
The
indentures governing our senior subordinated notes and Whiting Oil and Gas
Corporation’s credit agreement contain various restrictive covenants that may
limit our management’s discretion in certain respects. In particular,
these agreements will limit our and our subsidiaries’ ability to, among other
things:
·
|
pay
dividends on, redeem or repurchase our capital stock or redeem or
repurchase our subordinated debt;
|
·
|
incur
additional indebtedness or issue preferred
stock;
|
·
|
enter
into agreements that restrict dividends or other payments from our
restricted subsidiaries to us;
|
·
|
consolidate,
merge or transfer all or substantially all of the assets of us and our
restricted subsidiaries taken as a
whole;
|
·
|
engage
in transactions with affiliates;
|
·
|
enter
into hedging contracts;
|
·
|
create
unrestricted subsidiaries; and
|
·
|
enter
into sale and leaseback
transactions.
|
In
addition, Whiting Oil and Gas Corporation’s credit agreement requires us, as of
the last day of any quarter, (i) to not exceed a total debt to EBITDAX ratio (as
defined in the credit agreement) for the last four quarters of 4.5 to 1.0 for
quarters ending prior to and on September 30, 2010, 4.25 to 1.0 for quarters
ending December 31, 2010 to June 30, 2011 and 4.0 to 1.0 for quarters ending
September 30, 2011 and thereafter, (ii) to have a consolidated current assets to
consolidated current liabilities ratio (as defined in the credit agreement) of
not less than 1.0 to 1.0 and (iii) to not exceed a senior secured debt to
EBITDAX ratio (as defined in the credit agreement) for the last four quarters of
2.75 to 1.0 for quarters ending prior to and on December 31, 2009 and 2.5 to 1.0
for quarters ending March 31, 2010 and thereafter. Also, the indentures under
which we issued our senior subordinated 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. A substantial or extended decline in
oil or natural gas prices may adversely affect our ability to comply with these
covenants.
If we
fail to comply with the restrictions in the indentures governing our senior
subordinated notes or Whiting Oil and Gas Corporation’s credit agreement or any
other subsequent financing agreements, a default may allow the creditors, if the
agreements so provide, to accelerate the related indebtedness as well as any
other indebtedness to which a cross-acceleration or cross-default provision
applies. In addition, lenders may be able to terminate any
commitments they had made to make available further
funds. Furthermore, if we are in default under the agreements
governing our indebtedness, we will not be able to pay dividends on our capital
stock.
Our exploration
and development operations require substantial capital, and we may be unable to
obtain needed capital or financing on satisfactory terms, which could lead to a
loss of properties and a decline in our oil and natural gas
reserves.
The oil
and gas industry is capital intensive. We make and expect to continue
to make substantial capital expenditures in our business and operations for the
exploration, development, production and acquisition of oil and natural gas
reserves. To date, we have financed capital expenditures through a
combination of equity and debt issuances, bank borrowings and internally
generated cash flows. We intend to finance future capital
expenditures with cash flow from operations and existing financing
arrangements. Our cash flow from operations and access to capital is
subject to a number of variables, including:
·
|
the
level of oil and natural gas we are able to produce from existing
wells;
|
·
|
the
prices at which oil and natural gas are sold;
and
|
·
|
our
ability to acquire, locate and produce new
reserves.
|
If our
revenues or the borrowing base under our bank credit agreement decreases as a
result of lower oil and natural gas prices, operating difficulties, declines in
reserves or for any other reason, then we may have limited ability to obtain the
capital necessary to sustain our operations at current levels. We
may, from time to time, need to seek additional financing. There can
be no assurance as to the availability or terms of any additional
financing.
If
additional capital is needed, we may not be able to obtain debt or equity
financing on terms favorable to us, or at all. If cash generated by
operations or available under our revolving credit facility is not sufficient to
meet our capital requirements, the failure to obtain additional financing could
result in a curtailment of our operations relating to the exploration and
development of our prospects, which in turn could lead to a possible loss of
properties and a decline in our oil and natural gas reserves.
Our
acquisition activities may not be successful.
As part
of our growth strategy, we have made and may continue to make acquisitions of
businesses and properties. However, suitable acquisition candidates
may not continue to be available on terms and conditions we find acceptable, and
acquisitions pose substantial risks to our business, financial condition and
results of operations. In pursuing acquisitions, we compete with
other companies, many of which have greater financial and other resources to
acquire attractive companies and properties. The following are some
of the risks associated with acquisitions, including any completed or future
acquisitions:
·
|
some
of the acquired businesses or properties may not produce revenues,
reserves, earnings or cash flow at anticipated
levels;
|
·
|
we
may assume liabilities that were not disclosed to us or that exceed our
estimates;
|
·
|
we
may be unable to integrate acquired businesses successfully and realize
anticipated economic, operational and other benefits in a timely manner,
which could result in substantial costs and delays or other operational,
technical or financial problems;
|
·
|
acquisitions
could disrupt our ongoing business, distract management, divert resources
and make it difficult to maintain our current business standards, controls
and procedures; and
|
·
|
we
may issue additional equity or debt securities related to future
acquisitions.
|
Substantial
acquisitions or other transactions could require significant external capital
and could change our risk and property profile.
In order
to finance acquisitions of additional producing or undeveloped properties, we
may need to alter or increase our capitalization substantially through the
issuance of debt or equity securities, the sale of production payments or other
means. These changes in capitalization may significantly affect our
risk profile. Additionally, significant acquisitions or other
transactions can change the character of our operations and
business. The character of the new properties may be substantially
different in operating or geological characteristics or geographic location than
our existing properties. Furthermore, we may not be able to obtain
external funding for future acquisitions or other transactions or to obtain
external funding on terms acceptable to us.
Properties
that we acquire may not produce as projected, and we may be unable to identify
liabilities associated with the properties or obtain protection from sellers
against them.
Our
business strategy includes a continuing acquisition program. From
2004 through 2008, we completed 13 separate acquisitions of producing properties
with a combined purchase price of $1,823.8 million for estimated proved reserves
as of the effective dates of the acquisitions of 226.9 MMBOE. The
successful acquisition of producing properties requires assessments of many
factors, which are inherently inexact and may be inaccurate, including the
following:
·
|
the
amount of recoverable reserves;
|
·
|
future
oil and natural gas prices;
|
·
|
estimates
of operating costs;
|
·
|
estimates
of future development costs;
|
·
|
timing
of future development costs;
|
·
|
estimates
of the costs and timing of plugging and abandonment;
and
|
·
|
potential
environmental and other
liabilities.
|
Our
assessment will not reveal all existing or potential problems, nor will it
permit us to become familiar enough with the properties to assess fully their
capabilities and deficiencies. In the course of our due diligence, we
may not inspect every well, platform or pipeline. Inspections may not
reveal structural and environmental problems, such as pipeline corrosion or
groundwater contamination, when they are made. We may not be able to
obtain contractual indemnities from the seller for liabilities that it
created. We may be required to assume the risk of the physical
condition of the properties in addition to the risk that the properties may not
perform in accordance with our expectations.
Our
use of oil and natural gas price hedging contracts involves credit risk and may
limit future revenues from price increases and result in significant
fluctuations in our net income.
We enter
into hedging transactions of our oil and natural gas production to reduce our
exposure to fluctuations in the price of oil and natural gas. Our
hedging transactions to date have consisted of financially settled crude oil and
natural gas forward sales contracts, primarily costless collars, placed with
major financial institutions. As of July 7, 2009, we had contracts,
which include our 24.2% share of the Whiting USA Trust I hedges, covering the
sale for the remainder of 2009 of between 489,190 and 507,497 barrels of oil per
month and between 134,874 and 136,675 MMBtu of natural gas per
month. All our oil hedges will expire by November 2013, and all our
natural gas hedges will expire by December 2012. See “Quantitative
and Qualitative Disclosure about Market Risk” in Item 3 of this Form 10-Q for
pricing and a more detailed discussion of our hedging transactions.
We may in
the future enter into these and other types of hedging arrangements to reduce
our exposure to fluctuations in the market prices of oil and natural gas, or
alternatively, we may decide to unwind or restructure the hedging arrangements
we previously entered into. Hedging transactions expose us to risk of
financial loss in some circumstances, including if production is less than
expected, the other party to the contract defaults on its obligations or there
is a change in the expected differential between the underlying price in the
hedging agreement and actual prices received. Hedging transactions
may limit the benefit we may otherwise receive from increases in the price for
oil and natural gas. Furthermore, if we do not engage in hedging
transactions or unwind hedging transaction we previously entered into, then we
may be more adversely affected by declines in oil and natural gas prices than
our competitors who engage in hedging transactions. Additionally,
hedging transactions may expose us to cash margin requirements.
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 such, subsequent to March 31, 2009 we recognize 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. Subsequently, we may experience
significant net income and operating result losses, on a non-cash basis, due to
changes in the value of our hedges as a result of commodity price
volatility.
Seasonal
weather conditions and lease stipulations adversely affect our ability to
conduct drilling activities in some of the areas where we operate.
Oil and
gas operations in the Rocky Mountains are adversely affected by seasonal weather
conditions and lease stipulations designed to protect various
wildlife. In certain areas, drilling and other oil and gas activities
can only be conducted during the spring and summer months. This
limits our ability to operate in those areas and can intensify competition
during those months for drilling rigs, oil field equipment, services, supplies
and qualified personnel, which may lead to periodic
shortages. Resulting shortages or high costs could delay our
operations and materially increase our operating and capital costs.
The
differential between the NYMEX or other benchmark price of oil and natural gas
and the wellhead price we receive could have a material adverse effect on our
results of operations, financial condition and cash flows.
The
prices that we receive for our oil and natural gas production generally trade at
a discount to the relevant benchmark prices such as NYMEX. The
difference between the benchmark price and the price we receive is called a
differential. We cannot accurately predict oil and natural gas
differentials. Increases in the differential between the benchmark
price for oil and natural gas and the wellhead price we receive could have a
material adverse effect on our results of operations, financial condition and
cash flows.
We
may incur substantial losses and be subject to substantial liability claims as a
result of our oil and gas operations.
We are
not insured against all risks. Losses and liabilities arising from
uninsured and underinsured events could materially and adversely affect our
business, financial condition or results of operations. Our oil and
natural gas exploration and production activities are subject to all of the
operating risks associated with drilling for and producing oil and natural gas,
including the possibility of:
·
|
environmental
hazards, such as uncontrollable flows of oil, gas, brine, well fluids,
toxic gas or other pollution into the environment, including groundwater
and shoreline contamination;
|
·
|
abnormally
pressured formations;
|
·
|
mechanical
difficulties, such as stuck oil field drilling and service tools and
casing collapse;
|
·
|
personal
injuries and death; and
|
Any of
these risks could adversely affect our ability to conduct operations or result
in substantial losses to our company. We may elect not to obtain
insurance if we believe that the cost of available insurance is excessive
relative to the risks presented. In addition, pollution and
environmental risks generally are not fully insurable. If a
significant accident or other event occurs and is not fully covered by
insurance, then it could adversely affect us.
We
have limited control over activities on properties we do not operate, which
could reduce our production and revenues.
If we do
not operate the properties in which we own an interest, we do not have control
over normal operating procedures, expenditures or future development of
underlying properties. The failure of an operator of our wells to
adequately perform operations or an operator’s breach of the applicable
agreements could reduce our production and revenues. The success and
timing of our drilling and development activities on properties operated by
others therefore depends upon a number of factors outside of our control,
including the operator’s timing and amount of capital expenditures, expertise
and financial resources, inclusion of other participants in drilling wells, and
use of technology. Because we do not have a majority interest in most
wells we do not operate, we may not be in a position to remove the operator in
the event of poor performance.
Our
use of 3-D seismic data is subject to interpretation and may not accurately
identify the presence of oil and gas, which could adversely affect the results
of our drilling operations.
Even when
properly used and interpreted, 3-D seismic data and visualization techniques are
only tools used to assist geoscientists in identifying subsurface structures and
hydrocarbon indicators and do not enable the interpreter to know whether
hydrocarbons are, in fact, present in those structures. In addition,
the use of 3-D seismic and other advanced technologies requires greater
predrilling expenditures than traditional drilling strategies, and we could
incur losses as a result of such expenditures. Thus, some of our
drilling activities may not be successful or economical, and our overall
drilling success rate or our drilling success rate for activities in a
particular area could decline. We often gather 3-D seismic data over
large areas. Our interpretation of seismic data delineates for us
those portions of an area that we believe are desirable for
drilling. Therefore, we may choose not to acquire option or lease
rights prior to acquiring seismic data, and in many cases, we may identify
hydrocarbon indicators before seeking option or lease rights in the
location. If we are not able to lease those locations on acceptable
terms, it would result in our having made substantial expenditures to acquire
and analyze 3-D seismic data without having an opportunity to attempt to benefit
from those expenditures.
Market
conditions or operational impediments may hinder our access to oil and gas
markets or delay our production.
In
connection with our continued development of oil and gas properties, we may be
disproportionately exposed to the impact of delays or interruptions of
production from wells in these properties, caused by transportation capacity
constraints, curtailment of production or the interruption of transporting oil
and gas volumes produced. In addition, market conditions or a lack of
satisfactory oil and gas transportation arrangements may hinder our access to
oil and gas markets or delay our production. The availability of a
ready market for our oil and natural gas production depends on a number of
factors, including the demand for and supply of oil and natural gas and the
proximity of reserves to pipelines and terminal facilities. Our
ability to market our production depends substantially on the availability and
capacity of gathering systems, pipelines and processing facilities owned and
operated by third-parties. Additionally, entering into arrangements
for these services exposes us to the risk that third parties will default on
their obligations under such arrangements. Our failure to obtain such
services on acceptable terms or the default by a third party on their obligation
to provide such services could materially harm our business. We may
be required to shut in wells for a lack of a market or because access to gas
pipelines, gathering systems or processing facilities may be limited or
unavailable. If that were to occur, then we would be unable to
realize revenue from those wells until production arrangements were made to
deliver the production to market.
We
are subject to complex laws that can affect the cost, manner or feasibility of
doing business.
Exploration,
development, production and sale of oil and natural gas are subject to extensive
federal, state, local and international regulation. We may be
required to make large expenditures to comply with governmental
regulations. Matters subject to regulation include:
·
|
discharge
permits for drilling operations;
|
·
|
reports
concerning operations;
|
·
|
unitization
and pooling of properties; and
|
Under
these laws, we could be liable for personal injuries, property damage and other
damages. Failure to comply with these laws also may result in the
suspension or termination of our operations and subject us to administrative,
civil and criminal penalties. Moreover, these laws could change in
ways that could substantially increase our costs. Any such
liabilities, penalties, suspensions, terminations or regulatory changes could
materially adversely affect our financial condition and results of
operations.
Our
operations may incur substantial liabilities to comply with environmental laws
and regulations.
Our oil
and gas operations are subject to stringent federal, state and local laws and
regulations relating to the release or disposal of materials into the
environment or otherwise relating to environmental protection. These laws and
regulations may require the acquisition of a permit before drilling commences;
restrict the types, quantities, and concentration of materials that can be
released into the environment in connection with drilling and production
activities; limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands, and other protected areas; and impose substantial
liabilities for pollution resulting from our operations. Failure to
comply with these laws and regulations may result in the assessment of
administrative, civil, and criminal penalties, incurrence of investigatory or
remedial obligations, or the imposition of injunctive relief. Under
these environmental laws and regulations, we could be held strictly liable for
the removal or remediation of previously released materials or property
contamination regardless of whether we were responsible for the release or if
our operations were standard in the industry at the time they were
performed. Federal law and some state laws also allow the government
to place a lien on real property for costs incurred by the government to address
contamination on the property.
Changes
in environmental laws and regulations occur frequently, and any changes that
result in more stringent or costly material handling, storage, transport,
disposal or cleanup requirements could require us to make significant
expenditures to maintain compliance and may otherwise have a material adverse
effect on our results of operations, competitive position, or financial
condition as well as those of the oil and gas industry in
general. For instance, recent scientific studies have suggested that
emissions of certain gases, commonly referred to as “greenhouse gases”,
including carbon dioxide and methane, may be contributing to warming of the
Earth’s atmosphere. In response to such studies, President Obama has
expressed support for, and it is anticipated that the current session of
Congress will consider legislation to regulate emissions of greenhouse
gases. In addition, more than one-third of the states, either
individually or through multi-state regional initiatives, have already taken
legal measures to reduce emission of these gases, primarily through the planned
development of greenhouse gas emission inventories and/or regional greenhouse
gas cap and trade programs. Also, as a result of the U.S. Supreme
Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may
be required to regulate greenhouse gas emissions from mobile sources (e.g., cars
and trucks) even if Congress does not adopt new legislation specifically
addressing emissions of greenhouse gases. The Court’s holding in
Massachusetts that greenhouse gases fall under the federal Clean Air Act’s
definition of “air pollutant” may also result in future regulation of greenhouse
gas emissions from stationary sources under certain Clean Air Act
programs. As a result of the Massachusetts decision, in April 2009,
the EPA published a Proposed Endangerment and Cause or Contribute Findings for
Greenhouse Gases Under the Clean Air Act. New legislation or
regulatory programs that restrict emissions of greenhouse gases in
areas where we operate could adversely affect our operations by increasing
costs. The cost increases would result from the potential new
requirements to install additional emission control equipment and by increasing
our monitoring and record-keeping burden.
Unless
we replace our oil and natural gas reserves, our reserves and production will
decline, which would adversely affect our cash flows and results of
operations.
Unless we
conduct successful development, exploitation and exploration activities or
acquire properties containing proved reserves, our proved reserves will decline
as those reserves are produced. Producing oil and natural gas reservoirs
generally are characterized by declining production rates that vary depending
upon reservoir characteristics and other factors. Our future oil and
natural gas reserves and production, and therefore our cash flow and income, are
highly dependent on our success in efficiently developing and exploiting our
current reserves and economically finding or acquiring additional recoverable
reserves. We may not be able to develop, exploit, find or acquire
additional reserves to replace our current and future production.
The
loss of senior management or technical personnel could adversely affect
us.
To a
large extent, we depend on the services of our senior management and technical
personnel. The loss of the services of our senior management or technical
personnel, including James J. Volker, our Chairman, President and Chief
Executive Officer; James T. Brown, our Senior Vice President; Rick A. Ross, our
Vice President, Operations; Peter W. Hagist, our Vice President, Permian
Operations; J. Douglas Lang, our Vice President, Reservoir
Engineering/Acquisitions; David M. Seery, our Vice President of Land; Michael J.
Stevens, our Vice President and Chief Financial Officer; or Mark R. Williams,
our Vice President, Exploration and Development, could have a material adverse
effect on our operations. We do not maintain, nor do we plan to obtain, any
insurance against the loss of any of these individuals.
The
unavailability or high cost of additional drilling rigs, equipment, supplies,
personnel and oil field services could adversely affect our ability to execute
our exploration and development plans on a timely basis or within our
budget.
Shortages
or the high cost of drilling rigs, equipment, supplies or personnel could delay
or adversely affect our exploration and development operations, which could have
a material adverse effect on our business, financial condition, results of
operations or cash flows.
Competition
in the oil and gas industry is intense, which may adversely affect our ability
to compete.
We
operate in a highly competitive environment for acquiring properties, marketing
oil and gas and securing trained personnel. Many of our competitors
possess and employ financial, technical and personnel resources substantially
greater than ours, which can be particularly important in the areas in which we
operate. Those companies may be able to pay more for productive oil
and gas properties and exploratory prospects and to evaluate, bid for and
purchase a greater number of properties and prospects than our financial or
personnel resources permit. Our ability to acquire additional
prospects and to find and develop reserves in the future will depend on our
ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. Also, there is
substantial competition for available capital for investment in the oil and gas
industry. We may not be able to compete successfully in the future in
acquiring prospective reserves, developing reserves, marketing hydrocarbons,
attracting and retaining quality personnel and raising additional
capital.
Certain
federal income tax deductions currently available with respect to oil and gas
exploration and development may be eliminated as a result of future
legislation.
In May
2009, President Obama’s Administration released revenue proposals in “General
Explanations of the Administration’s Fiscal 2010 Revenue Proposals” that would,
if enacted into law, make significant changes to United States tax laws,
including the elimination of certain key U.S. federal income tax preferences
currently available to oil and gas exploration and production
companies. These changes include, but are not limited to (i) the
repeal of the percentage depletion allowance for oil and gas properties, (ii)
the elimination of current deductions for intangible drilling and development
costs, (iii) the elimination of the deduction for certain U.S. production
activities and (iv) an extension of the amortization period for certain
geological and geophysical expenditures. In April 2009, the Oil
Industry Tax Break Repeal Act of 2009, or the Senate Bill, was introduced in the
Senate and includes many of the proposals outlined in the revenue
proposals. It is unclear whether any such changes will actually be
enacted or how soon any such changes could become effective. The
passage of any legislation as a result of the revenue proposals, the Senate Bill
or any other similar change in U.S. federal income tax law could eliminate
certain tax deductions that are currently available with respect to oil and gas
exploration and development, and any such change could negatively impact our
financial condition and results of operations.
|
Submission of Matters to a Vote of Security
Holders
|
Whiting
Petroleum Corporation held its annual meeting of stockholders on May 5,
2009. At such meeting, James J. Volker, William N. Hahne and Graydon
D. Hubbard and were reelected as directors for terms to expire at the 2012
annual meeting of stockholders and until their successors are duly
elected and qualified pursuant to the following votes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
James
J.
Volker
|
|
|
38,586,992 |
|
|
|
5,329,688 |
|
William
N.
Hahne
|
|
|
39,586,070 |
|
|
|
4,330,610 |
|
Graydon
D.
Hubbard
|
|
|
39,673,297 |
|
|
|
4,243,383 |
|
The other
directors of Whiting Petroleum Corporation whose terms of office continued after
the 2009 annual meeting of stockholders are as follows: terms
expiring at the 2010 annual meeting: Thomas L. Aller and Thomas P.
Briggs; and terms expiring at the 2011 annual meeting: D. Sherwin
Artus and Palmer L. Moe.
The
following other matter brought for vote at the 2009 annual meeting of
stockholders passed by the vote indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ratification
of the appointment of Deloitte & Touche LLP as independent registered
public accounting firm
|
|
|
43,775,164 |
|
|
|
107,608 |
|
|
|
33,908 |
|
|
|
- |
|
The
exhibits listed in the accompanying index to exhibits are filed as part of this
Quarterly Report on Form 10-Q.
Pursuant
to the requirements of the Securities Exchange Act of 1934, the Registrant has
duly caused this report to be signed on its behalf by the undersigned thereunto
duly authorized, on this 30th day of July, 2009.
|
|
WHITING
PETROLEUM CORPORATION
|
|
|
|
|
|
|
|
By
|
/s/
James J. Volker
|
|
|
James
J. Volker
|
|
|
Chairman,
President and Chief Executive Officer
|
|
|
|
|
|
|
|
By
|
/s/
Michael J. Stevens
|
|
|
Michael
J. Stevens
|
|
|
Vice
President and Chief Financial Officer
|
|
|
|
|
|
|
|
By
|
/s/
Brent P. Jensen
|
|
|
Brent
P. Jensen
|
|
|
Controller
and Treasurer
|
Exhibit
Number
|
Exhibit Description
|
(3.1)
|
Certificate
of Designations of 6.25% Convertible Perpetual Preferred Stock of Whiting
Petroleum Corporation [Incorporated by reference to Exhibit 3.1 to Whiting
Petroleum Corporation’s Current Report on Form 8-K dated June 17, 2009
(File No. 001- 31899)].
|
(4.1)
|
First
Amendment to Fourth Amended and Restated Credit Agreement, dated as of
June 15, 2009, among Whiting Petroleum Corporation, Whiting Oil and Gas
Corporation, JPMorgan Chase Bank, N.A., as Administrative Agent, and the
other agents and lenders party thereto [Incorporated by reference to
Exhibit 4.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K
dated June 15, 2009 (File No. 001- 31899)].
|
(31.1)
|
Certification
by the Chairman, President and Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act.
|
(31.2)
|
Certification
by the Vice President and Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act.
|
(32.1)
|
Written
Statement of the Chairman, President and Chief Executive Officer pursuant
to 18 U.S.C. Section 1350.
|
(32.2)
|
Written
Statement of the Vice President and Chief Financial Officer pursuant to 18
U.S.C. Section 1350.
|
58