UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM 10-Q
[X]
|
QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
|
For the
quarterly period ended September 30,
2008
or
[ ]
|
TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
|
For the
transition period from _______________ to _______________
|
Commission
file number: 001-31899
WHITING
PETROLEUM CORPORATION
|
|
|
(Exact
name of registrant as specified in its charter)
|
|
|
|
|
Delaware
|
|
20-0098515
|
(State
or other jurisdiction
of
incorporation or organization)
|
|
(I.R.S.
Employer
Identification
No.)
|
|
|
|
1700
Broadway, Suite 2300
Denver
Colorado
|
|
80290-2300
|
(Address
of principal executive offices)
|
|
(Zip
code)
|
|
|
|
|
(303)
837-1661
|
|
|
(Registrant’s
telephone number, including area code)
|
|
Indicate
by check mark whether the registrant (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past
90 days. Yes T No £
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,”
“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one):
Large
accelerated filerT
|
Accelerated
filer £
|
Non-accelerated
filer£
|
Smaller
reporting company£
|
|
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).Yes £No T
Number of
shares of the registrant’s common stock outstanding at October 15,
2008: 42,322,978 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.
“Bbl/d” One stock tank
barrel, or 42 U.S. gallons liquid volume, used in this report in reference to
oil and other liquid hydrocarbons per day.
“Bcf” One billion cubic feet
of natural gas.
“Bcfe” One billion cubic feet
of natural gas equivalent.
“BOE” One stock tank barrel
equivalent of oil, calculated by converting natural gas volumes to equivalent
oil barrels at a ratio of six Mcf to one Bbl of oil.
“flush production” The high
rate of flow from a well during initial production immediately after it is
brought on-line.
“Mbbl” One thousand barrels
of oil or other liquid hydrocarbons.
“MBOE” One thousand
BOE.
“MBOE/d” One thousand BOE per
day.
“Mcf” One thousand cubic feet
of natural gas.
“Mcfe” One thousand cubic
feet of natural gas equivalent.
“MMbbl” One million barrels of
oil or other liquid hydrocarbons.
“MMBOE” One million
BOE.
“MMbtu” One million British
Thermal Units.
“MMcf” One million cubic feet
of natural gas.
“MMcfe/d” One million cubic
feet of natural gas equivalent per day.
“plugging and abandonment”
Refers to the sealing off of fluids in the strata penetrated by a well so that
the fluids from one stratum will not escape into another or to the
surface. Regulations of many states require plugging of abandoned
wells.
“working interest” The
interest in a crude oil and natural gas property (normally a leasehold interest)
that gives the owner the right to drill, produce and conduct operations on the
property and to share in production, subject to all royalties, overriding
royalties and other burdens and to share in all costs of exploration,
development, operations and all risks in connection therewith.
PART I –
FINANCIAL INFORMATION
|
Consolidated Financial
Statements
|
WHITING PETROLEUM CORPORATION
CONDENSED
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In
thousands)
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
CURRENT
ASSETS:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
20,644 |
|
|
$ |
14,778 |
|
Accounts
receivable trade, net
|
|
|
192,711 |
|
|
|
110,437 |
|
Deferred
income taxes
|
|
|
1,949 |
|
|
|
27,720 |
|
Prepaid
expenses and other
|
|
|
26,562 |
|
|
|
9,232 |
|
Total
current assets
|
|
|
241,866 |
|
|
|
162,167 |
|
PROPERTY
AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
Oil
and gas properties, successful efforts method:
|
|
|
|
|
|
|
|
|
Proved
properties
|
|
|
4,137,940 |
|
|
|
3,313,777 |
|
Unproved
properties
|
|
|
132,908 |
|
|
|
55,084 |
|
Other
property and equipment
|
|
|
69,546 |
|
|
|
37,778 |
|
Total
property and equipment
|
|
|
4,340,394 |
|
|
|
3,406,639 |
|
Less
accumulated depreciation, depletion and amortization
|
|
|
(789,192 |
) |
|
|
(646,943 |
) |
Total
property and equipment, net
|
|
|
3,551,202 |
|
|
|
2,759,696 |
|
DEBT
ISSUANCE COSTS
|
|
|
11,826 |
|
|
|
15,016 |
|
OTHER
LONG-TERM ASSETS
|
|
|
30,252 |
|
|
|
15,132 |
|
TOTAL
|
|
$ |
3,835,146 |
|
|
$ |
2,952,011 |
|
|
|
|
|
|
|
|
|
|
See
notes to condensed consolidated financial statements.
|
|
|
|
|
|
(Continued)
|
|
WHITING
PETROLEUM CORPORATION
CONDENSED
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In
thousands, except share and per share data)
|
|
|
|
|
|
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
Accounts
payable
|
|
$ |
40,269 |
|
|
$ |
19,280 |
|
Accrued
capital expenditures
|
|
|
82,840 |
|
|
|
58,988 |
|
Accrued
liabilities
|
|
|
35,393 |
|
|
|
29,551 |
|
Accrued
interest
|
|
|
21,222 |
|
|
|
11,240 |
|
Oil
and gas sales payable
|
|
|
53,347 |
|
|
|
26,205 |
|
Accrued
employee compensation and benefits
|
|
|
37,153 |
|
|
|
21,081 |
|
Production
taxes payable
|
|
|
29,643 |
|
|
|
12,936 |
|
Current
portion of deferred gain on sale
|
|
|
15,235 |
|
|
|
- |
|
Current
portion of tax sharing liability
|
|
|
2,587 |
|
|
|
2,587 |
|
Current
portion of derivative liability
|
|
|
25,046 |
|
|
|
72,796 |
|
Total
current liabilities
|
|
|
342,735 |
|
|
|
254,664 |
|
NON-CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
1,118,560 |
|
|
|
868,248 |
|
Asset
retirement obligations
|
|
|
42,254 |
|
|
|
35,883 |
|
Production
Participation Plan liability
|
|
|
61,006 |
|
|
|
34,042 |
|
Tax
sharing liability
|
|
|
24,004 |
|
|
|
23,070 |
|
Deferred
income taxes
|
|
|
381,753 |
|
|
|
242,964 |
|
Long-term
derivative liability
|
|
|
5,243 |
|
|
|
- |
|
Deferred
gain on sale
|
|
|
77,229 |
|
|
|
- |
|
Other
long-term liabilities
|
|
|
2,933 |
|
|
|
2,314 |
|
Total
non-current liabilities
|
|
|
1,712,982 |
|
|
|
1,206,521 |
|
COMMITMENTS
AND CONTINGENCIES
|
|
|
|
|
|
|
|
|
STOCKHOLDERS’
EQUITY:
|
|
|
|
|
|
|
|
|
Common
stock, $0.001 par value; 75,000,000 shares authorized, 42,584,833 and
42,480,497 shares issued as of September 30, 2008 and December 31,
2007, respectively
|
|
|
43 |
|
|
|
42 |
|
Additional
paid-in capital
|
|
|
972,050 |
|
|
|
968,876 |
|
Accumulated
other comprehensive loss
|
|
|
(15,867 |
) |
|
|
(46,116 |
) |
Retained
earnings
|
|
|
823,203 |
|
|
|
568,024 |
|
Total
stockholders’ equity
|
|
|
1,779,429 |
|
|
|
1,490,826 |
|
TOTAL
|
|
$ |
3,835,146 |
|
|
$ |
2,952,011 |
|
|
|
|
|
|
|
|
|
|
See
notes to condensed consolidated financial statements.
|
|
|
|
|
|
(Concluded)
|
|
WHITING PETROLEUM CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(In
thousands, except per share data)
|
|
Three
Months Ended
September
30,
|
|
|
Nine
Months Ended
September
30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
AND OTHER INCOME:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and natural gas sales
|
|
$ |
425,392 |
|
|
$ |
205,594 |
|
|
$ |
1,102,658 |
|
|
$ |
557,953 |
|
Loss
on oil hedging activities
|
|
|
(41,879 |
) |
|
|
(2,101 |
) |
|
|
(112,902 |
) |
|
|
(2,101 |
) |
Gain
on sale of properties
|
|
|
- |
|
|
|
29,682 |
|
|
|
- |
|
|
|
29,682 |
|
Amortization
of deferred gain on sale
|
|
|
4,720 |
|
|
|
- |
|
|
|
7,677 |
|
|
|
- |
|
Interest
income and other
|
|
|
201 |
|
|
|
353 |
|
|
|
825 |
|
|
|
821 |
|
Total
revenues and other income
|
|
|
388,434 |
|
|
|
233,528 |
|
|
|
998,258 |
|
|
|
586,355 |
|
COSTS
AND EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating
|
|
|
64,690 |
|
|
|
53,472 |
|
|
|
177,866 |
|
|
|
154,512 |
|
Production
taxes
|
|
|
28,245 |
|
|
|
13,197 |
|
|
|
71,988 |
|
|
|
34,888 |
|
Depreciation,
depletion and amortization
|
|
|
74,233 |
|
|
|
49,308 |
|
|
|
179,555 |
|
|
|
143,214 |
|
Exploration
and impairment
|
|
|
10,939 |
|
|
|
10,420 |
|
|
|
30,566 |
|
|
|
26,239 |
|
General
and administrative
|
|
|
17,281 |
|
|
|
10,780 |
|
|
|
51,903 |
|
|
|
27,941 |
|
Change
in Production Participation Plan liability
|
|
|
9,117 |
|
|
|
2,254 |
|
|
|
26,964 |
|
|
|
6,404 |
|
Interest
expense
|
|
|
17,543 |
|
|
|
16,263 |
|
|
|
48,760 |
|
|
|
56,514 |
|
(Gain)
loss on mark-to-market derivatives
|
|
|
(10,561 |
) |
|
|
487 |
|
|
|
7,064 |
|
|
|
1,178 |
|
Total
costs and expenses
|
|
|
211,487 |
|
|
|
156,181 |
|
|
|
594,666 |
|
|
|
450,890 |
|
INCOME
BEFORE INCOME TAXES
|
|
|
176,947 |
|
|
|
77,347 |
|
|
|
403,592 |
|
|
|
135,465 |
|
INCOME
TAX EXPENSE:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
481 |
|
|
|
3,401 |
|
|
|
1,353 |
|
|
|
5,542 |
|
Deferred
|
|
|
64,049 |
|
|
|
26,233 |
|
|
|
147,060 |
|
|
|
45,073 |
|
Total
income tax expense
|
|
|
64,530 |
|
|
|
29,634 |
|
|
|
148,413 |
|
|
|
50,615 |
|
NET
INCOME
|
|
$ |
112,417 |
|
|
$ |
47,713 |
|
|
$ |
255,179 |
|
|
$ |
84,850 |
|
NET
INCOME PER COMMON SHARE, BASIC
|
|
$ |
2.66 |
|
|
$ |
1.14 |
|
|
$ |
6.03 |
|
|
$ |
2.20 |
|
NET
INCOME PER COMMON SHARE, DILUTED
|
|
$ |
2.65 |
|
|
$ |
1.13 |
|
|
$ |
6.01 |
|
|
$ |
2.19 |
|
WEIGHTED
AVERAGE SHARES OUTSTANDING, BASIC
|
|
|
42,322 |
|
|
|
42,027 |
|
|
|
42,305 |
|
|
|
38,555 |
|
WEIGHTED
AVERAGE SHARES OUTSTANDING, DILUTED
|
|
|
42,465 |
|
|
|
42,152 |
|
|
|
42,464 |
|
|
|
38,728 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See
notes to condensed consolidated financial statements.
|
|
|
|
|
|
|
|
|
|
WHITING PETROLEUM CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(In
thousands)
|
|
Nine
Months Ended
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
income
|
|
$ |
255,179 |
|
|
$ |
84,850 |
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
179,555 |
|
|
|
143,214 |
|
Deferred
income taxes
|
|
|
147,060 |
|
|
|
45,073 |
|
Amortization
of debt issuance costs and debt discount
|
|
|
3,618 |
|
|
|
3,793 |
|
Accretion
of tax sharing liability
|
|
|
934 |
|
|
|
1,142 |
|
Stock-based
compensation
|
|
|
4,917 |
|
|
|
3,652 |
|
Gain
on sale of properties
|
|
|
- |
|
|
|
(29,682 |
) |
Amortization
of deferred gain on sale
|
|
|
(7,677 |
) |
|
|
- |
|
Unproved
leasehold and oil and gas property impairments
|
|
|
9,016 |
|
|
|
7,158 |
|
Change
in Production Participation Plan liability
|
|
|
26,964 |
|
|
|
6,404 |
|
Unrealized
loss on mark-to-market derivatives
|
|
|
7,021 |
|
|
|
1,178 |
|
Other
non-current
|
|
|
(14,744 |
) |
|
|
(3,596 |
) |
Changes
in current assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts
receivable trade
|
|
|
(77,398 |
) |
|
|
2,591 |
|
Prepaid
expenses and other
|
|
|
(17,836 |
) |
|
|
3,654 |
|
Accounts
payable and accrued liabilities
|
|
|
26,683 |
|
|
|
(13,301 |
) |
Accrued
interest
|
|
|
9,982 |
|
|
|
15,113 |
|
Other
current liabilities
|
|
|
58,178 |
|
|
|
1,366 |
|
Net
cash provided by operating activities
|
|
|
611,452 |
|
|
|
272,609 |
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Cash
acquisition capital expenditures
|
|
|
(413,219 |
) |
|
|
(16,780 |
) |
Drilling
and development capital expenditures
|
|
|
(638,400 |
) |
|
|
(353,686 |
) |
Proceeds
from sale of oil and gas properties
|
|
|
1,445 |
|
|
|
45,419 |
|
Proceeds
from sale of marketable securities
|
|
|
764 |
|
|
|
- |
|
Net
proceeds from sale of 11,677,500 units in Whiting USA Trust
I
|
|
|
193,824 |
|
|
|
- |
|
Net
cash used in investing activities
|
|
|
(855,586 |
) |
|
|
(325,047 |
) |
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Issuance
of common stock
|
|
|
- |
|
|
|
210,394 |
|
Long-term
borrowings under credit agreement
|
|
|
925,000 |
|
|
|
274,400 |
|
Repayments
of long-term borrowings under credit agreement
|
|
|
(675,000 |
) |
|
|
(434,400 |
) |
Tax
effect from restricted stock vesting
|
|
|
- |
|
|
|
377 |
|
Net
cash provided by financing activities
|
|
|
250,000 |
|
|
|
50,771 |
|
NET
CHANGE IN CASH AND CASH EQUIVALENTS
|
|
|
5,866 |
|
|
|
(1,667 |
) |
CASH
AND CASH EQUIVALENTS:
|
|
|
|
|
|
|
|
|
Beginning
of period
|
|
|
14,778 |
|
|
|
10,372 |
|
End
of period
|
|
$ |
20,644 |
|
|
$ |
8,705 |
|
SUPPLEMENTAL
CASH FLOW DISCLOSURES:
|
|
|
|
|
|
|
|
|
Cash
paid for income taxes
|
|
$ |
1,175 |
|
|
$ |
1,717 |
|
Cash
paid for interest
|
|
$ |
34,227 |
|
|
$ |
36,467 |
|
NONCASH
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Accrued
capital expenditures during the period
|
|
$ |
82,840 |
|
|
$ |
45,038 |
|
See
notes to condensed consolidated financial statements.
|
|
|
|
|
|
|
|
|
WHITING PETROLEUM CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
AND
COMPREHENSIVE INCOME (Unaudited)
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
Paid-in Capital
|
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
|
|
|
Total
Stockholders’ Equity
|
|
|
|
|
BALANCES-January
1, 2007
|
|
|
36,948 |
|
|
$ |
37 |
|
|
$ |
754,788 |
|
|
$ |
(5,902 |
) |
|
$ |
437,747 |
|
|
$ |
1,186,670 |
|
|
|
|
Adoption
of FIN 48
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(323 |
) |
|
|
(323 |
) |
|
$ |
- |
|
Net
income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
130,600 |
|
|
|
130,600 |
|
|
|
130,600 |
|
Change
in derivative fair values, net of taxes of $31,012
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(53,637 |
) |
|
|
- |
|
|
|
(53,637 |
) |
|
|
(53,637 |
) |
Realized
loss on settled derivative contracts, net of taxes of
$7,766
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
13,423 |
|
|
|
- |
|
|
|
13,423 |
|
|
|
13,423 |
|
Issuance
of stock, secondary offering
|
|
|
5,425 |
|
|
|
5 |
|
|
|
210,389 |
|
|
|
- |
|
|
|
- |
|
|
|
210,394 |
|
|
|
- |
|
Restricted
stock issued
|
|
|
150 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Restricted
stock forfeited
|
|
|
(12 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Restricted
stock used for tax withholdings
|
|
|
(31 |
) |
|
|
- |
|
|
|
(1,403 |
) |
|
|
- |
|
|
|
- |
|
|
|
(1,403 |
) |
|
|
- |
|
Tax
effect from restricted stock vesting
|
|
|
- |
|
|
|
- |
|
|
|
45 |
|
|
|
- |
|
|
|
- |
|
|
|
45 |
|
|
|
- |
|
Stock-based
compensation
|
|
|
- |
|
|
|
- |
|
|
|
5,057 |
|
|
|
- |
|
|
|
- |
|
|
|
5,057 |
|
|
|
- |
|
BALANCES-December
31, 2007
|
|
|
42,480 |
|
|
$ |
42 |
|
|
$ |
968,876 |
|
|
$ |
(46,116 |
) |
|
$ |
568,024 |
|
|
$ |
1,490,826 |
|
|
$ |
90,386 |
|
Net
income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
255,179 |
|
|
|
255,179 |
|
|
|
255,179 |
|
Change
in derivative fair values, net of taxes of $23,878
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(41,274 |
) |
|
|
- |
|
|
|
(41,274 |
) |
|
|
(41,274 |
) |
Realized
loss on settled derivative contracts, net of taxes of
$41,379
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
71,523 |
|
|
|
- |
|
|
|
71,523 |
|
|
|
71,523 |
|
Restricted
stock issued
|
|
|
139 |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
Restricted
stock forfeited
|
|
|
(4 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Restricted
stock used for tax withholdings
|
|
|
(30 |
) |
|
|
- |
|
|
|
(1,743 |
) |
|
|
- |
|
|
|
- |
|
|
|
(1,743 |
) |
|
|
- |
|
Stock-based
compensation
|
|
|
- |
|
|
|
- |
|
|
|
4,917 |
|
|
|
- |
|
|
|
- |
|
|
|
4,917 |
|
|
|
- |
|
BALANCES-September
30, 2008
|
|
|
42,585 |
|
|
$ |
43 |
|
|
$ |
972,050 |
|
|
$ |
(15,867 |
) |
|
$ |
823,203 |
|
|
$ |
1,779,429 |
|
|
$ |
285,428 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See
notes to condensed consolidated financial statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WHITING PETROLEUM CORPORATION
NOTES
TO CONDENSED CONSOLIDATED
FINANCIAL
STATEMENTS (Unaudited)
Description of
Operations—Whiting Petroleum Corporation, a Delaware corporation, is an
independent oil and gas company that acquires, exploits, develops and explores
for crude oil, natural gas and natural gas liquids primarily in the Permian
Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the
United States. Unless otherwise specified or the context otherwise
requires, all references in these notes to “Whiting” or the “Company” are to
Whiting Petroleum Corporation and its consolidated subsidiaries.
Consolidated
Financial Statements—The unaudited condensed 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. The financial statements have been prepared in
accordance with U.S. generally accepted accounting principles for interim
financial reporting. All intercompany balances and transactions have
been eliminated in consolidation. In the opinion of management, the
accompanying financial statements include all adjustments (consisting of normal
recurring accruals and adjustments) necessary to present fairly, in all material
respects, the Company’s interim results. Whiting’s 2007 Annual Report
on Form 10-K includes certain definitions and a summary of significant
accounting policies and should be read in conjunction with this Form
10-Q. Except as disclosed herein, there has been no material change
to the information disclosed in the notes to the consolidated financial
statements included in Whiting’s 2007 Annual Report on
Form 10-K. Operating results for the periods presented are not
necessarily indicative of the results that may be expected for the full
year.
Earnings Per
Share—Basic net income per common share is calculated by dividing net
income by the weighted average number of common shares outstanding during each
period. Diluted net income per common share is calculated by dividing
net income by the weighted average number of common shares outstanding and other
dilutive securities. The only securities considered dilutive are the
Company’s unvested restricted stock awards.
2.
|
ACQUISITIONS
AND DIVESTITURES
|
2008
Acquisition
Flat Rock Natural
Gas Field—On
May 30, 2008, Whiting acquired interests in 31 producing gas wells,
development acreage and gas gathering and processing facilities on 22,029 gross
acres (11,533 net acres) in the Flat Rock field in Uintah County, Utah for an
aggregate acquisition price of $359.4 million. After allocating $79.5
million of the purchase price to unproved property, $35.7 million to the gas
gathering and processing facilities and $7.7 million to liabilities assumed, the
remaining $251.9 million results in an acquisition cost for proved reserves of
$2.19 per Mcfe. Of the estimated 115.2 Bcfe of proved reserves
acquired as of the January 1, 2008 acquisition effective date, 98% are natural
gas and 22% are proved developed producing. The average daily net
production from the properties was 17.8 MMcfe/d as of the acquisition effective
date. Whiting funded the acquisition with borrowings under its credit
agreement.
This
acquisition was recorded using the purchase method of accounting. The
table below summarizes the allocation of 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 condensed consolidated statements of income, Flat Rock’s results of
operations are included with the Company’s results beginning May 31,
2008. The following table, however, reflects the unaudited pro forma
results of operations for the nine months ended September 30, 2008 and for the
three and nine months ended September 30, 2007, as though the Flat Rock
acquisition had occurred on the first day of each period
presented. The pro forma information below includes numerous
assumptions and is not necessarily indicative of what historical results would
have been or what future results of operations will be.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
months ended September 30, 2008:
|
|
|
|
|
|
|
|
|
|
Total
revenues
|
|
$ |
998,258 |
|
|
$ |
17,761 |
|
|
$ |
1,016,019 |
|
Net
income
|
|
|
255,179 |
|
|
|
1,144 |
|
|
|
256,323 |
|
Net
income per common share – basic
|
|
|
6.03 |
|
|
|
0.03 |
|
|
|
6.06 |
|
Net
income per common share – diluted
|
|
|
6.01 |
|
|
|
0.03 |
|
|
|
6.04 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
months ended September 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
revenues
|
|
$ |
233,528 |
|
|
$ |
3,803 |
|
|
$ |
237,331 |
|
Net
income
|
|
|
47,713 |
|
|
|
(2,126 |
) |
|
|
45,587 |
|
Net
income per common share – basic
|
|
|
1.14 |
|
|
|
(0.06 |
) |
|
|
1.08 |
|
Net
income per common share – diluted
|
|
|
1.13 |
|
|
|
(0.05 |
) |
|
|
1.08 |
|
|
|
|
|
|
|
Pro
Forma
|
|
|
|
Whiting
(As
reported)
|
|
|
Flat
Rock
|
|
|
Consolidated |
|
Nine
months ended September 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
revenues
|
|
$ |
586,355 |
|
|
$ |
18,538 |
|
|
$ |
604,893 |
|
Net
income
|
|
|
84,850 |
|
|
|
(3,216 |
) |
|
|
81,634 |
|
Net
income per common share – basic
|
|
|
2.20 |
|
|
|
(0.08 |
) |
|
|
2.12 |
|
Net
income per common share – diluted
|
|
|
2.19 |
|
|
|
(0.08 |
) |
|
|
2.11 |
|
2008
Divestiture
Whiting USA Trust
I—On April 30, 2008, the Company completed an initial public
offering of units of beneficial interest in Whiting USA Trust I (the
“Trust”), selling 11,677,500 Trust units at $20.00 per Trust unit, providing net
proceeds of $215.0 million after underwriters’ discount and commissions and
offering related expenses. Whiting’s net profits from the Trust’s
underlying oil and gas properties received between the effective date and the
closing date of the Trust unit sale were paid to the Trust and thereby further
reduced net proceeds to $193.8 million. The Company used the net
offering proceeds to reduce the debt outstanding under its credit
agreement. The aggregate proceeds from the sale of Trust units to the
public resulted in a deferred gain on sale of $100.1
million. Immediately prior to the closing of the offering, Whiting
conveyed a term net profits interest in certain of its oil and natural gas
properties to the Trust in exchange for 13,863,889 Trust units. The
Company has retained 15.8%, or 2,186,389 Trust units, of the total Trust units
issued and outstanding.
The net
profits interest entitles the Trust to receive 90% of the net proceeds from the
sale of oil and natural gas production from the underlying
properties. The net profits interest will terminate at the time when
9.11 MMBOE have been produced and sold from the underlying
properties. This is the equivalent of 8.2 MMBOE in respect of the
Trust’s right to receive 90% of the net proceeds from such production pursuant
to the net profits interest, and these reserve quantities are projected to be
produced by December 31, 2017 based on the reserve report for the
underlying properties as of December 31, 2007. The conveyance of
the net profits interest to the Trust consisted entirely of proved developed
producing reserves of 8.2 MMBOE, as of the January 1, 2008 effective
date, representing 3.3% of Whiting’s proved reserves as of December 31,
2007, and 10.0%, or 4.2 MBOE/d, of its March 2008 average daily net
production. After netting the Company’s ownership of 2,186,389 Trust
units, third-party public Trust unit holders receive 6.9 MMBOE of proved
producing reserves, or 2.75% of the Company’s total year-end 2007 proved
reserves, and 7.4%, or 3.1 MBOE/d, of its March 2008 average daily net
production.
2007
Acquisitions
There
were no significant acquisitions during the year ended December 31,
2007.
2007
Divestitures
On
July 17, 2007, the Company sold its approximate 50% non-operated working
interest in several gas fields located in the LaSalle and Webb Counties of Texas
for total cash proceeds of $40.1 million, resulting in a pre-tax gain on sale of
$29.7 million. The divested properties had estimated proved reserves
of 2.3 MMBOE as of December 31, 2006, and when adjusted to the July 1,
2007 divestiture effective date, the divested property reserves yielded a sale
price of $17.77 per BOE. The June 2007 average daily net production
from these fields was 0.8 MBOE/d.
During
2007, the Company sold its interests in several additional non-core oil and gas
producing properties for an aggregate amount of $12.5 million in cash for
total estimated proved reserves of 0.6 MMBOE as of the divestitures’ effective
dates. The divested properties are located in Colorado, Louisiana,
Michigan, Montana, New Mexico, North Dakota, Oklahoma, Texas and
Wyoming. The average daily net production from the divested property
interests was 0.3 MBOE/d as of the dates of disposition.
Long-term
debt consisted of the following at September 30, 2008 and December 31, 2007 (in
thousands):
|
|
|
|
|
|
|
Credit
Agreement
|
|
$ |
500,000 |
|
|
$ |
250,000 |
|
7%
Senior Subordinated Notes due 2014
|
|
|
250,000 |
|
|
|
250,000 |
|
7.25%
Senior Subordinated Notes due 2013, net of unamortized debt discount of
$1,645 and $1,966, respectively
|
|
|
218,355 |
|
|
|
218,034 |
|
7.25%
Senior Subordinated Notes due 2012, net of unamortized debt discount of
$429 and $537, respectively
|
|
|
150,205 |
|
|
|
150,214 |
|
Total debt
|
|
$ |
1,118,560 |
|
|
$ |
868,248 |
|
Credit
Agreement—The Company’s wholly-owned subsidiary, Whiting Oil and Gas
Corporation (“Whiting Oil and Gas”) has a $1.2 billion credit agreement with a
syndicate of banks that, as of September 30, 2008, had a borrowing base of
$900.0 million with $397.3 million of available borrowing capacity, which is net
of $500.0 million in borrowings and $2.7 million in letters of credit
outstanding. The borrowing base under the credit agreement is
determined at the discretion of the lenders, based on the collateral value of
the proved reserves that have been mortgaged to the lenders, and is subject to
regular redeterminations on May 1 and November 1 of each year, as well as
special redeterminations described in the credit agreement.
The
credit agreement provides for interest only payments until August 31, 2010, when
the entire amount borrowed is due. Whiting Oil and Gas may,
throughout the five-year term of the credit agreement, borrow, repay and
reborrow up to the borrowing base in effect at any given time. The
lenders under the credit agreement have also committed to issue letters of
credit for the account of Whiting Oil and Gas or other designated subsidiaries
of the Company in an aggregate amount not to exceed $50.0 million. As
of September 30, 2008, $47.3 million was available for additional letters of
credit under the agreement.
Interest
accrues, at Whiting Oil and Gas’ option, at either (1) the base rate plus a
margin, where the base rate is defined as the higher of the prime rate or the
federal funds rate plus 0.5% and the margin varies from 0% to 0.5% depending on
the utilization percentage of the borrowing base, or (2) at the LIBOR rate plus
a margin, where the margin varies from 1.00% to 1.75% depending on the
utilization percentage of the borrowing base. Commitment fees of
0.25% to 0.375% accrue on the unused portion of the borrowing base, depending on
the utilization percentage, and are included as a component of interest
expense. At September 30, 2008, the weighted average interest rate on
the outstanding principal balance under the credit agreement was
3.9%.
The
credit agreement contains restrictive covenants that may limit the Company’s
ability to, among other things, pay cash dividends, incur additional
indebtedness, sell assets, make loans to others, make investments, enter into
mergers, enter into hedging contracts, change material agreements, incur liens
and engage in certain other transactions without the prior consent of the
lenders and requires the Company to maintain a debt to EBITDAX ratio (as defined
in the credit agreement) of less than 3.5 to 1 and a working capital ratio (as
defined in the credit agreement and which includes an add back of the available
borrowing capacity under the credit facility) of greater than
1 to 1. Except for limited exceptions, including the
payment of interest on the senior notes, the credit agreement restricts the
ability of Whiting Oil and Gas and Whiting Petroleum Corporation’s wholly-owned
subsidiary, Equity Oil Company, to make any dividends, distributions, principal
payments on senior notes, or other payments to Whiting Petroleum
Corporation. The restrictions apply to all of the net assets of these
subsidiaries. The Company was in compliance with its covenants under
the credit agreement as of September 30, 2008. The credit agreement
is secured by a first lien on all of Whiting Oil and Gas’ properties included in
the borrowing base for the credit agreement. Whiting Petroleum
Corporation and Equity Oil Company have guaranteed the obligations of Whiting
Oil and Gas under the credit agreement. Whiting Petroleum Corporation
has pledged the stock of Whiting Oil and Gas and Equity Oil Company as security
for its guarantee, and Equity Oil Company has mortgaged all of its properties,
that are included in the borrowing base for the credit agreement, as security
for its guarantee.
Senior
Subordinated Notes—In October 2005, the Company issued at par
$250.0 million of 7% Senior Subordinated Notes due 2014. The
estimated fair value of these notes was $207.5 million as of September 30,
2008, 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 $195.5 million as
of September 30, 2008, 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 $134.6 million
as of September 30, 2008, based on quoted market prices for these same debt
securities.
The notes
are unsecured obligations of Whiting Petroleum Corporation and are subordinated
to all of the Company’s senior debt, which currently consists of Whiting Oil and
Gas’ credit agreement. The indentures governing the notes contain
various restrictive covenants that are substantially identical and may limit the
Company’s ability to, among other things, pay cash dividends, redeem or
repurchase the Company’s capital stock or the Company’s subordinated debt, make
investments, incur additional indebtedness or issue preferred stock, sell
assets, consolidate, merge or transfer all or substantially all of the assets of
the Company and its restricted subsidiaries taken as a whole, and enter into
hedging contracts. These covenants may potentially limit the
discretion of the Company’s management in certain respects. The
Company was in compliance with these covenants as of September 30,
2008. The Company’s wholly-owned operating subsidiaries, Whiting Oil
and Gas, Whiting Programs, Inc. and Equity Oil Company (the “Guarantors”), have
fully, unconditionally, jointly and severally guaranteed the Company’s
obligations under the notes. The Company does not have any
subsidiaries other than the Guarantors, minor or otherwise, within the meaning
of Rule 3-10(h)(6) of Regulation S-X of the Securities and Exchange
Commission, and Whiting Petroleum Corporation has no assets or operations
independent of this debt and its investments in guarantor
subsidiaries.
Interest Rate
Swap—In August 2004, the Company entered into an interest rate swap
contract to hedge the fair value of $75.0 million of its 7.25% Senior
Subordinated Notes due 2012. Because this swap meets the conditions
to qualify for the “short cut” method of assessing effectiveness, the change in
fair value of the debt is assumed to equal the change in the fair value of the
interest rate swap. As such, there is no ineffectiveness assumed to
exist between the interest rate swap and the notes.
The
interest rate swap is a fixed for floating swap in that the Company receives the
fixed rate of 7.25% and pays the floating rate. The floating rate is
redetermined every six months based on the LIBOR rate in effect at the
contractual reset date. When LIBOR plus the Company’s margin of
2.345% is less than 7.25%, the Company receives a payment from the counterparty
equal to the difference in rate times $75.0 million for the six month
period. When LIBOR plus the Company’s margin of 2.345% is greater
than 7.25%, the Company pays the counterparty an amount equal to the difference
in rate times $75.0 million for the six month period. As of September
30, 2008, the Company has recorded a long term asset of $0.6 million related to
the interest rate swap, which has been designated as a fair value hedge, with an
offsetting increase to the fair value of the 7.25% Senior Subordinated Notes due
2012.
4.
|
ASSET
RETIREMENT OBLIGATIONS
|
The
Company’s asset retirement obligations represent the estimated future costs
associated with the plugging and abandonment of oil and gas wells, removal of
equipment and facilities from leased acreage, and land restoration (including
removal of certain onshore and offshore facilities in California), in accordance
with applicable local, state and federal laws. The Company determines
asset retirement obligations by calculating the present value of estimated cash
flows related to plug and abandonment obligations. The current
portions at September 30, 2008 and December 31, 2007 were $1.4 million and $1.3
million, respectively, and were recorded in accrued liabilities. The
following table provides a reconciliation of the Company’s asset retirement
obligations for the nine months ended September 30, 2008 (in
thousands):
Asset
retirement obligation, January 1, 2008
|
|
$ |
37,192 |
|
Additional
liability incurred
|
|
|
2,944 |
|
Revisions
in estimated cash flows
|
|
|
5,695 |
|
Accretion
expense
|
|
|
2,341 |
|
Obligations
on sold or conveyed properties
|
|
|
(537 |
) |
Liabilities
settled
|
|
|
(3,951 |
) |
Asset
retirement obligation, September 30, 2008
|
|
$ |
43,684 |
|
5.
|
DERIVATIVE
FINANCIAL INSTRUMENTS
|
Whiting
enters into derivative contracts, primarily costless collars, to achieve a more
predictable cash flow by reducing its exposure to commodity price
volatility. Historically, prices received for oil and gas production
have been volatile because of seasonal weather patterns, supply and demand
factors, worldwide political factors and general economic
conditions. Costless collars are designed to establish floor and
ceiling prices on anticipated future oil and gas production. While
the use of these derivative instruments limits the downside risk of adverse
price movements, they may also limit future revenues from favorable price
movements. The Company has designated a portion of its derivative
contracts as cash flow hedges, whose unrealized fair value gains and losses are
recorded to other comprehensive income, while the Company’s remaining derivative
contracts are not designated as hedges, with gains and losses from changes in
fair value recognized immediately in earnings. The Company does not
enter into derivative instruments for speculative or trading
purposes.
At
September 30, 2008, accumulated other comprehensive loss consisted of $25.0
million ($15.9 million after tax) of unrealized losses, representing the
mark-to-market value of the Company’s open commodity contracts designated as
cash flow hedges as of the balance sheet date. For the three and nine
months ended September 30, 2008, Whiting recognized realized cash settlement
losses of $41.9 million and $112.9 million, respectively, on commodity
derivative settlements. For the three and nine months ended September
30, 2007, Whiting recognized realized cash settlement losses of $2.1 million on
commodity derivative settlements. Based on the estimated fair value
of the Company’s derivative contracts designated as hedges at September 30,
2008, the Company expects to reclassify into earnings from accumulated other
comprehensive income net after-tax losses of $15.9 million during the next three
months, as all costless collars designated as cash flow hedges will expire by
December 31, 2008. However, actual cash settlement gains and losses
recognized may differ materially.
As of
October 1, 2008, the Company had entered into costless collar derivative
contracts to reduce its exposure to commodity price volatility as
follows:
|
|
Whiting
Petroleum Corporation
|
|
|
|
|
|
|
NYMEX
Price Collar Ranges
|
|
|
|
Crude
Oil
|
|
|
|
|
|
Crude
Oil
|
|
|
Natural
Gas
|
|
October
2008
|
|
|
342,448 |
|
|
|
55,377 |
|
|
$58.41
- $77.62
|
|
|
$7.00
- $19.00
|
|
November
2008
|
|
|
342,448 |
|
|
|
55,377 |
|
|
$58.41
- $77.62
|
|
|
$7.00
- $19.00
|
|
December
2008
|
|
|
342,448 |
|
|
|
55,377 |
|
|
$58.41
- $77.62
|
|
|
$7.00
- $19.00
|
|
Total
|
|
|
1,027,344 |
|
|
|
166,131 |
|
|
|
|
|
|
|
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 hedge contracts conveyed to the Trust. The
relative ownership of the future economic results of such hedge contracts is
reflected in the tables below. No additional hedges are allowed to be
placed on Trust assets.
The 24.2%
portion of Trust derivative contracts that are absorbed by Whiting are as
follows:
|
|
Whiting
Petroleum Corporation
|
|
|
|
|
|
|
NYMEX
Price Collar Ranges
|
|
|
|
Crude
Oil
|
|
|
|
|
|
Crude
Oil
|
|
|
Natural
Gas
|
|
4th
Quarter 2008
|
|
|
37,343 |
|
|
|
166,131 |
|
|
$82.00
- $131.58
|
|
|
$7.00
- $19.00
|
|
2009
|
|
|
139,873 |
|
|
|
577,820 |
|
|
$76.00
- $137.43
|
|
|
$6.50
- $17.11
|
|
2010
|
|
|
126,289 |
|
|
|
495,390 |
|
|
$76.00
- $134.98
|
|
|
$6.50
- $15.06
|
|
2011
|
|
|
115,039 |
|
|
|
436,510 |
|
|
$74.00
- $140.15
|
|
|
$6.50
- $14.62
|
|
2012
|
|
|
105,091 |
|
|
|
384,002 |
|
|
$74.00
- $141.72
|
|
|
$6.50
- $14.27
|
|
Total
|
|
|
523,635 |
|
|
|
2,059,853 |
|
|
|
|
|
|
|
The 75.8%
portion of Trust derivative contracts that are absorbed by third-party public
holders of Trust units are as follows:
|
|
Third-party
Public Holders of Trust Units
|
|
|
|
|
|
|
NYMEX
Price Collar Ranges
|
|
|
|
Crude
Oil
|
|
|
Natural
|
|
|
Crude
Oil
|
|
|
Natural
Gas
|
|
4th
Quarter 2008
|
|
|
116,965 |
|
|
|
520,359 |
|
|
$82.00
- $131.58
|
|
|
$7.00
- $19.00
|
|
2009
|
|
|
438,113 |
|
|
|
1,809,868 |
|
|
$76.00
- $137.43
|
|
|
$6.50
- $17.11
|
|
2010
|
|
|
395,567 |
|
|
|
1,551,678 |
|
|
$76.00
- $134.98
|
|
|
$6.50
- $15.06
|
|
2011
|
|
|
360,329 |
|
|
|
1,367,249 |
|
|
$74.00
- $140.15
|
|
|
$6.50
- $14.62
|
|
2012
|
|
|
329,171 |
|
|
|
1,202,785 |
|
|
$74.00
- $141.72
|
|
|
$6.50
- $14.27
|
|
Total
|
|
|
1,640,145 |
|
|
|
6,451,939 |
|
|
|
|
|
|
|
With
respect to costless collars entered into by Whiting for which the economic
benefits and detriments were conveyed to the Trust, the Company has recorded a
non-current liability of $5.2 million, with a corresponding non-current asset of
$4.0 million recorded in other long-term assets.
The
Company has also entered into an interest rate swap designated as a fair value
hedge as further explained in the note on Long-Term Debt.
6.
|
FAIR
VALUE DISCLOSURES
|
SFAS
157—Effective January 1, 2008, the Company adopted Financial
Accounting Standards Board (“FASB”) Statement No. 157, Fair Value Measurements
(“SFAS 157”), which defines fair value, establishes a framework for
measuring fair value, establishes a fair value hierarchy based on the quality of
inputs used to measure fair value and enhances disclosure requirements for fair
value measurements. The implementation of SFAS 157 did not cause a
change in the method of calculating fair value of assets or liabilities, with
the exception of incorporating a measure of the Company’s own nonperformance
risk or that of its counterparties as appropriate, which was not
material. The primary impact from adoption was additional
disclosures.
The
Company elected to implement SFAS 157 with the one-year deferral permitted by
FASB Staff Position No. FAS 157-2, Effective Date of FASB Statement No.
157 (“FSP 157-2”), issued February 2008, which defers the effective
date of SFAS 157 for one year for certain nonfinancial assets and nonfinancial
liabilities measured at fair value, except those that are recognized or
disclosed at fair value in the financial statements on a recurring
basis. As it relates to the Company, the deferral applies to certain
nonfinancial assets and liabilities as may be acquired in a business combination
and thereby measured at fair value; impaired oil and gas property assessments;
and the initial recognition of asset retirement obligations for which fair value
is used.
Fair Value
Hierarchy—SFAS 157 establishes a three-level valuation hierarchy for
disclosure of fair value measurements. The valuation hierarchy
categorizes assets and liabilities measured at fair value into one of three
different levels depending on the observability of the inputs employed in the
measurement. The three levels are defined as follows:
·
|
Level
1: Quoted Prices in Active Markets for Identical Assets – inputs to the
valuation methodology are quoted prices (unadjusted) for identical
assets or liabilities in active
markets.
|
·
|
Level
2: Significant Other Observable Inputs – inputs to the valuation
methodology include quoted prices for similar assets and liabilities in
active markets, and inputs that are observable for the asset or liability,
either directly or indirectly, for substantially the full term of the
financial instrument.
|
·
|
Level
3: Significant Unobservable Inputs – inputs to the valuation methodology
are unobservable and significant to the fair value
measurement.
|
A
financial instrument’s categorization within the valuation hierarchy is based
upon the lowest level of input that is significant to the fair value
measurement. The Company’s assessment of the significance of a
particular input to the fair value measurement in its entirety requires judgment
and considers factors specific to the asset or liability. The
following table presents information about the Company’s financial assets and
liabilities measured at fair value on a recurring basis as of September 30,
2008, and indicates the fair value hierarchy of the valuation techniques
utilized by the Company to determine such fair value (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
long-term assets (1)
(2)
|
|
$ |
- |
|
|
$ |
4,611 |
|
|
$ |
- |
|
|
$ |
4,611 |
|
Total
|
|
$ |
- |
|
|
$ |
4,611 |
|
|
$ |
- |
|
|
$ |
4,611 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
portion of derivative liability
|
|
$ |
- |
|
|
$ |
25,046 |
|
|
$ |
- |
|
|
$ |
25,046 |
|
Long-term
derivative liability
|
|
|
- |
|
|
|
5,243 |
|
|
|
- |
|
|
|
5,243 |
|
Long-term
debt (1)
|
|
|
- |
|
|
|
636 |
|
|
|
- |
|
|
|
636 |
|
Total
|
|
$ |
- |
|
|
$ |
30,925 |
|
|
$ |
- |
|
|
$ |
30,925 |
|
_______________
(1)
|
Amount
includes $636 related to interest rate swap (see note on Long-Term
Debt).
|
(2)
|
Amount
includes $3,975 related to non-current derivative
assets.
|
The
following methods and assumptions were used to estimate the fair values of the
assets and liabilities in the table above:
Commodity Derivative
Instruments—Commodity derivative instruments consist of costless collars
for crude oil and natural gas. The Company’s costless collars are
valued based on the counterparty’s marked-to-market statements, which are
validated by observable transactions for the same or similar commodity options
using the NYMEX futures index, and are designated as Level 2 within the
valuation hierarchy. The discount rate used in the fair values of
these instruments includes a measure of nonperformance risk.
Interest Rate Swap—The
Company’s interest rate swap is valued using the counterparty’s marked-to-market
statement, which can be validated using modeling techniques that include market
inputs such as publicly available interest rate yield curves, and is designated
as Level 2 within the valuation hierarchy.
SFAS
159—In February 2007, the FASB issued Statement No. 159, The Fair Value Option for Financial
Assets and Financial Liabilities – Including an amendment of FASB Statement
No. 115 (“SFAS 159”). SFAS 159 expands the use of fair
value accounting but does not affect existing standards which require assets or
liabilities to be carried at fair value. On January 1, 2008, the
Company adopted SFAS 159 and did not elect fair value accounting for any of its
eligible items. The adoption of SFAS 159 therefore had no impact on
the Company’s consolidated financial position, cash flows or results of
operations. If the use of fair value is elected (the fair value
option), however, any upfront costs and fees related to the item must be
recognized in earnings and cannot be deferred, e.g., debt issue
costs. The fair value election is irrevocable and generally made on
an instrument-by-instrument basis, even if a company has similar instruments
that it elects not to measure based on fair value. Subsequent to the
adoption of SFAS 159, changes in fair value are recognized in
earnings.
Equity Incentive
Plan—The Company maintains the Whiting Petroleum Corporation 2003 Equity
Incentive Plan (the “Plan”), pursuant to which two million shares of the
Company’s common stock have been reserved for issuance. No employee
or officer participant may be granted options for more than 300,000 shares of
common stock, stock appreciation rights with respect to more than 300,000 shares
of common stock, or more than 150,000 shares of restricted stock during any
calendar year.
Restricted
stock awards for executive officers, directors and employees generally vest
ratably over three years. However, restricted stock awards granted to
executive officers in February 2007 and 2008 included certain performance
conditions, in addition to the standard three-year service condition, that must
be met in order for the stock awards to vest. The Company believes
that it is probable that such performance conditions will be achieved and has
accrued compensation cost accordingly for its 2007 and 2008 restricted stock
grants to executives.
The
following table shows a summary of the Company’s nonvested restricted stock as
of September 30, 2008 as well as activity during the nine months then ended
(share and per share data, not presented in thousands):
|
|
Number
of
|
|
|
Weighted
Average Grant Date Fair Value
|
|
Restricted
stock awards nonvested, January 1, 2008
|
|
|
239,656 |
|
|
$ |
44.15 |
|
Granted
|
|
|
138,518 |
|
|
$ |
58.35 |
|
Vested
|
|
|
(112,026 |
) |
|
$ |
43.43 |
|
Forfeited
|
|
|
(4,293 |
) |
|
$ |
51.00 |
|
Restricted
stock awards nonvested, September 30, 2008
|
|
|
261,855 |
|
|
$ |
51.86 |
|
The grant
date fair value of restricted stock is determined based on the closing bid price
of the Company’s common stock on the grant date. The Company uses
historical data and projections to estimate expected employee behaviors related
to restricted stock forfeitures. The expected forfeitures are then
included as part of the grant date estimate of compensation cost.
As of
September 30, 2008, there was $6.3 million of total unrecognized compensation
cost related to unvested restricted stock granted under the stock incentive
plans. That cost is expected to be recognized over a weighted average
period of 2.2 years.
Rights
Agreement—In 2006, the Board of Directors of the Company declared a
dividend of one preferred share purchase right (a “Right”) for each outstanding
share of common stock of the Company payable to the stockholders of record as of
March 2, 2006. Each Right entitles the registered holder to
purchase from the Company one one-hundredth of a share of Series A Junior
Participating Preferred Stock, par value $0.001 per share (“Preferred Shares”),
of the Company at a price of $180.00 per one one-hundredth of a Preferred Share,
subject to adjustment. If any person becomes a 15% or more
stockholder of the Company, then each Right (subject to certain limitations)
will entitle its holder to purchase, at the Right’s then current exercise price,
a number of shares of common stock of the Company or of the acquirer having a
market value at the time of twice the Right’s per share exercise
price. The Company’s Board of Directors may redeem the Rights for
$0.001 per Right at any time prior to the time when the Rights become
exercisable. Unless the Rights are redeemed, exchanged or terminated
earlier, they will expire on February 23, 2016.
8.
|
EMPLOYEE
BENEFIT PLANS
|
Production
Participation Plan—The Company has a Production Participation Plan (the
“Plan”) in which all employees participate. On an annual basis,
interests in oil and gas properties acquired, developed or sold during the year
are allocated to the Plan as determined annually by the Compensation
Committee. Once allocated, the interests (not legally conveyed) are
fixed. Interest allocations prior to 1995 consisted of 2%-3%
overriding royalty interests. Interest allocations since 1995 have
been 2%-5% of oil and gas sales less lease operating expenses and production
taxes.
Payments
of 100% of the year’s Plan interests to employees and the vested percentages of
former employees in the year’s Plan interests are made annually in cash after
year-end. Accrued compensation expense under the Plan for the nine
months ended September 30, 2008 and 2007 amounted to $30.0 million and $11.3
million, respectively, charged to general and administrative expense and $4.7
million and $1.8 million, respectively, charged to exploration
expense.
Employees
vest in the Plan ratably at 20% per year over a five year
period. Pursuant to the terms of the Plan, (1) employees who
terminate their employment with the Company are entitled to receive their vested
allocation of future Plan year payments on an annual basis; (2) employees will
become fully vested at age 62, regardless of when their interests would
otherwise vest; and (3) any forfeitures inure to the benefit of the
Company.
The
Company uses average historical prices to estimate the vested long-term
Production Participation Plan liability. At September 30, 2008, the
Company used three-year average historical NYMEX prices of $75.76 for crude oil
and $7.41 for natural gas to estimate this liability. If the Company
were to terminate the Plan or upon a change in control (as defined in the Plan),
all employees fully vest, and the Company would distribute to each Plan
participant an amount based upon the valuation method set forth in the Plan in a
lump sum payment twelve months after the date of termination or within one month
after a change in control event. Based on prices at September 30,
2008, if the Company elected to terminate the Plan or if a change of control
event occurred, it is estimated that the fully vested lump sum cash payment to
employees would approximate $188.8 million. This amount includes
$37.1 million attributable to proved undeveloped oil and gas properties and
$34.7 million relating to the short-term portion of the Plan liability, which
has been accrued as a current payable to be paid in February
2009. The ultimate sharing contribution for proved undeveloped oil
and gas properties will be awarded in the year of Plan termination or change of
control. However, the Company has no intention to terminate the
Plan.
The
following table presents changes in the estimated long-term liability related to
the Plan for the nine months ended September 30, 2008 (in
thousands):
Production
Participation Plan liability, January 1, 2008
|
|
$ |
34,042 |
|
Change
in liability for accretion, vesting and changes in
estimates
|
|
|
61,647 |
|
Reduction
in liability for cash payments accrued and recognized as compensation
expense
|
|
|
(34,683 |
) |
Production
Participation Plan liability, September 30, 2008
|
|
$ |
61,006 |
|
The
Company records the expense associated with changes in the present value of
estimated future payments under the Plan as a separate line item in the
condensed consolidated statements of income. The amount recorded is
not allocated to general and administrative expense or exploration expense
because the adjustment of the liability is associated with the future net cash
flows from the oil and gas properties rather than current period
performance. The table below presents the estimated allocation of the
change in the liability if the Company did allocate the adjustment to these
specific line items (in thousands).
|
|
Nine
Months Ended
September
30,
|
|
|
|
|
|
|
|
|
General
and administrative expense
|
|
$ |
23,297 |
|
|
$ |
5,499 |
|
Exploration
expense
|
|
|
3,667 |
|
|
|
905 |
|
Total
|
|
$ |
26,964 |
|
|
$ |
6,404 |
|
401(k)
Plan—The Company has a defined contribution retirement plan for all
employees. The plan is funded by employee contributions and
discretionary Company contributions. Employees vest in employer
contributions at 20% per year of completed service.
9.
|
RELATED
PARTY TRANSACTIONS
|
Whiting USA Trust
I—As a result of
Whiting’s retained ownership of 15.8%, or 2,186,389 units in Whiting USA Trust
I, the Trust is a related party of the Company as of September 30,
2008. The following table summarizes the related party receivable and
payable balances between the Company and the Trust as of September 30, 2008
and December 31, 2007 (in thousands):
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
Unit
distributions due from Trust (1)
|
|
$ |
2,531 |
|
|
$ |
- |
|
Non-current
derivative asset (2)
|
|
|
3,975 |
|
|
|
- |
|
Total
|
|
$ |
6,506 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
Unit
distributions payable to Trust (3)
|
|
$ |
15,603 |
|
|
$ |
- |
|
Total
|
|
$ |
15,603 |
|
|
$ |
- |
|
__________________
(1)
|
This
amount is included within Prepaid Expenses and Other in the Company’s
condensed consolidated balance
sheet.
|
(2)
|
This
amount is included within Other Long-term Assets in the Company’s
condensed consolidated balance
sheet.
|
(3)
|
This
amount primarily represents net proceeds from the Trust’s underlying
properties, that the Company has received between the last Trust
distribution date and September 30, 2008, but which the Company has not
yet distributed to the Trust as of September 30, 2008. Due to
ongoing processing of Trust revenues and expenses after September 30,
2008, the amount of Whiting’s next scheduled distribution to the Trust,
and the related distribution by the Trust to its unit holders, will differ
from this amount. This amount is included within Accrued
Liabilities in the Company’s condensed consolidated balance
sheet.
|
For the
three and nine months ended September 30, 2008, Whiting paid $21.4 million and
$36.1 million, respectively, net of state tax withholdings, in unit
distributions to the Trust and received $3.3 million and $5.6 million,
respectively, in distributions back from the Trust pursuant to its retained
ownership in 2,186,389 Trust units.
Tax Sharing
Liability—Prior to Whiting’s initial public offering in November 2003, it
was a wholly-owned indirect subsidiary of Alliant Energy Corporation (“Alliant
Energy”), a holding company whose primary businesses are utility
companies. When the transactions discussed below were entered into,
Alliant Energy was a related party of the Company. As of December 31,
2004 and thereafter, Alliant Energy was no longer a related party.
In
connection with Whiting’s initial public offering in November 2003, the Company
entered into a Tax Separation and Indemnification Agreement with Alliant
Energy. Pursuant to this agreement, the Company and Alliant Energy
made a tax election with the effect that the tax bases of Whiting’s assets were
increased to the deemed purchase price of their assets immediately prior to such
initial public offering. Whiting has adjusted deferred taxes on its
balance sheet to reflect the new tax bases of its assets. The
additional bases are expected to result in increased future income tax
deductions and, accordingly, may reduce income taxes otherwise payable by
Whiting.
Under
this agreement, the Company has agreed to pay to Alliant Energy 90% of the
future tax benefits the Company realizes annually as a result of this step-up in
tax basis for the years ending on or prior to December 31, 2013. Such
tax benefits will generally be calculated by comparing the Company’s actual
taxes to the taxes that would have been owed by the Company had the increase in
basis not occurred. In 2014, Whiting will be obligated to pay Alliant
Energy the present value of the remaining tax benefits, assuming all such tax
benefits will be realized in future years. The Company has estimated
total payments to Alliant will approximate $34.7 million on an undiscounted
basis.
During
the first nine months of 2008, the Company did not make any payments under this
agreement but did recognize $0.9 million of discount accretion, which is
included as a component of interest expense. The Company’s estimated
payment of $2.6 million to be made in 2008 under this agreement is
reflected as a current liability at September 30, 2008.
The Tax
Separation and Indemnification Agreement provides that if tax rates were to
change (increase or decrease), the tax benefit or detriment would result in a
corresponding adjustment of the tax sharing liability. For purposes
of this calculation, management has assumed that no such future changes will
occur during the term of this agreement.
The
Company periodically evaluates its estimates and assumptions as to future
payments to be made under this agreement. If non-substantial changes
(less than 10% on a present value basis) are made to the anticipated payments
owed to Alliant Energy, a new effective interest rate is determined for this
debt based on the carrying amount of the liability as of the modification date
and based on the revised payment schedule. However, if there are
substantial changes to the estimated payments owed under this agreement, then a
gain or loss is recognized in the consolidated statements of income during the
period in which the modification has been made.
Alliant Energy
Guarantee—The Company holds a 6% working interest in three offshore
platforms and related onshore plant and equipment in
California. Alliant Energy has guaranteed the Company’s obligation in
the abandonment of these assets.
10.
|
COMMITMENTS
AND CONTINGENCIES
|
Non-cancelable
Leases—The Company leases 107,400 square feet of administrative office
space in Denver, Colorado under an operating lease arrangement through October
31, 2013 and an additional 46,700 square feet of office space in Midland, Texas
through March 7, 2012. Rental expense for the first nine months of
2008 and 2007 was $1.5 million and $1.6 million,
respectively. Minimum lease payments under the terms of
non-cancelable operating leases as of September 30, 2008 are as follows (in
thousands):
2008
|
|
$ |
583 |
|
2009
|
|
|
2,520 |
|
2010
|
|
|
2,677 |
|
2011
|
|
|
3,383 |
|
2012
|
|
|
2,931 |
|
Thereafter
|
|
|
2,383 |
|
Total
|
|
$ |
14,477 |
|
Purchase
Contracts—The Company has entered into two take-or-pay purchase
agreements, one agreement expiring in March 2014 and one agreement expiring in
December 2014, whereby the Company has committed to buy certain volumes of
CO2
for a fixed fee subject to annual escalation. The purchase agreements
are with different suppliers, and the CO2 is for use
in enhanced recovery projects in the Postle field in Texas County, Oklahoma and
the North Ward Estes field in Ward County, Texas. Under the terms of
the agreements, the Company is obligated to purchase a minimum daily volume of
CO2
(as calculated on an annual basis) or else pay for any deficiencies at the price
in effect when delivery was to have occurred. The CO2 volumes
planned for use on the enhanced recovery projects in the Postle and North Ward
Estes fields currently exceed the minimum daily volumes provided in these
take-or-pay purchase agreements. Therefore, the Company expects to
avoid any payments for deficiencies. As of September 30, 2008,
future commitments under the purchase agreements amounted to $241.0 million
through 2014.
Drilling
Contracts—The
Company has one drilling rig under contract through 2008, six drilling rigs
through 2009, four drilling rigs through 2010, two drilling rigs through 2012
and one workover rig under contract through 2009, all of which are operating in
the Rocky Mountains region. As of September 30, 2008, these
agreements had total commitments of $178.0 million and early termination would
require maximum penalties of $98.4 million. Other drilling rigs
working for the Company are not under long-term contracts but instead are under
contracts that can be terminated at the end of the well that is currently being
drilled.
Litigation—The
Company is subject to litigation, claims and governmental and regulatory
proceedings arising in the ordinary course of business. It is the
opinion of the Company’s management that all claims and litigation involving the
Company are not likely to have a material adverse effect on its consolidated
financial position, cash flows or results of operations.
11.
|
RECENTLY
ISSUED ACCOUNTING PRONOUNCEMENTS
|
In March
2008, the FASB issued Statement No. 161, Disclosure about Derivative
Instruments and Hedging Activities – an amendment to FASB Statement No.
133 (“SFAS 161”). The adoption of SFAS 161 is not expected to
have an impact on the Company’s consolidated financial statements, other than
additional disclosures. SFAS 161 expands interim and annual
disclosures about derivative and hedging activities that are intended to better
convey the purpose of derivative use and the risks managed. SFAS 161
is effective for fiscal years and interim periods beginning after
November 15, 2008.
In
December 2007, the FASB issued Statement No. 160, Noncontrolling Interests in
Consolidated Financial Statements – an amendment of ARB No. 51 (“SFAS
160”). As Whiting currently does not have any minority interests, the
Company does not expect the adoption of SFAS 160 to have an impact on its
consolidated financial statements. This statement amends ARB No. 51
and intends to improve the relevance, comparability, and transparency of the
financial information that a reporting entity provides in its consolidated
financial statements by establishing accounting and reporting standards of the
portion of equity in a subsidiary not attributable, directly or indirectly, to a
parent. SFAS 160 is effective for fiscal years, and interim periods,
beginning on or after December 15, 2008.
In
December 2007, the FASB issued Statement No. 141R, Business Combinations (“SFAS
141R”). SFAS 141R may have an impact on the Company’s consolidated
financial statements when effective, but the nature and magnitude of the
specific effects will depend upon the nature, terms and size of the acquisitions
the Company consummates after the effective date. SFAS 141R
establishes principles and requirements for how the acquirer of a business
recognizes and measures in its financial statements the identifiable assets
acquired, the liabilities assumed, and any noncontrolling interest in the
acquiree. The statement also provides guidance for recognizing and
measuring the goodwill acquired in business combinations and determines what
information to disclose to enable users of the financial statement to evaluate
the nature and financial effects of the business combination. SFAS
141R is effective for financial statements issued for fiscal years beginning
after December 15, 2008.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
|
Unless
the context otherwise requires, the terms “Whiting,” “we,” “us,” “our” or “ours”
when used in this Item refer to Whiting Petroleum Corporation, together with its
consolidated subsidiaries, Whiting Oil and Gas Corporation, Equity Oil Company
and Whiting Programs, Inc. When the context requires, we refer to
these entities separately. This document contains forward-looking
statements, which give our current expectations or forecasts of future
events. Please refer to “Forward-Looking Statements” at the end of
this item for an explanation of these types of statements.
Overview
We are an
independent oil and gas company engaged in oil and gas acquisition, development,
exploitation, production and exploration activities primarily in the Permian
Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the
United States. Prior to 2006, we generally emphasized the acquisition
of properties that increased our current production levels and provided upside
potential through further development. Since 2006, we have focused
our drilling activity on the development of these acquired properties,
specifically on projects that we believe provide repeatable successes in
particular fields. Our combination of acquisitions and subsequent
development allows us to direct our capital resources to what we believe to be
the most advantageous investments.
As
demonstrated by our recent capital expenditures, we are increasingly focused on
a balanced exploration and development program while continuing to selectively
pursue acquisitions that complement our existing core properties. We
believe that our significant drilling inventory, combined with our operating
experience and cost structure, provide us with meaningful organic growth
opportunities. Our growth plan is centered on the following
activities:
|
•
|
pursuing
the development of projects that we believe will generate attractive rates
of return;
|
|
•
|
maintaining
a balanced portfolio of lower risk, long-lived oil and gas properties that
provide stable cash flows;
|
|
•
|
seeking
property acquisitions that complement our core
areas; and
|
|
•
|
allocating
an increasing percentage of our capital budget to leasing and testing new
areas.
|
We have
historically acquired operated and non-operated properties that exceed our rate
of return criteria. For acquisitions of properties with additional
development, exploitation and exploration potential, our focus has been on
acquiring operated properties so that we can better control the timing and
implementation of capital spending. In some instances, we have been
able to acquire non-operated property interests at attractive rates of return
that established a presence in a new area of interest or that have complemented
our existing operations. We intend to continue to acquire both
operated and non-operated interests to the extent we believe they meet our
return criteria. In addition, our willingness to acquire non-operated
properties in new geographic regions provides us with geophysical and geologic
data in some cases that leads to further acquisitions in the same region,
whether on an operated or non-operated basis. We sell properties when
we believe that the sales price realized will provide an above average rate of
return for the property or when the property no longer matches the profile of
properties we desire to own.
Our
revenue, profitability and future growth rate depend on factors beyond our
control, such as economic, political and regulatory developments and competition
from other sources of energy. Oil and gas prices historically have
been volatile and may fluctuate widely in the future. Sustained
periods of low prices for crude oil or natural gas could materially and
adversely affect our financial position, cash flows, results of operations,
access to capital, and the quantities of oil and gas reserves that we can
economically produce.
Crude oil
and natural gas prices have fallen significantly since their third quarter 2008
levels. Lower oil and gas prices not only decrease our revenues, but an
extended decline in oil or gas prices may materially and adversely affect our
future business, 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.
2008
Highlights and Future Considerations
On April
30, 2008, we completed an initial public offering of units of beneficial
interest in Whiting USA Trust I (the “Trust”), selling 11,677,500 Trust
units at $20.00 per Trust unit, and providing net proceeds of $215.0 million
after underwriters’ discount and commissions and offering related
expenses. Our net profits from the Trust’s underlying oil and gas
properties received between the effective date and the closing date of the Trust
unit sale were paid to the Trust and thereby further reduced net proceeds to
$193.8 million. We used the offering net proceeds to reduce the debt
outstanding under our credit agreement. The aggregate proceeds from
the sale of Trust units to the public resulted in a deferred gain on sale of
$100.1 million. Immediately prior to the closing of the offering, we
conveyed a term net profits interest in certain of our oil and natural gas
properties to the Trust in exchange for 13,863,889 Trust units. We
have retained 15.8%, or 2,186,389 Trust units, of the total Trust units issued
and outstanding.
The net
profits interest entitles the Trust to receive 90% of the net proceeds from the
sale of oil and natural gas production from the underlying
properties. The net profits interest will terminate at the time when
9.11 MMBOE have been produced and sold from the underlying
properties. This is the equivalent of 8.2 MMBOE in respect of the
Trust’s right to receive 90% of the net proceeds from such production pursuant
to the net profits interest, and these reserve quantities are projected to be
produced by December 31, 2017 based on the reserve report for the underlying
properties as of December 31, 2007. The conveyance of the net profits
interest to the Trust consisted entirely of proved developed producing reserves
of 8.2 MMBOE, as of the January 1, 2008 effective date, representing
3.3% of our proved reserves as of December 31, 2007, and 10.0% (4.2 MBOE/d)
of our March 2008 average daily net production. After netting our
ownership of 2,186,389 Trust units, third-party public Trust unit holders
receive 6.9 MMBOE of proved producing reserves, or 2.75% of our total year-end
2007 proved reserves, and 7.4% (3.1 MBOE/d) of our March 2008 average daily net
production.
On
May 30, 2008, we acquired interests in 31 producing gas wells, development
acreage and gas gathering and processing facilities on 22,029 gross acres
(11,533 net acres) in the Flat Rock field in Uintah County, Utah for an
aggregate acquisition price of $359.4 million. After allocating $79.5
million of the purchase price to unproved property, $35.7 million to the gas
gathering and processing facilities, and $7.7 million to liabilities assumed,
the remaining $251.9 million results in an acquisition cost for the proved
reserves of $2.19 per Mcfe. Of the estimated 115.2
Bcfe of proved reserves acquired as of the January 1, 2008 acquisition
effective date, 98% are natural gas, and 22% are proved developed
producing. The average daily net production from the properties was
17.8 MMcfe/d as of the acquisition effective date. We funded the
acquisition with borrowings under our credit agreement.
Our
Sanish field in Mountrail County, North Dakota encompasses 118,571 gross acres
(83,310 net acres). September 2008 net production in the Sanish field
averaged 5.9 MBOE/d, a 72% increase from 3.4 MBOE/d in June 2008. At
the end of September 2008, we were drilling or completing five operated wells in
the Sanish field with an average working interest of 86% and had five operated
rigs working in the field. We expect to have eight operated rigs
drilling in the area by year-end 2008. We have completed 18 operated
wells in the Sanish field in 2008 and expect to complete an additional 14 to 16
wells during the balance of the year.
We
completed construction of the first phase of a natural gas processing plant that
will separate the natural gas liquids (“NGLs”) from the natural gas produced
from Sanish field. In August 2008, we completed the installation of a
17-mile pipeline to transport the natural gas and natural gas liquids to a sales
point in Stanley, North Dakota. At the end of September 2008, natural
gas sales from the plant were averaging approximately 1.0 MMcf/d and net NGL
sales were averaging approximately 130 Bbl/d.
Immediately
east of the Sanish field is the Parshall field, where we own interests in 72,790
gross acres (14,982 net acres). We have participated in the drilling
and completion of 64 wells that produce from the Bakken formation, 40 of which
were completed in 2008. We expect to participate in the drilling of
an additional 20 to 30 wells in the Parshall field during 2008, with an average
working interest of 25%. Four drilling rigs are expected to be
working in the Parshall field through 2008. Our net production from
the Parshall field averaged 6.6 MBOE/d in September 2008, a 31% increase from
5.0 MBOE/d in June 2008.
We hold
interests in 2,760 gross acres (1,570 net acres) in our Boies Ranch and Jimmy
Gulch prospects in the Piceance Basin of Rio Blanco County,
Colorado. In the Piceance, we have 15 wells that had a combined net
production rate of 9.5 MMcf/d of gas during September 2008, a 56% increase from
6.1 MMcf/d in June 2008. Whiting holds an average working interest of
72% and an average net revenue interest of 63% in these gas wells. We
plan to drill a total of 185 wells in the Piceance. We also own
an average 16% working interest in a federal lease consisting of
an additional 14,133 acres in the area.
We
recently completed a pipeline at our Boies Ranch prospect, and the newly
completed line connects to a supply trunk line, which in turn feeds a treating
and processing facility that is ultimately connected to the Rockies Express
pipeline (REX). REX gives us access to multiple intrastate and
interstate markets, and our new pipeline connection will allow us to market all
of our gas at Boies Ranch without restriction. We made alternative
marketing arrangements for our Piceance Basin gas production in September 2008
to mitigate the impact of pipeline capacity reductions due to testing on a
section of the REX pipeline for most of the month.
We
continue to have significant development and related infrastructure activity on
the Postle and North Ward Estes fields acquired in 2005, which have resulted in
reserve and production increases. During the first nine months of
2008, we incurred $248.1 million of development expenditures on these two
projects.
Our
expansion of the CO2 flood at
the Postle field, located in Texas County, Oklahoma, continues to generate
positive results. Production from the field has increased 17% from a
net 5.8 MBOE/d in December 2007 to a net 6.8 MBOE/d in September
2008. This project is part of the Company’s plan to expand the
existing water and CO2 flood from
the eastern half of the Postle field to the western half of the
field.
In 2007,
we initiated our CO2 flood in
the North Ward Estes field, located in Ward and Winkler Counties,
Texas. Net production from North Ward Estes in September 2008
averaged 6.6 MBOE/d, a 31% increase from 5.1 MBOE/d in December
2007.
Results
of Operations
Nine
Months Ended September 30, 2008 Compared to Nine Months Ended September 30,
2007
Selected
Operating Data:
|
|
Nine
Months Ended
September
30,
|
|
|
|
|
|
|
|
|
Net
production:
|
|
|
|
|
|
|
Oil
(MMbbls)
|
|
|
8.7 |
|
|
|
7.1 |
|
Natural
gas (Bcf)
|
|
|
22.4 |
|
|
|
23.3 |
|
Total
production (MMBOE)
|
|
|
12.4 |
|
|
|
11.0 |
|
|
|
|
|
|
|
|
|
|
Net
sales (in millions):
|
|
|
|
|
|
|
|
|
Oil
(1)
|
|
$ |
904.1 |
|
|
$ |
414.8 |
|
Natural
gas (1)
|
|
|
198.6 |
|
|
|
143.2 |
|
Total
oil and natural gas sales
|
|
$ |
1,102.7 |
|
|
$ |
558.0 |
|
|
|
|
|
|
|
|
|
|
Average
sales prices:
|
|
|
|
|
|
|
|
|
Oil
(per Bbl)
|
|
$ |
104.21 |
|
|
$ |
58.37 |
|
Effect
of oil hedges on average price (per Bbl)
|
|
|
(13.01 |
) |
|
|
(0.29 |
) |
Oil
net of hedging (per Bbl)
|
|
$ |
91.20 |
|
|
$ |
58.08 |
|
Average
NYMEX price
|
|
$ |
113.38 |
|
|
$ |
66.12 |
|
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$ |
8.87 |
|
|
$ |
6.14 |
|
Effect
of natural gas hedges on average price (per Mcf)
|
|
|
- |
|
|
|
- |
|
Natural
gas net of hedging (per Mcf)
|
|
$ |
8.87 |
|
|
$ |
6.14 |
|
Average
NYMEX price
|
|
$ |
9.75 |
|
|
$ |
6.83 |
|
|
|
|
|
|
|
|
|
|
Cost
and expense (per BOE):
|
|
|
|
|
|
|
|
|
Lease
operating expenses
|
|
$ |
14.33 |
|
|
$ |
14.05 |
|
Production
taxes
|
|
$ |
5.80 |
|
|
$ |
3.17 |
|
Depreciation,
depletion and amortization expense
|
|
$ |
14.47 |
|
|
$ |
13.02 |
|
General
and administrative expenses
|
|
$ |
4.18 |
|
|
$ |
2.54 |
|
(1)
|
Before
consideration of hedging
transactions.
|
Oil and Natural Gas
Sales. Our oil and natural gas sales revenue increased $544.7
million to $1,102.7 million for the first nine months of 2008 compared to the
same period in 2007. Sales are a function of volumes sold and average
sales prices. Our oil sales volumes increased 22% between periods,
while our gas sales volumes decreased 4%. 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
1,680 Mbbl compared to the first nine months of 2007, while Postle oil
production increased 295 Mbbl and North Ward Estes oil production increased 90
Mbbl over the same period in 2007. These production increases were
partially offset by the Whiting USA Trust I (the “Trust”) divestiture, which
decreased oil production by 595 Mbbl. The gas volume decline between
periods was primarily the result of the Trust divestiture, which decreased gas
production in 2008 by 2,740 MMcf, and property dispositions in the second half
of 2007, which decreased gas production in 2008 by an additional 775
MMcf. These decreases were partially offset by incremental gas
production of 1,870 MMcf from the Flat Rock acquisition and higher production in
the Boies Ranch area of 995 MMcf. Our average price for oil before
effects of hedging increased 79% between periods, and our average price for
natural gas before effects of hedging increased 44%.
Loss on Oil Hedging
Activities. We hedged 39% of our oil volumes during the first
nine months of 2008, incurring cash settlement losses of $112.9 million, and 54%
of our oil volumes during the first nine months of 2007, incurring cash
settlement losses of $2.1 million. We hedged 1% of our gas volumes
during the first nine months of 2008 and 21% of our gas volumes during the same
period in 2007, incurring no cash settlement gains or losses in either
period. See Item 3, “Qualitative and Quantitative Disclosures About
Market Risk” for a list of our outstanding oil and natural gas hedges as of
October 1, 2008.
Gain on Sale of
Properties. There was no gain or loss on the sale of
properties during the nine months ended September 30, 2008. During
the nine months ended September 30, 2007, however, we sold certain non-core
properties for aggregate sales proceeds of $45.4 million, resulting in a pre-tax
gain on sale of $29.7 million.
Amortization of Deferred Gain on
Sale. On April 30, 2008, in connection with the sale of 11,677,500
Trust units to the public and related oil and gas property conveyance, we
recognized a deferred gain on sale of $100.1 million. This deferred gain
is amortized over the life of the Trust on a units-of-production
basis. For the nine months ended September 30, 2008, we
recognized $7.7 million in income as amortization of deferred gain on
sale.
Lease Operating
Expenses. Our lease operating expenses during the first nine
months of 2008 were $177.9 million, a $23.4 million (15%) increase over the same
period in 2007. Our lease operating expenses per BOE increased from
$14.05 during the first nine months of 2007 to $14.33 during the first nine
months of 2008. The increase of 2% on a BOE basis was primarily
caused by inflation in the cost of oil field goods and services and a high level
of workover activity, which factors were partially offset by flush production
from Bakken drilling. Workovers amounted to $17.8 million in the
first nine months of 2008, as compared to $11.3 million in the first nine
months of 2007.
Production
Taxes. The production taxes we pay are generally calculated as
a percentage of oil and gas sales revenue before the effects of
hedging. We take full advantage of all credits and exemptions allowed
in our various taxing jurisdictions. Our production taxes for the
first nine months of 2008 and 2007 were 6.5% and 6.3%, respectively, of oil and
gas sales. Our production tax rate for the first nine months of 2008
was greater than the rate for same period in 2007 due to the change in property
mix associated with recent divestitures in low tax rate jurisdictions and
drilling successes in higher tax rate jurisdictions.
Depreciation, Depletion and
Amortization. Our depreciation, depletion and amortization
(“DD&A”) expense increased $36.3 million as compared to the first nine
months of 2007. The components of our DD&A expense were as
follows (in thousands):
|
|
Nine
Months Ended
September
30,
|
|
|
|
|
|
|
|
|
Depletion
|
|
$ |
174,715 |
|
|
$ |
138,826 |
|
Depreciation
|
|
|
2,499 |
|
|
|
2,293 |
|
Accretion
of asset retirement obligations
|
|
|
2,341 |
|
|
|
2,095 |
|
Total
|
|
$ |
179,555 |
|
|
$ |
143,214 |
|
DD&A
increased $36.3 million primarily due to $35.9 million in higher depletion
expense between periods. Of this $35.9 million increase in depletion,
$17.8 million relates to higher oil and gas volumes produced during the first
nine months of 2008, while $18.1 million relates to our higher depletion rate in
2008. On a BOE basis, our DD&A rate increased from $13.02 for the
first nine months of 2007 to $14.47 for the first nine months of
2008. The primary factors causing this rate increase were (i) $819.9
million in drilling expenditures incurred during the past twelve months in
relation to net oil and gas reserve additions over the same time period, and
(ii) 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 $4.3
million, as compared to the first nine months of 2007. The components
of exploration and impairment costs were as follows (in thousands):
|
|
Nine
Months Ended
September
30,
|
|
|
|
|
|
|
|
|
Exploration
|
|
$ |
21,550 |
|
|
$ |
19,081 |
|
Impairment
|
|
|
9,016 |
|
|
|
7,158 |
|
Total
|
|
$ |
30,566 |
|
|
$ |
26,239 |
|
Exploration
costs increased $2.5 million during the first nine months of 2008 as compared to
the same period in 2007 primarily due to higher exploration employee
compensation costs and exploratory dry hole expense, partially offset by a
decrease in geological and geophysical (“G&G”)
activity. Exploration compensation expenses were $3.9 million higher
between periods due to an increase of $2.7 million in accrued distributions
under our Production Participation Plan for exploration personnel and due to
additional geological and geophysical employees hired during the past twelve
months. During the first nine months of 2008, we drilled one
exploratory dry hole in the Permian region totaling $1.5 million, while during
the same period in 2007 we participated in a non-operated exploratory well in
the Gulf Coast region that resulted in an insignificant amount of dry hole
expense. G&G costs amounted to $7.6 million during the first nine
months of 2008, as compared to $10.5 million during the first nine months of
2007. The impairment charge in the first nine months of 2008 and 2007
is related to the amortization of leasehold costs associated with individually
insignificant unproved properties. As of September 30, 2008, the
amount of unproved properties being amortized totaled $72.2 million, as compared
to $48.8 million as of September 30, 2007.
General and Administrative
Expenses. We report general and administrative expenses net of
third party reimbursements and internal allocations. The components
of our general and administrative expenses were as follows (in
thousands):
|
|
Nine
Months Ended
September
30,
|
|
|
|
|
|
|
General
and administrative expenses
|
|
$ |
82,411 |
|
|
$ |
52,338 |
|
Reimbursements
and allocations
|
|
|
(30,508 |
) |
|
|
(24,397 |
) |
General
and administrative expense, net
|
|
$ |
51,903 |
|
|
$ |
27,941 |
|
General
and administrative expense before reimbursements and allocations increased $30.1
million to $82.4 million during the first nine months of 2008. The
largest components of the increase related to (i) $21.5 million in higher
accrued distributions under our Production Participation Plan between periods
due to increased oil and gas sales less lease operating expense and production
taxes, and (ii) $8.1 million of additional employee compensation for personnel
hired during the past twelve months as well as general pay
increases. The increase in reimbursements and allocations in 2008 was
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 gas sales remained constant at 5% for the first nine months of 2008
and 2007.
Change in Production Participation
Plan Liability. For the nine months ended September 30, 2008,
this non-cash expense increased $20.6 million as compared to the same period in
2007. This expense represents the change in the vested present value
of estimated future payments to be made to participants after 2009 under our
Production Participation Plan (“Plan”). Although payments take place
over the life of the Plan’s oil and gas properties, which for some properties is
over 20 years, we expense the present value of estimated future payments over
the Plan’s five year vesting period. This expense in 2008 and 2007
primarily reflects (i) changes to future cash flow estimates stemming from a
sustained higher commodity price environment, (ii) recent drilling activity, and
(iii) employees’ continued vesting in the Plan. Due to the recent
higher commodity price environment, during the nine months ended September 30,
2008 we moved from using a five-year average of historical NYMEX prices to a
three-year average when estimating the future payments to be made pursuant to
this liability. The average NYMEX prices used to estimate this
liability increased by $20.95 for crude oil and $0.71 for natural gas for the
nine months ended September 30, 2008, as compared to increases of $6.09 for
crude oil and $0.53 for natural gas over the same period in
2007. Assumptions that are used to calculate this liability are
subject to estimation and will vary from year to year based on the current
market for oil and gas, discount rates and overall market
conditions.
Interest
Expense. The components of our interest expense were as
follows (in thousands):
|
|
Nine
Months Ended
September
30,
|
|
|
|
|
|
|
|
|
Credit
agreement
|
|
$ |
13,410 |
|
|
$ |
20,035 |
|
Senior
subordinated notes
|
|
|
32,698 |
|
|
|
33,571 |
|
Amortization
of debt issue costs and debt discount
|
|
|
3,618 |
|
|
|
3,793 |
|
Accretion
of tax sharing liability
|
|
|
934 |
|
|
|
1,142 |
|
Other
|
|
|
156 |
|
|
|
445 |
|
Capitalized
interest
|
|
|
(2,056 |
) |
|
|
(2,472 |
) |
Total
interest expense
|
|
$ |
48,760 |
|
|
$ |
56,514 |
|
The
decrease in interest expense was mainly due to lower effective interest rates on
our debt during the first nine months of 2008.
Our
weighted average debt outstanding during the first nine months of 2008 was
$1,002.6 million, while it was $996.1 million for the first nine months of
2007. Our weighted average effective cash interest rate was 6.2%
during the first nine months of 2008 compared to 7.2% during the first nine
months of 2007. After inclusion of non-cash interest costs related to
the amortization of debt issue costs and debt discount and the accretion of the
tax sharing liability, our weighted average effective all-in interest rate was
6.6% during the first nine months of 2008 compared to 7.7% during the first nine
months of 2007.
(Gain) Loss on Mark-to-Market
Derivatives. During 2008, we entered into derivative contracts
that we did not designate as cash flow hedges. Accordingly, these
derivative contracts are marked-to-market each quarter with fair value gains and
losses 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. As a result of increases in oil prices,
we recognized $7.0 million in unrealized mark-to-market derivative losses and
$0.04 million in realized cash settlement losses for the first nine months of
2008. During 2007, the forecasted transactions, to which certain
crude oil collars had been designated, were no longer probable of occurring
within their specified time periods. We therefore reclassified the
net loss attributable to these hedges out of accumulated other comprehensive
loss and recognized $1.2 million in unrealized mark-to-market derivative losses
during the first nine months of 2007.
Income Tax
Expense. Income tax expense totaled $148.4 million for the
first nine months of 2008 and $50.6 million for the first nine months of
2007. Our effective income tax rate decreased from 37.4% for the
first nine months 2007 to 36.8% for the first nine months of
2008. Our effective income tax rate was higher in 2007 due to
adjustments of our tax estimates to actuals based on 2006 returns as
filed.
Net Income. Net
income increased from $84.9 million during the first nine months of 2007 to
$255.2 million during the first nine months of 2008. The primary
reasons for this increase include a 13% increase in equivalent volumes sold, a
57% increase in oil prices (net of hedging) and a 44% increase in gas prices
between periods, amortization of deferred gain on sale, and lower interest
expense. These positive factors were partially offset by higher lease
operating expenses, production taxes, DD&A, exploration and impairment,
general and administrative expenses, Production Participation Plan expense,
losses on mark-to-market derivatives, income taxes as well as no gain on sale of
properties during the first nine months of 2008.
Three
Months Ended September 30, 2008 Compared to Three Months Ended September 30,
2007
Selected
Operating Data:
|
|
Three
Months Ended
September
30,
|
|
|
|
|
|
|
|
|
Net
production:
|
|
|
|
|
|
|
Oil
(MMbbls)
|
|
|
3.3 |
|
|
|
2.5 |
|
Natural
gas (Bcf)
|
|
|
8.2 |
|
|
|
7.6 |
|
Total
production (MMBOE)
|
|
|
4.6 |
|
|
|
3.7 |
|
|
|
|
|
|
|
|
|
|
Net
sales (in millions):
|
|
|
|
|
|
|
|
|
Oil
(1)
|
|
$ |
354.8 |
|
|
$ |
167.4 |
|
Natural
gas (1)
|
|
|
70.6 |
|
|
|
38.2 |
|
Total
oil and natural gas sales
|
|
$ |
425.4 |
|
|
$ |
205.6 |
|
|
|
|
|
|
|
|
|
|
Average
sales prices:
|
|
|
|
|
|
|
|
|
Oil
(per Bbl)
|
|
$ |
108.04 |
|
|
$ |
67.51 |
|
Effect
of oil hedges on average price (per Bbl)
|
|
|
(12.76 |
) |
|
|
(0.85 |
) |
Oil
net of hedging (per Bbl)
|
|
$ |
95.28 |
|
|
$ |
66.66 |
|
Average
NYMEX price
|
|
$ |
118.13 |
|
|
$ |
75.03 |
|
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$ |
8.65 |
|
|
$ |
5.06 |
|
Effect
of natural gas hedges on average price (per Mcf)
|
|
|
- |
|
|
|
- |
|
Natural
gas net of hedging (per Mcf)
|
|
$ |
8.65 |
|
|
$ |
5.06 |
|
Average
NYMEX price
|
|
$ |
10.27 |
|
|
$ |
6.16 |
|
|
|
|
|
|
|
|
|
|
Cost
and expense (per BOE):
|
|
|
|
|
|
|
|
|
Lease
operating expenses
|
|
$ |
13.93 |
|
|
$ |
14.30 |
|
Production
taxes
|
|
$ |
6.08 |
|
|
$ |
3.53 |
|
Depreciation,
depletion and amortization expense
|
|
$ |
15.99 |
|
|
$ |
13.19 |
|
General
and administrative expenses
|
|
$ |
3.72 |
|
|
$ |
2.88 |
|
(1)
|
Before
consideration of hedging
transactions.
|
Oil and Natural Gas
Sales. Our oil and natural gas sales revenue increased $219.8
million to $425.4 million in the third quarter of 2008 compared to the third
quarter of 2007. Sales are a function of volumes sold and average
sales prices. Our oil sales volumes increased 32% between periods,
while our gas sales volumes increased 8%. 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
870 Mbbl compared to the third quarter of 2007, while Postle oil production
increased 100 Mbbl and North Ward Estes oil production increased 85 Mbbl over
the same period in 2007. These production increases were partially
offset by the Trust divestiture, which decreased oil production by 220
Mbbl. The gas volume increase between periods was primarily the
result of incremental production of 1,370 MMcf added from the Flat Rock
acquisition and higher production in the Boies Ranch area of 640
MMcf. These increases were partially offset by the Trust divestiture,
which decreased gas production by 1,050 MMcf, as well as normal field production
decline. Our average price for oil before effects of hedging
increased 60% between periods, and our average price for natural gas before
effects of hedging increased 71%.
Loss on Oil Hedging
Activities. We hedged 34% of our oil volumes during the third
quarter of 2008, incurring cash settlement losses of $41.9 million, and 50% of
our oil volumes during the third quarter of 2007, incurring cash settlement
losses of $2.1 million. We hedged 2% of our gas volumes during the
third quarter of 2008, incurring no cash settlement gains or losses, and we did
not hedge any of our gas volumes during the third quarter of
2007. See Item 3, “Qualitative and Quantitative Disclosures About
Market Risk” for a list of our outstanding oil and natural gas hedges as of
October 1, 2008.
Gain on Sale of
Properties. There was no gain or loss on the sale of
properties during the three months ended September 30, 2008. During
the three months ended September 30, 2007, however, we sold certain non-core
properties for aggregate sales proceeds of $44.1 million, resulting in a pre-tax
gain on sale of $29.7 million.
Amortization of Deferred Gain on
Sale. On April 30, 2008, in connection with the sale of 11,677,500
Trust units to the public and related oil and gas property conveyance, we
recognized a deferred gain on sale of $100.1 million. This deferred gain
is amortized over the life of the Trust on a units-of-production
basis. For the three months ended September 30, 2008, we recognized
$4.7 million in income as amortization of deferred gain on sale.
Lease Operating
Expenses. Our lease operating expenses during the third
quarter of 2008 were $64.7 million, an $11.2 million (21%) increase over the
third quarter of 2007. Our lease operating expenses per BOE decreased
from $14.30 during the third quarter of 2007 to $13.93 during the third quarter
of 2008. The decrease of 3% on a BOE basis was primarily caused by
flush production from Bakken drilling, partially offset by inflation in the cost
of oil field goods and services and a higher level of workover
activity. Workovers amounted to $9.4 million in the third
quarter of 2008, as compared to $4.7 million in the third quarter of
2007.
Production
Taxes. The production taxes we pay are generally calculated as
a percentage of oil and gas sales revenue before the effects of
hedging. We take full advantage of all credits and exemptions allowed
in our various taxing jurisdictions. Our production taxes for the
third quarter of 2008 and 2007 were 6.6% and 6.4%, respectively, of oil and gas
sales. Our production tax rate for the third quarter of 2008 was
greater than the rate for same period in 2007 due to the change in property mix
associated with recent divestitures in low tax rate jurisdictions and drilling
successes in higher tax rate jurisdictions.
Depreciation, Depletion and
Amortization. Our depreciation, depletion and amortization
(“DD&A”) expense increased $24.9 million as compared to the third quarter of
2007. The components of our DD&A expense were as follows (in
thousands):
|
|
Three
Months Ended
September
30,
|
|
|
|
|
|
|
|
|
Depletion
|
|
$ |
72,464 |
|
|
$ |
47,777 |
|
Depreciation
|
|
|
905 |
|
|
|
790 |
|
Accretion
of asset retirement obligations
|
|
|
864 |
|
|
|
741 |
|
Total
|
|
$ |
74,233 |
|
|
$ |
49,308 |
|
DD&A
increased $24.9 million primarily due to $24.7 million in higher depletion
expense between periods. Of the $24.7 million increase in depletion,
$11.6 million is related to higher oil and gas volumes produced during the third
quarter of 2008, while $13.1 million relates to our higher depletion rate in
2008. On a BOE basis, our DD&A rate increased from $13.19 for the
third quarter of 2007 to $15.99 for the third quarter of 2008. The
primary factors causing this rate increase were (i) $819.9 million in drilling
expenditures incurred during the past twelve months in relation to net oil and
gas reserve additions over the same time period, and (ii) 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 $0.5
million, as compared to the third quarter of 2007. The components of
exploration and impairment costs were as follows (in thousands):
|
|
Three
Months Ended
September
30,
|
|
|
|
|
|
|
|
|
Exploration
|
|
$ |
7,323 |
|
|
$ |
7,903 |
|
Impairment
|
|
|
3,616 |
|
|
|
2,517 |
|
Total
|
|
$ |
10,939 |
|
|
$ |
10,420 |
|
Exploration
costs decreased $0.6 million for the third quarter of 2008 as compared to the
same period in 2007 primarily due to a decrease in G&G activity between
periods, partially offset by higher exploratory dry hole expense and exploration
employee compensation costs. G&G costs amounted to $1.8 million
during the three months ended September 30, 2008, as compared to $5.0 million
during the same three months of 2007. During the third quarter of
2008, we drilled one exploratory dry hole in the Permian region totaling $1.5
million, while during the same period in 2007 we participated in a non-operated
exploratory well in the Gulf Coast region that resulted in an insignificant
amount of dry hole expense. Exploration compensation expenses were
higher primarily due to an increase of $0.5 million in accrued distributions
under our Production Participation Plan for exploration personnel and due to
additional geological and geophysical employees hired during the past twelve
months. The impairment charge in the third quarter of 2008 and 2007
is related to the amortization of leasehold costs associated with individually
insignificant unproved properties. As of September 30, 2008, the
amount of unproved properties being amortized totaled $72.2 million, as compared
to $48.8 million as of September 30, 2007.
General and Administrative
Expenses. We report general and administrative expenses net of
third party reimbursements and internal allocations. The components
of our general and administrative expenses were as follows (in
thousands):
|
|
Three
Months Ended
September
30,
|
|
|
|
|
|
|
General
and administrative expenses
|
|
$ |
28,096 |
|
|
$ |
19,341 |
|
Reimbursements
and allocations
|
|
|
(10,815 |
) |
|
|
(8,561 |
) |
General
and administrative expense, net
|
|
$ |
17,281 |
|
|
$ |
10,780 |
|
General
and administrative expense before reimbursements and allocations increased $8.8
million to $28.1 million during the third quarter of 2008. The
largest components of the increase related to (i) $4.6 million in higher accrued
distributions under our Production Participation Plan between periods due to
increased oil and gas sales less lease operating expense and production taxes,
and (ii) $3.6 million of additional employee compensation for personnel hired
during the past twelve months as well as general pay increases. The
increase in reimbursements and allocations in 2008 was 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 gas sales decreased from 5% for the third quarter of 2007 to 4% for
the third quarter of 2008.
Change in Production Participation
Plan Liability. For the three months ended September 30, 2008,
this non-cash expense increased $6.9 million to $9.1 million, as compared to the
same period in 2007. This expense represents the change in the vested
present value of estimated future payments to be made to participants after 2009
under our Production Participation Plan (“Plan”). Although payments
take place over the life of the Plan’s oil and gas properties, which for some
properties is over 20 years, we expense the present value of estimated future
payments over the Plan’s five year vesting period. This expense in
2008 and 2007 primarily reflects (i) changes to future cash flow estimates
stemming from a sustained higher commodity price environment, (ii) recent
drilling activity, and (iii) employees’ continued vesting in the
Plan. Due to the recent higher commodity price environment, during
the second quarter of 2008 we moved from using a five-year average of historical
NYMEX prices to a three-year average when estimating the future payments to be
made pursuant to this liability. The average NYMEX prices used to
estimate this liability increased by $5.44 for crude oil and decreased by $0.03
for natural gas for the three months ended September 30, 2008, as compared to
increases of $2.32 for crude oil and $0.15 for natural gas over the same period
in 2007. Assumptions that are used to calculate this liability are
subject to estimation and will vary from year to year based on the current
market for oil and gas, discount rates and overall market
conditions.
Interest
Expense. The components of our interest expense were as
follows (in thousands):
|
|
Three
Months Ended
September
30,
|
|
|
|
|
|
|
|
|
Credit
agreement
|
|
$ |
5,757 |
|
|
$ |
4,595 |
|
Senior
subordinated notes
|
|
|
10,755 |
|
|
|
11,199 |
|
Amortization
of debt issue costs and debt discount
|
|
|
1,195 |
|
|
|
1,251 |
|
Accretion
of tax sharing liability
|
|
|
311 |
|
|
|
381 |
|
Other
|
|
|
47 |
|
|
|
245 |
|
Capitalized
interest
|
|
|
(522 |
) |
|
|
(1,408 |
) |
Total
interest expense
|
|
$ |
17,543 |
|
|
$ |
16,263 |
|
The
increase in interest expense was mainly due to higher borrowings under our
credit agreement, partially offset by lower effective interest rates on our debt
during the third quarter of 2008.
Our
weighted average debt outstanding during the third quarter of 2008 was $1,147.6
million, while it was $868.8 million for the third quarter of
2007. Our weighted average effective cash interest rate was 5.8%
during the third quarter of 2008 compared to 7.4% during the third quarter of
2007. After inclusion of non-cash interest costs related to the
amortization of debt issue costs and debt discount and the accretion of the tax
sharing liability, our weighted average effective all-in interest rate was 6.2%
during the third quarter of 2008 compared to 7.9% during the third quarter of
2007.
(Gain) Loss on Mark-to-Market
Derivatives. During 2008, we entered into derivative contracts
that we did not designate as cash flow hedges. Accordingly, these
derivative contracts are marked-to-market each quarter with fair value gains and
losses 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. As a result of decreases in oil prices
during the quarter, we recognized $10.6 million in unrealized mark-to-market
derivative gains and $0.03 million in realized cash settlement losses in the
third quarter of 2008. During 2007, the forecasted transactions, to
which certain crude oil collars had been designated, were no longer probable of
occurring within their specified time periods. Therefore, we
discontinued hedge accounting prospectively for these collars and recognized
$0.5 million in unrealized mark-to-market derivative gains during the third
quarter of 2007.
Income Tax
Expense. Income tax expense totaled $64.5 million for the
third quarter of 2008 and $29.6 million for the third quarter of
2007. Our effective income tax rate decreased from 38.3% for the
third quarter 2007 to 36.5% for the third quarter of 2008. Our
effective income tax rate was higher in 2007 due to adjustments of our tax
estimates to actuals based on 2006 returns as filed.
Net Income. Net
income increased from $47.7 million during the third quarter of 2007 to $112.4
million during the third quarter of 2008. The primary reasons for
this increase include a 24% increase in equivalent volumes sold, a 43% increase
in oil prices (net of hedging) and a 71% increase in gas prices between periods,
amortization of deferred gain on sale and unrealized mark-to-market derivative
gains. These positive factors were partially offset by higher lease
operating expenses, production taxes, DD&A, exploration and impairment,
general and administrative expenses, Production Participation Plan expense,
interest expense, income taxes as well as no gain on sale of properties during
the third quarter of 2008.
Liquidity
and Capital Resources
Overview. At
September 30, 2008, our debt to total capitalization ratio was 38.6%, we had
$20.6 million of cash on hand and $1,779.4 million of stockholders’
equity. At December 31, 2007, our debt to total capitalization
ratio was 36.8%, we had $14.8 million of cash on hand and $1,490.8 million of
stockholders’ equity. In the first nine months of 2008, we generated
$611.5 million of cash provided by operating activities, an increase of $338.8
million over the same period in 2007. Cash provided by operating
activities increased primarily because of higher oil volumes produced in 2008
and higher average sales prices for both crude oil and natural
gas. We also generated $250.0 million from financing activities
consisting entirely of net borrowings against our credit
agreement. Cash flows from operating and financing activities, as
well as $193.8 million in net proceeds from the sale of Trust units, were used
to finance $638.4 million of drilling and development expenditures paid in the
first nine months of 2008 and $413.2 million of cash acquisition capital
expenditures. The following chart details our exploration and
development expenditures incurred by region during the first nine months of 2008
(in thousands):
|
|
Drilling
and Development Expenditures
|
|
|
|
|
|
|
|
|
|
|
Rocky
Mountains
|
|
$ |
335,174 |
|
|
$ |
5,389 |
|
|
$ |
340,563 |
|
|
|
50 |
% |
Permian
Basin
|
|
|
206,216 |
|
|
|
7,182 |
|
|
|
213,398 |
|
|
|
31 |
% |
Mid-Continent
|
|
|
77,775 |
|
|
|
1,582 |
|
|
|
79,357 |
|
|
|
12 |
% |
Gulf
Coast
|
|
|
31,377 |
|
|
|
420 |
|
|
|
31,797 |
|
|
|
5 |
% |
Michigan
|
|
|
11,710 |
|
|
|
6,977 |
|
|
|
18,687 |
|
|
|
2 |
% |
Total incurred
|
|
|
662,252 |
|
|
|
21,550 |
|
|
|
683,802 |
|
|
|
100 |
% |
Increase
in accrued capital expenditures
|
|
|
(23,852 |
) |
|
|
- |
|
|
|
(23,852 |
) |
|
|
|
|
Total paid
|
|
$ |
638,400 |
|
|
$ |
21,550 |
|
|
$ |
659,950 |
|
|
|
|
|
We
continually evaluate our capital needs and compare them to our capital
resources. Our current 2008 budgeted capital expenditures for the
further development of our property base are $900.0 million, an increase from
the $556.6 million incurred on exploration and development expenditures
during 2007. We increased our 2008 exploration and development budget
from $850.0 million to $900.0 million due primarily to additional exploration
and development activities across our regions. In the first nine
months of 2008, we spent $31.8 million on tubulars (casing, tubing and flow
lines) and $381.4 million on oil and gas property acquisitions, including
the Flat Rock acquisition of $359.4 million which was funded by borrowings under
Whiting Oil and Gas Corporation’s (“Whiting Oil and Gas”) credit
agreement. Although we have no specific budget for property
acquisitions in 2008, we will continue to selectively pursue property
acquisitions that complement our existing core property base. We
expect to fund our 2008 exploration and development expenditures from internally
generated cash flow, cash on hand, and borrowings under our credit
agreement. We believe that should attractive acquisition
opportunities arise or exploration and development expenditures exceed $900.0
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. However,
we recognize that the issuance of additional securities in periods of market
volatility may be less likely. 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. Although we have not yet
formally determined our 2009 exploration and development budget, we expect to
set this budget at an amount that approximates estimated discretionary cash flow
generated during 2009.
Credit
Agreement. Whiting Oil and Gas, our wholly-owned subsidiary,
has a $1.2 billion credit agreement with a syndicate of banks that, as of
September 30, 2008, had a borrowing base of $900.0 million with $397.3 million
of available borrowing capacity, which is net of $500.0 million in borrowings
and $2.7 million in letters of credit outstanding. The borrowing base
under the credit agreement is determined at the discretion of our lenders, based
on the collateral value of our proved reserves that have been mortgaged to our
lenders and is subject to regular redeterminations on May 1 and November 1 of
each year, as well as special redeterminations described in the credit
agreement.
The credit agreement provides for
interest only payments until August 31, 2010, when the entire amount
borrowed is due. Whiting Oil and Gas may, throughout the term of the
credit agreement, borrow, repay and re-borrow up to the borrowing base in effect
at any given time. The lenders under the credit agreement have also
committed to issue letters of credit for the account of Whiting Oil and Gas or
other designated subsidiaries of ours in an aggregate amount not to exceed
$50.0 million. As of September 30, 2008, $47.3 million was
available for additional letters of credit under the agreement.
Interest
accrues at Whiting Oil and Gas’ option at either (1) the base rate plus a
margin, where the base rate is defined as the higher of the prime rate or the
federal funds rate plus 0.5% and the margin varies from 0% to 0.5% depending on
the utilization percentage of the borrowing base, or (2) at the LIBOR rate
plus a margin, where the margin varies from 1.00% to 1.75% depending on the
utilization percentage of the borrowing base. Commitment fees of
0.25% to 0.375% accrue on the unused portion of the borrowing base, depending on
the utilization percentage and are included as a component of interest
expense. At September 30, 2008, the effective weighted average
interest rate on the outstanding principal balance under the credit agreement
was 3.9%.
The
credit agreement contains restrictive covenants that may limit our ability to,
among other things, pay cash dividends, incur additional indebtedness, sell
assets, make loans to others, make investments, enter into mergers, enter into
hedging contracts, change material agreements, incur liens and engage in certain
other transactions without the prior consent of the lenders and requires us to
maintain a debt to EBITDAX ratio (as defined in the credit agreement) of less
than 3.5 to 1 and a working capital ratio (as defined in the credit agreement
and which includes an add back of the available borrowing capacity under the
credit facility) of greater than 1 to 1. Except for limited
exceptions, including the payment of interest on the senior notes, the credit
agreement restricts the ability of Whiting Oil and Gas and our wholly-owned
subsidiary, Equity Oil Company, to make any dividends, distributions or other
payments to Whiting Petroleum Corporation. The restrictions apply to
all of the net assets of these subsidiaries. We were in compliance
with our covenants under the credit agreement as of September 30,
2008. The credit agreement is secured by a first lien on all of
Whiting Oil and Gas’ properties included in the borrowing base for the credit
agreement. Whiting Petroleum Corporation and Equity Oil Company have
guaranteed the obligations of Whiting Oil and Gas under the credit
agreement. Whiting Petroleum Corporation has pledged the stock of
Whiting Oil and Gas and Equity Oil Company as security for the guarantee, and
Equity Oil Company has mortgaged all of its properties, which are included in
the borrowing base for the credit agreement, as security for its
guarantee.
Senior Subordinated
Notes. In October 2005, we issued at par
$250.0 million of 7% Senior Subordinated Notes due 2014.
In
April 2005, we issued $220.0 million of 7.25% Senior Subordinated Notes due
2013. These notes were issued at 98.507% of par, and the associated
discount is being amortized to interest expense over the term of these
notes.
In
May 2004, we issued $150.0 million of 7.25% Senior Subordinated Notes
due 2012. These notes were issued at 99.26% of par, and the
associated discount is being amortized to interest expense over the term of
these notes.
The notes
are unsecured obligations of ours and are subordinated to all of our senior
debt, which currently consists of Whiting Oil and Gas’ credit
agreement. The indentures governing the notes contain restrictive
covenants that may limit our ability to, among other things, pay cash dividends,
redeem or repurchase our capital stock or our subordinated debt, make
investments, incur additional indebtedness or issue preferred stock, sell
assets, consolidate, merge or transfer all or substantially all of the assets of
ours and our restricted subsidiaries taken as a whole and enter into hedging
contracts. These covenants may potentially limit the discretion of
our management in certain respects. We were in compliance with these
covenants as of September 30, 2008. Our wholly-owned operating
subsidiaries, Whiting Oil and Gas Corporation, Whiting Programs, Inc. and Equity
Oil Company, have fully, unconditionally, jointly and severally guaranteed our
obligations under the notes.
Shelf Registration
Statement. We have on file with the SEC a universal shelf
registration statement to allow us to offer an indeterminate amount of
securities in the future. Under the registration statement, we may
periodically offer from time to time debt securities, common stock, preferred
stock, warrants and other securities or any combination of such securities in
amounts, prices and on terms announced when and if the securities are
offered. However,
we recognize that the issuance of additional securities in periods of market
volatility may be less likely. The specifics of any future
offerings, along with the use of proceeds of any securities offered, will be
described in detail in a prospectus supplement at the time of any such
offering.
Schedule of Contractual
Obligations. The table below does not include our Production
Participation Plan liabilities since we cannot determine with accuracy the
timing or amounts of future payments. The following table summarizes
our obligations and commitments as of September 30, 2008 to make future payments
under certain contracts, aggregated by category of contractual obligation, for
specified time periods (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt (a)
|
|
$ |
1,120,000 |
|
|
$ |
- |
|
|
$ |
500,000 |
|
|
$ |
370,000 |
|
|
$ |
250,000 |
|
Cash
interest expense on debt (b)
|
|
|
251,919 |
|
|
|
62,586 |
|
|
|
103,830 |
|
|
|
66,545 |
|
|
|
18,958 |
|
Asset
retirement obligation (c)
|
|
|
43,684 |
|
|
|
1,430 |
|
|
|
716 |
|
|
|
3,561 |
|
|
|
37,977 |
|
Tax
sharing liability (d)
|
|
|
26,591 |
|
|
|
2,587 |
|
|
|
4,408 |
|
|
|
3,699 |
|
|
|
15,897 |
|
Derivative
contract liability fair value (e)
|
|
|
30,289 |
|
|
|
25,046 |
|
|
|
3,279 |
|
|
|
1,964 |
|
|
|
- |
|
Purchasing
obligations (f)
|
|
|
240,978 |
|
|
|
43,941 |
|
|
|
97,454 |
|
|
|
80,724 |
|
|
|
18,859 |
|
Drilling
rig contracts (g)
|
|
|
177,953 |
|
|
|
82,172 |
|
|
|
82,218 |
|
|
|
13,563 |
|
|
|
- |
|
Operating
leases (h)
|
|
|
14,477 |
|
|
|
2,472 |
|
|
|
5,837 |
|
|
|
5,929 |
|
|
|
239 |
|
Total
|
|
$ |
1,905,891 |
|
|
$ |
220,234 |
|
|
$ |
797,742 |
|
|
$ |
545,985 |
|
|
$ |
341,930 |
|
________________
(a)
|
Long-term
debt consists of the 7.25% Senior Subordinated Notes due 2012 and 2013,
the 7% Senior Subordinated Notes due 2014 and the outstanding borrowings
under our credit agreement, and assumes no principal repayment until the
due date of the instruments.
|
(b)
|
Cash
interest expense on the 7.25% Senior Subordinated Notes due 2012 and 2013
and the 7% Senior Subordinated Notes due 2014 is estimated assuming no
principal repayment until the due date of the instruments. The
interest rate swap on the $75.0 million of our $150.0 million
fixed rate 7.25% Senior Subordinated Notes due 2012 is assumed to equal
5.3% until the due date of the instrument. Cash interest
expense on the credit agreement is estimated assuming no principal
repayment until the instrument due date and is estimated at a fixed
interest rate of 3.9%.
|
(c)
|
Asset
retirement obligations represent the present value of estimated amounts
expected to be incurred in the future to plug and abandon oil and gas
wells, remediate oil and gas properties and dismantle their related
facilities.
|
(d)
|
Amounts
shown represent the present value of estimated payments due to Alliant
Energy based on projected future income tax benefits attributable to an
increase in our tax bases. As a result of the Tax Separation
and Indemnification Agreement signed with Alliant Energy, the increased
tax bases are expected to result in increased future income tax deductions
and, accordingly, may reduce income taxes otherwise payable by
us. Under this agreement, we have agreed to pay Alliant Energy
90% of the future tax benefits we realize annually as a result of this
step up in tax basis for the years ending on or prior to December 31,
2013. In 2014, we will be obligated to pay Alliant Energy the
present value of the remaining tax benefits assuming all such tax benefits
will be realized in future years.
|
(e)
|
We
have entered into derivative contracts in the form of costless collars to
hedge our exposure to crude oil and natural gas price
fluctuations. As of September 30, 2008, the forward price
curves for crude oil generally exceeded the price curves that were in
effect when these contracts were entered into, resulting in a derivative
fair value liability. If current market prices are higher than
a collar’s price ceiling when the cash settlement amount is calculated, we
are required to pay the contract counterparties. The ultimate
settlement amounts under our derivative contracts are unknown, however, as
they are subject to continuing market
risk.
|
(f)
|
We
have two take-or-pay purchase agreements, one agreement expiring in March
2014 and one agreement expiring in December 2014, whereby we have
committed to buy certain volumes of CO2 for
a fixed fee, subject to annual escalation, for use in enhanced recovery
projects in our Postle field in Oklahoma and our North Ward Estes field in
Texas. The purchase agreements are with different
suppliers. Under the terms of the agreements, we are obligated
to purchase a minimum daily volume of CO2 (as
calculated on an annual basis) or else pay for any deficiencies at the
price in effect when the minimum delivery was to have
occurred. The CO2
volumes planned for use on the enhanced recovery projects in the Postle
and North Ward Estes fields currently exceed the minimum daily volumes
provided in these take-or-pay purchase agreements. Therefore,
we expect to avoid any payments for
deficiencies.
|
(g)
|
We
currently have one drilling rig under contract through 2008, six drilling
rigs through 2009, four drilling rigs through 2010, two drilling rigs
through 2012 and one workover rig under contract through 2009, all of
which are operating in the Rocky Mountains region. As of
September 30, 2008, early termination of these contracts would have
required maximum penalties of $98.4 million. No other drilling
rigs working for us are currently under long-term contracts or contracts
that cannot be terminated at the end of the well that is currently being
drilled. Due to the short-term and indeterminate nature of the
drilling time remaining on rigs drilling on a well-by-well basis, such
obligations have not been included in this
table.
|
(h)
|
We
lease 107,400 square feet of administrative office space in Denver,
Colorado under an operating lease arrangement through October 31,
2013, and an additional 46,700 square feet of office space in Midland,
Texas through March 7, 2012.
|
Based on
current oil and gas prices and anticipated levels of production, we believe that
the estimated net cash generated from operations, together with cash on hand and
amounts available under our credit agreement, will be adequate to meet future
liquidity needs, including satisfying our financial obligations and funding our
operations and exploration and development activities.
New
Accounting Pronouncements
In March
2008, the FASB issued Statement No. 161, Disclosure about Derivative
Instruments and Hedging Activities – an amendment to FASB Statement No.
133 (“SFAS 161”). The adoption of SFAS 161 is not expected to
have an impact on our consolidated financial statements, other than additional
disclosures. SFAS 161 expands interim and annual disclosures about
derivative and hedging activities that are intended to better convey the purpose
of derivative use and the risks managed. SFAS 161 is effective for
fiscal years and interim periods beginning after November 15, 2008.
In
December 2007, the FASB issued Statement No. 160, Noncontrolling Interests in
Consolidated Financial Statements – an amendment of ARB No. 51 (“SFAS
160”). As we currently do not have any minority interests, we do not
expect the adoption of SFAS 160 to have an impact on our consolidated financial
statements. This statement amends ARB No. 51 and intends to improve
the relevance, comparability, and transparency of the financial information that
a reporting entity provides in its consolidated financial statements by
establishing accounting and reporting standards of the portion of equity in a
subsidiary not attributable, directly or indirectly, to a
parent. SFAS 160 is effective for fiscal years, and interim periods,
beginning on or after December 15, 2008.
In
December 2007, the FASB issued Statement No. 141R, Business Combinations (“SFAS
141R”). SFAS 141R may have an impact on our consolidated financial
statements when effective, but the nature and magnitude of the specific effects
will depend upon the nature, terms and size of the acquisitions we consummate
after the effective date. SFAS 141R establishes principles and
requirements for how the acquirer of a business recognizes and measures in its
financial statements the identifiable assets acquired, the liabilities assumed,
and any noncontrolling interest in the acquiree. The statement also
provides guidance for recognizing and measuring the goodwill acquired in
business combinations and determines what information to disclose to enable
users of the financial statement to evaluate the nature and financial effects of
the business combination. SFAS 141R is effective for financial
statements issued for fiscal years beginning after December 15,
2008.
Critical
Accounting Policies and Estimates
Information
regarding critical accounting policies and estimates is contained in Item 7
of our Annual Report on Form 10-K for the fiscal year ended December 31,
2007.
Effects
of Inflation and Pricing
We
experienced increased costs during 2007 and the first nine months of 2008 due to
increased demand for oil field products and services. The oil and gas
industry is very cyclical and the demand for goods and services of oil field
companies, suppliers and others associated with the industry put extreme
pressure on the economic stability and pricing structure within the
industry. Typically, as prices for oil and gas increase, so do all
associated costs. Conversely, in a period of declining prices,
associated cost declines are likely to lag and may not adjust downward in
proportion. Material changes in prices also impact the current
revenue stream, estimates of future reserves, borrowing base calculations of
bank loans and values of properties in purchase and sale
transactions. Material changes in prices can impact the value of oil
and gas companies and their ability to raise capital, borrow money and retain
personnel. While we do not currently expect business costs to
materially increase, higher prices for oil and gas could result in increases in
the costs of materials, services and personnel.
Forward-Looking
Statements
This
report contains statements that we believe to be “forward-looking statements”
within the meaning of the Private Securities Litigation Reform Act of
1995. All statements other than historical facts, including, without
limitation, statements regarding our future financial position, business
strategy, projected revenues, earnings, costs, capital expenditures and debt
levels, and plans and objectives of management for future operations, are
forward-looking statements. When used in this report, words such as
we “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe” or “should”
or the negative thereof or variations thereon or similar terminology are
generally intended to identify forward-looking statements. Such
forward-looking statements are subject to risks and uncertainties that could
cause actual results to differ materially from those expressed in, or implied
by, such statements.
These
risks and uncertainties include, but are not limited to: declines in
oil or gas prices; our level of success in exploitation, exploration,
development and production activities; adverse weather conditions that may
negatively impact development or production activities; the timing of our
exploration and development expenditures, including our ability to obtain
drilling rigs and CO2; our
ability to obtain external capital to finance acquisitions; our ability to
identify and complete acquisitions, and to successfully integrate acquired
businesses; unforeseen underperformance of or liabilities associated with
acquired properties; our ability to successfully complete potential asset
dispositions; inaccuracies of our reserve estimates or our assumptions
underlying them; failure of our properties to yield oil or gas in commercially
viable quantities; uninsured or underinsured losses resulting from our oil and
gas operations; our inability to access oil and gas markets due to market
conditions or operational impediments; the impact and costs of compliance with
laws and regulations governing our oil and gas operations; risks related to our
level of indebtedness and periodic redeterminations of our borrowing base under
our credit agreement; our ability to replace our oil and gas reserves; any loss
of our senior management or technical personnel; competition in the oil and gas
industry in the regions in which we operate; risks arising out of our hedging
transactions; and other risks described under the caption “Risk Factors” in our
Annual Report on Form 10-K for the fiscal year ended December 31,
2007. We assume no obligation, and disclaim any duty, to update the
forward-looking statements in this report.
|
Quantitative and
Qualitative Disclosures about Market
Risk
|
Our
quantitative and qualitative disclosures about market risk for changes in
commodity prices and interest rates are included in Item 7A of our Annual Report
on Form 10-K for the fiscal year ended December 31, 2007 and have not
materially changed since that report was filed.
Our
outstanding hedges as of October 1, 2008 are summarized below:
Whiting
Petroleum Corporation
|
|
Monthly
Volume
(Bbl)/(MMBtu)
|
|
Crude
Oil
|
10/2008
to 12/2008
|
110,000
|
$48.00/$70.20
|
Crude
Oil
|
10/2008
to 12/2008
|
120,000
|
$60.00/$75.85
|
Crude
Oil
|
10/2008
to 12/2008
|
100,000
|
$65.00/$81.20
|
In
connection with our conveyance on April 30, 2008 of a term net profits interest
to Whiting USA Trust I (as further explained above in 2008 Highlights and Future
Considerations and in the note on Acquisitions and Divestitures), the rights to
any future hedge payments we make or receive on certain of our derivative
contracts, representing 2,164 Mbbls of crude oil and 8,512 MMcf of natural gas
from 2008 through 2012, have been conveyed to the Trust, and therefore such
payments will be included in the Trust’s calculation of net proceeds. Under the
Trust, we retain 10% of the net proceeds from the underlying
properties. Our retention of 10% of these net proceeds combined with
our ownership of 2,186,389 Trust units, results in third-party public holders of
Trust units receiving 75.8%, while we retain 24.2%, of future economic results
of such hedges. No additional hedges are allowed to be placed on
Trust assets.
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)
|
|
Crude
Oil
|
10/2008
to 12/2008
|
25,718
|
$82.00/$128.30
|
Crude
Oil
|
10/2008
to 12/2008
|
25,718
|
$82.00/$134.85
|
Crude
Oil
|
01/2009
to 03/2009
|
25,059
|
$76.00/$136.70
|
Crude
Oil
|
01/2009
to 03/2009
|
25,059
|
$76.00/$142.99
|
Crude
Oil
|
04/2009
to 06/2009
|
24,397
|
$76.00/$134.70
|
Crude
Oil
|
04/2009
to 06/2009
|
24,397
|
$76.00/$140.39
|
Crude
Oil
|
07/2009
to 09/2009
|
23,755
|
$76.00/$133.70
|
Crude
Oil
|
07/2009
to 09/2009
|
23,755
|
$76.00/$139.12
|
Crude
Oil
|
10/2009
to 12/2009
|
23,120
|
$76.00/$132.90
|
Crude
Oil
|
10/2009
to 12/2009
|
23,120
|
$76.00/$138.54
|
Crude
Oil
|
01/2010
to 03/2010
|
22,542
|
$76.00/$132.35
|
Crude
Oil
|
01/2010
to 03/2010
|
22,542
|
$76.00/$137.82
|
Crude
Oil
|
04/2010
to 06/2010
|
21,989
|
$76.00/$132.10
|
Crude
Oil
|
04/2010
to 06/2010
|
21,989
|
$76.00/$137.60
|
Crude
Oil
|
07/2010
to 09/2010
|
21,483
|
$76.00/$131.90
|
Commodity |
Period |
Monthly
Volume
(Bbl)/(MMBtu)
|
NYMEX Floor/Ceiling |
Crude
Oil
|
07/2010
to 09/2010
|
21,483
|
$76.00/$137.88
|
Crude
Oil
|
10/2010
to 12/2010
|
20,962
|
$76.00/$131.90
|
Crude
Oil
|
10/2010
to 12/2010
|
20,962
|
$76.00/$138.32
|
Crude
Oil
|
01/2011
to 03/2011
|
20,489
|
$74.00/$136.00
|
Crude
Oil
|
01/2011
to 03/2011
|
20,489
|
$74.00/$143.35
|
Crude
Oil
|
04/2011
to 06/2011
|
20,033
|
$74.00/$136.20
|
Crude
Oil
|
04/2011
to 06/2011
|
20,033
|
$74.00/$143.95
|
Crude
Oil
|
07/2011
to 09/2011
|
19,585
|
$74.00/$136.10
|
Crude
Oil
|
07/2011
to 09/2011
|
19,585
|
$74.00/$144.19
|
Crude
Oil
|
10/2011
to 12/2011
|
19,121
|
$74.00/$136.55
|
Crude
Oil
|
10/2011
to 12/2011
|
19,121
|
$74.00/$144.94
|
Crude
Oil
|
01/2012
to 03/2012
|
18,706
|
$74.00/$136.95
|
Crude
Oil
|
01/2012
to 03/2012
|
18,706
|
$74.00/$145.59
|
Crude
Oil
|
04/2012
to 06/2012
|
18,286
|
$74.00/$137.30
|
Crude
Oil
|
04/2012
to 06/2012
|
18,286
|
$74.00/$146.15
|
Crude
Oil
|
07/2012
to 09/2012
|
17,871
|
$74.00/$137.30
|
Crude
Oil
|
07/2012
to 09/2012
|
17,871
|
$74.00/$146.09
|
Crude
Oil
|
10/2012
to 12/2012
|
17,514
|
$74.00/$137.80
|
Crude
Oil
|
10/2012
to 12/2012
|
17,514
|
$74.00/$146.62
|
Natural
Gas
|
10/2008
to 12/2008
|
228,830
|
$7.00/$19.00
|
Natural
Gas
|
01/2009
to 03/2009
|
216,333
|
$7.00/$22.50
|
Natural
Gas
|
04/2009
to 06/2009
|
201,263
|
$6.00/$14.85
|
Natural
Gas
|
07/2009
to 09/2009
|
192,870
|
$6.00/$15.60
|
Natural
Gas
|
10/2009
to 12/2009
|
185,430
|
$7.00/$14.85
|
Natural
Gas
|
01/2010
to 03/2010
|
178,903
|
$7.00/$18.65
|
Natural
Gas
|
04/2010
to 06/2010
|
172,873
|
$6.00/$13.20
|
Natural
Gas
|
07/2010
to 09/2010
|
167,583
|
$6.00/$14.00
|
Natural
Gas
|
10/2010
to 12/2010
|
162,997
|
$7.00/$14.20
|
Natural
Gas
|
01/2011
to 03/2011
|
157,600
|
$7.00/$17.40
|
Natural
Gas
|
04/2011
to 06/2011
|
152,703
|
$6.00/$13.05
|
Natural
Gas
|
07/2011
to 09/2011
|
148,163
|
$6.00/$13.65
|
Natural
Gas
|
10/2011
to 12/2011
|
142,787
|
$7.00/$14.25
|
Natural
Gas
|
01/2012
to 03/2012
|
137,940
|
$7.00/$15.55
|
Natural
Gas
|
04/2012
to 06/2012
|
134,203
|
$6.00/$13.60
|
Natural
Gas
|
07/2012
to 09/2012
|
130,173
|
$6.00/$14.45
|
Natural
Gas
|
10/2012
to 12/2012
|
126,613
|
$7.00/$13.40
|
The
collared hedges shown above have the effect of providing a protective floor
while allowing us to share in upward pricing movements. Consequently,
while these hedges are designed to decrease our exposure to price decreases,
they also have the effect of limiting the benefit of price increases above the
ceiling. For the 2008 crude oil contracts listed in both tables
above, a hypothetical $1.00 change in the NYMEX price above the ceiling price or
below the floor price applied to the notional amounts would cause a change in
our gain (loss) on hedging activities in 2008 of $1.1
million. For the 2008 natural gas contracts listed above, a
hypothetical $0.10 change in the NYMEX price above the ceiling price or below
the floor price applied to the notional amounts would cause a change in our gain
(loss) on hedging activities in 2008 of $0.07 million.
In a 1997
non-operated property acquisition, we became subject to the operator’s fixed
price gas sales contract with end users for a portion of the natural gas we
produce in Michigan. This contract has built-in pricing escalators of
4% per year. Our estimated future production volumes to be sold under
the fixed pricing terms of this contract as of October 1, 2008 are summarized
below:
|
|
|
|
Natural
Gas
|
10/2008
to 05/2011
|
24,000
|
$4.94
|
Natural
Gas
|
10/2008
to 09/2012
|
67,000
|
$4.38
|
Evaluation of disclosure controls
and procedures. In accordance with Rule 13a-15(b) of the
Securities Exchange Act of 1934 (the “Exchange Act”), our management evaluated,
with the participation of our Chairman, President and Chief Executive Officer
and our Vice President and Chief Financial Officer, the effectiveness of the
design and operation of our disclosure controls and procedures (as defined in
Rule 13a-15(e) under the Exchange Act) as of September 30,
2008. Based upon their evaluation of these disclosures controls and
procedures, the Chairman, President and Chief Executive Officer and the Vice
President and Chief Financial Officer concluded that the disclosure controls and
procedures were effective as of September 30, 2008 to ensure that information
required to be disclosed by us in the reports we file or submit under the
Exchange Act is recorded, processed, summarized and reported, within the time
periods specified in the Securities and Exchange Commission’s rules and forms,
and to ensure that information required to be disclosed by us in the reports we
file or submit under the Exchange Act is accumulated and communicated to our
management, including our principal executive and principal financial officers,
as appropriate, to allow timely decisions regarding required
disclosure.
Changes in internal control over
financial reporting. There was no change in our internal
control over financial reporting that occurred during the quarter ended
September 30, 2008 that has materially affected, or is reasonably likely to
materially affect, our internal control over financial reporting.
PART II –
OTHER INFORMATION
Whiting
is subject to litigation claims and governmental and regulatory proceedings
arising in the ordinary course of business. It is management’s
opinion that all claims and litigation we are involved in are not likely to have
a material adverse effect on our consolidated financial position, cash flows or
results of operations.
Risk
factors relating to us are contained in Item 1A of our Annual Report on Form
10-K for the fiscal year ended December 31, 2007. No material change
to such risk factors has occurred during the nine months ended September 30,
2008.
Entry into a Material Definitive
Agreement. On October 28, 2008, Whiting’s Board of Directors
approved a form of indemnification agreement to be entered into by Whiting and
each of Whiting’s directors and executive officers. Whiting expects
its directors and executive officers will execute indemnification agreements
substantially in the form approved. The indemnification agreements do
not increase the extent or scope of indemnification provided to Whiting’s
directors and executive officers under Whiting’s Certificate of Incorporation
and By-laws, which provide for indemnification to the fullest extent permitted
by law. The indemnification agreements set forth indemnification and
expense advancement rights and establish processes and procedures determining
entitlement to and obtaining indemnification and advancement of
expenses.
The
foregoing description is not complete and is qualified in its entirety by
reference to the form of indemnification agreement, a copy of which is filed as
Exhibit 10.1 to this Quarterly Report on Form 10-Q and incorporated by reference
herein.
Amendments to Articles of
Incorporation or Bylaws; Change in Fiscal Year. On October 28,
2008, Whiting’s Board of Directors adopted Amended and Restated By-laws (the
“By-laws”). The By-laws effect the following amendments:
·
|
Article
II, Section 14 was amended to (i) clarify the applicability of the advance
notice provisions to all stockholder proposals not properly brought under
Rule 14a-8 of the Securities Exchange Act of 1934, (ii) modify the time
frames necessary for such proposals to be timely and (iii) clarify the
information that must be included in the written notice to the Secretary,
including a new requirement that proposing stockholders disclosure certain
details about the nature of their ownership interests in Whiting and
related arrangements;
|
·
|
Article
II, Section 14 was also amended to (i) clarify the applicability of the
advance notice provisions to stockholder nominations of directors, (ii)
modify the time frames necessary for such nominations to be timely and
(iii) clarify the information that must be included in the written notice
to the Secretary, including a new requirement that nominating stockholders
disclosure certain details about the nature of their ownership interests
in Whiting and related arrangements;
and
|
·
|
Article
VIII was amended to make
clear that indemnification and advancement of expense
provisions constitute a contract between Whiting and each director or
officer.
|
A
stockholder who intends to present business or nominate persons for election as
directors at Whiting’s 2009 annual meeting of stockholders otherwise than
pursuant to Rule 14a-8 under the Securities Exchange Act of 1934 (i.e.,
proposals stockholders intend to present at the 2009 annual meeting but do not
intend to include in our proxy statement for such meeting) must comply with the
requirements set forth in the By-laws. As a result of the amendments
noted above, among other things, to bring business before or nominate persons
for election as directors at an annual meeting, a stockholder must give written
notice thereof, complying with the By-laws, to Whiting’s Corporate Secretary no
earlier than the 120th day and
no later than the 90th day
prior to the first anniversary of the preceding year’s annual
meeting. Under the By-laws, if Whiting does not receive notice of a
stockholder proposal or nomination submitted otherwise than pursuant to Rule
14a-8 under the Securities Exchange Act of 1934 during the time period between
January 6, 2009 and February 5, 2009, then the notice will be considered
untimely and Whiting will not be required to present such proposal at the 2009
annual meeting.
The
foregoing description is not complete and qualified in its entirety by reference
to a copy of the Amended and Restated By-laws of Whiting Petroleum Corporation
which is filed as Exhibit 3.1 to this Quarterly Report on Form 10-Q and
incorporated by reference herein.
The
exhibits listed in the accompanying index to exhibits are filed as part of this
Quarterly Report on Form 10-Q.
SIGNATURES
Pursuant
to the requirements of the Securities Exchange Act of 1934, the Registrant has
duly caused this report to be signed on its behalf by the undersigned thereunto
duly authorized, on this 30th day of October, 2008.
|
|
WHITING
PETROLEUM CORPORATION
|
|
|
|
|
|
|
|
By
|
/s/
James J. Volker
|
|
|
James
J. Volker
|
|
|
Chairman,
President and Chief Executive Officer
|
|
|
|
|
|
|
|
By
|
/s/
Michael J. Stevens
|
|
|
Michael
J. Stevens
|
|
|
Vice
President and Chief Financial Officer
|
|
|
|
|
|
|
|
By
|
/s/
Brent P. Jensen
|
|
|
Brent
P. Jensen
|
|
|
Controller
and Treasurer
|
Exhibit
Number
|
Exhibit Description
|
(3.1)
|
Amended
and Restated By-laws of Whiting Petroleum Corporation, effective October
28, 2008.
|
(10.1)
|
Form
of Indemnification Agreement for directors and officers of Whiting
Petroleum Corporation, effective October 28, 2008.
|
(31.1)
|
Certification
by the Chairman, President and Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act.
|
(31.2)
|
Certification
by the Vice President and Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act.
|
(32.1)
|
Written
Statement of the Chairman, President and Chief Executive Officer pursuant
to 18 U.S.C. Section 1350.
|
(32.2)
|
Written
Statement of the Vice President and Chief Financial Officer pursuant to 18
U.S.C. Section 1350.
|