UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
|
[X]
|
ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
|
For the
fiscal year ended December 31, 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)
|
Registrant’s
telephone number, including area code: (303) 837-1661
Securities
registered pursuant to Section 12(b) of the Act:
|
Common
Stock, $0.001 par value
Preferred
Share Purchase Rights
(Title
of Class)
|
New
York Stock Exchange
New
York Stock Exchange
(Name
of each exchange on which
registered)
|
Securities
registered pursuant to Section 12(g) of the Act: None.
Indicate
by check mark if the Registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act. Yes T
No £
Indicate
by check mark if the Registrant is not required to file reports pursuant to
Section 13 or 15(d) of the Securities Act. Yes
£
No T
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 if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. T
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,”
“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one):
|
Large
accelerated filer T
|
Accelerated
filer £
|
Non-accelerated
filer £
|
Smaller
reporting company £
|
Indicate
by check mark whether the Registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes £ No T
Aggregate
market value of the voting common stock held by non-affiliates of the registrant
at June 30, 2008: $4,499,939,059.
Number of
shares of the registrant’s common stock outstanding at February 16,
2009: 50,771,882 shares.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions
of the Proxy Statement for the 2009 Annual Meeting of Stockholders are
incorporated by reference into Part III.
CERTAIN DEFINITIONS
Unless
the context otherwise requires, the terms “we,” “us,” “our” or “ours” when used
in this Annual Report on Form 10-K 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 Annual Report on
Form 10-K:
“3-D seismic” Geophysical data
that depict the subsurface strata in three dimensions. 3-D seismic
typically provides a more detailed and accurate interpretation of the subsurface
strata than 2-D, or two-dimensional, seismic.
“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 Bbl 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.
“CO2 flood” A tertiary recovery
method in which CO2 is
injected into a reservoir to enhance hydrocarbon recovery.
“completion” The installation
of permanent equipment for the production of crude oil or natural gas, or in the
case of a dry hole, the reporting of abandonment to the appropriate
agency.
“farmout” An assignment of an
interest in a drilling location and related acreage
conditioned upon the drilling of a well on that location.
"FASB" Financial Accounting
Standards Board.
“flush production” The high
rate of flow from a well during initial production immediately after it is
brought on-line.
“GAAP” Generally accepted
accounting principles in the United States of America.
“MBbl” One thousand barrels
of oil or other liquid hydrocarbons.
“MBOE” One thousand
BOE.
“MBOE/d” One MBOE per
day.
“Mcf” One thousand cubic feet
of natural gas.
“Mcfe” One thousand cubic
feet of natural gas equivalent.
“MMBbl” One million
Bbl.
“MMBOE” One million
BOE.
“MMBtu” One million British
Thermal Units.
“MMcf” One million cubic feet
of natural gas.
“MMcf/d” One MMcf per
day.
“MMcfe” One million cubic
feet of natural gas equivalent.
“MMcfe/d” One MMcfe per
day.
“PDNP” Proved developed
nonproducing.
“PDP” Proved developed
producing.
“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.
“PUD” Proved
undeveloped.
“pre-tax PV10%” The present
value of estimated future revenues to be generated from the production of proved
reserves calculated in accordance with the guidelines of the Securities and
Exchange Commission (“SEC”), net of estimated lease operating expense,
production taxes and future development costs, using price and costs as of the
date of estimation without future escalation, without giving effect to
non-property related expenses such as general and administrative expenses, debt
service and depreciation, depletion and amortization, or Federal income taxes
and discounted using an annual discount rate of 10%. Pre-tax PV10%
may be considered a non-GAAP financial measure as defined by the
SEC. See footnote (1) to the Proved Reserves table in Item 1.
“Business” for more information.
“reservoir” A porous and
permeable underground formation containing a natural accumulation of producible
crude oil and/or natural gas that is confined by impermeable rock or water
barriers and is individual and separate from other reservoirs.
“resource
play” Refers to drilling programs targeted at regionally distributed oil
or natural gas accumulations. Successful exploitation of these
reservoirs is dependent upon new technologies such as horizontal drilling and
multi-stage fracture stimulation to access large rock volumes in order to
produce economic quantities of oil or natural gas.
“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 a share of production, subject to all royalties, overriding
royalties and other burdens and to all costs of exploration, development and
operations and all risks in connection therewith.
PART
I
|
Item 1.
|
Business
|
Overview
We are an
independent oil and gas company engaged in 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. We were incorporated in 2003 in connection with our
initial public offering.
Since our
inception in 1980, we have built a strong asset base and achieved steady growth
through property acquisitions, development and exploration
activities. As of December 31, 2008, our estimated proved reserves
totaled 239.1 MMBOE, representing a 5% decrease in our proved reserves since
December 31, 2007. Our 2008 average daily production was 47.9
MBOE/d and implies an average reserve life of approximately 13.6
years.
The
following table summarizes our estimated proved reserves by core area, the
corresponding pre-tax PV10% value and our standardized measure of discounted
future net cash flows as of December 31, 2008, and our December 2008 average
daily production:
|
Proved
Reserves(1)
|
||||||||||||||||||||||||
|
Core
Area
|
Oil(2)
(MMBbl)
|
Natural
Gas (Bcf)
|
Total
(MMBOE)
|
%
Oil(2)
|
Pre-Tax
PV10% Value(3)
|
December
2008 Average Daily Production (MBOE/d)
|
||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||
|
Permian
Basin
|
88.1 | 57.8 | 97.7 | 90 | % | $ | 455.2 | 11.7 | ||||||||||||||||
|
Rocky
Mountains
|
49.2 | 203.9 | 83.2 | 59 | % | 548.2 | 27.7 | |||||||||||||||||
|
Mid-Continent
|
37.2 | 11.7 | 39.1 | 95 | % | 416.2 | 7.2 | |||||||||||||||||
|
Gulf
Coast
|
3.1 | 41.6 | 10.1 | 31 | % | 105.2 | 5.0 | |||||||||||||||||
|
Michigan
|
2.4 | 39.7 | 9.0 | 27 | % | 78.2 | 3.5 | |||||||||||||||||
|
Total
|
180.0 | 354.8 | 239.1 | 75 | % | $ | 1,603.0 | 55.1 | ||||||||||||||||
|
Discounted
Future Income Taxes
|
- | - | - | - | (226.6 | ) | - | |||||||||||||||||
|
Standardized
Measure of Discounted Future Net Cash Flows
|
- | - | - | - | $ | 1,376.4 | - | |||||||||||||||||
_____________________
|
(1)
|
Oil
and gas reserve quantities and related discounted future net cash flows
have been derived from oil and gas prices as of December 31, 2008 pursuant
to current SEC and FASB guidelines.
|
|
(2)
|
Oil
includes natural gas liquids.
|
|
(3)
|
Pre-tax
PV10% may be considered a non-GAAP financial measure as defined by the SEC
and is derived from the standardized measure of discounted future net cash
flows, which is the most directly comparable GAAP financial
measure. Pre-tax PV10% is computed on the same basis as the
standardized measure of discounted future net cash flows but without
deducting future income taxes. We believe pre-tax PV10% is a
useful measure for investors for evaluating the relative monetary
significance of our oil and natural gas properties. We further
believe investors may utilize our pre-tax PV10% as a basis for comparison
of the relative size and value of our reserves to other companies because
many factors that are unique to each individual company impact the amount
of future income taxes to be paid. Our management uses this
measure when assessing the potential return on investment related to our
oil and gas properties and acquisitions. However, pre-tax PV10%
is not a substitute for the standardized measure of discounted future net
cash flows. Our pre-tax PV10% and the standardized measure of
discounted future net cash flows do not purport to present the fair value
of our oil and natural gas
reserves.
|
While
historically we have grown through acquisitions, we are increasingly focused on
a balance between exploration and development programs and continuing to
selectively pursue acquisitions that complement our existing core
properties. We believe that our significant drilling inventory,
combined with our operating experience and cost structure, provides us with
meaningful organic growth opportunities.
Our
growth plan is centered on the following activities:
|
•
|
pursuing
the development of projects that we believe will generate attractive rates
of return;
|
|
|
•
|
maintaining
a balanced portfolio of lower risk, long-lived oil and gas properties that
provide stable cash flows;
|
|
|
•
|
seeking
property acquisitions that complement our core
areas; and
|
|
|
•
|
allocating
a portion of our capital budget to leasing and exploring prospect
areas.
|
During
2008, we incurred $1,386.1 million in acquisition, development and exploration
activities, including $947.4 million for the drilling of 308 gross (125.7 net)
wells. Of these new wells, 115.2 (net) resulted in productive
completions and 10.5 (net) were unsuccessful, yielding a 92% success
rate. Our current 2009 capital budget for exploration and development
expenditures is $474.0 million, which we expect to fund with net cash provided
by our operating activities and a portion of the proceeds from the common stock
offering we completed in February 2009. Our 2009 capital budget of
$474.0 million, however, represents a substantial decrease from the $947.4
million incurred on exploration and development expenditures during
2008. This reduced capital budget is in response to the significantly
lower oil and natural gas prices experienced during the fourth quarter of 2008
and continuing into 2009.
Acquisitions
and Divestitures
The
following is a summary of our acquisitions and divestitures during the last two
years. See “Management’s Discussion and Analysis of Financial
Condition and Results of Operations” for more information on these acquisitions
and divestitures.
2008 Acquisitions. On May 30, 2008, we
acquired interests in 31 producing gas wells, development acreage and gas
gathering and processing facilities on approximately 22,000 gross (11,500 net)
acres in the Flat Rock field in Uintah County, Utah for an aggregate acquisition
price of $365.0 million. After allocating $79.5 million of the
purchase price to unproved properties, the resulting acquisition cost is $2.48
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.
2008
Divestitures. 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, providing net
proceeds of $214.9 million after underwriters’ discounts and commissions and
offering 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 $193.7 million. We used the net offering proceeds to
reduce a portion of the debt outstanding under our credit
agreement. The net proceeds from the sale of Trust units to the
public resulted in a deferred gain on sale of $100.0
million. Immediately prior to the closing of the offering, we
conveyed a term net profits interest in certain of our oil and 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, 2021, based on the reserve report for the
underlying properties as of December 31, 2008. The conveyance of
the net profits interest to the Trust consisted entirely of proved developed
producing reserves of 8.2 MMBOE, as of the January 1, 2008 effective
date, representing 3.3% of our proved reserves as of December 31, 2007, and
10.0%, or 4.2 MBOE/d, of our March 2008 average daily net
production. After netting our ownership of 2,186,389 Trust units,
third-party public Trust unit holders receive 6.9 MMBOE of proved producing
reserves, or 2.75% of our total year-end 2007 proved reserves, and 7.4%, or 3.1
MBOE/d, of our March 2008 average daily net production.
2007
Acquisitions. We did not make any significant acquisitions
during the year ended December 31, 2007.
2007
Divestitures. On July 17, 2007, we sold our 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, we sold our 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. No gain or loss was recognized on the sales. 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.
Business
Strategy
Our goal
is to generate meaningful growth in both production and free cash flow by
investing in oil and gas projects with attractive rates of return on capital
employed. To date, we have achieved this goal through both the
acquisition of reserves and continued field development in our core
areas. Because of the extensive property base we have built, we are
pursuing several economically attractive oil and gas opportunities to exploit
and develop properties as well as explore our acreage positions for additional
production growth and proved reserves. Specifically, we have focused,
and plan to continue to focus, on the following:
Pursuing High-Return Organic Reserve
Additions. The development of large resource plays such as our
Williston Basin and Piceance Basin projects has become one of our central
objectives. We have assembled approximately 125,600 gross (83,600
net) acres on the eastern side of the Williston Basin in North Dakota in an
active oil development play at our Sanish field area, where the Middle Bakken
reservoir is oil productive. We have drilled and completed 49
successful Bakken wells (27 operated) in our Sanish field acreage that had a
combined net production rate of 7.5 MBOE/d during December 2008. With
the acquisition of Equity Oil Company in 2004, we acquired mineral interests and
federal oil and gas leases in the Piceance Basin of Colorado, where we have
found the Iles and Williams Fork (Mesaverde) reservoirs to be gas productive at
our Sulphur Creek field area and the Mesaverde formation to be gas productive at
our Jimmy Gulch prospect area. Our initial drilling results in both
projects have been positive. In the Piceance acreage, we have drilled
and completed 23 successful wells that had a combined net production rate of 9.5
Bcf/d of natural gas during December 2008. In addition to development
of our core areas, we have identified opportunities in the Lewis & Clark
prospect in the Williston Basin, the Sulphur Creek field – Jimmy Gulch and
Wasatch prospects in the Piceance Basin and the Hatfield prospect in the Green
River Basin.
Developing and Exploiting Existing
Properties. Our existing property base and our acquisitions
over the past five years have provided us with numerous low-risk opportunities
for exploitation and development drilling. As of December 31, 2008,
we have identified a drilling inventory of over 1,400 gross wells that we
believe will add substantial production over the next five years. Our
drilling inventory consists of the development of our proved and non-proved
reserves on which we have spent significant time evaluating the costs and
expected results. Additionally, we have several opportunities to
apply and expand enhanced recovery techniques that we expect will increase
proved reserves and extend the productive lives of our mature
fields. In 2005, we acquired two large oil fields, the Postle field,
located in the Oklahoma Panhandle, and the North Ward Estes field, located in
the Permian Basin of West Texas. We have experienced and anticipate
further significant production increases in these fields over the next four to
seven years through the use of secondary and tertiary recovery
techniques. In these fields, we are actively injecting water and
CO2
and executing extensive re-development, drilling and completion operations, as
well as enhanced gas handling and treating capability.
Growing Through Accretive
Acquisitions. From 2004 to 2008, we completed 13 separate
acquisitions of producing properties for estimated proved reserves of 226.9
MMBOE, as of the effective dates of the acquisitions. Our experienced
team of management, land, engineering and geoscience professionals has developed
and refined an acquisition program designed to increase reserves and complement
our existing properties, including identifying and evaluating acquisition
opportunities, negotiating and closing purchases and managing acquired
properties. We intend to selectively pursue the acquisition of
properties complementary to our core operating areas.
Disciplined Financial
Approach. Our goal is to remain financially strong, yet
flexible, through the prudent management of our balance sheet and active
management of commodity price volatility. We have historically funded
our acquisitions and growth activity through a combination of equity and debt
issuances, bank borrowings and internally generated cash flow, as appropriate,
to maintain our strong financial position. From time to time, we
monetize non-core properties and use the net proceeds from these asset sales to
repay debt under our credit agreement. To support cash flow
generation on our existing properties and help ensure expected cash flows from
acquired properties, we periodically enter into derivative
contracts. Typically, we use costless collars to provide an
attractive base commodity price level, while maintaining the ability to benefit
from improvements in commodity prices.
Competitive
Strengths
We
believe that our key competitive strengths lie in our balanced asset portfolio,
our experienced management and technical team and our commitment to effective
application of new technologies.
Balanced, Long-Lived Asset
Base. As of December 31, 2008, we had interests in 8,871 gross
(3,337 net) productive wells across approximately 992,400 gross (514,900 net)
developed acres in our five core geographical areas. We believe this
geographic mix of properties and organic drilling opportunities, combined with
our continuing business strategy of acquiring and exploiting properties in these
areas, presents us with multiple opportunities in executing our strategy because
we are not dependent on any particular producing regions or geological
formations. Our proved reserve life is approximately 13.6 years based
on year-end 2008 proved reserves and 2008 production.
Experienced Management
Team. Our management team averages 25 years of experience in
the oil and gas industry. Our personnel have extensive experience in
each of our core geographical areas and in all of our operational
disciplines. In addition, each of our acquisition professionals has
at least 28 years of experience in the evaluation, acquisition and operational
assimilation of oil and gas properties.
Commitment to
Technology. In each of our core operating areas, we have
accumulated detailed geologic and geophysical knowledge and have developed
significant technical and operational expertise. In recent years, we
have developed considerable expertise in conventional and 3-D seismic
imaging and interpretation. Our technical team has access to
approximately 5,934 square miles of 3-D seismic data, digital well logs and
other subsurface information. This data is analyzed with advanced
geophysical and geological computer resources dedicated to the accurate and
efficient characterization of the subsurface oil and gas reservoirs that
comprise our asset base. In addition, our information systems enable
us to update our production databases through daily uploads from hand held
computers in the field. With the acquisition of the Postle and North
Ward Estes properties, we have assembled a team of 14 professionals averaging
over 20 years of expertise managing CO2
floods. This provides us with the ability to pursue other
CO2
flood targets and employ this technology to add reserves to our
portfolio. This commitment to technology has increased the
productivity and efficiency of our field operations and development
activities.
Proved
Reserves
Our
estimated proved reserves as of December 31, 2008 are summarized in the table
below.
|
Oil
(MMBbl)
|
Natural
Gas
(Bcf)
|
Total
(MMBOE)
|
%
of Total
Proved
|
Future
Capital Expenditures
(In
millions)
|
||||||||||||||||
|
Permian
Basin:
|
||||||||||||||||||||
|
PDP
|
26.8 | 31.1 | 31.9 | 33 | % | |||||||||||||||
|
PDNP
|
21.8 | 3.8 | 22.4 | 23 | % | |||||||||||||||
|
PUD
|
39.5 | 23.0 | 43.4 | 44 | % | |||||||||||||||
|
Total
Proved
|
88.1 | 57.8 | 97.7 | 100 | % | $ | 494.0 | |||||||||||||
|
Rocky
Mountains:
|
||||||||||||||||||||
|
PDP
|
36.2 | 113.1 | 55.0 | 66 | % | |||||||||||||||
|
PDNP
|
0.9 | 6.4 | 2.0 | 2 | % | |||||||||||||||
|
PUD
|
12.1 | 84.4 | 26.2 | 32 | % | |||||||||||||||
|
Total
Proved
|
49.2 | 203.9 | 83.2 | 100 | % | $ | 287.7 | |||||||||||||
|
Mid-Continent:
|
||||||||||||||||||||
|
PDP
|
22.7 | 8.6 | 24.2 | 62 | % | |||||||||||||||
|
PDNP
|
8.4 | 1.8 | 8.6 | 22 | % | |||||||||||||||
|
PUD
|
6.1 | 1.3 | 6.3 | 16 | % | |||||||||||||||
|
Total
Proved
|
37.2 | 11.7 | 39.1 | 100 | % | $ | 149.0 | |||||||||||||
|
Gulf
Coast:
|
||||||||||||||||||||
|
PDP
|
1.9 | 25.7 | 6.2 | 61 | % | |||||||||||||||
|
PDNP
|
0.2 | 3.6 | 0.8 | 8 | % | |||||||||||||||
|
PUD
|
1.0 | 12.3 | 3.1 | 31 | % | |||||||||||||||
|
Total
Proved
|
3.1 | 41.6 | 10.1 | 100 | % | $ | 48.0 | |||||||||||||
|
Michigan:
|
||||||||||||||||||||
|
PDP
|
1.1 | 30.0 | 6.1 | 68 | % | |||||||||||||||
|
PDNP
|
1.0 | 5.1 | 1.9 | 21 | % | |||||||||||||||
|
PUD
|
0.3 | 4.6 | 1.0 | 11 | % | |||||||||||||||
|
Total
Proved
|
2.4 | 39.7 | 9.0 | 100 | % | $ | 3.5 | |||||||||||||
|
Total
Company:
|
||||||||||||||||||||
|
PDP
|
88.7 | 208.5 | 123.4 | 52 | % | |||||||||||||||
|
PDNP
|
32.3 | 20.7 | 35.7 | 15 | % | |||||||||||||||
|
PUD
|
59.0 | 125.6 | 80.0 | 33 | % | |||||||||||||||
|
Total
Proved
|
180.0 | 354.8 | 239.1 | 100 | % | $ | 982.2 | |||||||||||||
Marketing
and Major Customers
We
principally sell our oil and gas production to end users, marketers and other
purchasers that have access to nearby pipeline facilities. In areas
where there is no practical access to pipelines, oil is trucked to storage
facilities. During 2008, sales to Plains Marketing LP and Valero
Energy Corporation accounted for 15% and 14%, respectively, of our total oil and
natural gas sales. During 2007, sales to Valero Energy Corporation
and Plains Marketing LP accounted for 14% and 13%, respectively, of our total
oil and natural gas sales. During 2006, sales to Plains Marketing LP
and Valero Energy Corporation accounted for 16% and 12%, respectively, of our
total oil and natural gas sales.
Title
to Properties
Our
properties are subject to customary royalty interests, liens under indebtedness,
liens incident to operating agreements, liens for current taxes and other
burdens, including other mineral encumbrances and restrictions. Our
credit agreement is also secured by a first lien on substantially all of our
assets. We do not believe that any of these burdens materially
interfere with the use of our properties in the operation of our
business.
We
believe that we have satisfactory title to or rights in all of our producing
properties. As is customary in the oil and gas industry, minimal
investigation of title is made at the time of acquisition of undeveloped
properties. In most cases, we investigate title and obtain title
opinions from counsel only when we acquire producing properties or before
commencement of drilling operations.
Competition
We
operate in a highly competitive environment for acquiring properties, marketing
oil and natural gas and securing trained personnel. Many of our
competitors possess and employ financial, technical and personnel resources
substantially greater than ours, which can be particularly important in the
areas in which we operate. Those companies may be able to pay more
for productive oil and gas properties and exploratory prospects and to evaluate,
bid for and purchase a greater number of properties and prospects than our
financial or personnel resources permit. Our ability to acquire
additional prospects and to find and develop reserves in the future will depend
on our ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. Also, there is
substantial competition for capital available for investment in the oil and gas
industry.
Regulation
Regulation
of Transportation, Sale and Gathering of Natural Gas
The
Federal Energy Regulatory Commission (“FERC”) regulates the transportation, and
to a lesser extent sale for resale, of natural gas in interstate commerce
pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978
and regulations issued under those Acts. In 1989, however, Congress
enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining
price and nonprice controls affecting wellhead sales of natural gas, effective
January 1, 1993. While sales by producers of natural gas and all
sales of crude oil, condensate and natural gas liquids can currently be made at
uncontrolled market prices, in the future Congress could reenact price controls
or enact other legislation with detrimental impact on many aspects of our
business.
Our
natural gas sales are affected by the availability, terms and cost of
transportation. The price and terms of access to pipeline
transportation and underground storage are subject to extensive federal and
state regulation. From 1985 to the present, several major regulatory
changes have been implemented by Congress and the FERC that affect the economics
of natural gas production, transportation and sales. In addition, the
FERC is continually proposing and implementing new rules and regulations
affecting those segments of the natural gas industry that remain subject to the
FERC's jurisdiction, most notably interstate natural gas transmission companies
and certain underground storage facilities. These initiatives may
also affect the intrastate transportation of natural gas under certain
circumstances. The stated purpose of many of these regulatory changes
is to promote competition among the various sectors of the natural gas industry
by making natural gas transportation more accessible to natural gas buyers and
sellers on an open and non-discriminatory basis.
FERC
implements The Outer Continental Shelf Lands Act as to transportation and
pipeline issues, which requires that all pipelines operating on or across the
outer continental shelf provide open access and non-discriminatory
transportation service. One of the FERC’s principal goals in carrying
out this Act’s mandate is to increase transparency in the market to provide
producers and shippers on the outer continental shelf with greater assurance of
open access services on pipelines located on the outer continental shelf and
non-discriminatory rates and conditions of service on such
pipelines.
We cannot
accurately predict whether the FERC’s actions will achieve the goal of
increasing competition in markets in which our natural gas is
sold. In addition, many aspects of these regulatory developments have
not become final, but are still pending judicial and final FERC
decisions. Regulations implemented by the FERC in recent years could
result in an increase in the cost of transportation service on certain petroleum
product pipelines. The natural gas industry historically has been
very heavily regulated. Therefore, we cannot provide any assurance
that the less stringent regulatory approach recently established by the FERC
will continue. However, we do not believe that any action taken will
affect us in a way that materially differs from the way it affects other natural
gas producers.
Intrastate
natural gas transportation is subject to regulation by state regulatory
agencies. The basis for intrastate regulation of natural gas
transportation and the degree of regulatory oversight and scrutiny given to
intrastate natural gas pipeline rates and services varies from state to
state. Insofar as such regulation within a particular state will
generally affect all intrastate natural gas shippers within the state on a
comparable basis, we believe that the regulation of similarly situated
intrastate natural gas transportation in any of the states in which we operate
and ship natural gas on an intrastate basis will not affect our operations in
any way that is of material difference from those of our
competitors.
Pipeline
safety is regulated at both state and federal levels. After a final
rule was implemented by the U.S. Department of Transportation on March 15, 2006
that defines and puts new safety requirements on gas gathering pipelines, we
have completed an initial screening of gas gathering lines and are implementing
programs to comply with applicable requirements of this section.
Regulation
of Transportation of Oil
Sales of
crude oil, condensate and natural gas liquids are not currently regulated and
are made at negotiated prices. Nevertheless, Congress could reenact
price controls in the future.
Our crude
oil sales are affected by the availability, terms and cost of
transportation. The transportation of oil in common carrier pipelines
is also subject to rate regulation. The FERC regulates interstate oil
pipeline transportation rates under the Interstate Commerce Act. In
general, interstate oil pipeline rates must be cost-based, although settlement
rates agreed to by all shippers are permitted and market-based rates may be
permitted in certain circumstances. Effective January 1, 1995,
the FERC implemented regulations establishing an indexing system (based on
inflation) for crude oil transportation rates that allowed for an increase or
decrease in the cost of transporting oil to the purchaser. FERC’s
regulations include a methodology for oil pipelines to change their rates
through the use of an index system that establishes ceiling levels for such
rates. The mandatory five year review has revised the methodology for
this index to now be based on Producer Price Index for Finished Goods (PPI-FG),
plus a 1.3% adjustment, for the period July 1, 2006 through July
2011. The regulations provide that each year the Commission will
publish the oil pipeline index after the PPI-FG becomes
available. Intrastate oil pipeline transportation rates are subject
to regulation by state regulatory commissions. The basis for
intrastate oil pipeline regulation, and the degree of regulatory oversight and
scrutiny given to intrastate oil pipeline rates, varies from state to
state. Insofar as effective interstate and intrastate rates are
equally applicable to all comparable shippers, we believe that the regulation of
oil transportation rates will not affect our operations in any way that is of
material difference from those of our competitors.
Further,
interstate and intrastate common carrier oil pipelines must provide service on a
non-discriminatory basis. Under this open access standard, common
carriers must offer service to all shippers requesting service on the same terms
and under the same rates. When oil pipelines operate at full
capacity, access is governed by prorationing provisions set forth in the
pipelines’ published tariffs. Accordingly, we believe that access to
oil pipeline transportation services generally will be available to us to the
same extent as to our competitors.
Regulation
of Production
The
production of oil and gas is subject to regulation under a wide range of local,
state and federal statutes, rules, orders and regulations. Federal,
state and local statutes and regulations require permits for drilling
operations, drilling bonds and reports concerning operations. All of
the states in which we own and operate properties have regulations governing
conservation matters, including provisions for the unitization or pooling of oil
and gas properties, the establishment of maximum allowable rates of production
from oil and gas wells, the regulation of well spacing, and plugging and
abandonment of wells. The effect of these regulations is to limit the
amount of oil and gas that we can produce from our wells and to limit the number
of wells or the locations at which we can drill, although we can apply for
exceptions to such regulations or to have reductions in well
spacing. Moreover, each state generally imposes a production or
severance tax with respect to the production or sale of oil, gas and natural gas
liquids within its jurisdiction.
Some of
our offshore operations are conducted on federal leases that are administered by
Minerals Management Service, or MMS, and are required to comply with the
regulations and orders issued by MMS under the Outer Continental Shelf Lands
Act. Among other things, we are required to obtain prior MMS approval
for any exploration plans we pursue and our development and production plans for
these leases. MMS regulations also establish construction
requirements for production facilities located on our federal offshore leases
and govern the plugging and abandonment of wells and the removal of production
facilities from these leases. Under limited circumstances, MMS could
require us to suspend or terminate our operations on a federal
lease.
MMS also
establishes the basis for royalty payments due under federal oil and gas leases
through regulations issued under applicable statutory
authority. State regulatory authorities establish similar standards
for royalty payments due under state oil and gas leases. The basis
for royalty payments established by MMS and the state regulatory authorities is
generally applicable to all federal and state oil and gas
lessees. Accordingly, we believe that the impact of royalty
regulation on our operations should generally be the same as the impact on our
competitors.
The
failure to comply with these rules and regulations can result in substantial
penalties. Our competitors in the oil and gas industry are subject to
the same regulatory requirements and restrictions that affect our
operations.
Environmental
Regulations
General. Our oil
and gas exploration, development and production operations are subject to
stringent federal, state and local laws and regulations governing the discharge
of materials into the environment or otherwise relating to environmental
protection. Numerous governmental agencies, such as the U.S.
Environmental Protection Agency (the “EPA”) issue regulations to implement and
enforce such laws, which often require difficult and costly compliance measures
that carry substantial administrative, civil and criminal penalties or that may
result in injunctive relief for failure to comply. These laws and
regulations may require the acquisition of a permit before drilling or facility
construction commences, restrict the types, quantities and concentrations of
various materials that can be released into the environment in connection with
drilling and production activities, limit or prohibit project siting,
construction, or drilling activities on certain lands laying within wilderness,
wetlands, ecologically sensitive and other protected areas, require remedial
action to prevent pollution from former operations, such as plugging abandoned
wells or closing pits, and impose substantial liabilities for pollution
resulting from our operations. The EPA and analogous state agencies
may delay or refuse the issuance of required permits or otherwise include
onerous or limiting permit conditions that may have a significant adverse impact
on our ability to conduct operations. The regulatory burden on the
oil and gas industry increases the cost of doing business and consequently
affects its profitability.
Changes
in environmental laws and regulations occur frequently, and any changes that
result in more stringent and costly material handling, storage, transport,
disposal or cleanup requirements could materially and adversely affect our
operations and financial position, as well as those of the oil and gas industry
in general. While we believe that we are in substantial compliance
with current applicable environmental laws and regulations and have not
experienced any material adverse effect from compliance with these environmental
requirements, there is no assurance that this trend will continue in the
future.
The
environmental laws and regulations which have the most significant impact on the
oil and gas exploration and production industry are as follows:
Superfund. The
Comprehensive Environmental Response, Compensation and Liability Act of 1980,
also known as “CERCLA” or “Superfund,” and comparable state laws impose
liability, without regard to fault or the legality of the original conduct, on
certain classes of persons that contributed to the release of a “hazardous
substance” into the environment. These persons include the “owner” or
“operator” of a disposal site or sites where a release occurred and entities
that disposed or arranged for the disposal of the hazardous substances found at
the site. Under CERCLA, such persons may be subject to strict, joint
and several liability for the costs of cleaning up the hazardous substances that
have been released into the environment, for damages to natural resources and
for the costs of certain health studies, and it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damage allegedly caused by the hazardous substances released into the
environment. In the course of our ordinary operations, we may
generate material that may fall within CERCLA’s definition of a “hazardous
substance”. Consequently, we may be jointly and severally liable
under CERCLA or comparable state statutes for all or part of the costs required
to clean up sites at which these materials have been disposed or
released.
We
currently own or lease, and in the past have owned or leased, properties that
for many years have been used for the exploration and production of oil and
gas. Although we and our predecessors have used operating and
disposal practices that were standard in the industry at the time, hydrocarbons
or other materials may have been disposed or released on, under, or from the
properties owned or leased by us or on, under, or from other locations where
these hydrocarbons and materials have been taken for disposal. In
addition, many of these owned and leased properties have been operated by third
parties whose management and disposal of hydrocarbons and materials were not
under our control. Similarly, the disposal facilities where discarded
materials are sent are also often operated by third parties whose waste
treatment and disposal practices may not be adequate. While we only
use what we consider to be reputable disposal facilities, we might not know of a
potential problem if the disposal occurred before we acquired the property or
business, and if the problem itself is not discovered until years
later. Our properties, adjacent affected properties, the disposal
sites, and the material itself may be subject to CERCLA and analogous state
laws. Under these laws, we could be required:
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to
remove or remediate previously disposed materials, including materials
disposed or released by prior owners or operators or other third
parties;
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to
clean up contaminated property, including contaminated groundwater;
or
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to
perform remedial operations to prevent future contamination, including the
plugging and abandonment of wells drilled and left inactive by prior
owners and
operators.
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At this
time, we do not believe that we are a potentially responsible party with respect
to any Superfund site and we have not been notified of any claim, liability or
damages under CERCLA.
Oil Pollution
Act. The Oil Pollution Act of 1990, also known as “OPA,” and
regulations issued under OPA impose strict, joint and several liability on
“responsible parties” for damages resulting from oil spills into or upon
navigable waters, adjoining shorelines or in the exclusive economic zone of the
United States. A “responsible party” includes the owner or operator
of an onshore facility and the lessee or permittee of the area in which an
offshore facility is located. The OPA establishes a liability limit
for onshore facilities of $350.0 million, while the liability limit for offshore
facilities is the payment of all removal costs plus up to $75.0 million in other
damages, but these limits may not apply if a spill is caused by a party’s gross
negligence or willful misconduct; the spill resulted from violation of a federal
safety, construction or operating regulation; or if a party fails to report a
spill or to cooperate fully in a cleanup. The OPA also requires the
lessee or permittee of the offshore area in which a covered offshore facility is
located to establish and maintain evidence of financial responsibility in the
amount of $35.0 million ($10.0 million if the offshore facility is located
landward of the seaward boundary of a state) to cover liabilities related to an
oil spill for which such person is statutorily responsible. The
amount of financial responsibility required under OPA may be increased up to
$150.0 million, depending on the risk represented by the quantity or quality of
oil that is handled by the facility. Any failure to comply with OPA’s
requirements or inadequate cooperation during a spill response action may
subject a responsible party to administrative, civil or criminal enforcement
actions. We believe we are in compliance with all applicable OPA
financial responsibility obligations. Moreover, we are not aware of
any action or event that would subject us to liability under OPA, and we believe
that compliance with OPA’s financial responsibility and other operating
requirements will not have a material adverse effect on us.
Resource Conservation Recovery
Act. The Resource Conservation and Recovery Act, also known as
“RCRA,” is the principal federal statute governing the treatment, storage and
disposal of hazardous wastes. RCRA imposes stringent operating
requirements and liability for failure to meet such requirements on a person who
is either a “generator” or “transporter” of hazardous waste or on an “owner” or
“operator” of a hazardous waste treatment, storage or disposal
facility. RCRA and many state counterparts specifically exclude from
the definition of hazardous waste “drilling fluids, produced waters, and other
wastes associated with the exploration, development, or production of crude oil,
natural gas or geothermal energy” and thus we are not required to comply with a
substantial portion of RCRA’s requirements because our operations generate
minimal quantities of hazardous wastes. However, these wastes may be
regulated by EPA or state agencies as solid waste. In addition,
ordinary industrial wastes, such as paint wastes, waste solvents, laboratory
wastes, and waste compressor oils, may be regulated as hazardous
waste. Although we do not believe the current costs of managing our
materials constituting wastes as they are presently classified to be
significant, any repeal or modification of the oil and gas exploration and
production exemption by administrative, legislative or judicial process, or
modification of similar exemptions in analogous state statutes, would increase
the volume of hazardous waste we are required to manage and dispose of and would
cause us, as well as our competitors, to incur increased operating
expenses.
Clean Water
Act. The Federal Water Pollution Control Act of 1972, or the
Clean Water Act (the “CWA”), imposes restrictions and controls on the discharge
of produced waters and other pollutants into navigable
waters. Permits must be obtained to discharge pollutants into state
and federal waters and to conduct construction activities in waters and
wetlands. The CWA and certain state regulations prohibit the
discharge of produced water, sand, drilling fluids, drill cuttings, sediment and
certain other substances related to the oil and gas industry into certain
coastal and offshore waters without an individual or general National Pollutant
Discharge Elimination System discharge permit.
Historically,
the EPA had regulations under the authority of the CWA that required certain oil
and gas exploration and production projects to obtain permits for construction
projects with storm water discharges. However, the Energy Policy Act
of 2005 nullified most of the EPA regulations that required permitting of oil
and gas construction projects. There are still some states that
regulate the discharge of storm water from oil and gas construction
projects. Costs may be associated with the treatment of wastewater
and/or developing and implementing storm water pollution prevention
plans. The CWA and comparable state statutes provide for civil,
criminal and administrative penalties for unauthorized discharges of oil and
other pollutants and impose liability on parties responsible for those
discharges for the costs of cleaning up any environmental damage caused by the
release and for natural resource damages resulting from the
release. In Section 40 CFR 112 of the regulations, the EPA
promulgated the Spill Prevention, Control, and Countermeasure, or SPCC,
regulations, which require certain oil containing facilities to prepare plans
and meet construction and operating standards. The SPCC regulations
were revised in 2002 and will require the amendment of SPCC plans and the
modification of spill control devices at many facilities. On May 16,
2007 the EPA extended the compliance dates until July 1, 2009 for both
completion and implementation of the plan. The extension will allow
time for the EPA to complete additional rule amendments and guidance
documents. On December 5, 2008, the EPA published the final amendment
to the 2002 SPCC rule to provide increased clarity, to tailor requirements to
particular industry sectors, and to streamline certain requirements for a
facility owner or operator subject to the rule. The EPA, in accordance
with the January 20, 2009 White House memorandum, is delaying by 60 days the
effective date of this final rule. The amendments will now become
effective on April 4, 2009. We believe that our operations comply in all
material respects with the requirements of the CWA and state statutes enacted to
control water pollution and that any amendment and subsequent implementation of
our SPCC plans will be performed in a timely manner and not have a significant
impact on our operations.
Clean Air Act. The
Clean Air Act restricts the emission of air pollutants from many sources,
including oil and gas operations. New facilities may be required to
obtain permits before work can begin, and existing facilities may be required to
obtain additional permits and incur capital costs in order to remain in
compliance. More stringent regulations governing emissions of toxic
air pollutants are being developed by the EPA and may increase the costs of
compliance for some facilities. We believe that we are in substantial
compliance with all applicable air emissions regulations and that we hold or
have applied for all permits necessary to our operations.
Global Warming and Climate
Control. Recent scientific studies have suggested that
emissions of certain gases, commonly referred to as “greenhouse gases”,
including carbon dioxide and methane, may be contributing to warming of the
Earth’s atmosphere. In response to such studies, President Obama has
expressed support for, and it is anticipated that the current session of
Congress will consider legislation to regulate emissions of greenhouse
gases. In addition, more than one-third of the states, either
individually or through multi-state regional initiatives, have already taken
legal measures to reduce emission of these gases, primarily through the planned
development of greenhouse gas emission inventories and/or regional greenhouse
gas cap and trade programs. Also, as a result of the U.S. Supreme
Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA,
the EPA may be required to regulate greenhouse gas emissions from mobile sources
(e.g., cars and trucks) even if Congress does not adopt new legislation
specifically addressing emissions of greenhouse gases. The Court’s
holding in Massachusetts that greenhouse
gases fall under the federal Clean Air Act’s definition of “air pollutant” may
also result in future regulation of greenhouse gas emissions from stationary
sources under certain Clean Air Act programs. More recently, in July
2008, EPA released an “Advance Notice of Proposed Rulemaking,” regarding
possible future regulation of greenhouse gases under the Clean Air
Act. New legislation or regulatory programs that restrict emissions
of greenhouse gases in areas where we operate could adversely affect our
operations by increasing costs. The cost increases would result from
the potential new requirements to install additional emission control equipment
and by increasing our monitoring and record-keeping burden.
Consideration of Environmental
Issues in Connection with Governmental Approvals. Our
operations frequently require licenses, permits and/or other governmental
approvals. Several federal statutes, including the Outer Continental
Shelf Lands Act, the National Environmental Policy Act, and the Coastal Zone
Management Act require federal agencies to evaluate environmental issues in
connection with granting such approvals and/or taking other major agency
actions. The Outer Continental Shelf Lands Act, for instance,
requires the U.S. Department of Interior to evaluate whether certain proposed
activities would cause serious harm or damage to the marine, coastal or human
environment. Similarly, the National Environmental Policy Act
requires the Department of Interior and other federal agencies to evaluate major
agency actions having the potential to significantly impact the
environment. In the course of such evaluations, an agency would have
to prepare an environmental assessment and, potentially, an environmental impact
statement. The Coastal Zone Management Act, on the other hand, aids
states in developing a coastal management program to protect the coastal
environment from growing demands associated with various uses, including
offshore oil and gas development. In obtaining various approvals from
the Department of Interior, we must certify that we will conduct our activities
in a manner consistent with these regulations.
Employees
As of
December 31, 2008, we had 470 full-time employees, including 29 senior level
geoscientists and 45 petroleum engineers. Our employees are not
represented by any labor unions. We consider our relations with our
employees to be satisfactory and have never experienced a work stoppage or
strike.
Available
Information
We
maintain a website at the address www.whiting.com. We
are not including the information contained on our website as part of, or
incorporating it by reference into, this report. We make available
free of charge (other than an investor’s own Internet access charges) through
our website our Annual Report on Form 10-K, quarterly reports on Form 10-Q and
current reports on Form 8-K, and amendments to these reports, as soon as
reasonably practicable after we electronically file such material with, or
furnish such material to, the Securities and Exchange Commission.
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Risk
Factors
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Each of
the risks described below should be carefully considered, together with all of
the other information contained in this Annual Report on Form 10-K, before
making an investment decision with respect to our securities. If any
of the following risks develop into actual events, our business, financial
condition or results of operations could be materially and adversely affected,
and you may lose all or part of your investment.
Oil
and natural gas prices are very volatile. An extended period of oil
and natural gas prices similar to or below the prices in effect at December 31,
2008 may adversely affect our business, financial condition, results of
operations or cash flows.
The oil and gas markets are very
volatile, and we cannot predict future oil and natural gas
prices. The price we receive for our oil and natural gas production
heavily influences our revenue, profitability, access to capital and future rate
of growth. The prices we receive for our production and the levels of
our production depend on numerous factors beyond our control. These
factors include, but are not limited to, the
following:
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changes
in global supply and demand for oil and gas;
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the
actions of the Organization of Petroleum Exporting
Countries;
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the
price and quantity of imports of foreign oil and gas;
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political
and economic conditions, including embargoes, in oil-producing countries
or affecting other oil-producing activity;
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the
level of global oil and gas exploration and production
activity;
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the
level of global oil and gas inventories;
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weather
conditions;
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technological
advances affecting energy consumption;
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domestic
and foreign governmental regulations;
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proximity
and capacity of oil and gas pipelines and other transportation
facilities;
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the
price and availability of competitors’ supplies of oil and gas in captive
market areas; and
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the
price and availability of alternative
fuels.
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Furthermore,
the recent worldwide financial and credit crisis has reduced the availability of
liquidity and credit to fund the continuation and expansion of industrial
business operations worldwide. The shortage of liquidity and credit
combined with recent substantial losses in worldwide equity markets has lead to
a worldwide economic recession. The slowdown in economic activity caused
by such recession has reduced worldwide demand for energy and resulted in lower
oil and natural gas prices. Oil prices declined from record levels in
early July 2008 of over $140 per Bbl to below $40 per Bbl in December 2008,
while natural gas prices have declined from over $13 per Mcf to below $6 per Mcf
over the same period. In addition, actual and forecasted prices for 2009
have declined since year-end.
Lower oil
and natural gas prices may not only decrease our revenues on a per unit basis
but also may reduce the amount of oil and natural gas that we can produce
economically and therefore potentially lower our reserve bookings. A
substantial or extended decline in oil or natural gas prices may result in
impairments of our proved oil and gas properties and may materially and
adversely affect our future business, financial condition, results of
operations, liquidity or ability to finance planned capital expenditures.
To the extent commodity prices received from production are insufficient
to fund planned capital expenditures, we will be required to reduce spending or
borrow any such shortfall. Lower oil and natural gas prices may also
reduce the amount of our borrowing base under our credit agreement, which is
determined at the discretion of the lenders based on the collateral value of our
proved reserves that have been mortgaged to the lenders, and is subject to
regular redeterminations on May 1 and November 1 of each year, as well as
special redeterminations described in the credit agreement.
The
global financial crisis may have impacts on our business and financial condition
that we currently cannot predict.
The
continued credit crisis and related turmoil in the global financial system may
have an impact on our business and our financial condition, and we may face
challenges if conditions in the financial markets do not improve. Our
ability to access the capital markets may be restricted at a time when we would
like, or need, to raise financing, which could have an impact on our flexibility
to react to changing economic and business conditions. The economic
situation could have an impact on our lenders or customers, causing them to fail
to meet their obligations to us. Additionally, market conditions could
have an impact on our commodity hedging arrangements if our counterparties are
unable to perform their obligations or seek bankruptcy protection.
Drilling
for and producing oil and natural gas are high risk activities with many
uncertainties that could adversely affect our business, financial condition or
results of operations.
Our
future success will depend on the success of our development, exploitation,
production and exploration activities. Our oil and natural gas exploration
and production activities are subject to numerous risks beyond our control,
including the risk that drilling will not result in commercially viable oil or
natural gas production. Our decisions to purchase, explore, develop or
otherwise exploit prospects or properties will depend in part on the evaluation
of data obtained through geophysical and geological analyses, production data
and engineering studies, the results of which are often inconclusive or subject
to varying interpretations. Please read “— Reserve estimates depend
on many assumptions that may turn out to be inaccurate . . .” later in this Item
for a discussion of the uncertainty involved in these processes. Our cost
of drilling, completing and operating wells is often uncertain before drilling
commences. Overruns in budgeted expenditures are common risks that can
make a particular project uneconomical. Further, many factors may curtail,
delay or cancel drilling, including the following:
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delays
imposed by or resulting from compliance with regulatory
requirements;
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pressure
or irregularities in geological formations;
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shortages
of or delays in obtaining qualified personnel or equipment, including
drilling rigs and CO2;
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equipment
failures or accidents;
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adverse
weather conditions, such as freezing temperatures, hurricanes and
storms;
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reductions
in oil and natural gas prices; and
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title
problems.
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Prospects
that we decide to drill may not yield oil or gas in commercially viable
quantities.
We
describe some of our current prospects and our plans to explore those prospects
in this Annual Report on Form 10-K. A prospect is a property on which we
have identified what our geoscientists believe, based on available seismic and
geological information, to be indications of oil or gas. Our prospects are
in various stages of evaluation, ranging from a prospect which is ready to drill
to a prospect that will require substantial additional seismic data processing
and interpretation. There is no way to predict in advance of drilling and
testing whether any particular prospect will yield oil or gas in sufficient
quantities to recover drilling or completion costs or to be economically viable.
The use of seismic data and other technologies and the study of producing
fields in the same area will not enable us to know conclusively prior to
drilling whether oil or gas will be present or, if present, whether oil or gas
will be present in commercial quantities. In addition, because of the wide
variance that results from different equipment used to test the wells, initial
flowrates may not be indicative of sufficient oil or gas quantities in a
particular field. The analogies we draw from available data from
other wells, from more fully explored prospects, or from producing fields may
not be applicable to our drilling prospects. We may terminate our drilling
program for a prospect if results do not merit further investment.
Our
identified drilling locations are scheduled out over several years, making them
susceptible to uncertainties that could materially alter the occurrence or
timing of their drilling.
We have
specifically identified and scheduled drilling locations as an estimation of our
future multi-year drilling activities on our existing acreage. As of
December 31, 2008, we had identified a drilling inventory of over
1,400 gross drilling locations. These scheduled drilling locations
represent a significant part of our growth strategy. Our ability to drill
and develop these locations depends on a number of uncertainties, including oil
and natural gas prices, the availability of capital, costs of oil field goods
and services, drilling results, regulatory approvals and other factors.
Because of these uncertainties, we do not know if the numerous potential
drilling locations we have identified will ever be drilled or if we will be able
to produce oil or gas from these or any other potential drilling locations.
As such, our actual drilling activities may materially differ from those
presently identified, which could adversely affect our business.
We
have been an early entrant into new or emerging plays. As a result,
our drilling results in these areas are uncertain, and the value of our
undeveloped acreage will decline and we may incur impairment charges if drilling
results are unsuccessful.
While our
costs to acquire undeveloped acreage in new or emerging plays have generally
been less than those of later entrants into a developing play, our drilling
results in these areas are more uncertain than drilling results in areas that
are developed and producing. Since new or emerging plays have limited or
no production history, we are unable to use past drilling results in those areas
to help predict our future drilling results. Therefore, our cost of
drilling, completing and operating wells in these areas may be higher than
initially expected, and the value of our undeveloped acreage will decline if
drilling results are unsuccessful. Furthermore, if drilling results are
unsuccessful, we may be required to write down the carrying value of our
undeveloped acreage in new or emerging plays. During the fourth quarter of
2008, we recorded a $10.9 million non-cash charge for the partial
impairment of unproved properties in the central Utah Hingeline play. We
may also incur such impairment charges in the future, which could have a
material adverse effect on our results of operations in the period
taken.
Our
use of enhanced recovery methods creates uncertainties that could adversely
affect our results of operations and financial condition.
One of
our business strategies is to commercially develop oil reservoirs using enhanced
recovery technologies. For example, we inject water and CO2 into
formations on some of our properties to increase the production of oil and
natural gas. The additional production and reserves attributable to the
use of these enhanced recovery methods are inherently difficult to predict.
If our enhanced recovery programs do not allow for the extraction of oil
and gas in the manner or to the extent that we anticipate, our future results of
operations and financial condition could be materially adversely affected.
Additionally, our ability to utilize CO2 as an
enhanced recovery technique is subject to our ability to obtain sufficient
quantities of CO2. Our
CO2
contracts permit the suppliers to reduce the amount of CO2 they
provide to us in certain circumstances. If this occurs, we may not have
sufficient CO2 to
produce oil and natural gas in the manner or to the extent that we anticipate.
These contracts are also structured as “take-or-pay” arrangements, which
require us to continue to make payments even if we decide to terminate or reduce
our use of CO2 as part of
our enhanced recovery techniques.
The
development of the proved undeveloped reserves in the North Ward Estes and
Postle fields may take longer and may require higher levels of capital
expenditures than we currently anticipate.
As of
December 31, 2008, undeveloped reserves comprised 46.5% of the North Ward
Estes field’s total estimated proved reserves and 16.8% of the Postle field’s
total estimated proved reserves. To fully develop these reserves, we
expect to incur future development costs of $410.1 million at the North
Ward Estes field and $84.5 million at the Postle field. Together,
these fields encompass 58% of our total estimated future development costs of
$857.1 million related to proved undeveloped reserves. Development of
these reserves may take longer and require higher levels of capital expenditures
than we currently anticipate. In addition, the development of these
reserves will require the use of enhanced recovery techniques, including water
flood and CO2 injection
installations, the success of which is less predictable than traditional
development techniques. Therefore, ultimate recoveries from these fields
may not match current expectations.
If
oil and natural gas prices decrease, we may be required to take write-downs of
the carrying values of our oil and gas properties.
Accounting
rules require that we review periodically the carrying value of our oil and gas
properties for possible impairment. Based on specific market factors and
circumstances at the time of prospective impairment reviews, which may include
depressed oil and natural gas prices, and the continuing evaluation of
development plans, production data, economics and other factors, we may be
required to write down the carrying value of our oil and gas properties. A
write-down constitutes a non-cash charge to earnings. We may incur
impairment charges in the future, which could have a material adverse effect on
our results of operations in the period taken.
Reserve
estimates depend on many assumptions that may turn out to be inaccurate.
Any material inaccuracies in these reserve estimates or underlying
assumptions will materially affect the quantities and present value of our
reserves.
The
process of estimating oil and natural gas reserves is complex. It requires
interpretations of available technical data and many assumptions, including
assumptions relating to economic factors. Any significant inaccuracies in
these interpretations or assumptions could materially affect the estimated
quantities and present value of reserves referred to in this
report.
In order
to prepare our estimates, we must project production rates and timing of
development expenditures. We must also analyze available geological,
geophysical, production and engineering data. The extent, quality and
reliability of this data can vary. The process also requires economic
assumptions about matters such as oil and natural gas prices, drilling and
operating expenses, capital expenditures, taxes and availability of funds.
Therefore, estimates of oil and natural gas reserves are inherently
imprecise.
Actual
future production, oil and natural gas prices, revenues, taxes, exploration and
development expenditures, operating expenses and quantities of recoverable oil
and natural gas reserves most likely will vary from our estimates. Any
significant variance could materially affect the estimated quantities and
present value of reserves referred to in this report. In addition, we may
adjust estimates of proved reserves to reflect production history, results of
exploration and development, prevailing oil and natural gas prices and other
factors, many of which are beyond our control.
You
should not assume that the present value of future net revenues from our proved
reserves, as referred to in this report, is the current market value of our
estimated oil and natural gas reserves. In accordance with SEC
requirements, we generally base the estimated discounted future net cash flows
from our proved reserves on prices and costs on the date of the estimate.
Actual future prices and costs may differ materially from those used in
the present value estimate. If natural gas prices decline by $0.10 per
Mcf, then the standardized measure of discounted future net cash flows of our
estimated proved reserves as of December 31, 2008 would have decreased from
$1,376.4 million to $1,366.0 million. If oil prices decline by
$1.00 per Bbl, then the standardized measure of discounted future net cash flows
of our estimated proved reserves as of December 31, 2008 would have
decreased from $1,376.4 million to $1,326.1 million.
Our
debt level and the covenants in the agreements governing our debt could
negatively impact our financial condition, results of operations, cash flows and
business prospects.
As of
December 31, 2008, we had $620.0 million in borrowings and
$2.8 million in letters of credit outstanding under Whiting Oil and Gas’
credit agreement with $277.2 million of available borrowing capacity, as
well as $620.0 million of senior subordinated notes outstanding. We
are permitted to incur additional indebtedness, provided we meet certain
requirements in the indentures governing our senior subordinated notes and
Whiting Oil and Gas’ credit agreement.
Our level of indebtedness and the
covenants contained in the agreements governing our debt could have important
consequences for our operations, including:
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requiring
us to dedicate a substantial portion of our cash flow from operations to
required payments on debt, thereby reducing the availability of cash flow
for working capital, capital expenditures and other general business
activities;
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limiting
our ability to obtain additional financing in the future for working
capital, capital expenditures, acquisitions and general corporate and
other activities;
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limiting
our flexibility in planning for, or reacting to, changes in our business
and the industry in which we operate;
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placing
us at a competitive disadvantage relative to other less leveraged
competitors; and
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making
us vulnerable to increases in interest rates, because debt under Whiting
Oil and Gas’ credit agreement may be at variable
rates.
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We may be
required to repay all or a portion of our debt on an accelerated basis in
certain circumstances. If we fail to comply with the covenants and other
restrictions in the agreements governing our debt, it could lead to an event of
default and the acceleration of our repayment of outstanding debt. Our
ability to comply with these covenants and other restrictions may be affected by
events beyond our control, including prevailing economic and financial
conditions. Moreover, the borrowing base limitation on Whiting Oil and
Gas’ credit agreement is periodically redetermined based on an evaluation of our
reserves. Upon a redetermination, if borrowings in excess of the revised
borrowing capacity were outstanding, we could be forced to repay a portion of
our debt under the credit agreement.
We may
not have sufficient funds to make such repayments. If we are unable to
repay our debt out of cash on hand, we could attempt to refinance such debt,
sell assets or repay such debt with the proceeds from an equity offering.
We may not be able to generate sufficient cash flow to pay the interest on
our debt or future borrowings, and equity financings or proceeds from the sale
of assets may not be available to pay or refinance such debt. The terms of
our debt, including Whiting Oil and Gas’ credit agreement, may also prohibit us
from taking such actions. Factors that will affect our ability to raise
cash through an offering of our capital stock, a refinancing of our debt or a
sale of assets include financial market conditions and our market value and
operating performance at the time of such offering or other financing. We
may not be able to successfully complete any such offering, refinancing or sale
of assets.
The instruments
governing our indebtedness contain various covenants limiting the discretion of
our management in operating our business.
The
indentures governing our senior subordinated notes and Whiting Oil and Gas’
credit agreement contain various restrictive covenants that may limit our
management’s discretion in certain respects. In particular, these
agreements will limit our and our subsidiaries’ ability to, among other
things:
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pay
dividends on, redeem or repurchase our capital stock or redeem or
repurchase our subordinated debt;
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make
loans to others;
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make
investments;
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incur
additional indebtedness or issue preferred stock;
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create
certain liens;
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sell
assets;
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enter
into agreements that restrict dividends or other payments from our
restricted subsidiaries to us;
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consolidate,
merge or transfer all or substantially all of the assets of us and our
restricted subsidiaries taken as a whole;
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engage
in transactions with affiliates;
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enter
into hedging contracts;
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create
unrestricted subsidiaries; and
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enter
into sale and leaseback
transactions.
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In
addition, Whiting Oil and Gas’ credit agreement 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 of greater than 1 to 1. Also, the indentures under
which we issued our senior subordinated notes restrict us from incurring
additional indebtedness, subject to certain exceptions, unless our fixed charge
coverage ratio (as defined in the indentures) is at least 2.0 to 1. If we
were in violation of this covenant, then we may not be able to incur additional
indebtedness, including under Whiting Oil and Gas’ credit agreement. A
substantial or extended decline in oil or natural gas prices may adversely
affect our ability to comply with these covenants.
If we
fail to comply with the restrictions in the indentures governing our senior
subordinated notes or Whiting Oil and Gas’ credit agreement or any other
subsequent financing agreements, a default may allow the creditors, if the
agreements so provide, to accelerate the related indebtedness as well as any
other indebtedness to which a cross-acceleration or cross-default provision
applies. In addition, lenders may be able to terminate any commitments
they had made to make available further funds.
Our
exploration and development operations require substantial capital, and we may
be unable to obtain needed capital or financing on satisfactory terms, which
could lead to a loss of properties and a decline in our oil and natural gas
reserves.
The oil
and gas industry is capital intensive. We make and expect to continue to
make substantial capital expenditures in our business and operations for the
exploration, development, production and acquisition of oil and natural gas
reserves. To date, we have financed capital expenditures through a
combination of equity and debt issuances, bank borrowings and internally
generated cash flows. We intend to finance future capital expenditures
with cash flow from operations and existing financing arrangements. Our
cash flow from operations and access to capital is subject to a number of
variables, including:
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our
proved reserves;
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the
level of oil and natural gas we are able to produce from existing
wells;
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the
prices at which oil and natural gas are sold; and
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our
ability to acquire, locate and produce new
reserves.
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If our
revenues or the borrowing base under our bank credit agreement decreases as a
result of lower oil and natural gas prices, operating difficulties, declines in
reserves or for any other reason, then we may have limited ability to obtain the
capital necessary to sustain our operations at current levels. We may,
from time to time, need to seek additional financing. There can be no
assurance as to the availability or terms of any additional
financing.
If
additional capital is needed, we may not be able to obtain debt or equity
financing on terms favorable to us, or at all. If cash generated by
operations or available under our revolving credit facility is
not sufficient to meet our capital requirements, the failure to obtain
additional financing could result in a curtailment of our operations relating to
the exploration and development of our prospects, which in turn could lead to a
possible loss of properties and a decline in our oil and natural gas
reserves.
Our
acquisition activities may not be successful.
As part
of our growth strategy, we have made and may continue to make acquisitions of
businesses and properties. However, suitable acquisition candidates may
not continue to be available on terms and conditions we find acceptable, and
acquisitions pose substantial risks to our business, financial condition and
results of operations. In pursuing acquisitions, we compete with other
companies, many of which have greater financial and other resources to acquire
attractive companies and properties. The following are some of the risks
associated with acquisitions, including any completed or future
acquisitions:
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some
of the acquired businesses or properties may not produce revenues,
reserves, earnings or cash flow at anticipated levels;
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we
may assume liabilities that were not disclosed to us or that exceed our
estimates;
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we
may be unable to integrate acquired businesses successfully and realize
anticipated economic, operational and other benefits in a timely manner,
which could result in substantial costs and delays or other operational,
technical or financial problems;
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acquisitions
could disrupt our ongoing business, distract management, divert resources
and make it difficult to maintain our current business standards, controls
and procedures; and
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we
may issue additional equity or debt securities related to future
acquisitions.
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Substantial
acquisitions or other transactions could require significant external capital
and could change our risk and property profile.
In order
to finance acquisitions of additional producing or undeveloped properties,
we may need to alter or increase our capitalization substantially through the
issuance of debt or equity securities, the sale of production payments or other
means. These changes in capitalization may significantly affect our risk
profile. Additionally, significant acquisitions or other transactions can
change the character of our operations and business. The character of the
new properties may be substantially different in operating or geological
characteristics or geographic location than our existing properties.
Furthermore, we may not be able to obtain external funding for future
acquisitions or other transactions or to obtain external funding on terms
acceptable to us.
Properties
that we acquire may not produce as projected, and we may be unable to identify
liabilities associated with the properties or obtain protection from sellers
against them.
Our
business strategy includes a continuing acquisition program. From 2004
through 2008, we completed 13 separate acquisitions of producing properties with
a combined purchase price of $1,823.8 million for estimated proved reserves as
of the effective dates of the acquisitions of 226.9 MMBOE. The
successful acquisition of producing properties requires assessments of many
factors, which are inherently inexact and may be inaccurate, including the
following:
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the
amount of recoverable reserves;
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future
oil and natural gas prices;
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estimates
of operating costs;
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estimates
of future development costs;
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timing
of future development costs;
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estimates
of the costs and timing of plugging and
abandonment; and
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potential
environmental and other
liabilities.
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Our
assessment will not reveal all existing or potential problems, nor will it
permit us to become familiar enough with the properties to assess fully their
capabilities and deficiencies. In the course of our due diligence, we may
not inspect every well, platform or pipeline. Inspections may not reveal
structural and environmental problems, such as pipeline corrosion or groundwater
contamination, when they are made. We may not be able to obtain
contractual indemnities from the seller for liabilities that it created.
We may be required to assume the risk of the physical condition of the
properties in addition to the risk that the properties may not perform in
accordance with our expectations.
Seasonal
weather conditions and lease stipulations adversely affect our ability to
conduct drilling activities in some of the areas where we operate.
Oil and
gas operations in the Rocky Mountains are adversely affected by seasonal weather
conditions and lease stipulations designed to protect various wildlife. In
certain areas, drilling and other oil and gas activities can only be conducted
during the spring and summer months. This limits our ability to operate in
those areas and can intensify competition during those months for drilling rigs,
oil field equipment, services, supplies and qualified personnel, which may lead
to periodic shortages. Resulting shortages or high costs could delay our
operations and materially increase our operating and capital costs.
The
differential between the NYMEX or other benchmark price of oil and natural gas
and the wellhead price we receive could have a material adverse effect on our
results of operations, financial condition and cash flows.
The
prices that we receive for our oil and natural gas production generally trade at
a discount to the relevant benchmark prices such as NYMEX. The difference
between the benchmark price and the price we receive is called a differential.
We cannot accurately predict oil and natural gas differentials.
Increases in the differential between the benchmark price for oil and
natural gas and the wellhead price we receive could have a material adverse
effect on our results of operations, financial condition and cash
flows.
We
may incur substantial losses and be subject to substantial liability claims as a
result of our oil and gas operations.
We are
not insured against all risks. Losses and liabilities arising from
uninsured and underinsured events could materially and adversely affect our
business, financial condition or results of operations. Our oil and natural gas
exploration and production activities are subject to all of the operating risks
associated with drilling for and producing oil and natural gas, including the
possibility of:
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environmental
hazards, such as uncontrollable flows of oil, gas, brine, well fluids,
toxic gas or other pollution into the environment, including groundwater
and shoreline contamination;
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abnormally
pressured formations;
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mechanical
difficulties, such as stuck oil field drilling and service tools and
casing collapse;
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fires
and explosions;
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personal
injuries and death; and
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natural
disasters.
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Any of
these risks could adversely affect our ability to conduct operations or result
in substantial losses to our company. We may elect not to obtain insurance
if we believe that the cost of available insurance is excessive relative to the
risks presented. In addition, pollution and environmental risks generally
are not fully insurable. If a significant accident or other event occurs
and is not fully covered by insurance, then it could adversely affect
us.
We
have limited control over activities on properties we do not operate, which
could reduce our production and revenues.
If we do
not operate the properties in which we own an interest, we do not have control
over normal operating procedures, expenditures or future development of
underlying properties. The failure of an operator of our wells to
adequately perform operations or an operator’s breach of the applicable
agreements could reduce our production and revenues. The success and
timing of our drilling and development activities on properties operated by
others therefore depends upon a number of factors outside of our control,
including the operator’s timing and amount of capital expenditures, expertise
and financial resources, inclusion of other participants in drilling wells, and
use of technology. Because we do not have a majority interest in most
wells we do not operate, we may not be in a position to remove the operator in
the event of poor performance.
Our
use of 3-D seismic data is subject to interpretation and may not accurately
identify the presence of oil and gas, which could adversely affect the results
of our drilling operations.
Even when
properly used and interpreted, 3-D seismic data and visualization techniques are
only tools used to assist geoscientists in identifying subsurface structures and
hydrocarbon indicators and do not enable the interpreter to know whether
hydrocarbons are, in fact, present in those structures. In addition, the
use of 3-D seismic and other advanced technologies requires greater predrilling
expenditures than traditional drilling strategies, and we could incur losses as
a result of such expenditures. Thus, some of our drilling activities may
not be successful or economical, and our overall drilling success rate or our
drilling success rate for activities in a particular area could decline.
We often gather 3-D seismic data over large areas. Our
interpretation of seismic data delineates for us those portions of an area that
we believe are desirable for drilling. Therefore, we may choose not to
acquire option or lease rights prior to acquiring seismic data, and in many
cases, we may identify hydrocarbon indicators before seeking option or lease
rights in the location. If we are not able to lease those locations on
acceptable terms, it would result in our having made substantial expenditures to
acquire and analyze 3-D seismic data without having an opportunity to attempt to
benefit from those expenditures.
Market
conditions or operational impediments may hinder our access to oil and gas
markets or delay our production.
In
connection with our continued development of oil and gas properties, we may be
disproportionately exposed to the impact of delays or interruptions of
production from wells in these properties, caused by transportation capacity
constraints, curtailment of production or the interruption of transporting oil
and gas volumes produced. In addition, market conditions or a lack of
satisfactory oil and gas transportation arrangements may hinder our access to
oil and gas markets or delay our production. The availability of a ready
market for our oil and natural gas production depends on a number of factors,
including the demand for and supply of oil and natural gas and the proximity of
reserves to pipelines and terminal facilities. Our ability to market our
production depends substantially on the availability and capacity of gathering
systems, pipelines and processing facilities owned and operated by
third-parties. Additionally, entering into arrangements for these services
exposes us to the risk that third parties will default on their obligations
under such arrangements. Our failure to obtain such services on acceptable
terms or the default by a third party on their obligation to provide such
services could materially harm our business. We may be required to shut in
wells for a lack of a market or because access to gas pipelines, gathering
systems or processing facilities may be limited or unavailable. If that
were to occur, then we would be unable to realize revenue from those wells until
production arrangements were made to deliver the production to
market.
We
are subject to complex laws that can affect the cost, manner or feasibility of
doing business.
Exploration,
development, production and sale of oil and natural gas are subject to extensive
federal, state, local and international regulation. We may be required to
make large expenditures to comply with governmental regulations. Matters
subject to regulation include:
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discharge
permits for drilling operations;
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drilling
bonds;
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reports
concerning operations;
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the
spacing of wells;
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unitization
and pooling of properties; and
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taxation.
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Under
these laws, we could be liable for personal injuries, property damage and other
damages. Failure to comply with these laws also may result in the
suspension or termination of our operations and subject us to administrative,
civil and criminal penalties. Moreover, these laws could change in ways
that could substantially increase our costs. Any such liabilities,
penalties, suspensions, terminations or regulatory changes could materially
adversely affect our financial condition and results of operations.
Our
operations may incur substantial liabilities to comply with environmental laws
and regulations.
Our oil
and gas operations are subject to stringent federal, state and local laws and
regulations relating to the release or disposal of materials into the
environment or otherwise relating to environmental protection. These laws
and regulations may require the acquisition of a permit before drilling
commences; restrict the types, quantities, and concentration of materials that
can be released into the environment in connection with drilling and production
activities; limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands, and other protected areas; and impose substantial
liabilities for pollution resulting from our operations. Failure to comply
with these laws and regulations may result in the assessment of administrative,
civil, and criminal penalties, incurrence of investigatory or remedial
obligations, or the imposition of injunctive relief. Under these
environmental laws and regulations, we could be held strictly liable for the
removal or remediation of previously released materials or property
contamination regardless of whether we were responsible for the release or if
our operations were standard in the industry at the time they were performed.
Federal law and some state laws also allow the government to place a lien
on real property for costs incurred by the government to address contamination
on the property.
Changes
in environmental laws and regulations occur frequently, and any changes that
result in more stringent or costly material handling, storage, transport,
disposal or cleanup requirements could require us to make significant
expenditures to maintain compliance and may otherwise have a material adverse
effect on our results of operations, competitive position, or financial
condition as well as those of the oil and gas industry in general. For
instance, recent scientific studies have suggested that emissions of certain
gases, commonly referred to as “greenhouse gases”, including carbon dioxide and
methane, may be contributing to warming of the Earth’s atmosphere. In
response to such studies, President Obama has expressed support for, and it is
anticipated that the current session of Congress will consider legislation to
regulate emissions of greenhouse gases. In addition, more than
one-third of the states, either individually or through multi-state regional
initiatives, have already taken legal measures to reduce emission of these
gases, primarily through the planned development of greenhouse gas emission
inventories and/or regional greenhouse gas cap and trade
programs. Also, as a result of the U.S. Supreme Court’s decision on
April 2, 2007 in Massachusetts, et al. v. EPA,
the EPA may be required to regulate greenhouse gas emissions from mobile sources
(e.g., cars and trucks) even if Congress does not adopt new legislation
specifically addressing emissions of greenhouse gases. The Court’s
holding in Massachusetts that greenhouse
gases fall under the federal Clean Air Act’s definition of “air pollutant” may
also result in future regulation of greenhouse gas emissions from stationary
sources under certain Clean Air Act programs. More recently, in July
2008, the EPA released an “Advance Notice of Proposed Rulemaking,” regarding
possible future regulation of greenhouse gases under the Clean Air
Act. New legislation or regulatory programs that restrict emissions
of greenhouse gases in areas where we operate could adversely affect our
operations by increasing costs. The cost increases would result from
the potential new requirements to install additional emission control equipment
and by increasing our monitoring and record-keeping burden.
Unless
we replace our oil and natural gas reserves, our reserves and production will
decline, which would adversely affect our cash flows and results of
operations.
Unless we
conduct successful development, exploitation and exploration activities or
acquire properties containing proved reserves, our proved reserves will decline
as those reserves are produced. Producing oil and natural gas reservoirs
generally are characterized by declining production rates that
vary depending upon reservoir characteristics and other factors. Our
future oil and natural gas reserves and production, and therefore our cash flow
and income, are highly dependent on our success in efficiently developing and
exploiting our current reserves and economically finding or acquiring additional
recoverable reserves. We may not be able to develop, exploit, find or
acquire additional reserves to replace our current and future
production.
The
loss of senior management or technical personnel could adversely affect
us.
To a
large extent, we depend on the services of our senior management and technical
personnel. The loss of the services of our senior management or technical
personnel, including James J. Volker, our Chairman, President and Chief
Executive Officer; James T. Brown, our Senior Vice President; Rick A. Ross, our
Vice President, Operations; Peter W. Hagist, our Vice President, Permian
Operations; J. Douglas Lang, our Vice President, Reservoir
Engineering/Acquisitions; David M. Seery, our Vice President of Land; Michael J.
Stevens, our Vice President and Chief Financial Officer; or Mark R. Williams,
our Vice President, Exploration and Development, could have a material adverse
effect on our operations. We do not maintain, nor do we plan to obtain,
any insurance against the loss of any of these individuals.
The
unavailability or high cost of additional drilling rigs, equipment, supplies,
personnel and oil field services could adversely affect our ability to execute
our exploration and development plans on a timely basis or within our
budget.
Shortages
or the high cost of drilling rigs, equipment, supplies or personnel could delay
or adversely affect our exploration and development operations, which could have
a material adverse effect on our business, financial condition, results of
operations or cash flows.
Competition
in the oil and gas industry is intense, which may adversely affect our ability
to compete.
We
operate in a highly competitive environment for acquiring properties, marketing
oil and gas and securing trained personnel. Many of our competitors
possess and employ financial, technical and personnel resources substantially
greater than ours, which can be particularly important in the areas in which we
operate. Those companies may be able to pay more for productive oil and
gas properties and exploratory prospects and to evaluate, bid for and purchase a
greater number of properties and prospects than our financial or personnel
resources permit. Our ability to acquire additional prospects and to find
and develop reserves in the future will depend on our ability to evaluate and
select suitable properties and to consummate transactions in a highly
competitive environment. Also, there is substantial competition for
available capital for investment in the oil and gas industry. We may not
be able to compete successfully in the future in acquiring prospective reserves,
developing reserves, marketing hydrocarbons, attracting and retaining quality
personnel and raising additional capital.
Our
use of oil and natural gas price hedging contracts involves credit risk and may
limit future revenues from price increases and result in significant
fluctuations in our net income.
We enter
into hedging transactions of our oil and natural gas production to reduce our
exposure to fluctuations in the price of oil and natural gas. Our hedging
transactions to date have consisted of financially settled crude oil and natural
gas forward sales contracts, primarily costless collars, placed with major
financial institutions. As of December 31, 2008, we had contracts,
which include our 24.2% share of the Whiting USA Trust I hedges, covering
the sale in 2009 of between 489,190 and 556,129 barrels of oil per month
and between 44,874 and 52,353 MMBtu of natural gas per month. All our
oil hedges will expire by November 2013, and all our natural gas hedges will
expire by December 2012. See “Quantitative and Qualitative Disclosure
about Market Risk” for pricing and a more detailed discussion of our hedging
transactions.
We may in
the future enter into these and other types of hedging arrangements to reduce
our exposure to fluctuations in the market prices of oil and natural gas.
Hedging transactions expose us to risk of financial loss in some circumstances,
including if production is less than expected, the other party to the contract
defaults on its obligations or there is a change in the expected differential
between the underlying price in the hedging agreement and actual prices
received. Hedging transactions may limit the benefit we may otherwise
receive from increases in the price for oil and natural gas. Furthermore,
if we do not engage in hedging transactions, then we may be more adversely
affected by declines in oil and natural gas prices than our competitors who
engage in hedging transactions. Additionally, hedging transactions may
expose us to cash margin requirements.
|
Item 1B.
|
Unresolved Staff
Comments
|
None.
|
Item 2.
|
Properties
|
Summary
of Oil and Gas Properties and Projects
Permian
Basin Region
Our
Permian Basin operations include assets in Texas and New Mexico. As
of December 31, 2008, the Permian Basin region contributed 97.7 MMBOE (90%
oil) of estimated proved reserves to our portfolio of operations, which
represented 41% of our total estimated proved reserves and contributed 11.7
MBOE/d of average daily production in December 2008.
North Ward Estes
Field. The North Ward Estes field includes six base leases
with 100% working interest in approximately 58,000 gross and net acres in Ward
and Winkler Counties, Texas. The Yates Formation at 2,600 feet is the
primary producing zone with additional production from other zones including the
Queen at 3,000 feet. In the North Ward Estes field, the estimated
proved reserves as of December 31, 2008 were 29% PDP, 25% PDNP and 46%
PUD.
The North
Ward Estes field is responding positively to our water and CO2 floods,
which we initiated in May 2007. As of December 31, 2008, we were
injecting 123 MMcf/d of CO2 in this
field. Production from the field has increased 29% from 5.1 MBOE/d in
December 2007 to 6.6 MBOE/d in December 2008. In this field, we are
developing new and reactivated wells for water and CO2 injection
and production purposes.
Keystone South, Martin and Flying W
Fields. We operate these three fields located on the Western
edge of the Midland Basin. Production is from the Clearfork
Formation, with additional production from the Wichita, Wolfcamp, Devonian,
Silurian, McKee and Ellenburger Formations. During 2008, we drilled
three wells in the Martin field and ten wells in the Keystone South
field. The Keystone drilling program was in part to re-configure the
waterflood and to drill additional wells into a Devonian structure on the east
side of the lease that was discovered during 2007.
Rocky
Mountain Region
Our Rocky
Mountain operations include assets in the states of North Dakota, Montana,
Colorado, Utah, Wyoming and California. As of December 31, 2008,
our estimated proved reserves in the Rocky Mountain region were 83.2 MMBOE (59%
oil), which represented 35% of our total estimated proved reserves and
contributed 27.7 MBOE/d of average daily production in December
2008.
Sanish Field. Our
Sanish area in Mountrail County, North Dakota encompasses approximately 125,600
gross (83,600 net) acres. December 2008 net production in the Sanish
field averaged 7.5 MBOE/d, an 832% increase from 0.8 MBOE/d in December
2007. As of February 13, 2009, we have participated in 69 wells (39
operated) that target the Bakken formation, of which 54 are producing, eight are
in the process of completion and seven are being drilled. Of these
operated wells, 23 were completed in 2008. In order to process the
produced gas stream from the Sanish wells, we constructed and brought on stream
the Robinson Lake Gas Plant. The first phase of this plant began
processing gas in May 2008, and in December 2008 we completed the construction
of the second phase. We expect the 17-mile oil line connecting the
Sanish field to the Enbridge pipeline in Stanley, North Dakota to be in service
at the end of the second quarter of 2009.
Parshall
Field. Immediately east of the Sanish field is the Parshall
field, where we own interests in approximately 73,800 gross (18,300 net)
acres. Our net production from the Parshall field averaged 6.7 MBOE/d
in December 2008, a 345% increase from 1.5 MBOE/d in December
2007. As of February 13, 2009, we have participated in 97 Bakken
wells, the majority of which are operated by EOG Resources, Inc., of which 86
are producing, seven are in the process of completion and four are
drilling. Of these wells, 64 were completed in 2008.
Lewis & Clark
Prospect. We have assembled approximately 181,200 gross
(111,500 net) acres in our Lewis & Clark prospect along the Bakken Shale
pinch-out in the southern Williston Basin. In this area, the Upper
Bakken shale is thermally mature, moderately over pressured, and has charged
reservoir zones within the immediately underlying Three Forks
formation.
Flat Rock
Field. We acquired the Flat Rock Field in May 2008 and took
over operations June 1, 2008. In the Flat Rock field area in Uintah
County, Utah, we have an acreage position consisting of approximately 22,000
gross (11,500 net) acres. We recently completed two wells in the
Entrada formation that had initial gross production rates of 4.1 MMcf/d and 9.3
MMcf/d.
Sulphur Creek
Field. In the Sulphur Creek field in Rio Blanco County,
Colorado in the Piceance Basin, we own approximately 8,400 gross (4,300 net)
acres in the Sulphur Creek field area. We drilled three wells in Jimmy Gulch in
2008. As of February 13, 2009, the three wells were producing at a
combined net rate of 3.0 MMcf/d.
Hatfield
Prospect. In southern Wyoming in the Hatfield prospect area,
we have a large acreage position covering over 80-square miles and encompassing
approximately 53,200 gross (31,900 net) acres. In this area,
cumulative production from three vertical Niobrara wells drilled by other
operators has ranged from approximately 22.0 MBOE to 124.0 MBOE per
well. In September 2008, we drilled a vertical well to test the
Niobrara formation, as well as a deeper zone. During drilling
operations, oil flowed to the surface and oil shows were seen in the drill
cuttings, and we are currently conducting completion operations on this
well. We believe that current horizontal drilling techniques will
improve recovery compared to vertical drilling used at historic wells in this
area.
Hatch Point
Prospect. At our Hatch Point prospect in San Juan County, Utah
in the Paradox Basin, we have an exploratory horizontal well planned for 2009 in
the Cane Creek zone at an estimated cost of approximately $6.5 million ($3.5
million net).
Utah
Hingeline. We own a 15%, non-operated, working interest in
approximately 170,000 acres of leasehold in the central Utah Hingeline
play. This acreage covers several prospect leads which have been
identified along trend with the Covenant field discovery in Sevier County,
Utah. As part of our acquisition of this property, the operator
agreed to pay 100% of our drilling and completion costs for the first three
wells in the project. The three wells were drilled, but the
hydrocarbons encountered were not determined to be economic, resulting in dry
holes for all three wells.
Mid-Continent
Region
Our
Mid-Continent operations include assets in Oklahoma, Arkansas and
Kansas. As of December 31, 2008, the Mid-Continent region
contributed 39.1 MMBOE (95% oil) of proved reserves to our portfolio of
operations, which represented 16% of our total estimated proved reserves and
contributed 7.2 MBOE/d of average daily production in December
2008. The majority of the proved value within our Mid-Continent
operations is related to properties in the Postle field.
Postle Field. The
Postle field, located in Texas County, Oklahoma, includes five producing units
and one producing lease covering a total of approximately 25,600 gross (24,200
net) acres. Four of the units are currently active CO2 enhanced
recovery projects. Our expansion of the CO2 flood at
the Postle field continues to generate positive results. As of
December 31, 2008, we were injecting 142 MMcf/d of CO2 in this
field. Production from the field has increased 22% from a net 5.8
MBOE/d in December 2007 to a net 7.1 MBOE/d in December
2008. Operations are underway to expand CO2 injection
into the northern part of the fourth unit, HMU, and to optimize flood patterns
in the existing CO2
floods. These expansion projects include the restoration of shut-in
wells and the drilling of new producing and injection wells. In the
Postle field, the estimated proved reserves as of December 31, 2008 were 61%
PDP, 22% PDNP and 17% PUD.
We are
the sole owner of the Dry Trails Gas Plant located in the Postle
field. This gas processing plant utilizes a membrane technology to
separate CO2 gas from
the produced wellhead mixture of hydrocarbon and CO2 gas, so
that the CO2 gas can be
re-injected into the producing formation.
In
addition to the producing assets and processing plant, we have a 60% interest in
the 120-mile TransPetco operated CO2
transportation pipeline, thereby assuring the delivery of CO2 to the
Postle field at a fair tariff. A long-term CO2 purchase
agreement was executed in 2005 to provide the necessary CO2 for the
expansion planned in the field.
Gulf
Coast Region
Our Gulf
Coast operations include assets located in Texas, Louisiana and
Mississippi. As of December 31, 2008, the Gulf Coast region
contributed 10.1 MMBOE (31% oil) of proved reserves to our portfolio of
operations, which represented 4% of our total estimated proved reserves and
contributed 5.0 MBOE/d of average daily production in December
2008.
Edwards Trend. We
own acreage in the Word North, Yoakum, Kawitt, Sweet Home, and Three Rivers
fields along the Edwards Trend in Karnes, Dewitt and Lavaca Counties,
Texas. In 2007, we farmed out a large part of our acreage position to
another operator who is developing the Edwards Trend with horizontal
wellbores. Under the terms of the farmout agreement, we back in for a
25% working interest at payout of the well. In 2008, we participated
in three wells under this agreement.
Michigan
Region
As of
December 31, 2008, our estimated proved reserves in the Michigan region were 9.0
MMBOE (27% oil), and our December 2008 daily production averaged 3.5
MBOE/d. Production in Michigan can be divided into two
groups. The majority of the reserves are in non-operated Antrim Shale
wells located in the northern part of the state. The remainder of the
Michigan reserves are typified by more conventional oil and gas production
located in the central and southern parts of the state. We also
operate the West Branch and Reno gas processing plants. The West
Branch Plant gathers production from the Clayton, West Branch and other smaller
fields.
Clayton
Unit. Clayton Unit production is primarily from the Prairie du
Chien and Glenwood at a depth of around 11,000 feet. During 2008, two
successful wells were drilled in the Clayton Unit.
Marion 3-D
Project. The Marion Prospect, located in Missauke, Clare and
Oceola Counties, Michigan, covers approximately 17,700 gross (14,400 net)
acres. Our analysis of seismic data has identified three drillable
prospects and we are currently formulating our drilling plans for this
area.
Acreage
The
following table summarizes gross and net developed and undeveloped acreage by
state at December 31, 2008. Net acreage is our percentage
ownership of gross acreage. Acreage in which our interest is limited
to royalty and overriding royalty interests is excluded.
|
Developed
Acreage
|
Undeveloped
Acreage
|
Total
Acreage
|
||||||||||||||||||||||
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||||||||||||||
|
California
|
35,747 | 10,724 | 2,284 | 34 | 38,031 | 10,758 | ||||||||||||||||||
|
Colorado
|
36,253 | 18,053 | 32,379 | 8,429 | 68,632 | 26,482 | ||||||||||||||||||
|
Louisiana
|
41,156 | 10,729 | 4,960 | 2,619 | 46,116 | 13,348 | ||||||||||||||||||
|
Michigan
|
136,236 | 59,647 | 47,671 | 26,222 | 183,907 | 85,869 | ||||||||||||||||||
|
Montana
|
41,449 | 13,425 | 33,240 | 14,554 | 74,689 | 27,979 | ||||||||||||||||||
|
North
Dakota
|
258,161 | 135,280 | 343,815 | 192,232 | 601,976 | 327,512 | ||||||||||||||||||
|
Oklahoma
|
87,248 | 55,108 | 2,692 | 2,321 | 89,940 | 57,429 | ||||||||||||||||||
|
Texas
|
219,776 | 136,151 | 88,049 | 61,897 | 307,825 | 198,048 | ||||||||||||||||||
|
Utah
|
19,560 | 11,743 | 262,031 | 62,858 | 281,591 | 74,601 | ||||||||||||||||||
|
Wyoming
|
100,830 | 55,088 | 72,610 | 48,611 | 173,440 | 103,699 | ||||||||||||||||||
|
Other*
|
15,976 | 8,933 | 2,399 | 999 | 18,375 | 9,932 | ||||||||||||||||||
|
Total
|
992,392 | 514,881 | 892,130 | 420,776 | 1,884,522 | 935,657 | ||||||||||||||||||
* Other
includes Alabama, Arkansas, Kansas, Mississippi and New Mexico.
Production
History
The
following table presents historical information about our produced oil and gas
volumes:
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
Oil
production (MMBbls)
|
12.4 | 9.6 | 9.8 | |||||||||
|
Natural
gas production (Bcf)
|
30.4 | 30.8 | 32.1 | |||||||||
|
Total
production (MMBOE)
|
17.5 | 14.7 | 15.2 | |||||||||
|
Daily
production (MBOE/d)
|
47.9 | 40.3 | 41.5 | |||||||||
|
Average
sales prices:
|
||||||||||||
|
Oil
(per Bbl)
|
$ | 86.99 | $ | 64.57 | $ | 57.27 | ||||||
|
Effect
of oil hedges on average price (per Bbl)
|
(8.58 | ) | (2.21 | ) | (0.95 | ) | ||||||
|
Oil
net of hedging (per Bbl)
|
$ | 78.41 | $ | 62.36 | $ | 56.32 | ||||||
|
Natural
gas (per Mcf)
|
$ | 7.68 | $ | 6.19 | $ | 6.59 | ||||||
|
Effect
of natural gas hedges on average price (per Mcf)
|
- | - | 0.06 | |||||||||
|
Natural
gas net of hedging (per Mcf)
|
$ | 7.68 | $ | 6.19 | $ | 6.65 | ||||||
|
Per
BOE data:
|
||||||||||||
|
Sales
price (net of hedging)
|
$ | 69.06 | $ | 53.57 | $ | 50.52 | ||||||
|
Lease
operating expenses
|
$ | 13.77 | $ | 14.20 | $ | 12.12 | ||||||
|
Production
taxes
|
$ | 5.00 | $ | 3.56 | $ | 3.11 | ||||||
|
Depreciation,
depletion and amortization expenses
|
$ | 15.84 | $ | 13.11 | $ | 10.74 | ||||||
|
General
and administrative expenses
|
$ | 3.52 | $ | 2.66 | $ | 2.49 | ||||||
Productive
Wells
The
following table summarizes gross and net productive oil and natural gas wells by
region at December 31, 2008. A net well is our percentage ownership of a gross
well. Wells in which our interest is limited to royalty and
overriding royalty interests are excluded.
|
Oil
Wells
|
Natural
Gas Wells
|
Total
Wells(1)
|
||||||||||||||||||||||
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||||||||||||||
|
Permian
Basin
|
3,611 | 1,687 | 387 | 121 | 3,998 | 1,808 | ||||||||||||||||||
|
Rocky
Mountains
|
1,953 | 378 | 480 | 241 | 2,433 | 619 | ||||||||||||||||||
|
Mid-Continent
|
551 | 268 | 205 | 36 | 756 | 304 | ||||||||||||||||||
|
Gulf
Coast
|
92 | 54 | 481 | 116 | 573 | 170 | ||||||||||||||||||
|
Michigan
|
80 | 35 | 1,031 | 401 | 1,111 | 436 | ||||||||||||||||||
|
Total
|
6,287 | 2,422 | 2,584 | 915 | 8,871 | 3,337 | ||||||||||||||||||
|
|
(1)
|
102
wells are multiple completions. These 102 wells contain a total
of 222 completions. One or more completions in the same bore
hole are counted as one well.
|
Drilling
Activity
We are
engaged in numerous drilling activities on properties presently owned and intend
to drill or develop other properties acquired in the future. The
following table sets forth our drilling activity for the last three
years. The information should not be considered indicative of future
performance, nor should it be assumed that there is necessarily any correlation
between the number of productive wells drilled and quantities of reserves found
or economic value. Productive wells are those that produce commercial
quantities of hydrocarbons, whether or not they produce a reasonable rate of
return.
|
Gross
Wells
|
Net
Wells
|
|||||||||||||||||||||||
|
Productive
|
Dry
|
Total
|
Productive
|
Dry
|
Total
|
|||||||||||||||||||
|
2008:
|
||||||||||||||||||||||||
|
Development
|
283 | 20 | 303 | 113.3 | 9.2 | 122.5 | ||||||||||||||||||
|
Exploratory
|
2 | 3 | 5 | 1.9 | 1.3 | 3.2 | ||||||||||||||||||
|
Total
|
285 | 23 | 308 | 115.2 | 10.5 | 125.7 | ||||||||||||||||||
|
2007:
|
||||||||||||||||||||||||
|
Development
|
262 | 5 | 267 | 128.6 | 3.8 | 132.4 | ||||||||||||||||||
|
Exploratory
|
9 | 1 | 10 | 6.1 | 0.1 | 6.2 | ||||||||||||||||||
|
Total
|
271 | 6 | 277 | 134.7 | 3.9 | 138.6 | ||||||||||||||||||
|
2006:
|
||||||||||||||||||||||||
|
Development
|
401 | 14 | 415 | 300.6 | 9.0 | 309.6 | ||||||||||||||||||
|
Exploratory
|
17 | 5 | 22 | 10.2 | 2.3 | 12.5 | ||||||||||||||||||
|
Total
|
418 | 19 | 437 | 310.8 | 11.3 | 322.1 | ||||||||||||||||||
As of
February 13, 2009, nine operated drilling rigs and 37 operated workover rigs
were active on our properties. We were also participating in the
drilling of four non-operated wells, all of which are located in the Parshall
field. The breakdown of our operated rigs is as follows:
|
Region
|
Drilling
|
Workover
|
||||||
|
Rocky
Mountain
|
8 | 5 | ||||||
|
Permian
|
0 | 2 | ||||||
|
Mid-Continent/Michigan
|
0 | 3 | ||||||
|
North
Ward Estes
|
0 | 20 | ||||||
|
Postle
|
1 | 6 | ||||||
|
Gulf
Coast
|
0 | 1 | ||||||
|
Total
|
9 | 37 | ||||||
|
Item 3.
|
Legal
Proceedings
|
Whiting
is subject to litigation claims and governmental and regulatory proceedings
arising in the ordinary course of business. It is management’s
opinion that all claims and litigation we are involved in are not likely to have
a material adverse effect on our consolidated financial position, cash flows or
results of operations.
|
Item 4.
|
Submission of Matters to a Vote of Security
Holders
|
No
matters were submitted to a vote of security holders during the fourth quarter
of 2008.
EXECUTIVE OFFICERS OF THE
REGISTRANT
The
following table sets forth certain information, as of February 16, 2009,
regarding the executive officers of Whiting Petroleum Corporation:
|
Name
|
Age
|
Position
|
|
James
J. Volker
|
62
|
Chairman,
President and Chief Executive Officer
|
|
James
T. Brown
|
56
|
Senior
Vice President, Operations
|
|
Bruce
R. DeBoer
|
56
|
Vice
President, General Counsel and Corporate Secretary
|
|
Heather
M. Duncan
|
38
|
Vice
President, Human Resources
|
|
J.
Douglas Lang
|
59
|
Vice
President, Reservoir Engineering/Acquisitions
|
|
Rick
A. Ross
|
50
|
Vice
President, Operations
|
|
David
M. Seery
|
54
|
Vice
President, Land
|
|
Michael
J. Stevens
|
43
|
Vice
President and Chief Financial Officer
|
|
Mark
R. Williams
|
52
|
Vice
President, Exploration and Development
|
|
Brent
P. Jensen
|
39
|
Controller
and
Treasurer
|
The
following biographies describe the business experience of our executive
officers:
James J. Volker joined us in
August 1983 as Vice President of Corporate Development and served in that
position through April 1993. In March 1993, he became a contract
consultant to us and served in that capacity until August 2000, at which time he
became Executive Vice President and Chief Operating Officer. Mr.
Volker was appointed President and Chief Executive Officer and a director in
January 2002 and Chairman of the Board in January 2004. Mr. Volker
was co-founder, Vice President and later President of Energy Management
Corporation from 1971 through 1982. He has over 30 years of
experience in the oil and gas industry. Mr. Volker has a degree in
finance from the University of Denver, an MBA from the University of Colorado
and has completed H. K. VanPoolen and Associates’ course of study in reservoir
engineering.
James T. Brown joined us in
May 1993 as a consulting engineer. In March 1999, he became
Operations Manager, in January 2000, he became Vice President of Operations, and
in May 2007, he became Senior Vice President of Operations. Mr. Brown
has over 30 years of oil and gas experience in the Rocky Mountains, Gulf Coast,
California and Alaska. Mr. Brown is a graduate of the University of
Wyoming, with a Bachelor’s Degree in civil engineering, and the University of
Denver, with an MBA.
Bruce R. DeBoer joined us as our Vice
President, General Counsel and Corporate Secretary in January
2005. From January 1997 to May 2004, Mr. DeBoer served as Vice
President, General Counsel and Corporate Secretary of Tom Brown, Inc., an
independent oil and gas exploration and production company. Mr.
DeBoer has over 20 years of experience in managing the legal departments of
several independent oil and gas companies. He holds a Bachelor of
Science Degree in Political Science from South Dakota State University and
received his J.D. and MBA degrees from the University of South
Dakota.
Heather M. Duncan joined us
in February 2002 as Assistant Director of Human Resources and in January 2003
became Director of Human Resources. In January 2008, she was
appointed Vice President of Human Resources. Ms. Duncan has 12 years
of human resources experience in the oil and gas industry. She holds
a Bachelor of Arts Degree in Anthropology and an MBA from the University of
Colorado. She is a certified Professional in Human
Resources.
J. Douglas Lang joined us in
December 1999 as Senior Acquisition Engineer and became Manager of Acquisitions
and Reservoir Engineering in January 2004 and Vice President—Reservoir
Engineering/ Acquisitions in October
2004. His over 30 years of acquisition and reservoir engineering
experience has included staff and managerial positions with Amoco, Petro-Lewis,
General Atlantic Resources, UMC Petroleum and Ocean Energy. Mr. Lang
holds a Bachelor’s Degree in Petroleum Engineering from the University of
Wyoming and an MBA from the University of Denver. He is a registered
Professional Engineer and has served on the national Board of Directors of the
Society of Petroleum Evaluation Engineers.
Rick A. Ross joined us in
March 1999 as an Operations Manager. In May 2007, he became Vice
President of Operations. Mr. Ross has over 25 years of oil and gas
experience. Mr. Ross holds a Bachelor of Science Degree in Mechanical
Engineering from the South Dakota School of Mines and Technology.
David M. Seery joined us as
our Manager of Land in July 2004 as a result of our acquisition of Equity Oil
Company, where he was Manager of Land and Manager of Equity’s Exploration
Department, positions he had held for more than five years. He became
our Vice President of Land in January 2005. Mr. Seery has 27 years of
land experience including staff and managerial positions with Marathon Oil
Company. Mr. Seery holds a Bachelor of Science Degree in Business
Management from the University of Montana. He is a Registered Land
Professional and held various duties with the Denver Association of Petroleum
Landmen.
Michael J. Stevens joined us
in May 2001 as Controller, and became Treasurer in January 2002 and became Vice
President and Chief Financial Officer in March 2005. From 1993 until
May 2001, he served in various positions including Chief Financial Officer,
Controller, Secretary and Treasurer at Inland Resources Inc., a company engaged
in oil and gas exploration and development. He spent seven years in
public accounting with Coopers & Lybrand in Minneapolis,
Minnesota. He is a graduate of Mankato State University of Minnesota
and is a Certified Public Accountant.
Mark R. Williams joined us in
December 1983 as Exploration Geologist, becoming Vice President of Exploration
and Development in December 1999. He has 26 years of experience in
the oil and gas industry and his areas of primary technical expertise are in
sequence stratigraphy, seismic interpretation and petroleum
economics. Mr. Williams is a graduate of the Colorado School of Mines
with a Master’s Degree in geology and holds a Bachelor’s Degree in geology from
the University of Utah.
Brent P. Jensen joined us in
August 2005 as Controller, and he became Controller and Treasurer in January
2006. He was previously with PricewaterhouseCoopers L.L.P. in
Houston, Texas, where he held various positions in their oil and gas audit
practice since 1994, which included assignments of four years in Moscow, Russia
and three years in Milan, Italy. He has 15 years of oil and gas
accounting experience and is a Certified Public Accountant. Mr.
Jensen holds a Bachelor of Arts degree from the University of California, Los
Angeles.
Executive
officers are elected by, and serve at the discretion of, the Board of
Directors. There are no family relationships between any of our
directors or executive officers.
PART
II
|
Item 5.
|
Market for the Registrant’s Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity
Securities
|
Whiting
Petroleum Corporation’s common stock is traded on the New York Stock Exchange
under the symbol “WLL.” The following table shows the high and low
sale prices for our common stock for the periods presented.
|
High
|
Low
|
|||||||
|
Fiscal
Year Ended December 31, 2008
|
||||||||
|
Fourth
Quarter (Ended December 31,
2008)
|
$ | 69.58 | $ | 24.36 | ||||
|
Third
Quarter (Ended September 30,
2008)
|
$ | 112.42 | $ | 62.09 | ||||
|
Second
Quarter (Ended June 30,
2008)
|
$ | 108.53 | $ | 63.07 | ||||
|
First
Quarter (Ended March 31,
2008)
|
$ | 66.19 | $ | 44.60 | ||||
|
Fiscal
Year Ended December 31, 2007
|
||||||||
|
Fourth
Quarter (Ended December 31,
2007)
|
$ | 59.06 | $ | 44.09 | ||||
|
Third
Quarter (Ended September 30,
2007)
|
$ | 45.14 | $ | 35.85 | ||||
|
Second
Quarter (Ended June 30,
2007)
|
$ | 47.50 | $ | 38.71 | ||||
|
First
Quarter (Ended March 31,
2007)
|
$ | 46.04 | $ | 35.81 | ||||
On
February 16, 2009, there were 887 holders of record of our common
stock.
We have
not paid any dividends since we were incorporated in July 2003. We do
not anticipate paying any cash dividends on our common stock in the foreseeable
future. We currently intend to retain future earnings, if any, to
finance the expansion of our business. Our future dividend policy is
within the discretion of our board of directors and will depend upon various
factors, including our financial position, cash flows, results of operations,
capital requirements and investment opportunities. In addition, the
agreements governing our indebtedness prohibit us from paying
dividends.
Information
relating to compensation plans under which our equity securities are authorized
for issuance is set forth in Part III, Item 12 of this Annual Report
on Form 10-K.
The
following information in this Item 5 of this Annual Report on Form 10-K is
not deemed to be “soliciting material” or to be “filed” with the SEC or subject
to Regulation 14A or 14C under the Securities Exchange Act of 1934 or to
the liabilities of Section 18 of the Securities Exchange Act of 1934, and
will not be deemed to be incorporated by reference into any filing under the
Securities Act of 1933 or the Securities Exchange Act of 1934, except to the
extent we specifically incorporate it by reference into such a
filing.
The
following graph compares on a cumulative basis changes since December 31, 2003
in (a) the total stockholder return on our common stock with (b) the
total return on the Standard & Poor’s Composite 500 Index and
(c) the total return on the Dow Jones US Oil Companies, Secondary
Index. Such changes have been measured by dividing (a) the sum
of (i) the amount of dividends for the measurement period, assuming
dividend reinvestment, and (ii) the difference between the price per share
at the end of and the beginning of the measurement period, by (b) the price
per share at the beginning of the measurement period. The graph
assumes $100 was invested on December 31, 2003 in our common stock, the
Standard & Poor’s Composite 500 Index and the Dow Jones US Oil
Companies, Secondary Index.
|
12/31/03
|
12/31/04
|
12/31/05
|
12/31/06
|
12/31/07
|
12/31/08
|
|||||||||||||||||||
|
Whiting
Petroleum Corporation
|
$ | 100 | $ | 164 | $ | 217 | $ | 253 | $ | 313 | $ | 182 | ||||||||||||
|
Standard &
Poor’s Composite 500 Index
|
100 | 109 | 112 | 128 | 132 | 81 | ||||||||||||||||||
|
Dow
Jones US Oil Companies, Secondary Index
|
100 | 140 | 230 | 241 | 344 | 204 | ||||||||||||||||||
|
Item 6.
|
Selected Financial
Data
|
The
consolidated income statement information for the years ended December 31,
2008, 2007 and 2006 and the consolidated balance sheet information at December
31, 2008 and 2007 are derived from our audited financial statements included
elsewhere in this report. The consolidated income statement
information for the years ended December 31, 2005 and 2004 and the consolidated
balance sheet information at December 31, 2006, 2005 and 2004 are derived
from audited financial statements that are not included in this
report. Our historical results include the results from our recent
acquisitions beginning on the following dates: Flat Rock Natural Gas
Field, May 30, 2008; Utah
Hingeline, August 29, 2006; Michigan Properties, August 15, 2006;
North Ward Estes and Ancillary Properties, October 4, 2005; Postle
Properties, August 4, 2005; Limited Partnership Interests, June 23,
2005; Green River Basin, March 31, 2005; Permian Basin, September 23, 2004;
Equity Oil Company, July 20, 2004; Colorado and Wyoming, August 13, 2004;
Wyoming and Utah, September 30, 2004; Louisiana and Texas, August 16, 2004;
Mississippi, November 3, 2004; and additional Permian Basin interest, December
31, 2004.
|
Year
Ended December 31,
|
|||||||||||||||||||||
|
2008
|
2007
|
2006
|
2005
|
2004
|
|||||||||||||||||
|
(dollars
in millions, except per share data)
|
|||||||||||||||||||||
|
Consolidated
Statements of Income Information:
|
|||||||||||||||||||||
|
Revenues
and other income:
|
|||||||||||||||||||||
|
Oil
and natural gas sales
|
$ | 1,316.5 | $ | 809.0 | $ | 773.1 | $ | 573.2 | $ | 281.1 | |||||||||||
|
Loss
on oil and natural gas hedging activities
|
(107.6 | ) | (21.2 | ) | (7.5 | ) | (33.4 | ) | (4.9 | ) | |||||||||||
|
Gain
on sale of oil and gas properties
|
— | 29.7 | 12.1 | — | 1.0 | ||||||||||||||||
|
Gain
on sale of marketable securities
|
— | — | — | — | 4.8 | ||||||||||||||||
|
Amortization
of deferred gain on sale
|
12.1 | — | — | — | — | ||||||||||||||||
|
Interest
income and other
|
1.1 | 1.2 | 1.1 | 0.6 | 0.1 | ||||||||||||||||
|
Total
revenues and other income
|
1,222.1 | 818.7 | 778.8 | 540.4 | 282.1 | ||||||||||||||||
|
Costs
and expenses:
|
|||||||||||||||||||||
|
Lease
operating
|
241.2 | 208.9 | 183.6 | 111.6 | 54.2 | ||||||||||||||||
|
Production
taxes
|
87.5 | 52.4 | 47.1 | 36.1 | 16.8 | ||||||||||||||||
|
Depreciation,
depletion and amortization
|
277.5 | 192.8 | 162.8 | 97.6 | 54.0 | ||||||||||||||||
|
Exploration
and impairment
|
55.3 | 37.3 | 34.5 | 16.7 | 6.3 | ||||||||||||||||
|
General
and administrative
|
61.7 | 39.0 | 37.8 | 30.6 | 19.2 | ||||||||||||||||
|
Change
in Production Participation Plan liability
|
32.1 | 8.6 | 6.2 | 9.7 | 1.7 | ||||||||||||||||
|
Interest
expense
|
65.1 | 72.5 | 73.5 | 42.0 | 15.9 | ||||||||||||||||
|
Gain
on mark-to-market derivatives
|
(7.1 | ) | — | — | — | — | |||||||||||||||
|
Total
costs and expenses
|
813.3 | 611.5 | 545.5 | 344.3 | 168.1 | ||||||||||||||||
|
Income
before income taxes
|
408.8 | 207.2 | 233.3 | 196.1 | 114.0 | ||||||||||||||||
|
Income
tax expense
|
156.7 | 76.6 | 76.9 | 74.2 | 44.0 | ||||||||||||||||
|
Net
income
|
$ | 252.1 | $ | 130.6 | $ | 156.4 | $ | 121.9 | $ | 70.0 | |||||||||||
|
Net
income per common share, basic
|
$ | 5.96 | $ | 3.31 | $ | 4.26 | $ | 3.89 | $ | 3.38 | |||||||||||
|
Net
income per common share, diluted
|
$ | 5.94 | $ | 3.29 | $ | 4.25 | $ | 3.88 | $ | 3.38 | |||||||||||
|
Other
Financial Information:
|
|||||||||||||||||||||
|
Net
cash provided by operating activities
|
$ | 763.0 | $ | 394.0 | $ | 411.2 | $ | 330.2 | $ | 134.1 | |||||||||||
|
Net
cash used in investing activities
|
$ | (1,134.9 | ) | $ | 467.0 | $ | 527.6 | $ | 1,126.9 | $ | 524.4 | ||||||||||
|
Net
cash provided by financing activities
|
$ | 366.8 | $ | 77.3 | $ | 116.4 | $ | 805.5 | $ | 338.4 | |||||||||||
|
Ratio
of earnings to fixed charges (1)
|
6.92 | x | 3.65 | x | 4.14 | x | 5.64 | x | 8.01 | x | |||||||||||
|
Capital
expenditures
|
$ | 1,330.9 | $ | 519.6 | $ | 552.0 | $ | 1,126.9 | $ | 530.6 | |||||||||||
|
Consolidated
Balance Sheet Information:
|
|||||||||||||||||||||
|
Total
assets
|
$ | 4,029.1 | $ | 2,952.0 | $ | 2,585.4 | $ | 2,235.2 | $ | 1,092.2 | |||||||||||
|
Total
debt
|
$ | 1,239.8 | $ | 868.2 | $ | 995.4 | $ | 875.1 | $ | 328.4 | |||||||||||
|
Stockholders’
equity
|
$ | 1,808.8 | $ | 1,490.8 | $ | 1,186.7 | $ | 997.9 | $ | 612.4 | |||||||||||
|
(1)
|
For
the purpose of calculating the ratio of earnings to fixed charges,
earnings consist of income before income taxes and income from equity
investees, plus fixed charges, distributed income from equity investees,
and amortization of capitalized interest, less capitalized
interest. Fixed charges consist of interest expensed, interest
capitalized, amortized premiums, discounts and capitalized expenses
related to indebtedness, and an estimate of interest within rental
expense.
|
|
Item 7.
|
Management’s Discussion and Analysis of Financial
Condition and Results of
Operations
|
Unless
the context otherwise requires, the terms “Whiting,” “we,” “us,” “our” or “ours”
when used in this Item refer to Whiting Petroleum Corporation, together with its
consolidated subsidiaries, Whiting Oil and Gas Corporation, Equity Oil Company
and Whiting Programs, Inc. When the context requires, we refer to
these entities separately. This document contains forward-looking
statements, which give our current expectations or forecasts of future
events. Please refer to “Forward-Looking Statements” at the end of
this Item for an explanation of these types of statements.
Overview
We are an
independent oil and gas company engaged in oil and gas acquisition, development,
exploitation, production and exploration activities primarily in the Permian
Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the
United States. Prior to 2006, we generally emphasized the acquisition
of properties that increased our production levels and provided upside potential
through further development. Since 2006, we have focused primarily on
organic drilling activity and on the development of previously acquired
properties, specifically on projects that we believe provide the opportunity for
repeatable successes and production growth. We believe the
combination of acquisitions, subsequent development and organic drilling
provides us a broad set of growth alternatives and allows us to direct our
capital resources to what we believe to be the most advantageous
investments.
As
demonstrated by our recent capital expenditure programs, we are increasingly
focused on a balance between exploration and development programs and continuing
to selectively pursue acquisitions that complement our existing core
properties. We believe that our significant drilling inventory,
combined with our operating experience and cost structure, provides us with
meaningful organic growth opportunities. Our growth plan is centered
on the following activities:
|
•
|
pursuing
the development of projects that we believe will generate attractive rates
of return;
|
|
|
•
|
maintaining
a balanced portfolio of lower risk, long-lived oil and gas properties that
provide stable cash flows;
|
|
|
•
|
seeking
property acquisitions that complement our core
areas; and
|
|
|
•
|
allocating
a portion of our capital budget to leasing and exploring prospect
areas.
|
We have
historically acquired operated and non-operated properties that exceed our rate
of return criteria. For acquisitions of properties with additional
development, exploitation and exploration potential, our focus has been on
acquiring operated properties so that we can better control the timing and
implementation of capital spending. In some instances, we have been
able to acquire non-operated property interests at attractive rates of return
that established a presence in a new area of interest or that have complemented
our existing operations. We intend to continue to acquire both
operated and non-operated interests to the extent we believe they meet our
return criteria. In addition, our willingness to acquire non-operated
properties in new geographic regions provides us with geophysical and geologic
data in some cases that leads to further acquisitions in the same region,
whether on an operated or non-operated basis. We sell properties when
we believe that the sales price realized will provide an above average rate of
return for the property or when the property no longer matches the profile of
properties we desire to own.
Oil and
natural gas prices have fallen significantly since their third quarter 2008
levels. For example, oil prices declined from record levels in early July
2008 of over $140 per Bbl to below $40 per Bbl in December 2008, while natural
gas prices have declined from over $13 per Mcf to below $6 per Mcf over the same
period. In addition, the actual and forecasted prices for 2009 have also
declined since year-end. 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, financial position, cash flows, results of
operations, liquidity, ability to finance planned capital expenditures and the
oil and natural gas reserves that we can economically produce. 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
Operational
Highlights. Our Sanish field in Mountrail County, North Dakota
targets the Bakken formation. December 2008 net production in the
Sanish field averaged 7.5 MBOE/d in December 2008, an 832% increase from 0.8
MBOE/d in December 2007. In order to separate the natural gas liquids
(“NGLs”) from the natural gas processed from the Sanish wells, we constructed
and brought on stream the Robinson Lake Gas Plant. The first phase of
this plant began processing gas in May 2008, and the second phase was completed
in December 2008. Immediately east of the Sanish field is the
Parshall field, where net production averaged 6.7 MBOE/d in December 2008, a
341% increase from 1.5 MBOE/d in December 2007.
We
continue to have significant development and related infrastructure activity on
the Postle and North Ward Estes fields acquired in 2005, which have resulted in
reserve and production increases. Our expansion of the CO2 flood at
both fields continues to generate positive results. During 2008, we
incurred $325.1 million of development expenditures on these two
projects.
The
Postle field is located in Texas County, Oklahoma. Four of our five
producing units are currently under active CO2 enhanced
recovery projects. As of December 31, 2008, we were injecting 142
MMcf/d of CO2 in this
field. Production from the field has increased 22% from a net 5.8
MBOE/d in December 2007 to a net 7.1 MBOE/d in December
2008. Operations are under way to expand CO2 injection
into the northern part of the fourth unit, HMU, and to optimize flood patterns
in the existing CO2
floods. These expansion projects include the restoration of shut-in
wells and the drilling of new producing and injection wells.
The North
Ward Estes field is responding positively to our water and CO2 floods,
which we initiated in May 2007. As of December 31, 2008, we were
injecting 123 MMcf/d of CO2 in this
field. Production from the field has increased 29% from a net 5.1
MBOE/d in December 2007 to a net 6.6 MBOE/d in December 2008. In this
field, we are developing new and reactivated wells for water and CO2 injection
and production purposes. Additionally, we plan to install oil, gas
and water processing facilities in five phases through 2015, and we estimate
that the first three phases will be substantially complete by December
2009.
The
Sulphur Creek field in Rio Blanco County, Colorado in the Piceance Basin
includes the Boies Ranch and Jimmy Gulch prospects. We expect our
development in this area during 2009 will be focused on the Jimmy Gulch lease
which targets the shallow Wasatch zone. We drilled three wells in
Jimmy Gulch in 2008. As of February 13, 2009, the three wells were
producing at a combined net rate of 3.0 MMcf/d.
2009 Capital Budget and Major
Development Areas. Our current 2009 capital budget for
exploration and development expenditures is $474.0 million, which we expect to
fund with net cash provided by our operating activities and a portion of the
proceeds from the common stock offering we completed in February
2009. To the extent net cash provided by operating activities is
higher or lower than currently anticipated, we would adjust our capital budget
accordingly. Our 2009 capital budget currently is allocated among our
major development areas as indicated in the chart below. We may use a
portion of the balance of the net proceeds from our February 2009 common stock
offering to further develop these projects; or, in the event of further oil and
gas price declines, to keep our bank debt at lower levels.
Of our
existing potential projects, we believe these present the opportunity for the
highest return and most efficient use of our capital expenditures.
|
Development Area
|
2009
Planned Capital Expenditures
(In
millions)
|
|||
|
Northern
Rockies
|
$ | 242.3 | ||
|
CO2
Projects (1)
|
129.3 | |||
|
Central
Rockies
|
72.4 | |||
|
Other
(2)
|
30.0 | |||
|
Total
|
$ | 474.0 | ||
_________
|
|
(1)
|
2009
planned capital expenditures at our CO2
projects include $36.9 million for purchased CO2 at
North Ward Estes and $15.3 million for Postle CO2
purchases.
|
| (2) | Comprised primarily of exploration salaries, lease delay rentals and seismic and other development. |
Subsequent
Event
In
February 2009, we completed a public offering of our common stock under our
existing shelf registration statement, selling 8,000,000 shares of common stock
at a price of $29.00 per share and providing net proceeds of $222.2 million
after underwriters’ discounts and commissions and estimated offering expenses.
Pursuant to the exercise of the underwriters’ overallotment option, we
sold an additional 450,000 shares of common stock at $29.00 per share, providing
net proceeds of $12.5 million. We used the net offering proceeds to
repay a portion of the debt outstanding under Whiting Oil and Gas’ credit
agreement. We plan to use a portion of the increased credit
availability to fund capital expenditures in our 2009 capital
budget. Had the common stock issuance occurred at the beginning of
2008, the number of basic and diluted shares used in the computations of
earnings per share would have been 50,759,517 and 50,897,256, respectively, for
the year ended December 31, 2008.
Acquisitions
Flat Rock Natural Gas
Field. On May 30, 2008, we acquired interests in 31
producing gas wells, development acreage and gas gathering and processing
facilities on approximately 22,000 gross (11,500 net) acres in the Flat Rock
field in Uintah County, Utah for an aggregate acquisition price of $365.0
million. After allocating $79.5 million of the purchase price to
unproved properties, the resulting acquisition cost is $2.48 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.
Utah Hingeline. On
August 29, 2006, we acquired a 15% working interest in approximately
170,000 acres of unproved properties in the central Utah Hingeline play for
$25.0 million. No producing properties or proved reserves were
associated with this acquisition. As part of our acquisition of this
property, the operator agreed to pay 100% of our drilling and completion costs
for the first three wells in the project. The three wells were
drilled, but the hydrocarbons encountered were not determined to be economic,
resulting in dry holes for all three wells.
Michigan
Properties. On August 15, 2006, we acquired 65 producing
properties, a gathering line, gas processing plant and approximately 30,400 net
acres of leasehold held by production in Michigan. The purchase price
was $26.0 million for estimated proved reserves of 1.4 MMBOE as of the
acquisition effective date of May 1, 2006, resulting in a cost of $18.55
per BOE of estimated proved reserves. Proved developed reserve
quantities represented 99% of the total proved reserves acquired. The
average daily production from the properties was 0.6 MBOE/d as of the
acquisition effective date.
Divestitures
Whiting USA Trust
I. 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 $214.9 million after underwriters’ discounts and commissions and
offering 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 $193.7 million. We used the offering net proceeds to
reduce a portion of the debt outstanding under our credit
agreement. The net proceeds from the sale of Trust units to the
public resulted in a deferred gain on sale of $100.0 million. Immediately
prior to the closing of the offering, we conveyed a term net profits interest in
certain of our oil and 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, 2021, based on the reserve report for the underlying
properties as of December 31, 2008. 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
July 17, 2007, we sold our 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, we sold our 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. No gain or loss was recognized on the sales. 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.
During
2006, we sold our interests in several non-core oil and gas producing properties
for an aggregate amount of $24.4 million in cash for total estimated proved
reserves of 1.4 MMBOE as of the divestitures’ effective dates. The
divested properties included interests in the Cessford field in Alberta, Canada;
Permian Basin of West Texas and New Mexico; and the Ashley Valley field in
Uintah County, Utah. The average daily net production from the
divested property interests was 0.4 MBOE/d as of the dates of disposition,
and we recognized a pre-tax gain on sale of $12.1 million related to these
divestitures.
Results
of Operations
The
following table sets forth selected operating data for the periods
indicated:
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
Net
production:
|
||||||||||||
|
Oil
(MMBbls)
|
12.4 | 9.6 | 9.8 | |||||||||
|
Natural
gas (Bcf)
|
30.4 | 30.8 | 32.1 | |||||||||
|
Total
production (MMBOE)
|
17.5 | 14.7 | 15.2 | |||||||||
|
Net
sales (in millions):
|
||||||||||||
|
Oil
(1)
|
$ | 1,082.8 | $ | 618.5 | $ | 561.2 | ||||||
|
Natural
gas (1)
|
233.7 | 190.5 | 211.9 | |||||||||
|
Total
oil and natural gas sales
|
$ | 1,316.5 | $ | 809.0 | $ | 773.1 | ||||||
|
Average
sales prices:
|
||||||||||||
|
Oil
(per Bbl)
|
$ | 86.99 | $ | 64.57 | $ | 57.27 | ||||||
|
Effect
of oil hedges on average price (per Bbl)
|
(8.58 | ) | (2.21 | ) | (0.95 | ) | ||||||
|
Oil
net of hedging (per Bbl)
|
$ | 78.41 | $ | 62.36 | $ | 56.32 | ||||||
|
Average
NYMEX price
|
$ | 97.24 | $ | 72.30 | $ | 66.25 | ||||||
|
Natural
gas (per Mcf)
|
$ | 7.68 | $ | 6.19 | $ | 6.59 | ||||||
|
Effect
of natural gas hedges on average price (per Mcf)
|
- | - | 0.06 | |||||||||
|
Natural
gas net of hedging (per Mcf)
|
$ | 7.68 | $ | 6.19 | $ | 6.65 | ||||||
|
Average
NYMEX price
|
$ | 9.06 | $ | 6.86 | $ | 7.23 | ||||||
|
Cost
and expense (per BOE):
|
||||||||||||
|
Lease
operating expenses
|
$ | 13.77 | $ | 14.20 | $ | 12.12 | ||||||
|
Production
taxes
|
$ | 5.00 | $ | 3.56 | $ | 3.11 | ||||||
|
Depreciation,
depletion and amortization expense
|
$ | 15.84 | $ | 13.11 | $ | 10.74 | ||||||
|
General
and administrative expenses
|
$ | 3.52 | $ | 2.66 | $ | 2.49 | ||||||
________________
|
(1)
|
Before
consideration of hedging
transactions.
|
Year
Ended December 31, 2008 Compared to Year Ended December 31, 2007
Oil and Natural Gas
Sales. Our oil and natural gas sales revenue increased $507.5
million to $1,316.5 million in 2008 compared to 2007. Sales are a
function of volumes sold and average sales prices. Our oil sales
volumes increased 30% between periods, while our natural gas sales volumes
decreased 1%. The oil volume increase resulted primarily from
drilling success in the North Dakota Bakken area, in addition to increased
production at our two large CO2 projects,
Postle and North Ward Estes. Oil production from the Bakken increased
2,960 MBbl compared to 2007, while Postle oil production increased 380 MBbl and
North Ward Estes oil production increased 265 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 630
MBbl. The gas volume decline between periods was primarily the result
of the Trust divestiture, which decreased gas production in 2008 by 2,920 MMcf,
and property dispositions in the second half of 2007, which decreased gas
production in 2008 by an additional 780 MMcf. These decreases were
partially offset by incremental gas production of 2,885 MMcf from the Flat Rock
acquisition and higher production in the Boies Ranch area of 1,505
MMcf. Our average price for oil before effects of hedging increased
35% between periods, and our average price for natural gas before effects of
hedging increased 24%.
Loss on Oil and Natural Gas Hedging
Activities. Realized cash settlements on commodity derivatives
that we have designated as cash flow hedges are recognized as (gain) loss on oil
and natural gas hedging activities. During 2008, we incurred cash
settlement losses of $107.6 million on such crude oil hedges, and during 2007 we
incurred cash settlement losses of $21.2 million on these oil
hedges. We incurred no cash settlement gains or losses during 2008 or
2007 on natural gas derivative contracts designated as cash flow
hedges. See Item 7A, “Qualitative and Quantitative Disclosures About
Market Risk” for a list of our outstanding oil hedges as of January 1,
2009.
Gain on Sale of
Properties. There was no gain or loss on the sale of
properties during 2008. During 2007, however, we sold certain
non-core properties for aggregate sales proceeds of $52.6 million, resulting in
a pre-tax gain on sale of $29.7 million.
Amortization of Deferred Gain on
Sale. In connection with the sale of 11,677,500 Trust units to the
public and related oil and gas property conveyance on April 30, 2008, we
recognized a deferred gain on sale of $100.0 million. This deferred gain
is amortized to income over the life of the Trust on the units-of-production
basis. During 2008, we recognized $12.1 million in income as
amortization of deferred gain on sale.
Lease Operating
Expenses. Our lease operating expenses during 2008 were $241.2
million, a $32.4 million or 16% increase over the same period in
2007. Our lease operating expenses per BOE decreased from $14.20
during 2007 to $13.77 during 2008. The decrease of 3% on a BOE basis
was primarily caused by flush production from Bakken drilling, which was
partially offset by inflation in the cost of oil field goods and services and a
higher level of workover activity. Workovers amounted to $27.3
million in 2008, as compared to $17.4 million of workover activity during
2007.
Production
Taxes. The production taxes we pay are generally calculated as
a percentage of oil and natural gas sales revenue before the effects of
hedging. We take full advantage of all credits and exemptions allowed
in our various taxing jurisdictions. Our production taxes for 2008
and 2007 were 6.7% and 6.5%, respectively, of oil and natural gas
sales. The 2008 rate increased slightly from 2007 mainly due to
successful wells completed in the North Dakota Bakken area during 2008, which
carry an 11.5% production tax rate.
Depreciation, Depletion and
Amortization. Our depreciation, depletion and amortization
(“DD&A”) expense increased $84.6 million in 2008 as compared to
2007. The components of DD&A expense were as follows (in
thousands):
|
Year
Ended December 31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Depletion
|
$ | 270,770 | $ | 186,838 | ||||
|
Depreciation
|
3,439 | 3,123 | ||||||
|
Accretion
of asset retirement obligations
|
3,239 | 2,850 | ||||||
|
Total
|
$ | 277,448 | $ | 192,811 | ||||
DD&A
increased $84.6 million primarily due to $83.9 million in higher depletion
expense between periods. Of this $83.9 million increase in depletion,
$35.7 million relates to higher oil and gas volumes produced during 2008, while
$48.2 million relates to our higher depletion rate in 2008. On a BOE
basis, our DD&A rate increased by 21% from $13.11 for 2007 to $15.84 for
2008. The primary factors causing this rate increase were (i) $918.1
million in drilling expenditures incurred during the past twelve months, (ii)
net oil and natural gas reserve reductions of 11.6 MMBOE during 2008, which were
primarily attributable to a 39.0 MMBOE downward revision for lower oil and
natural gas prices at December 31, 2008, and (iii) the significant expenditures
necessary to develop proved undeveloped reserves, particularly related to the
enhanced oil recovery projects in the Postle and North Ward Estes fields,
whereby the development of proved undeveloped reserves does not increase
existing quantities of proved reserves. Under the successful efforts
method of accounting, costs to develop proved undeveloped reserves are added
into the DD&A rate when incurred.
Exploration and Impairment
Costs. Our exploration and impairment costs increased $17.9
million, as compared to 2007. The components of exploration and
impairment costs were as follows (in thousands):
|
Year
Ended December 31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Exploration
|
$ | 29,302 | $ | 27,344 | ||||
|
Impairment
|
25,955 | 9,979 | ||||||
|
Total
|
$ | 55,257 | $ | 37,323 | ||||
Exploration
costs increased $2.0 million during 2008 as compared to 2007 primarily due to
higher exploration employee compensation costs and exploratory dry hole expense,
which were partially offset by a decrease in geological and geophysical
activity. During 2008, we drilled one exploratory dry hole in the
Permian region and participated in two non-operated exploratory dry holes in the
Rocky Mountains region totaling $3.6 million, while during 2007 we participated
in a non-operated exploratory well in the Gulf Coast region that resulted in an
insignificant amount of dry hole expense. Impairment expense is
mainly related to the amortization of leasehold costs associated with
individually insignificant unproved properties. Impairment expense in
2008 is higher than 2007 because the amount of unproved properties being
amortized totaled $72.3 million as of December 31, 2008, as compared to $51.5
million as of December 31, 2007. Also lending to the increase in
impairment during 2008 was a $10.9 million non-cash charge to impairment
expense for the partial write-down of unproved properties in the central Utah
Hingeline play. In the fourth quarter of 2008 based on poor drilling
results, we determined that 1,873 net acres within our central Utah Hingeline
position would no longer be evaluated, drilled or otherwise developed and should
be written down accordingly.
General and Administrative
Expenses. We report general and administrative expenses net of
third party reimbursements and internal allocations. The components
of general and administrative expenses were as follows (in
thousands):
|
Year
Ended December 31,
|
|||||||||
|
2008
|
2007
|
||||||||
|
General
and administrative expenses
|
$ | 103,231 | $ | 72,008 | |||||
|
Reimbursements
and allocations
|
(41,547 | ) | (32,962 | ) | |||||
|
General
and administrative expenses, net
|
$ | 61,684 | $ | 39,046 | |||||
General
and administrative expense before reimbursements and allocations increased $31.2
million to $103.2 million during 2008. The largest components of the
increase related to (i) $20.1 million in higher accrued distributions under our
Production Participation Plan (“Plan”) between periods due to the net profits
interest divestiture associated with the sale of 11,677,500 Trust units, and a
higher level of Plan net revenues (which have been reduced by lease operating
expenses and production taxes pursuant to the Plan formula) in 2008, and (ii)
$9.1 million of additional employee compensation for personnel hired during the
past twelve months along with 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 natural gas sales
remained constant at 5% for both 2008 and 2007.
Interest
Expense. The components of interest expense were as follows
(in thousands):
|
Year
Ended December 31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Senior
Subordinated Notes
|
$ | 43,461 | $ | 44,691 | ||||
|
Credit
Agreement
|
18,377 | 24,428 | ||||||
|
Amortization
of debt issue costs and debt discount
|
4,801 | 5,022 | ||||||
|
Accretion
of tax sharing liability
|
1,267 | 1,505 | ||||||
|
Other
|
301 | 522 | ||||||
|
Capitalized
interest
|
(3,129 | ) | (3,664 | ) | ||||
|
Total
interest expense
|
$ | 65,078 | $ | 72,504 | ||||
The
decrease in interest expense of $7.4 million between years was mainly due to
lower interest rates during 2008 on borrowings under our credit
agreement. Our weighted average effective cash interest rate was 5.9%
during 2008 compared to 7.2% during 2007. Our weighted average debt
outstanding during 2008 was $1,049.4 million, while it was $964.4 million for
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 6.3%
during 2008 compared to 7.7% during 2007.
Change in Production Participation
Plan Liability. For the year ended December 31, 2008, this
non-cash expense was $32.1 million, an increase of $23.5 million as compared to
2007. This expense represents the change in the vested present value
of estimated future payments to be made to participants after 2009 under our
Plan. Although payments take place over the life of the Plan’s oil
and gas properties, which for some properties is over 20 years, we expense the
present value of estimated future payments over the Plan’s five-year vesting
period. This expense in 2008 and 2007 primarily reflects (i) changes
to future cash flow estimates stemming from the volatile commodity price
environment during the past three years, (ii) 2008 drilling activity and
property acquisitions, and (iii) employees’ continued vesting in the
Plan. Due to the higher commodity price environment during 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 under this
Plan. The average NYMEX prices used to estimate this liability
increased by $24.63 for crude oil and $0.86 for natural gas for the year ended
December 31, 2008, as compared to increases of $8.58 for crude oil and
$0.67 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.
Gain 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 mainly in oil
prices, we recognized $4.2 million in unrealized mark-to-market derivative gains
during 2008 and $0.9 million in realized cash settlement gains. We
also recognized income of $1.9 million as a gain on mark-to-market derivatives
for the ineffective portion of changes in fair value on our commodity
derivatives designated as cash flow hedges.
Income Tax
Expense. Income tax expense totaled $156.7 million in 2008 and
$76.6 million for 2007. Our effective income tax rate increased from
37.0% for 2007 to 38.3% for 2008. Our effective income tax rate was
higher in 2008 due to our drilling success in state jurisdictions having higher
income tax rates and an increase in the amount of current income taxes paid in
certain states.
The
current portion of income tax expense was $2.4 million for 2008 compared to $0.6
million in 2007. We reported a net operating loss in our 2007 income
tax return, and we anticipate reporting a net operating loss in our 2008 income
tax return, mainly due to intangible drilling deductions allowed.
Net Income. Net
income increased from $130.6 million for 2007 to $252.1 million for
2008. The primary reasons for this increase include a 19% increase in
equivalent volumes sold, a 26% increase in oil prices (net of hedging) and a 24%
increase in natural gas prices (net of hedging) between periods, amortization of
deferred gain on sale, lower interest expense and gains on mark-to-market
derivatives. 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 and income taxes, as well as no gain on sale of properties during
2008.
Year
Ended December 31, 2007 Compared to Year Ended December 31, 2006
Oil and Natural Gas
Sales. Our oil and natural gas sales revenue increased $35.9
million to $809.0 million in 2007 compared to 2006. Sales are a
function of volumes sold and average sales prices. Our oil sales
volumes decreased 2% between periods, while our natural gas sales volumes
decreased 4%. The volume declines resulted in part from property
sales, production shut-ins due to delays at third-party refineries, and normal
field production decline, which factors were partially offset by production
increases from development activities. Our 2007 and 2006 property
divestitures resulted in a decline of approximately 317 MBOE, 48% of which
related to natural gas. Approximately 34 MBOE of production from the
Postle field was shut-in or restricted from February 19 through
March 8, 2007 due to a fire at a third-party refinery, and approximately 32
MBOE of production from the Boies Ranch field was restricted from July 28 to
November 18, 2007 due to repairs at the field’s gas processing
plant. During 2007, we also converted several production wells to
injectors at our North Ward Estes field, as the Phase I area of the reservoir
was pressured up in preparation for CO2
injection. Our average price for oil before effects of hedging
increased 13% between periods, and our average price for natural gas before
effects of hedging decreased 6%.
Loss on Oil and Natural Gas Hedging
Activities. We hedged 53% of our oil volumes during 2007,
incurring cash settlement losses of $21.2 million, and 54% of our oil volumes
during 2006, incurring cash settlement losses of $9.4 million. We
hedged 16% of our gas volumes during 2007, incurring no cash settlement gains or
losses, and 59% of our gas volumes during 2006, resulting in cash settlement
gains of $1.9 million.
Gain on Sale of
Properties. During 2007, we sold certain non-core properties
for aggregate sales proceeds of $52.6 million, resulting in a pre-tax gain on
sale of $29.7 million. During 2006, we sold our interests in several
non-core properties for an aggregate amount of $24.4 million in cash and
recognized a pre-tax gain on sale of $12.1 million.
Lease Operating
Expenses. Our lease operating expenses for 2007 were $208.9
million, a $25.2 million or 14% increase over 2006. Our lease
operating expenses per BOE increased from $12.12 during 2006 to $14.20 during
2007. The increase of 17% on a BOE basis was primarily caused by a
high level of workover activity, inflation in the cost of oil field goods and
services, and a change in labor billing practices. Workovers amounted
to $17.4 million in 2007, as compared to $8.9 million of workover activity
during 2006. The cost of oil field goods and services increased due
to a higher demand in the industry. In addition, during the fourth
quarter of 2006, we revised our labor billing practices to better conform to
Council of Petroleum Accountants Societies (“COPAS”) guidelines. This
change in labor billing practices resulted in lower net general and
administrative expense and higher amounts of lease operating expense being
charged to us and our joint interest owners on properties we
operate.
Production
Taxes. The production taxes we pay are generally calculated as
a percentage of oil and natural 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 2007
and 2006 were 6.5% and 6.1%, respectively, of oil and natural gas
sales. Our production tax rate for 2007 was greater than the rate for
2006 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 $30.0 million as compared to 2006. The
components of DD&A expense were as follows (in thousands):
|
Year
Ended December 31,
|
||||||||
|
2007
|
2006
|
|||||||
|
Depletion
|
$ | 186,838 | $ | 157,868 | ||||
|
Depreciation
|
3,123 | 2,675 | ||||||
|
Accretion
of asset retirement obligations
|
2,850 | 2,288 | ||||||
|
Total
|
$ | 192,811 | $ | 162,831 | ||||
DD&A
increased $30.0 million primarily due to $29.0 million in higher depletion
expense between periods. Of this $29.0 million increase in depletion,
$33.7 million relates to our higher depletion rate in 2007, which was partially
offset by $4.7 million related to lower oil and gas volumes produced during
2007. On a BOE basis, our DD&A rate increased from $10.74 during
2006 to $13.11 for 2007. The primary factors causing this rate
increase were (i) $529.3 million in drilling expenditures incurred during the
past twelve months in relation to net oil and natural 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 $2.8
million, as compared to 2006. The components of exploration and
impairment costs were as follows (in thousands):
|
Year
Ended December 31,
|
||||||||
|
2007
|
2006
|
|||||||
|
Exploration
|
$ | 27,344 | $ | 30,079 | ||||
|
Impairment
|
9,979 | 4,455 | ||||||
|
Total
|
$ | 37,323 | $ | 34,534 | ||||
During
2007, we participated in a non-operated exploratory well drilled in the Gulf
Coast region that resulted in an insignificant amount of dry hole
expense. In 2006, we drilled three exploratory dry holes in the Rocky
Mountains region, one exploratory dry hole in the Gulf Coast region and one
exploratory dry hole in the Mid-Continent region, totaling $7.2
million. This reduction in exploratory dry hole expense was partially
offset by an increase in geological and geophysical (“G&G”) activity during
2007. G&G costs amounted to $15.7 million during 2007, as
compared to $12.2 million in 2006. Impairment charges in 2007 and
2006 relate to the amortization of leasehold costs associated with individually
insignificant unproved properties. As of December 31, 2007, the
amount of unproved properties being amortized totaled $51.5 million, as compared
to $16.2 million as of December 31, 2006.
General and Administrative
Expenses. We report general and administrative expenses net of
third party reimbursements and internal allocations. The components
of general and administrative expenses were as follows (in
thousands):
|
Year
Ended December 31,
|
|||||||||
|
2007
|
2006
|
||||||||
|
General
and administrative expenses
|
$ | 72,008 | $ | 60,972 | |||||
|
Reimbursements
and allocations
|
(32,962 | ) | (23,164 | ) | |||||
|
General
and administrative expenses, net
|
$ | 39,046 | $ | 37,808 | |||||
General
and administrative expenses before reimbursements and allocations increased
$11.0 million to $72.0 million during 2007. The largest components of
the increase related to (i) $7.5 million of additional salaries and wages for
personnel hired during the past twelve months and (ii) $2.9 million in
incremental distributions under our Production Participation Plan, attributable
primarily to the Company’s 2007 oil and gas property
divestitures. The increase in reimbursements and allocations in 2007
was caused by increased salary expenses and a higher number of field workers on
operated properties. In addition during the fourth quarter of 2006,
we revised our labor billing practices to better conform to COPAS
guidelines. These changes in labor billing practices resulted in
higher reimbursements and allocations and, therefore, higher amounts of lease
operating expense being allocated to us and charged to our joint interest owners
on properties we operate. Our net general and administrative expenses
as a percentage of oil and natural gas sales remained constant at 5% for both
2007 and 2006.
Interest
Expense. The components of interest expense were as follows
(in thousands):
|
Year
Ended December 31,
|
||||||||
|
2007
|
2006
|
|||||||
|
Senior
Subordinated Notes
|
$ | 44,691 | $ | 44,530 | ||||
|
Credit
Agreement
|
24,428 | 21,478 | ||||||
|
Amortization
of debt issue costs and debt discount
|
5,022 | 5,208 | ||||||
|
Accretion
of tax sharing liability
|
1,505 | 2,016 | ||||||
|
Other
|
522 | 813 | ||||||
|
Capitalized
interest
|
(3,664 | ) | (556 | ) | ||||
|
Total
interest expense
|
$ | 72,504 | $ | 73,489 | ||||
The
decrease in interest expense was mainly due to increased capitalized interest on
the construction and expansion of processing facilities. This
decrease was partially offset by increased interest expense on our credit
agreement as a result of additional borrowings outstanding in 2007, as well as
higher weighted average interest rates on our debt during 2007.
Our
weighted average debt outstanding during 2007 was $964.4 million, while it was
$945.3 million during 2006. Our weighted average effective cash
interest rate was 7.2% during 2007 compared to 7.0% during
2006. After inclusion of non-cash interest costs related to the
amortization of debt issue costs and debt discount and the accretion of the tax
sharing liability, our weighted average effective all-in interest rate was 7.7%
during 2007 compared to 7.5% during 2006.
Change in Production Participation
Plan Liability. For the year ended December 31, 2007, this
non-cash expense was $8.6 million, an increase of $2.4 million as compared to
2007. This expense represents the change in the vested present value
of estimated future payments to be made to participants after 2008 under our
Production Participation Plan (“Plan”). Although payments take place
over the life of 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 2007 and 2006
primarily reflects (i) changes to future cash flow estimates stemming from a
sustained higher commodity price environment, (ii) 2007 drilling activity and
(iii) employees’ continued vesting in the Plan. For the year ended
December 31, 2007, the five-year average historical NYMEX prices used to
estimate this liability increased $8.58 for crude oil and $0.67 for natural gas,
as compared to increases of $7.40 for crude oil and $0.52 for natural gas for
the year ended December 31, 2006. Assumptions that are used to
calculate this liability are subject to estimation and will vary from year to
year based on the current market for oil and gas, discount rates and overall
market conditions.
Income Tax
Expense. Income tax expense totaled $76.6 million in 2007 and
$76.9 million for 2006. Our effective income tax rate increased from
33.0% for 2006 to 37.0% for 2007. Our effective income tax rate was
higher for 2007 primarily due to several non-recurring benefits recognized in
2006 consisting of: a $4.3 million deferred tax benefit for 2005
enhanced oil recovery (“EOR”) tax credits; a $2.3 million benefit relating to a
true-up of our effective tax rate to our 2005 state returns as filed; and
deferred tax benefits of $1.2 million as a result of state tax legislation
enacted in 2006. In addition, we incurred incremental income tax of
$1.5 million during 2007 relating to an adjustment of prior year’s tax expense
upon filing our 2006 returns. This expense was partially offset by a
$0.6 million net deferred tax benefit recognized in 2007 for EOR credits
relating to 2003 and 2004.
EOR
credits are a credit against federal income taxes for certain costs related to
extracting high-cost oil, utilizing certain prescribed “enhanced” tertiary
recovery methods. Federal EOR credits are subject to phase-out
according to the level of average domestic crude prices. Due to high
oil prices during 2007 and 2006, the EOR credit was phased-out in those
years.
The
current portion of income tax expense was $0.6 million for 2007 compared to
$12.3 million in 2006. We reported a net operating loss in our 2007
returns, mainly due to intangible drilling deductions allowed.
Net Income. Net
income decreased from $156.4 million in 2006 to $130.6 million for
2007. The primary reasons for this decrease include a 3% decrease in
equivalent volumes sold, a 7% decrease in natural gas prices (net of hedging)
between periods, higher lease operating expenses, production taxes, DD&A,
exploration and impairment, general and administrative expenses, and change in
Production Participation Plan liability. The decreased production and
natural gas prices and increased expenses were partially offset by an 11%
increase in oil prices (net of hedging) between periods, a higher gain on sale
of properties, and lower interest expense and income taxes in 2007.
Liquidity
and Capital Resources
Overview. At
December 31, 2008, our debt to total capitalization ratio was 40.7%, we had
$9.6 million of cash on hand and $1,808.8 million of stockholders’
equity. 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 2008, we generated $763.0 million of cash
provided by operating activities, an increase of $369.0 million over
2007. Cash provided by operating activities increased primarily
because of higher oil volumes produced in 2008 and higher average sales prices
(net of hedging) for both crude oil and natural gas. We also
generated $366.8 million from financing activities primarily consisting of net
borrowings against our credit agreement. Cash flows from operating
and financing activities, as well as $193.7 million in net proceeds from the
sale of Trust units, were used to finance $892.1 million of drilling and
development expenditures paid in 2008 and $438.8 million of cash acquisition
capital expenditures. The following chart details our exploration and
development expenditures incurred by region during 2008 (in
thousands):
|
Drilling
and Development Expenditures
|
Exploration
Expenditures
|
Total
Expenditures
|
%
of Total
|
|||||||||||||
|
Rocky
Mountains
|
$ | 482,916 | $ | 9,901 | $ | 492,817 | 52 | % | ||||||||
|
Permian
Basin
|
279,236 | 10,729 | 289,965 | 31 | % | |||||||||||
|
Mid-Continent
|
94,331 | 1,984 | 96,315 | 10 | % | |||||||||||
|
Gulf
Coast
|
43,002 | 537 | 43,539 | 4 | % | |||||||||||
|
Michigan
|
18,581 | 6,151 | 24,732 | 3 | % | |||||||||||
|
Total incurred
|
918,066 | 29,302 | 947,368 | 100 | % | |||||||||||
|
Increase
in accrued capital expenditures
|
(25,972 | ) | - | (25,972 | ) | |||||||||||
|
Total paid
|
892,094 | 29,302 | $ | 921,396 | ||||||||||||
We
continually evaluate our capital needs and compare them to our capital
resources. Our current 2009 capital budget for exploration and
development expenditures is $474.0 million, which we expect to fund with net
cash provided by our operating activities and a portion of the proceeds from the
common stock offering we completed in February 2009. Our 2009 capital
budget of $474.0 million, however, represents a significant decrease from the
$947.4 million incurred on exploration and development expenditures during
2008. This reduced capital budget is in response to significantly
lower oil and natural gas prices experienced during the fourth quarter of 2008
and continuing into 2009. Although we have no specific budget for
property acquisitions in 2009, we will continue to selectively pursue property
acquisitions that complement our existing core property base. We
believe that should attractive acquisition opportunities arise or exploration
and development expenditures exceed $474.0 million, we will be able to finance
additional capital expenditures with cash on hand, cash flows from operating
activities, borrowings under our credit agreement, issuances of additional debt
or equity securities, or agreements with industry partners. Our level
of exploration and development expenditures is largely discretionary, and the
amount of funds devoted to any particular activity may increase or decrease
significantly depending on available opportunities, commodity prices, cash flows
and development results, among other factors. We believe that we have
sufficient liquidity and capital resources to execute our business plans over
the next 12 months and for the foreseeable future.
Credit
Agreement. Whiting Oil and Gas Corporation (“Whiting Oil and
Gas”), our wholly-owned subsidiary, has a $1.2 billion credit agreement with a
syndicate of banks that, as of December 31, 2008, had a borrowing base of
$900.0 million with $277.2 million of available borrowing capacity, which is net
of $620.0 million in borrowings and $2.8 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 December 31,
2008, $47.2 million was available for additional letters of credit under the
agreement.
Interest
accrues at our option at either (i) 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 (ii) 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
December 31, 2008, the effective interest rate on the outstanding principal
balance under the credit agreement was 2.5%.
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. The
credit agreement requires us to maintain a debt to EBITDAX ratio (as defined in
the 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, principal payments on senior notes 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 December 31,
2008. However, a substantial or extended decline in oil or natural
gas prices may adversely affect our ability to comply with these covenants in
the future. The credit agreement is secured by a first lien on all of
Whiting Oil and Gas’ properties included in the borrowing base for the
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, that are included in the
borrowing base for the credit agreement, as security for its
guarantee.
We
have initiated the process of renewing early this credit agreement held
with a syndicate of banks. While we believe that the process will
result in the successful renewal of our credit facility, we can provide no
assurances that this process will be successfully completed or that such renewal
will be completed on terms which are better than or equal to the current terms
of our existing credit agreement.
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 7.25% 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 7.25% notes were issued at
99.26% of par, and the associated discount is likewise 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 restrict us from
incurring additional indebtedness, subject to certain exceptions, unless our
fixed charge coverage ratio (as defined in the indentures) is at least 2.0 to
1. If we were in violation of this covenant, then we may not be able
to incur additional indebtedness, including under Whiting Oil and Gas
Corporation’s credit agreement. Additionally, the indentures
governing the notes contain restrictive covenants that may limit our ability to,
among other things, pay cash dividends, redeem or repurchase our capital stock
or our subordinated debt, make investments or issue preferred stock, sell
assets, consolidate, merge or transfer all or substantially all of the assets of
ours and our restricted subsidiaries taken as a whole and enter into hedging
contracts. These covenants may potentially limit the discretion of
our management in certain respects. We were in compliance with these
covenants as of December 31, 2008. However, a substantial or
extended decline in oil or natural gas prices may adversely affect our ability
to comply with these covenants in the future. 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.
Contractual
Obligations and Commitments
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 December 31, 2008 to make future payments
under certain contracts, aggregated by category of contractual obligation, for
specified time periods (in thousands):
|
Payments
due by period
|
||||||||||||||||||||
|
Contractual
Obligations
|
Total
|
Less
than 1 year
|
1-3
years
|
3-5
years
|
More
than 5 years
|
|||||||||||||||
|
Long-term
debt (a)
|
$ | 1,240,000 | $ | - | $ | 620,000 | $ | 370,000 | $ | 250,000 | ||||||||||
|
Cash
interest expense on debt (b)
|
229,471 | 58,285 | 96,317 | 60,285 | 14,584 | |||||||||||||||
|
Asset
retirement obligations (c)
|
54,348 | 6,456 | 2,363 | 4,928 | 40,601 | |||||||||||||||
|
Tax
sharing liability (d)
|
23,687 | 2,112 | 3,787 | 3,261 | 14,527 | |||||||||||||||
|
Derivative
contract liability fair value (e)
|
45,485 | 17,354 | 18,510 | 9,621 | - | |||||||||||||||
|
Purchase
obligations (f)
|
151,135 | 25,882 | 64,493 | 52,878 | 7,882 | |||||||||||||||
|
Drilling
rig contracts (g)
|
131,844 | 55,802 | 64,748 | 11,294 | - | |||||||||||||||
|
Operating
leases (h)
|
13,893 | 2,520 | 6,060 | 5,313 | - | |||||||||||||||
|
Total
|
$ | 1,889,863 | $ | 168,411 | $ | 876,278 | $ | 517,580 | $ | 327,594 | ||||||||||
________________
|
(a)
|
Long-term
debt consists of the 7.25% Senior Subordinated Notes due 2012 and 2013,
the 7% Senior Subordinated Notes due 2014 and the outstanding debt under
our credit agreement, and assumes no principal repayment until the due
date of the instruments.
|
|
(b)
|
Cash
interest expense on the 7.25% Senior Subordinated Notes due 2012 and 2013
and the 7% Senior Subordinated Notes due 2014 is estimated assuming no
principal repayment until the due date of the instruments. The
interest rate swap on the $75.0 million of our $150.0 million
fixed rate 7.25% Senior Subordinated Notes due 2012 is assumed to equal
5.6% 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 2.5%.
|
|
(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 primarily in the form of costless
collars to hedge our exposure to crude oil and natural gas price
fluctuations. With respect to open derivative contracts at
December 31, 2008 with certain counterparties, the forward price curves
for crude oil and natural gas generally exceeded the price curves that
were in effect when these contracts were entered into, resulting in a
derivative fair value liability. If current market prices are
higher than a collar’s price ceiling when the cash settlement amount is
calculated, we are required to pay the contract
counterparties. The ultimate settlement amounts under our
derivative contracts are unknown, however, as they are subject to
continuing market and commodity price
risk.
|
|
(f)
|
We
have two take-or-pay purchase agreements, one agreement expiring in March
2014 and one agreement expiring in December 2014, whereby we have
committed to buy certain volumes of CO2, for
use in enhanced recovery projects in our Postle field in Oklahoma and our
North Ward Estes field in Texas. The purchase agreements are
with different suppliers. Under the terms of the agreements, we
are obligated to purchase a minimum daily volume of CO2 (as
calculated on an annual basis) or else pay for any deficiencies at the
price in effect when the minimum delivery was to have
occurred. The CO2
volumes planned for use on the enhanced recovery projects in the Postle
and North Ward Estes fields currently exceed the minimum daily volumes
provided in these take-or-pay purchase agreements. Therefore,
we expect to avoid any payments for
deficiencies.
|
|
(g)
|
We
currently have nine drilling rigs under long-term contract, of which four
drilling rigs expire in 2009, two in 2010, one in 2011, and two in
2012. We also have one workover rig under contract until
2009. All of these rigs are operating in the Rocky Mountains
region. As of
December 31, 2008, early termination of these contracts would have
required maximum penalties of $90.5 million. No other drilling
rigs working for us are currently under long-term contracts or contracts
that cannot be terminated at the end of the well that is currently being
drilled. Due to the short-term and indeterminate nature of the
drilling time remaining on rigs drilling on a well-by-well basis, such
obligations have not been included in this
table.
|
|
(h)
|
We
lease 107,400 square feet of administrative office space in Denver,
Colorado under an operating lease arrangement expiring in 2013, and an
additional 46,700 square feet of office space in Midland, Texas expiring
in 2012.
|
Based on
current oil and natural gas prices and anticipated levels of production, we
believe that the estimated net cash generated from operations, together with
cash on hand and amounts available under our credit agreement, will be adequate
to meet future liquidity needs, including satisfying our financial obligations
and funding our operations and exploration and development
activities.
New
Accounting Pronouncements
On
December 31, 2008, the SEC published the final rules and interpretations
updating its oil and gas reporting requirements. Many of the revisions are
updates to definitions in the existing oil and gas rules to make them consistent
with the petroleum resource management system, which is a widely accepted
standard for the management of petroleum resources that was developed by several
industry organizations. Key revisions include the ability to include
nontraditional resources in reserves, the use of new technology for determining
reserves, permitting disclosure of probable and possible reserves, and changes
to the pricing used to determine reserves in that companies must use a 12-month
average price. The average is calculated using the
first-day-of-the-month price for each of the 12 months that make up the
reporting period. The SEC will require companies to comply with the
amended disclosure requirements for registration statements filed after January
1, 2010, and for annual reports for fiscal years ending on or after December 15,
2009. Early adoption is not permitted. We are currently assessing
the impact that the adoption will have on our disclosures, operating results,
financial position and cash flows.
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
Our
discussion of financial condition and results of operations is based upon the
information reported in our consolidated financial statements. The
preparation of these statements requires us to make certain assumptions and
estimates that affect the reported amounts of assets, liabilities, revenues and
expenses as well as the disclosure of contingent assets and liabilities at the
date of our financial statements. We base our assumptions and
estimates on historical experience and other sources that we believe to be
reasonable at the time. Actual results may vary from our estimates
due to changes in circumstances, weather, politics, global economics, mechanical
problems, general business conditions and other factors. A summary of
our significant accounting policies is detailed in Note 1 to our consolidated
financial statements. We have outlined below certain of these
policies as being of particular importance to the portrayal of our financial
position and results of operations and which require the application of
significant judgment by our management.
Successful Efforts Accounting. We account for our oil and gas operations
using the successful efforts method of accounting. Under this method,
all costs associated with property acquisitions, successful exploratory wells
and all development wells are capitalized. Items charged to expense
generally include geological and geophysical costs, costs of unsuccessful
exploratory wells and oil and gas production costs. All of our
properties are located within the continental United States and the Gulf of
Mexico.
Oil and Natural Gas Reserve
Quantities. Reserve quantities and the related estimates of
future net cash flows affect our periodic calculations of depletion, impairment
of our oil and natural gas properties, asset retirement obligations, and our
long-term Production Participation Plan liability. Proved oil and gas
reserves are the estimated quantities of crude oil, natural gas and natural gas
liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future periods from known reservoirs under
existing economic and operating conditions. Reserve quantities and
future cash flows included in this report are prepared in accordance with
guidelines established by the SEC and FASB. The accuracy of our
reserve estimates is a function of:
|
•
|
the
quality and quantity of available data;
|
|
|
•
|
the
interpretation of that data;
|
|
|
•
|
the
accuracy of various mandated economic assumptions; and
|
|
|
•
|
the
judgments of the persons preparing the
estimates.
|
Our
proved reserve information included in this report is based on estimates
prepared by our independent petroleum engineers, Cawley, Gillespie &
Associates, Inc. The independent petroleum engineers evaluated 100%
of our estimated proved reserve quantities and their related future net cash
flows as of December 31, 2008. Estimates prepared by others may
be higher or lower than our estimates. Because these estimates depend
on many assumptions, all of which may differ substantially from actual results,
reserve estimates may be different from the quantities of oil and gas that are
ultimately recovered. We continually make revisions to reserve
estimates throughout the year as additional information becomes
available. We make changes to depletion rates, impairment
calculations, asset retirement obligations and our Production Participation Plan
liability in the same period that changes to reserve estimates are
made.
Depreciation, Depletion and
Amortization. Our rate of recording DD&A is dependent upon
our estimates of total proved and proved developed reserves, which estimates
incorporate various assumptions and future projections. If the
estimates of total proved or proved developed reserves decline, the rate at
which we record DD&A expense increases, reducing our net
income. Such a decline in reserves may result from lower commodity
prices, which may make it uneconomic to drill for and produce higher cost
fields. We are unable to predict changes in reserve quantity
estimates as such quantities are dependent on the success of our exploitation
and development program, as well as future economic conditions.
Impairment of Oil and Gas
Properties. We review the value of our oil and gas properties
whenever management judges that events and circumstances indicate that the
recorded carrying value of properties may not be
recoverable. Impairments of producing properties are determined by
comparing future net undiscounted cash flows to the net book value at the end of
each period. If the net capitalized cost exceeds undiscounted future
cash flows, the cost of the property is written down to “fair value,” which is
determined using net discounted future cash flows from the producing
property. Different pricing assumptions or discount rates could
result in a different calculated impairment. We provide for
impairments on significant undeveloped properties when we determine that the
property will not be developed or a permanent impairment in value has
occurred. Individually insignificant unproved properties are
amortized on a composite basis, based on past success, experience and average
lease-term lives.
Asset Retirement
Obligation. Our asset retirement obligations (“AROs”) consist primarily
of 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 in accordance with applicable local, state and federal
laws. The discounted fair value of an ARO liability is required to be
recognized in the period in which it is incurred, with the associated asset
retirement cost capitalized as part of the carrying cost of the oil and gas
asset. The recognition of an ARO requires that management make
numerous assumptions regarding such factors as the estimated probabilities,
amounts and timing of settlements; the credit-adjusted risk-free rate to be
used; inflation rates; and future advances in technology. In periods
subsequent to the initial measurement of the ARO, we must recognize
period-to-period changes in the liability resulting from the passage of time and
revisions to either the timing or the amount of the original estimate of
undiscounted cash flows. Increases in the ARO liability due to
passage of time impact net income as accretion expense. The related
capitalized cost, including revisions thereto, is charged to expense through
DD&A over the life of the oil and gas field.
Production
Participation Plan. We have a Production Participation Plan
(“Plan”) in which all employees participate. Each year, a deemed
economic interest in all oil and gas properties acquired or developed during the
year is contributed to the Plan. The Compensation Committee of the
Board of Directors, in its discretion for each Plan year, allocates a percentage
of future net income (defined as gross revenues less production taxes, royalties
and direct lease operating expenses) attributable to such properties to Plan
participants. Once contributed and allocated, the interests (not
legally conveyed) are fixed for each Plan year. The short-term
obligation related to the Production Participation Plan is included in the
“Accrued Employee Compensation and Benefits” line item in our consolidated
balance sheets. This obligation is based on cash flows during the
year and is paid annually in cash after year end. The calculation of
this liability depends in part on our estimates of accrued revenues and costs as
of the end of each reporting period as discussed below under “Revenue
Recognition”. The vested long-term obligation related to the
Production Participation Plan is the “Production Participation Plan liability”
line item in the consolidated balance sheets. This liability is
derived primarily from reserve report estimates discounted at 12%, which as
discussed above, are subject to revision as more information becomes
available. Our price assumptions are currently determined using
average prices for the preceding three years. Variances between
estimates used to calculate liabilities related to the Production Participation
Plan and actual sales, costs and reserve data are integrated into the liability
calculations in the period identified. A 10% increase to the pricing
assumptions used in the measurement of this liability at December 31, 2008
would have decreased net income before taxes by $9.7 million in
2008.
Derivative Instruments and Hedging
Activity. We periodically enter into commodity derivative
contracts to manage our exposure to oil and natural gas price
volatility. We use hedging to help ensure that we have adequate cash
flow to fund our capital programs and manage price risks and returns on some of
our acquisitions and drilling programs. Our decision on the quantity
and price at which we choose to hedge our production is based in part on our
view of current and future market conditions. While the use of these
hedging arrangements limits the downside risk of adverse price movements, they
may also limit future revenues from favorable price movements. We
primarily utilize costless collars, which are generally placed with major
financial institutions. The oil and natural gas reference prices of
these commodity derivative contracts are based upon crude oil and natural gas
futures, which have a high degree of historical correlation with actual prices
we receive. All derivative instruments are recorded on the
consolidated balance sheet at fair value. Changes in the derivatives’
fair value are recognized currently in earnings unless specific hedge accounting
criteria are met. For qualifying cash flow hedges, the fair value
gain or loss on the derivative is deferred in accumulated other comprehensive
income (loss) to the extent the hedge is effective and is reclassified to gain
(loss) on oil and natural gas hedging activities line item in our consolidated
statements of income in the period that the hedged production is
delivered. Hedge effectiveness is measured at least quarterly based
on the relative changes in the fair value between the derivative contract and
the hedged item over time.
We value
our costless collars using industry-standard models that consider various
assumptions, including quoted forward prices for commodities, time value,
volatility factors and contractual prices for the underlying instruments, as
well as other relevant economic measures. The discount rate used in
the fair values of these instruments includes a measure of nonperformance risk
by the counterparty or us, as appropriate. We utilize the counterparties’
valuations to assess the reasonableness of our valuations. The values we report
in our financial statements change as these estimates are revised to reflect
actual results, changes in market conditions or other factors, many of which are
beyond our control.
Our
results of operations each period can be impacted by our ability to estimate the
level of correlation between future changes in the fair value of the hedge
instruments and the transactions being hedged, both at the inception and on an
ongoing basis. This correlation is complicated since energy commodity
prices, the primary risk we hedge, have quality and location differences that
can be difficult to hedge effectively. The factors underlying our
estimates of fair value and our assessment of correlation of our hedging
derivatives are impacted by actual results and changes in conditions that affect
these factors, many of which are beyond our control. If our
derivative contracts would not qualify for cash flow hedge treatment, then our
consolidated statements of income could include large non-cash fluctuations,
particularly in volatile pricing environments, as our contracts are marked to
their period end market values.
The use
of hedging transactions also involves the risk that the counterparties will be
unable to meet the financial terms of such transactions. We evaluate
the ability of our counterparties to perform at the inception of a hedging
relationship and on a periodic basis as appropriate.
Income Taxes and Uncertain Tax
Positions. We provide for income taxes in accordance with
Statement of Financial Accounting Standards No. 109, Accounting for Income
Taxes. We record deferred tax assets and liabilities to
account for the expected future tax consequences of events that have been
recognized in our financial statements and our tax returns. We
routinely assess the realizability of our deferred tax assets. If we
conclude that it is more likely than not that some portion or all of the
deferred tax assets will not be realized, the tax asset would be reduced by a
valuation allowance. We consider future taxable income in making such
assessments. Numerous judgments and assumptions are inherent in the
determination of future taxable income, including factors such as future
operating conditions (particularly as related to prevailing oil and natural gas
prices). In July 2006, the FASB issued Interpretation No. 48,
Accounting for Uncertainty in
Income Taxes — An Interpretation of FASB Statement No. 109
(“FIN 48”), which requires income tax positions to meet a
more-likely-than-not recognition threshold to be recognized in the financial
statements. Under FIN 48, tax positions that previously failed
to meet the more-likely-than-not threshold should be recognized in the first
subsequent financial reporting period in which that threshold is
met. Previously recognized tax positions that no longer meet the
more-likely-than-not threshold should be derecognized in the first subsequent
financial reporting period in which that threshold is no longer
met. Prior to 2007 we recorded contingent income tax liabilities to
the extent they were probable and could be reasonably estimated. We
are subject to taxation in many jurisdictions, and the calculation of our tax
liabilities involves dealing with uncertainties in the application of complex
tax laws and regulations in various taxing jurisdictions. If we
ultimately determine that the payment of these liabilities will be unnecessary,
we reverse the liability and recognize a tax benefit during the period in which
we determine the liability no longer applies. Conversely, we record
additional tax charges in a period in which we determine that a recorded tax
liability is less than we expect the ultimate assessment to be.
Revenue
Recognition. We predominantly derive our revenue from the sale
of produced oil and gas. Revenue is recorded in the month the product
is delivered to the purchaser. We receive payment from one to three
months after delivery. At the end of each month, we estimate the
amount of production delivered to purchasers and the price we will
receive. Variances between our estimated revenue and actual payment
are recorded in the month the payment is received. However,
differences have been insignificant.
Accounting for Business
Combinations. Our business has grown substantially through
acquisitions, and our business strategy is to continue to pursue acquisitions as
opportunities arise. We have accounted for all of our business
combinations to date using the purchase method, which is the only method
permitted under SFAS No. 141, Business Combinations, and
involves the use of significant judgment.
Under the
purchase method of accounting, a business combination is accounted for at a
purchase price based upon the fair value of the consideration
given. The assets and liabilities acquired are measured at their fair
values, and the purchase price is allocated to the assets and liabilities based
upon these fair values. The excess of the cost of an acquired entity,
if any, over the net amounts assigned to assets acquired and liabilities assumed
is recognized as goodwill. The excess of the fair value of assets
acquired and liabilities assumed over the cost of an acquired entity, if any, is
allocated as a pro rata reduction of the amounts that otherwise would have been
assigned to certain acquired assets.
Determining
the fair values of the assets and liabilities acquired involves the use of
judgment, since some of the assets and liabilities acquired do not have fair
values that are readily determinable. Different techniques may be
used to determine fair values, including market prices (where available),
appraisals, comparisons to transactions for similar assets and liabilities, and
present value of estimated future cash flows, among others. Since
these estimates involve the use of significant judgment, they can change as new
information becomes available.
Each of
the business combinations completed during the prior three years consisted of
oil and gas properties. The consideration we have paid to acquire
these properties or companies was entirely allocated to the fair value of the
assets acquired and liabilities assumed at the time of
acquisition. Consequently, there was no goodwill recognized from any
of our business combinations.
Effects
of Inflation and Pricing
We
experienced increased costs during 2008, 2007 and 2006 due to increased demand
for oil field products and services. The oil and gas industry is very
cyclical and the demand for goods and services of oil field companies, suppliers
and others associated with the industry put extreme pressure on the economic
stability and pricing structure within the industry. Typically, as
prices for oil and natural gas increase, so do all associated
costs. Conversely, in a period of declining prices, associated cost
declines are likely to lag and 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, impairment assessments of oil and gas properties, and values of
properties in purchase and sale transactions. Material changes in
prices can impact the value of oil and gas companies and their ability to raise
capital, borrow money and retain personnel. While we do not currently
expect business costs to materially increase, higher prices for oil and natural
gas could result in increases in the costs of materials, services and
personnel.
Forward-Looking
Statements
This
report contains statements that we believe to be “forward-looking statements”
within the meaning of the Private Securities Litigation Reform Act of
1995. All statements other than historical facts, including, without
limitation, statements regarding our future financial position, business
strategy, projected revenues, earnings, costs, capital expenditures and debt
levels, and plans and objectives of management for future operations, are
forward-looking statements. When used in this report, words such as
we “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe” or “should”
or the negative thereof or variations thereon or similar terminology are
generally intended to identify forward-looking statements. Such
forward-looking statements are subject to risks and uncertainties that could
cause actual results to differ materially from those expressed in, or implied
by, such statements.
These
risks and uncertainties include, but are not limited to: declines in
oil or natural gas prices; impacts of the global financial crisis; our level of
success in exploitation, exploration, development and production activities;
adverse weather conditions that may negatively impact development or production
activities; the timing of our exploration and development expenditures,
including our ability to obtain drilling rigs and CO2;
inaccuracies of our reserve estimates or our assumptions underlying them;
revisions to reserve estimates as a result of changes in commodity prices; risks
related to our level of indebtedness and periodic redeterminations of Whiting
Oil and Gas Corporation’s borrowing base under our credit agreement; our ability
to generate sufficient cash flows from operations to meet the internally funded
portion of our capital expenditures budget; our ability to obtain external
capital to finance exploration and development operations and acquisitions; our
ability to identify and complete acquisitions, and to successfully integrate
acquired businesses; unforeseen underperformance of or liabilities associated
with acquired properties; our ability to successfully complete potential asset
dispositions; failure of our properties to yield oil or gas in commercially
viable quantities; uninsured or underinsured losses resulting from our oil and
gas operations; our inability to access oil and gas markets due to market
conditions or operational impediments; the impact and costs of compliance with
laws and regulations governing our oil and gas operations; our ability to
replace our oil and natural gas reserves; any loss of our senior management or
technical personnel; competition in the oil and gas industry in the regions in
which we operate; risks arising out of our hedging transactions; and other risks
described under the caption “Risk Factors” in this Annual Report on Form
10-K. We assume no obligation, and disclaim any duty, to update the
forward-looking statements in this report.
|
Item 7A.
|
Quantitative and Qualitative Disclosure About
Market Risk
|
Commodity
Price Risk
The price
we receive for our oil and gas production heavily influences our revenue,
profitability, access to capital and future rate of growth. Crude oil
and natural gas are commodities and, therefore, their prices are subject to wide
fluctuations in response to relatively minor changes in supply and
demand. Historically, the markets for oil and gas have been volatile,
and these markets will likely continue to be volatile in the
future. The prices we receive for our production depend on numerous
factors beyond our control. Based on 2008 production, our income
before income taxes for 2008 would have moved up or down $12.4 million for each
$1.00 change in oil prices and $3.0 million for every $0.10 change in natural
gas prices.
We
periodically enter into derivative contracts to achieve a more predictable cash
flow by reducing our exposure to oil and natural gas price
volatility. Our derivative contracts have traditionally been costless
collars, although we evaluate other forms of derivative instruments as
well. Our derivative contracts have historically qualified for cash
flow hedge accounting, whereby accounting rules allow the aggregate change in
fair market value to be recorded as accumulated other comprehensive income
(loss). Recognition of derivative settlement gains and losses in the
consolidated statements of income occurs in the period that hedged production
volumes are sold.
Our
outstanding hedges as of January 1, 2009 are summarized below:
Whiting
Petroleum Corporation
|
Commodity
|
Period
|
Monthly
Volume
(Bbl)
|
Weighted
Average NYMEX Floor/Ceiling
|
|||
|
Crude
Oil
|
01/2009
to 03/2009
|
544,000
|
$50.74/$62.55
|
|||
|
Crude
Oil
|
04/2009
to 06/2009
|
518,000
|
$55.12/$65.68
|
|||
|
Crude
Oil
|
07/2009
to 09/2009
|
496,000
|
$57.12/$69.55
|
|||
|
Crude
Oil
|
10/2009
to 12/2009
|
478,000
|
$61.04/$74.89
|
|||
|
Crude
Oil
|
01/2010
to 03/2010
|
430,000
|
$60.27/$74.81
|
|||
|
Crude
Oil
|
04/2010
to 06/2010
|
415,000
|
$62.69/$80.09
|
|||
|
Crude
Oil
|
07/2010
to 09/2010
|
405,000
|
$60.28/$76.98
|
|||
|
Crude
Oil
|
10/2010
to 12/2010
|
390,000
|
$60.29/$78.23
|
|||
|
Crude
Oil
|
01/2011
to 03/2011
|
360,000
|
$60.32/$80.33
|
|||
|
Crude
Oil
|
04/2011
to 06/2011
|
360,000
|
$60.32/$80.33
|
|||
|
Crude
Oil
|
07/2011
to 09/2011
|
360,000
|
$60.32/$80.33
|
|||
|
Crude
Oil
|
10/2011
to 12/2011
|
360,000
|
$60.32/$80.33
|
|||
|
Crude
Oil
|
01/2012
to 03/2012
|
330,000
|
$60.35/$81.70
|
|||
|
Crude
Oil
|
04/2012
to 06/2012
|
330,000
|
$60.35/$81.70
|
|||
|
Crude
Oil
|
07/2012
to 09/2012
|
330,000
|
$60.35/$81.70
|
|||
|
Crude
Oil
|
10/2012
to 12/2012
|
330,000
|
$60.35/$81.70
|
|||
|
Crude
Oil
|
01/2013
to 03/2013
|
290,000
|
$60.40/$81.66
|
|||
|
Crude
Oil
|
04/2013
to 06/2013
|
290,000
|
$60.40/$81.66
|
|||
|
Crude
Oil
|
07/2013
to 09/2013
|
290,000
|
$60.40/$81.66
|
|||
|
Crude
Oil
|
10/2013
|
290,000
|
$60.40/$81.66
|
|||
|
Crude
Oil
|
11/2013
|
190,000
|
$59.29/$78.43
|
In
connection with our conveyance on April 30, 2008 of a term net profits interest
to Whiting USA Trust I (as further explained above in the note on Acquisitions
and Divestitures), the rights to any future hedge payments we make or receive on
certain of our derivative contracts, representing 2,009 MBbls of crude oil and
7,825 MMcf of natural gas from 2009 through 2012, have been conveyed to the
Trust, and therefore such payments will be included in the Trust’s calculation
of net proceeds. Under the 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
|
Commodity
|
Period
|
Monthly
Volume
(Bbl)/(MMBtu)
|
Weighted
Average NYMEX Floor/Ceiling
|
|||
|
Crude
Oil
|
01/2009
to 03/2009
|
50,118
|
$76.00/$135.85
|
|||
|
Crude
Oil
|
04/2009
to 06/2009
|
48,794
|
$76.00/$137.55
|
|||
|
Crude
Oil
|
07/2009
to 09/2009
|
47,510
|
$76.00/$136.41
|
|||
|
Crude
Oil
|
10/2009
to 12/2009
|
46,240
|
$76.00/$135.72
|
|||
|
Crude
Oil
|
01/2010
to 03/2010
|
45,084
|
$76.00/$135.09
|
|||
|
Crude
Oil
|
04/2010
to 06/2010
|
43,978
|
$76.00/$134.85
|
|||
|
Crude
Oil
|
07/2010
to 09/2010
|
42,966
|
$76.00/$134.89
|
|||
|
Crude
Oil
|
10/2010
to 12/2010
|
41,924
|
$76.00/$135.11
|
|||
|
Crude
Oil
|
01/2011
to 03/2011
|
40,978
|
$74.00/$139.68
|
|||
|
Crude
Oil
|
04/2011
to 06/2011
|
40,066
|
$74.00/$140.08
|
|||
|
Crude
Oil
|
07/2011
to 09/2011
|
39,170
|
$74.00/$140.15
|
|||
|
Crude
Oil
|
10/2011
to 12/2011
|
38,242
|
$74.00/$140.75
|
|||
|
Crude
Oil
|
01/2012
to 03/2012
|
37,412
|
$74.00/$141.27
|
|||
|
Crude
Oil
|
04/2012
to 06/2012
|
36,572
|
$74.00/$141.73
|
|||
|
Crude
Oil
|
07/2012
to 09/2012
|
35,742
|
$74.00/$141.70
|
|||
|
Crude
Oil
|
10/2012
to 12/2012
|
35,028
|
$74.00/$142.21
|
|||
|
Natural
Gas
|
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 2009 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 2009 of $6.2
million. For the 2009 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 2009 of $0.06 million.
In a 1997
acquisition of non-operated properties, we became subject to the operator’s
fixed price gas sales contract with end users for a portion of the natural gas
we produce in Michigan. This contract has built-in pricing escalators
of 4% per year. Our estimated future production volumes to be sold
under the fixed pricing terms of this contract as of January 1, 2009 are
summarized below:
|
Commodity
|
Period
Remaining
|
Monthly
Volume (MMbtu)
|
2009
Price Per MMbtu
|
|||
|
Natural
Gas
|
01/2009
to 05/2011
|
23,000
|
$
5.14
|
|||
|
Natural
Gas
|
01/2009
to 09/2012
|
67,000
|
$
4.56
|
Interest
Rate Risk
Market
risk is estimated as the change in fair value resulting from a hypothetical 100
basis point change in the interest rate on the outstanding balance under our
credit agreement. Our credit agreement allows us to fix the interest
rate for all or a portion of the principal balance for a period up to six
months. To the extent the interest rate is fixed, interest rate
changes affect the instrument’s fair market value but do not impact results of
operations or cash flows. Conversely, for the portion of the credit
agreement that has a floating interest rate, interest rate changes will not
affect the fair market value but will impact future results of operations and
cash flows. Changes in interest rates do not affect the amount of
interest we pay on our fixed-rate Senior Subordinated Notes. At
December 31, 2008, our outstanding principal balance under our credit
agreement was $620.0 million and the weighted average interest rate on the
outstanding principal balance was 2.5%. At December 31, 2008,
the carrying amount approximated fair market value. Assuming a
constant debt level of $620.0 million, the cash flow impact resulting from a 100
basis point change in interest rates during periods when the interest rate is
not fixed would be $5.9 million.
Interest
Rate Swap
In August
2004, we entered into an interest rate swap contract to hedge the fair value of
$75.0 million of our 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 we receive the fixed
rate of 7.25% and pay 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 our margin of 2.345% is less
than 7.25%, we receive a payment from the counterparty equal to the difference
in rate times $75.0 million for the six month period. When LIBOR plus
our margin of 2.345% is greater than 7.25%, we pay the counterparty an amount
equal to the difference in rate times $75.0 million for the six month
period. The LIBOR rate as of the November 1, 2008 swap reset date was
3.3%. As of December 31, 2008, we have recorded a long term asset of
$1.7 million related to the interest rate swap, which has been designated as a
fair value hedge, with a corresponding increase in the carrying value of the
Senior Subordinated Notes.
|
Item 8.
|
Financial Statements and Supplementary
Data
|
MANAGEMENT’S
ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The
management of Whiting Petroleum Corporation and subsidiaries is responsible for
establishing and maintaining adequate internal control over financial reporting,
as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities
Exchange Act of 1934. Our internal control over financial reporting
is designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles.
Because
of the inherent limitations of internal control over financial reporting,
misstatements may not be prevented or detected on a timely
basis. Also, projections of any evaluation of the effectiveness of
the internal control over financial reporting to future periods are subject to
the risk that the controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or procedures may
deteriorate.
Our
management assessed the effectiveness of our internal control over financial
reporting as of December 31, 2008 using the criteria set forth in Internal
Control - Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on this assessment,
our management believes that, as of December 31, 2008, our internal control
over financial reporting was effective based on those criteria.
The
effectiveness of our internal control over financial reporting as of
December 31, 2008 has been audited by Deloitte & Touche LLP, an
independent registered public accounting firm, as stated in their report which
is included herein on the following page.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors and Stockholders of
Whiting
Petroleum Corporation:
We have
audited the internal control over financial reporting of Whiting Petroleum
Corporation and its subsidiaries (the “Company”) as of December 31, 2008 based
on criteria established in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission. The Company's management is responsible for
maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting,
included in the accompanying Management’s Annual Report on
Internal Control Over Financial Reporting. Our responsibility is to
express an opinion on the Company's internal control over financial reporting
based on our audit.
We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness
of internal control based on the assessed risk, and performing such other
procedures as we considered necessary in the circumstances. We
believe that our audit provides a reasonable basis for our opinion.
A
company's internal control over financial reporting is a process designed by, or
under the supervision of, the company's principal executive and principal
financial officers, or persons performing similar functions, and effected by the
company's board of directors, management, and other personnel to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company's internal control
over financial reporting includes those policies and procedures that (1) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial
statements.
Because
of the inherent limitations of internal control over financial reporting,
including the possibility of collusion or improper management override of
controls, material misstatements due to error or fraud may not be prevented or
detected on a timely basis. Also, projections of any evaluation of the
effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of
changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
In our
opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2008, based on the criteria
established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated financial statements and
financial statement schedule as of and for the year ended December 31, 2008
of the Company and our report dated February 25, 2009, expressed an unqualified
opinion on those financial statements and financial statement
schedule.
/s/
DELOITTE & TOUCHE LLP
Denver,
Colorado
February
25, 2009
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors and Stockholders of
Whiting
Petroleum Corporation:
We have
audited the accompanying consolidated balance sheets of Whiting Petroleum
Corporation and subsidiaries (the "Company") as of December 31, 2008 and 2007,
and the related consolidated statements of income, stockholders' equity and
comprehensive income, and cash flows for each of the three years in the period
ended December 31, 2008. Our audits also included the financial statement
schedule listed in the Index at Item 15. These financial statements
and financial statement schedule are the responsibility of the Company's
management. Our responsibility is to express an opinion on the financial
statements and financial statement schedule based on our audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our
opinion, such consolidated financial statements present fairly, in all material
respects, the financial position of Whiting Petroleum Corporation and
subsidiaries as of December 31, 2008 and 2007, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2008, in conformity with accounting principles generally accepted
in the United States of America. Also, in our opinion, such financial
statement schedule, when considered in relation to the basic consolidated
financial statements taken as a whole, present fairly, in all material respects,
the information set forth therein.
We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the Company's internal control over financial
reporting as of December 31, 2008, based on the criteria established in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission and our report dated February 25, 2009 expressed an
unqualified opinion on the Company's internal control over financial
reporting.
/s/
DELOITTE & TOUCHE LLP
Denver,
Colorado
February
25, 2009
WHITING
PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS
(In
thousands)
|
December
31,
|
||||||||
|
2008
|
2007
|
|||||||
|
ASSETS
|
||||||||
|
CURRENT
ASSETS:
|
||||||||
|
Cash
and cash equivalents
|
$ | 9,624 | $ | 14,778 | ||||
|
Accounts
receivable trade, net
|
122,833 | 110,437 | ||||||
|
Derivative
assets
|
46,780 | - | ||||||
|
Deferred
income taxes
|
- | 27,720 | ||||||
|
Deposits
on oil field equipment
|
17,170 | - | ||||||
|
Prepaid
expenses and other
|
20,667 | 9,232 | ||||||
|
Total
current assets
|
217,074 | 162,167 | ||||||
|
PROPERTY
AND EQUIPMENT:
|
||||||||
|
Oil
and gas properties, successful efforts method:
|
||||||||
|
Proved
properties
|
4,423,197 | 3,313,777 | ||||||
|
Unproved
properties
|
106,436 | 55,084 | ||||||
|
Other
property and equipment
|
91,099 | 37,778 | ||||||
|
Total
property and equipment
|
4,620,732 | 3,406,639 | ||||||
|
Less
accumulated depreciation, depletion and amortization
|
(886,065 | ) | (646,943 | ) | ||||
|
Total
property and equipment, net
|
3,734,667 | 2,759,696 | ||||||
|
DEBT
ISSUANCE COSTS
|
10,779 | 15,016 | ||||||
|
DERIVATIVE
ASSETS
|
38,104 | - | ||||||
|
OTHER
LONG-TERM ASSETS
|
28,457 | 15,132 | ||||||
|
TOTAL
|
$ | 4,029,081 | $ | 2,952,011 | ||||
|
See
notes to consolidated financial statements.
|
(Continued)
|
|||||||
WHITING
PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS
(In
thousands, except share and per share data)
|
December
31,
|
||||||||
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
2008
|
2007
|
||||||
|
CURRENT
LIABILITIES:
|
||||||||
|
Accounts
payable
|
$ | 64,610 | $ | 19,280 | ||||
|
Accrued
capital expenditures
|
84,960 | 58,988 | ||||||
|
Accrued
liabilities
|
45,359 | 29,551 | ||||||
|
Accrued
interest
|
9,673 | 11,240 | ||||||
|
Oil
and gas sales payable
|
35,106 | 26,205 | ||||||
|
Accrued
employee compensation and benefits
|
41,911 | 21,081 | ||||||
|
Production
taxes payable
|
20,038 | 12,936 | ||||||
|
Deferred
gain on sale
|
14,650 | - | ||||||
|
Derivative
liabilities
|
17,354 | 72,796 | ||||||
|
Deferred
income taxes
|
15,395 | - | ||||||
|
Tax
sharing liability
|
2,112 | 2,587 | ||||||
|
Total
current liabilities
|
351,168 | 254,664 | ||||||
|
NON-CURRENT
LIABILITIES:
|
||||||||
|
Long-term
debt
|
1,239,751 | 868,248 | ||||||
|
Deferred
income taxes
|
390,902 | 242,964 | ||||||
|
Deferred
gain on sale
|
73,216 | - | ||||||
|
Production
Participation Plan liability
|
66,166 | 34,042 | ||||||
|
Asset
retirement obligations
|
47,892 | 35,883 | ||||||
|
Tax
sharing liability
|
21,575 | 23,070 | ||||||
|
Derivative
liabilities
|
28,131 | - | ||||||
|
Other
long-term liabilities
|
1,489 | 2,314 | ||||||
|
Total
non-current liabilities
|
1,869,122 | 1,206,521 | ||||||
|
COMMITMENTS
AND CONTINGENCIES
|
||||||||
|
STOCKHOLDERS’
EQUITY:
|
||||||||
|
Common
stock, $0.001 par value; 75,000,000 shares authorized, 42,582,100 and
42,480,497 shares issued as of December 31, 2008 and 2007,
respectively
|
43 | 42 | ||||||
|
Additional
paid-in capital
|
971,310 | 968,876 | ||||||
|
Accumulated
other comprehensive loss
|
17,271 | (46,116 | ) | |||||
|
Retained
earnings
|
820,167 | 568,024 | ||||||
|
Total
stockholders’ equity
|
1,808,791 | 1,490,826 | ||||||
|
TOTAL
|
$ | 4,029,081 | $ | 2,952,011 | ||||
|
See
notes to consolidated financial statements.
|
(Concluded)
|
|||||||
WHITING
PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF INCOME
(In
thousands, except per share data)
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
REVENUES
AND OTHER INCOME:
|
||||||||||||
|
Oil
and natural gas sales
|
$ | 1,316,480 | $ | 809,017 | $ | 773,120 | ||||||
|
Loss
on oil and natural gas hedging activities
|
(107,555 | ) | (21,189 | ) | (7,501 | ) | ||||||
|
Gain
on sale of properties
|
- | 29,682 | 12,092 | |||||||||
|
Amortization
of deferred gain on sale
|
12,143 | - | - | |||||||||
|
Interest
income and other
|
1,051 | 1,208 | 1,116 | |||||||||
|
Total
revenues and other income
|
1,222,119 | 818,718 | 778,827 | |||||||||
|
COSTS
AND EXPENSES:
|
||||||||||||
|
Lease
operating
|
241,248 | 208,866 | 183,642 | |||||||||
|
Production
taxes
|
87,548 | 52,407 | 47,095 | |||||||||
|
Depreciation,
depletion and amortization
|
277,448 | 192,811 | 162,831 | |||||||||
|
Exploration
and impairment
|
55,257 | 37,323 | 34,534 | |||||||||
|
General
and administrative
|
61,684 | 39,046 | 37,808 | |||||||||
|
Interest
expense
|
65,078 | 72,504 | 73,489 | |||||||||
|
Change
in Production Participation Plan liability
|
32,124 | 8,599 | 6,156 | |||||||||
|
Gain
on mark-to-market derivatives
|
(7,088 | ) | - | - | ||||||||
|
Total
costs and expenses
|
813,299 | 611,556 | 545,555 | |||||||||
|
INCOME
BEFORE INCOME TAXES
|
408,820 | 207,162 | 233,272 | |||||||||
|
INCOME
TAX EXPENSE:
|
||||||||||||
|
Current
|
2,361 | 550 | 12,346 | |||||||||
|
Deferred
|
154,316 | 76,012 | 64,562 | |||||||||
|
Total
income tax expense
|
156,677 | 76,562 | 76,908 | |||||||||
|
NET
INCOME
|
$ | 252,143 | $ | 130,600 | $ | 156,364 | ||||||
|
NET
INCOME PER COMMON SHARE, BASIC
|
$ | 5.96 | $ | 3.31 | $ | 4.26 | ||||||
|
NET
INCOME PER COMMON SHARE, DILUTED
|
$ | 5.94 | $ | 3.29 | $ | 4.25 | ||||||
|
WEIGHTED
AVERAGE SHARES OUTSTANDING, BASIC
|
42,310 | 39,483 | 36,736 | |||||||||
|
WEIGHTED
AVERAGE SHARES OUTSTANDING, DILUTED
|
42,447 | 39,645 | 36,826 | |||||||||
|
See
notes to consolidated financial statements.
|
||||||||||||
WHITING
PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(In
thousands)
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
||||||||||||
|
Net
income
|
$ | 252,143 | $ | 130,600 | $ | 156,364 | ||||||
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
||||||||||||
|
Depreciation,
depletion and amortization
|
277,448 | 192,811 | 162,831 | |||||||||
|
Deferred
income taxes
|
154,316 | 76,012 | 64,562 | |||||||||
|
Amortization
of debt issuance costs and debt discount
|
4,801 | 5,022 | 5,208 | |||||||||
|
Accretion
of tax sharing liability
|
1,267 | 1,505 | 2,016 | |||||||||
|
Stock-based
compensation
|
4,177 | 5,057 | 3,969 | |||||||||
|
Gain
on sale of properties
|
- | (29,682 | ) | (12,092 | ) | |||||||
|
Amortization
of deferred gain on sale
|
(12,143 | ) | - | - | ||||||||
|
Undeveloped
leasehold and oil and gas property impairments
|
25,955 | 9,979 | 4,455 | |||||||||
|
Change
in Production Participation Plan liability
|
32,124 | 8,599 | 6,156 | |||||||||
|
Unrealized
gain on mark-to-market derivatives
|
(6,189 | ) | - | - | ||||||||
|
Other
non-current
|
(18,825 | ) | (5,086 | ) | 2,653 | |||||||
|
Changes
in current assets and liabilities:
|
||||||||||||
|
Accounts
receivable trade
|
(12,396 | ) | (12,606 | ) | 3,235 | |||||||
|
Prepaid
expenses and other
|
(29,136 | ) | 1,404 | (2,268 | ) | |||||||
|
Accounts
payable and accrued liabilities
|
55,964 | (3,833 | ) | 20,412 | ||||||||
|
Accrued
interest
|
(1,567 | ) | 2,116 | (2,770 | ) | |||||||
|
Other
current liabilities
|
35,090 | 12,134 | (3,522 | ) | ||||||||
|
Net
cash provided by operating activities
|
763,029 | 394,032 | 411,209 | |||||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
||||||||||||
|
Cash
acquisition capital expenditures
|
(438,759 | ) | (21,568 | ) | (87,562 | ) | ||||||
|
Drilling
and development capital expenditures
|
(892,094 | ) | (497,988 | ) | (464,407 | ) | ||||||
|
Proceeds
from sale of oil and gas properties
|
1,450 | 52,585 | 24,390 | |||||||||
|
Proceeds
from sale of marketable securities
|
764 | - | - | |||||||||
|
Net
proceeds from sale of 11,677,500 units in Whiting USA Trust
I
|
193,692 | - | - | |||||||||
|
Net
cash used in investing activities
|
(1,134,947 | ) | (466,971 | ) | (527,579 | ) | ||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
||||||||||||
|
Issuance
of common stock
|
- | 210,394 | - | |||||||||
|
Long-term
borrowings under credit agreement
|
1,105,000 | 384,400 | 325,000 | |||||||||
|
Repayments
of long-term borrowings under credit agreement
|
(735,000 | ) | (514,400 | ) | (205,000 | ) | ||||||
|
Repayments
to Alliant Energy Corporation
|
(3,236 | ) | (3,019 | ) | (3,675 | ) | ||||||
|
Debt
issuance costs
|
- | (75 | ) | (253 | ) | |||||||
|
Tax
effect from restricted stock vesting
|
- | 45 | 288 | |||||||||
|
Net
cash provided by financing activities
|
366,764 | 77,345 | 116,360 | |||||||||
|
NET
CHANGE IN CASH AND CASH EQUIVALENTS
|
(5,154 | ) | 4,406 | (10 | ) | |||||||
|
CASH
AND CASH EQUIVALENTS:
|
||||||||||||
|
Beginning
of period
|
14,778 | 10,372 | 10,382 | |||||||||
|
End
of period
|
$ | 9,624 | $ | 14,778 | $ | 10,372 | ||||||
|
See
notes to consolidated financial statements.
|
(Continued)
|
|||||||||||
WHITING
PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(In
thousands)
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
SUPPLEMENTAL
CASH FLOW DISCLOSURES:
|
||||||||||||
|
Cash
paid for income taxes
|
$ | 1,667 | $ | 1,446 | $ | 12,063 | ||||||
|
Cash
paid for interest
|
$ | 60,578 | $ | 63,861 | $ | 69,034 | ||||||
|
NONCASH
INVESTING ACTIVITIES:
|
||||||||||||
|
Accrued
capital expenditures during the year
|
$ | 84,960 | $ | 58,988 | $ | 25,742 | ||||||
|
See
notes to consolidated financial statements.
|
(Concluded)
|
|||||||||||
WHITING
PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
(In
thousands)
|
Common
Stock
|
||||||||||||||||||||||||||||||||
|
Shares
|
Amount
|
Additional
Paid-in Capital
|
Accumulated
Other Comprehensive Income (Loss)
|
Deferred
Compensation
|
Retained
Earnings
|
Total
Stockholders’ Equity
|
Comprehensive
Income
|
|||||||||||||||||||||||||
|
BALANCES-January
1, 2006
|
36,842 | 37 | 753,093 | (34,620 | ) | (2,031 | ) | 281,383 | 997,862 | $ | 88,327 | |||||||||||||||||||||
|
Net
income
|
- | - | - | - | - | 156,364 | 156,364 | 156,364 | ||||||||||||||||||||||||
|
Change
in derivative fair values, net of taxes of $15,409
|
- | - | - | 24,140 | - | - | 24,140 | 24,140 | ||||||||||||||||||||||||
|
Realized
loss on settled derivative contracts, net of taxes of
$2,923
|
- | - | - | 4,578 | - | - | 4,578 | 4,578 | ||||||||||||||||||||||||
|
Restricted
stock issued
|
126 | - | - | - | - | - | - | - | ||||||||||||||||||||||||
|
Restricted
stock forfeited
|
(10 | ) | - | - | - | - | - | - | - | |||||||||||||||||||||||
|
Restricted
stock used for tax withholdings
|
(10 | ) | - | (440 | ) | - | - | - | (440 | ) | - | |||||||||||||||||||||
|
Tax
effect from restricted stock vesting
|
- | - | 288 | - | - | - | 288 | - | ||||||||||||||||||||||||
|
Adoption
of SFAS 123R
|
- | - | (2,122 | ) | - | 2,031 | - | (91 | ) | - | ||||||||||||||||||||||
|
Stock-based
compensation
|
- | - | 3,969 | - | - | - | 3,969 | - | ||||||||||||||||||||||||
|
BALANCES-December
31, 2006
|
36,948 | 37 | 754,788 | (5,902 | ) | - | 437,747 | 1,186,670 | $ | 185,082 | ||||||||||||||||||||||
|
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
|
- | - | - | - | - | 252,143 | 252,143 | 252,143 | ||||||||||||||||||||||||
|
Change
in derivative fair values, net of taxes of $1,812
|
- | - | - | (3,072 | ) | - | - | (3,072 | ) | (3,072 | ) | |||||||||||||||||||||
|
Realized
loss on settled derivative contracts, net of taxes of
$39,903
|
- | - | - | 67,652 | - | - | 67,652 | 67,652 | ||||||||||||||||||||||||
|
Ineffectiveness
gain on hedging activities, net of taxes of $703
|
- | - | - | (1,193 | ) | - | - | (1,193 | ) | (1,193 | ) | |||||||||||||||||||||
|
Restricted
stock issued
|
139 | 1 | - | - | - | - | 1 | - | ||||||||||||||||||||||||
|
Restricted
stock forfeited
|
(7 | ) | - | - | - | - | - | - | - | |||||||||||||||||||||||
|
Restricted
stock used for tax withholdings
|
(30 | ) | - | (1,743 | ) | - | - | - | (1,743 | ) | - | |||||||||||||||||||||
|
Stock-based
compensation
|
- | - | 4,177 | - | - | - | 4,177 | - | ||||||||||||||||||||||||
|
BALANCES-December
31, 2008
|
42,582 | $ | 43 | $ | 971,310 | $ | 17,271 | $ | - | $ | 820,167 | $ | 1,808,791 | $ | 315,530 | |||||||||||||||||
|
See
notes to consolidated financial statements.
|
||||||||||||||||||||||||||||||||
WHITING
PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
1.
|
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
|
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.
Basis of
Presentation of Consolidated Financial Statements—The 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 its 15.8% ownership
interest. Investments in entities which give Whiting significant
influence, but not control, over the investee are accounted for using the equity
method. Under the equity method, investments are stated at cost plus
the Company’s equity in undistributed earnings and losses. All
intercompany balances and transactions have been eliminated in
consolidation.
Use of
Estimates—The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities, the
disclosure of contingent assets and liabilities at the date of the financial
statements, and the reported amounts of revenues and expenses during the
reporting period. Items subject to such estimates and assumptions
include (1) oil and natural gas reserves; (2) cash flow estimates used in
impairment tests of long-lived assets; (3) depreciation, depletion and
amortization; (4) asset retirement obligations; (5) assigning fair value and
allocating purchase price in connection with business combinations; (6) income
taxes; (7) Production Participation Plan and other accrued liabilities; (8)
valuation of derivative instruments; and (9) accrued revenue and related
receivables. Although management believes these estimates are
reasonable, actual results could differ from these estimates.
Cash and Cash
Equivalents—Cash equivalents consist of demand deposits and highly liquid
investments which have an original maturity of three months or
less.
Accounts
Receivable Trade—Whiting’s accounts receivable trade consists mainly of
receivables from oil and gas purchasers and joint interest owners on properties
the Company operates. For receivables from joint interest owners,
Whiting typically has the ability to withhold future revenue disbursements to
recover any non-payment of joint interest billings. Generally, the
Company’s oil and gas receivables are collected within two months, and to date,
the Company has had minimal bad debts.
The
Company routinely assesses the recoverability of all material trade and other
receivables to determine their collectibility. At December 31, 2008
and 2007, the Company had an allowance for doubtful accounts of $0.6 million and
$0.3 million, respectively.
Inventories—Materials
and supplies inventories consist primarily of tubular goods and production
equipment, carried at weighted-average cost. Materials and supplies
are included in other property and equipment. Crude oil in tanks
inventory is carried at the lower of the estimated cost to produce or market
value and is included in prepaid expenses and other.
Oil
and Gas Properties
Proved. The
Company follows the successful efforts method of accounting for its oil and gas
properties. Under this method of accounting, all property acquisition
costs and development costs, including the cost of CO2 purchased
for injection, are capitalized when incurred and depleted on a
unit-of-production basis over the remaining life of proved reserves and proved
developed reserves, respectively. Costs of drilling exploratory wells
are initially capitalized, but are charged to expense if the well is determined
to be unsuccessful.
The
Company assesses its proved oil and gas properties for impairment whenever
events or circumstances indicate that the carrying value of the assets may not
be recoverable. The impairment test compares undiscounted future net
cash flows to the assets’ net book value. If the net capitalized
costs exceed future net cash flows, then the cost of the property is written
down to “fair value”. Fair value for oil and gas properties is
generally determined based on discounted future net cash
flows. Impairment expense for proved properties is reported in
exploration and impairment expense.
Net
carrying values of retired, sold or abandoned properties that constitute less
than a complete unit of depreciable property are charged or credited, net of
proceeds, to accumulated depreciation, depletion and amortization unless doing
so significantly affects the unit-of-production amortization rate, in which case
a gain or loss is recognized in income. Gains or losses from the
disposal of complete units of depreciable property are recognized in
income.
Interest
cost is capitalized as a component of property cost for development projects
that require greater than six months to be readied for their intended
use. During 2008, 2007 and 2006, the Company capitalized interest of
$3.1 million, $3.7 million and $0.6 million, respectively.
Unproved. Unproved
properties consist of costs incurred to acquire undeveloped leases as well as
costs to acquire unproved reserves. Undeveloped lease costs and
unproved reserve acquisition costs are capitalized, and individually
insignificant unproved properties are amortized on a composite basis, based on
past success, experience and average lease-term lives. The Company
evaluates significant unproved properties for impairment based on remaining
lease term, drilling results, reservoir performance, seismic interpretation or
future plans to develop acreage. Unamortized lease acquisition costs
related to successful exploratory drilling are reclassified to proved properties
and depleted on a unit-of-production basis. As unproved reserves are
developed and proven, the associated costs are likewise reclassified to proved
properties and depleted on a unit-of-production basis. Impairment
expense for unproved properties is reported in exploration and impairment
expense.
Exploratory. Geological
and geophysical costs,
including exploratory seismic studies, and the costs of carrying and retaining
unproved acreage are expensed as incurred. Costs of seismic studies
that are utilized in development drilling within an area of proved reserves are
capitalized as development costs. Amounts of seismic costs
capitalized are based on only those blocks of data used in determining
development well locations. To the extent that a seismic project
covers areas of both proved and unproved reserves, those seismic costs are
proportionately allocated between development costs and exploration
expense.
Costs of
drilling exploratory wells are initially capitalized, pending determination of
whether the well has found proved reserves. If an exploratory well
has not found proved reserves, the costs of drilling the well and other
associated costs are charged to expense. Cost incurred for
exploratory wells that find reserves, which cannot yet be classified as proved,
continue to be capitalized if (a) the well has found a sufficient quantity
of reserves to justify completion as a producing well, and (b) the Company
is making sufficient progress assessing the reserves and the economic and
operating viability of the project. If either condition is not met, or if
the Company obtains information that raises substantial doubt about the economic
or operational viability of the project, the exploratory well costs, net of any
salvage value, are expensed.
Other Property and
Equipment. Other property and equipment consists mainly of
materials and supplies inventories which are not depreciated. Also
included in other property and equipment are an oil pipeline, furniture and
fixtures, leasehold improvements and automobiles, which are stated at cost and
depreciated using the straight-line method over their estimated useful lives
ranging from 4 to 33 years.
Debt Issuance
Costs—Debt issuance costs related to the Company’s Senior Subordinated
Notes are amortized to interest expense using the effective interest method over
the term of the related debt. Debt issuance costs related to the
credit facility are amortized to interest expense on a straight-line basis over
the borrowing term.
Asset Retirement
Obligations and Environmental Costs—Asset retirement obligations relate
to future costs associated with the plugging and abandonment of oil and gas
wells, removal of equipment and facilities from leased acreage and returning
such land to its original condition. The fair value of a liability
for an asset retirement obligation is recorded in the period in which it is
incurred (typically when the asset is installed at the production location), and
the cost of such liability increases the carrying amount of the related
long-lived asset by the same amount. The liability is accreted each
period through charges to depreciation, depletion and amortization expense, and
the capitalized cost is depleted on a units-of-production basis over the proved
developed reserves of the related asset. Revisions to estimated
retirement obligations result in adjustments to the related capitalized asset
and corresponding liability.
Liabilities
for environmental costs are recorded on an undiscounted basis when it is
probable that obligations have been incurred and the amounts can be reasonably
estimated. These liabilities are not reduced by possible recoveries
from third parties.
Derivative
Instruments—The Company enters into derivative contracts, primarily
costless collars, to manage its exposure to commodity price risk and also enters
into derivatives, interest rate swaps, to manage its exposure to interest rate
risk. All derivative instruments, other than those that meet the
normal purchase and sales exceptions, are recorded on the balance sheet as
either an asset or liability measured at fair value. Gains and losses
from changes in the fair value of derivative instruments are recognized
immediately in earnings, unless the derivative meets specific hedge accounting
criteria, and the derivative has been designated as a hedge. Cash
flows from derivatives used to manage commodity price risk and interest rate
risk are classified in operating activities along with the cash flows of the
underlying hedged transactions. The Company does not enter into
derivative instruments for speculative or trading purposes.
For
derivatives qualifying as hedges of future cash flows, the effective portion of
any changes in fair value is recognized in accumulated other comprehensive
income (loss) and is reclassified to net income when the underlying forecasted transaction occurs. Any
ineffective portion of such hedges is recognized in (gain) loss on
mark-to-market derivatives as it occurs. The ineffective portion of the
hedge, if any, is calculated as the difference between the change in fair value
of the derivative and the estimated change in cash flows from the item hedged.
For discontinued cash flow hedges, prospective changes in the fair value
of the derivative are recognized in earnings. The accumulated gain or loss
recognized in accumulated other comprehensive income (loss) at the time a hedge
is discontinued continues to be deferred until the original forecasted
transaction occurs. However, if it is determined that the likelihood of
the original forecasted transaction occurring is no longer probable, the entire
accumulated gain or loss recognized in accumulated other comprehensive income
(loss) is immediately reclassified into earnings.
For
derivatives designated as hedges of the fair value of recognized assets,
liabilities or firm commitments, changes in the fair values of both the hedged
item and the related derivative are recognized immediately in net income with an
offsetting effect included in the basis of the hedged item. The net effect
is to report in earnings the extent to which the hedge is not effective, if any,
in achieving offsetting changes in fair value.
The
Company formally documents all relationships between hedging instruments and
hedged items, as well as the risk management objectives and strategy for
undertaking the hedge. This process includes specific identification
of the hedging instrument and the hedged item, the nature of the risk being
hedged and the manner in which the hedging instrument’s effectiveness will be
assessed. To designate a derivative as a cash flow hedge, the Company
documents at the hedge’s inception its assessment as to whether the derivative
will be highly effective in offsetting expected changes in cash flows from the
item hedged. This assessment, which is updated at least quarterly, is
generally based on the most recent relevant historical correlation between the
derivative and the item hedged. If, during the derivative’s term, the
Company determines that the hedge is no longer highly effective, hedge
accounting is prospectively discontinued.
Deferred Gain on
Sale—The deferred gain on sale of 11,677,500 Whiting USA Trust I units is
amortized to income based on the units-of-production method.
Revenue
Recognition—Oil and gas revenues are recognized when production is sold
to a purchaser at a fixed or determinable price, when delivery has occurred and
title has transferred, and if the collectibility of the revenue is
probable. Revenues from the production of gas properties in which the
Company has an interest with other producers are recognized on the basis of the
Company’s net working interest (entitlement method). Net deliveries
in excess of entitled amounts are recorded as liabilities, while net under
deliveries are reflected as receivables. Gas imbalance receivables or
payables are valued at the lowest of (i) the current market price; (ii) the
price in effect at the time of production; or (iii) the contract price, if a
contract is in hand. As of December 31, 2008 and 2007, the Company
was in a net under (over) produced imbalance position of 54,215 Mcf and
(102,000) Mcf, respectively.
General and
Administrative Expenses—General and administrative expenses are reported
net of reimbursements of overhead costs that are allocated to working interest
owners in the oil and gas properties operated by Whiting.
Maintenance and
Repairs—Maintenance and repair costs which do not extend the useful lives
of property and equipment are charged to expense as incurred. Major
replacements, renewals and betterments are capitalized.
Income
Taxes—Income taxes are provided based on earnings reported for tax return
purposes in addition to a provision for deferred income
taxes. Deferred income taxes are accounted for using the liability
method. Under this method, deferred tax assets and liabilities are
determined by applying the enacted statutory tax rates in effect at the end of a
reporting period to the cumulative temporary differences between the tax bases
of assets and liabilities and their reported amounts in the Company’s financial
statements. The effect on deferred taxes for a change in tax rates is
recognized in income in the period that includes the enactment
date. A valuation allowance for deferred tax assets is established
when it is more likely than not that some portion of the benefit from deferred
tax assets will not be realized. The Company’s income tax positions
must meet a more-likely-than-not recognition threshold to be recognized, and any
potential accrued interest and penalties related to unrecognized tax benefits
are recognized within income tax expense.
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
year. 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.
Industry Segment
and Geographic Information—The Company has evaluated how it is organized
and managed and has identified only one operating segment, which is the
exploration and production of crude oil, natural gas and natural gas
liquids. The Company considers its gathering, processing and
marketing functions as ancillary to its oil and gas producing
activities. All of the Company’s operations and assets are located in
the United States, and substantially all of its revenues are attributable to
United States customers.
Fair Value of
Financial Instruments—The Company has included fair value information in
these notes when the fair value of our financial instruments is materially
different from their book value. Cash and cash equivalents, accounts
receivable and payable are carried at cost, which approximates their fair value
because of the short-term maturity of these instruments. The
Company’s credit agreement has a recorded value that approximates its fair value
since its variable interest rate is tied to current market rates. The
Company’s interest rate swap and the related hedged portion of its Senior
Subordinated Notes are recorded at fair value, as are derivative financial
instruments, which include in the fair market value a measure of the Company’s
own nonperformance risk or that of its counterparties as
appropriate.
Concentration of
Credit Risk—Whiting is exposed to credit risk in the event of nonpayment
by counterparties, a significant portion of which are concentrated in energy
related industries. The creditworthiness of customers and other
counterparties is subject to continuing review, including the use of master
netting agreements, where appropriate. During 2008, sales to Plains
Marketing LP and Valero Energy Corporation accounted for 15% and 14%,
respectively, of the Company’s total oil and gas production
revenue. During 2007, sales to Valero Energy Corporation and Plains
Marketing LP accounted for 14% and 13%, respectively, of the Company’s total oil
and gas production revenue. During 2006, sales to Plains Marketing LP
and Valero Energy Corporation accounted for 16% and 12%, respectively, of the
Company’s total oil and gas production revenue. Commodity derivative
contracts held by the Company are with four counterparties, all of which are
part of Whiting’s credit facility and all of which have investment-grade ratings
from Moody’s and Standard & Poor. As of December 31, 2008, outstanding
derivative contracts with JP Morgan represent 73% of total crude oil and natural
gas volumes hedged.
New Accounting
Pronouncements— On December 31, 2008, the SEC published the final rules
and interpretations updating its oil and gas reporting requirements. Many
of the revisions are updates to definitions in the existing oil and gas rules to
make them consistent with the petroleum resource management system, which is a
widely accepted standard for the management of petroleum resources that was
developed by several industry organizations. Key revisions include the
ability to include nontraditional resources in reserves, the use of new
technology for determining reserves, permitting disclosure of probable and
possible reserves, and changes to the pricing used to determine reserves in that
companies must use a 12-month average price. The average is
calculated using the first-day-of-the-month price for each of the 12 months that
make up the reporting period. The SEC will require companies to
comply with the amended disclosure requirements for registration statements
filed after January 1, 2010, and for annual reports for fiscal years ending on
or after December 15, 2009. Early adoption is not permitted. We are
currently assessing the impact that the adoption will have on our disclosures,
operating results, financial position and cash flows.
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”). The Company does not currently have any minority interests and
therefore the adoption of SFAS 160 will not have a material 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 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.
|
2.
|
ACQUISITIONS
AND DIVESTITURES
|
2008
Acquisition
On
May 30, 2008, Whiting acquired interests in 31 producing gas wells,
development acreage and gas gathering and processing facilities on approximately
22,000 gross (11,500 net) acres in the Flat Rock field in Uintah County, Utah
for an aggregate unadjusted purchase price of $365.0 million.
This
acquisition was recorded using the purchase method of accounting. The
table below summarizes the allocation of the $359.4 million adjusted purchase
price, based on the acquisition date fair value of the assets acquired and the
liabilities assumed (in thousands).
|
Flat
Rock
|
||||
|
Purchase
price
|
$ | 359,380 | ||
|
Allocation
of purchase price:
|
||||
|
Proved
properties
|
$ | 251,895 | ||
|
Unproved
properties
|
79,498 | |||
|
Gas
gathering and processing facilities
|
35,736 | |||
|
Liabilities
assumed
|
(7,749 | ) | ||
|
Total
|
$ | 359,380 | ||
Acquisition Pro
Forma—In the Company’s consolidated statements of income, 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 twelve months ended December 31, 2008 and 2007, as
though the Flat Rock acquisition had occurred on the first day of each period
presented. The pro forma information below includes numerous
assumptions and is not necessarily indicative of what historical results would
have been or what future results of operations will be.
|
Pro
Forma
(Unaudited)
|
||||||||||||
|
Whiting
(As
reported)
|
Flat
Rock
|
Consolidated
|
||||||||||
|
Twelve
months ended December 31, 2008:
|
||||||||||||
|
Total
revenues
|
$ | 1,222,119 | $ | 17,761 | $ | 1,239,880 | ||||||
|
Net
income
|
252,143 | 1,144 | 253,287 | |||||||||
|
Net
income per common share – basic
|
5.96 | 0.03 | 5.99 | |||||||||
|
Net
income per common share – diluted
|
5.94 | 0.03 | 5.97 | |||||||||
|
Twelve
months ended December 31, 2007:
|
||||||||||||
|
Total
revenues
|
$ | 818,718 | $ | 24,648 | $ | 843,366 | ||||||
|
Net
income
|
130,600 | (4,560 | ) | 126,040 | ||||||||
|
Net
income per common share – basic
|
3.31 | (0.12 | ) | 3.19 | ||||||||
|
Net
income per common share – diluted
|
3.29 | (0.11 | ) | 3.18 | ||||||||
2008
Divestiture
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
$214.9 million after underwriters’ discounts and commissions and offering
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 $193.7 million. The Company used the net offering proceeds to
reduce a portion of the debt outstanding under its credit
agreement. The net proceeds from the sale of Trust units to the
public resulted in a deferred gain on sale of $100.0
million. Immediately prior to the closing of the offering, Whiting
conveyed a term net profits interest in certain of its oil and gas properties to
the Trust in exchange for 13,863,889 Trust units. The Company has
retained 15.8%, or 2,186,389 Trust units, of the total Trust units issued and
outstanding.
The net
profits interest entitles the Trust to receive 90% of the net proceeds from the
sale of oil and natural gas production from the underlying
properties. The net profits interest will terminate at the time when
9.11 MMBOE have been produced and sold from the underlying
properties. This is the equivalent of 8.2 MMBOE in respect of the
Trust’s right to receive 90% of the net proceeds from such production pursuant
to the net profits interest, and these reserve quantities are projected to be
produced by December 31, 2021, based on the reserve report for the
underlying properties as of December 31, 2008.
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.
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.
2006
Acquisitions
Utah Hingeline. On
August 29, 2006, Whiting acquired a 15% working interest in approximately
170,000 acres of unproved properties in the central Utah Hingeline play for
$25.0 million. No producing properties or proved reserves were
associated with this acquisition. As part of the acquisition of this
property, the operator agreed to pay 100% of Whiting’s drilling and completion
costs for the first three wells in the project. The three wells were
drilled, but the hydrocarbons encountered were not determined to be economic,
resulting in dry holes for all three wells. During 2008, based on
drilling results, Whiting determined that 1,873 net acres within its Utah
Hingeline position would no longer be evaluated, drilled or otherwise developed,
and Whiting has therefore recorded a $10.9 million non-cash charge for the
partial impairment of this unproved property.
Michigan
Properties. On August 15, 2006, Whiting acquired 65 producing
properties, a gathering line, gas processing plant and approximately 30,400 net
acres of leasehold held by production in Michigan for an aggregate purchase
price of $26.0 million.
The
Company funded its 2006 acquisitions with cash on hand as well as through
borrowings under its credit agreement.
2006
Divestitures
During
2006, the Company sold its interests in several non-core oil and gas producing
properties for an aggregate amount of $24.4 million in cash. The
divested properties included interests in the Cessford field in Alberta, Canada;
Permian Basin of West Texas and New Mexico; and the Ashley Valley field in
Uintah County, Utah. The Company recognized a pre-tax gain on sale of
$12.1 million related to these divestitures.
|
3.
|
LONG-TERM
DEBT
|
Long-term
debt consisted of the following at December 31, 2008 and 2007 (in
thousands):
|
December
31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Credit
agreement
|
$ | 620,000 | $ | 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
$1,541 and $1,966, respectively
|
218,459 | 218,034 | ||||||
|
7.25%
Senior Subordinated Notes due 2012, net of unamortized debt discount of
$397 and $537, respectively
|
151,292 | 150,214 | ||||||
|
Total
debt
|
$ | 1,239,751 | $ | 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 December 31, 2008, had a borrowing
base of $900.0 million with $277.2 million of available borrowing capacity,
which is net of $620.0 million in borrowings and $2.8 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 December 31, 2008, $47.2 million was
available for additional letters of credit under the agreement.
Interest
accrues at the Company’s option at either (i) 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 (ii) 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 December 31, 2008, the interest rate on the
outstanding principal balance under the credit agreement was 2.5%.
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. The credit agreement requires the Company to maintain a debt
to EBITDAX ratio (as defined in the agreement) of less than 3.5 to 1 and a
working capital ratio (as defined in the credit agreement which includes an add
back of the available borrowing capacity under the credit facility) of greater
than 1 to 1. Except for limited exceptions, including the
payment of interest on the senior notes, the credit agreement restricts the
ability of Whiting Oil and Gas and Whiting Petroleum Corporation’s wholly-owned
subsidiary, Equity Oil Company, to make any dividends, distributions, principal
payments on senior notes, or other payments to Whiting Petroleum
Corporation. The restrictions apply to all of the net assets of these
subsidiaries. The Company was in compliance with its covenants under
the credit agreement as of December 31, 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 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 $175.9 million as of
December 31, 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 $154.0 million
as of December 31, 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 $110.4 million
as of December 31, 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 restrict
the Company from incurring additional indebtedness, subject to certain
exceptions, unless its fixed charge coverage ratio (as defined in the
indentures) is at least 2.0 to 1. If the Company were in violation of
this covenant, then it may not be able to incur additional indebtedness,
including under Whiting Oil and Gas Corporation’s credit
agreement. Additionally, the indentures governing the notes contain
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 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 December 31, 2008. The
Company’s obligations under the notes are fully, unconditionally, jointly and
severally guaranteed by all of the Company’s wholly-owned operating
subsidiaries, Whiting Oil and Gas, Whiting Programs, Inc. and Equity Oil Company
(the “Guarantors”). Any subsidiaries other than the Guarantors are minor
subsidiaries as defined by Rule 3-10(h)(6) of Regulation S-X of the
Securities and Exchange Commission. Whiting Petroleum Corporation has
no assets or operations independent of this debt and its investments in
guarantor subsidiaries.
Interest Rate
Swap—In August 2004, the Company entered into an interest rate swap
contract to hedge the fair value of $75.0 million of its 7.25% Senior
Subordinated Notes due 2012. 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. The LIBOR
rate at December 31, 2008 was 1.75%. For the years ended
December 31, 2008, 2007 and 2006, Whiting recognized realized gains (losses) of
$0.9 million, $(0.4) million and $(0.2) million, respectively, on the interest
rate swap. As of December 31, 2008, the Company has recorded a
long-term asset of $1.7 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 December 31, 2008 and 2007 were $6.5 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 years ended December 31, 2008 and 2007 (in thousands):
|
Year
Ended December 31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Beginning
asset retirement obligation
|
$ | 37,192 | $ | 37,534 | ||||
|
Additional
liability incurred
|
3,503 | 1,490 | ||||||
|
Revisions
in estimated cash flows
|
16,287 | 76 | ||||||
|
Accretion
expense
|
3,236 | 2,850 | ||||||
|
Obligations
on sold or conveyed properties
|
(536 | ) | (2,557 | ) | ||||
|
Liabilities
settled
|
(5,334 | ) | (2,201 | ) | ||||
|
Ending
asset retirement obligation
|
$ | 54,348 | $ | 37,192 | ||||
During
2008, Whiting recognized $16.3 million in revisions to its asset retirement
obligations for i) changes in the estimated timing of plug and abandonment
cash outflows associated with downward revisions in oil and natural gas reserves
related to decreases in oil and natural gas prices, and ii) increases in
estimated future obligations associated with higher costs of oil field goods and
services.
|
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
December 31, 2008, accumulated other comprehensive income consisted of $27.5
million ($17.3 million after tax) of unrealized gains, representing the
mark-to-market value of the Company’s open commodity contracts designated as
cash flow hedges as of the balance sheet date. At December 31, 2007,
accumulated other comprehensive loss consisted of $72.8 million ($46.1 million
after tax) of unrealized losses, representing the mark-to-market value of the
Company’s open commodity contracts designated as cash flow hedges as of the
balance sheet date.
For the
years ended December 31, 2008, 2007 and 2006, Whiting recognized realized cash
settlement losses of $107.6 million, $21.2 million and $7.5 million,
respectively, on commodity derivatives designated as cash flow hedges, and in
2008 the Company recognized a $1.9 million unrealized gain for the ineffective
portion of the fair value change in its cash flow hedge
derivatives. Such ineffectiveness is recognized as (gain) loss on
mark-to-market derivatives in Whiting’s consolidated statements of
income. Based on the estimated fair value of the Company’s derivative
contracts designated as cash flow hedges at December 31, 2008, the Company
expects to reclassify into earnings from accumulated other comprehensive income
net after-tax gains of $16.0 million during the next twelve
months. However, actual cash settlement gains and losses recognized
may differ materially.
The
following table details the Company’s costless collar derivatives, including its
proportionate share of Trust hedges, as of January 1, 2009.
|
Whiting
Petroleum Corporation
|
||||||||||||||||
|
Contracted
Volumes
|
NYMEX
Price Collar Ranges
|
|||||||||||||||
|
Period
|
Crude
Oil
(Bbl)
|
Natural
Gas (Mcf)
|
Crude
Oil
(per
Bbl)
|
Natural
Gas
(per
Mcf)
|
||||||||||||
|
2009
|
6,247,873 | 577,820 |
$57.57
- $73.95
|
$6.50
- $17.11
|
||||||||||||
|
2010
|
5,046,289 | 495,390 |
$62.34
- $83.00
|
$6.50
- $15.06
|
||||||||||||
|
2011
|
4,435,039 | 436,510 |
$61.68
- $86.26
|
$6.50
- $14.62
|
||||||||||||
|
2012
|
4,065,091 | 384,002 |
$61.70
- $87.63
|
|
$6.50
- $14.27
|
|||||||||||
|
2013
|
3,090,000 | - |
$60.33
- $81.46
|
|
n/a
|
|||||||||||
|
Total
|
22,884,292 | 1,893,722 | ||||||||||||||
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 Whiting has retained the economic
rights to (and which are also included in the table above) are as
follows:
|
Whiting
Petroleum Corporation
|
||||||||||||||||
|
Contracted
Volumes
|
NYMEX
Price Collar Ranges
|
|||||||||||||||
|
Period
|
Crude
Oil
(Bbl)
|
Natural
Gas (Mcf)
|
Crude
Oil
(per
Bbl)
|
Natural
Gas
(per
Mcf)
|
||||||||||||
|
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
|
486,292 | 1,893,722 | ||||||||||||||
The 75.8%
portion of Trust derivative contracts for which Whiting has transferred the
economic rights to third-party public holders of Trust units (and which have not
been reflected in the above tables) are as follows:
|
Third-party
Public Holders of Trust Units
|
||||||||||||||||
|
Contracted
Volumes
|
NYMEX
Price Collar Ranges
|
|||||||||||||||
|
Period
|
Crude
Oil
(Bbl)
|
Natural
Gas
(Mcf)
|
Crude
Oil
(per
Bbl)
|
Natural
Gas
(per
Mcf)
|
||||||||||||
|
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
|
1,523,180 | 5,931,580 | ||||||||||||||
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
current derivative asset of $16.6 million, with a corresponding current
derivative liability of $12.6 million, and a non-current derivative asset of
$24.9 million, with a corresponding non-current derivative liability of $18.9
million.
The
Company has also entered into an interest rate swap designated as a fair value
hedge as further explained in Long-Term Debt.
|
6.
|
FAIR
VALUE DISCLOSURES
|
SFAS
157—Effective January 1, 2008, the Company adopted FASB
Statement No. 157, Fair
Value Measurements (“SFAS 157”) for financial assets and financial
liabilities measured at fair value on a recurring basis. SFAS 157
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. As defined in SFAS 157, fair value is the amount that
would be received to sell an asset or paid to transfer a liability in an orderly
transaction between market participants at the measurement date (“exit
price”). 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.
In
October 2008, the FASB issued FASB Staff Position No. FAS 157-3, Determining the Fair Value of a
Financial Asset When the Market for That Asset is Not Active (“FSP
157-3”), which clarifies the application of SFAS 157 in an inactive market and
provides an example to demonstrate how the fair value of a financial asset is
determined when the market for that financial asset is inactive. The
adoption of this standard did not have a material impact on the Company’s
consolidated financial statements. FSP 157-3 was effective upon issuance,
including prior periods for which financial statements had not been
issued.
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 December 31,
2008, and indicates the fair value hierarchy of the valuation techniques
utilized by the Company to determine such fair value (in
thousands):
|
Level
1
|
Level
2
|
Level
3
|
December
31, 2008
|
|||||||||||||
|
Assets
|
||||||||||||||||
|
Current
portion of commodity derivative assets
|
$ | - | $ | 46,780 | $ | - | $ | 46,780 | ||||||||
|
Non-current
commodity derivative assets
|
- | 38,104 | - | 38,104 | ||||||||||||
|
Other
long-term assets (1)
|
- | 1,690 | - | 1,690 | ||||||||||||
|
Total
|
$ | - | $ | 86,574 | $ | - | $ | 86,574 | ||||||||
|
Liabilities
|
||||||||||||||||
|
Current
portion of commodity derivative liabilities
|
$ | - | $ | 17,354 | $ | - | $ | 17,354 | ||||||||
|
Non-current
commodity derivative liabilities
|
- | 28,131 | - | 28,131 | ||||||||||||
|
Long-term
debt (1)
|
- | 1,690 | - | 1,690 | ||||||||||||
|
Total
|
$ | - | $ | 47,175 | $ | - | $ | 47,175 | ||||||||
_______________________
|
|
(1) Amount
represents interest rate swap (see note on Long-Term
Debt).
|
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 primarily of
costless collars for crude oil and natural gas. The Company’s
costless collars are valued using industry-standard modeling techniques that
consider the contractual prices for the underlying instruments as well as other
relevant economic measures. Substantially all of these assumptions
are observable in the marketplace throughout the full term of the contract, can
be derived from observable data or are supported by observable levels at which
transactions are executed in the marketplace, and are designated as Level 2
within the valuation hierarchy. The discount rate used in the fair
values of these instruments includes a measure of nonperformance risk. The
Company utilizes the counterparties’ valuations to assess the reasonableness of
its valuations.
Interest Rate Swap—The
Company’s interest rate swap is valued using the counterparty’s marked-to-market
statement, which is validated using modeling techniques that include market
inputs such as publicly available interest rate yield curves, and is designated
as Level 2 within the valuation hierarchy.
SFAS
159—In February 2007, the FASB issued Statement No. 159, The Fair Value Option for Financial
Assets and Financial Liabilities – Including an amendment of FASB Statement
No. 115 (“SFAS 159”). SFAS 159 expands the use of fair
value accounting but does not affect existing standards which require assets or
liabilities to be carried at fair value. On January 1, 2008, the
Company adopted SFAS 159 and did not elect fair value accounting for any of its
eligible items. The adoption of SFAS 159 therefore had no impact on
the Company’s consolidated financial position, cash flows or results of
operations. If the use of fair value is elected (the fair value
option), however, any upfront costs and fees related to the item must be
recognized in earnings and cannot be deferred, e.g., debt issue
costs. The fair value election is irrevocable and generally made on
an instrument-by-instrument basis, even if a company has similar instruments
that it elects not to measure based on fair value. Subsequent to the
adoption of SFAS 159, changes in fair value are recognized in
earnings.
|
7.
|
STOCKHOLDERS’
EQUITY
|
Common Stock
Offering—On
July 3, 2007, the Company completed a public offering of its common stock
under its existing shelf registration statement, selling 5,425,000 shares of
common stock at a price of $40.50 per share and providing net proceeds of $210.4
million. The number of shares includes the sale of 425,000 shares
pursuant to the exercise of the underwriters’ overallotment
option. The Company used the net proceeds to repay a portion of the
debt outstanding under its credit agreement.
Equity Incentive
Plan—The Company
maintains the Whiting Petroleum Corporation 2003 Equity Incentive Plan, pursuant
to which two million shares of the Company’s common stock have been reserved for
issuance. No employee or officer participant may be granted options
for more than 300,000 shares of common stock, stock appreciation rights relating
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. 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. For service-based
restricted stock awards, the grant date fair value is determined based on the
closing bid price of the Company’s common stock on the grant date.
In
February of 2007, 79,227 restricted shares, that are subject to certain internal
performance metrics in addition to the standard three-year service condition,
were granted to executive officers. These internal performance
conditions must be met in order for the stock awards to vest. It is
therefore possible that no shares could vest in one or more of the three-year
vesting periods. The Company recognizes compensation expense for
awards subject to performance conditions when it becomes probable that these
conditions will be achieved. However, any such compensation expense
recognized is reversed if vesting does not actually occur.
In
February of 2008, 74,542 restricted shares, that are subject to certain vesting
criteria related to Whiting’s common stock performance relative to the average
of a peer group of companies, were also granted to executive
officers. For restricted stock subject to such market-based vesting
conditions, the grant date fair value of the award is estimated using a Monte
Carlo valuation model. The Monte Carlo model is based on random
projections of stock price paths and must be repeated numerous times to achieve
a probabilistic assessment. Expected volatility was calculated from
historical daily volatilities and represents the extent to which the Company’s
stock price performance, relative to the average stock price performance of the
peer group, is expected to fluctuate during each of the three calendar periods
of the award’s anticipated term ending December 31, 2010. The
risk-free rate is based on a three-year U.S. Treasury rate consistent with the
three-year vesting period. The key assumptions used in valuing these
market-based restricted shares are as follows:
|
2008
|
||||
|
Number
of simulations
|
100,000 | |||
|
Expected
volatility
|
36.3 | % | ||
|
Risk-free
rate
|
2.24 | % | ||
The total
grant date fair value of the market-based restricted stock as determined by the
Monte Carlo valuation model is $1.8 million and will be recognized ratably over
the three-year vesting period.
For the
years ended December 31, 2008, 2007 and 2006, total stock compensation expense
recognized for restricted share awards was $4.2 million, $5.1 million and $4.0
million, respectively.
The
following table shows a summary of the Company’s nonvested restricted stock as
of December 31, 2006, 2007 and 2008 as well as activity during the years
then ended (share and per share data, not presented in thousands):
|
Number
of Shares
|
Weighted
Average
Grant
Date
Fair Value
|
|||||||
|
Restricted
stock awards nonvested, January 1, 2006
|
145,763 | $ | 32.34 | |||||
|
Granted
|
125,999 | $ | 43.38 | |||||
|
Vested
|
(58,409 | ) | $ | 27.81 | ||||
|
Forfeited
|
(10,089 | ) | $ | 37.87 | ||||
|
Restricted
stock awards nonvested, December 31, 2006
|
203,264 | $ | 39.33 | |||||
|
Granted
|
150,815 | $ | 45.24 | |||||
|
Vested
|
(101,985 | ) | $ | 36.13 | ||||
|
Forfeited
|
(12,438 | ) | $ | 44.28 | ||||
|
Restricted
stock awards nonvested, December 31, 2007
|
239,656 | $ | 44.15 | |||||
|
Granted
|
138,518 | $ | 40.67 | |||||
|
Vested
|
(112,384 | ) | $ | 43.46 | ||||
|
Forfeited
|
(7,026 | ) | $ | 50.66 | ||||
|
Restricted
stock awards nonvested, December 31, 2008
|
258,764 | $ | 42.41 | |||||
As of
December 31, 2008, there was $3.2 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 2.0 years. For the years ended December 31, 2008, 2007 and
2006, the total fair value of restricted stock vested was $6.6 million, $4.7
million and $2.6 million, respectively.
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 years
ended December 31, 2008, 2007 and 2006 amounted to $33.5 million, $15.8 million
and $13.2 million, respectively, charged to general and administrative expense
and $5.2 million, $2.8 million and $2.5 million, respectively, charged to
exploration expense.
Employees
vest in the Plan ratably at 20% per year over a five year
period. Pursuant to the terms of the Plan, (i) employees who
terminate their employment with the Company are entitled to receive their vested
allocation of future Plan year payments on an annual basis; (ii) employees will
become fully vested at age 62, regardless of when their interests would
otherwise vest; and (iii) any forfeitures inure to the benefit of the
Company.
The
Company uses average historical prices to estimate the vested long-term
Production Participation Plan liability. At December 31, 2008, the
Company used three-year average historical NYMEX prices of $79.44 for crude oil
and $7.64 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 December 31,
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 $114.6 million. This amount includes
$11.4 million attributable to proved undeveloped oil and gas properties and
$38.7 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 (in thousands):
|
Year
Ended December 31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Beginning
Production Participation Plan liability
|
$ | 34,042 | $ | 25,443 | ||||
|
Change
in liability for accretion, vesting and change in
estimates
|
70,811 | 27,225 | ||||||
|
Reduction
in liability for cash payments accrued and recognized as compensation
expense
|
(38,687 | ) | (18,626 | ) | ||||
|
Ending
Production Participation Plan liability
|
$ | 66,166 | $ | 34,042 | ||||
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
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 following table presents the estimated allocation of
the change in the liability if the Company did allocate the adjustment to these
specific line items (in thousands):
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
General
and administrative expense
|
$ | 27,852 | $ | 7,293 | $ | 5,196 | ||||||
|
Exploration
expense
|
4,272 | 1,306 | 960 | |||||||||
|
Total
|
$ | 32,124 | $ | 8,599 | $ | 6,156 | ||||||
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. The Company’s contributions for
2008, 2007 and 2006 were $3.0 million, $2.4 million and $2.1 million,
respectively. Employees vest in employer contributions at 20% per
year of completed service.
|
9.
|
INCOME
TAXES
|
Income
tax expense consists of the following (in thousands):
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
Current
income tax expense:
|
||||||||||||
|
Federal
|
$ | - | $ | 32 | $ | 11,576 | ||||||
|
State
|
2,361 | 518 | 770 | |||||||||
|
Total
current income tax expense
|
2,361 | 550 | 12,346 | |||||||||
|
Deferred
income tax expense:
|
||||||||||||
|
Federal
|
142,393 | 72,937 | 65,402 | |||||||||
|
State
|
11,923 | 3,075 | (840 | ) | ||||||||
|
Total
deferred income tax expense
|
154,316 | 76,012 | 64,562 | |||||||||
|
Total
|
$ | 156,677 | $ | 76,562 | $ | 76,908 | ||||||
Income
tax expense differed from amounts that would result from applying the U.S.
statutory income tax rate (35%) to income before income taxes as follows (in
thousands):
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
U.S.
statutory income tax expense
|
$ | 143,087 | $ | 72,506 | $ | 81,645 | ||||||
|
State
income taxes, net of federal benefit
|
13,458 | 4,176 | 907 | |||||||||
|
Tax
credits
|
- | 330 | (4,206 | ) | ||||||||
|
Statutory
depletion
|
(583 | ) | (405 | ) | (1,245 | ) | ||||||
|
Enacted
changes in state tax laws
|
- | (599 | ) | (1,295 | ) | |||||||
|
Change
in valuation allowance
|
- | 67 | 1,163 | |||||||||
|
Permanent
items
|
715 | 570 | (187 | ) | ||||||||
|
Other
|
- | (83 | ) | 126 | ||||||||
|
Total
|
$ | 156,677 | $ | 76,562 | $ | 76,908 | ||||||
The
principal components of the Company’s deferred income tax assets and liabilities
at December 31, 2008 and 2007 were as follows (in thousands):
|
Year
Ended December 31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Deferred
income tax assets:
|
||||||||
|
Net
operating loss carryforward
|
$ | 124,560 | $ | 20,952 | ||||
|
Derivative
instruments
|
- | 26,680 | ||||||
|
Production
Participation Plan liability
|
24,548 | 12,581 | ||||||
|
Tax
sharing liability
|
11,109 | 10,598 | ||||||
|
Asset
retirement obligations
|
13,050 | 11,806 | ||||||
|
Underwriter
fees
|
6,935 | - | ||||||
|
Restricted
stock compensation
|
1,979 | 2,274 | ||||||
|
Enhanced
oil recovery credit carryforwards
|
7,946 | 7,946 | ||||||
|
Alternative
minimum tax credit carryforwards
|
9,653 | 9,653 | ||||||
|
State
deductibles
|
2,215 | 2,135 | ||||||
|
Foreign
tax credit carryforwards
|
1,230 | 1,230 | ||||||
|
Other
|
655 | 110 | ||||||
|
Total
deferred income tax assets
|
203,880 | 105,965 | ||||||
|
Less
valuation allowances
|
(1,230 | ) | (1,230 | ) | ||||
|
Net
deferred income tax assets
|
202,650 | 104,735 | ||||||
|
Deferred
income tax liabilities:
|
||||||||
|
Oil
and gas properties
|
548,596 | 319,979 | ||||||
|
Derivative
instruments
|
12,482 | - | ||||||
|
Trust
distributions
|
47,869 | - | ||||||
|
Other
|
- | - | ||||||
|
Total
deferred income tax liabilities
|
608,947 | 319,979 | ||||||
|
Total
net deferred income tax liabilities
|
$ | 406,297 | $ | 215,244 | ||||
As of
December 31, 2008, we had federal net operating loss carryforwards of $344.6
million and various state net operating loss carryforwards. The
determination of the state net operating loss carryforwards is dependent upon
apportionment percentages and state laws that can change from year to year and
impact the amount of such carryforwards. If unutilized, the federal net
operating loss will expire in 2027 and 2028 and the state net operating loss
will expire between 2012 and 2028.
EOR
credits are a credit against federal income taxes for certain costs related to
extracting high-cost oil, utilizing certain prescribed “enhanced” tertiary
recovery methods. As of December 31, 2008, the Company had recognized
aggregate enhanced oil recovery credits of $7.9 million that are available to
offset regular federal income taxes in the future. These credits can
be carried forward and will expire between 2023 and 2025. Federal EOR
credits are subject to phase-out according to the level of average domestic
crude oil prices. The EOR credit has been phased-out since
2006.
The
Company is subject to the alternative minimum tax (“AMT”) principally due to
accelerated tax depreciation. As of December 31, 2008, the Company
had AMT credits totaling $9.7 million that are available to offset future
regular federal income taxes. These credits do not expire and can be
carried forward indefinitely.
At
December 31, 2008, the Company’s foreign tax credit carryforwards totaled $1.2
million, which will expire between 2014 and 2016. As of December 31,
2008, a valuation allowance of $1.2 million was established in full for the
foreign tax credit carryforwards because the Company determined that it was more
likely than not that the benefit from these deferred tax assets will not be
realized due to the divestiture of all foreign operations.
Net
deferred income tax liabilities were classified in the consolidated balance
sheets as follows (in thousands):
|
Year
Ended December 31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Assets:
|
||||||||
|
Current
deferred income taxes
|
$ | - | $ | 27,720 | ||||
|
Liabilities:
|
||||||||
|
Current
deferred income taxes
|
15,395 | - | ||||||
|
Non-current
deferred income taxes
|
390,902 | 242,964 | ||||||
|
Net
deferred income tax liabilities
|
$ | 406,297 | $ | 215,244 | ||||
On
January 1, 2007, the Company adopted the provisions of FIN 48, and the
following table summarizes the activity related to the Company's liability for
unrecognized tax benefits (in thousands):
|
Year
Ended December 31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Beginning
balance at January 1
|
$ | 170 | $ | 396 | ||||
|
Increases
related to tax position taken in the current year
|
129 | 96 | ||||||
|
Decreases
associated with accounting method change
|
- | (322 | ) | |||||
|
Ending
balance at December 31
|
$ | 299 | $ | 170 | ||||
Included
in the unrecognized tax benefit balance at December 31, 2008, are $0.2
million of tax positions, the allowance of which would positively affect the
annual effective income tax rate. For the year ended
December 31, 2008, the Company did not recognize any interest or penalties
with respect to unrecognized tax benefits, nor did the Company have any such
interest or penalties previously accrued.
The
Company files income tax returns in the U.S. Federal jurisdiction, in various
states, and previously filed in two foreign jurisdictions each with varying
statutes of limitations. The 2005 through 2008 tax years generally
remain subject to examination by federal and state tax
authorities. The foreign jurisdictions generally remain subject to
examination by their respective authorities for 2002 through 2008.
|
10.
|
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. The following table
summarizes the related party receivable and payable balances between the Company
and the Trust as of December 31, 2008 and 2007 (in thousands):
|
December
31, 2008
|
December
31, 2007
|
|||||||
|
Assets
|
||||||||
|
Unit
distributions due from Trust (1)
|
$ | 1,596 | $ | - | ||||
|
Total
|
$ | 1,596 | $ | - | ||||
|
Liabilities
|
||||||||
|
Unit
distributions payable to Trust (2)
|
$ | 10,120 | - | |||||
|
Current
portion of derivative liability
|
12,570 | - | ||||||
|
Non-current
derivative liability
|
18,907 | - | ||||||
|
Total
|
$ | 41,597 | $ | - | ||||
______________________
|
|
(1)
|
This
amount represents Whiting’s 15.8% interest in the net proceeds due from
the Trust and is included within Accounts Receivable Trade, Net in the
Company’s consolidated balance
sheets.
|
|
|
(2)
|
This
amount represents net proceeds from the Trust’s underlying properties as
well as realized cash settlements on Trust derivatives, that the Company
has received between the last Trust distribution date and December 31,
2008, but which the Company has not yet distributed to the Trust as of
December 31, 2008. Due to ongoing processing of Trust revenues
and expenses after December 31, 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 Accounts Payable in the Company’s consolidated
balance sheet.
|
For the
year ended December 31, 2008, Whiting paid $57.8 million, net of state tax
withholdings, in unit distributions to the Trust and received $9.0 million in
distributions back from the Trust pursuant to its retained ownership in
2,186,389 Trust units.
Tax Sharing
Liability—Prior to Whiting’s initial public offering in November 2003, it
was a wholly-owned indirect subsidiary of Alliant Energy Corporation (“Alliant
Energy”), a holding company whose primary businesses are utility
companies. When the transactions discussed below were entered into,
Alliant Energy was a related party of the Company. As of December 31,
2004 and thereafter, Alliant Energy was no longer a related party.
In
connection with Whiting’s initial public offering in November 2003, the Company
entered into a Tax Separation and Indemnification Agreement with Alliant
Energy. Pursuant to this agreement, the Company and Alliant Energy
made a tax election with the effect that the tax bases of Whiting’s assets were
increased to their deemed purchase price 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 $34.5 million on an undiscounted
basis.
During
2008, 2007 and 2006, the Company made payments of $3.2 million, $3.0 million and
$3.7 million, respectively, under this agreement and recognized interest expense
of $1.3 million, $1.5 million and $2.0 million, respectively. The
Company’s estimated payment of $2.1 million to be made in 2009 under this
agreement is reflected as a current liability at December 31, 2008.
The Tax
Separation and Indemnification Agreement provides that if tax rates were to
increase or decrease, the resulting tax benefit or detriment would cause a
corresponding adjustment of the tax sharing liability. For purposes
of this calculation, management has assumed that no such future changes will
occur during the term of this agreement.
The
Company periodically evaluates its estimates and assumptions as to future
payments to be made under this agreement. If non-substantial changes
(less than 10% on a present value basis) are made to the anticipated payments
owed to Alliant Energy, a new effective interest rate is determined for this
debt based on the carrying amount of the liability as of the modification date
and based on the revised payment schedule. However, if there are
substantial changes to the estimated payments owed under this agreement, then a
gain or loss is recognized in the consolidated statements of income during the
period in which the modification has been made.
Receivable from
Alliant Energy—Prior to the Company’s initial public offering, the
Company was included in the consolidated federal income tax return of Alliant
Energy. As a result, current tax due by Whiting was paid to Alliant
Energy, and current refunds were received from Alliant. Section 29
tax credits were generated by Whiting in 2002, and the Company therefore had a
current receivable from Alliant Energy of $4.1 million for these
credits. During 2007, Whiting received payment in full from Alliant,
as the Section 29 credits were entirely utilized.
Alliant Energy
Guarantee—The Company holds a 6% working interest in three offshore
platforms in California and the related onshore plant and
equipment. Alliant Energy has guaranteed the Company’s obligation in
the abandonment of these assets.
|
11.
|
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 2013 and
an additional 46,700 square feet of office space in Midland, Texas until
2012. Rental expense for 2008, 2007 and 2006 amounted to $2.2
million, $2.1 million and $1.9 million, respectively. Minimum lease
payments under the terms of non-cancelable operating leases as of December 31,
2008 are as follows (in thousands):
|
2009
|
$ | 2,520 | ||
|
2010
|
2,677 | |||
|
2011
|
3,383 | |||
|
2012
|
2,931 | |||
|
2013
|
2,382 | |||
|
Total
|
$ | 13,893 |
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 the Company’s enhanced recovery projects in Oklahoma and
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 in the Company’s enhanced recovery projects 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 December 31, 2008, future commitments under the
purchase agreements amounted to $151.1 million through 2014.
Drilling
Contracts—The
Company currently has nine drilling rigs under long-term contract, of which four
drilling rigs expire in 2009, two in 2010, one in 2011, and two in
2012. The Company also has one workover rig under contract until
2009. All of these rigs are operating in the Rocky Mountains
region. As of December 31, 2008, these agreements had total
commitments of $131.8 million and early termination would require maximum
penalties of $90.5 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.
|
12.
|
SUBSEQUENT
EVENTS
|
In
February 2009, the Company completed a public offering of its common stock under
its existing shelf registration statement, selling 8,000,000 shares of common
stock at a price of $29.00 per share and providing net proceeds of $222.2
million after underwriters’ discounts and commissions and estimated offering
expenses. Pursuant to the exercise of the underwriters’ overallotment
option, the Company sold an additional 450,000 shares of common stock at $29.00
per share, providing net proceeds of $12.5 million. The Company used
the net offering proceeds to repay a portion of the debt outstanding under
Whiting Oil and Gas’ credit agreement. Whiting plans to use a portion
of the increased credit availability to fund capital expenditures in its 2009
capital budget. Had the common stock issuance occurred at the
beginning of 2008, the number of basic and diluted shares used in the
computations of earnings per share would have been 50,759,517 and 50,897,256,
respectively, for the year ended December 31, 2008.
|
13.
|
OIL
AND GAS ACTIVITIES
|
The
Company’s oil and gas activities for 2008 and 2007 were entirely within the
United States. During 2006, the Company had insignificant foreign oil
and gas operations. Costs incurred in oil and gas producing
activities were as follows (in thousands):
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
Development
|
$ | 914,616 | $ | 506,057 | $ | 408,828 | ||||||
|
Proved
property acquisition
|
294,056 | 8,128 | 29,778 | |||||||||
|
Unproved
property acquisition
|
98,841 | 13,598 | 38,628 | |||||||||
|
Exploration
|
42,621 | 56,741 | 81,877 | |||||||||
|
Total
|
$ | 1,350,134 | $ | 584,524 | $ | 559,111 | ||||||
During
2008, 2007 and 2006, additions to oil and gas properties of $3.5 million, $1.5
million and $2.3 million were recorded for the estimated costs of future
abandonment related to new wells drilled or acquired.
Net
capitalized costs related to the Company’s oil and gas producing activities were
as follows (in thousands):
|
Year
Ended December 31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Proved
oil and gas properties
|
$ | 4,423,197 | $ | 3,313,777 | ||||
|
Unproved
oil and gas properties
|
106,436 | 55,084 | ||||||
|
Accumulated
depreciation, depletion and amortization
|
(873,233 | ) | (637,549 | ) | ||||
|
Oil
and gas properties, net
|
$ | 3,656,400 | $ | 2,731,312 | ||||
Exploratory
well costs that are incurred and expensed in the same annual period have not
been included in the table below. The net changes in capitalized
exploratory well costs were as follows (in thousands):
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
Beginning
balance at January 1
|
$ | 525 | $ | 10,194 | $ | 4,193 | ||||||
|
Additions
to capitalized exploratory well costs pending the determination of proved
reserves
|
12,794 | 19,203 | 51,798 | |||||||||
|
Reclassifications
to wells, facilities and equipment based on the determination of
proved reserves
|
(13,319 | ) | (28,872 | ) | (43,276 | ) | ||||||
|
Capitalized
exploratory well costs charged to expense
|
- | - | (2,521 | ) | ||||||||
|
Ending
balance at December 31
|
$ | - | $ | 525 | $ | 10,194 | ||||||
At
December 31, 2008, the Company had no costs capitalized for exploratory wells in
progress for a period of greater than one year after the completion of
drilling.
|
14.
|
DISCLOSURES
ABOUT OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
|
For all
years presented, the estimates of proved reserves and related valuations were
based 100% on reports prepared by the Company’s independent petroleum
engineers. The estimates of proved reserves and related valuations as
of December 31, 2008 were based on reports prepared by Cawley, Gillespie &
Associates, Inc., the Company’s independent petroleum
engineers. Proved reserve estimates included herein conform to the
definitions prescribed by the U.S. Securities and Exchange
Commission. The estimates of proved reserves are inherently imprecise
and are continually subject to revision based on production history, results of
additional exploration and development, price changes and other
factors.
As of
December 31, 2008, all of the Company’s oil and gas reserves are attributable to
properties within the United States. A summary of the Company’s
changes in quantities of proved oil and gas reserves for the years ended
December 31, 2006, 2007 and 2008, are as follows:
|
Oil
(MBbl)
|
Natural
Gas
(MMcf)
|
|||||||
|
Balance—January
1, 2006
|
199,199 | 386,412 | ||||||
|
Extensions
and discoveries
|
4,125 | 19,362 | ||||||
|
Sales
of minerals in place
|
(1,213 | ) | (983 | ) | ||||
|
Purchases
of minerals in place
|
670 | 4,009 | ||||||
|
Production
|
(9,799 | ) | (32,147 | ) | ||||
|
Revisions
to previous estimates
|
2,053 | (57,780 | ) | |||||
|
Balance—December
31, 2006
|
195,035 | 318,873 | ||||||
|
Extensions
and discoveries
|
10,973 | 40,936 | ||||||
|
Sales
of minerals in place
|
(1,194 | ) | (10,382 | ) | ||||
|
Purchases
of minerals in place
|
691 | - | ||||||
|
Production
|
(9,579 | ) | (30,764 | ) | ||||
|
Revisions
to previous estimates
|
392 | 8,079 | ||||||
|
Balance—December
31, 2007
|
196,318 | 326,742 | ||||||
|
Extensions
and discoveries
|
20,395 | 57,093 | ||||||
|
Sales
of minerals in place
|
(3,919 | ) | (14,277 | ) | ||||
|
Purchases
of minerals in place
|
513 | 90,329 | ||||||
|
Production
|
(12,448 | ) | (30,419 | ) | ||||
|
Revisions
to previous estimates
|
(20,851 | ) | (74,689 | ) | ||||
|
Balance—December
31, 2008
|
180,008 | 354,779 | ||||||
|
Proved
developed reserves:
|
||||||||
|
December
31, 2006
|
122,496 | 226,516 | ||||||
|
December
31, 2007
|
127,291 | 237,030 | ||||||
|
December
31, 2008
|
120,961 | 229,224 | ||||||
As
discussed in Employee Benefit Plans, all of the Company’s employees participate
in the Company’s Production Participation Plan. The reserve
disclosures above include oil and natural gas reserve volumes that have been
allocated to the Production Participation Plan (“Plan”). Once
allocated to Plan participants, the interests are fixed. Allocations
prior to 1995 consisted of 2%–3% overriding royalty interest, while allocations
since 1995 have been 2%–5% of oil and gas sales less lease operating expenses
and production taxes from the production allocated to the Plan.
The
standardized measure of discounted future net cash flows relating to proved oil
and gas reserves and the changes in standardized measure of discounted future
net cash flows relating to proved oil and natural gas reserves were prepared in
accordance with the provisions of SFAS No. 69. Future cash inflows
were computed by applying prices at year end to estimated future
production. Future production and development costs are computed by
estimating the expenditures to be incurred in developing and producing the
proved oil and natural gas reserves at year end, based on year-end costs and
assuming the continuation of existing economic conditions.
Future
income tax expenses are calculated by applying appropriate year-end tax rates to
future pretax net cash flows relating to proved oil and natural gas reserves,
less the tax basis of properties involved. Future income tax expenses
give effect to permanent differences, tax credits and loss carryforwards
relating to the proved oil and natural gas reserves. Future net cash
flows are discounted at a rate of 10% annually to derive the standardized
measure of discounted future net cash flows. This calculation does
not necessarily result in an estimate of the fair value of the Company’s oil and
gas properties.
The
standardized measure of discounted future net cash flows relating to proved oil
and natural gas reserves is as follows (in thousands):
|
December
31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
Future
cash flows
|
$ | 8,558,178 | $ | 19,747,430 | $ | 12,635,239 | ||||||
|
Future
production costs
|
(4,220,329 | ) | (6,022,667 | ) | (4,248,973 | ) | ||||||
|
Future
development costs
|
(982,193 | ) | (1,186,826 | ) | (1,176,778 | ) | ||||||
|
Future
income tax expense
|
(474,332 | ) | (3,952,146 | ) | (2,064,596 | ) | ||||||
|
Future
net cash flows
|
2,881,324 | 8,585,791 | 5,144,892 | |||||||||
|
10%
annual discount for estimated timing of cash flows
|
(1,504,876 | ) | (4,574,125 | ) | (2,752,650 | ) | ||||||
|
Standardized
measure of discounted future net cash flows
|
$ | 1,376,448 | $ | 4,011,666 | $ | 2,392,242 | ||||||
Future
cash flows as shown above are reported without consideration for the effects of
open hedge contracts at each period end. If the effects of hedging
transactions were included in the computation, then undiscounted future cash
flows would have increased by $345.9 million in 2008, decreased by $81.8 million
in 2007, and increased by $2.3 million in 2006.
The
changes in the standardized measure of discounted future net cash flows relating
to proved oil and natural gas reserves are as follows (in
thousands):
|
December
31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
Beginning
of year
|
$ | 4,011,665 | $ | 2,392,242 | $ | 2,882,901 | ||||||
|
Sale
of oil and gas produced, net of production costs
|
(987,682 | ) | (547,744 | ) | (542,383 | ) | ||||||
|
Sales
of minerals in place
|
(54,735 | ) | (72,360 | ) | (30,520 | ) | ||||||
|
Net
changes in prices and production costs
|
(4,059,904 | ) | 2,261,006 | (579,948 | ) | |||||||
|
Extensions,
discoveries and improved recoveries
|
259,930 | 440,337 | 162,969 | |||||||||
|
Development
costs, net
|
108,922 | (4,030 | ) | (212,076 | ) | |||||||
|
Purchases
of mineral in place
|
135,288 | 17,098 | 29,663 | |||||||||
|
Revisions
of previous quantity estimates
|
(289,381 | ) | 43,019 | (167,956 | ) | |||||||
|
Net
change in income taxes
|
1,851,178 | (757,127 | ) | 561,302 | ||||||||
|
Accretion
of discount
|
401,167 | 239,224 | 288,290 | |||||||||
|
End
of year
|
$ | 1,376,448 | $ | 4,011,665 | $ | 2,392,242 | ||||||
Average
wellhead prices in effect at December 31, 2008, 2007 and 2006 inclusive of
adjustments for quality and location used in determining future net revenues
related to the standardized measure calculation were as follows:
|
2008
|
2007
|
2006
|
||||||||||
|
Oil
(per Bbl)
|
$ | 38.51 | $ | 88.62 | $ | 54.81 | ||||||
|
Natural
Gas (per Mcf)
|
$ | 4.58 | $ | 6.31 | $ | 5.41 | ||||||
|
15.
|
QUARTERLY
FINANCIAL DATA (UNAUDITED)
|
The
following is a summary of the unaudited quarterly financial data for the years
ended December 31, 2008 and 2007 (in thousands, except per share
data):
|
Three
Months Ended
|
||||||||||||||||
|
March
31,
2008
|
June
30,
2008
|
September
30,
2008
|
December
31,
2008
|
|||||||||||||
|
Year ended December 31,
2008:
|
||||||||||||||||
|
Oil
and natural gas
sales
|
$ | 286,731 | $ | 390,536 | $ | 425,392 | $ | 213,821 | ||||||||
|
Operating
profit
(1)
|
162,828 | 252,198 | 258,224 | 36,986 | ||||||||||||
|
Net
income
|
62,314 | 80,449 | 112,417 | (3,037 | ) | |||||||||||
|
Basic
net income per
share
|
1.47 | 1.90 | 2.66 | (0.07 | ) | |||||||||||
|
Diluted
net income per
share
|
1.47 | 1.90 | 2.65 | (0.07 | ) | |||||||||||
|
Three
Months Ended
|
||||||||||||||||
|
March
31,
2007
|
June
30,
2007
|
September
30,
2007
|
December
31,
2007
|
|||||||||||||
|
Year ended December 31,
2007:
|
||||||||||||||||
|
Oil
and natural gas
sales
|
$ | 159,714 | $ | 192,646 | $ | 205,594 | $ | 251,063 | ||||||||
|
Operating
profit
(1)
|
56,474 | 79,249 | 89,617 | 129,593 | ||||||||||||
|
Net
income
|
10,666 | 26,471 | 47,713 | 45,750 | ||||||||||||
|
Basic
net income per
share
|
0.29 | 0.72 | 1.14 | 1.08 | ||||||||||||
|
Diluted
net income per
share
|
0.29 | 0.72 | 1.13 | 1.08 | ||||||||||||
(1) Oil
and natural gas sales less lease operating expense, production taxes and
depreciation, depletion and amortization.
******
|
Item 9.
|
Changes in and Disagreements with Accountants on
Accounting and Financial
Disclosure
|
None.
|
Item 9A.
|
Controls and
Procedures
|
Evaluation of disclosure controls
and procedures. In accordance with Rule 13a-15(b) of the
Securities Exchange Act of 1934 (the “Exchange Act”), our management evaluated,
with the participation of our Chairman, President and Chief Executive Officer
and our Chief Financial Officer, the effectiveness of the design and operation
of our disclosure controls and procedures (as defined in Rule 13a-15(e) under
the Exchange Act) as of the end of the year ended December 31,
2008. Based upon their evaluation of these disclosures controls and
procedures, the Chairman, President and Chief Executive Officer and the Chief
Financial Officer concluded that the disclosure controls and procedures were
effective as of the end of the year ended December 31, 2008 to ensure that
information required to be disclosed by us in the reports that we file or submit
under the Exchange Act is recorded, processed, summarized and reported within
the time periods specified in the rules and forms of the Securities and Exchange
Commission, and to ensure that information required to be disclosed by us in the
reports we file or submit under the Exchange Act is accumulated and communicated
to our management, including our principal executive and principal financial
officers, as appropriate, to allow timely decisions regarding required
disclosure.
Management’s Annual Report on
Internal Control Over Financial Reporting. The report of
management required under this Item 9A is contained in Item 8 of this Annual
Report on Form 10-K under the caption “Management’s Annual Report on Internal
Control Over Financial Reporting”.
Attestation Report of Registered
Public Accounting Firm. The attestation report required under
this Item 9A is contained in Item 8 of this Annual Report on Form 10-K under the
caption “Report of Independent Registered Public Accounting Firm”.
Changes in internal control over
financial reporting. There was no change in our internal
control over financial reporting that occurred during the quarter ended December
31, 2008 that has materially affected, or is reasonably likely to materially
affect, our internal control over financial reporting.
|
Item 9B.
|
Other
Information
|
On
February 18, 2009, the Compensation Committee of the Board of Directors of
Whiting Petroleum Corporation (the “Company”) approved grants to certain
executive officers of the Company of options to purchase shares of common stock
of the Company. The options have an exercise price of $25.51, the
fair market value of the Company’s common stock on the grant
date. The options vest one-third on each of the first three
anniversaries of the grant date and expire on the tenth anniversary of the grant
date. The named executive officers of the Company set forth below
received the number of options set forth below:
|
Name
|
Position
|
Shares
|
|
James
J. Volker
|
Chairman,
President and Chief Executive Officer
|
74,860
|
|
James
T. Brown
|
Senior
Vice President, Operations
|
16,535
|
|
Michael
J. Stevens
|
Vice
President and Chief Financial Officer
|
24,953
|
The
amounts payable to these executive officers are not determinable because the
value of the options are subject to the Company’s future stock
price. A copy of the form of award agreement used to grant such
options is filed as Exhibit 10.14 to this Annual Report on Form 10-K and is
incorporated by reference herein.
PART
III
|
Item 10.
|
Directors, Executive Officers and Corporate
Governance
|
The
information included under the captions “Election of Directors,” “Board of
Directors and Corporate Governance” and “Section 16(a) Beneficial Ownership
Reporting Compliance” in our definitive Proxy Statement for Whiting Petroleum
Corporation’s 2009 Annual Meeting of Stockholders (the “Proxy Statement”) is
hereby incorporated herein by reference. Information with respect to
our executive officers appears in Part I of this Annual Report on
Form 10-K.
We have
adopted the Whiting Petroleum Corporation Code of Business Conduct and Ethics
that applies to our directors, our Chairman, President and Chief Executive
Officer, our Chief Financial Officer, our Controller and Treasurer and other
persons performing similar functions. We have posted a copy of the
Whiting Petroleum Corporation Code of Business Conduct and Ethics on our website
at www.whiting.com. The
Whiting Petroleum Corporation Code of Business Conduct and Ethics is also
available in print to any stockholder who requests it in writing from the
Corporate Secretary of Whiting Petroleum Corporation. We intend to
satisfy the disclosure requirements under Item 5.05 of Form 8-K
regarding amendments to, or waivers from, the Whiting Petroleum Corporation Code
of Business Conduct and Ethics by posting such information on our website at
www.whiting.com.
We are
not including the information contained on our website as part of, or
incorporating it by reference into, this report.
|
Item 11.
|
Executive
Compensation
|
The
information required by this Item is included under the captions “Board of
Directors and Corporate Governance – Compensation Committee Interlocks and
Insider Participation,” “Board of Directors and Corporate Governance – Director
Compensation,” “Compensation Discussion and Analysis,” “Compensation Committee
Report” and “Executive Compensation” in the Proxy Statement and is hereby
incorporated herein by reference.
|
Item 12.
|
Security Ownership of Certain Beneficial Owners
and Management and Related Stockholder
Matters
|
The
information required by this Item with respect to security ownership of certain
beneficial owners and management is included under the caption “Principal
Stockholders” in the Proxy Statement and is hereby incorporated by
reference. The following table sets forth information with respect to
compensation plans under which equity securities of Whiting Petroleum
Corporation are authorized for issuance as of December 31,
2008.
Equity
Compensation Plan Information
|
Plan
Category
|
Number
of securities to be issued upon exercise of outstanding options, warrants
and rights
|
Weighted-average
exercise price of outstanding options, warrants and
rights
|
Number
of securities remaining available for future issuance under equity
compensation plans (excluding securities reflected in the first
column)
|
|||||||||
|
Equity
compensation plans approved by security holders(1)
|
- | N/A | 1,510,261 | (2) | ||||||||
|
Equity
compensation plans not approved by security holders
|
- | N/A | - | |||||||||
|
Total
|
- | N/A | 1,510,261 | (2) | ||||||||
|
|
_____________
|
|
(1)
|
Includes
only the Whiting Petroleum Corporation 2003 Equity Incentive
Plan.
|
|
(2)
|
Excludes
258,764 shares of restricted common stock previously issued for which the
restrictions have not lapsed.
|
|
Item 13.
|
Certain Relationships, Related Transactions and
Director Independence
|
The
information required by this Item is included under the caption “Board of
Directors and Corporate Governance – Transactions with Related Persons” and
“Board of Directors and Corporate Governance – Independence of Directors” in the
Proxy Statement and is hereby incorporated by reference.
|
Item 14.
|
Principal Accounting Fees and
Services
|
The
information required by this Item is included under the caption “Ratification of
Appointment of Independent Registered Public Accounting Firm” in the Proxy
Statement and is hereby incorporated by reference.
PART
IV
|
Item 15.
|
Exhibits, Financial Statement
Schedules
|
|
|
(a)
|
1.
|
Financial
statements – The following financial statements and the report of
independent registered public accounting firm are contained in Item
8.
|
|
|
a.
|
Report
of Independent Registered Public Accounting
Firm
|
|
|
b.
|
Consolidated
Balance Sheets as of December 31, 2008 and
2007
|
|
|
c.
|
Consolidated
Statements of Income for the Years ended December 31, 2008, 2007 and
2006
|
|
|
d.
|
Consolidated
Statements of Cash Flows for the Years ended December 31, 2008, 2007
and 2006
|
|
|
e.
|
Consolidated
Statements of Stockholders’ Equity and Comprehensive Income for the Years
ended December 31, 2008, 2007 and
2006
|
|
|
f.
|
Notes
to Consolidated Financial
Statements
|
|
|
2.
|
Financial
statement schedules – The following financial statement schedule is filed
as part of this Annual Report on Form
10-K:
|
a. Schedule
I – Condensed Financial Information of Registrant
All other
schedules are omitted since the required information is not present, or is not
present in amounts sufficient to require submission of the schedule, or because
the information required is included in the consolidated financial statements or
the notes thereto.
|
|
3.
|
Exhibits
– The exhibits listed in the accompanying index to exhibits are filed as
part of this Annual Report on Form
10-K.
|
|
(b)
|
Exhibits
|
|
|
The
exhibits listed in the accompanying exhibit index are filed (except where
otherwise indicated) as part of this
report.
|
|
(c)
|
Financial
Statement Schedules.
|
SCHEDULE I
- CONDENSED FINANCIAL INFORMATION OF REGISTRANT
WHITING
PETROLEUM CORPORATION
CONDENSED
FINANCIAL STATEMENTS OF THE PARENT COMPANY
CONDENSED
BALANCE SHEETS
(In
thousands)
|
December
31,
|
||||||||
|
2008
|
2007
|
|||||||
|
ASSETS
|
||||||||
|
Current
assets
|
$ | 2,859 | $ | 4,530 | ||||
|
Investment
in subsidiaries
|
1,187,019 | 919,186 | ||||||
|
Intercompany
receivable
|
1,249,869 | 1,256,550 | ||||||
|
TOTAL
|
$ | 2,439,747 | $ | 2,180,266 | ||||
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
||||||||
|
Current
liabilities
|
$ | 8,292 | $ | 2,587 | ||||
|
Long-term
debt
|
618,061 | 617,497 | ||||||
|
Other
long-term liabilities
|
21,874 | 23,240 | ||||||
|
Stockholders’
equity
|
1,791,520 | 1,536,942 | ||||||
|
TOTAL
|
$ | 2,439,747 | $ | 2,180,266 | ||||
CONDENSED
STATEMENTS OF OPERATIONS
(In
thousands)
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
Operating
expenses:
|
||||||||||||
|
General
and administrative
|
$ | 3,619 | $ | 4,290 | $ | 3,367 | ||||||
|
Interest
expense
|
1,830 | 2,112 | 2,671 | |||||||||
|
Equity
in earnings of subsidiaries
|
255,504 | 134,636 | 160,410 | |||||||||
|
Income
before income taxes
|
250,055 | 128,234 | 154,372 | |||||||||
|
Income
tax benefit
|
(2,088 | ) | (2,366 | ) | (1,992 | ) | ||||||
|
Net
income
|
$ | 252,143 | $ | 130,600 | $ | 156,364 | ||||||
|
See
notes to condensed financial statements.
|
||||||||||||
Schedule
I
WHITING
PETROLEUM CORPORATION
CONDENSED
FINANCIAL STATEMENTS OF THE PARENT COMPANY
CONDENSED
STATEMENTS OF CASH FLOWS
(In
thousands)
|
Year
Ended December 31,
|
||||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
Cash
flows provided by (used in) operating
activities
|
$ | 8,883 | $ | 4,633 | $ | (846 | ) | |||||
|
Cash
flows from investing activities
|
||||||||||||
|
Investment
in subsidiaries
|
- | - | - | |||||||||
|
Cash
flows from financing activities:
|
||||||||||||
|
Intercompany
receivable
|
(5,647 | ) | (1,659 | ) | 4,233 | |||||||
|
Other
financing activities
|
(3,236 | ) | (2,974 | ) | (3,387 | ) | ||||||
|
Net
cash (used in) provided by financing activities
|
(8,883 | ) | (4,633 | ) | 846 | |||||||
|
Net
change in cash and cash equivalents
|
- | - | - | |||||||||
|
Cash
and cash equivalents:
|
||||||||||||
|
Beginning
of period
|
- | - | - | |||||||||
|
End
of period
|
$ | - | $ | - | $ | - | ||||||
|
NONCASH
INVESTING ACTIVITES:
|
||||||||||||
|
Conveyance
to Whiting USA Trust I increasing investment in
subsidiaries
|
$ | 111,223 | $ | - | $ | - | ||||||
|
Sale
of Whiting USA Trust I units decreasing investment in
subsidiaries
|
$ | (93,683 | ) | $ | - | $ | - | |||||
|
Distributions
from Whiting USA Trust I decreasing investment in
subsidiaries
|
$ | (5,212 | ) | $ | - | $ | - | |||||
|
NONCASH
FINANCING ACTIVITES:
|
||||||||||||
|
Conveyance
to Whiting USA Trust I decreasing intercompany receivable
|
$ | (111,223 | ) | $ | - | $ | - | |||||
|
Sale
of Whiting USA Trust I units increasing intercompany
receivable
|
$ | 93,683 | $ | - | $ | - | ||||||
|
Distributions
from Whiting USA Trust I increasing intercompany
receivable
|
$ | 5,212 | $ | - | $ | - | ||||||
|
Issuance
of common stock increasing stockholders' equity
|
$ | - | $ | 210,394 | $ | - | ||||||
|
Issuance
of common stock decreasing intercompany receivable
|
$ | - | $ | (210,394 | ) | $ | - | |||||
|
See
notes to condensed financial statements.
|
||||||||||||
NOTES
TO CONDENSED FINANCIAL STATEMENTS
1. BASIS
OF PRESENTATION
Condensed
Financial Statements - The condensed financial statements of Whiting
Petroleum Corporation (the “Registrant” or “Parent Company”) do not include all
of the information and notes normally included with financial statements
prepared in accordance with GAAP. These condensed financial
statements, therefore, should be read in conjunction with the consolidated
financial statements and notes thereto of the Registrant, included elsewhere in
this 2008 Annual Report on Form 10-K. For purposes of these condensed
financial statements, the Parent Company’s investments in wholly-owned
subsidiaries are accounted for under the equity method.
Restricted Assets
of Registrant -
Except for limited exceptions, including the payment of interest on the
senior notes, Whiting Oil and Gas Corporation’s (“Whiting Oil and Gas”) credit
agreement restricts the ability of the subsidiaries to make any dividends,
distributions or other payments to the Parent Company. The
restrictions apply to all of the net assets of the
subsidiaries. Accordingly, these condensed financial statements have
been prepared pursuant to Rule 5-04 of Regulation
S-X of the Securities Exchange Act of 1934, as amended.
Reclassifications -
Certain prior period balances were reclassified to conform to the current year
presentation, and such reclassifications had no impact on net income or
stockholders’ equity previously reported.
|
2.
|
LONG-TERM
DEBT AND OTHER LONG-TERM
LIABILITIES
|
The
Parent Company’s long-term debt and other long-term liabilities consisted of the
following at December 31, 2008 and 2007 (in thousands):
|
December
31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Long-term
debt:
|
||||||||
|
7%
Senior Subordinated Notes due 2014
|
$ | 250,000 | $ | 250,000 | ||||
|
7.25%
Senior Subordinated Notes due 2013, net of unamortized debt discount of
$1,541 and $1,966, respectively
|
218,459 | 218,034 | ||||||
|
7.25%
Senior Subordinated Notes due 2012, net of unamortized debt discount of
$397 and $537, respectively
|
149,602 | 149,463 | ||||||
|
Other
long-term liabilities:
|
||||||||
|
Tax
sharing liability
|
21,575 | 23,070 | ||||||
|
Other
|
299 | 170 | ||||||
|
Total
long-term debt and other long-term liabilities
|
$ | 639,935 | $ | 640,737 | ||||
Scheduled
maturities of the Parent Company’s long-term debt and other long-term
liabilities as of December 31, 2008, were as follows (in
thousands):
|
2009
|
2010
|
2011
|
2012
|
2013
|
Thereafter
|
Total
|
|
$
2,112
|
$ 1,961
|
$ 1,826
|
$
151,685
|
$
221,577
|
$
264,824
|
$
643,985
|
For
further information on the Senior Subordinated Notes and tax sharing liability,
refer to the Long-Term Debt and Related Party Transactions notes to the
consolidated financial statements of the Registrant.
|
3.
|
WHITING
USA TRUST I
|
On April
30, 2008, the Parent 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, and providing net proceeds of
$214.9 million after underwriters’ discounts and commissions and offering
expenses. The 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
$193.7 million. The Parent Company used the offering net proceeds to
reduce a portion of the debt outstanding under Whiting Oil and Gas’ credit
agreement. Immediately prior to the closing of the offering, Whiting
Oil and Gas and Equity Oil Company 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, which Trust units were in turn transferred from Whiting
Oil and Gas to the Parent Company. The Parent Company retained 15.8%,
or 2,186,389 Trust units, of the total Trust units issued and
outstanding.
The net
profits interest entitles the Trust to receive 90% of the net proceeds from the
sale of oil and natural gas production from the underlying
properties. The net profits interest will terminate at the time when
9.11 MMBOE have been produced and sold from the underlying
properties. This is the equivalent of 8.2 MMBOE in respect of the
Trust’s right to receive 90% of the net proceeds from such production pursuant
to the net profits interest, and these reserve quantities are projected to be
produced by December 31, 2021, based on the reserve report for the underlying
properties as of December 31, 2008. The Trust will soon thereafter
wind up its affairs and terminate.
|
4.
|
SUBSEQUENT
EVENT
|
In
February 2009, the Parent Company completed a public offering of its common
stock under its existing shelf registration statement, selling 8,000,000 shares
of common stock at a price of $29.00 per share and providing net proceeds of
$222.2 million after underwriters’ discounts and commissions and estimated
offering expenses. Pursuant to the exercise of the underwriters’
overallotment option, the Parent Company sold an additional 450,000 shares of
common stock at $29.00 per share, providing net proceeds of $12.5
million. The Parent Company used the net offering proceeds to repay a
portion of the debt outstanding under Whiting Oil and Gas’ credit
agreement. The Parent Company plans to use a portion of the increased
credit availability to fund capital expenditures in its 2009 capital
budget. Had the common stock issuance occurred at the beginning of
2008, the number of basic and diluted shares used in the computations of
earnings per share would have been 50,759,517 and 50,897,256, respectively, for
the year ended December 31, 2008
******
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) 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 25th day of
February, 2009.
|
WHITING
PETROLEUM CORPORATION
|
||
|
By
|
/s/
James J. Volker
|
|
|
James
J. Volker
|
||
|
Chairman,
President and Chief Executive
Officer
|
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the Registrant and in the
capacities and on the dates indicated.
|
Signature
|
Title
|
Date
|
|
/s/ James J.
Volker
James
J. Volker
|
Chairman,
President, Chief
Executive
Officer and Director
(Principal
Executive Officer)
|
February
25, 2009
|
|
/s/ Michael J.
Stevens
Michael
J. Stevens
|
Vice
President and
Chief
Financial Officer
(Principal
Financial Officer)
|
February
25, 2009
|
|
/s/ Brent P.
Jensen
Brent
P. Jensen
|
Controller
and Treasurer
(Principal
Accounting Officer)
|
February
25, 2009
|
|
/s/ Thomas L.
Aller
Thomas
L. Aller
|
Director
|
February
25, 2009
|
|
/s/ D. Sherwin
Artus
D.
Sherwin Artus
|
Director
|
February
25, 2009
|
|
/s/ Thomas P.
Briggs
Thomas
P. Briggs
|
Director
|
February
25, 2009
|
|
/s/ William N.
Hahne
William
N. Hahne
|
Director
|
February
25, 2009
|
|
/s/ Graydon D.
Hubbard
Graydon
D. Hubbard
|
Director
|
February
25, 2009
|
|
/s/ Palmer L.
Moe
Palmer
L. Moe
|
Director
|
February
25, 2009
|
EXHIBIT INDEX
|
Exhibit
Number
|
Exhibit Description
|
|
(3.1)
|
Amended
and Restated Certificate of Incorporation of Whiting Petroleum Corporation
[Incorporated by reference to Exhibit 3.1 to Whiting Petroleum
Corporation’s Registration Statement on Form S-1 (Registration No.
333-107341)].
|
|
(3.2)
|
Amended
and Restated By-laws of Whiting Petroleum Corporation [Incorporated by
reference to Exhibit 3.1 to Whiting Petroleum Corporation’s Quarterly
Report on Form 10-Q for the quarter ended September 30, 2008 (File No.
001-31899)].
|
|
(3.3)
|
Certificate
of Designations of the Board of Directors Establishing the Series and
Fixing the Relative Rights and Preferences of Series A Junior
Participating Preferred Stock [Incorporated by reference to Exhibit 3.1 to
Whiting Petroleum Corporation’s Current Report on Form 8-K dated February
23, 2006 (File No. 001-31899)].
|
|
(4.1)
|
Third
Amended and Restated Credit Agreement, dated as of August 31, 2005, among
Whiting Oil and Gas Corporation, Whiting Petroleum Corporation, the
financial institutions listed therein and JPMorgan Chase Bank, N.A., as
Administrative Agent [Incorporated by reference to Exhibit 4 to Whiting
Petroleum Corporation’s Current Report on Form 8-K dated August 31,
2005 (File No. 001-31899)].
|
|
(4.2)
|
Indenture,
dated May 11, 2004, by and among Whiting Petroleum Corporation, Whiting
Oil and Gas Corporation, Whiting Programs, Inc., Equity Oil Company and
The Bank of New York Trust Company, N.A., as successor trustee
[Incorporated by reference to Exhibit 4.1 to Whiting Petroleum
Corporation’s Quarterly Report on Form 10-Q for the quarter ended
March 31, 2004 (File No. 001-31899)].
|
|
(4.3)
|
Subordinated
Indenture, dated as of April 19, 2005, by and among Whiting Petroleum
Corporation, Whiting Oil and Gas Corporation, Whiting Programs, Inc.,
Equity Oil Company and The Bank of New York Trust Company, N.A., as
successor trustee [Incorporated by reference to Exhibit 4.4 to Whiting
Petroleum Corporation’s Registration Statement on Form S-3 (Reg. No.
333-121615)].
|
|
(4.4)
|
First
Supplemental Indenture, dated as of April 19, 2005, by and among Whiting
Petroleum Corporation, Whiting Oil and Gas Corporation, Equity Oil
Company, Whiting Programs, Inc. and The Bank of New York Trust Company,
N.A., as successor trustee [Incorporated by reference to Exhibit 4.2 to
Whiting Petroleum Corporation’s Current Report on Form 8-K dated April 11,
2005 (File No. 001-31899)].
|
|
(4.5)
|
Indenture,
dated October 4, 2005, by and among Whiting Petroleum Corporation, Whiting
Oil and Gas Corporation, Whiting Programs, Inc. and The Bank of New York
Trust Company, N.A., as successor trustee [Incorporated by reference to
Exhibit 4.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K
dated October 4, 2005 (File No. 001-31899)].
|
|
(4.6)
|
Rights
Agreement, dated as of February 23, 2006, between Whiting Petroleum
Corporation and Computershare Trust Company, Inc. [Incorporated by
reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Current Report
on Form 8-K dated February 23, 2006 (File No.
001-31899)].
|
|
(10.1)*
|
Whiting
Petroleum Corporation 2003 Equity Incentive Plan, as amended through
October 23, 2007 [Incorporated by reference to Exhibit 10.2 to Whiting
Petroleum Corporation’s Current Report on Form 8-K dated October 23, 2007
(File No. 001-31899)].
|
|
(10.2)*
|
Form
of Restricted Stock Agreement pursuant to the Whiting Petroleum
Corporation 2003 Equity Incentive Plan for time-based vesting awards prior
to October 23, 2007 [Incorporated by reference to Exhibit 10.1 to Whiting
Petroleum Corporation’s Quarterly Report on Form 10-Q for the quarter
ended September 30, 2004 (File No.
001-31899)].
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|
(10.3)*
|
Form
of Restricted Stock Agreement pursuant to the Whiting Petroleum
Corporation 2003 Equity Incentive Plan for performance vesting awards
prior to October 23, 2007 and prior to February 23, 2008 [Incorporated by
reference to Exhibit 10.1 to Whiting Petroleum Corporation’s Quarterly
Report on Form 10-Q for the quarter ended March 31, 2007 (File No.
001-31899)].
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|
(10.4)*
|
Form
of Restricted Stock Agreement pursuant to the Whiting Petroleum
Corporation 2003 Equity Incentive Plan for performance vesting awards on
and after October 23, 2007 [Incorporated by reference to Exhibit 10.3 to
Whiting Petroleum Corporation’s Current Report on Form 8-K dated October
23, 2007 (File No. 001-31899)].
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|
(10.5)*
|
Form
of Restricted Stock Agreement pursuant to the Whiting Petroleum
Corporation 2003 Equity Incentive Plan for time-based vesting awards on
and after October 23, 2007 [Incorporated by reference to Exhibit 10.4 to
Whiting Petroleum Corporation’s Current Report on Form 8-K dated October
23, 2007 (File No. 001-31899)].
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|
(10.6)*
|
Form
of Restricted Stock Agreement pursuant to the Whiting Petroleum
Corporation 2003 Equity Incentive Plan for performance vesting awards on
and after February 23, 2008 [Incorporated by reference to Exhibit 10.1 to
Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the
quarter ended March 31, 2008 (File No. 001-31899)].
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|
(10.7)*
|
Whiting
Petroleum Corporation Production Participation Plan, as amended and
restated February 4, 2008 [Incorporated by reference to Exhibit 10.6 to
Whiting Petroleum Corporation’s Annual Report on Form 10-K for the year
ended December 31, 2007 (File No. 001-31899)].
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|
(10.8)
|
Tax
Separation and Indemnification Agreement between Alliant Energy
Corporation, Whiting Petroleum Corporation and Whiting Oil and Gas
Corporation [Incorporated by reference to Exhibit 10.3 to Whiting
Petroleum Corporation’s Registration Statement on Form S-1 (Registration
No. 333-107341)].
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|
(10.9)*
|
Summary
of Non-Employee Director Compensation for Whiting Petroleum
Corporation.
|
|
(10.10)*
|
Production
Participation Plan Credit Service Agreement, dated February 23, 2007,
between Whiting Petroleum Corporation and James J. Volker [Incorporated by
reference to Exhibit 10.7 to Whiting Petroleum Corporation’s Annual Report
on Form 10-K for the year ended December 31, 2006 (File No.
001-31899)].
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|
(10.11)*
|
Amended
and Restated Production Participation Plan Supplemental Payment Agreement,
dated January 14, 2008, between Whiting Petroleum Corporation and J.
Douglas Lang [Incorporated by reference to Exhibit 10.6 to Whiting
Petroleum Corporation’s Annual Report on Form 10-K for the year ended
December 31, 2007 (File No. 001-31899)].
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|
(10.12)*
|
Form
of Indemnification Agreement for directors and executive officers of
Whiting Petroleum Corporation [Incorporated by reference to Exhibit 10.10
to Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the
quarter ended September 30, 2008 (File No. 001-31899)].
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|
(10.13)*
|
Form
of Executive Excise Tax Gross-Up Agreement for executive officers of
Whiting Petroleum Corporation [Incorporated by reference to Exhibit 10.1
to Whiting Petroleum Corporation’s Current Report on Form 8-K dated
January 13, 2009 (File No. 001-31899)].
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|
(10.14)*
|
Form
of Stock Option Agreement pursuant to the Whiting Petroleum Corporation
2003 Equity Incentive Plan.
|
|
(12.1)
|
Statement
regarding computation of ratios of earnings to fixed
charges.
|
|
(21)
|
Subsidiaries
of Whiting Petroleum Corporation.
|
|
(23.1)
|
Consent
of Deloitte & Touche LLP.
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|
(23.2)
|
Consent
of Cawley, Gillespie & Associates, Inc., Independent Petroleum
Engineers.
|
|
(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)
|
Certification
of the Chairman, President and Chief Executive Officer pursuant to 18
U.S.C.
Section 1350.
|
|
(32.2)
|
Certification
of the Vice President and Chief Financial Officer pursuant to
18 U.S.C. Section 1350.
|
|
(99.1)
|
Proxy
Statement for the 2009 Annual Meeting of Stockholders, to be filed within
120 days of December 31, 2008 [To be filed with the Securities and
Exchange Commission under Regulation 14A within 120 days after December
31, 2008; except to the extent specifically incorporated by reference, the
Proxy Statement for the 2009 Annual Meeting of Stockholders shall not be
deemed to be filed with the Securities and Exchange Commission as part of
this Annual Report on Form 10-K].
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* A
management contract or compensatory plan or arrangement.
109