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, 2007
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
(State
or other jurisdiction
of
incorporation or organization)
|
20-0098515
(I.R.S.
Employer
Identification
No.)
|
|
1700
Broadway, Suite 2300
Denver,
Colorado
(Address
of principal executive offices)
|
80290-2300
(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.YesTNo£
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£NoT
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.YesTNo£
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.£
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,”
“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one):
|
Large
accelerated filerT
|
Accelerated
filer £
|
Non-accelerated
filer£
|
Smaller
reporting company £
|
Indicate
by check mark whether the Registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).Yes£NoT
Aggregate
market value of the voting common stock held by non-affiliates of the registrant
at June 30, 2007: $1,494,294,777.
Number of
shares of the registrant’s common stock outstanding at February 15,
2008: 42,241,356 shares.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions
of the Proxy Statement for the 2008 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 operating 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.
“Bcf” One billion cubic feet
of natural gas.
“BOE” One stock tank barrel
equivalent of oil, calculated by converting natural gas volumes to equivalent
oil barrels at a ratio of six Mcf to one Bbl of oil.
“BOE/d” One BOE per
day.
“Bopd” Barrels of oil or other
liquid hydrocarbons per day.
“CO2 flood” A tertiary recovery
method in which CO2 is
injected into a reservoir to enhance oil 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.
“GAAP” Generally accepted
accounting principles in the United States of America.
“farmout” An assignment of an
interest in a drilling location and related acreage conditioned upon the
drilling of a well on that location.
“MBOE” One thousand
BOE.
“MBOE/d” One thousand BOE per
day.
“Mcf” One thousand cubic feet
of natural gas.
“Mcf/d” One Mcf per
day.
“MMbbl” One million barrels of
oil or other liquid hydrocarbons.
“MMBOE” One million
BOE.
“MMbtu” One million British
Thermal Units.
“MMcf” One million cubic feet
of natural gas.
“MMcf/d” One MMcf per
day.
“NGLs” Natural gas
liquids.
“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 Securities and Exchange Commission
(“SEC”) guidelines, 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,
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.
“working interest” The
interest in an crude oil and natural gas property (normally a leasehold
interest) that gives the owner the right to drill, produce and conduct
operations on the property and to share in production, subject to all royalties,
overriding royalties and other burdens and to share in all costs of exploration,
development, operations and all risks in connection therewith.
PART
I
|
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, 2007, our estimated proved reserves
totaled 250.8 MMBOE, representing a 1% increase in our proved reserves since
December 31, 2006. Our estimated December 2007 average daily
production was 40.3 MBOE/d and implies an average reserve life of approximately
17.1 years.
The
following table summarizes our estimated proved reserves by core area, the
corresponding pre-tax PV10% value, our standardized measure of discounted future
net cash flows as of December 31, 2007, and our December 2007 average daily
production:
|
Proved
Reserves
|
||||||||||||||||||||||||
|
Core
Area
|
Oil
(MMbbl)
|
Natural
Gas (Bcf)
|
Total
(MMBOE)
|
%
Oil
|
Pre-Tax
PV10% Value(1)
|
December
2007 Average Daily Production (MBOE/d)
|
||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||
|
Permian
Basin
|
100.7 | 76.0 | 113.4 | 89 | % | $ | 2,483.0 | 10.7 | ||||||||||||||||
|
Rocky
Mountains
|
42.2 | 116.9 | 61.7 | 68 | % | 1,418.0 | 14.8 | |||||||||||||||||
|
Mid-Continent
|
46.0 | 30.6 | 51.1 | 90 | % | 1,418.0 | 7.2 | |||||||||||||||||
|
Gulf
Coast
|
3.5 | 52.5 | 12.3 | 29 | % | 284.7 | 4.1 | |||||||||||||||||
|
Michigan
|
3.9 | 50.7 | 12.3 | 32 | % | 254.6 | 3.5 | |||||||||||||||||
|
Total
|
196.3 | 326.7 | 250.8 | 78 | % | $ | 5,858.3 | 40.3 | ||||||||||||||||
|
Discounted
Future Income Taxes
|
- | - | - | - | (1,846.6 | ) | - | |||||||||||||||||
|
Standardized
Measure of Discounted Future Net Cash Flows
|
- | - | - | - | $ | 4,011.7 | - | |||||||||||||||||
_____________________
|
(1)
|
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 balanced exploration and development program while continuing to selectively
pursue acquisitions that complement our existing core properties. We
believe that our significant drilling inventory, combined with our operating
experience and cost structure, provides us with meaningful organic growth
opportunities.
Our
growth plan is centered on the following activities:
|
•
|
pursuing
the development of projects that we believe will generate attractive rates
of return;
|
|
|
•
|
maintaining
a balanced portfolio of lower risk, long-lived oil and gas properties that
provide stable cash flows;
|
|
|
•
|
seeking
property acquisitions that complement our core
areas; and
|
|
|
•
|
allocating
an increasing percentage of our capital budget to leasing and testing new
areas.
|
During
2007, we incurred $578.2 million in acquisition, development and exploration
activities, including $529.3 million for the drilling of 277 gross (138.6 net)
wells. Of these new wells, 271 resulted in productive completions and
6 were unsuccessful, yielding a 98% success rate. We have budgeted
$640.0 million for exploration and development drilling expenditures in
2008.
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.
2007
Acquisitions. There were no 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,
adjusted to the July 1, 2007 divestiture effective date, thereby yielding 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 properties for an
aggregate amount of $12.5 million in cash for total estimated proved
reserves of 0.6 MMBOE as of the divestitures’ effective dates. The
divested properties are located in Colorado, Louisiana, Michigan, Montana, New
Mexico, North Dakota, Oklahoma, Texas and Wyoming. The average daily
net production from the divested property interests was 0.3 MBOE/d as of the
dates of disposition.
2006
Acquisitions. 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
this transaction, the operator agreed to pay 100% of our drilling and completion
costs for the first three wells in the project.
On August
15, 2006, we acquired 65 producing properties, a gathering line, gas processing
plant and 30,437 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 net production from the
properties was 0.6 MBOE/d as of the acquisition effective date. We
operate 85% of the acquired properties.
We funded
our 2006 acquisitions with cash on hand and borrowings under our credit
agreement.
2006
Divestitures. During 2006, we sold our interests in several
non-core properties for an aggregate amount of $24.4 million in cash for total
estimated proved reserves of 1.4 MMBOE as of the effective dates of the
divestitures. 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 net
production from the divested property interests was 0.4 MBOE/d as of the
effective dates of disposition, and we recognized a pre-tax gain on sale of
$12.1 million related to these property sales.
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 largely through the
acquisition of additional reserves as well as continued field development in our
core areas. Based on the extensive property base we have built, we
now have several economically attractive opportunities to exploit and develop
within our oil and gas properties and several opportunities to explore our
acreage positions for production growth and additional 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 118,348 gross (83,033 net) acres on the
eastern side of the Williston Basin in North Dakota in an active oil exploration
play at our Robinson Lake prospect area, where the Middle Bakken reservoir is
oil productive. 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 reservoirs to
be gas productive at our Boies Ranch prospect area and the Williams Fork
reservoir to be gas productive at our Jimmy Gulch prospect area. Our
initial drilling results in both projects have been encouraging. We
have drilled five wells in our Robinson Lake acreage, which could support up to
90 locations on 1,280-acre spacing. In the Piceance acreage, we have
completed three wells and have identified 110 drilling locations based on
20-acre spacing.
Developing and Exploiting Existing
Properties. Our existing property base and our acquisitions
over the past three years have provided us with numerous low-risk opportunities
for exploitation and development drilling. As of December 31,
2007, we have identified a drilling inventory of over 1,900 gross wells
that we believe will add substantial production over the next five
years. Our drilling inventory consists largely of the development of
our 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 anticipate significant production
increases in these fields over the next five 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 2007, we completed 13 acquisitions
of producing properties totaling 208.4 MMBOE of estimated total proved
reserves, as of the respective acquisition effective dates. Our
experienced team of management, 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 acquire 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. We are also evaluating the
sale of non-core properties. We expect to use the net proceeds from
the 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, 2007, we had interests in
8,458 gross (3,565 net) productive wells across 934,723 gross (481,647
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. As a result of our acquisitions of the Postle and North
Ward Estes properties in 2005, we have enhanced the production stability and
reserve life of our developed reserves. Additionally, these
properties contain identified growth opportunities that we expect will
significantly increase 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 26 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
5,694 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 26 years of expertise in
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, 2007 are summarized in the table
below.
|
Oil
(MMbbl)
|
Natural
Gas
(Bcf)
|
Total
(MMBOE)
|
%
of Total
Proved
|
Future
Capital Expenditures
(In
millions)
|
||||||||||||||||
|
Permian
Basin:
|
||||||||||||||||||||
|
PDP
|
30.7 | 41.7 | 37.6 | 33 | % | |||||||||||||||
|
PDNP
|
21.2 | 8.5 | 22.6 | 20 | % | |||||||||||||||
|
PUD
|
48.8 | 25.8 | 53.2 | 47 | % | |||||||||||||||
|
Total
Proved
|
100.7 | 76.0 | 113.4 | 100 | % | $ | 704.0 | |||||||||||||
|
Rocky
Mountains:
|
||||||||||||||||||||
|
PDP
|
34.9 | 68.6 | 46.4 | 75 | % | |||||||||||||||
|
PDNP
|
1.3 | 15.5 | 3.9 | 6 | % | |||||||||||||||
|
PUD
|
6.0 | 32.8 | 11.4 | 19 | % | |||||||||||||||
|
Total
Proved
|
42.2 | 116.9 | 61.7 | 100 | % | $ | 160.6 | |||||||||||||
|
Mid-Continent:
|
||||||||||||||||||||
|
PDP
|
27.4 | 23.9 | 31.4 | 61 | % | |||||||||||||||
|
PDNP
|
6.6 | 2.8 | 7.1 | 14 | % | |||||||||||||||
|
PUD
|
12.0 | 3.9 | 12.6 | 25 | % | |||||||||||||||
|
Total
Proved
|
46.0 | 30.6 | 51.1 | 100 | % | $ | 264.7 | |||||||||||||
|
Gulf
Coast:
|
||||||||||||||||||||
|
PDP
|
2.1 | 29.7 | 7.1 | 58 | % | |||||||||||||||
|
PDNP
|
0.3 | 5.0 | 1.1 | 9 | % | |||||||||||||||
|
PUD
|
1.1 | 17.8 | 4.1 | 33 | % | |||||||||||||||
|
Total
Proved
|
3.5 | 52.5 | 12.3 | 100 | % | $ | 41.1 | |||||||||||||
|
Michigan:
|
||||||||||||||||||||
|
PDP
|
1.7 | 37.5 | 7.9 | 64 | % | |||||||||||||||
|
PDNP
|
1.1 | 3.8 | 1.7 | 14 | % | |||||||||||||||
|
PUD
|
1.1 | 9.4 | 2.7 | 22 | % | |||||||||||||||
|
Total
Proved
|
3.9 | 50.7 | 12.3 | 100 | % | $ | 16.4 | |||||||||||||
|
Total
Company:
|
||||||||||||||||||||
|
PDP
|
96.8 | 201.4 | 130.4 | 52 | % | |||||||||||||||
|
PDNP
|
30.5 | 35.6 | 36.4 | 15 | % | |||||||||||||||
|
PUD
|
69.0 | 89.7 | 84.0 | 33 | % | |||||||||||||||
|
Total
Proved
|
196.3 | 326.7 | 250.8 | 100 | % | $ | 1,186.8 | |||||||||||||
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. Our marketing of oil and gas can be affected by factors
beyond our control, the effects of which cannot be accurately
predicted. During 2007, sales to Plains Marketing LP and Valero
Energy Corporation accounted for 13% and 14%, 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. During 2005, sales to Teppco Crude Oil LLC
accounted for 10% 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 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
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 sales
of natural gas are affected by the availability, terms and cost of
transportation. The price and terms of access to pipeline
transportation 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. 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, 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 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.
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 are screening all of our pipeline systems to determine
if the new rules apply. In addition, many state agencies have adopted
these new federal regulations. As the agencies continue to work on
interpreting the definitions in the rule, we continue to evaluate which
pipelines may be subject to the new regulations. These new
regulations may put some of our gas gathering lines under the same level of
scrutiny that transmission lines have seen in the past. The new
regulations impose additional costly regulatory requirements on previously
unregulated pipelines.
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 sales
of crude oil 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. A review
of these regulations by the FERC in 2000 was successfully challenged on appeal
by an association of oil pipelines. As a result, the FERC in February
2003 increased the index slightly, effective July 2001. 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 and 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, 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 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 Clean Water Act 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. The due
date for having plans completed and control devices in place was extended on
December 12, 2005
with the new compliance date being October 31, 2007. 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 October 15, 2007 the EPA proposed amendments 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 expects to
finalize this proposed rule by the summer of 2008. We believe that
our operations comply in all material respects with the requirements of the
Clean Water Act 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” and
including carbon dioxide and methane, may be contributing to warming of the
Earth’s atmosphere. In response to such studies, the U.S. Congress is
actively considering legislation to reduce emissions of greenhouse
gases. In addition, at least 17 states have already taken legal
measures to reduce emissions of greenhouse 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. New legislation or regulatory programs that restrict
emissions of greenhouse gases in areas where we operate could adversely affect
demand for oil and gas products that, in turn, could have a significant impact
on our operations.
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, 2007, we had 412 full-time employees, including 29 senior level
geoscientists and 38 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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Item 1A.
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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.
A
substantial or extended decline in oil and gas prices may adversely affect our
business, financial condition, results of operations or cash flows.
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. These markets will likely continue to be volatile in the
future. 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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Lower oil and gas prices may not only
decrease our revenues on a per unit basis but also may reduce the amount of oil
and gas that we can produce economically. A substantial or extended
decline in oil or gas prices may materially and adversely affect our future
business, financial condition, results of operations, liquidity or ability to
finance planned capital expenditures. Lower oil and gas prices may
also reduce the amount of our borrowing base under our credit agreement, which
is determined at the discretion of the lenders based on the collateral value of
our proved reserves that have been mortgaged to the
lenders.
Drilling
for and producing oil and 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 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 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 equipment, including drilling rigs, CO2 and
qualified personnel;
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equipment
failures or accidents;
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adverse
weather conditions, such as hurricanes and storms;
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reductions
in oil and 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. The analogies we
draw from available data from other wells, more fully explored prospects or
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, 2007, we
had identified and scheduled over 1,900 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
natural 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 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.
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 CO 2 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 natural 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.
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 debt securities or equity related to future
acquisitions.
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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, 2007,
undeveloped reserves comprised 56% of the North Ward Estes field’s total
estimated proved reserves and 27% of Postle field’s estimated total proved
reserves. To fully develop these reserves, we expect to incur total
future development costs of $625.2 million at the North Ward Estes field
and $258.7 million at the Postle field. During 2007 and 2006,
the estimated future capital expenditures necessary to develop the proved
reserves at the North Ward Estes field and Postle field increased
substantially. The increases were due to several factors, including
equipment and service cost inflation, higher CO2 unit costs and volumes, higher costs
associated with the expanded scope of previously identified projects, as well as
new projects identified during 2006. Together, these fields encompass
75% of our estimated total future development costs related to proved
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.
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 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 to 2007, we completed 13
separate acquisitions of producing properties with a combined purchase price of
$1,474.8 million for estimated proved reserves as of the effective dates of
the acquisitions of 208.4 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 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.
If
oil and 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, 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.
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, 2007, we had
$250.0 million in outstanding indebtedness under Whiting Oil and Gas
Corporation’s (“Whiting Oil and Gas”) credit agreement with $650.0 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 potentially
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 also requires us to maintain a
certain working capital ratio and a certain debt to EBITDAX (as defined in the
credit agreement) ratio.
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 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 gas reserves. To date, we have
financed capital expenditures primarily with bank borrowings and cash generated
by operations. We intend to finance our future capital expenditures
with cash flow from operations and our existing financing
arrangements. Our cash flow from operations and access to capital are
subject to a number of variables, including:
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our
proved reserves;
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the
level of oil and gas we are able to produce from existing
wells;
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the
prices at which oil and 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 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 gas
reserves.
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 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 gas prices,
drilling and operating expenses, capital expenditures, taxes and availability of
funds. Therefore, estimates of oil and gas reserves are inherently
imprecise.
Actual future production, oil and gas
prices, revenues, taxes, exploration and development expenditures, operating
expenses and quantities of recoverable oil and 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 gas prices and other factors, many of which are beyond our
control.
It should not be assumed 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 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, 2007 would have decreased from
$4,011.7 million to $4,002.2 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, 2007 would have
decreased from $4,011.7 million to
$3,959.8 million.
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 sometimes trade at
a discount to the relevant benchmark prices, such as NYMEX, that are used for
calculating hedge positions. 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 gas exploration and production
activities are subject to all of the operating risks associated with drilling
for and producing oil and 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 gas production depends on a number of factors,
including the demand for and supply of oil and 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. Our failure to obtain such services on acceptable
terms could materially harm our business. We may be required to shut
in wells for a lack of a market or because access to natural 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 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, in response to studies suggesting
that emissions of certain gases, commonly referred to as greenhouse gases and
including carbon dioxide and methane, may be contributing to warming of the
Earth’s atmosphere, the U.S. Congress is actively considering legislation,
and more than a dozen states 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. Moreover, the U.S. Supreme Court only recently held in
a case, Massachusetts,
et al. v. EPA , that
greenhouse gases fall within the federal Clean Air Act’s definition of “air
pollutant,” which could result in the regulation of greenhouse gas emissions
from stationary sources under certain Clean Air Act programs. New
legislation or regulatory programs that restrict emissions of greenhouse gases
in areas in which we conduct business could have an adverse affect on our
operations and demand for our products.
Unless
we replace our oil and 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
gas reservoirs generally are characterized by declining production rates that
vary depending upon reservoir characteristics and other factors. Our
future oil and 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 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 gas production to reduce our
exposure to fluctuations in the price of oil and 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, 2007, we had contracts
maturing in 2008 covering the sale of 330,000 barrels of oil per
month. As of December 31, 2007, we had no outstanding gas hedges, and
all our oil hedges expire by December 2008. 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 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 gas. Furthermore, if
we do not engage in hedging transactions, then we may be more adversely affected
by declines in oil and gas prices than our competitors who engage in hedging
transactions. Additionally, hedging transactions may expose us to
cash margin requirements.
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Item 1B.
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Unresolved Staff
Comments
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None.
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Item 2.
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Properties
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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, 2007, the Permian Basin region contributed 113.4 MMBOE (89%
oil) of estimated proved reserves to our portfolio of operations, which
represents 45% of our total estimated proved reserves and contributed 10.7
MBOE/d of average daily production in December 2007. Approximately
96% of the proved reserves of our Permian Basin operations are related to
properties in Texas.
North Ward
Estes. The North Ward Estes field includes six base leases
with 100% working interest in 58,000 gross and net acres in Ward and Winkler
Counties, Texas. As of December 31, 2007, there were approximately
1,024 producing wells and 349 injection wells. 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. We also have the rights to
deeper horizons under 34,140 gross acres in the North Ward Estes
field. The North Ward Estes properties produced at an estimated
average net daily rate of 5.1 MBOE/d during the month of December
2007. In the North Ward Estes field, the estimated proved reserves as
of December 31, 2007 were 18% PDP, 26% PDNP and 56% PUD.
The North
Ward Estes field was initially developed in the 1930’s and full scale
waterflooding was initiated in 1955. A CO2 enhanced
recovery project was implemented in the core of the field in 1989, but was
terminated in 1996 after a successful top lease by a third party. We
reinitiated water injection in 2006 and successfully re-pressured the pilot
area. We initiated CO2 injection
into the pilot area on May 22, 2007. In January 2008, we began
expanding the CO2 flood from
the pilot area into additional sections in the Phase 1 area. By the
end of January 2008, we were injecting CO2 at 120
MMcf/d, above the target rate of 100 MMcf/d of CO2. In
the fourth quarter of 2006, we began construction of a gas plant to process and
separate the CO2 from the
produced gas. This plant is scheduled to start processing produced
gas during the second quarter of 2008.
We also
have interests in certain other fields within the Permian Basin of Texas and New
Mexico, including 2,753 producing oil and gas wells.
Keystone South, Martin and Flying W
Fields. We own a 100% working interest and operate these three
fields located on the Western edge of the Midland Basin. Production
comes from the Clearfork Formation, with additional production from the Wichita,
Wolfcamp, Devonian, Silurian, McKee and Ellenburger
Formations. During 2007, we drilled three wells in the Martin
field. In 2008, we have three additional wells planned at Martin and
a combination of seven additional new drills and recompletions planned in
Keystone South and Flying W.
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, 2007,
our estimated proved reserves in the Rocky Mountain region were 61.7 MMBOE (68%
oil), which represented 25% of our total estimated proved reserves, and our
December 2007 daily production averaged 14.8 MBOE/d. Approximately
53% and 27% of the proved reserves of our Rocky Mountain operations are related
to assets in North Dakota and Wyoming, respectively.
Robinson Lake Bakken
Play. The Bakken Formation is a low permeability,
unconventional reservoir consisting of highly oil saturated shale, dolomite and
fine grained sand. Horizontal drilling and advanced stimulation
techniques have been successfully employed in the drilling of hundreds of wells
in the Elm Coulee field in Montana and more recently in the North Dakota portion
of the Williston Basin. In early 2005, we embarked on an aggressive
leasing program and have acquired total acreage as of year-end 2007 of 118,348
gross (83,033 net) acres primarily in Mountrail County, North Dakota for the
purpose of developing a Bakken resource drilling program. As of year
end 2007, we had drilled five and completed four wells, and currently have four
rigs actively drilling. For 2008, we are planning to expand our
drilling program to as many as nine rigs. We are planning to drill 30
to 40 operated Bakken wells during 2008.
In
addition to the drilling program, we have begun construction of a gas plant to
process the associated gas. The first phase of this plant is
scheduled to begin receiving gas in the second quarter of 2008.
In March
2007, we purchased an interest in the Parshall field, also located in Montrail
County, North Dakota. As of December 31, 2007, we owned 66,957 gross
(13,470 net) acres in the Parshall area of mutual interest. This
field is operated by another operator and at the end of 2007, we had
participated in the drilling and completion of 24 horizontal middle Bakken
wells. We expect to participate in the drilling of approximately 50
to 60 additional wells in the Parshall field during 2008.
Red River Gas Drilling
Program. In 2004, we began acquiring 3-D seismic data over
several Red River Formation prospects in the deeper, gas bearing part of the
Williston Basin for the purpose of defining structure and reservoir
distribution. To date, we have acquired nine 3-D seismic surveys in
Billings, McKenzie and Williams Counties totaling 236 square miles, which we
have used to target 12 new wells. We are planning on drilling seven
new wells in 2008.
Billings Nose Drilling
Program. We have established a high concentration of producing
wells in the Billings Nose area of Billings County, North
Dakota. These assets include the Big Stick Madison Unit and North
Elkhorn Ranch Unit along with much of the acreage located between these two
fields. We have acquired 44 square miles of 3-D seismic data in this
area and have since identified multiple opportunities in a variety of reservoirs
including the Red River, Duperow, Bakken and Mission Canyon
Formations. Our efforts in 2007 focused on the North Elkhorn Ranch
Unit in Billings County, North Dakota. Four horizontal wellbores were
drilled into the Elkhorn Ranch member of the Mission Canyon.
Nisku A Drilling
Program. We made a significant exploration discovery in 2004
in western Billings County, North Dakota in the Nisku A zone and drilled ten
wells in 2004. Since the discovery, we have participated in eight
casing exit wells and 49 grass root wells (six drilled in 2007). We
are currently investigating waterflooding the reservoir. Modeling
efforts are complete and we are researching methods to install the waterflood
while minimizing the surface impact as much of this project is located in the
Theodore Roosevelt National Grassland, administered by the U.S. Forest
Service.
Green River Basin - Siberia
Ridge. Siberia Ridge is within the greater Wamsutter Arch area
of Sweetwater County, Wyoming and produces from a continuous-phase gas
accumulation in the Cretaceous Almond Formation at 10,500 feet. In
2004, the spacing rules governing the well density in the Siberia Ridge field
were adjusted to allow for up to two wells per 160 acres. This new
configuration resulted in a total of 44 additional potential locations on our
acreage. Because of lease stipulations on this Federal acreage,
drilling operations can begin on or after August 1st and must end by February
1st of the following year. We have been able to maintain a single
well drilling program by moving the rig between Anderson Canyon (described
below) and Siberia Ridge.
Our
development program commenced in mid-2005 and continued in 2006 with the
drilling of ten new wells. During 2007, an additional four wells were
drilled. Although not budgeted currently, there is potential for
additional drilling later in 2008 once the lease stipulations allow drilling
operations to resume.
Green River Basin - Anderson
Canyon. Anderson Canyon, North Anderson Canyon, Bird Canyon,
and McDonald Draw fields are all located on the LaBarge Platform in Southwest
Wyoming. We drilled six wells in 2006 and an additional 21 in
2007. We made improvements in the drilling operations, reducing the
drill time from 20 days in 2006 to around nine days in 2007. We are
continuing to work on refining the completion operations in an attempt to
optimize the resulting production and reserves.
Sulphur Creek - Boies Ranch Area,
Rio Blanco County, Colorado. The Sulphur Creek
Area in the North Central Piceance Basin has the potential to be a focal point
of our activity through 2009. We acquired mineral interests and
federal oil and gas leases in the 2004 Equity Oil Company
acquisition. As of year end 2007, we owned 16,893 gross (4,072 net)
acres in the Boies Ranch and Jimmy Gulch properties in Rio Blanco County,
Colorado. We are currently supplementing our leasehold in the
area. Drilling by third parties near our leasehold demonstrated the
presence of a continuous-phase gas resource in the Williams Fork Formation with
up-hole potential in the Wasatch Formation. We drilled and completed
three gas producing wells early in 2007, and during the third quarter of 2007,
we moved in two rigs and drilled an additional six wells that were awaiting
completion operations by year end. The rigs we moved in were
specifically designed to allow numerous wells to be drilled from a pad, to
reduce the footprint and surface impact. Our plans for 2008 are to
have a minimum of two drilling rigs running full time in the Piceance Basin and
to drill 24 twenty-acre locations on the Boies Ranch and Jimmy Gulch
acreage.
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 recent
Covenant field discovery in Sevier County, Utah. As part of our
acquisition of this property, the operator agreed to pay 100% our drilling and
completion costs for the first three wells in the project. The first
two wells have been drilled on the acreage. The first well, the
Joseph Prospect, was a dry hole. The second well, the Parowan
Prospect, has been drilled, cased and temporarily abandoned pending resumed
operations after lease stipulations allow operations to continue early in the
third quarter of 2008.
Mid-Continent
Region
Our
Mid-Continent operations include assets in Oklahoma, Arkansas and
Kansas. As of December 31, 2007, the Mid-Continent region
contributed 51.1 MMBOE (90% oil) of proved reserves to our portfolio of
operations, which represented 20% of our total estimated proved reserves and
contributed 7.2 MBOE/d of average daily production in December
2007. 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 six producing units
and one producing lease covering a total of approximately 25,600 gross (24,223
net) acres with working interests of 94% to 100%. Four of the units
are currently active CO2 enhanced
recovery projects. As of December 31, 2007, we were injecting
111 MMcf/d of CO2 and
surpassed 120 MMcf/d in January 2008. The Postle field is the largest
Morrow oil field in the U.S. The Postle properties produced at an
estimated average net daily rate of 5.8 MBOE/d during the month of December
2007. In the Postle field, the estimated proved reserves as of
December 31, 2007 were 58% PDP, 15% PDNP and 27% PUD.
The
Postle field was initially developed in the early 1960’s and unitized for
waterflood in 1967. Enhanced recovery projects in the three eastern
units using CO2 was
initiated in 1995. During 2007, we expanded CO2 injection
into the southern part of the fourth unit, HMU. Operations are
underway to expand CO2 injection
into the northern part of HMU and to optimize flood patterns in the existing
CO2
floods, with two drilling rigs and six workover rigs in the
field. These expansion projects include the restoration of shut-in
wells and the drilling of new producing and injection wells.
We are
the sole owner of the Dry Trails Gas Plant located in the Postle
field. This gas processing plant separates 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. Construction began in
mid-2006 to increase the plant capacity from its current capacity of 40.0 MMcf/d
to 80.0 MMcf/d. Construction is continuing and the plant expansion
will utilize a membrane technology to separate the CO2 from the hydrocarbon
gas. The expansion is scheduled to be on line during second quarter
2008.
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, 2007, the Gulf Coast region
contributed 12.3 MMBOE (29% oil) of proved reserves to our portfolio of
operations, which represented 5% of our total estimated proved reserves and
contributed 4.1 MBOE/d of average daily production in December
2007. Approximately 79% of the proved reserves of our Gulf Coast
operations are related to properties in Texas.
Edwards Trend. We
own 21,950 gross (21,870 net) acres in the Word North, Yoakum, Kawitt, Sweet
Home, and Three Rivers fields along the Edwards Trend in Karnes, Dewitt and
Lavaca Counties, Texas. Production in the Stuart City Reef Trend
comes primarily from the Edwards, Wilcox, and Sligo Formations at depths between
7,000 and 16,000 feet.
In 2007,
we farmed out interests in the Edwards to two different
operators. One of these operators utilized vertical wells to access
the Edwards reservoir at approximately 12,000 feet. The second
operator is utilizing horizontal wellbores with swell packers to provide zonal
isolation along the length of the wellbore. Results from the
horizontal wellbores look encouraging. The farmout agreement required
the drilling of four wells in the farmout acreage and the fourth well is just
being completed. Additional horizontal wells are being planned for
2008.
In 2008,
we shot a 34 square mile 3-D seismic survey along the trend in our South Runge
Prospect where we own 9,054 gross (7,643 net) acres, prospecting for expanded
Wilcox. We believe the results of the seismic shoot were promising,
and three wells targeting the Wilcox are planned during early 2008.
Vicksburg
Trend. Our non-operated holdings in the Vicksburg and Frio
Trends are concentrated primarily in the South Midway field in San Patricio
County, Texas and the Agua Dulce field. During 2005, we drilled or
participated in eleven new wells targeting multiple gas productive sands in the
Vicksburg and Frio Formations at depths between 10,000 and 14,500
feet. Results from this program encouraged us to drill seven wells in
South Midway and one well in Agua Dulce during 2006 and to participate in the
drilling of five additional wells in South Midway during 2007. In
2008, we plan to participate in three more wells in these fields.
Michigan
Region
As of
December 31, 2007, our estimated proved reserves in the Michigan region were
12.3 MMBOE (32% oil), and our December 2007 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. These plants
are in good mechanical condition and capable of handling additional
production. The West Branch Plant gathers production from the
Clayton, West Branch and other smaller fields.
Antrim
Production. In northern Michigan, we own an interest in over
50 multi-well Antrim Shale gas projects with proved producing reserves and
ongoing development drilling. During 2007, we participated in the
drilling and completion of 19 Antrim Shale wells. In 2008, we plan to
continue to pursue similar development drilling opportunities.
Clayton
Unit. Clayton Unit production is primarily from the Prairie du
Chien and Glenwood at a depth of around 11,000 feet. During late
2005, we drilled two Glenwood/Prairie du Chien (“PdC”) wells in the Clayton
Unit. The target reservoir was the upper PdC, which historically had
been the pay interval in the field. Both of these wells encountered
hydrocarbons in the Middle interval of the PdC, which had not previously
produced. The initial completion in both of these wells was in the
middle PdC and both wells still have the original target reservoir behind
pipe. We have been encouraged by the results. We have an
eight well commitment with the drilling contractor and we are just finishing up
well number six. In Missaukee, Oseceola and Clare Counties, Michigan,
we are in the process of permitting and shooting a 37 square mile 3-D seismic
shoot prospecting for additional PdC and Glenwood accumulations. This
data acquisition should be complete by second quarter 2008 and lead to
additional drilling later in the year.
Acreage
The
following table summarizes gross and net developed and undeveloped acreage at
December 31, 2007 by state. 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
|
35,698 | 10,707 | 2,333 | 50 | 38,031 | 10,757 | ||||||||||||||||||
|
Colorado
|
34,852 | 17,285 | 35,266 | 8,455 | 70,118 | 25,740 | ||||||||||||||||||
|
Louisiana
|
40,143 | 10,589 | 4,863 | 2,532 | 45,006 | 13,121 | ||||||||||||||||||
|
Michigan
|
140,331 | 61,462 | 32,524 | 25,869 | 172,855 | 87,331 | ||||||||||||||||||
|
Montana
|
40,161 | 13,183 | 41,814 | 19,622 | 81,975 | 32,805 | ||||||||||||||||||
|
North
Dakota
|
188,550 | 99,777 | 327,868 | 188,377 | 516,418 | 288,154 | ||||||||||||||||||
|
Oklahoma
|
79,569 | 51,400 | 2,692 | 2,317 | 82,261 | 53,717 | ||||||||||||||||||
|
Texas
|
234,079 | 141,490 | 76,110 | 61,118 | 310,189 | 202,608 | ||||||||||||||||||
|
Utah
|
20,237 | 11,497 | 221,117 | 48,067 | 241,354 | 59,564 | ||||||||||||||||||
|
Wyoming
|
105,205 | 55,961 | 70,045 | 44,378 | 175,250 | 100,339 | ||||||||||||||||||
|
Other*
|
15,898 | 8,296 | 1,070 | 786 | 16,968 | 9,082 | ||||||||||||||||||
|
Total
|
934,723 | 481,647 | 815,702 | 401,571 | 1,750,425 | 883,218 | ||||||||||||||||||
* Other
includes Alabama, Arkansas, Mississippi, Nebraska and New Mexico.
Production
History
The
following table presents historical information about our produced oil and gas
volumes:
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
Oil
production (MMbbls)
|
9.6 | 9.8 | 7.0 | |||||||||
|
Natural
gas production (Bcf)
|
30.8 | 32.1 | 30.3 | |||||||||
|
Total
production (MMBOE)
|
14.7 | 15.2 | 12.1 | |||||||||
|
Daily
production (MBOE/d)
|
40.3 | 41.5 | 33.1 | |||||||||
|
Average
sales prices:
|
||||||||||||
|
Oil
(per Bbl)
|
$ | 64.57 | $ | 57.27 | $ | 51.26 | ||||||
|
Effect
of oil hedges on average price (per Bbl)
|
(2.21 | ) | (0.95 | ) | (2.72 | ) | ||||||
|
Oil
net of hedging (per Bbl)
|
$ | 62.36 | $ | 56.32 | $ | 48.54 | ||||||
|
Natural
gas (per Mcf)
|
$ | 6.19 | $ | 6.59 | $ | 7.03 | ||||||
|
Effect
of natural gas hedges on average price (per Mcf)
|
- | 0.06 | (0.47 | ) | ||||||||
|
Natural
gas net of hedging (per Mcf)
|
$ | 6.19 | $ | 6.65 | $ | 6.56 | ||||||
|
Per
BOE data:
|
||||||||||||
|
Sales
price (net of hedging)
|
$ | 53.57 | $ | 50.52 | $ | 44.70 | ||||||
|
Lease
operating expenses
|
$ | 14.20 | $ | 12.12 | $ | 9.24 | ||||||
|
Production
taxes
|
$ | 3.56 | $ | 3.11 | $ | 2.99 | ||||||
|
Depreciation,
depletion and amortization expenses
|
$ | 13.11 | $ | 10.74 | $ | 8.08 | ||||||
|
General
and administrative expenses
|
$ | 2.66 | $ | 2.49 | $ | 2.53 | ||||||
Productive
Wells
The
following table presents our ownership at December 31, 2007 in productive oil
and gas wells by region (a net well is our percentage ownership of a gross
well).
|
Oil
Wells
|
Natural
Gas Wells
|
Total
Wells(1)
|
||||||||||||||||||||||
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||||||||||||||
|
Permian
Basin
|
3,646 | 1,778 | 374 | 131 | 4,020 | 1,909 | ||||||||||||||||||
|
Rocky
Mountains
|
1,711 | 406 | 405 | 199 | 2,116 | 605 | ||||||||||||||||||
|
Mid-Continent
|
470 | 312 | 211 | 93 | 681 | 405 | ||||||||||||||||||
|
Gulf
Coast
|
93 | 56 | 436 | 129 | 529 | 185 | ||||||||||||||||||
|
Michigan
|
81 | 57 | 1,031 | 404 | 1,112 | 461 | ||||||||||||||||||
|
Total
|
6,001 | 2,609 | 2,457 | 956 | 8,458 | 3,565 | ||||||||||||||||||
|
|
(1)
|
168
wells are multiple completions. These 168 wells contain a total
of 365 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
|
|||||||||||||||||||
|
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 | ||||||||||||||||||
|
2005:
|
||||||||||||||||||||||||
|
Development
|
276 | 18 | 294 | 164.7 | 10.6 | 175.3 | ||||||||||||||||||
|
Exploratory
|
7 | 7 | 14 | 1.3 | 3.9 | 5.2 | ||||||||||||||||||
|
Total
|
283 | 25 | 308 | 166.0 | 14.5 | 180.5 | ||||||||||||||||||
|
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 2007.
EXECUTIVE OFFICERS OF THE
REGISTRANT
The
following table sets forth certain information, as of February 15, 2008,
regarding the executive officers of Whiting Petroleum Corporation:
|
Name
|
Age
|
Position
|
|
James
J. Volker
|
61
|
Chairman,
President and Chief Executive Officer
|
|
James
T. Brown
|
55
|
Senior
Vice President, Operations
|
|
Bruce
R. DeBoer
|
55
|
Vice
President, General Counsel and Corporate Secretary
|
|
Heather
M. Duncan
|
37
|
Vice
President, Human Resources
|
|
J.
Douglas Lang
|
58
|
Vice
President, Reservoir Engineering/Acquisitions
|
|
Rick
A. Ross
|
49
|
Vice
President, Operations
|
|
David
M. Seery
|
53
|
Vice
President, Land
|
|
Michael
J. Stevens
|
42
|
Vice
President and Chief Financial Officer
|
|
Mark
R. Williams
|
51
|
Vice
President, Exploration and Development
|
|
Brent
P. Jensen
|
38
|
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 thirty 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 thirty 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 over
eleven 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 thirty 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 twenty-five
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 twenty-four 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 fourteen years of oil and gas
accounting experience and is a Certified Public Accountant. Mr.
Jensen holds a Bachelor of Arts degree with an emphasis in accounting and
business 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, 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 | ||||
|
Fiscal
Year Ended December 31, 2006
|
||||||||
|
Fourth
Quarter (Ended December 31, 2006)
|
$ | 50.30 | $ | 35.81 | ||||
|
Third
Quarter (Ended September 30, 2006)
|
$ | 48.10 | $ | 37.30 | ||||
|
Second
Quarter (Ended June 30, 2006)
|
$ | 46.95 | $ | 33.70 | ||||
|
First
Quarter (Ended March 31, 2006)
|
$ | 47.25 | $ | 37.41 | ||||
On
February 15, 2008, there were 869 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.
We
completed our initial public offering in November 2003. Our common
stock began trading on the New York Stock Exchange on November 20,
2003. The following graph compares on a cumulative basis changes
since November 20, 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 November 20, 2003
in our common stock, the Standard & Poor’s Composite 500 Index and the
Dow Jones US Oil Companies, Secondary Index.
|
11/20/03
|
12/31/03
|
12/31/04
|
12/31/05
|
12/31/06
|
12/31/07
|
|||||||||||||||||||
|
Whiting
Petroleum Corporation
|
$ | 100 | $ | 113 | $ | 186 | $ | 246 | $ | 286 | $ | 354 | ||||||||||||
|
Standard &
Poor’s Composite 500 Index
|
100 | 108 | 117 | 121 | 137 | 142 | ||||||||||||||||||
|
Dow
Jones US Oil Companies, Secondary Index
|
100 | 114 | 160 | 263 | 275 | 392 | ||||||||||||||||||
|
Item 6.
|
Selected Financial
Data
|
The
consolidated income statement information for the years ended December 31,
2007, 2006 and 2005 and the consolidated balance sheet information at December
31, 2007 and 2006 are derived from our audited financial statements included
elsewhere in this report. The consolidated income statement
information for the years ended December 31, 2004 and 2003 and the consolidated
balance sheet information at December 31, 2005, 2004 and 2003 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: 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,
|
||||||||||||||||||||
|
2007
|
2006
|
2005
|
2004
|
2003
|
||||||||||||||||
|
(dollars
in millions, except per share data)
|
||||||||||||||||||||
|
Consolidated
Income Statement Information:
|
||||||||||||||||||||
|
Revenues
and other income:
|
||||||||||||||||||||
|
Oil
and natural gas sales
|
$ | 809.0 | $ | 773.1 | $ | 573.2 | $ | 281.1 | $ | 175.7 | ||||||||||
|
Loss
on oil and natural gas hedging activities
|
(21.2 | ) | (7.5 | ) | (33.4 | ) | (4.9 | ) | (8.7 | ) | ||||||||||
|
Gain
on sale of oil and gas properties
|
29.7 | 12.1 | — | 1.0 | — | |||||||||||||||
|
Gain
on sale of marketable securities
|
— | — | — | 4.8 | — | |||||||||||||||
|
Interest
income and other
|
1.2 | 1.1 | 0.6 | 0.1 | 0.3 | |||||||||||||||
|
Total
revenues and other income
|
818.7 | 778.8 | 540.4 | 282.1 | 167.3 | |||||||||||||||
|
Costs
and expenses:
|
||||||||||||||||||||
|
Lease
operating
|
208.9 | 183.6 | 111.6 | 54.2 | 43.2 | |||||||||||||||
|
Production
taxes
|
52.4 | 47.1 | 36.1 | 16.8 | 10.7 | |||||||||||||||
|
Depreciation,
depletion and amortization
|
192.8 | 162.8 | 97.6 | 54.0 | 41.2 | |||||||||||||||
|
Exploration
and impairment
|
37.3 | 34.5 | 16.7 | 6.3 | 3.2 | |||||||||||||||
|
General
and administrative
|
39.0 | 37.8 | 30.6 | 19.2 | 13.0 | |||||||||||||||
|
Change
in Production Participation Plan liability
|
8.6 | 6.2 | 9.7 | 1.7 | (0.2 | ) | ||||||||||||||
|
Phantom
equity plan (1)
|
— | — | — | — | 10.9 | |||||||||||||||
|
Interest
expense
|
72.5 | 73.5 | 42.0 | 15.9 | 9.2 | |||||||||||||||
|
Total
costs and expenses
|
611.5 | 545.5 | 344.3 | 168.1 | 131.2 | |||||||||||||||
|
Income
before income taxes and cumulative change in accounting
principle
|
207.2 | 233.3 | 196.1 | 114.0 | 36.1 | |||||||||||||||
|
Income
tax expense
|
76.6 | 76.9 | 74.2 | 44.0 | 13.9 | |||||||||||||||
|
Income
before cumulative change in accounting principle
|
130.6 | 156.4 | 121.9 | 70.0 | 22.2 | |||||||||||||||
|
Cumulative
change in accounting principle (2)
|
— | — | — | — | (3.9 | ) | ||||||||||||||
|
Net
income
|
$ | 130.6 | $ | 156.4 | $ | 121.9 | $ | 70.0 | $ | 18.3 | ||||||||||
|
Income
per common share before cumulative change in accounting principle,
basic
|
$ | - | $ | - | $ | - | $ | - | $ | 1.18 | ||||||||||
|
Income
per common share before cumulative change in accounting principle,
diluted
|
$ | - | $ | - | $ | - | $ | - | $ | 1.18 | ||||||||||
|
Net
income per common share, basic
|
$ | 3.31 | $ | 4.26 | $ | 3.89 | $ | 3.38 | $ | 0.98 | ||||||||||
|
Net
income per common share, diluted
|
$ | 3.29 | $ | 4.25 | $ | 3.88 | $ | 3.38 | $ | 0.98 | ||||||||||
|
Other
Financial Information:
|
||||||||||||||||||||
|
Net
cash provided by operating activities
|
$ | 394.0 | $ | 411.2 | $ | 330.2 | $ | 134.1 | $ | 91.9 | ||||||||||
|
Net
cash used in investing activities
|
$ | 467.0 | $ | 527.6 | $ | 1,126.9 | $ | 524.4 | $ | 47.6 | ||||||||||
|
Net
cash provided by financing activities
|
$ | 77.3 | $ | 116.4 | $ | 805.5 | $ | 338.4 | $ | 4.4 | ||||||||||
|
Ratio
of earnings to fixed charges (3)
|
3.65 | x | 4.14 | x | 5.64 | x | 8.01 | x | 4.85 | x | ||||||||||
|
Capital
expenditures
|
$ | 519.6 | $ | 552.0 | $ | 1,126.9 | $ | 530.6 | $ | 47.6 | ||||||||||
|
As
of December 31,
|
||||||||||||||||||||
|
2007
|
2006
|
2005
|
2004
|
2003
|
||||||||||||||||
|
(dollars
in millions)
|
||||||||||||||||||||
|
Consolidated
Balance Sheet Information:
|
||||||||||||||||||||
|
Total
assets
|
$ | 2,952.0 | $ | 2,585.4 | $ | 2,235.2 | $ | 1,092.2 | $ | 536.3 | ||||||||||
|
Total
debt
|
$ | 868.2 | $ | 995.4 | $ | 875.1 | $ | 328.4 | $ | 188.0 | ||||||||||
|
Stockholders’
equity
|
$ | 1,490.8 | $ | 1,186.7 | $ | 997.9 | $ | 612.4 | $ | 259.6 | ||||||||||
|
(1)
|
The
completion of our initial public offering in November 2003 constituted a
triggering event under our phantom equity plan, pursuant to which our
employees received payments valued at $10.9 million in the form of shares
of our common stock. The phantom equity plan is now
terminated.
|
|
(2)
|
In
2003, we adopted Statement of Financial Accounting Standards No. 143,
Accounting for Asset
Retirement Obligations. This was a one-time charge to net
income.
|
|
(3)
|
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
operating 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. During 2004 and 2005, we emphasized the acquisition of
properties that provided additional volumes to our current production levels as
well as upside potential through further development. During 2006 and
2007, we have focused our drilling activity on the development of these acquired
properties, specifically on projects that we believe provide repeatable
successes in particular fields. Our combination of acquisitions and
subsequent development allows us to direct our capital resources to what we
believe to be the most advantageous investments.
While
historically we have grown through acquisitions, we are increasingly focused on
a balanced exploration and development program while continuing to selectively
pursue acquisitions that complement our existing core properties. We
believe that our significant drilling inventory, combined with our operating
experience and cost structure, provides us with meaningful organic growth
opportunities. Our growth plan is centered on the following
activities:
|
•
|
pursuing
the development of projects that we believe will generate attractive rates
of return;
|
|
|
•
|
maintaining
a balanced portfolio of lower risk, long-lived oil and gas properties that
provide stable cash flows;
|
|
|
•
|
seeking
property acquisitions that complement our core
areas; and
|
|
|
•
|
allocating
an increasing percentage of our capital budget to leasing and testing new
areas.
|
We have
historically acquired operated and non-operated properties that meet or 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 sale price realized will provide an above
average rate of return for the property or when the property no longer matches
the profile of properties we desire to own.
Our
revenue, profitability and future growth rate depend on factors beyond our
control, such as economic, political and regulatory developments and competition
from other sources of energy. Oil and gas prices historically have
been volatile and may fluctuate widely in the future. Sustained
periods of low prices for oil or gas could materially and adversely affect our
financial position, cash flows, results of operations, access to capital, and
the quantities of oil and gas reserves that we can economically
produce.
2007
Highlights and Future Considerations
On
July 3, 2007, we completed a public offering of our common stock under our
existing shelf registration statement, selling 5,425,000 shares of common stock
at a price of $40.50 per share, providing net proceeds of $210.4 million, which
we used to repay a portion of the debt outstanding under our credit
agreement. The number of shares includes the sale of 425,000 shares
pursuant to the exercise of the underwriters’ overallotment option.
We
continue to have significant development and related infrastructure activity on
the Postle and North Ward Estes fields acquired in 2005, which has resulted in
reserve and production increases. During 2007, we incurred $284.9
million of exploration and development expenditures on these two
projects. We expect to incur total future development costs of $625.2
million in the North Ward Estes field and $258.7 million in the Postle
field.
Our
expansion of the CO2 flood at
the Postle field, located in Texas County, Oklahoma, is generating positive
results. In December 2007, net production from the field averaged 5.8
MBOE/d. By the end of January 2008, we were injecting over 120 MMcf/d
of CO2
into the Morrow formation, the field’s producing reservoir.
In 2007,
we initiated our CO2 flood in
the North Ward Estes field, located in Ward and Winkler Counties,
Texas. By the end of January 2008, we were injecting approximately
120 MMcf/d of CO2 into the
Yates formation, the field’s primary producing reservoir. We expect
an initial response from this CO2 flood
during the fourth quarter of 2008. Net production from North Ward
Estes in December 2007 averaged 5.1 MBOE/d.
Our
Robinson Lake prospect in Mountrail County, North Dakota encompasses 118,348
gross acres (83,033 net acres), on which we plan to drill 30 to 40 operated
Middle Bakken wells during 2008. The Peery State 11-25H, our
discovery well on the Robinson Lake prospect, was completed in May 2007 in the
Middle Bakken formation, and was producing 0.3 MBOE/d at the end of January
2008. We completed the Locken 11-22H well in December 2007, which
averaged 0.9 MBOE/d during the first 30 days of production. In
January 2008, we completed the Liffrig 11-27H well, which averaged 1.1 MBOE/d
during the first 30 days of production. We are the operators on these
three wells and have three drilling rigs and one workover rig working full time
at Robinson Lake, with plans to add a fifth rig in March 2008. By
year end 2008, we could have as many as nine drillings rigs working in this
prospect.
In
December 2007, we began construction of a natural gas processing plant that will
separate the natural gas liquids from the natural gas produced from Robinson
Lake and allow the natural gas to be transported by pipeline to
market. The plant is expected to be operational in the second quarter
of 2008. The initial capacity of the plant will be 3.0 MMcf/d, and is
expected to increase to approximately 33 MMcf/d by the end of 2008.
Immediately
east of the Robinson Lake prospect is the Parshall field, where we have
participated in the drilling and completion of 24 wells, 19 of which were
drilled in 2007. The initial 15 wells that produced for 120 days had
average flow rates of 0.6 MBOE/d per well. We expect to participate
in the drilling of approximately 50 to 60 wells in the Parshall field during
2008.
Another
developmental area for us is in the Piceance Basin at the Boies Ranch and Jimmy
Gulch properties in Rio Blanco County, Colorado. In the first half of
2007, we drilled and completed three gas producers at Boies Ranch, with each
well flowing at an initial rate of 2.3 MMcf/d of gas from the Williams Fork and
Iles formations. At year end 2007, there were six wells awaiting
completion operations at Boies Ranch and two being drilled, with drilling
operations expected to commence at Jimmy Gulch in the third quarter of
2008. We plan to have a minimum of two drilling rigs running full
time in the Piceance Basin, drilling approximately 24 wells by the end of
2008.
We are
evaluating and engaged in discussions with respect to the potential sale of
economic interests in other non-core properties, although we have not made a
decision on whether to do so or the form that any such transaction would
take. Our intention is to monetize the value of some of our
predominantly proved developed producing properties with this potential
sale. In November 2007, we filed a registration statement relating to
a proposed initial public offering of units of beneficial interest in Whiting
USA Trust I. We plan to contribute a term net profits interest in
certain of our oil and natural gas properties in exchange for trust
units. These property interests had estimated reserves of up to
8.2 MMBOE, as of a January 1, 2008 effective date, representing up to 3.3%
of our proved reserves as of December 31, 2007, and 11.5%, or 4.6 MBOE/d,
of our December 2007 average daily net production. We intend to use
the net proceeds from this offering to repay a portion of the debt outstanding
under our credit agreement. The amount of proceeds ultimately received
from this offering, and the timing of the completion of this offering, is
subject to a variety of factors, including favorable market
conditions. We cannot provide any assurance, however, that we will be
able to complete this offering or any other form of asset sales.
Although
independent engineers estimated probable and possible reserves relating to
certain 2006 and prior year producing property acquisitions, we, consistent with
our present acquisition practices, have associated substantially all producing
property acquisition costs with proved reserves. Because of our
substantial acquisition activity, our discussion and analysis of our historical
financial condition and results of operations for the periods discussed below
may not necessarily be comparable with or applicable to our future results of
operations. Our historical results include the results from our
recent acquisitions beginning on the following dates: 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; and
Green River Basin, March 31, 2005.
Acquisitions
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 this transaction, the
operator agreed to pay 100% of our drilling and completion costs for the first
three wells in the project.
Michigan
Properties. On August 15, 2006, we acquired 65 producing
properties, a gathering line, gas processing plant and 30,437 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. We operate 85% of the acquired
properties.
North Ward Estes and Ancillary
Properties. On October 4, 2005, we acquired the operated
interest in the North Ward Estes field in Ward and Winkler counties, Texas, and
certain smaller fields located in the Permian Basin. The purchase
price was $459.2 million, consisting of $442.0 million in cash and 441,500
shares of our common stock, for estimated proved reserves of 82.1 MMBOE as of
the acquisition effective date of July 1, 2005, resulting in a cost of
$5.58 per BOE of estimated proved reserves. Proved developed reserve
quantities represented 36% of the total proved reserves acquired. The
average daily production from the properties was 4.6 MBOE/d as of the
acquisition effective date. We funded the cash portion of the
purchase price with the net proceeds from a public offering of common stock and
a private placement of 7% Senior Subordinated Notes due 2014.
Postle
Properties. On August 4, 2005, we acquired the operated
interest in producing oil and gas fields located in the Oklahoma
Panhandle. The purchase price was $343.0 million for estimated
proved reserves of 40.3 MMBOE as of the acquisition effective date of
July 1, 2005, resulting in a cost of $8.52 per BOE of estimated proved
reserves. The average daily production from the properties was 4.2
MBOE/d as of the acquisition effective date. Proved developed reserve
quantities represented 57% of the total proved reserves acquired. We
funded the acquisition through borrowings under our credit
agreement.
Limited Partnership
Interests. On June 23, 2005, we acquired all of the
limited partnership interests in three institutional partnerships managed by our
wholly-owned subsidiary Whiting Programs, Inc. The partnership
properties were located in Louisiana, Texas, Arkansas, Oklahoma and
Wyoming. The purchase price was $30.5 million for estimated
proved reserves of 2.9 MMBOE as of the acquisition effective date of January 1,
2005, resulting in a cost of $10.52 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 0.7 MBOE/d as of the acquisition effective date. We
funded the acquisition with cash on hand.
Green River
Basin. On March 31, 2005, we acquired operated interests
in five producing gas fields in the Green River Basin of Wyoming. The
purchase price was $65.0 million for estimated proved reserves of 8.4 MMBOE as
of the acquisition effective date of March 1, 2005, resulting in a cost of $7.74
per BOE of estimated proved reserves. Proved developed reserve
quantities represented 68% of the total proved reserves acquired. The
average daily production from the properties was 1.1 MBOE/d as of the
acquisition effective date. We funded the acquisition though
borrowings under our credit agreement and with cash on hand.
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, adjusted to the July 1, 2007
divestiture effective date, thereby yielding 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 non-core 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, or $18.82 per BOE. No
gain or loss was recognized on the sales. These 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 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 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,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
Net
production:
|
||||||||||||
|
Oil
(MMbbls)
|
9.6 | 9.8 | 7.0 | |||||||||
|
Natural
gas (Bcf)
|
30.8 | 32.1 | 30.3 | |||||||||
|
Total
production (MMBOE)
|
14.7 | 15.2 | 12.1 | |||||||||
|
Net
sales (in millions):
|
||||||||||||
|
Oil
(1)
|
$ | 618.5 | $ | 561.2 | $ | 360.4 | ||||||
|
Natural
gas (1)
|
190.5 | 211.9 | 212.8 | |||||||||
|
Total
oil and natural gas sales
|
$ | 809.0 | $ | 773.1 | $ | 573.2 | ||||||
|
Average
sales prices:
|
||||||||||||
|
Oil
(per Bbl)
|
$ | 64.57 | $ | 57.27 | $ | 51.26 | ||||||
|
Effect
of oil hedges on average price (per Bbl)
|
(2.21 | ) | (0.95 | ) | (2.72 | ) | ||||||
|
Oil
net of hedging (per Bbl)
|
$ | 62.36 | $ | 56.32 | $ | 48.54 | ||||||
|
Average
NYMEX price
|
$ | 72.30 | $ | 66.25 | $ | 56.61 | ||||||
|
Natural
gas (per Mcf)
|
$ | 6.19 | $ | 6.59 | $ | 7.03 | ||||||
|
Effect
of natural gas hedges on average price (per Mcf)
|
- | 0.06 | (0.47 | ) | ||||||||
|
Natural
gas net of hedging (per Mcf)
|
$ | 6.19 | $ | 6.65 | $ | 6.56 | ||||||
|
Average
NYMEX price
|
$ | 6.86 | $ | 7.23 | $ | 8.64 | ||||||
|
Cost
and expense (per BOE):
|
||||||||||||
|
Lease
operating expenses
|
$ | 14.20 | $ | 12.12 | $ | 9.24 | ||||||
|
Production
taxes
|
$ | 3.56 | $ | 3.11 | $ | 2.99 | ||||||
|
Depreciation,
depletion and amortization expense
|
$ | 13.11 | $ | 10.74 | $ | 8.08 | ||||||
|
General
and administrative expenses
|
$ | 2.66 | $ | 2.49 | $ | 2.53 | ||||||
________________
|
(1)
|
Before
consideration of hedging
transactions.
|
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% and our gas sales volumes decreased 4% between
periods. 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% and our average price for natural gas before effects of hedging
decreased 6% between periods.
Loss on Oil and Natural Gas Hedging
Activities. We hedged 53% of our oil volumes during 2007,
incurring derivative settlement losses of $21.2 million, and 54% of our oil
volumes during 2006, incurring derivative settlement losses of $9.4
million. We hedged 16% of our gas volumes during 2007, incurring no
realized hedging gains or losses, and 59% of our gas volumes during 2006,
resulting in derivative settlement gains of $1.9 million. See Item
7A, “Qualitative and Quantitative Disclosures About Market Risk” for a list of
our outstanding oil hedges as of January 1, 2008.
Gain on Sale of
Properties. During 2007, we sold our interests in several
non-core properties for an aggregate amount of $52.6 million in cash, 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 2007 lease operating expenses were $208.9
million, a $25.2 million increase over 2006. Our lease operating
expense as a percentage of oil and gas sales increased from 24% during 2006 to
26% during 2007, and 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 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 gas sales. The
2007 rate was greater than the 2006 rate due to the change in property mix
associated with recent divestitures in low tax jurisdictions and drilling
successes in higher tax jurisdictions.
Depreciation, Depletion and
Amortization. Depreciation, depletion and amortization expense
(“DD&A”) increased $30.0 million to $192.8 million during 2007, as compared
to $162.8 million for the same period in 2006. On a BOE basis, our
DD&A rate increased from $10.74 during 2006 to $13.11 in
2007. The primary factors causing this rate increase were (1) $529.3
million in drilling expenditures incurred during the past 12 months in relation
to net oil and gas reserve additions over the same time period, and (2) 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. The
components of our 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 | ||||
Exploration and Impairment
Costs. Our exploration and impairment costs increased $2.8
million in 2007 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. The increase in impairment of $5.5
million is due to an additional $35.1 million of unproved property costs being
amortized during the year ended December 31, 2007, as compared to the same
period in 2006.
General and Administrative
Expenses. We report general and administrative expenses net of
third party reimbursements and internal allocations. The components
of our general and administrative expenses were as follows (in
thousands):
|
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 $7.5 million of additional salaries and wages for
personnel hired during the past twelve months and $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 gas sales
remained consistent at 5% for both 2007 and 2006.
Change in Production Participation
Plan Liability. For the year ended December 31, 2007, this
non-cash expense increased $2.4 million to $8.6 million. 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 must
expense the present value of estimated future payments over the Plan’s five year
vesting period. This expense in 2007 and 2006 primarily reflects
changes to future cash flow estimates and related Plan liability due to the
effect of a sustained higher price environment, recent drilling activity and
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.
Interest
Expense. The components of our interest expense were as
follows (in thousands):
|
Year
Ended December 31,
|
||||||||
|
2007
|
2006
|
|||||||
|
Credit
Agreement
|
$ | 24,428 | $ | 21,478 | ||||
|
Senior
Subordinated Notes
|
44,691 | 44,530 | ||||||
|
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 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 versus $945.3
million during 2006. Our weighted average effective cash interest
rate was 7.2% during 2007 versus 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 versus 7.5% during
2006.
Income Tax
Expense. Income tax expense totaled $76.6 million for 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
recent high oil prices, the EOR credit was phased-out for 2007 and
2006.
The
current portion of income tax expense was $0.6 million for 2007 compared to
$12.3 million in 2006. We expect to report 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 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
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.
Year
Ended December 31, 2006 Compared to Year Ended December 31, 2005
Oil and Natural Gas
Sales. Our oil and natural gas sales revenue increased $199.9
million to $773.1 million in 2006 as compared to 2005. Sales are a
function of volumes sold and average sales prices. Our oil sales
volumes increased 39% and our gas sales volumes increased 6% between
periods. The volume increases resulted from acquisitions completed in
2005 and 2006 and successful drilling activities during 2006, which produced new
sales volumes that more than offset normal field production
decline. Our average price for oil before effects of hedging
increased 12% and our average price for natural gas before effects of hedging
decreased 6% between periods.
Loss on Oil and Natural Gas Hedging
Activities. We hedged 54% of our oil volumes during 2006,
incurring derivative settlement losses of $9.4 million, and 58% of our oil
volumes during 2005, incurring derivative settlement losses of $19.1
million. We hedged 59% of our gas volumes during 2006 incurring
derivative settlement gains of $1.9 million, and 60% of our gas volumes during
2005, incurring derivative settlement losses of $14.3 million.
Gain on Sale of
Properties. 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. 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. There was no gain or loss on sale of properties during
2005.
Lease Operating
Expenses. Our lease operating expenses increased $72.1 million
to $183.6 million in 2006 as compared to 2005. The increase resulted
primarily from costs associated with new property acquisitions during 2005 and
2006 and successful drilling activities during 2006. Our lease
operating expense as a percentage of oil and gas sales increased from 19% during
2005 to 24% during 2006. Our lease operating expenses per BOE
increased from $9.24 during 2005 to $12.12 during 2006. The increase
of 31% on a BOE basis was primarily caused by inflation in the cost of oil field
goods and services, a high level of workover activity on recently acquired
properties, increased costs related to tertiary recovery projects, a change in
labor billing practices and higher energy costs. Oil field goods and
services increased due to a higher demand in the industry. Workovers
amounted to $8.9 million in 2006, as compared to $3.9 million of workover
activity during 2005. In addition, during the fourth quarter of 2006,
we revised our labor billing practices to better conform to 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 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 2006
and 2005 were 6.1% and 6.3%, respectively, of oil and gas sales. The
2006 rate was lower than the 2005 rate due to the change in property mix
associated with recent acquisitions.
Depreciation, Depletion and
Amortization. Depreciation, depletion and amortization expense
(“DD&A”) increased $65.2 million to $162.8 million during 2006, as compared
to $97.6 million for 2005. The increase resulted from higher
production volumes in 2006 and an increase in our DD&A rate. On a
BOE basis, our DD&A rate increased from $8.08 during 2005 to $10.74 in
2006. The primary factors causing this rate increase were higher
drilling expenditures, downward oil and gas reserve revisions, and an increased
level of expenditures to develop proved undeveloped reserves, particularly
related to the enhanced oil recovery projects in the Postle and North Ward Estes
fields where the development of undeveloped reserves does not increase existing
proved reserves. Under the successful efforts method of accounting,
costs to develop proved undeveloped reserves are added into the DD&A rate
when incurred. Also contributing to our higher DD&A rate was the
association of all 2005 property acquisition costs with proved reserves and none
with unproved reserves, thereby including all such costs in our DD&A rate
immediately when incurred. The components of our DD&A expense
were as follows (in thousands):
|
Year
Ended December 31,
|
||||||||
|
2006
|
2005
|
|||||||
|
Depletion
|
$ | 157,868 | $ | 93,818 | ||||
|
Depreciation
|
2,675 | 1,457 | ||||||
|
Accretion
of asset retirement obligations
|
2,288 | 2,364 | ||||||
|
Total
|
$ | 162,831 | $ | 97,639 | ||||
Exploration and Impairment
Costs. Our exploration and impairment costs increased $17.8
million to $34.5 million in 2006 compared to 2005. The components of
our exploration and impairment costs were as follows (in
thousands):
|
Year
Ended December 31,
|
||||||||
|
2006
|
2005
|
|||||||
|
Exploration
|
$ | 30,079 | $ | 14,665 | ||||
|
Impairment
|
4,455 | 2,034 | ||||||
|
Total
|
$ | 34,534 | $ | 16,699 | ||||
Higher
exploration costs resulted from three exploratory dry holes drilled in the Rocky
Mountains region, one exploratory dry hole drilled in the Gulf Coast region and
one exploratory dry hole drilled in the Mid-Continent region in 2006, totaling
$7.2 million. In 2005, we drilled a total of seven exploratory dry
holes, totaling $4.0 million. We incurred $12.2 million in geological
and geophysical expenses during 2006, up $7.4 million from 2005. We
also hired additional exploration personnel to support the increased drilling
budget from $223.6 million in 2005 to $455.0 million in 2006, resulting in an
additional $4.0 million of exploration expense. The impairment charge
in 2006 consisted of $3.7 million in amortized leasehold costs associated with
individually insignificant unproved properties and $0.8 million in proved
property impairments. The impairment charge in 2005 related to
unrecoverable costs associated with our investment in the Cherokee Basin in
Kansas.
General and Administrative
Expenses. We report general and administrative expenses net of
third party reimbursements and internal allocations. The components
of our general and administrative expenses were as follows (in
thousands):
|
Year
Ended December 31,
|
|||||||||
|
2006
|
2005
|
||||||||
|
General
and administrative expenses
|
$ | 60,972 | $ | 42,594 | |||||
|
Reimbursements
and allocations
|
(23,164 | ) | (11,987 | ) | |||||
|
General
and administrative expenses, net
|
$ | 37,808 | $ | 30,607 | |||||
General
and administrative expenses before reimbursements and allocations increased
$18.4 million to $61.0 million during 2006. The largest components of
the increase related to higher costs for personnel salaries, benefits and
related taxes of $13.6 million and an increase in the 2006 accrual for cash
payments under our Production Participation Plan of $3.6
million. Personnel salary expenses were higher in 2006 due to an
increase in our employee base resulting from our continued
growth. The increased cost of the Production Participation Plan was
caused primarily by higher 2006 production volumes and higher average sales
prices on crude oil between years. The increase in reimbursements and
allocations in 2006 was caused by increased salary expenses and a higher number
of field workers on operated properties, due to recent acquisitions and drilling
activities during 2006. In addition, during the fourth quarter of
2006, we revised our labor billing practices to better conform to COPAS
guidelines. This change in labor billing practices resulted in higher
reimbursements and allocations and, therefore, higher amounts of lease operating
expense being charged to us and our joint interest owners on properties we
operate. Our net general and administrative expenses as a percentage
of oil and gas sales remained consistent at 5% for both 2006 and
2005.
Change in Production Participation
Plan Liability. For the year ended December 31, 2006, this
non-cash expense decreased by $3.5 million to $6.2 million. This
expense represents the change in the vested present value of estimated future
payments to be made to participants after 2007 under our Production
Participation Plan (“Plan”). Although payments take place over the
life of oil and gas properties contributed to the Plan, which for some
properties is over 20 years, we must expense the present value of estimated
future payments over the Plan’s five year vesting period. This
expense in 2006 and in 2005 primarily reflects changes to future cash flow
estimates and related Plan liability due to the effect of a sustained higher
price environment, recent drilling activity, and employees’ continued vesting in
the Plan. For the year ended December 31, 2006, the five-year average
historical NYMEX prices used to estimate this liability increased $7.40 for
crude oil and $0.52 for natural gas, as compared to increases in PPP pricing
utilized of $15.01 for crude oil and $2.75 for natural gas for the year ended
December 31, 2005. Assumptions that are used to calculate this
liability are subject to estimation and will vary from year to year based on the
current market for oil and gas, discount rates and overall market
conditions.
Interest
Expense. The components of our interest expense were as
follows (in thousands):
|
Year
Ended December 31,
|
||||||||
|
2006
|
2005
|
|||||||
|
Credit
Agreement
|
$ | 21,478 | $ | 9,997 | ||||
|
Senior
Subordinated Notes
|
44,530 | 25,109 | ||||||
|
Amortization
of debt issue costs and debt discount
|
5,208 | 4,076 | ||||||
|
Accretion
of tax sharing liability
|
2,016 | 2,725 | ||||||
|
Other
|
813 | 138 | ||||||
|
Capitalized
interest
|
(556 | ) | - | |||||
|
Total
interest expense
|
$ | 73,489 | $ | 42,045 | ||||
The
increases in interest expense and amortization of debt issue costs and debt
discount were mainly due to the April 2005 issuance of $220.0 million 7.25%
Senior Subordinated Notes due 2013, the October 2005 issuance of $250.0 million
7% Senior Subordinated Notes due 2014, and additional borrowings outstanding in
2006 under our credit agreement. We also experienced higher weighted
average interest rates on our debt during 2006.
Our
weighted average debt outstanding during 2006 was $945.3 million versus $553.0
million during 2005. Our weighted average effective cash interest
rate was 7.0% during 2006 versus 6.4% during 2005. 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 7.5% during 2006 versus 7.2% during
2005.
Income Tax
Expense. Income tax expense totaled $76.9 million for 2006 and
$74.2 million for 2005. Our effective income tax rate decreased from
37.8% for 2005 to 33.0% for 2006. Our effective income tax rate was
higher for 2006 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.
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
recent high oil prices, the EOR credit was phased-out for 2006.
The
current portion of income tax expense was $12.3 million for 2006 compared to
$8.5 million in 2005. In 2006, we reported a tax loss on our 2005
federal return, primarily due to intangible drilling deductions allowed, which
resulted in a federal tax refund of $4.7 million.
Net Income. Net
income increased from $121.9 million in 2005 to $156.4 million for
2006. The primary reasons for this increase included a 26% increase
in equivalent volumes sold, a 14% increase in oil and gas prices net of hedging
between periods, certain income tax benefits recognized during 2006 and a gain
on sale of oil and gas properties. These increases were partially
offset by higher lease operating expenses, production taxes, DD&A,
exploration and impairment, general and administrative and interest expenses in
2006 resulting from our continued growth.
Liquidity
and Capital Resources
Overview. 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. At December 31, 2006, our debt to total capitalization
ratio was 45.6%, we had $10.4 million of cash on hand and $1,186.7 million of
stockholders’ equity. In 2007, we generated $394.0 million of cash
provided by operating activities, a decrease of $17.2 million from
2006. Cash provided by operating activities decreased primarily
because of higher operating costs, lower production as a result of our recent
dispositions, and lower average sales prices for natural gas, partially offset
by higher average sales prices for crude oil. We also generated $77.3
million from financing activities primarily consisting of $210.4 million in net
proceeds received from the issuance of our common stock, offset by net
repayments under our credit agreement totaling $130.0 million. Cash
flows from operating and financing activities, as well proceeds from property
divestitures, were primarily used to finance $525.3 million of exploration and
development expenditures paid in 2007 and $21.6 million of cash acquisition
capital expenditures, including the Parshall Prospect in North
Dakota. The following chart details our exploration and development
expenditures incurred by region during 2007 (in thousands):
|
Drilling
and Development Expenditures
|
Exploration
Expenditures
|
Total
Expenditures
|
%
of Total
|
|||||||||||||
|
Rocky
Mountains
|
$ | 179,043 | $ | 15,199 | $ | 194,242 | 35 | % | ||||||||
|
Permian
Basin
|
179,715 | 4,737 | 184,452 | 33 | % | |||||||||||
|
Mid-Continent
|
131,936 | 1,819 | 133,755 | 24 | % | |||||||||||
|
Gulf
Coast
|
18,995 | 4,548 | 23,543 | 4 | % | |||||||||||
|
Michigan
|
19,613 | 1,040 | 20,653 | 4 | % | |||||||||||
|
Total incurred
|
529,302 | 27,343 | 556,645 | 100 | % | |||||||||||
|
Increase
in accrued capital expenditures
|
(31,314 | ) | - | (31,314 | ) | |||||||||||
|
Total paid
|
497,988 | 27,343 | $ | 525,331 | ||||||||||||
We
continually evaluate our capital needs and compare them to our capital
resources. Our 2008 budgeted exploration and development expenditures
for the further development of our property base are $640.0 million, an increase
from the $556.6 million incurred on exploration and development expenditures
during 2007, primarily due to additional drilling opportunities that have been
identified in our Robinson Lake area in the Williston Basin, our Boies Ranch and
Jimmy Gulch prospect areas in the Piceance Basin, and other core
areas. Although we have no specific budget for property acquisitions
in 2008, we will continue to selectively pursue property acquisitions that
complement our existing core property base. We expect to fund our
2008 exploration and development expenditures from internally generated cash
flow, cash on hand, and borrowings under our credit agreement. We
believe that should attractive acquisition opportunities arise or exploration
and development expenditures exceed $640.0 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. Our wholly-owned subsidiary, Whiting Oil and Gas
Corporation (“Whiting Oil and Gas”) has a $1.2 billion credit agreement with a
syndicate of banks that, as of December 31, 2007, had a borrowing base of
$900.0 million with $250.0 million in borrowings outstanding, leaving $650.0
million of available borrowing capacity. The borrowing base under the
credit agreement is determined at the discretion of the 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 five-year 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, 2007, letters of credit totaling $0.2 million were
outstanding under the credit agreement.
Interest
accrues at Whiting Oil and Gas’ option at either (1) the base rate plus a
margin, where the base rate is defined as the higher of the prime rate or the
federal funds rate plus 0.5% and the margin varies from 0% to 0.5% depending on
the utilization percentage of the borrowing base, or (2) at the LIBOR rate
plus a margin, where the margin varies from 1.00% to 1.75% depending on the
utilization percentage of the borrowing base. We have consistently
chosen the LIBOR rate option since it delivers the lowest effective interest
rate. Commitment fees of 0.25% to 0.375% accrue on the unused portion
of the borrowing base, depending on the utilization percentage and are included
as a component of interest expense. At December 31, 2007, the
effective weighted average interest rate on the outstanding principal balance
under the credit agreement was 6.1%. At December 31, 2007, we locked
in this LIBOR option at a rate of 5.92% through January 31, 2008. On
January 31, 2008, the LIBOR option rate was reset to 4.27% through March 31,
2008.
The
credit agreement contains restrictive covenants that may limit our ability to,
among other things, pay cash dividends, incur additional indebtedness, sell
assets, make loans to others, make investments, enter into mergers, enter into
hedging contracts, change material agreements, incur liens and engage in certain
other transactions without the prior consent of the lenders and requires us to
maintain a debt to EBITDAX ratio (as defined in the credit agreement) of less
than 3.5 to 1 and a working capital ratio (as defined in the credit agreement)
of greater than 1 to 1. Except for limited exceptions, including the
payment of interest on the senior notes, the credit agreement restricts the
ability of Whiting Oil and Gas and our wholly-owned subsidiary, Equity Oil
Company, to make any dividends, distributions or other payments to Whiting
Petroleum Corporation. The restrictions apply to all of the net
assets of these subsidiaries. We were in compliance with our
covenants under the credit agreement as of December 31,
2007. The credit agreement is secured by a first lien on all of
Whiting Oil and Gas’ properties included in the borrowing base for the credit
agreement. Whiting Petroleum Corporation and Equity Oil Company have
guaranteed the obligations of Whiting Oil and Gas under the credit
agreement. Whiting Petroleum Corporation has pledged the stock of
Whiting Oil and Gas and Equity Oil Company as security for our guarantee, and
Equity Oil Company has mortgaged all of its properties, which are included in
the borrowing base for the credit agreement, as security for its
guarantee.
Senior Subordinated
Notes. In October 2005, we issued at par
$250.0 million of 7% Senior Subordinated Notes due 2014.
In
April 2005, we issued $220.0 million of 7.25% Senior Subordinated Notes due
2013. These notes were issued at 98.507% of par, and the associated
discount is being amortized to interest expense over the term of these
notes.
In
May 2004, we issued $150.0 million of 7.25% Senior Subordinated Notes
due 2012. These notes were issued at 99.26% of par, and the
associated discount is being amortized to interest expense over the term of
these notes.
The notes
are unsecured obligations of ours and are subordinated to all of our senior
debt, which currently consists of Whiting Oil and Gas’ credit
agreement. The indentures governing the notes contain restrictive
covenants that may limit our ability to, among other things, pay cash dividends,
redeem or repurchase our capital stock or our subordinated debt, make
investments, incur additional indebtedness or issue preferred stock, sell
assets, consolidate, merge or transfer all or substantially all of the assets of
ours and our restricted subsidiaries taken as a whole and enter into hedging
contracts. These covenants may potentially limit the discretion of
our management in certain respects. We were in compliance with these
covenants as of December 31, 2007. Our wholly-owned operating
subsidiaries, Whiting Oil and Gas Corporation, Whiting Programs, Inc. and Equity
Oil Company, have fully, unconditionally, jointly and severally guaranteed our
obligations under the notes.
Shelf Registration
Statement. We have on file with the SEC a universal shelf
registration statement to allow us to offer an indeterminate amount of
securities in the future. Under the registration statement, we may
periodically offer from time to time debt securities, common stock, preferred
stock, warrants and other securities or any combination of such securities in
amounts, prices and on terms announced when and if the securities are
offered. The specifics of any future offerings, along with the use of
proceeds of any securities offered, will be described in detail in a prospectus
supplement at the time of any such offering.
Contractual
Obligations and Commitments
Schedule of Contractual
Obligations. The following table summarizes our obligations
and commitments as of December 31, 2007 to make future payments under
certain contracts, aggregated by category of contractual obligation, for
specified time periods. This table does not include Production
Participation Plan liabilities since we cannot determine with accuracy the
timing or amounts of future payments (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)
|
$ | 870,000 | $ | - | $ | 250,000 | $ | 150,000 | $ | 470,000 | ||||||||||
|
Cash
interest expense on debt (b)
|
300,526 | 59,460 | 118,920 | 84,747 | 37,399 | |||||||||||||||
|
Asset
retirement obligations (c)
|
37,192 | 1,309 | 512 | 3,263 | 32,108 | |||||||||||||||
|
Tax
sharing liability (d)
|
25,657 | 2,587 | 4,408 | 3,699 | 14,963 | |||||||||||||||
|
Derivative
contract liability fair value (e)
|
72,796 | 72,796 | - | - | - | |||||||||||||||
|
Purchase
obligations (f)
|
367,675 | 62,887 | 128,897 | 120,512 | 55,379 | |||||||||||||||
|
Drilling
rig contracts (g)
|
56,371 | 33,916 | 22,455 | - | - | |||||||||||||||
|
Operating
leases (h)
|
6,225 | 2,003 | 3,769 | 453 | - | |||||||||||||||
|
Total
|
$ | 1,736,442 | $ | 234,958 | $ | 528,961 | $ | 362,674 | $ | 609,849 | ||||||||||
________________
|
(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
7.2% 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 a fixed interest rate of
6.1%.
|
|
(c)
|
Asset
retirement obligations represent the present value of estimated amounts
expected to be incurred in the future to plug, abandon and 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 costless collars, to
hedge our exposure to crude oil price fluctuations. As of
December 31, 2007, the forward price curves for crude oil generally
exceeded the price curves that were in effect when these contracts were
entered into, resulting in a derivative fair value
liability. If current market prices are higher than a collar’s
price ceiling when the cash settlement amount is calculated, we are
required to pay the contract counterparties. The ultimate
settlement amounts under our derivative contracts are unknown, however, as
they are subject to continuing market
risk.
|
|
(f)
|
We
have two take-or-pay purchase agreements, one agreement expiring in March
2014 and one agreement expiring in December 2014, whereby we have
committed to buy certain volumes of CO2 for
a fixed fee, subject to annual escalation, for use in enhanced recovery
projects in our Postle field in Oklahoma and our North Ward Estes field in
Texas. The purchase agreements are with different
suppliers. Under the terms of the agreements, we are obligated
to purchase a minimum daily volume of CO2 (as
calculated on an annual basis) or else pay for any deficiencies at the
price in effect when the minimum delivery was to have
occurred. The CO2
volumes planned for use on the enhanced recovery projects in the Postle
and North Ward Estes fields currently exceed the minimum daily volumes
provided in these take-or-pay purchase agreements. Therefore,
we expect to avoid any payments for
deficiencies.
|
|
(g)
|
We
currently have two drilling rigs under contract through 2008, two drilling
rigs through 2009, one drilling rig through 2010, and a workover rig under
contract through 2009, all of which are operating in the Rocky Mountains
region. As of December 31, 2007, early termination of these
contracts would have required maximum penalties of $41.2
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 87,000 square feet of administrative office space in Denver,
Colorado under an operating lease arrangement through October 31,
2010, and an additional 30,100 square feet of office space in Midland,
Texas through February 15,
2012.
|
Based on
current oil and gas prices and anticipated levels of production, we believe that
the estimated net cash generated from operations, together with cash on hand and
amounts available under our credit agreement, will be adequate to meet future
liquidity needs, including satisfying our financial obligations and funding our
operations and exploration and development activities.
New
Accounting Policies
In
June 2006, the Financial Accounting Standards Board (“FASB”) issued
Interpretation No. 48, Accounting for Uncertainty in Income
Taxes, an interpretation of Statement of Financial Accounting Standards
No. 109, Accounting for
Income Taxes (“FIN 48”). The interpretation creates a
single model to address accounting for uncertainty in tax
positions. Specifically, the pronouncement prescribes a recognition
threshold and a measurement attribute for the financial statement recognition
and measurement of a tax position taken or expected to be taken in a tax
return. The interpretation also provides guidance on derecognition,
classification, interest and penalties, accounting in interim periods,
disclosure and transition of certain tax positions.
We
adopted the provisions of FIN 48 on January 1, 2007. As a
result of the implementation of FIN 48, we recognized a $0.3 million
increase in the liability for unrecognized tax benefits, which was accounted for
as a reduction to the January 1, 2007 balance of retained earnings and a
corresponding increase in other long-term liabilities. Our policy is
to recognize interest and penalties accrued related to unrecognized tax benefits
within income tax expense.
New
Accounting Pronouncements
In
September 2006, the FASB issued Statement No. 157, Fair Value Measurements
(“SFAS 157”). The adoption of SFAS 157 is not expected to
have a material impact on our consolidated financial position, cash flows or
results of operations. However, additional disclosures may be
required about the information used to develop the
measurements. SFAS 157 establishes a single authoritative
definition of fair value, sets out a framework for measuring fair value and
requires additional disclosures about fair value measurements. This
Standard requires companies to disclose the fair value of their financial
instruments according to a fair value hierarchy. SFAS 157 does
not require any new fair value measurements, but will remove inconsistencies in
fair value measurements between various accounting
pronouncements. SFAS 157 is effective for financial statements
issued for fiscal years beginning after November 15, 2007 and interim
periods within those fiscal years.
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. Under SFAS 159, a company
may elect to use fair value to measure many financial instruments and certain
other assets and liabilities at fair value. We decided not to elect
fair value accounting for any of our eligible items. The adoption of
SFAS 159 therefore will have no impact on our consolidated financial position,
cash flows or results of operations. If the use of fair value is
elected (the fair value option), 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. At the adoption
date, unrealized gains and losses on existing items for which fair value has
been elected are reported as a cumulative adjustment to beginning retained
earnings. Subsequent to the adoption of SFAS 159, changes in fair
value are recognized in earnings. SFAS 159 is effective for fiscal
years beginning after November 15, 2007.
In
December 2007, the FASB issued Statement No. 141R, Business Combinations (“SFAS
141R”). 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 the business combination 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. Accordingly, any
business combinations we engage in will be recorded and disclosed following
existing GAAP until January 1, 2009. We expect SFAS No. 141R will
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.
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. Our
significant accounting policies are 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 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 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, 2007. 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. This decline 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 (“ARO”) 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 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 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
preceding 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 five years. Variances between
estimates used to calculate liabilities related to the Production Participation
Plan and actual sales, cost 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, 2007
would have decreased net income before taxes by $5.6 million in
2007.
Derivative Instruments and Hedging
Activity. We periodically enter into commodity derivative
contracts to manage our exposure to oil and gas price volatility. We
use hedging to reduce price volatility, 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 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 derivative’s 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 currently do not have any derivative contracts in place that
do not qualify as cash flow hedges.
We have
established the fair value of all derivative instruments using estimates
determined by our counterparties and subsequently evaluated such fair values
internally using established index prices and readily available market
data. These values are based upon, among other things, futures
prices, volatility, time to maturity and credit risk. 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 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 estimated 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 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 or companies with oil and gas interests. 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 2007, 2006 and 2005 due to increased demand
for oil field products and services. The oil and gas industry is very
cyclical and the demand for goods and services of oil field companies, suppliers
and others associated with the industry put extreme pressure on the economic
stability and pricing structure within the industry. Typically, as
prices for oil and gas increase, so do all associated
costs. Conversely, in a period of declining prices, associated cost
declines are likely to lag and may not adjust downward in
proportion. Material changes in prices also impact the current
revenue stream, estimates of future reserves, borrowing base calculations of
bank loans and values of properties in purchase and sale
transactions. Material changes in prices can impact the value of oil
and gas companies and their ability to raise capital, borrow money and retain
personnel. While we do not currently expect business costs to
materially increase, continued high prices for oil and gas could result in
increases in the costs of materials, services and personnel.
Forward
Looking Statements
This
report contains statements that we believe to be “forward-looking statements”
within the meaning of the Private Securities Litigation Reform Act of
1995. All statements other than historical facts, including, without
limitation, statements regarding our future financial position, business
strategy, projected revenues, earnings, costs, capital expenditures and debt
levels, and plans and objectives of management for future operations, are
forward-looking statements. When used in this report, words such as
we “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe” or “should”
or the negative thereof or variations thereon or similar terminology are
generally intended to identify forward-looking statements. Such
forward-looking statements are subject to risks and uncertainties that could
cause actual results to differ materially from those expressed in, or implied
by, such statements.
These
risks and uncertainties include, but are not limited to: declines in
oil or gas prices; our level of success in exploitation, exploration,
development and production activities; adverse weather conditions that may
negatively impact development or production activities; the timing of our
exploration and development expenditures, including our ability to obtain
drilling rigs and CO2; our
ability to obtain external capital to finance acquisitions; our ability to
identify and complete acquisitions and to successfully integrate acquired
businesses, including our ability to realize cost savings from completed
acquisitions; unforeseen underperformance of or liabilities associated with
acquired properties; our ability to successfully complete our planned and
potential asset dispositions; inaccuracies of our reserve estimates or our
assumptions underlying them; failure of our properties to yield oil or gas in
commercially viable quantities; uninsured or underinsured losses resulting from
our oil and gas operations; our inability to access oil and gas markets due to
market conditions or operational impediments; the impact and costs of compliance
with laws and regulations governing our oil and gas operations; risks related to
our level of indebtedness and periodic redeterminations of our borrowing base
under our credit agreement; our ability to replace our oil and gas reserves; any
loss of our senior management or technical personnel; competition in the oil and
gas industry in the regions in which we operate; risks arising out of our
hedging transactions and other risks described under the caption “Risk Factors”
in 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 2007 production, our income
before income taxes for 2007 would have moved up or down $9.6 million for each
$1.00 change in oil prices and $3.1 million for every $0.10 change in gas
prices.
We
periodically enter into derivative contracts to manage our exposure to oil and
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, 2008 are summarized below:
|
Commodity
|
Period
|
Monthly
Volume (MMbtu)/(Bbl)
|
NYMEX
Floor/Ceiling
|
|
Crude
Oil
|
01/2008
to 03/2008
|
110,000
|
$49.00/$70.65
|
|
Crude
Oil
|
01/2008
to 03/2008
|
120,000
|
$60.00/$73.90
|
|
Crude
Oil
|
01/2008
to 03/2008
|
100,000
|
$65.00/$80.30
|
|
Crude
Oil
|
04/2008
to 06/2008
|
110,000
|
$48.00/$71.60
|
|
Crude
Oil
|
04/2008
to 06/2008
|
120,000
|
$60.00/$74.65
|
|
Crude
Oil
|
04/2008
to 06/2008
|
100,000
|
$65.00/$80.50
|
|
Crude
Oil
|
07/2008
to 09/2008
|
110,000
|
$48.00/$70.85
|
|
Crude
Oil
|
07/2008
to 09/2008
|
120,000
|
$60.00/$75.60
|
|
Crude
Oil
|
07/2008
to 09/2008
|
100,000
|
$65.00/$81.00
|
|
Crude
Oil
|
10/2008
to 12/2008
|
110,000
|
$48.00/$70.20
|
|
Crude
Oil
|
10/2008
to 12/2008
|
120,000
|
$60.00/$75.85
|
|
Crude
Oil
|
10/2008
to 12/2008
|
100,000
|
$65.00/$81.20
|
The crude
oil collars shown above have the effect of providing a protective floor while
allowing us to share in upward pricing movements. While these hedges
are designed to decrease our exposure to price decreases, they also have the
effect of limiting the benefit of price increases beyond the
ceiling. For the 2008 crude oil contracts listed above, a
hypothetical $1.00 change in the NYMEX price would cause a change in the gain
(loss) on hedging activities in 2008 of $4.0 million.
In a 1997
non-operated property acquisition, we became subject to the operator’s fixed
price gas sales contract with end users for a portion of the natural gas we
produce in Michigan. This contract has built-in pricing escalators of
4% per year. Our estimated future production volumes to be sold under
the fixed pricing terms of this contract as of January 1, 2008 are summarized
below:
|
Commodity
|
Period
Remaining
|
Monthly
Volume (MMbtu)
|
2008
Price Per MMbtu
|
|
Natural
Gas
|
01/2008
to 05/2011
|
26,000
|
$
4.94
|
|
Natural
Gas
|
01/2008
to 09/2012
|
67,000
|
$
4.38
|
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, 2007, our outstanding principal balance under our credit
agreement was $250.0 million and the weighted average interest rate on the
outstanding principal balance was fixed at 6.1% through January
2008. At December 31, 2007, the carrying amount approximated
fair market value. Assuming a constant debt level of $250.0 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 $2.3
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, 2007 swap reset date was
4.82%. As of December 31, 2007, we have recorded a long term asset of
$0.8 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, 2007 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, 2007, 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, 2007 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, 2007 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, 2007, 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, 2007
of the Company and our report dated February 28, 2008, expressed an unqualified
opinion on those financial statements and financial statement
schedule.
/s/
DELOITTE & TOUCHE LLP
Denver,
Colorado
February
28, 2008
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, 2007 and 2006,
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, 2007. 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, 2007 and 2006, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2007, 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, 2007, 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 28, 2008 expressed an
unqualified opinion on the Company's internal control over financial
reporting.
/s/
DELOITTE & TOUCHE LLP
Denver,
Colorado
February
28, 2008
WHITING
PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS
(In
thousands)
|
December
31,
|
||||||||
|
2007
|
2006
|
|||||||
|
ASSETS
|
||||||||
|
CURRENT
ASSETS:
|
||||||||
|
Cash
and cash equivalents
|
$ | 14,778 | $ | 10,372 | ||||
|
Accounts
receivable trade, net
|
110,437 | 97,831 | ||||||
|
Deferred
income taxes
|
27,720 | 3,025 | ||||||
|
Prepaid
expenses and other
|
9,232 | 10,484 | ||||||
|
Total
current assets
|
162,167 | 121,712 | ||||||
|
PROPERTY
AND EQUIPMENT:
|
||||||||
|
Oil
and gas properties, successful efforts method:
|
||||||||
|
Proved
properties
|
3,313,777 | 2,828,282 | ||||||
|
Unproved
properties
|
55,084 | 55,297 | ||||||
|
Other
property and equipment
|
37,778 | 44,902 | ||||||
|
Total
property and equipment
|
3,406,639 | 2,928,481 | ||||||
|
Less
accumulated depreciation, depletion and amortization
|
(646,943 | ) | (495,820 | ) | ||||
|
Total
property and equipment, net
|
2,759,696 | 2,432,661 | ||||||
|
DEBT
ISSUANCE COSTS
|
15,016 | 19,352 | ||||||
|
OTHER
LONG-TERM ASSETS
|
15,132 | 11,678 | ||||||
|
TOTAL
|
$ | 2,952,011 | $ | 2,585,403 | ||||
|
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
|
2007
|
2006
|
||||||
|
CURRENT
LIABILITIES:
|
||||||||
|
Accounts
payable
|
$ | 19,280 | $ | 21,077 | ||||
|
Accrued
capital expenditures
|
59,441 | 28,127 | ||||||
|
Accrued
liabilities
|
29,098 | 30,377 | ||||||
|
Accrued
interest
|
11,240 | 9,124 | ||||||
|
Oil
and gas sales payable
|
26,205 | 19,064 | ||||||
|
Accrued
employee compensation and benefits
|
21,081 | 17,800 | ||||||
|
Production
taxes payable
|
12,936 | 9,820 | ||||||
|
Current
portion of tax sharing liability
|
2,587 | 3,565 | ||||||
|
Current
portion of derivative liability
|
72,796 | 4,088 | ||||||
|
Total
current liabilities
|
254,664 | 143,042 | ||||||
|
NON-CURRENT
LIABILITIES:
|
||||||||
|
Long-term
debt
|
868,248 | 995,396 | ||||||
|
Asset
retirement obligations
|
35,883 | 36,982 | ||||||
|
Production
Participation Plan liability
|
34,042 | 25,443 | ||||||
|
Tax
sharing liability
|
23,070 | 23,607 | ||||||
|
Deferred
income taxes
|
242,964 | 165,031 | ||||||
|
Long-term
derivative liability
|
- | 5,248 | ||||||
|
Other
long-term liabilities
|
2,314 | 3,984 | ||||||
|
Total
non-current liabilities
|
1,206,521 | 1,255,691 | ||||||
|
COMMITMENTS
AND CONTINGENCIES
|
||||||||
|
STOCKHOLDERS’
EQUITY:
|
||||||||
|
Common
stock, $0.001 par value; 75,000,000 shares authorized, 42,480,497 and
36,947,681 shares issued as of December 31, 2007 and 2006,
respectively
|
42 | 37 | ||||||
|
Additional
paid-in capital
|
968,876 | 754,788 | ||||||
|
Accumulated
other comprehensive loss
|
(46,116 | ) | (5,902 | ) | ||||
|
Retained
earnings
|
568,024 | 437,747 | ||||||
|
Total
stockholders’ equity
|
1,490,826 | 1,186,670 | ||||||
|
TOTAL
|
$ | 2,952,011 | $ | 2,585,403 | ||||
|
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,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
REVENUES
AND OTHER INCOME:
|
||||||||||||
|
Oil
and natural gas sales
|
$ | 809,017 | $ | 773,120 | $ | 573,246 | ||||||
|
Loss
on oil and natural gas hedging activities
|
(21,189 | ) | (7,501 | ) | (33,377 | ) | ||||||
|
Gain
on sale of properties
|
29,682 | 12,092 | - | |||||||||
|
Interest
income and other
|
1,208 | 1,116 | 579 | |||||||||
|
Total
revenues and other income
|
818,718 | 778,827 | 540,448 | |||||||||
|
COSTS
AND EXPENSES:
|
||||||||||||
|
Lease
operating
|
208,866 | 183,642 | 111,560 | |||||||||
|
Production
taxes
|
52,407 | 47,095 | 36,092 | |||||||||
|
Depreciation,
depletion and amortization
|
192,811 | 162,831 | 97,639 | |||||||||
|
Exploration
and impairment
|
37,323 | 34,534 | 16,699 | |||||||||
|
General
and administrative
|
39,046 | 37,808 | 30,607 | |||||||||
|
Change
in Production Participation Plan liability
|
8,599 | 6,156 | 9,708 | |||||||||
|
Interest
expense
|
72,504 | 73,489 | 42,045 | |||||||||
|
Total
costs and expenses
|
611,556 | 545,555 | 344,350 | |||||||||
|
INCOME
BEFORE INCOME TAXES
|
207,162 | 233,272 | 196,098 | |||||||||
|
INCOME
TAX EXPENSE:
|
||||||||||||
|
Current
|
550 | 12,346 | 8,514 | |||||||||
|
Deferred
|
76,012 | 64,562 | 65,662 | |||||||||
|
Total
income tax expense
|
76,562 | 76,908 | 74,176 | |||||||||
|
NET
INCOME
|
$ | 130,600 | $ | 156,364 | $ | 121,922 | ||||||
|
NET
INCOME PER COMMON SHARE, BASIC
|
$ | 3.31 | $ | 4.26 | $ | 3.89 | ||||||
|
NET
INCOME PER COMMON SHARE, DILUTED
|
$ | 3.29 | $ | 4.25 | $ | 3.88 | ||||||
|
WEIGHTED
AVERAGE SHARES OUTSTANDING, BASIC
|
39,483 | 36,736 | 31,356 | |||||||||
|
WEIGHTED
AVERAGE SHARES OUTSTANDING, DILUTED
|
39,645 | 36,826 | 31,449 | |||||||||
|
See
notes to consolidated financial statements.
|
||||||||||||
WHITING
PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(In
thousands)
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
||||||||||||
|
Net
income
|
$ | 130,600 | $ | 156,364 | $ | 121,922 | ||||||
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
||||||||||||
|
Depreciation,
depletion and amortization
|
192,811 | 162,831 | 97,639 | |||||||||
|
Deferred
income taxes
|
76,012 | 64,562 | 65,662 | |||||||||
|
Amortization
of debt issuance costs and debt discount
|
5,022 | 5,208 | 4,076 | |||||||||
|
Accretion
of tax sharing liability
|
1,505 | 2,016 | 2,725 | |||||||||
|
Stock-based
compensation
|
5,057 | 3,969 | 2,861 | |||||||||
|
Gain
on sale of properties
|
(29,682 | ) | (12,092 | ) | - | |||||||
|
Undeveloped
leasehold and oil and gas property impairments
|
9,979 | 4,455 | 2,034 | |||||||||
|
Change
in Production Participation Plan liability
|
8,599 | 6,156 | 9,708 | |||||||||
|
Other
non-current
|
(5,086 | ) | 2,653 | 373 | ||||||||
|
Changes
in current assets and liabilities:
|
||||||||||||
|
Accounts
receivable trade
|
(12,606 | ) | 3,235 | (35,012 | ) | |||||||
|
Prepaid
expenses and other
|
1,404 | (2,268 | ) | (302 | ) | |||||||
|
Accounts
payable and accrued liabilities
|
(3,833 | ) | 20,412 | 20,077 | ||||||||
|
Accrued
interest
|
2,116 | (2,770 | ) | 9,844 | ||||||||
|
Other
liabilities
|
12,134 | (3,522 | ) | 28,586 | ||||||||
|
Net
cash provided by operating activities
|
394,032 | 411,209 | 330,193 | |||||||||
|
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
||||||||||||
|
Cash
acquisition capital expenditures
|
(21,568 | ) | (87,562 | ) | (900,332 | ) | ||||||
|
Drilling
and development capital expenditures
|
(497,988 | ) | (464,407 | ) | (196,163 | ) | ||||||
|
Proceeds
from sale of oil and gas properties
|
52,585 | 24,390 | - | |||||||||
|
Acquisition
of partnership interests, net of cash acquired of $26
|
- | - | (30,433 | ) | ||||||||
|
Net
cash used in investing activities
|
(466,971 | ) | (527,579 | ) | (1,126,928 | ) | ||||||
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
||||||||||||
|
Issuance
of common stock
|
210,394 | - | 277,117 | |||||||||
|
Issuance
of 7.25% Senior Subordinated Notes due 2013
|
- | - | 216,715 | |||||||||
|
Issuance
of 7% Senior Subordinated Notes due 2014
|
- | - | 250,000 | |||||||||
|
Long-term
borrowings under credit agreement
|
384,400 | 325,000 | 395,000 | |||||||||
|
Repayments
of long-term borrowings under credit agreement
|
(514,400 | ) | (205,000 | ) | (310,000 | ) | ||||||
|
Repayments
to Alliant Energy Corporation
|
(3,019 | ) | (3,675 | ) | (8,242 | ) | ||||||
|
Debt
issuance costs
|
(75 | ) | (253 | ) | (15,370 | ) | ||||||
|
Tax
effect from restricted stock vesting
|
45 | 288 | 237 | |||||||||
|
Net
cash provided by financing activities
|
77,345 | 116,360 | 805,457 | |||||||||
|
NET
CHANGE IN CASH AND CASH EQUIVALENTS
|
4,406 | (10 | ) | 8,722 | ||||||||
|
CASH
AND CASH EQUIVALENTS:
|
||||||||||||
|
Beginning
of period
|
10,372 | 10,382 | 1,660 | |||||||||
|
End
of period
|
$ | 14,778 | $ | 10,372 | $ | 10,382 | ||||||
|
See
notes to consolidated financial statements.
|
(Continued)
|
|||||||||||
WHITING
PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(In
thousands)
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
SUPPLEMENTAL
CASH FLOW DISCLOSURES:
|
||||||||||||
|
Cash
paid for income taxes
|
$ | 1,446 | $ | 12,063 | $ | 10,620 | ||||||
|
Cash
paid for interest
|
$ | 63,861 | $ | 69,034 | $ | 26,113 | ||||||
|
NONCASH
INVESTING ACTIVITIES:
|
||||||||||||
|
Accrued
capital expenditures during the year
|
$ | 59,441 | $ | 28,127 | $ | 37,544 | ||||||
|
NONCASH
FINANCING ACTIVITIES:
|
||||||||||||
|
Issuance
of common stock – North Ward Estes acquisition
|
$ | - | $ | - | $ | 17,175 | ||||||
|
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, 2005
|
29,718 | $ | 30 | $ | 455,635 | $ | (1,025 | ) | $ | (1,715 | ) | $ | 159,461 | $ | 612,386 | |||||||||||||||||
|
Net
income
|
- | - | - | - | - | 121,922 | 121,922 | $ | 121,922 | |||||||||||||||||||||||
|
Change
in derivative fair values, net of taxes of $34,004
|
- | - | - | (54,089 | ) | - | - | (54,089 | ) | (54,089 | ) | |||||||||||||||||||||
|
Realized
loss on settled derivative contracts, net of taxes of
$12,884
|
- | - | - | 20,494 | - | - | 20,494 | 20,494 | ||||||||||||||||||||||||
|
Restricted
stock issued
|
85 | - | 3,407 | - | (3,407 | ) | - | - | - | |||||||||||||||||||||||
|
Restricted
stock forfeited
|
(9 | ) | - | (230 | ) | - | 230 | - | - | - | ||||||||||||||||||||||
|
Restricted
stock used for tax withholdings
|
(6 | ) | - | (241 | ) | - | - | - | (241 | ) | - | |||||||||||||||||||||
|
Tax
effect from restricted stock vesting
|
- | - | 237 | - | - | - | 237 | - | ||||||||||||||||||||||||
|
Issuance
of stock – secondary offering
|
6,612 | 7 | 277,110 | - | - | - | 277,117 | - | ||||||||||||||||||||||||
|
Issuance
of stock – North Ward Estes acquisition
|
442 | - | 17,175 | - | - | - | 17,175 | - | ||||||||||||||||||||||||
|
Amortization
of deferred compensation
|
- | - | - | - | 2,861 | - | 2,861 | - | ||||||||||||||||||||||||
|
BALANCES-December
31, 2005
|
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 | ||||||||||||||||
|
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, Whiting Oil and
Gas Corporation, Equity Oil Company and Whiting Programs, Inc.
Basis of
Presentation of Consolidated Financial Statements—The consolidated
financial statements include the accounts of Whiting Petroleum Corporation and
its consolidated subsidiaries, all of which are wholly-owned, together with its
pro rata share of the assets, liabilities, revenue and expenses of limited
partnerships in which Whiting was the sole general partner. In June
2005, Whiting increased its ownership interest to 100% in limited partnerships
where it was the sole general partner and subsequently liquidated
them. 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 earning 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 and
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 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, 2007
and 2006, the Company had an allowance for doubtful accounts of $0.3 million and
$0.6 million, respectively.
Inventories—Materials
and supplies inventories consist primarily of tubular goods and production
equipment, stated at the lower of weighted-average cost or
market. Materials and supplies are included in other property and
equipment. Oil inventory in tanks 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 exploration and
development projects that require greater than six months to be readied for
their intended use. During 2007 and 2006, the Company capitalized
$3.7 million and $0.6 million, respectively, of interest. During
2005, capitalized interest costs were insignificant.
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, consisting mainly of
an oil pipeline, furniture and fixtures, leasehold improvements, and
automobiles, are stated at cost and depreciated using the straight-line method
over their estimated useful lives, which range from 4 to 33
years. Also included in other property and equipment are material and
supplies inventories which are not depreciated.
Debt Issuance
Costs—Debt issuance costs related to 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.
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 earnings 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 net income. 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
net income.
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 net income 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 the hedge is no longer highly effective, hedge accounting is
prospectively discontinued.
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, 2007 and 2006, the Company
was in a net (over) under produced imbalance position of (102,000) Mcf and
(273,000) 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. Effective January 1, 2007, the
Company adopted Financial Accounting Standards Board (“FASB”) Interpretation
No. 48, Accounting for
Uncertainty in Income Taxes – An Interpretation of FASB Statement
No. 109 (“FIN 48”). In accordance with this
pronouncement, 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 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 are also reported on the balance sheet at fair market
value.
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 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. During 2005, sales to Teppco Crude Oil
LLC accounted for 10% of the Company’s total oil and gas production
revenue.
Reclassifications—Certain
reclassifications have been made to prior years’ reported amounts in order to
conform to the current year presentation. Such reclassifications had
no impact on net income, stockholders’ equity or cash flows previously
reported.
Change in
Accounting Principle—In June 2006, the FASB issued FIN 48, and
this interpretation creates a single model to address accounting for uncertainty
in tax positions. Specifically, the pronouncement prescribes a
recognition threshold and a measurement attribute for the financial statement
recognition and measurement of a tax position taken or expected to be taken in a
tax return. The interpretation also provides guidance on
derecognition, classification, interest and penalties, accounting in interim
periods, disclosure and transition of certain tax positions.
The
Company adopted the provisions of FIN 48 on January 1, 2007. As a
result of the implementation of FIN 48, the Company recognized a $0.3
million increase in the liability for unrecognized tax benefits, which was
accounted for as a reduction to the January 1, 2007 balance of retained
earnings and a corresponding increase in other long-term
liabilities.
New Accounting
Pronouncements—In September 2006, the FASB issued Statement No. 157,
Fair Value Measurements
(“SFAS 157”). The adoption of SFAS 157 is not expected to
have a material impact on our consolidated financial position, cash flows or
results of operations. However, additional disclosures may be
required about the information used to develop the
measurements. SFAS 157 establishes a single authoritative
definition of fair value, sets out a framework for measuring fair value and
requires additional disclosures about fair value measurements. This
Standard requires companies to disclose the fair value of their financial
instruments according to a fair value hierarchy. SFAS 157 does
not require any new fair value measurements, but will remove inconsistencies in
fair value measurements between various accounting
pronouncements. SFAS 157 is effective for financial statements
issued for fiscal years beginning after November 15, 2007 and interim
periods within those fiscal years.
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. Under SFAS 159, a company
may elect to use fair value to measure many financial instruments and certain
other assets and liabilities at fair value. Whiting decided not to elect
fair value accounting for any of our eligible items. The adoption of SFAS
159 therefore will have no impact on our consolidated financial position, cash
flows or results of operations. If the use of fair value is elected (the
fair value option), 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. At the adoption
date, unrealized gains and losses on existing items for which fair value has
been elected are reported as a cumulative adjustment to beginning retained
earnings. Subsequent to the adoption of SFAS 159, changes in fair
value are recognized in earnings. SFAS 159 is effective for fiscal
years beginning after November 15, 2007.
In
December 2007, the FASB issued Statement No. 141R, Business Combinations (“SFAS
141R”). 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 the business combination 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. Accordingly, any
business combinations the Company engages in will be recorded and disclosed
following existing GAAP until January 1, 2009. The Company expects
SFAS No. 141R will 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.
|
2.
|
ACQUISITIONS
AND DIVESTITURES
|
2007
Acquisitions
There
were no significant acquisitions during the year ended December 31,
2007.
2007
Divestitures
On
July 17, 2007, the Company sold its approximate 50% non-operated working
interest in several gas fields located in the LaSalle and Webb Counties of Texas
for total cash proceeds of $40.1 million, resulting in a pre-tax gain on sale of
$29.7 million. The divested properties had estimated proved reserves
of 2.3 MMBOE as of December 31, 2006, adjusted to the July 1, 2007
divestiture effective date, thereby yielding a sale price of $17.77 per
BOE. The June 2007 average daily net production from these fields was
0.8 MBOE/d.
During
2007, the Company sold its interests in several additional non-core properties
for an aggregate amount of $12.5 million in cash for total estimated proved
reserves of 0.6 MMBOE as of the divestitures’ effective dates. The
divested properties are located in Colorado, Louisiana, Michigan, Montana, New
Mexico, North Dakota, Oklahoma, Texas and Wyoming. The average daily
net production from the divested property interests was 0.3 MBOE/d as of the
dates of disposition.
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 this transaction, the
operator agreed to pay 100% of Whiting’s drilling and completion costs for the
first three wells in the project. The first of these three wells was
drilled in the fourth quarter of 2006, but did not find commercial quantities of
hydrocarbons. The second well was drilled in the fourth quarter of
2007, but it has been cased and temporarily abandoned pending resumed operations
after lease stipulations allow operations to continue in the third quarter of
2008. The third well is planned to be drilled before the end of
2008.
Michigan
Properties. On August 15, 2006, Whiting acquired 65 producing
properties, a gathering line, gas processing plant and 30,437 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. The Company operates 85% of the acquired
properties.
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 properties for an
aggregate amount of $24.4 million in cash, which consisted of 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 net
production from the divested property interests was 0.4 MBOE/d as of the dates
of disposition, and the Company recognized a pre-tax gain of $12.1 million in
the fourth quarter of 2006 on the sale of these properties.
2005
Acquisitions
North Ward Estes and Ancillary
Properties. On October 4, 2005, the Company acquired the
operated interest in the North Ward Estes field in Ward and Winkler counties,
Texas, and certain smaller fields located in the Permian Basin. The
purchase price was $459.2 million, consisting of $442.0 million in
cash and 441,500 shares of the Company’s common stock, for estimated proved
reserves of 82.1 MMBOE as of the acquisition effective date of July 1,
2005, resulting in a cost of $5.58 per BOE of estimated proved
reserves. Proved developed reserve quantities represented 36% of the
total proved reserves acquired. The average daily production from the
properties was 4.6 MBOE/d as of the acquisition effective date. The
Company funded the cash portion of the purchase price with the net proceeds from
the Company’s public offering of common stock and private placement of 7% Senior
Subordinated Notes due 2014.
Postle Field. On
August 4, 2005, the Company acquired the operated interest in producing oil
and gas fields located in the Oklahoma Panhandle. The purchase price
was $343.0 million for estimated proved reserves of 40.3 MMBOE as of the
acquisition effective date of July 1, 2005, resulting in a cost of $8.52
per BOE of estimated proved reserves. Proved developed reserve
quantities represented 57% of the total proved reserves acquired. The
average daily production from the properties was 4.2 MBOE/d as of the
acquisition effective date. The Company funded the acquisition
through borrowings under its credit agreement.
Limited Partnership
Interests. On June 23, 2005, the Company acquired all of
the limited partnership interests in three institutional partnerships managed by
its wholly-owned subsidiary, Whiting Programs, Inc. The partnership
properties are located in Louisiana, Texas, Arkansas, Oklahoma and
Wyoming. The purchase price was $30.5 million for estimated
proved reserves of 2.9 MMBOE as of the acquisition effective date of
January 1, 2005, resulting in a cost of $10.52 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 0.7 MBOE/d as of the acquisition effective date. The
Company funded the acquisition with cash on hand.
Green River
Basin. On March 31, 2005, the Company acquired operated
interests in five producing natural gas fields in the Green River Basin of
Wyoming. The purchase price was $65.0 million for estimated
proved reserves of 8.4 MMBOE as of the acquisition effective date of
March 1, 2005, resulting in a cost of $7.74 per BOE of estimated proved
reserves. Proved developed reserve quantities represented 68% of the
total proved reserves acquired. The average daily production from the
properties was 1.1 MBOE/d as of the acquisition effective date. The
Company funded the acquisition through borrowings under its credit agreement and
with cash on hand.
As these
acquisitions were recorded using the purchase method of accounting, the results
of operations from the acquisitions are included with the Company’s results from
the respective acquisition dates noted above. The table below
summarizes the allocation of the purchase price for each 2005 purchase
transaction based on the acquisition date fair values of the assets acquired and
the liabilities assumed (in thousands).
|
Postle
Field
|
N.
Ward Estes and Ancillary
|
All
Other Acquisitions
|
||||||||||
|
Purchase
Price:
|
||||||||||||
|
Cash
paid, net of cash acquired
|
$ | 343,000 | $ | 442,000 | $ | 95,433 | ||||||
|
Common
stock issued
|
- | 17,175 | - | |||||||||
|
Total
|
$ | 343,000 | $ | 459,175 | $ | 95,433 | ||||||
|
Allocation
of Purchase Price:
|
||||||||||||
|
Working
capital
|
$ | - | $ | - | $ | 2,096 | ||||||
|
Oil
and gas properties
|
343,513 | 463,340 | 95,832 | |||||||||
|
Other
long-term assets
|
243 | - | - | |||||||||
|
Other
non-current liabilities
|
(756 | ) | (4,165 | ) | (2,495 | ) | ||||||
|
Total
|
$ | 343,000 | $ | 459,175 | $ | 95,433 | ||||||
Acquisition Pro
Forma
Pro forma
effects of 2007 and 2006 acquisitions were insignificant to the Company’s
results of operations. The following table reflects the pro forma
results of operations for the year ended December 31, 2005 as though the above
2005 acquisitions had occurred on January 1, 2005. The pro forma
information includes numerous assumptions and is not necessarily indicative of
future results of operations.
|
Year
Ended December 31, 2005
|
||||||||
|
As
Reported
|
Pro
Forma
|
|||||||
|
(In
thousands, except per common share data)
|
||||||||
|
Revenues
and other income
|
$ | 540,448 | $ | 652,634 | ||||
|
Net
income
|
121,922 | 155,462 | ||||||
|
Net
income per common share, basic
|
3.89 | 4.05 | ||||||
|
Net
income per common share, diluted
|
3.88 | 4.04 | ||||||
|
3.
|
LONG-TERM
DEBT
|
Long-term
debt consisted of the following at December 31, 2007 and 2006 (in
thousands):
|
December
31,
|
||||||||
|
2007
|
2006
|
|||||||
|
Credit
agreement
|
$ | 250,000 | $ | 380,000 | ||||
|
7.25%
Senior Subordinated Notes due 2012, net of unamortized debt discount of
$537 and $687, respectively
|
150,214 | 147,820 | ||||||
|
7.25%
Senior Subordinated Notes due 2013, net of unamortized debt discount of
$1,966 and $2,424, respectively
|
218,034 | 217,576 | ||||||
|
7%
Senior Subordinated Notes due 2014
|
250,000 | 250,000 | ||||||
|
Total
debt
|
$ | 868,248 | $ | 995,396 | ||||
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, 2007, had a borrowing
base of $900.0 million. The borrowing base under the credit
agreement is determined at the discretion of the lenders, based on the
collateral value of the proved reserves that have been mortgaged to the lenders,
and is subject to regular redeterminations on May 1 and November 1 of each year,
as well as special redeterminations described in the credit
agreement. As of December 31, 2007, outstanding borrowings under
the credit agreement totaled $250.0 million.
The
credit agreement provides for interest only payments until August 31, 2010,
when the entire amount borrowed is due. Whiting Oil and Gas may,
throughout the five-year term of the credit agreement, borrow, repay and
reborrow up to the borrowing base in effect at any given time. The
lenders under the credit agreement have also committed to issue letters of
credit for the account of Whiting Oil and Gas or other designated subsidiaries
of the Company in an aggregate amount not to exceed
$50.0 million. As of December 31, 2007, letters of credit
totaling $0.2 million were outstanding under the credit agreement.
Interest
accrues, at Whiting Oil and Gas’ option at either (1) the base rate plus a
margin, where the base rate is defined as the higher of the prime rate or the
federal funds rate plus 0.5% and the margin varies from 0% to 0.5% depending on
the utilization percentage of the borrowing base, or (2) at the LIBOR rate
plus a margin, where the margin varies from 1.00% to 1.75% depending on the
utilization percentage of the borrowing base. The Company has
consistently chosen the LIBOR rate option since it delivers the lowest effective
interest rate. Commitment fees of 0.25% to 0.375% accrue on the
unused portion of the borrowing base, depending on the utilization percentage,
and are included as a component of interest expense. At
December 31, 2007, the weighted average interest rate on the outstanding
principal balance under the credit agreement was 6.1%.
The
credit agreement contains restrictive covenants that may limit the Company’s
ability to, among other things, pay cash dividends, incur additional
indebtedness, sell assets, make loans to others, make investments, enter into
mergers, enter into hedging contracts, change material agreements, incur liens
and engage in certain other transactions without the prior consent of the
lenders and requires the Company to maintain a debt to EBITDAX ratio (as defined
in the credit agreement) of less than 3.5 to 1 and a working capital ratio (as
defined in the credit agreement which includes an add back of the available
borrowing capacity under the credit facility) of greater than
1 to 1. Except for limited exceptions, including the
payment of interest on the senior notes, the credit agreement restricts the
ability of Whiting Oil and Gas and Whiting Petroleum Corporation’s wholly-owned
subsidiary, Equity Oil Company, to make any dividends, distributions, principal
payments on senior notes, or other payments to Whiting Petroleum
Corporation. The restrictions apply to all of the net assets of these
subsidiaries. The Company was in compliance with its covenants under
the credit agreement as of December 31, 2007. The credit
agreement is secured by a first lien on all of Whiting Oil and Gas’ properties
included in the borrowing base for the credit agreement. Whiting
Petroleum Corporation and Equity Oil Company have guaranteed the obligations of
Whiting Oil and Gas under the credit agreement. Whiting Petroleum
Corporation has pledged the stock of Whiting Oil and Gas and Equity Oil Company
as security for its guarantee, and Equity Oil Company has mortgaged all of its
properties, that are included in the borrowing base for the credit agreement, as
security for its guarantee.
Senior
Subordinated Notes—In October 2005, the Company issued at par
$250.0 million of 7% Senior Subordinated Notes due 2014. The
estimated fair value of these notes was $246.6 million as of
December 31, 2007.
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
7.5%. The estimated fair value of these notes was $215.9 million
as of December 31, 2007.
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
7.4%. The estimated fair value of these notes was $147.0 million
as of December 31, 2007.
The notes
are unsecured obligations of Whiting Petroleum Corporation and are subordinated
to all of the Company’s senior debt, which currently consists of Whiting Oil and
Gas’ credit agreement. The indentures governing the notes contain
various restrictive covenants that are substantially identical and may limit the
Company’s ability to, among other things, pay cash dividends, redeem or
repurchase the Company’s capital stock or the Company’s subordinated debt, make
investments, incur additional indebtedness or issue preferred stock, sell
assets, consolidate, merge or transfer all or substantially all of the assets of
the Company and its restricted subsidiaries taken as a whole, and enter into
hedging contracts. These covenants may potentially limit the
discretion of the Company’s management in certain respects. The
Company was in compliance with these covenants as of December 31,
2007. The Company’s wholly-owned operating subsidiaries, Whiting Oil
and Gas, Whiting Programs, Inc. and Equity Oil Company (the “Guarantors”), have
fully, unconditionally, jointly and severally guaranteed the Company’s
obligations under the notes. The Company does not have any
subsidiaries other than the Guarantors, minor or otherwise, within the meaning
of Rule 3-10(h)(6) of Regulation S-X of the Securities and Exchange
Commission, and Whiting Petroleum Corporation has no assets or operations
independent of this debt and its investments in guarantor
subsidiaries.
Interest Rate
Swap—In August 2004, the Company entered into an interest rate swap
contract to hedge the fair value of $75.0 million of its 7.25% Senior
Subordinated Notes due 2012. Because this swap meets the conditions
to qualify for the “short cut” method of assessing effectiveness, the change in fair value of
the debt is assumed to equal the change in the fair value of the interest rate
swap. As such, there is no ineffectiveness assumed to exist between
the interest rate swap and the notes.
The
interest rate swap is a fixed for floating swap in that the Company receives the
fixed rate of 7.25% and pays the floating rate. The floating rate is
redetermined every six months based on the LIBOR rate in effect at the
contractual reset date. When LIBOR plus the Company’s margin of
2.345% is less than 7.25%, the Company receives a payment from the counterparty
equal to the difference in rate times $75.0 million for the six month
period. When LIBOR plus the Company’s margin of 2.345% is greater
than 7.25%, the Company pays the counterparty an amount equal to the difference
in rate times $75.0 million for the six month period. The LIBOR
rate at December 31, 2007 was 4.6%. For the years ended December
31, 2007, 2006 and 2005, Whiting recognized realized gains (losses) of $(0.4)
million, $(0.05) million and $1.5 million, respectively, on the interest rate
swap. As of December 31, 2007, the Company has recorded a
long-term asset of $0.8 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
portion at December 31, 2007 and 2006 is $1.3 million and $0.6 million,
respectively, and is recorded in accrued liabilities. The following
table provides a reconciliation of the Company’s asset retirement obligations
for the years ended December 31, 2007 and 2006 (in thousands):
|
Year
Ended December 31,
|
||||||||
|
2007
|
2006
|
|||||||
|
Beginning
asset retirement obligation
|
$ | 37,534 | $ | 32,246 | ||||
|
Revisions
in estimated cash flows
|
76 | 3,719 | ||||||
|
Additional
liability incurred
|
1,490 | 2,260 | ||||||
|
Accretion
expense
|
2,850 | 2,288 | ||||||
|
Obligations
on sold properties
|
(2,557 | ) | (1,432 | ) | ||||
|
Liabilities
settled
|
(2,201 | ) | (1,547 | ) | ||||
|
Ending
asset retirement obligation
|
$ | 37,192 | $ | 37,534 | ||||
|
5.
|
DERIVATIVE
FINANCIAL INSTRUMENTS
|
Whiting
enters into derivative contracts, primarily costless collars, to hedge future
crude oil and natural gas production in order to mitigate the risk of market
price fluctuations. 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. The
Company has designated these contracts as cash flow hedges designed to achieve a
more predictable cash flow, as well as to reduce its exposure to price
volatility. While the use of these derivative instruments limits the
downside risk of adverse price movements, they may also limit future revenues
from favorable price movements. The Company does not enter into
derivative instruments for speculative or trading purposes.
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. At December 31, 2006,
accumulated other comprehensive loss consisted of $9.3 million ($5.9 million
after tax) of unrealized losses, representing the mark-to-market value of the
Company’s open commodity contracts, designated as cash flow hedges, as of the
balance sheet date.
For the
years ended December 31, 2007, 2006 and 2005, Whiting recognized realized cash
settlement losses of $21.2 million, $7.5 million and $33.4 million,
respectively, on commodity derivative settlements. Based on the
estimated fair value of the Company’s derivative contracts at December 31, 2007,
it expects to reclassify net losses of $72.8 million into earnings related to
derivative contracts during the next twelve months; however, actual cash
settlement gains and losses recognized may differ materially. The
Company has hedged 4.0 MMbbl of crude oil volumes in 2008.
The
Company has also entered into an interest rate swap designated as a fair value
hedge as further explained in Long-Term Debt.
|
6.
|
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, 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.
On
October 4, 2005, the Company completed a public offering of its common stock,
selling 6,612,500 shares of common stock at a price of $43.60 per share,
providing net proceeds of $277.1 million. The number of shares
includes the sale of 862,500 shares pursuant to the exercise of the
underwriters’ overallotment option. The Company used the net proceeds
to pay the cash portion of the purchase price for the acquisition of the North
Ward Estes properties and to repay a portion of the debt outstanding under its
credit agreement, which incremental borrowings were incurred in connection with
the acquisition of the Postle properties.
Equity Incentive
Plan—The Company
maintains the Whiting Petroleum Corporation 2003 Equity Incentive Plan (“the
Plan”), pursuant to which two million shares of the Company’s common stock have
been reserved for issuance. No employee or officer participant may be
granted options for more than 300,000 shares of common stock, stock appreciation
rights with respect to more than 300,000 shares of common stock, or more than
150,000 shares of restricted stock during any calendar year.
Restricted
stock awards for executive officers, directors and employees generally vest
ratably over three years. In February 2007, however, restricted stock
awards granted to executive officers included certain performance conditions, in
addition to the standard three-year service condition, that must be met in order
for the stock awards to vest. The Company believes that it is
probable that such performance conditions will be achieved and has accrued
compensation cost accordingly for its 2007 restricted stock grants to
executives.
The
following table shows a summary of the Company’s nonvested restricted stock as
of December 31, 2005, 2006 and 2007 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, 2005
|
105,197 | $ | 21.83 | |||||
|
Granted
|
84,652 | $ | 40.26 | |||||
|
Vested
|
(28,699 | ) | $ | 21.73 | ||||
|
Forfeited
|
(15,387 | ) | $ | 23.19 | ||||
|
Restricted
stock awards nonvested, December 31, 2005
|
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 | |||||
The grant
date fair value of restricted stock is determined based on the closing bid price
of the Company’s common stock on the grant date. The Company uses
historical data and projections to estimate expected employee behaviors related
to restricted stock forfeitures. The expected forfeitures are then
included as part of the grant date estimate of compensation cost.
As of
December 31, 2007, there was $3.5 million of total unrecognized compensation
cost related to unvested restricted stock granted under the
Plan. That cost is expected to be recognized over a weighted average
period of 1.9 years. For the years ended December 31, 2007, 2006 and
2005, the total fair value of restricted stock vested was $4.7 million, $2.6
million and $1.4 million, respectively.
Rights
Agreement—On February 23, 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.
|
7.
|
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, 2007, 2006 and 2005 amounted to $15.8 million, $13.2 million
and $10.2 million, respectively, charged to general and administrative expense
and $2.8 million, $2.5 million and $1.9 million, respectively, charged to
exploration expense.
Employees
vest in the Plan ratably at 20% per year over a five year
period. Pursuant to the terms of the Plan, (1) employees who
terminate their employment with the Company are entitled to receive their vested
allocation of future Plan year payments on an annual basis; (2) employees will
become fully vested at age 62, regardless of when their interests would
otherwise vest; and (3) any forfeitures for Plan years after 2003 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, 2007, the
Company used five-year average historical NYMEX prices of $54.82 for crude oil
and $6.68 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,
2007, 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 $125.2 million. This amount includes
$20.8 million attributable to proved undeveloped oil and gas properties and
$18.6 million relating to the short-term portion of the Plan liability, which
has been accrued as a current payable to be paid in February
2008. 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,
|
||||||||
|
2007
|
2006
|
|||||||
|
Beginning
Production Participation Plan liability
|
$ | 25,443 | $ | 19,287 | ||||
|
Change
in liability for accretion, vesting and change in
estimates
|
27,225 | 21,849 | ||||||
|
Reduction
in liability for cash payments accrued and recognized as compensation
expense
|
(18,626 | ) | (15,693 | ) | ||||
|
Ending
Production Participation Plan liability
|
$ | 34,042 | $ | 25,443 | ||||
The
Company records the expense associated with changes in the present value of
estimated non-current 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 table below presents the estimated allocation of the
change in the non-current portion of the liability if the Company did allocate
the adjustment to these specific line items (in thousands).
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
General
and administrative expense
|
$ | 7,293 | $ | 5,196 | $ | 8,186 | ||||||
|
Exploration
expense
|
1,306 | 960 | 1,522 | |||||||||
|
Total
|
$ | 8,599 | $ | 6,156 | $ | 9,708 | ||||||
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
2007, 2006 and 2005 were $2.4 million, $2.1 million and $1.2 million,
respectively. Employees vest in employer contributions at 20% per
year of completed service.
|
8.
|
INCOME
TAXES
|
Income
tax expense consists of the following (in thousands):
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
Current
income tax expense:
|
||||||||||||
|
Federal
|
$ | 32 | $ | 11,576 | $ | 5,076 | ||||||
|
State
|
518 | 770 | 3,438 | |||||||||
|
Total
current income tax expense
|
550 | 12,346 | 8,514 | |||||||||
|
Deferred
income tax expense:
|
||||||||||||
|
Federal
|
72,937 | 65,402 | 59,538 | |||||||||
|
State
|
3,075 | (840 | ) | 6,124 | ||||||||
|
Total
deferred income tax expense
|
76,012 | 64,562 | 65,662 | |||||||||
|
Total
|
$ | 76,562 | $ | 76,908 | $ | 74,176 | ||||||
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,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
U.S.
statutory income tax expense
|
$ | 72,506 | $ | 81,645 | $ | 68,634 | ||||||
|
State
income taxes, net of federal benefit
|
4,176 | 907 | 7,028 | |||||||||
|
Tax
credits
|
330 | (4,206 | ) | (929 | ) | |||||||
|
Statutory
depletion
|
(405 | ) | (1,245 | ) | (434 | ) | ||||||
|
Enacted
changes in state tax laws
|
(599 | ) | (1,295 | ) | - | |||||||
|
Change
in valuation allowance
|
67 | 1,163 | - | |||||||||
|
Permanent
items
|
570 | (187 | ) | (123 | ) | |||||||
|
Other
|
(83 | ) | 126 | - | ||||||||
|
Total
|
$ | 76,562 | $ | 76,908 | $ | 74,176 | ||||||
The
principal components of the Company’s deferred income tax assets and liabilities
at December 31, 2007 and 2006 were as follows (in thousands):
|
Year
Ended December 31,
|
||||||||
|
2007
|
2006
|
|||||||
|
Deferred
income tax assets:
|
||||||||
|
Net
operating loss carryforward
|
$ | 20,952 | $ | - | ||||
|
Derivative
instruments
|
26,680 | 3,433 | ||||||
|
Production
Participation Plan liability
|
12,581 | 9,357 | ||||||
|
Tax
sharing liability
|
10,598 | 9,993 | ||||||
|
Asset
retirement obligations
|
11,806 | 11,673 | ||||||
|
Restricted
stock compensation
|
2,274 | 1,849 | ||||||
|
Enhanced
oil recovery credit carryforwards
|
7,946 | 6,894 | ||||||
|
Alternative
minimum tax credit carryforwards
|
9,653 | 9,900 | ||||||
|
State
deductibles
|
2,135 | - | ||||||
|
Foreign
tax credit carryforwards
|
1,230 | 1,560 | ||||||
|
Other
|
110 | - | ||||||
|
Total
deferred income tax assets
|
105,965 | 54,659 | ||||||
|
Less
valuation allowances
|
(1,230 | ) | (1,163 | ) | ||||
|
Net
deferred income tax assets
|
104,735 | 53,496 | ||||||
|
Deferred
income tax liabilities:
|
||||||||
|
Oil
and gas properties
|
319,979 | 215,488 | ||||||
|
Other
|
- | 14 | ||||||
|
Total
deferred income tax liabilities
|
319,979 | 215,502 | ||||||
|
Total
net deferred income tax liabilities
|
$ | 215,244 | $ | 162,006 | ||||
At
December 31, 2007, the Company had federal and state net operating loss
carryforwards of $21.0 million. If unutilized, the federal net
operating loss will expire in 2027 and the state net operating loss will expire
between 2012 and 2027.
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, 2007, 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. Due to recent high oil prices, the EOR credit was
phased-out for 2007 and 2006.
The
Company is subject to the alternative minimum tax (“AMT”) principally due to
accelerated tax depreciation. As of December 31, 2007, 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, 2007, the Company’s foreign tax credit carryforwards totaled $1.2
million, which will expire between 2024 and 2026. As of December 31,
2007, 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 recent divestitures of all foreign operations.
Net
deferred income tax liabilities were classified in the consolidated balance
sheets as follows (in thousands):
|
Year
Ended December 31,
|
||||||||
|
2007
|
2006
|
|||||||
|
Assets:
|
||||||||
|
Current
deferred income taxes
|
$ | 27,720 | $ | 3,025 | ||||
|
Liabilities:
|
||||||||
|
Non-current
deferred income taxes
|
242,964 | 165,031 | ||||||
|
Net
deferred income tax liabilities
|
$ | 215,244 | $ | 162,006 | ||||
On
January 1, 2007, the Company adopted the provisions of FIN 48. As a
result of the implementation of FIN 48, the Company recognized a $0.3
million increase in the liability for unrecognized tax benefits, which was
accounted for as a reduction to the January 1, 2007 balance of retained
earnings and a corresponding increase in other long-term
liabilities. As of the adoption date after recognizing the increase
noted above, the Company’s liability for unrecognized tax benefits totaled $0.4
million. The following table summarizes the activity during the year
related to the liability for unrecognized tax benefits (in
thousands):
|
Year Ended
|
||||
|
December
31, 2007
|
||||
|
Beginning
balance at January 1
|
$ | 396 | ||
|
Increases
related to amended returns
|
96 | |||
|
Decreases
associated with accounting method change
|
(322 | ) | ||
|
Ending
balance at December 31
|
$ | 170 | ||
Included
in the unrecognized tax benefit balance at December 31, 2007, 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, 2007, 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 2004 through 2007 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 2001 through 2007.
Prior to
November 23, 2003, Whiting was owned 100% by Alliant Energy Corporation
(“Alliant Energy”). Alliant Energy is presently under audit by the
IRS for the years 1999 through 2003. Based on discussions with
Alliant Energy, the Company believes that there are no issues that would require
adjustment to Whiting’s tax liability for the periods 1999 to
2001. Information is not yet available for the 2002 to 2003
periods.
|
9.
|
RELATED
PARTY TRANSACTIONS
|
Prior to
Whiting’s initial public offering in November 2003, it was a wholly-owned
indirect subsidiary of 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.
Tax Sharing
Liability—In connection with Whiting’s initial public offering in
November 2003, the Company entered into a Tax Separation and Indemnification
Agreement with Alliant Energy. Pursuant to this agreement, the
Company and Alliant Energy made a tax election with the effect that the tax
bases of Whiting’s assets were increased to the deemed purchase price of their
assets immediately prior to such initial public offering. Whiting has
adjusted deferred taxes on its balance sheet to reflect the new tax bases of its
assets. The additional bases are expected to result in increased
future income tax deductions and, accordingly, may reduce income taxes otherwise
payable by Whiting.
Under
this agreement, the Company has agreed to pay to Alliant Energy 90% of the
future tax benefits the Company realizes annually as a result of this step-up in
tax basis for the years ending on or prior to December 31, 2013. Such
tax benefits will generally be calculated by comparing the Company’s actual
taxes to the taxes that would have been owed by the Company had the increase in
basis not occurred. In 2014, Whiting will be obligated to pay Alliant
Energy the present value of the remaining tax benefits, assuming all such tax
benefits will be realized in future years. The Company has estimated
total payments to Alliant will approximate $34.7 million on an undiscounted
basis.
During
2007, 2006 and 2005, the Company made payments of $3.0 million, $3.7 million and
$5.1 million, respectively, under this agreement and recognized accretion
expense of $1.5 million, $2.0 million and $2.7 million, respectively, which is
included as a component of interest expense. The Company’s estimated
payment of $2.6 million to be made in 2008 under this agreement is reflected as
a current liability at December 31, 2007.
The Tax
Separation and Indemnification Agreement provides that if tax rates were to
change (increase or decrease), the tax benefit or detriment would result in a
corresponding adjustment of the tax sharing liability. For purposes
of this calculation, management has assumed that no such future changes will
occur during the term of this agreement.
The
Company periodically evaluates its estimates and assumptions as to future
payments to be made under this agreement. If non-substantial changes
(less than 10% on a present value basis) are made to the anticipated payments
owed to Alliant Energy, a new effective interest rate is determined for this
debt based on the carrying amount of the liability as of the modification date
and based on the revised payment schedule. However, if there are
substantial changes to the estimated payments owed under this agreement, then a
gain or loss is recognized in the consolidated statements of income during the
period in which the modification has been made.
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 and calculated its income tax expense on a separate return basis at
Alliant Energy’s effective tax rate, less any research or Section 29 tax credits
generated by the Company. Current tax due under this calculation was
paid to Alliant Energy, and current refunds were received from Alliant
Energy. Section 29 tax credits were generated by Whiting in 2002, and
on a stand-alone basis Whiting would have been unable to use the credits in its
2002 tax return. The Company therefore had a current receivable from
Alliant Energy of $4.1 million for these credits. During 2007,
Whiting received payment in full, as the credits were entirely utilized by
Alliant Energy.
Alliant Energy
Guarantee—The Company holds a 6% working interest in three offshore
platforms and related onshore plant and equipment in
California. Alliant Energy has guaranteed the Company’s obligation in
the abandonment of these assets.
|
10.
|
COMMITMENTS
AND CONTINGENCIES
|
Non-cancelable
Leases—The Company leases 87,000 square feet of administrative office
space in Denver, Colorado under an operating lease arrangement through October
31, 2010 and an additional 30,100 square feet of office space in Midland, Texas
through February 15, 2012. Rental expense for 2007, 2006 and 2005
amounted to $2.1 million, $1.9 million and $1.5 million,
respectively. Minimum lease payments under the terms of
non-cancelable operating leases as of December 31, 2007 are as follows (in
thousands):
|
2008
|
$ | 2,003 | ||
|
2009
|
2,017 | |||
|
2010
|
1,753 | |||
|
2011
|
381 | |||
|
2012
|
71 | |||
|
Total
|
$ | 6,225 |
Purchase
Contracts—The Company has two take-or-pay purchase agreements, one
agreement expiring in March 2014 and one agreement expiring in December 2014,
whereby the Company has committed to buy certain volumes of CO2 for a
fixed fee subject to annual escalation. The purchase agreements are
with different suppliers, and the CO2 is for use
in enhanced recovery projects in the Postle field in Texas County, Oklahoma and
the North Ward Estes field in Ward County, Texas. Under the terms of
the agreements, the Company is obligated to purchase a minimum daily volume of
CO2
(as calculated on an annual basis) or else pay for any deficiencies at the price
in effect when delivery was to have occurred. The CO2 volumes
planned for use on the enhanced recovery projects in the Postle and North Ward
Estes fields currently exceed the minimum daily volumes provided in these
take-or-pay purchase agreements. Therefore, the Company expects to
avoid any payments for deficiencies. As of December 31, 2007, future
commitments under the purchase agreements amounted to $367.7 million through
2014.
Drilling
Contracts—The
Company has two drilling rigs under contract through 2008, two drilling rigs
through 2009, one drilling rig through 2010, and a workover rig under contract
through 2009, all of which are operating in the Rocky Mountains
region. As of December 31, 2007, these agreements had total
commitments of $56.4 million and early termination would require maximum
penalties of $41.2 million. Other drilling rigs working for the
Company are not under long-term contracts but instead are under contracts that
can be terminated at the end of the well that is currently being
drilled.
Litigation—The
Company is subject to litigation, claims and governmental and regulatory
proceedings arising in the ordinary course of business. It is the
opinion of the Company’s management that all claims and litigation involving the
Company are not likely to have a material adverse effect on its consolidated
financial position, cash flows or results of operations.
|
11.
|
OIL
AND GAS ACTIVITIES
|
The
Company’s oil and gas activities for 2007 were entirely within the United
States. During 2006 and 2005, 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,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
Unproved
property acquisition
|
$ | 13,598 | $ | 38,628 | $ | 16,124 | ||||||
|
Proved
property acquisition
|
8,128 | 29,778 | 906,208 | |||||||||
|
Development
|
506,057 | 408,828 | 215,162 | |||||||||
|
Exploration
|
56,741 | 81,877 | 22,532 | |||||||||
|
Total
|
$ | 584,524 | $ | 559,111 | $ | 1,160,026 | ||||||
During
2007, 2006 and 2005, additions to oil and gas properties of $1.5 million, $2.3
million and $8.1 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,
|
||||||||
|
2007
|
2006
|
|||||||
|
Proved
oil and gas properties
|
$ | 3,313,777 | $ | 2,828,282 | ||||
|
Unproved
oil and gas properties
|
55,084 | 55,297 | ||||||
|
Accumulated
depreciation, depletion and amortization
|
(637,549 | ) | (489,550 | ) | ||||
|
Oil
and gas properties, net
|
$ | 2,731,312 | $ | 2,394,029 | ||||
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,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
Beginning
balance at January 1
|
$ | 10,194 | $ | 4,193 | $ | 2,937 | ||||||
|
Additions
to capitalized exploratory well costs pending the determination of proved
reserves
|
19,203 | 51,798 | 6,500 | |||||||||
|
Reclassifications
to wells, facilities and equipment based on the determination of
proved reserves
|
(28,872 | ) | (43,276 | ) | (5,244 | ) | ||||||
|
Capitalized
exploratory well costs charged to expense
|
- | (2,521 | ) | - | ||||||||
|
Ending
balance at December 31
|
$ | 525 | $ | 10,194 | $ | 4,193 | ||||||
At
December 31, 2007, the Company had no exploratory well costs capitalized for a
period of greater than one year after the completion of drilling.
|
12.
|
DISCLOSURES
ABOUT OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
|
The
estimates of proved reserves and related valuations were based 100% on reports
prepared by the Company’s independent petroleum engineers, Cawley, Gillespie
& Associates, Inc. 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, 2007, 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, 2005, 2006 and 2007, are as follows:
|
Oil
(Mbbl)
|
Natural
Gas
(MMcf)
|
|||||||
|
Balance—January
1, 2005
|
87,588 | 339,856 | ||||||
|
Extensions
and discoveries
|
1,956 | 21,068 | ||||||
|
Sales
of minerals in place
|
- | - | ||||||
|
Purchases
of minerals in place
|
115,737 | 101,082 | ||||||
|
Production
|
(7,032 | ) | (30,272 | ) | ||||
|
Revisions
to previous estimates
|
950 | (45,322 | ) | |||||
|
Balance—December
31, 2005
|
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 | ||||||
|
Proved
developed reserves:
|
||||||||
|
December
31, 2005
|
111,954 | 267,429 | ||||||
|
December
31, 2006
|
122,496 | 226,516 | ||||||
|
December
31, 2007
|
127,291 | 237,030 | ||||||
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 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 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 gas reserves at year end, based on year-end costs and assuming
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 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 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 procedure does not
necessarily result in an estimate of the fair market value or the present value
of the Company’s oil and gas properties.
The
standardized measure of discounted future net cash flows relating to proved oil
and gas reserves are as follows (in thousands):
|
December
31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
Future
cash flows
|
$ | 19,747,430 | $ | 12,635,239 | $ | 14,294,674 | ||||||
|
Future
production costs
|
(6,022,667 | ) | (4,248,973 | ) | (4,484,415 | ) | ||||||
|
Future
development costs
|
(1,186,826 | ) | (1,176,778 | ) | (909,093 | ) | ||||||
|
Future
income tax expense
|
(3,952,146 | ) | (2,064,596 | ) | (2,773,077 | ) | ||||||
|
Future
net cash flows
|
8,585,791 | 5,144,892 | 6,128,089 | |||||||||
|
10%
annual discount for estimated timing of cash flows
|
(4,574,125 | ) | (2,752,650 | ) | (3,245,188 | ) | ||||||
|
Standardized
measure of discounted future net cash flows
|
$ | 4,011,666 | $ | 2,392,242 | $ | 2,882,901 | ||||||
Future
cash flows as shown above were reported without consideration for the effects of
hedging transactions outstanding at each period end. If the effects
of hedging transactions were included in the computation, then future cash flows
would have decreased by $81.8 million in 2007, increased by $2.3 million in
2006, and decreased by $7.3 million in 2005.
The
changes in the standardized measure of discounted future net cash flows relating
to proved oil and gas reserves are as follows (in thousands):
|
December
31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Beginning
of year
|
$ | 2,392,242 | $ | 2,882,901 | $ | 1,312,054 | ||||||
|
Sale
of oil and gas produced, net of production costs
|
(547,744 | ) | (542,383 | ) | (425,594 | ) | ||||||
|
Sales
of minerals in place
|
(72,360 | ) | (30,520 | ) | - | |||||||
|
Net
changes in prices and production costs
|
2,261,006 | (579,948 | ) | 628,987 | ||||||||
|
Extensions,
discoveries and improved recoveries
|
440,337 | 162,969 | 104,609 | |||||||||
|
Development
costs, net
|
(4,030 | ) | (212,076 | ) | (361,356 | ) | ||||||
|
Purchases
of mineral in place
|
17,098 | 29,663 | 2,321,289 | |||||||||
|
Revisions
of previous quantity estimates
|
43,019 | (167,956 | ) | (115,617 | ) | |||||||
|
Net
change in income taxes
|
(757,127 | ) | 561,302 | (766,485 | ) | |||||||
|
Accretion
of discount
|
239,224 | 288,290 | 185,014 | |||||||||
|
End
of year
|
$ | 4,011,665 | $ | 2,392,242 | $ | 2,882,901 | ||||||
Average
wellhead prices in effect at December 31, 2007, 2006 and 2005 inclusive of
adjustments for quality and location used in determining future net revenues
related to the standardized measure calculation were as follows:
|
2007
|
2006
|
2005
|
||||||||||
|
Oil
(per Bbl)
|
$ | 88.62 | $ | 54.81 | $ | 55.10 | ||||||
|
Gas
(per Mcf)
|
$ | 6.31 | $ | 5.41 | $ | 7.97 | ||||||
|
13.
|
QUARTERLY
FINANCIAL DATA (UNAUDITED)
|
The
following is a summary of the unaudited quarterly financial data for the years
ended December 31, 2007 and 2006 (in thousands, except per share
data):
|
Three
Months Ended
|
||||||||||||||||||||
|
March
31,
2007
|
June
30,
2007
|
September
30,
2007
|
December
31,
2007
|
Year
|
||||||||||||||||
|
Year ended December 31,
2007:
|
||||||||||||||||||||
|
Oil
and natural gas sales
|
$ | 159,714 | $ | 192,646 | $ | 205,594 | $ | 251,063 | $ | 809,017 | ||||||||||
|
Operating
profit (1)
|
56,474 | 79,249 | 89,617 | 129,593 | 354,933 | |||||||||||||||
|
Net
income
|
10,666 | 26,471 | 47,713 | 45,750 | 130,600 | |||||||||||||||
|
Basic
net income per share
|
0.29 | 0.72 | 1.14 | 1.08 | 3.31 | |||||||||||||||
|
Diluted
net income per share
|
0.29 | 0.72 | 1.13 | 1.08 | 3.29 | |||||||||||||||
|
Three
Months Ended
|
||||||||||||||||||||
|
March
31,
2006
|
June
30,
2006
|
September
30,
2006
|
December
31,
2006
|
Year
|
||||||||||||||||
|
Year ended December 31,
2006:
|
||||||||||||||||||||
|
Oil
and natural gas sales
|
$ | 189,865 | $ | 203,643 | $ | 207,751 | $ | 171,861 | $ | 773,120 | ||||||||||
|
Operating
profit (1)
|
98,234 | 107,683 | 106,339 | 67,296 | 379,552 | |||||||||||||||
|
Net
income
|
32,990 | 45,880 | 49,544 | 27,950 | 156,364 | |||||||||||||||
|
Basic
net income per share
|
0.90 | 1.25 | 1.35 | 0.76 | 4.26 | |||||||||||||||
|
Diluted
net income per share
|
0.90 | 1.25 | 1.35 | 0.76 | 4.25 | |||||||||||||||
(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,
2007. 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, 2007 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, 2007 that has materially affected, or is reasonably likely to materially
affect, our internal control over financial reporting.
|
Item 9B.
|
Other
Information
|
None.
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 2008 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,
2007.
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 | 1,611,864 | (2) | ||||||||
|
Equity
compensation plans not approved by security holders
|
- | N/A | - | |||||||||
|
Total
|
- | N/A | 1,611,864 | (2) | ||||||||
|
|
_____________
|
|
(1)
|
Includes
only the Whiting Petroleum Corporation 2003 Equity Incentive
Plan.
|
|
(2)
|
Excludes
239,656 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, 2007 and
2006
|
|
|
c.
|
Consolidated
Statements of Income for the Years ended December 31, 2007, 2006 and
2005
|
|
|
d.
|
Consolidated
Statements of Cash Flows for the Years ended December 31, 2007, 2006
and 2005
|
|
|
e.
|
Consolidated
Statements of Stockholders’ Equity and Comprehensive Income for the Years
ended December 31, 2007, 2006 and
2005
|
|
|
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,
|
||||||||
|
2007
|
2006
|
|||||||
|
ASSETS
|
||||||||
|
Current
assets
|
$ | 4,530 | $ | 7,263 | ||||
|
Investment
in subsidiaries
|
919,186 | 784,550 | ||||||
|
Intercompany
receivable
|
1,256,550 | 1,044,820 | ||||||
|
TOTAL
|
$ | 2,180,266 | $ | 1,836,633 | ||||
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
||||||||
|
Current
liabilities
|
$ | 2,587 | $ | 3,565 | ||||
|
Long-term
debt
|
617,497 | 616,889 | ||||||
|
Other
long-term liabilities
|
23,240 | 23,607 | ||||||
|
Stockholders’
equity
|
1,536,942 | 1,192,572 | ||||||
|
TOTAL
|
$ | 2,180,266 | $ | 1,836,633 | ||||
CONDENSED
STATEMENTS OF OPERATIONS
(In
thousands)
|
Year
Ended December 31,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
Operating
expenses:
|
||||||||||||
|
General
and administrative
|
$ | 4,290 | $ | 3,367 | $ | 2,861 | ||||||
|
Interest
expense
|
2,112 | 2,671 | 3,269 | |||||||||
|
Equity
in earnings of subsidiaries
|
134,636 | 160,410 | 125,733 | |||||||||
|
Income
before income taxes
|
128,234 | 154,372 | 119,603 | |||||||||
|
Income
tax benefit
|
(2,366 | ) | (1,992 | ) | (2,319 | ) | ||||||
|
Net
income
|
$ | 130,600 | $ | 156,364 | $ | 121,922 | ||||||
|
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,
|
||||||||||||
|
2007
|
2006
|
2005
|
||||||||||
|
Cash
flows provided by (used in) operating activities
|
$ | 4,633 | $ | (846 | ) | $ | (635 | ) | ||||
|
Cash
flows from investing activities
|
- | - | - | |||||||||
|
Cash
flows from financing activities:
|
||||||||||||
|
Issuance
of common stock
|
210,394 | - | 277,117 | |||||||||
|
Issuance
of Senior Subordinated Notes
|
- | - | 466,715 | |||||||||
|
Intercompany
receivable
|
(212,053 | ) | 4,233 | (735,192 | ) | |||||||
|
Other
financing activities
|
(2,974 | ) | (3,387 | ) | (8,005 | ) | ||||||
|
Net
cash (used in) provided by financing activities
|
(4,633 | ) | 846 | 635 | ||||||||
|
Net
change in cash and cash equivalents
|
- | - | - | |||||||||
|
Cash
and cash equivalents:
|
||||||||||||
|
Beginning
of period
|
- | - | - | |||||||||
|
End
of period
|
$ | - | $ | - | $ | - | ||||||
|
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 2007 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 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.
Schedule
I
|
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, 2007 and 2006 (in thousands):
|
December
31,
|
||||||||
|
2007
|
2006
|
|||||||
|
Long-term
debt:
|
||||||||
|
7.25%
Senior Subordinated Notes due 2012, net of unamortized debt discount of
$537 and $687, respectively
|
$ | 149,463 | $ | 149,313 | ||||
|
7.25%
Senior Subordinated Notes due 2013, net of unamortized debt discount of
$1,966 and $2,424, respectively
|
218,034 | 217,576 | ||||||
|
7%
Senior Subordinated Notes due 2014
|
250,000 | 250,000 | ||||||
|
Other
long-term liabilities:
|
||||||||
|
Tax
sharing liability
|
23,070 | 23,607 | ||||||
|
Other
|
170 | - | ||||||
|
Total
long-term debt and other long-term liabilities
|
$ | 640,737 | $ | 640,496 | ||||
Scheduled
maturities of the Parent Company’s long-term debt and other long-term
liabilities as of December 31, 2007, were as follows (in
thousands):
|
2008
|
2009
|
2010
|
2011
|
2012
|
Thereafter
|
Total
|
||||||||||||||||||||
| $ | 2,587 | $ | 2,302 | $ | 2,105 | $ | 1,934 | $ | 151,765 | $ | 480,044 | $ | 640,737 | |||||||||||||
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.
******
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 28th day of
February, 2008.
|
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
28, 2008
|
|
/s/ Michael J.
Stevens
Michael
J. Stevens
|
Vice
President and
Chief
Financial Officer
(Principal
Financial Officer)
|
February
28, 2008
|
|
/s/ Brent P.
Jensen
Brent
P. Jensen
|
Controller
and Treasurer
(Principal
Accounting Officer)
|
February
28, 2008
|
|
/s/ Thomas L.
Aller
Thomas
L. Aller
|
Director
|
February
28, 2008
|
|
/s/ D. Sherwin
Artus
D.
Sherwin Artus
|
Director
|
February
28, 2008
|
|
/s/ Thomas P.
Briggs
Thomas
P. Briggs
|
Director
|
February
28, 2008
|
|
/s/ William N.
Hahne
William
N. Hahne
|
Director
|
February
28, 2008
|
|
/s/ Graydon D.
Hubbard
Graydon
D. Hubbard
|
Director
|
February
28, 2008
|
|
/s/ Palmer L.
Moe
Palmer
L. Moe
|
Director
|
February
28, 2008
|
|
/s/ Kenneth R.
Whiting
Kenneth
R. Whiting
|
Director
|
February
28, 2008
|
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 Current Report
on Form 8-K dated February 23, 2006 (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
J.P. Morgan Trust Company, National Association [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 JPMorgan Chase Bank [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 JP Morgan Trust Company, National
Association [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 JP Morgan Trust
Company, National Association [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)].
|
|
(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 [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)].
|
|
(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)].
|
|
(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)].
|
|
(10.6)*
|
Whiting
Petroleum Corporation Production Participation Plan, as amended and
restated February 4, 2008.
|
|
(10.7)
|
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)].
|
|
(10.8)*
|
Summary
of Non-Employee Director Compensation for Whiting Petroleum Corporation.
[Incorporated by reference to Exhibit 10.1 to Whiting Petroleum
Corporation’s Quarterly Report on Form 10-Q for the quarter ended
September 30, 2007 (File No. 001-31899)].
|
|
(10.9)*
|
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)].
|
|
(10.10)*
|
Amended
and Restated Production Participation Plan Supplemental Payment Agreement,
dated January 14, 2008, between Whiting Petroleum Corporation and J.
Douglas Lang.
|
|
(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.
|
|
(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 2008 Annual Meeting of Stockholders, to be filed within
120 days of December 31, 2007 [To be filed with the Securities and
Exchange Commission under Regulation 14A within 120 days after December
31, 2007; except to the extent specifically incorporated by reference, the
Proxy Statement for the 2008 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].
|
____________________
* A
management contract or compensatory plan or arrangement.
107