Attached files
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
|
[X]
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ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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For the
fiscal year ended December 31, 2009
or
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[ ]
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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For the
transition period from _______________ to _______________
Commission
file number: 001-31899
Whiting Petroleum
Corporation
(Exact
name of registrant as specified in its charter)
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Delaware
(State
or other jurisdiction
of
incorporation or organization)
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20-0098515
(I.R.S.
Employer
Identification
No.)
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1700
Broadway, Suite 2300
Denver, Colorado
(Address
of principal executive offices)
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80290-2300
(Zip
code)
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Registrant’s
telephone number, including area code: (303) 837-1661
Securities
registered pursuant to Section 12(b) of the Act:
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6.25%
Convertible Perpetual Preferred Stock, $0.001 par value
Common
Stock, $0.001 par value
Preferred
Share Purchase Rights
(Title
of Class)
|
New
York Stock Exchange
New
York Stock Exchange
New
York Stock Exchange
(Name
of each exchange on which
registered)
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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.YesT No £
Indicate
by check mark if the Registrant is not required to file reports pursuant to
Section 13 or 15(d) of the Securities Act.Yes£ No T
Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days. YesT No£
Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such
files). Yes £
No £
Indicate
by check mark 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
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Accelerated
filer £
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Non-accelerated
filer£
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Smaller
reporting company £
|
Indicate
by check mark whether the Registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes£ No T
Aggregate
market value of the voting common stock held by non-affiliates of the registrant
at June 30, 2009: $1,794,225,805.
Number of
shares of the registrant’s common stock outstanding at February 15,
2010: 50,843,843 shares.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions
of the Proxy Statement for the 2010 Annual Meeting of Stockholders are
incorporated by reference into Part III.
CERTAIN DEFINITIONS
Unless
the context otherwise requires, the terms “we,” “us,” “our” or “ours” when used
in this Annual Report on Form 10-K refer to Whiting Petroleum Corporation,
together with its consolidated subsidiaries. When the context
requires, we refer to these entities separately.
We have
included below the definitions for certain terms used in this Annual Report on
Form 10-K:
“3-D seismic” Geophysical
data that depict the subsurface strata in three dimensions. 3-D
seismic typically provides a more detailed and accurate interpretation of the
subsurface strata than 2-D, or two-dimensional, seismic.
“Bbl” One stock tank barrel,
or 42 U.S. gallons liquid volume, used in this report in reference to oil and
other liquid hydrocarbons.
“Bcf” One billion cubic feet
of natural gas.
“Bcfe” One billion cubic feet
of natural gas equivalent.
“BOE” One stock tank barrel
equivalent of oil, calculated by converting natural gas volumes to equivalent
oil barrels at a ratio of six Mcf to one Bbl of oil.
“CO2 flood” A tertiary recovery
method in which CO2 is
injected into a reservoir to enhance hydrocarbon recovery.
“completion” The installation
of permanent equipment for the production of crude oil or natural gas, or in the
case of a dry hole, the reporting of abandonment to the appropriate
agency.
“deterministic method” The
method of estimating reserves or resources using a single value for each
parameter (from the geoscience, engineering or economic data) in the reserves
calculation.
“farmout” An assignment of an
interest in a drilling location and related acreage conditioned upon the
drilling of a well on that location.
“FASB” Financial Accounting
Standards Board.
“FASB ASC” The Financial
Accounting Standards Board Accounting Standards Codification.
“flush production” The high
rate of flow from a well during initial production immediately after it is
brought on-line.
“GAAP” Generally accepted
accounting principles in the United States of America.
“MBbl” One thousand barrels
of oil or other liquid hydrocarbons.
“MBOE” One thousand
BOE.
“MBOE/d” One MBOE per
day.
“Mcf” One thousand cubic feet
of natural gas.
“Mcfe” One thousand cubic
feet of natural gas equivalent.
“MMBbl” One million
Bbl.
“MMBOE” One million
BOE.
“MMBtu” One million British
Thermal Units.
“MMcf” One million cubic feet
of natural gas.
“MMcf/d” One MMcf per
day.
“MMcfe” One million cubic
feet of natural gas equivalent.
“MMcfe/d” One MMcfe per
day.
“PDNP” Proved developed
nonproducing reserves.
“PDP” Proved developed
producing reserves.
“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.
“possible reserves” Those
reserves that are less certain to be recovered than probable
reserves.
“pre-tax PV10%” The present
value of estimated future revenues to be generated from the production of proved
reserves calculated in accordance with the guidelines of the Securities and
Exchange Commission (“SEC”), net of estimated lease operating expense,
production taxes and future development costs, using price and costs as of the
date of estimation without future escalation, without giving effect to
non-property related expenses such as general and administrative expenses, debt
service and depreciation, depletion and amortization, or Federal income taxes
and discounted using an annual discount rate of 10%. Pre-tax PV10%
may be considered a non-GAAP financial measure as defined by the
SEC. See footnote (1) to the Proved Reserves table in Item 1.
“Business” of this Annual Report on Form 10-K for more information.
“probable reserves” Those
reserves that are less certain to be recovered than proved reserves but which,
together with proved reserves, are as likely as not to be
recovered.
“proved developed reserves”
Proved reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods or in which the cost of the required
equipment is relatively minor compared to the cost of a new well.
“proved reserves” Those
reserves which, by analysis of geoscience and engineering data, can be estimated
with reasonable certainty to be economically producible—from a given date
forward, from known reservoirs and under existing economic conditions, operating
methods and government regulations—prior to the time at which contracts
providing the right to operate expire, unless evidence indicates that renewal is
reasonably certain, regardless of whether deterministic or probabilistic methods
are used for the estimation. The project to extract the hydrocarbons
must have commenced, or the operator must be reasonably certain that it will
commence the project, within a reasonable time.
The area
of the reservoir considered as proved includes all of the
following:
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a.
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The
area identified by drilling and limited by fluid contacts, if any,
and
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b.
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Adjacent
undrilled portions of the reservoir that can, with reasonable certainty,
be judged to be continuous with it and to contain economically producible
oil or gas on the basis of available geoscience and engineering
data.
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Reserves
that can be produced economically through application of improved recovery
techniques (including, but not limited to, fluid injection) are included in the
proved classification when both of the following occur:
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a.
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Successful
testing by a pilot project in an area of the reservoir with properties no
more favorable than in the reservoir as a whole, the operation of an
installed program in the reservoir or an analogous reservoir, or other
evidence using reliable technology establishes the reasonable certainty of
the engineering analysis on which the project or program was based,
and
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b.
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The
project has been approved for development by all necessary parties and
entities, including governmental
entities.
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Existing
economic conditions include prices and costs at which economic producibility
from a reservoir is to be determined. The price shall be the average
price during the 12-month period before the ending date of the period covered by
the report, determined as an unweighted arithmetic average of the
first-day-of-the-month price for each month within such period, unless prices
are defined by contractual arrangements, excluding escalations based upon future
conditions.
“proved undeveloped reserves”
Proved reserves that are expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major expenditure is required
for recompletion. Reserves on undrilled acreage shall be limited to
those directly offsetting development spacing areas that are reasonably certain
of production when drilled, unless evidence using reliable technology exists
that establishes reasonable certainty of economic producibility at greater
distances. Undrilled locations can be classified as having
undeveloped reserves only if a development plan has been adopted indicating that
they are schedule to be drilled within five years, unless specific circumstances
justify a longer time. Under no circumstances shall estimates for
proved undeveloped reserves be attributable to any acreage for which an
application of fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective by actual
projects in the same reservoir or an analogous reservoir, or by other evidence
using reliable technology establishing reasonable certainty.
“PUD” Proved undeveloped
reserves.
“reasonable certainty” If
deterministic methods are used, reasonable certainty means a high degree of
confidence that the quantities will be recovered. If probabilistic
methods are used, there should be at least a 90 percent probability that the
quantities actually recovered will equal or exceed the estimate. A
high degree of confidence exists if the quantity is much more likely to be
achieved than not, and, as changes due to increased availability of geoscience
(geological, geophysical and geochemical) engineering, and economic data are
made to estimated ultimate recovery with time, reasonably certain estimated
ultimate recovery is much more likely to increase or remain constant than to
decrease.
“reserves” Estimated
remaining quantities of oil and gas and related substances anticipated to be
economically producible, as of a given date, by application of development
projects to known accumulations. In addition, there must exist, or
there must be a reasonable expectation that there will exist, the legal right to
produce or a revenue interest in the production, installed means of delivering
oil and gas or related substances to market, and all permits and financing
required to implement the project.
“reservoir” A porous and
permeable underground formation containing a natural accumulation of producible
crude oil and/or natural gas that is confined by impermeable rock or water
barriers and is individual and separate from other reservoirs.
“resource
play”
Refers to drilling programs targeted at regionally distributed oil or natural
gas accumulations. Successful exploitation of these reservoirs is
dependent upon new technologies such as horizontal drilling and multi-stage
fracture stimulation to access large rock volumes in order to produce economic
quantities of oil or natural gas.
“working interest” The
interest in a crude oil and natural gas property (normally a leasehold interest)
that gives the owner the right to drill, produce and conduct operations on the
property and a share of production, subject to all royalties, overriding
royalties and other burdens and to all costs of exploration, development and
operations and all risks in connection therewith.
PART
I
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Item 1.
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Business
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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, 2009, our estimated proved reserves
totaled 275.0 MMBOE, representing a 15% increase in our proved reserves since
December 31, 2008. Our 2009 average daily production was 55.5
MBOE/d and implies an average reserve life of approximately 13.6
years.
The
following table summarizes our estimated proved reserves by core area, the
corresponding pre-tax PV10% value and our standardized measure of discounted
future net cash flows as of December 31, 2009, and our December 2009 average
daily production:
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Proved
Reserves(1)
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||||||||||||||||||||||||
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Core
Area
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Oil(2)
(MMBbl)
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Natural
Gas (Bcf)
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Total
(MMBOE)
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%
Oil(2)
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Pre-Tax
PV10% Value(3)
(In
millions)
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December
2009 Average Daily Production (MBOE/d)
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||||||||||||||||||
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Permian
Basin
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112.3 | 66.2 | 123.3 | 91 | % | $ | 901.3 | 11.7 | ||||||||||||||||
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Rocky
Mountains
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70.2 | 159.4 | 96.8 | 73 | % | 1,266.3 | 30.3 | |||||||||||||||||
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Mid-Continent
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36.6 | 15.2 | 39.1 | 94 | % | 581.3 | 9.3 | |||||||||||||||||
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Gulf
Coast
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2.3 | 36.6 | 8.4 | 27 | % | 69.6 | 3.0 | |||||||||||||||||
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Michigan
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2.4 | 30.0 | 7.4 | 32 | % | 57.2 | 2.3 | |||||||||||||||||
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Total
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223.8 | 307.4 | 275.0 | 81 | % | $ | 2,875.7 | 56.6 | ||||||||||||||||
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Discounted
Future Income Taxes
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- | - | - | - | (532.2 | ) | - | |||||||||||||||||
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Standardized
Measure of Discounted Future Net Cash Flows
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- | - | - | - | $ | 2,343.5 | - | |||||||||||||||||
_____________________
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(1)
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Oil
and gas reserve quantities and related discounted future net cash flows
have been derived from oil and gas prices calculated using an average of
the first-day-of-the month price for each month within the most recent 12
months, pursuant to current SEC and FASB
guidelines.
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(2)
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Oil
includes natural gas liquids.
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(3)
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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 proved 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 proved oil and natural gas
reserves.
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While
historically we have grown through acquisitions, we are increasingly focused on
a balance between exploration and development programs and continuing to
selectively pursue acquisitions that complement our existing core
properties. We believe that our significant drilling inventory,
combined with our operating experience and cost structure, provides us with
meaningful organic growth opportunities.
Our
growth plan is centered on the following activities:
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•
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pursuing
the development of projects that we believe will generate attractive rates
of return;
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•
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maintaining
a balanced portfolio of lower risk, long-lived oil and gas properties that
provide stable cash flows;
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•
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seeking
property acquisitions that complement our core
areas; and
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•
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allocating
a portion of our capital budget to leasing and exploring prospect
areas.
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During
2009, we incurred $577.9 million in acquisition, development and exploration
activities, including $479.8 million for the drilling of 145 gross (56.2 net)
wells. Of these new wells, 51.1 (net) resulted in productive
completions and 5.1 (net) were unsuccessful, yielding a 91% success
rate. Our current 2010 capital budget for exploration and development
expenditures is $830.0 million, which we expect to fund with net cash provided
by our operating activities. Our 2010 capital budget of $830.0
million represents a substantial increase from the $479.8 million incurred on
exploration and development expenditures during 2009. This increased
capital budget is in response to the higher oil and natural gas prices
experienced during the second half of 2009 and continuing into the first part of
2010.
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.
2009 Acquisitions. During
2009, we acquired additional royalty and overriding royalty interests in the
North Ward Estes field and various other fields in the Permian Basin in two
separate transactions with private owners. Also included in these
transactions were contractual rights, including an option to participate for an
aggregate 10% working interest and right to back in after payout for an
additional aggregate 15% working interest in the development of deeper pay zones
on acreage under and adjoining the North Ward Estes field.
We
completed the first additional royalty and overriding interests acquisition in
November 2009, with a purchase price of $38.7 million and an effective date of
October 1, 2009. The average daily net production attributable to
this transaction was approximately 0.3 MBOE/d in September
2009. Estimated proved reserves attributable to the acquired
interests are 2.2 MMBOE, resulting in an acquisition price of $17.59 per
BOE. Reserves attributable to royalty and overriding royalty
interests are not burdened by operating expenses or any additional capital
costs, including CO2 costs,
which are paid by the working interest owners.
We
completed the second additional royalty and overriding interests acquisition in
December 2009, with a purchase price of $27.4 million and an effective date of
November 1, 2009. The average daily net production attributable to
this transaction was approximately 0.2 MBOE/d in September
2009. Estimated proved reserves attributable to the acquired
interests are 1.6 MMBOE, resulting in an acquisition price of $17.13 per
BOE.
In
aggregate, the two acquisitions in the North Ward Estes field represent 3.8
MMBOE of proved reserves at an acquisition price of $66.1 million, or $17.39 per
BOE. We funded these acquisitions primarily with net cash provided by
our operating activities.
2009 Participation
Agreement. In June 2009, we entered into a participation
agreement with a privately held independent oil company covering twenty-five
1,280-acre units and one 640-acre unit located primarily in the western portion
of the Sanish field in Mountrail County, North Dakota. Under the
terms of the agreement, the private company agreed to pay 65% of our net
drilling and well completion costs to receive 50% of our working interest and
net revenue interest in the first and second wells planned for each of the
units. Pursuant to the agreement, we will remain the operator for
each unit.
At the
closing of the agreement, the private company paid us $107.3 million,
representing $6.4 million for acreage costs, $65.8 million for 65% of our cost
in 18 wells drilled or drilling and $35.1 million for a 50% interest in our
Robinson Lake gas plant and oil and gas gathering system. We used
these proceeds to repay a portion of the debt outstanding under our credit
agreement.
2008 Acquisitions. In May 2008, we acquired
interests in 31 producing gas wells, development acreage and gas gathering and
processing facilities on approximately 22,000 gross (11,500 net) acres in the
Flat Rock field in Uintah County, Utah for an aggregate acquisition price of
$365.0 million. After allocating $79.5 million of the purchase price
to unproved properties, the resulting acquisition cost is $2.48 per
Mcfe. Of the estimated 115.2 Bcfe of proved reserves acquired as of
the January 1, 2008 acquisition effective date, 98% are natural gas and 22% are
proved developed producing. The average daily net production from the
properties was 17.8 MMcfe/d as of the acquisition effective date. We
funded the acquisition with borrowings under our credit agreement.
2008
Divestitures. On April 30, 2008, we completed an initial
public offering of units of beneficial interest in Whiting USA Trust I (the
“Trust”), selling 11,677,500 Trust units at $20.00 per Trust unit, providing net
proceeds of $193.8 million after underwriters’ fees, offering expenses and
post-close adjustments. We used the net offering proceeds to repay a
portion of the debt outstanding under our credit agreement. The net
proceeds from the sale of Trust units to the public resulted in a deferred gain
on sale of $100.2 million. Immediately prior to the closing of the
offering, we conveyed a term net profits interest in certain of our oil and gas
properties to the Trust in exchange for 13,863,889 Trust units. We
retained 15.8%, or 2,186,389 Trust units, of the total Trust units issued and
outstanding.
The net
profits interest entitles the Trust to receive 90% of the net proceeds from the
sale of oil and natural gas production from the underlying
properties. The net profits interest will terminate at the time when
9.11 MMBOE have been produced and sold from the underlying
properties. This is the equivalent of 8.2 MMBOE in respect of the
Trust’s right to receive 90% of the net proceeds from such production pursuant
to the net profits interest, and these reserve quantities are projected to be
produced by August 31, 2018, based on the reserve report for the underlying
properties as of December 31, 2009. The conveyance of the net
profits interest to the Trust consisted entirely of proved developed producing
reserves of 8.2 MMBOE, as of the January 1, 2008 effective date,
representing 3.3% of our proved reserves as of December 31, 2007, and
10.0%, or 4.2 MBOE/d, of our March 2008 average daily net
production. After netting our ownership of 2,186,389 Trust units,
third-party public Trust unit holders receive 6.9 MMBOE of proved producing
reserves, or 2.75% of our total year-end 2007 proved reserves, and 7.4%, or 3.1
MBOE/d, of our March 2008 average daily net production.
Business
Strategy
Our goal
is to generate meaningful growth in our net asset value per share for proved
reserves by acquisition, exploitation and exploration of oil and gas projects
with attractive rates of return on capital employed. To date, we have
pursued this goal through both the acquisition of reserves and continued field
development in our core areas. Because of our extensive property
base, we are pursuing several economically attractive oil and gas opportunities
to exploit and develop properties as well as explore our acreage positions for
additional production growth and proved reserves. Specifically, we
have focused, and plan to continue to focus, on the following:
Pursuing High-Return Organic Reserve
Additions. The development of large resource plays such as our
Williston Basin and Piceance Basin projects has become one of our central
objectives. We have assembled approximately 118,000 gross (69,600
net) acres on the eastern side of the Williston Basin in North Dakota in an
active oil development play at our Sanish field area, where the Middle Bakken
reservoir is oil productive. As of February 15, 2010, we have
participated in the drilling of 123 successful wells (88 operated) in our Sanish
field acreage that had a combined net production rate of 12.6 MBOE/d during
December 2009.
As of
December 31, 2009, we have assembled 213,500 gross (127,800 net) acres in the
Lewis & Clark Prospect in Golden Valley and Billings Counties, North
Dakota. Subsequent to year-end we assembled additional acreage, primarily
in Stark County, North Dakota, which brings our total acreage position in the
Lewis & Clark area to 320,000 gross (202,400 net) acres. Through
the end of 2009 we have drilled three horizontal wells into the Three Forks
reservoir at Lewis & Clark and are very encouraged with the results.
We intend to further delineate this area with additional drilling in
2010.
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 (Mesaverde formation) to be gas
productive at our Sulphur Creek field area and the Mesaverde formation to be gas
productive at our Jimmy Gulch prospect area.
In May
2008 we acquired interests in the Flat Rock Gas field in Uintah County,
Utah. The main production in the Flat Rock field is from the Entrada
formation. In our Piceance projects and at the Flat Rock Gas field we
have entered into 5-year fixed-price gas contracts at over $5.00 per Mcf to
enhance the economics of further drilling and development in this area and
thereby maintain the economic viability of this production.
Developing and Exploiting Existing
Properties. Our existing property base and our acquisitions
over the past five years have provided us with numerous low-risk opportunities
for exploitation and development drilling. As of December 31, 2009,
we have identified a drilling inventory of over 1,400 gross wells that we
believe will add substantial production over the next five years. Our
drilling inventory consists of the development of our proved and non-proved
reserves on which we have spent significant time evaluating the costs and
expected results. Additionally, we have several opportunities to
apply and expand enhanced recovery techniques that we expect will increase
proved reserves and extend the productive lives of our mature
fields. In 2005, we acquired two large oil fields, the Postle field,
located in the Oklahoma Panhandle, and the North Ward Estes field, located in
the Permian Basin of West Texas. We have experienced and anticipate
further significant production increases in these fields over the next four to
seven years through the use of secondary and tertiary recovery
techniques. In these fields, we are actively injecting water and
CO2 and executing extensive
re-development, drilling and completion operations, as well as enhanced gas
handling and treating capability.
Growing Through Accretive
Acquisitions. From 2004 to 2009, we completed 15 separate
acquisitions of producing properties for estimated proved reserves of 230.7
MMBOE, as of the effective dates of the acquisitions. Our experienced
team of management, land, engineering and geoscience professionals has developed
and refined an acquisition program designed to increase reserves and complement
our existing properties, including identifying and evaluating acquisition
opportunities, negotiating and closing purchases and managing acquired
properties. We intend to selectively pursue the acquisition of
properties complementary to our core operating areas.
Disciplined Financial
Approach. Our goal is to remain financially strong, yet
flexible, through the prudent management of our balance sheet and active
management of commodity price volatility. We have historically funded
our acquisitions and growth activity through a combination of equity and debt
issuances, bank borrowings and internally generated cash flow, as appropriate,
to maintain our strong financial position. From time to time, we
monetize non-core properties and use the net proceeds from these asset sales to
repay debt under our credit agreement. To support cash flow
generation on our existing properties and help ensure expected cash flows from
acquired properties, we periodically enter into derivative
contracts. Typically, we use costless collars and fixed price gas
contracts to provide an attractive base commodity price
level.
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, 2009, we had interests in 9,616 gross
(3,719 net) productive wells across approximately 1,059,500 gross (545,300 net)
developed acres in our five core geographical areas. We believe this
geographic mix of properties and organic drilling opportunities, combined with
our continuing business strategy of acquiring and exploiting properties in these
areas, presents us with multiple opportunities in executing our strategy because
we are not dependent on any particular producing regions or geological
formations. Our proved reserve life is approximately 13.6 years based
on year-end 2009 proved reserves and 2009 production.
Experienced Management
Team. Our management team averages 26 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 29 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
6,370 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 21 years
of expertise managing CO2 floods. This
provides us with the ability to pursue other CO2 flood
targets and employ this technology to add reserves to our
portfolio. This commitment to technology has increased the
productivity and efficiency of our field operations and development
activities.
In June
2009, we implemented a “Drill Well on Paper” (“DWOP”) process on our drilling
program in the Sanish field in North Dakota. This process involves
everyone who partakes in the drilling of a well and analyzes what synergies
exist to reduce the cost to drill a well. The first step in the process is
to determine the time required to drill a well assuming everything went right
(drill the well on paper). The next steps are how to apply this to drill
the perfect well in the field. Prior to starting the project the number of
days from well spud to total depth averaged 38 days. As of the end of
February 2010, we have reduced drilling time by 11 days to an average of 27
days, resulting in meaningful cost reductions. We will expand this program
to all of our Sanish field rigs in 2010.
Proved,
Probable and Possible Reserves
Our
estimated proved, probable and possible reserves as of December 31, 2009 are
summarized in the table below. See “Reserves” in Item 2 of this
Annual Report on Form 10-K for information relating to the uncertainties
surrounding these reserve categories.
|
Permian
Basin:
|
Oil
(MMBbl)
|
Natural
Gas
(Bcf)
|
Total
(MMBOE)
|
%
of Total
Proved
|
Future
Capital Expenditures
(In
millions)
|
|||||||||||||||
|
PDP
|
36.3 | 24.8 | 40.4 | 33 | % | |||||||||||||||
|
PDNP
|
25.4 | 11.9 | 27.4 | 22 | % | |||||||||||||||
|
PUD
|
50.6 | 29.5 | 55.5 | 45 | % | |||||||||||||||
|
Total
Proved
|
112.3 | 66.2 | 123.3 | 100 | % | $ | 921.6 | |||||||||||||
|
Total
Probable
|
41.4 | 50.2 | 49.7 | $ | 338.0 | |||||||||||||||
|
Total
Possible
|
89.8 | 13.5 | 92.1 | $ | 433.0 | |||||||||||||||
|
Rocky
Mountains:
|
||||||||||||||||||||
|
PDP
|
48.4 | 74.8 | 60.9 | 63 | % | |||||||||||||||
|
PDNP
|
0.5 | 1.9 | 0.8 | 1 | % | |||||||||||||||
|
PUD
|
21.3 | 82.7 | 35.1 | 36 | % | |||||||||||||||
|
Total
Proved
|
70.2 | 159.4 | 96.8 | 100 | % | $ | 333.1 | |||||||||||||
|
Total
Probable
|
12.0 | 107.1 | 29.9 | $ | 357.5 | |||||||||||||||
|
Total
Possible
|
69.9 | 130.7 | 91.7 | $ | 828.8 | |||||||||||||||
|
Mid-Continent:
|
||||||||||||||||||||
|
PDP
|
28.6 | 13.1 | 30.8 | 79 | % | |||||||||||||||
|
PDNP
|
1.5 | 0.5 | 1.6 | 4 | % | |||||||||||||||
|
PUD
|
6.5 | 1.6 | 6.7 | 17 | % | |||||||||||||||
|
Total
Proved
|
36.6 | 15.2 | 39.1 | 100 | % | $ | 107.7 | |||||||||||||
|
Total
Probable
|
2.3 | 0.0 | 2.3 | $ | 40.3 | |||||||||||||||
|
Total
Possible
|
2.7 | 0.8 | 2.8 | $ | 33.6 | |||||||||||||||
|
Gulf
Coast:
|
||||||||||||||||||||
|
PDP
|
1.7 | 18.7 | 4.8 | 57 | % | |||||||||||||||
|
PDNP
|
0.3 | 3.8 | 0.9 | 11 | % | |||||||||||||||
|
PUD
|
0.3 | 14.1 | 2.7 | 32 | % | |||||||||||||||
|
Total
Proved
|
2.3 | 36.6 | 8.4 | 100 | % | $ | 37.0 | |||||||||||||
|
Total
Probable
|
1.6 | 22.4 | 5.3 | $ | 56.5 | |||||||||||||||
|
Total
Possible
|
3.5 | 30.4 | 8.6 | $ | 116.5 | |||||||||||||||
|
Michigan:
|
||||||||||||||||||||
|
PDP
|
1.1 | 25.5 | 5.4 | 73 | % | |||||||||||||||
|
PDNP
|
1.0 | 3.8 | 1.6 | 22 | % | |||||||||||||||
|
PUD
|
0.3 | 0.7 | 0.4 | 5 | % | |||||||||||||||
|
Total
Proved
|
2.4 | 30.0 | 7.4 | 100 | % | $ | 6.3 | |||||||||||||
|
Total
Probable
|
1.5 | 2.2 | 1.9 | $ | 13.4 | |||||||||||||||
|
Total
Possible
|
0.7 | 9.5 | 2.3 | $ | 27.0 | |||||||||||||||
|
Total
Company:
|
||||||||||||||||||||
|
PDP
|
116.1 | 156.9 | 142.3 | 52 | % | |||||||||||||||
|
PDNP
|
28.7 | 21.9 | 32.3 | 12 | % | |||||||||||||||
|
PUD
|
79.0 | 128.6 | 100.4 | 36 | % | |||||||||||||||
|
Total
Proved
|
223.8 | 307.4 | 275.0 | 100 | % | $ | 1,405.7 | |||||||||||||
|
Total
Probable
|
58.8 | 181.9 | 89.1 | $ | 805.7 | |||||||||||||||
|
Total
Possible
|
166.6 | 184.9 | 197.5 | $ | 1,438.9 | |||||||||||||||
Marketing
and Major Customers
We
principally sell our oil and gas production to end users, marketers and other
purchasers that have access to nearby pipeline facilities. In areas
where there is no practical access to pipelines, oil is trucked to storage
facilities. During 2009, sales to Shell Western E&P, Inc., Plains
Marketing LP and EOG Resources, Inc. accounted for 18%, 15% and 13%,
respectively, of our total oil and natural gas sales. During 2008,
sales to Plains Marketing LP and Valero Energy Corporation accounted for 15% and
14%, respectively, of our total oil and natural gas sales. During
2007, sales to Valero Energy Corporation and Plains Marketing LP accounted for
14% and 13%, respectively, of our total oil and natural gas sales.
Title
to Properties
Our
properties are subject to customary royalty interests, liens under indebtedness,
liens incident to operating agreements, liens for current taxes and other
burdens, including other mineral encumbrances and restrictions. Our
credit agreement is also secured by a first lien on substantially all of our
assets. We do not believe that any of these burdens materially
interfere with the use of our properties in the operation of our
business.
We
believe that we have satisfactory title to or rights in all of our producing
properties. As is customary in the oil and gas industry, minimal
investigation of title is made at the time of acquisition of undeveloped
properties. In most cases, we investigate title and obtain title
opinions from counsel only when we acquire producing properties or before
commencement of drilling operations.
Competition
We
operate in a highly competitive environment for acquiring properties, marketing
oil and natural gas and securing trained personnel. Many of our
competitors possess and employ financial, technical and personnel resources
substantially greater than ours, which can be particularly important in the
areas in which we operate. Those companies may be able to pay more
for productive oil and gas properties and exploratory prospects and to evaluate,
bid for and purchase a greater number of properties and prospects than our
financial or personnel resources permit. Our ability to acquire
additional prospects and to find and develop reserves in the future will depend
on our ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. Also, there is
substantial competition for capital available for investment in the oil and gas
industry.
Regulation
Regulation
of Transportation, Sale and Gathering of Natural Gas
The
Federal Energy Regulatory Commission (“FERC”) regulates the transportation, and
to a lesser extent sale for resale, of natural gas in interstate commerce
pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978
and regulations issued under those Acts. In 1989, however, Congress
enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining
price and nonprice controls affecting wellhead sales of natural gas, effective
January 1, 1993. While sales by producers of natural gas and all
sales of crude oil, condensate and natural gas liquids can currently be made at
uncontrolled market prices, in the future Congress could reenact price controls
or enact other legislation with detrimental impact on many aspects of our
business.
Our
natural gas sales are affected by the availability, terms and cost of
transportation. The price and terms of access to pipeline
transportation and underground storage are subject to extensive federal and
state regulation. From 1985 to the present, several major regulatory
changes have been implemented by Congress and the FERC that affect the economics
of natural gas production, transportation and sales. In addition, the
FERC is continually proposing and implementing new rules and regulations
affecting those segments of the natural gas industry that remain subject to the
FERC's jurisdiction, most notably interstate natural gas transmission companies
and certain underground storage facilities. These initiatives may
also affect the intrastate transportation of natural gas under certain
circumstances. The stated purpose of many of these regulatory changes
is to promote competition among the various sectors of the natural gas industry
by making natural gas transportation more accessible to natural gas buyers and
sellers on an open and non-discriminatory basis.
The FERC
implemented The Outer Continental Shelf Lands Act pertaining to transportation
and pipeline issues, which requires that all pipelines operating on or across
the outer continental shelf provide open access and non-discriminatory
transportation service. One of the FERC’s principal goals in carrying
out this Act’s mandate is to increase transparency in the market to provide
producers and shippers on the outer continental shelf with greater assurance of
open access services on pipelines located on the outer continental shelf and
non-discriminatory rates and conditions of service on such
pipelines.
We cannot
accurately predict whether the FERC’s actions will achieve the goal of
increasing competition in markets in which our natural gas is
sold. In addition, many aspects of these regulatory developments have
not become final, but are still pending judicial and final FERC
decisions. Regulations implemented by the FERC in recent years could
result in an increase in the cost of transportation service on certain petroleum
product pipelines. The natural gas industry historically has been
very heavily regulated. Therefore, we cannot provide any assurance
that the less stringent regulatory approach recently established by the FERC
will continue. However, we do not believe that any action taken will
affect us in a way that materially differs from the way it affects other natural
gas producers.
Intrastate
natural gas transportation is subject to regulation by state regulatory
agencies. The basis for intrastate regulation of natural gas
transportation and the degree of regulatory oversight and scrutiny given to
intrastate natural gas pipeline rates and services varies from state to
state. Insofar as such regulation within a particular state will
generally affect all intrastate natural gas shippers within the state on a
comparable basis, we believe that the regulation of similarly situated
intrastate natural gas transportation in any of the states in which we operate
and ship natural gas on an intrastate basis will not affect our operations in
any way that is of material difference from those of our
competitors.
Pipeline
safety is regulated at both state and federal levels. After a final
rule was implemented by the U.S. Department of Transportation on March 15, 2006
that defines and puts new safety requirements on gas gathering pipelines, we
have screened our gas gathering lines and are implementing programs to comply
with applicable requirements of this section.
Regulation
of Transportation of Oil
Sales of
crude oil, condensate and natural gas liquids are not currently regulated and
are made at negotiated prices. Nevertheless, Congress could reenact
price controls in the future.
Our crude
oil sales are affected by the availability, terms and cost of
transportation. The transportation of oil in common carrier pipelines
is also subject to rate regulation. The FERC regulates interstate oil
pipeline transportation rates under the Interstate Commerce Act. In
general, interstate oil pipeline rates must be cost-based, although settlement
rates agreed to by all shippers are permitted and market-based rates may be
permitted in certain circumstances. Effective January 1, 1995,
the FERC implemented regulations establishing an indexing system (based on
inflation) for crude oil transportation rates that allowed for an increase or
decrease in the cost of transporting oil to the purchaser. FERC’s
regulations include a methodology for oil pipelines to change their rates
through the use of an index system that establishes ceiling levels for such
rates. The mandatory five year review has revised the methodology for
this index to now be based on Producer Price Index for Finished Goods (PPI-FG),
plus a 1.3% adjustment, for the period July 1, 2006 through July
2011. The regulations provide that each year the Commission will
publish the oil pipeline index after the PPI-FG becomes
available. Intrastate oil pipeline transportation rates are subject
to regulation by state regulatory commissions. The basis for
intrastate oil pipeline regulation, and the degree of regulatory oversight and
scrutiny given to intrastate oil pipeline rates, varies from state to
state. Insofar as effective interstate and intrastate rates are
equally applicable to all comparable shippers, we believe that the regulation of
oil transportation rates will not affect our operations in any way that is of
material difference from those of our competitors.
Further,
interstate and intrastate common carrier oil pipelines must provide service on a
non-discriminatory basis. Under this open access standard, common
carriers must offer service to all shippers requesting service on the same terms
and under the same rates. When oil pipelines operate at full
capacity, access is governed by prorationing provisions set forth in the
pipelines’ published tariffs. Accordingly, we believe that access to
oil pipeline transportation services generally will be available to us to the
same extent as to our competitors.
Regulation
of Production
The
production of oil and gas is subject to regulation under a wide range of local,
state and federal statutes, rules, orders and regulations. Federal,
state and local statutes and regulations require permits for drilling
operations, drilling bonds and periodic report submittals during
operations. All of the states in which we own and operate properties
have regulations governing conservation matters, including provisions for the
unitization or pooling of oil and gas properties, the establishment of maximum
allowable rates of production from oil and gas wells, the regulation of well
spacing, and plugging and abandonment of wells. The effect of these
regulations is to limit the amount of oil and gas that we can produce from our
wells and to limit the number of wells or the locations at which we can drill,
although we can apply for exceptions to such regulations or to have reductions
in well spacing. Moreover, each state generally imposes a production
or severance tax with respect to the production or sale of oil, gas and natural
gas liquids within its jurisdiction.
Some of
our offshore operations are conducted on federal leases that are administered by
Minerals Management Service, or MMS, and Whiting is 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 approval for our lease development and
production plans. 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
or release 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 located 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
unauthorized pollution resulting from our operations. The EPA and
analogous state agencies may delay or refuse the issuance of required permits or
otherwise include onerous or limiting permit conditions that may have a
significant adverse impact on our ability to conduct operations. The
regulatory burden on the oil and gas industry increases the cost of doing
business and consequently affects its profitability.
Changes
in environmental laws and regulations occur frequently, and any changes that
result in more stringent and costly material handling, storage, transport,
disposal or cleanup requirements could materially and adversely affect our
operations and financial position, as well as those of the oil and gas industry
in general. While we believe that we are in substantial compliance
with current applicable environmental laws and regulations and have not
experienced any material adverse effect from compliance with these environmental
requirements, there is no assurance that this trend will continue in the
future.
The
environmental laws and regulations which have the most significant impact on the
oil and gas exploration and production industry are as follows:
Superfund. The
Comprehensive Environmental Response, Compensation and Liability Act of 1980,
also known as “CERCLA” or “Superfund,” and comparable state laws impose
liability, without regard to fault or the legality of the original conduct, on
certain classes of persons that contributed to the release of a “hazardous
substance” into the environment. These persons include the “owner” or
“operator” of a disposal site or sites where a release occurred and entities
that disposed or arranged for the disposal of the hazardous substances found at
the site. Under CERCLA, such persons may be subject to strict, joint
and several liability for the costs of cleaning up the hazardous substances that
have been released into the environment, for damages to natural resources and
for the costs of certain health studies, and it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damage allegedly caused by the hazardous substances released into the
environment. In the course of our ordinary operations, we may
generate material that may fall within CERCLA’s definition of a “hazardous
substance”. Consequently, we may be jointly and severally liable
under CERCLA or comparable state statutes for all or part of the costs required
to clean up sites at which these materials have been disposed or
released.
We
currently own or lease, and in the past have owned or leased, properties that
for many years have been used for the exploration and production of oil and
gas. Although we and our predecessors have used operating and
disposal practices that were standard in the industry at the time, hydrocarbons
or other materials may have been disposed or released on, under, or from the
properties owned or leased by us or on, under, or from other locations where
these hydrocarbons and materials have been taken for disposal. In
addition, many of these owned and leased properties have been operated by third
parties whose management and disposal of hydrocarbons and materials were not
under our control. Similarly, the disposal facilities where discarded
materials are sent are also often operated by third parties whose waste
treatment and disposal practices may not be adequate. While we only
use what we consider to be reputable disposal facilities, we might not know of a
potential problem if the disposal occurred before we acquired the property or
business, and if the problem itself is not discovered until years
later. Our properties, adjacent affected properties, the disposal
sites, and the material itself may be subject to CERCLA and analogous state
laws. Under these laws, we could be required:
|
·
|
to
remove or remediate previously disposed materials, including materials
disposed or released by prior owners or operators or other third
parties;
|
|
·
|
to
clean up contaminated property, including contaminated groundwater;
or
|
|
·
|
to
perform remedial operations to prevent future contamination, including the
plugging and abandonment of wells drilled and left inactive by prior
owners and operators.
|
At this
time, we do not believe that we are a potentially responsible party with respect
to any Superfund site and we have not been notified of any claim, liability or
damages under CERCLA.
Oil Pollution
Act. The Oil Pollution Act of 1990, also known as “OPA,” and
regulations issued under OPA impose strict, joint and several liability on
“responsible parties” for damages resulting from oil spills into or upon
navigable waters, adjoining shorelines or in the exclusive economic zone of the
United States. A “responsible party” includes the owner or operator
of an onshore facility and the lessee or permittee of the area in which an
offshore facility is located. The OPA establishes a liability limit
for onshore facilities of $350.0 million, while the liability limit for offshore
facilities is the payment of all removal costs plus up to $75.0 million in other
damages, but these limits may not apply if a spill is caused by a party’s gross
negligence or willful misconduct; the spill resulted from violation of a federal
safety, construction or operating regulation; or if a party fails to report a
spill or to cooperate fully in a cleanup. The OPA also requires the
lessee or permittee of the offshore area in which a covered offshore facility is
located to establish and maintain evidence of financial responsibility in the
amount of $35.0 million ($10.0 million if the offshore facility is located
landward of the seaward boundary of a state) to cover liabilities related to an
oil spill for which such person is statutorily responsible. The
amount of financial responsibility required under OPA may be increased up to
$150.0 million, depending on the risk represented by the quantity or quality of
oil that is handled by the facility. Any failure to comply with OPA’s
requirements or inadequate cooperation during a spill response action may
subject a responsible party to administrative, civil or criminal enforcement
actions. We believe we are in compliance with all applicable OPA
financial responsibility obligations. Moreover, we are not aware of
any action or event that would subject us to liability under OPA, and we believe
that compliance with OPA’s financial responsibility and other operating
requirements will not have a material adverse effect on us.
Resource Conservation Recovery
Act. The Resource Conservation and Recovery Act, also known as
“RCRA,” is the principal federal statute governing the treatment, storage and
disposal of hazardous wastes. RCRA imposes stringent operating
requirements and liability for failure to meet such requirements on a person who
is either a “generator” or “transporter” of hazardous waste or on an “owner” or
“operator” of a hazardous waste treatment, storage or disposal
facility. RCRA and many state counterparts specifically exclude from
the definition of hazardous waste “drilling fluids, produced waters, and other
wastes associated with the exploration, development, or production of crude oil,
natural gas or geothermal energy”. Therefore, a substantial portion
of RCRA’s requirements do not apply to our operations because we generate
minimal quantities of these hazardous wastes. However, these
exploration and production wastes may be regulated by 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.
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 storm water permitting of
oil and gas construction projects. There are still some state and
federal rules that regulate the discharge of storm water from some oil and gas
construction projects. Costs may be associated with the treatment of
wastewater and/or developing and implementing storm water pollution prevention
plans. The CWA and comparable state statutes provide for civil,
criminal and administrative penalties for unauthorized discharges of oil and
other pollutants and impose liability on parties responsible for those
discharges, for the costs of cleaning up any environmental damage caused by the
release and for natural resource damages resulting from the
release. In Section 40 CFR 112 of the regulations, the EPA
promulgated the Spill Prevention, Control, and Countermeasure, or SPCC,
regulations, which require certain oil containing facilities to prepare plans
and meet construction and operating standards. The SPCC regulations
were revised in 2002 and required the amendment of SPCC plans and the
modification of spill control devices at many facilities. Since 2002
there have been numerous amendments and extensions for compliance with the 2002
rule and subsequent amendments. On June 19, 2009, the EPA extended
the compliance dates until November 10, 2010 to allow the industry to comply
with the 2002 rule and subsequent amendments and the implementation of SPCC
plans. We believe that our operations comply in all material respects
with the requirements of the CWA and state statutes enacted to control water
pollution and that any amendment and subsequent implementation of our SPCC plans
will be performed in a timely manner and not have a significant impact on our
operations.
Clean Air Act. The
Clean Air Act restricts the emission of air pollutants from many sources,
including oil and gas operations. New facilities may be required to
obtain permits before work can begin, and existing facilities may be required to
obtain additional permits and incur capital costs in order to remain in
compliance. More stringent regulations governing emissions of toxic
air pollutants have been developed by the EPA and may increase the costs of
compliance for some facilities. We believe that we are in substantial
compliance with all applicable air emissions regulations and that we hold or
have applied for all permits necessary to our operations.
Global Warming and Climate
Control. Recent scientific studies have suggested that
emissions of certain gases, commonly referred to as “greenhouse gases”,
including carbon dioxide and methane, may be contributing to warming of the
Earth’s atmosphere. In response to such studies, President Obama has
expressed support for, and it is anticipated that the current session of
Congress will consider legislation to regulate emissions of greenhouse
gases. In addition, more than one-third of the states, either
individually or through multi-state regional initiatives, have already taken
legal measures to reduce emission of these gases, primarily through the planned
development of greenhouse gas emission inventories and/or regional greenhouse
gas cap and trade programs. Also, as a result of the U.S. Supreme
Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA,
the EPA may be required to regulate greenhouse gas emissions from mobile sources
(e.g., cars and trucks) even if Congress does not adopt new legislation
specifically addressing emissions of greenhouse gases. The Court’s
holding in Massachusetts that greenhouse
gases fall under the federal Clean Air Act’s definition of “air pollutant” may
also result in future regulation of greenhouse gas emissions from stationary
sources under certain Clean Air Act programs. As a result of the
Massachusetts decision,
in April 2009, the EPA published a Proposed Endangerment and Cause or Contribute
Findings for Greenhouse Gases Under the Clean Air Act. New
legislation or regulatory programs that restrict emissions of greenhouse gases
in areas where we operate could adversely affect our operations by increasing
costs. The cost increases would result from the potential new
requirements to install additional emission control equipment and by increasing
our monitoring and record-keeping burden.
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, 2009, we had 481 full-time employees, including 29 senior level
geoscientists and 45 petroleum engineers. Our employees are not
represented by any labor unions. We consider our relations with our
employees to be satisfactory and have never experienced a work stoppage or
strike.
Available
Information
We
maintain a website at the address www.whiting.com. We
are not including the information contained on our website as part of, or
incorporating it by reference into, this report. We make available
free of charge (other than an investor’s own Internet access charges) through
our website our Annual Report on Form 10-K, quarterly reports on Form 10-Q and
current reports on Form 8-K, and amendments to these reports, as soon as
reasonably practicable after we electronically file such material with, or
furnish such material to, the Securities and Exchange Commission.
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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.
Oil
and natural gas prices are very volatile. An extended period of low
oil and natural gas prices may adversely affect our business, financial
condition, results of operations or cash flows.
The oil
and gas markets are very volatile, and we cannot predict future oil and natural
gas prices. The price we receive for our oil and natural gas
production heavily influences our revenue, profitability, access to capital and
future rate of growth. The prices we receive for our production and
the levels of our production depend on numerous factors beyond our
control. These factors include, but are not limited to, the
following:
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changes
in global supply and demand for oil and gas;
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the
actions of the Organization of Petroleum Exporting
Countries;
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the
price and quantity of imports of foreign oil and gas;
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political
and economic conditions, including embargoes, in oil-producing countries
or affecting other oil-producing activity;
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the
level of global oil and gas exploration and production
activity;
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the
level of global oil and gas inventories;
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weather
conditions;
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technological
advances affecting energy consumption;
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domestic
and foreign governmental regulations;
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proximity
and capacity of oil and gas pipelines and other transportation
facilities;
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the
price and availability of competitors’ supplies of oil and gas in captive
market areas; and
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the
price and availability of alternative
fuels.
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Furthermore,
the continued economic slowdown worldwide has reduced worldwide demand for
energy and resulted in lower oil and natural gas prices. Oil and
natural gas prices have fallen significantly since their third quarter 2008
levels. For example, the daily average NYMEX oil price was $118.13
per Bbl for the third quarter of 2008, $58.75 per Bbl for the fourth quarter of
2008, and $61.93 per Bbl for 2009. Similarly, daily average NYMEX
natural gas prices have declined from $10.27 per Mcf for the third quarter of
2008 to $6.96 per Mcf for the fourth quarter of 2008 and $3.99 per Mcf for
2009.
Lower oil
and natural gas prices may not only decrease our revenues on a per unit basis
but also may reduce the amount of oil and natural gas that we can produce
economically and therefore potentially lower our reserve bookings. A
substantial or extended decline in oil or natural gas prices may result in
impairments of our proved oil and gas properties and may materially and
adversely affect our future business, financial condition, results of
operations, liquidity or ability to finance planned capital
expenditures. To the extent commodity prices received from production
are insufficient to fund planned capital expenditures, we will be required to
reduce spending or borrow any such shortfall. Lower oil and natural
gas prices may also reduce the amount of our borrowing base under our credit
agreement, which is determined at the discretion of the lenders based on the
collateral value of our proved reserves that have been mortgaged to the lenders,
and is subject to regular redeterminations on May 1 and November 1 of each year,
as well as special redeterminations described in the credit
agreement.
The
global recession and tight financial markets may have impacts on our business
and financial condition that we currently cannot predict.
The
current global recession and tight credit financial markets may have an impact
on our business and our financial condition, and we may face challenges if
conditions in the financial markets do not improve. Our ability to
access the capital markets may be restricted at a time when we would like, or
need, to raise financing, which could have an impact on our flexibility to react
to changing economic and business conditions. The economic situation
could have an impact on our lenders or customers, causing them to fail to meet
their obligations to us. Additionally, market conditions could have
an impact on our commodity hedging arrangements if our counterparties are unable
to perform their obligations or seek bankruptcy protection.
Drilling
for and producing oil and natural gas are high risk activities with many
uncertainties that could adversely affect our business, financial condition or
results of operations.
Our
future success will depend on the success of our development, exploitation,
production and exploration activities. Our oil and natural gas
exploration and production activities are subject to numerous risks beyond our
control, including the risk that drilling will not result in commercially viable
oil or natural gas production. Our decisions to purchase, explore,
develop or otherwise exploit prospects or properties will depend in part on the
evaluation of data obtained through geophysical and geological analyses,
production data and engineering studies, the results of which are often
inconclusive or subject to varying interpretations. Please read “—
Reserve estimates depend on many assumptions that may turn out to be inaccurate
. . .” later in these Risk Factors for a discussion of the uncertainty involved
in these processes. Our cost of drilling, completing and operating
wells is often uncertain before drilling commences. Overruns in
budgeted expenditures are common risks that can make a particular project
uneconomical. Further, many factors may curtail, delay or cancel
drilling, including the following:
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delays
imposed by or resulting from compliance with regulatory
requirements;
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pressure
or irregularities in geological formations;
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shortages
of or delays in obtaining qualified personnel or equipment, including
drilling rigs and CO2;
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equipment
failures or accidents;
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adverse
weather conditions, such as freezing temperatures, hurricanes and
storms;
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reductions
in oil and natural gas prices; and
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title
problems.
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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, 2009, undeveloped reserves comprised 47% of the North Ward Estes
field’s total estimated proved reserves and 18% of the Postle field’s total
estimated proved reserves. To fully develop these reserves, we expect
to incur future development costs of $573.9 million at the North Ward Estes
field and $44.4 million at the Postle field as of December 31,
2009. Together, these fields encompass 56% of our total estimated
future development costs of $1,103.2 million related to proved undeveloped
reserves. Development of these reserves may take longer and require
higher levels of capital expenditures than we currently
anticipate. In addition, the development of these reserves will
require the use of enhanced recovery techniques, including water flood and
CO2 injection
installations, the success of which is less predictable than traditional
development techniques. Therefore, ultimate recoveries from these
fields may not match current expectations.
Our
use of enhanced recovery methods creates uncertainties that could adversely
affect our results of operations and financial condition.
One of
our business strategies is to commercially develop oil reservoirs using enhanced
recovery technologies. For example, we inject water and CO2 into
formations on some of our properties to increase the production of oil and
natural gas. The additional production and reserves attributable to
the use of these enhanced recovery methods are inherently difficult to
predict. If our enhanced recovery programs do not allow for the
extraction of oil and gas in the manner or to the extent that we anticipate, our
future results of operations and financial condition could be materially
adversely affected. Additionally, our ability to utilize CO2 as an enhanced recovery
technique is subject to our ability to obtain sufficient quantities of CO2. Under our CO2 contracts, if the supplier
suffers an inability to deliver its contractually required quantities of CO2 to us and other parties with
whom it has CO2 contracts,
then the supplier may reduce the amount of CO2 on a pro rata basis it provides
to us and such other parties. If this occurs, we may not have
sufficient CO2 to produce
oil and natural gas in the manner or to the extent that we
anticipate. These contracts are also structured as “take-or-pay”
arrangements, which require us to continue to make payments even if we decide to
terminate or reduce our use of CO2 as part of our enhanced
recovery techniques.
Prospects
that we decide to drill may not yield oil or gas in commercially viable
quantities.
We
describe some of our current prospects and our plans to explore those prospects
in this Annual Report on Form 10-K. A prospect is a property on which
we have identified what our geoscientists believe, based on available seismic
and geological information, to be indications of oil or gas. Our
prospects are in various stages of evaluation, ranging from a prospect which is
ready to drill to a prospect that will require substantial additional seismic
data processing and interpretation. There is no way to predict in
advance of drilling and testing whether any particular prospect will yield oil
or gas in sufficient quantities to recover drilling or completion costs or to be
economically viable. The use of seismic data and other technologies
and the study of producing fields in the same area will not enable us to know
conclusively prior to drilling whether oil or gas will be present or, if
present, whether oil or gas will be present in commercial
quantities. In addition, because of the wide variance that results
from different equipment used to test the wells, initial flowrates may not be
indicative of sufficient oil or gas quantities in a particular
field. The analogies we draw from available data from other wells,
from more fully explored prospects, or from producing fields may not be
applicable to our drilling prospects. We may terminate our drilling
program for a prospect if results do not merit further investment.
If
oil and natural gas prices decrease, we may be required to take write-downs of
the carrying values of our oil and gas properties.
Accounting
rules require that we review periodically the carrying value of our oil and gas
properties for possible impairment. Based on specific market factors
and circumstances at the time of prospective impairment reviews, which may
include depressed oil and natural gas prices, and the continuing evaluation of
development plans, production data, economics and other factors, we may be
required to write down the carrying value of our oil and gas
properties. For example, we recorded a $9.4 million impairment
write-down during 2009 for the partial impairment of producing properties,
primarily natural gas, in the Rocky Mountains region. A write-down
constitutes a non-cash charge to earnings. We may incur additional
impairment charges in the future, which could have a material adverse effect on
our results of operations in the period taken.
Reserve
estimates depend on many assumptions that may turn out to be
inaccurate. Any material inaccuracies in these reserve estimates or
underlying assumptions will materially affect the quantities and present value
of our reserves.
The
process of estimating oil and natural gas reserves is complex. It
requires interpretations of available technical data and many assumptions,
including assumptions relating to economic factors. Any significant
inaccuracies in these interpretations or assumptions could materially affect the
estimated quantities and present value of reserves referred to in this Annual
Report on Form 10-K.
In order
to prepare our estimates, we must project production rates and timing of
development expenditures. We must also analyze available geological,
geophysical, production and engineering data. The extent, quality and
reliability of this data can vary. The process also requires economic
assumptions about matters such as oil and natural gas prices, drilling and
operating expenses, capital expenditures, taxes and availability of
funds. Therefore, estimates of oil and natural gas reserves are
inherently imprecise.
Actual
future production, oil and natural gas prices, revenues, taxes, exploration and
development expenditures, operating expenses and quantities of recoverable oil
and natural gas reserves most likely will vary from our
estimates. Any significant variance could materially affect the
estimated quantities and present value of reserves referred to in this Annual
Report on Form 10-K. In addition, we may adjust estimates of proved
reserves to reflect production history, results of exploration and development,
prevailing oil and natural gas prices and other factors, many of which are
beyond our control.
You
should not assume that the present value of future net revenues from our proved
reserves, as referred to in this report, is the current market value of our
estimated proved oil and natural gas reserves. In accordance with SEC
requirements, we generally base the estimated discounted future net cash flows
from our proved reserves on 12-month average prices and current costs as of the
date of the estimate. Actual future prices and costs may differ
materially from those used in the 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, 2009 would have
decreased from $2,343.5 million to $2,335.5 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, 2009 would have
decreased from $2,343.5 million to $2,286.3 million.
Our
debt level and the covenants in the agreements governing our debt could
negatively impact our financial condition, results of operations, cash flows and
business prospects.
As of
December 31, 2009, we had $160.0 million in borrowings and
$0.3 million in letters of credit outstanding under Whiting Oil and Gas
Corporation’s credit agreement with $939.7 million of available borrowing
capacity, as well as $620.0 million of senior subordinated notes
outstanding. We are permitted to incur additional indebtedness,
provided we meet certain requirements in the indentures governing our senior
subordinated notes and Whiting Oil and Gas Corporation’s credit
agreement.
Our level of indebtedness and the
covenants contained in the agreements governing our debt could have important
consequences for our operations, including:
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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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potentially
limiting our ability to pay dividends in cash on our convertible perpetual
preferred stock;
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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 Corporation’s 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. In addition, if we are in default under the agreements
governing our indebtedness, we will not be able to pay dividends on our capital
stock. Our ability to comply with these covenants and other
restrictions may be affected by events beyond our control, including prevailing
economic and financial conditions. Moreover, the borrowing base
limitation on Whiting Oil and Gas Corporation’s credit agreement is periodically
redetermined based on an evaluation of our reserves. Upon a
redetermination, if borrowings in excess of the revised borrowing capacity were
outstanding, we could be forced to repay a portion of our debt under the credit
agreement.
We may
not have sufficient funds to make such repayments. If we are unable
to repay our debt out of cash on hand, we could attempt to refinance such debt,
sell assets or repay such debt with the proceeds from an equity
offering. We may not be able to generate sufficient cash flow to pay
the interest on our debt or future borrowings, and equity financings or proceeds
from the sale of assets may not be available to pay or refinance such
debt. The terms of our debt, including Whiting Oil and Gas
Corporation’s credit agreement, may also prohibit us from taking such
actions. Factors that will affect our ability to raise cash through
an offering of our capital stock, a refinancing of our debt or a sale of assets
include financial market conditions and our market value and operating
performance at the time of such offering or other financing. We may
not be able to successfully complete any such offering, refinancing or sale of
assets.
The
instruments governing our indebtedness contain various covenants limiting the
discretion of our management in operating our business.
The
indentures governing our senior subordinated notes and Whiting Oil and Gas
Corporation’s credit agreement contain various restrictive covenants that may
limit our management’s discretion in certain respects. In particular,
these agreements will limit our and our subsidiaries’ ability to, among other
things:
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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 Corporation’s credit agreement requires us, as of
the last day of any quarter, (i) to not exceed a total debt to EBITDAX ratio (as
defined in the credit agreement) for the last four quarters of 4.5 to 1.0 for
quarters ending prior to and on September 30, 2010, 4.25 to 1.0 for quarters
ending December 31, 2010 to June 30, 2011 and 4.0 to 1.0 for quarters ending
September 30, 2011 and thereafter, (ii) to have a consolidated current assets to
consolidated current liabilities ratio (as defined in the credit agreement) of
not less than 1.0 to 1.0 and (iii) to not exceed a senior secured debt to
EBITDAX ratio (as defined in the credit agreement) for the last four quarters of
2.75 to 1.0 for quarters ending prior to and on December 31, 2009 and 2.5 to 1.0
for quarters ending March 31, 2010 and thereafter. Also, the indentures under
which we issued our senior subordinated notes restrict us from incurring
additional indebtedness, subject to certain exceptions, unless our fixed charge
coverage ratio (as defined in the indentures) is at least 2.0 to
1. If we were in violation of this covenant, then we may not be able
to incur additional indebtedness, including under Whiting Oil and Gas
Corporation’s credit agreement. A substantial or extended decline in
oil or natural gas prices may adversely affect our ability to comply with these
covenants.
If we
fail to comply with the restrictions in the indentures governing our senior
subordinated notes or Whiting Oil and Gas Corporation’s credit agreement or any
other subsequent financing agreements, a default may allow the creditors, if the
agreements so provide, to accelerate the related indebtedness as well as any
other indebtedness to which a cross-acceleration or cross-default provision
applies. In addition, lenders may be able to terminate any
commitments they had made to make available further
funds. Furthermore, if we are in default under the agreements
governing our indebtedness, we will not be able to pay dividends on our capital
stock.
Our exploration
and development operations require substantial capital, and we may be unable to
obtain needed capital or financing on satisfactory terms, which could lead to a
loss of properties and a decline in our oil and natural gas
reserves.
The oil
and gas industry is capital intensive. We make and expect to continue
to make substantial capital expenditures in our business and operations for the
exploration, development, production and acquisition of oil and natural gas
reserves. To date, we have financed capital expenditures through a
combination of equity and debt issuances, bank borrowings and internally
generated cash flows. We intend to finance future capital
expenditures with cash flow from operations and existing financing
arrangements. Our cash flow from operations and access to capital is
subject to a number of variables, including:
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our
proved reserves;
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the
level of oil and natural gas we are able to produce from existing
wells;
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the
prices at which oil and natural gas are sold;
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the
costs of producing oil and natural gas; and
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our
ability to acquire, locate and produce new
reserves.
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If our
revenues or the borrowing base under our bank credit agreement decreases as a
result of lower oil and natural gas prices, operating difficulties, declines in
reserves or for any other reason, then we may have limited ability to obtain the
capital necessary to sustain our operations at current levels. We
may, from time to time, need to seek additional financing. There can
be no assurance as to the availability or terms of any additional
financing.
If
additional capital is needed, we may not be able to obtain debt or equity
financing on terms favorable to us, or at all. If cash generated by
operations or available under our revolving credit facility is not sufficient to
meet our capital requirements, the failure to obtain additional financing could
result in a curtailment of our operations relating to the exploration and
development of our prospects, which in turn could lead to a possible loss of
properties and a decline in our oil and natural gas reserves.
Our
acquisition activities may not be successful.
As part
of our growth strategy, we have made and may continue to make acquisitions of
businesses and properties. However, suitable acquisition candidates
may not continue to be available on terms and conditions we find acceptable, and
acquisitions pose substantial risks to our business, financial condition and
results of operations. In pursuing acquisitions, we compete with
other companies, many of which have greater financial and other resources to
acquire attractive companies and properties. The following are some
of the risks associated with acquisitions, including any completed or future
acquisitions:
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some
of the acquired businesses or properties may not produce revenues,
reserves, earnings or cash flow at anticipated levels;
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we
may assume liabilities that were not disclosed to us or that exceed our
estimates;
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we
may be unable to integrate acquired businesses successfully and realize
anticipated economic, operational and other benefits in a timely manner,
which could result in substantial costs and delays or other operational,
technical or financial problems;
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acquisitions
could disrupt our ongoing business, distract management, divert resources
and make it difficult to maintain our current business standards, controls
and procedures; and
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we
may issue additional equity or debt securities related to future
acquisitions.
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Substantial
acquisitions or other transactions could require significant external capital
and could change our risk and property profile.
In order
to finance acquisitions of additional producing or undeveloped properties, we
may need to alter or increase our capitalization substantially through the
issuance of debt or equity securities, the sale of production payments or other
means. These changes in capitalization may significantly affect our
risk profile. Additionally, significant acquisitions or other
transactions can change the character of our operations and
business. The character of the new properties may be substantially
different in operating or geological characteristics or geographic location than
our existing properties. Furthermore, we may not be able to obtain
external funding for future acquisitions or other transactions or to obtain
external funding on terms acceptable to us.
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, 2009, we had identified a drilling inventory of over 1,400 gross
drilling locations. These scheduled drilling locations represent a
significant part of our growth strategy. Our ability to drill and
develop these locations depends on a number of uncertainties, including oil and
natural gas prices, the availability of capital, costs of oil field goods and
services, drilling results, ability to extend drilling acreage leases beyond
expiration, regulatory approvals and other factors. Because of these
uncertainties, we do not know if the numerous potential drilling locations we
have identified will ever be drilled or if we will be able to produce oil or gas
from these or any other potential drilling locations. As such, our
actual drilling activities may materially differ from those presently
identified, which could adversely affect our business.
We
have been an early entrant into new or emerging plays. As a result,
our drilling results in these areas are uncertain, and the value of our
undeveloped acreage will decline and we may incur impairment charges if drilling
results are unsuccessful.
While our
costs to acquire undeveloped acreage in new or emerging plays have generally
been less than those of later entrants into a developing play, our drilling
results in these areas are more uncertain than drilling results in areas that
are developed and producing. Since new or emerging plays have limited
or no production history, we are unable to use past drilling results in those
areas to help predict our future drilling results. Therefore, our
cost of drilling, completing and operating wells in these areas may be higher
than initially expected, and the value of our undeveloped acreage will decline
if drilling results are unsuccessful. Furthermore, if drilling
results are unsuccessful, we may be required to write down the carrying value of
our undeveloped acreage in new or emerging plays. For example, during
the fourth quarter of 2008, we recorded a $10.9 million non-cash charge for the
partial impairment of unproved properties in the central Utah Hingeline
play. We may also incur such impairment charges in the future, which
could have a material adverse effect on our results of operations in the period
taken. Additionally, our rights to develop a portion of our
undeveloped acreage may expire if not successfully developed or
renewed. See “Acreage” in Item 2 of this Annual Report on Form 10-K
for more information relating to the expiration of our rights to develop
undeveloped acreage.
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.
Properties
that we acquire may not produce as projected, and we may be unable to identify
liabilities associated with the properties or obtain protection from sellers
against them.
Our
business strategy includes a continuing acquisition program. From
2004 through 2009, we completed 15 separate acquisitions of producing properties
with a combined purchase price of $1,889.9 million for estimated proved reserves
as of the effective dates of the acquisitions of 230.7 MMBOE. The
successful acquisition of producing properties requires assessments of many
factors, which are inherently inexact and may be inaccurate, including the
following:
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the
amount of recoverable reserves;
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future
oil and natural gas prices;
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estimates
of operating costs;
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estimates
of future development costs;
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timing
of future development costs;
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estimates
of the costs and timing of plugging and
abandonment; and
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potential
environmental and other
liabilities.
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Our
assessment will not reveal all existing or potential problems, nor will it
permit us to become familiar enough with the properties to assess fully their
capabilities and deficiencies. In the course of our due diligence, we
may not inspect every well, platform or pipeline. Inspections may not
reveal structural and environmental problems, such as pipeline corrosion or
groundwater contamination, when they are made. We may not be able to
obtain contractual indemnities from the seller for liabilities that it
created. We may be required to assume the risk of the physical
condition of the properties in addition to the risk that the properties may not
perform in accordance with our expectations.
Our
use of oil and natural gas price hedging contracts involves credit risk and may
limit future revenues from price increases and result in significant
fluctuations in our net income.
We enter
into hedging transactions of our oil and natural gas production to reduce our
exposure to fluctuations in the price of oil and natural gas. Our
hedging transactions to date have consisted of financially settled crude oil and
natural gas forward sales contracts, primarily costless collars, placed with
major financial institutions. As of February 16, 2010, we had
contracts, which include our 24.2% share of the Whiting USA Trust I hedges,
covering the sale for 2010 of between 565,910 and 650,643 barrels of oil per
month and between 39,445 and 43,295 MMBtu of natural gas per
month. All our oil hedges will expire by November 2013, and all our
natural gas hedges will expire by December 2012. See “Quantitative
and Qualitative Disclosure about Market Risk” in Item 7A of this Annual Report
on Form 10-K for pricing and a more detailed discussion of our hedging
transactions.
We may in
the future enter into these and other types of hedging arrangements to reduce
our exposure to fluctuations in the market prices of oil and natural gas, or
alternatively, we may decide to unwind or restructure the hedging arrangements
we previously entered into. Hedging transactions expose us to risk of
financial loss in some circumstances, including if production is less than
expected, the other party to the contract defaults on its obligations or there
is a change in the expected differential between the underlying price in the
hedging agreement and actual prices received. Hedging transactions
may limit the benefit we may otherwise receive from increases in the price for
oil and natural gas. Furthermore, if we do not engage in hedging
transactions or unwind hedging transaction we previously entered into, then we
may be more adversely affected by declines in oil and natural gas prices than
our competitors who engage in hedging transactions. Additionally,
hedging transactions may expose us to cash margin requirements.
Effective
April 1, 2009, we elected to de-designate all of our commodity derivative
contracts that had been previously designated as cash flow hedges as of March
31, 2009 and have elected to discontinue hedge accounting
prospectively. As such, subsequent to March 31, 2009 we recognize all
gains and losses from prospective changes in commodity derivative fair values
immediately in earnings rather than deferring any such amounts in accumulated
other comprehensive income. Subsequently, we may experience
significant net income and operating result losses, on a non-cash basis, due to
changes in the value of our hedges as a result of commodity price
volatility.
Seasonal
weather conditions and lease stipulations adversely affect our ability to
conduct drilling activities in some of the areas where we operate.
Oil and
gas operations in the Rocky Mountains are adversely affected by seasonal weather
conditions and lease stipulations designed to protect various
wildlife. In certain areas, drilling and other oil and gas activities
can only be conducted during the spring and summer months. This
limits our ability to operate in those areas and can intensify competition
during those months for drilling rigs, oil field equipment, services, supplies
and qualified personnel, which may lead to periodic
shortages. Resulting shortages or high costs could delay our
operations and materially increase our operating and capital costs.
The
differential between the NYMEX or other benchmark price of oil and natural gas
and the wellhead price we receive could have a material adverse effect on our
results of operations, financial condition and cash flows.
The
prices that we receive for our oil and natural gas production generally trade at
a discount to the relevant benchmark prices such as NYMEX. The
difference between the benchmark price and the price we receive is called a
differential. We cannot accurately predict oil and natural gas
differentials. Increases in the differential between the benchmark
price for oil and natural gas and the wellhead price we receive could have a
material adverse effect on our results of operations, financial condition and
cash flows.
We
may incur substantial losses and be subject to substantial liability claims as a
result of our oil and gas operations.
We are
not insured against all risks. Losses and liabilities arising from
uninsured and underinsured events could materially and adversely affect our
business, financial condition or results of operations. Our oil and
natural gas exploration and production activities are subject to all of the
operating risks associated with drilling for and producing oil and natural gas,
including the possibility of:
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•
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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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•
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abnormally
pressured formations;
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•
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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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•
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personal
injuries and death; and
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•
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natural
disasters.
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Any of
these risks could adversely affect our ability to conduct operations or result
in substantial losses to our company. We may elect not to obtain
insurance if we believe that the cost of available insurance is excessive
relative to the risks presented. In addition, pollution and
environmental risks generally are not fully insurable. If a
significant accident or other event occurs and is not fully covered by
insurance, then it could adversely affect us.
We
have limited control over activities on properties we do not operate, which
could reduce our production and revenues.
If we do
not operate the properties in which we own an interest, we do not have control
over normal operating procedures, expenditures or future development of
underlying properties. The failure of an operator of our wells to
adequately perform operations or an operator’s breach of the applicable
agreements could reduce our production and revenues. The success and
timing of our drilling and development activities on properties operated by
others therefore depends upon a number of factors outside of our control,
including the operator’s timing and amount of capital expenditures, expertise
and financial resources, inclusion of other participants in drilling wells, and
use of technology. Because we do not have a majority interest in most
wells we do not operate, we may not be in a position to remove the operator in
the event of poor performance.
Our
use of 3-D seismic data is subject to interpretation and may not accurately
identify the presence of oil and gas, which could adversely affect the results
of our drilling operations.
Even when
properly used and interpreted, 3-D seismic data and visualization techniques are
only tools used to assist geoscientists in identifying subsurface structures and
hydrocarbon indicators and do not enable the interpreter to know whether
hydrocarbons are, in fact, present in those structures. In addition,
the use of 3-D seismic and other advanced technologies requires greater
predrilling expenditures than traditional drilling strategies, and we could
incur losses as a result of such expenditures. Thus, some of our
drilling activities may not be successful or economical, and our overall
drilling success rate or our drilling success rate for activities in a
particular area could decline. We often gather 3-D seismic data over
large areas. Our interpretation of seismic data delineates for us
those portions of an area that we believe are desirable for
drilling. Therefore, we may choose not to acquire option or lease
rights prior to acquiring seismic data, and in many cases, we may identify
hydrocarbon indicators before seeking option or lease rights in the
location. If we are not able to lease those locations on acceptable
terms, it would result in our having made substantial expenditures to acquire
and analyze 3-D seismic data without having an opportunity to attempt to benefit
from those expenditures.
Market
conditions or operational impediments may hinder our access to oil and gas
markets or delay our production.
In
connection with our continued development of oil and gas properties, we may be
disproportionately exposed to the impact of delays or interruptions of
production from wells in these properties, caused by transportation capacity
constraints, curtailment of production or the interruption of transporting oil
and gas volumes produced. In addition, market conditions or a lack of
satisfactory oil and gas transportation arrangements may hinder our access to
oil and gas markets or delay our production. The availability of a
ready market for our oil and natural gas production depends on a number of
factors, including the demand for and supply of oil and natural gas and the
proximity of reserves to pipelines and terminal facilities. Our
ability to market our production depends substantially on the availability and
capacity of gathering systems, pipelines and processing facilities owned and
operated by third-parties. Additionally, entering into arrangements
for these services exposes us to the risk that third parties will default on
their obligations under such arrangements. Our failure to obtain such
services on acceptable terms or the default by a third party on their obligation
to provide such services could materially harm our business. We may
be required to shut in wells for a lack of a market or because access to gas
pipelines, gathering systems or processing facilities may be limited or
unavailable. If that were to occur, then we would be unable to
realize revenue from those wells until production arrangements were made to
deliver the production to market.
We
are subject to complex laws that can affect the cost, manner or feasibility of
doing business.
Exploration,
development, production and sale of oil and natural gas are subject to extensive
federal, state, local and international regulation. We may be
required to make large expenditures to comply with governmental
regulations. Matters subject to regulation include:
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discharge
permits for drilling operations;
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drilling
bonds;
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reports
concerning operations;
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the
spacing of wells;
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unitization
and pooling of properties; and
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taxation.
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Under
these laws, we could be liable for personal injuries, property damage and other
damages. Failure to comply with these laws also may result in the
suspension or termination of our operations and subject us to administrative,
civil and criminal penalties. Moreover, these laws could change in
ways that could substantially increase our costs. Any such
liabilities, penalties, suspensions, terminations or regulatory changes could
materially adversely affect our financial condition and results of
operations.
Our
operations may incur substantial liabilities to comply with environmental laws
and regulations.
Our oil
and gas operations are subject to stringent federal, state and local laws and
regulations relating to the release or disposal of materials into the
environment or otherwise relating to environmental protection. These
laws and regulations may require the acquisition of a permit before drilling
commences; restrict the types, quantities, and concentration of materials that
can be released into the environment in connection with drilling and production
activities; limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands, and other protected areas; and impose substantial
liabilities for pollution resulting from our operations. Failure to
comply with these laws and regulations may result in the assessment of
administrative, civil, and criminal penalties, incurrence of investigatory or
remedial obligations, or the imposition of injunctive relief. Under
these environmental laws and regulations, we could be held strictly liable for
the removal or remediation of previously released materials or property
contamination regardless of whether we were responsible for the release or if
our operations were standard in the industry at the time they were
performed. Federal law and some state laws also allow the government
to place a lien on real property for costs incurred by the government to address
contamination on the property.
Changes
in environmental laws and regulations occur frequently, and any changes that
result in more stringent or costly material handling, storage, transport,
disposal or cleanup requirements could require us to make significant
expenditures to maintain compliance and may otherwise have a material adverse
effect on our results of operations, competitive position, or financial
condition as well as those of the oil and gas industry in
general. For instance, recent scientific studies have suggested that
emissions of certain gases, commonly referred to as “greenhouse gases”,
including carbon dioxide and methane, may be contributing to warming of the
Earth’s atmosphere. In response to such studies, President Obama has
expressed support for, and it is anticipated that the current session of
Congress will consider legislation to regulate emissions of greenhouse
gases. In addition, more than one-third of the states, either
individually or through multi-state regional initiatives, have already taken
legal measures to reduce emission of these gases, primarily through the planned
development of greenhouse gas emission inventories and/or regional greenhouse
gas cap and trade programs. Also, as a result of the U.S. Supreme
Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA,
the EPA may be required to regulate greenhouse gas emissions from mobile sources
(e.g., cars and trucks) even if Congress does not adopt new legislation
specifically addressing emissions of greenhouse gases. The Court’s
holding in Massachusetts that greenhouse
gases fall under the federal Clean Air Act’s definition of “air pollutant” may
also result in future regulation of greenhouse gas emissions from stationary
sources under certain Clean Air Act programs. As a result of the
Massachusetts decision,
in April 2009, the EPA published a Proposed Endangerment and Cause or Contribute
Findings for Greenhouse Gases Under the Clean Air Act. New
legislation or regulatory programs that restrict emissions of greenhouse gases
in areas where we operate could adversely affect our operations by increasing
costs. The cost increases would result from the potential new
requirements to install additional emission control equipment and by increasing
our monitoring and record-keeping burden.
Unless
we replace our oil and natural gas reserves, our reserves and production will
decline, which would adversely affect our cash flows and results of
operations.
Unless we
conduct successful development, exploitation and exploration activities or
acquire properties containing proved reserves, our proved reserves will decline
as those reserves are produced. Producing oil and natural gas
reservoirs generally are characterized by declining production rates that vary
depending upon reservoir characteristics and other factors. Our
future oil and natural gas reserves and production, and therefore our cash flow
and income, are highly dependent on our success in efficiently developing and
exploiting our current reserves and economically finding or acquiring additional
recoverable reserves. We may not be able to develop, exploit, find or
acquire additional reserves to replace our current and future
production.
The
loss of senior management or technical personnel could adversely affect
us.
To a
large extent, we depend on the services of our senior management and technical
personnel. The loss of the services of our senior management or
technical personnel, including James J. Volker, our Chairman, President and
Chief Executive Officer; James T. Brown, our Senior Vice President; Rick A.
Ross, our Vice President, Operations; Peter W. Hagist, our Vice President,
Permian Operations; J. Douglas Lang, our Vice President, Reservoir
Engineering/Acquisitions; David M. Seery, our Vice President, 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.
Competition
in the oil and gas industry is intense, which may adversely affect our ability
to compete.
We
operate in a highly competitive environment for acquiring properties, marketing
oil and gas and securing trained personnel. Many of our competitors
possess and employ financial, technical and personnel resources substantially
greater than ours, which can be particularly important in the areas in which we
operate. Those companies may be able to pay more for productive oil
and gas properties and exploratory prospects and to evaluate, bid for and
purchase a greater number of properties and prospects than our financial or
personnel resources permit. Our ability to acquire additional
prospects and to find and develop reserves in the future will depend on our
ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. Also, there is
substantial competition for available capital for investment in the oil and gas
industry. We may not be able to compete successfully in the future in
acquiring prospective reserves, developing reserves, marketing hydrocarbons,
attracting and retaining quality personnel and raising additional
capital.
Certain
federal income tax deductions currently available with respect to oil and gas
exploration and development may be eliminated as a result of future
legislation.
In May
2009, President Obama’s Administration released revenue proposals in “General
Explanations of the Administration’s Fiscal 2010 Revenue Proposals” that would,
if enacted into law, make significant changes to United States tax laws,
including the elimination of certain key U.S. federal income tax preferences
currently available to oil and gas exploration and production
companies. These changes include, but are not limited to (i) the
repeal of the percentage depletion allowance for oil and gas properties, (ii)
the elimination of current deductions for intangible drilling and development
costs, (iii) the elimination of the deduction for certain U.S. production
activities and (iv) an extension of the amortization period for certain
geological and geophysical expenditures. In April 2009, the Oil
Industry Tax Break Repeal Act of 2009, or the Senate Bill, was introduced in the
Senate and includes many of the proposals outlined in the revenue
proposals. It is unclear whether any such changes will actually be
enacted or how soon any such changes could become effective. The
passage of any legislation as a result of the revenue proposals, the Senate Bill
or any other similar change in U.S. federal income tax law could eliminate
certain tax deductions that are currently available with respect to oil and gas
exploration and development, and any such change could negatively impact our
financial condition and results of operations.
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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, 2009, the Permian Basin region contributed 123.3 MMBOE (91%
oil) of estimated proved reserves to our portfolio of operations, which
represented 45% of our total estimated proved reserves and contributed 11.7
MBOE/d of average daily production in December 2009.
North Ward Estes
Field. The North Ward Estes field includes six base leases
with 100% working interest in approximately 58,000 gross and net acres in Ward
and Winkler Counties, Texas. The Yates Formation at 2,600 feet is the
primary producing zone with additional production from other zones including the
Queen at 3,000 feet. In the North Ward Estes field, the estimated
proved reserves as of December 31, 2009 were 30% PDP, 23% PDNP and 47%
PUD.
The North
Ward Estes field is responding positively to our water and CO2 floods, which we initiated in
May 2007. As of December 31, 2009, we were injecting 204 MMcf/d of
CO2 in this
field. Production from the field has increased 8% from 6.6 MBOE/d in
December 2008 to 7.1 MBOE/d in December 2009. In this field, we are
developing new and reactivated wells for water and CO2 injection and production
purposes.
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, 2009,
our estimated proved reserves in the Rocky Mountain region were 96.8 MMBOE (73%
oil), which represented 35% of our total estimated proved reserves and
contributed 30.3 MBOE/d of average daily production in December
2009.
Sanish Field. Our
Sanish area in Mountrail County, North Dakota encompasses approximately 118,000
gross (69,600 net) acres. December 2009 net production in the Sanish
field averaged 12.6 MBOE/d, a 68% increase from 7.5 MBOE/d in December
2008. As of February 15, 2010, we have participated in 123 wells (88
operated) in the Sanish field, of which 103 are producing, ten are in the
process of completion and ten are being drilled. Of these operated
wells, 38 were completed in 2009. In order to process the produced
gas stream from the Sanish wells, we constructed and brought on-line the
Robinson Lake Gas Plant. The first phase of this plant began
processing gas in May 2008, and in December 2008 we completed the construction
of the second phase. We completed the installation of the 17-mile oil
line connecting the Sanish field to the Enbridge pipeline in Stanley, North
Dakota in late December 2009. The pipeline is currently moving
approximately 10,000 Bbls of oil per day. We expect to have all of
our net operated oil production in the pipeline upon completion of Enbridge’s
tank facility at Stanley, which is expected to occur in June 2010.
Parshall
Field. Immediately east of the Sanish field is the Parshall
field, where we own interests in approximately 74,900 gross (18,400 net)
acres. Our net production from the Parshall field averaged 6.4 MBOE/d
in December 2009, a 4% decrease from 6.7 MBOE/d in December 2008. As
of February 15, 2010, we have participated in 114 Bakken wells in the Parshall
field, the majority of which are operated by EOG Resources, Inc., of which 111
are producing and three are in the process of completion. Of these
wells, 28 were completed in 2009.
Lewis & Clark
Prospect. As of December 31, 2009, we have assembled
approximately 213,500 gross (127,800 net) acres in our Lewis & Clark
prospect along the Bakken Shale pinch-out in the southern Williston
Basin. Subsequent to year-end we assembled additional acreage,
primarily in Stark County, North Dakota, which brings our total acreage position
in the Lewis & Clark area to 320,000 gross (202,400 net)
acres. In this area, the Upper Bakken shale is thermally mature,
moderately over-pressured, and we believe that it has charged reservoir zones
within the immediately underlying Three Forks formation.
Flat Rock
Field. We acquired the Flat Rock Field in May 2008 and took
over operations June 1, 2008. In the Flat Rock field area in Uintah
County, Utah, we have an acreage position consisting of approximately 22,000
gross (11,500 net) acres. We currently have one active drilling rig
operating in the field.
Sulphur Creek
Field. In the Sulphur Creek field in Rio Blanco County,
Colorado in the Piceance Basin, we own approximately 10,200 gross (4,500 net)
acres in the Sulphur Creek field area.
Mid-Continent
Region
Our
Mid-Continent operations include assets in Oklahoma, Arkansas and
Kansas. As of December 31, 2009, the Mid-Continent region
contributed 39.1 MMBOE (94% oil) of proved reserves to our portfolio of
operations, which represented 14% of our total estimated proved reserves and
contributed 9.3 MBOE/d of average daily production in December
2009. The majority of the proved value within our Mid-Continent
operations is related to properties in the Postle field.
Postle Field. The
Postle field, located in Texas County, Oklahoma, includes five producing units
and one producing lease covering a total of approximately 25,600 gross (24,200
net) acres. Four of the units are currently active CO2 enhanced recovery
projects. Our expansion of the CO2 flood at the Postle field
continues to generate positive results. As of December 31, 2009,
we were injecting 140 MMcf/d of CO2 in
this field. Production from the field has increased 30% from a net
7.1 MBOE/d in December 2008 to a net 9.2 MBOE/d in December
2009. Operations are underway to expand CO2 injection into the northern
part of the fourth unit, HMU, and to optimize flood patterns in the existing
CO2
floods. These expansion projects include the restoration of shut-in
wells and the drilling of new producing and injection wells. In the
Postle field, the estimated proved reserves as of December 31, 2009 were 78%
PDP, 4% PDNP and 18% PUD.
We are
the sole owner of the Dry Trails Gas Plant located in the Postle
field. This gas processing plant utilizes a membrane technology to
separate CO2 gas from the
produced wellhead mixture of hydrocarbon and CO2 gas so that the CO2 gas can be re-injected into the
producing formation.
In
addition to the producing assets and processing plant, we have a 60% interest in
the 120-mile TransPetco operated CO2 transportation pipeline,
thereby assuring the delivery of CO2 to the Postle field at a fair
tariff. A long-term CO2 purchase agreement was executed
in 2005 to provide the necessary CO2 for the expansion planned in
the field.
Gulf
Coast Region
Our Gulf
Coast operations include assets located in Texas, Louisiana and
Mississippi. As of December 31, 2009, the Gulf Coast region
contributed 8.4 MMBOE (27% oil) of proved reserves to our portfolio of
operations, which represented 3% of our total estimated proved reserves and
contributed 3.0 MBOE/d of average daily production in December
2009.
Edwards Trend. We own
acreage in the Nordheim, Word North, Yoakum, Kawitt, Sweet Home, and Three
Rivers fields along the Edwards Trend in Karnes, Dewitt, Live Oak, and Lavaca
Counties, Texas. In 2007, we farmed out the Kawitt and Nordheim lease
position (12,000 net acres) to another operator who is developing the Edwards
Trend with horizontal wellbores. Under the terms of this agreement,
we were carried on all drilling and completion costs on four Edwards Trend
wells, and Whiting maintained a 16.67% working interest in the completed
wells. Going forward, we had the option to participate upfront for a 25%
working interest in additional Edwards wells to be drilled or elect to take the
25% working interest after payout has occurred. To date, we have
elected to take a 25% after payout working interest in seven wells drilled under
this farmout. We anticipate three more wells to be proposed in 2010
which will fully develop the acreage under the agreement. This agreement
thereby allowed us to maintain a working interest in an expiring acreage
position, which is now held by production, and furthermore our acreage position
in this area has upside potential in the Eagle Ford shale that lies just above
the Edwards Trend.
Michigan
Region
As of
December 31, 2009, our estimated proved reserves in the Michigan region were 7.4
MMBOE (32% oil), and our December 2009 daily production averaged 2.3
MBOE/d. Production in Michigan can be divided into two
groups. The majority of the reserves are in non-operated Antrim Shale
wells located in the northern part of the state. The remainder of the
Michigan reserves are typified by more conventional oil and gas production
located in the central and southern parts of the state. We also
operate the West Branch and Reno gas processing plants. The West
Branch Plant gathers production from the Clayton unit, West Branch field and
other smaller fields.
Marion 3-D
Project. The Marion Prospect, located in Missauke, Clare and
Oceola Counties, Michigan, covers approximately 16,000 gross (14,700 net)
acres. Our analysis of seismic data has identified two drillable
prospects, and we are currently formulating our drilling plans for this
area.
Reserves
As of
December 31, 2009, all of our oil and gas reserves are attributable to
properties within the United States. A summary of our oil and gas
reserves as of December 31, 2009 based on average fiscal-year prices (calculated
as the unweighted arithmetic average of the first-day-of-the-month price for
each month within the 12-month period ended December 31, 2009) is as
follows:
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Summary
of Oil and Gas Reserves as of Fiscal-Year End Based on Average Fiscal-Year
Prices
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Oil
(MBbl)
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Natural
Gas
(MMcf)
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Total
(MBOE)
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Proved
reserves
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Developed
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144,813 | 178,782 | 174,610 | |||||||||
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Undeveloped
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78,983 | 128,611 | 100,419 | |||||||||
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Total
proved—December 31, 2009
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223,796 | 307,393 | 275,029 | |||||||||
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Probable
reserves
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Developed
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1,360 | 9,844 | 3,000 | |||||||||
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Undeveloped
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57,463 | 172,045 | 86,138 | |||||||||
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Total
probable—December 31, 2009
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58,823 | 181,889 | 89,138 | |||||||||
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Possible
reserves
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Developed
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22,728 | 9,254 | 24,270 | |||||||||
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Undeveloped
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143,912 | 175,656 | 173,188 | |||||||||
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Total
possible—December 31, 2009
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166,640 | 184,910 | 197,458 | |||||||||
Proved
reserves. Estimates of proved developed and undeveloped
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.
In 2009,
total extensions and discoveries of 32.1 MMBOE were primarily attributable to
successful drilling in the Sanish and Parshall fields and related proved
undeveloped well locations added during the year, which in turn extended the
proved acreage in those areas.
In 2009,
revisions to previous estimates increased proved developed and undeveloped
reserves by a net amount of 23.1 MMBOE. Included in these revisions
were (i) 17.3 MMBOE of net upward adjustments caused by higher crude oil prices
incorporated into our reserve estimates at December 31, 2009 as compared to
December 31, 2008 that were partially offset by lower natural gas prices as of
December 31, 2009, and (ii) 5.8 MMBOE of net upward adjustments attributable to
reservoir analysis and well performance. The liquids component of the
5.8 MMBOE revision consisted of a 14.8 MMBOE increase that was primarily related
to North Ward Estes, where additional field areas are now planned for CO2 injection and where the total
amount of CO2 planned for
injection into previously identified flood pattern areas has been
increased. The gas component of the 5.8 MMBOE revision consisted of a
9.0 MMBOE decrease that was primarily related to the Sulphur Creek field, where
reserve assignments for proved developed producing as well as proved undeveloped
well locations were adjusted downward to reflect the current performance of
producing wells.
Proved undeveloped
reserves. From December 31, 2008 to December 31, 2009, our
proved undeveloped reserves (“PUDs”) increased 26% or 20.4
MMBOE. This increase in proved undeveloped reserves was primarily
attributable to additional PUDs estimated at the Sanish and Parshall fields as
well as the North Ward Estes field. The Sanish and Parshall field PUD
extensions resulted from our significant drilling activity in those areas during
2009 and the related proved undeveloped well locations therefore
added. The additional PUDs estimated at North Ward Estes in 2009
related to new field areas now planned for CO2 injection and to previously
identified flood pattern areas where the total CO2 planned for injection has now
been increased. These PUD increases were partially offset by (i) 3.1
MMBOE in PUDs that were removed from the proved undeveloped reserve category
pursuant to the new SEC rules on oil and gas reserve estimation, which in most
cases disallow proved undeveloped reserves to remain in the PUD category for a
period of more than 5 years, and (ii) 5.5 MMBOE of PUDs that were converted into
proved developed reserves due to 39 proved undeveloped well locations that were
drilled and placed on production during 2009. We incurred $69.9
million in capital expenditures, or $12.71 per BOE, to drill and bring on-line
these 39 PUD locations.
The
quantities of PUDs that remain undeveloped after having been disclosed as proved
undeveloped reserves for a period of five years or more are insignificant as of
December 31, 2009. However, we do have material quantities of proved
undeveloped reserves at our North Ward Estes field that will remain in the PUD
category for periods extending beyond five years. Due to the large
areal extent of the field, the CO2 enhanced recovery project will
progress through the field in a sequential manner as earlier injection areas are
completed and new injection areas are initiated. This staged development
is necessary to allow efficient use of purchased and recycled CO2 as well as to enable facilities
to be properly sized for the most economical operation of the
field.
Probable
reserves. Estimates of probable developed and undeveloped
reserves are inherently imprecise. When producing an estimate of the
amount of oil and gas that is recoverable from a particular reservoir, an
estimated quantity of probable reserves is an estimate that is as likely as not
to be achieved. Estimates of probable reserves are also continually
subject to revision based on production history, results of additional
exploration and development, price changes and other factors.
We use
deterministic methods to estimate probable reserve quantities, and when
deterministic methods are used, it is as likely as not that actual remaining
quantities recovered will exceed the sum of estimated proved plus probable
reserves. Probable reserves may be assigned to areas of a reservoir
adjacent to proved reserves where data control or interpretations of available
data are less certain, even if the interpreted reservoir continuity of structure
or productivity does not meet the reasonable certainty
criterion. Probable reserves may be assigned to areas that are
structurally higher than the proved area if these areas are in communication
with the proved reservoir. Probable reserves estimates also include
potential incremental quantities associated with a greater percentage recovery
of the hydrocarbons in place than assumed for proved reserves.
Reductions
in probable reserves during 2009 were primarily attributable to probable
reserves in the Sanish and Parshall fields that were converted into proved
reserves and therefore transferred out of the probable reserve category into
proved. In addition, the participation agreement that we entered into
in 2009 to farmout a portion of our interest in 26 units in the western part of
our Sanish field also decreased our probable reserve quantities during
2009.
Possible
reserves. Estimates of possible developed and undeveloped
reserves are also inherently imprecise. When producing an estimate of
the amount of oil and gas that is recoverable from a particular reservoir, an
estimated quantity of possible reserves is an estimate that might be achieved,
but only under more favorable circumstances than are
likely. Estimates of possible reserves are also continually subject
to revision based on production history, results of additional exploration and
development, price changes and other factors.
We use
deterministic methods to estimate possible reserve quantities, and when
deterministic methods are used to estimate possible reserve quantities, the
total quantities ultimately recovered from a project have a low probability of
exceeding proved plus probable plus possible reserves. Possible
reserves may be assigned to areas of a reservoir adjacent to probable reserves
where data control and interpretations of available data are progressively less
certain. Frequently, this will be in areas where geoscience and
engineering data are unable to define clearly the area and vertical limits of
commercial production from the reservoir by a defined
project. Possible reserves also include incremental quantities
associated with a greater percentage recovery of the hydrocarbons in place than
the recovery quantities assumed for probable reserves.
Possible
reserves may be assigned where geoscience and engineering data identify directly
adjacent portions of a reservoir within the same accumulation that may be
separated from proved areas by faults with displacement less than formation
thickness or other geological discontinuities and that have not been penetrated
by a wellbore, and we believe that such adjacent portions are in communication
with the known (proved) reservoir. Possible reserves may be assigned
to areas that are structurally higher or lower than the proved area if these
areas are in communication with the proved reservoir.
Possible
reserves increased during 2009 primarily due to (i) North Ward Estes where
additional field areas are now planned for CO2 injection and where the total
amount of CO2 planned for
injection into previously identified flood pattern areas has been increased, and
(ii) the Sanish and Parhsall fields where additional possible reserves were
estimated for continued development of the Bakken formation and the anticipated
development of the Three Forks formations.
Preparation
of reserves estimates.
The
Company maintains adequate and effective internal controls over the reserve
estimation process as well as the underlying data upon which reserve estimates
are based. The primary inputs to the reserve estimation process are
comprised of technical information, financial data, ownership interests and
production data. All field and reservoir technical information, which
is updated annually, is assessed for validity when the reservoir engineers hold
technical meetings with geoscientists, operations and land personnel to discuss
field performance and to validate future development plans. Current
revenue and expense information is obtained from the Company’s accounting
records, which are subject to external quarterly reviews, annual audits and
their own set of internal controls over financial reporting. Internal
controls over financial reporting are assessed for effectiveness annually using
the criteria set forth in Internal Control – Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission. All
current financial data such as commodity prices, lease operating expenses,
production taxes and field commodity price differentials are updated in the
reserve database and then analyzed to ensure that they have been entered
accurately and that all updates are complete. The Company’s current
ownership in mineral interests and well production data are also subject to the
aforementioned internal controls over financial reporting, and they are
incorporated in the reserve database as well and verified to ensure their
accuracy and completeness. Once the reserve database has been
entirely updated with current information, and all relevant technical support
material has been assembled, Whiting’s independent engineering firm Cawley,
Gillespie & Associates, Inc. (“CG&A”) meets with Whiting’s technical
personnel in the Company’s Denver and Midland offices to review field
performance and future development plans in order to further verify their
validity. Following these reviews the reserve database is furnished
to CG&A so that they can prepare their independent reserve estimates and
final report. Access to the Company’s reserve database is restricted
to specific members of the reservoir engineering department.
CG&A
is a Texas Registered Engineering Firm. Our primary contact at CG&A is
Mr. Robert Ravnaas, Executive Vice President. Mr. Ravnaas is a State of
Texas Licensed Professional Engineer. See Exhibit 99.2 of this Annual
Report on Form 10-K for the Report of Cawley, Gillespie & Associates, Inc.
and further information regarding the professional qualifications of Mr.
Ravnaas.
Our Vice
President of Reservoir Engineering/ Acquisitions is responsible
for overseeing the preparation of the reserves estimates. He has over
36 years of experience, the majority of which has involved reservoir engineering
and reserve estimation, holds a Bachelor’s Degree in Petroleum Engineering from
the University of Wyoming, holds an MBA from the University of Denver and is a
registered Professional Engineer. He has also served on the national
Board of Directors of the Society of Petroleum Evaluation
Engineers.
Acreage
The
following table summarizes gross and net developed and undeveloped acreage by
state at December 31, 2009. 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
|
32,929 | 8,951 | - | - | 32,929 | 8,951 | ||||||||||||||||||
|
Colorado
|
40,284 | 18,571 | 22,205 | 7,489 | 62,489 | 26,060 | ||||||||||||||||||
|
Louisiana
|
47,457 | 10,718 | 4,304 | 2,294 | 51,761 | 13,012 | ||||||||||||||||||
|
Michigan
|
140,825 | 63,510 | 40,673 | 24,128 | 181,498 | 87,638 | ||||||||||||||||||
|
Montana
|
42,382 | 13,875 | 8,753 | 4,227 | 51,135 | 18,102 | ||||||||||||||||||
|
North
Dakota
|
313,022 | 155,742 | 307,712 | 178,141 | 620,734 | 333,883 | ||||||||||||||||||
|
Oklahoma
|
91,428 | 59,781 | 772 | 471 | 92,200 | 60,252 | ||||||||||||||||||
|
Texas
|
216,109 | 135,818 | 52,189 | 41,751 | 268,298 | 177,569 | ||||||||||||||||||
|
Utah
|
23,090 | 14,162 | 257,566 | 61,650 | 280,656 | 75,812 | ||||||||||||||||||
|
Wyoming
|
96,955 | 55,496 | 75,638 | 50,365 | 172,593 | 105,861 | ||||||||||||||||||
|
Other*
|
15,063 | 8,703 | 3,524 | 1,674 | 18,587 | 10,377 | ||||||||||||||||||
|
Total
|
1,059,544 | 545,327 | 773,336 | 372,190 | 1,832,880 | 917,517 | ||||||||||||||||||
|
*
|
Other
includes Alabama, Arkansas, Kansas, Mississippi and New
Mexico.
|
|
**
|
Out
of a total of approximately 773,300 gross (372,200 net) undeveloped acres
as of December 31, 2009, the portion of our net undeveloped acres that is
subject to expiration over the next three years, if not successfully
developed or renewed, is approximately 14% in 2010, 18% in 2011, and 8% in
2012.
|
Production
History
The
following table presents historical information about our produced oil and gas
volumes:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Oil
production (MMBbls)
|
15.4 | 12.4 | 9.6 | |||||||||
|
Natural
gas production (Bcf)
|
29.3 | 30.4 | 30.8 | |||||||||
|
Total
production (MMBOE)
|
20.3 | 17.5 | 14.7 | |||||||||
|
Daily
production (MBOE/d)
|
55.5 | 47.9 | 40.3 | |||||||||
|
North
Ward Estes field production (1)
|
||||||||||||
|
Oil
production (MMBbls)
|
2.2 | 1.9 | 1.6 | |||||||||
|
Natural
gas production (Bcf)
|
0.6 | 1.2 | 1.8 | |||||||||
|
Total
production (MMBOE)
|
2.3 | 2.1 | 2.0 | |||||||||
|
Average
sales prices (including transfers):
|
||||||||||||
|
Oil
(per Bbl)
|
$ | 52.51 | $ | 86.99 | $ | 64.57 | ||||||
|
Natural
gas (per Mcf)
|
$ | 3.75 | $ | 7.68 | $ | 6.19 | ||||||
|
Average
production costs:
|
||||||||||||
|
Production
costs (per BOE) (2)
|
$ | 11.10 | $ | 12.81 | $ | 13.08 | ||||||
|
(1)
|
The
North Ward Estes field was our only field that contained 15% or more of
our total proved reserve volumes as of December 31,
2009.
|
|
(2)
|
Production
costs reported above exclude from lease operating expenses ad valorem
taxes of $12.2 million ($0.61 per BOE), $16.8 million ($0.96 per BOE), and
$16.5 million ($1.12 per BOE) for the years ended December 31, 2009, 2008
and 2007, respectively.
|
Productive
Wells
The
following table summarizes gross and net productive oil and natural gas wells by
region at December 31, 2009. A net well is our percentage
ownership of a gross well. Wells in which our interest is limited to
royalty and overriding royalty interests are excluded.
|
Oil
Wells
|
Natural
Gas Wells
|
Total
Wells(1)
|
||||||||||||||||||||||
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||||||||||||||
|
Permian
Basin
|
4,030 | 1,772 | 395 | 132 | 4,425 | 1,904 | ||||||||||||||||||
|
Rocky
Mountains
|
2,199 | 481 | 481 | 262 | 2,680 | 743 | ||||||||||||||||||
|
Mid-Continent
|
568 | 358 | 201 | 83 | 769 | 441 | ||||||||||||||||||
|
Gulf
Coast
|
95 | 51 | 470 | 122 | 565 | 173 | ||||||||||||||||||
|
Michigan
|
78 | 41 | 1,099 | 417 | 1,177 | 458 | ||||||||||||||||||
|
Total
|
6,970 | 2,703 | 2,646 | 1,016 | 9,616 | 3,719 | ||||||||||||||||||
|
(1)
|
133
wells are multiple completions. These 133 wells contain a total
of 326 completions. One or more completions in the same bore
hole are counted as one well.
|
We have an interest in or operate 16
enhanced oil recovery projects, which include both secondary (waterflood) and
tertiary (CO2 injection)
recovery efforts, and aggregate production from such enhanced oil recovery
fields averaged 17.3 MBOE/d during 2009 or 31.2% of our 2009 daily
production. For these areas, we need to use enhanced recovery
techniques in order to maintain oil and gas production from these
fields.
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. As of
December 31, 2009, we were drilling five gross (2.7 net) wells in the Sanish
field and one gross and net well in the Flat Rock field. All of these
wells were intended to be productive wells rather than service
wells.
The
following table sets forth our drilling activity for the last three
years. A dry well is an exploratory, development or extension well
that proves to be incapable of producing either oil or gas in sufficient
quantities to justify completion as an oil or gas well. A productive
well is an exploratory, development or extension well that is not a dry
well. 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.
|
Gross
Wells
|
Net
Wells
|
|||||||||||||||||||||||
|
Productive
|
Dry
|
Total
|
Productive
|
Dry
|
Total
|
|||||||||||||||||||
|
2009:
|
||||||||||||||||||||||||
|
Development
|
137 | 4 | 141 | 50.2 | 2.6 | 52.8 | ||||||||||||||||||
|
Exploratory
|
1 | 3 | 4 | 0.9 | 2.5 | 3.4 | ||||||||||||||||||
|
Total
|
138 | 7 | 145 | 51.1 | 5.1 | 56.2 | ||||||||||||||||||
|
2008:
|
||||||||||||||||||||||||
|
Development
|
283 | 20 | 303 | 113.3 | 9.2 | 122.5 | ||||||||||||||||||
|
Exploratory
|
2 | 3 | 5 | 1.9 | 1.3 | 3.2 | ||||||||||||||||||
|
Total
|
285 | 23 | 308 | 115.2 | 10.5 | 125.7 | ||||||||||||||||||
|
2007:
|
||||||||||||||||||||||||
|
Development
|
262 | 5 | 267 | 128.6 | 3.8 | 132.4 | ||||||||||||||||||
|
Exploratory
|
9 | 1 | 10 | 6.1 | 0.1 | 6.2 | ||||||||||||||||||
|
Total
|
271 | 6 | 277 | 134.7 | 3.9 | 138.6 | ||||||||||||||||||
As of
December 31, 2009, six operated drilling rigs and 32 operated workover rigs were
active on our properties. We were also participating in the drilling
of three non-operated wells, two of which are located in the Parshall field and
one in the Gulf Coast area. The breakdown of our operated rigs is as
follows:
|
Region
|
Drilling
|
Workover
|
||||||
|
Rocky
Mountain
|
6 | 7 | ||||||
|
Permian
|
- | 4 | ||||||
|
Mid-Continent/Michigan
|
- | 1 | ||||||
|
North
Ward Estes
|
- | 19 | ||||||
|
Postle
|
- | 1 | ||||||
|
Gulf
Coast
|
- | - | ||||||
|
Total
|
6 | 32 | ||||||
Delivery
Commitments
Our
production sales agreements contain customary terms and conditions for the oil
and natural gas industry, generally provide for sales based on prevailing market
prices in the area, and generally have terms of one year or less. We have
also entered into physical delivery contracts which require us to deliver fixed
volumes of natural gas. As of December 31, 2009, we had delivery
commitments of 9.8 Bcf (or 34% of total 2009 natural gas production), 9.1 Bcf
(31%) and 5.3 Bcf (18%) for the years ended December 31, 2010, 2011 and 2012,
respectively. These contracts were related to production at our Boies
Ranch prospect in Rio Blanco County, Colorado, at our Antrim Shale wells in
Michigan and at our Flat Rock field in Uintah County, Utah. We believe our
production and reserves are adequate to meet these delivery
commitments. See “Quantitative and Qualitative Disclosure about
Market Risk” in Item 7A of this Annual Report on Form 10-K for more information
about these contracts.
|
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.
|
Reserved
|
EXECUTIVE OFFICERS OF THE
REGISTRANT
The
following table sets forth certain information, as of February 15, 2010,
regarding the executive officers of Whiting Petroleum Corporation:
|
Name
|
Age
|
Position
|
|
James
J. Volker
|
63
|
Chairman,
President and Chief Executive Officer
|
|
James
T. Brown
|
57
|
Senior
Vice President
|
|
Bruce
R. DeBoer
|
57
|
Vice
President, General Counsel and Corporate Secretary
|
|
Heather
M. Duncan
|
39
|
Vice
President, Human Resources
|
|
Jack
R. Ekstrom
|
63
|
Vice
President, Corporate and Government Relations
|
|
J.
Douglas Lang
|
60
|
Vice
President, Reservoir Engineering/Acquisitions
|
|
Rick
A. Ross
|
51
|
Vice
President, Operations
|
|
David
M. Seery
|
55
|
Vice
President, Land
|
|
Michael
J. Stevens
|
44
|
Vice
President and Chief Financial Officer
|
|
Mark
R. Williams
|
53
|
Vice
President, Exploration and Development
|
|
Brent
P. Jensen
|
40
|
Controller
and Treasurer
|
The
following biographies describe the business experience of our executive
officers:
James J. Volker joined us in
August 1983 as Vice President of Corporate Development and served in that
position through April 1993. In March 1993, he became a contract
consultant to us and served in that capacity until August 2000, at which time he
became Executive Vice President and Chief Operating Officer. Mr.
Volker was appointed President and Chief Executive Officer and a director in
January 2002 and Chairman of the Board in January 2004. Mr. Volker
was co-founder, Vice President and later President of Energy Management
Corporation from 1971 through 1982. He has over 30 years of
experience in the oil and gas industry. Mr. Volker has a degree in
finance from the University of Denver, an MBA from the University of Colorado
and has completed H. K. VanPoolen and Associates’ course of study in reservoir
engineering.
James T. Brown joined us in
May 1993 as a consulting engineer. In March 1999, he became
Operations Manager, in January 2000, he became Vice President of Operations, and
in May 2007, he became Senior Vice President. Mr. Brown has over 30
years of oil and gas experience in the Rocky Mountains, Gulf Coast, California
and Alaska. Mr. Brown is a graduate of the University of Wyoming,
with a Bachelor’s Degree in civil engineering, and the University of Denver,
with an MBA.
Bruce R. DeBoer joined us as our Vice
President, General Counsel and Corporate Secretary in January
2005. From January 1997 to May 2004, Mr. DeBoer served as Vice
President, General Counsel and Corporate Secretary of Tom Brown, Inc., an
independent oil and gas exploration and production company. Mr.
DeBoer has over 25 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 13 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 Senior Professional in Human
Resources.
Jack R. Ekstrom joined us in
October 2008 as Executive Director, Corporate Communications and Investor
Relations, and became Vice President, Corporate and Government Relations in
January 2010. From 2004 to 2008, Mr. Ekstrom served as the Director of
Government Affairs for Pioneer Natural Resources, an independent oil and gas
exploration and production company. Prior to this he served as the
Director of Government Affairs for Evergreen Resources and Forest Oil. He
has 35 years of experience in the oil and gas industry. Mr. Ekstrom is a
Director of the Colorado Oil & Gas Association and the Independent Petroleum
Association of Mountain States, and is a past chairman of the Western Business
Roundtable and past president of the Denver Petroleum Club. He holds
a Bachelor of Arts Degree in Communications from Augustana College in Rock
Island, Illinois.
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 36 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 27 years of oil and gas
experience, including 17 years with Amoco Production Company where he served in
various technical and managerial positions. Mr. Ross holds a Bachelor
of Science Degree in Mechanical Engineering from the South Dakota School of
Mines and Technology. He is a registered Professional Engineer and is
currently Chairman of the North Dakota Petroleum Council.
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 29 years of
land experience including staff and managerial positions with Marathon Oil
Company. Mr. Seery holds a Bachelor of Science Degree in Business
Administration from the University of Montana.
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 and has been Vice President of
Exploration and Development since December 1999. He has 27 years of
domestic and international experience in the oil and gas
industry. Mr. Williams holds a Master’s Degree in geology from the
Colorado School of Mines and 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 16 years of oil and gas
accounting experience and is a Certified Public Accountant. Mr.
Jensen holds a Bachelor of Arts degree from the University of California, Los
Angeles.
Executive
officers are elected by, and serve at the discretion of, the Board of
Directors. There are no family relationships between any of our
directors or executive officers.
PART
II
|
Item 5.
|
Market for the Registrant’s Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity
Securities
|
Whiting
Petroleum Corporation’s common stock is traded on the New York Stock Exchange
under the symbol “WLL”. The following table shows the high and low
sale prices for our common stock for the periods presented.
|
High
|
Low
|
|||||||
|
Fiscal
Year Ended December 31, 2009
|
||||||||
|
Fourth
Quarter (Ended December 31, 2009)
|
$ | 75.65 | $ | 52.67 | ||||
|
Third
Quarter (Ended September 30, 2009)
|
$ | 59.41 | $ | 29.77 | ||||
|
Second
Quarter (Ended June 30, 2009)
|
$ | 49.94 | $ | 24.54 | ||||
|
First
Quarter (Ended March 31, 2009)
|
$ | 44.99 | $ | 19.26 | ||||
|
Fiscal
Year Ended December 31, 2008
|
||||||||
|
Fourth
Quarter (Ended December 31, 2008)
|
$ | 69.58 | $ | 24.36 | ||||
|
Third
Quarter (Ended September 30, 2008)
|
$ | 112.42 | $ | 62.09 | ||||
|
Second
Quarter (Ended June 30, 2008)
|
$ | 108.53 | $ | 63.07 | ||||
|
First
Quarter (Ended March 31, 2008)
|
$ | 66.19 | $ | 44.60 | ||||
On
February 15, 2010, there were 691 holders of record of our common
stock.
We have
not paid any dividends on our common stock since we were incorporated in July
2003, and we do not anticipate paying any such 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. Except for limited exceptions, which include the
payment of dividends on our 6.25% convertible perpetual preferred stock, our
credit agreement restricts our ability to make any dividends or distributions on
our common stock. Additionally, the indentures governing our senior
subordinated notes contain restrictive covenants that may limit our ability to
pay cash dividends on our common stock and our 6.25% convertible perpetual
preferred stock.
Information
relating to compensation plans under which our equity securities are authorized
for issuance is set forth in Part III, Item 12 of this Annual Report
on Form 10-K.
The
following information in this Item 5 of this Annual Report on Form 10-K is
not deemed to be “soliciting material” or to be “filed” with the SEC or subject
to Regulation 14A or 14C under the Securities Exchange Act of 1934 or to
the liabilities of Section 18 of the Securities Exchange Act of 1934, and
will not be deemed to be incorporated by reference into any filing under the
Securities Act of 1933 or the Securities Exchange Act of 1934, except to the
extent we specifically incorporate it by reference into such a
filing.
The
following graph compares on a cumulative basis changes since December 31, 2004
in (a) the total stockholder return on our common stock with (b) the
total return on the Standard & Poor’s Composite 500 Index and
(c) the total return on the Dow Jones US Oil Companies, Secondary
Index. Such changes have been measured by dividing (a) the sum
of (i) the amount of dividends for the measurement period, assuming
dividend reinvestment, and (ii) the difference between the price per share
at the end of and the beginning of the measurement period, by (b) the price
per share at the beginning of the measurement period. The graph
assumes $100 was invested on December 31, 2004 in our common stock, the
Standard & Poor’s Composite 500 Index and the Dow Jones US Oil
Companies, Secondary Index.
|
12/31/04
|
12/31/05
|
12/31/06
|
12/31/07
|
12/31/08
|
12/31/09
|
|||||||||||||||||||
|
Whiting
Petroleum Corporation
|
$ | 100 | $ | 132 | $ | 154 | $ | 191 | $ | 111 | $ | 236 | ||||||||||||
|
Standard &
Poor’s Composite 500 Index
|
100 | 103 | 117 | 121 | 75 | 92 | ||||||||||||||||||
|
Dow
Jones US Oil Companies, Secondary Index
|
100 | 164 | 172 | 245 | 145 | 202 | ||||||||||||||||||
|
Item 6.
|
Selected Financial
Data
|
The
consolidated statements of income and statements of cash flows information for
the years ended December 31, 2009, 2008 and 2007 and the consolidated
balance sheet information at December 31, 2009 and 2008 are derived from our
audited financial statements included elsewhere in this report. The
consolidated statements of income and statements of cash flows information for
the years ended December 31, 2006 and 2005 and the consolidated balance sheet
information at December 31, 2007, 2006 and 2005 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: Additional interests in North Ward Estes, November 1, 2009
and October 1, 2009; Flat Rock Natural Gas Field, May 30, 2008; Utah
Hingeline, August 29, 2006; Michigan Properties, August 15, 2006;
North Ward Estes and Ancillary Properties, October 4, 2005; Postle
Properties, August 4, 2005; Limited Partnership Interests, June 23,
2005; and Green River Basin, March 31, 2005.
|
Year
Ended December 31,
|
||||||||||||||||||||
|
2009
|
2008
|
2007
|
2006
|
2005
|
||||||||||||||||
|
(dollars
in millions, except per share data)
|
||||||||||||||||||||
|
Consolidated
Statements of Income Information:
|
||||||||||||||||||||
|
Revenues
and other income:
|
||||||||||||||||||||
|
Oil
and natural gas sales
|
$ | 917.6 | $ | 1,316.5 | $ | 809.0 | $ | 773.1 | $ | 573.2 | ||||||||||
|
Gain
(loss) on hedging activities
|
38.8 | (107.6 | ) | (21.2 | ) | (7.5 | ) | (33.4 | ) | |||||||||||
|
Amortization
of deferred gain on sale
|
16.6 | 12.1 | — | — | — | |||||||||||||||
|
Gain
on sale of properties
|
5.9 | — | 29.7 | 12.1 | — | |||||||||||||||
|
Interest
income and other
|
0.5 | 1.1 | 1.2 | 1.1 | 0.6 | |||||||||||||||
|
Total
revenues and other income
|
979.4 | 1,222.1 | 818.7 | 778.8 | 540.4 | |||||||||||||||
|
Costs
and expenses:
|
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