fp_Cover 3/15/13 2:44 PM Page 1
1700 Broadway, Suite 2300
Denver, Colorado 80290-2300
Tel: (303) 837-1661
Fax: (303) 861-4023
www.whiting.com
Whiting Petroleum Corporation
ANNUAL REPORT 20 12
YEAR OF RECORD PRODUCTION
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ABOUT THE COVER
CONTENTS
EX ECUTIVE OFFICERS
OTHER OFFICERS
BOARD OF DIRECTORS
We are a Bakken oil company. With a focus on
the Bakken/Three Forks in the Williston Basin, we
generated record production of 30.21 MMBOE or
82,540 BOE per day in 2012. According to the
December 2012 Oil and Gas Production Report
published by the North Dakota State Industrial
Commission, Department of Minerals, Oil and Gas
Division, Whiting was the number one oil producer
in North Dakota at 66,155.7 barrels per day. North
Dakota is the second largest oil producing state
in the United States.
We were one of the first successful operators in the
Bakken/Three Forks Hydrocarbon System in the
Williston Basin with the discovery of our Sanish field
in early 2007. With our experience and expertise in
operating in the Williston Basin, we expect a very
good year for organic growth in reserves and production
in 2013. We expect to generate year-over-year
production growth of between 12% and 16%. In the
Bakken and Three Forks hydrocarbon system in the
Williston Basin alone, we hold more than 700,000
net acres and continue to add to that position.
Importantly, our average cost in this acreage is $521
per net acre.
ABBREVIATIONS
Bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in
this report in reference to oil, NGLs and other liquid hydrocarbons.
Bcf: One billion cubic feet of natural gas.
BOE: One stock tank barrel equivalent of oil, calculated by
converting natural gas volumes to equivalent oil barrels at a ratio
of six Mcf to one Bbl of oil.
BOE/d: Barrels of oil equivalent per day.
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.
EOR: Enhanced Oil Recovery is a tertiary recovery method in
which injectants, such as CO2, are introduced into a reservoir to
enhance hydrocarbon recovery.
MBOE: One thousand BOE.
Mcf: One thousand cubic feet of natural gas.
Mcfe: One thousand cubic feet of natural gas equivalent.
MMBbl: One million barrels.
MMBOE: One million BOE.
MMcf: One million cubic feet of natural gas.
MMcf/d: One million cubic feet of natural gas per day.
NGLs: Natural gas liquids.
PDP: Proved developed producing.
PDNP: Proved developed nonproducing.
PUD: Proved undeveloped.
Corporate Overview . . . . . . . . . . . . . . . . . . . . . . . 1
Financial and Operations Summary . . . . . . . . . . . 2
Letter to the Shareholders . . . . . . . . . . . . . . . . . . 4
Drilling and Operations Overview . . . . . . . . . . . . 6
Williston Basin Oil Plays . . . . . . . . . . . . . . . . . . . . 8
Other Development Areas . . . . . . . . . . . . . . . . . 12
Optimization Programs . . . . . . . . . . . . . . . . . . . 14
Building for the Future . . . . . . . . . . . . . . . . . . . . 16
Board of Directors . . . . . . . . . . . . . . . . . . . . . . . 20
Annual Report on Form 10-K . . . . . . . . . . . . . . . 21
Corporate Investor Information
Inside back cover
RESERVE AND RESOURCE INFORMATION
Whiting uses in this annual report the terms proved, probable
and possible reserves. Proved reserves are 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 under existing economic conditions, operating
methods and government regulations prior to the time at which
contracts providing the right to operate expire, unless eviden-
ceindicates that renewal is reasonably certain. Probable reserves are
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. Possible reserves are reserves that are less certain to be
recovered than probable reserves. Estimates of probable and possible
reserves which may potentially be recoverable through additional
drilling or recovery techniques are by nature more uncertain than
estimates of proved reserves and accordingly are subject to substan-
tially greater risk of not actually being realized by the Company.
Whiting uses in this annual report the term “total resources,”
which consists of contingent and prospective resources, which SEC
rules prohibit in filings of U.S. registrants. Contingent resources are
resources that are potentially recoverable but not yet considered
mature enough for commercial development due to technological
or business hurdles. For contingent resources to move into the
reserves category, the key conditions, or contingencies, that pre-
vented commercial development must be clarified and removed.
Prospective resources are estimated volumes associated with undis-
covered accumulations. These represent quantities of petroleum
which are estimated to be potentially recoverable from oil and gas
deposits identified on the basis of indirect evidence but which
have not yet been drilled. This class represents a higher risk than
contingent resources since the risk of discovery is also added. For
prospective resources to become classified as contingent resources,
hydrocarbons must be discovered, the accumulations must be
further evaluated and an estimate of quantities that would be
recoverable under appropriate development projects prepared.
Estimates of resources are by nature more uncertain than reserves
and accordingly are subject to substantially greater risk of not
actually being realized by the Company.
FORWARD-LOOKING STATEMENTS
This annual report contains forward-looking statements. Please
refer to “Forward-Looking Statements” on pages 70–71 of the
attached Annual Report on Form 10-K for an explanation of these
types of statements. These statements should be considered in light
of the “Risk Factors” set forth on page 22 of the attached Annual
Report on Form 10-K.
JAMES J.VOLKER
Chairman of the Board
and Chief Executive Officer
PETER W. HAGIST
Vice President, Permian Operations
for Whiting Oil and Gas Corporation
JAMES T. BROWN
President and Chief Operating Officer
CHUCK LACOUTURE
Vice President, Marketing
DIRECTOR SINCE
JAMES J. VOLKER 2003
Chairman of the Board
and Chief Executive Officer
for Whiting Oil and Gas Corporation
THOMAS L. ALLER *+ 2003
MARK D. SONNENFELD
Vice President, Geoscience
President
Interstate Power and
Light Company,
for Whiting Oil and Gas Corporation
an Alliant Energy Company
Vice President and Chief Financial Officer
JOHN K. SOUTHWELL
D. SHERWIN ARTUS^ 2006
Vice President, Permian Exploration
for Whiting Oil and Gas Corporation
Retired President and CEO
of Whiting
MARK R. WILLIAMS
Senior Vice President, Exploration
and Development
MICHAEL J. STEVENS
BRUCE R. DEBOER
Vice President, General Counsel
and Corporate Secretary
J. DOUGLAS LANG
and Acquisitions
DAVID M. SEERY
Vice President, Land
RICK A. ROSS
Vice President, Operations
BRENT P. JENSEN
Controller and Treasurer
Vice President, Reservoir Engineering
for Whiting Oil and Gas Corporation
DOUGLAS L. WALTON
Vice President and
National Drilling Manager
ERIC K. HAGEN
Vice President, Investor Relations
JACK R. EKSTROM
Vice President,
Corporate and Government Relations
HEATHER M. DUNCAN
Vice President, Human Resources
GALE N. KEITHLINE
Vice President, Information Technology
THOMAS P. BRIGGS*+(1) 2006
Inactive Certified
Public Accountant
PHILIP E. DOTY*^ 2010
Certified Public Accountant
WILLIAM N. HAHNE +^ 2007
Past Chief Operating Officer
Petrohawk Energy
ALLAN R. LARSON^ 2011
Consulting Geologist
* Audit Committee
+ Compensation Committee
^ Nominating and Governance Committee
(1) Mr. Briggs’ term expires at the 2013
annual meeting.
CORPORATE OFFICES
TRANSFER AGENT
Whiting Petroleum Corporation
Please direct communication regarding
1700 Broadway, Suite 2300
individual stock records and address
Denver, Colorado 80290-2300
changes to:
INFORMATION UPDATES
Whiting’s quarterly financial results and
other information are available on our
website at www.whiting.com
Securities analysts, investors and the
www.computershare.com
Tel: (303) 837-1661
Fax: (303) 861-4023
www.whiting.com
INVESTOR RELATIONS
financial media should contact:
John B. Kelso
Director, Investor Relations
Tel: (303) 837-1661
Eric K. Hagen
Vice President, Investor Relations
Tel: (303) 837-1661
Computershare Trust Company, N.A.
350 Indiana Street, Suite 800
Golden, Colorado 80401
Tel: (303) 262-0600
Fax: (303) 262-0700
INDEPENDENT
PETROLEUM ENGINEERS
Cawley, Gillespie & Associates, Inc.
INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
Deloitte & Touche LLP
ANNUAL REPORT ON FORM 10-K
Upon request, the Company will
provide, without charge, copies of the
2012 Annual Report on Form 10-K
as filed with the Securities and
Exchange Commission.
ANNUAL MEETING
Tuesday, May 7, 2013
10:00 A.M. (DENVER TIME)
1750 Welton Street
Denver, Colorado 80202
The Grand Hyatt Hotel – Grand Ballroom
STOCK EXCHANGE LISTING
New York Stock Exchange, trading
symbol: WLL
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C O R P O R AT E O V E RV I E W
Whiting Petroleum Corporation, a Delaware
corporation, is an independent oil and gas company
that explores for, develops, acquires and produces
crude oil, NGLs and natural gas primarily
in the Rocky Mountain, Permian Basin,
Mid-Continent, Michigan and Gulf Coast
regions of the United States. The Company’s
largest projects are in the Bakken and Three
Forks plays in North Dakota and its Enhanced
Oil Recovery fields in Oklahoma and Texas. The
Company trades publicly under the symbol
WLL on the New York Stock Exchange.
We are focused on increasing
shareholder value by executing on
the following:
• Well managed and fiscally responsible
development of the Bakken and Three Forks
hydrocarbon system in the Williston Basin,
where we hold more than 700,000 net acres
and continue to add to that position.
• Establishing our Redtail Niobrara play in the
DJ Basin as a major resource play.
• Further exploration activities in order to discover
new resource plays.
• Increasing production and proved reserves from
our North Ward Estes EOR project.
HEADQUARTERS
Denver, Colorado
FIELD OFFICES
WHITING PROPERTIES
The following table summarizes our proved, probable and possible reserves:
Oil
(MMBbl)
NGLs
(MMBbl)
PROVED
PROBABLE
POSSIBLE
301.3
85.0
123.2
40.1
11.9
21.9
3 P R E S E R V E S ( 1 )
Natural
Gas
(Bcf)
224.3
109.6
156.4
Total
(MMBOE)
378.8
115.2
171.2
%
Oil
80%
74%
72%
Pre-Tax
PV10% Value
(in MM)
$7,284(2)
$1,262(3)
$1,359(3)
% of
Total
73%
13%
14%
(1) 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 NYMEX
price for each month within the 12 months ended December 31, 2012, pursuant to current SEC and FASB guidelines. The NYMEX prices used were $94.71/Bbl and $2.76/MMBtu.
(2) Pre-tax PV10% of Proved reserves 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 U.S. 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. As of December 31, 2012, our discounted future income taxes were $1,876.9 million and our standardized measure of after-tax
discounted future net cash flows was $5,407.0 million. 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.
(3) Pre-tax PV10% of probable or possible reserves represent the present value of estimated future revenues to be generated from the production of probable or possible reserves,
calculated net of estimated lease operating expenses, production taxes and future development costs, using costs as of the date of estimation without future escalation and using
12-month average prices, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization,
or future income taxes and discounted using an annual discount rate of 10%. With respect to pre-tax PV10% amounts for probable or possible reserves, there do not exist any directly
comparable U.S. GAAP measures, and such amounts do not purport to present the fair value of our probable and possible reserves.
1
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F I N A N C I A L & O P E R AT I O N S S U M M A R Y
(IN MILLIONS, EXCEPT PER SHARE, PER UNIT PRICES OR RATIO AMOUNTS)
2012
2011
2010
2009
2008
Income Statement and Cash Flow
Oil and Gas Sales
Earnings (Loss)
$ 2,137.7
$ 1,860.1
$ 1,475.3
$
917.5
$ 1,316.5
$ 414.1
$ 491.6
$ 336.7
$ (106.9)(1) $ 252.1
Earnings (Loss) per Share (Diluted)
$ 3.48
$ 4.14
$ 2.55
$
(1.18)(1) $
2.97
Weighted Average Shares Outstanding (Diluted)
119.028
118.668
107.846
100.088
84.894
Net Cash Provided by Operating Activities
$ 1,401.2
$ 1,192.1
$ 997.3
$ 453.8
$ 766.5
Net Cash Used in Investing Activities
$(1,780.3)
$(1,760.0)
$ (914.6)
$ (523.5)
$(1,138.5)
Net Cash Provided by (used in) Financing Activities $ 408.1
$ 564.8
$
(75.7)
$ 72.1
$ 366.8
Balance Sheet
Total Assets
Debt
$ 7,272.4
$ 6,045.6
$ 4,648.8
$ 4,029.5
$ 4,029.1
$ 1,800.0
$ 1,380.0
$ 800.0
$ 779.6
$ 1,239.8
Shareholders’ Equity
$ 3,453.2
$ 3,029.1
$ 2,531.3
$ 2,270.1
$ 1,808.8
Debt-to-Capitalization Ratio
34%
31%
24%
26%
41%
Production and Commodity Prices
Oil Production, MMBbl
Natural Gas Liquids Production, MMBbl
Natural Gas Production, Bcf
Production, MMBOE
23.1
2.8
25.8
30.2
18.3
2.1
26.4
24.8
17.5
1.5
27.4
23.6
13.9
1.5
29.3
20.3
11.3
1.1
30.4
17.5
Oil Sales Price, per Bbl Average, Excluding Hedging $ 83.86
$ 88.61
$ 72.61
$ 54.80
$ 89.59
Natural Gas Liquids Price, per Bbl Average
$ 39.36
$ 52.38
$ 47.33
$ 31.07
$ 61.06
Natural Gas Sales Price, per Mcf Average,
Excluding Hedging
$ 3.42
$ 4.92
$ 4.86
$ 3.75
$
7.68
Average Sales Price, per BOE Net of Hedging
$ 69.85
$ 73.88
$ 61.48
$ 45.01
$ 69.06
Year-End 2012 Well Count and Acreage Statistics
Total Wells
Developed Acreage
Undeveloped Acreage
GROSS
10,218
NET
3,927
1,277,411
680,338
1,324,667
883,316
(1) Includes after-tax, non-cash losses on hedging arrangements of $137.5 million or $2.75 per share.
2
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Proved Reserves as of December 31,
Oil, MMBbl
NGLs, MMBbl
Natural Gas, Bcf
Reserves, MMBOE
Reserves-to-Production Ratio (Reserves/Annual Production)
2012
301.3
40.1
224.3
378.8
12.6
2011
260.2
37.6
285.0
345.2
13.9
2010
224.2
30.1
303.5
304.9
12.9
2009
193.3
30.5
307.4
275.0
13.6
2008
160.0
20.0
354.8
239.1
13.6
Average Wellhead Oil Price per Bbl in Reserve Report
$ 87.15
$ 89.18
$ 73.14
$ 54.84
$ 38.93
Average Wellhead NGLs Price per Bbl in Reserve Report
$ 58.15
$ 62.93
$ 49.35
$ 35.44
$ 20.58
Average Wellhead Gas Price per Mcf in Reserve Report
$ 3.21
$ 4.39
$ 4.72
$ 3.77
$ 4.58
Reserves & Production per Region as of December 31, 2012
378.8 MMBOE
2%
1%
Q4 2012 — 86.1 MBOE/d
3%
2%
13%
33%
51%
9%
13%
73%
(cid:0) ROCKY MOUNTAINS (cid:0) PERMIAN BASIN (cid:0) MID-CONTINENT (cid:0) MICHIGAN (cid:0) GULF COAST
The following is a summary of Whiting’s changes in quantities of proved oil and gas reserves for the year ended
December 31, 2012:
Natural
Gas
(MMcf)
284,975
40,915
(13,987)
(25,827)
(61,812)
224,264
Total
(MBOE)
345,249
81,479
(10,611)
(30,209)
(7,148)
378,760
Balance – December 31, 2011
Extensions and discoveries
Sales of minerals in place
Production
Revisions to previous estimates
Balance – December 31, 2012
Oil
(MBbl)
260,144
68,134
(7,960)
(23,139)
4,106
301,285
NGLs
(MBbl)
37,609
6,526
(320)
(2,766)
(951)
40,098
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D E A R F E L L O W S H A R E H O L D E R S
gross (175 net) operated wells planned for 2013 and
have substantially added to our drilling inventory
through new discoveries and an active leasing
program. Based on independent engineering and
internal estimates, we project that we have a total
of 9,661 gross (4,503.2 net) potential future
drilling locations.
We will continue to focus on oil and natural gas
liquids in the foreseeable future. Currently, crude oil
trades at more than 25 times the price of natural gas,
which compares to their 6 to 1 heating equivalency
ratio. At year-end 2012, 80% of our proved reserves
and 77% of our production consisted of crude oil.
We expect that percentage to continue to increase
over the next several years. In the September 3, 2012
edition of the Oil & Gas Journal, we ranked 14th in
the world in terms of liquids proved reserves and
14th in the world in terms of liquids production for
public companies.
We believe we have some of the best geoscientists
in the oil and gas industry. This belief is evidenced by
discoveries and subsequent reserves and production
growth at our Sanish field and our Pronghorn and
Hidden Bench/Tarpon prospects. We are providing
our staff with the best tools available to enable their
continued success.
We also believe that we have garnered some of
the best young talent available in the industry. We
have been very active recruiting from colleges in
North Dakota, South Dakota, Montana, Texas and
Colorado. As we build for the future, more than 70%
of our new-hires in 2012 were 40 years old and under.
The average age of a Whiting employee has dropped
from 48 to 44 years old over the past two years.
All of us at Whiting are enthusiastic about our
prospects for growing long-term shareholder value.
On behalf of the Whiting Petroleum Corporation
Board of Directors and all of our dedicated employees,
thank you very much for your continuing interest in
Whiting Petroleum Corporation.
2012 was a record year for Whiting Petroleum,
and we are off to a great start in 2013. The develop-
ment of the fields we discovered in 2011 such as
Pronghorn, Hidden Bench, Tarpon and Redtail
generated excellent results in 2012. In the wake of
this development, we posted records in production,
proved reserves and discretionary cash flow. Accord-
ing to the December 2012 Oil and Gas Production
Report published by the North Dakota State Industrial
Commission, Department of Minerals, Oil and Gas
Division, Whiting was the number one oil producer
in North Dakota at 66,155.7 barrels per day in
December 2012.
We believe the following factors will lead to a
strong year in 2013 for Whiting and our shareholders:
(cid:0)• Optimization programs that should lead to efficient,
low-cost drilling and completion operations;
(cid:0)•
(cid:0)•
(cid:0)•
Infill/higher density pilot projects at Sanish,
Pronghorn and Hidden Bench;
Sincerely,
Solid cash flow and balance sheet;
Strong Bakken oil prices as differentials improve; and
(cid:0)• The emergence of our Redtail prospect as a major
resource play.
JAMES J. VOLKER
Chairman of the Board and Chief Executive Officer
We expect a very good year for organic growth
in reserves and production in 2013. We have 256
February 28, 2013
4
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D R I L L I N G A N D O P E R AT I O N S O V E RV I E W
The table below summarizes Whiting’s drilling activity
and exploration and development costs incurred for
the fourth quarter and the twelve months ended
December 31, 2012:
Gross/Net Wells Completed
PRODUCING PRODUCING
NON-
TOTAL NEW
DRILLING
% SUCCESS
RATE
CAPEX
(IN MM)
Q4 12
124/63.0
4/3.9
128/66.9
96.9%/94.2% $ 574.1
Pictured above is our Big Tex prospect, located primarily in Pecos
County, Texas. We have established production on three corners of
our acreage block and have experienced some encouraging results.
In January 2013, we completed the May 2502H horizontal well
flowing 674 barrels of oil per day from the Wolfcamp formation.
The well’s peak 30-day average was 397 barrels of oil per day.
12M 12 392/188.2
5/4.7
397/192.9
98.7%/97.6% $2,111.5
oil, 10% natural gas liquids and 10% natural gas.
PRODUCTION
Production in 2012 totaled a record 30.21 MMBOE
or 82,540 BOE per day. This represents a 22% increase
over total production of 24.78 MMBOE or 67,890 BOE
per day in 2011. Adding back the 4,500 BOE per day of
production that was conveyed to Whiting USA Trust II
in March 2012, our production in 2012 would have
been up 28% over 2011.
PROVED RESERVES
As of December 31, 2012, we had estimated proved
reserves of 378.8 MMBOE, of which 64% were classified
as proved developed. These estimated proved reserves
had a pre-tax PV10% value of $7,283.9 million, of
which approximately 99% came from properties located
in Whiting’s Rocky Mountain, Permian Basin and
Mid-Continent core areas. Our reserves are 80% crude
Our proved reserves of 378.8 MMBOE represented a
10% increase over the 345.2 MMBOE of proved reserves
at year-end 2011, which equates to 246% reserve
replacement. Adding back the 10.6 MMBOE that was
conveyed to Whiting USA Trust II, our proved reserves
were up 13%. An estimated 81.5 MMBOE of proved
reserves were added through exploration and develop-
ment activities. This represents a 68% increase over the
48.6 MMBOE of proved reserves that were added from
exploration and development in 2011.
Most of the proved reserve additions during 2012
came from our Bakken and Three Forks development in
the Williston Basin of North Dakota and Montana. We
booked an estimated 66.4 MMBOE of new Bakken and
Three Forks proved reserves, bringing our total proved
reserves in the Northern Rockies to 165.1 MMBOE
at year-end 2012. Of this 165.1 MMBOE, 67% were
proved developed and 33% were proved undeveloped.
6
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PROBABLE AND POSSIBLE RESERVES
2013 CAPITAL BUDGET
At year-end 2012, our probable reserves were
estimated to be 115.2 MMBOE and our possible
reserves were estimated to be 171.2 MMBOE, for a total
of 286.3 MMBOE. The year-end 2012 estimated pre-tax
PV10% for our probable and possible reserves was
$2,621.4 million.
As with our proved reserves, 100% of Whiting’s
probable and possible reserve estimates were independ-
ently engineered by Cawley, Gillespie & Associates, Inc.
Please refer to “Reserve and Resource Information” on
the inside front cover of this annual report.
POTENTIAL FUTURE DRILLING LOCATIONS
Based on independent engineering and internal
estimates, we project that we have a total of 9,661 gross
(4,503.2 net) potential future drilling locations. These
consist of 7,556 gross (3,623.3 net) primary locations
identified in our reserve database and 2,105 gross
(879.9 net) prospective locations supported by success-
ful exploration drilling or extensive geoscience. Of
these gross locations, 50% are located in our Williston
Basin Bakken/Three Forks plays and 25% are located in
our Redtail Niobrara play.
Identified Primary Locations
Northern Rockies
Southern Williston (Lewis & Clark; Pronghorn)
Western Williston(1) (Cassandra; Hidden Bench; Tarpon; Missouri Breaks)
Sanish (Sanish; Parshall) (2)
Other (3)
Total
Central Rockies
Redtail Niobrara
Other (4)
Total
Gulf Coast
Mid-Continent
Permian Basin (5)
Michigan
Total Primary Inventory
Identified Prospective Locations
Williston Basin
Williston Basin New Objectives
Missouri Breaks Upper Three Forks
Hidden Bench Lower Bakken Silt / Higher Density Pilot
Cassandra Lower Three Forks
Tarpon Lower Three Forks
Total
Williston Basin Higher Density Locations
Pronghorn Sand Higher Density
Sanish Higher Density and Infill
Total
Williston Basin Total Prospective Locations
Permian Basin
Big Tex Horizontal
Total Prospective Inventory
Total Potential Locations (6)
Our 2013 capital budget is $2,200 million, which
we expect to fund substantially with net cash provided
by our operating activities, borrowings under our credit
facility and certain oil and gas property divestitures.
We expect to invest $1,914 million of the 2013 capital
budget in exploration and development activity, $108
million for land and $178 million for facilities. Based
on this level of capital spending, we forecast production
of 33.8 MMBOE — 35.0 MMBOE for 2013, an increase of
12% - 16% over our 2012 production of 30.2 MMBOE.
In 2013, we plan to invest $1,142 million for the
drilling and completion of 219 gross (148 net) wells in
the Williston Basin. This represents 60% of our total
planned exploration and development expenditures of
$1,914 million. We have initiated pad drilling at our
Sanish field, Lewis & Clark/Pronghorn prospects and
Hidden Bench/Tarpon prospects. We expect to drill two
or three wells off of each pad. We currently estimate
that we can save approximately $500,000 per well
in the Pronghorn field and $175,000 per well in the
Sanish field in mobilization costs and efficiencies
utilizing pad drilling.
GROSS
NET
WELLS PER SPACING UNIT
3 Pronghorn Sand / 1280
4 Middle BKN; 3 Upper TFK / 1280
3.5 Middle BKN; 3 Upper TFK / 1280
8 Nio “B”; 4 Nio “A” / 640 –960
1,104
1,174
260
588
3,126
2,420
958
3,378
131
41
817
63
7,556
410.2
380.5
118.1
340.3
1,249.1
1,215.7
654.1
1,869.8
98.1
33.7
319.3
53.3
3,623.3
GROSS
NET
WELLS PER SPACING UNIT
321
556
120
40
1,037
453
191
644
1,681
424
2,105
9,661
102.8
161.9
40.0
15.0
319.7
167.3
175.9
343.2
662.9
217.0
879.9
4,503.2
3 Upper TFK / 1280
4 BKN Silt; 4 Middle BKN per 1280
4 Lower TFK per 1280
3 Lower TFK per 1280
3 Add'l Pronghorn Sand / 1280
3 Add'l Middle BKN / 1280
6 Upper Wolfcamp / 640
(1) Tarpon primary development on 3 Middle Bakken; 2 Upper Three Forks due to high natural fracturing. Excludes Upper Three Forks at Missouri Breaks.
(2) Cross unit boundary wells at Sanish result in an average of 3.5 wells per spacing unit. Parshall was developed on 640-acre spacing units and there is no Three Forks.
(3) Various fields in North Dakota and Montana, including Big Island, Starbuck, Big Stick and others.
(4) Various fields in Colorado, Wyoming and Utah including Sulphur Creek, Fontenelle, Nitchie Gulch, Flat Rock and others.
(5) Various fields in Texas and New Mexico including Jo-Mill, West Jo-Mill, Garza, Signal Peak and others.
(6) Locations include both 3P reserves and Resource Potential.
7
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W I L L I S T O N B A S I N O I L P L AY S
WILLISTON BASIN In the Bakken and Three
Forks hydrocarbon system in the Williston Basin
alone, we hold more than 700,000 net acres and
continue to add to that position. Importantly, our
average cost in this acreage is $521 per net acre.
With a focus on Bakken/Three Forks oil in the
Williston Basin, we generated record production of
30.21 MMBOE or 82,540 BOE per day in 2012.
We were one of the first successful operators in
the Bakken/Three Forks Hydrocarbon System in the
Williston Basin with the discovery of our Sanish
field in early 2007. Outside of our Sanish field, we
have assembled lease positions on seven separate
prospects in the Williston Basin targeting the Bakken/
Three Forks and Pronghorn Sand formations. Our
focus in 2012 was on the development of the fields
we discovered in 2011, such as our Pronghorn and
Hidden Bench/Tarpon prospects.
The following graphic depicts our drilling plans
across our major Williston Basin fields:
SOUTHERN WILLISTON BASIN The Southern
Williston Basin encompasses our Lewis & Clark
and Pronghorn prospects, which represent a total of
398,334 gross (262,974 net) acres. Fourth quarter
2012 production from this region averaged 13,430
BOE per day. This daily rate represents a 129%
increase over the 5,870 BOE per day rate in the
fourth quarter of 2011.
Lewis & Clark/Pronghorn — We were very
pleased with our drilling results at the Lewis &
Clark/Pronghorn prospects in 2012. The Lewis
& Clark/Pronghorn prospects are located primarily
in North Dakota’s Stark and Billings counties and run
along the Bakken shale pinch-out in the southern
Williston Basin. In this area, the Upper Bakken shale
is thermally mature, moderately over-pressured,
and it has charged reservoir zones within the
immediately underlying Pronghorn Sand and Three
Forks formations.
MISSOURI BREAKS
CASSANDRA
SANISH
HIDDEN BENCH
PRONGHORN
TARPON
Lower Virden
U. Bakken Shale
Middle Bakken
L. Bakken Shale
Upr 3Fks–1st Bench
Upr 3Fks–2nd Bench
Lower Virden
U. Bakken Shale
Middle Bakken
L. Bakken Shale
L. Bakken Silt
Pronghorn Sand
Upr 3Fks–1st Bench
Upr 3Fks–2nd Bench
EXISTING 4P LOCATIONS
POTENTIAL HIGH DENSITY INFILLS
NEW OBJECTIVES
8
0’
50’
100’
150’
200’
0’
50’
100’
150’
200’
fp_Text 3/18/13 5:02 PM Page 9
Pictured above is the Obrigewitch 11-17TFH, which was completed
in the Pronghorn Sand flowing 1,740 BOE per day. The well is
located on our Pronghorn prospect in Stark County, North Dakota.
The rig in the background in the picture below is drilling the
Buckman 34-9PH, which was completed flowing 1,964 BOE
per day. The wellhead in the foreground is the Obrigewitch
21-16 TFH, which flowed 3,373 BOE per day on completion in the
Pronghorn Sand. Both wells were drilled on our Pronghorn prospect.
We intend to conduct a higher density pilot
program at Pronghorn. Our plan is to drill six
Pronghorn Sand wells per 1,280-acre spacing unit,
which is up from our initial plan of three wells per
spacing unit. We currently have seven drilling rigs
operating in the Pronghorn prospect and have
begun utilizing pad drilling with two or three wells
being drilled from each pad.
In order to process the produced gas stream from
the Lewis & Clark/Pronghorn areas, we constructed
and brought on-line the Belfield gas processing
plant, located south of Belfield, North Dakota. The
gas plant has a processing capacity of 30 MMcf per
day and processes production from the Pronghorn
area. Currently, there is inlet compression in place to
process 24 MMcf per day. Additionally, we completed
construction on an oil terminal and a seven-mile
oil transmission line to allow for the delivery of oil
production from the Pronghorn area into the
Bridger Four Bears oil transmission system, which
came on stream in March 2013. The use of this
terminal reduces our transportation costs per barrel
and makes development more economical.
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WESTERN WILLISTON BASIN
The Western Williston Basin includes our Hidden
Bench, Tarpon, Missouri Breaks and Cassandra
prospects. These areas represent a total of 183,508
gross (114,732 net) acres. Production from the
Western Williston Basin averaged 5,120 BOE per day
in the fourth quarter of 2012, which represents a
155% increase over the 2,010 BOE per day average
rate in the fourth quarter of 2011.
Hidden Bench/Tarpon — Drilling on the Hidden
Bench and Tarpon prospects, which encompass
approximately 49,108 gross (28,556 net) acres and
8,125 gross (6,265 net) acres, respectively, target the
Bakken and Three Forks formations. Based on core
analysis, we have identified an additional reservoir
positioned between the Middle Bakken and Three
Forks that has demonstrated high oil in place and
may significantly increase reserves at our Hidden
Bench area. We plan to test this zone, which we
refer to as the “Middle Bakken Silt,” by drilling 160-
acre spaced wells above and below this target zone
and stimulating these wells with large frac volumes.
We believe that this higher density drilling will also
On page #10 is our Belfield Gas Plant, located in Stark County,
North Dakota. The Belfield plant was processing 18 MMcf of gas
per day (gross) as of December 31, 2012. Currently, there is inlet
compression in place to process 24 MMcf per day. Whiting owns
50% of the Belfield plant. We began connecting other operators’
wells to the plant in November 2012.
Pictured below is the Estvold 42-26TFH at our Sanish field. Net
production from Sanish in 2012 totaled 11.4 MMBOE (an average
of 31,081 BOE per day), representing a 40% increase over 2011.
improve our recovery efficiency in the Middle Bakken
reservoir. We plan to drill as many as eight wells per
1,280-acre spacing unit at Hidden Bench, up from
our initial plan of four wells per unit.
In the fourth quarter of 2012, we drilled another
prolific well at our Tarpon prospect in McKenzie
County, North Dakota. The Tarpon Federal 21-4-3H
was tested on December 28, 2012 flowing 4,971
barrels of oil and 11,450 Mcf of gas (6,879 BOE) per
day from the Middle Bakken formation. This is the
third best well drilled to date in the Williston Basin,
the first being Whiting’s Tarpon Federal 21-4H with
an initial production rate of 7,009 BOE per day. We
hold a 56% working interest and a 45% net revenue
interest in the Tarpon Federal 21-4-3H. We have
implemented pad drilling at Tarpon with plans to
drill three wells off of each pad.
Missouri Breaks Prospect — We hold 95,928
gross (66,095 net) acres in the Missouri Breaks
prospect, located in Richland County, Montana and
McKenzie County, North Dakota. We continue to
de-risk our acreage in the Missouri Breaks area. We
have now drilled successful wells on the western,
eastern and southern portions of our acreage. On
October 27, 2012, we completed the Amber Elizabeth
9-4H in the Middle Bakken formation flowing 1,315
BOE per day. This was our first well drilled in the
eastern portion of Missouri Breaks.
SANISH FIELD AREA
Whiting’s net production from the Sanish field
averaged 32,590 BOE per day in the fourth quarter of
2012, an increase of 4% over the third quarter 2012
average of 31,400 BOE per day. Net production from
Sanish in 2012 totaled 11.4 MMBOE (an average of
31,081 BOE per day), representing a 40% increase
over 2011. Whiting continues to generate strong
results from the field.
We plan to initiate a higher density pilot
program in the Sanish field in the first half of 2013.
This could add 191 gross (175.9 net) locations. We
also plan to refrac several wells at Sanish in 2013.
11
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O T H E R D E V E L O P M E N T A R E A S
DENVER BASIN
Redtail Niobrara Prospect — We hold a total
of 109,856 gross (79,467 net) acres in our Redtail
prospect, located in the Denver Julesberg Basin in
Weld County, Colorado. Based on our drilling
success in 2012, we have submitted a plan to the
Colorado Oil & Gas Division to drill up to 8 wells in
the Niobrara “B” formation and 4 wells in the “A”
zone per 640 or 960 acre spacing units.
We plan to construct a new gas processing plant
at our Redtail prospect. Construction is expected to
be completed in early 2014. The plant’s planned inlet
capacity is 15 MMcf of gas per day. We currently
have one drilling rig running at Redtail. We plan to
add a second rig around mid-year and a third rig
once the plant is completed.
DELAWARE BASIN
Big Tex Prospect — Whiting’s lease position at Big
Tex consists of 116,694 gross (86,882 net) acres,
located primarily in Pecos County, Texas. We have
established production on three corners of our
acreage block at Big Tex and recently drilled our best
well in the play to date. On January 23, 2013, we
completed the May 2502H flowing 674 barrels of oil
per day from the Wolfcamp formation. The horizontal
well’s peak 30-day average was 397 barrels of oil per
day. Whiting owns a 100% working interest and an
80% net revenue interest in the May 2502H.
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fp_Text 3/18/13 5:02 PM Page 13
EOR PROJECTS
Our EOR projects at North Ward Estes and Postle
fields represented 38% of our year-end 2012 proved
reserves and 19% of our company-wide production
in the fourth quarter of 2012.
North Ward Estes Field — The North Ward Estes
field includes six base leases with 100% working
interests in 62,138 gross (60,377 net) acres in Ward
and Winkler counties, Texas. Current EOR production
is from the Yates formation at 2,600 feet, which is
the primary producing zone, with additional
production from other zones including the Queen
at 3,000 feet.
Net production from our North Ward Estes field
averaged 8,540 BOE per day in the fourth quarter of
2012. One of the largest phases at North Ward Estes
(Phase 3B) is pressuring up with CO2, and we are
beginning to see a production response. Current
production from the field is approximately 9,000 BOE
per day. Whiting is currently injecting approximately
350 MMcf of CO2 per day into the field, of which
about 63% is recycled gas.
Pictured at the top of page #12 is the Wildhorse 02-0214H well at
our Redtail prospect in the Denver Basin in Weld County, Colorado.
This well flowed 660 BOE per day from the Niobrara “B” formation
in October 2012. The well was drilled on a 640-acre spacing unit.
Pictured below on page #12 is the Legear 11-02 well at our
Big Tex prospect in Pecos County, Texas. This horizontal well was
completed in the Wolfcamp formation in July 2012 flowing
478 BOE per day.
In the photo above, Lease Operator Scott Forbess collects data
from our Nitrogen Rejection Unit at North Ward Estes field in
Ward County, Texas.
Postle Field — The Postle field, located in Texas
County, Oklahoma, includes five producing units
and one producing lease covering a total of approxi-
mately 26,442 gross (26,135 net) acres. Four of the
units are currently active CO2 enhanced recovery
projects. In the fourth quarter of 2012, production
from the field averaged 7,820 BOE per day, which
represents a slight decrease from 8,050 BOE per day
in the fourth quarter of 2011. Currently, we are
injecting approximately 120 MMcf per day of CO2
in this field, over half of which is recycled gas.
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O P T I M I Z AT I O N P R O G R A M S
Over the past three and a half years, our use of
the “Drill Well on Paper” (“DWOP”) optimization
process to perform step-by-step analysis of the
drilling programs in the Bakken and Three Forks
formations in North Dakota has allowed us to
reduce average drill times from 38 days to 18.5 days
per well in the Sanish field and from 35 days to
17.0 days per well in other fields throughout
North Dakota.
As post-DWOP drill times in North Dakota have
stabilized at these reduced rates, drilling procedures
are being modified to utilize pad drilling technologies
to further reduce drilling time and costs per well. Pad
drilling is a batch drilling methodology utilized to
reduce surface disturbance, rig mobilization, and
service costs by drilling two or three wells from a
single drilling location. Drilling costs for pad wells
have been over $175,000 lower in the Sanish field
and more than $500,000 lower in the Pronghorn
field than single well locations in the same fields.
Whiting currently has 10 pad capable rigs drilling in
North Dakota.
In September 2012, we initiated a program to
reduce our overall cycle time, or the time from spud
to first production. This program initially covered
operations in our Pronghorn, Lewis & Clark, Hidden
Bench, Tarpon and East Missouri Breaks fields.
The focus of the program is on: the construction of
pads and tank batteries; drilling rig mobilization
times; pre-job preparation; timing for fracture
stimulations; post-frac flow back and construction
of production facilities.
To date, we have reduced this cycle time by 23.7
days, to 67.1 days from 90.8 days. The cycle time
reduction is resulting in accelerated production and
drilling and completion cost savings.
fp_Text 3/18/13 5:02 PM Page 15
Depicted on page #14 is an example of multi-well development
in the Williston Basin. The five wells at our Sanish field in this
photo had average initial production rates of more than 2,250
BOE per day. They were completed in both the Middle Bakken and
Three Forks formations.
Pictured above is the Lydia 11-14PH, which was completed in the
Pronghorn Sand in September 2012 flowing 1,154 BOE per day.
The well was drilled on our Pronghorn prospect in Stark County,
North Dakota.
Lease Operator Will Goldsbury is pictured below checking the tank
batteries at the Johnson 34-33H well at our Hidden Bench prospect
in McKenzie County, North Dakota. The well was completed in the
Middle Bakken formation flowing 2,213 BOE per day.
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B U I L D I N G F O R T H E F U T U R E
We are very pleased with the young talent we have
been able to attract to be part of the Whiting team.
Our Northern Initiative Program focuses on recruit-
ing some of the most promising young professionals
from highly regarded universities in the states where
we operate. The following pages feature some of
Whiting’s up-and-comers.
JONATHAN COLE WATERFIELD-ORLEY
Jonathan Cole Waterfield-Orley joined Whiting in
July 2008 as a member of our Drilling Department.
Prior to joining Whiting, he worked for a drilling
contractor for four years as a floorhand, driller,
toolpusher and drilling manager in the Green
River Basin of Wyoming, Uintah Basin of Utah,
and Piceance Basin and Denver Julesburg Basin of
Colorado. At Whiting, Cole has advanced to the
position of Regional Drilling Manager after serving
as a Drilling Engineer where his duties include
overseeing all aspects of daily drilling operations in
a safe and efficient manner. His accomplishments
at Whiting include developing drilling practices to
reduce costs and days on location in several of
Whiting’s prospects, including the Sanish, Pronghorn,
Hidden Bench and Lewis & Clark prospects in North
Dakota, the Postle field in Oklahoma, the Big Tex
prospect in Texas and the Redtail Niobrara prospect
in Colorado. Cole has a B.S. degree in Petroleum
Engineering from the University of Montana.
JESSICA JEAN BENSON
Jessica Jean Benson joined Whiting in May 2011
as a member of our Land Department. At Whiting,
Jessica has advanced to the position of Landman II
after serving as both a Land Coordinator and
Landman I. Jessica works closely with the asset team
she serves on in the management of Bakken / Three
Forks resource plays in both North Dakota and
Montana. She is largely responsible for negotiating
acquisitions, high-grade consolidation trades and
partner buy-outs. She spearheaded negotiations for
more than 13,300 net acres in the Missouri Breaks
Prospect, increasing Whiting’s working interest in
10 operated units and adding an additional seven
operated units to the drilling program. In conjunction
with strengthening Whiting’s leasehold position,
Jessica is responsible for testifying in oil and gas
hearings for temporary spacing, field-wide spacing,
compulsory pooling and increased density authority
before both the Montana Board of Oil & Gas
Conservation and the North Dakota Industrial
Commission. Jessica has a B.S. degree in Agricultural
and Natural Resource Economics from Colorado
State University, a B.A. in Professional Land and
Resource Management from Western State Colorado
University, and is working on a Master of Science
degree in Global Energy Management at the
University of Colorado – Denver. She is a certified
paralegal through the University of Colorado – Denver
and is a Registered Professional Landman through
the American Association of Professional Landmen.
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MARSHALL JUNG
BRANDON ROLLINS
Marshall Jung joined Whiting in May 2011 as a
member of the Geo-services group. Prior to joining
Whiting, he worked for a service company for six
years as a wireline engineer and Petrophysicist in
various worldwide locations, where he published
Society of Petroleum Engineers (SPE) papers and
assisted in design of new wireline logging technolo-
gies. At Whiting, Marshall works as a Petrophysicist
where his duties include exploration and develop-
ment petrophysics. He is responsible for planning,
advising and evaluating petrophysical studies on a
field-wide basis for Whiting assets. His work is used
for reserves calculations and development decisions.
His accomplishments include successful evaluations
in Whiting’s Permian Basin, Niobrara and Red River
fields. Marshall holds degrees in Mathematics and
Economics from the Colorado School of Mines.
Brandon Rollins joined Whiting in March 2011 as a
member of our Northern Rockies Operations Team.
Prior to joining Whiting, he attended the University
of Montana where he received his B.S. degree in
Petroleum Engineering. At Whiting, Brandon has
advanced to the position of Operations Engineer
after serving as a Production Engineer in Dickinson,
North Dakota, where his duties included production
optimization in our sliding ball and sleeve completion
technology, water-flood optimization and completion-
rig coordination/procedures. His accomplishments
at Whiting include Missouri Breaks/East Missouri
Breaks field development, completions optimization,
North Elkhorn Ranch Unit and Big Stick Madison
Unit waterflood optimization and Pronghorn field
production development.
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SIRIKKA LOHOEFENER
BENJAMIN BETTS
Sirikka Lohoefener joined Whiting in June 2006 as
a member of our Financial Reporting Department.
Prior to joining Whiting, she worked for five years
in public accounting as an auditor. At Whiting,
Sirikka was promoted to the position of Financial
Reporting Manager in 2011, where her duties
include internal financial reporting, SEC reporting
and FERC reporting. Her accomplishments at
Whiting include participating in the launch of two
royalty trust IPO’s and assisting with several of
Whiting’s debt and equity offerings. Sirikka has a
B.S. degree and a Master of Accountancy degree
from the University of Missouri – Columbia and is a
Certified Public Accountant.
Benjamin Betts joined Whiting in May 2007 as
a member of our North Ward Estes Operations
Department. At Whiting, Benjamin has advanced to
the position of Drilling Engineer after serving as
Operations Engineer where his duties include the
planning and the safe, efficient implementation of a
well for the desired completion. His accomplishments
at Whiting include overseeing the drilling of a total of
78 wells as part of the Whiting Drilling Department
in Colorado, Montana, North Dakota, Utah and Texas.
Benjamin holds a B.S. degree in Petroleum Engineering
from the Colorado School of Mines and is a registered
Professional Engineer in the State of Colorado.
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JOSHUA BRNAK
TAYLOR WINEGAR
Joshua Brnak joined Whiting in June 2006 as a
member of our North Ward Estes reservoir engineer-
ing group. Prior to joining Whiting, he worked for
four years as a field operations engineer at the
SACROC Unit in the Permian Basin of West Texas.
He co-authored an SPE technical paper, presented at
the Improved Oil Recovery conference in Oklahoma,
and has had his SPE paper published in several
industry magazines. At Whiting, Josh’s duties include
CO2 flood management, project development and
reservoir surveillance. His accomplishments at Whiting
include a CO2 flood reservoir simulation, design and
initiation of the North Ward Estes CO2 flood pilot
project, development of several in-house databases
and justification and approval of several CO2 and
waterflood projects at North Ward Estes. Josh has a
B.S. degree in Petroleum Engineering from the
Colorado School of Mines.
Taylor Winegar joined Whiting in April 2010 as a
member of our Drilling Department. Prior to joining
Whiting, he worked for three years as a Drilling
Engineer on various drilling programs in the Piceance
and Uintah Basins. At Whiting, Taylor has advanced
to the position of Level III Drilling Engineer where
his duties include providing drilling engineering
support while managing the daily operations of four
rigs in the Pronghorn, Missouri Breaks and Big Island
prospects that Whiting is currently developing. His
accomplishments at Whiting include reduced drilling
cycle times through the testing and implementation
of Lateral Drilling Reamers, saving an average of
three days of rig time per well. One of Taylor’s rigs,
Pioneer 3, recently set a Williston Basin record
drilling the Tomchuk 11-30PH to a total measured
depth of 20,620 feet in 10.9 days from spud to total
depth. He also introduced Electromagnetic MWD
technology in the vertical and curve sections of
horizontal Bakken, Three Forks and Pronghorn Sand
wells, generating further reduced spud-to-TD times.
Taylor has a B.S. degree in Petroleum Engineering
from the University of Montana.
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B O A R D O F D I R E C T O R S
JAMES J. VOLKER, 66, is Chairman of
the Board and Chief Executive Officer of
Whiting Petroleum Corporation. Mr. Volker
has been a director of Whiting Petroleum
Corporation since 2003 and a director of
Whiting Oil and Gas Corporation since
2002. He joined Whiting Oil and Gas
Corporation in August 1983 as Vice Pres-
ident of Corporate Development and
served in that position through April 1993.
In May 1993, he became a contract con-
sultant to Whiting Oil and Gas Corporation 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
of Whiting Oil and Gas Corporation in January 2002. Mr. Volker
retained his position of Chief Executive Officer when Mr. James
T. Brown was appointed President and Chief Operating Officer
effective January 1, 2011. Mr. Volker was co-founder, Vice Pres-
ident and later President of Energy Management Corporation
from 1971 through 1982. He has over 40 years of experience in
the oil and natural 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.
THOMAS L. ALLER, 64, has been a
director of Whiting Petroleum Corporation
since 2003. Mr. Aller, who serves as Senior
Vice President of Operations Support
for Alliant Energy Corporation effective
January 13, 2013, has served as Senior
Vice President —Energy Resource Develop-
ment of Alliant Energy Corporation since
January 2009 and President of Interstate
Power and Light Company since 2004. Prior
to that, he served as President of Alliant
Energy Investments, Inc. since 1998 and interim Executive Vice
President — Energy Delivery of Alliant Energy Corporation since
2003 and Senior Vice President — Energy Delivery of Alliant Energy
Corporation since 2004. From 1993 to 1998, he served as Vice
President of IES Investments. He received his Bachelor’s Degree
in political science from Creighton University and his Master’s
Degree in municipal administration from the University of Iowa.
D. SHERWIN ARTUS, 75, has been a
director of Whiting Petroleum Corporation
since 2006. Mr. Artus joined Whiting Oil
and Gas Corporation in January 1989 as
Vice President of Operations and became
Executive Vice President and Chief Operat-
ing Officer in July 1999. In January 2000,
he was appointed President and Chief
Executive Officer. Mr. Artus became Senior
Vice President in January 2002 and retired
from the Company on April 1, 2006. Prior
to joining Whiting, he was employed by Shell Oil Company in
various engineering research and management positions. From
1974-1977, he was employed by Wainoco Oil and Gas Company
as Production Manager. He was a co-founder and later became
President of Solar Petroleum Corporation, an independent oil
and gas producing company. He has over 51 years of experience
in the oil and natural gas business. Mr. Artus holds a Bachelor’s
Degree in Geological Engineering and a Master’s Degree in Mining
Engineering from the South Dakota School of Mines and Tech-
nology. He is a registered Professional Engineer in Colorado,
Wyoming, Montana and North Dakota. Mr. Artus is a member,
and a past officer, of the Society of Professional Well Log Analysts
and is a member of the Society of Petroleum Engineers.
THOMAS P. BRIGGS, 64, has been a
director of Whiting Petroleum Corporation
since 2006 and is chairman of the Com-
pensation Committee. Mr. Briggs is an
inactive certified public accountant and
served as chief financial officer of six
private and public companies, primarily
in the oil and gas and food industries.
Recently, he was chief financial officer
of Healthy Food Holdings, Inc., a private
holding and management company for
branded food companies. Prior to that, he served as chief
financial officer of Horizon Organic, a publicly-held organic
foods company. During the 1980s, he was a chief financial
officer and senior officer of two Denver-based independent oil
and gas companies. Mr. Briggs spent 10 years with PriceWater-
houseCoopers and Deloitte as a tax and M&A consultant to oil
and gas clients. Mr. Briggs holds an accounting degree from
Duke University and a law degree from Georgetown University.
Mr. Briggs’ term expires at the 2013 annual meeting.
PHILIP E. DOTY, 69, has been a director
of Whiting Petroleum Corporation since
2010 and is chairman of the Audit
Committee. Mr. Doty is a certified public
accountant. Since 2007, Mr. Doty has
been counsel to Ehrhardt Keefe Steiner &
Hottman PC, the largest Colorado-based
accounting and consulting firm, where he
previously was a partner from 2002 to
2007. From 1967 to 2000 he worked at
Arthur Andersen and Co., where he was a
partner since 1978 and served as the audit partner and head of
the Denver office oil and gas practice until his retirement in
2000. He is a graduate of Drake University with a Bachelor’s
degree in accounting.
WILLIAM N. HAHNE, 61, has been a
director since 2007 and is chairman of the
Nominating and Governance Committee.
Mr. Hahne was Chief Operating Officer
of Petrohawk Energy Corporation from
July 2006 until October 2007. Mr. Hahne
served at KCS Energy, Inc. as President,
Chief Operating Officer and Director from
April 2003 to July 2006, as Executive Vice
President and Chief Operating Officer
from March 2002 to April 2003 and in
other management positions prior to that. He is a graduate of
Oklahoma University with a BS in petroleum engineering and
has 38 years of extensive technical and management experience
with independent oil and gas companies including Unocal, Union
Texas Petroleum Corporation, NERCO, The Louisiana Land and
Exploration Company (LL&E) and Burlington Resources, Inc.
ALLAN R. LARSON, 75, has been a
director of Whiting Petroleum Corporation
since 2011. He has more than 47 years
experience in oil and gas exploration and
development, primarily in the Rocky
Mountains and the Midcontinent regions.
For 26 years he has operated Larson
Petroleum, LLC, a geological consulting
company. His previous affiliations include
Jade Drilling Company, Belleview Capital
Corporation, Mesa Petroleum Company
and Amoco Production Company. Mr. Larson earned a PhD in
Geology at the University of California, Los Angeles. He earned
his M.S. in Geology from UCLA and his BS degree in Geology at
Pennsylvania State University. He is a member of the American
Association of Petroleum Geologists, the Rocky Mountain Asso-
ciation of Geologists, the Wyoming Geological Association, the
Montana Geologic Society and the Utah Geologic Association.
20
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X]
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
For the fiscal year ended December 31, 2012
or
[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the transition period from _______________ to _______________
Commission file number: 001-31899
WHITING PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction
of incorporation or organization)
1700 Broadway, Suite 2300
Denver, Colorado
(Address of principal executive offices)
20-0098515
(I.R.S. Employer
Identification No.)
80290-2300
(Zip code)
(303) 837-1661
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
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)
Securities registered pursuant to Section 12(g) of the Act: None.
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes (cid:1) No (cid:2)
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 (cid:2) No (cid:1)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes (cid:1) No (cid:2)
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 (cid:1)
No (cid:2)
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. (cid:1)
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a
smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting
company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer (cid:1) Accelerated filer (cid:2) Non-accelerated filer (cid:2)
Smaller reporting company (cid:2)
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes (cid:2) No (cid:1)
Aggregate market value of the voting common stock held by non-affiliates of the registrant at June 30, 2012:
$4,845,579,443.
Number of shares of the registrant’s common stock outstanding at February 15, 2013: 117,829,366 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the 2013 Annual Meeting of Stockholders are incorporated by reference into Part III.
TABLE OF CONTENTS
Glossary of Certain Definitions .............................................................................................
3
PART I
8
Item 1.
Business ................................................................................................................................................
22
Item 1A. Risk Factors ..........................................................................................................................................
36
Item 1B. Unresolved Staff Comments .................................................................................................................
36
Properties ..............................................................................................................................................
Item 2.
Legal Proceedings ................................................................................................................................45
Item 3.
45
Mine Safety Disclosures .......................................................................................................................
Item 4.
Executive Officers of the Registrant ................................................................................................46
PART II
Item 5.
Item 6.
Item 7.
Market for the Registrant’s Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities ................................................................................................48
50
Selected Financial Data ........................................................................................................................
Management’s Discussion and Analysis of Financial Condition and Results of
51
Operations .............................................................................................................................................
72
Item 7A. Quantitative and Qualitative Disclosure About Market Risk ...............................................................
75
Financial Statements and Supplementary Data.....................................................................................
Item 8.
Changes in and Disagreements with Accountants on Accounting and Financial
Item 9.
116
Disclosure .............................................................................................................................................
116
Item 9A. Controls and Procedures .......................................................................................................................
Item 9B. Other Information ................................................................................................................................118
PART III
Item 10. Directors, Executive Officers and Corporate Governance ................................................................118
118
Executive Compensation ......................................................................................................................
Item 11.
Security Ownership of Certain Beneficial Owners and Management and Related
Item 12.
118
Stockholder Matters ..............................................................................................................................
119
Item 13. Certain Relationships, Related Transactions and Director Independence ............................................
119
Principal Accounting Fees and Services ...............................................................................................
Item 14.
Item 15.
119
Exhibits, Financial Statement Schedules ..............................................................................................
PART IV
2
GLOSSARY OF 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, NGLs and
other liquid hydrocarbons.
“Bcf” One billion cubic feet of natural gas.
“BOE” One stock tank barrel of oil equivalent, computed on an approximate energy equivalent basis that one Bbl
of crude oil equals six Mcf of natural gas and one Bbl of crude oil equals one Bbl of natural gas liquids.
“CO2” Carbon dioxide.
“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.
“costless collar” An options position where the proceeds from the sale of a call option at its inception fund the
purchase of a put option at its inception.
“differential” The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil spot,
and the wellhead price received.
“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.
“development well” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a
stratigraphic horizon known to be productive.
“exploratory well” A well drilled to find a new field or to find a new reservoir in a field previously found to be
productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a
development well, an extension well, a service well or a stratigraphic test well.
“extension well” A well drilled to extend the limits of a known reservoir.
“FASB” Financial Accounting Standards Board.
“FASB ASC” The Financial Accounting Standards Board Accounting Standards Codification.
“field” An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same
individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a
field that are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or both.
Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common
operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify
3
localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas of interest,
etc.
“GAAP” Generally accepted accounting principles in the United States of America.
“gross acres or wells” The total acres or wells, as the case may be, in which a working interest is owned.
“lease operating expense” or “LOE” The expenses of lifting oil or gas from a producing formation to the surface,
constituting part of the current operating expenses of a working interest, and also including labor, superintendence,
supplies, repairs, short-lived assets, maintenance, allocated overhead costs and other expenses incidental to
production, but not including lease acquisition or drilling or completion expenses.
“LIBOR” London interbank offered rate.
“MBbl” One thousand barrels of oil or other liquid hydrocarbons.
“MBbl/d” One MBbl per day.
“MBOE” One thousand BOE.
“MBOE/d” One MBOE per day.
“Mcf” One thousand cubic feet of natural gas.
“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.
“net production” The total production attributable to our fractional working interest owned.
“NGL” Natural gas liquid.
“NYMEX” The New York Mercantile Exchange.
“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 SEC, net of estimated lease operating expense,
production taxes and future development costs, using costs as of the date of estimation without future escalation
and using an average of the first-day-of-the month price for each of the 12 months within the fiscal year, without
4
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 ( )
to the Proved Reserves table in Item 1. “Business” of this Annual Report on Form 10-K for more information.
2
“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:
a.
b.
The area identified by drilling and limited by fluid contacts, if any, and
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.
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:
a.
b.
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
The project has been approved for development by all necessary parties and entities, including
governmental entities.
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
5
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.
“recompletion” An operation whereby a completion in one zone is abandoned in order to attempt a completion in a
different zone within the existing wellbore.
“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.
“royalty” The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross
income from crude oil or natural gas produced and sold, unencumbered by expenses relating to the drilling,
completing or operating of the affected well.
“royalty interest” An interest in an oil or natural gas property entitling the owner to shares of the crude oil or
natural gas production free of costs of exploration, development and production operations.
“SEC” The United States Securities and Exchange Commission.
“service well” A service well is a well drilled or completed for the purpose of supporting production in an existing
field. Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane
or flue gas), water injection, steam injection, air injection, salt-water disposal, water supply for injection,
observation or injection for in-situ combustion.
“standardized measure of discounted future net cash flows” The discounted future net cash flows relating to proved
reserves based on 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); current costs and statutory tax rates (to the extent applicable); and a 10% annual discount rate.
“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
6
royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all
risks in connection therewith.
“workover” Operations on a producing well to restore or increase production.
7
Item 1. Business
Overview
PART I
We are an independent oil and gas company engaged in exploration, development, acquisition and production
activities primarily in the Rocky Mountains, Permian Basin, Mid-Continent, Michigan and Gulf Coast 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, 2012, our estimated proved reserves
totaled 378.8 MMBOE, representing a 10% increase in our proved reserves since December 31, 2011. Our 2012
average daily production was 82.5 MBOE/d and implies an average reserve life of approximately 12.6 years.
The following table summarizes by core area, our estimated proved reserves as of December 31, 2012, their
corresponding pre-tax PV10% values, and our fourth quarter 2012 average daily production rates, as well as our
company’s total standardized measure of discounted future net cash flows as of December 31, 2012:
Oil
(MMBbl)
Core Area
Rocky Mountains ......................154.0
Permian Basin ...........................103.7
Mid-Continent ...........................40.9
Michigan ................................
1.7
Gulf Coast ................................ 1.0
Total................................301.3
Discounted Future
Income Taxes .........................
-
Standardized Measure
of Discounted Future
Net Cash Flows ......................
-
NGLs
(MMBbl)
17.9
15.9
4.9
1.2
0.2
40.1
-
-
Proved Reserves (1)
Natural
Gas
(Bcf)
139.8
25.1
20.4
28.1
10.9
224.3
Total
(MMBOE)
195.2
123.8
49.2
7.6
3.0
378.8
-
-
-
-
Pre-Tax
PV10%
Value (2)
(In millions)
$ 4,488.9
1,731.9
969.4
62.0
31.7
$ 7,283.9
(1,876.9)
$ 5,407.0
%
Oil
79%
84%
83%
22%
33%
80%
-
-
4th Quarter 2012
Average Daily
Production
(MBOE/d)
63.0
11.0
8.1
2.7
1.3
86.1
-
-
_____________________
(1) 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 12 months ended December 31,
2012, pursuant to current SEC and FASB guidelines.
(2) 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, NGL and natural gas reserves.
While historically we have grown through acquisitions, we are increasingly focused on a balance between our
exploration and development programs and are 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.
8
Our growth plan is centered on the following activities:
• pursuing the development of projects that we believe will generate attractive rates of return;
• maintaining a balanced portfolio of lower risk, long-lived oil and gas properties that provide stable cash
•
•
flows;
seeking property acquisitions that complement our core areas; and
allocating a portion of our exploration and development (“E&D”) budget to leasing and exploring
prospect areas.
During 2012, we incurred $2,113.8 million in exploration, development and cash acquisition capital expenditures,
including $1,951.7 million for the drilling of 397 gross (192.9 net) wells. Of these new wells, 188.2 (net) resulted
in productive completions and 4.7 (net) were unsuccessful, yielding a 98% success rate.
Our current 2013 E&D budget is $2,200.0 million, and included in this amount is approximately $108.0 million in
acreage acquisition costs. The 2013 budget of $2,200.0 million represents a 4% increase from the $2,111.5 million
in E&D (which consisted of exploration, development and acreage expenditures) we incurred in 2012. We expect
to fund substantially all of our 2013 E&D budget using net cash provided by operating activities, borrowings under
our credit facility and certain oil and gas property divestitures. We sell properties when we believe that the sales
price realized will provide an above average rate of return for the property or when the property no longer matches
the profile of properties we desire to own.
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.
2012 Acquisitions. On March 22, 2012, we completed the acquisition of approximately 13,300 net undeveloped
acres in the Missouri Breaks prospect in Richland County, Montana for $33.3 million.
2012 Divestitures. On May 18, 2012, we sold a 50% ownership interest in our Belfield gas processing plant,
natural gas gathering system, oil gathering system and related facilities located in Stark County, North Dakota for
total cash proceeds of $66.2 million. We used the net proceeds from the sale to repay a portion of the debt
outstanding under our credit agreement.
On March 28, 2012, we completed an initial public offering of units of beneficial interest in Whiting USA Trust II
(“Trust II”), selling 18,400,000 Trust II units at $20.00 per unit, which generated net proceeds of $322.3 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 II units to the
public resulted in a deferred gain on sale of $128.2 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 Trust II in exchange for 100% of the trust’s units issued, or 18,400,000 units. The net profits interest
entitles Trust II 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 on the later to occur of (1) December 31, 2021, or (2)
the time when 11.79 MMBOE have been produced from the underlying properties and sold. This is the equivalent
of 10.61 MMBOE in respect of Trust II’s right to receive 90% of the net proceeds from such reserves pursuant to
the net profits interest. The conveyance of the net profits interest to Trust II consisted entirely of proved reserves of
10.61 MMBOE as of the January 1, 2012 effective date, representing 3% of our proved reserves as of December 31,
2011 and 5% (or 4.5 MBOE/d) of our March 2012 average daily net production.
9
2011 Acquisitions. On July 28, 2011, we completed the acquisition of approximately 23,400 net acres and one well
in the Missouri Breaks prospect in Richland County, Montana for an unadjusted purchase price of $46.9 million.
On March 18, 2011, we formed Sustainable Water Resources, LLC (“SWR”) with an unrelated third party to
develop a water project in the state of Colorado. We contributed $25.0 million for a 75% interest in SWR, and the
25% noncontrolling interest in SWR was ascribed a fair value of $8.3 million, which consisted of $2.5 million in
cash contributions, as well as $5.8 million in intangible and fixed assets contributed to the joint venture.
On February 15, 2011, we completed the acquisition of 6,000 net undeveloped acres and additional working
interests in the Pronghorn field in Billings and Stark counties, North Dakota, for an aggregate purchase price of
$40.0 million.
2011 Divestitures. On September 29, 2011, we sold our interest in several non-core oil and gas producing
properties located in the Karnes, Live Oak and DeWitt counties of Texas for total cash proceeds of $64.8 million,
resulting in a pre-tax gain on sale of $12.3 million. We used the net proceeds from the property sale to repay a
portion of the debt outstanding under our credit agreement.
Business Strategy
Our goal is to generate meaningful growth in our net asset value per share of proved reserves through the
exploration, development and acquisition of oil and gas projects with attractive rates of return on capital employed.
To date, we have pursued this goal through both continued field development in our core areas and the acquisition
of reserves. 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 project has become one of our central objectives. As of December 31, 2012, we have assembled
approximately 1,109,200 gross (703,700 net) developed and undeveloped acres in the Williston Basin located in
Montana and North Dakota. As of December 31, 2012, we had 20 drilling rigs operating in the Williston Basin.
During 2012, the focus of our development has expanded beyond the Sanish field to include several additional
areas in the Williston Basin such as the Lewis & Clark/Pronghorn, Hidden Bench/Tarpon, Missouri Breaks and
Cassandra prospects. We have completed the construction of our gas processing plant located south of Belfield,
North Dakota, which has a processing capacity of 30 MMcf/d and which primarily processes production from the
Pronghorn area. Currently, there is inlet compression in place to process 24 MMcf/d, and as of December 31, 2012
the plant was processing 18 MMcf/d. In November 2012, we began connecting other operators’ wells to the plant.
We intend to add inlet compression during 2013 in order to fully utilize the 30 MMcf/d processing capability. We
are also currently installing fractionation equipment to convert NGLs into propane and butane, which end products
are typically sold for higher realized prices in local markets. Additionally, we completed construction on an oil
terminal and a seven-mile oil transmission line to allow for the delivery of oil production from the Pronghorn
prospect into the Bridger Four Bears oil transmission system. The use of this terminal will reduce our
transportation costs per barrel and thereby increase our returns on the development of this prospect.
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, 2012, we have identified a drilling inventory of over 2,400 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. 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 significant production increases to
date in these fields through the use of secondary and tertiary recovery techniques, and we anticipate such
production increases at the North Ward Estes field to continue over the next four to five years. In these fields, we
10
are actively injecting water and CO2 and executing extensive re-development, drilling and completion operations,
as well as expanding our gas processing facilities, which will allow us to separate and inject over 300 MMcf/d of
recycled CO2 and thereby maximize our recovery of oil and gas from these reservoirs.
Growing Through Accretive Acquisitions. From 2004 to 2012, we completed 16 separate significant acquisitions of
producing properties for estimated proved reserves of 230.9 MMBOE, as of the effective dates of the acquisitions.
Our experienced team of management, land, engineering and geoscience professionals has developed and refined
an acquisition program designed to increase reserves and complement our existing properties, including identifying
and evaluating acquisition opportunities, closing purchases and then effectively managing properties we acquire.
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,
internally generated cash flow and certain oil and gas divestitures, 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, 2012, we had interests in 10,218 gross (3,927 net)
productive wells across approximately 1,277,400 gross (680,300 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 to execute our strategy because we are not dependent on any particular producing regions or
geological formations. Our proved reserve life is approximately 12.6 years based on year-end 2012 proved reserves
and 2012 production.
Experienced Management Team. Our management team averages 29 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 32 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 7,224 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 12 professionals averaging over 24 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 2011, we completed the build-out and installation of our in-house rock analysis laboratory. This state-of-the-art
facility includes two scanning electron microscopes (“SEM”), and these SEMs enable rapid turnaround analysis of
11
drilling or cored wells designed to support real-time drilling and completion decisions. These SEMs also allow us
to quantify porosity networks, which in turn helps our staff comparatively evaluate producing zones in present and
future plays under consideration. In addition, having SEMs in-house allows our team of experts to analyze samples
more rapidly than an outside service company would and with the full operational context that only full-time
employees possess, while protecting our proprietary data. Furthermore, we have established a two-room core
layout facility capable of displaying several hundred feet of core slabs under plain or ultraviolet light. The ability
for multidisciplinary groups such as geoscientists, operations personnel, reservoir engineers, drilling engineers and
senior management to discuss technical issues over the displayed cores has helped us become a leader in tight oil
play exploration and development.
Over the past few years, we utilized our “Drill Well on Paper” optimization process to significantly reduce the
number of days it takes to drill a well. Due to the success of this program, in September 2012 we expanded the
concept using a program called “Build-to-POP.” The objective of this program is to optimize the process from the
time we build a drilling location to the time we put a well on production (“POP”), to reduce our overall cycle time.
Early results have reduced the time from spud to POP from just under 91 days per well to approximately 67 days
per well. We have realized similar results in the amount of time required to move a rig from one location to the
next. Our rig move times have dropped from approximately nine days to just over seven days. We plan to take
what we learn with this project in the Williston Basin and apply the process to our Redtail prospect in Colorado.
As the Bakken project in the Williston Basin matures and wells are drilled across large areas of the Williston Basin,
we have assembled a more comprehensive database of information. This provides the opportunity to apply more
scientific analysis of the data and to develop tools to assist our petro-technical staff with well and completion
designs. In mid-2012, we initiated a study with a major service provider to review, analyze and make refinements
to our fracture stimulations. Results from this study have enhanced our ability to numerically model fracture
stimulations and to make refinements to increase the effectiveness of these stimulations and improve well
performance.
12
Proved, Probable and Possible Reserves
Our estimated proved, probable and possible reserves as of December 31, 2012 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.
Rocky Mountains:
PDP ................................
PDNP ................................
PUD ................................
Oil
(MMBbl)
98.0
0.4
55.6
154.0
Total Proved .............................
Total Probable ..........................43.7
Total Possible............................43.3
Permian Basin:
PDP ................................
PDNP ................................
PUD ................................
44.2
15.8
43.7
103.7
Total Proved .............................
Total Probable ..........................27.6
Total Possible............................78.2
Mid-Continent:
PDP ................................
PDNP ................................
PUD ................................
29.0
0.9
11.0
Total Proved .............................40.9
Total Probable ..........................11.0
Total Possible............................0.1
Michigan:
PDP ................................
PDNP ................................
PUD ................................
1.0
0.6
0.1
Total Proved .............................1.7
Total Probable ..........................1.9
Total Possible............................0.5
Gulf Coast:
PDP ................................
PDNP ................................
PUD ................................
0.9
0.1
-
Total Proved .............................1.0
Total Probable ..........................0.8
Total Possible............................1.1
Total Company:
PDP ................................
PDNP ................................
PUD ................................
173.1
17.8
110.4
301.3
Total Proved .............................
Total Probable ..........................85.0
123.2
Total Possible............................
NGLs
(MMBbl)
11.9
0.2
5.8
17.9
3.2
4.3
Natural
Gas
(Bcf)
94.5
1.4
43.9
139.8
42.2
117.4
Total
(MMBOE)
125.7
0.8
68.7
195.2
53.9
67.1
% of Total
Proved
65%
-%
35%
100%
12.1
2.3
10.7
25.1
43.6
9.6
17.0
0.5
2.9
20.4
3.9
-
16.3
6.0
5.8
28.1
9.8
9.2
8.6
2.2
0.1
10.9
10.1
20.2
148.5
12.4
63.4
224.3
109.6
156.4
4.2
3.0
8.7
15.9
6.6
17.5
3.8
0.1
1.0
4.9
1.5
-
0.5
0.3
0.4
1.2
0.2
0.1
0.2
-
-
0.2
0.4
-
20.6
3.6
15.9
40.1
11.9
21.9
13
50.4
19.2
54.2
123.8
41.5
97.3
35.6
1.1
12.5
49.2
13.2
0.1
4.2
1.9
1.5
7.6
3.7
2.2
2.5
0.5
-
3.0
2.9
4.5
218.4
23.5
136.9
378.8
115.2
171.2
41%
15%
44%
100%
72%
2%
26%
100%
55%
25%
20%
100%
83%
17%
-%
100%
58%
6%
36%
100%
Estimated
Future Capital
Expenditures
(In millions)
$
$
$
1,645.0
1,408.3
1,478.7
$
$
$
1,136.3
560.0
966.7
$
$
$
$
$
$
$
$
$
375.7
147.8
0.4
17.2
32.3
16.0
7.4
27.9
71.6
$
$
$
3,181.6
2,176.3
2,533.4
The estimated future capital expenditures in the table above incorporate numerous assumptions and are subject to
many uncertainties, including oil and natural gas prices, costs of oil field goods and services, drilling results and
several other factors.
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.
The table below presents percentages by purchaser that accounted for 10% or more of our total oil, NGL and
natural gas sales for the years ended December 31, 2012, 2011 and 2010. We believe that the loss of any individual
purchaser would not have a long-term material adverse impact on our financial position or results of operations.
2012
Plains Marketing LP (1) ................................................................20%
14%
Shell Trading US ................................................................
Nexen Pipeline USA, Inc. (1) ................................................................
-
Eighty Eight Oil Company ................................................................11%
Bridger Trading LLC ................................................................ 11%
EOG Resources, Inc. ................................................................ 4%
2011
27%
13%
-
8%
6%
7%
(1) Effective December 30, 2010, Plains Marketing LP acquired Nexen Pipeline USA, Inc.
2010
16%
17%
13%
4%
5%
10%
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 rights or title to all of our producing properties. As is customary in the oil and
gas industry, limited 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 (the “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 non-price 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
14
and NGLs 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.
Transportation and safety of natural gas is subject to regulation by the Department of Transportation (the “DOT”)
under the PIPES Act of 2006 and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2012. The
Pipeline and Hazardous Material Safety Administration (“PHMSA”), an agency with the DOT, enforces regulations
on interstate natural gas transportation. Intrastate natural gas transportation is subject to enforcement by state
regulatory agencies. State regulatory agencies can also create their own transportation and safety regulations as
long as they meet PHMSA’s minimum requirements. 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.
Likewise, the effect of regulatory changes under the DOT and their effect on interstate natural gas transportation
will not affect our operations in any way that is of material difference from those of our competitors. We use the
latest tools and technologies to remain compliant with current pipeline safety regulations.
Regulation of Transportation of Oil
Sales of crude oil, condensate and NGLs 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,
15
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 most recent mandatory five-
year review period resulted in an order from FERC for the index to be based on Producer Price Index for Finished
Goods (the “PPI-FG”), plus a 2.65% adjustment, for the five-year period July 1, 2011 through June 30, 2016. This
represents an increase for the PPI-FG plus 1.3% adjustment from the prior five-year period. A requested rehearing
of the order was denied by FERC. 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.
Transportation and safety of oil and hazardous liquid is subject to regulation by the DOT under the Pipeline
Integrity, Protection, Enforcement and Safety Act of 2006 and the Pipeline Safety, Regulatory Certainty and Job
Creation Act of 2012. PHMSA enforces regulations on all interstate liquids transportation and some intrastate
liquids transportation. PHMSA does not enforce the regulations in states that are capable of enforcing the same
regulations themselves. The effect of regulatory changes under the DOT and their effect on interstate and intrastate
oil and hazardous liquid transportation will not affect our operations in any way that is of material difference from
those of 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,
NGLs and natural gas within its jurisdiction.
Some of our offshore operations are conducted on federal leases that are administered by the Bureau of Ocean
Energy Management (“BOEM”). Currently, only 0.1% of our total production volumes are produced from offshore
leases. However, the present value of our future abandonment obligations associated with offshore properties was
$30.8 million as of December 31, 2012. Whiting is therefore required to comply with the regulations and orders
issued by BOEM under the Outer Continental Shelf Lands Act. Among other things, we are required to obtain
prior BOEM approval for any exploration plans we pursue and approval for our lease development and production
plans. BOEM 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, BOEM could require us to suspend or terminate our operations on a
federal lease.
16
BOEM 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 BOEM 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 compliance, in all material respects, 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, as amended
(“CERCLA” or “Superfund”), and comparable state laws impose strict joint and several liability, without regard to
fault or the legality of conduct, on classes of persons who are considered to be responsible for the release of a
“hazardous substance” into the environment. These persons include the owner or operator of the site where a
release occurred and anyone who disposed or arranged for the disposal of the hazardous substance released at the
site. Under CERCLA, such persons may be subject to 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. 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 be regulated as
“hazardous substances.” 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
17
practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have
been released on, under, or from the properties owned or leased by us or on, under, or from other locations where
such substances have been taken for recycling or disposal. In addition, many of these owned and leased properties
have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous
substances, wastes or hydrocarbons was 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 offsite disposal facilities, and the
substances disposed or released on them 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;
to perform remedial operations to prevent future contamination, including the plugging and
abandonment of wells drilled and left inactive by prior owners and operators; or
to pay some or all of the costs of any such action.
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 (“OPA”) and regulations issued under OPA impose strict, joint
and several liability on “responsible parties” for removal costs and 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, permittee, or holder of a right of use and
easement of the area in which an offshore facility is located. OPA establishes a liability limit for onshore facilities
of $350.0 million per spill, while the liability limit for offshore facilities is the payment of all removal costs plus
$75.0 million per spill damages. These limits do not apply if the spill is caused by a responsible party’s gross
negligence or willful misconduct; the spill resulted from a responsible party’s violation of a federal safety,
construction or operating regulation; a responsible party fails to report a spill or to cooperate fully in a cleanup; or a
responsible party fails to comply with an order issued under the authority of the Intervention on the High Seas Act.
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 to cover liabilities related
to an oil spill for which such responsible party is statutorily responsible. The President may increase the amount of
financial responsibility required under OPA by 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 penalties up
to $25,000 per day per violation. 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 (“RCRA”), and comparable
state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-
hazardous wastes. Under the auspices of the EPA, the individual states administer some or all of the provisions of
RCRA, sometimes in conjunction with their own, more stringent requirements. We generate solid and hazardous
wastes that are subject to RCRA and comparable state laws. Drilling fluids, produced waters and most of the other
wastes associated with the exploration, development and production of crude oil or natural gas are currently
regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas
exploration and production wastes now classified as non-hazardous could be classified as hazardous waste in the
future. In September 2010, the Natural Resources Defense Council filed a petition with the EPA, requesting them to
18
reconsider the RCRA exemption for exploration, production and development wastes but, to date, the agency has
not taken any action on the petition. The EPA has not formally responded to this petition yet. Any such change in
the current RCRA exemption and comparable state laws, could result in an increase in the costs to manage and
dispose of wastes. Additionally, these exploration and production wastes may be regulated by state agencies as
solid waste. Also, 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, or the Clean Water Act, as amended (“CWA”), and
analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including
spills and leaks of oil and other substances, into state waters or other waters of the United States. The discharge of
pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or
an analogous state agency. Spill prevention, control and countermeasure requirements under federal law require
appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the
event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, CWA and analogous state laws require
individual permits or coverage under general permits for discharges of storm water runoff from certain types of
facilities.
The EPA had regulations under the authority of 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. Federal and state regulatory agencies can impose
administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of
CWA and analogous state laws and regulations. In Section 40 CFR 112 of the regulations, the EPA promulgated
the Spill Prevention, Control, and Countermeasure (“SPCC”) regulations, which require certain oil containing
facilities to prepare plans and meet construction and operating standards.
Air Emissions. The federal Clean Air Act (the “CAA”), as amended, and comparable state laws, regulate emissions
of various air pollutants from various industrial sources through air emissions permitting programs and also impose
other monitoring and reporting requirements. We may be required to incur certain capital expenditures in the future
for air pollution control equipment in connection with obtaining and maintaining pre-construction and operating
permits and approvals for air emissions. In addition, the EPA has developed, and continues to develop, stringent
regulations governing emissions of toxic air pollutants at specified sources. For example, on April 17, 2012, the
EPA finalized rules that would establish new air emission controls for oil and natural gas production operations.
Specifically, the EPA’s rule includes New Source Performance Standards to address emissions of sulfur dioxide
and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants
frequently associated with oil and natural gas production and processing activities. Among other things, these
standards would require the application of reduced emission completion techniques for completion of newly drilled
and fractured wells in addition to existing wells that are refractured. The rules also establish specific requirements
regarding emissions from compressors, dehydrators, storage tanks and other production equipment. These rules
could require a number of modifications to operations at certain of our oil and gas properties including the
installation of new equipment. Compliance with such rules could result in significant costs, including increased
capital expenditures and operating costs, which may adversely impact our business. Federal and state regulatory
agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other
requirements of the CAA and associated state laws and regulations.
Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate
production of hydrocarbons, particularly natural gas, from tight formations. Hydraulic fracturing has been utilized
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in the completion of wells we have drilled, and we expect it will also be used in the future. The process involves
the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and
stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA
recently took the position that hydraulic fracturing operations using diesel are subject to regulation under the
Underground Injection Control program of the Safe Drinking Water Act as Class II wells and has commenced
drafting guidance for permitting authorities and the industry regarding the process for obtaining a permit for
hydraulic fracturing involving diesel. Industry groups have filed suit challenging the EPA’s recent decision. At the
same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing
activities on drinking water resources. The EPA published a progress report of the study in December 2012 and
expects to release the final results by 2014. Moreover, the EPA announced in October 2011 that it is also launching
a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards
by 2014 that such wastewater must meet before being transported to a treatment plant. Other federal agencies are
also examining hydraulic fracturing, including the U.S. Department of Energy (“DOE”), the U.S. Government
Accountability Office and the White House Council for Environmental Quality. The U.S. Department of the
Interior is also considering regulation of hydraulic fracturing activities on public lands. In addition, the Fracturing
Responsibility and Awareness of Chemicals Act (“FRAC Act”) has been introduced in Congress to provide for
federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process.
Also, some states have adopted, and other states are considering adopting, regulations that could restrict or impose
additional requirements relating to hydraulic fracturing in certain circumstances. For example, on June 17, 2011,
Texas enacted a law that requires the disclosure of information regarding the substances used in the hydraulic
fracturing process to the Railroad Commission of Texas (the entity that regulates oil and natural gas production)
and the public. Such federal or state legislation could require the disclosure of chemical constituents used in the
fracturing process to state or federal regulatory authorities who could then make such information publicly
available. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing
hydraulic fracturing to pursue legal proceedings against producers and service providers based on allegations that
specific chemicals used in the fracturing process could adversely affect human health or the environment, including
groundwater. In addition, if hydraulic fracturing is regulated at the federal level, our fracturing activities could
become subject to additional permit requirements or operational restrictions and also to associated permitting
delays and potential increases in costs. Further, at least three local governments in Texas have imposed temporary
moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to
address such activities. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such
legal requirements could make it more difficult or costly for us to perform hydraulic fracturing activities.
Moreover, we believe that enactment of legislation regulating hydraulic fracturing at the federal level may have a
material adverse effect on our business.
Global Warming and Climate Change. On December 15, 2009, the EPA published its findings that emissions of
carbon dioxide, methane, and other greenhouse gases (“GHG”) present an endangerment to public health and the
environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s
atmosphere and other climate changes. Based on these findings, the EPA has begun adopting and implementing
regulations that restrict emissions of GHG under existing provisions of the CAA, including one rule that limits
emissions of GHG from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final
motor vehicle GHG emission standards trigger the CAA construction and operating permit requirements for
stationary sources, commencing when the motor vehicle standards took effect on January 2, 2011. On June 3,
2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under
the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. This rule “tailors” these
permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the
largest sources first subject to permitting. Further, facilities required to obtain PSD permits for their GHG
emissions are required to reduce those emissions consistent with guidance for determining “best available control
technology” standards for GHG, which guidance was published by the EPA in November 2010. Also in November
2010, the EPA expanded its existing GHG reporting rule to include onshore oil and natural gas production,
processing, transmission, storage, and distribution facilities. This rule requires reporting of GHG emissions from
such facilities on an annual basis with reporting beginning in 2012 for emissions occurring in 2011. We believe
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that we are in compliance with all substantial applicable emissions requirements, and we are preparing to comply
with future requirements.
In addition, both houses of Congress have considered legislation to reduce emissions of GHG, and many states have
already taken legal measures to reduce emissions of GHG, primarily through the development of GHG inventories,
greenhouse gas permitting and/or regional GHG cap and trade programs. Most of these cap and trade programs
work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission
allowances, with the number of allowances available for purchase reduced each year until the overall GHG
emission reduction goal is achieved. In the absence of new legislation, the EPA is issuing new regulations that
limit emissions of GHG associated with our operations which will require us to incur costs to inventory and reduce
emissions of GHG associated with our operations and which could adversely affect demand for the oil and natural
gas that we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations
of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased
frequency and severity of storms, droughts, floods and other climatic events.
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 (“OCSLA”), the National Environmental Policy Act (“NEPA”), and the Coastal Zone
Management Act (“CZMA”) require federal agencies to evaluate environmental issues in connection with granting
such approvals and/or taking other major agency actions. OCSLA, 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, NEPA 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 CZMA, 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 all applicable regulations.
Employees
As of December 31, 2012, we had 829 full-time employees, including 33 senior level geoscientists and 71
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, exhibits 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. Risk Factors
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, NGL and natural gas production heavily influences our revenue, profitability, access to capital
and future rate of growth. The prices we receive for our production depend on numerous factors beyond our
control. These factors include, but are not limited to, the following:
• changes in regional, domestic and global supply and demand for oil and natural gas;
• the actions of the Organization of Petroleum Exporting Countries;
• the price and quantity of imports of foreign oil and natural gas;
• political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-
producing activity, such as recent conflicts in the Middle East;
• the level of global oil and natural gas exploration and production activity;
• the effects of global credit, financial and economic issues;
• the level of global oil and natural gas inventories;
• developments of United States energy infrastructure, such as the recent announcement of the planned reversal
of the Seaway pipeline from Cushing, Oklahoma to the Gulf Coast and the development of liquefied natural
gas exporting facilities and the perceived timing thereof;
• weather conditions;
• technological advances affecting energy consumption;
• domestic and foreign governmental regulations;
• proximity and capacity of oil and natural gas pipelines and other transportation facilities;
• the price and availability of competitors’ supplies of oil and natural gas in captive market areas;
• the price and availability of alternative fuels; and
• acts of force majeure.
Moreover, government regulations, such as regulation of oil and natural gas gathering and transportation, can
adversely affect commodity prices in the long term.
Lower oil, NGL and natural gas prices may not only decrease our revenues on a per unit basis but also may
ultimately reduce the amount of oil and natural gas that we can produce economically and therefore potentially
lower our reserve quantities. A substantial or extended decline in oil, NGL 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, NGL 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.
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Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could
adversely affect our business, financial condition or results of operations.
Our future success will depend on the success of our development, exploitation, production and exploration
activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our
control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our
decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the
evaluation of data obtained through geophysical and geological analyses, production data and engineering studies,
the results of which are often inconclusive or subject to varying interpretations. Please read “— Reserve estimates
depend on many assumptions that may turn out to be inaccurate...” later in these Risk Factors for a discussion of the
uncertainty involved in these processes. Our cost of drilling, completing and operating wells is often uncertain
before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project
uneconomical. Further, many factors may curtail, delay or cancel drilling, including the following:
• delays imposed by or resulting from compliance with regulatory requirements;
• pressure or irregularities in geological formations;
• shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs, completion
services and CO2;
• equipment failures or accidents;
• adverse weather conditions, such as freezing temperatures, hurricanes and storms;
• reductions in oil, NGL and natural gas prices;
• pipeline takeaway and refining and processing capacity; and
• title problems.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased
costs and additional operating restrictions or delays.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons
from tight formations. The process involves the injection of water, sand and chemicals under pressure into
formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing has been utilized to
complete wells in our most active areas located in the states of Colorado, Michigan, Montana, North Dakota and
Texas, and we expect it will also be used in the future. Should our exploration and production activities expand to
other states, it is likely that we will utilize hydraulic fracturing to complete or recomplete wells in those areas. The
process is typically regulated by state oil and gas commissions. However, the EPA has asserted federal regulatory
authority over hydraulic fracturing involving diesel under the Safe Drinking Water Act’s Underground Injection
Control Program and has commenced drafting guidance for permitting authorities and the industry regarding the
process for obtaining a permit for hydraulic fracturing involving diesel. Industry groups have filed suit challenging
the EPA’s recent decision.
At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing
activities on drinking water resources. The EPA published a progress report of the study in December 2012 and
expects to release the final results by 2014. Moreover, the EPA announced in October 2011 that it is also launching
a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards
by 2014 that such wastewater must meet before being transported to a treatment plant. Other federal agencies are
also examining hydraulic fracturing, including the DOE, the U.S. Government Accountability Office and the White
House Council for Environmental Quality. The U.S. Department of the Interior is also considering regulation of
hydraulic fracturing activities on public lands. In addition, legislation called the FRAC Act has been introduced in
Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in
the fracturing process. Also, some states have adopted, and other states are considering adopting, regulations that
could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances. For
example, on June 17, 2011, Texas enacted a law that requires the disclosure of information regarding the substances
used in the hydraulic fracturing process to the Railroad Commission of Texas (the entity that regulates oil and
natural gas production) and the public. Such federal or state legislation could require the disclosure of chemical
23
constituents used in the fracturing process to state or federal regulatory authorities who could then make such
information publicly available. Disclosure of chemicals used in the fracturing process could make it easier for third
parties opposing hydraulic fracturing to pursue legal proceedings against producers and service providers based on
allegations that specific chemicals used in the fracturing process could adversely affect human health or the
environment including groundwater. In addition, if hydraulic fracturing is regulated at the federal level, our
fracturing activities could become subject to additional permit requirements or operational restrictions and also to
associated permitting delays, litigation risk and potential increases in costs. Further, at least three local
governments in Texas have imposed temporary moratoria on drilling permits within city limits so that local
ordinances may be reviewed to assess their adequacy to address such activities. No assurance can be given as to
whether or not similar measures might be considered or implemented in the jurisdictions in which our properties are
located. If new laws or regulations that significantly restrict or otherwise impact hydraulic fracturing are passed by
Congress or adopted in the states where our properties are located, such legal requirements could make it more
difficult or costly for us to perform hydraulic fracturing activities and thereby could affect the determination of
whether a well is commercially viable. In addition, restrictions on hydraulic fracturing could reduce the amount of
oil and natural gas that we are ultimately able to produce in commercially paying quantities.
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 or
if we are otherwise limited in the quantities of CO2 available to us, we may not have sufficient CO2 to produce oil
and natural gas in the manner or to the extent that we anticipate, and our future oil and gas production volumes
could be negatively impacted. These contracts are also structured as “take-or-pay” arrangements, which require us
to continue to make payments even if we decide to terminate or reduce our use of CO2 as part of our enhanced
recovery techniques.
The development of the proved undeveloped reserves in the North Ward Estes field may take longer and may
require higher levels of capital expenditures than we currently anticipate.
As of December 31, 2012, proved undeveloped reserves comprised 43% of the North Ward Estes field’s total
estimated proved reserves. To fully develop these reserves, we expect to incur future development costs of
$750.0 million at the North Ward Estes field as of December 31, 2012. This field encompasses 28% of our total
estimated future development costs 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.
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
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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 flow rates 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, NGL 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 periodically review the carrying value of our producing 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, NGL 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 $3.2 million impairment write-down during 2011
for the partial impairment of producing properties, primarily natural gas, in California and Michigan. 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 recognized.
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 the
following:
• historical production from the area compared with production rates from other producing areas;
• the assumed effect of governmental regulation; and
• assumptions about future prices of oil, NGLs and natural gas including differentials, production and
development costs, gathering and transportation costs, severance and excise taxes, capital expenditures and
availability of funds.
Therefore, estimates of oil and natural gas reserves are inherently imprecise. Actual future production; oil, NGL
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 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
25
discounted future net cash flows of our estimated proved reserves as of December 31, 2012 would have decreased
from $5,407.0 million to $5,398.9 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, 2012 would have decreased
from $5,407.0 million to $5,312.0 million.
Risks associated with the production, gathering, transportation and sale of oil, NGLs and natural gas could
adversely affect net income and cash flows.
Our net income and cash flows will depend upon, among other things, oil, NGL and natural gas production and the
prices and costs incurred to exploit oil and natural gas reserves. Drilling, production or transportation accidents that
temporarily or permanently halt the production and sale of oil, NGLs and natural gas will decrease revenues and
increase expenditures. For example, accidents may occur that result in personal injuries, property damage, damage
to productive formations or equipment and environmental damages. Any costs incurred in connection with any
such accidents that are not insured against will have the effect of reducing net income. Also, we do not have
insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing
operations. Please read “— Federal and state legislative and regulatory initiatives relating to hydraulic
fracturing...” above in these Risk Factors for a discussion of the uncertainty involved in the practice of hydraulic
fracturing. In addition, curtailments or damage to pipelines used to transport oil, NGLs and natural gas production
to markets for sale could decrease revenues or increase transportation expenses. Any such curtailment or damage
to the gathering systems could also require finding alternative means to transport the oil, NGLs and natural gas
production, which alternative means could result in additional costs that will have the effect of increasing
transportation expenses.
Also, drilling, production and transportation of hydrocarbons bear an inherent risk of loss of containment. Potential
consequences include loss of reserves, loss of production, loss of economic value associated with the affected
wellbore, contamination of soil, ground water, and surface water, as well as potential fines, penalties or damages
associated with any of the foregoing consequences.
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, 2012, we had $1,200.0 million in borrowings and $2.4 million in letters of credit outstanding
under Whiting Oil and Gas Corporation’s credit agreement with $797.6 million of available borrowing capacity, as
well as $600.0 million of senior subordinated notes outstanding. We are permitted to incur additional indebtedness,
provided we meet certain requirements in the indentures governing our senior subordinated notes and Whiting Oil
and Gas Corporation’s credit agreement.
Our level of indebtedness and the covenants contained in the agreements governing our debt could have important
consequences for our operations, including:
• requiring us to dedicate a substantial portion of our cash flow from operations to required payments on debt,
thereby reducing the availability of cash flow for working capital, capital expenditures and other general
business activities;
• limiting our ability to obtain additional financing in the future for working capital, capital expenditures,
acquisitions and general corporate and other activities;
• limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we
operate;
• placing us at a competitive disadvantage relative to other less leveraged competitors;
• making us vulnerable to increases in interest rates, because debt under Whiting Oil and Gas Corporation’s
credit agreement is subject to certain rate variability; and
• potentially limiting our ability to pay dividends in cash on our convertible perpetual preferred stock.
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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 oil and gas reserves.
Upon a redetermination, if borrowings in excess of the revised borrowing capacity were outstanding, we could be
forced to immediately repay a portion of our debt under the credit agreement.
We may not have sufficient funds to make such repayments. If we are unable to repay our debt out of cash on
hand, we could attempt to refinance such debt, sell assets or repay such debt with the proceeds from an equity
offering. We may not be able to generate sufficient cash flow to pay the interest on our debt or future borrowings,
and equity financings or proceeds from the sale of assets may not be available to pay or refinance such debt. The
terms of our debt, including Whiting Oil and Gas Corporation’s credit agreement, may also prohibit us from taking
such actions. Factors that will affect our ability to raise cash through an offering of our capital stock, a refinancing
of our debt or a sale of assets include financial market conditions and our market value and operating performance
at the time of such offering or other financing. We may not be able to successfully complete any such offering,
refinancing or sale of assets.
The instruments governing our indebtedness contain various covenants limiting the discretion of our
management in operating our business.
The indentures governing our senior subordinated notes and Whiting Oil and Gas Corporation’s credit agreement
contain various restrictive covenants that may limit our management’s discretion in certain respects. In particular,
these agreements will limit our and our subsidiaries’ ability to, among other things:
• pay dividends on, redeem or repurchase our capital stock or redeem or repurchase our subordinated debt;
• make loans to others;
• make investments;
• incur additional indebtedness or issue preferred stock;
• create certain liens;
• sell assets;
• enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;
• consolidate, merge or transfer all or substantially all of our assets and those of our restricted subsidiaries taken
as a whole;
• engage in transactions with affiliates;
• enter into hedging contracts;
• create unrestricted subsidiaries; and
• enter into sale and leaseback transactions.
In addition, Whiting Oil and Gas Corporation’s credit agreement requires us, as of the last day of any quarter, (i) to
not exceed a total debt to the last four quarters’ EBITDAX ratio (as defined in the credit agreement) of 4.25 to 1.0
for quarters ending prior to and on December 31, 2012 and 4.0 to 1.0 for the quarters ending March 31, 2013 and
thereafter and (ii) to have a consolidated current assets to consolidated current liabilities ratio (as defined in the
credit agreement and which includes an add back of the available borrowing capacity under the credit agreement) of
not less than 1.0 to 1.0. 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 these covenants, then we may not be able to incur
27
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 further funds available to us. 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, existing financing arrangements and certain oil and gas divestitures. Our cash flow
from operations and access to capital is subject to a number of variables, including:
• our proved reserves;
• the level of oil and natural gas we are able to produce from existing wells;
• the prices at which oil and natural gas are sold;
• the costs of producing oil and natural gas; and
• our ability to acquire, locate and produce new reserves.
If our revenues or the borrowing base under our bank credit agreement decreases as a result of lower oil and natural
gas prices, operating difficulties, declines in reserves, or for any other reason, then we may have limited ability to
obtain the capital necessary to sustain our operations at current levels.
We may, from time to time, need to seek additional financing. There can be no assurance as to the availability or
terms of any additional financing. If additional capital is needed, we may not be able to obtain debt or equity
financing on terms favorable to us, or at all. If cash generated by operations or available under our revolving credit
facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a
curtailment of our operations relating to the exploration and development of our prospects, which in turn could lead
to a possible loss of properties and a decline in our oil and natural gas reserves.
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.
28
Our acquisition activities may not be successful.
As part of our growth strategy, we have made and may continue to make acquisitions of businesses and properties.
However, suitable acquisition candidates may not continue to be available on terms and conditions we find
acceptable, and acquisitions pose substantial risks to our business, financial condition and results of operations. In
pursuing acquisitions, we compete with other companies, many of which have greater financial and other resources
to acquire attractive companies and properties. The following are some of the risks associated with acquisitions,
including any completed or future acquisitions:
• some of the acquired businesses or properties may not produce revenues, reserves, earnings or cash flow at
anticipated levels;
• we may assume liabilities that were not disclosed to us or that exceed our estimates;
• we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational
and other benefits in a timely manner, which could result in substantial costs and delays or other operational,
technical or financial problems;
• acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to
maintain our current business standards, controls and procedures; and
• we may issue additional equity or debt securities related to future acquisitions.
Substantial acquisitions or other transactions could require significant external capital and could change our
risk and property profile.
In order to finance acquisitions of additional producing or undeveloped properties, we may need to alter or increase
our capitalization substantially through the issuance of debt or equity securities, the sale of production payments or
other means. These changes in capitalization may significantly affect our risk profile. Additionally, significant
acquisitions or other transactions can change the character of our operations and business. The character of the new
properties may be substantially different in operating or geological characteristics or geographic location than our
existing properties. Furthermore, we may not be able to obtain external funding for additional future acquisitions or
other transactions or to obtain external funding on terms acceptable to us.
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.
The demand for qualified and experienced field personnel to conduct field operations, geologists, geophysicists,
engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation
with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs
and other oilfield equipment as demand for rigs and equipment has increased along with the number of wells being
drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil
and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and
associated supplies, equipment and services. Additionally, our operations in some instances require supply
materials such as CO2 for production which could become subject to shortage and increasing costs. Shortages of
field personnel, drilling rigs, equipment, supplies or personnel or price increases 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, or restrict operations.
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, 2012, we had identified a drilling inventory of over
2,400 gross drilling locations. These scheduled drilling locations represent a significant part of our growth strategy.
29
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 may 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 2010, we recorded a $5.8 million non-cash charge for the
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.
Properties that we acquire may not produce as projected, and we may be unable to identify liabilities associated
with the properties or obtain indemnities from sellers for liabilities they may have created.
Our business strategy includes a continuing acquisition program. From 2004 through 2012, we completed 16
separate significant acquisitions of producing properties with a combined purchase price of $1,900.3 million for
estimated proved reserves as of the effective dates of the acquisitions of 230.9 MMBOE. The successful
acquisition of producing properties requires assessments of many factors, which are inherently inexact and may be
inaccurate, including the following:
• the amount of recoverable reserves;
• future oil and natural gas prices;
• estimates of operating costs;
• estimates of future development costs;
• timing of future development costs;
• estimates of the costs and timing of plugging and abandonment; and
• potential environmental and other liabilities.
Our assessment will not reveal all existing or potential problems, nor will it permit us to become familiar enough
with the properties to assess fully their capabilities and deficiencies. In the course of our due diligence, we may not
inspect every well, platform, facility 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.
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Our use of oil and natural gas price hedging contracts involves credit risk and may limit higher revenues in the
future in connection with commodity price increases and may result in significant fluctuations in our net
income.
We enter into hedging transactions of our oil and natural gas production revenues 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 6, 2013, we had contracts, which include our 10% share of the Whiting USA Trust II
hedges, covering the sale of between 1,044,340 and 1,334,550 barrels of oil per month for all of 2013. All of our
oil hedges will expire by December 2014. 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.
We recognize all gains and losses from changes in commodity derivative fair values immediately in earnings rather
than deferring any such amounts in accumulated other comprehensive income. Consequently, we may experience
significant net 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.
An increase in the differential or decrease in the premium between the NYMEX or other benchmark prices 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, but sometimes at a
premium, to the relevant benchmark prices such as NYMEX. A negative difference between the benchmark price
and the price received is called a differential and a positive difference is called a premium. The differential and
premium may vary significantly due to market conditions, the quality and location of production and other risk
factors. We cannot accurately predict oil and natural gas differentials and premiums. Increases in the differential
and decreases in the premium 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.
31
We may incur substantial losses and be subject to substantial liability claims as a result of our oil and gas
operations.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could
materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas
exploration and production activities are subject to all of the operating risks associated with drilling for and
producing oil and natural gas, including the possibility of:
• environmental hazards, such as uncontrollable flows of oil, gas, brine, well fluids, toxic gas or other pollution
into the environment, including groundwater and shoreline contamination;
• abnormally pressured formations;
• mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
• fires and explosions;
• personal injuries and death; and
• natural disasters.
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 and increase capital expenditures.
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 our 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 decisions with respect
to the timing and amount of capital expenditures, the period of time over which the operator seeks to generate a
return on capital expenditures, inclusion of other participants in drilling wells, and the use of technology, as well as
the operator’s expertise and financial resources and the operator’s relative interest in the field. Operators may also
opt to decrease operational activities following a significant decline in oil or natural gas prices. 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. Accordingly, while we use commercially reasonable efforts to cause the operator to act
as a reasonably prudent operator, we are limited in our ability to do so.
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.
32
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, NGL and natural gas
production depends on a number of factors, including the demand for and supply of oil, NGLs and natural gas and
the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends
substantially on the availability and capacity of gathering systems, pipelines and processing facilities owned and
operated by third-parties. Additionally, entering into arrangements for these services exposes us to the risk that
third parties will default on their obligations under such arrangements. Our failure to obtain such services on
acceptable terms or the default by a third party on their obligation to provide such services could materially harm
our business. We may be required to shut in wells for a lack of a market or because access to gas pipelines,
gathering systems or processing facilities may be limited or unavailable. If that were to occur, then we would be
unable to realize revenue from those wells until production arrangements were made to deliver the production to
market.
We are subject to complex laws that can affect the cost, manner or feasibility of doing business.
Exploration, development, production and sale of oil and natural gas are subject to extensive federal, state, local
and international regulation. We may be required to make large expenditures to comply with governmental
regulations. Matters subject to regulation include:
• discharge permits for drilling operations;
• drilling bonds;
• reports concerning operations;
• the spacing of wells;
• unitization and pooling of properties; and
• taxation.
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 and adversely
affect our financial condition and results of operations.
Our operations may incur substantial costs and 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. Private parties, including the surface owners of properties upon
which we drill, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for
33
non-compliance with environmental laws and regulations or for personal injury or property damage. We may not
be able to recover some or any of these costs from insurance. Moreover, federal law and some state laws 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 may have a materially adverse impact on our
business. For example, as a result of the explosion and fire on the Deepwater Horizon drilling rig in April 2010 and
the release of oil from the Macondo well in the Gulf of Mexico, there has been a variety of governmental regulatory
initiatives to make more stringent or otherwise restrict oil and natural gas drilling operations in certain locations.
Any increased governmental regulation or suspension of oil and natural gas exploration or production activities that
arises out of these incidents could result in higher operating costs, which could, in turn, adversely affect our
operating results. Also, for instance, any changes in laws or regulations 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.
Climate change legislation or regulations restricting emissions of “greenhouse gasses” could result in increased
operating costs and reduced demand for oil and gas that we produce.
On December 15, 2009, the U.S. Environmental Protection Agency (the “EPA”) published its findings that
emissions of carbon dioxide, methane, and other greenhouse gases (“GHG”) present an endangerment to public
health and the environment because emissions of such gases are, according to the EPA, contributing to the warming
of the earth’s atmosphere and other climate changes. Based on these findings, the EPA has begun adopting and
implementing regulations that restrict emissions of GHG under existing provisions of the federal Clean Air Act (the
“CAA”), including one rule that limits emissions of GHG from motor vehicles beginning with the 2012 model year.
The EPA has asserted that these final motor vehicle GHG emission standards trigger the CAA construction and
operating permit requirements for stationary sources, commencing when the motor vehicle standards took effect on
January 2, 2011. On June 3, 2010, the EPA published its final rule to address the permitting of GHG emissions
from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs.
This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-
step process, with the largest sources first subject to permitting. Further, facilities required to obtain PSD permits
for their GHG emissions are required to reduce those emissions consistent with guidance for determining “best
available control technology” standards for GHG, which guidance was published by the EPA in November 2010.
Also in November 2010, the EPA expanded its existing GHG reporting rule to include onshore oil and natural gas
production, processing, transmission, storage, and distribution facilities. This rule requires reporting of GHG
emissions from such facilities on an annual basis with reporting beginning in 2012 for emissions occurring in 2011.
In addition, both houses of Congress have actively considered legislation to reduce emissions of GHG, and many
states have already taken legal measures to reduce emissions of GHG, primarily through the development of GHG
inventories, greenhouse gas permitting and/or regional GHG cap and trade programs. Most of these cap and trade
programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender
emission allowances, with the number of allowances available for purchase reduced each year until the overall
GHG emission reduction goal is achieved. In the absence of new legislation, the EPA is issuing new regulations
that limit emissions of GHG associated with our operations which will require us to incur costs to inventory and
reduce emissions of GHG associated with our operations and which could adversely affect demand for the oil,
NGLs and natural gas that we produce. Finally, it should be noted that some scientists have concluded that
increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical
effects, such as increased frequency and severity of storms, droughts, floods and other climatic events; if any such
effects were to occur, they could have an adverse effect on our assets and operations.
34
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, Chairman and Chief
Executive Officer; James T. Brown, President and Chief Operating Officer; Mark R. Williams, Senior Vice
President, Exploration and Development; J. Douglas Lang, Vice President, Reservoir Engineering/Acquisitions;
Rick A. Ross, Vice President, Operations; David M. Seery, Vice President, Land; Michael J. Stevens, Vice
President and Chief Financial Officer; or Peter W. Hagist, Vice President, Permian Operations, 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 or deferred as a result of future legislation.
In February 2012, President Obama’s Administration released its proposed federal budget for fiscal year 2013 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.
Such changes include, but are not limited to:
• the repeal of the percentage depletion allowance for oil and gas properties;
• the elimination of current deductions for intangible drilling and development costs;
• the elimination of the deduction for certain U.S. production activities; and
• an extension of the amortization period for certain geological and geophysical expenditures.
It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective. The
passage of any legislation containing these or similar changes in U.S. federal income tax law could eliminate or
defer certain tax deductions that are currently available with respect to oil and gas exploration and development,
and any such changes could negatively affect our financial condition and results of operations.
35
In connection with the passage of the Dodd-Frank Wall Street Reform and Consumer Protection Act, new
regulations forthcoming in this area may result in increased costs and cash collateral requirements for the types
of oil and gas derivative instruments we use to manage our risks related to oil and gas commodity price volatility.
On July 21, 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act was enacted into law. This
financial reform legislation includes provisions that require over-the-counter derivative transactions to be executed
through an exchange or centrally cleared. In addition, the legislation provides an exemption from mandatory
clearing requirements based on regulations to be developed by the Commodity Futures Trading Commission (the
“CFTC”) and the SEC for transactions by non-financial institutions to hedge or mitigate commercial risk. At the
same time, the legislation includes provisions under which the CFTC may impose collateral requirements for
transactions, including those that are used to hedge commercial risk. However, during drafting of the legislation,
members of Congress adopted report language and issued a public letter stating that it was not their intention to
impose margin and collateral requirements on counterparties that utilize transactions to hedge commercial risk.
Final rules on major provisions in the legislation, like new margin requirements, will be established through
rulemakings and will not take effect until 12 months after the date of enactment. Although we cannot predict the
ultimate outcome of these rulemakings, new regulations in this area may result in increased costs and cash
collateral requirements for the types of oil and gas derivative instruments we use to hedge and to otherwise manage
our financial risks related to volatility in oil and gas commodity prices.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Properties
Summary of Oil and Gas Properties and Projects
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, 2012, our estimated proved reserves in the Rocky Mountain region were 195.2
MMBOE (79% oil), which represented 51% of our total estimated proved reserves and contributed 67.6 MBOE/d
of average daily production in December 2012.
Sanish Field. Our Sanish area in Mountrail County, North Dakota encompasses approximately 107,800 gross
(66,100 net) developed and undeveloped acres. Net production in the Sanish field averaged 32.6 MBOE/d for the
fourth quarter of 2012, representing a 4% increase from 31.4 MBOE/d in the third quarter of 2012. As of
December 31, 2012, we had seven drilling rigs active in the Sanish field. Two of these rigs are drilling multiple
wells from the same drilling location or well pad (“pad drilling”). We plan to initiate a higher density pilot program
in the Sanish field in the first half of 2013. We also plan to re-fracture stimulate several wells in our Sanish field in
2013.
In order to process the produced gas stream from the Sanish wells, we constructed and brought on-line the
Robinson Lake gas plant. In December 2010, we added additional equipment which brought the plant’s processing
capacity to 90 MMcf/d. In April 2011, we added fractionation equipment which allows us to produce propane and
butane, which end products are typically sold for higher realized prices in local markets. Additionally, we added
compression in September 2012 that brought the plant’s inlet capacity to 72 MMcf/d, and we intend to add field
compression during 2013 in order to fully utilize the 90 MMcf/d processing capability.
Lewis & Clark/Pronghorn. Our Lewis & Clark/Pronghorn prospects are located primarily in the Stark and Billings
counties of North Dakota and run along the Bakken shale pinch-out in the southern Williston Basin. In this area,
the Upper Bakken shale is thermally mature, moderately over-pressured, and we believe that it has charged
reservoir zones within the immediately underlying Pronghorn Sand and Three Forks formations (Middle Bakken
36
and Lower Bakken Shale is absent). As of December 31, 2012, the Lewis & Clark/Pronghorn prospects
encompassed approximately 398,300 gross (263,000 net) developed and undeveloped acres. Net production in the
Lewis & Clark/Pronghorn prospects averaged 13.4 MBOE/d in the fourth quarter of 2012, representing a 10%
increase from 12.2 MBOE/d in the third quarter of 2012. As of December 31, 2012, we had seven drilling rigs
operating in the Pronghorn prospect, making this our second most active area in the Williston Basin. Four of the
rigs working in the Pronghorn prospect are utilizing pad drilling, drilling two or three wells from each pad. We are
realizing cost efficiencies with the use of multi-well pads in the drilling and completion of wells. We also plan to
conduct a higher density pilot program in the Pronghorn prospect in 2013.
We have completed the construction of our gas processing plant located south of Belfield, North Dakota, which has
a processing capacity of 30 MMcf/d and which primarily processes production from the Pronghorn area. Currently,
there is inlet compression in place to process 24 MMcf/d, and as of December 31, 2012 the plant was processing 18
MMcf/d. In November 2012, we began connecting other operators’ wells to the plant. We intend to add inlet
compression during 2013 in order to fully utilize the 30 MMcf/d processing capability. We are also currently
installing fractionation equipment to convert NGLs into propane and butane, which end products are typically sold for
higher realized prices in local markets In May 2012, we sold a 50% ownership interest in the plant, gathering systems
and related facilities. We retained a 50% ownership interest and will continue to operate the Belfield plant and
facilities. Additionally, we completed construction on an oil terminal and a seven-mile oil transmission line to
allow for the delivery of oil production from the Pronghorn prospect into the Bridger Four Bears oil transmission
system. The use of this terminal will reduce our transportation costs per barrel and thereby increase our returns on
the development of this prospect.
Hidden Bench/Tarpon. Our Hidden Bench and Tarpon prospects in McKenzie County, North Dakota target the
Bakken and Three Forks formations and encompass approximately 49,100 gross (28,600 net) developed and
undeveloped acres and 8,100 gross (6,300 net) developed and undeveloped acres, respectively, as of December 31,
2012. Net production at Hidden Bench/Tarpon averaged 3.1 MBOE/d in the fourth quarter of 2012, which
represents a 23% increase from 2.5 MBOE/d in the third quarter of 2012. We drilled a highly productive Tarpon
Federal well in late 2011 in the Tarpon prospect. Based on the results, we had planned to drill additional wells in
Tarpon but were delayed by federal drilling permit requirements for these wells. During the fourth quarter of 2012,
we received the required permits and drilled four additional wells in this area. We expect to drill most of the
remaining planned Tarpon development wells during 2013. We have implemented pad drilling at our Tarpon
prospect and plan to drill three wells from each pad.
Missouri Breaks Prospect. As of December 31, 2012, we had approximately 95,900 gross (66,100 net) developed
and undeveloped acres at our Missouri Breaks prospect located in Richland County, Montana and McKenzie
County, North Dakota. In the fourth quarter of 2012, net production from the Missouri Breaks prospect averaged
1.7 MBOE/d, representing a 189% increase from 0.6 MBOE/d in the third quarter of 2012. We have drilled
successful wells on the western and southern portions of our acreage. In the fourth quarter of 2012, we completed
our first well on the eastern portion of our Missouri Breaks prospect.
Big Island Prospect. As of December 31, 2012, we had approximately 172,500 gross (122,400 net) developed and
undeveloped acres at our Big Island prospect, which is located in Golden Valley County, North Dakota and Wibaux
County, Montana. We are using 3-D seismic interpretations to identify Red River drilling locations at our Big
Island prospect. We plan to use a horizontal well to test the Lower Red River “D” zone in 2013.
Redtail Prospect. As of December 31, 2012, we had approximately 109,900 gross (79,500 net) developed and
undeveloped acres at our Redtail prospect in the Weld County, Colorado portion of the Denver Julesburg Basin. In
2012, we drilled 15 wells in this prospect and were very encouraged with the results. We plan to drill up to eight
Niobrara “B” wells per spacing unit and utilize pad drilling to place the wells. The associated gas produced along
with Niobrara crude oil must be processed before being sold, and we have therefore initiated the construction of our
own gas processing plant in Weld County, Colorado for this purpose. The plant’s planned inlet capacity will be 15
MMcf/d. The air permit for the plant was filed with the Colorado Department of Public Health and Environment in
November 2012. We have ordered the major equipment necessary to construct this plant, and we plan to have the
37
plant online in early 2014. As of December 31, 2012, we had one drilling rig operating in this area, and we plan to
add a second drilling rig in mid-year 2013 and a third upon completion of the plant.
Permian Basin Region
Our Permian Basin operations include assets in Texas and New Mexico. As of December 31, 2012, the Permian
Basin region contributed 123.8 MMBOE (84% oil) of estimated proved reserves to our portfolio of operations,
which represented 33% of our total estimated proved reserves and contributed 11.0 MBOE/d of average daily
production in December 2012.
North Ward Estes Field. The North Ward Estes field includes six base leases with 100% working interests in
approximately 62,100 gross (60,400 net) developed and undeveloped acres in Ward and Winkler counties, Texas.
Current EOR production is from the Yates formation at 2,600 feet, which 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, 2012 were 41% PDP, 16% PDNP and 43% PUD.
The North Ward Estes field has been responding positively to our water and CO2 floods that we initiated in May
2007. In the fourth quarter of 2012, production from the field averaged 8.5 MBOE/d, which was consistent with
production rates in the third quarter of 2012. As of December 31, 2012, we were injecting approximately 350
MMcf/d of CO2 in this field, over half of which is recycled. In this field, we are developing new and reactivated
wells for water and CO2 injection and for production purposes. Additionally, we plan to install oil, gas and water
processing facilities in eight phases. The first three phases are essentially complete and are currently undergoing
water and CO2 injection. The field and injection infrastructure of Phase IV is complete, and injection has been
initiated on about half of the project.
In order to fully develop the proved undeveloped reserves at North Ward Estes within our currently planned
timeframe, we will need to utilize significant quantities of purchased CO2. As of December 31, 2012, we currently
have under contract 100% of the future CO2 volumes that we believe are necessary to develop the field’s proved
undeveloped reserves. In addition, we are currently in negotiations and planning for future sources capable of
generating sufficient CO2 quantities to carry out the development of all probable and possible reserves at North
Ward Estes. However, we cannot provide absolute assurance with respect to the timing or actual quantities of CO2
that will be obtainable for the development of oil and gas reserves at this field.
Big Tex Prospect. As of December 31, 2012, we had accumulated approximately 116,700 gross (86,900 net)
developed and undeveloped acres at our Big Tex prospect in Pecos, Reeves and Ward counties, Texas in the
Delaware Basin. Prospective formations include the Brushy Canyon, Bone Spring and Wolfcamp horizons.
During 2013, we plan to drill three wells in the Big Tex prospect, all of which are expected to be horizontal
Wolfcamp wells. In late 2012, we completed a well utilizing a cemented liner and a plug and perf completion
technique that is providing encouraging early results. We plan to implement this completion strategy on the
horizontal wells drilled during 2013.
Mid-Continent Region
Our Mid-Continent operations include assets in Oklahoma, Arkansas and Kansas. As of December 31, 2012, the
Mid-Continent region contributed 49.2 MMBOE (83% oil) of proved reserves to our portfolio of operations, which
represented 13% of our total estimated proved reserves and contributed 7.9 MBOE/d of average daily production in
December 2012. 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 26,400 gross (26,100 net) developed and undeveloped acres.
Four of the units are currently active CO2 enhanced recovery projects. In the fourth quarter of 2012, production
from the field averaged 7.8 MBOE/d, which represents a 4% decrease from 8.2 MBOE/d in the third quarter of
2012. As of December 31, 2012, we were injecting approximately 120 MMcf/d of CO2 in this field, over half of
38
which is recycled gas. We manage our CO2 flood at Postle on a pattern-by-pattern basis in order to optimize
utilization of CO2, crude oil production, and ultimate recovery. A pattern typically consists of a producing well
surrounded by four water/CO2 injectors. As a pattern matures, increasing volumes of water are alternated with CO2
injection to control gas breakthrough and to optimize sweep efficiency. This process, referred to as “WAG” (Water
Alternating Gas), typically results in the highest possible oil recovery. In the Postle field, the estimated proved
reserves as of December 31, 2012 were 73% PDP, 2% PDNP and 25% PUD.
We are the sole owner of the Dry Trails gas plant located in the Postle field. This plant is comprised of two trains
each with a processing capacity of approximately 40 MMcf/d. The more recent train, which Whiting constructed,
utilizes a membrane technology to extract CO2 from the produced wellhead mixture of hydrocarbon and CO2 gas,
so that it 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. We
have entered into long-term purchase agreements that will provide the necessary CO2 to carry out the flood over the
life of the field.
Michigan Region
As of December 31, 2012, our estimated proved reserves in the Michigan region were 7.6 MMBOE (22% oil),
which represents 2% of our total estimated proved reserves, and our December 2012 daily production averaged 2.7
MBOE/d. 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.
Gulf Coast Region
Our Gulf Coast operations include assets located in Texas, Louisiana and Mississippi. As of December 31, 2012,
the Gulf Coast region contributed 3.0 MMBOE (33% oil) of proved reserves to our portfolio of operations, which
represented 1% of our total estimated proved reserves and contributed 1.2 MBOE/d of average daily production in
December 2012.
Reserves
As of December 31, 2012, 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, 2012 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, 2012) is as follows:
Oil
(MBbl)
NGLs
(MBbl)
Natural Gas
(MMcf)
Total
(MBOE)
Proved reserves
190,845
Developed ................................................................
110,440
Undeveloped ................................................................
301,285
Total proved—December 31, 2012 ................................
Probable reserves
2,343
Developed ................................................................
82,639
Undeveloped ................................................................
84,982
Total probable—December 31, 2012 ................................
Possible reserves
772
Developed ................................................................
122,407
Undeveloped ................................................................
123,179
Total possible—December 31, 2012 ................................
39
24,204
15,894
40,098
534
11,388
11,922
97
21,839
21,936
160,893
63,371
224,264
6,984
102,598
109,582
1,721
154,661
156,382
241,864
136,896
378,760
4,041
111,127
115,168
1,156
170,022
171,178
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 2012, total extensions and discoveries of 81.5 MMBOE were primarily attributable to successful drilling in the
Sanish field, Redtail prospect, Missouri Breaks prospect and the Pronghorn area. The new producing wells in these
fields and their related proved undeveloped locations added during the year increased our proved reserves.
In 2012, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of
7.1 MMBOE. Included in these revisions were (i) 11.8 MMBOE of downward adjustments caused by lower crude
oil and natural gas prices incorporated into our reserve estimates at December 31, 2012 as compared to December
31, 2011 and (ii) 4.7 MMBOE of net upward adjustments attributable to reservoir analysis and well performance.
The gas component of the net 4.7 MMBOE revision consisted of a 1.1 MMBOE decrease that was primarily related
to (i) a downward revision for the recent performance of various gas wells in the Central Rockies area, and (ii)
performance adjustments on various oil wells in the Northern Rockies area and Permian Basin region that
negatively impacted those wells’ associated gas reserves. Partially offsetting these negative revisions was an
increase in associated gas volumes related to additional oil reserves assigned to the Postle and North Ward Estes
fields.
Proved undeveloped reserves. From December 31, 2011 to December 31, 2012, our proved undeveloped reserves
(“PUDs”) increased 28% or 29.9 MMBOE. This increase in proved undeveloped reserves was primarily
attributable to additional PUD locations added as a result of successful drilling in the Northern and Central Rockies
areas and additional PUD reserves being assigned to our Postle and North Ward Estes EOR projects. There were
16.8 MMBOE of PUDs that became proved developed reserves during the year as a result of 83 proved
undeveloped well locations that were drilled and placed on production in 2012. We incurred $392.2 million in
capital expenditures, or $23.33 per BOE, to drill and bring on-line these 83 PUD locations. In addition, there were
approximately 7.1 MMBOE of PUDs that became proved developed reserves in 2012 at our CO2 EOR projects in
the Postle and North Ward Estes fields. These PUDs were converted to proved developed at a cost of
approximately $34.95 per BOE. Combining the PUD drilling conversions with the PUD enhanced oil recovery
conversions, the Company converted 23.9 MMBOE of PUDs to proved developed reserves during 2012 at a cost of
$26.80 per BOE.
Based on our 2012 year end independent engineering reserve report, we will drill all of our individual PUD drilling
locations within five years. However, we do have certain quantities of proved undeveloped reserves in the North
Ward Estes field that will remain in the PUD category for periods extending beyond five years because of certain
external factors that preclude the development of the North Ward Estes enhanced oil recovery PUDs all at once.
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. External factors
that preclude the initiation of the CO2 project throughout the field at the same time include: (i) the volume of
injection water necessary to repressure the reservoir in advance of the CO2 injection, (ii) the volume of purchased
and recycled CO2 necessary to be injected to process the oil in the reservoir, and (iii) the equipment and manpower
necessary to build the infrastructure and prepare the wells for the CO2 enhanced recovery project. Our staged
development plan is designed to expand the project as quickly and efficiently as possible to fully develop 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
40
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 and 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.
Increases in probable reserves during 2012 were primarily attributable to (i) 400 new probable undeveloped well
locations, which were added in 2012 as a result of our drilling activity in the Rocky Mountains region, and (ii) new
probable reserve volumes in the Queen formation at North Ward Estes, that were added due to successful CO2 pilot
floods that were carried out on this reservoir.
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. 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 decreased during 2012 primarily due to successful drilling at our Sanish field, Lewis &
Clark/Pronghorn prospects and Hidden Bench/Tarpon prospects, which resulted in possible reserves being
promoted to either the probable or proved reserve categories in these areas.
At December 31, 2012, our probable reserves were estimated to be 115.2 MMBOE and our possible reserves were
estimated to be 171.2 MMBOE, for a total of 286.3 MMBOE. The EOR project at our North Ward Estes field
represented 106.8 MMBOE, or 37%, of our total 286.3 MMBOE probable and possible reserve quantities. In order
to fully develop the EOR probable and possible reserves at North Ward Estes, we will need to utilize significant
quantities of purchased CO2. We are currently in negotiations and planning for future sources capable of generating
sufficient CO2 quantities to carry out the development of all probable and possible reserves at North Ward Estes.
However, the availability of future CO2 supplies is subject to uncertainty and may require significant future capital
expenditures by us, and we cannot therefore provide assurance with respect to the timing or actual quantities of CO2
that will be obtainable for the development of such reserves.
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
41
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 into 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. Following these reviews, the reserve database and
supporting data 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 D. Ravnaas,
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 and Acquisitions is responsible for overseeing the preparation of the
reserves estimates. He has over 39 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, 2012.
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
Net
Gross
Undeveloped Acreage
Net(2)
Gross(2)
California ...........................................
Colorado .............................................
Louisiana ............................................
Michigan ............................................
Montana .............................................
North Dakota ......................................
Oklahoma ...........................................
Texas ..................................................
Utah ....................................................
Wyoming ............................................
Other(1) ...............................................
25,548
46,454
39,431
141,800
61,808
460,297
85,969
260,358
31,148
97,964
26,634
Total ............................................ 1,277,411
3,606
28,815
7,353
63,571
33,754
259,780
54,143
146,910
16,016
56,455
9,935
-
137,285
54,383
9,291
204,826
382,232
566
149,707
332,964
51,581
1,832
-
89,318
49,835
6,554
151,473
258,660
175
107,857
179,815
38,363
1,266
Total Acreage
Gross
25,548
183,739
93,814
151,091
266,634
842,529
86,535
410,065
364,112
149,545
28,466
Net
3,606
118,133
57,188
70,125
185,227
518,440
54,318
254,767
195,831
94,818
11,201
680,338
1,324,667
883,316
2,602,078
1,563,654
_____________________
(1) Other includes Alabama, Arkansas, Kansas, Mississippi, Nebraska and New Mexico.
(2) Out of a total of approximately 1,324,667 gross (883,316 net) undeveloped acres as of December 31, 2012, the portion of
our net undeveloped acres that is subject to expiration over the next three years, if not successfully developed or renewed,
is less than 12% in 2013, approximately 9% in 2014 and 21% in 2015.
42
Production History
The following table presents historical information about our produced oil and gas volumes:
Year Ended December 31,
2011
2012
2010
Oil production (MMBbl) ............................................................................................
NGL production (MMBbl) .........................................................................................
Natural gas production (Bcf) ......................................................................................
Total production (MMBOE) ......................................................................................
Daily production (MBOE/d) ......................................................................................
North Ward Estes field production (1)
Oil production (MMBbl) .....................................................................................
NGL production (MMBbl) ..................................................................................
Natural gas production (Bcf) ...............................................................................
Total production (MMBOE) ...............................................................................
Sanish field production (1)
Oil production (MMBbl) .....................................................................................
NGL production (MMBbl) ..................................................................................
Natural gas production (Bcf) ...............................................................................
Total production (MMBOE) ...............................................................................
Average sales prices (before the effects of hedging):
Oil (per Bbl) ........................................................................................................$
NGLs (per Bbl) ...................................................................................................$
Natural gas (per Mcf) ..........................................................................................$
Average production costs:
Production costs (per BOE) (2) ............................................................................$
23.1
2.8
25.8
30.2
82.5
2.8
0.3
0.3
3.2
9.0
1.2
3.6
10.8
18.3
2.1
26.4
24.8
67.9
2.6
0.4
0.4
3.0
6.5
0.8
2.2
7.7
17.5
1.5
27.4
23.6
64.6
2.4
0.3
0.4
2.8
6.4
0.4
2.5
7.2
83.86
39.36
3.42
11.92
$
$
$
$
88.61
52.38
4.92
11.77
$
$
$
$
72.61
47.33
4.86
10.62
_____________________
(1) The North Ward Estes and Sanish fields were our only fields that contained 15% or more of our total proved reserve
volumes as of December 31, 2012.
(2) Production costs reported above exclude from lease operating expenses ad valorem taxes of $16.3 million ($0.54 per
BOE), $13.9 million ($0.56 per BOE) and $17.7 million ($0.75 per BOE) for the years ended December 31, 2012, 2011
and 2010, respectively.
Productive Wells
The following table summarizes gross and net productive oil and natural gas wells by region at December 31, 2012.
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
Gross
2,916
Rocky Mountains ................................
4,053
Permian Basin ................................
598
Mid-Continent ................................
Michigan ...........................................................
77
82
Gulf Coast .........................................................
7,726
Total ..........................................................
Net
832
1,709
386
42
42
3,011
Gross
420
390
184
1,100
398
2,492
Natural Gas Wells
Net
227
125
68
418
78
916
Total Wells(1)
Gross
3,336
4,443
782
1,177
480
10,218
Net
1,059
1,834
454
460
120
3,927
_____________________
(1) 133 wells have multiple completions. These 133 wells contain a total of 333 completions. One or more completions in
the same bore hole are counted as one well.
We have an interest in or operate 35 EOR projects, which include both secondary (waterflood) and tertiary (CO2
injection) recovery efforts, and aggregate production from such EOR fields averaged 19.1 MBOE/d during 2012 or
23% of our 2012 daily production. For these areas, we need to use enhanced recovery techniques in order to
maintain oil and gas production from these fields.
43
Drilling Activity
We are engaged in numerous drilling activities on properties presently owned, and we intend to drill or develop
other properties acquired in the future. 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 below 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.
Productive
Gross Wells
Dry
Total
Productive
Net Wells
Dry
Total
2012:
Development .............................
Exploratory ................................
Total ..........................................
2011:
Development .............................
Exploratory ................................
Total ..........................................
2010:
Development .............................
Exploratory ................................
Total ..........................................
324
68
392
218
60
278
163
20
183
-
5
5
3
3
6
3
3
6
324
73
397
221
63
284
166
23
189
140.4
47.8
188.2
93.9
36.6
130.5
73.8
10.5
84.3
-
4.7
4.7
1.5
3.0
4.5
0.7
3.0
3.7
140.4
52.5
192.9
95.4
39.6
135.0
74.5
13.5
88.0
As of December 31, 2012, 25 operated drilling rigs were active on our properties. We were also participating in the
drilling of nine non-operated wells. The breakdown of our operated rigs by region is as follows:
Region
Rocky Mountains ............................................................................................................................................
North Ward Estes ............................................................................................................................................
Postle ..............................................................................................................................................................
Total ...........................................................................................................................................................
Drilling Rigs
22
2
1
25
Hydraulic Fracturing
Hydraulic fracturing is a common practice in the oil and gas industry that is used to stimulate production of
hydrocarbons from tight oil and gas formations. The process involves the injection of water, sand and chemicals
under pressure into formations to fracture the surrounding rock and stimulate production. This process has
typically been regulated by state oil and gas commissions. However, as described in more detail in Item 1.
“Business – Regulation – Environmental Regulations – Hydraulic Fracturing” of this Annual Report on Form 10-K,
the EPA has initiated the regulation of hydraulic fracturing; other federal agencies are examining hydraulic
fracturing; and federal legislation is pending with respect to hydraulic fracturing. We have utilized hydraulic
fracturing in the completion of our wells in our most active areas located in the states of North Dakota, Colorado,
Michigan, Montana and Texas, and we plan on continuing to utilize this completion methodology.
Proved undeveloped reserves associated with hydraulic fracture treatments consist of substantially all of our proved
undeveloped reserves, or 136.9 MMBOE.
In November 2010, we had a well control incident involving one well in our Sanish field, whereby the North
Dakota Industrial Commission (“NDIC”) filed a complaint against Whiting alleging the violation of regulations.
This matter resulted in us entering into a consent agreement with the NDIC, pursuant to which we paid $4,357 in
costs, donated $15,000 to the North Dakota Abandoned Oil and Gas Well Plugging and Site Reclamation Fund, and
44
agreed to implement certain operational procedures. Other than this incident, we are not aware of any
environmental incidents, citations or suits related to hydraulic fracturing operations involving oil and gas properties
that we operate or our non-operated interests.
In order to minimize any potential environmental impact from hydraulic fracture treatments, we have taken the
following steps:
• we follow fracturing and flowback procedures that comply with or exceed NDIC or other state requirements;
• we train all company and contract personnel, who are responsible for well preparation, fracture stimulation and
flowback, on our procedures;
• we have implemented the incremental procedures of running a well casing caliper; visually inspecting the
surface joint of intermediate casing; and if a lighter wall joint of casing or drilling wear is detected, the
minimum burst pressure is reduced accordingly;
• for wells that are within one mile of major bodies of water or locations that lead to bodies of water, we
construct sufficient berming around the well location prior to initiating fracturing operations;
• we run fracturing strings in certain situations when extra precaution is warranted, such as where the anticipated
maximum treating pressure for the well is greater than the pressure rating of the intermediate casing or in areas
located within one mile of major bodies of water; and
• we are constructing a facility in North Dakota to treat and dispose of flow fluids from well stimulations.
While we do not have insurance policies in effect that are intended to provide coverage for losses solely related to
hydraulic fracturing operations, we do have general liability and excess liability insurance policies that we believe
would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in
accordance with, and subject to, the terms of such policies.
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, 2012, we had delivery commitments of 4.4 Bcf (or 17% of total 2012 natural gas production)
and 4.0 Bcf (16%) for the years ended December 31, 2013 and 2014, respectively. These contracts relate to
production at our Boies Ranch field in Rio Blanco County, Colorado and our Flat Rock field in Uintah County,
Utah. We believe that 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. Mine Safety Disclosures
Not applicable.
45
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information, as of February 15, 2013, regarding the executive officers of
Whiting Petroleum Corporation:
Name
James J. Volker ..........................................
James T. Brown .........................................
Mark R. Williams ......................................
Bruce R. DeBoer ........................................
Heather M. Duncan ....................................
J. Douglas Lang .........................................
Rick A. Ross ..............................................
David M. Seery ..........................................
Michael J. Stevens .....................................
Brent P. Jensen ...........................................
Age
66
60
56
60
42
63
54
58
47
43
Position
Chairman and Chief Executive Officer
President and Chief Operating Officer
Senior Vice President, Exploration and Development
Vice President, General Counsel and Corporate Secretary
Vice President, Human Resources
Vice President, Reservoir Engineering and Acquisitions
Vice President, Operations
Vice President, Land
Vice President and Chief Financial Officer
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.
Effective January 1, 2011, Mr. Volker stepped down as President, but remains Chairman and Chief Executive
Officer. Mr. Volker was co-founder, Vice President and later President of Energy Management Corporation from
1971 through 1982. He has 41 years of experience in the oil and gas industry. Mr. Volker has a Bachelor’s 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.
Effective January 1, 2011, Mr. Brown was elected President and Chief Operating Officer. Mr. Brown has 38 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.
Mark R. Williams joined us in December 1983 as Exploration Geologist and has been Vice President of Exploration
and Development since December 1999. Mr. Williams was elected Senior Vice President, Exploration and
Development effective January 1, 2011. He has 32 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.
Bruce R. DeBoer joined us as 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 33 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 16 years of human resources experience in the oil and gas industry. She holds a Bachelor of Arts
46
degree in anthropology and an MBA from the University of Colorado. She is a certified Senior Professional in
Human Resources.
J. Douglas Lang joined us in December 1999 as Senior Acquisition Engineer and became Manager of Acquisitions
and Reservoir Engineering in January 2004 and Vice President, Reservoir Engineering and Acquisitions in October
2004. His 39 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 30 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 was a past 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 32 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, became Treasurer in January 2002 and became Vice
President and Chief Financial Officer in March 2005. His 26 years of oil and gas experience includes eight years of
service 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.
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 19 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.
47
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 (as adjusted for the two-for-
one stock split as noted below) for the periods presented.
High
Low
Fiscal Year Ended December 31, 2012
Fourth Quarter (Ended December 31, 2012) .....................................................
Third Quarter (Ended September 30, 2012) ......................................................
Second Quarter (Ended June 30, 2012) .............................................................
First Quarter (Ended March 31, 2012) ..............................................................
Fiscal Year Ended December 31, 2011
Fourth Quarter (Ended December 31, 2011) .....................................................
Third Quarter (Ended September 30, 2011) ......................................................
Second Quarter (Ended June 30, 2011) .............................................................
First Quarter (Ended March 31, 2011) ..............................................................
$
$
$
$
$
$
$
$
48.87
54.86
58.33
63.97
52.38
63.31
75.40
75.91
$
$
$
$
$
$
$
$
40.19
38.29
35.68
46.55
28.87
34.65
52.08
55.26
On January 26, 2011, our Board of Directors approved a two-for-one split of the Company's shares of common
stock to be effected in the form of a stock dividend. As a result of the stock split, stockholders of record on
February 7, 2011 received one additional share of common stock for each share of common stock held. The
additional shares of common stock were distributed on February 22, 2011. All common share and per share
amounts in this Annual Report on Form 10-K for periods prior to February 2011 have been retroactively adjusted to
reflect the stock split.
On February 15, 2013, there were 622 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, 2007 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 U.S. 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
48
(b) the price per share at the beginning of the measurement period. The graph assumes $100 was invested on
December 31, 2007 in our common stock, the Standard & Poor’s Composite 500 Index and the Dow Jones U.S. Oil
Companies, Secondary Index.
Whiting Petroleum Corporation .................. $
Standard & Poor’s Composite 500 Index ....
Dow Jones U.S. Oil Companies,
12/31/07
100
100
12/31/08
$
58
62
12/31/09
124
$
76
12/31/10
203
$
86
12/31/11
162
$
86
12/31/12
150
$
97
Secondary Index ..................................
100
59
83
96
91
95
49
Item 6.
Selected Financial Data
The consolidated statements of income and statements of cash flows information for the years ended December 31,
2012, 2011 and 2010 and the consolidated balance sheet information at December 31, 2012 and 2011 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, 2009 and 2008 and the consolidated
balance sheet information at December 31, 2010, 2009 and 2008 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: proved properties in Colorado, September 1, 2010; additional interests in North Ward Estes,
November 1, 2009 and October 1, 2009; and Flat Rock natural gas field, May 30, 2008.
2012
Year Ended December 31,
2010
(dollars in millions, except per share data)
2011
2009
2008
Consolidated Statements of Income Information:
Revenues and other income:
Oil, NGL and natural gas sales ...................................................$ 2,137.7
2.3
Gain (loss) on hedging activities .................................................
29.5
Amortization of deferred gain on sale ................................
3.4
Gain on sale of properties ...........................................................
0.5
Interest income and other ............................................................
2,173.4
Total revenues and other income ............................................
$ 1,860.1
8.8
13.9
16.3
0.5
1,899.6
$ 1,475.3
23.2
15.6
1.4
0.6
1,516.1
$
917.5
38.8
16.6
5.9
0.6
979.4
$ 1,316.5
(107.6)
12.1
—
1.1
1,222.1
Costs and expenses:
Lease operating ...........................................................................
Production taxes ..........................................................................
Depreciation, depletion and amortization ................................
Exploration and impairment ........................................................
General and administrative .........................................................
Interest expense ...........................................................................
Loss on early extinguishment of debt ................................
Change in Production Participation Plan liability .......................
Commodity derivative (gain) loss, net ................................
Total costs and expenses ........................................................
Income (loss) before income taxes ...................................................
Income tax expense (benefit) ...........................................................
Net income (loss) .............................................................................
Net loss attributable to noncontrolling interest ................................
Net income (loss) available to shareholders ................................
Preferred stock dividends(1) ..............................................................
Net income (loss) available to common shareholders ......................$
Earnings (loss) per common share, basic(2) ................................$
Earnings (loss) per common share, diluted(2) ................................$
Other Financial Information:
Net cash provided by operating activities ................................ $ 1,401.2
Net cash used in investing activities .................................................$ (1,780.3)
408.1
Net cash provided by (used in) financing activities ..........................$
Capital expenditures ................................................................ $ 2,171.5
376.4
171.6
684.7
167.0
108.6
75.2
—
13.8
(85.9)
1,511.4
662.0
247.9
414.1
0.1
414.2
(1.1)
413.1
3.51
3.48
305.5
139.2
468.2
84.6
85.0
62.5
—
(0.9)
(24.8)
1,119.3
780.3
288.7
491.6
0.1
491.7
(1.1)
490.6
4.18
4.14
$
$
$
$ 1,192.1
$ (1,760.0)
564.8
$
$ 1,804.3
268.3
103.9
393.9
59.4
64.7
59.1
6.2
12.1
7.1
974.7
541.4
204.8
336.7
—
336.7
(64.0)
272.7
2.57
2.55
997.3
(914.6)
(75.7)
923.8
237.3
64.7
394.8
73.0
42.3
64.6
—
3.3
262.2
1,142.2
(162.8)
(55.9)
(106.9)
—
(106.9)
(10.3)
(117.2)
(1.18)
(1.18)
$
$
$
241.2
87.5
277.5
55.3
61.7
65.1
—
32.1
(7.1)
813.3
408.8
156.7
252.1
—
252.1
—
252.1
2.98
2.97
453.8
(523.5)
72.1
585.8
$
766.5
$ (1,138.5)
366.8
$
$ 1,330.9
$
$
$
$
$
$
$
$
$
$
$
$
$
$
Consolidated Balance Sheet Information:
Total assets ......................................................................................$ 7,272.4
Long-term debt ................................................................................$ 1,800.0
Total equity ......................................................................................$ 3,453.2
_____________________
(1) The year ended December 31, 2010 includes a cash premium of $47.5 million for the induced conversion of our 6.25%
$ 4,648.8
800.0
$
$ 2,531.3
$ 4,029.5
779.6
$
$ 2,270.1
$ 4,029.1
$ 1,239.8
$ 1,808.8
$ 6,045.6
$ 1,380.0
$ 3,029.1
Perpetual Preferred Stock.
(2) On January 26, 2011, our Board of Directors approved a two-for-one split of the Company's shares of common stock to
be effected in the form of a stock dividend effective February 22, 2011. Earnings (loss) per common share, basic and
diluted for periods prior to February 2011 have been retroactively adjusted to reflect the stock split.
50
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Unless the context otherwise requires, the terms “Whiting,” “we,” “us,” “our” or “ours” when used in this Item
refer to Whiting Petroleum Corporation, together with its consolidated subsidiaries, Whiting Oil and Gas
Corporation and Whiting Programs, Inc. When the context requires, we refer to these entities separately. This
document contains forward-looking statements, which give our current expectations or forecasts of future events.
Please refer to “Forward-Looking Statements” at the end of this Item for an explanation of these types of
statements.
Overview
We are an independent oil and gas company engaged in exploration, development, acquisition and production
activities primarily in the Rocky Mountains, Permian Basin, Mid-Continent, Michigan and Gulf Coast regions of
the United States. Prior to 2006, we generally emphasized the acquisition of properties that increased our
production levels and provided upside potential through further development. Since 2006, we have focused
primarily on organic drilling activity and on the development of previously acquired properties, specifically on
projects that we believe provide the opportunity for repeatable successes and production growth. We believe the
combination of acquisitions, subsequent development and organic drilling provides us with a broad set of growth
alternatives and allows us to direct our capital resources to what we believe to be the most advantageous
investments.
As demonstrated by our recent capital expenditure programs, we are increasingly focused on a balanced exploration
and development program, while continuing to selectively pursue acquisitions that complement our existing core
properties. We believe that our significant drilling inventory, combined with our operating experience and cost
structure, provides us with meaningful organic growth opportunities. Our growth plan is centered on the following
activities:
• pursuing the development of projects that we believe will generate attractive rates of return;
•
• maintaining a balanced portfolio of lower risk, long-lived oil and gas properties that provide stable cash flows;
allocating a portion of our exploration and development budget to leasing and exploring prospect areas;
and
seeking property acquisitions that complement our core areas.
•
We have historically acquired operated and non-operated properties that exceed our rate of return criteria. For
acquisitions of properties with additional development and exploration potential, our focus has been on acquiring
operated properties so that we can better control the timing and implementation of capital spending. In some
instances, we have been able to acquire non-operated property interests at attractive rates of return that established a
presence in a new area of interest or that have complemented our existing operations. We intend to continue to
acquire both operated and non-operated interests to the extent we believe they meet our return criteria. In addition,
our willingness to acquire non-operated properties in new geographic regions provides us with geophysical and
geologic data in some cases that leads to further acquisitions in the same region, whether on an operated or non-
operated basis. We sell properties when we believe that the sales price realized will provide an above average rate
of return for the property or when the property no longer matches the profile of properties we desire to own.
Our revenue, profitability and future growth rate depend on many factors which are beyond our control, such as
economic, political and regulatory developments and competition from other sources of energy. Oil and gas prices
historically have been volatile and may fluctuate widely in the future. The following table highlights the quarterly
average NYMEX price trends for crude oil and natural gas prices since the first quarter of 2011:
51
Crude Oil
Natural Gas
Q1
$94.25
$4.10
Q2
$102.55
$4.32
Q3
$89.81
$4.20
Q4
$94.02
$3.54
Q1
$102.94
$2.72
Q2
$93.51
$2.21
Q3
$92.19
$2.81
Q4
$88.20
$3.41
2011
2012
Lower oil and natural gas prices may not only decrease our revenues, but may also reduce the amount of oil and
natural gas that we can produce economically and therefore potentially lower our oil and gas reserves. A
substantial or extended decline in oil or natural gas prices may result in impairments of our proved oil and gas
properties and may materially and adversely affect our future business, financial condition, cash flows, results of
operations, liquidity or ability to finance planned capital expenditures. Lower oil and gas prices may also reduce
the amount of our borrowing base under our credit agreement, which is determined at the discretion of the lenders
and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Alternatively,
higher oil and natural gas prices may result in significant non-cash, mark-to-market losses being incurred on our
commodity-based derivatives, which may in turn cause us to experience net losses.
For a discussion of material changes to our proved, probable and possible reserves from December 31, 2011 to
December 31, 2012 and our ability to convert PUDs to proved developed reserves, probable reserves to proved
reserves and possible reserves to probable or proved reserves, see “Reserves” in Item 2 of this Annual Report on
Form 10-K. Additionally, for a discussion relating to the minimum remaining terms of our leases, see “Acreage” in
Item 2 of this Annual Report on Form 10-K, and for a discussion on our need to use enhanced recovery techniques,
see “Productive Wells” in Item 2 of this Annual Report on Form 10-K.
2012 Highlights and Future Considerations
Operational Highlights.
Sanish. Our Sanish field in Mountrail County, North Dakota targets the Bakken and Three Forks formations. Net
production in the Sanish field averaged 32.6 MBOE/d for the fourth quarter of 2012, representing a 4% increase
from 31.4 MBOE/d in the third quarter of 2012. In 2012, net production in the Sanish field totaled 11.4 MMBOE
(an average of 31.1 MBOE/d), representing a 40% increase from 8.1 MMBOE in 2011. As of December 31, 2012
we had seven drilling rigs active in the Sanish field. Two of these rigs are drilling multiple wells from the same
drilling location or well pad (“pad drilling”). We plan to initiate a higher density pilot program in the Sanish field
in the first half of 2013. We also plan to re-fracture stimulate several wells in our Sanish field in 2013.
Lewis & Clark/Pronghorn. Our Lewis & Clark/Pronghorn prospects are located primarily in the Stark and Billings
counties of North Dakota and run along the Bakken shale pinch-out in the southern Williston Basin. In this area,
the Upper Bakken shale is thermally mature, moderately over-pressured, and we believe that it has charged
reservoir zones within the immediately underlying Pronghorn Sand and Three Forks formations (Middle Bakken
and Lower Bakken Shale is absent). Net production in the Lewis & Clark/Pronghorn prospects averaged 13.4
MBOE/d in the fourth quarter of 2012, representing a 10% increase from 12.2 MBOE/d in the third quarter of 2012.
As of December 31, 2012, we had seven drilling rigs operating in the Pronghorn prospect, making this our second
most active area in the Williston Basin. Four of the rigs working in the Pronghorn prospect are utilizing pad
drilling, drilling two or three wells from each pad. We are realizing cost efficiencies with the use of multi-well
pads in the drilling and completion of wells. We also plan to conduct a higher density pilot program in the
Pronghorn prospect in 2013.
We have completed the construction of our gas processing plant located south of Belfield, North Dakota, which has
a processing capacity of 30 MMcf/d and which primarily processes production from the Pronghorn area. Currently,
there is inlet compression in place to process 24 MMcf/d, and as of December 31, 2012 the plant was processing 18
MMcf/d. In November 2012, we began connecting other operators’ wells to the plant. We intend to add inlet
compression during 2013 in order to fully utilize the 30 MMcf/d processing capability. We are also currently
installing fractionation equipment to convert NGLs into propane and butane, which end products are typically sold for
higher realized prices in local markets In May 2012, we sold a 50% ownership interest in the plant, gathering systems
52
and related facilities. We retained a 50% ownership interest and will continue to operate the Belfield plant and
facilities. Additionally, we completed construction on an oil terminal and a seven-mile oil transmission line to
allow for the delivery of oil production from the Pronghorn prospect into the Bridger Four Bears oil transmission
system. The use of this terminal will reduce our transportation costs per barrel and increase our returns on the
development of this prospect.
Hidden Bench/Tarpon. Our Hidden Bench and Tarpon prospects in McKenzie County, North Dakota target the
Bakken and Three Forks formations. In the fourth quarter of 2012, net production from the Hidden Bench/Tarpon
prospects averaged 3.1 MBOE/d, representing a 23% increase from 2.5 MBOE/d in the third quarter of 2012. We
drilled a highly productive Tarpon Federal well in late 2011 in the Tarpon prospect. Based on these results, we had
planned to drill additional wells in Tarpon but were delayed by federal drilling permit requirements for these wells.
During the fourth quarter of 2012, we received the required permits and drilled four additional wells in this area.
We expect to drill most of the remaining planned Tarpon development wells during 2013. We have implemented
pad drilling at our Tarpon prospect and plan to drill three wells from each pad.
Missouri Breaks Prospect. Our Missouri Breaks prospect, which is located in Richland County, Montana and
McKenzie County, North Dakota, targets the Middle Bakken formation. In the fourth quarter of 2012, net
production from the Missouri Breaks prospect averaged 1.7 MBOE/d, representing a 189% increase from 0.6
MBOE/d in the third quarter of 2012. We have drilled successful wells on the western and southern portions of our
acreage. In the fourth quarter of 2012, we completed our first well on the eastern portion of our Missouri Breaks
prospect.
Big Island Prospect. Our Big Island prospect, which is located in Golden Valley County, North Dakota and Wibaux
County, Montana, targets the Red River formation. We are using 3-D seismic interpretations to identify Red River
drilling locations at our Big Island prospect. We plan to use a horizontal well to test the Lower Red River “D” zone
in 2013.
North Ward Estes. The North Ward Estes field is located in the Ward and Winkler counties in Texas, and we
continue to have significant development and related infrastructure activity in this field since we acquired it in
2005. Our activity at North Ward Estes to date has resulted in substantial reserve additions and production
increases, and our expansion of the CO2 flood in this area continues to generate positive results.
North Ward Estes has been responding positively to the water and CO2 floods that we initiated in May 2007. We
are currently injecting CO2 in one of the largest phases of our eight-phase project at North Ward Estes, and we
anticipate a production response in early 2013. Net production from North Ward Estes averaged 8.5 MBOE/d for
the fourth quarter of 2012, which was consistent with production rates in the third quarter of 2012. As of December
31, 2012, we were injecting approximately 350 MMcf/d of CO2 into the field, over half of which is recycled.
Postle. The Postle field is located in Texas County, Oklahoma and produces from the Morrow sandstone. Postle
averaged 7.8 MBOE/d in the fourth quarter of 2012, which represents a 4% decrease from 8.2 MBOE/d in the third
quarter of 2012. As of December 31, 2012, we were injecting approximately 120 MMcf/d of CO2 into the field,
over half of which is recycled.
Big Tex. Our Big Tex prospect in Pecos, Reeves and Ward counties, Texas targets the Brushy Canyon, Bone
Spring and Wolfcamp horizons. During 2013, we plan to drill three wells in the Big Tex prospect, all of which are
expected to be horizontal Wolfcamp wells. In late 2012, we completed a well utilizing a cemented liner and a plug
and perf completion technique that is providing encouraging early results. We plan to implement this completion
strategy on the horizontal wells drilled during 2013.
Redtail. Our Redtail prospect in the Denver Julesberg Basin in Weld County, Colorado targets the Niobrara
formation. In 2012, we drilled 15 wells in this prospect, and we are very encouraged with the results. We plan to
drill up to eight Niobrara “B” wells per spacing unit and utilize pad drilling to place the wells. The associated gas
produced with the Niobrara oil must be processed before being sold, and we have therefore initiated the
53
construction of our own gas processing plant in Weld County, Colorado for this purpose. The plant’s planned inlet
capacity will be 15 MMcf/d. The air permit for the plant was filed with the Colorado Department of Public Health
and Environment in November 2012. We have ordered the major equipment necessary to construct this plant, and
our plan is to have the plant online in early 2014. As of December 31, 2012, we had one drilling rig operating in
this area, and we plan to add a second drilling rig in mid-year 2013 and a third upon completion of the plant.
Financing Highlights. In October 2012, we entered into an amendment to our existing credit agreement that
increased our borrowing base under the facility from $1.5 billion to $2.5 billion, of which $2.0 billion has been
committed by lenders and is available for borrowing. We may increase the maximum aggregate amount of
commitments under the credit agreement from $2.0 billion to $2.5 billion if certain conditions are satisfied,
including the consent of lenders participating in the increase. All other terms of the credit agreement remain
unchanged.
2013 Exploration and Development Budget. Our current 2013 exploration and development (“E&D”) budget is
$2,200.0 million, which we expect to fund substantially with net cash provided by our operating activities,
borrowings under our credit facility and certain oil and gas property divestitures. This represents a 4% increase
from the $2,111.5 million incurred on E&D (which consisted of exploration, development and acreage
expenditures) during 2012, and based on this level of capital spending, we are forecasting production growth over
our 2012 production level of 30.2 MMBOE. We expect to allocate $1,914.5 million of our 2013 budget to
exploration and development activity, $108.0 million for land and $177.5 million for facilities. To the extent net
cash provided by operating activities is higher or lower than currently anticipated, we would adjust our E&D
budget accordingly or adjust borrowings outstanding under our credit facility as needed. Our 2013 E&D budget
currently is allocated among our major development areas as indicated in the chart below. Of our existing potential
projects, we believe these present the opportunity for the highest return and most efficient use of our capital
expenditures.
Development Area
Northern Rockies ............................................................................................................................................$
CO2 projects (1) ................................................................................................................................................
Central Rockies ...............................................................................................................................................
Non-operated ...................................................................................................................................................
Land ................................................................................................................................................................
Exploration (2) ..................................................................................................................................................
Facilities ..........................................................................................................................................................
Well work, miscellaneous costs, other ............................................................................................................
1,142.2
240.3
135.6
164.0
108.0
82.4
177.5
150.0
2013 Exploration and
Development Budget
(In millions)
Total ...........................................................................................................................................................$
_____________________
(1) 2013 planned capital expenditures at our CO2 projects include $79.3 million for North Ward Estes CO2 purchases and
2,200.0
$8.0 million for Postle CO2 purchases.
(2) Comprised primarily of exploration salaries, seismic activities, lease delay rentals and exploratory drilling.
Acquisition and Divestiture Highlights. On March 28, 2012, we completed an initial public offering of units of
beneficial interest in Whiting USA Trust II (“Trust II”), selling 18,400,000 Trust II units at $20.00 per unit, which
generated net proceeds of $322.3 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 II units to the public resulted in a deferred gain on sale of $128.2 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 Trust II in exchange for 100% of the trust’s units issued, or 18,400,000 units. The net profits interest
entitles Trust II 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 on the later to occur of (1) December 31, 2021, or (2)
54
the time when 11.79 MMBOE have been produced from the underlying properties and sold. This is the equivalent
of 10.61 MMBOE in respect of Trust II’s right to receive 90% of the net proceeds from such reserves pursuant to
the net profits interest. The conveyance of the net profits interest to Trust II consisted entirely of proved reserves of
10.61 MMBOE as of the January 1, 2012 effective date, representing 3% of our proved reserves as of December 31,
2011 and 5% (or 4.5 MBOE/d) of our March 2012 average daily net production.
On May 18, 2012, we sold a 50% ownership interest in our Belfield gas processing plant, natural gas gathering
system, oil gathering system and related facilities located in Stark County, North Dakota for total cash proceeds of
$66.2 million. We used the net proceeds from the sale to repay a portion of the debt outstanding under our credit
agreement.
Results of Operations
The following table sets forth selected operating data for the periods indicated:
2012
Year Ended December 31,
2011
2010
Net production:
23.1
Oil (MMBbl) ................................................................................................
2.8
NGLs (MMBbl) ................................................................................................
Natural gas (Bcf) ................................................................................................
25.8
30.2
Total production (MMBOE) ................................................................
Net sales (in millions):
Oil (1) ................................................................................................$
NGLs ................................................................................................
Natural gas (1) ................................................................................................
Total oil, NGL and natural gas sales ................................................................
1,940.5
108.9
88.3
2,137.7
$
Average sales prices:
Oil (per Bbl) ................................................................................................
$
Effect of oil hedges on average price (per Bbl) ................................
$
Oil net of hedging (per Bbl) ................................................................
$
Average NYMEX price (per Bbl) ................................................................
83.86
(1.25)
82.61
94.19
NGLs (per Bbl) ................................................................................................
$
39.36
Natural gas (per Mcf) ................................................................ $
Effect of natural gas hedges on average price (per Mcf) ................................
Natural gas net of hedging (per Mcf) ................................................................
Average NYMEX price (per Mcf) ................................................................
3.42
0.06
3.48
2.79
$
$
Cost and expenses (per BOE):
Lease operating expenses ................................................................$
$
Production taxes ................................................................................................
$
Depreciation, depletion and amortization expense ................................
$
General and administrative expenses ................................................................
12.46
5.68
22.67
3.59
_____________________
(1) Before consideration of hedging transactions.
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
18.3
2.1
26.4
24.8
1,621.5
108.6
130.0
1,860.1
88.61
(1.67)
86.94
95.14
52.38
4.92
0.04
4.96
4.04
12.33
5.62
18.89
3.43
$
$
$
$
$
$
$
$
$
$
$
$
$
17.5
1.5
27.4
23.6
1,268.2
74.0
133.1
1,475.3
72.61
(1.47)
71.14
79.55
47.33
4.86
0.04
4.90
4.39
11.37
4.40
16.69
2.74
$
$
$
$
$
$
$
$
$
$
$
$
$
Oil, NGL and Natural Gas Sales. Our oil, NGL and natural gas sales revenue increased $277.6 million to $2,137.7
million in 2012 compared to 2011. Sales revenue is a function of oil and gas volumes sold and average commodity
prices realized. Our oil sales volumes increased 26%, and our NGL sales volumes increased 33% between periods,
while our natural gas sales volumes decreased 2%. The oil volume increase resulted primarily from drilling success
at our Sanish field, Lewis & Clark/Pronghorn prospects and our Hidden Bench/Tarpon prospects. During 2012, oil
55
production from our Sanish field increased 2,475 MBbl, while oil production from our Lewis & Clark/Pronghorn
prospects increased 2,150 MBbl compared to 2011, and oil production from our Hidden Bench/Tarpon prospects
increased 495 MBbl over the same period in 2011. These production increases were partially offset by the Trust II
divestiture, which decreased oil production by 915 MBOE in 2012. Our NGLs are generally produced concurrently
with our crude oil volumes, resulting in a high correlation between fluctuations in our oil quantities sold and our
NGL quantities sold. As a result, our NGL sales volume increases generally relate to the same areas as our oil
volume increases, such as our Sanish field, Lewis & Clark/Pronghorn prospects and our Hidden Bench/Tarpon
prospects. The gas volume decline between periods was primarily the result of normal field production decline
across several of our areas, as well as the Trust II divestiture. During 2012, gas production at our Flat Rock field
decreased 1,795 MMcf, and gas production at our Canyon field decreased 645 MMcf compared to 2011. In
addition, the Trust II divestiture in March 2012 negatively impacted gas production by 1,760 MMcf during 2012.
These gas volume declines were partially offset by increases in associated gas production of 2,035 MMcf at our
Lewis & Clark/Pronghorn prospects and 1,500 MMcf at our Sanish field, related to new wells drilled and
completed in these areas during the past twelve months.
Partially offsetting the above crude oil and NGL production-related increases in net revenue, were decreases in the
average sales prices realized for oil, NGLs and natural gas. Our average price for oil before the effects of hedging
decreased 5% in 2012 as compared to 2011, while our average price for NGLs decreased 25%, and our average
price for natural gas before the effects of hedging decreased 30% between periods.
Gain on Hedging Activities. Our gain on hedging activities decreased $6.4 million in 2012 as compared to 2011,
and it consisted of the following (in thousands):
Year Ended December 31,
2011
2012
Gains reclassified from AOCI on de-designated hedges ......................................
$
2,338
$
8,758
Effective April 1, 2009, we elected to de-designate all of our commodity derivative contracts that had been
previously designated as cash flow hedges, and we elected to discontinue all hedge accounting prospectively.
Accordingly, each period we reclassify from accumulated other comprehensive income (“AOCI”) into earnings
unrealized gains (which were frozen in AOCI on the April 1, 2009 de-designation date) upon the expiration of these
de-designated crude oil hedges, and we report such non-cash unrealized gains as gain on hedging activities.
See Item 7A, “Quantitative and Qualitative Disclosures about Market Risk,” for a list of our outstanding derivatives
as of February 6, 2013.
Lease Operating Expenses. Our lease operating expenses (“LOE”) during 2012 were $376.4 million, a $70.9
million increase over the same period in 2011. This rise in LOE in 2012 was primarily related to a $68.2 million
increase in the cost of oil field goods and services and gas plant operating expenses, both of which were associated
with net wells we added during the last twelve months. In addition, well workover activity increased to $81.9
million in 2012, as compared to $79.2 million in 2011, primarily due to a higher number of well workovers being
conducted at our Sanish field and at our CO2 project at our North Ward Estes field. This increase in workover
expense was partially offset by decreases in the number of workovers being conducted in our Western Texas
district and at our Postle CO2 project.
Our lease operating expenses on a BOE basis only slightly increased during 2012. LOE per BOE amounted to
$12.46 during 2012, which was up from $12.33 per BOE during 2011. This slight increase was mainly due to the
higher costs of oil field goods and services, plant expenses and workover activity in 2012, as discussed above,
which were largely offset by higher overall production volumes between periods.
Production Taxes. Our production taxes during 2012 were $171.6 million, a $32.4 million increase over the same
period in 2011, which increase was primarily due to higher oil, NGL and natural gas sales between periods.
56
However, our production taxes are generally calculated as a percentage of oil, NGL and natural gas sales revenue
before the effects of hedging, and this percentage on a company-wide basis was 8.0% and 7.5% for 2012 and 2011,
respectively. Our production tax rate of 8.0% for 2012 was greater than the rate for 2011 due to successful wells
completed during the past twelve months in North Dakota, which has an 11.5% tax rate. However, we attempt to
take full advantage of production tax credits and exemptions allowed in our various jurisdictions.
Depreciation, Depletion and Amortization. Our depreciation, depletion and amortization (“DD&A”) expense
increased $216.5 million in 2012 as compared to 2011. The components of our DD&A expense were as follows (in
thousands):
Year Ended December 31,
2011
2012
Depletion ..................................................................................................................
Depreciation .............................................................................................................
Accretion of asset retirement obligations .................................................................
Total ..................................................................................................................
$
$
673,789
3,672
7,263
684,724
$
$
457,499
2,688
8,016
468,203
DD&A increased in 2012 primarily due to $216.3 million in higher depletion expense between periods. This
increase was the result of $121.1 million in higher depletion due to a rise in overall production volumes during
2012 and $95.2 million in higher depletion due to an increase in our depletion rate between periods. On a BOE
basis, our DD&A rate of $22.67 for 2012 was 20% higher than the rate of $18.89 for 2011. The higher DD&A rate
was mainly due to $2,031.6 million in drilling and development expenditures during the past twelve months, which
were partially offset by reserve additions during this same time period.
Exploration and Impairment Costs. Our exploration and impairment costs increased $82.3 million in 2012 as
compared to 2011. The components of our exploration and impairment costs were as follows (in thousands):
Exploration ...............................................................................................................
Impairment ...............................................................................................................
Total ..................................................................................................................
Year Ended December 31,
2011
2012
$
$
59,117
107,855
166,972
$
$
45,861
38,783
84,644
Exploration costs increased $13.3 million during 2012 as compared to 2011 primarily due to higher exploratory dry
hole costs. Exploratory dry hole costs for 2012 totaled $18.4 million, primarily related to five exploratory dry holes
drilled in the Rocky Mountains, Permian Basin and Michigan regions during 2012. During 2011, we drilled three
exploratory dry holes in the Rocky Mountains, Permian Basin and Gulf Coast regions totaling $4.9 million.
Impairment expense in 2012 and 2011 primarily related to the amortization of leasehold costs associated with
individually insignificant unproved properties, and such amortization resulted in impairment expense of $54.5
million in 2012 as compared to $34.9 million in 2011. Also included in impairment expense for 2012 is $46.9
million in non-cash impairment charges for the partial write-down of proved properties, mainly in the Rocky
Mountains region, whose net book values exceeded their undiscounted future cash flows, whereas 2011 impairment
expense only included $3.2 million of non-cash proved property impairment write-downs.
57
General and Administrative Expenses. We report general and administrative expenses net of third-party
reimbursements and internal allocations. The components of our general and administrative expenses were as
follows (in thousands):
General and administrative expenses .......................................................................
Reimbursements and allocations ..............................................................................
General and administrative expense, net ...........................................................
$
$
Year Ended December 31,
2011
2012
153,341
199,943
(68,356)
(91,370)
84,985
108,573
$
$
General and administrative expense before reimbursements and allocations increased $46.6 million during 2012 as
compared to 2011 primarily due to higher employee compensation, an increase in accrued Production Participation
Plan (the “Plan”) distributions and a $7.8 million increase in professional fees and information technology costs.
Employee compensation increased $21.7 million in 2012 as compared to 2011 due to personnel hired during the
past twelve months, general pay increases and higher stock compensation between periods. In addition, accrued
distributions under the Plan increased general and administrative expenses by $10.7 million when comparing 2012
to 2011. Of this increase in general and administrative expenses related to Plan distributions, $8.6 million related to
the Trust II net profits interest divestiture, and $2.1 million related to a higher level of Plan net revenues (which
have been reduced by lease operating expenses and production taxes pursuant to the plan formula).
The increase in reimbursements and allocations for 2012 was primarily caused by higher salary costs and a greater
number of field workers on operated properties. Our general and administrative expenses as a percentage of oil,
NGL and natural gas sales remained constant at 5% for 2012 and 2011.
Interest Expense. The components of our interest expense were as follows (in thousands):
Year Ended December 31,
2011
2012
Senior Subordinated Notes .......................................................................................
Credit agreement .....................................................................................................
Amortization of debt issue costs and debt discount .................................................
Other ........................................................................................................................
Capitalized interest ...................................................................................................
Total ..................................................................................................................
$
$
40,250
28,043
9,518
148
(2,749)
75,210
$
$
40,250
17,049
8,682
109
(3,574)
62,516
The increase in interest expense of $12.7 million between periods was mainly attributable to an $11.0 million
increase in the amount of interest incurred on our credit agreement during 2012 as compared to 2011. Our credit
agreement interest was higher in 2012 due to a greater amount of borrowings outstanding under this facility. Our
weighted average debt outstanding during 2012 was $1,576.6 million versus $1,151.5 million for 2011. Our
weighted average effective cash interest rate was 4.3% during 2012 compared to 5.0% during 2011.
Commodity Derivative (Gain) Loss, Net. All of our commodity derivative contracts as well as our embedded
derivatives are marked-to-market each quarter with fair value gains and losses recognized immediately in earnings,
as commodity derivative (gain) loss, net. Cash flow, however, is only impacted to the extent that settlements under
these contracts result in making or receiving a payment from the counterparty, and only cash settlement gains and
losses on commodity derivatives (except for settlements on embedded derivatives) are recorded immediately to
earnings as commodity derivative (gain) loss, net. The components of commodity derivative (gain) loss, net were
as follows (in thousands):
58
Change in unrealized (gains) losses on derivative contracts ....................................
Realized cash settlement losses ................................................................................
Total ..................................................................................................................
$
$
Year Ended December 31,
2011
2012
(113,395)
27,484
(85,911)
$
$
(54,336)
29,479
(24,857)
With respect to our open derivative contracts at December 31, 2012, the futures curve of forecasted commodity
prices (“forward price curve”) for crude oil was generally below the forward price curves that were in effect when
the majority of these contracts were entered into, resulting in a net fair value asset position at the end of 2012.
However, with respect to our open derivative contracts at December 31, 2011, the forward price curve for crude oil
generally exceeded the forward price curves that were in effect when the majority of these contracts were entered
into, resulting in a net fair value liability position at the end of 2011. The change in unrealized (gains) losses on
derivative contracts in 2012 resulted in a $113.4 million gain due to the significant downward shift in the forward
price curve for NYMEX crude oil from January 1 to December 31, 2012 and the corresponding net fair value
position shifting from a liability to an asset from January 1 to December 31, 2012. The change in unrealized
(gains) losses on derivative contracts in 2011 resulted in a $54.3 million gain due to a less significant downward
shift in the same forward price curve from January 1 to December 31, 2011.
Income Tax Expense. Income tax expense totaled $247.9 million for 2012 as compared to $288.7 million of income
tax for 2011, a decrease of $40.8 million that was mainly related to $118.3 million in lower pre-tax income between
periods.
Our effective tax rates for 2012 and 2011 differ from the U.S. statutory income tax rate primarily due to the effects
of state income taxes and permanent taxable differences. Our overall effective tax rate only increased slightly
between periods from 37.0% for 2011 to 37.4% for 2012.
Year Ended December 31, 2011 Compared to Year Ended December 31, 2010
Oil, NGL and Natural Gas Sales. Our oil, NGL and natural gas sales revenue increased $384.8 million to $1,860.1
million in 2011 compared to 2010. Sales revenue is a function of oil and gas volumes sold and average commodity
prices realized. Our oil sales volumes increased 5%, and our NGL sales volumes increased 33% between periods,
while our natural gas sales volumes decreased 3%. The oil volume increase resulted primarily from drilling success
at our Lewis & Clark/Pronghorn prospects and our Hidden Bench/Tarpon prospects, as well as increased
production attributable to our CO2 project at North Ward Estes. During 2011, oil production from our Lewis &
Clark/Pronghorn prospects increased 1,045 MBbl compared to 2010, while oil production from our Hidden
Bench/Tarpon prospects increased 240 MBbl, and oil production at our North Ward Estes field increased 300 MBbl
over the same period in 2010. These production increases were partially offset by a decrease in oil production
volumes of 400 MBbl at our Postle field primarily due to normal oil and gas production decline at this field. Our
NGL production increased by 450 MBbl at our Sanish and Parshall fields in 2011 due to an increase in the number
of wells connected to the Robinson Lake gas plant during the past twelve months. Gas production volumes
decreased between periods primarily due to normal field production decline across many of our areas.
Additionally, gas production at our Sanish and Parshall fields decreased 450 MMcf due to a large number of shut-in
wells in this area during the second half of 2011. These gas volume decreases were largely offset by higher gas
production of 1,755 MMcf at our Flat Rock field, related to new wells drilled and completed in this area during the
past twelve months.
Also contributing to the above crude oil and NGL production-related increases in net revenue, were increases in the
average sales prices realized for oil, NGLs and natural gas from 2010 to 2011. Our average price for oil before the
effects of hedging increased 22% between periods, while our average price for NGLs increased 11%, and our
average price for natural gas before the effects of hedging increased 1%.
59
Gain on Hedging Activities. Our gain on hedging activities decreased $14.4 million in 2011 as compared to 2010,
and it consisted of the following (in thousands):
Year Ended December 31,
2010
2011
Gains reclassified from AOCI on de-designated hedges ............................................
$
8,758
$
23,198
Effective April 1, 2009, we elected to de-designate all of our commodity derivative contracts that had been
previously designated as cash flow hedges, and we elected to discontinue all hedge accounting prospectively.
Accordingly, each period we reclassify from AOCI into earnings unrealized gains (which were frozen in AOCI on
the April 1, 2009 de-designation date) upon the expiration of these de-designated crude oil hedges, and we report
such non-cash unrealized gains as gain on hedging activities.
See Item 7A, “Quantitative and Qualitative Disclosures about Market Risk,” for a list of our outstanding derivatives
as of February 6, 2013.
Lease Operating Expenses. Our lease operating expenses (“LOE”) during 2011 were $305.5 million, a $37.1
million increase over the same period in 2010. This rise in LOE in 2011 was related to a higher level of workover
activity, as well as a $24.5 million increase in the cost of oil field goods and services associated with net wells we
added during the last twelve months. Workovers activity increased to $79.2 million in 2011, as compared to $66.6
million in 2010, primarily due to a higher number of well workovers being conducted on our two main CO2
projects.
Our lease operating expenses on a BOE basis also increased in 2011. LOE per BOE amounted to $12.33 during
2011, which was up from $11.37 per BOE during 2010. This increase was mainly due to the higher amount of
workover activity in 2011, as discussed above.
Production Taxes. Our production taxes during 2011 were $139.2 million, a $35.3 million increase over the same
period in 2010, which increase was primarily due to higher oil, NGL and natural gas sales between periods.
However, our production taxes are generally calculated as a percentage of oil, NGL and natural gas sales revenue
before the effects of hedging, and this percentage on a company-wide basis was 7.5% and 7.0% for 2011 and 2010,
respectively. However, we attempt to take full advantage of production tax credits and exemptions allowed in our
various jurisdictions.
Depreciation, Depletion and Amortization. Our depreciation, depletion and amortization (“DD&A”) expense
increased $74.3 million in 2011 as compared to 2010. The components of our DD&A expense were as follows (in
thousands):
Year Ended December 31,
2010
2011
Depletion ..................................................................................................................
Depreciation .............................................................................................................
Accretion of asset retirement obligations .................................................................
Total ..................................................................................................................
$
$
457,499
2,688
8,016
468,203
$
$
384,383
2,291
7,223
393,897
DD&A increased in 2011 primarily due to $73.1 million in higher depletion expense between periods. This
increase was the result of $51.2 million in higher depletion due to an increase in our depletion rate between periods
and $21.9 million in higher depletion due to a rise in overall production volumes during 2011. On a BOE basis, our
DD&A rate of $18.89 for 2011 was 13% higher than the rate of $16.69 for 2010. The higher DD&A rate was
mainly due to $1,549.3 million in drilling and development expenditures during the past twelve months, which
were partially offset by reserve additions during this same time period.
60
Exploration and Impairment Costs. Our exploration and impairment costs increased $25.3 million in 2011 as
compared to 2010. The components of our exploration and impairment costs were as follows (in thousands):
Exploration ...............................................................................................................
Impairment ...............................................................................................................
Total ..................................................................................................................
Year Ended December 31,
2010
2011
$
$
45,861
38,783
84,644
$
$
32,846
26,525
59,371
Exploration costs increased $13.0 million during 2011 as compared to 2010 primarily due to an increase in
geology-related general and administrative expenses, an increase in geological and geophysical (“G&G”) activity
and higher exploratory dry hole costs. Geology-related general and administrative expenses increased $5.9 million
between periods. G&G costs, such as seismic studies, amounted to $19.0 million during 2011 as compared to $14.3
million during 2010. During 2011, we drilled three exploratory dry holes in the Rocky Mountains, Permian Basin
and Gulf Coast regions totaling $4.9 million, while we drilled three exploratory dry holes in the Gulf Coast region
totaling $3.8 million during 2010.
Impairment expense in 2011 and 2010 primarily related to the amortization of leasehold costs associated with
individually insignificant unproved properties. A higher amount of undeveloped leasehold costs were amortized to
impairment on a group basis for 2011 as compared to 2010. Also included in impairment expense for 2011 is $3.2
million in non-cash impairment charges for the partial write-down of mainly natural gas proved properties whose
net book values exceeded their undiscounted future cash flows, whereas 2010 impairment expense included a $5.8
million impairment write-down of the remaining undeveloped leasehold costs related to the central Utah Hingeline
play.
General and Administrative Expenses. We report general and administrative expenses net of third-party
reimbursements and internal allocations. The components of our general and administrative expenses were as
follows (in thousands):
General and administrative expenses .......................................................................
Reimbursements and allocations ..............................................................................
General and administrative expense, net ...........................................................
$
$
Year Ended December 31,
2010
2011
118,606
153,341
(53,912)
(68,356)
64,694
84,985
$
$
General and administrative expense before reimbursements and allocations increased $34.7 million during 2011 as
compared to 2010 primarily due to higher employee compensation and an increase in accrued Plan distributions.
Employee compensation increased $25.2 million in 2011 as compared to 2010 due to personnel hired during the
past twelve months, general pay increases and higher stock compensation between periods. In addition, accrued
distributions under the Plan increased general and administrative expenses by $6.9 million when comparing 2011 to
2010.
The increase in reimbursements and allocations in 2011 was primarily caused by higher salary costs and a greater
number of field workers on operated properties. Our general and administrative expenses as a percentage of oil,
NGL and natural gas sales increased from 4% for 2010 to 5% for 2011.
61
Interest Expense. The components of our interest expense were as follows (in thousands):
Year Ended December 31,
2010
2011
Senior Subordinated Notes .......................................................................................
Credit agreement .....................................................................................................
Amortization of debt issue costs and debt discount .................................................
Other ........................................................................................................................
Capitalized interest ...................................................................................................
Total ..................................................................................................................
$
$
40,250
17,049
8,682
109
(3,574)
62,516
$
$
42,034
9,225
10,592
147
(2,920)
59,078
The increase in interest expense of $3.4 million between periods was mainly attributable to a $7.8 million increase
in the amount of interest incurred on our credit agreement during 2011 as compared to 2010. Our credit agreement
interest was higher in 2011 due to a greater amount of borrowings outstanding under this facility. Our weighted
average debt outstanding during 2011 was $1,151.5 million versus $739.9 million for 2010. However, our
weighted average effective cash interest rate was lower during 2011 at 5.0% compared to 6.9% during 2010. The
increase in interest incurred on our credit agreement was partially offset by lower amortization of debt issuance
costs and debt discounts of $1.9 million and lower interest of $1.8 million on our Senior Subordinated Notes.
These decreases resulted from redeeming $150.0 million of 7.25% notes and $220.0 million of 7.25% notes in early
September 2010. Also in September 2010, we subsequently issued $350.0 million of 6.5% notes due 2018.
Commodity Derivative (Gain) Loss, Net. All of our commodity derivative contracts as well as our embedded
derivatives are marked-to-market each quarter with fair value gains and losses recognized immediately in earnings,
as commodity derivative (gain) loss, net. Cash flow, however, is only impacted to the extent that settlements under
these contracts result in making or receiving a payment from the counterparty, and only cash settlement gains and
losses on commodity derivatives (except for settlements on embedded derivatives) are recorded immediately to
earnings as commodity derivative (gain) loss, net. The components of commodity derivative (gain) loss, net were
as follows (in thousands):
Year Ended December 31,
2010
2011
Change in unrealized (gains) losses on derivative contracts ....................................
Realized cash settlement losses ................................................................................
Total ..................................................................................................................
$
$
(54,336)
29,479
(24,857)
$
$
(17,537)
24,599
7,062
With respect to our open derivative contracts at December 31, 2011 and 2010, the forward price curve for crude oil
generally exceeded the forward price curves that were in effect when the majority of these contracts were entered
into, resulting in a net fair value liability position at the end of each respective period. The change in unrealized
(gains) losses on derivative contracts in 2011 resulted in a $54.3 million gain in such net liability position due to the
significant downward shift in the forward price curve for NYMEX crude oil from January 1 to December 31, 2011.
The change in unrealized (gains) losses on derivative contracts in 2010 resulted in a $17.5 million gain due to a less
significant downward shift in the same forward price curve from January 1 to December 31, 2010.
Income Tax Expense. Income tax expense totaled $288.7 million for 2011 as compared to $204.8 million of income
tax for 2010, an increase of $83.9 million that was mainly related to $238.9 million of higher pre-tax income
between periods.
Our effective tax rates for 2011 and 2010 differ from the U.S. statutory income tax rate primarily due to the effects
of state income taxes and permanent taxable differences. Our overall effective income tax rate decreased from
37.8% for 2010 to 37.0% for 2011. This change in our effective income tax rate between periods was primarily
attributable to recent North Dakota corporate tax legislation, which created a one-time benefit in 2011.
62
Liquidity and Capital Resources
Overview. At December 31, 2012, our debt to total capitalization ratio was 34.3%, we had $44.8 million of cash on
hand and $3,445.0 million of equity. At December 31, 2011, our debt to total capitalization ratio was 31.4%, we
had $15.8 million of cash on hand and $3,020.9 million of equity. During 2012, we generated $1,401.2 million of
cash provided by operating activities, an increase of $209.1 million from 2011. Cash provided by operating
activities increased primarily due to higher crude oil and NGL production volumes in 2012. This positive factor
was partially offset by lower realized sales prices for oil, NGLs and natural gas and lower natural gas production
volumes in 2012, as well as increased lease operating expenses, production taxes, general and administrative and
cash interest expense during 2012 as compared to 2011. See “Results of Operations” for more information on the
impact of prices and volumes on revenues and for more information on increases in certain expenses during 2012.
Cash flows from operating activities plus $420.0 million in net borrowings under our credit agreement, $322.3
million of proceeds from the sale of Trust II units and $69.2 million of proceeds from the sale of oil and gas
properties were used to finance $2,050.0 million of drilling and development expenditures and $121.4 million of
cash acquisition capital expenditures paid in 2012. The following chart details our exploration, development and
undeveloped acreage expenditures incurred by region during 2012 (in thousands):
Drilling and
Development
Expenditures(1)
$ 1,471,278
375,816
78,197
10,039
(2,103)
1,933,227
Rocky Mountains(2) ................................
Permian Basin ................................
Mid-Continent ................................
Gulf Coast ................................
Michigan ................................
Total incurred ................................
Decrease in accrued capital
Undeveloped
Leasehold
Expenditures
$
80,272
14,585
430
23,884
4
Exploration
Expenditures
$
30,384
19,753
1,057
2,601
5,322
Total
Expenditures
$ 1,581,934
410,154
79,684
36,524
3,223
119,175
59,117
2,111,519
% of
Total
75%
19%
4%
2%
-%
100%
expenditures ................................
32,164
-
-
32,164
Total paid ................................$ 1,965,391
_________
(1) For purposes of this schedule, exploratory dry hole costs of $18.4 million are excluded from drilling and development
expenditures as reported on the statement of cash flows and instead have been included in exploration expenditures
above.
$ 2,143,683
119,175
(2) Proceeds from the sale of the Belfield gas plant of $66.2 million have been included above as a reduction to drilling and
59,117
$
$
development expenditures in the Rocky Mountains region.
We continually evaluate our capital needs and compare them to our capital resources. Our current 2013 E&D
budget is $2,200.0 million, which we expect to fund substantially with net cash provided by our operating activities,
borrowings under our credit facility and certain oil and gas property divestitures. This represents a 4% increase
from the $2,111.5 million incurred on exploration, development and acreage expenditures during 2012, and based
on this level of capital spending, we are forecasting production growth in 2013 over our 2012 production level of
30.2 MMBOE. We expect to allocate $1,914.5 million of our 2013 budget to exploration and development activity,
$108.0 million for undeveloped acreage and $177.5 million for facilities. Although we have only budgeted $108.0
million for undeveloped leaseholds in 2013, we will continue to selectively pursue property acquisitions that
complement our existing core property base. We believe that should additional attractive acquisition opportunities
arise or exploration and development expenditures exceed $2,200.0 million, we will be able to finance additional
capital expenditures with cash on hand, cash flows from operating activities, borrowings under our credit
agreement, issuances of additional debt or equity securities, agreements with industry partners or divestitures of
certain oil and gas property interests. Our level of exploration, development and acreage expenditures is largely
discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly
depending on available opportunities, commodity prices, cash flows and development results, among other factors.
We believe that we have sufficient liquidity and capital resources to execute our business plans over the next 12
months and for the foreseeable future. In addition, with our expected cash flow streams, commodity price hedging
63
strategies, current liquidity levels, access to debt and equity markets and flexibility to modify future capital
expenditure programs, we expect to be able to fund all planned capital programs and debt repayments; comply with
our debt covenants; and meet other obligations that may arise from our oil and gas operations.
Credit Agreement. Whiting Oil and Gas Corporation (“Whiting Oil and Gas”), our wholly-owned subsidiary, has a
credit agreement with a syndicate of banks that as of December 31, 2012 had a borrowing base of $2.5 billion, of
which $2.0 billion has been committed by lenders and is available for borrowing. We may increase the maximum
aggregate amount of commitments under the credit agreement from $2.0 billion to $2.5 billion if certain conditions
are satisfied, including the consent of lenders participating in the increase. As of December 31, 2012, we had
$797.6 million of available borrowing capacity, which was net of $1,200.0 million in borrowings and $2.4 million
in letters of credit outstanding.
The borrowing base under the credit agreement is determined at the discretion of the lenders, based on the collateral
value of 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, in each
case which may reduce the amount of the borrowing base. A portion of the revolving credit facility in an aggregate
amount not to exceed $50.0 million may be used to issue letters of credit for the account of Whiting Oil and Gas or
other designated subsidiaries of ours. As of December 31, 2012, $47.6 million was available for additional letters
of credit under the agreement.
The credit agreement provides for interest only payments until April 2016, when the entire amount borrowed is due.
Interest accrues at our option at either (i) a base rate for a base rate loan plus the margin in the table below, where
the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50% or an adjusted LIBOR
rate plus 1.00%, or (ii) an adjusted LIBOR rate for a Eurodollar loan plus the margin in the table below.
Additionally, we also incur commitment fees as set forth in the table below on the unused portion of the lesser of
the aggregate commitments of the lenders or the borrowing base.
Ratio of Outstanding Borrowings to Borrowing Base
Less than 0.25 to 1.0
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0
Greater than or equal to 0.90 to 1.0
Applicable
Margin for Base
Rate Loans
Applicable
Margin for
Eurodollar Loans Commitment Fee
0.50%
0.75%
1.00%
1.25%
1.50%
1.50%
1.75%
2.00%
2.25%
2.50%
0.375%
0.375%
0.50%
0.50%
0.50%
The credit agreement contains restrictive covenants that may limit our ability to, among other things, incur
additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging
contracts, incur liens and engage in certain other transactions without the prior consent of our lenders. Except for
limited exceptions, which include the payment of dividends on our 6.25% convertible perpetual preferred stock, the
credit agreement also restricts our ability to make any dividend payments or distributions on our common stock.
These restrictions apply to all of the net assets of Whiting Oil and Gas. The credit agreement requires us, as of the
last day of any quarter, (i) to not exceed a total debt to the last four quarters’ EBITDAX ratio (as defined in the
credit agreement) of 4.25 to 1.0 for quarters ending prior to and on December 31, 2012 and 4.0 to 1.0 for the
quarters ending March 31, 2013 and thereafter and (ii) to have a consolidated current assets to consolidated current
liabilities ratio (as defined in the credit agreement and which includes an add back of the available borrowing
capacity under the credit agreement) of not less than 1.0 to 1.0. We were in compliance with our covenants under
the credit agreement as of December 31, 2012.
For further information on the interest rates and loan security related to our credit agreement, refer to the Long-
Term Debt footnote in the Notes to Consolidated Financial Statements.
64
Senior Subordinated Notes. In September 2010, we issued at par $350.0 million of 6.5% Senior Subordinated
Notes due October 2018. In October 2005, we issued at par $250.0 million of 7% Senior Subordinated Notes due
February 2014.
The indentures governing the notes restrict us from incurring additional indebtedness, subject to certain exceptions,
unless our fixed charge coverage ratio (as defined in the indentures) is at least 2.0 to 1. If we were in violation of
this covenant, then we may not be able to incur additional indebtedness, including under Whiting Oil and Gas
Corporation’s credit agreement. Additionally, the indentures governing the notes contain restrictive covenants that
may limit our ability to, among other things, pay cash dividends, redeem or repurchase our capital stock or our
subordinated debt, make investments or issue preferred stock, sell assets, consolidate, merge or transfer all or
substantially all of the assets of ours and our restricted subsidiaries taken as a whole and enter into hedging
contracts. These covenants may potentially limit the discretion of our management in certain respects. We were in
compliance with these covenants as of December 31, 2012. However, a substantial or extended decline in oil, NGL
or natural gas prices may adversely affect our ability to comply with these covenants in the future.
Shelf Registration Statement. We have on file with the SEC a universal shelf registration statement to allow us to
offer an indeterminate amount of securities in the future. Under the registration statement, we may periodically
offer from time to time debt securities, common stock, preferred stock, warrants and other securities or any
combination of such securities in amounts, prices and on terms announced when and if the securities are offered.
The specifics of any future offerings, along with the use of proceeds of any securities offered, will be described in
detail in a prospectus supplement at the time of any such offering.
Contractual Obligations and Commitments
Schedule of Contractual Obligations. The table below does not include our Production Participation Plan liability
of $143.8 million (which amount comprises both the long and short-term portions of this obligation) as of
December 31, 2012, since we cannot determine with accuracy the timing or amounts of future payments other than
the short-term portion. The following table summarizes our obligations and commitments as of December 31, 2012
to make future payments under certain contracts, aggregated by category of contractual obligation, for specified
time periods (in thousands):
Payments due by period
$
$
Total
Less than 1
year
Contractual Obligations
Long-term debt (a) ...................................................... $ 1,800,000
227,143
Cash interest expense on debt (b) ................................
23,633
Derivative contract liability fair value (c) ...................
97,818
Asset retirement obligations (d) ..................................
Tax sharing liability (e) ...............................................
22,526
712,296
Purchase obligations (f) ...............................................
187,342
Drilling rig contracts (g) ..............................................
33,947
Operating leases (h) .....................................................
Total ........................................................................ $ 3,104,705
_____________________
(a) Long-term debt consists of the 7% Senior Subordinated Notes due 2014, the 6.5% Senior Subordinated Notes due 2018
and the outstanding borrowings under our credit agreement due in 2016, and assumes no principal repayment until the
due date of the instruments.
3-5 years
$ 1,200,000
52,312
-
12,679
-
183,787
918
10,566
$ 1,460,262
-
63,770
21,955
11,639
1,452
60,899
92,823
5,402
$ 257,940
1-3 years
250,000
93,998
1,678
12,508
21,074
204,822
93,601
12,058
689,739
More than 5
years
$ 350,000
17,063
-
60,992
-
262,788
-
5,921
$ 696,764
$
(b) Cash interest expense on the 7% Senior Subordinated Notes due 2014 and the 6.5% Senior Subordinated Notes due 2018
is estimated assuming no principal repayment until the due dates of the instruments. Cash interest expense on the credit
agreement is estimated assuming no principal repayment until the 2016 instrument due date and is estimated at a fixed
interest rate of 2.0%.
(c) The above derivative obligation at December 31, 2012 primarily consists of (i) a $21.0 million fair value liability for
derivative contracts we have entered into on our own behalf, primarily in the form of costless collars, to hedge our
65
exposure to crude oil price fluctuations and (ii) a $2.6 million payable to Trust II for derivative contracts that we have
entered into but have in turn conveyed to Trust II (although these derivatives are in a fair value asset position at quarter
end, 90% of such derivative assets are due to Trust II under the terms of the conveyance). With respect to only a portion
of our open derivative contracts at December 31, 2012 with certain counterparties, the forward price curve for crude oil
generally exceeded the price curve that was in effect when these contracts were entered into, resulting in a derivative fair
value liability. If current market prices are higher than a collar’s price ceiling when the cash settlement amount is
calculated, we are required to pay the contract counterparties. The ultimate settlement amounts under our derivative
contracts are unknown, however, as they are subject to continuing market risk and commodity price volatility.
(d) Asset retirement obligations represent the present value of estimated amounts expected to be incurred in the future to plug
and abandon oil and gas wells, remediate oil and gas properties and dismantle their related facilities.
(e) Amounts shown represent the present value of estimated payments due to Alliant Energy based on projected future
income tax benefits attributable to an increase in our tax bases. As a result of the Tax Separation and Indemnification
Agreement signed with Alliant Energy, the increased tax bases are expected to result in increased future income tax
deductions and, accordingly, may reduce income taxes otherwise payable by us. Under this agreement, we have agreed
to pay Alliant Energy 90% of the future tax benefits we realize annually as a result of this step up in tax basis for the
years ending on or prior to December 31, 2013. In 2014, we will be obligated to pay Alliant Energy the present value of
the remaining tax benefits assuming all such tax benefits will be realized in future years.
(f) We have four take-or-pay purchase agreements, two agreements expiring in December 2014, one agreement expiring in
December 2017 and one agreement expiring in December 2029, whereby we have committed to buy certain volumes of
CO2 for use in enhanced recovery projects in our Postle field in Oklahoma and our North Ward Estes field in Texas. The
purchase agreements are with three different suppliers. Under the terms of the agreements, we are obligated to purchase a
minimum daily volume of CO2 (as calculated on an annual basis) or else pay for any deficiencies at the price in effect
when the minimum delivery was to have occurred. In addition, we have two ship-or-pay agreements with two different
parties, one expiring in June 2013 and one expiring in December 2017, whereby we have committed to transport a
minimum daily volume of CO2 via certain pipelines or else pay for any deficiencies at a price stipulated in the contract.
The CO2 volumes planned for use in the enhanced recovery projects in the Postle and North Ward Estes fields currently
exceed the minimum daily volumes specified in all of these agreements. Therefore, we expect to avoid any payments for
deficiencies. The purchasing obligations reported above represent our minimum financial commitment pursuant to the
terms of these contracts. However, our actual expenditures under these contracts are expected to exceed the minimum
commitments presented above.
(g) We currently have 12 drilling rigs under long-term contract, of which three drilling rigs expire in 2013, six in 2014, one
in 2015 and two in 2016. All of these rigs are operating in the Rocky Mountains region. As of December 31, 2012, early
termination of the remaining contracts would require termination penalties of $145.1 million, which would be in lieu of
paying the remaining drilling commitments of $187.3 million. No other drilling rigs working for us are currently under
long-term contracts or contracts that cannot be terminated at the end of the well that is currently being drilled. Due to the
short-term and indeterminate nature of the time remaining on rigs drilling on a well-by-well basis, such obligations have
not been included in this table.
(h) We lease 172,400 square feet of administrative office space in Denver, Colorado under an operating lease arrangement
expiring in 2018, 46,300 square feet of office space in Midland, Texas expiring in 2020 and 20,000 square feet of office
space in Dickinson, North Dakota expiring in 2016. In addition, we entered into a lease for several residential apartments
in Watford City, North Dakota under an operating lease agreement expiring in 2015.
Based on current oil and natural gas prices and anticipated levels of production, we believe that the estimated net
cash generated from operations, together with cash on hand and amounts available under our credit agreement, will
be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations
and exploration and development activities.
New Accounting Pronouncements
For further information on the effects of recently adopted accounting pronouncements and the potential effects of
new accounting pronouncements, refer to the Adopted and Recently Issued Accounting Pronouncements footnote
in the Notes to Consolidated Financial Statements.
66
Critical Accounting Policies and Estimates
Our discussion of financial condition and results of operations is based upon the information reported in our
consolidated financial statements. The preparation of these statements requires us to make certain assumptions and
estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of
contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on
historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from
our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general
business conditions and other factors. A summary of our significant accounting policies is detailed in Note 1 to our
Consolidated Financial Statements. We have outlined below certain of these policies as being of particular
importance to the portrayal of our financial position and results of operations and which require the application of
significant judgment by our management.
Successful Efforts Accounting. We account for our oil and gas operations using the successful efforts method of
accounting. Under this method, the fair value of property acquired and all costs associated with successful
exploratory wells and all development wells are capitalized. Items charged to expense generally include geological
and geophysical costs, costs of unsuccessful exploratory wells and oil and gas production costs. All of our
properties are located within the continental United States.
Oil and Natural Gas Reserve Quantities. Reserve quantities and the related estimates of future net cash flows
affect our periodic calculations of depletion, impairment of our oil and natural gas properties, asset retirement
obligations, and our long-term Production Participation Plan liability. Proved oil and gas reserves are those
quantities of oil and gas, 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. Reserve quantities and future cash flows
included in this report are prepared in accordance with guidelines established by the SEC and FASB. The accuracy
of our reserve estimates is a function of:
•
•
•
•
the quality and quantity of available data;
the interpretation of that data;
the accuracy of various mandated economic assumptions; and
the judgments of the persons preparing the estimates.
External petroleum engineers independently estimated all of the proved, probable and possible reserve quantities
included in this annual report. In connection with our external petroleum engineers performing their independent
reserve estimations, we furnish them with the following information that they review: (1) technical support data, (2)
technical analysis of geologic and engineering support information, (3) economic and production data, and (4) our
well ownership interests. The independent petroleum engineers, Cawley, Gillespie & Associates, Inc., evaluated
100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31,
2012. Estimates prepared by others may be higher or lower than our estimates. Because these estimates depend on
many assumptions, all of which may differ substantially from actual results, reserve estimates may be different
from the quantities of oil and gas that are ultimately recovered. We continually make revisions to reserve estimates
throughout the year as additional information becomes available. We make changes to depletion rates, impairment
calculations (when impairment indicators arise) and our Production Participation Plan liability in the same period
that changes to reserve estimates are made.
Depreciation, Depletion and Amortization. Our rate of recording DD&A is dependent upon our estimates of total
proved and proved developed reserves, which estimates incorporate various assumptions and future projections. If
the estimates of total proved or proved developed reserves decline, the rate at which we record DD&A expense
increases, which in turn reduces our net income. Such a decline in reserves may result from lower commodity
prices or other changes to reserve estimates, as discussed above, and we are unable to predict changes in reserve
67
quantity estimates as such quantities are dependent on the success of our exploitation and development program, as
well as future economic conditions.
Impairment of Oil and Gas Properties. We review the value of our oil and gas properties whenever management
judges that events and circumstances indicate that the recorded carrying value of properties may not be recoverable.
Impairments of producing properties are determined by comparing future net undiscounted cash flows to the net
book value at the end of each period. If the net capitalized cost exceeds undiscounted future cash flows, the cost of
the property is written down to “fair value,” which is determined using net discounted future cash flows from the
producing property. Different pricing assumptions or discount rates could result in a different calculated
impairment. In addition to proved property impairments, we provide for impairments on significant undeveloped
properties when we determine that the property will not be developed or a permanent impairment in value has
occurred. Individually insignificant unproved properties are amortized on a composite basis, based on past success,
experience and average lease-term lives.
Asset Retirement Obligation. Our asset retirement obligations (“AROs”) consist primarily of estimated future costs
associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased
acreage, and land restoration in accordance with applicable local, state and federal laws. The discounted fair value
of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset
retirement cost capitalized as part of the carrying cost of the oil and gas asset. The recognition of an ARO requires
that management make numerous assumptions regarding such factors as the estimated probabilities, amounts and
timing of settlements; the credit-adjusted risk-free rate to be used; inflation rates; and future advances in
technology. In periods subsequent to the initial measurement of the ARO, we must recognize period-to-period
changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the
original estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time impact net
income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense
through DD&A over the life of the oil and gas property.
Production Participation Plan. We have a Production Participation Plan (“Plan”) in which all employees
participate. Each year, a deemed economic interest in all oil and gas properties acquired or developed during the
year is contributed to the Plan. The Compensation Committee of the Board of Directors, in its discretion for each
Plan year, allocates a percentage of future net income (defined as gross revenues less production taxes, royalties
and direct lease operating expenses) attributable to such properties to Plan participants. Once contributed and
allocated, the interests (not legally conveyed) are fixed for each Plan year. The short-term obligation related to the
Production Participation Plan is included in the accrued liabilities and other line item in our consolidated balance
sheets. This obligation is based on cash flows during the year and is paid annually in cash after year end. The
calculation of this liability depends in part on our estimates of accrued revenues and costs as of the end of each
reporting period as discussed below under “Revenue Recognition.” The vested long-term obligation related to the
Production Participation Plan is the “Production Participation Plan liability” line item in the consolidated balance
sheets. This liability is derived primarily from reserve report estimates, which as discussed above, are subject to
revision as more information becomes available. Variances between estimates used to calculate liabilities related to
the Production Participation Plan and actual sales, costs and production data are integrated into the liability
calculations in the period identified. A 10% increase to the pricing assumptions used in the measurement of this
liability at December 31, 2012 would have decreased net income before taxes by $16.3 million in 2012.
Derivative Instruments and Hedging Activity. We periodically enter into commodity derivative contracts to manage
our exposure to oil and natural gas price volatility. We use hedging to help ensure that we have adequate cash flow
to fund our capital programs and manage returns on our acquisitions and drilling programs. Our decision on the
quantity and price at which we choose to hedge our production is based in part on our view of current and future
market conditions. While the use of these hedging arrangements limits the downside risk of adverse price
movements, they may also limit future revenues from favorable price movements. We primarily utilize costless
collars, which are generally placed with major financial institutions.
68
All derivative instruments are recorded on the consolidated balance sheet at fair value, other than the derivative
instruments that meet the “normal purchase normal sales” exclusion. Changes in the derivatives’ fair value are
recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow
hedges, the fair value gain or loss on the derivative is deferred in accumulated other comprehensive income (loss)
to the extent the hedge is effective and is reclassified to gain (loss) on hedging activities line item in our
consolidated statements of income in the period that the hedged production is delivered.
We value our costless collars using industry-standard models that consider various assumptions, including quoted
forward prices for commodities, time value, volatility factors and contractual prices for the underlying instruments,
as well as other relevant economic measures. The discount rate used in the fair values of these instruments includes
a measure of nonperformance risk by the counterparty or us, as appropriate. We utilize the counterparties’
valuations to assess the reasonableness of our valuations. The values we report in our financial statements change
as these estimates are revised to reflect changes in market conditions (particularly those for oil and natural gas
futures) or other factors, many of which are beyond our control.
The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial
terms of such transactions. We evaluate the ability of our counterparties to perform at the inception of a hedging
relationship and on a periodic basis as appropriate.
Income Taxes and Uncertain Tax Positions. We provide for income taxes in accordance with FASB ASC Topic
740, Income Taxes (“ASC 740”). We record deferred tax assets and liabilities to account for the expected future tax
consequences of events that have been recognized in our financial statements and our tax returns. We routinely
assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or
all of our deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. We consider
future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the
determination of future taxable income, including factors such as future operating conditions (particularly as related
to prevailing oil and natural gas prices).
ASC 740 requires uncertain income tax positions to meet a more-likely-than-not recognition threshold to be
recognized in the financial statements. Under ASC 740, uncertain tax positions that previously failed to meet the
more-likely-than-not threshold should be recognized in the first subsequent financial reporting period in which that
threshold is met. Previously recognized uncertain tax positions that no longer meet the more-likely-than-not
threshold should be derecognized in the first subsequent financial reporting period in which that threshold is no
longer met.
We are subject to taxation in many jurisdictions, and the calculation of our tax liabilities involves dealing with
uncertainties in the application of complex tax laws and regulations in various taxing jurisdictions. If we ultimately
determine that the payment of these liabilities will be unnecessary, we reverse the liability and recognize a tax
benefit during the period in which we determine the liability no longer applies. Conversely, we record additional
tax charges in a period in which we determine that a recorded tax liability is less than we expect the ultimate
assessment to be.
Revenue Recognition. We predominantly derive our revenue from the sale of produced oil, NGLs and gas.
Revenue is recorded in the month the product is delivered to the purchaser. We receive payment from one to three
months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers and
the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month
the payment is received. However, differences have been and are insignificant.
Accounting for Business Combinations. Our business has grown substantially through acquisitions, and our
business strategy is to continue to pursue acquisitions as opportunities arise. We have accounted for all of our
business combinations to date using the purchase method, which is the only method permitted under FASB ASC
Topic 805, Business Combinations, and involves the use of significant judgment.
69
Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon
the fair value of the consideration given. The assets and liabilities acquired are measured at their fair values, and
the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the cost of an
acquired entity, if any, over the net amounts assigned to assets acquired and liabilities assumed is recognized as
goodwill. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity,
if any, is recognized immediately to earnings as a gain from bargain purchase.
Determining the fair values of the assets and liabilities acquired involves the use of judgment, since some of the
assets and liabilities acquired do not have fair values that are readily determinable. Different techniques may be
used to determine fair values, including market prices (where available), appraisals, comparisons to transactions for
similar assets and liabilities, and present value of estimated future cash flows, among others. Since these estimates
involve the use of significant judgment, they can change as new information becomes available.
The business combinations completed during the prior three years consisted of oil and gas properties. The
consideration we have paid to acquire these properties or companies was entirely allocated to the fair value of the
assets acquired and liabilities assumed at the time of acquisition. Consequently, there was no goodwill nor any
bargain purchase gains recognized on any of our business combinations.
Effects of Inflation and Pricing
We experienced increased costs during 2011 and 2012 due to increased demand for oil field products and services.
The oil and gas industry is very cyclical, and the demand for goods and services of oil field companies, suppliers
and others associated with the industry put extreme pressure on the economic stability and pricing structure within
the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period
of declining prices, associated cost declines are likely to lag and not adjust downward in proportion to prices.
Material changes in prices also impact the current revenue stream, estimates of future reserves, borrowing base
calculations of bank loans, depletion expense, impairment assessments of oil and gas properties, and values of
properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas
companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect
business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of
materials, services and personnel.
Forward-Looking Statements
This report contains statements that we believe to be “forward-looking statements” within the meaning of the
Private Securities Litigation Reform Act of 1995. All statements other than historical facts, including, without
limitation, statements regarding our future financial position, business strategy, projected revenues, earnings, costs,
capital expenditures and debt levels, and plans and objectives of management for future operations, are forward-
looking statements. When used in this report, words such as we “expect,” “intend,” “plan,” “estimate,”
“anticipate,” “believe” or “should” or the negative thereof or variations thereon or similar terminology are generally
intended to identify forward-looking statements. Such forward-looking statements are subject to risks and
uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such
statements.
These risks and uncertainties include, but are not limited to: declines in oil, NGL or natural gas prices; our level of
success in exploration, development and production activities; adverse weather conditions that may negatively
impact development or production activities; the timing of our exploration and development expenditures; our
ability to obtain sufficient quantities of CO2 necessary to carry out our enhanced oil recovery projects; inaccuracies
of our reserve estimates or our assumptions underlying them; revisions to reserve estimates as a result of changes in
commodity prices; risks related to our level of indebtedness and periodic redeterminations of the borrowing base
under our credit agreement; our ability to generate sufficient cash flows from operations to meet the internally
funded portion of our capital expenditures budget; our ability to obtain external capital to finance exploration and
development operations and acquisitions; federal and state initiatives relating to the regulation of hydraulic
70
fracturing; the potential impact of federal debt reduction initiatives and tax reform legislation being considered by
the U.S. Federal government that could have a negative effect on the oil and gas industry; impacts of the global
recession and tight credit markets; our ability to identify and complete acquisitions and to successfully integrate
acquired businesses; unforeseen underperformance of or liabilities associated with acquired properties; our ability
to successfully complete potential asset dispositions and the risks related thereto; the impacts of hedging on our
results of operations; failure of our properties to yield oil or gas in commercially viable quantities; uninsured or
underinsured losses resulting from our oil and gas operations; our inability to access oil and gas markets due to
market conditions or operational impediments; the impact and costs of compliance with laws and regulations
governing our oil and gas operations; our ability to replace our oil and natural gas reserves; any loss of our senior
management or technical personnel; competition in the oil and gas industry in the regions in which we operate;
risks arising out of our hedging transactions; and other risks described under the caption “Risk Factors” in this
Annual Report on Form 10-K. We assume no obligation, and disclaim any duty, to update the forward-looking
statements in this Annual Report on Form 10-K.
71
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Commodity Price Risk
The price we receive for our oil and gas production heavily influences our revenue, profitability, access to capital
and future rate of growth. Crude oil and natural gas are commodities, and therefore, their prices are subject to wide
fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and gas
have been volatile, and these markets will likely continue to be volatile in the future. The prices we receive for our
production depend on numerous factors beyond our control. Based on 2012 production, our income before income
taxes for 2012 would have moved up or down $194.0 million for each 10% change in oil prices per Bbl, $10.9
million for each 10% change in NGL prices per Bbl and $8.8 million for each 10% change in natural gas prices per
Mcf.
We periodically enter into derivative contracts to achieve a more predictable cash flow by reducing our exposure to
oil and natural gas price volatility. Our derivative contracts have traditionally been costless collars, although we
evaluate other forms of derivative instruments as well. Currently, we do not apply hedge accounting, and therefore all
changes in commodity derivative fair values are recorded immediately to earnings. Recognition of derivative cash
settlement gains and losses in the consolidated statements of income occurs in the period that hedged production
volumes are sold, and the related hedge contract expires.
Commodity Derivative Contracts—Our outstanding hedges as of February 6, 2013 are summarized below:
Whiting Petroleum Corporation
Derivative
Instrument
Collars
Three-way collars(1)
Commodity
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Period
01/2013 to 03/2013
04/2013 to 06/2013
07/2013 to 09/2013
10/2013
11/2013
01/2013 to 03/2013
04/2013 to 06/2013
07/2013 to 09/2013
10/2013 to 12/2013
Monthly Volume
(Bbl)
290,000
290,000
290,000
290,000
190,000
910,000
1,040,000
1,040,000
1,040,000
Weighted Average
NYMEX Floor/Ceiling
$47.67/$90.21
$47.67/$90.21
$47.67/$90.21
$47.67/$90.21
$47.22/$85.06
$70.00/$85.00/$114.80
$71.25/$85.63/$113.95
$71.25/$85.63/$113.95
$71.25/$85.63/$113.95
_____________________
(1) A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call establishes a
maximum price (ceiling) we will receive for the volumes under contract. The purchased put establishes a minimum price
(floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be NYMEX
plus the difference between the purchased put and the sold put strike price.
Fixed-price Natural Gas Contracts. We have various fixed-price gas sales contracts with end users for a portion of
the natural gas we produce in Colorado and Utah. Our future production volumes projected to be sold under these
fixed-price contracts as of February 6, 2013 are summarized below:
Commodity
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Period
01/2013 to 03/2013
04/2013 to 06/2013
07/2013 to 09/2013
10/2013 to 12/2013
01/2014 to 03/2014
04/2014 to 06/2014
07/2014 to 09/2014
10/2014 to 12/2014
72
Monthly Volume
(MMBtu)
360,000
364,000
368,000
368,000
330,000
333,667
337,333
337,333
Weighted Average Price
Per MMBtu
$5.47
$5.47
$5.47
$5.47
$5.49
$5.49
$5.49
$5.49
Commodity Derivatives Conveyed to Whiting USA Trust II. In connection with our conveyance on March 28, 2012
of a term net profits interest to Whiting USA Trust II (“Trust II”), the rights to any future hedge payments we make
or receive on certain of our derivative contracts, representing 1,030 MBbl of crude oil from 2013 through 2014,
have been conveyed to Trust II, and therefore such payments will be included in Trust II’s calculation of net
proceeds. Under the terms of the aforementioned conveyance, we retain 10% of the net proceeds from the
underlying properties. This results in third-party public holders of Trust II units receiving 90%, while we retain
10%, of the future economic results of such hedges. No additional hedges are allowed to be placed on Trust II
assets.
The table below summarizes all of the outstanding costless collars that we entered into and then in turn conveyed,
as described in the preceding paragraph, to Trust II (of which we retain 10% of the future economic results and
third-party public holders of Trust II units receive 90% of the future economic results):
Conveyed to Whiting USA Trust II
Derivative
Instrument
Collars
Commodity
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Period
01/2013 to 03/2013
04/2013 to 06/2013
07/2013 to 09/2013
10/2013 to 12/2013
01/2014 to 03/2014
04/2014 to 06/2014
07/2014 to 09/2014
10/2014 to 12/2014
Monthly Volume
(Bbl)
45,600
45,500
44,500
43,400
42,500
41,500
40,600
39,700
NYMEX Floor/Ceiling
$80.00/$122.50
$80.00/$122.50
$80.00/$122.50
$80.00/$122.50
$80.00/$122.50
$80.00/$122.50
$80.00/$122.50
$80.00/$122.50
The collared hedges shown above (excluding the fixed-price natural gas contracts) have the effect of providing a
protective floor while allowing us to share in upward pricing movements. Consequently, while these hedges are
designed to decrease our exposure to price decreases, they also have the effect of limiting the benefit of price
increases above the ceiling. For the crude oil hedges outstanding as of December 31, 2012, a hypothetical upward
or downward shift of 10% per Bbl in the NYMEX forward curve as of December 31, 2012 would cause a decrease
or increase, respectively, of $51.0 million in our commodity derivative gain.
Embedded Commodity Derivative Contracts—The price we pay for oil field products and services significantly
impacts our profitability, reserve estimates, access to capital and future growth rate. Typically, as prices for oil and
natural gas increase, so do all associated costs. We have entered into certain contracts for oil field goods and
services with price adjustment clauses that are linked to changes in NYMEX crude oil prices, in order to reduce our
exposure to paying higher than the market rates for these goods and services in a climate of declining oil prices.
We have determined that the portions of these contracts linked to NYMEX oil prices are not clearly and closely
related to the host contracts, and we have therefore bifurcated these embedded pricing features from their host
contracts and reflected them at fair value in the consolidated financial statements. These embedded commodity
derivative contracts have not been designated as hedges, and therefore all changes in fair value since inception have
been recorded immediately to earnings.
Drilling Rig Contracts. As of December 31, 2012, we had two contracts with drilling rig companies, whereby the
rig day rates increased or decreased along with changes in the price of NYMEX crude oil. These drilling rig
contracts have termination dates of April 2014 and September 2014. For these embedded commodity derivative
contracts, a hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve as of December
31, 2012 would cause a decrease or increase, respectively, of $0.9 million in our commodity derivative (gain) loss.
CO2 Purchase Contract. In May 2011, we entered into a long-term contract to purchase CO2 from 2015 through
2029 for use in our EOR project at our North Ward Estes field in Texas. The price per Mcf of CO2 purchased under
this agreement increases or decreases as the average price of NYMEX crude oil likewise increases or decreases.
For this embedded commodity derivative contract, a hypothetical upward or downward shift of 10% per Bbl in the
73
NYMEX forward curve as of December 31, 2012 would cause a decrease or increase, respectively, of $14.4 million
in our commodity derivative (gain) loss.
Interest Rate Risk
Market risk is estimated as the change in fair value resulting from a hypothetical 100 basis point change in the
interest rate on the outstanding balance under our credit agreement. Our credit agreement allows us to fix the
interest rate for all or a portion of the principal balance for a period up to six months. To the extent that the interest
rate is fixed, interest rate changes affect the instrument’s fair market value but do not impact results of operations or
cash flows. Conversely, for the portion of the credit agreement that has a floating interest rate, interest rate changes
will not affect the fair market value but will impact future results of operations and cash flows. Changes in interest
rates do not affect the amount of interest we pay on our fixed-rate Senior Subordinated Notes. At December 31,
2012, our outstanding principal balance under our credit agreement was $1,200.0 million, and the weighted average
interest rate on the outstanding principal balance was 2.0%. At December 31, 2012, the carrying amount
approximated fair market value. Assuming a constant debt level of $1,200.0 million, the cash flow impact resulting
from a 100 basis point change in interest rates during periods when the interest rate is not fixed would be $11.1
million over a 12-month time period.
74
Item 8.
Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm ................................................................................ 76
Consolidated Balance Sheets as of December 31, 2012 and 2011 ...................................................................... 77
Consolidated Statements of Income for the Years Ended December 31, 2012, 2011 and 2010 ......................... 78
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2012,
2011 and 2010 ............................................................................................................................................. 79
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010 ................... 80
Consolidated Statements of Equity for the Years Ended December 31, 2012, 2011 and 2010 ........................... 82
Notes to Consolidated Financial Statements........................................................................................................ 83
75
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Whiting Petroleum Corporation
Denver, Colorado
We have audited the accompanying consolidated balance sheets of Whiting Petroleum Corporation and subsidiaries
(the "Company") as of December 31, 2012 and 2011, and the related consolidated statements of income,
comprehensive income, cash flows, and equity for each of the three years in the period ended December 31, 2012.
Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements
and financial statement schedule are the responsibility of the Company's management. Our responsibility is to
express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position
of Whiting Petroleum Corporation and subsidiaries as of December 31, 2012 and 2011, and the results of their
operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity
with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial
statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole,
presents fairly, in all material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States), the Company's internal control over financial reporting as of December 31, 2012, based on the
criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission and our report dated February 28, 2013 expressed an unqualified
opinion on the Company's internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 28, 2013
76
WHITING PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)
December 31,
2012
2011
ASSETS
Current assets:
Cash and cash equivalents ................................................................................................
Accounts receivable trade, net ..........................................................................................
Prepaid expenses and other ..............................................................................................
Total current assets .....................................................................................................
$
44,800
318,265
21,347
384,412
Property and equipment:
Oil and gas properties, successful efforts method:
Proved properties ........................................................................................................
Unproved properties....................................................................................................
Other property and equipment ..........................................................................................
Total property and equipment .....................................................................................
Less accumulated depreciation, depletion and amortization ............................................
Total property and equipment, net....................................................................................
Debt issuance costs...............................................................................................................
Other long-term assets ..........................................................................................................
TOTAL ASSETS ................................................................................................................
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable trade ....................................................................................................
Accrued capital expenditures ...........................................................................................
Accrued liabilities and other.............................................................................................
Revenues and royalties payable .......................................................................................
Taxes payable ...................................................................................................................
Derivative liabilities .........................................................................................................
Deferred income taxes ......................................................................................................
Total current liabilities ................................................................................................
Long-term debt .....................................................................................................................
Deferred income taxes ..........................................................................................................
Derivative liabilities .............................................................................................................
Production Participation Plan liability ..................................................................................
Asset retirement obligations .................................................................................................
Deferred gain on sale ............................................................................................................
Other long-term liabilities ....................................................................................................
Total liabilities ............................................................................................................
Commitments and contingencies ..........................................................................................
Equity:
Preferred stock, $0.001 par value, 5,000,000 shares authorized; 6.25% convertible
perpetual preferred stock, 172,391 shares issued and outstanding as of December
31, 2012 and 2011, aggregate liquidation preference of $17,239,100 at December
31, 2012 ........................................................................................................................
Common stock, $0.001 par value, 300,000,000 shares authorized; 118,582,477 issued
and 117,631,451 outstanding as of December 31, 2012, 118,105,279 issued and
117,380,884 outstanding as of December 31, 2011 ......................................................
Additional paid-in capital .................................................................................................
Accumulated other comprehensive income (loss) ............................................................
Retained earnings .............................................................................................................
Total Whiting shareholders’ equity .............................................................................
Noncontrolling interest ............................................................................................................
Total equity .................................................................................................................
TOTAL LIABILITIES AND EQUITY ............................................................................
See notes to consolidated financial statements.
$
$
$
77
$
$
$
15,811
262,515
20,377
298,703
7,221,550
354,774
150,933
7,727,257
(2,088,517)
5,638,740
33,306
74,860
6,045,609
56,673
142,827
157,214
103,894
31,195
73,647
1,584
567,034
1,380,000
823,643
47,763
80,659
61,984
29,619
25,776
3,016,478
8,849,515
362,483
141,738
9,353,736
(2,590,203)
6,763,533
28,748
95,726
7,272,419
131,370
110,663
180,622
149,692
33,283
21,955
9,394
636,979
1,800,000
1,063,681
1,678
94,483
86,179
110,395
25,852
3,819,247
-
-
119
1,566,717
(1,236)
1,879,388
3,444,988
8,184
3,453,172
7,272,419
$
118
1,554,223
240
1,466,276
3,020,857
8,274
3,029,131
6,045,609
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per share data)
Year Ended December 31,
2011
2010
2012
REVENUES AND OTHER INCOME:
Oil, NGL and natural gas sales .............................................................. $ 2,137,714 $ 1,860,146 $ 1,475,288
Gain on hedging activities ......................................................................
23,198
15,613
Amortization of deferred gain on sale ....................................................
1,388
Gain on sale of properties ......................................................................
612
Interest income and other .......................................................................
1,516,099
Total revenues and other income ....................................................
8,758
13,937
16,313
468
1,899,622
2,338
29,458
3,423
519
2,173,452
COSTS AND EXPENSES:
Lease operating ......................................................................................
Production taxes .....................................................................................
Depreciation, depletion and amortization ..............................................
Exploration and impairment ...................................................................
General and administrative ....................................................................
Interest expense ......................................................................................
Loss on early extinguishment of debt ....................................................
Change in Production Participation Plan liability ..................................
Commodity derivative (gain) loss, net ...................................................
Total costs and expenses .................................................................
376,424
171,625
684,724
166,972
108,573
75,210
-
13,824
(85,911)
1,511,441
305,487
139,190
468,203
84,644
84,985
62,516
-
(865)
(24,857)
1,119,303
268,348
103,880
393,897
59,371
64,694
59,078
6,235
12,091
7,062
974,656
INCOME BEFORE INCOME TAXES ....................................................
662,011
780,319
541,443
INCOME TAX EXPENSE (BENEFIT):
Current ...................................................................................................
Deferred .................................................................................................
Total income tax expense ................................................................
(669)
248,581
247,912
NET INCOME .............................................................................................
Net loss attributable to noncontrolling interest ......................................
414,099
90
NET INCOME AVAILABLE TO SHAREHOLDERS ...........................
Preferred stock dividends and inducement premium .............................
414,189
(1,077)
3,853
284,838
288,691
491,628
59
491,687
(1,077)
4,979
199,811
204,790
336,653
-
336,653
(63,970)
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS ....... $
413,112
$
490,610
$
272,683
EARNINGS PER COMMON SHARE (1):
Basic ....................................................................................................... $
Diluted ................................................................................................... $
3.51
3.48
$
$
4.18
4.14
$
$
2.57
2.55
WEIGHTED AVERAGE SHARES OUTSTANDING (1):
Basic .......................................................................................................
Diluted ...................................................................................................
117,601
119,028
117,345
118,668
106,338
107,846
(1) All share and per share amounts have been retroactively restated for the 2010 period to reflect the Company’s two-for-one stock split in
February 2011, as described in Note 8 to these consolidated financial statements.
See notes to consolidated financial statements.
78
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
Year Ended December 31,
2011
2010
2012
NET INCOME .............................................................................................
$
414,099
$
491,628
$
336,653
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
OCI amortization on de-designated hedges(1) ........................................
Total other comprehensive loss, net of tax ......................................
COMPREHENSIVE INCOME .................................................................
Comprehensive loss attributable to noncontrolling interest ...................
(1,476)
(1,476)
412,623
90
(5,528)
(5,528)
486,100
59
(14,645)
(14,645)
322,008
-
COMPREHENSIVE INCOME ATTRIBUTABLE TO WHITING ......
$
412,713
$
486,159
$
322,008
(1) Presented net of income tax expense of $862, $3,230 and $8,553 for the years ended December 31, 2012, 2011 and 2010,
respectively.
See notes to consolidated financial statements.
79
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ................................................................................................$
Adjustments to reconcile net income to net cash provided by operating
Year Ended December 31,
2011
2012
2010
414,099
$
491,628
$
336,653
activities:
Depreciation, depletion and amortization ...............................................................
Deferred income tax expense ................................................................
Amortization of debt issuance costs and debt discount ................................
Stock-based compensation .....................................................................................
Amortization of deferred gain on sale ................................................................
Gain on sale of properties .......................................................................................
Undeveloped leasehold and oil and gas property impairments...............................
Exploratory dry hole costs ......................................................................................
Loss on early extinguishment of debt ................................................................
Change in Production Participation Plan liability................................
Unrealized gain on derivative contracts ................................................................
Other, net ................................................................................................
684,724
248,581
9,518
18,190
(29,458)
(3,423)
107,855
18,428
-
13,824
(115,733)
(18,708)
Changes in current assets and liabilities:
Accounts receivable trade .......................................................................................
Prepaid expenses and other.....................................................................................
Accounts payable trade and accrued liabilities .......................................................
Revenues and royalties payable ................................................................
Taxes payable ................................................................................................
Net cash provided by operating activities ...........................................................
(55,750)
2,535
58,647
45,798
2,088
1,401,215
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash acquisition capital expenditures ................................................................
Drilling and development capital expenditures ..........................................................
Proceeds from sale of oil and gas properties ..............................................................
Net proceeds from sale of 18,400,000 units in Whiting USA Trust II .......................
Issuance of note receivable ........................................................................................
Net cash used in investing activities ................................................................
(121,430)
(2,050,029)
69,190
322,257
(306)
(1,780,318)
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of 6.5% Senior Subordinated Notes due 2018 ................................
Redemption of 7.25% Senior Subordinated Notes due 2012 ................................
Redemption of 7.25% Senior Subordinated Notes due 2013 ................................
Premium on induced conversion of 6.25% convertible perpetual
-
-
-
preferred stock ................................................................................................
Contributions from noncontrolling interest ................................................................
Preferred stock dividends paid ................................................................
Long-term borrowings under credit agreement ..........................................................
Repayments of long-term borrowings under credit agreement ................................
Repayments to Alliant Energy Corporation ...............................................................
Debt issuance costs ................................................................................................
Restricted stock used for tax withholdings ................................................................
-
-
(1,077)
2,340,000
(1,920,000)
(2,329)
(2,807)
(5,695)
408,092
Net cash provided by (used in) financing activities ................................
468,203
284,838
8,682
13,509
(13,937)
(16,313)
38,783
4,924
-
(865)
(63,093)
(13,512)
(62,802)
(3,771)
33,135
21,770
904
1,192,083
(250,041)
(1,554,271)
69,276
-
(25,000)
(1,760,036)
-
-
-
-
2,500
(1,077)
1,760,000
(1,180,000)
(1,871)
(5,691)
(9,049)
564,812
393,897
199,811
10,592
8,871
(15,613)
(1,388)
26,525
3,819
6,235
12,091
(40,736)
(4,013)
(47,631)
(3,387)
66,663
35,797
9,103
997,289
(184,729)
(739,047)
9,202
-
-
(914,574)
350,000
(150,000)
(223,988)
(47,529)
-
(16,441)
1,150,000
(1,110,000)
(1,615)
(20,471)
(5,679)
(75,723)
See notes to consolidated financial statements.
(Continued)
80
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
NET CHANGE IN CASH AND CASH EQUIVALENTS ................................$
CASH AND CASH EQUIVALENTS:
Year Ended December 31,
2011
2012
2010
28,989
$
(3,141)
$
6,992
Beginning of period ................................................................................................
End of period ................................................................................................$
15,811
44,800
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Income taxes paid (refunded), net ................................................................$
$
Interest paid, net of amounts capitalized ................................................................
(268)
68,005
NONCASH INVESTING ACTIVITIES:
Accrued capital expenditures .....................................................................................
$
110,663
18,952
15,811
4,065
53,761
$
$
$
11,960
18,952
6,181
46,332
$
$
$
$
142,827
$
84,789
NONCASH FINANCING ACTIVITIES:
Contributions from noncontrolling interest ................................................................
Issuance of common stock related to the induced conversion of
preferred stock ................................................................................................
$
$
Preferred stock cancelled in connection with its induced conversion ........................
$
-
-
-
$
$
$
5,833
-
-
$
$
$
-
317,406
(317,406)
See notes to consolidated financial statements.
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S
WHITING PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description of Operations—Whiting Petroleum Corporation, a Delaware corporation, is an independent oil
and gas company that explores for, develops, acquires and produces crude oil, NGLs and natural gas
primarily in the Rocky Mountains, Permian Basin, Mid-Continent, Michigan and Gulf Coast regions of the
United States. Unless otherwise specified or the context otherwise requires, all references in these notes to
“Whiting” or the “Company” are to Whiting Petroleum Corporation and its consolidated subsidiaries.
Basis of Presentation of Consolidated Financial Statements—The consolidated financial statements
include the accounts of Whiting Petroleum Corporation, its consolidated subsidiaries and Whiting’s pro
rata share of the accounts of Whiting USA Trust I (“Trust I”) pursuant to Whiting’s 15.8% ownership
interest in Trust I. Investments in entities which give Whiting significant influence, but not control, over
the investee are accounted for using the equity method. Under the equity method, investments are stated at
cost plus the Company’s equity in undistributed earnings and losses. All intercompany balances and
transactions have been eliminated upon consolidation.
Use of Estimates—The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the
financial statements, and the reported amounts of revenues and expenses during the reporting period. Items
subject to such estimates and assumptions include (1) oil and natural gas reserves; (2) cash flow estimates
used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset
retirement obligations; (5) assigning fair value and allocating purchase price in connection with business
combinations; (6) income taxes; (7) Production Participation Plan and other accrued liabilities; (8)
valuation of derivative instruments; and (9) accrued revenue and related receivables. Although
management believes these estimates are reasonable, actual results could differ from these estimates.
Cash and Cash Equivalents—Cash equivalents consist of demand deposits and highly liquid investments
which have an original maturity of three months or less.
Accounts Receivable Trade—Whiting’s accounts receivable trade consist mainly of receivables from oil
and gas purchasers and joint interest owners on properties the Company operates. For receivables from
joint interest owners, Whiting typically has the ability to withhold future revenue disbursements to recover
any non-payment of joint interest billings. Generally, the Company’s oil and gas receivables are collected
within two months, and to date, the Company has had minimal bad debts.
The Company routinely assesses the recoverability of all material trade and other receivables to determine
their collectability. At December 31, 2012 and 2011, the Company had an allowance for doubtful accounts
of $3.9 million and $1.7 million, respectively.
Inventories—Materials and supplies inventories consist primarily of tubular goods and production
equipment, carried at weighted-average cost. Materials and supplies are included in other property and
equipment. Crude oil in tanks inventory is carried at the lower of the estimated cost to produce or market
value and is included in prepaid expenses and other.
Oil and Gas Properties
Proved. The Company follows the successful efforts method of accounting for its oil and gas properties.
Under this method of accounting, all property acquisition costs and development costs are capitalized when
incurred and depleted on a units-of-production basis over the remaining life of proved reserves and proved
83
developed reserves, respectively. Costs of drilling exploratory wells are initially capitalized but are
charged to expense if the well is determined to be unsuccessful.
The Company assesses its proved oil and gas properties for impairment whenever events or circumstances
indicate that the carrying value of the assets may not be recoverable. The impairment test compares
undiscounted future net cash flows to the assets’ net book value. If the net capitalized costs exceed future
net cash flows, then the cost of the property is written down to fair value. Fair value for oil and gas
properties is generally determined based on discounted future net cash flows. Impairment expense for
proved properties is reported in exploration and impairment expense.
Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of
depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and
amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a
gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable
property are recognized to earnings.
Interest cost is capitalized as a component of property cost for development projects that require greater
than six months to be readied for their intended use. During 2012, 2011 and 2010, the Company
capitalized interest of $2.7 million, $3.6 million and $2.9 million, respectively.
Unproved. Unproved properties consist of costs to acquire undeveloped leases as well as costs to acquire
unproved reserves. Undeveloped lease costs and unproved reserve acquisitions are capitalized, and
individually insignificant unproved properties are amortized on a composite basis, based on past success,
past experience and average lease-term lives. The Company evaluates significant unproved properties for
impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or
future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved
property costs are reclassified to proved properties and depleted on a unit-of-production basis. Impairment
expense for unproved properties is reported in exploration and impairment expense.
Exploratory. Geological and geophysical costs, including exploratory seismic studies, and the costs of
carrying and retaining unproved acreage are expensed as incurred. Costs of seismic studies that are utilized
in development drilling within an area of proved reserves are capitalized as development costs. Amounts
of seismic costs capitalized are based on only those blocks of data used in determining development well
locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling,
those seismic costs are proportionately allocated between development costs and exploration expense.
Costs of drilling exploratory wells are initially capitalized, pending determination of whether the well has
found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well
and other associated costs are charged to expense. Cost incurred for exploratory wells that find reserves,
which cannot yet be classified as proved, continue to be capitalized if (a) the well has found a sufficient
quantity of reserves to justify completion as a producing well, and (b) the Company is making sufficient
progress assessing the reserves and the economic and operating viability of the project. If either condition
is not met, or if the Company obtains information that raises substantial doubt about the economic or
operational viability of the project, the exploratory well costs, net of any salvage value, are expensed.
Enhanced recovery activities. The Company carries out tertiary recovery methods on certain of its oil and
gas properties in order to recover additional hydrocarbons that are not recoverable from primary or
secondary recovery methods. Acquisition costs of tertiary injectants, such as purchased CO2, for enhanced
oil recovery (“EOR”) activities that are used during a project’s pilot phase, or prior to a project’s technical
and economic viability (i.e. prior to the recognition of proved tertiary recovery reserves) are expensed as
incurred. After a project has been determined to be technically feasible and economically viable, all
acquisition costs of tertiary injectants are capitalized as development costs and depleted, as they are
incurred solely for obtaining access to reserves not otherwise recoverable and have future economic
84
benefits over the life of the project. As CO2 is recovered together with oil and gas production, it is
extracted and re-injected, and all the associated CO2 recycling costs are expensed as incurred. Likewise
costs incurred to maintain reservoir pressure are also expensed.
Other Property and Equipment. Other property and equipment consists mainly of materials and supplies
inventories which are not depreciated. Also included in other property and equipment are an oil pipeline,
furniture and fixtures, leasehold improvements and automobiles, which are stated at cost and depreciated
using the straight-line method over their estimated useful lives ranging from 4 to 33 years.
Debt Issuance Costs—Debt issuance costs related to the Company’s Senior Subordinated Notes are
amortized to interest expense using the effective interest method over the term of the related debt. Debt
issuance costs related to the credit facility are amortized to interest expense on a straight-line basis over the
borrowing term.
Asset Retirement Obligations and Environmental Costs—Asset retirement obligations relate to future
costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and
facilities from leased acreage and returning such land to its original condition. The fair value of a liability
for an asset retirement obligation is recorded in the period in which it is incurred (typically when a well is
completed or an asset is installed at the production location), and the cost of such liability increases the
carrying amount of the related long-lived asset by the same amount. The liability is accreted each period
through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on
a units-of-production basis over the proved developed reserves of the related asset. Revisions to estimated
retirement obligations result in adjustments to the related capitalized asset and corresponding liability.
Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that
obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not
reduced by possible recoveries from third parties.
Derivative Instruments—The Company enters into derivative contracts, primarily costless collars, to
manage its exposure to commodity price risk. All derivative instruments, other than those that meet the
“normal purchase normal sales” exclusion, are recorded on the balance sheet as either an asset or liability
measured at fair value. Gains and losses from changes in the fair value of derivative instruments are
recognized immediately in earnings, unless the derivative meets specific hedge accounting criteria, and the
derivative has been designated as a hedge. Effective April 1, 2009, however, the Company elected to
discontinue all hedge accounting prospectively. Cash flows from derivatives used to manage commodity
price risk are classified in operating activities along with the cash flows of the underlying hedged
transactions. The Company does not enter into derivative instruments for speculative or trading purposes.
For derivatives qualifying as hedges of future cash flows prior to April 1, 2009, the effective portion of any
changes in fair value was recognized in accumulated other comprehensive income (loss) and is reclassified
to net income when the underlying forecasted transaction occurs. Any ineffective portion of such hedges
was recognized in commodity derivative (gain) loss, net as it occurred. For discontinued cash flow hedges,
prospective changes in the fair value of the derivative are recognized in earnings. The accumulated gain or
loss recognized in accumulated other comprehensive income (loss) at the time a hedge is discontinued
continues to be deferred until the original forecasted transaction occurs. However, if it is determined that
the likelihood of the original forecasted transaction occurring is no longer probable, the entire accumulated
gain or loss recognized in accumulated other comprehensive income (loss) is immediately reclassified into
earnings.
Deferred Gain on Sale—The deferred gain on sale relates to the sale of 11,677,500 Trust I units and
18,400,000 Whiting USA Trust II (“Trust II”) units, and is amortized to income based on the units-of-
production method.
85
Revenue Recognition—Oil and gas revenues are recognized when production is sold to a purchaser at a
fixed or determinable price, when delivery has occurred and title has transferred, and if the collectability of
the revenue is probable. Revenues from the production of gas properties in which the Company has an
interest with other producers are recognized on the basis of the Company’s net working interest
(entitlement method). Net deliveries in excess of entitled amounts are recorded as liabilities, while net
under deliveries are reflected as receivables. Gas imbalance receivables or payables are valued at the
lowest of (i) the current market price; (ii) the price in effect at the time of production; or (iii) the contract
price, if a contract is in hand. As of December 31, 2012 and 2011, the Company was in a net under (over)
produced imbalance position of (53,536) Mcf and (13,716) Mcf, respectively.
Taxes collected and remitted to governmental agencies on behalf of customers are not included in revenues
or costs and expenses.
General and Administrative Expenses—General and administrative expenses are reported net of
reimbursements of overhead costs that are allocated to working interest owners in the oil and gas properties
operated by Whiting.
Maintenance and Repairs—Maintenance and repair costs which do not extend the useful lives of property
and equipment are charged to expense as incurred. Major replacements, renewals and betterments are
capitalized.
Income Taxes—Income taxes are recognized based on earnings reported for tax return purposes in addition
to a provision for deferred income taxes. Deferred income taxes are accounted for using the liability
method. Under this method, deferred tax assets and liabilities are determined by applying the enacted
statutory tax rates in effect at the end of a reporting period to the cumulative temporary differences between
the tax bases of assets and liabilities and their reported amounts in the Company’s financial statements.
The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the
enactment date. A valuation allowance for deferred tax assets is established when it is more likely than not
that some portion of the benefit from deferred tax assets will not be realized. The Company’s uncertain tax
positions must meet a more-likely-than-not realization threshold to be recognized, and any potential
accrued interest and penalties related to unrecognized tax benefits are recognized within income tax
expense.
Earnings Per Share—Basic earnings per common share is calculated by dividing net income available to
common shareholders by the weighted average number of common shares outstanding during each period.
Diluted earnings per common share is calculated by dividing adjusted net income available to common
shareholders by the weighted average number of diluted common shares outstanding, which includes the
effect of potentially dilutive securities. Potentially dilutive securities for the diluted earnings per share
calculations consist of unvested restricted stock awards and outstanding stock options using the treasury
method, as well as convertible perpetual preferred stock using the if-converted method. In the computation
of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of
unvested restricted shares or the assumed exercise of stock options (i.e. hypothetical excess tax benefits)
are included in the assumed proceeds component of the treasury share method to the extent that such excess
tax benefits are more likely than not to be realized. When a loss from continuing operations exists, all
potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted
earnings per share.
Industry Segment and Geographic Information—The Company has evaluated how it is organized and
managed and has identified only one operating segment, which is the exploration and production of crude
oil, NGLs and natural gas. The Company considers its gathering, processing and marketing functions as
ancillary to its oil and gas producing activities. All of the Company’s operations and assets are located in
the United States, and substantially all of its revenues are attributable to United States customers.
86
Fair Value of Financial Instruments—The Company has included fair value information in these notes
when the fair value of our financial instruments is materially different from their book value. Cash and
cash equivalents, accounts receivable and payable are carried at cost, which approximates their fair value
because of the short-term maturity of these instruments. The Company’s credit agreement has a recorded
value that approximates its fair value since its variable interest rate is tied to current market rates. The
Company’s derivative financial instruments are recorded at fair value and include a measure of the
Company’s own nonperformance risk or that of its counterparties as appropriate.
Concentration of Credit Risk—Whiting is exposed to credit risk in the event of nonpayment by
counterparties, a significant portion of which are concentrated in energy related industries. The
creditworthiness of customers and other counterparties is subject to continuing review. The following table
presents the percentages by purchaser that accounted for 10% or more of the Company’s total oil, NGL and
natural gas sales for the years ended December 31, 2012, 2011 and 2010:
2012
Plains Marketing LP (1) ................................................................
20%
Shell Trading US................................................................14%
Nexen Pipeline USA, Inc. (1) ................................
Eighty Eight Oil Company ................................
Bridger Trading LLC ................................................................
EOG Resources, Inc. ................................................................
-
11%
11%
4%
2011
27%
13%
-
8%
6%
7%
2010
16%
17%
13%
4%
5%
10%
(1) Effective December 30, 2010, Plains Marketing LP acquired Nexen Pipeline USA, Inc.
Commodity derivative contracts held by the Company are with ten counterparties, all of which are
participants in Whiting’s credit facility as well, and all of which have investment-grade ratings from
Moody’s and Standard & Poor. As of December 31, 2012, outstanding derivative contracts with JP
Morgan Chase Bank, N.A., The Bank of Nova Scotia and Bank of America Merrill Lynch represent 49%,
17% and 17%, respectively, of total crude oil volumes hedged.
Adopted and Recently Issued Accounting Pronouncements—In December 2010, the FASB issued
Accounting Standards Update No. 2010-29, Business Combinations: Disclosure of Supplementary Pro
Forma Information for Business Combinations (“ASU 2010-29”), which provides amendments to FASB
ASC Topic 805, Business Combinations. The objective of ASU 2010-29 is to clarify and expand the pro
forma revenue and earnings disclosure requirements for business combinations. ASU 2010-29 was
effective for fiscal years beginning after December 15, 2010. The Company adopted ASU 2010-29
effective January 1, 2011, which did not have an impact on the Company’s consolidated financial
statements.
In May 2011, the FASB issued Accounting Standards Update No. 2011-04, Fair Value Measurement:
Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP
and IFRSs (“ASU 2011-04”), which provides amendments to FASB ASC Topic 820, Fair Value
Measurement. The objective of ASU 2011-04 is to create common fair value measurement and disclosure
requirements between GAAP and International Financial Reporting Standards (“IFRS”). The amendments
clarify existing fair value measurement and disclosure requirements and make changes to particular
principles or requirements for measuring or disclosing information about fair value measurements. ASU
2011-04 was effective for interim and annual reporting periods beginning after December 15, 2011. The
Company adopted this standard effective January 1, 2012, which did not have an impact on the Company’s
consolidated financial statements other than additional disclosures.
In June 2011, the FASB issued Accounting Standards Update No. 2011-05, Comprehensive Income:
Presentation of Comprehensive Income (“ASU 2011-05”), which provides amendments to FASB ASC
Topic 220, Comprehensive Income. The objective of ASU 2011-05 is to require an entity to present the
total of comprehensive income, the components of net income and the components of other comprehensive
87
income either in a single continuous statement of comprehensive income or in two separate but consecutive
statements. ASU 2011-05 eliminates the option to present the components of other comprehensive income
as part of the statement of equity. ASU 2011-05 is effective for interim and annual periods beginning after
December 15, 2011 and is to be applied retrospectively. In December 2011, the FASB issued Accounting
Standards Update No. 2011-12, Comprehensive Income: Deferral of the Effective Date for Amendments to
the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in
Accounting Standards Update No. 2011-05 (“ASU 2011-12”), which deferred the effective date of changes
in ASU 2011-05 that relate to the presentation of reclassification adjustments out of accumulated other
comprehensive income. The amendments in this update are effective at the same time as the amendments
in ASU 2011-05. The Company adopted the provisions of ASU 2011-05 and 2011-12 effective January 1,
2012, which did not have an impact on its consolidated financial statements other than requiring the
Company to present its statements of comprehensive income separately from its statements of equity, as
these statements were formerly presented on a combined basis.
In December 2011, the FASB issued Accounting Standards Update No. 2011-11, Balance Sheet:
Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). The objective of ASU 2011-11 is to
require an entity to provide enhanced disclosures that will enable users of its financial statements to
evaluate the effect or potential effect of netting arrangements on an entity’s financial position. In January
2013, the FASB issued Accounting Standards Update No. 2013-01, Clarifying the Scope of Disclosures
about Offsetting Assets and Liabilities (“ASU 2013-01”), which clarifies that the scope of ASU 2011-11
applies to derivatives accounted for in accordance with FASB ASC Topic 815, Derivative and Hedging,
including bifurcated embedded derivatives, repurchase agreements and reverse purchase agreements, and
securities lending transactions that are either offset in accordance with FASB ASC Section 210-20-45 or
Section 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. ASU
2011-11 and ASU 2013-01 are effective for interim and annual reporting periods beginning on or after
January 1, 2013 and should be applied retrospectively. The adoption of this standard will not have a
significant impact on the Company’s consolidated financial statements.
In July 2012, the FASB issued Accounting Standards Update No. 2012-02, Intangibles – Goodwill and
Other – Testing Indefinite-Lived Intangible Assets for Impairment (“ASU 2012-02”). The objective of
ASU 2012-02 is to reduce the cost and complexity of performing an impairment test for indefinite-lived
intangible assets by permitting an entity first to assess qualitative factors to determine whether it is more
likely than not that an indefinite-lived intangible asset is impaired, as a basis for determining whether it is
necessary to perform a quantitative impairment test. ASU 2012-02 is effective for interim and annual
reporting periods beginning after September 15, 2012. The adoption of this standard will not have a
significant impact on the Company’s consolidated financial statements.
In August 2012, The SEC issued the Disclosure of Payments by Resource Extraction Issuers: Final Rule.
The rule requires resource extraction issuers to include in a separate annual report information relating to
any payment made by the issuer, its subsidiaries or an entity under the issuer’s control, to a foreign
government or the Federal government for the purpose of the commercial development of oil, natural gas or
minerals. Issuers must provide information about the type and total amount of such payments made for
each project related to the commercial development of oil, natural gas or minerals, and the type and total
amount of payments made to each government. The rule is effective for fiscal years ending after
September 30, 2013. The Company will be required to annually file the required disclosures as exhibits to
a newly created form, Form SD, and the first report will be filed for the period beginning October 1, 2013
through December 31, 2013. The adoption of this standard therefore will not have an impact on the
Company’s consolidated financial statements due to its stand-alone reporting requirements.
In February 2013, the FASB issued Accounting Standards Update No. 2013-02, Reporting of Amounts
Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). The objective of ASU
2013-02 is to improve the reporting of reclassifications out of accumulated other comprehensive income
(“AOCI”) by requiring an entity to report the effect of significant reclassifications out of AOCI on the
88
respective line items in net income if the amount being reclassified is required under GAAP to be
reclassified in its entirety to net income. For other amounts that are not required under GAAP to be
reclassified in their entirety to net income in the same reporting period, an entity is required to cross-
reference other disclosures required under GAAP that provide additional detail about those amounts. ASU
2013-02 is effective for interim and annual reporting periods beginning after December 15, 2012. The
adoption of this standard will not have a significant impact on the Company’s consolidated financial
statements other than additional disclosures.
2.
ACQUISITIONS AND DIVESTITURES
2012 Acquisitions
On March 22, 2012, the Company completed the acquisition of approximately 13,300 net undeveloped
acres in the Missouri Breaks prospect in Richland County, Montana for $33.3 million.
2012 Divestitures
On May 18, 2012, the Company sold a 50% ownership interest in its Belfield gas processing plant, natural
gas gathering system, oil gathering system and related facilities located in Stark County, North Dakota for
total cash proceeds of $66.2 million. Whiting used the net proceeds from the sale to repay a portion of the
debt outstanding under its credit agreement.
On March 28, 2012, the Company completed an initial public offering of units of beneficial interest in
Trust II, selling 18,400,000 Trust II units at $20.00 per unit, which generated net proceeds of $322.3
million after underwriters’ fees, offering expenses and post-close adjustments. The Company used the net
offering proceeds to repay a portion of the debt outstanding under its credit agreement. The net proceeds
from the sale of Trust II units to the public resulted in a deferred gain on sale of $128.2 million.
Immediately prior to the closing of the offering, Whiting conveyed a term net profits interest in certain of
its oil and gas properties to Trust II in exchange for 100% of the trust’s units issued, or 18,400,000 units.
The net profits interest entitles Trust II 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 on the later to occur
of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying
properties and sold. This is the equivalent of 10.61 MMBOE in respect of Trust II’s right to receive 90%
of the net proceeds from such reserves pursuant to the net profits interest. The conveyance of the net
profits interest to Trust II consisted entirely of proved reserves of 10.61 MMBOE as of the January 1, 2012
effective date, representing 3% of Whiting’s proved reserves as of December 31, 2011 and 5% (or 4.5
MBOE/d) of its March 2012 average daily net production.
2011 Acquisitions
On July 28, 2011, the Company completed the acquisition of approximately 23,400 net acres and one well
in the Missouri Breaks prospect in Richland County, Montana for an unadjusted purchase price of $46.9
million. Disclosures of pro forma revenues and net income for the acquisition of this one well are not
material and have not been presented accordingly.
On March 18, 2011, Whiting and an unrelated third party formed Sustainable Water Resources, LLC
(“SWR”) to develop a water project in the state of Colorado. The Company contributed $25.0 million for a
75% interest in SWR, and the 25% noncontrolling interest in SWR was ascribed a fair value of $8.3
million, which consisted of $2.5 million in cash contributions, as well as $5.8 million in intangible and
fixed assets contributed to the joint venture.
89
On February 15, 2011, the Company completed the acquisition of 6,000 net undeveloped acres and
additional working interests in the Pronghorn field in the Billings and Stark counties of North Dakota, for
an aggregate purchase price of $40.0 million.
2011 Divestiture
On September 29, 2011, Whiting sold its interest in several non-core oil and gas producing properties
located in the Karnes, Live Oak and DeWitt counties of Texas for total cash proceeds of $64.8 million,
resulting in a pre-tax gain on sale of $12.3 million. Whiting used the net proceeds from the property sale to
repay a portion of the debt outstanding under its credit agreement.
2010 Activity
In September 2010, Whiting acquired operated interests in 19 producing oil and gas wells, undeveloped
acreage, and gathering lines, all of which are located on approximately 20,400 gross (16,100 net) acres in
Weld County, Colorado. The aggregate purchase price was $19.2 million; substantially all of which was
allocated to the oil and gas properties and acreage acquired. Disclosures of pro forma revenues and net
income for the 19 wells acquired are not material and have not been presented accordingly.
In August 2010, Whiting acquired oil and gas leasehold interests covering approximately 112,000 gross
(90,200 net) acres in the Montana portion of the Williston Basin for $26.0 million. The undeveloped
acreage is located in Roosevelt and Sheridan counties.
There were no significant divestitures during the year ended December 31, 2010.
3.
LONG-TERM DEBT
Long-term debt consisted of the following at December 31, 2012 and 2011 (in thousands):
Credit agreement ........................................................................................
7% Senior Subordinated Notes due 2014...................................................
6.5% Senior Subordinated Notes due 2018 ................................................
Total debt ...............................................................................................
December 31,
2012
1,200,000
250,000
350,000
1,800,000
$
$
2011
780,000
250,000
350,000
1,380,000
$
$
The following table shows five succeeding fiscal years of scheduled maturities for the Company’s long-
term debt as of December 31, 2012 (in thousands):
Long-term debt ................................
$
-
$
250,000
$
-
$ 1,200,000
$
-
2013
2014
2015
2016
2017
Credit Agreement—Whiting Oil and Gas Corporation (“Whiting Oil and Gas”), the Company’s wholly-
owned subsidiary, has a credit agreement with a syndicate of banks. In October 2012, Whiting Oil and Gas
entered into an amendment to its existing credit agreement that increased the borrowing base under the
facility from $1.5 billion to $2.5 billion, of which $2.0 billion has been committed by lenders and is
available for borrowing. We may increase the maximum aggregate amount of commitments under the
credit agreement from $2.0 billion to $2.5 billion if certain conditions are satisfied, including the consent of
lenders participating in the increase. As of December 31, 2012, the Company had $797.6 million of
available borrowing capacity, which is net of $1,200.0 million in borrowings and $2.4 million in letters of
credit outstanding. The credit agreement provides for interest only payments until April 2016, when the
agreement expires and all outstanding borrowings are due.
90
The borrowing base under the credit agreement is determined at the discretion of the lenders, based on the
collateral value of the Company’s proved reserves that have been mortgaged to its lenders, and is subject to
regular redeterminations on May 1 and November 1 of each year, as well as special redeterminations
described in the credit agreement, in each case which may reduce the amount of the borrowing base. A
portion of the revolving credit facility in an aggregate amount not to exceed $50.0 million may be used to
issue letters of credit for the account of Whiting Oil and Gas or other designated subsidiaries of the
Company. As of December 31, 2012, $47.6 million was available for additional letters of credit under the
agreement.
Interest accrues at the Company’s option at either (i) a base rate for a base rate loan plus the margin in the
table below, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus
0.50% or an adjusted LIBOR rate plus 1.00%, or (ii) an adjusted LIBOR rate for a Eurodollar loan plus the
margin in the table below. Additionally, the Company also incurs commitment fees, as set forth in the table
below on the unused portion of the lesser of the aggregate commitments of the lenders or the borrowing
base, and which are included as a component of interest expense. At December 31, 2012, the weighted
average interest rate on the outstanding principal balance under the credit agreement was 2.0%.
Ratio of Outstanding Borrowings to Borrowing Base
Less than 0.25 to 1.0
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0
Greater than or equal to 0.90 to 1.0
Applicable
Margin for Base
Rate Loans
Applicable
Margin for
Eurodollar Loans
Commitment
Fee
0.50%
0.75%
1.00%
1.25%
1.50%
1.50%
1.75%
2.00%
2.25%
2.50%
0.375%
0.375%
0.50%
0.50%
0.50%
The credit agreement contains restrictive covenants that may limit the Company’s ability to, among other
things, incur additional indebtedness, sell assets, make loans to others, make investments, enter into
mergers, enter into hedging contracts, incur liens and engage in certain other transactions without the prior
consent of its lenders. Except for limited exceptions, which include the payment of dividends on the
Company’s 6.25% convertible perpetual preferred stock, the credit agreement also restricts the Company’s
ability to make any dividend payments or distributions on its common stock. These restrictions apply to all
of the net assets of Whiting Oil and Gas. As of December 31, 2012, total restricted net assets were
$3,477.4 million, and the amount of retained earnings free from restrictions was $19.7 million. The credit
agreement requires the Company, as of the last day of any quarter, (i) to not exceed a total debt to the last
four quarters’ EBITDAX ratio (as defined in the credit agreement) of 4.25 to 1.0 for quarters ending prior
to and on December 31, 2012 and 4.0 to 1.0 for the quarters ending March 31, 2013 and thereafter and (ii)
to have a consolidated current assets to consolidated current liabilities ratio (as defined in the credit
agreement and which includes an add back of the available borrowing capacity under the credit agreement)
of not less than 1.0 to 1.0. The Company was in compliance with its covenants under the credit agreement
as of December 31, 2012.
The obligations of Whiting Oil and Gas under the amended credit agreement are secured by a first lien on
substantially all of Whiting Oil and Gas’ properties included in the borrowing base for the credit
agreement. The Company has guaranteed the obligations of Whiting Oil and Gas under the credit
agreement and has pledged the stock of Whiting Oil and Gas as security for its guarantee.
Senior Subordinated Notes—In October 2005, the Company issued at par $250.0 million of 7% Senior
Subordinated Notes due February 2014. The estimated fair value of these notes was $262.5 million as of
December 31, 2012, based on quoted market prices for these debt securities, and such fair value is therefore
designated as Level 1 within the valuation hierarchy.
91
Redemption of 7.25% Senior Subordinated Notes Due 2012 and 2013—In September 2010, the Company
paid $383.5 million to redeem $150.0 million of its 7.25% Senior Subordinated Notes due 2012 and $220.0
million of its 7.25% Senior Subordinated Notes due 2013, which consisted of a redemption price of
100.00% for the 2012 notes and 101.8125% for the 2013 notes and included the payment of accrued and
unpaid interest on such notes. The Company financed the redemption of the 2012 and 2013 notes with
borrowings under its credit agreement. As a result of the redemption, Whiting recognized a $6.2 million
loss on early extinguishment of debt, which consisted of a cash charge of $4.0 million related to the
redemption premium on the 2013 notes and a non-cash charge of $2.2 million related to the acceleration of
debt discounts and unamortized debt issuance costs.
Issuance of 6.5% Senior Subordinated Notes Due 2018—In September 2010, the Company issued at par
$350.0 million of 6.5% Senior Subordinated Notes due October 2018. The Company used the net proceeds
from this issuance to repay a portion of the debt (which was borrowed to redeem its 2012 and 2013 notes)
outstanding under its credit agreement. The estimated fair value of these notes was $375.4 million as of
December 31, 2012, based on quoted market prices for these debt securities, and such fair value is therefore
designated as Level 1 within the valuation hierarchy.
The notes are unsecured obligations of Whiting Petroleum Corporation and are subordinated to all of the
Company’s senior debt, which currently consists of Whiting Oil and Gas’ credit agreement. The
Company’s obligations under the 2014 notes are fully, unconditionally, jointly and severally guaranteed by
the Company’s 100%-owned subsidiaries, Whiting Oil and Gas and Whiting Programs, Inc. (the “2014
Guarantors”). Additionally, the Company’s obligations under the 2018 notes are fully, unconditionally,
jointly and severally guaranteed by the Company’s 100%-owned subsidiary, Whiting Oil and Gas
(collectively with the 2014 Guarantors, the “Guarantors”). Any subsidiaries other than the Guarantors are
minor subsidiaries as defined by Rule 3-10(h)(6) of Regulation S-X of the Securities and Exchange
Commission. Whiting Petroleum Corporation has no assets or operations independent of this debt and its
investments in guarantor subsidiaries.
4.
ASSET RETIREMENT OBLIGATIONS
The Company’s asset retirement obligations represent the present value of estimated future costs associated
with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased
acreage, and land restoration (including removal of certain onshore and offshore facilities in California) in
accordance with applicable local, state and federal laws. The Company follows FASB ASC Topic 410,
Asset Retirement and Environmental Obligations, to determine its asset retirement obligation amounts by
calculating the present value of the estimated future cash outflows associated with its plug and
abandonment obligations. The current portions at December 31, 2012 and 2011 were $11.6 million and
$7.7 million, respectively, and are included in accrued liabilities and other. Revisions to the liability
typically occur due to changes in estimated abandonment costs or well economic lives, or if federal or state
regulators enact new requirements regarding the abandonment of wells. The following table provides a
reconciliation of the Company’s asset retirement obligations for the year ended December 31, 2012 and
2011 (in thousands):
Year Ended December 31,
2011
2012
Asset retirement obligation at January 1 ....................................................
Additional liability incurred .......................................................................
Revisions in estimated cash flows .............................................................
Accretion expense ......................................................................................
Obligations on sold properties ...................................................................
Liabilities settled ........................................................................................
Asset retirement obligation at December 31 ..............................................
$
$
69,721
9,292
23,162
7,263
(4)
(11,616)
97,818
$
$
83,083
4,882
(20,049)
8,016
(790)
(5,421)
69,721
92
5.
DERIVATIVE FINANCIAL INSTRUMENTS
The Company is exposed to certain risks relating to its ongoing business operations, and Whiting uses
derivative instruments to manage its commodity price risk. Whiting follows FASB ASC Topic 815,
Derivatives and Hedging, to account for its derivative financial instruments.
Commodity Derivative Contracts—Historically, prices received for crude oil and natural gas production
have been volatile because of seasonal weather patterns, supply and demand factors, worldwide political
factors and general economic conditions. Whiting enters into derivative contracts, primarily costless
collars, to achieve a more predictable cash flow by reducing its exposure to commodity price volatility.
Commodity derivative contracts are thereby used to ensure adequate cash flow to fund the Company’s
capital programs and to manage returns on acquisitions and drilling programs. Costless collars are
designed to establish floor and ceiling prices on anticipated future oil and gas production. While the use of
these derivative instruments limits the downside risk of adverse price movements, they may also limit
future revenues from favorable price movements. The Company does not enter into derivative contracts for
speculative or trading purposes.
Whiting Derivatives. The table below details the Company’s costless collar derivatives, including its
proportionate share of Trust II derivatives, entered into to hedge forecasted crude oil production revenues,
as of February 6, 2013.
Whiting Petroleum Corporation
Derivative
Instrument
Collars
Three-way collars(1)
Period
Jan – Dec 2013
Jan – Dec 2014
Jan – Dec 2013
Total
Contracted Crude Oil
Volumes (Bbl)
3,143,700
49,290
12,090,000
15,282,990
Weighted Average NYMEX Price
Collar Ranges for Crude Oil (per Bbl)
$ 48.20 - $ 90.45
$ 80.00 - $122.50
$70.97 - $85.48 - $114.14
(1) A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call
establishes a maximum price (ceiling) Whiting will receive for the volumes under contract. The purchased put
establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point
the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike
price.
Derivatives Conveyed to Whiting USA Trust II. In connection with the Company’s conveyance in March
2012 of a term net profits interest to Trust II and related sale of 18,400,000 Trust II units to the public, the
right to any future hedge payments made or received by Whiting on certain of its derivative contracts have
been conveyed to Trust II, and therefore such payments will be included in Trust II’s calculation of net
proceeds. Under the terms of the aforementioned conveyance, Whiting retains 10% of the net proceeds
from the underlying properties, which results in third-party public holders of Trust II units receiving 90%,
and Whiting retaining 10%, of the future economic results of commodity derivative contracts conveyed to
Trust II. The relative ownership of the future economic results of such commodity derivatives is reflected
in the tables below. No additional hedges are allowed to be placed on Trust II assets.
The 10% portion of Trust II derivatives that Whiting has retained the economic rights to (and which are
also included in the first derivative table above) are as follows:
93
Derivative
Instrument
Collars
Period
Jan – Dec 2013
Jan – Dec 2014
Total
Contracted Crude Oil
Volumes (Bbl)
53,700
49,290
102,990
NYMEX Price Collar Ranges for
Crude Oil (per Bbl)
$80.00 - $122.50
$80.00 - $122.50
Whiting Petroleum Corporation
The 90% portion of Trust II derivative contracts of which Whiting has transferred the economic rights to
third-party public holders of Trust II units (and which have not been reflected in the above tables) are as
follows:
Third-party Public Holders of Trust II Units
Derivative
Instrument
Collars
Period
Jan – Dec 2013
Jan – Dec 2014
Total
Contracted Crude Oil
Volumes (Bbl)
483,300
443,610
926,910
NYMEX Price Collar Ranges for
Crude Oil (per Bbl)
$80.00 - $122.50
$80.00 - $122.50
Embedded Commodity Derivative Contracts—As of December 31, 2012, Whiting had entered into certain
contracts for oil field goods or services, whereby the price adjustment clauses for such goods or services
are linked to changes in NYMEX crude oil prices. The Company has determined that the portions of these
contracts linked to NYMEX oil prices are not clearly and closely related to the host contracts, and the
Company has therefore bifurcated these embedded pricing features from their host contracts and reflected
them at fair value in the consolidated financial statements.
Drilling Rig Contracts. As of December 31, 2012, Whiting had entered into two contracts with drilling rig
companies, whereby the rig day rates included price adjustment clauses that are linked to changes in
NYMEX crude oil prices. These drilling rig contracts have termination dates of April 2014 and September
2014. The price adjustment formulas in the rig contracts stipulate that with every $10 increase or decrease
in the price of NYMEX crude, the cost of drilling rig day rates to the Company will likewise increase or
decrease by specific dollar amounts as set forth in each of the individual contracts. As of December 31,
2012, the aggregate estimated fair value of the embedded derivatives in these drilling rig contracts was
zero. This is because over the remaining period of each contract’s term, the prices on the forward curve for
crude oil at December 31, 2012 were within $10 of the prices on the forward curve on the date the contracts
were entered into, which leads to no change in the expected drilling costs under these contracts and
therefore no change in contractual value from the execution date.
As global crude oil prices increase or decrease, the demand for drilling rigs in North America similarly
increases and decreases. Because the supply of onshore drilling rigs in North America is fairly inelastic,
these changes in rig demand cause drilling rig day rates to increase or decrease in tandem with crude oil
price fluctuations. When the Company enters into a long-term drilling rig contract that has a fixed rig day
rate, which does not increase or decrease with changes in oil prices, the Company is exposed to the risk of
paying higher than the market day rate for drilling rigs in a climate of declining oil prices. This in turn
could have a negative impact on the Company’s oil and gas well economics. As a result, the Company
reduces its exposure to this risk by entering into certain drilling rig contracts which have day rates that
fluctuate in tandem with changes in oil prices.
CO2 Purchase Contract. In May 2011, Whiting entered into a long-term contract to purchase CO2 from
2015 through 2029 for use in its EOR project that is being carried out at its North Ward Estes field in
Texas. The price per Mcf of CO2 purchased under this agreement increases or decreases as the average
price of NYMEX crude oil likewise increases or decreases. As of December 31, 2012, the estimated fair
value of the embedded derivative in this CO2 purchase contract was an asset of $23.7 million.
94
Although CO2 is not a commodity that is actively traded on a public exchange, the market price for CO2
generally fluctuates in tandem with increases or decreases in crude oil prices. When Whiting enters into a
long-term CO2 purchase contract where the price of CO2 is fixed and does not adjust with changes in oil
prices, the Company is exposed to the risk of paying higher than the market rate for CO2 in a climate of
declining oil and CO2 prices. This in turn could have a negative impact on the project economics of the
Company’s CO2 flood at North Ward Estes. As a result, the Company reduces its exposure to this risk by
entering into certain CO2 purchase contracts which have prices that fluctuate along with changes in crude
oil prices.
Derivative Instrument Reporting—All derivative instruments are recorded on the consolidated balance
sheet at fair value, other than derivative instruments that meet the “normal purchase normal sale” exclusion.
The following tables summarize the location and fair value amounts of all derivative instruments in the
consolidated balance sheets (in thousands):
Not Designated as
ASC 815 Hedges
Derivative assets:
Balance Sheet Classification
Fair Value
December 31,
2012
December 31,
2011
Commodity contracts ................................Prepaid expenses and other ....................$
Embedded commodity contracts ....................
Prepaid expenses and other ....................
Commodity contracts ................................Other long-term assets ...........................
Embedded commodity contracts ....................Other long-term assets ...........................
Total derivative assets ................................................................................... $
Derivative liabilities:
Commodity contracts ................................Current derivative liabilities ..................$
Commodity contracts ................................Non-current derivative liabilities ...........
Total derivative liabilities.............................................................................. $
9,472
-
1,864
23,715
35,051
21,955
1,678
23,633
$
$
$
$
5,719
240
-
13,347
19,306
73,647
47,763
121,410
The following tables summarize the effects of commodity derivatives instruments on the consolidated
statements of income for the twelve months ended December 31, 2012 and 2011 (in thousands):
ASC 815 Cash Flow
Hedging Relationships (1)
Commodity contracts ...............................
Income Statement Classification
Gain on hedging activities ................................$
Gain Reclassified from OCI into
Income (Effective Portion) (1)
Year Ended December 31,
2011
2012
2,338
$
8,758
(1) Effective April 1, 2009, the Company elected to de-designate all of its commodity derivative contracts that
had been previously designated as cash flow hedges and elected to discontinue hedge accounting
prospectively. As a result, such mark-to-market values at March 31, 2009 were frozen in accumulated other
comprehensive income as of the de-designation date and are being reclassified into earnings as the original
hedged transactions affect income. During the next twelve months, the Company expects to reclassify into
earnings from accumulated other comprehensive income net after-tax losses of $1.2 million related to de-
designated commodity hedges.
Not Designated as
ASC 815 Hedges
Commodity contracts .......................Commodity derivative (gain) loss, net .............................
$
Embedded commodity contracts ......Commodity derivative (gain) loss, net ........
$
Total ...................................................................................................
Income Statement Classification
(Gain) Loss Recognized in Income
Year Ended December 31,
2011
2012
(11,270)
(75,782)
(13,587)
(10,129)
(24,857)
(85,911)
$
$
Contingent Features in Derivative Instruments. None of the Company’s derivative instruments contain
credit-risk-related contingent features. Counterparties to the Company’s derivative contracts are high
95
credit-quality financial institutions that are lenders under Whiting’s credit agreement. At the time Whiting
enters into derivative contracts, the Company uses only credit agreement participants to hedge with, since
these institutions are secured equally with the holders of Whiting’s bank debt, which eliminates the
potential need to post collateral when Whiting is in a derivative liability position. As a result, the Company
is not required to post letters of credit or corporate guarantees for its derivative counterparties in order to
secure contract performance obligations.
6.
FAIR VALUE MEASUREMENTS
The Company follows FASB ASC Topic 820, Fair Value Measurement and Disclosure, which establishes
a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy
categorizes assets and liabilities measured at fair value into one of three different levels depending on the
observability of the inputs employed in the measurement. The three levels are defined as follows:
• Level 1: Quoted Prices in Active Markets for Identical Assets – inputs to the valuation
methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
• Level 2: Significant Other Observable Inputs – inputs to the valuation methodology include quoted
prices for similar assets and liabilities in active markets, and inputs that are observable for the asset
or liability, either directly or indirectly, for substantially the full term of the financial instrument.
• Level 3: Significant Unobservable Inputs – inputs to the valuation methodology are unobservable
and significant to the fair value measurement.
A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of
input that is significant to the fair value measurement. The Company’s assessment of the significance of a
particular input to the fair value measurement in its entirety requires judgment and considers factors
specific to the asset or liability. The Company reflects transfers between the three levels at the beginning
of the reporting period in which the availability of observable inputs no longer justifies classification in the
original level.
The following tables present information about the Company’s financial assets and liabilities measured at
fair value on a recurring basis as of December 31, 2012 and 2011, and indicate the fair value hierarchy of
the valuation techniques utilized by the Company to determine such fair values (in thousands):
Level 1
Level 2
Level 3
Total Fair Value
December 31,
2012
Financial Assets
Commodity derivatives – current .............................
$
Commodity derivatives – non-current ................
Embedded commodity derivatives – non-
current................................................................
Total financial assets ................................$
Financial Liabilities
Commodity derivatives – current ..............................
Commodity derivatives – non-current .......................
Total financial liabilities ................................
$
$
-
-
-
-
-
-
-
$
$
$
$
9,472
1,864
-
11,336
21,955
1,678
23,633
$
$
$
$
-
-
23,715
23,715
-
-
-
$
$
$
$
9,472
1,864
23,715
35,051
21,955
1,678
23,633
96
Level 1
Level 2
Level 3
Total Fair Value
December 31,
2011
Financial Assets
Commodity derivatives – current ..............................
Embedded commodity derivatives – current .............
Embedded commodity derivatives – non-
$
current................................................................
Total financial assets ................................$
Financial Liabilities
Commodity derivatives – current ..............................
Commodity derivatives – non-current .......................
Total financial liabilities ................................
$
$
-
-
-
-
-
-
-
$
$
$
$
5,719
240
367
6,326
73,647
47,763
121,410
$
$
$
$
-
-
12,980
12,980
-
-
-
$
$
$
$
5,719
240
13,347
19,306
73,647
47,763
121,410
The following methods and assumptions were used to estimate the fair values of the assets and liabilities in
the tables above:
Commodity Derivatives. Commodity derivative instruments consist of costless collars for crude oil. The
Company’s costless collars are valued based on an income approach. These option models consider
various assumptions, including quoted forward prices for commodities, time value and volatility factors.
These assumptions are observable in the marketplace throughout the full term of the contract, can be
derived from observable data or are supported by observable levels at which transactions are executed in
the marketplace, and are therefore designated as Level 2 within the valuation hierarchy. The discount rates
used in the fair values of these instruments include a measure of either the Company’s or the counterparty’s
nonperformance risk, as appropriate. The Company utilizes counterparties’ valuations to assess the
reasonableness of its own valuations.
Embedded Commodity Derivatives. Embedded commodity derivatives relate to long-term drilling rig
contracts as well as a long-term CO2 purchase contract, which all have price adjustment clauses that are
linked to changes in NYMEX crude oil prices. Whiting has determined that the portions of these contracts
linked to NYMEX oil prices are not clearly and closely related to their corresponding host contracts, and
the Company has therefore bifurcated these embedded pricing features from the host contracts and reflected
them at fair value in its consolidated financial statements. These embedded commodity derivatives are
valued based on an income approach. These option models consider various assumptions, including quoted
forward prices for commodities, LIBOR discount rates and either the Company’s or the counterparty’s
nonperformance risk, as appropriate.
The assumptions used in the valuation of the drilling rig contracts are observable in the marketplace
throughout the full term of the contract, can be derived from observable data or are supported by
observable levels at which transactions are executed in the marketplace, and the fair value measurements of
the drilling rig contracts are therefore designated as Level 2 within the valuation hierarchy.
The assumptions used in the CO2 contract valuation, however, include inputs that are both observable in the
marketplace as well as unobservable during the term of the contract. With respect to forward prices for
NYMEX crude oil where there is a lack of price transparency in certain future periods, such unobservable
oil price inputs are significant to the CO2 contract valuation methodology, and the contract’s fair value is
therefore designated as Level 3 within the valuation hierarchy.
Level 3 Fair Value Measurements. A third-party valuation specialist is utilized on a quarterly basis to
determine the fair value of the embedded commodity derivative instrument designated as Level 3. The
Company reviews these valuations (including the related model inputs and assumptions) and analyzes
changes in fair value measurements between periods. The Company corroborates such inputs, calculations
97
and fair value changes using various methodologies, and Whiting reviews unobservable inputs for
reasonableness utilizing relevant information from other published sources.
The following table presents a reconciliation of changes in the fair value of financial assets (liabilities)
designated as Level 3 in the valuation hierarchy for the year ended December 31, 2012 and 2011 (in
thousands):
Fair value asset, beginning of period ................................................................$
Unrealized gains (losses) on embedded commodity derivative contracts
included in earnings(1) ................................................................................................
Transfers into (out of) Level 3(2) .........................................................................................
Fair value asset, end of period .........................................................................................
10,735
-
23,715
$
11,081
1,899
12,980
$
Year Ended December 31,
2011
2012
12,980
$
-
(1) Included in commodity derivative (gain) loss, net in the consolidated statements of income.
(2) With respect to forward prices for NYMEX crude oil where there is a lack of price transparency in certain future
periods during the term of the CO2 contract, such unobservable oil price inputs became significant to the
valuation methodology, and the contract’s fair value was therefore transferred from Level 2 to Level 3 within the
valuation hierarchy during the third quarter of 2011.
Quantitative Information About Level 3 Fair Value Measurements. The significant unobservable inputs
used in the fair value measurement of the Company’s embedded commodity derivative contract designated
as Level 3 are as follows:
Fair Value at
December 31, 2012
(in thousands)
Valuation
Technique
Embedded commodity
derivative ...............................
$ 23,715
Option model
Unobservable
Input
Future prices of
NYMEX crude oil after
December 31, 2020
Range
(per Bbl)
$88.02 - $111.61
Sensitivity To Changes In Significant Unobservable Inputs. As presented in the table above, the significant
unobservable inputs used in the fair value measurement of Whiting’s embedded commodity derivative
within its CO2 purchase contract are the future prices of NYMEX crude oil from January 2021 to December
2029. Significant increases (decreases) in these unobservable inputs in isolation would result in a
significantly lower (higher) fair value asset measurement.
Nonrecurring Fair Value Measurements. The Company applies the provisions of the fair value
measurement standard to its nonrecurring, non-financial measurements, including proved oil and gas
property impairments. These assets and liabilities are not measured at fair value on an ongoing basis but
are subject to fair value adjustments only in certain circumstances. The following tables present
information about the Company’s non-financial assets and liabilities measured at fair value on a
nonrecurring basis as of December 31, 2012 and 2011, and indicates the fair value hierarchy of the
valuation techniques utilized by the Company to determine such fair values (in thousands):
98
Net Carrying
Value as of
December 31,
2012
$ 23,473
Fair Value Measurements Using
Level 1
-
Level 2
-
Level 3
$ 23,473
Loss (Before
Tax) Year
Ended
December 31,
2012
$
46,924
Proved property impairments(1) ...................
(1) During the year ended December 31, 2012, proved oil and gas properties with a carrying amount of $70.4 million
were written down to their fair value of $23.5 million, resulting in a non-cash impairment charge of $46.9 million.
The impairment consisted of a $46.3 million write-down in the Rocky Mountains region related to changes in
estimated reserves and a $0.6 million write-down in the Michigan region related to decreased natural gas prices.
Net Carrying
Value as of
December 31,
2011
$ 1,612
Fair Value Measurements Using
Level 1
-
Level 2
-
Level 3
$ 1,612
Loss (Before
Tax) Year
Ended
December 31,
2011
$
3,241
Proved property impairments(1) ...................
(1) During the year ended December 31, 2011, proved oil and gas properties with a carrying amount of $4.8 million
were written down to their fair value of $1.6 million, resulting in a non-cash impairment charge of $3.2 million.
The impairment consisted of a $2.4 million write-down in the Rocky Mountains region and a $0.8 million write-
down in the Michigan region. These impairments were mainly due to decreases in natural gas prices.
The following methods and assumptions were used to estimate the fair values of the non-financial liabilities
in the tables above:
Proved Property Impairments. Once the Company has determined that a proved property impairment has
occurred, the cost of the property is written down to its fair value, which is determined using net discounted
future cash flows from the producing property, and such discounted cash flows are based on the income
approach. The factors used to determine the estimated future cash flows include, but are not limited to,
internal estimates of reserves, future commodity prices, production levels, operating costs, development
expenditures, and a risk-adjusted discount rate, which are all Level 3 inputs. Quantitative information
about the unobservable inputs used in the Company’s significant nonrecurring fair value measurement of
its proved oil and natural gas properties (designated as Level 3 in the fair value hierarchy) in 2012 is as
follows:
Unobservable Input
Future production ...............................................................................................................
Future prices of crude oil per Bbl .......................................................................................
Future prices of NGLs per Bbl ...........................................................................................
Future prices of natural gas per Mcf ...................................................................................
Future operating costs per BOE .........................................................................................
Productive lives of fields ....................................................................................................
Discount rate ......................................................................................................................
Quantitative Data
836 MBOE
$ 80.75 - $110.38
$ 51.25 - $ 73.54
$ 3.76 - $ 10.17
$ 10.09 - $ 74.40
15 – 29 years
15%
7.
DEFERRED COMPENSATION
Production Participation Plan—The Company has a Production Participation Plan (the “Plan”) in which
all employees participate. On an annual basis, interests in oil and gas properties acquired, developed or
sold during the year are allocated to the Plan as determined annually by the Compensation Committee of
the Company’s Board of Directors. Once allocated, the interests (not legally conveyed) are fixed. Interest
allocations prior to 1995 consisted of 2%-3% overriding royalty interests. Interest allocations since 1995
have been 2%-5% of oil and gas sales less lease operating expenses and production taxes.
99
Payments of 100% of the year’s Plan interests to employees and the vested percentages of former
employees in the year’s Plan interests are made annually in cash after year-end. Accrued compensation
expense under the Plan for the years ended December 31, 2012, 2011 and 2010 amounted to $44.7 million,
$34.1 million and $27.7 million, respectively, charged to general and administrative expense and $4.6
million, $4.2 million and $3.7 million, respectively, charged to exploration expense.
Employees vest in the Plan ratably at 20% per year over a five-year period. Pursuant to the terms of the
Plan, (i) employees who terminate their employment with the Company are entitled to receive their vested
allocation of future Plan year payments on an annual basis; (ii) employees will become fully vested at age
62, regardless of when their interests would otherwise vest; and (iii) any forfeitures inure to the benefit of
the Company.
The Company uses average historical prices to estimate the vested long-term Production Participation Plan
liability. At December 31, 2012, the Company used three-year average historical NYMEX prices of $89.62
for crude oil and $3.77 for natural gas to estimate this liability. If the Company were to terminate the Plan
or upon a change in control of the Company (as defined in the Plan), all employees fully vest and the
Company would distribute to each Plan participant an amount, based upon the valuation method set forth in
the Plan, in a lump sum payment twelve months after the date of termination or within one month after a
change in control event. Based on current strip prices at December 31, 2012, if the Company elected to
terminate the Plan or if a change of control event occurred, it is estimated that the fully vested lump sum
cash payment to employees would approximate $175.0 million. This amount includes $10.5 million
attributable to proved undeveloped oil and gas properties and $49.3 million relating to the short-term
portion of the Plan liability, which has been accrued as a current payable and was paid in January 2013.
The ultimate sharing contribution for proved undeveloped oil and gas properties will be awarded in the year
of Plan termination or change of control. However, the Company has no intention to terminate the Plan.
The following table presents changes in the Plan’s estimated long-term liability (in thousands):
Long-term Production Participation Plan liability at January 1 .................
Change in liability for accretion, vesting, changes in estimates and new
Plan year activity ................................................................................
Accrued compensation expense reflected as a current liability .................
Long-term Production Participation Plan liability at December 31 ...........
Year Ended December 31,
2011
2012
$
80,659
$
81,524
63,135
(49,311)
94,483
$
37,429
(38,294)
80,659
$
The Company records the expense associated with changes in the present value of estimated future
payments under the Plan as a separate line item in the consolidated statements of income. The amount
recorded is not allocated to general and administrative expense or exploration expense because the
adjustment of the liability is associated with the future net cash flows from the oil and gas properties rather
than current period performance. The following table presents the estimated allocation of the change in the
liability if the Company did allocate the adjustment to these specific line items (in thousands):
General and administrative expense ...............................
Exploration expense ........................................................
Total .........................................................................
$
$
2012
12,544
1,280
13,824
Year Ended December 31,
2011
$
$
(770)
(95)
(865)
$
$
2010
10,676
1,415
12,091
401(k) Plan—The Company has a defined contribution retirement plan for all employees. The plan is
funded by employee contributions and discretionary Company contributions.
The Company’s
contributions for 2012, 2011 and 2010 were $5.9 million, $5.0 million and $3.6 million, respectively.
Employees vest in employer contributions at 20% per year of completed service.
100
8.
SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST
Common Stock—In May 2011, Whiting’s stockholders approved an amendment to the Company’s
Restated Certificate of Incorporation to increase the number of authorized shares of common stock from
175,000,000 shares to 300,000,000 shares.
Stock Split. On January 26, 2011, the Company’s Board of Directors approved a two-for-one split of the
Company's shares of common stock to be effected in the form of a stock dividend. As a result of the stock
split, stockholders of record on February 7, 2011 received one additional share of common stock for each
share of common stock held. The additional shares of common stock were distributed on February 22,
2011. Concurrently with the payment of such stock dividend in February 2011, there was a transfer from
additional paid-in capital to common stock of $0.1 million, which amount represents $0.001 per share
(being the par value thereof) for each share of common stock so issued. All common share and per share
amounts in these consolidated financial statements and related notes for periods prior to February 2011
have been retroactively adjusted to reflect the stock split. The common stock dividend resulted in the
conversion price for Whiting’s 6.25% Convertible Perpetual Preferred Stock being adjusted from $43.4163
to $21.70815.
6.25% Convertible Perpetual Preferred Stock—In June 2009, the Company completed a public offering of
6.25% convertible perpetual preferred stock (“preferred stock”), selling 3,450,000 shares at a price of
$100.00 per share. As of December 31, 2012, however, only 172,391 shares of preferred stock remained
outstanding.
Each holder of the preferred stock is entitled to an annual dividend of $6.25 per share to be paid quarterly
in cash, common stock or a combination thereof on March 15, June 15, September 15 and December 15,
when and if such dividend has been declared by Whiting’s board of directors. Each share of preferred
stock has a liquidation preference of $100.00 per share plus accumulated and unpaid dividends and is
convertible, at a holder’s option, into shares of Whiting’s common stock based on a conversion price of
$21.70815, subject to adjustment upon the occurrence of certain events. The preferred stock is not
redeemable by the Company. At any time on or after June 15, 2013, the Company may cause all
outstanding shares of this preferred stock to be converted into shares of common stock if the closing price
of our common stock equals or exceeds 120% of the then-prevailing conversion price for at least 20 trading
days in a period of 30 consecutive trading days. The holders of preferred stock have no voting rights unless
dividends payable on the preferred stock are in arrears for six or more quarterly periods.
Induced Conversion of 6.25% Convertible Perpetual Preferred Stock. In August 2010, Whiting
commenced an offer to exchange up to 3,277,500, or 95%, of its preferred stock for the following
consideration per share of preferred stock: 4.6066 shares of its common stock and a cash premium of
$14.50. The exchange offer expired in September 2010 and resulted in the Company accepting 3,277,500
shares of preferred stock in exchange for the issuance of 15,098,020 shares of common stock and a cash
premium payment of $47.5 million. Following the exchange offer, the 3,277,500 shares of preferred stock
accepted in the exchange were cancelled, and a total of 172,500 shares of preferred stock remained
outstanding.
Equity Incentive Plan—The Company maintains the Whiting Petroleum Corporation 2003 Equity
Incentive Plan (the “Equity Plan”), pursuant to which 2,978,323 shares of the Company’s common stock
have been reserved for issuance. No employee or officer participant may be granted options for more than
600,000 shares of common stock, stock appreciation rights relating to more than 600,000 shares of
common stock, or more than 300,000 shares of restricted stock during any calendar year. As of
December 31, 2012, 1,178,071 shares of common stock remained available for grant under the Plan.
For the years ended December 31, 2012, 2011 and 2010, total stock compensation expense recognized for
restricted share awards and stock options was $18.2 million, $13.5 million and $8.9 million, respectively.
101
Restricted Shares. Restricted stock awards for executive officers, directors and employees generally vest
ratably over a three-year service period. The Company uses historical data and projections to estimate
expected employee behaviors related to restricted stock forfeitures. The expected forfeitures are then
included as part of the grant date estimate of compensation cost. For service-based restricted stock awards,
the grant date fair value is determined based on the closing bid price of the Company’s common stock on
the grant date.
In January 2012, 2011 and 2010, 444,501 shares, 201,420 shares and 180,898 shares, respectively, of
restricted stock, subject to certain market-based vesting criteria in addition to the standard three-year
service condition, were granted to executive officers under the Equity Plan. Vesting each year is subject to
the condition that Whiting’s stock price increases by a greater percentage, or decreases by a lesser
percentage, than the average percentage increase or decrease, respectively, of the stock prices of a peer
group of companies. The market-based conditions must be met in order for the stock awards to vest, and it
is therefore possible that no shares could vest in one or more of the three-year vesting periods. However,
the Company recognizes compensation expense for awards subject to market conditions regardless of
whether it becomes probable that these conditions will be achieved or not, and compensation expense is not
reversed if vesting does not actually occur.
For these awards subject to market conditions, the grant date fair value was estimated using a Monte Carlo
valuation model. The Monte Carlo model is based on random projections of stock price paths and must be
repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on
the historical volatility of Whiting’s common stock, and the risk-free interest rate is based on U.S. Treasury
yield curve rates with maturities consistent with the three-year vesting period. The key assumptions used in
valuing the market-based restricted shares were as follows:
2012
Number of simulations ................................................................
65,000
Expected volatility ................................................................51.9%
0.35%
Risk-free rate................................................................
2011
65,000
75.8%
1.00%
2010
65,000
75.9%
1.40%
The grant date fair value of the market-based restricted stock as determined by the Monte Carlo valuation
model was $29.45 per share, $42.20 per share and $22.99 per share in January 2012, 2011 and 2010,
respectively.
The following table shows a summary of the Company’s nonvested restricted stock as of December 31,
2010, 2011 and 2012 as well as activity during the years then ended:
Number
of Shares
Weighted Average
Grant Date
Fair Value
Restricted stock awards nonvested, January 1, 2010 .............................................
Granted ..................................................................................................................
Vested ....................................................................................................................
Forfeited .................................................................................................................
Restricted stock awards nonvested, December 31, 2010 ................................
Granted ..................................................................................................................
Vested ....................................................................................................................
Forfeited .................................................................................................................
Restricted stock awards nonvested, December 31, 2011 ................................
Granted ..................................................................................................................
Vested ....................................................................................................................
Forfeited .................................................................................................................
Restricted stock awards nonvested, December 31, 2012 ................................
1,036,528
324,770
(465,194)
(26,734)
869,370
304,355
(429,136)
(20,194)
724,395
592,400
(357,170)
(8,599)
951,026
$
$
11.86
28.44
14.49
24.10
16.27
48.48
15.32
33.53
29.88
34.45
17.91
51.72
37.02
102
As of December 31, 2012, there was $10.5 million of total unrecognized compensation cost related to
unvested restricted stock granted under the stock incentive plans. That cost is expected to be recognized
over a weighted average period of 1.8 years. For the years ended December 31, 2012, 2011 and 2010, the
total fair value of restricted stock vested was $18.9 million, $26.0 million and $17.1 million, respectively.
Stock Options. In January 2012, 2011 and 2010, 45,359 stock options, 80,820 stock options and 55,302
stock options, respectively, were granted under the Equity Plan to certain executive officers of the
Company with exercise prices equal to the closing market price of the Company’s common stock on the
grant date. These stock options vest ratably over a three-year service period from the grant date and are
exercisable immediately upon vesting through the tenth anniversary of the grant date.
The Company uses a Black-Scholes option-pricing model to estimate the fair value of stock option awards.
Because the Company first granted stock options in 2009, it does not have historical exercise data upon
which to estimate the expected term of the options. As such, the Company has elected to estimate the
expected term of the stock options granted using the “simplified” method for “plain vanilla” options. The
expected volatility at the grant date is based on the historical volatility of Whiting’s common stock, and the
risk-free interest rate is determined based on the yield on U.S. Treasury strips with maturities similar to
those of the expected term of the stock options. The following table summarizes the assumptions used to
estimate the grant date fair value of stock options awarded in each respective year:
Risk-free interest rate ................................................................1.19%
Expected volatility ................................................................61.4%
6.0 yrs.
Expected term ................................................................
Dividend yield................................................................
-
2012
2011
2.47%
59.3%
6.0 yrs.
-
2010
2.75%
58.8%
6.0 yrs.
-
The grant date fair value of the stock options awarded, as determined by the Black-Scholes valuation
model, was $28.88 per share, $34.15 per share and $19.44 per share in January 2012, 2011 and 2010,
respectively.
The following table shows a summary of the Company’s stock options outstanding as of December 31,
2010, 2011 and 2012 as well as activity during the years then ended (aggregate intrinsic value presented in
thousands):
103
Weighted
Average
Remaining
Contractual
Term
(in Years)
Aggregate
Intrinsic
Value
Options outstanding at January 1, 2010 ................................
Granted ................................................................................................
Exercised ................................................................................................
Forfeited or expired................................................................
Options outstanding at December 31, 2010 ................................
Granted ................................................................................................
Exercised ................................................................................................
Forfeited or expired................................................................
Options outstanding at December 31, 2011 ................................
Granted ................................................................................................
Exercised ................................................................................................
Forfeited or expired................................................................
Options outstanding at December 31, 2012 ................................
Options vested and expected to vest at December
Number of
Options
241,214
55,302
-
-
296,516
80,820
-
-
377,336
45,359
-
-
422,695
31, 2012 ................................................................ 422,695
305,006
Options exercisable at December 31, 2012 ................................
Weighted
Average
Exercise Price
per Share
12.76
$
34.31
-
-
16.78
60.28
-
-
26.09
51.22
-
-
28.79
$
$
$
$
-
-
-
$ 7,884.6
$
$
28.79
19.56
$ 7,884.6
$ 7,717.5
6.9
6.9
6.4
Unrecognized compensation cost as of December 31, 2012 related to unvested stock option awards was
$1.0 million, which is expected to be recognized over a period of 1.7 years.
Rights Agreement—In 2006, the Board of Directors of the Company declared a dividend of one preferred
share purchase right (a “Right”) for each outstanding share of common stock of the Company payable to
the stockholders of record as of March 2, 2006. As a result of the two-for-one split of the Company’s
common stock effective February 22, 2011, one-half of a Right is now associated with each share of
common stock. Each Right entitles the registered holder to purchase from the Company one one-hundredth
of a share of Series A Junior Participating Preferred Stock, par value $0.001 per share (“Preferred Shares”),
of the Company at a price of $180.00 per one one-hundredth of a Preferred Share, subject to adjustment. If
any person becomes a 15% or more stockholder of the Company, then each Right (subject to certain
limitations) will entitle its holder to purchase, at the Right’s then current exercise price, a number of shares
of common stock of the Company or of the acquirer having a market value at the time of twice the Right’s
per share exercise price. The Company’s Board of Directors may redeem the Rights for $0.001 per Right
at any time prior to the time when the Rights become exercisable. Unless the Rights are redeemed,
exchanged or terminated earlier, they will expire on February 23, 2016.
Noncontrolling Interest—The noncontrolling interest represents an unrelated third party’s 25% ownership
interest in SWR. The table below summarizes the activity for the equity attributable to the noncontrolling
interest (in thousands):
Year Ended December 31,
2012
2011
Balance at January 1 ................................................................................................
Contributions from noncontrolling interest ................................................................
Net income (loss) ................................................................................................
Balance at December 31 ................................................................ $
8,274
-
(90)
8,184
$
$
$
-
8,333
(59)
8,274
104
9.
INCOME TAXES
Income tax expense consists of the following (in thousands):
2012
Year Ended December 31,
2011
2010
Current income tax expense (refund):
Federal .......................................................................
State ...........................................................................
Total current income tax expense .........................
Deferred income tax expense:
Federal .......................................................................
State ...........................................................................
Total deferred income tax expense .......................
Total ..............................................................
$
$
-
(669)
(669)
233,468
15,113
248,581
247,912
$
$
107
3,746
3,853
272,653
12,185
284,838
288,691
$
$
892
4,087
4,979
188,386
11,425
199,811
204,790
Income tax expense differed from amounts that would result from applying the U.S. statutory income tax
rate (35%) to income before income taxes as follows (in thousands):
U.S. statutory income tax expense ..................................
State income taxes, net of federal benefit .......................
Statutory depletion ..........................................................
Enacted changes in state tax laws ...................................
Permanent items ..............................................................
Other ...............................................................................
Total .......................................................................
$
$
$
Year Ended December 31,
2011
273,112
16,602
(697)
(1,842)
1,420
96
288,691
$
2012
231,704
14,444
(620)
-
1,524
860
247,912
$
$
2010
189,505
14,051
(632)
-
1,071
795
204,790
The principal components of the Company’s deferred income tax assets and liabilities at December 31,
2012 and 2011 were as follows (in thousands):
Year Ended December 31,
2011
2012
Deferred income tax assets:
$
Net operating loss carryforward ..........................................................
Derivative instruments .........................................................................
Production Participation Plan liability .................................................
Tax sharing liability .............................................................................
Asset retirement obligations ................................................................
Underwriter fees ..................................................................................
Restricted stock compensation ............................................................
Enhanced oil recovery credit carryforwards ........................................
Alternative minimum tax credit carryforwards ...................................
Foreign tax credit carryforwards .........................................................
Other ....................................................................................................
Total deferred income tax assets ..................................................
Less valuation allowances ..................................................................
Net deferred income tax assets .....................................................
520,980
19,957
34,865
8,312
19,759
12,677
9,852
7,946
11,391
1,230
1,508
648,477
(1,230)
647,247
$
172,531
60,938
29,764
9,062
17,079
4,348
5,431
7,946
11,391
1,230
650
320,370
(1,230)
319,140
Deferred income tax liabilities:
Oil and gas properties ..........................................................................
Trust distributions ................................................................................
Total deferred income tax liabilities ............................................
Total net deferred income tax liabilities .............................................
1,555,142
165,180
1,720,322
1,073,075
$
1,108,276
36,091
1,144,367
825,227
$
105
As of December 31, 2012, we had federal net operating loss (“NOL”) carryforwards of $1,470.3 million.
Of this amount, $46.0 million in NOL carryforwards relate to tax deductions for stock compensation that
exceed stock compensation costs recognized for financial statement purposes. The benefit of these excess
tax deductions will not be recognized as an NOL in the Company’s financial statements, until the related
deductions reduce taxes payable and are thereby realized. The Company also has various state net
operating loss carryforwards. The determination of the state net operating loss carryforwards is dependent
upon apportionment percentages and state laws that can change from year to year and impact the amount of
such carryforwards. If unutilized, the federal net operating loss will expire between 2027 and 2032, and the
state net operating losses will expire between 2013 and 2032.
EOR credits are a credit against federal income taxes for certain costs related to extracting high-cost oil,
utilizing certain prescribed “enhanced” tertiary recovery methods. As of December 31, 2012, the Company
had recognized aggregate enhanced oil recovery credits of $7.9 million that are available to offset regular
federal income taxes in the future. These credits can be carried forward and will expire between 2023 and
2025. Federal EOR credits are subject to phase-out according to the level of average domestic crude oil
prices. The EOR credit has been phased-out since 2006, but this phase-out affects only the periods for
which EOR credits can be captured and not the periods in which such credits can be utilized.
The Company is subject to the alternative minimum tax (“AMT”) principally due to its significant
intangible drilling cost deductions. As of December 31, 2012, the Company had AMT credits totaling
$11.4 million that are available to offset future regular federal income taxes. These credits do not expire
and can be carried forward indefinitely.
At December 31, 2012, the Company’s foreign tax credit carryforwards totaled $1.2 million, which will
expire between 2014 and 2016. As of December 31, 2012, a valuation allowance of $1.2 million was
established in full for the foreign tax credit carryforwards because the Company determined that it was
more likely than not that the benefit from these deferred tax assets will not be realized due to the divestiture
of all foreign operations.
Net deferred income tax liabilities were classified in the consolidated balance sheets as follows (in
thousands):
Year Ended December 31,
2011
2012
Assets:
Current deferred income taxes ............................................................
$
-
Liabilities:
Current deferred income taxes ............................................................
Non-current deferred income taxes .....................................................
Net deferred income tax liabilities ...............................................
9,394
1,063,681
1,073,075
$
$
$
-
1,584
823,643
825,227
The following table summarizes the activity related to the Company's liability for unrecognized tax benefits
(in thousands):
Beginning balance at January 1 ......................................
Decrease related to tax position taken in a prior period ..
Ending balance at December 31......................................
$
$
2012
Year Ended December 31,
2011
2010
299
(129)
170
$
$
299
-
299
$
$
299
-
299
Included in the unrecognized tax benefit balance at December 31, 2012, are $0.2 million of tax positions,
the allowance of which would positively affect the annual effective income tax rate. For the year ended
106
December 31, 2012, the Company did not recognize any interest or penalties with respect to unrecognized
tax benefits, nor did the Company have any such interest or penalties previously accrued. The Company
believes that it is reasonably possible that no increases or decreases to unrecognized tax benefits will occur
in the next twelve months.
The Company files income tax returns in the U.S. Federal jurisdiction, in various states, and previously
filed in two foreign jurisdictions each with varying statutes of limitations. The 2009 through 2012 tax
years generally remain subject to examination by federal and state tax authorities. The foreign jurisdictions
generally remain subject to examination by their respective authorities for the 2006 period.
10.
EARNINGS PER SHARE
The reconciliations between basic and diluted earnings per share are as follows (in thousands, except per
share data):
Basic Earnings Per Share (1)
Numerator:
2012
Year Ended December 31,
2011
2010
Net income (loss) available to shareholders ............................
Preferred stock dividends (2) ....................................................
Net income (loss) available to common
$
414,189
(1,077)
shareholders, basic ................................................................
$
413,112
$
491,687
(1,077)
$
336,653
(63,069)
$
490,610
$
273,584
Denominator:
Weighted average shares outstanding, basic ...........................
117,601
117,345
106,338
Diluted Earnings Per Share(1)
Numerator:
Net income (loss) available to common
shareholders, basic ................................................................
Preferred stock dividends ........................................................
Adjusted net income (loss) available to
$
413,112
1,077
$
490,610
1,077
$
273,584
1,078
common shareholders, diluted ................................ $
414,189
$
491,687
$
274,662
Denominator:
Weighted average shares outstanding, basic ...........................
Restricted stock and stock options ................................
Convertible perpetual preferred stock ................................
Weighted average shares outstanding, diluted ........................
117,601
633
794
119,028
117,345
529
794
118,668
106,338
714
794
107,846
Earnings (loss) per common share, basic ................................$
Earnings (loss) per common share, diluted ................................$
_____________________
(1) All share and per share amounts have been retroactively restated for the 2010 period to reflect the Company’s two-
2.57
2.55
3.51
3.48
4.18
4.14
$
$
$
$
for-one stock split in February 2011, as described in Note 8 to these consolidated financial statements.
(2) For the year ended December 31, 2010, amount includes a decrease of $0.9 million in preferred stock dividends for
preferred stock dividends accumulated. There were no accumulated dividend adjustments for the years ended
December 31, 2012 and 2011.
For the year ended December 31, 2012, the diluted earnings per share calculation excludes (i) the dilutive
effect of 141,807 incremental shares of restricted stock that did not meet its market-based vesting criteria
as of December 31, 2012, and (ii) the anti-dilutive effect of 7,720 common shares for stock options that
were out-of-the-money. For the year ended December 31, 2011, the diluted earnings per share calculation
excludes the dilutive effect of (i) 113,228 incremental shares of restricted stock that did not meet its
market-based vesting criteria as of December 31, 2011, and (ii) 2,285 common shares for stock options that
107
were out-of-the-money. For the year ended December 31, 2010, the diluted earnings per share calculation
excludes the effect of 10,713,390 incremental common shares (which were issuable upon the conversion of
perpetual preferred stock as of a January 1, 2010 assumed conversion date) because their effect was anti-
dilutive.
11.
RELATED PARTY TRANSACTIONS
Whiting USA Trust I—As a result of Whiting’s retained ownership of 15.8%, or 2,186,389 units in
Whiting USA Trust I, it is a related party of the Company. The following table summarizes the related
party receivable and payable balances between the Company and Trust I as of December 31, 2012 and
2011 (in thousands):
Assets
Unit distributions due from Trust I (1) ........................................................
Total .................................................................................................
Liabilities
Unit distributions payable to Trust I (2) ......................................................
Current portion of derivative liability due to Trust I ..................................
Total .................................................................................................
$
$
$
$
December 31,
2012
2011
929
929
5,731
-
5,731
$
$
$
$
1,127
1,127
7,146
4,336
11,482
_____________________
(1) This amount represents Whiting’s 15.8% interest in the net proceeds due from Trust I and is included within
accounts receivable trade, net in the Company’s consolidated balance sheets.
(2) This amount represents net proceeds from Trust I’s underlying properties as well as realized cash settlements on
Trust I derivatives, that the Company has received between the last Trust I distribution date and December 31,
2012, but which the Company has not yet distributed to Trust I as of December 31, 2012. Due to ongoing
processing of Trust I revenues and expenses after December 31, 2012, the amount of Whiting’s next scheduled
distribution to Trust I, and the related distribution by Trust I to its unitholders, will differ from this amount. This
amount is included within accounts payable trade in the Company’s consolidated balance sheet.
For the year ended December 31, 2012, Whiting paid $37.6 million, net of state tax withholdings, in unit
distributions to Trust I and received $5.8 million in distributions back from Trust I pursuant to its retained
ownership in 2,186,389 Trust I units.
Tax Sharing Liability—Prior to Whiting’s initial public offering in November 2003, it was a wholly-
owned indirect subsidiary of Alliant Energy Corporation (“Alliant Energy”), and when the transactions
discussed below were entered into, Alliant Energy was a related party of the Company. As of December
31, 2004 and thereafter, Alliant Energy was no longer a related party.
In 2003, the Company entered into a Tax Separation and Indemnification Agreement with Alliant Energy,
whereby the Company and Alliant Energy made certain tax elections with the effect that the tax bases of
Whiting’s assets were increased. Such additional tax bases have resulted in increased income tax
deductions for Whiting and, accordingly, have reduced income taxes otherwise payable by Whiting. Under
this Tax Separation and Indemnification Agreement, the Company agreed to pay to Alliant Energy (each
year from 2004 to 2013) 90% of the tax benefits the Company realizes annually as a result of this step-up
in tax bases. In 2014, Whiting will be obligated to pay Alliant the present value of 90% of the remaining
tax benefits expected to result from its increased tax bases, assuming all such tax benefits will be realized
in future years.
The present value of estimated payments due Alliant Energy under this agreement have been reflected in
the Company’s consolidated balance sheets. The long-term portions of this tax sharing liability of $21.1
million and $21.2 million as of December 31, 2012 and 2011, respectively, have been included in other
long-term liabilities, and the Company’s estimated payment of $1.5 million to be made in 2013 is reflected
108
as a current liability at December 31, 2012. During 2012, 2011 and 2010, the Company made payments of
$2.3 million, $1.9 million and $1.6 million, respectively, under this agreement and recognized interest
expense of $2.2 million, $2.1 million and $1.5 million, respectively.
Alliant Energy Guarantee—The Company holds a 6% working interest in three offshore platforms in
California and the related onshore plant and equipment. Alliant Energy has guaranteed the Company’s
obligation in the abandonment of these assets.
12.
COMMITMENTS AND CONTINGENCIES
The table below shows the Company’s minimum future payments under non-cancelable operating leases
and unconditional purchase obligations as of December 31, 2012 (in thousands):
2013
$ 5,402
Non-cancelable leases ................................
92,823
Drilling rig contracts ................................
Total ................................$ 98,225
2014
$ 6,227
65,899
$ 72,126
Payments due by period
2016
$ 5,352
918
$ 6,270
2017
$ 5,214
-
$ 5,214
2015
$ 5,831
27,702
$ 33,533
Thereafter
$ 5,921
-
$ 5,921
Total
$ 33,947
187,342
$ 221,289
Non-cancelable Leases—The Company leases 172,400 square feet of administrative office space in
Denver, Colorado under an operating lease arrangement expiring in 2018, 46,300 square feet of office
space in Midland, Texas expiring in 2020 and 20,000 square feet of office space in Dickinson, North
Dakota expiring in 2016. In addition, the Company entered into a lease for several residential apartments
in Watford City, North Dakota under an operating lease arrangement expiring in 2015. Rental expense for
2012, 2011 and 2010 amounted to $5.7 million, $4.4 million and $3.4 million, respectively. Minimum
lease payments under the terms of non-cancelable operating leases as of December 31, 2012 are shown in
the table above.
Drilling Rig Contracts—The Company currently has 12 drilling rigs under long-term contract, of which
three drilling rigs expire in 2013, six in 2014, one in 2015 and two in 2016. All of these rigs are operating
in the Rocky Mountains region. As of December 31, 2012, early termination of the remaining contracts
would require termination penalties of $145.1 million, which would be in lieu of paying the remaining
drilling commitments of $187.3 million. No other drilling rigs working for the Company are currently
under long-term contracts or contracts that cannot be terminated at the end of the well that is currently
being drilled. During 2012, 2011 and 2010, the Company made payments of $101.1 million, $49.8 million
and $44.6 million, respectively, under these long-term contracts, which are initially capitalized as a
component of oil and gas properties and either depleted in future periods or written off as exploration
expense. Two of these drilling rigs have price adjustment clauses that are linked to changes in NYMEX
crude oil prices, and this component of those purchase obligations is therefore variable. Minimum drilling
commitments under the terms of these contracts as of December 31, 2012 are shown in the table above.
Purchase Contracts—The Company has four take-or-pay purchase agreements, two agreements expiring
in December 2014, one agreement expiring in December 2017 and one agreement expiring in December
2029, whereby the Company has committed to buy certain volumes of CO2 for use in its enhanced recovery
projects in the Postle field in Oklahoma and the North Ward Estes field in Texas. The purchase
agreements are with three different suppliers. Under the terms of the agreements, the Company is
obligated to purchase a minimum daily volume of CO2 (as calculated on an annual basis) or else pay for
any deficiencies at the price in effect when the minimum delivery was to have occurred. In addition, the
Company has two ship-or-pay agreements with two different parties, one expiring in June 2013 and one
expiring in December 2017, whereby it has committed to transport a minimum daily volume of CO2 via
certain pipelines or else pay for any deficiencies at a price stipulated in the contract.
109
The CO2 volumes planned for use in the Company’s enhanced recovery projects in the Postle and North
Ward Estes fields currently exceed the minimum daily volumes specified in all of these agreements.
Therefore, the Company expects to avoid any payments for deficiencies. During 2012, 2011 and 2010,
purchases and transportation of CO2 amounted to $86.0 million, $69.8 million and $56.2 million,
respectively. Although minimum daily quantities are specified in the agreements, the actual CO2 volumes
purchased or transported and their corresponding unit prices are variable over the term of the contracts. As
a result, the future minimum payments for each of the five succeeding fiscal years are not fixed and
determinable and are not therefore included in the table above. As of December 31, 2012, the Company
estimated future commitments under these purchase agreements to approximate $712.3 million through
2029.
Litigation—The Company is subject to litigation, claims and governmental and regulatory proceedings
arising in the ordinary course of business. It is the opinion of the Company’s management that all claims
and litigation involving the Company are not likely to have a material effect on its consolidated financial
position, cash flows or results of operations.
13.
SUBSEQUENT EVENTS
On February 15, 2013, the Company declared a dividend of $1.5625 per share on its 6.25% convertible
perpetual preferred stock. The total dividend amounting to $0.3 million is payable on March 15, 2013 to
holders of record on March 1, 2013.
14.
OIL AND GAS ACTIVITIES
The Company’s oil and gas activities for 2012, 2011 and 2010 were entirely within the United States.
Costs incurred in oil and gas producing activities were as follows (in thousands):
Development(1) ................................................................
Proved property acquisition ............................................
Unproved property acquisition........................................
Exploration......................................................................
Total .........................................................................
2012
$ 1,667,182
19,785
119,175
436,084
$ 2,242,226
Year Ended December 31,
2011
$ 1,245,150
4,324
191,482
400,823
$ 1,841,779
$
2010
723,687
22,763
155,472
114,012
$ 1,015,934
_____________________
(1) During 2012, 2011 and 2010, non-cash additions to oil and gas properties of $36.3 million, $4.9 million and $3.5
million, respectively, which relate to estimated costs of the future plugging and abandonment of the Company’s
oil and gas wells, are included in development costs in the table above.
Net capitalized costs related to the Company’s oil and gas producing activities were as follows (in
thousands):
Year Ended December 31,
2011
2012
7,221,550
8,849,515
354,774
362,483
(2,066,830)
(2,564,081)
6,647,917
5,509,494
$
$
Proved oil and gas properties .....................................................................
Unproved oil and gas properties ................................................................
Accumulated depreciation, depletion and amortization .............................
Oil and gas properties, net ..................................................................
$
$
110
Exploratory well costs that are incurred and expensed in the same annual period have not been included in
the table below. The net changes in capitalized exploratory well costs were as follows (in thousands):
Beginning balance at January 1 ........................................
Additions to capitalized exploratory well costs
2012
Year Ended December 31,
2011
2010
$
90,519
$
4,434
$
-
pending the determination of proved reserves ...............
384,223
354,962
Reclassifications to wells, facilities and equipment
based on the determination of proved reserves .............
Capitalized exploratory well costs charged to expense .....
Ending balance at December 31 ........................................
(358,625)
(7,256)
108,861
$
(267,847)
(1,030)
90,519
$
$
81,167
(76,733)
-
4,434
At December 31, 2012, the Company had $51.2 million of capitalized exploratory well costs related to four
wells that were in progress for a period of greater than one year after the completion of drilling. These four
wells are located in the Company’s Permian Basin, Rocky Mountains and Mid-Continent regions. Of the
$51.2 million in costs capitalized for these exploratory wells, $21.8 million and $29.4 million were incurred
in 2012 and 2011, respectively. With respect to the two wells in the Permian Basin region and one well in
the Rocky Mountains region, the Company is continuing to incur costs to assess these wells’ reserves and
their related development potential. As for the one remaining well located in the Mid-Continent region, the
Company has found economic quantities of oil and gas reserves. However, the permitting of a gas line to
bring this well’s production to market is still currently in progress.
15.
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
For all years presented our independent petroleum engineers independently estimated all of the proved,
probable and possible reserve quantities included in this annual report. In connection with our external
petroleum engineers performing their independent reserve estimations, we furnish them with the following
information that they review: (1) technical support data, (2) technical analysis of geologic and engineering
support information, (3) economic and production data, and (4) our well ownership interests. The
independent petroleum engineers, Cawley, Gillespie & Associates, Inc., evaluated 100% of our estimated
proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2012. Proved
reserve estimates included herein conform to the definitions prescribed by the U.S. Securities and
Exchange Commission. Estimates of proved reserves are inherently imprecise and are continually subject
to revision based on production history, results of additional exploration and development, price changes
and other factors.
As of December 31, 2012, all of the Company’s oil and gas reserves are attributable to properties within the
United States. A summary of the Company’s changes in quantities of proved oil and gas reserves for the
years ended December 31, 2010, 2011 and 2012 are as follows:
111
Oil
(MBbl)
NGLs
(MBbl)
Natural Gas
(MMcf)
Total
(MBOE)
Balance—January 1, 2010 ................................
Extensions and discoveries ................................
Sales of minerals in place ................................
Purchases of minerals in place ................................
Production................................................................
Revisions to previous estimates ................................
Balance—December 31, 2010 ................................
Extensions and discoveries ................................
Sales of minerals in place ................................
Purchases of minerals in place ................................
Production................................................................
Revisions to previous estimates ................................
Balance—December 31, 2011 ................................
Extensions and discoveries ................................
Sales of minerals in place ................................
Production................................................................
Revisions to previous estimates ................................
Balance—December 31, 2012 ................................
193,293
26,735
(221)
466
(17,466)
21,389
224,196
39,660
(579)
114
(18,299)
15,052
260,144
68,134
(7,960)
(23,139)
4,106
301,285
Proved developed reserves:
December 31, 2009 ................................
December 31, 2010 ................................
December 31, 2011 ................................
December 31, 2012 ................................
Proved undeveloped reserves:
December 31, 2009 ................................
December 31, 2010 ................................
December 31, 2011 ................................
December 31, 2012 ................................
129,104
160,088
180,975
190,845
64,189
64,108
79,169
110,440
30,503
2,699
(4)
39
(1,565)
(1,590)
30,082
5,024
(632)
58
(2,074)
5,151
37,609
6,526
(320)
(2,766)
(951)
40,098
15,709
18,321
22,109
24,204
14,794
11,761
15,500
15,894
307,393
23,135
(500)
1,526
(27,392)
(618)
303,544
23,211
(9,759)
1,639
(26,443)
(7,217)
284,975
40,915
(13,987)
(25,827)
(61,812)
224,264
178,782
220,530
211,297
160,893
128,611
83,014
73,678
63,371
275,029
33,290
(308)
759
(23,596)
19,695
304,869
48,552
(2,837)
445
(24,780)
19,000
345,249
81,479
(10,611)
(30,209)
(7,148)
378,760
174,610
215,164
238,300
241,864
100,419
89,705
106,949
136,896
Notable changes in proved reserves for the year ended December 31, 2012 included:
• Revisions to previous estimates. In 2012, revisions to previous estimates decreased proved
developed and undeveloped reserves by a net amount of 7.1 MMBOE. Included in these revisions
were (i) 11.8 MMBOE of downward adjustments caused by lower crude oil and natural gas prices
incorporated into the Company’s reserve estimates at December 31, 2012 as compared to
December 31, 2011, and (ii) 4.7 MMBOE of net upward adjustments attributable to reservoir
analysis and well performance.
• Extensions and discoveries. In 2012, total extensions and discoveries of 81.5 MMBOE were
primarily attributable to successful drilling in the Sanish field, Redtail prospect, Missouri Breaks
prospect and the Pronghorn area. The new producing wells in these fields and their related proved
undeveloped locations added during the year increased the Company’s proved reserves.
Notable changes in proved reserves for the year ended December 31, 2011 included:
• Revisions to previous estimates. In 2011, revisions to previous estimates increased proved
developed and undeveloped reserves by a net amount of 19.0 MMBOE. Included in these revisions
were (i) 4.7 MMBOE of upward adjustments caused by higher crude oil prices incorporated into
the Company’s reserve estimates at December 31, 2011 as compared to December 31, 2010, and
112
(ii) 14.3 MMBOE of net upward adjustments attributable to reservoir analysis and well
performance. The oil component of the net 14.3 MMBOE revision consisted of a 10.9 MMBOE
increase that was primarily related to the Postle and North Ward Estes fields, as discussed above,
where the performance of the CO2 injection EOR projects supported an increase in the proved
reserve assignments. The NGL component of the net 14.3 MMBOE revision consisted of a 4.8
MMBOE increase due to the performance of the Postle and North Ward Estes fields and various
properties in the Northern Rockies area, primarily in the Sanish field. The gas component of the
net 14.3 MMBOE revision consisted of a 1.4 MMBOE decrease that was primarily related to the
Flat Rock field where proved reserve assignments were reduced due to the production performance
of two recently completed wells.
• Extensions and discoveries. In 2011, total extensions and discoveries of 48.6 MMBOE were
primarily attributable to successful drilling in the Sanish field and Pronghorn area of the Lewis &
Clark prospect. The new producing wells in these fields and their related proved undeveloped
locations added during the year increased the Company’s proved reserves in these areas.
Notable changes in proved reserves for the year ended December 31, 2010 included:
• Revisions to previous estimates. In 2010, revisions to previous estimates increased proved
developed and undeveloped reserves by a net amount of 19.7 MMBOE. Included in these revisions
were (i) 15.4 MMBOE of upward adjustments caused by higher crude oil and natural gas prices
incorporated into the Company’s reserve estimates at December 31, 2010 as compared to
December 31, 2009, and (ii) 4.3 MMBOE of net upward adjustments attributable to reservoir
analysis and well performance. The oil component of the net 4.3 MMBOE revision consisted of a
10.1 MMBOE increase that was primarily related to the Sanish field, where reserve assignments
for proved developed producing as well as proved undeveloped well locations were adjusted
upward by 5.6 MMBOE to reflect the current performance of producing wells, and the Postle and
North Ward Estes fields, where recent performance of CO2 injection at those EOR projects
positively impacted their reserve assignments by 4.7 MMBOE. The NGL component of the net 4.3
MMBOE revision consisted of a decrease of 2.7 MMBOE primarily related to lower estimated
NGL volumes at the North Ward Estes field. The gas component of the net 4.3 MMBOE revision
consisted of a 3.1 MMBOE decrease that was primarily related to the Beall East field, where three
proved undeveloped locations were removed from our proved reserve estimate since those wells
are no longer planned to be drilled due to low gas prices.
• Extensions and discoveries. In 2010, total extensions and discoveries of 33.3 MMBOE were
primarily attributable to successful drilling in the Sanish field and related proved undeveloped well
locations added during the year, which in turn increased the Company’s proved reserves in the
Sanish area.
As discussed in Deferred Compensation within these footnotes to the consolidated financial statements, all
of the Company’s employees participate in the Company’s Production Participation Plan (“Plan”). The
reserve disclosures above include oil and natural gas reserve volumes that have been allocated to the Plan.
Once allocated to Plan participants, the interests are fixed. Allocations prior to 1995 consisted of 2%–3%
overriding royalty interest, while allocations since 1995 have been 2%–5% of oil and gas sales less lease
operating expenses and production taxes from the production allocated to the Plan.
The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and
the changes in standardized measure of discounted future net cash flows relating to proved oil and natural
gas reserves were prepared in accordance with the provisions of FASB ASC Topic 932, Extractive
Activities—Oil and Gas. Future cash inflows as of December 31, 2012, 2011 and 2010 were computed by
applying 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, 2012, 2011 and 2010,
113
respectively) to estimated future production. Future production and development costs are computed by
estimating the expenditures to be incurred in developing and producing the proved oil and natural gas
reserves at year end, based on year-end costs and assuming the continuation of existing economic
conditions.
Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net
cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future
income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the
proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to
derive the standardized measure of discounted future net cash flows. This calculation does not necessarily
result in an estimate of the fair value of the Company’s oil and gas properties.
The standardized measure of discounted future net cash flows relating to proved oil and natural gas
reserves is as follows (in thousands):
Future cash flows............................................................
Future production costs ..................................................
Future development costs ...............................................
Future income tax expense .............................................
Future net cash flows ......................................................
10% annual discount for estimated timing of cash
flows ..........................................................................
Standardized measure of discounted future net cash
flows ..........................................................................
2012
$ 29,308,752
(11,397,332)
(3,181,618)
(4,278,529)
10,451,273
December 31,
2011
$ 26,815,086
(8,908,131)
(1,982,813)
(4,875,973)
11,048,169
2010
$ 19,314,032
(7,705,465)
(1,491,937)
(2,890,668)
7,225,962
(5,044,240)
(5,775,677)
(3,558,356)
$ 5,407,033
$ 5,272,492
$ 3,667,606
Future cash flows as shown above are reported without consideration for the effects of open hedge
contracts at each period end. If the effects of hedging transactions were included in the computation, then
undiscounted future cash inflows would have decreased by $20.2 million in 2012, decreased by $50.7
million in 2011 and decreased by $12.6 million in 2010.
The changes in the standardized measure of discounted future net cash flows relating to proved oil and
natural gas reserves are as follows (in thousands):
Beginning of year ...........................................................
Sale of oil and gas produced, net of production costs ....
Sales of minerals in place ...............................................
Net changes in prices and production costs ....................
Extensions, discoveries and improved recoveries ..........
Previously estimated development costs incurred
during the period .........................................................
Changes in estimated future development costs .............
Purchases of mineral in place .........................................
Revisions of previous quantity estimates .......................
Net change in income taxes ............................................
Accretion of discount .....................................................
End of year .....................................................................
2012
$ 5,272,492
(1,589,665)
(438,614)
(1,061,495)
3,708,780
526,982
(1,498,592)
-
(295,432)
255,328
527,249
$ 5,407,033
December 31,
2011
$ 3,667,606
(1,415,469)
(67,600)
2,246,014
1,156,740
408,079
(797,542)
10,604
452,668
(755,369)
366,761
$ 5,272,492
2010
$ 2,343,542
(1,103,060)
(5,927)
1,881,636
639,924
405,499
(434,549)
14,597
378,552
(686,962)
234,354
$ 3,667,606
114
Future net revenues included in the standardized measure of discounted future net cash flows relating to
proved oil and natural gas reserves incorporate calculated weighted average sales prices (inclusive of
adjustments for quality and location) in effect at December 31, 2012, 2011 and 2010 as follows:
Oil (per Bbl) ......................................................................
NGLs (per Bbl) ................................................................
Natural Gas (per Mcf) .......................................................
2012
$ 87.15
$ 58.15
3.21
$
2011
$ 89.18
$ 62.93
4.39
$
2010
$ 73.14
$ 49.35
4.72
$
16.
QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of the unaudited quarterly financial data for the years ended December 31,
2012 and 2011 (in thousands, except per share data):
Three Months Ended
Year ended December 31, 2012:
Oil, NGL and natural gas sales ................... $
Operating profit (1) ...................................... $
Net income ................................................. $
Basic earnings per share ............................. $
Diluted earnings per share .......................... $
March 31,
2012
558,697
263,176
98,446
0.84
0.83
June 30,
2012
492,756
201,900
150,851
1.28
1.27
$
$
$
$
$
September 30,
2012
521,195
204,230
83,113
0.70
0.70
$
$
$
$
$
December 31,
2012
565,066
235,635
81,689
0.69
0.69
$
$
$
$
$
Three Months Ended
Year ended December 31, 2011:
Oil, NGL and natural gas sales ................... $
Operating profit (1) ...................................... $
Net income ................................................. $
Basic earnings per share ............................. $
Diluted earnings per share .......................... $
_____________________
(1) Oil, NGL and natural gas sales less lease operating expense, production taxes and depreciation, depletion and
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
September 30,
2011
468,573
233,543
206,235
1.75
1.74
December 31,
2011
492,025
243,362
62,830
0.54
0.53
March 31,
2011
425,683
214,789
19,414
0.16
0.16
June 30,
2011
473,865
255,572
203,149
1.73
1.71
amortization.
******
115
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of disclosure controls and procedures. In accordance with Rule 13a-15(b) of the Securities
Exchange Act of 1934 (the “Exchange Act”), our management evaluated, with the participation of our Chairman
and Chief Executive Officer and our Chief Financial Officer, the effectiveness of the design and operation of our
disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of the end of the year
ended December 31, 2012. Based upon their evaluation of these disclosures controls and procedures, the Chairman
and Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures
were effective as of the end of the year ended December 31, 2012 to ensure that information required to be
disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized
and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission,
and to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange
Act is accumulated and communicated to our management, including our principal executive and principal financial
officers, as appropriate, to allow timely decisions regarding required disclosure.
Management’s Annual Report on Internal Control Over Financial Reporting. The management of
Whiting Petroleum Corporation and subsidiaries is responsible for establishing and maintaining adequate internal
control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities
Exchange Act of 1934. Our internal control over financial reporting is designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles.
Because of the inherent limitations of internal control over financial reporting, misstatements may not be
prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal
control over financial reporting to future periods are subject to the risk that the controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our management assessed the effectiveness of our internal control over financial reporting as of
December 31, 2012 using the criteria set forth in Internal Control - Integrated Framework issued by the Committee
of Sponsoring Organizations of the Treadway Commission. Based on this assessment, our management believes
that, as of December 31, 2012, our internal control over financial reporting was effective based on those criteria.
The effectiveness of our internal control over financial reporting as of December 31, 2012 has been audited
by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is
included herein on the following page.
Changes in internal control over financial reporting. There was no change in our internal control over
financial reporting that occurred during the quarter ended December 31, 2012 that has materially affected, or is
reasonably likely to materially affect, our internal control over financial reporting.
116
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Whiting Petroleum Corporation
Denver, Colorado
We have audited the internal control over financial reporting of Whiting Petroleum Corporation and subsidiaries
(the "Company") as of December 31, 2012, based on criteria established in Internal Control — Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's
management is responsible for maintaining effective internal control over financial reporting and for its assessment
of the effectiveness of internal control over financial reporting, included in the accompanying Management’s
Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the
Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether effective internal control over financial reporting was maintained in all material respects. Our audit
included obtaining an understanding of internal control over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the
assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the
company's principal executive and principal financial officers, or persons performing similar functions, and effected
by the company's board of directors, management, and other personnel to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance with generally
accepted accounting principles, and that receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets
that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion
or improper management override of controls, material misstatements due to error or fraud may not be prevented or
detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over
financial reporting to future periods are subject to the risk that the controls may become inadequate because of
changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting
as of December 31, 2012, based on the criteria established in Internal Control — Integrated Framework issued by
the Committee of Sponsoring Organizations of the Treadway Commission.
117
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States), the consolidated financial statements and financial statement schedule as of and for the year ended
December 31, 2012 of the Company and our report dated February 28, 2013 expressed an unqualified opinion on
those financial statements and financial statement schedule.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 28, 2013
Item 9B. Other Information
None.
Item 10. Directors, Executive Officers and Corporate Governance
PART III
The information included under the captions “Election of Directors,” “Board of Directors and Corporate
Governance” and “Section 16(a) Beneficial Ownership Reporting Compliance” in our definitive Proxy Statement
for Whiting Petroleum Corporation’s 2013 Annual Meeting of Stockholders (the “Proxy Statement”) is hereby
incorporated herein by reference. Information with respect to our executive officers appears in Part I of this Annual
Report on Form 10-K.
We have adopted the Whiting Petroleum Corporation Code of Business Conduct and Ethics that applies to
our directors, our Chairman and Chief Executive Officer, our Chief Financial Officer, our Controller and Treasurer
and other persons performing similar functions. We have posted a copy of the Whiting Petroleum Corporation
Code of Business Conduct and Ethics on our website at www.whiting.com. The Whiting Petroleum Corporation
Code of Business Conduct and Ethics is also available in print to any stockholder who requests it in writing from
the Corporate Secretary of Whiting Petroleum Corporation. We intend to satisfy the disclosure requirements under
Item 5.05 of Form 8-K regarding amendments to, or waivers from, the Whiting Petroleum Corporation Code of
Business Conduct and Ethics by posting such information on our website at www.whiting.com.
We are not including the information contained on our website as part of, or incorporating it by reference
into, this report.
Item 11. Executive Compensation
The information required by this Item is included under the captions “Board of Directors and Corporate
Governance – Compensation Committee Interlocks and Insider Participation,” “Board of Directors and Corporate
Governance – Director Compensation,” “Compensation Discussion and Analysis,” “Compensation Committee
Report” and “Executive Compensation” in the Proxy Statement and is hereby incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
The information required by this Item with respect to security ownership of certain beneficial owners and
management is included under the caption “Principal Stockholders” in the Proxy Statement and is hereby
incorporated by reference. The following table sets forth information with respect to compensation plans under
which equity securities of Whiting Petroleum Corporation are authorized for issuance as of December 31, 2012.
118
Equity Compensation Plan Information
Plan Category
Equity compensation plans
approved by security holders(1) ......
Equity compensation plans not
approved by security holders .........
Total ............................................
Number of securities to be
issued upon exercise of
outstanding options,
warrants and rights
Weighted-average
exercise price of
outstanding options,
warrants and rights
Number of securities remaining
available for future issuance
under equity compensation
plans (excluding securities
reflected in the first column)
422,695
-
422,695
$
$
28.79
N/A
28.79
1,178,071 (2)
-
1,178,071 (2)
_____________________
(1)
(2) Number of securities reduced by 422,695 stock options outstanding and 951,026 shares of restricted common stock previously issued
Includes only the Whiting Petroleum Corporation 2003 Equity Incentive Plan.
for which the restrictions have not lapsed.
Item 13. Certain Relationships, Related Transactions and Director Independence
The information required by this Item is included under the caption “Board of Directors and Corporate
Governance – Transactions with Related Persons” and “Board of Directors and Corporate Governance –
Independence of Directors” in the Proxy Statement and is hereby incorporated by reference.
Item 14. Principal Accounting Fees and Services
The information required by this Item is included under the caption “Ratification of Appointment of
Independent Registered Public Accounting Firm” in the Proxy Statement and is hereby incorporated by reference.
Item 15. Exhibits, Financial Statement Schedules
PART IV
(a)
1.
Financial statements – Refer to the Index to Consolidated Financial Statements included in Item 8
of this Form 10-K for a list of all financial statements filed as part of this report.
2.
Financial statement schedules – The following financial statement schedule is filed as part of this
Annual Report on Form 10-K:
a.
Schedule I – Condensed Financial Information of Registrant
All other schedules are omitted since the required information is not present, or is not present in
amounts sufficient to require submission of the schedule, or because the information required is
included in the consolidated financial statements or the notes thereto.
3.
Exhibits – The exhibits listed in the accompanying index to exhibits are filed as part of this Annual
Report on Form 10-K.
(b)
Exhibits
The exhibits listed in the accompanying exhibit index are filed (except where otherwise indicated) as part
of this report.
(c)
Financial Statement Schedules
119
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
WHITING PETROLEUM CORPORATION
CONDENSED FINANCIAL STATEMENTS OF THE PARENT COMPANY
CONDENSED BALANCE SHEETS
(In thousands)
December 31,
2012
2011
ASSETS
Current assets ............................................................................................................................ $
Investment in subsidiaries .........................................................................................................
Intercompany receivable ...........................................................................................................
2,390
2,330,987
1,748,463
Total assets............................................................................................................................ $ 4,081,840
LIABILITIES AND EQUITY
Current liabilities ....................................................................................................................... $
Long-term debt ..........................................................................................................................
Other long-term liabilities .........................................................................................................
Shareholders’ equity ..................................................................................................................
14,372
600,000
21,244
3,446,224
Total liabilities and equity ................................................................................................................
$ 4,081,840
$
1,986
1,910,944
1,733,629
$ 3,646,559
$
4,482
600,000
21,460
3,020,617
$ 3,646,559
CONDENSED STATEMENTS OF OPERATIONS
(In thousands)
Year Ended December 31,
2011
2010
2012
Operating expenses:
General and administrative ..................................................................... $
(16,506)
$
(12,024)
$
(7,835)
Interest expense ......................................................................................
Equity in earnings of subsidiaries ...........................................................
Income before income taxes ..........................................................................
Income tax benefit ..................................................................................
Net income .................................................................................................... $
(2,168)
425,870
407,196
6,993
414,189
(2,066)
500,564
486,474
5,213
491,687
(1,844)
342,671
332,992
3,661
336,653
$
$
See notes to condensed financial statements.
120
WHITING PETROLEUM CORPORATION
CONDENSED FINANCIAL STATEMENTS OF THE PARENT COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(In thousands)
Schedule I
Cash flows provided by operating activities ................................................ $
Year Ended December 31,
2011
2010
$
4,962
$
1,108
2012
16,423
Cash flows from investing activities:
Investment in subsidiaries ........................................................................
-
-
-
Cash flows from financing activities:
Intercompany receivable ..........................................................................
Other financing activities .........................................................................
Net cash used in financing activities .............................................
(14,094)
(2,329)
(16,423)
(3,091)
(1,871)
(4,962)
507
(1,615)
(1,108)
Net change in cash and cash equivalents .....................................................
Cash and cash equivalents:
Beginning of period ..................................................................................
End of period ............................................................................................ $
-
-
-
$
-
-
-
$
-
-
-
NONCASH INVESTING ACTIVITIES:
Distributions from Whiting USA Trust I decreasing investment in
subsidiaries .......................................................................................... $
(5,827)
$
(6,500)
$
(5,937)
See notes to condensed financial statements.
(Continued)
121
WHITING PETROLEUM CORPORATION
CONDENSED FINANCIAL STATEMENTS OF THE PARENT COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(In thousands)
Schedule I
Year Ended December 31,
2011
2012
2010
NONCASH FINANCING ACTIVITIES:
Issuance of 6.50% Senior Subordinated Notes due 2018 increasing
long-term debt ..................................................................................... $
Issuance of 6.50% Senior Subordinated Notes due 2018 increasing
intercompany receivable ..................................................................... $
Redemption of 7.25% Senior Subordinated Notes due 2012
decreasing long-term debt ................................................................... $
Redemption of 7.25% Senior Subordinated Notes due 2012
decreasing intercompany receivable ................................................... $
Redemption of 7.25% Senior Subordinated Notes due 2013
decreasing long-term debt ................................................................... $
Redemption of 7.25% Senior Subordinated Notes due 2013
decreasing intercompany receivable ................................................... $
Issuance of common stock related to the induced conversion of
preferred stock increasing shareholders’ equity .................................. $
Issuance of common stock related to the induced conversion of
preferred stock increasing intercompany receivable ........................... $
Preferred stock cancelled in connection with its induced conversion
decreasing shareholders’ equity .......................................................... $
Preferred stock cancelled in connection with its induced conversion
decreasing intercompany receivable ................................................... $
Preferred stock dividends paid decreasing shareholders’ equity .............. $
Preferred stock dividends paid decreasing intercompany receivable ....... $
Premium on induced conversion of 6.25% convertible perpetual
preferred stock decreasing shareholders’ equity ................................. $
Premium on induced conversion of 6.25% convertible perpetual
preferred stock decreasing intercompany receivable .......................... $
Distributions from Whiting USA Trust I increasing intercompany
-
-
-
-
-
-
-
-
-
-
(1,077)
(1,077)
-
-
receivable ............................................................................................ $
5,827
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
-
-
-
-
-
-
-
-
-
-
(1,077)
(1,077)
-
-
6,500
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
350,000
350,000
(150,000)
(150,000)
(223,988)
(223,988)
317,406
317,406
(317,406)
(317,406)
(16,441)
(16,441)
(47,529)
(47,529)
5,937
See notes to condensed financial statements.
(Concluded)
122
WHITING PETROLEUM CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS OF THE PARENT COMPANY
1.
BASIS OF PRESENTATION
Condensed Financial Statements—The condensed financial statements of Whiting Petroleum Corporation
(the “Registrant” or “Parent Company”) do not include all of the information and notes normally included
with financial statements prepared in accordance with GAAP. These condensed financial statements,
therefore, should be read in conjunction with the consolidated financial statements and notes thereto of the
Registrant, included elsewhere in this Annual Report on Form 10-K. For purposes of these condensed
financial statements, the Parent Company’s investments in wholly-owned subsidiaries are accounted for
under the equity method.
Restricted Assets of Registrant—Except for limited exceptions, including the payment of interest on the
senior notes and the payment of dividends on the 6.25% convertible perpetual preferred stock, Whiting Oil
and Gas Corporation’s (“Whiting Oil and Gas”) credit agreement restricts the ability of Whiting Oil and
Gas to make any dividend payments, distributions or other payments to the Parent Company. As of
December 31, 2012, total restricted net assets were $3,477.4 million. Accordingly, these condensed
financial statements have been prepared pursuant to Rule 5-04 of Regulation S-X of the Securities
Exchange Act of 1934, as amended.
2.
LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES
The Parent Company’s long-term debt and other long-term liabilities consisted of the following at
December 31, 2012 and 2011 (in thousands):
December 31,
2012
2011
Long-term debt:
6.5% Senior Subordinated Notes due 2018 .................................................$
7% Senior Subordinated Notes due 2014 ....................................................
Other long-term liabilities:
Tax sharing liability .....................................................................................
Other ............................................................................................................
Total long-term debt and other long-term liabilities ...........................................$
350,000
250,000
21,074
170
621,244
$
$
350,000
250,000
21,161
299
621,460
Scheduled maturities of the Parent Company’s long-term debt and other long-term liabilities (including the
current portions thereof) as of December 31, 2012 were as follows (in thousands):
2013
2014
2015
2016
2017
Thereafter
Total
Amounts due ...... $
1,452
$ 271,074
$
-
$
-
$
-
$
350,000
$ 622,526
For further information on the Senior Subordinated Notes and tax sharing liability, refer to the Long-Term
Debt and Related Party Transactions notes to the consolidated financial statements of the Registrant.
3.
SHAREHOLDERS’ EQUITY
Common Stock—In May 2011, the Registrant’s stockholders approved an amendment to its Restated
Certificate of Incorporation to increase the number of authorized shares of common stock from
175,000,000 shares to 300,000,000 shares.
123
Stock Split. On January 26, 2011, the Board of Directors approved a two-for-one split of the Registrant's
shares of common stock to be effected in the form of a stock dividend. As a result of the stock split,
stockholders of record on February 7, 2011 received one additional share of common stock for each share
of common stock held. The additional shares of common stock were distributed on February 22, 2011. All
common share and per share amounts in these notes to the condensed financial statements for periods prior
to February 2011 have been retroactively adjusted to reflect the stock split. The common stock dividend
resulted in the conversion price for Parent Company’s 6.25% Convertible Perpetual Preferred Stock being
adjusted from $43.4163 to $21.70815.
6.25% Convertible Perpetual Preferred Stock—In June 2009, the Parent Company completed a public
offering of 6.25% convertible perpetual preferred stock (“preferred stock”), selling 3,450,000 shares at a
price of $100.00 per share. As of December 31, 2012, however, only 172,391 shares of preferred stock
remained outstanding.
Induced Conversion of 6.25% Convertible Perpetual Preferred Stock. In August 2010, the Registrant
commenced an offer to exchange up to 3,277,500, or 95%, of its preferred stock for the following
consideration per share of preferred stock: 4.6066 shares of its common stock and a cash premium of
$14.50. The exchange offer expired in September 2010 and resulted in the Parent Company accepting
3,277,500 shares of preferred stock in exchange for the issuance of 15,098,020 shares of common stock and
a cash premium payment of $47.5 million. Following the exchange offer, the 3,277,500 shares of preferred
stock accepted in the exchange were cancelled, and a total of 172,500 shares of preferred stock remained
outstanding.
For further information on the common stock and convertible perpetual preferred stock, refer to the
Shareholders’ Equity note to the consolidated financial statements of the Registrant.
4.
SUBSEQUENT EVENTS
On February 15, 2013, the Parent Company declared a dividend of $1.5625 per share on its 6.25%
convertible perpetual preferred stock. The total dividend amounting to $0.3 million is payable on March
15, 2013 to holders of record on March 1, 2013.
******
124
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant
has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on
this 28th day of February, 2013.
SIGNATURES
WHITING PETROLEUM CORPORATION
By /s/ James J. Volker
James J. Volker
Chairman and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by
the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ James J. Volker
James J. Volker
/s/ Michael J. Stevens
Michael J. Stevens
/s/ Brent P. Jensen
Brent P. Jensen
/s/ Thomas L. Aller
Thomas L. Aller
/s/ D. Sherwin Artus
D. Sherwin Artus
/s/ Thomas P. Briggs
Thomas P. Briggs
/s/ Philip E. Doty
Philip E. Doty
/s/ William N. Hahne
William N. Hahne
/s/ Allan R. Larson
Allan R. Larson
February 28, 2013
February 28, 2013
February 28, 2013
February 28, 2013
February 28, 2013
February 28, 2013
February 28, 2013
February 28, 2013
February 28, 2013
Chairman and Chief
Executive Officer and Director
(Principal Executive Officer)
Vice President and
Chief Financial Officer
(Principal Financial Officer)
Controller and Treasurer
(Principal Accounting Officer)
Director
Director
Director
Director
Director
Director
125
Exhibit
Number
(3.1)
(3.2)
(4.1)
(4.2)
(4.3)
(4.4)
(4.5)
(4.6)
(4.7)
(4.8)
EXHIBIT INDEX
Exhibit Description
Restated Certificate of Incorporation of Whiting Petroleum Corporation [Incorporated by
reference to Exhibit 3.2 to Whiting Petroleum Corporation’s Quarterly Report on Form 10-
Q for the quarter ended June 30, 2011 (File No. 001-31899)].
Amended and Restated By-laws of Whiting Petroleum Corporation, effective February 17,
2011 [Incorporated by reference to Exhibit 3.2 to Whiting Petroleum Corporation’s
Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 001-
31899)].
Fifth Amended and Restated Credit Agreement, dated as of October 15, 2010, among
Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, the lenders party
thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the various other
agents party thereto [Incorporated by reference to Exhibit 4 to Whiting Petroleum
Corporation’s Current Report on Form 8-K dated October 15, 2010 (File No. 001-31899)].
First Amendment to Fifth Amended and Restated Credit Agreement, dated as of April 15,
2011, among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation,
JPMorgan Chase Bank, N.A., as Administrative Agent, the various other agents party
thereto and the lenders party thereto [Incorporated by reference to Exhibit 4.1 to Whiting
Petroleum Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31,
2011 (File No. 001-31899)].
Second Amendment to Fifth Amended and Restated Credit Agreement, dated as of
October 12, 2011, among Whiting Petroleum Corporation, Whiting Oil and Gas
Corporation, JPMorgan Chase Bank, N.A., as Administrative Agent, the various other
agents party thereto and the lenders party thereto [Incorporated by reference to Exhibit 4 to
Whiting Petroleum Corporation’s Current Report on Form 8-K dated October 12, 2011
(File No. 001-31899)].
Third Amendment to Fifth Amended and Restated Credit Agreement, dated as of October
19, 2012, among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation,
JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto
[Incorporated by reference to Exhibit 4 to Whiting Petroleum Corporation’s Current
Report on Form 8-K dated October 19, 2012 (File No. 001-31899)].
Subordinated Indenture, dated as of April 19, 2005, by and among Whiting Petroleum
Corporation, Whiting Oil and Gas Corporation, Whiting Programs, Inc., Equity Oil
Company and The Bank of New York Trust Company, N.A., as successor trustee
[Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Current
Report on Form 8-K dated September 21, 2010 (File No. 001-31899)].
Second Supplemental Indenture, dated September 24, 2010, among Whiting Petroleum
Corporation, Whiting Oil and Gas Corporation and The Bank of New York Mellon Trust
Company, N.A., as Trustee, creating the 6.5% Senior Subordinated Notes due 2018
[Incorporated by reference to Exhibit 4.2 to Whiting Petroleum Corporation’s Current
Report on Form 8-K dated September 21, 2010 (File No. 001-31899)].
Indenture, dated October 4, 2005, by and among Whiting Petroleum Corporation, Whiting
Oil and Gas Corporation, Whiting Programs, Inc. and The Bank of New York Trust
Company, N.A., as successor trustee [Incorporated by reference to Exhibit 4.1 to Whiting
Petroleum Corporation’s Current Report on Form 8-K dated October 4, 2005 (File No.
001-31899)].
Rights Agreement, dated as of February 23, 2006, between Whiting Petroleum
Corporation and Computershare Trust Company, Inc. [Incorporated by reference to Exhibit
4.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated February 23,
2006 (File No. 001-31899)].
126
Exhibit
Number
(10.1)*
(10.2)*
(10.3)*
(10.4)*
(10.5)*
(10.6)*
(10.7)*
(10.8)
(10.9)*
(10.10)*
(10.11)*
(10.12)*
(10.13)*
Exhibit Description
Whiting Petroleum Corporation 2003 Equity Incentive Plan, as amended through October
23, 2007 [Incorporated by reference to Exhibit 10.2 to Whiting Petroleum Corporation’s
Current Report on Form 8-K dated October 23, 2007 (File No. 001-31899)].
Form of Restricted Stock Agreement pursuant to the Whiting Petroleum Corporation 2003
Equity Incentive Plan for time-based vesting awards prior to October 23, 2007
[Incorporated by reference to Exhibit 10.1 to Whiting Petroleum Corporation’s Quarterly
Report on Form 10-Q for the quarter ended September 30, 2004 (File No. 001-31899)].
Form of Restricted Stock Agreement pursuant to the Whiting Petroleum Corporation 2003
Equity Incentive Plan for performance vesting awards prior to October 23, 2007
[Incorporated by reference to Exhibit 10.1 to Whiting Petroleum Corporation’s Quarterly
Report on Form 10-Q for the quarter ended March 31, 2007 (File No. 001-31899)].
Form of Restricted Stock Agreement pursuant to the Whiting Petroleum Corporation 2003
Equity Incentive Plan for performance vesting awards on and after October 23, 2007 and
prior to February 23, 2008 [Incorporated by reference to Exhibit 10.3 to Whiting
Petroleum Corporation’s Current Report on Form 8-K dated October 23, 2007 (File No.
001-31899)].
Form of Restricted Stock Agreement pursuant to the Whiting Petroleum Corporation 2003
Equity Incentive Plan for time-based vesting awards on and after October 23, 2007
[Incorporated by reference to Exhibit 10.4 to Whiting Petroleum Corporation’s Current
Report on Form 8-K dated October 23, 2007 (File No. 001-31899)].
Form of Restricted Stock Agreement pursuant to the Whiting Petroleum Corporation 2003
Equity Incentive Plan for performance vesting awards on and after February 23, 2008
[Incorporated by reference to Exhibit 10.1 to Whiting Petroleum Corporation’s Quarterly
Report on Form 10-Q for the quarter ended March 31, 2008 (File No. 001-31899)].
Whiting Petroleum Corporation Production Participation Plan, as amended and restated
February 4, 2008 [Incorporated by reference to Exhibit 10.6 to Whiting Petroleum
Corporation’s Annual Report on Form 10-K for the year ended December 31, 2007 (File
No. 001-31899)].
Tax Separation and Indemnification Agreement between Alliant Energy Corporation,
Whiting Petroleum Corporation and Whiting Oil and Gas Corporation [Incorporated by
reference to Exhibit 10.3 to Whiting Petroleum Corporation’s Registration Statement on
Form S-1 (Registration No. 333-107341)].
Summary of Non-Employee Director Compensation for Whiting Petroleum Corporation.
Production Participation Plan Credit Service Agreement, dated February 23, 2007,
between Whiting Petroleum Corporation and James J. Volker [Incorporated by reference to
Exhibit 10.7 to Whiting Petroleum Corporation’s Annual Report on Form 10-K for the
year ended December 31, 2006 (File No. 001-31899)].
Amended and Restated Production Participation Plan Supplemental Payment Agreement,
dated January 14, 2008, between Whiting Petroleum Corporation and J. Douglas Lang
[Incorporated by reference to Exhibit 10.6 to Whiting Petroleum Corporation’s Annual
Report on Form 10-K for the year ended December 31, 2007 (File No. 001-31899)].
Form of Indemnification Agreement for directors and executive officers of Whiting
Petroleum Corporation [Incorporated by reference to Exhibit 10.10 to Whiting Petroleum
Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008
(File No. 001-31899)].
Form of Executive Excise Tax Gross-Up Agreement for executive officers of Whiting
Petroleum Corporation [Incorporated by reference to Exhibit 10.1 to Whiting Petroleum
Corporation’s Current Report on Form 8-K dated January 13, 2009 (File No. 001-31899)].
127
Exhibit
Number
(10.14)*
(21)
(23.1)
(23.2)
(31.1)
(31.2)
(32.1)
(32.2)
(99.1)
(99.2)
(101)
Exhibit Description
Form of Stock Option Agreement pursuant to the Whiting Petroleum Corporation 2003
Equity Incentive Plan [Incorporated by reference to Exhibit 10.14 to Whiting Petroleum
Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008 (File
No. 001-31899)].
Subsidiaries of Whiting Petroleum Corporation.
Consent of Deloitte & Touche LLP.
Consent of Cawley, Gillespie & Associates, Inc., Independent Petroleum Engineers.
Certification by the Chairman and Chief Executive Officer pursuant to Section 302 of the
Sarbanes-Oxley Act.
Certification by the Vice President and Chief Financial Officer pursuant to Section 302 of
the Sarbanes-Oxley Act.
Written Statement of the Chairman and Chief Executive Officer pursuant to 18 U.S.C.
Section 1350.
Written Statement of the Vice President and Chief Financial Officer pursuant to 18 U.S.C.
Section 1350.
Proxy Statement for the 2013 Annual Meeting of Stockholders, to be filed within 120 days
of December 31, 2012 [To be filed with the Securities and Exchange Commission under
Regulation 14A within 120 days after December 31, 2012; except to the extent specifically
incorporated by reference, the Proxy Statement for the 2013 Annual Meeting of
Stockholders shall not be deemed to be filed with the Securities and Exchange
Commission as part of this Annual Report on Form 10-K].
Report of Cawley, Gillespie & Associates, Inc., Independent Petroleum Engineers relating
to Total Proved Reserves and Report of Cawley, Gillespie & Associates, Inc. relating to
Probable and Possible Reserves, each dated January 11, 2013.
The following materials from Whiting Petroleum Corporation’s Annual Report on Form
10-K for the year ended December 31, 2012 are filed herewith, formatted in XBRL
(Extensible Business Reporting Language): (i) the Consolidated Balance Sheets as of
December 31, 2012 and 2011, (ii) the Consolidated Statements of Income for the Years
Ended December 31, 2012, 2011 and 2010, (iii) the Consolidated Statements of
Comprehensive Income for the Years Ended December 31, 2012, 2011 and 2010, (iv) the
Consolidated Statements of Cash Flow for the Years Ended December 31, 2012, 2011 and
2010, (v) the Consolidated Statements of Equity for the Years Ended December 31, 2012,
2011 and 2010 and (vi) Notes to Consolidated Financial Statements.
*
A management contract or compensatory plan or arrangement.
128
Director Compensation
Effective June 1, 2012, non-employee director compensation is as follows:
Exhibit 10.9
Board
Service
Annual retainer ....................................................... $
45,000
Restricted stock (value), one year vesting .............. $ 150,000
Committee chair annual retainer .............................
Committee chair restricted stock (value) ................
Committee member annual retainer ........................
Meeting fee ............................................................. $
1,500
Committee Service
Nominating
and
Governance
Audit Compensation
$ 25,000
$ 25,000
7,500
$
1,500
$
$
$
$
$
15,000
15,000
5,000
1,500
$ 15,000
$ 15,000
5,000
$
1,500
$
SUBSIDIARIES OF WHITING PETROLEUM CORPORATION
Name
Whiting Oil and Gas Corporation
Jurisdiction of
Incorporation or
Organization
Delaware
Percent
Ownership
100%
Exhibit 21
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement No. 333-111056 on Form S-8,
Registration Statement No. 333-121614 on Form S-4, and Registration Statement No. 333-183729 on Form S-3 of
our reports dated February 28, 2013, relating to the financial statements and financial statement schedule of
Whiting Petroleum Corporation, and the effectiveness of Whiting Petroleum Corporation’s internal control over
financial reporting, appearing in this Annual Report on Form 10-K of Whiting Petroleum Corporation for the year
ended December 31, 2012.
Exhibit 23.1
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 28, 2013
Cawley, Gillespie & Associates, Inc.
P E T R O L E U M C O N S U L T A N T S
1 0 0 0 L O U I S I A N A S T R E E T , S U I T E 6 2 5
H O U S T O N , T E X A S 7 7 0 0 2 - 5 0 0 8
7 1 3 - 6 5 1 - 9 9 4 4
F A X 7 1 3 - 6 5 1 - 9 9 8 0
3 0 6 W E S T S E V E N T H S T R E E T , S U I T E 3 0 2
F O R T W O R T H , T E X A S 7 6 1 0 2 - 4 9 8 7
8 1 7 - 3 3 6 - 2 4 6 1
F A X 8 1 7 - 8 7 7 - 3 7 2 8
9 6 0 1 A M B E R G L E N B L V D . , S U I T E 1 1 7
A U S T I N , T E X A S 7 8 7 2 9 - 1 1 0 6
5 1 2 - 2 4 9 - 7 0 0 0
F A X 5 1 2 - 2 3 3 - 2 6 1 8
Exhibit 23.2
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
The undersigned hereby consents to the references to our firm in the form and context in which they appear
in the Annual Report on Form 10-K of Whiting Petroleum Corporation for the year ended December 31, 2012. We
hereby further consent to the use of information contained in our reports setting forth the estimates of revenues
from Whiting Petroleum Corporation’s oil and gas reserves as of December 31, 2012, 2011 and 2010 and to the
inclusion of our reports dated January 11, 2013 as an exhibit to the Annual Report on Form 10-K of Whiting
Petroleum Corporation for the year ended December 31, 2012. We further consent to the incorporation by
reference thereof into Whiting Petroleum Corporation’s Registration Statements on Form S-8 (Registration No.
333-111056), Form S-4 (Registration No. 333-121614) and Form S-3 (Registration No. 333-183729).
Sincerely,
/s/ Cawley, Gillespie & Associates, Inc.
Cawley, Gillespie & Associates, Inc.
Texas Registered Engineering Firm F-693
February 28, 2013
Exhibit 31.1
I, James J. Volker, certify that:
CERTIFICATIONS
1.
2.
3.
4.
I have reviewed this Annual Report on Form 10-K of Whiting Petroleum Corporation;
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state
a material fact necessary to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this report;
Based on my knowledge, the financial statements and other financial information included in this report,
fairly present in all material respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this report;
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
b)
c)
d)
Designed such disclosure controls and procedures, or caused such disclosure controls and
procedures to be designed under our supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
Designed such internal control over financial reporting, or caused such internal control over
financial reporting to be designed under our supervision, to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in
this report our conclusions about the effectiveness of the disclosure controls and procedures, as of
the end of the period covered by this report based on such evaluation; and
Disclosed in this report any change in the registrant’s internal control over financial reporting that
occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in
the case of an annual report) that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of
internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s
board of directors (or persons performing the equivalent functions):
a)
b)
All significant deficiencies and material weaknesses in the design or operation of internal control
over financial reporting which are reasonably likely to adversely affect the registrant’s ability to
record, process, summarize and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant’s internal control over financial reporting.
Date: February 28, 2013
/s/ James J. Volker
James J. Volker
Chairman and Chief Executive Officer
Exhibit 31.2
I, Michael J. Stevens, certify that:
CERTIFICATIONS
1.
2.
3.
4.
I have reviewed this Annual Report on Form 10-K of Whiting Petroleum Corporation;
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state
a material fact necessary to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this report;
Based on my knowledge, the financial statements and other financial information included in this report,
fairly present in all material respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this report;
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
b)
c)
d)
Designed such disclosure controls and procedures, or caused such disclosure controls and
procedures to be designed under our supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
Designed such internal control over financial reporting, or caused such internal control over
financial reporting to be designed under our supervision, to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in
this report our conclusions about the effectiveness of the disclosure controls and procedures, as of
the end of the period covered by this report based on such evaluation; and
Disclosed in this report any change in the registrant’s internal control over financial reporting that
occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in
the case of an annual report) that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of
internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s
board of directors (or persons performing the equivalent functions):
a)
b)
All significant deficiencies and material weaknesses in the design or operation of internal control
over financial reporting which are reasonably likely to adversely affect the registrant’s ability to
record, process, summarize and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant’s internal control over financial reporting.
Date: February 28, 2013
/s/ Michael J. Stevens
Michael J. Stevens
Vice President and Chief Financial Officer
Written Statement of the Chief Executive Officer
Pursuant to 18 U.S.C. Section 1350
Exhibit 32.1
Solely for the purposes of complying with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002, I, the undersigned Chairman and Chief Executive Officer of Whiting Petroleum
Corporation, a Delaware corporation (the “Company”), hereby certify, based on my knowledge, that the Annual
Report on Form 10-K of the Company for the fiscal year ended December 31, 2012 (the “Report”) fully complies
with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and that information contained in the
Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
/s/ James J. Volker
James J. Volker
Chairman and Chief Executive Officer
Date: February 28, 2013
Written Statement of the Chief Financial Officer
Pursuant to 18 U.S.C. Section 1350
Exhibit 32.2
Solely for the purposes of complying with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002, I, the undersigned Vice President and Chief Financial Officer of Whiting
Petroleum Corporation, a Delaware corporation (the “Company”), hereby certify, based on my knowledge, that the
Annual Report on Form 10-K of the Company for the fiscal year ended December 31, 2012 (the “Report”) fully
complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and that information
contained in the Report fairly presents, in all material respects, the financial condition and results of operations of
the Company.
/s/ Michael J. Stevens
Michael J. Stevens
Vice President and Chief Financial Officer
Date: February 28, 2013
Cawley, Gillespie & Associates, Inc.
P E T R O L E U M C O N S U L T A N T S
1 3 6 4 0 B R I A R W I C K D R I V E , S U I T E 1 0 0
A U S T I N , T E X A S 7 8 7 2 9 - 1 7 0 7
5 1 2 - 2 4 9 - 7 0 0 0
3 0 6 W E S T S E V E N T H S T R E E T , S U I T E 3 0 2
F O R T W O R T H , T E X A S 7 6 1 0 2 - 4 9 8 7
8 1 7 - 3 3 6 - 2 4 6 1
w w w . c g a u s . c o m
1 0 0 0 L O U I S I A N A S T R E E T , S U I T E 6 2 5
H O U S T O N , T E X A S 7 7 0 0 2 - 5 0 0 8
7 1 3 - 6 5 1 - 9 9 4 4
Exhibit 99.2
January 11, 2013
Mr. J. Douglas Lang
Vice President - Reservoir
Engineering/Acquisitions
Whiting Petroleum Corporation
1700 Broadway, Suite 2300
Denver, Colorado 80290-2300
Re: Evaluation Summary – SEC Price
Whiting Petroleum Corporation Interests
Total Proved Reserves
Various States
As of December 31, 2012
Pursuant to the Guidelines of the Securities and
Exchange Commission for Reporting Corporate
Reserves and Future Net Revenue
Dear Mr. Lang:
As requested, we are submitting our estimates of total proved reserves and forecasts of economics
attributable to the interests in certain oil and gas properties located in various states within the United States. This
report, completed January 11, 2013 covers 100% of the proved reserves estimated for Whiting Petroleum
Corporation. This report includes results for an SEC pricing scenario. The results of this evaluation are presented
in the accompanying tabulations, with a composite summary presented below:
Proved
Developed
Producing
Proved
Developed
Behind Pipe
Proved
Developed
Non-Producing
Proved
Undeveloped
Total Proved
Net Reserves
Oil
Gas
NGL
Revenue
Oil
Gas
NGL
Severance Taxes
Ad Valorem Taxes
Operating Expenses
Investments
Net Operating Income
- Mbbl
- MMcf
- Mbbl
173,010.5
148,476.9
20,634.8
15,008,039.0
489,681.4
1,222,986.3
1,383,756.5
148,060.0
5,924,220.0
255,948.8
- M$
- M$
- M$
- M$
- M$
- M$
- M$
- M$
1,440.6
8,506.3
470.4
129,233.3
26,641.7
26,235.6
12,757.9
1,520.9
45,398.4
7,268.1
16,393.8
3,909.9
3,098.5
1,485,124.4
11,520.2
192,707.3
80,364.7
36,992.2
491,099.5
196,611.5
110,439.7
63,370.7
15,893.9
9,634,857.0
192,056.7
889,669.3
798,635.9
147,580.8
2,326,945.3
2,721,789.8
301,284.6
224,263.8
40,097.6
26,257,252.0
719,900.3
2,331,598.3
2,275,515.3
334,153.9
8,787,663.0
3,181,618.8
Discounted @ 10%
- M$
5,375,564.5
25,302.8
395,337.9
1,487,691.5
7,283,896.5
9,008,719.0
115,165.3
884,284.3
4,721,629.5
14,729,797.0
The discounted cash flow value shown above should not be construed to represent an estimate of the fair market
value by Cawley, Gillespie & Associates, Inc.
Hydrocarbon Pricing
As requested for the SEC scenario, initial WTI spot oil and Henry Hub Gas Daily prices of $94.71 per Bbl
and $2.76 per MMBtu, respectively, were adjusted individually to WTI posted pricing at $91.32 per Bbl and
Houston Ship Channel pricing at $2.71 per MMBtu, as of December 31, 2012. Further adjustments were applied
on a lease level basis for oil price differentials, gas price differentials and heating values as furnished by your
office. Prices were not escalated in the SEC scenario. The average adjusted prices used in the estimation of proved
reserves were $87.15 per Bbl of oil, $58.15 per Bbl of natural gas liquids and $3.21 per Mcf of natural gas.
Capital, Expenses and Taxes
Capital expenditures, lease operating expenses and Ad Valorem tax values were forecast as provided by
your office. As you explained, the capital costs were based on the most current estimates, lease operating expenses
were based on the analysis of historical actual expenses, operating overhead is included for operated properties and
no credit or deduction is made for producing overhead paid to the company by other owners of the operated
properties. Capital costs and lease operating expenses were held constant in accordance with SEC guidelines.
Severance tax rates were applied at normal state percentages of oil and gas revenue.
SEC Conformance and Regulations
The reserve classifications and the economic considerations used herein conform to the criteria of the SEC
as defined in pages 3 and 4 of the Appendix. The reserves and economics are predicated on regulatory agency
classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible
effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and
economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or
restrictive regulatory actions that may impact the recovery of reserves.
Reserve Estimation Methods
The methods employed in estimating reserves are described on page 2 of the Appendix. Reserves for
proved developed producing wells were estimated using production performance methods for the vast majority of
properties. Certain new producing properties with very little production history were forecast using a combination
of production performance and analogy to similar production, both of which are considered to provide a relatively
high degree of accuracy.
Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using
either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of
accuracy for predicting proved developed non-producing and proved undeveloped reserves. The assumptions, data,
methods and procedures used herein are appropriate for the purpose served by this report.
Miscellaneous
An on-site field inspection of the properties has not been performed. The mechanical operation or
conditions of the wells and their related facilities have not been examined nor have the wells been tested by
Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been
investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not
been included.
The reserve estimates were based on interpretations of factual data furnished by your office. We have used
all methods and procedures as we considered necessary under the circumstances to prepare the report. We believe
that the assumptions, data, methods and procedures were appropriate for the purpose served by this report.
Production data, gas prices, gas price differentials, expense data, tax values and ownership interests were also
supplied by you and were accepted as furnished. To some extent information from public records has been used to
check and/or supplement these data. The basic engineering and geological data were subject to third party
reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we
are not justified in relying on such data.
The professional qualifications of the undersigned, the technical person primarily responsible for the
preparation of this report, are included as an attachment to this letter.
Yours very truly,
/s/ Robert D. Ravnaas
Robert D. Ravnaas, P.E.
President
Cawley, Gillespie & Associates
Texas Registered Engineering Firm F-693
APPENDIX
Explanatory Comments for Individual Tables
Table Number
Effective Date of the Evaluation
Identity of Interest Evaluated
Reserve Classification and Development Status
Operator – Property Name
Field (Reservoir) Names – County, State
Calendar or Fiscal years/months commencing on effective date.
Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of
cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the
effective date are shown following the annual/monthly forecasts.
Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take
into account changes in interest and gas shrinkage.
Average (volume weighted) gross liquid price per barrel before deducting production-severance taxes.
Average (volume weighted) gross gas price per Mcf before deducting production-severance taxes.
Average (volume weighted) gross NGL price per barrel before deducting production-severance taxes.
Revenue derived from oil sales -- column (5) times column (8).
Revenue derived from gas sales -- column (6) times column (9).
Revenue derived from NGL sales -- column (7) times column (10).
Revenue derived from other sources.
Revenue derived from hedge positions.
Total Revenue – sum of column (12) through column (16).
Production-Severance taxes deducted from gross oil and NGL revenue.
Production-Severance taxes deducted from gross gas revenue.
Revenue after taxes – column (17) less column (18) and column (19).
Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative
overhead charges for operated oil and gas producers known as COPAS.
Ad Valorem taxes.
Work-over Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair.
3rd Party COPAS are combined fixed rate administrative overhead charges for non-operated oil and gas producers.
Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs.
Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and
the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life.
Future Net Cash Flow is column (18) less the total of column (19), column (22), column (24), column (25), column (26) and column (27).
The data in column (28) are accumulated in column (29). Federal income taxes have not been considered.
Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates.
HEADINGS
FORECAST
(Columns)
(1) (11) (21)
(2) (3) (4)
(5) (6) (7)
(8)
(9)
(10)
(12)
(13)
(14)
(15)
(16)
(17)
(18)
(19)
(20)
(22)
(23)
(24)
(25)
(26)
(27)
(28) (29)
(30)
MISCELLANEOUS
Input Data
Interests
DCF Profile
Life
Footnotes
• Evaluation parameters such as rates, tax percentages, and expenses are shown below columns (21-26).
•
• The cash flow discounted at six different rates are shown at the bottom of columns (29-30). Interest has been compounded
Initial and final expense and revenue interests are shown below columns (27-28).
monthly.
• The economic life of the appraised property is noted in the lower right-hand corner of the table.
• Well ID information or other pertinent comments may be shown in the lower left-hand footnotes.
Cawley, Gillespie & Associates, Inc.
Appendix
Page 1
APPENDIX
Methods Employed in the Estimation of Reserves
The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3)
volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent
of the data available and the characteristics of the reservoirs.
Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality,
quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly
production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general
rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity
in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and
reliability of estimates.
A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy
follows:
Production performance. This method employs graphical analyses of production data on the premise that all factors which have
controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only
information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative
production. This procedure is referred to as "decline curve" analysis. Both capacity and restricted production can, in some cases, be analyzed
from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally
considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.
Material balance. This method employs the analysis of the relationship of production and pressure performance on the premise that
the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be
estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data,
production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the
time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be
estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available.
Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this
method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are
generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data
available.
Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of
hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume,
fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production
performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of
hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and
a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy;
but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is
uncomplicated.
Analogy. This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and
includes consideration of theoretical performance. The analogy method is applicable where the data are insufficient or so inconclusive that
reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a
relatively low degree of accuracy.
Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to
continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain
substantial errors as time passes and new information is obtained about well and reservoir performance.
Cawley, Gillespie & Associates, Inc.
Appendix
Page 2
APPENDIX
Reserve Definitions and Classifications
The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and
January 1, 2010, requires adherence to the following definitions of oil and gas reserves:
“(22)
Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, 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.
“(i)
The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any,
and (B) 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.
“(ii)
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons
(LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with
reasonable certainty.
“(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists
for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering,
or performance data and reliable technology establish the higher contact with reasonable certainty.
“(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not
limited to, fluid injection) are included in the proved classification when: (A) 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 (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
“(v) 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 prior to 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.
“(6)
Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be
recovered:
“(i)
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; and
“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is
by means not involving a well.
“(31)
Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category 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.
“(i)
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.
“(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating
that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
“(iii) Under no circumstances shall estimates for 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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology
establishing reasonable certainty.
Cawley, Gillespie & Associates, Inc.
Appendix
Page 3
“(18)
Probable reserves. Probable reserves are those additional 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.
“(i) 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. When probabilistic methods are used, there should be at least a 50% probability that the actual
quantities recovered will equal or exceed the proved plus probable reserves estimates.
“(ii)
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.
“(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the
hydrocarbons in place than assumed for proved reserves.
“(iv) See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).
"(17)
Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable
reserves.
“(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of
exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the
total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
“(ii)
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.
“(iii) 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.
“(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative
technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in
successful similar projects.
“(v)
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 the registrant believes 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.
“(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO)
elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the
reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the
reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid
properties and pressure gradient interpretations.”
Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that "a
registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S–K." This is
relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves
pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”
“(26)
Reserves. Reserves are 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.
“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until
those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from
a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas
may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”
Cawley, Gillespie & Associates, Inc.
Appendix
Page 4
Cawley, Gillespie & Associates, Inc.
P E T R O L E U M C O N S U L T A N T S
1 3 6 4 0 B R I A R W I C K D R I V E , S U I T E 1 0 0
A U S T I N , T E X A S 7 8 7 2 9 - 1 7 0 7
5 1 2 - 2 4 9 - 7 0 0 0
3 0 6 W E S T S E V E N T H S T R E E T , S U I T E 3 0 2
F O R T W O R T H , T E X A S 7 6 1 0 2 - 4 9 8 7
8 1 7 - 3 3 6 - 2 4 6 1
w w w . c g a u s . c o m
1 0 0 0 L O U I S I A N A S T R E E T , S U I T E 6 2 5
H O U S T O N , T E X A S 7 7 0 0 2 - 5 0 0 8
7 1 3 - 6 5 1 - 9 9 4 4
January 11, 2013
Mr. J. Douglas Lang
Vice President - Reservoir
Engineering/Acquisitions
Whiting Petroleum Corporation
1700 Broadway, Suite 2300
Denver, Colorado 80290-2300
Re:
Evaluation Summary – SEC Price
Whiting Petroleum Corporation Interests
Probable and Possible Reserves
Various States
As of December 31, 2012
Pursuant to the Guidelines of the Securities and
Exchange Commission for Reporting Corporate
Reserves and Future Net Revenue
Dear Mr. Lang:
As requested, we are submitting our estimates of probable and possible reserves and forecasts of economics
attributable to the interests in certain oil and gas properties located in various states within the United States. This
report, completed January 11, 2013 covers 100% of the probable and possible reserves estimated for Whiting
Petroleum Corporation. This report includes results for an SEC pricing scenario. The results of this evaluation are
presented in the accompanying tabulations, with a composite summary presented below:
Net Reserves
Oil
Gas
NGL
Revenue
Oil
Gas
NGL
Severance Taxes
Ad Valorem Taxes
Operating Expenses
Investments
Net Operating Income
- Mbbl
- MMcf
- Mbbl
- M$
- M$
- M$
- M$
- M$
- M$
- M$
- M$
Discounted @ 10%
- M$
Probable Developed
Behind Pipe
Probable Developed
Non-Producing
Probable
Undeveloped
Total
Probable
850.0
6,926.4
138.8
77,911.9
25,264.4
7,623.9
7,034.2
1,464.4
35,309.8
5,109.4
61,882.4
34,926.4
1,492.4
57.8
395.2
135,155.8
148.9
25,604.6
7,406.1
3,730.1
44,577.0
21,919.4
83,276.7
30,450.2
82,639.1
102,597.8
11,388.4
7,216,017.5
329,689.5
627,543.8
547,473.3
188,486.3
1,499,329.9
2,149,231.5
84,981.5
109,582.0
11,922.3
7,429,085.0
355,102.8
660,772.3
561,913.6
193,680.9
1,579,216.6
2,176,260.3
3,788,730.5
3,933,890.3
1,196,386.5
1,261,763.1
Net Reserves
Oil
Gas
NGL
Revenue
Oil
Gas
NGL
Severance Taxes
Ad Valorem Taxes
Operating Expenses
Investments
Net Operating Income
- Mbbl
- MMcf
- Mbbl
- M$
- M$
- M$
- M$
- M$
- M$
- M$
- M$
Discounted @ 10%
- M$
Possible Developed
Possible Undeveloped
772.3
1,720.7
97.1
68,187.8
5,252.7
5,639.8
4,543.7
1,866.4
16,204.1
6,845.6
49,620.5
34,008.3
122,406.8
154,660.9
21,838.6
10,866,868.0
446,190.9
1,320,019.9
730,987.0
277,333.0
1,716,433.6
2,526,578.0
7,381,748.5
1,325,599.5
Total
Possible
123,179.1
156,381.6
21,935.7
10,935,056.0
451,443.7
1,325,659.6
735,530.6
279,199.3
1,732,637.6
2,533,424.3
7,431,368.0
1,359,607.6
The discounted cash flow value shown above should not be construed to represent an estimate of the fair market
value by Cawley, Gillespie & Associates, Inc.
Hydrocarbon Pricing
As requested for the SEC scenario, initial WTI spot oil and Henry Hub Gas Daily prices of $94.71 per Bbl
and $2.76 per MMBtu, respectively, were adjusted individually to WTI posted pricing at $91.32 per Bbl and
Houston Ship Channel pricing at $2.71 per MMBtu, as of December 31, 2012. Further adjustments were applied
on a lease level basis for oil price differentials, gas price differentials and heating values as furnished by your
office. Prices were not escalated in the SEC scenario. The average adjusted prices used in the estimation of
Probable reserves were $87.42 per Bbl of oil, $55.42 per Bbl of natural gas liquids and $3.24 per Mcf of natural
gas. For the Possible reserves, the average adjusted prices were $88.77 per Bbl of oil, $60.43 per Bbl of natural gas
liquids and $2.89 per Mcf of natural gas.
Capital, Expenses and Taxes
Capital expenditures, lease operating expenses and Ad Valorem tax values were forecast as provided by
your office. As you explained, the capital costs were based on the most current estimates, lease operating expenses
were based on the analysis of historical actual expenses, operating overhead is included for operated properties and
no credit or deduction is made for producing overhead paid to the company by other owners of the operated
properties. Capital costs and lease operating expenses were held constant in accordance with SEC guidelines.
Severance tax rates were applied at normal state percentages of oil and gas revenue.
SEC Conformance and Regulations
The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as
defined on page 4 of the Appendix. The reserves and economics are predicated on regulatory agency classifications,
rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in
legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been
considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions
that may impact the recovery of reserves.
Reserve Estimation Methods
The methods employed in estimating reserves are described on pages 2 through 4 of the Appendix.
Reserves for producing wells were estimated using production performance methods for the vast majority of
properties. Certain new producing properties with very little production history were forecast using a combination
of production performance and analogy to similar production, both of which are considered to provide a relatively
high degree of accuracy.
Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using
either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of
accuracy for predicting developed non-producing and undeveloped reserves. The assumptions, data, methods and
procedures used herein are appropriate for the purpose served by this report.
Miscellaneous
An on-site field inspection of the properties has not been performed. The mechanical operation or
conditions of the wells and their related facilities have not been examined nor have the wells been tested by
Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been
investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not
been included.
The reserve estimates were based on interpretations of factual data furnished by your office. We have used all
methods and procedures as we considered necessary under the circumstances to prepare the report. We believe that the
assumptions, data, methods and procedures were appropriate for the purpose served by this report. Production data, gas
prices, gas price differentials, expense data, tax values and ownership interests were also supplied by you and were
accepted as furnished. To some extent information from public records has been used to check and/or supplement these
data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has
come to our attention, however, that would cause us to believe that we are not justified in relying on such data.
The professional qualifications of the undersigned, the technical person primarily responsible for the
preparation of this report, are included as an attachment to this letter.
Yours very truly,
/s/ Robert D. Ravnaas
Robert D. Ravnaas, P.E.
President
Cawley, Gillespie & Associates
Texas Registered Engineering Firm F-693
APPENDIX
Explanatory Comments for Individual Tables
Table Number
Effective Date of the Evaluation
Identity of Interest Evaluated
Reserve Classification and Development Status
Operator – Property Name
Field (Reservoir) Names – County, State
Calendar or Fiscal years/months commencing on effective date.
Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of
cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the
effective date are shown following the annual/monthly forecasts.
Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take
into account changes in interest and gas shrinkage.
Average (volume weighted) gross liquid price per barrel before deducting production-severance taxes.
Average (volume weighted) gross gas price per Mcf before deducting production-severance taxes.
Average (volume weighted) gross NGL price per barrel before deducting production-severance taxes.
Revenue derived from oil sales -- column (5) times column (8).
Revenue derived from gas sales -- column (6) times column (9).
Revenue derived from NGL sales -- column (7) times column (10).
Revenue derived from other sources.
Revenue derived from hedge positions.
Total Revenue – sum of column (12) through column (16).
Production-Severance taxes deducted from gross oil and NGL revenue.
Production-Severance taxes deducted from gross gas revenue.
Revenue after taxes – column (17) less column (18) and column (19).
Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative
overhead charges for operated oil and gas producers known as COPAS.
Ad Valorem taxes.
Work-over Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair.
3rd Party COPAS are combined fixed rate administrative overhead charges for non-operated oil and gas producers.
Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs.
Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and
the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life.
Future Net Cash Flow is column (18) less the total of column (19), column (22), column (24), column (25), column (26) and column (27).
The data in column (28) are accumulated in column (29). Federal income taxes have not been considered.
Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates.
HEADINGS
FORECAST
(Columns)
(1) (11) (21)
(2) (3) (4)
(5) (6) (7)
(8)
(9)
(10)
(12)
(13)
(14)
(15)
(16)
(17)
(18)
(19)
(20)
(22)
(23)
(24)
(25)
(26)
(27)
(28) (29)
(30)
MISCELLANEOUS
Input Data
Interests
DCF Profile
Life
Footnotes
• Evaluation parameters such as rates, tax percentages, and expenses are shown below columns (21-26).
•
• The cash flow discounted at six different rates are shown at the bottom of columns (29-30). Interest has been compounded
Initial and final expense and revenue interests are shown below columns (27-28).
monthly.
• The economic life of the appraised property is noted in the lower right-hand corner of the table.
• Well ID information or other pertinent comments may be shown in the lower left-hand footnotes.
Cawley, Gillespie & Associates, Inc.
Appendix
Page 1
APPENDIX
Methods Employed in the Estimation of Reserves
The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3)
volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent
of the data available and the characteristics of the reservoirs.
Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality,
quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly
production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general
rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity
in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and
reliability of estimates.
A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy
follows:
Production performance. This method employs graphical analyses of production data on the premise that all factors which have
controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only
information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative
production. This procedure is referred to as "decline curve" analysis. Both capacity and restricted production can, in some cases, be analyzed
from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally
considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.
Material balance. This method employs the analysis of the relationship of production and pressure performance on the premise that
the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be
estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data,
production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the
time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be
estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available.
Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this
method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are
generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data
available.
Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of
hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume,
fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production
performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of
hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and
a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy;
but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is
uncomplicated.
Analogy. This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and
includes consideration of theoretical performance. The analogy method is applicable where the data are insufficient or so inconclusive that
reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a
relatively low degree of accuracy.
Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to
continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain
substantial errors as time passes and new information is obtained about well and reservoir performance.
Cawley, Gillespie & Associates, Inc.
Appendix
Page 2
APPENDIX
Reserve Definitions and Classifications
The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and
January 1, 2010, requires adherence to the following definitions of oil and gas reserves:
“(22)
Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, 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.
“(i)
The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any,
and (B) 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.
“(ii)
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons
(LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with
reasonable certainty.
“(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists
for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering,
or performance data and reliable technology establish the higher contact with reasonable certainty.
“(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not
limited to, fluid injection) are included in the proved classification when: (A) 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 (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
“(v) 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 prior to 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.
“(6)
Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be
recovered:
“(i)
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; and
“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is
by means not involving a well.
“(31)
Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category 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.
“(i)
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.
“(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating
that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
“(iii) Under no circumstances shall estimates for 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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing
reasonable certainty.
Cawley, Gillespie & Associates, Inc.
Appendix
Page 3
“(18)
Probable reserves. Probable reserves are those additional 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.
“(i) 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. When probabilistic methods are used, there should be at least a 50% probability that the actual
quantities recovered will equal or exceed the proved plus probable reserves estimates.
“(ii)
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.
“(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the
hydrocarbons in place than assumed for proved reserves.
“(iv) See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).
“(17)
Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable
reserves.
“(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of
exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the
total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
“(ii)
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.
“(iii) 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.
“(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative
technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in
successful similar projects.
“(v)
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 the registrant believes 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.
“(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO)
elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the
reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the
reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid
properties and pressure gradient interpretations.”
Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that "a
registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S–K." This is
relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves
pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”
“(26)
Reserves. Reserves are 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.
“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until
those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from
a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas
may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”
Cawley, Gillespie & Associates, Inc.
Appendix
Page 4
Cawley, Gillespie & Associates, Inc.
P E T R O L E U M C O N S U L T A N T S
1 3 6 4 0 B R I A R W I C K D R I V E , S U I T E 1 0 0
A U S T I N , T E X A S 7 8 7 2 9 - 1 7 0 7
5 1 2 - 2 4 9 - 7 0 0 0
3 0 6 W E S T S E V E N T H S T R E E T , S U I T E 3 0 2
F O R T W O R T H , T E X A S 7 6 1 0 2 - 4 9 8 7
8 1 7 - 3 3 6 - 2 4 6 1
w w w . c g a u s . c o m
1 0 0 0 L O U I S I A N A S T R E E T , S U I T E 6 2 5
H O U S T O N , T E X A S 7 7 0 0 2 - 5 0 0 8
7 1 3 - 6 5 1 - 9 9 4 4
Professional Qualifications of Robert D. Ravnaas, P.E.
President of Cawley, Gillespie & Associates
Mr. Ravnaas has been a Petroleum Consultant for Cawley, Gillespie & Associates (CG&A) since 1983, and became
President in 2011. He has completed numerous field studies, reserve evaluations and reservoir simulation,
waterflood design and monitoring, unit equity determinations and producing rate studies. He has testified before
the Texas Railroad Commission in unitization and field rules hearings. Prior to CG&A he worked as a Production
Engineer for Amoco Production Company. Mr. Ravnaas received a B.S. with special honors in Chemical
Engineering from the University of Colorado at Boulder, and a M.S. in Petroleum Engineering from the University
of Texas at Austin. He is a registered professional engineer in Texas, No. 61304, and a member of the Society of
Petroleum Engineers (SPE), the Society of Petroleum Evaluation Engineers, the American Association of
Petroleum Geologists and the Society of Professional Well Log Analysts.
fp_Cover 3/15/13 2:44 PM Page 2
the Bakken/Three Forks in the Williston Basin, we
Financial and Operations Summary . . . . . . . . . . . 2
Division, Whiting was the number one oil producer
Other Development Areas . . . . . . . . . . . . . . . . . 12
in the United States.
Building for the Future . . . . . . . . . . . . . . . . . . . . 16
We are a Bakken oil company. With a focus on
generated record production of 30.21 MMBOE or
82,540 BOE per day in 2012. According to the
December 2012 Oil and Gas Production Report
published by the North Dakota State Industrial
Commission, Department of Minerals, Oil and Gas
in North Dakota at 66,155.7 barrels per day. North
Dakota is the second largest oil producing state
We were one of the first successful operators in the
Bakken/Three Forks Hydrocarbon System in the
Williston Basin with the discovery of our Sanish field
in early 2007. With our experience and expertise in
operating in the Williston Basin, we expect a very
good year for organic growth in reserves and production
in 2013. We expect to generate year-over-year
production growth of between 12% and 16%. In the
Bakken and Three Forks hydrocarbon system in the
Williston Basin alone, we hold more than 700,000
net acres and continue to add to that position.
Importantly, our average cost in this acreage is $521
per net acre.
ABBREVIATIONS
Bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in
this report in reference to oil, NGLs and other liquid hydrocarbons.
Bcf: One billion cubic feet of natural gas.
BOE: One stock tank barrel equivalent of oil, calculated by
converting natural gas volumes to equivalent oil barrels at a ratio
of six Mcf to one Bbl of oil.
BOE/d: Barrels of oil equivalent per day.
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.
EOR: Enhanced Oil Recovery is a tertiary recovery method in
which injectants, such as CO2, are introduced into a reservoir to
enhance hydrocarbon recovery.
MBOE: One thousand BOE.
Mcf: One thousand cubic feet of natural gas.
Mcfe: One thousand cubic feet of natural gas equivalent.
MMBbl: One million barrels.
MMBOE: One million BOE.
MMcf: One million cubic feet of natural gas.
MMcf/d: One million cubic feet of natural gas per day.
NGLs: Natural gas liquids.
PDP: Proved developed producing.
PDNP: Proved developed nonproducing.
Corporate Overview . . . . . . . . . . . . . . . . . . . . . . . 1
Letter to the Shareholders . . . . . . . . . . . . . . . . . . 4
Drilling and Operations Overview . . . . . . . . . . . . 6
Williston Basin Oil Plays . . . . . . . . . . . . . . . . . . . . 8
Optimization Programs . . . . . . . . . . . . . . . . . . . 14
Board of Directors . . . . . . . . . . . . . . . . . . . . . . . 20
Annual Report on Form 10-K . . . . . . . . . . . . . . . 21
Corporate Investor Information
Inside back cover
RESERVE AND RESOURCE INFORMATION
Whiting uses in this annual report the terms proved, probable
and possible reserves. Proved reserves are 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 under existing economic conditions, operating
methods and government regulations prior to the time at which
contracts providing the right to operate expire, unless eviden-
ceindicates that renewal is reasonably certain. Probable reserves are
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. Possible reserves are reserves that are less certain to be
recovered than probable reserves. Estimates of probable and possible
reserves which may potentially be recoverable through additional
drilling or recovery techniques are by nature more uncertain than
estimates of proved reserves and accordingly are subject to substan-
tially greater risk of not actually being realized by the Company.
Whiting uses in this annual report the term “total resources,”
which consists of contingent and prospective resources, which SEC
rules prohibit in filings of U.S. registrants. Contingent resources are
resources that are potentially recoverable but not yet considered
mature enough for commercial development due to technological
or business hurdles. For contingent resources to move into the
reserves category, the key conditions, or contingencies, that pre-
vented commercial development must be clarified and removed.
Prospective resources are estimated volumes associated with undis-
covered accumulations. These represent quantities of petroleum
which are estimated to be potentially recoverable from oil and gas
deposits identified on the basis of indirect evidence but which
have not yet been drilled. This class represents a higher risk than
contingent resources since the risk of discovery is also added. For
prospective resources to become classified as contingent resources,
hydrocarbons must be discovered, the accumulations must be
further evaluated and an estimate of quantities that would be
recoverable under appropriate development projects prepared.
Estimates of resources are by nature more uncertain than reserves
and accordingly are subject to substantially greater risk of not
actually being realized by the Company.
FORWARD-LOOKING STATEMENTS
This annual report contains forward-looking statements. Please
refer to “Forward-Looking Statements” on pages 70–71 of the
attached Annual Report on Form 10-K for an explanation of these
types of statements. These statements should be considered in light
of the “Risk Factors” set forth on page 22 of the attached Annual
PUD: Proved undeveloped.
Report on Form 10-K.
ABOUT THE COVER
CONTENTS
EXECUTIVE OFFICERS
OTHER OFFICERS
BOARD OF DIRECTORS
PETER W. HAGIST
Vice President, Permian Operations
for Whiting Oil and Gas Corporation
CHUCK LACOUTURE
Vice President, Marketing
for Whiting Oil and Gas Corporation
MARK D. SONNENFELD
Vice President, Geoscience
for Whiting Oil and Gas Corporation
DIRECTOR SINCE
JAMES J. VOLKER 2003
Chairman of the Board
and Chief Executive Officer
THOMAS L. ALLER *+ 2003
President
Interstate Power and
Light Company,
an Alliant Energy Company
JOHN K. SOUTHWELL
Vice President, Permian Exploration
for Whiting Oil and Gas Corporation
D. SHERWIN ARTUS^ 2006
Retired President and CEO
of Whiting
JAMES J.VOLKER
Chairman of the Board
and Chief Executive Officer
JAMES T. BROWN
President and Chief Operating Officer
MARK R. WILLIAMS
Senior Vice President, Exploration
and Development
MICHAEL J. STEVENS
Vice President and Chief Financial Officer
BRUCE R. DEBOER
Vice President, General Counsel
and Corporate Secretary
J. DOUGLAS LANG
Vice President, Reservoir Engineering
and Acquisitions
DAVID M. SEERY
Vice President, Land
RICK A. ROSS
Vice President, Operations
DOUGLAS L. WALTON
Vice President and
National Drilling Manager
for Whiting Oil and Gas Corporation
ERIC K. HAGEN
Vice President, Investor Relations
JACK R. EKSTROM
Vice President,
Corporate and Government Relations
HEATHER M. DUNCAN
Vice President, Human Resources
GALE N. KEITHLINE
Vice President, Information Technology
BRENT P. JENSEN
Controller and Treasurer
CORPORATE OFFICES
Whiting Petroleum Corporation
1700 Broadway, Suite 2300
Denver, Colorado 80290-2300
Tel: (303) 837-1661
Fax: (303) 861-4023
www.whiting.com
INVESTOR RELATIONS
Securities analysts, investors and the
financial media should contact:
John B. Kelso
Director, Investor Relations
Tel: (303) 837-1661
Eric K. Hagen
Vice President, Investor Relations
Tel: (303) 837-1661
TRANSFER AGENT
Please direct communication regarding
individual stock records and address
changes to:
Computershare Trust Company, N.A.
350 Indiana Street, Suite 800
Golden, Colorado 80401
Tel: (303) 262-0600
Fax: (303) 262-0700
www.computershare.com
INDEPENDENT
PETROLEUM ENGINEERS
Cawley, Gillespie & Associates, Inc.
INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
Deloitte & Touche LLP
THOMAS P. BRIGGS*+(1) 2006
Inactive Certified
Public Accountant
PHILIP E. DOTY*^ 2010
Certified Public Accountant
WILLIAM N. HAHNE +^ 2007
Past Chief Operating Officer
Petrohawk Energy
ALLAN R. LARSON^ 2011
Consulting Geologist
* Audit Committee
+ Compensation Committee
^ Nominating and Governance Committee
(1) Mr. Briggs’ term expires at the 2013
annual meeting.
INFORMATION UPDATES
Whiting’s quarterly financial results and
other information are available on our
website at www.whiting.com
ANNUAL REPORT ON FORM 10-K
Upon request, the Company will
provide, without charge, copies of the
2012 Annual Report on Form 10-K
as filed with the Securities and
Exchange Commission.
ANNUAL MEETING
Tuesday, May 7, 2013
10:00 A.M. (DENVER TIME)
The Grand Hyatt Hotel – Grand Ballroom
1750 Welton Street
Denver, Colorado 80202
STOCK EXCHANGE LISTING
New York Stock Exchange, trading
symbol: WLL
fp_Cover 3/15/13 2:44 PM Page 1
1700 Broadway, Suite 2300
Denver, Colorado 80290-2300
Tel: (303) 837-1661
Fax: (303) 861-4023
www.whiting.com
Whiting Petroleum Corporation
ANNUA L REPORT 2012
YEA R OF RECORD PRODUCTIO N