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WHITING PETROLEUM CORPORATION
The Largest Bakken/Three Forks Producer
A STRONGER
COMPANY
WORKING TO
PROSPER AT
CURRENT PRICES
Annual Report 2014
1700 Broadway, Suite 2300
Denver, Colorado 80290-2300
Tel: (303) 837-1661
Fax: (303) 861-4023
www.whiting.com
CONTENTS
Corporate Overview
Financial and Operations Summary
Letter to the Shareholders
Acquisitions
Drilling and Operations Overview
Exploration and Development
Redtail: Our Economic Sweet Spot
Technique and Technology
Board of Directors
Annual Report on Form 10-K
1
2
4
6
8
10
12
14
16
17
Corporate Investor Information
Inside back cover
RESERVE 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 con-
tracts providing the right to operate expire, unless evidence indicates
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. Pos-
sible 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 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 page 64 of the attached
Annual Report on Form 10-K for an explanation of these types of state-
ments. These statements should be considered in light of the “Risk Factors”
set forth on page 17 of the attached Annual Report on Form 10-K.
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ABOUT THE COVER
With our acquisition of Kodiak Oil & Gas Corp., we are a
stronger company working to prosper at current prices.
Our complimentary acreage positions concentrated in
the sweet spots of the Williston Basin allow for more
efficient operations, and the application of Whiting’s
technological expertise to enhance drilling results and
reduce costs. The increased scale of the combined
companies enhances the company’s position relative to
competitors and achieves a better cost profile for its
drilling and completion program. Along with our high
quality acreage position in the DJ Basin Niobrara play
in our Redtail field, we believe Whiting controls the
premier light, tight oil assets in North America.
Pictured on the cover is higher density drilling at our Mork
Trust Unit in the Hidden Bench field, located in McKenzie
County, North Dakota. The Mork Trust 21-17-2H and the
Mork Trust 21-17-3H were completed at an average rate
of 2,643 BOE/d per well from the Bakken. These wells
were infill wells testing an eight well per spacing unit
pattern in the Middle Bakken formation. Both wells,
which were completed using cemented liners and plug-
and-perf technology, were fracture stimulated in 30
stages with four entry points per stage. These wells, using
our new completion design, had initial production rates
that were 53% better than old wells completed with our
previous completion design.
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 of oil equivalent, computed on an approxi-
mate 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.
BOE/d: Barrels of oil equivalent per day.
Completion: The installation of permanent equipment for the produc-
tion 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.
MBOE/d: MBOE per day.
Mcf: One thousand cubic feet, used in reference to natural gas or CO2.
MMBbl: One million barrels.
MMBOE: One million BOE.
MMcf: One million cubic feet, used in reference to natural gas or CO2.
MMcf/d: MMcf per day.
NGLs: Natural gas liquids.
EXECUTIVE OFFICERS
OTHER OFFICERS
BOARD OF DIRECTORS
JAMES J.VOLKER
Chairman of the Board, President
and Chief Executive Officer
CHUCK LACOUTURE
Vice President, Marketing
for Whiting Oil and Gas Corporation
MICHAEL J. STEVENS
Senior Vice President and
Chief Financial Officer
MARK D. SONNENFELD
Vice President, Geoscience
for Whiting Oil and Gas Corporation
Retired President
MARK R. WILLIAMS
Senior Vice President, Exploration
and Development
DOUGLAS L. WALTON
Vice President and
National Drilling Manager
for Whiting Oil and Gas Corporation
RICK A. ROSS
Senior Vice President, Operations
ERIC K. HAGEN
Vice President, Investor Relations
JACK R. EKSTROM
Vice President, Corporate
and Government Relations
MICHAEL R. CRAIG
Vice President,
Information Technology
PETER W. HAGIST
Senior Vice President, Planning
STEVEN A. KRANKER
Vice President, Reservoir Engineering
and Acquisitions
BRUCE R. DEBOER
Vice President, General Counsel
and Corporate Secretary
BRENT P. JENSEN
Vice President and Treasurer
DAVID M. SEERY
Vice President, Land
HEATHER M. DUNCAN
Vice President, Human Resources
DIRECTOR SINCE
JAMES J. VOLKER 2003
Chairman of the Board, President
and Chief Executive Officer
THOMAS L. ALLER *+ 2003
Interstate Power and Light Company
an Alliant Energy Company
D. SHERWIN ARTUS^ 2006
Retired President and CEO
Whiting Petroleum Corporation
JAMES E. CATLIN 2014
Past Executive Vice President
and Director
Kodiak Oil and Gas Corporation
PHILIP E. DOTY*^ 2010
Certified Public Accountant
WILLIAM N. HAHNE +^ 2007
Past Chief Operating Officer
Petrohawk Energy Corporation
ALLAN R. LARSON^ 2011
Consulting Geologist
LYNN A. PETERSON 2014
Past President, CEO and
Chairman of the Board
Kodiak Oil and Gas Corporation
MICHAEL B. WALEN*+ 2013
Past Chief Operating Officer
Cabot Oil and Gas Corporation
* Audit Committee
+ Compensation Committee
^ Nominating and Governance Committee
CORPORATE OFFICES
TRANSFER AGENT
Whiting Petroleum Corporation
Please direct communication
1700 Broadway, Suite 2300
regarding individual stock records
INFORMATION UPDATES
Whiting’s quarterly financial results and
other information are available on our
Denver, Colorado 80290 - 2300
and address changes to:
website at www.whiting.com
Tel: (303) 837-1661
Fax: (303) 861- 4023
www.whiting.com
INVESTOR RELATIONS
Computershare Trust Company, N.A.
8742 Lucent Blvd., Suite 225
ANNUAL REPORT ON FORM 10-K
Highlands Ranch, Colorado 80129
Upon request, the Company will
Tel: (303) 262- 0600
Fax: (303) 262- 0700
Securities analysts, investors and the
www.computershare.com
financial media should contact:
John B. Kelso
INDEPENDENT
Director, Investor Relations
PETROLEUM ENGINEERS
Cawley, Gillespie & Associates, Inc.
Tel: (303) 837-1661
Eric K. Hagen
Tel: (303) 837-1661
Vice President, Investor Relations
INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
Deloitte & Touche LLP
provide, without charge, copies of the
2014 Annual Report on Form 10-K
as filed with the Securities and
Exchange Commission
ANNUAL MEETING
Tuesday, June 2, 2015
10:00 A.M. (DENVER TIME)
The Grand Hyatt Hotel
Capitol Peak Ballroom
555 17th Street, 38th floor
Denver, Colorado 80202
STOCK EXCHANGE LISTING
New York Stock Exchange, trading
symbol: WLL
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As exemplified by our operations at the Redtail
Niobrara field (pictured below), our goal is to generate
meaningful growth in our net asset value per share
through the exploration, development and acquisi-
tion of oil and gas projects with attractive rates of
return on capital employed. We remain confident in
our outlook for continued growth in our production
and reserves. We believe we have one of the highest
rate of return acreage positions in North America. Our efficient operations and leadership
in the implementation of new completion technologies enhances the capital productivity
of this asset base helping to offset the impact of lower prices.
CORPORATE
OVERVIEW
Over the past 12 months we have built an even stronger Whiting. Our Kodiak Oil &
Gas Corp. acquisition added to the high quality of our inventory. Our asset sales lowered
our operating cost structure. Our premier Williston Basin and Niobrara acreage positions
deliver some of the most profitable drilling results in the industry with a combined
drilling inventory that exceeds 14,000 gross locations. We look forward to competing
in the current environment.
(BELOW) Two rigs working
for Whiting at its 132,155 net
acre Redtail Niobrara Field
in Weld County, Colorado.
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FINANCIAL AND OPERATIONS SUMMARY
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS,
PER UNIT PRICES OR RATIO AMOUNTS) 2014 2013 2012 2011 2010
Income Statement and Cash Flow
Oil, NGL and Natural Gas Sales $ 3,024.6 $ 2,666.5 $ 2,137.7 $ 1,860.1 $ 1,475.3
Earnings $
64.7(1) $ 366.0(1) $ 414.1 $ 491.6 $ 336.7
Earnings per Share, Diluted $
0.53(1) $ 3.06(1) $ 3.48 $ 4.14 $ 2.55
Weighted Average Shares Outstanding, Diluted 122.519 119.588 119.028 118.668 107.846
Net Cash Provided by Operating Activities $ 1,815.3 $ 1,744.7 $ 1,401.2 $ 1,192.1 $ 997.3
Net Cash Used in Investing Activities $ (2,860.5) $(1,902.5) $(1,780.3) $(1,760.0) $ (914.6)
Net Cash Provided by (Used in) Financing Activities $
423.9 $ 812.4 $ 408.1 $ 564.8 $
(75.7)
Balance Sheet
Total Assets $14,019.5 $ 8,833.5 $ 7,272.4 $ 6,045.6 $ 4,648.8
Debt $ 5,628.8 $ 2,653.8 $ 1,800.0 $ 1,380.0 $ 800.0
Shareholders’ Equity $ 5,703.0 $ 3,836.7 $ 3,453.2 $ 3,029.1 $ 2,531.3
Debt-to-Capitalization Ratio 50% 41% 34% 31% 24%
Production and Average Commodity Prices
Oil Production, MMBbl 33.5 27.0 23.1 18.3 17.5
NGL Production, MMBbl 3.3 2.8 2.8 2.1 1.5
Natural Gas Production, Bcf 30.2 26.9 25.8 26.4 27.4
Total Production, MMBOE 41.8 34.3 30.2 24.8 23.6
Oil Price, per Bbl, Excluding Hedging $
81.50 $ 90.39 $ 83.86 $ 88.61 $ 72.61
Natural Gas Liquids Price, per Bbl $
39.17 $ 40.41 $ 39.36 $ 52.38 $ 47.33
Natural Gas Price, per Mcf, Excluding Hedging $
5.53 $ 4.04 $ 3.42 $ 4.92 $ 4.86
Sales Price, per BOE, Net of Hedging $
73.38 $ 76.76 $ 69.85 $ 73.88 $ 61.48
Year-End 2014 Well Count and Acreage Statistics GROSS NET
Total Wells 11,654 4,471
Developed Acreage 1,610,833 886,654
Undeveloped Acreage 1,611,344 1,172,735
(1) For the year ended December 31, 2014, this amount includes $587 million in non-cash pre-tax impairment charges for the partial write-down
of non-core proved oil and gas properties not currently being developed primarily attributable to oil and gas reserves in legacy, non-core areas in
Colorado, Louisiana, North Dakota and Utah related to the decrease in oil and gas prices at December 31, 2014, as well as $42 million of impairment
write-downs on our CO2 development properties. Impairment charges in 2014 totaled $629 million, or $5.14 per diluted share after tax. For the year
ended December 31, 2013, this amount includes $267 million in non-cash pre-tax impairment charges, or $2.23 per diluted share after tax, for the
partial write-down of proved properties, mainly in non-core portions of the Rocky Mountains and Michigan regions.
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Proved Reserves as of December 31, 2014 2013 2012 2011 2010
Oil, MMBbl 643.6 347.4 301.3 260.2 224.2
NGLs, MMBbl 54.7 44.9 40.1 37.6 30.1
Natural Gas, Bcf 492.0 277.5 224.3 285.0 303.5
Reserves, MMBOE 780.3 438.5 378.8 345.2 304.9
Reserves-to-Production Ratio (Reserves/Annual Production) 18.7 12.8 12.6 13.9 12.9
Average Wellhead Oil Price per Bbl in Reserve Report $ 84.69 $ 90.80 $ 87.15 $ 89.18 $ 73.14
Average Wellhead NGL Price per Bbl in Reserve Report $ 46.59 $ 54.38 $ 58.15 $ 62.93 $ 49.35
Average Wellhead Gas Price per Mcf in Reserve Report $ 5.88 $ 4.30 $ 3.21 $ 4.39 $ 4.72
Reserves & Production per Region as of December 31, 2014
780.3 MMBOE Q4 2014 — 131.3 MBOE/d
2%
17%
3%
9%
81%
88%
(cid:0) ROCKY MOUNTAINS (cid:0) PERMIAN BASIN (cid:0) OTHER
The following is a summary of Whiting’s changes in quantities of proved oil and gas reserves for the year ended
December 31, 2014:
Natural
Oil NGLs Gas Total
(MBbl) (MBbl) (MMcf) (MBOE)
Balance – January 1, 2014 347,421 44,869 277,514 438,542
Extensions and discoveries 146,122 12,947 94,452 174,811
Sales of minerals in place (1,642) – (2,925) (2,130)
Acquisitions 169,586 – 156,140 195,609
Production (33,485) (3,283) (30,218) (41,804)
Revisions to previous estimates 15,627 151 (2,943) 15,288
Balance – December 31, 2014 643,629 54,684 492,020 780,316
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2014 was a record year for Whiting Petroleum. We posted records in production, proved
reserves and discretionary cash flow during 2014. Discretionary cash flow increased
14% and proved reserves and production increased 29% and 22%, respectively. Our
acquisition of Kodiak Oil & Gas Corp. established us as the largest Bakken/Three Forks
producer in the Williston Basin of North Dakota and Montana.
Despite the pullback in oil prices, we remain confident in our outlook for continued
growth in our production and reserves. We believe we have one of the highest rate of
return acreage positions in North America. Our efficient operations and leadership
in the implementation of new com-
pletion technologies enhances the
capital productivity of this asset
base helping to offset the impact of
lower prices.
DEAR FELLOW
SHAREHOLDERS
We have taken prudent measures in
2015 to reduce our capital budget
while maintaining our financial
flexibility. Our 2015 capital budget of $2.0 billion reflects a disciplined approach to
maintaining our financial strength while preserving our long-term growth plans. We
plan to reduce our rig fleet to approximately 13 rigs by mid-year, down 48% from 25
rigs for the combined companies in 2014, and will focus our operations on our highest
rate-of-return properties. At the same time, we are seeing lower rig and service costs
through price reductions and technology applications. We expect our completed well
cost in the Williston Basin to average $7 million, down from $8.5 million in 2014. We
expect our Redtail completed well cost to be $5 million.
We welcome the 145 Kodiak employees who have joined Whiting. They have made a
seamless transition to Whiting. We have already completed several wells on properties
acquired from Kodiak. In the Moccasin Creek area in Dunn County, North Dakota, we
completed three wells off of a pad that had an average initial production rate of 3,473
BOE/d per well. That’s a great start to the assimilation of the Kodiak acreage.
We continue to focus on oil and natural gas liquids. Currently, crude oil trades at over
15 times the price of natural gas, which compares to their 6 to 1 heating equivalency
ratio. At year-end 2014, 82% of our proved reserves and 80% of our production consisted
of crude oil. We expect these percentages to continue to increase over the next several
years. In the September 1, 2014 edition of the Oil & Gas Journal, we ranked 18th in the
world in terms of liquids proved reserves and 16th in the world in terms of liquids pro-
duction for public companies. Pro forma for the Kodiak acquisition, we would be 13th
in the world in terms of liquids proved reserves and 14th in the world in terms of liquids
production for public companies.
In summary, over the past 12 months we have built an even stronger Whiting. Our
Kodiak acquisition added to the high quality of our inventory. Our asset sales lowered
our operating cost structure. Our premier Williston Basin and Niobrara acreage positions
deliver some of the most profitable drilling results in the industry with a combined
drilling inventory that exceeds 14,000 locations. 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.
Sincerely,
(ABOVE) CEO, Jim Volker,
discusses our plans at our
Redtail Niobrara Field in
Northeastern Colorado with
employees and investors.
(RIGHT) Drilling operations
on our Good Shepherd
21-15H well in the Hidden
Bench Field in McKenzie
County, North Dakota.
JAMES J. VOLKER
CHAIRMAN OF THE BOARD, PRESIDENT AND CHIEF EXECUTIVE OFFICER
February 27, 2015
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KODIAK ACQUISITION ADDS PRODUCTION AND RESERVES
On July 13, 2014, Whiting announced the acquisition of Kodiak Oil & Gas Corp. in a
stock-for-stock transaction. Under the agreement, Kodiak shareholders received 0.177
shares of Whiting stock for every one share of Kodiak stock. The transaction closed
on December 8, 2014 after both Whiting
and Kodiak shareholders overwhelmingly
voted in favor of the acquisition at special
meetings on December 3, 2014.
ACQUISITIONS
Through the Kodiak acquisition Whiting acquired approximately 327,000 gross (178,000
net) acres, which are predominantly in the Williston Basin in North Dakota. These
properties are an excellent overlay to Whiting’s existing acreage in the Williston Basin.
The proved reserves associated with the acquisition totaled 191.8 MMBOE. Production
from the acquired properties averaged 41,250 BOE/d in the fourth quarter of 2014. In
the wake of the Kodiak acquisition, Whiting had an estimated 4,637 gross drilling
locations in the Bakken formation and 2,904 future gross drilling locations in the Three
Forks formation at year-end 2014. Of Kodiak’s 227 employees, 145 were offered positions
and joined Whiting.
(BELOW) The Flatland Federal
11-4HR in our Tarpon Field in
McKenzie County, North Dakota
was completed in the Middle
Bakken formation flowing 7,120
BOE/d. This was a record initial
production rate for a Bakken
well in the Williston Basin. An off-
setting well, the Flatland Federal
11-4TFH, was completed in the
Three Forks and set the record for
the highest initial Three Forks pro-
duction rate in the Williston Basin
with an IP rate of 7,824 BOE/d.
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LAND — STANDING (LEFT TO RIGHT) Justin Shannonhouse, Landman III, Daren Carr, Landman II, Keelen Hauptman, Landman II,
Travis Barrett, Landman II. SEATED (LEFT TO RIGHT) Ellen Britt, Division Orders Supervisor, John Marshall, Landman III.
COMPLETIONS AND OPERATIONS — STANDING (LEFT TO RIGHT) Ryan Lundsford, Construction Manager,
Brandon Rollins, Operations Engineer, Nate Rutledge, Operations Engineer.
SEATED (LEFT TO RIGHT) Monte Madsen, Completions Engineering Team Lead, Kelly Eisele, Operations Engineer,
Ted Skinner, Operations Engineering Team Lead – Watford.
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PRODUCTION
Production in 2014 totaled a record 41.8 MMBOE or 114,530 BOE/d. This represents a
22% increase over total production of 34.3 MMBOE or 94,090 BOE/d in 2013.
PROVED RESERVES
As of December 31, 2014, Whiting had estimated proved reserves of 780.3 MMBOE, of
which 53% were classified as proved developed. These estimated proved reserves had a
pre-tax PV10% value of $14.1 billion, using SEC NYMEX prices of $94.99 per barrel of
oil and $4.35 per Mcf of gas. This represents an increase of 57% over the December 31,
2013 value of $9.0 billion, which used SEC NYMEX prices of $96.78 per barrel of oil
and $3.67 per Mcf of gas.
Whiting’s proved reserves of 780.3 MMBOE repre-
sented a 78% increase over the 438.5 MMBOE of
proved reserves at year-end 2013. Adding the proved
reserves associated with the Kodiak acquisition at
year-end 2013, our proved reserves were up 29%.
An estimated 174.8 MMBOE of extensions and
discoveries of proved reserves were added by the
combined companies. This represents a 61% increase
over the 108.8 MMBOE of proved reserves that were
added from extensions and discoveries in 2013 by
Whiting alone. During 2014, we replaced 923% of
the Company’s 2014 production of 41.8 MMBOE.
DRILLING
AND
OPERATIONS
OVERVIEW
Significant proved reserve additions during 2014
came from the Company’s operations in the Williston Basin of North Dakota and
Montana. Whiting booked an estimated 124.1 MMBOE of Bakken/Three Forks proved
reserves in the Williston Basin during 2014. Also contributing was our Redtail Niobrara
field in northeastern Colorado where we booked 49.5 MMBOE of new proved reserves
during 2014.
PROBABLE AND POSSIBLE RESERVES
At year-end 2014, our probable and possible reserves were estimated to total 624.8 MMBOE.
The year-end 2014 estimated pre-tax PV10% for our probable and possible reserves was
$5.2 billion, an increase of 44% over the $3.6 billion at year-end 2013.
As with our proved reserves, 100% of Whiting’s probable and possible reserve estimates
were independently engineered by Cawley, Gillespie & Associates, Inc. Please refer to
“Reserve Information” on the inside front cover of this annual report.
2015 CAPITAL BUDGET
Our 2015 capital budget is $2.0 billion. Whiting expects to invest $1.8 billion of the 2015
capital budget in exploration and development activity, $59 million for undeveloped
acreage and $123 million for facilities. While spending at approximately 50% of our
combined Whiting/Kodiak pro forma 2014 capex rate, we expect to grow production
at 6% year-over-year.
(RIGHT) Drilling operations
on our Hunter 21-26-1H
in the Missouri Breaks Field
in McKenzie County,
North Dakota.
(INSET) A three-well pad at
our Tarpon Field in McKenzie
County, North Dakota.
At Tarpon Whiting has
recorded the Williston Basin’s
highest initial production
rates from both the Bakken
and Three Forks.
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WILLISTON BASIN
We generated record production of 131,260 BOE/d in the fourth quarter of 2014, of
which 77% came from our Williston Basin Bakken/Three Forks plays. 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. In 2014, we continued
to achieve productivity increases as we expanded the use of our cemented liner
and plug-and-perf completion method
across the Williston Basin. We continue
to optimize our completion techniques
to achieve the best mix of productivity
versus costs. Drilling highlights from
our six core areas in the Williston Basin
are as follows:
TARPON FIELD—Tarpon field continues
to prove itself as the sweet spot of the
Bakken. During the fourth quarter of
2014, we completed three prolific wells
off of a pad. The Tarpon Federal 24-20-
1H was completed in the Bakken formation on December 16, 2014 flowing 6,234
BOE/d. The Tarpon Federal 24-20-1RTF was completed in the Three Forks formation on
December 17, 2014 flowing 4,818 BOE/d, and the Federal 24-20-2RTF was completed
in the Three Forks formation on December 17, 2014 flowing 4,105 BOE/d. Whiting
holds a 75% working interest in all three wells.
EXPLORATION
AND
DEVELOPMENT
(RIGHT) Map of combined
Whiting/Kodiak properties in
the Williston Basin.
HIDDEN BENCH FIELD — At Hidden Bench, we tested five perforation clusters per stage
and achieved strong results. In September 2014, we completed a four-well pad at our
Sovig unit. The average initial production rate for the pad was 3,278 BOE/d per well
with a range from 3,036 to 3,572 BOE/d per well. The four wells were completed on
September 22 and September 23, 2014, respectively, with 30 stages and five perforation
clusters per stage.
CASSANDRA FIELD—We utilized our cemented liner completion method on three
wells in our Cassandra field. The Kaldahl 11-3H was completed in the Middle Bakken
on April 1, 2014 flowing 1,930 BOE/d, 104% higher than the 10 prior wells completed
in the Middle Bakken formation.
PRONGHORN FIELD—We have had favorable results from slickwater fracs at our
Pronghorn field, which is located primarily in Stark and Billings counties, North Dakota.
The Pronghorn Federal 14-12PH was completed on November 12, 2014. During its first
60 days of production, the well averaged 1,524 BOE/d.
SANISH FIELD AREA—We completed the Brehm 13-7H in the Sanish field in the Middle
Bakken formation using a slickwater frac and a cemented liner on August 31, 2014. Pro-
duction from the Brehm 13-7H has held up well with 30, 60 and 90-day rates averaging
1,716 BOE/d, 1,338 BOE/d and 1,111 BOE/d, respectively.
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WHITING CONTROLS “SWEET SPOTS” WHERE
BAKKEN–THREE FORKS WELLS PRODUCE OVER
50,000 BBLS IN 90 DAYS.
90 DAYS
> 50 MBOE
< 50 MBOE
Whiting Units
fp_Text 4/2/15 7:01 PM Page 12
REDTAIL:
OUR ECONOMIC
SWEET SPOT
IN THE NIOBRARA
WeWW hold a total of 185,703 gross
(132,155 net) acres in our Redtail
field, located in the Denver
Julesberg Basin in WeWW ld County,yy
Colorado. Whiting has establish-
ed production in the Niobrara
“A”, “B” and “C” zones as well as
the Codell/Fort Hays formation.
Net production from the Redtail
field averaged 10,155 BOE/d in
the fourth quarter of 2014, an
18% sequential increase over the third quarter 2014. At year-end 2014, we had an
estimated 3,523 fuff ture gross drilling locations in the Niobrara “A”, “B” and “C” zones
as well as the Codell/Fort Hays formation. After year-end, we added 3,162 Niobrara “C”
and Codell/Fort Hays fuff ture gross drilling locations to bring our total to 6,685 fuff ture
gross drilling locations.
(RIGHT) We are expanding
the inlet capacity of our
Redtail Niobrara gas plant to
70 MMcf of gas per day, up
from 20 MMcf per day.
(INSET) Roughnecks drilling
the Razor 26L-3503A well at
our Redtail Niobrara Field in
Weld County, Colorado.
Our first Niobrara “C” zone and Codell/Fort Hays formation tests continue to perform
well. The Razor 25B-2551 well, completed in the Codell/Fort Hays on September 9,
2014, averaged 397 BOE/d in its first 120 days on production. The Razor 25B-2549 well,
completed in the Niobrara “C” zone on September 11, 2014, averaged 384 BOE/d in its
first 120 days on production. Both wells were drilled on 640-acre spacing units and are
trending toward returns competitive with Niobrara “A” and “B” wells drilled on 960-acre
spacing units with estimated EURs of 450 MBOE per well.
NIOBRARA & CODELL
Inital 30-Day Average Rate
(Gas converted at price
equivalent ratio 15 to 1)
Pre-2013 Codell & Niobrara
2013–2015 Niobrara
2013–2015 Codell
LARAMIE
KIMBALL
Redtail
Field Area
BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB
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BOULDER
12
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NEW COMPLETION DESIGN BOLSTERS PRODUCTION
As a result of our new completion designs across all of our prospect areas in the Williston
Basin, we have experienced a 20% increase in initial production rates. We continue to
hone our completion techniques, including varying the number of completion stages,
utilizing different fracture stimulation fluids including slickwater, and increasing or
decreasing the volume of sand and ceramic proppant used. In 2015, we plan to continue
use of our state-of-the-art completion designs on the wells we drill in the Williston Basin.
We are also utilizing our completion techniques in the Niobrara formation in the DJ Basin
of Colorado with encouraging results.
COMMITMENT TO TECHNOLOGY
TECHNIQUE
AND
TECHNOLOGY
In each of our core operating areas, we
have accumulated extensive geologic and
geophysical knowledge and have develop-
ed significant technical and operational
expertise. In recent years, we have develop-
ed considerable expertise in conventional
and 3-D seismic imaging and interpreta-
tion. Our technical team has access to
approximately 9,100 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. We have a team
of 10 professionals averaging over 26 years of experience managing CO2 floods, which
provides us with the ability to pursue other CO2 flood targets and employ this technol-
ogy to add reserves to our portfolio. This commitment to technology has increased the
productivity and efficiency of our field operations and development activities.
(RIGHT) In 2014, we
expanded the inlet capacity
of our Robinson Lake Gas
Plant to 130 MMcf/d of gas.
In 2011, we completed the build-out and installation of an in-house, state-of-the-art
rock analysis laboratory at our Denver headquarters. We continue to utilize the data
from this rock lab to support real-time drilling and completion decisions, and to help
us to further understand unconventional oil plays.
14
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BOAR D OF D IR ECTOR S
JAMES J. VOLKER, 68, is Chairman of the
Board, President 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
President of Corporate Development and served
in that position through April 1993. In May 1993,
he became a contract consultant 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 President and later Pres-
ident of Energy Management Corporation from 1971 through 1982. He
has over 41 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, 66, has been a director
of Whiting Petroleum Corporation since 2003.
Mr. Aller retired as Senior Vice President of Oper-
ations Support for Alliant Energy Corporation
in 2014, has served as Senior Vice President —
Energy Resource Development 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, 78, has been a director
of Whiting Petroleum Corporation since 2006.
Mr. Artus joined Whiting Oil and Gas Corpora-
tion in January 1989 as Vice President of Oper-
ations and became Executive Vice President and
Chief Operating 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 52 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 Engi-
neering from the South Dakota School of Mines and Technology. 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.
JAMES E. CATLIN, 68, became a director of
Whiting Petroleum Corporation December 8,
2014. Mr. Catlin was a co-founder of Kodiak Oil
& Gas (USA), Inc. Mr. Catlin served as a director
of Kodiak since February 2001, Chairman of the
Board from July 2002 until June 2011, Secretary
from July 2002 to May 2008, Chief Operating
Officer from June 2006 until June 2011 and
Executive Vice President of Business Develop-
ment since June 2011. Mr. Catlin has nearly 40
years of geologic experience primarily in the
Rocky Mountain Region. Mr. Catlin was an
owner of CP Resources LLC, an independent oil
and natural gas company from 1986 to 2001. Mr. Catlin was a Founder,
Vice President and Director of Deca Energy from 1980 to 1986 and
worked as a district geologist for Petroleum Inc. and Fuelco prior to this
time. He received a Bachelor of Arts and a Master’s of Science Degree in
Geology from the University of Northern Illinois in 1973. Mr. Catlin has
extensive training and experience with respect to geology and executive
level experience working with oil and natural gas companies.
16
PHILIP E. DOTY, 71, 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 EKS&H LLP, the
largest Colorado-based accounting and consult-
ing 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, 63, 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 manage-
ment positions prior to that. He is a graduate of
Oklahoma University with a BS in petroleum
engineering and has 39 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, 77, 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 27 years he has operated Larson
Petroleum, LLC, a geological consulting com-
pany. His previous affiliations include Jade
Drilling Company, Belleview Capital Corpora-
tion, 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 Association of Geologists, the Wyoming Geological Association,
the Montana Geologic Society and the Utah Geologic Association.
LYNN A. PETERSON, 61, became a director
of Whiting Petroleum Corporation December 8,
2014. Mr. Peterson was a co-founder of Kodiak Oil
& Gas (USA), Inc. and was a director of Kodiak
since November 2001, President and Chief
Executive Officer since July 2002 and Chairman
of the Board since June 2011. Mr. Peterson has
over 30 years of industry experience. Mr. Peterson
was an independent oilman from 1986 to 2001
and served as Treasurer of Deca Energy from
1981 to 1986. He received a Bachelor of Science
in Accounting from the University of Northern
Colorado in 1975. Mr. Peterson has extensive
executive level experience working with oil and natural gas companies.
M I C H A E L B . WA L E N , 66, was elected
May 7, 2013 as a director of Whiting Petroleum
Corporation. Mr. Walen was the Senior Vice
President — Chief Operating Officer of Cabot
Oil and Gas Corporation from January 2001
until May 2010 and served in other manage-
ment and exploration positions prior to that
time. He has 40 years of exploration and
management experience with independent oil
and gas companies including PetroCorp Inc.,
Patrick Petroleum Co., TXO Production Co. and
Tenneco Oil Company. Mr. Walen holds a
Bachelor’s Degree in Geology from Central
Washington University and a Master’s Degree in Geology from Western
Washington University.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2014
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:
Common Stock, $0.001 par value
Preferred Share Purchase Rights
(Title of Class)
New York Stock Exchange
New York Stock Exchange
(Name of each exchange on which registered)
Securities registered pursuant to Section 12(g) of the Act: None.
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes No
Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities
Act. Yes No
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 No
Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Web site, if any, every
Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the
preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files). Yes No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not
be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III
of this Form 10-K or any amendment to this Form 10-K.
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller
reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2
of the Exchange Act. (Check one):
Large accelerated filer
Accelerated filer
Non-accelerated filer
Smaller reporting company
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No
Aggregate market value of the voting common stock held by non-affiliates of the Registrant at June 30, 2014: $9,569,978,297.
Number of shares of the Registrant’s common stock outstanding at February 13, 2015: 167,041,054 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the 2015 Annual Meeting of Stockholders are incorporated by reference into Part III.
Glossary of Certain Definitions ...........................................................................................................................................................
1
TABLE OF CONTENTS
PART I
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
Business ..........................................................................................................................................................................
Risk Factors ....................................................................................................................................................................
Unresolved Staff Comments ...........................................................................................................................................
Properties ........................................................................................................................................................................
Legal Proceedings...........................................................................................................................................................
Mine Safety Disclosures .................................................................................................................................................
Executive Officers of the Registrant ...............................................................................................................................
5
17
30
31
39
39
40
PART II
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities ........................................................................................................................................................................
Selected Financial Data ..................................................................................................................................................
Management’s Discussion and Analysis of Financial Condition and Results of Operations .........................................
Quantitative and Qualitative Disclosures About Market Risk ........................................................................................
Financial Statements and Supplementary Data ...............................................................................................................
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure .........................................
Controls and Procedures .................................................................................................................................................
Other Information ...........................................................................................................................................................
42
44
46
65
68
107
107
108
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Directors, Executive Officers and Corporate Governance ..............................................................................................
Executive Compensation ................................................................................................................................................
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters .......................
Certain Relationships, Related Transactions and Director Independence ......................................................................
Principal Accounting Fees and Services .........................................................................................................................
109
109
109
109
110
Item 15.
Exhibits, Financial Statement Schedules ........................................................................................................................
110
PART IV
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, used in reference to natural gas or CO2.
“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.
“delay rental” Consideration paid to the lessor by a lessee to extend the terms of an oil and natural gas lease in the absence of drilling
operations and/or production that is contractually required to hold the lease. This consideration is generally required to be paid on or
before the anniversary date of the oil and gas lease during its primary term, and typically extends the lease for an additional year.
“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.
“differential” The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil spot, and the wellhead
price received.
“dry hole” A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas
well.
“EOR” Enhanced oil recovery.
“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
1
condition” are intended to identify 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.
“ISDA” International Swaps and Derivatives Association, Inc.
“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, NGLs 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, used in reference to natural gas or CO2.
“MMBbl” One million Bbl.
“MMBOE” One million BOE.
“MMBtu” One million British Thermal Units.
“MMcf” One million cubic feet, used in reference to natural gas or CO2.
“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.
“plug-and-perf technology” A horizontal well completion technique in which hydraulic fractures are performed in multiple stages,
with each stage utilizing a bridge plug to divert fracture stimulation fluids through the casing perforations into the formation within
that stage.
“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 most 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 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
2
rate of 10%. Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC. See the footnote to the
Proved Reserves table in Item 1. “Business” of this Annual Report on Form 10-K for more information.
“probable reserves” Those reserves that are less certain to be recovered than proved reserves but which, together with proved
reserves, are as likely as not to be recovered.
“prospect” A property on which indications of oil or gas have been identified based on available seismic and geological information.
“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 scheduled to be
drilled within five years, unless specific circumstances justify a longer time. Under no circumstances shall estimates for proved
undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or
by other evidence using reliable technology establishing reasonable certainty.
“PUD” Proved undeveloped reserves.
“reasonable certainty” If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities
will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually
recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved
than not, and, as changes due to increased availability of geoscience (geological, geophysical and geochemical) engineering, and
economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely
to increase or remain constant than to decrease.
3
“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, CO2 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 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.
4
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 and Permian Basin 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
of proved reserves and exploration activities. As of December 31, 2014, our estimated proved reserves totaled 780.3 MMBOE,
representing a 78% increase in our proved reserves since December 31, 2013. Our 2014 average daily production was 114.5 MBOE/d
and results in an average reserve life of approximately 18.7 years.
The following table summarizes by core area, our estimated proved reserves as of December 31, 2014, their corresponding pre-tax
PV10% values, and our fourth quarter 2014 average daily production rates, as well as our company’s total standardized measure of
discounted future net cash flows as of December 31, 2014:
Proved Reserves (1)
Natural
Oil
NGLs
Gas
Total
%
(MMBbl)
(MMBbl)
(Bcf)
(MMBOE) Oil
Pre-Tax
PV10%
Value (2)
(in millions)
528.6
110.9
4.1
643.6
35.0
19.0
0.7
54.7
432.9
18.7
40.4
492.0
635.7
83%
$
12,517.9
133.0
83%
11.6
35%
1,460.9
156.6
780.3
82%
$
14,135.4
4th Quarter 2014
Average Daily
Production
(MBOE/d)
116.2
11.5
3.6
131.3
Core Area
Rocky Mountains (3) .............
Permian Basin ......................
Other (4) ................................
Total .............................
Discounted Future Income
Taxes ......................................................................................................................................
(3,292.0)
Standardized Measure of
Discounted Future Net
Cash Flows ............................................................................................................................ $
10,843.4
_____________________
(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, 2014, 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.
(3) Includes oil and gas properties located in Colorado, Montana, North Dakota, Utah and Wyoming.
(4) Other primarily includes oil and gas properties located in Arkansas, Michigan, Oklahoma and Texas.
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, such as the
Kodiak Acquisition discussed below under “Acquisitions and Divestitures”. We believe that our significant drilling inventory,
combined with our operating experience and cost structure, provides us with meaningful organic growth opportunities.
5
Our growth plan is centered on the following activities:
•
•
•
•
pursuing the development of projects that we believe will generate attractive rates of return;
allocating a portion of our exploration and development (“E&D”) budget to leasing and exploring prospect areas;
maintaining a balanced portfolio of lower risk, long-lived oil and gas properties that provide stable cash flows; and
seeking property acquisitions that complement our core areas, such as the Kodiak Acquisition discussed below under
“Acquisitions and Divestitures”.
During 2014, we incurred $3.2 billion in exploration, development and acreage expenditures including $3.0 billion for the drilling of
611 gross (257.1 net) wells. Of these new wells, 253.0 (net) resulted in productive completions and 4.1 (net) were unsuccessful,
yielding a 98% success rate.
Our current 2015 E&D budget is $2.0 billion, and included in this amount is approximately $59 million in acreage acquisition costs.
The 2015 budget of $2.0 billion represents a substantial decrease from the $3.2 billion in E&D (which amount also includes acreage
expenditures) we incurred in 2014. This reduced capital budget is in response to the significantly lower crude oil prices experienced
during the fourth quarter of 2014 and continuing into 2015. We expect to fund substantially all of our 2015 E&D budget using net
cash provided by operating activities, cash on hand, borrowings under our credit facility, or through the issuance of additional debt or
equity securities.
We continually evaluate our current portfolio and 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
Our significant acquisitions and divestitures during the last two years are summarized below. See “Management’s Discussion and
Analysis of Financial Condition and Results of Operations” in Item 7 of this Annual Report on Form 10-K for additional information
on these acquisitions and divestitures.
2014 Acquisitions. On December 8, 2014, we completed the acquisition of Kodiak Oil & Gas Corp. (now known as Whiting
Canadian Holding Company ULC, “Kodiak”) whereby we acquired all of the outstanding common stock of Kodiak (the “Kodiak
Acquisition”). Pursuant to the terms of the Kodiak Acquisition agreement, Kodiak shareholders received 0.177 of a share of Whiting
common stock in exchange for each share of Kodiak common stock they owned. Total consideration for the Kodiak Acquisition was
$1.8 billion, consisting of the 47,546,139 Whiting common shares issued at the market price of $37.25 per share on the date of
issuance plus the fair value of Kodiak’s outstanding equity awards assumed by Whiting. The aggregate purchase price of the
transaction was $4.3 billion, which includes the assumption of Kodiak’s outstanding debt of $2.5 billion as of December 8, 2014 and
the net cash acquired of $19 million.
As a result of the Kodiak Acquisition, Whiting acquired approximately 327,000 gross (178,000 net) acres located primarily in North
Dakota, including interests in 778 producing oil and gas wells and undeveloped acreage. Approximately 10,000 of the net acres
acquired were located in Wyoming and Colorado. The producing properties had estimated proved reserves of 191.8 MMBOE as of
the acquisition date, 86% of which are crude oil and NGLs.
The acquisition significantly expanded our presence in the Williston Basin, adding undeveloped acreage, oil and natural gas reserves
and production that were complementary to our existing asset base and operations in this area. As a result of this acquisition, we
became the largest Bakken/Three Forks producer in the Williston Basin as of the acquisition date.
2014 Divestitures. On March 27, 2014, we completed the sale of approximately 49,900 gross (41,000 net) acres in our Big Tex
prospect, which consisted mainly of undeveloped acreage as well as our interests in certain producing oil and gas wells, located in the
Delaware Basin of Texas for a cash purchase price of $76 million resulting in a pre-tax gain on sale of $12 million. With this
divestiture, we no longer own any interests in the Big Tex prospect.
2013 Acquisitions. On September 20, 2013, we completed the acquisition of approximately 39,300 gross (17,300 net) acres in the
Williston Basin, including interests in 121 producing oil and gas wells and undeveloped acreage, located in Williams and McKenzie
counties of North Dakota and Roosevelt and Richland counties of Montana for an initial purchase price of $261 million.
2013 Divestitures. On October 31, 2013, we completed the sale of approximately 45,000 gross (32,200 net) acres in our Big Tex
prospect, which consisted mainly of undeveloped acreage as well as our interests in certain producing oil and gas wells, located in the
Delaware Basin of Texas for a cash purchase price of $151 million, resulting in a pre-tax gain on sale of $11 million. Of the total net
acres sold, approximately 30,800 net acres were located in Pecos County, Texas, and approximately 1,400 net acres were located in
Reeves County, Texas. The producing properties had estimated proved reserves of 1.1 MMBOE as of December 31, 2012,
6
representing 0.3% of our proved reserves as of that date, and generated 0.2 MBOE/d of our third quarter 2013 average daily net
production.
On July 15, 2013, we completed the sale of our interests in certain oil and gas producing properties located in our EOR projects in the
Postle and Northeast Hardesty fields in Texas County, Oklahoma, including the related Dry Trail plant gathering and processing
facility, oil delivery pipeline, our entire 60% interest in the Transpetco CO2 pipeline, crude oil swap contracts and certain other related
assets and liabilities (collectively the “Postle Properties”) for a cash purchase price of $809 million after selling costs and post-closing
adjustments. This divestiture resulted in a pre-tax gain on sale of $109 million. We used the net proceeds from this sale to repay a
portion of the debt outstanding under our credit agreement. The Postle Properties consisted of estimated proved reserves of 45.1
MMBOE as of December 31, 2012, representing 11.9% of our proved reserves as of that date, and generated 8% (or 7.6 MBOE/d) of
our June 2013 average daily net production.
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 develop properties as well as to 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, 2014, we have assembled approximately 1,311,800 gross (811,700 net)
developed and undeveloped acres in the Williston Basin located in Montana and North Dakota. As of December 31, 2014, we had 16
drilling rigs operating in the Williston Basin. During 2014, the focus of our development in the Williston Basin continued in the
Sanish and Parshall, Lewis & Clark/Pronghorn, Hidden Bench/Tarpon, Missouri Breaks and Cassandra fields. Additionally, Whiting
owns a 50% ownership interest in two gas processing plants located in the Williston Basin. The Robinson Lake plant located in our
Sanish field has a current processing capacity of approximately 130 MMcf/d. Our Belfield plant located near the Pronghorn field
currently has inlet compression in place to process 35 MMcf/d. Both plants have fractionation capability to convert NGLs into
propane and butane, which end products can then be sold locally for higher realized prices. We are also currently constructing a 100%
owned gas processing plant in our Cassandra field which is expected to come online during the first quarter of 2015 with a processing
capacity of 15 MMcf/d.
A new area of focus for us is our Redtail field in the Denver Julesberg Basin (“DJ Basin”) in Weld County, Colorado, where we have
the potential to drill over 1,400 gross wells targeting several intervals in the Niobrara formation. As of December 31, 2014, we had
approximately 185,700 gross (132,200 net) acres, with four drilling rigs operating in this area. In April 2014, we completed the
construction of and brought online a gas processing plant for this area. The plant’s current inlet capacity is 20 MMcf/d, and we plan to
further expand the plant’s capacity to 70 MMcf/d in the second quarter of 2015. We expect our Redtail field will be another growth
platform for Whiting in 2015 and beyond.
Developing Existing Properties. Our current property base, which includes our acquisitions over the past 11 years, provides us with
numerous low-risk opportunities for exploration and development drilling. As of December 31, 2014, we have identified a drilling
inventory of over 5,600 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 unproved reserves. Additionally, we have 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 the North Ward Estes field, located in the Permian Basin of West Texas. We have experienced significant production
increases in this field through the use of secondary and tertiary recovery techniques, and we anticipate such production increases will
continue over the next five to seven years. In this field, we 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 approximately 290 MMcf/d of recycled CO2, thereby maximizing our recovery of oil and gas from this reservoir.
Growing Through Accretive Acquisitions. From 2004 to 2014, we completed 21 separate significant acquisitions of producing
properties for estimated proved reserves of 445.2 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, as demonstrated by the Kodiak Acquisition, which closed on December 8, 2014 and expanded our presence in
the Williston Basin located in Montana and North Dakota.
Disciplined Financial Approach. Our goal is to remain financially strong, yet flexible, through the prudent management of our
balance sheet and active management of our exposure to 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
7
and gas property 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, as we did with the sale of our
Postle Properties, which we completed on July 15, 2013. 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 oil and 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 the effective application of new technologies.
Balanced, Long-Lived Asset Base. As of December 31, 2014, we had interests in 11,654 gross (4,471 net) productive wells across
approximately 1,610,800 gross (886,700 net) developed acres across all our geographical areas. We believe this geographic mix of
properties and organic drilling opportunities, combined with our continuing business strategy of acquiring and developing properties
in these areas, presents us with multiple opportunities to execute our strategy. Our proved reserve life is approximately 18.7 years
based on year-end 2014 proved reserves and 2014 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 30 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 extensive 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 9,100 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. We have a team of 10 professionals averaging over 26 years of experience managing CO2 floods, which
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 an in-house, state-of-the-art rock analysis laboratory. We continue to utilize
the data from this rock lab to support real-time drilling and completion decisions, and to help us to further understand unconventional
oil plays. This knowledge has given us the confidence to assemble over 600,000 gross acres in four oil resource plays, located in three
separate basin areas that were new to us.
As a result of our successful testing of cemented liner and plug-and-perf completion designs across all of our prospect areas, in
January 2014 we began using this technique for all of our completions in the Williston Basin, resulting in a significant improvement in
initial production rates. We have continued to evaluate modifications to our completion techniques, including varying the number of
completion stages, utilizing different fracture stimulation fluids including slickwater, and increasing the volume of sand and ceramic
proppant used in these fluids. In 2015, we plan to continue use of our state-of-the-art completion design on a majority of the wells we
drill in the Williston Basin. We are also utilizing this completion technique in the Niobrara formation in the DJ Basin of Colorado
with encouraging results. We continue to refine our completion techniques to deliver improved results across all of our fields.
8
Proved, Probable and Possible Reserves
Our estimated proved, probable and possible reserves as of December 31, 2014 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 (1):
PDP ...............................................
PDNP ............................................
PUD ..............................................
Total proved ............................
Total probable .........................
Total possible ..........................
Oil
(MMBbl)
261.4
0.6
266.6
528.6
308.3
107.5
NGLs
(MMBbl)
18.9
0.1
16.0
35.0
10.0
8.8
Permian Basin:
PDP ...............................................
PDNP ............................................
PUD ..............................................
Total proved ............................
Total probable .........................
Total possible ..........................
53.4
14.4
43.1
110.9
23.9
71.2
Other (2):
PDP ...............................................
PDNP ............................................
PUD ..............................................
Total proved ............................
Total probable .........................
Total possible ..........................
3.5
0.3
0.3
4.1
2.0
1.4
Total Company:
PDP ...............................................
PDNP ............................................
PUD ..............................................
Total proved ............................
Total probable .........................
Total possible ..........................
318.3
15.3
310.0
643.6
334.2
180.1
5.8
3.6
9.6
19.0
8.3
16.9
0.5
0.1
0.1
0.7
0.4
0.1
25.2
3.8
25.7
54.7
18.7
25.8
Natural Gas
(Bcf)
Total
(MMBOE)
% of Total
Proved
Estimated
Future Capital
Expenditures
(in millions)
247.8
1.1
184.0
432.9
235.1
88.9
10.4
2.6
5.7
18.7
29.3
5.8
32.9
3.4
4.1
40.4
13.7
22.9
291.1
7.1
193.8
492.0
278.1
117.6
321.6
0.8
313.3
635.7
357.5
131.1
60.9
18.4
53.7
133.0
37.1
89.1
9.5
1.0
1.1
11.6
4.7
5.3
392.0
20.2
368.1
780.3
399.3
225.5
51%
-%
49%
100%
46%
14%
40%
100%
82%
9%
9%
100%
50%
3%
47%
100%
$
$
$
$
$
$
$
$
$
$
$
$
6,418.0
8,062.1
3,113.6
1,490.2
446.0
692.0
16.4
41.8
97.5
7,924.6
8,549.9
3,903.1
_____________________
(1) Includes oil and gas properties located in Colorado, Montana, North Dakota, Utah and Wyoming.
(2) Other primarily includes oil and gas properties located in Arkansas, Michigan, Oklahoma and Texas.
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 or transported by rail to terminals, market hubs,
refineries or storage facilities. The table below presents percentages by purchaser that accounted for 10% or more of our total oil,
9
NGL and natural gas sales for the years ended December 31, 2014, 2013 and 2012. 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.
Plains Marketing LP ........................................................................................
Shell Trading US .............................................................................................
Bridger Trading LLC .......................................................................................
Eighty Eight Oil Company ...............................................................................
2014
17%
10%
10%
6%
2013
21%
14%
8%
11%
2012
20%
14%
11%
11%
Title to Properties
Our properties are subject to customary royalty interests, liens securing 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 or
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 available investment capital 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, the 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 and NGLs can currently be made at unregulated 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 implements 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 the 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. In addition, the natural gas industry historically has always been heavily regulated.
10
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 Pipeline
Inspection, Protection, Enforcement and Safety Act of 2006 and the Pipeline Safety, Regulatory Certainty and Job Creation Act of
2012. In addition, intrastate natural gas transportation is subject to enforcement by state regulatory agencies, and the Pipeline and
Hazardous Material Safety Administration (“PHMSA”), an agency within the DOT, enforces regulations on interstate natural gas
transportation. 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 by 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, 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. The 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 the 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 the 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.
In addition, the FERC has emergency authority under the Interstate Commerce Act to intervene and direct priority use of oil pipeline
transportation capacity, and the FERC has exercised this authority over a specific pipeline in February 2014 in response to significant
disruptions in the supply of propane. 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.
A portion of our crude oil production may be shipped to market centers using rail transportation facilities owned and operated by third
parties. The DOT and PHMSA establish safety regulations relating to crude-by-rail transportation. In addition, third-party rail
operators are subject to the regulatory jurisdiction of the Surface Transportation Board of the DOT, the Federal Railroad
Administration (the “FRA”) of the DOT, OSHA and other federal regulatory agencies. Additionally, various state and local agencies
have jurisdiction over disposal of hazardous waste and seek to regulate movement of hazardous materials in ways not preempted by
federal law.
11
In response to rail accidents occurring between 2002 and 2008, the U.S. Congress passed the Rail Safety and Improvement Act of
2008, which implemented regulations governing different areas related to railroad safety. In response to train derailments occurring in
the United States and Canada in 2013 and 2014, U.S. regulators are implementing or considering new rules to address the safety risks
of transporting crude oil by rail.
On February 25, 2014 the DOT issued an emergency order requiring all persons to ensure crude oil is properly tested and classed prior
to offering such product into transportation, and to assure all shipments by rail of crude oil be handled as a Packing Group I or II
hazardous material. Also in February 2014, the Association of American Railroads entered into a voluntary agreement with the DOT
to implement certain restrictions around the movement of crude oil by rail. In May 2014, the DOT issued an Emergency
Restriction/Prohibition Order requiring each railroad carrier operating trains transporting 1,000,000 gallons or more of Bakken crude
oil to provide notice to state officials regarding the expected movement of the trains through the counties in each state. The PHMSA
and FRA have also issued safety advisories and alerts regarding oil transportation, have issued a report focused on the increased
volatility and flammability of Bakken crude oil as compared with other crudes in the U.S. and have various rulemaking proceedings
underway.
We do not currently own or operate rail transportation facilities or rail cars. However, the adoption of any regulations that impact the
testing or rail transportation of crude oil could increase our costs of doing business and limit our ability to transport and sell our crude
oil at favorable prices at market centers throughout the U.S., the consequences of which could have a material adverse effect on our
financial condition, results of operations and cash flows. The effect of any such regulatory changes 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 the 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
that 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
(the “BOEM”). Currently, none of our total production volumes are produced from offshore leases. However, the present value of
our future abandonment obligations associated with offshore properties was $36 million as of December 31, 2014. Whiting is
therefore required to comply with the regulations and orders issued by the 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 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, the BOEM could require us to suspend or terminate our operations on a federal lease.
The 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 the 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.
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
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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 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 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:
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to remove or remediate previously disposed materials, including materials disposed or released by prior owners or operators or
other third parties;
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 million per spill, while the liability limit for offshore facilities is the payment of all
removal costs plus $75 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
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 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
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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 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, as amended (the “CAA”), 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, in 2012, the EPA finalized rules establishing 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 require the application of reduced emission completion
techniques associated with the 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
from tight rock 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, Texas and Wyoming, 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
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complete or recomplete wells in those areas. The process is typically regulated by state oil and gas commissions. However, the EPA
recently issued guidance, which was published in the Federal Register on February 12, 2014, for permitting authorities and the
industry regarding the process for obtaining a permit for hydraulic fracturing involving diesel.
At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities on
drinking water resources. In addition, the EPA is currently studying wastewater and stormwater discharges from hydraulic fracturing
facilities. A proposed rule to amend the Effluent Limitations Guidelines and Standards for the oil and gas extraction category which
would address discharges of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned
treatment works is expected in early 2015. The EPA announced in 2015 that it would directly regulate methane emissions from oil
and natural gas wells for the first time as part of President Obama’s Climate Action Plan. As part of this strategy, the EPA will
propose in the summer of 2015 a rule to set methane and volatile organic compound emissions standards for new and modified oil and
natural gas wells. The final rule is expected in 2016. Other federal agencies are also examining hydraulic fracturing, including the
U.S. Department of Energy, the U.S. Government Accountability Office and the White House Council for Environmental Quality.
The U.S. Department of the Interior released a draft proposed rule in May 2012 governing hydraulic fracturing on federal and Indian
oil and natural gas leases to require disclosure of information regarding the chemicals used in hydraulic fracturing, advance approval
for well-stimulation activities, mechanical integrity testing of casing and monitoring of well-stimulation operations, and on May 24,
2013 the Federal Bureau of Land Management issued a revised draft of the proposed rule. In addition, legislation has been introduced
in Congress from time to time 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 ban, restrict
or impose additional requirements on activities 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 in Texas) 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, litigation risk and potential
increases in costs. Further, local governments may seek to adopt, and some have adopted, ordinances within their jurisdictions
restricting the use of or regulating the time, place and manner of drilling or hydraulic fracturing. 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, regulations or ordinances that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted
in the states or local municipalities where our properties are located, such legal requirements could prohibit or 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 and the calculation of our reserves.
In addition, on July 3, 2014, a major university and U.S. Geological Survey researchers published a study purporting to find a causal
connection between the deep well injection of hydraulic fracturing wastewater and a sharp increase in seismic activity in Oklahoma
since 2008. Such studies may trigger new legislation or regulations that would limit or ban the disposal of hydraulic fracturing
wastewater in deep injection wells. If such new laws or rules are adopted, our operations may be curtailed while alternative treatment
and disposal methods are developed and approved.
Further, on May 19, 2014, the EPA published an Advance Notice of Proposed Rulemaking (“ANPR”) under the Toxic Substances
Control Act, relating to the disclosure of chemical substances and mixtures used in oil and gas exploration and production. Depending
on the precise disclosure requirements the EPA elects to impose, if any, we may be obliged to disclose valuable proprietary
information, and failure to do so may subject us to penalties.
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 (the “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 becoming 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
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annual basis with reporting beginning in 2012 for emissions occurring in 2011. We believe that we are in compliance with all
substantial applicable emissions requirements, and we are preparing to comply with future requirements.
In June 2014, the Supreme Court upheld most of the EPA’s GHG permitting requirements, allowing the agency to regulate the
emission of GHG from stationary sources already subject to the PSD and Title V requirements. Certain of our equipment and
installations may currently be subject to PSD and Title V requirements and hence, under the Supreme Court’s ruling, may also be
subject to the installation of controls to capture GHG. For any equipment or installation so subject, we may have to incur increased
compliance costs to capture related GHG emissions.
The EPA took additional action under the CAA in June 2014. In accordance with President Obama’s Climate Action Plan, on June
18, 2014, the EPA proposed rules to reduce carbon emissions from electric generating units. The proposal, commonly called the
“Clean Power Plan,” requires states to develop plans to reduce carbon emissions from fossil fuel-fired generating units commencing in
2020, with the reductions to be fully phased in by 2030. Each state is given a different carbon reduction target, but the EPA expects
that, in the aggregate, the overall proposal will reduce carbon emissions from electric generating units by 30% from 2005 levels. As
proposed, states are given substantial flexibility in meeting their emission reduction targets and can generally choose to lower carbon
emissions by replacing higher carbon generation, such as coal or natural gas, with lower carbon generation, such as efficient natural
gas units or renewable energy alternatives. It is not possible at this time to predict what requirements might be adopted by the EPA in
the final rule expected in 2015, or how any such final rule would impact our business.
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, NGLs and natural
gas that we produce. Finally, it should be noted that many 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.
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, 2014, we had 1,282 full-time employees, including 43 senior level geoscientists and 84 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 reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, including
exhibits and amendments to these reports, as soon as reasonably practicable after we electronically file such material with, or furnish
such material to, the SEC.
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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. In the event of the occurrence,
reoccurrence, continuation or increased severity of any of the risks described below, 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:
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changes in regional, domestic and global supply and demand for oil and natural gas;
the actions of the Organization of Petroleum Exporting Countries;
the level of global oil and natural gas inventories;
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;
developments of United States energy infrastructure, such as President Obama’s recent veto of legislation that would have
allowed the Keystone XL pipeline from Hardesty, Alberta to Cushing, Oklahoma to proceed 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.
These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price
movements. Also, prices for oil and prices for natural gas do not necessarily move in tandem. Declines in oil or natural gas prices
would not only reduce revenue but could reduce the amount of oil and natural gas that we can economically produce. If the oil and
natural gas industry experiences significant price declines, we may, among other things, be unable to meet all of our financial
obligations or make planned expenditures.
Oil prices have fallen significantly since reaching highs of over $105.00 per Bbl in June 2014, dropping below $45.00 per Bbl in
January 2015. Natural gas prices have also declined from over $4.80 per Mcf in April 2014 to below $2.60 per Mcf in February 2015.
In addition, forecasted prices for both oil and gas for 2015 have also declined.
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. At the time of the last
redetermination, the applicable oil and gas prices were $92.68 per Bbl and $3.88 per Mcf, whereas the quoted NYMEX prices for oil
and gas on February 13, 2015 were $53.67 per Bbl and $2.81 per Mcf.
Alternatively, higher oil and natural gas prices may result in significant mark-to-market losses being incurred on our commodity-based
derivatives, which may in turn cause us to experience net losses.
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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 exploration, development and production activities. Our oil and natural gas
exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in
commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or
properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and
engineering studies, the results of which are often inconclusive or subject to varying interpretations. Please read “— Reserve
estimates depend on many assumptions that may turn out to be inaccurate...” later in these Risk Factors for a discussion of the
uncertainty involved in these processes. Our cost of drilling, completing and operating wells is often uncertain before drilling
commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many
factors may curtail, delay or cancel drilling, including the following:
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delays imposed by or resulting from compliance with regulatory requirements;
delays or limits on the issuance of drilling permits on our federal leases, including as a result of government shutdowns;
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.
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, 2014, we had $1.4 billion in borrowings and $3 million in letters of credit outstanding under Whiting Oil and Gas
Corporation’s (“Whiting Oil and Gas”) credit facility with $3.1 billion of available borrowing capacity, as well as $3.9 billion of
senior notes outstanding and $350 million of senior subordinated notes outstanding. We are allowed to incur additional indebtedness,
provided that we meet certain requirements in the indentures governing our senior notes and our senior subordinated notes and
Whiting Oil and Gas’ credit agreement.
Our level of indebtedness and the covenants contained in the agreements governing our debt could have important consequences for
our operations, including:
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requiring us to dedicate a substantial portion of our cash flow from operations to required payments on debt, thereby reducing
the availability of cash flow for working capital, capital expenditures and other general business activities;
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; and
making us vulnerable to increases in interest rates, because debt under Whiting Oil and Gas’ credit agreement is subject to
certain rate variability.
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 would 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’ credit agreement is periodically redetermined based on an evaluation of our oil and gas reserves. Because oil
and gas prices are principal inputs into the valuation of our reserves, if oil and gas prices remain at their current levels for a prolonged
period or go lower, our borrowing base could be reduced at the next redetermination date or during future redeterminations. 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 outstanding under the credit agreement.
We may not have sufficient funds to make such repayments. If we are unable to repay our debt out of cash on hand, we could attempt
to refinance such debt, sell assets or repay such debt with the proceeds from an equity offering. We may not be able to generate
sufficient cash flow to pay the interest on our debt or future borrowings, and equity financings or proceeds from the sale of assets may
not be available to pay or refinance such debt. The terms of our debt, including Whiting Oil and Gas’ credit agreement, may also
prohibit us from taking such actions. Factors that will affect our ability to raise cash through an offering of our capital stock, a
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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.
In conjunction with the Kodiak Acquisition in December 2014, we assumed Kodiak’s outstanding principal amount of $800 million of
8.125% Senior Notes due December 2019, $350 million of 5.5% Senior Notes due January 2021 and $400 million of 5.5% Senior
Notes due February 2022 (the “Kodiak Notes”). On January 7, 2015, as required under the terms of the indentures governing the
Kodiak Notes (the “Kodiak Indentures”) upon a change in control of Kodiak, we offered to repurchase at 101% of par all $1,550
million principal amount of Kodiak Notes outstanding. The repurchase offer expires on March 3, 2015. We expect to fund any
payments due as a result of such repurchase offer with borrowings under our revolving credit facility, which would reduce availability
under such facility.
Federal, state and local 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 rock
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, Texas and Wyoming, 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 U.S.
Environmental Protection Agency (the “EPA”) recently issued guidance, which was published in the Federal Register on February 12,
2014, for permitting authorities and the industry regarding the process for obtaining a permit for hydraulic fracturing involving diesel.
At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities on
drinking water resources. In addition, the EPA is currently studying wastewater and stormwater discharges from hydraulic fracturing
facilities. A proposed rule to amend the Effluent Limitations Guidelines and Standards for the oil and gas extraction category which
would address discharges of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned
treatment works is expected in early 2015. The EPA announced in 2015 that it would directly regulate methane emissions from oil
and natural gas wells for the first time as part of President Obama’s Climate Action Plan. As part of this strategy, the EPA will
propose in the summer of 2015 a rule to set methane and volatile organic compound emissions standards for new and modified oil and
natural gas wells. The final rule is expected in 2016. Other federal agencies are also examining hydraulic fracturing, including the
U.S. Department of Energy, the U.S. Government Accountability Office and the White House Council for Environmental Quality.
The U.S. Department of the Interior released a draft proposed rule in May 2012 governing hydraulic fracturing on federal and Indian
oil and natural gas leases to require disclosure of information regarding the chemicals used in hydraulic fracturing, advance approval
for well-stimulation activities, mechanical integrity testing of casing and monitoring of well-stimulation operations, and on May 24,
2013 the Federal Bureau of Land Management issued a revised draft of the proposed rule. In addition, legislation has been introduced
in Congress from time to time 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 ban, restrict
or impose additional requirements on activities 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 in Texas) 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, litigation risk and potential
increases in costs. Further, local governments may seek to adopt, and some have adopted, ordinances within their jurisdictions
restricting the use of or regulating the time, place and manner of drilling or hydraulic fracturing. 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, regulations or ordinances that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted
in the states or local municipalities where our properties are located, such legal requirements could prohibit or 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 and the calculation of our reserves.
In addition, on July 3, 2014, major university and U.S. Geological Survey researchers published a study purporting to find a causal
connection between the deep well injection of hydraulic fracturing wastewater and a sharp increase in seismic activity in Oklahoma
since 2008. Such studies may trigger new legislation or regulations that would limit or ban the disposal of hydraulic fracturing
wastewater in deep injection wells. If such new laws or rules are adopted, our operations may be curtailed while alternative treatment
and disposal methods are developed and approved.
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Further, on May 19, 2014, the EPA published an Advance Notice of Proposed Rulemaking (“ANPR”) under the Toxic Substances
Control Act, relating to the disclosure of chemical substances and mixtures used in oil and gas exploration and production. Depending
on the precise disclosure requirements the EPA elects to impose, if any, we may be obliged to disclose valuable proprietary
information, and failure to do so may subject us to penalties.
Refer to “Hydraulic Fracturing” in Item 2 of this Annual Report on Form 10-K for more information on hydraulic fracturing.
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 $587 million
impairment write-down during 2014 for the partial impairment of non-core oil and gas producing properties, which are not currently
being developed, in Colorado, Louisiana, North Dakota and Utah related to the decrease in oil and gas prices at December 31, 2014.
A write-down constitutes a non-cash charge to earnings. Oil and gas prices have continued to decline since December 31, 2014 which
may cause us to incur additional impairments that could have a material adverse effect on our results of operations in the period
recognized.
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 injection 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, 2014, proved undeveloped reserves comprised 40% of the North Ward Estes field’s total estimated proved
reserves. To fully develop these reserves, we expect to incur future development costs of $762 million at the North Ward Estes field
as of December 31, 2014. This field encompasses 11% 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 that is ready to drill to a prospect
that will require substantial additional seismic data processing and interpretation. There is no way to predict in advance of drilling and
testing whether any particular prospect will yield oil or gas in sufficient quantities to recover drilling or completion costs or to be
economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable
us to know conclusively prior to drilling whether oil or gas will be present or, if present, whether oil or gas will be present in
commercially viable 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.
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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:
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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 will most likely 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. The 12-month average prices used for the year ended December 31, 2014 were $94.99 per Bbl and $4.35 per Mcf, whereas
the quoted NYMEX prices for oil and gas on February 13, 2015 were $53.67 per Bbl and $2.81 per Mcf. Actual future prices and
costs may differ materially from those used in the estimate. If natural gas prices decline by $0.10 per Mcf, then the standardized
measure of discounted future net cash flows of our estimated proved reserves as of December 31, 2014 would have decreased by
$21 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, 2014 would have decreased by $179 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 develop and produce 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, state and local legislative and regulatory initiatives relating to hydraulic
fracturing...” above in these Risk Factors for a discussion of the uncertainty involved in the regulation of hydraulic fracturing. Also,
our oil, NGL and natural gas production depends in large part on the proximity and capacity of pipeline systems and transportation
facilities which are mostly owned by third parties. The lack of availability or the lack of capacity on these systems and facilities could
result in the curtailment of production or the delay or discontinuance of drilling plans. Similarly, curtailments or damage to pipelines
and other transportation facilities used to transport oil, NGLs and natural gas production to markets for sale could decrease revenues
or increase transportation expenses. Any such curtailments 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, there have been recent accidents involving rail cars carrying Bakken formation crude oil, which resulted in the U.S. Department
of Transportation (the “DOT”) issuing an emergency order on February 25, 2014 that requires rail shippers to test the makeup of such
crude oil before transporting it. This move follows the safety alert the DOT issued in January 2014 that Bakken formation crude oil is
more flammable than other types of crude oil and has been followed by additional emergency orders and safety advisories and alerts.
An accident involving rail cars could result in significant personal injuries and property and environmental damage. Additionally,
added regulations currently being considered in response to such accidents could result in additional costs that could increase
transportation expenses.
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In addition, drilling, production and transportation of hydrocarbons bear the 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.
The instruments governing our indebtedness contain various covenants limiting the discretion of our management in operating
our business.
The indentures governing our senior notes and our senior subordinated notes and Whiting Oil and Gas’ credit agreement contain
various restrictive covenants that may limit our management’s discretion in certain respects. In particular, these agreements will limit
our and our subsidiaries’ ability to, among other things:
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pay dividends on, redeem or repurchase our capital stock or redeem or repurchase our senior or 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’ 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 4.0 to 1.0 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 notes and our
senior subordinated notes restrict us from incurring additional indebtedness and making certain restricted payments, subject to certain
exceptions, unless our fixed charge coverage ratio (as defined in the indentures) is at least 2.0 to 1. The Kodiak Indentures restrict us
from incurring additional indebtedness and making certain restricted payments, subject to certain exceptions, unless our fixed charge
coverage ratio (as defined in the indentures) is at least 2.25 to 1. If we were in violation of these covenants, then we may not be able
to incur additional indebtedness, including under Whiting Oil and Gas’ credit agreement. A substantial or extended decline in oil or
natural gas prices may adversely affect our ability to comply with these covenants.
If we fail to comply with the restrictions in the indentures (including the Kodiak Indentures) governing our and Kodiak’s senior notes
and our senior subordinated notes or Whiting Oil and Gas’ credit agreement or any other subsequent financing agreements, a default
may allow the creditors, if the agreements so provide, to accelerate the related indebtedness as well as any other indebtedness to which
a cross-acceleration or cross-default provision applies. In addition, lenders may be able to terminate any commitments they had made
to make 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, internally generated cash flows,
agreements with industry partners and oil and gas property divestments. We intend to finance future capital expenditures with cash
flow from operations, cash on hand and financing arrangements. Our cash flow from operations and access to capital is subject to a
number of variables, including:
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our proved reserves;
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.
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If our revenues or the borrowing base under our credit agreement decrease as a result of lower oil and natural gas prices, operating
difficulties, declines in reserves, or for any other reason, then we may have limited ability to obtain the capital necessary to sustain our
operations at current levels.
We may, from time to time, need to seek additional financing. There can be no assurance as to the availability or terms of any
additional financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or
at all. If cash generated by operations or available under our revolving credit facility is not sufficient to meet our capital requirements,
the failure to obtain additional financing could result in a curtailment of our operations relating to the exploration and development of
our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves.
Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production.
Failure to drill sufficient wells in order to hold acreage will result in substantial lease renewal costs, or if renewal is not feasible,
loss of our lease and prospective drilling opportunities.
Unless production is established on our undeveloped acreage, the underlying leases will expire. As of December 31, 2014, the portion
of our net undeveloped acreage that is subject to expiration over the next three years, if not successfully developed or renewed, is
approximately 26% in 2015, 29% in 2016 and 13% in 2017. The cost to renew such leases may increase significantly, and we may
not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party
leases become immediately effective if our leases expire. As such, our actual drilling activities may materially differ from our current
expectations, which could adversely affect our business.
Our acquisition activities may not be successful.
As part of our growth strategy, we have made and may continue to make acquisitions of businesses and properties. However, suitable
acquisition candidates may not continue to be available on terms and conditions we find acceptable, and acquisitions pose substantial
risks to our business, financial condition and results of operations. In pursuing acquisitions, we compete with other companies, many
of which have greater financial and other resources to acquire attractive companies and properties. The following are some of the
risks associated with acquisitions, including any completed or future acquisitions:
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some of the acquired businesses or properties may not produce revenues, reserves, earnings or cash flow at anticipated levels;
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;
we may issue additional equity or debt securities in order to fund future acquisitions; and
we may incur losses as a result of title defects.
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 for production, such as CO2, 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.
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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, 2014, we had identified a drilling inventory of over 5,600 gross drilling locations. These
scheduled drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends
on a number of uncertainties, including oil and natural gas prices, the availability of capital, costs of oil field goods and services,
drilling results, our 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 in turn 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, 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 2014, we recorded a $45 million non-cash charge for the impairment of unproved oil and gas
properties in Louisiana, Michigan, Montana, North Dakota and Texas, as well as a $21 million non-cash charge for the impairment of
unproved CO2 properties in New Mexico. 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 2014, we completed 21 separate significant
acquisitions of producing properties with a combined purchase price of $6.4 billion for estimated proved reserves as of the effective
dates of the acquisitions of 445.2 MMBOE. The successful acquisition of producing properties requires assessment of many factors,
which are inherently inexact and may be inaccurate, including the following:
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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
the assumption of unknown potential environmental and other liabilities, losses or costs, including for example, historical spills
or releases for which we are not indemnified or for which our indemnity is inadequate.
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.
We may not be able to replace the reserves on properties we divest, and the agreements pursuant to which assets we divest may
contain continuing indemnification obligations.
Part of our business strategy includes selling 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. Unless we conduct
successful exploration, development and production activities or acquire properties containing proved reserves, divestitures of our
properties will reduce our proved reserves and potentially our production. We may not be able to develop, find or acquire additional
reserves sufficient to replace such reserves and production from any of the properties we sell. Additionally, agreements pursuant to
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which we sell properties may include terms that survive closing of the sale, including indemnification provisions, which could obligate
us to substantial liabilities.
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 options contracts,
primarily costless collars and swap contracts, placed with major financial institutions. As of February 13, 2015, we had contracts
covering the sale of between 444,700 and 968,360 barrels of oil per month for all of 2015. All of our oil hedges will expire by
December 2017. See “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A of this Annual Report on Form 10-K
for pricing information 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. Our three-way collars only provide partial protection against declines in market prices
due to the fact that when the market price falls below the sub-floor, the minimum price we will receive will be NYMEX plus the
difference between the floor and the sub-floor. Furthermore, if we do not engage in hedging transactions or unwind hedging
transactions 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, cause temporary declines in our oil and gas production 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.
We may incur substantial losses and be subject to substantial liability claims as a result of our oil and gas operations.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and
adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities
are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:
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environmental hazards, such as uncontrollable flows of oil, gas, brine, well fluids, toxic gas or other pollution into the
environment, including groundwater and shoreline contamination;
abnormally pressured formations;
mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
the loss of well control;
fires and explosions;
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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.
We operate 70% of our net productive oil and natural gas wells, which represents 85% of our proved developed producing reserves as
of December 31, 2014. 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 do, and we could incur losses as a result of such expenditures. Thus, some of our
drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in
a particular area could decline. We often gather 3-D seismic data over large areas. Our interpretation of seismic data delineates for us
those portions of an area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights
prior to acquiring seismic data, and in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the
location. If we are not able to lease those locations on acceptable terms, it would result in our having made substantial expenditures to
acquire and analyze 3-D seismic data without having an opportunity to attempt to benefit from those expenditures.
Market conditions or operational impediments may hinder our access to oil and gas markets or delay our production.
In connection with our continued development of oil and gas properties, we may be disproportionately exposed to the impact of delays
or interruptions of production from wells in these properties, caused by transportation capacity constraints, curtailment of production
or the interruption of transporting oil and gas volumes produced. In addition, market conditions or a lack of satisfactory oil and gas
transportation arrangements may hinder our access to oil and gas markets or delay our production. The availability of a ready market
for our oil, 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:
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discharge permits for drilling operations;
drilling bonds;
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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 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, in 2012, the EPA published final rules under the Federal Clean Air Act that subject oil and natural gas production,
processing, transmission and storage operations to regulation under the New Source Performance Standards and National Emission
Standards for Hazardous Air Pollutants. With regards to production activities, these rules require, among other things, the reduction
of volatile organic compound emissions from certain fractured and refractured gas wells for which well completion operations are
conducted and, in particular, requiring some of these wells to use reduced emission completions, also known as “green completions,”
after January 1, 2015. These regulations also establish specific new requirements regarding emissions from production-related wet
seal and reciprocating compressors, pneumatic controllers and storage vessels. 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 gases could result in increased operating costs and
reduced demand for oil and gas that we produce.
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 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 (the “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 June 2014, the Supreme Court upheld most of the EPA’s GHG permitting requirements, allowing the agency to regulate the
emission of GHG from stationary sources already subject to the PSD and Title V requirements. Certain of our equipment and
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installations may currently be subject to PSD and Title V requirements and hence, under the Supreme Court’s ruling, may also be
subject to the installation of controls to capture GHGs. For any equipment or installation so subject, we may have to incur increased
compliance costs to capture related GHG emissions.
The EPA took additional action under the CAA in June 2014. In accordance with President Obama’s Climate Action Plan, on June
18, 2014, the EPA proposed rules to reduce carbon emissions from electric generating units. The proposal, commonly called the
“Clean Power Plan,” requires states to develop plans to reduce carbon emissions from fossil fuel-fired generating units commencing in
2020, with the reductions to be fully phased in by 2030. Each state is given a different carbon reduction target, but the EPA expects
that, in the aggregate, the overall proposal will reduce carbon emissions from electric generating units by 30% from 2005 levels. As
proposed, states are given substantial flexibility in meeting their emission reduction targets and can generally choose to lower carbon
emissions by replacing higher carbon generation, such as coal or natural gas, with lower carbon generation, such as efficient natural
gas units or renewable energy alternatives. It is not possible at this time to predict what requirements might be adopted by the EPA in
the final rule expected in 2015, or how any such final rule would impact our business.
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 many 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.
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 exploration, development and production 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 producing
our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, 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, President and Chief Executive Officer; Peter W. Hagist,
Senior Vice President, Planning; Rick A. Ross, Senior Vice President, Operations; Mark R. Williams, Senior Vice President,
Exploration and Development; Steven A. Kranker, Vice President, Reservoir Engineering/Acquisitions; David M. Seery, Vice
President, Land; or Michael J. Stevens, Vice President and Chief Financial Officer, 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 allow for. 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.
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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 2015, President Obama’s Administration released its proposed federal budget for fiscal year 2016 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:
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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 U.S. oil and gas 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.
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.
We depend on computer and telecommunications systems, and failures in our systems or cyber security attacks could significantly
disrupt our business operations.
We have entered into agreements with third parties for hardware, software, telecommunications and other information technology
services in connection with our business. In addition, we have developed proprietary software systems, management techniques and
other information technologies incorporating software licensed from third parties. It is possible we could incur interruptions from
cyber security attacks, computer viruses or malware. We believe that we have positive relations with our related vendors and maintain
adequate anti-virus and malware software and controls; however, any interruptions to our arrangements with third parties for our
computing and communications infrastructure or any other interruptions to our information systems could lead to data corruption,
communication interruption or otherwise significantly disrupt our business operations.
We may experience difficulties in integrating Kodiak into our businesses, which could cause the combined company to fail to
realize many of the anticipated potential benefits of the Kodiak Acquisition.
We acquired Kodiak with the expectation that the acquisition would result in various benefits, including, among other things,
operating efficiencies and cost savings. Achieving the anticipated benefits of the Kodiak Acquisition will depend in part upon
whether our two companies integrate our businesses in an efficient and effective manner. We may not be able to accomplish this
integration process successfully. The difficulties of combining the two companies’ businesses potentially will include, among other
things:
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the necessity of addressing possible differences, incorporating cultures and management philosophies and the integration of
certain operations following the transaction will require the dedication of significant management resources, which may
temporarily distract management’s attention from the day-to-day business of the combined company; and
any inability of our management to cause best practices to be applied to the combined company’s business.
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An inability to realize the full extent of the anticipated benefits of the transaction, as well as any delays encountered in the transition
process, could have an adverse effect upon the revenues, level of expenses and operating results of the combined company, which may
affect the value of our common stock.
The market price of our common stock may decline in the future as a result of the Kodiak Acquisition.
The market price of our common stock may decline in the future as a result of the Kodiak Acquisition for a number of reasons,
including the unsuccessful integration of Kodiak (including the reasons set forth in the preceding risk factor) or our failure to achieve
the perceived benefits of the Kodiak Acquisition, including financial and operating results, as rapidly as or to the extent anticipated by
financial or industry analysts. These factors are, to some extent, beyond our control.
Item 1B. Unresolved Staff Comments
None.
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Item 2. Properties
Summary of Oil and Gas Properties and Projects
Rocky Mountains Region
Our Rocky Mountains operations include assets in the states of Colorado, Montana, North Dakota, Utah and Wyoming. As of
December 31, 2014, our estimated proved reserves in the Rocky Mountains region were 635.7 MMBOE (83% oil), which represented
81% of our total estimated proved reserves and contributed 116.2 MBOE/d of average daily production in the fourth quarter of 2014.
Sanish and Parshall Fields. Our Sanish and Parshall fields in Mountrail County, North Dakota target the Bakken and Three Forks
formations and encompass approximately 169,900 gross (82,600 net) developed and undeveloped acres. Net production in the Sanish
and Parshall fields averaged 45.0 MBOE/d for the fourth quarter of 2014, representing a 2% decrease from 46.1 MBOE/d in the third
quarter of 2014. As of December 31, 2014, we had three drilling rigs active in the Sanish field. Based on the success of our high
density pilot programs in the Sanish field, we commenced a development program drilling nine Bakken wells per spacing unit in the
area, an increase over our original plan of three to four wells per spacing unit. Additionally, we have implemented a new slickwater
fracture stimulation method using cemented liners at the Sanish field and are encouraged by the initial results.
In order to process the produced gas stream from the Sanish wells, we constructed and brought on-line the Robinson Lake gas plant.
The plant has a current processing capacity of 130 MMcf/d and fractionation equipment that allows us to convert NGLs into propane
and butane, which end products can then be sold locally for higher realized prices.
Lewis & Clark/Pronghorn Fields. Our Lewis & Clark/Pronghorn fields 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 and 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). As of December 31, 2014, the
Lewis & Clark/Pronghorn fields encompassed approximately 339,200 gross (227,400 net) developed and undeveloped acres. Net
production in the Lewis & Clark/Pronghorn fields averaged 16.4 MBOE/d in the fourth quarter of 2014, representing a 2% decrease
from 16.7 MBOE/d in the third quarter of 2014. As of December 31, 2014, we had one drilling rig operating in the Pronghorn field,
which utilizes drilling pads, with two or three wells being drilled from each pad. We have implemented our new completion design in
this field utilizing cemented liners and plug-and-perf technology based on our successful testing of this completion technique in 2013.
Additionally, we are evaluating our slickwater fracture stimulation method at the Pronghorn field and are encouraged by the results.
At our gas processing plant located south of Belfield, North Dakota, which primarily processes production from the Pronghorn area,
there is currently inlet compression in place to process 35 MMcf/d. As of December 31, 2014 the plant was processing over 23
MMcf/d. In May 2012, we sold a 50% ownership interest in the plant, gathering systems and related facilities. We retained a 50%
ownership interest and continue to operate the Belfield plant and facilities.
Hidden Bench/Tarpon Fields. Our Hidden Bench and Tarpon fields in McKenzie County, North Dakota target the Bakken and Three
Forks formations and encompass approximately 121,300 gross (69,000 net) developed and undeveloped acres and 18,800 gross
(13,900 net) developed and undeveloped acres, respectively, as of December 31, 2014. Net production at Hidden Bench/Tarpon
averaged 22.6 MBOE/d in the fourth quarter of 2014, which represents a 40% increase from 16.2 MBOE/d in the third quarter of
2014. Contributing to this period over period production increase was net production added as a result of the Kodiak Acquisition
totaling 10.7 MBOE/d from December 8, 2014, the closing date of the acquisition, through December 31, 2014. As of December 31,
2014, we had four drilling rigs active in the Hidden Bench field. We have also implemented our new completion design at our Hidden
Bench/Tarpon fields, utilizing cemented liners and plug-and-perf technology incorporating three to five perforation clusters per
fracture stage. This new design has generated positive results, demonstrated by average increases of 20% in initial production rates, as
well as 30, 60 and 90-day production rates, from wells recently drilled in these fields. At our Tarpon field we have also implemented
a completion technique using cemented liners and coiled tubing, and at our Hidden Bench field, based on the success of our high
density drilling pilot in this area, we initiated a development program of drilling eight wells per spacing unit, an increase over our
original plan of four wells per spacing unit.
Cassandra Field. Our Cassandra field in Williams County, North Dakota targets the Bakken and Three Forks formations and
encompasses approximately 29,800 gross (14,000 net) developed and undeveloped acres as of December 31, 2014. As of December
31, 2014, we had one drilling rig active in the Cassandra field. In 2014, we improved our completion design in this area utilizing
cemented liners and plug-and-perf technology with increased proppant volumes resulting in significant improvements in performance.
Missouri Breaks Field. As of December 31, 2014, we had approximately 130,300 gross (82,600 net) developed and undeveloped
acres at our Missouri Breaks field located in Richland County, Montana and McKenzie County, North Dakota. We have drilled
successful wells on the western, eastern and southern portions of our acreage in this area. In the fourth quarter of 2014, net production
from the Missouri Breaks field averaged 6.6 MBOE/d, representing an 8% increase from 6.1 MBOE/d in the third quarter of 2014. As
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of December 31, 2014, we had three drilling rigs active in the Missouri Breaks field. We have implemented a new completion design
at this field, utilizing cemented liners, plug-and-perf technology and higher sand volumes, and this new design has significantly
improved initial production rates. In addition, we continue to evaluate the slickwater fracture stimulation method used in this area and
are encouraged by the initial results.
Other Northern Rocky Mountains. As of December 31, 2014, we had four drilling rigs operating in new areas of the Williston Basin
that were acquired in the Kodiak Acquisition. We plan to release two of these rigs during the first quarter of 2015.
Redtail Field. Our Redtail field in the DJ Basin in Weld County, Colorado targets the Niobrara formation and encompasses
approximately 185,700 gross (132,200 net) developed and undeveloped acres as of December 31, 2014. In the fourth quarter of 2014,
net production from the Redtail field averaged 10.2 MBOE/d, representing an 18% increase from 8.6 MBOE/d in the third quarter of
2014. Our development plan at Redtail currently includes drilling up to eight Niobrara “B” wells per spacing unit and eight Niobrara
“A” wells per spacing unit. We are currently completing wells drilled from the Horsetail 30F pad in this area to test a high-density
pattern in the Niobrara “A”, “B” and “C” zones, with 32 wells per spacing unit. As of December 31, 2014, we had four drilling rigs
operating in this area. As a result of the recent decline in crude oil prices, we plan to decrease the number of rigs operating in this area
to three for most of 2015. We have implemented our updated completion design at this field, utilizing cemented liners, plug-and-perf
technology and higher sand volumes, which has been yielding improved production results.
In April 2014, we brought online the Redtail gas plant to process the associated gas produced by our wells in this area. The plant’s
current inlet capacity is 20 MMcf/d, and we plan to further expand the plant’s capacity to 70 MMcf/d in the second quarter of 2015.
Permian Basin Region
Our Permian Basin operations include assets in Texas and New Mexico. As of December 31, 2014, the Permian Basin region
contributed 133.0 MMBOE (83% oil) of estimated proved reserves to our portfolio of operations, which represented 17% of our total
estimated proved reserves and contributed 11.5 MBOE/d of average daily production in the fourth quarter of 2014.
North Ward Estes Field. The North Ward Estes field includes five base leases with 100% working interests in approximately 64,900
gross (62,900 net) developed and undeveloped acres in Ward and Winkler counties, Texas. Current production from our EOR project
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.
The North Ward Estes field has been responding positively to the water and CO2 floods that we initiated in May 2007. We are
currently injecting CO2 into one of the largest phases of our eight-phase project at North Ward Estes, and all phases of the project
subject to CO2 flood procedures continue to respond positively. In the fourth quarter of 2014, production from the field averaged 9.7
MBOE/d, which represents a 2% increase from 9.5 MBOE/d in the third quarter of 2014. As of December 31, 2014, we were
injecting approximately 410 MMcf/d of CO2 in this field, over half of which is recycled.
North Ward Estes’ proved reserves at December 31, 2014 were 40% proved undeveloped. In order to fully develop the reserves at this
field within our currently planned timeframe, we will need to utilize significant quantities of purchased CO2. As of December 31,
2014, we currently have under contract the future volumes of CO2 that we believe are necessary to develop the field’s PUDs over at
least the next seven years. In addition, we are currently planning for future sources of CO2 capable of generating sufficient quantities
to carry out the development of all probable and possible reserves at North Ward Estes. However, we cannot provide assurance with
respect to the timing or actual quantities of CO2 that will be obtainable for the development of this field’s oil and gas reserves.
Other
Our other operations primarily relate to assets in Arkansas, Michigan, Oklahoma and Texas. As of December 31, 2014, these
properties contributed 11.6 MMBOE (35% oil) of proved reserves to our portfolio of operations, which represented 2% of our total
estimated proved reserves and contributed 3.6 MBOE/d of average daily production in the fourth quarter of 2014.
32
Reserves
As of December 31, 2014, 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, 2014 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, 2014) is as follows:
Oil
(MBbl)
NGLs
(MBbl)
Natural Gas
(MMcf)
Total
(MBOE)
Proved reserves
Developed .................................................................
Undeveloped .............................................................
Total proved—December 31, 2014 ................................
Probable reserves
Developed .................................................................
Undeveloped .............................................................
Total probable—December 31, 2014 .............................
Possible reserves
Developed .................................................................
Undeveloped .............................................................
Total possible—December 31, 2014 ..............................
333,593
310,036
643,629
10,665
323,579
334,244
25,363
154,741
180,104
28,935
25,749
54,684
3,032
15,685
18,717
7,116
18,728
25,844
298,237
193,783
492,020
6,463
271,610
278,073
2,682
114,923
117,605
412,234
368,082
780,316
14,774
384,532
399,306
32,926
192,623
225,549
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 2014, total extensions and discoveries of 174.8 MMBOE were primarily attributable to successful drilling at our Redtail, Sanish,
Hidden Bench, Missouri Breaks, Pronghorn, Tarpon and Cassandra fields. Both the new wells drilled in these areas as well as the
PUD locations added as a result of drilling increased our proved reserves.
In 2014, total sales of minerals in place of 2.1 MMBOE were primarily attributable to the disposition of properties in the Big Tex
prospect, further described in “Acquisitions and Divestitures” within Item 1 of this Annual Report on Form 10-K, as well as other
property divestitures in the Lucky Ditch, Whiskey Springs and Bridger Lake fields, which decreased our proved reserves.
In 2014, total purchases of minerals in place of 195.6 MMBOE were primarily attributable to the Kodiak Acquisition, whereby we
acquired interests in 778 producing oil and gas wells and undeveloped acreage in the Williston Basin, as further described in
“Acquisitions and Divestitures” within Item 1 of this Annual Report on Form 10-K, which increased our proved reserves.
In 2014, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 15.3 MMBOE.
Included in these revisions were (i) 15.6 MMBOE of net upward adjustments attributable to reservoir analysis and well performance
and (ii) 0.3 MMBOE of downward adjustments caused by lower crude oil prices incorporated into our reserve estimates at December
31, 2014 as compared to December 31, 2013.
Proved undeveloped reserves. Our PUD reserves increased 98% or 182.0 MMBOE on a net basis from December 31, 2013 to
December 31, 2014. The following table provides a reconciliation of our PUDs for the year ended December 31, 2014:
PUD balance—December 31, 2013 .................................................................................................................
Converted to proved developed through drilling ........................................................................................
Converted to proved developed at EOR projects ........................................................................................
Added from extensions and discoveries ......................................................................................................
Removed for five-year rule .........................................................................................................................
Removed due to low commodity prices ......................................................................................................
Purchased ....................................................................................................................................................
Sold .............................................................................................................................................................
Revisions .....................................................................................................................................................
PUD balance—December 31, 2014 .................................................................................................................
33
Total
(MBOE)
186,096
(30,064)
(7,940)
135,615
(2,168)
(218)
94,166
-
(7,405)
368,082
During 2014, we incurred $767 million in capital expenditures, or $25.51 per BOE, to drill and bring on-line 30.1 MMBOE of PUD
reserves. Also during 2014, 7.9 MMBOE of PUD volumes became proved developed reserves at our CO2 EOR project in the North
Ward Estes field, at a cost of $39.58 per BOE. Combining the PUD drilling conversions with the PUD EOR conversions, we
converted PUDs to proved developed reserves at a cost of $28.45 per BOE during 2014.
In addition, we added 135.6 MMBOE of PUD volumes from extensions and discoveries during the year, and this increase in proved
undeveloped reserves was primarily due to additional PUD locations added based on successful drilling in the Northern and Central
Rockies areas and additional PUD reserves being assigned to our North Ward Estes EOR project.
During 2014, we added total PUD volumes of 94.2 MMBOE through acquisitions, of which 90.5 MMBOE were attributable to the
Kodiak Acquisition.
Based on our 2014 year end independent engineering reserve report, we will drill all of our individual PUD drilling locations within
five years of the date such PUDs were added. 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 EOR PUDs all at once. Due to the large areal extent of the field, this CO2 EOR
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 execution of the CO2 project throughout the field all at the same time include: (i) the
volume of injection water necessary to re-pressure 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 EOR 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 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 reserve 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 2014 were primarily attributable to 1,916 new probable well locations that were added in 2014
as a result of the Kodiak Acquisition as well as drilling activity across the Rocky Mountains region. Offsetting these increases were
14.0 MMBOE of probable reserves that were converted to proved reserves during 2014, primarily at our Redtail field and various
fields in the Northern Rocky Mountains.
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.
34
Possible reserves increased during 2014 primarily due to successful drilling at our Redtail, Sanish, Parshall, Lewis & Clark/Pronghorn
and Hidden Bench fields. Offsetting these increases were 7.0 MMBOE of possible reserves that were converted to probable during
2014 at our North Ward Estes field and various other fields in the Northern Rocky Mountains, and 11.8 MMBOE of possible reserves
were converted to proved during 2014 at the same areas.
At December 31, 2014, our probable reserves were estimated to be 399.3 MMBOE and our possible reserves were estimated to be
225.5 MMBOE, for a total of 624.8 MMBOE. The EOR project at our North Ward Estes field represented 110.3 MMBOE, or 18%,
of our total 624.8 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 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. We maintain adequate and effective internal controls over the reserve estimation process as well as
the underlying data upon which reserve estimates are based. The primary inputs to the reserve estimation process are comprised of
technical information, financial data, ownership interests and production data. All field and reservoir technical information, which is
updated annually, is assessed for validity when the reservoir engineers hold technical meetings with geoscientists, operations and land
personnel to discuss field performance and to validate future development plans. Current revenue and expense information is obtained
from our accounting records, which are subject to our 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 (2013) 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. Our 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, our independent engineering firm Cawley, Gillespie &
Associates, Inc. (“CG&A”) meets with our technical personnel in our 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 our 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 30 years of experience, the majority of which has involved reservoir engineering and reserve estimation, and he holds a
Bachelor’s degree in petroleum engineering from the Colorado School of Mines. He is also a member of the Society of Petroleum
Engineers.
35
Acreage
The following table summarizes gross and net developed and undeveloped acreage by state at December 31, 2014. Net acreage is our
percentage ownership of gross acreage. Acreage in which our interest is limited to royalty and overriding royalty interests has been
excluded.
Developed Acreage
Net
Gross
Undeveloped Acreage (2)
Gross
Net
California ..........................
Colorado ...........................
Louisiana ...........................
Michigan ...........................
Montana ............................
New Mexico ......................
North Dakota.....................
Oklahoma ..........................
Texas .................................
Utah...................................
Wyoming ..........................
Other (1) .............................
Total .............................
_____________________
(1) Other includes Alabama, Arkansas, Kansas, Mississippi and Nebraska.
25,548
71,493
23,867
139,390
97,406
17,625
813,348
56,610
252,273
14,301
89,162
9,810
3,606
51,181
9,191
61,221
58,886
6,387
474,804
28,391
136,831
6,972
44,596
4,588
-
195,372
100,697
289,465
107,825
123,412
293,266
406
23,772
431,488
44,729
912
1,611,344
1,610,833
886,654
-
119,981
91,472
245,868
68,172
114,045
209,876
68
18,061
273,295
31,548
349
1,172,735
Total Acreage
Gross
25,548
266,865
124,564
428,855
205,231
141,037
1,106,614
57,016
276,045
445,789
133,891
10,722
3,222,177
Net
3,606
171,162
100,663
307,089
127,058
120,432
684,680
28,459
154,892
280,267
76,144
4,937
2,059,389
(2) Out of a total of 1,611,344 gross (1,172,735 net) undeveloped acres as of December 31, 2014, the portion of our net undeveloped
acres that is subject to expiration over the next three years, if not successfully developed or renewed, is approximately 26% in
2015, 29% in 2016 and 13% in 2017.
36
Production History
The following table presents historical information about our produced oil and gas volumes:
Year Ended December 31,
2013
2014
2012
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):
33.5
3.3
30.2
41.8
114.5
3.1
0.4
0.3
3.6
9.9
1.1
5.9
12.0
27.0
2.8
26.9
34.3
94.1
2.9
0.4
0.3
3.4
9.8
1.1
4.8
11.7
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
Oil (per Bbl) ..............................................................................................
NGLs (per Bbl) .........................................................................................
Natural gas (per Mcf) ................................................................................
$
$
$
81.50
39.17
5.53
$
$
$
90.39
40.41
4.04
$
$
$
83.86
39.36
3.42
Average production costs:
Production costs (per BOE) (2) ..................................................................
$
11.24
$
11.94
$
11.92
_____________________
(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, 2014.
(2) Production costs reported above exclude from lease operating expenses ad valorem taxes of $27 million ($0.65 per BOE), $20
million ($0.59 per BOE) and $16 million ($0.54 per BOE) for the years ended December 31, 2014, 2013 and 2012, respectively.
Productive Wells
The following table summarizes gross and net productive oil and natural gas wells by region at December 31, 2014. 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
Net
Natural Gas Wells
Net
Gross
Total Wells(1)
Gross
Net
Rocky Mountains .....................
Permian Basin ..........................
Other (2) ....................................
Total ..................................
4,670
4,098
467
9,235
1,653
1,746
209
3,608
413
374
1,632
2,419
215
111
537
863
5,083
4,472
2,099
11,654
1,868
1,857
746
4,471
_____________________
(1) 137 wells have multiple completions. These 137 wells contain a total of 341 completions. One or more completions in the same
bore hole are counted as one well.
(2) Other primarily includes oil and gas properties located in Arkansas, Michigan, Oklahoma and Texas.
We have an interest in or operate 32 EOR projects, which include either secondary (waterflood) or tertiary (CO2 injection) recovery
efforts, and aggregate production from such EOR fields averaged 12.0 MBOE/d during 2014 or 10% of our 2014 daily production.
For these areas, we need to use enhanced recovery techniques in order to maintain oil and gas production from these fields.
37
Oil and Gas 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 oil and gas drilling activity for the last three years. Wells drilled to develop
our CO2 reserves at our Bravo Dome field in New Mexico have not been included in the drilling activity table below. 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.
2014:
Development ..........................
Exploratory .............................
Total ...................................
2013:
Development ..........................
Exploratory .............................
Total ...................................
2012:
Development ..........................
Exploratory .............................
Total ...................................
Productive
Gross Wells
Dry
Total
Productive
Net Wells
Dry
Total
571
34
605
376
43
419
324
68
392
1
5 (1)
6
1
8
9
-
5
5
572
39
611
377
51
428
324
73
397
231.5
21.5
253.0
185.5
35.2
220.7
140.4
47.8
188.2
0.4
3.7
4.1
1
7.5
8.5
-
4.7
4.7
231.9
25.2
257.1
186.5
42.7
229.2
140.4
52.5
192.9
_____________________
(1) During 2014, we drilled six CO2 wells at our Bravo Dome field that were exploratory dry holes and that have not been included in
the drilling results above.
As of December 31, 2014, we had 21 operated drilling rigs active on our properties. The breakdown of our operated rigs by
geographic area is as follows:
Northern Rocky Mountains ............................................................................................................................
Central Rocky Mountains ..............................................................................................................................
North Ward Estes ...........................................................................................................................................
Total ............................................................................................................................................................
Drilling Rigs
16
4
1
21
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 “Business – Regulation – Environmental Regulations – Hydraulic Fracturing” in Item 1 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 Colorado, Michigan, Montana, North Dakota, Texas and
Wyoming and we plan to continue to utilize this completion methodology.
Whiting’s proved undeveloped reserve quantities that are associated with hydraulic fracture treatments consist of substantially all of
our proved undeveloped reserves, or 368.1 MMBOE.
On February 13, 2014, we had a well control incident during drilling operations involving one well in our Hidden Bench field in North
Dakota. The well was quickly brought under control with no liquids leaving the location, and there were no resulting injuries.
Appropriate regulatory agencies were notified of the incident. Other than this incident, we are not aware of any environmental
incidents or citations or suits that have occurred during the last three years related to hydraulic fracturing operations involving oil and
gas properties that we operate or in which we own a non-operated interest.
38
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 North Dakota Industrial Commission 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;
we conduct annual emergency incident response drills in all of our active areas; and
we are a member of the Sakakawea Area Spill Response LLC (“SASR”), which is composed of 13 oil and gas related
companies operating in the Missouri River and Lake Sakakawea region of North Dakota. Members agreed to share spill
response resources and maintain SASR-owned water response equipment that can be accessed quickly in the early stages of a
spill.
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 crude oil. As of December 31,
2014, we had delivery commitments totaling 12.4 MMBbl of crude oil (or 37% of total 2014 oil production), 17.8 MMBbl (53%),
19.6 MMBbl (59%), 21.5 MMBbl (64%), 23.3 MMBbl (70%) and 6.0 MMBbl (18%) for the years ended December 31, 2015 through
2020, respectively. These contracts are tied to oil production at our Redtail field in the DJ Basin in Weld County, Colorado. As of
December 31, 2014, we determined that it is no longer probable that future oil production from our Redtail field will be sufficient to
meet the minimum volume requirements specified in these physical delivery contracts, and as a result, we expect to make periodic
deficiency payments for any shortfalls in delivering the minimum committed volumes. We currently anticipate that we will under-
deliver by a total of approximately 10.4 MMBbl over the duration of the contracts, which would require undiscounted aggregate
deficiency payments of approximately $49 million over the next 5 years. We recognize any monthly deficiency payments in the
period in which the underdelivery takes place and the related liability has been incurred. See “Quantitative and Qualitative
Disclosures about Market Risk” in Item 7A of this Annual Report on Form 10-K for more information about our delivery
commitments under these agreements.
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.
39
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information, as of February 13, 2015, regarding the executive officers of Whiting Petroleum
Corporation:
Name
James J. Volker ......................................................
Peter W. Hagist ......................................................
Rick A. Ross ..........................................................
Mark R. Williams ..................................................
Bruce R. DeBoer ....................................................
Heather M. Duncan ................................................
Steven A. Kranker ..................................................
David M. Seery ......................................................
Michael J. Stevens .................................................
Brent P. Jensen .......................................................
Age Position
68 Chairman, President and Chief Executive Officer
54 Senior Vice President, Planning
56 Senior Vice President, Operations
58 Senior Vice President, Exploration and Development
62 Vice President, General Counsel and Corporate Secretary
44 Vice President, Human Resources
53 Vice President, Reservoir Engineering and Acquisitions
60 Vice President, Land
49 Vice President and Chief Financial Officer
45 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 continued as Chairman and Chief Executive Officer. Effective June 2014, he was again elected President and Chief
Executive Officer. Mr. Volker was co-founder, Vice President and later President of Energy Management Corporation from 1971
through 1982. He has 43 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.
Peter W. Hagist joined us in October 2005 as Vice President, Operations-Midland. In June 2014, he was elected Senior Vice
President of Planning. Mr. Hagist has 33 years of experience in the oil and gas industry and 25 years of experience managing tertiary
recovery operations. Prior to joining Whiting, he held management and professional positions with Kinder Morgan CO2 Company
and Pennzoil Exploration and Production Company. Mr. Hagist holds a Bachelor of Science degree in Petroleum Engineering from
the Colorado School of Mines. He is a registered Professional Engineer and a member of the Society of Petroleum Engineers.
Rick A. Ross joined us in March 1999 as an Operations Manager. In May 2007, he became Vice President of Operations and in June
2014, he was elected Senior Vice President of Operations. Mr. Ross has 32 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,
a member of the Society of Petroleum Engineers and was a past Chairman of the North Dakota Petroleum Council.
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 34 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 35 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 18 years of human
resources experience in the oil and gas industry. She holds a Bachelor of Arts degree in anthropology and an MBA from the
University of Colorado. She is a certified Senior Professional in Human Resources.
Steven A. Kranker joined us in March 2013 as First Director – Acquisitions and Reservoir Engineering and became Vice President of
Reservoir Engineering and Acquisitions in July 2013. Prior to joining Whiting, Mr. Kranker held positions at several companies
engaged in oil and gas exploration and development, including Manager of Reserves at Bill Barrett Corporation from June 2012 to
March 2013, President of Earth Energy Reserves, Inc. from July 2010 to June 2012, and various positions at Forest Oil Corporation,
40
including Corporate Engineering Manager, from May 2001 to July 2010. Mr. Kranker has 30 years of acquisition and reservoir
engineering experience, including Brunei Shell Petroleum, Arco Alaska Inc., Maxus Exploration, Conoco Inc. and Shell Western E&P
Inc. He received his Bachelor of Science degree in petroleum engineering from the Colorado School of Mines. Mr. Kranker is a
member of the Society of Petroleum Engineers.
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 34 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. He is a registered
Land Professional and has held various duties with the Denver Association of Petroleum Landmen.
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 28 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 21 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.
41
PART II
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Whiting Petroleum Corporation’s common stock is traded on the New York Stock Exchange under the symbol “WLL.” The
following table shows the high and low sale prices for our common stock for the periods presented.
Fiscal Year Ended December 31, 2014
Fourth quarter (ended December 31, 2014) .......................................................
Third quarter (ended September 30, 2014) ........................................................
Second quarter (ended June 30, 2014) ...............................................................
First quarter (ended March 31, 2014) .................................................................
Fiscal Year Ended December 31, 2013
Fourth quarter (ended December 31, 2013) .......................................................
Third quarter (ended September 30, 2013) ........................................................
Second quarter (ended June 30, 2013) ...............................................................
First quarter (ended March 31, 2013) .................................................................
$
$
$
$
$
$
$
$
On February 13, 2015, there were 809 holders of record of our common stock.
High
Low
78.99
92.92
82.35
72.32
70.57
60.65
50.96
52.02
$
$
$
$
$
$
$
$
24.13
76.28
68.46
54.93
56.40
46.13
42.44
43.60
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, our credit agreement restricts our ability to make any dividends or distributions on our common stock.
Additionally, the indentures governing our senior and senior subordinated notes (including Kodiak’s senior notes) contain restrictive
covenants that may limit our ability to pay cash dividends on our common 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, 2009 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 (b) the price per share at the beginning of the measurement period. The graph assumes $100
was invested on December 31, 2009 in our common stock, the Standard & Poor’s Composite 500 Index and the Dow Jones U.S. Oil
Companies, Secondary Index.
42
Whiting Petroleum Corporation ..................................
Standard & Poor’s Composite 500 Index....................
Dow Jones U.S. Exploration & Production Index ......
$
12/31/2009 12/31/2010 12/31/2011 12/31/2012 12/31/2013 12/31/2014
92
131 $
185
113
132
110
164 $
113
116
173 $
166
150
121 $
128
115
100 $
100
100
43
Item 6. Selected Financial Data
The consolidated statements of income and statements of cash flows information for the years ended December 31, 2014, 2013 and
2012 and the consolidated balance sheet information at December 31, 2014 and 2013 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, 2011 and 2010 and the consolidated balance sheet information at December 31, 2012, 2011 and 2010 are derived
from audited financial statements that are not included in this report. Our historical results include the results from our recent proved
property acquisitions beginning on the following closing dates: properties related to the Kodiak Acquisition, December 8, 2014;
properties in North Dakota and Montana, September 20, 2013; and properties in Colorado, September 9, 2010. In addition, our
historical results also include the effects of our recent proved property divestitures beginning on the following closing dates: properties
in the Postle field, July 15, 2013; and properties in Texas, October 31, 2013.
2014
Year Ended December 31,
2012
2013
2011
(in millions, except per share data)
Consolidated Statements of Income Information:
Revenues and other income:
Oil, NGL and natural gas sales ......................................
Gain (loss) on hedging activities ...................................
Amortization of deferred gain on sale ...........................
Gain on sale of properties ..............................................
Interest income and other ..............................................
Total revenues and other income ................................
$
3,024.6
—
30.5
27.6
2.3
3,085.0
$
2,666.5
$
(1.9)
31.7
128.6
3.4
2,828.3
$
$
2,137.7
2.3
29.5
3.4
0.5
2,173.4
1,860.1
8.8
13.9
16.3
0.5
1,899.6
Costs and expenses:
2010
1,475.3
23.2
15.6
1.4
0.6
1,516.1
305.5
139.2
468.2
84.6
85.0
62.5
—
(0.9)
(24.8)
376.4
171.6
684.7
167.0
108.6
75.2
—
13.8
(85.9)
430.2
225.4
891.5
453.2
138.0
112.9
4.4
(7.0)
7.8
2,256.4
571.9
205.9
366.0
0.1
366.1
496.9
253.0
1,089.5
854.4
177.2
170.6
—
—
(100.5)
2,941.1
143.9
79.2
64.7
0.1
64.8
—
64.8
0.53
0.53
Lease operating .............................................................
Production taxes ............................................................
Depreciation, depletion and amortization ......................
Exploration and impairment (1) ......................................
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 before income taxes ...............................................
Income tax expense ............................................................
Net income .........................................................................
Net loss attributable to noncontrolling interest ...................
Net income available to shareholders .................................
Preferred stock dividends (2) ...............................................
Net income available to common shareholders ..................
Earnings per common share, basic (3) .................................
Earnings per common share, diluted (3) ...............................
Other Financial Information:
Net cash provided by operating activities ...........................
Net cash used in investing activities ...................................
Net cash provided by (used in) financing activities ............
Capital expenditures ...........................................................
Consolidated Balance Sheet Information:
Total assets .........................................................................
Long-term debt ...................................................................
Total equity (4) ....................................................................
_____________________
(1) Includes proved oil and gas property impairments of $587 million and CO2 property impairments of $42 million for the year
ended December 31, 2014, and proved oil and gas property impairments of $267 million for the year ended December 31, 2013.
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
$
1,192.1
(1,760.0) $
$
$
$
1,815.3
(2,860.5) $
$
$
$
1,744.7
(1,902.5) $
$
$
$
1,401.2
(1,780.3) $
$
$
1,511.4
662.0
247.9
414.1
0.1
414.2
1,119.3
780.3
288.7
491.6
0.1
491.7
$ 14,019.5
$
5,628.8
$
5,703.0
997.3
(914.6)
(75.7)
923.8
4,648.8
800.0
2,531.3
7,272.4
1,800.0
3,453.2
6,045.6
1,380.0
3,029.1
8,833.5
2,653.8
3,836.7
365.5
3.09
3.06
413.1
3.51
3.48
490.6
4.18
4.14
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
812.4
2,772.7
423.9
2,888.4
408.1
2,171.5
564.8
1,804.3
$
$
$
(1.1)
(1.1)
(0.5)
44
(2) The year ended December 31, 2010 includes a cash premium of $47.5 million for the induced conversion of our 6.25% Perpetual
Preferred Stock.
(3) 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 per common share, basic and diluted for periods
prior to February 2011 have been retroactively adjusted to reflect the stock split.
(4) No cash dividends were declared or paid on our common stock during the periods presented.
45
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 (“Whiting Oil and Gas”),
Whiting US Holding Company, Whiting Canadian Holding Company ULC (formerly Kodiak Oil & Gas Corp., “Kodiak”), Whiting
Resources Corporation (formerly Kodiak Oil & Gas (USA) Inc.) 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 and Permian Basin regions of the United States. Since 2006, we have increased our focus 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, while continuing to selectively pursue acquisitions that complement our existing core
properties, such as the recent acquisition of Kodiak (the “Kodiak Acquisition”) discussed below under “Acquisitions and Divestiture
Highlights”. 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 consider to be the most advantageous investments. We
also 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;
allocating a portion of our exploration and development budget to leasing and exploring prospect areas;
maintaining a balanced portfolio of lower risk, long-lived oil and gas properties that provide stable cash flows; and
seeking property acquisitions that complement our core areas, such as the recent Kodiak Acquisition discussed below under
“Acquisition and Divestiture Highlights”.
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 continually evaluate our current property portfolio and 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, as well as the other items discussed in “Risk Factors” in
Item IA of this Annual Report on Form 10-K. 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 2013:
Crude oil ...........
Natural gas ........
$
$
Q1
94.34 $
3.34 $
Q2
94.23 $
4.10 $
Q3
105.82 $
3.58 $
Q4
97.50 $
3.60 $
Q1
98.62 $
4.93 $
Q2
102.98 $
4.68 $
Q3
97.21 $
4.07 $
Q4
73.12
4.04
2013
2014
Oil prices have fallen significantly since reaching highs of over $105.00 per Bbl in June 2014, dropping below $45.00 per Bbl in
January 2015. Natural gas prices have also declined from over $4.80 per Mcf in April 2014 to below $2.60 per Mcf in February 2015.
In addition, forecasted prices for both oil and gas for 2015 have also declined. Lower oil, NGL 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, 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, cash
flows, results of operations, liquidity or ability to finance planned capital expenditures. 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 and
which is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Upon a redetermination, if
borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of the
debt outstanding under our credit agreement. In addition, higher oil and natural gas prices may result in significant mark-to-market
losses being incurred on our commodity-based derivatives, which may in turn cause us to experience net losses.
46
For a discussion of material changes to our proved, probable and possible reserves from December 31, 2013 to December 31, 2014
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.
2014 Highlights and Future Considerations
Operational Highlights.
Sanish and Parshall Fields. Our Sanish and Parshall fields in Mountrail County, North Dakota target the Bakken and Three Forks
formations. Net production in the Sanish and Parshall fields averaged 45.0 MBOE/d for the fourth quarter of 2014, representing a 2%
decrease from 46.1 MBOE/d in the third quarter of 2014. As of December 31, 2014, we had three drilling rigs active in the Sanish
field. Based on the success of our high density pilot programs in the Sanish field, we commenced a development program drilling
nine Bakken wells per spacing unit in the area, an increase over our original plan of three to four wells per spacing unit. Additionally,
we have implemented a new slickwater fracture stimulation method using cemented liners at the Sanish field and are encouraged by
the initial results.
Lewis & Clark/Pronghorn Fields. Our Lewis & Clark/Pronghorn fields 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 and 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 fields averaged 16.4 MBOE/d in the fourth quarter of 2014, representing a 2% decrease from 16.7 MBOE/d in the
third quarter of 2014. As of December 31, 2014, we had one drilling rig operating in the Pronghorn field, which utilizes drilling pads,
with two or three wells being drilled from each pad. We have implemented our new completion design in this field utilizing cemented
liners and plug-and-perf technology based on our successful testing of this completion technique in 2013. Additionally, we are
evaluating our slickwater fracture stimulation method at the Pronghorn field and are encouraged by the results.
At our gas processing plant located south of Belfield, North Dakota, which primarily processes production from the Pronghorn area,
there is currently inlet compression in place to process 35 MMcf/d. As of December 31, 2014 the plant was processing over 23
MMcf/d. In May 2012, we sold a 50% ownership interest in the plant, gathering systems and related facilities. We retained a 50%
ownership interest and continue to operate the Belfield plant and facilities.
Hidden Bench/Tarpon Fields. Our Hidden Bench and Tarpon fields in McKenzie County, North Dakota target the Bakken and Three
Forks formations. Net production at Hidden Bench/Tarpon averaged 22.6 MBOE/d in the fourth quarter of 2014, which represents a
40% increase from 16.2 MBOE/d in the third quarter of 2014. Contributing to this period over period production increase was net
production added as a result of the Kodiak Acquisition totaling 10.7 MBOE/d from December 8, 2014, the closing date of the
acquisition, through December 31, 2014. As of December 31, 2014, we had four drilling rigs active in the Hidden Bench field. We
have also implemented our new completion design at our Hidden Bench/Tarpon fields, utilizing cemented liners and plug-and-perf
technology incorporating three to five perforation clusters per fracture stage. This new design has generated positive results,
demonstrated by average increases of 20% in initial production rates, as well as 30, 60 and 90-day production rates, from wells
recently drilled in these fields. At our Tarpon field we have also implemented a completion technique using cemented liners and
coiled tubing, and at our Hidden Bench field, based on the success of our high density drilling pilot in this area, we initiated a
development program of drilling eight wells per spacing unit, an increase over our original plan of four wells per spacing unit.
Cassandra Field. Our Cassandra field in Williams County, North Dakota targets the Bakken and Three Forks formations. As of
December 31, 2014, we had one drilling rig active in the Cassandra field. In 2014, we improved our completion design in this area
utilizing cemented liners and plug-and-perf technology with increased proppant volumes resulting in significant improvements in
performance.
Missouri Breaks Field. Our Missouri Breaks field, which is located in Richland County, Montana and McKenzie County, North
Dakota, targets the Middle Bakken formation. We have drilled successful wells on the western, eastern and southern portions of our
acreage in this area. In the fourth quarter of 2014, net production from the Missouri Breaks field averaged 6.6 MBOE/d, representing
an 8% increase from 6.1 MBOE/d in the third quarter of 2014. As of December 31, 2014, we had three drilling rigs active in the
Missouri Breaks field. We have implemented a new completion design at this field, utilizing cemented liners, plug-and-perf
technology and higher sand volumes, and this new design has significantly improved initial production rates. In addition, we continue
to evaluate the slickwater fracture stimulation method used in this area and are encouraged by the initial results.
Redtail Field. Our Redtail field in the Denver Julesberg Basin (“DJ Basin”) in Weld County, Colorado targets the Niobrara formation.
In the fourth quarter of 2014, net production from the Redtail field averaged 10.2 MBOE/d, representing an 18% increase from 8.6
MBOE/d in the third quarter of 2014. Our development plan at Redtail currently includes drilling up to eight Niobrara “B” wells per
47
spacing unit and eight Niobrara “A” wells per spacing unit. We are currently completing wells drilled from the Horsetail 30F pad in
this area to test a high-density pattern in the Niobrara “A”, “B” and “C” zones, with 32 wells per spacing unit. As of December 31,
2014, we had four drilling rigs operating in this area. We have implemented our updated completion design at this field, utilizing
cemented liners, plug-and-perf technology and higher sand volumes, which has been yielding improved production results.
In April 2014, we brought online the Redtail gas plant to process the associated gas produced from our wells in this area. The plant’s
current inlet capacity is 20 MMcf/d, and we plan to further expand the plant’s capacity to 70 MMcf/d in the second quarter of 2015.
North Ward Estes Field. 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 production increases and substantial reserve additions, 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 into one of the largest phases of our eight-phase project at North Ward Estes, and all phases of the project subject to
CO2 flood procedures continue to respond positively. Net production from North Ward Estes averaged 9.7 MBOE/d for the fourth
quarter of 2014, which represents a 2% increase from 9.5 MBOE/d in the third quarter of 2014. As of December 31, 2014, we were
injecting approximately 410 MMcf/d of CO2 into the field, over half of which is recycled.
Whiting USA Trust I. On January 28, 2015, the net profits interest that Whiting conveyed to Whiting USA Trust I (“Trust I”)
terminated as a result of 9.11 MMBOE (which amount is equivalent to 8.20 MMBOE attributable to the net profits interest) having
been produced and sold from the underlying properties. Upon termination, the net profits interest in the underlying properties reverted
back to Whiting, resulting in an increase in our production volumes of approximately 2.3 MBOE/d as of the termination of the net
profits interest.
Financing Highlights. In August 2014, we entered into a Sixth Amended and Restated Credit Agreement with a syndicate of banks
which replaced Whiting Oil and Gas’ existing credit agreement effective December 8, 2014, the closing date of the Kodiak
Acquisition. This amended credit agreement increased the borrowing base under Whiting Oil and Gas’ credit facility to $4.5 billion,
with aggregate commitments of $3.5 billion. Subsequently in December 2014, the lenders under the credit agreement increased their
aggregate commitments under this amended agreement from $3.5 billion to $4.5 billion, of which $3.5 billion relates to commitments
to extend revolving credit and $1.0 billion relates to a senior secured delayed draw term loan facility (“Delayed Draw Facility”). The
Delayed Draw Facility may be used to provide cash consideration for any repurchase or redemption of Kodiak’s outstanding senior
notes in connection with the Kodiak Acquisition, to pay transaction costs and for other corporate purposes. A portion of the revolving
credit facility, in an aggregate amount not to exceed $100 million, may be used to issue letters of credit for the account of Whiting Oil
and Gas and other designated subsidiaries of Whiting Petroleum Corporation. Under the amended credit agreement, the revolving
credit facility will mature on December 8, 2019, and the Delayed Draw Facility will mature on December 31, 2015.
In conjunction with the Kodiak Acquisition in December 2014, we assumed Kodiak’s outstanding principal amount of $800 million of
8.125% Senior Notes due December 2019, $350 million of 5.5% Senior Notes due January 2021 and $400 million of 5.5% Senior
Notes due February 2022 (the “Kodiak Notes”). On January 7, 2015, as required under the terms of the indentures governing the
Kodiak Notes (the “Kodiak Indentures”) upon a change in control of Kodiak, we offered to repurchase at 101% of par all $1,550
million principal amount of Kodiak Notes outstanding. The repurchase offer expires on March 3, 2015. We expect to fund any
payments due as a result of such repurchase offer with borrowings under our revolving credit facility, which would reduce availability
under such facility.
2015 Exploration and Development Budget. Our current 2015 exploration and development (“E&D”) budget is $2.0 billion, which
we expect to fund substantially with net cash provided by our operating activities, cash on hand, borrowings under our credit facility,
or through the issuance of additional debt or equity securities. This represents a substantial decrease from the $3.2 billion incurred on
E&D (which amount also includes acreage expenditures) during 2014. This reduced capital budget is in response to the significantly
lower crude oil prices experienced during the fourth quarter of 2014 and continuing into 2015. We expect to allocate $1.8 billion of
our 2015 budget to exploration and development activity (of which, $82 million is related to CO2 development projects), $59 million
for undeveloped acreage and $123 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
necessary. Our 2015 E&D budget currently is allocated among our major development areas as indicated in the table below. Of our
existing potential projects, we believe these present the opportunity for the highest return and most efficient use of our capital
expenditures.
48
Development Area
Northern Rockies .................................................................................................................................
Central Rockies ....................................................................................................................................
Non-operated .......................................................................................................................................
CO2 EOR project (1) .............................................................................................................................
Well work and other.............................................................................................................................
Exploration (2).......................................................................................................................................
Facilities ...............................................................................................................................................
Undeveloped acreage ...........................................................................................................................
Total ..............................................................................................................................................
$
$
2015 Exploration and
Development Budget
(in millions)
960.5
386.4
132.9
82.2
194.7
61.1
123.2
59.0
2,000.0
_____________________
(1) 2015 planned capital expenditures at our CO2 EOR project include $80 million for North Ward Estes CO2 purchases.
(2) Comprised primarily of exploration salaries, seismic activities, lease delay rentals and exploratory drilling.
Acquisition and Divestiture Highlights.
Kodiak Acquisition. On December 8, 2014, we completed the Kodiak Acquisition whereby we acquired all of the outstanding
common stock of Kodiak. Pursuant to the terms of the Kodiak Acquisition agreement, Kodiak shareholders received 0.177 of a share
of Whiting common stock in exchange for each share of Kodiak common stock they owned. Total consideration for the Kodiak
Acquisition was $1.8 billion, consisting of the 47,546,139 Whiting common shares issued at the market price of $37.25 per share on
the date of issuance plus the fair value of Kodiak’s outstanding equity awards assumed by Whiting. The aggregate purchase price of
the transaction was $4.3 billion, which includes the assumption of Kodiak’s outstanding debt of $2.5 billion as of December 8, 2014
and the net cash acquired of $19 million.
As a result of the Kodiak Acquisition, Whiting acquired approximately 327,000 gross (178,000 net) acres located primarily in North
Dakota including interests in 778 producing oil and gas wells and undeveloped acreage. Approximately 10,000 of the net acres
acquired were located in Wyoming and Colorado. The producing properties had estimated proved reserves of 191.8 MMBOE as of
the acquisition date, 86% of which are crude oil and NGLs.
The acquisition significantly expanded our presence in the Williston Basin, adding undeveloped acreage, oil and natural gas reserves
and production that were complementary to our existing asset base and operations in this area. As a result of this acquisition, we
became the largest Bakken/Three Forks producer in the Williston Basin as of the acquisition date.
Big Tex Divestiture. In March 2014, we completed the sale of approximately 49,900 gross (41,000 net) acres in our Big Tex prospect,
which consisted mainly of undeveloped acreage as well as our interests in certain producing oil and gas wells, located in the Delaware
Basin of Texas for a cash purchase price of $76 million resulting in a pre-tax gain on sale of $12 million. With this divestiture, we no
longer own any interests in the Big Tex prospect.
49
Results of Operations
The following table sets forth selected operating data for the periods indicated:
Net production:
Oil (MMBbl) ..............................................................................................
NGLs (MMBbl) .........................................................................................
Natural gas (Bcf) ........................................................................................
Total production (MMBOE) ......................................................................
Net sales (in millions):
Oil (1) ..........................................................................................................
NGLs ..........................................................................................................
Natural gas .................................................................................................
Total oil, NGL and natural gas sales ..........................................................
Average sales prices:
Oil (per Bbl) (1) ...........................................................................................
Effect of oil hedges on average price (per Bbl) ..........................................
Oil net of hedging (per Bbl) .......................................................................
Weighted average NYMEX price (per Bbl) (2) ...........................................
$
$
$
$
$
Year Ended
December 31,
2013
2014
2012
33.5
3.3
30.2
41.8
2,729.0 $
128.6
167.0
3,024.6 $
81.50 $
1.29
82.79 $
91.55 $
27.0
2.8
26.9
34.3
2,443.7 $
114.0
108.8
2,666.5 $
90.39 $
(1.13)
89.26 $
98.02 $
23.1
2.8
25.8
30.2
1,940.5
108.9
88.3
2,137.7
83.86
(1.25)
82.61
94.03
NGLs (per Bbl) ..........................................................................................
$
39.17 $
40.41 $
39.36
Natural gas (per Mcf) (1) .............................................................................
Effect of natural gas hedges on average price (per Mcf) ............................
Natural gas net of hedging (per Mcf) .........................................................
Weighted average NYMEX price (per Mcf) (2) ..........................................
$
$
$
Costs and expenses (per BOE):
Lease operating expenses ...........................................................................
Production taxes .........................................................................................
Depreciation, depletion and amortization ..................................................
General and administrative.........................................................................
$
$
$
$
_____________________
(1) Before consideration of hedging transactions.
(2) Average NYMEX pricing weighted for monthly production volumes.
Year Ended December 31, 2014 Compared to Year Ended December 31, 2013
5.53 $
-
5.53 $
4.40 $
11.89 $
6.05 $
26.06 $
4.24 $
4.04 $
-
4.04 $
3.66 $
12.53 $
6.56 $
25.96 $
4.02 $
3.42
0.06
3.48
2.79
12.46
5.68
22.67
3.59
Oil, NGL and Natural Gas Sales. Our oil, NGL and natural gas sales revenue increased $358 million to $3,025 million when
comparing 2014 to 2013. Sales revenue is a function of oil, NGL and gas volumes sold and average commodity prices realized. Our
oil sales volumes increased 24%, our NGL sales volumes increased 16% and our natural gas sales volumes increased 12% between
periods. The oil volume increase resulted primarily from drilling success at our Hidden Bench/Tarpon, Sanish and Parshall, Redtail,
Missouri Breaks and Lewis & Clark/Pronghorn fields. During 2014, oil production from our Hidden Bench/Tarpon fields increased
2,355 MBbl, Sanish and Parshall fields increased 1,830 MBbl, Redtail field increased 1,450 MBbl, Missouri Breaks field increased
795 MBbl, and our Lewis & Clark/Pronghorn fields increased 450 MBbl over the same period in 2013. In addition to the production
increases from drilling were 850 MBbl of oil production added across several of our Northern Rockies areas as a result of the Kodiak
Acquisition, which closed on December 8, 2014. These production increases were partially offset by the sale of our Postle field,
which had oil production of 1,270 MBbl in 2013 but which was fully divested in July 2013, as well as normal field production decline
across several of our areas. 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
related to the same areas as our oil volume increases, such as our Hidden Bench/Tarpon fields, our Redtail field, our Lewis &
Clark/Pronghorn fields and our Sanish and Parshall fields. The gas volume increase between periods was primarily the result of new
wells drilled and completed during the past twelve months, which caused increases in associated gas production of 1,750 MMcf at our
Sanish and Parshall fields, 1,530 MMcf at our Hidden Bench/Tarpon fields and 1,455 MMcf at our Redtail field. In addition, 615
50
MMcf of gas production was added as a result of the Kodiak Acquisition. These gas volume increases were partially offset by normal
field production decline across several of our areas, the most notable of which was our Flat Rock field where production volumes
decreased 740 MMcf when comparing 2014 to 2013.
In addition to the above crude oil, NGL and natural gas production-related increases in net revenue was an increase in the average
sales price realized for natural gas of 37% in 2014 compared to 2013. These increases were partially offset by decreases in the
average sales prices realized for oil and NGLs. Our average price for oil before the effects of hedging decreased 10%, and our
average sales price for NGLs decreased 3% between periods.
Gain on Sale of Properties. During 2014, we sold undeveloped acreage as well as our interests in certain producing oil and gas wells
in the Big Tex prospect for net proceeds of $76 million in cash, which resulted in a pre-tax gain on sale of $12 million. Also during
2014, we sold certain non-core properties in the Rocky Mountains region for aggregate sales proceeds of $33 million, resulting in a
pre-tax gain on sale of $17 million. In July 2013, we sold our interest in the Postle Properties for net proceeds of $810 million, which
resulted in a pre-tax gain on sale of $110 million. Additionally during 2013, we sold our interest in certain producing oil and gas wells
and undeveloped acreage in the Big Tex prospect for net proceeds of $152 million, which resulted in a pre-tax gain on sale of $13
million for the year ended December 31, 2013. There were no other property divestitures resulting in a significant gain or loss on sale
during 2014 or 2013.
Lease Operating Expenses. Our lease operating expenses (“LOE”) during 2014 were $497 million, a $67 million increase over 2013.
Higher LOE in 2014 were primarily related to a $92 million increase in the cost of oil field goods and services associated with net
wells we added during the last twelve months, partially offset by a decrease in well workover activity. Workovers decreased from $82
million in 2013 to $57 million in 2014, primarily due to a lower number of well workovers being conducted at our CO2 project at
North Ward Estes.
Our lease operating expenses on a BOE basis, however, decreased when comparing 2014 to 2013. LOE per BOE amounted to $11.89
during 2014, which represents a decrease of $0.64 per BOE from 2013. This decrease was mainly due to higher overall production
volumes between periods combined with the decline in well workover costs, as discussed above.
Production Taxes. Our production taxes during 2014 were $253 million, a $28 million increase over the same period in 2013, which
increase was primarily due to higher oil, NGL and natural gas sales between periods. Our production taxes, however, are generally
calculated as a percentage of net sales revenue before the effects of hedging, and this percentage on a company-wide basis was 8.4%
and 8.5% for 2014 and 2013, respectively.
Depreciation, Depletion and Amortization. Our depreciation, depletion and amortization (“DD&A”) expense increased $198 million
in 2014 as compared to 2013. The components of our DD&A expense were as follows (in thousands):
Depletion ..............................................................................................................................
Depreciation .........................................................................................................................
Accretion of asset retirement obligations .............................................................................
Total ...............................................................................................................................
$
$
Year Ended
December 31,
2014
2013
1,070,503 $
5,494
13,548
1,089,545 $
876,208
4,700
10,608
891,516
DD&A in 2014 increased over 2013 primarily due to $194 million in higher depletion expense between periods. Of this increase,
$191 million related to an increase in our overall production volumes during 2014 and $3 million related to a higher depletion rate
between periods. On a BOE basis, our overall DD&A rate of $26.06 for 2014 represented a slight increase over the 2013 rate of
$25.96 due to $2.8 billion in drilling and development expenditures during the past twelve months, which were largely offset by
additions to proved and proved developed reserves over this same time period.
Exploration and Impairment Costs. Our exploration and impairment costs increased $401 million in 2014 as compared to 2013. The
components of our exploration and impairment costs were as follows (in thousands):
Exploration...........................................................................................................................
Impairment ...........................................................................................................................
Total ................................................................................................................................
$
$
51
Year Ended
December 31,
2014
2013
86,803 $
767,627
854,430 $
94,755
358,455
453,210
Exploration costs decreased $8 million during 2014 as compared to 2013 primarily due to decreases in geological and geophysical
(“G&G”) activity, lower delay lease rentals paid and lower exploratory dry hole costs, partially offset by rig termination fees of $3
million incurred during 2014. G&G costs, such as seismic studies, amounted to $23 million during 2014 as compared to $30 million
during 2013. Delay lease rentals decreased $6 million between periods. Exploratory dry hole costs for 2014 totaled $26 million,
primarily related to five exploratory dry holes drilled on our oil and gas properties in 2014, including three in Michigan and two in the
Rocky Mountains region, as well as six exploratory dry holes at our CO2 development project in New Mexico. During 2013, on the
other hand, we drilled eight exploratory dry holes in the Rocky Mountains and Permian Basin regions totaling $29 million.
Impairment expense in 2014 primarily related to (i) $587 million in non-cash impairment charges for the partial write-down of non-
core proved oil and gas properties, which are not currently being developed, in Colorado, Louisiana, North Dakota and Utah related to
the decrease in oil and gas prices at December 31, 2014, (ii) $70 million of amortization of leasehold costs associated with
individually insignificant unproved properties, (iii) $66 million in impairment write-downs of undeveloped leases that had reached
their expiration dates but that had no wells drilled on them or in areas where we have no further plans to drill or otherwise develop the
acreage, (including $21 million in impairment write-downs of undeveloped CO2 acreage), and (iv) $42 million of impairment write-
downs on our CO2 development properties whose net book values exceeded their undiscounted future net cash flows. Impairment
expense in 2013 primarily related to (i) $267 million in non-cash impairment charges for the partial write-down of proved properties,
primarily attributable to gas reserves in the Rocky Mountains region and in Michigan, whose net book values exceeded their
undiscounted future net cash flows, (ii) $71 million of amortization of leasehold costs associated with individually insignificant
unproved properties, and (iii) $19 million of impairment write-downs of undeveloped acreage costs for leases that had reached their
expiration dates but where no wells had been drilled on such acreage.
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 expenses, net .......................................................................
$
$
Year Ended
December 31,
2014
2013
300,814 $
(123,603)
177,211 $
251,593
(113,599)
137,994
General and administrative expense before reimbursements and allocations increased $49 million during 2014 as compared to 2013
primarily due to transaction-related costs totaling $53 million incurred in 2014 for the Kodiak Acquisition discussed under
“Acquisition and Divestiture Highlights” above, as well as higher employee compensation between periods. Employee compensation
increased $31 million in 2014 as compared to 2013 due to personnel hired during the past twelve months, as well as general pay
increases.
These increases were offset by a decrease in accrued distributions under our Production Participation Plan (the “Plan”) between
periods. General and administrative expense for 2014 and 2013 includes $24 million and $66 million, respectively, for accrued Plan
compensation. On June 11, 2014, the Plan was terminated effective December 31, 2013. Accordingly, there will be no compensation
expense incurred under the Plan going forward. Refer to the Deferred Compensation footnote in the notes to consolidated financial
statements for more information. Beginning January 1, 2015, we have implemented a new cash bonus structure for our employees to
replace the terminated Plan.
The increase in reimbursements and allocations for 2014 was primarily caused by higher salary costs and a greater number of field
workers on Whiting-operated properties. Our general and administrative expenses as a percentage of oil, NGL and natural gas sales
increased from 5% in 2013 to 6% for 2014, as a result of the increases in general and administrative costs between periods discussed
above.
52
Interest Expense. The components of our interest expense were as follows (in thousands):
Senior Notes and Senior Subordinated Notes ......................................................................
Credit agreement ..................................................................................................................
Amortization of debt issue costs and premium ....................................................................
Other ....................................................................................................................................
Capitalized interest ..............................................................................................................
Total ................................................................................................................................
$
$
Year Ended
December 31,
2014
2013
153,260 $
9,419
11,984
63
(4,084)
170,642 $
73,983
27,978
12,405
85
(1,515)
112,936
The increase in interest expense of $58 million between periods was mainly attributable to $79 million in higher interest costs incurred
on our notes during 2014. This increase is due to our September 2013 issuance of $1.1 billion of 5% Senior Notes due 2019 and $1.2
billion of 5.75% Senior Notes due 2021, as well as interest costs incurred on the $1.6 billion of senior notes we assumed on December
8, 2014 as part of the Kodiak Acquisition. This increase was partially offset by a $19 million decrease in the amount of interest
incurred on our credit agreement during 2014 as compared to 2013 due to lower borrowings outstanding during 2014.
Our weighted average debt outstanding during 2014 was $2.9 billion versus $2.3 billion for 2013. Our weighted average effective
cash interest rate was 5.5% during 2014 compared to 4.5% during 2013.
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. Commodity derivative (gain) loss, net amounted to a gain of $101 million for 2014 mainly due to the recognition of
a $54 million asset related to two fixed-differential derivative contracts that failed the “normal purchase normal sale” exclusion during
the fourth quarter of 2014, as well as the significant downward shift in the futures curve of forecasted commodity prices (“forward
price curve”) for crude oil from January 1, 2014 (or the 2014 date on which new contracts were entered into) to December 31, 2014.
Commodity derivative (gain) loss, net for 2013, however, resulted in a loss of $8 million due to the less significant upward shift in the
same forward price curve from January 1, 2013 (or the 2013 date on which prior year contracts were entered into) to December 31,
2013.
See Item 7A, “Quantitative and Qualitative Disclosures about Market Risk,” for a list of our outstanding derivatives as of February 13,
2015.
Income Tax Expense. Income tax expense totaled $79 million for 2014 as compared to $206 million of income tax for 2013, a
decrease of $127 million that was mainly related to $428 million in lower pre-tax income between periods.
Our effective tax rates for 2014 and 2013 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 increased from 36.0% in 2013 to 55.0% for 2014. This
increase is mainly the result of expanded activity in states with higher corporate tax rates, merger costs related to the Kodiak
Acquisition that are not deductible and reduced state tax credits.
Year Ended December 31, 2013 Compared to Year Ended December 31, 2012
Oil, NGL and Natural Gas Sales. Our oil, NGL and natural gas sales revenue increased $529 million to $2,667 million when
comparing 2013 to 2012. Sales revenue is a function of oil, NGL and gas volumes sold and average commodity prices realized. Our
oil sales volumes increased 17%, and our natural gas sales volumes increased 4% between periods, while our NGL sales volumes
remained consistent between periods. The oil volume increase resulted primarily from drilling success at our Hidden Bench/Tarpon,
Sanish and Parshall, Missouri Breaks, Lewis & Clark/Pronghorn and Redtail fields. During 2013, oil production from our Hidden
Bench/Tarpon fields increased 1,770 MBbl, Sanish and Parshall fields increased 1,100 MBbl, Missouri Breaks field increased 765
MBbl, Lewis & Clark/Pronghorn fields increased 765 MBbl, and our Redtail field increased 610 MBbl over the same period in 2012.
These production increases were partially offset by the sale of the Postle Properties in July 2013 and the Whiting USA Trust II (“Trust
II”) divestiture in March 2012, which divestitures negatively impacted oil production in 2013 by 1,250 MBbl and 295 MBbl,
respectively. The gas volume increase between periods was primarily the result of new wells drilled and completed during 2013,
which caused increases in associated gas production of 1,380 MMcf at our Hidden Bench/Tarpon fields, 1,330 MMcf at our Sanish
and Parshall fields and 870 MMcf at our Lewis & Clark/Pronghorn fields. These gas volume increases were largely offset by normal
field production decline across several of our areas, the most notable of which was our Flat Rock field where production volumes
decreased 1,080 MMcf when comparing 2013 to 2012. In addition, the Trust II divestiture in March 2012 negatively impacted gas
production in 2013 by 545 MMcf.
53
In addition to the above crude oil and natural gas production-related increases in net revenue were increases in the average sales prices
realized for oil, NGLs and natural gas in 2013 compared to 2012. Our average price for oil before the effects of hedging increased
8%, our average price for NGLs increased 3% between periods, and our average price for natural gas before the effects of hedging
increased 18% between periods.
Gain on Sale of Properties. During 2013, we sold our interest in the Postle Properties for net proceeds of $810 million, which resulted
in a pre-tax gain on sale of $110 million. Additionally during 2013, we sold our interest in certain producing oil and gas wells and
undeveloped acreage in the Big Tex prospect for net proceeds of $152 million, which resulted in a pre-tax gain on sale of $13 million
for the year ended December 31, 2013. There were no other property divestitures resulting in a significant gain or loss on sale during
2013 or 2012.
Lease Operating Expenses. Our LOE during 2013 were $430 million, a $54 million increase over the same period in 2012. Higher
LOE in 2013 were primarily related to a $45 million increase in the cost of oil field goods and services associated with net wells we
added during the twelve months ended December 31, 2013, and a $9 million increase in costs at the North Ward Estes CO2 processing
facility due to increased production from that field and higher volumes therefore processed through the plant.
Our lease operating expenses on a BOE basis only increased slightly during 2013. LOE per BOE amounted to $12.53 during 2013,
which was up from $12.46 per BOE during 2012. This increase was mainly due to the higher costs of oil field goods and services and
CO2 processing facility costs in 2013, as discussed above, partially offset by higher overall production volumes between periods.
Production Taxes. Our production taxes during 2013 were $225 million, a $54 million increase over the same period in 2012, which
increase was primarily due to higher oil, NGL and natural gas sales between periods. Our production taxes, however, are generally
calculated as a percentage of net sales revenue before the effects of hedging, and this percentage on a company-wide basis was 8.5%
and 8.0% for 2013 and 2012, respectively.
Depreciation, Depletion and Amortization. Our DD&A expense increased $207 million in 2013 as compared to 2012. The
components of our DD&A expense were as follows (in thousands):
Depletion ..............................................................................................................................
Depreciation .........................................................................................................................
Accretion of asset retirement obligations .............................................................................
Total ................................................................................................................................
$
$
Year Ended
December 31,
2013
2012
876,208 $
4,700
10,608
891,516 $
673,789
3,672
7,263
684,724
DD&A in 2013 increased over 2012 primarily due to $202 million in higher depletion expense between periods. Of this increase,
$105 million related to an increase in our overall production volumes during 2013 and $97 million related to a higher depletion rate
between periods. On a BOE basis, our overall DD&A rate of $25.96 for 2013 was 15% higher than the rate of $22.67 for 2012 due to
$2.3 billion in drilling and development expenditures during the twelve months ended December 31, 2013, which were partially offset
by additions to proved and proved developed reserves over this same time period.
Exploration and Impairment Costs. Our exploration and impairment costs increased $286 million in 2013 as compared to 2012. The
components of our exploration and impairment costs were as follows (in thousands):
Exploration...........................................................................................................................
Impairment ...........................................................................................................................
Total ................................................................................................................................
$
$
Year Ended
December 31,
2013
2012
94,755 $
358,455
453,210 $
59,117
107,855
166,972
Exploration costs increased $36 million during 2013 as compared to 2012 primarily due to an increase in G&G activity, higher
exploratory dry hole costs, higher delay lease rentals paid and an increase in geology-related general and administrative expenses.
G&G costs, such as seismic studies, amounted to $30 million during 2013 as compared to $17 million during 2012. Exploratory dry
hole costs for 2013 totaled $29 million, primarily related to eight exploratory dry holes drilled in the Rocky Mountains and Permian
Basin regions during 2013. During 2012, on the other hand, we drilled five exploratory dry holes in the Rocky Mountains and
Permian Basin regions and in Michigan totaling $18 million. Delay lease rentals increased $7 million between periods, while
geology-related general and administrative expenses increased $6 million.
54
Impairment expense in 2013 primarily related to (i) $267 million in non-cash impairment charges for the partial write-down of proved
properties, primarily attributable to gas reserves in the Rocky Mountains region and in Michigan, whose net book values exceeded
their undiscounted future cash flows, (ii) $71 million of amortization of leasehold costs associated with individually insignificant
unproved properties and (iii) $19 million of impairment write-downs of undeveloped acreage costs for leases that had reached their
expiration dates but where no wells had been drilled on such acreage. Impairment expense in 2012 primarily related to (i) the
amortization of leasehold costs associated with individually insignificant unproved properties of $54 million, (ii) $47 million of non-
cash proved property impairment write-downs, mainly in the Rocky Mountains region and (iii) $6 million of impairment write-downs
of undeveloped acreage costs.
General and Administrative Expenses. We report general and administrative expenses net of third-party reimbursements and internal
allocations. The components of our general and administrative expenses were as follows (in thousands):
Year Ended
December 31,
2013
2012
General and administrative expenses ...................................................................................
$
251,593 $
Reimbursements and allocations ..........................................................................................
General and administrative expenses, net .......................................................................
$
(113,599)
137,994 $
199,943
(91,370)
108,573
General and administrative expense before reimbursements and allocations increased $52 million during 2013 as compared to 2012
primarily due to higher employee compensation and an increase in accrued Plan distributions. However, our general and
administrative expenses as a percentage of oil, NGL and natural gas sales remained consistent for 2013 and 2012 at about 5%.
Employee compensation increased $29 million in 2013 as compared to 2012 due to personnel hired during 2013, general pay increases
and higher stock compensation between periods. Accrued distributions under the Plan increased $22 million between periods. This
increase was primarily due to a one-time charge under the Plan of $22 million for the sale of the Postle Properties in the third quarter
of 2013 and $9 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), which increases were partially offset by higher accrued Plan distributions of $9 million
during 2012 due to the Trust II net profits interest divestiture in 2012.
The increase in reimbursements and allocations for 2013 was primarily caused by higher salary costs and a greater number of field
workers on Whiting-operated properties.
Interest Expense. The components of our interest expense were as follows (in thousands):
Senior Notes and Senior Subordinated Notes ......................................................................
Credit agreement ..................................................................................................................
Amortization of debt issue costs and premium ....................................................................
Other ....................................................................................................................................
Capitalized interest ..............................................................................................................
Total ................................................................................................................................
$
$
Year Ended
December 31,
2013
2012
73,983 $
27,978
12,405
85
(1,515)
112,936 $
40,250
28,043
9,518
148
(2,749)
75,210
The increase in interest expense of $38 million between periods was mainly attributable to a $34 million increase in the amount of
interest incurred on our notes during 2013 as compared to 2012 due to our September 2013 issuance of $1.1 billion of 5% Senior
Notes due 2019 and $1.2 billion of 5.75% Senior Notes due 2021. Our weighted average debt outstanding during 2013 was $2.3
billion versus $1.6 billion for 2012. Our weighted average effective cash interest rate was 4.5% during 2013 compared to 4.3% during
2012.
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. Commodity derivative (gain) loss, net amounted to a loss of $8 million for 2013 mainly due to the upward shift in
the forward price curve for crude oil from January 1, 2013 (or the 2013 date on which new contracts were entered into) to December
31, 2013. Commodity derivative (gain) loss, net for 2012, however, resulted in a gain of $86 million due to a significant downward
shift in the same forward price curve from January 1, 2012 (or the 2012 date on which prior year contracts were entered into) to
December 31, 2012.
55
Income Tax Expense. Income tax expense totaled $206 million for 2013 as compared to $248 million of income tax for 2012, a
decrease of $42 million that was mainly related to $90 million in lower pre-tax income between periods, as well as $11 million in state
tax credits realized during 2013.
Our effective tax rates for 2013 and 2012 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 decreased from 37.4% in 2012 to 36.0% for 2013. This
decrease in rate is mainly attributable to state tax credits and a reduction to the North Dakota corporate tax rate, which created a one-
time benefit during 2013.
Liquidity and Capital Resources
Overview. At December 31, 2014, we had $78 million of cash on hand and $5.7 billion of equity, while at December 31, 2013, we
had $699 million of cash on hand and $3.8 billion of equity.
One of the primary sources of variability in our cash flows from operating activities is commodity price volatility, which we partially
mitigate through the use of commodity hedge contracts. Oil accounted for 80% and 79% of our total production in 2014 and 2013,
respectively. As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in NGL
or natural gas prices. As of February 13, 2015, we had derivative contracts covering the sale of approximately 18% of our forecasted
2015 oil production volumes. For a list of all of our outstanding derivatives as of February 13, 2015, see Item 7A, “Quantitative and
Qualitative Disclosures about Market Risk.”
Cash Flows from 2014 Compared to 2013. During 2014, we generated $1.8 billion of cash provided by operating activities, an
increase of $71 million from 2013. Cash provided by operating activities increased primarily due to higher crude oil, NGL and natural
gas production volumes and higher realized sales prices for natural gas, as well as lower exploration costs during 2014. These positive
factors were partially offset by lower realized sales prices for oil and NGLs, as well as increased lease operating expenses, production
taxes, general and administrative expenses and cash interest expense in 2014 as compared to 2013. Refer to “Results of Operations”
for more information on the impact of volumes and prices on revenues and for more information on increases and decreases in certain
expenses during 2014.
During 2014, cash flows from operating activities and cash on hand plus $475 million in net borrowings under our credit agreement
and $108 million of proceeds from the sale of properties were used to finance $2.8 billion of drilling and development expenditures,
$80 million for purchases of other property and equipment, $46 million of oil and gas property acquisitions (net of cash acquired), $26
million for the final payment under our Tax Sharing and Indemnification Agreement with Alliant Energy Corporation and $15 million
of debt issuance costs.
Cash Flows from 2013 Compared to 2012. During 2013, we generated $1.7 billion of cash provided by operating activities, an
increase of $344 million from 2012. Cash provided by operating activities increased primarily due to higher realized sales prices for
oil, NGLs and natural gas and higher crude oil and natural gas production volumes during 2013. These positive factors were partially
offset by increased lease operating expenses, production taxes, exploration costs, general and administrative expenses and cash
interest expense in 2013 as compared to 2012. 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 2013. Cash flows from operating activities plus $2.3
billion of proceeds from the issuance of our Senior Notes and $969 million of proceeds from the sale of properties were used to
finance $2.3 billion of drilling and development expenditures, $1.2 billion of net repayments under our credit agreement, $423 million
of oil and gas property acquisitions, $254 million for the redemption of our 7% Senior Subordinated Notes due 2014, $43 million in
investing derivative purchases (net of cash receipts for settlements), $45 million for purchases of other property and equipment and
$30 million of debt issuance costs.
Exploration, Development and Undeveloped Acreage Expenditures. The following chart details our exploration, development and
undeveloped acreage expenditures incurred by region (in thousands):
Rocky Mountains (1) .........................................................................
Permian Basin (2) ..............................................................................
Other (3) ............................................................................................
Total incurred ..............................................................................
$
$
2014
2,756,647 $
379,702
45,589
3,181,938 $
Year Ended
December 31,
2013
2,172,462 $
346,812
155,918
2,675,192 $
2012
1,581,934
410,154
119,431
2,111,519
_____________________
(1) For the year ended December 31, 2012, proceeds from the sale of the Belfield gas plant of $66 million have been included as a
reduction to expenditures in the Rocky Mountains region.
56
(2) For the year ended December 31, 2014, amount includes $76 million related to the acquisition of undeveloped acreage and the
development of CO2 reserves and facilities at our Bravo Dome field in New Mexico. For the year ended December 31, 2013
amount includes $21 million related to the acquisition of undeveloped acreage and related facilities at our Bravo Dome field in
New Mexico. For the year ended December 31, 2012, amount includes $11 million related to the acquisition of undeveloped
acreage at our Bravo Dome field in New Mexico.
(3) Other primarily includes oil and gas properties located in Louisiana, Michigan, Oklahoma and Texas.
We continually evaluate our capital needs and compare them to our capital resources. Our current 2015 E&D budget is $2.0 billion,
which we expect to fund substantially with net cash provided by our operating activities, cash on hand, borrowings under our credit
facility, or through the issuance of additional debt or equity securities. This represents a substantial decrease from the $3.2 billion
incurred on exploration, development and acreage expenditures during 2014. This reduced capital budget is in response to the
significantly lower crude oil prices experienced during the fourth quarter of 2014 and continuing into 2015. We expect to allocate
$1.8 billion of our 2015 budget to exploration and development activity, $59 million for undeveloped acreage and $123 million for
facilities. Although we have only budgeted $59 million for undeveloped leasehold purchases in 2015, 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 $2.0 billion, 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, including obligations arising as a result of the recent Kodiak Acquisition. On December 8,
2014, under the terms of the Kodiak Acquisition agreement, we acquired all of the outstanding common stock of Kodiak, whereby
Kodiak shareholders received 0.177 of a share of Whiting common stock in exchange for each share of Kodiak common stock they
owned, and we assumed or repaid all of Kodiak’s outstanding debt as of that date. With our expected cash flow streams, commodity
price hedging 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, our wholly-owned subsidiary, has a credit agreement with a syndicate of banks that as of
December 31, 2014 had a borrowing base of $4.5 billion, with aggregate commitments of $4.5 billion, of which $3.5 billion relates to
commitments to extend revolving credit and $1.0 billion relates to a Delayed Draw Facility. The Delayed Draw Facility may be used
to provide cash consideration for any repurchase or redemption of Kodiak’s outstanding senior notes in connection with the Kodiak
Acquisition, to pay transaction costs and for other corporate purposes. As of December 31, 2014, we had $3.1 billion of available
borrowing capacity, which was net of $1.4 billion in borrowings (which includes $925 million we borrowed to repay the debt
outstanding under Kodiak’s credit facility after the completion of the Kodiak Acquisition) and $3 million in letters of credit
outstanding. The revolving credit facility will mature on December 8, 2019, and the Delayed Draw Facility will mature on December
31, 2015.
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 such 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. At the time of the last redetermination, the applicable oil and gas prices were $92.68 per Bbl and $3.88 per Mcf,
whereas the quoted NYMEX prices for oil and gas on February 13, 2015 were $53.67 per Bbl and $2.81 per Mcf. Because oil and gas
prices are principal inputs into the valuation of our reserves, if oil and gas prices remain at their current levels for a prolonged period
or go lower, our borrowing base could be reduced at the next redetermination date or during future redeterminations. However, we
anticipate an increase in our proved reserves since the time of the last redetermination resulting from the Kodiak Acquisition as well
as drilling results, which factors are expected to have a positive impact on our borrowing base and may offset any borrowing base
reductions driven by a low price environment. Upon a redetermination of our borrowing base, either on a periodic or special
redetermination date, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately
repay a portion of our debt outstanding under the credit agreement.
A portion of the revolving credit facility in an aggregate amount not to exceed $100 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, 2014, $97 million was available for
additional letters of credit under the agreement.
The credit agreement provides for interest only payments until the expiration date of the agreement, when all outstanding borrowings
are due. Interest under the revolving credit facility 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 0.5% per annum, or an
adjusted LIBOR rate plus 1.0% per annum, or (ii) an adjusted LIBOR rate for a Eurodollar loan plus the margin in the table below.
57
Additionally, we also incur commitment fees as set forth in the table below on the unused portion of the aggregate commitments of the
lenders under the revolving credit facility.
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
0.50%
0.75%
1.00%
1.25%
1.50%
Applicable
Margin for
Eurodollar Loans
1.50%
1.75%
2.00%
2.25%
2.50%
Commitment
Fee
0.375%
0.375%
0.50%
0.50%
0.50%
Interest under the Delayed Draw Facility accrues at our option at either (i) a base rate for a base rate loan plus (A) 1.00% per annum
through March 8, 2015 and (B) 1.50% per annum from March 9, 2015 through the December 31, 2015 maturity date, or (ii) an
adjusted LIBOR rate for a Eurodollar loan plus (A) 2.00% per annum through March 8, 2015 and (B) 2.50% per annum from March 9,
2015 through the December 31, 2015 maturity date. We also incur commitment fees of 0.25% on the unused portion of the aggregate
commitments of the lenders under the Delayed Draw Facility.
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, 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 4.0 to 1.0 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, 2014. 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.
Under the terms of the credit agreement, at any time during which we have an investment-grade debt rating from Moody’s Investors
Service, Inc. or Standard & Poor’s Ratings Group and we have elected, at our discretion, to effect an investment-grade rating period,
(i) certain security requirements, including the borrowing base requirement, and restrictive covenants will cease to apply, (ii) certain
other restrictive covenants will become less restrictive, (iii) an asset coverage covenant will be imposed, and (iv) the interest rate
margin applicable to all revolving borrowings as well as the commitment fee with respect to the revolving facility will be based upon
our debt rating rather than the ratio of outstanding borrowings to the borrowing base.
For further information on the loan security related to our credit agreement, refer to the Long-Term Debt footnote in the notes to
consolidated financial statements.
Senior Notes and Senior Subordinated Notes. In September 2013, we issued at par $1.1 billion of 5% Senior Notes due March 2019
(the “2019 Senior Notes”) and $800 million of 5.75% Senior Notes due March 2021, and also in September 2013, we issued at 101%
of par an additional $400 million of 5.75% Senior Notes due March 2021 (collectively, the “2021 Senior Notes”). In September 2010,
we issued at par $350 million of 6.5% Senior Subordinated Notes due October 2018 (the “2018 Senior Subordinated Notes”).
Kodiak Senior Notes. In conjunction with the Kodiak Acquisition, Whiting US Holding Company, our wholly-owned subsidiary,
became a co-issuer of the Kodiak Notes. Upon closing of the Kodiak Acquisition, the Kodiak Indentures were amended to (i) modify
certain covenants and restrictions, (ii) to provide for unconditional and irrevocable guarantees by Whiting Petroleum Corporation and
Whiting Oil and Gas Corporation of the prompt payment, when due, of any amounts owed under the Kodiak Notes and the Kodiak
Indentures, and (iii) to allow Whiting US Holding Company to become a co-issuer of the Kodiak Notes. Also in conjunction with the
Kodiak Acquisition, in December 2014, each of the indentures governing our 2019 Senior Notes, 2021 Senior Notes and 2018 Senior
Subordinated Notes (collectively, the “Whiting Notes”) were amended to include Whiting US Holding Company, Kodiak and Whiting
Resources Corporation (formerly Kodiak Oil & Gas (USA) Inc.) as guarantors.
The indentures governing the Whiting 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. The indentures governing the Kodiak 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 2.25 to 1. If we were in violation of these covenants, then we may not be able to incur additional indebtedness,
including under Whiting Oil and Gas’ credit agreement. Additionally, the indentures governing the Whiting Notes and the Kodiak
Notes contain restrictive covenants that may limit our ability to, among other things, pay cash dividends, make certain other restricted
payments, 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
58
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, 2014. 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.
On January 7, 2015, as required under the Kodiak Indentures upon a change in control of Kodiak, Whiting offered to repurchase at
101% of par all $1,550 million principal amount of Kodiak Notes outstanding. The repurchase offer expires on March 3, 2015. We
expect to fund any payments due as a result of such repurchase offer with borrowings under our revolving credit facility.
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 any penalties that may be incurred under our physical delivery
contracts, since we cannot predict with accuracy the amount and timing of any such penalties if incurred. The following table
summarizes our obligations and commitments as of December 31, 2014 to make future payments under certain contracts, aggregated
by category of contractual obligation, for the time periods specified below (in thousands):
Payments due by period
Contractual Obligations
Long-term debt (1) ..........................................................
Cash interest expense on debt (2) ....................................
Asset retirement obligations (3) ......................................
Purchase obligations (4) ..................................................
Pipeline transportation agreements (5) ............................
Drilling rig contracts (6) ..................................................
Operating leases (7) .........................................................
Production Participation Plan liability (8) .......................
Total ........................................................................
Total
$ 5,600,000 $
Less than 1
year
1-3 years
3-5 years
More than 5
years
- $
- $ 3,650,000 $ 1,950,000
1,468,613
279,701
559,402
480,250
149,260
179,931
12,190
24,326
24,615
118,800
148,969
68,775
80,194
-
-
113,784
18,794
25,781
19,118
50,091
278,784
146,141
132,643
-
34,602
7,692
14,157
12,537
-
216
113,391
$ 7,938,074 $
113,391
646,684 $
-
-
836,503 $ 4,186,520 $ 2,268,367
-
_____________________
(1) Long-term debt consists of the principal amounts of the 6.5% Senior Subordinated Notes due 2018, the 5% Senior Notes due
2019, the 8.125% Senior Notes due 2019, the 5.5% Senior Notes due 2021, the 5.75% Senior Notes due 2021, the 5.5% Senior
Notes due 2022 and the outstanding borrowings under our credit agreement due in 2019. The $800 million of 8.125% Senior
Notes due 2019, $350 million of 5.5% Senior Notes due 2021 and $400 million of 5.5% Senior Notes due 2022 are subject to our
repurchase offer in connection with the Kodiak Acquisition that expires on March 3, 2015. See “—2014 Highlights and Future
Considerations – Financing Highlights” above for more information.
(2) Cash interest expense on our Senior Subordinated Notes and our Senior Notes 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 December 2019 instrument due date and is estimated at a fixed interest rate of 1.9%.
(3) 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 plants and facilities.
(4) We have three take-or-pay purchase agreements, of which one agreement expires in 2015 and two agreements expire in 2017.
One of these agreements contains commitments to buy certain volumes of CO2 for use in our North Ward Estes EOR project in
Texas. Under the remaining two take-or-pay agreements, we have committed to buy certain volumes of water for use in the
fracture stimulation process of wells in our Redtail field. Under the terms of these agreements, we are obligated to purchase a
minimum volume of CO2 or water, as the case may be, or else pay for any deficiencies at the price stipulated in the contract. The
CO2 volumes planned for use in the EOR project in our North Ward Estes field and the water volumes planned for use at our
Redtail field currently exceed the minimum volumes specified in all of these agreements. Therefore, we expect to avoid any
payments for deficiencies under these contracts. The purchasing obligations reported above represent our minimum financial
commitments pursuant to the terms of these contracts, however, our actual expenditures under these contracts are expected to
exceed the minimum commitments presented above.
59
(5) We have two ship-or-pay agreements with different suppliers, one expiring in 2015 and one expiring in 2017, whereby we have
committed to transport a minimum daily volume of CO2 or water, as the case may be, via certain pipelines or else pay for any
deficiencies at a price stipulated in the contracts. In addition, we have three pipeline transportation agreements with one supplier,
one expiring in 2024 and two expiring in 2025, whereby we have committed to pay fixed monthly reservation fees on dedicated
pipelines for natural gas and NGL transportation capacity from our Redtail field, plus a variable charge based on actual
transportation volumes.
(6) As of December 31, 2014, we had 18 drilling rigs under long-term contract, all of which were operating in the Rocky Mountains
region. Subsequent to December 31, 2014, we early terminated five of these long-term contracts incurring early termination
penalties of approximately $27 million. These penalties have been included as contractual commitment amounts in the table
above. Of the remaining 13 long-term contracts, seven expire in 2016 and six in 2017. Early termination of the remaining
contracts would require termination penalties of $212 million, which would be in lieu of paying the remaining drilling
commitments under these contracts. 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.
(7) We lease 197,000 square feet of administrative office space in Denver, Colorado under an operating lease arrangement expiring in
2019, 47,900 square feet of office space in Midland, Texas expiring in 2020, an additional 36,300 square feet of administrative
office space in Denver, Colorado assumed in the Kodiak Acquisition expiring in 2016, 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
and Dickinson, North Dakota under an operating lease agreement expiring in 2015.
(8) In June 2014, we terminated our Production Participation Plan effective December 31, 2013. Pursuant to the terms of the Plan,
upon termination we are required to 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. As of December 31, 2014, a portion of this liability
representing a regular distribution under the Plan totaling $41 million had been paid to our third-party payroll administrator.
However, these funds were not distributed by the payroll administrator to Plan participants until January 2015. The final Plan
distribution payment will be made in June 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 and the Delayed Draw Facility, will be
adequate to meet future liquidity needs, including satisfying our financial obligations and any obligations arising as a result of the
Kodiak Acquisition and funding our operations, 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 Summary of Significant Accounting Policies footnote in the notes to consolidated financial statements.
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 and our asset retirement obligations. 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,
60
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 the 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, 2014. 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 and impairment calculations (when impairment indicators arise)
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 our 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 quantity estimates as such quantities are dependent on the success of our exploration 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 their future net undiscounted cash flows to their net book values at the end of each period. If
their net capitalized costs exceed 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.
Goodwill Impairment. We test our goodwill for impairment annually in the second quarter or when events or changes in
circumstances indicate that the fair value of a reporting unit has been reduced below its carrying value. When testing goodwill for
impairment, if our qualitative analysis indicates that it is more likely than not that the fair value of the reporting unit is less than its
carrying value, we then perform a quantitative impairment test. If the carrying value of the reporting unit exceeds its fair value,
goodwill is written down to its implied fair value with an offsetting charge to earnings.
Asset Retirement Obligation. Our asset retirement obligations (“ARO”) consist 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 discount 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. On June 11, 2014, the Board of Directors terminated our Production Participation Plan (the “Plan”), in
which all employees participated, effective December 31, 2013. Prior to Plan termination, interests in oil and gas properties acquired,
developed or sold during the year were allocated to the Plan on an annual basis as determined by the Compensation Committee of the
Board of Directors. Once allocated, the interests (not legally conveyed) were fixed. The short-term obligation related to the Plan is
reflected in the “Current portion of Production Participation Plan liability” line item in our consolidated balance sheets. This
obligation at December 31, 2013 was based on cash flows during 2013 and was paid in cash in January 2014. The calculation of this
61
liability depended in part on our estimates of accrued revenues and costs as of December 31, 2013 as discussed below under “Revenue
Recognition.” The vested long-term obligation related to the Plan at December 31, 2013 is reflected in the “Production Participation
Plan liability” line item in the consolidated balance sheets. This liability was derived primarily from reserve report estimates as of that
date. Pursuant to the terms of the Plan, upon Plan termination all employees became fully vested, and the fully vested amount due to
Plan participants has been reflected as a current payable as of December 31, 2014, as it will be distributed to Plan participants during
the first half of 2015. This liability includes the value of proved undeveloped oil and gas properties awarded upon Plan termination,
and is based on reserve report estimates and forecasted commodity prices for crude oil, NGLs and natural gas as of the December 31,
2013 termination effective date.
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, it may also limit future revenues from favorable price movements. We primarily
utilize costless collars and swaps contracts, which are generally placed with major financial institutions, as well as fixed-differential
crude oil sales contracts.
All derivative instruments are recorded on the consolidated balance sheet at fair value, other than the derivative instruments that meet
the “normal purchase normal sale” 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 the 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 and swaps 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. We value our long-term crude oil sales and delivery contracts based on an income approach, which considers
various assumptions, including quoted forward prices for commodities, market differentials for crude oil and U.S. Treasury rates. 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 they relate
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 natural 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
62
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. We account for all of our business combinations using the purchase method, which is the only
method permitted under FASB ASC Topic 805, Business Combinations, and involves the use of significant judgment.
Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the
consideration given. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the
assets and liabilities based upon these fair values. The excess, if any, of the cost of an acquired entity over the net amounts assigned to
assets acquired and liabilities assumed is recognized as goodwill. The excess, if any, of the fair value of assets acquired and liabilities
assumed over the cost of an acquired entity 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 values 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. In general, 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 and consequently, there was no goodwill nor any bargain purchase gains recognized on our business
combinations. However, the purchase price allocation associated with the Kodiak Acquisition resulted in the recognition of goodwill.
For further information on the Kodiak Acquisition, refer to the Acquisitions and Divestitures footnote in the notes to consolidated
financial statements.
Effects of Inflation and Pricing
We experienced increased costs during 2013 and 2014 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 puts 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 our 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 Section 27A of the
Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. 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; risks related to our level of indebtedness and periodic redeterminations of the
borrowing base under our credit agreement; impacts to financial statements as a result of impairment write-downs; our ability to
successfully complete asset dispositions and the risks related thereto; 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 EOR projects; inaccuracies of our reserve estimates or our assumptions underlying them;
revisions to reserve estimates as a result of changes in commodity prices, regulation and other factors; risks relating to any unforeseen
liabilities of ours; 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 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; our
ability to identify and complete acquisitions and to successfully integrate acquired businesses; unforeseen underperformance of or
liabilities associated with acquired properties; the impacts of hedging on our results of operations; failure of our properties to yield oil
63
or gas in commercially viable quantities; availability of, and risks associated with, transport of oil and gas; our ability to drill
producing wells on undeveloped acreage prior to its lease expiration; shortages of or delays in obtaining qualified personnel or
equipment, including drilling rigs and completion services; 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; cyber security attacks or failures of our
telecommunication systems; our ability to successfully integrate Kodiak after the Kodiak Acquisition and achieve anticipated benefits
from the transaction; 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.
64
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. Based on 2014 production, our income before income taxes for 2014 would have moved up or
down $273 million for each 10% change in oil prices per Bbl, $13 million for each 10% change in NGL prices per Bbl and $17
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 and swap contracts, although we evaluate and have
entered into 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.
Commodity Derivative Contracts
Crude Oil Costless Collars and Swaps. The collared hedges shown in the table below have the effect of providing a protective floor
while allowing us to share in upward pricing movements. The three-way collars, however, do not provide complete protection against
declines in crude oil prices due to the fact that when the market price falls below the sub-floor, the minimum price we would receive
would be NYMEX plus the difference between the floor and the sub-floor. While these hedges are designed to reduce our exposure to
price decreases, they also have the effect of limiting the benefit of price increases above the ceiling. For the crude oil collars
outstanding as of December 31, 2014, a hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve as of
December 31, 2014 would cause a decrease or increase, respectively, of $2 million in our commodity derivative (gain) loss.
The swap contracts shown in the tables below entitle us to receive settlement from the counterparty in amounts, if any, by which the
settlement price for the applicable calculation period is less than the fixed price, or to pay the counterparty if the settlement price for
the applicable calculation period is more than the fixed price. While the fixed-price swaps are designed to decrease our exposure to
downward price movements, they also have the effect of limiting the benefit of upward price movements. For the swaps outstanding
as of December 31, 2014, a hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve as of December 31,
2014 would cause a decrease or increase, respectively, of $17 million in our commodity derivative (gain) loss.
Our outstanding hedges as of February 13, 2015 are summarized below:
Derivative
Instrument
Three-way collars (1)
Collars
Monthly Volume
Weighted Average
Commodity
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Period
01/2015 to 03/2015
04/2015 to 06/2015
07/2015 to 09/2015
10/2015 to 12/2015
01/2016 to 03/2016
04/2016 to 06/2016
07/2016 to 09/2016
10/2016 to 12/2016
01/2015 to 03/2015
04/2015 to 06/2015
07/2015 to 09/2015
10/2015 to 12/2015
01/2016 to 03/2016
04/2016 to 06/2016
07/2016 to 09/2016
10/2016 to 12/2016
01/2017 to 03/2017
04/2017 to 06/2017
07/2017 to 09/2017
10/2017 to 12/2017
65
(Bbl)
100,000
100,000
500,000
500,000
550,000
550,000
550,000
550,000
9,000
9,100
209,200
209,200
250,000
250,000
250,000
250,000
250,000
250,000
250,000
250,000
NYMEX Sub-Floor/Floor/Ceiling
$70.00/$85.00/$107.90
$70.00/$85.00/$107.90
$47.00/$58.00/$78.99
$47.00/$58.00/$78.99
$43.18/$53.18/$76.26
$43.18/$53.18/$76.26
$43.18/$53.18/$76.26
$43.18/$53.18/$76.26
$85.00/$102.75
$85.00/$102.75
$51.06/$57.37
$51.06/$57.37
$51.00/$63.48
$51.00/$63.48
$51.00/$63.48
$51.00/$63.48
$53.00/$70.44
$53.00/$70.44
$53.00/$70.44
$53.00/$70.44
Derivative
Instrument
Swaps
Monthly Volume
Weighted Average
Commodity
Crude oil
Crude oil
Crude oil
Crude oil
Period
01/2015 to 03/2015
04/2015 to 06/2015
07/2015 to 09/2015
10/2015 to 12/2015
(Bbl)
335,700
339,430
259,160
251,230
NYMEX Sub-Floor/Floor/Ceiling
$93.33
$93.33
$76.57
$76.25
_____________________
(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-differential Crude Oil Contracts. We have entered into two fixed-differential crude oil sales and delivery contracts for oil
volumes we plan to produce from the Niobrara in Colorado.
The table below summarizes the future production volumes to be sold under one of these contracts as of January 1, 2015 at a price
equal to NYMEX less a fixed differential of $4.75 per Bbl. When we are unable to deliver the production volumes specified in this
contract, the fixed differential increases proportionately.
Commodity
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Period
04/2015 to 12/2015
01/2016 to 12/2016
01/2017 to 12/2017
01/2018 to 12/2018
01/2019 to 12/2019
01/2020 to 03/2020
Daily Volume
(Bbl per day)
25,000
28,750
33,750
38,750
43,750
45,000
The table below summarizes the future production volumes to be sold under the second contract as of January 1, 2015 at a price equal
to NYMEX less certain fixed differentials depending on the delivery methods specified in the contract.
Commodity
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Period
04/2015 to 12/2015
01/2016 to 12/2016
01/2017 to 12/2017
01/2018 to 12/2018
01/2019 to 12/2019
01/2020 to 03/2020
Daily Volume
(Bbl per day)
20,000
20,000
20,000
20,000
20,000
20,000
As of December 31, 2014, we determined that it is no longer probable that future oil production from our Redtail field will be
sufficient to meet the minimum volume requirements specified in these fixed-differential crude oil contracts, and accordingly, that we
will not settle these contracts through physical delivery of crude oil volumes. As a result, we have determined that these contracts no
longer qualify for the “normal purchase normal sale” exclusion, and we have therefore reflected these contracts at fair value in the
consolidated financial statements. For these commodity derivative contracts, a hypothetical $10.00 per Bbl increase in the market
differential for crude oil as of December 31, 2014 would cause an increase in our commodity derivative (gain) loss of $42 million,
whereas a hypothetical $10.00 per Bbl decrease in the market differential for crude oil would cause a decrease in our commodity
derivative (gain) loss of $43 million.
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. At December 31, 2014, our outstanding principal balance under our credit agreement was $1.4 billion, and the weighted
average interest rate on the outstanding principal balance was 1.9%. At December 31, 2014, the carrying amount approximated fair
market value. Assuming a constant debt level of $1.4 billion, the cash flow impact resulting from a 100 basis point change in interest
66
rates during periods when the interest rate is not fixed would be $14 million over a 12-month time period. Changes in interest rates do
not affect the amount of interest we pay on our fixed-rate Senior Notes or Senior Subordinated Notes, but interest rates do affect the
fair values of our Senior Notes and Senior Subordinated Notes.
67
Item 8. Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm ..................................................................................................................
Consolidated Balance Sheets as of December 31, 2014 and 2013 .........................................................................................................
Consolidated Statements of Income for the Years Ended December 31, 2014, 2013 and 2012 ............................................................
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012 ..................................
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012 .....................................................
Consolidated Statements of Equity for the Years Ended December 31, 2014, 2013 and 2012 .............................................................
Notes to Consolidated Financial Statements ..........................................................................................................................................
69
70
71
72
73
75
76
68
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, 2014 and 2013, 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, 2014. 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, 2014 and 2013, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2014, 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, 2014, based on the criteria established in Internal Control—
Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report
dated February 27, 2015 expressed an unqualified opinion on the Company's internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 27, 2015
69
WHITING PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)
December 31,
2014
2013
ASSETS
Current assets:
Cash and cash equivalents ...............................................................................................
Accounts receivable trade, net ........................................................................................
Derivative assets .............................................................................................................
Prepaid expenses and other .............................................................................................
Total current assets .....................................................................................................
$
$
78,100
543,172
135,577
86,150
842,999
Property and equipment:
Oil and gas properties, successful efforts method ...........................................................
Other property and equipment.........................................................................................
Total property and equipment ....................................................................................
Less accumulated depreciation, depletion and amortization ...........................................
Total property and equipment, net ..............................................................................
Goodwill ..............................................................................................................................
Debt issuance costs ..............................................................................................................
Other long-term assets .........................................................................................................
TOTAL ASSETS ................................................................................................................
$
14,949,702
276,582
15,226,284
(3,083,572)
12,142,712
875,676
53,274
104,843
14,019,504
LIABILITIES AND EQUITY
Current liabilities:
$
Accounts payable trade ...................................................................................................
Accrued capital expenditures ..........................................................................................
Revenues and royalties payable ......................................................................................
Current portion of Production Participation Plan liability ..............................................
Accrued liabilities and other ...........................................................................................
Taxes payable ..................................................................................................................
Accrued interest ..............................................................................................................
Deferred income taxes .....................................................................................................
Total current liabilities ...............................................................................................
Long-term debt ....................................................................................................................
Deferred income taxes .........................................................................................................
Production Participation Plan liability .................................................................................
Asset retirement obligations ................................................................................................
Deferred gain on sale ...........................................................................................................
Other long-term liabilities ....................................................................................................
Total liabilities ............................................................................................................
Commitments and contingencies .........................................................................................
Equity:
Common stock, $0.001 par value, 300,000,000 shares authorized; 168,346,020
issued and 166,889,152 outstanding as of December 31, 2014 and 120,101,555
issued and 118,657,245 outstanding as of December 31, 2013...................................
Additional paid-in capital ................................................................................................
Retained earnings ............................................................................................................
Total Whiting shareholders' equity .............................................................................
Noncontrolling interest ....................................................................................................
Total equity ................................................................................................................
TOTAL LIABILITIES AND EQUITY ............................................................................
$
See notes to consolidated financial statements.
70
699,460
341,177
1,274
27,707
1,069,618
10,065,150
206,385
10,271,535
(2,676,490)
7,595,045
-
48,530
120,277
8,833,470
107,692
158,739
198,558
73,264
144,327
50,052
44,405
648
777,685
2,653,834
1,278,030
87,503
116,442
79,065
4,212
4,996,771
120
1,583,542
2,244,905
3,828,567
8,132
3,836,699
8,833,470
$
$
62,664
429,970
254,018
113,391
169,193
63,822
67,913
47,545
1,208,516
5,628,782
1,230,630
-
167,741
60,305
20,486
8,316,460
168
3,385,094
2,309,712
5,694,974
8,070
5,703,044
14,019,504
$
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(in thousands, except per share data)
REVENUES AND OTHER INCOME:
Oil, NGL and natural gas sales .......................................................
Gain (loss) on hedging activities.....................................................
Amortization of deferred gain on sale ............................................
Gain on sale of properties ...............................................................
Interest income and other ................................................................
Total revenues and other income .............................................
$
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 ..........................................................
Year Ended
December 31,
2013
2,666,549 $
(1,958)
31,737
128,648
3,409
2,828,385
430,221
225,403
891,516
453,210
137,994
112,936
4,412
(6,980)
7,802
2,256,514
2014
3,024,617 $
-
30,494
27,657
2,329
3,085,097
496,925
253,008
1,089,545
854,430
177,211
170,642
-
-
(100,579)
2,941,182
2012
2,137,714
2,338
29,458
3,423
519
2,173,452
376,424
171,625
684,724
166,972
108,573
75,210
-
13,824
(85,911)
1,511,441
INCOME BEFORE INCOME TAXES .............................................
143,915
571,871
662,011
INCOME TAX EXPENSE (BENEFIT):
Current ............................................................................................
Deferred ..........................................................................................
Total income tax expense ........................................................
NET INCOME .....................................................................................
Net loss attributable to noncontrolling interests .............................
NET INCOME AVAILABLE TO SHAREHOLDERS ....................
Preferred stock dividends................................................................
2,625
76,545
79,170
64,745
62
64,807
-
986
204,882
205,868
366,003
52
366,055
(538)
(669)
248,581
247,912
414,099
90
414,189
(1,077)
NET INCOME AVAILABLE TO COMMON
SHAREHOLDERS .......................................................................
$
64,807 $
365,517 $
413,112
EARNINGS PER COMMON SHARE:
Basic ...............................................................................................
Diluted ............................................................................................
$
$
0.53 $
0.53 $
3.09 $
3.06 $
3.51
3.48
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic ...............................................................................................
Diluted ............................................................................................
122,138
122,519
118,260
119,588
117,601
119,028
See notes to consolidated financial statements.
71
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in thousands)
Year Ended
December 31,
2013
2014
2012
NET INCOME .....................................................................................
$
64,745 $
366,003 $
414,099
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
OCI amortization on de-designated hedges (1) (2) ...........................
Total other comprehensive income (loss), net of tax ...............
COMPREHENSIVE INCOME ..........................................................
Comprehensive loss attributable to noncontrolling interest ..........
-
-
64,745
62
1,236
1,236
367,239
52
(1,476)
(1,476)
412,623
90
COMPREHENSIVE INCOME ATTRIBUTABLE TO
WHITING....................................................................................
$
64,807 $
367,291 $
412,713
_____________________
(1) Presented net of income tax expense of $722 for the year ended December 31, 2013 and an income tax benefit of $862 for the
year ended December 31, 2012.
(2) These OCI amortization amounts on de-designated hedges are reclassified from accumulated other comprehensive income
(“AOCI”) to gain (loss) on hedging activities in the consolidated statements of income.
See notes to consolidated financial statements.
72
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
$
activities:
Depreciation, depletion and amortization ..........................................................
Deferred income tax expense ............................................................................
Amortization of debt issuance costs and debt premium ....................................
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 .............................................
Non-cash portion of derivative gains.................................................................
Other, net ...........................................................................................................
Changes in current assets and liabilities:
Accounts receivable trade, net ...........................................................................
Prepaid expense and other .................................................................................
Accounts payable trade and accrued liabilities ..................................................
Revenues and royalties payable .........................................................................
Taxes payable ....................................................................................................
Net cash provided by operating activities .....................................................
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and development capital expenditures ......................................................
Acquisition of oil and gas properties, net of cash acquired ....................................
Other property and equipment................................................................................
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 ....................................................................................
Cash paid for investing derivatives ........................................................................
Cash settlements received on investing derivatives ...............................................
Net cash used in investing activities .............................................................
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of 5% Senior Notes due 2019 ..................................................................
Issuance of 5.75% Senior Notes due 2021 .............................................................
Redemption of 7% Senior Subordinated Notes due 2014 ......................................
Borrowings under credit agreement .......................................................................
Repayments of borrowings under credit agreement ...............................................
Repayment of tax sharing liability .........................................................................
Debt issuance costs ................................................................................................
Restricted stock used for tax withholdings .............................................................
Proceeds from stock options exercised ..................................................................
Preferred stock dividends paid ...............................................................................
Net cash provided by financing activities .....................................................
$
See notes to consolidated financial statements.
73
Year Ended
December 31,
2013
2014
2012
64,745 $
366,003 $
414,099
1,089,545
76,545
11,984
23,258
(30,494)
(27,657)
767,627
26,327
-
-
(57,465)
(9,030)
17,618
(50,352)
(86,480)
(1,963)
1,094
1,815,302
(2,842,837)
(45,573)
(79,955)
107,848
-
-
-
-
(2,860,517)
-
-
-
2,150,000
(1,675,000)
(26,373)
(14,901)
(11,652)
1,781
-
423,855 $
891,516
204,882
12,405
22,436
(31,737)
(128,648)
358,455
28,725
4,412
(6,980)
(20,830)
(16,118)
(22,912)
(15,981)
33,360
48,988
16,769
1,744,745
(2,349,819)
(422,923)
(45,304)
968,606
-
(10,530)
(44,900)
2,371
(1,902,499)
1,100,000
1,204,000
(253,988)
1,860,000
(3,060,000)
(1,759)
(29,690)
(5,611)
-
(538)
812,414 $
684,724
248,581
9,518
18,190
(29,458)
(3,423)
107,855
18,428
-
13,824
(115,733)
(18,708)
(55,750)
2,535
58,647
45,798
2,088
1,401,215
(2,050,029)
(125,282)
3,852
69,190
322,257
(306)
-
-
(1,780,318)
-
-
-
2,340,000
(1,920,000)
(2,329)
(2,807)
(5,695)
-
(1,077)
408,092
(Continued)
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,
2013
654,660 $
2014
(621,360) $
2012
28,989
Beginning of period................................................................................................
End of period ..........................................................................................................
$
699,460
78,100 $
44,800
699,460 $
15,811
44,800
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Income taxes paid (refunded), net ..........................................................................
Interest paid, net of amounts capitalized ................................................................
$
$
1,380 $
135,150 $
3,681 $
66,541 $
(268)
68,005
NONCASH INVESTING AND FINANCING ACTIVITIES:
Accrued capital expenditures related to property additions ...................................
Fair value of equity issued and debt assumed in the Kodiak Acquisition ..............
$
429,970 $
$ 4,289,088 $
158,739 $
- $
110,663
-
See notes to consolidated financial statements.
(Concluded)
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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 and Permian Basin
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, including the determination of any resulting goodwill;
(6) income taxes; (7) 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, 2014 and 2013, the Company had an allowance for doubtful accounts of $9 million and $4 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 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.
76
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 2014, 2013 and 2012, the Company capitalized interest of $4 million, $2 million and $3 million,
respectively.
Unproved. Unproved properties consist of costs to acquire undeveloped leases as well as purchases of 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 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 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 of (i) materials and supplies inventories, (ii) leasehold costs
and development costs of our CO2 source properties and (iii) other property and equipment including, furniture and fixtures, buildings,
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 30 years.
Goodwill—Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in a business
combination. Goodwill has an indefinite useful life and is not amortized, but rather is tested by the Company for impairment annually
in the second quarter or when events or changes in circumstances indicate that the fair value of a reporting unit has been reduced
below its carrying value. If the Company’s qualitative analysis indicates that it is more likely than not that the fair value of the
reporting unit is less than its carrying value, the Company then performs a quantitative impairment test. If the carrying value of the
reporting unit exceeds its fair value, goodwill is written down to its implied fair value with an offsetting charge to earnings.
Debt Issuance Costs—Debt issuance costs related to the Company’s Senior Notes and 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.
Derivative Instruments—The Company enters into derivative contracts, primarily costless collars and swap contracts, to manage its
exposure to commodity price risk. All derivative instruments, other than those that meet the “normal purchase normal sale” 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, and as of December 31, 2013, all amounts related to de-designated cash flow hedges had been reclassified
into earnings.
77
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.
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 acquired 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.
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.
Revenue Recognition—Oil and gas revenues are recognized when production volumes are sold to a purchaser at a fixed or
determinable price, delivery has occurred and title has transferred, persuasive evidence of a sales arrangement exists and 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. The Company’s aggregate imbalance
positions as of December 31, 2014 and 2013 were not significant.
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 which participate in oil and gas properties operated by Whiting.
Acquisition Costs—Acquisition related expenses, which consist of external costs directly related to the Company’s acquisitions, such
as advisory, legal, accounting, valuation and other professional fees, are expensed as incurred.
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.
78
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, 2014, 2013 and 2012:
Plains Marketing LP ........................................................................
Shell Trading US .............................................................................
Bridger Trading LLC .......................................................................
Eighty Eight Oil Company ...............................................................
2014
17%
10%
10%
6%
2013
21%
14%
8%
11%
2012
20%
14%
11%
11%
Commodity derivative contracts held by the Company are with seven 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, 2014,
outstanding derivative contracts with Wells Fargo Bank, N.A., JP Morgan Chase Bank, N.A. and Canadian Imperial Bank of
Commerce represented 34%, 28% and 13%, respectively, of total crude oil volumes hedged.
Reclassifications—Certain prior period balances in the consolidated balance sheets have been reclassified to conform to the current
year presentation. Such reclassifications had no impact on net income, cash flows or shareholders’ equity previously reported.
Adopted and Recently Issued Accounting Pronouncements—In February 2013, the FASB issued Accounting Standards Update No.
2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed
at the Reporting Date (“ASU 2013-04”). The objective of ASU 2013-04 is to provide guidance for the recognition, measurement and
disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the
scope of this guidance is fixed at the reporting date. ASU 2013-04 is effective for fiscal years, and interim periods within those years,
beginning after December 15, 2013. The Company adopted ASU 2013-04 effective January 1, 2014, which did not have an impact on
the Company’s consolidated financial statements.
In July 2013, the FASB issued Accounting Standards Update No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net
Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (“ASU 2013-11”). The objective of ASU
2013-11 is to provide guidance on financial statement presentation of an unrecognized tax benefit when a net operating loss
carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 is effective for fiscal years, and interim periods
within those years, beginning after December 15, 2013. The Company adopted ASU 2013-11 effective January 1, 2014, which did
not have an impact on the Company’s consolidated financial statements, other than insignificant balance sheet reclassifications.
In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU
2014-09”). The objective of ASU 2014-09 is to clarify the principles for recognizing revenue and to develop a common revenue
standard for U.S. GAAP and International Financial Reporting Standards. ASU 2014-09 is effective for fiscal years, and interim
periods within those years, beginning after December 15, 2016. The Company is currently evaluating the impact of adopting ASU
2014-09, but the standard is not expected to have a significant effect on its consolidated financial statements.
In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Presentation of Financial Statements – Going Concern
(“ASU 2014-15”). The objective of ASU 2014-15 is to provide guidance on management’s responsibility to evaluate whether there is
substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15
is effective for fiscal years ending after December 15, 2016, and annual and interim periods thereafter. This standard is not expected
to have an impact on the Company’s consolidated financial statements.
79
2. OIL AND GAS PROPERTIES
Net capitalized costs related to the Company’s oil and gas producing activities at December 31, 2014 and 2013 are as follows (in
thousands):
Proved leasehold costs .........................................................................................................
Unproved leasehold costs ....................................................................................................
Costs of completed wells and facilities ................................................................................
Wells and facilities in progress ............................................................................................
Total oil and gas properties, successful efforts method ................................................
Accumulated depletion ........................................................................................................
Oil and gas properties, net ............................................................................................
$
$
December 31,
2014
3,637,026 $
1,232,040
9,319,808
760,828
14,949,702
(3,003,270)
11,946,432 $
2013
1,633,495
372,298
7,563,350
496,007
10,065,150
(2,645,841)
7,419,309
3. ACQUISITIONS AND DIVESTITURES
2014 Acquisitions
On December 8, 2014, the Company completed the acquisition of Kodiak Oil & Gas Corp. (now known as Whiting Canadian Holding
Company ULC, “Kodiak”), whereby Whiting acquired all of the outstanding common stock of Kodiak (the “Kodiak Acquisition”).
Pursuant to the terms of the Kodiak Acquisition agreement, Kodiak shareholders received 0.177 of a share of Whiting common stock
in exchange for each share of Kodiak common stock they owned. Total consideration for the Kodiak Acquisition was $1.8 billion,
consisting of 47,546,139 Whiting common shares issued at the market price of $37.25 per share on the date of issuance plus the fair
value of Kodiak’s outstanding equity awards assumed by Whiting. The aggregate purchase price of the transaction was $4.3 billion,
which includes the assumption of Kodiak’s outstanding debt of $2.5 billion as of December 8, 2014 and the net cash acquired of $19
million.
Kodiak was an independent energy company focused on exploration and production of crude oil and natural gas reserves, primarily in
the Williston Basin region of the United States. As a result of the Kodiak Acquisition, Whiting acquired approximately 327,000 gross
(178,000 net) acres located primarily in North Dakota, including interests in 778 producing oil and gas wells and undeveloped
acreage. Approximately 10,000 of the net acres acquired were located in Wyoming and Colorado.
The acquisition significantly expanded the Company’s presence in the Williston Basin, adding undeveloped acreage, oil and natural
gas reserves and production that were complementary to its existing asset base and operations in this area. As a result of this
acquisition, Whiting became the largest Bakken/Three Forks producer in the Williston Basin as of the acquisition date.
The Kodiak Acquisition was accounted for using the acquisition method of accounting for business combinations. The allocation of
the preliminary estimated purchase price is based upon management’s estimates and assumptions related to the fair value of assets
acquired and liabilities assumed on the acquisition date using currently available information. Transaction costs relating to the Kodiak
Acquisition were expensed as incurred. The initial accounting for the Kodiak Acquisition is preliminary, and adjustments to
provisional amounts (such as goodwill, certain accrued liabilities and their related deferred taxes), or recognition of additional assets
acquired or liabilities assumed, may occur as additional information is obtained about facts and circumstances that existed as of the
acquisition date.
80
The preliminary consideration transferred, fair value of assets acquired and liabilities assumed, and the resulting goodwill as of the
acquisition date are as follows (in thousands):
Consideration:
Fair value of Whiting’s common stock issued (1) .......................................................................................
Fair value of Kodiak restricted stock units assumed by Whiting (2) ...........................................................
Fair value of Kodiak options assumed by Whiting ....................................................................................
Total consideration .............................................................................................................................
Fair value of liabilities assumed:
Accounts payable trade ..............................................................................................................................
Accrued capital expenditures .....................................................................................................................
Revenues and royalties payable .................................................................................................................
Accrued liabilities and other ......................................................................................................................
Taxes payable ............................................................................................................................................
Accrued interest .........................................................................................................................................
Current deferred tax liability .....................................................................................................................
Long-term debt ..........................................................................................................................................
Asset retirement obligations ......................................................................................................................
Other long-term liabilities ..........................................................................................................................
Amount attributable to liabilities assumed .........................................................................................
Fair value of assets acquired:
Cash and cash equivalents .........................................................................................................................
Accounts receivable trade, net ...................................................................................................................
Derivative asset ..........................................................................................................................................
Prepaid expenses and other ........................................................................................................................
Oil and gas properties, successful efforts method:
$
$
$
$
$
1,771,094
9,596
7,523
1,788,213
18,390
104,509
57,423
45,695
12,676
18,070
30,279
2,500,875
8,646
15,735
2,812,298
18,879
219,654
85,718
8,624
Proved properties ...................................................................................................................................
Unproved properties ...............................................................................................................................
Other property and equipment ...................................................................................................................
Long-term deferred tax asset .....................................................................................................................
Other long-term assets ...............................................................................................................................
Amount attributable to assets acquired ...............................................................................................
Goodwill ...........................................................................................................................................................
_____________________
(1) 47,546,139 shares of Whiting common stock at $37.25 per share (closing price as of December 5, 2014), based on Kodiak’s
2,266,607
1,000,396
11,347
107,497
6,113
3,724,835
875,676
$
$
268,622,497 common shares outstanding at closing.
(2) 257,601 shares of Whiting common stock issued at $37.25 per share (closing price as of December 5, 2014), based on Kodiak’s
1,455,409 restricted stock units held by employees as of December 8, 2014.
Goodwill recognized as a result of the Kodiak Acquisition totaled $876 million, none of which is deductible for income tax purposes.
Goodwill is primarily attributable to the operational and financial synergies expected to be realized from the acquisition, including
employing optimized completion techniques on Kodiak's undrilled acreage which will improve hydrocarbon recovery, realized
savings in drilling and well completion costs, the accelerated development of Kodiak’s asset base, and the acquisition of experienced
oil and gas technical personnel.
The results of operations of Kodiak from the December 8, 2014 closing date through December 31, 2014, representing approximately
$46 million of revenue and $17 million of net income, have been included in Whiting’s consolidated statements of income for the year
ended December 31, 2014.
2014 Divestitures
On March 27, 2014, the Company completed the sale of approximately 49,900 gross (41,000 net) acres in its Big Tex prospect, which
consisted mainly of undeveloped acreage as well as its interests in certain producing oil and gas wells, located in the Delaware Basin
of Texas for a cash purchase price of $76 million resulting in a pre-tax gain on sale of $12 million.
81
2013 Acquisitions
On September 20, 2013, the Company completed the acquisition of approximately 39,300 gross (17,300 net) acres in the Williston
Basin, including interests in 121 producing oil and gas wells and undeveloped acreage, located in Williams and McKenzie counties of
North Dakota and Roosevelt and Richland counties of Montana for an initial purchase price of $261 million. Revenue and earnings
from these properties since the September 20, 2013 acquisition date are not material, and disclosures of pro forma revenues and net
income for this acquisition of these wells are also not material and have not been presented accordingly.
The acquisition was recorded using the purchase method of accounting. The initial purchase price has been adjusted for post-closing
settlements that have occurred since the acquisition date totaling $6 million. The following table summarizes the allocation of the
$256 million adjusted purchase price to the tangible assets acquired and liabilities assumed in this acquisition of oil and gas properties
(in thousands):
Purchase price ...................................................................................................................................................
Allocation of purchase price:
Oil and gas properties, successful efforts method:
Proved properties ...................................................................................................................................
Unproved properties ...............................................................................................................................
Oil in tank inventory ..................................................................................................................................
Accounts receivable ...................................................................................................................................
Asset retirement obligations ......................................................................................................................
Total ....................................................................................................................................................
$
$
$
255,537
229,002
27,335
522
578
(1,900)
255,537
2013 Divestitures
On October 31, 2013, the Company completed the sale of approximately 45,000 gross (32,200 net) acres in its Big Tex prospect,
which consisted mainly of undeveloped acreage as well as its interests in certain producing oil and gas wells, located in the Delaware
Basin of Texas for a cash purchase price of $151 million, resulting in a pre-tax gain on sale of $11 million. Of the total net acres sold,
approximately 30,800 net acres are located in Pecos County, Texas, and approximately 1,400 net acres are located in Reeves County,
Texas.
On July 15, 2013, the Company completed the sale of its interests in certain oil and gas producing properties located in its EOR
projects in the Postle and Northeast Hardesty fields in Texas County, Oklahoma, including the related Dry Trail plant gathering and
processing facility, oil delivery pipeline, its entire 60% interest in the Transpetco CO2 pipeline, crude oil swap contracts and certain
other related assets and liabilities (collectively the “Postle Properties”) for a cash purchase price of $809 million after selling costs and
post-closing adjustments. This divestiture resulted in a pre-tax gain on sale of $109 million. The Company used the net proceeds
from this sale to repay a portion of the debt outstanding under its credit agreement.
2012 Acquisitions
There were no significant acquisitions during the year ended December 31, 2012.
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 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 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 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.
82
Unaudited Pro Forma Operating Results
The following unaudited pro forma combined results of operations for the years ended December 31, 2014 and 2013 are derived from
the historical consolidated financial statements of Whiting and Kodiak and give effect to the Kodiak Acquisition as if it had occurred
on January 1, 2013.
Total revenues ......................................................................................................................
Net income available to common shareholders....................................................................
December 31,
2014
2013
(in thousands, except per share data)
3,774,137
576,450
4,141,046 $
362,376 $
$
$
Earnings per common share:
Basic .............................................................................................................................
Diluted ..........................................................................................................................
$
$
2.18 $
2.17 $
3.48
3.46
The unaudited pro forma combined results of operations reflect pro forma adjustments based on available information and certain
assumptions that the Company believes are reasonable, including (i) Whiting common stock and equity awards issued to convert
Kodiak’s outstanding shares of common stock and equity awards as of the closing date of the transaction, (ii) adjustments to conform
Kodiak’s historical policy of accounting for its oil and natural gas properties from the full cost method to the successful efforts method
of accounting, (iii) depletion of Kodiak’s fair-valued proved oil and gas properties, (iv) adjustments to interest expense to reflect the
assumption of Kodiak’s debt by Whiting, and (v) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma
earnings for the year ended December 31, 2014 were adjusted to exclude $86 million of acquisition-related costs incurred by Whiting
and Kodiak, and the pro forma earnings for the year ended December 31, 2013 were adjusted to include these charges.
The unaudited pro forma financial information has been prepared for informational purposes only and does not purport to represent
what Whiting’s results of operations would have been had the transactions actually been consummated on the assumed dates nor are
they indicative of future results of operations. The unaudited pro forma combined financial information does not reflect future events
that may occur after the transactions including, but not limited to, the anticipated realization of ongoing savings from operating
efficiencies from the Kodiak Acquisition.
4. LONG-TERM DEBT
Long-term debt consisted of the following at December 31, 2014 and 2013 (in thousands):
December 31,
2014
2013
Credit agreement ..................................................................................................................
6.5% Senior Subordinated Notes due 2018 ..........................................................................
5% Senior Notes due 2019 ...................................................................................................
8.125% Senior Notes due 2019, including unamortized debt premium of $23,742 .............
5.75% Senior Notes due 2021, including unamortized debt premium of $3,180 and
$3,834, respectively ......................................................................................................
5.5% Senior Notes due 2021, including unamortized debt premium of $867......................
5.5% Senior Notes due 2022, including unamortized debt premium of $993......................
Total debt ...............................................................................................................
$
$
1,400,000 $
350,000
1,100,000
823,742
1,203,180
350,867
400,993
5,628,782 $
-
350,000
1,100,000
-
1,203,834
-
-
2,653,834
The following table shows five succeeding fiscal years of scheduled maturities for the Company’s long-term debt as of December 31,
2014 (in thousands):
2015
2016
Long-term debt (1) .......
_____________________
(1) Refer to “Kodiak Senior Notes Repurchase Offer” below for more information.
-
-
$
$
$
2017
2018
-
$
350,000
$
2019
3,300,000
Credit Agreement—In August 2014, Whiting Oil and Gas Corporation (“Whiting Oil and Gas”), the Company’s wholly-owned
subsidiary, entered into a Sixth Amended and Restated Credit Agreement with a syndicate of banks, which replaced its existing credit
agreement upon closing of the Kodiak Acquisition on December 8, 2014. This amended credit agreement increased the borrowing
83
base under Whiting Oil and Gas’ credit facility to $4.5 billion, with aggregate commitments of $3.5 billion. Subsequently in
December 2014, the lenders under the credit agreement increased their aggregate commitments under this amended agreement from
$3.5 billion to $4.5 billion, of which $3.5 billion relates to commitments to extend revolving credit and $1.0 billion relates to a senior
secured delayed draw term loan facility (“Delayed Draw Facility”). The Delayed Draw Facility may be used to provide cash
consideration for any repurchase or redemption of Kodiak’s outstanding senior notes in connection with the Kodiak Acquisition, to
pay transaction costs and for other corporate purposes. Under the amended credit agreement, the revolving credit facility will mature
on December 8, 2019, and the Delayed Draw Facility will mature on December 31, 2015. As of December 31, 2014, the Company
had $3.1 billion of available borrowing capacity, which was net of $1.4 billion in borrowings and $3 million in letters of credit
outstanding.
The borrowing base under the credit agreement is determined at the discretion of the lenders, based on the collateral value of the
Company’s proved reserves that have been mortgaged to such 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. Upon a redetermination of our borrowing base, either on a periodic or special redetermination date, if
borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of our
debt outstanding under the credit agreement. A portion of the revolving credit facility in an aggregate amount not to exceed $100
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, 2014, $97 million was available for additional letters of credit under the agreement.
The credit agreement provides for interest only payments until the expiration date of the agreement, when all outstanding borrowings
are due. Interest under the revolving credit facility 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 0.5% per
annum, or an adjusted LIBOR rate plus 1.0% per annum, 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
aggregate commitments of the lenders under the revolving credit facility, which are included as a component of interest expense. At
December 31, 2014, the entire $1.4 billion outstanding principal balance under the credit agreement was under the revolving credit
facility with a weighted average interest rate of 1.9%.
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
0.50%
0.75%
1.00%
1.25%
1.50%
Applicable
Margin for
Eurodollar Loans
1.50%
1.75%
2.00%
2.25%
2.50%
Commitment
Fee
0.375%
0.375%
0.50%
0.50%
0.50%
Interest under the Delayed Draw Facility accrues at the Company’s option at either (i) a base rate for a base rate loan plus (A) 1.00%
per annum through March 8, 2015 and (B) 1.50% per annum from March 9, 2015 through the December 31, 2015 maturity date, or (ii)
an adjusted LIBOR rate for a Eurodollar loan plus (A) 2.00% per annum through March 8, 2015 and (B) 2.50% per annum from
March 9, 2015 through the December 31, 2015 maturity date. We also incur commitment fees of 0.25% on the unused portion of the
aggregate commitments of the lenders under the Delayed Draw Facility.
The amended 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, 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 the subsidiaries. As of December 31, 2014, total restricted net assets were $6.9 billion, and
the amount of retained earnings free from restrictions was $24 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 4.0 to 1.0
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, 2014.
Under the terms of the credit agreement, at any time during which Whiting has an investment-grade debt rating from Moody’s
Investors Service, Inc. or Standard & Poor’s Ratings Group and Whiting has elected, at its discretion, to effect an investment-grade
rating period, (i) certain security requirements, including the borrowing base requirement, and restrictive covenants will cease to
apply, (ii) certain other restrictive covenants will become less restrictive, (iii) an additional financial covenant will be imposed, and
(iv) the interest rate margin applicable to all revolving borrowings as well as the commitment fee with respect to the revolving facility
will be based upon the Company’s debt rating rather than the ratio of outstanding borrowings to the borrowing base.
84
The obligations of Whiting Oil and Gas under the credit agreement are secured by a first lien on substantially all of Whiting Oil and
Gas’ and Whiting Resource Corporation’s 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 its subsidiaries as security
for its guarantee.
Senior Notes and Senior Subordinated Notes—In September 2010, the Company issued at par $350 million of 6.5% Senior
Subordinated Notes due October 2018 (the “2018 Senior Subordinated Notes”). The estimated fair value of these notes was $345
million and $371 million as of December 31, 2014 and 2013, respectively, based on quoted market prices for these debt securities, and
such fair value is therefore designated as Level 1 within the valuation hierarchy.
Issuance of Senior Notes. In September 2013, the Company issued at par $1.1 billion of 5% Senior Notes due March 2019 (the “2019
Senior Notes”) and $800 million of 5.75% Senior Notes due March 2021, and issued at 101% of par an additional $400 million of
5.75% Senior Notes due March 2021 (collectively, the “2021 Senior Notes” and together with the 2019 Senior Notes, the “Whiting
Senior Notes”). The estimated fair value of the 2019 Senior Notes was $1.0 billion and $1.1 billion as of December 31, 2014 and
2013, respectively. The estimated fair value of the 2021 Senior Notes was $1.1 billion and $1.3 billion as of December 31, 2014 and
2013, respectively. These fair values are based on quoted market prices for these debt securities, and such fair values are therefore
designated as Level 1 within the valuation hierarchy.
Redemption of Senior Subordinated Notes. In October 2013, the Company paid $254 million to redeem its entire $250 million
aggregate principal amount of the 7% Senior Subordinated Notes due February 2014 (the “2014 Senior Subordinated Notes”) at a
redemption price of 101.595%. Concurrent with this redemption, the Company paid all accrued and unpaid interest on the 2014
Senior Subordinated Notes up to but not including the redemption date. The Company financed the redemption of these notes with
proceeds from the issuance of the Whiting Senior Notes, as discussed above. As a result of the redemption, Whiting recognized a $4
million loss on early extinguishment of debt, which primarily consisted of a cash charge of $4 million related to the redemption
premium on the 2014 Senior Subordinated Notes.
Kodiak Senior Notes. In conjunction with the Kodiak Acquisition, Whiting US Holding Company, a wholly-owned subsidiary of the
Company, became a co-issuer of Kodiak’s outstanding principal amount of $800 million of 8.125% Senior Notes due December 2019,
$350 million of 5.5% Senior Notes due January 2021, and $400 million of 5.5% Senior Notes due February 2022 (the “Kodiak
Notes”). The Kodiak Notes were recorded at their fair values of $824 million, $351 million and $401 million, respectively, on
December 8, 2014, the closing date of the acquisition. The related premiums of $24 million, $1 million and $1 million, respectively,
are being amortized to interest expense over the life of the related notes. As of December 31, 2014, the estimated fair value of the
Kodiak Notes was $812 million, $351 million and $401 million, respectively, based on quoted market prices for these debt securities,
and such fair value is therefore designated as Level 1 within the valuation hierarchy.
Upon closing of the Kodiak Acquisition, the indentures under which the Kodiak Notes were issued (the “Kodiak Indentures”) were
amended to (i) modify certain covenants and restrictions, (ii) to provide for unconditional and irrevocable guarantees by Whiting
Petroleum Corporation and Whiting Oil and Gas of the prompt payment, when due, of any amounts owed under the Kodiak Notes and
the Kodiak Indentures, and (iii) to allow Whiting US Holding Company to become a co-issuer of the Kodiak Notes. Also in
conjunction with the Kodiak Acquisition, in December 2014, each of the indentures governing the Company’s 2019 Senior Notes,
2021 Senior Notes and 2018 Senior Subordinated Notes were amended to include Whiting US Holding Company, Kodiak and
Whiting Resources Corporation (formerly Kodiak Oil & Gas (USA) Inc.) as guarantors. Shortly after closing, the Kodiak Notes were
deregistered in accordance with the Securities Exchange Act of 1934, and accordingly, the Company is exempt from the reporting
requirements under Rule 3-10 of Regulation S-X of the SEC with respect to the Kodiak Notes.
Kodiak Senior Notes Repurchase Offer. On January 7, 2015, as required under the Kodiak Indentures upon a change in control of
Kodiak, Whiting offered to repurchase at 101% of par all $1,550 million principal amount of Kodiak Notes outstanding. The
repurchase offer expires on March 3, 2015. The Company expects to fund any payments due as a result of such repurchase offer with
borrowings under its revolving credit facility.
The Whiting Senior Notes and Kodiak Notes are unsecured obligations of Whiting Petroleum Corporation and Whiting US Holding
Company, respectively, and are subordinated to all of the Company’s secured indebtedness, which consists of Whiting Oil and Gas’
credit agreement. The 2018 Senior Subordinated Notes are also unsecured obligations of Whiting Petroleum Corporation and are
subordinated to all of the Company’s senior debt, which currently consists of the Whiting Senior Notes, the Kodiak Notes and Whiting
Oil and Gas’ credit agreement.
The Company’s obligations under the 2018 Senior Subordinated Notes and the Whiting Senior Notes are fully and unconditionally
guaranteed by the Company’s wholly-owned subsidiaries, Whiting Oil and Gas, Whiting US Holding Company, Whiting Canadian
Holding Company ULC and Whiting Resources Corporation (the “Guarantors”). Any subsidiaries other than these Guarantors are
minor subsidiaries as defined by Rule 3-10(h)(6) of Regulation S-X of the SEC. Whiting Petroleum Corporation has no assets or
operations independent of this debt and its investments in its consolidated subsidiaries.
85
5. 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, 2014 and 2013 were $12 million and $10 million, respectively, and have been 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 years ended December 31, 2014 and 2013 (in thousands):
0.01
December 31,
2014
2013
Asset retirement obligation at January 1 .............................................................................. $
Additional liability incurred .................................................................................................
Revisions in estimated cash flows (1) ....................................................................................
Accretion expense ................................................................................................................
Obligations on sold properties .............................................................................................
Liabilities settled ..................................................................................................................
Asset retirement obligation at December 31 ........................................................................ $
_____________________
(1) Revisions in estimated cash flows during the year ended December 31, 2014 are primarily attributable to increased estimates of
future costs for oilfield goods and services required to plug and abandon wells in certain fields in the Rocky Mountains and
Permian Basin regions. Revisions in estimated cash flows during the year ended December 31, 2013 were primarily attributable
to increased estimates of futures costs for oilfield goods and services required to plug and abandon wells in certain fields in the
Rocky Mountains region.
126,148
29,186
25,909
13,548
(7,237)
(7,623)
179,931
97,818
17,535
12,225
10,608
(3,630)
(8,408)
126,148
$
$
6. 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, such as costless collars, swaps and fixed-differential contracts 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. The Company does not enter into
derivative contracts for speculative or trading purposes.
Crude Oil Costless Collars and Swaps. Costless collars are designed to establish floor and ceiling prices on anticipated future oil or
gas production, while swaps are designed to establish a fixed price for anticipated future oil or 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.
86
The table below details the Company’s costless collar and swap derivatives entered into to hedge forecasted crude oil production
revenues as of February 13, 2015, including certain oil collars and swaps assumed in the Kodiak Acquisition.
Derivative
Instrument
Three-way collars (1)
Collars
Swaps
Period
Jan - Dec 2015
Jan - Dec 2016
Jan - Dec 2015
Jan - Dec 2016
Jan - Dec 2017
Jan - Dec 2015
Total
Whiting Petroleum Corporation
Contracted Crude
Oil Volumes (Bbl)
3,600,000
6,600,000
1,309,500
3,000,000
3,000,000
3,556,560
21,066,060
Weighted Average NYMEX Price
Collar Ranges for Crude Oil (per Bbl)
$50.83 - $62.50 - $83.81
$43.18 - $53.18 - $76.26
$52.47 - $59.26
$51.00 - $63.48
$53.00 - $70.44
$86.05
_____________________
(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.
In March 2013, Whiting entered into certain crude oil swap contracts in order to achieve more predictable cash flows and manage
returns on certain oil and gas properties that the Company was considering for monetization. Accordingly, the acquisition of these
swap contracts and cash receipts from settlements of these swap positions have been reflected as an investing activity in the statement
of cash flows. On July 15, 2013, upon closing of the sale of the Postle Properties discussed in the Acquisitions and Divestitures
footnote, these crude oil swaps were novated to the buyer. Cash settlements that do not relate to investing derivatives or that do not
have a significant financing element are reflected as operating activities in the statement of cash flows.
Fixed-differential Crude Oil Contracts. The Company has entered into two long-term crude oil sales and delivery contracts for oil
volumes produced from its Redtail field in Colorado. Under the terms of these agreements, Whiting has committed to deliver certain
fixed volumes of crude oil from 2015 through 2020 at a price equal to NYMEX less the fixed differentials specified in the agreements.
As of December 31, 2014, the Company determined that it is no longer probable that future oil production from its Redtail field will
be sufficient to meet the minimum volume requirements specified in these contracts, and accordingly, that the Company will not settle
these contracts through physical delivery of crude oil volumes. As a result, Whiting has determined that these contracts no longer
qualify for the “normal purchase normal sale” exclusion, and has therefore reflected them at fair value in the consolidated financial
statements. As of December 31, 2014, the estimated fair value of these derivative contracts was an asset of $54 million.
Embedded Commodity Derivative Contract—In May 2011, Whiting entered into a long-term contract to purchase CO2 for use in its
EOR project that is being carried out at its North Ward Estes field in Texas. This contract contained a price adjustment clause that
was linked to changes in NYMEX crude oil prices. The Company had determined that the portion of this contract linked to NYMEX
oil prices was not clearly and closely related to the host contract, and the Company therefore bifurcated this embedded pricing feature
from its host contract and reflected it at fair value in the consolidated financial statements. The Company had terminated this contract,
however, prior to the issuance date of these financial statements, and the fair value of this embedded derivative was therefore zero as
of December 31, 2014.
Derivative Instrument Reporting—All derivative instruments are recorded in the consolidated financial statements at fair value, other
than derivative instruments that meet the “normal purchase normal sale” exclusion. The following tables summarize the effects of
commodity derivative instruments on the consolidated statements of income for the years ended December 31, 2014 and 2013 (in
thousands):
ASC 815 Cash Flow
Hedging Relationships (1)
Commodity contracts ..............................
_____________________
(1) Effective April 1, 2009, the Company de-designated 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 AOCI as of the de-designation date and were reclassified into earnings as the original hedged transactions
affected income. As of December 31, 2013, all amounts previously in AOCI had been reclassified into earnings.
Income Statement Classification
Gain (loss) on hedging activities .....................
(1,958)
$
-
$
Loss Reclassified from AOCI into
Income (Effective Portion)
Year Ended December 31,
2013
2014
87
Not Designated as
ASC 815 Hedges
Commodity contracts ..............................
Embedded commodity contracts .............
Income Statement Classification
Commodity derivative (gain) loss, net .............
Commodity derivative (gain) loss, net .............
Total ..............................................................................................................................
$
$
(Gain) Loss Recognized in Income
Year Ended December 31,
2013
2014
(136,995)
36,416
(100,579)
$
$
20,503
(12,701)
7,802
Offsetting of Derivative Assets and Liabilities. With each individual financial derivative counterparty, the Company typically has
numerous hedge positions that span a several-month time period and that typically result in both fair value asset and liability positions
held with that counterparty, which positions are all offset to a single fair value asset or liability amount at the end of each reporting
period. The Company nets its financial derivative instrument fair value amounts executed with the same counterparty pursuant to
ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of
the contract. The following tables summarize the location and fair value amounts of all derivative instruments in the consolidated
balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets (in
thousands):
Not Designated as
ASC 815 Hedges
Derivative assets:
Balance Sheet Classification
Commodity contracts .........................
Commodity contracts .........................
Derivative assets ............................
Other long-term assets ..................
Total derivative assets ............................................................................
$
$
Derivative liabilities:
Commodity contracts .........................................................................................
Total derivative liabilities ......................................................................
$
$
Not Designated as
ASC 815 Hedges
Derivative assets:
Balance Sheet Classification
Commodity contracts .........................
Embedded commodity contracts ........
Derivative assets ............................
Other long-term assets ...................
Total derivative assets ............................................................................
$
$
Derivative liabilities:
Commodity contracts .........................
Accrued liabilities and other ..........
Total derivative liabilities ......................................................................
$
$
December 31, 2014 (1)
Gross
Recognized
Assets/
Liabilities
Gross
Amounts
Offset
Net
Recognized
Fair Value
Assets/
Liabilities
154,329 $
45,459
199,788 $
(18,752) $
-
(18,752) $
135,577
45,459
181,036
18,752 $
18,752 $
(18,752) $
(18,752) $
-
-
December 31, 2013 (1)
Gross
Recognized
Assets/
Liabilities
Gross
Amounts
Offset
Net
Recognized
Fair Value
Assets/
Liabilities
23,752 $
36,416
60,168 $
(22,478) $
-
(22,478) $
25,960 $
25,960 $
(22,478) $
(22,478) $
1,274
36,416
37,690
3,482
3,482
_____________________
(1) Because counterparties to the Company’s financial derivative contracts are lenders under Whiting Oil and Gas’ credit agreement,
which eliminates its need to post or receive collateral associated with its derivative positions, columns for cash collateral pledged
or received have not been presented in the tables above.
Contingent Features in Financial Derivative Instruments. None of the Company’s derivative instruments contain credit-risk-related
contingent features. Counterparties to the Company’s financial derivative contracts are high credit-quality financial institutions that
are lenders under Whiting’s credit agreement. 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 financial derivative counterparties in order to secure contract performance obligations.
88
7. FAIR VALUE MEASUREMENTS
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 Senior Notes (including the Kodiak Notes) and Senior
Subordinated Notes are recorded at cost, and the fair values of these instruments are included in the Long-Term Debt footnote. 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.
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, 2014 and 2013, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to
determine such fair values (in thousands):
Financial Assets
Commodity derivatives – current ..........................................
Commodity derivatives – non-current ..................................
Total financial assets ......................................................
$
$
Financial Assets
Commodity derivatives – current ..........................................
Embedded commodity derivatives – non-current .................
Total financial assets ......................................................
$
$
Financial Liabilities
Commodity derivatives – current ..........................................
Total financial liabilities ................................................
$
$
Level 1
Level 2
Level 3
Total Fair Value
December 31, 2014
- $
-
- $
127,506 $
-
127,506 $
8,071 $
45,459
53,530 $
135,577
45,459
181,036
Level 1
Level 2
Level 3
Total Fair Value
December 31, 2013
- $
-
- $
- $
- $
1,274 $
-
1,274 $
- $
36,416
36,416 $
3,482 $
3,482 $
- $
- $
1,274
36,416
37,690
3,482
3,482
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 mainly of costless collars and swap contracts for crude oil. The
Company’s costless collars and swaps are valued based on an income approach. Both the option and swap models consider various
assumptions, such as 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
89
nonperformance risk, as appropriate. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own
valuations.
In addition, the Company has two long-term crude oil sales and delivery contracts, whereby it has committed to deliver certain fixed
volumes of crude oil at a price equal to NYMEX less the fixed differentials specified in the agreement. Whiting has determined that
the contracts do not meet the “normal purchase normal sale” exclusion, and has therefore reflected these contracts at fair value in its
consolidated financial statements. These commodity derivatives are valued based on an income approach, which considers various
assumptions, including quoted forward prices for commodities, market differentials for crude oil, U.S. Treasury rates and either the
Company’s or the counterparty’s nonperformance risk, as appropriate.
The assumptions used in the valuation of the fixed-differential contracts include certain market differential metrics that are
unobservable during the term of the contracts. Such unobservable inputs are significant to the contract valuation methodology, and
the contracts’ fair values are therefore designated as Level 3 within the valuation hierarchy.
Embedded Commodity Derivatives. The embedded commodity derivative was related to a long-term CO2 purchase contract, which
had a price adjustment clause linked to changes in NYMEX crude oil prices. Whiting determined that the portion of this contract
linked to NYMEX oil prices was not clearly and closely related to its corresponding host contract, and the Company therefore
bifurcated this embedded pricing feature from the host contract and reflected it at fair value in its consolidated financial statements as
of December 31, 2013. The assumptions used in the CO2 contract valuation, which was based on the income approach, included
certain oil price metrics that were unobservable during the term of the contract. Such unobservable oil price inputs were significant to
the CO2 contract valuation methodology, and the contract’s fair value was therefore designated as Level 3 within the valuation
hierarchy. Because the Company subsequently terminated this CO2 purchase contract, however, its embedded derivative had a fair
value of zero as of December 31, 2014.
Level 3 Fair Value Measurements. A third-party valuation specialist is utilized to determine the fair value of the commodity
derivative instruments 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
and fair value changes using various methodologies, and 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 years ended December 31, 2014 and 2013 (in thousands):
Fair value asset, beginning of period ................................................................................ $
Unrealized gains (losses) on commodity derivative contracts included in earnings (1) .....
Transfers into (out of) Level 3 ..........................................................................................
Fair value asset, end of period .......................................................................................... $
_____________________
(1) Included in commodity derivative (gain) loss, net in the consolidated statements of income.
Year Ended December 31,
2013
2014
36,416 $
17,114
-
53,530 $
23,715
12,701
-
36,416
Quantitative Information About Level 3 Fair Value Measurements. The significant unobservable inputs used in the fair value
measurement of the Company’s commodity derivative contracts designated as Level 3 are as follows:
Fair Value at
December 31, 2014
(in thousands)
Commodity derivative
contracts .........................
$53,530
Valuation
Technique
Income
approach
Unobservable
Input
Amount
(per Bbl)
Market differential for crude oil
$5.74
Sensitivity to Changes in Significant Unobservable Inputs. As presented above, the significant unobservable inputs used in the fair
value measurement of Whiting’s commodity derivative contracts are the market differentials for crude oil over the term of the
contracts. Significant increases (decreases) in these unobservable inputs in isolation would result in 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
90
December 31, 2014 and 2013, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine
such fair values (in thousands):
Loss (Before
Tax) Year
Ended
December 31,
2014
629,450
Loss (Before
Tax) Year
Ended
December 31,
2013
267,109
Net Carrying
Value as of
December 31,
2014
Fair Value Measurements Using
Level 2
Level 1
Level 3
$
179,155 $
Proved property impairments (1) ..............
_____________________
(1) During the year ended December 31, 2014, proved oil and gas properties with a carrying amount of $763 million were written
down to their fair value of $176 million, resulting in a non-cash impairment charge of $587 million. The impairment primarily
consisted of non-core oil and gas properties, that are not currently being developed, in Colorado, Louisiana, North Dakota and
Utah and related to the decrease in the forward price curve for crude oil and natural gas on December 31, 2014 and the associated
decline in oil and gas reserves in those areas. Also during the year ended December 31, 2014, proved CO2 properties at the Bravo
Dome field in New Mexico with a carrying amount of $45 million were written down to their fair value of $3 million, resulting in
a non-cash impairment charge of $42 million.
179,155 $
- $
- $
Net Carrying
Value as of
December 31,
2013
Fair Value Measurements Using
Level 2
Level 3
Level 1
$
106,114 $
Proved property impairments (1) ..............
_____________________
(1) During the year ended December 31, 2013, proved oil and gas properties with a carrying amount of $373 million were written
down to their fair value of $106 million, resulting in a non-cash impairment charge of $267 million. The impairment consisted of
(i) a $221 million write-down in the Rocky Mountains region and Michigan related to the decrease in the forward price curve for
natural gas at December 31, 2013 and the associated decline in gas reserves in those areas and (ii) a $46 million write-down in the
Rocky Mountains region related to well performance and associated changes in reserves during the fourth quarter of 2013.
106,114 $
- $
- $
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 developed using the income approach. The discounted cash flows are based on management’s
expectations for the future. Unobservable inputs include estimates of future oil and gas or CO2 production, as the case may be, from
the Company’s reserve reports, commodity prices based on sales contract terms or NYMEX forward price curves as of the date of the
estimate (adjusted for basis differentials), estimated operating and development costs, and a risk-adjusted discount rate (all of which
are designated as Level 3 inputs within the fair value hierarchy).
8. DEFERRED COMPENSATION
Production Participation Plan—The Company had a Production Participation Plan (the “Plan”) in which all employees participated.
On June 11, 2014, the Board of Directors of the Company terminated the Plan effective December 31, 2013. Prior to Plan
termination, interests in oil and gas properties acquired, developed or sold during the year were allocated to the Plan on an annual
basis as determined by the Compensation Committee of the Company’s Board of Directors. Once allocated, the interests (not legally
conveyed) were fixed. Interest allocations prior to 1995 consisted of 2%-3% overriding royalty interests. Interest allocations after
1995 were 1.75%-5% of oil and gas sales less lease operating expenses and production taxes.
Employees vested in the Plan ratably at 20% per year over a five-year period. However, pursuant to the terms of the Plan, upon Plan
termination all employees fully vested, and the Company is required to 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. This distribution includes
the value of proved undeveloped oil and gas properties (“PUDs”) awarded upon Plan termination and is based on forecasted
commodity prices for crude oil, NGLs and natural gas as of December 31, 2013. The fully vested amount due to Plan participants
totals $113 million and has been reflected as a current payable, as it will be distributed to Plan participants during the first half of
2015. As of December 31, 2014, a portion of this liability representing a regular distribution under the Plan totaling $41 million had
91
been paid to the Company’s third-party payroll administrator. However, these funds were not distributed by the payroll administrator
to Plan participants until January 2015. The final Plan distribution payment will be made in June 2015.
Accrued compensation expense under the Plan for the year ended December 31, 2014 primarily relates to the change in liability for
employee vestings and PUDs assigned upon Plan termination and amounted to $24 million charged to general and administrative
expense and $2 million charged to exploration expense. Accrued compensation expense under the Plan for the years ended December
31, 2013 and 2012 amounted to $66 million and $45 million, respectively, charged to general and administrative expense and $7
million and $4 million, respectively, charged to exploration expense. Of the aggregate $73 million of accrued compensation under the
Plan as of December 31, 2013, $24 million relates to the sale of the Postle Properties, which is further described in the Acquisitions
and Divestitures footnote.
Prior to Plan termination, the Company recorded non-cash changes in the present value of estimated future payments under the Plan as
a separate line item in the consolidated statements of income. As a result of Plan termination, all changes in the Plan liability during
2014 related to cash termination payments to be made in 2015. 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 prior to Plan termination ..................................................................................
Change in liability for vesting and PUDs assigned upon Plan termination .........................
Amount reflected as a current liability .................................................................................
Long-term Production Participation Plan liability at December 31 .....................................
$
Year Ended December 31,
2013
2014
87,503 $
94,483
-
25,888
(113,391)
- $
66,284
-
(73,264)
87,503
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 2014, 2013 and 2012 were $9 million, $8
million and $6 million, respectively. Employees vest in employer contributions at 20% per year of completed service.
9. SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST
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 a result of voluntary
conversions and the Company exercising its right to mandatorily convert shares of preferred stock effective June 27, 2013, all 172,129
remaining shares of preferred stock outstanding on March 31, 2013 were converted into 792,919 shares of common stock. As of
December 31, 2014, no shares of preferred stock remained issued or outstanding.
Each holder of the preferred stock was 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, once such dividend had been declared by Whiting’s
board of directors.
Equity Incentive Plan—At the Company’s 2013 Annual Meeting held on May 7, 2013, shareholders approved the Whiting Petroleum
Corporation 2013 Equity Incentive Plan (the “2013 Equity Plan”), which replaced the Whiting Petroleum Corporation 2003 Equity
Incentive Plan (the “2003 Equity Plan”) and includes the authority to issue 5,300,000 shares of the Company’s common stock. Upon
shareholder approval of the 2013 Equity Plan, the 2003 Equity Plan was terminated. The 2003 Equity Plan continues to govern
awards that were outstanding as of the date of its termination, which remain in effect pursuant to their terms. Any shares netted or
forfeited after May 7, 2013 under the 2003 Equity Plan will be available for future issuance under the 2013 Equity Plan. Under the
2013 Equity Plan, 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. On December 8, 2014, the Company increased the number of shares issuable under the 2013 Equity Plan by 978,161
shares to accommodate for the conversion of Kodiak’s outstanding equity awards to Whiting equity awards upon closing of the
Kodiak Acquisition. Any shares netted or forfeited under this increased availability will be cancelled and will not be available for
future issuance under the 2013 Equity Plan. As of December 31, 2014, 5,048,433 shares of common stock remained available for
grant under the 2013 Equity Plan.
For the years ended December 31, 2014, 2013 and 2012, total stock compensation expense recognized for restricted share awards and
stock options was $23 million, $22 million and $18 million, respectively.
Equity Awards Assumed in Kodiak Acquisition. Upon closing of the Kodiak Acquisition, the Company assumed all of Kodiak’s
outstanding equity awards, including restricted stock awards, restricted stock units and stock options. Kodiak’s outstanding equity
92
awards held by employees were converted into Whiting’s equity awards using a conversion ratio of 0.177. The outstanding restricted
stock awards and restricted stock units vested upon closing of the transaction, and the $10 million estimated fair value of the 257,601
shares of Whiting common stock issued to convert these awards was recorded as part of the purchase consideration.
The estimated fair value of the 673,235 Whiting options issued in exchange for Kodiak’s outstanding options was approximately $8
million, based on a Black-Scholes option-pricing model. Of this value, approximately $7 million was attributable to service rendered
prior to the date of acquisition and was recorded as part of the purchase consideration, and the remaining $1 million will be expensed
over the remaining service term of the replacement stock option awards. The unvested stock option awards will vest over a one to
three-year service period from the grant date and are exercisable immediately upon vesting through the tenth anniversary of the grant
date. The following table summarizes the assumptions used to estimate the fair value of stock options assumed in the Kodiak
Acquisition:
Risk-free interest rate ...........................................................................................................................................
Expected volatility ...............................................................................................................................................
Expected term ......................................................................................................................................................
Dividend yield......................................................................................................................................................
2014
0.08% - 1.90%
40.3% - 49.7%
2.0 yrs. - 6.1 yrs.
-
The weighted average fair value of these options, as determined by the Black-Scholes valuation model, was $12.20 per share as of the
December 8, 2014 closing date of the Kodiak Acquisition.
Restricted Shares. Restricted stock awards for executive officers and employees generally vest ratably over a three-year service
period, while awards to directors generally vest ratably over a one-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 2014, 2013 and 2012, 750,681 shares, 751,872 shares and 444,501 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:
Number of simulations .....................................................................
Expected volatility ...........................................................................
Risk-free interest rate .......................................................................
Dividend yield..................................................................................
2014
65,000
42.3%
0.86%
-
2013
65,000
43.1%
0.41%
-
2012
65,000
51.9%
0.35%
-
The grant date fair value of the market-based restricted stock as determined by the Monte Carlo valuation model was $26.59 per share,
$23.01 per share and $29.45 per share in January 2014, 2013 and 2012, respectively.
93
The following table shows a summary of the Company’s nonvested restricted stock as of December 31, 2012, 2013 and 2014 as well
as activity during the years then ended:
Number
of Shares
Weighted Average
Grant Date
Fair Value
Restricted stock awards nonvested, January 1, 2012 .....................................................
Granted ..........................................................................................................................
Vested ............................................................................................................................
Forfeited .........................................................................................................................
Restricted stock awards nonvested, December 31, 2012 ...............................................
Granted ..........................................................................................................................
Vested ............................................................................................................................
Forfeited .........................................................................................................................
Restricted stock awards nonvested, December 31, 2013 ...............................................
Granted ..........................................................................................................................
Assumed in Kodiak Acquisition (1) ................................................................................
Vested ............................................................................................................................
724,395 $
592,400
(357,170)
(8,599)
951,026
940,792
(347,824)
(99,684)
1,444,310
907,856
304,926
(814,439)
29.88
34.45
17.91
51.72
37.02
27.59
35.32
30.95
31.71
32.41
37.25
34.05
Forfeited .........................................................................................................................
Restricted stock awards nonvested, December 31, 2014 ...............................................
_____________________
(1) Kodiak’s existing restricted stock units and restricted stock awards held by employees, which automatically converted into
257,601 restricted stock units and 47,325 restricted stock awards of Whiting and vested upon closing of the Kodiak Acquisition.
(385,785)
1,456,868 $
34.86
31.16
As of December 31, 2014, there was $13 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 1.7 years. For the years
ended December 31, 2014, 2013 and 2012, the total fair value of restricted stock vested was $31 million, $17 million and $19 million,
respectively.
Stock Options. Stock options may be granted 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. There were no stock options granted under either the 2003 Equity
Plan or the 2013 Equity Plan during 2014 or 2013, other than the 673,235 stock options assumed in connection with the Kodiak
Acquisition. In January 2012, 45,359 stock options were granted under the 2003 Equity Plan. The Company’s 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
2012:
Risk-free interest rate ...........................................................................................................................................
Expected volatility ...............................................................................................................................................
Expected term ......................................................................................................................................................
Dividend yield......................................................................................................................................................
2012
1.19%
61.4%
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 in
January 2012.
94
The following table shows a summary of the Company’s stock options outstanding as of December 31, 2012, 2013 and 2014 as well
as activity during the years then ended:
Weighted
Average
Exercise Price
per Share
Number of
Options
Weighted
Average
Remaining
Contractual
Term
(in years)
Aggregate
Intrinsic
Value
(in thousands)
Options outstanding at January 1, 2012 ......................................
Granted .......................................................................................
Exercised .....................................................................................
Forfeited or expired.....................................................................
Options outstanding at December 31, 2012 ................................
Granted .......................................................................................
Exercised .....................................................................................
Forfeited or expired.....................................................................
Options outstanding at December 31, 2013 ................................
Granted .......................................................................................
Assumed in Kodiak Acquisition .................................................
Exercised .....................................................................................
Forfeited or expired.....................................................................
Options outstanding at December 31, 2014 ................................
Options vested and expected to vest at December 31, 2014 .......
Options exercisable at December 31, 2014 .................................
377,336 $
45,359
-
-
422,695
-
-
(1,855)
420,840
-
673,235
(117,123)
(8,559)
968,393 $
905,107 $
831,220 $
26.09
51.22
-
-
28.79
-
-
60.28
28.65
-
44.48
15.21
50.51
41.09
40.78
38.45
$
$
$
$
$
$
-
-
6,203,361
5,216,952
4,984,431
5,216,952
4.8
4.8
4.2
Unrecognized compensation cost as of December 31, 2014 related to unvested stock option awards was $1 million, which is expected
to be recognized over a period of 1.2 years.
Rights Agreement—In 2006, the Board of Directors of the Company declared a dividend of one preferred share purchase right (a
“Right”) for each outstanding share of common stock of the Company payable to the stockholders of record as of March 2, 2006. 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 Sustainable
Water Resources, LLC. The table below summarizes the activity for the equity attributable to the noncontrolling interest (in
thousands):
Balance at January 1 ............................................................................................................
Net loss ................................................................................................................................
Balance at December 31 ......................................................................................................
$
$
Year Ended December 31,
2013
2014
8,132 $
(62)
8,070 $
8,184
(52)
8,132
95
10. INCOME TAXES
Income tax expense consists of the following (in thousands):
Current income tax expense (refund):
Federal ..........................................................................................
State ..............................................................................................
Total current income tax expense (refund) ...............................
$
Deferred income tax expense:
Federal ..........................................................................................
State ..............................................................................................
Total deferred income tax expense ...........................................
Total ...................................................................................
$
2014
Year Ended December 31,
2013
2012
$
(2,758)
5,383
2,625
65,522
11,023
76,545
79,170
$
$
7,060
(6,074)
986
196,787
8,095
204,882
205,868
$
-
(669)
(669)
233,468
15,113
248,581
247,912
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 ........................................
State income tax credits ...................................................................
Statutory depletion ...........................................................................
Enacted changes in state tax laws ....................................................
Market-based equity awards ............................................................
Permanent items ...............................................................................
Transaction costs ..............................................................................
Other ................................................................................................
Total ..........................................................................................
$
2014
Year Ended December 31,
2013
2012
50,371
12,705
-
(618)
3,700
2,805
3,504
6,936
(233)
79,170
$
$
200,155
13,962
(10,525)
(796)
(1,416)
-
2,122
-
2,366
205,868
$
$
231,704
14,444
-
(620)
-
-
1,524
-
860
247,912
96
The principal components of the Company’s deferred income tax assets and liabilities at December 31, 2014 and 2013 were as follows
(in thousands):
Deferred income tax assets:
$
Net operating loss carryforward ....................................................................................
Production Participation Plan liability ...........................................................................
Tax sharing liability .......................................................................................................
Asset retirement obligations ..........................................................................................
Underwriter fees ............................................................................................................
Restricted stock compensation ......................................................................................
Premium on Senior Notes ..............................................................................................
EOR credit carryforwards ..............................................................................................
Alternative minimum tax credit carryforwards .............................................................
Transaction costs ...........................................................................................................
Other ..............................................................................................................................
Total deferred income tax assets ......................................................................
Less valuation allowance ...............................................................................................
Net deferred income tax assets .........................................................................
Deferred income tax liabilities:
Year Ended December 31,
2013
2014
588,330 $
26,942
-
13,791
14,065
15,527
7,979
7,946
15,694
7,957
9,493
707,724
(5,638)
702,086
438,922
32,245
9,439
23,642
10,974
13,384
-
7,946
18,452
-
3,234
558,238
(1,230)
557,008
Oil and gas properties ....................................................................................................
Trust distributions ..........................................................................................................
Derivative instruments ...................................................................................................
Total deferred income tax liabilities .................................................................
Total net deferred income tax liabilities ........................................................................
$
1,785,926
129,437
64,898
1,980,261
1,278,175
$
1,675,916
149,332
10,438
1,835,686
1,278,678
As of December 31, 2014, the Company had federal net operating loss (“NOL”) carryforwards of $1.7 billion. Of this amount, $70
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. In addition, $170 million of NOL carryforwards
are a result of the Kodiak Acquisition, and the utilization of this amount is limited to $77 million each year for the next three years.
The Company also has various state NOL carryforwards. The determination of the state NOL carryforwards is dependent upon
apportionment percentages and state laws that can change from year to year and that can thereby impact the amount of such
carryforwards. If unutilized, the federal NOL will expire between 2028 and 2035, and the state NOLs will expire between 2015 and
2035.
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, 2014, the Company had recognized aggregate EOR credits of $8 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, 2014, the Company had AMT credits totaling $16 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, 2014, the Company had a valuation allowance totaling $6 million, comprised of unamortized underwriter fees in
Canada and foreign tax credit carryforwards, which will expire between 2015 and 2016. These valuation allowances have been
recorded because the Company determined 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.
In conjunction with the Kodiak Acquisition, the Company acquired Kodiak, which is a Canadian entity that is to be disregarded for
U.S. tax purposes. Kodiak holds an interest in Whiting Resources Corporation (formerly Kodiak Oil & Gas (USA) Inc.), a U.S. entity
which has undistributed earnings at December 31, 2014. These earnings are considered to be indefinitely reinvested, and accordingly,
no provision has been provided for on those earnings. If the Company were to repatriate those earnings in the form of dividends or
otherwise, no taxes would result.
97
Net deferred income tax liabilities were classified in the consolidated balance sheets as follows (in thousands):
Year Ended December 31,
2013
2014
Assets:
Current deferred income taxes ........................................................................................ $
-
$
-
Liabilities:
Current deferred income taxes ........................................................................................
Non-current deferred income taxes .................................................................................
$
Net deferred income tax liabilities ...........................................................................
47,545
1,230,630
1,278,175
$
648
1,278,030
1,278,678
The following table summarizes the activity related to the Company’s liability for unrecognized tax benefits (in thousands):
2014
Year Ended December 31,
2013
2012
Beginning balance at January 1 .......................................................
Decrease related to tax position taken in a prior period ...................
Ending balance at December 31.......................................................
$
$
170
-
170
$
$
170
-
170
$
$
299
(129)
170
The unrecognized tax benefit balance at December 31, 2014 includes certain tax positions, the allowance of which would positively
affect the annual effective income tax rate. For the year ended December 31, 2014, 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 and in various states, each with varying statutes of limitations.
The 2011 through 2014 tax years generally remain subject to examination by federal and state tax authorities. Additionally, in
conjunction with the Kodiak Acquisition, the Company has Canadian income tax filings which remain subject to examination by the
related tax authorities for the 2009 through 2014 tax years.
98
11. 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
Numerator:
Net income available to shareholders ....................................
Preferred stock dividends (1) ..................................................
Net income available to common shareholders, basic ...........
$
$
2014
Year Ended December 31,
2013
2012
64,807 $
-
64,807 $
366,055 $
(494)
365,561 $
414,189
(1,077)
413,112
Denominator:
Weighted average shares outstanding, basic .........................
122,138
118,260
117,601
Diluted Earnings Per Share
Numerator:
Net income available to common shareholders, basic ...........
Preferred stock dividends ......................................................
Adjusted net income available to common shareholders,
$
64,807 $
-
365,561 $
538
413,112
1,077
diluted ..............................................................................
$
64,807 $
366,099 $
414,189
Denominator:
Weighted average shares outstanding, basic .........................
Restricted stock and stock options ........................................
Convertible perpetual preferred stock ...................................
Weighted average shares outstanding, diluted ......................
122,138
381
-
122,519
118,260
957
371
119,588
117,601
633
794
119,028
Earnings per common share, basic ...................................................
Earnings per common share, diluted ................................................
_____________________
(1) For the year ended December 31, 2013, amount includes a decrease of $0.04 million in preferred stock dividends for preferred
stock dividends accumulated. There were no accumulated dividend adjustments for the years ended December 31, 2014 or 2012.
3.09 $
3.06 $
0.53 $
0.53 $
3.51
3.48
$
$
For the year ended December 31, 2014, the diluted earnings per share calculation excludes (i) the dilutive effect of 803,902
incremental shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2014, and (ii) the anti-
dilutive effect of 791 common shares for stock options that were out-of-the-money. For the year ended December 31, 2013, the
diluted earnings per share calculation excludes the dilutive effect of (i) 173,778 incremental shares of restricted stock that did not meet
its market-based vesting criteria as of December 31, 2013, and (ii) 8,689 common shares for stock options that were out-of-the-money.
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.
12. 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, 2014 and 2013 (in thousands):
Assets
Unit distributions due from Trust I (1) ........................................................................... $
652
$
Liabilities
Unit distributions payable to Trust I (2) ......................................................................... $
4,133
$
1,093
6,932
_____________________
(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.
December 31,
2014
2013
99
(2) This amount represents net proceeds from Trust I’s underlying properties that the Company has received between the last Trust I
distribution date and December 31, 2014 and 2013, respectively, but which the Company has not yet distributed to Trust I as of
December 31, 2014 and 2013, respectively. Due to ongoing processing of Trust I revenues and expenses after December 31,
2014 and 2013, 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. These amounts are included within accounts payable trade in the Company’s
consolidated balance sheet.
For the year ended December 31, 2014, Whiting paid $30 million, net of state tax withholdings, in unit distributions to Trust I and
received $5 million in distributions back from Trust I pursuant to its retained ownership in 2,186,389 Trust I units.
On January 28, 2015, the net profits interest that Whiting conveyed to Trust I terminated as a result of 9.11 MMBOE (which amount is
equivalent to 8.20 MMBOE attributable to the net profits interest) having been produced and sold from the underlying properties.
Upon termination, the net profits interest in the underlying properties reverted back to Whiting, and Trust I will no longer be a related
party.
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 realized annually as a result of this step-up in tax bases. In 2014, Whiting was
obligated to pay Alliant the present value of 90% of the remaining tax benefits expected to result from its increased tax bases, which
payout assumes all such tax benefits will be realized in future years.
In March 2014, the Company made the final payment due Alliant Energy under this agreement totaling $26 million, including $3
million of interest. During 2013 and 2012, the Company made payments of $2 million each year under this agreement and recognized
interest expense of $3 million and $2 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.
13. 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, 2014 (in thousands):
2015
2016
Payments Due by Period
2018
2017
2019
Thereafter
Total
Non-cancelable leases .................
Drilling rig contracts ...................
Pipeline transportation
$
7,692 $
7,547 $
146,141
101,855
6,610 $
30,788
6,693 $
-
5,844 $
-
216 $
-
34,602
278,784
agreements ...............................
Total ...................................
5,948
9,722
$ 159,781 $ 119,124 $
9,559
46,957 $
9,559
16,252 $
9,559
15,403 $
50,091
94,438
50,307 $ 407,824
Non-cancelable Leases—The Company leases 197,000 square feet of administrative office space in Denver, Colorado under an
operating lease arrangement expiring in 2019, 47,900 square feet of office space in Midland, Texas expiring in 2020, an additional
36,300 square feet of administrative office space in Denver, Colorado assumed in the Kodiak Acquisition expiring in 2016, 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 and Dickinson, North Dakota under an operating lease arrangement expiring in 2015.
Rental expense for 2014, 2013 and 2012 amounted to $7 million, $5 million and $6 million, respectively. Minimum lease payments
under the terms of non-cancelable operating leases as of December 31, 2014 are shown in the table above.
Drilling Rig Contracts—As of December 31, 2014, the Company had 18 drilling rigs under long-term contract, all of which were
operating in the Rocky Mountains region. Subsequent to December 31, 2014, the Company early terminated five of these long-term
contracts incurring early termination penalties totaling approximately $27 million. These penalties and the Company’s minimum
drilling commitments under the terms of the 18 long-term drilling rig contracts as of December 31, 2014 are shown in the table above.
Of the remaining 13 long-term contracts, seven expire in 2016 and six in 2017. Early termination of the remaining contracts would
100
require termination penalties of $212 million, which would be in lieu of paying the remaining drilling commitments under these
contracts. 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 2014, 2013 and 2012, the Company made payments of $106
million, $93 million and $101 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.
Pipeline Transportation Agreements—The Company has two ship-or-pay agreements with different suppliers, one expiring in 2015
and one expiring in 2017, whereby it has committed to transport a minimum daily volume of CO2 or water, as the case may be, via
certain pipelines or else pay for any deficiencies at a price stipulated in the contracts. Although minimum daily quantities are
specified in the agreements, the actual CO2 or water volumes 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, 2014, the Company estimated future commitments under these
ship-or-pay agreements to approximate $20 million through 2017.
In addition, the Company has three pipeline transportation agreements, one expiring in 2024 and two expiring in 2025, whereby it has
committed to pay monthly reservation fees on dedicated pipelines for natural gas and NGL transportation capacity from the Redtail
field, plus a variable charge based on actual transportation volumes. These fixed monthly reservation fees totaling approximately $94
million have been included in the table above.
During 2014, 2013 and 2012, transportation of natural gas, CO2 and water under these contracts amounted to $13 million, $4 million
and $3 million, respectively. As of December 31, 2014, the Company estimated future commitments under all of these pipeline
transportation agreements to approximate $114 million through 2025.
Purchase Contracts—The Company has three take-or-pay purchase agreements, of which one agreement expires in 2015 and two
agreements expire in 2017. One of these agreements contains commitments to buy certain volumes of CO2 for use in its EOR project
in the North Ward Estes field in Texas. Under the remaining two take-or-pay agreements, the Company has committed to buy certain
volumes of water for use in the fracture stimulation process of wells in its Redtail field. Under the terms of these agreements, the
Company is obligated to purchase a minimum volume of CO2 or water, as the case may be, or else pay for any deficiencies at the price
stipulated in the contract. The CO2 volumes planned for use in the Company’s EOR project in the North Ward Estes field and the
water volumes planned for use at our Redtail field currently exceed the minimum volumes specified in all of these agreements,
therefore, the Company expects to avoid any payments for deficiencies under these contracts. During 2014, 2013 and 2012, purchases
of CO2 and water amounted to $105 million, $84 million and $83 million, respectively. Although minimum daily quantities are
specified in the agreements, the actual CO2 or water volumes purchased 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, 2014, the Company estimated future commitments under all of
these purchase agreements to approximate $149 million through 2017.
Delivery Commitments—The Company has various physical delivery contracts which require the Company to deliver fixed volumes
of crude oil. As of December 31, 2014, the Company had delivery commitments of 12.4 MMBbl, 17.8 MMBbl, 19.6 MMBbl, 21.5
MMBbl, 23.3 MMBbl and 6.0 MMBbl of crude oil for the years ended December 31, 2015 through 2020, respectively. These
delivery commitments relate to crude oil production at Whiting’s Redtail field in the DJ Basin in Weld County, Colorado. As of
December 31, 2014, the Company determined that it is no longer probable that future oil production from its Redtail field will be
sufficient to meet the minimum volume requirements specified in these physical delivery contracts, and as a result, the Company
expects to make periodic deficiency payments for any shortfalls in delivering the minimum committed volumes. The Company
currently anticipates that it will under-deliver by a total of approximately 10.4 MMBbl over the duration of the contracts, which would
require undiscounted aggregate deficiency payments of approximately $49 million over the next 5 years. The Company recognizes
any monthly deficiency payments in the period in which the underdelivery takes place and the related liability has been incurred. The
table above does not include any such deficiency payments that may be incurred under the Company’s physical delivery contracts,
since it cannot be predicted with accuracy the amount and timing of any such penalties incurred.
Litigation—The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the ordinary course
of business. We accrue a loss contingency for these lawsuits and claims when it is probable that a loss has been incurred and the
amount of the loss can be reasonably estimated. Accordingly, no material amounts for loss contingencies associated with litigation,
claims or assessments have been accrued at December 31, 2014 or 2013. While the outcome of these lawsuits and claims cannot be
predicted with certainty, it is the opinion of the Company’s management that the loss for any litigation matters and claims that are
reasonably possible to occur will not have a material adverse effect, individually or in the aggregate, on its consolidated financial
position, cash flows or results of operations.
101
14. SUBSEQUENT EVENT
On January 7, 2015, as required under the Kodiak Indentures upon a change in control, Whiting offered to repurchase at 101% of par
all $1,550 million principal amount of Kodiak Notes outstanding. The repurchase offer expires on March 3, 2015. The Company
expects to fund any payments due as a result of such repurchase offer with borrowings under its revolving credit facility.
15. OIL AND GAS ACTIVITIES
The Company’s oil and gas activities for 2014, 2013 and 2012 were entirely within the United States. Costs incurred in oil and gas
producing activities were as follows (in thousands):
Development (1) ...............................................................................
Proved property acquisition (2) .........................................................
Unproved property acquisition (2).....................................................
Exploration ......................................................................................
Total ...........................................................................................
$
$
2014
Year Ended December 31,
2013
2,891,893 $
2,278,855
1,035,439
216,587
6,422,774 $
2,132,824 $
232,572
174,103
363,234
2,902,733 $
2012
1,667,182
19,785
119,175
436,084
2,242,226
_____________________
(1) During 2014, 2013 and 2012, non-cash additions to oil and gas properties of $45 million, $30 million and $36 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.
(2) During 2014, amounts include $2.3 billion of non-cash proved property additions and $1.0 billion of non-cash unproved property
additions related to the Kodiak Acquisition.
Net capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):
Proved oil and gas properties ...............................................................................................
Unproved oil and gas properties ..........................................................................................
Accumulated depletion ........................................................................................................
Oil and gas properties, net ...................................................................................................
$
$
Year Ended December 31,
2014
2013
12,956,834 $
1,992,868
(3,003,270)
11,946,432 $
9,196,845
868,305
(2,645,841)
7,419,309
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 pending the
$
2014
Year Ended December 31,
2013
2012
85,378 $
108,861 $
90,519
determination of proved reserves ..............................................
145,336
281,951
384,223
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.......................................................
$
(200,869)
(15,552)
14,293 $
(291,962)
(13,472)
85,378 $
(358,625)
(7,256)
108,861
At December 31, 2014, the Company had no costs capitalized for exploratory wells in progress for a period of greater than one year
after the completion of drilling.
16. 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
102
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, 2014. Proved reserve estimates included herein conform to the
definitions prescribed by the SEC. 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, 2014, 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, 2012, 2013 and
2014 are as follows:
Oil
(MBbl)
NGLs
(MBbl)
Natural Gas
(MMcf)
Total
(MBOE)
Balance—January 1, 2012 ....................................
Extensions and discoveries ..............................
Sales of minerals in place .................................
Production ........................................................
Revisions to previous estimates .......................
Balance—December 31, 2012 ..............................
Extensions and discoveries ..............................
Sales of minerals in place .................................
Purchases of minerals in place .........................
Production ........................................................
Revisions to previous estimates .......................
Balance—December 31, 2013 ..............................
Extensions and discoveries ..............................
Sales of minerals in place .................................
Purchases of minerals in place .........................
Production ........................................................
Revisions to previous estimates .......................
Balance—December 31, 2014 ..............................
Proved developed reserves:
December 31, 2011 ..........................................
December 31, 2012 ..........................................
December 31, 2013 ..........................................
December 31, 2014 ..........................................
Proved undeveloped reserves:
December 31, 2011 ..........................................
December 31, 2012 ..........................................
December 31, 2013 ..........................................
December 31, 2014 ..........................................
260,144
68,134
(7,960)
(23,139)
4,106
301,285
88,293
(36,992)
14,543
(27,035)
7,327
347,421
146,122
(1,642)
169,586
(33,485)
15,627
643,629
180,975
190,845
198,204
333,593
79,169
110,440
149,217
310,036
37,609
6,526
(320)
(2,766)
(951)
40,098
9,830
(4,777)
1,311
(2,821)
1,228
44,869
12,947
-
-
(3,283)
151
54,684
22,109
24,204
23,721
28,935
15,500
15,894
21,148
25,749
284,975
40,915
(13,987)
(25,827)
(61,812)
224,264
63,893
(12,411)
7,751
(26,917)
20,934
277,514
94,452
(2,925)
156,140
(30,218)
(2,943)
492,020
211,297
160,893
183,129
298,237
73,678
63,371
94,385
193,783
345,249
81,479
(10,611)
(30,209)
(7,148)
378,760
108,772
(43,838)
17,146
(34,342)
12,044
438,542
174,811
(2,130)
195,609
(41,804)
15,288
780,316
238,300
241,864
252,446
412,234
106,949
136,896
186,096
368,082
Notable changes in proved reserves for the year ended December 31, 2014 included:
•
•
•
Extensions and discoveries. In 2014, total extensions and discoveries of 174.8 MMBOE were primarily attributable to
successful drilling at the Redtail, Sanish, Hidden Bench, Missouri Breaks, Pronghorn, Tarpon and Cassandra fields. Both the
new wells drilled in these areas as well as the PUD locations added as a result of drilling increased the Company’s proved
reserves.
Sales of minerals in place. In 2014, total sales of minerals in place of 2.1 MMBOE were primarily attributable to the disposition
of properties in the Big Tex prospect, further described in the Acquisitions and Divestitures footnote, as well as other property
divestitures in the Lucky Ditch, Whiskey Springs and Bridger Lake fields, which decreased the Company’s proved reserves.
Purchases of minerals in place. In 2014, total purchases of minerals in place of 195.6 MMBOE were primarily attributable to
the Kodiak Acquisition, whereby we acquired interests in 778 producing oil and gas wells and undeveloped acreage in the
Williston Basin, further described in the Acquisitions and Divestitures footnote, which increased the Company’s proved
reserves.
103
•
Revisions to previous estimates. In 2014, revisions to previous estimates increased proved developed and undeveloped reserves
by a net amount of 15.3 MMBOE. Included in these revisions were (i) 15.6 MMBOE of net upward adjustments attributable to
reservoir analysis and well performance and (ii) 0.3 MMBOE of downward adjustments caused by lower crude oil prices
incorporated into the Company’s reserve estimates at December 31, 2014 as compared to December 31, 2013.
Notable changes in proved reserves for the year ended December 31, 2013 included:
•
•
•
•
Extensions and discoveries. In 2013, total extensions and discoveries of 108.8 MMBOE were primarily attributable to
successful drilling in the Redtail, Sanish, Missouri Breaks, Hidden Bench and Pronghorn fields. The new producing wells in
these areas and their related proved undeveloped locations added during the year increased the Company’s proved reserves.
Sales of minerals in place. In 2013, total sales of minerals in place of 43.8 MMBOE were primarily attributable to the
disposition of the Postle Properties, further described in the Acquisitions and Divestitures footnote, which decreased the
Company’s proved reserves.
Purchases of minerals in place. In 2013, total purchases of minerals in place of 17.1 MMBOE were primarily attributable to the
acquisition of 121 producing oil and gas wells and undeveloped acreage in the Williston Basin, further described in the
Acquisitions and Divestitures footnote, which increased the Company’s proved reserves.
Revisions to previous estimates. In 2013, revisions to previous estimates increased proved developed and undeveloped reserves
by a net amount of 12.0 MMBOE. Included in these revisions were (i) 4.9 MMBOE of upward adjustments caused by higher
crude oil and natural gas prices incorporated into the Company’s reserve estimates at December 31, 2013 as compared to
December 31, 2012 and (ii) 7.1 MMBOE of net upward adjustments attributable to reservoir analysis and well performance.
Notable changes in proved reserves for the year ended December 31, 2012 included:
•
•
Extensions and discoveries. In 2012, total extensions and discoveries of 81.5 MMBOE were primarily attributable to successful
drilling in the Sanish, Redtail, Missouri Breaks and Pronghorn fields. The new producing wells in these fields and their related
proved undeveloped locations added during the year increased the Company’s proved reserves.
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.
As discussed in Deferred Compensation within these footnotes to the consolidated financial statements, the Company had a
Production Participation Plan (the “Plan”) in which all employees participated. On June 11, 2014, the Board of Directors of the
Company terminated the Plan effective December 31, 2013. The reserve disclosures above include oil and natural gas reserve
volumes that were allocated to the Plan prior to its termination. Once allocated to Plan participants, the interests were fixed. Interest
allocations prior to 1995 consisted of 2%–3% overriding royalty interests. Interest allocations after 1995 were 1.75%–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, 2014, 2013 and
2012 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, 2014, 2013 and 2012, 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.
104
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 ..............
$
$
2014
59,949,707 $
(20,772,234)
(7,924,573)
(8,579,237)
22,673,663
(11,830,243)
10,843,420 $
December 31,
2013
35,178,399 $
(12,973,292)
(5,355,383)
(3,954,401)
12,895,323
(6,301,462)
6,593,861 $
2012
29,308,752
(11,397,332)
(3,181,618)
(4,278,529)
10,451,273
(5,044,240)
5,407,033
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 $7
million in 2014, would not have changed in 2013 and would have decreased by $20 million in 2012.
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
Changes in estimated future development costs ..............................
Purchases of minerals in place .........................................................
Revisions of previous quantity estimates .........................................
Net change in income taxes .............................................................
Accretion of discount .......................................................................
End of year .......................................................................................
$
$
2014
6,593,861 $
(2,274,682)
(48,532)
81,522
3,950,413
1,149,926
(3,382,849)
4,420,417
345,775
(651,817)
659,386
10,843,420 $
December 31,
2013
5,407,033 $
(2,010,925)
(1,064,195)
902,916
2,827,321
832,096
(1,264,189)
445,669
313,069
(335,637)
540,703
6,593,861 $
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
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, 2014, 2013 and 2012 as follows:
Oil (per Bbl) .....................................................................................
NGLs (per Bbl) ................................................................................
Natural Gas (per Mcf) ......................................................................
$
$
$
2014
84.69
46.59
5.88
2013
90.80
54.38
4.30
$
$
$
2012
87.15
58.15
3.21
$
$
$
105
17. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2014 and 2013 (in thousands,
except per share data):
Three Months Ended
March 31,
2014
June 30,
2014
September 30,
December 31,
2014
2014
Oil, NGL and natural gas sales ...............................
Operating profit (1) ...................................................
Net income (loss) ....................................................
Basic earnings (loss) per share ................................
Diluted earnings (loss) per share .............................
$
$
$
$
$
721,250 $
311,169 $
109,051 $
0.92 $
0.91 $
825,760 $
370,033 $
151,426 $
1.27 $
1.26 $
805,054 $
326,215 $
157,961 $
1.33 $
1.32 $
672,553
177,722
(353,693)
(2.69)
(2.68)
Three Months Ended
March 31,
2013
June 30,
2013
September 30,
December 31,
2013
2013
Oil, NGL and natural gas sales ...............................
Operating profit (1) ...................................................
Net income (loss) ....................................................
Basic earnings (loss) per share ................................
Diluted earnings (loss) per share .............................
_____________________
(1) Oil, NGL and natural gas sales less lease operating expense, production taxes and depreciation, depletion and amortization.
605,114 $
252,806 $
86,244 $
0.73 $
0.72 $
651,868 $
269,528 $
134,944 $
1.14 $
1.14 $
706,543 $
316,764 $
204,091 $
1.72 $
1.71 $
$
$
$
$
$
703,024
280,311
(59,276)
(0.50)
(0.50)
******
106
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of disclosure controls and procedures. In accordance with Rule 13a-15(b) of the Securities Exchange Act of 1934 (the
“Exchange Act”), our management evaluated, with the participation of our Chairman, President and Chief Executive Officer and our
Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule
13a-15(e) under the Exchange Act) as of the end of the year ended December 31, 2014. Based upon their evaluation of these
disclosures controls and procedures, the Chairman, President and Chief Executive Officer and the Chief Financial Officer concluded
that the disclosure controls and procedures were effective as of the end of the year ended December 31, 2014 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, 2014 using the criteria
set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission. Based on this assessment, our management believes that, as of December 31, 2014, our internal control over financial
reporting was effective based on those criteria. Our assessment of, and conclusion on, the effectiveness of internal control over
financial reporting did not include the internal controls of the entities acquired in the Kodiak Acquisition on December 8, 2014.
Kodiak’s consolidated total assets and total revenues represent approximately 32% of our consolidated total assets at December 31,
2014 and 1% of our consolidated revenues for the year ended December 31, 2014. We are in the process of integrating Kodiak’s and
our internal control over financial reporting. As a result of these integration activities, certain controls will be evaluated and may be
changed. We believe, however, that we will be able to maintain sufficient internal control over financial reporting throughout this
integration process.
The effectiveness of our internal control over financial reporting as of December 31, 2014 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, 2014 that has materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting.
107
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, 2014, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission. As described in Management’s Annual Report on Internal Control over
Financial Reporting, management excluded from its assessment the internal control over financial reporting of Kodiak Oil & Gas
Corp. (“Kodiak”), which was acquired on December 8, 2014, and whose financial statements constitute 32% of total assets as of
December 31, 2014 and 1% of total revenues of the consolidated financial statement amounts as of and for the year ended December
31, 2014. Accordingly, our audit did not include the internal control over financial reporting at Kodiak. 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,
2014, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the
consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2014 of the Company
and our report dated February 27, 2015 expressed an unqualified opinion on those financial statements and financial statement
schedule.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 27, 2015
Item 9B. Other Information
None.
108
Item 10. Directors, Executive Officers and Corporate Governance
PART III
The information included under the captions “Corporate Governance – Proposal 1 – Election of Directors,” “Corporate Governance –
Board Committee Information – Audit Committee” and “Share Ownership – Section 16(a) Beneficial Ownership Reporting
Compliance” in our definitive Proxy Statement for Whiting Petroleum Corporation’s 2015 Annual Meeting of Stockholders (the
“Proxy Statement”) is incorporated herein by reference. Information with respect to our executive officers appears in Part I of this
Annual Report on Form 10-K.
We have adopted the Whiting Petroleum Corporation Code of Business Conduct and Ethics that applies to our directors, our
Chairman, President and Chief Executive Officer, our Chief Financial Officer, our Controller and Treasurer and other persons
performing similar functions. We have posted a copy of the Whiting Petroleum Corporation Code of Business Conduct and Ethics on
our website at www.whiting.com. The Whiting Petroleum Corporation Code of Business Conduct and Ethics is also available in print
to any stockholder who requests it in writing from the Corporate Secretary of Whiting Petroleum Corporation. We intend to satisfy
the disclosure requirements under Item 5.05 of Form 8-K regarding amendments to, or waivers from, the Whiting Petroleum
Corporation Code of Business Conduct and Ethics by posting such information on our website at www.whiting.com.
We are not including the information contained on our website as part of, or incorporating it by reference into, this report.
Item 11. Executive Compensation
The information required by this Item is included under the captions “Corporate Governance – Director Compensation,” “Executive
Compensation” (other than “Executive Compensation – Proposal 2 – Advisory Vote on the Compensation of Our Named Executive
Officers”) in the Proxy Statement and is 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 captions “Share Ownership – Directors and Executive Officers” and “Share Ownership – Certain Beneficial Owners” in the
Proxy Statement and is incorporated herein 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, 2014.
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)
968,393
$
-
968,393
$
41.09
N/A
41.09
5,048,433 (2)
-
5,048,433 (2)
_____________________
(1) Includes the Whiting Petroleum Corporation 2003 Equity Incentive Plan (the “2003 Plan”) and Whiting Petroleum Corporation
2013 Equity Incentive Plan (the “2013 Plan”). Upon shareholder approval of the 2013 Plan in May 2013, the 2003 Plan was
terminated, but continues to govern awards that were outstanding on its termination. Any shares netted or forfeited under the
2003 Plan will be available for future issuance under the 2013 Plan.
(2) Number of securities reduced by 968,393 stock options outstanding and 1,456,868 shares of restricted common stock previously
issued for which the restrictions have not lapsed.
Item 13. Certain Relationships, Related Transactions and Director Independence
The information required by this Item is included under the caption “Corporate Governance – Governance Information –
Independence of Directors” and “Corporate Governance – Governance Information – Transactions with Related Persons” in the Proxy
Statement and is incorporated herein by reference.
109
Item 14. Principal Accounting Fees and Services
The information required by this Item is included under the caption “Audit Matters – Audit and Non-Audit Fees and Services” in the
Proxy Statement and is incorporated herein 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
110
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
WHITING PETROLEUM CORPORATION
CONDENSED FINANCIAL STATEMENTS OF THE PARENT COMPANY
CONDENSED BALANCE SHEETS
(in thousands)
ASSETS
Current assets .......................................................................................................................
Investment in subsidiaries ....................................................................................................
Intercompany receivable ......................................................................................................
Total assets ...................................................................................................................
$
$
LIABILITIES AND EQUITY
Current liabilities .................................................................................................................
Long-term debt ....................................................................................................................
Other long-term liabilities ....................................................................................................
Shareholders’ equity ............................................................................................................
Total liabilities and equity ............................................................................................
$
$
December 31,
2014
2013
3,859 $
5,464,763
2,907,270
8,375,892 $
27,738 $
2,653,180
-
5,694,974
8,375,892 $
5,120
2,707,184
3,796,321
6,508,625
26,054
2,653,834
170
3,828,567
6,508,625
CONDENSED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(in thousands)
2014
Year Ended December 31,
2013
2012
(1,010) $
(1,864)
66,100
63,226
1,581
64,807 $
64,807 $
(1,131) $
(2,922)
361,732
357,679
8,376
366,055 $
366,055 $
(16,506)
(2,168)
425,870
407,196
6,993
414,189
414,189
OPERATING EXPENSES:
General and administrative .......................................................
Interest expense ........................................................................
Equity in earnings of subsidiaries .............................................
INCOME BEFORE INCOME TAXES .......................................
Income tax benefit ....................................................................
NET INCOME ...............................................................................
COMPREHENSIVE INCOME ....................................................
$
$
$
See notes to condensed financial statements.
111
WHITING PETROLEUM CORPORATION
CONDENSED FINANCIAL STATEMENTS OF THE PARENT COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(in thousands)
Schedule I
2014
Year Ended December 31,
2013
2012
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES .......
$
- $
- $
16,423
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in subsidiaries ...............................................................
-
-
-
CASH FLOWS FROM FINANCING ACTIVITIES:
Intercompany receivable ................................................................
Issuance of 5% Senior Notes due 2019 ...........................................
Issuance of 5.75% Senior Notes due 2021 ......................................
Redemption of 7% Senior Subordinated Notes due 2014 ...............
Repayment of tax sharing liability ..................................................
Net cash used in financing activities........................................
NET CHANGE IN CASH AND CASH EQUIVALENTS ................
CASH AND CASH EQUIVALENTS:
26,373
-
-
-
(26,373)
-
-
(2,048,253)
1,100,000
1,204,000
(253,988)
(1,759)
-
-
Beginning of period ........................................................................
End of period ..................................................................................
$
-
- $
-
- $
NONCASH INVESTING AND FINANCING ACTIVITIES:
Fair value of equity issued in the Kodiak Acquisition ....................
Distributions from Whiting USA Trust I ........................................
Preferred stock dividends paid ........................................................
$
$
$
2,696,094 $
4,614 $
- $
- $
4,749 $
(538) $
(14,094)
-
-
-
(2,329)
(16,423)
-
-
-
-
5,827
(1,077)
See notes to condensed financial statements.
112
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 senior
subordinated notes, 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, 2014, total
restricted net assets were $6.9 billion. 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, 2014 and 2013 (in
thousands):
December 31,
2014
2013
Long-term debt:
6.5% Senior Subordinated Notes due 2018 ..................................................................
5% Senior Notes due 2019 ............................................................................................
5.75% Senior Notes due 2021, including unamortized debt premium of $3,180 and
$
$3,834, respectively .................................................................................................
Other long-term liabilities ....................................................................................................
Total long-term debt and other long-term liabilities .....................................................
$
350,000 $
1,100,000
1,203,180
-
2,653,180 $
350,000
1,100,000
1,203,834
170
2,654,004
Scheduled maturities of the Parent Company’s principal amounts of long-term debt and other long-term liabilities (including the
current portions thereof) as of December 31, 2014 were as follows (in thousands):
Amounts due ..
$
- $
- $
- $
2015
2016
2017
2018
350,000 $ 1,100,000 $ 1,200,000 $ 2,650,000
Thereafter
Total
2019
For further information on the Senior Subordinated Notes, Senior 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
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 a result of voluntary
conversions and the Parent Company exercising its right to mandatorily convert shares of preferred stock effective June 27, 2013, all
172,129 remaining shares of preferred stock outstanding on March 31, 2013, were converted into 792,919 shares of common stock.
As of December 31, 2014, no shares of preferred stock remained outstanding.
For further information on the convertible perpetual preferred stock, refer to the Shareholders’ Equity note to the consolidated
financial statements of the Registrant.
******
113
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 27th day of February, 2015.
SIGNATURES
WHITING PETROLEUM CORPORATION
By /s/ James J. Volker
James J. Volker
Chairman, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on
behalf of the Registrant and in the capacities and on the dates indicated.
Signature
/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/ James E. Catlin
James E. Catlin
/s/ Philip E. Doty
Philip E. Doty
/s/ William N. Hahne
William N. Hahne
/s/ Allan R. Larson
Allan R. Larson
/s/ Lynn A. Peterson
Lynn A. Peterson
/s/ Michael B. Walen
Michael B. Walen
Date
February 27, 2015
February 27, 2015
February 27, 2015
February 27, 2015
February 27, 2015
February 27, 2015
February 27, 2015
February 27, 2015
February 27, 2015
February 27, 2015
February 27, 2015
Title
Chairman, President 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
Director
Director
114
Exhibit
Number
(2.1)^
(3.1)
(3.2)
(4.1)
(4.2)^
(4.3)
(4.4)
(4.5)
(4.6)
(4.7)
(4.8)
(4.9)
(4.10)
(4.11)
EXHIBIT INDEX
Exhibit Description
Arrangement Agreement, dated as of July 13, 2014, by and among Whiting Petroleum Corporation, 1007695 B.C.
Ltd. and Kodiak Oil & Gas Corp. [Incorporated by reference to Exhibit 2.1 to Whiting Petroleum Corporation’s
Current Report on Form 8-K filed on July 14, 2014 (File No. 001-31899)].
Restated Certificate of Incorporation of Whiting Petroleum Corporation [Incorporated by reference to Exhibit 3.2 to
Whiting Petroleum Corporation’s Current Report on Form 8-K filed on July 1, 2013 (File No. 001-31899)].
Amended and Restated By-laws of Whiting Petroleum Corporation, effective February 20, 2014 [Incorporated by
reference to Exhibit 3.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on February 20,
2014 (File No. 001-31899)].
Sixth Amended and Restated Credit Agreement, dated as of August 27, 2014, 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 4.1 to
Whiting Petroleum Corporation’s Current Report on Form 8-K filed on August 28, 2014 (File No. 001-31899)].
Amended and Restated Guaranty and Collateral Agreement, dated as of December 8, 2014, among Whiting
Petroleum Corporation, Whiting Oil and Gas Corporation, Kodiak Oil & Gas Corp., Kodiak Oil & Gas (USA) Inc.,
Kodiak Williston, LLC and JPMorgan Chase Bank, N.A., as Administrative Agent [Incorporated by reference to
Exhibit 4.16 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on December 8, 2014 (File No.
001-31899)].
Maximum Credit Amount Increase Agreement, dated as of December 19, 2014, among Whiting Petroleum
Corporation, Whiting Oil and Gas Corporation, the lenders party thereto, and JPMorgan Chase Bank, N.A., as
Administrative Agent [Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Current Report
on Form 8-K filed on December 22, 2014 (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 (succeeded to Whiting Oil and Gas Corporation)
and The Bank of New York Mellon 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 filed on September 24, 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 filed on September 24, 2010 (File No. 001-31899)].
Supplemental Indenture and Amendment – Subsidiary Guarantee, dated as of December 11, 2014, among Whiting
Petroleum Corporation, Whiting Canadian Holding Company ULC, Whiting Resources Corporation, Whiting US
Holding Company and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to the 6.5% Senior
Subordinated Notes Due 2018 [Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s
Current Report on Form 8-K filed on December 12, 2014 (File No. 001-31899)].
Indenture, dated September 12, 2013, among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation
and The Bank of New York Mellon Trust Company, N.A., as Trustee [Incorporated by reference to Exhibit 4.1 to
Whiting Petroleum Corporation’s Current Report on Form 8-K filed on September 12, 2013 (File No. 001-31899)].
First Supplemental Indenture, dated September 12, 2013, among Whiting Petroleum Corporation, Whiting Oil and
Gas Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating the 5.0% Senior
Notes due 2019 [Incorporated by reference to Exhibit 4.2 to Whiting Petroleum Corporation’s Current Report on
Form 8-K filed on September 12, 2013 (File No. 001-31899)].
Supplemental Indenture and Amendment – Subsidiary Guarantee, dated as of December 11, 2014, among Whiting
Petroleum Corporation, Whiting Canadian Holding Company ULC, Whiting Resources Corporation, Whiting US
Holding Company and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to the 5.0% Senior
Notes Due 2019 [Incorporated by reference to Exhibit 4.2 to Whiting Petroleum Corporation’s Current Report on
Form 8-K filed on December 12, 2014 (File No. 001-31899)].
Second Supplemental Indenture, dated September 12, 2013, among Whiting Petroleum Corporation, Whiting Oil
and Gas Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating the 5.75%
Senior Notes due 2021 [Incorporated by reference to Exhibit 4.3 to Whiting Petroleum Corporation’s Current
Report on Form 8-K filed on September 12, 2013 (File No. 001-31899)].
Supplemental Indenture and Amendment – Subsidiary Guarantee, dated as of December 11, 2014, among Whiting
Petroleum Corporation, Whiting Canadian Holding Company ULC, Whiting Resources Corporation, Whiting US
Holding Company and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to the 5.75%
Senior Notes Due 2021 [Incorporated by reference to Exhibit 4.3 to Whiting Petroleum Corporation’s Current
Report on Form 8-K filed on December 12, 2014 (File No. 001-31899)].
115
Exhibit
Number
(4.12)^
(4.13)^
(4.14)^
(4.15)^
(4.16)^
(4.17)^
(4.18)^
(4.19)^
(4.20)^
(4.21)^
(4.22)^
Exhibit Description
Indenture, dated November 23, 2011, among Kodiak Oil & Gas Corp., Kodiak Oil & Gas (USA) Inc., U.S. Bank
National Association and Computershare Trust Company of Canada, relating to the Kodiak Oil & Gas Corp.
8.125% Senior Notes Due 2019 [Incorporated by reference to Exhibit 4.2 to Kodiak Oil & Gas Corp.’s Current
Report on Form 8-K filed on November 23, 2011 (File No. 001-32920)].
Supplemental Indenture, dated as of July 30, 2013, among Kodiak Oil & Gas Corp., Kodiak Williston, LLC, KOG
Finance, LLC, U.S. Bank National Association and Computershare Trust Company of Canada, to the Indenture,
dated as of November 23, 2011, among Kodiak Oil & Gas Corp., Kodiak Oil & Gas (USA) Inc., U.S. Bank
National Association and Computershare Trust Company of Canada, relating to the Kodiak Oil & Gas Corp.
8.125% Senior Notes Due 2019 [Incorporated by reference to Exhibit 4.1 to Kodiak Oil & Gas Corp.’s Quarterly
Report on Form 10-Q for the Quarter Ended June 30, 2013 (File No. 001-32920)].
Supplemental Indenture, dated as of October 3, 2014, among Kodiak Oil & Gas Corp., KOG Oil & Gas ULC, U.S.
Bank National Association and Computershare Trust Company of Canada, to the Indenture, dated as of November
23, 2011, as supplemented, among Kodiak Oil & Gas Corp., Kodiak Oil & Gas (USA) Inc., U.S. Bank National
Association and Computershare Trust Company of Canada, relating to the Kodiak Oil & Gas Corp. 8.125% Senior
Notes Due 2019 [Incorporated by reference to Exhibit 4.1 to Kodiak Oil & Gas Corp.’s Current Report on Form 8-
K filed on October 6, 2014 (File No. 001-32920)].
First Supplemental Indenture, dated October 17, 2014, among Kodiak Oil & Gas Corp., Kodiak Oil & Gas (USA)
Inc., KOG Finance, LLC, Kodiak Williston, LLC, KOG Oil & Gas ULC, U.S. Bank National Association, as
trustee, Computershare Trust Company of Canada, as Canadian trustee, and Whiting Petroleum Corporation,
relating to the Kodiak Oil & Gas Corp. 8.125% Senior Notes Due 2019 [Incorporated by reference to Exhibit 4.1 to
Whiting Petroleum Corporation’s Current Report on Form 8-K filed on October 20, 2014 (File No. 001-31899)].
Second Supplemental Indenture, dated as of December 4, 2014, among Kodiak Oil & Gas Corp., Kodiak Oil & Gas
(USA) Inc., Kodiak Williston, LLC, Whiting Oil and Gas Corporation, Whiting US Holding Company, U.S. Bank
National Association, as trustee, and Computershare Trust Company of Canada, as Canadian Trustee, relating to the
8.125% Senior Notes Due 2019 [Incorporated by reference to Exhibit 4.12 to Whiting Petroleum Corporation’s
Current Report on Form 8-K filed on December 8, 2014 (File No. 001-31899)].
Indenture, dated January 15, 2013, among Kodiak Oil & Gas Corp., Kodiak Oil & Gas (USA) Inc., U.S. Bank,
National Association, as trustee, and Computershare Trust Company of Canada, as the Canadian trustee, relating to
the Kodiak Oil & Gas Corp. 5.5% Senior Notes Due 2021 [Incorporated by reference to Exhibit 4.2 to Kodiak Oil
& Gas Corp.’s Current Report on Form 8-K filed on January 15, 2013 (File No. 001-32920)].
Supplemental Indenture, dated as of July 30, 2013, among Kodiak Oil & Gas Corp., Kodiak Williston, LLC, KOG
Finance, LLC, U.S. Bank National Association and Computershare Trust Company of Canada, to the Indenture,
dated as of January 15, 2013, among Kodiak Oil & Gas Corp., Kodiak Oil & Gas (USA) Inc., U.S. Bank National
Association and Computershare Trust Company of Canada, relating to the Kodiak Oil & Gas Corp. 5.5% Senior
Notes Due 2021 [Incorporated by reference to Exhibit 4.2 to Kodiak Oil & Gas Corp.’s Quarterly Report on Form
10-Q for the Quarter Ended June 30, 2013 (File No. 001-32920)].
Supplemental Indenture, dated as of October 3, 2014, among Kodiak Oil & Gas Corp., KOG Oil & Gas ULC, U.S.
Bank National Association and Computershare Trust Company of Canada, to the Indenture, dated as of January 15,
2013, as supplemented, among Kodiak Oil & Gas Corp., Kodiak Oil & Gas (USA) Inc., U.S. Bank National
Association and Computershare Trust Company of Canada, relating to the Kodiak Oil & Gas Corp. 5.5% Senior
Notes Due 2021 [Incorporated by reference to Exhibit 4.2 to Kodiak Oil & Gas Corp.’s Current Report on Form 8-
K filed on October 6, 2014 (File No. 001-32920)].
First Supplemental Indenture, dated October 17, 2014, among Kodiak Oil & Gas Corp., Kodiak Oil & Gas (USA)
Inc., KOG Finance, LLC, Kodiak Williston, LLC, KOG Oil & Gas ULC, U.S. Bank National Association, as
trustee, and Computershare Trust Company of Canada, as Canadian trustee, and Whiting Petroleum Corporation,
relating to the Kodiak Oil & Gas Corp. 5.5% Senior Notes Due 2021 [Incorporated by reference to Exhibit 4.2 to
Whiting Petroleum Corporation’s Current Report on Form 8-K filed on October 20, 2014 (File No. 001-31899)].
Second Supplemental Indenture, dated as of December 4, 2014, among Kodiak Oil & Gas Corp., Kodiak Oil & Gas
(USA) Inc., Kodiak Williston, LLC, Whiting Oil and Gas Corporation, Whiting US Holding Company, U.S. Bank
National Association, as trustee, Computershare Trust Company of Canada, as Canadian Trustee, relating to the
5.5% Senior Notes Due 2021 [Incorporated by reference to Exhibit 4.13 to Whiting Petroleum Corporation’s
Current Report on Form 8-K filed on December 8, 2014 (File No. 001-31899)].
Indenture, dated July 26, 2013, among Kodiak Oil & Gas Corp., Kodiak Oil & Gas (USA) Inc., KOG Finance,
LLC, Kodiak Williston, LLC, U.S. Bank National Association, as trustee, and Computershare Trust Company of
Canada, as Canadian trustee, relating to the Kodiak Oil & Gas Corp. 5.5% Senior Notes Due 2022 [Incorporated by
reference to Exhibit 4.2 to Kodiak Oil & Gas Corp.’s Current Report on Form 8-K filed on July 26, 2013 (File No.
001-32920)].
116
Exhibit
Number
(4.23)^
(4.24)^
(4.25)^
(4.26)
(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
Supplemental Indenture, dated as of October 3, 2014, among Kodiak Oil & Gas Corp., KOG Oil & Gas ULC, U.S.
Bank National Association and Computershare Trust Company of Canada, to the Indenture, dated as of July 26,
2013, among Kodiak Oil & Gas Corp., Kodiak Oil & Gas (USA) Inc., U.S. Bank National Association and
Computershare Trust Company of Canada, relating to the Kodiak Oil & Gas Corp. 5.5% Senior Notes Due 2022
[Incorporated by reference to Exhibit 4.3 to Kodiak Oil & Gas Corp.’s Current Report on Form 8-K filed on
October 6, 2014 (File No. 001-32920)].
First Supplemental Indenture, dated October 17, 2014, among Kodiak Oil & Gas Corp., Kodiak Oil & Gas (USA)
Inc., KOG Finance, LLC, Kodiak Williston, LLC, KOG Oil & Gas ULC, U.S. Bank National Association, as
trustee, Computershare Trust Company of Canada, as Canadian trustee, and Whiting Petroleum Corporation,
relating to the Kodiak Oil & Gas Corp. 5.5% Senior Notes Due 2022 [Incorporated by reference to Exhibit 4.3 to
Whiting Petroleum Corporation’s Current Report on Form 8-K filed on October 20, 2014 (File No. 001-31899)].
Second Supplemental Indenture, dated as of December 4, 2014, among Kodiak Oil & Gas Corp., Kodiak Oil & Gas
(USA) Inc., Kodiak Williston, LLC, Whiting Oil and Gas Corporation, Whiting US Holding Company, U.S. Bank
National Association, as trustee, and Computershare Trust Company of Canada, as Canadian Trustee, relating to the
5.5% Senior Notes Due 2022 [Incorporated by reference to Exhibit 4.14 to Whiting Petroleum Corporation’s
Current Report on Form 8-K filed on December 8, 2014 (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 filed on February 24, 2006 (File No. 001-31899)].
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 filed on October 29,
2007 (File No. 001-31899)].
Whiting Petroleum Corporation 2013 Equity Incentive Plan [Incorporated by reference to Annex A to Whiting
Petroleum Corporation’s definitive proxy statement filed with the Securities and Exchange Commission on
Schedule 14A on March 25, 2013 (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 filed on October 29, 2007 (File No. 001-31899)].
Form of Restricted Stock Agreement pursuant to the Whiting Petroleum Corporation 2003 Equity Incentive Plan for
awards to executive officers 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)].
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)].
Form of Indemnification Agreement for directors and 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 Employment and Severance 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 filed on January 5, 2015 (File No. 001-31899)].
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)].
Form of Restricted Stock Agreement pursuant to the Whiting Petroleum Corporation 2013 Equity Incentive Plan for
performance vesting awards [Incorporated by reference to Exhibit 10.14 to Whiting Petroleum Corporation’s
Annual Report on Form 10-K for the year ended December 31, 2013 (File No. 001-31899)].
Form of Restricted Stock Agreement pursuant to the Whiting Petroleum Corporation 2013 Equity Incentive Plan for
time-based vesting awards [Incorporated by reference to Exhibit 10.15 to Whiting Petroleum Corporation’s Annual
Report on Form 10-K for the year ended December 31, 2013 (File No. 001-31899)].
Form of Stock Option pursuant to the Whiting Petroleum Corporation 2013 Equity Incentive Plan [Incorporated by
reference to Exhibit 10.16 to Whiting Petroleum Corporation’s Annual Report on Form 10-K for the year ended
December 31, 2013 (File No. 001-31899)].
117
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 Performance Share Award Agreement pursuant to the Whiting Petroleum Corporation 2013 Equity
Incentive Plan [Incorporated by reference to Exhibit 10.2 to Whiting Petroleum Corporation’s Current Report on
Form 8-K filed on January 5, 2015 (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, President 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, President 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 2015 Annual Meeting of Stockholders, to be filed within 120 days of December 31, 2014
[To be filed with the Securities and Exchange Commission under Regulation 14A within 120 days after December
31, 2014; except to the extent specifically incorporated by reference, the Proxy Statement for the 2015 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
6, 2015.
The following materials from Whiting Petroleum Corporation’s Annual Report on Form 10-K for the year ended
December 31, 2014 are filed herewith, formatted in XBRL (Extensible Business Reporting Language): (i) the
Consolidated Balance Sheets as of December 31, 2014 and 2013, (ii) the Consolidated Statements of Income for the
Years Ended December 31, 2014, 2013 and 2012, (iii) the Consolidated Statements of Comprehensive Income for
the Years Ended December 31, 2014, 2013 and 2012, (iv) the Consolidated Statements of Cash Flows for the Years
Ended December 31, 2014, 2013 and 2012, (v) the Consolidated Statements of Equity for the Years Ended
December 31, 2014, 2013 and 2012 and (vi) Notes to Consolidated Financial Statements.
_____________________
*
^
A management contract or compensatory plan or arrangement.
Kodiak Oil & Gas Corp. is now known as Whiting Canadian Holding Company ULC; Kodiak Oil & Gas (USA) Inc. is now
known as Whiting Resources Corporation; Kodiak Williston, LLC has merged with Whiting Resources Corporation; KOG
Finance, LLC has been dissolved; and KOG Oil & Gas ULC has been liquidated.
118
Director Compensation
Effective June 1, 2015, non-employee director compensation is as follows:
Exhibit 10.6
Annual retainer .........................................................
Restricted stock (value), one year vesting .................
Committee chair annual retainer ...............................
Committee chair restricted stock (value) ..................
Committee member annual retainer ..........................
Meeting fee ...............................................................
$
Committee Service
$
Board
Service
58,500
175,000
-
-
-
1,500
$
Audit
-
-
25,000
25,000
10,000
1,500
Compensation
-
$
-
15,000
15,000
5,000
1,500
Nominating
and
Governance
-
-
15,000
15,000
5,000
1,500
SUBSIDIARIES OF WHITING PETROLEUM CORPORATION
Name
Whiting Oil and Gas Corporation
Whiting US Holding Company
Whiting Canadian Holding Company ULC
Whiting Resources Corporation
Jurisdiction of Incorporation or
Organization
Delaware
Delaware
British Columbia
Colorado
Percent Ownership
100%
100%
100%
100%
Exhibit 21
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement Nos. 333-111056, 333-190197 and 333-200793 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 27, 2015, 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, 2014.
Exhibit 23.1
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 27, 2015
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
Cawley, Gillespie & Associates, Inc.
PETROLEUM CONSULTANTS
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 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, 2014. 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, 2014, 2013 and 2012 and to the inclusion of our reports dated January 6, 2015 as an exhibit to the Annual Report
on Form 10-K of Whiting Petroleum Corporation for the year ended December 31, 2014. We further consent to the incorporation by
reference thereof into Whiting Petroleum Corporation’s Registration Statements on Form S-8 (Registration Nos. 333-111056, 333-
190197 and 333-200793), 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 27, 2015
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.
/s/ James J. Volker
James J. Volker
Chairman, President and Chief Executive Officer
Date: February 27, 2015
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.
/s/ Michael J. Stevens
Michael J. Stevens
Vice President and Chief Financial Officer
Date: February 27, 2015
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, President 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, 2014 (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, President and Chief Executive Officer
Date: February 27, 2015
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, 2014 (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 27, 2015
Cawley, Gillespie & Associates, Inc.
PETROLEUM CONSULTANTS
Exhibit 99.2
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 6, 2015
Mr. Steven Kranker
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, 2014
Pursuant to the Guidelines of the Securities and
Exchange Commission for Reporting Corporate
Reserves and Future Net Revenue
Dear Mr. Kranker:
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 6, 2015 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
Developed
Shut-in
Proved
Undeveloped
Total Proved
Net Reserves
Oil
Gas
NGL
Revenue
Oil
Gas
NGL
Severance Taxes
Ad Valorem Taxes
Operating Expenses
Investments
- Mbbl
- MMcf
- Mbbl
- M$
- M$
- M$
- M$
- M$
- M$
- M$
318,300.9
291,135.2
25,171.8
26,780,016.0
1,734,098.3
1,201,102.9
2,777,641.0
272,769.2
8,835,211.0
435,685.2
1,116.3
5,473.8
194.6
97,030.3
26,447.8
9,236.5
9,202.9
1,507.0
32,676.0
6,113.8
14,175.8
1,627.8
3,568.8
1,279,660.8
6,749.0
180,986.4
69,312.0
34,061.6
237,032.6
254,682.0
Net Operating Income
- M$
17,393,896.0
83,214.9
872,307.9
Discounted @ 10%
- M$
9,680,699.0
31,402.9
245,719.7
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
310,035.8
193,783.4
25,749.3
643,628.6
492,020.0
54,684.5
26,354,444.0
1,123,661.6
1,156,281.6
54,511,144.0
2,890,956.0
2,547,607.5
2,493,943.3
746,724.3
5,262,144.5
7,228,092.0
5,350,098.0
1,055,061.6
14,367,074.0
7,924,573.0
12,903,478.0
31,252,898.0
4,177,611.0
14,135,443.0
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 $94.99 per bbl and $4.35 per
MMBtu, respectively, were adjusted individually to WTI posted pricing at $91.60 per bbl and Houston Ship Channel pricing at $4.30
per MMBtu, as of December 31, 2014. 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 $84.69 per bbl of oil, $46.59 per bbl of natural gas liquids and $5.88 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 costs of plugging and abandonment,
less proceeds from the salvage value of equipment and/or facilities, have been included where material.
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
• 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.
Life
Footnotes
• 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)
recovered:
Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be
“(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.
PETROLEUM CONSULTANTS
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 6, 2015
Mr. Steven Kranker
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, 2014
Pursuant to the Guidelines of the Securities and
Exchange Commission for Reporting Corporate
Reserves and Future Net Revenue
Dear Mr. Kranker:
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 6, 2015 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 composite summaries presented below, beginning with the probable summary and followed by the possible
summary:
Probable Developed
Behind Pipe
Probable Developed
Non-Producing
Probable
Undeveloped
Total
Probable
Net Reserves
Oil
Gas
NGL
Revenue
Oil
Gas
NGL
Severance Taxes
Ad Valorem Taxes
Operating Expenses
Investments
Net Operating Income
Discounted @ 10%
- Mbbl
- MMcf
- Mbbl
- M$
- M$
- M$
- M$
- M$
- M$
- M$
- M$
- M$
491.8
6,082.2
147.0
43,710.8
29,514.8
5,889.9
4,859.5
848.5
20,497.0
4,285.2
48,625.3
10,173.5
381.2
2,884.2
919,902.6
1,702.7
147,762.3
49,240.3
24,789.1
94,196.7
249,149.4
323,579.2
271,609.8
15,685.3
27,440,776.0
1,649,638.9
696,288.3
2,635,746.0
881,919.8
5,427,207.5
8,296,450.5
334,244.4
278,073.3
18,716.6
28,404,386.0
1,680,856.5
849,940.4
2,689,845.8
907,557.4
5,541,902.5
8,549,884.0
651,992.1
12,545,382.0
13,246,002.0
18,320.2
123,223.7
3,500,892.3
3,642,436.3
Net Reserves
Oil
Gas
NGL
Revenue
Oil
Gas
NGL
Severance Taxes
Ad Valorem Taxes
Operating Expenses
Investments
Net Operating Income
Discounted @ 10%
- Mbbl
- MMcf
- Mbbl
- M$
- M$
- M$
- M$
- M$
- M$
- M$
- M$
- M$
Possible
Developed
Possible Developed
Non-Producing
Possible Undeveloped
647.8
1,784.1
109.4
58,448.7
9,902.9
4,990.0
4,083.3
896.1
14,995.2
6,152.8
24,714.8
897.5
7,006.7
2,232,404.8
4,007.5
358,616.3
119,487.5
60,155.6
184,118.3
280,501.6
154,741.2
114,922.8
18,728.0
13,477,413.0
559,957.4
904,687.2
974,096.7
653,829.8
2,514,296.3
3,616,402.0
Total
Possible
180,103.9
117,604.4
25,844.0
15,768,267.0
573,867.8
1,268,293.5
1,097,667.4
714,881.6
2,713,410.0
3,903,055.8
47,214.3
1,950,765.6
7,183,433.5
9,181,412.0
24,998.8
199,740.3
1,354,187.4
1,578,926.8
The discounted cash flow values shown in the previous two tables 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 $94.99 per bbl and $4.35
per MMBtu, respectively, were adjusted individually to WTI posted pricing at $91.60 per bbl and Houston Ship Channel
pricing at $4.30 per MMBtu, as of December 31, 2014. 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 $84.98 per bbl of oil, $45.41 per bbl of
natural gas liquids and $6.05 per mcf of natural gas. For the Possible reserves, the average adjusted prices were $87.55 per bbl
of oil, $49.08 per bbl of natural gas liquids and $4.88 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 costs of plugging and
abandonment, less proceeds from the salvage value of equipment and/or facilities, have been included where material.
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
• 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.
Life
Footnotes
• 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
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
Cawley, Gillespie & Associates, Inc.
PETROLEUM CONSULTANTS
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 4/6/15 11:23 AM Page 2
With our acquisition of Kodiak Oil & Gas Corp., we are a
Corporate Overview
stronger company working to prosper at current prices.
Our complimentary acreage positions concentrated in
Financial and Operations Summary
the sweet spots of the Williston Basin allow for more
Letter to the Shareholders
efficient operations, and the application of Whiting’s
technological expertise to enhance drilling results and
reduce costs. The increased scale of the combined
companies enhances the company’s position relative to
competitors and achieves a better cost profile for its
drilling and completion program. Along with our high
quality acreage position in the DJ Basin Niobrara play
Acquisitions
Drilling and Operations Overview
Exploration and Development
Redtail: Our Economic Sweet Spot
in our Redtail field, we believe Whiting controls the
Technique and Technology
premier light, tight oil assets in North America.
1
2
4
6
8
10
12
14
16
17
ABBREVIATIONS
Bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in this
reserves and accordingly are subject to substantially greater risk of
report in reference to oil, NGLs and other liquid hydrocarbons.
not actually being realized by the Company.
Board of Directors
Annual Report on Form 10-K
Corporate Investor Information
Inside back cover
RESERVE 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 con-
tracts providing the right to operate expire, unless evidence indicates
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. Pos-
sible 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
FORWARD-LOOKING STATEMENTS
This annual report contains forward-looking statements. Please
refer to “Forward-Looking Statements” on page 64 of the attached
Annual Report on Form 10-K for an explanation of these types of state-
ments. These statements should be considered in light of the “Risk Factors”
set forth on page 17 of the attached Annual Report on Form 10-K.
Pictured on the cover is higher density drilling at our Mork
Trust Unit in the Hidden Bench field, located in McKenzie
County, North Dakota. The Mork Trust 21-17-2H and the
Mork Trust 21-17-3H were completed at an average rate
of 2,643 BOE/d per well from the Bakken. These wells
were infill wells testing an eight well per spacing unit
pattern in the Middle Bakken formation. Both wells,
which were completed using cemented liners and plug-
and-perf technology, were fracture stimulated in 30
stages with four entry points per stage. These wells, using
our new completion design, had initial production rates
that were 53% better than old wells completed with our
previous completion design.
Bcf: One billion cubic feet of natural gas.
BOE: One stock tank barrel of oil equivalent, computed on an approxi-
mate 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.
BOE/d: Barrels of oil equivalent per day.
Completion: The installation of permanent equipment for the produc-
tion 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.
MBOE/d: MBOE per day.
MMBbl: One million barrels.
MMBOE: One million BOE.
MMcf/d: MMcf per day.
NGLs: Natural gas liquids.
Mcf: One thousand cubic feet, used in reference to natural gas or CO2.
MMcf: One million cubic feet, used in reference to natural gas or CO2.
ABOUT THE COVER
CONTENTS
EXECUTIVE OFFIC ERS
OTHER OFFICERS
BOARD OF DIRECTORS
JAMES J.VOLKER
Chairman of the Board, President
and Chief Executive Officer
CHUCK LACOUTURE
Vice President, Marketing
for Whiting Oil and Gas Corporation
MARK D. SONNENFELD
Vice President, Geoscience
for Whiting Oil and Gas Corporation
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
MICHAEL R. CRAIG
Vice President,
Information Technology
MICHAEL J. STEVENS
Senior Vice President and
Chief Financial Officer
MARK R. WILLIAMS
Senior Vice President, Exploration
and Development
RICK A. ROSS
Senior Vice President, Operations
PETER W. HAGIST
Senior Vice President, Planning
STEVEN A. KRANKER
Vice President, Reservoir Engineering
and Acquisitions
BRUCE R. DEBOER
Vice President, General Counsel
and Corporate Secretary
BRENT P. JENSEN
Vice President and Treasurer
DAVID M. SEERY
Vice President, Land
HEATHER M. DUNCAN
Vice President, Human Resources
DIRECTOR SINCE
JAMES J. VOLKER 2003
Chairman of the Board, President
and Chief Executive Officer
THOMAS L. ALLER *+ 2003
Retired President
Interstate Power and Light Company
an Alliant Energy Company
D. SHERWIN ARTUS^ 2006
Retired President and CEO
Whiting Petroleum Corporation
JAMES E. CATLIN 2014
Past Executive Vice President
and Director
Kodiak Oil and Gas Corporation
PHILIP E. DOTY*^ 2010
Certified Public Accountant
WILLIAM N. HAHNE +^ 2007
Past Chief Operating Officer
Petrohawk Energy Corporation
ALLAN R. LARSON^ 2011
Consulting Geologist
LYNN A. PETERSON 2014
Past President, CEO and
Chairman of the Board
Kodiak Oil and Gas Corporation
MICHAEL B. WALEN*+ 2013
Past Chief Operating Officer
Cabot Oil and Gas Corporation
* Audit Committee
+ Compensation Committee
^ Nominating and Governance Committee
CORPORATE OFFICES
TRANSFER AGENT
Whiting Petroleum Corporation
Please direct communication
1700 Broadway, Suite 2300
regarding individual stock records
INFORMATION UPDATES
Whiting’s quarterly financial results and
other information are available on our
Denver, Colorado 80290-2300
and address changes to:
website at www.whiting.com
Tel: (303) 837-1661
Fax: (303) 861-4023
www.whiting.com
Computershare Trust Company, N.A.
8742 Lucent Blvd., Suite 225
ANNUAL REPORT ON FORM 10-K
Highlands Ranch, Colorado 80129
Upon request, the Company will
INVESTOR RELATIONS
Securities analysts, investors and the
financial media should contact:
John B. Kelso
Director, Investor Relations
Tel: (303) 837-1661
Eric K. Hagen
Tel: (303) 262-0600
Fax: (303) 262-0700
www.computershare.com
INDEPENDENT
PETROLEUM ENGINEERS
Cawley, Gillespie & Associates, Inc.
Vice President, Investor Relations
INDEPENDENT REGISTERED
Tel: (303) 837-1661
PUBLIC ACCOUNTING FIRM
Deloitte & Touche LLP
provide, without charge, copies of the
2014 Annual Report on Form 10-K
as filed with the Securities and
Exchange Commission
ANNUAL MEETING
Tuesday, June 2, 2015
10:00 A.M. (DENVER TIME)
The Grand Hyatt Hotel
Capitol Peak Ballroom
555 17th Street, 38th floor
Denver, Colorado 80202
STOCK EXCHANGE LISTING
New York Stock Exchange, trading
symbol: WLL
fp_Cover 4/6/15 11:23 AM Page 1
1700 Broadway, Suite 2300
Denver, Colorado 80290-2300
Tel: (303) 837-1661
Fax: (303) 861-4023
www.whiting.com
WHITING PETROLEUM CORPORATION
The Largest Bakken/Three Forks Producer
A STRONGER
COMPANY
WORKING TO
PROSPER AT
CURRENT PRICES
Annual Report 2014