WHITING PETROLEUM
CORPORATION
TEN
YEARS
OF
GROWTH
+
Bakken Continues
to Grow
A
COMPANY
ON
THE
MOVE
The Sun Rises on
Whiting’s High Potential
Niobrara Play
ANNUAL REPOR T 2O13
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2
4
6
9
14
18
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20
21
ABOUT THE COVER
We are a company on the move:
CONTENTS
Corporate Overview
Financial and Operations Summary
• Cash flow hit a record $457.6 in the fourth quarter of
Letter to the Shareholders
2013, up 20% year-over-year;
• Production and proved reserves also set new records.
Adjusting for the Postle sale, production increased 21%
and reserves increased 31% over 2012 levels;
• Sold our Postle/N.E. Hardesty EOR project for $809.7
million. We replaced the 7,560 BOE/d of the production
associated with the project in one quarter;
Drilling and Operations Overview
Williston Basin Oil Plays
Other Development Areas
Safety and the Environment
Building for the Future
• Sold more than 32,000 net acres in our Big Tex prospect
Board of Directors
in the Delaware Basin for $152.0 million;
• Acquired more than 39,000 gross (17,000 net) acres and
2,420 BOE/d in the Williston Basin for $259 million.
The acreage is prospective in both the Bakken and Three
Forks formations;
• Accumulated more than 600,000 gross (500,000 net)
acres in three new oil resource plays at an average cost
of $228 per net acre;
• Raised $2.3 billion from two senior note offerings that
provides us with the financial flexibility to execute on
our operating plans;
• As a result of these actions, we have an exceptionally
good balance sheet which we are using to accelerate pro-
duction and reserve growth at Redtail and in the Bakken.
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.
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.
Annual Report on Form 10-K
Corporate Investor Information
Inside back cover
RESERVE AND RESOURCE INFORMATION
Whiting uses in this annual report the terms proved, probable and
possible reserves. Proved reserves are reserves which, by analysis of
geoscience and engineering data, can be estimated with reasonable
certainty to be economically producible from a given date forward,
from known reservoirs under existing economic conditions, operating
methods and government regulations prior to the time at which 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.
Possible reserves are reserves that are less certain to be recovered
than probable reserves. Estimates of probable and possible reserves
which may potentially be recoverable through additional drilling or
recovery techniques are by nature more uncertain than estimates of
proved reserves and accordingly are subject to substantially greater
risk of not actually being realized by the Company.
Whiting uses in this annual report the term “total resources,”
which consists of contingent and prospective resources, which SEC
rules prohibit in filings of U.S. registrants. Contingent resources are
resources that are potentially recoverable but not yet considered
mature enough for commercial development due to technological
or business hurdles. For contingent resources to move into the reserves
category, the key conditions or contingencies that prevented com-
mercial development must be clarified and removed. Prospective
resources are estimated volumes associated with undiscovered
accumulations. These represent quantities of petroleum which are
estimated to be potentially recoverable from oil and gas deposits
identified on the basis of indirect evidence but which have not yet
been drilled. This class represents a higher risk than contingent
resources since the risk of discovery is also added. For prospective
resources to become classified as contingent resources, hydrocarbons
must be discovered, the accumulations must be further evaluated
and an estimate of quantities that would be recoverable under
appropriate development projects prepared. Estimates of resources
are by nature more uncertain than reserves and accordingly are
subject to substantially greater risk of not actually being realized by
the Company. Our drilling inventory of primary and potential future
locations assume contingent and prospective resources.
FORWARD-LOOKING STATEMENTS
This annual report contains forward-looking statements. Please
refer to “Forward-Looking Statements” on page 70 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 Fac-
tors” set forth on page 20 of the attached Annual Report on Form 10-K.
fp_AR Pgs 1-20 3/11/14 3:10 PM Page 1
CORPORATE OVERVIEW
Whiting Petroleum Corporation, a Delaware
corporation, is an independent oil and gas company
that explores for, develops, acquires and produces
crude oil, natural gas and natural gas liquids primarily
in the Rocky Mountains and Permian Basin regions
of the United States. The Company’s largest projects
are in the Bakken and Three Forks plays in North
Dakota, the Niobrara play in northeast Colorado and
its Enhanced Oil Recovery fiff eld in TeTT xas. The Company
trades publicly under the symbol WLL on the New
YoYY rk Stock Exchange.
WeWW believe that our significant drilling inventory
of over 10,600 identified primary gross locations
provides us with strong organic growth opportunities.
Of these total gross locations, 41% are located in our
Williston Basin Bakken/Three Forks plays and 31%
are located in our Redtail Niobrara play in Colorado.
This large inventory,yy combined with our operating
experience and cost structure, is expected to fuff el our
growth for years to come.
The following table summarizes our proved,
probable and possible reserves:
3P RESERVES ( 1 )
Oil
(MMBbl)
NGLs
(MMBbl)
347.4
109.3
137.2
44.9
22.3
24.6
Natural
Gas
(Bcf)
277.5
267.6
163.8
ToTT tal %
Oil
(MMBOE)
438.5
176.2
189.1
79%
62%
73%
PROVED
PROBABLE
POSSIBLE
(1) Oil and gas reserve quantities and related discounted future net cash flows have been derived
from oil and gas prices calculated using an average of the first-day-of-the month NYMEX price for
each month within the 12 months ended December 31, 2013, pursuant to current SEC and FAFF SB
guidelines. The NYMEX prices used were $96.78/Bbl and $3.67/MMBtu.
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FINANCIAL AND OPERATIONS SUMMARY
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS,
PER UNIT PRICES OR RATIO AMOUNTS) 2013 2012 2011 2010 2009
Income Statement and Cash Flow
Oil and Gas Sales $ 2,666.5 $ 2,137.7 $ 1,860.1 $ 1,475.3 $ 917.5
Earnings (Loss) $ 366.0 $ 414.1 $ 491.6 $ 336.7 $ (106.9)(1)
Earnings (Loss) per Share, Diluted $ 3.06 $ 3.48 $ 4.14 $ 2.55 $
(1.18)(1)
Weighted Average Shares Outstanding, Diluted 119.588 119.028 118.668 107.846 100.088
Net Cash Provided by Operating Activities $ 1,744.7 $ 1,401.2 $ 1,192.1 $ 997.3 $ 453.8
Net Cash Used in Investing Activities $(1,902.5) $(1,780.3) $(1,760.0) $ (914.6) $ (523.5)
Net Cash Provided by (Used in) Financing Activities $ 812.4 $ 408.1 $ 564.8 $
(75.7) $ 72.1
Balance Sheet
Total Assets $ 8,833.5 $ 7,272.4 $ 6,045.6 $ 4,648.8 $ 4,029.5
Debt $ 2,653.8 $ 1,800.0 $ 1,380.0 $ 800.0 $ 779.6
Shareholders’ Equity $ 3,836.7 $ 3,453.2 $ 3,029.1 $ 2,531.3 $ 2,270.1
Debt-to-Capitalization Ratio 34% 34% 31% 24% 26%
Production and Average Commodity Prices
Oil Production, MMBbl 27.0 23.1 18.3 17.5 13.9
NGL Production, MMBbl 2.8 2.8 2.1 1.5 1.5
Natural Gas Production, Bcf 26.9 25.8 26.4 27.4 29.3
Total Production, MMBOE 34.3 30.2 24.8 23.6 20.3
Oil Price, per Bbl, Excluding Hedging $ 90.39 $ 83.86 $ 88.61 $ 72.61 $ 54.80
Natural Gas Liquids Price, per Bbl $ 40.41 $ 39.36 $ 52.38 $ 47.33 $ 31.07
Natural Gas Price, per Mcf, Excluding Hedging $ 4.04 $ 3.42 $ 4.92 $ 4.86 $ 3.75
Sales Price, per BOE, Net of Hedging $ 76.76 $ 69.85 $ 73.88 $ 61.48 $ 45.01
Year-End 2013 Well Count and Acreage Statistics GROSS NET
Total Wells 10,476 3,922
Developed Acreage 1,387,181 751,703
Undeveloped Acreage 1,694,585 1,192,424
(1) Includes after-tax, non-cash losses on hedging arrangements of $137.5 million or $2.75 per share.
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Proved Reserves as of December 31, 2013 2012 2011 2010 2009
Oil, MMBbl 347.4 301.3 260.2 224.2 193.3
NGLs, MMBbl 44.9 40.1 37.6 30.1 30.5
Natural Gas, Bcf 277.5 224.3 285.0 303.5 307.4
Reserves, MMBOE 438.5 378.8 345.2 304.9 275.0
Reserves-to-Production Ratio (Reserves/Annual Production) 12.8 12.6 13.9 12.9 13.6
Average Wellhead Oil Price per Bbl in Reserve Report $ 90.80 $ 87.15 $ 89.18 $ 73.14 $ 54.84
Average Wellhead NGLs Price per Bbl in Reserve Report $ 54.38 $ 58.15 $ 62.93 $ 49.35 $ 35.44
Average Wellhead Gas Price per Mcf in Reserve Report $ 4.30 $ 3.21 $ 4.39 $ 4.72 $ 3.77
Reserves & Production per Region as of December 31, 2013
438.5 MMBOE Q4 2013— 101.0 MBOE/d
3%
29%
4%
12%
68%
84%
(cid:31) ROCKY MOUNTAINS (cid:31) PERMIAN BASIN (cid:31) OTHER
The following is a summary of Whiting’s changes in quantities of proved oil and gas reserves for the year ended
December 31, 2013:
Natural
Oil NGLs Gas Total
(MBbl) (MBbl) (MMcf) (MBOE)
Balance – December 31, 2012 301,285 40,098 224,264 378,760
Extensions and discoveries 88,293 9,830 63,893 108,772
Sales of minerals in place (36,992) (4,777) (12,411) (43,838)
Purchase of minerals in place 14,543 1,311 7,751 17,146
Production (27,035) (2,821) (26,917) (34,342)
Revisions to previous estimates 7,327 1,228 20,934 12,044
Balance – December 31, 2013 347,421 44,869 277,514 438,542
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DEAR FELLOW
SHAREHOLDERS
CEO, Jim Volker, discusses our
plans at our Redtail Niobrara
Field in northeastern Colorado
with employees and investors.
2013 MARKED OUR 10TH YEAR as a public company.
Upon the completion of our IPO in November 2003,
our market capitalization was under $300 million,
we had 110 full-time employees and our production
averaged 17,000 BOE/d (42% liquids). We exited 2013
with market capitalization of more than $7 billion, we
had nearly 1,000 full-time employees and our produc-
tion was over 100,000 BOE/d (87% liquids). Entering
our second decade, we are a leading operator in two
of the hottest plays in North America, the Bakken in
North Dakota and Montana and the Niobrara in
northeastern Colorado. These plays set the stage for
another 10 years of growth.
2013 was a record year for Whiting. We posted
records in production, proved reserves and discre-
tionary cash flow during 2013. Discretionary cash
flow increased 20% and, adjusting for the Postle sale,
proved reserves and production increased 21% and
31%, respectively. We believe the following factors
will lead to a strong year in 2014 for Whiting and
our shareholders:
● A solid cash flow outlook and a strong balance sheet;
● Rapid development underway at our Redtail Niobrara
prospect with over 3,300 potential drilling loca-
tions, three rigs running now and a fourth scheduled
for August;
● Full-scale implementation of our new completion
design in the Williston Basin where early results
indicate productivity increases of 30% to 100%;
● Additional higher density drilling at Sanish, Prong-
horn and Hidden Bench; and
● Optimization programs that should lead to efficient,
low-cost drilling and completion operations.
We expect a very good year for organic growth in
reserves and production in 2014. Our 2014 capital
budget of $2.7 billion is expected to yield year-over-
year production growth in the 17% to 19% range. We
have 328 gross (249.4 net) operated wells planned for
2014 and have substantially added to our drilling in-
ventory through new discoveries and an active leasing
program. In the Bakken and Three Forks hydrocarbon
system in the Williston Basin alone, we hold more
than 715,000 net acres and continue to add to that
position. We are in rapid development mode at our
Redtail Niobrara prospect in Weld County, Colorado,
where we hold approximately 120,000 net acres and
estimate we have more than 3,300 future gross loca-
tions. We believe that our Redtail field is a “Whiting
within a Whiting”.
We will continue to focus on oil and natural gas
liquids in the foreseeable future. Currently, crude oil
trades at nearly 20 times the price of natural gas,
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which compares to their 6 to 1 heating equivalency
ratio. At year-end 2013, 79% of our proved reserves
and 79% of our production consisted of crude oil.
We expect that percentage to continue to increase
over the next several years. In the September 2, 2013
edition of the Oil & Gas Journal, we ranked 18th
in the world in terms of liquids proved reserves and
15th in the world in terms of liquids production for
public companies.
We are a technology focused oil company. We are
providing our staff with the best tools available to
enable their continued success, including our in-house
core lab. This technology focus is leading to increased
productivity and a larger drilling inventory. Our new
completion design using cemented liners and plug-and-
perf technology is working throughout the Williston
Basin. Initial results from our higher density drilling
programs across our Bakken acreage base have been
encouraging.
All of us at Whiting are enthusiastic about our
prospects for growing long-term shareholder value.
On behalf of the Whiting Petroleum Corporation
Board of Directors and all of our dedicated employees,
thank you very much for your continuing interest in
Whiting Petroleum Corporation.
Sincerely,
JAMES J. VOLKER
Chairman of the Board and Chief Executive Officer
February 27, 2014
(RIGHT) The Obrigewitch 41-17PH
(IP: 2,292 BOE/d) and the 3J Trust
44-8PH (IP: 2,696 BOE/d) at our
Pronghorn Field in Stark County,
North Dakota.
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DRILLING
AND
OPERATIONS
OVERVIEW
PRODUCTION
Production in 2013 totaled a record 34.34 MMBOE
or 94,090 BOE/d. This represents a 14% increase over
total production of 30.21 MMBOE or 82,540 BOE/d
in 2012. Excluding the production associated with
the Postle/Northeast Hardesty sale, our production in
2013 was up 21% over 2012.
PROVED RESERVES
As of December 31, 2013, Whiting had estimated
proved reserves of 438.5 MMBOE, of which 58% were
classified as proved developed. These estimated proved
reserves had a pre-tax PV10% value of $8,994.0 million,
using SEC NYMEX prices of $96.78 per barrel of oil
and $3.67 per Mcf of gas. This represents an increase
of 23% over the December 31, 2012 value of $7,283.9
million, which used SEC NYMEX prices of $94.71 per
barrel of oil and $2.76 per Mcf of gas.
108.8 MMBOE of proved reserves were added through
exploration and development activities. This repre-
sents a 33% increase over the 81.5 MMBOE of proved
reserves that were added from exploration and devel-
opment in 2012. During 2013, we replaced 402% of
the Company’s 2013 production of 34.3 MMBOE.
Most of the proved reserve additions during 2013
came from our Redtail Niobrara prospect in northeast-
ern Colorado. We booked an estimated 65.9 MMBOE of
new Niobrara proved reserves, bringing our total proved
reserves at Redtail to 79.8 MMBOE at year-end 2013.
PROBABLE AND POSSIBLE RESERVES
At year-end 2013, our probable reserves were
estimated to be 176.2 MMBOE and our possible
reserves were estimated to be 189.1 MMBOE, for a
total of 365.3 MMBOE. The year-end 2013 estimated
pre-tax PV10% for our probable and possible reserves
was $3,619.3 million.
Whiting’s proved reserves of 438.5 MMBOE rep-
resented a 16% increase over the 378.8 MMBOE
of proved reserves at year-end 2012. Excluding the
reserves associated with the Postle/Northeast Hardesty
sale, our proved reserves were up 31%. An estimated
As with our proved reserves, 100% of Whiting’s
probable and possible reserve estimates were independ-
ently engineered by Cawley, Gillespie & Associates, Inc.
Please refer to “Reserve and Resource Information” on
the inside front cover of this annual report.
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POTENTIAL FUTURE
DRILLING LOCATIONS
Our 2013 drilling program sets the table for what
we believe will be a strong year for production and
reserves growth in 2014. Based on independent engi-
neering and internal estimates, Whiting projects it has
a total of 14,230 gross (7,478.7 net) potential future
drilling locations as of year-end 2013, increases of
47% and 66%, respectively, over our 2012 gross and
net totals. Of this total, 10,643 gross (4,563.2 net)
locations are identified as primary locations, which
have been validated by drilling results. This represents
a 41% increase in gross primary total locations and
26% increase in net primary total locations relative to
year-end 2012.
In our core Northern Rockies area, our gross and
net estimated primary well counts were 4,331 and
1,665.3, increases of 39% and 33%, respectively, over
year-end 2012. In our core Central Rockies area, our
gross and net estimated primary well counts were
5,226 and 2,373.6, increases of 55% and 27%, respec-
tively, over year-end 2012.
2014 CAPITAL BUDGET
Our 2014 capital budget is $2.7 billion, which we
expect to fund substantially with net cash provided by
our operating activities, cash on hand and nominal
borrowings under our credit facility. Whiting expects
to invest $2,433 million of the 2014 capital budget in
exploration and development activity, $116 million
for land and $151 million for facilities. Based on this
level of capital spending, we forecast production of
40.2 MMBOE –40.8 MMBOE for 2014, an increase of
17% –19% over our 2013 production of 34.34 MMBOE.
Within our $2.7 billion budget we also plan to
invest $575 million for the drilling and completion of
120 gross (104.9 net) wells at our Redtail Niobrara
prospect in northeastern Colorado. We have initiated
pad drilling at our Redtail field and expect to drill eight
wells off of each pad. We currently estimate that we
can save approximately $500,000 per well in mobi-
lization costs and efficiencies utilizing pad drilling.
(OPPOSITE) Pumping units at our Pronghorn
Field in Stark County, North Dakota.
(LEFT) In the foreground is the Smith 11-7H
(IP: 2,421 BOE/d) in our Sanish Field in
Mountrail County, North Dakota. The rig
in the background is drilling our Carl
Kannianen 13-7XH.
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EXPLORATION
AND
DEVELOPMENT
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WILLISTON BASIN
We generated record production of 100,965 BOE/d
in the fourth quarter of 2013, of which 73% 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. Outside of our Sanish field, we have
assembled lease positions on seven separate fields in
the Williston Basin that target the Bakken, Three
Forks and Pronghorn Sand formations. Our focus in
2013 was on the development of the fields we discov-
ered in 2011, such as our Pronghorn, Hidden Bench,
Tarpon and Missouri Breaks fields.
In 2013, we experienced significant productivity
increases as we moved into development drilling
mode in new fields in the Southern and Western
Williston Basin. We are using our new completion
design with cemented liners and plug-and-perf tech-
nology to enhance productivity throughout the
Williston Basin. Initial results from our higher density
drilling programs across our Bakken acreage base have
been positive.
(OPPOSITE) In the foreground is the
Smith 11-7H (IP: 3,752 BOE/d).
The rig in the background is
drilling our Nesheim 13-24H.
(RIGHT) Roughnecks drilling the KG
Ranch 21-21 well at our Big Island
Field in Golden Valley, North Dakota.
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10
WESTERN WILLISTON BASIN
The Western Williston Basin includes our Hidden
Bench, Tarpon, Missouri Breaks and Cassandra fields.
These areas represent a total of 204,198 gross (121,909
net) acres. Production from the Western Williston Basin
averaged 17,790 BOE/d in the fourth quarter of 2013,
a 30% increase over the 13,710 BOE/d average rate in
the third quarter of 2013.
Hidden Bench Field. We experienced favorable
results from our new completion design and tested
higher density drilling at the Mork Trust Unit, 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 on November 30,
2013 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 use our new
completion design and had initial production rates
that were an average of 53% better than the wells
completed with our previous completion design.
Missouri Breaks Field. We hold 98,601 gross
(64,277 net) acres in the Missouri Breaks field, located
in Richland County, Montana and McKenzie County,
North Dakota. We have experienced very good results
with our new completion design in the Missouri
Breaks area. We have 13 wells completed using our
new cemented liner completion method that have
more than 90 days of production history. For these
wells, 30-day, 60-day and 90-day average rates have
been 64%, 53% and 52%, respectively, greater than
the average rates for the 31 wells completed with our
old sliding sleeve technology in the Missouri Breaks
area in 2013.
(LEFT) Drilling operations on our
Nesheim 13-24H in the Sanish Field in
Mountrail County, North Dakota.
(OPPOSITE) The Savannah TTT 41-26H on
the left and the Brittany TTT 13-26TFH on
the right were drilled off of a three-well
pad in our Sanish Field in Mountrail
County, North Dakota.
fp_AR Pgs 1-20 3/11/14 3:10 PM Page 11
BAKKEN TEAM (L to R) Jessica Benson, Landman II, Mark Williams, Senior Vice President – Exploration
and Development, Orion Skinner, Senior Explorationist, Brent Miller, Operations Manager – Northern Rockies,
Monte Madsen, Completions Engineering Technician, and Tom Siirola, Regional Land Manager.
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SOUTHERN WILLISTON BASIN
The Southern Williston Basin encompasses our
Lewis & Clark/Pronghorn fields, which encompass a
total of 392,483 gross (263,376 net) acres. Fourth
quarter 2013 production from this region averaged
15,065 BOE/d. This daily rate represents a significant
increase over the rate in the third quarter of 2013.
Pronghorn Field. We continue to generate favor-
able results from our new completion technique at our
Pronghorn field, which is located primarily in Stark
and Billings counties, North Dakota. The Obrigewitch
21-29PH produced 50.8 MBOE during its first 60 days
of production ending on November 11, 2013. The
well, which was completed in the Pronghorn Sand
using a cemented liner and plug-and-perf technology,
was fraced in 40 stages with three entry points per
stage. The production rate is a 10 MBOE improvement
in the 60 day production over the offsetting well, the
Obrigewitch 41-29PH, which produced 40.0 MBOE
during its first 60 days of production ending on
November 8, 2013.
(RIGHT) Using our new completion
design, the Obrigewitch 21-29PH
(IP: 2,432 BOE/d) in our Pronghorn
Field in Stark County, North Dakota
produced 10 MBOE more during its
first 60 days of production than an
offsetting well.
(OPPOSITE) We have employed pad
drilling at our Pronghorn Field in
Stark County, North Dakota, typically
drilling three wells off of one pad.
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13
In the second quarter of 2014, we plan to drill a
960-acre spacing unit on a 32-well pattern. If success-
ful, our potential drilling locations would increase to
more than 6,600 gross wells. Our 30F pad, located
in our Horsetail area, will test the Niobrara “A”, “B”
and “C” zones. Together these three zones have an
estimated 70 MMBOE of original oil in place.
Typifying the production performance of a Redtail
Niobrara well is the Horsetail 18-0713H. This well was
completed on August 23, 2013. The Horsetail well
posted a 30-day average rate of 452 BOE/d, a 60-day
average rate of 458 BOE/d and a 90-day average rate
of 531 BOE/d. This well’s estimated ultimate recovery
is calculated to be approximately 570 MBOE gross.
It was drilled on a 960-acre spacing unit and utilized
a large fracture stimulation and plug-and-perf
completion technology.
fp_AR Pgs 1-20 3/11/14 3:11 PM Page 14
OTHER DEVELOPMENT AREAS
Sanish Field Area. Whiting’s net production from
the Sanish field area, which includes our 21% working
interest in the Parshall field, averaged 40,370 BOE/d
in the fourth quarter of 2013, an increase of 10% over
the third quarter 2013 average of 36,840 BOE/d.
Whiting continues to generate strong results from the
field. Highlighting recent results were the completion
of two higher density wells. These wells were infill
wells testing an eight well per spacing unit pattern in
the Middle Bakken formation. The Uran 43-17H was
completed in the Middle Bakken on January 17, 2014
flowing 1,451 BOE/d, while the Uran 43-17-2H was
completed in the Middle Bakken on January 19, 2014
flowing 1,252 BOE/d. These rates compare favorably
with the original wells that tested 955 BOE/d and 623
BOE/d on May 27, 2012 and October 25, 2011, respec-
tively. Both infill wells were completed with our new
completion design that consisted of 40 stages and
three entry points per stage versus the original two
wells that were completed with 25 to 30 stages and
only one entry point per stage.
Denver Basin: Redtail Niobrara Field. We hold a
total of 169,677 gross (122,278 net) acres in our Redtail
field, located in the Denver Julesberg Basin in Weld
County, Colorado, where we have the potential to
drill 3,310 gross (1,653.8 net) wells based on a 16-well
per drilling spacing unit pattern. Whiting estimates
the total resource potential for Redtail to be 492.4
MMBOE net to Whiting. As of February 1, 2014, net
production from the Redtail field was running at
approximately 5,100 BOE/d, up 58% from its fourth
quarter 2013 average of 3,230 BOE/d.
We recently completed drilling operations on two
four-well pads. Our 27L pad is targeting the Niobrara
“B” zone while our 27K pad is testing both the
Niobrara “B” and “A” zones. Both pads are located in
our Razor area and are testing a 16-well per 960-acre
drilling spacing unit pattern. Initial results from both
pads are encouraging with early results from both “B”
and “A” zone wells tracking our typical 400 MBOE
type curve.
(RIGHT) Drilling operations
on the Razor 27I-2214B well
at our Redtail Field in Weld
County, Colorado.
(OPPOSITE) Tank batteries at
the Razor 22-2712H well in
our Redtail Field.
14
fp_AR Pgs 1-20 3/11/14 3:11 PM Page 15
REDTAIL TEAM (L to R) John Forster, Regional Geologic Manager, Mike Stahl, Operations Manager,
Rick Ross, Vice President – Operations, Jack Breig, Chief Petrophysicist, Mark Odegard, Senior Geologist,
Scott McDaniel, Regional Land Manager, and Tom Smith, Business Development Manager.
15
fp_AR Pgs 1-20 3/11/14 3:11 PM Page 16
EOR PROJECTS
North Ward Estes Field. Net production from our
North Ward Estes field averaged 9,755 BOE/d in the
fourth quarter of 2013, up 2% over the third quarter
2013 rate of 9,610 BOE/d. One of the largest phases at
North Ward Estes (Phase 5) is pressuring up with CO2,
and we are beginning to see a production response.
Whiting is currently injecting approximately 397
MMcf/d of CO2 into the field, of which about 68% is
recycled gas.
Postle/Northeast Hardesty Fields. This past
summer, Whiting closed on a successful $809.7 mil-
lion divestment package, which included the CO2
EOR projects in the Postle and Northeast Hardesty
fields. From the mid-summer closing through October
2013, the Postle Asset Team was responsible for both
the operations of the asset and the smooth transition
of operations to the buyer.
(RIGHT) CO2 Recovery
and Re-injection Plant
at our North Ward
Estes Field EOR Project
in Ward and Winkler
counties, Texas.
(OPPOSITE) Nitrogen
Rejection Unit at our
North Ward Estes Field.
16
fp_AR Pgs 1-20 3/11/14 3:11 PM Page 17
POSTLE TEAM (L to R) Ryan Vera, Operations Engineer, Shane McNeeley, Operations Engineer,
Cindi Goodman, Engineering Technician, Kera Thompson, Reservoir Engineer, Mike Raines, Geoscientist,
Bob Boomer, Senior Reservoir Engineer, and Robert McNaughton, Senior Operations Engineer.
17
fp_AR Pgs 1-20 3/11/14 3:11 PM Page 18
COMMITTED TO SAFETY AND
THE ENVIRONMENT
To reduce Whiting’s carbon footprint Whiting’s
management continuously seeks opportunities to
improve efficiency and reduce emissions from its
operations. Whiting is implementing new and ongoing
measures to prevent and minimize the environmental
impact of its operations. These include a significant
investment in natural gas gathering and processing
infrastructure and infrared monitoring systems to
eliminate or reduce natural gas emissions, EOR proj-
ects that recycle and sequester carbon dioxide, and
projects to monitor and reduce nitrogen oxides, sulfur
oxides and greenhouse gas emissions. More specifi-
cally, these initiatives include the following measures.
Whiting strives to maximize natural resource recov-
ery and minimize natural resource waste. It is Whiting’s
policy to market natural gas resources wherever feasible.
By maximizing its marketing of natural gas, Whiting
reduces potential greenhouse gas emissions.
Where Whiting is unable to market its natural gas
resources, it seeks to utilize control devices to minimize
the impact of natural gas emissions to the environ-
ment. For example, Whiting captures and combusts
tank and other process vapors at many of its facilities,
resulting in fewer greenhouse gas emissions. In addi-
tion, internal combustion engines used meet or exceed
the state and federal emission standards for volatile
organic compounds and nitrous oxides, which in turn
results in reduced greenhouse gas emissions.
Ahead of the recently promulgated Oil and
Gas Production New Source Performance Standards
regulations, Whiting enacted a reduced emissions
completions policy whereby all drilling and workover
operations utilize techniques aimed at reducing
venting and flaring of greenhouse gases where feasible.
The use of these techniques has reduced Whiting’s
carbon footprint and natural gas flaring.
Whiting also enacted a policy whereby whenever
possible all newly installed natural gas-driven pneu-
matic devices must be low-emitting. Whiting believes
such a policy reduces its carbon footprint
On its own initiative, Whiting routinely inspects
many of its facilities with a FLIR (infrared) thermal
imaging camera to identify and repair gas leaks. This
successful program has resulted in a reduced carbon
footprint and increased gas sales.
In addition to these FLIR inspections, Whiting
personnel routinely inspect facilities in an effort
EH&S TEAM (L to R) Tom Fisk, Director – Environmental, Health and Safety,
Justin Clock, Health and Safety Coordinator II, Jeff Brown, Health and Safety Manager,
Jeremy Jones, Health and Safety Coordinator I, Rafe Espinoza, Environmental Coordinator III,
and Jagadeesan Sethuraman, Environmental Manager.
18
fp_AR Pgs 1-20 3/12/14 4:15 PM Page 19
to identify potential emission sources. Through
inspection, Whiting identifies and repairs equipment
leaks to ensure efficient use of natural gas resources,
resulting in reduced greenhouse gas emissions.
BUILDING FOR THE FUTURE
At Whiting we believe that being a successful
company is a reflection of the quality, professionalism,
talent and solid experience of our employees. Our
goal is to hire the best people for the right jobs and
to reward competitively for their achievements. Our
professionals are a uniquely capable and creative
group of people. We are focused first on the success of
the Company but also on the impact of what we do
on the communities and environments in which we
work. This level of attentiveness and the integrity
shown by our employees truly represent the excellence
of our workforce and ultimately support the great suc-
cesses of Whiting Petroleum.
Whiting proactively advocates Equal Employment
Opportunities for all. We have an attractive array of
benefits, a uniquely competitive compensation pro-
gram and multiple opportunities for advancement for
our top performers. Our employee programs inten-
tionally focus on rewarding our employees for their
efforts towards the Company’s success. Our benefit
plans provide high quality and competitive services,
and our compensation program is unique in pro-
viding both short and long-term incentives for all
Whiting employees.
Our employee retention is extremely high at
Whiting. We have a superb work environment, and
the longevity of our professionals’ tenure shows that.
Additionally, our turnover rate historically has been
significantly less than industry averages. We are very
proud that so many quality individuals have chosen
to join and stay with Whiting to support its success.
Here at Whiting, our workforce consistently
performs at an exceptional level. Their performance
supports the growth and success of Whiting Petroleum;
whether we’re growing through the drill bit or by
acquisition. The exceptional abilities of our high
quality people, combined with the remarkable oppor-
tunities available to our company right now, have
created a recipe for success, and it’s a recipe that
continues to build value for our shareholders.
HUMAN RESOURCES TEAM (L to R) Annie Thomas, HR Manager – Southern Region,
Robin Finneseth, Regional HR Lead – Robinson Lake, Heather Duncan, Vice President – Human Resources,
Rachel Hunley, Human Resources Representative, Tricia Hewitt, Human Resources Director – Corporate Services,
Marge Ybarra, Benefits Administrator, and Tim Kastle, HR Manager – Northern Region and Recruiting.
19
fp_AR Pgs 1-20 3/11/14 3:11 PM Page 20
B OARD OF D IREC TORS
JAMES J. VOLKER, 67, is Chairman of
the Board and Chief Executive Officer of
Whiting Petroleum Corporation. Mr. Volker
has been a director of Whiting Petroleum
Corporation since 2003 and a director of
Whiting Oil and Gas Corporation since
2002. He joined Whiting Oil and Gas
Corporation in August 1983 as Vice Pres-
ident of Corporate Development and
served in that position through April 1993.
In May 1993, he became a contract con-
sultant to Whiting Oil and Gas Corporation and served in that
capacity until August 2000, at which time he became Executive
Vice President and Chief Operating Officer. Mr. Volker was
appointed President and Chief Executive Officer and a director
of Whiting Oil and Gas Corporation in January 2002. Mr. Volker
retained his position of Chief Executive Officer when Mr. James
T. Brown was appointed President and Chief Operating Officer
effective January 1, 2011. Mr. Volker was co-founder, Vice Pres-
ident and later President of Energy Management Corporation
from 1971 through 1982. He has over 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, 65, has been a
director of Whiting Petroleum Corporation
since 2003. Mr. Aller, who serves as Senior
Vice President of Operations Support
for Alliant Energy Corporation effective
January 13, 2013, has served as Senior
Vice President —Energy Resource Develop-
ment of Alliant Energy Corporation since
January 2009 and President of Interstate
Power and Light Company since 2004. Prior
to that, he served as President of Alliant
Energy Investments, Inc. since 1998 and interim Executive Vice
President —Energy Delivery of Alliant Energy Corporation since
2003 and Senior Vice President — Energy Delivery of Alliant Energy
Corporation since 2004. From 1993 to 1998, he served as Vice
President of IES Investments. He received his Bachelor’s Degree
in political science from Creighton University and his Master’s
Degree in municipal administration from the University of Iowa.
D. SHERWIN ARTUS, 76, has been a
director of Whiting Petroleum Corporation
since 2006. Mr. Artus joined Whiting Oil
and Gas Corporation in January 1989 as
Vice President of Operations and became
Executive Vice President and Chief Operat-
ing Officer in July 1999. In January 2000,
he was appointed President and Chief
Executive Officer. Mr. Artus became Senior
Vice President in January 2002 and retired
from the Company on April 1, 2006. Prior
to joining Whiting, he was employed by Shell Oil Company in
various engineering research and management positions. From
1974-1977, he was employed by Wainoco Oil and Gas Company
as Production Manager. He was a co-founder and later became
President of Solar Petroleum Corporation, an independent oil
and gas producing company. He has over 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
Engineering from the South Dakota School of Mines and Tech-
nology. He is a registered Professional Engineer in Colorado,
Wyoming, Montana and North Dakota. Mr. Artus is a member,
and a past officer, of the Society of Professional Well Log Analysts
and is a member of the Society of Petroleum Engineers.
20
PHILIP E. DOTY, 70, has been a director
of Whiting Petroleum Corporation since
2010 and is chairman of the Audit
Committee. Mr. Doty is a certified public
accountant. Since 2007, Mr. Doty has
been counsel to Ehrhardt Keefe Steiner &
Hottman PC, the largest Colorado-based
accounting and consulting firm, where he
previously was a partner from 2002 to
2007. From 1967 to 2000 he worked at
Arthur Andersen and Co., where he was a
partner since 1978 and served as the audit partner and head of
the Denver office oil and gas practice until his retirement in
2000. He is a graduate of Drake University with a Bachelor’s
degree in accounting.
WILLIAM N. HAHNE, 62, has been a
director since 2007 and is chairman of the
Nominating and Governance Committee.
Mr. Hahne was Chief Operating Officer
of Petrohawk Energy Corporation from
July 2006 until October 2007. Mr. Hahne
served at KCS Energy, Inc. as President,
Chief Operating Officer and Director from
April 2003 to July 2006, as Executive Vice
President and Chief Operating Officer
from March 2002 to April 2003 and in
other management positions prior to that. He is a graduate of
Oklahoma University with a BS in petroleum engineering and
has 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, 76, 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
company. His previous affiliations include
Jade Drilling Company, Belleview Capital
Corporation, Mesa Petroleum Company
and Amoco Production Company. Mr. Larson earned a PhD in
Geology at the University of California, Los Angeles. He earned
his M.S. in Geology from UCLA and his BS degree in Geology at
Pennsylvania State University. He is a member of the American
Association of Petroleum Geologists, the Rocky Mountain Asso-
ciation of Geologists, the Wyoming Geological Association, the
Montana Geologic Society and the Utah Geologic Association.
MICHAEL B. WALEN, 65, 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 management and explo-
ration 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
[X]
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
For the fiscal year ended December 31, 2013
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 (cid:2) No (cid:3)
Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities
Act. Yes (cid:3) No (cid:2)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes (cid:2) No (cid:3)
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post
such files).
Yes (cid:2)
No
(cid:3)
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated
by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
(cid:3)
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a
smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting
company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer (cid:2) Accelerated filer (cid:3) Non-accelerated filer (cid:3)
Smaller reporting company (cid:3)
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes (cid:3)
No (cid:2)
Aggregate market value of the voting common stock held by non-affiliates of the registrant at June 30, 2013:
$5,481,981,242.
Number of shares of the registrant’s common stock outstanding at February 14, 2014: 118,956,489 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the 2014 Annual Meeting of Stockholders are incorporated by reference into Part III.
TABLE OF CONTENTS
Glossary of Certain Definitions ..................................................................................... 1
PART I
Business ....................................................................................................................................... 6
Item 1.
Item 1A. Risk Factors ................................................................................................................................. 20
Item 1B. Unresolved Staff Comments ........................................................................................................ 34
Properties ..................................................................................................................................... 35
Item 2.
Legal Proceedings ........................................................................................................................ 44
Item 3.
Mine Safety Disclosures .............................................................................................................. 44
Item 4.
Executive Officers of the Registrant ............................................................................................ 45
PART II
Item 5.
Item 6.
Item 7.
Market for the Registrant’s Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities .......................................................................................... 47
Selected Financial Data ............................................................................................................... 49
Management’s Discussion and Analysis of Financial Condition and Results of
Operations .................................................................................................................................... 51
Item 7A. Quantitative and Qualitative Disclosures About Market Risk ..................................................... 71
Financial Statements and Supplementary Data............................................................................ 74
Item 8.
Changes in and Disagreements with Accountants on Accounting and Financial
Item 9.
Disclosure .................................................................................................................................... 115
Item 9A. Controls and Procedures .............................................................................................................. 115
Item 9B. Other Information ........................................................................................................................ 117
PART III
Item 10. Directors, Executive Officers and Corporate Governance ........................................................... 117
Executive Compensation ............................................................................................................. 117
Item 11.
Security Ownership of Certain Beneficial Owners and Management and Related
Item 12.
Stockholder Matters ..................................................................................................................... 117
Item 13. Certain Relationships, Related Transactions and Director Independence ................................... 118
Principal Accounting Fees and Services ...................................................................................... 118
Item 14.
Item 15.
Exhibits, Financial Statement Schedules ..................................................................................... 118
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.
“differential” The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil spot,
and the wellhead price received.
“deterministic method” The method of estimating reserves or resources using a single value for each parameter
(from the geoscience, engineering or economic data) in the reserves calculation.
“development well” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a
stratigraphic horizon known to be productive.
“exploratory well” A well drilled to find a new field or to find a new reservoir in a field previously found to be
productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a
development well, an extension well, a service well or a stratigraphic test well.
“extension well” A well drilled to extend the limits of a known reservoir.
“FASB” Financial Accounting Standards Board.
“FASB ASC” The Financial Accounting Standards Board Accounting Standards Codification.
“field” An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same
individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a
field that are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or both.
Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common
operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify
1
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 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 perforations
in 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 many states require plugging of
abandoned wells.
2
“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 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.
“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
3
undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain
of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of
economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves
only if a development plan has been adopted indicating that they are schedule to be drilled within five years, unless
specific circumstances justify a longer time. Under no circumstances shall estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid injection or other improved recovery
technique is contemplated, unless such techniques have been proved effective by actual projects in the same
reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable
certainty.
“PUD” Proved undeveloped reserves.
“reasonable certainty” If deterministic methods are used, reasonable certainty means a high degree of confidence
that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent
probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence
exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of
geoscience (geological, geophysical and geochemical) engineering, and economic data are made to estimated
ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or
remain constant than to decrease.
“recompletion” An operation whereby a completion in one zone is abandoned in order to attempt a completion in a
different zone within the existing wellbore.
“reserves” Estimated remaining quantities of oil and gas and related substances anticipated to be economically
producible, as of a given date, by application of development projects to known accumulations. In addition, there
must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue
interest in the production, installed means of delivering oil and gas or related substances to market, and all permits
and financing required to implement the project.
“reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude
oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from
other reservoirs.
“resource play” Refers to drilling programs targeted at regionally distributed oil or natural gas accumulations.
Successful exploitation of these reservoirs is dependent upon new technologies such as horizontal drilling and
multi-stage fracture stimulation to access large rock volumes in order to produce economic quantities of oil or
natural gas.
“royalty” The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross
income from crude oil or natural gas produced and sold, unencumbered by expenses relating to the drilling,
completing or operating of the affected well.
“royalty interest” An interest in an oil or natural gas property entitling the owner to shares of the crude oil or
natural gas production free of costs of exploration, development and production operations.
“SEC” The United States Securities and Exchange Commission.
“service well” A service well is a well drilled or completed for the purpose of supporting production in an existing
field. Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane
or flue gas), water injection, steam injection, air injection, salt-water disposal, water supply for injection,
observation or injection for in-situ combustion.
“standardized measure of discounted future net cash flows” The discounted future net cash flows relating to proved
reserves based on the average price during the 12-month period before the ending date of the period covered by the
4
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.
5
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 and exploration activities. As of December 31, 2013, our estimated proved reserves
totaled 438.5 MMBOE, representing a 16% increase in our proved reserves since December 31, 2012. Our 2013
average daily production was 94.1 MBOE/d and results in an average reserve life of approximately 12.8 years.
The following table summarizes by core area, our estimated proved reserves as of December 31, 2013, their
corresponding pre-tax PV10% values, and our fourth quarter 2013 average daily production rates, as well as our
company’s total standardized measure of discounted future net cash flows as of December 31, 2013:
Proved Reserves (1)
Oil
(MMBbl)
236.6
106.4
4.4
347.4
NGLs
(MMBbl)
25.7
17.8
1.4
44.9
Natural
Gas
(Bcf)
208.8
17.6
51.1
277.5
Total
(MMBOE)
297.0
127.1
14.4
438.5
%
Oil
80%
84%
31%
79%
4th Quarter 2013
Average Daily
Production
(MBOE/d)
84.7
12.3
4.0
101.0
Pre-Tax
PV10%
Value (2)
(in millions)
$ 7,309.7
1,524.6
159.7
$ 8,994.0
(2,400.1)
Core Area
Rocky Mountains ............
Permian Basin .................
Other (3) ...........................
Total.......................
Discounted Future
Income Taxes ...............
Standardized Measure
of Discounted Future
Net Cash Flows ............
_____________________
(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,
2013, pursuant to current SEC and FASB guidelines.
$ 6,593.9
(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) Other primarily includes oil and gas properties in Arkansas, Louisiana, 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. We believe that our significant drilling inventory, combined with our operating experience
and cost structure, provides us with meaningful organic growth opportunities.
6
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.
•
During 2013, we incurred $2,896.1 million in exploration, development and cash acquisition capital expenditures,
including $2,398.4 million for the drilling of 428 gross (229.2 net) wells. Of these new wells, 220.7 (net) resulted
in productive completions and 8.5 (net) were unsuccessful, yielding a 96% success rate.
Our current 2014 E&D budget is $2.7 billion, and included in this amount is approximately $116.0 million in
acreage acquisition costs. The 2014 budget of $2.7 billion represents a slight increase from the $2,675.2 million in
E&D (which consisted of exploration, development and acreage expenditures) we incurred in 2013. We expect to
fund substantially all of our 2014 E&D budget using net cash provided by operating activities, cash on hand and
borrowings under our credit facility.
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
The following is a summary of our acquisitions and divestitures during the last two years. See “Management’s
Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Annual Report on
Form 10-K for more information on these acquisitions and divestitures.
2013 Acquisitions. On September 20, 2013, we completed the acquisition of approximately 39,300 gross (17,300
net) acres, including interests in 121 producing oil and gas wells and undeveloped acreage, in the Williston Basin in
Williams and McKenzie counties of North Dakota and Roosevelt and Richland counties of Montana for an
aggregate unadjusted purchase price of $260.0 million.
2013 Divestitures. On October 31, 2013, we completed the sale of approximately 45,000 gross (32,200 net) acres,
including our interests in certain producing oil and gas wells and undeveloped acreage, in our Big Tex prospect
located in the Delaware Basin for a cash purchase price of $152.0 million (subject to post-closing adjustments),
resulting in a pre-tax gain on sale of $13.0 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. The
producing properties had estimated proved reserves of 1.1 MMBOE as of December 31, 2012, 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
enhanced oil recovery 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 $809.7 million after selling costs and post-closing adjustments,
resulting in a pre-tax gain on sale of $109.7 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.
7
2012 Acquisitions. On March 22, 2012, we completed the acquisition of approximately 13,300 net undeveloped
acres in the Missouri Breaks field in Richland County, Montana for $33.3 million.
2012 Divestitures. On May 18, 2012, we sold a 50% ownership interest in our Belfield gas processing plant,
natural gas gathering system, oil gathering system and related facilities located in Stark County, North Dakota for
total cash proceeds of $66.2 million. We used the net proceeds from the sale to repay a portion of the debt
outstanding under our credit agreement.
On March 28, 2012, we completed an initial public offering of units of beneficial interest in Whiting USA Trust II
(“Trust II”), selling 18,400,000 Trust II units at $20.00 per unit, which generated net proceeds of $322.3 million
after underwriters’ fees, offering expenses and post-close adjustments. We used the net offering proceeds to repay
a portion of the debt outstanding under our credit agreement. The net proceeds from the sale of Trust II units to the
public resulted in a deferred gain on sale of $128.2 million. Immediately prior to the closing of the offering, we
conveyed a term net profits interest in certain of our oil and gas properties to Trust II in exchange for 100% of the
trust’s units issued, or 18,400,000 units.
The net profits interest entitles Trust II to receive 90% of the net proceeds from the sale of oil and natural gas
production from the underlying properties. The net profits interest will terminate on the later to occur of (1)
December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and
sold. This is the equivalent of 10.61 MMBOE in respect of Trust II’s right to receive 90% of the net proceeds from
such reserves pursuant to the net profits interest. The conveyance of the net profits interest to Trust II consisted
entirely of proved reserves of 10.61 MMBOE as of the January 1, 2012 effective date, representing 3% of our
proved reserves as of December 31, 2011 and 5% (or 4.5 MBOE/d) of our March 2012 average daily net
production.
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 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, 2013, we have assembled
approximately 1,147,500 gross (715,000 net) developed and undeveloped acres in the Williston Basin located in
Montana and North Dakota. As of December 31, 2013, we had 18 drilling rigs operating in the Williston Basin.
During 2013, the focus of our development in the Williston Basin continued in the Sanish, 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 90 MMcf/d, and we have projects underway to
increase this processing capability to 110 MMcf/d by mid-year 2014. Our Belfield Plant located near the
Pronghorn field has a processing capacity of 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.
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 1,000 gross wells targeting several intervals in the Niobrara
formation. As of December 31, 2013, we had approximately 169,700 gross (122,300 net) acres, with three drilling
rigs operating in this area. We are nearing the completion of a gas processing plant in Weld County, Colorado with
an initial processing capacity of 15 MMcf/d, which will process production from our Redtail field. We expect our
Redtail field will be another growth platform for Whiting in 2014 and beyond.
8
Developing Existing Properties. Our current property base, which includes our acquisitions over the past ten years,
provides us with numerous low-risk opportunities for exploration and development drilling. As of December 31,
2013, we have identified a drilling inventory of over 3,200 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 295 MMcf/d of recycled CO2,
thereby maximizing our recovery of oil and gas from this reservoir.
Growing Through Accretive Acquisitions. From 2004 to 2013, we completed 17 separate significant acquisitions of
producing properties for estimated proved reserves of 248.0 MMBOE, as of the effective dates of the acquisitions.
Our experienced team of management, land, engineering and geoscience professionals has developed and refined
an acquisition program designed to increase reserves and complement our existing properties, including identifying
and evaluating acquisition opportunities, closing purchases and then effectively managing properties we acquire.
We intend to selectively pursue the acquisition of properties complementary to our core operating areas.
Disciplined Financial Approach. Our goal is to remain financially strong, yet flexible, through the prudent
management of our balance sheet and active management of commodity price volatility. We have historically
funded our acquisitions and growth activity through a combination of equity and debt issuances, bank borrowings,
internally generated cash flow and certain oil and gas divestitures, as appropriate, to maintain our strong financial
position. From time to time, we monetize non-core properties and use the net proceeds from these asset sales to
repay debt under our credit agreement, 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 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, 2013, we had interests in 10,476 gross (3,922 net)
productive wells across approximately 1,387,200 gross (751,700 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 12.8 years based on year-end 2013
proved reserves and 2013 production.
Experienced Management Team. Our management team averages 28 years of experience in the oil and gas
industry. Our personnel have extensive experience in each of our core geographical areas and in all of our
operational disciplines. In addition, each of our acquisition professionals has at least 29 years of experience in the
evaluation, acquisition and operational assimilation of oil and gas properties.
Commitment to Technology. In each of our core operating areas, we have accumulated 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 12,100 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
9
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 25 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. In addition, it
has helped us to further understand unconventional oil plays, which has given us the confidence to assemble over
600,000 gross acres in three new oil resource plays, located in three separate basin areas that are new to us.
During 2013, we tested several different modifications to our completion techniques, including varying the number
of completion stages, utilizing different fracture stimulation fluids and increasing the volume of sand and ceramic
proppant used in these fluids. As we continued to refine our process, our well completions in several of our
development areas have evolved to utilize cemented liners and plug-and-perf technology to deliver improved
results. In 2014, we plan to utilize this technique on a majority of the wells we drill in the Williston Basin. We
have also tested this completion technique in the Niobrara formation in the DJ Basin of Colorado and the Delaware
Basin of West Texas with encouraging results. We continue to refine our completion techniques to deliver
improved results across all of our fields.
10
Proved, Probable and Possible Reserves
Our estimated proved, probable and possible reserves as of December 31, 2013 are summarized in the table below.
See “Reserves” in Item 2 of this Annual Report on Form 10-K for information relating to the uncertainties
surrounding these reserve categories.
Rocky Mountains:
PDP ................................
PDNP .............................
PUD ...............................
Total proved ..........
Total probable .......
Total possible .........
Permian Basin:
PDP ................................
PDNP .............................
PUD ...............................
Total proved ..........
Total probable .......
Total possible .........
Other (1):
PDP ................................
PDNP .............................
PUD ...............................
Total proved ..........
Total probable .......
Total possible .........
Total Company:
PDP ................................
PDNP .............................
PUD ...............................
Total proved ..........
Total probable .......
Total possible .........
Oil
(MMBbl)
128.5
0.5
107.6
236.6
90.8
59.0
NGLs
(MMBbl)
13.2
0.1
12.4
25.7
17.4
8.4
Natural
Gas
(Bcf)
122.1
1.2
85.5
208.8
215.3
136.2
Total
(MMBOE)
161.9
0.8
134.3
297.0
144.1
90.1
% of Total
Proved
55%
-%
45%
100%
49.6
15.3
41.5
106.4
15.9
76.9
3.6
0.7
0.1
4.4
2.6
1.3
181.7
16.5
149.2
347.4
109.3
137.2
5.9
3.5
8.4
17.8
4.3
16.1
0.8
0.3
0.3
1.4
0.6
0.1
19.9
3.9
21.1
44.9
22.3
24.6
11.8
2.8
3.0
17.6
34.6
2.8
38.7
6.6
5.8
51.1
17.7
24.8
172.6
10.6
94.3
277.5
267.6
163.8
57.4
19.3
50.4
127.1
26.0
93.4
11.0
2.1
1.3
14.4
6.1
5.6
230.3
22.2
186.0
438.5
176.2
189.1
45%
15%
40%
100%
76%
15%
9%
100%
53%
5%
42%
100%
Estimated
Future Capital
Expenditures
(in millions)
$
$
$
2,597.7
2,835.7
1,866.2
$
$
$
1,335.3
265.1
739.8
$
$
$
21.4
57.1
80.1
$
$
$
3,954.4
3,157.9
2,686.1
_____________________
(1) Other primarily includes oil and gas properties in Arkansas, Louisiana, 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 to storage facilities.
The table below presents percentages by purchaser that accounted for 10% or more of our total oil, NGL and
natural gas sales for the years ended December 31, 2013, 2012 and 2011. 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.
11
Plains Marketing LP ....................................................
Shell Trading US .........................................................
Eighty Eight Oil Company ..........................................
Bridger Trading LLC ..................................................
Title to Properties
2013
21%
14%
11%
8%
2012
20%
14%
11%
11%
2011
27%
13%
8%
6%
Our properties are subject to customary royalty interests, liens under indebtedness, liens incident to operating
agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. Our
credit agreement is also secured by a first lien on substantially all of our assets. We do not believe that any of these
burdens materially interfere with the use of our properties 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.
12
The FERC implemented The Outer Continental Shelf Lands Act pertaining to transportation and pipeline issues,
which requires that all pipelines operating on or across the outer continental shelf provide open access and non-
discriminatory transportation service. One of the FERC’s principal goals in carrying out this Act’s mandate is to
increase transparency in the market to provide producers and shippers on the outer continental shelf with greater
assurance of open access services on pipelines located on the outer continental shelf and non-discriminatory rates
and conditions of service on such pipelines.
We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in 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. 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
13
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.
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, only 0.1% of our total production volumes are produced from
offshore leases. However, the present value of our future abandonment obligations associated with offshore
properties was $32.8 million as of December 31, 2013. 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. Our competitors in the oil
and gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
14
Environmental Regulations
General. Our oil and gas exploration, development and production operations are subject to stringent federal, state
and local laws and regulations governing the discharge or release of materials into the environment or otherwise
relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection
Agency (the “EPA”) issue regulations to implement and enforce such laws, which often require difficult and costly
compliance measures that carry substantial administrative, civil and criminal penalties or that may result in
injunctive relief for failure to comply. These laws and regulations may require the acquisition of a permit before
drilling or facility construction commences; restrict the types, quantities and concentrations of various materials
that can be released into the environment in connection with drilling and production activities; limit or prohibit
project siting, construction or drilling activities on certain lands located within wilderness, wetlands, ecologically
sensitive and other protected areas; require remedial action to prevent pollution from former operations, such as
plugging abandoned wells or closing pits; and impose substantial liabilities for unauthorized pollution resulting
from our operations. The EPA and analogous state agencies may delay or refuse the issuance of required permits or
otherwise include onerous or limiting permit conditions that may have a significant adverse impact on our ability to
conduct operations. The regulatory burden on the oil and gas industry increases the cost of doing business and
consequently affects its profitability.
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and
costly material handling, storage, transport, disposal or cleanup requirements could materially and adversely affect
our operations and financial position, as well as those of the oil and gas industry in general. While we believe that
we are in compliance, in all material respects, with current applicable environmental laws and regulations and have
not experienced any material adverse effect from compliance with these environmental requirements, there is no
assurance that this trend will continue in the future.
The environmental laws and regulations which have the most significant impact on the oil and gas exploration and
production industry are as follows:
Superfund. The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
(“CERCLA” or “Superfund”), and comparable state laws impose strict joint and several liability, without regard to
fault or the legality of conduct, on classes of persons who are considered to be responsible for the release of a
“hazardous substance” into the environment. These persons include the owner or operator of the site where a
release occurred and anyone who disposed or arranged for the disposal of the hazardous substance released at the
site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment, for damages to natural resources and for the
costs of certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims
for personal injury and property damage allegedly caused by 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
15
substances disposed or released on them may be subject to CERCLA and analogous state laws. Under these laws,
we could be required:
• to remove or remediate previously disposed materials, including materials disposed or released by prior owners
or operators or other third parties;
• to clean up contaminated property, including contaminated groundwater;
• to perform remedial operations to prevent future contamination, including the plugging and abandonment of
wells drilled and left inactive by prior owners and operators; or
• to pay some or all of the costs of any such action.
At this time, we do not believe that we are a potentially responsible party with respect to any Superfund site and we
have not been notified of any claim, liability or damages under CERCLA.
Oil Pollution Act. The Oil Pollution Act of 1990 (“OPA”) and regulations issued under OPA impose strict, joint
and several liability on “responsible parties” for removal costs and damages resulting from oil spills into or upon
navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible
party” includes the owner or operator of an onshore facility and the lessee, permittee or holder of a right of use and
easement of the area in which an offshore facility is located. OPA establishes a liability limit for onshore facilities
of $350.0 million per spill, while the liability limit for offshore facilities is the payment of all removal costs plus
$75.0 million per spill damages. These limits do not apply if the spill is caused by a responsible party’s gross
negligence or willful misconduct; the spill resulted from a responsible party’s violation of a federal safety,
construction or operating regulation; a responsible party fails to report a spill or to cooperate fully in a cleanup; or a
responsible party fails to comply with an order issued under the authority of the Intervention on the High Seas Act.
OPA also requires the lessee or permittee of the offshore area in which a covered offshore facility is located to
establish and maintain evidence of financial responsibility in the amount of $35.0 million to cover liabilities related
to an oil spill for which such responsible party is statutorily responsible. The President may increase the amount of
financial responsibility required under OPA by up to $150.0 million, depending on the risk represented by the
quantity or quality of oil that is handled by the facility. Any failure to comply with OPA’s requirements or
inadequate cooperation during a spill response action may subject a responsible party to administrative penalties up
to $25,000 per day per violation. We believe we are in compliance with all applicable OPA financial responsibility
obligations. Moreover, we are not aware of any action or event that would subject us to liability under OPA, and
we believe that compliance with OPA’s financial responsibility and other operating requirements will not have a
material adverse effect on us.
Resource Conservation Recovery Act. The Resource Conservation and Recovery Act (“RCRA”), and comparable
state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-
hazardous wastes. Under the auspices of the EPA, the individual states administer some or all of the provisions of
RCRA, sometimes in conjunction with their own more stringent requirements. We generate solid and hazardous
wastes that are subject to RCRA and comparable state laws. Drilling fluids, produced waters and most of the other
wastes associated with the exploration, development and production of crude oil or natural gas are currently
regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas
exploration and production wastes now classified as non-hazardous could be classified as hazardous waste in the
future. In September 2010, the Natural Resources Defense Council filed a petition with the EPA, requesting them to
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
16
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 and Texas, and we expect it will also be used in the future. Should our exploration and
production activities expand to other states, it is likely that we will utilize hydraulic fracturing to complete or
recomplete wells in those areas. The process is typically regulated by state oil and gas commissions. However, the
EPA 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.
17
At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing
activities on drinking water resources. The EPA published a progress report of the study in December 2012 and
expects to release a draft final report for public comment and peer review in 2014. Moreover, the EPA announced
in October 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities
and currently plans to propose standards for coalbed methane in 2013 and shale gas in 2014 that such wastewater
must meet before being transported to a treatment plant. Other federal agencies are also examining hydraulic
fracturing, including the U.S. Department of Energy, 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. On November 20, 2013, the U.S.
House of Representatives passed the Protecting States’ Rights to Promote American Energy Security Act, which
would ban the U.S. Department of the Interior from regulating hydraulic fracturing if enacted into law. 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 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 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.
Global Warming and Climate Change. On December 15, 2009, the EPA published its findings that emissions of
carbon dioxide, methane and other greenhouse gases (“GHG”) present an endangerment to public health and the
environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s
atmosphere and other climate changes. Based on these findings, the EPA has begun adopting and implementing
regulations that restrict emissions of GHG under existing provisions of the CAA, including one rule that limits
emissions of GHG from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final
motor vehicle GHG emission standards trigger the CAA construction and operating permit requirements for
stationary sources, commencing when the motor vehicle standards took effect on January 2, 2011. On June 3,
2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under
the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. This rule “tailors” these
permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the
largest sources first 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
18
production, processing, transmission, storage and distribution facilities. This rule requires reporting of GHG
emissions from such facilities on an annual basis with reporting beginning in 2012 for emissions occurring in 2011.
We believe that we are in compliance with all substantial applicable emissions requirements, and we are preparing
to comply with future requirements.
In addition, both houses of Congress have considered legislation to reduce emissions of GHG, and many states have
already taken legal measures to reduce emissions of GHG, primarily through the development of GHG inventories,
greenhouse gas permitting and/or regional GHG “cap and trade” programs. Most of these “cap and trade”
programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender
emission allowances, with the number of allowances available for purchase reduced each year until the overall
GHG emission reduction goal is achieved. In the absence of new legislation, the EPA is issuing new regulations
that limit emissions of GHG associated with our operations, which will require us to incur costs to inventory and
reduce emissions of GHG associated with our operations and which could adversely affect demand for the oil and
natural gas that we produce. Finally, it should be noted that some scientists have concluded that increasing
concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such
as increased frequency and severity of storms, droughts, floods and other climatic events. 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, 2013, we had 958 full-time employees, including 39 senior level geoscientists and 73
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 Securities and
Exchange Commission.
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Item 1A. Risk Factors
Each of the risks described below should be carefully considered, together with all of the other information
contained in this Annual Report on Form 10-K, before making an investment decision with respect to our securities.
If any of the following risks develop into actual events, our business, financial condition or results of operations
could be materially and adversely affected, and you may lose all or part of your investment.
Oil and natural gas prices are very volatile. An extended period of low oil and natural gas prices may adversely
affect our business, financial condition, results of operations or cash flows.
The oil and gas markets are very volatile, and we cannot predict future oil and natural gas prices. The price we
receive for our oil, NGL and natural gas production heavily influences our revenue, profitability, access to capital
and future rate of growth. The prices we receive for our production depend on numerous factors beyond our
control. These factors include, but are not limited to, the following:
• changes in regional, domestic and global supply and demand for oil and natural gas;
•
•
• political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-
the actions of the Organization of Petroleum Exporting Countries;
the price and quantity of imports of foreign oil and natural gas;
producing activity, such as recent conflicts in the Middle East;
the level of global oil and natural gas exploration and production activity;
the effects of global credit, financial and economic issues;
the level of global oil and natural gas inventories;
•
•
•
• developments of United States energy infrastructure, such as the approval to proceed with the Keystone XL
pipeline from Hardesty, Alberta to Cushing, Oklahoma and the development of liquefied natural gas exporting
facilities and the perceived timing thereof;
technological advances affecting energy consumption;
• weather conditions;
•
• domestic and foreign governmental regulations;
• proximity and capacity of oil and natural gas pipelines and other transportation facilities;
•
•
• acts of force majeure.
the price and availability of competitors’ supplies of oil and natural gas in captive market areas;
the price and availability of alternative fuels; and
Moreover, government regulations, such as regulation of oil and natural gas gathering and transportation, can
adversely affect commodity prices in the long term.
Lower oil, NGL and natural gas prices may not only decrease our revenues on a per unit basis but also may
ultimately reduce the amount of oil and natural gas that we can produce economically and therefore potentially
lower our reserve quantities. A substantial or extended decline in oil, NGL or natural gas prices may result in
impairments of our proved oil and gas properties and may materially and adversely affect our future business,
financial condition, results of operations, liquidity or ability to finance planned capital expenditures. To the extent
commodity prices received from production are insufficient to fund planned capital expenditures, we will be
required to reduce spending or borrow any such shortfall. Lower oil, NGL and natural gas prices may also reduce
the amount of our borrowing base under our credit agreement, which is determined at the discretion of the lenders
based on the collateral value of our proved reserves that have been mortgaged to the lenders, and is subject to
regular redeterminations on May 1 and November 1 of each year, as well as special redeterminations described in
the credit agreement.
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Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could
adversely affect our business, financial condition or results of operations.
Our future success will depend on the success of our 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:
• 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;
•
• pipeline takeaway and refining and processing capacity; and
•
reductions in oil, NGL and natural gas prices;
title problems.
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 and
Texas, and we expect it will also be used in the future. Should our exploration and production activities expand to
other states, it is likely that we will utilize hydraulic fracturing to complete or recomplete wells in those areas. The
process is typically regulated by state oil and gas commissions. However, the 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. The EPA published a progress report of the study in December 2012 and
expects to release a draft final report for public comment and peer review in 2014. Moreover, the EPA announced
in October 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities
and currently plans to propose standards for coalbed methane in 2013 and shale gas in 2014 that such wastewater
must meet before being transported to a treatment plant. Other federal agencies are also examining hydraulic
fracturing, including the U.S. Department of Energy, 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. On November 20, 2013, the U.S.
House of Representatives passed the Protecting States’ Rights to Promote American Energy Security Act, which
21
would ban the U.S. Department of the Interior from regulating hydraulic fracturing if enacted into law. 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 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 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.
Refer to “Hydraulic Fracturing” in Item 2 of this Annual Report on Form 10-K for more information on hydraulic
fracturing.
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, 2013, proved undeveloped reserves comprised 39% of the North Ward Estes field’s total
estimated proved reserves. To fully develop these reserves, we expect to incur future development costs of
$684.2 million at the North Ward Estes field as of December 31, 2013. This field encompasses 20% 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
22
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 commercial quantities. In addition, because of the wide variance that results
from different equipment used to test the wells, initial flow rates may not be indicative of sufficient oil or gas
quantities in a particular field. The analogies we draw from available data from other wells, from more fully
explored prospects, or from producing fields may not be applicable to our drilling prospects. We may terminate our
drilling program for a prospect if results do not merit further investment.
If oil, NGL and natural gas prices decrease, we may be required to take write-downs of the carrying values of
our oil and gas properties.
Accounting rules require that we periodically review the carrying value of our producing oil and gas properties for
possible impairment. Based on specific market factors and circumstances at the time of prospective impairment
reviews (which may include depressed oil, NGL and natural gas prices, and the continuing evaluation of
development plans, production data, economics and other factors) we may be required to write down the carrying
value of our oil and gas properties. For example, we recorded a $220.8 million impairment write-down during
2013 for the partial impairment of producing properties, primarily natural gas, in Michigan, Utah and Wyoming. A
write-down constitutes a non-cash charge to earnings. We may incur additional impairment charges in the future,
which could have a material adverse effect on our results of operations in the period recognized.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies
in these reserve estimates or underlying assumptions will materially affect the quantities and present value of
our reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical
data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in
these interpretations or assumptions could materially affect the estimated quantities and present value of reserves
referred to in this Annual Report on Form 10-K.
In order to prepare our estimates, we must project production rates and timing of development expenditures. We
must also analyze available geological, geophysical, production and engineering data. The extent, quality and
reliability of this data can vary. The process also requires economic assumptions about matters such as the
following:
the assumed effect of governmental regulation; and
• historical production from the area compared with production rates from other producing areas;
•
• 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
23
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. 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, 2013 would have decreased
from $6,593.9 million to $6,583.2 million. If oil prices decline by $1.00 per Bbl, then the standardized measure of
discounted future net cash flows of our estimated proved reserves as of December 31, 2013 would have decreased
from $6,593.9 million to $6,483.8 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. In addition, curtailments or damage to pipelines used to transport oil, NGLs and
natural gas production to markets for sale could decrease revenues or increase transportation expenses. Any such
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. An
accident involving rail cars could result in significant personal injuries and property and environmental damage.
Additionally, added regulations in response to such accidents could result in additional costs that could increase
transportation expenses.
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.
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, 2013, we had no borrowings and $3.0 million in letters of credit outstanding under Whiting Oil
and Gas Corporation’s (“Whiting Oil and Gas”) credit facility with $1,197.0 million of available borrowing
capacity, as well as $2,300.0 million of senior notes outstanding and $350.0 million of senior subordinated notes
24
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:
• 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. 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 refinancing of our debt or
a sale of assets include financial market conditions and our market value and operating performance at the time of
such offering or other financing. We may not be able to successfully complete any such offering, refinancing or
sale of assets.
The instruments governing our indebtedness contain various covenants limiting the discretion of our
management in operating our business.
The indentures governing our senior 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:
• 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;
25
sell assets;
• create certain liens;
•
• 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, subject to certain exceptions, unless our fixed charge coverage ratio (as defined
in the indentures) is at least 2.0 to 1. If we were in violation of these covenants, then we may not be able to incur
additional indebtedness, including under Whiting Oil and Gas’ credit agreement. A substantial or extended decline
in oil or natural gas prices may adversely affect our ability to comply with these covenants.
If we fail to comply with the restrictions in the indentures governing our senior 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 and oil and gas property divestments. We intend to
finance future capital expenditures with cash flow from operations, cash on hand and existing financing
arrangements. Our cash flow from operations and access to capital is subject to a number of variables, including:
• our proved reserves;
•
•
•
• our ability to acquire, locate and produce new 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
If our revenues or the borrowing base under our credit agreement decreases as a result of lower oil and natural gas
prices, operating difficulties, declines in reserves, or for any other reason, then we may have limited ability to
obtain the capital necessary to sustain our operations at current levels.
We may, from time to time, need to seek additional financing. There can be no assurance as to the availability or
terms of any additional financing. If additional capital is needed, we may not be able to obtain debt or equity
26
financing on terms favorable to us, or at all. If cash generated by operations or available under our revolving credit
facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a
curtailment of our operations relating to the exploration and development of our prospects, which in turn could lead
to a possible loss of properties and a decline in our oil and natural gas reserves.
Our acquisition activities may not be successful.
As part of our growth strategy, we have made and may continue to make acquisitions of businesses and properties.
However, suitable acquisition candidates may not continue to be available on terms and conditions we find
acceptable, and acquisitions pose substantial risks to our business, financial condition and results of operations. In
pursuing acquisitions, we compete with other companies, many of which have greater financial and other resources
to acquire attractive companies and properties. The following are some of the risks associated with acquisitions,
including any completed or future acquisitions:
•
some of the acquired businesses or properties may not produce revenues, reserves, earnings or cash flow at
anticipated levels;
• we may assume liabilities that were not disclosed to us or that exceed our estimates;
• we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational
and other benefits in a timely manner, which could result in substantial costs and delays or other operational,
technical or financial problems;
• acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to
maintain our current business standards, controls and procedures; and
• we may issue additional equity or debt securities in order to fund future acquisitions.
Substantial acquisitions or other transactions could require significant external capital and could change our
risk and property profile.
In order to finance acquisitions of additional producing or undeveloped properties, we may need to alter or increase
our capitalization substantially through the issuance of debt or equity securities, the sale of production payments or
other means. These changes in capitalization may significantly affect our risk profile. Additionally, significant
acquisitions or other transactions can change the character of our operations and business. The character of the new
properties may be substantially different in operating or geological characteristics or geographic location than our
existing properties. Furthermore, we may not be able to obtain external funding for additional future acquisitions or
other transactions or to obtain external funding on terms acceptable to us.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oil field services
could adversely affect our ability to execute our exploration and development plans on a timely basis or within
our budget.
The demand for qualified and experienced field personnel to conduct field operations, geologists, geophysicists,
engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation
with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs
and other oilfield equipment as demand for rigs and equipment has increased along with the number of wells being
drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil
and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and
associated supplies, equipment and services. Additionally, our operations in some instances require supply
materials 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.
27
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, 2013, we had identified a drilling inventory of over
3,200 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, and the value of our undeveloped acreage may decline, and we may incur impairment charges if
drilling results are unsuccessful.
While our costs to acquire undeveloped acreage in new or emerging plays have generally been less than those of
later entrants into a developing play, our drilling results in these areas are more uncertain than drilling results in
areas that are developed and producing. Since new or emerging plays have limited or no production history, we are
unable to use past drilling results in those areas to help predict our future drilling results. Therefore, our cost of
drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our
undeveloped acreage will decline if drilling results are unsuccessful. Furthermore, if drilling results are
unsuccessful, we may be required to write down the carrying value of our undeveloped acreage in new or emerging
plays. For example, during the fourth quarter of 2013, we recorded a $13.6 million non-cash charge for the
impairment of unproved properties in our Flat Rock field in Utah. 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 2013, we completed 17
separate significant acquisitions of producing properties with a combined purchase price of $2,160.3 million for
estimated proved reserves as of the effective dates of the acquisitions of 248.0 MMBOE. The successful
acquisition of producing properties requires assessment of many factors, which are inherently inexact and may be
inaccurate, including the following:
the amount of recoverable reserves;
future oil and natural gas prices;
•
•
• estimates of operating costs;
• estimates of future development costs;
timing of future development costs;
•
• estimates of the costs and timing of plugging and abandonment; and
•
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
28
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 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, placed with major financial
institutions. As of February 6, 2014, we had contracts, which include our 10% share of the Whiting USA Trust II
hedges, covering the sale of between 1,204,250 and 1,284,250 barrels of oil per month for all of 2014. All of our
oil hedges will expire by December 2014. 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. 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
29
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:
• 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;
•
•
• personal injuries and death; and
• natural disasters.
the loss of well control;
fires and explosions;
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 77% of our net productive oil and natural gas wells, which represents 86% of our proved developed
producing reserves as of December 31, 2013. 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
30
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:
• discharge permits for drilling operations;
• drilling bonds;
•
•
• unitization and pooling of properties; and
•
reports concerning operations;
the spacing of wells;
taxation.
31
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
32
the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. This rule “tailors” these
permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the
largest sources first subject to permitting. Further, facilities required to obtain PSD permits for their GHG
emissions are required to reduce those emissions consistent with guidance for determining “best available control
technology” standards for GHG, which guidance was published by the EPA in November 2010. Also in November
2010, the EPA expanded its existing GHG reporting rule to include onshore oil and natural gas production,
processing, transmission, storage and distribution facilities. This rule requires reporting of GHG emissions from
such facilities on an annual basis with reporting beginning in 2012 for emissions occurring in 2011.
In addition, both houses of Congress have actively considered legislation to reduce emissions of GHG, and many
states have already taken legal measures to reduce emissions of GHG, primarily through the development of GHG
inventories, greenhouse gas permitting and/or regional GHG “cap and trade” programs. Most of these “cap and
trade” programs work by requiring either major sources of emissions or major producers of fuels to acquire and
surrender emission allowances, with the number of allowances available for purchase reduced each year until the
overall GHG emission reduction goal is achieved. In the absence of new legislation, the EPA is issuing new
regulations that limit emissions of GHG associated with our operations which will require us to incur costs to
inventory and reduce emissions of GHG associated with our operations and which could adversely affect demand
for the oil, NGLs and natural gas that we produce. Finally, it should be noted that some scientists have concluded
that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant
physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If
any such effects were to occur, they could have an adverse effect on our assets and operations.
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 and Chief
Executive Officer; James T. Brown, President and Chief Operating Officer; Mark R. Williams, Senior Vice
President, Exploration and Development; Steven A. Kranker, Vice President, Reservoir Engineering/Acquisitions;
Rick A. Ross, Vice President, Operations; David M. Seery, Vice President, Land; Michael J. Stevens, Vice
President and Chief Financial Officer; or Peter W. Hagist, Vice President, Permian Operations, could have a
material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the
loss of any of these individuals.
Competition in the oil and gas industry is intense, which may adversely affect our ability to compete.
We operate in a highly competitive environment for acquiring properties, marketing oil and gas and securing
trained personnel. Many of our competitors possess and employ financial, technical and personnel resources
substantially greater than ours, which can be particularly important in the areas in which we operate. Those
companies may be able to pay more for productive oil and gas properties and exploratory prospects and to evaluate,
bid for and purchase a greater number of properties and prospects than our financial or personnel resources 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
33
environment. Also, there is substantial competition for available capital for investment in the oil and gas industry.
We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves,
marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.
Certain federal income tax deductions currently available with respect to oil and gas exploration and
development may be eliminated or deferred as a result of future legislation.
In April 2013, President Obama’s Administration released its proposed federal budget for fiscal year 2014 that
would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain
key U.S. federal income tax preferences currently available to oil and gas exploration and production companies.
Such changes include, but are not limited to:
the repeal of the percentage depletion allowance for oil and gas properties;
the elimination of current deductions for intangible drilling and development costs;
the elimination of the deduction for 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.
Item 1B. Unresolved Staff Comments
None.
34
Item 2.
Properties
Summary of Oil and Gas Properties and Projects
Rocky Mountains Region
Our Rocky Mountains operations include assets in the states of North Dakota, Colorado, Montana, Wyoming, Utah
and California. As of December 31, 2013, our estimated proved reserves in the Rocky Mountains region were
297.0 MMBOE (80% oil), which represented 68% of our total estimated proved reserves and contributed 84.7
MBOE/d of average daily production in the fourth quarter of 2013.
Sanish and Parshall Fields. Our Sanish and Parshall fields in Mountrail County, North Dakota target the Bakken
and Three Forks formations and encompass approximately 174,700 gross (82,400 net) developed and undeveloped
acres. Net production in the Sanish and Parshall fields averaged 40.4 MBOE/d for the fourth quarter of 2013,
representing a 10% increase from 36.8 MBOE/d in the third quarter of 2013. As of December 31, 2013, we had
four drilling rigs active in the Sanish field. We also initiated three high density pilot programs in the Sanish field
and participated in several infill wells in the Parshall field during 2013. We recently completed two infill wells
using our new completion design 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 90 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. We currently have projects underway to expand the inlet compression and processing capability at
this plant to 110 MMcf/d.
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, 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, 2013, the Lewis & Clark/Pronghorn fields encompassed
approximately 392,500 gross (263,400 net) developed and undeveloped acres. Net production in the Lewis &
Clark/Pronghorn fields averaged 15.1 MBOE/d in the fourth quarter of 2013, representing a 6% increase from 14.2
MBOE/d in the third quarter of 2013. As of December 31, 2013, we had four drilling rigs operating in the
Pronghorn field, all of which are utilizing drilling pads, with two or three wells from each pad. Additionally, we
have tested our new completion design in the Pronghorn field utilizing cemented liners and plug-and-perf
technology and are encouraged by the results. As a result of these successes, we plan to use this completion
technique on all future wells drilled in the area.
We have completed the construction of our gas processing plant located south of Belfield, North Dakota, which has
a processing capacity of 35 MMcf/d and which primarily processes production from the Pronghorn area. In
November 2012, we began connecting other operators’ wells to the plant, and we added inlet compression during
2013 in order to fully utilize the plant’s processing capability. Currently, there is inlet compression in place to
process 35 MMcf/d, and as of December 31, 2013 the plant was processing 18 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 66,800 gross (37,400 net) developed and
undeveloped acres and 8,800 gross (6,300 net) developed and undeveloped acres, respectively, as of December 31,
2013. Net production at Hidden Bench/Tarpon averaged 13.4 MBOE/d in the fourth quarter of 2013, which
represents a 31% increase from 10.2 MBOE/d in the third quarter of 2013. We have also implemented our new
completion design at our Hidden Bench field, utilizing cemented liners and plug-and-perf technology, which has
generated positive results. In addition, we have tested a high density drilling pilot at our Hidden Bench field and
35
are currently analyzing the resulting data. In the Tarpon field, we have drilled six productive wells as of
December 31, 2013. We had previously planned to drill most of the remaining Tarpon development wells during
2013 but have experienced delays resulting from the U.S. Forest Service’s requirement to perform an
Environmental Assessment prior to the issuance of federal drilling permits for these wells. We anticipate that we
will be able to resume drilling in 2014, and we have begun permitting additional wells for 2014.
Missouri Breaks Field. As of December 31, 2013, we had approximately 98,600 gross (64,300 net) developed and
undeveloped acres at our Missouri Breaks field located in Richland County, Montana and McKenzie County, North
Dakota. In the fourth quarter of 2013, net production from the Missouri Breaks field averaged 3.8 MBOE/d,
representing a 31% increase from 2.9 MBOE/d in the third quarter of 2013. During 2013, we implemented our new
completion design at this field, utilizing cemented liners, plug-and-perf technology and higher sand volumes, and
the new design has improved initial production rates. We have drilled successful wells on the western, eastern and
southern portions of our acreage in this area.
Redtail Field. Our Redtail field in the Weld County, Colorado portion of the DJ Basin targets the Niobrara
formation and encompasses approximately 169,700 gross (122,300 net) developed and undeveloped acres as of
December 31, 2013. In September 2013, we completed the acquisition of approximately 47,800 gross (32,100 net)
acres at our Redtail field, including interests in one producing well. 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. In
2014, we plan to test a high-density pattern in the Niobrara “A”, “B” and “C” zones drilling 32 wells per spacing
unit. As of December 31, 2013, we had three drilling rigs operating in this area, and we plan to add another rig in
2014. We implemented a new completion design in this field utilizing larger proppant volumes, which has been
yielding improved production results, and we are currently evaluating the use of cemented liners in the Redtail
field.
The associated gas produced with the Niobrara oil must be processed before being sold, and we are nearing
completion of the construction of a gas processing plant for this area. The plant’s initial inlet capacity will be 15
MMcf/d, and we plan to further expand the plant’s capacity to 60 MMcf/d in 2015. We anticipate having the plant
online in early 2014.
Permian Basin Region
Our Permian Basin operations include assets in Texas and New Mexico. As of December 31, 2013, the Permian
Basin region contributed 127.1 MMBOE (84% oil) of estimated proved reserves to our portfolio of operations,
which represented 29% of our total estimated proved reserves and contributed 12.3 MBOE/d of average daily
production in the fourth quarter of 2013.
North Ward Estes Field. The North Ward Estes field includes six base leases with 100% working interests in
approximately 62,300 gross (60,500 net) developed and undeveloped acres in Ward and Winkler counties, Texas.
Current production from our enhanced oil recovery (“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 in one of the largest phases of our eight-phase project at North Ward Estes,
and several of the phases of the CO2 flood are continuing to respond. In the fourth quarter of 2013, production
from the field averaged 9.8 MBOE/d, which represents a 2% increase from 9.6 MBOE/d in the third quarter of
2013. As of December 31, 2013, we were injecting approximately 390 MMcf/d of CO2 in this field, over half of
which is recycled.
North Ward Estes’ proved reserves at December 31, 2013 were 39% 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, 2013, we currently have under contract 100% of the future CO2 volumes that
36
we believe are necessary to develop the field’s PUDs. In addition, we are currently in negotiations and 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 absolute 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.
Big Tex Prospect. As of December 31, 2013, we had accumulated approximately 52,300 gross (40,900 net)
developed and undeveloped acres at our Big Tex prospect in Pecos, Reeves and Ward counties, Texas in the
Delaware Basin. Prospective formations include the Brushy Canyon, Bone Spring and Wolfcamp horizons. In
October 2013, we sold approximately 45,000 gross (32,200 net) acres, including interests in certain producing oil
and gas wells, as well as undeveloped acreage, in our Big Tex prospect. Refer to “Acquisitions and Divestitures” in
Item 1 of this Annual Report on Form 10-K for more information on this divestiture.
Other
Our other operations primarily relate to assets in Arkansas, Louisiana, Michigan, Oklahoma and Texas. As of
December 31, 2013, these properties contributed 14.4 MMBOE (31% oil) of proved reserves to our portfolio of
operations, which represented 3% of our total estimated proved reserves and contributed 4.0 MBOE/d of average
daily production in the fourth quarter of 2013. In Michigan, we also operate the West Branch and Reno gas
processing plants. The West Branch plant gathers production from the Clayton unit, West Branch field and other
smaller fields.
Reserves
As of December 31, 2013, 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, 2013 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, 2013) is as follows:
Oil
(MBbl)
NGLs
(MBbl)
Natural Gas
(MMcf)
Total
(MBOE)
Proved reserves
Developed .........................................
Undeveloped .....................................
Total proved—December 31, 2013 ..........
Probable reserves
Developed .........................................
Undeveloped .....................................
Total probable—December 31, 2013 .......
Possible reserves
Developed .........................................
Undeveloped .....................................
Total possible—December 31, 2013 ........
198,204
149,217
347,421
748
108,520
109,268
1,989
135,234
137,223
23,721
21,148
44,869
139
22,191
22,330
387
24,220
24,607
183,129
94,385
277,514
6,832
260,723
267,555
1,746
162,034
163,780
252,446
186,096
438,542
2,026
174,165
176,191
2,667
186,460
189,127
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 2013, total extensions and discoveries of 108.8 MMBOE were primarily attributable to successful drilling in our
Redtail, Sanish, Missouri Breaks, Hidden Bench and Pronghorn fields. The new wells drilled in these areas and
their related PUD locations added during the year increased our proved reserves.
37
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 “Acquisitions and Divestitures” within Item 1 of this Annual Report on Form 10-K,
which decreased our proved reserves.
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 “Acquisitions and
Divestitures” within Item 1 of this Annual Report on Form 10-K, which increased our proved reserves.
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 our 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.
Proved undeveloped reserves. Our PUD reserves increased 36% or 49.2 MMBOE on a net basis from
December 31, 2012 to December 31, 2013. The following table provides a reconciliation of our PUDs for the year
ended December 31, 2013:
PUD balance—December 31, 2012 ..............................................................................................................
Converted to proved developed through drilling (1)(3) ............................................................................
Converted to proved developed at EOR projects (2)(3) ............................................................................
Added from revisions, extensions and discoveries ................................................................................
Removed for five-year rule ....................................................................................................................
Removed due to low commodity prices .................................................................................................
Purchased ...............................................................................................................................................
Sold ........................................................................................................................................................
PUD balance—December 31, 2013 ..............................................................................................................
_____________________
(1) We incurred $701.5 million in capital expenditures, or $25.25 per BOE, to drill and bring on-line these PUD quantities.
Total
(MBOE)
136,896
(27,782)
(12,364)
90,519
(602)
(143)
12,745
(13,173)
186,096
(2) Amount relates to PUD volumes that became proved developed reserves during 2013 at our CO2 EOR project in the
North Ward Estes field, at a cost of $40.35 per BOE.
(3) Combining the PUD drilling conversions with the PUD EOR conversions, we converted PUDs to proved developed
reserves at a cost of $29.90 per BOE during 2013.
During the year we added 90.5 MMBOE of gross PUD volumes, 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.
Based on our 2013 year end independent engineering reserve report, we will drill all of our individual PUD drilling
locations within five years. However, we do have certain quantities of proved undeveloped reserves in the North
Ward Estes field that will remain in the PUD category for periods extending beyond five years because of certain
external factors that preclude the development of the North Ward Estes enhanced oil recovery PUDs all at once.
Due to the large areal extent of the field, the CO2 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 initiation of the CO2 project throughout the field 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
38
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 2013 were primarily attributable to 724 new probable well locations that were
added in 2013 as a result of our drilling activity across the Rocky Mountains region. During 2013, 31.3 MMBOE
of probable reserves were converted to proved reserves at our North Ward Estes field, 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.
Possible reserves increased during 2013 primarily due to successful drilling at our Redtail, Sanish, Parshall, Lewis
& Clark/Pronghorn and Hidden Bench fields. During 2013, 27.0 MMBOE of possible reserves were converted to
probable at our Redtail field and various other fields in the Northern Rocky Mountains, and 19.7 MMBOE of
possible reserves were converted to proved at certain fields in the Northern Rocky Mountains.
At December 31, 2013, our probable reserves were estimated to be 176.2 MMBOE and our possible reserves were
estimated to be 189.1 MMBOE, for a total of 365.3 MMBOE. The EOR project at our North Ward Estes field
represented 94.1 MMBOE, or 26%, of our total 365.3 MMBOE probable and possible reserve quantities. In order
to fully develop the EOR probable and possible reserves at North Ward Estes, we will need to utilize significant
quantities of purchased CO2. We are currently in negotiations and planning for future sources capable of generating
sufficient CO2 quantities to carry out the development of all probable and possible reserves at North Ward Estes.
However, the availability of future CO2 supplies is subject to uncertainty and may require significant future capital
39
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 external quarterly reviews, annual audits and their own set of internal controls over
financial reporting. Internal controls over financial reporting are assessed for effectiveness annually using the criteria
set forth in Internal Control – Integrated Framework (1992) 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.(cid:2)
Our Vice President of Reservoir Engineering and Acquisitions is responsible for overseeing the preparation of the
reserves estimates. He has over 29 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.
Acreage
The following table summarizes gross and net developed and undeveloped acreage by state at December 31, 2013.
Net acreage is our percentage ownership of gross acreage. Acreage in which our interest is limited to royalty and
overriding royalty interests is excluded.
40
Developed Acreage
Net
Gross
Undeveloped Acreage
Net(2)
Gross(2)
California .......................................
Colorado .........................................
Louisiana ........................................
Michigan ........................................
Montana .........................................
New Mexico ...................................
North Dakota ..................................
Oklahoma .......................................
Texas ..............................................
Utah ................................................
Wyoming ........................................
Other (1) ..........................................
25,548
61,579
40,074
139,351
91,973
16,665
553,050
56,645
260,935
35,826
95,725
9,810
Total ........................................ 1,387,181
3,606
42,555
11,691
61,064
55,425
5,427
316,872
28,392
147,963
18,370
55,835
4,503
-
179,242
101,325
291,960
136,964
78,190
365,538
406
84,214
406,522
49,312
912
-
116,629
90,862
247,996
81,730
56,668
261,008
68
60,849
240,108
36,072
434
Total Acreage
Gross
25,548
240,821
141,399
431,311
228,937
94,855
918,588
57,051
345,149
442,348
145,037
10,722
Net
3,606
159,184
102,553
309,060
137,155
62,095
577,880
28,460
208,812
258,478
91,907
4,937
751,703
1,694,585
1,192,424
3,081,766
1,944,127
_____________________
(1) Other includes Alabama, Arkansas, Kansas, Mississippi and Nebraska.
(2) Out of a total of approximately 1,694,585 gross (1,192,424 net) undeveloped acres as of December 31, 2013, 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 13% in 2014, 27% in 2015 and 22% in 2016.
Production History
The following table presents historical information about our produced oil and gas volumes:
Year Ended December 31,
2012
2013
2011
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):
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
18.3
2.1
26.4
24.8
67.9
2.6
0.4
0.4
3.0
6.5
0.8
2.2
7.7
Oil (per Bbl) ..................................................................................................... $
NGLs (per Bbl) ................................................................................................ $
Natural gas (per Mcf) ....................................................................................... $
Average production costs:
Production costs (per BOE) (2) ......................................................................... $
90.39
40.41
4.04
11.94
$
$
$
$
83.86
39.36
3.42
11.92
$
$
$
$
88.61
52.38
4.92
11.77
_____________________
(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, 2013.
(2) Production costs reported above exclude from lease operating expenses ad valorem taxes of $20.1 million ($0.59 per
BOE), $16.3 million ($0.54 per BOE) and $13.9 million ($0.56 per BOE) for the years ended December 31, 2013, 2012
and 2011, respectively.
41
Productive Wells
The following table summarizes gross and net productive oil and natural gas wells by region at December 31, 2013.
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.
Rocky Mountains ...........................
Permian Basin ................................
Other (2) ..........................................
Total .......................................
Oil Wells
Gross
3,441
4,091
479
8,011
Net
1,082
1,727
217
3,026
Natural Gas Wells
Net
Gross
413
386
1,666
2,465
221
122
553
896
Total Wells(1)
Gross
3,854
4,477
2,145
10,476
Net
1,303
1,849
770
3,922
_____________________
(1) 141 wells have multiple completions. These 141 wells contain a total of 349 completions. One or more completions in
the same bore hole are counted as one well.
(2) Other primarily includes oil and gas properties in Arkansas, Louisiana, Michigan, Oklahoma and Texas.
We have an interest in or operate 33 EOR projects, which include either secondary (waterflood) or tertiary (CO2
injection) recovery efforts, and aggregate production from such EOR fields averaged 15.5 MBOE/d during 2013 or
16% of our 2013 daily production. For these areas, we need to use enhanced recovery techniques in order to
maintain oil and gas production from these fields.
Drilling Activity
We are engaged in numerous drilling activities on properties presently owned, and we intend to drill or develop
other properties acquired in the future. The following table sets forth our drilling activity for the last three years. A
dry well is an exploratory, development or extension well that proves to be incapable of producing either oil or gas
in sufficient quantities to justify completion as an oil or gas well. A productive well is an exploratory, development
or extension well that is not a dry well. The information below should not be considered indicative of future
performance, nor should it be assumed that there is necessarily any correlation between the number of productive
wells drilled and quantities of reserves found.
Productive
Gross Wells
Dry
Total
Productive
Net Wells
Dry
Total
2013:
Development ............................
Exploratory ..............................
Total ...................................
2012:
Development ............................
Exploratory ..............................
Total ...................................
2011:
Development ............................
Exploratory ..............................
Total ...................................
376
43
419
324
68
392
218
60
278
1
8
9
-
5
5
3
3
6
377
51
428
324
73
397
221
63
284
185.5
35.2
220.7
140.4
47.8
188.2
93.9
36.6
130.5
1
7.5
8.5
-
4.7
4.7
1.5
3.0
4.5
186.5
42.7
229.2
140.4
52.5
192.9
95.4
39.6
135.0
As of December 31, 2013, 23 operated drilling rigs were active on our properties. The breakdown of our operated
rigs by geographic area is as follows:
42
Northern Rocky Mountains..........................................................................................................................
Central Rocky Mountains ............................................................................................................................
North Ward Estes .........................................................................................................................................
Total ........................................................................................................................................................
Drilling Rigs
18
3
2
23
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 and Texas, 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 186.1 MMBOE.
In November 2010, we had a well control incident involving one well in our Sanish field, whereby the North
Dakota Industrial Commission (“NDIC”) filed a complaint against Whiting alleging the violation of regulations.
This matter resulted in us entering into a consent agreement with the NDIC, pursuant to which we paid $4,357 in
costs, donated $15,000 to the North Dakota Abandoned Oil and Gas Well Plugging and Site Reclamation Fund, and
agreed to implement certain operational procedures. In addition, 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 these incidents, we are not aware of any
environmental incidents, citations or suits related to hydraulic fracturing operations involving oil and gas properties
that we operate or our non-operated interests.
In order to minimize any potential environmental impact from hydraulic fracture treatments, we have taken the
following steps:
• we follow fracturing and flowback procedures that comply with or exceed NDIC or other state requirements;
• we train all company and contract personnel, who are responsible for well preparation, fracture stimulation and
flowback, on our procedures;
• we have implemented the incremental procedures of running a well casing caliper; visually inspecting the
surface joint of intermediate casing; and if a lighter wall joint of casing or drilling wear is detected, the
minimum burst pressure is reduced accordingly;
for wells that are within one mile of major bodies of water or locations that lead to bodies of water, we construct
sufficient berming around the well location prior to initiating fracturing operations;
•
• we run fracturing strings in certain situations when extra precaution is warranted, such as where the anticipated
maximum treating pressure for the well is greater than the pressure rating of the intermediate casing or in areas
located within one mile of major bodies of water; and
• we are constructing a facility in North Dakota to treat and dispose of flow fluids from well stimulations.
While we do not have insurance policies in effect that are intended to provide coverage for losses solely related to
hydraulic fracturing operations, we do have general liability and excess liability insurance policies that we believe
43
would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in
accordance with, and subject to, the terms of such policies.
Delivery Commitments
Our production sales agreements contain customary terms and conditions for the oil and natural gas industry;
generally provide for sales based on prevailing market prices in the area; and generally have terms of one year or
less.
We have also entered into physical delivery contracts which require us to deliver fixed volumes of natural gas and
crude oil. As of December 31, 2013, we had delivery commitments of 4.0 Bcf of natural gas (or 15% of total 2013
natural gas production) for the year ended December 31, 2014. These contracts relate to gas production at our
Boies Ranch field in Rio Blanco County, Colorado and our Flat Rock field in Uintah County, Utah. We believe
that our current production and proved reserves are adequate to meet these delivery commitments. As of
December 31, 2013, we also had delivery commitments of 9.1 MMBbl of crude oil (or 34% of total 2013 oil
production), 11.0 MMBbl (41%), 12.8 MMBbl (47%), 14.6 MMBbl (54%) and 16.4 MMBbl (61%) for the years
ended December 31, 2015, 2016, 2017, 2018 and 2019, respectively. These contracts are tied to oil production at
our Redtail field in the DJ Basin in Weld County, Colorado, and we expect to fulfill these delivery commitments
from the future production from this field. 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.
44
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information, as of February 14, 2014, regarding the executive officers of
Whiting Petroleum Corporation:
Name
James J. Volker ..........................................
James T. Brown .........................................
Mark R. Williams ......................................
Bruce R. DeBoer ........................................
Heather M. Duncan ....................................
Steven A. Kranker .....................................
Rick A. Ross ..............................................
David M. Seery ..........................................
Michael J. Stevens .....................................
Brent P. Jensen ...........................................
Age
67
61
57
61
43
52
55
59
48
44
Position
Chairman and Chief Executive Officer
President and Chief Operating Officer
Senior Vice President, Exploration and Development
Vice President, General Counsel and Corporate Secretary
Vice President, Human Resources
Vice President, Reservoir Engineering and Acquisitions
Vice President, Operations
Vice President, Land
Vice President and Chief Financial Officer
Controller and Treasurer
The following biographies describe the business experience of our executive officers:
James J. Volker joined us in August 1983 as Vice President of Corporate Development and served in that position
through April 1993. In March 1993, he became a contract consultant to us and served in that capacity until August
2000, at which time he became Executive Vice President and Chief Operating Officer. Mr. Volker was appointed
President and Chief Executive Officer and a director in January 2002 and Chairman of the Board in January 2004.
Effective January 1, 2011, Mr. Volker stepped down as President, but remains Chairman and Chief Executive
Officer. Mr. Volker was co-founder, Vice President and later President of Energy Management Corporation from
1971 through 1982. He has 42 years of experience in the oil and gas industry. Mr. Volker has a Bachelor’s degree
in finance from the University of Denver, an MBA from the University of Colorado and has completed H. K.
VanPoolen and Associates’ course of study in reservoir engineering.
James T. Brown joined us in May 1993 as a consulting engineer. In March 1999, he became Operations Manager;
in January 2000, he became Vice President of Operations; and in May 2007, he became Senior Vice President.
Effective January 1, 2011, Mr. Brown was elected President and Chief Operating Officer. Mr. Brown has 39 years
of oil and gas experience in the Rocky Mountains, Gulf Coast, California and Alaska. Mr. Brown is a graduate of
the University of Wyoming with a Bachelor’s degree in civil engineering and the University of Denver with an
MBA.
Mark R. Williams joined us in December 1983 as Exploration Geologist and has been Vice President of Exploration
and Development since December 1999. Mr. Williams was elected Senior Vice President, Exploration and
Development effective January 1, 2011. He has 33 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 34 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 17 years of human resources experience in the oil and gas industry. She holds a Bachelor of Arts
45
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, including Corporate Engineering Manager, from May
2001 to July 2010. Mr. Kranker has 29 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.
Rick A. Ross joined us in March 1999 as an Operations Manager. In May 2007, he became Vice President of
Operations. Mr. Ross has 31 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.
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 33 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 27 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 20 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.
46
PART II
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities
Whiting Petroleum Corporation’s common stock is traded on the New York Stock Exchange under the symbol
“WLL.” The following table shows the high and low sale prices for our common stock for the periods presented.
High
Low
Fiscal Year Ended December 31, 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)................................................................
Fiscal Year Ended December 31, 2012
Fourth quarter (ended December 31, 2012) ......................................................
Third quarter (ended September 30, 2012) .......................................................
Second quarter (ended June 30, 2012) ..............................................................
First quarter (ended March 31, 2012)................................................................
$
$
$
$
$
$
$
$
70.57
60.65
50.96
52.02
48.87
54.86
58.33
63.97
$
$
$
$
$
$
$
$
56.40
46.13
42.44
43.60
40.19
38.29
35.68
46.55
On February 14, 2014, there were 639 holders of record of our common stock.
We have not paid any dividends on our common stock since we were incorporated in July 2003, and we do not
anticipate paying any such dividends on our common stock in the foreseeable future. We currently intend to retain
future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion
of our board of directors and will depend upon various factors, including our financial position, cash flows, results
of operations, capital requirements and investment opportunities. Except for limited exceptions, 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 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, 2008 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, 2008 in our common stock, the Standard & Poor’s Composite 500 Index and the Dow Jones U.S. Oil
Companies, Secondary Index.
47
Whiting Petroleum Corporation .................. $
Standard & Poor’s Composite 500 Index ....
Dow Jones U.S. Oil Companies,
12/31/08
100
100
12/31/09
214
$
123
12/31/10
350
$
139
12/31/11
279
$
139
12/31/12
259
$
158
12/31/13
370
$
205
Secondary Index ..................................
100
139
161
153
160
208
48
Item 6.
Selected Financial Data
The consolidated statements of income and statements of cash flows information for the years ended December 31,
2013, 2012 and 2011 and the consolidated balance sheet information at December 31, 2013 and 2012 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, 2010 and 2009 and the consolidated
balance sheet information at December 31, 2011, 2010 and 2009 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 dates: properties in North Dakota and Montana, September 20, 2013;
properties in Colorado, September 1, 2010; and additional interests in properties in North Ward Estes, November 1,
2009 and October 1, 2009. In addition, our historical results also include the effects of our recent proved property
divestitures beginning on the following dates: properties in the Postle field, April 1, 2013; and properties in Texas,
October 1, 2013.
2013
Year Ended December 31,
2011
(dollars in millions, except per share data)
2012
2010
Consolidated Statements of Income Information:
Revenues and other income:
Oil, NGL and natural gas sales .......................................... $ 2,666.5
(1.9)
Gain (loss) on hedging activities ........................................
Amortization of deferred gain on sale ................................
31.7
128.6
Gain on sale of properties ..................................................
3.4
Interest income and other ...................................................
2,828.3
Total revenues and other income ...................................
$ 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
$ 1,475.3
23.2
15.6
1.4
0.6
1,516.1
$
Costs and expenses:
Lease operating ..................................................................
Production taxes .................................................................
Depreciation, depletion and amortization ..........................
Exploration and impairment ...............................................
General and administrative ................................................
Interest expense ..................................................................
Loss on early extinguishment of debt ................................
Change in Production Participation Plan liability ..............
Commodity derivative (gain) loss, net ...............................
Total costs and expenses ...............................................
Income (loss) before income taxes ..........................................
Income tax expense (benefit) ..................................................
Net income (loss) ....................................................................
Net loss attributable to noncontrolling interest ........................
Net income (loss) available to shareholders ............................
Preferred stock dividends (1) ....................................................
Net income (loss) available to common shareholders ............. $
Earnings (loss) per common share, basic (2) ............................ $
Earnings (loss) per common share, diluted (2) ......................... $
Other Financial Information:
Net cash provided by operating activities ................................ $ 1,744.7
Net cash used in investing activities ........................................ $ (1,902.5)
Net cash provided by (used in) financing activities ................. $
812.4
Capital expenditures ................................................................ $ 2,772.7
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
(0.5)
365.5
3.09
3.06
376.4
171.6
684.7
167.0
108.6
75.2
—
13.8
(85.9)
1,511.4
662.0
247.9
414.1
0.1
414.2
(1.1)
413.1
3.51
3.48
$
$
$
305.5
139.2
468.2
84.6
85.0
62.5
—
(0.9)
(24.8)
1,119.3
780.3
288.7
491.6
0.1
491.7
(1.1)
490.6
4.18
4.14
$
$
$
$ 1,401.2
$ (1,780.3)
$
408.1
$ 2,171.5
$ 1,192.1
$ (1,760.0)
$
564.8
$ 1,804.3
268.3
103.9
393.9
59.4
64.7
59.1
6.2
12.1
7.1
974.7
541.4
204.8
336.7
—
336.7
(64.0)
272.7
2.57
2.55
997.3
(914.6)
(75.7)
923.8
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2009
917.5
38.8
16.6
5.9
0.6
979.4
237.3
64.7
394.8
73.0
42.3
64.6
—
3.3
262.2
1,142.2
(162.8)
(55.9)
(106.9)
—
(106.9)
(10.3)
(117.2)
(1.18)
(1.18)
453.8
(523.5)
72.1
585.8
Consolidated Balance Sheet Information:
Total assets ............................................................................. $ 8,833.5
Long-term debt ....................................................................... $ 2,653.8
Total equity (3) ......................................................................... $ 3,836.7
_____________________
(1) The year ended December 31, 2010 includes a cash premium of $47.5 million for the induced conversion of our 6.25%
$ 4,648.8
$
800.0
$ 2,531.3
$ 4,029.5
$
779.6
$ 2,270.1
$ 7,272.4
$ 1,800.0
$ 3,453.2
$ 6,045.6
$ 1,380.0
$ 3,029.1
Perpetual Preferred Stock.
49
(2) On January 26, 2011, our Board of Directors approved a two-for-one split of the Company's shares of common stock to
be effected in the form of a stock dividend effective February 22, 2011. Earnings (loss) per common share, basic and
diluted for periods prior to February 2011 have been retroactively adjusted to reflect the stock split.
(3) No cash dividends were declared or paid on our common stock during the periods presented.
50
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Unless the context otherwise requires, the terms “Whiting,” “we,” “us,” “our” or “ours” when used in this Item
refer to Whiting Petroleum Corporation, together with its consolidated subsidiaries, Whiting Oil and Gas
Corporation and Whiting Programs, Inc. When the context requires, we refer to these entities separately. This
document contains forward-looking statements, which give our current expectations or forecasts of future events.
Please refer to “Forward-Looking Statements” at the end of this Item for an explanation of these types of
statements.
Overview
We are an independent oil and gas company engaged in exploration, development, acquisition and production
activities primarily in the Rocky Mountains and Permian Basin regions of the United States. Prior to 2006, we
generally emphasized the acquisition of properties that increased our production levels and provided upside
potential through further development. Since 2006, we have focused primarily on organic drilling activity and on
the development of previously acquired properties, specifically on projects that we believe provide the opportunity
for repeatable successes and production growth. We believe the combination of acquisitions, subsequent
development and organic drilling provides us with a broad set of growth alternatives and allows us to direct our
capital resources to what we believe to be the most advantageous investments.
As demonstrated by our recent capital expenditure programs, we are increasingly focused on a balanced exploration
and development program, while continuing to selectively pursue acquisitions that complement our existing core
properties. We believe that our significant drilling inventory, combined with our operating experience and cost
structure, provides us with meaningful organic growth opportunities. Our growth plan is centered on the following
activities:
• pursuing the development of projects that we believe will generate attractive rates of return;
•
• maintaining a balanced portfolio of lower risk, long-lived oil and gas properties that provide stable cash flows;
allocating a portion of our exploration and development budget to leasing and exploring prospect areas;
and
seeking property acquisitions that complement our core areas.
•
We have historically acquired operated and non-operated properties that exceed our rate of return criteria. For
acquisitions of properties with additional development and exploration potential, our focus has been on acquiring
operated properties so that we can better control the timing and implementation of capital spending. In some
instances, we have been able to acquire non-operated property interests at attractive rates of return that established a
presence in a new area of interest or that have complemented our existing operations. We intend to continue to
acquire both operated and non-operated interests to the extent we believe they meet our return criteria. In addition,
our willingness to acquire non-operated properties in new geographic regions provides us with geophysical and
geologic data in some cases that leads to further acquisitions in the same region, whether on an operated or non-
operated basis.
We 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. 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 2012:
51
Crude oil ...........
Natural gas .......
Q1
$102.94
$2.72
Q2
$93.51
$2.21
Q3
$92.19
$2.81
Q4
$88.20
$3.41
Q1
$94.34
$3.34
Q2
$94.23
$4.10
Q3
$105.82
$3.58
Q4
$97.50
$3.60
2012
2013
Lower oil and natural gas prices may not only decrease our revenues, but may also reduce the amount of oil and
natural gas that we can produce economically and therefore potentially lower our oil and gas reserves. A
substantial or extended decline in oil or natural gas prices may result in impairments of our proved oil and gas
properties and may materially and adversely affect our future business, financial condition, cash flows, results of
operations, liquidity or ability to finance planned capital expenditures. Lower oil and gas prices may also reduce
the amount of our borrowing base under our credit agreement, which is determined at the discretion of the lenders
and which is based on the collateral value of our proved reserves that have been mortgaged to the lenders.
Alternatively, higher oil and natural gas prices may result in significant mark-to-market losses being incurred on
our commodity-based derivatives, which may in turn cause us to experience net losses.
For a discussion of material changes to our proved, probable and possible reserves from December 31, 2012 to
December 31, 2013 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.
2013 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 40.4 MBOE/d for the fourth
quarter of 2013, representing a 10% increase from 36.8 MBOE/d in the third quarter of 2013. In 2013, net
production in the Sanish and Parshall fields totaled 13.6 MMBOE (an average of 37.3 MBOE/d), representing a
10% increase from 12.4 MMBOE in 2012. As of December 31, 2013, we had four drilling rigs active in the Sanish
field. We also initiated three high density pilot programs in the Sanish field and participated in several infill wells
in the Parshall field during 2013. We recently completed two infill wells using our new completion design 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, 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 15.1 MBOE/d
in the fourth quarter of 2013, representing a 6% increase from 14.2 MBOE/d in the third quarter of 2013. As of
December 31, 2013, we had four drilling rigs operating in the Pronghorn field, all of which are utilizing drilling
pads, with two or three wells from each pad. Additionally, we have tested our new completion design in the
Pronghorn field utilizing cemented liners and plug-and-perf technology and are encouraged by the results. As a
result of these successes, we plan to use this completion procedure on all future wells drilled in the area.
We have completed the construction of our gas processing plant located south of Belfield, North Dakota, which has
a processing capacity of 35 MMcf/d and which primarily processes production from the Pronghorn area. In
November 2012, we began connecting other operators’ wells to the plant, and we added inlet compression during
2013 in order to fully utilize the plant’s processing capability. Currently, there is inlet compression in place to
process 35 MMcf/d, and as of December 31, 2013 the plant was processing 18 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.
52
Hidden Bench/Tarpon Fields. Our Hidden Bench and Tarpon fields in McKenzie County, North Dakota target the
Bakken and Three Forks formations. In the fourth quarter of 2013, net production from the Hidden Bench/Tarpon
fields averaged 13.4 MBOE/d, representing a 31% increase from 10.2 MBOE/d in the third quarter of 2013. We
have also implemented our new completion design at our Hidden Bench field, utilizing cemented liners and plug-
and-perf technology, which has generated positive results. In addition, we have tested a high density drilling pilot
at our Hidden Bench field and are currently analyzing the resulting data. In the Tarpon field, we have drilled six
productive wells as of December 31, 2013. We had previously planned to drill most of the remaining Tarpon
development wells during 2013 but have experienced delays resulting from the U.S. Forest Service’s requirement to
perform an Environmental Assessment prior to the issuance of federal drilling permits for these wells. We
anticipate that we will be able to resume drilling in 2014, and we have begun permitting additional wells for 2014.
Missouri Breaks Field. Our Missouri Breaks field, which is located in Richland County, Montana and McKenzie
County, North Dakota, targets the Middle Bakken formation. In the fourth quarter of 2013, net production from the
Missouri Breaks field averaged 3.8 MBOE/d, representing a 31% increase from 2.9 MBOE/d in the third quarter of
2013. During 2013, we implemented our new completion design at this field, utilizing cemented liners, plug-and-
perf technology and higher sand volumes, and the new design has improved initial production rates. We have
drilled successful wells on the western, eastern and southern portions of our acreage in this area.
Redtail Field. Our Redtail field in the Denver Julesberg Basin (“DJ Basin”) in Weld County, Colorado targets the
Niobrara formation. In September 2013, we completed the acquisition of approximately 47,800 gross (32,100 net)
acres at our Redtail field, including interests in one producing well, which brings our total acreage position to
approximately 169,700 gross (122,300 net) acres in this play. 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. In 2014, we
plan to test a high-density pattern in the Niobrara “A”, “B” and “C” zones drilling 32 wells per spacing unit. As of
December 31, 2013, we had three drilling rigs operating in this area, and we plan to add another rig in 2014. We
implemented a new completion design in this field, utilizing larger proppant volumes, which has been yielding
improved production results, and we are currently evaluating the use of cemented liners in the Redtail field.
The associated gas produced with the Niobrara oil must be processed before being sold, and we are nearing
completion of the construction of a gas processing plant for this area. The plant’s initial inlet capacity will be 15
MMcf/d, and we plan to further expand the plant’s capacity to 60 MMcf/d in 2015. We anticipate having the plant
online in early 2014.
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 in one of the largest phases of our eight-phase project at North Ward Estes, and several
of the phases of the CO2 flood are continuing to respond. Net production from North Ward Estes averaged 9.8
MBOE/d for the fourth quarter of 2013, which represents a 2% increase from 9.6 MBOE/d in the third quarter of
2013. As of December 31, 2013, we were injecting approximately 390 MMcf/d of CO2 into the field, over half of
which is recycled.
Financing Highlights. In October 2013, our credit agreement borrowing base increased to $2.8 billion from $2.15
billion based on the collateral value of our proved reserves at the regular redetermination date. Of the $2.8 billion
borrowing base, $1.2 billion has been committed by lenders and is available for borrowing. The Company may
increase the maximum aggregate amount of commitments under the credit agreement up to the $2.8 billion
borrowing base if certain conditions are satisfied, including the consent of lenders participating in the increase. All
other terms of the credit agreement remain unchanged.
53
In October 2013, we paid $254.0 million to redeem all of our $250.0 million aggregate principal amount of 7%
Senior Subordinated Notes due February 2014 (the “2014 Notes”), which consisted of a redemption price of
101.595%. Concurrent with this redemption, we paid all accrued and unpaid interest on the 2014 Notes up to but
not including the redemption date. We financed the redemption of the 2014 Notes with proceeds from the issuance
of our Senior Notes, as discussed below. As a result of the redemption, we recognized a $4.4 million loss on early
extinguishment of debt, which consisted of a cash charge of $4.0 million related to the redemption premium on the
2014 Notes and a non-cash charge of $0.4 million related to the acceleration of unamortized debt issuance costs.
On September 12, 2013, we issued at par $1,100.0 million of 5% Senior Notes due March 2019 and $800.0 million
of 5.75% Senior Notes due March 2021. On September 26, 2013, we issued at 101% of par $400.0 million of
5.75% Senior Notes due March 2021. We used the net proceeds from these issuances to repay all of the debt
outstanding under our credit agreement, to fund our $260.0 million acquisition of Williston Basin assets and to
redeem on October 31, 2013 all $250.0 million aggregate principal amount of our outstanding 7% Senior
Subordinated Notes due February 2014. We plan to use the remaining net issuance proceeds for general corporate
purposes including capital expenditures.
2014 Exploration and Development Budget. Our current 2014 exploration and development (“E&D”) budget is
$2.7 billion, which we expect to fund substantially with net cash provided by our operating activities, cash on hand
and borrowings under our credit facility. This represents a slight increase from the $2,675.2 million incurred on
E&D (which consisted of exploration, development and acreage expenditures) during 2013, and based on this level
of capital spending, we are forecasting production growth over our 2013 production level of 34.3 MMBOE. We
expect to allocate $2,433.0 million of our 2014 budget to exploration and development activity, $116.0 million for
undeveloped acreage and $151.0 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 2014 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.
2014 Exploration and
Development Budget
(in millions)
Development Area
Northern Rockies ......................................................................................................................................
Central Rockies .........................................................................................................................................
Non-operated .............................................................................................................................................
CO2 EOR project (1) ...................................................................................................................................
Facilities ....................................................................................................................................................
Well work and other ..................................................................................................................................
Exploration (2) ............................................................................................................................................
Undeveloped acreage ................................................................................................................................
CO2 development (3) ..................................................................................................................................
Total .....................................................................................................................................................
_____________________
(1) 2014 planned capital expenditures at our CO2 EOR projects include $104.8 million for North Ward Estes CO2 purchases.
1,101.0
575.0
232.0
203.0
151.0
150.0
116.0
116.0
56.0
2,700.0
$
$
(2) Comprised primarily of exploration salaries, seismic activities, lease delay rentals and exploratory drilling.
(3) E&D expenditures for the development of organic CO2 reserves at our Bravo Dome field in New Mexico.
Acquisition and Divestiture Highlights. In October 2013, we completed the sale of approximately 45,000 gross
(32,200 net) acres, including our interests in certain producing oil and gas wells and undeveloped acreage, in our
Big Tex prospect located in the Delaware Basin for a cash purchase price of $152.0 million (subject to post-closing
adjustments), resulting in a pre-tax gain on sale of $13.0 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. The producing properties had estimated proved reserves of 1.1 MMBOE as of December 31, 2012,
54
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.
In September 2013, we completed the acquisition of approximately 39,300 gross (17,300 net) acres, including
interests in 121 producing oil and gas wells and undeveloped acreage, in the Williston Basin in Williams and
McKenzie counties of North Dakota and Roosevelt and Richland counties of Montana for an aggregate unadjusted
purchase price of $260.0 million.
In July 2013, we completed the sale of our interests in certain oil and gas producing properties located in our
enhanced oil recovery 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 $809.7 million after selling costs and post-closing adjustments,
resulting in a pre-tax gain on sale of $109.7 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.
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 (1) ..........................................................................
Total oil, NGL and natural gas sales .......................................
Average sales prices:
Oil (per Bbl) ............................................................................
Effect of oil hedges on average price (per Bbl) .......................
Oil net of hedging (per Bbl) ....................................................
Average NYMEX price (per Bbl) ...........................................
NGLs (per Bbl) .......................................................................
Natural gas (per Mcf) ..............................................................
Effect of natural gas hedges on average price (per Mcf) .........
Natural gas net of hedging (per Mcf) ......................................
Average NYMEX price (per Mcf) ..........................................
Cost and expenses (per BOE):
Lease operating expenses ........................................................
Production taxes ......................................................................
Depreciation, depletion and amortization expense ..................
General and administrative expenses ......................................
_____________________
(1) Before consideration of hedging transactions.
$
$
$
$
$
$
$
$
$
$
$
$
$
55
2013
Year Ended December 31,
2012
2011
27.0
2.8
26.9
34.3
2,443.7
114.0
108.8
2,666.5
90.39
(1.13)
89.26
98.00
40.41
4.04
-
4.04
3.66
12.53
6.56
25.96
4.02
23.1
2.8
25.8
30.2
1,940.5
108.9
88.3
2,137.7
83.86
(1.25)
82.61
94.19
39.36
3.42
0.06
3.48
2.79
12.46
5.68
22.67
3.59
$
$
$
$
$
$
$
$
$
$
$
$
$
18.3
2.1
26.4
24.8
1,621.5
108.6
130.0
1,860.1
88.61
(1.67)
86.94
95.14
52.38
4.92
0.04
4.96
4.04
12.33
5.62
18.89
3.43
$
$
$
$
$
$
$
$
$
$
$
$
$
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 $528.8 million to $2,666.5
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, Parshall, Missouri Breaks, Lewis &
Clark/Pronghorn and Redtail fields. During 2013, oil production from our Hidden Bench/Tarpon fields increased
1,770 MBbl, oil production from our Sanish and Parshall fields increased 1,100 MBbl, oil production from our
Missouri Breaks field increased 765 MBbl, oil production from our Lewis & Clark/Pronghorn fields increased 765
MBbl, and oil production from 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 the past twelve months, 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.
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 $809.7
million in cash, which resulted in a pre-tax gain on sale of $109.7 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
$152.0 million, which resulted in a pre-tax gain on sale of $13.0 million. There were no other property divestitures
resulting in a significant gain or loss on sale during 2013 or 2012.
Lease Operating Expenses. Our lease operating expenses (“LOE”) during 2013 were $430.2 million, a $53.8
million increase over the same period in 2012. Higher LOE in 2013 were primarily related to a $45.2 million
increase in the cost of oil field goods and services associated with net wells we added during the last twelve
months, and an $8.6 million increase in costs at the North Ward Estes CO2 processing facility due to increased
production from that field and higher related volumes 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 $225.4 million, a $53.8 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. Our
production tax rate of 8.5% for 2013 was greater than the rate for 2012 due to successful wells completed during
the past twelve months in North Dakota, which carries an 11.5% severance tax rate.
Depreciation, Depletion and Amortization. Our depreciation, depletion and amortization (“DD&A”) expense
increased $206.8 million in 2013 as compared to 2012. The components of our DD&A expense were as follows (in
thousands):
56
Year Ended December 31,
2013
2012
Depletion ..................................................................................................................
Depreciation .............................................................................................................
Accretion of asset retirement obligations .................................................................
Total ..................................................................................................................
$
$
876,208
4,700
10,608
891,516
$
$
673,789
3,672
7,263
684,724
DD&A increased in 2013 primarily due to $202.4 million in higher depletion expense between periods. Of this
increase, $105.4 million related to an increase in our overall production volumes during 2013 and $97.0 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 $2,349.8 million in drilling and development expenditures
during the past twelve months, which were partially offset by reserve additions during this same time period.
Exploration and Impairment Costs. Our exploration and impairment costs increased $286.2 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 $35.6 million during 2013 as compared to 2012 primarily due to an increase in
geological and geophysical (“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 $30.4 million during 2013 as compared to $16.6 million during 2012. Exploratory dry hole costs for 2013
totaled $28.7 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 $18.4 million. Delay lease rentals increased $7.1
million between periods, while geology-related general and administrative expenses increased $5.5 million.
Impairment expense in 2013 primarily related to (i) $267.1 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) $70.9 million of amortization
of leasehold costs associated with individually insignificant unproved properties and (iii) $18.9 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 $54.5 million, (ii) $46.9 million of
non-cash proved property impairment write-downs, mainly in the Rocky Mountains region and (iii) $6.1 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):
General and administrative expenses .......................................................................
Reimbursements and allocations ..............................................................................
General and administrative expense, net ...........................................................
$
$
57
Year Ended December 31,
2013
2012
199,943
251,593
(113,599)
(91,370)
137,994
108,573
$
$
General and administrative expense before reimbursements and allocations increased $51.7 million during 2013 as
compared to 2012 primarily due to higher employee compensation and an increase in accrued Production
Participation Plan (the “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 $28.5 million in 2013 as compared to 2012 due to personnel hired during the past twelve months, general
pay increases and higher stock compensation between periods. Accrued distributions under the Plan increased
$21.7 million between periods. This increase was primarily due to a one-time charge under the Plan of $21.7
million for the sale of the Postle Properties in the third quarter of 2013 and $8.6 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 $8.6 million at December 31,
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):
Year Ended December 31,
2013
2012
Senior Notes and Senior Subordinated Notes ..........................................................
Credit agreement .....................................................................................................
Amortization of debt issue costs and debt premium.................................................
Other ........................................................................................................................
Capitalized interest ...................................................................................................
Total ..................................................................................................................
$
$
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 $37.7 million between periods was mainly attributable to a $33.7 million
increase in the amount of interest incurred on our notes during 2013 as compared to 2012 due to our September
2013 issuance of $1,100.0 million of 5% Senior Notes due 2019 and $1,200.0 million of 5.75% Senior Notes due
2021. Our weighted average debt outstanding during 2013 was $2,263.0 million versus $1,576.6 million 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 $7.8 million for 2013 mainly due to the upward shift in the futures curve of forecasted
commodity prices (“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 $85.9 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.
See Item 7A, “Quantitative and Qualitative Disclosures about Market Risk,” for a list of our outstanding derivatives
as of February 6, 2014.
Income Tax Expense. Income tax expense totaled $205.9 million for 2013 as compared to $247.9 million of income
tax for 2012, a decrease of $42.0 million that was mainly related to $90.1 million in lower pre-tax income between
periods, as well as $10.5 million in state tax credits.
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.
58
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Oil, NGL and Natural Gas Sales. Our oil, NGL and natural gas sales revenue increased $277.6 million to $2,137.7
million in 2012 compared to 2011. Sales revenue is a function of oil, NGL and gas volumes sold and average
commodity prices realized. Our oil sales volumes increased 26%, and our NGL sales volumes increased 33%
between periods, while our natural gas sales volumes decreased 2%. The oil volume increase resulted primarily
from drilling success at our Sanish, Lewis & Clark/Pronghorn and Hidden Bench/Tarpon fields. During 2012, oil
production from our Sanish field increased 2,475 MBbl, while oil production from our Lewis & Clark/Pronghorn
fields increased 2,150 MBbl compared to 2011, and oil production from our Hidden Bench/Tarpon fields increased
495 MBbl over the same period in 2011. These production increases were partially offset by the Trust II divestiture
in March 2012, which divestiture negatively impacted oil production by 915 MBbl in 2012. Our NGL sales volume
increases generally relate to drilling success in the same areas as our oil volume increases, such as our Sanish,
Lewis & Clark/Pronghorn and Hidden Bench/Tarpon fields. The gas volume decline between periods was
primarily the result of normal field production decline across several of our areas, as well as the Trust II divestiture.
During 2012, gas production at our Flat Rock field decreased 1,795 MMcf, and gas production at our Canyon field
decreased 645 MMcf compared to 2011. In addition, the Trust II divestiture negatively impacted gas production by
1,760 MMcf during 2012. These gas volume declines were partially offset by increases in associated gas
production of 2,035 MMcf at our Lewis & Clark/Pronghorn fields and 1,500 MMcf at our Sanish field related to
new wells drilled and completed in these areas during the past twelve months.
Partially offsetting the above crude oil and NGL production-related increases in net revenue, were decreases in the
average sales prices realized for oil, NGLs and natural gas. Our average price for oil before the effects of hedging
decreased 5% in 2012 as compared to 2011, while our average price for NGLs decreased 25%, and our average
price for natural gas before the effects of hedging decreased 30% between periods.
Gain (Loss) on Hedging Activities. Our gain (loss) on hedging activities decreased $6.4 million in 2012 as
compared to 2011, and it consisted of the following (in thousands):
Year Ended December 31,
2012
2011
Gains (losses) reclassified from AOCI on de-designated hedges .........................
$
2,338
$
8,758
Effective April 1, 2009, we elected to de-designate all of our commodity derivative contracts that had been
previously designated as cash flow hedges, and we elected to discontinue all hedge accounting prospectively.
Accordingly, each period we reclassify from accumulated other comprehensive income (“AOCI”) into earnings
unrealized gains and losses (which were frozen in AOCI on the April 1, 2009 de-designation date) upon the
expiration of these de-designated crude oil hedges, and we report such non-cash unrealized gains and losses as gain
(loss) on hedging activities.
See Item 7A, “Quantitative and Qualitative Disclosures about Market Risk,” for a list of our outstanding derivatives
as of February 6, 2014.
Lease Operating Expenses. Our LOE during 2012 were $376.4 million, a $70.9 million increase over the same
period in 2011. Higher LOE in 2012 were primarily related to a $68.2 million increase in the cost of oil field goods
and services and gas plant operating expenses, both of which were associated with net wells we added during the
last twelve months. In addition, well workover activity increased to $81.9 million in 2012, as compared to $79.2
million in 2011, primarily due to a higher number of well workovers being conducted at our Sanish field and at our
CO2 project at North Ward Estes. This increase in workover expense was partially offset by a lower number of
workovers in our Western Texas district and at our Postle field.
Our lease operating expenses on a BOE basis only slightly increased during 2012. LOE per BOE amounted to
$12.46 during 2012, which was up from $12.33 per BOE during 2011. This slight increase was mainly due to the
59
higher costs of oil field goods and services, plant expenses and workover activity in 2012, as discussed above,
which were largely offset by higher overall production volumes between periods.
Production Taxes. Our production taxes during 2012 were $171.6 million, a $32.4 million increase over the same
period in 2011, which increase was primarily due to higher oil, NGL and natural gas sales between periods. 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 8.0% and 7.5% for 2012 and 2011, respectively. Our
production tax rate of 8.0% for 2012 was greater than the rate for 2011 due to successful wells completed during
the past twelve months in North Dakota, which carries an 11.5% severance tax rate.
Depreciation, Depletion and Amortization. Our DD&A expense increased $216.5 million in 2012 as compared to
2011. The components of our DD&A expense were as follows (in thousands):
Year Ended December 31,
2012
2011
Depletion ..................................................................................................................
Depreciation .............................................................................................................
Accretion of asset retirement obligations .................................................................
Total ..................................................................................................................
$
$
673,789
3,672
7,263
684,724
$
$
457,499
2,688
8,016
468,203
DD&A increased in 2012 primarily due to $216.3 million in higher depletion expense between periods. Of this
increase, $121.1 million related to the increase in our overall production volumes during 2012 and $95.2 million
related to a higher depletion rate between periods. On a BOE basis, our overall DD&A rate of $22.67 for 2012 was
20% higher than the rate of $18.89 for 2011 due to $2,031.6 million in drilling and development expenditures
during 2012, which were partially offset by reserve additions during this same time period.
Exploration and Impairment Costs. Our exploration and impairment costs increased $82.3 million in 2012 as
compared to 2011. The components of our exploration and impairment costs were as follows (in thousands):
Exploration ...............................................................................................................
Impairment ...............................................................................................................
Total ..................................................................................................................
Year Ended December 31,
2012
2011
$
$
59,117
107,855
166,972
$
$
45,861
38,783
84,644
Exploration costs increased $13.3 million during 2012 as compared to 2011 primarily due to higher exploratory dry
hole costs. Exploratory dry hole costs for 2012 totaled $18.4 million, primarily related to five exploratory dry holes
drilled in the Rocky Mountains and Permian Basin regions and in Michigan during 2012. During 2011, we drilled
three exploratory dry holes in the Rocky Mountains and Permian Basin regions and in Texas totaling $4.9 million.
Impairment expense in 2012 and 2011 primarily related to the amortization of leasehold costs associated with
individually insignificant unproved properties, and such amortization resulted in impairment expense of $54.5
million in 2012 as compared to $34.9 million in 2011. Also included in impairment expense for 2012 is $46.9
million in non-cash impairment charges for the partial write-down of proved properties, mainly in the Rocky
Mountains region, whose net book values exceeded their undiscounted future cash flows, whereas 2011 impairment
expense only included $3.2 million of non-cash proved property impairment write-downs.
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):
60
General and administrative expenses .......................................................................
Reimbursements and allocations ..............................................................................
General and administrative expense, net ...........................................................
$
$
Year Ended December 31,
2012
2011
153,341
199,943
(91,370)
(68,356)
108,573
84,985
$
$
General and administrative expense before reimbursements and allocations increased $46.6 million during 2012 as
compared to 2011 primarily due to higher employee compensation, an increase in accrued Plan distributions and a
$7.8 million increase in professional fees and information technology costs. Employee compensation increased
$21.7 million in 2012 as compared to 2011 due to personnel hired during the past twelve months, general pay
increases and higher stock compensation between periods. In addition, accrued distributions under the Plan
increased general and administrative expenses by $10.7 million when comparing 2012 to 2011. Of this increase in
general and administrative expenses related to Plan distributions, $8.6 million related to the Trust II net profits
interest divestiture, and $2.1 million related to a higher level of Plan net revenues (which have been reduced by
lease operating expenses and production taxes pursuant to the Plan formula).
The increase in reimbursements and allocations for 2012 was primarily caused by higher salary costs and a greater
number of field workers on Whiting-operated properties. Our general and administrative expenses as a percentage
of oil, NGL and natural gas sales remained consistent for 2012 and 2011 at about 5%.
Interest Expense. The components of our interest expense were as follows (in thousands):
Year Ended December 31,
2012
2011
Senior Subordinated Notes .......................................................................................
Credit agreement .....................................................................................................
Amortization of debt issue costs ..............................................................................
Other ........................................................................................................................
Capitalized interest ...................................................................................................
Total ..................................................................................................................
$
$
40,250
28,043
9,518
148
(2,749)
75,210
$
$
40,250
17,049
8,682
109
(3,574)
62,516
The increase in interest expense of $12.7 million between periods was mainly attributable to an $11.0 million
increase in the amount of interest incurred on our credit agreement during 2012 as compared to 2011. Our credit
agreement interest was higher in 2012 due to a greater amount of borrowings outstanding under this facility. Our
weighted average debt outstanding during 2012 was $1,576.6 million versus $1,151.5 million for 2011. Our
weighted average effective cash interest rate was 4.3% during 2012 compared to 5.0% during 2011.
Commodity Derivative (Gain) Loss, Net. All of our commodity derivative contracts as well as our embedded
derivatives are marked-to-market each quarter with fair value gains and losses recognized immediately in earnings,
as commodity derivative (gain) loss, net. Cash flow, however, is only impacted to the extent that settlements under
these contracts result in making or receiving a payment from the counterparty. Commodity derivative (gain) loss,
net amounted to a gain of $85.9 million for 2012 due to the significant downward shift in the forward price curve
for NYMEX crude oil from January 1, 2012 (or the 2012 date on which new contracts were entered into) to
December 31, 2012. Commodity derivative (gain) loss, net for 2011 resulted in a gain of $24.9 million due to a less
significant downward shift in the same forward price curve from January 1, 2011 (or the 2011 date on which those
prior year contracts were entered into) to December 31, 2011.
Income Tax Expense. Income tax expense totaled $247.9 million for 2012 as compared to $288.7 million of income
tax for 2011, a decrease of $40.8 million that was mainly related to $118.3 million in lower pre-tax income between
periods.
61
Our effective tax rates for 2012 and 2011 differ from the U.S. statutory income tax rate primarily due to the effects
of state income taxes and permanent taxable differences. Our overall effective tax rate only increased slightly
between periods from 37.0% for 2011 to 37.4% for 2012.
Liquidity and Capital Resources
Overview. At December 31, 2013, we had $699.5 million of cash on hand and $3,828.6 million of equity, while at
December 31, 2012, we had $44.8 million of cash on hand and $3,445.0 million 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 derivative contracts. Oil accounted for 79% and 77% of
our total production in 2013 and 2012, respectively. As a result, our operating cash flows are more sensitive to
fluctuations in the price for crude oil than to fluctuations in the price for NGLs and natural gas. As of February 6,
2014, we had derivative contracts covering the sale of approximately 47% of our forecasted 2014 oil production
volumes.
Cash Flows from 2013 Compared to 2012. During 2013, we generated $1,744.7 million of cash provided by
operating activities, an increase of $343.5 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 and cash interest expense in 2013 as
compared to 2012. Refer to “Results of Operations” for more information on the impact of prices and volumes on
revenues and for more information on increases and decreases in certain expenses during 2013.
During 2013, cash flows from operating activities plus $2,304.0 million of proceeds from the issuance of our Senior
Notes and $968.6 million of proceeds from the sale of properties were used to finance $2,349.8 million of drilling
and development expenditures, $1,200.0 million of net repayments under our credit agreement, $422.9 million of
oil and gas property acquisitions, $254.0 million for the redemption of our 7% Senior Subordinated Notes due
2014, $42.5 million in investing derivative purchases (net of cash receipts for settlements), $45.3 million for other
property and equipment and $29.7 million of debt issuance costs.
Cash Flows from 2012 Compared to 2011. During 2012, we generated $1,401.2 million of cash provided by
operating activities, an increase of $209.1 million from 2011. Cash provided by operating activities increased
primarily due to higher crude oil and NGL production volumes in 2012. This positive factor was partially offset by
lower realized sales prices for oil, NGLs and natural gas and lower natural gas production volumes in 2012, as well
as increased lease operating expenses, production taxes, general and administrative and cash interest expense
during 2012 as compared to 2011. See “Results of Operations” for more information on the impact of prices and
volumes on revenues and for more information on increases in certain expenses during 2012. Cash flows from
operating activities plus $420.0 million in net borrowings under our credit agreement, $322.3 million of proceeds
from the sale of Trust II units and $69.2 million of proceeds from the sale of oil and gas properties were used to
finance $2,050.0 million of drilling and development expenditures and $125.3 million of oil and gas property
acquisitions in 2012.
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 ..........................................................................
_____________________
62
2013
$ 2,172,462
346,812
155,918
$ 2,675,192
Year Ended December 31,
2012
$ 1,581,934
410,154
119,431
$ 2,111,519
2011
$ 1,364,324
366,637
109,193
$ 1,840,154
(1) For the year ended December 31, 2012, proceeds from the sale of the Belfield gas plant of $66.2 million have been
included as a reduction to expenditures in the Rocky Mountains region.
(2) For the years ended December 31, 2013 and 2012, amount includes $21.3 million and $10.8 million, respectively, related
to the development of CO2 reserves for use in our North Ward Estes field EOR project. We did not incur any such costs
during the year ended December 31, 2011.
(3) Other primarily includes oil and gas properties in Arkansas, Louisiana, Michigan, Oklahoma and Texas.
We continually evaluate our capital needs and compare them to our capital resources. Our current 2014 E&D
budget is $2.7 billion, which we expect to fund substantially with net cash provided by our operating activities, cash
on hand and borrowings under our credit facility. This represents a slight increase from the $2,675.2 million
incurred on exploration, development and acreage expenditures during 2013, and based on this level of capital
spending, we are forecasting production growth in 2014 over our 2013 production level of 34.3 MMBOE. We
expect to allocate $2,433.0 million of our 2014 budget to exploration and development activity, $116.0 million for
undeveloped acreage and $151.0 million for facilities. Although we have only budgeted $116.0 million for
undeveloped leasehold purchases in 2014, 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 $2.7 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. In addition, 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 Corporation (“Whiting Oil and Gas”), our wholly-owned subsidiary, has a
credit agreement with a syndicate of banks that as of December 31, 2013 had a borrowing base of $2.8 billion, of
which $1.2 billion has been committed by lenders and is available for borrowing. We may increase the maximum
aggregate amount of commitments under the credit agreement up to the $2.8 billion borrowing base if certain
conditions are satisfied, including the consent of lenders participating in the increase. As of December 31, 2013,
we had $1,197.0 million of available borrowing capacity, which was net of $3.0 million in letters of credit and no
borrowings outstanding.
The borrowing base under the credit agreement is determined at the discretion of the lenders, based on the collateral
value of our proved reserves that have been mortgaged to 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. A portion of the revolving credit facility in an aggregate
amount not to exceed $50.0 million may be used to issue letters of credit for the account of Whiting Oil and Gas or
other designated subsidiaries of ours. As of December 31, 2013, $47.0 million was available for additional letters
of credit under the agreement.
The credit agreement provides for interest only payments until April 2016, when the agreement expires and all
outstanding borrowings are due. Interest accrues at our option at either (i) a base rate for a base rate loan plus the
margin in the table below, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus
0.50% or an adjusted LIBOR rate plus 1.00%, or (ii) an adjusted LIBOR rate for a Eurodollar loan plus the margin
in the table below. Additionally, we also incur commitment fees as set forth in the table below on the unused
portion of the lesser of the aggregate commitments of the lenders or the borrowing base.
63
Ratio of Outstanding Borrowings to Borrowing Base
Less than 0.25 to 1.0
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0
Greater than or equal to 0.90 to 1.0
Applicable
Margin for Base
Rate Loans
Applicable
Margin for
Eurodollar Loans Commitment Fee
0.50%
0.75%
1.00%
1.25%
1.50%
1.50%
1.75%
2.00%
2.25%
2.50%
0.375%
0.375%
0.50%
0.50%
0.50%
The credit agreement contains restrictive covenants that may limit our ability to, among other things, incur
additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging
contracts, incur liens and engage in certain other transactions without the prior consent of our lenders. Except for
limited exceptions, 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, 2013.
For further information on the interest rates and loan security related to our credit agreement, refer to the Long-
Term Debt footnote in the notes to consolidated financial statements.
Senior Notes and Senior Subordinated Notes. In September 2013, we issued at par $1,100.0 million of 5% Senior
Notes due March 2019 and $800.0 million of 5.75% Senior Notes due March 2021, and also in September 2013, we
issued at 101% of par an additional $400.0 million of 5.75% Senior Notes due March 2021. In September 2010, we
issued at par $350.0 million of 6.5% Senior Subordinated Notes due October 2018. In October 2005, we issued at
par $250.0 million of 7% Senior Subordinated Notes due February 2014 (“2014 Notes”). In October 2013, we
redeemed all $250.0 million of the outstanding 2014 Notes.
The indentures governing the notes restrict us from incurring additional indebtedness, subject to certain exceptions,
unless our fixed charge coverage ratio (as defined in the indentures) is at least 2.0 to 1. If we were in violation of
this covenant, then we may not be able to incur additional indebtedness, including under Whiting Oil and Gas
Corporation’s credit agreement. Additionally, the indentures governing the notes contain restrictive covenants that
may limit our ability to, among other things, pay cash dividends, redeem or repurchase our capital stock or our
subordinated debt, make investments or issue preferred stock, sell assets, consolidate, merge or transfer all or
substantially all of the assets of ours and our restricted subsidiaries taken as a whole and enter into hedging
contracts. These covenants may potentially limit the discretion of our management in certain respects. We were in
compliance with these covenants as of December 31, 2013. However, a substantial or extended decline in oil, NGL
or natural gas prices may adversely affect our ability to comply with these covenants in the future.
Shelf Registration Statement. We have on file with the SEC a universal shelf registration statement to allow us to
offer an indeterminate amount of securities in the future. Under the registration statement, we may periodically
offer from time to time debt securities, common stock, preferred stock, warrants and other securities or any
combination of such securities in amounts, prices and on terms announced when and if the securities are offered.
The specifics of any future offerings, along with the use of proceeds of any securities offered, will be described in
detail in a prospectus supplement at the time of any such offering.
Contractual Obligations and Commitments
Schedule of Contractual Obligations. The table below does not include our Production Participation Plan liability
of $160.8 million (which amount comprises both the long and short-term portions of this obligation) as of
64
December 31, 2013, since we cannot determine with accuracy the timing or amounts of future payments other than
the short-term portion of $73.3 million. The table below also does not include any penalties that may be incurred
under our physical delivery contracts, since we cannot predict with accuracy whether we will be subject to any such
penalties or the amount and timing of any such penalties if incurred. The following table summarizes our
obligations and commitments as of December 31, 2013 to make future payments under certain contracts,
aggregated by category of contractual obligation, for specified time periods (in thousands):
Payments due by period
$
Total
Less than 1
year
Contractual Obligations
Long-term debt (1) ........................................................ $ 2,650,000
Cash interest expense on debt (2) .................................
891,896
Derivative contract liability fair value (3) .....................
3,482
Asset retirement obligations (4) ....................................
126,148
Tax sharing liability (5) ................................................
23,856
Purchase obligations (6) ................................................
632,627
Drilling rig contracts (7) ...............................................
137,896
Operating leases (8) ......................................................
28,791
44,966
Construction and drilling contract (9) ...........................
Total ........................................................................ $ 4,539,662
_____________________
(1) Long-term debt consists of the principal amounts of the 6.5% Senior Subordinated Notes due 2018, the 5% Senior Notes
3-5 years
$ 350,000
287,813
-
21,642
-
111,854
-
9,879
11,000
$ 792,188
-
146,750
3,482
9,706
23,856
82,633
87,610
6,279
31,066
$ 391,382
1-3 years
-
293,500
-
19,243
-
227,531
50,286
11,259
2,900
604,719
More than 5
years
$ 2,300,000
163,833
-
75,557
-
210,609
-
1,374
-
$ 2,751,373
$
$
due 2019 and the 5.75% Senior Notes due 2021.
(2) Cash interest expense on the 6.5% Senior Subordinated Notes due 2018, the 5% Senior Notes due 2019 and the 5.75%
Senior Notes due 2021 is estimated assuming no principal repayment until the due dates of the instruments. No cash
interest expense is assumed on the credit facility as there were no borrowings outstanding as of December 31, 2013.
(3) The above derivative obligation at December 31, 2013 primarily consists of (i) a $3.1 million fair value liability for
derivative contracts we have entered into on our own behalf, primarily in the form of costless collars, to hedge our
exposure to crude oil price fluctuations and (ii) a $0.4 million payable to Trust II for derivative contracts that we have
entered into but have in turn conveyed to Trust II (although these derivatives are in a fair value asset position at quarter
end, 90% of such derivative assets are due to Trust II under the terms of the conveyance). With respect to only a portion
of our open derivative contracts at December 31, 2013 with certain counterparties, the forward price curve for crude oil
generally exceeded the price curve that was in effect when these contracts were entered into, resulting in a derivative fair
value liability. If current market prices are higher than a collar’s price ceiling when the cash settlement amount is
calculated, we are required to pay the contract counterparties. The ultimate settlement amounts under our derivative
contracts are unknown, however, as they are subject to continuing market risk and commodity price volatility.
(4) 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.
(5) Amount shown represents the expected payment due to Alliant Energy based on projected future income tax benefits
attributable to an increase in our tax bases. As a result of the Tax Separation and Indemnification Agreement signed with
Alliant Energy, the increased tax bases are expected to result in increased future income tax deductions and, accordingly,
may reduce income taxes otherwise payable by us. Under this agreement, we have agreed to pay Alliant Energy 90% of
the future tax benefits we realize annually as a result of this step up in tax basis. In 2014, we are obligated to pay Alliant
Energy the present value of the remaining tax benefits, which assumes that all such tax benefits will be realized in future
years.
(6) We have three take-or-pay purchase agreements, one agreement expiring in December 2014, one agreement expiring in
December 2017 and one agreement expiring in December 2029, whereby we have committed to buy certain volumes of
CO2 for use in our North Ward Estes EOR project in Texas. The purchase agreements are with two different suppliers.
Under the terms of the agreements, we are obligated to purchase a minimum daily volume of CO2 (as calculated on an
annual basis) or else pay for any deficiencies at the price in effect when the minimum delivery was to have occurred. In
addition, we have one ship-or-pay agreement expiring in December 2017, whereby we have committed to transport a
minimum daily volume of CO2 via a certain pipeline or else pay for any deficiencies at a price stipulated in the contract.
The CO2 volumes planned for use in the EOR project in the North Ward Estes field currently exceed the minimum daily
65
volumes specified in all of these agreements. Therefore, we expect to avoid any payments for deficiencies. The
purchasing obligations reported above represent our minimum financial commitment pursuant to the terms of these
contracts. However, our actual expenditures under these contracts are expected to exceed the minimum commitments
presented above.
(7) We currently have 12 drilling rigs under long-term contract, of which six drilling rigs expire in 2014, four in 2015 and
two in 2016. All of these rigs are operating in the Rocky Mountains region. As of December 31, 2013, early termination
of the remaining contracts would require termination penalties of $101.1 million, which would be in lieu of paying the
remaining drilling commitments of $137.9 million. No other drilling rigs working for us are currently under long-term
contracts or contracts that cannot be terminated at the end of the well that is currently being drilled. Due to the short-term
and indeterminate nature of the time remaining on rigs drilling on a well-by-well basis, such obligations have not been
included in this table.
(8) We lease 172,400 square feet of administrative office space in Denver, Colorado under an operating lease arrangement
expiring in 2018, 47,900 square feet of office space in Midland, Texas expiring in 2020 and 20,000 square feet of office
space in Dickinson, North Dakota expiring in 2016. In addition, we entered into a lease for several residential apartments
in Watford City and Dickinson, North Dakota under an operating lease agreement expiring in 2015.
(9) We have a contractual obligation of up to $51.4 million to fund the construction of certain facilities and field
infrastructure and the drilling of forty-six CO2 wells in our Bravo Dome field. If we fail to spend the required amounts
by the dates set forth in the agreement, we will be required to pay the remaining unspent capital expenditures as
liquidated damages. However, we expect to fulfill our obligations under this contract and thereby avoid any payments for
deficiencies. We do not have any volumetric CO2 delivery or supply commitments associated with this contract.
Based on current oil and natural gas prices and anticipated levels of production, we believe that the estimated net
Based on current oil and natural gas prices and anticipated levels of production, we believe that the estimated net
cash generated from operations, together with cash on hand and amounts available under our credit agreement, will
be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations
and exploration and development activities.
New Accounting Pronouncements
For further information on the effects of recently adopted accounting pronouncements and the potential effects of
new accounting pronouncements, refer to the 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, asset retirement
66
obligations and our long-term Production Participation Plan liability. Proved oil and gas reserves are those
quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable
certainty to be economically producible—from a given date forward, from known reservoirs and under existing
economic conditions, operating methods, and government regulations—prior to the time at which contracts
providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of
whether deterministic or probabilistic methods are used for the estimation. Reserve quantities and future cash flows
included in this report are prepared in accordance with guidelines established by the SEC and 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,
2013. Estimates prepared by others may be higher or lower than our estimates. Because these estimates depend on
many assumptions, all of which may differ substantially from actual results, reserve estimates may be different
from the quantities of oil and gas that are ultimately recovered. We continually make revisions to reserve estimates
throughout the year as additional information becomes available. We make changes to depletion rates, impairment
calculations (when impairment indicators arise) and our Production Participation Plan liability in the same period
that changes to reserve estimates are made.
Depreciation, Depletion and Amortization. Our rate of recording DD&A is dependent upon our estimates of total
proved and proved developed reserves, which estimates incorporate various assumptions and future projections. If
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.
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
67
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. We have a Production Participation Plan (the “Plan”) in which all employees
participate. Each year, a deemed economic interest in all oil and gas properties acquired or developed during the
year is contributed to the Plan. The Compensation Committee of the Board of Directors, in its discretion for each
Plan year, allocates a percentage of future net income (defined as gross revenues less production taxes, royalties
and direct lease operating expenses) attributable to such properties to Plan participants. Once contributed and
allocated, the interests (not legally conveyed) are fixed for each Plan year. The short-term obligation related to the
Plan is included in the accrued liabilities and other line item in our consolidated balance sheets. This obligation is
based on cash flows during the year and is paid annually in cash after year end. The calculation of this liability
depends in part on our estimates of accrued revenues and costs as of the end of each reporting period as discussed
below under “Revenue Recognition.” The vested long-term obligation related to the Plan is the “Production
Participation Plan liability” line item in the consolidated balance sheets. This liability is derived primarily from
reserve report estimates, which as discussed above, are subject to revision as more information becomes available.
Variances between estimates used to calculate liabilities related to the Plan and actual sales, costs and production
data are integrated into the liability calculations in the period identified. A 10% increase to the pricing assumptions
used in the measurement of this liability at December 31, 2013 would have decreased net income before taxes by
$15.6 million in 2013.
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, which are generally placed with major financial institutions.
All derivative instruments are recorded on the consolidated balance sheet at fair value, other than the derivative
instruments that meet the “normal purchase normal sales” exclusion. Changes in the derivatives’ fair value are
recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow
hedges, the fair value gain or loss on the derivative is deferred in accumulated other comprehensive income (loss)
to the extent the hedge is effective and is reclassified to 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 using industry-standard models that consider various assumptions, including quoted
forward prices for commodities, time value, volatility factors and contractual prices for the underlying instruments,
as well as other relevant economic measures. The discount rate used in the fair values of these instruments includes
a measure of nonperformance risk by the counterparty or us, as appropriate. We utilize the counterparties’
valuations to assess the reasonableness of our valuations. The values we report in our financial statements change
as these estimates are revised to reflect changes in market conditions (particularly those for oil and natural gas
futures) or other factors, many of which are beyond our control.
The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial
terms of such transactions. We evaluate the ability of our counterparties to perform at the inception of a hedging
relationship and on a periodic basis as appropriate.
Income Taxes and Uncertain Tax Positions. We provide for income taxes in accordance with FASB ASC Topic
740, Income Taxes (“ASC 740”). We record deferred tax assets and liabilities to account for the expected future tax
68
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 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. In the past, our business has grown through acquisitions, and our business
strategy is to continue to pursue acquisitions as opportunities arise. We have accounted for all of our business
combinations to date using the purchase method, which is the only method permitted under FASB ASC Topic 805,
Business Combinations, and involves the use of significant judgment.
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. The
consideration we have paid to acquire these properties or companies was entirely allocated to the fair value of the
assets acquired and liabilities assumed at the time of acquisition. Consequently, there was no goodwill nor any
bargain purchase gains recognized on any of our business combinations.
69
Effects of Inflation and Pricing
We experienced increased costs during 2012 and 2013 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; 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; impacts to financial statements as a result of impairment write-downs; risks related to our level of
indebtedness and periodic redeterminations of the borrowing base under our credit agreement; our ability to
generate sufficient cash flows from operations to meet the internally funded portion of our capital expenditures
budget; our ability to obtain external capital to finance exploration and development operations and acquisitions;
federal and state initiatives relating to the regulation of hydraulic 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;
our ability to successfully complete potential asset dispositions and the risks related thereto; the impacts of hedging
on our results of operations; failure of our properties to yield oil or gas in commercially viable quantities; uninsured
or underinsured losses resulting from our oil and gas operations; our inability to access oil and gas markets due to
market conditions or operational impediments; the impact and costs of compliance with laws and regulations
governing our oil and gas operations; our ability to replace our oil and natural gas reserves; any loss of our senior
management or technical personnel; competition in the oil and gas industry in the regions in which we operate;
risks arising out of our hedging transactions; and other risks described under the caption “Risk Factors” in this
Annual Report on Form 10-K. We assume no obligation, and disclaim any duty, to update the forward-looking
statements in this Annual Report on Form 10-K.
70
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 2013 production,
our income before income taxes for 2013 would have moved up or down $244.4 million for each 10% change in oil
prices per Bbl, $11.4 million for each 10% change in NGL prices per Bbl and $10.9 million for each 10% change in
natural gas prices per Mcf.
We periodically enter into derivative contracts to achieve a more predictable cash flow by reducing our exposure to
oil and natural gas price volatility. Our derivative contracts have traditionally been costless collars, although we
evaluate other forms of derivative instruments as well. Currently, we do not apply hedge accounting, and therefore all
changes in commodity derivative fair values are recorded immediately to earnings. For derivative instruments that
were previously designated as cash flow hedges in periods prior to April 1, 2009, the effective portion of derivative
gains and losses was reclassified from accumulated other comprehensive income into earnings in the same period that
the forecasted transactions effected income.
Commodity Derivative Contracts—Our outstanding hedges as of February 6, 2014 are summarized below:
Whiting Petroleum Corporation
Derivative
Instrument
Three-way collars (1)
Commodity
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Period
01/2014
02/2014
03/2014
04/2014 to 06/2014
07/2014 to 09/2014
10/2014 to 12/2014
Monthly Volume
(Bbl)
1,200,000
1,280,000
1,280,000
1,280,000
1,280,000
1,280,000
Weighted Average
NYMEX Floor/Ceiling
$71.00/$85.00/$103.56
$70.94/$85.00/$103.34
$70.94/$85.00/$103.34
$70.94/$85.00/$103.34
$70.94/$85.00/$103.34
$70.94/$85.00/$103.34
_____________________
(1) A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call establishes a
maximum price (ceiling) we will receive for the volumes under contract. The purchased put establishes a minimum price
(floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be NYMEX
plus the difference between the purchased put and the sold put strike price.
Fixed-price Natural Gas Contracts. We have various fixed-price gas sales contracts with end users for a portion of
the natural gas we produce in Colorado and Utah. Our future production volumes projected to be sold under these
fixed-price contracts as of February 6, 2014 are summarized below:
Commodity
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Period
01/2014 to 03/2014
04/2014 to 06/2014
07/2014 to 09/2014
10/2014 to 12/2014
Average Monthly Volume
(MMBtu)
330,000
333,667
337,333
337,333
Weighted Average Price
Per MMBtu
$5.49
$5.49
$5.49
$5.49
Fixed-differential Crude Oil Contract. We have a fixed-differential crude oil sales contract with a purchaser for
crude oil we plan to produce in Colorado from the Niobrara. The table below summarizes the future production
volumes to be sold under this contract as of February 6, 2014 at a price equal to NYMEX less a fixed-differential of
$4.75 per Bbl:
71
Commodity
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Period
01/2015 to 12/2015
01/2016 to 12/2016
01/2017 to 12/2017
01/2018 to 12/2018
01/2019 to 12/2019
Average Monthly Volume
(Bbl)
760,417
915,000
1,064,583
1,216,667
1,368,750
Commodity Derivatives Conveyed to Whiting USA Trust II. In connection with our conveyance on March 28, 2012
of a term net profits interest to Whiting USA Trust II (“Trust II”), the rights to any future hedge payments we make
or receive on certain of our derivative contracts, representing 493 MBbl of crude oil in 2014, have been conveyed
to Trust II, and therefore such payments will be included in Trust II’s calculation of net proceeds. Under the terms
of the aforementioned conveyance, we retain 10% of the net proceeds from the underlying properties. This results
in third-party public holders of Trust II units receiving 90%, while we retain 10%, of the future economic results of
such hedges. No additional hedges are allowed to be placed on Trust II assets.
The table below summarizes all of the outstanding costless collars that we entered into and then in turn conveyed,
as described in the preceding paragraph, to Trust II (of which we retain 10% of the future economic results and
third-party public holders of Trust II units receive 90% of the future economic results):
Conveyed to Whiting USA Trust II
Derivative
Instrument
Collars
Commodity
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Period
01/2014 to 03/2014
04/2014 to 06/2014
07/2014 to 09/2014
10/2014 to 12/2014
Monthly Volume
(Bbl)
42,500
41,500
40,600
39,700
NYMEX Floor/Ceiling
$80.00/$122.50
$80.00/$122.50
$80.00/$122.50
$80.00/$122.50
The collared hedges shown in the tables above have the effect of providing a protective floor while allowing us to
share in upward pricing movements. Consequently, while these hedges are designed to decrease our exposure to
price decreases, they also have the effect of limiting the benefit of price increases above the ceiling. For the crude
oil collars outstanding as of December 31, 2013, a hypothetical upward or downward shift of 10% per Bbl in the
NYMEX forward curve as of December 31, 2013 would cause a decrease or increase, respectively, of $74.6 million
in our commodity derivative (gain) loss.
Embedded Commodity Derivative Contracts—The price we pay for oil field products and services significantly
impacts our profitability, reserve estimates, access to capital and future growth rate. Typically, as prices for oil and
natural gas increase, so do all associated costs. In May 2011, we entered into a long-term contract to purchase CO2
from 2015 through 2029 for use in the EOR project at our North Ward Estes field in Texas. This contract contains
a price adjustment clause that is linked to changes in NYMEX crude oil prices, in order to reduce our exposure to
paying higher than the market rates for CO2 in a climate of declining oil prices. We have determined that the
portion of this contract linked to NYMEX oil prices is not clearly and closely related to the host contract, and we
have therefore bifurcated this embedded pricing feature from its host contract and reflected it at fair value in the
consolidated financial statements. This embedded commodity derivative contract has not been designated as a
hedge, and therefore all changes in fair value since inception have been recorded immediately to earnings. The
price per Mcf of CO2 purchased under this agreement increases or decreases as the average price of NYMEX crude
oil likewise increases or decreases. For this embedded commodity derivative contract, a hypothetical upward or
downward shift of 10% per Bbl in the NYMEX forward curve as of December 31, 2013 would cause a decrease or
increase, respectively, of $13.3 million in our commodity derivative (gain) loss.
72
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,
2013, we had no outstanding principal balance under our credit agreement, and therefore, a change in interest rates
would not affect the amount of interest we would pay under our credit agreement. 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.
73
Item 8.
Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm ............................................................................... 75
Consolidated Balance Sheets as of December 31, 2013 and 2012 ..................................................................... 76
Consolidated Statements of Income for the Years Ended December 31, 2013, 2012 and 2011 ........................ 77
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2013,
2012 and 2011 ............................................................................................................................................ 78
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011 .................. 79
Consolidated Statements of Equity for the Years Ended December 31, 2013, 2012 and 2011 .......................... 81
Notes to Consolidated Financial Statements....................................................................................................... 82
74
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, 2013 and 2012, 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, 2013.
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, 2013 and 2012, and the results of their
operations and their cash flows for each of the three years in the period ended December 31, 2013, 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, 2013, based on the
criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring
Organizations of the Treadway Commission and our report dated February 27, 2014 expressed an unqualified
opinion on the Company's internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 27, 2014
75
WHITING PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)
ASSETS
Current assets:
Cash and cash equivalents ................................................................................................
Accounts receivable trade, net ..........................................................................................
Prepaid expenses and other ..............................................................................................
Total current assets .....................................................................................................
$
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 ..............................................................................
Debt issuance costs...............................................................................................................
Other long-term assets ..........................................................................................................
TOTAL ASSETS ................................................................................................................
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable trade ....................................................................................................
Accrued capital expenditures ...........................................................................................
Accrued liabilities and other.............................................................................................
Revenues and royalties payable .......................................................................................
Taxes payable ...................................................................................................................
Accrued interest ...............................................................................................................
Derivative liabilities .........................................................................................................
Deferred income taxes ......................................................................................................
Total current liabilities ................................................................................................
Long-term debt .....................................................................................................................
Deferred income taxes ..........................................................................................................
Derivative liabilities .............................................................................................................
Production Participation Plan liability ..................................................................................
Asset retirement obligations .................................................................................................
Deferred gain on sale ............................................................................................................
Other long-term liabilities ....................................................................................................
Total liabilities ............................................................................................................
Commitments and contingencies ..........................................................................................
Equity:
Preferred stock, $0.001 par value, 5,000,000 shares authorized; 6.25% convertible
perpetual preferred stock, no shares authorized, issued or outstanding as of
December 31, 2013 and 172,391 shares issued and outstanding as of December 31,
2012..............................................................................................................................
Common stock, $0.001 par value, 300,000,000 shares authorized; 120,101,555 issued
and 118,657,245 outstanding as of December 31, 2013 and 118,582,477 issued and
117,631,451 outstanding as of December 31, 2012 ......................................................
Additional paid-in capital .................................................................................................
Accumulated other comprehensive loss ...........................................................................
Retained earnings .............................................................................................................
Total Whiting shareholders’ equity .............................................................................
Noncontrolling interest ............................................................................................................
Total equity .................................................................................................................
TOTAL LIABILITIES AND EQUITY ............................................................................
See notes to consolidated financial statements.
$
$
$
76
December 31,
2013
2012
699,460
341,177
28,981
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
214,109
198,558
50,052
44,405
3,482
648
777,685
2,653,834
1,278,030
-
87,503
116,442
79,065
4,212
4,996,771
$
$
$
44,800
318,265
21,347
384,412
9,211,998
141,738
9,353,736
(2,590,203)
6,763,533
28,748
95,726
7,272,419
131,370
110,663
170,207
149,692
33,283
10,415
21,955
9,394
636,979
1,800,000
1,063,681
1,678
94,483
86,179
110,395
25,852
3,819,247
-
-
120
1,583,542
-
2,244,905
3,828,567
8,132
3,836,699
8,833,470
119
1,566,717
(1,236)
1,879,388
3,444,988
8,184
3,453,172
7,272,419
$
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(in thousands, except per share data)
Year Ended December 31,
2012
2011
2013
REVENUES AND OTHER INCOME:
Oil, NGL and natural gas sales .............................................................. $ 2,666,549
(1,958)
Gain (loss) on hedging activities ............................................................
31,737
Amortization of deferred gain on sale ....................................................
128,648
Gain on sale of properties ......................................................................
3,409
Interest income and other .......................................................................
2,828,385
Total revenues and other income ....................................................
$ 2,137,714
2,338
29,458
3,423
519
2,173,452
$ 1,860,146
8,758
13,937
16,313
468
1,899,622
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 .................................................................
430,221
225,403
891,516
453,210
137,994
112,936
4,412
(6,980)
7,802
2,256,514
376,424
171,625
684,724
166,972
108,573
75,210
-
13,824
(85,911)
1,511,441
305,487
139,190
468,203
84,644
84,985
62,516
-
(865)
(24,857)
1,119,303
INCOME BEFORE INCOME TAXES ....................................................
571,871
662,011
780,319
INCOME TAX EXPENSE (BENEFIT):
Current ...................................................................................................
Deferred .................................................................................................
Total income tax expense ................................................................
986
204,882
205,868
NET INCOME .............................................................................................
Net loss attributable to noncontrolling interest ......................................
366,003
52
NET INCOME AVAILABLE TO SHAREHOLDERS ...........................
Preferred stock dividends .......................................................................
366,055
(538)
(669)
248,581
247,912
414,099
90
414,189
(1,077)
3,853
284,838
288,691
491,628
59
491,687
(1,077)
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS ....... $
365,517
$
413,112
$
490,610
EARNINGS PER COMMON SHARE:
Basic ....................................................................................................... $
Diluted ................................................................................................... $
3.09
3.06
$
$
3.51
3.48
$
$
4.18
4.14
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic .......................................................................................................
Diluted ...................................................................................................
118,260
119,588
117,601
119,028
117,345
118,668
See notes to consolidated financial statements.
77
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in thousands)
Year Ended December 31,
2012
2011
2013
NET INCOME .............................................................................................
$
366,003
$
414,099
$
491,628
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 ...................
1,236
1,236
367,239
52
(1,476)
(1,476)
412,623
90
(5,528)
(5,528)
486,100
59
COMPREHENSIVE INCOME ATTRIBUTABLE TO WHITING ......
$
367,291
$
412,713
$
486,159
(1) Presented net of income tax expense of $722 for the year ended December 31, 2013 and income tax benefits of $862 and
$3,230 for the years ended December 31, 2012 and 2011, respectively.
(2) These gain (loss) 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.
78
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) and losses ...............................
Other, net .............................................................................................
Changes in current assets and liabilities:
Accounts receivable trade ....................................................................
Prepaid expenses and other..................................................................
Accounts payable trade and accrued liabilities ....................................
Revenues and royalties payable ...........................................................
Taxes payable ......................................................................................
Net cash provided by operating activities ........................................
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and development capital expenditures .......................................
Acquisition of oil and gas properties.......................................................
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 .......................
Long-term borrowings under credit agreement .......................................
Repayments of long-term borrowings under credit agreement ...............
Debt issuance costs .................................................................................
Restricted stock used for tax withholdings .............................................
Repayments to Alliant Energy Corporation ............................................
Preferred stock dividends paid ................................................................
Contributions from noncontrolling interest .............................................
Net cash provided by financing activities ........................................ $
See notes to consolidated financial statements.
Year Ended December 31,
2012
2013
2011
366,003
$
414,099
$
491,628
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)
(29,690)
(5,611)
(1,759)
(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)
(2,807)
(5,695)
(2,329)
(1,077)
-
408,092
$
468,203
284,838
8,682
13,509
(13,937)
(16,313)
38,783
4,924
-
(865)
(63,093)
(13,512)
(62,802)
(3,771)
33,135
21,770
904
1,192,083
(1,554,271)
(193,809)
(56,232)
69,276
-
(25,000)
-
-
(1,760,036)
-
-
-
1,760,000
(1,180,000)
(5,691)
(9,049)
(1,871)
(1,077)
2,500
564,812
(Continued)
$
79
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,
2012
2013
2011
654,660
$
28,989
$
(3,141)
Beginning of period ................................................................................
End of period ........................................................................................... $
44,800
699,460
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Income taxes paid (refunded), net ........................................................... $
Interest paid, net of amounts capitalized ................................................. $
3,681
66,541
15,811
44,800
(268)
68,005
$
$
$
18,952
15,811
4,065
53,761
$
$
$
NONCASH INVESTING ACTIVITIES:
Accrued capital expenditures .................................................................. $
158,739
$
110,663
$
142,827
NONCASH FINANCING ACTIVITIES:
Contributions from noncontrolling interest ............................................. $
-
$
-
$
5,833
See notes to consolidated financial statements.
(Concluded)
80
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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; (6) income taxes; (7) Production Participation Plan and other accrued liabilities; (8)
valuation of derivative instruments; and (9) accrued revenue and related receivables. Although
management believes these estimates are reasonable, actual results could differ from these estimates.
Cash and Cash Equivalents—Cash equivalents consist of demand deposits and highly liquid investments
which have an original maturity of three months or less.
Accounts Receivable Trade—Whiting’s accounts receivable trade consist mainly of receivables from oil
and gas purchasers and joint interest owners on properties the Company operates. For receivables from
joint interest owners, Whiting typically has the ability to withhold future revenue disbursements to recover
any non-payment of joint interest billings. Generally, the Company’s oil and gas receivables are collected
within two months, and to date, the Company has had minimal bad debts.
The Company routinely assesses the recoverability of all material trade and other receivables to determine
their collectability. At December 31, 2013 and 2012, the Company had an allowance for doubtful accounts
of $4.2 million and $3.9 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
82
developed reserves, respectively. Costs of drilling exploratory wells are initially capitalized but are
charged to expense if the well is determined to be unsuccessful.
The Company assesses its proved oil and gas properties for impairment whenever events or circumstances
indicate that the carrying value of the assets may not be recoverable. The impairment test compares
undiscounted future net cash flows to the assets’ net book value. If the net capitalized costs exceed future
net cash flows, then the cost of the property is written down to fair value. Fair value for oil and gas
properties is generally determined based on discounted future net cash flows. Impairment expense for
proved properties is reported in exploration and impairment expense.
Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of
depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and
amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a
gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable
property are recognized to earnings.
Interest cost is capitalized as a component of property cost for development projects that require greater
than six months to be readied for their intended use. During 2013, 2012 and 2011, the Company
capitalized interest of $1.5 million, $2.7 million and $3.6 million, respectively.
Unproved. Unproved properties consist of costs to acquire undeveloped leases as well as costs to acquire
unproved reserves. Undeveloped lease costs and unproved reserve acquisitions are capitalized, and
individually insignificant unproved properties are amortized on a composite basis, based on past success,
past experience and average lease-term lives. The Company evaluates significant unproved properties for
impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or
future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved
property costs are reclassified to proved properties and depleted on a unit-of-production basis. Impairment
expense for unproved properties is reported in exploration and impairment expense.
Exploratory. Geological and geophysical costs, including exploratory seismic studies, and the costs of
carrying and retaining unproved acreage are expensed as incurred. Costs of seismic studies that are utilized
in development drilling within an area of proved reserves are capitalized as development costs. Amounts
of seismic costs capitalized are based on only those blocks of data used in determining development well
locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling,
those seismic costs are proportionately allocated between development costs and exploration expense.
Costs of drilling exploratory wells are initially capitalized, pending determination of whether the well has
found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well
and other associated costs are charged to expense. Cost incurred for exploratory wells that find reserves,
which cannot yet be classified as proved, continue to be capitalized if (a) the well has found a sufficient
quantity of reserves to justify completion as a producing well, and (b) the Company is making sufficient
progress assessing the reserves and the economic and operating viability of the project. If either condition
is not met, or if the Company obtains information that raises substantial doubt about the economic or
operational viability of the project, the exploratory well costs, net of any salvage value, are expensed.
Enhanced recovery activities. The Company carries out tertiary recovery methods on certain of its oil and
gas properties in order to recover additional hydrocarbons that are not recoverable from primary or
secondary recovery methods. Acquisition costs of tertiary injectants, such as purchased CO2, for enhanced
oil recovery (“EOR”) activities that are used during a project’s pilot phase, or prior to a project’s technical
and economic viability (i.e. prior to the recognition of proved tertiary recovery reserves) are expensed as
incurred. After a project has been determined to be technically feasible and economically viable, all
acquisition costs of tertiary injectants are capitalized as development costs and depleted, as they are
incurred solely for obtaining access to reserves not otherwise recoverable and have future economic
83
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 an oil pipeline, 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 33 years. In July 2013, the Company sold the oil pipeline, as discussed in the
Acquisitions and Divestitures footnote.
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.
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.
Derivative Instruments—The Company enters into derivative contracts, primarily costless collars, to
manage its exposure to commodity price risk. All derivative instruments, other than those that meet the
“normal purchase normal sales” exclusion, are recorded on the balance sheet as either an asset or liability
measured at fair value. Gains and losses from changes in the fair value of derivative instruments are
recognized immediately in earnings, unless the derivative meets specific hedge accounting criteria, and the
derivative has been designated as a hedge. Effective April 1, 2009, however, the Company elected to
discontinue all hedge accounting prospectively. Cash flows from derivatives used to manage commodity
price risk are classified in operating activities along with the cash flows of the underlying hedged
transactions. The Company does not enter into derivative instruments for speculative or trading purposes.
For derivatives qualifying as hedges of future cash flows prior to April 1, 2009, the effective portion of any
changes in fair value was recognized in accumulated other comprehensive income (loss) and was
reclassified to net income when the underlying forecasted transaction occurred. Any ineffective portion of
such hedges was recognized in commodity derivative (gain) loss, net as it occurred. For discontinued cash
flow hedges, prospective changes in the fair value of the derivative are recognized in earnings. The
accumulated gain or loss recognized in accumulated other comprehensive income (loss) at the time a hedge
is discontinued continues to be deferred until the original forecasted transaction occurs. However, if it is
determined that the likelihood of the original forecasted transaction occurring is no longer probable, the
entire accumulated gain or loss recognized in accumulated other comprehensive income (loss) is
immediately reclassified into earnings. As of December 31, 2013, all amounts related to de-designated
cash flow hedges had been reclassified into earnings.
84
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. Gas imbalance
receivables or payables are valued at the lowest of (i) the current market price, (ii) the price in effect at the
time of production, or (iii) the contract price, if a contract is in hand. As of December 31, 2013 and 2012,
the Company was in a net under (over) produced imbalance position of (110,798) Mcf and (53,536) Mcf,
respectively.
Taxes collected and remitted to governmental agencies on behalf of customers are not included in revenues
or costs and expenses.
General and Administrative Expenses—General and administrative expenses are reported net of
reimbursements of overhead costs that are allocated to working interest owners in the oil and gas properties
operated by Whiting.
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
85
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.
Fair Value of Financial Instruments—The Company has included fair value information in these notes
when the fair value of our financial instruments is materially different from their book value. Cash and
cash equivalents, accounts receivable and payable are carried at cost, which approximates their fair value
because of the short-term maturity of these instruments. The Company’s credit agreement has a recorded
value that approximates its fair value since its variable interest rate is tied to current market rates. The
Company’s Senior 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.
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, 2013, 2012 and 2011:
Plains Marketing LP .....................................
Shell Trading US...........................................
Eighty Eight Oil Company ............................
Bridger Trading LLC ....................................
2013
21%
14%
11%
8%
2012
20%
14%
11%
11%
2011
27%
13%
8%
6%
Commodity derivative contracts held by the Company are with eight 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, 2013, outstanding derivative contracts with JP
Morgan Chase Bank, N.A., Canadian Imperial Bank of Commerce, The Bank of Nova Scotia and Bank of
America Merrill Lynch represented 29%, 21%, 12% and 12%, 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 May 2011, the FASB issued Accounting
Standards Update No. 2011-04, Fair Value Measurement: Amendments to Achieve Common Fair Value
Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”), which provides
amendments to FASB ASC Topic 820, Fair Value Measurement. The objective of ASU 2011-04 is to
create common fair value measurement and disclosure requirements between GAAP and International
Financial Reporting Standards (“IFRS”). The amendments clarify existing fair value measurement and
disclosure requirements and make changes to particular principles or requirements for measuring or
disclosing information about fair value measurements. ASU 2011-04 was effective for interim and annual
reporting periods beginning after December 15, 2011. The Company adopted this standard effective
January 1, 2012, which did not have an impact on the Company’s consolidated financial statements other
than additional disclosures.
86
In June 2011, the FASB issued Accounting Standards Update No. 2011-05, Comprehensive Income:
Presentation of Comprehensive Income (“ASU 2011-05”), which provides amendments to FASB ASC
Topic 220, Comprehensive Income. The objective of ASU 2011-05 is to require an entity to present the
total of comprehensive income, the components of net income and the components of other comprehensive
income either in a single continuous statement of comprehensive income or in two separate but consecutive
statements. ASU 2011-05 eliminates the option to present the components of other comprehensive income
as part of the statement of equity. ASU 2011-05 is effective for interim and annual periods beginning after
December 15, 2011 and is to be applied retrospectively. In December 2011, the FASB issued Accounting
Standards Update No. 2011-12, Comprehensive Income: Deferral of the Effective Date for Amendments to
the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in
Accounting Standards Update No. 2011-05 (“ASU 2011-12”), which deferred the effective date of changes
in ASU 2011-05 that relate to the presentation of reclassification adjustments out of accumulated other
comprehensive income. The amendments in this update are effective at the same time as the amendments
in ASU 2011-05. The Company adopted the provisions of ASU 2011-05 and 2011-12 effective January 1,
2012, which did not have an impact on its consolidated financial statements other than requiring the
Company to present its statements of comprehensive income separately from its statements of equity, as
these statements were formerly presented on a combined basis.
In December 2011, the FASB issued Accounting Standards Update No. 2011-11, Balance Sheet:
Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). The objective of ASU 2011-11 is to
require an entity to provide enhanced disclosures that will enable users of its financial statements to
evaluate the effect or potential effect of netting arrangements on an entity’s financial position. In January
2013, the FASB issued Accounting Standards Update No. 2013-01, Clarifying the Scope of Disclosures
about Offsetting Assets and Liabilities (“ASU 2013-01”), which clarifies that the scope of ASU 2011-11
applies to derivatives accounted for in accordance with FASB ASC Topic 815, Derivatives and Hedging,
including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and
securities lending transactions that are either offset in accordance with FASB ASC Section 210-20-45 or
Section 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. ASU
2011-11 and ASU 2013-01 are effective for interim and annual reporting periods beginning on or after
January 1, 2013 and should be applied retrospectively. The Company adopted ASU 2011-11 and ASU
2013-01 effective January 1, 2013, which did not have an impact on the Company’s consolidated financial
statements other than additional disclosures.
In July 2012, the FASB issued Accounting Standards Update No. 2012-02, Intangibles – Goodwill and
Other – Testing Indefinite-Lived Intangible Assets for Impairment (“ASU 2012-02”). The objective of
ASU 2012-02 is to reduce the cost and complexity of performing an impairment test for indefinite-lived
intangible assets by permitting an entity first to assess qualitative factors to determine whether it is more
likely than not that an indefinite-lived intangible asset is impaired, as a basis for determining whether it is
necessary to perform a quantitative impairment test. ASU 2012-02 is effective for interim and annual
reporting periods beginning after September 15, 2012. The Company adopted ASU 2012-02 effective
January 1, 2013, which did not have an impact on the Company’s consolidated financial statements.
In February 2013, the FASB issued Accounting Standards Update No. 2013-02, Reporting of Amounts
Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). The objective of ASU
2013-02 is to improve the reporting of reclassifications out of AOCI by requiring an entity to report the
effect of significant reclassifications out of AOCI on the respective line items in net income if the amount
being reclassified is required under GAAP to be reclassified in its entirety to net income. For other
amounts that are not required under GAAP to be reclassified in their entirety to net income in the same
reporting period, an entity is required to cross-reference other disclosures required under GAAP that
provide additional detail about those amounts. ASU 2013-02 is effective for interim and annual reporting
periods beginning after December 15, 2012. The Company adopted ASU 2013-02 effective January 1,
2013, which did not have a significant impact on the Company’s consolidated financial statements.
87
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 adoption of this standard will 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 adoption of this standard will not have an
impact on the Company’s consolidated financial statements, other than insignificant balance sheet
reclassifications.
2.
OIL AND GAS PROPERTIES
Net capitalized costs related to the Company’s oil and gas producing activities at December 31, 2013 and
2012 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,
2013
1,633,495
372,298
7,563,350
496,007
10,065,150
(2,645,841)
7,419,309
$
$
2012
2,119,541
362,483
6,369,170
360,804
9,211,998
(2,564,081)
6,647,917
$
$
3.
ACQUISITIONS AND DIVESTITURES
2013 Acquisitions
On September 20, 2013, the Company completed the acquisition of approximately 39,300 gross (17,300
net) acres, including interests in 121 producing oil and gas wells and undeveloped acreage, in the Williston
Basin located in Williams and McKenzie counties of North Dakota and Roosevelt and Richland counties of
Montana for an aggregate unadjusted purchase price of $260.0 million. Revenue and earnings from these
properties since the September 20, 2013 acquisition date, which are included in the consolidated statements
of income for the year ended December 31, 2013, are not material. Disclosures of pro forma revenues and
net income for the acquisition of these wells are not material and have not been presented accordingly.
The acquisition was recorded using the purchase method of accounting. The following table summarizes
the preliminary allocation of the $258.9 million adjusted purchase price (which is still subject to post-
closing adjustments) to the tangible assets acquired and liabilities assumed in this acquisition oil and gas
properties. As the purchase price is further adjusted for post-close adjustments and as oil and gas property
valuations are completed, the final purchase price allocation may result in a different allocation to the
tangible assets from that which is presented in the table below (in thousands):
88
Purchase price................................................................................................................................
Allocation of purchase price:
Proved properties....................................................................................................................
Unproved properties ...............................................................................................................
Oil in tank inventory ..............................................................................................................
Accounts receivable ...............................................................................................................
Asset retirement obligations ...................................................................................................
$
$
Total ................................................................................................................................ $
258,892
232,187
27,335
692
578
(1,900)
258,892
2013 Divestitures
On October 31, 2013, the Company completed the sale of approximately 45,000 gross (32,200 net) acres,
including its interests in certain producing oil and gas wells and undeveloped acreage, in its Big Tex
prospect located in the Delaware Basin for a cash purchase price of $152.0 million (subject to post-closing
adjustments), resulting in a pre-tax gain on sale of $13.0 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 enhanced oil recovery 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 $809.7
million after selling costs and post-closing adjustments, resulting in a pre-tax gain on sale of $109.7
million. The Company used the net proceeds from this sale to repay a portion of the debt outstanding under
its credit agreement.
Upon closing of the transaction, the following crude oil swaps and any of their related cash settlements as
of that date were transferred to the buyer of the Postle Properties:
Period
Apr – Dec 2013
Jan – Dec 2014
Jan – Dec 2015
Jan – Mar 2016
Total
2012 Acquisitions
Contracted Crude Oil Volumes
(Bbl)
1,677,500
2,007,500
1,825,000
400,400
5,910,400
NYMEX Price for Crude Oil
(per Bbl)
$98.50
$94.75
$94.75
$93.50
On March 22, 2012, the Company completed the acquisition of approximately 13,300 net undeveloped
acres in the Missouri Breaks field in Richland County, Montana for $33.3 million.
2012 Divestitures
On May 18, 2012, the Company sold a 50% ownership interest in its Belfield gas processing plant, natural
gas gathering system, oil gathering system and related facilities located in Stark County, North Dakota for
total cash proceeds of $66.2 million. Whiting used the net proceeds from the sale to repay a portion of the
debt outstanding under its credit agreement.
On March 28, 2012, the Company completed an initial public offering of units of beneficial interest in
Trust II, selling 18,400,000 Trust II units at $20.00 per unit, which generated net proceeds of $322.3
89
million after underwriters’ fees, offering expenses and post-close adjustments. The Company used the net
offering proceeds to repay a portion of the debt outstanding under its credit agreement. The net proceeds
from the sale of Trust II units to the public resulted in a deferred gain on sale of $128.2 million.
Immediately prior to the closing of the offering, Whiting conveyed a term net profits interest in certain of
its oil and gas properties to Trust II in exchange for 100% of the trust’s units issued, or 18,400,000 units.
The net profits interest entitles Trust II to receive 90% of the net proceeds from the sale of oil and natural
gas production from the underlying properties. The net profits interest will terminate on the later to occur
of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying
properties and sold. This is the equivalent of 10.61 MMBOE in respect of Trust II’s right to receive 90%
of the net proceeds from such reserves pursuant to the net profits interest.
2011 Acquisitions
On July 28, 2011, the Company completed the acquisition of approximately 23,400 net acres and one well
in the Missouri Breaks field in Richland County, Montana for an unadjusted purchase price of $46.9
million. Disclosures of pro forma revenues and net income for the acquisition of this one well are not
material and have not been presented accordingly.
On March 18, 2011, Whiting and an unrelated third party formed Sustainable Water Resources, LLC
(“SWR”) to develop a water project in the state of Colorado. The Company contributed $25.0 million for a
75% interest in SWR, and the 25% noncontrolling interest in SWR was ascribed a fair value of $8.3
million, which consisted of $2.5 million in cash contributions, as well as $5.8 million in intangible and
fixed assets contributed to the joint venture.
On February 15, 2011, the Company completed the acquisition of 6,000 net undeveloped acres and
additional working interests in the Pronghorn field in the Billings and Stark counties of North Dakota, for
an aggregate purchase price of $40.0 million.
2011 Divestiture
On September 29, 2011, Whiting sold its interest in several non-core oil and gas producing properties
located in the Karnes, Live Oak and DeWitt counties of Texas for total cash proceeds of $64.8 million,
resulting in a pre-tax gain on sale of $12.3 million. Whiting used the net proceeds from the property sale to
repay a portion of the debt outstanding under its credit agreement.
4.
LONG-TERM DEBT
Long-term debt consisted of the following at December 31, 2013 and 2012 (in thousands):
Credit agreement ........................................................................................
7% Senior Subordinated Notes due 2014 ...................................................
6.5% Senior Subordinated Notes due 2018 ................................................
5% Senior Notes due 2019 .........................................................................
5.75% Senior Notes due 2021, including unamortized debt premium of
$3,834 ..................................................................................................
Total debt ............................................................................................
December 31,
$
2013
-
-
350,000
1,100,000
$
2012
1,200,000
250,000
350,000
-
1,203,834
2,653,834
$
-
1,800,000
$
The following table shows five succeeding fiscal years of scheduled maturities for the Company’s long-
term debt as of December 31, 2013 (in thousands):
90
Long-term debt ................... $
-
$
-
$
-
$
-
$
350,000
2014
2015
2016
2017
2018
Credit Agreement—Whiting Oil and Gas Corporation (“Whiting Oil and Gas”), the Company’s wholly-
owned subsidiary, has a credit agreement with a syndicate of banks that as of December 31, 2013 had a
borrowing base of $2.8 billion, of which $1.2 billion has been committed by lenders and is available for
borrowing. The Company may increase the maximum aggregate amount of commitments under the credit
agreement up to the $2.8 billion borrowing base if certain conditions are satisfied, including the consent of
lenders participating in the increase. As of December 31, 2013, the Company had $1,197.0 million of
available borrowing capacity, which was net of $3.0 million in letters of credit with no borrowings
outstanding.
The credit agreement provides for interest only payments until April 2016, when the agreement expires and
all outstanding borrowings are due. 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. A portion of the revolving credit facility in an aggregate amount not to
exceed $50.0 million may be used to issue letters of credit for the account of Whiting Oil and Gas or other
designated subsidiaries of the Company. As of December 31, 2013, $47.0 million was available for
additional letters of credit under the agreement.
Interest accrues at the Company’s option at either (i) a base rate for a base rate loan plus the margin in the
table below, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus
0.50% or an adjusted LIBOR rate plus 1.00%, or (ii) an adjusted LIBOR rate for a Eurodollar loan plus the
margin in the table below. Additionally, the Company also incurs commitment fees as set forth in the table
below on the unused portion of the lesser of the aggregate commitments of the lenders or the borrowing
base, and which are included as a component of interest expense. 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.
Ratio of Outstanding Borrowings to Borrowing Base
Less than 0.25 to 1.0
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0
Greater than or equal to 0.90 to 1.0
Applicable
Margin for Base
Rate Loans
Applicable
Margin for
Eurodollar Loans
Commitment
Fee
0.50%
0.75%
1.00%
1.25%
1.50%
1.50%
1.75%
2.00%
2.25%
2.50%
0.375%
0.375%
0.50%
0.50%
0.50%
The credit agreement contains restrictive covenants that may limit the Company’s ability to, among other
things, incur additional indebtedness, sell assets, make loans to others, make investments, enter into
mergers, enter into hedging contracts, incur liens and engage in certain other transactions without the prior
consent of its lenders. Except for limited exceptions, the credit agreement also restricts the Company’s
ability to make any dividend payments or distributions on its common stock. These restrictions apply to all
of the net assets of Whiting Oil and Gas. As of December 31, 2013, total restricted net assets were
$4,070.4 million, and the amount of retained earnings free from restrictions was $23.0 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, 2013.
91
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’ properties included in the borrowing base for the credit
agreement. The Company has guaranteed the obligations of Whiting Oil and Gas under the credit
agreement and has pledged the stock of Whiting Oil and Gas as security for its guarantee.
Senior Notes and Senior Subordinated Notes—In September 2010, the Company issued at par $350.0
million of 6.5% Senior Subordinated Notes due October 2018. The estimated fair value of these notes was
$371.0 million as of December 31, 2013, 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 $1,100.0 million of 5% Senior
Notes due March 2019 and $800.0 million of 5.75% Senior Notes due March 2021, and issued at 101% of
par an additional $400.0 million of 5.75% Senior Notes due March 2021 (collectively, the “Senior Notes”).
The Company used the net proceeds from these issuances to repay all of the debt outstanding under its
credit agreement, to fund its $260.0 million acquisition of Williston Basin assets discussed in the
Acquisitions and Divestitures footnote and to redeem all $250.0 million of its 7% Senior Subordinated
Notes due February 2014 (the “2014 Notes”). The Company plans to use the remainder of the net proceeds
for general corporate purposes including capital expenditures. The estimated fair values of the 2019 notes
and the 2021 notes were $1,122.0 million and $1,260.0 million, respectively, as of December 31, 2013,
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 $254.0 million to redeem
all of its $250.0 million aggregate principal amount of the 2014 Notes at a redemption price of 101.595%.
Concurrent with this redemption, the Company paid all accrued and unpaid interest on the 2014 Notes up to
but not including the redemption date. The Company financed the redemption of the 2014 Notes with
proceeds from the issuance of the Senior Notes, as discussed above. As a result of the redemption, Whiting
recognized a $4.4 million loss on early extinguishment of debt, which consisted of a cash charge of $4.0
million related to the redemption premium on the 2014 Notes and a non-cash charge of $0.4 million related
to the acceleration of unamortized debt issuance costs.
The Senior Notes are unsecured obligations of Whiting Petroleum Corporation and are subordinated to all
of the Company’s secured indebtedness, which consists of Whiting Oil and Gas’ credit agreement. The
6.5% Senior Subordinated Notes due 2018 (the “2018 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 Senior Notes and Whiting Oil and Gas’ credit agreement. The Company’s obligations under the
2018 Notes and the Senior Notes are fully and unconditionally guaranteed by the Company’s 100%-owned
subsidiary, Whiting Oil and Gas (the “Guarantor”). Any subsidiaries other than the Guarantor 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.
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, 2013 and 2012 were $9.7 million and
$11.6 million, respectively, and are included in accrued liabilities and other. Revisions to the liability
typically occur due to changes in estimated abandonment costs or well economic lives, or if federal or state
regulators enact new requirements regarding the abandonment of wells. The following table provides a
92
reconciliation of the Company’s asset retirement obligations for the year ended December 31, 2013 and
2012 (in thousands):
Year Ended December 31,
2013
2012
Asset retirement obligation at January 1 ....................................................
Additional liability incurred .......................................................................
Revisions in estimated cash flows .............................................................
Accretion expense ......................................................................................
Obligations on sold properties ...................................................................
Liabilities settled ........................................................................................
Asset retirement obligation at December 31 ..............................................
$
$
97,818
17,535
12,225
10,608
(3,630)
(8,408)
126,148
$
$
69,721
9,292
23,162
7,263
(4)
(11,616)
97,818
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, primarily costless
collars and swaps, to achieve a more predictable cash flow by reducing its exposure to commodity price
volatility. Commodity derivative contracts are thereby used to ensure adequate cash flow to fund the
Company’s capital programs and to manage returns on acquisitions and drilling programs. Costless collars
are designed to establish floor and ceiling prices on anticipated future oil 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. The Company does not enter into derivative contracts for
speculative or trading purposes.
Whiting Derivatives. The table below details the Company’s costless collar derivatives, including its
proportionate share of Trust II derivatives, entered into to hedge forecasted crude oil production revenues,
as of February 6, 2014.
Whiting Petroleum Corporation
Derivative
Instrument
Collars
Three-way collars (1)
Period
Jan – Dec 2014
Jan – Dec 2014
Total
Contracted Crude Oil
Volumes (Bbl)
49,290
15,280,000
15,329,290
Weighted Average NYMEX Price
Collar Ranges for Crude Oil (per
Bbl)
$ 80.00 - $122.50
$70.94 - $85.00 - $103.35
(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
93
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.
Derivatives Conveyed to Whiting USA Trust II. In connection with the Company’s conveyance in March
2012 of a term net profits interest to Trust II and related sale of 18,400,000 Trust II units to the public, the
right to any future hedge payments made or received by Whiting on certain of its derivative contracts have
been conveyed to Trust II, and therefore such payments will be included in Trust II’s calculation of net
proceeds. Under the terms of the aforementioned conveyance, Whiting retains 10% of the net proceeds
from the underlying properties, which results in third-party public holders of Trust II units receiving 90%,
and Whiting retaining 10%, of the future economic results of commodity derivative contracts conveyed to
Trust II. The relative ownership of the future economic results of such commodity derivatives is reflected
in the tables below. No additional hedges are allowed to be placed on Trust II assets.
The 10% portion of Trust II derivatives that Whiting has retained the economic rights to (and which are
also included in the first derivative table above) are as follows:
Derivative
Instrument
Collars
Period
Jan – Dec 2014
Contracted Crude Oil
Volumes (Bbl)
49,290
NYMEX Price Collar Ranges for
Crude Oil (per Bbl)
$80.00 - $122.50
Whiting Petroleum Corporation
The 90% portion of Trust II derivative contracts of which Whiting has transferred the economic rights to
third-party public holders of Trust II units (and which have not been reflected in the above tables) are as
follows:
Derivative
Instrument
Collars
Period
Jan – Dec 2014
Third-party Public Holders of Trust II Units
Contracted Crude Oil
Volumes (Bbl)
443,610
NYMEX Price Collar Ranges for
Crude Oil (per Bbl)
$80.00 - $122.50
Embedded Commodity Derivative Contract—In May 2011, Whiting entered into a long-term contract to
purchase CO2 from 2015 through 2029 for use in its enhanced oil recovery project that is being carried out
at its North Ward Estes field in Texas. This contract contains a price adjustment clause that is linked to
changes in NYMEX crude oil prices. The Company has determined that the portion of this contract linked
to NYMEX oil prices is not clearly and closely related to the host contract, and the Company has therefore
bifurcated this embedded pricing feature from its host contract and reflected it at fair value in the
consolidated financial statements. As of December 31, 2013, the estimated fair value of the embedded
derivative in this CO2 purchase contract was an asset of $36.4 million.
Although CO2 is not a commodity that is actively traded on a public exchange, the market price for CO2
generally fluctuates in tandem with increases or decreases in crude oil prices. When Whiting enters into a
long-term CO2 purchase contract where the price of CO2 is fixed and does not adjust with changes in oil
prices, the Company is exposed to the risk of paying higher than the market rate for CO2 in a climate of
declining oil and CO2 prices. This in turn could have a negative impact on the project economics of the
Company’s CO2 flood at North Ward Estes. As a result, the Company reduces its exposure to this risk by
entering into certain CO2 purchase contracts which have prices that fluctuate along with changes in crude
oil prices.
Derivative Instrument Reporting—All derivative instruments are recorded 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 year ended December 31, 2013 and 2012 (in thousands):
94
ASC 815 Cash Flow
Hedging Relationships (1)
Commodity contracts .................. Gain (loss) on hedging activities ............
Income Statement Classification
Gain (Loss) Reclassified from AOCI
into Income (Effective Portion) (1)
Year Ended December 31,
2012
2013
$
(1,958)
$
2,338
(1) Effective April 1, 2009, the Company elected to de-designate all of its commodity derivative contracts that had
been previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively. As a
result, such mark-to-market values at March 31, 2009 were frozen in AOCI as of the de-designation date and
were being reclassified into earnings as the original hedged transactions affected income. As of December 31,
2013, all amounts had been reclassified into earnings.
Not Designated as
ASC 815 Hedges
Commodity contracts ................. Commodity derivative (gain) loss, net ..
Embedded commodity contracts Commodity derivative (gain) loss, net ..
Total ...................................................................................................
Income Statement Classification
(Gain) Loss Recognized in Income
Year Ended December 31,
2012
2013
(75,782)
(10,129)
(85,911)
20,503
(12,701)
7,802
$
$
$
$
Offsetting of Derivative Assets and Liabilities. With each individual 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
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
December 31, 2013 (1)
Gross
Recognized
Assets/
Liabilities
Gross
Amounts
Offset
Net
Recognized
Fair Value
Assets/
Liabilities
Commodity contracts ................... Prepaid expenses and other ........... $ 23,752
36,416
Embedded commodity contracts .. Other long-term assets ..................
$ 60,168
Total derivative assets ......................................................................
$ (22,478)
-
$ (22,478)
$
1,274
36,416
$ 37,690
Derivative liabilities:
Commodity contracts ................... Current derivative liabilities ......... $ 25,960
$ 25,960
Total derivative liabilities.................................................................
$ (22,478)
$ (22,478)
$
$
3,482
3,482
95
Not Designated as
ASC 815 Hedges
Derivative assets:
Balance Sheet Classification
December 31, 2012 (1)
Gross
Recognized
Assets/
Liabilities
Gross
Amounts
Offset
Net
Recognized
Fair Value
Assets/
Liabilities
Commodity contracts ................... Prepaid expenses and other ...........
Commodity contracts ................... Other long-term assets ..................
Embedded commodity contracts .. Other long-term assets ..................
Total derivative assets ......................................................................
$ 40,909
4,053
24,038
$ 69,000
$ (31,437)
(2,189)
(323)
$ (33,949)
$
9,472
1,864
23,715
$ 35,051
Derivative liabilities:
Commodity contracts ................... Current derivative liabilities .........
Commodity contracts ................... Non-current derivative liabilities ..
Embedded commodity contracts .. Non-current derivative liabilities ..
Total derivative liabilities.................................................................
$ 53,392
3,867
323
$ 57,582
$ (31,437)
(2,189)
(323)
$ (33,949)
$ 21,955
1,678
-
$ 23,633
(1) Because counterparties to the Company’s 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 Derivative Instruments. None of the Company’s derivative instruments contain
credit-risk-related contingent features. Counterparties to the Company’s 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 derivative counterparties in order to secure contract performance obligations.
7.
FAIR VALUE MEASUREMENTS
The Company follows FASB ASC Topic 820, Fair Value Measurement and Disclosure, which establishes
a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy
categorizes assets and liabilities measured at fair value into one of three different levels depending on the
observability of the inputs employed in the measurement. The three levels are defined as follows:
• Level 1: Quoted Prices in Active Markets for Identical Assets – inputs to the valuation
methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
• Level 2: Significant Other Observable Inputs – inputs to the valuation methodology include quoted
prices for similar assets and liabilities in active markets, and inputs that are observable for the asset
or liability, either directly or indirectly, for substantially the full term of the financial instrument.
• Level 3: Significant Unobservable Inputs – inputs to the valuation methodology are unobservable
and significant to the fair value measurement.
A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of
input that is significant to the fair value measurement. The Company’s assessment of the significance of a
particular input to the fair value measurement in its entirety requires judgment and considers factors
specific to the asset or liability. The Company reflects transfers between the three levels at the beginning
of the reporting period in which the availability of observable inputs no longer justifies classification in the
original level.
96
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, 2013 and 2012, and indicate the fair value hierarchy of
the valuation techniques utilized by the Company to determine such fair values (in thousands):
Level 1
Level 2
Level 3
Financial Assets
Commodity derivatives – current .................. $
Embedded commodity derivatives – non-
current.......................................................
Total financial assets ......................... $
Financial Liabilities
Commodity derivatives – current .................. $
Total financial liabilities .................... $
-
-
-
-
-
$
$
$
$
1,274
$
-
36,416
36,416
-
1,274
3,482
3,482
$
$
$
Level 1
Level 2
Level 3
Financial Assets
Commodity derivatives – current ................. $
Commodity derivatives – non-current ...........
Embedded commodity derivatives – non-
current.......................................................
Total financial assets ......................... $
Financial Liabilities
Commodity derivatives – current .................. $
Commodity derivatives – non-current ...........
Total financial liabilities .................... $
-
-
-
-
-
-
-
$
$
$
$
9,472
1,864
-
11,336
21,955
1,678
23,633
$
$
$
$
Total Fair Value
December 31,
2013
$
$
$
$
1,274
36,416
37,690
3,482
3,482
Total Fair Value
December 31,
2012
$
$
$
$
9,472
1,864
23,715
35,051
21,955
1,678
23,633
-
-
-
-
23,715
23,715
-
-
-
The following methods and assumptions were used to estimate the fair values of the assets and liabilities in
the tables above:
Commodity Derivatives. Commodity derivative instruments consist of costless collars 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 nonperformance risk, as appropriate. The Company utilizes its
counterparties’ valuations to assess the reasonableness of its own valuations.
Embedded Commodity Derivatives. The embedded commodity derivative relates to a long-term CO2
purchase contract, which has a price adjustment clause that is linked to changes in NYMEX crude oil
prices. Whiting has determined that the portion of this contract linked to NYMEX oil prices is not clearly
and closely related to its corresponding host contract, and the Company has therefore bifurcated this
embedded pricing feature from the host contract and reflected it at fair value in its consolidated financial
statements. This embedded commodity derivative is valued based on an income approach. The option
model used in the valuation considers various assumptions, including quoted forward prices for
commodities, LIBOR discount rates and either the Company’s or the counterparty’s nonperformance risk,
as appropriate.
97
The assumptions used in the CO2 contract valuation include inputs that are both observable in the
marketplace as well as unobservable during the term of the contract. With respect to forward prices for
NYMEX crude oil where there is a lack of price transparency in certain future periods, such unobservable
oil price inputs are significant to the CO2 contract valuation methodology, and the contract’s fair value is
therefore designated as Level 3 within the valuation hierarchy.
Level 3 Fair Value Measurements. A third-party valuation specialist is utilized on a quarterly basis to
determine the fair value of the embedded commodity derivative instrument designated as Level 3. The
Company reviews this valuation (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 year ended December 31, 2013 and 2012 (in
thousands):
Fair value asset, beginning of period .......................................................... $
Unrealized gains (losses) on embedded commodity derivative contracts
included in earnings (1) ...........................................................................
Transfers into (out of) Level 3 ....................................................................
Fair value asset, end of period .................................................................... $
Year Ended December 31,
2013
2012
23,715
$
12,980
12,701
-
36,416
$
10,735
-
23,715
(1)
Included in commodity derivative (gain) loss, net in the consolidated statements of income.
Quantitative Information About Level 3 Fair Value Measurements. The significant unobservable inputs
used in the fair value measurement of the Company’s embedded commodity derivative contract designated
as Level 3 are as follows:
Fair Value at
December 31, 2013
(in thousands)
Valuation
Technique
Embedded commodity
derivative ...........................
$ 36,416
Option model
Unobservable
Input
Future prices of
NYMEX crude oil after
March 31, 2022
Range
(per Bbl)
$79.87 - $95.75
Sensitivity to Changes In Significant Unobservable Inputs. As presented in the table above, the significant
unobservable inputs used in the fair value measurement of Whiting’s embedded commodity derivative
within its CO2 purchase contract are the future prices of NYMEX crude oil from April 2022 to December
2029. Significant increases (decreases) in these unobservable inputs in isolation would result in a
significantly lower (higher) fair value asset measurement.
Nonrecurring Fair Value Measurements. The Company applies the provisions of the fair value
measurement standard to its nonrecurring, non-financial measurements, including proved oil and gas
property impairments. These assets and liabilities are not measured at fair value on an ongoing basis but
are subject to fair value adjustments only in certain circumstances. The following tables present
information about the Company’s non-financial assets and liabilities measured at fair value on a
nonrecurring basis as of December 31, 2013 and 2012, and indicates the fair value hierarchy of the
valuation techniques utilized by the Company to determine such fair values (in thousands):
98
Net Carrying
Value as of
December 31,
2013
Proved property impairments (1) ................. $ 106,114
Fair Value Measurements Using
Level 1
-
$
Level 2
-
$
Level 3
$ 106,114
Loss (Before
Tax) Year
Ended
December 31,
2013
$ 267,109
(1) During the year ended December 31, 2013, proved oil and gas properties with a carrying amount of $373.2
million were written down to their fair value of $106.1 million, resulting in a non-cash impairment charge of
$267.1 million. The impairment consisted of (i) a $220.8 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 $46.3 million write-down in the Rocky Mountains
region related to well performance and associated changes in reserves during the fourth quarter of 2013.
Proved property impairments (1) ................. $
Net Carrying
Value as of
December 31,
2012
23,473
Fair Value Measurements Using
Level 1
-
$
Level 2
-
$
Level 3
$ 23,473
Loss (Before
Tax) Year
Ended
December 31,
2012
$
46,924
(1) During the year ended December 31, 2012, proved oil and gas properties with a carrying amount of $70.4
million were written down to their fair value of $23.5 million, resulting in a non-cash impairment charge of
$46.9 million. The impairment consisted primarily of a $46.3 million write-down in the Rocky Mountains
region related to changes in estimated reserves at December 31, 2012.
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 production 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 of 15% (all of which are designated as Level 3 inputs within the fair value
hierarchy).
8.
DEFERRED COMPENSATION
Production Participation Plan—The Company has a Production Participation Plan (the “Plan”) in which
all employees participate. On an annual basis, interests in oil and gas properties acquired, developed or
sold during the year are allocated to the Plan as determined annually by the Compensation Committee of
the Company’s Board of Directors. Once allocated, the interests (not legally conveyed) are fixed. Interest
allocations prior to 1995 consisted of 2%-3% overriding royalty interests. Interest allocations since 1995
have been 1.75%-5% of oil and gas sales less lease operating expenses and production taxes.
Payments of 100% of the year’s Plan interests to employees and the vested percentages of former
employees in the year’s Plan interests are made annually in cash after year-end. Accrued compensation
expense under the Plan for the years ended December 31, 2013, 2012 and 2011 amounted to $66.5 million,
$44.7 million and $34.1 million, respectively, charged to general and administrative expense and $6.8
million, $4.6 million and $4.2 million, respectively, charged to exploration expense.
99
Employees vest in the Plan ratably at 20% per year over a five-year period. Pursuant to the terms of the
Plan, (i) employees who terminate their employment with the Company are entitled to receive their vested
allocation of future Plan year payments on an annual basis; (ii) employees will become fully vested at age
62, regardless of when their interests would otherwise vest; and (iii) any forfeitures inure to the benefit of
the Company.
The Company uses average historical prices to estimate the vested long-term Production Participation Plan
liability. At December 31, 2013, the Company used three-year average historical NYMEX prices of $95.60
for crude oil and $3.49 for natural gas to estimate this liability. The Company records the expense
associated with changes in the present value of estimated future payments under the Plan as a separate line
item in the consolidated statements of income. If the Company were to terminate the Plan or upon a
change in control of the Company (as defined in the Plan), all employees fully vest and the Company
would distribute to each Plan participant an amount, based upon the valuation method set forth in the Plan,
in a lump sum payment twelve months after the date of termination or within one month after a change in
control event. Based on current strip prices at December 31, 2013, if the Company elected to terminate the
Plan or if a change of control event occurred, it is estimated that the fully vested lump sum cash payment to
employees would approximate $186.7 million. This amount includes $19.2 million attributable to proved
undeveloped oil and gas properties and $73.3 million relating to the short-term portion of the Plan liability,
which has been reflected as a current payable in accrued liabilities and other, and was paid in January and
February 2014. The ultimate sharing contribution for proved undeveloped oil and gas properties will be
awarded in the year of Plan termination or change of control. However, the Company has no intention to
terminate the Plan.
The following table presents changes in the Plan’s estimated long-term liability (in thousands):
Long-term Production Participation Plan liability at January 1 .................
Change in liability for accretion, vesting, changes in estimates and new
Plan year activity ................................................................................
Accrued compensation expense reflected as a current liability .................
Long-term Production Participation Plan liability at December 31 ...........
Year Ended December 31,
2013
2012
$
94,483
$
80,659
66,284
(73,264)
87,503
$
63,135
(49,311)
94,483
$
Of the aggregate $73.3 million of accrued compensation under the Plan as of December 31, 2013, $23.9
million relates to the sale of the Postle Properties, which is further described in the Acquisitions and
Divestitures footnote. This property sale also resulted in an offsetting benefit of $19.4 million realized
related to the reduction in the Company’s long-term Plan liability.
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 2013, 2012 and 2011 were $7.9 million, $5.9 million and $5.0 million, respectively.
Employees vest in employer contributions at 20% per year of completed service.
9.
SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST
Common Stock—In May 2011, Whiting’s stockholders approved an amendment to the Company’s
Restated Certificate of Incorporation to increase the number of authorized shares of common stock from
175,000,000 shares to 300,000,000 shares.
Stock Split. On January 26, 2011, the Company’s Board of Directors approved a two-for-one split of the
Company’s shares of common stock to be effected in the form of a stock dividend. As a result of the stock
split, stockholders of record on February 7, 2011 received one additional share of common stock for each
share of common stock held. The additional shares of common stock were distributed on February 22,
100
2011. Concurrently with the payment of such stock dividend in February 2011, there was a transfer from
additional paid-in capital to common stock of $0.1 million, which amount represents $0.001 per share
(being the par value thereof) for each share of common stock so issued. The common stock dividend
resulted in the conversion price for Whiting’s 6.25% Convertible Perpetual Preferred Stock being adjusted
from $43.4163 to $21.70815.
6.25% Convertible Perpetual Preferred Stock—In June 2009, the Company completed a public offering of
6.25% convertible perpetual preferred stock (“preferred stock”), selling 3,450,000 shares at a price of
$100.00 per share. As 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 shares of preferred stock
outstanding on March 31, 2013, were converted into 792,919 shares of common stock. As of
December 31, 2013, 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,
when and if 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. As of December 31, 2013, 5,380,594 shares of common stock remained
available for grant under the 2013 Equity Plan.
For the years ended December 31, 2013, 2012 and 2011, total stock compensation expense recognized for
restricted share awards and stock options was $22.4 million, $18.2 million and $13.5 million, respectively.
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 or three-year service
period. The Company uses historical data and projections to estimate expected employee behaviors related
to restricted stock forfeitures. The expected forfeitures are then included as part of the grant date estimate
of compensation cost. For service-based restricted stock awards, the grant date fair value is determined
based on the closing bid price of the Company’s common stock on the grant date.
In January 2013, 2012 and 2011, 751,872 shares, 444,501 shares and 201,420 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
101
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 rate........................................................
Dividend yield......................................................
2013
65,000
43.1%
0.41%
-
2012
65,000
51.9%
0.35%
-
2011
65,000
75.8%
1.00%
-
The grant date fair value of the market-based restricted stock as determined by the Monte Carlo valuation
model was $23.01 per share, $29.45 per share and $42.20 per share in January 2013, 2012 and 2011,
respectively.
The following table shows a summary of the Company’s nonvested restricted stock as of December 31,
2011, 2012 and 2013 as well as activity during the years then ended:
Restricted stock awards nonvested, January 1, 2011 ..................................
Granted .......................................................................................................
Vested .........................................................................................................
Forfeited ......................................................................................................
Restricted stock awards nonvested, December 31, 2011 ............................
Granted .......................................................................................................
Vested .........................................................................................................
Forfeited ......................................................................................................
Restricted stock awards nonvested, December 31, 2012 ............................
Granted .......................................................................................................
Vested .........................................................................................................
Forfeited ......................................................................................................
Restricted stock awards nonvested, December 31, 2013 ............................
Number
of Shares
Weighted Average
Grant Date
Fair Value
869,370
304,355
(429,136)
(20,194)
724,395
592,400
(357,170)
(8,599)
951,026
940,792
(347,824)
(99,684)
1,444,310
$
$
16.27
48.48
15.32
33.53
29.88
34.45
17.91
51.72
37.02
27.59
35.32
30.95
31.71
As of December 31, 2013, there was $11.8 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, 2013, 2012 and 2011, the
total fair value of restricted stock vested was $16.8 million, $18.9 million and $26.0 million, respectively.
Stock Options. In January 2012 and 2011, 45,359 stock options and 80,820 stock options, respectively,
were granted under the 2003 Equity Plan to certain executive officers of the Company with exercise prices
equal to the closing market price of the Company’s common stock on the grant date. There were no stock
options granted under either the 2003 Equity Plan or the 2013 Equity Plan during 2013. These stock
options vest ratably over a three-year service period from the grant date and are exercisable immediately
upon vesting through the tenth anniversary of the grant date.
The Company uses a Black-Scholes option-pricing model to estimate the fair value of stock option awards.
Because the Company first granted stock options in 2009, it does not have historical exercise data upon
which to estimate the expected term of the options. As such, the Company has elected to estimate the
expected term of the stock options granted using the “simplified” method for “plain vanilla” options. The
expected volatility at the grant date is based on the historical volatility of Whiting’s common stock, and the
risk-free interest rate is determined based on the yield on U.S. Treasury strips with maturities similar to
102
those of the expected term of the stock options. The following table summarizes the assumptions used to
estimate the grant date fair value of stock options awarded in each respective year:
Risk-free interest rate .................................................................................
Expected volatility .....................................................................................
Expected term ............................................................................................
Dividend yield............................................................................................
2012
1.19%
61.4%
6.0 yrs.
-
2011
2.47%
59.3%
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 and $34.15 per share in January 2012 and 2011, respectively.
The following table shows a summary of the Company’s stock options outstanding as of December 31,
2011, 2012 and 2013 as well as activity during the years then ended:
Aggregate
Intrinsic
Value
(in thousands)
Weighted
Average
Remaining
Contractual
Term
(in years)
Options outstanding at January 1, 2011 .................
Granted ..................................................................
Exercised ................................................................
Forfeited or expired................................................
Options outstanding at December 31, 2011 ...........
Granted ..................................................................
Exercised ................................................................
Forfeited or expired................................................
Options outstanding at December 31, 2012 ...........
Granted ..................................................................
Exercised ................................................................
Forfeited or expired................................................
Options outstanding at December 31, 2013 ...........
Options vested and expected to vest at December
31, 2013 ............................................................
Options exercisable at December 31, 2013 ............
Weighted
Average
Exercise Price
per Share
16.78
$
60.28
-
-
26.09
51.22
-
-
28.79
-
-
60.28
28.65
$
Number of
Options
296,516
80,820
-
-
377,336
45,359
-
-
422,695
-
-
(1,855)
420,840
$
$
$
-
-
-
$ 13,979.6
420,840
365,511
$
$
28.65
24.61
$ 13,979.6
$ 13,617.8
5.9
5.9
5.7
Unrecognized compensation cost as of December 31, 2013 related to unvested stock option awards was
$0.2 million, which is expected to be recognized over a period of one year.
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.
103
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 income (loss) .......................................................................
Balance at December 31 ............................................................
$
$
10.
INCOME TAXES
Income tax expense consists of the following (in thousands):
Year Ended December 31,
2013
8,184
(52)
8,132
2012
8,274
(90)
8,184
$
$
2013
Year Ended December 31,
2012
2011
Current income tax expense (refund):
Federal .......................................................................
State ...........................................................................
Total current income tax expense .........................
$
7,060
(6,074)
986
Deferred income tax expense:
Federal .......................................................................
State ...........................................................................
Total deferred income tax expense .......................
Total ..............................................................
$
196,787
8,095
204,882
205,868
$
$
-
(669)
(669)
233,468
15,113
248,581
247,912
$
$
107
3,746
3,853
272,653
12,185
284,838
288,691
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 ...................................
Permanent items ..............................................................
Other ...............................................................................
Total .......................................................................
$
$
$
Year Ended December 31,
2012
231,704
14,444
-
(620)
-
1,524
860
247,912
$
2013
200,155
13,962
(10,525)
(796)
(1,416)
2,122
2,366
205,868
$
$
2011
273,112
16,602
-
(697)
(1,842)
1,420
96
288,691
The principal components of the Company’s deferred income tax assets and liabilities at December 31,
2013 and 2012 were as follows (in thousands):
104
Year Ended December 31,
2013
2012
Deferred income tax assets:
$
Net operating loss carryforward ..........................................................
Derivative instruments .........................................................................
Production Participation Plan liability .................................................
Tax sharing liability .............................................................................
Asset retirement obligations ................................................................
Underwriter fees ..................................................................................
Restricted stock compensation ............................................................
Enhanced oil recovery credit carryforwards ........................................
Alternative minimum tax credit carryforwards ...................................
Foreign tax credit carryforwards .........................................................
Other ....................................................................................................
Total deferred income tax assets ..................................................
Less valuation allowances ..................................................................
Net deferred income tax assets .....................................................
438,922
-
32,245
9,439
23,642
10,974
13,384
7,946
18,452
1,230
2,004
558,238
(1,230)
557,008
$
520,980
19,957
34,865
8,312
19,759
12,677
9,852
7,946
11,391
1,230
1,508
648,477
(1,230)
647,247
Deferred income tax liabilities:
Oil and gas properties ..........................................................................
Trust distributions ................................................................................
Derivative instruments.........................................................................
Total deferred income tax liabilities ............................................
Total net deferred income tax liabilities .............................................
1,675,916
149,332
10,438
1,835,686
1,278,678
$
1,555,142
165,180
-
1,720,322
1,073,075
$
As of December 31, 2013, we had federal net operating loss (“NOL”) carryforwards of $1,255.2 million.
Of this amount, $50.5 million in NOL carryforwards relate to tax deductions for stock compensation that
exceed stock compensation costs recognized for financial statement purposes. The benefit of these excess
tax deductions will not be recognized as an NOL in the Company’s financial statements, until the related
deductions reduce taxes payable and are thereby realized. The Company also has various state 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 impact the amount of such carryforwards.
If unutilized, the federal NOL will expire between 2027 and 2033, and the state NOLs will expire between
2014 and 2033.
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, 2013, the Company
had recognized aggregate EOR credits of $7.9 million that are available to offset regular federal income
taxes in the future. These credits can be carried forward and will expire between 2023 and 2025. Federal
EOR credits are subject to phase-out according to the level of average domestic crude oil prices. The EOR
credit has been phased-out since 2006, but this phase-out affects only the periods for which EOR credits
can be captured and not the periods in which such credits can be utilized.
The Company is subject to the alternative minimum tax (“AMT”) principally due to its significant
intangible drilling cost deductions. As of December 31, 2013, the Company had AMT credits totaling
$18.5 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, 2013, the Company’s foreign tax credit carryforwards totaled $1.2 million, which will
expire between 2014 and 2016. As of December 31, 2013, a valuation allowance of $1.2 million was
established in full for the foreign tax credit carryforwards because the Company determined that it was
more likely than not that the benefit from these deferred tax assets will not be realized due to the divestiture
of all foreign operations.
105
Net deferred income tax liabilities were classified in the consolidated balance sheets as follows (in
thousands):
Year Ended December 31,
2013
2012
Assets:
Current deferred income taxes ............................................................
$
-
Liabilities:
Current deferred income taxes ............................................................
Non-current deferred income taxes .....................................................
Net deferred income tax liabilities ...............................................
648
1,278,030
1,278,678
$
$
$
-
9,394
1,063,681
1,073,075
The following table summarizes the activity related to the Company’s liability for unrecognized tax
benefits (in thousands):
Beginning balance at January 1 ......................................
Decrease related to tax position taken in a prior period ..
Ending balance at December 31......................................
$
$
2013
Year Ended December 31,
2012
2011
170
-
170
$
$
299
(129)
170
$
$
299
-
299
Included in the unrecognized tax benefit balance at December 31, 2013, are $0.2 million of tax positions,
the allowance of which would positively affect the annual effective income tax rate. For the year ended
December 31, 2013, 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 2010 through 2013 tax years generally remain subject to examination
by federal and state tax authorities.
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 ....................................................................
Denominator:
2013
Year Ended December 31,
2012
2011
$
366,055
(494)
$
414,189
(1,077)
$
491,687
(1,077)
$
365,561
$
413,112
$
490,610
Weighted average shares outstanding, basic .........
118,260
117,601
117,345
Diluted Earnings Per Share
Numerator:
Net income available to common shareholders,
basic ....................................................................
Preferred stock dividends ......................................
Adjusted net income available to common
shareholders, diluted ...........................................
$
365,561
538
$
413,112
1,077
$
490,610
1,077
$
366,099
$
414,189
$
491,687
106
2013
Year Ended December 31,
2012
2011
Denominator:
Weighted average shares outstanding, basic .........
Restricted stock and stock options ........................
Convertible perpetual preferred stock ...................
Weighted average shares outstanding, diluted ......
118,260
957
371
119,588
117,601
633
794
119,028
117,345
529
794
118,668
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, 2012 and 2011.
3.09
3.06
3.51
3.48
4.18
4.14
$
$
$
$
$
$
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. For the year ended December 31, 2011, the diluted earnings per share
calculation excludes the dilutive effect of (i) 113,228 incremental shares of restricted stock that did not
meet its market-based vesting criteria as of December 31, 2011, and (ii) 2,285 common shares for stock
options that 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, 2013 and
2012 (in thousands):
December 31,
2013
2012
Assets
Unit distributions due from Trust I (1) ...................................................
Liabilities
Unit distributions payable to Trust I (2) .................................................
_____________________
(1) This amount represents Whiting’s 15.8% interest in the net proceeds due from Trust I and is included within
1,093
6,932
5,731
929
$
$
$
$
accounts receivable trade, net in the Company’s consolidated balance sheets.
(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, 2013 and 2012, respectively, but which the
Company has not yet distributed to Trust I as of December 31, 2013 and 2012, respectively. Due to ongoing
processing of Trust I revenues and expenses after December 31, 2013 and 2012, the amount of Whiting’s next
scheduled distribution to Trust I, and the related distribution by Trust I to its unitholders, will differ from this
amount. These amounts are included within accounts payable trade in the Company’s consolidated balance
sheet.
For the year ended December 31, 2013, Whiting paid $30.7 million, net of state tax withholdings, in unit
distributions to Trust I and received $4.7 million in distributions back from Trust I pursuant to its retained
ownership in 2,186,389 Trust I units.
107
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 is 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.
The final remaining payment of $23.9 million due Alliant Energy under this agreement has been reflected
in the Company’s consolidated balance sheets as a current liability at December 31, 2013. During 2013,
2012 and 2011, the Company made payments of $1.8 million, $2.3 million and $1.9 million, respectively,
under this agreement and recognized interest expense of $3.1 million, $2.2 million and $2.1 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, 2013 (in thousands):
2014
Non-cancelable leases . $ 6,279
87,610
Drilling rig contracts ...
Construction and
drilling contract ........
31,066
Total ...................... $ 124,955
2015
$ 5,872
48,531
Payments due by period
2017
$ 5,250
-
2018
$ 4,629
-
2016
$ 5,387
1,755
Thereafter
$ 1,374
-
Total
$ 28,791
137,896
-
$ 54,403
2,900
$ 10,042
6,900
$ 12,150
4,100
$ 8,729
-
$ 1,374
44,966
$ 211,653
Non-cancelable Leases—The Company leases 172,400 square feet of administrative office space in
Denver, Colorado under an operating lease arrangement expiring in 2018, 47,900 square feet of office
space in Midland, Texas expiring in 2020 and 20,000 square feet of office space in Dickinson, North
Dakota expiring in 2016. In addition, the Company entered into a lease for several residential apartments
in Watford City and Dickinson, North Dakota under an operating lease arrangement expiring in 2015.
Rental expense for 2013, 2012 and 2011 amounted to $5.0 million, $5.7 million and $4.4 million,
respectively. Minimum lease payments under the terms of non-cancelable operating leases as of December
31, 2013 are shown in the table above.
Drilling Rig Contracts—The Company currently has 12 drilling rigs under long-term contract, of which six
drilling rigs expire in 2014, four in 2015 and two in 2016. All of these rigs are operating in the Rocky
Mountains region. As of December 31, 2013, early termination of the remaining contracts would require
termination penalties of $101.1 million, which would be in lieu of paying the remaining drilling
commitments of $137.9 million. No other drilling rigs working for the Company are currently under long-
term contracts or contracts that cannot be terminated at the end of the well that is currently being drilled.
108
During 2013, 2012 and 2011, the Company made payments of $92.8 million, $101.1 million and $49.8
million, respectively, under these long-term contracts, which are initially capitalized as a component of oil
and gas properties and either depleted in future periods or written off as exploration expense. Two of these
drilling rigs have price adjustment clauses that make their corresponding day rates fluctuate, and this
component of those purchase obligations is therefore variable. Minimum drilling commitments under the
terms of these contracts as of December 31, 2013 are shown in the table above.
Construction and Drilling Contract—The Company entered into a contract whereby it is obligated to
spend up to $51.4 million on the construction of certain facilities and field infrastructure and the drilling of
forty-six CO2 wells in its Bravo Dome field. As of December 31, 2013, the Company had spent $6.4
million towards meeting this contractual commitment and had a remaining capital expenditure obligation of
$45.0 million. If the Company fails to spend the required amounts by the dates set forth in the agreement,
it will be required to pay the remaining unspent capital expenditures as liquidated damages. However, the
Company expects to fulfill its obligations under this contract and therefore avoid any payments for
deficiencies. The Company’s remaining financial commitments under this agreement as of December 31,
2013 are shown in the table above. The Company does not have any volumetric CO2 delivery or supply
commitments associated with this contract.
Purchase Contracts—The Company has three take-or-pay purchase agreements, one agreement expiring in
December 2014, one agreement expiring in December 2017 and one agreement expiring in December
2029, whereby the Company has committed to buy certain volumes of CO2 for use in its EOR project in the
North Ward Estes field in Texas. The purchase agreements are with two different suppliers. Under the
terms of the agreements, the Company is obligated to purchase a minimum daily volume of CO2 (as
calculated on an annual basis) or else pay for any deficiencies at the price in effect when the minimum
delivery was to have occurred. In addition, the Company has one ship-or-pay agreement, expiring in
December 2017, whereby it has committed to transport a minimum daily volume of CO2 via a certain
pipeline or else pay for any deficiencies at a price stipulated in the contract.
The CO2 volumes planned for use in the Company’s EOR project in the North Ward Estes field currently
exceed the minimum daily volumes specified in all of these agreements. Therefore, the Company expects
to avoid any payments for deficiencies. During 2013, 2012 and 2011, purchases and transportation of CO2
amounted to $88.1 million, $86.0 million and $69.8 million, respectively. Although minimum daily
quantities are specified in the agreements, the actual CO2 volumes purchased or transported and their
corresponding unit prices are variable over the term of the contracts. As a result, the future minimum
payments for each of the five succeeding fiscal years are not fixed and determinable and are not therefore
included in the table above. As of December 31, 2013, the Company estimated future commitments under
these purchase agreements to approximate $632.6 million through 2029.
Delivery Commitments—The Company has various physical delivery contracts which require the
Company to deliver fixed volumes of natural gas and crude oil. As of December 31, 2013, the Company
had delivery commitments of 4.0 Bcf of natural gas for the year ended December 31, 2014, which relate to
gas production at its Boies Ranch field in Rio Blanco County, Colorado and its Flat Rock field in Uintah
County, Utah. As of December 31, 2013, the Company also had delivery commitments of 9.1 MMBbl,
11.0 MMBbl, 12.8 MMBbl, 14.6 MMBbl and 16.4 MMBbl of crude oil for the years ended December 31,
2015, 2016, 2017, 2018 and 2019, respectively. These delivery commitments relate to crude oil production
at Whiting’s Redtail field in the DJ Basin in Weld County, Colorado. The Company anticipates that future
production from this field will be sufficient to meet the delivery commitments under these physical
delivery contracts, and the Company therefore expects to avoid any payments for deficiencies. As a result,
there is no financial obligation under these contracts.
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.
109
Accordingly, no material amounts for loss contingencies associated with litigation, claims or assessments
have been accrued at December 31, 2013 or 2012. 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.
14.
OIL AND GAS ACTIVITIES
The Company’s oil and gas activities for 2013, 2012 and 2011 were entirely within the United States.
Costs incurred in oil and gas producing activities were as follows (in thousands):
Development (1) ...............................................................
Proved property acquisition ............................................
Unproved property acquisition........................................
Exploration......................................................................
Total .........................................................................
2013
$ 2,132,824
232,572
174,103
363,234
$ 2,902,733
Year Ended December 31,
2012
$ 1,667,182
19,785
119,175
436,084
$ 2,242,226
2011
$ 1,245,150
4,324
191,482
400,823
$ 1,841,779
_____________________
(1) During 2013, 2012 and 2011, non-cash additions to oil and gas properties of $29.8 million, $36.3 million and
$4.9 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.
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
$
2013
108,861
Year Ended December 31,
2012
2011
$
90,519
$
4,434
pending the determination of proved reserves ..............
281,951
384,223
354,962
Reclassifications to wells, facilities and equipment
based on the determination of proved reserves ............
Capitalized exploratory well costs charged to expense ....
Ending balance at December 31 .......................................
(291,962)
(13,472)
85,378
$
(358,625)
(7,256)
108,861
$
(267,847)
(1,030)
90,519
$
At December 31, 2013, the Company had $10.3 million of capitalized exploratory well costs related to one
well that was in progress for a period of greater than one year after the completion of drilling. This well is
located in the Company’s Rocky Mountains region. Of the $10.3 million in costs capitalized for this
exploratory well, $7.7 million and $2.6 million were incurred in 2013 and 2012, respectively. Due to the
high nitrogen and CO2 content resident in the natural gas produced by this well, processing is required
before this well’s gas can be sold. Before Whiting can begin building a CO2 removal and compression skid
and gas pipeline for this well, however, the Company needs to first determine if there are sufficient
quantities of natural gas reserves in this field to make the construction of gas processing facilities
economically justifiable. As a result, the Company is continuing to drill additional wells in this area to
delineate the field and to make a determination as to the aggregate quantity of natural gas reserves that can
be produced from this reservoir.
15.
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
For all years presented our independent petroleum engineers independently estimated all of the proved,
probable and possible reserve quantities included in this annual report. In connection with our external
petroleum engineers performing their independent reserve estimations, we furnish them with the following
information that they review: (1) technical support data, (2) technical analysis of geologic and engineering
110
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, 2013. Proved
reserve estimates included herein conform to the definitions prescribed by the U.S. Securities and
Exchange Commission. Estimates of proved reserves are inherently imprecise and are continually subject
to revision based on production history, results of additional exploration and development, price changes
and other factors.
As of December 31, 2013, 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, 2011, 2012 and 2013 are as follows:
Oil
(MBbl)
NGLs
(MBbl)
Natural Gas
(MMcf)
Total
(MBOE)
Balance—January 1, 2011 ..........................
Extensions and discoveries ..................
Sales of minerals in place ....................
Purchases of minerals in place .............
Production............................................
Revisions to previous estimates ...........
Balance—December 31, 2011 ....................
Extensions and discoveries ..................
Sales of minerals in place ....................
Production............................................
Revisions to previous estimates ...........
Balance—December 31, 2012 ....................
Extensions and discoveries ..................
Sales of minerals in place ....................
Purchases of minerals in place .............
Production............................................
Revisions to previous estimates ...........
Balance—December 31, 2013 ....................
Proved developed reserves:
December 31, 2010 ..............................
December 31, 2011 ..............................
December 31, 2012 ..............................
December 31, 2013 ..............................
Proved undeveloped reserves:
December 31, 2010 ..............................
December 31, 2011 ..............................
December 31, 2012 ..............................
December 31, 2013 ..............................
224,196
39,660
(579)
114
(18,299)
15,052
260,144
68,134
(7,960)
(23,139)
4,106
301,285
88,293
(36,992)
14,543
(27,035)
7,327
347,421
160,088
180,975
190,845
198,204
64,108
79,169
110,440
149,217
30,082
5,024
(632)
58
(2,074)
5,151
37,609
6,526
(320)
(2,766)
(951)
40,098
9,830
(4,777)
1,311
(2,821)
1,228
44,869
18,321
22,109
24,204
23,721
11,761
15,500
15,894
21,148
303,544
23,211
(9,759)
1,639
(26,443)
(7,217)
284,975
40,915
(13,987)
(25,827)
(61,812)
224,264
63,893
(12,411)
7,751
(26,917)
20,934
277,514
220,530
211,297
160,893
183,129
83,014
73,678
63,371
94,385
304,869
48,552
(2,837)
445
(24,780)
19,000
345,249
81,479
(10,611)
(30,209)
(7,148)
378,760
108,772
(43,838)
17,146
(34,342)
12,044
438,542
215,164
238,300
241,864
252,446
89,705
106,949
136,896
186,096
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.
111
• 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.
Notable changes in proved reserves for the year ended December 31, 2011 included:
• Extensions and discoveries. In 2011, total extensions and discoveries of 48.6 MMBOE were
primarily attributable to successful drilling in the Sanish 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 in these areas.
• Revisions to previous estimates. In 2011, revisions to previous estimates increased proved
developed and undeveloped reserves by a net amount of 19.0 MMBOE. Included in these revisions
were (i) 4.7 MMBOE of upward adjustments caused by higher crude oil prices incorporated into
the Company’s reserve estimates at December 31, 2011 as compared to December 31, 2010, and
(ii) 14.3 MMBOE of net upward adjustments attributable to reservoir analysis and well
performance. The oil component of the net 14.3 MMBOE revision consisted of a 10.9 MMBOE
increase that was primarily related to the Postle and North Ward Estes fields, where the
performance of the CO2 injection EOR projects supported an increase in the proved reserve
assignments. The NGL component of the net 14.3 MMBOE revision consisted of a 4.8 MMBOE
increase due to the performance of the Postle and North Ward Estes fields and various properties in
the Northern Rockies area, primarily in the Sanish field. The gas component of the net 14.3
MMBOE revision consisted of a 1.4 MMBOE decrease that was primarily related to the Flat Rock
field where proved reserve assignments were reduced due to the production performance of two
recently completed wells.
112
As discussed in Deferred Compensation within these footnotes to the consolidated financial statements, all
of the Company’s employees participate in the Company’s Production Participation Plan (the “Plan”). The
reserve disclosures above include oil and natural gas reserve volumes that have been allocated to the Plan.
Once allocated to Plan participants, the interests are fixed. Allocations prior to 1995 consisted of 2%–3%
overriding royalty interest, while allocations since 1995 have been 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, 2013, 2012 and 2011 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, 2013, 2012 and 2011,
respectively) to estimated future production. Future production and development costs are computed by
estimating the expenditures to be incurred in developing and producing the proved oil and natural gas
reserves at year end, based on year-end costs and assuming the continuation of existing economic
conditions.
Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net
cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future
income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the
proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to
derive the standardized measure of discounted future net cash flows. This calculation does not necessarily
result in an estimate of the fair value of the Company’s oil and gas properties.
The standardized measure of discounted future net cash flows relating to proved oil and natural gas
reserves is as follows (in thousands):
Future cash flows................................................................
Future production costs ......................................................
Future development costs ...................................................
Future income tax expense .................................................
Future net cash flows ..........................................................
10% annual discount for estimated timing of cash flows ...
Standardized measure of discounted future net cash
flows ..............................................................................
2013
$ 35,178,399
(12,973,292)
(5,355,383)
(3,954,401)
12,895,323
(6,301,462)
December 31,
2012
$ 29,308,752
(11,397,332)
(3,181,618)
(4,278,529)
10,451,273
(5,044,240)
2011
$ 26,815,086
(8,908,131)
(1,982,813)
(4,875,973)
11,048,169
(5,775,677)
$ 6,593,861
$ 5,407,033
$ 5,272,492
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 not have changed in 2013 and would have decreased by $20.2
million and $50.7 million in 2012 and 2011, respectively.
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):
113
Beginning of year ...........................................................
Sale of oil and gas produced, net of production costs ....
Sales of minerals in place ...............................................
Net changes in prices and production costs ....................
Extensions, discoveries and improved recoveries ..........
Previously estimated development costs incurred
during the period .........................................................
Changes in estimated future development costs .............
Purchases of minerals in place .......................................
Revisions of previous quantity estimates .......................
Net change in income taxes ............................................
Accretion of discount .....................................................
End of year .....................................................................
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
December 31,
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
2011
$ 3,667,606
(1,415,469)
(67,600)
2,246,014
1,156,740
408,079
(797,542)
10,604
452,668
(755,369)
366,761
$ 5,272,492
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, 2013, 2012 and 2011 as follows:
Oil (per Bbl) .....................................................................
NGLs (per Bbl) ................................................................
Natural Gas (per Mcf) ......................................................
2013
$ 90.80
$ 54.38
4.30
$
2012
$ 87.15
$ 58.15
3.21
$
2011
$ 89.18
$ 62.93
4.39
$
16.
QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of the unaudited quarterly financial data for the years ended December 31,
2013 and 2012 (in thousands, except per share data):
Three Months Ended
Year ended December 31, 2013:
Oil, NGL and natural gas sales ................... $
Operating profit (1) ...................................... $
Net income (loss) ........................................ $
Basic earnings (loss) per share ................... $
Diluted earnings (loss) per share ................ $
March 31,
2013
605,114
252,806
86,244
0.73
0.72
June 30,
2013
651,868
269,528
134,944
1.14
1.14
$
$
$
$
$
September 30,
2013
706,543
316,764
204,091
1.72
1.71
$
$
$
$
$
December 31,
2013
703,024
280,311
(59,276)
(0.50)
(0.50)
$
$
$
$
$
Three Months Ended
Year ended December 31, 2012:
Oil, NGL and natural gas sales ................... $
Operating profit (1) ...................................... $
Net income ................................................. $
Basic earnings per share ............................. $
Diluted earnings per share .......................... $
_____________________
(1) Oil, NGL and natural gas sales less lease operating expense, production taxes and depreciation, depletion and
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
September 30,
2012
521,195
204,230
83,113
0.70
0.70
December 31,
2012
565,066
235,635
81,689
0.69
0.69
March 31,
2012
558,697
263,176
98,446
0.84
0.83
June 30,
2012
492,756
201,900
150,851
1.28
1.27
amortization.
******
114
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of disclosure controls and procedures. In accordance with Rule 13a-15(b) of the Securities Exchange
Act of 1934 (the “Exchange Act”), our management evaluated, with the participation of our Chairman and Chief
Executive Officer and our Chief Financial Officer, the effectiveness of the design and operation of our disclosure
controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of the end of the year ended
December 31, 2013. Based upon their evaluation of these disclosures controls and procedures, the Chairman and
Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures were
effective as of the end of the year ended December 31, 2013 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,
2013 using the criteria set forth in Internal Control - Integrated Framework (1992) issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Based on this assessment, our management believes that,
as of December 31, 2013, our internal control over financial reporting was effective based on those criteria.
The effectiveness of our internal control over financial reporting as of December 31, 2013 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, 2013 that has materially affected, or is reasonably
likely to materially affect, our internal control over financial reporting.
115
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, 2013, based on criteria established in Internal Control — Integrated
Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The
Company's management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting, included in the accompanying
Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an
opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether effective internal control over financial reporting was maintained in all material respects. Our audit
included obtaining an understanding of internal control over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the
assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the
company's principal executive and principal financial officers, or persons performing similar functions, and effected
by the company's board of directors, management, and other personnel to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance with generally
accepted accounting principles, and that receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets
that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion
or improper management override of controls, material misstatements due to error or fraud may not be prevented or
detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over
financial reporting to future periods are subject to the risk that the controls may become inadequate because of
changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting
as of December 31, 2013, based on the criteria established in Internal Control — Integrated Framework (1992)
issued by the Committee of Sponsoring Organizations of the Treadway Commission.
116
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, 2013 of the Company and our report dated February 27, 2014 expressed an unqualified opinion on
those financial statements and financial statement schedule.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 27, 2014
Item 9B. Other Information
None.
Item 10. Directors, Executive Officers and Corporate Governance
PART III
The information included under the captions “Election of Directors,” “Board of Directors and Corporate
Governance” and “Section 16(a) Beneficial Ownership Reporting Compliance” in our definitive Proxy Statement
for Whiting Petroleum Corporation’s 2014 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 and Chief Executive Officer, our Chief Financial Officer, our Controller and Treasurer and
other persons performing similar functions. We have posted a copy of the Whiting Petroleum Corporation Code of
Business Conduct and Ethics on our website at www.whiting.com. The Whiting Petroleum Corporation Code of
Business Conduct and Ethics is also available in print to any stockholder who requests it in writing from the
Corporate Secretary of Whiting Petroleum Corporation. We intend to satisfy the disclosure requirements under
Item 5.05 of Form 8-K regarding amendments to, or waivers from, the Whiting Petroleum Corporation Code of
Business Conduct and Ethics by posting such information on our website at www.whiting.com.
We are not including the information contained on our website as part of, or incorporating it by reference into, this
report.
Item 11. Executive Compensation
The information required by this Item is included under the captions “Board of Directors and Corporate
Governance – Compensation Committee Interlocks and Insider Participation,” “Board of Directors and Corporate
Governance – Director Compensation,” “Compensation Discussion and Analysis,” “Compensation Committee
Report” and “Executive Compensation” in the Proxy Statement and is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
The information required by this Item with respect to security ownership of certain beneficial owners and
management is included under the caption “Principal Stockholders” in the Proxy Statement and is 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, 2013.
117
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)
420,840
-
420,840
$
$
28.65
N/A
28.65
5,380,594 (2)
-
5,380,594 (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 420,840 stock options outstanding and 1,444,310 shares of restricted common stock previously issued
for which the restrictions have not lapsed.
Item 13. Certain Relationships, Related Transactions and Director Independence
The information required by this Item is included under the caption “Board of Directors and Corporate Governance
– Transactions with Related Persons” and “Board of Directors and Corporate Governance – Independence of
Directors” in the Proxy Statement and is incorporated herein by reference.
Item 14. Principal Accounting Fees and Services
The information required by this Item is included under the caption “Ratification of Appointment of Independent
Registered Public Accounting Firm” in the Proxy Statement and is 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
118
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
WHITING PETROLEUM CORPORATION
CONDENSED FINANCIAL STATEMENTS OF THE PARENT COMPANY
CONDENSED BALANCE SHEETS
(in thousands)
December 31,
2013
2012
ASSETS
Current assets ............................................................................................................................ $
Investment in subsidiaries .........................................................................................................
Intercompany receivable ...........................................................................................................
5,120
2,707,184
3,796,321
Total assets........................................................................................................................... $ 6,508,625
LIABILITIES AND EQUITY
Current liabilities ....................................................................................................................... $
Long-term debt ..........................................................................................................................
Other long-term liabilities .........................................................................................................
Shareholders’ equity ..................................................................................................................
26,054
2,653,834
170
3,828,567
Total liabilities and equity ................................................................................................... $ 6,508,625
$
2,390
2,330,987
1,748,463
$ 4,081,840
$
14,372
600,000
21,244
3,446,224
$ 4,081,840
CONDENSED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(in thousands)
Year Ended December 31,
2012
2011
2013
Operating expenses:
General and administrative ................................................................... $
(1,131)
$
(16,506)
$
(12,024)
Interest expense ....................................................................................
Equity in earnings of subsidiaries .........................................................
Income before income taxes ........................................................................
Income tax benefit ................................................................................
Net income .................................................................................................. $
Comprehensive income ............................................................................... $
(2,922)
361,732
357,679
8,376
366,055
366,055
(2,168)
425,870
407,196
6,993
414,189
414,189
$
$
(2,066)
500,564
486,474
5,213
491,687
491,687
$
$
See notes to condensed financial statements.
119
WHITING PETROLEUM CORPORATION
CONDENSED FINANCIAL STATEMENTS OF THE PARENT COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(in thousands)
Schedule I
Cash flows provided by operating activities ................................................ $
2013
Year Ended December 31,
2012
16,423
$
$
-
2011
4,962
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 ........................
Other financing activities .........................................................................
Net cash used in financing activities .................................................
(2,048,253)
1,100,000
1,204,000
(253,988)
(1,759)
-
(14,094)
-
-
-
(2,329)
(16,423)
Net change in cash and cash equivalents .....................................................
Cash and cash equivalents:
Beginning of period ..................................................................................
End of period ............................................................................................ $
-
-
-
$
-
-
-
$
(3,091)
-
-
-
(1,871)
(4,962)
-
-
-
NONCASH INVESTING ACTIVITIES:
Distributions from Whiting USA Trust I decreasing investment in
subsidiaries .......................................................................................... $
(4,749)
$
(5,827)
$
(6,500)
NONCASH FINANCING ACTIVITIES:
Preferred stock dividends paid decreasing shareholders’ equity .............. $
Preferred stock dividends paid decreasing intercompany receivable ....... $
Distributions from Whiting USA Trust I increasing intercompany
receivable ............................................................................................ $
(538)
(538)
4,749
$
$
$
(1,077)
(1,077)
5,827
$
$
$
(1,077)
(1,077)
6,500
See notes to condensed financial statements.
120
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, 2013, total restricted net assets were
$4,070.4 million. Accordingly, these condensed financial statements have been prepared pursuant to Rule
5-04 of Regulation S-X of the Securities Exchange Act of 1934, as amended.
2.
LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES
The Parent Company’s long-term debt and other long-term liabilities consisted of the following at
December 31, 2013 and 2012 (in thousands):
Long-term debt
7% Senior Subordinated Notes due 2014 ............................................ $
6.5% Senior Subordinated Notes due 2018 .........................................
5% Senior Notes due 2019 ...................................................................
5.75% Senior Notes due 2021, including unamortized debt
$
-
350,000
1,100,000
premium of $3,834 .........................................................................
1,203,834
250,000
350,000
-
-
Other long-term liabilities
December 31,
2013
2012
Tax sharing liability (1) .........................................................................
Other ....................................................................................................
Total long-term debt and other long-term liabilities ................................... $
_____________________
(1) As of December 31, 2013, the entire $23.9 million balance due to Alliant Energy under the tax sharing agreement
was reflected as a current liability in these condensed financial statements and is included in the schedule of
maturities below.
-
170
2,654,004
21,074
170
621,244
$
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, 2013 were as follows (in thousands):
2014
2015
2016
2017
2018
Thereafter
Total
Amounts due ..... $ 23,856
$
-
$
-
$
-
$ 350,000
$ 2,300,000
$2,673,856
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.
121
3.
SHAREHOLDERS’ EQUITY
Common Stock—In May 2011, the Registrant’s stockholders approved an amendment to its Restated
Certificate of Incorporation to increase the number of authorized shares of common stock from
175,000,000 shares to 300,000,000 shares.
Stock Split. On January 26, 2011, the Board of Directors approved a two-for-one split of the Registrant's
shares of common stock to be effected in the form of a stock dividend. As a result of the stock split,
stockholders of record on February 7, 2011 received one additional share of common stock for each share
of common stock held. The additional shares of common stock were distributed on February 22, 2011. The
common stock dividend resulted in the conversion price for Parent Company’s 6.25% Convertible
Perpetual Preferred Stock being adjusted from $43.4163 to $21.70815.
6.25% Convertible Perpetual Preferred Stock—In June 2009, the Parent Company completed a public
offering of 6.25% convertible perpetual preferred stock (“preferred stock”), selling 3,450,000 shares at a
price of $100.00 per share. As 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 shares of
preferred stock outstanding on March 31, 2013, were converted into 792,919 shares of common stock. As
of December 31, 2013, no shares of preferred stock remained outstanding.
For further information on the common stock and convertible perpetual preferred stock, refer to the
Shareholders’ Equity note to the consolidated financial statements of the Registrant.
******
122
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, 2014.
SIGNATURES
WHITING PETROLEUM CORPORATION
By /s/ James J. Volker
James J. Volker
Chairman and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature
Title
/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/ Philip E. Doty
Philip E. Doty
/s/ William N. Hahne
William N. Hahne
/s/ Allan R. Larson
Allan R. Larson
/s/ Michael B. Walen
Michael B. Walen
Chairman and Chief
Executive Officer and Director
(Principal Executive Officer)
Vice President and
Chief Financial Officer
(Principal Financial Officer)
Controller and Treasurer
(Principal Accounting Officer)
Director
Director
Director
Director
Director
Director
123
Date
February 27, 2014
February 27, 2014
February 27, 2014
February 27, 2014
February 27, 2014
February 27, 2014
February 27, 2014
February 27, 2014
February 27, 2014
Exhibit
Number
(3.1)
(3.2)
(4.1)
(4.2)
(4.3)
(4.4)
(4.5)
(4.6)
(4.7)
(4.8)
EXHIBIT INDEX
Exhibit Description
Restated Certificate of Incorporation of Whiting Petroleum Corporation [Incorporated by reference
to Exhibit 3.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated June 28,
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 dated February 20, 2014 (File No. 001-31899)].
Fifth Amended and Restated Credit Agreement, dated as of October 15, 2010, among Whiting
Petroleum Corporation, Whiting Oil and Gas Corporation, the lenders party thereto, JPMorgan
Chase Bank, N.A., as Administrative Agent, and the various other agents party thereto
[Incorporated by reference to Exhibit 4 to Whiting Petroleum Corporation’s Current Report on
Form 8-K dated October 15, 2010 (File No. 001-31899)].
First Amendment to Fifth Amended and Restated Credit Agreement, dated as of April 15, 2011,
among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, JPMorgan Chase Bank,
N.A., as Administrative Agent, the various other agents party thereto and the lenders party thereto
[Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Quarterly Report on
Form 10-Q for the quarter ended March 31, 2011 (File No. 001-31899)].
Second Amendment to Fifth Amended and Restated Credit Agreement, dated as of October 12,
2011, among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, JPMorgan Chase
Bank, N.A., as Administrative Agent, the various other agents party thereto and the lenders party
thereto [Incorporated by reference to Exhibit 4 to Whiting Petroleum Corporation’s Current Report
on Form 8-K dated October 12, 2011 (File No. 001-31899)].
Third Amendment to Fifth Amended and Restated Credit Agreement, dated as of October 19,
2012, among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, JPMorgan Chase
Bank, N.A., as Administrative Agent, and the lenders party thereto [Incorporated by reference to
Exhibit 4 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated October 19, 2012
(File No. 001-31899)].
Fourth Amendment to Fifth Amended and Restated Credit Agreement, dated as of June 27, 2013,
among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, JPMorgan Chase Bank,
N.A., as Administrative Agent, and the lenders party thereto [Incorporated by reference to Exhibit
4.1 to Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the quarter ended June
30, 2013 (File No. 001-31899)].
Fifth Amendment to Fifth Amended and Restated Credit Agreement, dated as of September 6,
2013, among Whiting Petroleum Corporation, its subsidiary Whiting Oil and Gas Corporation,
JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents and lenders party
thereto [Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Current
Report on Form 8-K dated September 6, 2013 (File No. 001-31899)].
Subordinated Indenture, dated as of April 19, 2005, by and among Whiting Petroleum Corporation,
Whiting Oil and Gas Corporation, Whiting Programs, Inc., Equity Oil Company and The Bank of
New York Trust Company, N.A., as successor trustee [Incorporated by reference to Exhibit 4.1 to
Whiting Petroleum Corporation’s Current Report on Form 8-K dated September 21, 2010 (File No.
001-31899)].
Second Supplemental Indenture, dated September 24, 2010, among Whiting Petroleum
Corporation, Whiting Oil and Gas Corporation and The Bank of New York Mellon Trust
Company, N.A., as Trustee, creating the 6.5% Senior Subordinated Notes due 2018 [Incorporated
by reference to Exhibit 4.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated
September 21, 2010 (File No. 001-31899)].
124
Exhibit
Number
(4.9)
(4.10)
(4.11)
(4.12)
(4.13)
(4.14)
(10.1)*
(10.2)*
(10.3)*
(10.4)*
(10.5)*
(10.6)
(10.7)*
Exhibit Description
Rights Agreement, dated as of February 23, 2006, between Whiting Petroleum Corporation and
Computershare Trust Company, Inc. [Incorporated by reference to Exhibit 4.1 to Whiting
Petroleum Corporation’s Current Report on Form 8-K dated February 23, 2006 (File No.
001-31899)].
Notice to JPMorgan Chase Bank, N.A., as Administrative Agent, dated September 9, 2013, to
reduce the aggregate commitments under the Fifth Amended and Restated Credit Agreement, as
amended [Incorporated by reference to Exhibit 4.4 to Whiting Petroleum Corporation’s Current
Report on Form 8-K dated September 9, 2013 (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 dated
September 9, 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 5.000% Senior Notes due 2019 [Incorporated by reference to Exhibit 4.2 to
Whiting Petroleum Corporation’s Current Report on Form 8-K dated September 9, 2013 (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 5.750% Senior Notes due 2021 [Incorporated by reference
to Exhibit 4.3 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated September
9, 2013 (File No. 001-31899)].
Third Supplemental Indenture, dated September 26, 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 5.750% Senior Notes due 2021 issued on September 26, 2013 [Incorporated
by reference to Exhibit 4.3 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated
September 23, 2013 (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 dated October 23, 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 dated
October 23, 2007 (File No. 001-31899)].
Form of Restricted Stock Agreement pursuant to the Whiting Petroleum Corporation 2003 Equity
Incentive Plan for performance vesting awards on and after February 23, 2008 [Incorporated by
reference to Exhibit 10.1 to Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for
the quarter ended March 31, 2008 (File No. 001-31899)].
Whiting Petroleum Corporation Production Participation Plan, as amended and restated February
4, 2008 [Incorporated by reference to Exhibit 10.6 to Whiting Petroleum Corporation’s Annual
Report on Form 10-K for the year ended December 31, 2007 (File No. 001-31899)].
Tax Separation and Indemnification Agreement between Alliant Energy Corporation, Whiting
Petroleum Corporation and Whiting Oil and Gas Corporation [Incorporated by reference to Exhibit
10.3 to Whiting Petroleum Corporation’s Registration Statement on Form S-1 (Registration No.
333-107341)].
Summary of Non-Employee Director Compensation for Whiting Petroleum Corporation.
125
Exhibit
Number
(10.8)*
(10.9)*
(10.10)*
(10.11)*
(10.12)*
(10.13)
(10.14)*
(10.15)*
(10.16)*
(21)
(23.1)
(23.2)
(31.1)
(31.2)
(32.1)
(32.2)
(99.1)
(99.2)
Exhibit Description
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 executive officers of Whiting Petroleum
Corporation [Incorporated by reference to Exhibit 10.10 to Whiting Petroleum Corporation’s
Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 (File No. 001-31899)].
Form of Executive Excise Tax Gross-Up Agreement for executive officers of Whiting Petroleum
Corporation [Incorporated by reference to Exhibit 10.1 to Whiting Petroleum Corporation’s
Current Report on Form 8-K dated January 13, 2009 (File No. 001-31899)].
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)].
Noncompetition Agreement, between J. Douglas Lang and Whiting Petroleum Corporation,
effective as of June 17, 2013 [Incorporated by reference to Exhibit 10.1 to Whiting Petroleum
Corporation’s Current Report on Form 8-K dated June 17, 2013 (File No. 001-31899)].
Purchase and Sale Agreement, by and between Whiting Oil and Gas Corporation and BreitBurn
Operating L.P., effective as of April 1, 2013 [Incorporated by reference to Exhibit 10.1 to Whiting
Petroleum Corporation’s Current Report on Form 8-K dated June 22, 2013 (File No. 001-31899)].
Form of Restricted Stock Agreement pursuant to the Whiting Petroleum Corporation 2013 Equity
Incentive Plan for performance vesting awards.
Form of Restricted Stock Agreement pursuant to the Whiting Petroleum Corporation 2013 Equity
Incentive Plan for time-based vesting awards.
Form of Stock Option Agreement pursuant to the Whiting Petroleum Corporation 2013 Equity
Incentive Plan.
Subsidiaries of Whiting Petroleum Corporation.
Consent of Deloitte & Touche LLP.
Consent of Cawley, Gillespie & Associates, Inc., Independent Petroleum Engineers.
Certification by the Chairman and Chief Executive Officer pursuant to Section 302 of the
Sarbanes-Oxley Act.
Certification by the Vice President and Chief Financial Officer pursuant to Section 302 of the
Sarbanes-Oxley Act.
Written Statement of the Chairman and Chief Executive Officer pursuant to 18 U.S.C.
Section 1350.
Written Statement of the Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section
1350.
Proxy Statement for the 2014 Annual Meeting of Stockholders, to be filed within 120 days of
December 31, 2013 [To be filed with the Securities and Exchange Commission under Regulation
14A within 120 days after December 31, 2013; except to the extent specifically incorporated by
reference, the Proxy Statement for the 2014 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 3, 2014.
126
Exhibit
Number
(101)
Exhibit Description
The following materials from Whiting Petroleum Corporation’s Annual Report on Form 10-K for
the year ended December 31, 2013 are filed herewith, formatted in XBRL (Extensible Business
Reporting Language): (i) the Consolidated Balance Sheets as of December 31, 2013 and 2012, (ii)
the Consolidated Statements of Income for the Years Ended December 31, 2013, 2012 and 2011,
(iii) the Consolidated Statements of Comprehensive Income for the Years Ended December 31,
2013, 2012 and 2011, (iv) the Consolidated Statements of Cash Flow for the Years Ended
December 31, 2013, 2012 and 2011, (v) the Consolidated Statements of Equity for the Years
Ended December 31, 2013, 2012 and 2011 and (vi) Notes to Consolidated Financial Statements.
*
A management contract or compensatory plan or arrangement.
127
Director Compensation
Effective January 1, 2014, non-employee director compensation is as follows:
Director Compensation
Effective January 1, 2014, non-employee director compensation is as follows:
Committee Service
Annual retainer .....................................................
Restricted stock (value), one year vesting ............
Annual retainer .....................................................
Committee chair annual retainer ...........................
Restricted stock (value), one year vesting ............
Committee chair restricted stock (value) ..............
Committee member annual retainer ......................
Committee chair annual retainer ...........................
Committee chair restricted stock (value) ..............
Meeting fee ...........................................................
Committee member annual retainer ......................
Meeting fee ...........................................................
Board
Service
Board
$
58,500
Service
$ 157,500
$
58,500
$ 157,500
$
$
1,500
1,500
Audit
Committee Service
Compensation
Audit
$ 25,000
$ 25,000
$ 10,000
$ 25,000
$ 25,000
1,500
$
$ 10,000
1,500
$
Compensation
$
$
$
$
$
$
$
$
15,000
15,000
15,000
5,000
15,000
1,500
5,000
1,500
Exhibit 10.7
Exhibit 10.7
Nominating
and
Nominating
Governance
and
Governance
$ 15,000
$ 15,000
$
$ 15,000
5,000
$ 15,000
1,500
$
5,000
$
1,500
$
(cid:3)
(cid:3)
(cid:3)
(cid:3)
WHITING PETROLEUM CORPORATION
RESTRICTED STOCK AGREEMENT
Exhibit 10.14
THIS RESTRICTED STOCK AGREEMENT (this “Agreement”) is made and entered into as of
[•], 20[•] by and between Whiting Petroleum Corporation, a Delaware corporation with its principal offices at
Denver, Colorado (the “Company”), and the executive officer of the Company or one of its affiliates whose
signature is set forth on the signature page hereof (the “Participant”).
W I T N E S S E T H :
WHEREAS, the Company has adopted the Whiting Petroleum Corporation 2013 Equity Incentive
Plan (the “Plan”) to permit shares of the Company’s common stock (the “Stock”), to be awarded to certain key
salaried employees and non-employee directors of the Company and any affiliate of the Company; and
WHEREAS, the Participant is an executive officer of the Company, and the Company desires such
person to remain in such capacity and to further an opportunity for his or her stock ownership in the Company in
order to increase his or her proprietary interest in the success of the Company;
NOW, THEREFORE, in consideration of the premises and of the covenants and agreements herein
set forth, the parties hereby mutually covenant and agree as follows:
1. Award of Restricted Stock. Subject to the terms and conditions set forth herein, the
Company hereby awards the Participant the number of shares of Stock set forth on the signature page
hereof (the “Restricted Stock”).
2. Restrictions. (a) Except as otherwise provided herein, Restricted Stock may not be
sold, transferred, pledged, assigned, encumbered or otherwise alienated or hypothecated until the date of
release (the “Release Date”) determined as follows:
(i)
the Release Date with respect to one-third of the shares of Restricted Stock
shall be the first anniversary of the Grant Date specified on the signature page hereof (the “Grant
Date”) if the Compensation Committee of the Board of Directors of the Company (the
“Committee”) determines the Performance Contingency (as defined below) has been satisfied with
respect to the Company’s fiscal year immediately preceding the first anniversary of the Grant Date;
(ii)
the Release Date with respect to two-thirds of the shares of Restricted
Stock (less any shares of Restricted Stock for which there already has been a Release Date) shall be
the second anniversary of the Grant Date if the Committee determines the Performance
Contingency has been satisfied with respect to the Company’s two fiscal years immediately
preceding the second anniversary of the Grant Date; and
(iii)
the Release Date with respect to all of the shares of Restricted Stock (less
any shares of Restricted Stock for which there already has been a Release Date) shall be the third
anniversary of the Grant Date if the Committee determines the Performance Contingency has been
satisfied with respect to the Company’s three fiscal years immediately preceding the third
anniversary of the Grant Date.
If the Committee determines that the Performance Contingency has not been satisfied with respect
to the criteria set forth in Section 2(a)(iii), then all Restricted Stock that previously has not been released shall be
forfeited to the Company on the date the Committee makes such determination.
(cid:2)
(cid:2)
(b) Within six weeks after the end of each of the Company’s fiscal years preceding the
first three anniversaries of the Grant Date, the Committee will determine whether the Performance
Contingency has been satisfied with respect to such fiscal year based on the criteria set forth in this Section
2. The “Performance Contingency” will be satisfied with respect to such a fiscal year (i) if the Company
Stock Price Percentage (as defined below) at the end of such fiscal year is a positive number and either (A)
the Peer Group Stock Price Percentage (as defined below) at the end of such fiscal year is a positive
number and such Company Stock Price Percentage is greater than such Peer Group Stock Price Change or
(B) the Peer Group Stock Price Percentage is a negative number or (ii) if the Company Stock Price
Percentage at the end of such fiscal year is a negative number and the Peer Group Stock Price Percentage at
the end of such fiscal year is a negative number and the absolute value of such Company Stock Price
Percentage is less than the absolute value of such Peer Group Stock Price Percentage.
(c)
“Company Stock Price Percentage” means the percentage (whether positive or
negative) equal to the quotient of (i) the amount determined by subtracting (A) $[•] (i.e., the closing price
of the Stock on December 31, 20[•]), which shall be adjusted equitably for any stock split, stock dividend,
special cash dividend or similar event affecting the Stock (the “Company Base Price”), from (B) the
closing price of the Stock on each of the fiscal year ends (or the last trading day of each such year)
preceding the first three anniversaries, as applicable, of the Grant Date divided by (ii) the Company Base
Price.
(d)
“Peer Group” means [••••]. If any of the foregoing companies is no longer a
publicly traded company at any time during a fiscal year, then such company shall be removed from the
Peer Group and the remaining companies shall make up the Peer Group for purposes of determining the
Peer Group Stock Price Percentage and whether the Performance Contingency has been satisfied for such
fiscal year and any applicable future fiscal years.
(e)
“Peer Group Stock Price Percentage” means the percentage (whether negative or
positive) equal to the average of the percentages determined for each company in Peer Group by
calculating the quotient of (i) the amount determined by subtracting (A) the closing price of the common
stock of such Peer Group company on December 31, 20[•], which shall be adjusted equitably for any stock
split, stock dividend, special cash dividend or similar event affecting the common stock of such Peer Group
company (the “Peer Group Company Base Price”), from (B) closing price of the common stock of such
Peer Group company on each of the fiscal year ends (or the last trading day of each such year) preceding
the first three anniversaries, as applicable, of the Grant Date divided by (ii) the Peer Group Company Base
Price.
3. Initial Issuance. The Restricted Stock shall be issued as soon as practicable in the
name of the Participant but shall be held in a segregated account by the transfer agent of the Company.
Unless forfeited as provided herein, Restricted Stock eligible for release pursuant to the terms hereof shall
cease to be held in such segregated account and certificates for such Restricted Stock shall be delivered or
such Restricted Stock shall be transferred electronically to the Participant on the applicable Release Date.
4. Transfer After Release Date; Securities Law Restrictions. On the applicable Release
Date as determined in accordance with Section 2, that portion of Restricted Stock shall become free of the
restrictions of Section 2 and be freely transferable by the Participant. Notwithstanding the foregoing or
anything to the contrary herein, the Participant agrees and acknowledges with respect to any Restricted
Stock that has not been registered under the Securities Act of 1933, as amended (the “Act”) (i) he or she
will not sell or otherwise dispose of such Stock except pursuant to an effective registration statement under
the Act and any applicable state securities laws, or in a transaction which, in the opinion of counsel for the
Company, is exempt from such registration, and (ii) a legend will be placed on the certificates for the
Restricted Stock to such effect.
(cid:2)
(cid:2)
5. Termination of Employment or Death. If the Participant’s employment with the
Company (as applicable) is terminated for any reason (including death) prior to the Release Date, all
Restricted Stock that has not been released shall be forfeited to the Company on the date on which such
termination of status occurs.
6. Certificate Legend. In addition to any legends placed on certificates for Restricted
Stock under Section 4 hereof, each certificate for shares of Restricted Stock may bear the following legend:
“THE SALE OR OTHER TRANSFER OF THE SHARES OF STOCK
REPRESENTED BY THIS CERTIFICATE, WHETHER VOLUNTARY,
INVOLUNTARY OR BY OPERATION OF LAW, IS SUBJECT TO CERTAIN
RESTRICTIONS SET FORTH IN THE WHITING PETROLEUM CORPORATION
2013 EQUITY INCENTIVE PLAN AND A RESTRICTED STOCK AGREEMENT
BETWEEN WHITING PETROLEUM CORPORATION AND THE REGISTERED
OWNER HEREOF. A COPY OF SUCH PLAN AND SUCH AGREEMENT MAY
BE OBTAINED FROM THE CORPORATE SECRETARY OF WHITING
PETROLEUM CORPORATION.”
When the restrictions imposed by Section 2 hereof terminate, the Participant shall be entitled to have the foregoing
legend removed from the certificates representing such Restricted Stock.
7. Voting Rights; Dividends and Other Distributions. (a) While the Restricted Stock is
subject to restrictions under Section 2 and prior to any forfeiture thereof, the Participant may exercise full
voting rights for the Restricted Stock registered in his or her name and held in a segregated account
hereunder.
(b) While the Restricted Stock is subject to the restrictions under Section 2 and prior to
any forfeiture thereof, the Participant shall be entitled to receive all dividends and other distributions paid
with respect to the Restricted Stock. If any such dividends or distributions are paid in Stock, such shares
shall be subject to the same terms, conditions and restrictions as the shares of Restricted Stock with respect
to which they were paid, including the requirement that Restricted Stock be held in a segregated account
pursuant to Section 3 hereof.
(c)
Subject to the provisions of this Agreement, the Participant shall have, with respect
to the Restricted Stock, all other rights of holders of Stock.
8. Tax Withholding. (a) It shall be a condition of the obligation of the Company to issue
or release from the segregated account Restricted Stock to the Participant, and the Participant agrees, that
the Participant shall pay to the Company upon demand such amount as may be requested by the Company
for the purpose of satisfying its liability to withhold federal, state, or local income or other taxes incurred
by reason of the award of the Restricted Stock or as a result of the termination of the restrictions on such
Stock hereunder.
(b)
If the Participant does not make an election under Section 83(b) of the Internal
Revenue Code of 1986, as amended, with respect to the Restricted Stock awarded hereunder, the
Participant may satisfy the Company’s withholding tax requirements by electing to have the Company
withhold that number of shares of Restricted Stock otherwise deliverable to the Participant from the
segregated account hereunder or to deliver to the Company a number of shares of Stock, in each case,
having a Fair Market Value (as defined in the Plan) on the Tax Date (as defined below) equal to the
minimum amount required to be withheld as a result of the termination of the restrictions on such
Restricted Stock. The election must be made in writing and must be delivered to the Company prior to the
Tax Date. If the number of shares so determined shall include a fractional share, the Participant shall
deliver cash in lieu of such fractional share. All elections shall be made in a form approved by the
(cid:2)
(cid:2)
Committee and shall be subject to disapproval, in whole or in part, by the Committee. As used herein,
“Tax Date” means the date on which the Participant must include in his or her gross income for federal
income tax purposes the fair market value of the Restricted Stock over the purchase price therefor, if any.
9. Powers of Company Not Affected. The existence of the Restricted Stock shall not
affect in any way the right or power of the Company or its stockholders to make or authorize any
combination, subdivision or reclassification of the Stock or any reorganization, merger, consolidation,
business combination, exchange of shares, or other change in the Company’s capital structure or its
business, or any issue of bonds, debentures or stock having rights or preferences equal, superior or affecting
the Restricted Stock or the rights thereof, or dissolution or liquidation of the Company, or any sale or
transfer of all or any part of its assets or business, or any other corporate act or proceeding, whether of a
similar character or otherwise. Nothing in this Agreement shall confer upon the Participant any right to
continue in the employment of the Company, or interfere with or limit in any way the right of the Company
to terminate the Participant’s employment at any time.
10. Interpretation by Committee. The Participant agrees that any dispute or disagreement
which may arise in connection with this Agreement shall be resolved by the Committee, in its sole
discretion, and that any interpretation by the Committee of the terms of this Agreement or the Plan and any
determination made by the Committee under this Agreement or the Plan may be made in the sole discretion
of the Committee and shall be final, binding, and conclusive. Any such determination need not be uniform
and may be made differently among Participants awarded Restricted Stock.
11. Miscellaneous. (a) This Agreement shall be governed and construed in accordance
with the internal laws of the State of Delaware applicable to contracts made and to be performed therein
between residents thereof.
(b)
This Agreement may not be amended or modified except by the written consent of
the parties hereto.
(c)
The captions of this Agreement are inserted for convenience of reference only and
shall not be taken into account in construing this Agreement.
(d)
Any notice, filing or delivery hereunder or with respect to Restricted Stock shall be
given to the Participant at either his or her usual work location or his or her home address as indicated in
the records of the Company, and shall be given to the Committee or the Company at 1700 Broadway, Suite
2300, Denver, Colorado 80290-2300, Attention: Corporate Secretary. All such notices shall be given by
first class mail, postage prepaid, or by personal delivery.
(e)
This Agreement shall be binding upon and inure to the benefit of the Company and
its successors and assigns and shall be binding upon and inure to the benefit of the Participant, except that
the Participant may not transfer any interest in any Restricted Stock prior to the release of the restrictions
imposed by Section 2.
(f)
This Agreement is subject in all respects to the terms and conditions of the Plan.
12. Change of Control. Notwithstanding any other provision to the contrary contained in
this Agreement, effective upon a Change in Control(as defined in the Plan), the restrictions imposed upon
the Restricted Stock (except for any such shares which were previously forfeited to the Company) by
Section 2 of this Agreement shall immediately be deemed to have lapsed and the Release Date shall be
deemed to have occurred as of the date of the Change in Control with respect to such Restricted Stock.
[Signature page follows]
(cid:2)
(cid:2)
IN WITNESS WHEREOF, the Company has caused this instrument to be executed by its duly
authorized officer and the Participant has hereunto affixed his or her signature, all as of the day and year first set
forth above.
WHITING PETROLEUM CORPORATION
By:
James J. Volker
Chief Executive Officer
«Name»
No. of Shares of Restricted Stock: «Shares»
Grant Date:
(cid:2)
(cid:2)
WHITING PETROLEUM CORPORATION
RESTRICTED STOCK AGREEMENT
Exhibit 10.15
THIS RESTRICTED STOCK AGREEMENT (this “Agreement”) is made and entered into as of
[•], 20[•] by and between Whiting Petroleum Corporation, a Delaware corporation with its principal offices at
Denver, Colorado (the “Company”), and the non-employee director or key employee of the Company or one of its
affiliates whose signature is set forth on the signature page hereof (the “Participant”).
W I T N E S S E T H :
WHEREAS, the Company has adopted the Whiting Petroleum Corporation 2013 Equity Incentive
Plan (the “Plan”) to permit shares of the Company’s common stock (the “Stock”), to be awarded to certain key
salaried employees and non-employee directors of the Company and any affiliate of the Company; and
WHEREAS, the Participant is a key salaried employee or a non-employee director of the
Company, and the Company desires such person to remain in such capacity and to further an opportunity for his or
her stock ownership in the Company in order to increase his or her proprietary interest in the success of the
Company;
NOW, THEREFORE, in consideration of the premises and of the covenants and agreements herein
set forth, the parties hereby mutually covenant and agree as follows:
1. Award of Restricted Stock. Subject to the terms and conditions set forth herein, the Company
hereby awards the Participant the number of shares of Stock set forth on the signature page hereof (the “Restricted
Stock”).
2. Restrictions. Except as otherwise provided herein, Restricted Stock may not be sold,
transferred, pledged, assigned, encumbered or otherwise alienated or hypothecated until the date of release (the
“Release Date”) determined as follows: the Release Date with respect to one-third of the shares of Restricted
Stock shall be the first anniversary of the Grant Date specified on the signature page hereof; the Release Date with
respect to an additional one-third of the shares of Restricted Stock shall be the second anniversary of the Grant
Date; and the Release Date with respect to the remaining one-third of the shares of Restricted Stock shall be the
third anniversary of the Grant Date.
3. Initial Issuance. The Restricted Stock shall be issued as soon as practicable in the name of the
Participant but shall be held in a segregated account by the transfer agent of the Company. Unless forfeited as
provided herein, Restricted Stock eligible for release pursuant to the terms hereof shall cease to be held in such
segregated account and certificates for such Restricted Stock shall be delivered or such Restricted Stock shall be
transferred electronically to the Participant on the applicable Release Date.
4. Transfer After Release Date; Securities Law Restrictions. On the applicable Release Date as
determined in accordance with Paragraph 2, that portion of Restricted Stock shall become free of the restrictions of
Paragraph 2 and be freely transferable by the Participant. Notwithstanding the foregoing or anything to the
contrary herein, the Participant agrees and acknowledges with respect to any Restricted Stock that has not been
registered under the Securities Act of 1933, as amended (the “Act”) (i) he or she will not sell or otherwise dispose
of such Stock except pursuant to an effective registration statement under the Act and any applicable state securities
laws, or in a transaction which, in the opinion of counsel for the Company, is exempt from such registration, and
(ii) a legend will be placed on the certificates for the Restricted Stock to such effect.
(cid:2)
(cid:2)
5. Termination of Employment or Death. If the Participant’s employment with, or service on the
board of directors of, the Company (as applicable) is terminated for any reason (including death) prior to the
Release Date, all Restricted Stock that has not been released shall be forfeited to the Company on the date on which
such termination of status occurs.
6. Certificate Legend. In addition to any legends placed on certificates for Restricted Stock under
Paragraph 4 hereof, each certificate for shares of Restricted Stock may bear the following legend:
“THE SALE OR OTHER TRANSFER OF THE SHARES OF STOCK
REPRESENTED BY THIS CERTIFICATE, WHETHER VOLUNTARY,
INVOLUNTARY OR BY OPERATION OF LAW, IS SUBJECT TO CERTAIN
RESTRICTIONS SET FORTH IN THE WHITING PETROLEUM CORPORATION
2013 EQUITY INCENTIVE PLAN AND A RESTRICTED STOCK AGREEMENT
BETWEEN WHITING PETROLEUM CORPORATION AND THE REGISTERED
OWNER HEREOF. A COPY OF SUCH PLAN AND SUCH AGREEMENT MAY
BE OBTAINED FROM THE CORPORATE SECRETARY OF WHITING
PETROLEUM CORPORATION.”
When the restrictions imposed by Paragraph 2 hereof terminate, the Participant shall be entitled to have the
foregoing legend removed from the certificates representing such Restricted Stock.
7. Voting Rights; Dividends and Other Distributions. (a) While the Restricted Stock is subject to
restrictions under Paragraph 2 and prior to any forfeiture thereof, the Participant may exercise full voting rights for
the Restricted Stock registered in his or her name and held in escrow hereunder.
(b) While the Restricted Stock is subject to the restrictions under Paragraph 2 and prior to any
forfeiture thereof, the Participant shall be entitled to receive all dividends and other distributions paid with respect
to the Restricted Stock. If any such dividends or distributions are paid in Stock, such shares shall be subject to the
same terms, conditions and restrictions as the shares of Restricted Stock with respect to which they were paid,
including the requirement that Restricted Stock be held in a segregated account pursuant to Paragraph 3 hereof.
(c) Subject to the provisions of this Agreement, the Participant shall have, with respect to the
Restricted Stock, all other rights of holders of Stock.
8. Tax Withholding. (a) It shall be a condition of the obligation of the Company to issue or
release from the segregated account Restricted Stock to the Participant, and the Participant agrees, that the
Participant shall pay to the Company upon demand such amount as may be requested by the Company for the
purpose of satisfying its liability to withhold federal, state, or local income or other taxes incurred by reason of the
award of the Restricted Stock or as a result of the termination of the restrictions on such Stock hereunder.
(b) If the Participant does not make an election under Section 83(b) of the Internal Revenue Code
of 1986, as amended, with respect to the Restricted Stock awarded hereunder, the Participant may satisfy the
Company’s withholding tax requirements by electing to have the Company withhold that number of shares of
Restricted Stock otherwise deliverable to the Participant from escrow hereunder or to deliver to the Company a
number of shares of Stock, in each case, having a Fair Market Value (as defined in the Plan) on the Tax Date (as
defined below) equal to the minimum amount required to be withheld as a result of the termination of the
restrictions on such Restricted Stock. The election must be made in writing and, if the Participant is an Insider (as
defined below), (i) delivered to the Company either six months or more prior to the Tax Date or during a ten-day
period beginning on the third day following the release of the Company’s quarterly or annual summary statement of
sales and earnings which occurs prior to the Tax Date and (ii) shall not be effective until at least six months after
the Grant Date, provided, however, that the restriction in clause (ii) shall not apply in the event death or Total
Disability of the Participant occurs prior to the expiration of such six-month period. If the Participant is not an
Insider, the election must be delivered to the Company prior to the Tax Date. If the Participant is an Insider, the
(cid:2)
(cid:2)
full number of shares of Restricted Stock deliverable may be released to the Participant, and in such event the
Participant shall be unconditionally obligated to tender back to the Company, as soon as practicable after the Tax
Date, a number of shares of Stock having a Fair Market Value on the Tax Date equal to the minimum amount
required to be withheld. If the number of shares so determined shall include a fractional share, the Participant shall
deliver cash in lieu of such fractional share. All elections shall be made in a form approved by the Committee (as
defined in the Plan) and shall be subject to disapproval, in whole or in part, by the Committee. As used herein, (i)
“Tax Date” means the date on which the Participant must include in his or her gross income for federal income tax
purposes the fair market value of the Restricted Stock over the purchase price therefor and (ii) “Insider” means an
officer or director of the Company or a beneficial owner of more than 10% of the class of Stock.
9. Powers of Company Not Affected. The existence of the Restricted Stock shall not affect in any
way the right or power of the Company or its stockholders to make or authorize any combination, subdivision or
reclassification of the Stock or any reorganization, merger, consolidation, business combination, exchange of
shares, or other change in the Company’s capital structure or its business, or any issue of bonds, debentures or stock
having rights or preferences equal, superior or affecting the Restricted Stock or the rights thereof, or dissolution or
liquidation of the Company, or any sale or transfer of all or any part of its assets or business, or any other corporate
act or proceeding, whether of a similar character or otherwise. Nothing in this Agreement shall confer upon the
Participant any right to continue in the employment of the Company, or interfere with or limit in any way the right
of the Company to terminate the Participant’s employment at any time.
10. Interpretation by Committee. The Participant agrees that any dispute or disagreement which
may arise in connection with this Agreement shall be resolved by the Compensation Committee of the Board of
Directors of the Company (the “Committee”), in its sole discretion, and that any interpretation by the Committee of
the terms of this Agreement or the Plan and any determination made by the Committee under this Agreement or the
Plan may be made in the sole discretion of the Committee and shall be final, binding, and conclusive. Any such
determination need not be uniform and may be made differently among Participants awarded Restricted Stock.
11. Miscellaneous. (a) This Agreement shall be governed and construed in accordance with the
internal laws of the State of Delaware applicable to contracts made and to be performed therein between residents
thereof.
(b) This Agreement may not be amended or modified except by the written consent of the parties
hereto.
(c) The captions of this Agreement are inserted for convenience of reference only and shall not be
taken into account in construing this Agreement.
(d) Any notice, filing or delivery hereunder or with respect to Restricted Stock shall be given to
the Participant at either his or her usual work location or his or her home address as indicated in the records of the
Company, and shall be given to the Committee or the Company at 1700 Broadway, Suite 2300, Denver, Colorado
80290-2300, Attention: Corporate Secretary. All such notices shall be given by first class mail, postage prepaid, or
by personal delivery.
(e) This Agreement shall be binding upon and inure to the benefit of the Company and its
successors and assigns and shall be binding upon and inure to the benefit of the Participant, except that the
Participant may not transfer any interest in any Restricted Stock prior to the release of the restrictions imposed by
Paragraph 2.
(f) This Agreement is subject in all respects to the terms and conditions of the Plan.
12. Change of Control. Notwithstanding any other provision to the contrary contained in this
Agreement, effective upon a Change in Control (as defined in the Plan), the restrictions imposed upon the
Restricted Stock (except for any such shares which were previously forfeited to the Company) by Paragraph 2 of
(cid:2)
(cid:2)
this Agreement shall immediately be deemed to have lapsed and the Release Date shall be deemed to have occurred
as of the date of the Change in Control with respect to such Restricted Stock.
[Signature page follows]
(cid:2)
(cid:2)
IN WITNESS WHEREOF, the Company has caused this instrument to be executed by its duly
authorized officer and the Participant has hereunto affixed his or her signature, all as of the day and year first set
forth above.
COMPANY
WHITING PETROLEUM CORPORATION
PARTICIPANT
By:
James J. Volker
Chief Executive Officer
No. of Shares of Restricted Stock:
Grant Date:
(cid:2)
(cid:2)
Exhibit 10.16
WHITING PETROLEUM CORPORATION
STOCK OPTION AGREEMENT
THIS STOCK OPTION AGREEMENT (this “Agreement”) is made and entered into as of the date set
forth on the signature page hereof (the “Grant Date”) by and between Whiting Petroleum Corporation, a Delaware
corporation with its principal offices at Denver, Colorado (the “Company”), and the key employee of the Company
or one of its Affiliates whose signature is set forth on the signature page hereof (the “Participant”).
W I T N E S S E T H :
WHEREAS, the Company has adopted the Whiting Petroleum Corporation 2013 Equity Incentive Plan (the
“Plan”) to permit options to purchase shares of the Company’s common stock (the “Stock”) to be awarded to
certain key employees of the Company and any Affiliate of the Company; and
WHEREAS, the Participant is a key employee of the Company, and the Company desires such person to
remain in such capacity and to further an opportunity for his or her stock ownership in the Company in order to
increase his or her proprietary interest in the success of the Company;
NOW, THEREFORE, in consideration of the premises and of the covenants and agreements herein set
forth, the parties hereby mutually covenant and agree as follows:
1. Grant. Subject to the terms and conditions of the Plan, a copy of which is made a part hereof,
and this Agreement, the Company hereby grants to the Participant an option to purchase from the Company all or
any part of the aggregate number of shares of Stock set forth on the signature page hereof (hereinafter such shares
of Stock are referred to as the “Optioned Shares,” and the option to purchase the Optioned Shares is referred to as
the “Option”). The Option is not intended to qualify as an incentive stock option within the meaning of
Section 422 of the Internal Revenue Code of 1986, as amended.
2. Vesting. One-third of the Optioned Shares shall vest and become exercisable on each of the
first three anniversaries of the Grant Date, provided the Participant has remained in the continuous employment of
the Company and its Affiliates from the Grant Date through and including the applicable vesting date. Any
Optioned Shares not vested as of the date of the Participant’s termination of employment from the Company and its
Affiliates shall be forfeited.
3. Price. The price to be paid for each Optioned Share shall be the price set forth on the signature
page hereof (the “Option Price”).
4. Term; Exercise. The Participant may exercise the Option, to the extent vested, in whole or in
part until the close of business at the Company’s headquarters on the earliest of:
(a)
(b)
The tenth anniversary of the Grant Date;
The first anniversary of the Participant’s termination of employment from the Company
and its Affiliates for any reason other than cause; and
(c)
The date of the Participant’s termination of employment from the Company and its
Affiliates for cause, as determined by the Compensation Committee of the Board of Directors of the Company (the
“Committee”) in its sole discretion. The exercise of the Option may be suspended pending the Committee’s
(cid:2)
(cid:2)
determination of whether the Participant’s employment is terminated for cause, and in the event the Committee
determines that termination is for cause, such exercise shall be rescinded.
5. Method of Exercise. The Option may be exercised only by written notice, provided to the
Company in the manner set forth in Paragraph 10(d), specifying the number of vested Optioned Shares being
purchased. Such notice shall be accompanied by payment of the entire Option Price of the Optioned Shares being
purchased plus related federal, state, local or foreign withholding taxes due as a result of exercise, which may be
paid:
(a)
in cash, or by check or money order;
(b)
Market Value at the date of delivery);
by delivery (including by attestation) of shares of Stock (which will be valued at Fair
(c)
(d)
through a cashless exercise procedure established by the Committee, if any; or
by any combination of the foregoing.
Shares of Stock tendered under subparagraph (b) above shall be duly endorsed in blank or
accompanied by stock powers duly endorsed in blank. Upon receipt of the payment of the entire purchase price of
the Optioned Shares being purchased and the related federal, state, local or foreign withholding taxes, certificates
for such Optioned Shares shall be issued to the Participant. The Optioned Shares so purchased shall be fully paid
and nonassessable.
6. Securities Law Restrictions. Notwithstanding the foregoing or anything to the contrary herein,
the Participant agrees and acknowledges with respect to any Stock received under this Option that has not been
registered under the Securities Act of 1933, as amended (the “Act”) (a) he or she will not sell or otherwise dispose
of such Stock except pursuant to an effective registration statement under the Act and any applicable state securities
laws, or in a transaction which, in the opinion of counsel for the Company, is exempt from such registration, and
(b) a legend will be placed on the certificates for the Stock to such effect.
7. No Rights as a Stockholder. The Participant shall not be deemed for any purposes to be a
stockholder of the Company with respect to any shares that may be acquired hereunder except to the extent that the
Option shall have been exercised with respect thereto and a stock certificate issued therefor.
8. Powers of Company Not Affected. The existence of the Option shall not affect in any way the
right or power of the Company or its stockholders to make or authorize any combination, subdivision or
reclassification of the Stock or any reorganization, merger, consolidation, business combination, exchange of
shares, or other change in the Company’s capital structure or its business, or any issue of bonds, debentures or stock
having rights or preferences equal, superior or affecting the Stock or the rights thereof, or dissolution or liquidation
of the Company, or any sale or transfer of all or any part of its assets or business, or any other corporate act or
proceeding, whether of a similar character or otherwise. Nothing in this Agreement shall confer upon the
Participant any right to continue in the employment of the Company or any Affiliate, or interfere with or limit in
any way the right of the Company or an Affiliate to terminate the Participant’s employment at any time.
9. Interpretation by Committee. The Participant agrees that any dispute or disagreement which
may arise in connection with this Agreement shall be resolved by the Committee, in its sole discretion, and that any
interpretation by the Committee of the terms of this Agreement or the Plan and any determination made by the
Committee under this Agreement or the Plan may be made in the sole discretion of the Committee and shall be
final, binding, and conclusive. Any such determination need not be uniform and may be made differently among
Participants awarded options under the Plan.
(cid:2)
(cid:2)
10. Miscellaneous. (a) This Agreement shall be governed and construed in accordance with the
internal laws of the State of Delaware applicable to contracts made and to be performed therein between residents
thereof.
(b) This Agreement may not be amended or modified except by the written consent of the parties
hereto.
(c) The captions of this Agreement are inserted for convenience of reference only and shall not be
taken into account in construing this Agreement.
(d) Any notice, filing or delivery hereunder or with respect to the Option shall be given to the
Participant at either his or her usual work location or his or her home address as indicated in the records of the
Company, and shall be given to the Committee or the Company at 1700 Broadway, Suite 2300, Denver, Colorado
80290-2300, Attention: Corporate Secretary. All such notices shall be given by first class mail, postage prepaid, or
by personal delivery.
(e) This Agreement shall be binding upon and inure to the benefit of the Company and its
successors and assigns and shall be binding upon and inure to the benefit of the Participant and his successor and
assigns, except that the Participant may not transfer any interest in any Option other than pursuant to will or the
laws of descent and distribution. Any individual claiming entitlement to exercise the Option following the
Participant’s death shall provide such information and evidence of his or her right to do so in such form as is
satisfactory to the Company.
(f) This Agreement is subject in all respects to the terms and conditions of the Plan. Any
capitalized terms used in this Agreement but not defined herein shall have the meanings given in the Plan.
11. Change of Control. Notwithstanding any other provision to the contrary contained in this
Agreement, effective upon a Change in Control (as defined in the Plan), the Optioned Shares shall become 100%
vested if the Participant is employed by the Company or an Affiliate immediately prior to the date of such Change
in Control.
[Signature page follows]
(cid:2)
(cid:2)
IN WITNESS WHEREOF, the Company has caused this instrument to be executed by its duly authorized
officer and the Participant has hereunto affixed his or her signature, all as of the day and year set forth below.
WHITING PETROLEUM CORPORATION
PARTICIPANT
By:
James J. Volker
Chief Executive Officer
No. of Optioned Shares:
Option Price per Share: $
Grant Date:
(cid:2)
(cid:2)
SUBSIDIARIES OF WHITING PETROLEUM CORPORATION
Name
Whiting Oil and Gas Corporation
Jurisdiction of
Incorporation or
Organization
Delaware
Percent
Ownership
100%
Exhibit 21
(cid:2)
(cid:2)
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement Nos. 333-111056 and 333-190197 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, 2014, 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, 2013.
Exhibit 23.1
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 27, 2014
(cid:2)
(cid:2)
Cawley, Gillespie & Associates, Inc.
P E T R O L E U M C O N S U L T A N T S
(cid: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
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, 2013. 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, 2013, 2012 and 2011 and to the
inclusion of our reports dated January 3, 2014 as an exhibit to the Annual Report on Form 10-K of Whiting
Petroleum Corporation for the year ended December 31, 2013. We further consent to the incorporation by
reference thereof into Whiting Petroleum Corporation’s Registration Statements on Form S-8 (Registration Nos.
333-111056 and 333-190197), 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, 2014
(cid:2)
(cid:2)
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 and Chief Executive Officer
Date: February 27, 2014
(cid:2)
(cid:2)
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
Date: February 27, 2014
Michael J. Stevens
Vice President and Chief Financial Officer
/s/ Michael J. Stevens
Michael J. Stevens
Date: February 27, 2014
Vice President and Chief Financial Officer
(cid:3)
(cid:3)
(cid:3)
(cid:3)
Written Statement of the Chief Executive Officer
Pursuant to 18 U.S.C. Section 1350
Exhibit 32.1
Solely for the purposes of complying with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002, I, the undersigned Chairman and Chief Executive Officer of Whiting Petroleum
Corporation, a Delaware corporation (the “Company”), hereby certify, based on my knowledge, that the Annual
Report on Form 10-K of the Company for the fiscal year ended December 31, 2013 (the “Report”) fully complies
with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and that information contained in the
Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
/s/ James J. Volker
James J. Volker
Chairman and Chief Executive Officer
Date: February 27, 2014
(cid:2)
(cid:2)
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, 2013 (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, 2014
(cid:2)
(cid:2)
Cawley, Gillespie & Associates, Inc.
P E T R O L E U M C O N S U L T A N T S
Exhibit 99.2
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
(cid:2)
January 3, 2014
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
(cid: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
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, 2013
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 3, 2014 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
181,673.9
172,527.2
19,831.5
1,528.0
9,141.5
468.2
15,002.0
1,460.6
3,420.9
- M$
- M$
- M$
- M$
- M$
- M$
- M$
16,374,094.0
695,266.1
997,729.9
139,710.0
37,586.0
21,603.9
1,397,231.4
5,132.9
194,753.2
1,592,264.6
183,014.0
6,287,949.5
324,007.7
13,982.0
1,840.8
42,789.2
9,278.7
73,816.4
37,213.5
268,143.2
273,292.2
Net Operating Income
- M$
9,679,857.0
131,009.1
944,652.1
Discounted @ 10%
- M$
5,741,946.0
29,386.7
261,341.9
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
149,217.3
94,385.0
21,148.2
347,421.2
277,514.3
44,868.8
13,635,381.0
454,046.4
1,225,861.9
31,546,420.0
1,192,031.4
2,439,948.0
1,049,492.3
379,090.3
3,043,696.3
3,347,822.8
2,729,555.3
601,158.8
9,642,578.0
3,954,401.8
7,495,188.5
18,250,706.0
2,961,371.5
8,994,048.0
(cid:2)
(cid:2)
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 $96.78 per bbl
and $3.67 per MMBtu, respectively, were adjusted individually to WTI posted pricing at $93.55 per bbl and
Houston Ship Channel pricing at $3.65 per MMBtu, as of December 31, 2013. 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 $90.80 per bbl of oil, $54.38 per bbl of natural gas liquids and $4.30 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
(cid:2)
(cid:2)
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.
(cid:2)
(cid:2)
Yours very truly,
/s/ Robert D. Ravnaas
Robert D. Ravnaas, P.E.
President
Cawley, Gillespie & Associates(cid:2)
Texas Registered Engineering Firm F-693
(cid:2)
APPENDIX
Explanatory Comments for Individual Tables
Table Number
Effective Date of the Evaluation
Identity of Interest Evaluated
Reserve Classification and Development Status
Operator – Property Name
Field (Reservoir) Names – County, State
Calendar or Fiscal years/months commencing on effective date.
Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic
feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the
effective date are shown following the annual/monthly forecasts.
Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take
into account changes in interest and gas shrinkage.
Average (volume weighted) gross liquid price per barrel before deducting production-severance taxes.
Average (volume weighted) gross gas price per Mcf before deducting production-severance taxes.
Average (volume weighted) gross NGL price per barrel before deducting production-severance taxes.
Revenue derived from oil sales -- column (5) times column (8).
Revenue derived from gas sales -- column (6) times column (9).
Revenue derived from NGL sales -- column (7) times column (10).
Revenue derived from other sources.
Revenue derived from hedge positions.
Total Revenue – sum of column (12) through column (16).
Production-Severance taxes deducted from gross oil and NGL revenue.
Production-Severance taxes deducted from gross gas revenue.
Revenue after taxes – column (17) less column (18) and column (19).
Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative
overhead charges for operated oil and gas producers known as COPAS.
Ad Valorem taxes.
Work-over Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair.
3rd Party COPAS are combined fixed rate administrative overhead charges for non-operated oil and gas producers.
Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs.
Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and
the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life.
Future Net Cash Flow is column (18) less the total of column (19), column (22), column (24), column (25), column (26) and column (27). The
data in column (28) are accumulated in column (29). Federal income taxes have not been considered.
Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates.
HEADINGS
FORECAST
(Columns)
(1) (11) (21)
(2) (3) (4)
(5) (6) (7)
(8)
(9)
(10)
(12)
(13)
(14)
(15)
(16)
(17)
(18)
(19)
(20)
(22)
(23)
(24)
(25)
(26)
(27)
(28) (29)
(30)
MISCELLANEOUS
Input Data
Interests
DCF Profile
Life
Footnotes
(cid:2)
• Evaluation parameters such as rates, tax percentages, and expenses are shown below columns (21-26).
•
• The cash flow discounted at six different rates are shown at the bottom of columns (29-30). Interest has been compounded
Initial and final expense and revenue interests are shown below columns (27-28).
monthly.
• The economic life of the appraised property is noted in the lower right-hand corner of the table.
• Well ID information or other pertinent comments may be shown in the lower left-hand footnotes.
(cid:2)(cid:3)(cid:4)(cid:5)(cid:6)(cid:7)(cid:8)(cid:9)(cid:10)(cid:11)(cid:5)(cid:5)(cid:6)(cid:12)(cid:13)(cid:11)(cid:6)(cid:9)(cid:14)(cid:9)(cid:15)(cid:12)(cid:12)(cid:16)(cid:17)(cid:11)(cid:3)(cid:18)(cid:6)(cid:12)(cid:8)(cid:9)(cid:19)(cid:20)(cid:17)(cid:21)(cid:9)
(cid:9)
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.
(cid:9)
(cid:2)(cid:3)(cid:4)(cid:5)(cid:6)(cid:7)(cid:8)(cid:9)(cid:10)(cid:11)(cid:5)(cid:5)(cid:6)(cid:12)(cid:13)(cid:11)(cid:6)(cid:9)(cid:14)(cid:9)(cid:15)(cid:12)(cid:12)(cid:16)(cid:17)(cid:11)(cid:3)(cid:18)(cid:6)(cid:12)(cid:8)(cid:9)(cid:19)(cid:20)(cid:17)(cid:21)(cid:9)
(cid:9)
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.
(cid:2)(cid:3)(cid:4)(cid:5)(cid:6)(cid:7)(cid:8)(cid:9)(cid:10)(cid:11)(cid:5)(cid:5)(cid:6)(cid:12)(cid:13)(cid:11)(cid:6)(cid:9)(cid:14)(cid:9)(cid:15)(cid:12)(cid:12)(cid:16)(cid:17)(cid:11)(cid:3)(cid:18)(cid:6)(cid:12)(cid:8)(cid:9)(cid:19)(cid:20)(cid:17)(cid:21)(cid:9)
(cid:9)
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).”
(cid:2)
(cid:2)(cid:3)(cid:4)(cid:5)(cid:6)(cid:7)(cid:8)(cid:9)(cid:10)(cid:11)(cid:5)(cid:5)(cid:6)(cid:12)(cid:13)(cid:11)(cid:6)(cid:9)(cid:14)(cid:9)(cid:15)(cid:12)(cid:12)(cid:16)(cid:17)(cid:11)(cid:3)(cid:18)(cid:6)(cid:12)(cid:8)(cid:9)(cid:19)(cid:20)(cid:17)(cid:21)(cid:9)
(cid:9)
Appendix
Page 4
Cawley, Gillespie & Associates, Inc.
P E T R O L E U M C O N S U L T A N T S
1 3 6 4 0 B R I A R W I C K D R I V E , S U I T E 1 0 0
A U S T I N , T E X A S 7 8 7 2 9 - 1 7 0 7
5 1 2 - 2 4 9 - 7 0 0 0
3 0 6 W E S T S E V E N T H S T R E E T , S U I T E 3 0 2
F O R T W O R T H , T E X A S 7 6 1 0 2 - 4 9 8 7
8 1 7 - 3 3 6 - 2 4 6 1
w w w . c g a u s . c o m
1 0 0 0 L O U I S I A N A S T R E E T , S U I T E 6 2 5
H O U S T O N , T E X A S 7 7 0 0 2 - 5 0 0 8
7 1 3 - 6 5 1 - 9 9 4 4
January 3, 2014
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, 2013
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 3, 2014 covers 100% of the probable and possible reserves estimated for Whiting
Petroleum Corporation. This report includes results for an SEC pricing scenario. The results of this evaluation are
presented in the accompanying tabulations, with a composite summary presented below, beginning with the
probable summary and followed by the possible summary:
Net Reserves
Oil
Gas
NGL
Revenue
Oil
Gas
NGL
Severance Taxes
Ad Valorem Taxes
Operating Expenses
Investments
Net Operating Income
- Mbbl
- MMcf
- Mbbl
- M$
- M$
- M$
- M$
- M$
- M$
- M$
- M$
Discounted @ 10%
- M$
Probable Developed
Behind Pipe
Probable
Undeveloped
Total
Probable
748.1
6,831.9
139.5
69,047.0
27,639.0
5,771.6
6,522.2
1,365.5
31,047.1
5,304.1
58,218.8
32,007.9
108,519.5
260,723.1
22,190.9
9,922,280.0
1,301,342.6
1,139,478.9
762,354.2
428,324.1
2,640,484.5
3,152,649.8
5,379,293.5
1,830,880.4
109,267.5
267,554.9
22,330.4
9,991,329.0
1,328,981.6
1,145,250.8
768,876.3
429,689.6
2,671,532.0
3,157,954.0
5,437,512.5
1,862,888.3
Possible
Developed
Possible Developed
Non-Producing
Possible
Undeveloped
Total
Possible
Net Reserves
Oil
Gas
NGL
Revenue
Oil
Gas
NGL
Severance Taxes
Ad Valorem Taxes
Operating Expenses
Investments
Net Operating Income
- Mbbl
- MMcf
- Mbbl
- M$
- M$
- M$
- M$
- M$
- M$
- M$
- M$
Discounted @ 10%
- M$
754.8
1,693.7
98.5
67,579.8
6,843.9
4,249.8
4,339.6
1,965.8
14,797.5
6,735.6
50,834.9
27,036.3
1,234.5
52.5
288.1
115,758.2
189.6
16,578.0
6,101.7
3,072.1
16,365.5
26,814.2
80,172.3
28,906.9
135,234.4
162,034.3
24,220.0
12,450,120.0
684,815.3
1,401,039.1
844,115.8
341,939.4
2,240,180.8
2,652,584.0
137,223.6
163,780.4
24,606.6
12,633,459.0
691,848.7
1,421,866.8
854,557.1
346,977.3
2,271,343.8
2,686,134.0
8,457,154.0
8,588,163.0
1,700,430.1
1,756,373.6
The discounted cash flow value 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 $96.78 per bbl
and $3.67 per MMBtu, respectively, were adjusted individually to WTI posted pricing at $93.55 per bbl and
Houston Ship Channel pricing at $3.65 per MMBtu, as of December 31, 2013. 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 $91.44 per bbl of oil, $51.29 per bbl of natural gas liquids and $4.97 per mcf of natural gas.
For the Possible reserves, the average adjusted prices were $92.07 per bbl of oil, $57.78 per bbl of natural gas
liquids and $4.22 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
Life
Footnotes
• Evaluation parameters such as rates, tax percentages, and expenses are shown below columns (21-26).
•
• The cash flow discounted at six different rates are shown at the bottom of columns (29-30). Interest has been compounded
Initial and final expense and revenue interests are shown below columns (27-28).
monthly.
• The economic life of the appraised property is noted in the lower right-hand corner of the table.
• Well ID information or other pertinent comments may be shown in the lower left-hand footnotes.
Cawley, Gillespie & Associates, Inc.(cid:9)
(cid:9)
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.(cid:9)
(cid:9)
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.
(cid:9)
(cid:9)
Cawley, Gillespie & Associates, Inc.(cid:9)
(cid:9)
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.(cid:9)
(cid:9)
Appendix
Page 4
Cawley, Gillespie & Associates, Inc.
P E T R O L E U M C O N S U L T A N T S
1 3 6 4 0 B R I A R W I C K D R I V E , S U I T E 1 0 0
A U S T I N , T E X A S 7 8 7 2 9 - 1 7 0 7
5 1 2 - 2 4 9 - 7 0 0 0
3 0 6 W E S T S E V E N T H S T R E E T , S U I T E 3 0 2
F O R T W O R T H , T E X A S 7 6 1 0 2 - 4 9 8 7
8 1 7 - 3 3 6 - 2 4 6 1
w w w . c g a u s . c o m
1 0 0 0 L O U I S I A N A S T R E E T , S U I T E 6 2 5
H O U S T O N , T E X A S 7 7 0 0 2 - 5 0 0 8
7 1 3 - 6 5 1 - 9 9 4 4
Professional Qualifications of Robert D. Ravnaas, P.E.
President of Cawley, Gillespie & Associates
Mr. Ravnaas has been a Petroleum Consultant for Cawley, Gillespie & Associates (CG&A) since 1983, and became
President in 2011. He has completed numerous field studies, reserve evaluations and reservoir simulation,
waterflood design and monitoring, unit equity determinations and producing rate studies. He has testified before
the Texas Railroad Commission in unitization and field rules hearings. Prior to CG&A he worked as a Production
Engineer for Amoco Production Company. Mr. Ravnaas received a B.S. with special honors in Chemical
Engineering from the University of Colorado at Boulder, and a M.S. in Petroleum Engineering from the University
of Texas at Austin. He is a registered professional engineer in Texas, No. 61304, and a member of the Society of
Petroleum Engineers (SPE), the Society of Petroleum Evaluation Engineers, the American Association of
Petroleum Geologists and the Society of Professional Well Log Analysts.
Intentionally Left Blank
EXECUTIVE OFFICERS
OTHER OFFICERS
BOARD OF DIRECTORS
JAMES J.VOLKER
Chairman of the Board
and Chief Executive Officer
JAMES T. BROWN
President and
Chief Operating Officer
PETER W. HAGIST
Vice President, Permian Operations
for Whiting Oil and Gas Corporation
CHUCK LACOUTURE
Vice President, Marketing
for Whiting Oil and Gas Corporation
MARK R. WILLIAMS
Senior Vice President, Exploration
and Development
MARK D. SONNENFELD
Vice President, Geoscience
for Whiting Oil and Gas Corporation
DIRECTOR SINCE
JAMES J. VOLKER 2003
Chairman of the Board
and Chief Executive Officer
THOMAS L. ALLER *+ 2003
President
Interstate Power and
Light Company
an Alliant Energy Company
MICHAEL J. STEVENS
Vice President and
Chief Financial Officer
JOHN K. SOUTHWELL
Vice President, Permian Exploration
for Whiting Oil and Gas Corporation
D. SHERWIN ARTUS^ 2006
Retired President and CEO
Whiting Petroleum Corporation
BRUCE R. DEBOER
Vice President, General Counsel
and Corporate Secretary
DOUGLAS L. WALTON
Vice President and
National Drilling Manager
for Whiting Oil and Gas Corporation
STEVEN A. KRANKER
Vice President, Reservoir Engineering
and Acquisitions
ERIC K. HAGEN
Vice President, Investor Relations
DAVID M. SEERY
Vice President, Land
RICK A. ROSS
Vice President, Operations
HEATHER M. DUNCAN
Vice President, Human Resources
BRENT P. JENSEN
Controller and Treasurer
JACK R. EKSTROM
Vice President, Corporate
and Government Relations
MICHAEL R. CRAIG
Vice President,
Information Technology
PHILIP E. DOTY*^ 2010
Certified Public Accountant
WILLIAM N. HAHNE +^ 2007
Past Chief Operating Officer
Petrohawk Energy Corporation
ALLAN R. LARSON^ 2011
Consulting Geologist
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.
350 Indiana Street, Suite 800
Golden, Colorado 80401
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
Tel: (303) 837-1661
Eric K. Hagen
Cawley, Gillespie & Associates, Inc.
Vice President, Investor Relations
INDEPENDENT REGISTERED
Tel: (303) 837-1661
PUBLIC ACCOUNTING FIRM
Deloitte & Touche LLP
ANNUAL REPORT ON FORM 10-K
Upon request, the Company will
provide, without charge, copies of the
2013 Annual Report on Form 10-K
as filed with the Securities and
Exchange Commission
ANNUAL MEETING
Tuesday, May 6, 2014
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
1700 Broadway, Suite 2300
Denver, Colorado 80290-2300
Tel: (303) 837-1661
Fax: (303) 861-4023
www.whiting.com