RESURGENT
2 0 1 6 A N N U A L R E P O R T
About
the Cover
Re·sur·gent – adjective – rising again, as to new life, vigor
Our team’s dedication and work in 2016 have positioned Whiting with a balance sheet and
enhanced asset base to support strong future growth for years to come.
Whiting has a sharp focus on driving repeatable and profitable oil growth from our core
resource plays in the Williston Basin of North Dakota and Montana and the DJ Basin of
Colorado. In the Williston Basin, we target the Bakken and Three Forks formations. At our
Redtail play in the DJ Basin, we target the Niobrara “A”, “B” and “C” and Codell/Fort Hays
formations.
No detail is too small. Using state-of-the-art technology, our teams analyze the reservoir at a
molecular level, enabling us to optimize well completions and high-grade assets.
Our dedication to better understanding our reservoirs and generating efficiencies has
reduced well costs in the Williston and Eastern DJ Basins while raising per-well estimated
ultimate recoveries (EURs). This improves our returns on drilling and enhances our ability
to deliver long-term value to shareholders through the commodity price cycle.
Forward-
Looking
Statements
This annual report contains forward-looking statements. Please refer to “Forward-Looking
Statements” on page 63 of the attached Annual Report on Form 10-K for an explanation
of these types of statements. These statements should be considered in light of the “Risk
Factors” set forth on page 18 of the attached Annual Report on Form 10-K.
Table of
Contents
Abbreviations
01 Corporate Overview
02 Financial and Operations Summary
04 Letter to the Shareholders
06 Asset Overview
09 Operational Focus
11 Productivity Focus
13 Environmental Focus
14 Board of Directors
15 Form 10-K
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.
MBOE: One thousand BOE.
MBOE/D: MBOE per day.
Bcf: One billion cubic feet, used in reference to
natural gas.
Mcf: One thousand cubic feet, used in reference
to natural gas.
MMBbl: One million barrels.
MMBOE: One million BOE.
MMLb: One million pounds.
NGLs: Natural gas liquids.
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.
BOE/D: BOE per day.
BTU: British Thermal Unit.
Completion: The process of preparing an oil
and gas wellbore for production through the
installation of permanent production equipment,
as well as perforation and fracture stimulation to
optimize production.
Corporate Overview
Headquartered
in Denver, Colorado, Whiting Petroleum
Corporation is an independent oil and gas company that
develops, produces, acquires and explores for crude oil, natural
gas and natural gas liquids in the Rocky Mountains region of the
United States. We are currently focused on organic drilling and
development activity, both on grassroots oil plays and on the
development of previously acquired properties. Whiting targets
projects that provide the opportunity for repeatable success
and meaningful production growth. We lead the industry with
our competitive assets, dedication to technology and record
setting results. Whiting is a competitive company with a strong
plan for the future. The Company’s shares are traded on the New
York Stock Exchange under the stock symbol WLL.
2016 ANNUAL REPORT | WHITING PETROLEUM CORPORATION 1
FINANCIAL & OPERATIONS SUMMARY
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS, PER UNIT PRICES, RATIOS AND WELL AND ACREAGE STATISTICS)
INCOME STATEMENT & CASH FLOW
2016
2015
Oil, NGL & Natural Gas Sales
$ 1,285.0
$ 2,092.5
Net Income (Loss)
Earnings (Loss) per Common Share, Diluted
Weighted Average Shares Outstanding, Diluted
Net Cash Provided by Operating Activities
Net Cash Used in Investing Activities
Net Cash Provided by (Used in) Financing Activities
BALANCE SHEET
Total Assets
Long-Term Debt
Total Equity
Debt-to-Capitalization Ratio
$
(1,339.1)
$
(5.32)
251.869
$
$
$
$
$
$
595.0
(222.6)
(315.3)
2016
9,876.1
3,535.3
5,149.2
41%
$
$
$
$
$
$
$
$
(2,219.3)
(11.35)
195.472
1,051.4
(1,982.1)
868.7
2015
11,389.1
5,197.7
4,758.6
52%
$
$
$
$
$
$
$
$
$
2014
3,024.6
64.7
0.53
122.519
1,815.3
(2,860.5)
423.9
2014
13,993.1
5,602.4
5,703.0
50%
$
$
$
$
$
$
$
$
$
2013
2,666.5
366.0
3.06
2012
2,137.7
414.1
3.48
$
$
$
119.588
119.028
1,744.7
$
1,401.2
(1,902.5)
$
(1,780.3)
812.4
$
408.1
2013
8,802.5
2,622.9
3,836.7
2012
7,265.7
1,793.2
3,453.2
$
$
$
41%
34%
PRODUCTION & AVERAGE COMMODITY PRICES
2016
2015
2014
2013
2012
Oil Production, MMBbl
NGL Production, MMBbl
Natural Gas Production, Bcf
Total Production, MMBOE
Oil Price, per Bbl, Excluding Hedging
Natural Gas Liquids Price, per Bbl
Natural Gas Price, per Mcf
Sales Price, per BOE, Net of Hedging
34.0
6.6
41.4
47.5
34.36
8.88
1.40
30.22
$
$
$
$
$
$
$
$
47.2
5.5
41.1
59.6
40.95
12.67
2.20
38.76
$
$
$
$
33.5
3.3
30.2
41.8
81.50
39.17
5.53
73.38
$
$
$
$
27.0
2.8
26.9
34.3
90.39
40.41
4.04
76.76
GROSS
4,687
23.1
2.8
25.8
30.2
83.86
39.36
3.42
69.85
NET
1,917
$
$
$
$
849,306
517,169
362,400
247,663
YEAR-END 2016 WELL COUNT & ACREAGE STATISTICS
Total Productive Wells
Developed Acreage
Undeveloped Acreage
RESERVES & PRODUCTION PER REGION
26.1%
CENTRAL ROCKY
MOUNTAINS
0.7%
OTHER
7.7%
CENTRAL ROCKY
MOUNTAINS
0.7%
OTHER
73.2%
NORTHERN ROCKY
MOUNTAINS
91.6%
NORTHERN ROCKY
MOUNTAINS
615.5 MMBOE PROVED RESERVES AS OF 12/31/2016
Q4 2016–118.9 MBOE/D PRODUCTION
2
2016 Highlights
108,850BOE/D
Q4 2016 Williston Basin net production
3% INCREASE OVER Q3 2016
900MBOE
Williston Basin 5+ million
pound completions
TYPE CURVE
1,500MBOE
Williston Basin 10+ million
pound completions
TYPE CURVE
$2.4BILLION
Debt reduction
THROUGH FEB. 2017
$1.9BILLION
Strong liquidity position
AS OF 12/31/2016
2016 ANNUAL REPORT | WHITING PETROLEUM CORPORATION 3
RESURGENT
Dear Fellow Shareholders,
In 2016, initiatives Whiting embarked on in 2015 to strengthen its
balance sheet came to fruition. Since the beginning of 2015,
we generated $2.8 billion in proceeds from asset sales and
innovative capital market transactions. This exceeds the $2.5
billion of debt we assumed in the Kodiak transaction, which closed
in December of 2014. Throughout this process, we maintained our
focus on operational execution and the application of innovative
well completion technology to improve capital efficiency. This
positions Whiting for strong growth.
At our core Bakken/Three Forks play in the Williston Basin, Whiting
pioneered the application of new well technology to dramatically
improve productivity. As measured by 90-day average production
per well, productivity increased 42% in 2016 year-over-year and
has increased 84% since 2014. We achieved this through new
well designs that enable us to stimulate more rock using additional
entry points and larger sand volumes. The average sand volume
per well increased from 3.6 million pounds in 2014 to over 8 million
pounds in Q4 2016. Applying the same metric of 90-day average
production per well to all significant operators in the Williston Basin
(10 or more wells drilled in a 12-month period), Whiting emerges
as the Bakken champion with the most productive wells. We plan
to apply similar technology in our Redtail Niobrara/Codell play in
the DJ Basin of Colorado with the potential for significant increases
in productivity.
Our focus on safety and the environment remains strong. Our gas
capture rate in both plays was typically 90% or greater in 2016. We
also led the way in North Dakota working with state regulators to
implement a new, more rigorous inspection regime for methane
emissions. On the safety side, we had one of our best years ever
as incidents decreased significantly in 2016. We are committed to
the health and welfare of our employees as they perform the vital
task of providing reliable and affordable energy for our country.
As we look ahead, we believe the potential of our top tier assets
and talented employees will be realized through sustainable
growth and shareholder value creation. Our 2017 outlook calls for
23% production growth from the first quarter to the fourth quarter.
We worked to secure this outlook by building a strong hedge
profile with 49% of our forecasted 2017 production hedged at
attractive prices. This contributes to our goal of strong growth in net
asset value while maintaining a solid balance sheet. Thank you
for your support as shareholders as Whiting emerges stronger than
ever from one of the most challenging downturns in the history of
oil markets.
Sincerely,
In addition to more productive wells, we have also increased
operational efficiencies. In the Williston Basin, we lowered our
spud to rig release times by 36% since the beginning of 2014. In
the DJ Basin, we lowered our spud to rig release times by 50% over
the same period.
JAMES J. VOLKER
CHAIRMAN OF THE BOARD,
PRESIDENT AND CHIEF EXECUTIVE OFFICER
FEBRUARY 23, 2017
ABOVE: James J. Volker participates as a Keynote Panel Speaker at the Williston Basin Petroleum Conference.
4
A Focused Company
2016 ANNUAL REPORT | WHITING PETROLEUM CORPORATION 5
Headquarters
Williston Basin
Redtail
RIGHT: Drilling rig on the Razor 25M-2402 well
with the Pawnee Buttes in the background.
ASSET OVERVIEW
Williston Basin
Q4 2016 Production of 108,850 BOE/D
Whiting is one of the largest producers in the oil-
rich Williston Basin of North Dakota and Montana,
which encompasses the prolific Bakken and
Three Forks formations. Since our Sanish Field
discovery in 2007, we’ve been a leader in the
development of new well designs, completion
technologies and operating processes. We
control one of the largest acreage positions in
the Williston Basin with 443,839 net acres that
hold approximately 5,300 potential gross drilling
locations.
DJ Basin
Q4 2016 Production of 9,210 BOE/D
In the oil-prone sweet spot of the eastern DJ
Basin of Colorado, we have 132,184 net acres.
Similar to our Bakken and Three Forks acreage
position, we are utilizing the latest technology
to develop multiple horizons, which include the
Niobrara “A”, “B” and “C” and Codell/Fort Hays
formations. This provides us with an estimated
5,400 potential gross drilling locations.
6
WILLIAMS
MOUNTRAIL
MCKENZIE
MCLEAN
DUNN
Large Acreage Position in the Core of the Play
WLL Acreage
WYOMING
Laramie
Kimball
REDTAIL
FIELD AREA
Weld
Larimer
Boulder
Morgan
O M IN ER AL BELT
WATTENBERG
FIELD AREA
O L O R A D
N O F C
E XTE N SIO
Economic sweet spot in the oil window
WLL Acreage
Area of Resistivity
118,890BOE/D
Net Production in Q4 2016
2016 ANNUAL REPORT | WHITING PETROLEUM CORPORATION 7
OPERATIONAL FOCUS
Improves Performance
8
OPERATIONAL FOCUS
Whiting is a leader in both drilling and completion technology. It has adopted the
latest drill bit technology and pioneered new completion techniques to maximize
efficiency.
Operational Focus
Faster Drilling Times and Longer Laterals
In Whiting’s Redtail Niobrara/Codell play in the DJ Basin, the average
time to drill a well from spud to rig release has decreased 50% to
5.8 days in Q4 2016 since the beginning of 2014. This was driven by
more efficient operations and a new monobore wellbore design that
eliminates intermediate casing. We continue to increase the number
of longer lateral 1,280-acre spaced wells in our drilling program. In
2016, we drilled 34 1,280-acre spaced wells in an average time of 4.4
days from spud to total depth and 7.4 days from spud to spud. Our
1,280-acre spaced wells have the potential to deliver approximately
40% higher reserves for only a 12.5% increase in cost relative to our
standard 960-acre spaced wells.
Improving Performance
Whiting continues to improve Bakken well productivity by increasing
sand concentration to enlarge stimulated rock volume. In the Bakken,
our 90-day average rate during 2016 was 42% higher than 2015 and
84% higher than 2014. The new completion technique and resulting
productivity gains increased Whiting’s Bakken targeted type curve by
50% to 900 MBOE from 600 MBOE in 2014. The Redtail Field in the DJ
Basin is also delivering attractive results. In 2016, we shifted our mix
towards longer 10,000’ laterals and built a robust inventory of 105 DUCs
(drilled uncompleted wells). This should contribute to highly capital
efficient growth in 2017 at Redtail.
Redtail Drilling Time
50% Improvement
from Beginning of 2014
14
12
10
8
6
4
2
0
s
y
a
D
e
g
a
e
v
A
r
4
.
2
5 1
.
1
1
9
.
1
1
4
.
2
1
2
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1
1
7
.
0
1
5
.
9
2
.
9
2
.
6
9
.
5
4
.
6
8
.
5
Q1
Q3
Q2
2014
Q4
Q1
Q2
Q3
Q4
Q1
2015
Q2
Q3
2016
Q4
Williston Basin Drilling Time
Improvement
36%
.
6
1
2
.
6
9
1
.
4
8
1
.
7
7
1
.
2
8
1
from Beginning of 2014
.
9
5
1
.
5
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1
.
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4
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.
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a
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v
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r
20
15
10
5
0
Q1
Q3
Q2
2014
Q4
Q1
Q2
Q3
Q4
Q1
2015
Q2
Q3
2016
Q4
Enhanced Completions Increase Well
Productivity in the Williston Basin
1,600
1,400
1,200
1,000
D
P
E
O
B
800
600
400
200
0
%
6 4
5
7
3
,
1
5
8
9 9
3
8
3
5
2
,
1
%
8 8
4
3
8
5
6
6
7
5
0
,
1
%
8 4
6
4
7
6
7
5
30-Day Avg. BOEPD
60-Day Avg. BOEPD
90-Day Avg. BOEPD
2014
2015
2016
2016 ANNUAL REPORT | WHITING PETROLEUM CORPORATION 9
ABOVE: Worker on a drilling rig stacks pipe while drilling a Redtail well.
PRODUCTIVITY FOCUS
Powers Industry Leading Results
10
PRODUCTIVITY FOCUS
Technology increases recovery efficiency and reserves per well. It has empowered
our operations team to achieve industry leading productivity while reducing costs.
Productivity Focus
Enhanced Completion Wells Continue to Track 900
MBOE Type Curve after 265 Days
Whiting’s initial set of 48 enhanced completion wells in the Williston
Basin continues to produce in line with a 900 MBOE type curve after
265 days. These wells span Whiting’s acreage and are located in
Billings, Dunn, McKenzie, Mountrail, Stark and Williams counties of North
Dakota. On average, these wells were completed with 36 stages and
6.6 million pounds of sand.
Super Completion Wells Tracking 1,500 MBOE Type
Curve after 120 Days
During the second half of 2016, Whiting brought on production its
initial three super completions. Two of the wells, the Carscallen 31-
14-4H completed with 13.6 million pounds of sand, and the P Bibler
155-99-16-31-30-1H completed with 10.1 million pounds of sand,
were located approximately ten miles apart in Williams County, North
Dakota. The third well, the Rolla Federal 11-3-1TFHU, was completed
with 10.0 million pounds of sand and completed in McKenzie County,
North Dakota. On average, the wells are tracking above a 1,500
MBOE type curve after 120 days on production.
Williston Basin
90-Day Average
for Wells Completed between December 2015
and Novemeber 2016
1,200
1,000
800
D
P
E
O
B
600
400
200
0
3
0
2
,
1
7
9
9
L
L
W
17
A
R
E
E
P
18
6
1
8
B
R
E
E
P
22
2
9
6
C
R
E
E
P
10
0
8
6
D
R
E
E
P
33
Wells
2
7
5
E
R
E
E
P
14
7
6
5
F
R
E
E
P
34
8
2
3
G
R
E
E
P
27
Enhanced Completion 5+MMLb Fracs Tracking 900
MBOE EUR Type Curve
Super Completion 10+MMLb Fracs Continue
to Deliver Outstanding Results
E
O
B
200,000
180,000
160,000
140,000
120,000
100,000
80,000
60,000
40,000
20,000
0 M B O E
0
9
7 0 0 M B O E
Enhanced Completion Average
900 MBOE
700 MBOE
250,000
200,000
150,000
E
O
B
100,000
50,000
0.0
E
O
0 M B
0
1 , 5
9 0 0 M B O E
3-Well Avg.
1,500 MBOE
900 MBOE
30
60
90
120
150
180
210
240
270
20
40
60
80
100
120
140
160
180
200
Days
Days
Williston Basin Well Costs Down 14% Since 2014
ABOVE: Whiting pad and reclamation site in Williams County, North Dakota.
M
M
$
8.4
8.2
8.0
7.8
7.6
7.4
7.2
7.0
6.8
6.6
6.4
AFE Cost per year
14% Decrease
.
3
8
$
2014
.
9
7
$
2015
.
1
7
$
2016
2016 ANNUAL REPORT | WHITING PETROLEUM CORPORATION 11
ENVIRONMENTAL FOCUS
Protects Nature and Engages Community
12
ENVIRONMENTAL FOCUS
Whiting is deeply committed to protecting the environment as we safely and
responsibly develop our resources.
Environmental Focus
We Are Good Stewards of the Environment
Whiting uses FLIR (forward looking infrared) sensing technology to inspect facilities
and reduce methane emissions. We have a team of highly trained technicians that
frequently inspect well sites and tank batteries to gather valuable data and promptly
initiate corrective action if needed.
Whiting also works diligently to reduce its impact on the environment. In 2016, our
extensive pipeline network at our Redtail field in Weld County, Colorado saved over
60,000 truck trips related to transportation of produced fluids (oil, water and NGLs).
Our natural gas processing plant captures over 90% of methane emitted from our
wells and has provided approximately 990 mcf of fuel gas to the field to power frac
fleets, drilling rigs and production equipment. On a BTU basis, this replaced 8.7 million
gallons (207,000 Bbl) of diesel.
Working with Our Communities
During the well planning process, Whiting is committed to working with landowners
and county, state and federal officials to minimize its impact on the environment
and community. We consult with county planning officials and Colorado Oil and Gas
Conservation Commission (COGCC) personnel regarding optimal site location and
layout. We work with COGCC personnel on reclamation of pads after initial production
to reduce and minimize environmental impacts for the remainder of the pad’s life.
We identify best practices for seed mixture, ground preparation, soil stockpiling and
handling, cuttings remediation and storm water management to preserve the natural
environment.
Safety is a Part of Our Daily Life
Whiting’s safety programs and associated values are ingrained in our culture. We
have adopted a robust training program that is a priority for all of our company
employees and has resulted in a significant decrease in safety incidents. Our focus is
reflected in our continued industry leading TRIR and DART statistics.
Rolling 12 -Month Average Rate/Month
2.00
1.80
1.60
1.40
1.20
t
e
a
R
1.00
0.80
0.60
0.40
0.20
0.00
2014
2015
2016
TRIR - Total Recordable Incident Rate DART - Days Away, Restricted and/or Transfered
TRIR Rolling Average
DART Rolling Average
Linear (TRIR Rolling Average)
Linear (DART Rolling Average)
ABOVE: Reclamation and production site in Williams
County, North Dakota.
2016 ANNUAL REPORT | WHITING PETROLEUM CORPORATION 13
BOARD OF DIRECTORS
JAMES J. VOLKER
70, Chairman of the Board, President and
Chief Executive Officer, 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 1983 as Vice President of Corporate
Development and served in that position through
1993. In 1993, he became a contract consultant
to Whiting Oil and Gas Corporation and served
in that capacity until 2000, at which time he
became Executive Vice President and Chief
Operating Officer. Mr. Volker was appointed
President and Chief Executive Officer of Whiting
Oil and Gas Corporation in 2002. Mr. Volker was
co-founder, Vice President and later President
of Energy Management Corporation from 1971
through 1982. He has 45 years of experience in
the oil and natural gas industry. Mr. Volker has a
degree in finance from the University of Denver,
a MBA from the University of Colorado and has
completed H. K. VanPoolen and Associates’
course of study in reservoir engineering.
is Chairman of
THOMAS L. ALLER
68,
the Compensation
Committee and has been a director of Whiting
Petroleum Corporation since 2003. Mr. Aller
retired as Senior Vice President of Operations
Support for Alliant Energy Corporation in 2014.
He served as Senior Vice President-Energy
Resource Development of Alliant Energy
Corporation from January 2009 to 2013
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
80, 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 Operating Officer in
July 1999. In January 2000, he was appointed
President and Chief Executive Officer. Mr. Artus
became Senior Vice President in January 2002
and retired from the Company on April 1, 2006.
Prior to joining Whiting, he was employed by
Shell Oil Company in various engineering
research and management positions. From
1974-1977, he was employed by Wainoco Oil
and Gas Company as Production Manager. He
was a co-founder and later became President
of Solar Petroleum Corporation, an independent
oil and gas producing company. He has over 54
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 Technology. He is
a registered Professional Engineer in Colorado,
Wyoming, Montana and North Dakota. Mr. Artus
is a member, and a past officer, of the Society of
Professional Well Log Analysts and is a member
of the Society of Petroleum Engineers.
JAMES E. CATLIN
70, has been a director of Whiting Petroleum
Corporation since 2014. Mr. Catlin was a co-
founder of Kodiak Oil & Gas (USA), Inc. Mr. Catlin
served as a director of Kodiak since February
2001, Chairman of the Board from July 2002
until June 2011, Secretary from July 2002
to May 2008, Chief Operating Officer from
June 2006 until June 2011 and Executive
Vice President of Business Development since
June 2011. Mr. Catlin has over 40 years of
geologic experience primarily in the Rocky
Mountain Region. Mr. Catlin was an owner of CP
Resources LLC, an independent oil and natural
gas company from 1986 to 2001. Mr. Catlin
was a Founder, Vice President and Director of
Deca Energy from 1980 to 1986 and worked as
a district geologist for Petroleum Inc. and Fuelco
prior to this time. He received a Bachelor of Arts
and a Master’s of Science Degree in Geology
from the University of Northern Illinois in 1973.
Mr. Catlin has extensive training and experience
with respect to geology and executive level
experience working with oil and natural gas
companies.
PHILIP E. DOTY
73, is Chairman of the Audit Committee and
has been a director of Whiting Petroleum
Corporation since 2010. Mr. Doty is a certified
public accountant. Since 2007, Mr. Doty
has been counsel to EKS&H LLP, 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
65,
the
is Lead Director, Chairman of
Nominating and Governance Committee and
has been a director of Whiting Petroleum
Corporation since 2007. 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 over 40
years of extensive technical and management
independent oil and gas
experience with
companies
including Unocal, Union Texas
Petroleum Corporation, NERCO, The Louisiana
Land and Exploration Company (LL&E) and
Burlington Resources, Inc.
includes over
CARIN S. KNICKEL
60, has been a director of Whiting Petroleum
Corporation since 2015. Ms. Knickel’s energy
industry experience
three
decades in operations leadership in refining,
marketing,
transportation, exploration and
production for ConocoPhillips. She also held
roles
in business development, strategic
planning and commodity trading, and led the
company’s specialty products business from
2001 to 2003. She became Vice President of
Global Human Resources in 2003 and served
on the company’s management committee
from that time until she retired in May 2012.
Ms. Knickel also served as Assistant Dean
for Programs and Talent for the University of
Colorado College of Engineering from January
2013 through July 2014 and currently serves
on the school’s Engineering Advisory Council.
She has a Bachelor’s Degree in Marketing
from the University of Colorado and a Master’s
Degree in Management Science from the
Massachusetts Institute of Technology.
MICHAEL B. WALEN
68, has been a director of Whiting Petroleum
Corporation since 2013. 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 exploration positions
prior to that time. He has over 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.
14
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2016
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
(Title of Class)
New York Stock Exchange
(Name of each exchange on which registered)
Securities registered pursuant to Section 12(g) of the Act: None.
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes No
Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities
Act. Yes No
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports),
and (2) has been subject to such filing requirements for the past 90 days. Yes No
Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Web site, if any, every
Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the
preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files). Yes No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not
contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller
reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2
of the Exchange Act. (Check one):
Large accelerated filer
Accelerated filer
Non-accelerated filer
(Do not check if a smaller reporting company)
Smaller reporting company
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No
Aggregate market value of the voting common stock held by non-affiliates of the Registrant at June 30, 2016: $3,357,000,000.
Number of shares of the Registrant’s common stock outstanding at February 15, 2017: 362,698,464 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the 2017 Annual Meeting of Stockholders are incorporated by reference into Part III.
TABLE OF CONTENTS
Glossary of Certain Definitions
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
Business
Risk Factors
Unresolved Staff Comments
Properties
Legal Proceedings
Mine Safety Disclosures
Executive Officers of the Registrant
PART I
PART II
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures about Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Certain Relationships, Related Transactions and Director Independence
Principal Accounting Fees and Services
Item 15.
Item 16.
Exhibits and Financial Statement Schedules
Form 10-K Summary
PART IV
1
5
18
31
32
38
38
39
41
43
44
65
67
109
109
110
111
111
111
112
112
112
112
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.
“ASC” Accounting Standards Codification.
“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.
“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.
“completion” The process of preparing an oil and gas wellbore for production through the installation of permanent production
equipment, as well as perforation and fracture stimulation to optimize production.
“costless collar” An option position where the proceeds from the sale of a call option at its inception fund the purchase of a put option
at its inception.
“delay rental” Consideration paid to the lessor by a lessee to extend the terms of an oil and natural gas lease in the absence of drilling
operations and/or production that is contractually required to hold the lease. This consideration is generally required to be paid on or
before the anniversary date of the oil and gas lease during its primary term, and typically extends the lease for an additional year.
“deterministic method” The method of estimating reserves or resources using a single value for each parameter (from the geoscience,
engineering or economic data) in the reserves calculation.
“development well” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon
known to be productive.
“differential” The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil spot price, and the
wellhead price received.
“dry hole” A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas
well.
“EOR” Enhanced oil recovery.
“exploratory well” A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or
natural gas in another reservoir.
“extension well” A well drilled to extend the limits of a known reservoir.
“FASB” Financial Accounting Standards Board.
“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 localized geological features as opposed to the broader terms of basins, trends, provinces, plays,
areas of interest, etc.
1
“GAAP” Generally accepted accounting principles in the United States of America.
“gross acres” or “gross wells” The total acres or wells, as the case may be, in which a working interest is owned.
“ISDA” International Swaps and Derivatives Association, Inc.
“lease operating expense” or “LOE” The expenses of lifting oil or gas from a producing formation to the surface, constituting part of
the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets,
maintenance, allocated overhead costs and other expenses incidental to production, but not including lease acquisition or drilling or
completion expenses.
“LIBOR” London interbank offered rate.
“MBbl” One thousand barrels of oil, NGLs or other liquid hydrocarbons.
“MBbl/d” One MBbl per day.
“MBOE” One thousand BOE.
“MBOE/d” One MBOE per day.
“Mcf” One thousand cubic feet, used in reference to natural gas.
“MMBbl” One million Bbl.
“MMBOE” One million BOE.
“MMBtu” One million British Thermal Units, used in reference to natural gas.
“MMcf” One million cubic feet, used in reference to natural gas.
“MMcf/d” One MMcf per day.
“net acres” or “net wells” The sum of the fractional working interests owned in gross acres or wells, as the case may be.
“net production” The total production attributable to our fractional working interest owned.
“NGL” Natural gas liquid.
“NYMEX” The New York Mercantile Exchange.
“PDNP” Proved developed nonproducing reserves.
“PDP” Proved developed producing reserves.
“plug-and-perf technology” A horizontal well completion technique in which hydraulic fractures are performed in multiple stages,
with each stage utilizing a bridge plug to divert fracture stimulation fluids through the casing perforations into the formation within
that stage.
“plugging and abandonment” Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum
will not escape into another or to the surface. Regulations of most states legally require plugging of abandoned wells.
“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.
2
“prospect” A property on which indications of oil or gas have been identified based on available seismic and geological information.
“proved developed reserves” Proved reserves that can be expected to be recovered through existing wells with existing equipment
and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.
“proved reserves” Those reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty
to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating
methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence
indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the
project, within a reasonable time.
The area of the reservoir considered as proved includes all of the following:
a.
b.
The area identified by drilling and limited by fluid contacts, if any, and
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it
and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid
injection) are included in the proved classification when both of the following occur:
a.
b.
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the
reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other
evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the
project or program was based, and
The project has been approved for development by all necessary parties and entities, including governmental
entities.
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The
price shall be the average price during the 12-month period before the ending date of the period covered by the report, determined as
an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by
contractual arrangements, excluding escalations based upon future conditions.
“proved undeveloped reserves” or “PUDs” Proved reserves that are expected to be recovered from new wells on undrilled acreage, or
from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited
to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using
reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can
be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be
drilled within five years, unless specific circumstances justify a longer time. Under no circumstances shall estimates of 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.
“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.
3
“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” An expansive contiguous geographical area with known accumulations of crude oil or natural gas reserves that has
the potential to be developed uniformly with repeatable commercial success due to advancements in horizontal drilling and
completion technologies.
“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.
“standardized measure of discounted future net cash flows” or “Standardized Measure” The discounted future net cash flows relating
to proved reserves based on the average price during the 12-month period before the ending date of the period covered by the report,
determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period (unless prices
are defined by contractual arrangements, excluding escalations based upon future conditions); current costs and statutory tax rates (to
the extent applicable); and a 10% annual discount rate.
“working interest” The interest in a crude oil and natural gas property (normally a leasehold interest) that gives the owner the right to
drill, produce and conduct operations on the property and to a share of production, subject to all royalties, overriding royalties and
other burdens and to all costs of exploration, development and operations and all risks in connection therewith.
“workover” Operations on a producing well to restore or increase production.
4
Item 1. Business
Overview
PART I
We are an independent oil and gas company engaged in development, production, acquisition and exploration activities primarily in
the Rocky Mountains region of the United States. We were incorporated in the state of Delaware in 2003 in connection with our
initial public offering.
Since our inception, we have built a strong asset base through a combination of property acquisitions, development of proved reserves
and exploration activities. Our current operations and capital programs are focused on organic drilling opportunities and on the
development of previously acquired properties, specifically on projects that we believe provide the greatest potential for repeatable
success and production growth, while selectively pursuing acquisitions that complement our existing core properties, such as the
acquisition of Kodiak Oil & Gas Corp. (the “Kodiak Acquisition”) discussed in the “Acquisitions and Divestitures” footnote in the
notes to the consolidated financial statements. As a result of lower crude oil prices during 2015 and 2016, we significantly reduced
our level of capital spending to more closely align with our cash flows generated from operations, and have focused our drilling
activity on projects that provide the highest rate of return. In addition, we continually evaluate our 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, such as the asset sales discussed below under “Acquisitions and
Divestitures”.
As of December 31, 2016, our estimated proved reserves totaled 615.5 MMBOE and our 2016 average daily production was 129.9
MBOE/d, which results in an average reserve life of approximately 12.9 years.
The following table summarizes by core area, our estimated proved reserves as of December 31, 2016, their corresponding pre-tax
PV10% values, and our fourth quarter 2016 average daily production rates, as well as our company’s total standardized measure of
discounted future net cash flows as of December 31, 2016:
Proved Reserves (1)
Natural
Oil
NGLs
(MMBbl) (MMBbl)
Gas
(Bcf)
%
Total
(MMBOE) Oil
Pre-Tax
PV10%
Value (2)
(in millions)
281.9
109.3
3.6
394.8
81.8
19.6
0.1
101.5
522.3
191.2
2.2
715.7
450.8
63% $
2,397
160.7
68%
4.0
90%
285
16
615.5
64% $
2,698
-
$
2,698
4th Quarter 2016
Average Daily
Production
(MBOE/d)
108.9
9.2
0.8
118.9
Core Area
Northern Rocky Mountains (3)
Central Rocky Mountains (4)
Other (5)
Total
Discounted Future Income Tax
Expense (6)
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 an oil price of $42.75 per Bbl
and a gas price of $2.49 per MMBtu, which were calculated using an average of the first-day-of-the month price for each month
within the 12 months ended December 31, 2016 as required by current SEC and FASB guidelines.
(2) Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized
measure of discounted future net cash flows (the “Standardized Measure”), which is the most directly comparable GAAP
financial measure. Pre-tax PV10% is computed on the same basis as the Standardized Measure but without deducting future
income taxes. We believe pre-tax PV10% is a useful measure for investors when 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. Our pre-tax PV10% and Standardized Measure do not purport to present the fair value of our proved oil,
NGL and natural gas reserves.
5
(3) Includes oil and gas properties located in Montana and North Dakota.
(4) Includes oil and gas properties located in Colorado.
(5) Primarily includes non-core oil and gas properties located in Colorado, Mississippi, New Mexico, North Dakota, Texas and
Wyoming.
(6) Based on the 12-month average oil and natural gas prices used in the computation of pre-tax PV10% as of December 31, 2016,
our future net income generated over the life of our proved reserves is expected to be less than our net operating loss carryforward
deductions and therefore, under the Standardized Measure, there is no deduction for federal or state income taxes.
During 2016, we incurred $554 million in exploration and development (“E&D”) expenditures, including $504 million for the drilling
of 89 gross (48.2 net) wells. All of these new wells resulted in productive completions.
Our current 2017 E&D budget is $1.1 billion, which we expect to fund substantially with net cash provided by our operating activities,
proceeds from property divestitures, cash on hand, borrowings under our credit facility or by accessing the capital markets. To the
extent net cash provided by operating activities is higher or lower than currently anticipated, we would adjust our E&D budget
accordingly, enter into agreements with industry partners, divest certain oil and gas property interests, adjust borrowings outstanding
under our credit facility or access the capital markets as necessary.
Acquisitions and Divestitures
During 2015 and 2016, in response to sustained lower crude oil prices, we divested of a large number of non-core oil and gas
properties that no longer matched the profile of properties we desire to own. In addition, in January 2017 we closed on the sale of our
interests in two gas processing plants located in the Williston Basin for aggregate sales proceeds of $375 million. Refer to the
“Subsequent Events” footnote in the notes to consolidated financial statements for more information on this transaction. Our
significant acquisitions and divestitures during the last two years are summarized below.
Acquisitions. There were no significant acquisitions during the years ended December 31, 2016 and 2015.
2016 Divestitures. In July 2016, we completed the sale of our interest in our enhanced oil recovery project in the North Ward Estes
field in Ward and Winkler counties of Texas, including our interest in certain CO2 properties in the McElmo Dome field in Colorado
and certain other related assets and liabilities (the “North Ward Estes Properties”) for a cash purchase price of $300 million (before
closing adjustments). The sale was effective July 1, 2016 and resulted in a pre-tax loss on sale of $187 million. In addition to the cash
purchase price, the buyer has agreed to pay us $100,000 for every $0.01 that, as of June 28, 2018, the average NYMEX crude oil
futures contract price for each month from August 2018 through July 2021 is above $50.00/Bbl up to a maximum amount of $100
million (the “Contingent Payment”). The Contingent Payment will be made at the option of the buyer either in cash on July 31, 2018
or in the form of a secured promissory note, accruing interest at 8% per annum with a maturity date of July 29, 2022. The North Ward
Estes Properties consisted of estimated proved reserves of 120.3 MMBOE as of December 31, 2015, representing 15% of our proved
reserves as of that date, and generated 8.6 MBOE/d (or 6%) of our June 2016 average daily net production.
2015 Divestitures. In December 2015, we completed the sale of a fresh water delivery system, a produced water gathering system and
four saltwater disposal wells located in Weld County, Colorado, effective December 16, 2015, for aggregate sales proceeds of $75
million (before closing adjustments).
In June 2015, we completed the sale of our interests in certain non-core oil and gas wells, effective June 1, 2015, for aggregate sales
proceeds of $150 million (before closing adjustments) resulting in a pre-tax loss on sale of $118 million. The properties included over
2,000 gross wells in 132 fields across 10 states. The properties had estimated proved reserves of 20.9 MMBOE as of December 31,
2014, representing 3% of our proved reserves as of that date, and generated 5.3 MBOE/d (or 3%) of our May 2015 average daily
production.
In April 2015, we completed the sale of our interests in certain non-core oil and gas wells, effective May 1, 2015, for aggregate sales
proceeds of $108 million (before closing adjustments) resulting in a pre-tax gain on sale of $29 million. The properties are located in
187 fields across 14 states, and predominately consisted of assets that were previously included in the underlying properties of
Whiting USA Trust I. The properties had estimated proved reserves of 8.9 MMBOE as of December 31, 2014, representing 1% of our
total proved reserves as of that date, and generated 2.7 MBOE/d (or 2%) of our March 2015 average daily net production.
Also during the year ended December 31, 2015, we completed several immaterial divestiture transactions for the sale of our interests
in certain non-core oil and gas wells and undeveloped acreage, for aggregate sales proceeds of $176 million (before closing
adjustments) resulting in a pre-tax gain on sale of $28 million. These properties had estimated proved reserves of 23.4 MMBOE as of
6
December 31, 2014, representing 3% of our total proved reserves as of that date. The properties generated a combined total of
approximately 4.4 MBOE/d of average daily net production, based on production rates at each of the respective closing dates.
Business Strategy
Our goal is to generate meaningful growth in shareholder value through the development, acquisition and exploration of oil and gas
projects with attractive rates of return on capital. Specifically, we have focused, and plan to continue to focus, on the following:
Developing Existing Properties. The development of large resource plays such as our Williston Basin and Denver Julesburg Basin
(“DJ Basin”) projects has become one of our central objectives. As of December 31, 2016, we have assembled approximately 736,000
gross (443,800 net) developed and undeveloped acres in the Williston Basin located in North Dakota and Montana. As of December
31, 2016, we had four drilling rigs operating in this area. During 2016, we entered into two separate wellbore participation
agreements related to wells drilled in the Williston Basin, which helped allow us to continue completion activity in this area.
At our Redtail field in the DJ Basin in Weld County, Colorado, we have assembled approximately 157,200 gross (132,200 net)
developed and undeveloped acres. As of December 31, 2016, we had one drilling rig operating in the DJ Basin. We suspended
completion operations in this area beginning in the second quarter of 2016; however, we plan to resume completion activity in early
2017. Our Redtail gas plant processes the associated gas produced from our wells in this area, and has a current inlet capacity of 50
MMcf/d.
Disciplined Financial Approach. Our goal is to remain financially strong, yet flexible, through the prudent management of our
balance sheet and active management of our exposure to commodity price volatility. We have historically funded our acquisition and
growth activity through a combination of equity and debt issuances, bank borrowings, internally generated cash flows and certain oil
and gas property divestitures, as appropriate, to maintain our financial position. As a result of sustained lower crude oil prices in 2015
and 2016, we significantly reduced our level of capital spending to more closely align with our cash flows generated from operations,
and have focused our drilling activity on projects that provide the highest rate of return. 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 or fund our E&D expenditures.
For example, during 2015 and 2016 we sold a large number of non-core oil and gas properties that no longer matched the profile of
properties we desire to own. In addition, to support cash flow generation on our existing properties and help ensure expected cash
flows from newly acquired properties, we periodically enter into derivative contracts. Typically, we use costless collars, swaps and
crude oil sales and delivery contracts to provide an attractive base commodity price level. As of January 3, 2017, we had derivative
contracts covering the sale of approximately 49% of our forecasted 2017 oil production.
Growing Through Accretive Acquisitions. Since 2003, we have completed 21 separate significant acquisitions of producing properties
for total estimated proved reserves of 445.2 MMBOE, as of the effective dates of the acquisitions. Our experienced team of
management, land, engineering and geoscience professionals has developed and refined an acquisition program designed to increase
reserves and complement our existing properties, including identifying and evaluating acquisition opportunities, closing purchases and
effectively managing the properties we acquire. We intend to selectively pursue the acquisition of properties that are complementary
to our core operating areas, such as the Kodiak Acquisition, which closed in 2014 and significantly expanded our presence in the
Williston Basin.
Competitive Strengths
We believe that our key competitive strengths lie in our focused asset portfolio, our experienced management and technical teams and
our commitment to the effective application of new technologies.
Focused, Long-Lived Asset Base. As of December 31, 2016, we had interests in 4,687 gross (1,917 net) productive wells on
approximately 849,300 gross (517,200 net) developed acres across our geographical areas. We believe the concentration of our
operated assets presents us with multiple opportunities to successfully execute our business strategy by enabling us to leverage our
technical expertise and take advantage of operational efficiencies. Our proved reserve life is approximately 12.9 years based on year-
end 2016 proved reserves and 2016 production.
Experienced Management and Technical Teams. Our management team averages 30 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,
our team of acquisition professionals has an average of 33 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. Data provided by our in-house, state-of-the-art rock analysis laboratory is
used to support real-time drilling and completion decisions, and to help us further understand unconventional oil plays. Our technical
7
team has access to approximately 9,400 square miles of 3-D seismic data, digital well logs and other subsurface information. This
data is analyzed with advanced geophysical and geological computer resources dedicated to the accurate and efficient characterization
of the subsurface oil and gas reservoirs that comprise our asset base. In addition, our information systems enable us to update our
production databases through daily uploads from hand-held computers in the field. This commitment to technology has increased the
productivity and efficiency of our field operations and development activities.
We continue to advance our completion techniques, including significantly increasing proppant volumes, utilizing diverter agents to
better distribute fluid and proppant across individual zones, varying the number of completion stages, and employing new fracture
stimulation fluids, including slickwater. We plan to continue use of these state-of-the-art completion designs on wells we drill
throughout 2017, while also testing new diversion technology and more efficient placement and drillout of down-hole plugs.
Proved Reserves
Our estimated proved reserves as of December 31, 2016 are summarized by core area 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.
Oil
(MMBbl)
168.1
0.9
112.9
281.9
NGLs
(MMBbl)
49.4
0.3
32.1
81.8
10.2
0.4
98.7
109.3
3.2
0.4
3.6
2.0
0.1
17.5
19.6
0.1
0.0
0.1
Natural Gas
(Bcf)
Estimated
Future Capital
% of Total Expenditures (1)
Total
(MMBOE) Proved
314.5
2.0
205.8
522.3
18.6
0.6
172.0
191.2
1.6
0.6
2.2
270.0
1.5
179.3
450.8
15.2
0.6
144.9
160.7
3.6
0.4
4.0
60%
-%
40%
100% $
10%
-%
90%
100% $
90%
10%
100% $
(in millions)
1,847.7
1,753.9
4.3
Northern Rocky Mountains (2)
PDP
PDNP
PUD
Total proved
Central Rocky Mountains (3)
PDP
PDNP
PUD
Total proved
Other (4)
PDP
PDNP
Total proved
Total Company
PDP
PDNP
PUD
181.5
1.7
211.6
394.8
51.5
0.4
49.6
101.5
334.7
3.2
377.8
715.7
288.8
2.5
324.2
615.5
47%
-%
53%
100% $
Total proved
_____________________
(1) Estimated future capital expenditures incorporate numerous assumptions and are subject to many uncertainties, including oil and
3,605.9
natural gas prices, costs of oil field goods and services, drilling results and several other factors.
(2) Includes oil and gas properties located in Montana and North Dakota.
(3) Includes oil and gas properties located in Colorado.
(4) Primarily includes non-core oil and gas properties located in Colorado, Mississippi, New Mexico, North Dakota, Texas and
Wyoming.
8
Marketing and Major Customers
We principally sell our oil and gas production to end users, marketers and other purchasers that have access to nearby pipeline
facilities. In areas where there is no practical access to pipelines, oil is trucked or transported by rail to terminals, market hubs,
refineries or storage facilities. The tables below present percentages by purchaser that accounted for 10% or more of our total oil,
NGL and natural gas sales for the years ended December 31, 2016 and 2014. For the year ended December 31, 2015, no individual
purchaser accounted for 10% or more of our total oil, NGL and natural gas sales. 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, as alternative customers and
markets for the sale of our products are readily available in the areas in which we operate.
Year Ended December 31, 2016
Tesoro Crude Oil Co
Jamex Marketing LLC
Year Ended December 31, 2014
Plains Marketing LP
Shell Trading US
Bridger Trading LLC
Title to Properties
15%
12%
17%
10%
10%
Our properties are subject to customary royalty interests, liens securing indebtedness, liens incident to operating agreements, liens for
current taxes and other burdens, including other mineral encumbrances and restrictions. Our credit agreement is also collateralized 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
The oil and gas industry is a highly competitive environment for acquiring properties, obtaining investment capital, securing oil field
goods and services, marketing oil and natural gas products and attracting and retaining qualified 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 resources permit. In addition,
the unavailability or high cost of drilling rigs or other equipment and services could delay or adversely affect our development and
exploration operations. 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.
Regulation
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.
Currently, none of our total production volumes are produced from offshore leases, however, some of our prior offshore operations
were conducted on federal leases that are administered by the Bureau of Ocean Energy Management (the “BOEM”). The present
value of our future abandonment obligations associated with offshore properties was $38 million as of December 31, 2016. We are
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
9
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.
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.
Regulation of Sale and Transportation of Oil
Sales of crude oil, condensate and NGLs are not currently regulated and are made at negotiated prices, however, Congress could
reenact price controls or enact other legislation 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 Federal Energy Regulatory Commission (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 1.23% adjustment for the five-year period from July 1, 2016 through June 30, 2021.
This represents a decrease from the PPI-FG plus 2.65% adjustment from the prior five-year period. The FERC determined that it
would now use a calculation based on what it determined to be a superior data source, reflecting actual cost-of-service data as opposed
to the accounting data historically used as a proxy for such information under the prior index methodology. The regulations provide
that each year the Commission will publish the oil pipeline index after the PPI-FG becomes available. Intrastate oil pipeline
transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation and the
degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates varies from state to state. Insofar as effective interstate
and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not
affect our operations in any way that is of material difference from those of our competitors.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open
access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates.
When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs.
In addition, the FERC has emergency authority under the Interstate Commerce Act to intervene and direct priority use of oil pipeline
transportation capacity, and the FERC 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.
Public protests and media attention related to permitting and construction of the Dakota Access Pipeline in North Dakota near the
Standing Rock Indian Reservation may attract additional attention to oil pipeline operations and regulation. We do not expect any
resulting impacts to oil pipeline transportation would affect our operations in any way that is of material difference from those of our
competitors.
Transportation and safety of oil and hazardous liquid is subject to regulation by the Department of Transportation (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. The Pipeline and Hazardous Material Safety Administration (“PHMSA”), an agency within the DOT, enforces
regulations on all interstate liquids transportation and some intrastate liquids transportation. PHMSA does not enforce the regulations
in states that are capable of enforcing the same regulations themselves. The effect of regulatory changes under the DOT and their
effect on interstate and intrastate oil and hazardous liquid transportation will not affect our operations in any way that is of material
difference from those of our competitors.
A portion of our crude oil production may be shipped to market centers using rail transportation facilities owned and operated by third
parties. The DOT and PHMSA establish safety regulations relating to crude-by-rail transportation. In addition, third-party rail
operators are subject to the regulatory jurisdiction of the Surface Transportation Board of the DOT, the Federal Railroad
Administration (the “FRA”) of the DOT, the Occupational Safety and Health Administration and other federal regulatory agencies.
Additionally, various state and local agencies have jurisdiction over disposal of hazardous waste and seek to regulate movement of
hazardous materials in ways not preempted by federal law.
10
In response to rail accidents occurring between 2002 and 2008, the U.S. Congress passed the Rail Safety and Improvement Act of
2008, which implemented regulations governing different areas related to railroad safety. In response to train derailments occurring in
the United States and Canada in 2013 and 2014, U.S. regulators have taken a number of actions to address the safety risks of
transporting crude oil by rail.
In February 2014, the DOT issued an emergency order requiring all persons to ensure crude oil is properly tested and classed prior to
offering such product into transportation, and to assure all shipments by rail of crude oil be handled as a Packing Group I or II
hazardous material. Also in February 2014, the Association of American Railroads entered into a voluntary agreement with the DOT
to implement certain restrictions around the movement of crude oil by rail. In May 2014 (and extended indefinitely in May 2015), the
DOT issued an Emergency Restriction/Prohibition Order requiring each railroad carrier operating trains transporting 1,000,000 gallons
or more of Bakken crude oil to provide notice to state officials regarding the expected movement of the trains through the counties in
each state. The PHMSA and FRA have also issued safety advisories and alerts regarding oil transportation and have issued a report
focused on the increased volatility and flammability of Bakken crude oil as compared with other crudes in the U.S. In May 2015,
PHMSA issued new rules applicable to “high-hazard flammable trains”, defined as a continuous block of 20 or more tank cars loaded
with a flammable liquid or 35 or more tank cars loaded with a flammable liquid dispersed throughout a train. Among other
requirements, the new rules require enhanced braking systems, enhanced standards for newly constructed tank cars and retrofitting of
existing tank cars, restricted operating speeds, a documented testing and sampling program, and routine assessments that evaluate 27
safety and security factors. In December 2015, the Fixing America's Surface Transportation (“FAST”) Act became law, further
extending PHMSA’s authority to improve the safety of transporting flammable liquids by rail and pursuant to which new regulations
phasing out the use of certain older rail cars were finalized in August 2016. In June 2016, the Protecting our Infrastructure of
Pipelines and Enhancing Safety (“PIPES”) Act of 2016 became law. The PIPES Act strengthens PHMSA’s safety authority, including
an expansion of its ability to issue emergency orders, which were adopted by rule in October 2016. PHMSA continues to review
further potential new safety regulations under the PIPES Act and the FAST Act.
We do not currently own or operate rail transportation facilities or rail cars. However, the adoption of any regulations that impact the
testing or rail transportation of crude oil could increase our costs of doing business and limit our ability to transport and sell our crude
oil at favorable prices at market centers throughout the U.S., the consequences of which could have a material adverse effect on our
financial condition, results of operations and cash flows. The effect of any such regulatory changes will not affect our operations in
any way that is of material difference from those of our competitors.
Regulation of Transportation, Storage, Sale and Gathering of Natural Gas
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 can currently be made at unregulated market prices,
in the future Congress could reenact price controls or enact other legislation with detrimental impact on many aspects of our business.
Our natural gas sales are affected by the availability, terms and cost of transportation. The price and terms of access to pipeline
transportation and underground storage are subject to extensive federal and state regulation. From 1985 to the present, several major
regulatory changes have been implemented by Congress and the FERC that affect the economics of natural gas production,
transportation and sales. In addition, the FERC is continually proposing and implementing new rules and regulations affecting those
segments of the natural gas industry that remain subject to the FERC's jurisdiction, most notably interstate natural gas transmission
companies and certain underground storage facilities. These initiatives may also affect the intrastate transportation of natural gas
under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various
sectors of the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open
and non-discriminatory basis.
The FERC implements the Outer Continental Shelf Lands Act pertaining to transportation and pipeline issues, which requires that all
pipelines operating on or across the outer continental shelf provide open access and non-discriminatory transportation service. One of
the FERC’s principal goals in carrying out this Act’s mandate is to increase transparency in the market to provide producers and
shippers on the outer continental shelf with greater assurance of open access services on pipelines located on the outer continental
shelf and non-discriminatory rates and conditions of service on such pipelines.
We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in the markets in which our
natural gas is sold. 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 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.
11
Transportation and safety of natural gas is subject to regulation by 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 PHMSA 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.
The failure to comply with these rules and regulations can result in substantial penalties. We use the latest tools and technologies to
remain compliant with current pipeline safety regulations.
In October 2015, a failure at an underground natural gas storage facility in Southern California prompted PHMSA to issue an advisory
bulletin reminding owners and operators of underground storage facilities to review operations, identify the potential for facility leaks
and failures, and to review and update emergency plans. The State of California proclaimed the underground natural gas storage
facility an emergency situation in January 2016. A federal task force was also convened to make recommendations to help avoid such
failures. An interim final rule of PHMSA became effective in January 2017 addressing design issues for underground storage
facilities, including wells, wellbore tubing and casing. Any further increased attention to and requirements for underground storage
safety and infrastructure by state and federal regulators that may result from this incident will not affect us in a way that materially
differs from the way it affects other natural gas producers.
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.
President Trump has indicated that he would work to ease regulatory burdens on industry and on the oil and gas sector, including
environmental regulations. However, any executive orders the President may issue or any new legislation Congress may pass with the
goal of reducing environmental statutory or regulatory requirements may be challenged in court. In addition, various state laws and
regulations (and permits issued thereunder) will be unaffected by federal changes unless and until the state laws and corresponding
permits are similarly changed, and any judicial review is completed.
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 of 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
12
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 where 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 were not under our control. Similarly, the disposal facilities where
discarded materials are sent are also often operated by third parties whose waste treatment and disposal practices may not be adequate.
While we only use what we consider to be reputable disposal facilities, we might not know of a potential problem if the disposal
occurred before we acquired the property or business, and if the problem itself is not discovered until years later. Our properties,
adjacent affected properties, offsite disposal facilities and 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 million per spill, while the liability limit for offshore facilities is the payment of all
removal costs plus $75 million per spill damages. These limits do not apply if the spill is caused by a responsible party’s gross
negligence or willful misconduct; the spill resulted from a responsible party’s violation of a federal safety, construction or operating
regulation; a responsible party fails to report a spill or to cooperate fully in a cleanup; or a responsible party fails to comply with an
order issued under the authority of the Intervention on the High Seas Act. OPA also requires the lessee or permittee of the offshore
area in which a covered offshore facility is located to establish and maintain evidence of financial responsibility in the amount of $35
million to cover liabilities related to an oil spill for which such responsible party is statutorily responsible. The President may increase
the amount of financial responsibility required under OPA by up to $150 million, depending on the risk represented by the quantity or
quality of oil that is handled by the facility. Any failure to comply with OPA’s requirements or inadequate cooperation during a spill
response action may subject a responsible party to administrative penalties up to $25,000 per day per violation. We believe we are in
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 and 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 water 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. In May 2016, several environmental groups sued the EPA for failing
to update its rules for management of oil and gas drilling waste under RCRA. The petitioners requested that the EPA revise its
regulations for waste materials generated as a result of oil and gas exploration and production activities. The petitioners claimed that
the EPA has not reviewed or revised its regulations for management of wastes from oil and gas exploration and production operations
since 1988, even though the statute requires the EPA to review and, if necessary, revise the regulations every three years. In
December 2016, the court entered a Consent Decree resolving the litigation. Under the Consent Decree, the EPA has agreed to
propose no later than March 15, 2019 a rulemaking for revision of the regulations pertaining to oil and gas wastes or sign a
13
determination that revision of the regulations is not necessary. In the event that the EPA proposes a rulemaking for revised oil and gas
waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than
July 15, 2021. Any such change in the current RCRA exemption and comparable state laws could result in an increase in the costs to
manage and dispose of wastes. Additionally, these exploration and production wastes may be regulated by state agencies as solid
waste. Also, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes and waste compressor oils may be
regulated as hazardous waste. Although we do not believe the current costs of managing our materials constituting wastes (as they are
presently classified) to be significant, any repeal or modification of the oil and gas exploration and production exemption by
administrative, legislative or judicial process, or modification of similar exemptions in analogous state statutes would increase the
volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur
increased operating expenses.
Clean Water Act. The Federal Water Pollution Control Act, or the Clean Water Act, as amended (“CWA”), and analogous state laws
impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances,
into state waters or other waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in
accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure
requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of
navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, CWA and analogous state laws
require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.
The EPA had regulations under the authority of CWA that required certain oil and gas exploration and production projects to obtain
permits for construction projects with storm water discharges. However, the Energy Policy Act of 2005 nullified most of the EPA
regulations that required storm water permitting of oil and gas construction projects. There are still some state and federal rules that
regulate the discharge of storm water from some oil and gas construction projects. Costs may be associated with the treatment of
wastewater and/or developing and implementing storm water pollution prevention plans. Federal and state regulatory agencies can
impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of CWA and
analogous state laws and regulations. In Section 40 CFR 112 of the regulations, the EPA promulgated the Spill Prevention, Control
and Countermeasure 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.
The EPA announced in 2015 that it would directly regulate methane emissions from oil and natural gas wells for the first time as part
of President Obama’s Climate Action Plan. As part of this strategy, in May 2016, the EPA issued three final rules. The EPA issued a
final rule that updated the New Source Performance Standards to add requirements that the oil and gas industry reduce emissions of
greenhouse gases and to cover additional equipment and activities in the oil and gas production chain. The final rule sets emissions
limits for methane, which is the principal greenhouse gas emitted by equipment and processes in the oil and gas sector. This rule
applies to new, reconstructed and modified processes and equipment. This rule also expands the volatile organic compound emissions
limits to hydraulically fractured oil wells and equipment used across the industry that was not regulated in the 2012 rules. The rule
also requires owners and operators to find and repair leaks, also known as “fugitive emissions.” The EPA also issued a final rule
known as the Source Determination Rule, which is intended to clarify when multiple pieces of equipment and activities in the oil and
gas industry must be deemed a single source when determining whether major source permitting programs apply under the prevention
of significant deterioration, nonattainment new source review preconstruction and operation permit programs under Title V of the
CAA (“Title V”). The final rule defines the term “adjacent” to clarify that equipment and activities in the oil and gas sector that are
under common control will be considered part of the same source if they are located near each other – specifically, if they are located
on the same site, or on sites that share equipment and are within one quarter of a mile of each other. This rule applies to equipment
and activities used for onshore oil and natural gas production, and for natural gas processing. It does not apply to offshore operations.
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Finally, the EPA also issued a final Federal Implementation Plan (“FIP”) for Indian country, which implements the minor new source
review program in Indian country for oil and natural gas production. The FIP will be used instead of site-specific minor new source
review preconstruction permits in Indian country and incorporates emissions limits and other requirements from eight federal air
standards, including the final New Source Performance Standard. Requirements of the FIP apply throughout Indian country, except
non-reservation areas, unless a tribe or the EPA demonstrates jurisdiction for those areas.
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.
In 2016, the EPA also issued the first draft of an Information Collection Request, seeking a broad range of information on the oil and
gas industry, including: how equipment and emissions controls are, or can be, configured, what installing those controls entails and the
associated costs. This includes information on natural gas venting that occurs as part of existing processes or maintenance activities,
such as well and pipeline blowdowns, equipment malfunctions and flashing emissions from storage tanks.
After the closing of the Kodiak Acquisition, the EPA contacted us to discuss Kodiak’s responses to a June 2014 information request
from the EPA under Section 114(a) of the CAA. In addition, in July 2015 and March 2016, we received information requests from the
EPA under Section 114(a) of the CAA. The information requests relate to tank batteries used in our Williston Basin operations and
our compliance with certain regulatory requirements at those locations for the control of air pollutant emissions from those facilities.
We have responded to the EPA’s July 2015 and March 2016 information requests, and such responses were also provided to the North
Dakota Department of Health (the “NDDoH”), with whom the EPA was coordinating in making the requests. The EPA has sole
authority to enforce CAA violations on the Fort Berthold Indian Reservation in North Dakota, and, to date, no formal federal
enforcement action has been commenced in connection with this matter for our North Dakota tribal properties beyond receipt of the
noted information requests. We are unable to predict the ultimate outcome of possible federal enforcement with respect to our North
Dakota tribal properties, or other exclusively federal requirements at any of our North Dakota properties, at this time, which could
result in civil penalties or require us to undertake corrective actions, or both.
In connection with the above EPA inquiries, in October 2016, the NDDoH concurrently filed in the North Dakota District Court for
Burleigh County (the “Court”) a complaint against, and a settlement with, us regarding tank operation and other inspection-related
alleged violations of North Dakota’s air pollution control laws. In November 2016, the Court issued its order accepting this settlement
as its final judgment to resolve the issues raised in the complaint. This settlement addresses approximately 94 percent of our North
Dakota properties but does not address our North Dakota tribal property operations or exclusively federal requirements applicable to
all of our North Dakota properties, which are governed by the EPA. In the settlement, we and a significant number of North Dakota
operators have worked with the NDDoH to develop inspection and repair measures to detect and prevent emissions from facilities
even more effectively going forward. We believe these measures will be included in settlements between the NDDoH and each
participating operator. We and the NDDoH, pending Court approval of the settlement, have agreed that we will pay a civil penalty of
$1.2 million, of which $1.1 million may be reduced by up to 60 percent by early and continued implementation of the aforementioned
inspection and repair measures and a quality control policy. We anticipate being able to qualify for all available penalty reductions.
The settlement is not an admission by us of any violation.
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 mainly water and sand plus a de minimis amount of 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, Montana and North Dakota, 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
also issued guidance in 2014 for permitting authorities and the industry regarding the process for obtaining a permit for hydraulic
fracturing involving diesel.
In December 2016, the EPA released a final report on the potential impacts of oil and gas fracturing activities on the quality and
quantity of drinking water resources in the United States. In addition, in June 2016, the EPA issued a final rule promulgating
pretreatment standards for the oil and gas extraction category which would address discharges of wastewater pollutants from onshore
unconventional oil and gas extraction facilities to publicly-owned treatment works. The EPA is also conducting a study of private
wastewater treatment facilities accepting oil and gas extraction wastewater. The EPA is collecting data and information regarding the
extent to which these facilities accept such wastewater, available treatment technologies (and their associated costs), discharge
characteristics, financial characteristics of the facilities, the environmental impacts of discharges and other information.
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. In March 2015, the U.S. Department of the Interior
released a final rule addressing (i) hydraulic fracturing on federal and Indian oil and natural gas leases to require validation of well
integrity and strong cement barriers between the wellbore and water zones through which the wellbore passes, (ii) disclosure of
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chemicals used in hydraulic fracturing to the Bureau of Land Management, (iii) higher standards for interim storage of recovered
waste fluids from hydraulic fracturing, and (iv) measures to lower the risk of cross-well contamination with chemicals and fluids used
in fracturing operations. In addition, legislation has been introduced in Congress from time to time to provide for federal regulation of
hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Also, some states have adopted, and
other states are considering adopting, regulations that could ban, restrict or impose additional requirements on activities relating to
hydraulic fracturing in certain circumstances. For example, in June 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 permitting requirements or operational
restrictions and also to associated permitting delays, litigation risk and potential increases in costs. Further, local governments may
seek to adopt, and some have adopted, ordinances within their jurisdictions restricting the use of or regulating the time, place and
manner of drilling or hydraulic fracturing. No assurance can be given as to whether or not similar measures might be considered or
implemented in the jurisdictions in which our properties are located. If new laws, regulations or ordinances that significantly restrict
or otherwise impact hydraulic fracturing are passed by Congress or adopted in the states or local municipalities where our properties
are located, such legal requirements could prohibit or make it more difficult or costly for us to perform hydraulic fracturing activities
and thereby could affect the determination of whether a well is commercially viable. In addition, restrictions on hydraulic fracturing
could reduce the amount of oil and natural gas that we are ultimately able to produce in commercially paying quantities and the
calculation of our reserves.
In addition, in July 2014, a major university and U.S. Geological Survey researchers published a study purporting to find a causal
connection between the deep well injection of hydraulic fracturing wastewater and a sharp increase in seismic activity in Oklahoma
since 2008. This study, as well as subsequent studies and reports, may trigger new legislation or regulations that would limit or ban
the disposal of hydraulic fracturing wastewater in deep injection wells. If such new laws or rules are adopted, our operations may be
curtailed while alternative treatment and disposal methods are developed and approved.
Further, in May 2014, the EPA published an Advance Notice of Proposed Rulemaking under the Toxic Substances Control Act,
relating to the disclosure of chemical substances and mixtures used in oil and gas exploration and production. Depending on the
precise disclosure requirements the EPA elects to impose, if any, we may be obliged to disclose valuable proprietary information, and
failure to do so may subject us to penalties.
Global Warming and Climate Change. In December 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 adopted and implemented regulations that restrict emissions of GHG under existing provisions of the CAA, including
rules that limit 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 in January 2011. In June 2010, the EPA published its final rule to address
the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (the “PSD”) and Title V
permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-
step process, with the largest sources first becoming subject to permitting. Further, facilities required to obtain PSD permits for their
GHG emissions are required to reduce those emissions consistent with guidance for determining “best available control technology”
standards for GHG, which guidance was published by the EPA in November 2010. Also in November 2010, the EPA expanded its
existing GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution
facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis. We believe that we are in
compliance with all substantial applicable emissions requirements.
In June 2014, the Supreme Court upheld most of the EPA’s GHG permitting requirements, allowing the agency to regulate the
emission of GHG from stationary sources already subject to the PSD and Title V requirements. Certain of our equipment and
installations may currently be subject to PSD and Title V requirements and hence, under the Supreme Court’s ruling, may also be
subject to the installation of controls to capture GHG. For any equipment or installation so subject, we may have to incur increased
compliance costs to capture related GHG emissions.
In October 2016, the EPA proposed revisions to the rule applicable to GHGs for PSD and Title V permitting requirements. The
proposed rule has not been finalized.
In accordance with President Obama’s Climate Action Plan, in August 2015, the EPA issued a rule to reduce carbon emissions from
electric generating units. The rule, commonly called the “Clean Power Plan”, requires states to develop plans to reduce carbon
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emissions from fossil fuel-fired generating units commencing in 2022, with the reductions to be fully phased in by 2030. Each state is
given a different carbon reduction target, but the EPA expects that, in the aggregate, the overall proposal will reduce carbon emissions
from electric generating units by 32% from 2005 levels. States are given substantial flexibility in meeting their emission reduction
targets and can generally choose to lower carbon emissions by replacing higher carbon generation, such as coal or natural gas, with
lower carbon generation, such as efficient natural gas units or renewable energy alternatives. Several industry groups and states have
challenged the Clean Power Plan in the Court of Appeals for the D.C. Circuit, and in February 2016, the U.S. Supreme Court stayed
the implementation of the Clean Power Plan while it is being challenged in court. The Court of Appeals for the D.C. Circuit heard
oral arguments on the Clean Power Plan in September 2016, but has not yet issued a decision. President Trump has indicated that he
is opposed to the Clean Power Plan, and the new administration could withdraw the rule and potentially repropose it, or seek to
invalidate the EPA’s prior determination that GHGs present an endangerment to public health and the environment. Either action is
likely to be challenged in court, which could delay implementation of any new rules.
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, GHG permitting and/or
regional GHG “cap and trade” programs. Most of these “cap and trade” programs work by requiring either major sources of emissions
or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase
reduced each year until the overall GHG emission reduction goal is achieved. In the absence of new legislation, the EPA is issuing
new regulations that limit emissions of GHG associated with our operations, which will require us to incur costs to inventory and
reduce emissions of GHG associated with our operations and which could adversely affect demand for the oil, NGLs and natural gas
that we produce. Finally, it should be noted that many scientists have concluded that increasing concentrations of GHG in the
atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms,
droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our assets and
operations.
Consideration of Environmental Issues in Connection with Governmental Approvals. Our operations frequently require licenses,
permits and/or other governmental approvals. Several federal statutes, including the Outer Continental Shelf Lands Act (“OCSLA”),
the National Environmental Policy Act (“NEPA”) and the Coastal Zone Management Act (“CZMA”), require federal agencies to
evaluate environmental issues in connection with granting such approvals and/or taking other major agency actions. OCSLA, for
instance, requires the U.S. Department of Interior to evaluate whether certain proposed activities would cause serious harm or damage
to the marine, coastal or human environment. Similarly, NEPA requires the Department of Interior and other federal agencies to
evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an
agency would have to prepare an environmental assessment and potentially an environmental impact statement. The CZMA, on the
other hand, aids states in developing a coastal management program to protect the coastal environment from growing demands
associated with various uses, including offshore oil and gas development. In obtaining various approvals from the Department of
Interior, we must certify that we will conduct our activities in a manner consistent with all applicable regulations.
Employees
As of January 31, 2017, we had approximately 850 full-time employees, including 27 senior level geoscientists and 63 petroleum
engineers. Our employees are not represented by any labor unions. We consider our relations with our employees to be satisfactory
and have never experienced a work stoppage or strike.
Available Information
We maintain a website at the address www.whiting.com. We are not including the information contained on our website as part of, or
incorporating it by reference into, this report. We make available free of charge (other than an investor’s own Internet access charges)
through our website our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, including
exhibits and amendments to these reports, as soon as reasonably practicable after we electronically file such material with, or furnish
such material to, the SEC.
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Item 1A. Risk Factors
Each of the risks described below should be carefully considered, together with all of the other information contained in this Annual
Report on Form 10-K, before making an investment decision with respect to our securities. In the event of the occurrence,
reoccurrence, continuation or increased severity of any of the risks described below, our business, financial condition or results of
operations could be materially and adversely affected, and you may lose all or part of your investment.
Oil and natural gas prices are very volatile. An extended period of low oil and natural gas prices may adversely affect our
business, financial condition, results of operations or cash flows.
The oil and gas markets are very volatile, and we cannot predict future oil and natural gas prices. The price we receive for our oil,
NGL and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. The prices
we receive for our production depend on numerous factors beyond our control, including, but not limited to, the following:
changes in regional, domestic and global supply and demand for oil and natural gas;
the level of global oil and natural gas inventories;
the actions of the Organization of Petroleum Exporting Countries;
the price and quantity of imports of foreign oil and natural gas;
political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity,
such as the recent conflicts in the Middle East;
the level of global oil and natural gas exploration and production activity;
the effects of global credit, financial and economic issues;
developments of United States energy infrastructure, such as the recent delays in constructing the Dakota Access Pipeline;
weather conditions;
technological advances affecting energy consumption;
current and anticipated changes to domestic and foreign governmental regulations, including those expected as a result of the
election of Donald Trump to the U.S. Presidency;
proximity and capacity of oil and natural gas pipelines and other transportation facilities;
the price and availability of competitors’ supplies of oil and natural gas in captive market areas;
the price and availability of alternative fuels; and
acts of force majeure.
Moreover, government regulations, such as regulation of oil and natural gas gathering and transportation, can adversely affect
commodity prices in the long term.
These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price
movements. Also, prices for crude oil and prices for natural gas do not necessarily move in tandem. Declines in oil or natural gas
prices would not only reduce revenue, but could also reduce the amount of oil and natural gas that we can economically produce and
therefore potentially lower our oil and gas reserve quantities. If the oil and natural gas industry continues to experience low prices, we
may, among other things, be unable to meet all of our financial obligations or make planned expenditures.
Oil prices have fallen significantly since reaching highs of over $105.00 per Bbl in June 2014, dropping below $27.00 per Bbl in
February 2016. Natural gas prices have also declined from over $4.80 per MMBtu in April 2014 to below $1.70 per MMBtu in March
2016. Although oil and natural gas prices have begun to recover from the lows experienced during the first quarter of 2016, forecasted
prices for both oil and natural gas remain low.
Substantial and extended declines in oil, NGL and natural gas prices have resulted and may continue to result in impairments of our
proved oil and gas properties or undeveloped acreage and may materially and adversely affect our future business, financial condition,
cash flows, 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, sell assets or borrow to
fund any such shortfall. Lower commodity prices have reduced, and may further reduce, the amount of our borrowing base under our
credit agreement, which is determined at the discretion of our 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. Upon a redetermination, if borrowings in excess of the revised borrowing capacity
were outstanding, we could be forced to immediately repay a portion of the debt outstanding under our credit agreement.
Lower commodity prices may also make it more difficult for us to comply with the covenants and other restrictions in the agreements
governing our debt as described under “— The instruments governing our indebtedness contain various covenants limiting the
discretion of our management in operating our business.”
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Alternatively, higher oil 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.
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 development 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:
substantial or extended declines in oil, NGL and natural gas prices;
delays imposed by or resulting from compliance with regulatory requirements;
delays in 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 and completion services;
equipment failures or accidents;
adverse weather conditions, such as freezing temperatures, hurricanes and storms;
pipeline takeaway and refining and processing capacity; and
title problems.
Our debt level and the covenants in the agreements governing our debt could negatively impact our financial condition, results of
operations, cash flows and business prospects.
As of December 31, 2016, we had $550 million in borrowings and $11 million in letters of credit outstanding under Whiting Oil and
Gas Corporation’s (“Whiting Oil and Gas”) credit facility with $1.9 billion of available borrowing capacity, as well as $2,243 million
of senior notes outstanding, $562 million of convertible senior notes outstanding and $275 million of senior subordinated notes
outstanding. On February 2, 2017, we redeemed all $275 million of our senior subordinated notes outstanding. We are allowed to
incur additional indebtedness, provided that we meet certain requirements in the indentures governing our senior notes and 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:
making it more difficult for us to satisfy our obligations with respect to our indebtedness, and any failure to comply with the
obligations of any of our debt agreements, including financial and other restrictive covenants, could result in an event of default
under Whiting Oil and Gas’ credit agreement and the indentures governing our senior notes and our convertible senior notes;
requiring us to dedicate a substantial portion of our cash flow from operations to required payments on debt, thereby reducing
the availability of cash flow for working capital, capital expenditures and other general business activities;
limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general
corporate and other activities;
limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
placing us at a competitive disadvantage relative to other less leveraged competitors;
making us vulnerable to increases in interest rates, because debt under Whiting Oil and Gas’ credit agreement is subject to
certain rate variability;
making us more vulnerable to economic downturns and adverse developments in our industry or the economy in general,
especially declines in oil and natural gas prices; and
when oil and natural gas prices decline, our ability to maintain compliance with our financial covenants becomes more difficult
and our borrowing base is subject to reductions, which may reduce or eliminate our ability to fund our operations.
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 redetermined on May 1 and November 1 of each year, and may be the subject of special redeterminations
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described in such credit agreement based on an evaluation of our oil and gas reserves. Because oil and gas prices are principal inputs
into the valuation of our reserves, if oil and gas prices remain at their current levels for a prolonged period or go lower, our borrowing
base could be reduced at the next redetermination date or during future redeterminations. Upon a redetermination, if borrowings in
excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of our debt outstanding
under the credit agreement.
We may not have sufficient funds to make such repayments. If we are unable to repay our debt out of cash on hand, we could attempt
to refinance such debt, sell assets or repay such debt with the proceeds from an equity offering. We may not be able to generate
sufficient cash flow to pay the interest on our debt or future borrowings, and equity financings or proceeds from the sale of assets may
not be available to pay or refinance such debt. The terms of our debt, including Whiting Oil and Gas’ credit agreement, may also
prohibit us from taking such actions. Factors that will affect our ability to raise cash through an offering of our capital stock or debt
securities, 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.
If we cannot make scheduled payments on our indebtedness or otherwise fail to comply with the covenants and other restrictions in
the agreements governing our debt, we will be in default and the lenders under Whiting Oil and Gas’ credit agreement and the holders
of our senior notes and convertible senior notes could declare all outstanding principal and interest to be due and payable, and the
lenders under Whiting Oil and Gas’ credit agreement could terminate their commitments to loan money and could foreclose against
the assets collateralizing their borrowings and we could be forced into bankruptcy or liquidation. Our inability to generate sufficient
cash flows to satisfy our debt obligations, or to refinance our indebtedness on commercially reasonable terms or at all, would
materially and adversely affect our financial position and results of operations. Further, failing to comply with the financial and other
restrictive covenants in Whiting Oil and Gas’ credit agreement and the indentures governing our senior notes and convertible senior
notes could result in an event of default, which could adversely affect our business, financial condition and results of operations.
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 convertible senior 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 debt;
make loans to others;
make investments;
incur additional indebtedness or issue preferred stock;
create certain liens;
sell assets;
enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;
consolidate, merge or transfer all or substantially all of our assets and those of our restricted subsidiaries taken as a whole;
engage in transactions with affiliates;
enter into hedging contracts;
create unrestricted subsidiaries; and
enter into sale and leaseback transactions.
In addition, Whiting Oil and Gas’ credit agreement requires us, as of the last day of any quarter, to maintain the following ratios (as
defined in the credit agreement): (i) a consolidated current assets to consolidated current liabilities ratio (which includes an add back
of the available borrowing capacity under the credit agreement) of not less than 1.0 to 1.0, (ii) a total senior secured debt to the last
four quarters’ EBITDAX ratio of less than 3.0 to 1.0 during the Interim Covenant Period (defined below), and thereafter a total debt to
EBITDAX ratio of less than 4.0 to 1.0, and (iii) a ratio of the last four quarters’ EBITDAX to consolidated cash interest charges of not
less than 2.25 to 1.0 during the Interim Covenant Period. Under the credit agreement, the “Interim Covenant Period” is defined as the
period from June 30, 2015 until the earlier of (i) April 1, 2018 or (ii) the commencement of an investment-grade debt rating period.
Also, the indentures under which we issued our senior notes restrict us from incurring additional indebtedness and making certain
restricted payments, subject to certain exceptions, unless our fixed charge coverage ratio (as defined in the indentures) is at least
2.0 to 1.0. 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 convertible senior notes or Whiting Oil and
Gas’ credit agreement or any other subsequent financing agreements, a default may allow the creditors to accelerate the related
indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision applies. In addition, lenders
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may be able to terminate any commitments they had made to make further funds available to us. Furthermore, if we were unable to
repay the amounts due and payable under Whiting Oil and Gas’ credit agreement, those lenders could proceed against the collateral
granted to them to secure that indebtedness. In the event that our lenders or noteholders accelerate the repayment of our borrowings,
we and our subsidiaries may not have sufficient assets or be able to borrow sufficient funds to repay or refinance that indebtedness.
Also, if we are in default under the agreements governing our indebtedness, we will not be able to pay dividends on our capital stock.
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 $1.5 billion
impairment charge during 2015 for the partial write-down of the North Ward Estes field in Texas and other non-core proved oil and
gas properties primarily in Texas, Wyoming, North Dakota and Colorado that were not being developed due to depressed oil and gas
prices. Additionally, we recorded a $62 million impairment charge during 2015 for the partial write-down of our CO2 development
properties in New Mexico and Colorado whose net book values exceeded their undiscounted future net cash flows. 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.
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 mainly water and sand plus a de minimis amount of 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, Montana and North Dakota, 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”) also issued guidance in 2014 for permitting authorities and the industry regarding the
process for obtaining a permit for hydraulic fracturing involving diesel.
In December 2016, the EPA released a final report on the potential impacts of oil and gas fracturing activities on the quality and
quantity of drinking water resources in the United States. In addition, in June 2016, the EPA issued a final rule promulgating
pretreatment standards for the oil and gas extraction category which would address discharges of wastewater pollutants from onshore
unconventional oil and gas extraction facilities to publicly-owned treatment works. The EPA is also conducting a study of private
wastewater treatment facilities accepting oil and gas extraction wastewater. The EPA is collecting data and information regarding the
extent to which these facilities accept such wastewater, available treatment technologies (and their associated costs), discharge
characteristics, financial characteristics of the facilities, the environmental impacts of discharges and other information.
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. In March 2015, the U.S. Department of the Interior
released a final rule addressing (i) hydraulic fracturing on federal and Indian oil and natural gas leases to require validation of well
integrity and strong cement barriers between the wellbore and water zones through which the wellbore passes, (ii) disclosure of
chemicals used in hydraulic fracturing to the Bureau of Land Management, (iii) higher standards for interim storage of recovered
waste fluids from hydraulic fracturing, and (iv) measures to lower the risk of cross-well contamination with chemicals and fluids used
in fracturing operations. In addition, legislation has been introduced in Congress from time to time to provide for federal regulation of
hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Also, some states have adopted, and
other states are considering adopting, regulations that could ban, restrict or impose additional requirements on activities relating to
hydraulic fracturing in certain circumstances. For example, in June 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 permitting 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
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or otherwise impact hydraulic fracturing are passed by Congress or adopted in the states or local municipalities where our properties
are located, such legal requirements could prohibit or make it more difficult or costly for us to perform hydraulic fracturing activities
and thereby could affect the determination of whether a well is commercially viable. In addition, restrictions on hydraulic fracturing
could reduce the amount of oil and natural gas that we are ultimately able to produce in commercially paying quantities and the
calculation of our reserves.
In addition, in July 2014, a major university and U.S. Geological Survey researchers published a study purporting to find a causal
connection between the deep well injection of hydraulic fracturing wastewater and a sharp increase in seismic activity in Oklahoma
since 2008. This study, as well as subsequent studies and reports, may trigger new legislation or regulations that would limit or ban
the disposal of hydraulic fracturing wastewater in deep injection wells. If such new laws or rules are adopted, our operations may be
curtailed while alternative treatment and disposal methods are developed and approved.
Further, in May 2014, the EPA published an Advance Notice of Proposed Rulemaking under the Toxic Substances Control Act,
relating to the disclosure of chemical substances and mixtures used in oil and gas exploration and production. Depending on the
precise disclosure requirements the EPA elects to impose, if any, we may be obliged to disclose valuable proprietary information, and
failure to do so may subject us to penalties.
Refer to “Hydraulic Fracturing” in Item 2 of this Annual Report on Form 10-K for more information on hydraulic fracturing.
We have entered into physical delivery contracts and do not expect to be able to deliver all the oil required under such contracts
and, as a result, we expect we will be required to make deficiency payments.
We have entered into three physical delivery contracts which require us to deliver fixed volumes of crude oil. One of these contracts
is tied to oil production at our Sanish field in Mountrail County, North Dakota, and two are tied to oil production at our Redtail field in
Weld County, Colorado. Although, we believe that our production and reserves are sufficient to fulfill the delivery commitment at our
Sanish field in North Dakota, if we fail to deliver the committed volumes, we would be required to pay a deficiency payment of $7.00
per undelivered barrel. At our Redtail field, we have determined that it is no longer probable that future oil production will be
sufficient to meet the minimum volume requirements and we expect to make periodic deficiency payments that currently total $4.91
per undelivered Bbl (subject to upward adjustment) under one contract and that equal the terminal and transportation fees paid by the
counterparty on undelivered barrels, currently $3.93 per undelivered Bbl (subject to upward adjustment), under the other contract.
During 2016 and 2015, total deficiency payments under these contracts amounted to $43 million and $15 million, respectively. See
“Properties – Delivery Commitments” for more information about these delivery contracts.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve
estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many
assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions
could materially affect the estimated quantities and present value of reserves referred to in this Annual Report on Form 10-K.
In order to prepare our estimates, we must project production rates and timing of development expenditures. We must also analyze
available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The
process also requires economic assumptions about matters such as the following:
historical production from the area compared with production rates from other producing areas;
the assumed effect of governmental regulation; and
assumptions about future prices of oil, NGLs and natural gas including differentials, production and development costs,
gathering and transportation costs, severance and excise taxes, capital expenditures and availability of funds.
Therefore, estimates of oil and natural gas reserves are inherently imprecise. Actual future production; oil, NGL and natural gas
prices; revenues; taxes; exploration and development expenditures; operating expenses; and quantities of recoverable oil and natural
gas reserves will most likely vary from our estimates. Any significant variance could materially affect the estimated quantities and
present value of reserves referred to in this Annual Report on Form 10-K. In addition, we may adjust estimates of proved reserves to
reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of
which are beyond our control.
You should not assume that the present value of future net revenues from our proved reserves, as referred to in this report, is the
current market value of our estimated proved oil and natural gas reserves. In accordance with SEC requirements, we base the
estimated discounted future net cash flows from our proved reserves on 12-month average prices and current costs as of the date of the
estimate. The 12-month average prices used for the year ended December 31, 2016 were $42.75 per Bbl and $2.49 per MMBtu.
Actual future prices and costs may differ materially from those used in the estimate. If the 12-month average oil prices used to
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calculate our oil reserves 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, 2016 would have decreased by $181 million. If the 12-month average natural gas prices used to
calculate our natural gas reserves decline by $0.10 per MMBtu, then the standardized measure of discounted future net cash flows of
our estimated proved reserves as of December 31, 2016 would have decreased by $17 million.
Our exploration and development operations require substantial capital, and we may be unable to obtain needed capital or
financing on satisfactory terms, which could lead to a loss of properties and a decline in our oil and natural gas reserves.
The oil and gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business
and operations for the exploration, development, production and acquisition of oil and natural gas reserves. To date, we have financed
capital expenditures through a combination of equity and debt issuances, bank borrowings, internally generated cash flows,
agreements with industry partners and oil and gas property divestments. We intend to finance future capital expenditures with cash
flow from operations, proceeds from property divestitures, cash on hand and financing arrangements. Our cash flow from operations
and access to capital is subject to a number of variables, including:
the prices at which oil and natural gas are sold;
our proved reserves;
the level of oil and natural gas we are able to produce from existing wells;
the costs of producing oil and natural gas; and
our ability to acquire, locate and produce new reserves.
If our revenues or the borrowing base under our credit agreement decrease as a result of lower oil and natural gas prices, operating
difficulties, declines in reserves, or for any other reason, then we may have limited ability to obtain the capital necessary to sustain our
operations at current levels.
We may, from time to time, need to seek additional financing. There can be no assurance as to the availability or terms of any
additional financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or
at all. If cash generated by operations or available under our revolving credit facility is not sufficient to meet our capital requirements,
the failure to obtain additional financing could result in a curtailment of our operations relating to the exploration and development of
our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves.
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 received and
costs incurred to develop and produce oil and natural gas reserves. Drilling, production or transportation accidents that temporarily or
permanently halt the production and sale of oil, NGLs and natural gas will decrease revenues and increase expenditures. For example,
accidents may occur that result in personal injuries, property damage, damage to productive formations or equipment and
environmental damages. Any costs incurred in connection with any such accidents that are not insured against will have the effect of
reducing net income. Also, we do not have insurance policies in effect that are intended to provide coverage for losses solely related
to hydraulic fracturing operations. Please read “— Federal, state and local legislative and regulatory initiatives relating to hydraulic
fracturing...” above in these Risk Factors for a discussion of the uncertainty involved in the regulation of hydraulic fracturing. Also,
our oil, NGL and natural gas production depends in large part on the proximity and capacity of pipeline systems and transportation
facilities which are mostly owned by third parties. The lack of availability or the lack of capacity on these systems and facilities could
result in the curtailment of production or the delay or discontinuance of drilling plans. Similarly, curtailments or damage to pipelines
and other transportation facilities used to transport oil, NGLs and natural gas production to markets for sale could decrease revenues
or increase transportation expenses. Any such curtailments or damage to the gathering systems could also require finding alternative
means to transport the oil, NGLs and natural gas production, which alternative means could result in additional costs that will have the
effect of increasing transportation expenses.
Also, in response to accidents involving rail cars carrying Bakken formation crude oil, the U.S. Department of Transportation (the
“DOT”) issued an emergency order in February 2014 that requires rail shippers to test the makeup of such crude oil before
transporting it. This move follows the safety alert the DOT issued in January 2014 that Bakken formation crude oil is more flammable
than other types of crude oil and has been followed by additional emergency orders and safety advisories and alerts. An accident
involving rail cars could result in significant personal injuries and property and environmental damage. In May 2015, the Pipeline and
Hazardous Material Safety Administration issued new rules applicable to “high-hazard flammable trains”, discussed in “Item 1
Business – Regulation – Regulation of Sale and Transportation of Oil” above, which could increase transportation expenses.
Similarly, regulatory responses to the October 2015 failure at a Southern California underground natural gas storage facility could also
lead to increased expenses for underground storage.
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In addition, drilling, production and transportation of hydrocarbons bear the inherent risk of loss of containment. Potential
consequences include loss of reserves, loss of production, loss of economic value associated with the affected wellbore, contamination
of air, soil, ground water and surface water, as well as potential fines, penalties or damages associated with any of the foregoing
consequences.
Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production.
Failure to drill sufficient wells in order to hold acreage will result in substantial lease renewal costs, or if renewal is not feasible,
loss of our lease and prospective drilling opportunities.
Unless production is established on our undeveloped acreage, the underlying leases will expire. As of December 31, 2016, the portion
of our net undeveloped acreage that is subject to expiration over the next three years, if not successfully developed or renewed, is
approximately 25% in 2017, 28% in 2018 and 8% in 2019. The cost to renew such leases may increase significantly, and we may not
be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party
leases become immediately effective if our leases expire. As such, our actual drilling activities may materially differ from our current
expectations, which could adversely affect our business.
Our acquisition activities may not be successful.
As part of our growth strategy, we have made and may continue to make acquisitions of businesses and properties. However, suitable
acquisition candidates may not continue to be available on terms and conditions we find acceptable, and acquisitions pose substantial
risks to our business, financial condition and results of operations. In pursuing acquisitions, we compete with other companies, many
of which have greater financial and other resources to acquire attractive companies and properties. The following are some of the
risks associated with acquisitions, including any completed or future acquisitions:
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 to realize anticipated economic, operational and other
benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial
problems;
acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our
current business standards, controls and procedures;
we may issue additional equity or debt securities in order to fund future acquisitions; and
we may incur losses as a result of title defects.
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, completion crews and other oilfield equipment as demand
for these items has increased along with the number of wells being drilled and completed. 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 and other oilfield goods and services. Shortages of field personnel and other professionals, drilling
rigs, completion crews, equipment or supplies or price increases could delay or adversely affect our exploration and development
operations, which could restrict such operations or have a material adverse effect on our business, financial condition, results of
operations or cash flows.
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. 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.
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We have been an early entrant into new or emerging plays. As a result, our drilling results in these areas are uncertain, the value
of our undeveloped acreage may decline and we may incur impairment charges if drilling results are unsuccessful.
While our costs to acquire undeveloped acreage in new or emerging plays have generally been less than those of later entrants into a
developing play, our drilling results in these areas are more uncertain than drilling results in areas that are developed and producing.
Since new or emerging plays have limited or no production history, we are unable to use past drilling results in those areas to help
predict our future drilling results. Therefore, our cost of drilling, completing and operating wells in these areas may be higher than
initially expected, and the value of our undeveloped acreage will decline if drilling results are unsuccessful. Furthermore, if drilling
results are unsuccessful, we may be required to write down the carrying value of our undeveloped acreage in new or emerging plays.
For example, during 2016 we recorded a $13 million non-cash charge for the impairment of undeveloped oil and gas properties where
we have no current or future plans to drill. 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 2016, we completed 21 separate significant
acquisitions of producing properties with a combined purchase price of $6.4 billion for estimated proved reserves as of the effective
dates of the acquisitions of 445.2 MMBOE. The successful acquisition of producing properties requires assessment of many factors,
which are inherently inexact and may be inaccurate, including the following:
the amount of recoverable reserves;
future oil and natural gas prices;
estimates of operating costs;
estimates of future development costs;
timing of future development costs;
estimates of the costs and timing of plugging and abandonment; and
the assumption of unknown potential environmental and other liabilities, losses or costs, including for example, historical spills
or releases for which we are not indemnified or for which our indemnity is inadequate.
Our assessment will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to
assess fully their capabilities and deficiencies. In the course of our due diligence, we may not inspect every well, platform, facility or
pipeline. Inspections may not reveal structural and environmental problems, such as pipeline corrosion or groundwater contamination,
when they are made. We may not be able to obtain contractual indemnities from the seller for liabilities that it created. We may be
required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in
accordance with our expectations.
Part of our business strategy includes selling properties which subjects us to various risks.
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. However, there is no
assurance that such sales will occur on the time frames or with the economic terms we expect. 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 only a portion of our anticipated production, may limit higher
revenues in the future in connection with commodity price increases and may result in significant fluctuations in our net income.
We enter into hedging transactions of our oil and natural gas production revenues to reduce our exposure to fluctuations in the price of
oil and natural gas. Our hedging transactions to date have consisted of financially settled crude oil and natural gas options contracts,
primarily costless collars and swaps, placed with major financial institutions. As of January 3, 2017, we had contracts covering the
sale of 1,300,000 barrels of oil per month for all of 2017, which represents approximately 49% of our forecasted 2017 oil production
volumes. All of our oil hedges will expire by December 2018. 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.
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We may in the future enter into these and other types of hedging arrangements to reduce our exposure to fluctuations in the market
prices of oil and natural gas, or alternatively, we may decide to unwind or restructure the hedging arrangements we previously entered
into. Hedging transactions expose us to risk of financial loss in some circumstances, including if production is less than expected, the
other party to the contract defaults on its obligations or there is a change in the expected differential between the underlying price in
the hedging agreement and actual prices received. Hedging transactions may limit the benefit we may otherwise receive from
increases in the price for oil and natural gas. Our three-way collars only provide partial protection against declines in market prices
due to the fact that when the market price falls below the sub-floor, the minimum price we will receive will be NYMEX plus the
difference between the floor and the sub-floor. Furthermore, if we do not engage in hedging transactions or unwind hedging
transactions we previously entered into, then we may be more adversely affected by declines in oil and natural gas prices than our
competitors who engage in hedging transactions. Additionally, hedging transactions may expose us to cash margin requirements.
We recognize all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any
such amounts in accumulated other comprehensive income (loss). Consequently, we may experience significant net losses, on a non-
cash basis, due to changes in the value of our hedges as a result of commodity price volatility.
Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas
where we operate.
Oil and gas operations in the Rocky Mountains are adversely affected by seasonal weather conditions and lease stipulations designed
to protect various wildlife. In certain areas, drilling and other oil and gas activities can only be conducted during the spring and
summer months. This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs,
oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. Resulting shortages or high
costs could delay our operations, cause temporary declines in our oil and gas production and materially increase our operating and
capital costs.
An increase in the differential or decrease in the premium between the NYMEX or other benchmark prices of oil and natural gas
and the wellhead price we receive could have a material adverse effect on our results of operations, financial condition and cash
flows.
The prices that we receive for our oil and natural gas production generally trade at a discount, but sometimes at a premium, to the
relevant benchmark prices such as NYMEX. A negative difference between the benchmark price and the price received is called a
differential and a positive difference is called a premium. The differential and premium may vary significantly due to market
conditions, the quality and location of production and other risk factors. We cannot accurately predict oil and natural gas differentials
and premiums. Increases in the differential and decreases in the premium between the benchmark price for oil and natural gas and the
wellhead price we receive could have a material adverse effect on our results of operations, financial condition and cash flows.
We may incur substantial losses and be subject to substantial liability claims as a result of our oil and gas operations.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and
adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities
are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:
environmental hazards, such as uncontrollable flows of oil, gas, brine, well fluids, toxic gas or other pollution into the
environment, including groundwater and shoreline contamination;
abnormally pressured formations;
mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
the loss of well control;
fires and explosions;
personal injuries and death; and
natural disasters.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to our company. We may
elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition,
pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully
covered by insurance, then it could adversely affect us.
We have limited control over activities on properties we do not operate, which could reduce our production and revenues and
increase capital expenditures.
We operate 87% of our net productive oil and natural gas wells, which represents 86% of our proved developed producing reserves as
of December 31, 2016. If we do not operate the properties in which we own an interest, we do not have control over normal operating
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procedures, expenditures or future development of our properties. The failure of an operator of our wells to adequately perform
operations or an operator’s breach of the applicable agreements could reduce our production and revenues. The success and timing of
our drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our
control, including the operator’s decisions with respect to the timing and amount of capital expenditures, the period of time over which
the operator seeks to generate a return on capital expenditures, inclusion of other participants in drilling wells, and the use of
technology, as well as the operator’s expertise and financial resources and the operator’s relative interest in the field. Operators may
also opt to decrease operational activities following a significant decline in, or a sustained period of low, 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 reasonable efforts to cause the operator to act in a prudent manner, 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 on these properties, caused by transportation capacity constraints, curtailment of production
or the interruption of transporting oil and gas volumes produced. In addition, market conditions or a lack of satisfactory oil and gas
transportation arrangements may hinder our access to oil and gas markets or delay our production. The availability of a ready market
for our oil, NGL and natural gas production depends on a number of factors, including the demand for and supply of oil, NGLs and
natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends
substantially on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third-
parties. Additionally, entering into arrangements for these services exposes us to the risk that third parties will default on their
obligations under such arrangements. Our failure to obtain such services on acceptable terms or the default by a third party on their
obligation to provide such services could materially harm our business. We may be required to shut in wells for a lack of a market or
because access to gas pipelines, gathering systems or processing facilities may be limited or unavailable. If that were to occur, then
we would be unable to realize revenue from those wells until production arrangements were made to deliver the production to market.
We are subject to complex laws that can affect the cost, manner or feasibility of doing business.
Exploration, development, production and sale of oil and natural gas are subject to extensive federal, state, local and international
regulation. We may be required to make large expenditures to comply with governmental regulations. Matters subject to regulation
include:
discharge permits for drilling operations;
drilling bonds;
reports concerning operations;
well spacing;
unitization and pooling of properties; and
taxation.
Under these laws, we could be liable for personal injuries, property damage and other damages. Failure to comply with these laws
also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties.
Moreover, these laws could change in ways that could substantially increase our costs. Any such liabilities, penalties, suspensions,
terminations or regulatory changes could materially and adversely affect our financial condition and results of operations.
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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.
President Trump has indicated that he would work to ease regulatory burdens on industry and on the oil and gas sector, including
environmental regulations. However, any executive orders the President may issue or any new legislation Congress may pass with the
goal of reducing environmental statutory or regulatory requirements may be challenged in court. In addition, various state laws and
regulations (and permits issued thereunder) will be unaffected by federal changes unless and until the state laws and corresponding
permits are similarly changed, and any judicial review is completed.
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 (the “CAA”) 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.
The EPA announced in 2015 that it would directly regulate methane emissions from oil and natural gas wells for the first time as part
of President Obama’s Climate Action Plan. As part of this strategy, in May 2016, the EPA issued three final rules. The EPA issued a
final rule that updated the New Source Performance Standards to add requirements that the oil and gas industry reduce emissions of
greenhouse gases and to cover additional equipment and activities in the oil and gas production chain. The final rule sets emissions
limits for methane, which is the principal greenhouse gas emitted by equipment and processes in the oil and gas sector. This rule
applies to new, reconstructed and modified processes and equipment. This rule also expands the volatile organic compound emissions
limits to hydraulically fractured oil wells and equipment used across the industry that was not regulated in the 2012 rules. The rule
also requires owners and operators to find and repair leaks, also known as “fugitive emissions.” The EPA also issued a final rule
known as the Source Determination Rule, which is intended to clarify when multiple pieces of equipment and activities in the oil and
gas industry must be deemed a single source when determining whether major source permitting programs apply under the prevention
of significant deterioration, nonattainment new source review preconstruction and operation permit programs under Title V of the
CAA (“Title V”). The final rule defines the term “adjacent” to clarify that equipment and activities in the oil and gas sector that are
under common control will be considered part of the same source if they are located near each other – specifically, if they are located
on the same site, or on sites that share equipment and are within one quarter of a mile of each other. This rule applies to equipment
and activities used for onshore oil and natural gas production, and for natural gas processing. It does not apply to offshore operations.
Finally, the EPA also issued a final Federal Implementation Plan (“FIP”) for Indian country, which implements the minor new source
review program in Indian country for oil and natural gas production. The FIP will be used instead of site-specific minor new source
review preconstruction permits in Indian country and incorporates emissions limits and other requirements from eight federal air
standards, including the final New Source Performance Standard. Requirements of the FIP apply throughout Indian country, except
non-reservation areas, unless a tribe or the EPA demonstrates jurisdiction for those areas.
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.
In 2016, the EPA also issued the first draft of an Information Collection Request, seeking a broad range of information on the oil and
gas industry, including: how equipment and emissions controls are, or can be, configured, what installing those controls entails and the
associated costs. This includes information on natural gas venting that occurs as part of existing processes or maintenance activities,
such as well and pipeline blowdowns, equipment malfunctions and flashing emissions from storage tanks.
28
After the closing of the Kodiak Acquisition, the EPA contacted us to discuss Kodiak’s responses to a June 2014 information request
from the EPA under Section 114(a) of the CAA. In addition, in July 2015 and March 2016, we received information requests from the
EPA under Section 114(a) of the CAA. The information requests relate to tank batteries used in our Williston Basin operations and
our compliance with certain regulatory requirements at those locations for the control of air pollutant emissions from those facilities.
We have responded to the EPA’s July 2015 and March 2016 information requests, and such responses were also provided to the North
Dakota Department of Health (the “NDDoH”), with whom the EPA was coordinating in making the requests. The EPA has sole
authority to enforce CAA violations on the Fort Berthold Indian Reservation in North Dakota, and, to date, no formal federal
enforcement action has been commenced in connection with this matter for our North Dakota tribal properties beyond receipt of the
noted information requests. We are unable to predict the ultimate outcome of possible federal enforcement with respect to our North
Dakota tribal properties, or other exclusively federal requirements at any of our North Dakota properties, at this time, which could
result in civil penalties or require us to undertake corrective actions, or both.
In connection with the above EPA inquiries, in October 2016, the NDDoH concurrently filed in the North Dakota District Court for
Burleigh County (the “Court”) a complaint against, and a settlement with, us regarding tank operation and other inspection-related
alleged violations of North Dakota’s air pollution control laws. In November 2016, the Court issued its order accepting this settlement
as its final judgment to resolve the issues raised in the complaint. This settlement addresses approximately 94 percent of our North
Dakota properties but does not address our North Dakota tribal property operations or exclusively federal requirements applicable to
all of our North Dakota properties, which are governed by the EPA. In the settlement, we and a significant number of North Dakota
operators have worked with the NDDoH to develop inspection and repair measures to detect and prevent emissions from facilities
even more effectively going forward. We believe these measures will be included in settlements between the NDDoH and each
participating operator. We and the NDDoH, pending Court approval of the settlement, have agreed that we will pay a civil penalty of
$1.2 million, of which $1.1 million may be reduced by up to 60 percent by early and continued implementation of the aforementioned
inspection and repair measures and a quality control policy. We anticipate being able to qualify for all available penalty reductions.
The settlement is not an admission by us of any violation.
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.
In December 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 adopted and
implemented regulations that restrict emissions of GHG under existing provisions of the CAA, including rules that limit 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 in January 2011. In June 2010, the EPA published its final rule to address the permitting of GHG emissions
from stationary sources under the Prevention of Significant Deterioration (the “PSD”) and Title V permitting programs. This rule
“tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest
sources first subject to permitting. Further, facilities required to obtain PSD permits for their GHG emissions are required to reduce
those emissions consistent with guidance for determining “best available control technology” standards for GHG, which guidance was
published by the EPA in November 2010. Also in November 2010, the EPA expanded its existing GHG reporting rule to include
onshore oil and natural gas production, processing, transmission, storage and distribution facilities. This rule requires reporting of
GHG emissions from such facilities on an annual basis.
In June 2014, the Supreme Court upheld most of the EPA’s GHG permitting requirements, allowing the agency to regulate the
emission of GHG from stationary sources already subject to the PSD and Title V requirements. Certain of our equipment and
installations may currently be subject to PSD and Title V requirements and hence, under the Supreme Court’s ruling, may also be
subject to the installation of controls to capture GHGs. For any equipment or installation so subject, we may have to incur increased
compliance costs to capture related GHG emissions.
In accordance with President Obama’s Climate Action Plan, in August 2015, the EPA issued a rule to reduce carbon emissions from
electric generating units. The rule, commonly called the “Clean Power Plan”, requires states to develop plans to reduce carbon
emissions from fossil fuel-fired generating units commencing in 2022, with the reductions to be fully phased in by 2030. Each state is
given a different carbon reduction target, but the EPA expects that, in the aggregate, the overall proposal will reduce carbon emissions
from electric generating units by 32% from 2005 levels. States are given substantial flexibility in meeting their emission reduction
targets and can generally choose to lower carbon emissions by replacing higher carbon generation, such as coal or natural gas, with
29
lower carbon generation, such as efficient natural gas units or renewable energy alternatives. Several industry groups and states have
challenged the Clean Power Plan in the Court of Appeals for the D.C. Circuit, and in February 2016, the U.S. Supreme Court stayed
the implementation of the Clean Power Plan while it is being challenged in court. The Court of Appeals for the D.C. Circuit heard
oral arguments on the Clean Power Plan in September 2016, but has not yet issued a decision. President Trump has indicated that he
is opposed to the Clean Power Plan, and the new administration could withdraw the rule and potentially repropose it, or seek to
invalidate the EPA’s prior determination that GHGs present an endangerment to public health and the environment. Either action is
likely to be challenged in court, which could delay implementation of any new rules.
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, GHG permitting and/or
regional GHG “cap and trade” programs. Most of these “cap and trade” programs work by requiring either major sources of emissions
or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase
reduced each year until the overall GHG emission reduction goal is achieved. In the absence of new legislation, the EPA is issuing
new regulations that limit emissions of GHG associated with our operations which will require us to incur costs to inventory and
reduce emissions of GHG associated with our operations and which could adversely affect demand for the oil, NGLs and natural gas
that we produce. Finally, it should be noted that many scientists have concluded that increasing concentrations of GHG in the
atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms,
droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our assets and
operations.
Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our
cash flows and results of operations.
Unless we conduct successful exploration, development and production activities or acquire properties containing proved reserves, our
proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs are generally characterized by
declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves
and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing and producing
our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or
acquire additional reserves to replace our current and future production.
The loss of senior management or technical personnel could adversely affect us.
To a large extent, we depend on the services of our senior management and technical personnel. The loss of the services of our senior
management or technical personnel, including James J. Volker, Chairman, President and Chief Executive Officer; Peter W. Hagist,
Senior Vice President, Planning; Rick A. Ross, Senior Vice President, Operations; Michael J. Stevens, Senior Vice President and
Chief Financial Officer; Mark R. Williams, Senior Vice President, Exploration and Development; Brent P. Jensen, Vice President,
Finance and Treasurer; Steven A. Kranker, Vice President, Reservoir Engineering/Acquisitions; or David M. Seery, Vice President,
Land, 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.
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.
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, obtaining investment capital, securing oilfield goods and
services, marketing oil and natural gas products and attracting and retaining qualified 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 resources allow for. Our ability to acquire
additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties
and to consummate transactions in a highly competitive environment. 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.
30
In connection with the passage of the Dodd-Frank Wall Street Reform and Consumer Protection Act, 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 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, may be established through rulemakings and would not take effect until 12 months after the
date of enactment. Although we cannot predict the ultimate outcome of these rulemakings, new regulations in this area may result in
increased costs and cash collateral requirements for the types of oil and gas derivative instruments we use to hedge and to otherwise
manage our financial risks related to volatility in oil and gas commodity prices.
We depend on computer and telecommunications systems, and failures in our systems or cyber security attacks could significantly
disrupt our business operations.
We have entered into agreements with third parties for hardware, software, telecommunications and other information technology
services in connection with our business. In addition, we have developed proprietary software systems, management techniques and
other information technologies incorporating software licensed from third parties. It is possible we could incur interruptions from
cyber security attacks, computer viruses or malware. We believe that we have positive relations with our related vendors and maintain
adequate anti-virus and malware software and controls; however, any interruptions to our arrangements with third parties for our
computing and communications infrastructure or any other interruptions to our information systems could lead to data corruption,
communication interruption or otherwise significantly disrupt our business operations.
Our convertible senior notes may adversely affect the market price of our common stock.
The market price of our common stock is likely to be influenced by our convertible senior notes. For example, the market price of our
common stock could become more volatile and could be depressed by:
investors’ anticipation of the potential resale in the market of a substantial number of additional shares of our common stock
received upon conversion of our convertible senior notes;
possible sales of our common stock by investors who view our convertible senior notes as a more attractive means of equity
participation in us than owning shares of our common stock; and
hedging or arbitrage trading activity that may develop involving our convertible senior notes and our common stock.
Item 1B. Unresolved Staff Comments
None.
31
Item 2. Properties
Summary of Oil and Gas Properties and Projects
Northern Rocky Mountains
Our Northern Rocky Mountains operations include our properties in the Williston Basin of North Dakota and Montana targeting the
Bakken and Three Forks formations and encompassing approximately 736,000 gross (443,800 net) developed and undeveloped acres
as of December 31, 2016. Our estimated proved reserves in the Northern Rocky Mountains as of December 31, 2016 were 450.8
MMBOE (63% oil), which represented 73% of our total estimated proved reserves and contributed 108.9 MBOE/d of average daily
production in the fourth quarter of 2016.
In April and July 2016, we entered into two separate wellbore participation agreements related to the wells that we drilled in the
Williston Basin in 2016, which helped allow us to continue completion activity in this area. As of December 31, 2016, we had four
rigs active in the Williston Basin. Across our acreage in the Williston Basin, we have implemented our new completion design which
utilizes cemented liners, plug-and-perf technology, significantly higher sand volumes, new diversion technology and both hybrid and
slickwater fracture stimulation methods, which has resulted in improved initial production rates.
In order to process the produced gas stream from our wells in the Sanish and Pronghorn fields, we constructed the Robinson Lake gas
plant and the Belfield gas plant, respectively. As of December 31, 2016, we held a 50% ownership interest in each of these gas
processing plants. On January 1, 2017, we closed on the sale of our interests in these two gas processing plants and the related
gathering systems and facilities. Refer to the “Subsequent Events” footnote in the notes to the consolidated financial statements for
further information.
Central Rocky Mountains
Our Central Rocky Mountains operations include properties at our Redtail field in the Denver Julesburg Basin (“DJ Basin”) in Weld
County, Colorado targeting the Niobrara and Codell/Fort Hays formations and encompassing approximately 157,200 gross (132,200
net) developed and undeveloped acres as of December 31, 2016. Our estimated proved reserves in the Central Rocky Mountains as of
December 31, 2016 were 160.7 MMBOE (68% oil), which represented 26% of our total estimated proved reserves and contributed 9.2
MBOE/d of average daily production in the fourth quarter of 2016.
We have established production in the Niobrara “A”, “B” and “C” zones and the Codell/Fort Hays formations. Our development plan
at Redtail currently includes drilling up to eight wells per spacing unit in the Niobrara “A”, “B” and “C” zones and up to four wells
per spacing unit in the Codell/Fort Hays formations. Additionally, the Codell/Fort Hays formation is prospective throughout our
acreage in the Redtail field, and we are currently evaluating that formation. We have implemented a new wellbore configuration in
this area, which significantly reduces drilling times. As of December 31, 2016, we had one drilling rig operating in the DJ Basin. We
suspended completion operations in this area beginning in the second quarter of 2016; however, we plan to resume completion activity
in early 2017.
Our Redtail gas plant processes the associated gas produced from our wells in this area, and has a current inlet capacity of 50 MMcf/d.
As of December 31, 2016, the plant was processing over 16 MMcf/d.
Other
Our other operations primarily relate to non-core assets in Colorado, Mississippi, North Dakota, Texas and Wyoming. As of
December 31, 2016, these properties contributed 4.0 MMBOE (90% oil) of proved reserves to our portfolio of operations, which
represented 1% of our total estimated proved reserves and contributed 0.8 MBOE/d of average daily production in the fourth quarter
of 2016.
In July 2016, we sold our interest in the North Ward Estes field located in Ward and Winkler counties in Texas as further described in
“Acquisitions and Divestitures” within Item 1 of this Annual Report on Form 10-K.
32
Reserves
As of December 31, 2016 and 2015, all of our oil and gas reserves were attributable to properties within the United States. A
summary of our proved oil and gas reserves as of December 31, 2016 and 2015 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,
2016 and 2015, respectively) is as follows:
2016
Proved developed reserves
Proved undeveloped reserves
Total proved reserves
2015
Proved developed reserves
Proved undeveloped reserves
Total proved reserves
Oil
(MBbl)
NGLs
(MBbl)
Natural Gas
(MMcf)
Total
(MBOE)
183,165
211,602
394,767
298,444
298,233
596,677
51,888
49,605
101,493
55,437
57,510
112,947
337,860
377,799
715,659
300,631
365,029
665,660
291,363
324,174
615,537
403,986
416,581
820,567
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.
Total extensions and discoveries of 76.7 MMBOE in 2016 were primarily attributable to successful drilling in the Williston Basin and
DJ Basin. Both the new wells drilled in these areas as well as the PUD locations added as a result of drilling increased our proved
reserves.
Sales of minerals in place totaled 114.4 MMBOE during 2016 and were primarily attributable to the disposition of the North Ward
Estes Properties as further described in “Acquisitions and Divestitures” within Item 1 of this Annual Report on Form 10-K.
In 2016, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 119.8 MMBOE.
Included in these revisions were (i) 121.6 MMBOE of downward adjustments caused by lower crude oil, NGL and natural gas prices
incorporated into our reserve estimates at December 31, 2016 as compared to December 31, 2015 and (ii) 1.8 MMBOE of net upward
adjustments attributable to reservoir analysis and well performance.
Proved undeveloped reserves. Our PUD reserves decreased 22% or 92.4 MMBOE on a net basis from December 31, 2015 to
December 31, 2016. The following table provides a reconciliation of our PUDs for the year ended December 31, 2016:
Total
(MBOE)
PUD balance—December 31, 2015
Converted to proved developed through drilling (1)
Added from extensions and discoveries
Removed due to low commodity prices
Sold
Revisions
PUD balance—December 31, 2016
_____________________
(1) During 2016, we incurred $125 million in capital expenditures on approximately 105 wells which remained uncompleted as of
December 31, 2016, and as a result the PUD reserves associated with these wells were not converted to proved developed during
2016.
During 2016, we incurred $177 million in capital expenditures, or $12.46 per BOE, to drill and bring on-line 14.2 MMBOE of PUD
reserves. In addition, we added 66.8 MMBOE of PUDs from extensions and discoveries during the year primarily due to successful
drilling in the Williston Basin and DJ Basin. We have made an investment decision and adopted a development plan to drill all of our
individual PUD locations within five years of the date such PUDs were added.
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
33
416,581
(14,191)
66,755
(93,260)
(46,492)
(5,219)
324,174
technical information, financial data, ownership interests and production data. All field and reservoir technical information, which is
updated annually, is assessed for validity when the reservoir engineers hold technical meetings with geoscientists, operations and land
personnel to discuss field performance and to validate future development plans. Current revenue and expense information is obtained
from our accounting records, which are subject to our internal controls over financial reporting. Internal controls over financial reporting
are assessed for effectiveness annually using the criteria set forth in Internal Control – Integrated Framework (2013) issued by the
Committee of Sponsoring Organizations of the Treadway Commission. All current financial data such as commodity prices, lease
operating expenses, production taxes and field commodity price differentials are updated in the reserve database and then analyzed to
ensure that they have been entered accurately and that all updates are complete. Our current ownership in mineral interests and well
production data are also subject to the aforementioned internal controls over financial reporting, and they are incorporated into the reserve
database as well and verified to ensure their accuracy and completeness. Once the reserve database has been entirely updated with current
information, and all relevant technical support material has been assembled, our independent engineering firm Cawley, Gillespie &
Associates, Inc. (“CG&A”) meets with our technical personnel in our Denver office to review field performance and future development
plans. Following this review, 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. W. Todd Brooker, Senior Vice President. Mr.
Brooker 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. Brooker.
Our Vice President of Reservoir Engineering and Acquisitions is responsible for overseeing the preparation of the reserves estimates. He
has over 32 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 core area at December 31, 2016. Net acreage
represents our percentage ownership of gross acreage. Acreage in which our interest is limited to royalty and overriding royalty
interests has been excluded.
Northern Rocky Mountains
Central Rocky Mountains
Other (2)
Gross
Developed Acreage
Net
417,473
37,900
61,796
517,169
696,711
43,716
108,879
849,306
Undeveloped Acreage (1)
Gross
Net
39,257
113,462
209,681
362,400
26,366
94,284
127,013
247,663
Total Acreage
Gross
735,968
157,178
318,560
1,211,706
Net
443,839
132,184
188,809
764,832
_____________________
(1) Out of a total of approximately 362,400 gross (247,700 net) undeveloped acres as of December 31, 2016, the portion of our net
undeveloped acreage that is subject to expiration over the next three years, if not successfully developed or renewed, is
approximately 25% in 2017, 28% in 2018 and 8% in 2019.
(2) Other includes Arkansas, California, Colorado, Louisiana, Michigan, Mississippi, New Mexico, Oklahoma, Texas, Utah and
Wyoming.
34
Production History
The following table presents historical information about our produced oil and gas volumes:
Total Company production
Oil (MMBbl)
NGL (MMBbl)
Natural gas (Bcf)
Total (MMBOE)
Daily average (MBOE/d)
Sanish field production (1)
Oil (MMBbl)
NGL (MMBbl)
Natural gas (Bcf)
Total (MMBOE)
North Ward Estes field production (1)
Oil (MMBbl)
NGL (MMBbl)
Natural gas (Bcf)
Total (MMBOE)
Average sales prices (before the effects of hedging)
Oil (per Bbl)
NGLs (per Bbl)
Natural gas (per Mcf)
Average production costs
Production costs (per BOE) (2)
Year Ended December 31,
2015
2016
2014
34.0
6.6
41.4
47.5
129.9
7.2
1.0
7.8
9.5
1.6
0.2
0.1
1.8
47.2
5.5
41.1
59.6
163.2
9.4
1.2
7.3
11.8
3.0
0.4
0.2
3.4
33.5
3.3
30.2
41.8
114.5
9.9
1.1
5.9
12.0
3.1
0.4
0.3
3.6
$
$
$
$
34.36
8.88
1.40
8.25
$
$
$
$
40.95
12.67
2.20
$
$
$
81.50
39.17
5.53
9.02
$
11.24
_____________________
(1) The Sanish and North Ward Estes fields were our only fields that contained 15% or more of our total proved reserve volumes
during the periods presented. In July 2016, we sold our interest in the North Ward Estes field.
(2) Production costs reported above exclude from lease operating expenses ad valorem taxes of $3 million ($0.06 per BOE), $18
million ($0.30 per BOE) and $27 million ($0.65 per BOE) for the years ended December 31, 2016, 2015 and 2014, respectively.
Productive Wells
The following table summarizes gross and net productive oil and natural gas wells by core area at December 31, 2016. A net well
represents our percentage ownership of a gross well. Wells in which our interest is limited to royalty and overriding royalty interests
are excluded.
Northern Rocky Mountains
Central Rocky Mountains
Other (2)
Total
Oil Wells
Gross
Net
Natural Gas Wells
Net
Gross
Total Wells(1)
Gross
Net
2,804
280
1,492
4,576
1,250
200
424
1,874
-
-
111
111
-
-
43
43
2,804
280
1,603
4,687
1,250
200
467
1,917
_____________________
(1) 12 wells have multiple completions. These 12 wells contain a total of 30 completions. One or more completions in the same bore
hole are counted as one well.
(2) Other primarily includes non-core oil and gas properties located in Colorado, Mississippi, New Mexico, North Dakota, Texas and
Wyoming.
35
Oil and Gas Drilling Activity
We are engaged in numerous drilling activities on properties presently owned, and we intend to drill or develop other properties
acquired in the future. The following table sets forth our oil and gas drilling activity for the last three years. 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.
2016
Development
Exploratory
Total
2015
Development
Exploratory
Total
2014
Development
Exploratory
Total
Productive
Gross Wells
Dry
Total
Productive
Net Wells
Dry
Total
89
-
89
531
7
538
571
34
605
-
-
-
1
1
2
1
5 (1)
6
89
-
89
532
8
540
572
39
611
48.2
-
48.2
260.1
5.7
265.8
231.5
21.5
253.0
-
-
-
1.0
1.0
2.0
0.4
3.7
4.1
48.2
-
48.2
261.1
6.7
267.8
231.9
25.2
257.1
_____________________
(1) During 2014, we drilled six CO2 wells at our Bravo Dome field that were exploratory dry holes and that have not been included in
the drilling results above. We sold our interest in the Bravo Dome field in January 2016.
As of December 31, 2016, we had five operated drilling rigs active on our properties. The breakdown of our operated rigs by core
area is as follows:
Northern Rocky Mountains
Central Rocky Mountains
Total
Drilling Rigs
4
1
5
As of December 31, 2016, we had 221 gross (151.4 net) operated and non-operated wells in the process of drilling, completing or
waiting on completion.
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, Montana and North Dakota and we plan to continue
to utilize this completion methodology.
Our proved undeveloped reserve quantities that are associated with hydraulic fracture treatments consist of substantially all of our
proved undeveloped reserves, or 324.2 MMBOE.
On February 13, 2014, we had a well control incident during drilling operations involving one well in our Hidden Bench field in North
Dakota. The well was quickly brought under control with no liquids leaving the location, and there were no resulting injuries.
Appropriate regulatory agencies were notified of the incident. Other than this incident, we are not aware of any environmental
incidents, citations or suits that have occurred during the last three years related to hydraulic fracturing operations involving oil and
gas properties that we operate or in which we own a non-operated interest.
36
In order to minimize any potential environmental impact from hydraulic fracture treatments, we have taken the following steps:
we follow fracturing and flowback procedures that comply with or exceed North Dakota Industrial Commission or other state
requirements;
we train all company and contract personnel who are responsible for well preparation, fracture stimulation and flowback on our
procedures;
we have implemented the incremental procedures of running a well casing caliper, visually inspecting the surface joint of
intermediate casing and, if a lighter wall joint of casing or drilling wear is detected, reducing the minimum burst pressure
accordingly;
for wells that are within one mile of major bodies of water or locations that lead to bodies of water, we construct sufficient
berming around the well location prior to initiating fracturing operations;
we run fracturing strings in certain situations when extra precaution is warranted, such as where the anticipated maximum
treating pressure for the well is greater than the pressure rating of the intermediate casing or in areas located within one mile of
major bodies of water;
we conduct annual emergency incident response drills in all of our active areas; and
we are a member of the Sakakawea Area Spill Response LLC (“SASR”), which is composed of 13 oil and gas related
companies operating in the Missouri River and Lake Sakakawea regions of North Dakota. Members agreed to share spill
response resources and maintain SASR-owned water response equipment that can be accessed quickly in the early stages of a
spill.
While we do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing
operations, we do have general liability and excess liability insurance policies that we believe would cover third-party claims related
to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.
Delivery Commitments
Our production sales agreements contain customary terms and conditions for the oil and natural gas industry, generally provide for
sales based on prevailing market prices in the area, and generally have terms of one year or less.
We have entered into three physical delivery contracts which require us to deliver fixed volumes of crude oil. One of these contracts
is tied to oil production at our Sanish field in Mountrail County, North Dakota and requires delivery of 15 MBbl/d for a term of seven
years. The effective date of this contract is contingent upon the completion of the Dakota Access Pipeline, the timing of which is
currently unknown. Under the terms of this contract, if we fail to deliver the committed volumes we will be required to pay a
deficiency payment of $7.00 per undelivered Bbl, subject to upward adjustment, over the duration of the contract. However, we
believe that our production and reserves are sufficient to fulfill the delivery commitment at our Sanish field, and we therefore expect
to avoid any payments for deficiencies under this contract.
The remaining two contracts are tied to oil production at our Redtail field in Weld County, Colorado. The following table summarizes
our Redtail delivery commitments as of December 31, 2016:
Period
Jan - Dec 2017
Jan - Dec 2018
Jan - Dec 2019
Jan - Dec 2020
Redtail 1 Contracted
Crude Oil Volumes
(Bbl)
12,325,000
14,150,000
15,975,000
4,140,000
Redtail 2 Contracted
Crude Oil Volumes
(Bbl)
7,300,000
7,300,000
7,300,000
2,420,000
As a Percentage of
Total 2016
Oil Production
58%
63%
68%
19%
Under the terms of the first Redtail contract, if we fail to deliver the committed volumes we are required to pay a deficiency payment
that currently totals $4.91 per undelivered Bbl (subject to upward adjustment) over the duration of the contract. Under the terms of the
second Redtail contract, if we fail to deliver the committed volumes we are required to pay a deficiency payment equal to the terminal
and pipeline transportation fees paid by the counterparty on such undelivered barrels, currently $3.93 per undelivered Bbl (subject to
upward adjustment). We have determined that it is not probable that future oil production from our Redtail field will be sufficient to
meet the minimum volume requirements specified in the related physical delivery contracts, and as a result, we expect to make
periodic deficiency payments for any shortfalls in delivering the minimum committed volumes. We recognize any monthly deficiency
payments in the period in which the underdelivery takes place and the related liability has been incurred. During 2016 and 2015, total
deficiency payments under these contracts amounted to $43 million and $15 million, respectively.
37
Item 3. Legal Proceedings
We are subject to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business. While the
outcome of these lawsuits and claims cannot be predicted with certainty, it is management’s opinion that the loss for any litigation
matters and claims we are involved in that are reasonably possible to occur will not have a material adverse effect, individually or in
the aggregate, on our consolidated financial position, cash flows or results of operations.
After the closing of the Kodiak Acquisition, the EPA contacted us to discuss Kodiak’s responses to a June 2014 information request
from the EPA under Section 114(a) of the CAA. In addition, in July 2015 and March 2016, we received information requests from the
EPA under Section 114(a) of the CAA. The information requests relate to tank batteries used in our Williston Basin operations and
our compliance with certain regulatory requirements at those locations for the control of air pollutant emissions from those facilities.
We have responded to the EPA’s July 2015 and March 2016 information requests, and such responses were also provided to the North
Dakota Department of Health (the “NDDoH”), with whom the EPA was coordinating in making the requests. The EPA has sole
authority to enforce CAA violations on the Fort Berthold Indian Reservation in North Dakota, and, to date, no formal federal
enforcement action has been commenced in connection with this matter for our North Dakota tribal properties beyond receipt of the
noted information requests. We are unable to predict the ultimate outcome of possible federal enforcement with respect to our North
Dakota tribal properties, or other exclusively federal requirements at any of our North Dakota properties, at this time, which could
result in civil penalties or require us to undertake corrective actions, or both.
In connection with the above EPA inquiries, in October 2016, the NDDoH concurrently filed in the North Dakota District Court for
Burleigh County (the “Court”) a complaint against, and a settlement with, us regarding tank operation and other inspection-related
alleged violations of North Dakota’s air pollution control laws. In November 2016, the Court issued its order accepting this settlement
as its final judgment to resolve the issues raised in the complaint. This settlement addresses approximately 94 percent of our North
Dakota properties but does not address our North Dakota tribal property operations or exclusively federal requirements applicable to
all of our North Dakota properties, which are governed by the EPA. In the settlement, we and a significant number of North Dakota
operators have worked with the NDDoH to develop inspection and repair measures to detect and prevent emissions from facilities
even more effectively going forward. We believe these measures will be included in settlements between the NDDoH and each
participating operator. We and the NDDoH, pending Court approval of the settlement, have agreed that we will pay a civil penalty of
$1.2 million, of which $1.1 million may be reduced by up to 60 percent by early and continued implementation of the aforementioned
inspection and repair measures and a quality control policy. We anticipate being able to qualify for all available penalty reductions.
The settlement is not an admission by us of any violation.
Item 4. Mine Safety Disclosures
Not applicable.
38
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information, as of February 15, 2017, regarding the executive officers of Whiting Petroleum
Corporation:
Name
James J. Volker
Peter W. Hagist
Rick A. Ross
Michael J. Stevens
Mark R. Williams
Bruce R. DeBoer
Heather M. Duncan
Brent P. Jensen
Steven A. Kranker
David M. Seery
Age Position
70 Chairman, President and Chief Executive Officer
56 Senior Vice President, Planning
58 Senior Vice President, Operations
51 Senior Vice President and Chief Financial Officer
60 Senior Vice President, Exploration and Development
64 Vice President, General Counsel and Corporate Secretary
46 Vice President, Human Resources
47 Vice President, Finance and Treasurer
55 Vice President, Reservoir Engineering and Acquisitions
62 Vice President, Land
The following biographies describe the business experience of our executive officers:
James J. Volker joined us in August 1983 as Vice President of Corporate Development and served in that position through April 1993.
In March 1993, he became a contract consultant to us and served in that capacity until August 2000, at which time he became
Executive Vice President and Chief Operating Officer. Mr. Volker was appointed President and Chief Executive Officer and a
director in January 2002 and Chairman of the Board in January 2004. Effective January 1, 2011, Mr. Volker stepped down as
President, but continued as Chairman and Chief Executive Officer. Effective June 2014, he was again elected President and Chief
Executive Officer. Mr. Volker was co-founder, Vice President and later President of Energy Management Corporation from 1971
through 1982. He has 45 years of experience in the oil and gas industry. Mr. Volker has a Bachelor’s degree in finance from the
University of Denver, an MBA from the University of Colorado and has completed H. K. VanPoolen and Associates’ course of study
in reservoir engineering.
Peter W. Hagist joined us in October 2005 as Vice President, Operations-Midland. In June 2014, he was elected Senior Vice
President of Planning. Mr. Hagist has 35 years of experience in the oil and gas industry and 27 years of experience managing tertiary
recovery operations. Prior to joining Whiting, he held management and professional positions with Kinder Morgan CO2 Company
and Pennzoil Exploration and Production Company. Mr. Hagist holds a Bachelor of Science degree in petroleum engineering from
the Colorado School of Mines. He is a registered Professional Engineer and a member of the Society of Petroleum Engineers.
Rick A. Ross joined us in March 1999 as an Operations Manager. In May 2007, he became Vice President of Operations and in June
2014, he was elected Senior Vice President of Operations. Mr. Ross has 34 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.
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. Mr. Stevens was elected Senior Vice President and Chief Financial Officer effective March 1, 2015.
His 30 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.
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 36 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 37 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 20 years of human
39
resources experience in the oil and gas industry. She holds a Bachelor of Arts degree in anthropology and an MBA from the
University of Colorado. She is a certified Senior Professional in Human Resources.
Brent P. Jensen joined us in August 2005 as Controller, and he became Controller and Treasurer in January 2006. Mr. Jensen was
elected Vice President, Finance and Treasurer effective March 1, 2015. 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 23 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.
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 32 years of acquisition and reservoir
engineering experience, including Brunei Shell Petroleum, Arco Alaska Inc., Maxus Exploration, Conoco Inc. and Shell Western E&P
Inc. He received his Bachelor of Science degree in petroleum engineering from the Colorado School of Mines. Mr. Kranker is a
member of the Society of Petroleum Engineers.
David M. Seery joined us as our Manager of Land in July 2004 as a result of our acquisition of Equity Oil Company, where he was
Manager of Land and Manager of Equity’s Exploration Department, positions he had held for more than five years. He became our Vice
President of Land in January 2005. Mr. Seery has 36 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.
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.
40
PART II
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Whiting Petroleum Corporation’s common stock is traded on the New York Stock Exchange under the symbol “WLL”. The
following table shows the high and low sale prices for our common stock for the periods presented.
Fiscal Year Ended December 31, 2016
Fourth quarter (ended December 31, 2016)
Third quarter (ended September 30, 2016)
Second quarter (ended June 30, 2016)
First quarter (ended March 31, 2016)
Fiscal Year Ended December 31, 2015
Fourth quarter (ended December 31, 2015)
Third quarter (ended September 30, 2015)
Second quarter (ended June 30, 2015)
First quarter (ended March 31, 2015)
High
Low
13.39 $
9.93 $
14.44 $
9.79 $
22.80 $
33.79 $
39.15 $
41.57 $
7.72
6.38
7.25
3.35
8.12
13.50
30.95
26.14
$
$
$
$
$
$
$
$
On February 15, 2017, there were 793 holders of record of our common stock.
We have not paid any cash 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 cash dividends or distributions on our common stock.
Additionally, the indentures governing our senior notes contain restrictive covenants that may limit our ability to pay cash dividends
on our common stock.
Information relating to compensation plans under which our equity securities are authorized for issuance is set forth in Part III,
Item 12 of this Annual Report on Form 10-K.
The following information in this Item 5 of this Annual Report on Form 10-K is not deemed to be “soliciting material” or to be “filed”
with the SEC or subject to Regulation 14A or 14C under the Securities Exchange Act of 1934 or to the liabilities of Section 18 of the
Securities Exchange Act of 1934, and will not be deemed to be incorporated by reference into any filing under the Securities Act of
1933 or the Securities Exchange Act of 1934, except to the extent we specifically incorporate it by reference into such a filing.
The following graph compares on a cumulative basis changes since December 31, 2011 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.
Exploration & Production Index. Such changes have been measured by dividing (a) the sum of (i) the cumulative 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, 2011 in our common stock, the Standard & Poor’s Composite 500 Index and the Dow Jones U.S.
Exploration & Production Index, respectively.
41
Whiting Petroleum Corporation
Standard & Poor’s Composite 500 Index
Dow Jones U.S. Exploration & Production Index
$
12/31/2011 12/31/2012 12/31/2013 12/31/2014 12/31/2015 12/31/2016
26
133 $
178
147
110
136
71 $
164
120
100 $
100
100
93 $
113
105
20 $
163
90
42
Item 6. Selected Financial Data
The consolidated statements of operations and statements of cash flows information for the years ended December 31, 2016, 2015 and
2014 and the consolidated balance sheet information at December 31, 2016 and 2015 are derived from our audited financial statements
included elsewhere in this report. The consolidated statements of operations and statements of cash flows information for the years
ended December 31, 2013 and 2012 and the consolidated balance sheet information at December 31, 2014, 2013 and 2012 are derived
from audited financial statements that are not included in this report. Our historical results include the results from our recent proved
property acquisitions beginning on the following closing dates: properties related to the Kodiak Acquisition, December 8, 2014, and
properties in North Dakota and Montana, September 20, 2013. In addition, our historical results also include the effects of our recent
proved property divestitures beginning on the following closing dates: properties in the North Ward Estes field, July 27, 2016; water
facilities in Colorado, December 16, 2015; non-core properties in various fields across multiple states, December 15, 2015, November
12, 2015 and June 10, 2015; the underlying properties of Whiting USA Trust I, April 15, 2015; properties in the Postle field, July 15,
2013; and properties in Texas, October 31, 2013. For a discussion of other material factors affecting the comparability of the
information presented below, refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in
Item 7 of this Annual Report on Form 10-K.
Consolidated Statements of Operations Information
$
$
$
$
Operating revenues
Net income (loss) available to common shareholders
Earnings (loss) per common share, basic
Earnings (loss) per common share, diluted
Other Financial Information
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by (used in) financing activities
Cash capital expenditures
Consolidated Balance Sheet Information
Total assets
Long-term debt
Total equity (1)
$
$
$
$
$
$
$
2016
Year Ended December 31,
2014
2015
2013
2012
(in millions, except per share data)
1,285.0 $
(1,339.1) $
(5.32) $
(5.32) $
2,092.5 $
(2,219.2) $
(11.35) $
(11.35) $
3,024.6 $
64.8 $
0.53 $
0.53 $
2,664.6 $
365.5 $
3.09 $
3.06 $
595.0 $
(222.6) $
(315.3) $
543.9 $
1,051.4 $
(1,982.1) $
868.7 $
2,483.7 $
1,815.3 $
(2,860.5) $
423.9 $
2,888.4 $
1,744.7 $
(1,902.5) $
812.4 $
2,772.7 $
2,140.1
413.1
3.51
3.48
1,401.2
(1,780.3)
408.1
2,171.5
9,876.1 $
3,535.3 $
5,149.2 $
11,389.1 $
5,197.7 $
4,758.6 $
13,993.1 $
5,602.4 $
5,703.0 $
8,802.5 $
2,622.9 $
3,836.7 $
7,265.7
1,793.2
3,453.2
_____________________
(1) No cash dividends were declared or paid on our common stock during the periods presented.
43
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Unless the context otherwise requires, the terms “Whiting”, “we”, “us”, “our” or “ours” when used in this Item refer to Whiting
Petroleum Corporation, together with its consolidated subsidiaries, Whiting Oil and Gas Corporation (“Whiting Oil and Gas”),
Whiting US Holding Company, Whiting Canadian Holding Company ULC (formerly Kodiak Oil & Gas Corp., “Kodiak”), Whiting
Resources Corporation (formerly Kodiak Oil & Gas (USA) Inc.) and Whiting Programs, Inc. When the context requires, we refer to
these entities separately. This document contains forward-looking statements, which give our current expectations or forecasts of
future events. Please refer to “Forward-Looking Statements” at the end of this Item for an explanation of these types of statements.
Overview
We are an independent oil and gas company engaged in development, production, acquisition and exploration activities primarily in
the Rocky Mountains region of the United States. Our current operations and capital programs are focused on organic drilling
opportunities and on the development of previously acquired properties, specifically on projects that we believe provide the greatest
potential for repeatable success and production growth, while selectively pursuing acquisitions that complement our existing core
properties, such as the acquisition of Kodiak (the “Kodiak Acquisition”). As a result of lower crude oil prices during 2015 and 2016,
we significantly reduced our level of capital spending to more closely align with our cash flows generated from operations, and have
focused our drilling activity on projects that provide the highest rate of return. In addition, we continually evaluate our 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, such as the asset sales discussed below under
“Acquisition and Divestiture Highlights” and in the “Acquisitions and Divestitures” footnote in the notes to the consolidated financial
statements.
Our revenue, profitability and future growth rate depend on many factors which are beyond our control, such as oil and gas prices,
economic, political and regulatory developments, competition from other sources of energy, and the other items discussed under the
caption “Risk Factors” in Item 1A of this Annual Report on Form 10-K. Oil and gas prices historically have been volatile and may
fluctuate widely in the future. The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas
since the first quarter of 2015:
Crude oil
Natural gas
$
$
Q1
48.57 $
2.99 $
2015
Q2
57.96 $
2.61 $
Q3
46.44 $
2.74 $
Q4
42.17 $
2.17 $
Q1
33.51 $
2.06 $
Q2
45.60 $
1.98 $
Q3
44.94 $
2.93 $
Q4
49.33
2.98
2016
Oil prices have fallen significantly since reaching highs of over $105.00 per Bbl in June 2014, dropping below $27.00 per Bbl in
February 2016. Natural gas prices have also declined from over $4.80 per MMBtu in April 2014 to below $1.70 per MMBtu in March
2016. Although oil and natural gas prices have begun to recover from the lows experienced during the first quarter of 2016, forecasted
prices for both oil and gas remain low. Lower oil, NGL and natural gas prices may not only decrease our revenues on a per unit basis,
but may also reduce the amount of oil and natural gas that we can produce economically and therefore potentially lower our oil and
gas reserve quantities. Substantial and extended declines in oil, NGL and natural gas prices have resulted and may continue to result
in impairments of our proved oil and gas properties or undeveloped acreage (such as the impairments discussed below under “Results
of Operations”) and may materially and adversely affect our future business, financial condition, cash flows, results of operations,
liquidity or ability to finance planned capital expenditures. In addition, lower commodity prices have reduced, and may further
reduce, the amount of our borrowing base under our credit agreement (such as the reduction discussed below under “Financing
Highlights”), which is determined at the discretion of our lenders and is based on the collateral value of our proved reserves that have
been mortgaged to the lenders. Upon a redetermination, if borrowings in excess of the revised borrowing capacity were outstanding,
we could be forced to immediately repay a portion of the debt outstanding under our credit agreement. Alternatively, higher oil prices
may result in significant mark-to-market losses being incurred on our commodity-based derivatives.
For a discussion of material changes to our proved reserves from December 31, 2015 to December 31, 2016 and our ability to convert
PUDs to proved developed 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.
44
2016 Highlights and Future Considerations
Operational Highlights
Northern Rocky Mountains – Williston Basin
Our properties in the Williston Basin of North Dakota and Montana target the Bakken and Three Forks formations. Net production
from the Williston Basin averaged 108.9 MBOE/d for the fourth quarter of 2016, which represents a 3% increase from 105.6 MBOE/d
in the third quarter of 2016. In April and July 2016, we entered into two separate wellbore participation agreements related to the
wells that we drilled in the Williston Basin during 2016, which helped allow us to continue completion activity in this area. As of
December 31, 2016, we had four rigs active in the Williston Basin. Across our acreage in the Williston Basin, we have implemented
new completion designs which utilize cemented liners, plug-and-perf technology, significantly higher sand volumes, new diversion
technology and both hybrid and slickwater fracture stimulation methods, which has resulted in improved initial production rates.
In order to process the produced gas stream from our wells in the Sanish and Pronghorn fields, we constructed the Robinson Lake gas
plant and the Belfield gas plant, respectively. As of December 31, 2016, we held a 50% ownership interest in each of these gas
processing plants. On January 1, 2017, we closed on the sale of our interests in these two gas processing plants and the related
gathering systems and facilities. Refer to the “Subsequent Events” footnote in the notes to the consolidated financial statements for
further information.
Central Rocky Mountains – Denver Julesburg Basin
Our Redtail field in the Denver Julesburg Basin (“DJ Basin”) in Weld County, Colorado targets the Niobrara and Codell/Fort Hays
formations. In the fourth quarter of 2016, net production from the Redtail field averaged 9.2 MBOE/d, representing a 16% decrease
from 10.9 MBOE/d in the third quarter of 2016. We have established production in the Niobrara “A”, “B” and “C” zones and the
Codell/Fort Hays formations. Our development plan at Redtail currently includes drilling up to eight wells per spacing unit in the
Niobrara “A”, “B” and “C” zones and up to four wells per spacing unit in the Codell/Fort Hays formations. Additionally, the
Codell/Fort Hays formation is prospective throughout our acreage in the Redtail field, and we are currently evaluating that formation.
We have implemented a new wellbore configuration in this area, which significantly reduces drilling times. As of December 31,
2016, we had one drilling rig operating in the DJ Basin. We suspended completion operations in this area beginning in the second
quarter of 2016; however, we plan to resume completion activity in early 2017.
Our Redtail gas plant processes the associated gas produced from our wells in this area, and has a current inlet capacity of 50 MMcf/d.
As of December 31, 2016, the plant was processing over 16 MMcf/d.
Other
On July 27, 2016, we sold our interest in the North Ward Estes field located in Ward and Winkler counties in Texas as discussed
below under “Acquisition and Divestiture Highlights”.
Financing Highlights
On March 23, 2016, we completed the exchange of $477 million aggregate principal amount of our senior notes and senior
subordinated notes, consisting of (i) $49 million aggregate principal amount of our 6.5% Senior Subordinated Notes due 2018, (ii) $97
million aggregate principal amount of our 5.0% Senior Notes due 2019, (iii) $152 million aggregate principal amount of our 5.75%
Senior Notes due 2021, and (iv) $179 million aggregate principal amount of our 6.25% Senior Notes due 2023, for (i) $49 million
aggregate principal amount of new 6.5% Convertible Senior Subordinated Notes due 2018, (ii) $97 million aggregate principal
amount of new 5.0% Convertible Senior Notes due 2019, (iii) $152 million aggregate principal amount of new 5.75% Convertible
Senior Notes due 2021, and (iv) $179 million aggregate principal amount of new 6.25% Convertible Senior Notes due 2023 (together
the “New Convertible Notes”). During the second quarter of 2016, holders of the New Convertible Notes voluntarily converted all
$477 million aggregate principal amount of the New Convertible Notes for approximately 41.8 million shares of our common stock.
Upon conversion, we paid $46 million in cash consisting of early conversion payments to the holders of the notes, as well as all
accrued and unpaid interest on such notes.
On June 29, 2016 and July 1, 2016, we completed the exchange of $1.1 billion aggregate principal amount of our senior notes,
convertible senior notes and senior subordinated notes consisting of (i) $26 million aggregate principal amount of our 6.5% Senior
Subordinated Notes due 2018, (ii) $42 million aggregate principal amount of our 5.0% Senior Notes due 2019, (iii) $688 million
aggregate principal amount of our 1.25% Convertible Senior Notes due 2020, (iv) $174 million aggregate principal amount of our
5.75% Senior Notes due 2021, and (v) $163 million aggregate principal amount of our 6.25% Senior Notes due 2023, for (i) $26
million aggregate principal amount of new 6.5% Mandatory Convertible Senior Subordinated Notes due 2018, (ii) $42 million
aggregate principal amount of new 5.0% Mandatory Convertible Senior Notes due 2019, (iii) $688 million aggregate principal amount
45
of new 1.25% Mandatory Convertible Senior Notes due 2020, (iv) $174 million aggregate principal amount of new 5.75% Mandatory
Convertible Senior Notes due 2021, and (v) $163 million aggregate principal amount of new 6.25% Mandatory Convertible Senior
Notes due 2023 (together the “Mandatory Convertible Notes”). During the initial 25 trading day observation period from June 23,
2016 through July 28, 2016, $333 million aggregate principal amount of the Mandatory Convertible Notes were converted into
approximately 33.2 million shares of our common stock pursuant to the terms of the Mandatory Convertible Notes. Upon conversion,
we paid $3 million in cash consisting of all accrued and unpaid interest on such notes.
The July 1, 2016 note exchange transactions triggered an ownership shift as defined under Section 382 of the Internal Revenue Code
due to the “deemed share issuance” that resulted from the note exchanges. This triggering event will limit our usage of certain of our
net operating losses and tax credits in the future. Accordingly, we recorded a valuation allowance on tax credits totaling $8 million
and a valuation allowance on our net operating losses of $251 million during 2016, resulting in a total non-cash charge of $259
million.
On August 12, 2016, we completed the exchange of (i) $13 million aggregate principal amount of our 6.5% Mandatory Convertible
Senior Subordinated Notes due 2018 which had a conversion price of $8.75 per share (equivalent to 114.29 common shares per $1,000
principal amount of the notes) for shares of our common stock at an issuance price of $7.77 per share (equivalent to 128.69 common
shares per $1,000 principal amount of the notes) and (ii) $25 million aggregate principal amount of our 5.0% Mandatory Convertible
Senior Notes due 2019 which had a conversion price of $8.79 per share (equivalent to 113.72 common shares per $1,000 principal
amount of the notes) for shares of our common stock at an issuance price of $7.80 per share (equivalent to 128.17 shares per $1,000
principal amount of the notes). Upon acceptance of this inducement offer by the holders of the notes, such notes were immediately
cancelled in exchange for approximately 4.9 million shares of our common stock and we paid $1 million in cash consisting of all
accrued and unpaid interest on such notes.
On December 9, 2016, we provided notice to the holders of the remaining $721 million aggregate principal amount of the Mandatory
Convertible Notes of our intent to exercise our right to convert such notes on December 19, 2016 pursuant to their terms. The notes
were subsequently converted into approximately 77.6 million shares of our common stock, and upon conversion, we paid $5 million in
cash consisting of all accrued and unpaid interest on such notes.
In October 2016, the borrowing base under Whiting Oil and Gas’ credit agreement was reduced from $2.6 billion to $2.5 billion in
connection with the November 1, 2016 regular borrowing base redetermination. There were no changes to the $2.5 billion aggregate
commitments under the facility or to any other terms of the credit agreement.
On January 3, 2017, the trustee under the indenture governing our 6.5% Senior Subordinated Notes due 2018 (the “2018 Senior
Subordinated Notes”) provided notice to the holders of such notes that we elected to redeem all of the remaining $275 million
aggregate principal amount of our 2018 Senior Subordinated Notes on February 2, 2017, and on that date, we paid $281 million
consisting of the 100% redemption price plus all accrued and unpaid interest on the notes. We financed the redemption with
borrowings under our credit agreement.
Refer to the “Long-Term Debt” and “Subsequent Events” footnotes in the notes to consolidated financial statements for more
information on these financing transactions.
2017 Exploration and Development Budget
Our 2017 exploration and development (“E&D”) budget is $1.1 billion, which we expect to fund substantially with net cash provided
by our operating activities, proceeds from property divestitures, cash on hand, borrowings under our credit facility or by accessing the
capital markets. The overall budget represents an increase over the $554 million incurred on E&D expenditures during 2016. This
increased capital budget is in response to the higher crude oil prices experienced during the fourth quarter of 2016 and continuing into
2017. A portion of the 2017 budget will be used to resume completions at our Redtail field in early 2017, as this activity has been
suspended in this area since the second quarter of 2016. To the extent net cash provided by operating activities is higher or lower than
currently anticipated, we would adjust our E&D budget accordingly, enter into agreements with industry partners, divest certain oil
and gas property interests, adjust borrowings outstanding under our credit facility or access the capital markets as necessary. Our
2017 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.
46
Development Area
Northern Rocky Mountains
Central Rocky Mountains
Non-operated properties
Other (1)
Total
2017 Exploration and
Development Budget
(in millions)
580
420
60
40
1,100
$
$
_____________________
(1) Comprised of exploration salaries, seismic activities, lease delay rentals, facilities costs and undeveloped acreage purchases.
Acquisition and Divestiture Highlights
On July 27, 2016, we completed the sale of our interest in our enhanced oil recovery project in the North Ward Estes field in Ward
and Winkler counties of Texas, including our interest in certain CO2 properties in the McElmo Dome field in Colorado and certain
other related assets and liabilities (the “North Ward Estes Properties”) for a cash purchase price of $300 million (before closing
adjustments). The sale was effective July 1, 2016 and resulted in a pre-tax loss on sale of $187 million. In addition to the cash
purchase price, the buyer has agreed to pay us $100,000 for every $0.01 that, as of June 28, 2018, the average NYMEX crude oil
futures contract price for each month from August 2018 through July 2021 is above $50.00/Bbl up to a maximum amount of $100
million (the “Contingent Payment”). The Contingent Payment will be made at the option of the buyer either in cash on July 31, 2018
or in the form of a secured promissory note, accruing interest at 8% per annum with a maturity date of July 29, 2022. We used the net
proceeds from the sale to repay a portion of the debt outstanding under our credit agreement. The North Ward Estes Properties
consisted of estimated proved reserves of 120.3 MMBOE as of December 31, 2015, representing 15% of our proved reserves as of that
date, and generated 6% (or 8.6 MBOE/d) of our June 2016 average daily net production.
On January 1, 2017, we completed the sale of our 50% interest in the Robinson Lake gas processing plant located in Mountrail
County, North Dakota and our 50% interest in the Belfield gas processing plant located in Stark County, North Dakota, as well as the
associated natural gas, crude oil and water gathering systems, effective January 1, 2017, for aggregate sales proceeds of $375 million
(before closing adjustments). We used the net proceeds from this transaction to repay a portion of the debt outstanding under our
credit agreement.
47
Results of Operations
The following table sets forth selected operating data for the periods indicated:
Net production
Oil (MMBbl)
NGLs (MMBbl)
Natural gas (Bcf)
Total production (MMBOE)
Net sales (in millions)
Oil (1)
NGLs
Natural gas
Total oil, NGL and natural gas sales
Average sales prices
Oil (per Bbl) (1)
Effect of oil hedges on average price (per Bbl)
Oil net of hedging (per Bbl)
Weighted average NYMEX price (per Bbl) (2)
NGLs (per Bbl)
Natural gas (per Mcf)
Weighted average NYMEX price (per MMBtu) (2)
Costs and expenses (per BOE)
Lease operating expenses
Production taxes
Depreciation, depletion and amortization
General and administrative
_____________________
(1) Before consideration of hedging transactions.
Year Ended
December 31,
2015
2016
2014
34.0
6.6
41.4
47.5
1,167.8 $
59.0
58.2
1,285.0 $
34.36 $
4.46
38.82 $
42.71 $
47.2
5.5
41.1
59.6
1,931.9 $
70.2
90.4
2,092.5 $
40.95 $
4.59
45.54 $
49.06 $
33.5
3.3
30.2
41.8
2,729.0
128.6
167.0
3,024.6
81.50
1.29
82.79
91.55
8.88 $
12.67 $
39.17
1.40 $
2.47 $
2.20 $
2.62 $
5.53
4.40
8.31 $
2.29 $
24.64 $
3.09 $
9.32 $
3.07 $
20.87 $
2.90 $
11.89
6.05
26.06
4.24
$
$
$
$
$
$
$
$
$
$
$
$
(2) Average NYMEX pricing weighted for monthly production volumes.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Oil, NGL and Natural Gas Sales. Our oil, NGL and natural gas sales revenue decreased $808 million to $1.3 billion when comparing
2016 to 2015. Sales revenue is a function of oil, NGL and gas volumes sold and average commodity prices realized. Our oil sales
volumes decreased 28%, while our NGL and natural gas sales volumes increased 20% and 1%, respectively, between periods. The oil
volume decrease between periods was primarily attributable to normal field production decline across several of our areas resulting
from reduced drilling and completion activity during 2015 and 2016 in response to the depressed commodity price environment. In
addition, we completed several non-core oil and gas property divestitures during 2015 and 2016, which negatively impacted oil
production in 2016 by 2,615 MBbl. These decreases were partially offset by new wells drilled and completed in the Williston Basin
and DJ Basin which added 4,990 MBbl and 605 MBbl, respectively, of oil production during 2016 as compared to 2015. Our NGL
sales volume increases between periods generally relate to additional volumes processed as more wells were connected to gas
processing plants in the Williston Basin, as well as new wells drilled and completed in the Williston Basin and DJ Basin over the last
twelve months. Many of the new Williston Basin wells are in areas with higher gas-to-oil production ratios than previously drilled
areas. These NGL volume increases were partially offset by normal field production decline across several of our areas. The gas
volume increase between periods was primarily due to drilling success at our Williston Basin and DJ Basin properties which resulted
in 9,570 MMcf and 1,125 MMcf, respectively, of additional gas volumes during 2016 as compared to 2015. In addition, gas volumes
increased between periods as more wells were connected to gas processing plants in the Williston Basin over the last twelve months in
an effort to increase our overall gas capture rate in this area and reduce flared volumes. These gas volume increases were largely
offset by the 2015 and 2016 property divestitures, which negatively impacted gas production in 2016 by 5,740 MMcf, as well as
normal field production decline across several of our areas.
48
In addition to production-related decreases in net revenue there were also significant decreases in the average sales price realized for
oil, NGLs and natural gas in 2016 compared to 2015. Our average price for oil before the effects of hedging decreased 16%, our
average price for NGLs decreased 30% and our average price for natural gas decreased 36% between periods.
Lease Operating Expenses. Our lease operating expenses (“LOE”) during 2016 were $395 million, a $160 million decrease over
2015. This decrease was primarily due to (i) $84 million of lower LOE attributable to properties that we divested during 2015 and
2016, (ii) a $51 million decline in the costs of oilfield goods and services resulting from cost reduction measures we have
implemented as well as the general downturn in the oil and gas industry, and (iii) a reduction in well workover activity between
periods. Workovers decreased from $52 million in 2015 to $27 million in 2016, primarily due to a reduction in well workover activity
at our EOR project at North Ward Estes, which we sold in July 2016.
Our lease operating expenses on a BOE basis also decreased when comparing 2016 to 2015. LOE per BOE amounted to $8.31 during
2016, which represents a decrease of $1.01 per BOE (or 11%) from 2015. This decrease was mainly due to the impact of property
divestitures, the declining costs of goods and services in the industry and lower well workover costs, as discussed above, partially
offset by lower overall production volumes between periods. The properties sold during 2015 and 2016 consisted mainly of mature
oil and gas producing properties with LOE per BOE rates that were higher than our overall blended corporate rate.
Production Taxes. Our production taxes during 2016 were $109 million, a $74 million decrease over the same period in 2015, which
decrease was primarily due to lower 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 8.7% for 2016 and 2015, respectively. This decrease primarily relates to a reduction in the severance tax rate in North Dakota
from 11.5% in 2015 to 10% in 2016.
Depreciation, Depletion and Amortization. Our depreciation, depletion and amortization (“DD&A”) expense decreased $72 million in
2016 as compared to 2015. The components of our DD&A expense were as follows (in thousands):
Depletion
Depreciation
Accretion of asset retirement obligations
Total
Year Ended
December 31,
$
$
2016
1,149,302 $
8,479
13,801
1,171,582 $
2015
1,213,355
9,664
20,274
1,243,293
DD&A decreased between periods primarily due to $64 million in lower depletion expense. This decrease was mainly attributable to
a $291 million decrease due to lower overall production volumes during 2016, which was partially offset by a $227 million increase in
expense related to a higher depletion rate between periods. On a BOE basis, our overall DD&A rate of $24.64 for 2016 was 18%
higher than the rate of $20.87 in 2015. The primary factors contributing to this higher DD&A rate were (i) decreases to proved and
proved developed reserves over the last twelve months primarily attributable to lower average oil and natural gas prices used to
calculate our reserves, (ii) $539 million in drilling and development expenditures during the past twelve months, and (iii) property
divestitures. These factors that negatively impacted our DD&A rate were partially offset by impairment write-downs on proved oil
and gas properties recognized in the third quarter of 2015.
Exploration and Impairment Costs. Our exploration and impairment costs decreased $1.8 billion in 2016 as compared to 2015. The
components of our exploration and impairment expense were as follows (in thousands):
Exploration
Impairment
Total
Year Ended
December 31,
$
$
2016
45,846 $
75,622
121,468 $
2015
143,363
1,738,308
1,881,671
Exploration costs decreased $98 million during 2016 as compared to 2015 primarily due to lower rig termination fees incurred
between periods, lower exploratory dry hole costs and a decrease in geology-related general and administrative expenses. Rig
termination fees amounted to $18 million during 2016 as compared to $95 million in 2015. During 2015, we drilled one exploratory
dry hole in Michigan totaling $9 million, whereas in 2016 we drilled no exploratory dry holes. Geology-related general and
administrative expenses decreased $6 million between periods.
49
Impairment expense in 2016 primarily related to $60 million of leasehold amortization associated with individually insignificant
unproved properties and $13 million in impairment write-downs of undeveloped acreage costs for leases where we have no future
plans to drill. Impairment expense in 2015 primarily related to (i) $1.5 billion in non-cash impairment charges for the partial write-
down of our North Ward Estes field in Texas and other non-core proved oil and gas properties primarily in Texas, Wyoming, North
Dakota and Colorado that were not being developed due to depressed oil and gas prices, (ii) $86 million of leasehold amortization
associated with individually insignificant unproved properties, (iii) $62 million of impairment write-downs on our CO2 development
properties whose net book values exceeded their undiscounted future net cash flows, and (iv) $49 million in impairment write-downs
of undeveloped acreage costs for leases where we had no future plans to drill.
Goodwill Impairment. As a result of a sustained decrease in the price of our common stock during the third quarter of 2015 caused by
a significant decline in crude oil and natural gas prices over that same period, we performed a goodwill impairment test as of
September 30, 2015. The impairment test indicated that the fair value of our reporting unit was less than its carrying amount, and
further that there was no remaining implied fair value attributable to goodwill. Based on these results, we recorded a non-cash
impairment charge of $874 million in 2015 to reduce the carrying value of goodwill to zero.
General and Administrative Expenses. We report general and administrative (“G&A”) expenses net of third-party reimbursements
and internal allocations. The components of our G&A expenses were as follows (in thousands):
General and administrative expenses
Reimbursements and allocations
General and administrative expenses, net
Year Ended
December 31,
$
$
2016
2015
264,948 $
(118,070)
146,878 $
309,987
(137,371)
172,616
G&A expense before reimbursements and allocations decreased $45 million during 2016 as compared to 2015 primarily due to lower
employee compensation, savings realized as a result of cost reduction measures we have implemented and the impact of property
divestitures. Employee compensation decreased $28 million in 2016 as compared to 2015 primarily due to reductions in personnel
over the past twelve months. The decrease in reimbursements and allocations for 2016 was the result of a lower number of field
workers on Whiting-operated properties associated with reduced drilling activity and property divestitures over the past twelve
months.
Our general and administrative expenses on a BOE basis, however, increased when comparing 2016 to 2015. G&A expense per BOE
amounted to $3.09 during 2016, which represents an increase of $0.19 per BOE (or 7%) from 2015. This increase was mainly due to
lower overall production volumes between periods, partially offset by lower employee compensation and savings realized as a result
of our cost reduction measures.
Derivative Gain, Net. Our commodity derivative contracts and embedded derivatives are marked to market each quarter with fair
value gains and losses recognized immediately in earnings as 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 to or from the counterparty. Derivative gain, net
amounted to a gain of $1 million for 2016, which consisted of a $59 million fair value gain on embedded derivatives, partially offset
by a $58 million loss on commodity derivative contracts resulting from the upward shift in the futures curve of forecasted commodity
prices (“forward price curve”) for crude oil from January 1, 2016 (or the 2016 date on which new contracts were entered into) to
December 31, 2016. Derivative gain, net for 2015 consisted of a $218 million gain on commodity derivative contracts primarily due
to the more significant downward shift in the same forward price curve from January 1, 2015 (or the 2015 date on which prior year
contracts were entered into) to December 31, 2015.
See Item 7A, “Quantitative and Qualitative Disclosures about Market Risk”, for a list of our outstanding commodity derivative
contracts as of January 3, 2017.
(Gain) Loss on Sale of Properties. During 2016, we sold our interest in the North Ward Estes Properties for net cash proceeds of $295
million, which resulted in a pre-tax loss on sale of $187 million. There were no other property divestitures resulting in a significant
gain or loss on sale during 2016. During 2015, we sold our interests in certain non-core producing oil and gas wells and undeveloped
acreage across many of our operating areas, as well as a water system in Colorado for aggregate net proceeds of $515 million, which
resulted in a pre-tax loss on sale of $61 million.
50
Interest Expense. The components of our interest expense were as follows (in thousands):
Notes
Amortization of debt issue costs, discounts and premiums
Credit agreement
Other
Capitalized interest
Total
Year Ended
December 31,
2016
2015
$
$
187,374 $
335,569
32,885
1,930
(138)
557,620 $
265,358
46,525
26,071
453
(4,282)
334,125
The increase in interest expense of $223 million between periods was mainly attributable to an increase in amortization of debt issue
costs, discounts and premiums, partially offset by lower interest costs incurred on our notes during 2016 as compared to 2015. The
increase in amortization of debt issue costs, discounts and premiums of $289 million was primarily due to (i) a non-cash charge of
$244 million for the acceleration of unamortized debt discounts in connection with the December 2016 conversions of our Mandatory
Convertible Notes, (ii) $22 million of amortization of debt discounts on the Mandatory Convertible Notes we issued in June and July
2016 prior to their conversions, (iii) a non-cash charge of $14 million for the acceleration of unamortized debt discounts in connection
with the August 2016 induced exchange of a portion of our Mandatory Convertible Notes, and (iv) a non-cash charge of $6 million for
the acceleration of unamortized debt issuance costs in connection with a reduction of the aggregate commitments under our credit
agreement in March 2016. The $78 million decrease in note interest was primarily due to (i) $71 million incurred during 2015 on the
$1.6 billion of notes we assumed as part of the Kodiak Acquisition (the “Kodiak Notes”), all of which were subsequently repurchased
in 2015, and (ii) a $22 million decrease in note interest as a result of the conversions of the New Convertible Notes in May 2016 and
the Mandatory Convertible Notes in July, August and December 2016. This decrease in note interest expense was partially offset by
our March 2015 issuance of $1,250 million of 2020 Convertible Senior Notes and $750 million of 2023 Senior Notes, which resulted
in a $15 million increase in interest expense between periods.
Our weighted average debt outstanding during 2016 was $5.0 billion versus $5.7 billion for 2015. Our weighted average effective
cash interest rate was 4.4% during 2016 compared to 5.2% during 2015.
Loss on Extinguishment of Debt. During 2016, we recognized a net loss on extinguishment of debt of $42 million. In March 2016, we
completed the exchange of $477 million aggregate principal amount of our senior notes and senior subordinated notes for the same
aggregate principal amount of New Convertible Notes, and recognized a $91 million gain on extinguishment of debt. During the
second quarter of 2016, the holders of the New Convertible Notes voluntarily converted all $477 million aggregate principal amount
of the New Convertible Notes for approximately 41.8 million shares of our common stock, and we recognized a $188 million loss on
extinguishment of debt upon conversion. In June and July 2016, we completed the exchange of $1.1 billion aggregate principal
amount of our senior notes, convertible senior notes and senior subordinated notes for the same aggregate principal amount of
Mandatory Convertible Notes, and recognized a $57 million gain on extinguishment of debt. Subsequently in July, $333 million
aggregate principal amount of the Mandatory Convertible Notes were converted into approximately 33.2 million shares of our
common stock, and we recognized a $3 million gain on extinguishment of debt upon conversion. In August 2016, we induced the
exchange of an additional $38 million aggregate principal amount of the Mandatory Convertible Notes for approximately 4.9 million
shares of our common stock, and we recognized a $4 million debt inducement expense. During 2015, we repurchased all $1.6 billion
aggregate principal amount of the Kodiak Notes then outstanding, and recognized an $18 million loss on extinguishment of debt.
Refer to the “Long-Term Debt” footnote in the notes to consolidated financial statements for more information on these debt
transactions.
Income Tax Expense (Benefit). Income tax benefit for 2016 totaled $88 million as compared to a benefit of $774 million for 2015, a
decrease of $686 million that was mainly related to (i) $1.6 billion in lower pre-tax loss between periods, (ii) a $259 million non-cash
charge in 2016 resulting from an ownership shift as defined under Section 382 of the Internal Revenue Code which will limit our
usage of certain net operating losses and tax credits in the future, as discussed above under “Financing Highlights”, and (iii) the tax
impact of $174 million of permanent tax differences associated with the issuance and subsequent conversion of the New Convertible
Notes and the Mandatory Convertible Notes during 2016.
Our effective tax rates for 2016 and 2015 differ from the U.S. statutory income tax rate primarily due to the effects of state income
taxes and permanent taxable differences. Excluding the impact of the Section 382 limitation discussed above, our overall effective tax
rate decreased from 25.9% in 2015 to 24.3% for 2016. This decrease is mainly the result of $174 million of permanent tax differences
associated with the issuance and subsequent conversions of the New Convertible Notes and the Mandatory Convertible Notes during
2016, which differences increased our 2016 effective tax rate to a lesser extent than the increase in our 2015 effective tax rate resulting
from $874 million in goodwill impairment expense which was not tax deductible.
51
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Oil, NGL and Natural Gas Sales. Our oil, NGL and natural gas sales revenue decreased $932 million to $2.1 billion when comparing
2015 to 2014. Sales revenue is a function of oil, NGL and gas volumes sold and average commodity prices realized. Our oil sales
volumes increased 41%, our NGL sales volumes increased 69% and our natural gas sales volumes increased 36% between periods.
The oil volume increase between periods resulted primarily from producing properties acquired in the Kodiak Acquisition, as well as
drilling success across our two core development areas. The Kodiak Acquisition, which closed on December 8, 2014, added 10,540
MBbl of oil production during 2015 across several of our areas in the Northern Rocky Mountains. In addition, oil production from our
Williston Basin and DJ Basin properties increased 4,420 MBbl and 1,950 MBbl, respectively, from 2014 to 2015 as a result of new
wells drilled and completed in those areas. These production increases were partially offset by normal field production decline across
several of our areas, as well as decreases in production volumes resulting from non-core oil and gas property divestitures during 2015,
which negatively impacted oil production by 790 MBbl during 2015. Our NGL sales volume increases generally related to NGL
production added from properties acquired in the Kodiak Acquisition, as well as new wells drilled and completed in the Williston and
DJ Basin. Similar to the trends noted for crude oil and NGL production, the gas volume increase between periods was also primarily
the result of producing properties acquired in the Kodiak Acquisition, as well as drilling success across our two core development
areas. The Kodiak Acquisition added 8,165 MMcf of gas production during 2015. In addition, gas production increased 6,265 MMcf
at our Williston Basin properties and 3,050 MMcf at our DJ Basin properties from 2014 to 2015 as a result of new wells drilled and
completed in those areas. These gas volume increases were partially offset by decreases in production volumes resulting from the
2015 property divestitures, which negatively impacted gas production by 5,880 MMcf during 2015, as well as normal field production
decline across several of our areas.
These crude oil, NGL and natural gas production-related increases in net revenue were offset by significant decreases in the average
sales price realized for oil, NGLs and natural gas in 2015 compared to 2014. Our average price for oil before the effects of hedging
decreased 50%, our average sales price for NGLs decreased 68% and our average sales price for natural gas decreased 60% between
periods.
Lease Operating Expenses. Our lease operating expenses during 2015 were $555 million, a $58 million increase over 2014. Higher
LOE in 2015 were primarily related to a $63 million increase in oil field goods and services associated with net wells we added during
2015 as a result of the Kodiak Acquisition and through drilling, partially offset by the impact of our property divestitures in 2015 and
a decrease in well workover activity between periods. Workovers decreased from $57 million in 2014 to $52 million in 2015,
primarily due to a reduction in well workover activity at our EOR project at North Ward Estes, which we sold in July 2016.
Our lease operating expenses on a BOE basis, however, decreased when comparing 2015 to 2014. LOE per BOE amounted to $9.32
during 2015, which represents a decrease of $2.57 per BOE (or 22%) from 2014. This decrease was mainly due to declining costs of
goods and services in the industry combined with higher overall production volumes between periods, lower well workover costs and
the impact of property divestitures discussed above. The properties sold during 2015 consisted mainly of mature oil and gas
producing properties with LOE per BOE rates that were higher than our overall blended corporate rate.
Production Taxes. Our production taxes during 2015 were $183 million, a $70 million decrease over the same period in 2014, which
decrease was primarily due to lower 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 8.7%
and 8.4% for 2015 and 2014, respectively.
Depreciation, Depletion and Amortization. Our depreciation, depletion and amortization expense increased $154 million in 2015 as
compared to 2014. The components of our DD&A expense were as follows (in thousands):
Depletion
Depreciation
Accretion of asset retirement obligations
Total
Year Ended
December 31,
$
$
2015
1,213,355 $
9,664
20,274
1,243,293 $
2014
1,070,503
5,494
13,548
1,089,545
DD&A increased between periods primarily due to $143 million in higher depletion expense. This increase was mainly attributable to
a $362 million increase due to higher overall production volumes during 2015, which was partially offset by a $219 million decrease
in expense related to a lower depletion rate between periods. On a BOE basis, our overall DD&A rate of $20.87 for 2015 was 20%
lower than the rate of $26.06 for the same period in 2014. The primary factors contributing to this lower DD&A rate were additions to
proved and proved developed reserves over the twelve months ended December 31, 2015, including reserves that were added as a
result of the Kodiak Acquisition, as well as impairment write-downs on proved oil and gas properties recognized in the fourth quarter
52
of 2014 and the third quarter of 2015. These factors that positively impacted our DD&A rate were partially offset by $2.5 billion in
drilling and development expenditures during the twelve months ended December 31, 2015.
Exploration and Impairment Costs. Our exploration and impairment costs increased $1.0 billion in 2015 as compared to 2014. The
components of our exploration and impairment costs were as follows (in thousands):
Exploration
Impairment
Total
Year Ended
December 31,
2015
2014
$
$
143,363 $
1,738,308
1,881,671 $
86,803
767,627
854,430
Exploration costs increased $57 million during 2015 as compared to 2014 primarily due to rig termination fees incurred in 2015
totaling $95 million, which were partially offset by lower exploratory dry hole costs and a decrease in geological and geophysical
(“G&G”) activity between periods. During 2015, we drilled one exploratory dry hole in Michigan totaling $9 million. Exploratory
dry hole costs for 2014, on the other hand, totaled $26 million due to five exploratory dry holes we drilled on our oil and gas
properties, including three in Michigan and two in the Northern Rocky Mountains, as well as six exploratory dry holes at our CO2
development project in New Mexico. G&G costs, such as seismic studies, amounted to $8 million during 2015 as compared to $23
million during 2014.
Impairment expense in 2015 was primarily related to (i) $1.5 billion in non-cash impairment charges for the partial write-down of our
North Ward Estes field in Texas and other non-core proved oil and gas properties primarily in Texas, Wyoming, North Dakota and
Colorado that were not being developed due to depressed oil and gas prices, (ii) $86 million of leasehold amortization associated with
individually insignificant unproved properties, (iii) $62 million of impairment write-downs on our CO2 development properties whose
net book values exceeded their undiscounted future net cash flows, and (iv) $49 million in impairment write-downs of undeveloped
acreage costs for leases where we had no future plans to drill. Impairment expense in 2014 primarily related to (i) $587 million in
non-cash impairment charges for the partial write-down of non-core proved oil and gas properties primarily in Colorado, Louisiana,
North Dakota and Utah which were not being developed due to depressed oil and gas prices at December 31, 2014, (ii) $70 million of
leasehold amortization associated with individually insignificant unproved properties, (iii) $66 million in impairment write-downs of
undeveloped acreage costs for leases where we had no future plans to drill, and (iv) $42 million of impairment write-downs on our
CO2 development properties.
Goodwill Impairment. As a result of a sustained decrease in the price of our common stock during the third quarter of 2015 caused by
a significant decline in crude oil and natural gas prices over that same period, we performed a goodwill impairment test as of
September 30, 2015. The impairment test indicated that the fair value of our reporting unit was less than its carrying amount, and
further that there was no remaining implied fair value attributable to goodwill. Based on these results, we recorded a non-cash
impairment charge of $874 million in 2015 to reduce the carrying value of goodwill to zero.
General and Administrative Expenses. We report general and administrative expenses net of third-party reimbursements and internal
allocations. The components of our G&A expenses were as follows (in thousands):
General and administrative expenses
Reimbursements and allocations
General and administrative expenses, net
Year Ended
December 31,
$
$
2015
2014
309,987 $
(137,371)
172,616 $
300,814
(123,603)
177,211
G&A expense before reimbursements and allocations increased $9 million during 2015 as compared to 2014 primarily due to higher
employee compensation, as well as general increases in G&A expense between periods as a result of the Kodiak Acquisition. These
increases were partially offset by lower transaction-related costs incurred on the Kodiak Acquisition. Employee compensation
increased $49 million in 2015 as compared to 2014 primarily due to personnel added as a result of the Kodiak Acquisition, as well as
general pay increases. Transaction costs incurred for the Kodiak Acquisition totaled $53 million during 2014. The increase in
reimbursements and allocations for 2015 was the result of higher salary costs and a greater number of field workers on Whiting-
operated properties, primarily related to the Kodiak Acquisition.
Our general and administrative expenses on a BOE basis, however, decreased when comparing 2015 to 2014. G&A expense per BOE
amounted to $2.90 during 2015, which represents a decrease of $1.34 per BOE (or 32%) from 2014. This decrease was mainly due to
higher overall production volumes between periods, as well as savings realized as a result of cost reduction measures.
53
Derivative Gain, Net. Our commodity derivative contracts and embedded derivatives are marked to market each quarter with fair
value gains and losses recognized immediately in earnings as 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 to or from the counterparty. Derivative gain, net
amounted to a gain of $218 million for 2015 mainly due to the significant downward shift in the forward price curve for crude oil from
January 1, 2015 (or the 2015 date on which new contracts were entered into) to December 31, 2015. Derivative gain, net for 2014
resulted in a gain of $101 million mainly due to the recognition of a $54 million asset related to two crude oil sales and delivery
contracts that failed the “normal purchase normal sale” exclusion during the fourth quarter of 2014, as well as the less significant
downward shift in the same forward price curve from January 1, 2014 (or the 2014 date on which prior year contracts were entered
into) to December 31, 2014.
(Gain) Loss on Sale of Properties. During 2015, we sold our interests in certain non-core producing oil and gas wells and
undeveloped acreage across many of our operating areas, as well as a water system in Colorado for aggregate net proceeds of $515
million, which resulted in a pre-tax loss on sale of $61 million. During 2014, we sold undeveloped acreage as well as our interests in
certain producing oil and gas wells in the Big Tex prospect for net proceeds of $76 million in cash, which resulted in a pre-tax gain on
sale of $12 million. Also during 2014, we sold certain non-core producing oil and gas properties in the Rocky Mountains region for
aggregate sales proceeds of $33 million, resulting in a pre-tax gain on sale of $17 million. There were no other property divestitures
resulting in a significant gain or loss on sale during 2014.
Amortization of Deferred Gain on Sale. Amortization of deferred gain on sale during 2015 was $17 million, a $14 million decrease
over the same period in 2014. This decrease was primarily the result of the deferred gain on sale related to Trust I becoming fully
amortized in January 2015 in connection with the termination of the Trust I net profits interest.
Interest Expense. The components of our interest expense were as follows (in thousands):
Notes
Credit agreement
Amortization of debt issue costs, discounts and premiums
Other
Capitalized interest
Total
Year Ended
December 31,
2015
2014
$
$
265,358 $
26,071
46,525
453
(4,282)
334,125 $
153,260
9,419
11,984
63
(4,084)
170,642
The increase in interest expense of $163 million between periods was mainly attributable to higher interest costs incurred on our notes
during 2015, an increase in amortization of debt issue costs, discounts and premiums, and an increase in the amount of interest
incurred on our credit agreement during 2015 as compared to 2014. The increase in note interest of $112 million was due to interest
costs incurred on the $1.6 billion of Kodiak Notes we assumed as part of the Kodiak Acquisition, as well as our March 2015 issuance
of $1,250 million of 2020 Convertible Senior Notes. The increase in amortization of debt issue costs, discounts and premiums of $35
million was primarily due to amortization of the discount on our 2020 Convertible Senior Notes. Our credit agreement interest was
$17 million higher in 2015 due to a greater amount of average borrowings outstanding under this facility. During 2015, all of the $1.6
billion Kodiak Notes were repurchased using proceeds from our debt and equity issuances, as well as borrowings under our credit
agreement.
Our weighted average debt outstanding during 2015 was $5.7 billion versus $2.9 billion for 2014. Our weighted average effective
cash interest rate was 5.2% during 2015 compared to 5.5% during 2014.
Loss on Extinguishment of Debt. During 2015, we repurchased all $1.6 billion aggregate principal amount of the Kodiak Notes. As a
result of the repurchases, we recognized an $18 million loss on extinguishment of debt. Refer to the “Long-Term Debt” footnote in
the notes to consolidated financial statements for more information on this debt transaction.
Income Tax Expense (Benefit). Income tax benefit for 2015 totaled $774 million as compared to $79 million of income tax expense
for 2014, a decrease of $853 million that was mainly related to $3.1 billion in lower pre-tax income between periods.
Our effective tax rates for 2015 and 2014 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 55.0% in 2014 to 25.9% for 2015. This
decrease was mainly the result of $874 million in goodwill impairment recognized during 2015, which was not tax deductible, the
impact of pre-tax earnings shifting from net income in 2014 to a net loss in 2015, and merger costs that were incurred in 2014 related
to the Kodiak Acquisition, which were not tax deductible.
54
Liquidity and Capital Resources
Overview. At December 31, 2016, we had $56 million of cash on hand and $5.1 billion of equity, while at December 31, 2015, we
had $16 million of cash on hand and $4.8 billion of equity.
One of the primary sources of variability in our cash flows from operating activities is commodity price volatility, which we partially
mitigate through the use of commodity hedge contracts. Oil accounted for 72% and 79% of our total production in 2016 and 2015,
respectively. As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in NGL
or natural gas prices. As of January 3, 2017, we had derivative contracts covering the sale of approximately 49% of our forecasted
2017 oil production volumes. For a list of all of our outstanding derivatives as of January 3, 2017, refer to Item 7A, “Quantitative and
Qualitative Disclosures about Market Risk”.
Cash Flows from 2016 Compared to 2015. During 2016, we generated $595 million of cash provided by operating activities, a
decrease of $456 million from 2015. Cash provided by operating activities decreased primarily due to lower realized sales prices for
oil, NGLs and natural gas, lower crude oil production volumes, and a decrease in cash settlements received on our derivative contracts
during 2016. These negative factors were partially offset by higher NGL and natural gas production volumes, as well as lower lease
operating expenses, exploration costs, production taxes, cash interest expense and general and administrative expenses during 2016 as
compared to 2015. Refer to “Results of Operations” for more information on the impact of volumes and prices on revenues and for
more information on increases and decreases in certain expenses during 2016.
During 2016, cash flows from operating activities plus $313 million in proceeds from the sale of oil and gas properties were used to
finance $539 million of drilling and development expenditures, $250 million of net repayments under our credit agreement, $42
million of early conversion payments on our New Convertible Notes and $22 million of debt issuance costs.
Cash Flows from 2015 Compared to 2014. During 2015, we generated $1.1 billion of cash provided by operating activities, a
decrease of $764 million from 2014. Cash provided by operating activities decreased primarily due to lower realized sales prices for
oil, NGLs and natural gas, as well as increased lease operating expenses, exploration costs and cash interest expense during 2015.
These negative factors were partially offset by higher crude oil, NGL and natural gas production volumes and an increase in cash
settlements received on our derivative contracts, as well as lower production taxes and general and administrative expenses in 2015 as
compared to 2014.
During 2015, cash flows from operating activities plus $2.0 billion in proceeds from the issuance of our 2020 Convertible Senior
Notes and 2023 Senior Notes, $1.1 billion in proceeds from the issuance of our common stock and $515 million in proceeds from the
sale of non-core oil and gas properties were used to finance $2.5 billion of drilling and development expenditures, $1.6 billion for the
redemption of the Kodiak Notes, $600 million of net repayments under our credit agreement, $54 million of debt and equity issuance
costs and $28 million of oil and gas property acquisitions.
Exploration and Development Expenditures. The following chart details our E&D expenditures incurred by core area (in thousands):
Northern Rocky Mountains
Central Rocky Mountains
Permian Basin (1)
Other (2)
Total incurred
$
$
Year Ended
December 31,
2015
1,556,267 $
603,646
94,940
58,749
2,313,602 $
2016
348,610 $
170,256
33,266
1,462
553,594 $
2014
1,999,243
757,404
379,702
45,589
3,181,938
_____________________
(1) For the year ended December 31, 2014, amount includes $76 million related to the acquisition of undeveloped CO2 acreage and
the development of CO2 reserves and related facilities at our Bravo Dome field in New Mexico. We sold our interest in the Bravo
Dome field in January 2016. In July 2016, we sold our North Ward Estes Properties, including all of our remaining assets in the
Permian Basin.
(2) Other primarily includes non-core oil and gas properties located in Colorado, Mississippi, North Dakota, Texas and Wyoming.
We continually evaluate our capital needs and compare them to our capital resources. Our 2017 E&D budget is $1.1 billion, which we
expect to fund substantially with net cash provided by operating activities, proceeds from property divestitures, cash on hand,
borrowings under our credit facility or by accessing the capital markets. The 2017 E&D budget represents an increase over the $554
million incurred on E&D expenditures during 2016. This increased capital budget is in response to the higher crude oil prices
experienced during the fourth quarter of 2016 and continuing into 2017. A portion of the 2017 budget will be used to resume
55
completions at our Redtail field in early 2017, as this activity has been suspended in this area since the second quarter of 2016. We
believe that should additional attractive acquisition opportunities arise or E&D expenditures exceed $1.1 billion, we will be able to
finance additional capital expenditures through agreements with industry partners, divestitures of certain oil and gas property interests,
borrowings under our credit agreement or by accessing the capital markets. Our level of E&D expenditures is largely discretionary,
and the amount of funds we devote to any particular activity may increase or decrease significantly depending on commodity prices,
cash flows, available opportunities and development results, among other factors. We believe that we have sufficient liquidity and
capital resources to execute our business plan over the next 12 months and for the foreseeable future. With our expected cash flow
streams, commodity price hedging strategies, current liquidity levels (including availability under our credit agreement), access to debt
and equity markets and flexibility to modify future capital expenditure programs, we expect to be able to fund all planned capital
programs and debt repayments, comply with our debt covenants, and meet other obligations that may arise from our oil and gas
operations.
Credit Agreement. Whiting Oil and Gas, our wholly-owned subsidiary, has a credit agreement with a syndicate of banks that as of
December 31, 2016 had a borrowing base and aggregate commitments of $2.5 billion. In October 2016, our borrowing base under the
facility was reduced from $2.6 billion to $2.5 billion in connection with the November 1, 2016 regular borrowing base
redetermination, with no change to our aggregate commitments of $2.5 billion. As of December 31, 2016, we had $1.9 billion of
available borrowing capacity, which was net of $550 million in borrowings and $11 million in letters of credit outstanding.
The borrowing base under the credit agreement is determined at the discretion of the lenders, based on the collateral value of our
proved reserves that have been mortgaged to 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. Because oil and gas prices are principal inputs into the valuation of our reserves, if current or projected oil and gas
prices decline from their current levels, our borrowing base could be reduced at the next redetermination date, which is scheduled for
May 1, 2017, or during future redeterminations. Upon a redetermination of our borrowing base, either on a periodic or special
redetermination date, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately
repay a portion of our debt outstanding under the credit agreement.
A portion of the revolving credit facility in an aggregate amount not to exceed $50 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, 2016, $39 million was available for
additional letters of credit under the agreement.
The credit agreement provides for interest only payments until December 2019, when the credit agreement expires and all outstanding
borrowings are due. Interest under the revolving credit facility accrues at our option at either (i) a base rate for a base rate loan plus
the margin in the table below, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.5% per
annum, or an adjusted LIBOR rate plus 1.0% per annum, or (ii) an adjusted LIBOR rate for a Eurodollar loan plus the margin in the
table below. Additionally, we also incur commitment fees as set forth in the table below on the unused portion of the aggregate
commitments of the lenders under the revolving credit facility.
Ratio of Outstanding Borrowings to Borrowing Base
Less than 0.25 to 1.0
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0
Greater than or equal to 0.90 to 1.0
Applicable
Margin for Base
Rate Loans
1.00%
1.25%
1.50%
1.75%
2.00%
Applicable
Margin for
Eurodollar Loans
2.00%
2.25%
2.50%
2.75%
3.00%
Commitment
Fee
0.50%
0.50%
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. However, the credit agreement permits us and certain of our subsidiaries to
issue second lien indebtedness of up to $1.0 billion subject to certain conditions and limitations. 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 our restricted subsidiaries (as defined in the credit agreement). The credit agreement requires us, as of the last day of
any quarter, to maintain the following ratios (as defined in the credit agreement): (i) a consolidated current assets to consolidated
current liabilities ratio (which includes an add back of the available borrowing capacity under the credit agreement) of not less than
1.0 to 1.0, (ii) a total senior secured debt to the last four quarters’ EBITDAX ratio of less than 3.0 to 1.0 during the Interim Covenant
Period (defined below), and thereafter a total debt to EBITDAX ratio of less than 4.0 to 1.0 and (iii) a ratio of the last four quarters’
EBITDAX to consolidated cash interest charges of not less than 2.25 to 1.0 during the Interim Covenant Period. Under the credit
agreement, the “Interim Covenant Period” is defined as the period from June 30, 2015 until the earlier of (i) April 1, 2018 or (ii) the
commencement of an investment-grade debt rating period (as defined in the credit agreement). We were in compliance with our
56
covenants under the credit agreement as of December 31, 2016. 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.
For further information on the loan security related to our credit agreement, refer to the “Long-Term Debt” footnote in the notes to
consolidated financial statements.
Senior Notes and Senior Subordinated Notes. In March 2015, we issued at par $750 million of 6.25% Senior Notes due April 2023
(the “2023 Senior Notes”). In September 2013, we issued at par $1.1 billion of 5.0% Senior Notes due March 2019 (the “2019 Senior
Notes”) and $800 million of 5.75% Senior Notes due March 2021, and issued at 101% of par an additional $400 million of 5.75%
Senior Notes due March 2021 (collectively the “2021 Senior Notes” and together with the 2023 Senior Notes and the 2019 Senior
Notes, the “Senior Notes”). In September 2010, we issued at par $350 million of 6.5% Senior Subordinated Notes due October 2018
(the “2018 Senior Subordinated Notes”).
Exchange of Senior Notes and Senior Subordinated Notes for Convertible Notes. On March 23, 2016, we completed the exchange of
$477 million aggregate principal amount of our Senior Notes and 2018 Senior Subordinated Notes, consisting of (i) $49 million
aggregate principal amount of our 2018 Senior Subordinated Notes, (ii) $97 million aggregate principal amount of our 2019 Senior
Notes, (iii) $152 million aggregate principal amount of our 2021 Senior Notes, and (iv) $179 million aggregate principal amount of
our 2023 Senior Notes, for (i) $49 million aggregate principal amount of new 6.5% Convertible Senior Subordinated Notes due 2018,
(ii) $97 million aggregate principal amount of new 5.0% Convertible Senior Notes due 2019, (iii) $152 million aggregate principal
amount of new 5.75% Convertible Senior Notes due 2021, and (iv) $179 million aggregate principal amount of new 6.25%
Convertible Senior Notes due 2023 (together the “New Convertible Notes”). During the second quarter of 2016, holders of the New
Convertible Notes voluntarily converted all $477 million aggregate principal amount of the New Convertible Notes for approximately
41.8 million shares of our common stock. As of June 30, 2016, no New Convertible Notes remained outstanding.
Exchange of Senior Notes and Senior Subordinated Notes for Mandatory Convertible Notes. On July 1, 2016, we completed the
exchange of $405 million aggregate principal amount of our Senior Notes and 2018 Senior Subordinated Notes for the same aggregate
principal amount of new mandatory convertible senior notes and mandatory convertible senior subordinated notes. Refer to
“Mandatory Convertible Notes” below for more information on these exchange transactions.
Redemption of 2018 Senior Subordinated Notes. On January 3, 2017, the trustee under the indenture governing our 2018 Senior
Subordinated Notes provided notice to the holders of such notes that we elected to redeem all of the remaining $275 million aggregate
principal amount of our 2018 Senior Subordinated Notes on February 2, 2017, and on that date, we paid $281 million consisting of the
100% redemption price plus all accrued and unpaid interest on the notes. We financed the redemption with borrowings under our
credit agreement.
2020 Convertible Senior Notes. In March 2015, we issued at par $1,250 million of 1.25% Convertible Senior Notes due April 2020
(the “2020 Convertible Senior Notes”). On June 29, 2016, we completed the exchange of $129 million aggregate principal amount of
our 2020 Convertible Senior Notes for the same aggregate principal amount of new mandatory convertible senior notes, and on July 1,
2016, we completed the exchange of $559 million aggregate principal amount of our 2020 Convertible Senior Notes for the same
aggregate principal amount of new mandatory convertible senior notes. Refer to “Mandatory Convertible Notes” below for more
information on these exchange transactions.
For the remaining $562 million aggregate principal amount of 2020 Convertible Senior Notes, we have the option to settle conversions
of the these notes with cash, shares of common stock or a combination of cash and common stock at our election. Our intent is to
settle the principal amount of the 2020 Convertible Senior Notes in cash upon conversion. Prior to January 1, 2020, the 2020
Convertible Senior Notes will be convertible at the holder’s option only under the following circumstances: (i) during any calendar
quarter commencing after the calendar quarter ending on June 30, 2015 (and only during such calendar quarter), if the last reported
sale price of our common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading
days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion
price on each applicable trading day; (ii) during the five business day period after any five consecutive trading day period (the
“measurement period”) in which the trading price per $1,000 principal amount of the 2020 Convertible Senior Notes for each trading
day of the measurement period is less than 98% of the product of the last reported sale price of our common stock and the conversion
rate on each such trading day; or (iii) upon the occurrence of specified corporate events. On or after January 1, 2020, the 2020
Convertible Senior Notes will be convertible at any time until the second scheduled trading day immediately preceding the April 1,
2020 maturity date of the notes. The notes will be convertible at an initial conversion rate of 25.6410 shares of our common stock per
$1,000 principal amount of the notes, which is equivalent to an initial conversion price of approximately $39.00. The conversion rate
will be subject to adjustment in some events. In addition, following certain corporate events that occur prior to the maturity date, we
will increase, in certain circumstances, the conversion rate for a holder who elects to convert its 2020 Convertible Senior Notes in
connection with such corporate event. As of December 31, 2016, none of the contingent conditions allowing holders of the 2020
Convertible Senior Notes to convert these notes had been met.
57
Mandatory Convertible Notes. On June 29, 2016 we completed the exchange of $129 million aggregate principal amount of our 2020
Convertible Senior Notes for the same aggregate principal amount of new 1.25% Mandatory Convertible Senior Notes due 2020,
Series 2 (the “2020 Mandatory Convertible Notes, Series 2”). On July 1, 2016, we completed the exchange of $964 million aggregate
principal amount of our Senior Notes, 2020 Convertible Senior Notes and 2018 Senior Subordinated Notes, consisting of (i) $26
million aggregate principal amount of our 2018 Senior Subordinated Notes, (ii) $42 million aggregate principal amount of our 2019
Senior Notes, (iii) $559 million aggregate principal amount of our 2020 Convertible Senior Notes, (iv) $174 million aggregate
principal amount of our 2021 Senior Notes, and (v) $163 million aggregate principal amount of our 2023 Senior Notes, for (i) $26
million aggregate principal amount of new 6.5% Mandatory Convertible Senior Subordinated Notes due 2018 (the “2018 Mandatory
Convertible Notes”), (ii) $42 million aggregate principal amount of new 5.0% Mandatory Convertible Senior Notes due 2019 (the
“2019 Mandatory Convertible Notes”), (iii) $559 million aggregate principal amount of new 1.25% Mandatory Convertible Senior
Notes due 2020, Series 1 (the “2020 Mandatory Convertible Notes, Series 1” and together with the 2020 Mandatory Convertible
Notes, Series 2, the “2020 Mandatory Convertible Notes”), (iv) $174 million aggregate principal amount of new 5.75% Mandatory
Convertible Senior Notes due 2021 (the “2021 Mandatory Convertible Notes”), and (v) $163 million aggregate principal amount of
new 6.25% Mandatory Convertible Senior Notes due 2023 (the “2023 Mandatory Convertible Notes” and together with the 2018
Mandatory Convertible Notes, the 2019 Mandatory Convertible Notes, the 2020 Mandatory Convertible Notes and the 2021
Mandatory Convertible Notes, the “Mandatory Convertible Notes”).
The redemption provisions, covenants, interest payments and maturity terms applicable to each series of Mandatory Convertible Notes
were substantially identical to those applicable to the corresponding series of Senior Notes, 2020 Convertible Senior Notes and 2018
Senior Subordinated Notes.
The Mandatory Convertible Notes contained mandatory conversion features whereby four percent of the aggregate principal amount
of the Mandatory Convertible Notes were converted into shares of our common stock for each day of the 25 trading day period that
commenced on June 23, 2016 (the “Observation Period”) if the daily volume weighted average price (the “Daily VWAP”) (as defined
in the indentures governing the Mandatory Convertible Notes) of our common stock on such day, rounded to four decimal places for
the 2020 Mandatory Convertible Notes and rounded to two decimal places for the 2018 Mandatory Convertible Notes, the 2019
Mandatory Convertible Notes, the 2021 Mandatory Convertible Notes and the 2023 Mandatory Convertible Notes, was above $8.75
(the “Threshold Price”). Upon conversion, the common stock issue price per share was equal to the higher of (i) the Daily VWAP for
our common stock for such trading day multiplied by one plus zero for the 2018 Mandatory Convertible Notes, one plus 0.5% for the
2019 Mandatory Convertible Notes, one plus 8.0% for the 2020 Mandatory Convertible Notes, one plus 2.5% for the 2021 Mandatory
Convertible Notes and one plus 3.5% for the 2023 Mandatory Convertible Notes or (ii) $8.75 for the 2018 Mandatory Convertible
Notes (equivalent to 114.29 common shares per $1,000 principal amount of the notes), $8.79 for the 2019 Mandatory Convertible
Notes (equivalent to 113.72 common shares per $1,000 principal amount of the notes), $9.45 for the 2020 Mandatory Convertible
Notes (equivalent to 105.82 common shares per $1,000 principal amount of the notes), $8.97 for the 2021 Mandatory Convertible
Notes (equivalent to 111.50 common shares per $1,000 principal amount of the notes) and $9.06 for the 2023 Mandatory Convertible
Notes (equivalent to 110.42 common shares per $1,000 principal amount of the notes) (the “Minimum Conversion Prices”).
After the Observation Period, we had the right, which we exercised on December 9, 2016 as noted below, to mandatorily convert any
remaining Mandatory Convertible Notes if the Daily VWAP of our common stock exceeded $8.75 for at least 20 trading days during a
30 consecutive trading day period and holders had the right to convert the Mandatory Convertible Notes at any time. The conversion
price after the Observation Period was the Minimum Conversion Price for each applicable series of Mandatory Convertible Notes.
During the Observation Period, the Daily VWAP of our common stock was above the Threshold Price (i) for 7 of the 25 trading days
for the 2018 Mandatory Convertible Notes, the 2019 Mandatory Convertible Notes, the 2021 Mandatory Convertible Notes and the
2023 Mandatory Convertible Notes and (ii) for 8 of the 25 trading days for the 2020 Mandatory Convertible Notes. As a result, $333
million aggregate principal amount of the Mandatory Convertible Notes were converted into approximately 33.2 million shares of our
common stock.
On August 12, 2016, we completed the exchange of (i) $13 million aggregate principal amount of our 2018 Mandatory Convertible
Notes which had a conversion price of $8.75 per share (equivalent to 114.29 common shares per $1,000 principal amount of the notes)
for shares of our common stock at an issuance price of $7.77 per share (equivalent to 128.69 common shares per $1,000 principal
amount of the notes) and (ii) $25 million aggregate principal amount of our 2019 Mandatory Convertible Notes which had a
conversion price of $8.79 per share (equivalent to 113.72 common shares per $1,000 principal amount of the notes) for shares of our
common stock at an issuance price of $7.80 per share (equivalent to 128.17 shares per $1,000 principal amount of the notes). Upon
acceptance of this inducement offer by the holders of the notes, such notes were immediately cancelled in exchange for approximately
4.9 million shares of our common stock.
During the fourth quarter of 2016, the Daily VWAP of our common stock was above $8.75 for 20 trading days during a 30
consecutive trading day period. As a result, on December 9, 2016, we provided notice to the holders of the remaining $721 million
aggregate principal amount of the Mandatory Convertible Notes of our intent to exercise our right to convert such notes on December
58
19, 2016 pursuant to their terms. The notes were subsequently converted into approximately 77.6 million shares of our common
stock. As of December 31, 2016, no Mandatory Convertible Notes remained outstanding.
Note Covenants. The indentures governing the Senior 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’ credit agreement.
Additionally, these indentures contain restrictive covenants that may limit our ability to, among other things, pay cash dividends, make
certain other restricted payments, redeem or repurchase our capital stock or our subordinated debt, make investments or issue
preferred stock, sell assets, consolidate, merge or transfer all or substantially all of the assets of ours and our restricted subsidiaries
taken as a whole, and enter 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, 2016. 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 following table summarizes our obligations and commitments as of December 31, 2016 to
make future payments under certain contracts, aggregated by category of contractual obligation, for the time periods specified below.
This table does not include amounts payable under contracts where we cannot predict with accuracy the amount and timing of such
payments, including any amounts we may be obligated to pay under our derivative contracts, as such payments are dependent upon the
price of crude oil in effect at the time of settlement, and any penalties that may be incurred for underdelivery under our physical
delivery contracts. For further information on these contracts refer to the “Derivative Financial Instruments” footnote in the notes to
consolidated financial statements and “Delivery Commitments” in Item 2 of this Annual Report on Form 10-K.
Payments due by period
(in thousands)
Contractual Obligations
Long-term debt (1)
Cash interest expense on debt (2)
Asset retirement obligations (3)
Water disposal agreement (4)
Purchase obligations (5)
Pipeline transportation agreements (6)
Drilling rig contracts (7)
Leases (8)
Total
Total
$ 3,630,510 $
Less than 1
year
1-3 years
3-5 years
- $ 1,786,530 $ 1,435,684 $
More than 5
years
408,296
567,602
154,575
267,777
113,352
31,898
177,135
8,500
32,787
17,149
118,699
137,441
15,782
38,896
40,635
42,128
30,624
43,694
7,656
15,312
7,656
-
5,369
10,738
10,738
16,849
30,717
30,717
-
-
-
22,131
$ 4,639,854 $
7,502
801
13,828
230,101 $ 2,165,868 $ 1,626,015 $
-
617,870
_____________________
(1) Long-term debt consists of the principal amounts of the Senior Notes, the 2020 Convertible Senior Notes and the 2018 Senior
Subordinated Notes, as well as the outstanding borrowings under our credit agreement.
(2) Cash interest expense on the Senior Notes is estimated assuming no principal repayment until the due dates of the instruments.
Cash interest expense on the 2020 Convertible Senior Notes is estimated assuming no principal repayments or conversions prior
to maturity. Cash interest expense on the 2018 Senior Subordinated Notes is estimated based on the notes having been redeemed
on February 2, 2017 using borrowings under our credit agreement. Cash interest expense on the credit agreement is estimated
assuming $275 million of incremental borrowings on February 2, 2017 used to redeem the 2018 Senior Subordinated Notes, no
principal repayment until the December 2019 instrument due date and a fixed interest rate of 2.8%.
(3) Asset retirement obligations represent the present value of estimated amounts expected to be incurred in the future to plug and
abandon oil and gas wells, remediate oil and gas properties and dismantle their related plants, facilities and offshore platforms.
(4) We have one water disposal agreement which expires in 2024, whereby we have contracted for the transportation and disposal of
the produced water from our Redtail field. Under the terms of the agreement, we are obligated to provide a minimum volume of
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produced water or else pay for any deficiencies at the price stipulated in the contract. The obligations reported above represent
our minimum financial commitments pursuant to the terms of this contract, however, our actual expenditures under this contract
may exceed the minimum commitments presented above.
(5) We have one take-or-pay purchase agreement which expires in 2020, whereby we have committed to buy certain volumes of
water for use in the fracture stimulation process on wells we complete in our Redtail field. Under the terms of the agreement, we
are obligated to purchase a minimum volume of water or else pay for any deficiencies at the price stipulated in the contract. The
purchasing obligations reported above represent our minimum financial commitments pursuant to the terms of this contract,
however, our actual expenditures under this contract may exceed the minimum commitments presented above.
(6) We have two pipeline transportation agreements with one supplier, expiring in 2024 and 2025, whereby we have committed to
pay fixed monthly reservation fees on dedicated pipelines from our Redtail field for natural gas and NGL transportation capacity,
plus a variable charge based on actual transportation volumes.
(7) As of December 31, 2016, we had five drilling rigs under long-term contract, all of which expire in 2017. As of December 31,
2016, early termination of these contracts would require termination penalties of $27 million, which would be in lieu of paying
the remaining drilling commitments under these contracts.
(8) We lease 222,900 square feet of administrative office space in Denver, Colorado under an operating lease arrangement expiring in
2019, 44,500 square feet of office space in Midland, Texas expiring in 2020, and 36,500 square feet of office space in Dickinson,
North Dakota expiring in 2020.
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 operating, development and exploration 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 in accordance with GAAP and SEC rules and regulations requires us to make certain
assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of
contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on historical
experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes
in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors. A
summary of our significant accounting policies is detailed in Note 1 to our consolidated financial statements. We have outlined below
certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which
require the application of significant judgment by our management.
Successful Efforts Accounting. We account for our oil and gas operations using the successful efforts method of accounting. Under
this method, the fair value of property acquired and all costs associated with successful exploratory wells and all development wells
are capitalized. Items charged to expense generally include geological and geophysical costs, costs of unsuccessful exploratory wells
and oil and gas production costs. All of our properties are located within the continental United States.
Oil and Natural Gas Reserve Quantities. Reserve quantities and the related estimates of future net cash flows affect our periodic
calculations of depletion, impairment of our oil and natural gas properties and our asset retirement obligations. Proved oil and gas
reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable
certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions,
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 (i) the quality and quantity of available data, (ii) the
interpretation of that data, (iii) the accuracy of various mandated economic assumptions, and (iv) the judgments of the persons
preparing the estimates.
External petroleum engineers independently estimated all of the proved reserve quantities included in this Annual Report on Form 10-
K. In connection with our external petroleum engineers performing their independent reserve estimations, we furnish them with the
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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, 2016. 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. For example, if the crude oil and natural gas prices used in our year-end reserve estimates
increased or decreased by 10%, our proved reserve quantities at December 31, 2016 would have increased by 75 MBOE (12%) or
decreased by 90 MBOE (15%), respectively, and the pre-tax PV10% of our proved reserves would have increased by $920 million
(34%) or decreased by $800 million (30%), respectively. We continually make revisions to reserve estimates throughout the year as
additional information becomes available. We make changes to depletion rates and impairment calculations (when impairment
indicators arise) in the same period that changes to reserve estimates are made.
Depreciation, Depletion and Amortization. Our rate of recording DD&A is dependent upon our estimates of total proved and proved
developed reserves, which estimates incorporate various assumptions and future projections. If our estimates of total proved or proved
developed reserves decline, the rate at which we record DD&A expense increases, which in turn reduces our net income. Such a
decline in reserves may result from lower commodity prices or other changes to reserve estimates, as discussed above, and we are
unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploration and
development program, as well as future economic conditions.
Impairment of Oil and Gas Properties. We review the value of our oil and gas properties whenever management judges that events
and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments of producing
properties are determined by comparing their future net undiscounted cash flows to their net book values at the end of each period. If
their net capitalized costs exceed undiscounted future cash flows, the cost of the property is written down to “fair value”, which is
determined using net discounted future cash flows from the producing property. Different pricing assumptions or discount rates could
result in a different calculated impairment. In addition to proved property impairments, we provide for impairments on significant
undeveloped properties when we determine that the property will not be developed or a permanent impairment in value has occurred.
Individually insignificant unproved properties are amortized on a composite basis, based on past success, experience and average
lease-term lives.
Goodwill Impairment. We tested goodwill for impairment annually in the second quarter or whenever events or changes in
circumstances indicated that the fair value of our reporting unit may have been reduced below its carrying value. When testing
goodwill for impairment, if our qualitative analysis indicated that it was more likely than not that the fair value of the reporting unit
was less than its carrying value, we then performed a quantitative impairment test. If the carrying value of the reporting unit exceeded
its fair value, goodwill was written down to its implied fair value with an offsetting charge to earnings.
We performed our annual goodwill impairment test as of June 30, 2015, and determined that no impairment had occurred. However,
as a result of a sustained decrease in the price of Whiting’s common stock during the third quarter of 2015 caused by a significant
decline in crude oil and natural gas prices over that same period, we performed another goodwill impairment test as of September 30,
2015. The impairment test indicated that the fair value of our reporting unit was less than its carrying amount, and further that there
was no remaining implied fair value attributable to goodwill. Based on these results, we recorded a non-cash impairment charge to
reduce the carrying value of goodwill to zero.
The fair value of our reporting unit was ascribed using an income approach analysis based on net discounted future cash flows and a
market approach analysis. The income approach analysis was dependent on a number of factors including estimates of future oil and
gas production from our reserve reports, future commodity prices based on sales contract terms or NYMEX forward price curves as of
the date of the estimate (adjusted for basis differentials), future operating and development costs, the successful development of
proved and unproved reserves, an inflation rate and a discount rate based on our weighted-average cost of capital. The market
approach was dependent on our market capitalization as of the date of the estimate, an estimate of the control premium that a market
participant would apply to value our reporting unit as a whole and the fair value of our outstanding debt.
There is considerable judgment involved in estimating fair values, particularly in determining the valuation methodologies to utilize
and the weighting applied to such methodologies. Although we based the fair value estimate of our reporting unit on assumptions we
believed to be reasonable, those assumptions are inherently uncertain, and actual results could differ from our estimates.
Asset Retirement Obligation. Our asset retirement obligations (“ARO”) consist of estimated future costs associated with the plugging
and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and land restoration in accordance
with applicable local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period
in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The
recognition of an ARO requires that management make numerous assumptions regarding such factors as the estimated probabilities,
amounts and timing of settlements; the credit-adjusted risk-free discount rate; the inflation rate; and future advances in technology. In
periods subsequent to the initial measurement of an ARO, we must recognize period-to-period changes in the liability resulting from
61
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.
Derivative and Embedded Derivative Instruments. 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 or other derivative scope
exceptions. We do not currently apply hedge accounting to any of our outstanding derivative instruments, and as a result, all changes
in derivative fair values are recognized currently in earnings.
We determine the recorded amounts of our derivative instruments measured at fair value utilizing third-party valuation specialists.
We review these valuations, including the related model inputs and assumptions, and analyze changes in fair value measurements
between periods. We corroborate such inputs, calculations and fair value changes using various methodologies, and review
unobservable inputs for reasonableness utilizing relevant information from other published sources. When available, we utilize
counterparty valuations to assess the reasonableness of our valuations. The values we report in our financial statements change as the
assumptions used in these valuations 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.
We periodically enter into commodity derivative contracts to manage our exposure to oil and natural gas price volatility. We
primarily utilize costless collars which are generally placed with major financial institutions, as well as swaps and crude oil sales and
delivery contracts. 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. 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.
We value our costless collars and swaps using industry-standard models that consider various assumptions, including quoted forward
prices for commodities, time value, volatility factors and contractual prices for the underlying instruments, as well as other relevant
economic measures. We value our long-term crude oil sales and delivery contracts based on an income approach, which considers
various assumptions, including quoted forward prices for commodities, market differentials for crude oil and U.S. Treasury rates. The
discount rates used in the fair values of these instruments include a measure of nonperformance risk by the counterparty or us, as
appropriate.
In addition, we evaluate the terms of our convertible debt and other contracts, if any, to determine whether they contain embedded
components that are required to be bifurcated and accounted for separately as derivative financial instruments.
We valued the embedded derivatives related to our convertible notes using a binomial lattice model which considered various inputs
including (i) our common stock price, (ii) risk-free rates based on U.S. Treasury rates, (iii) recovery rates in the event of default, (iv)
default intensity and (v) volatility of our common stock.
We also have an embedded derivative related to our purchase and sale agreement with the buyer of the North Ward Estes Properties,
which includes a contingent payment linked to NYMEX crude oil prices. We value this embedded derivative using a modified Black-
Scholes swaption pricing model which considers various assumptions, including quoted forward prices for commodities, time value
and volatility factors. The discount rate used in the fair value of this instrument includes a measure of the counterparty’s
nonperformance risk.
Income Taxes and Uncertain Tax Positions. We provide for income taxes in accordance with FASB ASC Topic 740, Income Taxes
(“ASC 740”). We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have
been recognized in our financial statements and our tax returns. We routinely assess the realizability of our deferred tax assets. If we
conclude that it is more likely than not that some portion or all of our deferred tax assets will not be realized, the tax asset is reduced
by a valuation allowance. We consider future taxable income in making such assessments. Numerous judgments and assumptions are
inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as they relate
to prevailing oil and natural gas prices).
ASC 740 requires uncertain income tax positions to meet a more-likely-than-not recognition threshold to be recognized in the
financial statements. Under ASC 740, uncertain tax positions that previously failed to meet the more-likely-than-not threshold should
be recognized in the first subsequent financial reporting period in which that threshold is met. Previously recognized uncertain tax
positions that no longer meet the more-likely-than-not threshold should be derecognized in the first subsequent financial reporting
period in which that threshold is no longer met.
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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. We account for business combinations using the acquisition method, which is the only
method permitted under FASB ASC Topic 805, Business Combinations, and involves the use of significant judgment.
Under the acquisition 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 consideration given to acquire an entity over the net
amounts assigned to its 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.
With the exception of the Kodiak Acquisition, the business combinations completed during the past three years consisted of oil and
gas properties. In general, the consideration we have paid to acquire these properties or companies was entirely allocated to the fair
value of the assets acquired and liabilities assumed at the time of acquisition and consequently, there was no goodwill nor any bargain
purchase gains recognized on our business combinations. However, the purchase price allocation associated with the Kodiak
Acquisition resulted in the recognition of goodwill. For further information on the Kodiak Acquisition, refer to the “Acquisitions and
Divestitures” footnote in the notes to consolidated financial statements.
Effects of Inflation and Pricing
We experienced increased costs during 2014 due to the increased demand for oil field products and services at the time, however,
these costs declined during 2015 and 2016 as demand for these same products and services decreased in response to the sustained
depressed commodity price environment. 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 in the near term, higher demand in the industry 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.
63
These risks and uncertainties include, but are not limited to: declines in, or extended periods of low oil, NGL or natural gas prices; our
level of success in exploration, development and production activities; risks related to our level of indebtedness, ability to comply with
debt covenants and periodic redeterminations of the borrowing base under our credit agreement; impacts to financial statements as a
result of impairment write-downs; our ability to successfully complete asset dispositions and the risks related thereto; revisions to
reserve estimates as a result of changes in commodity prices, regulation and other factors; adverse weather conditions that may
negatively impact development or production activities; the timing of our exploration and development expenditures; inaccuracies of
our reserve estimates or our assumptions underlying them; risks relating to any unforeseen liabilities of ours; our ability to generate
sufficient cash flows from operations to meet the internally funded portion of our capital expenditures budget; our ability to obtain
external capital to finance exploration and development operations; federal and state initiatives relating to the regulation of hydraulic
fracturing and air emissions; unforeseen underperformance of or liabilities associated with acquired properties; the impacts of hedging
on our results of operations; failure of our properties to yield oil or gas in commercially viable quantities; availability of, and risks
associated with, transport of oil and gas; our ability to drill producing wells on undeveloped acreage prior to its lease expiration;
shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs and completion services; uninsured or
underinsured losses resulting from our oil and gas operations; our inability to access oil and gas markets due to market conditions or
operational impediments; the impact and costs of compliance with laws and regulations governing our oil and gas operations; our
ability to replace our oil and natural gas reserves; any loss of our senior management or technical personnel; competition in the oil and
gas industry; the potential impact of changes in laws, including tax reform, that could have a negative effect on the oil and gas
industry; cyber security attacks or failures of our telecommunication systems; and other risks described under the caption “Risk
Factors” in Item 1A of 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.
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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 2016 production, our income (loss) before income taxes for 2016 would have moved up
or down $117 million for each 10% change in oil prices per Bbl, $6 million for each 10% change in NGL prices per Bbl and $6
million for each 10% change in natural gas prices per Mcf.
We periodically enter into derivative contracts to achieve a more predictable cash flow by reducing our exposure to oil and natural gas
price volatility. Our derivative contracts have traditionally been costless collars and swaps, although we evaluate and have entered into
other forms of derivative instruments as well. Currently, we do not apply hedge accounting, and therefore all changes in commodity
derivative fair values are recorded immediately to earnings.
Commodity Derivative Contracts
Crude Oil Costless Collars. The collared hedges shown in the table below have the effect of providing a protective floor while
allowing us to share in upward pricing movements. The three-way collars, however, do not provide complete protection against
declines in crude oil prices due to the fact that when the market price falls below the sub-floor, the minimum price we would receive
would be NYMEX plus the difference between the floor and the sub-floor. While these hedges are designed to reduce our exposure to
price decreases, they also have the effect of limiting the benefit of price increases above the ceiling. The fair value of these
commodity derivative instruments at December 31, 2016, was a net liability of $19 million. A hypothetical upward or downward shift
of 10% per Bbl in the NYMEX forward curve for crude oil as of December 31, 2016 would cause an increase of $57 million or a
decrease of $43 million, respectively, in this fair value liability.
Our outstanding commodity derivative contracts as of January 3, 2017 are summarized below:
Derivative
Instrument
Three-way collars (1)
Collars
Commodity
Period
(Bbl)
NYMEX Sub-Floor/Floor/Ceiling
Monthly Volume
Weighted Average
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
Crude oil
01/2017 to 03/2017
04/2017 to 06/2017
07/2017 to 09/2017
10/2017 to 12/2017
01/2018 to 03/2018
04/2018 to 06/2018
07/2018 to 09/2018
10/2018 to 12/2018
01/2017 to 03/2017
04/2017 to 06/2017
07/2017 to 09/2017
10/2017 to 12/2017
1,050,000
1,050,000
1,050,000
1,050,000
200,000
200,000
200,000
200,000
250,000
250,000
250,000
250,000
$34.76/$45.00/$60.26
$34.76/$45.00/$60.26
$34.76/$45.00/$60.26
$34.76/$45.00/$60.26
$40.00/$50.00/$61.40
$40.00/$50.00/$61.40
$40.00/$50.00/$61.40
$40.00/$50.00/$61.40
$53.00/$70.44
$53.00/$70.44
$53.00/$70.44
$53.00/$70.44
_____________________
(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.
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, 2016, our outstanding principal balance under our credit agreement was $550 million, and the weighted
average interest rate on the outstanding principal balance was 4.0%. At December 31, 2016, the carrying amount approximated fair
market value. Assuming a constant debt level of $550 million, the cash flow impact resulting from a 100 basis point change in interest
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rates during periods when the interest rate is not fixed would be $5 million over a 12-month time period. Changes in interest rates do
not affect the amount of interest we pay on our fixed-rate senior notes, but changes in interest rates do affect the fair values of these
notes.
In March 2015, we issued 1.25% Convertible Senior Notes due April 2020 (the “2020 Convertible Senior Notes”). As the interest rate
on these notes is fixed at 1.25%, we are not subject to any direct risk of loss related to fluctuations in interest rates. However, changes
in interest rates do affect the fair value of this debt instrument, which could impact the amount of gain or loss that we recognize in
earnings upon conversion of the notes. Refer to the “Long-Term Debt” and “Fair Value Measurements” footnotes in the notes to
consolidated financial statements for more information on the material terms and fair values of the 2020 Convertible Senior Notes.
66
Item 8.
Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2016 and 2015
Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Statements of Equity for the Years Ended December 31, 2016, 2015 and 2014
Notes to Consolidated Financial Statements
68
69
70
71
73
74
67
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, 2016 and 2015, and the related consolidated statements of operations, cash flows, and equity for each of the three
years in the period ended December 31, 2016. These financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on the financial statements 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, 2016 and 2015, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the
United States of America.
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, 2016, based on the criteria established in Internal Control—
Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report
dated February 23, 2017 expressed an unqualified opinion on the Company's internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 23, 2017
68
WHITING PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)
$
$
$
ASSETS
Current assets:
Cash and cash equivalents
Restricted cash
Accounts receivable trade, net
Derivative assets
Prepaid expenses and other
Assets held for sale
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
Other long-term assets
TOTAL ASSETS
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable trade
Revenues and royalties payable
Accrued capital expenditures
Accrued interest
Accrued lease operating expenses
Accrued liabilities and other
Taxes payable
Accrued employee compensation and benefits
Liabilities related to assets held for sale
Total current liabilities
Long-term debt
Deferred income taxes
Asset retirement obligations
Deferred gain on sale
Other long-term liabilities
Total liabilities
Commitments and contingencies
Equity:
Common stock, $0.001 par value, 600,000,000 shares authorized; 367,174,542
issued and 362,013,928 outstanding as of December 31, 2016 and 206,441,303
issued and 204,147,647 outstanding as of December 31, 2015
Additional paid-in capital
Retained earnings (accumulated deficit)
Total Whiting shareholders' equity
Noncontrolling interest
Total equity
TOTAL LIABILITIES AND EQUITY
$
The accompanying notes are an integral part of these consolidated financial statements.
69
December 31,
2016
2015
55,975 $
17,250
173,919
-
26,312
349,146
622,602
16,053
-
332,428
158,729
27,980
-
535,190
13,230,851
134,638
13,365,489
(4,222,071)
9,143,418
110,122
9,876,142 $
13,904,525
168,277
14,072,802
(3,323,102)
10,749,700
104,195
11,389,085
32,126 $
147,226
56,830
44,749
45,015
81,166
39,547
31,134
538
478,331
3,535,303
475,689
168,504
35,424
33,699
4,726,950
77,276
179,601
94,105
62,661
55,291
50,261
47,789
32,829
-
599,813
5,197,704
593,792
155,550
48,974
34,664
6,630,497
367
6,389,435
(1,248,572)
5,141,230
7,962
5,149,192
9,876,142 $
206
4,659,868
90,530
4,750,604
7,984
4,758,588
11,389,085
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
OPERATING REVENUES
Oil, NGL and natural gas sales
OPERATING EXPENSES
Lease operating expenses
Production taxes
Depreciation, depletion and amortization
Exploration and impairment
Goodwill impairment
General and administrative
Derivative gain, net
(Gain) loss on sale of properties
Amortization of deferred gain on sale
Total operating expenses
Year Ended
December 31,
2015
2016
2014
$
1,284,982 $
2,092,482 $
3,024,617
395,135
108,715
1,171,582
121,468
-
146,878
(587)
184,567
(14,570)
2,113,188
555,392
183,035
1,243,293
1,881,671
873,772
172,616
(217,972)
60,791
(16,751)
4,735,847
496,925
253,008
1,089,545
854,430
-
177,211
(100,579)
(27,657)
(30,494)
2,712,389
INCOME (LOSS) FROM OPERATIONS
(828,206)
(2,643,365)
312,228
OTHER INCOME (EXPENSE)
Interest expense
Loss on extinguishment of debt
Interest income and other
Total other expense
(557,620)
(42,236)
1,292
(598,564)
(334,125)
(18,361)
2,356
(350,130)
(170,642)
-
2,329
(168,313)
INCOME (LOSS) BEFORE INCOME TAXES
(1,426,770)
(2,993,495)
143,915
INCOME TAX EXPENSE (BENEFIT)
Current
Deferred
Total income tax expense (benefit)
NET INCOME (LOSS)
Net loss attributable to noncontrolling interests
NET INCOME (LOSS) AVAILABLE TO COMMON
SHAREHOLDERS
INCOME (LOSS) PER COMMON SHARE
Basic
Diluted
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic
Diluted
(7,190)
(80,456)
(87,646)
(357)
(773,870)
(774,227)
(1,339,124)
22
(2,219,268)
86
2,625
76,545
79,170
64,745
62
$
(1,339,102) $
(2,219,182) $
64,807
$
$
(5.32) $
(5.32) $
(11.35) $
(11.35) $
0.53
0.53
251,869
251,869
195,472
195,472
122,138
122,519
The accompanying notes are an integral part of these consolidated financial statements.
70
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Year Ended
December 31,
2015
2016
2014
$
(1,339,124) $
(2,219,268) $
64,745
Depreciation, depletion and amortization
Deferred income tax expense (benefit)
Amortization of debt issuance costs, debt discount and debt premium
Stock-based compensation
Amortization of deferred gain on sale
(Gain) loss on sale of properties
Undeveloped leasehold and oil and gas property impairments
Goodwill impairment
Exploratory dry hole costs
Loss on extinguishment of debt
Non-cash derivative (gain) loss
Other, net
Changes in current assets and liabilities:
Accounts receivable trade, net
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
Deposit received on properties held for sale
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under credit agreement
Repayments of borrowings under credit agreement
Issuance of common stock
Issuance of 1.25% Convertible Senior Notes due 2020
Issuance of 6.25% Senior Notes due 2023
Redemption of 8.125% Senior Notes due 2019
Redemption of 5.5% Senior Notes due 2021
Redemption of 5.5% Senior Notes due 2022
Early conversion payments for New Convertible Notes
Debt and equity issuance costs
Repayment of tax sharing liability
Proceeds from stock options exercised
Restricted stock used for tax withholdings
Net cash provided by (used in) financing activities
$
71
1,171,582
(80,456)
335,569
25,647
(14,570)
184,567
75,622
-
134
42,236
151,151
(10,185)
155,416
586
(62,774)
(32,185)
(8,206)
595,010
(539,208)
(4,718)
(9,255)
313,355
17,250
(222,576)
1,243,293
(773,870)
46,525
28,098
(16,751)
60,791
1,738,308
873,772
9,440
18,361
(1,615)
(9,337)
207,367
54,027
(117,136)
(74,417)
(16,196)
1,051,392
(2,455,218)
(28,449)
(13,266)
514,814
-
(1,982,119)
1,310,000
(1,560,000)
-
-
-
-
-
-
(41,919)
(22,499)
-
-
(844)
(315,262) $
3,550,000
(4,150,000)
1,111,148
1,250,000
750,000
(832,429)
(353,500)
(404,000)
-
(54,461)
-
3,048
(1,126)
868,680 $
1,089,545
76,545
11,984
23,258
(30,494)
(27,657)
767,627
-
26,327
-
(57,465)
(9,030)
17,618
(50,352)
(86,480)
(1,963)
1,094
1,815,302
(2,842,837)
(45,573)
(79,955)
107,848
-
(2,860,517)
2,150,000
(1,675,000)
-
-
-
-
-
-
-
(14,901)
(26,373)
1,781
(11,652)
423,855
(Continued)
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
NET CHANGE IN CASH, CASH EQUIVALENTS AND
RESTRICTED CASH
CASH, CASH EQUIVALENTS AND RESTRICTED CASH
Beginning of period
End of period
SUPPLEMENTAL CASH FLOW DISCLOSURES
Income taxes paid (refunded), net
Interest paid, net of amounts capitalized
NONCASH INVESTING ACTIVITIES
Year Ended
December 31,
2015
2016
2014
$
57,172 $
(62,047) $
(621,360)
$
$
$
16,053
73,225 $
78,100
16,053 $
699,460
78,100
(1,044) $
239,963 $
(604) $
292,852 $
1,380
135,150
Accrued capital expenditures related to property additions
$
Fair value of equity issued and debt assumed in the Kodiak Acquisition $
65,052 $
- $
94,105 $
- $
429,970
4,289,088
NONCASH FINANCING ACTIVITIES (1)
The accompanying notes are an integral part of these consolidated financial statements.
(Concluded)
(1) Refer to the “Long-Term Debt” footnote in the notes to consolidated financial statements for a discussion of (i) the Company’s
exchange of senior notes and senior subordinated notes for convertible notes and the subsequent conversions of such notes, and
(ii) the Company’s exchange of senior notes, convertible senior notes and senior subordinated notes for mandatory convertible
notes and the subsequent conversions of such notes.
72
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
(in thousands)
Common Stock
Amount
Shares
120,102 $
-
47,546
Additional
Paid-in
Capital
Retained
Earnings
(Accumulated
Deficit)
Total
Whiting
Shareholders' Noncontrolling
Equity
Interest
Total
Equity
120 $
-
48
1,583,542 $
-
1,771,046
2,244,905 $
64,807
-
3,828,567 $
64,807
1,771,094
8,132 $
(62)
-
3,836,699
64,745
1,771,094
258
-
9,596
-
9,596
-
9,596
BALANCES-January 1, 2014
Net income (loss)
Issuance of common stock for the Kodiak Acquisition
Fair value of restricted stock units assumed in the Kodiak
Acquisition
Fair value of stock options assumed in the Kodiak
Acquisition
Exercise of stock options
Restricted stock issued
Restricted stock forfeited
Restricted stock used for tax withholdings
Stock-based compensation
BALANCES-December 31, 2014
Net loss
Issuance of common stock
Equity component of 2020 Convertible Senior Notes, net
Exercise of stock options
Restricted stock issued
Restricted stock forfeited
Restricted stock used for tax withholdings
Stock-based compensation
BALANCES-December 31, 2015
Net loss
Issuance of common stock upon conversion of convertible
-
117
908
(386)
(199)
-
168,346
-
37,000
-
149
1,216
(230)
(40)
-
206,441
-
-
-
-
-
-
-
168
-
37
-
-
1
-
-
-
206
-
7,523
1,781
-
-
(11,652)
23,258
3,385,094
-
1,100,000
144,755
3,048
(1)
-
(1,126)
28,098
4,659,868
-
-
-
-
-
-
-
2,309,712
(2,219,182)
-
-
-
-
-
-
-
90,530
(1,339,102)
-
-
7,523
1,781
-
-
(11,652)
23,258
5,694,974
(2,219,182)
1,100,037
144,755
3,048
-
-
(1,126)
28,098
4,750,604
(1,339,102)
1,535,454
(63,330)
notes
157,543
158
1,535,296
Reduction of equity component of 2020 Convertible Senior
Notes upon extinguishment, net
Recognition of beneficial conversion features on
-
-
(63,330)
convertible notes
Restricted stock issued
Restricted stock forfeited
Restricted stock used for tax withholdings
Stock-based compensation
BALANCES-December 31, 2016
-
4,025
(729)
(105)
-
367,175 $
-
4
(1)
-
-
367 $
232,801
(4)
1
(844)
25,647
6,389,435 $
-
-
-
-
-
(1,248,572) $
232,801
-
-
(844)
25,647
5,141,230 $
The accompanying notes are an integral part of these consolidated financial statements.
73
-
-
-
-
-
-
8,070
(86)
-
-
-
-
-
-
-
7,984
(22)
-
-
-
-
-
-
-
7,962 $
7,523
1,781
-
-
(11,652)
23,258
5,703,044
(2,219,268)
1,100,037
144,755
3,048
-
-
(1,126)
28,098
4,758,588
(1,339,124)
1,535,454
(63,330)
232,801
-
-
(844)
25,647
5,149,192
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 engaged
in the development, production, acquisition and exploration of crude oil, NGLs and natural gas primarily in the Rocky Mountains
region of the United States. Unless otherwise specified or the context otherwise requires, all references in these notes to “Whiting” or
the “Company” are to Whiting Petroleum Corporation and its consolidated subsidiaries, Whiting Oil and Gas Corporation (“Whiting
Oil and Gas”), Whiting US Holding Company, Whiting Canadian Holding Company ULC (formerly Kodiak Oil & Gas Corp.,
“Kodiak”), Whiting Resources Corporation (formerly Kodiak Oil & Gas (USA) Inc.) and Whiting Programs, Inc.
Basis of Presentation of Consolidated Financial Statements—The consolidated financial statements have been prepared in
accordance with GAAP and SEC rules and regulations and 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. On January 28, 2015, the net profits interest that Whiting conveyed to Trust I terminated and such interest in the
underlying properties reverted back to Whiting. 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 GAAP 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 (i) oil and natural gas reserves; (ii) impairment tests of long-lived assets; (iii) depreciation, depletion and
amortization; (iv) asset retirement obligations; (v) assignment of fair value and allocation of purchase price in connection with
business combinations, including the determination of any resulting goodwill; (vi) valuations of our reporting unit used in impairment
tests of goodwill; (vii) income taxes; (viii) accrued liabilities; (ix) valuation of derivative instruments; and (x) accrued revenue and
related receivables. Although management believes these estimates are reasonable, actual results could differ from these estimates.
Reclassifications—The Company changed the presentation of its consolidated statements of operations and reclassified certain prior
year balances to conform to such presentation. The reclassifications had no impact on net income, cash flows or shareholders’ equity
previously reported.
Cash, Cash Equivalents and Restricted Cash—Cash equivalents consist of demand deposits and highly liquid investments which
have an original maturity of three months or less.
Restricted cash relates to a deposit received in connection with the sale of our interests in the Robinson Lake and Belfield gas
processing plants. The use of these funds was restricted per the terms of the purchase agreement until the sale transaction closed on
January 1, 2017. Refer to the “Subsequent Events” footnote for further information on this transaction.
The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance
sheets and the consolidated statements of cash flows:
Cash and cash equivalents
Restricted cash
Total cash, cash equivalents and restricted cash
December 31,
2016
2015
$
$
55,975 $
17,250
73,225 $
16,053
-
16,053
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, 2016 and 2015, the Company had an allowance for doubtful accounts of $10 million and $12 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 and totaled $33 million and $69 million as of
74
December 31, 2016 and 2015, respectively. Crude oil in tanks inventory is carried at the lower of the estimated cost to produce or net
realizable value. Oil in tanks is included in prepaid expenses and other and totaled $8 million as of December 31, 2016 and 2015.
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 unit-of-production
basis over the remaining life of proved reserves and proved developed reserves, respectively. Costs of drilling exploratory wells are
initially capitalized but are charged to expense if the well is determined to be unsuccessful.
The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying
value of the assets may not be recoverable. The impairment test compares undiscounted future net cash flows to the assets’ net book
value. If the net capitalized costs exceed future net cash flows, then the cost of the property is written down to fair value. Fair value
for oil and gas properties is generally determined based on discounted future net cash flows. Impairment expense for proved
properties that were not being developed due to depressed oil and gas prices totaled $1.6 billion and $629 million for the years ended
December 31, 2015 and 2014, respectively, which 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 2016, 2015 and 2014, the Company capitalized interest of $0.1 million, $4 million and $4 million,
respectively.
Unproved. Unproved properties consist of costs to acquire undeveloped leases as well as purchases of unproved reserves.
Undeveloped lease costs and unproved reserve acquisitions are capitalized, and individually insignificant unproved properties are
amortized on a composite basis, based on average lease-term lives and the historical experience of developing acreage in a particular
prospect. 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 totaled $73 million, $135 million and $136 million for the years ended December 31, 2016, 2015 and
2014, respectively, which 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 (i) the well has
found a sufficient quantity of reserves to justify completion as a producing well, and (ii) the Company is making sufficient progress
assessing the reserves and the economic and operating viability of the project. If either condition is not met, or if the Company
obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well costs,
net of any salvage value, are expensed.
Enhanced recovery activities. The Company carries out tertiary recovery methods on certain of its oil and gas properties in order to
recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods. Acquisition costs of tertiary
injectants, such as purchased CO2, for EOR activities that are used during a project’s pilot phase, or prior to a project’s technical and
economic viability (i.e. prior to the recognition of proved tertiary recovery reserves) are expensed as incurred. After a project has
been determined to be technically feasible and economically viable, all acquisition costs of tertiary injectants are capitalized as
development costs and depleted, as they are incurred solely for obtaining access to reserves not otherwise recoverable and have future
economic benefits over the life of the project. As CO2 is recovered together with oil and gas production, it is extracted and re-injected,
and all the associated CO2 recycling costs are expensed as incurred. Likewise costs incurred to maintain reservoir pressure are also
expensed.
Other Property and Equipment—Other property and equipment consists of materials and supplies inventories, carried at weighted-
average cost, and furniture and fixtures, buildings, leasehold improvements and automobiles, which are stated at cost and depreciated
75
using the straight-line method over their estimated useful lives ranging from 4 to 30 years.
Goodwill—Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business
combinations. Goodwill has an indefinite useful life and is not amortized, but rather is tested by the Company for impairment
annually in the second quarter or whenever events or changes in circumstances indicate that the fair value of the reporting unit may
have been reduced below its carrying value. If the Company’s qualitative analysis indicates that it is more likely than not that the fair
value of the reporting unit is less than its carrying value, the Company then performs a quantitative impairment test. If the carrying
value of the reporting unit exceeds its fair value, goodwill is written down to its implied fair value with an offsetting charge to
earnings.
The Company performed its annual goodwill impairment test as of June 30, 2015, and determined that no impairment had occurred.
However, as a result of a sustained decrease in the price of Whiting’s common stock during the third quarter of 2015 caused by a
significant decline in crude oil and natural gas prices over that same period, the Company performed another goodwill impairment test
as of September 30, 2015. The impairment test performed by the Company indicated that the fair value of its reporting unit was less
than its carrying amount, and further that there was no remaining implied fair value attributable to goodwill. Based on these results,
the Company recorded a non-cash impairment charge to reduce the carrying value of goodwill to zero.
Debt Issuance Costs—Debt issuance costs related to the Company’s senior notes, convertible senior notes and senior subordinated
notes are included as a deduction from the carrying amount of long-term debt in the consolidated balance sheets and 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 included in other long-term assets and are amortized to interest expense on a straight-line basis over the term of the agreement.
Derivative Instruments—The Company enters into derivative contracts, primarily costless collars and swaps as well as crude oil sales
and delivery contracts, to manage its exposure to commodity price risk. Whiting follows FASB ASC Topic 815, Derivatives and
Hedging, to account for its derivative financial instruments. All derivative instruments, other than those that meet the “normal
purchase normal sale” exclusion, are recorded on the balance sheet as either an asset or liability measured at fair value. Gains and
losses from changes in the fair value of derivative instruments are recognized immediately in earnings, unless the derivative meets
specific hedge accounting criteria and the derivative has been designated as a hedge. The Company does not currently apply hedge
accounting to any of its outstanding derivative instruments, and as a result, all changes in derivative fair values are recognized
currently in earnings.
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.
Refer to the “Derivative Financial Instruments” footnote for further information.
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 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 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 when 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 unit-of-production basis
over the proved developed reserves of the related asset. Revisions 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, and such revisions
result in adjustments to the related capitalized asset and corresponding liability.
Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that obligations have been incurred and
the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties.
Deferred Gain on Sale—The deferred gain on sale relates to the sale of 11,677,500 Trust I units and 18,400,000 Whiting USA Trust
II (“Trust II”) units, and is amortized to income based on the unit-of-production method. In January 2015, the deferred gain on sale
related to Trust I was fully amortized in connection with the termination of the trust’s net profits interest.
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 reasonably assured. Revenues from the production of gas properties in which the Company has an interest with other
producers are recognized on the basis of the Company’s net working interest (entitlement method). Net deliveries in excess of entitled
amounts are recorded as liabilities, while net under deliveries are reflected as receivables. The Company’s aggregate imbalance
positions as of December 31, 2016 and 2015 were not significant.
76
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 the working interest owners that participate in oil and gas properties operated by Whiting.
Stock-based Compensation Expense—The Company has share-based employee compensation plans that provide for the issuance of
restricted stock and stock option awards to employees and non-employee directors. The Company determines compensation expense
for awards granted under these plans based on the grant date fair value net of estimated forfeitures, and such expense is recognized on
a straight-line basis over the requisite service period of the award. Refer to the “Stock-Based Compensation” footnote for further
information.
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 2016, 2015 and 2014 were $8 million, $12
million and $9 million, respectively. Employees vest in employer contributions at 20% per year of completed service.
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 that 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, outstanding stock options and contingently issuable shares of convertible debt
to be settled in cash, all using the treasury stock method. In addition, the diluted earnings per share calculation for the year ended
December 31, 2016 considers the effect of convertible debt issued and converted during 2016, using the if-converted method for
periods prior to their actual conversions. When a loss from continuing operations exists, all dilutive securities and 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.
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 tables present 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, 2016 and 2014. For the year ended December 31, 2015, no
individual purchaser accounted for 10% or more of the Company’s total oil, NGL and natural gas sales.
Year Ended December 31, 2016
Tesoro Crude Oil Co
Jamex Marketing LLC
Year Ended December 31, 2014
Plains Marketing LP
Shell Trading US
Bridger Trading LLC
77
15%
12%
17%
10%
10%
Commodity derivative contracts held by the Company are with seven counterparties, all of which are participants in Whiting’s credit
facility as well, and all of which have investment-grade ratings from Moody’s and Standard & Poor’s. As of December 31, 2016,
outstanding derivative contracts with JP Morgan Chase Bank, N.A. and Wells Fargo Bank, N.A. represented 66% and 10%,
respectively, of total crude oil volumes hedged.
Adopted and Recently Issued Accounting Pronouncements—In May 2014, the FASB issued Accounting Standards Update No.
2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The objective of ASU 2014-09 is to clarify the principles for
recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The
FASB subsequently issued ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-12 and ASU 2016-20, which deferred the
effective date of ASU 2014-09 and provided additional implementation guidance. These ASUs are effective for fiscal years, and
interim periods within those years, beginning after December 31, 2017. The standards permit retrospective application using either of
the following methodologies: (i) restatement of each prior reporting period presented or (ii) recognition of a cumulative-effect
adjustment as of the date of initial application. The Company plans to adopt these ASUs effective January 1, 2018. Although the
Company is still in the process of assessing its contracts with customers and evaluating the effect of adopting these standards, as well
as the transition method to be applied, the adoption is not expected to have a significant impact on the Company’s consolidated
financial statements other than additional disclosures.
In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (“ASU 2016-02”). The objective of this ASU
is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and
disclosing key information about leasing arrangements. ASU 2016-02 is effective for fiscal years, and interim periods within those
fiscal years, beginning after December 15, 2018 and should be applied using a modified retrospective approach. Early adoption is
permitted. Although the Company is still in the process of evaluating the effect of adopting ASU 2016-02, the adoption is expected to
result in an increase in the assets and liabilities recorded on its consolidated balance sheet. As of December 31, 2016, the Company
had approximately $97 million of contractual obligations related to its non-cancelable leases, drilling rig contracts and pipeline
transportation agreements, and it will evaluate those contracts as well as other existing arrangements to determine if they qualify for
lease accounting under ASU 2016-02.
In March 2016, the FASB issued Accounting Standards Update No. 2016-09, Improvements To Employee Share-Based Payment
Accounting (“ASU 2016-09”). The objective of this ASU is to simplify several aspects of the accounting for employee share-based
payment transactions, including income tax consequences, classification of awards as either equity or liabilities and classification in
the statement of cash flows. ASU 2016-09 is effective for fiscal years, and interim periods within those fiscal years, beginning after
December 15, 2016. Portions of this ASU must be applied prospectively while other portions may be applied either prospectively or
retrospectively. Early adoption is permitted. The Company does not anticipate that the adoption of ASU 2016-09 will have a
significant impact on its consolidated financial statements, as the Company will record a full valuation allowance on the excess tax
benefits that will be recognized upon adoption of this ASU as a result of the Internal Revenue Code Section 382 limitation that was
triggered in 2016. Refer to the “Income Taxes” footnote for further information.
In November 2016, the FASB issued Accounting Standards Update No. 2016-18, Statement of Cash Flows: Restricted Cash (“ASU
2016-18”). This ASU amends ASC Topic 230, Statement of Cash Flows, to clarify guidance on the classification and presentation of
restricted cash in the statement of cash flows. ASU 2016-18 is effective for fiscal years, and interim periods within those fiscal years,
beginning after December 15, 2017 and must be applied retrospectively. Early adoption is permitted. The Company elected to adopt
ASU 2016-18 as of December 31, 2016 on a retrospective basis, and as a result has included its restricted cash with cash and cash
equivalents in the statement of cash flows. There was no impact to the statements of cash flows for the years ended December 31,
2015 and 2014 as the Company had no restricted cash balances during those periods.
2. OIL AND GAS PROPERTIES
Net capitalized costs related to the Company’s oil and gas producing activities at December 31, 2016 and 2015 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
78
December 31,
2016
3,330,928 $
392,484
9,016,472
490,967
13,230,851
(4,170,237)
9,060,614 $
2015
3,206,237
689,754
9,503,020
505,514
13,904,525
(3,279,156)
10,625,369
$
$
3. ACQUISITIONS AND DIVESTITURES
2016 Acquisitions and Divestitures
In July 2016, the Company completed the sale of its interest in its enhanced oil recovery project in the North Ward Estes field in Ward
and Winkler counties of Texas, including Whiting’s interest in certain CO2 properties in the McElmo Dome field in Colorado and
certain other related assets and liabilities (the “North Ward Estes Properties”) for a cash purchase price of $300 million (before closing
adjustments). The sale was effective July 1, 2016 and resulted in a pre-tax loss on sale of $187 million. The Company used the net
proceeds from the sale to repay a portion of the debt outstanding under its credit agreement.
In addition to the cash purchase price, the buyer has agreed to pay Whiting $100,000 for every $0.01 that, as of June 28, 2018, the
average NYMEX crude oil futures contract price for each month from August 2018 through July 2021 is above $50.00/Bbl up to a
maximum amount of $100 million (the “Contingent Payment”). The Contingent Payment will be made at the option of the buyer
either in cash on July 31, 2018 or in the form of a secured promissory note, accruing interest at 8% per annum with a maturity date of
July 29, 2022. The Company has determined that this Contingent Payment is an embedded derivative and has reflected it at fair value
in the consolidated financial statements. The fair value of the Contingent Payment as of the closing date of this sale transaction was
$39 million. Refer to the “Derivative Financial Instruments” and “Fair Value Measurements” footnotes for more information on this
embedded derivative instrument.
There were no significant acquisitions during the year ended December 31, 2016.
2015 Acquisitions and Divestitures
In December 2015, the Company completed the sale of a fresh water delivery system, a produced water gathering system and four
saltwater disposal wells located in Weld County, Colorado, effective December 16, 2015, for aggregate sales proceeds of $75 million
(before closing adjustments).
In June 2015, the Company completed the sale of its interests in certain non-core oil and gas wells, effective June 1, 2015, for
aggregate sales proceeds of $150 million (before closing adjustments) resulting in a pre-tax loss on sale of $118 million. The
properties included over 2,000 gross wells in 132 fields across 10 states.
In April 2015, the Company completed the sale of its interests in certain non-core oil and gas wells, effective May 1, 2015, for
aggregate sales proceeds of $108 million (before closing adjustments) resulting in a pre-tax gain on sale of $29 million. The
properties were located in 187 fields across 14 states, and predominately consisted of assets that were previously included in the
underlying properties of Whiting USA Trust I.
Also during the year ended December 31, 2015, the Company completed several immaterial divestiture transactions for the sale of its
interests in certain non-core oil and gas wells and undeveloped acreage, for aggregate sales proceeds of $176 million (before closing
adjustments) resulting in a pre-tax gain on sale of $28 million.
There were no significant acquisitions during the year ended December 31, 2015.
2014 Acquisitions
On December 8, 2014, the Company completed the acquisition of Kodiak Oil & Gas Corp. (now known as Whiting Canadian Holding
Company ULC, “Kodiak”), whereby Whiting acquired all of the outstanding common stock of Kodiak (the “Kodiak Acquisition”).
Pursuant to the terms of the Kodiak Acquisition agreement, Kodiak shareholders received 0.177 of a share of Whiting common stock
in exchange for each share of Kodiak common stock they owned. Total consideration for the Kodiak Acquisition was $1.8 billion,
consisting of 47,546,139 Whiting common shares issued at the market price of $37.25 per share on the date of issuance plus the fair
value of Kodiak’s outstanding equity awards assumed by Whiting. The aggregate purchase price of the transaction was $4.3 billion,
which included the assumption of Kodiak’s outstanding debt of $2.5 billion as of December 8, 2014 and the net cash acquired of $19
million.
Kodiak was an independent energy company focused on exploration and production of crude oil and natural gas reserves, primarily in
the Williston Basin region of the United States. As a result of the Kodiak Acquisition, Whiting acquired approximately 327,000 gross
(178,000 net) acres located primarily in North Dakota, including interests in 778 producing oil and gas wells and undeveloped
acreage. Approximately 10,000 of the net acres acquired were located in Wyoming and Colorado.
The Kodiak Acquisition was accounted for using the acquisition method of accounting for business combinations. Transaction costs
relating to the Kodiak Acquisition were expensed as incurred. The allocation of the purchase price has been finalized, and is based
79
upon management’s estimates and assumptions related to the fair value of assets acquired and liabilities assumed on the acquisition
date using currently available information.
The consideration transferred, fair value of assets acquired and liabilities assumed, and the resulting goodwill as of the acquisition date
are as follows (in thousands):
Consideration
Fair value of Whiting’s common stock issued (1)
Fair value of Kodiak restricted stock units assumed by Whiting (2)
Fair value of Kodiak options assumed by Whiting
Total consideration
Fair value of liabilities assumed
Accounts payable trade
Accrued capital expenditures
Revenues and royalties payable
Accrued interest
Accrued liabilities and other
Taxes payable
Long-term debt
Deferred tax liability
Asset retirement obligations
Other long-term liabilities
Amount attributable to liabilities assumed
Fair value of assets acquired
Cash and cash equivalents
Accounts receivable trade, net
Derivative assets
Prepaid expenses and other
Oil and gas properties, successful efforts method:
Proved properties
Unproved properties
Other property and equipment
Deferred tax asset
Other long-term assets
Amount attributable to assets acquired
$
$
$
$
$
1,771,094
9,596
7,523
1,788,213
18,390
97,848
57,423
18,070
43,563
12,807
2,500,875
31,034
8,646
15,735
2,804,391
18,879
215,654
85,718
8,523
2,266,607
1,000,396
11,347
106,758
4,950
3,718,832
873,772
$
$
Goodwill
_____________________
(1) 47,546,139 shares of Whiting common stock at $37.25 per share (closing price as of December 5, 2014), based on Kodiak’s
268,622,497 common shares outstanding at closing.
(2) 257,601 shares of Whiting common stock issued at $37.25 per share (closing price as of December 5, 2014), based on Kodiak’s
1,455,409 restricted stock units held by employees as of December 8, 2014.
Goodwill recognized as a result of the Kodiak Acquisition totaled $874 million, none of which was deductible for income tax
purposes. Goodwill was primarily attributable to the operational and financial synergies expected to be realized from the acquisition,
including the employment of optimized completion techniques on Kodiak's undrilled acreage which improved hydrocarbon recovery,
the realization of savings in drilling and well completion costs, the accelerated development of Kodiak’s asset base, and the
acquisition of experienced oil and gas technical personnel. During the third quarter of 2015, the Company determined that the
goodwill recognized as a result of the Kodiak Acquisition had become fully impaired and wrote its carrying value down to zero. Refer
to the “Fair Value Measurements” footnote for further information regarding goodwill impairment.
80
The changes in the carrying amount of goodwill as of December 31, 2015 are as follows (in thousands):
Balance, January 1, 2015
Adjustments to previously recorded goodwill
Impairment losses
Balance, December 31, 2015
Gross Carrying
Amount
Accumulated
Impairment
Losses
Net Carrying
Amount
$
$
875,676 $
(1,904)
-
873,772 $
- $
-
(873,772)
(873,772) $
875,676
(1,904)
(873,772)
-
The results of operations of Kodiak from the December 8, 2014 closing date through December 31, 2014, representing approximately
$46 million of revenue and $17 million of net income, have been included in Whiting’s consolidated statements of operations for the
year ended December 31, 2014.
2014 Divestitures
In March 2014, the Company completed the sale of approximately 49,900 gross (41,000 net) acres in its Big Tex prospect, which
consisted mainly of undeveloped acreage as well as its interests in certain producing oil and gas wells, located in the Delaware Basin
of Texas for aggregate sales proceeds of $76 million resulting in a pre-tax gain on sale of $12 million.
Unaudited Pro Forma Operating Results
The following unaudited pro forma combined results of operations for the year ended December 31, 2014 are derived from the
historical consolidated financial statements of Whiting and Kodiak and give effect to the Kodiak Acquisition as if it had occurred on
January 1, 2013 (in thousands, except per share data).
Total operating revenues and other income
Net income available to common shareholders
Earnings per common share:
Basic
Diluted
Year Ended
December 31,
2014
$
$
$
$
4,141,046
362,376
2.18
2.17
The unaudited pro forma combined results of operations reflect pro forma adjustments based on available information and certain
assumptions that the Company believes are reasonable, including (i) Whiting common stock and equity awards issued to convert
Kodiak’s outstanding shares of common stock and equity awards as of the closing date of the transaction, (ii) adjustments to conform
Kodiak’s historical policy of accounting for its oil and natural gas properties from the full cost method to the successful efforts method
of accounting, (iii) depletion of Kodiak’s fair-valued proved oil and gas properties, (iv) adjustments to interest expense to reflect the
assumption of Kodiak’s debt by Whiting, and (v) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma
earnings for the year ended December 31, 2014 were adjusted to exclude $86 million of acquisition-related costs incurred by Whiting
and Kodiak.
The unaudited pro forma financial information has been prepared for informational purposes only and does not purport to represent
what Whiting’s results of operations would have been had the transactions actually been consummated on the assumed dates nor are
they indicative of future results of operations. The unaudited pro forma combined financial information does not reflect future events
that may occur after the transactions including, but not limited to, the anticipated realization of ongoing savings from operating
efficiencies from the Kodiak Acquisition.
81
4. LONG-TERM DEBT
Long-term debt consisted of the following at December 31, 2016 and 2015 (in thousands):
Credit agreement
6.5% Senior Subordinated Notes due 2018
5.0% Senior Notes due 2019
1.25% Convertible Senior Notes due 2020
5.75% Senior Notes due 2021
6.25% Senior Notes due 2023
Total principal
Unamortized debt discounts and premiums
Unamortized debt issuance costs on notes
Total long-term debt
December 31,
2016
2015
550,000 $
275,121
961,409
562,075
873,609
408,296
3,630,510
(71,340)
(23,867)
3,535,303 $
800,000
350,000
1,100,000
1,250,000
1,200,000
750,000
5,450,000
(203,082)
(49,214)
5,197,704
$
$
The following table shows five succeeding fiscal years of scheduled maturities for the Company’s long-term debt as of December 31,
2016 (in thousands):
Long-term debt
$
-
$
275,121
$
2017
2018
2019
1,511,409
2020
2021
$
562,075
$
873,609
Credit Agreement
Whiting Oil and Gas, the Company’s wholly-owned subsidiary, has a credit agreement with a syndicate of banks that as of December
31, 2016 had a borrowing base and aggregate commitments of $2.5 billion. As of December 31, 2016, the Company had $1.9 billion
of available borrowing capacity, which was net of $550 million in borrowings and $11 million in letters of credit outstanding.
The borrowing base under the credit agreement is determined at the discretion of the lenders, based on the collateral value of the
Company’s proved reserves that have been mortgaged to such lenders, and is subject to regular redeterminations on May 1 and
November 1 of each year, as well as special redeterminations described in the credit agreement, in each case which may reduce the
amount of the borrowing base. Upon a redetermination of the borrowing base, either on a periodic or special redetermination date, if
borrowings in excess of the revised borrowing capacity were outstanding, the Company could be forced to immediately repay a
portion of its debt outstanding under the credit agreement.
A portion of the revolving credit facility in an aggregate amount not to exceed $50 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, 2016, $39 million was
available for additional letters of credit under the agreement.
The credit agreement provides for interest only payments until December 2019, when the credit agreement expires and all outstanding
borrowings are due. Interest under the revolving credit facility accrues at the Company’s option at either (i) a base rate for a base rate
loan plus the margin in the table below, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.5%
per annum, or an adjusted LIBOR rate plus 1.0% per annum, or (ii) an adjusted LIBOR rate for a Eurodollar loan plus the margin in
the table below. Additionally, the Company also incurs commitment fees as set forth in the table below on the unused portion of the
aggregate commitments of the lenders under the revolving credit facility, which are included as a component of interest expense. At
December 31, 2016 and 2015, the weighted average interest rate on the outstanding principal balance under the credit agreement was
4.0% and 1.9%, respectively.
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
Applicable
Margin for
Commitment
Rate Loans
1.00%
1.25%
1.50%
1.75%
2.00%
Eurodollar Loans
2.00%
2.25%
2.50%
2.75%
3.00%
Fee
0.50%
0.50%
0.50%
0.50%
0.50%
82
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. However, the credit agreement permits the Company and
certain of its subsidiaries to issue second lien indebtedness of up to $1.0 billion subject to certain conditions and limitations. 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 Company’s restricted subsidiaries (as defined in the credit agreement). As of
December 31, 2016, there were no retained earnings free from restrictions. The credit agreement requires the Company, as of the last
day of any quarter, to maintain the following ratios (as defined in the credit agreement): (i) a consolidated current assets to
consolidated current liabilities ratio (which includes an add back of the available borrowing capacity under the credit agreement) of
not less than 1.0 to 1.0, (ii) a total senior secured debt to the last four quarters’ EBITDAX ratio of less than 3.0 to 1.0 during the
Interim Covenant Period (defined below), and thereafter a total debt to EBITDAX ratio of less than 4.0 to 1.0, and (iii) a ratio of the
last four quarters’ EBITDAX to consolidated cash interest charges of not less than 2.25 to 1.0 during the Interim Covenant Period.
Under the credit agreement, the “Interim Covenant Period” is defined as the period from June 30, 2015 until the earlier of (i) April 1,
2018 or (ii) the commencement of an investment-grade debt rating period (as defined in the credit agreement). The Company was in
compliance with its covenants under the credit agreement as of December 31, 2016.
The obligations of Whiting Oil and Gas under the credit agreement are collateralized by a first lien on substantially all of Whiting Oil
and Gas’ and Whiting Resource Corporation’s properties. The Company has guaranteed the obligations of Whiting Oil and Gas under
the credit agreement and has pledged the stock of its subsidiaries as security for its guarantee.
Senior Notes, Convertible Senior Notes and Senior Subordinated Notes
The following table summarizes the material terms of the Company’s senior notes, convertible senior notes and senior subordinated
notes outstanding at December 31, 2016.
2018 Senior
Subordinated
Notes
275,121
6.5%
$
$
Outstanding principal (in thousands) $
Interest rate
Maturity date
Interest payment dates
Make-whole redemption date (1)
_____________________
(1) On or after these dates, the Company may redeem the applicable series of notes, in whole or in part, at a redemption price equal to
100% of the principal amount redeemed, together with accrued and unpaid interest up to the redemption date. At any time prior
to these dates, the Company may redeem the notes at a redemption price that includes an applicable premium as defined in the
indentures to such notes.
Oct 1, 2018
Apr 1, Oct 1
Oct 1, 2016
Apr 1, 2020
Apr 1, Oct 1
N/A (2)
Apr 1, 2023
Apr 1, Oct 1
Jan 1, 2023
$
$
2023
Senior Notes
408,296
6.25%
2021
Senior Notes
873,609
5.75%
Mar 15, 2021
Mar 15, Sep 15
Dec 15, 2020
2019
Senior Notes
961,409
5.0%
Mar 15, 2019
Mar 15, Sep 15
Dec 15, 2018
2020
Convertible
Senior Notes
562,075
1.25%
(2) The indenture governing our 1.25% Convertible Senior Notes due 2020 do not allow for optional redemption by the Company
prior to the maturity date.
Senior Notes and Senior Subordinated Notes—In September 2010, the Company issued at par $350 million of 6.5% Senior
Subordinated Notes due October 2018 (the “2018 Senior Subordinated Notes”).
In September 2013, the Company issued at par $1.1 billion of 5.0% Senior Notes due March 2019 (the “2019 Senior Notes”) and $800
million of 5.75% Senior Notes due March 2021, and issued at 101% of par an additional $400 million of 5.75% Senior Notes due
March 2021 (collectively, the “2021 Senior Notes”). The debt premium recorded in connection with the issuance of the 2021 Senior
Notes is being amortized to interest expense over the term of the notes using the effective interest method, with an effective interest
rate of 5.5% per annum.
In March 2015, the Company issued at par $750 million of 6.25% Senior Notes due April 2023 (the “2023 Senior Notes” and together
with the 2019 Senior Notes and 2021 Senior Notes, the “Senior Notes”).
Exchange of Senior Notes and Senior Subordinated Notes for Convertible Notes. On March 23, 2016, the Company completed the
exchange of $477 million aggregate principal amount of Senior Notes and 2018 Senior Subordinated Notes, consisting of (i) $49
million aggregate principal amount of its 2018 Senior Subordinated Notes, (ii) $97 million aggregate principal amount of its 2019
Senior Notes, (iii) $152 million aggregate principal amount of its 2021 Senior Notes, and (iv) $179 million aggregate principal amount
of its 2023 Senior Notes, for (i) $49 million aggregate principal amount of new 6.5% Convertible Senior Subordinated Notes due 2018
(the “2018 Convertible Senior Subordinated Notes”), (ii) $97 million aggregate principal amount of new 5.0% Convertible Senior
Notes due 2019 (the “2019 Convertible Senior Notes”), (iii) $152 million aggregate principal amount of new 5.75% Convertible
83
Senior Notes due 2021 (the “2021 Convertible Senior Notes”), and (iv) $179 million aggregate principal amount of new 6.25%
Convertible Senior Notes due 2023 (the “2023 Convertible Senior Notes” and together with the 2018 Convertible Senior Subordinated
Notes, the 2019 Convertible Senior Notes and the 2021 Convertible Senior Notes, the “New Convertible Notes”).
The redemption provisions, covenants, interest payments and maturity terms applicable to each series of New Convertible Notes were
substantially identical to those applicable to the corresponding series of Senior Notes and 2018 Senior Subordinated Notes.
This exchange transaction was accounted for as an extinguishment of debt for each portion of the Senior Notes and 2018 Senior
Subordinated Notes that was exchanged. As a result, Whiting recognized a $91 million gain on extinguishment of debt, which is net
of a $4 million non-cash charge for the acceleration of unamortized debt issuance costs and debt premium on the original notes. Each
series of New Convertible Notes was recorded at fair value upon issuance, with the difference between the principal amount of the
notes and their fair values, totaling $95 million, recorded as a debt discount. The aggregate debt discount of $185 million recorded
upon issuance of the New Convertible Notes also included $90 million related to the fair value of the holders’ conversion options,
which were embedded derivatives that met the criteria to be bifurcated from their host contracts and accounted for separately. Refer to
the “Derivative Financial Instruments” and “Fair Value Measurements” footnotes for more information on these embedded
derivatives. The debt discount and transaction costs of $8 million attributable to the New Convertible Notes issuance were being
amortized to interest expense over the respective terms of the notes using the effective interest method.
The New Convertible Notes were convertible, at the option of the holders, into shares of the Company’s common stock at an initial
conversion rate of 86.9565 common shares per $1,000 principal amount of the notes (representing an initial conversion price of $11.50
per share) for the 2018 Convertible Senior Subordinated Notes, the 2021 Convertible Senior Notes and the 2023 Convertible Senior
Notes and an initial conversion rate of 90.9091 common shares per $1,000 principal amount of the notes (representing an initial
conversion price of $11.00 per share) for the 2019 Convertible Senior Notes. Upon exercise of this option, the holder was entitled to
receive an early conversion cash payment as well as a cash payment of all accrued and unpaid interest through the conversion date.
During the second quarter of 2016, holders of the New Convertible Notes voluntarily converted all $477 million aggregate principal
amount of the New Convertible Notes for approximately 41.8 million shares of the Company’s common stock. Upon conversion, the
Company paid $46 million in cash consisting of early conversion payments to the holders of the notes, as well as all accrued and
unpaid interest on such notes. As a result of the conversions, Whiting recognized a $188 million loss on extinguishment of debt,
which consisted of a non-cash charge for the acceleration of unamortized debt issuance costs and debt discount on the notes. As of
June 30, 2016, no New Convertible Notes remained outstanding.
Exchange of Senior Notes and Senior Subordinated Notes for Mandatory Convertible Notes. On July 1, 2016, the Company
completed the exchange of $405 million aggregate principal amount of Senior Notes and 2018 Senior Subordinated Notes for the
same aggregate principal amount of new mandatory convertible senior notes and mandatory convertible senior subordinated notes.
Refer to “Mandatory Convertible Notes” below for more information on these exchange transactions.
Kodiak Senior Notes. In conjunction with the Kodiak Acquisition, Whiting US Holding Company, a wholly-owned subsidiary of the
Company, became a co-issuer of Kodiak’s $800 million of 8.125% Senior Notes due December 2019 (the “2019 Kodiak Notes”),
$350 million of 5.5% Senior Notes due January 2021 (the “2021 Kodiak Notes”), and $400 million of 5.5% Senior Notes due
February 2022 (the “2022 Kodiak Notes” and together with the 2019 Kodiak Notes and the 2021 Kodiak Notes, the “Kodiak Notes”).
In January 2015, Whiting offered to repurchase at 101% of par all $1,550 million principal amount of Kodiak Notes then outstanding.
In March 2015, Whiting paid $760 million to repurchase $2 million aggregate principal amount of the 2019 Kodiak Notes, $346
million aggregate principal amount of the 2021 Kodiak Notes and $399 million aggregate principal amount of the 2022 Kodiak Notes,
which payment consisted of the 101% redemption price and all accrued and unpaid interest on such notes. In May 2015, Whiting paid
an additional $5 million to repurchase the remaining $4 million aggregate principal amount of the 2021 Kodiak Notes and $1 million
aggregate principal amount of the 2022 Kodiak Notes, which payment consisted of the 101% redemption price and all accrued and
unpaid interest on such notes. In December 2015, Whiting paid $834 million to repurchase the remaining $798 million aggregate
principal amount of the 2019 Kodiak Notes, which payment consisted of the 104.063% redemption price and all accrued and unpaid
interest on such notes. As a result of the repurchases, Whiting recognized an $18 million loss on extinguishment of debt, which
consisted of a $40 million cash charge related to the redemption premium on the Kodiak Notes, partially offset by a $22 million non-
cash credit related to the acceleration of unamortized debt premiums on such notes. As of December 31, 2015, no Kodiak Notes
remained outstanding.
Redemption of 2018 Senior Subordinated Notes. On January 3, 2017, the trustee under the indenture governing the 2018 Senior
Subordinated Notes provided notice to the holders of such notes that the Company elected to redeem all of the remaining $275 million
aggregate principal amount of 2018 Senior Subordinated Notes on February 2, 2017, and on that date, Whiting paid $281 million
consisting of the 100% redemption price plus all accrued and unpaid interest on the notes. The Company financed the redemption
with borrowings under its credit agreement.
84
2020 Convertible Senior Notes—In March 2015, the Company issued at par $1,250 million of 1.25% Convertible Senior Notes due
April 2020 (the “2020 Convertible Senior Notes”) for net proceeds of $1.2 billion, net of initial purchasers’ fees of $25 million. On
June 29, 2016, the Company exchanged $129 million aggregate principal amount of its 2020 Convertible Senior Notes for the same
aggregate principal amount of new mandatory convertible senior notes, and on July 1, 2016, the Company exchanged $559 million
aggregate principal amount of its 2020 Convertible Senior Notes for the same aggregate principal amount of new mandatory
convertible senior notes. Refer to “Mandatory Convertible Notes” below for more information on these exchange transactions.
For the remaining $562 million aggregate principal amount of 2020 Convertible Senior Notes, the Company has the option to settle
conversions of these notes with cash, shares of common stock or a combination of cash and common stock at its election. The
Company’s intent is to settle the principal amount of the 2020 Convertible Senior Notes in cash upon conversion. Prior to January 1,
2020, the 2020 Convertible Senior Notes will be convertible at the holder’s option only under the following circumstances: (i) during
any calendar quarter commencing after the calendar quarter ending on June 30, 2015 (and only during such calendar quarter), if the
last reported sale price of the Company’s common stock for at least 20 trading days (whether or not consecutive) during the period of
30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to
130% of the conversion price on each applicable trading day; (ii) during the five business day period after any five consecutive trading
day period (the “measurement period”) in which the trading price per $1,000 principal amount of the 2020 Convertible Senior Notes
for each trading day of the measurement period is less than 98% of the product of the last reported sale price of the Company’s
common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events. On or after
January 1, 2020, the 2020 Convertible Senior Notes will be convertible at any time until the second scheduled trading day
immediately preceding the April 1, 2020 maturity date of the notes. The notes will be convertible at an initial conversion rate of
25.6410 shares of Whiting’s common stock per $1,000 principal amount of the notes, which is equivalent to an initial conversion price
of approximately $39.00. The conversion rate will be subject to adjustment in some events. In addition, following certain corporate
events that occur prior to the maturity date, the Company will increase, in certain circumstances, the conversion rate for a holder who
elects to convert its 2020 Convertible Senior Notes in connection with such corporate event. As of December 31, 2016, none of the
contingent conditions allowing holders of the 2020 Convertible Senior Notes to convert these notes had been met.
Upon issuance, the Company separately accounted for the liability and equity components of the 2020 Convertible Senior Notes. The
liability component was recorded at the estimated fair value of a similar debt instrument without the conversion feature. The
difference between the principal amount of the 2020 Convertible Senior Notes and the estimated fair value of the liability component
was recorded as a debt discount and is being amortized to interest expense over the term of the notes using the effective interest
method, with an effective interest rate of 5.6% per annum. The fair value of the 2020 Convertible Senior Notes as of the issuance date
was estimated at $1.0 billion, resulting in a debt discount at inception of $238 million. The equity component, representing the value
of the conversion option, was computed by deducting the fair value of the liability component from the initial proceeds of the 2020
Convertible Senior Notes issuance. This equity component was recorded, net of deferred taxes and issuance costs, in additional paid-
in capital within shareholders’ equity, and will not be remeasured as long as it continues to meet the conditions for equity
classification.
Transaction costs related to the 2020 Convertible Senior Notes issuance were allocated to the liability and equity components based on
their relative fair values. Issuance costs attributable to the liability component were recorded as a reduction to the carrying value of
long-term debt on the consolidated balance sheet and are being amortized to expense over the term of the notes using the effective
interest method. Issuance costs attributable to the equity component were recorded as a charge to additional paid-in capital within
shareholders’ equity.
The 2020 Convertible Senior Notes consist of the following at December 31, 2016 and 2015 (in thousands):
Liability component
Principal
Less: unamortized note discount
Less: unamortized debt issuance costs
Net carrying value
Equity component (1)
December 31,
2016
2015
$
$
$
562,075 $
(72,622)
(5,988)
483,465 $
136,522 $
1,250,000
(205,572)
(17,277)
1,027,151
237,500
(1) Recorded in additional paid-in capital, net of $5 million of issuance costs and $50 million of deferred taxes as of December 31,
2016 and $5 million of issuance costs and $88 million of deferred taxes as of December 31, 2015.
Interest expense recognized on the 2020 Convertible Senior Notes related to the stated interest rate and amortization of the debt
discount totaled $43 million and $44 million for the years ended December 31, 2016 and 2015, respectively.
85
Mandatory Convertible Notes—On June 29, 2016, the Company completed the exchange of $129 million aggregate principal amount
of its 2020 Convertible Senior Notes for the same aggregate principal amount of new 1.25% Mandatory Convertible Senior Notes due
2020, Series 2 (the “2020 Mandatory Convertible Notes, Series 2”). On July 1, 2016, the Company completed the exchange of $964
million aggregate principal amount of Senior Notes, 2020 Convertible Senior Notes and 2018 Senior Subordinated Notes, consisting
of (i) $26 million aggregate principal amount of 2018 Senior Subordinated Notes, (ii) $42 million aggregate principal amount of 2019
Senior Notes, (iii) $559 million aggregate principal amount of 2020 Convertible Senior Notes, (iv) $174 million aggregate principal
amount of 2021 Senior Notes, and (v) $163 million aggregate principal amount of 2023 Senior Notes, for (i) $26 million aggregate
principal amount of new 6.5% Mandatory Convertible Senior Subordinated Notes due 2018 (the “2018 Mandatory Convertible
Notes”), (ii) $42 million aggregate principal amount of new 5.0% Mandatory Convertible Senior Notes due 2019 (the “2019
Mandatory Convertible Notes”), (iii) $559 million aggregate principal amount of new 1.25% Mandatory Convertible Senior Notes due
2020, Series 1 (the “2020 Mandatory Convertible Notes, Series 1”, and together with the 2020 Mandatory Convertible Notes, Series 2,
the “2020 Mandatory Convertible Notes”), (iv) $174 million aggregate principal amount of new 5.75% Mandatory Convertible Senior
Notes due 2021 (the “2021 Mandatory Convertible Notes”), and (v) $163 million aggregate principal amount of new 6.25%
Mandatory Convertible Senior Notes due 2023 (the “2023 Mandatory Convertible Notes” and, together with the 2018 Mandatory
Convertible Notes, the 2019 Mandatory Convertible Notes, the 2020 Mandatory Convertible Notes and the 2021 Mandatory
Convertible Notes, the “Mandatory Convertible Notes”).
The redemption provisions, covenants, interest payments and maturity terms applicable to each series of Mandatory Convertible Notes
were substantially identical to those applicable to the corresponding series of Senior Notes, 2020 Convertible Senior Notes and 2018
Senior Subordinated Notes.
These transactions were accounted for as extinguishments of debt for the portions of Senior Notes, 2020 Convertible Senior Notes and
2018 Senior Subordinated Notes that were exchanged. As a result, Whiting recognized a $57 million gain on extinguishment of debt,
which was net of a $113 million charge for the non-cash write-off of unamortized debt issuance costs, debt discounts and debt
premium on the original notes. In addition, Whiting recorded a $63 million reduction to the equity component of the 2020
Convertible Senior Notes, which was net of deferred taxes. The Mandatory Convertible Notes were recorded at fair value upon
issuance with the difference between the principal amount of the notes and their fair values, totaling $69 million, recorded as a debt
discount. The Mandatory Convertible Notes contained contingent beneficial conversion features, the intrinsic value of which was
recognized in additional paid-in capital at the time the contingency was resolved, resulting in an additional debt discount of $233
million. The aggregate debt discount of $302 million was being amortized to interest expense over the respective terms of the notes
using the effective interest method.
Transaction costs of $14 million attributable to these note issuances were recorded as a reduction to the carrying value of long-term
debt on the consolidated balance sheet and were being amortized to interest expense over the respective terms of the notes using the
effective interest method.
The July 1, 2016 note exchange transactions triggered an ownership shift as defined under Section 382 of the Internal Revenue Code
due to the “deemed share issuance” that resulted from the note exchanges. This triggering event will limit the Company’s usage of
certain of its net operating losses and tax credits in the future. Refer to the “Income Taxes” footnote for more information.
The Mandatory Convertible Notes contained mandatory conversion features whereby four percent of the aggregate principal amount
of the Mandatory Convertible Notes were converted into shares of the Company’s common stock for each day of the 25 trading day
period that commenced on June 23, 2016 (the “Observation Period”) if the daily volume weighted average price (the “Daily VWAP”)
(as defined in the indentures governing the Mandatory Convertible Notes) of the Company’s common stock on such day, rounded to
four decimal places for the 2020 Mandatory Convertible Notes and rounded to two decimal places for the 2018 Mandatory
Convertible Notes, the 2019 Mandatory Convertible Notes, the 2021 Mandatory Convertible Notes and the 2023 Mandatory
Convertible Notes, was above $8.75 (the “Threshold Price”). Upon conversion, the common stock issue price per share was equal to
the higher of (i) the Daily VWAP for the Company’s common stock for such trading day multiplied by one plus zero for the 2018
Mandatory Convertible Notes, one plus 0.5% for the 2019 Mandatory Convertible Notes, one plus 8.0% for the 2020 Mandatory
Convertible Notes, one plus 2.5% for the 2021 Mandatory Convertible Notes and one plus 3.5% for the 2023 Mandatory Convertible
Notes or (ii) $8.75 for the 2018 Mandatory Convertible Notes (equivalent to 114.29 common shares per $1,000 principal amount of
the notes), $8.79 for the 2019 Mandatory Convertible Notes (equivalent to 113.72 common shares per $1,000 principal amount of the
notes), $9.45 for the 2020 Mandatory Convertible Notes (equivalent to 105.82 common shares per $1,000 principal amount of the
notes), $8.97 for the 2021 Mandatory Convertible Notes (equivalent to 111.50 common shares per $1,000 principal amount of the
notes) and $9.06 for the 2023 Mandatory Convertible Notes (equivalent to 110.42 common shares per $1,000 principal amount of the
notes) (the “Minimum Conversion Prices”).
After the Observation Period, the Company had the right, which the Company exercised on December 9, 2016 as noted below, to
mandatorily convert any remaining Mandatory Convertible Notes if the Daily VWAP of the Company’s common stock exceeded
$8.75 for at least 20 trading days during a 30 consecutive trading day period and holders had the right to convert the Mandatory
86
Convertible Notes at any time. The conversion price after the Observation Period was the Minimum Conversion Price for each
applicable series of Mandatory Convertible Notes.
During the Observation Period, the Daily VWAP of the Company’s common stock was above the Threshold Price (i) for 7 of the 25
trading days for the 2018 Mandatory Convertible Notes, the 2019 Mandatory Convertible Notes, the 2021 Mandatory Convertible
Notes and the 2023 Mandatory Convertible Notes and (ii) for 8 of the 25 trading days for the 2020 Mandatory Convertible Notes. As
a result, $333 million aggregate principal amount of the Mandatory Convertible Notes were converted into approximately 33.2 million
shares of the Company’s common stock, and the Company paid $3 million in cash consisting of all accrued and unpaid interest on
such notes. As a result of the conversions, Whiting recognized a $3 million gain on extinguishment of debt, which was net of a non-
cash charge for the acceleration of unamortized debt issuance costs and debt discount on the notes.
On August 12, 2016, the Company completed the exchange of (i) $13 million aggregate principal amount of the 2018 Mandatory
Convertible Notes which had a conversion price of $8.75 per share (equivalent to 114.29 common shares per $1,000 principal amount
of the notes) for shares of the Company’s common stock at an issuance price of $7.77 per share (equivalent to 128.69 common shares
per $1,000 principal amount of the notes) and (ii) $25 million aggregate principal amount of the 2019 Mandatory Convertible Notes
which had a conversion price of $8.79 per share (equivalent to 113.72 common shares per $1,000 principal amount of the notes) for
shares of the Company’s common stock at an issuance price of $7.80 per share (equivalent to 128.17 shares per $1,000 principal
amount of the notes). Upon acceptance of this inducement offer by the holders of the notes, such notes were immediately cancelled in
exchange for approximately 4.9 million shares of the Company’s common stock and the Company paid $1 million in cash consisting
of all accrued and unpaid interest on such notes. As a result of the exchanges, Whiting recognized (i) $4 million of debt inducement
expense related to the fair value of the incremental shares issued in the inducement offer over the original conversion terms of the
notes, which expense is included in loss on extinguishment of debt in the consolidated statements of operations, and (ii) a $14 million
non-cash charge for the acceleration of unamortized debt discount on the notes, which is included in interest expense in the
consolidated statements of operations.
During the fourth quarter of 2016, the Daily VWAP of the Company’s common stock was above $8.75 for 20 trading days during a 30
consecutive trading day period. As a result, on December 9, 2016, the Company provided notice to the holders of the remaining $721
million aggregate principal amount of the Mandatory Convertible Notes of its intent to exercise its right to convert such notes on
December 19, 2016 pursuant to the terms of the indentures. The notes were subsequently converted into approximately 77.6 million
shares of the Company’s common stock, and upon conversion, the Company paid $5 million in cash consisting of all accrued and
unpaid interest on such notes. As a result of the conversions, Whiting recognized a $244 million non-cash charge for the acceleration
of unamortized debt discounts on the notes, which is included in interest expense in the consolidated statements of operations. As of
December 31, 2016, no Mandatory Convertible Notes remained outstanding.
Security and Guarantees
The Senior Notes and the 2020 Convertible Senior Notes are unsecured obligations of Whiting Petroleum Corporation and these
unsecured obligations are subordinated to all of the Company’s secured indebtedness, which consists of Whiting Oil and Gas’ credit
agreement. The 2018 Senior Subordinated Notes are also unsecured obligations of Whiting Petroleum Corporation and are
subordinated to all of the Company’s senior debt, which currently consists of the Senior Notes, the 2020 Convertible Senior Notes and
borrowings under Whiting Oil and Gas’ credit agreement.
The Company’s obligations under the Senior Notes, the 2020 Convertible Senior Notes and the 2018 Senior Subordinated Notes are
guaranteed by the Company’s 100%-owned subsidiaries, Whiting Oil and Gas, Whiting US Holding Company, Whiting Canadian
Holding Company ULC and Whiting Resources Corporation (the “Guarantors”). These guarantees are full and unconditional and
joint and several among the Guarantors. Any subsidiaries other than these Guarantors are minor subsidiaries as defined by Rule 3-
10(h)(6) of Regulation S-X of the SEC. Whiting Petroleum Corporation has no assets or operations independent of this debt and its
investments in its consolidated subsidiaries.
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 current portions
at December 31, 2016 and 2015 were $8 million and $6 million, respectively, and have been included in accrued liabilities and other.
The following table provides a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2016
and 2015 (in thousands):
87
Asset retirement obligation at January 1
Additional liability incurred
Revisions to estimated cash flows (1)
Accretion expense
Obligations on sold properties and assets held for sale
Liabilities settled
Asset retirement obligation at December 31
December 31,
2016
2015
161,908 $
3,238
11,620
13,800
(4,771)
(8,791)
177,004 $
179,931
9,208
29,307
20,274
(69,601)
(7,211)
161,908
$
$
(1) Revisions to estimated cash flows during the year ended December 31, 2016 and 2015 are primarily attributable to the
acceleration in the estimated timing of abandonment of a large number of our producing properties resulting from decreases in
commodity prices used in the calculation of the Company’s reserves as of December 31, 2016 and 2015, respectively, which
shortened the economic lives of these properties. For the year ended December 31, 2016, the increase was partially offset by
decreases in the estimates of future costs required to plug and abandon wells in certain fields in the Central and Northern Rocky
Mountains.
6. DERIVATIVE FINANCIAL INSTRUMENTS
The Company is exposed to certain risks relating to its ongoing business operations, and it uses derivative instruments to manage its
commodity price risk. In addition, the Company periodically enters into contracts that contain embedded features which are required
to be bifurcated and accounted for separately as derivatives.
Commodity Derivative Contracts—Historically, prices received for crude oil and natural gas production have been volatile because of
supply and demand factors, worldwide political factors, general economic conditions and seasonal weather patterns. Whiting enters
into derivative contracts such as costless collars, swaps and crude oil sales and delivery contracts to achieve a more predictable cash
flow by reducing its exposure to commodity price volatility. Commodity derivative contracts are thereby used to ensure adequate cash
flow to fund the Company’s capital programs and to manage returns on drilling programs and acquisitions. The Company does not
enter into derivative contracts for speculative or trading purposes.
Crude Oil Costless Collars. Costless collars are designed to establish floor and ceiling prices on 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 table below details the Company’s costless collar derivatives entered into to hedge forecasted crude oil production revenues as of
December 31, 2016.
Derivative
Instrument
Three-way collars (1) (2)
Collars
Whiting Petroleum Corporation
Period
Jan - Dec 2017
Jan - Dec 2018
Jan - Dec 2017
Total
Contracted Crude
Oil Volumes (Bbl)
12,000,000
2,400,000
3,000,000
17,400,000
Weighted Average NYMEX Price
Collar Ranges for Crude Oil (per Bbl)
$34.50 - $44.75 - $60.01
$40.00 - $50.00 - $61.40
$53.00 - $70.44
_____________________
(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.
(2) Subsequent to year-end, the Company entered into additional three-way collar contracts for 600,000 Bbl of crude oil volumes for
the year ended December 31, 2017.
Crude Oil Sales and Delivery Contract. The Company has a long-term crude oil sales and delivery contract for oil volumes produced
from its Redtail field in Colorado. Under the terms of the agreement, Whiting has committed to deliver certain fixed volumes of crude
oil through April 2020. The Company determined that it was not probable that future oil production from its Redtail field would be
sufficient to meet the minimum volume requirements specified in this contract, and accordingly, that the Company would not settle
this contract through physical delivery of crude oil volumes. As a result, Whiting determined that this contract would not qualify for
the “normal purchase normal sale” exclusion and has therefore reflected the contract at fair value in the consolidated financial
88
statements. As of December 31, 2016 and 2015, the estimated fair value of this derivative contract was a liability of $9 million and
$4 million, respectively.
Embedded Derivatives—In March 2016, the Company issued convertible notes that contained debtholder conversion options which
the Company determined were not clearly and closely related to the debt host contracts, and the Company therefore bifurcated these
embedded features and reflected them at fair value in the consolidated financial statements. During the second quarter of 2016, the
entire aggregate principal amount of these notes was converted into shares of the Company’s common stock, and the fair value of
these embedded derivatives as of December 31, 2016 was therefore zero.
In July 2016, the Company entered into a purchase and sale agreement with the buyer of its North Ward Estes Properties, whereby the
buyer has agreed to pay Whiting additional proceeds of $100,000 for every $0.01 that, as of June 28, 2018, the average NYMEX
crude oil futures contract price for each month from August 2018 through July 2021 is above $50.00/Bbl up to a maximum amount of
$100 million. The Company has determined that this NYMEX-linked Contingent Payment is not clearly and closely related to the
host contract, and the Company therefore bifurcated this embedded feature and reflected it at fair value in the consolidated financial
statements. As of December 31, 2016, the estimated fair value of this embedded derivative was an asset of $51 million.
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 or other derivative scope exceptions. The
following table summarizes the effects of derivative instruments on the consolidated statements of operations for the years ended
December 31, 2016, 2015 and 2014 (in thousands):
Not Designated as
ASC 815 Hedges
Commodity contracts
Embedded derivatives
Total
Statement of Operations
Classification
Derivative gain, net
Derivative gain, net
$
$
(Gain) Loss Recognized in Income
Year Ended December 31,
2015
(217,972) $
2016
58,771 $
(59,358)
-
(587) $
(217,972) $
2014
(136,995)
36,416
(100,579)
Offsetting of Derivative Assets and Liabilities. The Company nets its financial derivative instrument fair value amounts executed with
the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the
event of default or termination of the contract. The following tables summarize the location and fair value amounts of all the
Company’s 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
Derivative assets
Commodity contracts - current
Commodity contracts - non-current
Other long-term assets
Embedded derivatives - non-current Other long-term assets
Total derivative assets
Derivative liabilities:
Commodity contracts - current
Commodity contracts - non-current
Total derivative liabilities
Accrued liabilities and other
Other long-term liabilities
December 31, 2016 (1)
Gross
Recognized
Assets/
Liabilities
Gross
Amounts
Offset
Net
Recognized
Fair Value
Assets/
Liabilities
$
$
$
$
21,405 $
9,495
50,632
81,532 $
39,033 $
19,724
58,757 $
(21,405) $
(9,495)
-
(30,900) $
(21,405) $
(9,495)
(30,900) $
-
-
50,632
50,632
17,628
10,229
27,857
89
Not Designated as
ASC 815 Hedges
Derivative assets:
Balance Sheet Classification
December 31, 2015 (1)
Gross
Recognized
Assets/
Liabilities
Gross
Amounts
Offset
Net
Recognized
Fair Value
Assets/
Liabilities
Commodity contracts - current
Commodity contracts - non-current
Derivative assets
Other long-term assets
Total derivative assets
Derivative liabilities:
Commodity contracts - current
Commodity contracts - non-current
Total derivative liabilities
Accrued liabilities and other
Other long-term liabilities
$
$
$
$
258,778 $
31,415
290,193 $
(100,049) $
(3,465)
(103,514) $
158,729
27,950
186,679
101,214 $
6,327
107,541 $
(100,049) $
(3,465)
(103,514) $
1,165
2,862
4,027
_____________________
(1) Because counterparties to the Company’s financial derivative contracts subject to master netting arrangements 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 these tables.
Contingent Features in Financial Derivative Instruments. None of the Company’s derivative instruments contain credit-risk-related
contingent features. Counterparties to the Company’s financial derivative contracts are high credit-quality financial institutions that
are lenders under Whiting’s credit agreement. The Company uses only credit agreement participants to hedge with, since these
institutions are secured equally with the holders of Whiting’s bank debt, which eliminates the potential need to post collateral when
Whiting is in a derivative liability position. As a result, the Company is not required to post letters of credit or corporate guarantees
for its 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.
Cash, cash equivalents, restricted cash, accounts receivable and accounts 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 and the applicable margins represent market
rates.
90
The Company’s senior notes and senior subordinated notes are recorded at cost, and the Company’s convertible senior notes are
recorded at fair value at the date of issuance. The following table summarizes the fair values and carrying values of these instruments
as of December 31, 2016 and 2015 (in thousands):
6.5% Senior Subordinated Notes due 2018
5.0% Senior Notes due 2019
1.25% Convertible Senior Notes due 2020
5.75% Senior Notes due 2021
6.25% Senior Notes due 2023
Total
December 31, 2016
Fair
Value (1)
Carrying
Value (2)
December 31, 2015
Fair
Value (1)
Carrying
Value (2)
$
$
275,121 $
961,409
503,057
868,149
408,296
3,016,032 $
273,506 $
956,607
483,465
868,460
403,265
2,985,303 $
265,125 $
830,500
850,000
870,000
543,750
3,359,375 $
346,876
1,092,219
1,027,151
1,191,861
739,597
4,397,704
(1) Fair values are based on quoted market prices for these debt securities, and such fair values are therefore designated as Level 1
within the valuation hierarchy.
(2) Carrying values are presented net of unamortized debt issuance costs and debt discounts or premiums.
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 counterparty, as appropriate. 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, 2016 and 2015, and indicate the fair
value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands):
Financial Assets
Commodity derivatives – current
Commodity derivatives – non-current
Embedded derivatives – non-current
Total financial assets
Financial Liabilities
Commodity derivatives – current
Commodity derivatives – non-current
Total financial liabilities
Financial Assets
Commodity derivatives – current
Commodity derivatives – non-current
Total financial assets
Financial Liabilities
Commodity derivatives – current
Commodity derivatives – non-current
Total financial liabilities
Level 1
Level 2
Level 3
Total Fair Value
December 31, 2016
- $
-
-
- $
- $
-
- $
- $
-
50,632
50,632 $
- $
-
-
- $
14,664 $
3,979
18,643 $
2,964 $
6,250
9,214 $
-
-
50,632
50,632
17,628
10,229
27,857
Level 1
Level 2
Level 3
Total Fair Value
December 31, 2015
- $
-
- $
158,729 $
27,950
186,679 $
- $
-
- $
- $
-
- $
- $
-
- $
1,165 $
2,862
4,027 $
158,729
27,950
186,679
1,165
2,862
4,027
$
$
$
$
$
$
$
$
The following methods and assumptions were used to estimate the fair values of the Company’s financial assets and liabilities that are
measured on a recurring basis:
Commodity Derivatives. Commodity derivative instruments consist mainly of costless collars for crude oil. The Company’s costless
collars are valued based on an income approach. The option model considers 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.
91
In addition, the Company has a long-term crude oil sales and delivery contract, whereby it has committed to deliver certain fixed
volumes of crude oil through April 2020. Whiting has determined that the contract does not meet the “normal purchase normal sale”
exclusion, and has therefore reflected this contract at fair value in its consolidated financial statements. This commodity derivative
was valued based on an income approach which considers various assumptions, including quoted forward prices for commodities,
market differentials for crude oil, U.S. Treasury rates and either the Company’s or the counterparty’s nonperformance risk, as
appropriate. The assumptions used in the valuation of the crude oil sales and delivery contract include certain market differential
metrics that were unobservable during the term of the contract. Such unobservable inputs were significant to the contract valuation
methodology, and the contract’s fair value was therefore designated as Level 3 within the valuation hierarchy.
Embedded Derivatives. The Company had embedded derivatives related to its convertible notes that were issued in March 2016. The
notes contained debtholder conversion options which the Company determined were not clearly and closely related to the debt host
contracts and the Company therefore bifurcated these embedded features and reflected them at fair value in the consolidated financial
statements. Prior to their settlements, the fair values of these embedded derivatives were determined using a binomial lattice model
which considered various inputs including (i) Whiting’s common stock price, (ii) risk-free rates based on U.S. Treasury rates, (iii)
recovery rates in the event of default, (iv) default intensity, and (v) volatility of Whiting’s common stock. The expected volatility and
default intensity used in the valuation were unobservable in the marketplace and significant to the valuation methodology, and the
embedded derivatives’ fair value was therefore designated as Level 3 in the valuation hierarchy. During the second quarter of 2016,
the entire aggregate principal amount of these convertible notes was converted into shares of the Company’s common stock, and these
embedded derivatives were thereby settled in their entirety as of June 30, 2016.
The Company has an embedded derivative related to its purchase and sale agreement with the buyer of the North Ward Estes
Properties. The agreement includes a Contingent Payment linked to NYMEX crude oil prices which the Company has determined is
not clearly and closely related to the host contract, and the Company therefore bifurcated this embedded feature and reflected it at fair
value in the consolidated financial statements. The fair value of this embedded derivative was determined using a modified Black-
Scholes swaption pricing model which considers various assumptions, including quoted forward prices for commodities, time value
and volatility factors. These assumptions are observable in the marketplace throughout the full term of the financial instrument, 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 rate used in the fair value of this instrument includes a
measure of the counterparty’s nonperformance risk.
Level 3 Fair Value Measurements—A third-party valuation specialist is utilized to determine the fair value of the Company’s
derivative instruments designated as Level 3. The Company reviews these valuations, including the related model inputs and
assumptions, and analyzes changes in fair value measurements between periods. The Company corroborates such inputs, calculations
and fair value changes using various methodologies, and reviews unobservable inputs for reasonableness utilizing relevant information
from other published sources.
The following table presents a reconciliation of changes in the fair value of financial assets or liabilities designated as Level 3 in the
valuation hierarchy for the years ended December 31, 2016 and 2015 (in thousands):
Fair value asset (liability), beginning of period
Recognition of embedded derivatives associated with convertible note issuances
Unrealized gains on embedded derivatives included in earnings (1)
Settlement of embedded derivatives upon conversion of convertible notes
Unrealized losses on commodity derivative contracts included in earnings (1)
Settlement of commodity derivative contracts
Transfers into (out of) Level 3
Fair value liability, end of period
_____________________
(1) Included in derivative gain, net in the consolidated statements of operations.
Year Ended
December 31,
2016
2015
(4,027) $
(89,884)
47,965
41,919
(5,187)
-
-
(9,214) $
53,530
-
-
-
(24,018)
(33,539)
-
(4,027)
$
$
Quantitative Information about Level 3 Fair Value Measurements. The significant unobservable inputs used in the fair value
measurement of the Company’s commodity derivative instrument designated as Level 3 are as follows:
Derivative Instrument
Commodity derivative contract
Valuation Technique
Income approach
Unobservable Input
Market differential for crude oil
Amount
$4.91 per Bbl
92
Sensitivity to Changes In Significant Unobservable Inputs. As presented above, the significant unobservable inputs used in the fair
value measurement of Whiting’s commodity derivative contract are the market differentials for crude oil over the term of the contract.
Significant increases or decreases in these unobservable inputs in isolation would result in a significantly higher or lower, respectively,
fair value liability measurement.
Non-recurring Fair Value Measurements—The Company applies the provisions of the fair value measurement standard on a non-
recurring basis to its non-financial assets and liabilities, including proved property and goodwill. 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 Company did
not recognize any impairment write-downs with respect to its proved property or goodwill during the year ended December 31, 2016.
The following table presents information about the Company’s non-financial assets measured at fair value on a non-recurring basis for
the year ended December 31, 2015, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to
determine such fair value (in thousands):
Loss (Before
Tax) Year
Ended
December 31,
2015
1,602,226
873,772
2,475,998
Net Carrying
Value as of
September 30,
2015
Fair Value Measurements Using
Level 2
Level 1
Level 3
-
$
$
531,775 $
531,775 $
- $
-
- $
Proved property (1)
Goodwill (2)
Total non-recurring assets at fair value
_____________________
(1) During the third quarter of 2015, proved oil and gas properties with a previous carrying amount of $2.1 billion were written down
to their fair value as of September 30, 2015 of $531 million, resulting in a non-cash impairment charge of $1.5 billion which was
recorded within exploration and impairment expense. The impaired properties consisted of the North Ward Estes field in Texas
and other non-core proved oil and gas properties primarily in Texas, Wyoming, North Dakota and Colorado that were not being
developed due to depressed oil and gas prices. Also during the third quarter of 2015, proved CO2 properties at the Bravo Dome
field in New Mexico and the McElmo Dome field in Colorado with a previous carrying amount of $63 million were written down
to their fair value as of September 30, 2015 of $1 million, resulting in a non-cash impairment charge of $62 million which was
also recorded within exploration and impairment expense.
- $
-
- $
531,775 $
531,775 $
-
(2) During 2015, goodwill related to the Kodiak Acquisition with a carrying amount of $874 million was written down to its fair
value of zero, resulting in a non-cash impairment charge of $874 million which was recorded as a separate line in the consolidated
statements of operations.
The following methods and assumptions were used to estimate the fair values of the non-financial assets in the table above:
Proved Property Impairments. The Company tests proved property for impairment whenever events or changes in circumstances
indicate that the fair value of these assets may be reduced below their carrying value. As a result of the significant decrease in the
forward price curves for crude oil and natural gas during the third quarter of 2015, and the associated decline in oil and gas reserves
over that same period, the Company performed a proved property impairment test as of September 30, 2015. The fair value was
ascribed using income approach analyses based on the net discounted future cash flows from the producing property and a market
approach analysis, which approaches were probability-weighted. The discounted cash flows were based on management’s
expectations for the future. Unobservable inputs included estimates of future oil and gas or CO2 production, as the case may be, from
the Company’s reserve reports, commodity prices based on sales contract terms or forward price curves (adjusted for basis
differentials), operating and development costs, and a discount rate based on the Company’s weighted-average cost of capital (all of
which were designated as Level 3 inputs within the fair value hierarchy). The impairment test indicated that a proved property
impairment had occurred, and the Company therefore recorded a non-cash impairment charge to reduce the carrying value of the
impaired property to its fair value at the measurement date.
Goodwill Impairment. The Company tested goodwill for impairment annually in the second quarter or whenever events or changes in
circumstances indicated that the fair value of its reporting unit may have been reduced below its carrying value. The Company
performed its annual goodwill impairment test as of June 30, 2015, and determined that no impairment had occurred. However, as a
result of a sustained decrease in the price of Whiting’s common stock during the third quarter of 2015 caused by a significant decline
in crude oil and natural gas prices over that same period, the Company performed another goodwill impairment test as of September
30, 2015. The fair value of the Company’s reporting unit was ascribed using an income approach analysis based on the Company’s
net discounted future cash flows and a market approach analysis. The discounted cash flows were based on management’s
expectations for the future. Unobservable inputs included estimates of future oil and gas production from the Company’s reserve
reports, commodity prices based on sales contract terms or forward price curves (adjusted for basis differentials), operating and
development costs, and a discount rate based on the Company’s weighted-average cost of capital (all of which were designated as
93
Level 3 inputs within the fair value hierarchy). The impairment test performed by the Company indicated that the fair value of its
reporting unit was less than its carrying amount, and further that there was no remaining implied fair value attributable to goodwill.
Based on these results, the Company recorded a non-cash impairment charge to reduce the carrying value of goodwill to zero.
8. SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST
Common Stock—In May 2016, Whiting’s shareholders approved an amendment to the Company’s Restated Certificate of
Incorporation to increase the number of authorized shares of common stock from 300,000,000 to 600,000,000 shares.
Common Stock Offering. In March 2015, the Company completed a public offering of its common stock, selling 35,000,000 shares of
common stock at a price of $30.00 per share and providing net proceeds of approximately $1.0 billion after underwriter’s fees. In
addition, the Company granted the underwriter a 30-day option to purchase up to an additional 5,250,000 shares of common stock.
On April 1, 2015, the underwriter exercised its right to purchase an additional 2,000,000 shares of common stock, providing additional
net proceeds of $61 million.
Noncontrolling Interest—The Company’s 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 beginning of period
Net loss
Balance at end of period
9. STOCK-BASED COMPENSATION
Year Ended
December 31,
2016
2015
$
$
7,984 $
(22)
7,962 $
8,070
(86)
7,984
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 included 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 and any shares forfeited under the 2013 Equity Plan will be available for future
issuance under the 2013 Equity Plan. However, shares netted for tax withholding under the 2013 Equity Plan will be cancelled and
will not be available for future issuance. On December 8, 2014, the Company increased the number of shares issuable under the 2013
Equity Plan by 978,161 shares to accommodate for the conversion of Kodiak’s outstanding equity awards to Whiting equity awards
upon closing of the Kodiak Acquisition. Any shares netted or forfeited under this increased availability will be cancelled and will not
be available for future issuance under the 2013 Equity Plan. At the Company’s 2016 Annual Meeting held on May 17, 2016,
shareholders approved an amendment and restatement of the 2013 Equity Plan which increased the total number of shares issuable
under the plan by 5,500,000 and revised certain award limits for employees and non-employee directors. Under the amended and
restated 2013 Equity Plan, no employee or officer participant may be granted options for more than 900,000 shares of common stock,
stock appreciation rights relating to more than 900,000 shares of common stock, or more than 600,000 shares of restricted stock
during any calendar year. In addition, no non-employee director participant may be granted options for more than 100,000 shares of
common stock, stock appreciation rights relating to more than 100,000 shares of common stock, or more than 100,000 shares of
restricted stock during any calendar year. As of December 31, 2016, 6,333,174 shares of common stock remained available for grant
under the amended 2013 Equity Plan.
Equity Awards Assumed in Kodiak Acquisition—Upon closing of the Kodiak Acquisition, the Company assumed all of Kodiak’s
outstanding equity awards, including restricted stock awards, restricted stock units and stock options. Kodiak’s outstanding equity
awards held by employees were converted into Whiting’s equity awards using a conversion ratio of 0.177. The outstanding restricted
stock awards and restricted stock units vested upon closing of the transaction, and the $10 million estimated fair value as of the
closing date of the 257,601 shares of Whiting common stock issued to convert these awards was recorded as part of the purchase
consideration.
The estimated fair value as of the closing date of the 673,235 Whiting options issued in exchange for Kodiak’s outstanding options
was approximately $8 million, based on a Black-Scholes option-pricing model. Of this value, approximately $7 million was
attributable to service rendered prior to the date of acquisition and was recorded as part of the purchase consideration, and the
remaining $1 million will be expensed over the remaining service term of the replacement stock option awards. The unvested stock
option awards will vest over a one to three-year service period from the grant date and are exercisable immediately upon vesting
94
through the tenth anniversary of the grant date. The following table summarizes the assumptions used to estimate the fair value of
stock options assumed in the Kodiak Acquisition:
Risk-free interest rate
Expected volatility
Expected term
Dividend yield
2014
0.08% -1.90%
40.3% - 49.7%
2.0 yrs. - 6.1 yrs.
-
The weighted average fair value of these options, as determined by the Black-Scholes valuation model, was $12.20 per share as of the
December 8, 2014 closing date of the Kodiak Acquisition.
Restricted Shares—The Company grants service-based restricted stock awards to executive officers and employees, which generally
vest ratably over a three-year service period, and to directors, which generally vest over a one-year service period. In addition, the
Company grants restricted stock awards to executive officers that are subject to market-based vesting criteria as well as a three-year
service period. The Company uses historical data and projections to estimate expected employee behaviors related to restricted stock
forfeitures. The expected forfeitures are then included as part of the grant date estimate of compensation cost. The Company
recognizes compensation expense for all awards subject to market-based vesting 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 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. The weighted average grant date fair value of service-based restricted stock awards was $6.95 per
share, $30.93 per share and $60.22 per share for the years ended December 31, 2016, 2015, and 2014, respectively.
In January 2016 and 2015, 1,073,143 shares and 391,773 shares, respectively of restricted stock subject to certain market-based
vesting criteria were granted to executive officers under the 2013 Equity Plan. These market-based awards cliff vest on the third
anniversary of the grant date, and the number of shares that will vest at the end of that three-year performance period will be
determined based on the rank of Whiting’s cumulative stockholder return compared to the stockholder return of a peer group of
companies over the same three-year period. The number of shares earned could range from zero up to two times the number of shares
initially granted.
In January 2014, 750,681 shares 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 2013 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. As of January 8, 2017, the end of the three-year vesting
period, these market-based conditions had not been met and all of these awards were therefore cancelled and are available for future
issuance under the 2013 Equity Plan.
For awards subject to market conditions, the grant date fair value was estimated using a Monte Carlo valuation model. The Monte
Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic
assessment. Expected volatility was calculated based on the historical volatility of Whiting’s common stock, and the risk-free interest
rate is based on U.S. Treasury yield curve rates with maturities consistent with the three-year vesting period. The key assumptions
used in valuing the market-based restricted shares were as follows:
Number of simulations
Expected volatility
Risk-free interest rate
Dividend yield
2016
2,500,000
60.8%
1.13%
-
2015
2,500,000
40.3%
0.99%
-
2014
65,000
42.3%
0.86%
-
The grant date fair value of the market-based restricted stock as determined by the Monte Carlo valuation model was $6.39 per share,
$33.25 per share and $26.59 per share in January 2016, 2015 and 2014, respectively.
95
The following table shows a summary of the Company’s restricted stock activity for the year ended December 31, 2016:
Nonvested awards, January 1, 2016
Granted
Vested
Forfeited
Nonvested awards, December 31, 2016
Number of Shares
Weighted Average
Service-Based
Restricted Stock
Market-Based
Restricted Stock
Grant Date
Fair Value
892,693
2,952,193
(428,659)
(348,423)
3,067,804
1,400,963 $
1,073,143
-
(381,296)
2,092,810 $
30.03
6.80
32.41
17.08
13.55
As of December 31, 2016, there was $18 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 1.6 years. For the years
ended December 31, 2016, 2015 and 2014, the total fair value of restricted stock vested was $5 million, $4 million and $31 million,
respectively.
Stock Options—Stock options may be granted to certain executive officers of the Company with exercise prices equal to the closing
market price of the Company’s common stock on the grant date. There were no stock options granted under the 2013 Equity Plan
during 2016, 2015 or 2014, other than the 673,235 stock options assumed in connection with the Kodiak Acquisition, as discussed
above. The Company’s stock options vest ratably over a three-year service period from the grant date and are exercisable immediately
upon vesting through the tenth anniversary of the grant date.
The following table shows a summary of the Company’s stock options outstanding as of December 31, 2016 as well as activity during
the year then ended:
Weighted
Average
Exercise Price
per Share
Aggregate
Intrinsic
Value
(in thousands)
Weighted
Average
Remaining
Contractual
Term
(in years)
Number of
Options
Options outstanding at January 1, 2016
Granted
Exercised
Forfeited or expired
Options outstanding at December 31, 2016
Options vested and expected to vest at December 31, 2016
Options exercisable at December 31, 2016
588,175 $
-
-
(73,741)
514,434 $
490,978 $
510,717 $
41.35
-
-
55.85
39.27
38.81
39.06
$
$
$
$
-
60
54
60
4.3
4.2
4.3
There was no unrecognized compensation cost related to unvested stock option awards as of December 31, 2016. There were no stock
options exercised during the year ended December 31, 2016. For the years ended December 31, 2015 and 2014, the aggregate
intrinsic value of stock options exercised was $2 million and $6 million, respectively.
For the years ended December 31, 2016, 2015 and 2014, total stock compensation expense recognized for restricted share awards and
stock options was $26 million, $28 million and $23 million, respectively.
96
10. INCOME TAXES
Income tax expense (benefit) consists of the following (in thousands):
Current income tax expense (benefit)
Federal
State
Total current income tax expense (benefit)
Deferred income tax expense (benefit)
Federal
State
Total deferred income tax expense (benefit)
Total
Year Ended December 31,
2015
2014
2016
$
$
(7,340) $
150
(7,190)
- $
(357)
(357)
(65,130)
(15,326)
(80,456)
(87,646) $
(736,520)
(37,350)
(773,870)
(774,227) $
(2,758)
5,383
2,625
65,522
11,023
76,545
79,170
Income tax expense (benefit) 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 (benefit)
State income taxes, net of federal benefit
Statutory depletion
Enacted changes in state tax laws
Market-based equity awards
Permanent items
IRC Section 382 limitation
Non-deductible convertible debt expenses
Transaction costs
Goodwill impairment
Other
Total
Year Ended December 31,
2015
(1,047,723) $
(44,654)
(327)
7,350
2,690
5,071
-
-
-
305,820
(2,454)
(774,227) $
2016
(499,370) $
(33,050)
(52)
5,020
8,352
783
259,494
174,071
-
-
(2,894)
(87,646) $
2014
50,371
12,705
(618)
3,700
2,805
3,504
-
-
6,936
-
(233)
79,170
$
$
97
The principal components of the Company’s deferred income tax assets and liabilities at December 31, 2016 and 2015 were as follows
(in thousands):
Deferred income tax assets
Net operating loss carryforward
Derivative instruments
Asset retirement obligations
Underwriter fees
Restricted stock compensation
EOR credit carryforwards
Alternative minimum tax credit carryforwards
Transaction costs
Other
Total deferred income tax assets
Less valuation allowance
Net deferred income tax assets
Deferred income tax liabilities
Oil and gas properties
Trust distributions
Discount on convertible senior notes
Derivative instruments
Total deferred income tax liabilities
Total net deferred income tax liabilities
Year Ended December 31,
2015
2016
$
1,248,034 $
6,145
21,398
5,134
12,171
7,946
7,847
4,786
9,436
1,322,897
(264,461)
1,058,436
1,412,781
94,120
27,224
-
1,534,125
$
475,689 $
835,995
-
18,896
6,060
17,675
7,946
15,694
6,395
11,110
919,771
(5,061)
914,710
1,264,598
101,665
76,475
65,764
1,508,502
593,792
The Company’s July 1, 2016 note exchange transactions triggered an ownership shift within the meaning of Section 382 of the
Internal Revenue Code (“IRC”) due to the “deemed share issuance” that resulted from the note exchanges. The ownership shift will
limit Whiting’s usage of certain of its net operating losses and tax credits in the future. Accordingly, the Company recognized
valuation allowances on its deferred tax assets totaling $259 million.
As of December 31, 2016, the Company had federal net operating loss (“NOL”) carryforwards of $2.7 billion, which was net of the
IRC Section 382 limitation. Of this amount, $70 million in NOL carryforwards relate to tax deductions for stock compensation that
exceed stock compensation costs recognized for financial statement purposes. The benefit of these excess tax deductions has not been
recognized as of December 31, 2016. The Company also has various state NOL carryforwards. The determination of the state NOL
carryforwards is dependent upon apportionment percentages and state laws that can change from year to year and that can thereby
impact the amount of such carryforwards. If unutilized, the federal NOL will expire in 2036, and the state NOLs will expire between
2017 and 2036.
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, 2016, the Company had recognized aggregate EOR credits of $8 million.
As a result of the IRC Section 382 limitation in July 2016, the Company recorded a full valuation allowance on these credits.
The Company is subject to the alternative minimum tax (“AMT”) principally due to its significant intangible drilling cost deductions.
The Company expects to forego bonus depreciation and claim a refund under the Protecting Americans from Tax Hikes Act for its
AMT credits and has recognized a $7 million current benefit. As of December 31, 2016, the Company had AMT credits totaling $8
million that are available to offset future regular federal income taxes. These credits do not expire and can be carried forward
indefinitely.
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion, or all,
of the Company’s deferred tax assets will not be realized. In making such determination, the Company considers all available positive
and negative evidence, including future reversals of temporary differences, tax-planning strategies and projected future taxable income
and results of operations. If the Company concludes that it is more likely than not that some portion, or all, of its deferred tax assets
will not be realized, the tax asset is reduced by a valuation allowance. At December 31, 2016, the Company had a valuation
allowance totaling $265 million, comprised of $251 million of NOL carryforward limitations under Section 382 of the IRC, $8 million
of EOR credits, which will expire between 2023 and 2025, and $5 million of Canadian NOL carryforwards, which will expire between
2034 and 2035. At December 31, 2015, the Company had a valuation allowance totaling $5 million on Canadian NOL carryforwards.
These valuation allowances have been recorded because the Company determined it was more likely than not that the benefit from
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these deferred tax assets will not be realized due to the IRC Section 382 limitation on the NOL carryforward and the EOR credit
carryforwards, as well as the divestiture of all foreign operations. The Company expects the carrying value of its remaining deferred
tax assets at December 31, 2016 and 2015 to be realized based on the anticipated reversal of existing temporary differences, and
accordingly, the Company has not recorded additional valuation allowance as of December 31, 2016 or 2015.
In conjunction with the Kodiak Acquisition, the Company acquired Kodiak, which is a Canadian entity that is disregarded for U.S. tax
purposes. Kodiak holds an interest in Whiting Resources Corporation, a U.S. entity. Canadian taxes have not been recognized on the
excess of the amount for financial reporting over the tax basis of the investment in Kodiak that is indefinitely reinvested outside the
United States. This amount becomes taxable in Canada upon a repatriation of assets from the Canadian subsidiary or a sale or
liquidation of the subsidiary. The amount of such temporary differences totaled $698 million as of December 31, 2016.
Determination of the amount of any unrecognized deferred Canadian tax liability on this temporary difference is not practicable. U.S.
income taxes on Kodiak and its subsidiary, Whiting Resources Corporation, however, have been fully recognized on their cumulative
losses to date.
During the year ended December 31, 2016, the Company derecognized an unrecognized tax benefit of $170,000 as a result of the IRC
Section 382 limitation, which resulted in the Company recording a full valuation allowance on its EOR credits, the underlying asset
generating the uncertain tax position. For the years ended December 31, 2016, 2015 and 2014, the Company did not recognize any
interest or penalties with respect to unrecognized tax benefits, nor did the Company have any such interest or penalties previously
accrued. The Company believes that it is reasonably possible that no increases 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 2013 through 2016 tax years generally remain subject to examination by federal and state tax authorities. Additionally, the
Company has Canadian income tax filings which remain subject to examination by the related tax authorities for the 2011 through
2016 tax years.
11. EARNINGS PER SHARE
The reconciliations between basic and diluted earnings (loss) per share are as follows (in thousands, except per share data):
Year Ended
December 31,
2015
2016
2014
Basic Earnings (Loss) Per Share
Numerator
Net income (loss) available to common shareholders, basic
$
(1,339,102) $
(2,219,182) $
64,807
Denominator
Weighted average shares outstanding, basic
251,869
195,472
122,138
Diluted Earnings (Loss) Per Share
Numerator
Adjusted net income (loss) available to common shareholders, diluted $
(1,339,102) $
(2,219,182) $
64,807
Denominator
Weighted average shares outstanding, basic
Restricted stock and stock options
Weighted average shares outstanding, diluted
251,869
-
251,869
195,472
-
195,472
122,138
381
122,519
Earnings (loss) per common share, basic
Earnings (loss) per common share, diluted
$
$
(5.32) $
(5.32) $
(11.35) $
(11.35) $
0.53
0.53
For the year ended December 31, 2016, the Company had a net loss and therefore the diluted earnings per share calculation for that
period excludes the anti-dilutive effect of (i) 43,283,035 shares issuable for the convertible notes prior to their conversions under the
if-converted method, (ii) 1,778,587 shares of service-based restricted stock, and (iii) 4,635 stock options. In addition, the diluted
earnings per share calculation for the year ended December 31, 2016 excludes the dilutive effect of 1,917,811 common shares for
stock options that were out-of-the-money and 370,195 shares of restricted stock that did not meet its market-based vesting criteria as
of December 31, 2016.
For the year ended December 31, 2015, the Company had a net loss and therefore the diluted earnings per share calculation for that
period excludes the anti-dilutive effect of 516,139 shares of service-based restricted stock and 85,564 stock options. In addition, the
99
diluted earnings per share calculation for the year ended December 31, 2015 excludes (i) the anti-dilutive effect of 676,277
incremental shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2015, and (ii) the dilutive
effect of 514,757 common shares for stock options that were out-of-the-money.
For the year ended December 31, 2014, the diluted earnings per share calculation excludes (i) the dilutive effect of 803,902
incremental shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2014, and (ii) the anti-
dilutive effect of 791 common shares for stock options that were out-of-the-money.
Refer to the “Stock-Based Compensation” footnote for further information on the Company’s restricted stock and stock options.
As discussed in the “Long-Term Debt” footnote, the Company has the option to settle the 2020 Convertible Senior Notes with cash,
shares of common stock or any combination thereof upon conversion. Based on the initial conversion price, the entire outstanding
principal amount of the 2020 Convertible Senior Notes as of December 31, 2016 would be convertible into approximately 21.9 million
shares of the Company’s common stock. However, the Company’s intent is to settle the principal amount of the notes in cash upon
conversion. As a result, only the amount by which the conversion value exceeds the aggregate principal amount of the notes (the
“conversion spread”) is considered in the diluted earnings per share computation under the treasury stock method. As of December
31, 2016 and 2015, the conversion value did not exceed the principal amount of the notes, and accordingly, there was no impact to
diluted earnings per share or the related disclosures for those periods.
12. RELATED PARTY TRANSACTIONS
Whiting USA Trust I—Whiting had a retained ownership of 15.8%, or 2,186,389 units in Trust I, and it was therefore a related party
of the Company. On January 28, 2015, the net profits interest that Whiting conveyed to Trust I terminated causing such interest in the
underlying properties to revert back to Whiting, and Trust I was no longer a related party.
Tax Sharing Liability—Prior to Whiting’s initial public offering in November 2003, it was a wholly-owned indirect subsidiary of
Alliant Energy Corporation (“Alliant Energy”), and when the transactions discussed below were entered into, Alliant Energy was a
related party of the Company. As of December 31, 2004 and thereafter, Alliant Energy was no longer a related party.
In 2003, the Company entered into a Tax Separation and Indemnification Agreement with Alliant Energy, whereby the Company and
Alliant Energy made certain tax elections with the effect that the tax bases of Whiting’s assets were increased. Such additional tax
bases have resulted in increased income tax deductions for Whiting and, accordingly, have reduced income taxes otherwise payable by
Whiting. Under this Tax Separation and Indemnification Agreement, the Company agreed to pay to Alliant Energy (each year from
2004 to 2013) 90% of the tax benefits the Company realized annually as a result of this step-up in tax bases. In 2014, Whiting was
obligated to pay Alliant the present value of 90% of the remaining tax benefits expected to result from its increased tax bases, which
payout assumes all such tax benefits will be realized in future years.
In March 2014, the Company made the final payment due Alliant Energy under this agreement totaling $26 million, including $3
million of interest.
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, 2016 (in thousands):
Non-cancelable leases
Drilling rig contracts
Pipeline transportation
agreements
Total
2017
2018
Payments due by period
2020
2019
2021
Thereafter
$
7,502 $
30,717
7,460 $
-
6,368 $
-
801 $
-
- $
-
- $
-
Total
22,131
30,717
5,369
43,588 $
5,369
12,829 $
5,369
11,737 $
$
5,369
6,170 $
5,369
5,369 $
16,849
16,849 $
43,694
96,542
Non-cancelable Leases—The Company leases 222,900 square feet of administrative office space in Denver, Colorado under an
operating lease arrangement expiring in 2019, 44,500 square feet of office space in Midland, Texas expiring in 2020, and 36,500
square feet of office space in Dickinson, North Dakota expiring in 2020. Rental expense for 2016, 2015 and 2014 amounted to
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$9 million, $9 million and $7 million, respectively. Minimum lease payments under the terms of non-cancelable operating leases as of
December 31, 2016 are shown in the table above.
Drilling Rig Contracts—As of December 31, 2016, the Company had five drilling rigs under long-term contract, all of which expire
in 2017. The Company’s minimum drilling commitments under the terms of these contracts as of December 31, 2016 are shown in
the table above. As of December 31, 2016, early termination of these contracts would require termination penalties of $27 million,
which would be in lieu of paying the remaining drilling commitments under these contracts. During 2016, 2015 and 2014, the
Company made payments of $66 million, $161 million and $106 million, respectively, under these long-term contracts, which are
initially capitalized as a component of oil and gas properties and either depleted in future periods or written off as exploration expense.
Pipeline Transportation Agreements—The Company has two pipeline transportation agreements with one supplier, expiring in 2024
and 2025, whereby it has committed to pay fixed monthly reservation fees on dedicated pipelines from its Redtail field for natural gas
and NGL transportation capacity, plus a variable charge based on actual transportation volumes. These fixed monthly reservation fees
totaling approximately $44 million have been included in the table above.
During the second quarter of 2016, the Company terminated two ship-or-pay agreements to transport crude oil and water via certain
pipelines expiring in 2026, and incurred termination penalties totaling $1 million.
In conjunction with the sale of its interest in the North Ward Estes field in Texas on July 27, 2016, the Company transferred to the
buyer of the properties a ship-or-pay agreement expiring in 2017 to transport a minimum daily volume of CO2 via certain pipelines.
During 2016, 2015 and 2014, transportation of crude oil, natural gas, NGLs, CO2 and water under these contracts amounted to $8
million, $15 million and $13 million, respectively.
Purchase Contracts—The Company has one take-or-pay purchase agreement which expires in 2020, whereby the Company has
committed to buy certain volumes of water for use in the fracture stimulation process of wells the Company completes in its Redtail
field. Under the terms of the agreement, the Company is obligated to purchase a minimum volume of water or else pay for any
deficiencies at the price stipulated in the contract. Although minimum daily quantities are specified in the agreement, the actual water
volumes purchased and their corresponding unit prices are variable over the term of the contract. 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, 2016, the Company estimated the minimum future commitments under this purchase agreement to approximate
$31 million through 2020.
In conjunction with the sale of the North Ward Estes field in Texas on July 27, 2016, the Company transferred to the buyer of the
properties a take-or-pay purchase agreement expiring in 2017 to buy certain volumes of CO2 for use in the North Ward Estes EOR
project.
During 2016, 2015 and 2014, purchases of CO2 and water amounted to $37 million, $88 million and $105 million, respectively.
Water Disposal Agreement—The Company has one water disposal agreement which expires in 2024, whereby it has contracted for
the transportation and disposal of the produced water from its Redtail field. Under the terms of the agreement, the Company is
obligated to provide a minimum volume of produced water or else pay for any deficiencies at the price stipulated in the contract.
Although minimum monthly quantities are specified in the agreement, the actual water volumes disposed of and their corresponding
unit prices are variable over the term of the contract. 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, 2016, the Company
estimated the minimum future commitments under this disposal agreement to approximate $137 million through 2024. During 2016,
transportation and disposal of produced water amounted to $8 million. There were no water disposal costs incurred under this contract
during 2015 or 2014.
Delivery Commitments—The Company has various physical delivery contracts which require the Company to deliver fixed volumes
of crude oil. One of these delivery commitments is tied to crude oil production at Whiting’s Sanish field in Mountrail County, North
Dakota and requires delivery of 15 MBbl/d for a term of seven years. The effective date of this contract is contingent upon the
completion of the Dakota Access Pipeline, the timing of which is currently unknown. The Company believes its production and
reserves are sufficient to fulfill the delivery commitment at the Sanish field in North Dakota, and therefore expects to avoid any
payments for deficiencies under this contract. The remaining two delivery commitments are tied to crude oil production at Whiting’s
Redtail field in Weld County, Colorado. As of December 31, 2016, these two contracts contain delivery commitments of 19.6
MMBbl, 21.5 MMBbl, 23.3 MMBbl and 6.6 MMBbl of crude oil for the years ended December 31, 2017 through 2020, respectively.
The Company has determined that it is not probable that future oil production from its Redtail field will be sufficient to meet the
minimum volume requirements specified in these physical delivery contracts, and as a result, the Company expects to make periodic
deficiency payments for any shortfalls in delivering the minimum committed volumes. During 2016 and 2015, total deficiency
payments under these contracts amounted to $43 million and $15 million, respectively. The Company recognizes any monthly
101
deficiency payments in the period in which the underdelivery takes place and the related liability has been incurred. The table above
does not include any such deficiency payments that may be incurred under the Company’s physical delivery contracts, since it cannot
be predicted with accuracy the amount and timing of any such penalties incurred.
Litigation—The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the ordinary course
of business. The Company accrues 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. 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. Accordingly, no material amounts for loss contingencies associated with litigation, claims or
assessments have been accrued at December 31, 2016 or 2015.
14. CAPITALIZED EXPLORATORY WELL COSTS
Exploratory well costs that are incurred and expensed in the same annual period have not been included in the table below. The net
changes in capitalized exploratory well costs were as follows (in thousands):
Beginning balance at January 1
Additions to capitalized exploratory well costs pending the determination
$
of proved reserves
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
Year Ended December 31,
2015
2014
2016
- $
14,293 $
85,378
-
54,707
145,336
-
-
- $
(63,352)
(5,648)
- $
(200,869)
(15,552)
14,293
$
At December 31, 2016, the Company had no costs capitalized for exploratory wells in progress for a period of greater than one year
after the completion of drilling.
15. SUBSEQUENT EVENTS
Gas Plant Sale—On January 1, 2017, the Company completed the sale of Whiting’s 50% interest in the Robinson Lake gas
processing plant located in Mountrail County, North Dakota and its 50% interest in the Belfield gas processing plant located in Stark
County, North Dakota, as well as the associated natural gas, crude oil and water gathering systems, effective January 1, 2017, for
aggregate sales proceeds of $375 million (before closing adjustments). The Company used the net proceeds from this transaction to
repay a portion of the debt outstanding under its credit agreement.
The following table shows the components of assets and liabilities classified as held for sale as of December 31, 2016 (in thousands):
Assets
Oil and gas properties, net
Other property and equipment, net
Total property and equipment, net
Other long-term assets
Total assets held for sale
Liabilities
Asset retirement obligations
Other long-term liabilities
Total liabilities related to assets held for sale
Carrying Value as of
December 31, 2016
$
$
$
$
347,817
475
348,292
854
349,146
131
407
538
Redemption of 2018 Senior Subordinated Notes—On January 3, 2017, the trustee under the indenture governing the Company’s
2018 Senior Subordinated Notes provided notice to the holders of such notes that Whiting elected to redeem all of the remaining $275
million aggregate principal amount of the 2018 Senior Subordinated Notes on February 2, 2017, and on that date, Whiting paid
102
$281 million consisting of the 100% redemption price plus all accrued and unpaid interest on the notes. The Company financed the
redemption with borrowings under its credit agreement.
103
SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Oil and Gas Producing Activities
Net capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):
Proved oil and gas properties
Unproved oil and gas properties
Accumulated depletion
Oil and gas properties, net
Year Ended December 31,
2015
2016
12,709,257
12,347,400 $
1,195,268
883,451
(3,279,156)
(4,170,237)
10,625,369
9,060,614 $
$
$
The Company’s oil and gas activities for 2016, 2015 and 2014 were entirely within the United States. Costs incurred in oil and gas
producing activities were as follows (in thousands):
Development (1)
Proved property acquisition (2)
Unproved property acquisition (2)
Exploration
Total
$
$
Year Ended December 31,
2015
2,137,755 $
2016
518,585 $
797
3,642
45,846
568,870 $
-
29,050
192,422
2,359,227 $
2014
2,891,893
2,278,855
1,035,439
216,587
6,422,774
_____________________
(1) During 2016, 2015 and 2014, non-cash additions to oil and gas properties of $15 million, $48 million and $45 million,
respectively, which relate to estimated costs of the future plugging and abandonment of the Company’s oil and gas wells, are
included in development costs in the table above.
(2) During 2014, amounts include $2.3 billion of non-cash proved property additions and $1.0 billion of non-cash unproved property
additions related to the Kodiak Acquisition.
Oil and Gas Reserve Quantities
For all years presented, the Company’s independent petroleum engineers independently estimated all of the proved reserve quantities
included in this Annual Report on Form 10-K. In connection with the external petroleum engineers performing their independent
reserve estimations, Whiting furnishes them with the following information for their review: (i) technical support data, (ii) technical
analysis of geologic and engineering support information, (iii) economic and production data, and (iv) the Company’s well ownership
interests. The independent petroleum engineers, Cawley, Gillespie & Associates, Inc., evaluated 100% of the Company’s estimated
proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2016. Proved reserve estimates included
herein conform to the definitions prescribed by the SEC. Estimates of proved reserves are inherently imprecise and are continually
subject to revision based on production history, results of additional exploration and development, price changes and other factors.
104
As of December 31, 2016, 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, 2014, 2015 and
2016 are as follows:
Proved reserves
Balance—January 1, 2014
Extensions and discoveries
Sales of minerals in place
Purchases of minerals in place
Production
Revisions to previous estimates
Balance—December 31, 2014
Extensions and discoveries
Sales of minerals in place
Production
Revisions to previous estimates
Balance—December 31, 2015
Extensions and discoveries
Sales of minerals in place
Production
Revisions to previous estimates
Balance—December 31, 2016
Proved developed reserves
December 31, 2013
December 31, 2014
December 31, 2015
December 31, 2016
Proved undeveloped reserves
December 31, 2013
December 31, 2014
December 31, 2015
December 31, 2016
Oil
(MBbl)
NGLs
(MBbl)
Natural Gas
(MMcf)
Total
(MBOE)
347,421
146,122
(1,642)
169,586
(33,485)
15,627
643,629
131,134
(33,767)
(47,176)
(97,143)
596,677
48,208
(95,294)
(33,992)
(120,832)
394,767
198,204
333,593
298,444
183,165
149,217
310,036
298,233
211,602
44,869
12,947
-
-
(3,283)
151
54,684
26,074
(3,240)
(5,539)
40,968
112,947
12,980
(16,795)
(6,642)
(997)
101,493
23,721
28,935
55,437
51,888
21,148
25,749
57,510
49,605
277,514
94,452
(2,925)
156,140
(30,218)
(2,943)
492,020
192,575
(96,891)
(41,129)
119,085
665,660
93,070
(13,797)
(41,438)
12,164
715,659
183,129
298,237
300,631
337,860
94,385
193,783
365,029
377,799
438,542
174,811
(2,130)
195,609
(41,804)
15,288
780,316
189,304
(53,156)
(59,570)
(36,327)
820,567
76,700
(114,388)
(47,540)
(119,802)
615,537
252,446
412,234
403,986
291,363
186,096
368,082
416,581
324,174
Notable changes in proved reserves for the year ended December 31, 2016 included the following:
Extensions and discoveries. In 2016, total extensions and discoveries of 76.7 MMBOE were primarily attributable to successful
drilling in the Williston Basin and DJ Basin. Both the new wells drilled in these areas as well as the PUD locations added as a
result of drilling increased the Company’s proved reserves.
Sales of minerals in place. Sales of minerals in place totaled 114.4 MMBOE during 2016 and were primarily attributable to the
disposition of the North Ward Estes Properties as further described in the “Acquisitions and Divestitures” footnote in the notes
to the consolidated financial statements.
Revisions to previous estimates. In 2016, revisions to previous estimates decreased proved developed and undeveloped reserves
by a net amount of 119.8 MMBOE. Included in these revisions were (i) 121.6 MMBOE of downward adjustments caused by
lower crude oil, NGL and natural gas prices incorporated into the Company’s reserve estimates at December 31, 2016 as
compared to December 31, 2015 and (ii) 1.8 MMBOE of net upward adjustments attributable to reservoir analysis and well
performance.
Notable changes in proved reserves for the year ended December 31, 2015 included the following:
Extensions and discoveries. In 2015, total extensions and discoveries of 189.3 MMBOE were primarily attributable to
successful drilling in the Williston Basin and DJ Basin. Both the new wells drilled in these areas as well as the PUD locations
added as a result of drilling increased the Company’s proved reserves.
105
Sales of minerals in place. Sales of minerals in place totaled 53.2 MMBOE during 2015 and were primarily attributable to the
disposition of various non-core properties across all of the Company’s operating areas as further described in the “Acquisitions
and Divestitures” footnote in the notes to the consolidated financial statements.
Revisions to previous estimates. In 2015, revisions to previous estimates decreased proved developed and undeveloped reserves
by a net amount of 36.3 MMBOE. Included in these revisions were (i) 82.3 MMBOE of downward adjustments caused by
lower crude oil, NGL and natural gas prices incorporated into the Company’s reserve estimates at December 31, 2015 as
compared to December 31, 2014 and (ii) 46.0 MMBOE of net upward adjustments attributable to reservoir analysis and well
performance.
Notable changes in proved reserves for the year ended December 31, 2014 included the following:
Extensions and discoveries. In 2014, total extensions and discoveries of 174.8 MMBOE were primarily attributable to
successful drilling in the Williston Basin and DJ Basin. Both the new wells drilled in these areas as well as the PUD locations
added as a result of drilling increased the Company’s proved reserves.
Sales of minerals in place. Sales of minerals in place totaled 2.1 MMBOE during 2014 and were primarily attributable to the
disposition of properties in the Big Tex prospect as further described in the “Acquisitions and Divestitures” footnote in the notes
to the consolidated financial statements, as well as other property divestitures in the Lucky Ditch, Whiskey Springs and Bridger
Lake fields.
Purchases of minerals in place. In 2014, total purchases of minerals in place of 195.6 MMBOE were primarily attributable to
the Kodiak Acquisition, whereby the Company acquired interests in 778 producing oil and gas wells and undeveloped acreage
in the Williston Basin, further described in the “Acquisitions and Divestitures” footnote in the notes to the consolidated financial
statements.
Revisions to previous estimates. Revisions to previous estimates increased proved developed and undeveloped reserves by a net
amount of 15.3 MMBOE in 2014. Included in these revisions were (i) 15.6 MMBOE of net upward adjustments attributable to
reservoir analysis and well performance and (ii) 0.3 MMBOE of downward adjustments caused by lower crude oil prices
incorporated into the Company’s reserve estimates at December 31, 2014 as compared to December 31, 2013.
Standardized Measure of Discounted Future Net Cash Flows
The Standardized Measure relating to proved oil and gas reserves and changes in the Standardized Measure 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, 2016, 2015 and 2014 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,
2016, 2015 and 2014, 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. This calculation does not necessarily result in an estimate of the fair value of the
Company’s oil and gas properties.
The Standardized Measure relating to proved oil and natural gas reserves is as follows (in thousands):
2016
December 31,
2015
2014
$
Future cash flows
Future production costs
Future development costs
Future income tax expense (1)
Future net cash flows
10% annual discount for estimated timing of cash flows
Standardized measure of discounted future net cash flows
_____________________
(1) Based on the 12-month average oil and natural gas prices used in the computation of pre-tax PV10% as of December 31, 2016,
Whiting’s future net income generated over the life of its proved reserves is expected to be less than its NOL carryforward
deductions and therefore, under the Standardized Measure, there is no deduction for federal or state income taxes.
29,339,528 $
(12,344,463)
(6,166,397)
(388,072)
10,440,596
(5,866,225)
4,574,371 $
16,946,961 $
(7,266,435)
(3,605,977)
-
6,074,549
(3,376,463)
2,698,086 $
59,949,707
(20,772,234)
(7,924,573)
(8,579,237)
22,673,663
(11,830,243)
10,843,420
$
106
Future cash flows as shown above are reported without consideration for the effects of open hedge contracts at each period end. If the
effects of hedging transactions were included in the computation, then undiscounted future cash inflows would have increased by $77
million and $71 million in 2016 and 2015, respectively, and would have decreased by $7 million in 2014.
The changes in the Standardized Measure relating to proved oil and natural gas reserves are as follows (in thousands):
Beginning of year
Sale of oil and gas produced, net of production costs
Sales of minerals in place
Net changes in prices and production costs
Extensions, discoveries and improved recoveries
Previously estimated development costs incurred during the period
Changes in estimated future development costs
Purchases of minerals in place
Revisions of previous quantity estimates
Net change in income taxes
Accretion of discount
End of year
$
$
2016
4,574,371 $
(781,132)
(1,434,545)
(1,594,183)
730,396
477,830
1,722,897
-
(1,502,416)
47,431
457,437
2,698,086 $
December 31,
2015
10,843,420 $
(1,354,054)
(1,414,511)
(11,001,949)
2,078,071
1,625,160
102,499
-
(966,713)
3,578,106
1,084,342
4,574,371 $
2014
6,593,861
(2,274,682)
(48,532)
81,522
3,950,413
1,149,926
(3,382,849)
4,420,417
345,775
(651,817)
659,386
10,843,420
Future net revenues included in the Standardized Measure 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, 2016, 2015 and 2014 as
follows:
Oil (per Bbl)
NGLs (per Bbl)
Natural Gas (per Mcf)
2016
35.60
10.09
2.61
$
$
$
2015
43.07
15.53
2.83
$
$
$
2014
84.69
46.59
5.88
$
$
$
107
QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2016 and 2015 (in thousands,
except per share data):
Oil, NGL and natural gas sales
Gross loss (1)
Net loss
Basic loss per share
Diluted loss per share
Three Months Ended
March 31,
2016
June 30,
2016
September 30,
December 31,
2016
2016
$
$
$
$
$
289,697 $
(162,898) $
(171,758) $
(0.84) $
(0.84) $
337,036 $
(98,978) $
(301,046) $
(1.33) $
(1.33) $
315,554 $
(83,369) $
(693,055) $
(2.47) $
(2.47) $
342,695
(45,205)
(173,265)
(0.59)
(0.59)
Three Months Ended
March 31,
2015
June 30,
2015
September 30,
December 31,
2015
2015
Oil, NGL and natural gas sales
Gross profit (loss) (1)
Net loss
Basic loss per share
Diluted loss per share
_____________________
(1) Oil, NGL and natural gas sales less lease operating expense, production taxes and depreciation, depletion and amortization.
504,155 $
18,130 $
(1,865,118) $
(9.14) $
(9.14) $
519,848 $
25,586 $
(106,128) $
(0.63) $
(0.63) $
650,527 $
128,012 $
(149,295) $
(0.73) $
(0.73) $
$
$
$
$
$
417,952
(60,966)
(98,727)
(0.48)
(0.48)
******
108
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of disclosure controls and procedures. In accordance with Rule 13a-15(b) of the Securities Exchange Act of 1934 (the
“Exchange Act”), our management evaluated, with the participation of our Chairman, President and Chief Executive Officer and our
Senior Vice President and 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, 2016. Based upon
their evaluation of these disclosure controls and procedures, the Chairman, President and Chief Executive Officer and the Senior Vice
President and Chief Financial Officer concluded that the disclosure controls and procedures were effective as of December 31, 2016 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, 2016 using the criteria
set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission. Based on this assessment, our management believes that, as of December 31, 2016, 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, 2016 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, 2016 that has materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting.
109
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, 2016, based on criteria established in Internal Control — Integrated Framework (2013) 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,
2016, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the
consolidated financial statements as of and for the year ended December 31, 2016 of the Company and our report dated February 23,
2017 expressed an unqualified opinion on those financial statements.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 23, 2017
Item 9B. Other Information
None.
110
Item 10. Directors, Executive Officers and Corporate Governance
PART III
The information included under the captions “Corporate Governance – Proposal 1 – Election of Directors”, “Corporate Governance –
Board Committee Information – Audit Committee” and “Share Ownership – Section 16(a) Beneficial Ownership Reporting
Compliance” in our definitive Proxy Statement for Whiting Petroleum Corporation’s 2017 Annual Meeting of Stockholders (the
“Proxy Statement”) is incorporated herein by reference. Information with respect to our executive officers appears in Part I of this
Annual Report on Form 10-K.
We have adopted the Whiting Petroleum Corporation Code of Business Conduct and Ethics that applies to our directors, our
Chairman, President and Chief Executive Officer, our Senior Vice President and Chief Financial Officer, our Vice President, Finance
and Treasurer and other persons performing similar functions. We have posted a copy of the Whiting Petroleum Corporation Code of
Business Conduct and Ethics on our website at www.whiting.com. The Whiting Petroleum Corporation Code of Business Conduct
and Ethics is also available in print to any stockholder who requests it in writing from the Corporate Secretary of Whiting Petroleum
Corporation. We intend to satisfy the disclosure requirements under Item 5.05 of Form 8-K regarding amendments to, or waivers
from, the Whiting Petroleum Corporation Code of Business Conduct and Ethics by posting such information on our website at
www.whiting.com.
We are not including the information contained on our website as part of, or incorporating it by reference into, this report.
Item 11. Executive Compensation
The information required by this Item is included under the captions “Corporate Governance – Director Compensation” and
“Executive Compensation” (other than “Executive Compensation – Proposal 2 – Advisory Vote on the Compensation of Our Named
Executive Officers” and “Executive Compensation – Proposal 3 – Advisory Vote on the Frequency of the Advisory Vote on
Compensation of Our Named Executive Officers”) in the Proxy Statement and is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by this Item with respect to security ownership of certain beneficial owners and management is included
under the captions “Share Ownership – Directors and Executive Officers” and “Share Ownership – Certain Beneficial Owners” in the
Proxy Statement and is incorporated herein by reference. The following table sets forth information with respect to compensation
plans under which equity securities of Whiting Petroleum Corporation are authorized for issuance as of December 31, 2016.
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)
514,434
$
-
514,434
$
39.27
N/A
39.27
6,333,174 (2)
-
6,333,174 (2)
_____________________
(1) Includes the Whiting Petroleum Corporation 2003 Equity Incentive Plan (the “2003 Equity Plan”) and Whiting Petroleum
Corporation 2013 Equity Incentive Plan (the “2013 Equity Plan”). Upon shareholder approval of the 2013 Equity Plan in May
2013, the 2003 Equity Plan was terminated, but continues to govern awards that were outstanding at the date of its termination.
Any shares netted or forfeited under the 2003 Equity Plan and any shares forfeited under the 2013 Equity Plan will be available
for future issuance under the 2013 Equity Plan. However, shares netted for tax withholding under the 2013 Equity Plan will be
cancelled and will not be available for future issuance.
(2) Number of securities reduced by 514,434 stock options outstanding and 5,160,614 shares of restricted common stock previously
issued for which the restrictions have not lapsed.
111
Item 13. Certain Relationships, Related Transactions and Director Independence
The information required by this Item is included under the caption “Corporate Governance – Governance Information –
Independence of Directors” and “Corporate Governance – Governance Information – Transactions with Related Persons” in the Proxy
Statement and is incorporated herein by reference.
Item 14. Principal Accounting Fees and Services
The information required by this Item is included under the caption “Audit Matters – Audit and Non-Audit Fees and Services” in the
Proxy Statement and is incorporated herein by reference.
Item 15. Exhibits and 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 – All 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.
Item 16. Form 10-K Summary
None.
******
112
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 23rd day of February, 2017.
SIGNATURES
WHITING PETROLEUM CORPORATION
By
/s/ James J. Volker
James J. Volker
Chairman, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on
behalf of the Registrant and in the capacities and on the dates indicated.
Signature
/s/ James J. Volker
James J. Volker
/s/ Michael J. Stevens
Michael J. Stevens
/s/ Brent P. Jensen
Brent P. Jensen
/s/ Thomas L. Aller
Thomas L. Aller
/s/ D. Sherwin Artus
D. Sherwin Artus
/s/ James E. Catlin
James E. Catlin
/s/ Philip E. Doty
Philip E. Doty
/s/ William N. Hahne
William N. Hahne
/s/ Carin S. Knickel
Carin S. Knickel
/s/ Michael B. Walen
Michael B. Walen
Date
February 23, 2017
February 23, 2017
February 23, 2017
February 23, 2017
February 23, 2017
February 23, 2017
February 23, 2017
February 23, 2017
February 23, 2017
February 23, 2017
Title
Chairman, President and Chief
Executive Officer and Director
(Principal Executive Officer)
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
Vice President, Finance and Treasurer
(Principal Accounting Officer)
Director
Director
Director
Director
Director
Director
Director
113
Exhibit
Number
(2.1)
(3.1)
(3.2)
(4.1)
(4.2)
(4.3)
(4.4)
(4.5)^
(4.6)
(4.7)
(4.8)
(4.9)
(4.10)
EXHIBIT INDEX
Exhibit Description
Purchase and Sale Agreement, dated July 27, 2016, by and between Whiting Oil and Gas Corporation and Four
Corners Petroleum II, LLC, effective as of July 1, 2016, including Exhibit K, the Form of Promissory Note for
Additional Consideration [Incorporated by reference to Exhibit 2.1 to Whiting Petroleum Corporation’s Current
Report on Form 8-K filed on August 2, 2016 (File No. 001-31899)].
Restated Certificate of Incorporation of Whiting Petroleum Corporation [Incorporated by reference to Exhibit 3.3 to
Whiting Petroleum Corporation’s Current Report on Form 8-K filed on May 18, 2016 (File No. 001-31899)].
Amended and Restated By-laws of Whiting Petroleum Corporation, effective February 18, 2016 [Incorporated by
reference to Exhibit 3.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on February 22,
2016 (File No. 001-31899)].
Sixth Amended and Restated Credit Agreement, dated as of August 27, 2014, among Whiting Petroleum
Corporation, Whiting Oil and Gas Corporation, the lenders party thereto, JPMorgan Chase Bank, N.A., as
Administrative Agent, and the various other agents party thereto [Incorporated by reference to Exhibit 4.1 to
Whiting Petroleum Corporation’s Current Report on Form 8-K filed on August 28, 2014 (File No. 001-31899)].
First Amendment to Sixth Amended and Restated Credit Agreement, dated as of April 27, 2015, among Whiting
Petroleum Corporation, Whiting Oil and Gas Corporation, the lenders party thereto, JPMorgan Chase Bank, N.A.,
as Administrative Agent, and the various other agents party thereto [Incorporated by reference to Exhibit 4.1 to
Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2015 (File No.
001-31899)].
Second Amendment to Sixth Amended and Restated Credit Agreement, dated as of October 13, 2015, among
Whiting Petroleum Corporation, its subsidiary 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 Current Report on Form 8-K filed on October 14, 2015 (File No. 001-31899)].
Third Amendment to Sixth Amended and Restated Credit Agreement and First Amendment to Amended and
Restated Guaranty and Collateral Agreement, dated as of March 25, 2016, among Whiting Petroleum Corporation,
its subsidiary Whiting Oil and Gas Corporation, certain other subsidiaries of Whiting Petroleum 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 filed on March 28,
2016 (File No. 001-31899)].
Amended and Restated Guaranty and Collateral Agreement, dated as of December 8, 2014, among Whiting
Petroleum Corporation, Whiting Oil and Gas Corporation, Kodiak Oil & Gas Corp., Kodiak Oil & Gas (USA) Inc.,
Kodiak Williston, LLC and JPMorgan Chase Bank, N.A., as Administrative Agent [Incorporated by reference to
Exhibit 4.16 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on December 8, 2014 (File No.
001-31899)].
Maximum Credit Amount Increase Agreement, dated as of December 19, 2014, among Whiting Petroleum
Corporation, Whiting Oil and Gas Corporation, the lenders party thereto, and JPMorgan Chase Bank, N.A., as
Administrative Agent [Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Current Report
on Form 8-K filed on December 22, 2014 (File No. 001-31899)].
Indenture, dated September 12, 2013, among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation
and The Bank of New York Mellon Trust Company, N.A., as Trustee [Incorporated by reference to Exhibit 4.1 to
Whiting Petroleum Corporation’s Current Report on Form 8-K filed on September 12, 2013 (File No. 001-31899)].
First Supplemental Indenture, dated September 12, 2013, among Whiting Petroleum Corporation, Whiting Oil and
Gas Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating the 5.0% Senior
Notes due 2019 [Incorporated by reference to Exhibit 4.2 to Whiting Petroleum Corporation’s Current Report on
Form 8-K filed on September 12, 2013 (File No. 001-31899)].
Supplemental Indenture and Amendment – Subsidiary Guarantee, dated as of December 11, 2014, among Whiting
Petroleum Corporation, Whiting Canadian Holding Company ULC, Whiting Resources Corporation, Whiting US
Holding Company and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to the 5.0% Senior
Notes Due 2019 [Incorporated by reference to Exhibit 4.2 to Whiting Petroleum Corporation’s Current Report on
Form 8-K filed on December 12, 2014 (File No. 001-31899)].
Second Supplemental Indenture, dated September 12, 2013, among Whiting Petroleum Corporation, Whiting Oil
and Gas Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating the 5.75%
Senior Notes due 2021 [Incorporated by reference to Exhibit 4.3 to Whiting Petroleum Corporation’s Current
Report on Form 8-K filed on September 12, 2013 (File No. 001-31899)].
114
Exhibit
Number
(4.11)
(4.12)
(4.13)
(10.1)*
(10.2)*
(10.3)*
(10.4)*
(10.5)*
(10.6)*
(10.7)*
(10.8)*
(10.9)*
(10.10)*
(10.11)*
(10.12)*
(21)
(23.1)
(23.2)
(31.1)
(31.2)
(32.1)
(32.2)
Exhibit Description
Supplemental Indenture and Amendment – Subsidiary Guarantee, dated as of December 11, 2014, among Whiting
Petroleum Corporation, Whiting Canadian Holding Company ULC, Whiting Resources Corporation, Whiting US
Holding Company and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to the 5.75%
Senior Notes Due 2021 [Incorporated by reference to Exhibit 4.3 to Whiting Petroleum Corporation’s Current
Report on Form 8-K filed on December 12, 2014 (File No. 001-31899)].
Fourth Supplemental Indenture, dated March 27, 2015, among Whiting Petroleum Corporation, Whiting Oil and
Gas Corporation, Whiting US Holding Company, Whiting Canadian Holding Company ULC, Whiting Resources
Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating the 6.25% Senior Notes
due 2023 [Incorporated by reference to Exhibit 4.3 to Whiting Petroleum Corporation’s Current Report on Form 8-
K filed on March 30, 2015 (File No. 001-31899)].
Indenture, dated March 27, 2015, among Whiting Petroleum Corporation, the Guarantors and The Bank of New
York Mellon Trust Company, N.A., as Trustee, creating the 1.25% Convertible Senior Notes due 2020
[Incorporated by reference to Exhibit 4.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on
March 30, 2015 (File No. 001-31899)].
Whiting Petroleum Corporation 2003 Equity Incentive Plan, as amended through October 23, 2007 [Incorporated by
reference to Exhibit 10.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on October 29,
2007 (File No. 001-31899)].
Whiting Petroleum Corporation 2013 Equity Incentive Plan, as amended and restated effective as of January 1,
2017.
Form of Restricted Stock Agreement pursuant to the Whiting Petroleum Corporation 2003 Equity Incentive Plan for
time-based vesting awards [Incorporated by reference to Exhibit 10.4 to Whiting Petroleum Corporation’s Current
Report on Form 8-K filed on October 29, 2007 (File No. 001-31899)].
Form of Restricted Stock Agreement pursuant to the Whiting Petroleum Corporation 2003 Equity Incentive Plan for
awards to executive officers [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)].
Summary of Non-Employee Director Compensation for Whiting Petroleum Corporation.
Form of Indemnification Agreement for directors and officers of Whiting Petroleum Corporation [Incorporated by
reference to Exhibit 10.10 to Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the quarter
ended September 30, 2008 (File No. 001-31899)].
Form of Executive Employment and Severance Agreement for executive officers of Whiting Petroleum
Corporation [Incorporated by reference to Exhibit 10.1 to Whiting Petroleum Corporation’s Current Report on
Form 8-K filed on January 5, 2015 (File No. 001-31899)].
Form of Stock Option Agreement pursuant to the Whiting Petroleum Corporation 2003 Equity Incentive Plan
[Incorporated by reference to Exhibit 10.14 to Whiting Petroleum Corporation’s Annual Report on Form 10-K for
the year ended December 31, 2008 (File No. 001-31899)].
Form of Restricted Stock Agreement pursuant to the Whiting Petroleum Corporation 2013 Equity Incentive Plan for
performance vesting awards [Incorporated by reference to Exhibit 10.14 to Whiting Petroleum Corporation’s
Annual Report on Form 10-K for the year ended December 31, 2013 (File No. 001-31899)].
Form of Restricted Stock Agreement pursuant to the Whiting Petroleum Corporation 2013 Equity Incentive Plan for
time-based vesting awards.
Form of Stock Option Agreement pursuant to the Whiting Petroleum Corporation 2013 Equity Incentive Plan
[Incorporated by reference to Exhibit 10.16 to Whiting Petroleum Corporation’s Annual Report on Form 10-K for
the year ended December 31, 2013 (File No. 001-31899)].
Form of Performance Share Award Agreement pursuant to the Whiting Petroleum Corporation 2013 Equity
Incentive Plan.
Significant Subsidiaries of Whiting Petroleum Corporation.
Consent of Deloitte & Touche LLP.
Consent of Cawley, Gillespie & Associates, Inc., Independent Petroleum Engineers.
Certification by the Chairman, President and Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley
Act.
Certification by the Senior Vice President and Chief Financial Officer pursuant to Section 302 of the Sarbanes-
Oxley Act.
Written Statement of the Chairman, President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.
Written Statement of the Senior Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
115
Exhibit
Number
(99.1)
(99.2)
(101)
Exhibit Description
Proxy Statement for the 2017 Annual Meeting of Stockholders, to be filed within 120 days of December 31, 2016
[To be filed with the Securities and Exchange Commission under Regulation 14A within 120 days after December
31, 2016; except to the extent specifically incorporated by reference, the Proxy Statement for the 2017 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, dated January 6, 2017.
The following materials from Whiting Petroleum Corporation’s Annual Report on Form 10-K for the year ended
December 31, 2016 are filed herewith, formatted in XBRL (Extensible Business Reporting Language): (i) the
Consolidated Balance Sheets as of December 31, 2016 and 2015, (ii) the Consolidated Statements of Operations for
the Years Ended December 31, 2016, 2015 and 2014, (iii) the Consolidated Statements of Cash Flows for the Years
Ended December 31, 2016, 2015 and 2014, (iv) the Consolidated Statements of Equity for the Years Ended
December 31, 2016, 2015 and 2014, and (v) Notes to Consolidated Financial Statements.
_____________________
*
^
A management contract or compensatory plan or arrangement.
Kodiak Oil & Gas Corp. is now known as Whiting Canadian Holding Company ULC; Kodiak Oil & Gas (USA) Inc. is now
known as Whiting Resources Corporation; Kodiak Williston, LLC has merged with Whiting Resources Corporation; KOG
Finance, LLC has been dissolved; and KOG Oil & Gas ULC has been liquidated.
116
EXECUTIVE OFFICERS
OTHER OFFICERS
BOARD OF DIRECTORS
James J. Volker
Chairman of the Board, President
and Chief Executive Officer
Bill L. Cadman
Vice President, Corporate
and Government Relations
Michael R. Craig
Vice President, Information Technology
Eric K. Hagen
Vice President, Investor Relations
Mark D. Sonnenfeld
Vice President, Geoscience
for Whiting Oil and Gas Corporation
Bruce L. Taton
Vice President, Marketing
for Whiting Oil and Gas Corporation
Douglas L. Walton
Vice President and
National Drilling Manager
for Whiting Oil and Gas Corporation
Michael J. Stevens
Senior Vice President and
Chief Financial Officer
Peter W. Hagist
Senior Vice President, Planning
Rick A. Ross
Senior Vice President, Operations
Mark R. Williams
Senior Vice President, Exploration
and Development
Bruce R. DeBoer
Vice President, General Counsel
and Corporate Secretary
Heather M. Duncan
Vice President, Human Resources
Brent P. Jensen
Chief Accounting Officer
Vice President, Finance and Treasurer
Steven A. Kranker
Vice President, Reservoir Engineering
and Acquisitions
David M. Seery
Vice President, Land
* Audit Committee + Compensation Committee ^ Nominating and Governance Committee
James J. Volker (Since 2003)
Chairman of the Board, President
and Chief Executive Officer
William N. Hahne +^ (Since 2007)
Lead Director
Past Chief Operating Officer
Petrohawk Energy Corporation
Thomas L. Aller*+ (Since 2003)
Retired President
Interstate Power and Light Company
an Alliant Energy Company
D. Sherwin Artus ^ (Since 2006)
Retired President and CEO
Whiting Petroleum Corporation
James E. Catlin (Since 2014)
Past Executive Vice President
and Director
Kodiak Oil and Gas Corporation
Philip E. Doty* ^ (Since 2010)
Certified Public Accountant
Carin S. Knickel +^ (Since 2015)
Past Vice President
ConocoPhillips
Michael B. Walen *+ (Since 2013)
Past Chief Operating Officer
Cabot Oil and Gas Corporation
CORPORATE OFFICES
TRANSFER AGENT
INFORMATION UPDATES
Whiting Petroleum Corporation
1700 Broadway, Suite 2300
Denver, Colorado 80290-2300
Tel: 303.837.1661
Fax: 303.861.4023
www.whiting.com
INVESTOR RELATIONS
Securities analysts, investors and the
financial media should contact:
Eric K. Hagen
Vice President, Investor Relations
Tel: 303.837.1661
Please direct communication
regarding individual stock records
and address changes to:
Computershare Trust Company, N.A.
8742 Lucent Blvd., Suite 225
Highlands Ranch, Colorado 80129
Tel: 303.262.0600
Fax: 303.262.0700
www.computershare.com
INDEPENDENT PETROLEUM
ENGINEERS
Cawley, Gillespie & Associates, Inc.
STOCK EXCHANGE LISTING
New York Stock Exchange, trading symbol: WLL
INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
Deloitte & Touche LLP
Whiting’s quarterly financial results and
other information are available on our
website at www.whiting.com
ANNUAL REPORT ON
FORM 10-K
Upon request, the Company will
provide, without charge, copies of the
2016 Annual Report on Form 10-K
as filed with the Securities and
Exchange Commission
ANNUAL MEETING
Tuesday, May 2, 2017
10:00 A.M. (Mountain Daylight Time)
The Grand Hyatt Hotel
Capitol Peak Ballroom
555 17th Street, 38th floor
Denver, Colorado 80202