P R OGR E SS
MEET S
VA LUE
W H I T I N G A N N U A L R E P O R T 2 0 1 9
A B O U T W H I T I N G P E T R O L E U M
2 0 1 9 AC H I E V E M E N T S
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 primarily in the Rocky
Mountains region of the United States. We are focused
primarily on organic exploration and development activity,
both on grassroots oil plays and on the development of
previously acquired properties. Our core assets provide
the opportunity for repeatable success and meaningful
the
production growth. We
industry with our
lead
competitive asset base, dedication to technology and
strong results. Whiting is a competitive company with
a strong plan for the future. The Company’s shares are
traded on the NYSE under the stock symbol WLL.
Fourth Quarter 2019 Net Cash
Provided by Operating Activities
Exceeded Capex by $132 million
Full-year well costs declined ~10%
from 2018
Successfully added over 300
potential drilling locations through
Sanish infill drilling and Foreman
Butte delineation
PROGRESS MEETS VALUE
As Whiting enters a new decade, we find ourselves in the midst of an onshore
revolution for oil and gas. The industry is changing rapidly, and Whiting
is prepared to stand apart and lead because we understand the external
environment and continue to take a long-term outlook. We know our investors
have the opportunity to earn returns from virtually any source. We take the
competition seriously and strive to provide transparency, disclosure, and an
easy-to-understand capital structure.
As we look to 2020, you’ll see us continue to deliver value
in a number of ways, as we make every effort to generate
cash flow, provide returns to our investors, and pay down
debt. We’re working tirelessly to create cash flow growth,
improve margins, and increase efficiency. Yet, we’ll
never position ourselves as just a low-cost operator,
because we refuse to compromise. Throughout this
report, you’ll find that our commitment to our values, our
investors, our employees, and our communities never
wavers. At the end of the day, that’s how we’ll deliver the
greatest value to all.
Sincerely,
BRADLEY J. HOLLY
Chairman, President and
Chief Executive Officer
Ultimately, the question is this: Who can generate value?
Whiting has answered the call with our transition to a
free cash flow model. For us, this isn’t a trend, but rather
the right way to do business. It required us to embrace
significant change
isn’t necessarily
in 2019, which
simple in a large, established organization, but as always,
we met the challenge on the strength of our people
and culture.
Making this kind of sea change involved an economic
evaluation of every aspect of our business. It meant taking
a fresh look at how we spend on capital projects, existing
projects, and general and administrative functions, with
generating value as our guide at every turn. In this light,
we identified the need for a restructuring, resulting in a
flatter organization, key hires, and cultural adjustments.
From an operating perspective, we saw an opportunity
to generate more value from mature reservoirs. Not only
did we apply the latest technology to our completions,
we also centralized reporting for all field operations to
streamline communications. From a financial point of view,
we brought Correne Loeffler on board as Chief Financial
Officer to contribute strategic leadership to finance and
accounting. She brought a wealth of experience, as well as
an enthusiastic, high-energy approach to building a team
with new ideas and a can-do attitude.
We approached our employees in different ways, too.
Our compensation structure now aligns employees with
shareholders, providing a new framework for decision-
making and performance which benefits all investors. At
the same time, we reinvented our working environments.
Whiting opened two new state-of-the-art offices. In North
Dakota, the office is closer to the field, shortening
commutes and supporting employees with automated
tools. And for the first time, our Denver office moved to a
new space at equal cost. More than a hundred of our own
Whiting employees helped to design our modern and
inspiring offices, filled with cutting-edge tools and collab-
orative spaces that encourage productive interaction. It’s a
place we can all function even better than before.
0 1
STRATEGY MEETS TRANSPARENCY
In 2019, I joined Whiting as our industry faced a significant transformation.
Thankfully, Whiting is an established organization with people, processes,
and groups that work well together, translating to the field, where 2,171
wells produced 125 thousand BOE per day in 2019. In addition, Whiting’s
large asset base gives us a strong competitive advantage, with 65%
of production in oil.
At the same time, we must evolve to meet new
challenges. In a volatile commodities market,
it’s essential to maximize every dollar and
achieve the highest, most efficient production
possible. To continue as a premier producer in
this environment requires cost discipline, so
we’re able to take advantage of opportunities
as soon as they emerge.
To that end, we are building a new strategic
financial organization focused on strength-
ening our planning capabilities, facilitating
greater in-depth understanding of the business,
implementing real-time dashboards, and build-
ing bridges between finance, accounting, and
operations by communicating all of this infor-
mation. Our guiding principle is transparency,
both internally and externally. We want our
employees to know how and why we work in
certain ways, so departments can understand
each other. Beyond the walls of the company,
we want our investors to know they can trust
us, especially in an industry where trust is in
jeopardy.
Every day, our proactive leadership team
continues to move Whiting away from a
production-only mindset by looking for new
and different ways to generate value and
deliver returns for our investors. Through
our operational efficiency efforts we reduced
lease operating expense and G&A by approxi-
mately $100 million on an annualized basis in
the second half of 2019 from second quarter
levels.
As 2020 takes shape, we know where we’re
going, and with our smarter approach to using
information and encouraging communication,
we know how to get there. Whiting is position-
ing ourselves to control our own destiny like
never before.
Sincerely,
CORRENE LOEFFLER
Chief Financial Officer
0 2
LOWERED CASH COSTS THROUGH
REORGANIZATION & COST SAVING INITIATIVES (PER BOE)
$12.00
$10.28
$10.34
$9.461
$8.381
$8.00
$4.00
$0.00
Q119
Q219
Q319
Q419
LOE
G&A
1 G&A adjusted to exclude $20 million of reorganization costs and certain legal accruals.
0 3
CULTURE MEETS COMMITMENT
Whiting remains committed to a company culture that values
high integrity, engaged leadership, business excellence, effective
communication, meaningful stewardship and safety always.
This requires a consistent and dedicated approach to developing our employees
personally and professionally. An important way we accomplish this objective is through
WLL Lead. The goal of WLL Lead is to increase employee engagement and foster more
effective leadership throughout the organization. Employees who participate in the
program receive classroom training every six weeks, and most collaborate with an
executive coach during a monthly one-on-one meeting. Approximately 52 employees
completed the WLL Lead program in 2019.
HIGHEST INTEGRITY
Exhibiting the highest
ethical standards
EFFECTIVE COMMUNICATION
Exchanging information in a
purposeful and productive way
ENGAGED LEADERSHIP
MEANINGFUL STEWARDSHIP
Leading, serving and
inspiring others
Preserving our environment and
enriching our communities
BUSINESS EXCELLENCE
SAFETY ALWAYS
Achieving operational
excellence
Protecting people, property
and communities
S A F E T Y M E E T S N O C O M P R O M I S E
At Whiting, “safety always” is our core value. Our goal is zero incidents every single
day. To foster this culture of safety, we promote transparency and accountability, while
providing tools and resources to empower our people to identify and report potential
hazards and stop work when necessary. To further instill the value of safety always,
Whiting holds quarterly meetings with employees and contractors to ensure effective
communication and a continuous focus on safety. Maintaining the safety of our employees,
contractors, and communities will not be compromised.
H I G H S TA N DA R D S M E E T R E C O G N I T I O N
Whiting’s core values provide the foundation for how we work, interact, manage, and
lead. In 2019, we formed a committee to recognize employees who exemplify our values.
Each quarter, employees nominate colleagues who best represent one of Whiting’s
six core values, and the committee reviews all nominations and selects a winner for
each value. In 2019, an incredible 347 values nominations were received, proving
Whiting employees hold themselves and others to the highest standards of integrity,
accountability, and performance.
0 4
0 5
C H A R L E S J. “ C H I P ” R I M E R / Chief Operating Officer
2019 brought drastic weather conditions to our properties.
The way our people responded tells you everything about
how we do business at Whiting. In the first quarter, the
field experienced record-low temperatures, but production
continued without complaint. Next came the Yellowstone
floods. The team worked tirelessly to make sure our
emergency response was ready and prepared. In the third
quarter, heavy rains led to knee-deep mud and shut-down
roads, blocking equipment. Through it all, the passion and
pride to do things right kept production going safely. But
personal and professional development doesn’t end there.
We also support every employee in honing their business
perspective, so they know how they impact production
and create value for the company and investors. Applying
technology has strengthened this understanding and
improved operational efficiency. Implementing dashboards
provides the field with real-time data. Modern completions
enable us to produce for less cost, creating opportunities to
build infrastructure like oil, gas, and water takeaways.
After two strong quarters at the end of 2019, we’re striving
to keep the winning streak going through all four quarters
of 2020. This means operating at a low cost, while earning
the best selling price. Maximizing base production, while
minimizing downtime. All with the purpose of getting the
most value from every barrel—while keeping everyone safe.
We’ll never sacrifice that.
0 6
OPERATIONS MEET OPTIMIZATIONS
With control of approximately 476,000 net acres, we’re one of
the largest producers in the oil-rich Williston Basin of North
Dakota and Montana, encompassing the prolific Bakken and
Three Forks formations. Whiting remains on the forefront of
the industry in the application of optimized completions, a
key factor in our ability to expand top-tier results outside the
established core of the Bakken.
POD 8
POD 9
POD 10
At the Pod 8 project, infill Bakken and Three Forks wells have outper-
formed parent wells by approximately 160% and 230%, respectively,
after 180 days on production. Parent wells have experienced a marked
increase in production relative to the trend prior to infill drilling.
The Bakken wells drilled in the Bartelson unit, located at the far western
edge of the Sanish Field, have outperformed the parent well by 244%
after 180 days on production. The parent well in the Bartelson area
saw a substantial and sustained positive response to infill drilling,
flowing for over four months after the new completions.
Whiting also brought on the Pod 9 infill pilot, located in the northwest
portion of the Sanish field. At Pod 9, Whiting drilled nine Bakken wells
in an area that had 11 parent wells. The average well produced 760
barrels of oil equivalent per day (BOE/d) over the first 90 days and
continues to produce with moderate decline. The new wells are
producing above the parent wells, and the parent wells are producing
above their prior trend due to positive stimulation from child wells.
To date, Whiting has completed multiple successful infill pilots that
span the field and demonstrate the potential for a full-scale redevelop-
ment program.
Pod 10 represents the latest evolution of infill development in the
Sanish Field. It spans two 1,280-acre drilling spacing units with 16
parent wells and 10 child wells. Based on prior infill pilot results,
the Company optimized proppant and fluid volumes and modified its
artificial lift program. On average, cumulative production per well from
Pod 10 is trending higher than Pod 9 production results. Performance
relative to parent wells has also been superior, with average 30-day
cumulative rates for child wells 45% above the parent trend.
0 7
CASSANDRA
In the Northern Williston Basin, the Periot wells located in the
Cassandra area continue to deliver strong results. With over 100 days
on production, Bakken and Three Forks wells have outperformed
competitor wells by 37% and 48%, respectively. Also, construction on
the Ray gas plant was completed during the year. This additional gas
capacity supported accelerated activity in the Polar area in 2019, as
well as supporting future activity in the Cassandra area.
HIDDEN
BENCH
In the Southern Williston Basin, the Stenehjem wells in southern
Hidden Bench continue to outperform parent wells. With more than 80
days on production, the Stenehjem wells have generated 90,000 barrels
of oil per well on average—a 124% increase relative to parent results.
FOREMAN
BUTTE
Whiting acquired the Foreman Butte property in 2018 and has now
completed its delineation program, establishing production from the first
17 wells in the field. These wells produced 2.5x above the offset wells
drilled in the area. Whiting is currently working with third parties to
install gathering infrastructure in preparation for full field development.
RESERVES & PRODUCTION BY AREA
2019 PROVED RESERVES
2019 FULL-YEAR PRODUCTION
485.43
MMBOE
125,535
BOEPD
93.4 %
NORTHERN
ROCKY
MOUNTAINS
4.8 %
CENTRAL
ROCKY
MOUNTAINS
1.8 %
OTHER
89.6 %
NORTHERN
ROCKY
MOUNTAINS
9.9 %
CENTRAL
ROCKY
MOUNTAINS
0.5 %
OTHER
0 8
W H I T I N G A C R E A G E AS
OF DECEMBER 31, 2019
0 9
R E S P O N S I B I L I T Y M E E T S E F F I C I E N C Y
Delivering value through an integrated and collaborative
approach to business planning and use of supply chain
practices is key to our operations.
First, Whiting has developed strong procurement policies
that allow us to maximize the value we receive for each
dollar we spend with our suppliers. These policies generate
savings and reduce supplier risk, while holding suppliers
accountable. In addition, Whiting makes every effort to
competitively bid high-volume and frequently purchased
goods and services while consolidating awarded goods and
services over a period (e.g., quarterly, semi-annually).
Our policies also help Whiting maintain strong relationships
with our employees, suppliers and communities, who have
become an essential part of why and how we do business.
Due to the remote nature of many of our operations, we
often hire locally for services on our locations from
reputable small businesses, whose employees live in the
communities nearby. Providing scheduling and financial
certainty to local suppliers and contractors can, in turn,
help them with employee retention and business planning.
We also keep our communities top of mind as we screen
waste disposal and injection vendors based on our Waste
Management Program. We maintain Environmental
Addendums (EAs) associated with our Master Service
Agreements for generator and compressor rental vendors,
and we piloted software to track vendors’ movements and
where they deliver waste. The software is designed to help
select which waste vendors provide goods and services to
Whiting, and to provide additional assurance that Whiting’s
waste is handled properly.
Finally, since 2018, Whiting has been using safety per-
formance as a component in vendor selection. We screen
contractors for safety-related items via ISNetworld, an
online contractor and supplier management platform
that manages risk and reduces unnecessary duplication
associated with traditional vendor qualification processes.
1 0
PASSION MEETS VISION
Whiting continues to build on its commitment to sustainability
planning, reporting, and execution. We have increased transparency,
achieved tangible progress, and maintained a strong resolve to
advance key initiatives. As challenges to our industry grow, our
dedication to our people, the communities where we live and work,
and the environment we all value and enjoy, only increases.
A I R E M I S S I O N S
Consistent with our overall commitment to environmental responsibility, Whiting seeks to limit
and capture air emissions. Whiting estimates the air emissions from our operations by using
state and federal emission estimation methodologies relevant to the locations in which Whiting
operates, along with manufacturer-provided or EPA-required emissions factors. Ongoing
initiatives include improving our gas capture rate in North Dakota, implementing pilot emissions
reduction initiatives, pursuing the most advantageous emissions calculation method and devel-
oping a greenhouse gas (GHG) emissions reduction target.
R I S K M A N A G E M E N T
At Whiting, protecting the health and safety of our employees is paramount in sustaining a
culture that values caring for others, quality of work, productivity and company pride. Our Health
and Safety programs are designed to guide employees in the recognition of hazards and the
assessment of those risks inherent to our industry. Through Health and Safety training, we
prepare our employees to use industry best practices and consensus standards to mitigate risk
in a manner that protects themselves, co-workers, the public, and our property. Ongoing
initiatives include formalizing risk management process, standardizing operating procedures,
and consistently reviewing Whiting’s position on climate risk.
W AT E R M A N A G E M E N T
Whiting understands and respects water as a limited natural resource, and is committed to
responsible water use. We recognize that our water use affects neighboring communities,
governments, businesses and industries, and we remain dedicated to using water responsibly
and effectively while developing energy resources. Whiting strives to obtain fresh water from
nearby water resources, and to minimize water consumption by only using the necessary volume
of fresh water. Where possible, we utilize pipelines to transport fresh water, which eliminates
the use of haul trucks and their associated emissions and road traffic. Ongoing initiatives
include enhancing the water data collection process, completing a water risk assessment,
developing water reduction and recycling initiatives and creating a water reduction target.
W A S T E M A N A G E M E N T
Whiting has developed an effective waste management program in order to minimize our impact
on the environment and to limit the risk and liability of handling and disposing waste. Our corporate
Waste Management and Minimization Plan and third-party audits of all disposal locations ensure
that waste generated at all our locations is properly disposed of or treated. Whiting’s waste manage-
ment program is always evolving and looking for new ways to improve how we manage and dispose
of our wastes and reduce the amount of wastes we generate. Ongoing initiatives include enhancing
the waste data collection process, creating a baseline using 2020 data, developing and piloting
waste reduction initiatives, and leveraging supply chain to consolidate vendors.
S E E O U R F U L L S U S TA I N A B I L I T Y R E P O R T AT W H I T I N G . C O M
1 1
F I N A N C I A L & O P E R AT I O N S S U M M A R Y
(In millions, except per share amounts, per unit prices, ratios, and well and acreage statistics)
INCOME STATEMENT & CASH FLOW
2019
2018
2017
2016
2015
Oil, NGL & Natural Gas Sales
Net Income (Loss) Attributable to Common Shareholders
Earnings (Loss) per Common Share, Diluted
Weighted Average Shares Outstanding, Diluted
Net Cash Provided by Operating Activities
Net Cash Provided by (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
$
$
$
$
$
$
$
$
$
1,572.2
(241.2)
(2.64)
$
$
$
2,081.4
$
1,481.4
$
1,285.0
$ 2,092.5
342.5
$
(1,237.6)
$
(1,339.1)
$
(2,219.2)
3.73
$
(13.65)
$
(21.27)
$
(45.41)
91.285
91.869
90.683
62.967
48.868
756.0
(733.8)
$
$
1,092.0
(953.1)
(27.1)
$
(1,004.7)
$
$
$
577.1
73.4
155.6
$
$
$
595.0
$ 1,051.4
(222.6)
$
(1,982.1)
(315.3)
$
868.7
2019
2018
2017
2016
2015
7,636.7
2,799.9
4,025.0
41%
$
$
$
7,759.6
2,792.3
4,270.3
40%
$
$
$
8,403.0
2,764.7
3,919.1
49%
$
$
$
9,876.1
$ 11,389.1
3,535.3
$ 5,197.7
5,149.2
$ 4,758.6
41%
52%
PRODUCTION & AVERAGE COMMODITY PRICES
2019
2018
2017
2016
2015
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
29.8
7.6
50.5
45.8
50.06
6.76
0.57
34.86
$
$
$
$
31.5
7.4
46.8
46.7
58.70
20.78
1.66
41.20
$
$
$
$
29.3
7.0
41.3
43.1
44.30
16.00
1.78
34.55
$
$
$
$
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
$
$
$
$
YEAR-END 2019 WELL COUNT & ACREAGE STATISTICS
Total Productive Wells
Developed Acreage
Undeveloped Acreage
GROSS
NET
5,021
2,171
824,177
523,644
171,368
114,065
WHITING PETROLEUM
FORM 10-K
2019 ANNUAL RE PO RT
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, 2019
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 Lincoln Street, Suite 4700
Denver, Colorado
(Address of principal executive offices)
20-0098515
(I.R.S. Employer
Identification No.)
80203-4547
(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 each class)
WLL
New York Stock Exchange
(Trading Symbol) (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 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 every Interactive Data File required to be submitted 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 such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting
company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting
company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Accelerated filer
Non-accelerated filer
☒
☐
☐
Smaller reporting company
Emerging growth company
☐
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for
complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
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, 2019: $1,693,000,000.
Number of shares of the registrant’s common stock outstanding at February 20, 2020: 91,813,908 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the 2020 Annual Meeting of Stockholders are incorporated by reference into Part III.
Glossary of Certain Definitions
TABLE OF CONTENTS
Item 1. Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2.
Properties
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Information about our Executive Officers
PART I
PART II
Selected Financial Data
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Item 8.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Financial Statements and Supplementary Data
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships, Related Transactions and Director Independence
Item 14. Principal Accounting Fees and Services
Item 15. Exhibits and Financial Statement Schedules
Item 16. Form 10-K Summary
PART IV
1
5
18
36
36
42
42
43
45
47
48
64
65
105
105
106
107
107
107
108
108
108
108
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:
“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.
“Btu” or “British thermal unit” The quantity of heat required to raise the temperature of one pound of water one degree Fahrenheit.
“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. A collar can also contain an additional sold put option. Refer to “three-way collar” for more information.
“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” or “dry well” 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.
“GAAP” Generally accepted accounting principles in the United States of America.
1
“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 barrels of oil, NGLs or other liquid hydrocarbons.
“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.
“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, transportation, gathering, compression and other
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. Refer to the footnote to the Proved Reserves table in Item 1. “Business” of this Annual Report on Form 10-K for more
information.
2
“probabilistic method” The method of estimating reserves using the full range of values that could reasonably occur for each unknown
parameter (from the geoscience and engineering data) to generate a full range of possible outcomes and their associated probabilities of
occurrence.
“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.
3
“recompletion” An operation whereby a completion in one zone is abandoned in order to attempt a completion in a different zone within
the existing wellbore.
“reserves” Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given
date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable
expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and
gas or related substances to market, and all permits and financing required to implement the project.
“reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural
gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
“resource play” 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.
“three-way collar” A combination of options: a sold call, a purchased put and a sold put. The sold call establishes a maximum price
(ceiling) to be received 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.
“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 associated risks.
“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 discussed below under “Acquisitions and Divestitures,” and exploring other basins where we can apply our existing
knowledge and expertise to build production and add proved reserves. As a result of lower crude oil prices during 2017 and 2018, we
significantly reduced our level of capital spending and focused our drilling activity on projects that provide the highest rate of return,
while closely aligning our capital spending with cash flows generated from operations. During 2019, we focused on developing our
large resource play in the Williston Basin of North Dakota and Montana, while continuing to closely align our capital spending with
cash flows generated from operations. 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, 2019, our estimated proved reserves totaled 485.4 MMBOE and our 2019 average daily production was 125.5
MBOE/d, which results in an average reserve life of approximately 10.6 years.
The following table summarizes by core area, our estimated proved reserves as of December 31, 2019 with the corresponding pre-tax
PV10% values, our fourth quarter 2019 average daily production rates, and our total standardized measure of discounted future net cash
flows as of December 31, 2019:
Proved Reserves (1)
Core Area
Northern Rocky Mountains (3)
Central Rocky Mountains (4)
Other (5)
Total
Oil
NGLs
Natural
Gas
(Bcf)
(MMBbl) (MMBbl)
(MMBOE) Oil (in millions)
Total
%
Pre-Tax
PV10%
Value (2)
246.9
14.1
7.3
268.3
90.0
3.4
0.4
93.8
700.1
33.4
6.5
740.0
453.5 54% $
23.1 61%
8.8 83%
485.4 55% $
4th Quarter 2019
Average Daily
Production
(MBOE/d)
112.0
10.4
0.6
123.0
Discounted Future Income Tax Expense
Standardized Measure of Discounted Future Net Cash Flows
$
3,458
206
78
3,742
(40)
3,702
(1) Oil and gas reserve quantities and related discounted future net cash flows have been derived from an oil price of $55.69 per Bbl
and a gas price of $2.58 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, 2019 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
5
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.
(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, North Dakota, Texas and Wyoming.
During 2019, we incurred $778 million in exploration and development (“E&D”) expenditures, including $772 million for the drilling
and completion of 210 gross (94.0 net) wells.
Our current 2020 E&D budget is a range of $585 million to $620 million, which we expect to fund substantially with net cash provided
by our operating activities and cash on hand. To the extent net cash provided by operating activities is higher or lower than currently
anticipated, we would generate more or less free cash flow than we currently anticipate, 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
2019 Acquisitions and Divestitures. In July 2019, we completed the divestiture of our interests in 137 non-operated, producing oil and
gas wells located in McKenzie, Mountrail and Williams counties of North Dakota for aggregate sales proceeds of $27 million (before
closing adjustments).
In August 2019, we completed the divestiture of our interests in 58 non-operated, producing oil and gas wells located in Richland
County, Montana and Mountrail and Williams counties of North Dakota for aggregate sales proceeds of $26 million (before closing
adjustments).
On a combined basis, the divested properties consisted of less than 1% of our estimated proved reserves as of December 31, 2018 and
our April 2019 average daily production.
There were no significant acquisitions during the year ended December 31, 2019.
2018 Acquisitions and Divestitures. In July 2018, we completed the acquisition of approximately 54,800 net acres in the Williston
Basin, including interests in 117 producing oil and gas wells and undeveloped acreage located in Richland County, Montana and
McKenzie County, North Dakota for an aggregate purchase price of $130 million (before closing adjustments). The producing properties
had estimated proved reserves of 25.7 MMBOE as of the acquisition date, 84% of which were crude oil and NGLs.
There were no significant divestitures during the year ended December 31, 2018.
Subsequent to December 31, 2019, we completed the divestiture of our interests in 30 non-operated, producing oil and gas wells and
related undeveloped acreage located in McKenzie County, North Dakota for aggregate sales proceeds of $25 million (before closing
adjustments). The divested properties consisted of less than 1% of our estimated proved reserves as of December 31, 2019 and 1% of
our average daily production for the year ended December 31, 2019.
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:
Efficiently Developing Existing Properties. The development of our large resource play at our Williston Basin project in North Dakota
and Montana continues to be our central objective. We have assembled approximately 756,800 gross (476,300 net) developed and
undeveloped acres in this area, on which we had four drilling rigs operating as of December 31, 2019. During 2019, we completed and
6
brought on production 133 gross (87 net) operated Bakken and Three Forks wells in the Williston Basin. Under our current 2020 capital
program, we expect to put on production approximately 122 gross wells in this area during the year.
At our Redtail field in the Denver-Julesburg Basin (the “DJ Basin”) in Weld County, Colorado, we have assembled approximately
96,400 gross (84,600 net) developed and undeveloped acres. We completed 22 drilled uncompleted wells (“DUCs”) in our Redtail field
during the first half of 2018, and no additional wells were drilled or completed in 2019. During 2019 we worked on maintaining base
production with improved artificial lift techniques and reductions in lease operating expenses.
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 internally generated cash flows, equity and debt issuances, bank borrowings and certain oil and gas
property divestitures, as appropriate, to maintain our financial position. As a result of lower crude oil prices during 2017 and 2018, we
significantly reduced our level of capital spending and focused our drilling activity on projects that provide the highest rate of return,
while closely aligning our capital spending with cash flows generated from operations. During 2019, we focused on developing our
large resource play in the Williston Basin of North Dakota and Montana, while continuing to closely align our capital spending with
cash flows generated from operations. 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 2019 we sold certain oil and gas
properties operated by third parties 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 and swaps to provide an attractive base commodity price level.
Growing Through Accretive Acquisitions. Since 2010, we have completed 7 separate significant acquisitions of producing properties
for total estimated proved reserves of 240.2 MMBOE, as of the effective dates of the acquisitions. Our experienced team of management,
business development, 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, as well as explore opportunities in other basins where we can apply our existing knowledge
and expertise to build production and add proved reserves.
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, 2019, we had interests in 5,021 gross (2,171 net) productive wells on
approximately 824,200 gross (523,600 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 10.6 years based on year-end 2019
proved reserves and 2019 production.
Experienced Management and Technical Teams. Our management team averages 23 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 20 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 engineering, operational, geologic and
geophysical technical knowledge. Our technical team has access to an abundance of digital well log, seismic, completion, production
and other subsurface information, which is analyzed in order to accurately and efficiently characterize the anticipated performance of
our oil and gas reservoirs. In addition, our information systems enable us to update our production databases through field automation.
This commitment to technology has increased the productivity and efficiency of our field operations and development activities.
We continue to advance our completion techniques by utilizing customized, right-sized completion designs based on calibrated models
for each of our prospect areas, using multivariate analysis to understand which completion factors most significantly impact the results
in each area, and piloting and adopting the latest completion technologies available. Such customized designs utilize the optimum
volume of proppant, diversion techniques, fluids and frac stages, allowing us to increase well performance while reducing cost. We
7
have increased stages pumped per day by focusing on new technologies such as quick-install wellhead connections and frac plug
innovations. We plan to continue to use right-sized completion designs on wells we drill in 2020, while also utilizing state-of-the-art
drilling rigs, high-torque mud motors and evolving 3-D bit cutter technology to reduce time-on-location and total well cost.
Proved Reserves
Our estimated proved reserves as of December 31, 2019 are summarized by core area in the table below. Refer to “Reserves” in Item 2
of this Annual Report on Form 10-K for information relating to the uncertainties surrounding these reserve categories.
Oil
NGLs
Natural Gas
(Bcf)
(MMBbl) (MMBbl)
(MMBOE) Proved
(in millions)
Future Capital
% of Total Expenditures (1)
Total
Estimated
Northern Rocky Mountains (2)
PDP
PDNP
PUD
Total proved
Central Rocky Mountains (3)
PDP
PUD
Total proved
Other (4)
PDP
PDNP
Total proved
Total Company
PDP
PDNP
PUD
Total proved
169.8
2.3
74.8
246.9
11.4
2.7
14.1
6.9
0.4
7.3
188.1
2.7
77.5
268.3
67.9
0.8
21.3
90.0
3.0
0.4
3.4
0.3
0.1
0.4
71.2
0.9
21.7
93.8
534.8
5.8
159.5
700.1
29.1
4.3
33.4
5.5
1.0
6.5
569.4
6.8
163.8
740.0
326.7
4.0
122.8
453.5
19.3
3.8
23.1
8.1
0.7
8.8
354.1
4.7
126.6
485.4
72%
1%
27%
100% $
84%
16%
100% $
92%
8%
100% $
73%
1%
26%
100% $
1,396
48
8
1,452
(1) Estimated future capital expenditures incorporate numerous assumptions and are subject to many uncertainties, including oil and
natural gas prices, costs of oil field goods and services, drilling results and several other factors.
(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, North Dakota, Texas and Wyoming.
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 or rail
takeaway. In areas where there is no practical access to gathering pipelines, oil is trucked or transported 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, 2019, 2018 and 2017. We believe that the loss of any individual purchaser
8
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, 2019
Tesoro Crude Oil Co
Philips 66 Company
Year Ended December 31, 2018
United Energy Trading, LLC
Tesoro Crude Oil Co
Philips 66 Company
Year Ended December 31, 2017
Tesoro Crude Oil Co
Title to Properties
14 %
12 %
17 %
14 %
11 %
18 %
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 obtain necessary capital as well as evaluate and select suitable properties and to consummate transactions in a highly
competitive environment.
In addition, the oil and gas industry as a whole competes with other industries in supplying the energy and fuel requirements of industrial,
commercial and individual consumers. The price and availability of alternative energy sources, such as wind, solar, nuclear and electric
power, could adversely affect our revenue.
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.
9
Currently, none of our 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”). Among other things,
BOEM regulations 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 present value of our future
abandonment obligations associated with offshore properties was $41 million as of December 31, 2019. We are therefore required to
comply with the regulations and orders issued by the BOEM under the Outer Continental Shelf Lands Act.
The Bureau of Land Management (“BLM”) establishes the basis for onshore 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 BLM 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 a 2015 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.
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. 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, generally, and PHMSA, more specifically, 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
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Railroad Administration (the “FRA”) of the DOT, the Occupational Safety and Health Administration and other federal regulatory
agencies.
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 additional 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 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 certain 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 became law. The
PIPES Act strengthens PHMSA’s safety authority, including an expansion of its ability to issue emergency orders, which was adopted
by rule in October 2016 and further enhanced by rule in October 2019. 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 of natural gas for resale 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.
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 could result in an increase in the cost of transportation service on certain
petroleum product pipelines. In addition, the natural gas industry has historically been heavily regulated. Therefore, we cannot provide
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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.
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 which adopted certain specific industry recommended practices into
Part 192 of the Federal Pipeline Safety Regulations. PHMSA later reopened the post-promulgation comment period through November
2017 in response to petitions for reconsideration and has stated it would consider such comments further when it adopts a final rule.
Under the interim final rule, if an operator fails to take any measures recommended it would need to justify in its written procedures
why the measure is impracticable and unnecessary. PHMSA regulations had previously covered much of the surface piping up to the
wellhead at underground natural gas storage facilities served by pipelines and did not extend in part to the “downhole” portion of these
facilities. The adopted requirements cover design, construction, material, testing, commissioning, reservoir monitoring and
recordkeeping for existing and newly constructed underground natural gas storage facilities as well as procedures and practices for
newly constructed and existing underground natural gas storage facilities, such as operations, maintenance, threat identification,
monitoring, assessment, site security, emergency response and preparedness, training, recordkeeping and reporting. These regulations
and 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 costly compliance measures that carry substantial penalties for noncompliance. 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; limit or prohibit project siting, construction or drilling
activities on certain lands; require remedial and closure activities to prevent pollution from former operations; and impose substantial
liabilities for unauthorized pollution. 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.
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, future environmental enforcement remains a material risk due to the potential magnitude
of exposure in the event of a noncompliance. We have incurred in the past, and expect to incur in the future, capital costs related to
environmental compliance. Such expenditures are included within our overall capital budget and are not separately itemized.
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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 for sites contaminated by certain hazardous substances
on classes of potentially responsible persons. 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 costs of certain health studies. In the course of our ordinary operations, we may use,
generate or handle 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 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 previously owned or operated by third parties whose treatment and disposal of hazardous substances, wastes
or hydrocarbons were not under our control and not known to us. Similarly, the disposal facilities where discarded materials are sent
are also often operated by third parties whose waste treatment and disposal practices are similarly not under our control. While we only
use what we consider to be reputable disposal facilities, we might not know of a potential problem if the problem itself is not discovered
until years later. Current and formerly owned or operated 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:
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to investigate the source and extent of impacts from released hazardous substances;
to remove or remediate previously disposed materials, including materials disposed or released by prior owners or operators or
other third parties;
to clean up and remediate contaminated property, including both soils and 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 or any state analog.
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 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 of the United States 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. 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.
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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. Additionally, various federal, state and local agencies have jurisdiction over transportation, storage and
disposal of hazardous waste and seek to regulate movement of hazardous waste in ways not preempted by federal law. We generate
solid and hazardous wastes that are subject to RCRA and comparable state laws. Drilling fluid, produced water and many other wastes
associated with the exploration, development and production of crude oil or natural gas are currently exempt from RCRA’s hazardous
waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-
hazardous could be regulated as hazardous waste in the future. In September 2010, the Natural Resources Defense Council filed a
petition with the EPA, requesting it to reconsider the RCRA hazardous waste exemption for exploration, production and development
wastes. In December 2016, the court entered a Consent Decree resolving the litigation, under which the EPA would issue such a
rulemaking or make a determination that it was not necessary by March 15, 2019. In response, in April 2019, the EPA issued a
determination that rulemaking to address waste from oil and gas exploration and production operations was not necessary at this time.
However, it is possible that the EPA will take up such regulatory changes at a later date. 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 will continue to be regulated by state agencies as solid waste. Also, non-exempt waste streams
generated by us will continue to be subject to existing onerous hazardous waste regulations. Although we do not believe the current
costs of managing our 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.
Where required, costs may be associated with the treatment of wastewater and/or the development and implementation of 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 addition, the CWA requires permits for discharges of dredged or filled materials into waters of the United States. These permits
(“404 Permits”) are under the joint jurisdiction of the EPA and the Army Corps of Engineers. 404 Permits may be required where
development or construction activities have the potential to impact wetland areas that are considered waters of the United States. In
2015, the EPA greatly expanded the definition of waters of the United States. In doing so, it required 404 permits for disturbances in
areas before not considered subject to United States CWA jurisdiction. However, effective December 23, 2019, the rule broadening the
definition was repealed, ostensibly restoring jurisdiction to only those waterbodies (including wetlands) that have a “significant nexus”
to navigable waters of the United States. Further rulemaking to refine the definition of waters of the United States is expected from the
EPA in 2020. Any expansion of the scope of the CWA could increase costs associated with permitting and regulatory compliance.
However, it is expected that any such change would not disparately affect us and our competitors.
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. New Source Performance Standards were promulgated for the oil and gas industry in 2012. These standards set limits
for sulfur dioxide and volatile organic compound emissions and required application of reduced emission completion techniques by the
industry. 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. Federal and state
regulatory agencies can impose penalties for non-compliance with air permits or other requirements of the CAA and associated state
laws and regulations.
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In May 2016, the EPA issued a final rule regulating methane emissions from oil and natural gas operations (the “Subpart OOOOa Rule”).
This rule applies to emissions from new, reconstructed and modified processes and equipment and also requires owners and operators
to find and repair leaks to address fugitive emissions.
Certain states have also adopted, or are considering, regulations addressing methane releases from oil and gas operations. Colorado has
adopted regulations reducing methane emissions from oil and gas operations. Compliance with rules applicable to jurisdictions in which
we operate could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact
our business.
However, in September 2019, the EPA proposed two alternative amendments to the Subpart OOOOa Rule. Both amendments would
remove all methane-specific requirements from production and processing segments. The first amendment would also remove
transportation and storage facilities from the definition of covered facilities. The comment period for the proposed rule closed on
November 25, 2019. The net effect of either of these amendments, if finalized, would significantly reduce compliance obligations and
associated costs.
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. We expect that we will utilize hydraulic fracturing
for the foreseeable future to complete or recomplete wells in areas in which we work. Hydraulic fracturing is typically regulated at the
state level; however, the EPA issued guidance in 2014 to address hydraulic fracturing injections using diesel.
In addition, in June 2016, the EPA issued a final rule promulgating pretreatment standards for discharges of wastewater pollutants from
onshore unconventional oil and gas extraction facilities to publicly-owned treatment works. The EPA, along with other federal agencies
such as the U.S. Department of Energy, the U.S. Government Accountability Office, the U.S. Department of Interior and the White
House Council for Environmental Quality continue to study various aspects of hydraulic fracturing.
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. Multiple states, including Texas, Colorado and Wyoming have
already adopted rules requiring disclosures of chemicals used in hydraulic fracturing and others have enacted regulations imposing
additional requirements on activities involving hydraulic fracturing. Chemical disclosure regulations may increase compliance costs
and may limit our ability to use cutting-edge technology in markets where disclosure is required. Further, laws such as those restricting
the use of or regulating the time, place and manner of hydraulic fracturing (such as setback ordinances) may impact our ability to fully
extract reserves. No assurance can be given as to whether or not such measures might be adopted 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.
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. On July 11, 2014, the EPA
extended the public comment period for the rulemaking to September 18, 2014. The EPA has not yet taken further action with respect
to this rule. 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. In addition, we may be required to disclose information of
third parties, that may be inaccurate or that we may be contractually prohibited from disclosing, which could also subject us to penalties.
In addition, in July 2014, a major university and U.S. Geological Survey researchers published a study purporting to find a 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.
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.
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At present, the EPA may establish GHG permitting requirements for stationary sources already subject to the Prevention of Significant
Deterioration (“PSD”) and Title V requirements of the CAA. 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 October 2016, the EPA proposed revisions to the rule applicable to GHGs for PSD and Title V permitting requirements. The public
comment period for the rulemaking concluded on December 16, 2016. However, although the rulemaking remains on the EPA’s long-
term regulatory agenda, no final rule has been published.
In August 2015, the EPA issued a rule to reduce carbon emissions from electric generating units. The rule, commonly called the “Clean
Power Plan”, required 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. However, in February 2016, the U.S. Supreme Court stayed the implementation of
the Clean Power Plan while it was being challenged in court. On October 16, 2017, the EPA published a proposed rule that would repeal
the Clean Power Plan and on August 18, 2018, the EPA proposed the Affordable Clean Energy (“ACE”) rule as a replacement to the
Clean Power Plan. The EPA issued the final ACE rule in June 2019. As expected, over 20 states and public health and environmental
organizations have challenged the rule. The EPA has sought expedited review in the hopes that the cases will be resolved by the summer
of 2020. If the ACE rule were to become final, the costs of compliance are expected to be significantly less than they would have been
under the Clean Power Plan.
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. Also, in recent years, lawsuits have been brought against other
energy companies for matters relating to climate change. Multiple states and localities have also initiated investigations in climate-
change related matters. While the current suits focus on a variety of issues, at their core they seek compensation for the effects of climate
change from companies with ties to GHG emissions. It is currently unknown what the outcome of these types of actions may be, but
the costs of defending against such actions may be expected to rise. 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 U.S. 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. Recent federal court cases involving
natural gas pipelines have involved challenges to the sufficiency of the evaluation of climate change impacts in environmental impact
statements prepared under NEPA. 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 U.S. 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, 2020, we had approximately 505 full-time employees. 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.
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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:
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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 oil and natural gas;
market demand and capacity limitations on exports of oil and natural gas;
political and economic conditions, including embargoes and sanctions, in oil-producing countries or affecting other oil-producing
activity, such as the U.S. imposed sanctions on Venezuela and Iran and conflicts in the Middle East;
developments of North American energy infrastructure;
the level of global oil and natural gas exploration and production activity;
the effects of global conservation and sustainability measures;
proximity and capacity of oil and natural gas pipelines and other transportation facilities;
the effects of global and domestic economy, including the impact of expected growth, access to credit, financial and other
economic issues;
weather conditions;
technological advances affecting energy consumption;
current and anticipated changes to domestic and foreign governmental regulations, such as regulation of oil and natural gas
gathering and transportation, including those that may arise as a result of the upcoming U.S. Presidential election;
the price and availability of competitors’ supplies of oil and natural gas;
basis differentials associated with market conditions, the quality and location of production and other factors;
acts of terrorism;
the price and availability of alternative fuels; and
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acts of force majeure.
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 experiences extended periods of low prices, we
may, among other things, be unable to meet all of our financial obligations or make planned expenditures.
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 may 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 total outstanding credit exposure exceeds the redetermined borrowing base, we will be
required to prepay outstanding borrowings in an aggregate principal amount equal to such excess in six substantially equal monthly
installments.
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 risk factor entitled “The instruments governing our indebtedness contain various covenants
limiting the discretion of our management in operating our business.”
Alternatively, higher oil, NGL and natural gas prices may result in significant mark-to-market losses being incurred on our commodity-
based derivatives, which may in turn cause us to experience net losses.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our
business, financial condition, results of operations or cash flows.
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. Refer to the risk factor entitled
“Reserve estimates depend on many assumptions that may turn out to be inaccurate...” 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, but not limited to, the following:
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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 by state agencies or on our federal leases, including as a result of government
shutdowns;
pressure or irregularities in geological formations;
pipeline takeaway and refining and processing capacity;
shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs and completion services;
equipment failures or accidents;
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adverse weather events, such as floods, blizzards, ice storms, tornadoes and freezing temperatures; and
title defects.
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, 2019, we had outstanding $262 million of 1.25% Convertible Senior Notes due April 2020 and $2.2 billion of
senior notes, which consisted of $774 million of 5.75% Senior Notes due March 2021, $408 million of 6.25% Senior Notes due April
2023 and $1,000 million of 6.625% Senior Notes due January 2026. We had $375 million of borrowings and $2 million in letters of
credit outstanding under Whiting Oil and Gas Corporation’s (“Whiting Oil and Gas”) credit facility with $1.4 billion of available
borrowing capacity. The credit agreement matures on April 12, 2023, provided that if at any time and for so long as any senior notes
(other than the 1.25% Convertible Senior Notes due April 2020) have a maturity date prior to 91 days after April 12, 2023, the maturity
date shall be the date that is 91 days prior to the maturity of such senior notes. 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, but not limited to:
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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 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;
increasing the possibility that we may be unable to generate sufficient cash to pay, when due, the principal of, interest on or other
amounts due or otherwise refinance our indebtedness;
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
reducing our borrowing base when oil and natural gas prices decline and our ability to maintain compliance with our financial
covenants becomes more difficult, 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. Refer to the risk factor entitled “The instruments governing our indebtedness contain various covenants
limiting the discretion of our management in operating our business.”
If we are unable to generate enough cash flow from operations to service our indebtedness or are unable to use future borrowings
to refinance our indebtedness or fund other capital needs, we may have to undertake alternative financing plans, which may have
onerous terms or may be unavailable.
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Our earnings and cash flow could vary significantly from year to year due to the volatility of oil and natural gas prices. As a result, the
amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow
may be insufficient to meet our debt obligations and commitments. A range of economic, competitive, business and industry factors
will affect our future financial performance and, as a result, our ability to generate cash flow from operations and service our debt.
Factors that may cause us to generate cash flow that is insufficient to meet our debt obligations include the events and risks related to
our business, many of which are beyond our control. Any cash flow insufficiency would have a material adverse impact on our business,
financial condition, results of operations, cash flows and liquidity and our ability to repay or refinance our debt. If we do not generate
sufficient cash flow from operations to service our outstanding indebtedness, or if future borrowings are not available to us in an amount
sufficient to enable us to pay or refinance our indebtedness, we may be required to undertake various alternative financing plans, which
may include:
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refinancing or restructuring all or a portion of our debt;
seeking alternative financing or additional capital investment;
selling strategic assets;
reducing or delaying capital investments; or
revising or delaying our strategic plans.
We cannot assure you that we would be able to implement any of the above alternative financing plans, if necessary, on commercially
reasonable terms or at all. 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. Additionally, the lenders under Whiting Oil and Gas’ credit agreement could terminate their commitments to loan money
and could foreclose against our assets collateralizing our borrowings, and we could be forced into bankruptcy or liquidation. If the
amounts outstanding under any of our significant indebtedness were to be accelerated, we cannot assure you that our assets would be
sufficient to repay in full the amounts owed to the lenders or to our other debt holders. 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 business, financial position, results of operations and cash flows.
A negative shift in investor sentiment of the oil and gas industry could adversely affect our ability to raise debt and equity capital.
Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns
in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition,
some investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments and family
foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. Certain
other stakeholders have also pressured commercial and investment banks to stop financing oil and gas production and related
infrastructure projects.
Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could
result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction
of available capital funding for potential development projects, impacting our future financial results. Refer to the Risk Factor entitled
“Negative public perception regarding us and/or our industry could have an adverse effect on our 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 limit our and our
subsidiaries’ ability to, among other things:
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prepay, redeem or repurchase certain debt;
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pay dividends or make other distributions or repurchase or redeem our capital stock;
make loans and investments;
incur or guarantee additional indebtedness or issue preferred stock;
create certain liens;
enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;
sell assets;
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; and
create unrestricted subsidiaries.
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 and (ii) a total debt to last four quarters’
EBITDAX ratio of not greater than 4.0 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. 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. Factors that may adversely affect our ability to comply with
these covenants include oil or natural gas price declines, lack of liquidity in property and capital markets and our inability to execute on
our business plan.
If we fail to comply with the restrictions in the indentures governing our senior notes and convertible senior notes, 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 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.
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 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 decline, our borrowing
base could be reduced at the next redetermination date or during future redeterminations. Upon a redetermination, if total outstanding
credit exposure exceeds the redetermined borrowing base, we will be required to prepay outstanding borrowings in an aggregate principal
amount equal to such excess in six substantially equal monthly installments. We may not have sufficient funds to make such repayments.
Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging, and a
failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our business, financial
condition, results of operations or cash flows.
Our future growth prospects are dependent upon our ability to identify optimal strategies for investing our capital resources to produce
rates of return. In developing our business plan, we consider allocating capital and other resources to various aspects of our business
including well development (primarily drilling), reserve acquisitions, exploratory activity, corporate items and other alternatives. We
also consider our likely sources of capital, including cash generated from operations and borrowings under Whiting Oil and Gas’ credit
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agreement. Notwithstanding the determinations made in the development of our business plan, business opportunities not previously
identified periodically come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business
strategies or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of
our business strategies, our financial condition and future growth may be adversely affected. Moreover, economic or other circumstances
may change from those contemplated by our business plan and our failure to recognize or respond to those changes may limit our ability
to achieve our objectives.
A large portion of our producing properties are concentrated in the Williston Basin of North Dakota and Montana, making us
vulnerable to risks associated with operating in one major geographic area.
A large portion of our producing properties are geographically concentrated in the Williston Basin of North Dakota and Montana. At
December 31, 2019, approximately 93% of our total estimated proved reserves were attributable to properties located in this area.
Because of this concentration in a limited geographic area, the success and profitability of our operations may be disproportionately
exposed to regional factors compared to competitors having more geographically dispersed operations. These factors include, among
others: (i) the prices of crude oil and natural gas produced from wells in the region and other regional supply and demand factors,
including gathering, pipeline and rail transportation capacity constraints, (ii) the availability of rigs, equipment, oilfield services, supplies
and labor, (iii) the availability of processing and refining facilities and (iv) infrastructure capacity. In addition, our operations in the
Williston Basin may be adversely affected by severe weather events such as floods, blizzards, ice storms, tornadoes and freezing
temperatures which can intensify competition for the items and services described above and may result in periodic shortages. The
concentration of our operations in a limited geographic area also increases our exposure to changes in local laws and regulations, certain
lease stipulations designed to protect wildlife and unexpected events that may occur in the regions such as natural disasters, seismic
events (which may result in third-party lawsuits), industrial accidents, labor difficulties, civil disturbances, public protests or terrorist
attacks. Any one of these events has the potential to cause producing wells to be shut-in, delay operations, decrease cash flows, increase
operating and capital costs and prevent development of lease inventory before expiration. Any of the risks described above could have
a material adverse effect on our business, financial condition, results of operations and cash flows.
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, possible asset sales and
other factors) we may be required to write down the carrying value of our oil and gas properties. For example, we recorded an
$835 million impairment charge during 2017 for the partial write-down of the Redtail field in Colorado. 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 business, financial condition, results of operations or cash flows in the period recognized.
We may continue to incur cash and noncash charges that would negatively impact our future results of operations and liquidity.
While executing our strategic priorities to reduce financial leverage and complexity and to lower our capital expenditures in the face of
lower commodity prices, we have incurred certain cash charges. As we continue to focus on our strategic priorities, we may incur
additional cash and noncash charges in the future. If incurred, these charges could have a material adverse effect on our liquidity and
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. We expect that we will utilize hydraulic fracturing for the
foreseeable future to complete or recomplete wells in the areas in which we work. Hydraulic fracturing is typically regulated at the state
level, however, the U.S. Environmental Protection Agency (the “EPA”) issued guidance in 2014 to address hydraulic fracturing
injections involving diesel. In addition, in June 2016, the EPA issued a final rule promulgating pretreatment standards for discharges
of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works. The EPA,
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along with other federal agencies such as the U.S. Department of Energy, the U.S. Government Accountability Office, the U.S.
Department of Interior and the White House Council for Environmental Quality continue to study various aspects of hydraulic fracturing.
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. Multiple states, including Texas, Colorado and Wyoming have
already adopted rules requiring disclosures of chemicals used in hydraulic fracturing and others have enacted regulations imposing
additional requirements on activities involving hydraulic fracturing. Chemical disclosure regulations may increase compliance costs
and may limit our ability to use cutting-edge technology in markets where disclosure is required. Further, laws such as those restricting
the use of or regulating the time, place and manner of drilling or hydraulic fracturing (such as setback ordinances) may impact our ability
to fully extract reserves. No assurance can be given as to whether or not such 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.
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. On July 11, 2014, the EPA
extended the public comment period for the rulemaking to September 18, 2014. The EPA has not yet taken further action with respect
to this rule. 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. In addition, we may be required to disclose information of
third parties, which may be inaccurate or which we may be contractually prohibited from disclosing, which could also subject us to
penalties.
In addition, in July 2014, a major university and U.S. Geological Survey researchers published a study purporting to find a 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.
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.
As of December 31, 2019, we had 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, the second is tied to oil production in the
Williston Basin and the third is 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 commitments at our Sanish field in North Dakota and the Williston Basin,
if we fail to deliver the committed volumes, we would be required to pay deficiency payments of $7.00 and $5.75, respectively, per
undelivered barrel (subject to upward adjustment). At our Redtail field, we have determined that it is not probable that future oil
production will be sufficient to meet the minimum volume requirements under the contract in this area. We expect to make periodic
deficiency payments under the Redtail contract that currently total $5.24 per undelivered Bbl through the April 2020 termination date.
During 2019, 2018 and 2017, total deficiency payments under this contract amounted to $64 million, $37 million and $42 million,
respectively. Refer to “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.
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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, among others:
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historical production from the area compared with production rates from other producing areas;
the assumed effect of governmental regulation; and
assumptions about future prices of oil, NGLs and natural gas including differentials, production and development costs, gathering
and transportation costs, severance and excise taxes, capital expenditures and availability of funds.
Therefore, estimates of oil and natural gas reserves are inherently imprecise. Actual future production, oil, NGL and natural gas prices,
revenues, taxes, exploration and development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves
will most likely vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of
reserves referred to in this Annual Report on Form 10-K. In addition, we may adjust estimates of proved reserves to reflect production
history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our
control.
You should not assume that the present value of future net revenues from our proved reserves, as referred to in this report, is the current
market value of our estimated proved oil and natural gas reserves. In accordance with SEC requirements, we base the estimated
discounted future net cash flows from our proved reserves on 12-month average prices and current costs as of the date of the estimate.
The 12-month average prices used for the year ended December 31, 2019 were $55.69 per Bbl of oil and $2.58 per MMBtu of natural
gas. Actual future prices and costs may differ materially from those used in the estimate. If the 12-month average oil prices used to
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, 2019 would have decreased by $137 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, 2019 would have decreased by $41 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 internally generated cash flows, equity and debt issuances, bank borrowings, agreements
with industry partners and oil and gas property divestments. We intend to finance future capital expenditures substantially with cash
flow from operations, cash on hand, borrowings under our credit agreement and proceeds from asset divestitures. Our cash flow from
operations and access to capital is subject to a number of variables, including, but not limited to:
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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. Disruptions in the capital and credit markets, particularly in the energy sector, could limit our ability to access these markets
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or may significantly increase our cost to borrow. If cash generated by operations or available under our revolving credit facility is not
sufficient to meet our capital requirements, the inability to access the cash and credit markets to obtain additional financing, on favorable
terms or otherwise, 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.
Unless we replace our oil and natural gas reserves, our reserves and production will decline, we may not be able to sustain production.
Unless we conduct successful exploration, development and production activities or acquire properties containing proved reserves, our
proved reserves will decline over time. 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 finding economically recoverable or acquiring additional economically recoverable reserves. In pursuing acquisitions, we compete
with other companies, many of which have greater financial and other resources to acquire attractive companies or properties. Therefore,
we may not be able to develop, find or acquire additional reserves to sustain or replace our current and future production, which could
adversely affect our business, financial condition, results of operations or cash flows.
Our credit rating could negatively impact our availability and cost of capital and could require us to post more collateral under
certain commercial arrangements.
Some of our counterparties have requested or required us to post collateral as financial assurance of our performance under certain
contractual arrangements, such as gathering, transportation, processing and hedging agreements. These collateral requirements depend,
in part, on our credit rating. We may be requested or required by other counterparties to post additional collateral, which may be in the
form of additional letters of credit, cash or other acceptable collateral. Any downgrade to our credit ratings could impact the posting of
collateral consisting of cash or letters of credit, which would reduce availability under our credit agreement and negatively impact our
liquidity.
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 are 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,
downstream market conditions and competing supply alternatives. Our ability to market our production also depends substantially on
the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties and the ability
to obtain such services on acceptable terms. We may be disproportionately exposed to the impact of delays or interruptions of production
caused by market constraints or the interruption of transporting oil and gas produced. This could lead to production curtailments or
shut-ins, and reduced revenue which could materially harm our business. We may enter into arrangements for transportation services
and sales to reduce curtailment risks. However, these services expose us to the risk that third parties will default on their obligations
under such arrangements.
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. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing
operations. 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, NGL 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
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alternative means to transport oil, NGL and natural gas production, which alternative means could result in additional costs that will
have the effect of increasing transportation expenses.
Also, accidents 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.
In addition, drilling, production and transportation of hydrocarbons bear the inherent risk of loss of containment. Potential consequences
include, but are not limited to, loss of reserves, loss of production, loss of economic value associated with the affected wellbore, personal
injuries and death, contamination of air, soil, ground water and surface water, as well as potential fines, penalties or damages associated
with any of the foregoing consequences.
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 in 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 but not limited to indemnification provisions, which could result in us retaining
substantial liabilities.
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, 2019, 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 18% in 2020, 13% in 2021 and 15% in 2022. 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, financial condition, results of operations or cash flows.
The unavailability or 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
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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, financial condition, results of
operations or cash flows or require us to remove certain proved undeveloped reserves from our proved reserve base if we are unable to
drill those PUD locations within the SEC’s 5-year window.
Weaker price differentials and/or weaker benchmark prices of oil and natural gas and the wellhead price we receive could have a
material adverse effect on our business, financial condition, results of operations or 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 or positive difference between the benchmark price and the price received is
called a differential. The differential may vary significantly due to market conditions, the quality and location of production and other
risk factors, as demonstrated in the fourth quarter of 2018 when our oil differentials weakened substantially. We cannot accurately
predict oil and natural gas differentials. Changes in the differential and decreases in the benchmark price for oil and natural gas could
have a material adverse effect on our business, financial condition, results of operations or cash flows.
Properties that we acquire may not produce as projected, and we may be unable to identify liabilities associated with the properties
or obtain indemnities from sellers for liabilities they may have created.
Our business strategy includes a continuing acquisition program. From 2010 through 2019, we completed 7 separate significant
acquisitions of producing properties with a combined purchase price of $4.6 billion for estimated proved reserves as of the effective
dates of the acquisitions of 240.2 MMBOE. The successful acquisition of producing properties requires assessment of many factors,
which are inherently inexact and may be inaccurate, including, but not limited to, the following:
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the anticipated levels of recoverable reserves, earnings or cash flow;
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, title defects,
historical spills or releases for which we are not indemnified or for which our indemnity is inadequate.
Furthermore, acquisitions pose substantial risks to our business, financial condition, results of operations and cash flows. The risks
associated with acquisitions, either completed or future acquisitions, include, but are not limited to:
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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; and
we may issue additional equity or debt securities in order to fund future acquisitions.
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,
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when they are made. We may not be able to obtain contractual indemnities from the seller for liabilities that it created. We may be
required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in
accordance with our expectations.
Our use of oil and natural gas price hedging contracts involves 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 February 20, 2020, we had contracts covering the
sale of 31 MMBbl of oil per day for the remainder of 2020 and 6 MMBbl of oil per day for all of 2021. All of our oil hedges will expire
by December 2021. Refer to “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A and the “Derivative Financial
Instruments” footnote of the consolidated financial statements in Item 8 of this Annual Report on Form 10-K for pricing information
and a more detailed discussion of our hedging transactions.
We may in the future enter into these and other types of hedging arrangements to reduce our exposure to fluctuations in the market
prices of oil and natural gas, or alternatively, we may decide to unwind or restructure the hedging arrangements we previously entered
into. Hedging transactions expose us to risk of financial loss in some circumstances, including if production is less than expected, the
other party to the contract defaults on its obligations or there is a change in the expected differential between the underlying price in the
hedging agreement and actual prices received. Hedging transactions may limit the benefit we may otherwise receive from increases in
the price for oil and natural gas. Our three-way collars only provide partial protection against declines in market prices due to the fact
that when the market price falls below the sub-floor, the minimum price we will receive will be NYMEX plus the difference between
the floor and 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 certain 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.
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, results of operations or cash flows. 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, but not limited to, the
possibility of:
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environmental hazards, such as uncontrollable flows of oil, gas, brine, well fluids, toxic gas or other pollution into the environment,
including groundwater and shoreline contamination;
abnormally pressured formations;
mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
the loss of well control;
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fires and explosions;
personal injuries and death;
terrorist attacks; 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 88% of our net productive oil and natural gas wells, which represents 92% of our proved developed producing reserves as
of December 31, 2019. If we do not operate the properties in which we own an interest, we do not have control over normal operating
procedures, expenditures or future development of our properties. The failure of an operator of our wells to adequately perform
operations or an operator’s breach of the applicable agreements could reduce our production and revenues. The success and timing of
our drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our
control, including the operator’s decisions with respect to the timing and amount of capital expenditures, the period of time over which
the operator seeks to generate a return on capital expenditures, inclusion of other participants in drilling wells, and the use of technology,
as well as the operator’s expertise and financial resources and the operator’s relative interest in the field. Operators may also opt to
decrease operational activities following a significant decline in, 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.
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.
Our drilling results in undeveloped acreage in new or emerging plays 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 2018 we recorded an $8 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. Refer to “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.
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, but are not limited to:
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discharge permits for drilling operations;
drilling bonds;
reports concerning operations;
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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 and litigation.
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 business, financial condition, results of operations or cash
flows. Strict liability or joint and several liability may be imposed under certain laws, which could cause us to become liable for the
conduct of others or for consequences of our own actions. For instance, an accidental release from one of our wells could subject us to
substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third
parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations.
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 discharge 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; limit or prohibit drilling activities on certain lands; and impose substantial liabilities for unauthorized discharges. 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, the imposition of injunctive relief, or certain leases could be cancelled in the event that an agency
refuses to issue or delays the issuance of a required permit. Under these environmental laws and regulations, we could be held strictly
liable for the removal or remediation of previous 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. We may not be able to recover some or any of these costs from insurance. Moreover, federal law and some
state laws allow the government to place a lien on real property for costs incurred by the government to address contamination on the
property.
Changes in environmental laws and regulations occur frequently and may have a materially adverse impact on our business. Compliance
with any enacted 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 of environmental laws and regulations.
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 regard 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 requirements were further expanded again in 2016 when the implementation of Subpart OOOOa applied limits on methane
emissions to oil and gas facilities and required operators to address leaks, also known as “fugitive emissions.”
However, in September 2019, the EPA proposed two alternative amendments to the Subpart OOOOa Rule. Both amendments remove
all methane-specific requirements from production and processing segments. The first amendment would also remove transportation
and storage facilities from the definition of covered facilities. The comment period for proposed rule closed on November 25, 2019.
The net effect of any of these amendments, if finalized, would significantly reduce compliance obligations and associated costs.
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The enactment of Senate Bill 19-181 “Protect Public Welfare Oil And Gas Operations” increased the regulatory authority of local
governments in Colorado over the surface impacts of oil and gas development, which could have a material adverse effect on our
business, financial condition, results of operations or cash flows.
In Colorado, on April 16, 2019, Governor Polis signed into law the final version of Senate Bill 19-181 (“SB 181”), known as the “Protect
Public Welfare Oil and Gas Operations” legislation. SB 181 amends the Oil and Gas Conservation Act and other statutes to change the
manner in which oil and gas development is regulated in Colorado and provide the opportunity for greater control to local governments.
The amendments include changes to expand the authority of local governments relating to oil and gas development, as well as rulemaking
requirements involving the Colorado Oil and Gas Conservation Commission (“COGCC”) and the Air Quality Control Commission
(“AQCC”) that could include more stringent air emission limits for pollutants such as methane and volatile organic carbons and more
rigorous permitting requirements. In December 2019, Colorado’s AQCC adopted new rules targeting air emissions from upstream oil
and gas operations, and depending on the results of other ongoing and upcoming rulemakings and actions by COGCC, the Colorado
Department of Public Health and Environment and local jurisdictions, SB 181 could result in greater restrictions with respect to oil and
gas development in Colorado, which could have a material adverse effect on our business, financial condition, results of operations or
cash flows. Efforts similar to SB 181 are likely to continue in the future, which, if successful, could result in dramatically reducing the
area available for future oil and gas development or outright banning oil and gas development in certain jurisdictions. We cannot predict
the nature or outcome of future ballot initiatives, legislative actions or other similar efforts, or the effects of implementation of these
efforts by local governments. If we are required to cease operating in any of the areas in which we now operate as the result of bans or
moratoria on drilling or related oilfield services activities, it could have a material effect on our business, financial condition, and results
of operations.
Issues surrounding climate change and greenhouse gas emissions 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.
At present, the EPA may establish GHG permitting requirements for stationary sources already subject to the Prevention of Significant
Deterioration (“PSD”) and Title V requirements of the CAA. 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 October 2016, the EPA proposed revisions to the rule applicable to GHGs for PSD and Title V permitting requirements. The public
comment period for the rulemaking concluded on December 16, 2016. However, although the rulemaking remains on the EPA’s long-
term regulatory agenda, no final rule has been published.
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. However, in February 2016, the U.S. Supreme Court stayed the implementation of
the Clean Power Plan while it was being challenged in court. On October 16, 2017, the EPA published a proposed rule that would repeal
the Clean Power Plan and on August 18, 2018, the EPA proposed the Affordable Clean Energy (“ACE”) rule as a replacement to the
Clean Power Plan. The EPA issued the final ACE rule in June 2019. As expected, over 20 states and public health and environmental
organizations have already challenged the rule. The EPA has sought expedited review in the hopes that the cases will be resolved by
the summer of 2020.
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.
Also, in recent years, lawsuits have been brought against other energy companies for matters relating to climate change. Multiple states
and localities have also initiated investigations in climate-change related matters. While the current suits focus on a variety of issues,
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at their core they seek compensation for the effects of climate change from companies with ties to GHG emissions. It is currently
unknown what the outcome of these types of actions may be, but the costs of defending against such actions may rise. Finally, 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.
Negative public perception regarding us and/or our industry could have an adverse effect on our operations.
Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups
about hydraulic fracturing, waste disposal, oil spills, seismic activity, climate change, explosions of natural gas transmission lines and
the development and operation of pipelines and other midstream facilities may lead to increased regulatory scrutiny, which may, in turn,
lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. Additionally,
environmental groups, landowners, local groups and other advocates may oppose our operations through organized protests, attempts to
block or sabotage our operations or those of our midstream transportation providers, intervene in regulatory or administrative
proceedings involving our assets or those of our midstream transportation providers, or file lawsuits or other actions designed to prevent,
disrupt or delay the development or operation of our assets and business or those of our midstream transportation providers. These
actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of
litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public
may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits
we require to conduct our operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct
our business.
Recently, activists concerned about the potential effects of climate change have directed their attention towards sources of funding for
fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or
eliminating their investment in energy-related activities. Ultimately, this could make it more difficult to secure funding for exploration
and production activities.
A low ESG or sustainability score could result in the exclusion of our common shares from consideration by certain investment
funds and a negative perception of us by certain investors.
Certain organizations that provide corporate governance and other corporate risk information to investors and shareholders have
developed scores and ratings to evaluate companies and investment funds based upon environmental, social and governance (“ESG”)
or sustainability metrics. Currently, there are no universal standards for such scores or ratings, but the importance of sustainability
evaluations is becoming more broadly accepted by investors and shareholders. Many investment funds focus on positive ESG business
practices and sustainability scores when making investments. In addition, investors, particularly institutional investors, use these scores
to benchmark companies against their peers and if a company is perceived as lagging, these investors may engage with companies to
require improved ESG disclosure or performance. Moreover, certain members of the broader investment community may consider a
company’s sustainability score as a reputational or other factor in making an investment decision. Consequently, a low sustainability
score could result in exclusion of our common shares from consideration by certain investment funds, engagement by investors seeking
to improve such scores and a negative perception of us by certain investors.
We may be negatively impacted by litigation and legal proceedings.
We are subject from time to time, and in the future may become subject, to litigation claims. These claims and legal proceedings are
typically claims that arise in the normal course of business and include, without limitation, claims relating to environmental, safety and
health matters, commercial or contractual disputes with suppliers and customers, claims regarding ownership of mineral interests,
including from royalty owners, claims regarding acquisitions and divestitures, regulatory matters and employment and labor matters.
We may also become subject to governmental or regulatory proceedings. The outcome of such claims and legal proceedings cannot be
predicted with certainty and some may be disposed of unfavorably to us. Among other pending litigation claims, the Company is
involved with litigation related to a payment arrangement with a third party which currently claims damages up to $41 million, as well
as court costs and interest. We also may not have insurance that covers such claims and legal proceedings. Successful claims or
litigation against us for significant amounts could have a material adverse effect on our reputation, business, financial condition, results
of operations and cash flows. Further, even if successful in resolving a claim or legal proceeding, such process could require the attention
of members of our senior management, reducing the time they have available to devote to managing our business, and require us to
incur substantial legal expenses.
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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 Bradley J. Holly, Chairman, President and Chief Executive Officer; Bruce DeBoer, Chief
Administrative Officer, General Counsel and Corporate Secretary; Charles J. Rimer, Chief Operating Officer; Correne S. Loeffler, Chief
Financial Officer; and Timothy M. Sulser, Chief Corporate Development and Strategy Officer, could have a material adverse effect on
our business, financial condition, results of operations or cash flows. We do not maintain, nor do we plan to obtain, any insurance
against the loss of any of these individuals.
We expect to consider from time to time further strategic opportunities that may involve acquisitions, dispositions, investments in
joint ventures, partnerships, and other strategic alternatives that may enhance shareholder value, any of which may result in the use
of a significant amount of our management resources or significant costs, and we may not be able to fully realize the potential benefit
of such transactions.
We expect to continue to consider acquisitions, dispositions, investments in joint ventures, partnerships, and other strategic alternatives
with the objective of maximizing shareholder value. The Board and our management may from time to time be engaged in evaluating
potential transactions and other strategic alternatives. In addition, from time to time, we may engage financial advisors, enter into non-
disclosure agreements, conduct discussions, and undertake other actions that may result in one or more transactions. Although there
would be uncertainty that any of these activities or discussions would result in definitive agreements or the completion of any transaction,
we may devote a significant amount of our management resources to analyzing and pursuing such a transaction, which could negatively
impact our operations, and may impair our ability to retain and motivate key personnel. In addition, we may incur significant costs in
connection with seeking such transactions or other strategic alternatives regardless of whether the transaction is completed. In the event
that we consummate an acquisition, disposition, partnership or other or strategic alternative in the future, we cannot be certain that we
would fully realize the potential benefit of such a transaction and cannot predict the impact that such strategic transaction might have
on our operations or stock price. Any potential transaction would be dependent upon a number of factors that may be beyond our
control, including, among other factors, market conditions, industry trends, regulatory limitations and the interest of third parties in us
and our assets. There can be no assurance that the exploration of strategic alternatives will result in any specific action or transaction.
Further, any such strategic alternative may not ultimately lead to increased shareholder value. We do not undertake to provide updates
or make further comments regarding the evaluation of strategic alternatives, unless otherwise required by law.
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 on economically acceptable terms or at all.
Competition in the oil and gas industry and from alternative energy sources 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. 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.
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We also face indirect competition from alternative energy sources, including wind, solar, nuclear and electric power. The proliferation
of alternative energy sources and businesses that provide such alternative energy sources may decrease the demand for oil and natural
gas products. Decreased demand for our products could adversely affect our business, financial condition, results of operations or cash
flows.
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, such as us, 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. 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 cybersecurity attacks could have an adverse
effect on our business, financial condition, results of operations or cash flows.
Our business has become increasingly dependent upon digital technologies to conduct day-to-day operations, including information
systems, infrastructure and cloud applications. 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. We rely on such systems to process, transmit and store electronic information, including financial records and personally
identifiable information such as contractor, investor and payroll data, and to manage or support a variety of business processes, including
our supply chain, pipeline operations, gathering and processing operations, financial transactions, banking and numerous other processes
and transactions.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, also have
increased in frequency. A cyber-attack could include unauthorized access to digital systems for purposes of misappropriating assets or
sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. It is possible that
we could incur interruptions from cybersecurity attacks, computer viruses or malware, or that third party service providers could cause
a breach of our data. We believe that we have positive relations with our related vendors and maintain adequate anti-virus and malware
software and controls over personally identifiable information and contractor data; however, any interruptions to our arrangements with
third parties for our computing and communications infrastructure or any other interruptions to, or breaches of, our information systems
could lead to data corruption, communication interruption, loss of sensitive or confidential information or otherwise significantly disrupt
our business operations.
Strategic targets, such as energy-related assets and transportation assets, may be at greater risk of future cyber-attacks than other targets.
The various procedures, facilities, infrastructure and controls we utilize to monitor these threats and mitigate our exposure to such threats
are costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches
from occurring. We do not expect to obtain or maintain specialized insurance for possible liability or loss resulting from a cyber-attack
on our assets that may shut down all or part of our business. However, as cyber threats continue to evolve, we may be required to expend
significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information
security vulnerabilities. State and federal cybersecurity legislation could also impose new requirements, which could increase our cost
of doing business.
To our knowledge we have not experienced any material losses relating to cyber-attacks; however, there can be no assurance that we
will not suffer material losses in the future either as a result of an interruption to or a breach of our systems or those of our third party
35
vendors and service providers. A cyber incident involving our information systems and related infrastructure, or that of third parties,
could disrupt our business plans and negatively impact our operations in the following ways, among others, any of which could have an
adverse effect on our reputation, business, financial condition, results of operations or cash flows:
•
•
•
•
•
•
unauthorized disclosure of sensitive or personally identifiable information, including by cyber-attacks or other security breaches,
could cause loss of data, give rise to remediation or other expenses, expose us to liability under federal and state laws, reduce our
customers’ willingness to do business with us, disrupt the services we provide to customers and subject us to litigation and
investigations;
a cyber-attack on a third party could result in supply chain disruptions which could delay or halt development of additional
infrastructure, effectively delaying the start of cash flow from the project;
a cyber-attack on downstream or midstream pipelines could prevent us from delivering product, resulting in a loss of revenues;
a cyber-attack on a communications network or power grid could cause operational disruption resulting in a loss of revenues;
a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory
fines or penalties; and
business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation, or a
negative impact on the price of our common shares.
Item 1B. Unresolved Staff Comments
None.
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 756,800 gross (476,300 net) developed and undeveloped acres as
of December 31, 2019. Our estimated proved reserves in the Northern Rocky Mountains as of December 31, 2019 were 453.5 MMBOE
(54% oil), which represented 93% of our total estimated proved reserves and contributed 112.0 MBOE/d of average daily production in
the fourth quarter of 2019.
Across our acreage in the Williston Basin, we have implemented customized, right-sized completion designs which utilize the optimum
volume of proppant, diversion, fluids and frac stages to increase well performance while reducing cost. We plan to continue to use
right-sized completion designs on wells we drill in 2020, while also utilizing state-of-the-art drilling rigs, high-torque mud motors and
evolving 3-D bit cutter technology to reduce time-on-location and total well cost. Our engineers have worked with service providers to
optimize fluid systems and bit designs to increase drill rate and hole cleaning resulting in higher capital efficiency in the drilling program.
As of December 31, 2019, we had four rigs active in the Williston Basin.
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 96,400 gross (84,600 net)
developed and undeveloped acres as of December 31, 2019. Our estimated proved reserves in the Central Rocky Mountains as of
December 31, 2019 were 23.1 MMBOE (61% oil), which represented 5% of our total estimated proved reserves and contributed 10.4
MBOE/d of average daily production in the fourth quarter of 2019.
36
We have established production in the Niobrara “A”, “B” and “C” zones and the Codell/Fort Hays formations. We completed 22 drilled
uncompleted wells (“DUCs”) in our Redtail field during the first half of 2018, and no additional wells were drilled or completed in
2019. During 2019 we worked on maintaining base production in this area with improved artificial lift techniques and reductions in
lease operating expenses.
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, 2019, the plant was processing 22 MMcf/d.
Other
Our other operations primarily relate to non-core assets in Colorado, Mississippi, North Dakota, Texas and Wyoming. As of
December 31, 2019, these properties contributed 8.8 MMBOE (83% oil) of proved reserves to our portfolio of operations, which
represented 2% of our total estimated proved reserves and contributed 0.6 MBOE/d of average daily production in the fourth quarter of
2019.
Reserves
As of December 31, 2019 and 2018, 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, 2019 and 2018 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, 2019 and 2018,
respectively) is as follows:
2019
Proved developed reserves
Proved undeveloped reserves
Total proved reserves
2018
Proved developed reserves
Proved undeveloped reserves
Total proved reserves
Oil
(MBbl)
NGLs
(MBbl)
Natural Gas
(MMcf)
Total
(MBOE)
190,725
77,528
268,253
194,869
92,095
286,964
72,102
21,739
93,841
82,725
28,559
111,284
576,213
163,829
740,042
529,154
201,930
731,084
358,863
126,572
485,435
365,786
154,309
520,095
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 34.0 MMBOE in 2019 were primarily attributable to successful drilling in the Williston Basin. Both
the new wells drilled in this area as well as the PUD locations added as a result of drilling increased our proved reserves.
Sales of minerals in place totaled 4.9 MMBOE during 2019 and were primarily attributable to the disposition of certain non-operated
properties in North Dakota as further described in “Acquisitions and Divestitures” within Item 1 of this Annual Report on Form 10-K.
In 2019, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 17.9 MMBOE.
Included in this change were upward revisions of 48.0 MMBOE to proved undeveloped reserves primarily located in the Williston Basin
in locations where we have significant development activity and past drilling success. Offsetting these upward reserve revisions were:
(i) 32.9 MMBOE of downward adjustments caused by lower crude oil, NGL and natural gas prices incorporated into our reserve
estimates at December 31, 2019 as compared to December 31, 2018, (ii) 19.3 MMBOE of downward adjustments primarily attributable
to reservoir analysis and well performance across our Northern and Central Rockies assets and (iii) 13.7 MMBOE of proved undeveloped
reserves no longer expected to be developed within five years from their initial recognition.
37
Proved undeveloped reserves. Our PUD reserves decreased 18% or 27.7 MMBOE on a net basis from December 31, 2018 to
December 31, 2019. The following table provides a reconciliation of our PUDs for the year ended December 31, 2019:
PUD balance—December 31, 2018
Converted to proved developed through drilling
Added from extensions and discoveries
Sold
Revisions
PUD balance—December 31, 2019
Total
(MBOE)
154,309
(42,801)
19,436
(2)
(4,370)
126,572
During 2019, we incurred $475 million in capital expenditures, or $11.10 per BOE, to drill and bring on-line 42.8 MMBOE of PUD
reserves. In addition, we added 19.4 MMBOE of PUDs from extensions and discoveries during the year primarily due to successful
drilling in the Williston 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. In that regard, under our current 2020 development plan, we expect to
convert approximately 48.1 MMBOE of PUDs to proved developed reserves during the year.
Preparation of reserves estimates. We maintain adequate and effective internal controls over the reserve estimation process as well as
the underlying data upon which reserve estimates are based. The primary inputs to the reserve estimation process are comprised of
technical information, financial data, ownership interests and production data. All field and reservoir technical information, which is
updated annually, is assessed for validity when the reservoir engineers hold technical meetings with geoscientists, operations and land
personnel to discuss field performance and to validate future development plans. Current revenue and expense information is obtained
from our accounting records, which are subject to our internal controls over financial reporting. Internal controls over financial reporting
are assessed for effectiveness annually using the criteria set forth in Internal Control – Integrated Framework (2013) issued by the
Committee of Sponsoring Organizations of the Treadway Commission. All current financial data such as commodity prices, lease
operating expenses, transportation, gathering, compression and other 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, President. Mr. Brooker is a
State of Texas Licensed Professional Engineer. Refer to 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.
Trina Medina, our Director of Reservoir Engineering, is responsible for overseeing the preparation of the reserves estimates. She has
more than 25 years of broad reservoir engineering experience in the oil and gas industry, focused across conventional, unconventional
and secondary recovery evaluation and development projects, including corporate reserves estimations. Ms. Medina holds a Bachelor
of Science degree in petroleum engineering from the Universidad Central de Venezuela, a Master of Science degree in reservoir
engineering from Texas A&M University and a Master of Science degree in reservoir geoscience from the Institut Francais du Petrole.
Ms. Medina is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
38
Acreage
The following table summarizes gross and net developed and undeveloped acreage by core area at December 31, 2019. 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
Gross
Gross
Developed Acreage
Net
435,029
36,264
52,351
523,644
698,891
39,716
85,570
824,177
Undeveloped Acreage (1)
Total Acreage
57,905
56,646
56,817
171,368
Net
41,302
48,343
24,420
114,065
756,796
96,362
142,387
995,545
Net
476,331
84,607
76,771
637,709
(1) Out of a total of approximately 171,400 gross (114,100 net) undeveloped acres as of December 31, 2019, 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 18% in 2020, 13% in 2021 and 15% in 2022.
(2) Other includes Arkansas, Colorado, Louisiana, Michigan, Mississippi, New Mexico, Oklahoma, Texas, Utah and Wyoming.
Production History
The following table presents historical information about our produced oil and gas volumes:
Year Ended December 31,
2018
2017
2019
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)
29.8
7.6
50.5
45.8
125.5
5.8
1.1
7.6
8.2
31.5
7.4
46.8
46.7
128.0
6.2
1.2
7.2
8.6
Average sales prices (before the effects of hedging)
Oil (per Bbl)
NGLs (per Bbl)
Natural gas (per Mcf)
Average production costs (per BOE)
Lease operating expenses
Transportation, gathering, compression and other
$
$
$
$
$
50.06
6.76
0.57
7.17
0.93
$
$
$
$
$
58.70
20.78
1.66
6.68
1.03
$
$
$
$
$
29.3
7.0
41.3
43.1
118.1
5.7
1.1
7.1
8.0
44.30
16.00
1.78
6.47
2.10
(1) The Sanish field was our only field that contained 15% or more of our total proved reserve volumes during the periods presented.
Productive Wells
The following table summarizes gross and net productive oil and natural gas wells by core area at December 31, 2019. 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.
39
Northern Rocky Mountains
Central Rocky Mountains
Other (2)
Total
Oil Wells
Gross
3,022
392
1,541
4,955
Net
1,426
312
396
2,134
Natural Gas Wells
Net
Gross
Gross
Total Wells(1)
-
-
66
66
-
-
37
37
3,022
392
1,607
5,021
Net
1,426
312
433
2,171
(1) 20 wells have multiple completions, and these 20 wells contain a total of 41 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, New Mexico, North Dakota, Texas and Wyoming.
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.
2019
Development
Exploratory
Total
2018
Development
Exploratory
Total
2017
Development
Exploratory
Total
Productive
Gross Wells
Dry
Total
Productive
Net Wells
Dry
Total
208
-
208
210
1
211
238
-
238
2
-
2
-
-
-
-
-
-
210
-
210
210
1
211
238
-
238
93.9
-
93.9
120.9
0.8
121.7
164.1
-
164.1
0.1
-
0.1
-
-
-
-
-
-
94.0
-
94.0
120.9
0.8
121.7
164.1
-
164.1
As of December 31, 2019, we had four operated drilling rigs active on our properties in our Northern Rocky Mountains area. As of
December 31, 2019, we had 129 gross (57.1 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 North Dakota, Montana and Colorado and we plan to continue to utilize this
completion methodology.
Substantially all of our 126.6 MMBOE of proved undeveloped reserves are associated with hydraulic fracture treatments.
40
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.
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 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 our active areas; and
we are a member of the Sakakawea Area Spill Response LLC (“SASR”), which is comprised of 17 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.
As of December 31, 2019, 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 crude oil production from the Williston Basin and requires delivery of 10 MBbl/d for a term of seven
years. The effective date of this contract is contingent upon the completion of certain related pipelines, which are currently expected to
be brought online in 2021. Under the terms of this contract, if we fail to deliver the committed volumes we will be required to pay a
deficiency payment of $5.75 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 in the Williston Basin, and we therefore expect to avoid
any payments for deficiencies under this contract.
41
Our two remaining physical delivery contracts are effective as of December 31, 2019. One of these contracts is tied to oil production at
our Sanish field in Mountrail County, North Dakota and is effective for a term of seven years ending May 31, 2024. The other contract
is tied to oil production at our Redtail field in Weld County, Colorado and terminates in April 2020. The following table summarizes
our Sanish and Redtail delivery commitments as of December 31, 2019:
Period
Jan - Dec 2020
Jan - Dec 2021
Jan - Dec 2022
Jan - Dec 2023
Jan - Dec 2024
Sanish Contracted
Crude Oil Volumes
(Bbl)
5,490,000
5,475,000
5,475,000
5,475,000
2,280,000
Redtail Contracted
Crude Oil Volumes
(Bbl)
4,140,000
—
—
—
—
As a Percentage of
Total 2019
Oil Production
32%
18%
18%
18%
8%
Under the terms of the Sanish 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.
Under the terms of the Redtail contract, if we fail to deliver the committed volumes we are required to pay a deficiency payment that
currently totals $5.24 per undelivered Bbl over the remaining term of the contract. 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 contract, and as a result, we expect to make 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 2019, 2018 and 2017, total deficiency payments under this contract, as well as a second Redtail contract that
we terminated in February 2018, amounted to $64 million, $39 million and $66 million, respectively.
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.
We are involved in litigation related to a payment arrangement with a third party which currently claims damages up to $41 million, as
well as court costs and interest, that is scheduled to go to trial in May 2020. Certain amounts have been accrued in accrued liabilities
and other in the consolidated balance sheet as of December 31, 2019 and general and administrative expenses in the consolidated
statement of operations for the year ended December 31, 2019 based on the determination that it is probable that a loss has been incurred
and can be reasonably estimated.
Item 4. Mine Safety Disclosures
Not applicable.
42
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
The following table sets forth certain information, as of February 20, 2020, regarding the executive officers of Whiting Petroleum
Corporation:
Name
Bradley J. Holly
Bruce R. DeBoer
Correne S. Loeffler
Charles J. Rimer
Timothy M. Sulser
Sirikka R. Lohoefener
Age
49
67
43
62
43
41
Position
Chairman, President and Chief Executive Officer
Chief Administrative Officer, General Counsel and Secretary
Chief Financial Officer
Chief Operating Officer
Chief Strategy Officer
Vice President and Controller
The following biographies describe the business experience of our executive officers:
Bradley J. Holly joined us in November 2017 upon his appointment as director and election as President and Chief Executive Officer.
Mr. Holly was appointed Chairman of the Board in May 2018. Mr. Holly has 25 years of experience in the oil and gas industry. Prior
to joining Whiting, he held various management and technical positions during his 20 years at Anadarko Petroleum Corporation
including Executive Vice President, U.S. Onshore Exploration and Production; Senior Vice President, U.S. Onshore Exploration and
Production; Senior Vice President, Operations; Vice President, Operations for the Southern and Appalachia Region; among others. He
began his career in 1994 with Amoco Corporation. Mr. Holly holds a Bachelor of Science degree in petroleum engineering from Texas
Tech University, and he is a graduate of the Harvard Business School’s Advanced Management Program.
Bruce R. DeBoer joined us as Vice President, General Counsel and Secretary in January 2005 and was elected Chief Administrative
Officer, General Counsel and Secretary effective August 2019. Previously, 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 40 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.
Correne S. Loeffler joined us in August 2019 as Chief Financial Officer. Ms. Loeffler has 14 years of oil and gas experience. She
previously served as Vice President, Finance and Treasurer for Callon Petroleum Company for two years and also served as Interim
Chief Financial Officer for a portion of that time. Prior to joining Callon, Ms. Loeffler was Executive Director with JPMorgan Securities,
LLC where she was employed in the Corporate Client Bank Group for 12 years. She started her career as a consultant at Accenture.
Ms. Loeffler holds a Bachelor of Arts degree from Indiana University and a Master of Business Administration degree from the
University of Texas.
Charles J. Rimer joined us in November 2018 as Chief Operating Officer. Mr. Rimer has 37 years of experience in the industry. Prior
to joining Whiting, he held various management and technical positions during his 16 years at Noble Energy, Inc. including Senior Vice
President, Global Services; Senior Vice President, U.S. Onshore; Senior Vice President, Global EHSR and Operations Services; Vice
President of Operations Services; among others. He also held various management and technical positions at Aspect Resources, Vastar
Resources and ARCO Oil & Gas Company where he began his career in 1983. Mr. Rimer holds a Bachelor of Arts degree in business
from Furman University and Bachelor of Science degree in petroleum engineering from the University of Texas.
43
Timothy M. Sulser joined us in September 2018 as Chief Corporate Development and Strategy Officer. Mr. Sulser has 21 years of oil and
gas experience. He co-founded Salt Creek Oil and Gas, LLC in 2015 after five years as an investment banker with Tudor, Pickering, Holt
& Co. (“TPH”), most recently heading its Denver office. While at TPH, Mr. Sulser advised upstream clients on acquisitions and divestitures
and energy capital markets. Prior to joining TPH, he worked as a reservoir engineer for reserve engineering consultant Netherland, Sewell,
and Associates in Houston, Texas. He started his career with Marathon Oil Company in Lafayette, Louisiana. Mr. Sulser holds a Bachelor
of Science degree in petroleum engineering from Montana Tech and a Master of Science degree in operations research from Columbia
University.
Sirikka R. Lohoefener joined us in June 2006 as a Senior Financial Accountant, became Financial Reporting Manager in January 2011
and Controller in March 2015. She was appointed Controller and Treasurer in March 2017, Vice President, Controller and Treasurer in
December 2018 and Vice President and Controller in October 2019 and serves as the Company’s designated principal accounting officer.
Prior to joining Whiting, Ms. Lohoefener spent five years with Wagner, Burke & Barnes, LLP, a public accounting firm previously
based in Golden, Colorado. She holds a Master of Accountancy degree from the University of Missouri and is a Certified Public
Accountant.
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.
44
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”. On February 20,
2020, there were 444 holders of record of our common stock.
On November 8, 2017, our Board of Directors approved a reverse stock split of our common stock at a ratio of one-for-four and a
reduction in the number of authorized shares of our common stock from 600,000,000 shares to 225,000,000. Our common stock began
trading on a split-adjusted basis on November 9, 2017 upon opening of the markets. All share and per share amounts in this Annual
Report on Form 10-K for periods prior to November 2017 have been retroactively adjusted to reflect the reverse stock split.
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.
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, 2014 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, 2014 in our common stock, the Standard & Poor’s Composite 500 Index and the Dow Jones U.S.
Exploration & Production Index, respectively.
45
Whiting Petroleum Corporation
Standard & Poor’s Composite 500 Index
Dow Jones U.S. Exploration & Production Index
12/31/2014
$
12/31/2015 12/31/2016 12/31/2017 12/31/2018 12/31/2019
6
157
91
29 $
99
75
109
92
122
74
130
91
20 $
36 $
17 $
100 $
100
100
46
Item 6. Selected Financial Data
The consolidated statements of operations and statements of cash flows information for the years ended December 31, 2019, 2018 and
2017 and the consolidated balance sheet information at December 31, 2019 and 2018 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, 2016 and 2015 and the consolidated balance sheet information at December 31, 2017, 2016 and 2015 are derived
from audited financial statements that are not included in this report. Our historical results include the results from our recent proved
property acquisition of properties in North Dakota and Montana on July 31, 2018. In addition, our historical results also include the
effects of our recent property divestitures beginning on the following closing dates: non-operated properties in North Dakota, July 29,
2019 and August 15, 2019; properties in the Fort Berthold Indian Reservation area, September 1, 2017; gas processing plants and related
gathering systems in North Dakota, January 1, 2017; 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; and the underlying properties of Whiting USA Trust I, April 15, 2015. 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) attributable to common shareholders
Earnings (loss) per common share, basic (1)
Earnings (loss) per common share, diluted (1)
Other Financial Information
Net cash provided by operating activities
Net cash provided by (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 (2)
$
$
$
$
$
$
$
$
$
$
$
2019
2018
Year Ended December 31,
2017
(in millions, except per share data)
2016
1,572.2 $
(241.2) $
(2.64) $
(2.64) $
2,081.4 $
342.5 $
3.77 $
3.73 $
1,481.4 $
(1,237.6) $
(13.65) $
(13.65) $
1,285.0 $
(1,339.1) $
(21.27) $
(21.27) $
756.0 $
(733.8) $
(27.1) $
793.4 $
1,092.0 $
(953.1) $
(1,004.7) $
956.7 $
577.1 $
73.4 $
155.6 $
852.0 $
595.0 $
(222.6) $
(315.3) $
543.9 $
2015
2,092.5
(2,219.2)
(45.41)
(45.41)
1,051.4
(1,982.1)
868.7
2,483.7
7,636.7 $
2,799.9 $
4,025.0 $
7,759.6 $
2,792.3 $
4,270.3 $
8,403.0 $
2,764.7 $
3,919.1 $
9,876.1 $
3,535.3 $
5,149.2 $
11,389.1
5,197.7
4,758.6
(1) On November 8, 2017, our Board of Directors approved a one-for-four reverse stock split of our common stock. Earnings (loss)
per common share for periods prior to 2017 have been retroactively adjusted to reflect the reverse stock split.
(2) No cash dividends were declared or paid on our common stock during the periods presented.
47
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, Whiting Resources Corporation and Whiting Programs, Inc. When
the context requires, we refer to these entities separately. This document contains forward-looking statements, which give our current
expectations or forecasts of future events. Please refer to “Forward-Looking Statements” at the end of this Item for an explanation of
these types of statements.
Overview
We are an independent oil and gas company engaged in 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 and
exploring other basins where we can apply our existing knowledge and expertise to build production and add proved reserves. As a
result of lower crude oil prices during 2017 and 2018, we significantly reduced our level of capital spending and focused our drilling
activity on projects that provide the highest rate of return, while closely aligning our capital spending with cash flows generated from
operations. During 2019, we focused on developing our large resource play in the Williston Basin of North Dakota and Montana, while
continuing to closely align our capital spending with cash flows generated from operations. 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 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
prices since the first quarter of 2018:
Crude oil
Natural gas
Q1
$
$
62.89 $
3.13 $
Q2
2018
Q3
Q4
Q1
67.90 $
2.77 $
69.50 $
2.88 $
58.83 $
3.62 $
54.90 $
3.00 $
2019
Q2
59.83 $
2.58 $
Q3
56.45 $
2.29 $
Q4
56.96
2.44
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 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 may reduce the amount of our borrowing base under our credit agreement, 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, as occurred with our most recent semi-annual redetermination where the borrowing base was lowered from $2.25 billion to
$2.05 billion in October 2019. Upon a redetermination, if total outstanding credit exposure exceeds the redetermined borrowing base,
we will be required to prepay outstanding borrowings in an aggregate principal amount equal to such excess in six substantially equal
monthly installments. 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, 2018 to December 31, 2019 and our ability to convert
PUDs to proved developed reserves, refer to “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, refer to “Acreage” in Item 2 of this Annual Report on Form 10-K.
48
2019 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 112.0 MBOE/d for the fourth quarter of 2019, representing a 1% increase from 111.4 MBOE/d in
the third quarter of 2019. Across our acreage in the Williston Basin, we have implemented customized, right-sized completion designs
which utilize the optimum volume of proppant, fluids, and frac stages to increase well performance while reducing cost. We have
increased stages pumped per day by focusing on new technologies such as quick-install wellhead connections and frac plug innovations.
We plan to continue to use right-sized completion designs on wells we drill in 2020, while also utilizing state-of-the-art drilling rigs,
high-torque mud motors and 3-D bit cutter technology to reduce time-on-location and total well cost. As of December 31, 2019, we had
four rigs active in the Williston Basin. We drilled 31 wells and put 35 wells on production in this area during the fourth quarter of 2019.
First quarter 2020 production has been impacted by severe weather conditions and associated electric submersible pump failures on
multiple high value wells. We estimate that this will impact first quarter 2020 production results by approximately 5 MBOE/d.
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. Net production from the Redtail field averaged 10.4 MBOE/d in the fourth quarter of 2019, representing a 7% decrease
from 11.2 MBOE/d in the third quarter of 2019. We have established production in the Niobrara “A”, “B” and “C” zones and the
Codell/Fort Hays formations. We completed 22 drilled uncompleted wells (“DUCs”) in our Redtail field during the first half of 2018,
and no additional wells were drilled or completed in 2019. During 2019 we worked on maintaining base production with improved
artificial lift techniques and reductions in lease operating expenses.
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, 2019, the plant was processing 22 MMcf/d.
Financing Highlights
In September 2019, we paid $299 million to complete a cash tender offer for $300 million aggregate principal amount of our 2020
Convertible Senior Notes, which payment consisted of the 99.0% purchase price plus all accrued and unpaid interest on the notes.
In September 2019, we paid $24 million to repurchase $25 million aggregate principal amount of our 2021 Senior Notes, which payment
consisted of the average 94.708% purchase price plus all accrued and unpaid interest on the notes. In October 2019, we paid an additional
$72 million to repurchase $75 million aggregate principal amount of the 2021 Senior Notes, which payment consisted of the average
95.467% purchase price plus all accrued and unpaid interest on the notes.
We financed the tender offer and repurchases with borrowings under our credit agreement. Refer to the “Long Term Debt” footnote in
the notes to the consolidated financial statements for more information on the tender offer and repurchases.
In October 2019, the borrowing base under our credit agreement was reduced from $2.25 billion to $2.05 billion in connection with the
November 1, 2019 regular borrowing base redetermination, with no change to the aggregate commitments of $1.75 billion.
2020 Exploration and Development Budget
Our 2020 exploration and development (“E&D”) budget is a range of $585 million to $620 million, which we expect to fund substantially
with net cash provided by our operating activities and cash on hand, and represents a decrease from the $778 million incurred on E&D
expenditures during 2019. This reduced spending is primarily attributable to our commitment to closely align capital spending with
cash flows generated from operations. To the extent net cash provided by operating activities is higher or lower than currently
anticipated, we would generate more or less free cash flow than we currently anticipate, and may adjust our E&D budget and attempt to
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. Approximately 90% of the midpoint of our 2020 E&D budget currently is allocated
49
to drilling and completion activity. Of our existing development opportunities, we believe this allocation of our capital presents the
opportunity for the highest return and most efficient use of our capital.
Acquisition and Divestiture Highlights
On July 29, 2019, we completed the divestiture of our interests in 137 non-operated, producing oil and gas wells located in McKenzie,
Mountrail and Williams counties of North Dakota for aggregate sales proceeds of $27 million (before closing adjustments).
On August 15, 2019, we completed the divestiture of our interests in 58 non-operated, producing oil and gas wells located in Richland
County, Montana and Mountrail and Williams counties of North Dakota for aggregate sales proceeds of $26 million (before closing
adjustments).
On a combined basis, the divested properties consisted of less than 1% of our estimated proved reserves as of December 31, 2018 and
our April 2019 average daily production.
On January 9, 2020, we completed the divestiture of our interests in 30 non-operated, producing oil and gas wells and related
undeveloped acreage located in McKenzie County, North Dakota for aggregate sales proceeds of $25 million (before closing
adjustments). The divested properties consisted of less than 1% of our estimated proved reserves as of December 31, 2019 and 1% of
our average daily production for the year ended December 31, 2019.
Restructuring
On July 31, 2019, we executed a workforce reduction as part of an organizational redesign and cost reduction strategy to better align
our business with the current operating environment and drive long-term value. We incurred a one-time net charge of $8 million to
general and administrative expense during 2019 related to this restructuring.
50
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 after the effect 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
Transportation, gathering, compression and other
Production and ad valorem taxes
Depreciation, depletion and amortization
General and administrative
(1) Before consideration of hedging transactions.
2019
Year Ended December 31,
2018
2017
29.8
7.6
50.5
45.8
1,492.2
51.4
28.6
1,572.2
50.06
0.83
50.89
56.97
6.76
0.57
2.58
7.17
0.93
3.02
17.82
2.89
$
$
$
$
$
$
$
$
$
$
$
$
$
31.5
7.4
46.8
46.7
1,850.1
153.6
77.7
2,081.4
58.70
(4.98)
53.72
64.69
20.78
1.66
3.11
6.68
1.03
3.68
16.73
2.64
$
$
$
$
$
$
$
$
$
$
$
$
$
29.3
7.0
41.3
43.1
1,296.4
111.6
73.4
1,481.4
44.30
0.29
44.59
51.11
16.00
1.78
2.97
6.47
2.10
2.80
22.01
2.88
$
$
$
$
$
$
$
$
$
$
$
$
$
(2) Average NYMEX pricing weighted for monthly production volumes.
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
Oil, NGL and Natural Gas Sales. Our oil, NGL and natural gas sales revenue decreased $509 million to $1.6 billion when comparing
2019 to 2018. Changes in sales revenue between periods are due to changes in production sold and changes in average commodity
prices realized (excluding the impacts of hedging). For 2019, decreases in total production accounted for approximately $90 million of
the change in revenue and decreases in commodity prices realized accounted for approximately $419 million of the change in revenue
when comparing to 2018.
Our oil volumes decreased 5% and our NGL and natural gas sales volumes increased 3% and 8%, respectively, during 2019 compared
to 2018. The oil volume decrease was mainly attributable to normal field production decline primarily in the DJ Basin, where we ceased
our development activity during 2019, as well as the result of infrastructure constraints in the Williston Basin and the impact of severe
weather experienced in both the Williston Basin and the DJ Basin during 2019. This decrease was partially offset by increased
production from new wells drilled and completed in the Williston Basin. The NGL and natural gas volume increases between periods
generally relate to new wells drilled and completed in the Williston Basin over the last twelve months, as well as additional volumes
processed as more wells were connected to gas processing plants in the Williston Basin in an effort to increase our overall gas capture
rate in this area and reduce flared volumes. Many of the new Williston Basin wells are in areas with higher gas-to-oil production ratios
51
than previously drilled areas. These NGL and natural gas volume increases were partially offset by normal field production decline
across several of our areas.
Our average price for oil (before the effects of hedging), NGLs and natural gas decreased 15%, 67% and 66%, respectively, between
periods. Our average sales price realized for oil is impacted by deficiency payments we were making under two physical delivery
contracts at our Redtail field due to our inability to meet the minimum volume commitments under these contracts. During 2019 and
2018, our total average sales price realized for oil was $2.14 per Bbl lower and $1.25 per Bbl lower, respectively, as a result of these
deficiency payments. On February 1, 2018, we paid $61 million to the counterparty to one of these Redtail delivery contracts to settle
all future minimum volume commitments under the agreement. The remaining agreement will continue to negatively impact the price
we receive for oil from our Redtail field through April 2020, when the contract terminates. Refer to the “Commitments and
Contingencies” footnote in the notes to the consolidated financial statements for more information on these physical delivery contracts
and the related deficiency payments. Our average sales price realized for natural gas is impacted by rising market differentials as
compared to NYMEX as well as high fixed third-party costs for transportation, gathering and compression services.
Lease Operating Expenses. Our lease operating expenses (“LOE”) during 2019 were $328 million, a $17 million increase over 2018.
This increase was primarily due to new wells put on production in the Williston Basin during 2019 as well as rising costs of oilfield
goods and services. These increases were partially offset by cost savings as a result of our company restructuring in July 2019 and cost
reduction initiatives implemented during 2019. Refer to “Restructuring” for more information on this event.
Our lease operating expenses on a BOE basis also increased when comparing 2019 to 2018. LOE per BOE amounted to $7.17 during
2019, which represents an increase of $0.49 per BOE (or 7%) from 2018. This increase was mainly due to the overall increase in LOE
expense discussed above, as well as lower overall production volumes between periods.
Transportation, Gathering, Compression and Other. Our transportation, gathering, compression and other expenses (“TGC”) during
2019 were $42 million, a $6 million decrease over 2018. This decrease was primarily due to lower realized NGL prices during 2019,
which led to lower gas processing fees under our percentage-of-proceeds contracts as compared to 2018.
TGC on a BOE basis also decreased when comparing 2019 to 2018. TGC per BOE amounted to $0.93 during 2019, which represents a
decrease of $0.10 per BOE (or 10%) from 2018. This decrease was mainly due to the overall decrease in TGC expense discussed above,
partially offset by lower overall production volumes between periods.
Production and Ad Valorem Taxes. Our production and ad valorem taxes during 2019 were $138 million, a $34 million decrease
compared to 2018, which was primarily due to lower sales revenue 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 8.6%
and 7.8% for 2019 and 2018, respectively. Our production tax rate for 2019 was higher than the rate for 2018 primarily due to our
concentration of development over the last twelve months in the Williston Basin states of North Dakota and Montana, which have higher
tax rates than Colorado where we have had limited development activity over the past twelve months. This increase in rate was partially
offset by certain North Dakota wells receiving stripper well status, which reduces the rate from 10% to 5%.
Depreciation, Depletion and Amortization. Our depreciation, depletion and amortization (“DD&A”) expense increased $35 million in
2019 as compared to 2018. The components of our DD&A expense were as follows (in thousands):
Depletion
Accretion of asset retirement obligations
Depreciation
Total
Year Ended December 31,
2018
2019
$
$
799,080
11,602
5,806
816,488
$
$
763,429
11,405
6,495
781,329
DD&A increased between periods primarily due to $36 million in higher depletion expense, consisting of a $52 million increase related
to a higher depletion rate between periods, partially offset by a $16 million decrease due to lower overall production volumes during
2019. On a BOE basis, our overall DD&A rate of $17.82 for 2019 was 7% higher than the rate of $16.73 in 2018. The primary factors
contributing to this higher DD&A rate were a recent shift in our development activity to areas with higher average historical DD&A
rates and downward revisions to proved reserves over the last twelve months.
52
Exploration and Impairment Costs. Our exploration and impairment costs decreased $13 million in 2019 as compared to 2018. The
components of our exploration and impairment expense were as follows (in thousands):
Exploration
Impairment
Total
Year Ended December 31,
2018
2019
$
$
36,872 $
17,866
54,738 $
22,080
45,288
67,368
Exploration costs increased $15 million between periods primarily due to increased deficiency fees paid under our produced water
disposal agreement driven by reduced drilling and completions at our Redtail field during 2019 compared to 2018.
Impairment expense in 2019 primarily related to the amortization of leasehold costs associated with individually insignificant unproved
properties. Impairment expense in 2018 primarily related to (i) $29 million of leasehold amortization costs associated with individually
insignificant unproved properties and (ii) $8 million in impairment write-downs of undeveloped acreage costs for leases where we have
no future plans to drill.
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,
2018
2019
$
$
224,885
(92,276)
132,609
$
$
220,100
(96,850)
123,250
G&A expense before reimbursements and allocations increased $5 million during 2019 as compared to 2018 primarily due to an $8
million one-time net charge related to the company restructuring during 2019 as well as higher legal and litigation costs. In addition,
G&A expense for 2018 includes $5 million of credits to bad debt expense related to the collection of certain receivables that had been
previously deemed uncollectible. These factors resulting in increased G&A expense for 2019 were partially offset by lower employee
compensation costs as a result of the restructuring. The decrease in reimbursements and allocations in 2019 was primarily the result of
lower headcount due to the restructuring as well as lower development activity during the fourth quarter of 2019. Refer to
“Restructuring” for more information on the company restructuring.
Our G&A expenses on a BOE basis also increased between periods. G&A expense per BOE amounted to $2.89 in 2019, which
represents an increase of $0.25 per BOE (9%) from 2018. This increase was mainly due to the overall increase in G&A expense
discussed above, as well as lower overall production volumes between periods.
Derivative Loss, Net. Our commodity derivative contracts 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 loss, net amounted to $54 million and $17
million for 2019 and 2018, respectively. These losses primarily related to our collar, swap and option commodity derivative contracts
and resulted from the upward shift in the futures curve of forecasted commodity prices for crude oil during the respective periods.
For further information on our outstanding derivatives refer to the “Derivative Financial Instruments” footnote in the notes to the
consolidated financial statements.
53
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
Total
Year Ended December 31,
2018
2019
$
$
146,583
28,340
15,236
888
191,047
$
$
152,366
30,700
13,262
1,146
197,474
The decrease in interest expense of $6 million between periods was mainly attributable to lower interest incurred on our notes in 2019
compared to 2018 resulting from the redemption of the 2019 Notes in January 2018, the tender offer for the 2020 Convertible Senior
Notes in September 2019 and the repurchases of the 2021 Senior Notes in September and October 2019. Refer to the “Long-Term Debt”
footnote in the notes to the consolidated financial statements for more information on these debt transactions.
Our weighted average debt outstanding during 2019 was $2.9 billion versus $3.0 billion for 2018. Our weighted average effective cash
interest rate was 5.5% during both 2019 and 2018.
Gain (Loss) on Extinguishment of Debt. During 2019, we recognized a gain on extinguishment of debt of $8 million. In September
2019, we paid $299 million to purchase $300 million aggregate principal amount of the 2020 Convertible Senior Notes in a cash tender
offer and recognized a $4 million gain on extinguishment of debt. Additionally, in September and October 2019, we paid $96 million
to repurchase $100 million aggregate principal amount of the 2021 Senior Notes and recognized a $4 million gain on extinguishment of
debt. During 2018, we redeemed all of the remaining $961 million aggregate principal amount of 2019 Senior Notes and recognized a
$31 million loss on extinguishment of debt. Refer to the “Long-Term Debt” footnote in the notes to the consolidated financial statements
for more information on these debt transactions.
Income Tax Expense (Benefit). Income tax expense for 2019 totaled $72 million as compared to $1 million for 2018. As a result of our
positive pre-tax income in 2018, we transitioned from a net deferred tax asset position to a net deferred tax liability position as of
December 31, 2018. Accordingly, we released the valuation allowance related to our general net deferred tax assets that was established
in 2017 and recognized $1 million in deferred tax expense related to U.S. income tax for the year ended December 31, 2018. As a result
of pre-tax losses in 2019, we transitioned from a net deferred tax liability position to a net deferred tax asset position for U.S. income
taxes which resulted in the recognition of a full valuation allowance on our deferred tax assets again during the second quarter of 2019
and recognition of a $1 million deferred U.S. tax benefit. Additionally, during the fourth quarter of 2019, we recognized $74 million of
Canadian deferred tax expense associated with the outside basis difference in Whiting Canadian Holding Company ULC pursuant to
ASC 740-30-25-17. Refer to the “Income Taxes” footnote in the notes to the consolidated financial statements for more information on
this deferred tax liability.
Our effective tax rates for 2019 and 2018 differ from the U.S. statutory income tax rate primarily due to the effects of state income taxes,
permanent taxable differences and changes in the valuation allowance. Our overall effective tax rate decreased from 0.4% for 2018 to
(42.7)% for 2019 primarily due to the recognition of the outside basis difference in Whiting Canadian Holding Company ULC.
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017
For discussion on the year ended December 31, 2018 compared to the year ended December 31, 2017, refer to Part II, Item 7
“Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2018 Annual Report on Form 10-K
filed with the SEC on February 28, 2019 under the subheading “Year Ended December 31, 2018 Compared to Year Ended December 31,
2017.”
Liquidity and Capital Resources
Overview. At December 31, 2019, we had $9 million of cash on hand and $4.0 billion of equity, while at December 31, 2018, we had
$14 million of cash on hand and $4.3 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 65% and 67% of our total production in 2019 and 2018,
54
respectively. As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in NGL
or natural gas prices. As of February 20, 2020, we had contracts covering the sale of 31 MMBbl of oil per day for the remainder of
2020 and 6 MMBbl of oil per day for all of 2021. For further information on our outstanding derivatives refer to the “Derivative
Financial Instruments” footnote in the notes to the consolidated financial statements.
Cash Flows from 2019 Compared to 2018. During 2019, we generated $756 million of cash provided by operating activities, a decrease
of $336 million from 2018. Cash provided by operating activities decreased primarily due to lower realized sales prices for oil, NGLs
and natural gas, lower crude oil production volumes, as well as higher lease operating expenses, exploration costs and cash G&A
expenses. These negative factors were partially offset by higher NGL and natural gas production volumes, a decrease in cash settlements
paid on our derivative contracts, and lower production and ad valorem taxes, cash interest expense and TGC for 2019 compared to 2018.
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 2019.
During 2019, cash flows from operating activities, $375 million of net borrowings under our credit agreement, proceeds from the sale
of properties and cash on hand were used to finance $793 million of drilling and development expenditures, the repurchase of $300
million aggregate principal amount of 2020 Convertible Senior Notes and $100 million aggregate principal amount of 2021 Senior
Notes, and $6 million of other property and equipment purchases.
Cash Flows from 2018 Compared to 2017. For discussion on cash flows for the year ended December 31, 2018 compared to the year
ended December 31, 2017, refer to Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of
Operations” of our 2018 Annual Report on Form 10-K filed with the SEC on February 28, 2019 under the subheading “Cash Flows
from 2018 Compared to 2017.”
Exploration and Development Expenditures. The following table details our E&D expenditures incurred by core area (in thousands):
Northern Rocky Mountains
Central Rocky Mountains
Other (1)
Total incurred
Year Ended December 31,
2018
2017
2019
$
$
768,651 $
209
9,394
778,254 $
741,378 $
82,660
7,985
832,023 $
601,737
292,826
17,866
912,429
(1) Other primarily includes non-core oil and gas properties located in Colorado, Mississippi, New Mexico, North Dakota, Texas and
Wyoming.
We continually evaluate our capital needs and compare them to our capital resources. Our 2020 E&D budget is a range of $585 million
to $620 million, which we expect to fund substantially with net cash provided by operating activities and cash on hand, and represents
a decrease from the $778 million incurred on E&D expenditures during 2019. We believe that should additional attractive acquisition
opportunities arise, we will attempt 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 twelve 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, 2019 had a borrowing base and aggregate commitments of $2.05 billion and $1.75 billion, respectively. As of
December 31, 2019, we had $1.4 billion of available borrowing capacity under the credit agreement, which was net of $375 million of
borrowings outstanding and $2 million in letters of credit outstanding.
The borrowing base under the credit agreement is determined at the discretion of our 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,
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as well as special redeterminations described in the credit agreement, in each case which may reduce the amount of the borrowing base.
Upon a redetermination of our borrowing base, either on a periodic or special redetermination date, if total outstanding credit exposure
exceeds the redetermined borrowing base, we will be required to prepay outstanding borrowings in an aggregate principal amount equal
to such excess in six substantially equal monthly installments. In October 2019, the borrowing base under our credit agreement was
reduced from $2.25 billion to $2.05 billion in connection with the November 1, 2019 regular borrowing base redetermination, with no
change to the aggregate commitments of $1.75 billion.
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, 2019, $48 million was available for
additional letters of credit under the agreement.
The credit agreement provides for interest only payments until maturity, when the credit agreement expires and all outstanding
borrowings are due. Interest under the credit agreement accrues at our option at either (i) a base rate for a base rate loan plus a margin
between 0.50% and 1.50% based on the ratio of outstanding borrowings to the borrowing base, 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 a margin of 1.50% and 2.50% based on the ratio of outstanding borrowings to the borrowing
base. Additionally, we also incur commitment fees of 0.375% or 0.50% based on the ratio of outstanding borrowings to the borrowing
base on the unused portion of the aggregate commitments of the lenders under the credit agreement.
The credit agreement matures on April 12, 2023, provided that if at any time and for so long as any senior notes (other than the 2020
Convertible Senior Notes) have a maturity date prior to 91 days after April 12, 2023, the maturity date shall be the date that is 91 days
prior to the maturity of such senior notes. On September 13, 2019, we amended the credit agreement to, among other things, permit the
repurchase, redemption, prepayment or other acquisition or retirement for value of any senior notes (as defined in the credit agreement)
if (i) such transaction is for a price not greater than an amount equal to par plus accrued and unpaid interest and fees and any applicable
make-whole premium, (ii) immediately after giving effect to such transaction, there is unused availability under the facility of not less
than the greater of $100 million or 15% of the then effective total commitments, and (iii) our ratio of consolidated total debt as of the
date of such transaction (upon giving effect thereto) to EBITDAX (as defined in the credit agreement) during the last four quarters is
not greater than 3.25 to 1.0. Our business plan includes the intent to refinance certain senior notes, including our convertible senior
notes due in 2020 and our senior notes due in 2021, as permitted by the September 13, 2019 amendment to the credit agreement.
Consequently, we have classified the credit agreement as long-term debt.
The credit agreement contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell
assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, incur liens and engage in certain other
transactions without the prior consent of our lenders. Except for limited exceptions, the credit agreement also restricts our ability to
make any dividend payments or distributions on our common stock. These restrictions apply to all of our restricted subsidiaries (as
defined in the credit agreement). As of December 31, 2019, there were no retained earnings free from restrictions.
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 and (ii) a total debt to the last four quarters’ EBITDAX ratio of not greater than
4.0 to 1.0. As of December 31, 2019, we were in compliance with the covenants under the credit agreement. While not required to
maintain compliance with covenants, our business plan may include property divestitures and utilizing our credit facility or accessing
capital markets to repay outstanding debt.
For further information on the loan security related to our credit agreement, refer to the “Long-Term Debt” footnote in the notes to the
consolidated financial statements.
Under Whiting Oil and Gas’ credit agreement, a cross default provision provides that a default under certain other debt of the Company
or certain of its subsidiaries in an aggregate principal amount exceeding $100 million may constitute an event of default under such
credit agreement. Additionally, under the indentures governing our senior notes and senior convertible notes, a cross-default provision
provides that a default under certain other debt of the Company or certain of its subsidiaries in an aggregate principal amount exceeding
$100 million (or $50 million in the case of the 2021 Senior Notes) may constitute an event of default under such indenture.
Senior Notes. In December 2017, we issued at par $1.0 billion of 6.625% Senior Notes due January 15, 2026 (the “2026 Senior Notes”).
In March 2015, we issued at par $750 million of 6.25% Senior Notes due April 1, 2023 (the “2023 Senior Notes”). In September 2013,
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we issued at par $1.1 billion of 5.0% Senior Notes due March 15, 2019 (the “2019 Senior Notes”) and $800 million of 5.75% Senior
Notes due March 15, 2021, and issued at 101% of par an additional $400 million of 5.75% Senior Notes due March 15, 2021
(collectively the “2021 Senior Notes” and together with the 2023 Senior Notes and the 2026 Senior Notes, the “Senior Notes”).
During 2016, we exchanged (i) $139 million aggregate principal amount of our 2019 Senior Notes, (ii) $326 million aggregate principal
amount of our 2021 Senior Notes, and (iii) $342 million aggregate principal amount of our 2023 Senior Notes, for the same aggregate
principal amount of convertible notes. Subsequently during 2016, all $807 million aggregate principal amount of these convertible
notes was converted into approximately 19.8 million shares of our common stock pursuant to the terms of the notes.
Redemption of 2019 Senior Notes. In January 2018, we paid $1.0 billion to redeem all of the then outstanding $961 million aggregate
principal amount of our 2019 Senior Notes, which payment consisted of the 102.976% redemption price plus all accrued and unpaid
interest on the notes. We financed the redemption with proceeds from the issuance of our 2026 Senior Notes and borrowings under our
credit agreement.
Repurchases of 2021 Senior Notes. In September 2019, we paid $24 million to repurchase $25 million aggregate principal amount of
the 2021 Senior Notes, which payment consisted of the average 94.708% purchase price plus all accrued and unpaid interest on the
notes. We financed the repurchases with cash and borrowings under our credit agreement.
In October 2019, we paid an additional $72 million to repurchase $75 million aggregate principal amount of the 2021 Senior Notes,
which payment consisted of the average 95.467% purchase price plus all accrued and unpaid interest on the notes. We financed the
repurchases with borrowings under our credit agreement. As of December 31, 2019, $774 million of 2021 Senior Notes remained
outstanding.
2020 Convertible Senior Notes. In March 2015, we issued at par $1,250 million of 1.25% Convertible Senior Notes due April 1, 2020
(the “2020 Convertible Senior Notes”). During 2016, we exchanged $688 million aggregate principal amount of our 2020 Convertible
Senior Notes for the same aggregate principal amount of new mandatory convertible senior notes. Subsequently during 2016, all $688
million aggregate principal amount of these mandatory convertible senior notes was converted into approximately 17.8 million shares
of our common stock pursuant to the terms of the notes.
In September 2019, we paid $299 million to complete a cash tender offer for $300 million aggregate principal amount of the 2020
Convertible Senior Notes, which payment consisted of the 99.0% purchase price plus all accrued and unpaid interest on the notes and
associated transaction costs. We financed the tender offer with cash and borrowings under our credit agreement.
The remaining $262 million aggregate principal amount of 2020 Convertible Senior Notes outstanding as of December 31, 2019 are
convertible exclusively at the holder’s option. Prior to January 1, 2020, the 2020 Convertible Senior Notes were convertible only upon
the achievement of certain contingent market conditions. As of December 31, 2019, none of the contingent market conditions allowing
holders of the 2020 Convertible Senior Notes to convert these notes had been met. On or after January 1, 2020, the 2020 Convertible
Senior Notes are convertible at any time until the second scheduled trading day immediately preceding the April 1, 2020 maturity date
of the notes. The notes are convertible at a current conversion rate of 6.4102 shares of Whiting’s common stock per $1,000 principal
amount of the notes, which is equivalent to a current conversion price of approximately $156.00. The conversion rate is 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. We have the option to settle conversions of 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. At maturity, we must settle all outstanding 2020 Convertible Senior Notes in cash. Our business plan includes the intent
to settle the outstanding 2020 Convertible Senior Notes using borrowings under the credit agreement.
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, 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
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with these covenants as of December 31, 2019. 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, 2019 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 the
consolidated financial statements and “Delivery Commitments” in Item 2 of this Annual Report on Form 10-K.
Contractual Obligations
Long-term debt (1)
Cash interest expense on debt (2)
Asset retirement obligations (3)
Water disposal agreement (4)
Operating leases (5)
Pipeline transportation agreements (6)
Finance leases (5)
Purchase obligations (7)
Total
Payments due by period
(in thousands)
Less than 1
More than 5
Total
year
1-3 years 3-5 years
years
$ 2,818,980 $ 262,075 $
773,609 $ 783,296 $ 1,000,000
68,827
144,434
232,427
79,048
17,464
34,696
25,117
37,328
-
16,951
8,927
11,913
2,736
8,981
-
2,535
7,095
10,501
-
-
-
$ 3,738,471 $ 472,586 $ 1,109,455 $ 989,069 $ 1,167,361
156,997
3,685
20,318
8,886
6,327
6,642
7,656
602,685
134,893
82,763
46,677
18,044
26,773
7,656
(1) Long-term debt consists of the outstanding principal amounts of the Senior Notes and the 2020 Convertible Senior Notes, as well
as the outstanding borrowings under our credit agreement. The credit agreement matures on April 12, 2023, provided that if at any
time and for so long as any senior notes (other than the 2020 Convertible Senior Notes) have a maturity date prior to 91 days after
April 12, 2023, the maturity date shall be the date that is 91 days prior to the maturity of such senior notes. As of December 31,
2019, we had $774 million aggregate principal amount of senior notes due March 15, 2021 and $408 million aggregate principal
amount of senior notes due April 1, 2023. Our business plan includes the intent to refinance certain senior notes, including our
convertible senior notes due in 2020 and our senior notes due in 2021, as permitted by the September 13, 2019 amendment to the
credit agreement. Consequently, we have classified the credit agreement as long-term debt.
(2) Cash interest expense on the Senior Notes is estimated assuming no further principal repayment until the due dates of the
instruments. Cash interest expense on the 2020 Convertible Senior Notes is estimated assuming no further principal repayments or
conversions prior to maturity. Cash interest expense on the credit agreement is estimated assuming no principal borrowings or
repayments through the April 2023 instrument due date and a fixed interest rate of 3.9%. Commitment fees on the credit agreement
are estimated assuming no principal borrowings or repayments or changes to commitments through the April 2023 instrument due
date.
(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 a water disposal agreement which expires in 2024 under which 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
produced water or else pay for any deficiencies at the price stipulated in the contract. As a result of our reduced development
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operations at our Redtail field, we have made and expect to continue to make deficiency payments under this contract. Refer to the
“Commitments and Contingencies” footnote in the notes to the consolidated financial statements for more information on this
contract and the related deficiency payments.
(5) We have operating and finance leases for corporate and field offices, pipeline and midstream facilities and automobiles. The
obligations reported above represent our minimum financial commitments pursuant to the terms of these contracts, however, our
actual expenditures under these contracts may exceed the minimum commitments presented above. Refer to the “Leases” footnote
in the notes to the consolidated financial statements for more information on these leases.
(6) Our pipeline transportation agreements consist of contracts through 2024 with various third parties to facilitate the delivery of our
produced oil, gas and NGLs to market. These contracts require either fixed monthly reservation fees or commitments to deliver
minimum volumes at fixed rates in exchange for dedicated pipeline capacity. If minimum volume commitments are not met, we
are required to pay any deficiencies at the prices stipulated in the contracts. The obligations reported above represent our minimum
financial commitments pursuant to the terms of these contracts, however, our actual expenditures under these contracts may exceed
the minimum commitments presented above.
(7) 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 prices stipulated in the contract. As a
result of our reduced development operations in this field, we have made and expect to continue to make deficiency payments under
this contract. Refer to the “Commitments and Contingencies” footnote in the notes to the consolidated financial statements for
more information on this contract and the related deficiency payments.
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 the 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, political environment, global economics, mechanical problems, general business conditions and other factors.
A summary of our significant accounting policies is detailed in the “Summary of Significant Policies” footnote in the notes to the
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
59
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
following information that they review: (1) technical support data, (2) technical analysis of geologic and engineering support
information, (3) economic and production data, (4) our well ownership interests and (5) expected future development activity. 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, 2019. 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, 2019 would
have increased by 9 MMBOE (2%) or decreased by 33 MMBOE (7%), respectively, and the pre-tax PV10% of our proved reserves
would have increased by $0.9 billion (23%) or decreased by $0.8 billion (22%), 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. Such events and circumstances include,
but are not limited to, declines in commodity prices, increases in operating costs, unfavorable reserve revisions, poor well performance,
changes in development plans and potential property divestitures. Impairments of producing properties are determined by comparing
their undiscounted future net cash flows to their net book values at the end of each period. If a property’s net capitalized costs exceed
undiscounted future net cash flows, the cost of the property is written down to “fair value,” which is determined using discounted future
net cash flows from the producing property. Different pricing assumptions or discount rates could result in a different calculated
impairment. In addition to proved property impairments, we provide for impairments on significant undeveloped properties when we
determine that the property will not be developed or a permanent impairment in value has occurred. Individually insignificant unproved
properties are amortized on a composite basis, based on past success, experience and average lease-term lives.
Asset Retirement Obligation. Our asset retirement obligations (“ARO”) consist of estimated future costs associated with the plugging
and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and land restoration in accordance with
applicable local, state and federal laws and the terms of our lease agreements. 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 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 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.
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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 and swaps which are generally placed with major financial institutions, as well as crude oil sales and delivery
contracts. We use hedging to help ensure that we have adequate funding for our capital programs and to manage returns on our drilling
programs and acquisitions. 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 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 a probability-weighted income approach which
considers various assumptions, including quoted spot 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.
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.
On December 22, 2017, Congress passed the Tax Cuts and Jobs Act (the “TCJA”). The new legislation significantly changed the U.S.
corporate tax law by, among other things, lowering the U.S. corporate income tax rate from 35% to 21% beginning in January 2018,
implementing a territorial tax system and imposing a repatriation tax on deemed repatriated earnings of foreign subsidiaries. The SEC
issued Staff Accounting Bulletin No. 118 (“SAB 118”), which allowed registrants to record provisional amounts during a one-year
“measurement period” similar to that used to account for business combinations, however, the measurement period was deemed to have
ended earlier once the registrant had obtained, prepared and analyzed the information necessary to finalize its accounting. During the
measurement period, impacts of the law were to be recorded at the time a reasonable estimate for all or a portion of the effects could be
made, and provisional amounts recognized and adjusted as information became available, prepared or analyzed. As a result of the new
legislation, we recognized the provisional impacts of the revaluation of our deferred tax assets and liabilities as of the date of enactment.
We did not recognize any measurement period adjustments to these provisional amounts, and as of December 31, 2018, our accounting
for the TCJA was complete.
ASC 740 requires uncertain income tax positions to meet a more-likely-than-not realization threshold to be recognized in the financial
statements. Under ASC 740, uncertain tax positions that previously failed to meet the more-likely-than-not threshold should be
recognized in the first subsequent financial reporting period in which that threshold is met. Previously recognized uncertain tax positions
that no longer meet the more-likely-than-not threshold should be derecognized in the first subsequent financial reporting period in which
that threshold is no longer met.
We are subject to taxation in many jurisdictions, and the calculation of our tax liabilities involves dealing with uncertainties in the
application of complex tax laws and regulations in various taxing jurisdictions. If we ultimately determine that the payment of these
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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
recognized when we meet our performance obligation to deliver the product and control is transferred to the customer. We receive
payment for product sales from one to three months after delivery. At the end of each month when the performance obligation is
satisfied, the amount of production delivered and the price we will receive can be reasonably estimated and amounts due from customers
are accrued in accounts receivable trade, net in the consolidated balance sheets. Variances between our estimated revenue and actual
payments 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.
The business combinations completed during the prior three years consisted of oil and gas properties. In general, the consideration we
have paid to acquire these properties or companies was entirely allocated to the fair value of the assets acquired and liabilities assumed
at the time of acquisition and consequently, there was no goodwill nor any bargain purchase gains recognized on our business
combinations.
Leases. We have operating and finance leases for corporate and field offices, pipeline and midstream facilities, field and office
equipment and automobiles. Right-of-use (“ROU”) assets and liabilities associated with these leases are recognized at the lease
commencement date based on the present value of the lease payments over the lease term. ROU assets represent our right to use an
underlying asset for the lease term, and lease liabilities represent our obligation to make lease payments.
Operating lease cost is recognized on a straight-line basis over the lease term. Finance lease cost is recognized based on the effective
interest method for the lease liability and straight-line amortization of the ROU asset, resulting in more cost being recognized in earlier
lease periods. All payments for short-term leases, including leases with a term of one month or less, are recognized in income or
capitalized to the cost of oil and gas properties on a straight-line basis over the lease term. Additionally, any variable payments, which
are generally related to the corresponding utilization of the asset, are recognized in the period in which the obligation was incurred.
We adopted FASB ASC Topic 842 – Leases effective January 1, 2019 using the modified retrospective approach. Refer to the “Summary
of Significant Accounting Policies” and “Leases” footnotes in the notes to the consolidated financial statements for more information
on this new accounting standard.
Effects of Inflation and Pricing
As commodity prices have begun to recover from previous lows during 2018 and 2019, the cost of oil field goods and services has also
risen. 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 our credit agreement, 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
62
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.
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, our ability to comply
with debt covenants, periodic redeterminations of the borrowing base under our credit agreement and our ability to generate sufficient
cash flows from operations to service our indebtedness; 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; the impact of negative shifts in investor sentiment towards the oil and gas industry; impacts resulting from the allocation of
resources among our strategic opportunities; the geographic concentration of our operations; impacts to financial statements as a result
of impairment write-downs and other cash and noncash charges; federal and state initiatives relating to the regulation of hydraulic
fracturing and air emissions; revisions to reserve estimates as a result of changes in commodity prices, regulation and other factors;
inaccuracies of our reserve estimates or our assumptions underlying them; the timing of our exploration and development expenditures;
risks relating to decreases in our credit rating; our inability to access oil and gas markets due to market conditions or operational
impediments; market availability of, and risks associated with, transport of oil and gas; our ability to successfully complete asset
dispositions and the risks related thereto; 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; weakened
differentials impacting the price we receive for oil and natural gas; risks relating to any unforeseen liabilities of ours; the impacts of
hedging on our results of operations; adverse weather conditions that may negatively impact development or production activities;
uninsured or underinsured losses resulting from our oil and gas operations; lack of control over non-operated properties; failure of our
properties to yield oil or gas in commercially viable quantities; the impact and costs of compliance with laws and regulations governing
our oil and gas operations; the potential impact of changes in laws that could have a negative effect on the oil and gas industry; impacts
of local regulations, climate change issues, negative public perception of our industry and corporate governance standards; our ability
to replace our oil and natural gas reserves; negative impacts from litigation and legal proceedings; unforeseen underperformance of or
liabilities associated with acquired properties or other strategic partnerships or investments; competition in the oil and gas industry; any
loss of our senior management or technical personnel; cybersecurity attacks or failures of our telecommunication and other information
technology infrastructure; 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.
63
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.
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.
Crude Oil Collars, Swaps and Options. Our hedging portfolio currently consists of collars, swaps and options. Refer to the “Derivative
Financial Instruments” footnote in the notes to the consolidated financial statements for a description and list of our outstanding
derivative contracts at December 31, 2019, as well as derivative contracts established subsequent to that date.
Our collars and options have the effect of providing a protective floor while allowing us to share in upward pricing movements. The
fair value of our crude oil collars and options at December 31, 2019 was a net liability of $3 million. A hypothetical upward or downward
shift of 10% per Bbl in the NYMEX forward curve for crude oil as of December 31, 2019 would cause an increase of $26 million or a
decrease of $19 million, respectively, in this fair value liability.
Our swap contracts entitle us to receive settlement from the counterparty in amounts, if any, by which the settlement price for the
applicable calculation period is less than the fixed price, or to pay the counterparty if the settlement price for the applicable calculation
period is more than the fixed price. The fair value of our swaps at December 31, 2019 was a net liability of $7 million. A hypothetical
upward or downward shift of 10% per Bbl in the NYMEX forward curve for crude oil as of December 31, 2019 would cause an increase
or decrease, respectively, of $29 million in this fair value liability.
While these collars, options and fixed-price swaps are designed to decrease our exposure to downward price movements, they also have
the effect of limiting the benefit of price increases above the ceiling with respect to the hedges and options and upward price movements
generally with respect to the fixed-price swaps.
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, 2019, our outstanding principal balance under our credit agreement was $375 million, and the weighted average interest
rate on the outstanding principal balance was 3.3%. At December 31, 2019, the carrying amount approximated fair market value.
Assuming a constant debt level of $375 million, the cash flow impact resulting from a 100 basis point change in interest rates during
periods when the interest rate is not fixed would be $4 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.
The interest rate on our 2020 Convertible Senior Notes is fixed at 1.25%, and as such, 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 the consolidated financial statements for more information on the material terms and fair values
of the 2020 Convertible Senior Notes.
64
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, 2019 and 2018
Consolidated Statements of Operations for the Years Ended December 31, 2019, 2018 and 2017
Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017
Consolidated Statements of Equity for the Years Ended December 31, 2019, 2018 and 2017
Notes to Consolidated Financial Statements
66
68
69
70
72
73
65
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Whiting Petroleum Corporation
Denver, Colorado
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Whiting Petroleum Corporation and subsidiaries (the "Company")
as of December 31, 2019 and 2018, the related consolidated statements of operations, cash flows and equity for each of the three years
in the period ended December 31, 2019, and the related notes (collectively referred to as the "financial statements"). In our opinion, the
financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018,
and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, 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) (PCAOB),
the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control —
Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated
February 27, 2020, expressed an unqualified opinion on the Company's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the
Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to
be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations
of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error
or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding
the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and
significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that
our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was
communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to
the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical
audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the
critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Proved Oil and Natural Gas Property Depletion – Oil and Natural Gas Reserve Quantities – Refer to Notes 1, 2 and 8 to the financial
statements
Critical Audit Matter Description
The Company’s proved oil and natural gas properties are depleted using the units of production method and are evaluated for impairment
by comparison to the future net cash flows of the underlying oil and natural gas reserves. The development of the Company’s oil and
natural gas reserve quantities and the related future net cash flows requires management to make significant estimates and assumptions
related to the five-year development rule for proved undeveloped reserves and future oil and natural gas prices. The Company engages
an independent reserve engineer to estimate oil and natural gas quantities using these estimates and assumptions and engineering data.
Changes in these assumptions or engineering data could have a significant impact on the amount of depletion and any proved oil and
gas impairment. The proved oil and gas properties balance was $7 billion, as of December 31, 2019, net of accumulated depreciation,
66
depletion and amortization. Depreciation, depletion and amortization expense was $816 million for the year ended December 31, 2019.
No impairment was recognized during 2019.
Given the significant judgments made by management, performing audit procedures to evaluate the Company’s oil and natural gas
reserve quantities and the related net cash flows including management’s estimates and assumptions related to the five-year development
rule and future oil and natural gas prices, required a high degree of auditor judgment and an increased extent of effort, including the
need to involve our fair value specialists.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to management’s significant judgments and assumptions related to oil and natural gas reserves quantities
and estimates of the future net cash flows included the following, among others:
• We tested the operating effectiveness of controls related to the Company’s estimation of oil and natural gas reserve quantities
and the related future net cash flows, including controls relating to the five-year development plan and future oil and natural
gas prices.
• We evaluated the reasonableness of management’s five-year development plan by comparing the forecasts to:
- Historical conversions of proved undeveloped oil and natural gas reserves into proved developed oil and natural gas
reserves
-
Internal communications to management and the Board of Directors
- Permits and approval for expenditures
- Forecasted information by basin included in Company press releases as well as in analyst and industry reports for the
Company and certain of its peer companies
• With the assistance of our fair value specialists, we evaluated management’s estimated future sales prices for oil and natural
gas, by:
- Understanding the methodology used by management for development of the future prices and comparing the
estimated prices to an independently determined range of prices
- Comparing management’s estimates to published forward pricing indices and third-party industry sources
- Evaluating the historical realized price differentials incorporated in the future oil and natural gas prices
- Evaluating the experience, qualifications and objectivity of management’s expert, an independent reservoir
engineering firm, including performing analytical procedures on the reserve quantities
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 27, 2020
We have served as the Company’s auditor since 2003.
67
WHITING PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)
December 31,
2019
2018
$
$
8,652
308,249
886
13,196
330,983
$
$
12,812,007
178,689
12,990,696
(5,735,239)
7,255,457
50,281
7,636,721
80,100
202,010
64,263
53,928
38,262
53,597
26,844
10,285
21,125
550,414
2,799,885
131,208
31,722
73,593
24,928
3,611,750
13,607
294,468
68,342
22,009
398,426
12,195,659
134,212
12,329,871
(5,003,509)
7,326,362
34,785
7,759,573
42,520
228,284
73,178
55,080
37,499
33,872
31,357
-
35,141
536,931
2,792,321
131,544
-
1,373
27,088
3,489,257
92
6,409,991
(2,385,112)
4,024,971
7,636,721
$
92
6,414,170
(2,143,946)
4,270,316
7,759,573
ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable trade, net
Derivative assets
Prepaid expenses and other
Total current assets
Property and equipment:
Oil and gas properties, successful efforts method
Other property and equipment
Total property and equipment
Less accumulated depreciation, depletion and amortization
Total property and equipment, net
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
Derivative liabilities
Accrued employee compensation and benefits
Total current liabilities
Long-term debt
Asset retirement obligations
Operating lease obligations
Deferred income taxes
Other long-term liabilities
Total liabilities
Commitments and contingencies
Equity:
Common stock, $0.001 par value, 225,000,000 shares authorized; 91,743,571 issued and
91,326,469 outstanding as of December 31, 2019 and 92,067,216 issued and 91,018,692
outstanding as of December 31, 2018
Additional paid-in capital
Accumulated deficit
Total equity
TOTAL LIABILITIES AND EQUITY
The accompanying notes are an integral part of these consolidated financial statements.
68
$
$
$
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
Transportation, gathering, compression and other
Production and ad valorem taxes
Depreciation, depletion and amortization
Exploration and impairment
General and administrative
Derivative loss, net
Loss on sale of properties
Amortization of deferred gain on sale
Total operating expenses
Year Ended December 31,
2018
2017
2019
$
1,572,245 $
2,081,414 $
1,481,435
328,427
42,438
138,212
816,488
54,738
132,609
53,769
1,964
(9,069)
1,559,576
311,895
48,105
171,823
781,329
67,368
123,250
17,170
1,949
(11,354)
1,511,535
278,919
90,574
120,870
948,939
936,177
124,288
122,847
401,113
(12,963)
3,010,764
INCOME (LOSS) FROM OPERATIONS
12,669
569,879
(1,529,329)
OTHER INCOME (EXPENSE)
Interest expense
Gain (loss) on extinguishment of debt
Interest income and other
Total other expense
(191,047)
7,830
1,602
(181,615)
(197,474)
(31,968)
3,430
(226,012)
(191,088)
(1,540)
1,316
(191,312)
INCOME (LOSS) BEFORE INCOME TAXES
(168,946)
343,867
(1,720,641)
INCOME TAX EXPENSE (BENEFIT)
Current
Deferred
Total income tax expense (benefit)
NET INCOME (LOSS)
Net loss attributable to noncontrolling interests
-
72,220
72,220
(241,166)
-
-
1,373
1,373
(7,291)
(475,688)
(482,979)
342,494
-
(1,237,662)
14
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON
SHAREHOLDERS
$
(241,166) $
342,494 $
(1,237,648)
INCOME (LOSS) PER COMMON SHARE
Basic
Diluted
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic
Diluted
$
$
(2.64) $
(2.64) $
3.77 $
3.73 $
(13.65)
(13.65)
91,285
91,285
90,953
91,869
90,683
90,683
The accompanying notes are an integral part of these consolidated financial statements.
69
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
Year Ended December 31,
2018
2017
2019
$
(241,166) $
342,494 $
(1,237,662)
operating activities:
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
Loss on sale of properties
Oil and gas property impairments
(Gain) loss on extinguishment of debt
Non-cash derivative (gain) loss
Payment for settlement of commodity derivative contract
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 properties
Net cash provided by (used in) investing activities
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under credit agreement
Repayments of borrowings under credit agreement
Issuance of 6.625% Senior Notes due 2026
Redemption of 6.5% Senior Subordinated Notes due 2018
Redemption of 5.0% Senior Notes due 2019
Repurchase of 1.25% Convertible Senior Notes due 2020
Repurchase of 5.75% Senior Notes due 2021
Debt issuance and extinguishment costs
Restricted stock used for tax withholdings
Proceeds from stock options exercised
Principal payments on finance lease obligations
Net cash provided by (used in) financing activities
$
70
816,488
72,220
28,340
7,721
(9,069)
1,964
17,866
(7,830)
78,626
-
(1,352)
(24,343)
7,165
40,117
(26,274)
(4,513)
755,960
(793,365)
(6,031)
(6,451)
72,000
(733,847)
781,329
1,373
30,700
12,669
(11,354)
1,949
45,288
31,968
(139,831)
(61,036)
(6,706)
(11,571)
4,026
11,368
56,751
2,586
1,092,003
(813,981)
(142,723)
(1,096)
4,746
(953,054)
2,650,000
(2,275,000)
-
-
-
(297,000)
(95,279)
(819)
(3,830)
-
(5,140)
(27,068) $
2,214,265
(2,214,265)
-
-
(990,023)
-
-
(10,709)
(4,744)
755
-
(1,004,721) $
948,939
(475,688)
31,715
21,641
(12,963)
401,113
899,853
1,540
131,129
-
(9,255)
(110,879)
(444)
(24,953)
23,799
(10,776)
577,109
(830,552)
(21,429)
(4,596)
929,974
73,397
1,900,000
(2,450,000)
1,000,000
(275,121)
-
-
-
(13,150)
(6,081)
-
-
155,648
(Continued)
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
NET CHANGE IN CASH AND CASH EQUIVALENTS
$
2019
Year Ended December 31,
2018
(865,772) $
(4,955) $
2017
806,154
CASH AND CASH EQUIVALENTS
Beginning of period
End of period
SUPPLEMENTAL CASH FLOW DISCLOSURES
Income taxes paid (refunded), net
Interest paid, net of amounts capitalized
NONCASH INVESTING ACTIVITIES
Accrued capital expenditures and accounts payable related to property
additions
Leasehold improvements paid for by third party lessor under office
lease agreement
NONCASH FINANCING ACTIVITIES (1)
13,607
8,652 $
879,379
13,607 $
73,225
879,379
(7,508) $
163,859 $
(32) $
152,665 $
49
163,151
86,088 $
90,358 $
80,762
10,422 $
- $
-
$
$
$
$
$
(Concluded)
(1) Refer to the “Leases” footnote in the notes to the consolidated financial statements for discussion of right-of-use assets obtained in
exchange for finance lease liabilities.
The accompanying notes are an integral part of these consolidated financial statements.
71
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2
7
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, Whiting Resources Corporation 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 and its consolidated subsidiaries.
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) income taxes; (vii) accrued liabilities; (viii) valuation of
derivative instruments; and (ix) accrued revenue and related receivables. Although management believes these estimates are reasonable,
actual results could differ from these estimates. Further, these estimates and other factors, including those outside of the Company’s
control, such as the impact of lower commodity prices, may have a significant negative impact to the Company’s business, financial
condition, results of operations and cash flows.
Cash and Cash Equivalents—Cash equivalents consist of demand deposits and highly liquid investments which have an original
maturity of three months or less.
Accounts Receivable Trade—Whiting’s accounts receivable trade consist mainly of receivables from oil and gas purchasers and joint
interest owners on properties the Company operates. For receivables from joint interest owners, Whiting typically has the ability to
withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, the Company’s oil and gas
receivables are collected within two months, and to date, the Company has had minimal bad debts.
The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. At
December 31, 2019 and 2018, the Company had an allowance for doubtful accounts of $9 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 $39 million and $23 million as of
December 31, 2019 and 2018, 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 $6 million and $5 million as of December 31, 2019
and 2018, respectively.
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. Such events include, but are not limited to, declines in commodity prices, increases in
73
operating costs, unfavorable reserve revisions, poor well performance, changes in development plans and potential property divestitures.
The impairment test compares undiscounted future net cash flows to the assets’ net book value. These undiscounted cash flows are
driven by significant assumptions, including the Company’s expected future development activity, reserve estimates, forecasted pricing,
future operating costs, capital expenditures and severance taxes. If the net capitalized costs exceed undiscounted future net cash flows,
then the cost of the property is written down to fair value utilizing a discounted future net cash flow analysis.
Impairment expense for proved properties totaled $835 million for the year ended December 31, 2017, 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.
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 $9 million, $37 million and $59 million for the years ended December 31, 2019, 2018 and 2017,
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. Costs
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.
Other Property and Equipment—Other property and equipment consists of materials and supplies inventories, carried at weighted-
average cost, and furniture and fixtures, buildings and leasehold improvements, which are stated at cost and depreciated using the
straight-line method over their estimated useful lives ranging from 4 to 30 years. Additionally, other property and equipment includes
finance lease right-of-use assets for pipeline and midstream facilities, field and office equipment and automobiles, which are depreciated
using the straight-line method over their estimated useful lives ranging from 5 to 30 years. Refer to the “Leases” footnote for additional
information on these lease assets.
Debt Issuance Costs—Debt issuance costs related to the Company’s senior notes and convertible senior 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.
Debt Discounts and Premiums—Debt discounts and premiums related to the Company’s senior notes and convertible senior notes are
included as a deduction from or addition to the carrying amount of the 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 notes.
Derivative Instruments—The Company enters into derivative contracts, primarily collars, swaps and options, to manage its exposure
to commodity price risk. Whiting follows FASB ASC Topic 815 – Derivatives and Hedging, to account for its derivative financial
74
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 18,400,000 Whiting USA Trust II (“Trust II”) units, and is
amortized to income based on the unit-of-production method.
Revenue Recognition—Revenues are predominantly derived from the sale of produced oil, NGLs and natural gas. The Company
accounts for revenues in accordance with FASB ASC Topic 606 – Revenue from Contracts with Customers, and thus oil and gas revenues
are recognized when the performance obligation to deliver the product is met and control is transferred to the customer. Payments for
product sales are received one to three months after delivery. At the end of each month when the performance obligation is satisfied
and the amount of production delivered and the price received can be reasonably estimated, amounts due from customers are accrued in
accounts receivable trade, net in the consolidated balance sheets. Variances between estimated revenue and actual payments are recorded
in the month the payment is received. However, differences have been and are insignificant.
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
various types of stock-based awards, including shares of restricted stock, restricted stock units, performance shares, performance share
units and stock options, to employees and non-employee directors. The Company determines compensation expense for share-settled
awards granted under these plans based on the grant date fair value, and such expense is recognized on a straight-line basis over the
requisite service period of the award. The Company determines compensation expense for cash-settled awards granted under these
plans based on the fair value of such awards at the end of each reporting period. Cash-settled awards are recorded as a liability in the
consolidated balance sheets, and gains and losses from changes in fair value are recognized immediately in earnings. The Company
accounts for forfeitures of share-based awards as they occur. 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 2019, 2018 and 2017 were $7 million, $7 million and
$8 million, respectively. Employees vest in employer contributions at 20% per year of completed service up to five years.
75
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 attributable 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 attributable 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 and performance stock awards and units, outstanding stock options and contingently issuable
shares of convertible debt to be settled in cash, all using the treasury stock method. 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, 2019, 2018 and 2017.
Year Ended December 31, 2019
Tesoro Crude Oil Co
Philips 66 Company
Year Ended December 31, 2018
United Energy Trading, LLC
Tesoro Crude Oil Co
Philips 66 Company
Year Ended December 31, 2017
Tesoro Crude Oil Co
14 %
12 %
17 %
14 %
11 %
18 %
Commodity derivative contracts held by the Company are with nine counterparties, all of which are participants in Whiting’s credit
facility and all of which have investment-grade ratings from Moody’s and Standard & Poor’s. As of December 31, 2019, outstanding
derivative contracts with Capital One, N.A., JP Morgan Chase Bank, N.A., the Bank of Nova Scotia, Merrill Lynch Commodities, Inc.
and Citibank, N.A. represented 28%, 16%, 14%, 13% and 11%, respectively, of total crude oil volumes hedged.
Adopted and Recently Issued Accounting Pronouncements—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. The FASB
subsequently issued various ASUs which provided additional implementation guidance, and these ASUs collectively make up FASB
76
ASC Topic 842 – Leases (“ASC 842”). ASC 842 is effective for fiscal years, and interim periods within those fiscal years, beginning
after December 15, 2018. The standard permits retrospective application through recognition of a cumulative-effect adjustment at the
beginning of either the earliest reporting period presented or the period of adoption. The Company adopted ASC 842 effective January 1,
2019 using the modified retrospective method as of the adoption date. Whiting has completed the assessment of its existing accounting
policies and documentation, implementation of lease accounting software and enhancement of its internal controls. Adoption of the
standard resulted in the recognition of additional lease assets and liabilities on Whiting’s consolidated balance sheet as well as additional
disclosures. The adoption did not have a material impact to the Company’s consolidated statement of operations. Refer to the “Leases”
footnote for further information on the Company’s implementation of this standard.
2. OIL AND GAS PROPERTIES
Net capitalized costs related to the Company’s oil and gas producing activities at December 31, 2019 and 2018 are as follows (in
thousands):
Costs of completed wells and facilities
Proved leasehold costs
Wells and facilities in progress
Unproved leasehold costs
Total oil and gas properties, successful efforts method
Accumulated depletion
Oil and gas properties, net
3. ACQUISITIONS AND DIVESTITURES
2019 Acquisitions and Divestitures
December 31,
2019
9,847,159 $
2,702,236
159,334
103,278
12,812,007
(5,656,929)
7,155,078 $
2018
9,182,384
2,729,593
160,995
122,687
12,195,659
(4,937,579)
7,258,080
$
$
On July 29, 2019, the Company completed the divestiture of its interests in 137 non-operated, producing oil and gas wells located in the
McKenzie, Mountrail and Williams counties of North Dakota for aggregate sales proceeds of $27 million (before closing adjustments).
On August 15, 2019, the Company completed the divestiture of its interests in 58 non-operated, producing oil and gas wells located in
Richland County, Montana and Mountrail and Williams counties of North Dakota for aggregate sales proceeds of $26 million (before
closing adjustments).
There were no significant acquisitions during the year ended December 31, 2019.
2018 Acquisitions and Divestitures
On July 31, 2018, the Company completed the acquisition of certain oil and gas properties located in Richland County, Montana and
McKenzie County, North Dakota for an aggregate purchase price of $130 million (before closing adjustments). The properties consist
of approximately 54,800 net acres in the Williston Basin, including interests in 117 producing oil and gas wells and undeveloped
acreage. The revenue and earnings from these properties since the acquisition date are included in the Company’s consolidated financial
statements for the year ended December 31, 2018 and are not material. Pro forma revenue and earnings for the acquired properties are
not material to the Company’s consolidated financial statements and have not been presented accordingly.
77
The acquisition was recorded using the acquisition method of accounting. The following table summarizes the allocation of the
$123 million adjusted purchase price to the tangible assets acquired and liabilities assumed in this acquisition based on their relative fair
values at the acquisition date, which did not result in the recognition of goodwill or a bargain purchase gain (in thousands):
Cash consideration
Fair value of assets acquired:
Accounts receivable trade, net
Prepaid expenses and other
Oil and gas properties, successful efforts method:
Proved oil and gas properties
Unproved oil and gas properties
Total fair value of assets acquired
Fair value of liabilities assumed:
Revenue and royalties payable
Asset retirement obligations
Total fair value of liabilities assumed
$
$
122,861
30
43
106,860
21,769
128,702
3,309
2,532
5,841
Total fair value of assets and liabilities acquired
$
122,861
2017 Acquisitions and Divestitures
On January 1, 2017, the Company completed the sale of its 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.
On September 1, 2017, the Company completed the sale of its interests in certain producing oil and gas properties located in the Fort
Berthold Indian Reservation area in Dunn and McLean counties of North Dakota, as well as other related assets and liabilities, (the
“FBIR Assets”) for aggregate sales proceeds of $500 million (before closing adjustments). The sale was effective September 1, 2017
and resulted in a pre-tax loss on sale of $402 million. The Company used the net proceeds from the sale to repay a portion of the debt
outstanding under its credit agreement.
There were no significant acquisitions during the year ended December 31, 2017.
4. LEASES
The Company adopted ASC 842 effective January 1, 2019, which replaces previous lease accounting requirements under FASB ASC
Topic 840 – Leases (“ASC 840”). The standard was adopted using the modified retrospective approach which resulted in the recognition
of approximately $30 million and $36 million of additional lease assets and liabilities, respectively, on the consolidated balance sheet
upon adoption. The Company has elected certain practical expedients available under ASC 842 including those that permit the Company
to not (i) reassess prior conclusions reached under ASC 840 for lease identification, lease classification and initial direct costs, (ii)
evaluate existing or expired land easements under the new standard and (iii) separate lease and non-lease components contained within
a single agreement for all classes of underlying assets. Accordingly, the adoption of the standard did not result in the Company
recognizing a cumulative-effect adjustment to retained earnings. Additionally, the Company has elected the short-term lease recognition
exemption for all classes of underlying assets, and therefore, leases with a term of one year or less have not and will not be recognized
on the consolidated balance sheets.
The Company has operating and finance leases for corporate and field offices, pipeline and midstream facilities and automobiles. Right-
of-use (“ROU”) assets and liabilities associated with these leases are recognized at the lease commencement date based on the present
value of the lease payments over the lease term. ROU assets represent the Company’s right to use an underlying asset for the lease term,
and lease liabilities represent the Company’s obligation to make lease payments.
78
Supplemental balance sheet information for the Company’s leases as of December 31, 2019 consisted of the following (in thousands):
Leases
Balance Sheet Classification
December 31, 2019
Operating Leases
Operating lease ROU assets
Accumulated depreciation
Operating lease ROU assets, net
Short-term operating lease obligations
Long-term operating lease obligations
Total operating lease obligations
Finance Leases
Finance lease ROU assets
Accumulated depreciation
Finance lease ROU assets, net
Short-term finance lease obligations
Long-term finance lease obligations
Total finance lease obligations
Other long-term assets
Other long-term assets
Accrued liabilities and other
Operating lease obligations
$
$
$
$
Other property and equipment
$
Accumulated depreciation, depletion and amortization
$
Accrued liabilities and other
Other long-term liabilities
$
$
31,882
(4,895)
26,987
7,346
31,722
39,068
33,312
(14,180)
19,132
4,974
16,638
21,612
The Company’s leases have remaining terms of less than one year to 10 years. Most of the Company’s leases do not state or imply a
discount rate. Accordingly, the Company uses its incremental borrowing rate based on information available at lease commencement
to determine the present value of the lease payments. Information regarding the Company’s lease terms and discount rates as of
December 31, 2019 is as follows:
Weighted Average Remaining Lease Term
Operating leases
Finance leases
Weighted Average Discount Rate
Operating leases
Finance leases
8 years
5 years
4.6%
8.6%
Operating lease cost is recognized on a straight-line basis over the lease term. Finance lease cost is recognized based on the effective
interest method for the lease liability and straight-line amortization of the ROU asset, resulting in more cost being recognized in earlier
lease periods. All payments for short-term leases, including leases with a term of one month or less, are recognized in income or
capitalized to the cost of oil and gas properties on a straight-line basis over the lease term. Additionally, any variable payments, which
are generally related to the corresponding utilization of the asset, are recognized in the period in which the obligation was incurred.
Lease cost for the year ended December 31, 2019 consisted of the following (in thousands):
Operating lease cost
Finance lease cost:
Amortization of ROU assets
Interest on lease liabilities
Total finance lease cost
Short-term lease payments
Variable lease payments
79
Year Ended
December 31, 2019
11,512
5,661
1,996
7,657
676,850
31,812
$
$
$
$
$
Total lease cost represents the total financial obligations of the Company, a portion of which has been or will be reimbursed by the
Company’s working interest partners. Lease cost is included in various line items on the consolidated statements of operations or
capitalized to oil and gas properties and is recorded at the Company’s net working interest.
Supplemental cash flow information related to leases for the year ended December 31, 2019 consisted of the following (in thousands):
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases
Operating cash flows from finance leases
Financing cash flows from finance leases
ROU assets obtained in exchange for new operating lease obligations
ROU assets obtained in exchange for new finance lease obligations
The Company’s lease obligations as of December 31, 2019 will mature as follows (in thousands):
Year Ended
December 31, 2019
$
$
$
$
$
11,978
2,006
5,140
18,658
4,158
Year ending December 31,
2020
2021
2022
2023
2024
Remaining
Total lease payments
Less imputed interest
Total discounted lease payments
Operating Leases
Finance Leases
8,886 $
6,657
5,256
4,592
4,335
16,951
46,677 $
(7,609)
39,068 $
6,642
5,753
4,748
3,849
3,246
2,535
26,773
(5,161)
21,612
$
$
$
As of December 31, 2019, the Company had a contract for an additional corporate office space that consists of approximately $16 million
of undiscounted minimum lease payments. The operating lease has a nine-year lease term and is expected to commence in June 2020.
As of December 31, 2018, minimum future contractual payments for long-term leases under the scope of ASC 840 were as follows (in
thousands):
Year ending December 31,
2019
2020
2021
2022
2023
Remaining
Total lease payments
Real Estate
Leases
Pipeline
Transportation
Agreement
Automobile and
Equipment
Leases
7,407
4,770
4,066
4,188
4,017
25,140
49,588
$
$
3,180
3,180
3,180
3,180
3,180
5,565
21,465
$
$
4,216
3,422
1,678
488
35
-
9,839
$
$
80
5. LONG-TERM DEBT
Long-term debt consisted of the following at December 31, 2019 and 2018 (in thousands):
Credit agreement
1.25% Convertible Senior Notes due 2020
5.75% Senior Notes due 2021
6.25% Senior Notes due 2023
6.625% Senior Notes due 2026
Total principal
Unamortized debt discounts and premiums
Unamortized debt issuance costs on notes
Total long-term debt
Credit Agreement
December 31,
2019
2018
$
$
375,000 $
262,075
773,609
408,296
1,000,000
2,818,980
(2,575)
(16,520)
2,799,885 $
-
562,075
873,609
408,296
1,000,000
2,843,980
(28,994)
(22,665)
2,792,321
Whiting Oil and Gas, the Company’s wholly owned subsidiary, has a credit agreement with a syndicate of banks that as of December 31,
2019 had a borrowing base of $2.05 billion and aggregate commitments of $1.75 billion. As of December 31, 2019, the Company had
$1.4 billion of available borrowing capacity under the credit agreement, which was net of $375 million of borrowings outstanding and
$2 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
total outstanding credit exposure exceeds the redetermined borrowing base, the Company will be required to prepay outstanding
borrowings in an aggregate principal amount equal to such excess in six substantially equal monthly installments. In October 2019, the
borrowing base under the credit agreement was reduced from $2.25 billion to $2.05 billion in connection with the semi-annual regular
borrowing base redetermination, with no change to the aggregate commitments of $1.75 billion.
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, 2019, $48 million was available
for additional letters of credit under the agreement.
The credit agreement provides for interest only payments until maturity, when the credit agreement expires and all outstanding
borrowings are due. Interest under the credit agreement accrues at the Company’s option at either (i) a base rate for a base rate loan
plus a margin between 0.50% and 1.50% based on the ratio of outstanding borrowings to the borrowing base, 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 a margin between 1.50% and 2.50% based on the ratio of outstanding
borrowings to the borrowing base. Additionally, the Company incurs commitment fees of 0.375% or 0.50% based on the ratio of
outstanding borrowings to the borrowing base on the unused portion of the aggregate commitments of the lenders under the credit
agreement, which are included as a component of interest expense. At December 31, 2019, the weighted average interest rate on the
outstanding principal balance under the credit agreement was 3.3%.
The credit agreement matures on April 12, 2023, provided that if at any time and for so long as any senior notes (other than the 2020
Convertible Senior Notes) have a maturity date prior to 91 days after April 12, 2023, the maturity date shall be the date that is 91 days
prior to the maturity of such senior notes. On September 13, 2019, the Company amended the credit agreement to, among other things,
permit the repurchase, redemption, prepayment or other acquisition or retirement for value of any senior notes (as defined in the credit
agreement) if: (i) such transaction is for a price not greater than an amount equal to par plus accrued and unpaid interest and fees and
any applicable make-whole premium, (ii) immediately after giving effect to such transaction, there is unused availability under the
facility of not less than the greater of $100 million or 15% of the then effective total commitments, and (iii) the Company’s ratio of
consolidated total debt as of the date of such transaction (upon giving effect thereto) to EBITDAX (as defined in the credit agreement)
during the last four quarters is not greater than 3.25 to 1.0. The Company’s business plan includes the intent to refinance certain senior
81
notes, including the convertible senior notes due in 2020 and the senior notes due in 2021, as permitted by the September 13, 2019
amendment to the credit agreement. Consequently, the Company has classified the credit agreement as long-term debt.
The credit agreement contains restrictive covenants that may limit the Company’s ability to, among other things, incur additional
indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, incur liens and engage
in certain other transactions without the prior consent of its lenders. Except for limited exceptions, the credit agreement also restricts
the Company’s ability to make any dividend payments or distributions on its common stock. These restrictions apply to all of the
Company’s restricted subsidiaries (as defined in the credit agreement). As of December 31, 2019, 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 and (ii) a total debt to last four quarters’
EBITDAX ratio of not greater than 4.0 to 1.0. As of December 31, 2019, the Company was in compliance with its covenants under the
credit agreement.
Under Whiting Oil and Gas’ credit agreement, a cross default provision provides that a default under certain other debt of the Company
or certain of its subsidiaries in an aggregate principal amount exceeding $100 million may constitute an event of default under such
credit agreement. Additionally, under the indentures governing our senior notes and senior convertible notes, a cross-default provision
provides that a default under certain other debt of the Company or certain of its subsidiaries in an aggregate principal amount exceeding
$100 million (or $50 million in the case of the 2021 Senior Notes) may constitute an event of default under such indenture.
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
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 15, 2019 (the “2019 Senior Notes”) and
$800 million of 5.75% Senior Notes due March 15, 2021, and issued at 101% of par an additional $400 million of 5.75% Senior Notes
due March 15, 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 1, 2023 (the “2023 Senior Notes”).
In December 2017, the Company issued at par $1.0 billion of 6.625% Senior Notes due January 15, 2026 (the “2026 Senior Notes” and
together with the 2021 Senior Notes and the 2023 Senior Notes, the “Senior Notes”). The Company used the net proceeds from this
offering to redeem in January 2018 all of the then outstanding 2019 Senior Notes. Refer to “Redemption of 2019 Senior Notes” below
for more information on the redemption of the 2019 Senior Notes.
During 2016, the Company exchanged (i) $75 million aggregate principal amount of its 2018 Senior Subordinated Notes, (ii) $139
million aggregate principal amount of its 2019 Senior Notes, (iii) $326 million aggregate principal amount of its 2021 Senior Notes, and
(iv) $342 million aggregate principal amount of its 2023 Senior Notes, for the same aggregate principal amount of convertible notes.
Subsequently during 2016, all $882 million aggregate principal amount of these convertible notes was converted into approximately
21.6 million shares of the Company’s common stock pursuant to the terms of the notes.
Redemption of 2018 Senior Subordinated Notes. In February 2017, the Company paid $281 million to redeem all of the then outstanding
$275 million aggregate principal amount of 2018 Senior Subordinated Notes, which payment consisted 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.
As a result of the redemption, Whiting recognized a $2 million loss on extinguishment of debt.
Redemption of 2019 Senior Notes. In January 2018, the Company paid $1.0 billion to redeem all of the remaining $961 million aggregate
principal amount of the 2019 Senior Notes, which payment consisted of the 102.976% redemption price plus all accrued and unpaid
82
interest on the notes. The Company financed the redemption with proceeds from the issuance of the 2026 Senior Notes and borrowings
under its credit agreement. As a result of the redemption, the Company recognized a $31 million loss on extinguishment of debt.
Repurchases of 2021 Senior Notes. In September 2019, the Company paid $24 million to repurchase $25 million aggregate principal
amount of the 2021 Senior Notes, which payment consisted of the average 94.708% purchase price plus all accrued and unpaid interest
on the notes. The Company financed the repurchases with borrowings under its credit agreement. As a result of the repurchases, the
Company recognized a $1 million gain on extinguishment of debt, which included a non-cash charge for the acceleration of unamortized
debt issuance costs and debt premium on the notes.
In October 2019, the Company paid an additional $72 million to repurchase $75 million aggregate principal amount of the 2021 Senior
Notes, which payment consisted of the average 95.467% purchase price plus all accrued and unpaid interest on the notes. The Company
financed the repurchases with borrowings under its credit agreement. As a result of the repurchases, the Company recognized a $3
million gain on extinguishment of debt, which included a noncash charge for the acceleration of unamortized debt issuance costs and
debt premium on the notes. As of December 31, 2019, $774 million of 2021 Senior Notes remained outstanding.
2020 Convertible Senior Notes—In March 2015, the Company issued at par $1,250 million of 1.25% Convertible Senior Notes due
April 1, 2020 (the “2020 Convertible Senior Notes”) for net proceeds of $1.2 billion, net of initial purchasers’ fees of $25 million.
During 2016, the Company exchanged $688 million aggregate principal amount of its 2020 Convertible Senior Notes for the same
aggregate principal amount of new mandatory convertible senior notes. Subsequently during 2016, all $688 million aggregate principal
amount of these mandatory convertible notes was converted into approximately 17.8 million shares of the Company’s common stock
pursuant to the terms of the notes.
In September 2019, the Company paid $299 million to complete a cash tender offer for $300 million aggregate principal amount of the
2020 Convertible Senior Notes, which payment consisted of the 99.0% purchase price plus all accrued and unpaid interest on the notes,
which were allocated to the liability and equity components based on their relative fair values. The Company financed the tender offer
with borrowings under its credit agreement. As a result of the tender offer, the Company recognized a $4 million gain on extinguishment
of debt, which was net of a $7 million charge for the non-cash write-off of unamortized debt issuance costs and debt discount and a
$1 million charge for transaction costs. In addition, the Company recorded an $8 million reduction to the equity component of the 2020
Convertible Senior Notes. There was no deferred tax impact associated with this reduction due to the full valuation allowance in effect
as of September 30, 2019.
The remaining $262 million aggregate principal amount of 2020 Convertible Senior Notes outstanding as of December 31, 2019 are
convertible exclusively at the holder’s option. Prior to January 1, 2020, the 2020 Convertible Senior Notes were convertible only upon
the achievement of certain contingent market conditions. As of December 31, 2019, none of the contingent market conditions allowing
holders of the 2020 Convertible Senior Notes to convert these notes had been met. On or after January 1, 2020, the 2020 Convertible
Senior Notes are convertible at any time until the second scheduled trading day immediately preceding the April 1, 2020 maturity date
of the notes. The notes are convertible at a current conversion rate of 6.4102 shares of Whiting’s common stock per $1,000 principal
amount of the notes, which is equivalent to a current conversion price of approximately $156.00. 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. 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. At maturity, the Company must settle all outstanding 2020 Convertible Senior Notes in cash.
The Company’s business plan includes the intent to settle the outstanding 2020 Convertible Senior Notes using borrowings under its
credit agreement. Accordingly, the outstanding balance has been classified as long-term debt in the consolidated balance sheet as of
December 31, 2019.
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 liability component 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
83
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 interest 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 consisted of the following at December 31, 2019 and 2018 (in thousands):
Liability component
Principal
Less: unamortized note discount
Less: unamortized debt issuance costs
Net carrying value
Equity component (1)
December 31,
2019
2018
$
$
$
262,075
(2,829)
(220)
259,026
128,452
$
$
$
562,075
(29,504)
(2,340)
530,231
136,522
(1) Recorded in additional paid-in capital, net of $5 million of issuance costs and $50 million of deferred taxes as of December 31,
2019 and 2018.
Interest expense recognized on the 2020 Convertible Senior Notes related to the stated interest rate and amortization of the debt discount
totaled $26 million, $29 million and $28 million for the years ended December 31, 2019, 2018 and 2017, respectively.
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 Company’s obligations under the Senior Notes and the 2020 Convertible Senior 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.
6. 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 and the terms of the
Company’s lease agreements. The current portions as of December 31, 2019 and 2018 were $4 million and have been included in
84
accrued liabilities and other in the consolidated balance sheets. The following table provides a reconciliation of the Company’s asset
retirement obligations for the years ended December 31, 2019 and 2018 (in thousands):
Asset retirement obligation at January 1
Additional liability incurred
Revisions to estimated cash flows
Accretion expense
Obligations on sold properties
Liabilities settled
Asset retirement obligation at December 31
7. DERIVATIVE FINANCIAL INSTRUMENTS
December 31,
2019
2018
135,834
2,097
(10,945)
11,602
(2,078)
(1,617)
134,893
$
$
134,237
11,981
(17,197)
11,405
(676)
(3,916)
135,834
$
$
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 primarily
enters into derivative contracts such as crude oil collars, swaps and options, as well as sales and delivery contracts, to achieve a more
predictable cash flow by reducing its exposure to commodity price volatility, thereby ensuring adequate funding for the Company’s
capital programs and facilitating the management of returns on drilling programs and acquisitions. The Company does not enter into
derivative contracts for speculative or trading purposes.
Crude Oil Collars, Swaps and Options. Collars are designed to establish floor and ceiling prices on anticipated future oil or gas
production, while swaps and options establish a fixed price for anticipated future oil or gas production. While the use of these derivative
instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements.
The table below details the Company’s collar, swap and option derivatives entered into to hedge forecasted crude oil production revenues
as of December 31, 2019.
Commodity
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Settlement
Period
2020
2020
2020
2021
2021
Derivative Instrument
Index
Fixed Price Swaps
NYMEX WTI
NYMEX WTI
Two-way Collars
NYMEX WTI Three-way Collars (2)
NYMEX WTI Three-way Collars (2)
Call Option (3)
NYMEX WTI
Total
Weighted Average Prices
Swap
Price
$57.57
-
-
-
-
Sub-
Floor
-
-
$43.50
$42.50
-
Floor
-
$54.33
$54.00
$52.50
-
Ceiling
-
$61.77
$63.63
$59.08
$65.00
Contracted
Crude Oil
Volumes
(Bbl)(1)
4,883,000
1,648,000
3,658,000
1,095,000
365,000
11,649,000
(1) Subsequent to December 31, 2019, the Company entered into additional two-way collars for 1,373,000 Bbl of crude oil volumes
for the remainder of 2020 and additional three-way collars for 730,000 Bbl of crude oil volumes for 2021.
(2) The Company is contracted to pay deferred premiums related to certain three-way collars at each settlement date. The weighted
average premium for all three-way collars was $0.56 per Bbl as of December 31, 2019.
(3) This derivative instrument is a sold call option.
85
Crude Oil Sales and Delivery Contract. The Company had a long-term crude oil sales and delivery contract for oil volumes produced
from its Redtail field in Colorado. Whiting determined that this contract would not qualify for the “normal purchase normal sale”
exclusion and therefore reflected the contract at fair value in the consolidated financial statements prior to settlement. On February 1,
2018, Whiting paid $61 million to the counterparty to settle all future minimum volume commitments under this agreement.
Accordingly, this crude oil sales and delivery contract was fully terminated and the fair value of the corresponding derivative was
therefore zero as of that date.
Embedded Derivatives—In July 2016, the Company entered into a purchase and sale agreement with the buyer of its North Ward Estes
Properties, whereby the buyer 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 determined that this NYMEX-linked contingent payment was not clearly and closely
related to the host contract, and the Company therefore bifurcated this embedded feature and reflected it at its estimated fair value in the
consolidated financial statements. On July 19, 2017, the buyer paid $35 million to Whiting to settle this NYMEX-linked contingent
payment, and accordingly, the embedded derivative’s fair value was zero as of December 31, 2019 and 2018.
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,
2019, 2018 and 2017 (in thousands):
Not Designated as
ASC 815 Hedges
Commodity contracts
Embedded derivatives
Total
Statement of Operations
Classification
Derivative loss, net
Loss on sale of properties
Loss Recognized in Income
Year Ended December 31,
2018
2019
$
$
53,769 $
-
53,769 $
17,170 $
-
17,170 $
2017
104,138
18,709
122,847
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):
Balance Sheet Classification
Liabilities
Gross
Recognized
Assets/
December 31, 2019 (1)
Gross
Amounts
Offset
Net
Recognized
Fair Value
Assets/
Liabilities
Not Designated as
ASC 815 Hedges
Derivative assets
Commodity contracts - current
Commodity contracts - non-current Other long-term assets
Derivative assets
Total derivative assets
Derivative liabilities
Commodity contracts - current
Commodity contracts - non-current Other long-term liabilities
Accrued liabilities and other
Total derivative liabilities
$
$
$
$
75,654
5,648
81,302
85,053
6,534
91,587
$
$
$
$
(74,768)
(5,648)
(80,416)
(74,768)
(5,648)
(80,416)
$
$
$
$
886
-
886
10,285
886
11,171
86
Not Designated as
ASC 815 Hedges
Derivative assets
Commodity contracts - current
Total derivative assets
Derivative liabilities
Commodity contracts - current
Total derivative liabilities
Balance Sheet Classification
Liabilities
Gross
Recognized
Assets/
December 31, 2018 (1)
Gross
Amounts
Offset
Net
Recognized
Fair Value
Assets/
Liabilities
Derivative assets
Accrued liabilities and other
$
$
$
$
69,735
69,735
1,393
1,393
$
$
$
$
(1,393)
(1,393)
(1,393)
(1,393)
$
$
$
$
68,342
68,342
-
-
(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.
8. 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.
Cash, cash equivalents, 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.
87
The Company’s senior notes are recorded at cost and the 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, 2019 and 2018 (in thousands):
1.25% Convertible Senior Notes due 2020
5.75% Senior Notes due 2021
6.25% Senior Notes due 2023
6.625% Senior Notes due 2026
Total
Value (1)
$
December 31, 2019
Fair
Carrying
Value (2)
December 31, 2018
Fair
Carrying
Value (2)
Value (1)
260,214 $
732,995
343,989
681,250
2,018,448 $
259,026 $
772,080
405,392
988,387
2,424,885 $
531,161 $
829,929
375,632
865,000
2,601,722 $
530,231
870,545
404,659
986,886
2,792,321
$
(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, 2019 and 2018, 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
Total financial assets
Financial Liabilities
Commodity derivatives – current
Commodity derivatives – non-current
Total financial liabilities
Financial Assets
Commodity derivatives – current
Total financial assets
Level 1
Level 2
Level 3
Total Fair Value
December 31, 2019
$
$
$
$
- $
- $
- $
-
- $
886 $
886 $
10,285 $
886
11,171 $
- $
- $
- $
-
- $
886
886
10,285
886
11,171
Level 1
Level 2
Level 3
Total Fair Value
December 31, 2018
$
$
- $
- $
68,342 $
68,342 $
- $
- $
68,342
68,342
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 collars, swaps and options for crude oil. The Company’s
collars, swaps and options are valued based on an income approach. Both the option and swap models consider various assumptions,
such as quoted forward prices for commodities, time value and volatility factors. These assumptions are observable in the marketplace
throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions
are executed in the marketplace, and are therefore designated as Level 2 within the valuation hierarchy. The discount rates used in the
fair values of these instruments include a measure of either the Company’s or the counterparty’s nonperformance risk, as appropriate.
The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.
In addition, the Company had a long-term crude oil sales and delivery contract, whereby it had committed to deliver certain fixed
volumes of crude oil produced from its Redtail field in Colorado. Whiting determined that the contract did not meet the “normal
purchase normal sale” exclusion, and therefore reflected this contract at fair value in its consolidated financial statements prior to
settlement. This commodity derivative was valued based on a probability-weighted income approach which considered various
assumptions, including quoted spot prices for commodities, market differentials for crude oil, U.S. Treasury rates and either the
88
Company’s or the counterparty’s nonperformance risk, as appropriate. The assumptions used in the valuation of the crude oil sales and
delivery contract included 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. On February 1, 2018, Whiting paid $61 million to the counterparty to settle all future minimum volume
commitments under this agreement. Accordingly, this derivative was settled in its entirety as of that date.
Level 3 Fair Value Measurements—The Company did not have any amounts designated as Level 3 in the valuation hierarchy as of and
for the year ended December 31, 2019. The following table presents a reconciliation of changes in the fair value of financial liabilities
designated as Level 3 in the valuation hierarchy for the year ended December 31, 2018 (in thousands):
Fair value liability, beginning of period
Unrealized gains 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 loss, net in the consolidated statements of operations.
Year Ended
December 31, 2018
$
$
(63,278)
2,242
61,036
-
-
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. 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 during the years ended December 31, 2019 and 2018. 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, 2017, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair
value (in thousands):
Net Carrying
Value as of
December 31,
Fair Value Measurements Using
December 31,
Loss (Before
Tax) Year
Ended
Proved property (1)
2017
389,390 $
Level 1
$
Level 2
Level 3
- $
- $
389,390
$
2017
834,950
(1) During the fourth quarter of 2017, proved oil and gas properties at the Redtail field in the Denver-Julesburg Basin (the “DJ Basin”)
in Weld County, Colorado, with a previous carrying amount of $1.2 billion were written down to their fair value as of December 31,
2017 of $389 million, resulting in a non-cash impairment charge of $835 million which was recorded within exploration and
impairment expense.
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. Based on well performance results in the DJ
Basin, the Company reduced its reserves at its Redtail field during the fourth quarter of 2017, and performed a proved property
impairment test as of December 31, 2017. The fair value was ascribed using income approach analyses based on the net discounted
future cash flows from the producing property and related assets. 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 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 December 31, 2017.
89
9. SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST
Common Stock
Reverse Stock Split. On November 8, 2017 and following approval by the Company’s stockholders of an amendment to its certificate
of incorporation to effect a reverse stock split, the Company’s Board of Directors approved a reverse stock split of Whiting’s common
stock at a ratio of one-for-four and a reduction in the number of authorized shares of the Company’s common stock from 600,000,000
shares to 225,000,000. Whiting’s common stock began trading on a split-adjusted basis on November 9, 2017 upon opening of the New
York Stock Exchange trading day. All share and per share amounts in these consolidated financial statements and related notes for
periods prior to November 2017 have been retroactively adjusted to reflect the reverse stock split.
Noncontrolling Interest—The Company’s noncontrolling interest represented an unrelated third party’s 25% ownership interest in
Sustainable Water Resources, LLC (“SWR”). During the third quarter of 2017, the third party’s ownership interest in SWR was assigned
back to SWR. The table below summarizes the activity for the equity attributable to the noncontrolling interest (in thousands):
Year Ended
Balance at beginning of period
Net loss
Conveyance of ownership interest
Balance at end of period
10. REVENUE RECOGNITION
$
December 31, 2017
7,962
(14)
(7,948)
-
$
The Company recognizes revenue in accordance with FASB ASC Topic 606 – Revenue from Contracts with Customers (“ASC 606”).
Revenue is recognized at the point in time at which the Company’s performance obligations under its commodity sales contracts are
satisfied and control of the commodity is transferred to the customer. The Company has determined that its contracts for the sale of
crude oil, unprocessed natural gas, residue gas and NGLs contain monthly performance obligations to deliver product at locations
specified in the contract. Control is transferred at the delivery location, at which point the performance obligation has been satisfied
and revenue is recognized. Fees included in the contract that are incurred prior to control transfer are classified as transportation,
gathering, compression and other, and fees incurred after control transfers are included as a reduction to the transaction price. The
transaction price at which revenue is recognized consists entirely of variable consideration based on quoted market prices less various
fees and the quantity of volumes delivered. The table below presents the disaggregation of revenue by product type for the years ended
December 31, 2019 and 2018 (in thousands):
Operating Revenues
Oil sales
NGL and natural gas sales
Oil, NGL and natural gas sales
December 31,
2019
2018
$
$
1,492,218 $
80,027
1,572,245 $
1,850,052
231,362
2,081,414
Whiting receives payment for product sales from one to three months after delivery. At the end of each month when the performance
obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in accounts
receivable trade, net in the consolidated balance sheets. As of December 31, 2019 and 2018, such receivable balances were $161 million
and $165 million, respectively. Variances between the Company’s estimated revenue and actual payments are recorded in the month
the payment is received, however, differences have been and are insignificant. Accordingly, the variable consideration is not
constrained.
The Company has elected to utilize the practical expedient in ASC 606 that states the Company is not required to disclose the transaction
price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied
performance obligation. Under the Company’s contracts, each monthly delivery of product represents a separate performance
obligation, therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance
obligations is not required.
90
11. STOCK-BASED COMPENSATION
Equity Incentive Plan—The Company maintains the Whiting Petroleum Corporation 2013 Equity Incentive Plan, as amended and
restated (the “2013 Equity Plan”), which replaced the Whiting Petroleum Corporation 2003 Equity Incentive Plan (the “2003 Equity
Plan”) and originally granted the authority to issue 1,325,000 shares of the Company’s common stock. During 2016, shareholders
approved an amendment to the 2013 Equity Plan granting the authority to issue an additional 1,375,000 shares of the Company’s
common stock. In May 2019, shareholders approved an additional amendment to the 2013 Equity Plan granting the authority to issue
an additional 3,000,000 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
awards remain in effect pursuant to their terms. 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. Under the amended and restated 2013 Equity
Plan, during any calendar year, no officer or other key employee participant may be granted options or stock appreciation rights for
more than 500,000 shares of common stock or more than 500,000 shares of restricted stock (“RSAs”), restricted stock units (“RSUs”),
performance shares (“PSAs”) or performance share units (“PSUs”), the value of which is based on the fair market value of a share of
common stock. In addition, no non-employee director participant may be granted during any calendar year options or stock appreciation
rights for more than 25,000 shares of common stock, or more than 25,000 shares of RSAs or RSUs. As of December 31, 2019, 3,698,933
shares of common stock remained available for grant under the 2013 Equity Plan.
The Company grants service-based RSAs and RSUs to executive officers and employees, which generally vest ratably over a three-year
service period. The Company also grants service-based RSAs to directors, which generally vest over a one-year service period. In
addition, the Company grants PSAs and PSUs to executive officers that are subject to market-based vesting criteria, which generally
vest over a three-year service period. The Company accounts for forfeitures of awards granted under these plans as they occur in
determining compensation expense. The Company recognizes compensation expense for awards subject to market-based vesting
conditions regardless of whether it becomes probable that these conditions will be achieved or not, and compensation expense for share-
settled awards is not reversed if vesting does not actually occur.
During 2019, 2018 and 2017, 467,055, 249,983 and 538,194 shares, respectively, of service-based RSAs and RSUs were granted to
employees, executive officers and directors under the 2013 Equity Plan. The Company determines compensation expense for these
share-settled awards using their fair value at the grant date, which is based on the closing bid price of the Company’s common stock on
such date. The weighted average grant date fair value of service-based RSAs and RSUs was $24.65 per share, $32.34 per share and
$40.66 per share for the years ended December 31, 2019, 2018, and 2017, respectively.
During 2019 and 2018, 774,665 and 308,432 shares, respectively, of service-based RSUs were granted to employees under the 2013
Equity Plan. These awards will be settled in cash and are recorded as a liability in the consolidated balance sheets. The Company
determines compensation expense for cash-settled RSUs using the fair value at the end of each reporting period, which is based on the
closing bid price of the Company’s common stock on such date.
During 2019 and 2018, 347,493 and 230,932 shares, respectively, of PSAs and PSUs subject to certain market-based vesting criteria
were granted to executive officers under the 2013 Equity Plan. The 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 is determined based on the rank of Whiting’s
cumulative stockholder return compared to the stockholder return of a peer group of companies on each anniversary of the grant date
over the three-year performance period. The number of awards earned could range from zero up to two times the number of shares
initially granted. However, awards earned up to the target shares granted (or 100%) will be settled in shares, while awards earned in
excess of the target shares granted will be settled in cash. The cash-settled component of such awards is recorded as a liability in the
consolidated balance sheets and will be remeasured at fair value using a Monte Carlo valuation model at the end of each reporting
period.
During 2017, 168,466 PSAs 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 is 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 and will be settled entirely in shares.
91
For awards subject to market conditions, the grant date fair value is 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 is calculated based on the historical volatility and implied 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 these market-based awards were as follows:
Number of simulations
Expected volatility
Risk-free interest rate
Dividend yield
2019
2,500,000
72.95%
2.60%
—
2018
2,500,000
72.80%
2.12%
—
2017
2,500,000
82.44%
1.52%
—
The weighted average grant date fair value of the market-based awards that will be settled in shares as determined by the Monte Carlo
valuation model was $25.97 per share, $27.28 per share and $63.04 per share in 2019, 2018 and 2017, respectively.
The following table shows a summary of the Company’s service-based and market-based awards activity for the year ended
December 31, 2019:
Nonvested awards, January 1
Granted
Vested
Forfeited
Nonvested awards, December 31
Number of Awards
Weighted Average
Service‑Based
RSAs & RSUs
Market-Based
PSAs & PSUs
Grant Date
Fair Value
554,527
467,055
(383,908)
(170,172)
467,502
503,696
347,493
(98,581)
(304,221)
448,387
$
$
34.94
24.61
32.15
32.88
28.28
As of December 31, 2019, there was $13 million of total unrecognized compensation cost related to unvested awards granted under the
stock incentive plans. That cost is expected to be recognized over a weighted average period of 2.0 years. For the years ended
December 31, 2019, 2018 and 2017, the total fair value of the Company’s service-based and market-based awards vested was $12
million, $16 million and $15 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
2019, 2018 or 2017. 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, 2019 as well as activity during
the year then ended:
Weighted
Average
Exercise Price
per Share
Aggregate
Intrinsic
Value
(in thousands) (in years)
Weighted
Average
Remaining
Contractual
Term
Number of
Options
Options outstanding at January 1
Granted
Exercised
Forfeited or expired
Options outstanding at December 31
Options vested at December 31
Options exercisable at December 31
49,230
-
-
(6,270)
42,960
42,960
42,960
$
$
$
$
195.92
-
-
216.78
192.88
192.88
192.88
$
$
$
$
-
-
-
-
2.2
2.2
2.2
92
There was no unrecognized compensation cost related to unvested stock option awards as of December 31, 2019. For the year ended
December 31, 2018, the aggregate intrinsic value of stock options exercised was $0.1 million. There were no stock options exercised
during the years ended December 31, 2019 or 2017.
Total stock-based compensation expense was $8 million, $18 million and $22 million for the years ended December 31, 2019, 2018 and
2017, respectively.
12. INCOME TAXES
Income tax expense (benefit) consists of the following (in thousands):
Current income tax expense (benefit)
Federal
State
Total current income tax benefit
Deferred income tax expense (benefit)
Federal
State
Foreign
Total deferred income tax expense (benefit)
Total
Year Ended December 31,
2018
2019
2017
$
$
- $
-
-
2,140
(3,513)
73,593
72,220
72,220 $
- $
-
-
(10,960)
12,333
-
1,373
1,373 $
(7,305)
14
(7,291)
(398,686)
(77,002)
-
(475,688)
(482,979)
Income tax expense (benefit) differed from amounts that would result from applying the U.S. statutory income tax rate (21% for the
years ended December 31, 2019 and 2018 and 35% for the year ended December 31, 2017) to income before income taxes as follows
(in thousands):
U.S. statutory income tax expense (benefit)
State income taxes, net of federal benefit
Foreign tax expense
Valuation allowance
Federal tax reform
Impairment charge after enactment of federal tax reform
IRC Section 382 limitation
Market-based equity awards
Outside basis difference recognition
Other
Total
Year Ended December 31,
2018
2019
$
$
(35,479) $
(8,288)
(147)
39,672
-
-
-
910
73,740
1,812
72,220 $
72,211 $
14,324
-
(87,774)
-
-
-
2,215
-
397
1,373 $
2017
(602,219)
(39,557)
-
120,880
(42,033)
114,293
(45,899)
7,003
-
4,553
(482,979)
93
The principal components of the Company’s deferred income tax assets and liabilities at December 31, 2019 and 2018 were as follows
(in thousands):
Deferred income tax assets
Net operating loss carryforward
Derivative instruments
Asset retirement obligations
Restricted stock compensation
EOR credit carryforwards
Lease obligations
Other
Total deferred income tax assets
Less valuation allowance
Net deferred income tax assets
Deferred income tax liabilities
Oil and gas properties
Trust distributions
Lease assets
Derivative instruments
Discount on convertible senior notes
Foreign outside basis difference
Total deferred income tax liabilities
Total net deferred income tax liabilities
Year Ended December 31,
2018
2019
$
$
944,709
2,451
32,152
2,033
7,946
14,463
12,847
1,016,601
(188,281)
828,320
805,989
10,517
10,993
-
674
73,740
901,913
73,593
$
$
873,646
-
32,546
5,603
7,946
-
10,777
930,518
(152,035)
778,483
740,933
15,479
-
16,375
7,069
-
779,856
1,373
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 (“NOLs”) and tax credits in the future. Accordingly, the Company recognized
valuation allowances on its deferred tax assets totaling $259 million. In the third quarter of 2017 there was a partial release of this
valuation allowance in the amount of $41 million associated with built-on gains on the sale of the FBIR Assets.
As of December 31, 2019, the Company had federal NOL carryforwards of $3.4 billion, which is net of the IRC Section 382 limitation.
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 majority of the federal NOLs will expire between 2023 and 2037 and the state NOLs will expire
between 2020 and 2037. Any federal NOLs generated in 2018 or subsequent do not expire.
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, 2019, 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.
On December 22, 2017, Congress passed the Tax Cuts and Jobs Act (the “TCJA”). The legislation significantly changed the U.S.
corporate tax law by, among other things, lowering the U.S. corporate income tax rate from 35% to 21% beginning in January 2018,
implementing a territorial tax system and imposing a repatriation tax on deemed repatriated earnings of foreign subsidiaries. FASB
ASC Topic 740 – Income Taxes requires companies to recognize the impact of the changes in tax law in the period of enactment. The
SEC subsequently issued Staff Accounting Bulletin No. 118, which allowed registrants to record provisional amounts during a one-year
“measurement period” similar to that used to account for business combinations. The Company did not recognize any measurement
period adjustments during 2018 and its accounting for the TCJA was complete as of December 31, 2018.
Amounts recorded during the year ended December 31, 2017 related to the TCJA principally relate to the reduction in the U.S. corporate
income tax rate to 21%, which resulted in (i) income tax expense of $51 million from the revaluation of the Company’s deferred tax
assets and liabilities as of the date of enactment and (ii) an income tax benefit totaling $93 million related to a reduction in the Company’s
existing valuation allowances.
94
Other elements of the TCJA that did not have an impact on the Company’s financial statements upon enactment of the TCJA, but may
impact the Company’s income taxes in future periods include: (i) IRC Section 168(k) first-year optional bonus depreciation, (ii) repeal
of the corporate alternative minimum tax, (iii) limitation on the usage of NOLs generated after 2017 to 80% of taxable income, (iv)
additional limitations on certain meals and entertainment expenses, (v) repeal of the deduction for income attributable to domestic
production activities, (vi) like-kind exchange limitations for property other than real property, (vii) ability to capitalize and amortize
intangible drilling costs under IRC Section 59(e), and (viii) interest deduction limitations under IRC Section 163(j).
In assessing the realizability of deferred tax assets (“DTAs”), management considers whether it is more likely than not that some portion,
or all, of the Company’s DTAs 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 DTAs will not be realized,
the tax asset is reduced by a valuation allowance. At December 31, 2019, the Company had a valuation allowance totaling $188 million,
comprised of $138 million of NOL carryforward limitations under Section 382 of the IRC, $8 million of EOR credits, which will expire
between 2023 and 2025, $1 million of short-term capital loss carryforwards that are not expected to be realized and a $41 million general
valuation allowance against the Company’s net U.S. deferred tax assets.
During the fourth quarter of 2019, the Company determined it no longer had the ability to indefinitely prevent the reversal of the outside
basis difference related to Whiting Canadian Holding Company ULC, Whiting’s wholly owned subsidiary, which owns a portion of
Whiting’s U.S. assets obtained through the acquisition of Kodiak Oil and Gas Corporation during 2014. Accordingly, the Company
revised its assessment related to noncurrent Canadian deferred taxes pursuant to ASC 740-30-25-17 and recognized a $74 million
deferred tax liability as well as the same amount of deferred income tax expense as of and for the year ended December 31, 2019
associated with the outside basis difference related to Whiting Canadian Holding Company ULC.
During 2018, the Company recorded an adjustment to its valuation allowance on DTAs totaling $30 million. At December 31, 2018,
the Company had a valuation allowance totaling $152 million, comprised of $138 million of NOL carryforward limitations under
Section 382 of the IRC, $8 million of EOR credits, which will expire between 2023 and 2025, $5 million of Canadian NOL
carryforwards, which will expire between 2034 and 2035, and $1 million of short-term capital loss carryforwards that are not expected
to be realized.
As of December 31, 2019 and 2018, the Company did not have any uncertain tax positions. For the years ended December 31, 2019,
2018 and 2017, 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 2015 through 2019 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 2014 through 2019 tax years.
95
13. EARNINGS PER SHARE
The reconciliations between basic and diluted earnings (loss) per share are as follows (in thousands, except per share data):
Basic Earnings (Loss) Per Share
Net income (loss) attributable to common shareholders
Weighted average shares outstanding, basic
Earnings (loss) per common share, basic
Diluted Earnings (Loss) Per Share
Net income (loss) attributable to common shareholders
Year Ended December 31,
2018
2019
2017
(241,166)
91,285
(2.64)
$
$
342,494 $
90,953
3.77 $
(1,237,648)
90,683
(13.65)
(241,166)
$
342,494 $
(1,237,648)
$
$
$
Weighted average shares outstanding, basic
Service-based awards, market-based awards and stock options
Weighted average shares outstanding, diluted
91,285
-
91,285
90,953
916
91,869
90,683
-
90,683
Earnings (loss) per common share, diluted
$
(2.64)
$
3.73 $
(13.65)
For the year ended December 31, 2019 the Company had a net loss and therefore the diluted earnings per share calculation for that
period excludes the anti-dilutive effect of 344,671 shares of service-based awards and 3,511 shares of market-based awards. In addition,
the diluted earnings per share calculation for the year ended December 31, 2019 excludes the effect of 45,588 common shares for stock
options that were out of the money as of December 31, 2019.
For the year ended December 31, 2018, the diluted earnings per share calculation excludes the effect of 100,708 common shares for
stock options that were out of the money as of December 31, 2018.
For the year ended December 31, 2017, the Company had a net loss and therefore the diluted earnings per share calculation for that
period excludes the anti-dilutive effect of 509,744 shares of service-based awards, 22,946 shares of market-based awards and 1,083
stock options. In addition, the diluted earnings per share calculation for the year ended December 31, 2017 excludes the effect of
123,775 common shares for stock options that were out-of-the-money and 345,071 shares of market-based awards that did not meet the
market-based vesting criteria as of December 31, 2017.
Refer to the “Stock-Based Compensation” footnote for further information on the Company’s service-based awards, market-based
awards and stock options.
As discussed in the “Long-Term Debt” footnote, the Company has the option to settle conversions of the 2020 Convertible Senior Notes
with cash, shares of common stock or any combination thereof. Based on the current conversion price, the entire outstanding principal
amount of the 2020 Convertible Senior Notes as of December 31, 2019 would be convertible into approximately 1.7 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, 2019, 2018
and 2017, the conversion value did not exceed the principal amount of the notes. Accordingly, there was no impact to diluted earnings
per share or the related disclosures for those periods.
96
14. COMMITMENTS AND CONTINGENCIES
The table below shows the Company’s minimum future payments due by period under unconditional purchase obligations as of
December 31, 2019 (in thousands):
Year ending December 31,
2020
2021
2022
2023
2024
Total payments
Pipeline
Transportation
Agreements
$
$
2,189
2,189
2,189
2,189
547
9,303
Pipeline Transportation Agreements—The Company has two effective agreements through 2024 with various third parties to facilitate
the delivery of its produced oil, gas and NGLs to market. Under one of these contracts, the Company has committed to pay fixed
monthly reservation fees on dedicated pipelines for natural gas and NGL transportation capacity, plus additional variable charges based
on actual transportation volumes. These fixed monthly reservation fees totaling approximately $9 million have been included in the
table above.
The remaining contract contains a commitment to transport a minimum volume of crude oil or else pay for any deficiencies at a price
stipulated in the contract. Although minimum annual quantities are specified in the agreement, the actual oil volumes transported 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, 2019, the
Company estimated the minimum future commitments under this transportation agreement to approximate $9 million through 2022.
During 2019, 2018 and 2017, the cost of transportation of crude oil, natural gas and NGLs under these contracts amounted to $2 million,
$2 million and $2 million, respectively.
Purchase Contracts—The Company’s purchase obligation consists of a take-or-pay arrangement to buy volumes of water for use in the
fracture stimulation process. 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, 2019, the Company estimated the minimum future commitments under this purchase agreement to
approximate $8 million through 2020.
As a result of the Company’s reduced development operations in its Redtail field, Whiting has made and expects to make periodic
deficiency payments under this purchase contract during the remaining term, which expires in 2020. During 2019, 2018 and 2017,
purchases of water under the Company’s take-or-pay arrangement amounted to $8 million, $8 million and $22 million, respectively,
which included $8 million and $2 million of deficiency payments for the years ended December 31, 2019 and 2018, respectively, and
insignificant deficiency payments for the year ended December 31, 2017.
Water Disposal Agreement—The Company has a water disposal agreement expiring in 2024 under which 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 therefore not included in the table above. As of December 31, 2019, the Company estimated the minimum future
commitments under this disposal agreement to approximate $83 million through 2024. As a result of the Company’s reduced
development operations at its Redtail field, Whiting has made and expects to make periodic deficiency payments under this contract.
During 2019, 2018 and 2017, transportation and disposal of produced water amounted to $20 million, $19 million and $16 million,
respectively, which includes $14 million, $5 million and $4 million of deficiency payments, respectively.
97
Delivery Commitments—The Company has three physical delivery contracts which require the Company to deliver fixed volumes of
crude oil. One of these delivery commitments became effective on June 1, 2017 upon completion of the Dakota Access Pipeline, and it
is tied to crude oil production from Whiting’s Sanish field in Mountrail County, North Dakota. Under the terms of the agreement,
Whiting has committed to deliver 15 MBbl/d for a term of seven years. The Company believes its production and reserves at the Sanish
field are sufficient to fulfill this delivery commitment, and therefore expects to avoid any payments for deficiencies under this contract.
The second delivery contract is tied to oil production in the Williston Basin. The effective date of this contract is contingent upon the
completion of certain related pipelines, which are currently expected to be brought online in 2021. Under the terms of the agreement,
Whiting has committed to deliver 10 MBbl/d for a term of seven years. The Company believes its production and reserves in the
Williston Basin are sufficient to fulfill this delivery commitment, and therefore expects to avoid any payments for deficiencies under
this contract.
The third delivery contract is tied to crude oil production at Whiting’s Redtail field in Weld County, Colorado. As of December 31,
2019, this contract contains remaining delivery commitments of 4.1 MMBbl of crude oil through the end of the contract’s term in April
2020. 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 2019, 2018 and 2017, total deficiency payments under these contracts, as well as a previous Redtail contract that was terminated
in February 2018, amounted to $64 million, $39 million and $66 million, respectively. The Company recognizes any monthly deficiency
payments in the period in which the underdelivery takes place and the related liability has been incurred. The table above does not
include any such deficiency payments that may be incurred under the Company’s physical delivery contracts, since it cannot be predicted
with accuracy the amount and timing of any such penalties incurred.
Litigation—The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the ordinary course
of business. 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. The Company is involved in litigation related to a payment arrangement with a third party which currently claims
damages up to $41 million, as well as court costs and interest, that is scheduled to go to trial in May 2020. Certain amounts have been
accrued in accrued liabilities and other in the consolidated balance sheet as of December 31, 2019 and general and administrative
expenses in the consolidated statement of operations for the year ended December 31, 2019 based on the determination that it is probable
that a loss has been incurred and can be reasonably estimated.
15. 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
2019
Year Ended December 31,
2018
- $
13,894 $
-
10,831
determination of proved reserves
Ending balance at December 31
$
-
- $
(24,725)
- $
2017
-
13,894
-
13,894
At December 31, 2019, the Company had no costs capitalized for exploratory wells in progress for a period of greater than one year
after the completion of drilling.
98
16. RESTRUCTURING
On July 31, 2019, the Company executed a workforce reduction as part of an organizational redesign and cost reduction strategy to
better align its business with the current operating environment and drive long-term value. In connection with these activities, the
Company incurred $8 million in net restructuring costs associated with one-time employee termination benefits. These restructuring
costs are included in general and administrative expenses in the consolidated statements of operations.
17. SUBSEQUENT EVENTS
On January 9, 2020, the Company completed the divestiture of its interests in 30 non-operated, producing oil and gas wells and related
undeveloped acreage located in McKenzie County, North Dakota for aggregate sales proceeds of $25 million (before closing
adjustments).
99
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,
2018
2019
11,911,977
12,549,395
283,682
262,612
(4,937,579)
(5,656,929)
7,258,080
7,155,078
$
$
The Company’s oil and gas activities for 2019, 2018 and 2017 were entirely within the United States. Costs incurred in oil and gas
producing activities were as follows (in thousands):
Development (1)
Proved property acquisition
Unproved property acquisition
Exploration
Total
Year Ended December 31,
2018
2019
2017
763,395 $
-
6,281
36,872
806,548 $
803,143 $
105,519
34,671
32,911
976,244 $
799,462
4,075
17,629
50,218
871,384
$
$
(1) Development costs include non-cash downward adjustments to oil and gas properties of $9 million, $5 million and $45 million for
2019, 2018 and 2017, respectively, which relate to estimated future plugging and abandonment costs of the Company’s oil and gas
wells.
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, 2019. 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.
100
As of December 31, 2019, 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, 2017, 2018 and 2019 are as
follows:
Oil
(MBbl)
NGLs
(MBbl)
Natural Gas
(MMcf)
Total
(MBOE)
Proved reserves
Balance—January 1, 2017
Extensions and discoveries
Sales of minerals in place
Purchases of minerals in place
Production
Revisions to previous estimates
Balance—December 31, 2017
Extensions and discoveries
Purchases of minerals in place
Production
Revisions to previous estimates
Balance—December 31, 2018
Extensions and discoveries
Sales of minerals in place
Production
Revisions to previous estimates
Balance—December 31, 2019
Proved developed reserves
December 31, 2016
December 31, 2017
December 31, 2018
December 31, 2019
Proved undeveloped reserves
December 31, 2016
December 31, 2017
December 31, 2018
December 31, 2019
394,767
30,076
(42,137)
157
(29,261)
(16,019)
337,583
17,470
20,293
(31,517)
(56,865)
286,964
20,103
(3,175)
(29,811)
(5,828)
268,253
183,165
179,829
194,869
190,725
211,602
157,754
92,095
77,528
101,493
14,512
(5,263)
29
(6,978)
35,156
138,949
8,552
1,386
(7,394)
(30,209)
111,284
6,056
(855)
(7,596)
(15,048)
93,841
51,888
76,957
82,725
72,102
49,605
61,992
28,559
21,739
715,659
82,391
(18,116)
283
(41,261)
107,521
846,477
48,969
24,003
(46,810)
(141,555)
731,084
46,808
(5,253)
(50,483)
17,886
740,042
337,860
473,829
529,154
576,213
377,799
372,648
201,930
163,829
615,537
58,320
(50,419)
233
(43,115)
37,056
617,612
34,184
25,679
(46,712)
(110,668)
520,095
33,960
(4,906)
(45,820)
(17,894)
485,435
291,363
335,758
365,786
358,863
324,174
281,854
154,309
126,572
Notable changes in proved reserves for the year ended December 31, 2019 included the following:
• Extensions and discoveries. In 2019, total extensions and discoveries of 34.0 MMBOE were primarily attributable to successful
drilling in the Williston Basin. Both the new wells drilled in this area 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 4.9 MMBOE during 2019 and were primarily attributable to the
disposition of certain non-operated properties in North Dakota as further described in the “Acquisitions and Divestitures” footnote
in the notes to the consolidated financial statements.
• Revisions to previous estimates. In 2019, revisions to previous estimates decreased proved developed and undeveloped reserves by
a net amount of 17.9 MMBOE. Included in this change were upward revisions of 48.0 MMBOE to proved undeveloped reserves
primarily located in the Williston Basin in locations where we have significant development activity and past drilling success.
Offsetting these upward revisions were: (i) 32.9 MMBOE of downward adjustments caused by lower crude oil, NGL and natural
gas prices incorporated into our reserve estimates at December 31, 2019 as compared to December 31, 2018, (ii) 19.3 MMBOE of
downward adjustments primarily attributable to reservoir analysis and well performance across our Northern and Central Rockies
101
assets and (iii) 13.7 MMBOE of proved undeveloped reserves no longer expected to be developed within five years from their initial
recognition.
Notable changes in proved reserves for the year ended December 31, 2018 included the following:
•
•
•
Extensions and discoveries. In 2018, total extensions and discoveries of 34.2 MMBOE were primarily attributable to successful
drilling in the Williston Basin. Both the new wells drilled in this area as well as the PUD locations added as a result of drilling
increased the Company’s proved reserves.
Purchases of minerals in place. In 2018, total purchases of minerals in place of 25.7 MMBOE were primarily attributable to the
acquisition of 117 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, which increased the Company’s
proved reserves.
Revisions to previous estimates. In 2018, revisions to previous estimates decreased proved developed and undeveloped reserves
by a net amount of 110.7 MMBOE. Included in these revisions were 99.9 MMBOE of proved undeveloped reserves no longer
expected to be developed within five years from their initial recognition. As a result of sustained lower crude oil prices in recent
years, the Company has moved toward a more disciplined capital development program focused on the highest-return projects and
the generation of free cash flow. This shift in strategy resulted in a change in the timing of the Company’s development plans
related to PUD reserves in certain areas. These revisions do not represent the elimination of recoverable hydrocarbons physically
in place, however, as they may be developed in the future. In addition, there were 38.1 MMBOE of downward adjustments
primarily attributable to reservoir analysis and well performance across the Company’s Northern and Central Rockies assets and
27.3 MMBOE of upward adjustments caused by higher crude oil, NGL and natural gas prices incorporated into the Company’s
reserve estimates at December 31, 2018 as compared to December 31, 2017.
Notable changes in proved reserves for the year ended December 31, 2017 included the following:
•
•
•
Extensions and discoveries. In 2017, total extensions and discoveries of 58.3 MMBOE were primarily attributable to successful
drilling in the Williston Basin. Both the new wells drilled in this area 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 50.4 MMBOE during 2017 and were primarily attributable to the
disposition of the FBIR Assets as further described in the “Acquisitions and Divestitures” footnote in the notes to the consolidated
financial statements.
Revisions to previous estimates. In 2017, revisions to previous estimates increased proved developed and undeveloped reserves
by a net amount of 37.1 MMBOE. Included in these revisions were (i) 88.7 MMBOE of upward adjustments caused by higher
crude oil, NGL and natural gas prices incorporated into the Company’s reserve estimates at December 31, 2017 as compared to
December 31, 2016 and (ii) 51.6 MMBOE of downward adjustments primarily attributable to reservoir analysis and well
performance in the Redtail field.
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, 2019, 2018 and 2017 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,
2019, 2018 and 2017, 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
102
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):
Future cash flows
Future production costs
Future development costs
Future income tax expense
Future net cash flows
10% annual discount for estimated timing of cash flows
Standardized measure of discounted future net cash flows
2019
14,700,974
(6,983,878)
(1,451,487)
(88,960)
6,176,649
(2,474,320)
3,702,329
$
$
December 31,
2018
$
$
20,237,473
(7,450,206)
(1,853,805)
(1,065,686)
9,867,776
(4,661,666)
5,206,110
2017
19,635,532
(7,874,590)
(3,022,841)
(474,646)
8,263,455
(4,395,897)
3,867,558
$
$
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 had no significant
impact on undiscounted future cash inflows in 2019, 2018 and 2017.
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
$
$
$
$
2019
5,206,110
(1,063,167)
(52,456)
(1,681,530)
234,782
455,236
(12,964)
-
(191,329)
287,036
520,611
3,702,329
Year Ended December 31,
2018
3,867,558
(1,549,591)
-
1,800,523
465,766
639,827
598,535
349,896
(1,167,886)
(185,274)
386,756
5,206,110
$
$
2017
2,698,086
(991,069)
(312,346)
994,749
437,459
542,746
50,215
1,748
277,967
(101,806)
269,809
3,867,558
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, 2019, 2018 and 2017 as follows:
Oil (per Bbl)
NGLs (per Bbl)
Natural Gas (per Mcf)
2019
2018
2017
$
$
$
50.89
8.72
0.31
$
$
$
60.08
18.58
1.27
$
$
$
47.16
14.74
1.97
103
QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2019 and 2018 (in thousands,
except per share data):
Oil, NGL and natural gas sales
Gross profit
Net loss
Basic loss per share
Diluted loss per share
Oil, NGL and natural gas sales
Gross profit
Net income
Basic earnings per share
Diluted earnings per share
Three Months Ended
March 31,
2019
June 30,
2019
September 30,
2019
December 31,
2019
389,489 $
69,283 $
(68,925) $
(0.76) $
(0.76) $
426,264 $
85,720 $
(5,687) $
(0.06) $
(0.06) $
375,891 $
33,150 $
(19,067) $
(0.21) $
(0.21) $
380,601
58,527
(147,487)
(1.62)
(1.62)
Three Months Ended
March 31,
2018
June 30,
2018
September 30,
2018
December 31,
2018
515,083 $
197,293 $
15,012 $
0.17 $
0.16 $
526,403 $
194,626 $
2,120 $
0.02 $
0.02 $
566,695 $
232,168 $
121,400 $
1.33 $
1.32 $
473,233
144,175
203,962
2.24
2.22
$
$
$
$
$
$
$
$
$
$
******
104
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of disclosure controls and procedures. In accordance with Rule 13a-15(b) of the Securities Exchange Act of 1934 (the
“Exchange Act”), our management evaluated, with the participation of our Chairman, President and Chief Executive Officer and our
Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in
Rule 13a-15(e) under the Exchange Act) as of the end of the year ended December 31, 2019. Based upon their evaluation of these
disclosure controls and procedures, the Chairman, President and Chief Executive Officer and the Chief Financial Officer concluded that
the disclosure controls and procedures were effective as of December 31, 2019 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, 2019 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, 2019, 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, 2019 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, 2019 that has materially affected, or is reasonably likely to materially affect, our internal control
over financial reporting.
105
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Whiting Petroleum Corporation
Denver, Colorado
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Whiting Petroleum Corporation and subsidiaries (the “Company”) as of
December 31, 2019, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control —
Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”),
the consolidated financial statements as of and for the year ended December 31, 2019 of the Company and our report dated February 27,
2020 expressed an unqualified opinion on those financial statements.
Basis for Opinion
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 are a public accounting firm registered with the PCAOB and are required to be independent with respect to the
Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange
Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. 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.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process 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. 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 its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections
of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 27, 2020
Item 9B. Other Information
None.
106
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 “Delinquent Section 16(a) Reports” in our definitive Proxy Statement for
Whiting Petroleum Corporation’s 2020 Annual Meeting of Stockholders (the “Proxy Statement”) is incorporated herein by reference.
Information with respect to our executive officers appears in Part I of this Annual Report on Form 10-K.
We have adopted the Whiting Petroleum Corporation Code of Business Conduct and Ethics that applies to our directors, our Chairman,
President and Chief Executive Officer, our Chief Financial Officer, our Vice President and Controller 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”) 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, 2019.
Equity Compensation Plan Information
Number of securities to Weighted-average
be issued upon exercise
exercise price of
of outstanding options, outstanding options,
warrants and rights
warrants and rights
Number of securities remaining
available for future issuance under
equity compensation plans
(excluding securities reflected in
the first column)
Plan Category
Equity compensation plans approved by
security holders (1)
Equity compensation plans not
approved by security holders
Total
42,960 $
192.88
—
42,960 $
N/A
195.92
(2)
3,698,933
—
3,698,933 (2)
(1) Includes the Whiting Petroleum Corporation 2003 Equity Incentive Plan (the “2003 Equity Plan”) and Whiting Petroleum
Corporation 2013 Equity Incentive Plan, as amended and restated (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 42,960 stock options outstanding and 915,889 shares of restricted common stock previously issued
for which the restrictions have not lapsed.
107
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.
******
108
EXHIBIT INDEX
Exhibit
Number
(3.1)
(3.2)
(4.1)
(4.2)
(4.3)
(4.4)
(4.5)
(4.6)
(4.7)
(4.8)
(4.9)
(10.1)*
(10.2)*
(10.3)*
(10.4)*
Exhibit Description
Restated Certificate of Incorporation of Whiting Petroleum Corporation [Incorporated by reference to Exhibit 3.2 to
Whiting Petroleum Corporation’s Current Report on Form 8-K filed on November 9, 2017 (File No. 001-31899)].
Amended and Restated By-laws of Whiting Petroleum Corporation, effective October 24, 2017 [Incorporated by
reference to Exhibit 3.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed on October 26, 2017
(File No. 001-31899)].
Seventh Amended and Restated Credit Agreement, dated as of April 12, 2018, 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 April 13, 2018 (File No. 001-31899)].
First Amendment to Seventh Amended and Restated Credit Agreement, dated as of September 13, 2019, 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 September 16, 2019 (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)].
Second Supplemental Indenture, dated September 12, 2013, among Whiting Petroleum Corporation, Whiting Oil and
Gas Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating the 5.75% Senior Notes
due 2021 [Incorporated by reference to Exhibit 4.3 to Whiting Petroleum Corporation’s Current Report on Form 8-
K filed on September 12, 2013 (File No. 001-31899)].
Supplemental Indenture and Amendment – Subsidiary Guarantee, dated as of December 11, 2014, among Whiting
Petroleum Corporation, Whiting Canadian Holding Company ULC, Whiting Resources Corporation, Whiting US
Holding Company and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to the 5.75% Senior
Notes Due 2021 [Incorporated by reference to Exhibit 4.3 to Whiting Petroleum Corporation’s Current Report on
Form 8-K filed on December 12, 2014 (File No. 001-31899)].
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)].
Fifth Supplemental Indenture, dated December 27, 2017, 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 6.625% Senior Notes due
2026 [Incorporated by reference to Exhibit 4.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K filed
on December 27, 2017 (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)].
Description of Securities.
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 [Incorporated by reference to
Exhibit A to Whiting Petroleum Corporation’s definitive proxy statement filed with the Securities and Exchange
Commission on Schedule 14A on March 19, 2019 (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 10.1 to Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the quarter ended
September 30, 2008 (File No. 001-31899)].
109
Exhibit
Number
(10.5)*
(10.6)*
(10.7)*
Exhibit Description
Form of Executive Employment and Severance Agreement for executive officers of Whiting Petroleum Corporation
other than Bradley J. Holly and Charles J. Rimer [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
time-based vesting awards [Incorporated by reference to Exhibit 10.10 to Whiting Petroleum Corporation’s Annual
Report on Form 10-K for the year ended December 31, 2016 (File No. 001-31899)].
(10.8)*
Form of Restricted Stock Agreement pursuant to the Whiting Petroleum Corporation 2013 Equity Incentive Plan for
time-based vesting awards granted to executive officers.
(10.9)*
(10.10)*
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 granted in 2018. [Incorporated by reference to Exhibit 10.11 to Whiting Petroleum Corporation’s Annual Report
on Form 10-K for the year ended December 31, 2017 (File No. 001-31899)].
(10.11)*
Form of Performance Share Award Agreement pursuant to the Whiting Petroleum Corporation 2013 Equity Incentive
Plan granted in 2020.
(10.12)*
Form of Restricted Stock Unit Award Agreement (Cash-Settled) pursuant to the Whiting Petroleum Corporation 2013
Equity Incentive Plan [Incorporated by reference to Exhibit 10.3 to Whiting Petroleum Corporation’s Current Report
on Form 8-K filed on October 26, 2017 (File No. 001-31899)].
(10.13)*
Form of Restricted Stock Unit Agreement (Cash-Settled) pursuant to the Whiting Petroleum Corporation 2013 Equity
(10.14)*
(10.15)*
(10.16)*
(10.17)*
(10.18)*
(10.19)*
(10.20)*
(21)
(23.1)
(23.2)
(31.1)
(31.2)
(32.1)
(32.2)
Incentive Plan granted to executive officers.
Form of Restricted Stock Unit Award Agreement (Stock-Settled) pursuant to the Whiting Petroleum Corporation 2013
Equity Incentive Plan for awards granted prior to August 24, 2018 [Incorporated by reference to Exhibit 10.4 to Whiting
Petroleum Corporation’s Current Report on Form 8-K filed on October 26, 2017 (File No. 001-31899)].
Letter Agreement, dated August 24, 2018, Amending Outstanding Restricted Stock and Performance Share Awards and
Executive Employment and Severance Agreement [Incorporated by reference to Exhibit 10.1 to Whiting Petroleum
Corporation’s Current Report on Form 8-K filed on August 30, 2018 (File No. 001-31899)].
Form of Restricted Stock Unit Award Agreement (Stock-Settled) pursuant to the Whiting Petroleum Corporation 2013
Equity Incentive Plan for awards granted on or after August 24, 2018 [Incorporated by reference to Exhibit 10.2 to
Whiting Petroleum Corporation’s Current Report on Form 8-K Filed on August 30, 2018 (File No. 001-31899)].
Form of Performance Share Unit Award Agreement pursuant to the Whiting Petroleum Corporation 2013 Equity
Incentive Plan [Incorporated by reference to Exhibit 10.3 to Whiting Petroleum Corporation’s Current Report on Form
8-K filed on August 30, 2018 (File No. 001-31899)].
Executive Employment and Severance Agreement, between Charles J. Rimer and Whiting Petroleum Corporation,
effective as of November 15, 2018 [Incorporated by reference to Exhibit 10.1 to Whiting Petroleum Corporation’s
Current Report on Form 8-K as filed on November 15, 2018 (File No. 001-31899)].
Executive Employment and Severance Agreement, between Bradley J. Holly and Whiting Petroleum Corporation,
effective as of November 1, 2017 [Incorporated by reference to Exhibit 10.1 to Whiting Petroleum Corporation’s
Current Report on Form 8-K as filed on October 26, 2017 (File No. 001-31899)].
Non-Competition and Non-Solicitation Agreement, between Michael J. Stevens and Whiting Petroleum Corporation
effective as of August 1, 2019 [Incorporated by reference to Exhibit 10.2 to Whiting Petroleum Corporation’s Current
Report on Form 8-K filed on July 16, 2019 (File No. 001-31899)].
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 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 Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
110
Exhibit
Number
(99)
(101)
Exhibit Description
Report of Cawley, Gillespie & Associates, Inc., Independent Petroleum Engineers relating to Total Proved Reserves,
dated February 7, 2020.
The following materials from Whiting Petroleum Corporation’s Annual Report on Form 10-K for the year ended
December 31, 2019 are filed herewith, formatted in iXBRL (Inline Extensible Business Reporting Language): (i) the
Consolidated Balance Sheets as of December 31, 2019 and 2018, (ii) the Consolidated Statements of Operations for the
Years Ended December 31, 2019, 2018 and 2017, (iii) the Consolidated Statements of Cash Flows for the Years Ended
December 31, 2019, 2018 and 2017, (iv) the Consolidated Statements of Equity for the Years Ended December 31,
2019, 2018 and 2017, and (v) Notes to Consolidated Financial Statements. The instance document does not appear in
the interactive data file because its XBRL tags are embedded within the iXBRL document.
(104)
Cover Page Interactive Data File (formatted as Inline XBRL) – The cover page interactive data file does not appear in
the interactive data file because its XBRL tags are embedded within the iXBRL document.
* A management contract or compensatory plan or arrangement.
111
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to
be signed on its behalf by the undersigned, thereunto duly authorized, on this 27th day of February, 2020.
SIGNATURES
WHITING PETROLEUM CORPORATION
By /s/ Bradley J. Holly
Bradley J. Holly
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
Title
Date
/s/ Bradley J. Holly
Bradley J. Holly
/s/ Correne S. Loeffler
Correne S. Loeffler
/s/ Sirikka R. Lohoefener
Sirikka R. Lohoefener
/s/ Thomas L. Aller
Thomas L. Aller
/s/ Lyne B. Andrich
Lyne B. Andrich
/s/ James E. Catlin
James E. Catlin
/s/ Philip E. Doty
Philip E. Doty
/s/ William N. Hahne
William N. Hahne
/s/ Michael G. Hutchison
Michael G. Hutchison
/s/ Carin S. Knickel
Carin S. Knickel
/s/ Michael B. Walen
Michael B. Walen
Chairman, President and Chief Executive
February 27, 2020
February 27, 2020
February 27, 2020
February 27, 2020
February 27, 2020
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Officer
(Principal Executive Officer)
Chief Financial Officer
(Principal Financial Officer)
Vice President and Controller
(Principal Accounting Officer)
Director
Director
Director
Director
Director
Director
Director
Director
112
C O R P O R AT E O F F I C E R S
BRADLEY J. HOLLY
Chairman, President and
Chief Executive Officer
CHARLES J. RIMER
Chief Operating Officer
TIMOTHY M. SULSER
Chief Strategy Officer
BRUCE R. DEBOER
Chief Administrative Officer,
General Counsel and Secretary
B OA R D O F D I R E CTO R S
BRADLEY J. HOLLY (Since 2017)
Chairman, President and
Chief Executive Officer
JAMES E. CATLIN 2 3 (Since 2014)
Lead Director
Past Executive Vice President and Director
CORRENE LOEFFLER
Chief Financial Officer
SHANE A. FROSS
Vice President, Operations
SIRIKKA R. LOHOEFENER
Vice President and Controller
ERIC K. HAGEN
Vice President, Corporate Affairs
CHRISTOPHER L. EDWARDS
Vice President, Human Resources
KEVIN A. KELLY
Vice President, Marketing and Midstream
RICK HATCHER
Vice President, Information Technology
J. BRAD MARVIN
Vice President, Business Development
M. SCOTT REGAN
Assistant Secretary and Deputy
General Counsel
LYNE B. ANDRICH 1 (Since 2019)
Past Executive Vice President and
Chief Operating Officer
CoBiz Financial Inc.
MICHAEL G. HUTCHINSON 1 (Since 2019)
Past Interim Chief Executive Officer
Westmoreland Coal Company
Certified Public Accountant
PHILIP E. DOTY 1 3 (Since 2010)
Nominating and Governance Committee
CARIN S. KNICKEL 2 4 (Since 2015)
Past Vice President
Kodiak Oil and Gas Corporation
Certified Public Accountant
ConocoPhillips
THOMAS L. ALLER 2 4 (Since 2003)
Retired President
Interstate Power and Light Company
an Alliant Energy Company
WILLIAM N. HAHNE 3 (Since 2007)
Past Chief Operating Officer
Petrohawk Energy Corporation
MICHAEL B. WALEN 3 4 (Since 2013)
Past Chief Operating Officer
Cabot Oil and Gas Corporation
1 Audit Committee 2 Compensation Committee 3 Nominating and Governance Committee 4 Sustainability Committee
INFORMATION UPDATES
Whiting’s quarterly financial results and other information
are available on our website at www.whiting.com
ANNUAL REPORT ON FORM 10-K
Upon request, the Company will provide, without charge,
copies of the 2019 Annual Report on Form 10-K as filed with
the Securities and Exchange Commission.
ANNUAL MEETING
Friday, May 1, 2020
9:00 A.M. (Mountain Time)
The 1700 Club
Wells Fargo Center
1700 Lincoln Street
Denver, Colorado 80203
CORPORATE OFFICES
Whiting Petroleum Corporation
1700 Lincoln Street, Suite 4700
Denver, Colorado 80203
Tel: 303.837.1661
Fax: 303.390.4293
www.whiting.com
INVESTOR RELATIONS
Securities analysts, investors and the financial media should contact:
Eric K. Hagen
Vice President, Corporate Affairs
Tel: 303.837.1661
STOCK EXCHANGE LISTING
New York Stock Exchange, trading symbol: WLL
TRANSFER AGENT
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.
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Deloitte & Touche LLP
1 7 0 0 L I N C O L N S T R E E T , S U I T E 4 7 0 0
D E N V E R , C O LO R A D O 8 0 2 0 3
W W W. W H I T I N G . C O M
N Y S E : W L L