CORE
Returns | Results | Responsibility
2017 Annual Report
OPERATING DATA
(as of December 31)
Proved Reserves
Crude oil and condensate (MMBbls)
Natural gas (Bcf)
NGLs (MMBbls)
Total Proved Reserves (MMBoe)
Annual Production
Crude oil (MMBbls)
Natural gas (Bcf)
NGLs (MMBbls)
Total Production (MMBoe)
Average Sales Price* & Select Expenses
Crude oil (per Bbl)
Natural gas (per Mcf)
NGLs (per Bbl)
‘17
‘16
‘15
155
1,154
106
453
12.9
71.7
7.0
31.8
118
834
84
341
8.7
51.7
4.8
22.2
99
661
64
273
7.0
33.3
2.8
15.4
$
$
$
48.45
2.21
18.59
$
$
$
39.96
1.77
11.80
$
$
$
40.14
2.04
10.72
Crude Oil Equivalent per Boe
$ 28.69
$ 22.43
$
24.64
Lease operating expenses per Boe
General and administrative expense per Boe
Production taxes per Boe
$
$
$
2.82
3.78
1.91
$
$
$
2.70
5.07
1.42
$
$
$
3.71
5.85
1.20
SELECTED FINANCIAL DATA
(in millions except per share data)
(as of December 31)
Statement of Operations
‘17
‘16
‘15
Crude oil, natural gas and NGLs sales
$
913.1
$
497.4
$
378.7
Commodity price risk management gain (loss), net
Total revenues
Net income (loss)
(3.9)
921.6
(127.5)
(125.7)
382.9
(245.9)
203.2
595.3
(68.3)
Net income (loss) per diluted share
$
(1.94)
$
(5.01)
$
(1.74)
Statement of Cash Flows
Net cash provided by operating activities
$
588.6
$
486.3
$
411.1
Capital expenditures
Acquisitions (cash portion)
Balance Sheet
Total assets
Long-term debt
Total stockholders equity
Total Debt-to-Book Capital
* Excludes net settlements on derivatives and transportation,
gathering and processing expense
742.3
15.6
440.3
1,073.7
604.7
-
$ 4,419.9
$ 4,485.8
$ 2,370.5
1,151.9
2,507.6
1,044.0
2,622.8
529.4
1,287.2
31%
28%
33%
SENIOR MANAGEMENT TEAM
BOARD OF DIRECTORS
Barton R. Brookman
President and Chief Executive Officer
Lance A. Lauck
Executive Vice President Corporate Development and Strategy
Scott J. Reasoner
Senior Vice President Chief Operating Officer
R. Scott Meyers
Senior Vice President Chief Financial Officer
Daniel W. Amidon
Senior Vice President General Counsel and Secretary
CORPORATE HEADQUARTERS
PDC Energy, Inc.
1775 Sherman Street
Suite 3000
Denver, Colorado 80203-4341
303.860.5800
www.pdce.com
REGIONAL HEADQUARTERS
PDC Energy, Inc.
120 Genesis Boulevard
Bridgeport, West Virginia 26330-9665
304.842.3597
STOCK EXCHANGE LISTING
NASDAQ: PDCE
2018 ANNUAL MEETING OF STOCKHOLDERS
The Annual Meeting of Stockholders will be held on May 30, 2018,
beginning at 9:15 a.m. MT. The meeting will be held at Denver
Financial Center at 1775 Sherman St., Denver, Colorado 80203.
INDEPENDENT RESERVE ENGINEERS
Ryder Scott Company, L.P. Houston, Texas
Netherland, Sewell & Associates, Inc. Dallas, Texas
INDEPENDENT AUDITORS
PricewaterhouseCoopers LLP, Denver
Jeffrey C. Swoveland
Chairman of the Board
Barton R. Brookman
Anthony J. Crisafio
Mark E. Ellis
Christina M. Ibrahim
Larry F. Mazza
Randy S. Nickerson
David C. Parke
FORM 10-K
Additional copies of the PDC Energy, Inc. Annual Report on Form 10-K for the
year ended December 31, 2017, as filed with the U.S. Securities and Exchange
Commission (SEC), may be obtained free of charge by writing to the Company’s
corporate headquarters, Attention: Corporate Secretary. Copies are also available
electronically on the Company’s website, www.pdce.com. While we recommend
you view our website, the information available on our website is not part of this
report and is not incorporated by reference.
SHAREHOLDER SERVICES
Broadridge Corporate Issuer Solutions, Inc.
P.O. Box 1342
Brentwood, NY 11717
www.shareholder.broadridge.com
shareholder@broadridge.com
877-830-4936
Contact Broadridge for information regarding change of address, registration of
shares, transfers or lost certificates, or for information about your shareholder
account.
ANNUAL REPORT DESIGN
Prism Group Marketing, Denver
FORWARD-LOOKING STATEMENTS
The information provided in this annual report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-
looking statements are based on management’s current expectations and beliefs, as well as a number of assumptions concerning future events. These statements are based
on certain assumptions and analyses made by management of the Company in light of its experience and its perception of historical trends, current conditions and expected
future developments as well as other factors it believes are appropriate in the circumstances. However, whether actual results and developments will conform with management’s
expectations and predictions is subject to a number of risks and uncertainties, general economic, market or business conditions; the opportunities (or lack thereof) that may be
presented to and pursued by the Company; changes in laws or regulations; and other factors, many of which are beyond the control of the Company. You are cautioned not to put
undue reliance on such forward-looking statements because actual results may vary materially from those expressed or implied, as more fully discussed in the safe harbor statements
found in the Company’s SEC fi lings, including, without limitation, the discussion under the heading “Note Regarding Forward-Looking Statements” and “Risk Factors” and elsewhere
in the Company’s most recent annual report on Form 10-K and in subsequent Form 10-Qs. All forward-looking statements are based on information available to management on
this date and the Company assumes no obligation to, and expressly disclaims any obligation to, update or revise any forward-looking statements, whether as a result of new
information, future events or otherwise.
The Company has a Code of Business Conduct and Ethics (the “Code of Conduct”) that applies to all Directors, officers, employees, agents, consultants and representatives of the
Company, which is reviewed at least annually by the Nominating and Governance Committee. The Company’s principal executive officer, principal financial officer and principal
accounting officer are subject to additional specific provisions under the Code of Conduct. The Code of Conduct can be viewed on the Company’s website at www.pdce.com.
In the event the Board approves an amendment to or a waiver of any provisions of the Code of Conduct, the Company will disclose the information on its website.
Denver
Headquarters
CORE WATTENBERG
~100,000 net acres
CORE DELAWARE
~60,000 net acres
NASDAQ: PDCE
PDC’s strategy is simple: increase shareholder value
through the growth of reserves, production and per
share cash flow and earnings, while focusing on safe
and efficient operations, environmental stewardship
and community outreach.
1
VALUE ADDED PRODUCTION
DEAR SHAREHOLDERS
MMBoe
31.8
22.2
15.4
9.3
2014 2015 2016 2017
RESILIENT BALANCE SHEET
Debt to EBITDAX
2.1X
1.1X
ACQUISITION
RELATED
FINANCING
1.9X
1.4X
1.0X
2014 2015 2016 2017
STRONG PROVED RESERVES GROWTH
31.8
MMBoe
453
341
273
250
2014 2015 2016 2017
LEASE OPERATING EXPENSE ($/BOE)
2
Let us begin by sincerely thanking all of our loyal investors
and dedicated employees. Our exceptional staff is the
35
driving force behind the implementation and execution
30
of our long-term strategy. At PDC, we are steadfast in
25
our pursuit of value-add returns for our stakeholders
20
by focusing on capital efficiency, financial discipline
15
and technological innovation. We feel fortunate we
10
can achieve these strategic goals while still delivering
0
5
substantial growth.
In the face of turbulent industry change, our ability to remain
committed to our core strategy has positioned us for ongoing
success. Today, the company stands strong. Our technical
capabilities within two premier U.S. onshore basins enables
2.0
us to provide exceptional returns. These substantial returns
on capital are the foundation of an emerging era of enhanced
1.5
financial strength for PDC.
1.0
As we navigate this new era, our corporate culture and the
0.5
health and safety of our employees are paramount in achieving
our strategic goals. At PDC, we remain devoted to responsible
0.0
and sustainable development while operating under some of the
most stringent regulatory mandates in the country. Through our
proactive and sincere investment of both time and resources,
we take great pride in the relationships we’ve established with
our communities.
Our people are our strongest asset.
At PDC, we attract and retain top-industry talent by fostering a
500
culture of integrity, innovation and respect. We also work hard
to incorporate these core values at all levels of the organization,
400
including our e(cid:410)orts to strengthen and diversify our (cid:37)oard of
300
Directors by adding three new board members this year. One of
200
our key objectives is to ensure PDC is as respected and progressive
as possible in today’s ever changing corporate climate.
100
0
In 2017, we focused on the integration of our Delaware
assets and the ongoing execution of our capital program.
Our financial fortitude is highlighted by a substantial
operations, we turned-in-line nearly 20 wells with initial
liquidity position and the improvement of our year-end
results largely exceeding our expectations, while also
leverage ratio to 1.9 times.
improving our drill times by nearly 40 percent. Our 2017
program also helped us further define approximately
Operationally, it was a pivotal year as we enhanced our
450 future drilling locations. At our current pace these
core positions in the Wattenberg Field and unbundled the
high rate-of-return projects offer more than 15 years
tremendous resource potential in the Delaware Basin. We
of inventory.
are also excited about the emerging value of our Delaware
Basin midstream assets.
Entering 2018, we believe PDC is uniquely positioned
to deliver tremendous value. Once again, we anticipate
Through the continued success of our extended-reach
robust production growth while improving both our capital
lateral drilling program, we were able to increase our
efficiency and balance sheet.
proved reserves 33 percent to over 450 million barrels
of oil equivalent while efficiently growing our production
by more than 40 percent to 31.8 million barrels of
oil equivalent.
In the Wattenberg, we reaped the benefits of our
consolidated Kersey Area position; namely, the ability
to drill
longer-lateral wells with
increased working
interests while capturing operational synergies and
improved margins.
As a result of our successful efforts in Kersey,
we made the strategic decision to further
consolidate our Wattenberg position.
With the completion of two acreage trades and our
acquisition of approximately 7,400 net acres, we
successfully formed our Plains and Prairie Areas.
When combined, these three acreage positions offer
an expansive drilling inventory of approximately 1,500
highly-economic projects which serve as the foundation
for our future development.
In the Delaware, we built an incredibly talented team
capable of developing one of the more geologically
complex basins in the U.S. Our goal was to both de-risk
our asset’s potential value through strong well results
and to increase our understanding of the play through
delineation and scientific testing. By all accounts, this
integration effort was a success. In our first year of
Our expectation of positive cash flow in the
second half of the year is a testament to the
strength of our assets and organization.
We owe much of our ongoing success to the hard
work and integrity of our dedicated employees and
are grateful
to be
associated with
such
an
extraordinary team.
Thank you for your continued confidence and support of
PDC Energy.
BARTON R. BROOKMAN
BARTON R. BROOKMAN
President and
Chief Executive Officer
JEFFREY C. SWOVELAND
JEFFREY C. SWOVELAND
Non-Executive
Chairman of the Board
3
PRARIE AREA
OUTER CORE
OUTER CORE
MIDDLE CORE
MIDDLE CORE
KERSEY AREA
INNER CORE
INNER CORE
PLAINS AREA
Weld County
PRODUCTION (Boe/d)
73,465
PRODUCTION (Boe/d)
57,225
38,990
73,465
57,225
38,990
2015 2016 2017
2015 2016 2017
WATTENBERG FIELD
The Wattenberg Field, known for
its prolific Niobrara and Codell
formations, is located in Weld County, Colorado, in the greater Denver-
Julesburg (DJ) Basin. With nearly two decades of PDC drilling activity
and approximately 100,000 net acres, the Wattenberg Field represents
the Company’s largest asset in terms of production, reserves and activity,
while offering some of the most consistent results and efficient drilling in
the U.S. onshore.
AVERAGE LATERAL LENGTH (TIL*)
* turn-in-line
Strong execution in 2017, with production volumes of nearly 27 MMBoe – a
28 percent increase over 2016 – lead to year-end 2017 proved reserves in
7,300
Wattenberg of over 350 MMBoe, representing a 15 percent increase over
AVERAGE LATERAL LENGTH (TIL*)
5,650
year-end 2016.
4,943
Operations in 2017 were primarily focused in the Company’s Kersey area –
a consolidated position of an estimated 30,000 net acres featuring some
of PDC’s highest rate-of-return projects. The blocky nature of the Kersey
Area acreage proved beneficial in the continued advancement of drilling
7,300
5,650
4,943
2015 2016 2017
2015 2016 2017
and completion efficiencies which
included monobore drilling, zipper
completions and extended-reach
lateral wells. The consolidated
acreage and ability to centralize
facilities also drove operating costs
lower. In 2017 PDC once again
improved drill times in the basin,
this time, by an estimated 15 percent per
Net Acres
~100,000
that are expected to provide additional
production in 2018. The Prairie Area,
after
the
acquisition,
contains
approximately 29,000 net acres and
an inventory of over 650 locations
that typically have a higher percent
of crude oil than wells in the Kersey
and Plains areas. Recent completion
design enhancements are expected to
well. This allowed the Company to reduce
improve well results in the area, where PDC
its operated rig count from four to three, while
has not been active for several years.
still drilling over 150 gross operated wells, and
turning-in-line 130 wells with an average lateral length
These strategic moves and the newly formed areas
of approximately 7,300 feet.
are expected to have multiple benefits, including a
portion that were realized in the Company’s year-end
As a result of successful execution
in
2017 drilling inventory. That inventory was
Kersey, several business development
initiatives were undertaken with the
goal of further consolidating our
Wattenberg position.
The Plains Area resulted from
combining
PDC’s
existing
leasehold with
the successful
execution of two strategic acreage
trades.
The Plains Area contains
of approximately 17,500 net acres and
Proved Reserves
350.8
MMBoe
equal in lateral feet to PDC’s year-end
2016 lateral feet inventory, despite
drilling approximately one million
lateral feet in 2017. Additionally, the
average lateral length and average
working interest in the Company’s
Wattenberg
inventory
increased
between the two years.
PDC believes that 2018 has the makings
of a transformative year as the Company’s
includes nearly 20 percent of the Company’s currently
primary third-party midstream natural gas processor
identified (cid:58)attenberg inventory. (cid:55)his area is expected to
expects to increase processing capacity on its system
be a major focus area for the Company in the near future.
by nearly 25 percent beginning in the second half of
the year. The Company’s 2018 plans are once again
The Prairie Area was created with a $186 million bolt-
focused on long-lateral development of the Kersey
on acquisition of approximately 7,400 net acres
area as half of the planned turn-in-lines this year
and 1,000 Boe per day of production.
are expected to have lateral lengths of
PDC
identified approximately 220
new gross
locations as a result
of
this acquisition, while also
increasing the lateral length and/
or working interests of its existing
locations. At the time of closing in
January 2018, 24 operated drilled
uncompleted wells were
included
Gross
Drilling Locations
~1,500
6,900 feet or more. The Company also
plans to test a ‘completion recipe’
designed for the oilier Prairie Area
on multiple wells. It is through
technological advancements such
as these that PDC plans to continue
efficiently developing this field for
years to come.
5
WESTERN CENTRAL
Loving County
NORTH CENTRAL
EASTERN
Culberson County
Reeves County
BLOCK 4
PRODUCTION (Boe/d)
16,030
PRODUCTION (Boe/d)
12,845
10,047
6,810
16,030
12,845
DELAWARE BASIN
10,047
1Q17 2Q17 3Q17 4Q17
6,810
1Q17 2Q17 3Q17 4Q17
AVERAGE DRILLING FEET PER DAY
651
AVERAGE DRILLING FEET PER DAY
558
471
464
651
PDC’s Delaware Basin team had a banner year in 2017 as it grew produc-
tion volumes 135 percent from the first quarter to the fourth quarter.
Considering 2017 marked the first year of ownership, the production
increase was an outstanding accomplishment. The team also made great
strides in both an operational and geologic perspective. Located in West
Texas and known for approximately 3,000 feet of prospective pay zones
from the top of the Bone Spring and Avalon Shale, to the base of the
Wolfcamp formations, the Delaware Basin has become one of the hottest
plays in the country over the past several years.
PDC’s position at year-end 2017 included approximately 60,000 net acres
in Reeves and Culberson Counties, Texas, that the Company divided into
three areas: Eastern, Central and Western. Through successful drilling
and completion operations, as well as multiple geologic initiatives,
including drilling and logging pilot holes to better correlate 3D-seismic
558
data, two primary near-term focus areas have been identified within
471
464
1Q17 2Q17 3Q17 4Q17
1Q17 2Q17 3Q17 4Q17
the oilier Eastern and Central Areas.
PDC has
identified an estimated
450 gross drilling locations within
these two areas with an average
equivalent lateral length of 7,500
feet per well. At the Company’s
current drilling pace, this implies
an inventory life of 15 – 18 years.
Additionally, these estimates do not
Net Acres
~60,000
cost savings, which coupled with the
Company’s
enhanced
completion
design, delivered multiple highly-
productive,
liquid-rich wells with
strong rates-of-return.
In terms of downspacing, in 2018 PDC
plans a six-well test on a half-section in
the Wolfcamp A. Successful results would
include the potential for additional locations
support the viability of 12-wells per section in
in other zones, including the Wolfcamp C in certain
the Eastern area Wolfcamp A and provide a strong step
areas, and Bone Spring horizons. Depending on lateral
towards validating the Company’s inventory assumption.
length, wells in these areas are expected to deliver
(cid:36)dditional 201(cid:27) tests
include the Company(cid:393)s first
EURs between 1.0 and 2.6 MMBoe, with a strong oil
operated Wolfcamp C well in the Eastern Area. This test
component of approximately 40 to 70 percent.
is expected to be completed mid-year and will play a
In 2017, PDC operated at a three-rig
pace for the majority of the year
while drilling and turning-in-line
26 and 18 wells, respectively.
The geographic
locations of
these wells contributed to the
Company’s near-term focus areas,
while also driving strong growth in
both proved reserves and production.
Proved reserves increased approximately
Proved Reserves
97.9
MMBoe
large part in potential inventory expansion, as
the Company does not currently include
any Wolfcamp C locations in this area.
In addition to the 25 – 30 total
wells PDC plans to spud and turn-
in-line in 2018, there is also an
increased focus on the development
of its midstream assets. Similar to
2017, investments are being made in
2018 towards the expansion of natural
200 percent year-over-year to nearly 100
gas and produced water gathering lines, as
MMBoe, while quarterly production more than doubled
well as construction of fresh water supply and salt-
between the first and fourth quarters of 2017.
water disposal wells. As a new initiative in 2018, PDC
plans to implement a water recycling program aimed
In a basin as complex as the Delaware, increased focus
at reducing costs and improving sustainability in the
is placed on a company’s ability to climb the learning
area. Additionally, the Company is making an initial
curve
through drilling and completion
investment in the construction of a crude oil
enhancements
and
downspacing
initiatives. From a drilling perspective,
PDC was able to increase its average
feet per day nearly 40 percent
during the year. This reduced time
to drill wells, led directly to per-well
Gross
Drilling Locations*
~450
gathering system
in
its Eastern Area.
Midstream assets are a key area for
the next several years as they carry
tremendous potential value that has
yet to be completely unlocked.
*Some locations subject to a higher degree of uncertainty.
7
DID YOU KNOW?
Women account for roughly
half of Denver headquarters
work force
PDC added 160+ new hires in 2017
PDC donated time or dollars to
130+ organizations in 2017
COMMITMENT TO COMMUNITY
As PDC Energy executes on its long-term business plan, we
recognize our responsibility to both individual stakeholders
and the surrounding community to create mutually beneficial
relationships that endure.
It is part of PDC’s mission to invest time, effort and charitable
dollars in the communities in which we live and operate.
ENERGIZING OUR COMMUNITY DAY:
2012
2012
The year PDC began an organized effort for our
employees and their families to participate in an
annual day of volunteering called Energizing Our
Community day.
85
85
The percentage of PDC employees who
participated in Energizing Our Community day
in 2017.
2,000
2,000
The number of hours that PDC
employees volunteered on Energizing
Our Community day.
31
31
Non-profit organizations across the country were
directly helped through PDC volunteer efforts.
SUSTAINABLE OPERATIONS:
136
136
Trucks taken off the road per day in the Delaware,
by transporting produced water via pipe.
Infrared cameras, using state-of-the-art technology
designed to detect emissions not visible to the
naked eye.
6
6
140,000
140,000
Audio, Visual and Olfactory (AVO)
inspections completed in 2017.
9
OPERATIONAL STEWARDSHIP
Environmental Health & Safety (EHS) is an
integral part of PDC’s operations, business
planning, development and decision-making
processes. Responsible EHS performance is a key
component to the success of the Company. PDC’s
EHS culture stresses personal accountability for all
employees, contractors and others working for PDC
or on PDC properties. PDC’s EHS policies promote
knowledge and understanding of laws, regulations,
industry best practices and standards. With this
knowledge, employees have the framework to maintain
a safe and healthy workplace and environment.
PDC works cooperatively with regulatory agencies,
communities,
industry
representatives, customers
and suppliers to stay informed and current on EHS
requirements, initiatives and activities. The Company
strives
to
implement best operating practices,
environmental awareness, on-going
training and
enhanced communication including:
• Multi-well pad sites to reduce surface footprint
•
Emissions reduction team equipped with
Infrared cameras
• Recycling of expired or outdated equipment
• Wildlife protection
• Contractor training and support
• Continuing education and training
for PDC employees
•
Emergency response training for
local first responders
• Solar panels monitor and control remote
well sites
• 24-hour hotline for site emergencies
and concerns
• 24-hour on-call EHS professionals
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, 2017
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 001-37419
PDC ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware
(State of incorporation)
95-2636730
(I.R.S. Employer Identification No.)
1775 Sherman Street, Suite 3000
Denver, Colorado 80203
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code: (303) 860-5800
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock, par value $0.01 per share
Name of each exchange on which registered
NASDAQ Global Select Market
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 Section 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 and posted on its corporate Website, if any, every Interactive Data
File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or
for such shorter period that the registrant was required to submit and post such files). Yes
No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained
herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference
in Part III of this Form 10-K or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Non-accelerated filer
(Do not check if a smaller reporting company)
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 Act). Yes
No
The aggregate market value of our common stock held by non-affiliates on June 30, 2017 was $2.8 billion (based on the closing price of $43.11
per share as of the last business day of the fiscal quarter ending June 30, 2017).
As of February 15, 2018, there were 65,965,374 shares of our common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
We hereby incorporate by reference into this document the information required by Part III of this Form, which will appear in our definitive
proxy statement to be filed pursuant to Regulation 14A for our 2018 Annual Meeting of Stockholders.
Items 1. and 2. Business and Properties
Item 1A.
Item 1B.
Item 3.
Item 4.
Risk Factors
Unresolved Staff Comments
Legal Proceedings
Mine Safety Disclosures
PDC ENERGY, INC.
2017 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
PART I
PART II
Item 5.
Item 6.
Item 7.
Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Selected Financial Data
Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
PART III
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Certain Relationships and Related Transactions, and Director Independence
Principal Accounting Fees and Services
PART IV
Item15.
Item 16.
Exhibits, Financial Statement Schedules
Form 10-K Summary
Signatures
Glossary of Units of Measurements and Industry Terms
Page
2
22
38
38
38
39
41
42
66
70
128
128
129
130
130
130
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130
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112
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135
REFERENCES TO THE REGISTRANT
PART I
Unless the context otherwise requires, references in this report to "PDC," the "Company," "we," "us," "our," or "ours"
refer to the registrant, PDC Energy, Inc., our wholly-owned subsidiaries consolidated for the purposes of its financial
statements, including our proportionate share of the financial position, results of operations, cash flows and operating activities
of our affiliated partnerships.
GLOSSARY OF UNITS OF MEASUREMENTS AND INDUSTRY TERMS
Units of measurements and industry terms are defined in the Glossary of Units of Measurements and Industry Terms,
included at the end of this report.
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933
("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding our business, financial
condition, results of operations, and prospects. All statements other than statements of historical facts included in this report
are "forward-looking statements" within the meaning of the safe harbor provisions of the United States ("U.S.") Private
Securities Litigation Reform Act of 1995. Words such as expect, anticipate, intend, plan, believe, seek, estimate and similar
expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking
statements include, among other things, statements regarding future: reserves, production, costs, cash flows and earnings;
drilling locations and zones and growth opportunities; capital expenditures and projects, including expected lateral lengths of
wells, drill times and number of rigs employed; rates of return; operational enhancements and efficiencies; management of
lease expiration issues; financial ratios; our anticipated sale of our Utica Shale assets; certain accounting and tax change
impacts; midstream capacity and related curtailments; and the closing of pending, and the nature of future, transactions.
The above statements are not the exclusive means of identifying forward-looking statements herein. Although
forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts
and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become
subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this report or
accompanying materials, we may use the term “projection” or similar terms or expressions, or indicate that we have “modeled”
certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our
business or the industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further
in the future, they are subject to increased levels of uncertainty.
Important factors that could cause actual results to differ materially from the forward-looking statements include, but
are not limited to:
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changes in worldwide production volumes and demand, including economic conditions that might impact demand
and prices for products we produce;
volatility of commodity prices for crude oil, natural gas, and natural gas liquids ("NGLs") and the risk of an
extended period of depressed prices;
reductions in the borrowing base under our revolving credit facility;
impact of governmental policies and/or regulations, including changes in environmental and other laws, the
interpretation and enforcement related to those laws and regulations, liabilities arising thereunder, and the costs to
comply with those laws and regulations;
declines in the value of our crude oil, natural gas, and NGLs properties resulting in further impairments;
changes in estimates of proved reserves;
inaccuracy of estimated reserves and production rates;
production decline rates from our wells being greater than expected;
timing and extent of our success in discovering, acquiring, developing, and producing reserves;
availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process
and transport our production and the impact of these facilities and regional capacity on the prices we receive for
our production;
timing and receipt of necessary regulatory permits;
risks incidental to the drilling and operation of crude oil and natural gas wells;
losses from our gas marketing business exceeding our expectations;
1
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difficulties in integrating our operations as a result of any significant acquisitions and acreage exchanges;
increases or changes in expenses;
availability of supplies, materials, contractors, and services that may delay the drilling or completion of our wells;
potential losses of acreage or zones due to partial or complete lease expirations or otherwise;
increases or adverse changes in construction costs and procurement costs associated with future build out of mid-
stream related assets;
future cash flows, liquidity, and financial condition;
possibility that the sale of the Utica Shale properties will not close as expected;
competition within the oil and gas industry;
availability and cost of capital;
our success in marketing crude oil, natural gas, and NGLs;
effect of crude oil and natural gas derivatives activities;
impact of environmental events, governmental and other third-party responses to such events, and our ability to
insure adequately against such events;
cost of pending or future litigation;
effect that acquisitions we may pursue have on our capital requirements;
our ability to retain or attract senior management and key technical employees; and
success of strategic plans, expectations and objectives for our future operations.
Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those
under Item 1A, Risk Factors, made in this report and our other filings with the U.S. Securities and Exchange Commission
("SEC") for further information on risks and uncertainties that could affect our business, financial condition, results of
operations and cash flows. We caution you not to place undue reliance on forward-looking statements, which speak only as of
the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any
event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence
of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement.
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
The Company
We are a domestic independent exploration and production company that acquires, explores, and develops properties
for the production of crude oil, natural gas, and NGLs. Our primary operations are located in the Wattenberg Field in Colorado
and the Delaware Basin in Texas. Our operations in the Wattenberg Field are focused on the Niobrara and Codell formations
and our Delaware Basin operations are currently focused on the Wolfcamp zones. We also have operations in the Utica Shale in
Southeastern Ohio; however, in February 2018, we entered into a definitive purchase and sale agreement ("PSA") for the sale of
these properties for net cash proceeds of approximately $40.0 million, subject to certain customary closing adjustments. This
transaction is expected to close in the first quarter of 2018.
As of December 31, 2017, we own an interest in approximately 2,800 gross (2,300 net) productive wells, of which
approximately 32 percent are horizontal. We operate 87 percent of the wells in which we have an interest. We produced 31.8
MMBoe in 2017, a 44 percent increase compared to 2016, including 4.2 MMBoe from the Delaware Basin assets that we
acquired in December 2016. For the month ended December 31, 2017, we maintained an average production rate of 97 MBoe
per day, representing a 33 percent increase from December 2016. We were able to achieve this strong growth rate while
maintaining a robust liquidity position, comprised of cash and cash equivalents and available capacity under our revolving
credit facility totaling $880.7 million as of December 31, 2017. Our leverage ratio as of December 31, 2017, as defined in our
revolving credit facility agreement, was 1.9 to 1.0. As of December 31, 2017, we had 452.9 MMBoe of proved reserves, 32
percent of which are proved developed reserves. Approximately 58 percent of our reserves at December 31, 2017 are liquids,
which includes crude oil and NGLs. Our 452.9 MMBoe of total proved reserves as of December 31, 2017, represented an
increase of 111.5 MMBoe, or 33 percent, relative to December 31, 2016. The additions to our proved reserves were primarily a
result of extending the average lateral length of newly-drilled and expected future wells, combined with an increase in our
working interest ownership in wells in areas with established reserves, and the addition of proved undeveloped locations in the
Delaware Basin.
On January 5, 2018, we closed an acquisition of properties from Bayswater Exploration and Production, LLC and
certain related parties in the core Wattenberg Field (the "Bayswater Acquisition") for approximately $186 million, subject to
certain customary post-closing adjustments. In addition to the approximately $186 million of cash paid at closing, we invested
approximately $15 million during 2017 to complete certain drilled uncompleted wells ("DUCs") acquired in the transaction.
2
Our Strengths
• Multi-year project inventory in premier crude oil, natural gas, and NGL plays. We have a significant operational
presence in two premier U.S. onshore basins, the Wattenberg Field in Weld County, Colorado, and the Delaware Basin
in Reeves and Culberson Counties, Texas. The company has identified a significant inventory of horizontal drilling
locations in each basin which will allow us to continue to grow our proved reserves and production at attractive rates
of return based on our current internal long-term commodity price projections and our current expected cost structure.
Our 2018 drilling and completion operations are expected to focus on the Kersey area of the Wattenberg Field and in
our oilier eastern and north central areas of the Delaware Basin, where we expect to deliver our strongest economic
results.
In the Wattenberg Field, we have identified a gross operated inventory of approximately 1,500 horizontal drilling
locations, including locations acquired in the Bayswater Acquisition, that consist of an average lateral length of
approximately 6,300 feet per well. Our Wattenberg Field horizontal drilling locations have been substantially de-
risked through multiple years of successful development from the field. In the Delaware Basin, we have identified a
gross operated inventory of approximately 450 horizontal Wolfcamp drilling locations, primarily within our oilier
eastern and north central focus areas, that consist of an average lateral length of approximately 7,500 feet per well.
Some of these 450 locations are subject to a higher degree of uncertainty as they reflect assumptions primarily related
to future downspacing that we are either in the process of testing, or have not yet tested. Our other Delaware Basin
leaseholds that are not currently in our primary focus area contain an estimated 240 additional potential horizontal
Wolfcamp drilling locations that typically have a higher gas to oil ratio, contain less contiguous acreage for long
lateral development, or may require additional technical assessments. We believe that our inventory in the Delaware
Basin may increase over time, depending upon, among other variables, successful trades to consolidate leaseholds,
additional exploration and development activity in other potential zones, service cost efficiencies, and improved
commodity and netback pricing.
•
Strong liquidity position. As of December 31, 2017, we had a total liquidity position of $880.7 million, comprised of
$180.7 million of cash and cash equivalents and $700.0 million available for borrowing under our revolving credit
facility. In November 2017, we issued $600 million principal amount of 5.75 percent unsecured senior notes due in
2026 (the "2026 Senior Notes"). The net proceeds from the offering were used to redeem our $500 million 7.75
percent senior notes due in 2022 (the "2022 Senior Notes"), fund a portion of the Bayswater Acquisition, which closed
in early January 2018, and for general corporate purposes. If the Bayswater Acquisition had closed in December 2017,
our liquidity position as of December 31, 2017 would have been approximately $700 million. We intend to continue
to manage our liquidity position through investment in projects with attractive rates of return, protection of cash flows
on a portion of our anticipated sales through the use of an active commodity derivative program, and access to capital
markets from time to time.
• Balanced and diversified portfolio across two premier U.S. onshore basins. Having drilling opportunities in both the
Wattenberg Field and the Delaware Basin allows us to allocate capital between the two basins to diversify our risk.
We believe this will improve overall economic results and drive our future production and reserve growth.
Additionally, we believe the geographical diversity of our portfolio aids in the mitigation of risks associated with a
single dominant producing area, as each basin has its own operating and competitive dynamic in terms of commodity
price markets, service costs, takeaway capacity, and regulatory and political considerations.
•
Significant operational control in our core areas. We have, and expect to continue to have, a substantial degree of
operational control over our properties. As a result of successfully executing our strategy of acquiring and
consolidating largely concentrated acreage positions with high working interests, we operate and manage
approximately 87 percent of all wells in which we have an interest across all of our operating basins. Our control
allows us to manage our drilling, production, operating and administrative costs, and to leverage our technical
expertise in our core operating areas. Our leaseholds that are held by production further enhance our operational
control by providing us flexibility in selecting drilling locations based upon various operational criteria.
In the Wattenberg Field, our operational control is attributable to our high working interest leasehold and large
contiguous acreage blocks, which have been significantly enhanced as a result of our 2016 and 2017 acreage
exchanges and the Bayswater Acquisition, and because substantially all of our Wattenberg Field acreage is held by
production. We remain flexible in terms of rig activity and capital deployment due to short-term rig contracts and we
are confident in our ability to manage our acreage in the Wattenberg Field in order to maintain our current level of
operational control. As a result, we can adjust our drilling plans if commodity prices deteriorate in order to manage
cash flows from operations relative to cash flows from investing activities.
3
In the Delaware Basin, our average working interest in our properties that we operate is approximately 90 percent. We
own and operate certain midstream assets in the Delaware Basin and believe this will allow for timely system
expansion, well connections, fresh water supply for completion operations, and produced water disposal. Our
leasehold in the Delaware Basin requires a more active drilling program and we have less flexibility than we do in the
Wattenberg Field, in terms of managing lease expiration issues. In some cases, continuous operations will be required
to maintain the underlying leasehold in the Delaware Basin. However, with our high percentage of operated leasehold
in the area, we expect to have adequate control over the location and pace of our development to manage lease
expirations and meet our drilling obligations in the central and eastern parts of the basin. See Item 1A. Risk Factors -
Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly
competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease
renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.
• Utilizing technology to focus on efficiency. In the Wattenberg Field, we have a proven track record of continuing
improvement in both costs and productivity of our existing operations. Our efficiencies have historically been driven
by a focus on the use of multi-well pad drilling, extended-reach lateral well development, increased fracture
stimulation stage density, enhanced fracture stimulation completion design, and improved drilling efficiencies. In
2017, approximately 65 percent of our horizontal well spuds were mid- or extended-reach laterals that ranged from
approximately 6,000 to 10,000 horizontal feet in length. We also use a mono-bore drilling design to reduce drill times
and well costs. Through the combination of these techniques, our drilling team has improved our drilling efficiencies
with average drill results increasing to approximately 2,700 feet drilled per day in 2017 from approximately 2,200 feet
drilled per day in 2016.
•
Strong environmental, health and safety compliance programs, and community outreach. We have focused on
establishing effective environmental, health and safety programs that are intended to promote safe working practices
for our employees and contractors and to help earn the trust and respect of land owners, regulatory agencies, and
public officials. This is an important part of our strategy and in competing in today’s intensive regulatory and public
debate climate. We are also dedicated to being an active and contributing member of the communities in which we
operate. We share our success with these communities in various ways, including charitable giving and community
event sponsorships.
• Commodity derivative program. Our active use of commodity derivative instruments to protect our investment
returns and cash flows was particularly important through the recent commodity price downturns. We have continued
this program and entered into commodity derivative instruments to mitigate a portion of our short-term future
exposure to commodity price fluctuations, including fixed-price swaps, crude oil and natural gas collars, basis swaps,
and rollfactor swap contracts. While our commodity derivative program limits the upside benefits we may otherwise
receive during periods of higher commodity prices, the program helps protect a portion of our cash flows, borrowing
base, and liquidity during periods of depressed commodity prices. We strive to scale our overall hedging position to
be appropriate relative to our current and expected level of indebtedness and consistent with our goals of preserving
balance sheet strength and substantial liquidity, as well as our internal price view.
As of December 31, 2017, we had commodity derivatives positions covering approximately 11.9 MMBbls and 6.6
MMBbls of crude oil production for 2018 and 2019, respectively. As of the same date, we had hedged approximately
56.5 Bcf of natural gas and 1.1 MMBbls of propane for 2018. The details of these transactions are described in Item
7a. - Quantitative and Qualitative Disclosures About Market Risk.
•
Strong management team and operational capabilities. We have strong and stable management, led by our executive
management team. Each member of the team has between 10 and 30 years of experience in the energy and natural
resource industry. This experience collectively spans expertise in land, reservoir analysis, operations, accounting,
strategy, and general operations, and has helped us continue our growth through periods of commodity price pressure
and cost inflation, and other challenging environments.
4
Business Strategy
Our long-term business strategy focuses on generating stockholder value through the acquisition, exploration, and
development of crude oil and natural gas properties. We are focused on the growth of our reserves, production, and cash flows
through organic exploration and development of our existing and acquired leasehold through horizontal drilling. Our
operational focus is concentrated within two basins. We pursue various midstream, marketing, and cost reduction initiatives
designed to increase our per unit operating margins, while maintaining a disciplined financial strategy focused on providing
sufficient liquidity and balance sheet strength to execute our business strategy.
We focus on horizontal development drilling programs in resource plays that offer repeatable results and the potential
for attractive returns on investment in a range of commodity price environments. Our inventory of drilling locations supports
our planned organic growth over the next several years. We expect our drilling and completion activity to drive increases in
proved reserves, production, and cash flows. In addition to development drilling, we routinely review acquisition and acreage
swap opportunities in our core areas of operations. We believe we can extract additional value from such transactions through
production optimization opportunities and increases in our working interests in our development drilling locations afforded by
more concentrated acreage positions. As a result, once we have established a significant presence in an area, the use of bolt-on
acquisitions and acreage exchanges can potentially provide synergies that result in additional economies of scale. We also
pursue a limited and disciplined exploration program with the goal of replenishing our portfolio with new exploration projects
capable of positioning us for significant production and reserve growth in future years.
In 2017, we completed two significant acreage exchanges that consolidated certain acreage positions in the core area
of the Wattenberg Field, creating two development areas that we refer to as Prairie and Plains. Both transactions involved the
exchange of leasehold acreage with a limited number of wells that were in the process of being drilled and completed. Upon
closing the transactions, we received an aggregate of approximately 15,900 net acres in exchange for an aggregate of
approximately 16,200 net acres. The difference in net acres is primarily due to variances in working and net revenue interests
and in midstream contracts.
As referenced above, we closed the Bayswater Acquisition in January 2018, acquiring approximately 7,400 net acres,
24 operated horizontal wells that were either DUCs or in-process wells at the time of closing and an estimated 220 gross
drilling locations at the time of closing.
Development drilling
The following map presents the general locations of our development and production activities as of December 31, 2017:
(1) In February 2018, we entered into a PSA to sell the Utica Shale properties.
5
Our leasehold interests cover properties with developed and undeveloped crude oil, natural gas, and NGLs resources.
We own approximately 2,800 gross (2,300 net) wells in our two primary operating basins. Our 2018 capital investment
program, which contemplates expenditures of between $850 million and $920 million, is primarily focused on continued
execution in the Wattenberg Field and Delaware Basin using three drilling rigs and one completion crew in each basin
throughout the year.
Based on our current production forecast for 2018 and assuming an average $57.50 New York Mercantile Exchange
("NYMEX") crude oil price for the year and a $3.00 NYMEX natural gas price, we expect 2018 capital investments to exceed
our 2018 cash flows from operations by approximately less than $90 million. We anticipate that the proceeds received from the
sale of our Utica Shale assets and a midstream dedication agreement (see the footnote titled Subsequent Events to the
consolidated financial statements included elsewhere in this report), will fund approximately two-thirds of this outspend. We
expect this outspend to occur during the first half of 2018, with cash flows exceeding capital investment during the second half
of the year. Our leverage ratio, as defined in our revolving credit facility agreement, is expected to decrease by the end of 2018
based on production and operational cash flow growth. However, a significant deterioration in commodity prices could
negatively impact our results of operations, financial condition, and future development plans. We may increase or decrease
our 2018 capital investment program during the year as a result of, among other things, changes in commodity prices or our
internal long-term outlook for commodity prices, requirements to hold acreage, the cost of services for drilling and well
completion activities, drilling results, changes in our borrowing capacity, a significant change in cash flows, regulatory issues,
requirements to maintain continuous activity on leaseholds or acquisition and/or divestiture opportunities. If such changes
result in our election to deploy additional capital, amounts invested may further exceed our cash flow from operations.
Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays in the core Wattenberg Field, which is
further delineated between the Kersey, Prairie and Plains development areas. We plan to drill standard-reach lateral (“SRL”),
mid-reach lateral (“MRL”), and extended-reach lateral (“XRL”) wells in 2018, the majority of which will be in the Kersey area
of the field. Wells in the Wattenberg Field typically have productive horizons at depths of approximately 6,500 to 7,500 feet
below the surface. In 2018, we anticipate spudding and turning-in-line between approximately 135 to 150 operated wells, as
outlined below:
Estimated average lateral length (in feet)
Expected drilling days (spud-to-spud)
Estimated percentage of 2018 wells spud
Estimated percentage of 2018 wells turned-in-line
Estimated cost per well (in millions)
SRL
4,200
6
25%
50%
$2.6
MRL
6,900
8
45%
35%
$3.5
XRL
9,500
10
30%
15%
$4.4
Our 2018 capital investment program for the Wattenberg Field is approximately $470 million to $500 million, of
which approximately 90 percent is expected to be invested in operated drilling and completion activity. The remainder of the
Wattenberg Field capital investment program is expected to be used for non-operated drilling, land, and miscellaneous
workover and capital projects.
6
The following map presents the general locations of our development areas in the Niobrara and Codell plays of the
Wattenberg Field as of December 31, 2017:
Delaware Basin. Our 2018 capital investment program for the Delaware Basin contemplates operating at a three-rig
pace throughout the year. Total capital investment in the Delaware Basin for 2018 is expected to be approximately $380
million to $420 million, of which approximately 75 percent is allocated to both spud and turn-in-line approximately 25 to 30
operated wells. Based on the timing of our operations and requirements to hold acreage, we may elect to drill wells different
from or in addition to those currently anticipated, as we are continuing to analyze the terms of the relevant leases. Our
anticipated Delaware Basin drilling program is outlined below:
Estimated average lateral length (in feet)
Expected drilling days (spud-to-rig release)
Estimated percentage of 2018 wells spud
Estimated percentage of 2018 wells turned-in-line
Estimated cost per well (in millions)
SRL
5,000
30
10%
25%
$9.2
MRL
8,000
31
40%
45%
$10.8
XRL
10,000
36
50%
30%
$13.2
Wells in the Delaware Basin typically have productive horizons at depths of approximately 8,000 to 11,000 feet below
the surface. We plan to use approximately 10 percent of our budgeted capital for leasing, non-operated capital, seismic, and
technical studies, with the remaining 15 percent for midstream-related projects, including oil and gas gathering systems and
water supply and disposal systems.
7
The following map presents the general locations of our Wolfcamp formation development areas in the Delaware
Basin as of December 31, 2017:
Utica Shale. In 2017, as part of our plan to divest the Utica Shale properties, we engaged an investment banking firm
and began actively marketing the properties for sale; therefore, these properties are classified as held-for-sale as of December
31, 2017. In February 2018, we entered into a PSA to sell these properties for net cash proceeds of approximately $40.0
million, subject to certain customary closing adjustments.
Strategic acquisitions
As part of our overall growth strategy, we examine and evaluate acquisition opportunities as they present themselves
and pursue those that meet our strategic plan and that we believe will increase stockholder value. We seek properties with large
undeveloped drilling upside where we believe we can utilize our operational expertise to grow production and proved reserves.
In addition, we may pursue opportunities to exchange acreage with other producers or complete small bolt-on acquisitions in
order to optimize our portfolio by consolidating and concentrating on our core assets. The creation of large, contiguous acreage
blocks through the trading of properties or bolt-on acquisitions provides the opportunity to optimize drilling activities and add
more extended-reach lateral wells to our drilling program, while increasing our working interests in the related wells. We have
an experienced team of management, engineering, geosciences, and commercial professionals who identify and evaluate
acquisition opportunities. We believe the Bayswater Acquisition and the acreage exchanges executed in 2016 and 2017 met the
criteria. Any acquisition activity we may pursue in 2018 is expected to be focused on the Wattenberg Field and Delaware
Basin.
Selective exploration
Historically, we have pursued a disciplined exploration program intended to replenish our portfolio of potential drilling
locations and position us for production and reserve growth in future years. When doing so, we attempt to accumulate
significant leasehold positions prior to competitive forces driving up the cost of entry and to invest in leasehold positions that
are near existing or emerging midstream infrastructure. Our recent exploration activity has been in the Delaware Basin as there
are multiple zones that have not seen development sufficient to record proved reserves. We believe such zones could provide
8
us with additional potential drilling locations and/or proved reserves, based upon the results of our exploratory wells. See the
footnote titled Properties and Equipment - Suspended Well Costs to our consolidated financial statements included elsewhere in
this report for additional details regarding our exploratory wells.
Business Segments
We are engaged in two operating segments: our oil and gas exploration and production segment and our gas marketing
segment. Beginning in 2017, our gas marketing segment did not meet the quantitative thresholds to require disclosure as a
separate reportable segment. All of our material operations are attributable to our exploration and production business;
therefore, all of our operations are presented as a single segment for all periods presented.
The results of our Oil and Gas Exploration and Production segment primarily reflect revenues and expenses from the
production and sale of crude oil, natural gas, and NGLs, commodity price risk management, and well operations. The
exploration for and production of crude oil, natural gas, and NGLs involves the acquisition or leasing of mineral and related
surface rights. Prior to development of these properties, we assess the economic viability of potential well development
opportunities. We then develop the reserves through the permitting, drilling and completion of crude oil and natural gas wells,
which are then turned-in-line to production. We operate and maintain the producing wells, while managing associated
production, operating, and transportation costs. At the end of a well's economic life, the well is plugged and surface
disturbances surrounding the well and producing facilities are remediated. The Oil and Gas Exploration and Production
segment's most significant customers are Suncor Energy Marketing, Inc. and DCP Midstream, LP ("DCP"). Sales to each of
these parties constituted more than 10 percent of our 2017 revenues. Given the liquidity in the market for the sale of
hydrocarbons, we believe that the loss of any purchaser or the aggregate loss of several customers could be managed by selling
to alternative purchasers. See Part II, Item 7,Management's Discussion and Analysis of Financial Condition and Results of
Operations - Results of Operations, Summary Operating Results, for sales, pricing, production, and operating cost data.
9
Properties
Productive Wells
The following table presents our productive wells:
Productive Wells
As of December 31, 2017
Natural Gas
Total
Crude Oil
Operating Region/Area
Wattenberg Field (1)
Delaware Basin (2)
Utica Shale (3)
Total productive wells
Gross
811
47
27
885
Net
551.6
43.1
22.2
616.9
Gross
1,893
4
3
1,900
Net
1,660.7
4.0
3.0
1,667.7
Gross
2,704
51
30
2,785
Net
2,212.3
47.1
25.2
2,284.6
_________
(1) Additionally, the Bayswater Acquisition, which closed in January 2018, included 56 gross (19.7 net) productive crude oil
wells and 164 gross (118.7 net) productive natural gas wells.
(2) During 2017, we submitted applications to the Railroad Commission of Texas ("RRC of Texas") requesting that the
designation for 20 wells in the Delaware Basin be changed from crude oil to natural gas per their GOR analysis. The
applications are currently pending review by the RRC of Texas.
(3) In February 2018, we entered into a PSA to sell the Utica Shale properties.
Proved Reserves
The following table presents our proved reserve estimates as of December 31, 2017, based on reserve reports prepared
by our independent petroleum engineering consulting firms, Ryder Scott Company, L.P. ("Ryder Scott"), and Netherland,
Sewell & Associates, Inc. ("NSAI"), and related information:
Proved Reserves at December 31, 2017
Proved
Reserves
(MMBoe)
% of Total
Proved
Reserves
% Proved
Developed
% Liquids
Proved
Reserves to
Production
Ratio
(in years)(1)
2017
Production
(MBoe)
Wattenberg Field
Delaware Basin
Utica Shale (2)
Total proved reserves
350.8
97.9
4.2
452.9
77%
22%
1%
100%
33%
23%
100%
32%
55%
67%
51%
58%
13.1
23.4
5.1
14.2
26,815
4,184
831
31,830
_________
(1) Based on production during 2017.
(2) In February 2018, we entered into a PSA to sell the Utica Shale properties.
Our proved reserves are sensitive to future crude oil, natural gas, and NGLs sales prices and the related effect on the
economic productive life of producing properties. Increases in commodity prices may result in a longer economic productive life
of a property or result in recognition of more economically viable proved undeveloped reserves, while decreases in commodity
prices may result in negative impacts of this nature.
All of our proved reserves are located onshore in the U.S. Our proved reserve estimates are prepared using the
definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a) and other applicable SEC rules. Our proved
reserves in the Wattenberg Field and Utica Shale as of December 31, 2017 were estimated by Ryder Scott and our reserves in
the Delaware Basin as of that date were estimated by NSAI. Both Ryder Scott and NSAI are independent professional
engineering firms.
We have a comprehensive process that governs the determination and reporting of our proved reserves. As part of our
internal control process, our reserves are reviewed annually by an internal team composed of reservoir engineers, geologists,
land, and accounting personnel for adherence to SEC guidelines through a detailed review of land and accounting records,
10
available geological and reservoir data, and production performance data. The internal team compiles the reviewed data and
forwards the data to Ryder Scott and NSAI, as applicable.
When preparing our reserve estimates, neither Ryder Scott nor NSAI independently verifies the accuracy and
completeness of information and data furnished by us with respect to ownership interests, production volumes, well test data,
historical costs of operations and development, product prices or any agreements relating to current and future operations of
properties, or sales of production. Ryder Scott and NSAI prepare estimates of our reserves in conjunction with an ongoing
review by our engineers. A final comparison of data is performed to ensure that the reserve estimates are complete, determined
pursuant to acceptable industry methods, and with a level of detail we deem appropriate. The final estimated reserve reports are
prepared by Ryder Scott and NSAI and reviewed by our engineering staff and management prior to issuance by those firms.
The professional qualifications of our internal lead engineer primarily responsible for overseeing the preparation of
our reserve estimates, as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves
Information as promulgated by the Society of Petroleum Engineers, qualifies this individual as a Reserve Estimator. This
person holds a Bachelor of Science degree in Petroleum and Chemical Refining Engineering with a minor in Petroleum
Engineering, has over 40 years of experience in reservoir engineering, is a member of the Society of Petroleum Engineers and
the Society of Petroleum Evaluation Engineers, and is a registered Professional Engineer in the State of Colorado.
The SEC's reserve rules allow the use of techniques that have been proved effective by evaluation of actual production
from projects in the same reservoir or an analogous reservoir or by other observational evidence using reliable technology that
establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational
methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and
repeatability in the formation being evaluated or in an analogous formation. We used a combination of performance methods,
including decline curve analysis and other computational methods, offset analogies, and seismic data and interpretation to
calculate our reserve estimates. All of our proved undeveloped reserves conform to the SEC five-year rule requirement as all
proved undeveloped locations are scheduled, according to an adopted development plan, to be drilled within five years of the
location’s initial booking date. Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted
arithmetic average of the first of the month prices for the preceding 12 months. The NYMEX prices used in preparing the
reserves are then adjusted based on energy content, location and basis differentials and other marketing deductions to arrive at
the net realized price. The SEC NYMEX prices used in the preparation of reserves are as follows:
2017
As of December 31,
2016
2015
Crude oil (SEC NYMEX - $/Bbl)
Natural gas (SEC NYMEX - $/MMBtu)
$
$
51.34
2.98
$
$
42.75
2.48
$
$
50.28
2.59
Reserve estimates involve judgments and cannot be measured exactly. The estimates must be reviewed periodically
and adjusted to reflect additional information gained from reservoir performance, new geologic and geophysical data, and
economic changes. Neither the estimated future net cash flows nor the standardized measure of discounted future net cash
flows ("standardized measure") is intended to represent the current market value of our proved reserves. For additional
information regarding both of these measures, as well as other information regarding our proved reserves, see the Supplemental
Information Unaudited - Crude Oil and Natural Gas Information provided with our consolidated financial statements included
elsewhere in this report.
11
The following tables provide information regarding our estimated proved reserves:
Proved reserves
Crude oil and condensate (MMBbls)
Natural gas (Bcf)
NGLs (MMBbls)
Total proved reserves (MMBoe)
Proved developed reserves (MMBoe)
Estimated undiscounted future net cash flows (in
millions) (1)
Standardized measure (in millions)
PV-10 (in millions) (2) (3)
$
$
$
2017
As of December 31,
2016
2015
155
1,154
106
453
143
5,453
2,880
3,212
$
$
$
118
834
84
341
98
2,681
1,421
1,675
$
$
$
99
661
64
273
70
2,259
1,097
1,338
___________
(1) Amount represents aggregate undiscounted future net cash flows, before income taxes, estimated by Ryder Scott and NSAI, of
approximately $6.2 billion, $3.3 billion, and $2.8 billion as of December 31, 2017, 2016, and 2015, respectively, less an internally-
estimated undiscounted future income tax expense of approximately $0.7 billion, $0.6 billion, and $0.5 billion, respectively.
(2) PV-10 is a non-U.S. GAAP financial measure. It is not intended to represent the current market value of our estimated reserves.
PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. GAAP,
but rather should be considered in addition to the standardized measure. See Part II, Item 7, Management's Discussion and
Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition
of PV-10 and a reconciliation of our PV-10 value to the standardized measure.
(3) Of the PV-10 amounts, $31.6 million, $21.6 million, and $26.6 million represent amounts attributable to our Utica Shale properties
as of December 31, 2017, 2016, and 2015, respectively. In February 2018, we entered into a PSA to sell these properties.
The following table presents our estimated proved developed and undeveloped reserves by category and area:
Operating Region/Area
Proved developed
Wattenberg Field
Delaware Basin
Utica Shale (1)
Total proved developed
Proved undeveloped
Wattenberg Field
Delaware Basin
Total proved undeveloped
Total proved reserves
Wattenberg Field
Delaware Basin
Utica Shale (1)
Total proved reserves
As of December 31, 2017
Crude Oil
and
Condensate
(MMBbls)
Natural
Gas
(Bcf)
NGLs
(MMBbls)
Crude Oil
Equivalent
(MMBoe)
Percent
36.3
9.5
1.0
46.8
69.7
38.3
108.0
106.0
47.8
1.0
154.8
301.9
50.6
12.8
365.3
644.5
144.5
789.0
946.4
195.1
12.8
1,154.3
29.2
4.9
1.1
35.2
57.8
12.7
70.5
87.0
17.6
1.1
105.7
115.9
22.9
4.2
143.0
234.9
75.0
309.9
350.8
97.9
4.2
452.9
26%
5%
1%
32%
51%
17%
68%
77%
22%
1%
100%
________
(1) In February 2018, we entered into a PSA to sell the Utica Shale properties.
12
We have performed an analysis of our proved reserve estimates as of December 31, 2017 to present sensitivity
associated with a lower crude oil price as the value of crude oil influences the value of our proved reserves and PV-10 most
significantly. Replacing the 2017 NYMEX price for crude oil used in estimating our reported proved reserves with $30.00 as
shown on the table below, and leaving all other parameters unchanged, results in changes to our estimated proved reserves as
shown.
Pricing Scenario - NYMEX
Crude Oil
(per Bbl)
Natural
Gas (per
MMBtu)
Proved
Reserves
(MMBoe)
% Change from
December 31,
2017 Estimated
Reserves
PV-10
(in Millions)
PV-10 %
Change from
December 31,
2017 Estimate
Reserves
2017 SEC Reserve Report (1)
Alternate Price Scenario
$
$
51.34
30.00
$
$
2.98
2.98
452.9
424.9
— $
(6)% $
3,212.0
1,021.0
—
(68)%
__________
(1) These prices are the SEC NYMEX prices applied to the calculation of the PV-10 value. Such prices have been applied
consistently in the alternate pricing scenario to include the impact of adjusting for deductions for any basin differentials,
transportation fees, contractual adjustments, and any Btu adjustments we experienced for the respective commodity.
Developed and Undeveloped Acreage
The following table presents our developed and undeveloped lease acreage:
Operating Region/Area
Wattenberg Field (1) (2)
Delaware Basin (3)
Utica Shale (4)
Total acreage
___________
Developed
Gross
114,200
31,900
5,300
151,400
Net
109,200
29,500
4,500
143,200
As of December 31, 2017
Undeveloped
Total
Gross
8,800
36,600
44,600
90,000
Net
7,600
30,400
41,100
79,100
Gross
123,000
68,500
49,900
241,400
Net
116,800
59,900
45,600
222,300
(1) Of the amounts shown, 91,600 gross (87,400 net) developed lease acres and 4,700 gross (3,900 net) undeveloped
lease acres are associated with our approximately 1,500 operated horizontal Wattenberg Field drilling locations targeting
the Niobrara or Codell plays. The remaining acres are associated with other zones within the field that we do not
currently estimate to be economic to develop; therefore, we have not currently identified any potential drilling
locations on these acres.
(2) The Bayswater Acquisition, which closed in January 2018, included 9,100 gross (7,200 net) developed lease acres and
200 gross and net undeveloped lease acres, providing us a total of 132,300 gross (124,200 net) total acres in the Wattenberg
Field.
(3) See below regarding Culberson County acreage expirations.
(4) In February 2018, we entered into a PSA to sell the Utica Shale properties.
13
Substantially all of our undeveloped acreage in the Wattenberg Field is related to leaseholds that are held by
production. In the Wattenberg Field, the leaseholds at risk to expire in 2018, 2019, and 2020 are not material. In the Delaware
Basin, there are drilling obligations or continuous drilling clauses associated with the majority of our acreage. While we
believe that our current Delaware Basin drilling plan should provide sufficient development to meet these obligations for the
next few years, in the event that we do not meet the obligations for certain leases, we anticipate that, when development plans
dictate or when our analysis of the acreage supports such a decision, we will make any necessary bonus extension payments,
changes to drilling schedules, or will seek to renew or re-lease in order to retain the leases in the eastern and central areas.
However, the payments necessary to extend or retain certain leases may be significant and we may not be successful in such
efforts or may elect not to pursue them. We expect that approximately 3,200 gross and net Delaware Basin acres in our western
area block located in Culberson County will expire during the first half of 2019 as a result of normal course lease expirations
that we do not anticipate renewing due to an expected lack of economically recoverable production quantities. These acres
were impaired to an immaterial value in 2017. In total for the Delaware Basin, approximately 12 percent, 35 percent, and two
percent of the leaseholds are at risk to expire in 2018, 2019, and 2020, respectively. See Item 1A. Risk Factors - Our
undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets
for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not
feasible, loss of our lease and prospective drilling opportunities.
14
Drilling Activity. The following tables set forth a summary of our developmental and exploratory well drilling activity
for the periods presented. There is no necessary correlation between the number of productive wells completed during any
period and the aggregate reserves attributable to those wells. Productive wells consist of wells that were turned-in-line and
commenced production during the period, regardless of when drilling was initiated. In-process wells represent wells that are in
the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection as of the date
shown. The in-process wells are a normal part of our activity. The Wattenberg Field activity is comprised of pad drilling
operations where multiple wells are developed from the same well pad. Because we operate multiple drilling rigs in the area,
we expect to have in-process wells at any given time. Wells may be in-process for anywhere from days to several months. This
normal in-process inventory also exists in the development of our Delaware Basin leasehold.
Gross Development Well Drilling Activity
Year Ended December 31,
2017
2016
2015
Operating Region/Area
Productive
In-
Process
Non-
Productive
(1)
Productive
In-
Process
Non-
Productive
(1)
In-
Process
Non-
Productive
(1)
Productive
Wattenberg Field, operated wells
Wattenberg Field, non-operated wells
Delaware Basin
Utica Shale (2)
130
12
11
—
87
14
18
—
Total gross development wells
153
119
—
1
—
—
1
140
24
1
5
170
64
12
5
—
81
2
—
—
—
2
136
58
—
4
78
19
—
5
198
102
4
—
—
—
4
__________
(1) Represents mechanical failures that resulted in the plugging and abandonment of the respective wells.
(2) In February 2018, we entered into a PSA to sell the Utica Shale properties.
Net Development Well Drilling Activity
Year Ended December 31,
2017
2016
2015
Operating Region/Area
Wattenberg Field, operated wells
Wattenberg Field, non-operated wells
Delaware Basin
Utica Shale (2)
Total net development wells
Productive
In-
Process
Non-
Productive
(1)
In-
Process
Non-
Productive
(1)
Productive
112.8
1.6
10.5
—
124.9
80.1
2.6
10.4
—
93.1
—
0.1
—
—
0.1
109.7
52.7
5.0
1.0
4.5
2.8
4.8
—
120.2
60.3
1.7
—
—
—
1.7
Productive
In-
Process
110.8
54.6
9.3
—
3.0
4.3
—
4.5
123.1
63.4
Non-
Productive
(1)
2.7
—
—
—
2.7
__________
(1) Represents mechanical failures that resulted in the plugging and abandonment of the respective wells.
(2) In February 2018, we entered into a PSA to sell the Utica Shale properties.
15
Gross Exploratory Well Drilling Activity
Year Ended December 31,
2017
2016
2015
Operating Region/Area
Wattenberg Field, operated wells
Wattenberg Field, non-operated wells
Delaware Basin
Utica Shale
Total gross development wells
Productive
In-
Process
Non-
Productive
Productive
In-
Process
Non-
Productive
Productive
In-
Process
Non-
Productive
—
—
5
—
5
—
—
3
—
3
—
—
2
—
2
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Net Exploratory Well Drilling Activity
Year Ended December 31,
2017
2016
2015
Operating Region/Area
Wattenberg Field, operated wells
Wattenberg Field, non-operated wells
Delaware Basin
Utica Shale
Total gross development wells
Productive
In-
Process
Non-
Productive
Productive
In-
Process
Non-
Productive
Productive
In-
Process
Non-
Productive
—
—
3.1
—
3.1
—
—
2.8
—
2.8
—
—
2.0
—
2.0
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Title to Properties
We believe that we hold good and defensible leasehold title to substantially all of our crude oil and natural gas
properties in accordance with standards generally accepted in the industry. A preliminary title examination is typically
conducted at the time the undeveloped properties are acquired. Prior to the commencement of drilling operations, a title
examination is conducted and remedial curative work is performed, as necessary, with respect to discovered defects which we
deem to be significant, in order to procure division order title opinions. Title examinations have been performed with respect to
substantially all of our producing properties.
The properties we own are subject to royalty, overriding royalty, and other outstanding interests. The properties may
also be subject to additional burdens, liens, or encumbrances customary in the industry, including items such as operating
agreements, current taxes, development obligations under crude oil and natural gas leases, farm-out agreements, and other
restrictions. We do not believe that any of these burdens will materially interfere with our use of the properties.
Substantially all of our crude oil and natural gas properties, excluding our share of properties held by the limited
partnerships that we sponsor, have been mortgaged or pledged as security for our revolving credit facility. See the footnote
titled Long-Term Debt to our consolidated financial statements included elsewhere in this report.
Facilities
We lease 87,000 square feet of office space in Denver, Colorado, which serves as our corporate office, through
February 2023 and 47,000 square feet of office space in Evans, Colorado through November 2025. We own a 32,000 square
foot administrative office building located in Bridgeport, West Virginia.
We own or lease field operating facilities in or near Evans, Colorado and Midland, Texas.
Governmental Regulation
The U.S. crude oil and natural gas industry is extensively regulated at the federal, state and local levels. The following
is a summary of certain laws, rules and regulations currently in force that apply to us. The regulatory environment in which we
operate changes frequently and we cannot predict the timing or nature of such changes or their effects on us.
16
Regulation of Crude Oil and Natural Gas Exploration and Production. Our exploration and production activities are
subject to a variety of rules and regulations concerning drilling permits, the spacing and density of wells, rates of production,
water discharge, prevention of waste, bonding requirements, surface use and restoration and well plugging and abandonment.
The primary state-level regulatory authority regarding these matters is the Colorado Oil and Gas Conservation Commission (the
“COGCC”). For example, prior to commencing drilling activities for a well, we must procure permits and/or approvals for the
various stages of the drilling process from the relevant state and local agencies. Similarly, our operations must comply with
rules governing the size of drilling and spacing units or proration units and the unitization or pooling of lands and leases. Some
states, such as Colorado, allow the forced pooling or integration of tracts to facilitate exploration while other states, such as
Texas, rely primarily or exclusively on voluntary pooling of lands and leases. In states, such as Texas, where pooling is
primarily or exclusively voluntary, it may be more difficult to form units and therefore to drill and develop our leases in
circumstances where we do not own all of the leases in the proposed unit. State laws may also establish maximum rates of
production from crude oil and natural gas wells, prohibit the venting or flaring of natural gas, and impose requirements
regarding the ratability of production. Leases covering state or federal lands often include additional regulations and
conditions. These laws, regulations and conditions can limit the number of wells we can drill and the permissible production
from successful wells and can increase our costs.
Regulation of Transportation of Natural Gas. We move natural gas through pipelines owned by other companies and
sell natural gas to other companies that also utilize common carrier pipeline facilities. Natural gas pipeline interstate
transmission and storage activities are subject to regulation by the Federal Energy Regulatory Commission ("FERC") under the
Natural Gas Act of 1938 ("NGA") and under the Natural Gas Policy Act of 1978. Rates and charges for the transportation of
natural gas in interstate commerce, and the extension, enlargement or abandonment of jurisdictional facilities, among other
things, are subject to regulation. Natural gas pipeline companies hold certificates of public convenience and necessity issued by
FERC authorizing ownership and operation of certain pipelines, facilities and properties. Each natural gas pipeline company is
also subject to the Natural Gas Pipeline Safety Act of 1968, as amended, which imposes safety requirements in the design,
construction, operation, and maintenance of interstate natural gas transmission facilities. Under the Energy Policy Act of 2005,
FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and
orders, including the ability to assess substantial civil penalties. Interstate pipelines may not operate their pipeline systems to
preferentially benefit their marketing affiliates.
Transportation and safety of natural gas is also subject to regulation by the United States Department of Transportation
under the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 and the Pipeline Safety, Regulatory Certainty and
Job Creation Act of 2012.
The availability, terms, and cost of transportation affect our natural gas sales. Historically, producers were able to flow
supplies into interstate pipelines on an interruptible basis; however, recently we have seen the increased need to acquire firm
transportation on pipelines in order to avoid curtailments or shut-in gas, which could adversely affect cash flows from the affected
area. Gathering is exempt from regulation under the NGA, thus allowing gatherers to charge negotiated rates. Gathering lines are
subject to state regulation, however, which includes various safety, environmental, and in some circumstances, nondiscriminatory
take requirements.
Environmental Matters
Our operations are subject to numerous laws and regulations relating to environmental protection. These laws and
regulations change frequently, and the effect of these changes is often to impose additional costs or other restrictions on our
operations. We cannot predict the occurrence, timing, nature or effect of these changes.
Hazardous Substances and Wastes
We generate wastes that may be subject to the Federal Resource Conservation and Recovery Act (“RCRA”) and
comparable state statutes. The U.S. Environmental Protection Agency (“EPA”) and various state agencies have adopted
requirements that limit the approved disposal methods for certain hazardous and non-hazardous wastes. Furthermore, certain
wastes generated by our operations that are currently exempt from treatment as “hazardous wastes” may in the future be
designated as hazardous wastes, and therefore may subject us to more rigorous and costly operating and disposal requirements.
In December 2016, the U.S. District Court for the District of Columbia approved a consent decree between the EPA and a
coalition of environmental groups. The consent decree requires the EPA to review and determine whether it will revise the
RCRA regulations for exploration and production waste to treat such waste as hazardous waste. The EPA must complete its
review and make its decision regarding revision by March 2019. If the EPA chooses to revise the applicable RCRA regulations,
it must sign a notice taking final action related to the new regulation by July 2021.
17
We currently own or lease numerous properties that have been used for the exploration and production of crude oil and
natural gas for many years. If hydrocarbons or other wastes have been disposed of or released on or under the properties that we
own or lease or on or under locations where such wastes have been taken for disposal by us or prior owners or operators of such
properties, we could be subject to liability under the Comprehensive Environmental Response, Compensation and Liability Act
(“CERCLA”), RCRA and analogous state laws, as well as state laws governing the management of crude oil and natural gas wastes.
CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes
of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons
include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of, transported,
or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for release of
hazardous substances under CERCLA may be subject to full liability for the costs of cleaning up the hazardous substances that
have been released into the environment or remediation to prevent future contamination and for damages to natural resources.
Under state laws, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and
property damage allegedly caused by the hazardous substances released into the environment.
In October 2015, the EPA granted, in part, a petition filed by several national environmental advocacy groups to add
the oil and gas extraction industry to the list of industries required to report releases of certain “toxic chemicals” under the
Toxics Release Inventory (“TRI”) program under the Emergency Planning and Community Right-to-Know Act.
Hydraulic Fracturing
Hydraulic fracturing is commonly used to stimulate production of crude oil and/or natural gas from dense subsurface
rock formations. We consistently utilize hydraulic fracturing in our crude oil and natural gas development programs. The
process involves the injection of water, sand, and additives under pressure into a targeted subsurface formation. The water and
pressure create fractures in the rock formations which are held open by the grains of sand, enabling the crude oil or natural gas
to more easily flow to the wellbore. The process is generally subject to regulation by state oil and gas commissions, but is also
the subject of various other regulatory initiatives at the federal, state and local levels.
Federal Regulation
Beginning in 2012, the EPA implemented Clean Air Act (“CAA”) standards (New Source Performance Standards
(“NSPS”) and National Emission Standards for Hazardous Air Pollutants) applicable to hydraulically fractured natural gas
wells and certain storage vessels. The standards require, among other things, use of reduced emission completions, or “green”
completions, to reduce volatile organic compound emissions during well completions as well as new controls applicable to a
wide variety of storage tanks and other equipment, including compressors, controllers, and dehydrators.
In February 2014, the EPA issued permitting guidance under the Safe Drinking Water Act ("SDWA") for the
underground injection of liquids from hydraulically fractured and other wells where diesel is used. Depending upon how it is
implemented, this guidance may create duplicative requirements in certain areas, further slow the permitting process in certain
areas, increase the costs of operations, and result in expanded regulation of hydraulic fracturing activities by the EPA, and may
therefore adversely affect even companies, such as PDC, that do not use diesel fuel in hydraulic fracturing activities.
In May 2014, the EPA issued an advance notice of proposed rulemaking under the Toxic Substances Control Act
pursuant to which it will collect extensive information on the chemicals used in hydraulic fracturing fluid, as well as other
health-related data, from chemical manufacturers and processors.
The U.S. Department of the Interior, through the Bureau of Land Management (the “BLM”), finalized a rule in 2015
requiring the disclosure of chemicals used, mandating well integrity measures and imposing other requirements relating to
hydraulic fracturing on federal lands. The BLM rescinded the rule in December 2017.
In June 2016, the EPA finalized pretreatment standards for indirect discharges of wastewater from the oil and gas
extraction industry. The regulation prohibits sending wastewater pollutants from onshore unconventional oil and gas extraction
facilities to publicly-owned treatment works.
In December 2016, the EPA released a report titled “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic
Fracturing Water Cycle on Drinking Water Resources.” The report concluded that activities involved in hydraulic fracturing can
have impacts on drinking water under certain circumstances. In addition, the U.S. Department of Energy has investigated practices
the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. These
18
and similar studies, depending on their degree of development and nature of results obtained, could spur initiatives to further
regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.
State Regulation
Each of the states in which we currently operate, Colorado, Texas, and Ohio, have adopted or are considering adopting
laws and regulations that impose or could impose, among other requirements, stringent permitting or air emission control
requirements, disclosure, wastewater disposal, baseline sampling, seismic monitoring, well construction and well location
requirements on hydraulic fracturing operations and/or more stringent notification or consultation processes. The Ohio
Department of Natural Resources (“ODNR”) has required the suspension of certain activities relating to hydraulic fracturing in
the past in response to earthquakes occurring near development operations. Similarly, the Railroad Commission of Texas has
implemented rules requiring the submission of detailed information related to seismicity in connection with permit applications.
In addition, some states have banned the treatment of fracturing wastewater at publicly owned treatment facilities.
Colorado and Texas require that all chemicals used in the hydraulic fracturing of a well be reported in a publicly
searchable registry website developed and maintained by the Ground Water Protection Council and Interstate Oil and Gas
Compact Commission (“Frac Focus”).
Concerns about hydraulic fracturing have contributed to support for proposed ballot initiatives in Colorado that would
dramatically limit the areas of the state in which drilling would be permitted to occur. See Item 1A. Risk Factors-Risks Relating
to Our Business and the Industry-Changes in laws and regulations applicable to us could increase our costs, impose additional
operating restrictions or have other adverse effects on us.
Local Regulation
Various local and municipal bodies in each of the states in which we operate have purported to impose drilling
moratoria and other restrictions on hydraulic fracturing activities. The cities purporting to ban hydraulic fracturing currently
include Fort Collins, Boulder, Lafayette, Longmont and Brighton in Colorado and Denton in Texas. Ballot initiatives have
been proposed in Colorado that would authorize local governmental authorities to implement hydraulic fracturing bans or other
regulations. See Item 1A. Risk Factors-Risks Relating to Our Business and the Industry-Changes in laws and regulations
applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us.
Private Lawsuits
Lawsuits have been filed against other operators in several states, including Colorado and Ohio, alleging
contamination of drinking water as a result of hydraulic fracturing activities.
Greenhouse Gases
In December 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse
gases (“GHGs”) present an endangerment to public health and the environment because such emissions are, according to the
EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings provide the basis for the
EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. In June
2010, the EPA began regulating GHG emissions from stationary sources.
In the past, Congress has considered proposed legislation to reduce emissions of GHGs. Congress has not adopted any
significant legislation in this respect to date, but could do so in the future. In addition, many states and regions have taken legal
measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or
regional GHG cap and trade programs. In February 2014 and November 2017, Colorado adopted rules regulating methane
emissions from the oil and gas sector.
The Obama administration reached an agreement during the December 2015 United Nations climate change
conference in Paris pursuant to which the United States initially pledged to make a 26-28 percent reduction in its GHG
emissions by 2025 against a 2005 baseline and committed to periodically update this pledge every five years starting in 2020
(the Paris Agreement). In June 2017, President Trump announced that the United States would initiate the formal process to
withdraw from the Paris Agreement.
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Air Quality
Our operations are subject to the CAA and comparable state and local requirements. The CAA contains provisions
that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our
operations. The EPA and state governments continue to develop regulations to implement these requirements. We may be
required to incur certain capital investments in the next several years for air pollution control equipment in connection with
maintaining or obtaining operating permits and approvals addressing other air emission-related issues. See the footnote titled
Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in
this report for further information regarding the Clean Air Act Section 114 Information Request that we received from the EPA
in August 2015.
In June 2016, the EPA implemented new requirements focused on achieving additional methane and volatile organic
compound reductions from the oil and natural gas industry. The rules imposed, among other things, new requirements for leak
detection and repair, control requirements for oil well completions, replacement of certain pneumatic pumps and controllers,
and additional control requirements for gathering, boosting, and compressor stations. The EPA has proposed a two-year stay of
the effective dates of several requirements of the rules. Also in 2016, the EPA issued guidelines for reducing volatile organic
compound emissions from existing oil and natural gas equipment and processes in ozone non-attainment areas, including the
Denver Metro North Front Range Ozone 8-Hour Non-Attainment (“Denver Metro/North Front Range NAA”) area discussed
below.
In November 2016, the BLM finalized rules to further regulate venting, flaring, and leaks during oil and natural gas
production activities on onshore federal and Indian leases. The rules require additional controls and impose new emissions and
other standards on certain operations on applicable leases, including committed state or private tracts in a federally approved
unit or communitized agreement that drains federal minerals. The rules are the subject of litigation in federal court. In
December 2017, the BLM published a rule to temporarily suspend or delay certain rule requirements until January 2019; that
rule is also the subject of litigation in federal court.
In 2016, the EPA increased the state of Colorado’s non-attainment ozone classification for the Denver Metro/North
Front Range NAA area from “marginal” to “moderate” under the 2008 national ambient air quality standard (“NAAQS”). This
increase in non-attainment status triggered significant additional obligations for the state under the CAA and resulted in
Colorado adopting new and more stringent air quality control requirements in November 2017 that are applicable to our
operations. The Denver Metro/North Front Range NAA is at risk of being reclassified again to “serious” if it does not meet the
2008 NAAQS by 2018 or obtain an extension of the deadline from the EPA. A “serious” classification would trigger significant
additional obligations for the state under the CAA and could result in new and more stringent air quality control requirements
applicable to our operations and significant costs and delays in obtaining necessary permits.
State-level rules applicable to our operations include regulations imposed by the Colorado Department of Public
Health and Environment’s Air Quality Control Commission, including stringent requirements relating to monitoring,
recordkeeping, and reporting matters.
Water Quality
The federal Clean Water Act (“CWA”) and analogous state laws impose strict controls concerning the discharge of
pollutants and fill material, including spills and leaks of crude oil and other substances. The CWA also requires approval and/or
permits prior to construction, where construction will disturb wetlands or other waters of the United States. The scope of what
areas constitute jurisdictional waters of the United States regulated under the CWA is currently the subject of ongoing litigation
and related administrative matters that are not expected to be resolved for several years. In January 2017, the Army Corps of
Engineers issued revised and renewed streamlined general nationwide permits that are available to satisfy permitting
requirements for certain work in streams, wetlands and other waters of the United States under Section 404 of the CWA and the
Rivers and Harbors Act. The new nationwide permits took effect in March 2017, or when certified by each state, whichever
was later. The oil and gas industry broadly utilizes nationwide permits 12, 14, and 39 for the construction, maintenance and
repairs of pipelines, roads, and drill pads, respectively, and related structures in waters of the United States that impact less than
a half-acre of waters of the United States and meet the other criteria of each nationwide permit.
The CWA also regulates storm water run-off from crude oil and natural gas facilities and requires storm water
discharge permits for certain activities. Spill Prevention, Control, and Countermeasure (“SPCC”) requirements of the CWA
require appropriate secondary containment load out controls, piping controls, berms, and other measures to help prevent the
contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture, or leak.
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Endangered Species
The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats.
Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and bald and golden eagles under the
Bald and Golden Eagle Protection Act. Some of our operations may be located in areas that are or may be designated as
habitats for endangered or threatened species or that may attract migratory birds, bald eagles, or golden eagles.
Safety and Spill Prevention
In October 2015, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration
proposed to expand its regulations in a number of ways, including increased regulation of gathering lines, even in rural areas,
and proposed additional standards to revise safety regulations applicable to onshore gas transmission and gathering pipelines in
2016.
Crude oil production is subject to many of the same operating hazards and environmental concerns as natural gas
production, but is also subject to the risk of crude oil spills. In addition to SPCC requirements, the Oil Pollution Act of 1990
(“OPA”) subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other
damages arising from crude oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities.
Historically, we have not experienced any significant crude oil discharge or crude oil spill problems.
In May 2015, the U.S. Department of Transportation issued a final rule regarding the safe transportation of flammable
liquids by rail. The final rule imposes certain requirements on “offerors” of crude oil, including sampling, testing, and certification
requirements.
We are also subject to rules regarding worker safety and similar matters promulgated by the U.S. Occupational Safety
and Health Administration (“OSHA”) and other governmental authorities. OSHA has established workplace safety standards
that provide guidelines for maintaining a safe workplace in light of potential hazards, such as employee exposure to hazardous
substances. The COGCC has adopted or amended numerous rules in recent years, including rules relating to safety matters, and
currently is pursuing a rulemaking process relating to flowline safety and leak detection.
WHERE YOU CAN FIND ADDITIONAL INFORMATION
We file annual, quarterly, and current reports, proxy statements and other information with the SEC. Our SEC filings
are available free of charge from the SEC’s website at www.sec.gov or from our website at www.pdce.com. You may also read
or copy any document we file at the SEC’s public reference room in Washington, D.C., located at 100 F Street, N.E.,
Washington, D.C. 20549. Please call the SEC at (800) SEC-0330 for further information on the public reference room. We
also make available free of charge any of our SEC filings by mail. For a mailed copy of a report, please contact PDC Energy,
Inc., Investor Relations, 1775 Sherman Street, Suite 3000, Denver, CO 80203, or call (800) 624-3821.
We recommend that you view our website for additional information, as we routinely post information that we believe
is important for investors. Our website can be used to access such information as our recent news releases, committee charters,
code of business conduct and ethics, stockholder communication policy, director nomination procedures, and our whistle
blower hotline. While we recommend that you view our website, the information available on our website is not part of this
report and is not incorporated by reference.
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ITEM 1A. RISK FACTORS
You should carefully consider the following risk factors in addition to the other information included in this report.
Each of these risk factors could adversely affect our business, operating results, and financial condition, as well as adversely
affect the value of an investment in our common stock or other securities.
Risks Relating to Our Business and the Industry
Crude oil, natural gas, and NGL prices fluctuate and declines in these prices, or an extended period of low prices, can
significantly affect the value of our assets and our financial results and may impede our growth.
Our revenue, profitability, cash flows and liquidity depend in large part upon the prices we receive for our crude oil,
natural gas, and NGLs. Changes in prices affect many aspects of our business, including:
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•
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•
•
our revenue, profitability and cash flows;
our liquidity;
the quantity and present value of our reserves;
the borrowing base under our revolving credit facility and access to other sources of capital; and
the nature and scale of our operations.
The markets for crude oil, natural gas, and NGLs are often volatile, and prices may fluctuate in response to, among
other things:
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relatively minor changes in regional, national, or global supply and demand;
regional, national, or global economic conditions, and perceived trends in those conditions;
geopolitical factors, such as events that may reduce or increase production from particular oil-producing regions
and/or from members of the Organization of Petroleum Exporting Countries, or ("OPEC"); and
regulatory changes.
The price of oil has been volatile since mid-2014, with a high over $100 per barrel in June 2014 to lows below $30 per
barrel in 2016, in each case based on West Texas Intermediate (“WTI”) prices, due to a combination of factors including increased
U.S. supply and global economic concerns. Prices for natural gas and NGLs have experienced similar volatility. If we reduce our
capital expenditures due to low prices, natural declines in production from our wells will likely result in reduced production and
therefore reduced cash flow from operations, which would in turn further limit our ability to make the capital expenditures necessary
to replace our reserves and production.
In addition to factors affecting the price of crude oil, natural gas, and NGLs generally, the prices we receive for our
production are affected by factors specific to us and to the local markets where the production occurs. The prices that we
receive for our production are generally lower than the relevant benchmark prices that are used for calculating commodity
derivative positions. These differences, or differentials, are difficult to predict and may widen or narrow in the future based on
market forces. Differentials can be influenced by, among other things, local or regional supply and demand factors and the
terms of our sales contracts. Over the longer term, differentials will be significantly affected by factors such as investment
decisions made by providers of midstream facilities and services, refineries and other industry participants, and the overall
regulatory and economic climate. For example, increases in U.S. domestic oil production generally, or in production from
particular basins, may result in widening differentials. We may be materially and adversely impacted by widening differentials
on our production and decreasing commodity prices.
The marketability of our production is dependent upon transportation and processing facilities the capacity and operation of
which we do not control. Market conditions or operational impediments affecting midstream facilities and services could
hinder our access to crude oil, natural gas, and NGL markets, increase our costs or delay production. Our efforts to address
midstream issues may not be successful.
Our ability to market our production depends in substantial part on the availability, proximity and capacity of
gathering systems, pipelines and processing facilities owned and operated by third parties. If adequate midstream facilities and
services are not available to us on a timely basis and at acceptable costs, our production and results of operations will be
adversely affected. For example, in recent periods, due to ongoing drilling activities by us and third parties and seasonal
changes in temperatures, our principal third-party provider in the Wattenberg Field for midstream facilities and services has
experienced significantly increased gathering system pressures. The resulting capacity constraints reduced the productivity of
some of our older vertical wells and limited incremental production from some of our newer horizontal wells. This constrained
our production volumes and reduced our revenue from the affected wells. Capacity constraints affecting natural gas production
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also impacted the associated NGLs. While this has not been a problem for us in the Delaware Basin to date, some operators in
the Delaware Basin have also experienced similar issues from time to time, in part due to significant increases in production in
the area. The use of alternative forms of transportation for oil production, such as trucks or rail, involve risks, including the risk
that increased regulation could lead to increased costs or shortages of trucks or rail-cars. In addition to causing production
curtailments, capacity constraints can also reduce the price we receive for the crude oil, natural gas, and NGLs we produce.
We rely on third parties to continue to construct additional midstream facilities and related infrastructure to
accommodate our growth, and the ability and willingness of those parties to do so is subject to a variety of risks. For example:
• Decreases in commodity prices in recent years have resulted in reduced investment in midstream facilities by
some third parties;
• Various interest groups have protested the construction of new pipelines, and particularly pipelines near water
bodies, in various places throughout the country, and protests have at times physically interrupted pipeline
construction activities; and
Some upstream energy companies have recently sought to reject volume commitment agreements with midstream
providers in bankruptcy proceedings, and the risk that such efforts will succeed, or that upstream energy company
counterparties will otherwise be unable or unwilling to satisfy their volume commitments, may have the effect of
reducing investment in midstream infrastructure.
•
Like other producers, we from time to time enter into volume commitments with midstream providers in order to
induce them to provide increased capacity. If our production falls below the level required under these agreements, we could be
subject to substantial penalties.
In order to attempt to alleviate some of the risks associated with the midstream services and facilities upon which we
rely, we have pursued various means of addressing our midstream needs, including by entering into facility expansion
agreements with our primary midstream provider in the Wattenberg Field in 2017. We may pursue additional options with
respect to midstream matters, possibly through one or more joint ventures or monetization transactions. There can be no
assurance that we will be able to negotiate and complete the transactions contemplated by our chosen strategy or that such
transactions will provide us with the benefits we expect to obtain.
Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive
markets for acreage, failure to drill sufficient wells to hold acreage could result in substantial lease renewal costs or, if
renewal is not feasible, loss of our lease and prospective drilling opportunities.
Unless production is established within the spacing units covering our undeveloped acreage, our leases for such
acreage will expire. 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. As such, our actual drilling activities may differ materially from our current
expectations, which could adversely affect our business. These risks are greater at times and in areas where the pace of our
exploration and development activity slows. Our ability to drill and develop these locations depends on a number of
uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability
of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints,
access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. These risks are
currently greater for us in the Delaware Basin area than in our other operating areas as approximately one-third of our Delaware
Basin acreage is currently scheduled to expire by mid-2019 unless the relevant leases are extended or adequate production is
established.
A substantial part of our crude oil, natural gas, and NGLs production is located in the Wattenberg Field, making us
vulnerable to risks associated with operating primarily in a single geographic area. In addition, we have a large amount of
proved reserves attributable to a small number of producing formations.
Although we have significant leasehold positions in the Delaware Basin in Texas, our current production is primarily
located in the Wattenberg Field in Colorado. Because our production is not as diversified geographically as many of our
competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional
events, including:
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fluctuations in prices of crude oil, natural gas, and NGLs produced from the wells in the area;
natural disasters such as the flooding that occurred in northern Colorado in September 2013;
restrictive governmental regulations; and
curtailment of production or interruption in the availability of gathering, processing, or transportation
infrastructure and services, and any resulting delays or interruptions of production from existing or planned new
wells.
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For example, bottlenecks in processing and transportation that have occurred in some recent periods in the Wattenberg
Field have negatively affected our results of operations, and these adverse effects may be disproportionately severe to us
compared to our more geographically diverse competitors. Similarly, the concentration of our producing assets within a small
number of producing formations exposes us to risks, such as changes in field-wide rules that could adversely affect
development activities or production relating to those formations. Such an event could have a material adverse effect on our
results of operations and financial condition. In addition, in areas where exploration and production activities are increasing, as
has been the case in recent years in the Wattenberg Field and the Delaware Basin, the demand for, and cost of, drilling rigs,
equipment, supplies, chemicals, personnel, and oilfield services increase. Shortages or the high cost of drilling rigs, equipment,
supplies, chemicals, personnel, or oilfield services could delay or adversely affect our development and exploration operations
or cause us to incur significant expenditures that are not provided for in our capital forecast, which could have a material
adverse effect on our business, financial condition or results of operations.
Certain of our properties are subject to land use restrictions, which could limit the manner in which we conduct our
business.
Certain of our properties are subject to land use restrictions, including city ordinances, which could limit the manner in
which we conduct our business. Such restrictions could affect, among other things, our access to and the permissible uses of
our facilities as well as the manner in which we produce oil and natural gas, and may restrict or prohibit drilling in general. The
costs we incur to comply with such restrictions may be significant, and we may experience delays or curtailment in the pursuit
of development activities and may be precluded from drilling wells in some areas.
We may incur losses as a result of title defects in the properties in which we invest or acquire.
It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine
the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of oil and gas lease brokers or
landmen who perform record title examinations before we acquire oil and gas leases and related interests. The existence of a
material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition.
While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may
not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the
minerals under the property.
We are subject to complex federal, state, local, and other laws and regulations that adversely affect the cost and manner of
doing business.
Our exploration, development, production, and marketing operations are regulated extensively at the federal, state, and
local levels. Environmental and other governmental laws and regulations have increased the costs of planning, designing,
drilling, installing, operating, and abandoning crude oil and natural gas wells and associated facilities. Under these laws and
regulations, we could also be liable for personal injuries, property damage, and natural resource or other damages, and could be
required to change, suspend or terminate operations. Similar to our competitors, we incur substantial operating and capital
costs to comply with such laws and regulations. These costs may put us at a competitive disadvantage compared to larger
companies in the industry which can more easily capture economies of scale with respect to compliance. A summary of certain
laws and regulations that apply to us is set forth in Items 1 and 2 - Business and Properties - Governmental Regulation.
In June 2017, the U.S. Department of Justice, on behalf of the EPA and the State of Colorado, filed a complaint against
us, claiming that we failed to operate and maintain certain condensate collection equipment at 65 facilities so as to minimize
leakage of volatile organic compounds in compliance with applicable law. In October 2017, we entered into a consent decree to
resolve the lawsuit. Pursuant to the consent decree, we agreed to implement a variety of operational enhancements and
mitigation and similar projects, including vapor control system modifications and verification, increased inspection and
monitoring, and installation of tank pressure monitors. If we fail to comply fully with the requirements of the consent decree
with respect to those matters, we could be subject to additional liability. In addition, we could be the subject of other
enforcement actions by regulatory authorities in the future relating to our past, present or future operations. See the footnote
titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere
in this report for further information regarding this litigation.
A major risk inherent in our drilling plans is the possibility that we will be unable to obtain needed drilling permits
from relevant governmental authorities in a timely manner. Our ability to obtain the permits needed to pursue our development
plans may be impacted by a variety of factors, including opposition by landowners or interest groups. Delays in obtaining
regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well, or the receipt of a permit with
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unreasonable or unexpected conditions or costs could have a material adverse effect on our ability to explore or develop our
properties.
Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have
other adverse effects on us.
The regulatory environment in which we operate changes frequently, often through the imposition of new or more
stringent environmental and other requirements. We cannot predict the nature, timing or effect of such additional requirements,
but they may have a variety of adverse effects on us. The types of regulatory changes that could impact our operations vary
widely and include, but are not limited to, the following:
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Substantially all of our drilling activities involve the use of hydraulic fracturing, and proposals are made from
time to time at the federal, state and local levels to further regulate, or to ban, hydraulic fracturing practices.
Additional laws or regulations regarding hydraulic fracturing could, among other things, increase our costs,
reduce our inventory of economically viable drilling locations and reduce our reserves.
Federal and various state, local and regional governmental authorities have implemented, or considered
implementing, regulations that seek to limit or discourage the emission of carbon, methane and other greenhouse
gases ("GHGs"). For example, the EPA has made findings and issued regulations that require us to establish and
report an inventory of greenhouse gas emissions, and the state of Colorado has adopted rules regulating methane
emissions from oil and gas operations. In addition, the Obama administration reached an agreement during the
December 2015 United Nations climate change conference in Paris pursuant to which the United States initially
pledged to make a 26 percent to 28 percent reduction in its GHG emissions by 2025 against a 2005 baseline
(although President Trump subsequently announced that the United States is withdrawing from the Paris
Agreement). Additional laws or regulations intended to restrict the emission of GHGs could require us to incur
additional operating costs and could adversely affect demand for the oil, natural gas and NGLs that we sell. These
new laws or rules could, among other things, require us to install new emission controls on our equipment and
facilities, acquire allowances to authorize our GHG emissions, pay taxes related to our emissions and administer
and manage a GHG emissions program.
From time to time ballot initiatives have been proposed in Colorado that would adversely affect our operations.
For example, during 2016, interest groups in Colorado opposed to oil and natural gas development generally, and
hydraulic fracturing in particular, advanced two initiatives: (i) a “local control” initiative that would have
amended the state constitution to give city, town, and county governments the right to regulate, or to ban, oil and
gas development and production within their boundaries, notwithstanding rules and approvals to the contrary at
the state level, and (ii) a “setback” initiative that would have amended the state constitution to require all new oil
and gas development facilities to be located at least 2,500 feet away from any occupied structure or broadly
defined “area of special concern”. If implemented, the setback initiative would have effectively prohibited the
vast majority of our planned future drilling activities in Colorado and would therefore have made it impossible to
pursue our current development plans. The local control proposal would potentially have had a similar effect,
depending on the nature and extent of regulations implemented by relevant local governmental authorities. These
proposals ultimately did not appear on the November 2016 ballot but it is likely that similar proposals will be
made in 2018 and in future years. Similar proposals may also be made in other states.
• A recently-adopted ballot initiative that would make it more difficult to implement certain types of ballot
initiatives in the future is currently the subject of a legal challenge and may be invalidated.
•
Proposals are made from time to time to amend U.S. federal and state income tax laws in ways that would be
adverse to us, including by eliminating certain key U.S. federal income tax preferences currently available with
respect to crude oil and natural gas exploration and production. The changes could include (i) the repeal of the
percentage depletion deduction for crude oil and natural gas properties, (ii) the elimination of current deductions
for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production
activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures.
Also, state severance taxes may increase in the states in which we operate. This could adversely affect our
existing operations in the relevant state and the economic viability of future drilling.
• The development of new environmental initiatives or regulations related to the acquisition, withdrawal, storage,
and use of surface water or groundwater, or treatment and discharge of water waste, may limit our ability to use
techniques such as hydraulic fracturing, increase our development and operating costs and cause delays,
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interruptions or termination of our operations, any of which could have an adverse effect on our operations and
financial condition.
See Items 1 and 2, Business and Properties - Governmental Regulation for a summary of certain laws and regulations
that currently apply to us. Any of such laws and regulations could be amended, and new laws or regulations could be
implemented, in a way that adversely affects our operations.
In addition, the election of President Trump has resulted in uncertainty with respect to the future regulatory
environment affecting the oil and natural gas industry. This uncertainty may affect how our industry is regulated as well as the
level of public interest in environmental protection and may result in new or different pressures being exerted. For example,
public interest groups may increase their use of litigation as a means of continuing to exert pressure on the oil and natural gas
industry. Accordingly, while we expect regulatory and enforcement pressures on our business to continue at federal, state, and
local levels, the nature, level, and source of such pressures may change.
Our ability to produce crude oil, natural gas, and NGLs economically and in commercial quantities could be impaired if we
are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of or
recycle the water we use at a reasonable cost and within applicable environmental rules.
Drilling and development activities such as hydraulic fracturing require the use of water and result in the production of
wastewater. Our operations could be adversely impacted if we are unable to locate sufficient amounts of water or dispose of or
recycle water used in our exploration and production operations. The quantity of water required in certain completion
operations, such as hydraulic fracturing, and changing regulations governing usage may lead to water constraints and supply
concerns, particularly in relatively arid climates such as eastern Colorado and western Texas.
As we turn-in-line wells in the Delaware Basin, we are seeing a greater volume of water recovery and production than
originally anticipated. Our operations depend on being able to reuse or dispose of wastewater in a timely and economic
fashion. Wastewater from oil and gas operations is often disposed of through underground injection. An increased number of
earthquakes have been detected in the Delaware Basin in recent years. Some studies have linked earthquakes, or induced
seismicity, in certain areas to underground injection, which is leading to increased public and regulatory scrutiny of injection
safety.
Reduced commodity prices could result in significant impairment charges and significant downward revisions of proved
reserves.
Commodity prices are volatile. Significant and rapid declines in prices have occurred in the past and may occur in the
future. Low commodity prices could result in, among other things, significant impairment charges. The cash flow model we
use to assess properties for impairment includes numerous assumptions, such as management’s estimates of future oil and gas
production and commodity prices, the outlook for forward commodity prices and operating and development costs. All inputs
to the cash flow model must be evaluated at each date the estimate of future cash flows for each producing basin is calculated.
However, a significant decrease in long-term forward prices alone could result in a significant impairment for our properties
that are sensitive to declines in prices. We have incurred impairment charges in a number of recent periods, including charges
of $251.6 million to write down assets and $75.1 million to impair goodwill associated with our acquisition in the Delaware
Basin in 2017 and $150.3 million to write down our Utica Shale producing and non-producing crude oil and natural gas
properties to their estimated fair value in 2015. Similar charges could occur in the future.
Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in
these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.
Calculating reserves for crude oil, natural gas, and NGLs requires subjective estimates of remaining volumes of
underground accumulations of hydrocarbons. Assumptions are also made concerning commodity prices, production levels, and
operating and development costs over the economic life of the properties. As a result, estimated quantities of proved reserves
and projections of future production rates and the timing of development expenditures may be inaccurate. Independent
petroleum engineers prepare our estimates of crude oil, natural gas, and NGLs reserves using pricing, production, cost, tax and
other information that we provide. The reserve estimates are based on assumptions regarding commodity prices, production
levels, and operating and development costs that may prove to be incorrect. Any significant variance from these assumptions to
actual results could greatly affect:
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the economically recoverable quantities of crude oil, natural gas, and NGLs attributable to any particular group of
properties;
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future depreciation, depletion, and amortization (“DD&A”) rates and amounts;
impairments in the value of our assets;
the classifications of reserves based on risk of recovery;
estimates of future net cash flows;
timing of our capital expenditures; and
the amount of funds available for us to borrow under our revolving credit facility.
Some of our reserve estimates must be made with limited production histories, which renders these estimates less reliable
than those based on longer production histories. Further, reserve estimates are based on the volumes of crude oil, natural gas, and
NGLs that are anticipated to be economically recoverable from a given date forward based on economic conditions that exist at
that date. The actual quantities of crude oil, natural gas, and NGLs recovered will be different than the reserve estimates since
they will not be produced under the same economic conditions as are used for the reserve calculations. In addition, quantities of
probable and possible reserves by definition are inherently more risky than proved reserves, in part because they have greater
uncertainty associated with the recoverable quantities of hydrocarbons.
At December 31, 2017, approximately 68 percent of our estimated proved reserves were undeveloped. These reserve
estimates reflect our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including
approximately $2.8 billion during the five years ending December 31, 2022, as estimated in the calculation of the standardized
measure of oil and gas activity. The estimated development costs may not be accurate, development may not occur as scheduled
and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop
them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s
reserve reporting rules, PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the
date of initial booking, and we may therefore be required to downgrade any PUDs that are not developed within this five-year
time frame.
The present value of the estimated future net cash flows from our proved reserves is not necessarily the same as the
current market value of those reserves. Pursuant to SEC rules, the estimated discounted future net cash flows from our proved
reserves, and the estimated quantity of those reserves, are based on the prior year’s first day of the month 12-month average crude
oil and natural gas index prices. However, factors such as actual prices we receive for crude oil and natural gas and hedging
instruments, the amount and timing of actual production, the amount and timing of future development costs, the supply of and
demand for crude oil, natural gas, and NGLs, and changes in governmental regulations or taxation, also affect our actual future
net cash flows from our properties. The timing of both our production and incurrence of expenses in connection with the development
and production of crude oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves,
and thus their actual present value. In addition, the 10 percent discount factor we use when calculating discounted future net cash
flows (the rate required by the SEC) may not be the most appropriate discount factor based on interest rates currently in effect and
risks associated with our properties or the industry in general.
Unless reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect
our future business, financial condition and results of operations. We may not be able to develop our identified drilling
locations as planned.
Producing crude oil, natural gas, and NGL reservoirs are generally characterized by declining production rates that vary
depending upon reservoir characteristics and other factors. The rate of decline may change over time and may exceed our estimates.
Our future reserves and production and, therefore, our cash flows and income, are highly dependent on our ability to efficiently
develop and exploit our current reserves and to economically find or acquire additional recoverable reserves. We may not be able
to develop, discover, or acquire additional reserves to replace our current and future production at acceptable costs. Our failure
to do so would adversely affect our future operations, financial condition and results of operations.
We have identified a number of well locations as an estimation of our future multi-year drilling activities on our
existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these
locations depends on a number of uncertainties, including:
crude oil, natural gas, and NGL prices;
the availability and cost of capital;
drilling and production costs;
availability of drilling services and equipment;
drilling results;
lease expirations or limitations as to depth;
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access to and availability of water sourcing and distribution systems;
regulatory approvals; and
other factors.
Because of these factors, we do not know if the numerous potential well locations we have identified will ever be
drilled or if we will be able to produce crude oil, natural gas, or NGLs from these or any other potential well locations. In
addition, the number of drilling locations available to us will depend in part on the spacing of wells in our operating areas. An
increase in well density in an area could result in additional locations in that area, but a reduced production performance from
the area on a per-well basis. Further, certain of the horizontal wells we intend to drill in the future may require pooling of our
lease interests with the interests of third parties. Some states, including Colorado, allow the involuntary pooling of tracts in a
relatively broad number of circumstances in order to facilitate exploration. Other states, including Texas, restrict involuntary
pooling to a narrower set of circumstances and consequently these states rely primarily on voluntary pooling of lands and
leases. In states where pooling is accomplished primarily on a voluntary basis, it may be more difficult to form units and,
therefore, more difficult to fully develop a project if we own less than all the leasehold or one or more of our leases does not
provide the necessary pooling authority. If third parties are unwilling to pool their interests with ours, we may be unable to
require such pooling on a timely basis or at all, and this would limit the total locations we can drill. Further, the number of
available locations will depend in part on the expected lateral lengths of the wells we drill. Because the intended lateral length
of a well is subject to change for a variety of reasons, our estimated drilling locations will change over time. For this or
numerous other reasons, our actual drilling activities may materially differ from those presently identified.
Our inventory of drilling projects includes locations in addition to those that we currently classify as proved, probable,
and possible. The development of and results from these additional projects are more uncertain than those relating to probable
and possible locations, and significantly more uncertain than those relating to proved locations. We have generally accelerated
the pace of our development activities in the Wattenberg Field over the past several years, and this has reduced our related
inventory of drilling locations.
The wells we drill may not yield crude oil, natural gas, or NGLs in commercially viable quantities and productive wells may
be less successful than we expect.
A prospect is a property on which our geologists have identified what they believe, based on available information, to
be indications of hydrocarbon-bearing rocks. However, given the limitations of available data and technology, our geologists
cannot know conclusively prior to drilling and testing whether crude oil, natural gas, or NGLs will be present in sufficient
quantities to repay drilling or completion costs and generate a profit. Furthermore, even when properly used and interpreted, 2-
D and 3-D seismic data and visualization techniques do not enable our geologists to be certain as to the quantity of the
hydrocarbons in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater pre-
drilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of
such expenditures, which may result in a reduction in our returns or losses. As a result, our drilling activities may not be
successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could
decline. If a well is determined to be dry or uneconomic, which can occur even though it contains some crude oil, natural gas,
or NGLs, it is classified as a dry hole and must be plugged and abandoned in accordance with applicable regulations. This
generally results in the loss of the entire cost of drilling and completion to that point, the cost of plugging, and lease costs
associated with the prospect. Even wells that are completed and placed into production may not produce sufficient crude oil,
natural gas, and NGLs to be profitable, or they may be less productive and/or profitable than we expected. In some recent
periods we have been able to achieve reductions in drilling and completion costs in connection with lower commodity prices.
However, as commodity prices have increased since mid-2016, many of these costs have increased, and further increases are
expected. If we drill a dry hole or unprofitable well on a current or future prospect, or if drilling or completion costs increase,
the profitability of our operations will decline and the value of our properties will likely be reduced. Exploratory drilling is
typically subject to substantially greater risk than development drilling. In addition, initial results from a well are not
necessarily indicative of its performance over a longer period.
Drilling for and producing crude oil, natural gas, and NGLs are high risk activities with many uncertainties that could
adversely affect our business, financial condition and results of operations.
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Drilling activities are subject to many risks, including the risk that we will not discover commercially productive
reservoirs. Drilling can be unprofitable, not only due to dry holes, but also due to curtailments, delays, or cancellations as a
result of other factors, including:
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unusual or unexpected geological formations;
pressures;
fires;
floods;
loss of well control;
loss of drilling fluid circulation;
title problems;
facility or equipment malfunctions;
unexpected operational events;
shortages or delays in the delivery of equipment and services;
unanticipated environmental liabilities;
compliance with environmental and other governmental requirements; and
adverse weather conditions.
Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of
property, natural resources and equipment, pollution, environmental contamination or loss of wells, and regulatory penalties.
For example, a loss of containment of hydrocarbons during drilling activities could potentially subject us to civil and/or
criminal liability and the possibility of substantial costs, including for environmental remediation. We maintain insurance
against various losses and liabilities arising from our operations; however, insurance against certain operational risks may not
be available or may be prohibitively expensive relative to the perceived risks presented. For example, we may not have
coverage with respect to a pollution event if we are unaware of the event while it is occurring and are therefore unable to report
the occurrence of the event to our insurance company within the time frame required under our insurance policy. Thus, losses
could occur for uninsurable or uninsured risks or for amounts in excess of existing insurance coverage. The occurrence of an
event that is not fully covered by insurance and/or governmental or third party responses to an event could have a material
adverse effect on our business activities, financial condition and results of operations. We are currently involved in various
remedial and investigatory activities at some of our wells and related sites.
Prior to 2012, most of the wells we drilled were vertical wells. Since 2012, however, we have devoted the majority of
our capital to drilling horizontal wells. Drilling horizontal wells is technologically more difficult than drilling vertical wells -
including as a result of risks relating to our ability to fracture stimulate the planned number of stages and to successfully run
casing the length of the well bore - and the risk of failure is therefore greater than the risk involved in drilling vertical wells.
Additionally, drilling a horizontal well is typically far costlier than drilling a vertical well. This means that the risks of our
drilling program will be spread over a smaller number of wells, and that, in order to be economic, each horizontal well will
need to produce at a higher level in order to cover the higher drilling costs. Similarly, the average lateral length of the
horizontal wells we drill has generally been increasing. Longer-lateral wells are typically more expensive and require more
time for preparation and permitting. In addition, we have transitioned to the use of multi-well pads instead of single-well sites.
The use of multi-well pad drilling increases some operational risks because problems affecting the pad or a single well could
adversely affect production from all of the wells on the pad. Pad drilling can also make our overall production, and therefore
our revenue and cash flows, more volatile, because production from multiple wells on a pad will typically commence
simultaneously. While we believe that we will be better served by drilling horizontal wells using multi-well pads, the risk
component involved in such drilling will be increased in some respects, with the result that we might find it more difficult to
achieve economic success in our drilling program.
The inability of one or more of our customers or other counterparties to meet their obligations may adversely affect our
financial results.
Substantially all of our accounts receivable result from our crude oil, natural gas, and NGLs sales or joint interest billings
to a small number of third parties in the energy industry. This concentration of customers and joint interest owners may affect our
overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our
commodity derivatives expose us to credit risk in the event of nonperformance by counterparties. Nonperformance by our customers
or derivative counterparties may adversely affect our financial condition and profitability. We face similar risks with respect to
our other counterparties, including the lenders under our revolving credit facility and the providers of our insurance coverage.
Seasonal weather conditions and lease stipulations can adversely affect our operations.
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Seasonal weather conditions and lease stipulations designed to prohibit or limit operations during crop-growing
seasons and to protect wildlife affect operations in some areas. In certain areas drilling and other activities may be restricted or
prohibited by lease stipulations, or prevented by weather conditions, for significant periods of time. This limits our operations
in those areas and can intensify competition during the active months for drilling rigs, equipment, supplies, chemicals,
personnel, and oilfield services, which may lead to additional or increased costs or periodic shortages. These constraints, and
the resulting high costs or shortages, could delay our operations and materially increase operating and capital costs and
therefore adversely affect our profitability. Similarly, hot weather during some recent periods adversely impacted the operation
of certain midstream facilities, and therefore our production. Similar events could occur in the future and could negatively
impact our results of operations and cash flows.
We have limited control over activities on properties in which we own an interest but we do not operate, which could reduce
our production and revenues.
We operate approximately 87 percent of the wells in which we own an interest. If we do not operate a property, we do
not have control over normal operating procedures, expenditures or future development of the property. The success and timing
of drilling and development activities on properties operated by others therefore depends upon a number of factors outside of
our control, including the operator’s timing and amount of capital expenditures, expertise (including safety and environmental
compliance) and financial resources, inclusion of other participants in drilling wells, and use of technology. The failure by an
operator to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce production and
revenues and adversely affect our profitability. These risks may be heightened during periods of depressed commodity prices
as operators may propose operations that we believe to be economically unattractive, leading us to incur non-consent penalties.
Our lack of control over non-operated properties also makes it more difficult for us to forecast capital expenditures, production
and related matters
We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects.
We frequently own less than all of the working interest in the oil and gas leases on which we conduct operations.
Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by
more than one person. We could be held liable for joint activity obligations of other working interest owners, such as
nonpayment of costs and liabilities, arising from the actions of the other owners. In addition, declines in oil, natural gas, and
NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less
established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of
project costs, and, in some cases, may declare bankruptcy. In the event any of our project partners does not pay their share of
such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover the costs from the
partner. This could materially adversely affect our financial position.
We may not be able to keep pace with technological developments in our industry.
Our industry is characterized by rapid and significant technological advancements. As our competitors use or develop
new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those
or other new technologies at substantial cost. In addition, our competitors may have greater financial, technical, and personnel
resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies
before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely
basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we
were unable to use the most advanced technology, our business, financial condition and results of operations could be
materially adversely affected.
Competition in our industry is intense, which may adversely affect our ability to succeed.
Our industry is intensely competitive, and we compete with other companies that have greater resources. Many of
these companies not only explore for and produce crude oil, natural gas, and NGLs, but also carry on refining operations and
market petroleum and other products on a regional, national, or worldwide basis. These companies may be able to pay more for
productive properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and
prospects than we can. Our ability to acquire additional properties and to discover reserves in the future will be dependent
upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.
In addition, larger companies may have a greater ability to continue exploration activities during periods of low commodity
prices. Larger competitors may also be able to absorb the burden of present and future federal, state, local, and other laws and
regulations more easily than we can, which could adversely affect our competitive position. These factors could adversely
affect our operations and our profitability.
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Our success depends on key members of our management and our ability to attract and retain experienced technical and
other professional personnel.
Our future success depends to a large extent on the services of our key employees. The loss of one or more of these
individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other
professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel,
our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical
expertise.
A failure to complete successful acquisitions would limit our growth.
Because our crude oil and natural gas properties are depleting assets, our future reserves, production volumes, and
cash flows depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring
additional recoverable reserves economically. In addition, we continue to strive to achieve greater efficiencies in our drilling
program, and our ability to do so is dependent in part on our ability to complete asset exchanges and other acquisitions that
allow us to increase our working interests in particular properties. When attractive opportunities arise, acquiring additional
crude oil and natural gas properties, or businesses that own or operate such properties, is a significant component of our
strategy. We may not be able to identify attractive acquisition opportunities. If we do identify an appropriate acquisition
candidate, we may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the
necessary regulatory approvals. It may be difficult to agree on the economic terms of a transaction, as a potential seller may be
unwilling to accept a price that we believe to be appropriately reflective of prevailing economic conditions. If we are unable to
complete suitable acquisitions, it will be more difficult to replace our reserves, and an inability to replace our reserves would
have a material adverse effect on our financial condition and results of operations.
Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential liabilities,
including environmental uncertainties.
Acquisitions of producing and undeveloped properties have been an important part of our growth over time. We
expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of
factors, many of which are beyond our control. These factors include recoverable reserves, development potential, future
commodity prices, operating costs, title issues, and potential environmental and other liabilities. Such assessments are inexact
and their accuracy is inherently uncertain. In connection with our assessments, we generally perform engineering,
environmental, geological, and geophysical reviews of the acquired properties that we believe are generally consistent with
customary industry practices. However, such reviews are not likely to permit us to become sufficiently familiar with the
properties to fully assess their deficiencies and capabilities. We do not inspect every well prior to an acquisition and our ability
to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural,
subsurface, and environmental problems that may exist or arise. In some cases, our review prior to signing a definitive
purchase agreement may be even more limited. In addition, we often acquire acreage without any warranty of title except as to
claims made by, through or under the transferor.
When we acquire properties, we will generally have potential exposure to liabilities and costs for environmental and
other problems existing on the acquired properties, and these liabilities may exceed our estimates. We may not be entitled to
contractual indemnification associated with acquired properties. We often acquire interests in properties on an “as is” basis
with no or limited remedies for breaches of representations and warranties. Therefore, we could incur significant unknown
liabilities, including environmental liabilities or losses due to title defects, in connection with acquisitions for which we have
limited or no contractual remedies or insurance coverage. In addition, the acquisition of undeveloped acreage is subject to
many inherent risks and we may not be able to realize efficiently, or at all, the assumed or expected economic benefits of
acreage that we acquire.
Additionally, significant acquisitions can change the nature of our operations depending upon the character of the
acquired properties, which may have substantially different operating and geological characteristics or may be in different
geographic locations than our existing properties. These factors can increase the risks associated with an acquisition.
Acquisitions also present risks associated with the additional indebtedness that may be required to finance the purchase price,
and any related increase in interest expense or other related charges.
Some of our acquisitions are structured as asset trades or exchanges. These transactions may give rise to any or all of
the foregoing risks. In addition, transactions of this type create a risk that we will undervalue the properties we transfer to the
counterparty in the trade or exchange or overvalue the properties we receive. Such an undervaluation or overvaluation would
result in the transaction being less favorable to us than we expected.
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We operate in a litigious environment. The cost of defending any suits brought against us, and any judgments or
settlements resulting from such suits, could have an adverse effect on our results of operations and financial condition.
Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as
title, royalty or contractual disputes, employment litigation, regulatory compliance matters, and personal injury or property
damage matters, in the ordinary course of our business. For example, in recent years, we have been subject to lawsuits
regarding royalty practices and payments and matters relating to certain of our affiliated partnerships. As discussed in the
footnote titled Commitments and Contingencies to our consolidated financial statements included elsewhere in this report, we
are the subject of a recently filed lawsuit relating to our two remaining affiliated partnerships, and the strained financial
condition of those partnerships makes additional litigation more likely. The outcome of legal proceedings is inherently
uncertain. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of
management attention and other factors. In addition, the resolution of such a proceeding could result in penalties or sanctions,
settlement costs and/or judgments, consent decrees, or orders requiring a change in our business practices, any of which could
materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties,
sanctions or costs may be insufficient. Judgments and estimates to determine accruals or the anticipated range of potential
losses related to legal and other proceedings could change from one period to the next, and such changes could be material.
Information regarding our legal proceedings can found in the footnote titled Commitments and Contingencies - Litigation and
Legal Items to our consolidated financial statements included elsewhere in this report.
Our business could be negatively impacted by security threats, including cybersecurity threats, and other disruptions.
We face various security threats, including attempts by third parties to gain unauthorized access to competitive
information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our
infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts.
There can be no assurance that the procedures and controls we use to monitor these threats and mitigate our exposure to them
will be sufficient in preventing them from materializing.
Our industry has become increasingly dependent on digital technologies to conduct day-to-day operations, including
certain exploration, development, and production activities. We depend on digital technology, including information systems
and related infrastructure, as well as cloud applications and services, to store, transmit, process, and record sensitive
information (including but not limited to trade secrets, employee information, and financial and operating data), communicate
with our employees and business partners, and for many other activities related to our business. The complexity of the
technologies needed to explore for and develop crude oil, natural gas, and NGLs make certain information more attractive to
thieves.
As dependence on digital technologies has increased in our industry, cyber incidents, including deliberate attacks and
unintentional events, have also increased. A cyber-attack could include an attempt to gain unauthorized access to digital
systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption.
“Phishing” and other types of attempts to obtain unauthorized information or access are often sophisticated and difficult to
detect or defeat.
Our business partners, including vendors, service providers, operating partners, purchasers of our production, and
financial institutions, are also dependent on digital technology. A vulnerability in the cybersecurity of one or more of our
vendors could facilitate an attack on our systems.
Our technologies, systems and networks, and those of our business partners, may become the target of cyber-attacks or
information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of
proprietary and other information, theft of property or other disruption of our business operations. In addition, certain cyber
incidents, such as surveillance, may remain undetected for an extended period. Although we have not suffered material losses
related to cyber-attacks to date, if we were successfully attacked, we could incur substantial remediation and other costs or
suffer other negative consequences, such as a loss of competitive information, critical infrastructure, personnel or capabilities
essential to our operations. Events of this nature could have a material adverse effect on our reputation, financial condition,
results of operations, or cash flows. Moreover, as the sophistication of cyber-attacks continues to evolve, we may be required
to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities.
The physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for
or responding to those effects.
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Many scientists believe that increasing concentrations of carbon dioxide, methane, and other GHGs in the Earth's
atmosphere are changing global climate patterns. One consequence of climate change could be increased severity of extreme
weather, such as increased hurricanes and floods. Flooding that occurred in Colorado in 2013 is an example of an extreme
weather event that negatively impacted our operations. If such events were to continue to occur, or become more frequent, our
operations could be adversely affected in various ways, including through damage to our facilities or from increased costs for
insurance.
Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for
natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in
climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for
climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially
colder than their historical averages. As a result, it is difficult to predict how the market for our production could be affected by
increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an
adverse effect on our business.
Risks Relating to Financial Matters
Our development and exploration 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 production and reserves, and
ultimately our profitability.
Our industry is capital intensive. We expect to continue to make substantial capital expenditures for the exploration,
development, production and acquisition of crude oil, natural gas, and NGL reserves. To date, we have financed capital
expenditures primarily with bank borrowings under our revolving credit facility, cash generated by operations and proceeds
from capital markets transactions and the sale of properties. We intend to finance our future capital expenditures utilizing
similar financing sources. Our cash flows from operations and access to capital are subject to a number of variables, including:
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our proved reserves;
the amount of crude oil, natural gas, and NGLs we are able to produce from existing wells;
the prices at which crude oil, natural gas, and NGLs are sold;
the costs to produce crude oil, natural gas, and NGLs; and
our ability to acquire, locate and produce new reserves.
If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower commodity
prices, operating difficulties or for any other reason, our need for capital from other sources could increase, and there can be no
assurance that such other sources of capital would be available at that time on reasonable terms or at all. If we raise funds by
issuing additional equity securities, this would have a dilutive effect on existing shareholders. If we raise funds through the
incurrence of debt, the risks we face with respect to our indebtedness would increase and we would incur additional interest
expense. Our inability to obtain sufficient financing on acceptable terms would adversely affect our financial condition and
profitability.
We have a substantial amount of debt and the cost of servicing, and risks related to refinancing, that debt could adversely
affect our business. Those risks could increase if we incur more debt.
We have a substantial amount of indebtedness outstanding. As a result, a significant portion of our cash flows will be
required to pay interest and principal on our indebtedness, and we may not generate sufficient cash flows from operations, or
have future borrowing capacity available, to enable us to repay our indebtedness or to fund other liquidity needs.
Servicing our indebtedness and satisfying our other obligations will require a significant amount of cash. Our cash
flow from operating activities and other sources may not be sufficient to fund our liquidity needs. Our ability to pay interest and
principal on our indebtedness and to satisfy our other obligations will depend on our future operating performance, our
financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions
and financial, business and other factors, many of which are beyond our control. We cannot assure you that our business will
generate sufficient cash flow from operations, or that sufficient future borrowings will be available to us under our revolving
credit facility or otherwise, to fund our liquidity needs.
A substantial decrease in our operating cash flow or an increase in our expenses could make it difficult for us to meet
debt service requirements and could require us to modify our operations, including by curtailing our exploration and drilling
programs, selling assets, reducing our capital expenditures, refinancing all or a portion of our existing debt or obtaining
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additional financing. These alternative measures may not be successful and may not permit us to meet our scheduled debt
service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our
financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with
more onerous covenants, which could further restrict our business operations.
In addition, the terms of our debt agreements could restrict us from implementing some of these alternatives. In the
absence of adequate cash from operations and other available capital resources, we could face substantial liquidity problems
and might be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be
able to consummate these dispositions for fair market value, in a timely manner or at all. Furthermore, any proceeds that we
could realize from any dispositions may not be adequate to meet our debt service obligations then due.
Covenants in our debt agreements currently impose, and future financing agreements may impose, significant operating
and financial restrictions.
Our current debt agreements contain restrictions, and future financing agreements may contain additional restrictions,
on our activities, including covenants that restrict our and our restricted subsidiaries’ ability to:
incur additional debt;
pay dividends on, redeem or repurchase stock;
create liens;
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apply net proceeds from certain asset sales;
engage in transactions with our affiliates;
engage in sale and leaseback transactions;
restrict dividends or other payments from restricted subsidiaries;
sell equity interests of restricted subsidiaries; and
sell, assign, transfer, lease, convey or dispose of assets.
Our revolving credit facility is secured by substantially all of our oil and gas properties as well as a pledge of all
ownership interests in operating subsidiaries. The restrictions contained in our debt agreements may prevent us from taking
actions that we believe would be in the best interest of our business, and may make it difficult for us to successfully execute our
business strategy or effectively compete with companies that are not similarly restricted. We may also incur future debt
obligations that subject us to additional restrictive covenants.
Our revolving credit facility has substantial restrictions and financial covenants and our ability to comply with those
restrictions and covenants is uncertain. Our lenders can unilaterally reduce our borrowing availability based on anticipated
commodity prices.
We expect to depend on our revolving credit facility for part of our future capital needs. The terms of the credit
agreement require us to comply with certain financial covenants. Our ability to comply with these covenants in the future is
uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our
failure to comply with any of the restrictions and covenants under the revolving credit facility or other debt agreements could
result in a default under those agreements, which could cause all of our existing indebtedness to become immediately due and
payable.
The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders
in their sole discretion based upon projected revenues from the properties securing their loan. Decreases in the price of crude
oil, natural gas, or NGLs can be expected to have an adverse effect on the borrowing base. The lenders can unilaterally adjust
the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Outstanding borrowings
in excess of the borrowing base must be repaid immediately unless we pledge other crude oil and natural gas properties as
additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial
resources in the future to make any mandatory principal prepayments required under the revolving credit facility. Our inability
to borrow additional funds under our revolving credit facility could adversely affect our operations and our financial results.
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If we are unable to comply with the restrictions and covenants in our debt agreements, the resulting default could lead to an
acceleration of payment of funds that we have borrowed and we may not have or be able to obtain the funds necessary to
repay those amounts.
Any default under the agreements governing our indebtedness, including a default under our revolving credit facility
that is not waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make us
unable to pay principal and interest on our indebtedness and satisfy our other obligations. If we are unable to generate sufficient
cash flows and are otherwise unable to obtain the funds necessary to meet required payments of principal and interest on our
indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the
instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness.
In the event of such a default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be
due and payable, together with accrued and unpaid interest, the lenders under our revolving credit facility could elect to
terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets, and we could
be forced into bankruptcy or liquidation. In addition, the default could result in a cross-default under other debt agreements. If
our operating performance declines, we may in the future need to seek waivers from the required lenders under our revolving
credit facility to avoid being in default and we may not be able to obtain such a waiver. If this occurs and no waiver is obtained,
we would be in default under our revolving credit facility, the lenders could exercise their rights as described above, and we
could be forced into bankruptcy or liquidation. We cannot assure you that we will be granted waivers or amendments to our
debt agreements if for any reason we are unable to comply with these agreements, or that we will be able to refinance our debt
on terms acceptable to us, or at all.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase
significantly.
Borrowings under our revolving credit facility bear interest at variable rates and expose us to interest rate risk. If
interest rates increase, our debt service obligations on the variable rate indebtedness would increase although the amount
borrowed remained the same, and our net income and cash available for servicing our indebtedness and for other purposes
would decrease.
Notwithstanding our current indebtedness levels and restrictive covenants, we may still be able to incur substantial
additional debt, which could exacerbate the risks described above.
We may be able to incur additional debt in the future. Although our debt agreements contain restrictions on our ability
to incur indebtedness, those restrictions are subject to a number of exceptions. In particular, we may borrow under the revolving
credit facility. We may also consider investments in joint ventures or acquisitions that may increase our indebtedness. Adding
new debt to current debt levels could intensify the related risks that we and our subsidiaries now face.
Under the “successful efforts” accounting method that we use, unsuccessful exploratory wells must be expensed in the
period in which they are determined to be non-productive, which reduces our net income in such periods.
We conduct exploratory drilling in order to identify additional opportunities for future development. Under the
“successful efforts” method of accounting that we use, the cost of unsuccessful exploratory wells must be charged to expense in
the period in which the wells are determined to be unsuccessful. In addition, lease costs for acreage condemned by the
unsuccessful well must also be expensed. In contrast, unsuccessful development wells are capitalized as a part of the
investment in the field where they are located. The costs of unsuccessful exploratory wells could result in a significant
reduction in our profitability in periods in which the costs are required to be expensed.
Our commodity derivative activities could result in financial losses or reduced income from failure to perform by our
counterparties, could limit our potential gains from increases in prices and could result in volatility in our net income.
We use commodity derivatives for a portion of the production from our own wells and for natural gas purchases and
sales by our marketing subsidiary to achieve more predictable cash flows, to reduce exposure to adverse fluctuations in
commodity prices, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and
purchasers. These arrangements expose us to the risk of financial loss in some circumstances, including when purchases or
sales are different than expected or the counterparty to the commodity derivative contract defaults on its contractual obligations.
In addition, many of our commodity derivative contracts are based on WTI or another crude oil or natural gas index price. The
risk that the differential between the index price and the price we receive for the relevant production may change unexpectedly
makes it more difficult to hedge effectively and increases the risk of a hedging-related loss. Also, commodity derivative
arrangements may limit the benefit we would otherwise receive from increases in the prices for the relevant commodity, and
they may require the use of our resources to meet cash margin requirements.
35
At December 31, 2017, we had hedged a total of 18,484 MBbls of crude oil and 56,510 BBtu of natural gas for 2018
and 2019. These hedges may be inadequate to protect us from continuing and prolonged declines in crude oil and natural gas
prices, and our current hedge position is smaller, and its estimated fair value is lower, than our hedge position in some recent
periods.
Since we do not designate our commodity derivatives as cash flow hedges, we do not currently qualify for use of
hedge accounting; therefore, changes in the fair value of commodity derivatives are recorded in our income statements, and our
net income is subject to greater volatility than it would be if our commodity derivative instruments qualified for hedge
accounting. For instance, if commodity prices rise significantly, this could result in significant non-cash charges during the
relevant period, which could have a material negative effect on our net income.
Our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur.
The occurrence of a significant accident or other event that is not fully covered by insurance, not properly or timely
noticed to our carrier, or that is in excess of our insurance coverage could have a material adverse effect on our operations and
financial condition. Insurance does not protect us against all operational risks. We do not carry business interruption insurance
at levels that would provide enough funds for us to continue operating without access to other funds. In addition, pollution and
environmental risks are generally not fully insurable.
The price of our common stock has been and may continue to be highly volatile, which may make it difficult for
shareholders to sell our common stock when desired or at attractive prices.
The market price of our common stock is highly volatile, and we expect it to continue to be volatile for the foreseeable
future. Adverse events could trigger declines in the price of our common stock, including, among others:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
changes in production volumes, worldwide demand and prices for crude oil and natural gas;
changes in market prices of crude oil and natural gas;
inability to hedge future production at the same pricing level as our current or prior hedges;
changes in securities analysts’ estimates of our financial performance;
fluctuations in stock market prices and volumes, particularly among securities of energy companies;
changes in market valuations and valuation multiples of similar companies;
changes in interest rates;
announcements regarding adverse timing or lack of success in discovering, acquiring, developing, and producing
crude oil and natural gas resources;
announcements by us or our competitors of significant contracts, new acquisitions, discoveries, commercial
relationships, joint ventures, or capital commitments;
decreases in the amount of capital available to us, including as a result of borrowing base reductions and/or
lenders ceasing to participate in our revolving credit facility syndicate;
operating results that fall below market expectations or variations in our quarterly operating results;
loss of a major customer;
loss of a relationship with a partner;
the identification of and severity of environmental events and governmental and other third-party responses to the
events; or
additions or departures of key personnel.
External events, such as news concerning economic conditions, counterparties to our natural gas or crude oil
derivatives arrangements, changes in government regulations impacting the crude oil and natural gas exploration and
production industry or the movement of capital into or out of our industry, are also likely to affect the price of our common
stock, regardless of our operating performance. For example, there have been recent efforts by some investment advisers,
sovereign wealth funds, public pension funds, universities, and other investment groups to divest themselves from investments
in companies involved in fossil fuel extraction, and these efforts could reduce the trading prices of our securities. Similarly, our
stock price could be adversely affected by changes in the way that analysts and investors assess the geological and economic
characteristics of the basins in which we operate. Furthermore, general market conditions, including the level of, and
fluctuations in, the trading prices of stocks generally could affect the price of our common stock. The stock markets regularly
experience price and volume volatility that affects many companies’ stock prices without regard to the operating performance
of those companies. Volatility of this type may affect the trading price of our common stock. Similar factors could also affect
the trading prices of our senior notes.
36
We have identified material weaknesses in our internal control over financial reporting which could, if not remediated,
result in material misstatements in our financial statements.
As disclosed in Item 9A - Controls and Procedures, management identified certain material weaknesses in our internal
control over precision of the review of supporting documentation regarding the completeness and accuracy of certain land
administrative records. Because of these material weaknesses, our management concluded that we did not maintain effective
internal control over financial reporting as of December 31, 2017. A material weakness is a deficiency, or combination of
deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement
of the annual or interim financial statements will not be prevented or detected on a timely basis.
With the oversight of the audit committee, we have begun taking steps to remediate the underlying cause of these
material weaknesses and improve the design of controls. We cannot assure you that we will adequately remediate the material
weaknesses or that additional material weaknesses in our internal controls will not be identified in the future. Any failure to
maintain or implement required new or improved controls, or any difficulties we encounter in their implementation, could
result in additional material weaknesses, or could result in material misstatements in our financial statements. These
misstatements could result in restatements of our financial statements, cause us to fail to meet our reporting obligations, or
cause investors to lose confidence in our reported financial information. Further and continued determinations that there are
material weaknesses in the effectiveness of our internal controls could reduce our ability to obtain financing or could increase
the cost of any financing we obtain and require additional expenditures of resources to comply with applicable requirements.
Derivatives legislation and regulation could adversely affect our ability to hedge crude oil and natural gas prices and
increase our costs and adversely affect our profitability.
In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted
into law. The Dodd-Frank Act regulates derivative transactions, including our commodity hedging swaps, and could have a
number of adverse effects on us, including the following:
• The Dodd-Frank Act may limit our ability to enter into hedging transactions, thus exposing us to additional risks
related to commodity price volatility; commodity price decreases would then have an increased adverse effect on
our profitability and revenues. Reduced hedging may also impair our ability to have certainty with respect to a
portion of our cash flows, which could lead to decreases in capital spending and, therefore, decreases in future
production and reserves.
If, as a result of the Dodd-Frank Act or its implementing regulations, we are required to post cash collateral in
connection with our derivative positions, this would likely make it impracticable to implement our current
hedging strategy.
•
• Our derivatives counterparties are subject to significant requirements imposed as a result of the Dodd-Frank Act.
We expect that these requirements will increase the cost to hedge because there will be fewer counterparties in the
market and increased counterparty costs will be passed on to us.
The above factors could also affect the pricing of derivatives and make it more difficult for us to enter into hedging
transactions on favorable terms.
37
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
Information regarding our legal proceedings can found in the footnote titled Commitments and Contingencies -
Litigation and Legal Items to our consolidated financial statements included elsewhere in this report.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
38
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS,
AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock, par value $0.01 per share, is traded on the NASDAQ Global Select Market under the symbol
PDCE. The following table sets forth the range of high and low sales prices for our common stock based on intra-day trading
for each of the periods presented:
High
Low
$
January 1 - March 31, 2016
April 1 - June 30, 2016
July 1 - September 30, 2016
October 1 - December 31, 2016
January 1 - March 31, 2017
April 1 - June 30, 2017
July 1 - September 30, 2017
October 1 - December 31, 2017
$
60.56
65.86
71.00
84.88
78.61
65.99
50.51
53.41
42.68
51.92
50.12
59.82
60.27
40.12
36.74
41.13
As of February 15, 2018, we had approximately 589 stockholders of record. Since inception, no cash dividends have
been declared on our common stock. Cash dividends are restricted under the terms of our revolving credit facility as well as
the indentures governing our 6.125% senior notes due September 15, 2024 (the "2024 Senior Notes") and our 2026 Senior
Notes, and we presently intend to continue a policy of using retained earnings for the expansion of our business.
The following table presents information about our purchases of our common stock during the three months ended
December 31, 2017:
Period
October 1 - 31, 2017
November 1 - 30, 2017
December 1 - 31, 2017
Total fourth quarter 2017 purchases
Total Number of
Shares Purchased (1)
Average Price Paid per
Share
$
5,636
—
21,301
26,937
48.88
—
50.68
50.30
__________
(1) Purchases primarily represent shares purchased from employees for the payment of their tax liabilities related to the vesting of securities
issued pursuant to our stock-based compensation plans.
39
STOCKHOLDER PERFORMANCE GRAPH
The performance graph below compares the cumulative total return of our common stock over the five-year period
ended December 31, 2017 with the cumulative total returns for the same period for the Standard and Poor's ("S&P") 500 Index
and the Standard Industrial Code ("SIC") Index. The SIC Index is a weighted composite of 233 crude petroleum and natural
gas companies. The cumulative total stockholder return assumes that $100 was invested, including reinvestment of dividends,
if any, in our common stock on December 31, 2012, and in the S&P 500 Index and the SIC Index on the same date. The results
shown in the graph below are not necessarily indicative of future performance.
40
ITEM 6. SELECTED FINANCIAL DATA
Statement of Operations (From Continuing Operations) (2):
Crude oil, natural gas, and NGLs sales
$
913.1
$
497.4
$
378.7
$
471.4
$
340.8
2017
Year Ended/As of December 31,
2014
2015
(in millions, except per share data and as noted)
2016 (1)
2013
Commodity price risk management gain (loss), net
Total revenues
Income (loss) from continuing operations
Earnings per share from continuing operations:
Basic
Diluted
Statement of Cash Flows:
Net cash flows from:
Operating activities
Investing activities
Financing activities
Capital expenditures from development and exploration activities (3)
Acquisitions of crude oil and natural gas properties, including
settlement adjustments and deposit for pending acquisition
Balance Sheet:
Total assets
Working capital (deficit)
Total debt, net of unamortized discount and debt issuance costs
Total equity
Average Pricing and Production Expenses From Continuing
Operations (per Boe and as a percent of sales for production
taxes):
Sales price (excluding net settlements on derivatives)
Lease operating expenses
Transportation, gathering, and processing
Production taxes
Production taxes as a percent of sales
Production (MBoe):
Production from continuing operations
Production from discontinued operations
Total production
(3.9)
921.6
(127.5)
(125.7)
382.9
(245.9)
$
(1.94)
(1.94)
(5.01)
(5.01)
588.6
(717.0)
65.0
737.2
$
486.3
(1,509.1)
1,266.1
436.9
$
$
203.2
595.3
(68.3)
(1.74)
(1.74)
411.1
(604.3)
178.0
599.5
$
$
310.3
856.2
107.3
3.00
2.93
236.7
(474.1)
60.3
623.8
$
$
(23.9)
392.7
(21.1)
(0.65)
(0.65)
159.2
(217.1)
248.7
384.7
$
$
15.6
1,073.7
—
—
9.7
$ 4,419.9
(16.4)
1,151.9
2,507.6
$ 4,485.8
129.2
1,044.0
2,622.8
$ 2,370.5
30.7
642.4
1,287.2
$ 2,331.1
89.5
655.5
1,137.4
$ 1,991.7
90.0
593.9
967.6
$
$
$
$
28.69
2.82
1.04
1.91
$
$
$
$
22.43
2.70
0.83
1.42
$
$
$
$
24.64
3.71
0.66
1.20
$
$
$
$
50.72
4.56
0.49
2.76
$
$
$
$
52.23
5.18
0.79
3.33
6.6%
6.3%
4.9%
5.4%
6.4%
31,830
—
31,830
22,176
—
22,176
15,369
—
15,369
9,294
1,093
10,387
6,525
2,032
8,557
Total proved reserves (MMBoe) (4)
452.9
341.4
272.8
250.1
265.8
______________
(1) In 2016, we closed an acquisition in the Delaware Basin for aggregate consideration of approximately $1.76 billion. See footnotes
titled Properties and Equipment - Delaware Basin Acreage Acquisition and Business Combination to our consolidated financial
statements included elsewhere in this report for further information regarding this acquisition.
(2) In 2014, we completed the sale of our ownership interest in PDC Mountaineer, LLC ("PDCM"). Our proportionate share of
PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations.
(3) Includes impact of change in accounts payable related to capital expenditures.
(4) Includes total proved reserves related to our Marcellus Shale and shallow Upper Devonian Appalachian Basin assets of 40 MMBoe
as of December 31, 2013. PDCM, which owned these reserves, was sold in late 2014.
41
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
The following discussion and analysis should be read in conjunction with our consolidated financial statements and
related notes thereto included elsewhere in this report. Further, we encourage you to revisit the Special Note Regarding
Forward-Looking Statements in Part I of this report.
SUMMARY
2017 Financial Overview of Operations and Liquidity
Production volumes increased 44 percent to 31.8 MMBoe in 2017 compared to 2016, including 4.2 MMBoe
contributed from the Delaware Basin assets that we acquired in December 2016. The increase in production volumes was
primarily attributable to the continued success of our horizontal Niobrara and Codell drilling program in the Wattenberg Field
and growing production from our horizontal Wolfcamp drilling program in our Delaware Basin properties. Crude oil
production increased 48 percent in 2017, which comprised approximately 41 percent of our total production. Natural gas
production increased 39 percent and NGLs increased 45 percent in 2017 compared to 2016. On a combined basis, total liquids
production of crude oil and NGLs comprised 62 percent of production in 2017. For the month ended December 31, 2017, we
maintained an average production rate of approximately 97,000 Boe per day, including approximately 18,000 Boe per day from
the Delaware Basin, up from approximately 73,200 Boe per day, including approximately 6,000 Boe per day from the Delaware
Basin, for the month ended December 31, 2016.
Crude oil, natural gas, and NGLs sales increased to $913.1 million in 2017 compared to $497.4 million in 2016, due to
a 44 percent increase in production, combined with a 28 percent increase in the weighted average realized commodity prices.
Crude oil, natural gas, and NGLs sales increased 31 percent in 2016 as compared to 2015 due to a 44 percent increase in
production, partially offset by a nine percent decrease in average realized commodity prices.
We had positive net settlements from our commodity derivative contracts of $13.3 million for 2017, $208.1 million for
2016, and $238.9 million for 2015. We entered into agreements for the derivative instruments that settled throughout 2016 and
2015 prior to commodity prices becoming depressed in late 2014. Substantially all of these higher-value derivatives settled by
the end of 2016. Net settlements for 2017 reflect derivative instruments entered into since 2015, which more closely
approximate recent realized prices. See Results of Operations - Commodity Price Risk Management, Net for further details of
our settlements of derivatives and changes in the fair value of unsettled derivatives.
The combined revenue from crude oil, natural gas, and NGLs sales and net settlements received on our commodity
derivative instruments increased 31 percent to $926.4 million in 2017 from $705.5 million in 2016. Such combined revenue of
$705.5 million in 2016 increased 14 percent from $617.6 million in 2015.
During 2017, we recorded exploratory dry hole well expense of $41.3 million and an unproved and proved property
impairment charge of $285.5 million, and we impaired all of the goodwill associated with the assets acquired in the Delaware
Basin, which resulted in an impairment charge of $75.1 million. The majority of these charges are a result of our western
Culberson County acreage not meeting our performance expectations. In addition, we recorded a loss on extinguishment of
debt of $24.7 million related to the redemption of our 2022 Senior Notes. For more information regarding these expenses and
charges see Results of Operations - Exploration, Geologic, and Geophysical Expense, Results of Operations - Impairments of
Properties, Results of Operations - Impairment of Goodwill, and Results of Operations - Loss on Extinguishment of Debt.
In December 2017, the President of the United States signed into law the 2017 Tax Cuts and Jobs Act (the "2017 Tax
Act"). We recorded the effects of changes in tax law in the period of enactment. The 2017 Tax Act reduces the corporate tax
rate from 35 percent to 21 percent effective January 1, 2018. Consequently, we have decreased our deferred tax assets and
deferred tax liabilities as of December 31, 2017. Since we are in a net deferred liability position at 2017 year end, the tax rate
change resulted in a deferred tax benefit and corresponding reduction of our net deferred tax liability of approximately $114
million in 2017.
42
In 2017, we generated a net loss of $127.5 million or $1.94 per diluted share. Our net income was negatively
impacted by the aforementioned impairment charges, expensing of exploratory dry hole well costs, and extinguishment of
debt. During the same period, our adjusted EBITDAX, a non-U.S. GAAP financial measure, was $682.1 million, up 48
percent relative to 2016. The increase in our 2017 adjusted EBITDAX as compared to 2016 was primarily the result of the
increase in crude oil, natural gas, and NGLs sales of $415.7 million, as well as the recording of a provision for a note
receivable in 2016 of $44.0 million and the subsequent sale of the note in 2017 to a third-party for $40.2 million. These
increases were partially offset by a decrease in derivative commodity settlements of $194.8 million and increases in
operating costs of $81.7 million and interest expense of $16.7 million. Beginning in 2017, we have included non-cash
stock-based compensation and exploration, geologic, and geophysical expense in our reconciliation of adjusted EBITDAX.
In prior periods, we reported adjusted EBITDA, a non-U.S. GAAP financial measure that did not include these adjustments.
All prior periods have been conformed for comparability of this updated EBITDAX presentation. In 2016 and 2015, our net
loss per diluted share was $5.01 and $1.74, respectively, and our adjusted EBITDAX was $459.8 million and $464.3
million, respectively. Our net cash flows from operating activities in 2017, 2016, and 2015 were $588.6 million, $486.3
million, and $411.1 million, respectively, and our adjusted cash flow from operations, a non-U.S. GAAP financial measure,
were $582.1 million, $466.8 million, and $420.8 million, respectively. See Reconciliation of Non-U.S. GAAP Financial
Measures, below, for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these
measures to the most comparable U.S. GAAP measures.
Liquidity
Available liquidity as of December 31, 2017 was $880.7 million, which was comprised of $180.7 million of cash
and cash equivalents and $700.0 million available for borrowing under our revolving credit facility at our current
commitment level. In October 2017, we entered into a Sixth Amendment to the Third Amended and Restated Credit
Agreement. The amendment allowed the borrowing base to be set above the $1.0 billion borrowing capacity of the facility.
The borrowing base for our November 2017 redetermination was confirmed at $1.1 billion and we elected to maintain a
$700 million commitment level. Assuming that the Bayswater Acquisition had closed in December 2017, our liquidity
position as of December 31, 2017, would have been approximately $700 million.
In November 2017, we issued $600 million principal amount of our 2026 Senior Notes. The net proceeds from the
offering were used to fund the redemption of our $500 million 2022 Senior Notes and a portion of the purchase price of the
January 2018 Bayswater Acquisition, and for general corporate purposes.
We intend to continue to manage our liquidity position by a variety of means, including through the generation of
cash flows from operations, investment in projects with attractive rates of return, protection of cash flows on a portion of our
anticipated sales through the use of an active commodity derivative hedging program, potential utilization of our borrowing
capacity under our revolving credit facility, and if warranted, capital markets transactions from time to time.
Acquisition
On January 5, 2018, we closed the Bayswater Acquisition for approximately $186 million, subject to certain
customary post-closing adjustments. In addition to the approximately $186 million of cash paid at closing, we invested
approximately $15 million during 2017 to complete certain DUCs acquired in the transaction.
Acreage Exchanges
In 2017, we completed two significant acreage exchanges that consolidated certain acreage positions in the core area
of the Wattenberg Field. Both transactions involved the exchange of leasehold acreage with a limited number of wells that
were in the process of being drilled and completed. Upon closing the transactions, we received an aggregate of approximately
15,900 net acres in exchange for an aggregate of approximately 16,200 net acres. The difference in net acres is primarily due to
variances in working and net revenue interests and midstream contracts.
43
2017 Drilling Overview
During the year ended December 31, 2017, we continued to execute our strategic plan to grow production while
preserving our financial strength and liquidity. Our drilling efficiency in the Wattenberg Field over the last year has resulted in
shorter drill times; as a result, we decreased our rig count from four to three in the fourth quarter of 2017. Due to the decreased
drill times, the impact of the reduced rig count on our expected turn-in-line count in the Wattenberg Field was minimal in 2017.
During the three months ended December 31, 2017, we briefly ran four rigs in the Delaware Basin as we swapped out rigs to
focus on improving drill times. During the fourth quarter of 2017, we turned-in-line 19 wells in the Wattenberg Field and five
wells in the Delaware Basin. We did not complete or turn-in-line any wells in the Utica Shale during 2017.
The following tables summarizes our drilling and completion activity for the year ended December 31, 2017:
In-process as of December 31, 2016
Wells spud
Wells turned-in-line
Exploratory dry holes
In-process as of December 31, 2017
In-process as of December 31, 2016
Wells spud
Wells turned-in-line
Wells interest exchanged
Exploratory dry holes
In-process as of December 31, 2017
Wattenberg Field
Net
Gross
64
153
(130)
—
87
52.7
140.2
(112.8)
—
80.1
Wells Operated by PDC
Delaware Basin
Net
Gross
Total
Gross
5
26
(16)
(2)
13
4.8
22.7
(15.2)
(2.0)
10.3
69
179
(146)
(2)
100
Net
57.5
162.9
(128.0)
(2.0)
90.4
Wattenberg Field
Gross
Net
18
94
(12)
(85)
(1)
14
3.4
13.1
(1.6)
(12.2)
(0.1)
2.6
Wells Operated by Others
Delaware Basin
Net
Gross
Total
Gross
Net
—
10
(2)
—
—
8
—
1.5
(0.4)
—
—
1.1
18
104
(14)
(85)
(1)
22
3.4
14.5
(2.0)
(12.2)
(0.1)
3.6
Our in-process wells represent wells that are in the process of being drilled and/or have been drilled and are waiting to
be fractured and/or for gas pipeline connection. Our DUCs are generally completed and turned-in-line within three to nine
months of drilling. The majority of the PDC-operated in-process wells at each period end are DUCs, as we do not begin the
completion process until the entire well pad is drilled. All appropriate costs incurred through the end of the period have been
capitalized, while the capital investment to complete the wells will be incurred in the period in which the wells are completed.
2018 Operational and Financial Outlook
We expect our production for 2018 to range between 38 MMBoe to 42 MMBoe, or approximately 104,000 Boe to
115,000 Boe per day for the year. We expect that approximately 42 to 45 percent of our 2018 production will be comprised of
crude oil and approximately 19 to 22 percent will be NGLs, for total liquids of approximately 64 to 67 percent. Our 2018
capital forecast of between $850 million and $920 million is focused on continued execution in the Wattenberg Field and
Delaware Basin with three drilling rigs and one completion crew in each basin throughout the year.
We believe that we maintain significant operational flexibility to control the pace of our capital spending. As we
execute our capital investment program, we continually monitor, among other things, commodity prices, development costs,
midstream capacity, and offset and continuous drilling obligations. Should commodity pricing or the operating environment
deteriorate, we may determine that an adjustment to our development plan is appropriate. We believe we have ample
opportunities to reduce capital spending in order to stay within the range of our capital investment plan, including but not
limited to reducing the number of rigs being utilized in our drilling program and/or managing our completion schedule. This
flexibility is more limited in the Delaware Basin given leasehold maintenance requirements.
44
Wattenberg Field. We are drilling in the Niobrara and Codell plays within the field and anticipate spudding and
turning-in-line between approximately 135 to 150 operated wells in 2018. Our 2018 capital investment program is estimated to
be approximately $470 million to $500 million in the Wattenberg Field, of which approximately 90 percent is anticipated to be
invested in operated drilling and completion activity. The remainder of the Wattenberg Field capital investment program is
expected to be used for non-operated wells and miscellaneous workover and capital projects.
Delaware Basin. Total capital investment in the Delaware Basin in 2018 is estimated to be approximately $380
million to $420 million, of which approximately 75 percent is allocated to both spud and turn-in-line approximately 25 to 30
operated wells targeting the Wolfcamp formation. Based on the timing of our operations and requirements to hold acreage, we
may adapt our capital investment program to drill wells different from or in addition to those currently anticipated, as we are
continuing to analyze the terms of the relevant leases. We plan to invest approximately 10 percent of our capital in leasing,
non-operated capital, seismic, and technical studies with an additional approximately 15 percent for midstream related projects
including oil and gas gathering systems and water supply and disposal systems.
Utica Shale. In 2017, as part of plans to divest the Utica Shale properties, we engaged an investment banking firm and
began actively marketing the properties for sale; therefore, these properties are classified as held-for-sale as of December 31,
2017. In February 2018, we entered into a definitive PSA to sell these properties for net cash proceeds of approximately $40.0
million. The transaction is expected to close in the first quarter of 2018, subject to certain customary closing conditions.
Financial Guidance. Based on our current production forecast for 2018 and assuming averages of approximately
$57.50 NYMEX crude oil price for the year and a $3.00 NYMEX natural gas price, we expect 2018 capital investments to
exceed our 2018 cash flows from operations by approximately less than $90 million. We anticipate that the proceeds received
from the sale of our Utica Shale assets and a midstream dedication agreement (see the footnote titled Subsequent Events to the
consolidated financial statements included elsewhere in this report), will fund approximately two-thirds of this outspend. We
expect this capital investment outspend to occur during the first half of 2018, with cash flows exceeding capital investment
during the second half of the year. Our leverage ratio, as defined in our revolving credit facility agreement, is expected to
decrease in 2018 to 1.4 based on production and operational cash flow growth.
The following table provides projected financial guidance for 2018:
Operating Expenses
Lease operating expenses ($/Boe)
Transportation, gathering, and processing expenses ("TGP") ($/Boe)
Production taxes (% of crude oil, natural gas, and NGL sales)
General and administrative expense ($/Boe)
Estimated Price Realizations (% of NYMEX, excludes TGP)
Crude oil
Natural gas
NGLs
Low
High
$
$
$
2.75
0.60
6%
3.40
$
$
$
3.00
0.80
8%
3.70
91%
55%
30%
95%
60%
35%
45
Results of Operations
Summary Operating Results
The following table presents selected information regarding our operating results from continuing operations:
Year Ended December 31,
2017
2016
(dollars in millions, except per unit data)
2015
Percent Change
2017-2016
2016-2015
Production
Crude oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)
Crude oil equivalent (MBoe)
Average Boe per day (Boe)
Crude Oil, Natural Gas and NGLs Sales
Crude oil
Natural gas
NGLs
Total crude oil, natural gas, and NGLs sales
Net Settlements on Commodity Derivatives
Crude oil
Natural gas
NGLs (propane portion)
Total net settlements on derivatives
Average Sales Price (excluding net settlements on derivatives)
Crude oil (per Bbl)
Natural gas (per Mcf)
NGLs (per Bbl)
Crude oil equivalent (per Boe)
Average Costs and Expenses (per Boe)
Lease operating expenses
Production taxes
Transportation, gathering, and processing expenses
General and administrative expense
Depreciation, depletion, and amortization
Lease Operating Expenses by Operating Region (per Boe)
Wattenberg Field
Delaware Basin
Utica Shale (1)
12,902
71,689
6,981
31,830
87,206
8,728
51,730
4,826
22,176
60,590
6,984
33,302
2,835
15,369
42,108
625.0
158.3
129.8
913.1
$
$
(2.7) $
23.3
(7.3)
13.3
$
$
$
$
48.45
2.21
18.59
28.69
2.82
1.91
1.04
3.78
14.74
2.48
5.16
1.66
$
$
$
$
$
$
$
348.9
91.6
56.9
497.4
165.2
42.9
—
208.1
39.96
1.77
11.80
22.43
2.70
1.42
0.83
5.07
18.80
2.70
8.79
1.75
280.3
68.0
30.4
378.7
208.9
30.0
—
238.9
40.14
2.04
10.72
24.64
3.71
1.20
0.66
5.85
19.73
3.78
*
2.78
$
$
$
$
$
$
$
47.8 %
38.6 %
44.7 %
43.5 %
43.9 %
79.1 %
72.8 %
128.1 %
83.6 %
(101.6)%
(45.7)%
*
(93.6)%
21.2 %
24.9 %
57.5 %
27.9 %
4.4 %
34.5 %
25.3 %
(25.4)%
(21.6)%
(8.1)%
(41.3)%
(5.1)%
25.0 %
55.3 %
70.2 %
44.3 %
43.9 %
24.5 %
34.7 %
87.2 %
31.3 %
(20.9)%
43.0 %
*
(12.9)%
(0.4)%
(13.2)%
10.1 %
(9.0)%
(27.2)%
18.3 %
25.8 %
(13.3)%
(4.7)%
(28.6)%
*
(37.1)%
Percentage change is not meaningful or equal to or greater than 300% or not applicable.
*
Amounts may not recalculate due to rounding.
______________
(1) In February 2018, we entered into a PSA to sell the Utica Shale properties.
46
Crude Oil, Natural Gas, and NGLs Sales
The year-over-year change in crude oil, natural gas, and NGLs sales revenue were primarily due to the following:
Year Ended December 31,
2016
2017
Increase in production
Increase (decrease) in average crude oil price
Increase (decrease) in average natural gas price
Increase in average NGLs price
Total increase in crude oil, natural gas and NGLs sales revenue
$
$
$
(in millions)
227.5
109.6
31.2
47.4
415.7
$
129.0
(1.6)
(14.0)
5.2
118.6
Crude Oil, Natural Gas, and NGLs Production
The following tables present crude oil, natural gas, and NGLs production. Our acquisition of assets in the Delaware
Basin closed in December 2016; therefore, there is no comparative data for 2015.
Production by Operating Region
2017
2016
2015
2017-2016
2016-2015
Year Ended December 31,
Change
Crude oil (MBbls)
Wattenberg Field
Delaware Basin
Utica Shale (1)
Total
Natural gas (MMcf)
Wattenberg Field
Delaware Basin
Utica Shale (1)
Total
NGLs (MBbls)
Wattenberg Field
Delaware Basin
Utica Shale (1)
Total
Crude oil equivalent (MBoe)
Wattenberg Field
Delaware Basin
Utica Shale (1)
Total
Average crude oil equivalent per day (Boe)
Wattenberg Field
Delaware Basin
Utica Shale (1)
Total
10,922
1,699
281
12,902
60,106
9,410
2,173
71,689
5,876
917
188
6,981
26,815
4,184
831
31,830
73,466
11,463
2,277
87,206
8,230
79
419
8,728
48,889
373
2,468
51,730
4,568
36
222
4,826
20,945
178
1,053
22,176
57,227
486
2,877
60,590
6,490
—
494
6,984
30,753
—
2,549
33,302
2,616
—
219
2,835
14,231
—
1,138
15,369
38,990
—
3,118
42,108
32.7 %
*
(32.9)%
47.8 %
22.9 %
*
(12.0)%
38.6 %
28.6 %
*
(15.3)%
44.7 %
28.0 %
*
(21.1)%
43.5 %
28.4 %
*
(20.9)%
43.9 %
26.8 %
*
(15.2)%
25.0 %
59.0 %
*
(3.2)%
55.3 %
74.6 %
*
1.4 %
70.2 %
47.2 %
*
(7.5)%
44.3 %
46.8 %
*
(7.7)%
43.9 %
*Percentage change is not meaningful or equal to or greater than 300%.
Amounts may not recalculate due to rounding.
______________
(1) In February 2018, we entered into a PSA to sell the Utica Shale properties.
47
In the Wattenberg Field, we rely on third-party midstream service providers to construct gathering, compression,
and processing facilities to keep pace with our and the overall field's natural gas production growth. In 2017 and during
2018, our production has been adversely affected by high line pressures on the gas gathering facilities, primarily due to
increases in field-wide production volumes. As a result, we experienced some production curtailments during the second
half of 2017. The gathering system of our primary midstream service provider, DCP Midstream, LP ("DCP"), is currently at
capacity. We believe that our 2018 production guidance range appropriately reflects the impact of anticipated gathering
system line pressures and the resulting temporary limitations on the gathering system’s capacity, but curtailments may be
greater than anticipated. For 2017, 94 percent of our production in the Wattenberg Field was delivered from horizontal
wells, with the remaining six percent coming from vertical wells. The horizontal wells are less prone to curtailments than
the vertical wells because they are newer and have greater producing capacity and higher formation pressures and therefore
tend to be more resilient to gas system pressure issues; however, all of our wells in the field are currently experiencing some
impact. We expect to continue to operate in a constrained environment into the third quarter of 2018, at which time
additional processing capacity is scheduled to be brought into operation by DCP.
We continue to work closely with our third-party midstream providers in an effort to ensure that adequate
midstream system capacity is available going forward in the Wattenberg Field. We, along with other operators, have made a
commitment with DCP to support its construction of two additional processing facilities with associated gathering pipe and
compression in the field. These expansions are expected to increase DCP's system capacity, assist in the control of line
pressures on its natural gas gathering facilities, and reduce production curtailments in the field. We will be bound to the
incremental volume requirements in these agreements on the first day of the calendar month after the actual in-service dates
of the plants for a period of seven years, which are currently scheduled to occur in the third quarter of 2018 and in the
second quarter of 2019, respectively. The agreements impose a baseline volume commitment and guarantee a certain target
profit margin to DCP on those volumes during the initial three years of the contracts. Under our current drilling plans, we
expect to meet both the baseline and incremental volume commitments, and we believe that the contractual target profit
margin will be achieved without additional payment from us. See the footnote titled Commitments and Contingencies to our
consolidated financial statements included elsewhere in this report for additional details regarding the agreements. In
addition, we have begun early discussions with DCP with respect to further increasing its processing facilities in the
Wattenberg Field. We also continue to work with all of our midstream service providers in the field in an effort to ensure all
of the existing infrastructure is fully utilized and that all options for system expansions are evaluated and implemented,
where possible. The ultimate timing and availability of adequate infrastructure is not within our control and if our
midstream service providers' construction projects are delayed, we could experience higher gathering line pressures that
would negatively impact our ability to meet our production targets.
48
Crude Oil, Natural Gas, and NGLs Pricing
Our results of operations depend upon many factors. Key factors include the price of crude oil, natural gas, and
NGLs and our ability to market our production effectively. Crude oil, natural gas, and NGL prices have a high degree of
volatility and our realizations can change substantially. Our sales prices for crude oil, natural gas, and NGLs increased
during 2017 compared to 2016. NYMEX crude oil prices increased 18 percent and NYMEX natural gas prices increased 26
percent as compared to 2016. Our sales prices for crude oil and natural gas decreased and prices for NGLs increased during
2016 compared to 2015. NYMEX crude oil prices decreased 12 percent and NYMEX natural gas prices decreased 8 percent
as compared to 2015. The majority of our NGL prices in the Wattenberg Field are reflected in the tables below, net of the
processing and transport costs that are embedded in the applicable percent-of-proceeds contracts.
The following tables present weighted-average sales prices of crude oil, natural gas, and NGLs for the periods
presented. Our acquisition of assets in the Delaware Basin closed in December 2016; therefore, there is no comparative data
for 2015:
Weighted-Average Sales Price by Operating Region
(excluding net settlements on derivatives)
Year Ended December 31,
Change
2017
2016
2015
2017-2016
2016-2015
Crude oil (per Bbl)
Wattenberg Field
Delaware Basin
Utica Shale (1)
Weighted-average price
Natural gas (per Mcf)
Wattenberg Field
Delaware Basin
Utica Shale (1)
Weighted-average price
NGLs (per Bbl)
Wattenberg Field
Delaware Basin
Utica Shale (1)
Weighted-average price
Crude oil equivalent (per Boe)
Wattenberg Field
Delaware Basin
Utica Shale (1)
Weighted-average price
$
$
48.48
48.68
45.63
48.45
2.19
2.26
2.40
2.21
17.75
22.64
25.06
18.59
28.55
29.80
27.36
28.69
$
39.99
49.28
37.62
39.96
1.77
2.78
1.58
1.77
11.59
17.87
15.11
11.80
22.38
31.50
21.88
22.43
40.03
—
41.59
40.14
2.06
—
1.85
2.04
10.58
—
12.43
10.72
24.64
—
24.59
24.64
21.2 %
(1.2)%
21.3 %
21.2 %
23.7 %
(18.7)%
51.9 %
24.9 %
53.1 %
26.7 %
65.9 %
57.5 %
27.6 %
(5.4)%
25.0 %
27.9 %
(0.1)%
*
(9.5)%
(0.4)%
(14.1)%
*
(14.6)%
(13.2)%
9.5 %
*
21.6 %
10.1 %
(9.2)%
*
(11.0)%
(9.0)%
* Percentage change is not meaningful or equal to or greater than 300%.
Amounts may not recalculate due to rounding.
______________
(1) In February 2018, we entered into a PSA to sell the Utica Shale properties.
Our crude oil, natural gas, and NGLs sales are recorded using either the “net-back” or "gross" method of accounting,
depending upon the related purchase agreement. We use the net-back method when the purchasers of these commodities also
provide transportation, gathering, or processing services. In these situations, the purchaser pays us proceeds based on a percent
of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition
of a net sales price that is lower than the indices for which the production is based because the operating costs and profit of the
midstream facilities are embedded in the net price we are paid.
We use the gross method of accounting when the purchasers do not provide transportation, gathering, or processing
services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable
transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and
recognize transportation, gathering, and processing expenses.
49
The following table summarizes how we recognize revenue related to the sales of our crude oil, natural gas, and
NGLs:
Years Ended December 31, 2015 through 2017
Net-Back
Gross
Wattenberg Field
Crude oil
Natural gas
NGLs
Delaware Basin
Crude oil
Natural gas
NGLs
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No
Yes
Yes
No
As discussed above, we enter into agreements for the sale, transportation, gathering, and processing of our
production. The terms of these agreements can result in variances in the per unit realized prices that we receive for our crude
oil, natural gas and NGLs. Information related to the components and classifications in the consolidated statements of
operations is shown below. For crude oil, the average NYMEX prices shown below are based upon average daily prices
throughout each month and our natural gas average NYMEX pricing is based upon first-of-the-month index prices as this is
how the majority of each of these commodities are sold pursuant to terms of the respective sales agreements. For NGLs, we
use the NYMEX crude oil price as a reference for presentation purposes. For NGLs, the average realized price both before and
after transportation, gathering, and processing expenses shown in the table below represents our approximate composite per
barrel price.
Average
Realized Price
Before
Transportation,
Gathering and
Processing
Expenses
Average
Realization
Percentage
Before
Transportation,
Gathering and
Processing
Expenses
Average
NYMEX
Price
Average
Realized Price
After
Transportation,
Gathering and
Processing
Expenses
Average
Realization
Percentage
After
Transportation,
Gathering and
Processing
Expenses
Average
Transportation,
Gathering and
Processing
Expenses
2017
Crude oil (per Bbl)
$
50.95
$
Natural gas (per MMBtu)
NGLs (per Bbl)
Crude oil equivalent (per
Boe)
3.11
50.95
38.83
48.45
2.21
18.59
28.69
95% $
1.41
$
71%
36%
74%
0.17
0.30
1.04
47.04
2.04
18.29
27.65
92%
66%
36%
71%
We adopted a new revenue recognition accounting standard effective January 1, 2018. Under the guidance of the new
revenue recognition standard, certain crude oil sales in the Wattenberg Field that were recognized using the gross method prior
to the adoption of the new revenue standard will be recognized using the net-back method and in the Delaware Basin certain
crude oil and natural gas sales that were recognized using the gross method prior to the adoption of the new revenue standard
will be recognized using the net-back method. If we had adopted the standard on January 1, 2017, we estimate that the average
realization percentage before transportation, gathering, and processing expenses would have been 94 percent, 70 percent, 36
percent, and 73 percent for crude oil, natural gas, NGLs, and crude oil equivalent, respectively, as $11.3 million in expenses
currently recorded in transportation, gathering, and processing on our consolidated statements of operations would, in that case,
have been reflected as a reduction to the sales price. However, the net realized price would remain unchanged.
50
Average
Realized Price
Before
Transportation,
Gathering and
Processing
Expenses
Average
Realization
Percentage
Before
Transportation,
Gathering and
Processing
Expenses
Average
NYMEX
Price
Average
Realized Price
After
Transportation,
Gathering and
Processing
Expenses
Average
Realization
Percentage
After
Transportation,
Gathering and
Processing
Expenses
Average
Transportation,
Gathering and
Processing
Expenses
2016
Crude oil (per Bbl)
$
43.32
$
Natural gas (per MMBtu)
NGLs (per Bbl)
Crude oil equivalent (per
Boe)
2.46
43.32
32.22
39.96
1.77
11.80
22.43
92% $
72%
27%
70%
$
1.51
0.07
0.28
0.83
38.45
1.70
11.52
21.60
89%
69%
27%
67%
Average
Realized Price
Before
Transportation,
Gathering and
Processing
Expenses
Average
Realization
Percentage
Before
Transportation,
Gathering and
Processing
Expenses
Average
NYME
X Price
Average
Transportation,
Gathering and
Processing
Expenses
Average
Realized Price
After
Transportation,
Gathering and
Processing
Expenses
Average
Realization
Percentage
After
Transportation,
Gathering and
Processing
Expenses
2015
Crude oil (per Bbl)
$ 48.80
$
Natural gas (per MMBtu)
NGLs (per Bbl)
Crude oil equivalent (per
Boe)
2.66
48.80
36.94
40.14
2.04
10.72
24.64
Commodity Price Risk Management, Net
82% $
0.67
$
77%
22%
67%
0.12
0.55
0.66
39.47
1.92
10.17
23.98
81%
72%
21%
65%
We use commodity derivative instruments to manage fluctuations in crude oil and natural gas prices. We have in place
a variety of collars, fixed-price swaps, and basis swaps on a portion of our estimated crude oil, natural gas, and propane
production. Because we sell all of our crude oil, natural gas, and NGLs production at prices related to the indexes inherent in
our underlying derivative instruments, we ultimately realize value related to our collars of no less than the floor and no more
than the ceiling. For our commodity swaps, we ultimately realize the fixed price value related to our swaps. See the footnote
titled Commodity Derivative Financial Instruments for a detailed presentation of our derivative positions as of December 31,
2017.
Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments, as
well as the change in fair value of unsettled commodity derivatives related to our crude oil, natural gas, and propane
production. Commodity price risk management, net, does not include derivative transactions related to our gas marketing,
which are included in other income and other expenses.
Net settlements of commodity derivative instruments are based on the difference between the crude oil, natural gas,
and propane index prices at the settlement date of our commodity derivative instruments compared to the respective strike
prices. The net change in fair value of unsettled commodity derivatives is comprised of the net value increase or decrease in
the beginning-of-period fair value of commodity derivative instruments that settled during the period, and the net change in fair
value of unsettled commodity derivatives during the period or from inception of any new contracts entered into during the
applicable period. The net change in fair value of unsettled commodity derivatives during the period is primarily related to
shifts in the crude oil, natural gas, and NGLs forward curves and changes in certain differentials.
51
The following table presents net settlements and net change in fair value of unsettled commodity derivatives included
in commodity price risk management, net:
2017
Year Ended December 31,
2016
(in millions)
2015
Commodity price risk management gain (loss), net:
Net settlements of commodity derivative instruments:
Crude oil fixed price swaps and collars
Natural gas fixed price swaps and collars
Natural gas basis protection swaps
NGLs (propane portion) fixed price swaps
Total net settlements of commodity derivative instruments
Change in fair value of unsettled commodity derivative instruments:
Reclassification of settlements included in prior period changes in fair value of
commodity derivative instruments
Crude oil fixed price swaps, collars, and rollfactors
Natural gas fixed price swaps and collars
Natural gas basis protection swaps
NGLs (propane portion) fixed price swaps
Net change in fair value of unsettled commodity derivative instruments
Total commodity price risk management gain (loss), net
$
$
(2.7) $
19.5
3.8
(7.3)
13.3
44.8
(77.9)
14.7
5.7
(4.6)
(17.3)
(4.0) $
$
165.2
41.9
1.0
—
208.1
(220.0)
(78.6)
(37.1)
1.9
—
(333.8)
(125.7) $
208.9
31.0
(1.0)
—
238.9
(186.9)
99.3
53.3
(1.4)
—
(35.7)
203.2
Lease Operating Expenses
Lease operating expenses were $89.6 million in 2017 compared to $60.0 million in 2016. Aggregate lease operating
expenses during 2017 increased $29.6 million, of which $20.1 million related to our properties in the Delaware Basin. The
$29.6 million increase in the total lease operating expenses in 2017 as compared to 2016 was primarily due to increases of $9.4
million for payroll and employee benefits related to increases in headcount, $5.6 million for produced water disposal, $5.6
million for increased workover projects, $3.9 million related to additional compressor rentals, and $2.2 million for equipment
rentals. The increases were slightly offset by a $1.5 million decrease in environmental remediation costs. Lease operating
expense per Boe increased by four percent to $2.82 for 2017 from $2.70 for 2016, primarily due to expected higher per Boe
costs in the Delaware Basin compared to our other areas of operation.
Lease operating expenses were $60.0 million in 2016 compared to $57.0 million in 2015. The $3.0 million increase in
lease operating expenses in 2016 as compared to 2015 was primarily due to an increase of $3.7 million for increases in wages
and employee benefits related to an increase in headcount, including costs for additional contract labor, $1.8 million for
additional leased compressors to address line pressures, and an increase of $1.5 million related to lease operating expenses for
the acquisition in the Delaware Basin. These increases were partially offset by a decrease in environmental remediation and
regulatory compliance projects of $3.2 million due to a reduction in new remediation projects, and a decrease of $1.4 million
related to fewer workover and maintenance related projects. Lease operating expenses per Boe decreased significantly to $2.70
for 2016 from $3.71 in 2015 as a result of increased production.
Production Taxes
Production taxes were $60.7 million, $31.4 million, and $18.4 million in 2017, 2016, and 2015, respectively.
Production taxes are comprised mainly of severance tax and ad valorem tax and are directly related to crude oil, natural gas,
and NGLs sales as the taxes are generally assessed as a percentage of net revenues. From time to time, there are adjustments to
the statutory rates for these taxes based upon certain credits that are determined based upon activity levels and relative
commodity prices from year to year. The $29.3 million and $13.0 million increases in production taxes during 2017 and 2016,
respectively, were primarily related to the 84 percent and 31 percent increases in crude oil, natural gas, and NGLs sales in 2017
and 2016, respectively, and to a lesser extent, an increase in tax rates. Our overall production tax rates were 6.6 percent, 6.3
percent, and 4.9 percent in 2017, 2016, and 2015, respectively.
52
Transportation, Gathering and Processing Expenses
Transportation expenses were $33.2 million in 2017 compared to $18.4 million in 2016. The increase was mainly
attributable to a $5.0 million increase in oil transportation costs due to additional volumes delivered through pipelines in the
Wattenberg Field and an increase of $9.7 million related to natural gas gathering and transportation operations in the Delaware
Basin. Transportation expenses were $18.4 million in 2016 compared to $10.2 million in 2015. The increase was mainly
attributable to the costs associated with certain pipelines in the Wattenberg Field as we began delivering crude oil on these
pipelines in July and December 2015, respectively. Transportation, gathering, and processing expenses per Boe increased to
$1.04 for 2017 compared to $0.83 for 2016 and $0.66 for 2015. As discussed in — Crude Oil, Natural Gas, and NGLs
Pricing, whether transportation, gathering, and processing costs are presented separately or are reflected as a reduction to net
revenue is a function of the terms of the relevant marketing contract. The tables at the end of that section show our net realized
prices for the periods shown after the relevant costs are deducted, regardless of where those costs appear on our income
statement (see in particular the columns titled “Average Realized Price After Transportation, Gathering and Processing
Expenses” and “Average Realization Percentage After Transportation, Gathering and Processing Expenses”). We expect that
our transportation, gathering, and processing expenses will decrease beginning in 2018 with the adoption of a new revenue
recognition standard as a portion of our current transportation, gathering, and processing expense will be recorded as a
reduction to the sales price.
Exploration, Geologic, and Geophysical Expense
The following table presents the major components of exploration, geologic, and geophysical expense:
Exploratory dry hole costs
Geological and geophysical costs
Operating, personnel and other
Total exploration expense
2017
Year Ended December 31,
2016
(in millions)
2015
$
$
41.3
3.9
2.1
47.3
$
$
— $
3.5
1.2
4.7
$
—
—
1.1
1.1
Exploratory dry hole costs. During 2017, two exploratory dry hole wells, associated lease costs, and related
infrastructure assets in the Delaware Basin were expensed at a cost of $41.3 million. The conclusion to expense these items
was based on our determination that the acreage on which these wells were drilled was exploratory in nature and, following
drilling, that the hydrocarbon production was insufficient for the wells to be deemed economically viable.
Geological and geophysical costs. Geological and geophysical costs in 2017 and 2016 were primarily related to the
portion of the purchase of seismic data related to unproved acreage in the Delaware Basin.
53
Impairment of Properties and Equipment
The following table sets forth the major components of our impairments of properties and equipment expense:
Year Ended December 31,
2017
2016
(in millions)
2015
Impairment of proved and unproved properties
Amortization of individually insignificant unproved properties
Land and buildings
Total impairment of properties and equipment
$
$
285.5
$
0.4
—
$
5.6
1.4
3.0
285.9
$
10.0
$
154.6
7.0
—
161.6
Impairment of proved and unproved properties. Amounts represent the retirement or expiration of certain leases that
are no longer part of our development plan or that we do not plan to extend and will allow to expire. Deterioration of
commodity prices or other operating circumstances could result in additional impairment charges.
During 2017, we recorded a charge related to two exploratory dry holes we had drilled in the western area of our
Culberson County acreage in the Delaware Basin, as referenced previously. We then assessed the impact of the dry holes and
various factors related thereto, including (i) the operational and geologic data obtained, (ii) the current increased cost
environment for drilling and completion services in the Delaware Basin, (iii) our future commodity price outlook, and (iv) the
terms of the related lease agreements. Based on the results of this assessment, we concluded that the underlying geologic risk
and the challenged economics of future capital expenditures reduced the likelihood that we would perform future development
in this area over the remaining lease term for this acreage. Accordingly, we recorded an impairment of $251.6 million covering
approximately 13,400 acres during 2017. The amount of the impairment was based on the value assigned to individual lease
acres in the final purchase price allocation of our Delaware Basin acquisition. This allocation included the consideration paid
to the sellers, including the effect of the non-cash impact from the deferred tax liability created at the time of the acquisition.
We recorded approximately $29 million of additional lease impairments in the Delaware Basin and an impairment charge of
$2.1 million related to the Utica Shale properties that are classified as held-for-sale during 2017. Due to the aforementioned
events and circumstances, we also evaluated our proved property for possible impairment and concluded that no further
impairments were necessary at this time.
During 2015, due to a significant decline in commodity prices and decreases in our net realized sales prices, we
experienced triggering events that required us to assess our crude oil and natural gas properties for possible impairment. As a
result of our assessments, we recorded impairment charges of $150.3 million in 2015 to write-down our Utica Shale proved and
unproved properties. Of these impairment charges, $24.7 million were recorded in 2015 to write-down certain capitalized well
costs on our Utica Shale proved producing properties. In 2015, we also recorded impairment charges of $125.6 million to write-
down our Utica Shale lease acquisition costs. The impairment charges, which are included in the consolidated statements of
operations line item impairment of properties and equipment, represented the amount by which the carrying value of these
crude oil and natural gas properties exceeded the estimated fair values.
Amortization of individually insignificant unproved properties. The decrease in 2016 as compared to 2015 is due to
the impairment of leases in the Utica Shale in 2015.
Impairment of Goodwill
The final goodwill that resulted from the purchase price allocation of the assets acquired in the Delaware Basin was
determined to be $75.1 million. With the creation of goodwill from this transaction, we expected to perform our evaluation of
goodwill for impairment annually in the fourth quarter. However, primarily due to a combination of increases in per well
development and operational costs and our drilling of two exploratory dry holes in the Delaware Basin subsequent to the
acquisition, in conjunction with our lower future commodity price outlook, we determined that a triggering event had occurred
in the quarter ended September 30, 2017. In addition to the factors mentioned above, we also considered our recent
impairments of certain unproven leasehold costs and the impact of these items on our internal expectations for acceptable rates
of return. We evaluated goodwill for impairment by performing a quantitative test, which involves comparing the estimated
fair value of the goodwill reporting unit, which we define as the Delaware Basin, to the carrying value. We determined the fair
54
value of the goodwill at September 30, 2017 by using an estimated after-tax future discounted cash flow analysis, along with a
combination of market-based pricing factors for similar acreage, reserve valuation techniques, and other fair value
considerations. The discounted cash flow analysis used to estimate fair value was based on known or knowable information at
the interim measurement date. Fair value determinations require considerable judgment and are sensitive to changes in
underlying assumptions and factors. The quantitative test resulted in a determination that a full impairment charge of $75.1
million was required; therefore, the charge was recorded in third quarter of 2017.
General and Administrative Expense
General and administrative expense increased $7.9 million, or seven percent, in 2017 compared to 2016. The increase
was primarily attributable to an $8.1 million increase in payroll and employee benefits due to an increase in headcount in 2017
as compared to 2016, $4.4 million related to professional services, $4.2 million related to legal expenses, $1.4 million related to
software license and maintenance agreements, and $1.3 million for the rental of additional office space. The increases were
partially offset by the $12.2 million of legal and professional fees related to the acquisition in the Delaware Basin that were
incurred in 2016.
General and administrative expense increased $22.5 million, or 25 percent, in 2016 compared to 2015. The increase in
cash based general and administrative costs was primarily attributable to $12.2 million of legal and professional fees related to
the acquisition in the Delaware Basin and a $7.7 million increase in payroll and employee benefits due to increases in wages
and increases in headcount.
Depreciation, Depletion, and Amortization
Crude oil and natural gas properties. During 2017, 2016, and 2015, we invested $788.0 million, $396.4 million, and
$554.3 million, net of changes in accounts payable related to capital expenditures, in the development of our crude oil and
natural gas properties, respectively. We also incurred $1.76 billion to acquire reserves during 2016 in the Delaware Basin. We
did not invest in any acquisitions of proved reserves in 2015. DD&A expense related to crude oil and natural gas properties is
directly related to proved reserves and production volumes. DD&A expense related to crude oil and natural gas properties was
$462.5 million, $413.1 million, and $298.8 million in 2017, 2016, and 2015, respectively. The year-over-year changes in
DD&A expense related to crude oil and natural gas properties were primarily due to the following:
Increase in production
Decrease in weighted-average depreciation, depletion and amortization rates
Total increase in DD&A expense related to crude oil and natural gas properties
Year Ended December 31,
2017 - 2016
2016 - 2015
(in millions)
144.7
(95.3)
49.4
$
$
132.3
(18.0)
114.3
$
$
The following table presents our DD&A expense rates for crude oil and natural gas properties:
Operating Region/Area
2017
Wattenberg Field
Delaware Basin (1)
Utica Shale (2)
Total weighted-average
____________
$
Year Ended December 31,
2016
(per Boe)
2015
$
14.67
14.89
8.09
14.53
$
19.11
8.34
10.66
18.63
20.13
—
10.74
19.44
(1) The 2016 Delaware Basin rate represents one month of DD&A expense. Accordingly, the comparison of the 2017 rate
to the 2016 rate is not meaningful.
(2) In February 2018, we entered into a PSA to sell the Utica Shale properties.
55
The 2017 rate in the Wattenberg Field decreased as compared to the 2016 rate due to a decrease in per well
development costs, and an increase in 2017 year-end reserves. The slight decrease in the Wattenberg Field rate for 2016 as
compared to 2015 was primarily due to the impact of our 2016 year-end reserves.
Provision for Uncollectible Notes Receivable
In 2016, we recorded a provision for uncollectible notes receivable of $44.0 million to impair two third-party notes
receivable whose collection was not reasonably assured. As described in the footnote titled Note Receivable included
elsewhere in this report, in April 2017, we signed a definitive agreement and simultaneously closed on the sale of one of the
associated notes receivable to an unrelated third-party for $40.2 million. Accordingly, we reversed $40.2 million of the
provision for uncollectible notes receivable during 2017.
Accretion of Asset Retirement Obligations
Accretion of asset retirement obligations for 2017 decreased by $0.8 million, or 11 percent, compared to 2016, and
increased by $0.8 million, or 13 percent, in 2016 compared to 2015. The decrease in 2017 was due to the replacement of
vertical wells that have been plugged and abandoned with horizontal wells, which have a longer expected life. The increase in
2016 was due to adding new wells and the associated increase in amortization expense.
Interest Expense
Interest expense increased by $16.7 million in 2017 compared to 2016. The increase is primarily attributable to an
$18.0 million increase in interest for the issuance of our 2024 Senior Notes, a $7.4 million increase in interest expense for the
issuance of $200 million principal amount of our 1.125% convertible notes due 2021 (the "2021 Convertible Notes") in
September 2016, a $3.1 million increase in interest expense for the issuance of our 2026 Notes in November 2017, and a $3.0
million increase in the utilization fee of our revolving credit facility. The increases were partially offset by a $9.3 million
charge for a bridge loan commitment related to the 2016 acquisition of properties in the Delaware Basin, a $3.5 million
decrease in interest expense resulting from the net settlement of our 2016 Convertible Notes in May 2016, and a $1.8 million
decrease in interest expense resulting from the net settlement of our 2022 Notes in December 2017.
Interest expense increased by approximately $14.4 million in 2016 compared to 2015. The increase is primarily
attributable to a $9.3 million charge for the bridge loan commitment related to the acquisition of properties in the Delaware
Basin, a $7.4 million increase in interest for the issuance of our 2024 Senior Notes, and a $2.9 million increase in interest
expense for the issuance of our 2021 Convertible Notes in September 2016. The increases were partially offset by a $5.1
million decrease in interest expense resulting from the net settlement of our 2016 Convertible Notes in May 2016. The entire
$9.3 million of interest expense attributed to the bridge loan facility was expensed in 2016 as the bridge loan was not used.
Interest costs capitalized in 2017, 2016, and 2015 were $5.0 million, $4.5 million, and $5.1 million, respectively.
Loss on Extinguishment of Debt
The $24.7 million pre-tax loss on extinguishment of debt relates to the redemption of the 2022 Senior Notes during the
fourth quarter of 2017. The pretax loss consists of a $19.4 million make-whole premium and the write-off of unamortized debt
issuance costs of $5.4 million.
Provision for Income Taxes
Current income tax (expense) benefit in 2017, 2016, and 2015 was $8.2 million, $9.9 million, and $(3.1) million,
respectively. Current income taxes generally relate to the cash that is paid or recovered for income taxes associated with the
applicable period. The remaining portion of the total income tax provision is comprised of deferred income taxes, which are a
result of differences in the timing of deductions from our U.S. GAAP presentation of financial statements and the income tax
regulations.
Our effective income tax rates for 2017, 2016, and 2015 were 62.4 percent, 37.4 percent, and 35.9 percent,
respectively, on income (loss) from operations. The 2017 rate differs from the statutory rate of 35 percent primarily due to the
reduction in the federal corporate income tax rate resulting from the 2017 Tax Act increasing the tax rate on our 2017 loss from
operations by 33.7 percent. Additionally, the nondeductible goodwill impairment charge in 2017 reduced the 2017 rate by 7.7
percent. The 2017 rate was also impacted by state taxes. The 2016 and 2015 rates differ from the federal statutory tax rate
56
primarily due to state taxes and excess stock compensation benefits, offset by nondeductible expenses that consist primarily of
officers' compensation cost and government lobbying expenses.
In 2016, we recorded a net deferred tax liability of $379.9 million due to book versus tax accounting basis differences
of assets acquired and deferred tax liabilities assumed from the acquisition in the Delaware Basin, resulting in a material
increase in our deferred tax liability on the balance sheet as of December 31, 2016. In 2017, the deferred tax liability was
reduced by $94.1 million as a result of recording an impairment charge related to a portion of these Delaware Basin assets.
As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions. We
continue to voluntarily participate in the Internal Revenue Service’s ("IRS") Compliance Assurance Program (the "CAP
Program") for the 2016 through 2018 tax years. We have received a partial acceptance notice from the IRS for our filed 2016
federal tax return and the IRS's post filing review is currently ongoing.
Net Income (Loss)/Adjusted Net Income (Loss)
The factors resulting in changes in net loss in 2017, 2016, and 2015 are discussed above. These same reasons
similarly impacted adjusted net income (loss), a non-U.S. GAAP financial measure, with the exception of the net change in fair
value of unsettled derivatives, adjusted for taxes, of $13.1 million, $208.9 million, and $22.2 million in 2017, 2016, and 2015,
respectively. Adjusted net loss, a non-U.S. GAAP financial measure, was $114.4 million, $37.0 million, and $46.2 million in
2017, 2016, and 2015 respectively. See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed
discussion of this non-U.S. GAAP financial measure.
Financial Condition, Liquidity and Capital Resources
Historically, our primary sources of liquidity have been cash flows from operating activities, our revolving credit
facility, proceeds from debt and equity capital market transactions, and asset sales. In 2017, our primary sources of liquidity
were net cash flows from operating activities of $588.6 million, net proceeds from issuance of the 2026 Senior Notes of
approximately $592.4 million, and $40.2 million of proceeds from the sale of a promissory note.
We used a portion of the net proceeds from the 2026 Senior Notes to fund the redemption our 2022 Senior Notes and a
portion of the purchase price of the Bayswater Acquisition in early 2018, and for general corporate purposes.
Our primary source of cash flows from operating activities is the sale of crude oil, natural gas, and NGLs.
Fluctuations in our operating cash flows are principally driven by commodity prices and changes in our production volumes.
Commodity prices have historically been volatile and we manage a portion of this volatility through our use of derivative
instruments. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the
instrument. Our revolving credit facility imposes limits on the amount of our production we can hedge, and we may choose not
to hedge the maximum amounts permitted. Therefore, we may still have fluctuations in our cash flows from operating
activities due to the remaining non-hedged portion of our future production. Based upon our hedge position and assuming
forward strip pricing as of December 31, 2017, our derivatives are not expected to be a significant source of cash flow in the
near term.
Our working capital fluctuates for various reasons, including, but not limited to, changes in the fair value of our
commodity derivative instruments and changes in our cash and cash equivalents due to our practice of utilizing excess cash to
reduce the outstanding borrowings under our revolving credit facility. At December 31, 2017, we had a working capital deficit
of $16.4 million compared to working capital of $129.2 million at December 31, 2016. The decrease in working capital as of
December 31, 2017 is primarily the result of a decrease in cash and cash equivalents of $63.4 million related to capital
investment exceeding operating cash flows, an increase in accounts payable of $83.7 million related to increased development
and exploration activity, and a decrease in the net fair value of our unsettled commodity derivatives of $20.2 million, which
was partially offset by an increase in our net accounts receivable balance of $54.2 million.
Our cash and cash equivalents were $180.7 million at December 31, 2017 and availability under our revolving credit
facility was $700.0 million, providing for total liquidity of $880.7 million as of December 31, 2017. Our liquidity was
augmented in 2017 by the net proceeds from the 2026 Senior Notes and the proceeds from the sale of a promissory note,
described previously.
57
Based on our expectations of cash flows from operations, our cash and cash equivalent balance and availability under
our revolving credit facility, we believe that we have sufficient capital to fund our planned activities through the 12-month
period following the filing of this report.
Our revolving credit facility is a borrowing base facility and availability under the facility is subject to
redetermination generally each May and November, based upon a quantification of our proved reserves at each December 31
and June 30, respectively. The maturity date of our revolving credit facility is May 2020.
In May and October 2017, we entered into the Fifth and Sixth Amendments, respectively, to the Third Amended
and Restated Credit Agreement to amend the revolving credit facility to reflect increases in the borrowing base. The Fifth
amendment reflected an increase of the borrowing base from $700 million to $950 million and the Sixth Amendment
amended the revolving credit facility to allow the borrowing base to increase above the borrowing capacity of $1.0 billion.
In addition, the Fifth Amendment made changes to certain of the covenants in the existing agreement as well as other
administrative changes. We elected to increase the borrowing base to $1.1 billion for our November 2017 borrowing base
redetermination and have elected to maintain a $700 million commitment level as of the date of this report.
Amounts borrowed under the revolving credit facility bear interest at either an alternate base rate option or a
LIBOR option as defined in the revolving credit facility plus an applicable margin, depending on the percentage of the
commitment that has been utilized. As of December 31, 2017, the applicable margin is 1.25 percent for the alternate base
rate option or 2.25 percent for the LIBOR option, and the unused commitment fee is 0.5 percent.
We had no amounts outstanding under our revolving credit facility as of December 31, 2017. In May 2017, we
replaced our $11.7 million irrevocable standby letter of credit that we held in favor of a third-party transportation service
provider to secure a firm transportation obligation with a $9.3 million deposit, which is classified as restricted cash and is
included in other assets on the consolidated balance sheet. As of December 31, 2017, the available funds under our
revolving credit facility were $700 million based on our elected commitment level.
Our revolving credit facility contains financial maintenance covenants. The covenants require that we maintain (i)
a leverage ratio defined as total debt of less than 4.0 times the trailing 12 months earnings before interest, taxes,
depreciation, depletion and amortization, change in fair value of unsettled commodity derivatives, exploration expense,
gains (losses) on sales of assets and other non-cash gains (losses) and (ii) an adjusted current ratio of at least 1.0:1.0. Our
adjusted current ratio is adjusted by eliminating the impact on our current assets and liabilities of recording the fair value of
crude oil and natural gas commodity derivative instruments. Additionally, available borrowings under our revolving credit
facility are added to the current asset calculation and the current portion of our revolving credit facility debt is eliminated
from the current liabilities calculation. At December 31, 2017, we were in compliance with all debt covenants, as defined
by the revolving credit agreement, with a leverage ratio of 1.9 and a current ratio of 3.2. We expect to remain in
compliance throughout the 12-month period following the filing of this report.
The indentures governing our 2024 Senior Notes and 2026 Senior Notes contain customary restrictive covenants
that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt including
under our revolving credit facility, (b) make certain investments or pay dividends or distributions on our capital stock or
purchase, redeem, or retire capital stock, (c) sell assets, including capital stock of our restricted subsidiaries, (d) restrict the
payment of dividends or other payments by restricted subsidiaries to us, (e) create liens that secure debt, (f) enter into
transactions with affiliates, and (g) merge or consolidate with another company. At December 31, 2017, we were in
compliance with all covenants and expect to remain in compliance throughout the next 12-month period.
In January 2017, pursuant to the filing of the supplemental indentures for the 2021 Convertible Senior Notes and
the 2024 Senior Notes, our subsidiary PDC Permian, Inc. became a guarantor of the notes. PDC Permian, Inc. is also the
guarantor of our 2026 Senior Notes issued in November 2017.
58
Cash Flows
Operating Activities. Our net cash flows from operating activities are primarily impacted by commodity prices,
production volumes, net settlements from our commodity derivative positions, operating costs, and general and administrative
expenses. Cash flows provided by operating activities increased in 2017 as compared to 2016. The $102.3 million increase
was primarily due to the increase in crude oil, natural gas, and NGLs sales of $415.7 million. The increase was partially offset
by a decrease in derivative commodity settlements of $194.8 million and increases in lease operating expenses of $29.7 million,
production taxes of $29.3 million, interest expense of $16.7 million, transportation, gathering, and processing expenses of
$14.8 million, and increases in general and administrative expense of $7.9 million as well as a decrease in the changes in assets
and liabilities of $13.0 million.
Cash flows provided by operating activities increased in 2016 compared to 2015. The $75.2 million increase was
primarily due to the increase in crude oil, natural gas, and NGLs sales of $118.7 million. We also realized an increase in the
change of funds held for distribution of $36.5 million, and an increase in the deferral of income taxes of $13.1 million. The
increases were partially offset by a decrease in derivative commodity settlements of $30.8 million, and increases in general and
administrative expense of $22.5 million, interest expense of $14.4 million, production taxes of $13.0 million and transportation,
gathering, and processing expenses of $8.3 million.
Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by $115.3 million in 2017 to
$582.1 million, and $46.0 million to $466.8 million in 2016, when compared to the respective prior years. These changes were
primarily due to the same factors mentioned above for changes in cash flows provided by operating activities, without regard to
changes in assets and liabilities.
Adjusted EBITDAX, a non-U.S. GAAP financial measure, increased by $222.3 million in 2017 to $682.1 million
from $459.8 million in 2016, primarily as the result of the increase in crude oil, natural gas, and NGLs sales of $415.7 million,
as well as the recording of a provision for a note receivable in 2016 of $44.0 million, and the subsequent sale of the note in
2017 to a third-party for $40.2 million. The increase was partially offset by a decrease in derivative commodity settlements of
$194.8 million, and increases in lease operating expenses of $29.7 million, production taxes of $29.3 million, interest expense
of $16.7 million, transportation, gathering, and processing expenses of $14.8 million, and general and administrative expense
of $7.9 million.
Adjusted EBITDAX, a non-U.S. GAAP financial measure, decreased by $4.5 million in 2016 to $459.8 million from
$464.3 million in 2015, primarily as a result of the provision for uncollectible notes receivable of $44.0 million, the decrease in
net settlements from our monthly derivative commodity settlements of $30.8 million, an increase in general and administrative
expense of $22.5 million, and a $13.0 million increase in production taxes. The decrease was partially offset by the increase in
crude oil, natural gas, and NGLs sales of $118.7 million.
See Item 7. Reconciliation of Non-U.S. GAAP Financial Measures for a reconciliation of our U.S. GAAP to non-U.S.
GAAP financial measures.
Investing Activities. Because crude oil and natural gas production from a well declines rapidly in the first few years of
production, we continue to invest significant amounts of capital in order to maintain and grow our production and replace our
reserves. If capital markets are not available in the future, we will be limited to our cash flows from operations and liquidity
under our revolving credit facility as the sources for funding our capital investments.
Cash flows from investing activities primarily consist of the acquisition, exploration, and development of crude oil
and natural gas properties, net of dispositions of crude oil and natural gas properties. Net cash used in investing activities of
$717.0 million during 2017 was primarily related to cash utilized for our drilling operations, including completion activities of
$737.2 million, a $21.0 million deposit toward the Bayswater Acquisition, purchases of short-term investments of $49.9
million, and a $9.3 million deposit with a third-party transportation service provider for surety of an existing firm transportation
obligation. Partially offsetting these investments was the receipt of approximately $49.9 million related to the sale of short-term
investments, $40.2 million from the sale of a promissory note, and $5.4 million related to post-closing settlements of properties
acquired in 2016. During 2016, our acquisition in the Delaware Basin comprised the majority of our cash flows used in
investing activities. Net cash used in the Delaware Basin acquisition was $1.1 billion and we used cash of $436.9 million for
our crude oil and gas operations. Our total cash used in investing activities during 2016 was approximately $1.5 billion.
Financing Activities. Net cash from financing activities in 2017 was primarily related to $592.4 million of net
proceeds from issuance of the 2026 Senior Notes, partially offset by the $519.4 million used to redeem our 2022 Senior Notes.
59
Net cash from financing activities in 2016 was primarily related to the $855.1 million of net proceeds received from
the issuance of 9.4 million shares of our common stock, $392.2 million of net proceeds from issuance of the 2024 Senior Notes,
and $193.9 million of net proceeds from issuance of the 2021 Convertible Notes, partially offset by the $115.0 million payment
upon the maturity of the 2016 Convertible Notes and net payments of approximately $37.0 million to pay down amounts
borrowed under our revolving credit facility.
Contractual Obligations and Contingent Commitments
The following table presents our contractual obligations and contingent commitments as of December 31, 2017:
Contractual Obligations and Contingent Commitments
Total
Long-term liabilities reflected on the consolidated balance sheet (1)
Less than
1 year
Payments due by period
1-3
years
(in millions)
3-5
years
More than
5 years
Long-term debt (2)
Commodity derivative contracts (3)
Capital leases (4)
Production tax liability
Asset retirement obligations
Other liabilities (5)
Commitments, contingencies and other arrangements (6)
Interest on long-term debt (7)
Operating leases
Firm transportation and processing agreements (8)
Total
$
$
1,200
101
4
85
87
8
1,485
552
23
262
837
2,322
$
$
— $
79
1
38
16
2
136
87
4
23
114
250
$
— $
22
3
47
32
2
106
172
8
86
266
372
$
200
—
—
—
32
2
234
135
8
66
209
443
$
$
1,000
—
—
—
7
2
1,009
158
3
87
248
1,257
__________
(1) Table does not include deferred income tax liability to taxing authorities of $192.0 million due to the uncertainty surrounding the
ultimate settlement of amounts and timing of these obligations.
(2) Amount presented does not agree with the consolidated balance sheets in that it excludes $30.3 million of unamortized debt discount
and $17.7 million of unamortized debt issuance costs.
(3) Represents our gross liability related to the fair value of derivative positions.
(4) Short-term capital lease obligations are included in other accrued expenses on the consolidated balance sheets. Long-term capital
lease obligations are included in other liabilities on the consolidated balance sheets.
(5) Includes deferred compensation to former executive officers and deferred payments related to firm transportation agreements.
(6) The table does not include termination benefits related to employment agreements with our executive officers, due to the uncertainty
surrounding the ultimate settlement of amounts and timing of these obligations.
(7) Amounts presented include $288.9 million to the holders of our 2026 Senior Notes, $164.2 million to the holders of our 2024 Senior
Notes, and $90.7 million payable to the holders of our 2021 Convertible Notes. Amounts also include interest of $8.4 million related
to unutilized commitments at a rate of 0.50 percent per annum.
(8) Represents our gross commitment which includes volumes produced by us, purchased from third parties and produced by our
affiliated partnerships and other third-party working, royalty and overriding royalty interest owners whose volumes we market on
their behalf. This includes anticipated and estimated commitments associated with two new gas processing facilities by our primary
mid-stream provider. The timing of such payments has been estimated and is subject to change based on the completion of
construction and the commencement of operations by the midstream provider.
From time to time, we are a party to various legal proceedings in the ordinary course of business. We are not currently
a party to any litigation that we believe would have a materially adverse effect on our business, financial condition, results of
operations, or liquidity. Information regarding our legal proceedings can found in the footnote titled Commitments and
Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report.
Critical Accounting Policies and Estimates
We have identified the following policies as critical to business operations and the understanding of our results of
operations. This is not a comprehensive list of all of the accounting policies. In many cases, the accounting treatment of a
particular transaction is specifically dictated by U.S. GAAP, with no need for our judgment in the application. There are also
60
areas in which our judgment in selecting available alternatives would not produce a materially different result. However,
certain of our accounting policies are particularly important to the presentation of our financial position and results of
operations and we may use significant judgment in their application. As a result, they are subject to an inherent degree of
uncertainty. In applying those policies, we use our judgment to determine the appropriate assumptions to be used in the
determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry and
information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and
other accounting policies, see the footnote titled Summary of Significant Accounting Policies to our consolidated financial
statements included elsewhere in this report.
Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful
efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and
developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated
proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method
based on estimated proved reserves.
Annually, we engage independent petroleum engineers to prepare reserve and economic evaluations of all our
properties on a well-by-well basis as of December 31. We adjust our crude oil and natural gas reserves for major acquisitions,
new drilling, and divestitures during the year as needed. The process of estimating and evaluating crude oil and natural gas
reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering, and
economic data. The data for a given property may also change substantially over time as a result of numerous factors,
including additional development activity, evolving production history and a continual reassessment of the viability of
production under changing economic conditions. As a result, revisions in existing reserve estimates occur. Although every
reasonable effort is made to ensure that reserve estimates reported represent our most accurate assessments possible, the
subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these
estimates over time. Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves
could have an effect on our net income (loss).
Exploration costs, including geological and geophysical expenses, the acquisition of seismic data covering unproved
acreage, and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of
stratigraphic test wells, are initially capitalized, but are charged to expense if the well is determined to be nonproductive. The
status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts
method of accounting. Exploratory well costs continue to be capitalized as long as the well has found a sufficient quantity of
reserves to justify completion as a producing well and we are making sufficient progress assessing our reserves and economic
and operating viability. If an in-progress exploratory well is found to be unsuccessful prior to the issuance of the financial
statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to
make a final determination about the productive status of a well prior to issuance of the financial statements, the well is
classified as a "suspended well" until we have had sufficient time to conduct additional completion or testing operations to
evaluate the pertinent geological and engineering data obtained. At the time when we are able to make a final determination of
a well’s productive status, the well is removed from suspended well status and the proper accounting treatment is applied.
The acquisition costs of unproved properties are capitalized when incurred until such properties are transferred to
proved properties or charged to expense when expired, impaired, or amortized. Unproved crude oil and natural gas properties
with individually significant acquisition costs are periodically assessed, and any impairment in value is charged to impairment
of crude oil and natural gas properties. The amount of impairment recognized on unproved properties which are not
individually significant is determined by amortizing the costs of such properties within appropriate fields based on our
historical experience, acquisition dates and average lease terms, with the amortization recognized in impairment of crude oil
and natural gas properties. The valuation of unproved properties is subjective and requires us to make estimates and
assumptions which, with the passage of time, may prove to be materially different from actual realizable values.
We assess our crude oil and natural gas properties for possible impairment upon a triggering event, including when
general industry conditions warrant, by comparing net capitalized costs to estimated undiscounted future net cash flows on a
field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity will be sold.
Any impairment in value is charged to impairment of properties and equipment. The estimates of future prices may differ from
current market prices of crude oil and natural gas. Any downward revisions in estimates to our reserve quantities, expectations
of falling commodity prices, or rising operating costs could result in a triggering event, and therefore, a reduction in
undiscounted future net cash flows and an impairment of our crude oil and natural gas properties. Although our cash flow
estimates are based on the relevant information available at the time the estimates are made, estimates of future cash flows are,
by nature, highly uncertain and may vary significantly from actual results.
61
Crude Oil, Natural Gas, and NGLs Sales Revenue Recognition. Crude oil, natural gas, and NGLs sales are
recognized when production is sold to a purchaser at a determinable price, delivery has occurred, rights and responsibility of
ownership have transferred and collection of revenue is reasonably assured. We record sales revenue based on an estimate of
the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes
based on company-measured volume readings. We then adjust our crude oil, natural gas, and NGLs sales in subsequent periods
based on the data received from our purchasers that reflects actual volumes and prices received. We receive payment for sales
from one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one
to two months later. Historically, these differences have been immaterial. If a sale is deemed uncollectible, an allowance for
doubtful collection is recorded. There is a new revenue standard effective for annual reporting periods beginning after
December 15, 2017. See the footnote titled Summary of Significant Accounting Policies - Recently Issued Accounting
Standards.
Fair Value of Financial Instruments. Our fair value measurements are estimated pursuant to a fair value hierarchy
that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair
value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the
measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to
unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value
hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in
the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires
judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their
placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined
as:
Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets.
Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for
the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for
identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the
asset or liability, and inputs that are derived from observable market data by correlation or other means.
Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity.
Commodity Derivative Financial Instruments. We measure the fair value of our commodity derivative instruments
based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying
position, current market prices, natural gas, and crude oil forward curves, discount rates such as the LIBOR curve for a similar
duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of
our credit standing on the fair value of commodity derivative liabilities and the effect of our counterparties' credit standings on
the fair value of commodity derivative assets. Both inputs to the model are based on published credit default swap rates and the
duration of each outstanding commodity derivative position.
We validate our fair value measurement through the review of counterparty statements and other supporting
documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs
through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and
assumptions. While we use common industry practices to develop our valuation techniques, changes in our pricing
methodologies or the underlying assumptions could result in significantly different fair values. While we believe our valuation
method is appropriate and consistent with those used by other market participants, the use of a different methodology, or
assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value.
Net settlements on our commodity derivative instruments are initially recorded to accounts receivable or payable, as
applicable, and may not be received from or paid to counterparties to our commodity derivative contracts within the same
accounting period. Such settlements typically occur the month following the maturity of the commodity derivative instrument.
We have evaluated the credit risk of the counterparties holding our commodity derivative assets, which are primarily financial
institutions who are also major lenders in our revolving credit facility, giving consideration to amounts outstanding for each
counterparty and the duration of each outstanding commodity derivative position. Based on our evaluation, we have
determined that the potential impact of nonperformance of our counterparties on the fair value of our commodity derivative
instruments is not significant.
Deferred Income Tax Asset Valuation Allowance. Deferred income tax assets are recognized for deductible
temporary differences, net operating loss carry-forwards and credit carry-forwards if it is more likely than not that the tax
62
benefits will be realized. To the extent a deferred tax asset is not expected to be realized under the preceding criteria, we
establish a valuation allowance. The factors which we consider in assessing whether we will realize the value of deferred
income tax assets involve judgments and estimates of both amount and timing. The judgments used in applying these policies
are based on our evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results
may differ from those estimates.
Accounting for Business Combinations. We utilize the purchase method to account for acquisitions of businesses
and assets. The value of the purchase consideration takes into account the degree to which the consideration is objective and
measurable such as cash consideration paid to a seller. With the issuance of equity, restrictions upon the sale of the issued stock
are taken into consideration. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired
and liabilities assumed based on fair values as of the acquisition date. The purchase price allocations are based on appraisals,
discounted cash flows, quoted market prices, and estimates by management. When appropriate, we review comparable
purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market
value as such sales represent the amount at which a willing buyer and seller would enter into an exchange for such properties.
In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most
significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-
producing, proved undeveloped and unproved crude oil and natural gas properties, and other non-crude oil and natural gas
properties. To estimate the fair values of these properties, we prepare estimates of crude oil and natural gas reserves. When
appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use
that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an
exchange for such properties. We estimate future prices by using the applicable forward pricing strip to apply to our estimate
of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net
revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of
capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is
subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved
properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors.
We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities.
Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed
and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information
becomes known.
Recent Accounting Standards
See the footnote titled Summary of Significant Accounting Policies - Recently Adopted Accounting Standards to our
consolidated financial statements included elsewhere in this report.
Reconciliation of Non-U.S. GAAP Financial Measures
We use "adjusted cash flows from operations," "adjusted net income (loss)" and "adjusted EBITDAX," non-U.S.
GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases,
providing public guidance on possible future results. Beginning in 2017, we have included non-cash stock-based compensation
and exploration, geologic and geophysical expense in our reconciliation of adjusted EBITDAX calculation. In prior periods,
we disclosed adjusted EBITDA, a non-U.S. GAAP financial measure that did not include these adjustments. We have elected
to disclose Adjusted EBITDAX rather than Adjusted EBITDA in this report and other public disclosures because we believe it
is more comparable to similar metrics presented by others in the industry. All prior periods have been conformed for
comparability of this information. These measures are not measures of financial performance under U.S. GAAP and should be
considered in addition to, not as a substitute for, net income (loss) or cash flows from operations, investing or financing
activities, and should not be viewed as liquidity measures or indicators of cash flows reported in accordance with U.S. GAAP.
The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other
companies. Also, in the future, we may disclose different non-U.S. GAAP financial measures in order to help our investors
more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We
strongly encourage investors to review our financial statements and publicly filed reports in their entirety and not rely on any
single financial measure.
Adjusted cash flows from operations. We define adjusted cash flows from operations as the cash flows earned or
incurred from operating activities, without regard to changes in operating assets and liabilities. We believe it is important to
consider adjusted cash flows from operations, as well as cash flows from operations, as we believe it often provides more
63
transparency into what drives the changes in our operating trends, such as production, prices, operating costs, and related
operational factors, without regard to whether the related asset or liability was received or paid during the same period. We
also use this measure because the timing of cash received from our assets, cash paid to obtain an asset or payment of our
obligations has generally been a timing issue from one period to the next as we have not had significant accounts receivable
collection problems, nor been unable to purchase assets or pay our obligations.
Adjusted net income (loss). We define adjusted net income (loss) as net income (loss), plus loss on commodity
derivatives, less gain on commodity derivatives, and net settlements on commodity derivatives, each adjusted for tax effect.
We believe it is important to consider adjusted net income (loss), as well as net income (loss). We believe this measure often
provides more transparency into our operating trends, such as production, prices, operating costs, net settlements from
derivatives, and related factors, without regard to changes in our net income (loss) from our mark-to-market adjustments
resulting from net changes in the fair value of unsettled derivatives. Additionally, other items which are not indicative of future
results may be excluded to clearly identify operating trends.
Adjusted EBITDAX. We define adjusted EBITDAX as net income (loss), plus loss on commodity derivatives, interest
expense, net of interest income, income taxes, impairment of properties and equipment, exploration, geologic, and geophysical
expense, depreciation, depletion and amortization expense, accretion of asset retirement obligations, and non-cash stock-based
compensation, less gain on commodity derivatives and net settlements on commodity derivatives. Adjusted EBITDAX is not a
measure of financial performance or liquidity under U.S. GAAP and should be considered in addition to, not as a substitute for,
net income (loss), and should not be considered an indicator of cash flows reported in accordance with U.S. GAAP. Adjusted
EBITDAX includes certain non-cash costs incurred by us and does not take into account changes in operating assets and
liabilities. Other companies in our industry may calculate adjusted EBITDAX differently than we do, limiting its usefulness as
a comparative measure. We believe adjusted EBITDAX is relevant because it is a measure of our operational and financial
performance, as well as a measure of our liquidity, and is used by our management, investors, commercial banks, research
analysts, and others to analyze such things as:
•
•
•
•
operating performance and return on capital as compared to our peers;
financial performance of our assets and our valuation without regard to financing methods, capital structure, or
historical cost basis;
our ability to generate sufficient cash to service our debt obligations; and
the viability of acquisition opportunities and capital expenditure projects, including the related rate of return.
PV-10. We define PV-10 as the estimated present value of the future net cash flows from our proved reserves before
income taxes, discounted using a 10 percent discount rate. We believe that PV-10 provides useful information to investors as it
is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that
PV-10 is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts, investors,
and other users of our financial statements may utilize the measure as a basis for comparison of the relative size and value of
our reserves to other companies' reserves. Because there are many unique factors that can impact an individual company when
estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable in evaluating us
and our reserves. PV-10 is not intended to represent the current market value of our estimated reserves.
64
The following table presents a reconciliation of our non-U.S. GAAP financial measures to its most comparable U.S.
GAAP measure:
Adjusted cash flows from operations:
Net cash from operating activities
Changes in assets and liabilities
Adjusted cash flows from operations
Adjusted net loss:
Net loss
(Gain) loss on commodity derivative instruments
Net settlements on commodity derivative instruments
Tax effect of above adjustments
Adjusted net loss
Net loss to adjusted EBITDAX:
Net loss
(Gain) loss on commodity derivative instruments
Net settlements on commodity derivative instruments
Non-cash stock-based compensation
Interest expense, net
Income tax benefit
Impairment of properties and equipment
Impairment of goodwill
Exploration, geologic, and geophysical expense
Depreciation, depletion, and amortization
Accretion of asset retirement obligations
Loss on extinguishment of debt
Adjusted EBITDAX
Cash from operating activities to adjusted EBITDAX:
Net cash from operating activities
Interest expense, net
Amortization of debt discount and issuance costs
Gain on sale of properties and equipment
Exploration, geologic, and geophysical expense
Exploratory dry hole expense
Other
Changes in assets and liabilities
Adjusted EBITDAX
PV-10:
PV-10
Present value of estimated future income tax discounted at 10%
Standardized measure of discounted future net cash flows
$
$
$
$
$
$
$
$
$
$
2017
Year Ended December 31,
2016
(in millions)
2015
588.6
(6.5)
582.1
(127.5)
3.9
13.3
(4.1)
(114.4)
(127.5)
3.9
13.3
19.4
76.4
(211.9)
285.9
75.1
47.3
469.1
6.4
24.7
682.1
588.6
76.4
(12.9)
0.7
47.3
(41.3)
29.8
(6.5)
682.1
3,212.0
(331.9)
2,880.1
$
$
$
$
$
$
$
$
$
$
486.3
(19.5)
466.8
(245.9)
125.7
208.1
(124.9)
(37.0)
(245.9)
125.7
208.1
19.5
61.0
(147.2)
10.0
—
4.7
416.9
7.0
—
459.8
486.3
61.0
(16.2)
—
4.7
—
(56.5)
(19.5)
459.8
1,675.0
(254.4)
1,420.6
$
$
$
$
$
$
$
$
$
$
411.1
9.7
420.8
(68.3)
(203.2)
238.9
(13.6)
(46.2)
(68.3)
(203.2)
238.9
20.1
42.8
(38.3)
161.6
—
1.1
303.3
6.3
—
464.3
411.1
42.8
(7.0)
0.4
1.1
—
6.2
9.7
464.3
1,337.5
(240.6)
1,096.9
Amounts above include results from continuing and discontinued operations.
65
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market-Sensitive Instruments and Risk Management
We are exposed to market risks associated with interest rate risks, commodity price risk, and credit risk. We have
established risk management processes to monitor and manage these market risks.
Interest Rate Risk
Changes in interest rates affect the amount of interest we earn on our interest bearing cash and cash equivalents and
the interest we pay on borrowings under our revolving credit facility. Our 2021 Convertible Notes, 2024 Senior Notes, and
2026 Senior Notes have fixed rates and, therefore, near-term changes in interest rates do not expose us to risk of earnings or
cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt.
As of December 31, 2017, our interest-bearing deposit accounts included money market accounts and checking
accounts with various banks. The amount of our interest-bearing cash and cash equivalents as of December 31, 2017 was
$179.6 million, with a weighted-average interest rate of one percent. Based on a sensitivity analysis of our interest bearing
deposits as of December 31, 2017 and assuming we had $179.6 million outstanding throughout the period, we estimate that a
one percent increase in interest rates would have increased interest income for the twelve months ended December 31, 2017 by
approximately $1.8 million.
As of December 31, 2017, we had no outstanding balance on our revolving credit facility.
Commodity Price Risk
We are exposed to the potential risk of loss from adverse changes in the market price of crude oil, natural gas, and
NGLs. Pursuant to established policies and procedures, we manage a portion of the risks associated with these market
fluctuations using commodity derivative instruments. These instruments help us predict with greater certainty the effective
crude oil, natural gas, and propane prices we will receive for our hedged production. We believe that our commodity derivative
policies and procedures are effective in achieving our risk management objectives.
66
The following table presents our commodity derivative positions related to crude oil, natural gas, and NGLs in effect
as of December 31, 2017:
Collars
Fixed-Price Swaps
Quantity
(Gas -
BBtu
Oil -
MBbls)
Weighted-Average
Contract Price
Floors
Ceilings
Quantity (Oil -
MBbls
Gas and Basis-
BBtu
Propane - MBbls)
Weighted-
Average
Contract
Price
Fair Value
December
31,
2017 (1)
(in millions)
1,512.0
—
1,512.0
5,230.0
5,230.0
—
—
—
—
—
—
—
—
—
—
$ 41.85
—
$ 54.31
—
10,372.0
6,600.0
16,972.0
$
52.93
52.47
$
3.00
$
3.54
51,280.0
51,280.0
$
2.95
$
$
$
$
—
—
1,809.9
1,809.9
(0.10) $
—
—
—
—
—
—
35,200.0
$
(0.36) $
6,000.0
(0.50)
3,000.0
44,200.0
(0.62) $
$
(73.4)
(22.3)
(95.7)
7.3
7.3
(0.2)
(0.2)
5.2
1.3
0.5
7.0
—
—
1,095.3
1,095.3
$
32.08
$
$
(4.6)
(4.6)
—
—
5,333.9
5,333.9
0.12
$
(1.1)
(1.1)
Commodity/ Index/
Maturity Period
Crude Oil
NYMEX
2018
2019
Total Crude Oil
Natural Gas
NYMEX
2018
Total Natural Gas
Basis Protection - Crude Oil
Midland Cushing
2018
Total Basis Protection - Crude Oil
Basis Protection - Natural Gas
CIG
2018
Waha
2018
El Paso
2018
Total Basis Protection - Natural Gas
Propane
Mont Belvieu
2018
Total Propane
Rollfactor (2)
Crude Oil CMA
2018
Total Rollfactor
Commodity Derivatives Fair Value
$
(87.3)
_____________
(1) Approximately ten percent of the fair value of our commodity derivative assets and 11 percent of the fair value of our commodity
derivative liabilities were measured using significant unobservable inputs (Level 3).
(2) These positions hedge the timing risk associated with our physical sales. We generally sell crude oil for the delivery month at a
sales price based on the average NYMEX West Texas Intermediate price during that month, plus an adjustment calculated as a
spread between the weighted average prices of the delivery month, the next month and the following month during the period when
the delivery month is the first month (the "trade month roll").
67
Our realized prices vary regionally based on local market differentials and our transportation agreements. The
following table presents average market index prices for crude oil and natural gas for the periods identified, as well as the
average sales prices we realized for our crude oil, natural gas, and NGLs production:
Average NYMEX Index Price:
Crude oil (per Bbl)
NYMEX
Natural gas (per MMBtu)
NYMEX
Average Sales Price Realized:
Excluding net settlements on commodity
derivatives
Crude oil (per Bbl)
Natural gas (per Mcf)
NGLs (per Bbl)
Year Ended December 31,
2017
2016
$
$
$
$
$
$
50.95
3.11
48.45
2.21
18.59
43.32
2.46
39.96
1.77
11.80
Based on a sensitivity analysis as of December 31, 2017, it was estimated that a 10 percent increase in natural gas,
crude oil prices, and the propane portion of NGLs prices, inclusive of basis, over the entire period for which we have
commodity derivatives in place would have resulted in a decrease in the fair value of our derivative positions of $119.3 million,
whereas a 10 percent decrease in prices would have resulted in an increase in fair value of $118.0 million.
Credit Risk
Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations.
We attempt to reduce credit risk by diversifying our counterparty exposure and entering into transactions with high-quality
counterparties. When exposed to significant credit risk, we analyze the counterparties’ financial condition prior to entering into
an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We monitor the
creditworthiness of significant counterparties through our credit committee, which utilizes a number of qualitative and
quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. While we believe that our credit risk
analysis and monitoring procedures are reasonable, no amount of analysis can assure financial performance by our
counterparties.
Our oil and gas exploration and production business's crude oil, natural gas, and NGLs sales are concentrated with a
few predominately large customers. This concentrates our credit risk exposure with a small number of large customers.
Amounts due to our gas marketing business are from a diverse group of entities. The underlying operations of these
entities are geographically concentrated in the same region, which increases the credit risk associated with this business. As
natural gas prices continue to remain depressed, certain third-party producers committed to providing natural gas to our gas
marketing business continue to experience financial distress, which has led to certain contractual defaults and litigation;
however, to date, we have had no material counterparty default losses. We have initiated several legal actions for breach of
contract and collection claims against certain third-party producers that are delinquent in their payment obligations. We expect
this trend to continue for this business segment.
We primarily use financial institutions which are lenders in our revolving credit facility as counterparties for our
derivative financial instruments. Disruption in the credit markets, changes in commodity prices and other factors may have a
significant adverse impact on a number of financial institutions. To date, we have had no material counterparty default losses
from our commodity derivative financial instruments. See the footnote titled Commodity Derivative Financial Instruments to
our consolidated financial statements included elsewhere in this report for more detail on our commodity derivative financial
instruments.
Disclosure of Limitations
Because the information above included only those exposures that existed at December 31, 2017, it does not consider
those exposures or positions which could arise after that date. Our ultimate realized gain or loss with respect to interest rate
68
and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk
management strategies at the time and interest rates and commodity prices at the time.
69
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental Information
Financial Statements:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets - December 31, 2017 and 2016
Consolidated Statements of Operations - Years Ended December 31, 2017, 2016, and 2015
Consolidated Statements of Cash Flows - Years Ended December 31, 2017, 2016, and 2015
Consolidated Statements of Equity - Years Ended December 31, 2017, 2016, and 2015
Notes to Consolidated Financial Statements
Supplemental Information - Unaudited:
Crude Oil and Natural Gas Information
Quarterly Financial Information
Financial Statement Schedule:
Schedule II - Valuation and Qualifying Accounts - Years Ended December 31, 2017, 2016, and 2015
71
73
74
75
77
78
119
126
127
70
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of PDC Energy, Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of PDC Energy, Inc. and its subsidiaries as of
December 31, 2017 and 2016, and the related consolidated statements of operations, equity and cash flows for each of the three
years in the period ended December 31, 2017, including the related notes and financial statement schedule listed in the
accompanying index (collectively referred to as the “consolidated financial statements”). We also have audited the Company's
internal control over financial reporting as of December 31, 2017, 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 consolidated financial statements referred to above present fairly, in all material respects, the
financial position of the Company as of December 31, 2017 and 2016, and the results of their operations and their cash flows
for each of the three years in the period ended December 31, 2017 in conformity with accounting principles generally accepted
in the United States of America. Also in our opinion, the Company did not maintain, in all material respects, effective internal
control over financial reporting as of December 31, 2017 based on criteria established in Internal Control - Integrated
Framework (2013) issued by the COSO because material weaknesses in internal control over financial reporting existed as of
that date related to not maintaining a sufficient complement of personnel within the Land Department as a result of increased
volume of leases, which contributed to the ineffective design and maintenance of controls to verify the completeness and
accuracy of land administrative records associated with unproved leases.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such
that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be
prevented or detected on a timely basis. The material weaknesses referred to above are described in Management's Report on
Internal Control over Financial Reporting appearing under Item 9A. We considered these material weaknesses in determining
the nature, timing, and extent of audit tests applied in our audit of the 2017 consolidated financial statements, and our opinion
regarding the effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those
consolidated financial statements.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective
internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting,
included in management's report referred to above. Our responsibility is to express opinions on the Company’s consolidated
financial statements and on the Company's internal control over financial reporting based on our audits. We are a public
accounting firm registered with the Public Company Accounting Oversight Board (United States) ("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 audits to obtain reasonable assurance about whether the consolidated financial statements are free of material
misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in
all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material
misstatement of the consolidated 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
consolidated 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 consolidated financial statements. Our audit of
internal control over financial reporting included obtaining an understanding of internal control over financial reporting,
assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal
control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in
the circumstances. We believe that our audits provide a reasonable basis for our opinions.
71
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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions
and dispositions of the assets of the company; (ii) 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 (iii) 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/PricewaterhouseCoopers LLP
Denver, Colorado
February 26, 2018
We have served as the Company’s auditor since 2007.
72
PDC ENERGY, INC.
Consolidated Balance Sheets
(in thousands, except share and per share data)
As of December 31,
Assets
Current assets:
Cash and cash equivalents
Accounts receivable, net
Fair value of derivatives
Prepaid expenses and other current assets
Total current assets
Properties and equipment, net
Assets held-for-sale, net
Fair value of derivatives
Goodwill
Other assets
Total Assets
Liabilities and Stockholders' Equity
Liabilities
Current liabilities:
Accounts payable
Production tax liability
Fair value of derivatives
Funds held for distribution
Accrued interest payable
Other accrued expenses
Total current liabilities
Long-term debt
Deferred income taxes
Asset retirement obligations
Fair value of derivatives
Other liabilities
Total liabilities
Commitments and contingent liabilities
Stockholders' equity
Common shares - par value $0.01 per share, 150,000,000
authorized, 65,955,080 and 65,704,568 issued as of December 31,
2017 and 2016, respectively
Additional paid-in capital
Retained earnings
Treasury shares - at cost, 55,927 and 28,763 as of December 31,
2017 and 2016, respectively
Total stockholders' equity
Total Liabilities and Stockholders' Equity
2017
2016
180,675
197,598
14,338
8,613
401,224
3,933,467
40,084
—
—
45,116
4,419,891
150,067
37,654
79,302
95,811
11,815
42,987
417,636
1,151,932
191,992
71,006
22,343
57,333
1,912,242
659
2,503,294
6,704
(3,008)
2,507,649
4,419,891
$
$
$
$
244,100
143,392
8,791
3,542
399,825
4,002,994
5,272
2,386
62,041
13,324
4,485,842
66,322
24,767
53,595
71,339
15,930
38,625
270,578
1,043,954
400,867
82,612
27,595
37,482
1,863,088
657
2,489,557
134,208
(1,668)
2,622,754
4,485,842
$
$
$
$
See accompanying Notes to Consolidated Financial Statements
73
PDC ENERGY, INC.
Consolidated Statements of Operations
(in thousands, except per share data)
Year Ended December 31,
Revenues
Crude oil, natural gas, and NGLs sales
Commodity price risk management gain (loss), net
Other income
Total revenues
Costs, expenses and other
Lease operating expenses
Production taxes
Transportation, gathering, and processing expenses
Exploration, geologic, and geophysical expense
Impairment of properties and equipment
Impairment of goodwill
General and administrative expense
Depreciation, depletion and amortization
Provision for uncollectible notes receivable
Accretion of asset retirement obligations
Gain on sale of properties and equipment
Other expenses
Total costs, expenses and other
Loss from operations
Loss on extinguishment of debt
Interest expense
Interest income
Loss before income taxes
Income tax benefit
Net loss
Earnings per share:
Basic
Diluted
Weighted-average common shares outstanding:
Basic
Diluted
2017
2016
2015
$
$
$
$
$
913,084
(3,936)
12,468
921,616
89,641
60,717
33,220
47,334
285,887
75,121
120,370
469,084
(40,203)
6,306
(766)
13,157
1,159,868
(238,252)
(24,747)
(78,694)
2,261
(339,432)
211,928
(127,504) $
$
497,353
(125,681)
11,243
382,915
59,950
31,410
18,415
4,669
9,973
—
112,470
416,874
44,038
7,080
(43)
10,193
715,029
(332,114)
—
(61,972)
963
(393,123)
147,195
(245,928) $
(1.94) $
(1.94) $
(5.01) $
(5.01) $
65,837
65,837
49,052
49,052
378,713
203,183
13,430
595,326
56,992
18,443
10,151
1,102
161,620
—
89,959
303,258
—
6,293
(385)
11,717
659,150
(63,824)
—
(47,571)
4,807
(106,588)
38,308
(68,280)
(1.74)
(1.74)
39,153
39,153
See accompanying Notes to Consolidated Financial Statements
74
PDC ENERGY, INC.
Consolidated Statements of Cash Flows
(in thousands)
Year Ended December 31,
Cash flows from operating activities:
Net loss
Adjustments to net loss to reconcile to net cash from operating activities:
2017
2016
2015
$
(127,504) $
(245,928) $
(68,280)
Net change in fair value of unsettled commodity derivatives
Depreciation, depletion and amortization
Provision for uncollectible notes receivable
Impairment of properties and equipment
Impairment of goodwill
Exploratory dry hole costs
Loss on extinguishment of debt
Accretion of asset retirement obligations
Non-cash stock-based compensation
Gain on sale of properties and equipment
Amortization of debt discount and issuance costs
Deferred income taxes
Other
Total adjustments to net loss to reconcile to net cash from operating activities:
Changes in assets and liabilities:
Accounts receivable
Other assets
Production tax liability
Accounts payable and accrued expenses
Funds held for future distribution
Asset retirement obligations
Other liabilities
Total changes in assets and liabilities
Net cash from operating activities
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties
Capital expenditures for other properties and equipment
Acquisition of crude oil and natural gas properties, including settlement adjustments and
deposit for pending acquisition
Proceeds from sale of properties and equipment
Sale of promissory note
Restricted cash
Sale of short-term investments
Purchase of short-term investments
Net cash from investing activities
Cash flows from financing activities:
Proceeds from issuance of equity, net of issuance costs
Proceeds from issuance of senior notes
Proceeds from issuance of convertible senior notes
Proceeds from revolving credit facility
Repayment of revolving credit facility
Redemption of senior notes
Redemption of convertible notes
Payment of debt issuance costs
Purchase of treasury shares
Other
Net cash from financing activities
Net change in cash and cash equivalents
Cash and cash equivalents, beginning of year
Cash and cash equivalents, end of year
17,260
469,084
(40,203)
285,887
75,121
41,297
24,747
6,306
19,353
(766)
12,907
(203,685)
2,265
709,573
(60,546)
(5,886)
31,316
31,378
24,472
(10,176)
(4,064)
6,494
588,563
333,770
416,874
44,038
9,973
—
—
—
7,080
19,502
(43)
16,167
(137,249)
2,603
712,715
(32,627)
2,303
9,223
(162)
36,510
(4,109)
8,338
19,476
486,263
(737,208)
(5,094)
(436,884)
(3,464)
(15,628)
(1,073,723)
9,991
40,203
(9,250)
49,890
(49,890)
(716,986)
—
592,366
—
—
—
(519,375)
—
(50)
(6,672)
(1,271)
64,998
(63,425)
244,100
180,675
4,945
—
—
—
—
(1,509,126)
855,074
392,172
193,935
85,000
(122,000)
—
(115,000)
(15,556)
(6,935)
(577)
1,266,113
243,250
850
244,100
$
$
$
35,791
303,258
—
161,620
—
—
—
6,293
20,068
(385)
7,040
(41,415)
(3,216)
489,054
24,815
(2,264)
(1,629)
(30,310)
2,699
(4,458)
1,446
(9,701)
411,073
(599,546)
(5,122)
—
405
—
—
—
—
(604,263)
202,851
—
—
397,000
(416,000)
—
—
(974)
(6,055)
1,152
177,974
(15,216)
16,066
850
See accompanying Notes to Consolidated Financial Statements
75
Supplemental cash flow information:
Cash payments (receipts) for:
Interest, net of capitalized interest
Income taxes
Non-cash investing activities:
Issuance of common stock for acquisition of crude oil and natural gas properties
Change in accounts payable related to capital expenditures
Change in asset retirement obligation, with a corresponding change to crude oil and natural gas
properties, net of disposal
Purchase of properties and equipment under capital leases
See footnote titled Business Combinations for non-cash transactions related to our acquisitions.
$
69,880
(13,925)
$
43,406
167
$
45,642
10,049
—
50,761
839
3,497
690,702
(40,448)
4,894
1,404
—
(45,230)
14,030
1,601
See accompanying Notes to Consolidated Financial Statements
76
PDC ENERGY, INC.
Consolidated Statements of Equity
(in thousands, except share data)
Common Stock
Treasury Stock
Shares
Amount
Additional
Paid-in
Capital
Shares
Amount
Retained
Earnings
Total
Stockholders'
Equity
Balances, January 1, 2015
35,927,985
$
359
$ 689,209
(21,643) $
(911) $ 448,702
$
1,137,359
Net loss
Issuance pursuant to sale of equity
Purchase of treasury shares
Issuance of treasury shares
Non-employee directors' deferred compensation plan
—
4,002,000
—
—
—
Issuance of stock awards, net of forfeitures
244,791
Stock-based compensation expense, including tax
impact
—
—
40
—
—
—
3
—
—
202,811
—
—
—
—
— (120,864)
(6,055)
(6,206)
127,159
—
—
21,568
(4,872)
—
—
6,206
(249)
—
—
(68,280)
—
—
—
—
—
—
(68,280)
202,851
(6,055)
—
(249)
3
21,568
Balances, December 31, 2015
40,174,776
$
402
$ 907,382
(20,220) $ (1,009) $ 380,422
$
1,287,197
— (245,928)
(245,928)
Net loss
Issuance pursuant to acquisition
Issuance pursuant to sale of equity
Convertible debt discount, net of issuance costs and
tax
Purchase of treasury shares
Issuance pursuant to note conversion
Issuance of treasury shares
Non-employee directors' deferred compensation plan
Issuance of stock awards, net of forfeitures
Exercise of stock options
Stock-based compensation expense
Other
—
9,386,768
15,007,500
—
—
792,406
(114,697)
—
411,731
46,084
—
—
—
94
150
—
—
8
—
3
—
—
—
—
690,608
854,933
23,518
—
—
—
—
—
—
—
— (116,085)
(6,935)
(8)
—
(6,661)
114,697
—
(3)
—
19,502
286
(7,155)
—
—
—
—
—
6,661
(385)
—
—
—
—
Balances, December 31, 2016
65,704,568
$
657
$ 2,489,557
(28,763) $ (1,668) $ 134,208
$
2,622,754
Net loss
Purchase of treasury shares
Issuance of treasury shares
Non-employee directors' deferred compensation plan
Issuance of stock awards, net of forfeitures
Stock-based compensation expense
—
—
—
—
250,512
—
—
—
—
—
2
—
Other
Balance, December 31, 2017
—
65,955,080
$
—
659
—
—
— (127,504)
— (107,357)
(6,672)
(5,517)
83,228
—
(2)
19,353
(97)
$ 2,503,294
(3,035)
—
—
—
(55,927) $ (3,008) $
5,517
(185)
—
—
—
—
—
—
—
—
—
—
—
—
—
(286)
690,702
855,083
23,518
(6,935)
—
—
(385)
—
—
19,502
—
—
—
—
—
—
—
6,704
$
(127,504)
(6,672)
—
(185)
—
19,353
(97)
2,507,649
See accompanying Notes to Consolidated Financial Statements
77
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION
PDC Energy, Inc. ("PDC", the "Company," "we," "us," or "our") is a domestic independent exploration and production
company that acquires, explores and develops properties for the production of crude oil, natural gas, and NGLs, with primary
operations in the Wattenberg Field in Colorado and the Delaware Basin in Texas. Our operations in the Wattenberg Field are
focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are currently focused in the Wolfcamp
zones. We also have operations in the Utica Shale in Southeastern Ohio; however, in 2017, we began actively marketing the
Utica Shale properties for sale; therefore, these properties are classified as held-for-sale as they met the criteria for such
classification during the third quarter of 2017. In February 2018, we entered into a PSA for the sale of these properties for net
cash proceeds of approximately $40.0 million, subject to the terms and conditions of the agreement. As of December 31, 2017,
we owned an interest in approximately 2,800 productive gross wells. We are engaged in two operating segments: our oil and
gas exploration and production segment and our gas marketing segment. Beginning in 2017, our gas marketing segment does
not meet the quantitative thresholds to require disclosure as a separate reportable segment. All of our material operations are
attributable to our exploration and production business; therefore, all of our operations are presented as a single segment for all
periods presented.
The audited consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries, and our
proportionate share of our two affiliated partnerships. All intercompany accounts and transactions have been eliminated in
consolidation.
The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates
and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual
results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements
include estimates of crude oil, natural gas and NGLs sales revenue; crude oil, natural gas, and NGLs reserves; estimates of
unpaid revenues and unbilled costs; future cash flows from crude oil and natural gas properties; valuation of commodity
derivative instruments; exploratory dry hole costs; impairment of proved and unproved properties; impairment of goodwill;
valuation and allocations of purchased businesses and assets; estimates of fair value of our fixed rate debt instruments; and
valuation of deferred income tax assets.
Certain immaterial reclassifications have been made to our prior period balance sheet and statement of operations to
conform to the current period presentation. The reclassifications had no impact on previously reported cash flows, net earnings,
earnings per share, or stockholders' equity.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be
cash equivalents.
Commodity Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of
crude oil, natural gas, and NGLs. We employ established policies and procedures to manage a portion of the risks associated
with these market fluctuations using commodity derivative instruments. Our policy and our revolving credit facility prohibit
the use of crude oil and natural gas derivative instruments for speculative purposes.
All derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not
to designate any of our commodity derivative instruments as cash flow hedges. Accordingly, changes in the fair value of our
commodity derivative instruments are recorded in the consolidated statements of operations. We use the normal purchase,
normal sale exception for our crude oil and natural gas contracts. Classification of net settlements resulting from maturities and
changes in fair value of unsettled commodity derivatives depends on the purpose for issuing or holding the derivative. Net
settlements and changes in the fair value of commodity derivative instruments related to our Oil and Gas Exploration and
Production segment are recorded in commodity price risk management, net. Net settlements and changes in the fair value of
commodity derivative instruments related to our Gas Marketing segment are recorded in other income and other expenses. The
consolidated statements of cash flows reflects the net settlement of commodity derivative instruments in operating cash flows.
The calculation of the commodity derivative instrument's fair value is performed internally and, while we use common
industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions
could result in significantly different fair values.
78
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Properties and Equipment. Significant accounting polices related to our properties and equipment are discussed
below.
Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful
efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells, and
developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method, based on estimated
proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method
based on estimated proved reserves. We have determined that we have three units-of-production fields: the Wattenberg Field,
the Delaware Basin, and the Utica Shale. In making these conclusions we consider the geographic concentration, operating
similarities within the areas, geologic considerations, and common cost environments in these areas. We calculate quarterly
depreciation, depletion, and amortization ("DD&A") expense by using our estimated prior period-end reserves as the
denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted to add back fourth
quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable
property, the net book value thereof, less proceeds or salvage value, is recognized in the consolidated statement of operations as
a gain or loss. Upon the sale of individual wells or a portion of a field, the proceeds are credited to accumulated DD&A.
Exploration costs, including geologic and geophysical expenses, seismic costs on unproved leasehold, and delay
rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are
initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-
progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of
accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to
justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating
viability, or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory
well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the
end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the
productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as
"suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the
pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s
productive status, the well is removed from suspended well status and the proper accounting treatment is recorded.
Proved Property Impairment. Upon a triggering event, including when general industry conditions warrant review, we
assess our producing crude oil and natural gas properties for possible impairment by comparing net capitalized costs, or
carrying value, to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon
prices at which we reasonably estimate the commodity will be sold. The estimates of future prices may differ from current
market prices of crude oil, natural gas, and NGLs. Certain events, including but not limited to downward revisions in estimates
of our reserve quantities, expectations of falling commodity prices, or rising operating costs, could result in a triggering event,
and therefore a possible impairment of our proved crude oil and natural gas properties. If net capitalized costs exceed
undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future
discounted cash flows analysis. The impairment recorded is the amount by which the net capitalized costs exceed fair value.
Impairments are included in the consolidated statements of operations line item impairment of properties and equipment, with a
corresponding impact on accumulated DD&A.
Unproved Property Impairment. The acquisition costs of unproved properties are capitalized when incurred, until
such properties are transferred to proved properties or charged to expense when expired, impaired, or amortized. Unproved
crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment.
Unproved crude oil and natural gas properties which are not individually significant are amortized, by field, based on our
historical experience, acquisition dates, and average lease terms. Impairment and amortization charges related to unproved
crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of properties
and equipment.
79
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Other Property and Equipment. Other property and equipment is carried at cost. Depreciation is provided principally
on the straight-line method over the assets' estimated useful lives. We review these long-lived assets for impairment whenever
events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of
assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated undiscounted future
cash flows expected to be generated by the asset. If the carrying amount of the asset exceeds our estimated future cash flows,
an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset.
Impairment and amortization charges related to other property and equipment are charged to the consolidated statements of
operations line item impairment of properties and equipment.
The following table presents the estimated useful lives of our other property and equipment:
Transportation, pipeline, and other equipment
Buildings
2 - 30 years
20 - 40 years
Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals
and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition
of assets, the cost and related accumulated DD&A are removed from the accounts, the proceeds are applied thereto, and any
resulting gain or loss is reflected in income. Total depreciation expense related to other property and equipment was $6.6
million, $3.8 million, and $4.5 million in 2017, 2016, and 2015, respectively.
Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in
unproved crude oil and natural gas properties and major development projects, on which DD&A expense is not currently
recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major
construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest
is calculated by multiplying our weighted-average interest rate on our outstanding debt by the qualifying costs. Interest
capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin
amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $5.0 million, $4.5
million, and $5.1 million in 2017, 2016, and 2015, respectively.
Goodwill. Goodwill represents the excess of the purchase price over the fair value of net assets acquired, including
the additional value resulting from the creation of the deferred tax liability, and represents the future economic benefits arising
from other assets acquired that could not be individually identified and separately recognized. Among the factors that could
contribute to a purchase price in excess of the fair value of the net tangible and intangible assets acquired is the acquisition of
an element of a workforce and the expected value from operations of the acquisition to be derived in the future, such as
production from future development of additional producing zones.
We evaluate goodwill for impairment by performing a quantitative test, which involves comparing the estimated fair
value of the goodwill reporting unit to the carrying value. We determine the fair value of the goodwill at the impairment
evaluation date by using an estimated after-tax future discounted cash flow analysis, along with a combination of market-based
pricing factors for similar acreage, reserve valuation techniques, and other fair value considerations. The discounted cash flow
analysis used to estimate fair value is based on known or knowable information at the interim measurement date. Fair value
determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors.
Assets Held-for-Sale. Assets held-for-sale are valued at the lower of their carrying amount or estimated fair value,
less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair
values are estimated using accepted valuation techniques, such as a discounted cash flow model, valuations performed by third
parties, earnings multiples, or indicative bids, when available. Management considers historical experience and all available
information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to
be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not
recorded on assets to be divested once they are classified as held-for-sale. Assets classified as held-for-sale are expected to be
disposed of within one year. Assets to be divested are classified in the consolidated financial statements as held-for-sale.
Production Tax Liability. Production tax liability represents estimated taxes, primarily severance, ad valorem, and
property taxes, to be paid to the states and counties in which we produce crude oil, natural gas, and NGLs. These taxes are
expensed and included in the statements of operations line item production taxes. The long-term portion of the production tax
liability is included in other liabilities on the consolidated balance sheets and was $50.5 million and $29.0 million in
December 31, 2017 and 2016, respectively.
80
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets
and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between
the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and
liabilities are measured using enacted tax rates. The effect on deferred tax assets and liabilities of a change in tax rates is
recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some
portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax
assets to what we consider realizable. As of December 31, 2017 and 2016, we had no valuation allowance.
Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings
using the effective interest method. Debt issuance costs for the 2021 Convertible Notes, the 2024 Senior Notes, and the 2026
Senior Notes are included in long-term debt on the consolidated balance sheets and the debt issuance costs for the revolving
credit facility are included in other assets on the consolidated balance sheets.
Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging
and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an
asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the
liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage
value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated
asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement
cost. Revisions in estimated liabilities can result from, among other things, changes in retirement costs or the estimated timing
of settling asset retirement obligations.
Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs.
Amounts are recorded as a reduction in shareholders’ equity in the consolidated balance sheets. When we retire treasury shares,
we charge any excess of cost over the par value to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC,
with any remaining excess cost being charged to retained earnings.
Revenue Recognition. Significant accounting polices related to our revenue recognition are discussed below.
Crude oil, natural gas, and NGLs sales. Crude oil, natural gas, and NGLs revenues are recognized when production is
sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have
transferred, and collection of revenue is reasonably assured. Our crude oil, natural gas, and NGLs sales are recorded using
either the “net-back” or "gross" method of accounting, depending upon the related purchase agreement. We use the net-back
method when the purchasers of these commodities also provide transportation, gathering, or processing services. In these
situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less
specified deductions. The net-back method results in the recognition of a net sales price that is lower than the indices for which
the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are
paid.
We use the gross method of accounting when the purchasers do not provide transportation, gathering, or processing
services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable
transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and
recognize transportation, gathering, and processing expenses.
There is a new revenue standard effective for annual reporting periods beginning after December 15, 2017. See
Recently Issued Accounting Standards below.
Accounting for Business Combinations. We utilize the purchase method to account for acquisitions of businesses.
Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based
upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted
cash flows, quoted market prices, and estimates by management, which are Level 3 inputs. When appropriate, we review
comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for
fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such
properties.
In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most
significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-
81
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
producing, proved undeveloped, unproved crude oil and natural gas properties, and other non-crude oil and natural gas
properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We
estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and
estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved
reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined
appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional
project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the
discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for
acquisitions with significant unproved properties, we complete an analysis of comparable purchased properties to determine an
estimation of fair value.
We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities, except
goodwill. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities
assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional
information becomes known.
Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the grant-
date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements
on a straight-line basis over the vesting period for the entire award. To the extent compensation cost relates to employees
directly involved in crude oil and natural gas exploration and development activities, such amounts may be capitalized to
properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense
line item in the consolidated statements of operations. No amounts for stock-based compensation were capitalized in 2017,
2016, or 2015.
Credit Risk and Allowance for Doubtful Accounts. Inherent to our industry is the concentration of crude oil, natural
gas, and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to
credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices,
or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our
existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and the overall
creditworthiness of our customers. Further, consideration is given to well production data for receivables related to well
operations.
Recently Adopted Accounting Standards.
In January 2017, the FASB issued an accounting update to simplify the measurement of goodwill. The update
eliminates the two-step process that required identification of potential impairment and a separate measure of actual
impairment. The annual and/or interim assessments are still required to be completed. The guidance is effective for fiscal
years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted. We
elected to early adopt this standard in the second quarter of 2017. Our annual evaluation of goodwill for impairment was
expected to occur in the fourth quarter of 2017; however, we experienced an impairment triggering event as of September 30,
2017 and implemented the new guidance as part of the impairment evaluation. See the footnote titled Goodwill for a detailed
description of the results of our impairment testing.
In August 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice
in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The update
addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The guidance is
effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early
adoption permitted. We elected to early adopt this standard in the fourth quarter of 2017. Adoption of this standard did not
have an impact on our consolidated financial statements or related disclosures.
In January 2017, the FASB issued an accounting update clarifying the definition of a business, with the objective of
adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of
assets or businesses. This guidance is to be applied using a prospective method and is effective for fiscal years beginning after
December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We elected to early adopt this
standard in the fourth quarter of 2017. Adoption of this standard did not have an impact on our consolidated financial
statements or related disclosures.
82
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
In May 2017, the FASB issued an accounting update clarifying when to account for a change to the terms or
conditions of a share-based payment award as a modification. The guidance is effective for fiscal years beginning on or after
December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We elected to early adopt
this standard in the fourth quarter of 2017. Adoption of this standard did not have an impact on our consolidated financial
statements or related disclosures.
Recently Issued Accounting Standards
In May 2014, the FASB and the International Accounting Standards Board issued their converged standard on
revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement of
revenue and timing of when it is recognized. The standard has been updated and now includes technical corrections. The
underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an
amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step
approach to apply the underlying principle: (1) identify the contract with the customer, (2) identify the separate performance
obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to separate performance
obligations, and (5) recognize revenue when or as each performance obligation is satisfied. The revenue standard is
effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting
period; we are adopting the standard effective January 1, 2018. The revenue standard can be adopted under the full
retrospective method or modified retrospective method. In order to evaluate the impact that the adoption of the revenue
standard will have on our consolidated financial statements, we have performed a comprehensive review of our significant
revenue streams. The focus of this review included, among other things, the identification of the significant contracts and
other arrangements we have with our customers to identify performance obligations and principal versus agent
considerations, and factors affecting the determination of the transaction price. We are also reviewing our current
accounting policies, procedures, and controls with respect to these contracts and arrangements to determine what changes, if
any, may be required by the adoption of the revenue standard. We have determined that we will adopt the standard under
the modified retrospective method. Based upon our review, we currently estimate that adoption of the standard would have
reduced our crude oil, natural gas, and NGLs sales by approximately $11.3 million in 2017 with corresponding decreases in
transportation, gathering, and processing expenses and no impact on net earnings. Upon adoption, no adjustment to our
opening balance of retained earnings was deemed necessary.
In February 2016, the FASB issued an accounting update aimed at increasing the transparency and comparability
among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about
related leasing arrangements. For leases with terms of more than 12 months, the accounting update requires lessees to
recognize a right-of-use asset and lease liability for its right to use the underlying asset and the corresponding lease
obligation. Both the lease asset and liability will initially be measured at the present value of the future minimum lease
payments over the lease term. Subsequent measurement, including the presentation of expenses and cash flows, will depend
upon the classification of the lease as either a finance or operating lease. The guidance is effective for fiscal years beginning
after December 15, 2018, and interim periods within those years, with early adoption permitted, and is to be applied as of the
beginning of the earliest period presented using a modified retrospective approach. The update does not apply to leases of
mineral rights to explore for or use crude oil and natural gas. We are currently evaluating the impact these changes may have
on our consolidated financial statements.
In November 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice
in the classification and presentation of changes in restricted cash. The accounting update requires that a statement of cash
flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted
cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash or restricted cash equivalents
should be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period amounts shown on
the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods
within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our
consolidated financial statements.
In August 2017, the FASB issued an accounting update to provide guidance for various components of hedge
accounting, including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in
the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The
guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with
early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial
statements.
83
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
NOTE 3 - BUSINESS COMBINATIONS
Delaware Basin Acquisition. On December 6, 2016, we closed on an acquisition which was accounted for as a
business combination. The acquisition consisted of the purchase of stock of an entity and assets of other entities under
common control. The transaction was for the purchase of approximately 57,900 net acres, approximately 30 completed and
producing wells and related midstream infrastructure in Reeves and Culberson Counties, Texas, for an aggregate consideration
to the sellers of approximately $1.64 billion, after preliminary post-closing adjustments. The total consideration to sellers was
comprised of approximately $946.0 million in cash, including the payment of $40.0 million of debt of the sellers at closing and
other purchase price adjustments, and 9.4 million shares of our common stock valued at approximately $690.7 million at the
time the acquisition closed. The purchase accounting for the entity, the stock of which we acquired, reflected oil and gas assets
for which we did not receive a fair value step-up of the tax basis. As a result, a significant deferred income tax liability was
calculated based on the acquired allocated fair value of the assets in excess of the tax basis of assets inside the entity. This
calculation resulted in approximately $375.0 million of non-cash basis needing to be allocated to the acquired assets. No
deferred tax liability was established for the calculated goodwill as it did not qualify as tax goodwill.
The final fair value allocation of the assets acquired and liabilities assumed in the acquisition are presented below and
include customary post-closing adjustments. The most significant item to be completed during the final purchase price
allocation in the third quarter of 2017 was the final allocation of value to the unproved oil and gas properties associated with
the acquired acreage. Adjustments to the preliminary purchase price primarily stem from additional information we obtained
about facts and circumstances that existed at the acquisition date that impact the underlying value of certain assets acquired and
liabilities assumed, including detailed lease terms, location of the acreage, and intent to develop the acreage as of the date of
closing. There were a significant number of leases acquired with complex lease terms and evaluation of these terms and the
timing of the lease expirations impacted the manner in which the final purchase price was allocated. Our final determination of
the value of goodwill has been adjusted for all post-closing adjustments.
The details of the final purchase price and the allocation of the purchase price for the transaction, are presented below
(in thousands):
Year Ended December 31, 2016
Acquisition costs:
Cash, net of cash acquired
Retirement of seller's debt
Total cash consideration
Common stock
Other purchase price adjustments
Total acquisition costs
Recognized amounts of identifiable assets acquired and liabilities assumed:
Assets acquired:
Current Assets
Crude oil and natural gas properties - proved
Crude oil and natural gas properties - unproved
Infrastructure, pipeline, and other
Construction in progress
Goodwill
Total assets acquired
Liabilities assumed:
Current liabilities
Asset retirement obligations
Deferred tax liabilities, net
Total liabilities assumed
Total identifiable net assets acquired
84
$
$
$
$
905,962
40,000
945,962
690,702
426
1,637,090
6,401
216,000
1,697,000
33,153
12,323
75,121
2,039,998
(24,496)
(3,705)
(374,707)
(402,908)
1,637,090
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in
the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement
obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant
inputs to the valuation of crude oil and natural gas properties include estimates of reserves, future operating and development
costs, future commodity prices, estimated future cash flows, lease terms and expirations, and a market-based weighted-average
cost of capital rate. Within the unproven properties, the allocation of the value to the underlying leases also required significant
judgment and was based on a combination of comparable market transactions, the terms and conditions associated with the
individual leases, our ability and intent to develop specific leases, and our initial assessment of the underlying relative value of
the leases given our knowledge of the geology at the time of closing. These inputs require significant judgments and estimates
by management at the time of the valuation and were the most sensitive and subject to change.
This acquisition was accounted for under the acquisition method. Accordingly, we conducted assessments of net
assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition
date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred.
Pro Forma Information. The results of operations for the Delaware Basin acquisition have been included in our
consolidated financial statements since the December 6, 2016 closing date, including approximately $5.6 million of total
revenue and $1.7 million of loss from operations in our statements of operations for the year ended December 31, 2016. The
following unaudited pro forma financial information represents a summary of the consolidated results of operations for the
years ended December 31, 2016 and December 31, 2015, assuming the acquisition had been completed as of January 1, 2015.
This pro forma financial information includes proceeds from the sale of 9,085,000 shares of our common stock, the 2021
Convertible Notes, and the 2024 Senior Notes in September 2016, the shares issued to the sellers, and other acquisition costs.
The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if
the acquisition had been effective as of these dates, or of future results.
Total revenue
Net loss
Earnings per share:
Basic and diluted
Years Ended December 31,
2016
2015
(in thousands, except per share amounts)
412,746
(270,942)
$
$
598,932
(138,904)
(4.22)
$
(2.41)
$
$
$
Goodwill. Goodwill was calculated as the excess of the purchase price over the fair value of net assets acquired,
including the additional value resulting from the creation of the deferred tax liability, and represents the future economic
benefits arising from other assets acquired that could not be individually identified and separately recognized. Among the
factors that contributed to a purchase price in excess of the fair value of the net tangible and intangible assets acquired were the
acquisition of an element of a workforce and the expected value from operations of the Delaware Basin acquisition to be
derived in the future, such as production from future development of additional producing zones. The amount of the final
goodwill that was recorded in the third quarter of 2017 related to the Delaware Basin acquisition was $75.1 million, which was
higher than the initial estimated amount recorded as of December 31, 2016. The increase primarily related to finalization of the
aggregate acreage position acquired and the related lease terms and a final settlement with the sellers in connection with a
revised valuation of certain acquired leases and the retirement of estimated environmental remediation liabilities. Any value
assigned to goodwill was not expected to be deductible for income tax purposes.
The following table presents the changes in goodwill from the preliminary allocation at December 31, 2016, and the
final allocation determined during the third quarter of 2017:
Preliminary purchase price allocation
Adjustments
Final purchase price allocation
85
Amount
(in thousands)
$
$
62,041
13,080
75,121
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
See the footnote titled Goodwill for the details regarding the impairment of goodwill related to the Delaware Basin
acquisition.
86
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
NOTE 4 - FAIR VALUE OF FINANCIAL INSTRUMENTS
Commodity Derivative Financial Instruments
Determination of fair value. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires
us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The
valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date,
giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3).
In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level
input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy.
Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering
factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the
fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:
Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets.
Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for
the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for
identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the
asset or liability, and inputs that are derived from observable market data by correlation or other means.
Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity.
Commodity Derivative Financial Instruments. We measure the fair value of our commodity derivative instruments
based on a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying
position, current market prices, crude oil and natural gas forward curves, discount rates such as the LIBOR curve for a similar
duration of each outstanding position, volatility factors, and nonperformance risk. Nonperformance risk considers the effect of
our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair
value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each
outstanding derivative position.
We validate our fair value measurement through the review of counterparty statements and other supporting
documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs
through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and
assumptions. While we use common industry practices to develop our valuation techniques and believe our valuation method
is appropriate and consistent with those used by other market participants, changes in our pricing methodologies or the
underlying assumptions could result in significantly different fair values.
Our crude oil and natural gas fixed-price swaps are included in Level 2. Our collars and propane fixed-price swaps
are included in Level 3. Our basis swaps are included in Level 2 and Level 3. The following table presents, for each applicable
level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions,
measured at fair value on a recurring basis:
As of December 31,
Significant
Other
Observable
Inputs
(Level 2)
2017
Significant
Unobservable
Inputs
(Level 3)
Total
Significant
Other
Observable
Inputs
(Level 2)
2016
Significant
Unobservable
Inputs
(Level 3)
Total
(in thousands)
Total assets
Total liabilities
Net liability
$
$
$
12,949
90,569
(77,620) $
$
1,389
11,076
(9,687) $
$
14,338
101,645
(87,307) $
$
6,350
66,789
(60,439) $
$
4,827
14,401
(9,574) $
11,177
81,190
(70,013)
87
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The following table presents a reconciliation of our Level 3 commodity derivative instruments measured at fair value:
2017
2016
(in thousands)
2015
Fair value of Level 3 instruments, net asset (liability) beginning of period
$
(9,574) $
91,288
$
62,356
Changes in fair value included in consolidated statements of operations line item:
Commodity price risk management gain (loss), net
6,241
(28,550)
65,164
Settlements included in consolidated statements of operations line items:
Commodity price risk management (loss), net
Fair value of Level 3 instruments, net asset (liability) end of period
Net change in fair value of Level 3 unsettled derivatives included in consolidated
statements of operations line item:
Commodity price risk management gain (loss), net
Total
$
$
$
(6,354)
(9,687) $
(72,312)
(9,574) $
(36,232)
91,288
(866) $
(866) $
(12,905) $
(12,905) $
43,540
43,540
The significant unobservable input used in the fair value measurement of our derivative contracts is the implied
volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in
isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our
Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3
derivative contracts during the periods covered by the financial statements.
Non-Derivative Financial Assets and Liabilities
The carrying value of the financial instruments included in current assets and current liabilities approximate fair value
due to the short-term maturities of these instruments.
We utilize fair value on a nonrecurring basis to review our crude oil and natural gas properties and goodwill for
possible impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of
such assets. The fair value of the properties is determined based upon estimated future discounted cash flow, a Level 3 input,
using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. The fair value
of the goodwill is determined using either a qualitative method or a quantitative method, both of which utilize market data, a
Level 3 input, in the derivation of the value estimation.
The portion of our long-term debt related to our revolving credit facility approximates fair value due to the variable
nature of related interest rates. We have not elected to account for the portion of our debt related to our senior notes under the
fair value option; however, we have determined an estimate of the fair values based on measurements of trading activity and
broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. The table below
presents these estimates of the fair value of the portion of our long-term debt related to our senior notes and convertible notes
as of December 31, 2017:
Senior notes:
2021 Convertible Notes
2024 Senior Notes
2026 Senior Notes
Estimated Fair
Value
(in millions)
$
195.6
416.0
616.5
% of Par
97.8%
104.0%
102.8%
The carrying value of our capital lease obligations approximates fair value due to the variable nature of the imputed
interest rates and the duration of the related vehicle lease.
88
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
NOTE 5 - COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS
Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas,
and NGLs. To manage a portion of our exposure to price volatility from producing crude oil, natural gas, and propane, which
is an element of our NGLs, we enter into commodity derivative contracts to protect against price declines in future periods.
While we structure these commodity derivatives to reduce our exposure to decreases in commodity prices, they also limit the
benefit we might otherwise receive from price increases.
We believe our commodity derivative instruments continue to be effective in achieving the risk management
objectives for which they were intended. As of December 31, 2017, we had commodity derivatives positions covering
approximately 11.9 MMBbls and 6.6 MMBbls of crude oil production for 2018 and 2019, respectively. As of the same date,
we had hedged approximately 56.5 Bcf of natural gas and 1.1 MMBbls of propane for 2018. Our commodity derivative
contracts have been entered into at no cost to us as we hedge our anticipated production at the then-prevailing commodity
market prices, without adjustment for premium or discount.
As of December 31, 2017, our derivative instruments were comprised of collars, fixed-price commodity swaps, and
basis protection swaps.
• Collars contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike
price, we receive the market price from the purchaser and receive the difference between the put strike price and
index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market
price from the purchaser and pay the difference between the call strike price and index price to the counterparty.
If the index price is between the put and call strike price, no payments are due to or from the counterparty;
Fixed-price commodity swaps are arrangements that guarantee a fixed price. If the index price is below the fixed
contract price, we receive the market price from the purchaser and receive the difference between the index price
and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive
the market price from the purchaser and pay the difference between the index price and the fixed contract price
to the counterparty. If the index price and contract price are the same, no payment is due to or from the
counterparty;
•
• Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified
delivery point. For basis protection swaps, we receive a payment from the counterparty if the price differential is
greater than the stated terms of the contract and pay the counterparty if the price differential is less than the
stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the
counterparty. See Item 7a. - Quantitative and Qualitative Disclosures About Market Risk - Derivative Positions
Table found elsewhere in this report for a detailed list of our basis protection swaps.
We have elected not to designate any of our derivative instruments as cash flow hedges, and therefore do not qualify
for the use of hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the
statements of operations.
89
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The following table presents the balance sheet location and fair value amounts of our commodity derivative
instruments on the consolidated balance sheets as of December 31, 2017 and 2016:
Derivative instruments:
Derivative assets:
Current
Consolidated balance
sheet line item
2017
2016
(in thousands)
Commodity derivative contracts
Basis protection derivative contracts
Fair value of derivatives
Fair value of derivatives
Non-current
Commodity derivative contracts
Basis protection derivative contracts
Fair value of derivatives
Fair value of derivatives
Total derivative assets
Derivative liabilities:
Current
Commodity derivative contracts
Basis protection derivative contracts
Rollfactor derivative contracts
Fair value of derivatives
Fair value of derivatives
Fair value of derivatives
Non-current
Commodity derivative contracts
Fair value of derivatives
Total derivative liabilities
$
$
$
$
$
$
7,340
6,998
14,338
—
—
—
14,338
77,999
234
1,069
79,302
22,343
101,645
$
8,490
301
8,791
1,123
1,263
2,386
11,177
53,565
30
—
53,595
27,595
81,190
90
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The following table presents the impact of our derivative instruments on our consolidated statements of operations:
Consolidated statements of operations line item
2017
Year Ended December 31,
2016
(in thousands)
2015
Commodity price risk management gain (loss), net
Net settlements
Net change in fair value of unsettled derivatives
Total commodity price risk management gain (loss), net
$
$
$
13,324
(17,260)
(3,936) $
$
208,103
(333,784)
(125,681) $
238,935
(35,752)
203,183
All of our financial derivative agreements contain master netting provisions that provide for the net settlement of all
contracts through a single payment in the event of early termination. We have elected not to offset the fair value positions
recorded on our consolidated balance sheets.
The following table reflects the impact of netting agreements on gross derivative assets and liabilities:
As of December 31, 2017
Asset derivatives:
Derivative instruments, at fair value
Liability derivatives:
Derivative instruments, at fair value
Derivative
instruments, gross
Effect of master
netting agreements
(in thousands)
Derivative
instruments, net
$
$
14,338
$
(14,173) $
165
101,645
$
(14,173) $
87,472
As of December 31, 2016
Asset derivatives:
Derivative instruments, at fair value
Liability derivatives:
Derivative instruments, at fair value
Derivative
instruments, gross
Effect of master
netting agreements
(in thousands)
Derivative
instruments, net
$
$
11,177
$
(10,930) $
247
81,190
$
(10,930) $
70,260
91
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
NOTE 6 - CONCENTRATION OF RISK
Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful
accounts:
As of December 31,
2017
2016
(in thousands)
Crude oil, natural gas, and NGLs sales
Joint interest billings (1)
Derivative counterparties
Income tax receivable
Other
Allowance for doubtful accounts
Accounts receivable, net
$
$
154,260
34,576
(18)
6,015
5,893
(3,128)
197,598
$
$
97,520
20,118
10,266
11,505
6,173
(2,190)
143,392
_________
(1) The December 31, 2017 amount includes $13.9 million of pre-closing contracted completion costs of wells associated
with the Bayswater Acquisition, which closed in January 2018. Upon closing, the $13.9 million was capitalized and
included in properties and equipment, net on the consolidated balance sheet.
Our accounts receivable primarily relate to sales of our crude oil, natural gas, and NGLs production, receivable
balances from other third parties that own working interests in the properties we operate, and derivative counterparties. For the
years ended December 31, 2017 and 2016, amounts written off to allowance for doubtful accounts were not material. As of
December 31, 2017 and 2016, none of our customers represented 10 percent or greater of our accounts receivable balance.
Major Customers. The following table presents the individual customers constituting 10 percent or more of total
revenues:
Customer
DCP Midstream, LP
Suncor Energy Marketing, Inc.
Aka Energy Group, LLC
Concord Energy, LLC
Bridger Energy, LLC
Shell Trading Company
Year Ended December 31,
2017
2016
2015
19.6%
16.4%
—%
—%
—%
—%
20.2%
22.3%
13.4%
13.4%
11.5%
—%
13.2%
14.3%
—%
23.2%
—%
13.8%
Derivative Counterparties. A portion of our liquidity relates to commodity derivative instruments that enable us to
manage a portion of our exposure to price volatility from producing crude oil, natural gas, and NGLs. These arrangements
expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also major
lenders under our revolving credit facility as counterparties to our commodity derivative contracts; however, an insignificant
portion of our commodity derivative instruments may be with other counterparties. To date, we have had no derivative
counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant
credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each
outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of
our current counterparties on the fair value of our derivative instruments is not significant at December 31, 2017, taking into
account the estimated likelihood of nonperformance.
Note Receivable. In October 2014, we sold our entire 50 percent ownership interest in PDC Mountaineer, LLC to an
unrelated third-party. As part of the consideration, we received a promissory note (the “Promissory Note”) for a principal sum of
$39.0 million, bearing variable interest rates. The interest was to be paid quarterly, in arrears and at the option of the issuer could
be paid-in-kind (“PIK Interest”). Any such PIK Interest would be subject to the then current interest rate.
We regularly analyzed the Promissory Note for evidence of collectibility, evaluating factors such as the
creditworthiness of the issuer of the Promissory Note and the value of the issuer's assets. Based upon this analysis, during the
quarter ended March 31, 2016, we recognized a provision and recorded an allowance for uncollectible notes receivable for the
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PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
$44.0 million accumulated outstanding balance, including interest. Commencing in the second quarter of 2016, we ceased
recognizing interest income on the Promissory Note and began accounting for the interest on the Promissory Note under the
cash basis method.
We performed this analysis as of March 31, 2017 and evaluated preliminary 2016 year-end financial statements of the
note issuer which were available at such time, related information about the operations of the issuer, and existing market
conditions for natural gas. Based upon this evaluation, it was determined that collection of the Promissory Note and the PIK
Interest continued to be doubtful and the full valuation allowance on the Promissory Note remained appropriate as of that date.
This evaluation assumed that repayment of the Promissory Note would be made exclusively from the existing operations of the
issuer of the Promissory Note based on the latest available information.
In April 2017, we sold the Promissory Note to an unrelated third-party buyer for approximately $40.2 million in cash.
The sales agreement transferred all of our legal rights to collect from the issuer of the Promissory Note. Accordingly, we
reversed $40.2 million of the provision for uncollectible notes receivable during the second quarter of 2017.
Other Accrued Expenses. The following table presents the components of other accrued expenses:
As of December 31,
2017
2016
(in thousands)
Employee benefits
Asset retirement obligations
Environmental expenses
Other
Other accrued expenses
$
$
22,383
15,801
1,374
3,429
42,987
$
$
22,282
9,775
3,238
3,330
38,625
NOTE 7 - PROPERTIES AND EQUIPMENT
The following table presents the components of properties and equipment, net of accumulated DD&A:
Properties and equipment, net:
Crude oil and natural gas properties
Proved
Unproved
Total crude oil and natural gas properties
Infrastructure, pipeline, and other
Land and buildings
Construction in progress
Properties and equipment, at cost
Accumulated DD&A
Properties and equipment, net
As of December 31,
2017
2016
(in thousands)
$
$
4,356,922
1,097,317
5,454,239
109,359
10,960
196,024
5,770,582
(1,837,115)
3,933,467
$
$
3,499,718
1,874,671
5,374,389
62,093
6,392
122,591
5,565,465
(1,562,471)
4,002,994
Acreage Exchanges. In the fourth quarter of 2017, we completed two significant acreage exchanges that consolidated
certain acreage positions in the core area of the Wattenberg Field. Pursuant to the transactions, we exchanged leasehold
acreage with a limited number of wells that were in the process of being drilled and completed. Upon closing, we received an
aggregate of approximately 15,900 net acres in exchange for an aggregate of approximately 16,200 net acres with minimal cash
exchanged between the parties. The differences in net acres are primarily due to variances in working and net revenue interests
and in midstream contracts. The assets exchanged were all in the same unit-of-production for property considerations, so it was
concluded that this transaction was outside of the scope of the accounting requirements for recording the transaction at fair
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PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
value and determining gain or loss on the non-monetary exchanges. The new acreage and underlying property costs were
recorded at the previous historical cost of the assets we exchanged.
In September 2016, we closed on an acreage exchange transaction with Noble Energy, Inc. and certain of its
subsidiaries ("Noble") to consolidate certain acreage positions in the core area of the Wattenberg Field. Pursuant to the
transaction, we exchanged leasehold acreage and, to a lesser extent, interests in certain development wells. Upon closing, we
received approximately 13,500 net acres in exchange for approximately 11,700 net acres, with no cash exchanged between the
parties. The assets exchanged were all in the same unit of production for property considerations, so it was concluded that this
transaction was outside of the scope of the accounting requirements for recording the transaction at fair value and determining
gain or loss on the non-monetary exchanges. The new acreage and underlying property costs were recorded at the previous
historical cost of the assets we exchanged.
Delaware Basin Acreage Acquisition. On December 30, 2016, we closed the purchase of approximately 4,600 net
bolt-on acres in Reeves and Culberson Counties, Texas, for consideration to the sellers of approximately $120.6 million in cash,
subject to post-closing adjustments. The transaction was accounted for as an acquisition of assets.
Classification of Assets as Held-for-Sale. During the third quarter of 2017, as part of our plan to divest the Utica Shale
properties, we engaged an investment banking firm and began actively marketing the properties for sale; therefore, these
properties are classified as held-for-sale as they met the criteria for such classification beginning in the third quarter of 2017. In
February 2018, we entered into a PSA for the sale of these properties for net cash proceeds of approximately $40.0 million,
subject to certain customary closing adjustments. Based upon multiple offers received for the sale of our Utica Shale
properties, we recorded an impairment charge of $2.1 million in 2017 to reflect their fair value. Assets held-for-sale as of
December 31, 2017 included $36.8 million and $3.3 million, representing of our Utica Shale properties and field office
facilities and a parcel of land, respectively. Assets held-for-sale as of December 31, 2016 of $5.3 million represented field
office facilities and a parcel of land at that time.
The following table presents balance sheet data related to assets held-for-sale, which include the Utica Shale
properties, field office facilities, and a parcel of land that are being marketed for sale. Assets held-for-sale represents the assets
that are expected to be sold, net of liabilities that are expected to be assumed by the purchasers:
Assets
Properties and equipment, net
Total assets
Liabilities
Asset retirement obligation
Total liabilities
Net assets
December 31, 2017
December 31, 2016
(in thousands)
$
$
$
$
$
40,583
40,583
499
499
40,084
$
$
$
$
$
5,272
5,272
—
—
5,272
Impairment of Properties and Equipment
The following table presents impairment charges recorded for properties and equipment:
2017
Year Ended December 31,
2016
(in thousands)
2015
Impairment of proved and unproved properties
Amortization of individually insignificant unproved properties
Land and buildings
Total impairment of properties and equipment
$
$
285,465
422
—
285,887
$
$
5,562
1,379
3,032
9,973
$
$
154,608
7,012
—
161,620
During the third quarter of 2017, we recorded a charge related to two exploratory dry holes we had drilled in the
western area of our Culberson County acreage in the Delaware Basin. We then assessed the impact of the dry holes and various
factors related thereto, including (i) the operational and geologic data obtained, (ii) the current increased cost environment for
94
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
drilling and completion services in the Delaware Basin, (iii) our decreased future commodity price outlook, and (iv) the terms
of the related lease agreements. Based on the results of this assessment, we concluded that the underlying geologic risk and the
challenged economics of future capital expenditures reduced the likelihood that we would perform future development in this
area over the remaining lease term for this acreage. Accordingly, we recorded an impairment of $251.6 million covering
approximately 13,400 acres during the third quarter of 2017. The amount of the impairment was based on the value assigned to
individual lease acres in the final purchase price allocation of the Delaware Basin acquisition. This allocation had included the
consideration paid to the sellers, including the effect of the non-cash impact from the deferred tax liability created at the time of
the acquisition. We recorded approximately $29 million of additional lease impairments in the Delaware Basin and an
impairment charge of $2.1 million related to the Utica Shale properties that are classified as held-for-sale during 2017. Due to
the aforementioned events and circumstances, we also evaluated our proved property for possible impairment and concluded
that no further impairments were necessary. Future deterioration of commodity prices or other operating circumstances could
result in additional impairment charges to our properties and equipment.
During 2015, due to a significant decline in commodity prices and decreases in our net realized sales prices, we
experienced triggering events that required us to assess our crude oil and natural gas properties for possible impairment. As a
result of our assessments, we recorded impairment charges of $150.3 million in 2015 to write-down our Utica Shale proved and
unproved properties. Of these impairment charges, $24.7 million were recorded in 2015 to write-down certain capitalized well
costs on our Utica Shale proved producing properties. We also recorded impairment charges of $125.6 million to write-down
our Utica Shale lease acquisition costs. The impairment charges, which are included in the consolidated statements of
operations line item impairment of properties and equipment, represented the amount by which the carrying value of these
crude oil and natural gas properties exceeded the estimated fair values.
Suspended Well Costs. We have spud three wells in the Delaware Basin for which we are unable to make a final
determination regarding whether proved reserves can be associated with the wells as of December 31, 2017 as the wells had not
been completed as of that date. Therefore, we have classified the capitalized costs of the wells as suspended well costs as of
December 31, 2017 while we continue to conduct completion and testing operations to determine the existence of proved
reserves.
The following table presents the capitalized exploratory well cost pending determination of proved reserves and
included in properties and equipment, net on the consolidated balance sheet:
2017
(in thousands, except
for number of wells)
Beginning balance
Additions to capitalized exploratory well costs pending the
determination of proved reserves
Reclassifications to proved properties
Balance at December 31,
$
$
Number of wells pending determination at December 31,
—
51,776
(36,328)
15,448
3
We did not have any suspended well costs as of December 31, 2016 or 2015.
Exploration Expenses. The following table presents the major components of exploration, geologic, and geophysical
expense:
95
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
2017
Year Ended December 31,
2016
(in thousands)
2015
Exploratory dry hole costs
Geological and geophysical costs, including seismic purchases
Operating, personnel and other
Total exploration, geologic, and geophysical expense
$
$
41,297
3,881
2,156
47,334
$
$
— $
3,472
1,197
4,669
$
—
—
1,102
1,102
Exploratory dry hole costs. During the third quarter of 2017, two exploratory dry hole wells, associated lease costs,
and related infrastructure assets in the Delaware Basin were expensed at a cost of $41.3 million. The conclusion to expense
these items was based on our determination that the acreage on which these wells were drilled was exploratory in nature and,
following drilling, that the hydrocarbon production was insufficient for the wells to be deemed economically viable.
NOTE 8 - GOODWILL
The final goodwill that resulted from the purchase price allocation of the business combination in the Delaware Basin
in December 2016 was determined to be $75.1 million. With the creation of goodwill from this transaction, we expected to
perform our evaluation of goodwill for impairment annually in the fourth quarter. However, primarily due to a combination of
increases in per well development and operational costs and our drilling of two exploratory dry holes in the Delaware Basin
subsequent to the acquisition, in conjunction with the then current lower future commodity price outlook, we determined that a
triggering event had occurred in the third quarter of 2017. In addition to the factors mentioned above, we also considered our
impairments of certain unproven leasehold costs during the third quarter of 2017 and the impact of these items on our internal
expectations for acceptable rates of return. We evaluated goodwill for impairment by performing a quantitative test, which
involves comparing the estimated fair value of the goodwill reporting unit, which we define as the Delaware Basin, to the
carrying value. We determined the fair value of the goodwill at September 30, 2017 by using an estimated after-tax future
discounted cash flow analysis, along with a combination of market-based pricing factors for similar acreage, reserve valuation
techniques, and other fair value considerations. The discounted cash flow analysis used to estimate fair value was based on
known or knowable information at the interim measurement date. Fair value determinations require considerable judgment and
are sensitive to changes in underlying assumptions and factors. The quantitative test resulted in a determination that a full
impairment charge of $75.1 million was required; therefore, the charge was recorded in the third quarter of 2017.
96
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
NOTE 9 - LONG-TERM DEBT
Long-term debt consists of the following:
Senior notes:
1.125% Convertible Notes due 2021:
Principal amount
Unamortized discount
Unamortized debt issuance costs
1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance
costs
6.125% Senior Notes due 2024:
Principal amount
Unamortized debt issuance costs
6.125% Senior Notes due 2024, net of unamortized debt issuance costs
5.75% Senior Notes due 2026:
Principal amount
Unamortized debt issuance costs
5.75% Senior Notes due 2026, net of unamortized debt issuance costs
7.75% Senior notes redeemed 2017:
Principal amount
Unamortized debt issuance costs
7.75% Senior notes redeemed 2017, net of unamortized debt issuance costs
As of December 31,
2017
2016
(in thousands)
$
$
200,000
(30,328)
(3,615)
166,057
400,000
(6,570)
393,430
600,000
(7,555)
592,445
200,000
(37,475)
(4,584)
157,941
400,000
(7,544)
392,456
—
—
—
—
—
—
500,000
(6,443)
493,557
Total senior notes
1,151,932
1,043,954
Revolving credit facility
Total long-term debt, net of unamortized discount and debt issuance costs
Less current portion of long-term debt
Long-term debt
—
1,151,932
—
1,151,932
$
—
1,043,954
—
1,043,954
$
Senior Notes
2026 Senior Notes. In November 2017, we issued $600.0 million aggregate principal amount 5.75% senior notes due
May 15, 2026, in a private placement to qualified institutional buyers. The 2026 Senior Notes are governed by an indenture
dated November 29, 2017 between us and the U.S. Bank National Association, as trustee. The maturity for the payment of
principal is May 15, 2026. Interest at the rate of 5.75% per year is payable in cash semiannually in arrears on each May 15 and
November 15, commencing on May 15, 2018. Approximately $7.6 million in costs associated with the issuance of the 2026
Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes
using the effective interest method. The 2026 Senior Notes are senior unsecured obligations and rank senior in right of
payment to our future indebtedness that is expressly subordinated to the notes; equal in right of payment to all our existing and
future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the
extent of the value of the collateral securing such indebtedness, including borrowings under our revolving credit facility; and
structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries.
The 2026 Senior Notes are redeemable after May 15, 2021, at fixed redemption prices beginning at 104.313 percent of
the principal amount redeemed. At any time prior to May 15, 2021, we may redeem all or part of the 2026 Senior Notes at a
97
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
make-whole price set forth in the indenture which generally approximates the present value of the redemption price at May 15,
2021 and remaining interest payments on the 2026 Senior Notes at the time of redemption.
At any time prior to May 15, 2021 we may redeem up to 35 percent of the outstanding 2026 Senior Notes with
proceeds from certain equity offerings at a redemption price of 105.75 percent of the principal amount of the notes redeemed,
plus accrued and unpaid interest, if at least 65 percent of the aggregate principal amount of the 2026 Senior Notes remains
outstanding after each such redemption and the redemption occurs within 180 days after the closing of the equity offering.
Upon the occurrence of a "change of control," as defined in the indenture for the 2026 Senior Notes, holders will have
the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal
amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with
certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an
offer to purchase the notes at 100 percent of the principal amount, together with any accrued and unpaid interest to the date of
purchase.
The indenture governing the 2026 Senior Notes contains covenants that, among other things, limit our ability and the
ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or
redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict
distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or
merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries.
2021 Convertible Notes. In September 2016, we issued $200.0 million of 1.125% convertible senior notes due 2021
in a public offering. The 2021 Convertible Notes are governed by an indenture dated September 14, 2016 between us and the
U.S. Bank National Association, as trustee. The maturity for the payment of principal is September 15, 2021. Interest at the
rate of 1.125% per year is payable in cash semiannually in arrears on each March 15 and September 15, commencing on March
15, 2017. The 2021 Convertible Notes are senior unsecured obligations and rank senior in right of payment to our future
indebtedness that is expressly subordinated to the 2021 Convertible Notes; equal in right of payment to our existing and future
indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent
of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including
trade payables) incurred by our non-guarantor subsidiaries. The proceeds from the issuance of the 2021 Convertible Notes,
after deducting offering expenses and underwriting discounts, were used to fund a portion of the purchase price of acquisitions
in the Delaware Basin, to pay related fees and expenses, and for general corporate purposes.
The 2021 Convertible Notes are convertible prior to March 15, 2021 only upon specified events and during specified
periods and, thereafter, at any time, in each case at an initial conversion rate of 11.7113 shares of our common stock per $1,000
principal amount of the 2021 Convertible Notes, which is equal to an initial conversion price of approximately $85.39 per
share. The conversion rate is subject to adjustment upon certain events. Upon conversion, the 2021 Convertible Notes may be
settled, at our sole election, in shares of our common stock, cash, or a combination of cash and shares of our common stock.
We have initially elected a combination settlement method to satisfy our conversion obligation, which allows us to settle the
principal amount of the 2021 Convertible Notes in cash and to settle the excess conversion value, if any, in shares, as well as
cash in lieu of fractional shares.
We may not redeem the 2021 Convertible Notes prior to their maturity date. If we undergo a "fundamental change",
as defined in the indenture for the 2021 Convertible Notes, subject to certain conditions, holders of the 2021 Convertible Notes
may require us to repurchase all or part of the 2021 Convertible Notes for cash at a price equal to 100 percent of the principal
amount of the 2021 Convertible Notes to be repurchased, plus any accrued and unpaid interest to, but excluding, the
fundamental change repurchase date. The occurrence of a fundamental change will also result in the 2021 Convertible Notes
becoming convertible.
We allocated the gross proceeds of the 2021 Convertible Notes between the liability and equity components of the
debt. The initial $160.5 million liability component was determined based on the fair value of similar debt instruments
excluding the conversion feature for similar terms and priced on the same day we issued the 2021 Convertible Notes. The
initial $39.5 million equity component represents the debt discount and was calculated as the difference between the fair value
of the debt and the gross proceeds of the 2021 Convertible Notes. Approximately $4.8 million in costs associated with the
issuance of the 2021 Convertible Notes have been capitalized as debt issuance costs and are being amortized as interest expense
over the life of the notes using the effective interest method. As of December 31, 2017, the unamortized debt discount will be
amortized over the remaining contractual term to maturity of the 2021 Convertible Notes using an effective interest rate of
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PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
5.8%. Based upon the December 31, 2017 stock price of $51.54 per share, the “if-converted” value of the 2021 Convertible
Notes did not exceed the principal amount.
2024 Senior Notes. In September 2016, we issued $400.0 million aggregate principal amount of 6.125% senior notes
due September 2024 in a private placement to qualified institutional buyers. In May 2017, in accordance with the registration
rights agreement that we entered into with the initial purchasers when we issued the 2024 Senior Notes, we filed a registration
statement with the SEC relating to an offer to exchange the 2024 Senior Notes for registered notes with substantially identical
terms, and we completed the exchange offer in September 2017. The proceeds from the issuance of the 2024 Senior Notes,
after deducting offering expenses and underwriting discounts, were used to fund a portion of the purchase price of acquisitions
in the Delaware Basin (see the footnotes titled Business Combination and Properties and Equipment), to pay related fees and
expenses, and for general corporate purposes.
The 2024 Senior Notes began accruing interest from the date of issuance and interest is payable semi-annually in
arrears on March 15 and September 15. Approximately $7.8 million in costs associated with the issuance of the 2024 Senior
Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using
the effective interest method. The 2024 Senior Notes are senior unsecured obligations and rank senior in right of payment to
our future indebtedness that is expressly subordinated to the notes; equal in right of payment to all our existing and future
indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent
of the value of the collateral securing such indebtedness, including borrowings under our revolving credit facility; and
structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries.
The 2024 Senior Notes are redeemable after September 15, 2019, at fixed redemption prices beginning at 104.594
percent of the principal amount redeemed. At any time prior to September 15, 2019, we may redeem all or part of the 2024
Senior Notes at a make-whole price set forth in the indenture which generally approximates the present value of the redemption
price at September 15, 2019 and remaining interest payments on the 2024 Senior Notes at the time of redemption.
At any time prior to September 15, 2019, we may redeem up to 35 percent of the outstanding 2024 Senior Notes with
proceeds from certain equity offerings at a redemption price of 106.125 percent of the principal amount of the notes redeemed,
plus accrued and unpaid interest, if at least 65 percent of the aggregate principal amount of the 2024 Senior Notes remains
outstanding after each such redemption and the redemption occurs within 180 days after the closing of the equity offering.
Upon the occurrence of a "change of control," as defined in the indenture for the 2024 Senior Notes, holders will have
the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal
amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with
certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an
offer to purchase the notes at 100 percent of the principal amount, together with any accrued and unpaid interest to the date of
purchase.
The indenture governing the 2024 Senior Notes contains covenants that, among other things, limit our ability and the
ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or
redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict
distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or
merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries.
2022 Senior Notes. In October 2012, we issued $500 million aggregate principal amount of 7.75% senior notes due
October 15, 2022 (the "2022 Senior Notes") in a private placement to qualified institutional buyers. On November 14, 2017,
we issued a notice to redeem the notes on December 13, 2017 for a total redemption price of $519.4 million, including a $19.4
million make-whole premium. The make-whole provision was based upon terms set forth in the related indenture. On
December 14, 2017, upon the redemption of the 2022 Senior Notes, the $19.4 million make-whole premium and the remaining
unamortized debt issuance costs of $5.4 million were recognized as a $24.7 million pre-tax loss on debt extinguishment in the
consolidated statements of operations. The amount paid to bond holders for the make-whole premium has been included as a
financing activity in our statement of cash flows.
Our wholly-owned subsidiary PDC Permian, Inc. has been a guarantor of our obligations under the 2026 Senior Notes
since the issuance of those notes. In January 2017, pursuant to the filing of the supplemental indentures for the 2021
Convertible Notes, 2024 Senior Notes, and the 2022 Senior Notes, PDC Permian, Inc. became a guarantor of our obligations
under each of those notes.
99
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
As of December 31, 2017, we were in compliance with all covenants related to the 2021 Convertible Notes, 2024
Convertible Notes, and the 2026 Senior Notes, and expect to remain in compliance throughout the foreseeable future.
Revolving Credit Facility
Our revolving credit facility matures in May 2020. The revolving credit facility is available for working capital
requirements, capital investments, acquisitions, general corporate purposes and to support letters of credit. The revolving credit
facility provides for a maximum of $1 billion in allowable borrowing capacity, but allows the borrowing base to exceed this
capacity. The amount available under the revolving credit facility is based on, among other things, the loan value assigned to
the proved reserves attributable to our crude oil and natural gas interests, excluding proved reserves attributable to our affiliated
partnerships. The borrowing base is subject to a semi-annual size redetermination on November 1 and May 1 based upon
quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of
certain events. The revolving credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of
certain producing crude oil and natural gas properties and substantially all of our and such subsidiaries' other assets. Our
affiliated partnerships are not guarantors of our obligations under the revolving credit facility.
In May and October 2017, we entered into the Fifth and Sixth Amendments, respectively, to the Third Amended
and Restated Credit Agreement to amend the revolving credit facility to reflect increases in the borrowing base. The Fifth
amendment reflected an increase of the borrowing base from $700 million to $950 million and the Sixth Amendment
amended the revolving credit facility to allow the borrowing base to increase above the borrowing capacity of $1.0 billion.
In addition, the Fifth Amendment made changes to certain of the covenants in the existing agreement as well as other
administrative changes. We elected to increase the borrowing base to $1.1 billion for our November 2017 borrowing base
redetermination and have elected to maintain a $700 million commitment level as of the date of this report.
The weighted-average borrowing rate on our revolving credit facility, exclusive of fees on the unused commitment and
the letter of credit noted below, was 2.7 percent per annum for the year ended December 31, 2016. We did not borrow any
amounts under our revolving credit facility during 2017. We capitalized $6.2 million and $8.8 million of debt issuance costs as
of December 31, 2017 and 2016, respectively, related to our revolving credit facility which is included in other assets on the
consolidated balance sheets.
We had no outstanding balance on our revolving credit facility as of December 31, 2017 or 2016. The outstanding
principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate
base rate (equal to the greater of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus an applicable margin and
the rate for dollar deposits in the London interbank market (“LIBOR”) for one month plus a premium), or at our election, a rate
equal to LIBOR for certain time periods. Additionally, commitment fees, interest margin, and other bank fees, charged as a
component of interest, vary with our utilization of the facility. As of December 31, 2017, the applicable margin is 1.25 percent
and the unused commitment fee is 0.50 percent. No principal payments are generally required until the credit agreement
expires in May 2020, or in the event that the borrowing base falls below the outstanding balance.
The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being
certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements
to: (a) maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 4.0:1.0. As of
December 31, 2017, we were in compliance with all the revolving credit facility covenants and expect to remain in compliance
throughout the next 12-month period. As defined by the revolving credit facility, our leverage ratio was 1.9 and our current
ratio was 3.2 as of December 31, 2017.
In May 2017, we replaced our $11.7 million irrevocable standby letter of credit that we held in favor of a third-
party transportation service provider to secure a firm transportation obligation with a $9.3 million deposit, which is
classified as restricted cash and is included in other assets on the consolidated balance sheets. As of December 31, 2017, the
available funds under our revolving credit facility were $700 million based on our elected commitment level.
NOTE 10 - CAPITAL LEASES
We periodically enter into non-cancelable lease agreements for vehicles utilized by our operations and field personnel.
These leases are being accounted for as capital leases, as the present value of minimum monthly lease payments, including the
residual value guarantee, exceeds 90 percent of the fair value of the leased vehicles at inception of the lease.
100
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The following table presents leased vehicles under capital leases:
Vehicles
Accumulated depreciation
As of December 31,
2017
2016
(in thousands)
6,249
(1,882)
4,367
$
$
2,975
(776)
2,199
$
$
Future minimum lease payments by year and in the aggregate, under non-cancelable capital leases with terms of one
year or more, consist of the following:
For the Twelve Months Ending December 31,
2018
2019
2020
Less executory cost
Less amount representing interest
Present value of minimum lease payments
Short-term capital lease obligations
Long-term capital lease obligations
Amount
(in thousands)
2,075
1,623
1,507
5,205
(235)
(537)
4,433
1,672
2,761
4,433
$
$
$
$
Short-term capital lease obligations are included in other accrued expenses on the consolidated balance sheets. Long-
term capital lease obligations are included in other liabilities on the consolidated balance sheets.
NOTE 11 - INCOME TAXES
The table below presents the components of our provision for income taxes from continuing operations for the years
presented:
Current:
Federal
State
$
Total current income tax (expense) benefit
Deferred:
Federal
State
Total deferred income tax benefit
Income tax benefit from continuing operations
$
2017
Year Ended December 31,
2016
(in thousands)
2015
$
8,443
(200)
8,243
193,809
9,876
203,685
211,928
$
9,646
300
9,946
118,427
18,822
137,249
147,195
$
$
(2,944)
(163)
(3,107)
37,352
4,063
41,415
38,308
101
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The following table presents a reconciliation of the statutory rate to the effective tax rate related to our benefit for
income taxes from continuing operations:
Statutory tax rate
State income tax, net
Effect of state income tax rate changes
Percentage depletion
Non-deductible compensation
Federal tax reform rate reduction
Non-deductible goodwill impairment
Other
Effective tax rate
2017
Year Ended December, 31,
2016
2015
35.0%
1.8
—
—
(0.3)
33.7
(7.7)
(0.1)
62.4%
35.0%
2.6
0.6
—
(0.5)
—
—
(0.3)
37.4%
35.0%
2.7
(0.3)
0.3
(1.2)
—
—
(0.6)
35.9%
Tax effects of temporary differences that give rise to significant portions of deferred tax assets and deferred tax
liabilities at December 31, 2017 and 2016 are presented below. The 2017 amounts include the reduction of our deferred tax
assets and liabilities to a projected combined federal and state deferred tax rate of 23.9 percent as a result of the 2017 Tax Act.
Also in 2017, deferred tax liability for properties and equipment was reduced by $94.1 million as a result of recording an
impairment charge related to a portion of the Delaware Basin assets. The 2016 amounts include the $403.7 million effect of
including the deferred tax liability for the difference in the book and tax basis of the oil and gas properties acquired in a 2016
business combination and $23.8 million of acquired deferred tax assets:
Deferred tax assets:
Deferred compensation
Asset retirement obligations
Federal NOL carryforward
State NOL and tax credit carryforwards, net
Federal tax - credit carryforwards
Allowance for note receivable
Net change in fair value of unsettled derivatives
Other
Total gross deferred tax assets
Deferred tax liabilities:
Properties and equipment
Convertible debt
Total gross deferred tax liabilities
Net deferred tax liability
As of December 31,
2017
2016
(in thousands)
$
$
$
6,059
21,760
19,386
7,815
4,366
—
20,929
2,453
82,768
267,498
7,262
274,760
191,992
$
9,338
34,359
29,988
5,189
5,184
17,292
26,262
4,716
132,328
518,964
14,231
533,195
400,867
The 2017 Tax Act, enacted into law in December 2017, reduces the corporate income tax rate to 21 percent, effective
January 1, 2018. Consequently, we have decreased our deferred tax assets and deferred tax liabilities by $43.8 million and
$158.2 million, respectively, with a corresponding income tax benefit of $114.4 million. Our accounting for the deferred
income tax effects of the 2017 Tax Act is complete.
Prior to the decrease of deferred tax assets for the federal rate change noted above, the deferred tax assets would have
decreased primarily due to the utilization of the deferred tax benefit of an allowance for note receivable, partially offset by a
decrease in the value of unsettled derivatives and an increase in federal and state net operating loss (“NOL”) and tax credit
carryforwards.
In addition to the decrease of deferred tax liabilities for the tax rate change and our impairment in the Delaware Basin,
deferred tax liabilities also decreased for the amortization of the discount and debt issuance costs for the 2021 Convertible
102
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Notes, which were issued in 2016. These decreases were partially offset by accelerated deductions on properties and
equipment and deductions for lease expirations.
During the year ending December 31, 2017, we generated a federal NOL of $28 million, of which $10.1 million will
be utilized as a carryback leaving a federal NOL carryforward of $17.9 million that will begin to expire in 2037. We have a
marginal gas well credit of $1.2 million that can be carried forward five years and we have alternative minimum tax credits of
$3.2 million that may be carried forward, and pursuant to the new tax law will be refunded over the next four years. Also, we
acquired a federal NOL of $60.1 million as a component of our 2016 acquisition in the Delaware Basin that will begin to expire
in 2034 and is subject to an annual limitation of $15.1 million as a result of the acquisition, which constitutes a change of
ownership as defined under IRS Code Section 382.
As of December 31, 2017, we have state NOL carryforwards of $158.0 million that begin to expire in 2030 and state
credit carryforwards of $2.4 million that begin to expire in 2022.
Unrecognized tax benefits and related accrued interest and penalties were immaterial for the three-year period ended
December 31, 2017. The statutes of limitations for most of our state tax jurisdictions are open from 2013 forward.
The IRS partially accepted our recently-filed 2016 tax return. The 2016 tax return is currently going through the IRS
CAP post-filing review process, with no significant tax adjustments currently proposed. We are currently participating in the
CAP Program for the review of our 2017 and 2018 tax years. Participation in the CAP Program has enabled us to have minimal
uncertain tax benefits associated with our federal tax return filings.
As of December 31, 2017, we were current with our income tax filings in all applicable state jurisdictions.
NOTE 12 - ASSET RETIREMENT OBLIGATIONS
The following table presents the changes in carrying amounts of the asset retirement obligations associated with our
crude oil and natural gas properties and midstream assets:
Beginning balance
Obligations incurred with development activities
Accretion expense
Revisions in estimated cash flows
Obligations discharged with asset retirements
Balance at December 31
Less liabilities held-for-sale
Less current portion
Long-term portion
2017
2016
(in thousands)
$
$
92,387
3,638
6,306
(2,860)
(12,165)
87,306
(499)
(15,801)
71,006
$
$
89,492
4,894
7,080
—
(9,079)
92,387
—
(9,775)
82,612
Our estimated asset retirement obligations liability is based on historical experience in plugging and abandoning wells,
estimated economic lives, estimated plugging and abandonment cost and federal and state regulatory requirements. The
liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. In 2017,
the credit-adjusted risk-free rates used to discount our plugging and abandonment liabilities ranged from 6.5 percent to 7.5
percent. In periods subsequent to initial measurement of the liability, we must recognize period-to-period changes in the
liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or
changes in inflation factors, and changes to our credit-adjusted risk-free rate as market conditions warrant.
The revisions in estimated cash flows during 2017 were primarily due to changes in estimates of costs for materials
and services related to the plugging and abandonment of vertical and horizontal wells and the shortening of the estimated
expected lives of vertical wells in the Wattenberg Field.
NOTE 13 - EMPLOYEE BENEFIT PLANS
103
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
We sponsor a qualified retirement plan covering substantially all of our employees. The plan consists of both a
traditional and a Roth 401(k) component, as well as a profit sharing component. The 401(k) components enable eligible
employees to contribute a portion of their compensation through payroll deductions in accordance with specific guidelines. We
provide a discretionary matching contribution based on a percentage of the employees' contributions up to certain limits.
Additionally, our contribution to the profit sharing component is discretionary. Our total combined expense for the plan was
$6.2 million, $4.8 million, and $4.9 million for 2017, 2016, and 2015, respectively.
NOTE 14 - COMMITMENTS AND CONTINGENCIES
Firm Transportation and Processing Agreements. We enter into contracts that provide firm transportation and
processing on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume
requirements includes volumes produced by us, purchased from third parties, and produced by our affiliated partnerships and
other third-party working, royalty, and overriding royalty interest owners, whose volumes we market on their behalf. Our
consolidated statements of operations reflect our share of these firm transportation and processing costs. These contracts
require us to pay these transportation and processing charges whether or not the required volumes are delivered.
The following table presents gross volume information related to our long-term firm transportation, sales, and
processing agreements for pipeline capacity:
Area
2018
2019
2020
2021
2022 and
Through
Expiration
Total
Expiration
Date
Year Ending December 31,
Natural gas (MMcf)
Wattenberg Field
Delaware Basin
Gas Marketing
Utica Shale (1)
Total
Crude oil (MBbls)
Wattenberg Field
3,541
14,600
7,117
2,738
27,996
23,934
14,600
7,117
2,738
48,389
31,110
14,640
7,136
2,745
55,631
31,025
—
7,056
2,738
40,819
121,922
—
4,495
4,326
130,743
April 30, 2026
211,532
43,840 December 31, 2020
32,921
15,285
303,578
August 31, 2022
July 31, 2023
3,638
4,239
1,808
—
—
9,685
June 30, 2020
Dollar commitment (in thousands)
$
23,176
$
43,855
$
42,496
$
33,226
$ 118,927
$ 261,680
(1) In February 2018, we entered into a PSA to sell the Utica Shale properties. This commitment would be assumed by the purchaser of the
Utica Shale properties.
In anticipation of our future drilling activities in the Wattenberg Field, we entered into two facilities expansion
agreements in 2016 and 2017 with our primary midstream provider to expand and improve its natural gas gathering pipelines
and processing facilities. The midstream provider is expected to construct two new 200 MMcfd cryogenic plants. We will be
bound to the volume requirements in these agreements on the first day of the calendar month following after the actual in-
service date of the plants, which in the above table is scheduled to be in the third quarter of 2018 for the first plant and the
second quarter of 2019 for the second plant. Both agreements require baseline volume commitments, consisting of our gross
wellhead volume delivered in November 2016, to this midstream provider, and incremental wellhead volume commitments of
51.5 MMcfd and 33.5 MMcfd for the first and second agreements, respectively, for seven years. We may be required to pay
shortfall fees for any volumes under the 51.5 MMcfd and 33.5 MMcfd incremental commitments. Any shortfall of these
volume commitments may be offset by additional third party producers’ volumes sold to the midstream provider that are greater
than a certain total baseline volume. We are also required for the first three years of the contracts to guarantee a certain target
profit margin to the midstream provider on these incremental volumes. We currently expect that our future development plans
will meet both baseline and incremental volumes, and we believe that the contractual target profit margin will be achieved
without additional payment from us.
In April 2017, we entered into a transportation service agreement for delivery of 40,000 dekatherms per day of our
Delaware Basin natural gas production to the Waha market hub in West Texas.
104
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
For the years 2017, 2016, and 2015, commitments for long-term transportation volumes for Wattenberg Field crude
oil, Delaware Basin natural gas, and Utica Shale natural gas were $10.0 million, $10.0 million, and $4.7 million, respectively,
and were recorded in transportation, gathering and processing expense in our consolidated statements of operations.
Litigation and Legal Items. We are involved in various legal proceedings. We review the status of these
proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions
that management believes are in our best interests. We have provided the necessary estimated accruals in the accompanying
balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded.
Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not
have a material adverse effect on our financial position, results of operations, or liquidity.
Action Regarding Partnerships. In December 2017, we received an action entitled Dufresne, et al. v. PDC Energy,
et al., filed in the United States District Court for the District of Colorado. The complaint states that it is a derivative action
brought by a number of limited partner investors seeking to assert claims on behalf of our two affiliated partnerships, Rockies
Region 2006 LP and Rockies Region 2007 LP, against PDC and alleging claims for breach of fiduciary duty and breach of
contract. The plaintiffs also included claims against two of our senior officers for alleged breach of fiduciary duty. The lawsuit
accuses PDC, as the managing general partner of the two partnerships, of, among other things, failing to maximize the
productivity of the partnerships’ crude oil and natural gas wells. We filed a motion to dismiss the lawsuit on February 1, 2018,
on the grounds that the complaint is deficient, including because the plaintiffs failed to allege that PDC refused a demand to
take action on their claims. That motion is still pending. We are unable to estimate any potential damages as a result of this
recent lawsuit.
Action Regarding Firm Transportation Contracts. In June 2016, a group of 42 independent West Virginia natural
gas producers filed a lawsuit in Marshall County, West Virginia, naming Dominion Transmission, Inc. (“Dominion”), certain
entities affiliated with Dominion, and our subsidiary Riley Natural Gas ("RNG") as defendants, alleging various contractual,
fiduciary and related claims against the defendants, all of which are associated with firm transportation contracts entered into
by plaintiffs and relating to pipelines owned and operated by Dominion and its affiliates. The case has been transferred to the
Business Court Division of the Circuit Court of Marshall County, West Virginia. RNG is unable to estimate any potential
damages associated with the claims, but believes the complaint is without merit and intends to vigorously pursue its defenses.
Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We
have various policies and procedures designed to minimize and mitigate the risks from environmental contamination. We
conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded
when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as
discussed herein, we are not aware of any material environmental claims existing as of December 31, 2017 which have not
been provided for or would otherwise have a material impact on our financial statements; however, there can be no
assurance that current regulatory requirements will not change or that unknown potential past non-compliance with
environmental laws or other environmental liabilities will not be discovered on our properties. Accrued environmental
liabilities are recorded in other accrued expenses on the condensed consolidated balance sheets. The liability ultimately
incurred with respect to a matter may exceed the related accrual.
Clean Air Act Agreement and Related Consent Decree. In August 2015, we received a Clean Air Act Section 114
Information Request (the “Information Request”) from the U.S. Environmental Protection Agency (“EPA”). The Information
Request sought, among other things, information related to the design, operation, and maintenance of our Wattenberg Field
production facilities in the Denver-Julesburg Basin of Colorado (“DJ Basin”). The Information Request focused on historical
operation and design information for 46 of our production facilities and requested sampling and analyses at the identified 46
facilities. We responded to the Information Request with the requested data in January 2016.
In addition, in December 2015, we received a Compliance Advisory pursuant to C.R.S. 25-7-115(2) from the Colorado
Department of Public Health and Environment’s Air Quality Control Commission’s Air Pollution Control Division alleging that
we failed to design, operate, and maintain certain condensate collection, storage, processing, and handling operations to
minimize leakage of volatile organic compounds at 65 facilities consistent with applicable standards under Colorado law.
In June 2017, the U.S. Department of Justice, on behalf of the EPA and the state of Colorado, filed a complaint against
us in the U.S. District Court for the District of Colorado, claiming that we failed to operate and maintain certain condensate
collection facilities at 65 facilities so as to minimize leakage of volatile organic compounds in compliance with applicable law.
In October 2017, we entered into a consent decree to resolve the lawsuit. Pursuant to the consent decree, we agreed to
implement a variety of operational enhancements and mitigation and similar projects, including vapor control system
105
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
modifications and verification, increased inspection and monitoring, and installation of tank pressure monitors. The three
primary elements of the consent decree are: (i) fine/supplemental environmental projects ($1.5 million cash fine, plus $1
million in supplemental environmental projects) which have been accrued in other accrued expenses on our consolidated
balance sheet as of December 31, 2017; (ii) injunctive relief with an estimated cost of approximately $18 million, primarily
representing capital enhancements to our operations; and (iii) mitigation with an estimated cost of $1.7 million. We continue to
incur costs associated with these activities. If we fail to comply fully with the requirements of the consent decree with respect
to those matters, we could be subject to additional liability. In addition, we could be the subject of other enforcement actions
by regulatory authorities in the future relating to our past, present or future operations. We do not believe that the expenditures
resulting from the settlement will have a material adverse effect on our consolidated financial statements.
Lease Agreements. We entered into operating leases, principally for the leasing of natural gas compressors, office space,
and general office equipment.
The following table presents the minimum future lease payments under the non-cancelable operating leases as of
December 31, 2017:
Year Ending December 31,
2018
2019
2020
2021
2022
Thereafter
Total
(in thousands)
Minimum Lease Payments
$
3,865
$
3,865
$
3,932
$
3,998
$
4,078
$
3,515
$
23,253
Operating lease expense for 2017, 2016, and 2015 was $17.2 million, $10.2 million, and $9.8 million, respectively.
106
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
NOTE 15 - COMMON STOCK
Issuance of Equity Securities
In December 2016, we issued 9.4 million shares of our common stock as partial consideration for 100 percent of the
common stock of Arris Petroleum and for the acquisition of certain Delaware Basin properties. Pursuant to the terms of
previously disclosed lock-up agreements, the resale of these shares was restricted. The lock-up period ended in June 2017. We
have registered the 9.4 million shares of our common stock for resale under the Securities Act of 1933.
Sales of Equity Securities
The following table provides a summary of our public offerings of common stock in 2016 and 2015:
Date
Shares Issued
Price per Share
Net Proceeds
(in millions)
September 2016
9,085,000
$
March 2016
March 2015
5,922,500
4,002,000
61.51
$
50.11
50.73
558.5
296.6
202.9
Stock-Based Compensation Plans
2010 Long-Term Equity Compensation Plan. In June 2010, our stockholders approved a long-term equity
compensation plan for our employees and non-employee directors (the "2010 Plan"). The plan was amended in June 2013. In
accordance with the 2010 Plan, up to 3,000,000 new shares of our common stock are authorized for issuance. Shares issued
may be either authorized but unissued shares, treasury shares, or any combination. Additionally, the 2010 Plan permits the
reuse or reissuance of shares of common stock which were canceled, expired, forfeited, paid out in the form of cash, or
withheld for the payment of taxes. Awards may be issued to our employees in the form of stock appreciation rights ("SARs"),
restricted stock, restricted stock units ("RSUs"), performance shares, and performance units ("PSUs"), and to our non-employee
directors in the form of non-qualified stock options, SARs, restricted stock, and RSUs. Awards may vest over periods set at the
discretion of the Compensation Committee of our Board of Directors (the "Compensation Committee") with certain minimum
vesting periods. With regard to SARs, awards have a maximum exercisable period of ten years. In no event may an award be
granted under the 2010 Plan on or after June 5, 2023. As of December 31, 2017, 689,206 shares remain available for issuance
pursuant to the 2010 Plan.
The following table provides a summary of the impact of our outstanding stock-based compensation plans on the
results of operations for the periods presented:
2017
Year Ended December 31,
2016
(in thousands)
2015
Stock-based compensation expense
Income tax benefit
Net stock-based compensation expense
$
$
19,353
(7,372)
11,981
$
$
19,502
(7,296)
12,206
$
$
20,068
(7,636)
12,432
SARs
The SARs vest ratably over a three-year period and may be exercised at any point after vesting through ten years from
the date of issuance. Pursuant to the terms of the awards, upon exercise, the holders of the SARs will receive, in shares of
common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the
date of issuance.
107
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The Compensation Committee has awarded SARs to our executive officers in 2017, 2016, and 2015. The fair value of
each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions:
Year Ended December 31,
2016
2015
2017
Expected term of award (in years)
Risk-free interest rate
Expected volatility
Weighted-average grant date fair value per share
6.0 years
2.0%
53.3%
38.58
$
6.0 years
1.8%
54.5%
26.96
$
5.2 years
1.4%
58.0%
22.23
$
The expected term of the award was estimated using historical stock option exercise behavior data. The risk-free
interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant.
Expected volatilities were based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable
future.
The following table presents the changes in our SARs for all periods presented (in thousands, except per share data):
2017
2016
2015
Year Ended December 31,
Number
of
SARs
Weighted
-Average
Exercise
Price
Average
Remaining
Contractual
Term
(in years)
Aggregate
Intrinsic
Value
Number
of
SARs
Weighted
-Average
Exercise
Price
Aggregate
Intrinsic
Value
Number
of
SARs
Weighted
-Average
Exercise
Price
Aggregate
Intrinsic
Value
Outstanding at January 1,
244,078
$
41.36
6.9
$
7,620
326,453
$
38.99
$
4,697
279,011
$
38.77
$
1,472
Awarded
Exercised
54,142
—
Outstanding at December 31
298,220
Exercisable at December 31
223,865
74.57
—
47.39
43.28
—
—
6.5
5.9
—
58,709
— (141,084)
2,490
2,267
244,078
174,919
51.63
40.16
41.36
38.72
— 68,274
2,770
(20,832)
7,620
326,453
5,924
222,489
39.63
38.05
38.99
37.70
—
473
4,697
3,489
We expect all SARs outstanding as of December 31, 2017 to vest. Total compensation cost related to SARs granted
and not yet recognized in our consolidated statements of operations as of December 31, 2017 was $1.9 million. The cost is
expected to be recognized over a weighted-average period of 1.8 years.
Restricted Stock Unit Awards
Time-Based Awards. The fair value of the time-based RSUs is amortized ratably over the requisite service period,
primarily three years. The time-based RSUs generally vest ratably on each anniversary following the grant date that a
participant is continuously employed.
The following table presents the changes in non-vested time-based RSUs during 2017:
Non-vested at December 31, 2016
Granted
Vested
Forfeited
Non-vested at December 31, 2017
Shares
Weighted-Average
Grant Date
Fair Value per Share
$
479,642
273,941
(266,809)
(14,642)
472,132
56.09
65.14
57.67
62.92
60.23
108
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The following table presents the weighted-average grant date fair value per share and related information as of/for the
periods presented:
2017
As of/Year Ended December 31,
2016
(in thousands, except per share data)
2015
Total intrinsic value of time-based awards vested
Total intrinsic value of time-based awards non-vested
Market price per common share as of December 31,
Weighted-average grant date fair value per share
$
$
16,303
24,334
51.54
65.14
$
18,973
34,812
72.58
58.52
17,077
28,029
53.38
48.88
Total compensation cost related to non-vested time-based awards and not yet recognized in our consolidated
statements of operations as of December 31, 2017 was $18.5 million. This cost is expected to be recognized over a weighted-
average period of 1.8 years.
Market-Based Awards. The fair value of the market-based PSUs is amortized ratably over the requisite service period,
primarily three years. The market-based PSUs vest if the participant is continuously employed throughout the performance
period and the market-based performance measure is achieved, with a maximum vesting period of three years. All
compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the
market condition is not achieved.
In January 2017, the Compensation Committee awarded a total of 28,069 market-based PSUs to our executive
officers. In addition to continuous employment, the vesting of these PSUs is contingent on our total stockholder return
("TSR"), which is essentially our stock price change including any dividends, as compared to the TSR of a group of peer
companies. The shares are measured over a three-year period ending on December 31, 2019 and can result in a payout between
0 percent and 200 percent of the target PSUs awarded. As of December 31, 2017, we had approximately 52,000 non-vested
market based PSUs that could result in a payout between 0 and approximately 105,000 shares of our common stock. The
weighted-average grant date fair value per PSU granted was computed using the Monte Carlo pricing model using the
following assumptions:
2017
Year Ended December 31,
2016
2015
Expected term of award (in years)
Risk-free interest rate
Expected volatility
Weighted-average grant date fair value per share
$
3 years
1.4%
51.4%
94.02
$
3 years
1.2%
52.3%
72.54
$
3 years
0.9%
53.0%
66.16
The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on
the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected
volatility was based on our historical volatility.
The following table presents the change in non-vested market-based awards during 2017:
Non-vested at December 31, 2016
Granted
Vested
Non-vested at December 31, 2017
Shares
Weighted-Average
Grant Date
Fair Value per Share
$
48,420
28,069
(24,140)
52,349
64.97
94.02
57.35
84.06
109
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The following table presents the weighted-average grant date fair value per share and related information as of/for the
periods presented:
As of/Year Ended December 31,
2017
2016
2015
(in thousands, except per share data)
Total intrinsic value of market-based awards vested
$
2,687
$
6,562
$
Total intrinsic value of market-based awards non-vested
Market price per common share as of December 31,
Weighted-average grant date fair value per share
2,698
51.54
94.02
3,514
72.58
72.54
4,293
3,819
53.38
66.16
Total compensation cost related to non-vested market-based awards and not yet recognized in our consolidated
statements of operations as of December 31, 2017 was $2.4 million. This cost is expected to be recognized over a weighted-
average period of 1.8 years.
Treasury Share Purchases
In accordance with our stock-based compensation plans, employees may surrender shares of our common stock to pay
tax withholding obligations upon the vesting and exercise of share-based awards. Shares acquired that had been issued
pursuant to the 2010 Plan are withheld for reissuance for new grants. For shares reissued for new grants under the 2010 Plan,
shares are recorded at cost and upon reissuance we reduce the carrying value of shares acquired and held pursuant to the 2010
Plan by the weighted-average cost per share with an offsetting charge to APIC. During the year ended December 31, 2017, we
acquired 107,357 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 83,228 shares
were reissued and 34,526 are available for reissuance pursuant to our 2010 Plan. During the year ended December 31, 2016,
we acquired 116,085 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 114,697
were reissued and 10,397 are available for reissuance pursuant to our 2010 Plan. As of December 31, 2017 and 2016, we had
21,401 and 18,366, respectively, shares of treasury stock related to a rabbi trust.
Preferred stock
We are authorized to issue 50,000,000 shares of preferred stock, par value $0.01, in one or more series, with such
rights, preferences, privileges, and restrictions as shall be fixed by our Board of Directors at the time of issuance. As of
December 31, 2017, no preferred shares had been issued.
NOTE 16 - EARNINGS PER SHARE
Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares
outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect,
using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options, convertible notes, and shares
held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is
dilutive.
The following table presents a reconciliation of the weighted-average diluted shares outstanding:
2017
Year Ended December 31,
2016
(in thousands)
2015
Weighted-average common shares outstanding - basic
Weighted-average common shares and equivalents outstanding - diluted
65,837
65,837
49,052
49,052
39,153
39,153
For 2017, 2016, and 2015, we reported a net loss. As a result, our basic and diluted weighted-average common shares
outstanding were the same because the effect of the common share equivalents was anti-dilutive.
110
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The following table presents the weighted-average common share equivalents excluded from the calculation of diluted
earnings per share due to their anti-dilutive effect:
2017
Year Ended December 31,
2016
(in thousands)
2015
Weighted-average common share equivalents excluded from diluted earnings per share due to
their anti-dilutive effect:
Restricted stock
Convertible notes
Other equity-based awards
Total anti-dilutive common share equivalents
590
—
75
665
689
292
109
1,090
831
562
101
1,494
In September 2016, we issued the 2021 Convertible Notes, which gave the holders the right to convert the aggregate
principal amount into 2.3 million shares of our common stock at a conversion price of $85.39 per share. The 2021 Convertible
Notes would be included in the diluted earnings per share calculation using the treasury stock method if the average market
share price had exceeded the $85.39 conversion price during the periods presented.
In November 2010, we issued the 2016 Convertible Notes, which give the holders the right to convert the aggregate
principal amount into 2.7 million shares of our common stock at a conversion price of $42.40 per share. The 2016 Convertible
Notes matured and were redeemed in May 2016. Prior to maturity, the 2016 Convertible Notes were included in the diluted
earnings per share calculation using the treasury stock method when the average market share price exceeded the $42.40
conversion price during the period presented. Shares issuable upon conversion of the Convertible Notes were excluded from
the diluted earnings per share calculation for the years ended December 31, 2016 and 2015 as the effect would have been anti-
dilutive to our earnings per share.
NOTE 17 - SUBSIDIARY GUARANTOR
PDC Permian, Inc., our wholly-owned subsidiary, guarantees our obligations under our publicly-registered senior
notes. The following presents the condensed consolidating financial information separately for:
(i)
(ii)
PDC Energy, Inc. ("Parent"), the issuer of the guaranteed obligations, including non-material subsidiaries;
PDC Permian, Inc., the guarantor subsidiary ("Guarantor"), as specified in the indentures related to our senior notes;
(iii) Eliminations representing adjustments to (a) eliminate intercompany transactions between or among Parent, Guarantor,
and our other subsidiaries and (b) eliminate the investments in our subsidiaries; and
(iv) Parent and subsidiaries on a consolidated basis ("Consolidated").
The Guarantor was 100 percent owned by the Parent beginning in December 2016. The senior notes are fully and
unconditionally guaranteed on a joint and several basis by the Guarantor. The guarantee is subject to release in limited
circumstances only upon the occurrence of certain customary conditions. Each entity in the consolidating financial information
follows the same accounting policies as described in the notes to the consolidated financial statements.
The following consolidating financial statements have been prepared on the same basis of accounting as our
consolidated financial statements. Investments in subsidiaries are accounted for under the equity method. Accordingly, the
entries necessary to consolidate the Parent and Guarantor are reflected in the eliminations column.
111
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Consolidating Balance Sheets
December 31, 2017
Parent
Guarantor
Eliminations
Consolidated
(in thousands)
$
$
180,675
160,490
14,338
8,284
363,787
1,891,314
40,084
250,279
1,617,537
42,547
4,205,548
85,000
35,902
79,302
83,898
11,812
42,543
338,457
—
1,151,932
62,857
65,301
22,343
57,009
1,697,899
$
— $
37,108
—
329
37,437
2,042,153
—
—
—
2,569
2,082,159
— $
—
—
—
—
—
—
(250,279)
(1,617,537)
—
$
(1,867,816) $
$
65,067
1,752
—
11,913
3
444
79,179
250,279
—
129,135
5,705
—
324
464,622
— $
—
—
—
—
—
—
(250,279)
—
—
—
—
—
(250,279)
180,675
197,598
14,338
8,613
401,224
3,933,467
40,084
—
—
45,116
4,419,891
150,067
37,654
79,302
95,811
11,815
42,987
417,636
—
1,151,932
191,992
71,006
22,343
57,333
1,912,242
659
2,503,294
6,704
(3,008)
2,507,649
4,205,548
$
—
1,766,775
(149,238)
—
1,617,537
2,082,159
$
—
(1,766,775)
149,238
—
(1,617,537)
(1,867,816) $
659
2,503,294
6,704
(3,008)
2,507,649
4,419,891
Assets
Current assets:
Cash and cash equivalents
Accounts receivable, net
Fair value of derivatives
Prepaid expenses and other current assets
Total current assets
Properties and equipment, net
Assets held-for-sale, net
Intercompany receivable
Investment in subsidiaries
Other assets
Total Assets
Liabilities and Stockholders' Equity
Liabilities
Current liabilities:
Accounts payable
Production tax liability
Fair value of derivatives
Funds held for distribution
Accrued interest payable
Other accrued expenses
Total current liabilities
Intercompany payable
Long-term debt
Deferred income taxes
Asset retirement obligations
Fair value of derivatives
Other liabilities
Total liabilities
Stockholders' equity
Common shares
Additional paid-in capital
Retained earnings
Treasury shares
Total stockholders' equity
Total Liabilities and Stockholders' Equity
$
$
$
$
112
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Assets
Current assets:
Cash and cash equivalents
Accounts receivable, net
Fair value of derivatives
Prepaid expenses and other current assets
Total current assets
Properties and equipment, net
Assets held-for-sale, net
Intercompany receivable
Investment in subsidiaries
Fair value of derivatives
Goodwill
Other assets
Total Assets
Liabilities and Stockholders' Equity
Liabilities
Current liabilities:
Accounts payable
Production tax liability
Fair value of derivatives
Funds held for distribution
Accrued interest payable
Other accrued expenses
Total current liabilities
Intercompany payable
Long-term debt
Deferred income taxes
Asset retirement obligations
Fair value of derivatives
Other liabilities
Total liabilities
Stockholders' equity
Common shares
Additional paid-in capital
Retained earnings
Treasury shares
Total stockholders' equity
Total Liabilities and Stockholders' Equity
Consolidating Balance Sheets
December 31, 2016
Parent
Guarantor
Eliminations
Consolidated
(in thousands)
$
$
$
240,487
134,589
8,791
3,442
387,309
1,884,147
5,272
9,415
1,765,092
2,386
—
13,153
4,066,774
38,748
24,401
53,595
65,022
15,930
37,425
235,121
—
1,043,954
20,971
78,897
27,595
37,482
1,444,020
3,613
8,803
—
100
12,516
2,118,847
—
—
—
—
62,041
171
2,193,575
$
— $
—
—
—
—
—
—
(9,415)
(1,765,092)
—
—
—
$
(1,774,507) $
$
27,574
366
—
6,317
—
1,200
35,457
9,415
—
379,896
3,715
—
—
428,483
— $
—
—
—
—
—
—
(9,415)
—
—
—
—
—
(9,415)
244,100
143,392
8,791
3,542
399,825
4,002,994
5,272
—
—
2,386
62,041
13,324
4,485,842
66,322
24,767
53,595
71,339
15,930
38,625
270,578
—
1,043,954
400,867
82,612
27,595
37,482
1,863,088
657
2,489,557
134,208
(1,668)
2,622,754
4,066,774
$
—
1,766,775
(1,683)
—
1,765,092
2,193,575
$
—
(1,766,775)
1,683
—
(1,765,092)
(1,774,507) $
657
2,489,557
134,208
(1,668)
2,622,754
4,485,842
$
$
$
$
113
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Revenues
Crude oil, natural gas, and NGLs sales
Commodity price risk management gain (loss), net
Other income
Total revenues
Costs, expenses and other
Lease operating expenses
Production taxes
Transportation, gathering, and processing expenses
Exploration, geologic, and geophysical expense
Impairment of properties and equipment
Impairment of goodwill
General and administrative expense
Depreciation, depletion and amortization
Provision for uncollectible notes receivable
Accretion of asset retirement obligations
Gain on sale of properties and equipment
Other expenses
Total costs, expenses and other
Income (loss) from operations
Loss on extinguishment of debt
Interest expense
Interest income
Income (loss) before income taxes
Income tax (expense) benefit
Equity in loss of subsidiary
Net loss
Consolidating Statements of Operations
Year Ended December 31, 2017
Eliminations
Guarantor
Parent
Consolidated
(in thousands)
$
$
788,400
(3,936)
11,901
796,365
68,031
53,236
23,301
1,092
4,951
—
107,518
403,984
(40,203)
5,965
(766)
13,157
640,266
156,099
(24,747)
(79,919)
2,261
53,694
(33,643)
(147,555)
(127,504)
$
$
$
124,684
—
567
125,251
21,610
7,481
9,919
46,242
280,936
75,121
12,852
65,100
—
341
—
—
519,602
(394,351)
—
1,225
—
(393,126)
245,571
—
(147,555) $
— $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
147,555
147,555
$
913,084
(3,936)
12,468
921,616
89,641
60,717
33,220
47,334
285,887
75,121
120,370
469,084
(40,203)
6,306
(766)
13,157
1,159,868
(238,252)
(24,747)
(78,694)
2,261
(339,432)
211,928
—
(127,504)
Net losses of the Guarantor for the year ended 2017 are primarily the result of the exploratory dry hole expense,
impairment of certain unproved Delaware Basin leasehold positions, and the impairment of goodwill.
114
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Revenues
Crude oil, natural gas, and NGLs sales
Commodity price risk management gain (loss), net
Other income
Total revenues
Costs, expenses and other
Lease operating expenses
Production taxes
Transportation, gathering, and processing expenses
Exploration, geologic, and geophysical expense
Impairment of properties and equipment
General and administrative expense
Depreciation, depletion and amortization
Provision for uncollectible notes receivable
Accretion of asset retirement obligations
Gain on sale of properties and equipment
Other expenses
Total costs, expenses and other
Loss from operations
Interest expense
Interest income
Loss before income taxes
Income tax benefit
Equity in loss of subsidiary
Net loss
Consolidating Statements of Operations
Year Ended December 31, 2016
Eliminations
Guarantor
Parent
Consolidated
(in thousands)
$
$
491,750
(125,681)
11,241
377,310
58,401
31,132
18,263
1,197
9,973
112,166
415,321
44,038
7,070
(43)
10,193
707,711
(330,401)
(62,002)
963
(391,440)
147,195
(1,683)
(245,928)
$
$
$
5,603
—
2
5,605
1,549
278
152
3,472
—
304
1,553
—
10
—
—
7,318
(1,713)
30
—
(1,683)
—
—
(1,683) $
— $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,683
1,683
$
497,353
(125,681)
11,243
382,915
59,950
31,410
18,415
4,669
9,973
112,470
416,874
44,038
7,080
(43)
10,193
715,029
(332,114)
(61,972)
963
(393,123)
147,195
—
(245,928)
115
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2017
Eliminations
Guarantor
Parent
Consolidated
(in thousands)
$
537,704
$
50,859
$
— $
588,563
(439,897)
(3,539)
(21,000)
10,084
40,203
(9,250)
49,890
(49,890)
(239,191)
(662,590)
592,366
(519,375)
(6,672)
(50)
(1,195)
—
65,074
(59,812)
240,487
180,675
(297,311)
(1,555)
5,372
(93)
—
—
—
—
—
(293,587)
—
—
—
—
(76)
239,191
239,115
(3,613)
3,613
$
— $
—
—
—
—
—
—
—
—
239,191
239,191
—
—
—
—
—
(239,191)
(239,191)
—
—
— $
(737,208)
(5,094)
(15,628)
9,991
40,203
(9,250)
49,890
(49,890)
—
(716,986)
592,366
(519,375)
(6,672)
(50)
(1,271)
—
64,998
(63,425)
244,100
180,675
Cash flows from operating activities
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural
properties
Capital expenditures for other properties and equipment
Acquisition of crude oil and natural gas properties, including
settlement adjustments and deposit for pending acquisition
Proceeds from sale of properties and equipment
Sale of promissory note
Restricted cash
Sale of short-term investments
Purchase of short-term investments
Intercompany transfers
Net cash from investing activities
Cash flows from financing activities:
Proceeds from issuance of senior notes
Redemption of senior notes
Purchase of treasury stock
Payment of debt issuance costs
Other
Intercompany transfers
Net cash from financing activities
Net change in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
$
116
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2016
Eliminations
Guarantor
Parent
Consolidated
Cash flows from operating activities
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural
properties
Capital expenditures for other properties and equipment
Acquisition of crude oil and natural gas properties, including
settlement adjustments and deposit for pending acquisition
Proceeds from sale of properties and equipment
Intercompany transfers
Net cash from investing activities
Cash flows from financing activities:
Proceeds from issuance of equity, net of issuance costs
Proceeds from issuance of senior notes
Proceeds from issuance of convertible senior notes
Proceeds from revolving credit facility
Repayment of revolving credit facility
Redemption of convertible notes
Payment of debt issuance costs
Purchase of treasury shares
Other
Intercompany transfers
Net cash from financing activities
Net change in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
(in thousands)
$
492,893
$
(6,630) $
— $
486,263
(436,361)
(2,282)
(1,076,256)
4,945
(9,415)
(1,519,369)
855,074
392,172
193,935
85,000
(122,000)
(115,000)
(15,556)
(6,935)
(577)
—
1,266,113
239,637
850
240,487
$
$
(523)
(1,182)
2,533
—
—
828
—
—
—
—
—
—
—
—
—
9,415
9,415
3,613
—
3,613
$
—
—
—
—
9,415
9,415
—
—
—
—
—
—
—
—
—
(9,415)
(9,415)
—
—
— $
(436,884)
(3,464)
(1,073,723)
4,945
—
(1,509,126)
855,074
392,172
193,935
85,000
(122,000)
(115,000)
(15,556)
(6,935)
(577)
—
1,266,113
243,250
850
244,100
The condensed consolidating financial statements for the year ended December 31, 2016 represent one month of
activity for the Guarantor as the Delaware Basin acquisition occurred in December 2016.
117
PDC ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
NOTE 18 - SUBSEQUENT EVENTS
Bayswater Acquisition. On January 5, 2018, we closed the Bayswater Acquisition for approximately $186 million,
subject to certain customary post-closing adjustments. After adjustments, we acquired approximately 7,400 net acres,
approximately 220 gross drilling locations, and 24 operated horizontal wells that were either drilled uncompleted wells or in-
process wells at the time of closing, for approximately $186 million, subject to certain customary post-closing adjustments. In
addition to the approximately $186 million of cash paid at closing, we invested approximately $15 million during December
2017 to complete 12 of the 24 wells. Upon executing the PSA, we paid a $21.0 million deposit toward the purchase price into
an escrow account, which is included in other assets on our December 31, 2017 consolidated balance sheet.
Utica Shale Divestiture. In February 2018, we entered into a PSA for the sale of the Utica Shale properties for net
cash proceeds of approximately $40.0 million, subject to certain customary closing adjustments. These properties were
classified as held-for-sale as they met the criteria for such classification beginning in the third quarter of 2017. See the footnote
titled Properties and Equipment for further details regarding the assets held-for-sale.
Saddle Butte Rockies Midstream Amendment Payment. On January 31, 2018, we received a payment of approximately
$24 million from Saddle Butte for the execution of an Amendment to an existing crude oil purchase and sale agreement, signed
in December 2017. The Amendment was effective contingent upon certain events which occurred in late January 2018. The
Amendment, among other things, dedicates the majority of our Wattenberg Field acreage for crude oil production to be
gathered by Saddle Butte's gathering lines and extends the term through December 2029.
118
PDC ENERGY, INC.
SUPPLEMENTAL INFORMATION
(Unaudited)
SUPPLEMENTAL INFORMATION - UNAUDITED
CRUDE OIL AND NATURAL GAS INFORMATION - UNAUDITED
Net Proved Reserves
All of our crude oil, natural gas, and NGLs reserves are located in the U.S. We utilize the services of independent
petroleum engineers to estimate our crude oil, natural gas, and NGL reserves. As of December 31, 2017, 2016, and 2015, all of
our estimates of proved reserves for the Wattenberg Field and the Utica Shale were based on reserve reports prepared by Ryder
Scott Company, L.P. and beginning in 2016, Netherland, Sewell & Associates, Inc. prepared the reserve reports for the
Delaware Basin. These reserve estimates have been prepared in compliance with professional standards and the reserves
definitions prescribed by the SEC.
Proved reserves are those quantities of crude oil, natural gas, and NGLs which can be estimated with reasonable
certainty to be economically producible under existing economic conditions and operating methods. Proved developed reserves
are the proved reserves that can be produced through existing wells with existing equipment and infrastructure and operating
methods. Proved undeveloped reserves are 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 development. All of our proved
undeveloped reserves conform to the SEC five-year rule requirement to be drilled within five years of each location’s initial
booking date.
The indicated index prices for our reserves, by commodity, are presented below.
As of December 31,
$
2017
2016
2015
Crude Oil
(per Bbl)
Average Benchmark Prices (1)
Natural Gas
(per Mcf)
NGLs
(per Bbl) (2)
$
51.34
42.75
50.28
$
2.98
2.48
2.59
The netted back price used to estimate our reserves, by commodity, are presented below.
As of December 31,
$
2017
2016
2015
Crude Oil
(per Bbl)
Price Used to Estimate Reserves (3)
Natural Gas
(per Mcf)
NGLs
(per Bbl) (2)
$
48.68
38.67
42.10
$
2.31
1.85
2.05
51.34
42.75
50.28
20.21
11.97
12.23
___________
(1) Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the
month prices for the preceding 12 months.
(2) For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes.
(3) These prices are based on the index prices and are net of basin differentials, any transportation fees, contractual adjustments,
and any Btu adjustments we experienced for the respective commodity.
119
PDC ENERGY, INC.
SUPPLEMENTAL INFORMATION
(Unaudited)
The following tables present the changes in our estimated quantities of proved reserves:
Proved Reserves:
Proved reserves, January 1, 2015
Revisions of previous estimates
Extensions, discoveries, and other additions
Acquisition of reserves
Dispositions
Production
Proved reserves, December 31, 2015
Revisions of previous estimates
Extensions, discoveries, and other additions
Acquisition of reserves
Dispositions
Production
Proved reserves, December 31, 2016
Revisions of previous estimates
Extensions, discoveries, and other additions
Acquisition of reserves
Dispositions
Production
Proved reserves, December 31, 2017
Proved Developed Reserves, as of:
December 31, 2015
December 31, 2016
December 31, 2017
Proved Undeveloped Reserves, as of:
December 31, 2015
December 31, 2016
December 31, 2017
Crude Oil,
Condensate
(MBbls)
Natural Gas
(MMcf)
NGLs
(MBbls)
Total
(MBoe)
100,515
(43,268)
48,707
17
(12)
(6,984)
98,975
(22,097)
494
50,126
(601)
(8,728)
118,169
28,334
2,923
18,971
(653)
(12,902)
154,842
536,972
(154,775)
311,709
215
(82)
(33,302)
660,737
(80,426)
4,094
305,224
(4,202)
(51,730)
833,697
96,119
11,541
289,223
(4,597)
(71,689)
1,154,294
60,119
(24,407)
30,835
23
(8)
(2,835)
63,727
(7,130)
355
32,586
(424)
(4,826)
84,288
8,104
1,158
19,604
(481)
(6,981)
105,692
250,129
(93,471)
131,494
76
(34)
(15,369)
272,825
(42,631)
1,531
133,583
(1,725)
(22,176)
341,407
52,457
6,005
86,778
(1,900)
(31,830)
452,917
26,257
30,013
46,862
72,718
88,156
107,980
175,367
264,452
365,332
485,370
569,245
788,962
15,011
24,196
35,220
48,716
60,092
70,472
70,496
98,284
142,971
202,329
243,122
309,946
120
PDC ENERGY, INC.
SUPPLEMENTAL INFORMATION
(Unaudited)
Developed
Undeveloped
(MBoe)
Total
Proved reserves, January 1, 2015
Undeveloped reserves converted to developed
Revisions of previous estimates
Extensions, discoveries, and other additions
Acquisition of reserves
Dispositions
Production
Proved reserves, December 31, 2015
Undeveloped reserves converted to developed
Revisions of previous estimates
Extensions, discoveries, and other additions
Acquisition of reserves
Dispositions
Production
Proved reserves, December 31, 2016
Undeveloped reserves converted to developed
Revisions of previous estimates
Extensions, discoveries, and other additions
Acquisition of reserves
Dispositions
Production
Proved reserves, December 31, 2017
74,905
29,090
(26,875)
8,703
76
(34)
(15,369)
70,496
32,192
6,112
1,531
10,229
(99)
(22,176)
98,285
54,648
18,291
2,292
1,305
(20)
(31,830)
142,971
175,224
(29,090)
(66,596)
122,791
—
—
—
202,329
(32,192)
(48,743)
—
123,354
(1,626)
—
243,122
(54,648)
34,166
3,713
85,473
(1,880)
—
309,946
250,129
—
(93,471)
131,494
76
(34)
(15,369)
272,825
—
(42,631)
1,531
133,583
(1,725)
(22,176)
341,407
—
52,457
6,005
86,778
(1,900)
(31,830)
452,917
2017 Activity. During 2017, we increased proved reserves by 33 percent or 111.5 MMBoe, relative to December 31,
2016. This proved reserve increase was primarily a result of an increase in acquisitions and reserve additions on proved
acreage in our Delaware Basin properties from our 2017 development plan. In 2017, we produced 31.8 MMboe.
Extensions, discoveries, and other additions for 2017 of 6.0 MMBoe includes the addition of five newly drilled wells
and seven proved undeveloped ("PUD") locations in the Delaware Basin.
Acquisitions of reserves of 86.8 MMBoe includes proved developed producing properties and PUD locations obtained
in our Wattenberg Field from acreage exchange transactions. We had minimal dispositions of 1.9 MMBoe related to the
acreage disposed of in an acreage exchange. In relation to our acreage exchange transactions, we primarily divested proved
acreage with future locations that were not in our proved five-year development plan as of December 31, 2016, as we do not
add non-operated PUD locations to our proved five-year development plan until drilling has started as our certainty threshold is
not achieved until such time.
We estimated 52.5 MMBoe in upward revisions from the following changes:
• Negative revisions of 57.7 MMBoe were due to Wattenberg Field PUD locations being dropped from our proved five-
•
year development plan and being replaced by PUD locations on newly-acquired properties.
Positive revisions of 93.9 MMBoe for infill drilling within a proven area, with 37.3 MMBoe in our Wattenberg Field
and 56.6 MMBoe in our Delaware Basin.
• Net negative revisions of 2.2 MMBoe were due to an increase in operating costs, partially offset by an increase in
prices for crude oil, natural gas, and NGLs.
• Negative revisions of 0.7 MMBoe were due to locations being removed due to the SEC five-year development rule.
• Net positive revisions of 19.2 MMBoe includes performance revisions and other items.
At December 31, 2016, we projected a PUD reserve conversion rate of 26 percent for 2017. As a result of drilling
plans being extended in our Delaware Basin in the first half of 2017, our actual reserve conversion rate was 23 percent,
resulting in 54.6 MMBoe of reserves recorded as PUDs at December 31, 2016, being converted to proved developed reserves as
of December 31, 2017.
121
PDC ENERGY, INC.
SUPPLEMENTAL INFORMATION
(Unaudited)
Based on economic conditions on December 31, 2017, our approved development plan provides for the development
of our remaining PUD locations within five years of the date such reserves were initially recorded. As of December 31, 2017,
our 2018 PUD reserve conversion rate is expected to be approximately 16 percent. Our lower 2018 PUD conversion rate is a
result of our Bayswater Acquisition that closed on January 5, 2018. We anticipate drilling acquired Bayswater locations in 2018
that are not included within our December 31, 2017 reserves. The Bayswater Acquisition is more fully described in the
footnote titled Subsequent Events to the consolidated financial statements included elsewhere in this report. The balance of the
PUD reserves are scheduled to be developed over the remaining four years in accordance with our current development plan.
The level of capital spending necessary to achieve this drilling schedule is consistent with our recent performance and our
outlook for future development activities.
2016 Activity. During 2016, we increased proved reserves by 25 percent or 68.6 MMBoe, relative to December 31,
2015. This proved reserve increase was primarily a result of the development of longer lateral length well bores in the
Wattenberg Field, which was driven by technology advancements, together with the ability to consolidate our leasehold position
to drill longer length laterals with increased working interests. We also acquired proved developed reserves and undeveloped
reserves in the Delaware Basin. Extensions, discoveries, and other additions for 2016 of 1.5 MMBoe includes the addition of
five wells in the Utica Shale.
Acquisitions of reserves of 133.6 MMBoe includes proved developed producing properties and PUD locations
acquired in our Delaware Basin acquisitions, and new proved locations obtained from an acreage exchange transaction.
Because of the preferential economics of the more concentrated acreage in the Wattenberg Field, we rescheduled the timing of
anticipated development in the field. This resulted in a downward revision to our proved reserves in the revisions of previous
estimates category. The net downward revisions were 42.6 MMBoe. The revision was most notably attributed to a 61.0
MMBoe decrease in reserves due to 2015 PUD locations being removed from our five year development plan and being
replaced by PUD locations reflected in purchases of reserves. Infill reserve additions of 16.8 MMBoe in the Wattenberg Field
were included as a positive revision of previous estimates. Infill reserve additions for years prior to 2016 for the Wattenberg
Field were reported in extensions, discoveries, and other additions, including infill reserves in an existing proved field.
Revisions also include a 0.5 MMBoe decrease on production due to pricing. The remaining 2.1 MMBoe in positive revisions of
previous estimates includes performance revisions and other items.
We had minimal dispositions of 1.7 MMBoe related to the acreage we traded in the acreage exchange.
At December 31, 2015, we projected a PUD reserve conversion rate of 19 percent for 2016. As a result of revisions to
our drilling plan during the last two months of 2016, our actual reserve conversion rate was 16 percent, resulting in 32.2
MMBoe of reserves recorded as PUDs at December 31, 2015, being converted to proved developed reserves as of December
31, 2016.
Based on economic conditions on December 31, 2016, our then-current development plan provided for the
development of our remaining PUD locations within five years of the date such reserves were initially recorded. As of
December 31, 2016, our 2017 PUD reserve conversion rate was expected to be approximately 26 percent.
2015 Activity. Overall, our proved reserves increased by 23 MMBoe as of December 31, 2015 as compared to
December 31, 2014. In 2015, we produced 15.4 MMBoe. At December 31, 2014, we projected a PUD conversion rate of 16
percent for 2015. Our actual conversion rate was 17 percent, resulting in 29 MMBoe of reserves booked as PUDs at December
31, 2014 being converted to proved developed reserves during 2015. As shown, we acquired and divested minimal volumes of
proved reserves in 2015.
Extensions, discoveries, and other additions, including infill reserves, of approximately 131 MMBoe in 2015 were all
added in the Wattenberg Field and primarily related to horizontal Niobrara projects being added to our development plan. The
reserve additions associated with these projects were largely the result of data generated from our downspacing testing. This
led to increased well density of our PUD locations year-over-year and extended the field by enabling us to book more reserves
per section in the Niobrara. In general, at December 31, 2014, Niobrara PUD locations were booked at an equivalent of eight
wells per section and at December 31, 2015, such locations were booked at an equivalent of 16 wells per section. Additionally,
due to more efficient drilling leading to shorter spud-to-spud times, we have increased the number of wells drilled per drilling
rig utilized during the course of the year. We had 791 gross PUD horizontal drilling locations at December 31, 2015, which
was an increase from 774 locations at December 31, 2014. Approximately 9 MMBoe of the extensions, discoveries, and other
additions to our developed reserves related to wells drilled that were not related to reserves booked as of the prior year-end.
122
PDC ENERGY, INC.
SUPPLEMENTAL INFORMATION
(Unaudited)
We recorded net downward revisions of previous estimates of proved reserves of approximately 93 MMBoe. The
revision was a result of multiple factors, most notably a decrease of approximately 56 MMBoe for adjustments to our
development plans in the Wattenberg Field resulting from the booking of further-downspaced PUD locations. This
downspacing delayed the expected development date for many existing PUD locations beyond the limits of the SEC five-year
rule. Also contributing to the downward revision was a decrease of approximately 33 MMBoe due to the significant decrease in
SEC commodity prices utilized in the December 31, 2015 reserve report, including approximately 11 MMBoe specifically
related to the removal of vertical re-fracs and re-completions from the proved developed reserves which no longer fall within
our economic parameters. There was an additional negative revision of approximately 22 MMBoe primarily related to geology
findings and leasehold factors. Partially offsetting these decreases was an upward revision approximately 18 MMBoe related to
well performance and forecast adjustments.
Results of Operations for Crude Oil and Natural Gas Producing Activities
The results of operations for crude oil and natural gas producing activities are presented below. The results include
activities related to both continuing and discontinued operations and exclude activities related to gas marketing and other
income. Comprehensive income (loss) includes net income (loss), as well as other changes in stockholders' equity that result
from transactions and economic events other than those with shareholders. There was no difference between our net income
(loss) and comprehensive income (loss) for any of the periods presented in the results of operations for crude oil and natural gas
producing activities shown.
Revenue:
Crude oil, natural gas and NGLs sales
Commodity price risk management gain (loss), net
$
2017
Year Ended December 31,
2016
(in thousands)
2015
$
913,084
(3,936)
909,148
$
497,353
(125,681)
371,672
Expenses:
Lease operating expenses
Production taxes
Transportation, gathering and processing expenses
Exploration expense
Impairment of properties and equipment
Depreciation, depletion, and amortization
Accretion of asset retirement obligations
Gain on sale of properties and equipment
Results of operations for crude oil and natural gas producing
activities before provision for income taxes
Provision for income taxes
Results of operations for crude oil and natural gas producing
activities, excluding corporate overhead and interest costs
89,641
60,717
33,220
47,334
285,887
462,482
6,306
(766)
984,821
(75,673)
47,247
59,950
31,410
18,415
4,669
9,973
413,105
7,080
(43)
544,559
(172,887)
64,733
$
(28,426)
$
(108,154)
$
378,713
203,183
581,896
56,992
18,443
10,151
1,102
161,620
298,760
6,293
(385)
552,976
28,920
(10,394)
18,526
Production costs include those costs incurred to operate and maintain productive wells and related equipment,
including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, production and severance
taxes, and associated administrative expenses. DD&A expense includes those costs associated with capitalized acquisition,
exploration, and development costs, but does not include the depreciation applicable to support equipment. The provision for
income taxes is computed using effective tax rates.
123
PDC ENERGY, INC.
SUPPLEMENTAL INFORMATION
(Unaudited)
Costs Incurred in Crude Oil and Natural Gas Property Acquisition, Exploration, and Development Activities
Costs incurred in crude oil and natural gas property acquisition, exploration, and development are presented below.
Acquisition of properties: (1)
Proved properties
Unproved properties
Development costs (2)
Exploration costs: (3)
Exploratory drilling
Geological and geophysical
Total costs incurred (4)
$
$
2017
Year Ended December 31,
2016
(in thousands)
2015
172
18,914
688,165
80,103
3,881
791,235
$
$
268,567
1,843,985
383,336
—
4,669
2,500,557
$
$
3,561
15
552,104
—
—
555,680
__________
(1) Property acquisition costs represent costs incurred to purchase, lease, or otherwise acquire a property. Proved properties
include approximately $40.9 million of infrastructure and pipeline costs in 2016.
(2) Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and
equip development wells, recomplete wells, and provide facilities to extract, treat, gather, and store crude oil, natural gas, and
NGLs. Of these costs incurred for the years ended December 31, 2017, 2016, and 2015, $463.4 million, $204.6 million, and
$207.8 million, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior
year end. These costs also include approximately $32.8 million of infrastructure and pipeline costs in 2017.
(3) Exploration costs represent costs incurred in identifying areas that may warrant examination and in examining specific areas
that are considered to have prospects of containing crude oil, natural gas, and NGLs. These costs include, but are not limited
to, dry hole contributions and costs of drilling and equipping exploratory wells.
(4) During the year ended 2017, we finalized our purchase price allocation for the 2016 Delaware Basin acquisition within the
one year measurement period. The finalization included a reduction to our proved, undeveloped and development costs of
$24.6 million. We excluded this reduction from our 2017 costs incurred as it did not relate to any cash acquisitions in 2017.
Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities
Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable
accumulated DD&A are presented below:
As of December 31,
2017
2016
(in thousands)
Proved crude oil and natural gas properties
Unproved crude oil and natural gas properties
Uncompleted wells, equipment and facilities
Capitalized costs
Less accumulated DD&A
Capitalized costs, net
$
$
4,356,922
1,097,317
265,526
5,719,765
(1,803,847)
3,915,918
$
$
3,499,718
1,874,671
150,424
5,524,813
(1,534,678)
3,990,135
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves
The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were
based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month,
January through December, applied to our year-end estimated proved reserves. Prices for each of the three years were adjusted
by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of
our commodity derivatives. Production and development costs were based on prices as of December 31 for each of the
respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general
and administrative expenses, debt service or to depreciation, depletion, and amortization expense. Production and development
costs include those cash flows associated with the expected ultimate settlement of our asset retirement obligations. Future
124
PDC ENERGY, INC.
SUPPLEMENTAL INFORMATION
(Unaudited)
estimated income tax expense is computed by applying the statutory rate in effect at the end of each year to the projected future
pre-tax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits, and allowances
related to the properties.
The following table presents information with respect to the standardized measure of discounted future net cash flows
relating to proved reserves. Changes in the demand for crude oil, natural gas, and NGLs, inflation and other factors make such
estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the
current market value of our proved reserves.
2017
As of December 31,
2016
(in thousands)
2015
Future estimated cash flows
Future estimated production costs*
Future estimated development costs
Future estimated income tax expense
Future net cash flows
10% annual discount for estimated timing of cash flows
Standardized measure of discounted future estimated net cash flows
$
$
12,340,407
(3,245,627)
(2,893,335)
(748,494)
5,452,951
(2,572,846)
2,880,105
$
$
7,122,525
(1,624,167)
(2,219,914)
(597,476)
2,680,968
(1,260,339)
1,420,629
$
$
6,297,298
(1,493,040)
(2,036,685)
(508,332)
2,259,241
(1,162,377)
1,096,864
___________
* Represents future estimated lease operating expenses, production taxes, transportation, gathering, and processing expenses.
The following table presents the principal sources of change in the standardized measure of discounted future
estimated net cash flows:
2017
Year Ended December 31,
2016
(in thousands)
2015
Beginning of period
$
1,420,629
$
1,096,864
$
2,306,465
Sales of crude oil, natural gas and NGLs production, net of production
costs
Net changes in prices and production costs (1)
Extensions, discoveries, and improved recovery, less related costs
Sales of reserves
Purchases of reserves
Development costs incurred during the period
Revisions of previous quantity estimates
Changes in estimated income taxes
Net changes in future development costs
Accretion of discount
Timing and other
End of period
$
(729,506)
841,713
47,240
(2,613)
224,483
419,047
484,431
(138,560)
25,183
167,487
120,571
2,880,105
$
(387,576)
(205,760)
15,128
(3,745)
487,636
268,672
(320,286)
(13,630)
391,145
133,747
(41,566)
1,420,629
$
(293,127)
(1,752,921)
489,178
(463)
374
368,840
(1,286,462)
902,994
112,958
345,007
(95,979)
1,096,864
__________
(1) Our weighted-average price, net of production costs per Boe, in our 2017 reserve report increased to $20.08 as compared to $15.73
for 2016 and $17.30 for 2015.
The data presented should not be viewed as representing the expected cash flows from, or current value of, existing
proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities
cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The
required projection of production and related expenditures over time requires further estimates with respect to pipeline
availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different
from the recent average prices and current costs utilized in the computation of reported amounts. Any analysis or evaluation of
the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent
therein.
125
PDC ENERGY, INC.
QUARTERLY FINANCIAL INFORMATION - UNAUDITED
Quarterly financial data for the years ended December 31, 2017 and 2016 is presented below. The quarterly
consolidated statements of operations below reflect our revised presentation. The sum of the quarters may not equal the total of
the year's net income or loss per share due to changes in the weighted-average shares outstanding throughout the year.
2017
Quarter Ended
March 31
June 30
September 30 December 31
Total revenues
Total costs, expenses and other
Income (loss) from operations
Income (loss) before income taxes
Net income (loss) (1)
Earnings per share:
Basic
Diluted
________
(in thousands, except per share data)
$
$
$
$ 273,707
182,004
91,703
72,476
46,146
$
275,158
190,522
84,636
65,787
41,250
183,235
579,326
(396,091)
(414,887)
(292,537) $
189,516
208,016
(18,500)
(62,808)
77,637
$
$
$
$
$
0.70
0.70
0.63
0.62
(4.44) $
(4.44)
1.18
1.17
(1) Net income of $77.6 million for the quarter ended December 31, 2017 is primarily due to an income tax benefit of
$114.4 million resulting from a decrease in deferred tax assets and liabilities related to the 2017 Tax Act.
2016
Quarter Ended
March 31
June 30
September 30 December 31
(in thousands, except per share data)
$
$
$
90,831
193,864
(103,033)
(113,369)
(71,530) $
20,097
163,379
(143,282)
(153,777)
(95,450) $
163,890
179,178
(15,288)
(35,341)
(23,309) $
108,097
178,608
(70,511)
(90,636)
(55,639)
(1.72) $
(1.72)
(2.04) $
(2.04)
(0.48) $
(0.48)
(0.94)
(0.94)
Total revenues
Total costs, expenses and other
Loss from operations
Loss before income taxes
Net loss
Earnings per share:
Basic
Diluted
$
$
$
126
PDC ENERGY, INC.
FINANCIAL STATEMENT SCHEDULE
Schedule II -VALUATION AND QUALIFYING ACCOUNTS
Description
Beginning
Balance
January 1,
Charged to
Costs and
Expenses
Deductions
(1)
(in thousands)
Ending
Balance
December
31,
2017:
Allowance for uncollectible notes
Allowance for doubtful accounts
Allowance for expirations of unproved crude oil and natural gas
properties
$
44,038
2,190
$
— $
1,108
$
44,038
170
—
3,128
359
263,817
13,017
251,159
2016:
Allowance for uncollectible notes
Allowance for doubtful accounts
Allowance for expirations of unproved crude oil and natural
gas properties
2015:
Allowance for doubtful accounts
Allowance for expirations of unproved crude oil and natural
gas properties
—
2,009
144
486
9,293
44,038
1,309
215
1,700
7,012
—
1,128
—
177
16,161
44,038
2,190
359
2,009
144
____________
(1) For allowance for uncollectible notes, deductions represent reversals of allowances due to the collection of amounts owed. For
allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For allowance for
expirations of unproved crude oil and natural gas properties, deductions represent either actual expired or abandoned unproved crude
oil and natural gas properties or an accumulated amortization of expired or abandoned unproved crude oil and natural gas properties,
with a corresponding decrease to the historical cost of the associated asset.
127
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
As of December 31, 2017, we carried out an evaluation under the supervision and with the participation of
management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and
operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). Based on the
results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls
and procedures were not effective as of December 31, 2017 because of the material weaknesses in our internal control over
financial reporting described below.
Management's Report on Internal Control over Financial Reporting
Management 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) of the Exchange Act. Internal control over financial reporting is a process
designed by, or under the supervision of, our CEO and CFO, or persons performing similar functions, and effected by our board
of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
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 policies or procedures may deteriorate.
Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2017,
based upon the criteria established in "Internal Control – Integrated Framework (2013)" issued by the Committee of Sponsoring
Organizations of the Treadway Commission ("COSO").
A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such
that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be
prevented or detected on a timely basis.
We did not maintain a sufficient complement of personnel within the Land Department as a result of increased volume
of leases, which contributed to the ineffective design and maintenance of controls to verify the completeness and accuracy of
land administrative records associated with unproved leases, which are used in verifying the completeness, accuracy, valuation,
rights and obligations over the accounting of properties and equipment, sales and accounts receivable, and costs and expenses.
These control deficiencies resulted in immaterial adjustments of our unproved properties, impairment of unproved properties,
sales, accounts receivable, and depletion expense accounts and related disclosures during 2017.
Additionally, these control deficiencies could result in misstatements of substantially all accounts and disclosures that
would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented
or detected. Accordingly, our management has determined that these control deficiencies constitute material weaknesses.
The effectiveness of our internal control over financial reporting as of December 31, 2017, has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears under
Item 8.
Remediation Plan for Material Weaknesses
In response to the identified material weaknesses, our management, with the oversight of the Audit Committee of our
board of directors, has begun the process of assessing a number of different remediation initiatives to improve our internal
control over financial reporting for the year ended December 31, 2018. We are currently in the process of evaluating the
material weaknesses and are developing a plan of remediation to strengthen our overall controls over the sufficient complement
of personnel within the Land Department and the completeness and accuracy of land administration records. We are committed
to continuing to improve our internal control processes and will continue to review, optimize, and enhance our internal control
128
environment. These material weaknesses will not be considered remediated until the applicable remedial controls operate for a
sufficient period of time and management has concluded, through testing, that these controls are operating effectively.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting during the quarter ended December 31, 2017
that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
129
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed
pursuant to Regulation 14A for our 2018 Annual Stockholders' meeting and is incorporated by reference in this report.
ITEM 11. EXECUTIVE COMPENSATION
Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed
pursuant to Regulation 14A for our 2018 Annual Stockholders' meeting and is incorporated by reference in this report.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed
pursuant to Regulation 14A for our 2018 Annual Stockholders' meeting and is incorporated by reference in this report.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed
pursuant to Regulation 14A for our 2018 Annual Stockholders' meeting and is incorporated by reference in this report.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed
pursuant to Regulation 14A for our 2018 Annual Stockholders' meeting and is incorporated by reference in this report.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
PART IV
(a)
(1) Exhibits:
See Exhibits Index on the following page.
130
ITEM 16. FORM 10-K SUMMARY
None.
Exhibits Index
Exhibit
Number
Exhibit Description
Incorporated by Reference
Form
SEC File
Number
Exhibit
Filing Date
Filed
Herewith
2.1
2.2
2.3
3.1
3.2
4.1
4.2
4.3
4.4
4.5
10.1
10.2
10.3
10.4
Plan of Conversion, dated June 5, 2015, by PDC Energy, Inc. (the
"Company").
8-K12B
001-37419
2.1
6/8/2015
Stock Purchase and Sale Agreement, dated August 23, 2016, by and
among the seller parties thereto, Kimmeridge Energy Management
Company GP, LLC, Arris Petroleum Corporation, and PDC
Energy, Inc.
Asset Purchase and Sale Agreement, dated August 23, 2016, by and
among 299 Resources, LLC, 299 Production, LLC, 299 Pipeline,
LLC, Kimmeridge Energy Management Company GP, LLC and PDC
Energy, Inc.
8-K
001-37419
2.1
8/24/2016
8-K
001-37419
2.2
8/24/2016
Certificate of Incorporation of the Company.
8-K12B
001-37419
3.1
6/8/2015
By-laws of the Company.
Form of Common Stock Certificate of the Company.
Indenture, dated as of November 29, 2017, by and between PDC
Energy, Inc., PDC Permian, Inc., a subsidiary guarantor of the
Company, and U.S. Bank Trust National Association, as Trustee,
relating to the 5.750% Senior Notes due 2026.
8-K12B
001-37419
10-K
001-37419
8-K
001-37419
3.2
4.1
4.1
6/8/2015
2/28/2017
11/29/2017
Base Indenture, dated as of September 14, 2016, by and between the
Company and U.S. Bank Trust National Association, as Trustee.
8-K
001-37419
4.1
9/14/2016
First Supplemental Indenture, dated as of September 14, 2016, by and
between the Company and U.S. Bank Trust National Association, as
Trustee, relating to the 1.125% Convertible Senior Notes due 2021.
8-K
001-37419
4.2
9/14/2016
Indenture, dated as of September 15, 2016, by and between PDC
Energy, Inc. and U.S. Bank Trust National Association, as Trustee,
relating to the 6.125% Senior Notes due 2024.
8-K
001-37419
4.1
9/15/2016
Form of Indemnification Agreement.
8-K
000-07246
401(k) and Profit Sharing Plan, as amended on January 4, 2016.
10-K
001-37419
Amended and Restated Non-Employee Director Deferred
Compensation Plan.
10-K
6/8/2015
2/28/2017
10.1
10.2
10.3
X
2004 Long-Term Equity Compensation Plan amended and
restated as of March 8, 2008 ("2004 Plan").
10-K
000-07246
10.26
2/27/2009
10.4.1
Summary of 2010 Stock Appreciation Rights and Restricted
Stock Awards under the 2004 Plan.
8-K
000-07246
4/23/2010
10.5
10.6
10.7
10.7.1
10.7.2
Amended and Restated 2010 Long-Term Equity Compensation Plan,
as amended.
10-K
001-37419
10.5
2/22/2016
Executive Severance Compensation Plan, as amended.
Form of 2011 Restricted Stock/Stock Appreciation Rights
Agreement.
Form of 2013 Performance Share Agreement.
Form of 2013 Restricted Stock/Stock Appreciation Rights
Agreement.
10-K
10-K
10-K
10-K
001-37419
10.6
2/22/2016
000-07246
10.5.2
2/21/2014
000-07246
10.9
2/27/2013
000-07246
10.10
2/27/2013
10.7.3
Form of 2014 Performance Share Agreement.
10-K
000-07246
10.5.4
2/19/2015
10.7.4
Form of 2014 Restricted Stock/Stock Appreciation Rights Agreement.
10-K
000-07246
10.5.5
2/19/2015
131
Incorporated by Reference
SEC File
Number
Exhibit
Filing Date
Filed
Herewith
000-07246
10.5.6
2/19/2015
000-07246
10.5.7
2/19/2015
000-07246
10.5.8
2/19/2015
001-37419
10.7.8
2/22/2016
000-07246
10.3
4/23/2010
Form
10-K
10-K
10-K
10-K
8-K
Employment Agreement with Daniel W. Amidon, General Counsel
and Corporate Secretary, dated as of April 19, 2010.
Employment Agreement with Lance A. Lauck, Senior Vice President
of Business Development, dated as of April 19, 2010.
8-K
000-07246
10.4
4/23/2010
Exhibit
Number
Exhibit Description
10.7.5
Form of 2015 Performance Share Agreement.
10.7.6
Form of 2015 Restricted Stock Unit Agreement.
10.7.7
Form of 2015 Stock Appreciation Rights Agreement.
10.7.8
Form of 2016 Performance Share Agreement.
10.9
10.10
10.11
10.11.1
10.11.2
10.11.3
10.11.4
10.11.5
Third Amended and Restated Credit Agreement dated as of May 21,
2013, among PDC Energy, Inc. as Borrower, Riley Natural Gas
Company, a Subsidiary of PDC Energy, Inc., as Guarantor, JP Morgan
Chase Bank, N.A. as Administrative Agent, J.P. Morgan Securities
LLC as Sole Bookrunner and Co-Lead Arranger, Wells Fargo Bank,
N.A. as Syndication Agent, and Wells Fargo Securities, LLC as Co-
Lead Arranger, and Certain Lenders.
First and Second Amendments to Third Amended and Restated Credit
Agreement dated as of May 14, 2014 and September 30, 2015,
respectively, among PDC Energy, Inc. as the Borrower, the Lenders
party thereto and JPMorgan Chase Bank, N.A., as Administrative
Agent for the Lenders.
Third Amendment to the Third Amended and Restated Credit
Agreement, dated as of September 6, 2016, among the Company, as
Borrower, certain Subsidiaries of the Company, as Guarantors, the
lenders from time to time party thereto (the “Lenders”) and JPMorgan
Chase Bank, N.A., as Administrative Agent for the Lenders.
Fourth Amendment to the Third Amended and Restated Credit
Agreement, dated as of October 14, 2016, among the Company, as
Borrower, certain Subsidiaries of the Company, as Guarantors, the
lenders from time to time party thereto (the “Lenders”) and JPMorgan
Chase Bank, N.A., as Administrative Agent for the Lenders.
Fifth Amendment to Third Amended and Restated Credit Agreement,
dated as of May 10, 2017, among the Company, as Borrower, certain
Subsidiaries of the Company, as Guarantors, JPMorgan Chase Bank,
N.A., as administrative agent, and the other lenders party thereto.
Sixth Amendment to the Third Amended and Restated Credit
Agreement, dated as of October 6, 2017, among the Company, as
Borrower, certain Subsidiaries of the Company, as Guarantors, the
lenders from time to time party thereto (the “Lenders”) and JPMorgan
Chase Bank, N.A., as Administrative Agent for the Lenders.
10.12*
Change of Control and Severance Plan.
10.12.1*
Amendment to the PDC Energy Change of Control and Severance
Plan.
10.13
10.14
10.15
10.16
10.17
Registration Rights Agreement, dated as of September 15, 2016, by
and between PDC Energy, Inc. and J.P. Morgan Securities LLC, as
representative of the initial purchasers, relating to the 6.125% Senior
Notes due 2024.
Investment Agreement, dated December 6, 2016, by and among the
Investor parties identified therein and PDC Energy, Inc. (relating to
the Stock Purchase and Sale Agreement).
Investment Agreement, dated December 6, 2016, by and among the
Investor parties identified therein and PDC Energy, Inc. (relating to
the Asset Purchase and Sale Agreement).
Purchase Agreement, dated as of November 14, 2017, by and between
10.PDC Energy, Inc., Merrill Lynch, Pierce, Fenner & Smith
Incorporated, as representative of the initial purchasers named
therein, and PDC Permian, Inc., a subsidiary guarantor of the
Company, relating to the 5.750% Senior Notes due 2026.
Registration Rights Agreement, dated as of November 29, 2017, by
and between PDC Energy, Inc., PDC Permian, Inc., a subsidiary
guarantor of the Company, and Merrill Lynch, Pierce, Fenner &
Smith Incorporated, as representative of the initial purchasers,
relating to the 5.750% Senior Notes due 2026.
132
8-K
000-07246
10.1
5/28/2013
10-K
001-37419
10.11.1
2/22/2016
8-K
001-37419
10.1
9/8/2016
10-Q
001-37419
99.1
11/3/2016
8-K
001-37419
10.1
5/16/2017
10-Q
001-37419
10.1
11/7/2017
10-K
10-K
001-37419
10.14
2/28/2017
001-37419
10.14.1
2/28/2017
8-K
001-37419
10.2
9/15/2016
8-K
001-37419
10.1
12/7/2016
8-K
001-37419
10.2
12/7/2016
8-K
001-37419
10.1
11/17/2017
8-K
001-37419
10.1
11/29/2017
Exhibit
Number
Exhibit Description
Incorporated by Reference
Form
SEC File
Number
Exhibit
Filing Date
Filed
Herewith
12.1
21.1
23.1
23.2
23.3
31.1
31.2
32.1
99.1
99.2
Computation of Ratio of Earnings to Fixed Charges.
Subsidiaries.
Consent of PricewaterhouseCoopers LLP.
Consent of Ryder Scott Company, L.P., Petroleum Consultants.
Consent of Netherland, Sewell & Associates, Inc., Petroleum
Consultants.
Certification by Chief Executive Officer pursuant to Rule 13a-14(a)
and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
Certification by Chief Financial Officer pursuant to Rule 13a-14(a)
and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
Certifications by Chief Executive Officer and Chief Financial Officer
pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of Sarbanes-Oxley Act of 2002.
Report of Independent Petroleum Consultants - Ryder Scott
Company, L.P.
Report of Independent Petroleum Consultants - Netherland, Sewell &
Associates, Inc.
101.INS
XBRL Instance Document
101.SCH
XBRL Taxonomy Extension Schema Document
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document
101.LAB
XBRL Taxonomy Extension Label Linkbase Document
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
133
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.
SIGNATURES
PDC ENERGY, INC.
By: /s/ Barton R. Brookman
Barton R. Brookman
President and Chief Executive Officer
February 26, 2018
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the Registrant and in the capacities and on the dates indicated:
Signature
Title
/s/ Barton R. Brookman
Barton R. Brookman
/s/ R. Scott Meyers
R. Scott Meyers
/s/ Jeffrey C. Swoveland
Jeffrey C. Swoveland
/s/ Anthony J. Crisafio
Anthony J. Crisafio
/s/ Larry F. Mazza
Larry F. Mazza
/s/ David C. Parke
David C. Parke
/s/ Randy S. Nickerson
Randy S. Nickerson
/s/ Mark E. Ellis
Mark E. Ellis
/s/ Christina M. Ibrahim
Christina M. Ibrahim
Date
February 26, 2018
President, Chief Executive Officer and Director
(principal executive officer)
Senior Vice President and Chief Financial Officer
(principal financial officer and principal accounting officer)
February 26, 2018
Chairman and Director
February 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018
Director
Director
Director
Director
Director
Director
134
GLOSSARY OF UNITS OF MEASUREMENT AND INDUSTRY TERMS
UNITS OF MEASUREMENT
The following presents a list of units of measurement used throughout the document.
Bbl – One barrel of crude oil or NGL or 42 gallons of liquid volume.
Bcf – One billion cubic feet of natural gas volume.
Boe – One barrel of crude oil equivalent.
Btu – British thermal unit.
BBtu – One billion British thermal units.
MBoe – One thousand barrels of crude oil equivalent.
MBbls – One thousand barrels of crude oil.
Mcf – One thousand cubic feet of natural gas volume.
MMBoe – One million barrels of crude oil equivalent.
MMBbls – One million barrels of crude oil.
MMBtu – One million British thermal units.
MMcf – One million cubic feet of natural gas volume.
GLOSSARY OF INDUSTRY TERMS
The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report:
CIG - Colorado Interstate Gas.
Completion - Refers to the installation of permanent equipment for the production of crude oil and natural gas from a recently
drilled well or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.
Developed acreage - Acreage assignable to productive wells.
Development well - A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known
to be productive.
Differentials - The difference between the crude oil and natural gas index spot price and the corresponding cash spot price in a
specified location.
Dry well or dry hole - A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an
oil or gas well.
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 gas in another reservoir.
Extensions, discoveries, and other additions - As to any period, the increases to proved reserves from all sources other than the
acquisition of proved properties or revisions of previous estimates.
Farm-out - Transfer of all or part of the operating rights from a working interest owner to an assignee, who assumes all or some
of the burden of development in return for an interest in the property. The assignor usually retains an overriding royalty interest
but may retain any type of interest.
Fracture or Fracturing - Procedure to stimulate production by forcing a mixture of fluid and proppant into the formation under
high pressure. Fracturing creates artificial fractures in the reservoir rock to increase permeability and porosity, thereby allowing
the release of trapped hydrocarbons.
Gross acres or wells - Refers to the total acres or wells in which we have a working interest.
Horizontal drilling - A drilling technique that permits the operator to drill a horizontal well shaft from the bottom of a vertical
well and thereby to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques
and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons.
135
Joint interest billing - Process of billing/invoicing the costs related to well drilling, completions, and production operations among
working interest partners.
Natural gas liquid(s) or NGL(s) - Hydrocarbons which can be extracted from natural gas and become liquid under various
combinations of increasing pressure and lower temperature. NGLs include ethane, propane, butane, and other natural gasolines.
Net acres or wells - Refers to gross acres or wells we own multiplied, in each case, by our percentage working interest. References
to net acres or wells include our proportionate share of PDCM's and our affiliated partnerships' net acres or wells.
Net production - Crude oil and natural gas production that we own, less royalties and production due to others.
Non-operated - A project in which we are not the operator.
NYMEX - New York Mercantile Exchange.
Operator - The individual or company responsible for the exploration, development and/or production of an oil or gas well or
lease.
Overriding royalty - An interest which is created out of the operating or working interest. Its term is coextensive with that of the
operating interest.
Possible reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain
to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a
project have a low probability to exceed the sum of proved, probable, and possible reserves. When probabilistic methods are used,
there must be at least a 10 percent probability that the actual quantities recovered will equal or exceed the sum of proved, probable
and possible estimates.
Present value of future net revenues or (PV-10) - The present value of estimated future revenues to be generated from the production
of proved reserves, before income taxes, of proved reserves calculated in accordance with Financial Accounting Standards Board
guidelines, net of estimated production and future development costs, using pricing and costs as of the date of estimation without
future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative
expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10 percent.
PV-10 is pre-tax and therefore a non-U.S. GAAP financial measure.
Probable reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain
to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When
deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated
proved plus probable reserves. Similarly, when probabilistic methods are used, there must be at least a 50 percent probability that
the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
Productive well - An exploratory or developmental well that is not a dry well or dry hole, as defined above.
Proved developed non-producing reserves - Reserves that consist of (i) proved reserves from wells which have been completed
and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and/or
(ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log
characteristics and analogous production in the immediate vicinity of the wells.
Proved developed producing reserves or PDPs - Proved reserves that can be expected to be recovered from currently producing
zones under the continuation of present operating methods.
Proved developed reserves - The combination of proved developed producing and proved developed non-producing reserves.
Proved reserves - This term means "proved oil and gas reserves" as defined in SEC Regulation S-X Section 4-10(a) and refers to
those quantities of crude oil and condensate, natural gas, and NGLs, 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 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.
136
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.
Recomplete or Recompletion - The modification of an existing well for the purpose of producing crude oil and natural gas from a
different producing formation.
Reserves - Estimated remaining quantities of crude oil, natural gas, NGLs 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 crude oil, natural gas, and NGLs or related substances to market, and all permits and financing
required to implement the project.
Royalty - An interest in a crude oil and natural gas lease or mineral interest that gives the owner of the royalty the right to receive
a portion of the production from the leased acreage or mineral interest (or of the proceeds of the sale thereof), but generally does
not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be
either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding
royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
Section - A square tract of land one mile by one mile, containing 640 acres.
Spud - To begin drilling; the act of beginning a hole.
Standardized measure of discounted future net cash flows or standardized measure - Future net cash flows discounted at a rate of
10 percent. Future net cash flows represent the estimated future revenues to be generated from the production of proved reserves
determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs
as of the date of estimation without future escalation, giving effect to (i) estimated future abandonment costs, net of the estimated
salvage value of related equipment and (ii) future income tax expense.
Stratigraphic test well - A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition.
Such wells customarily are drilled without the intent of being completed for hydrocarbon production.
Undeveloped acreage - Leased acreage on which wells have not been drilled or completed to a point that would permit the
production of commercial quantities of crude oil and natural gas, regardless of whether such acreage contains proved reserves.
Waha - Waha West Texas natural gas prices
Working interest - An interest in a crude oil and natural gas lease that gives the owner of the interest the right to drill and produce
crude oil and natural gas on the leased acreage. It requires the owner to pay its share of the costs of drilling and production
operations.
Workover - Major remedial operations on a producing well to restore, maintain, or improve the well's production.
137
I, Barton R. Brookman, certify that:
CERTIFICATIONS
1.
I have reviewed this Annual Report on Form 10-K of PDC Energy, Inc.;
Exhibit 31.1
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and
for, the periods presented in this report;
4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period
in which this report is being prepared;
b. Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report
our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred
during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control
over financial reporting; and
5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control
over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or
persons performing the equivalent functions):
a. All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process,
summarize and report financial information; and
b. Any fraud, whether or not material, that involves management or other employees who have a significant role
in the registrant's internal control over financial reporting.
Date: February 26, 2018
/s/ Barton R. Brookman
Barton R. Brookman
President and Chief Executive Officer
(principal executive officer)
I, R. Scott Meyers, certify that:
CERTIFICATIONS
1.
I have reviewed this Annual Report on Form 10-K of PDC Energy, Inc.;
Exhibit 31.2
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and
for, the periods presented in this report;
4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period
in which this report is being prepared;
b. Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report
our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred
during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control
over financial reporting; and
5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control
over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or
persons performing the equivalent functions):
a. All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process,
summarize and report financial information; and
b. Any fraud, whether or not material, that involves management or other employees who have a significant role
in the registrant's internal control over financial reporting.
Date: February 26, 2018
/s/ R. Scott Meyers
R. Scott Meyers
Senior Vice President and Chief Financial Officer
(principal financial officer)
CERTIFICATION
Exhibit 32.1
In connection with the Annual Report of PDC Energy, Inc. (the "Company") on Form 10-K for the period ended December 31,
2017, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned certify pursuant
to § 906 of the Sarbanes-Oxley Act of 2002, that:
1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of
operations of the Company.
/s/ Barton R. Brookman
Barton R. Brookman
President and Chief Executive Officer
(principal executive officer)
/s/ R. Scott Meyers
R. Scott Meyers
Senior Vice President and Chief Financial Officer
(principal financial officer)
February 26, 2018
February 26, 2018
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OPERATING DATA
(as of December 31)
Proved Reserves
Crude oil and condensate (MMBbls)
Natural gas (Bcf)
NGLs (MMBbls)
Total Proved Reserves (MMBoe)
Annual Production
Crude oil (MMBbls)
Natural gas (Bcf)
NGLs (MMBbls)
Total Production (MMBoe)
Average Sales Price* & Select Expenses
Crude oil (per Bbl)
Natural gas (per Mcf)
NGLs (per Bbl)
‘17
‘16
‘15
155
1,154
106
453
12.9
71.7
7.0
31.8
118
834
84
341
8.7
51.7
4.8
22.2
99
661
64
273
7.0
33.3
2.8
15.4
$
$
$
48.45
2.21
18.59
$
$
$
39.96
1.77
11.80
$
$
$
40.14
2.04
10.72
Crude Oil Equivalent per Boe
$ 28.69
$ 22.43
$
24.64
Lease operating expenses per Boe
General and administrative expense per Boe
Production taxes per Boe
$
$
$
2.82
3.78
1.91
$
$
$
2.70
5.07
1.42
$
$
$
3.71
5.85
1.20
SELECTED FINANCIAL DATA
(in millions except per share data)
(as of December 31)
Statement of Operations
‘17
‘16
‘15
Crude oil, natural gas and NGLs sales
$
913.1
$
497.4
$
378.7
Commodity price risk management gain (loss), net
Total revenues
Net income (loss)
(3.9)
921.6
(127.5)
(125.7)
382.9
(245.9)
203.2
595.3
(68.3)
Net income (loss) per diluted share
$
(1.94)
$
(5.01)
$
(1.74)
Statement of Cash Flows
Net cash provided by operating activities
$
588.6
$
486.3
$
411.1
Capital expenditures
Acquisitions (cash portion)
Balance Sheet
Total assets
Long-term debt
Total stockholders equity
Total Debt-to-Book Capital
* Excludes net settlements on derivatives and transportation,
gathering and processing expense
742.3
15.6
440.3
1,073.7
604.7
-
$ 4,419.9
$ 4,485.8
$ 2,370.5
1,151.9
2,507.6
1,044.0
2,622.8
529.4
1,287.2
31%
28%
33%
SENIOR MANAGEMENT TEAM
BOARD OF DIRECTORS
Barton R. Brookman
President and Chief Executive Officer
Lance A. Lauck
Executive Vice President Corporate Development and Strategy
Scott J. Reasoner
Senior Vice President Chief Operating Officer
R. Scott Meyers
Senior Vice President Chief Financial Officer
Daniel W. Amidon
Senior Vice President General Counsel and Secretary
CORPORATE HEADQUARTERS
PDC Energy, Inc.
1775 Sherman Street
Suite 3000
Denver, Colorado 80203-4341
303.860.5800
www.pdce.com
REGIONAL HEADQUARTERS
PDC Energy, Inc.
120 Genesis Boulevard
Bridgeport, West Virginia 26330-9665
304.842.3597
STOCK EXCHANGE LISTING
NASDAQ: PDCE
2018 ANNUAL MEETING OF STOCKHOLDERS
The Annual Meeting of Stockholders will be held on May 30, 2018,
beginning at 9:15 a.m. MT. The meeting will be held at Denver
Financial Center at 1775 Sherman St., Denver, Colorado 80203.
INDEPENDENT RESERVE ENGINEERS
Ryder Scott Company, L.P. Houston, Texas
Netherland, Sewell & Associates, Inc. Dallas, Texas
INDEPENDENT AUDITORS
PricewaterhouseCoopers LLP, Denver
Jeffrey C. Swoveland
Chairman of the Board
Barton R. Brookman
Anthony J. Crisafio
Mark E. Ellis
Christina M. Ibrahim
Larry F. Mazza
Randy S. Nickerson
David C. Parke
FORM 10-K
Additional copies of the PDC Energy, Inc. Annual Report on Form 10-K for the
year ended December 31, 2017, as filed with the U.S. Securities and Exchange
Commission (SEC), may be obtained free of charge by writing to the Company’s
corporate headquarters, Attention: Corporate Secretary. Copies are also available
electronically on the Company’s website, www.pdce.com. While we recommend
you view our website, the information available on our website is not part of this
report and is not incorporated by reference.
SHAREHOLDER SERVICES
Broadridge Corporate Issuer Solutions, Inc.
P.O. Box 1342
Brentwood, NY 11717
www.shareholder.broadridge.com
shareholder@broadridge.com
877-830-4936
Contact Broadridge for information regarding change of address, registration of
shares, transfers or lost certificates, or for information about your shareholder
account.
ANNUAL REPORT DESIGN
Prism Group Marketing, Denver
FORWARD-LOOKING STATEMENTS
The information provided in this annual report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-
looking statements are based on management’s current expectations and beliefs, as well as a number of assumptions concerning future events. These statements are based
on certain assumptions and analyses made by management of the Company in light of its experience and its perception of historical trends, current conditions and expected
future developments as well as other factors it believes are appropriate in the circumstances. However, whether actual results and developments will conform with management’s
expectations and predictions is subject to a number of risks and uncertainties, general economic, market or business conditions; the opportunities (or lack thereof) that may be
presented to and pursued by the Company; changes in laws or regulations; and other factors, many of which are beyond the control of the Company. You are cautioned not to put
undue reliance on such forward-looking statements because actual results may vary materially from those expressed or implied, as more fully discussed in the safe harbor statements
found in the Company’s SEC fi lings, including, without limitation, the discussion under the heading “Note Regarding Forward-Looking Statements” and “Risk Factors” and elsewhere
in the Company’s most recent annual report on Form 10-K and in subsequent Form 10-Qs. All forward-looking statements are based on information available to management on
this date and the Company assumes no obligation to, and expressly disclaims any obligation to, update or revise any forward-looking statements, whether as a result of new
information, future events or otherwise.
The Company has a Code of Business Conduct and Ethics (the “Code of Conduct”) that applies to all Directors, officers, employees, agents, consultants and representatives of the
Company, which is reviewed at least annually by the Nominating and Governance Committee. The Company’s principal executive officer, principal financial officer and principal
accounting officer are subject to additional specific provisions under the Code of Conduct. The Code of Conduct can be viewed on the Company’s website at www.pdce.com.
In the event the Board approves an amendment to or a waiver of any provisions of the Code of Conduct, the Company will disclose the information on its website.
CORE
Returns | Results | Responsibility
PDC Energy, Inc.
1775 Sherman Street
Suite 3000
Denver, Colorado 80203-4341
303.860.5800
www.pdce.com
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2017 Annual Report