FPO
1
CALLON PETROLEUM ANNUAL REPORT
2
OILY PERMIAN
PROVED RESERVES
(MMBOE)
OIL
NATURAL GAS + NGLS
YEAR
2016
GROWTH VS. PY
TOTAL
91.6
+69%
71.2
20.4
2015
GROWTH VS. PY
43.3
10.9
54.3
+65%
2014
GROWTH VS. PY
25.7
7.1
32.8
+121%
2016HIGHLIGHTSEXPANDED SCOPE FOUR CORE OPERATING AREAS IN BOTH MIDLAND AND DELAWARE BASINSFOUR SIGNED ACQUISITIONS SUPPORTED BY $1.5 BILLION OF EQUITY ISSUANCE BALANCED GROWTH INITIATIVES
FOCUSED, EFFICIENT OPERATIONS
LEVERAGING TECHNOLOGY
15.2
MBOE/D (77% oil)
91.6
MMBOE
56,258
NET ACRES*
3
PERMIAN PRODUCTION
BOE/D
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
2016
2015
2014
9,610
3,508
5,649
2,062
15,227
5,573
MBOE
2,000
3,000
4,000
5,000
6,000
*The amounts are Pro Forma for the Delaware Basin acquisition announced in December 2016 that closed in February 2017
2016HIGHLIGHTS59% INCREASE IN PRODUCTION69% INCREASE IN PROVED RESERVES218% INCREASE IN SURFACE ACREAGE 4
A SMALL CALL OUT AREA FOR AN INTRO TO THE SHAREHOLDRE PAGE. TO OUR
S H A R E H O L D E R S
This past year was one that we are very proud of as an
organization. Callon delivered exceptional growth
in our
producing assets
in 2016, with a nearly 60%
increase
in daily production and nearly 70% increase in proved
reserves despite a relatively challenging commodity price
5
environment that entered its second year. Following a drop
in oil prices below $40 per barrel, we quickly pivoted our
business to focus on our highest returning assets with
a goal of living within our internal cash flows while still
maintaining operational momentum for the future.
We were successful in achieving this financial goal in
the second quarter while also delivering sustained,
sequential growth
in production. Moreover, the
strength of our capital efficient operational base,
combined with our solid financial position, allowed
us to stay on our front foot throughout the year
and ultimately enter into agreements that tripled
our acreage position in the Permian Basin on an
accretive basis.
O R G A N I C
A S S E T G R O W T H
6
Although expanding our acreage Permian position
was a top strategic objective in 2016, we never
lost sight of the foundation of our success –
safe and efficient development of our existing
assets. To that end, we replaced nearly 770% of
our production, of which over 310% was added
organically through the drill-bit. Overall, we
increased our proved reserves by 69% to 92 million
barrels of oil equivalent (“MMBOE”), demonstrating
a consistent track record of proved reserve growth
including over 65% and 120% during 2015 and 2014,
respectively. Importantly, our reserves are 78% oil,
the highest amongst our Permian peers, which will
provide strong cash flows as we turn our reserves
to production to fund our ongoing development,
reducing our reliance on other financing during
periods of increasing activity.
RESULTS OF OPERATIONS
LOE/BOE
$
10.85
7.71
6.88
-23%
2014
YEAR
-29%
2015
-11%
2016
Beyond growing our base of long-lived reserves, we
recognize that we create value by converting those
reserves into cash flow. To that end, we have grown
production sequentially every quarter since becoming
a pure-play Permian operator in 2013. We increased
production in 2016 by nearly 60% vs 2015 to 5.6
MMBOE, which equates to more than 15,000 barrels
of oil equivalent per day (“BOE/D”) compared to
just over 9,600 BOE/D in 2015. While much of our
development focused on the Lower Spraberry during
2016, we successfully placed our first Wolfcamp
A wells on production in both the Monarch and
WildHorse focus areas.
Including our recent
Delaware acquisition, we are now producing from
seven distinct flow units within the Basin including
the Middle Spraberry, two levels of the Lower
Spraberry, the Wolfcamp A, two levels of the
Wolfcamp B and the 3rd Bone Spring Shale.
R E S I L I E N T
O P E R AT I N G M A R G I N S
We realize that topline growth is only one part of the equation.
Equally important is being vigilant to control our costs in order to
maximize our cash margins to fund our growth initiatives while
minimizing our reliance on outside capital. Our high proportion
of oil volumes, combined with the realized benefits of strong
CASH OPERATING COSTS
7
$25.00
$22.37
service provider partnerships, generated operating cash
margins (after G&A) in excess of $27.43 per BOE produced in
$20.00
2016 relative to drill-bit finding costs of approximately $8.77
per BOE. As a result, we continue to be well-positioned to fund
our drilling initiatives from a strong foundation of internally
$15.00
generated cash flows. We expect the Permian Basin will
experience a steady increase in activity in the coming years
due to the quality of investments opportunities, creating
the potential for upward pressure on operating and capital
$10.00
costs. We recognize the need to proactively address
these pressures and have continued to add talented
professionals to our teams as well as in infrastructure
that will improve our operational efficiency and reduce
our reliance on third-party services.
$5.00
$7.17
$14.66
$4.35
$4.16
$11.82
$2.79
$2.81
$2.13
$10.85
$7.71
$6.88
Y/Y DECREASE
2014
2015
-34%
2016
-19%
LOE/Gathering
Production Taxes
Adjusted Cash
G&A
*Adjusted Cash G&A excludes the amortization of equity-settled, share-based incentive awards and corporate depreciation and
amortization. Inclusive of these amounts, total G&A per BOE for the periods reported was $12.18, $8.08 and $4.72 for 2014, 2015
and 2016, respectively.
...WE CONTINUE TO BE WELL-POSITIONED TO FUND OUR DRILLING INITIATIVES FROM A STRONG FOUNDATION OF INTERNALLY GENERATED CASH FLOWS.
P R O V E N
A C Q U I S I T I O N M O D E L
8
We have been focused on building our Permian
footprint over the past few years in an effort to
overlay a successful operational model on an
expanded opportunity set to deliver incremental
shareholder value. While a high level of interest
in the Permian has pushed activity further to the
fringes of the basin in 2016, our acquisition efforts
centered on core acreage supported by solid
subsurface data-points and proven well results.
Using this focused strategy, we were successful in
multiple leasehold acquisitions throughout 2016,
proving our ability as a disciplined consolidator of
Permian assets to be exploited by our team. Our
growth established two new core operating areas
on which to overlay our operational expertise such
that we now control nearly 60,000 net acres in both
the Midland and Delaware Basins. Importantly, we
funded 100% of these acquisitions with a solid base
on common equity proceeds, putting us in a strong
financial position to accelerate activity in the coming
quarters and pull forward strong cash returns from
delineated locations on both our legacy and newly
added acreage.
... WE WERE SUCCESSFUL IN MULTIPLE LEASEHOLD ACQUISITIONS THROUGHOUT 2016...
NET ACREAGE POSITION WITHIN THE PERMIAN BASIN
2016
39,570
2015
17,675
2016PF
TOTAL
56,258*
2016PF
16,688*
9
NET ACREAGE AT YEAR END
PRO FORMA FOR DELAWARE BASIN
ACQUISITION
*The amounts are Pro Forma for the Delaware Acquisition announced
in December 2016 that closed in February 2017
As we enter a period that will be largely characterized by drill-bit growth, we plan
to increase our horizontal development program to five rigs in both the Midland
OUTLOOK
and Delaware Basins by early 2018. Our 2017 drilling program will be active in all four of our core operating areas as we prioritize
top-tier cash returns in our portfolio, without the need to manage onerous drilling obligations. In the near-term, we are on the
cusp of unlocking the value of our newly acquired WildHorse position in the Midland Basin after investing in facilities for efficient
development and adding a second rig to this position in early 2017. We look forward to accelerating the value proposition
in a similar manner in our Spur area within the Delaware Basin with a rig starting by mid-year. Overall, we expect
our operations to produce another year of production growth approaching 60% in 2017 while maintaining
the financial strength required to navigate any potential headwinds in 2017 and beyond. With our
existing portfolio of delineated locations in core, unconventional shale plays, Callon is well-
positioned to deliver leading production and cash flow growth per share as well as
additional upside in emerging zones across the entire Permian Basin.
10
GRATITUDE
My father and uncle founded Callon in 1950, making 2016 our 66th year in the E&P business,
and I’m confident they would be extremely proud of what the team has accomplished on behalf of our
shareholders. I commend the team whose exceptional talent, dedication and commitment to safety and
operational excellence collectively strengthen the strong foundation of our long-term success. As we look to
convert our much larger asset base to cash flow, pulling forward the high returns unique to a core position in the
Permian basin, I have tremendous confidence in our team. After all, their efforts have affirmed Callon as a best-in-
class Permian operator, one that stands ready to capitalize on an exciting set of near-term growth opportunities.
Fred L. Callon, Chairman and Chief Executive Officer
March 17, 2017
WE CELEBRATED OUR 66TH YEAR OF OPERATIONS. UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For The Fiscal Year Ended December 31, 2016
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____________ to ____________
Commission File Number 001-14039
Callon Petroleum Company
(Exact Name of Registrant as Specified in Its Charter)
Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
200 North Canal Street
Natchez, Mississippi
(Address of Principal Executive Offices)
Title of Each Class
Common Stock, $.01 par value
10.0% Series A Cumulative Preferred Stock
601-442-1601
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
64-0844345
(IRS Employer
Identification No.)
39120
(Zip Code)
Name of Each Exchange on Which Registered
New York Stock Exchange
New York Stock Exchange
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 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 (check one):
Large accelerated filer
Non-accelerated filer
(Do not check if smaller reporting company)
Accelerated filer
Smaller reporting company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2016 was approximately $1,452,262,144.
The Registrant had 201,054,884 shares of common stock outstanding as of February 22, 2017.
Portions of the definitive Proxy Statement of Callon Petroleum Company (to be filed no later than 120 days after December 31, 2016) relating to the Annual Meeting of
Stockholders to be held on May 11, 2017, which are incorporated into Part III of this Form 10-K.
DOCUMENTS INCORPORATED BY REFERENCE
Special Note Regarding Forward-Looking Statements
Definitions
Part I
Items 1 and 2. Business and Properties
TABLE OF CONTENTS
Oil and Natural Gas Properties
Reserves and Production
Capital Budget
Exploration and Development Activity
Production Wells
Production Volumes, Average Sales Prices and Operating Costs
Leasehold Acreage
Other
Regulations
Commitments and Contingencies
Available Information
Risk Factors
Unresolved Staff Comments
Legal Proceedings
Mine Safety Disclosures
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Performance Graph
Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview and Outlook
Liquidity and Capital Resources
Results of Operations
Significant Accounting Policies and Critical Accounting Estimates
Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
Report of Independent Registered Public Accounting Firm
Directors and 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 Accountant Fees and Services
Exhibits
Item 1A.
Item 1B.
Item 3.
Item 4.
Part II
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Part III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Part IV
Item 15.
Signatures
3
4
5
5
7
7
9
10
10
11
12
12
14
21
21
22
34
34
34
35
36
37
38
39
40
44
51
54
56
57
59
60
61
62
63
87
87
88
89
90
90
90
90
90
91
93
2
Special Note Regarding Forward Looking Statements
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities
Act”), as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve
known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be
materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In
some cases, you can identify forward-looking statements in this Form 10-K by words such as “anticipate,” “project,” “intend,”
“estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions.
All statements, other than statements of historical facts, included in this report that address activities, events or developments that we
expect or anticipate will or may occur in the future are forward-looking statements, including such things as:
our oil and gas reserve quantities, and the discounted present value of these reserves;
the amount and nature of our capital expenditures;
our future drilling and development plans and our potential drilling locations;
the timing and amount of future production and operating costs;
commodity price risk management activities and the impact on our average realized prices;
business strategies and plans of management;
our ability to efficiently integrate recently completed acquisitions; and
prospect development and property acquisitions.
Some of the risks, which could affect our future results and could cause results to differ materially from those expressed in our forward-
looking statements, include:
general economic conditions including the availability of credit and access to existing lines of credit;
the volatility of oil and natural gas prices;
the uncertainty of estimates of oil and natural gas reserves;
impairments;
the impact of competition;
the availability and cost of seismic, drilling and other equipment;
operating hazards inherent in the exploration for and production of oil and natural gas;
difficulties encountered during the exploration for and production of oil and natural gas;
difficulties encountered in delivering oil and natural gas to commercial markets;
changes in customer demand and producers’ supply;
the uncertainty of our ability to attract capital and obtain financing on favorable terms;
compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business
including those related to climate change and greenhouse gases;
the impact of government regulation, including regulation of endangered species;
any increase in severance or similar taxes;
litigation relating to hydraulic fracturing, the climate and over-the-counter derivatives;
the financial impact of accounting regulations and critical accounting policies;
the comparative cost of alternative fuels;
credit risk relating to the risk of loss as a result of non-performance by our counterparties;
weather conditions; and
any other factors listed in the reports we have filed and may file with the SEC.
We caution you that the forward-looking statements contained in this Form 10-K are subject to all of the risks and uncertainties, many
of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. These risks
include, but are not limited to, the risks described in Item 1A of this Annual Report on Form 10-K for the year ended December 31,
2016 (the “2016 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto.
Should one or more of the risks or uncertainties described above or in our 2016 Annual Report on Form 10-K occur, or should underlying
assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.
We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-
looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.
All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.
3
All defined terms under Rule 4-10(a) of Regulation S-X shall have their prescribed meanings when used in this report. As used in this
document:
DEFINITIONS
ARO: asset retirement obligation.
ASU: accounting standards update.
Bbl or Bbls: barrel or barrels of oil or natural gas liquids.
BOE: barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas. The ratio of one
barrel of oil or NGL to six Mcf of natural gas is commonly used in the industry and represents the approximate energy
equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas.
The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas.
BBtu: billion Btu.
BOE/d: BOE per day.
BLM: Bureau of Land Management.
Btu: a British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water
one degree Fahrenheit.
DOI: Department of Interior.
EPA: Environmental Protection Agency.
FASB: Financial Accounting Standards Board.
GAAP: Generally Accepted Accounting Principles in the United States.
Henry Hub: A natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural
gas futures contracts.
GHG: greenhouse gases.
LIBOR: London Interbank Offered Rate.
LOE: lease operating expense.
MBbls: thousand barrels of oil.
MBOE: thousand BOE.
MMBOE: million BOE.
MBOE/d: MBOE per day.
Mcf: thousand cubic feet of natural gas.
MMBbls: million barrels of oil.
MMBOE: million BOE.
MMBtu: million Btu.
MMcf: million cubic feet of natural gas.
MMcf/d: MMcf per day.
NGL or NGLs: natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas
production streams.
NYMEX: New York Mercantile Exchange.
Oil: includes crude oil and condensate.
OPEC: Organization of Petroleum Exporting Countries
PDPs: proved developed producing reserves.
PDNPs: proved developed non-producing reserves.
PUDs: proved undeveloped reserves.
RSU: restricted stock units.
WTI: West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures
SEC: United States Securities and Exchange Commission.
contracts.
With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by
multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are
gross.
4
PART I.
Items 1 and 2 – Business and Properties
Overview
Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and natural gas
properties since 1950. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its
predecessors and subsidiaries unless the context requires otherwise.
We are an independent oil and natural gas company focused on the acquisition and development of unconventional oil and natural gas
reserves in the Permian Basin. The Permian Basin is located in West Texas and southeastern New Mexico and is comprised of three
primary sub-basins: the Midland Basin, the Delaware Basin, and the Central Basin Platform. We have historically been focused on the
Midland Basin and recently entered the Delaware Basin through an acquisition completed in February 2017. Our drilling activity during
2016 focused on the horizontal development of several prospective intervals in the Midland Basin, including multiple levels of the
Wolfcamp formation and the Lower Spraberry shale. As a result of our horizontal development efforts and contributions from
acquisitions, our net daily production for calendar year 2016 as compared to calendar year 2015 grew approximately 59% to 15,227
BOE/d (approximately 77% oil). We intend to grow our reserves and production through the development, exploitation and drilling of
our multi-year inventory of identified, potential drilling locations. We intend to add to this inventory through delineation drilling of
emerging zones on our existing acreage and acquisition of additional locations through leasehold purchases, leasing programs, joint
ventures and asset swaps.
For the year ended December 31, 2016, our net proved reserve volumes increased 69% as compared to the year ended December 31,
2015, to 91.6 MMBOE, comprised of 78% crude oil including 71.1 MMBbls with the remaining 22% natural gas of 122.6 Bcf.
Approximately 47% of our net proved year-end 2016 reserves were proved developed on a BOE basis.
Our Business Strategy
Our goal is to enhance stockholder value through the execution of the following strategies with an emphasis on safety:
Maintain fiscal discipline, financial liquidity and our capacity to capitalize on growth opportunities. During the past several quarters
of relative oil price weakness, we moderated our level of drilling activity and high-graded our investments to the highest returning
projects to preserve our financial flexibility while also maintaining operational momentum. In 2016, we reduced our operational capital
expenditures by 8% from 2015 to better align internal cash flows with spending, but were still able to deliver organic production and
reserve growth given the attractive drilling opportunities within our portfolio. Our ability to pivot our operations and maintain a solid
financial position allowed us to selectively pursue attractive acquisition opportunities during the course of 2016, ultimately putting us
in the position to grow our net surface acreage position by approximately 122%. Importantly, we funded these inorganic growth
initiatives with the issuance of common stock, allowing us to reduce leverage throughout the year and positioning us in a strong financial
position for future growth in our organic drilling plans.
Drive production and maximize resource recovery and reserve growth through horizontal development of our resource base. We
entered the Midland Basin in 2009 focused on a vertical development program that allowed us to amass a comprehensive database of
subsurface geologic and other technical data. Beginning in 2012, we leveraged that subsurface knowledge base to transition to horizontal
development of hydrocarbon bearing zones that were previously being exploited with vertical wells. Since that time, we have applied
the continued success of our horizontal development as evidenced in our significant year-over-year production growth, which increased
59% in 2016 to 5,573 MBOE (15,227 BOE/d) compared to 3,508 MBOE (9,610 BOE/d) in 2015. Additionally, we grew reserves 69%
in 2016 to 91.6 MMBOE from 54.3 MMBOE at year-end 2015, including reserve extensions and discoveries replacement in 2016 of
17.3 MMBOE. We intend to continue to grow our production volumes, both from our existing properties and from properties acquired
in recent acquisitions, as we execute a resource development program exclusively focused on horizontal development of currently
producing and prospective flow intervals in the Midland and Delaware Basins.
Expand our drilling portfolio through evaluation of existing acreage. We plan to further our efforts to expand our drilling inventory
through downspacing tests in existing flow units and selective delineation of new flow units. During 2016, we successfully tested a
second flow unit in the Lower Spraberry shale in the Midland Basin, bringing our producing flow unit count in the that sub-basin to six,
including the Upper and Lower sections of the Lower Spraberry, Middle Spraberry, Upper and Lower Wolfcamp A and the Upper and
Lower Wolfcamp B zones. In the Midland Basin, we believe incremental opportunities exist to develop existing flow units with tighter
well spacing, and add new flow units within both currently producing zones that have adequate thickness and new flow units in other
prospective zones including the Clearfork, Jo Mill, Wolfcamp C and Cline (also called the Wolfcamp D). As part of our entry into the
Delaware Basin, we will be initially focused on development of established zones such as the Wolfcamp A and Wolfcamp B, but plan
to test other prospective intervals within both the Bone Spring and Wolfcamp formations in the future.
Pursue selective acquisitions in the Permian Basin. During 2016, we significantly expanded our Permian Basin footprint after entering
into agreements to acquire over 41,000 net surface acres in both the Midland and Delaware sub-basins. On a combined basis, the
5
acquisitions added approximately 950 gross potential horizontal drilling locations across currently producing flow units in the Lower
Spraberry, Wolfcamp A and Wolfcamp B zones. These acquisitions have provided the foundation for two new core operating areas that
will be a significant component of our near-term drilling plans. In addition to selective evaluation of larger acquisition opportunities in
the Permian Basin, we will be focused on incremental “bolt-on” acquisitions, acreage trades and leasing programs in these two new
areas.
Our Strengths
Established resource base and acreage position in the core of the Permian Basin. Our production is exclusively from the Permian
Basin in West Texas, an area that has supported production since the 1940s. The Basin has well established infrastructure from historical
operations, and we believe the Basin also benefits from a relatively stable regulatory environment that has been established over time.
We have assembled a position of over 56,000 net surface acres in the Permian Basin that are prospective for multiple oil-bearing intervals
that have been produced by us and other industry participants. As of December 31, 2016, our estimated net proved reserves were
comprised of approximately 78% oil and 22% natural gas, which includes NGLs in the production stream.
Economic, multi-year drilling inventory in a lower commodity price environment. Our current acreage position in the Permian Basin
provides growth potential from a horizontal drilling inventory of approximately 1,550 gross locations based solely on seven currently
producing flow intervals, including the Upper and Lower sections of the Lower Spraberry, Middle Spraberry, Upper and Lower
Wolfcamp A, and the Upper and Lower Wolfcamp B. Our identified well locations across our Midland and Delaware Basin acreage
positions are based upon the results of horizontal wells drilled by us and other offsetting operators and by our analysis of core data and
historical vertical well performance. To the extent that long-term production data and microseismic data support the potential for capital
efficient resource recovery from reduced spacing between lateral wellbores and stacked development within thicker zones, the number
of drilling locations within currently producing zones may increase over time, complementing potential growth from additional
prospective zones without current production.
Experienced team operating in the Permian Basin. We have assembled a management team experienced in acquisitions, exploration,
development and production in the Permian Basin. Reflective of this experience, we were an early adopter of efficient multi-well pad
development, transitioning to this development model in 2012 which enabled us to realize improvements in our drilling and capital.
Since 2012, we have drilled more than 109 operated horizontal wells with lengths varying from approximately 5,000 feet to 10,400 feet,
continuing to employ new generation completion techniques in an effort to improve capital efficiency. In addition, we regularly evaluate
our operating results against those of other operators in the area in an effort to benchmark our performance against the top-performing
operators and evaluate and adopt best practices. We believe that the experience of our team is highlighted by our success in achieving
significantly lower well capital costs and reducing our operating cost structure to generate the operating margins and capital efficiency
to operate effectively in the current environment.
Significant amount of operational control. We operate nearly all of our Permian Basin acreage that is largely held by production,
providing us an advantage that enables us to modify our operational plans quickly and drill in areas that offer highest potential returns
on capital. For example, as commodity prices continued to decline throughout 2015 and into 2016, we shifted our development plan
exclusively to the Monarch operating area to focus on the Lower Spraberry which has demonstrated strong returns on capital over time.
Our operating team reacted quickly to pivot our operations and worked with our service partners to coordinate a smooth and efficient
transition to the new plan.
Operating culture focused on safety and the environment. We have a Health, Safety and Environmental (“HSE”) department dedicated
to our operations in the Permian Basin. This group is responsible for developing and implementing work processes to mitigate safety
and environmental risks associated with our work activities. With emphasis on leadership engagement, planning, training and
communication, and empowering both our employees and third party service providers with Stop Work Authority, we continue to
improve operational performance. We have enhanced Management of Change, routine facility maintenance and inspections, and
compliance action tracking methods with the implementation of a HSE management system software program. We also utilize the
program to distribute all incident reports, including near miss events and safety observations to track trends, learn from our mistakes
and implement corrective actions to drive improvement across our operations. This department also coordinates closely with our
operational team to ensure effective communication with appropriate regulatory bodies as well as landowners. We believe that our
proactive efforts in this area have made a positive impact on our operations and culture.
6
Oil and Natural Gas Properties
Permian Basin
As of December 31, 2016, we owned leaseholds in 39,570 net acres in the Permian Basin, all of which was located in the Midland Basin
on that date. Average net production from our Permian Basin properties increased 59% to 15,227 BOE/d in 2016 from 9,610 BOE/d in
2015. The following table sets forth certain information about our major operating areas in the Permian Basin as of December 31, 2016:
Producing Wells
Producing
Horizontal
Vertical
Horizontal Flow
Operating Area
Net Acres
Gross
Net
Gross
Net
Monarch
7,840
56
42.4
179
134.4
Ranger
8,428
52
40.7
13
9.2
Wildhorse
20,773
22
13.9
80
67.8
Other Permian
2,529
18
15.5
8
8.0
Total Permian Basin
39,570
148
112.5
280
219.4
Unit Zones
Middle Spraberry
Lower Spraberry
Wolfcamp A
Wolfcamp B
Lower Spraberry
Wolfcamp A
Upper Wolfcamp B
Lower Wolfcamp B
Lower Spraberry
Wolfcamp A
Wolfcamp B
Wolfcamp A
Upper Wolfcamp B
Lower Wolfcamp B
On February 13, 2017, the Company completed the acquisition of 27,552 gross (16,688 net) acres in the Delaware Basin, primarily
located in Ward and Pecos Counties, Texas, from American Resource Development, LLC, for total cash consideration of $633 million,
excluding customary purchase price adjustments (the “Ameredev Transaction”). The Company acquired an 82% average working
interest (75% average net revenue interest) in the properties acquired in the Ameredev Transaction. The Ameredev Transaction
represents our initial entry into the Delaware sub-basin. See Note 3 in the Footnotes to the Financial Statements for additional
information related to the Ameredev Transaction.
Other Property
We own additional immaterial properties in Louisiana.
Reserve Data
Proved Reserves
Estimates of volumes of proved reserves at year-end, net to our working interest, are presented in MBbls for oil and in MMcf for natural
gas, including NGLs, at a pressure base of 14.65 pounds per square inch. Total equivalent volumes are presented in BOE. For the BOE
computation, 6,000 cubic feet of gas are the equivalent of one barrel of oil. The ratio of six Mcf of gas to one BOE is typically used in
the oil and gas business and represents the approximate energy equivalent of a barrel of oil and a Mcf of natural gas. The price of a
barrel of oil is much higher than the price of six Mcf of natural gas, so the ratio of six Mcf to one BOE does not reflect the economic
equivalent of a barrel of oil to six Mcf of gas.
As of December 31, 2016, our estimated net proved reserves totaled 91.6 MMBOE and included 71.1 MMBbls of oil and 122.6 Bcf, of
natural gas with a pre-tax present value, discounted at 10%, of $809.8 million. Pre-tax present value is a non-GAAP financial measure,
which we reconcile to the GAAP measure of standardized measure of $809.8 million. Oil constituted approximately 78% of our total
estimated equivalent net proved reserves and approximately 76% of our total estimated equivalent proved developed reserves.
7
The following table sets forth certain information about our estimated net proved reserves prepared by our independent petroleum
reserve engineers. All of our proved reserves are located in the Permian Basin in the continental United States.
For the Year Ended December 31,
2015
2016
2014
Proved developed
Oil (MBbls)
Natural gas (MMcf)
MBOE
Proved undeveloped
Oil (MBbls)
Natural gas (MMcf)
MBOE
Total proved
Oil (MBbls)
Natural gas (MMcf)
MBOE
Financial Information (in thousands)
Estimated pre-tax future net cash flows (a)
Pre-tax discounted present value (a) (b)
Standardized measure of discounted future net cash flows (a) (b)
32,920
61,871
43,232
38,225
60,740
48,348
71,145
122,611
91,580
22,257
38,157
28,617
21,091
27,380
25,654
43,348
65,537
54,271
14,006
25,171
18,201
11,727
17,377
14,623
25,733
42,548
32,824
$
$
$
1,821,221 $
1,160,808 $
1,330,628
809,832 $
809,832 $
570,906 $
570,890 $
629,680
579,542
(a) Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at December 31, 2016
and 2015, in accordance with accounting standards for asset retirement obligations.
(b) The Company uses the financial measure “pre-tax discounted present value” which is a non-GAAP financial measure. The Company believes
that pre-tax discounted present value, while not a financial measure in accordance with GAAP, is an important financial measure used by
investors and independent oil and natural gas producers for evaluating the relative value of oil and natural gas properties and acquisitions
because the tax characteristics of comparable companies can differ materially. The total standardized measure calculated in accordance with
the guidance issued by the FASB for disclosures about oil and natural gas producing activities for our proved reserves as of December 31,
2016, was $809.8 million, net of discounted estimated future income taxes relating to such future net revenues. The projected per Mcf natural
gas price of $2.71 used in the 2016 reserve estimates has been adjusted to reflect the Btu content, transportation charges and other fees
specific to the individual properties. The projected per barrel oil price of $40.03 used in the 2016 reserve estimates has been adjusted to
reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude
quality.
See Note 13 of our Consolidated Financial Statements for the additional information regarding the Company’s reserves including its
estimates of proved reserves and the Company’s estimates of future net cash flows and discounted future net cash flows from proved
reserves.
The Company’s estimated net proved reserves increased 69% to 91.6 MBOE at December 31, 2016 from 54.3 MBOE at December 31,
2015. Additions during the year were due to (1) 17.3 MMBOE related to the Company’s horizontal development of a portion of its
properties and (2) 31.1 MMBOE related to acquired properties. These increases were partially offset by (1) 5.6 MMBOE related to the
Company’s production during 2016, (2) 2.2 MMBOE related to divestitures, and (3) 3.3 MMBOE of net revisions primarily due to
pricing.
Proved Undeveloped Reserves
Annually, the Company reviews its proved undeveloped reserves (“PUDs”) to ensure appropriate plans exist for development of this
reserve category. PUD reserves are recorded only if the Company has plans to convert these reserves into proved developed producing
reserves (“PDPs”) within five years of the date they are first recorded. Our development plans include the allocation of capital to projects
included within our 2017 capital budget and, in subsequent years, the allocation of capital within our long-range business plan to convert
PUDs to PDPs within this five year period. In general, our 2017 capital budget and our long-range capital plans are primarily governed
by our expectations of internally generated cash flow, senior secured revolving credit facility borrowing availability and corporate credit
metrics. Reserve calculations at any end-of-year period are representative of our development plans at that time. Changes in commodity
pricing, oilfield service costs and availability, and other economic factors may lead to changes in development plans.
The following table summarizes the Company’s recorded PUDs (in MBOE):
Permian Basin
48,348
25,654
14,623
8
For the Year Ended December 31,
2015
2014
2016
Our PUDs increased 88% to 48.3 MMBOE at December 31, 2016 from 25.7 MMBOE at December 31, 2015. Additions during the year
were due to (1) 17.5 MMBOE related to acquired properties, net of divestitures, and (2) 11.9 MMBOE related to the Company’s
horizontal development of a portion of its properties, net of revisions. These increases were offset by the reclassification of 6.8 MMBOE,
or 27%, included in the year-end 2015 PUDs, to PDPs as a result of our horizontal development of properties at a total cost of
approximately $43.4 million, net.
The Company plans to develop its PUDs as part of a multi-year drilling program. At December 31, 2016, we had no reserves that
remained undeveloped for five or more years, and all PUD drilling locations are currently scheduled to be drilled within five years of
their initial recording.
Controls Over Reserve Estimates
Compliance as it relates to reporting the Company’s reserves is the responsibility of our Chief Operating Officer, who has over 35 years
of industry experience, including 29 years as a manager, and is our principal engineer. In addition to his years of experience, our
principal engineer holds a degree in petroleum engineering and is experienced in asset evaluation and management.
Callon’s controls over reserve estimates included retaining DeGolyer and MacNaughton, a Texas registered engineering firm, as our
independent petroleum and geological firm. The Company provided to DeGolyer and MacNaughton information about our oil and gas
properties, including production profiles, prices and costs, and DeGolyer and MacNaughton prepared its own estimates of the reserves
attributable to the Company’s properties. All of the information regarding 2016, 2015 and 2014 reserves in this annual report is derived
from DeGolyer and MacNaughton’s report. DeGolyer and MacNaughton’s reserve report letter is included as an Exhibit to this annual
report. The principal engineer at DeGolyer and MacNaughton who certified the Company’s reserve estimates has over 32 years of
experience in the oil and gas industry and is a Texas Licensed Professional Engineer. Further professional qualifications include a degree
in petroleum engineering and membership in the International Society of Petroleum Engineers and the Society of Petroleum Evaluation
Engineers.
To further enhance the control environment over the reserve estimation process, our Strategic Planning and Reserve Committee, a
committee of the Board of Directors, assists management and the Board with its oversight of the integrity of the determination of the
Company’s oil and natural gas reserves and the work of our independent reserve engineer. The Committee’s charter also specifies that
the Committee shall perform, in consultation with the Company’s management and senior reserves and reservoir engineering personnel,
the following responsibilities:
Oversee the appointment, qualification, independence, compensation and retention of the independent petroleum and geological
firm (the “Firm”) engaged by the Company (including resolution of material disagreements between management and the Firm
regarding reserve determination) for the purpose of preparing or issuing an annual reserve report. The Committee shall review
any proposed changes in the appointment of the Firm, determine the reasons for such proposal, and whether there have been
any disputes between the Firm and management.
Review the Company’s significant reserves engineering principles and policies and any material changes thereto, and any
proposed changes in reserves engineering standards and principles which have, or may have, a material impact on the
Company’s reserves disclosure.
Review with management and the Firm the proved reserves of the Company, and, if appropriate, the probable reserves, possible
reserves and the total reserves of the Company, including: (i) reviewing significant changes from prior period reports; (ii)
reviewing key assumptions used or relied upon by the Firm; (iii) evaluating the quality of the reserve estimates prepared by
both the Firm and the Company relative to the Company’s peers in the industry; and (iv) reviewing any material reserves
adjustments and significant differences between the Company’s and Firm’s estimates.
If the Committee deems it necessary, it shall meet in executive session with management and the Firm to discuss the oil and
gas reserve determination process and related public disclosures, and any other matters of concern in respect of the evaluation
of the reserves.
During our last fiscal year, we filed no reports with other federal agencies which contain an estimate of total proved net oil and natural
gas reserves.
2017 Capital Budget
Our operational capital budget for 2017 has been established in the range of $325 to $350 million on an accrual, or GAAP, basis,
inclusive of a planned transition from a three-rig program that commenced in January 2017 to a four-rig program by July 2017 that
would include horizontal development activity at our recent Delaware Basin acquisition (see Note 3 in the Footnotes to the Financial
Statements for information on this acquisition).
As part of our 2017 operated horizontal drilling program, we expect to place 33 –36 net horizontal wells on production with lateral
lengths ranging from 5,000’ to 10,000’. We have also budgeted approximately $7.5 to $10 million for non-operated operational activity.
9
In addition to the operational capital expenditures budget, which includes well costs, facilities and infrastructure capital, and surface
land purchases, we budgeted an estimated $40 to $45 million for capitalized general and administrative expenses and capitalized interest
expenses, both on an accrual, or GAAP, basis.
Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop
our reserves of oil and natural gas. Despite a continued low price environment, we believe the long-term outlook for our business is
favorable due to our resource base, low cost structure, financial strength, risk management, including commodity hedging strategy, and
disciplined investment of capital. We monitor current and expected market conditions, including the commodity price environment, and
our liquidity needs and may adjust our capital investment plan accordingly.
Exploration and Development Activities
Our 2016 total capital expenditures, including acquisitions, on a cash basis were $866.4 million, of which $190 million was allocated to
operational capital expenditures, including drilling and completion and facilities and infrastructure expenditures.
For the year ended December 31, 2016, we drilled 29 gross (20.9 net) horizontal wells, completed 32 gross (23.7 net) horizontal wells
and had six gross (4.2 net) horizontal wells awaiting completion.
The following table sets forth the Company’s drilled wells, none of which were natural gas or nonproductive for the periods reflected:
2016
2015
2014 (a)
Gross
Net
Gross
Net
Gross
Net
Oil wells
Development (b)
Exploratory (c)
Total
9
20
29
4.9
16.0
20.9
14
22
36
11.4
15.7
27.1
19
13
32
15.5
11.7
27.2
(a) Does not include two gross (two net) nonproductive exploratory wells.
(b) A development well is a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known
to be productive.
(c) An exploratory well is a well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a
field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.
Productive Wells
As of December 31, 2016, we had 428 gross (331.9 net) working interest oil wells, three gross (0.1 net) royalty interest oil wells and no
natural gas wells. A well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas reserves on a BOE
basis. However, most of our wells produce both oil and natural gas.
Present Activities
Subsequent to December 31, 2016, and through February 22, 2017, the Company drilled four gross (3.4 net) horizontal wells and
completed five gross (3.4 net) horizontal wells and had five gross (4.1 net) horizontal wells awaiting completion.
10
Production Volumes, Average Sales Prices and Operating Costs
The following table sets forth certain information regarding the production volumes and average sales prices received for, and average
production costs associated with, the Company’s sale of oil and natural gas for the periods indicated (dollars in thousands, except per
unit data).
For the Year Ended December 31,
2015
2016
2014
Production
Oil (MBbl)
Natural gas (MMcf)
Total (MBOE)
Revenues
Oil sales
Natural gas sales
Total
Operating costs
Lease operating expense
Production taxes
Total
Average realized sales price
Oil (Bbl) (excluding impact of cash settled derivatives)
Oil (Bbl) (including impact of cash settled derivatives)
Natural gas (Mcf) (excluding impact of cash settled derivatives)
Natural gas (Mcf) (including impact of cash settled derivatives)
Total (BOE) (excluding impact of cash settled derivatives)
Total (BOE) (including impact of cash settled derivatives)
Operating costs per BOE
Lease operating expense
Production taxes
Total
Major Customers
4,280
7,758
5,573
2,789
4,312
3,508
1,692
2,220
2,062
177,652 $
23,199
200,851 $
125,166 $
12,346
137,512 $
139,374
12,488
151,862
38,353 $
11,870
50,223 $
27,036 $
9,793
36,829 $
22,372
8,973
31,345
41.51 $
45.67
2.99
3.00
36.04
39.25
6.88 $
2.13
9.01 $
44.88 $
56.82
2.86
3.26
39.20
49.18
7.71 $
2.79
10.50 $
82.37
84.84
5.63
5.59
73.65
75.63
10.85
4.35
15.20
$
$
$
$
$
$
$
Our production is sold generally on month-to-month contracts at prevailing prices. The following table identifies customers to whom
we sold a significant percentage of our total oil and natural gas production, on an equivalent basis, during each of the 12-month periods
indicated:
Enterprise Crude Oil, LLC
Shell Trading Company
Plains Marketing, L.P.
Permian Transport and Trading
Sunoco
Other
Total
For the Year Ended December 31,
2015
2016
2014
43%
18%
16%
—
—
23%
100%
42%
4%
19%
15%
9%
11%
100%
51%
—
22%
7%
10%
10%
100%
Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers
would not result in a material adverse effect on Callon’s ability to market future oil and natural gas production. We are not currently
committed to provide a fixed and determinable quantity of oil or gas in the near future under our contracts.
11
Leasehold Acreage
The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of December 31, 2016.
Permian Basin (a)
Other
Total
Developed
Undeveloped
Total
Gross
36,960
936
37,896
Net
29,765
200
29,965
Gross
Net
Gross
14,255
188
14,443
9,805
55
9,860
51,215
1,124
52,339
Net
39,570
255
39,825
(a) A portion of our Permian Basin acreage, which we have included in our development plans, requires continuous drilling to hold the acreage,
though the cost to renew this acreage, if necessary, is not considered material.
Undeveloped Acreage Expirations
The following table sets forth as of December 31, 2016 the number of our leased gross and net undeveloped acres in the Permian Basin
that will expire over the next three years unless production begins before lease expiration dates. Gross amounts may be more than net
amounts in a particular year due to timing of expirations.
Permian Basin
4,807
2,778
1,799
9,384
13,456
2017
2018
2019
Total
Net
Gross
Total
The expiring acreage set forth in the table above accounts for approximately 95% of our net undeveloped acreage (9,860 total net acres)
and there are no PUD reserves attributable to such acreage. We are continually engaged in a combination of drilling and development
and discussions with mineral lessors for lease extensions, renewals, new drilling and development units and new leases to address any
potential expiration of undeveloped acreage that occurs in the normal course of our business.
Title to Properties
The Company believes that the title to its oil and natural gas properties is good and defensible in accordance with standards generally
accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from
the use or value of such properties. The Company’s properties are potentially subject to one or more of the following:
royalties and other burdens and obligations, express or implied, under oil and natural gas leases;
overriding royalties and other burdens created by us or our predecessors in title;
a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements;
farm-out agreements, production sales contracts and other agreements that may affect the properties or their titles;
back-ins and reversionary interests existing under purchase agreements and leasehold assignments;
liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid
suppliers and contractors and contractual liens under operating agreements;
pooling, unitization and communitization agreements, declarations and orders; and
easements, restrictions, rights-of-way and other matters that commonly affect property.
To the extent that such burdens and obligations affect the Company’s rights to production revenues, these characteristics have been
taken into account in calculating Callon’s net revenue interests and in estimating the size and value of its reserves. The Company
believes that the burdens and obligations affecting our properties are typical within the industry for properties of the kind owned by
Callon.
Insurance
In accordance with industry practice, the Company maintains insurance against some, but not all, of the operating risks to which its
business is exposed. While not all inclusive, the Company’s insurance policies include coverage for general liability insuring onshore
operations (including sudden and accidental pollution), aviation liability, auto liability, worker’s compensation, and employer’s liability.
The Company carries control of well insurance for all of its drilling operations.
Currently, the Company has general liability insurance coverage up to $1 million per occurrence and $2 million per policy in the
aggregate, which includes sudden and accidental pollution liability coverage for the effects of pollution on third parties arising from its
operations. The Company’s insurance policies contain high policy limits, and in most cases, deductibles (generally ranging from $0 to
$250,000) that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. The
Company maintains up to $100 million in excess liability coverage, which is in addition to and triggered if the underlying liability limits
have been reached. In addition, the company purchases pollution legal liability coverage in the amount of $5 million, which is excess
and difference in conditions of the liability coverage.
12
The Company requires all of its third-party contractors to sign master service agreements in which they agree to indemnify the Company
for injuries and deaths of the service provider’s employees, as well as contractors and subcontractors hired by the service provider.
Similarly, the Company generally agrees to indemnify each third-party contractor against claims made by employees of the Company
and the Company’s other contractors. Additionally, each party generally is responsible for damage to its own property.
The third-party contractors that perform hydraulic fracturing operations for the Company sign master service agreements generally
containing the indemnification provisions noted above. The Company does not currently have any insurance policies in effect that are
intended to provide coverage for losses solely related to hydraulic fracturing operations. However, the Company believes its general
liability and excess liability insurance policies would cover foreseeable third party claims related to hydraulic fracturing operations and
associated legal expenses, in accordance with, and subject to, the terms of such policies.
The Company re-evaluates the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil
and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance
may become unavailable in the future or unavailable on terms that are economically acceptable. While based on the Company’s risk
analysis, it believes that it is properly insured, no assurance can be given that the Company will be able to maintain insurance in the
future at rates that it considers reasonable. In such circumstances, the Company may elect to self-insure or maintain only catastrophic
coverage for certain risks in the future.
Corporate Offices
The Company’s headquarters are located in Natchez, Mississippi, in a building owned by the Company. We also maintain leased
business offices in Houston and Midland, Texas. Because alternative locations to our leased spaces are readily available, the replacement
of any of our leased offices would not result in material expenditures.
Employees
Callon had 121 employees as of December 31, 2016. None of the Company’s employees are currently represented by a union, and the
Company believes that it has good relations with its employees.
13
Regulations
General. Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements
enacted by governmental authorities. Legislation and regulation affecting the entire oil and natural gas industry is continuously being
reviewed for amendment and/or expansion. Some of these requirements carry substantial penalties for failure to comply.
Exploration and Production. Our operations are subject to federal, state and local regulations that include requirements for permits to
drill and to conduct other operations and for provision of financial assurances (such as bonds and letters of credit) covering drilling and
well operations. Other activities subject to regulation are:
the location and spacing of wells;
the method of drilling and completing and operating wells;
the rate and method of production;
the surface use and restoration of properties upon which wells are drilled and other exploration activities;
notice to surface owners and other third parties;
the venting or flaring of natural gas;
the plugging and abandoning of wells;
the discharge of contaminants into water and the emission of contaminants into air;
the disposal of fluids used or other wastes obtained in connection with operations;
the marketing, transportation and reporting of production; and
the valuation and payment of royalties.
Operations conducted on federal or state oil and natural gas leases must comply with numerous regulatory restrictions, including various
nondiscrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to
certain on-site security regulations and other appropriate permits issued by DOI Bureaus or other appropriate federal or state agencies.
Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline transportation. The price and terms for access
to pipeline transportation remain subject to extensive federal and state regulation. If these regulations change, we could face higher
transmission costs for our production and, possibly, reduced access to transmission capacity.
Various proposals and proceedings that might affect the petroleum industry are pending before Congress, the Federal Energy Regulatory
Commission, or FERC, various state legislatures, and the courts. Historically, the industry has been heavily regulated and we can offer
you no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue nor can we
predict what effect such proposals or proceedings may have on our operations.
We do not currently anticipate that compliance with existing laws and regulations governing exploration and production will have a
significantly adverse effect upon our capital expenditures, earnings or competitive position.
Environmental Matters and Regulation. Our oil and natural gas exploration, development and production operations are subject to
stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental
protection. Numerous federal, state and local governmental agencies, such as the EPA issue regulations which often require difficult
and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations
for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types,
quantities and concentrations of various substances that can be released into the environment in connection with drilling and production
activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive
and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned
wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional
pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or
operated facilities. Violations of environmental laws could result in administrative, civil or criminal fines and injunctive relief. The strict
and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not
uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused
by the release of hazardous substances, hydrocarbons, air emissions or other waste products into the environment. Changes in
environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste
handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as
well as the oil and natural gas industry in general. Further, the EPA has identified environmental compliance by the energy extraction
sector as one of its enforcement initiatives for fiscal years 2017-2019, although the outlook for this initiative is unclear with the incoming
administration, and, as a general matter, the oil and natural gas exploration and production industry has been the subject of increasing
scrutiny and regulation by environmental authorities. Our management believes that we are in substantial compliance with applicable
environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental
requirements. Although such laws and regulations can increase the cost of planning, designing, installing and operating our facilities, it
is anticipated that, absent the occurrence of an extraordinary event, compliance with them will not have a material effect upon our
operations, capital expenditures, earnings or competitive position in the marketplace.
14
Waste Handling. The Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes and regulations
promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements
regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal
approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more
stringent requirements. Although most wastes associated with the exploration, development and production of oil and natural gas are
exempt from regulation as hazardous wastes under RCRA and its state analogs, it is possible that some wastes we generate presently or
in the future may be subject to regulation under RCRA and state analogs. Additionally, we cannot assure you that the EPA or state or
local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-
hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize
certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Additionally, following the filing of
a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against
the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the
environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28,
2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D
criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA
proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following
notice and comment rulemaking no later than July 15, 2021. Non-exempt waste is subject to more rigorous and costly disposal
requirements. Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and
operating expenses.
Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we
are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date
permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although
we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory
reclassification of wastes associated with oil and natural gas exploration and production could increase our costs to manage and dispose
of such wastes.
Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response,
Compensation and Liability Act (“CERCLA”), imposes joint and several liability for costs of investigation and remediation and for
natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the
release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so–called
potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone
who disposed or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some
instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs
the costs of such action. Many states have adopted comparable or more stringent state statutes.
Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have
generated and will generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of these
wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum.
We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor
our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of
our properties that are named as PRPs related to their ownership or operation of such properties. In the event contamination is discovered
at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs
of investigation and remediation and natural resources damages.
We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many
years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time,
hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under
other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of these properties
have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes,
or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to
CERCLA, RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing
or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property
contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to
prevent future or mitigate existing contamination.
Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe
Drinking Water Act, the Oil Pollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose
restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes,
into navigable waters of the United States (a term broadly defined to include, among other things, certain wetlands), as well as state
waters for analogous state programs. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms
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of a permit issued by the EPA or applicable state analog. The Clean Water Act and regulations implemented thereunder also prohibit
the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately
issued permit from the U.S. Army Corps of Engineers. The EPA has issued final rules on the federal jurisdictional reach over waters of
the United States that may constitute an expansion of federal jurisdiction over waters of the United States. The rule was stayed
nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015 and in January 2017, the United States Supreme Court accepted
review of the rule to determine whether jurisdiction rests with the federal district or appellate courts. Spill prevention, control and
countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the
contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The EPA has also adopted
regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under
general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing
storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities.
Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact
groundwater conditions.
The Oil Pollution Act is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention
of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and
certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain
significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of
facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release,
including, but not limited to, the costs of responding to a release of oil to surface waters.
Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as
injunctive obligations. We believe we are in material compliance with the requirements of each of these laws.
Air Emissions. The federal Clean Air Act, as amended, and comparable state and local laws and regulations, regulate emissions of
various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues
to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain
permits before work can begin, and modified and existing facilities may be required to obtain additional permits. As a result, we may
need to incur capital costs in order to remain in compliance. For example, on August 16, 2012, the EPA published final regulations
under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which
regulations are discussed in more detail below in “Regulation of Hydraulic Fracturing.” These laws and regulations may increase the
costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil
and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the federal Clean Air Act
and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations
and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the
potential to delay the development of oil and natural gas projects.
On June 3, 2016, the EPA expanded its regulatory coverage in the oil and gas industry with additional regulated equipment categories,
and the addition of new rules limiting methane emissions from new or modified sites and equipment. There has been discussion of the
EPA further expanding its regulatory coverage by developing and proposing rules for existing sites and equipment. Simultaneously with
the additional methane rules, EPA released a rule defining site aggregation for air permitting purposes. Should the EPA reconsider this
definition, some sites could require additional permitting under the Clean Air Act, an outcome that could result in costs and delays to
our operations.
Greenhouse Gas Regulation. More stringent laws and regulations relating to climate change and GHGs may be adopted in the future
and could cause us to incur material expenses in complying with them. In the absence of comprehensive federal legislation on GHG
emission control, the EPA attempted to require the permitting of GHG emissions. Although the Supreme Court struck down the
permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other
pollutants.
The EPA has established GHG reporting requirements for certain sources in the petroleum and natural gas industry, requiring those
sources to monitor, maintain records on, and annually report their GHG emissions. Although these requirements do not limit the amount
of GHGs that can be emitted, they do require us to incur costs to monitor, keep records of, and report GHG emissions associated with
our operations. The GHG reporting threshold was recently crossed due to drilling activity, acquisitions, and production growth. The
EPA recently began regulating methane emissions from oil and natural gas operations. Additional regulations for reducing methane
from new and modified oil and gas production sources and natural gas processing and transmission sources are discussed in more detail
above in “Air Emissions.”
In addition to possible federal regulation, a number of states, individually and regionally, are also considering or have implemented
GHG regulatory programs. These potential regional and state initiatives may result in so-called “Cap-and-Trade programs”, under
which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements,
that could result in our incurring material expenses to comply, such as by being required to purchase or to surrender allowances for
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GHGs resulting from our operations. These federal, regional and local regulatory initiatives also could adversely affect the marketability
of the oil and natural gas we produce. The impact of such future programs cannot be predicted, but we do not expect our operations to
be affected any differently than other similarly situated domestic competitors.
Regulation of Hydraulic Fracturing. Hydraulic fracturing is an important common practice that is used to stimulate production of
hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and
chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water
Act (“SDWA”), regulates the underground injection of substances through the Underground Injection Control (“UIC”), program.
Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically
regulated by state oil and gas commissions and not at the federal level, as the SDWA expressly excludes regulation of these fracturing
activities (except where diesel is a component of the fracturing fluid, as further discussed below). Legislation to amend the SDWA to
repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and
regulatory control of hydraulic fracturing have been proposed but have not passed.
The EPA, however, issued guidance on permitting hydraulic fracturing that uses fluids containing diesel fuel under the UIC program,
specifically as “Class II” UIC wells. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing
on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water
resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface
spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate
mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing
wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. This report could result in additional
regulatory scrutiny that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and business.
Further, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore
unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants.
The EPA has adopted regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas
production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards for
hydraulically fractured natural gas and oil wells to address emissions of sulfur dioxide, volatile organic compounds, or VOCs, and
methane, with a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas
production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs and methane emitted by requiring the use
of reduced emission completions or “green completions” on all hydraulically-fractured gas and oil wells newly constructed or
refractured. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage
tanks and other production equipment. These rules require a number of modifications to our operations, including the installation of new
equipment to control emissions from our wells. The BLM finalized regulations for hydraulic fracturing activities on federal lands.
Among other things, the BLM rules impose new requirements to validate the protection of groundwater, disclosure of chemicals used
in hydraulic fracturing and higher standards for the interim storage of recovered waste fluids from hydraulic fracturing. This rule is the
subject of legal challenges and in June 2016 a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority
to promulgate the rule, and that decision is currently remains on appeal by the federal government. In addition, the EPA has announced
that it is considering regulations under the Toxic Substance Control Act to require evaluation and disclosure of hydraulic fracturing.
Several states, including Texas, and some municipalities, have adopted, or are considering adopting, regulations that could restrict or
prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The
Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic
fracturing process, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations implementing
this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit after February 1, 2012. The
new law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational
Safety and Health Act (“OSHA”) for disclosure on a website and also file the list of chemicals with the Texas Railroad Commission
with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and
filed with the Texas Railroad Commission.
Additionally, some states, localities and local regulatory districts have adopted or have considered adopting regulations to limit, and in
some case impose a moratorium on hydraulic fracturing or other restrictions on drilling and completion operations, including
requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water.
Further, there has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts
on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A
number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new
laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to
perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic
fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely
affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could
become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased
monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays
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and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the
consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations.
At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing
hydraulic fracturing.
Surface Damage Statutes (“SDAs”). In addition, a number of states and some tribal nations have enacted SDAs. These laws are
designed to compensate for damage caused by oil and gas development operations. Most SDAs contain entry notification and negotiation
requirements to facilitate contact between operators and surface owners/users. Most also contain binding requirements for payments by
the operator to surface owners/users in connection with exploration and operating activities in addition to bonding requirements to
compensate for damages to the surface as a result of such activities. Costs and delays associated with SDAs could impair operational
effectiveness and increase development costs.
National Environmental Policy Act and Endangered Species Act. Oil and natural gas exploration and production activities on federal
lands may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies, including the Department
of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such
evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of
a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public
review and comment. To the extent that our current exploration and production activities, as well as proposed exploration and
development plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the
potential to delay or impose additional conditions upon the development of oil and natural gas projects.
The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is
listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ or its habitat. Similar
protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate
the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat
designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural
gas development. If the Company was to have a portion of its leases designated as critical or suitable habitat or a protected species were
located on a lease, it may adversely impact the value of the affected leases.
Mineral Leasing Act of 1920 (“Mineral Act”). The Mineral Act prohibits direct or indirect ownership of any interest in federal onshore
oil and natural gas leases by a foreign citizen or a foreign corporation except through stock ownership in a corporation formed under the
laws of the United States or of any U.S. state or territory, and only if the laws, customs, or regulations of their country of origin or
domicile do not deny similar or like privileges to citizens or corporations of the United States. If these restrictions are violated, the oil
and gas lease or leases can be canceled in a proceeding instituted by the United States Attorney General. Although the regulations of
the BLM (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such
designations in effect. For any federal leasehold interest that the Company owns, it is possible that holders of the Company’s equity
interests may be citizens of a foreign country, which is a non-reciprocal country under the Mineral Act. In such event, the federal onshore
oil and gas leases held by the Company could be subject to cancellation based on such determination.
Other Regulation of the Oil and Natural Gas Industry. The oil and natural gas industry is extensively regulated by numerous federal,
state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion,
frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute
to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry
substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing
business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser
extent than they affect other similar companies in the industry with similar types, quantities and locations of production.
The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and
natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage
and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the
rates and other terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas
transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.
Although oil and natural gas sales prices are currently unregulated, the federal government historically has been active in the area of oil
and natural gas sales regulation. We cannot predict whether new legislation to regulate oil and natural gas sales might be proposed, what
proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might
have on our operations. Sales of condensate, oil and natural gas liquids are not currently regulated and are made at market prices.
Exports of US Crude Oil Production. The federal government has recently ended its decades-old prohibition of exports of oil produced
in the lower 48 states of the US. It is too recent an event to determine the impact this regulatory change may have on our operations or
our sales of oil. The general perception in the industry is that ending the prohibition of exports of oil produced in the US will be positive
for producers of U.S. oil.
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Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local level. These types of
regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some
counties and municipalities, in which we operate also regulate one or more of the following:
the location of wells;
the method of drilling and casing wells;
the timing of construction or drilling activities, including seasonal wildlife closures;
the rates of production or “allowables”;
the surface use and restoration of properties upon which wells are drilled;
the plugging and abandoning of wells; and
notice to, and consultation with, surface owners and other third parties.
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas
properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling
of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest
in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells,
generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and
regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at
which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil,
natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct
regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the
amounts of oil and natural gas that may be produced from our wells, negatively affecting the economics of production from these wells
or to limit the number of locations we can drill.
Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of
production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other
state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S.
Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such
requirements.
Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural
gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of
natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978.
Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for
sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. 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.
Under the Energy Policy Act of 2005 (“EPAct”), Congress amended the Natural Gas Act (“NGA”) to give FERC 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. EPAct also amended the NGA to authorize FERC to “facilitate transparency in markets for the sale or transportation of
physical natural gas in interstate commerce,” pursuant to which authorization FERC now requires natural gas wholesale market
participants, including a number of entities that may not otherwise be subject to FERC’s traditional NGA jurisdiction, to report
information annually to FERC concerning their natural gas sales and purchases. FERC requires any wholesale market participant that
sells 2.2 million MMBtus or more annually in “reportable” natural gas sales to provide a report, known as FERC Form 552, to FERC.
Reportable natural gas sales include sales of natural gas that utilize a daily or monthly gas price index, contribute to index price
formation, or could contribute to index price formation, such as fixed price transactions for next-day or next-month delivery.
FERC also regulates interstate natural gas transportation rates, terms and conditions of natural gas transportation service, and the terms
under which we as a shipper may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce,
as well as the revenues we receive for sales of our natural gas and for the release of our excess, if any, natural gas pipeline capacity.
Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the
business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory
transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate
pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and
sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas
industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently
pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory
changes might have on our natural gas related activities.
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Under FERC’s current regulatory regime, interstate transportation services must be provided on an open-access, non-discriminatory
basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. The FERC-regulated
tariffs, under which interstate pipelines provide such open-access transportation service, contain strict limits on the means by which a
shipper releases its pipeline capacity to another potential shipper, which provisions include FERC’s “shipper-must-have-title” rule.
Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release rules or shipper-must-have-title rule could subject a shipper
to substantial penalties from FERC.
Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transportation services, is
regulated by the states onshore and in state waters. Depending on changes in the function performed by particular pipeline facilities,
FERC has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities and FERC
has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could
result in an increase to our costs of transporting gas to point-of-sale locations.
The pipelines used to gather and transport natural gas being produced by the Company are also subject to regulation by the U.S.
Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), the Pipeline Safety
Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act
of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to
determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In
August 2011, the PHMSA issued an Advance Notice of Proposed Rulemaking regarding pipeline safety, including questions regarding
the modification of regulations applicable to gathering lines in rural areas.
Oil and NGLs Sales and Transportation. Sales of oil, condensate and natural gas liquids are not currently regulated and are made at
negotiated prices. Nevertheless, Congress could reenact price controls in the future.
The Company’s sales of oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates,
terms, and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by the FERC
under the Interstate Commerce Act. The FERC has implemented a simplified and generally applicable ratemaking methodology for
interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of
an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. Intrastate oil pipeline transportation rates
are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory
oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates
are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations
in any materially different way than such regulation will affect the operations of our competitors.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access
standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil
pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly,
we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.
Any transportation of the Company’s crude oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane, and
natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”)
under the Hazardous Materials Regulations at 49 CFR Parts 171-180 (“HMR”), including Emergency Orders by the FRA and new
regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation
of flammable liquids.
In October 2015, the PHMSA issued proposed new safety regulations for hazardous liquid pipelines, including a requirement that all
hazardous liquid pipelines have a system for detecting leaks and establish a timeline for inspections of affected pipelines following
extreme weather events or natural disasters.
State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing
severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a
7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of
wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum
daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not
regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the
future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit
the number of wells or locations we can drill.
The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws
relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a
material adverse effect on us.
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Commitments and Contingencies
The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution
control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance
with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise
relating to the protection of the environment will not have a material effect upon the capital expenditures, earnings or the competitive
position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation
or legislation, enforcement policies included, and claims for damages to property, employees, other persons, and the environment
resulting from the Company’s operations could have on its activities. See Note 14 for additional information.
Available Information
We make available free of charge on our website (www.callon.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-
Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and
amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the SEC. You may
read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE., Washington, DC 20549. You
may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains
an website (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers, like Callon,
that file electronically with the SEC.
We also make available within the “About Callon” section of our website our Code of Business Conduct and Ethics, Corporate
Governance Guidelines, and Audit, Compensation, Strategic Planning and Reserve, and Nominating and Governance Committee
Charters, which have been approved by our Board of Directors. We will make timely disclosure by a Current Report on Form 8-K and
on our website of any change to, or waiver from, the Code of Business Conduct and Ethics for our principal executive and senior
financial officers. A copy of our Code of Business Conduct and Ethics is also available, free of charge by writing us at: Chief Financial
Officer, Callon Petroleum Company, P.O. Box 1287, Natchez, MS 39121.
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Item 1A. Risk Factors
Risk Factors
Depressed oil and natural gas prices may adversely affect our results of operations and financial condition. Our success is highly
dependent on prices for oil and natural gas, which are extremely volatile. Approximately 77% of our anticipated 2017 production, on a
BOE basis, is oil. Starting in the second half of 2014, the NYMEX price for a barrel of oil fell sharply, from a price of $105.37 on June
30, 2014 to $26.21 on February 11, 2016. In addition, NYMEX prices for natural gas have been low compared with historical prices.
Extended periods of low prices for oil or natural gas will have a material adverse effect on us. The prices of oil and natural gas depend
on factors we cannot control such as weather, economic conditions, levels of production, actions by OPEC and other countries and
government actions. Prices of oil and natural gas will affect the following aspects of our business:
our revenues, cash flows and earnings;
the amount of oil and natural gas that we are economically able to produce;
our ability to attract capital to finance our operations and the cost of the capital;
the amount we are allowed to borrow under our senior secured revolving credit facility;
the profit or loss we incur in exploring for and developing our reserves; and
the value of our oil and natural gas properties.
Any substantial and extended decline in the price of oil or natural gas could have an adverse effect on our borrowing capacity, our ability
to obtain additional capital, and our revenues, profitability and cash flows.
If oil and natural gas prices remain depressed for extended periods of time, we may be required to take additional write-downs
of the carrying value of our oil and natural gas properties. We may be required to write-down the carrying value of our oil and
natural gas properties when oil and natural gas prices are low. Under the full cost method, which we use to account for our oil and
natural gas properties, the net capitalized costs of our oil and natural gas properties may not exceed the present value, discounted at
10%, of future net cash flows from estimated net proved reserves, using the preceding 12-months’ average oil and natural gas prices
based on closing prices on the first day of each month, plus the lower of cost or fair market value of our unproved properties. If net
capitalized costs of our oil and natural gas properties exceed this limit, we must charge the amount of the excess to earnings. This type
of charge will not affect our cash flows, but will reduce the book value of our stockholders’ equity. Because the oil price we are required
to use to estimate our future net cash flows is the average price over the 12 months prior to the date of determination of future net cash
flows, the full effect of falling prices may not be reflected in our estimated net cash flows for several quarters. We review the carrying
value of our properties quarterly and once incurred, a write-down of oil and natural gas properties is not reversible at a later date, even
if prices increase. See Notes 2 and 13 to our Consolidated Financial Statements.
For the period ended December 31, 2016, we recorded a $95.8 million write-down of oil and natural gas properties as a result of the
ceiling test limitation driven primarily by the significant decrease in oil prices beginning in the fourth quarter of 2014. The ceiling test
calculation as of December 31, 2016 was calculated using the realized prices used in determining the estimated future net cash flows
from proved reserves of $42.75 per barrel of oil and $2.48 per Mcf of natural gas. Oil prices have continued to fluctuate since December
31, 2016 and we may experience further ceiling test write-downs in the future. Any future ceiling test cushion, and the risk we may incur
further write-downs or impairments, will be subject to fluctuation as a result of acquisition or divestiture activity. In addition, declining
commodity prices or other adverse market conditions, such as declines in the market price of our common stock, could result in goodwill
impairments or reductions in proved reserve estimates that would adversely affect our results of operation or financial condition.
Our actual recovery of reserves may substantially differ from our proved reserve estimates and our proved reserve estimates
may change over time. This Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net cash
flows from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to
oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating
oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available
geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. In addition, drilling,
testing and production data acquired since the date of an estimate may justify revising an estimate.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of
recoverable oil and natural gas reserves most likely will vary from the estimates. Any significant variance could materially affect the
estimated quantities and present value of reserves shown in this report. Additionally, reserves and future cash flows may be subject to
material downward or upward revisions, based on production history, development drilling and exploration activities and prices of oil
and natural gas. We incorporate many factors and assumptions into our estimates including:
expected reservoir characteristics based on geological, geophysical and engineering assessments;
future production rates;
future oil and natural gas prices and quality and locational differences; and
future development and operating costs.
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You should not assume that any present value of future net cash flows from our estimated net proved reserves contained in this Form
10-K represents the market value of our oil and natural gas reserves. We base the estimated discounted future net cash flows from our
proved reserves at December 31, 2016 on average 12-month prices and costs as of the date of the estimate. Actual future prices and
costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of
actual development expenditures, the rate and timing of production, and changes in governmental regulations or taxes. At December 31,
2016, approximately 38% of the discounted present value of our estimated net proved reserves consisted of PUDs. PUDs represented
53% of total proved reserves by volume. Recovery of PUDs generally requires significant capital expenditures and successful drilling
operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these PUDs and
the actual costs, development schedule, and results associated with these properties may not be as estimated. In addition, the 10%
discount factor that we use to calculate the net present value of future net revenues and cash flows may not necessarily be the most
appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil
and gas industry in general.
Information about reserves constitutes forward-looking information. See “Forward-Looking Statements” for information regarding
forward-looking information.
Unless we replace our oil and gas reserves, our reserves and production will decline. Our future oil and gas production depends on
our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our production,
revenues, reserve quantities and cash flows will decline. In general, production from oil and gas properties declines as reserves are
depleted, with the rate of decline depending on reservoir characteristics. Our ability to make the necessary capital investment to maintain
or expand our asset base of oil and gas reserves would be limited to the extent cash flow from operations is reduced and external sources
of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves.
Exploring for, developing, or acquiring reserves is capital intensive and uncertain. We may not be able to economically find,
develop, or acquire additional reserves, or may not be able to make the necessary capital investments to develop our reserves, if our cash
flows from operations decline or external sources of capital become limited or unavailable. As part of our exploration and development
operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture
stimulation techniques. The utilization of these techniques are capital intensive. If we do not replace the reserves we produce, our
reserves revenues and cash flow will decrease over time, which will have an adverse effect on our business.
Our business requires significant capital expenditures and we may not be able to obtain needed capital or financing on
satisfactory terms or at all. Our exploration and development activities are capital intensive. We make and expect to continue to make
substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas
reserves. Historically, we have funded our capital expenditures through a combination of cash flows from operations, borrowings from
financial institutions, the sale of public debt and equity securities and asset dispositions. In 2016, our total operational capital
expenditures, including expenditures for drilling, completion and facilities, were approximately $190 million on a cash basis ($142.7
million on an accrual, or GAAP, basis). Our 2017 budget for operational capital expenditures is currently estimated to be approximately
$325 to $350 million (on an accrual, or GAAP, basis). The actual amount and timing of our future capital expenditures may differ
materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs
and other services and equipment, and regulatory, technological and competitive developments.
If the borrowing base under our senior secured revolving credit facility or our revenues decrease as a result of lower oil or natural gas
prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to
sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms
favorable to us, or at all. If cash generated by operations or cash available under our senior secured revolving credit facility is not
sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations
relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our
estimated net proved reserves, and could adversely affect our business, financial condition and results of operations.
Our senior secured revolving credit facility and the indenture governing our 6.125% senior unsecured notes due 2024 (“6.125%
Senior Notes”) contain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue
business opportunities. Our senior secured revolving credit facility and the indenture governing our 6.125% senior unsecured notes
due 2024 contain restrictive covenants that limit our ability to, among other things:
incur additional indebtedness;
make loans to others;
make investments;
merge or consolidate with another entity;
pay dividends or make certain other payments;
hedge future production or interest rates;
create liens that secure indebtedness;
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sell assets;
engage in transactions with affiliates; and
engage in certain other transactions without the prior consent of the lenders.
As a result of these covenants, we are limited in the manner in which we conduct our business and we may be unable to react to changes
in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital
expenditures or withstand a continuing or future downturn in our business.
In addition, our senior secured revolving credit facility requires us to maintain certain financial ratios or to reduce our indebtedness if
we are unable to comply with such ratios. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds
necessary to meet required payments of principal, premium, if any, and interest, or special interest, if any, on our indebtedness, or if we
otherwise fail to comply with the various covenants, including financial and operating covenants, in the agreements governing our
indebtedness (including covenants in our senior secured revolving credit facility and the indenture governing the 6.125 % Senior Notes),
we could be in default under the terms of the agreements governing such indebtedness. In the event of such 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 senior secured revolving credit facility could elect to terminate their commitments thereunder, cease
making further loans and institute foreclosure proceedings against our assets; and
we could be forced into bankruptcy or liquidation.
If our operating performance declines, we may in the future need to obtain waivers under our senior secured revolving credit facility to
avoid being in default. If we breach our covenants under our senior secured revolving credit facility and seek a waiver, we may not be
able to obtain a waiver from the required lenders. If this occurs, we would be in default under our senior secured revolving credit facility,
the lenders could exercise their rights, as described above, and we could be forced into bankruptcy or liquidation.
Our borrowings under our senior secured revolving credit facility expose us to interest rate risk. Our earnings are exposed to
interest rate risk associated with borrowings under our senior secured revolving credit facility, which bear interest at a rate elected by us
that is based on the prime, LIBOR or federal funds rate plus margins ranging from 2.00% to 3.00% depending on the interest rate used
and the amount of the loan outstanding in relation to the borrowing base.
The borrowing base under our senior secured revolving credit facility may be reduced below the amount of borrowings
outstanding under such facilities. Under the terms of our senior secured revolving credit facility, our borrowing base is subject to
redeterminations at least semi-annually based in part on prevailing oil and gas prices. A negative adjustment could occur if the estimates
of future prices used by the banks in calculating the borrowing base are significantly lower than those used in the last redetermination.
The next redetermination of our borrowing base is scheduled to occur in March 2017. In addition, the portion of our borrowing base
made available to us is subject to the terms and covenants of our senior secured revolving credit facility including, without limitation,
compliance with the financial performance covenants of such facility. In the event the amount outstanding under our senior secured
revolving credit facility exceeds the redetermined borrowing base, we are required to either (i) grant liens on additional oil and gas
properties (not previously evaluated in determining such borrowing base) with a value equal to or greater than such excess, (ii) repay
such excess borrowings over five monthly installments, or (iii) elect a combination of options in clauses (i) and (ii). We may not have
sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of
our borrowings or arrange new financing, an event of default would occur under our senior secured revolving credit facility.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy
our obligations under applicable debt instruments, which may not be successful. Our ability to make scheduled payments on or to
refinance our indebtedness obligations, including our senior secured revolving credit facility and 6.125% senior unsecured notes due
2024, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive
conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows
from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments
and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or
refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of
indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict
business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition,
any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction
of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital
resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt
service and other obligations. Our senior secured revolving credit facility currently restricts our ability to dispose of assets and our use
of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition
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may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not
permit us to meet scheduled debt service obligations.
The borrowing base under our senior secured revolving credit facility is currently $500 million, with elected commitments of $385
million. Our next scheduled borrowing base redetermination is expected to occur in March 2017. In the future, we may not be able to
access adequate funding under our senior secured revolving credit facility as a result of a decrease in borrowing base due to the issuance
of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending
counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting
lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a
case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to
implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material
adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.
Our leverage and debt service obligations may adversely affect our financial condition, results of operations, business prospects.
As of February 22, 2017, we had $400 million outstanding of 6.125% senior unsecured notes due 2024 and no balance outstanding
under our senior secured revolving credit facility, which had an additional $385 million available for borrowings based on the existing
level of commitments. Our amount of indebtedness could affect our operations in several ways, including the following:
require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the
cash available to finance our operations and other business activities;
limit management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our
business and the industry in which we operate;
increase our vulnerability to downturns and adverse developments in our business and the economy;
limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working
capital, capital expenditures or acquisitions or to refinance existing indebtedness;
place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in
business combinations;
make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a
portion of our then-outstanding bank borrowings;
make us vulnerable to increases in interest rates as our indebtedness under our senior secured revolving credit facility may vary
with prevailing interest rates;
place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size
or less restrictive terms governing their indebtedness; and
make it more difficult for us to satisfy our obligations under the Senior Notes or other debt and increase the risk that we may
default on our debt obligations.
We cannot assure you that we will be able to maintain or improve our leverage position. An element of our business strategy
involves maintaining a disciplined approach to financial management. However, we are also seeking to acquire, exploit and develop
additional reserves that may require the incurrence of additional indebtedness. Although we will seek to maintain or improve our leverage
position, our ability to maintain or reduce our level of indebtedness depends on a variety of factors, including future performance and
our future debt financing needs. General economic conditions, oil, NGL and natural gas prices and financial, business and other factors
will also affect our ability to maintain or improve our leverage position. Many of these factors are beyond our control.
The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water,
personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely
basis and within our budget. From time to time, our industry experiences a shortage of drilling rigs, equipment, supplies, water or
qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In
addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. Increasing
levels of exploration and production may increase the demand for oilfield services and equipment, and the costs of these services and
equipment may increase, while the quality of these services and equipment may suffer. The unavailability or high cost of drilling rigs,
pressure pumping equipment, supplies, water or qualified personnel can materially and adversely affect our operations and profitability.
Our operations substantially depend on the availability of water. Restrictions on our ability to obtain, recycle and dispose of
water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner. Water is an
essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local
land owners and other sources for use in our operations. If drought conditions were to occur, our ability to obtain water could be impacted
and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. If we are unable to obtain
water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an
adverse effect on our financial condition, results of operations and cash flows.
Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with
operating in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of
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producing horizons within this area. All of our producing properties are geographically concentrated in the Permian Basin of West
Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors,
delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity
constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or
transportation of oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more
pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions
to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties,
a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our
results of operations than they might have on other companies that have a more diversified portfolio of properties. Such dela ys or
interruptions could have a material adverse effect on our financial condition and results of operations.
Our exploration projects increase the risks inherent in our oil and natural gas activities. We may seek to replace reserves through
exploration, where the risks are greater than in acquisitions and development drilling. Our exploration drilling operations may be
curtailed, delayed or canceled as a result of a variety of factors, including:
the results of our exploration drilling activities;
receipt of additional seismic data or other geophysical data or the reprocessing of existing data;
material changes in oil or natural gas prices;
the costs and availability of drilling rigs;
the success or failure of wells drilled in similar formations or which would use the same production facilities;
availability and cost of capital;
changes in the estimates of the costs to drill or complete wells; and
changes to governmental regulations.
Delays in exploration, cost overruns or unsuccessful drilling results could have a material adverse effect on our business and future
growth.
Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted
returns. Exploration, development, drilling and production activities are subject to many risks, including the risk that commercially
productive deposits will not be discovered. We may invest in property, including undeveloped leasehold acreage, which we believe will
result in projects that will add value over time. However, we cannot guarantee that any leasehold acreage acquired will be profitably
developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such leasehold acreage
or wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive
but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are profitable
may not achieve our targeted rate of return.
In addition, we may not be successful in controlling our drilling and production costs to improve our overall return. We may be forced
to limit, delay or cancel drilling operations as a result of a variety of factors, including:
unexpected drilling conditions;
pressure or irregularities in formations;
lack of proximity to and shortage of capacity of transportation facilities;
equipment failures or accidents and shortages or delays in the availability of drilling rigs and the delivery of equipment; and
compliance with governmental requirements.
Failure to conduct our oil and gas operations in a profitable manner may result in write-downs of our proved reserves quantities,
impairment of our oil and gas properties, and a write-down in the carrying value of our unproved properties, and over time may adversely
affect our growth, revenues and cash flows.
Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could
prevent them from being drilled or delay their drilling. Our management team has identified drilling locations as an estimation of
our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth
strategy. Our ability to drill and develop these identified drilling 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, marketing and transportation constraints, regulatory approvals and other factors. Because of
these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce oil or
natural gas from these drilling locations. In addition, unless production is established within the spacing units covering the undeveloped
acres on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual drilling activities
may materially differ from those presently identified.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures
than we currently anticipate. Approximately 53% of our total estimated proved reserves as of December 31, 2016, were proved
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undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant
capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum
engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated
costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development
will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in
commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects
becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves
as unproved reserves.
We may be unable to integrate successfully the operations of recent and future acquisitions with our operations, and we may not
realize all the anticipated benefits of these acquisitions. Our business has and may in the future include producing property
acquisitions that include undeveloped acreage. We can offer no assurance that we will achieve the desired profitability from our recent
acquisitions or from any acquisitions we may complete in the future. In addition, failure to assimilate recent and future acquisitions
successfully could adversely affect our financial condition and results of operations. Our acquisitions may involve numerous risks,
including:
operating a larger combined organization and adding operations;
difficulties in the assimilation of the assets and operations of the acquired business, especially if the assets acquired are in a
new geographic area;
risk that oil and natural gas reserves acquired may not be of the anticipated magnitude or may not be developed as anticipated;
loss of significant key employees from the acquired business;
inability to obtain satisfactory title to the assets we acquire;
a decrease in our liquidity if we use a portion of our available cash to finance acquisitions;
a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
diversion of management’s attention from other business concerns;
failure to realize expected profitability or growth;
failure to realize expected synergies and cost savings;
coordinating geographically disparate organizations, systems and facilities; and
coordinating or consolidating corporate and administrative functions.
Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and
we may experience unanticipated delays in realizing the benefits of an acquisition. If we consummate any future acquisition, our
capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic,
financial and other relevant information that we will consider in evaluating future acquisitions. The inability to effectively manage the
integration of acquisitions could reduce our focus on subsequent acquisition and current operations, which in turn, could negatively
impact our results of operations.
We may fail to fully identify problems with any properties we acquire, and as such, assets we acquire may prove to be worth
less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities. We are actively seeking to
acquire additional acreage in Texas or other regions in the future. Successful acquisitions require an assessment of a number of factors,
including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, operating and capital costs and
potential environmental and other liabilities. Although we conduct a review of properties we acquire which we believe is consistent with
industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with
such properties or that we will be able to mitigate any problems we do identify. Such assessments are inexact and their accuracy is
inherently uncertain. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their
deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural,
subsurface and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for
preclosing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited
remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas
properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms.
Unexpected subsurface conditions and other unforeseen operating hazards may adversely impact our ability to conduct business.
There are many operating hazards in exploring for and producing oil and natural gas, including:
our drilling operations may encounter unexpected formations or pressures, which could cause damage to equipment or personal
injury;
we may experience equipment failures which curtail or stop production;
we could experience blowouts or other damages to the productive formations that may require a well to be re-drilled or other
corrective action to be taken; and
storms and other extreme weather conditions could cause damages to our production facilities or wells.
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Because of these or other events, we could experience environmental hazards, including release of oil and natural gas from spills, natural
gas-leaks, accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or fracturing fluids, including
chemical additives, underground migration, and ruptures.
If we experience any of these problems, it could affect well bores, gathering systems and processing facilities, which could adversely
affect our ability to conduct operations. We could also incur substantial losses in excess of our insurance coverage as a result of:
injury or loss of life;
severe damage to and destruction of property, natural resources and equipment;
pollution and other environmental damage;
clean-up responsibilities;
regulatory investigation and penalties;
suspension of our operations; and
repairs to resume operations.
We cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable to cover our possible losses
from operating hazards. The occurrence of a significant event not fully insured or indemnified against could materially and adversely
affect our financial condition and results of operations.
Factors beyond our control affect our ability to market production and our financial results. The ability to market oil and natural
gas from our wells depends upon numerous factors beyond our control. These factors could negatively affect our ability to market all of
the oil or natural gas we produce. In addition, we may be unable to obtain favorable prices for the oil and natural gas we produce. These
factors include:
the extent of domestic production and imports of oil and natural gas;
recent changes in federal regulations allowing the export of U.S. crude oil after decades of prohibition;
federal regulations authorizing exports of liquefied natural gas (“LNG”), the development of new LNG export facilities under
construction in the U.S. Gulf Coast region, and the first LNG exports from such facilities;
the construction of new pipelines capable of exporting U.S. natural gas to Mexico;
the proximity of hydrocarbon production to pipelines;
the availability of pipeline and/or refining capacity;
the demand for oil and natural gas by utilities and other end users;
the availability of alternative fuel sources;
the effects of inclement weather;
state and federal regulation of oil and natural gas marketing; and
federal regulation of natural gas sold or transported in interstate commerce.
In particular, in areas with increasing non-conventional shale drilling activity, pipeline, rail or other transportation capacity may be
limited and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built.
The marketability of a portion of our production is dependent upon oil and condensate trucking facilities owned and operated
by third parties, and the unavailability of these facilities would have a material adverse effect on our revenue. Our ability to
market our production depends in part on the availability and capacity of oil and condensate trucking operations owned and operated
by third parties. Our failure to obtain these services on acceptable terms could materially harm our business. We may be required to
shut in wells for lack of a market or because of inadequate or unavailable trucking capacity. If that were to occur, we would be unable
to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we
were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to
maintain our leases.
The disruption of third party trucking facilities due to maintenance, weather or other factors could negatively impact our ability to market
and deliver our oil and condensate. The third parties control when, or if, such trucking facilities are restored and what prices will be
charged. In the past, we have experienced disruptions in our ability to market oil and condensate from bad weather. We may experience
similar interruptions as we continue to explore and develop our Permian Basin properties in the future. If we were required to shut in
our production for long periods of time due to lack of trucking capacity, it would have a material adverse effect on our business, financial
condition, results of operations and cash flows.
Part of our strategy involves drilling in new or emerging shale plays using horizontal drilling and completion techniques. The
results of our planned drilling program in these formations may be subject to more uncertainties than horizontal drilling
programs in more established areas and formations, and may not meet our expectations for reserves or production. The results
of our horizontal drilling efforts in emerging areas of the Permian Basin, including Howard and Ward Counties, are generally more
uncertain than drilling results in areas that are less developed and have more established production from horizontal formations such as
the Wolfcamp, Spraberry and Bone Spring horizons. Because emerging areas and associated target formations have limited or no
28
production history, we are less able to rely on past drilling results in those areas as a basis to predict our future drilling results. In
addition, horizontal wells drilled in shale formations, as distinguished from vertical wells, utilize multilateral wells and stacked laterals,
all of which are subject to well spacing, density and proration requirements of the Texas Railroad Commission, which requirements
could adversely impact our ability to maximize the efficiency of our horizontal wells related to reservoir drainage over time. Further,
access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more
challenging in new or emerging areas. If our drilling results are less than anticipated or we are unable to execute our drilling program
because of capital constraints, access to gathering systems and takeaway capacity or otherwise, and/or natural gas and oil prices decline,
our investment in these areas may not be as economic as we anticipate, we could incur material write-downs of unevaluated properties
and the value of our undeveloped acreage could decline in the future.
The loss of key personnel could adversely affect our ability to operate. We depend, and will continue to depend in the foreseeable
future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience
and expertise in evaluating and analyzing drilling prospects and producing oil and natural gas from proved properties and maximizing
production from oil and natural gas properties. Our ability to retain our senior officers, other key employees and our third party
consultants, none of whom are subject to employment agreements, is important to our future success and growth. The unexpected loss
of the services of one or more of these individuals could have a detrimental effect on our business.
We may not be insured against all of the operating risks to which our business is exposed. In accordance with industry practice,
we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We cannot assure you that our
insurance will be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels
that justify its purchase. No assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable
and may elect none or minimal insurance coverage. The occurrence of a significant event, not fully insured or indemnified against, could
have a material adverse effect on our financial condition and operations.
Competitive industry conditions may negatively affect our ability to conduct operations. We compete with numerous other
companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions and production include
major integrated oil and gas companies and smaller independents as well as numerous financial buyers, including many that have
significantly greater resources than us. Therefore, competitors may be able to pay more for desirable leases and evaluate, bid for and
purchase a greater number of properties or prospects than our financial or personnel resources permit. We also compete for the materials,
equipment and services that are necessary for the exploration, development and operation of our properties. Our ability to increase
reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development.
Factors that affect our ability to compete in the marketplace include:
our access to the capital necessary to drill wells and acquire properties;
our ability to acquire and analyze seismic, geological and other information relating to a property;
our ability to retain the personnel necessary to properly evaluate seismic and other information relating to a property;
our ability to procure materials, equipment and services required to explore, develop and operate our properties, including the
ability to procure fracture stimulation services on wells drilled; and
our ability to access pipelines, and the location of facilities used to produce and transport oil and natural gas production.
Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative
instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. Title VII of the
Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation of
over-the-counter derivatives and requires the U.S. Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact further
regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the
over-the-counter market.
Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant
definitions and/or exemptions still remain to be finalized. In one of the CFTC’s rulemaking proceedings still pending under the Dodd-
Frank Act, the CFTC approved on November 5, 2013, as modified and re-proposed on December 30, 2016, a rule imposing position
limits for certain futures and options contracts in various commodities (including Henry Hub Natural Gas, Light Sweet Crude Oil, NY
Harbor ULSD, and RBOB Gasoline traded on NYMEX) and for swaps that are their economic equivalents. Certain specified types of
hedging transactions are proposed to be exempt from these position limits, provided that such hedging transactions satisfy the CFTC’s
requirements for “bona fide hedging” transactions or positions. Similarly, the CFTC has issued on December 16, 2016 a proposed rule
regarding the capital that a swap dealer or major swap participant is required to post with respect to its swap business, but has not yet
issued a final rule. The CFTC issued a final rule on margin requirements for uncleared swap transactions in January 2016, which includes
an exemption for commercial end-users that enter into uncleared swaps in order to hedge commercial risks affecting their business, from
any requirement to post margin to secure such swap transactions. In addition, the CFTC has issued a final rule authorizing an exception
for commercial end-users using swaps to hedge their commercial risks from the otherwise applicable mandatory obligation under the
Dodd-Frank Act to clear all swap transactions through a registered derivatives clearing organization and to trade all such swaps on a
registered exchange. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions
29
and other regulatory compliance obligations. All of the above regulations could increase the costs to us of entering into financial
derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business.
While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or capital requirements,
depending on our ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using
swaps to hedge or mitigate its commercial risks, these rules and regulations may provide beneficial exemptions or may require us to
comply with position limits and other limitations with respect to our financial derivative activities. When a final rule on capital
requirements is issued, the Dodd-Frank Act may require our current counterparties to post additional capital as a result of entering into
uncleared financial derivatives with us, which could increase the cost to us of entering into such derivatives. The Dodd-Frank Act may
also require our current counterparties to financial derivative transactions to spin off some of their derivatives activities to separate
entities, which may not be as creditworthy as the current counterparties, and may cause some entities to cease their current business as
hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of commercial
end-users to have access to financial derivatives to hedge or mitigate their exposure to commodity price volatility. The Dodd-Frank Act
and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral
which could adversely affect our available capital for other commercial operations purposes), materially alter the terms of future swaps
relative to the terms of our existing bilaterally negotiated financial derivative contracts, and reduce the availability of derivatives to
protect against commercial risks we encounter.
In addition, federal banking regulators have adopted new capital requirements for certain regulated financial institutions in connection
with the Basel III Accord. The Federal Reserve Board also issued proposed regulations on September 30, 2016, proposing to impose
higher risk-weighted capital requirements on financial institutions active in physical commodities, such as oil and natural gas. If and
when these proposed regulations are fully implemented, financial institutions subject to these higher capital requirements may require
that we provide cash or other collateral with respect to our obligations under the financial derivatives and other contracts we may enter
into with such financial institutions in order to reduce the amount of capital such financial institutions may have to maintain.
Alternatively, financial institutions subject to these capital requirements may price transactions so that we will have to pay a premium
to enter into derivatives and other physical commodity transactions in an amount that will compensate the financial institutions for the
additional capital costs relating to such derivatives and physical commodity transactions. Rules implementing the Basel III Accord and
higher risk-weighted capital requirements could materially reduce our liquidity and increase the cost of derivative contracts and other
physical commodity contracts (including through requirements to post collateral which could adversely affect our available capital for
other commercial operations purposes).
If we reduce our use of derivative contracts as a result of any of the foregoing new requirements, our results of operations may become
more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally,
the legislation was intended, in part, to reduce the volatility of oil, natural gas and natural gas liquids prices, which some legislators
attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and natural gas liquids. Our revenues
could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these
consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows.
We may not have production to offset hedges. Part of our business strategy is to reduce our exposure to the volatility of oil and natural
gas prices by hedging a portion of our production. In a typical hedge transaction, we will have the right to receive from the other parties
to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity
hedged. If the floating price exceeds the fixed price, we are required to pay the other parties this difference multiplied by the quantity
hedged. Additionally, we are required to pay the difference between the floating price and the fixed price when the floating price exceeds
the fixed price regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions
in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements
even though such payments are not offset by sales of physical production.
Our hedging program may limit potential gains from increases in commodity prices or may result in losses or may be inadequate
to protect us against continuing and prolonged declines in commodity prices. We enter into hedging arrangements from time to time
to reduce our exposure to fluctuations in oil and natural gas prices and to achieve more predictable cash flow. Our hedges at December
31, 2016 are in the form of collars, swaps, put and call options, and other structures placed with the commodity trading branches of
certain national banking institutions and with certain other commodity trading groups. We cannot assure you that these or future
counterparties will not become credit risks in the future. Hedging arrangements expose us to risks in some circumstances, including
situations when the counterparty to the hedging contract defaults on the contractual obligations or there is a change in the expected
differential between the underlying price in the hedging agreement and actual prices received. These hedging arrangements may also
limit the benefit we could receive from increases in the market or spot prices for oil and natural gas. We cannot assure you that the
hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in oil and natural gas prices.
In addition, at December 31, 2016, the Company’s hedging portfolio, linked to NYMEX benchmark pricing, covers approximately
3,755 MBbls and 2,920 BBtu of our expected oil and natural gas production, respectively, for calendar year 2017. We also have
commodity hedging contracts linked to Midland WTI basis differentials relative to Cushing covering approximately 2,004 MBbls of our
expected oil production for calendar year 2017. These hedges may be inadequate to protect us from continuing and prolonged declines
in oil and natural gas prices. To the extent that oil and natural gas prices remain at current levels or decline further, we will not be able
30
to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition would
be negatively impacted.
Our hedging transactions expose us to counterparty credit risk. Our hedging transactions expose us to risk of financial loss if a
counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a
counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able
to realize the benefit of the derivative contract. During periods of falling commodity prices, our hedging transactions expose us to risk
of financial loss if our counterparty to a derivatives transaction fails to perform its obligations under a derivatives transaction (e.g., our
counterparty fails to perform its obligation to make payments to us under the derivatives transaction when the market (floating) price
under such derivative falls below the specified fixed price). We are unable to predict sudden changes in a counterparty’s creditworthiness
or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon
market conditions. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a
significant loss.
Should we fail to comply with all applicable statutes, rules, regulations and orders administered by the CFTC or the Federal
Energy Regulatory Commission (“FERC”), we could be subject to substantial penalties and fines. Under the Energy Policy Act
of 2005, FERC has been given greater civil penalty authority under the Natural Gas Act (“NGA”), including the ability to impose
penalties of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations
have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of
our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the
anti-market manipulation rules enforced by FERC under the NGA. Under the Commodity Exchange Act (as amended by the Dodd-
Frank Act) and regulations promulgated thereunder by the CFTC, the CFTC has also adopted anti-market manipulation, fraud and
market disruption rules relating to the prices of commodities, futures contracts, options on futures, and swaps. Additional rules and
legislation pertaining to those and other matters may be considered or adopted by Congress, the FERC, or the CFTC from time to
time. Failure to comply with those statutes, regulations, rules and orders could subject us to civil penalty liability.
The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results. Our
principal exposures to credit risk are through receivables resulting from the sale of our oil and natural gas production, which we market
to energy marketing companies, refineries and affiliates, advances to joint interest parties and joint interest receivables. We are also
subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The largest
purchaser of our oil and natural gas accounted for approximately 43% of our total oil and natural gas revenues for the year ended
December 31, 2016. We do not require any of our customers to post collateral. The inability or failure of our significant customers to
meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. Joint interest receivables arise
from billing entities who own a partial interest in the wells we operate. These entities participate in our wells primarily based on their
ownership in leases on which we choose to drill. We have limited ability to control participation in our wells.
Compliance with environmental and other government regulations could be costly and could negatively impact production. Our
operations are subject to numerous laws and regulations governing the operation and maintenance of our facilities and the discharge of
materials into the environment or otherwise relating to environmental protection. For a discussion of the material regulations applicable
to us, see “Regulations.” These laws and regulations may:
require that we acquire permits before commencing drilling;
impose operational, emissions control and other conditions on our activities;
restrict the substances that can be released into the environment or used in connection with drilling and production activities or
restrict the disposal of waste from our operations;
limit or prohibit drilling activities on protected areas such as wetlands, wilderness or other protected areas; and
require measures to remediate or mitigate pollution and environmental impacts from current and former operations, such as
cleaning up spills or dismantling abandoned production facilities.
Under these laws and regulations, the rate of oil and natural gas production may be restricted below the rate that would otherwise be
possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently
affects profitability. Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations,
and such changes could result in increased costs for environmental compliance, such as waste handling, permitting, or cleanup for the
oil and natural gas industry and could have a significant impact on our operating costs. In general, the oil and natural gas industry
recently has been the subject of increased legislative and regulatory attention with respect to environmental matters. For example, the
EPA has identified environmental compliance by the energy extraction sector as one of its enforcement initiatives for 2017-2019.
Further, under these laws and regulations, we could be liable for costs of investigation, removal and remediation, damages to and loss
of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of increased public services, as
well as administrative, civil and criminal fines and penalties, and injunctive relief. Certain environmental statutes, including the RCRA,
CERCLA, OPA and analogous state laws and regulations, impose strict joint and several liability for costs required to clean up and
restore sites where hazardous substances or other waste products have been disposed of or otherwise released. We could also be affected
31
by more stringent laws and regulations adopted in the future, including any related to climate change, greenhouse gases and hydraulic
fracturing. Under the common law, we could be liable for injuries to people and property. We maintain limited insurance coverage for
sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over
time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that could be caused
by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability or we
may be required to cease production from properties in the event of environmental incidents.
Climate change legislation or regulations restricting emissions of “greenhouse gases” (“GHG”) could result in increased
operating costs and reduced demand for the oil and natural gas we produce. In the absence of comprehensive federal legislation on
GHG emission control, the U.S. Environmental Protection Agency (the “EPA”) attempted to require the permitting of GHG emissions.
Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a
permit is required due to emissions of other pollutants. These permitting provisions, to the extent applicable to our operations, could
require us to implement emission controls or other measures to reduce GHG emissions and we could incur additional costs to satisfy
those requirements. The EPA has adopted rules to regulate methane emissions, including from new and modified oil and gas production
sources and natural gas processing and transmission sources, and has announced its intention to regulate methane emissions from
existing oil and gas sources.
In addition, the EPA requires the reporting of GHG emissions from specified large GHG emission sources including onshore and offshore
oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities,
which may include facilities we operate. Reporting of GHG emissions from such facilities is required on an annual basis. We will
continue to incur costs associated with this reporting obligation.
The United States Congress has considered (but not passed) legislation to reduce emissions of GHGs and many states and localities have
already taken or have considered legal measures to reduce or measure GHG emissions, often involving the planned development of
GHG emission inventories and/or cap and trade programs. Most of these cap and trade programs would require major sources of
emissions or major producers of fuels to acquire and surrender emission allowances. The number of allowances available for purchase
is reduced each year in an effort to achieve the overall GHG emission reduction goal. These allowances would be expected to escalate
significantly in cost over time. The adoption and implementation of any legislation or regulatory programs imposing GHG reporting
obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions
of GHGS associated with our operations or could adversely affect demand for the oil and natural gas that we produce.
Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and
cause us to incur significant costs in preparing for or responding to those effects. In an interpretative guidance on climate change
disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including storms and floods), the
arability of farmland, and water availability and quality. If such effects were to occur, our exploration and production operations have
the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising
waters in low-lying areas, disruption of our production activities either because of climate-related damages to our facilities in our costs
of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects
or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have
an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream
companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance
some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic
fracturing operations require large amounts of water. Should drought conditions occur, our ability to obtain water in sufficient quality
and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more
costly.
Federal legislation and state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in
increased costs and additional operating restrictions or delays. Hydraulic fracturing is used to stimulate production of hydrocarbons,
particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into
formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing activities are typically regulated by state oil
and gas commissions but not at the federal level, as the federal Safe Drinking Water Act expressly excludes regulation of these fracturing
activities (except where diesel is a component of the fracturing fluid). We engage third parties to provide hydraulic fracturing or other
well stimulation services to us in connection with the wells for which we are the operator. Contamination of groundwater by oil and
natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and
liabilities under federal and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages
for alternative water supplies, property damages, and bodily injury. In December 2016, the EPA released its final report “Hydraulic
Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States.” This
report concludes that hydraulic fracturing can impact drinking water resources in certain circumstances but also noted that certain date
gaps and uncertainties limited EPA’s assessment. The agency has identified one of its enforcement initiatives for 2017 to 2019 to be
environmental compliance by the energy extraction sector. This study and the EPA’s enforcement initiative could result in additional
regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.
32
A committee of the U.S. House of Representatives conducted an investigation of hydraulic fracturing practices. Legislation was
introduced before Congress, but not passed to provide for federal regulation of hydraulic fracturing and to require disclosure of the
chemicals used in the fracturing process. In addition, some states and local or regional regulatory authorities have adopted or are
considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, New York has banned
high volume hydraulic fracturing. Further, Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be
performed. While we have no operations in either New York or Pennsylvania, any other new laws or regulations that significantly
restrict hydraulic fracturing in areas in which we do operate could make it more difficult or costly for us to perform hydraulic fracturing
activities and thereby affect the determination of whether a well is commercially viable.
Further, the EPA issued pretreatment standards for wastewater from hydraulic fracturing, prohibiting the discharges of waste water
pollutants from onshore unconventional oil and gas extraction to publicly owned treatment works. The EPA has announced an initiative
under the Toxic Substance Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals.
The Bureau of Land Management (the “BLM”) finalized regulations for hydraulic fracturing activities on federal lands. Among other
things, the BLM rule imposed new requirements to validate the protection of groundwater, disclosure of chemicals used in hydraulic
fracturing and higher standards for the interim storage of recovered waste fluids from hydraulic fracturing. A federal district court in
Wyoming struck down the BLM rule; the federal government has appealed the district court’s decision. In addition, if hydraulic
fracturing becomes further regulated at the federal level, our fracturing activities could become subject to additional permit requirements
or operational restrictions and also to associated permitting delays and potential increases in costs and potential liabilities. Such federal
or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory
authorities who could then make such information publicly available. In addition, restrictions on hydraulic fracturing could reduce the
amount of oil and natural gas that we are ultimately able to produce in commercial quantities.
We are now subject to regulation under NSPS and NESHAPS programs, which could result in increased operating costs. On
April 17, 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to
regulation under the New Source Performance Standards (the “NSPS”) and the National Emissions Standards for Hazardous Air
Pollutants (the “NESHAP”) programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas
wells. Before January 1, 2015, these standards require owners/operators to reduce VOC emissions from natural gas not sent to the
gathering line during well completion either by flaring, using a completion combustion device, or by capturing the natural gas using
green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make
it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly fractured
wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, effective in
2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment.
These rules may require changes to our operations, including the installation of new equipment to control emissions.
The EPA has issued new rules limiting methane emissions from new or modified oil and gas sources. The rules amend the air emissions
rules for the oil and natural gas sources and natural gas processing and transmission sources to include new standards for
methane. Simultaneously with the methane rules, the EPA adopted new rules governing the aggregating of multiple surface sites into a
single-source of air quality permitting purposes. In addition, the EPA had announced plans to begin work on regulations to regulate
methane emissions from existing oil and gas sources.
We are subject to stringent and complex federal, state and local laws and regulations governing, among other things, worker
health and safety, the discharge of materials into the environment and environmental protection that could result in substantial
costs. In some areas of Texas, there has been concern that certain formations into which disposal wells are injecting produced waters
could become over-pressured after many years of injection, and the governing Texas regulatory agency is reviewing the data to determine
whether any action is necessary to address this issue. If the Texas state agency were to decline to issue permits for, or limit the volumes
of, new injection wells into the formations currently utilized by us, we may be required to seek alternative methods of disposing of
produced waters, including injecting into deeper formations, which could increase our costs.
Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated
as a result of future legislation. In recent years, the Obama administration’s budget proposals and other proposed legislation have
included the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production.
If enacted into law, these proposals would eliminate certain tax preferences applicable to taxpayers engaged in the exploration or
production of natural resources. These changes include, but are not limited to (1) the repeal of the percentage depletion allowance for
oil and gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the
deduction for U.S. production activities and (4) the increase in the amortization period from two years to seven years for geophysical
costs paid or incurred in connection with the exploration for or development of, oil and gas within the United States Whether the
proposed legislation will ever be enacted under the newly elected Trump administration remains in question, but the passage of such
legislation or any other similar changes in U.S. federal income tax laws could negatively affect our financial condition and results of
operations.
There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm our
business may occur and not be detected. Our management, including our Chief Executive Officer and Chief Financial Officer, do not
33
expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how
well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In
addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative
to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance
that all material control issues and instances of fraud, if any, in the Company have been detected. These inherent limitations include the
realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further,
controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system
of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design
will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control
system, misstatements due to error or fraud may occur and not be detected. A failure of our controls and procedures to detect error or
fraud could seriously harm our business and results of operations.
We have no plans to pay cash dividends on our common stock in the foreseeable future. We have no plans to pay cash dividends
in the foreseeable future. The terms of our senior secured revolving credit facility prohibit us from paying dividends and making other
distributions. In addition, any future determination as to the declaration and payment of cash dividends will be at the discretion of our
Board of Directors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements,
business prospects and other factors deemed relevant by our Board of Directors.
Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations. Our
business has become increasingly dependent on digital technologies to conduct certain exploration, development, production and
financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and
operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Unauthorized
access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication
interruption, or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil
and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber-attack
directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent
delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions.
While we have not experienced cyber-attacks, there is no assurance that we will not suffer such attacks and resulting losses in the future.
Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or
enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.
We may be subject to the actions of activist shareholders. We have been the subject of increased activity by activist shareholders.
Responding to shareholder activism can be costly and time-consuming, disrupt our operations and divert the attention of management
and our employees from executing our business plan. Activist campaigns can create perceived uncertainties as to our future direction,
strategy or leadership and may result in the loss of potential business opportunities, harm our ability to attract new investors, customers
and joint venture partners and cause our stock price to experience periods of volatility or stagnation. Moreover, if individuals are elected
to our board of directors with a specific agenda, our ability to effectively and timely implement our current initiatives, retain and attract
experienced executives and employees and execute on our long-term strategy may be adversely affected.
ITEM 1B. Unresolved Staff Comments
None.
ITEM 3. Legal Proceedings
We are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the
ultimate resolution of any such actions will have a material effect on our financial position or results of operations.
ITEM 4. Mine Safety Disclosures
Not applicable.
34
PART II.
ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
Our common stock trades on the New York Stock Exchange under the symbol “CPE”. The following table sets forth the high and low
sale prices per share as reported for the periods indicated.
First quarter
Second quarter
Third quarter
Fourth quarter
Holders
Common Stock Price
2016
2015
$
High
Low
High
Low
9.05 $
12.56
15.91
18.53
4.21 $
8.15
10.34
12.45
8.15 $
9.40
9.65
10.18
4.66
7.35
6.03
6.87
As of February 22, 2017 the Company had approximately 2,828 common stockholders of record.
Dividends
We have not paid any cash dividends on our common stock to date and presently do not expect to declare or pay any cash dividends on
our common stock in the foreseeable future as we intend to reinvest our cash flows and earnings into our business. The declaration and
payment of dividends is subject to the discretion of our Board of Directors and to certain limitations imposed under Delaware corporate
law and the agreements governing our debt obligations. The timing, amount and form of dividends, if any, will depend on, among other
things, our results of operations, financial condition, cash requirements and other factors deemed relevant by our Board of Directors. In
addition, certain of our debt facilities contain restrictions on the payment of dividends to the holders of our common stock.
Holders of our 10% Series A Cumulative Preferred Stock are entitled to a cumulative dividend whether or not declared, of $5.00 per
annum, payable quarterly, equivalent to 10.0% of the liquidation preference of $50.00 per share. Unless the full amount of the dividends
for the 10% Series A Cumulative Preferred Stock is paid in full, we cannot declare or pay any dividend on our common stock.
During 2016, neither the Company nor any affiliated purchasers made repurchases of Callon’s equity securities.
On February 4, 2016, a total of 120,000 shares of the Company’s 10% Series A Cumulative Preferred Stock were exchanged for 719,000
shares of common stock.
Equity Compensation Plan Information
The following table summarizes information regarding the number of shares of our common stock that are available for issuance under
all of our existing equity compensation plans as of December 31, 2016 (securities amounts are presented in thousands).
Plan Category
Equity compensation plans approved by security holders
Equity compensation plans not approved by security holders
Total
Number of
Securities to be
Issued Upon
Exercise of
Outstanding Options
— $
15 $
15 $
Weighted-Average
Exercise Price of
Outstanding
Options, Warrants
and Rights
—
14.37
14.37
Number of
Securities
Remaining Available
for Future Issuance
Under Equity
Compensation Plans
2,270
—
2,270
For additional information regarding the Company’s benefit plans and share-based compensation expense, see Notes 8 and 9 to the
Consolidated Financial Statements.
35
Performance Graph
The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the performance
of the Company’s common stock relative to four broad-based stock performance indices. The information is included for historical
comparative purposes only and should not be considered indicative of future stock performance.
The graph below compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock
with the cumulative total return of the S&P 500 Index and SIG (Susquehanna International Group, LLP) Oil Exploration & Production
Index from December 31, 2011, through December 31, 2016.
The stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall
information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934,
each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.
Comparison of Five Year Cumulative Total Return
Assumes Initial Investment of $100
December 2016
Company/Market/Peer Group
Callon Petroleum Company
S&P 500 Index - Total Returns
SIG Oil Exploration & Production Index
$
2011
100.00 $
100.00
100.00
2012
2013
2014
2015
94.57 $
116.00
93.07
131.39 $
153.57
117.80
109.66 $
174.60
84.46
167.81 $
177.01
46.39
2016
309.26
198.18
59.28
For the Year Ended December 31,
36
ITEM 6. Selected Financial Data
The following table sets forth, as of the dates and for the periods indicated, selected financial information about the Company. The
financial information for each of the five years in the period ended December 31, 2016 has been derived from our audited Consolidated
Financial Statements for such periods. The information should be read in conjunction with “Management’s Discussion and Analysis of
Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto. The following information
is not necessarily indicative of our future results (dollars in thousands, except per share amounts).
2016
For the Year Ended December 31,
2013
2015
2014
2012
Statement of Operations Data
Operating revenues
Oil and natural gas sales
Operating expenses
Total operating expenses
Income (loss) from operations
Net income (loss) (a)
Income (loss) per share ("EPS")
Basic
Diluted
Weighted average number of shares outstanding for Basic EPS
Weighted average number of shares outstanding for Diluted
EPS
Statement of Cash Flows Data
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by (used in) financing activities
Balance Sheet Data
Total oil and natural gas properties
Total assets
Long-term debt (b)
Stockholders' equity
Proved Reserves Data
Total oil (MBbls)
Total natural gas (MMcf)
Total (MBOE)
Standardized measure (c)
$
200,851 $ 137,512 $ 151,862 $ 102,569 $ 110,733
$
248,328 $ 346,622 $ 113,592 $
38,270
(47,477) (209,110)
91,905 $ 100,043
10,690
10,664
(91,813) (240,139)
37,766
4,304
2,747
$
$
(0.78) $
(0.78) $
126,258
(3.77) $
(3.77) $
65,708
0.67 $
0.65 $
44,848
(0.01) $
(0.01) $
40,133
0.07
0.07
39,522
126,258
65,708
45,961
40,133
40,337
$
118,567 $
94,387 $
(866,287) (259,160) (452,501)
1,399,489 172,564 356,070
86,852 $
54,475 $
(79,804)
27,202
51,290
(93,703)
(243)
$ 1,475,401 $ 711,386 $ 742,155 $ 324,187 $ 269,521
378,173
2,267,587 788,594
863,346
423,953
390,219 328,565
1,733,402 362,758
321,576
433,735
75,748
279,094
120,668
205,971
71,145
122,611
91,580
43,348
65,537
54,271
25,733
42,548
32,824
11,898
17,751
14,857
10,780
19,753
14,072
$
809,832 $ 570,890 $ 579,542 $ 283,946 $ 231,148
(a) Net loss for 2015 included the recognition of a write-down of oil and natural gas properties of $208,435 as a result of the ceiling test limitation
and $108,843 of income tax expense related to the recognition of a valuation allowance. Net loss for 2016 included the recognition of a write-
down of oil and natural gas properties of $95,788 as a result of the ceiling test limitation. See Notes 11 and 13 in the Footnotes to the Financial
Statements for additional information.
(b) See Note 5 in the Footnotes to the Financial Statements for additional information.
(c) Standardized measure is the future net cash flows related to estimated proved oil and natural gas reserves together with changes therein,
including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet. Prices are based
on either the preceding 12-months’ average price, based on closing prices on the first day of each month, or prices defined by existing
contractual arrangements. Future production and development costs are based on current estimates with no escalations. Estimated future cash
flows have been discounted to their present values based on a 10% discount rate. See Note 13 in the Footnotes to the Financial Statements
for additional information.
37
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s Discussion and Analysis of Financial Condition and Results of Operation
General
The following management’s discussion and analysis describes the principal factors affecting the Company’s results of operations,
liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying
audited consolidated financial statements, information about our business practices, significant accounting policies, risk factors, and the
transactions that underlie our financial results, which are included in various parts of this filing. Our website address is www.callon.com.
All of our filings with the SEC are available free of charge through our website as soon as reasonably practicable after we file them
with, or furnish them to, the SEC. Information on our website does not form part of this report on Form 10-K.
We are an independent oil and natural gas company established in 1950. We are focused on the acquisition, development, exploration
and exploitation of unconventional, onshore, oil and natural gas reserves in the Permian Basin in West Texas. Our operating culture is
centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our
operational performance. Our drilling activity is predominantly focused on the horizontal development of several prospective intervals,
including multiple levels of the Wolfcamp formation and, more recently, the Lower Spraberry shales. We have assembled a multi-year
inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our
existing acreage and acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint
ventures and asset swaps. Our production was approximately 77% oil and 23% natural gas for the year ended December 31, 2016. On
December 31, 2016, our net acreage position in the Permian Basin was 39,570 net acres, excluding acreage related to our recently
completed acquisition in the Delaware sub-basin. See Note 3 in the Footnotes to the Financial Statements for additional information
about the Company’s acquisitions.
Commodity Prices
The prices for oil and natural gas remain extremely volatile and sometimes experience large fluctuations as a result of relatively small
changes in supply, weather conditions, economic conditions and actions by the Organization of Petroleum Exporting Countries and other
countries and government actions. Prices of oil and natural gas will affect the following aspects of our business:
our revenues, cash flows and earnings;
the amount of oil and natural gas that we are economically able to produce;
our ability to attract capital to finance our operations and cost of the capital;
the amount we are allowed to borrow under our senior secured revolving credit facility; and
the value of our oil and natural gas properties.
Beginning in the second half of 2014, the NYMEX price for a barrel of oil declined from $105.37 on June 30, 2014 to $26.21 on
February 11, 2016. For the year ended December 31, 2016, the average NYMEX price for a barrel of oil was $43.39 per Bbl compared
to $48.82 per Bbl for the same period of 2015. The NYMEX price for a barrel of oil ranged from a low of $26.21 per Bbl to a high of
$54.06 per Bbl for the year ended December 31, 2016.
For the year ended December 31, 2016, the average NYMEX price for natural gas was $2.46 per MMBtu compared to $2.66 per MMBtu
for the same period in 2015. The NYMEX price for natural gas ranged from a low of $1.64 per MMBtu to a high of $3.93 per MMBtu
for the year ended December 31, 2016.
38
Management’s Discussion and Analysis of Financial Condition and Results of Operation
The table below presents the cumulative results of the full cost ceiling test along with various pricing scenarios to demonstrate the
sensitivity of our full cost ceiling and estimated total proved reserve volumes to changes in 12-month average oil and natural gas prices.
This sensitivity analysis is as of December 31, 2016 and, accordingly, does not consider drilling results, production, changes in oil and
natural gas prices, and changes in future development and operating costs subsequent to December 31, 2016 that may require revisions
to our proved reserve estimates and resulting estimated future net cash flows used in the full cost ceiling test. The volumes resulting
from the sensitivity analysis, which are for illustrative purposes only, incorporate a number of assumptions and have not been audited
by the Company’s third-party engineer.
Pricing Scenarios
12-Month Average Prices
Oil ($/Bbl)
Natural gas ($/Mcf)
Ceiling Test Analysis
Excess (Deficit)
of Full Cost
Ceiling Over Net
Capitalized Costs (a)
(in thousands)
Reserve Analysis
Estimated Total
Proved Reserves
(MBOE)
December 31, 2016 Actual
$
42.75 $
2.48 $
12,841
91,580
Combined price sensitivity
Oil and natural gas +10%
Oil and natural gas -10%
Oil price sensitivity
Oil +10%
Oil -10%
Natural gas sensitivity
Natural gas +10%
Natural gas -10%
$
$
$
$
$
$
47.03 $
38.47 $
47.03 $
38.47 $
42.75 $
42.75 $
2.73 $
2.23 $
2.48 $
2.48 $
2.73 $
2.23 $
166,622
(140,304)
152,993
(126,674)
26,789
(470)
92,379
90,551
92,201
90,816
91,708
91,433
(a) The Company uses the full cost method of accounting for its exploration and development activities. Under full cost accounting rules, the
Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and
natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present
value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of
unevaluated properties, net of related tax effects (the full cost ceiling amount). These rules require pricing based on the preceding 12-months’
average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs
of proved oil and natural gas properties exceeds the full cost ceiling. For the year ended December 31, 2016, the Company recorded a $95.8
million write-down of oil and natural gas properties as a result of the ceiling test limitation primarily driven by a 15% decrease in the 12-
month average realized price of oil from $50.16 per barrel as of December 31, 2015 to $42.75 per barrel as of December 31, 2016. If
commodity prices were to decline, we could incur additional ceiling test write-downs in the future. However, we do not expect such prevailing
commodity prices to have significant adverse effects on our proved oil and gas reserve quantities. See Notes 2 and 13 in the Footnotes to the
Financial Statements for more information.
Significant accomplishments for 2016 include:
increased annual production in 2016 by 59% to 5,573 MBOE as compared to 2015;
increased 2016 proved reserves by 69% to 91.6 MMBOE as compared to 2015;
drilled and completed our 100th horizontal well in the Midland Basin;
entered into agreements for multiple acquisitions, creating two new core operating areas and increasing our total acreage
footprint by approximately 41,000 net acres;
enhanced financial flexibility through the completion of four strategic equity offerings for $1.4 billion in net proceeds, funding
acquisition growth, increasing liquidity and reducing leverage;
issued $400 million in unsecured senior notes in a Rule 144A private offering, reducing our cost of term debt; and
achieved an OSHA Recordable Incident Rate (“ORIR”), of 0.58, well below the reported range by other similar sized operators
in the Permian Basin and below our average ORIRs reported for the past three years.
Operational Highlights
All of our producing properties are located in the Permian Basin. As a result of our acquisition and horizontal development efforts, our
production grew 59% in 2016 compared to 2015, increasing to 5,573 MBOE from 3,508 MBOE. Our production in 2016 was
approximately 77% oil and 23% natural gas.
During 2016, we operated with one horizontal rig, after placing a second rig on standby in January 2016, and then operated with two
horizontal rigs after returning the second one to service in August 2016. For the year ended December 31, 2016, we drilled 29 gross
39
Management’s Discussion and Analysis of Financial Condition and Results of Operation
(20.9 net) horizontal wells, completed 32 gross (23.7 net) horizontal wells and had six gross (4.2 net) horizontal wells awaiting
completion.
Reserve Growth
As of December 31, 2016, our estimated net proved reserves increased 69% to 91.6 MMBOE compared to 54.3 MMBOE of estimated
net proved reserves at year-end 2015. Our significant growth in proved reserves was primarily attributable to our horizontal development
and acquisition efforts. Our proved reserves at year-end 2016 were 78% oil and 22% natural gas, compared to 80% oil and 20% natural
gas at year-end 2015.
Liquidity and Capital Resources
Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions, the sale of
debt and equity securities, and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration
and exploitation of oil and natural gas properties, in addition to refinancing of debt instruments.
In 2016, we completed four common stock offerings and completed a debt offering to raise additional capital. In addition, we amended
the borrowing base under our senior secured revolving credit facility to $500 million with a current elected commitment level of $385
million, providing us with additional liquidity. We continue to evaluate other sources of capital to complement our cash flow from
operations and other sources of capital as we pursue our long-term growth plans.
For the year ended December 31, 2016, cash and cash equivalents increased $651.8 million to $653.0 million compared to $1.2 million
at December 31, 2015. As of February 22, 2017, our available liquidity was $48.9 million.
Liquidity and cash flow
(in millions)
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by financing activities
Net change in cash
For the Year Ended December 31,
2015
2016
2014
$
$
118.6 $
(866.3)
1,399.5
651.8 $
86.8
(259.2)
172.6
0.2 $
94.4
(452.5)
356.1
(2.0)
Operating activities. For the year ended December 31, 2016, net cash provided by operating activities was $118.6 million, compared
to $86.8 million for the same period in 2015. The change in operating activities was predominantly attributable to the following:
an increase in revenue, offset by a decrease in settlements of derivative contracts;
an increase in certain operating expenses related to acquired properties;
an increase in payments in cash-settled restricted stock unit (“RSU”) awards;
a decrease in payments related to nonrecurring early retirement expenses that were incurred in 2015; and
a change related to the timing of working capital payments and receipts.
Production, realized prices, and operating expenses are discussed below in Results of Operations. See Notes 6 and 7 in the Footnotes to
the Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to
derivative instruments including their composition and valuation. See Note 3 in the Footnotes to the Financial Statements for more
information on the Company’s acquisitions.
Investing activities. For the year ended December 31, 2016, net cash used in investing activities was $866 million compared to $259
million for the same period in 2015. The change in investing activities was primarily attributable to the following:
a $37 million decrease in operational expenditures primarily due to the transition from a two-rig to a one-rig program in
January 2016, offset in part by the release of a vertical rig in April 2015 and the transition back to a two-rig program in August
2016; and
a $644.4 million increase in acquisitions, net of proceeds from the sale of mineral interest and equipment. In addition, there
was a $46.1 million security deposit in relation to the Ameredev Transaction. The acquisitions were funded with cash and
common stock.
40
Our investing activities, on a cash basis, include the following for the periods indicated (in millions):
Management’s Discussion and Analysis of Financial Condition and Results of Operation
For the Year Ended December 31,
2015
$ Change
2016
Operational expenditures
Seismic, leasehold and other
Capitalized general and administrative expenses
Capitalized interest expense
Total capital expenditures (a)
Acquisitions
Acquisition deposits
Proceeds from the sale of mineral interest and equipment
Total investing activities
$
$
143.9 $
13.6
12.7
19.9
190.1
654.7
46.1
(24.5)
866.4 $
205.7 $
—
11.1
10.5
227.3
32.2
—
(0.4)
259.2
(61.7)
13.6
1.6
9.4
(37.2)
622.5
46.1
(24.1)
607.2
(a) On an accrual (GAAP) basis, which is the methodology used for establishing our annual capital budget, operational expenditures for the year
ended December 31, 2016 were $142.7 million. Inclusive of capitalized general and administrative expenses and capitalized interest expenses,
total capital expenditures were $196.2 million.
General and administrative expenses and capitalized interest are discussed below in Results of Operations. See Note 3 in the Footnotes
to the Financial Statements for additional information on significant acquisitions.
Financing activities. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings
under our senior secured revolving credit facility, term debt and equity offerings. For the year ended December 31, 2016, net cash
provided by financing activities was $1.4 million compared to cash provided by financing activities of $173 million during the same
period of 2015. The change in net cash provided by financing activities was primarily attributable to the following:
payments, net of borrowings, on our Credit Facility were $40 million, $45 million more than the same period of 2015;
a $1.2 billion increase in proceeds resulting from four common stock offerings in 2016 that raised $1.4 billion as compared to
two offerings in 2015 that raised $175 million; and
a $100 million increase in borrowings on fixed-rate debt, resulting from the issuance of $400 million of 6.125% senior
unsecured senior notes due 2024, net of the repayment of the Company’s secured second lien term loan.
Net cash provided by financing activities includes the following for the periods indicated (in millions):
For the Year Ended December 31,
2015
2016
$ Change
Net borrowings on senior secured revolving credit facility
Payments on term loans
Issuance of 6.125% senior unsecured notes due 2024
Payment of deferred financing costs
Issuance of common stock
Payment of preferred stock dividends
Net cash provided by financing activities
$
$
(40.0) $
(300.0)
400.0
(10.8)
1,357.6
(7.3)
1,399.5 $
5.0 $
—
—
—
175.5
(7.9)
172.6 $
(45.0)
(300.0)
400.0
(10.8)
1,182.1
0.6
1,226.9
See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s debt. See Note 10 in the
Footnotes to the Financial Statements for additional information about the Company’s equity offerings and Series A 10% Cumulative
Preferred Stock.
Senior secured revolving credit facility (“Credit Facility”)
The total notional amount available under the Company’s Credit Facility is $500 million. Effective November 21, 2016, the Company
achieved an indication to increase the Credit Facility’s borrowing base to $500 million, but elected to maintain commitments from
lenders at $385 million. As of December 31, 2016, the Credit Facility had no balance outstanding.
For the year ended December 31, 2016, the Credit Facility had a weighted-average interest rate of 2.60%, calculated as the LIBOR plus
a tiered rate ranging from 2.00% to 3.00%, which is determined based on utilization of the facility. In addition, the Credit Facility carries
a commitment fee of 0.5% per annum, payable quarterly, on the unused portion of the borrowing base.
See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s Credit Facility.
41
Management’s Discussion and Analysis of Financial Condition and Results of Operation
Term loan
On October 11, 2016, the secured second lien term loan (the “Second Lien Loan”) was repaid in full at the prepayment rate of 101%
using proceeds from the sale of the 6.125% senior unsecured notes due 2024, which resulted in a loss on early extinguishment of debt
of $12.9 million (inclusive of $3.0 million in prepayment fees and $9.9 million of unamortized debt issuance costs).
See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s Second Lien Loan.
6.125% senior notes due 2024
On October 3, 2016, the Company issued $400 million aggregate principal amount of 6.125% Senior Notes with a maturity date of
October 1, 2024 and interest payable semi-annually beginning on April 1, 2017. The net proceeds of the offering, after deducting initial
purchasers’ discounts and estimated offering expenses, were approximately $391.3 million. The 6.125% Senior Notes are guaranteed
on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed
by certain future subsidiaries.
The Company may redeem the 6.125% Senior Notes in accordance with the contractual redemption terms. Following a change of control,
each holder of the 6.125% Senior Notes may require the Company to repurchase all or a portion of the 6.125% Senior Notes at a price
of 101% of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase.
See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s 6.125% Senior Notes.
10% Series A Cumulative Preferred Stock (“Preferred Stock”)
Holders of the Company’s Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds
legally available for the payment of dividends, cumulative cash dividends at a rate of 10.0% per annum of the $50.00 liquidation
preference per share (equivalent to $5.00 per annum per share). Dividends are payable quarterly in arrears on the last day of each March,
June, September and December when, as and if declared by our Board of Directors. Preferred Stock dividends were $7.3 million in
2016.
The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. On or after May 30,
2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, by paying $50.00 per share, plus any accrued
and unpaid dividends to the redemption date.
On February 4, 2016, the Company exchanged a total of 120,000 shares of Preferred Stock for 719,000 shares of common stock. As of
December 31, 2016, the Company had 1,458,948 shares of its Preferred Stock issued and outstanding.
See Note 10 in the Footnotes to the Financial Statements for additional information about the Company’s Preferred Stock.
2017 Capital Plan and Outlook
Our operational capital budget for 2017 has been established in the range of $325 to $350 million on an accrual, or GAAP, basis,
inclusive of a planned transition from a three-rig program that commenced in January 2017 to a four-rig program by July 2017 that
would include horizontal development activity at our recent Delaware Basin acquisition (see Note 3 in the Footnotes to the Financial
Statements for information on this acquisition).
As part of our 2017 operated horizontal drilling program we expect to place 33 –36 net horizontal wells on production with lateral
lengths ranging from 5,000’ to 10,000’. We have also budgeted approximately $7.5 to $10 million for non-operated operational activity.
In addition to the operational capital expenditures budget, which includes well costs, facilities and infrastructure capital, and surface
land purchases, we budgeted an estimated $40 to $45 million for capitalized general and administrative expenses and capitalized interest
expenses, both on an accrual, or GAAP, basis.
Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop
our reserves of oil and natural gas. Despite a continued low price environment, we believe the long-term outlook for our business is
favorable due to our resource base, low cost structure, financial strength, risk management, including commodity hedging strategy, and
disciplined investment of capital. We monitor current and expected market conditions, including the commodity price environment, and
our liquidity needs and may adjust our capital investment plan accordingly.
42
Contractual Obligations
Management’s Discussion and Analysis of Financial Condition and Results of Operation
The following table includes the Company’s current contractual obligations and purchase commitments (in thousands):
Payments due by Period
6.125% Senior Notes (a)
Credit Facility (a)(b)
Interest expense and other fees related to debt commitments (c)
Drilling rig leases (d)
Office space lease and other commitments
Total contractual obligations
< 1 Year
Total
$ 400,000 $
—
193,943
20,340
2,915
$ 617,198 $
Years 2 - 3 Years 4 - 5 >5 Years
— $ 400,000
—
—
67,375
49,000
—
—
—
827
49,827 $ 467,375
— $
—
51,303
6,510
1,263
59,076 $
— $
—
26,265
13,830
825
40,920 $
(a) Includes the outstanding principal amount only.
(b) As of December 31, 2016, the Credit Facility had no balance outstanding. We cannot predict the timing of future borrowings and repayments.
(c) Includes scheduled cash payments on the 6.125% Senior Notes and the minimum amount of commitment fees due on the Credit Facility.
(d) Drilling rig leases represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a
party on December 31, 2016. See Note 14 in the Footnotes to the Financial Statements for additional information related to drilling rig leases.
43
Results of Operations
Management’s Discussion and Analysis of Financial Condition and Results of Operation
The following table sets forth certain operating information with respect to the Company’s oil and natural gas operations for the
periods indicated:
For the Year Ended December 31,
2016
2015
$ Change
%
Change
$ Change
%
Change
2014
$
Net production:
Oil (MBbls)
Natural gas (MMcf)
Total (MBOE)
Average daily production (BOE/d)
% oil (BOE basis)
Average realized sales price:
Oil (Bbl) (excluding impact of cash settled derivatives)
Oil (Bbl) (including impact of cash settled derivatives)
Natural gas (Mcf) (excluding impact of cash settled derivatives) $
Natural gas (Mcf) (including impact of cash settled derivatives)
Total (BOE) (excluding impact of cash settled derivatives)
$
Total (BOE) (including impact of cash settled derivatives)
Oil and natural gas revenues (in thousands):
Oil revenue
Natural gas revenue
Total
Additional per BOE data:
Sales price (excluding impact of cash settled derivatives)
Lease operating expense
Production taxes
Operating margin
$
$
4,280
7,758
5,573
15,227
77%
2,789
4,312
3,508
9,610
80%
1,491
3,446
2,065
5,617
53%
80%
59%
59%
1,692
2,220
2,062
5,649
82%
1,097
2,092
1,446
3,961
65%
94%
70%
70%
41.51 $
45.67
2.99 $
3.00
36.04 $
39.25
44.88 $
56.82
2.86 $
3.26
39.20 $
49.18
(3.37)
(11.15)
0.13
(0.26)
(3.16)
(9.93)
(8)% $
(20)%
5% $
(8)%
(8)% $
(20)%
82.37 $ (37.49)
(28.02)
84.84
(2.77)
5.63 $
5.59
(2.33)
73.65 $ (34.45)
(26.45)
75.63
(46)%
(33)%
(49)%
(42)%
(47)%
(35)%
$ 177,652 $ 125,166 $ 52,486
23,199 12,346
10,853
$ 200,851 $ 137,512 $ 63,339
42% $ 139,374 $ (14,208)
88% 12,488
(142)
46% $ 151,862 $ (14,350)
(10)%
(1)%
(9)%
36.04 $
6.88
2.13
27.03 $
39.20 $
7.71
2.79
28.70 $
(3.16)
(0.83)
(0.66)
(1.67)
(8)% $
(11)%
(24)%
(6)% $
73.65 $ (34.45)
10.85
(3.14)
4.35
(1.56)
58.45 $ (29.75)
(47)%
(29)%
(36)%
(51)%
44
Revenues
Management’s Discussion and Analysis of Financial Condition and Results of Operation
The following tables are intended to reconcile the change in oil, natural gas and total revenue for the respective periods presented by
reflecting the effect of changes in volume and in the underlying commodity prices.
(in thousands)
Revenues for the year ended December 31, 2013
Volume increase (decrease)
Price increase (decrease)
Net increase (decrease)
Revenues for the year ended December 31, 2014
Volume increase
Price decrease
Net decrease
Revenues for the year ended December 31, 2015
Volume increase
Price increase (decrease)
Net increase
Revenues for the year ended December 31, 2016
Oil revenue
Oil
Natural Gas
Total
$
$
$
$
88,960 $
76,237
(25,823)
50,414
139,374 $
90,398
(104,606)
(14,208)
125,166 $
66,916
(14,430)
52,486
177,652 $
13,609 $
(3,575)
2,454
(1,121)
12,488 $
11,774
(11,916)
(142)
12,346 $
9,856
997
10,853
23,199 $
102,569
72,662
(23,369)
49,293
151,862
102,172
(116,522)
(14,350)
137,512
76,772
(13,433)
63,339
200,851
For the year ended December 31, 2016, oil revenues of $178 million increased $52.5 million, or 42%, compared to revenues of $125
million for the same period of 2015. The increase in oil revenue was primarily attributable to a 53% increase in production offset by an
8% decrease in the average realized sales price, which fell to $41.51 per Bbl from $44.88 per Bbl. The increase in production was
comprised of 1,182 MBbls attributable to wells placed on production as a result of our horizontal drilling program and 547 MBbls
attributable to producing wells added from our acquired properties. Offsetting these increases were normal and expected declines from
our existing wells.
For the year ended December 31, 2015, oil revenues of $125 million decreased $14.2 million, or 10%, compared to revenues of $139
million for the same period of 2014. The decrease in oil revenue was primarily attributable to a 46% decrease in the average realized
sales price, which fell to $44.88 per Bbl from $82.37 per Bbl, and was predominately offset by a 65% increase in production. The
increase in production was primarily attributable to a 1,197 MBbls increase in production from our properties resulting from an increased
number of producing wells from our horizontal drilling program and acquisitions, offset by normal and expected declines from our
existing wells.
Natural gas revenue (including NGLs)
Natural gas revenues of $23.2 million increased $10.9 million, or 88%, during the year ended December 31, 2016 compared to $12.3
million for the same period of 2015. The increase primarily relates to an 80% increase in natural gas volumes and a 5% increase in the
average price realized, which rose to $2.99 per Mcf from $2.86 per Mcf, reflecting increases in both natural gas and natural gas liquids
prices. The increase in production was comprised of 1,387 MMcf attributable to wells placed on production as a result of our horizontal
drilling program and 1,025 MMcf attributable to producing wells added from our acquired properties. In addition, the increase in
production was also attributable to the increase in the percentage of natural gas produced in our production stream.
Natural gas revenues of $12.3 million decreased $0.2 million, or 1%, during the year ended December 31, 2015 compared to $12.5
million for the same period of 2014. The decrease primarily relates to 49% decrease in the average price realized, which fell to $2.86
per Mcf from $5.63 per Mcf, reflecting decreases in both natural gas and natural gas liquids prices and was predominantly offset by a
94% increase in natural gas volumes. The increase in production was primarily attributable to increased production of 1,757 MMcf from
our properties resulting from an increased number of producing wells.
45
Management’s Discussion and Analysis of Financial Condition and Results of Operation
$
(0.83)
(0.66)
(6.93)
(3.36)
(0.02)
nm
nm
nm
$
(3.14)
(1.56)
(7.77)
(4.10)
(0.21)
nm
nm
nm
nm
(11)%
(24)%
(35)%
(42)%
(11)%
nm
nm
nm
(29)%
(36)%
(28)%
(34)%
(53)%
nm
nm
nm
nm
Operating Expenses
(in thousands, except per unit data)
Lease operating expenses
Production taxes
Depreciation, depletion and amortization
General and administrative
Accretion expense
Write-down of oil and natural gas properties
Rig termination fee
Acquisition expense
Per
BOE
2016
$ 38,353 $
For the Year Ended December 31,
Per
BOE
Total Change
%
$
2015
BOE Change
%
11,870
71,369
26,317
958
95,788
—
3,673
6.88 $ 27,036 $
2.13
12.81
4.72
0.17
9,793
69,249
28,347
660
nm 208,435
3,075
nm
27
nm
7.71 11,317
2,077
2.79
2,120
19.74
(2,030)
8.08
298
0.19
nm (112,647)
(3,075)
nm
3,646
nm
42%
21%
3%
(7)%
45%
nm
nm
nm
For the Year Ended December 31,
Per
BOE
Per
BOE
Total Change
%
BOE Change
%
2014
(in thousands, except per unit data)
Lease operating expenses
Production taxes
Depreciation, depletion and amortization
General and administrative
Accretion expense
Write-down of oil and natural gas properties
Rig termination fee
Gain on sale of other property and equipment
Acquisition expense
2015
$ 27,036 $
9,793
69,249
28,347
660
208,435
3,075
—
27
7.71 $ 22,372 $
2.79
19.74
8.08
0.19
nm
nm
nm
nm
8,973
56,724
25,109
826
—
—
(1,080)
668
10.85
4.35
$
4,664
820
27.51 12,525
3,238
12.18
(166)
0.40
nm 208,435
3,075
nm
1,080
nm
(641)
nm
21%
9%
22%
13%
(20)%
nm
nm
nm
nm
nm = not meaningful
Lease operating expenses. These are daily costs incurred to extract oil and natural gas, together with the daily costs incurred to maintain
our producing properties. Such costs also include maintenance, repairs, gas treating fees, salt water disposal, insurance and workover
expenses related to our oil and natural gas properties.
LOE for the year ended December 31, 2016 increased by 42% to $38.4 million compared to $27.0 million for the same period of 2015.
Contributing to the increase for the current period was $7.3 million related to oil and natural gas properties acquired during 2016 (see
Note 3 in the Footnotes to the Financial Statements for information about the Company’s acquisitions). Excluding LOE related to these
acquired properties, LOE increased by $4.0 million, or 15%, compared to the same period of 2015. LOE per BOE for the year ended
December 31, 2016 decreased to $6.88 per BOE compared to $7.71 per BOE for the same period of 2015, which was primarily
attributable to higher production volumes offset by an increase in cost from workover activity on our legacy properties. The increase in
production was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions
as discussed above.
LOE for the year ended December 31, 2015 increased by 21% to $27.0 million compared to $22.4 million for the same period of 2014
primarily related to the growth in production and operations as a result of our horizontal drilling program and acquisition efforts. LOE
per BOE for the year ended December 31, 2015 decreased to $7.71 per BOE compared to $10.85 per BOE for the same period of
2014. The $3.14 per BOE decrease resulted primarily from a decrease in the number of workovers period over period and the impact
of leveraging fixed expenses over a larger production base.
Production taxes. Production taxes include severance and ad valorem taxes. In general, production taxes are directly related to
commodity price changes; however, severance taxes are based upon current year commodity prices, whereas ad valorem taxes are based
upon prior year commodity prices. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from
products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and
exemptions in our various taxing jurisdictions. In the counties where our production is located, we are also subject to ad valorem taxes,
which are generally based on the taxing jurisdictions’ valuation of our oil and gas properties.
For the year ended December 31, 2016, production taxes increased 21%, or $2.1 million, to $11.9 million compared to $9.8 million for
the same period of 2015. The increase was primarily due to an increase in severance taxes, which was attributable to the increase in
revenue. The increase was offset by a decrease in ad valorem taxes attributable to a lower valuation of our oil and gas properties by the
46
Management’s Discussion and Analysis of Financial Condition and Results of Operation
taxing jurisdictions. On a per BOE basis, production taxes for the year ended December 31, 2016 decreased by 24% compared to the
same period of 2015.
For the year ended December 31, 2015, production taxes increased 9%, or $0.8 million, to $9.8 million compared to $9.0 million for the
same period of 2014. The increase was primarily due to an increase in ad valorem taxes attributable to a greater number of producing
wells as a result of our horizontal drilling program and acquisition efforts. Offsetting this increase was a reduction in severance taxes as
a result of the decline of oil and natural gas revenue as previously mentioned. On a per BOE basis, production taxes for the year ended,
December 31, 2015 decreased by 36% compared to the same period of 2014.
Depreciation, depletion and amortization (“DD&A”). Under the full cost accounting method, we capitalize costs within a cost center
and then systematically expense those costs on a units-of-production basis based on proved oil and natural gas reserve quantities. We
calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unevaluated properties,
less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated
dismantlement and abandonment costs, net of estimated salvage values. Depreciation of other property and equipment is computed using
the straight line method over their estimated useful lives, which range from three to fifteen years.
For the year ended December 31, 2016, DD&A increased 3% to $71.4 million from $69.2 million compared to the same period of
2015. The increase is primarily attributable to a 59% increase in production, offset by a 35% decrease in our per BOE DD&A rate. The
increase in production was primarily attributable to an increased number of producing wells from our horizontal drilling program and
acquisitions. For the year ended December 31, 2016, DD&A on a per unit basis decreased to $12.81 per BOE compared to $19.74 per
BOE for the same period of 2015. The decrease is attributable to our increased estimated proved reserves relative to our depreciable
base and assumed future development costs related to undeveloped proved reserves as a result of additions made through our horizontal
drilling efforts and acquisitions, offset by the write down of oil and natural gas properties in the first half of 2016.
For the year ended December 31, 2015, DD&A increased 22% to $69.2 million from $56.7 million compared to the same period of
2014. The increase is primarily attributable to a 70% increase in production, offset by a 28% decrease in our per BOE DD&A rate. The
increase in production was primarily attributable to an increased number of producing wells from our horizontal drilling program and
acquisitions. For the year ended December 31, 2015, DD&A on a per unit basis decreased to $19.74 per BOE compared to $27.51 per
BOE for the same period of 2014 as a result of the increase in our estimated proved reserves relative to our depreciable base as a result
of our efforts on development, exploration, and exploitation of onshore oil and natural gas reserves in the Permian Basin and the write-
down of oil and natural gas properties.
General and administrative, net of amounts capitalized (“G&A”). These are costs incurred for overhead, including payroll and benefits
for our corporate staff, severance and early retirement expenses, costs of maintaining our headquarters, costs of managing our production
and development operations, franchise taxes, depreciation of corporate level assets, public company costs, vesting of equity and liability
awards under share-based compensation plans and related mark-to-market valuation adjustments over time, fees for audit and other
professional services, and legal compliance.
G&A for the year ended December 31, 2016 decreased to $26.3 million compared to $28.3 million for the same period of 2015. G&A
expenses for the periods indicated include the following (in millions):
For the Year Ended December 31,
2015
2016
$ Change
Recurring expenses
G&A
Share-based compensation
Fair value adjustments of cash-settled RSU awards
Non-recurring expenses
Early retirement expenses
Early retirement expenses related to share-based compensation
Expense related to a threatened proxy contest
Total G&A expenses
$
$
16.5 $
2.7
6.9
—
—
0.2
26.3 $
15.1 $
2.1
6.1
3.5
1.1
0.4
28.3 $
1.4
0.6
0.8
(3.5)
(1.1)
(0.2)
(2.0)
47
Management’s Discussion and Analysis of Financial Condition and Results of Operation
G&A for the year ended December 31, 2015 increased to $28.3 million compared to $25.1 million for the same period of 2014. G&A
expenses for the periods indicated include the following (in millions):
For the Year Ended December 31,
2014
2015
$ Change
Recurring expenses
G&A
Share-based compensation
Fair value adjustments of cash-settled RSU awards
Non-recurring expenses
Early retirement expenses
Early retirement expenses related to share-based compensation
Expense related to a threatened proxy contest
Total G&A expenses
$
$
15.1 $
2.1
6.1
3.5
1.1
0.4
28.3 $
15.3 $
2.7
3.1
1.4
1.1
1.5
25.1 $
(0.2)
(0.6)
3.0
2.1
—
(1.1)
3.2
Accretion expense. The Company is required to record the estimated fair value of liabilities for obligations associated with the retirement
of tangible long-lived assets and the associated ARO costs. Interest is accreted on the present value of the ARO and reported as accretion
expense within operating expenses in the consolidated statements of operations.
Accretion expense related to our ARO increased 45% for the year ended December 31, 2016 compared to the same period of 2015.
Accretion expense generally correlates with the Company’s average ARO, which was $5.6 million at December 31, 2016 versus $5.4
million at December 31, 2015. See Note 12 in the Footnotes to the Financial Statements for additional information regarding the
Company’s ARO.
Accretion expense related to our ARO decreased 20% for the year ended December 31, 2015 compared to the same period of 2014.
Accretion expense generally correlates with the Company’s average ARO, which was $5.4 million at December 31, 2015 versus $6.5
million at December 31, 2014.
Write-down of oil and natural gas properties. Under full cost accounting rules, the Company reviews the carrying value of its proved
oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated
depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows
from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related
tax effects (the full cost ceiling amount). These rules require pricing based on the preceding 12-months’ average oil and natural gas
prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and
natural gas properties exceeds the full cost ceiling.
For the year ended December 31, 2016, the Company recognized a write-down of oil and natural gas properties of $95.8 million as a
result of the ceiling test limitation, primarily driven by a 15% decrease in the 12-month average realized price of oil from $50.16 per
barrel as of December 31, 2015 to $42.75 per barrel as of December 31, 2016. For the year ended December 31, 2015, the Company
recognized a write-down of $208.4 million as a result of the ceiling test limitation, primarily driven by a 47% decrease in the 12-month
average realized price of oil from $94.99 per barrel as of December 31, 2014 to $42.75 per barrel as of December 31, 2015. If commodity
prices were to decline, we could incur additional ceiling test write-downs in the future. See Notes 2 and 13 in the Footnotes to the
Financial Statements for additional information.
Rig termination fee. For the year ended December 31, 2015, the Company recognized $3.1 million in expense related to the early
termination of the contract for its vertical rig. See Note 14 in the Footnotes to the Financial Statements for additional information.
Acquisition expense. Acquisition expense increased $3.6 million for the year ended December 31, 2016 compared to the same period
of 2015 and decreased $3.6 million for the year ended December 31, 2016 compared to the same period of 2014. Acquisition expense
is related to costs with respect to our acquisition efforts in the Permian Basin. See Note 3 in the Footnotes to the Financial Statements
for additional information regarding the Company’s acquisitions.
Gain on sale of other property and equipment. During 2014, the Company entered into an agreement to sell certain specialized deep
water equipment that resulted in a gain on the sale of other property and equipment of $1.1 million.
48
Other Income and Expenses and Preferred Stock Dividends
Management’s Discussion and Analysis of Financial Condition and Results of Operation
(in thousands)
Interest expense, net of capitalized amounts
Loss on early extinguishment of debt
(Gain) loss on derivative contracts
Other income, net
Total
Income tax (benefit) expense
Preferred stock dividends
(in thousands)
Interest expense, net of capitalized amounts
Gain on early extinguishment of debt
Gain on derivative contracts
Other income, net
Total
Income tax expense
Preferred stock dividends
2016
For the Year Ended December 31,
$ Change
2015
% Change
11,871 $
12,883
20,233
(637)
44,350 $
(14) $
(7,295)
21,111 $
—
(28,358)
(198)
(7,445)
(9,240)
12,883
48,591
(439)
(44)%
nm
(171)%
222%
38,474 $
(7,895)
(38,488)
600
(100)%
(8)%
2015
For the Year Ended December 31,
$ Change
2014
% Change
21,111 $
—
(28,358)
(198)
$
(7,445)
-
38,474 $
(7,895)
9,772
(151)
(31,736)
(515)
(22,630)
-
23,134 $
(7,895)
11,339
151
3,378
317
-
15,340
—
116%
nm
(11)%
(62)%
66%
nm
$
$
$
$
$
$
Interest expense, net of capitalized amounts. We finance a portion of our working capital requirements, capital expenditures and
acquisitions with borrowings under our Credit Facility or with term debt. We incur interest expense that is affected by both fluctuations
in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense, net of capitalized amounts. In
addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and
annual agency fees in interest expense. The amortization of deferred credit related to our 13% senior unsecured notes due 2016 (“13%
Senior Notes”) was recorded as an offset to interest expense until the notes were redeemed in April 2014.
Interest expense, net of capitalized amounts, incurred during the year ended December 31, 2016 decreased $9.2 million to $11.9 million
compared to $21.1 million for the same period of 2015. The decrease is primarily attributable to a $9.4 million increase in capitalized
interest compared to the 2015 period, resulting from a higher average unevaluated property balance for the year ended December 31,
2016 as compared to the same period of 2015. The increase in unevaluated property was primarily due to acquired properties (see Note
3 in the Footnotes to the Financial Statements for information about the Company’s acquisitions). Offsetting the decrease was a $0.2
million increase in interest expense related to our debt due to a higher average debt balance for the year ended December 31, 2016 as
compared to the same period of 2015, resulting from the issuance of our 6.125% Senior Notes in November 2016.
Interest expense incurred during the year ended December 31, 2015 increased $11.3 million to $21.1 million compared to $9.8 million
for the same period of 2014. The increase is primarily attributable to the $18.8 million increase in expense related to a higher outstanding
average debt balance of $372.3 million in 2015 compared to $174.0 million in 2014. Offsetting the increase is a $6.2 million increase
in capitalized interest compared to the 2014 period, resulting from a higher average unevaluated property balance for the year ended
December 31, 2015 as compared to the same period of 2014, and a $1.3 million decrease in interest expense related to the full redemption
of our 13% Senior Notes in April 2014.
Gain (loss) on the early extinguishment of debt. During October 2016, the Second Lien Loan was repaid in full at the prepayment rate
of 101% using proceeds from the sale of the 6.125% senior unsecured notes due 2024, which resulted in a loss on early extinguishment
of debt of $12.9 million (inclusive of $3.0 million in prepayment fees and $9.9 million of unamortized debt issuance costs).
During April 2014, the Company completed a full redemption of the remaining $53.3 million carrying value of its outstanding 13%
Senior Notes using proceeds from the issuance of a secured second lien term loan. The carrying value included $48.5 million of principal
value and $4.8 million of unamortized deferred credit. The Company recognized a net $3.2 million gain on early extinguishment of debt,
comprised of the recognition of $4.8 million in deferred credit, offset by $1.6 million of redemption expenses. See Note 5 for additional
information concerning the gain on early extinguishment of debt.
During October 2014, the Company repaid in full the existing term loan using proceeds from the Second Lien Loan resulting in a loss
on early extinguishment of debt of $3.1 million. The loss was comprised of a $1.7 million prepayment premium and the recognition of
49
Management’s Discussion and Analysis of Financial Condition and Results of Operation
$1.4 million of unamortized issuance costs. See Note 5 for additional information concerning the loss on the early extinguishment of
debt.
Gain (loss) on derivative instruments. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in
commodity prices. This amount represents the (i) gain (loss) related to fair value adjustments on our open derivative contracts and (ii)
gains (losses) on settlements of derivative contracts for positions that have settled within the period.
For the year ended December 31, 2016, the net loss on derivative instruments was $20.2 million, compared to a $28.4 million net gain
in 2015. The net gain (loss) on derivative instruments for the periods indicated includes the following (in millions):
Natural gas derivatives
Net gain on settlements
Net loss on fair value adjustments
Total gain (loss)
Oil derivatives
Net gain on settlements
Net loss on fair value adjustments
Total gain (loss)
Total gain (loss) on derivative contracts
$
$
$
$
$
2016
For the Year Ended December 31,
2015
$ Change
0.1 $
(0.6)
(0.5) $
17.8 $
(37.5)
(19.7) $
(20.2) $
1.7 $
(1.2)
0.5 $
33.3 $
(5.4)
27.9 $
28.4 $
(1.6)
0.6
(1.0)
(15.5)
(32.1)
(47.6)
(48.6)
For the year ended December 31, 2015, the net gain on derivative instruments was $28.4 million, compared to a $31.7 million net gain
in 2014. The net gain (loss) on derivative instruments for the periods indicated includes the following (in millions):
Natural gas derivatives
Net gain (loss) on settlements
Net gain (loss) on fair value adjustments
Total gain
Oil derivatives
Net loss on settlements
Net gain (loss) on fair value adjustments
Total gain
Total gain on derivative contracts
$
$
$
$
$
2015
For the Year Ended December 31,
2014
$ Change
1.7 $
(1.2)
0.5 $
33.3 $
(5.4)
27.9 $
28.4 $
(0.1) $
1.3
1.2 $
4.1 $
26.4
30.5 $
31.7 $
1.8
(2.5)
(0.7)
29.2
(31.8)
(2.6)
(3.3)
See Notes 6 and 7 in the Footnotes to the Financial Statements for additional information on the Company’s derivative contracts and
disclosures related to derivative instruments.
Income tax expense. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities
are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the
tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities
are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled.
The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted.
When appropriate based on our analysis, we record a valuation allowance for deferred tax assets when it is more likely than not that the
deferred tax assets will not be realized.
The Company had an income tax benefit of less than $0.1 million for the year ended December 31, 2016 compared to an income tax
expense of $38.5 million for the same period of 2015. The change in income tax is primarily related to recording a valuation allowance
of $108.8 in 2015 and the difference in the amount of income (loss) before income taxes between periods. The effective tax rate of 0%
in 2016 and (19)% in 2015 differed from the federal income tax rate of 35% primarily due to the valuation allowance for the comparative
periods, the effect of state taxes, and non-deductible executive compensation expenses.
The Company had an income tax expense of $38.5 million for the year ended December 31, 2015 compared to an income tax expense
of $23.1 million for the same period of 2014. The increase in income tax expense is primarily related to the establishment of a valuation
50
Management’s Discussion and Analysis of Financial Condition and Results of Operation
allowance of $108.8 million in 2015 and the difference in the amount of income (loss) before income taxes between periods. The
effective tax rate of (19)% in 2015 and 38% in 2014 differed from the federal income tax rate of 35% primarily due to the valuation
allowance established in 2015, the effect of state, taxes, and non-deductible executive compensation expenses.
For additional information, see Note 11 to the Consolidated Financial Statements.
Preferred stock dividends. Preferred stock dividends for the year ended December 31, 2016 decreased $0.6 million compared to the
same period of 2015. The decrease was due to a decrease in the number of preferred shares outstanding, attributable to a partial share
conversion in February 2016 in which the Company exchanged a total of 120,000 shares of Preferred Stock for 719,000 shares of
common stock. Preferred stock dividends for the year ended December 31, 2015 were consistent with the same period of 2014. Dividends
reflect a 10% dividend yield. See Note 10 in the Footnotes to the Financial Statements for additional information.
Summary of Significant Accounting Policies and Critical Accounting Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements,
which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make
estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and
natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood
that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual
results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below
are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative
treatments under GAAP. We also describe the most significant estimates and assumptions we make in applying these policies. See Note
2 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K for a discussion of additional
accounting policies and estimates made by management.
Oil and natural gas properties
The Company utilizes the full cost method of accounting for its oil and natural gas properties whereby all costs incurred in connection
with the acquisition, exploration and development of oil and natural gas reserves, including certain overhead costs, are capitalized into
the “full cost pool.” The amounts capitalized into the full cost pool are depleted (charged against earnings) using the unit-of-production
method. The full cost method of accounting for oil and natural gas properties requires that the Company makes estimates based on its
assumptions of future events that could change. These estimates are described below.
Depreciation, depletion and amortization (DD&A) of oil and natural gas properties
The Company calculates DD&A by using the depletable base, which is equal to the net capitalized costs in our full cost pool plus
estimated future development costs, and the estimated net proved reserve quantities. Capitalized costs added to the full cost pool include
the following:
costs of drilling and equipping productive wells, dry hole costs, acquisition costs of properties with proved reserves, delay
rentals and other costs related to exploration and development of our oil and natural gas properties;
payroll costs including the related fringe benefits paid to employees directly engaged in the acquisition, exploration and/or
development of oil and natural gas properties as well as other directly identifiable general and administrative costs associated
with such activities. Such capitalized costs do not include any costs related to the production of oil and natural gas or general
corporate overhead;
costs associated with unevaluated properties, those lacking proved reserves, are excluded from the depletable base. These
unevaluated property costs are added to the depletable base at such time as wells are completed on the properties or management
determines these costs have been impaired. The Company’s determination that a property has or has not been impaired (which
is discussed below) requires assumptions about future events;
estimated costs to dismantle, abandon and restore properties that are capitalized to the full cost pool when the related liabilities
are incurred (see also the discussion below regarding Asset Retirement Obligations);
estimated future costs to develop proved properties are added to the full cost pool for purposes of the DD&A computation. The
Company uses assumptions based on the latest geologic, engineering, regulatory and cost data available to it to estimate these
amounts. However, the estimates made are subjective and may change over time. The Company’s estimates of future
development costs are reviewed at least annually and as additional information becomes available; and
capitalized costs included in the full cost pool plus estimated future development costs are depleted and charged against
earnings using the unit-of-production method. Under this method, the Company estimates the proved reserves quantities at the
beginning of each accounting period. For each BOE produced during the period, the Company records a DD&A charge equal
to the amount included in the depletable base (net of accumulated depreciation, depletion and amortization) divided by our
estimated net proved reserve quantities.
51
Management’s Discussion and Analysis of Financial Condition and Results of Operation
Because the Company uses estimates and assumptions to determine proved reserves (as discussed below) and the amounts included in
the depletable base, our depletion rates may materially change if actual results differ from these estimates.
Ceiling test
Under the full cost method of accounting, the Company compares, at the end of each financial reporting period, the present value of
estimated future net cash flows from proved reserves (excluding cash flows related to estimated abandonment costs and the value of
commodity derivative instruments) plus the lower of cost or fair value of unevaluated properties, to the net capitalized costs of proved
oil and natural gas properties net of related deferred taxes. The Company refers to this comparison as a “ceiling test.” If the net capitalized
costs of proved oil and natural gas properties exceed the estimated discounted (at a 10% annualized rate) future net cash flows from
proved reserves plus the lower of cost or fair value of unevaluated properties, the Company is required to write-down the value of its oil
and natural gas properties to the value of the discounted cash flows. Estimated future net cash flows from proved reserves are based on
a twelve-month average pricing assumption. Given the volatility of oil and natural gas prices, it is reasonably possible that the
Company’s estimates of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. For
the periods ended December 31, 2016 and 2015 the Company recognized a write-down of oil and natural gas properties of $95.8 and
$208.4, respectively, as a result of the ceiling test limitation. If oil and natural gas prices were to decline, even if only for a short period
of time, we could incur additional write-downs of oil and natural gas properties in the future. See Notes 2 and 13 in the Footnotes to the
Financial Statements for additional information regarding the Company’s oil and natural gas properties.
Estimating reserves and present value of estimated future net cash flows
Estimates of quantities of proved oil and natural gas reserves, including the discounted present value of estimated future net cash flows
from such reserves at the end of each quarter, are based on numerous assumptions, which are likely to change over time. These
assumptions include:
the prices at which the Company can sell its oil and natural gas production in the future. Oil and natural gas prices are volatile,
but we are required to assume that they remain constant, using the twelve-month average pricing assumption. In general, higher
oil and natural gas prices will increase quantities of proved reserves and the present value of estimated future net cash flows
from such reserves, while lower prices will decrease these amounts; and
the costs to develop and produce the Company’s reserves and the costs to dismantle its production facilities when reserves are
depleted. These costs are likely to change over time, but we are required to assume that they remain constant. Increases in costs
will reduce estimated oil and natural gas quantities and the present value of estimated future net cash flows, while decreases in
costs will increase such amounts.
Changes in these prices and/or costs will affect the present value of estimated future net cash flows more than the estimated quantities
of oil and natural gas reserves for the Company’s properties that have relatively short productive lives. If oil and natural gas prices
remain at current levels or decline further, it will have a negative impact on the present value of estimated future net cash flows and the
estimated quantities of oil and natural gas reserves.
In addition, the process of estimating proved oil and natural gas reserves requires that the Company’s independent and internal reserve
engineers exercise judgment based on available geological, geophysical and technical information. We have described the risks
associated with reserve estimation and the volatility of oil and natural gas prices under “Risk Factors.”
Sales of oil and natural gas properties are accounted for as adjustments to the net full cost pool with no gain or loss recognized unless
the adjustment would significantly alter the relationship between capitalized costs and proved reserves.
Unproved properties
Costs, including capitalized interest, associated with properties that do not have proved reserves are excluded from the depletable base,
and are included in the line item “Unevaluated properties.” Unevaluated property costs are transferred to the depletable base when wells
are completed on the properties or management determines that these costs have been impaired. In addition, the Company is required to
determine whether its unevaluated properties are impaired and, if so, include the costs of such properties in the depletable base. We
assess properties on an individual basis or as a group. The Company considers the following factors, among others: exploration program
and intent to drill, remaining lease term, and the assignment of proved reserves. This determination may require the exercise of
substantial judgment by management.
Asset retirement obligations
We are required to record our estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-life
assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligations and reported
as accretion expense within operating expenses in the Consolidated Statements of Operations. See Note 12 in the Footnotes to the
Financial Statements for additional information.
52
Management’s Discussion and Analysis of Financial Condition and Results of Operation
Derivatives
To manage oil and natural gas price risk on a portion of our planned future production, we have historically utilized commodity
derivative instruments (including collars, swaps, put and call options and other structures) on approximately 40% to 60% of our projected
production volumes in any given year. We do not use these instruments for trading purposes. Settlements of derivative contracts are
generally based on the difference between the contract price and prices specified in the derivative instrument and a NYMEX price or
other cash or futures index price.
Our derivative positions are carried at their fair value on the balance sheet with changes in fair value recorded through earnings. The
estimated fair value of our derivative contracts is based upon current forward market prices on NYMEX and in the case of collars and
floors, the time value of options. For additional information regarding derivatives and their fair values, see Notes 6 and 7 in the Footnotes
to the Financial Statements and Part II, Item 7A Commodity Price Risk.
Income taxes
The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We
recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We
routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized
deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our
deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the
deferred tax assets will not be realized. Numerous judgments and assumptions are inherent in the determination of future taxable income,
including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). We had a valuation
allowance of $140.2 million as of December 31, 2016. See Note 11 in the Footnotes to the Financial Statements for additional
information regarding Income Taxes.
Accounting Standards Updates (“ASU”)
See Note 2 in the Footnotes to the Financial Statements for additional information regarding ASUs.
Off-balance Sheet Arrangements
We had no off-balance sheet arrangements as of December 31, 2016.
53
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We
address these risks through a program of risk management including the use of derivative instruments.
Commodity price risk
The Company’s revenues are derived from the sale of its oil and natural gas production. The prices for oil and natural gas remain
extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions,
economic conditions and government actions. From time to time, the Company enters into derivative financial instruments to manage
oil and natural gas price risk, related both to NYMEX benchmark prices and regional basis differentials. The total volumes which we
hedge through use of our derivative instruments varies from period to period; however, generally our objective is to hedge approximately
40% to 60% of our anticipated internally forecast production for the next 12 to 24 months, subject to the covenants under our Credit
Facility. Our hedge policies and objectives may change significantly with movements in commodities prices or futures prices, in addition
to modification of our capital spending plans related to operational activities and acquisitions.
The Company’s hedging portfolio, linked to NYMEX benchmark pricing, covers approximately 3,755 MBbls and 2,920 BBtu of our
expected oil and natural gas production, respectively, for calendar year 2017. We also have commodity hedging contracts linked to
Midland WTI basis differentials relative to Cushing covering approximately 2,004 MBbls of our expected oil production for calendar
year 2017. See Note 6 in the Footnotes to the Financial Statements for a description of the Company’s outstanding derivative contracts
at December 31, 2016, and derivative contracts established subsequent to that date.
The Company may utilize fixed price swaps, which reduce the Company’s exposure to decreases in commodity prices and limit the
benefit the Company might otherwise have received from any increases in commodity prices. Swap contracts may also be enhanced by
the simultaneous sale of call or put options to effectively increase the effective swap price as a result of the receipt of premiums from
the option sales.
The Company may utilize price collars to reduce the risk of changes in oil and natural gas prices. Under these arrangements, no payments
are due by either party as long as the applicable market price is above the floor price (purchased put option) and below the ceiling price
(sold call option) set in the collar. If the price falls below the floor, the counter-party to the collar pays the difference to the Company,
and if the price rises above the ceiling, the counterparty receives the difference from the Company. Additionally, the Company may sell
put (or call) options at a price lower than the floor price (or higher than the ceiling price) in conjunction with a collar (three-way collar)
and use the proceeds to increase either or both the floor or ceiling prices. In a three-way collar, to the extent that realized prices are
below the floor price of the sold put option (or above the ceiling price of the sold call option), the Company’s net realized benefit from
the three-way collar will be reduced on a dollar-for-dollar basis.
The Company may purchase put and call options, which reduce the Company’s exposure to decreases in oil and natural gas prices while
allowing realization of the full benefit from any increases in oil and natural gas prices. If the price falls below the floor, the counterparty
pays the difference to the Company.
The Company enters into these various agreements from time to time to reduce the effects of volatile oil and natural gas prices and does
not enter into derivative transactions for speculative purposes. Presently, none of the Company’s derivative positions are designated as
hedges for accounting purposes.
Interest rate risk
The Company is subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility.
Though we had no balance outstanding on our Credit Facility at December 31, 2016, based on a notional amount of $10 million
outstanding under the facility, an increase or decrease of 1% in the interest rate would have a corresponding increase or decrease in our
annual net income of approximately $0.1 million. See Note 5 in the Footnotes to the Financial Statements for more information on the
Company’s interest rates on our Credit Facility.
Counterparty and customer credit risk
The Company’s principal exposures to credit risk are through receivables from the sale of our oil and natural gas production, joint
interest receivables and receivables resulting from derivative financial contracts.
The Company markets its oil and natural gas production to energy marketing companies. We are subject to credit risk due to the
concentration of our oil and natural gas receivables with several significant customers. For the year ended December 31, 2016, three
purchasers accounted for more than 10% of our revenue: Enterprise Crude Oil, LLC (43%); Shell Trading Company (18%); and Plains
Marketing, L.P. (16%). We do not require any of our customers to post collateral, and the inability of our significant customers to meet
54
their obligations to us or their insolvency or liquidation may adversely affect our financial results. At December 31, 2016 our total
receivables from the sale of our oil and natural gas production were approximately $47.4 million.
Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our
wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these
entities will participate in our wells. At December 31, 2016 our joint interest receivables were approximately $20.6 million.
At December 31, 2016 our receivables resulting from derivative contracts were approximately $0.3 million. Our oil and natural gas
derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. Most of the counterparties on our
derivative instruments currently in place are lenders under our Credit Facility. We are likely to enter into additional derivative
instruments with these or other lenders under our Credit Facility, representing institutions with investment grade ratings. We have
existing International Swap Dealers Association Master Agreements (“ISDA Agreements”) with our derivative counterparties. The
terms of the ISDA Agreements provide us and the counterparties with rights of offset upon the occurrence of defined acts of default by
either us or a counterparty to a derivative, whereby the party not in default may offset all derivative liabilities owed to the defaulting
party against all derivative asset receivables from the defaulting party. At December 31, 2016 we had a net derivative asset position of
$18.2 million.
55
ITEM 8. Financial Statements and Supplementary Data
Reports of Independent Registered Public Accounting Firms
Consolidated Balance Sheets as of December 31, 2016 and 2015
Consolidated Statements of Operations for Each of the Three Years in the Period Ended December 31, 2016
Consolidated Statements of Stockholders’ Equity for Each of the Three Years in the Period Ended December 31, 2016
Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2016
Notes to Consolidated Financial Statements
Page
57
59
60
61
62
63
56
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Callon Petroleum Company
We have audited the accompanying consolidated balance sheet of Callon Petroleum Company (a Delaware corporation) and subsidiaries
(the “Company”) as of December 31, 2016, and the related consolidated statements of operations, stockholders’ equity, and cash flows
for the year ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of
Callon Petroleum Company and subsidiaries as of December 31, 2016, and the results of their operations and their cash flows for the
year ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the
Company’s internal control over financial reporting as of December 31, 2016, based on criteria established in the 2013 Internal Control—
Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report
dated February 27, 2017 expressed an unqualified opinion.
/s/GRANT THORNTON LLP
Houston, Texas
February 27, 2017
57
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of
Callon Petroleum Company
We have audited the accompanying consolidated balance sheet of Callon Petroleum Company as of December 31, 2015, and the related
consolidated statements of operations, stockholders’ equity and cash flows for each of the two years in the period ended December 31,
2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on
these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of
Callon Petroleum Company as of December 31, 2015, and the consolidated results of its operations and its cash flows for each of the
two years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.
New Orleans, Louisiana
March 2, 2016
/s/Ernst & Young LLP
58
Part I. Financial Information
Item I. Financial Statements
Callon Petroleum Company
Consolidated Balance Sheets
(in thousands, except par and per share values and share data)
December 31, 2016 December 31, 2015
$
$
$
ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable
Fair value of derivatives
Other current assets
Total current assets
Oil and natural gas properties, full cost accounting method:
Evaluated properties
Less accumulated depreciation, depletion, amortization and impairment
Net evaluated oil and natural gas properties
Unevaluated properties
Total oil and natural gas properties
Other property and equipment, net
Restricted investments
Deferred financing costs related to the senior secured revolving credit facility
Acquisition deposit
Other assets, net
Total assets
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities
Accrued interest
Cash-settleable restricted stock unit awards
Asset retirement obligations
Fair value of derivatives
Total current liabilities
Senior secured revolving credit facility
Secured second lien term loan, net of unamortized deferred financing costs
6.125% senior unsecured notes due 2024, net of unamortized deferred financing costs
Asset retirement obligations
Cash-settleable restricted stock unit awards
Deferred tax liability
Fair value of derivatives
Other long-term liabilities
Total liabilities
Commitments and contingencies
Stockholders’ equity:
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference,
2,500,000 shares authorized: 1,458,948 and 1,578,948 shares outstanding, respectively
Common stock, $0.01 par value, 300,000,000 and 150,000,000 shares authorized;
201,041,320 and 80,087,148 shares outstanding, respectively
Capital in excess of par value
Accumulated deficit
Total stockholders’ equity
Total liabilities and stockholders’ equity
$
652,993 $
69,783
103
2,247
725,126
2,754,353
(1,947,673)
806,680
668,721
1,475,401
14,114
3,332
3,092
46,138
384
2,267,587 $
95,577 $
6,057
8,919
2,729
18,268
131,550
—
—
390,219
3,932
8,071
90
28
295
534,185
1,224
39,624
19,943
1,461
62,252
2,335,223
(1,756,018)
579,205
132,181
711,386
7,700
3,309
3,642
—
305
788,594
70,970
5,989
10,128
790
—
87,877
40,000
288,565
—
4,317
4,877
—
—
200
425,836
15
16
2,010
2,171,514
(440,137)
1,733,402
2,267,587 $
801
702,970
(341,029)
362,758
788,594
The accompanying notes are an integral part of these consolidated financial statements.
59
Callon Petroleum Company
Consolidated Statements of Operations
(in thousands, except per share data)
For the Year Ended December 31,
2016
2015
2014
Operating revenues:
Oil sales
Natural gas sales
Total operating revenues
Operating expenses:
Lease operating expenses
Production taxes
Depreciation, depletion and amortization
General and administrative
Accretion expense
Write-down of oil and natural gas properties
Rig termination fee
Gain on sale of other property and equipment
Acquisition expense
Total operating expenses
Income (loss) from operations
Other (income) expenses:
Interest expense, net of capitalized amounts
(Gain) loss on early extinguishment of debt
(Gain) loss on derivative contracts
Other income
Total other (income) expense
Income (loss) before income taxes
Income tax (benefit) expense
Net income (loss)
Preferred stock dividends
Income (loss) available to common stockholders
Income (loss) per common share:
Basic
Diluted
$
177,652 $
23,199
200,851
125,166 $
12,346
137,512
38,353
11,870
71,369
26,317
958
95,788
—
—
3,673
248,328
(47,477)
11,871
12,883
20,233
(637)
44,350
(91,827)
(14)
(91,813)
(7,295)
(99,108) $
(0.78) $
(0.78) $
27,036
9,793
69,249
28,347
660
208,435
3,075
—
27
346,622
(209,110)
21,111
—
(28,358)
(198)
(7,445)
(201,665)
38,474
(240,139)
(7,895)
(248,034) $
(3.77) $
(3.77) $
$
$
$
139,374
12,488
151,862
22,372
8,973
56,724
25,109
826
—
—
(1,080)
668
113,592
38,270
9,772
(151)
(31,736)
(515)
(22,630)
60,900
23,134
37,766
(7,895)
29,871
0.67
0.65
Shares used in computing income (loss) per common share:
Basic
Diluted
126,258
126,258
65,708
65,708
44,848
45,961
The accompanying notes are an integral part of these consolidated financial statements.
60
Callon Petroleum Company
Consolidated Statements of Stockholders’ Equity
(in thousands)
Balance at 12/31/2013
Net income
Shares issued pursuant to employee benefit plans
Restricted stock
Common stock issued
Preferred stock dividend
Balance at 12/31/2014
Net loss
Shares issued pursuant to employee benefit plans
Restricted stock
Common stock issued
Preferred stock dividend
Balance at 12/31/2015
Net loss
Shares issued pursuant to employee benefit plans
Restricted stock
Common stock issued
Preferred stock conversion
Preferred stock dividend
Balance at 12/31/2016
$
$
$
$
Preferred
Stock
Common
Stock
Capital in
Excess of Par
Retained
Earnings
(Deficit)
Total
Stockholders'
Equity
16 $
—
—
—
—
—
16 $
—
—
—
—
—
16 $
—
—
—
—
(1)
—
15 $
404 $
—
—
4
144
—
552 $
—
—
8
241
—
801 $
—
—
4
1,198
7
—
2,010 $
401,540 $
—
262
2,054
122,306
—
526,162 $
—
268
1,323
175,217
—
702,970 $
—
275
2,323
1,465,952
(6)
—
2,171,514 $
(122,866) $
37,766
—
—
—
(7,895)
(92,995) $
(240,139)
—
—
—
(7,895)
(341,029) $
(91,813)
—
—
—
—
(7,295)
(440,137) $
279,094
37,766
262
2,058
122,450
(7,895)
433,735
(240,139)
268
1,331
175,458
(7,895)
362,758
(91,813)
275
2,327
1,467,150
—
(7,295)
1,733,402
The accompanying notes are an integral part of these consolidated financial statements.
61
Callon Petroleum Company
Consolidated Statements of Cash Flows
(in thousands)
Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization
Write-down of oil and natural gas properties
Accretion expense
Amortization of non-cash debt related items
Amortization of deferred credit
Deferred income tax (benefit) expense
Net loss (gain) on derivatives, net of settlements
Gain on sale of other property and equipment
Non-cash (gain) loss on early extinguishment of debt
Non-cash expense related to equity share-based awards
Change in the fair value of liability share-based awards
Payments to settle asset retirement obligations
Changes in current assets and liabilities:
Accounts receivable
Other current assets
Current liabilities
Change in other long-term liabilities
Change in other assets, net
Payments to settle vested liability share-based awards related to early retirements
Payments to settle vested liability share-based awards
Net cash provided by operating activities
Cash flows from investing activities:
Capital expenditures
Acquisitions
Acquisition deposit
Proceeds from sales of mineral interest and equipment
Net cash used in investing activities
Cash flows from financing activities:
Borrowings on senior secured revolving credit facility
Payments on senior secured revolving credit facility
Borrowings on term loans
Payments on term loans
Issuance of 6.125% senior unsecured notes due 2024
Payment of deferred financing costs
Redemption of 13% senior notes due 2016
Issuance of common stock
Payment of preferred stock dividends
Net cash provided by financing activities
Net change in cash and cash equivalents
Balance, beginning of period
Balance, end of period
For the Year Ended December 31,
2015
2016
2014
$
(91,813) $
(240,139) $
37,766
73,072
95,788
958
3,115
—
(14)
38,135
—
9,883
558
6,953
(1,471)
(30,055)
(786)
25,288
96
(840)
—
(10,300)
118,567
(190,032)
(654,679)
(46,138)
24,562
(866,287)
217,000
(257,000)
—
(300,000)
400,000
(10,793)
—
1,357,577
(7,295)
1,399,489
651,769
1,224
652,993 $
69,891
208,435
660
3,123
—
38,474
6,658
—
—
221
6,612
(3,258)
(4,761)
(20)
8,001
80
338
(3,538)
(3,925)
86,852
(227,292)
(32,245)
—
377
(259,160)
181,000
(176,000)
—
—
—
—
—
175,459
(7,895)
172,564
256
968
1,224 $
58,014
—
826
1,272
(487)
23,134
(27,650)
(1,080)
(151)
1,126
3,936
(3,808)
(7,915)
622
12,805
(106)
(448)
(1,417)
(2,052)
94,387
(232,596)
(222,883)
—
2,978
(452,501)
132,500
(119,500)
382,500
(84,149)
—
(19,779)
(50,057)
122,450
(7,895)
356,070
(2,044)
3,012
968
$
The accompanying notes are an integral part of these consolidated financial statements.
62
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Description of Business and Basis of Presentation
9.
Share-Based Compensation
Summary of Significant Accounting Policies
2.
3. Acquisitions and Dispositions
4. Earnings (Loss) Per Share
5. Borrowings
10. Equity Transactions
11.
Income Taxes
12. Asset Retirement Obligations
13. Supplemental Information on Oil and Natural Gas Operations
6. Derivative Instruments and Hedging Activities
7.
8. Employee Benefit Plans
Fair Value Measurements
Note 1 - Description of Business and Basis of Presentation
Description of business
(Unaudited)
14. Other
15. Summarized Quarterly Financial Information (Unaudited)
Callon Petroleum Company is an independent oil and natural gas company established in 1950. The Company was incorporated under
the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a
consortium of European investors and an independent energy company partially owned by a member of current management. As used
herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless
the context requires otherwise.
Callon is focused on the acquisition, development, exploration and exploitation of unconventional onshore, oil and natural gas reserves
in the Permian Basin in West Texas. The Company’s operations to date have been predominantly focused on horizontal drilling of
several prospective intervals, including multiple levels of the Wolfcamp formation and, more recently, the Lower Spraberry shale in the
Midland Basin. Callon has assembled a multi-year inventory of potential horizontal well locations and intends to add to this inventory
through delineation drilling of emerging zones on its existing acreage and acquisition of additional locations through working interest
acquisitions, acreage purchases, joint ventures and asset swaps.
Basis of presentation
Unless otherwise indicated, all dollar amounts included within the Footnotes to the Financial Statements are presented in
thousands, except for per share and per unit data.
The Consolidated Financial Statements include the accounts of the Company, and its subsidiary, Callon Petroleum Operating Company
(“CPOC”). CPOC also has subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing, Inc. All intercompany
accounts and transactions have been eliminated. In the opinion of management, the accompanying audited consolidated financial
statements reflect all adjustments, including normal recurring adjustments and all intercompany account and transaction eliminations,
necessary to present fairly the Company’s financial position, the results of its operations and its cash flows for the periods
indicated. Certain prior year amounts may have been reclassified to conform to current year presentation.
Note 2 – Summary of Significant Accounting Policies
A. Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
B. Cash and Cash Equivalents
The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
C. Accounts Receivable
Accounts receivable consists primarily of accrued oil and natural gas production receivables and joint interest receivables from outside
working interest owners.
63
D. Revenue Recognition and Natural Gas Balancing
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
The Company recognizes revenue under the entitlements method of accounting. Under this method, revenue is deferred for deliveries
in excess of the Company’s net revenue interest, while revenue is accrued for the undelivered volumes. The revenue we receive from
the sale of NGLs is included in natural gas sales. Natural gas balancing receivables and payables were immaterial as of December 31,
2016 and 2015.
See the Accounting Standards Updates (“ASU”) section within this footnote for information about recently issued ASUs related to
Revenue Recognition.
E. Major Customers
The Company’s production is generally sold on month-to-month contracts at prevailing prices. The following table identifies customers
to whom it sold greater than 10% of its total oil and natural gas production during each of the years ended:
Enterprise Crude Oil, LLC
Shell Trading Company
Plains Marketing, L.P.
Permian Transport and Trading
Sunoco
Other
Total
For the Year Ended December 31,
2015
2016
2014
43%
18%
16%
—
—
23%
100%
42%
4%
19%
15%
9%
11%
100%
51%
—
22%
7%
10%
10%
100%
Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers
would not result in a material adverse effect on its ability to market future oil and natural gas production.
F. Oil and Natural Gas Properties
The Company uses the full cost method of accounting for its exploration and development activities. Under this method of accounting,
the cost of both successful and unsuccessful exploration and development activities are capitalized as oil and gas properties. Such
amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest
capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and
abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any
internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any
costs related to production, general corporate overhead or similar activities.
When applicable, proceeds from the sale or disposition of oil and natural gas properties are accounted for as a reduction to capitalized
costs through adjustments to accumulated depreciation, depletion, amortization and impairment unless the sale would significantly alter
the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized.
Historical and estimated future development costs of oil and natural gas properties, which have been evaluated and contain proved
reserves, as well as the historical cost of properties that have been determined to have no future economic value, are depleted using the
unit-of-production method based on proved reserves. Excluded from this amortization are costs associated with unevaluated properties,
including capitalized interest on such costs. Unevaluated property costs are transferred to evaluated property costs at such time as wells
are completed on the properties or the Company determines that these costs have been impaired. The Company assesses properties on
an individual basis or as a group and considers the following factors, among others, to determine if these costs have been impaired:
exploration program and intent to drill, remaining lease term, and the assignment of proved reserves.
Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under
these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred
income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted
at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full cost ceiling). These rules require
pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and
require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling. At December 31,
2016 and 2015, the average realized prices used in determining the estimated future net cash flows from proved reserves were $42.75
and $50.16 per barrel of oil, respectively, and $2.48 and $2.64 per Mcf of natural gas, respectively. For the periods ended December 31,
2016 and 2015, the Company recognized a write-down of oil and natural gas properties of $95,788 and $208,435, respectively, as a
result of the ceiling test limitation. See Notes 2 and 13 for additional information regarding the Company’s oil and natural gas properties.
64
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
Upon the acquisition or discovery of oil and natural gas properties, the Company estimates the future net costs to dismantle, abandon
and restore the property by using available geological, engineering and regulatory data. Such cost estimates are periodically updated
for changes in conditions and requirements. In accordance with asset retirement obligation guidance, such costs are capitalized to the
full cost pool when the related liabilities are incurred. In accordance with full cost accounting rules, assets recorded in connection with
the recognition of an asset retirement obligation are included as part of the costs subject to the full cost ceiling limitation. The future
cash outflows associated with settling the recorded asset retirement obligations are excluded from the computation of the present value
of estimated future net revenues used in determining the full cost ceiling amount.
G. Other Property and Equipment
The Company depreciates its other property and equipment using the straight-line method over estimated useful lives of three to 20
years. Depreciation expense of $793, $865 and $836 relating to other property and equipment was included in general and administrative
expenses in the Company’s consolidated statements of operations for the years ended December 31, 2016, 2015 and 2014,
respectively. The accumulated depreciation on other property and equipment was $15,227 and $14,719 as of December 31, 2016 and
2015, respectively. The Company reviews its other property and equipment for impairment when indicators of impairment exist. See
Note 14 for additional information.
H. Capitalized Interest
The Company capitalizes interest on unevaluated oil and gas properties. Capitalized interest cannot exceed gross interest expense.
During the years ended December 31, 2016, 2015 and 2014, the Company capitalized $19,857, $10,459 and $4,295 of interest expense.
I. Deferred Financing Costs
Deferred financing costs are stated at cost, net of amortization, and as a direct reduction from the debt’s carrying value on the balance
sheet. For revolving debt arrangements, deferred financing costs are stated at cost, net of amortization, as an asset on the balance sheet.
Amortization of deferred financing costs is computed using the straight-line method over the life of the loan. Amortization of deferred
financing costs of $3,115, $3,123 and $1,272 were recorded for the years ended December 31, 2016, 2015 and 2014, respectively.
J. Asset Retirement Obligations
The Company is required to record its estimate of the fair value of liabilities for obligations associated with the retirement of tangible
long-lived assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligations
and reported as accretion expense within operating expenses in the consolidated statements of operations. See Note 12 for additional
information.
K. Derivatives
Derivative contracts outstanding as of December 31, 2016 were not designated as accounting hedges, and are carried on the balance
sheet at fair value. Changes in the fair value of derivative contracts not designated as accounting hedges are reflected in earnings as a
gain or loss on derivative contracts. See Notes 6 and 7 for additional information regarding the Company’s derivative contracts.
L. Income Taxes
Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods
for oil and natural gas properties for financial reporting purposes and income tax purposes. GAAP requires the recognition of a deferred
tax asset for net operating loss carryforwards, statutory depletion carryforwards and tax credit carryforwards. A valuation allowance is
provided for that portion of deferred tax assets, if any, for which it is deemed more likely than not that it will not be realized. As of
December 31, 2016 the valuation allowance was $140,192. See Note 11 for additional information.
M. Share-Based Compensation
The Company grants to directors and employees stock options and restricted stock awards (“RS awards”). The Company also grants
restricted stock unit awards (“RSU awards”) that may be settled in cash or common stock at the option of the Company and RSU awards
that may only be settled in cash (“Cash-settleable RSU awards”).
Stock Options. For stock options the Company expects to settle in common stock, share-based compensation expense is based on the
grant-date fair value as calculated using the Black-Scholes option pricing model and recognized straight-line over the vesting period
(generally three years).
65
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
RS awards, RSU equity awards and Cash-settleable RSU awards. For RS and RSU equity awards that the Company expects to settle in
common stock, share-based compensation expense is based on the grant-date fair value and recognized straight-line over the vesting
period (generally three years). For RSU equity awards with vesting subject to a market condition, share-based compensation expense is
based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model with the estimated value
recognized over the vesting period (generally three years). For Cash-settleable RSU awards that the Company expects or is required to
settle in cash, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a
Monte Carlo pricing model, because vesting of these awards is subject to a market condition, with the estimated fair value recognized
over the vesting period (generally three years).
See the Accounting Standards Updates section within this footnote for information about recently issued ASUs related to Stock
Compensation.
N. Non-cash Investing and Supplemental Cash Flow Information
The following table sets forth the non-cash investing and supplemental cash flow information for the periods indicated:
Non-cash investing information:
Change in accrued capital expenditures
Supplemental cash flow information (a):
Cash paid for interest, net of capitalized interest
For the Years Ended December 31,
2014
2015
2016
$
$
(613) $
(16,813) $
12,850
8,679 $
17,978 $
2,988
(a) During the three year period ended 2016, the Company paid no federal income taxes.
O. Earnings per Share (“EPS”)
The Company’s basic EPS amounts have been computed based on the weighted-average number of shares of common stock outstanding
for the period. Diluted EPS, using the treasury-stock method, reflects the potential dilution caused by the exercise of options and vesting
of restricted stock and RSUs settleable in shares.
P. Accounting Standards Updates (“ASU”)
Recently Issued ASUs
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The standard requires an
entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the
consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will replace most of the
existing revenue recognition requirements in GAAP when it becomes effective. In August 2015, the FASB issued ASU No. 2015-14,
deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for annual periods beginning on or after
December 31, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact of the
standard; however, we do not believe the standard will have a material impact on our financial statements and related disclosures.
In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers – Principal versus Agent Considerations
(Reporting Revenue Gross versus Net). Under this update, an entity should recognize revenue to depict the transfer of promised goods
or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those
goods or services. This update will be effective for annual an interim reporting periods beginning after December 15, 2017, with early
application not permitted. This update allows for either full retrospective adoption or modified retrospective adoption. The Company is
currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements.
In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers – Identifying Performance Obligations and
Licensing. This update clarifies two principles of Accounting Standards Codification Topic 606: identifying performance obligations
and the licensing implementation guidance. This update will be effective for annual an interim reporting periods beginning after
December 15, 2017, with early application not permitted. The Company is currently evaluating the impact of its pending adoption of
this guidance on its consolidated financial statements.
In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers - Narrow-Scope Improvements and Practical
Expedients. This update applies only to the following areas from Accounting Standards Codification Topic 606: assessing the
collectability criterion and accounting for contracts that do not meet the criteria for step 1, presentation of sales taxes and other similar
taxes collected from customers, non-cash consideration, contract modification at transition, completed contracts at transition and
66
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
technical correction. This update will be effective for annual an interim reporting periods beginning after December 15, 2017, with early
application not permitted. The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated
financial statements.
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and
Cash Payments (“ASU 2016-15”). The objective of the standard is to reduce the existing diversity in practice of several cash flow issues,
including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with
coupon rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payment made after
a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life
insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial
interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle. The
guidance in ASU 2016-15 is effective for public entities for annual reporting periods beginning after December 15, 2017, including
interim periods therein. Early adoption is permitted and is to be applied on retrospective basis. The Company is currently evaluating the
method of adoption and impact this standard may have on its financial statements and related disclosures.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”). The standard requires all lease transactions
(with terms in excess of 12 months) to be recognized on the balance sheet as lease assets and lease liabilities. Public entities are required
to apply ASU 2016-02 for annual and interim reporting periods beginning after December 15, 2018 with early adoption permitted. The
Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements.
In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee
Share-Based Payment Accounting (“ASU 2016-09”). The standard is intended to simplify several aspects of the accounting for share-
based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and
classification on the statement of cash flows, and will allow companies to estimate the number of stock awards expected to vest. The
guidance in ASU 2016-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including
interim periods therein. The Company is currently evaluating the method of adoption and impact this standard may have on its financial
statements and related disclosures.
In December 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topics 230): Restricted Cash (“ASU 2016-18”). The
objective of the standard is to require the change during the period in total restricted cash and cash equivalents to be included with cash
and cash equivalents when reconciling the beginning-of-period and the end-of-period total amounts shown on the statement of cash
flows. The Company is currently evaluating the method of adoption and impact this standard may have on its financial statements and
related disclosures.
Recently Adopted ASUs
In November 2015, the FASB issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”), which
eliminates the current requirement to present deferred tax liabilities and assets as current and noncurrent amounts on the balance sheet.
Instead, entities will be required to classify all deferred tax assets and liabilities as noncurrent on the balance sheet. The guidance in
ASU 2015-17 is effective for public entities for annual reporting periods beginning after December 15, 2016, and interim periods within
those annual periods. As of December 31, 2016, the Company adopted this ASU, which did not have a material impact on its financial
statements.
Note 3 – Acquisitions and Dispositions
2016 acquisitions
On October 20, 2016, the Company completed the acquisition of 6,904 gross (5,952 net) acres primarily located in Howard County,
Texas from Plymouth Petroleum, LLC and additional sellers that exercised their “tag-along” sales rights, for total cash consideration of
$339,687, excluding customary purchase price adjustments (the “Plymouth Transaction”). The Company funded the cash purchase price
with the net proceeds of an equity offering (see Note 10 for additional information regarding the equity offering). The Company acquired
an 82% average working interest (62% average net revenue interest) in the properties acquired in the Plymouth Transaction. The
following table summarizes the estimated acquisition date fair values of the net assets acquired in the acquisition:
Evaluated oil and natural gas properties
Unevaluated oil and natural gas properties
Asset retirement obligations
Net assets acquired
$
$
65,043
274,664
(20)
339,687
67
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
On May 26, 2016, the Company completed the acquisition of 17,298 gross (14,089 net) acres primarily located in Howard County,
Texas from BSM Energy LP, Crux Energy LP and Zaniah Energy LP, for total cash consideration of $220,000 and 9,333,333 shares of
common stock (at an assumed offering price of $11.74 per share, which is the last reported sale price of our common stock on the New
York Stock Exchange on that date) for a total purchase price of $329,573, excluding customary purchase price adjustments (the “Big
Star Transaction”). The Company acquired an 81% average working interest (61% average net revenue interest) in the properties
acquired in the Big Star Transaction. The following table summarizes the estimated acquisition date fair values of the net assets acquired
in the acquisition:
Evaluated oil and natural gas properties
Unevaluated oil and natural gas properties
Asset retirement obligations
Net assets acquired
$
$
96,194
233,387
(8)
329,573
The preliminary purchase price allocations are subject to change based on numerous factors, including the final adjusted purchase price
and the final estimated fair value of the assets acquired and liabilities assumed. Any such adjustments to the preliminary estimates of
fair value could be material.
During 2016, the Company also closed on various acquisitions in the Midland Basin for an aggregate total purchase price of
approximately $73,240, net of $23,045 in sales of working interest. The acquisitions included the purchase of additional working interest
and acreage in the Company’s existing core operating area.
2015 acquisitions
During 2015, the Company closed on an acquisition in the Midland Basin for an aggregate total purchase price of approximately $29,800.
The acquisition included the purchase of additional working interest in the Company’s existing core operating area.
2014 acquisitions
On October 8, 2014, the Company completed the acquisition of certain undeveloped acreage and producing oil and gas properties located
in Midland, Andrews, Ector and Martin Counties, Texas (the “Central Midland Basin Transaction”) for an aggregate cash purchase price
of $210,205 based on an effective date of May 1, 2014. The Company assumed operatorship of the properties on November 1, 2014,
and acquired a 62% working interest (46.5% net revenue interest) in the Central Midland Basin Transaction. The aggregate cash purchase
price was funded with a combination of the net proceeds from an equity offering of $122,450 and a portion of the proceeds from
borrowings under the Second Lien Loan. For additional information on the debt transactions and equity offering, see Notes 5 and 10,
respectively. The following purchase price allocation is based on management’s estimates of the fair value of the assets acquired and
liabilities assumed. The following table summarizes the acquisition date fair values of the net assets acquired:
Evaluated oil and natural gas properties
Unevaluated oil and natural gas properties
Asset retirement obligations
Net assets acquired
$
$
91,895
118,450
(140)
210,205
During 2014, the Company also closed on various acquisitions in the Midland Basin for an aggregate total purchase price of
approximately $8,200. The acquisitions included the purchase of additional working interest and acreage in the Company’s existing core
operating area.
68
Unaudited pro forma financial statements
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
The following unaudited summary pro forma financial information for the periods presented is for illustrative purposes only and does
not purport to represent what the Company’s results of operations would have been if the Big Star Transaction, Plymouth Transaction
and Central Midland Basin Transaction had occurred as presented, or to project the Company’s results of operations for any future
periods:
Twelve Months Ended December 31,
2015 (a)
2016 (a)
2014 (b)
Revenues
Income (loss) from operations
Income (loss) available to common stockholders
Net income (loss) per common share:
Basic
Diluted
$
$
$
225,326 $
(41,094)
(85,240)
168,506 $
(131,435)
(153,735)
180,458
53,526
33,674
(0.68) $
(0.68) $
(1.18) $
(1.18) $
0.57
0.56
(a) The pro forma financial information was prepared assuming the Big Star Transaction and Plymouth Transaction occurred as of January 1,
2015.
(b) The pro forma financial information was prepared assuming the Central Midland Basin Transaction occurred as of January 1, 2013.
The pro forma adjustments are based on available information and certain assumptions that management believes are reasonable,
including revenue, lease operating expenses, production taxes, depreciation, depletion and amortization expense, accretion expense,
interest expense and capitalized interest.
The properties associated with the Big Star Transaction, the Plymouth Transaction and the Central Midland Basin Transaction have been
comingled with our existing properties and it is impractical to provide the stand-alone operational results related to these properties.
Subsequent event
On February 13, 2017, the Company completed the acquisition of 27,552 gross (16,688 net) acres in the Delaware Basin, primarily
located in Ward and Pecos Counties, Texas from American Resource Development, LLC, for total cash consideration of $633,000,
excluding customary purchase price adjustments (the “Ameredev Transaction”). The Company funded the cash purchase price with the
net proceeds of an equity offering (see Note 10 for additional information regarding the equity offering). The Company acquired an
82% average working interest (75% average net revenue interest) in the properties acquired in the Ameredev Transaction. In December
2016, in connection with the execution of the purchase and sale agreement for the Ameredev Transaction, the Company paid a deposit
in the amount of $46,138 to a third party escrow agent, which was recorded as Acquisition deposit on the balance sheet as of December
31, 2016.
69
Note 4 - Earnings Per Share
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
Basic earnings (loss) per share is computed by dividing income (loss) available to common stockholders by the weighted average number
of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact
of non-vested restricted shares and unexercised options outstanding during the periods presented, as calculated using the treasury stock
method, unless their effect is anti-dilutive. The following table sets forth the computation of basic and diluted earnings per share:
Net income (loss)
Preferred stock dividends
Income (loss) available to common stockholders
$
2016
(91,813) $ (240,139) $
For the Year Ended December 31,
2014
37,766
(7,895)
29,871
(99,108) $ (248,034) $
(7,895)
(7,295)
2015
$
Weighted average shares outstanding
Dilutive impact of restricted stock
Weighted average shares outstanding for diluted income (loss) per share (a)
126,258
—
126,258
65,708
—
65,708
44,848
1,113
45,961
Basic income (loss) per share
Diluted income (loss) per share
Stock options (b)
Restricted stock (b)
$
$
(0.78) $
(0.78) $
(3.77) $
(3.77) $
15
—
15
126
0.67
0.65
30
317
(a) Because the Company reported a loss available to common stockholders for the years ended December 31, 2016, and 2015, no unvested
stock awards were included in computing loss per share because the effect was anti-dilutive.
(b) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.
Note 5 – Borrowings
The Company’s borrowings consisted of the following at:
Principal components:
Senior secured revolving credit facility
Secured second lien term loan
6.125% senior unsecured notes due 2024
Total principal outstanding
Secured second lien term loan, unamortized deferred financing costs
6.125% senior unsecured notes due 2024, unamortized deferred financing costs
Total carrying value of borrowings
$
$
Credit Facility
December 31,
2016
2015
— $
—
400,000
400,000
—
(9,781)
390,219 $
40,000
300,000
—
340,000
(11,435)
—
328,565
On March 11, 2014, the Company entered into the Fifth Amended and Restated Credit Agreement to the Credit Facility with a maturity
date of March 11, 2019. JPMorgan Chase Bank, N.A. is Administrative Agent, and participants include several institutional lenders.
The total notional amount available under the Credit Facility is $500,000. Amounts borrowed under the Credit Facility may not exceed
the borrowing base, which is generally reviewed on a semi-annual basis. The Credit Facility is secured by first preferred mortgages
covering the Company’s major producing properties.
Effective July 13, 2016, the Credit Facility’s borrowing base was increased to $385,000 and the Company’s capacity to hedge oil and
natural gas volumes was effectively increased with a change in the capacity calculation to a percentage of total proved reserves from
proved producing reserves. In addition, the interest rate for borrowings under the Credit Facility was increased 0.25% across all tiers of
the pricing grid, resulting in a range of interest costs equal to LIBOR plus 2.00% to 3.00%. There were no modifications to other terms
or covenants of the Credit Facility.
Effective November 21, 2016, the Company achieved an indication to increase the Credit Facility’s borrowing base to $500,000, but
elected to maintain the borrowing base at $385,000. As of December 31, 2016, the Credit Facility’s borrowing base remained at
$385,000.
70
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
As of December 31, 2016, there was no balance outstanding on the Credit Facility. For the year ended December 31, 2016, the Credit
Facility had a weighted-average interest rate of 2.60%, calculated as the LIBOR plus a tiered rate ranging from 2.00% to 3.00%, which
is determined based on utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum, payable
quarterly, on the unused portion of the borrowing base.
Term loans
On March 11, 2014, the Company entered into a term loan in an aggregate amount of up to $125,000, including initial commitments of
$100,000 and additional availability of $25,000 subject to the consent of two-thirds of the lenders and compliance with financial
covenants after giving effect to such increase. The term loan had a maturity date of September 11, 2019, and was not subject to mandatory
prepayments unless new debt or preferred stock was issued. It was prepayable at the Company’s option, subject to a prepayment
premium. The prepayment amount was (i) 102% if the prepayment event occurred prior to March 11, 2015, and (ii) 101% if the
prepayment event occurred on or after March 15, 2015 but before March 15, 2016, and (iii) 100% for prepayments made on or after
March 15, 2016. The term loan was secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor
agreement.
On October 8, 2014, the term loan described above was repaid in full using proceeds from a new secured second lien term loan (the
“Second Lien Loan”) in conjunction with the closing of the Central Midland Acquisition, resulting in a loss on early extinguishment of
debt of $3,054. The Second Lien Loan has a maturity date of October 8, 2021. The Royal Bank of Canada is Administrative Agent, and
participants include several institutional lenders. Borrowings under the Second Lien Loan were subject to interest, calculated at a rate
of LIBOR (subject to a floor rate of 1.0%) plus 7.5% per annum. The Company elected a LIBOR rate based on various tenors, and was
incurring interest based on an underlying three-month LIBOR rate, which was last elected in July 2016. The Second Lien Loan may be
prepaid at the Company’s option, subject to a prepayment premium. The prepayment amount was (i) 102% of principal if the prepayment
event occurred prior to October 8, 2016, and (ii) 101% of principal if the prepayment event occurred on or after October 8, 2016 but
before October 8, 2017, and (iii) 100% of principal for prepayments made on or after October 8, 2017. The Second Lien Loan was
secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement.
On October 11, 2016, the Second Lien Loan was repaid in full at the prepayment rate of 101% using proceeds from the sale of the
6.125% senior unsecured notes due 2024, which resulted in a loss on early extinguishment of debt of $12,883 (inclusive of $3,000 in
prepayment fees and $9,883 of unamortized debt issuance costs).
6.125% senior notes due 2024 (“6.125% Senior Notes”)
On October 3, 2016, the Company issued $400,000 aggregate principal amount of 6.125% Senior Notes with a maturity date of October
1, 2024 and interest payable semi-annually beginning on April 1, 2017. The net proceeds of the offering, after deducting initial
purchasers’ discounts and estimated offering expenses, were approximately $391,270. The 6.125% Senior Notes are guaranteed on a
senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by
certain future subsidiaries.
The Company may redeem the 6.125% Senior Notes in accordance with the following terms; (1) prior to October 1, 2019, a redemption
of up to 35% of the principal in an amount not greater than the net proceeds from certain equity offerings, and within 180 days of the
closing date of such equity offerings, at a redemption price of 106.125% of principal, plus accrued and unpaid interest, if any, to the
date of the redemption, if at least 65% of the principal will remain outstanding after such redemption; (2) prior to October 1, 2019, a
redemption of all or part of the principal at a price of 100% of principal of the amount redeemed, plus an applicable make-whole premium
and accrued and unpaid interest, if any, to the date of the redemption; (3) a redemption, in whole or in part, at a redemption price, plus
accrued and unpaid interest, if any, to the date of the redemption, (i) of 104.594% of principal if the redemption occurs on or after
October 1, 2019, but before October 1, 2020, and (ii) of 103.063% of principal if the redemption occurs on or after October 1, 2020, but
before October 1, 2021, and (iii) of 101.531% of principal if the redemption occurs on or after October 1, 2021, but before October 1,
2022, and (iv) of 100% of principal if the redemption occurs on or after October 1, 2022.
Following a change of control, each holder of the 6.125% Senior Notes may require the Company to repurchase all or a portion of the
6.125% Senior Notes at a price of 101% of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of
repurchase.
13% senior notes due 2016 (“13% Senior Notes”) and deferred credit
On April 11, 2014, the Company completed a full redemption of the remaining $48,481 principal amount of outstanding 13% Senior
Notes using proceeds from the Second Lien Loan. The redemption resulted in a net $3,205 gain on the early extinguishment of debt
(including $4,780 of accelerated deferred credit amortization). The gain represents the difference between the $50,057 paid for the
redemption of the 13% Senior Notes ($1,576 of redemption costs, primarily the call premium) and the carrying value of the remaining
71
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
13% Senior Notes of $53,261 (inclusive of $4,780 of deferred credit). The Company also paid $193 in accrued interest through the
redemption date. Upon the redemption, the indenture governing the 13% Senior Notes was discharged in accordance with its terms.
Restrictive covenants
The Company’s Credit Facility and the indenture governing our 6.125% Senior Notes contain various covenants including restrictions
on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. The Company was in compliance
with these covenants at December 31, 2016.
Note 6 - Derivative Instruments and Hedging Activities
Objectives and strategies for using derivative instruments
The Company is exposed to fluctuations in oil and natural gas prices received for its production. Consequently, the Company believes
it is prudent to manage the variability in cash flows on a portion of its oil and natural gas production. The Company utilizes a mix of
collars, swaps, put and call options and similar derivative financial instruments to manage fluctuations in cash flows resulting from
changes in commodity prices. The Company does not use these instruments for speculative or trading purposes.
Counterparty risk and offsetting
The use of derivative instruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. While
the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’
creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in
counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its
derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject
to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative
instrument; see Note 7 for additional information regarding fair value.
The Company executes commodity derivative contracts under master agreements with netting provisions that provide for offsetting
assets against liabilities. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement,
the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement.
Financial statement presentation and settlements
Settlements of the Company’s derivative instruments are based on the difference between the contract price or prices specified in the
derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative
instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in
underlying markets. See Note 7 for additional information regarding fair value.
Derivatives not designated as hedging instruments
The Company records its derivative contracts at fair value in the consolidated balance sheets and records changes in fair value as a gain
or loss on derivative contracts in the consolidated statements of operations. Cash settlements are also recorded as gain or loss on
derivative contracts in the consolidated statements of operations.
The following table reflects the fair value of the Company’s derivative instruments for the periods presented:
Balance Sheet Presentation
Commodity Classification Line Description
Natural gas Current
Current
Oil
Non-current
Oil
Total
Fair value of derivatives $
Fair value of derivatives
Fair value of derivatives
$
Asset Fair Value
Liability Fair Value
12/31/2016 12/31/2015 12/31/2016 12/31/2015 12/31/2016 12/31/2015
—
(593) $
19,943
(17,675)
(28)
—
19,943
(18,296) $
— $
19,943
—
19,943 $
— $
103
—
103 $
— $
—
—
— $
(17,572)
(28)
Net Derivative Fair
(18,193) $
(593) $
Value
72
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
As previously discussed, the Company’s derivative contracts are subject to master netting arrangements. The Company’s policy is to
present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this
presentation to the Company’s recognized assets and liabilities for the periods indicated:
For the Year Ended December 31, 2016
Current assets: Fair value of derivatives
Current liabilities: Fair value of derivatives
Long-term liabilities: Fair value of derivatives
$
(20,001)
(28) $
Presented without
Effects of Netting
$
1,836 $
Effects of Netting
As Presented with
Effects of Netting
(1,733) $
1,733
— $
103
(18,268)
(28)
Current assets: Fair value of derivatives
For the Year Ended December 31, 2015
Presented without
Effects of Netting
$
19,943 $
Effects of Netting
As Presented with
Effects of Netting
— $
19,943
For the periods indicated, the Company recorded the following related to its derivatives in the consolidated statement of operations as
gain or loss on derivative contracts:
Natural gas derivatives
Net gain (loss) on settlements
Net gain (loss) on fair value adjustments
Total gain (loss)
Oil derivatives
Net gain on settlements
Net gain (loss) on fair value adjustments
Total gain (loss)
Total gain (loss) on derivative contracts
For the Year Ended December 31,
2015
2016
2014
$
$
$
$
$
102 $
(593)
(491) $
17,801 $
(37,543)
(19,742) $
1,717 $
(1,255)
462 $
33,299 $
(5,403)
27,896 $
(20,233) $
28,358 $
(84)
1,267
1,183
4,170
26,383
30,553
31,736
73
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
Derivative positions
Listed in the tables below are the outstanding oil and natural gas derivative contracts as of December 31, 2016:
Oil contracts
Swap contracts combined with short puts (WTI, enhanced swaps)
Total volume (MBbls)
Weighted average price per Bbl
Swap
Short put option
Deferred premium put option
Total volume (MBbls)
Premium per Bbl
Weighted average price per Bbl
Long put option
Deferred premium put spread option
Total volume (MBbls)
Premium per Bbl
Weighted average price per Bbl
Long put option
Short put option
Collar contracts (WTI, two-way collars)
Total volume (MBbls)
Weighted average price per Bbl
Ceiling (short call)
Floor (long put)
Call option contracts (short position)
Total volume (MBbls)
Weighted average price per Bbl
Call strike price
Swap contracts (Midland basis differential)
Volume (MBbls)
Weighted average price per Bbl
Natural gas contracts
Collar contracts combined with short puts (Henry Hub, three-way collars)
Total volume (BBtu)
Weighted average price per MMBtu
Ceiling (short call option)
Floor (long put option)
Short put option
Collar contracts (Henry Hub, two-way collars)
Total volume (BBtu)
Weighted average price per MMBtu
Ceiling (short call option)
Floor (long put option)
For the Full Year of
2017
For the Full Year of
2018
730
44.50 $
30.00 $
498
2.05 $
50.00 $
506
2.45 $
50.00 $
40.00 $
1,351
58.19 $
47.50 $
670
50.00 $
2,004
(0.52) $
1,460
3.71 $
3.00 $
2.50 $
1,460
3.68 $
3.00 $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,825
(1.02)
—
—
—
—
—
—
—
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
74
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
Subsequent event
The following derivative contracts were executed subsequent to December 31, 2016:
Oil contracts
Collar contracts combined with short puts (WTI, three-way collars)
Total volume (MBbls)
Weighted average price per Bbl
Ceiling (short call option)
Floor (long put option)
Note 7 - Fair Value Measurements
For the Remainder of For the Remainder of
2017
2018
$
$
—
— $
— $
2,738
62.84
50.00
The fair value hierarchy included in GAAP gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for
identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived
from inputs that are significant and unobservable, and these valuations have the lowest priority.
Fair Value of Financial Instruments
Cash, cash equivalents, and restricted investments. The carrying amounts for these instruments approximate fair value due to the short-
term nature or maturity of the instruments.
Debt. The carrying amount of the Company’s floating-rate debt approximated fair value because the interest rates were variable and
reflective of market rates.
Credit Facility (a)
Second Lien (a)
6.125% Senior Notes (b)
Total
2016
Carrying Value
$
— $
—
390,219
390,219 $
$
December 31,
2015
Fair Value
Carrying Value
Fair Value
— $
—
412,000
412,000 $
40,000 $
288,565
—
328,565 $
40,000
288,565
—
328,565
(a) Floating-rate debt.
(b) The fair value was based upon Level 2 inputs. See Note 5 for additional information about the Company’s 6.125% Senior Notes.
Assets and liabilities measured at fair value on a recurring basis
Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheet. The following methods and
assumptions were used to estimate fair value:
Commodity derivative instruments. The fair value of commodity derivative instruments is derived using an income approach valuation
model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value
calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default
risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative
instruments fall within Level 2 of the fair value hierarchy based on the wide availability of quoted market prices for similar commodity
derivative contracts. See Note 6 for additional information regarding the Company’s derivative instruments.
75
The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis:
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
December 31, 2016
Assets
Derivative financial instruments
Liabilities
Derivative financial instruments
Total net assets
December 31, 2015
Assets
Derivative financial instruments
Liabilities
Derivative financial instruments
Total net assets
Classification
Level
1
Level 2 Level 3 Total
Fair value of derivatives
$ — $
103 $ — $
103
Fair value of derivatives
— (18,296)
— (18,296)
$ — $ (18,193) $ — $ (18,193)
Classification
Level
1
Level 2 Level 3 Total
Fair value of derivatives
$ — $ 19,943 $ — $ 19,943
Fair value of derivatives
—
—
$ — $ 19,943 $ — $ 19,943
—
—
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Acquisitions. The Company determines the fair value of the assets acquired and liabilities assumed using the income approach based on
expected discounted future cash flows from estimated reserve quantities, costs to produce and develop reserves, and oil and natural gas
forward prices. The future net revenues are discounted using a weighted average cost of capital. The discounted future net revenues of
proved undeveloped and probable reserves are reduced by an additional reserve adjustment factor to compensate for the inherent risk of
estimating the value of unevaluated properties. The fair value measurements were based on Level 2 and Level 3 inputs.
Note 8 – Employee Benefit Plans
The Company utilizes various forms of incentive compensation designed to align the interest of the executives and employees with those
of its stockholders. Tabular disclosures related to the share-based awards are presented in Note 9. The narrative that follows provides a
brief description of each plan, summarizes the overall status of each plan and discusses current year awards under each plan:
Savings and Protection Plan
The Savings and Protection Plan (“401(k) Plan”) provides employees with the option to defer receipt of a portion of their compensation,
and the Company may, at its discretion, match a portion of the employee’s deferral with cash. The Company may also elect, at its
discretion, to contribute a non-matching amount in cash and Company common stock to employees. The amounts held under the 401(k)
Plan are invested in various funds maintained by a third party in accordance with the directions of each employee. An employee is fully
vested, including Company discretionary contributions, immediately upon participation in the 401(k) Plan. The total amounts
contributed by the Company, including the value of the common stock contributed, were $1,018, $999 and $1,017 in the years 2016,
2015 and 2014, respectively.
2011 Omnibus Incentive Plan (the “2011 Plan”)
The 2011 Plan, which became effective May 12, 2011 following shareholder approval, authorized and reserved for issuance 2,300,000
shares of common stock, which may be issued upon exercise of vested stock options and/or the vesting of any other share-based equity
award that is granted under this plan. The 2011 Plan is the Company’s only active plan, and included a provision at inception whereby
all remaining, un-issued and authorized shares from the Company’s previous share-based incentive plans became issuable under the
2011 Plan. This transfer provision resulted in the transfer of an additional 841,000 shares into the plan, increasing the quantity authorized
and reserved for issuance under the 2011 Plan to 3,141,000 at the inception of the plan. Another provision provided that shares, which
would otherwise become available for issuance under the previous plans as a result of vesting and/or forfeiture of any equity awards
existing as of May 12, 2012, would also increase the authorized shares available to the 2011 Plan.
At the 2015 Annual Meeting of Shareholders, the Company’s shareholders approved the First Amendment to the Callon Petroleum
Company 2011 Omnibus Incentive Plan (the “First Amendment”), which provided for (i) an increase in the number of shares of the
Company’s common stock available for grant under the Plan by 2,000,000 shares from 2,300,000 shares to 4,300,000 shares, (ii) the
adoption of a “double trigger” meaning that, in the event of a Company change in control, early vesting or payment occurs only if a
change in control occurs and the executive’s employment is terminated or constructively terminated, and (iii) the elimination of the
adding back of terminated options and stock appreciation rights shares for future grants. The First Amendment was made effective as of
May 14, 2015. Including the transfer provision mentioned above, the quantity authorized and reserved for issuance under the 2011 Plan
is 5,141,000 as of the effective date of the First Amendment. As of December 31, 2016, the 2011 Plan had 2,270,448 shares remaining
and eligible for future issuance.
76
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
RSU equity awards. RSU equity awards issued under this plan may be subject to various vesting, accelerated vesting, and forfeiture
provisions upon the occurrence of certain events. RSU equity awards under the 2011 Plan generally vest over time but may also be
subject to attaining a specified performance metrics and may vest immediately or cliff vest at a specified date. The Company will
recognize expense on the grant date for all immediately vesting awards, while it will recognize expense ratably over the requisite service
(i.e. vesting) period for both cliff and ratably vesting awards.
For market-based RSU equity awards, the Company recognizes expense based on the fair value of the awards at the grant date. Awards
with a market-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved
and no shares ultimately vest or are awarded. Market-based RSU equity awards that vest are based on a calculation that compares the
Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the
number of units that will vest can range between 0% and 200% of the base units awarded.
Cash-settled RSU awards. Certain of the Company’s RSUs awarded require cash settlement. Cash-settled RSU awards are accounted
for as liabilities as the Company is contractually obligated to settle these awards in cash. Changes in the fair value of cash-settleable
awards are recorded as adjustments to compensation expense.
A significant portion of the Company’s cash-settled RSU awards include a market-based vesting condition that determines the actual
number of units that will ultimately vest. The number of RSUs that vest is based on a calculation that compares the Company’s total
shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that
will vest can range between 0% and 200% of the base units awarded. The fair value of the Company’s market-based RSU awards is
calculated using a Monte Carlo valuation model, which considers such inputs as the Company’s and its peer group’s stock prices, a risk-
free interest rate, and an estimated volatility for the Company and its peer group.
Note 9 - Share-Based Compensation
As discussed in Note 8, the Company grants various forms of share-based compensation awards to employees of the Company and its
subsidiaries and to non-employee members of the Board of Directors. At December 31, 2016, shares available for future share-based
awards, including stock options or restricted stock grants, under the Company’s only active plan, the 2011 Plan, were 2,270,448.
The following table presents share-based compensation expense for each respective period:
2016
For the Year Ended December 31,
2015
2014
Share-based compensation cost for:
RSU equity awards
Cash-settleable RSU awards
401(k) contributions in shares
Total share-based compensation cost (a)
Equity-based
$
Liability-based Equity-based
— $
12,285
—
12,285 $
3,797 $
—
266
4,063 $
Liability-based Equity-based
— $
11,437
—
11,437 $
4,223 $
—
270
4,493 $
Liability-based
—
6,918
—
6,918
4,536 $
—
277
4,813 $
$
(a) The portion of this share-based compensation cost that was included in general and administrative expense totaled $9,722, $9,299 and $7,235
for the same years, respectively, and the portion capitalized to oil and gas properties was $7,376, $6,201 and $4,176, respectively.
The following table presents the unrecognized compensation cost for the indicated periods:
Unrecognized compensation cost related to:
Unvested RSU equity awards
Unvested cash-settleable RSU awards
2016
December 31,
2015
$
7,276 $
8,948
5,208 $
4,728
2014
3,979
4,977
The Company’s unrecognized compensation cost related to unvested RSU equity awards and cash-settleable RSU awards is expected
to be recognized over a weighted-average period of 2 years.
The following table summarizes the Company’s liability for cash-settled RSU awards for the periods indicated:
Consolidated Balance Sheets Classification
Cash-settled RSU awards (current)
Cash-settled RSU awards (non-current)
Total cash-settled RSU awards
December 31,
2016
2015
$
$
8,919 $
8,071
16,990 $
10,128
4,877
15,005
77
Stock Options
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
The Company issued no stock options for the past three years and had no options vest or forfeit during 2016. Additionally, no options
were exercised, and no options expired unexercised during the year. As of December 31, 2016, the Company had 15,000 options
outstanding and exercisable at a weighted average exercise price per option of $14.37, with no aggregate intrinsic value and with a
weighted-average remaining contract life per unit of 0.3 years. As of December 31, 2015, the Company had 15,000 options outstanding
and exercisable at a weighted average exercise price per option of $14.37, with no aggregate intrinsic value and with a weighted-average
remaining contract life per unit of 1.3 years. As of December 31, 2014, the Company had 30,000 options outstanding and exercisable at
a weighted average exercise price per option of $14.04, with no aggregate intrinsic value and with a weighted-average remaining contract
life per unit of 1.3 years.
Restricted Stock Units
The following table represents unvested restricted stock activity for the year ended December 31, 2016:
(shares in 000s)
Outstanding at the beginning of the period
Granted (a)
Vested (b)
Forfeited
Outstanding at the end of the period
Weighted average
Grant-Date Fair Value
per Share
Period over which
expense is expected to
be recognized
Number of Shares
1,416 $
684
(630)
(22)
1,448 $
6.94
12.63
4.14
9.56
10.81
1.6
(a) Includes 143 market-based RSUs that will vest at a range of 0% - 200%. See Note 8 for additional information about market-based RSU
equity awards.
(b) The fair value of shares vested was $2,608.
For the year ended December 31, 2015, the Company granted 559,556 RSUs with a weighted average grant-date fair value of $8.98 per
share. The fair value of shares vested during 2015 was $5,425. For the year ended December 31, 2014, the Company granted 333,468
RSUs with a weighted average grant-date fair value of $9.67 per share. The fair value of shares vested during 2014 was $4,338.
As of December 31, 2016, the Company had the following cash-settleable RSUs outstanding (including those that are not based on a
market condition):
(shares in 000s)
Vesting in 2017
Vesting in 2018
Vesting in 2019
Other
Total cash-settleable RSUs
Base Units
Outstanding
Potential
Minimum Units
Vesting
Potential
Maximum Units
Vesting
227
244
29
191
691
19
25
29
191
264
435
464
29
191
1,119
For the year ended December 31, 2016, 281,792 market-based cash-settled RSUs subject to the peer market-based vesting described in
Note 8 vested at 200% of their issued units, resulting in payable amounts of $8,662 in 2017. Also during 2016, 45,282 non-market-
based cash settled RSUs vested, resulting in cash payments of $493 in 2016. During 2015, 853,673 market-based cash-settled RSUs
subject to the peer market-based vesting described above vested at between 150% - 200% of their issued units, depending on the date
of the vesting, resulting in cash payments of $3,319 in 2015 and $9,807 in 2016. Also during 2015, 72,108 non-market-based cash
settled RSUs vested, resulting in cash payments of $545 in 2015. See Note 8 for additional information regarding cash-settleable RSUs.
Note 10 – Equity Transactions
10% Series A Cumulative Preferred Stock (“Preferred Stock”)
Holders of the Company’s Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds
legally available for the payment of dividends, cumulative cash dividends at a rate of 10.0% per annum of the $50.00 liquidation
preference per share (equivalent to $5.00 per annum per share). Dividends are payable quarterly in arrears on the last day of each March,
June, September and December when, as and if declared by our Board of Directors. Preferred Stock dividends were $7,295, $7,895 and
$7,895 in 2016, 2015 and 2014 respectively.
78
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. On or after May 30,
2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, by paying $50.00 per share, plus any accrued
and unpaid dividends to the redemption date.
Following a change of control in which the Company or the acquirer no longer have a class of common securities listed on a national
exchange, the Company will have the option to redeem the Preferred Stock, in whole but not in part for $50.00 per share in cash, plus
accrued and unpaid dividends (whether or not declared), to the redemption date. If the Company does not exercise its option to redeem
the Preferred Stock upon such change of control, the holders of the Preferred Stock have the option to convert the Preferred Stock into
a number of shares of the Company’s common stock based on the value of the common stock on the date of the change of control as
determined under the certificate of designations for the Preferred Stock. If the change of control occurred on December 31, 2016, and
the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $15.37 as the value of a share of common
stock, each share of Preferred Stock would be convertible into approximately 3.3 shares of common stock. If the Company exercises its
redemption rights relating to shares of Preferred Stock, the holders of Preferred Stock will not have the conversion right described above.
On February 4, 2016, the Company exchanged a total of 120,000 shares of Preferred Stock for 719,000 shares of common stock. As of
December 31, 2016, the Company had 1,458,948 shares of its Preferred Stock issued and outstanding.
Common Stock
On December 19, 2016, the Company completed an underwritten public offering of 40,000,000 shares of its common stock for total
estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $634,917. Proceeds from
the offering were used to substantially fund the Ameredev Transaction, described in Note 3.
On September 6, 2016, the Company completed an underwritten public offering of 29,900,000 shares of its common stock for total
estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $421,864. Proceeds from
the offering were used to substantially fund the Plymouth Transaction, described in Note 3.
On May 26, 2016, the Company issued 9,333,333 shares of common stock to partially fund the Big Star Transaction, described in Note
3, at an assumed offering price of $11.74 per share, which is the last reported sale price of our common stock on the New York Stock
Exchange on that date.
On April 25, 2016, the Company completed an underwritten public offering of 25,300,000 shares of its common stock for total net
proceeds (after the underwriter’s discounts and commissions and estimated offering expenses) of approximately $205,869. Proceeds
from the offering were used to fund the Big Star Transaction, described in Note 3, and other working interest acquisitions.
On March 9, 2016, the Company completed an underwritten public offering of 15,250,000 shares of its common stock for total net
proceeds (after the underwriting discounts and estimated offering costs) of approximately $94,948. Proceeds from the offering were
used to pay down the balance on the Company’s Credit Facility and for general corporate purposes.
On November 16, 2015, the Company completed an underwritten public offering of 12,000,000 shares of its common stock at $8.40 per
share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,800,000 additional shares
of common stock at $8.40 per share, before underwriting discounts. The Company received net proceeds of approximately $109,864,
after the underwriting discounts and estimated offering costs, which were used to repay amounts outstanding under the Credit Facility.
On March 13, 2015, the Company completed an underwritten public offering of 9,000,000 shares of its common stock at $6.55 per
share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,350,000 additional shares
of common stock at $6.55 per share, before underwriting discounts. The Company received net proceeds of approximately $65,595,
after the underwriting discounts and estimated offering costs, which were used to repay amounts outstanding under the Credit Facility.
On September 15, 2014 the Company completed an underwritten public offering of 12,500,000 shares of its common stock at $9.00 per
share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,875,000 additional shares
of common stock at $9.00 per share. The Company received net proceeds of approximately $122,450, after the underwriting discounts
and estimated offering costs, which were used to fund a portion of the purchase price of the Central Midland Basin Transaction, described
in Note 3.
79
Note 11 - Income Taxes
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
The following table presents Callon’s deferred tax assets and liabilities with respect to its carryforwards and other temporary differences:
Deferred tax asset
Federal net operating loss carryforward (a)
Statutory depletion carryforward
Alternative minimum tax credit carryforward
Asset retirement obligations
Derivatives
Unvested RSU equity awards
Other
Deferred tax asset before valuation allowance
Deferred tax liability
Oil and natural gas properties
Derivatives
Other
Total deferred tax liability
Net deferred tax asset before valuation allowance
Less: Valuation allowance
Net deferred tax liability
As of December 31,
2016
2015
135,711 $
8,843
104
1,181
6,456
2,092
4,376
158,763
18,661
—
—
18,661
140,102
(140,192)
(90) $
107,935
8,843
208
630
—
1,418
6,823
125,857
6,488
6,984
3,542
17,014
108,843
(108,843)
—
$
$
(a) The Company’s $135,711 deferred tax asset related to NOL carryforwards is net of $9,288 of unrealized excess tax benefits related to stock
based compensation.
If not utilized, the Company’s federal operating loss (“NOL”) carryforwards will expire as follows:
Federal NOL carryforwards
$
387,745 $
56,979 $
65,878 $
32,714 $
53,806 $
178,368
Total
2017-2022
2023-2025
Year Expiring
2026-2028
2029-2031
2032-2036
As a result of the write-down of oil and natural gas properties discussed in Notes 2 and 13, the Company has incurred a
cumulative three year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax
assets through future earnings, the Company assessed the ability to realize its deferred tax assets based on the future reversals of existing
deferred tax liabilities. Accordingly, the Company established a valuation allowance for a portion of the deferred tax asset. The valuation
allowance was $140,192 as of December 31, 2016.
The Company had no significant unrecognized tax benefits at December 31, 2016. Accordingly, the Company does not have any interest
or penalties related to uncertain tax positions. However, if interest or penalties were to be incurred related to uncertain tax positions,
such amounts would be recognized in income tax expense. Tax periods for years 2003 through 2016 remain open to examination by the
federal and state taxing jurisdictions to which the Company is subject.
The Company provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, which
primarily relate to non-deductible executive compensation expenses and state income taxes. The following table presents a reconciliation
of the reported amount of income tax expense to the amount of income tax expense that would result from applying domestic federal
statutory tax rates to pretax income from continuing operations:
Components of income tax rate reconciliation
Income tax expense computed at the statutory federal income tax rate
Percentage depletion carryforward
State taxes net of federal benefit
Restricted stock and stock options
Section 162(m)
Valuation allowance
Effective income tax rate
80
For the Year Ended December 31,
2015
2016
2014
35%
—%
—%
—%
(1)%
(34)%
—%
35%
—%
1%
—%
(1)%
(54)%
(19)%
35%
—%
1%
—%
2%
—%
38%
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
Components of income tax expense
Current federal income tax benefit
Current state income tax expense
Deferred federal income tax (benefit) expense
Deferred state income tax (benefit) expense
Valuation allowance
Total income tax expense
.
Note 12 - Asset Retirement Obligations
For the Year Ended December 31,
2015
2016
2014
$
$
(104) $
—
—
90
—
(14) $
— $
—
(69,087)
(1,282)
108,843
38,474 $
—
—
22,373
761
—
23,134
The table below summarizes the activity for the Company’s asset retirement obligations:
Asset retirement obligations at January 1, 2016
Accretion expense
Liabilities incurred
Liabilities settled
Revisions to estimate
Asset retirement obligations at end of period
Less: Current asset retirement obligations
Long-term asset retirement obligations at December 31, 2016
For the Year Ended December 31,
2016
2015
$
$
5,107 $
958
84
(2,378)
2,890
6,661
(2,729)
3,932 $
6,674
660
165
(2,964)
572
5,107
(790)
4,317
Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded
on the Consolidated Balance Sheets at December 31, 2016 and 2015 as long-term restricted investments were $3,332 and $3,309,
respectively. These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to
pay future abandonment costs for several of the Company’s oil and natural gas properties.
81
Note 13 – Supplemental Information on Oil and Natural Gas Properties (Unaudited)
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
The following table discloses certain financial data relating to the Company’s oil and natural gas activities, all of which are located in
the United States.
Evaluated Properties (a)
Beginning of period balance
Capitalized G&A expenses
Property acquisition costs (b)
Exploration costs
Development costs
End of period balance
Unevaluated Properties (a)(c)
Beginning of period balance
Property acquisition costs (b)
Exploration costs
Capitalized interest expenses
Transfers to Evaluated Properties
End of period balance
Accumulated depreciation, depletion and amortization
Beginning of period balance
Provision charged to expense
Write-down of oil and natural gas properties (a)
Sale of mineral interests
End of period balance
For the Year Ended December 31,
2015
2016
2014
$
$
$
$
$
$
2,335,223 $
12,222
216,561
38,612
151,735
2,754,353 $
132,181 $
548,673
8,631
19,857
(40,621)
668,721 $
1,756,018 $
71,330
95,788
24,537
1,947,673 $
2,077,985 $
10,529
26,726
81,320
138,663
2,335,223 $
142,525 $
5,520
4,576
10,459
(30,899)
132,181 $
1,478,355 $
69,228
208,435
—
1,756,018 $
1,701,577
10,071
94,541
118,251
153,545
2,077,985
43,222
128,342
11,177
4,295
(44,511)
142,525
1,420,612
56,663
—
1,080
1,478,355
(a) The Company uses the full cost method of accounting for its exploration and development activities. See the Company’s accounting policy
about oil and natural gas properties in Note 2 for details on the full cost method of accounting.
(b) See Note 3 in the Footnotes to the Financial Statements for additional information about the Company’s significant acquisitions.
(c) Unevaluated property costs primarily include lease acquisition costs, unevaluated drilling costs, seismic, capitalized interest expenses and
certain overhead costs related to exploration and development. These costs are directly related to the acquisition and evaluation of unproved
properties. The excluded costs and related reserves are included in the amortization base as the properties are evaluated and proved reserves
are established or impairment is determined. The majority of these costs are primarily associated with the Company’s focus areas of its future
development program and are expected to be evaluated over ten to fifteen years. The Company’s unevaluated property balance of $668,721
as of December 31, 2016, consisted of $123,345, $521,520 and $23,856 of costs attributable to our Monarch, WildHorse and Ranger operating
areas, respectively.
Subsequent to December 31, 2016, and through February 22, 2017, the Company drilled four gross (3.4 net) horizontal wells and
completed five gross (3.4 net) horizontal wells and had five gross (4.1 net) horizontal wells awaiting completion.
Depletion per unit-of-production, on a BOE basis, amounted to $12.81, $19.74 and $27.51 for the years ended December 31, 2016,
2015, and 2014, respectively. Lease operating expenses per unit-of-production, on a BOE basis, amounted to $6.88, $7.71, and $10.85
for the years ended December 31, 2016, 2015, and 2014, respectively.
Estimated Reserves
The Company’s proved oil and natural gas reserves at December 31, 2016, 2015 and 2014 have been estimated by DeGolyer and
MacNaughton, the Company’s current independent petroleum engineers. The reserves were prepared in accordance with guidelines
established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions.
There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates
only, and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed
as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent
reserves.
The following tables disclose changes in the estimated net quantities of oil and natural gas reserves, all of which are located onshore
within the continental United States:
82
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
Proved developed and undeveloped reserves:
Oil (MBbls):
Beginning of period
Revisions to previous estimates
Purchase of reserves in place
Sale of reserves in place
Extensions and discoveries
Production
End of period
Natural Gas (MMcf):
Beginning of period
Revisions to previous estimates
Purchase of reserves in place
Sale of reserves in place
Extensions and discoveries
Production
End of period
Proved developed reserves:
Oil (MBbls):
Beginning of period
End of period
Natural gas (MMcf):
Beginning of period
End of period
MBOE:
Beginning of period
End of period
Proved undeveloped reserves:
Oil (MBbls):
Beginning of period
End of period
Natural gas (MMcf):
Beginning of period
End of period
MBOE:
Beginning of period
End of period
For the Year Ended December 31,
2015
2014
2016
43,348
(5,738)
25,054
(1,718)
14,479
(4,280)
71,145
65,537
13,929
36,474
(2,765)
17,194
(7,758)
122,611
25,733
(1,632)
2,932
(23)
19,127
(2,789)
43,348
42,548
4,870
2,915
(105)
19,621
(4,312)
65,537
11,898
(243)
3,223
—
12,547
(1,692)
25,733
17,751
(215)
8,591
—
18,641
(2,220)
42,548
For the Year Ended December 31,
2015
2014
2016
22,257
32,920
38,157
61,871
28,617
43,232
21,091
38,225
27,380
60,740
25,654
48,348
14,006
22,257
25,171
38,157
18,201
28,617
11,727
21,091
17,377
27,380
14,623
25,654
5,960
14,006
9,059
25,171
7,470
18,201
5,938
11,727
8,692
17,377
7,387
14,623
Total Proved Reserves: The Company ended 2016 with estimated net proved reserves of 91,580 MBOE, representing a 69% increase
over 2015 year-end estimated net proved reserves of 54,271 MBOE. The Company added 48,477 MBOE primarily from the Company’s
acquisition and development efforts in the Permian Basin, where it drilled a total of 29 gross (20.9 net) wells. This increase was primarily
offset by 11,168 MBOE related to divestitures, 2016 production and revisions primarily due to pricing.
The Company ended 2015 with estimated net proved reserves of 54,271 MBOE, representing a 65% increase over 2014 year-end
estimated net proved reserves of 32,824 MBOE. The increase was primarily due the Company’s development of its properties in the
Permian Basin, where it drilled a total of 36 gross (27.1 net) wells, and acquisitions made during 2015. This increase was primarily
offset by 2015 production and revisions.
The Company ended 2014 with estimated net proved reserves of 32,824 MBOE, representing a 121% increase over 2013 year-end
estimated net proved reserves of 14,857 MBOE. The increase was primarily due the Company’s development of its properties in the
Permian Basin, where it drilled a total of 34 gross (28.7 net) wells, and acquisitions made during 2014. This increase was primarily
offset by 2014 production and revisions.
83
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
Extrapolation of performance history and material balance estimates were utilized by the Company’s independent petroleum and
geological firm to project future recoverable reserves for the producing properties where sufficient history existed to suggest
performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing
properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to
nonproducing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production,
and to a small extent, horizontal PDP and PUD categories.
Proved Undeveloped Reserves: The Company annually reviews its proved undeveloped reserves (“PUDs”) to ensure an appropriate
plan for development exists. Generally, reserves for the Company’s properties are booked as PUDs only if the Company has plans to
convert the PUDs into proved developed reserves within five years of the date they are first booked as PUDs. The Company’s PUDs
increased 88% to 48,348 MBOE from 25,654 MBOE at December 31, 2016 and 2015, respectively. The Company added 17,482 MBOE
to its PUDs, primarily from acquisitions in the Permian Basin, net of divestitures, and added 12,035 MBOE from the continued horizontal
development of its Permian Basin properties, net of revisions. The increase in Permian Basin PUDs was partially offset by the
reclassification of 6,823 MBOE, or 27%, included in the year-end 2015 PUDs, to PDPs as a result of our horizontal development of
Permian Basin properties at a total cost of approximately $43,415, net.
The Company’s PUDs increased 75% to 25,654 MBOE from 14,623 MBOE at December 31, 2015 and 2014, respectively. The
Company added 13,774 MBOE to its PUDs, net of revisions, primarily from the continued horizontal development of its Permian Basin
properties and from acquisitions in the Permian Basin. The increase in Permian Basin PUDs was partially offset by the reclassification
of 2,742 MBOE, or 19%, included in the year-end 2014 PUDs, to PDPs as a result of our horizontal development of Permian Basin
properties at a total cost of approximately $55,933, net.
The Company’s PUDs increased 98% to 14,623 MBOE from 7,387 MBOE at December 31, 2014 and 2013, respectively. The Company
added 10,125 MBOE to its PUDs, net of revisions, primarily from the continued horizontal development of its Permian Basin properties
and from acquisitions in the Permian Basin. The increase in Permian Basin PUDs was partially offset by the reclassification of 1,757
MBOE, or 24%, included in the year-end 2013 PUD reserves, to PDPs as a result of our horizontal development of Permian Basin
properties at a total cost of approximately $34,619, net. Also offsetting the increase was the removal of 1,132 MBOE of PUDs, including
the impact from the reclassification of previous vertical PUDs to the horizontal probable category given our focus on horizontal
development.
Standardized Measure
The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves
together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability
on the balance sheet at December 31, 2016. You should not assume that the future net cash flows or the discounted future net cash flows,
referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Prices are based on the preceding
12-months’ average price based on closing prices on the first day of each month. The following table summarizes the average 12-month
oil and natural gas prices net of differentials for the respective periods:
Average 12-month price, net of differentials, per Mcf of natural gas (a)
Average 12-month price, net of differentials, per barrel of oil (b)
2016
2015
$
$
2.71 $
40.03 $
2.73 $
47.25 $
2014
6.38
86.30
(a) Includes a high Btu content of separator natural gas and adjustments to reflect the Btu content, transportation charges and other fees
specific to the individual properties.
(b) Includes adjustments to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs,
location differentials and crude quality.
84
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income
taxes have been discounted to their present values based on a 10% annual discount rate.
Future cash inflows
Future costs
Production
Development and net abandonment
Future net inflows before income taxes
Future income taxes
Future net cash flows
10% discount factor
Standardized measure of discounted future net cash flows
Standardized Measure
For the Year Ended December 31,
2015
2,227,463 $
2016
3,180,005 $
2014
2,492,178
$
(974,667)
(384,117)
1,821,221
(1,602)
1,819,619
(1,009,787)
$
809,832 $
(827,555)
(239,100)
1,160,808
—
1,160,808
(589,918)
570,890 $
(873,469)
(288,081)
1,330,628
(164,490)
1,166,138
(586,596)
579,542
Changes in Standardized Measure
For the Year Ended December 31,
2015
2014
2016
Standardized measure at the beginning of the period
Sales and transfers, net of production costs
Net change in sales and transfer prices, net of production costs
Net change due to purchases and sales of in place reserves
Extensions, discoveries, and improved recovery, net of future production
and development costs incurred
Changes in future development cost
Revisions of quantity estimates
Accretion of discount
Net change in income taxes
Changes in production rates, timing and other
Aggregate change
Standardized measure at the end of period
$
$
570,890 $
(150,628)
(103,136)
260,859
180,228
82,320
(35,938)
57,091
16
(51,870)
238,942
809,832 $
579,542 $
(110,476)
(286,660)
37,616
184,469
108,216
(12,625)
62,968
35,407
(27,567)
(8,652)
570,890 $
283,946
(120,518)
(156,066)
111,331
299,192
186,605
(7,673)
30,114
(32,940)
(14,449)
295,596
579,542
Note 14 – Other
Commitments and contingencies
The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability
hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company.
The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution
control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance
with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise
relating to the protection of the environment are not expected to have a material effect upon the capital expenditures, earnings or the
competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect
additional regulation or legislation, enforcement policies hereunder, and claims for damages to property, employees, other persons and
the environment resulting from the Company’s operations could have on its activities.
Operating leases
As of December 31, 2016, the Company had contracts for three horizontal drilling rigs (the “Cactus 1 Rig”, “Cactus 2 Rig” and “Cactus
3 Rig”). The contract terms, as amended through December 31, 2016, of the Cactus 1 Rig and Cactus 2 Rig will end in July 2018 and
August 2018, respectively. Effective October 27, 2016, the Company entered into a contract for the Cactus 3 Rig, which commenced
drilling in mid-January 2017. The contract terms of the Cactus 3 Rig will end in July 2017.
The rig lease agreements include early termination provisions that obligate the Company to reduced minimum rentals for the remaining
term of the agreement. These payments would be reduced assuming the lessor is able to re-charter the rig and staffing personnel to
another lessee. In January 2016, the Company decided to place the Cactus 1 Rig on standby and was required to pay a “standby” day
85
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
rate of $15,000 per day, pursuant to the terms of the agreement, allowing the Company to retain the option to return the rig to service
under the contract terms. In August 2016, the Company returned its Cactus 1 Rig to service.
In March 2015, the Company decided to terminate its one-year contract for a vertical rig (effective April 2015). The Company paid
approximately $3,075 in reduced rental payments over the remainder of the lease term, which ended November 2015. The amount was
recognized as rig termination fee on the consolidated statements of operations for the year ended December 31, 2015.
Note 15 – Summarized Quarterly Financial Information (Unaudited)
2016
Total revenues
Income (loss) from operations (a)
Net income (loss) (a)
Income (loss) available to common shares
Income (loss) per common share - basic
Income (loss) per common share - diluted
First Quarter
$
30,698 $
(34,767)
(41,109)
(42,933)
(0.51) $
(0.51) $
Second Quarter
Third Quarter
Fourth Quarter
45,145 $
(50,529)
(70,097)
(71,920)
(0.61) $
(0.61) $
55,927 $
16,651
21,139
19,315
0.14 $
0.14 $
69,081
21,168
(1,746)
(3,570)
(0.02)
(0.02)
(a) Loss from operations and net loss for the three months ended March, 31, 2016 and June 30, 2016 included write-downs of oil and natural gas
properties of $34,776 and $61,012, respectively.
2015
Total revenues
Income (loss) from operations (a)
Net loss (a)
Loss available to common shares
Loss per common share - basic
Loss per common share - diluted
Second Quarter
Third Quarter
Fourth Quarter
39,242 $
6,231
(4,967)
(6,940)
(0.11) $
(0.11) $
34,316 $
(83,910)
(111,805)
(113,779)
(1.72) $
(1.72) $
33,563
(118,542)
(113,170)
(115,144)
(1.58)
(1.58)
$
$
$
$
First Quarter
$
30,391 $
(12,889)
(10,197)
(12,171)
(0.21) $
(0.21) $
(a) Loss from operations and net loss for the three months ended September 30, 2015 and December 31, 2015 included write-downs of oil and
natural gas properties of $87,301 and $121,134, respectively.
86
ITEM 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
On January 11, 2016, the Audit Committee of the Board of Directors of Callon Petroleum Company (the “Company”) approved the
engagement of Grant Thornton LLP (“GT”) as the Company’s independent registered public accounting firm for the year ending
December 31, 2016. GT informed the Company that it completed the prospective client evaluation process on January 14, 2016. In
connection with the selection of GT, also on January 11, 2016, the Audit Committee informed Ernst & Young LLP (“E&Y”) that they
would no longer serve as the Company’s independent registered public accounting firm no later than the date of the filing of the
Company’s Form 10-K for the 2015 fiscal year. The Audit Committee made its decision in connection with its annual review of the
Company’s independent registered public accounting firm and after soliciting proposals from several accounting firms, including E&Y.
During the year ended December 31, 2014 and through January 11, 2016, neither the Company nor anyone on its behalf consulted with
GT with respect to either (i) the application of accounting principles to a specified transaction, either completed or proposed, or the type
of audit opinion that might be rendered on the Registrant’s consolidated financial statements, and neither written nor oral advice was
provided to the Company that GT concluded was an important factor considered by the Company in reaching a decision as to any
accounting, auditing or financial reporting issue; (ii) any matter that was either the subject of disagreement (as defined in Item
304(a)(l)(iv) of Regulation S-K and the related instructions to Item 304 of Regulations S-K) or a reportable event (as defined by Item
304(a)(l)(v) of Regulation S-K).
The report of E&Y on the Company’s consolidated financial statements for the years ended December 31, 2015 and 2014, did not contain
an adverse opinion or disclaimer of an opinion, and was not qualified or modified as to uncertainty, audit scope or accounting principles.
Item 9A. Controls and Procedures
Disclosure controls and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed
to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act
of 1934, as amended (the “Exchange Act”), is accumulated and communicated to the issuer’s management, including its principal
executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required
disclosure. Our Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures
(as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal
financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2016.
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 Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal
control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of
financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance
with U.S. generally accepted accounting principles. Under the supervision and with the participation of our management, including our
CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2016
based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO)
of the Treadway Commission (2013 framework)(the COSO criteria). Based on that evaluation, management concluded that our internal
control over financial reporting was effective as of December 31, 2016.
Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of
the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal
controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of
changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Company’s independent registered public accounting firm has issued an attestation report regarding its assessment of the Company’s
internal control over financial reporting as of December 31, 2016, which follows Part II, Item 9B of this filing. Additionally, the financial
statements for the year ended December 31, 2016, covered in this Annual Report on Form 10-K, have been audited by an independent
registered public accounting firm, Grant Thornton LLP, whose report is presented immediately preceding the Company’s financial
statements included in Part II, Item 8 of this Annual Report on Form 10-K. The financial statements for the years ended December 31,
2015 and 2014 were audited by the independent registered public accounting firm, Ernst & Young LLP, whose report is presented
immediately preceding the company’s financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.
Changes in internal control over financial reporting. There were no changes to our internal control over financial reporting during our
last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting.
87
ITEM 9A (T). Controls and Procedures
See Item 9A.
ITEM 9B. Other Information
Submissions of matters to a vote of the security holders.
None.
88
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Callon Petroleum Company
We have audited the internal control over financial reporting of Callon Petroleum Company (a Delaware corporation) and subsidiaries
(the “Company”) as of December 31, 2016, based on criteria established in the 2013 Internal Control—Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for
maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial
reporting, included in the accompanying Management’s report on internal control over financial reporting. Our responsibility is to
express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial
reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial
reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal
control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the
maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention
or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections
of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31,
2016, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the
consolidated financial statements of the Company as of and for the year ended December 31, 2016, and our report dated February 27,
2017 expressed an unqualified opinion on those financial statements.
/s/ GRANT THORNTON LLP
Houston, Texas
February 27, 2017
89
ITEM 10. Directors, Executive Officers and Corporate Governance
PART III.
For information concerning Item 10, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting
of Stockholders to be held on May 11, 2017, which will be filed with the Securities and Exchange Commission and is incorporated
herein by reference.
The Company has adopted a code of ethics that applies to the Company’s chief executive officer, chief financial officer and chief
accounting officer. The full text of such code of ethics has been posted on the Company’s website at www.callon.com, and is available
free of charge in print to any shareholder who requests it. Request for copies should be addressed to the Secretary at mailing address
Post Office Box 1287, Natchez, Mississippi 39121.
ITEM 11. Executive Compensation
For information concerning Item 11, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting
of Stockholders to be held on May 11, 2017, which will be filed with the Securities and Exchange Commission and is incorporated
herein by reference.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
For information concerning the security ownership of certain beneficial owners and management, see the definitive proxy statement of
Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 11, 2017, which will be filed with the
Securities and Exchange Commission and is incorporated herein by reference.
ITEM 13. Certain Relationships and Related Transactions and Director Independence
For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting
of Stockholders to be held on May 11, 2017, which will be filed with the Securities and Exchange Commission and is incorporated
herein by reference.
ITEM 14. Principal Accountant Fees and Services
For information concerning Item 14, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting
of Stockholders to be held on May 11, 2017, which will be filed with the Securities and Exchange Commission and is incorporated
herein by reference.
90
Item 15. Exhibits
The following is an index to the financial statements and financial statement schedules that are filed in Part II, Item 8 of this report on
Form 10-K.
Exhibit Number
Description
Reports of Independent Registered Public Accounting Firms
Consolidated Balance Sheets as of December 31, 2016 and 2015
Consolidated Statements of Operations for each of the three years in the period ended December 31, 2016
Consolidated Statements of Stockholders’ Equity (Deficit) for each of the three years in the period ended December 31, 2016
Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2016
Notes to Consolidated Financial Statements
Schedules other than those listed above are omitted because they are not required, not applicable or the required information is included in the
financial statements or notes thereto.
Plan of acquisition, reorganization, arrangement, liquidation or succession
Articles of Incorporation and Bylaws
Certificate of Incorporation of the Company, as amended through May 12, 2016 (incorporated by reference to Exhibit 3.1 of the Company’s
Quarterly Report on Form 10-Q, filed on November 3, 2016)
Certificate of Designation of Rights and Preferences of 10.00% Series A Cumulative Preferred Stock (incorporated by reference to Exhibit 3.5
of the Company’s Form 8-A, filed on May 23, 2013)
Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Registration Statement on Form S-4, filed on August 4,
1994, Reg. No. 33-82408)
Instruments defining the rights of security holders, including indentures
Specimen Common Stock Certificate (incorporated by reference from Exhibit 4.1 of the Company’s Registration Statement on Form S-4, filed
on August 4, 1994, Reg. No. 33-82408)
Certificate for the Company’s 10.00% Series A Cumulative Preferred Stock (incorporated by reference to Exhibit 4.1 of the Company’s Form 8-
A, filed on May 23, 2013)
Indenture of 6.125% Senior Notes Due 2024, dated as of October 3, 2016, among Callon Petroleum Company, the Guarantors party thereto and
U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 of the Company's Current Report on Form 8-K, filed on
October 4, 2016)
Registration Rights Agreement of 6.125% Senior Notes Due 2024, dated October 3, 2016, among Callon Petroleum Company, Callon Petroleum
Operating Company and J.P. Morgan Securities LLC, as representative of the Intitial Purchasers named on Annex E thereto (incorporated by
reference to Ehibit 4.2 of the Company's Current Report on Form 8-K, filed on October 4, 2016)
Voting trust agreement
None
Material contracts
Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference to Exhibit 10.13 of the Company’s Annual Report on Form
10-K for the year ended December 31, 2001, filed on April 1, 2002)
Amendment No. 1 to the Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference from Exhibit 10.2 of the Company’s
Current Report on Form 8-K, filed on January 5, 2009)
Callon Petroleum Company 2010 Phantom Share Plan, adopted May 4, 2010 (incorporated by reference to Exhibit 10.1 of the Company’s
Current Report on Form 8-K, filed on May 7, 2010)
Form of Callon Petroleum Company Phantom Share Award Agreement, adopted May 4, 2010 (incorporated by reference to Exhibit 10.2 of the
Company’s Current Report on Form 8-K, filed on May 7 , 2010)
Deferred Compensation Plan for Outside Directors - Callon Petroleum Company, effective as of January 1, 2011 (incorporated by reference to
Exhibit 10.17 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2010, filed on March 15, 2011)
Amended and Restated Severance Compensation Agreement, dated as of March 15, 2011 and effective as of January 1, 2011, by and between
Fred L. Callon and Callon Petroleum Company (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed
on March 18, 2011)
Form of Amended and Restated Severance Compensation Agreement, dated as of March 15, 2011 and effective as of January 1, 2011, by and
between Callon Petroleum Company and its executive officers (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on
Form 8-K, filed on March 18, 2011)
Callon Petroleum Company 2011 Omnibus Incentive Plan (incorporated by reference from Exhibit A of the Company’s Definitive Proxy
Statement on Schedule 14A, filed on March 21, 2011)
Agreement, dated March 9, 2014, among the Company and Lone Star Value Investors, L.P., Lone Star Value Co-Invest I, L.P., Lone Star Value
Investors GP, LLC, Lone Star Value Management, LLC, Jeffery E. Eberwein and Matthew R. Bob (incorporated by reference from Exhibit 10.1
of the Company's Current Report on Form 8-K, filed on March 10, 2014)
Fifth Amended and Restated Credit Agreement, dated March 11, 2014, among Callon Petroleum Company, JPMorgan Chase Bank, National
Association, as administrative agent and the Lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company's Quarterly Report
on Form 10-Q/A, filed on June 11, 2014)
Amendment No. 2 to Fifth Amended and Restated Credit Agreement, effective as of October 8, 2014, among Callon Petroleum Company,
JPMorgan Chase Bank, National Association, as administrative agent and the Lenders party thereto (incorporated by reference to Exhibit 10.4
of the Company's Current Report on Form 8-K, filed on October 14, 2014)
Second Lien Credit Agreement, dated October 8, 2014, among Callon Petroleum Company, Royal Bank of Canada and the Lenders party thereto
(incorporated by reference to Exhibit 10.5 of the Company's Current Report on Form 8-K, filed on October 14, 2014)
Second Lien Intercreditor Agreement, dated October 8, 2014, among Callon Petroleum Company, JPMorgan Chase Bank, National Association,
Royal Bank of Canada, and the other parties named therein(incorporated by reference to Exhibit 10.6 of the Company's Current Report on Form
8-K, filed on October 14, 2014)
Severance Compensation Agreement, dated as of February 13, 2015, by and between Bob Weatherly and Callon Petroleum Company
(incorporated by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q, filed on May 7, 2015)
Agreement, dated March 21, 2015, among the Company and Lone Star Value Investors, L.P., Lone Star Value Co-Invest I, L.P., Lone Star Value
Investors GP, LLC, Lone Star Value Management, LLC, Jeffery E. Eberwein and Michael L. Finch (incorporated by reference from Exhibit 10.1
of the Company's Current Report on Form 8-K, filed on March 25, 2015)
91
*
2.
3.
4.
9.
10.
3.1
3.2
3.3
4.1
4.2
4.3
4.4
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14
10.15
10.16
10.17
10.18
10.19
10.20
10.21
10.22
10.23
10.24
10.25
10.26
10.27
10.28
14.1
16.1
21.1
23.1
23.2
23.3
31.1
31.2
99.1
11.
12.
13.
14.
16.
18.
21.
22.
23.
24.
31.
32.
99.
Form of Callon Petroleum Company Restricted Stock Unit Award Agreement, adopted on March 12, 2015
Form of Callon Petroleum Company Phantom Share Award Agreement, adopted on March 12, 2015
Form of Callon Petroleum Company Phantom Share Award Agreement, adopted on March 12, 2015
Form of Callon Petroleum Company Phantom Share Award Agreement, adopted on March 12, 2015
First Amendment to the Callon Petroleum Company 2011 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.1 of the Company's
Quarterly Report on Form 10-Q, filed on November 5, 2015)
Agreement, dated February 25, 2016, among the Company and Lone Star Value Investors, L.P., Lone Star Value Co-Invest I, L.P., Lone Star
Value Investors GP, LLC, Lone Star Value Management, LLC, and Jeffery E. Eberwein (incorporated by reference from Exhibit 10.1 of the
Company's Current Report on Form 8-K, filed on March 1, 2016)
Purchase and Sale Agreement, dated April 19, 2016, among BSM Energy LP, Crux Energy, LP and Zaniah Energy, LP, as Sellers, and Callon
Petroleum Operating Company, as Purchaser, and Callon Petroleum Company, as Purchaser Parent (incorporated by reference to Exhibit 2.1 of
the Company's Current Report on Form 8-K, filed on April 19, 2016)
Registration Rights Agreement, dated May 26, 2016, among Callon Petroleum Company and each of the Persons set forth on Schedule A therein
(incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K, filed on May 31, 2016)
Amendment No. 3 to Fifth Amended and Restated Credit Agreement, effective as of July 11, 2016, among Callon Petroleum Company, JPMorgan
Chase Bank, National Association, as administrative agent and the Lenders party thereto (incorporated by reference to Exhibit 10.4 of the
Company's Current Report on Form 8-K, filed on August 8, 2016)
Purchase and Sale Agreement, dated September 1, 2016, between Plymouth Petroleum, LLC, as Seller, and Callon Petroleum Operating
Company, as Buyer (incorporated by reference to Exhibit 2.1 of the Company's Current Report on Form 8-K, filed on September 6, 2016)
Amendment No. 4 to Fifth Amended and Restated Credit Agreement, effective as of September 9, 2016, among Callon Petroleum Company,
JPMorgan Chase Bank, National Association, as administrative agent and the Lenders party thereto (incorporated by reference to Exhibit 10.1
of the Company's Current Report on Form 8-K, filed on September 12, 2016)
Purchase Agreement, dated September 15, 2016, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan
Securities LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 of the Company's Current Report
on Form 8-K, filed on September 16, 2016)
Purchase and Sale Agreement, dated December 13, 2016, between American Resource Development LLC, American Resource Development
Upstream LLC and American Resource Development Midstream LLC, collectively, as Seller, and Callon Petroleum Operating Company, as
Purchaser (incorporated by reference to Exhibit 2.1 of the Company's Form 8-K, filed on December 13, 2016)
Statement re computation of per share earnings
Statements re computation of ratios
Annual Report to security holders, Form 10-Q or quarterly reports
Code of Ethics
Code of Ethics for Chief Executive Officers and Senior Financial Officers (incorporated by reference to Exhibit 14.1 of the Company’s Annual
Report on Form 10-K for the year ended December 31, 2003, filed on March 15, 2004)
Letter re change in certifying accountant
Letter from E&Y dated January 15, 2016 (incorporated by reference to Exhibit 16.1 of the Company's Current Report on Form 8-K, filed on
January 15, 2016)
Letter re change in accounting principles
Subsidiaries of the Company
(a) Subsidiaries of the Company
*
*
*
*
*
Published report regarding matters submitted to vote of security holders
Consents of experts and counsel
(a) Consent of Grant Thornton LLP
(a) Consent of Ernst & Young LLP
(a) Consent of DeGolyer and MacNaughton, Inc.
*
Power of attorney
Rule 13a-14(a) Certifications
(a) Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)
(a) Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)
(b) Section 1350 Certifications of Chief Executive and Financial Officers pursuant to Rule 13(a)-14(b)
Additional Exhibits
(a) Reserve Report Summary prepared by DeGolyer and MacNaughton, Inc. as of December 31, 2016
(c) Interactive Data Files
Not applicable to this filing
Filed herewith.
101.
*
(a)
(b) Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report and not “filed” as part of such report
for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to
be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference.
(c) Pursuant to Rule 406T of Regulation S-T, these interactive data files are being furnished herewith and are not deemed filed or part of a registration statement or
prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities Exchange Act of 1934, as amended, and
otherwise are not subject to liability.
92
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
Date:
February 27, 2017
Callon Petroleum Company
/s/ Joseph C. Gatto, Jr.
By: Joseph C. Gatto, Jr., President,
Chief Financial Officer (principal financial officer) and Treasurer
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.
Date:
February 27, 2017
/s/ Fred L. Callon
Fred L. Callon (principal executive officer, director)
Date:
February 27, 2017
/s/ Joseph C. Gatto, Jr.
Joseph C. Gatto, Jr. (principal financial officer)
Date:
February 27, 2017
/s/ Mitzi P. Conn
Mitzi P. Conn (principal accounting officer)
Date:
February 27, 2017
Date:
February 27, 2017
/s/ L. Richard Flury
L. Richard Flury (director)
/s/ John C. Wallace
John C. Wallace (director)
Date:
February 27, 2017
/s/ Anthony J. Nocchiero
Anthony J. Nocchiero (director)
Date:
February 27, 2017
Date:
February 27, 2017
Date:
February 27, 2017
Date:
February 27, 2017
/s/ Larry D. McVay
Larry McVay (director)
/s/ Matthew R. Bob
Matthew R. Bob (director)
/s/ James M. Trimble
James M. Trimble (director)
/s/ Michael L. Finch
Michael L. Finch (director)
93
C O R P O R AT E D ATA
Fred L. Callon
Chairman and Chief Executive Officer
L. Richard Flury
Former Chief Executive
Gas, Power & Renewables
British Petroleum plc (Retired)
Larry D. McVay
Former Chief Operating Officer
TNK-BP Holdings
British Petroleum plc Joint Venture (Retired)
Anthony J. Nocchiero
Former Sr. Vice President
and Chief Financial Officer
CF Industries, Inc. (Retired)
John C. Wallace
Former Chairman, Fred. Olsen Ltd. (Retired)
Director, Siem Offshore Inc.;
Secunda Canada LP
Matthew R. Bob
President, Eagle Oil & Gas Company
James M. Trimble
Director, Stone Energy
Former Chief Executive Officer and
President of PCD Energy Corporation (Retired)
Michael L. Finch
Former Chief Financial Officer and
Director of Stone Energy Corporation (Retired)
Fred L. Callon
Chairman and Chief Executive Officer
Joseph C. Gatto, Jr.
President, Chief Financial Officer and Treasurer
Gary A. Newberry
Senior Vice President and Chief Operating Officer
Mitzi P. Conn
Vice President, Chief Accounting Officer and Controller
Jerry A. Weant
Vice President, Land
Michael O’Connor
Vice President, Permian Operations
B.F. Weatherly
Corporate Secretary
TRANSFER AGENT AND REGISTRAR
American Stock Transfer
& Trust Company, LLC
6201 15th Avenue
Brooklyn, New York 11219
(718) 921-8200
LEGAL COUNSEL
Haynes and Boone, LLP
Houston, Texas
INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
Grant Thornton LLP
Houston, Texas
ADMINISTRATIVE AGENT BANK
JPMorgan Chase Bank, N.A.
New York, New York
HEADQUARTERS
Callon Headquarters Building
200 North Canal Street
Natchez, Mississippi 39120
Mailing Address:
Callon Petroleum Company
PO Box 1287
Natchez, Mississippi 39121
CALLON WEBSITE
The Company website can be found at
www.callon.com. It contains news releases,
corporate governance materials, the annual report,
recent investor presentations, stock quotes and a
link to SEC filings.
PREFERRED STOCK DIVIDEND POLICY
Holders of our Series A preferred stock (NYSE:
CPE.A) are entitled to a cumulative dividend,
whether or not declared, of $5.00 per annum,
payable quarterly, equivalent to 10% of the
liquidation preference of $50.00 per share.
COMMON STOCK DIVIDEND POLICY
It is anticipated that all available funds will be
reinvested in the Company’s business activities.
Therefore, the Company does not anticipate
paying cash dividends on its common stock for the
foreseeable future.
MARKET FOR COMMON STOCK
Effective April 22, 1998, the Company’s Common
Stock began trading on the New York Stock
Exchange under the symbol “CPE.”
CEO SECTION 303A.12(A) CERTIFICATION
In accordance with requirements mandated by the
New York Stock Exchange under Section
303A.12 (a) of the Listed Company Manual, each
public company is required to disclose in its Annual
Report to Shareholders that its CEO certification
was filed and to state any qualifications to such
certification. On behalf of Fred L. Callon, the
Company filed the required certification on
February 27, 2017 without qualification.
CORPORATE OFFICE
Callon Petroleum Company
1401 Enclave Parkway, Suite 600
Houston, Texas 77077
PERMIAN OPERATIONS OFFICE
Callon Petroleum Company
10 Desta Drive, Suite 400W
Midland, Texas 79705
FORM 10-K
The Company’s Annual Report on Form 10-K, as
audited by Grant Thonton, excluding exhibits, has
been incorporated into this Annual Report.
NOTICE OF ANNUAL SHAREHOLDERS’ MEETING
The Annual Meeting of Shareholders will be held
Thursday, May 11, 2017 at 9:00 a.m. CST in the
Grand Ballroom of the Natchez Grand Hotel,
111 South Broadway Street, Natchez, MS 39120.
Information with respect to this meeting is
contained in the Proxy Statement sent to
shareholders of record on March 17, 2017. The
2016 Annual Report is not to be considered a part of
the proxy soliciting materials.
This Annual Report and the statements contained in it are submitted for the general information of the shareholders of Callon Petroleum Company. The information is not
presented in connection with the sale or the solicitation of any offer to buy any securities, nor is it intended to be a representation by the Company of the value of its securities. If
you have questions regarding this Annual Report or the Company, or would like additional copies of this report, please contact our Investor Relations Department at 1401 Enclave
Pkwy, Ste 600, Houston, TX 7707, Phone: (281) 589-5200, Email: ir@callon.com
INVESTORS, SECURITY ANALYSTS AND MEDIA RELATIONS
Shareholders, brokers, securities analysts, portfolio managers or financial news media seeking information about the company may email us at: ir@callon.com or call
Eric Williams, Investor Relations @ 281-589-5200. Written inquiries may be sent to 1401 Enclave Parkway, Suite 600, Houston, TX 77077.
2016 ANNUAL REPORT
BOARD OF DIRECTORSOFFICERS OF THE COMPANY WWW.CALLON.COMNYSE: CPE / CPE.A