Corporate Profile
Callon Petroleum Company has been engaged
Permian Production
in the exploration, development, acquisition
and production of oil and natural gas properties
since 1950. The Company is focused exclusively
in the Permian Basin on building reserves
and production through efficient operations
and
low finding and development costs.
The Company’s estimated proved reserves at
December 31, 2014 were 32.8 million barrels of
oil equivalent (MMBoe).
2010
2011
2012
2013
2014
0
300
600
900
1200
1500
1800
2100
MBoe
De-Risked Permian Acreage
Andrews
Martin
Howard
Odessa
Midland
Ector
Midland Glasscock
Crane
2010
2011
2012
2013
2014
Upton
Reagan
0
3
6
9
Net Acres (000’s)
12
15
18
Crockett
Proved Reserves By Oil/Gas
2010
2011
2012
2013
2014
0
5
10
15
20
25
30
35
MMBoe
1
To Our Shareholders
With nearly sixty producing horizontal wells from four distinct zones, we have firmly established ourselves
as an exceptional, pure-play operator within the oil-rich Midland Basin of the Permian Basin. We enter
2015 with a solid foundation of properties and an associated drilling portfolio concentrated in the heart
of the Midland Basin. The dedication and focus of our highly skilled team is evidenced by a year of
record proved reserves and production growth. In 2014, we grew our proved reserves by 121% to nearly
33 million barrels of oil equivalent (“MMBOE”). We efficiently invested approximately $218 million of
operational capital to generate this 15.7 MMBOE reserve growth, representing an average drill-bit finding
and development (“F&D”) cost of under $14 per barrel of oil equivalent (“BOE”), a 10% reduction versus
last year. Additionally, in 2014 we increased our Permian production by nearly 154% to over 2 MMBOE.
Recognizing the need to continue building upon our foundation for future growth and deliver shareholder
value, we added nearly 4,000 net acres in the heart of the Midland Basin to our overall position, which
grew our horizontal well inventory by 40% to a level that – assuming our current two-horizontal drilling
rig development program – provides approximately 20 years of drilling activity from our four currently
producing zones. Adding the other prospective zones across our acreage increases our horizontal drilling
inventory to approximately 40 years at our current development pace. These accomplishments, combined
with the improvements we’ve made to our capital structure and continued operational efficiencies,
position Callon for long-term operational success and will allow us to deliver meaningful value for our
shareholders.
During 2014, we replaced nearly 760% of our production with net proved reserve additions, and we
exited 2014 producing at an average rate of nearly 7,300 barrels of oil equivalent per day (“BOE/d”)
in the fourth quarter, a 144% increase over our corresponding 2013 Permian exit rate of 2,975 BOE/d.
Given the current commodity price environment, we decided to return to a focused, two-horizontal rig
drilling program and reduce our 2015 capital budget by 25%, as compared to the previous year. Despite
the constrained capital plan, we expect to grow total 2015 production, inclusive of production from our
recently acquired Cassleman and Bohannon fields (our “CaBo” field area), by over 45% to over 3 MMBOE.
We grew our proved reserves by 121% to
nearly 33 million barrels of oil equivalent
Sustained growth in our assets is an important objective, and our pursuit of that goal is governed by a strict
focus on capital efficiency and financial discipline. We expect our drilling program to generate average
returns of 25% in a $55 flat realized oil price environment, taking into account the well cost reductions
we have already achieved to date. Working with our service partners, we have made significant progress
reducing our drilling and completion costs, and we will continue in these efforts with the expectation of
obtaining additional reductions throughout 2015. The additional cost savings will serve to further reduce
our F&D costs and improve our expected returns on capital.
Currently, our total well costs are down 20%, as compared to 2014. Building on the momentum of
working with our service partners, we believe that total well costs could decline by as much as 30%
from 2014 levels by the second half of 2015. Realizing these incremental reductions would result in well
costs of approximately $5.1 million for a 7,500’ lateral and $4 million for 5,000’ laterals. These lower
costs would increase our expected average returns to between 35% and 40% in a flat realized price
environment of $55 per BOE. We firmly believe that this pace and magnitude of cost reductions is the
product of the strong relationships we have built with our key service partners of the past several years
and our willingness to work together through this challenging price environment.
2014 Annual Report 2
Callon Petroleum Company
2014 Highlights
•
Increased Permian Basin annual production by 154% to 2,062
thousand barrels of oil equivalent (“MBOE”)
• Ended 2014 producing nearly 7,300 BOE/d, a 144% increase
over 2013
• Acquired 6,230 gross (3,862 net; 100% held by existing
vertical production) surface acres in the core of the Midland
Basin located in close proximity to our existing Carpe Diem
and Pecan Acres fields, adding 441 horizontal drilling locations
including 177 in currently producing zones
•
Increased proved reserves by 121% to nearly 33 MMBOE
• Replaced nearly 760% of 2014 production with additional
proved reserves
• Drilled 27 horizontal wells in the Southern & Central Midland
Basin, producing from a total of four zones including the
Upper and Lower Wolfcamp B, the Wolfcamp A and the Lower
Spraberry
•
•
Increased our inventory of horizontal drilling locations by nearly
80% with over 50% targeting currently producing zones
Increased our drilling inventory to a level supporting 40 years of
continuous development based on our current two-horizontal
rig drilling program
• Raised nearly $430 million in equity ($130 million) and long-
term debt ($300 million) capital, strengthening our balance
sheet, funding our acquisition, and pre-funding a meaningful
portion of our ongoing development activity
• Retired the remaining portion of our 13% Senior Notes, further
improving our cost of capital
• Grew the borrowing base under our $500 million Senior
Secured Credit Facility to $250 million, an increase of more
than 200% over the $83 million borrowing base at the end
of 2013
A Strong Foundation for Growth
Given the multiple, stacked zone development opportunity across our acreage
position in the Permian, we enter 2015 with over 100,000 net effective acres in
the Midland Basin that have been de-risked for horizontal development, of which
we believe 82% to be located in the oil-rich core of the basin. Our oil production
as a percentage of total production, which totaled 82% in 2014, remains
well above our peer group average. Similarly, our 2014 proved reserves were
comprised of 78% oil, and is expected to increase as we continue to horizontally
develop our assets. With only 53 horizontal PUD locations carried at the end of
2014, we continue to employ a conservative booking philosophy. Of these total
PUD locations, only three are associated with the Lower Spraberry zone, which
we expect to become a larger contributor to our asset profile over time. Having
already drilled the single vertical PUD location recorded at the close of 2014,
we are now exclusively focused on horizontal development across our acreage.
Horizontal Well Inventory
12/31/2013
12/31/2014
0
200
400
600
Total Locations
800
1000
1200
Importantly, we operate the vast majority of our development and have minimal drilling obligations within our acreage portfolio, which is
largely held-by-production. As of January 1, 2015, we estimate that only 10% of our planned 30 gross horizontal wells in 2015 are required
to satisfy continuous drilling obligations. We believe this operational status uniquely positions Callon, providing the operational flexibility
to accommodate any meaningful changes in the overall commodity price environment that could affect the level of desired drilling activity.
Continue to Increase Producing Zones across our Acreage
We are off to a good start in 2015, poised for efficient program development of the four productive zones where we have already
established production to date. During 2014, we added both the Wolfcamp B and Lower Spraberry to production on our Central acreage,
2
3
expanding upon our Wolfcamp development that was limited to our Southern acreage at the end of 2013.
Already in 2015, we’ve drilled a Lower Spraberry well on our Southern acreage, further de-risking our
entire core acreage footprint by producing from the Wolfcamp A, Wolfcamp B (Upper and Lower) and
Lower Spraberry.
While we remain focused on the Wolfcamp B, the longer term performance of our initial Lower Spraberry
wells is very encouraging, and will likely attract additional capital allocation over time. Our first two
horizontal wells targeting the Lower Spraberry, which are located in northwest Midland County within our
Carpe Diem and Casselman fields, produced an average of over 192 BOE/d per 1,000’ completed lateral
feet. Importantly, the 751 BOE/d 30-day peak rate observed at the Casselman field was materially above
the 315 BOE/d 30-day peak rate associated with the Lower Spraberry type curve used for evaluation and
planning purposes at the time of the acquisition, assuming equivalent completed laterals.
We continue to monitor offsetting peer operator activity and our technical evaluation around other
zones we believe are likely to become productive in the future, including the Jo-Mill, Wolfcamp C and
Cline formations. In total, our horizontal inventory consists of nearly 1,050 potential locations with
approximately 40 years of drilling inventory for a two-rig drilling program on our existing acreage, a 151%
increase over our drilling inventory at the end of 2013.
Focus on Operational Efficiency
We continue to implement an increasing portion of gas lift systems for wells targeting the Wolfcamp zones
as we believe that this form of artificial lift, combined with the practice of restricting total produced fluids
(oil and water), will contribute to shallower production declines and reduce the impact of interference
from offsetting well completions. Additionally, we believe other economic benefits will stem from these
practices including the deferral of a portion of production volumes into a contango oil price environment
and a reduction in water-handling infrastructure investments.
Following our fourth quarter close of the CaBo acquisitions, we dedicated a great deal of focus during the
last part of 2014 to the integration of these fields into our ongoing operations. The transition has gone
well as we make progress developing good relationships with our working interest partners. We continue
to have constructive conversations with offset operators, and have secured off-lease surface locations for
our planned wells in 2015, which effectively allow us to access an incremental 10% of completed lateral
length. This progress, combined with the encouraging initial well results in both the Wolfcamp B and Lower
Spraberry, affirms our excitement about the potential for this core area and growth platform.
Production continues to benefit from improved chemical treatments and raising rod pumps in vertical
wells. During the fourth quarter, with the decline in commodity prices, we instituted a more stringent
framework for performing workovers of mature vertical wells. The result is a reduced number of expected
workovers, combined with lower associated workover service costs, is a key driver of our expectation for
lower lease operating costs in 2015.
Solid Balance Sheet and Improved Liquidity
We remain focused on generating both organic and acquired growth, recognizing the need for cost-
effective capital and financial flexibility. Our recent long-term capital raise of nearly $500 million,
including approximately $68 million from our equity offering in March of 2015, significantly enhances
Callon’s preparedness to enter a more challenging commodity price environment this year. We have
no debt maturities until 2019, allowing us to invest our cash flows from operations into the continued
development of our high-quality asset base. As we meaningfully grow production, we benefit from the
ability to spread our fixed costs over a larger production base, and our focus on cost control allows
us to maintain strong cash margins. Falling well costs reduces our capital funding needs, and our
current hedge portfolio provides significantly stronger cash flow relative to current commodity pricing.
2014 Annual Report 4
As of December 31, 2014, our unsettled hedges were valued at $27.8 million and include oil hedges with
an average swap price of nearly $71per barrel on an average of over 4,150 barrels of oil per day in 2015.
Our $250 million borrowing base under our credit facility was less than 15% drawn at the end of 2014,
and will be repaid with proceeds from our most recent equity offering. The fully-available borrowing base
provides low-cost liquidity to fund our two-rig horizontal drilling capital program well beyond 2015,
assuming current commodity prices and service costs.
2015 Outlook
We enter 2015 well-positioned for continued success. Our focus on established zones in our core fields
translates into an operational plan that requires minimal high-grading of acreage relative to previous
activity. Despite the significant pullback in commodity prices over the past several months, our quality
asset base, fiscal discipline, recent long-term capital raises and a strong 2015 hedge portfolio collectively
position us to continue adding meaningful value to our shareholders. While the $163 million midpoint of
our 2015 operational capital budget reflects a 25% reduction of our operational capital deployed in 2014,
we still expect to exit 2015 producing at a rate 15% over our 2014 exit rate. To achieve this increase, we
expect to place onto production approximately 30 gross (24 net) wells targeting each of our four currently
productive zones – the Lower Spraberry, Wolfcamp A, and the Upper and Lower Wolfcamp B. Inclusive of
the production contributed by our recently acquired CaBo fields, we project total 2015 production to grow
45% over last year. Reflective of our reduced capital program, we have already secured a 40% reduction
in drilling rig costs and average cost reductions of over 20% for completion and ancillary services. With
well costs that are already 20% below last year’s levels, the current environment provides the opportunity
to improve upon our 2014 “drill-bit” F&D costs of $13.91 per barrel of oil equivalent. Another advantage
we enjoy is the operational flexibility we possess because we operate nearly 100% of our leasehold
that is largely held-by-production. Accordingly, we have the flexibility to adjust our capital program to
accommodate unexpected changes in the macroeconomic environment. We believe our focused, two-
rig horizontal drilling program led by an exceptional operating team will continue to add value to our
shareholders, and position Callon to capitalize on further potential decreases in development costs while
maintaining operational momentum for the future.
Gratitude
Establishing ourselves as a exceptional operator within the Midland Basin has only been possible because
of the Callon team’s talent and dedication. With nearly 65 years in the business, I am extremely proud of
what the team has built in the five short years we have been operating in the Basin, especially the creation
of a culture focused on safety and responsible development. Although we as an industry face challenges
in the current commodity price environment, I firmly believe that our high-quality asset base and continued
progress to improve capital efficiency will continue to generate long-term value for our shareholders.
I also want to express my appreciation for our Board of Directors who remain fully committed to creating
value for all Callon shareholders. Their vision, expertise and persistence have been invaluable as we have
solidified Callon as a pure-Permian operator. We are fortunate to have a Board with the quality and
diversity of experience its members possess, and I look forward to working with the Board as we continue
to work towards the ongoing successful execution of our horizontal development and growth strategy.
Fred L. Callon
Chairman, President and Chief Executive Officer
March 27, 2015
Callon Petroleum Company UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☒ ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For The Fiscal Year Ended December 31, 2014
OR
☐ TRANSITION REPORT UNDER 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 ncorporation or Organization)
64-0844345
(IRS Employer Identification No.)
200 North Canal Street
Natchez, Mississippi
(Address of Principal Executive Offices)
39120
(Zip Code)
601-442-1601
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Common Stock, $.01 par value
10.0% Series A Cumulative Preferred Stock
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 whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒
Indicate by check mark whether 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 registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90
days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was
required to submit and post such files). Yes ☒ No ☐
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of
registrants 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 definition 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 ☒
Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2014 was approximately $456.3 million. The
Registrant had 55,510,729 shares of common stock outstanding as of February 27, 2015.
Portions of the definitive Proxy Statement of Callon Petroleum Company (to be filed no later than 120 days after December 31, 2014) relating to the Annual Meeting of
Stockholders to be held on May 14, 2015, which are incorporated into Part III of this Form 10-K.
DOCUMENTS INCORPORATED BY REFERENCE
TABLE OF CONTENTS
Special Note Regarding Forward-Looking Statements
Definitions
Part I
Items 1 and 2.
Business and Properties
Acquisitions and Divestitures
Oil and Natural Gas Properties
Reserves and Production
Production Wells and Leasehold Acreage
Other
Regulations
Available Information
Risk Factors
Unresolved Staff Comments
Legal Proceedings
Mine Safety Disclosures
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
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities
Performance Graph
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
Subsequent Events
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 Comprehensive Income
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
6
7
8
9
11
20
28
28
40
40
40
41
42
42
43
45
49
55
58
59
60
61
62
63
64
65
66
90
90
90
91
92
92
92
92
92
93
96
Special Note Regarding Forward Looking Statements
All statements, other than statements of historical fact, may be deemed to be forward-looking statements within the meaning
of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as
amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including,
without limitation, statements regarding the financial position, business strategy, production and reserve quantities, present
value and growth and other plans and objectives for our future operations, are forward-looking statements. Although we
believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements
are not guarantees of future performance.
Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or
assumed future results of operations and other statements in this Form 10-K identified by words such as “anticipate,”
“project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or
similar expressions.
You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks,
uncertainties and other factors that may affect our operations, markets, products, services and prices and 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 addition to any assumptions and other factors referred to
specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause our actual results
to differ materially from those indicated in any forward-looking statement include, but are not limited to:
the timing and extent of changes in market conditions and prices for oil, natural gas and NGLs (including regional
basis differentials),
our ability to transport our production to the most favorable markets or at all,
the timing and extent of our success in discovering, developing, producing and estimating reserves,
our ability to fund our planned capital investments,
the impact of government regulation, including regulation of endangered species, any increase in severance or
similar taxes, legislation relating to hydraulic fracturing, the climate and over-the-counter derivatives,
the costs and availability of oilfield personnel services and drilling supplies, raw materials, and equipment and
services,
our future property acquisition or divestiture activities,
the effects of weather,
increased competition,
the financial impact of accounting regulations and critical accounting policies,
the comparative cost of alternative fuels,
conditions in capital markets, changes in interest rates and the ability of our lenders to provide us with funds as
agreed,
credit risk relating to the risk of loss as a result of non-performance by our counterparties, 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, 2014 (the “2014 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 2014 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.
7
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.
Bbl or Bbls: barrel or barrels of oil or natural gas liquids.
Bcf: Billion cubic feet of natural gas.
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.
GHG: greenhouse gases.
LIBOR: London Interbank Offered Rate.
LOE: lease operating expense, including workover expense.
MBbls: thousand barrels of oil.
MBOE: thousand 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.\
PDPs: proved developed producing reserves.
PDNPs: proved developed non-producing reserves.
PUDs: proved undeveloped reserves.
RSU: restricted stock units.
SEC: United States Securities and Exchange Commission.
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.
8
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.
In 2013, we completed our onshore strategic repositioning that began in 2009, shifting our operations from the offshore
waters in the Gulf of Mexico to the onshore Permian Basin in West Texas. Our asset base is concentrated exclusively in the
Midland Basin, a sub-basin located within the broader Permian Basin, characterized by high drilling success rates, high oil
content, multiple vertical and horizontal productive intervals, and extensive production history. 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.
Our net daily production for calendar year 2014 was 5,648 BOE/d (approximately 82% oil), representing an approximately
155% increase over comparable net daily Permian production in 2013. The increase is primarily attributed to our increased
focus on horizontal development initiated in 2012. We currently operate two horizontal drilling rigs focused on four
prospective zones for development.
As of December 31, 2014, we had estimated net proved reserves of 25.7 MMBbls and 42.5 Bcf, or 32.8 MMBOE, all of
which were located in the Midland Basin. Additionally, 78% of our proved reserves were crude oil and 55% were proved
developed at year-end 2014 on a BOE basis.
Our Business Strategy
Our goal is to enhance stockholder value through the execution of the following strategy:
Drive production and maximize resource recovery and reserve growth through horizontal development of our resource
base. We believe our horizontal development efforts provide improved returns relative to vertical development of our
resource base. Our initial vertical development programs allowed us to amass a database related to the subsurface geology
and rock characteristics over the last several years. This information, combined with our review of industry activity and best
practices, provided the foundation for us to initiate the horizontal development of our resource base in 2012 and further
increase horizontal activity in recent quarters. As of December 31, 2014, we had 49 gross producing horizontal wells, all of
which we operate. During the fourth quarter of 2014, approximately 70% of our total Permian production was sourced from
horizontal wells. We expect to grow the contribution of horizontal production volumes, both from our existing properties and
from properties acquired in recent acquisitions, as we continue to execute a resource development program almost
exclusively focused on horizontal development.
Expand our drilling portfolio through evaluation of existing acreage. Our horizontal development drilling efforts to date
have been primarily focused on the Upper and Lower Wolfcamp B zones. We have focused on these development zones to
reduce drilling risk as we continue to grow our asset base in the Permian Basin, though we have continued to expand our
development focus on a measured basis. Most recently, we drilled three Lower Spraberry wells in the Southern and Central
Midland Basin in the second half of 2014, complementing three Wolfcamp A wells placed on production in the Southern
Midland Basin since the third quarter of 2013. We believe incremental opportunities exist to selectively target other
prospective zones across various positions of our acreage, including the Clearfork, Jo Mill, Middle Spraberry, Wolfcamp C
and Cline formations (in order of relative depth). In addition, we will continue to monitor the efficiency of our horizontal
wells related to reservoir drainage over time, and will pursue downspacing initiatives within target zones if we believe overall
returns would be enhanced.
Pursue selective acquisitions in the Permian Basin. During 2014, we continued to demonstrate our ability to acquire and
trade acreage in the Midland Basin. Most significantly, we acquired 6,230 gross (3,862 net) acres located in Midland and
Andrews Counties, which are in close proximity to our existing Carpe Diem and Pecan Acres fields, for approximately $210
million. Due to its close proximity to our existing fields, we believe this acquired acreage can be efficiently integrated into
our ongoing horizontal development activity. The acquisition added 194 gross (121.6 net) potential horizontal drilling
locations targeting the currently producing Wolcamp B, Lower Spraberry and Middle Spraberry zones, and additional
potential horizontal drilling locations targeting four other prospective zones that are producing in offsetting fields. We also
expanded our asset base in existing core development fields by acquiring 1,527 net acres for approximately $8.2 million
through a “bolt-on” strategy whereby we identify and pursue smaller blocks of offsetting acreage that are potentially
9
inefficient for the current owner to develop, but have value to Callon based on its location relative to our acreage. These
smaller scale acquisitions generally provide acreage at costs significantly below the value assigned to larger blocks of
acreage. While remaining mindful about our liquidity, we will continue to pursue leasehold acquisitions in the Permian
Basin, and primarily in the Midland Basin, that have horizontal resource potential that can be further augmented by “bolt-on
acreage” acquisitions and acreage trades over time.
Maintain financial liquidity and capacity to capitalize on growth opportunities. We believe that our asset base provides the
opportunity to deploy a significant amount of capital for horizontal development in the coming years. We have focused on
positioning ourselves to supplement our cash flow from operations with an improved cost of debt capital. In conjunction with
our acquisition completed in the fourth quarter of 2014, we raised approximately $430 million in gross proceeds through a
combination of common equity and long-term debt securities to support the acquisition and our ongoing development efforts
in the Midland Basin.
Our Strengths
Established resource base and acreage position in 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 approximately 18,065 net surface acres in the Southern and
Central Midland Basin that are prospective for multiple oil-bearing intervals that have been produced by us and other
industry participants. As of December 31, 2014, our estimated net proved reserves were comprised of approximately 78% oil
and 22% natural gas, which includes NGLs in the production stream.
Multi-year drilling inventory. Our current acreage position in the Permian Basin provides visible growth potential from a
horizontal drilling inventory of approximately 525 locations, or 20 years under our current two-rig horizontal drilling
program, based solely on four currently producing zones, which include the Lower Spraberry, the Wolfcamp A and the
Upper and Lower Wolfcamp B. This drilling inventory increases to over 1,000 drilling locations, with the addition of drilling
locations from other prospective zones, which include the Clearfork, Middle Spraberry, Jo Mill, Wolfcamp C and the Cline
(or Wolfcamp D). Our identified well locations across our Southern and Central Midland Basin acreage are based upon the
results of horizontal wells drilled by us and other offsetting operators, and our analysis of core data and historical vertical
well performance.
Experienced team operating in the Permian Basin. We have assembled a management team experienced in acquisitions,
exploration, development and production in the Midland Basin. Reflective of this experience, we have realized improvements
in our drilling and capital efficiency since launching our horizontal drilling program in 2012 and drilling more than 50
horizontal wells with lengths varying from approximately 5,000 feet to 10,000 feet. We continue to evaluate our completion
techniques, and downspacing initiatives that we believe have the potential to improve resource recovery and contribute to
enhanced returns on capital. 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 best performing operators and evaluate and adopt best practices.
High degree of operational control. We operate nearly all of our Permian Basin acreage and have limited continuous
drilling requirements across our acreage. For example, only 10% of our planned development drilling activity in 2015 is
required to satisfy acreage commitments, with decreasing obligations in future years. This acreage status, combined with our
control as an operator across the majority of our properties, provides us the opportunity to modify our operational plans to
respond to changes in operational and commodity price environments. In addition, we have the ability to change our drilling
schedule as needed to manage the assimilation of newly acquired acreage that may have drilling commitments.
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 planning,
training and communication, and empowering both our employees and third party service providers with Stop Work
Authority, we continue to improve operational performance. Callon has enhanced Management of Change, routine
inspections and compliance action tracking methods with the implementation of a HSE management system software
program. 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.
10
Exploration and Development Activities
Our 2014 total capital expenditures, including acquisitions, were $455.5 million, representing a 166% increase over 2013
capital expenditures. Of the $455.5 million, $217.7 million was allocated to drilling, development and leasehold acquisition
activity in the Permian Basin. During 2014, we drilled 27 gross (24.4 net) horizontal and 7 gross (4.3 net) vertical wells,
while completing 31 gross (27.3 net) horizontal and 5 gross (3.1 net) vertical wells. Capital expenditures for 2014 included
the following expenditures (in millions):
Southern Midland Basin
Central Midland Basin
Northern Midland Basin
Total operational expenditures
$
Capitalized general and administrative costs allocated directly to exploration and development projects
Capitalized interest
Total capitalized general and administrative and interest costs
Total operational expenditures inclusive of capitalized general and administrative and interest costs
Acquisitions
Total capital expenditures
$
160.3
56.9
0.5
217.7
12.5
2.4
14.9
232.6
222.9
455.5
In late 2014, we expanded our horizontal pad development efforts to six fields. We expect our 2015 horizontal drilling
program will be primarily focused on development of established Upper and Lower Wolfcamp zones in the Southern and
Central Midland Basin. We also expect to drill five wells in the Southern and Central Midland Basin targeting the Lower
Spraberry shale formation and one well targeting the Wolfcamp A shale formation.
Recent Developments
We are currently operating two horizontal drilling rigs, complemented by an additional vertical rig that is being used to drill
the vertical section of horizontal wells. Based on current commodity market conditions, the Company has elected to release
the vertical rig in mid-March and focus on a two-rig horizontal program for the balance of 2015.
Oil and Natural Gas Properties
As of December 31, 2014, our estimated net proved reserves totaled 32.8 MMBOE and included 25.7 MMBbls of oil and
42.5 Bcf, of natural gas with a pre-tax present value, discounted at 10%, of $629.7 million. Pre-tax present value is a non-
GAAP financial measure, which we reconcile to the GAAP measure of standardized measure of $579.5 million in note (d) to
the table below. Oil constituted approximately 78% of our total estimated equivalent net proved reserves and approximately
77% of our total estimated equivalent proved developed reserves.
The following table sets forth certain information about our estimated net proved reserves prepared by our independent
petroleum reserve engineers by major area and for all other properties combined at December 31, 2014:
Estimated Net Proved Reserves
Natural Gas
(MMcf)
Oil
(MBbls)
Total
(MBoe)
(a)
Pre-tax
Discounted
Present
Value
($000)
(b)(c)(d)
Southern Midland Basin
Central Midland Basin
Northern Midland Basin
Other
Total
16,973
8,736
24
—
25,733
26,102
16,337
109
—
42,548
21,323 $
11,459
42
—
32,824 $
416,463
219,286
803
(6,872)
629,680
11
(a) We convert Mcf to BOE using a conversion ratio of six Mcf to one Bbl. This ratio, which is typical in the industry and
represents the approximate energy equivalent of a Mcf to a Bbl, does not reflect to market price equivalence of Mcf of natural
gas compared with a Bbl of oil or NGLs. On a market price equivalence basis, a barrel of oil or NGLs has a substantially
higher price than six Mcf of natural gas.
(b) Represents the present value of future net cash flows before deduction of federal income taxes, discounted at 10%,
attributable to estimated net proved reserves as of December 31, 2014, as set forth in the Company’s reserve reports prepared
by its independent petroleum reserve engineers, DeGolyer and MacNaughton.
(c) Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at
December 31, 2014, in accordance with accounting for asset retirement obligations rules. These obligations were retained
following the sale of our offshore operations. The negative Pre-Tax Discounted Present Value of the “Other” reflects
plugging and abandonment obligations exceeding the future net cash flows.
(d) 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 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 gas producing activities for our proved reserves as of December 31, 2014 was $579.5 million inclusive of the
$50.1 million discounted estimated future income taxes relating to such future net revenues. The projected per Mcf natural
gas price of $6.38 used in the 2014 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 $86.30 used in the 2014 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.
Permian Basin
As of December 31, 2014, we owned leaseholds in 27,366 net acres in the Permian Basin. Average net production from the
Company’s Permian Basin properties increased 155% to 5,648 BOE/d in 2014 from 2,227 BOE/d in 2013.
Southern Midland Basin
Counties (fields)
o Upton (East Bloxom and Opal)
o Reagan (Taylor Draw and Garrison Draw)
o Crockett (Block 5)
10,790 net acres as of December 31, 2014
59 gross (54 net) vertical and 39 gross (36 net) horizontal producing wells as of December 31, 2014
Initiated horizontal development in 2012
4th quarter 2014 net production: 4,519 BOE/d (90% horizontal)
The Southern Midland Basin is our largest operating area in terms of production. We currently have 10,790 net acres in this
area. We commenced horizontal drilling efforts at our East Bloxom field in 2012 and have expanded our efforts to two
additional fields in the Southern Midland Basin using pad development. Our horizontal wells are currently producing from
three zones of the Wolfcamp shale (Upper Wolfcamp B, Lower Wolfcamp B and Wolfcamp A). We plan to continue
focusing on these intervals in 2015 and also place our first Lower Spraberry well on production in the first quarter of 2015.
Central Midland Basin
Counties (fields)
o Midland (Carpe Diem, Pecan Acres, Casselman and Bohannon)
o Ector (Kayleigh and Bohannon)
o Andrews (Bohannon)
o Martin (Casselman)
7,275 net acres as of December 31, 2014
12
218 gross (144 net) vertical and 11 gross (8 net) horizontal producing wells as of December 31, 2014
Initiated horizontal development in 2013
4th quarter 2014 net production: 2,736 BOE/d
The Central Midland Basin has historically been the focus of our high-graded vertical drilling program, targeting multiple
zones down to the Woodford shale. We shifted our focus to horizontal development in this area with our initial Wolfcamp B
wells placed on production in the first quarter of 2014 in our Carpe Diem field. We have continued with program
development of both the Wolfcamp B and Lower Spraberry zones in this field over the course of the year and are currently
expanding our horizontal development to the Pecan Acres field. Importantly, we recently completed our last vertical well in
the area and have no plans or obligations to drill any future vertical wells within our Permian Basin property base.
In addition to this organic drilling activity, in October 2014 we acquired 6,230 gross (3,862 net) acres located in Midland,
Andrews and Martin Counties, which are in close proximity to our existing Carpe Diem and Pecan Acres fields. Since the
closing of the acquisition, we have placed two Wolfcamp B and one Lower Spraberry wells on production.
Northern Midland Basin
We acquired 21,617 net acres in Borden and Lynn Counties in 2012. We currently own 9,301 net acres following our
decision to allow acreage in the Northern Midland Basin to expire as we refined our targeted areas for exploration. At this
time, we have no plans for future activity and anticipate that our Northern Midland Basin acreage will expire in its entirety by
2016. As such, we reclassed approximately $25 million of the carrying value of our Northern Midland acreage that were
classified as unevaluated properties to evaluated properties. We have no PUDs attributable to this acreage. At December 31,
2014, we had one gross (one net) producing vertical well in this area.
For additional details regarding our Permian wells and related information, please see “Present Activities and Productive
Wells” included below within this Item.
Other Property
We own a leasehold in 37,326 net acres located in various counties in Nevada. These leases are with the Bureau of Land
Management and carry primary terms that expire in 2018 and 2019. We are evaluating this acreage in conjunction with a
third-party consultant and developing options for future activity. Callon does not have any drilling commitments related to
this acreage during the primary term. However, we reclassed approximately $3 million of the carrying value of our Nevada
acreage that were classified as unevaluated properties to evaluated properties. We have no PUDs or drilling commitments
attributable to this acreage. We own additional immaterial properties in Louisiana.
Proved Reserves
Estimates of volumes of proved reserves at year-end, net to our interest, are presented in MBbls for oil and in MMcf for
natural gas, including NGLs, at a pressure base of 15.025 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.
The following table sets forth certain information about our estimated net proved reserves. All of our proved reserves are
currently located in the continental United States and also included volumes in federal and state waters in the Gulf of Mexico
at year-end 2012.
13
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
Estimated pre-tax future net cash flows (b)
Pre-tax discounted present value (b) (c)
Standardized measure of discounted future net cash flows (b) (c)
For the Year Ended December 31,
2014 (a)
2013 (a)
2012 (a)
14,006
25,171
18,201
11,727
17,377
14,623
25,733
42,548
32,824
5,960
9,059
7,470
5,938
8,692
7,387
11,898
17,751
14,857
4,955
10,680
6,735
5,825
9,073
7,337
10,780
19,753
14,072
$ 1,330,628 $
629,680 $
$
579,542 $
$
680,627 $
301,144 $
283,946 $
592,424
250,097
231,148
(a) The Company’s estimated proved reserves as of December 31, 2014 were prepared by DeGolyer and MacNaughton and
estimated proved reserves as of December 31, 2013 and 2012 were prepared by Huddleston & Co.
(b) Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at
December 31, 2014 and 2013, in accordance with accounting for asset retirement obligations rules.
(c) 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 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 gas producing activities for our proved reserves as of December 31, 2014 was $579.5 million inclusive of the
$50.1 million discounted estimated future income taxes relating to such future net revenues. The projected per Mcf natural
gas price of $6.38 used in the 2014 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 $86.30 used in the 2014 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, PDPs, PUDs 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 121% to 32.8 MBOE from 14.9 MBOE at December 31, 2014 and
2013, respectively. Additions during the year were due to (1) 15.7 MMBOE related to the Company’s horizontal
development of a portion of its Permian Basin properties and (2) 4.7 MMBOE related to acquired properties in the Permian
Basin. These increases were partially offset by (1) 2.1 MMBOE related to the Company’s production during 2014 and (2) 0.3
MMBOE of net revisions, including 0.8 MMBOE of positive performance-related revisions that were offset by 1.1 MMBOE
of PUD reclassifications.
Proved Undeveloped Reserves (PUDs)
Annually, the Company reviews its PUDs to ensure appropriate plans exist for development. PUD reserves are recorded only
if the Company has plans to convert these reserves into PDPs within five years of the date they are first recorded. Our
development plans include the allocation of capital to projects included within our 2015 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 2015 capital budget and our long-range capital plans are primarily governed by our expectations of internally
14
generated cash flow and credit facility borrowing availability. 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):
For the Year Ended December 31,
2013
2012
2014
Permian Basin
Medusa (a)
Total
14,623
—
14,623
7,387
—
7,387
6,040
1,297
7,337
(a) Effective July 1, 2013, we sold our interest in the Medusa field. See Note 3 for additional information.
Our PUDs increased 98% to 14.6 MMBOE from 7.4 MMBOE at December 31, 2014 and 2013, respectively. We added 10.1
MMBOE to our PUDs, net of revisions, primarily from the continued horizontal development of our Permian Basin
properties. The increase in PUDs was partially offset by the reclassification of 1.8 MMBOE, 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 $34.6 million, net. Also offsetting the increase was the removal of 1.1 MMBOE of PUDs, including the
impact from the reclassification of previous vertical PUDs to the horizontal probable category given our focus on horizontal
development.
The Company plans to develop its PUDs as part of a multi-year drilling program. At December 31, 2014, we had no reserves
that remained undeveloped for five or more years, and all PUD drilling locations are currently scheduled to be drilled within
three to 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 Senior Vice President of Operations,
who has over 35 years of industry experience including 27 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 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 40 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 American Association of Petroleum Geologists.
All of the information regarding 2013 and 2012 reserves in this annual report is derived from reserve reports prepared by
Huddleston & Co., Inc., a Texas engineering firm.
To further enhance the control environment over the reserve estimation process, our Strategic Planning 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.
15
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.
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).
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
For the Year Ended December 31,
2012
2013
2014
1,692
2,220
2,062
911
3,011
1,413
977
3,588
1,575
139,374 $
12,488
151,862 $
88,960 $
13,609
102,569 $
96,584
14,149
110,733
22,372 $
8,973
31,345 $
19,779 $
4,133
23,912 $
23,330
3,224
26,554
82.37 $
84.85
5.63
5.59
73.65
75.64
10.85 $
4.35
15.20 $
97.65 $
99.32
4.52
4.47
72.59
73.56
14.00 $
2.92
16.92 $
97.41
98.86
3.94
3.94
69.43
70.41
14.81
2.05
16.86
$
$
$
$
$
$
$
16
Present Activities and Productive Wells
The following table sets forth the wells drilled and completed during the periods indicated. All such wells were drilled in the
continental United States.
Southern Midland Basin
Vertical wells
Horizontal wells
Total
Central Midland Basin
Vertical wells
Horizontal wells
Total
Northern Midland Basin
Vertical wells
Total
Total vertical wells
Total horizontal wells
Total
Drilled
Completed (a)
Gross
Net
Gross
Net
Awaiting Completion
Gross
Net
1
22
23
4
5
9
2
2
7
27
34
1.0
20.1
21.1
1.8
4.3
6.1
1.5
1.5
4.3
24.4
28.7
1
22
23
3
9
12
1
1
5
31
36
1.0
20.1
21.1
1.3
7.2
8.5
0.8
0.8
3.1
27.3
30.4
—
3
3
1
—
1
—
—
1
3
4
—
3.0
3.0
0.4
—
0.4
—
—
0.4
3.0
3.4
(a) Completions include wells drilled prior to 2014.
The following table sets forth the Company’s drilled and completed wells, none of which were natural gas or nonproductive
for the periods reflected:
Oil wells
Development
Exploratory
Total
2014 (a)
2013
2012
Gross
Net
Gross
Net
Gross
Net
19
13
32
15.5
11.7
27.2
19
7
26
17.2
5.0
22.2
14
7
21
9.7
6.2
15.9
(a) Does not include two gross (two net) non-producing exploratory wells.
The following table sets forth productive wells as of December 31, 2014:
Working interest
Royalty interest
Total
Oil Wells
Gross
Net
Natural Gas Wells
Gross
Net
328
3
331
243.0
0.1
243.1
—
—
—
—
—
—
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.
17
For the periods presented, the following table sets forth by major field(s) net production volumes and percentage of estimated
proved reserves:
For the Year Ended December 31,
Production Volumes (MBOE)
2012
2013
2014
% of Total Proved Reserves
2013
2014
2012
Permian Basin:
Southern Midland Basin
Central Midland Basin
Northern Midland Basin
Total
1,497
549
16
2,062
612
193
8
813
402
189
—
591
65%
35%
0%
100%
85%
14%
1%
100%
51%
16%
0%
67%
Offshore and other (a)
—
600
984
0%
0%
33%
Total
2,062
1,413
1,575
100%
100%
100%
(a) In late 2013, we sold the remaining interests in our producing offshore fields and in the Haynesville shale.
Leasehold Acreage
The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of December
31, 2014.
Louisiana
Texas (a)
Federal onshore (b)
Total
(a)
Developed
Gross
Net
Undeveloped
Net
Gross
Total
Gross
Net
936
20,991
—
21,927
200
16,487
—
16,687
188
12,498
37,626
50,312
55
1,124
10,879 33,489
37,326 37,626
48,260 72,239
255
27,366
37,326
64,947
A portion of our Texas acreage requires continuous drilling to hold the acreage for which we have included in our
development plans, though the cost to renew this acreage, if necessary, is not considered material.
(b)
The Company’s lease of this acreage, located in Nevada, expires in 2018 and 2019. The lease requires no drilling
activity to hold the acreage, and we continue to evaluate our position and monitor the activity of other operators
conducting drilling in the area.
Undeveloped Acreage Expirations
The following table sets forth by geographic area as of December 31, 2014 the number of our leased gross and net
undeveloped acres 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.
Texas
Southern Permian Basin
Central Permian Basin
Northern Permian Basin (a)
Nevada (b)
Total
2015
2016
2017
Total
Net
Gross
165
—
7,307
—
7,472
—
—
648
—
648
—
—
—
—
—
165
—
7,955
—
8,120
165
—
10,575
—
10,740
(a)
7,916 of the total remaining net acres include extension options that would allow us to extend the primary term for
a period of two years.
(b) The Company’s lease of this acreage does not expire until 2018 and 2019.
18
The expiring acreage set forth in the table above accounts for 17% of our net undeveloped acreage (48,260 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 only those onshore operations that
it is contractually bound to do so. At the depths and in the areas in which the Company operates, and in light of the vertical
and horizontal drilling that it undertakes, the Company typically does not encounter high pressures or extreme drilling
conditions onshore.
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.
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.
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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.
Major Customers
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
Plains Marketing, L.P.
Sunoco
Shell Trading Company
Other
Total
For the Year Ended December 31,
2013
2014
2012
51%
22%
10%
0%
17%
100%
38%
15%
0%
31%
16%
100%
32%
15%
0%
39%
14%
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.
Corporate Offices
The Company’s headquarters are located in Natchez, Mississippi, in approximately 51,500 square feet of owned space. 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 109 employees as of December 31, 2014. None of the Company’s employees are currently represented by a
union, and the Company believes that it has good relations with its employees.
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. This 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;
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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 the Department of the
Interior (“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. The industry historically 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 U.S. Environmental
Protection Agency (“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 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 2014-2016 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.
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
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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.”
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 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. 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. These laws
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and regulations also prohibit the discharge of dredge or fill material in regulated waters, including wetlands, unless
authorized by a permit issued by the U.S. Army Corps of Engineers. 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 and incur capital costs in order to remain in compliance. For example, on April 17, 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.
Greenhouse Gas (“GHG”) 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 could require us to incur significant costs to monitor, keep records of, and
potentially report GHG emissions associated with our operations if the reporting threshold is reached with production
growth. The EPA recently announced its intention to take measures to require or encourage reductions in methane emissions,
including from oil and natural gas operations. Those measures include the development of NSPS regulations in 2016 for
reducing methane from new and modified oil and gas production sources and natural gas processing and transmission
sources.
In addition to possible federal regulation, a number of states, individually and regionally, also are 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 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.
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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 generally is 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 in recent sessions of Congress 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. At the same time, the White House Council on Environmental Quality is
coordinating an administration-wide review of hydraulic fracturing practices and the EPA has commenced a study of the
potential impacts of hydraulic fracturing activities on drinking water resources. The EPA has announced that it plans to
propose standards in 2014 that such wastewater must meet before being transported to a treatment plant. As part of these
studies, the EPA has requested that certain companies provide them with information concerning the chemicals used in the
hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing
under the SDWA or otherwise.
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 wells to address emissions of sulfur dioxide and volatile
organic compounds, or VOCs, and 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 emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured
gas wells constructed or refractured after January 1, 2015. 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
by January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the
environmental community, and court challenges to the rules were also filed. The EPA may issue revised rules that are likely
responsive to some of these requests. If revised, these rules could require modifications to our operations or increase our
capital and operating costs without being offset by increased product capture. At this point, we cannot predict the final
regulatory requirements or the cost to comply with such requirements with any certainty. In addition, the U.S. Department of
the Interior published a revised proposed rule that would update existing regulation for hydraulic fracturing activities on
federal lands, including requirements for disclosure, well bore integrity and handling of flowback water. EPA has announced
that it is considering regulations under the Toxic Substance Control Act to require evaluation and disclosure of hydraulic
fracturing.
In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of
hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing’s
potential impacts, most notably the EPA’s study on the environmental impacts of hydraulic fracturing, the final results of
which are not yet available.. These ongoing or proposed studies, depending on their degree of pursuit and whether any
meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other
regulatory authorities.
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 an
internet 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.
24
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 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 to the operator in connection with exploration and operating 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 were 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 Bureau of Land Management (“BLM”) (which
administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such
designations in effect. The Company owns an interest in federal leaseholds in Nevada. It is possible that holders of the
Company’s equity interests may be citizens of foreign countries, which could be determined to be citizens of 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.
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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 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.
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 affect 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
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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.
FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which
we 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.
Under FERC’s current regulatory regime, transmission 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. Gathering
service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters.
Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-
jurisdictional gathering facilities, which has the tendency to increase 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.
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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.
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 Internet web site (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 Internet site (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 Investors section of our Internet web site our Code of Business Conduct and Ethics,
Corporate Governance Guidelines, and Audit, Compensation 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
web site 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.
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, and the oil and natural gas markets
are cyclical. Approximately 80% of our anticipated 2015 production, on a BOE basis, is oil. Starting in the second half of
2014, the NYMEX price for a barrel of oil has fallen sharply, from a price of $105.37 on June 30, 2014 to $49.76 on
February 27, 2015. 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, and 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;
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our ability to attract capital to finance our operations and the cost of the capital;
the amount we are allowed to borrow under our credit facilities;
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 Note 13 to our Consolidated Financial Statements.
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.
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, 2014 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, 2014, approximately 25% of the discounted present value of our
estimated net proved reserves consisted of PUDs. PUDs represented 45% 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 undeveloped reserves 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.
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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 requires substantially
greater capital expenditures, currently expected to be in excess of three times the cost, as compared to the drilling of a
traditional vertical well. 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 under our credit facility and public debt and equity financings. In 2014, our total
capital expenditures, including expenditures for leasehold interests and property acquisitions, drilling, seismic and
infrastructure, were approximately $455.5 million. Our 2015 capital budget for drilling, completion and infrastructure is
estimated to be approximately $150 to $165 million. 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 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 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 revolving credit facility and second lien term loan facility contain restrictive covenants that may limit our ability
to respond to changes in market conditions or pursue business opportunities. Our credit facilities restrictive covenants
that limit our ability to, among other things:
incur additional indebtedness;
create additional liens;
sell assets;
merge or consolidate with another entity;
pay dividends or make other distributions;
engage in transactions with affiliates; and
enter into certain swap agreements.
In addition, we will be required to use substantial portions of our future cash flow to repay principal and interest on our
indebtedness. Our credit facilities require us to maintain certain financial ratios and tests, including a minimum asset value
coverage ratio of total debt. The requirement that we comply with these provisions may materially adversely affect our ability
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.
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Our borrowings under our revolving credit facility and second lien term loan facility expose us to interest rate
risk. Our earnings are exposed to interest rate risk associated with borrowings under our 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 1.75% to
2.75% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. Our second
lien term loan bears interest at a rate of LIBOR, subject to a floor of 1%, plus 7.50%. If interest rates increase, so will our
interest costs, which may have a material adverse effect on our results of operations and financial condition.
The borrowing base under our revolving credit facility may be reduced below the amount of borrowings outstanding
under such facilities. Under the terms of our 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 on or about March 31, 2015. In addition, the portion of
our borrowing base made available to us is subject to the terms and covenants of the revolving credit facility including,
without limitation, compliance with the financial performance covenants of such facility. In the event the amount outstanding
under our 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 or (ii) repay such excess borrowings over five monthly installments. 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 revolving credit facility.
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 has 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 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, dispose of or
recycle 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 our drilling and hydraulic fracturing processes. Historically, we have been able
to secure water from local landowners and other sources for use in our operations. During the last few years, West Texas has
experienced extreme drought conditions. As a result of the severe drought, some local water districts may begin restricting
the use of water under their jurisdiction for drilling and hydraulic fracturing to protect the local water supply. If we are unable
to obtain water to use in our operations from local sources, we may be unable to economically produce oil, NGLs and natural
gas, which could have an adverse effect on our business, financial condition and results of operations.
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 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 delays 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:
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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;
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 45% of our total estimated proved reserves as of December 31,
2014, were proved 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.
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We maybe unable to integrate successfully the operations of future acquisitions with our operations, and we may not
realize all the anticipated benefits of these acquisitions. Our business may include producing property acquisitions that
would include undeveloped acreage. We can offer no assurance that we will achieve the desired profitability 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:
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;
storms and other extreme weather conditions could cause damages to our production facilities or wells.
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.
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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;
federal regulations generally prohibiting the export of U.S. crude oil;
federal regulations applicable to exports of liquefied natural gas (LNG);
the proximity of hydrocarbon production to pipelines;
the availability of pipeline 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, capacity may be limited and it may be
necessary for new interstate and intrastate pipelines and gathering systems to be built.
The marketability 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 substantial 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 formations using horizontal drilling and completion
techniques. The results of our planned drilling program in these formations may be subject to more uncertainties than
conventional drilling programs in more established formations and may not meet our expectations for reserves or
production. The results of our recent horizontal drilling efforts in new or emerging formations, including certain intervals in
the Wolfcamp shale, the Spraberry shale and the Cline shale in the Permian basin, are generally more uncertain than drilling
34
results in areas that are developed and have established production. Because new or emerging formations have limited or no
production history, we are less able to rely on past drilling results in those areas as a basis predict our future drilling results.
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. 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 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 its rulemaking proceedings still pending under
the Dodd-Frank Act, the CFTC approved on November 5, 2013, a proposed rule imposing position limits for certain futures
and option contracts in various commodities (including natural gas) and for swaps that are their economic equivalents.
Certain specified types of hedging transactions are exempt from these position limits, provided that such hedging transactions
35
satisfy the CFTC’s requirements for “bona fide hedging” transactions or positions. Similarly, the CFTC has issued a
proposed rule on margin requirements for swap transactions, which proposes an exemption for commercial end-users,
entering 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 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 margin
requirements, depending on the Company’s 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 require us
to comply with position limits, margin requirements and with certain clearing and trade-execution requirements in connection
with financial derivative activities. 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.
If we reduce our use of derivative contracts as a result of the 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.
By hedging, we may not benefit from price increases. Hedging can prevent us from receiving the full advantage of
increases in oil or natural gas prices above the fixed amount specified in a hedge transaction in the case of a swap. We also
enter into price “collars” to reduce the risk of changes in oil and natural gas prices. Under a collar, no payments are due by
either party so long as the market price is above a floor set in the collar and below a ceiling. If the price falls below the floor,
the counter-party to the collar pays the difference to us and if the price is above the ceiling, we pay the counter-party the
difference. Another type of hedging contract we have entered into is a put contract. Under a put, if the price falls below the
set floor price, the counter-party to the contract pays the difference to us. See “Quantitative and Qualitative Disclosures
About Market Risks” for a discussion of our hedging practices.
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
36
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.
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 51% of our total
oil and natural gas revenues for the year ended December 31, 2014. 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 in connection with drilling and production activities;
limit or prohibit drilling activities on protected areas such as wetlands and wilderness 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, 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 and 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 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 gasses” (“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 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 recently announced its intention to take
measures to require or encourage reductions in methane emissions, including from oil and natural gas operations. Those
measures include the development of NSPS regulations in 2016 for reducing methane from new and modified oil and gas
production sources and natural gas processing and transmission sources.
37
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 have to incur costs associated with this reporting obligation.
In addition, the United States Congress has considered (but not passed) legislation to reduce emissions of GHGs and many
states 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 March 2010, the EPA announced that it would conduct a wide-ranging
study on the effects of hydraulic fracturing on drinking water resources. A progress report was issued in December 2012; a
final report is not yet available. The agency also announced that one of its enforcement initiatives for 2014 to 2016 would be
to focus on 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.
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 announced that it will ban 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 has announced initiatives under the CWA to
38
establish standards of wastewater from hydraulic fracturing and under TSCA to develop regulations governing the disclosure
and evaluation of hydraulic fracturing chemicals, and the BLM has indicated that it will continue with rulemaking to regulate
hydraulic fracturing on federal lands. 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 NSPS and 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.
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. It is unclear whether any such changes will be
enacted or how soon any such changes would become effective. The passage of any legislation as a result of these proposals
or any other similar changes in U.S. federal income tax laws could negatively affect the Company’s 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 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 our 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. 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. In addition,
the terms of our credit facilities prohibit us from paying dividends and making other distributions.
39
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.
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.
40
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
2014
2013
$
High
Low
High
Low
9.00 $
11.75
12.09
8.99
6.13 $
8.15
8.46
4.09
5.82 $
4.00
5.49
7.60
3.62
3.19
3.40
5.18
As of February 27, 2015 the Company had approximately 2,995 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 Series A 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 Series A Preferred Stock is paid in full, we cannot declare or pay any dividend on our common stock.
During the fourth quarter of 2014, neither the Company nor any affiliated purchasers made repurchases of Callon’s equity
securities.
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, 2014 (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
Weighted-average
exercise price of
outstanding options,
warrants and rights
Number of
securities remaining
available for future
issuance under
equity
compensation plans
15 $
15 $
30 $
13.71
14.37
14.04
1,132
-
1,132
41
For additional information regarding the Company’s benefit plans and share-based compensation expense, see Notes 8 and 9
to the Consolidated Financial Statements.
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 Oil Exploration & Production Index from
December 31, 2009, through December 31, 2014.
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 2014
Company/Market/Peer Group
Callon Petroleum Company
S&P 500 Index - Total Returns
SIG Oil Exploration & Production Index
$
2009
2010
2011
2012
2013
2014
100.00 $
100.00
100.00
394.67 $
115.06
123.12
331.33 $
117.49
111.96
313.33 $
136.30
104.20
435.33 $
180.44
131.89
363.33
205.14
94.56
For the Year Ended December 31,
ITEM 6. Selected Financial Data
The following table sets forth, as of the dates and for the periods indicated, selected financial information about us. The
financial information for each of the five years in the period ended December 31, 2014 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).
42
2014
For the Year Ended December 31,
2012
2011
2013
2010
$ 151,862 $ 102,569 $ 110,733 $ 127,644 $
89,882
$ 113,592 $
38,270
37,766
91,905 $ 100,043 $ 88,022 $
10,690
10,664
39,622
2,747 106,396
4,304
68,703
21,179
8,386
$
$
0.67 $
0.65 $
(0.01) $
(0.01) $
0.07 $
0.07 $
2.81 $
2.76 $
0.29
0.28
44,848
40,133
39,522
37,908
28,817
45,961
40,133
40,337
38,582
29,476
$
94,387 $
(452,501)
356,070
54,475 $
(79,804)
27,202
51,290 $ 79,167 $ 100,102
(59,738)
(93,703) (91,511)
(26,252)
38,703
(243)
$ 742,155 $ 324,187 $ 269,521 $ 215,912 $ 168,868
876,770 423,953 378,173 369,707 218,326
75,748 120,668 125,345 165,504
335,000
15,810
433,735 279,094 205,971 201,202
Statement of Operations Data
Operating revenues
Oil and natural gas sales
Operating expenses
Total operating expenses
Income from continuing operations
Net income (a)
Earnings (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 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)
8,149
32,957
13,641
$ 579,542 $ 283,946 $ 231,148 $ 270,357 $ 198,916
Net income for 2011 includes $69.3 million of income tax benefit related to the reversal of the Company’s deferred
tax asset valuation allowance. See Note 10 for additional information.
10,780
19,753
14,072
10,075
35,118
15,928
11,898
17,751
14,857
25,733
42,548
32,824
(a)
(b) See Note 4 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.
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
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, and
more specifically, the Midland Basin. Our operations to date have been predominantly focused on horizontal drilling of
several prospective intervals, including multiple levels of the Wolfcamp formation. We have assembled a multi-year
43
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 acreage purchases, joint ventures and asset
swaps. Our production was approximately 82% oil and 18% natural gas for the year ended December 31, 2014. On December
31, 2014, our net acreage position in the Permian Basin was 27,366 net acres, including 9,301 net acres in the Northern
Midland Basin that the Company plans to let expire.
Significant accomplishments for 2014 include:
Acquired 6,230 gross (3,862 net) surface acres in Midland, Andrews, Martin and Ector Counties for
approximately $210 million, which added over 1,300 BOE/d of production and approximately 194 gross (121.6 net)
potential horizontal drilling locations (see below);
Expanded our existing core development areas in Upton and Reagan Counties by acquiring 1,527 net acres for $8.2
million;
Increased Permian Basin annual production in 2014 by 155% to 2,062 MBOE as compared to 2013;
Increased 2014 proved reserves by 121% to 32.8 MMBOE as compared to 2013;
Placed a total of 31 gross horizontal wells on production from four distinct intervals;
Retired the remaining $48.5 million of the 13% Senior Notes, improving our cost of capital; and
Completed a common stock offering for $129.4 million in gross proceeds and entered into a new $300 million
second lien term loan to partially fund the previously mentioned acquisition and planned capital expenditures.
Increased the Credit Facility’s borrowing base to $250 million with a syndicate of 10 lending institutions;
Acquisition activity
In the first quarter of 2014, the Company acquired 1,527 net acres in Upton and Reagan Counties, Texas, which are located
in the Southern Midland Basin near its existing core development fields, for an aggregate cash purchase price of $8.2 million.
The properties bear a working interest of 100% and an average net revenue interest of 78%.
On October 8, 2014, the Company completed the acquisition of undeveloped acreage and producing oil and gas properties
located in Midland, Andrews, Martin and Ector Counties, Texas. Including estimated purchase price adjustments, total net
consideration paid for the acquisition was approximately $210 million for an estimated 62% working interest (46.5% net
revenue interest).
Key attributes of the acquired fields in the Central Midland Basin include:
6,230 gross (3,862 net) surface acres, 95% of which are located in Midland and Andrews Counties, in close
proximity to the Company’s existing Carpe Diem and Pecan Acres fields in Midland County
194 gross (121.6 net) potential horizontal drilling locations targeting the Wolfcamp B, Lower Spraberry and Middle
Spraberry zones which are currently producing in offsetting fields
255 gross (159.9 net) additional potential horizontal drilling locations targeting four other prospective zones
including the Wolfcamp A, Wolfcamp D (Cline), Clearfork and Jo Mill
100% of targeted horizontal zones held by production
The Company assumed operatorship of the properties November 1, 2014 and currently owns an estimated 62.7% working
interest after the recent purchase of additional working interests in October 2014. See Note 3 in the Footnotes to the Financial
Statements for additional information regarding the acquisition.
Operational Highlights
Following the sale of our remaining producing offshore and Haynesville properties in the fourth quarter of 2013, all of our
producing properties are located in the Permian Basin. As a result of our acquisition and horizontal development efforts, our
Permian production grew 154% in 2014 compared to 2013, increasing to 2,062 MBOE from 813 MBOE, respectively. Our
production in 2014 was approximately 82% oil and 18% natural gas.
44
Permian
Southern Midland Basin
Central Midland Basin
Northern Midland Basin
Total
Offshore and other
Medusa
Haynesville shale
Gulf of Mexico shelf and other
Total
Net Production (MBOE)
Twelve Months Ended December 31,
2014
2013
Change
% Change
1,497
549
16
2,062
—
—
—
—
612
193
8
813
302
18
280
600
885
356
8
1,249
(302)
(18)
(280)
(600)
145%
184%
100%
154%
(100)%
(100)%
(100)%
(100)%
Total
2,062
1,413
649
46%
During 2014 we operated two horizontal rigs and one vertical rig. The following table summarizes the Company’s drilling
activity in the Permian Basin for the year ended December 31, 2014:
Drilled
Completed (a)
Gross
Net
Gross
Net
Awaiting Completion
Gross
Net
Southern Midland Basin
Vertical wells
Horizontal wells
Total
Central Midland Basin
Vertical wells
Horizontal wells
Total
Northern Midland Basin
Vertical wells
Total
Total vertical wells
Total horizontal wells
Total
1
22
23
4
5
9
2
2
7
27
34
1.0
20.1
21.1
1.8
4.3
6.1
1.5
1.5
4.3
24.4
28.7
1
22
23
3
9
12
1
1
5
31
36
1.0
20.1
21.1
1.3
7.2
8.5
0.8
0.8
3.1
27.3
30.4
—
3
3
1
—
1
—
—
1
3
4
—
3.0
3.0
0.4
—
0.4
—
—
0.4
3.0
3.4
(a) Completions include wells drilled prior to 2014.
Permian Reserve Growth
As of December 31, 2014, our estimated proved reserves increased 121% to 32.8 MMBOE compared to 14.9 MMBOE of
proved reserves at year-end 2013. Our significant growth in proved reserves was primarily attributable to our horizontal
development and acquisition efforts. Our proved reserves at year-end 2014 were 78% oil and 22% natural gas, compared to
80% oil and 20% natural gas at year-end 2013.
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.
During the third and fourth quarters of 2014, we amended the borrowing base under our Credit Facility, entered into a second
lien term loan and completed a common stock offering to support the funding of our Central Midland Basin acquisition
completed in October 2014 and our ongoing operations and acquisition initiatives which are discussed in greater detail
45
in Notes 5, 10 and 14 in the Footnotes to the Financial Statements. In addition, we regularly 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 in the
Permian Basin.
Based upon current commodity price expectations for 2015, we believe that our cash flow from operations and borrowings
under our Credit Facility and Second Lien Loan will be sufficient to fund our operations for 2015, including any deficiencies
in the Company’s current net working capital. However, future cash flows are subject to a number of variables, including
forecast production volumes and commodity prices. Approximately 95% of our current 2015 capital program is allocated to
properties we operate and, as a result, the amount and timing of a substantial portion of our planned capital expenditures is
largely discretionary in the event we determine it prudent to curtail drilling and completion operations due to capital
constraints or reduced returns on investment in periods of commodity price weakness.
Cash and cash equivalents decreased $2.0 million in the year ended December 31, 2014 to $1.0 million compared to $3.0
million at December 31, 2013. As of February 27, 2015, our available liquidity was $172.0 million.
Liquidity and cash flow
For the Year Ended December 31,
2013
2014
2012
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by (used in) financing activities
Net change in cash
$
$
94.4 $
(452.5)
356.1
(2.0) $
54.5
(79.8)
27.2
1.9 $
51.3
(93.7)
(0.3)
(42.7)
Operating activities. For the year ended December 31, 2014, net cash provided by operating activities was $94.4 million,
compared to $54.5 million for the same period in 2013. The increase was primarily due to an increase in oil sales and an
increase in gains on the settlement of derivative contracts, partially offset by an increase in production taxes and lease
operating expense. Production and realized prices 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.
Investing activities. For the year ended December 31, 2014, net cash used in investing activities was $452.5 million
compared to $79.8 million for the same period in 2013. Net cash used in investing activities during the year included $232.6
million in capital expenditures (not including acquisition costs), an increase of $72.9 million over 2013, primarily attributable
to our drilling and completion activities in the Permian Basin, driven by the addition of a second horizontal drilling rig in
August 2013. Net cash used in investing activities also included $222.9 million in acquisition costs, an increase of $212.0
million over 2013. Net cash provided by investing activities included proceeds of $3.0 million received from the sale of
certain properties and equipment, an $87.0 million decrease compared to the same period in 2013, when the Company
received proceeds of $90.0 million from the sale of Medusa and our other offshore properties. See Note 3 in the Footnotes to
the Financial Statements for additional information on acquisitions and dispositions.
2015 Capital Plan
In early February 2015, we announced an operational capital budget for 2015 in the range of $150 to $165 million. This
represents a reduction of approximately 25%-30% to the comparable 2014 budgeted amounts in response to a lower oil and
natural gas price environment.
We expect our 2015 horizontal drilling program will be primarily focused on program development of established Upper and
Lower Wolfcamp B zones and the Lower Spraberry zones in the Southern and Central Midland Basin with lateral lengths
ranging from approximately 5,000’ to 10,000’.
In addition to the operational capital expenditures above, we budgeted approximately $17.2 million for capitalized general
and administrative expenses and certain retained plugging and abandonment expenses related to divested Gulf of Mexico
shelf assets.
46
We are the operator for approximately 95% of our 2015 capital program and, as a result, the amount and timing of these
capital expenditures are largely discretionary depending on commodity prices and other factors. We currently expect to fund
our 2015 capital program through a combination of cash flow from operations and Credit Facility borrowings.
Financing activities. For the year ended December 31, 2014, net cash provided by financing activities was $356.1 million
compared to cash provided by financing activities of $27.2 million during the same period of 2013. Net cash provided by
financing activities during the year ended December 31, 2014 included $122.5 million of net proceeds from the issuance of
common stock and a net $291.6 million of borrowings on our Credit Facility and Second Lien Loan, offset by a $50.1 million
redemption of our Senior Notes. In addition, the Company paid approximately $7.9 million in preferred stock dividends. See
Notes 5 and 10 in the Footnotes to the Financial Statements for additional information about the Company’s debt and equity
offering.
Senior secured revolving credit facility (“Credit Facility”)
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 participating lenders include
Regions Bank, Citibank, N.A., Capital One, N.A., KeyBank, N.A., Whitney Bank, IberiaBank, N.A., OneWest Bank, N.A.,
SunTrust Bank and Royal Bank of Canada. The total notional amount available under the Credit Facility is $500 million.
Amounts borrowed under the Credit Facility may not exceed the borrowing base, which is generally reviewed on a semi-
annual basis. In conjunction with the closing of the Acquisition on October 8, 2014, the borrowing base on the Company’s
Credit Facility was amended to $250 million. The Credit Facility is secured by first preferred mortgages covering the
Company’s major producing properties. As of December 31, 2014, the balance outstanding on the Credit Facility was
$35.0 million with a weighted-average interest rate of 1.91%, calculated as the LIBOR plus a tiered rate ranging from 1.75%
to 2.75%, 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 secured term loan in an aggregate amount of up to $125 million, including
initial commitments of $100 million and additional availability of $25 million 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 we issued. It was
prepayable at the Company’s option, subject to a prepayment premium. The prepayment amount was (i) 102% if the
prepayment event occurs prior to March 11, 2015, and (ii) 101% if the prepayment event occurs 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 April 10, 2014, the
Company drew an initial amount of $62.5 million with an original issue discount of 1.0%.
On October 8, 2014, the term loan described above was repaid in full using a new secured second lien term loan (the “Second
Lien Loan”) in conjunction with the closing of the Central Midland Basin acquisition, resulting in a loss on early
extinguishment of debt of $3.1 million. The Second Lien Loan has a maturity date of October 8, 2021. On October 8, 2014,
the Company drew an initial amount of $300 million with a discount of 2.0% and an interest rate of 8.5%, calculated at a rate
of LIBOR (subject to a floor rate of 1.0%) plus 7.5% per annum. The Second Lien Loan may be prepaid at the Company’s
option, subject to a prepayment premium. The
44
prepayment amount is (i) 102% if the prepayment event occurs prior to October 8, 2015, and (ii) 101% if the prepayment
event occurs on or after October 8, 2015 but before October 8, 2016, and (iii) 100% for prepayments made on or after
October 8, 2016. The Second Lien Loan is secured by junior liens on properties mortgaged under the Credit Facility, subject
to an intercreditor agreement. The Royal Bank of Canada is Administrative Agent, and participants include several
institutional lenders.
13% Senior Notes due 2016 (the “Senior Notes”) and deferred credit
On April 11, 2014, the Company completed the full redemption of the remaining $48.5 million principal amount of
outstanding Senior Notes using proceeds from the term loan issued on March 11, 2014. The redemption resulted in a net
$3.2 million gain on the early extinguishment of debt (including $4.8 million of accelerated deferred credit amortization).
47
The gain represents the difference between the $50.1 million paid for the redemption of the Senior Notes ($1.6 million of
redemption costs, primarily the call premium) and the carrying value of the remaining Senior Notes of $53.3 million
(inclusive of $4.8 million of deferred credit). The Company also paid $0.2 million in accrued interest through the redemption
date. Upon the redemption, the indenture governing the Senior Notes was discharged in accordance with its terms.
Common Stock Offering
On September 15, 2014, the Company completed an equity offering for $129.4 million in gross proceeds. The offering
consisted of 12,500,000 shares of the Company’s common stock at a price to the public of $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. See Note 10 in the Footnotes to the Financial Statements for additional information about
the Company’s equity offering.
Contractual Obligations
The following table includes the Company’s current contractual obligations and purchase commitments:
Payments due by Period
< 1 Year Years 2 - 3 Years 4 - 5 >5 Years
$
Second Lien Loan
Credit Facility
Drilling rig leases and related (a)
Office space lease and other commitments
Total
300,000
—
—
419
300,419
The <1 Year column includes $3,733 related to the early termination provisions of one of the Company’s vertical
drilling rigs (See Note 14), and the amount assumes the lessor is unable to re-charter the rig and staffing
personnel to another lessee. Should the lessor re-charter the rig and its related personnel to a new lessee, the
$3,733 would be reduced by the value of the new lessee’s rental payments.
— $
—
21,930
1,219
23,149 $
— $
—
16,893
637
17,530 $
— $
35,000
6,510
855
42,365 $
(a)
$
Total
300,000 $
35,000
45,333
3,130
383,463 $
Income Taxes
The Company’s income tax expense varies from the statutory rate primarily due to the effect of state income taxes and non-
deductible executive compensation expenses. For additional information, see the Income Tax discussion included below in
Results of Operations and Note 11 to the Consolidated Financial Statements.
48
Results of Operations
The following table sets forth certain operating information with respect to the Company’s oil and natural gas operations for
the periods indicated:
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
Lease operating expense
Production taxes
Operating margin
For the Year Ended December 31,
%
2014
2013
Change
Change 2012
Change
%
Change
781
911
1,692
(791)
2,220 3,011
2,062 1,413
649
5,648 3,871 1,777
977
(66)
86%
(26)% 3,588 (577)
46% 1,575 (162)
46% 4,303 (432)
(7)%
(16)%
(10)%
(10)%
82%
64%
62%
$ 82.37 $ 97.65 $ (15.28)
(16)% $ 97.41 $ 0.24
84.85 99.32 (14.46)
(15)% 98.86 0.46
—
—
$
5.63 $
4.52 $
1.11
24% $
3.94 $ 0.58
15%
5.59
4.47
1.12
25%
3.94 0.53
13%
$ 73.65 $ 72.59 $
1.06
1% $ 69.43 $ 3.16
5%
75.64 73.56
2.08
3% 70.41 3.15
4%
$139,374 $ 88,960 $ 50,414
12,488 13,609 (1,121)
$151,862 $102,569 $ 49,293
57% $ 96,584 $ (7,624)
(8)% 14,149 (540)
48% $ 110,733 $ (8,164)
$ 73.65 $ 72.59 $
10.85 14.00
2.92
$ 58.45 $ 55.67 $
4.35
1.06
(3.15)
1.43
2.78
1% $ 69.43 $ 3.16
(23)% 14.81 (0.81)
2.05 0.87
49%
5% $ 52.57 $ 3.10
(8)%
(4)%
(7)%
5%
(5)%
42%
6%
49
Revenues
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, as well as the impact of our
hedge program for the year ended December 31, 2012 when we had designated our derivative contracts as accounting
hedges.
(in thousands)
Revenues for the year ended December 31, 2011
Volume increase (decrease)
Price increase (decrease)
Impact of hedges
Net increase (decrease) in 2012
Revenues for the year ended December 31, 2012
Volume increase (decrease)
Price increase (decrease)
Net increase (decrease) in 2013
Revenues for the year ended December 31, 2013
Volume increase (decrease)
Price increase (decrease)
Net increase (decrease) in 2014
Revenues for the year ended December 31, 2014
Oil revenue
Oil
100,962
(1,926)
(3,872)
1,420
(4,378)
96,584
(6,528)
(1,096)
(7,624)
88,960
76,237
(25,823)
50,414
139,374
$
$
$
$
$
$
$
Natural Gas
Total
26,682 $
(7,840)
(4,693)
—
(12,533)
14,149
(2,278)
1,738
(540)
13,609 $
(3,575)
2,454
(1,121)
12,488 $
127,644
(9,766)
(8,565)
1,420
(16,911)
110,733
(8,806)
642
(8,164)
102,569
72,662
(23,369)
49,293
151,862
For the year ended December 31, 2014, oil revenues of $139.4 million increased $50.4 million, or 57%, compared to
revenues of $89.0 million for the same period of 2013. The increase primarily related to an 86% increase in total production,
while the average realized sales price decreased 16%. The increase in production was wholly attributable to a 1,048 MBbls
increase in Permian production resulting from an increased number of producing wells from acquisitions and our horizontal
drilling program offset by normal and expected declines from our existing wells. Partially offsetting the Permian increase was
a 267 MBbls decline in production due to the sale of our deepwater Medusa field in the fourth quarter of 2013.
For the year ended December 31, 2013, oil revenues of $89.0 million decreased $7.6 million, or 8%, compared to revenues of
$96.6 million for the same period of 2012. Lower production from our offshore properties, primarily related to the sale of
Habanero field in December 2012 and our Medusa and shelf properties in the fourth quarter of 2013, drove the revenue
decline. Also contributing to the production decline were 20 days of down time for scheduled downstream pipeline
maintenance at our Medusa field in the second quarter of 2013, approximately five days of production downtime at our key
producing Permian Basin fields in the fourth quarter of 2013 due to severe winter weather causing electricity outages and the
extended curtailment of trucking capacity to transport offtake and due to normal and expected declines from other producing
wells. Collectively, these declines were offset by the 222 MBbls increase in our oil production from our Permian properties.
Natural gas revenue (including NGLs)
Natural gas revenues of $12.5 million decreased $1.1 million, or 8%, during the year ended December 31, 2014 compared to
$13.6 million for the same period of 2013. The average realized price increased to $5.63 per Mcf from $4.52 per Mcf, or
24%, while total production decreased 26%. The decrease in production was primarily attributable to a 1,919 MMcf decrease
in production due to the sale of our offshore fields and Haynesville property in the fourth quarter of 2013. Offsetting the
production decline was a 1,128 MMcf increase in production from our Permian properties resulting from an increased
number of producing wells as mentioned above.
Natural gas revenues of $13.6 million decreased $0.5 million, or 4%, during the year ended December 31, 2013 compared to
$14.1 million for the same period of 2012. While the average realized price increased 15%, a 16% decrease in production
reduced total revenue. The production declines were primarily attributable to the shut-in of production of our Mobile Bay 908
property, the sale of our offshore fields, the sale of our Haynesville property in the fourth quarter of 2013 as well as normal
and expected declines from our existing wells. Offsetting these declines was a 248 MMcf increase in horizontal well
production from our Permian properties.
50
Operating Expenses
For the Year Ended December 31,
Per
Per
Total Change
%
BOE Change
%
2013 BOE
2014 BOE
$ 22,372 $ 10.85 $ 19,779 $ 14.00 2,593
Lease operating expenses
Production taxes
8,973
Depreciation, depletion and amortization 56,724 27.51 43,967 31.12 12,757
25,109 12.18 20,534 14.53 4,575
General and administrative
(959)
Accretion expense
Gain on sale of other property and
equipment
Impairment of other property and
equipment
Acquisition expense
— 1,707
—
13%
2.92 4,840 117%
29%
22%
(54)%
1.21 (1,707) (100)%
—
668
4.35 4,133
0.40 1,785
—
668
— (1,080)
(1,080)
(0.52)
0.32
826
1.26
—
—
$
$
(3.15)
1.43
(3.61)
(2.35)
(0.86)
(22)%
49%
(12)%
(16)%
(68)%
—
(0.52)
—
(1.21) (100)%
—
0.32
For the Year Ended December 31,
Per
Per
Total Change
%
$
BOE Change
%
2013 BOE
$ 19,779 $ 14.00 $ 23,330 $ 14.81 (3,551)
Lease operating expenses
Production taxes
909
4,133
Depreciation, depletion and amortization 43,967 31.12 49,701 31.56 (5,734)
176
General and administrative
Accretion expense
(468)
Impairment of other property and
equipment
20,534 14.53 20,358 12.93
1.43
1,785
2012 BOE
2.92 3,224
1.26 2,253
1.21 1,177
1,707
530
2.05
0.75
(15)%
28%
(12)%
1%
(21)%
$
(0.81)
0.87
(0.44)
1.60
(0.17)
(5)%
42%
(1)%
12%
(12)%
45%
0.46
61%
Lease operating expenses (“LOE”). These are daily costs incurred to extract oil and natural gas out of the ground and
deliver to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include
maintenance, repairs and workover expenses related to our oil and natural gas properties.
LOE for the year ended December 31, 2014 increased by 13% to $22.4 million compared to $19.8 million for the same
period of 2013 primarily due to $9.7 million in costs related to the growth in Permian production and operations, including an
increase in workover expenses associated with the impact of accelerated horizontal well activity on surrounding producing
wells. These increases were partially offset by a decrease in costs of $7.1 million resulting from the sale of our deep water
Medusa field and our other offshore fields. LOE per BOE for the year ended December 31, 2014 decreased by 22% to
$10.85 per BOE from $14.00 per BOE for the same period of 2013. The 22% decrease is primarily attributable to a 46%
increase in production while keeping expenses in line.
LOE for the year ended December 31, 2013 decreased by 15% to $19.8 million compared to $23.3 million for the same
period of 2012. The decrease was primarily due to $3.4 million of remediation costs on our Haynesville property in 2012,
for which we had no similar costs in 2013, and an estimated decrease of $3.2 million of LOE resulting from the sale of our
interests in Habanero, Medusa, the Medusa Spar facilities, our Haynesville property and substantially all our remaining shelf
properties. These decreases were partially offset by $3.0 million in LOE costs related to the growth in Permian production
and operations, including an increase in workover expenses associated with accelerated horizontal well activity.
Production taxes. Production taxes include severance and ad valorem taxes. 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. We are also
subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the
valuation of our oil and gas properties.
For the year ended December 31, 2014, production taxes increased 117%, or $4.9 million, to $9.0 million compared to $4.1
million for the same period of 2013. The increase was predominantly attributable to an increase in onshore production subject
to these taxes accompanied by a decline in offshore production, resulting from the sale of our Gulf of Mexico position in
2013, which was exempt from production taxes.
51
For the year ended December 31, 2013 production taxes of $4.1 million increased 28%, or $0.9 million, compared to $3.2
million for the same period of 2012. The increase was predominantly attributable to the previously mentioned increase in
onshore production
48
subject to these taxes and a decline in offshore production, resulting from the sale of our Gulf of Mexico position in 2013,
which is exempt from production taxes.
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, 2014, DD&A increased 29% from $44.0 million compared to $56.7 million for the same
period of 2013. The increase is primarily attributable to a 46% increase in production, offset by a 12% decrease in our per
BOE DD&A rate. For the year ended December 31, 2014, DD&A on a per unit basis decreased to $27.51 per BOE compared
to $31.12 per BOE for the same period of 2013 as a result of our 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.
For the year ended December 31, 2013, DD&A of $31.12 per BOE remained relatively flat compared to $31.56 per BOE for
the same period of 2012.
General and administrative, net of amounts capitalized (“G&A”). These are costs incurred for overhead, including payroll
and benefits for our corporate staff, 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, 2014 increased to $25.1 million (including $3.1 million in fair value adjustment of
cash-settled RSU awards) compared to $20.5 million (including $2.9 million in fair value adjustment of cash-settled RSU
awards) for the same period of 2013. The increase was primarily related to the following items:
·
·
$1.4 million in non-recurring, cash expenses related to a threatened proxy contest incurred in 2014
$2.5 million in non-recurring expenses (both cash and non-cash components) primarily related to the accelerated
vesting of outstanding equity awards for early retirement of employees
·
an increase of $0.2 million related to the fair value adjustment of cash-settled RSU awards
G&A for the year ended December 31, 2013 remained relatively flat at $20.5 million (including $2.9 million in fair value
adjustment of cash-settled RSU awards) compared to $20.4 million (including $1.6 million in fair value adjustment of cash-
settled RSU awards) for the same period of 2012. The $0.1 million increase was related to the following items:
·
·
an increase of $1.3 million related to the fair value adjustment of cash-settled RSU awards
a decrease of $1.6 million primarily related to non-recurring employee-related expenses including early retirement
and severance expense incurred in 2012
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 asset retirement costs. Interest is accreted on the present value
of the asset retirement obligations (“ARO”) and reported as accretion expense within operating expenses in the consolidated
statements of operations.
52
Accretion expense related to our ARO decreased 54% for the year ended December 31, 2014 compared to the same period of
2013. The decrease in accretion expense correlates with the Company’s average ARO, which was $6.5 million during 2014
versus $11.5 million during 2013. The reduction in our average ARO was primarily a result of the divestiture of our offshore
fields in the fourth quarter of 2013. See Note 12 in the Footnotes to the Financial Statements for additional information
regarding the Company’s ARO.
Accretion expense related to our asset retirement obligation decreased 21% for the year ended December 31, 2013 compared
to the same periods of 2012. Accretion expense generally correlates directionally with the Company’s ARO which was $6.7
million at December 31, 2013 versus $13.3 million at December 31, 2012.
Acquisition expense
Acquisition expense of $0.7 million for the year ended December 31, 2014 relates to acquisition related 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
See Note 14 in the Footnotes to the Financial Statements for a discussion of the gain on the sale of specialized deep water
property and equipment.
Impairment of other property and equipment
See Note 14 in the Footnotes to the Financial Statements for a discussion regarding the recognition of the impairment on
specialized deep water property and equipment.
Other Income and Expenses and Preferred Stock Dividends
Interest expense. 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 the deferred credit related to our 13%
Senior Notes was recorded as an offset to interest expense.
Gain/Loss on derivative instruments. We utilize commodity derivative financial instruments to reduce our exposure to
fluctuations in the price of oil and natural gas. 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. We provide a reconciliation of these components of the gain/loss on derivative contracts in Note 5.
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.
53
Interest expense
Gain on early extinguishment of debt
(Gain) loss on derivative contracts
Other income, net
Total
Income tax expense
Equity in earnings of Medusa Spar LLC
Preferred stock dividends
Interest expense
Gain on early extinguishment of debt
Loss (gain) on derivative contracts
Other income, net
Total
Income tax expense
Equity in earnings of Medusa Spar LLC
Preferred stock dividends
Interest expense
$
$
$
$
$
$
For the Year Ended December 31,
2014
2013
$ Change
% Change
9,772 $
(151)
(31,736)
(515)
(22,630) $
23,134 $
—
(7,895)
6,094 $
(3,696)
1,360
(485)
3,273
3,678
3,545
(33,096)
(30)
60%
(96)%
(2,434)%
6%
3,104 $
17
(4,627)
20,030
(17)
(3,268)
645%
(100)%
71%
For the Year Ended December 31,
2013
2012
$ Change
% Change
6,094 $
(3,696)
1,360
(485)
3,273 -$
3,104 $
17
(4,627)
9,108
(1,366)
(1,717)
(79)
5,946 -
2,223 $
226
—
(3,014)
(2,330)
3,077
(406)
-
881
(209)
(4,627)
(33)%
171%
(179)%
514%
(40)%
(92)%
—
Interest expense incurred during the year ended December 31, 2014 increased $3.7 million to $9.8 million compared to $6.1
million for the same period of 2013. The increase is primarily attributable to the $11.4 million increase in expense related to
additional draws on our Credit Facility and term loans in 2014 compared to the corresponding period of the prior year.
Offsetting the increase is a $7.9 million decrease in interest expense related to our Senior Notes following a $48.5 million
partial redemption during the fourth quarter of 2013 and a full redemption of the remaining outstanding principal in April
2014. Also offsetting the increase was a $0.2 million increase in capitalized interest, resulting from a higher average
unevaluated property balance period over period.
Interest expense incurred during the year ended December 31, 2013 decreased $3.0 million to $6.1 million compared to $9.1
million for the same period of 2012. The decrease was related primarily to an additional $2.3 million of interest capitalized in
2013 versus 2012, approximately $0.3 million of reduced interest payments attributable to the redemption of $48.5 million
principal of the Company’s Senior Notes in December 2013 and $0.1 million of additional deferred credit amortization
recognized in 2013 compared with 2012. The additional capitalized interest was related to a higher balance year-over-year in
average unevaluated oil and natural gas properties following the purchase of additional unevaluated acreage and exploration
costs incurred in the Permian Basin.
(Gain) loss on early extinguishment of debt
During April 2014, the Company completed a full redemption of the remaining $53.3 million carrying value of its
outstanding 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 $1.4 million of unamortized issuance costs. See Note 5 for additional information concerning the loss on
the early extinguishment of debt.
54
During December 2013, the Company redeemed $53.8 million carrying value of its Senior Notes using a portion of the
proceeds from the Company’s May 2013 preferred equity offering. The $53.8 million of carrying value included $48.5
million of principal value and $5.3 million of unamortized deferred credit. The Company recognized a net gain of $3.7
million on the early extinguishment of debt, comprised of the recognition of $5.3 million in deferred credit, offset by $1.6
million of redemption expenses.
Loss (gain) on derivative contracts
For the year ended December 31, 2014, the net gain on derivative instruments was $31.7 million, compared to a $1.4
million net loss in 2013. 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.
For the year ended December 31, 2013, the net loss on derivative instruments was $1.4 million, compared to a $1.7
million net gain in 2012.
Income tax expense
The effective tax rate of 38% in 2014 and 42% in 2013 differed from the federal income tax rate of 35% primarily due to the
effect of state taxes, non-deductible executive compensation expenses and percentage depletion. For additional information,
see Note 11 to the Consolidated Financial Statements.
Preferred stock dividends
Preferred stock dividends for the year ended December 31, 2014 increased $3.3 million compared to the same period of 2013.
We issued the Preferred Stock on May 30, 2013. Accordingly, the year ended December 31, 2014 reflects dividends for the
entire year compared to a partial year in 2013. Dividends reflect a 10% dividend rate and $79 million liquidation value. 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:
55
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.
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),
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, 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. If oil and natural gas prices remain at current levels or decline further, even if only
for a short period of time, write-downs of oil and natural gas properties could occur in the future. See Note 13 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.
56
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. The Company determines whether an unevaluated property is
impaired by periodically reviewing its exploration program on a property-by-property basis. 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 for additional information.
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, puts, and other structures) on approximately 50% to 75% of our
projected production volumes in any given year. We do not use these instruments for trading purposes. Settlement 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.
We elected to no longer designate derivative contracts executed after January 1, 2012 as accounting hedges and as such our
derivative positions are carried at their fair value on the balance sheet with changes in fair value recorded through earnings.
Derivative contracts that were entered into at and prior to December 31, 2011 were accounted for as cash flow hedges, and
were recorded at fair value on our consolidated balance sheet. Changes in fair value were recorded through other
comprehensive income (loss), net of tax, in stockholders’ equity. The changes in fair value related to ineffective derivative
contracts were recognized as derivative expense (income). The estimated fair value of our derivative contracts is based upon
closing exchange 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 to the Consolidated 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). See Note 11 for additional information regarding Income
Taxes.
57
Recent Accounting Standards
In May 2014, the FASB issued accounting standards update (“ASU”) No. 2014-09, Revenue from Contracts with
Customers. 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 No. 2014-09 will replace most of the existing revenue recognition requirements in GAAP when it becomes
effective. The guidance in ASU No. 2014-09 is effective for public entities for annual reporting periods beginning after
December 15, 2016, including interim periods therein. Early adoption is not permitted. The Company is currently evaluating
the method of adoption and impact this standard will have on its financial statements and related disclosures.
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. The total volumes which we hedge through the use of our
derivative instruments varies from period to period; however, generally our objective is to hedge approximately 50% to 75%
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.
As of February 27, 2015, we had commodity contracts covering approximately 63% and 62% of our expected oil and natural
gas production for calendar year 2015, respectively, based on the midpoint of publicly disclosed guidance as of March 4,
2015 and including the impact of derivative contracts established after December 31, 2014. Our short call options related to
natural gas have been integrated with swaps for purposes of this calculation. Our actual production will vary from the
amounts estimated, perhaps materially. See Note 6 in the Footnotes to the Financial Statements for a description of the
Company’s outstanding derivative contracts at December 31, 2014 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. Additionally, the Company may sell put options or call options in conjunction
with a swap and use the proceeds to increase the fixed price received.
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 options at a price lower than the floor price in conjunction with a collar
(three-way collar) and use the proceeds to increase either or both the floor or ceiling prices.
The Company may purchase put 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.
58
Interest rate risk
On December 31, 2014, the Company’s debt consisted of $300.0 million related to its Second Lien Facility and $35.0 million
related to its Credit Facility. The Company is subject to market risk exposure related to changes in interest rates on our
indebtedness under the Second Lien Loan and Credit Facility. As of December 31, 2014, the weighted average interest rate
on our Credit Facility borrowings was 1.91% and the interest rate on our Second Lien Loan borrowings was 8.50%. An
increase or decrease of 1% in the interest rate would have a corresponding increase or decrease in our annual net income of
approximately $3.4 million based on the $335.0 million outstanding in the aggregate under the two facilities on December
31, 2014. The Company is also subject to market risk exposure going forward related to changes in interest rate for the
Second Lien Loan and Credit Facility. See Note 5 to the Consolidated Financial Statements for more information on the
Company’s interest rates on debt.
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 receivables from the sale of our 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, 2014, three purchasers accounted for more than 10% of our revenue: Enterprise Crude Oil,
LLC (51%); Plains Marketing, L.P. (22%); and Sunoco (10%). We do not require any of our customers to post collateral,
and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely
affect our financial results. At December 31, 2014 our total receivables from the sale of our oil and natural gas production
were approximately $18.9 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, 2014 our joint interest receivables were
approximately $6.9 million.
At December 31, 2014 our receivables resulting from derivative contracts were approximately $4.1 million. Our oil and
natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. The
counterparties on our derivative instruments currently in place are lenders under our revolving credit facility. We are likely to
enter into additional derivative instruments with these or other lenders under our revolving credit facility, representing
institutions with an 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, 2014 we had a net derivative asset position of $27.9
million and a net derivative liability position of $1.3 million.
ITEM 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2014 and 2013
Consolidated Statements of Operations for Each of the Three Years in the Period Ended December 31, 3014
Consolidated Statements of Comprehensive Income (Loss) for the Three Years in the Period Ended December 31,
2014
Consolidated Statements of Stockholders’ Equity (Deficit) for Each of the Three Years in the Period Ended
December 31, 2014
Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2014
Notes to Consolidated Financial Statements
Page
60
61
62
63
64
65
66
59
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of
Callon Petroleum Company
We have audited the accompanying consolidated balance sheets of Callon Petroleum Company as of December 31, 2014 and
2013, and the related consolidated statements of operations, comprehensive income, stockholders’ equity and cash flows for
each of the three years in the period ended December 31, 2014. 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, 2014 and 2013, and the consolidated results of its operations and
its cash flows for each of the three years in the period ended December 31, 2014, in conformity with U.S. generally accepted
accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
Callon Petroleum Company’s internal control over financial reporting as of December 31, 2014, based on criteria established
in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (2013 framework) and our report dated March 4, 2015, expressed an unqualified opinion thereon.
New Orleans, Louisiana
March 4, 2015
/s/Ernst & Young LLP
60
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)
ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable
Deferred tax asset
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 and amortization
Net oil and natural gas properties
Unevaluated properties
Total oil and natural gas properties
Other property and equipment, net
Restricted investments
Deferred tax asset
Deferred financing costs
Other assets, net
Total assets
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities
Accrued interest
Cash-settled restricted stock unit awards
Asset retirement obligations
Deferred tax liability
Fair value of derivatives
Total current liabilities
13% senior notes:
Principal outstanding
Deferred credit, net of accumulated amortization of $0 and $26,239, respectively
Total 13% senior notes
Senior secured revolving credit facility
Secured second lien term loan
Asset retirement obligations
Cash-settled restricted stock unit awards
Other long-term liabilities
Total liabilities
Stockholders’ equity:
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares
authorized: 1,578,948 and 1,578,948 shares outstanding, respectively
Common stock, $0.01 par value, 110,000,000 and 60,000,000 shares authorized; 55,225,288 and
40,345,456 shares outstanding, respectively
Capital in excess of par value
Accumulated deficit
Total stockholders’ equity
Total liabilities and stockholders’ equity
December 31, 2014
December 31, 2013
968 $
30,198
—
27,850
1,441
60,457
3,012
20,586
3,843
60
2,063
29,564
2,077,985
(1,478,355)
1,701,577
(1,420,612)
599,630
142,525
742,155
7,118
3,810
44,688
18,200
342
876,770 $
76,753 $
5,993
3,856
4,747
6,214
1,249
98,812
—
—
—
35,000
300,000
1,927
7,175
121
443,035
280,965
43,222
324,187
7,255
3,806
57,765
1,098
278
423,953
53,447
17
4,173
4,120
—
1,036
62,793
48,481
5,267
53,748
22,000
—
2,612
3,409
297
144,859
16
16
552
526,162
(92,995)
433,735
876,770 $
404
401,540
(122,866)
279,094
423,953
$
$
$
$
The accompanying notes are an integral part of these consolidated financial statements.
61
Callon Petroleum Company
Consolidated Statements of Operations
(in thousands, except per share data)
For the Year Ended December 31,
2013
2014
2012
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
Gain on sale of other property and equipment
Impairment of other property and equipment
Acquisition expense
Total operating expenses
Income from operations
Other (income) expenses:
Interest expense
Gain on early extinguishment of debt
(Gain) loss on derivative contracts
Other income
Total other (income) expense
Income before income taxes
Income tax expense
Income before equity in earnings of Medusa Spar LLC
Equity in earnings of Medusa Spar LLC
Net income
Preferred stock dividends
Income (loss) available to common stockholders
Income (loss) per common share:
Basic
Diluted
$
$
$
$
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
—
37,766
(7,895)
29,871 $
0.67 $
0.65 $
88,960 $
13,609
102,569
19,779
4,133
43,967
20,534
1,785
—
1,707
—
91,905
10,664
6,094
(3,696)
1,360
(485)
3,273
7,391
3,104
4,287
17
4,304
(4,627)
(323) $
(0.01) $
(0.01) $
Shares used in computing income (loss) per common share:
Basic
Diluted
44,848
45,961
40,133
40,133
The accompanying notes are an integral part of these consolidated financial statements.
96,584
14,149
110,733
23,330
3,224
49,701
20,358
2,253
—
1,177
—
100,043
10,690
9,108
(1,366)
(1,717)
(79)
5,946
4,744
2,223
2,521
226
2,747
—
2,747
0.07
0.07
39,522
40,337
62
Callon Petroleum Company
Consolidated Statements of Comprehensive Income
(in thousands)
Net income
Other comprehensive income (loss):
Change in fair value of derivatives designated as hedges, net of tax
Comprehensive income
Preferred stock dividends
Comprehensive income (loss) available to common shareholders
For the Year Ended December 31,
2014
2013
2012
$
37,766 $
4,304 $
2,747
—
37,766
(7,895)
29,871 $
—
4,304
(4,627)
(323) $
(1,624)
1,123
—
1,123
$
The accompanying notes are an integral part of these consolidated financial statements.
63
Callon Petroleum Company
Consolidated Statements of Stockholders’ Equity
(in thousands)
Balance at 12/31/2011
Comprehensive income:
Net income
Other comprehensive loss
Total comprehensive income
Shares issued pursuant to employee
benefit plans
Restricted stock
Balance at 12/31/2012
Comprehensive income:
Net income and comprehensive
income
Shares issued pursuant to employee
benefit plans
Restricted stock
Preferred stock issued
Preferred stock dividend
Balance at 12/31/2013
Comprehensive income:
Net income and comprehensive
income
Shares issued pursuant to employee
benefit plans
Restricted stock
Common stock issued
Preferred stock dividend
Balance at 12/31/2014
Preferred
Stock
Common
Stock
$
— $
394 $
Capital in
Excess of
Par
324,474 $
Accumulated
Other
Comprehensive
Income (Loss)
Retained
Earnings
(Deficit)
Total
Stockholders'
Equity
1,624 $ (125,290) $
201,202
—
—
—
—
—
— $
—
—
—
—
—
—
—
(1,624)
—
2,747
—
—
—
4
398 $
235
3,407
328,116 $
—
—
—
—
— $ (122,543) $
1,123
235
3,411
205,971
—
—
—
—
4,304
4,304
—
—
16
—
16 $
—
6
—
—
404 $
243
3,162
70,019
—
401,540 $
—
—
—
—
—
—
—
(4,627)
— $ (122,866) $
243
3,168
70,035
(4,627)
279,094
—
—
—
— 37,766
37,766
—
—
—
—
16 $
—
4
144
—
552 $
262
2,054
122,306
—
526,162 $
—
—
—
—
—
—
—
(7,895)
— $ (92,995) $
262
2,058
122,450
(7,895)
433,735
$
$
$
The accompanying notes are an integral part of these consolidated financial statements.
64
Callon Petroleum Company
Consolidated Statements of Cash Flows
(in thousands)
Cash flows from operating activities:
Net income
Adjustments to reconcile net income to cash provided by operating
activities:
Depreciation, depletion and amortization
Accretion expense
Amortization of non-cash debt related items
Amortization of deferred credit
Equity in earnings of Medusa Spar LLC
Deferred income tax expense
Net loss (gain) on derivatives, net of settlements
Impairment of other property and equipment
Gain on sale of other property and equipment
Non-cash gain on early debt extinguishment
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
Payments to settle vested liability share-based awards
Change in other long-term liabilities
Change in other assets, net
Net cash provided by operating activities
Cash flows from investing activities:
Capital expenditures
Acquisition
Proceeds from sales of mineral interest and equipment
Distribution from Medusa Spar LLC
Net cash used in investing activities
Cash flows from financing activities:
Borrowings on credit facility
Borrowings on term loan
Payments on credit facility
Payments on term loan
Payment of deferred financing costs
Redemption of 13% senior notes
Issuance of preferred stock
Issuance of common stock
Payment of preferred stock dividends
Taxes paid related to exercise of employee stock options
Net cash provided by (used in) financing activities
Net change in cash and cash equivalents
Balance, beginning of period
Balance, end of period
For the Year Ended December 31,
2013
2014
2012
$
37,766 $
4,304 $
2,747
58,014
826
1,272
(487)
—
23,134
(27,650)
—
(1,080)
(151)
1,126
3,936
(3,808)
(7,915)
622
12,805
(3,469)
(106)
(448)
94,387
(232,596)
(222,883)
2,978
—
(452,501)
132,500
382,500
(119,500)
(84,149)
(19,779)
(50,057)
—
122,450
(7,895)
—
356,070
(2,044)
3,012
968 $
45,393
1,785
471
(3,164)
(17)
2,778
2,730
1,707
—
(3,696)
2,092
2,903
(721)
(3,497)
(560)
3,583
(239)
(711)
(666)
54,475
51,043
2,253
402
(3,086)
(226)
2,223
(1,683)
1,176
—
(1,366)
1,697
1,620
(1,314)
(883)
100
1,753
(3,383)
103
(1,886)
51,290
(159,724)
(10,885)
89,992
813
(79,804)
(133,299)
(2,075)
39,936
1,735
(93,703)
80,000
—
(68,000)
—
(146)
(50,060)
70,035
—
(4,627)
—
27,202
1,873
1,139
3,012 $
53,000
—
(43,000)
—
—
(10,225)
—
—
—
(18)
(243)
(42,656)
43,795
1,139
$
The accompanying notes are an integral part of these consolidated financial statements.
65
INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Description of Business and Basis of Presentation
2. Summary of Significant Accounting Policies
3. Acquisitions and Dispositions
4. Earnings (Loss) Per Share
5. Borrowings
9. Asset Retirement Obligations
10. Equity Transactions
11. Income Taxes
12. Asset Retirement Obligations
13. Supplemental Information on Oil and Natural Gas
6. Derivative Instruments and Hedging Activities
7. Fair Value Measurements
8. Employee Benefit Plans
Operations (Unaudited)
14. Other
15. Summarized Quarterly Financial Information (Unaudited)
66
Note 1 - Description of Business and Basis of Presentation
Description of business
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, and more specifically, the Midland Basin. The Company’s operations to
date have been predominantly focused on horizontal drilling of several prospective intervals, including multiple levels of the
Wolfcamp formation. 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 our existing acreage and acquisition of additional locations
through 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 includes the subsidiaries 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 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 United States generally accepted accounting principles (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.
D.
Revenue Recognition and Natural Gas Balancing
The Company recognizes revenue under the entitlement 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. Production
imbalances are generally recorded at the lower of cost or market. 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, 2014 and 2013.
67
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
Plains Marketing, L.P.
Sunoco
Shell Trading Company
Other
Total
For the Year Ended December 31,
2013
2014
2012
51%
22%
10%
0%
17%
100%
38%
15%
0%
31%
16%
100%
32%
15%
0%
39%
14%
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. The Company capitalized $16,688, $14,753 and $13,331 of these internal costs during 2014, 2013 and 2012,
respectively.
When applicable, proceeds from the sale or disposition of oil and natural gas properties are accounted for as a reduction to
capitalized costs unless the sale would significantly alter the relationship between capitalized costs and proved reserves, in
which case a gain or loss is recognized in income.
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 which 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.
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,
66
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 generally 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. See Note 13 for additional information regarding the Company’s oil and
natural gas properties.
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
68
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 of $7,118 and $7,255 at December 31, 2014 and 2013,
respectively, using the straight-line method over estimated useful lives of three to 20 years. Depreciation expense of
$836, $750 and $760 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, 2014, 2013 and 2012, respectively. The
accumulated depreciation on other property and equipment was $14,005 and $13,240 as of December 31, 2014 and 2013,
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, 2014, 2013 and 2012, the Company capitalized $4,295, $4,410 and $2,109 of
interest expense.
I.
Deferred Financing Costs
Deferred financing costs are stated at cost, net of amortization, which is computed using the straight-line method over the life
of the loan, which is reflective of the effective interest rate method. Deferred financing costs of $18,200 and $1,098 as of
December 31, 2014 and 2013, respectively, net of accumulated amortization. Amortization of deferred financing costs of
$1,272, $471 and $402 was recorded for the years ended December 31, 2014, 2013 and 2012, 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
The Company’s derivative contracts executed prior to 2012 were designated as cash flow hedges, and were recorded at fair
market value with the changes in fair value recorded net of tax through other comprehensive income (loss) (“OCI”) in
stockholders’ equity. Ineffective derivative contracts or ineffective portions of contracts designated as cash flow hedges
were recognized as gain or loss on derivative contracts. The last of the Company’s derivative contracts designated as cash
flow hedges expired on December 31, 2012. Derivative contracts executed subsequent to December 31, 2012 and
outstanding as of December 31, 2014 were not designated as accounting hedges, and are carried on the balance sheet at their
fair market 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, net of a valuation allowance. A valuation allowance is provided for that portion, if any, of the asset for which
it is deemed more likely than not that it will not be realized. See Note 11 for additional information.
69
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).
RS awards, RSU awards and Cash-settleable RSU awards. For RS and RSU 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 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 remeasured 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 value
recognized over the vesting period (generally three years).
N.
Statements of Cash Flows Supplemental Information
During the three year period ended 2013, the Company paid no federal income taxes. During the years ended December 31,
2014, 2013 and 2012, the company made cash interest payments of $7,283, $13,189 and $13,920, respectively.
O.
Investment in Medusa Spar LLC
During the fourth quarter of 2013, the Company closed on the sale of its 15.0% working interest in the Medusa field, its
10.0% membership interest in Medusa Spar LLC (“LLC”), and substantially all of its remaining Gulf of Mexico shelf
properties. Prior to the sale, the Company’s ownership interest in the LLC was accounted for under the equity method of
accounting. The LLC held a 75% undivided ownership interest in the deepwater spar production facilities at the Medusa field
in the Gulf of Mexico and earned a tariff based upon production volume throughput from the Medusa area. The Company
was obligated to process through the spar production facilities its share of production from the Medusa field and any future
discoveries in the area. The balance of the LLC was owned by Oceaneering International, Inc. and Murphy Oil Corporation.
See Note 3 for additional information on the Medusa divestiture.
P.
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 all options and vesting of all restricted stock and restricted stock units settleable in shares.
Q.
Recent Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board issued accounting standards update (“ASU”) No. 2014-09, Revenue
from Contracts with Customers. 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 No. 2014-09 will replace most of the existing revenue recognition requirements in
GAAP when it becomes effective. The guidance in ASU No. 2014-09 is effective for public entities for annual reporting
periods beginning after December 15, 2016, including interim periods therein. Early adoption is not permitted. The Company
is currently evaluating the method of adoption and impact this standard will have on its financial statements and related
disclosures.
Note 3 – Acquisitions and Dispositions
2014 acquisitions
In the first quarter of 2014, the Company acquired 1,527 net acres in Upton and Reagan Counties, Texas, which are located
in the southern portion of the Midland Basin near its existing core development fields, for an aggregate cash purchase price
of $8,200. The properties bear a working interest of 100% and an average net revenue interest of 78%.
70
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 Acquisition”) for an
aggregate cash purchase price of $210,205, including estimated purchase price adjustments of $2,367 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 Acquisition. 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 Central Midland Basin Acquisition was accounted for under the purchase method of accounting, which involves
determining the fair value of the assets acquired and liabilities assumed. 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:
Oil and natural gas properties
Unevaluated oil and natural gas properties
Asset retirement obligations
Net assets acquired
$
$
91,895
118,450
(140)
210,205
The following unaudited summary pro forma financial information for the year ended December 31, 2014 and 2013 has been
presented for illustrative purposes only and does not purport to represent what the Company’s results of operations would
have been if the Central Midland Basin Acquisition had occurred as presented, or to project the Company’s results of
operations for any future periods. The pro forma financial information was prepared assuming the Central Midland Basin
Acquisition and the debt transactions and equity offering discussed in Notes 5 and 10, respectively, 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.
Revenues
Income from operations
Income available to common stockholders
Net income per common share
Basic
Diluted
2013 acquisitions
For the Years Ended December 31,
2014
2013
180,458 $
53,526
33,674
0.57 $
0.56 $
151,766
36,002
4,033
0.07
0.07
$
$
$
During the second quarter of 2013, the Company acquired approximately 2,468 gross (2,186 net) acres in Reagan and Upton
Counties, Texas, which is located in the Southern Midland Basin and which is prospective for both horizontal and vertical
drilling. The acquisition also included seven gross vertical wells and 1,301 barrels of oil equivalent proved reserves. The
purchase price of $11,000 was funded using a portion of the proceeds from the preferred stock offering (discussed in Note
10).
2012 acquisitions
During the first quarter of 2012, the Company acquired 16,233 gross (14,653 net) acres in Borden County, which is located in
the Northern Midland basin. The Northern Midland basin has had limited drilling activity compared with the Southern
Midland basin (where our current production is located), increasing the economic risk related to these drilling activities. The
purchase price of $14,538 was funded from existing cash balances. During the third quarter of 2012, we acquired an
additional 8,095 gross acres (6,964 net) in this area for a total consideration of $4,835.
71
During the second quarter of 2012, the Company signed a purchase and sale agreement to acquire 2,319 gross (1,762 net)
acres in southern Reagan County, Texas for a total purchase price of $12,012, which was financed with a draw on the Credit
Facility. The transaction had an effective date of May 1, 2012 and closed on July 5, 2012.
2013 dispositions
During the fourth quarter of 2013, the Company closed on the sale of its 15.0% working interest in the Medusa field
(Mississippi Canyon blocks 582 and 538), our 10.0% membership interest in Medusa Spar LLC, and substantially all of our
remaining Gulf of Mexico shelf properties for total net cash consideration of approximately $88,000 after customary
purchase price adjustments. Also during the fourth quarter of 2013, the Company closed on the sale of its 69% interest in the
Swan Lake field for $2,000. This was the Company’s only field in the Haynesville shale. The proceeds from these sales were
accounted for as a reduction to capitalized costs as the sales did not significantly alter the relationship between capitalized
costs and proved reserves.
2012 dispositions
During 2012, the Company closed on the sale of its 11.25% working interest in the Habanero field (Garden Banks Block 341)
for net cash consideration of $39,410 after customary purchase price adjustments. The proceeds from this sale were
accounted for as a reduction to capitalized costs as the sale did not significantly alter the relationship between capitalized
costs and proved reserves.
Note 4 - Earnings Per Share
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. A reconciliation of the basic and diluted net
income per share computation is as follows:
The following table sets forth the computation of basic and diluted earnings per share:
For the Year Ended December 31,
Net income (loss)
Preferred stock dividends
Income (loss) available to common stockholders
2014
37,766 $
(7,895)
29,871 $
$
$
4,304 $
(4,627)
(323) $
2013
2012
Weighted average shares outstanding
Dilutive impact of stock options
Dilutive impact of restricted stock
Weighted average shares outstanding for diluted income (loss) per share (a)
44,848
—
1,113
45,961
40,133
—
—
40,133
Basic income (loss) per share
Diluted income (loss) per share
$
$
0.67 $
0.65 $
(0.01) $
(0.01) $
0.07
0.07
The following were excluded from the diluted earnings per share calculation because their effect would be anti-dilutive:
Stock options
Restricted stock
52
123
Because the Company reported a loss available to common stockholders for the year ended December 31, 2013, no
unvested stock awards were included in computing loss per share because the effect was anti-dilutive.
30
317
52
398
(a)
72
2,747
—
2,747
39,522
8
807
40,337
Note 5 – Borrowings
The Company’s borrowings consisted of the following at:
Principal components:
Senior secured revolving credit facility
Secured second lien term loan
13% Senior Notes, principal
Total principal outstanding
13% Senior Notes, unamortized deferred credit
Total carrying value of borrowings
For the Year Ended December 31,
2014
2013
$
$
35,000 $
300,000
—
335,000
—
335,000 $
22,000
—
48,481
70,481
5,267
75,748
Senior secured revolving credit facility (the “Credit Facility”)
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 participating lenders include
Regions Bank, Citibank, N.A., Capital One, N.A., KeyBank, N.A., Whitney Bank, IberiaBank, N.A., OneWest Bank, N.A.,
SunTrust Bank and Royal Bank of Canada. 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.
In conjunction with the closing of the Acquisition on October 8, 2014, the borrowing base on the Company’s Credit Facility
was amended to $250,000.
As of December 31, 2014, the balance outstanding on the Credit Facility was $35,000 with a weighted-average interest rate
of 1.91%, calculated as the LIBOR plus a tiered rate ranging from 1.75% to 2.75%, 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. The Company had $215,000 of available borrowings under the Credit Facility as of December
31, 2014.
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 occurs
prior to March 11, 2015, and (ii) 101% if the prepayment event occurs 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 April 10, 2014, the Company drew an initial
amount of $62,500 with an original issue discount of 1.0%.
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 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. On October 8, 2014, the Company drew an
initial amount of $300,000 with a discount of 2.0% and an interest rate of 8.5%, calculated at a rate of LIBOR (subject to a
floor rate of 1.0%) plus 7.5% per annum. The Second Lien Loan may be prepaid at the Company’s option, subject to a
prepayment premium. The prepayment amount is (i) 102% if the prepayment event occurs prior to October 8, 2015, and (ii)
101% if the prepayment event occurs on or after October 8, 2015 but before October 8, 2016, and (iii) 100% for prepayments
made on or after October 8, 2016. The Second Lien Loan is secured by junior liens on properties mortgaged under the Credit
Facility, subject to an intercreditor agreement. The Royal Bank of Canada is Administrative Agent, and participants include
several institutional lenders.
73
13% senior notes due 2016 (“Senior Notes”) and deferred credit
On April 11, 2014, the Company completed a full redemption of the remaining $48,481 principal amount of outstanding
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 Senior Notes ($1,576 of redemption costs, primarily the call premium)
and the carrying value of the remaining 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 Senior Notes
was discharged in accordance with its terms.
Using a portion of the proceeds from the sale of our interest in Medusa on December 17, 2013, the Company redeemed
$48,481 of its Senior Notes, which resulted in a net $3,696 gain on the early extinguishment of debt. The gain represents the
difference between the $50,057 paid for the redemption of the Senior Notes (inclusive of $1,576 of redemption expenses,
primarily the call premium) and the carrying value of $53,756 (inclusive of the $5,275 of accelerated deferred credit
amortization).
In June 2012, the Company redeemed $10,000 of its Senior Notes, which resulted in a net $1,366 gain on the early
extinguishment of debt. The gain represents the difference between the $10,225 paid for the redemption of the Senior Notes
(inclusive of $225 of redemption expenses, primarily the call premium) and the carrying value of $11,591 (inclusive of the
$1,591 of accelerated deferred credit amortization).
Restrictive covenants
The Company’s Credit Facility and Second Lien Loan 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, 2014.
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
72
collars, swaps, puts, calls 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 that have netting provisions that provide for
offsetting payables against receivables. 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.
74
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 elected not to designate its derivative contracts as accounting hedges for contracts executed subsequent to
December 31, 2012. Consequently, the Company records its derivative contracts at fair value in the consolidated balance
sheet and records changes in fair value as a gain or loss on derivative contracts in the consolidated statement of operations.
Cash settlements are also recorded as gain or loss on derivative contracts in the consolidated statement of operations.
The following table reflects the fair value of the Company’s derivative instruments for the periods presented:
Asset Fair Value
Commodity Classification Line Description 12/31/2014 12/31/2013 12/31/2014 12/31/2013 12/31/2014 12/31/2013
Balance Sheet Presentation
Liability Fair Value
Net Derivative Fair
Value
Derivatives not designated as Hedging Instruments under
ASC 815
Natural gas Current
Natural gas Non-current
Oil
Current
Total
Fair value of
derivatives
Other long-term
liabilities
Fair value of
derivatives
$
1,262 $
60 $
(7) $
— $
1,255 $
60
—
—
—
(72)
—
(72)
26,588
27,850 $
$
—
60 $
(1,242)
(1,249) $
(1,036) 25,346
(1,108) $ 26,601 $
(1,036)
(1,048)
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, 2014
Current assets: Fair value of derivatives
Current liabilities: Fair value of derivatives
Current assets: Fair value of derivatives
Current liabilities: Fair value of derivatives
Long-term liabilities: Fair value of derivatives
Presented without
As Presented with
Effects of Netting Effects of Netting Effects of Netting
$
$
27,850 $
(1,249) $
— $
— $
27,850
(1,249)
For the Year Ended December 31, 2013
Presented without
As Presented with
Effects of Netting Effects of Netting Effects of Netting
$
8 $
1,088
(72) $
52 $
(52)
— $
60
1,036
(72)
$
Derivatives not designated as hedging instruments under ASC 815
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:
75
Natural gas derivatives
Net gain (loss) on settlements
Net gain (loss) on fair value adjustments
Total gain (loss)
Oil derivatives
Net gain (loss) on settlements
Net gain (loss) on fair value adjustments
Total gain (loss)
Total gain (loss) on derivative contracts
For the Year Ended December 31,
2013
2014
2012
$
$
$
$
$
(84) $
1,267
1,183 $
4,170 $
26,383
30,553 $
(148) $
230
82 $
1,518 $
(2,960)
(1,442) $
31,736 $
(1,360) $
34
(241)
(207)
—
1,924
1,924
1,717
Derivatives designated as hedging instruments under ASC 815
The Company’s derivative contracts executed prior to December 31, 2012 were designated as accounting hedges. The table
below presents the effect of the Company’s derivative financial instruments on the consolidated statements of operations as
an increase to oil and natural gas sales:
For the Year Ended December
31,
2013
2014
2012
Amount of gain reclassified from OCI into income
$
— $
— $
1,420
Derivative positions
Listed in the tables below are the outstanding oil and natural gas derivative contracts as of December 31, 2014:
Oil contracts
Collar contracts combined with short puts
(three-way collar):
Volume (MBbls)
Price per Bbl
Ceiling (short call)
Floor (long put)
Short put
Swap contracts:
Total volume (MBbls)
Weighted average price per Bbl
Put spreads:
Volume (MBbls)
Long put price per Bbl
Short put price per Bbl
For the Three Months Ended
March 31,
2015
June 30,
2015
September 30, December 31,
2015
2015
158
159
$
$
$
$
$
$
99.10 $
90.00 $
75.00 $
171
92.25 $
—
— $
— $
99.10 $
90.00 $
75.00 $
136
92.18 $
—
— $
— $
—
— $
— $
— $
129
92.25 $
138
90.00 $
75.00 $
—
—
—
—
74
92.20
138
90.00
75.00
76
Natural gas contracts
Collar contracts combined with short
puts (three-way collar):
Volume (BBtu)
Weighted average price per MMBtu
Ceiling (short call)
Floor (long put)
Short put
Swap contracts:
Total volume (BBtu)
Weighted average price per MMBtu
Short call contract:
Short call volume (BBtu)
Short call price per MMBtu
For the Three Months Ended
March 31,
2015
June 30,
2015
September 30, December 31,
2015
2015
248
4.67 $
4.00 $
3.50 $
271
3.98 $
108
5.00 $
227
4.32 $
3.85 $
3.25 $
237
3.98 $
109
5.00 $
207
4.32 $
3.85 $
3.25 $
219
3.98 $
110
5.00 $
161
4.32
3.85
3.25
228
3.96
111
5.00
$
$
$
$
$
Subsequent to December 31, 2014, the Company restructured its portfolio of benchmark West Texas Intermediate oil hedges
for 2015 and separately entered into new swap arrangements. The Company converted all of its three-way collars and put
spreads into new swap contracts with fixed swap prices that received a premium to prevailing swap price levels at the time to
reflect the value of the monetized put spreads embedded in the converted non-swap structures. Following the restructuring
transaction and addition of new swap contracts, we currently have an average of 4,165 barrels of oil per day hedged at a
weighted average swap price of $70.89 per barrel for calendar year 2015.
In addition, the Company recently entered into basis differential swaps that provide for a fixed price spread between the
Midland and NYMEX prices for West Texas Intermediate oil. The Company hedged an average of approximately 4,120
barrels of oil per day from March 2015 to December 2015 at a weighted average Midland swap spread of ($2.39) per barrel.
The following derivative contracts for oil were executed subsequent to December 31, 2014:
Oil contracts
Swap contracts:
Total volume (MBbls)
Weighted average price per Bbl
Swap contracts (Differentials):
Total volume (MBbls)
Weighted average price per Bbl
Note 7 - Fair Value Measurements
For the Three Months Ended
March 31,
2015
June 30,
2015
September 30, December 31,
2015
2015
$
$
231
60.77 $
152
(2.41) $
273
60.09 $
400
(2.40) $
253
59.83 $
382
(2.39) $
253
59.83
326
(2.38)
The fair value hierarchy outlined in the relevant accounting guidance 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, restricted investments. The carrying amounts for these instruments approximate fair value due to the
short-term nature or maturity of the instruments.
Debt. The Company’s debt is recorded at the carrying amount in the consolidated balance sheet. The carrying amount of
floating-rate debt approximated fair value because the interest rates were variable and reflective of market rates.
77
The following table summarizes the respective carrying and fair values at:
December 31,
2014
2013
Carrying
Value
Fair Value
Carrying
Value
Fair Value
$
$
35,000 $
300,000
—
335,000 $
35,000 $
300,000
—
335,000 $
22,000 $
—
53,748
75,748 $
22,000
—
50,299
72,299
Credit Facility
Second Lien Loan
13% Senior Notes due 2016 (a)
Total
(a)
The fair value, using Level 2 inputs, was based upon estimates provided by an independent investment banking
firm. 2013 fair value was determined only in relation to the $48,481 face value outstanding of the 13% Senior
Notes. The remaining $5,267 represented the deferred credit, which was excluded from the fair value
calculation. See Note 5 for additional information.
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.
The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis:
December 31, 2014
Assets
Derivative financial instruments (current)
Derivative financial instruments (non-
current)
Sub-total assets
Liabilities
Derivative financial instruments (current)
Derivative financial instruments (non-
current)
Sub-total liabilities
Total net assets (liabilities)
Balance Sheet Presentation
Level 1 Level 2 Level 3 Total
Fair value of derivatives
$
— $ 27,850 $
— $ 27,850
Other assets, net
Fair value of derivatives
Other long-term liabilities
—
—
— $ 27,850 $
—
—
— $ 27,850
— $ (1,249) $
— $ (1,249)
—
—
— $ (1,249) $
—
—
— $ (1,249)
— $ 26,601 $
— $ 26,601
$
$
$
$
78
December 31, 2013
Assets
Derivative financial instruments (current)
Derivative financial instruments (non-
current)
Sub-total assets
Liabilities
Derivative financial instruments (current)
Derivative financial instruments (non-
current)
Sub-total liabilities
Total net assets (liabilities)
Balance Sheet Presentation
Level 1 Level 2 Level 3 Total
Fair value of derivatives
$
— $
60 $
— $
Other assets, net
Fair value of derivatives
Other long-term liabilities
$
$
$
$
—
— $
—
60 $
—
— $
— $ (1,036) $
— $ (1,036)
(72)
—
— $ (1,108) $
(72)
—
— $ (1,108)
— $ (1,048) $
— $ (1,048)
60
—
60
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Acquisition. On October 8, 2014, the Company completed the Acquisition as discussed in Note 3. The Company determined
the fair value of the assets acquired using the income approach based on expected future cash flows from estimated reserve
quantities; costs to produce and develop reserves; and oil and gas forward prices. Asset retirement obligations assumed in
connection with the Central Midland Basin Acquisition were determined in accordance with applicable accounting standards.
The fair value measurements were based on level 2 and level 3 inputs. For more information on the Acquisition see Note 3.
During the second quarter of 2013, the Company completed an acquisition as discussed in Note 3. The Company determined
the fair value of the assets acquired using the income approach based on expected future cash flows from estimated reserve
quantities; costs to produce and develop reserves; and oil and gas forward prices. Asset retirement obligations assumed in
connection with this acquisition were determined in accordance with applicable accounting standards. The fair value
measurements were based on level 2 and level 3 inputs.
Other Property and Equipment. As discussed in Note 14, the Company’s decision to abandon certain of its other property
and equipment, that had been classified as held for sale, resulted in an impairment charge of $1,707 which is included in the
Company’s Statement of Operations for the year ended December 31, 2013. The impairment charge was valued using level 3
inputs. See Note 14 for more information.
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:
77
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 $1,017, $923 and $918 in the years 2014, 2013 and 2012, 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
79
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
issue 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. As of December 31, 2014, the 2011 Plan had 1,132,000 shares
remaining and eligible for future issuance.
Equity awards issued under this plan may be subject to various vesting, accelerated vesting, and forfeiture provisions upon
the occurrence of certain events. Any vested but unexercised options contractually expire 10 years from the date of
grant. 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 performance-based awards, the Company recognizes expense based on
its analysis of the performance criteria, and records or reverses expense as necessary based on its analysis. For market-based
awards, the Company recognizes expense based on its analysis of the market criteria, and records expense as necessary based
on its analysis. 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.
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. 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. Changes in the
fair value of cash-settleable awards are recorded as adjustments to compensation expense.
Market-based RSUs: 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.
78
As of December 31, 2014, the Company had the following cash-settleable RSU awards outstanding (including those that are
not based on a market condition):
(shares in 000s)
Vesting in 2015
Vesting in 2016
Vesting in 2017
Other
Total cash-settleable RSU awards
Base Units
Outstanding
Potential Minimum
Units Vesting
Potential
Maximum Units
Vesting
837
416
24
137
1,414
52
60
24
137
273
1,622
772
24
137
2,555
For the year ended December 31, 2014, 523,000 market-based cash-settled RSUs subject to the peer market-based vesting
described above vested at between 150% - 200%, depending on the date of vesting, resulting in cash payments of $1,241 in
2014 and payable amounts of $3,599 in 2015. Also during 2014, 58,000 non-market-based cash settled RSUs vested,
resulting in cash payments of $559 in 2014. During 2013, 260,000 market-based cash-settled RSUs subject to the peer
market-based vesting described above vested at 100% of their issued units, resulting in cash payments of $1,669 in 2014.
Also during 2013, 65,000 non-market-based cash settled RSUs vested, resulting in cash payments of $239 in 2013. See Note
9 for additional information regarding cash-settleable RSUs.
80
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, 2014, 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 1,132,000.
The following table presents share-based compensation expense for each respective period:
2014
For the Year Ended December 31,
2013
2012
Share-based compensation cost for: Equity-based
RSU equity awards
Cash-settleable RSU awards
401(k) contributions in shares
Total share-based compensation cost
(a)
4,223 $
—
270
$
$
Liability-
based
Equity-based
Liability-
based
Equity-based
Liability-
based
— $
6,918
—
3,975 $
—
219
— $
5,347
—
4,210 $
—
218
—
2,916
—
(a)
2,916
The portion of this share-based compensation cost that was included in general and administrative expense totaled
$7,235, $5,751 and $4,081 for the same years, respectively, and the portion capitalized to oil and gas properties
was $4,176, $3,791 and $3,263, respectively.
5,347 $
6,918 $
4,428 $
4,194 $
4,493 $
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
For the Year Ended December 31,
2013
2014
2012
$
3,979 $
4,977
5,331 $
7,669
6,320
2,826
The Company’s unrecognized compensation cost related to unvested RSU and cash-settleable RSU awards is expected to be
recognized over a weighted-average period of 1.6 years.
The following table summarizes the Company’s liability for cash-settled RSU awards for the periods indicated:
Consolidated Balance Sheets Classification
Cash-settled restricted stock unit awards - current
Cash-settled restricted stock unit awards - non-current
Total cash-settled RSU awards
Stock Options
December 31,
2014
2013
$
$
3,856 $
7,175
11,031 $
4,173
3,409
7,582
The Company issued no stock options for the past three years and had no options vest or forfeit during 2014. Additionally, no
options were exercised, and 22,000 options expired unexercised during the year. 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.
As of December 31, 2013, the Company had 52,000 options outstanding and exercisable at a weighted average exercise price
per option of $13.75, with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 2.3
years. As of December 31, 2012, the Company had 67,000 options outstanding and exercisable at a weighted average
exercise price per option of $11.82, with no aggregate intrinsic value and with a weighted-average remaining contract life per
unit of 2.7 years.
81
Restricted Stock Units
The following table represents unvested restricted stock activity for the year ended December 31, 2014:
(shares in 000s)
Outstanding at the beginning of the period
Granted
Vested (a)
Forfeited
Outstanding at the end of the period
Number of Shares
2,262 $
333
(684)
(43)
1,868 $
(a) The fair value of shares vested was $4,338.
Weighted average
Grant-Date Fair
Value per Share
Period over which
expense is expected
to be recognized
5.03
9.67
6.34
4.11
5.40
1.2
For the year ended December 31, 2013, the Company granted 944,000 RSUs with a weighted average grant-date fair value of
$3.82 per share. The fair value of shares vested during 2013 was $2,689. For the year ended December 31, 2012, the
Company granted 1,008,000 RSUs with a weighted average grant-date fair value of $5.22 per share. The fair value of shares
vested during 2012 was $2,817.
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 $7,895 and $4,627 in 2014 and 2013, respectively.
The Preferred Stock has no stated maturity and is not be 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, 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 a 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, 2014, and the Company did not exercise its right to
redeem the Preferred Stock, using the closing price of the common stock on such date ($5.45) as the value of a share of
common stock, each share of Preferred Stock would be convertible
80
into approximately 9.2 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.
Common Stock
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 Acquisition (see Note 3).
82
Note 11 - Income Taxes
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 effective tax
rate for the years ended December 31, 2014 and 2013 was 38% and 42%, respectively.
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
Statutory depletion carryforward
Alternative minimum tax credit carryforward
Asset retirement obligations
Other
Total deferred tax asset
Deferred tax liability
Oil and natural gas properties
Other
Total deferred tax liability
Net deferred tax asset
As of December 31,
2014
2013
$
$
86,629 $
8,876
208
1,003
6,621
103,337
54,723
10,140
64,863
38,474 $
70,365
8,880
208
1,024
7,575
88,052
26,412
32
26,444
61,608
If not utilized, the Company’s federal operating loss (“NOL”) carryforwards will expire as follows:
Federal NOL carryforwards $
247,513 $
— $
111,415 $
14,408 $
41,379 $
Total
2015-2020
2021-2023
2024-2026 2027-2029
2030-2034
80,311
Year Expiring
The Company’s current operations are located in Texas and are subject to the Texas margin tax. The Company has
established a full valuation allowance on the tax benefits associated with state net operating loss carryforwards of
approximately $171,907, which expire in years through 2034, related to other states in which the Company does not
anticipate generating taxable state income. These amounts are not included in the deferred tax summary table above.
The Company had no significant unrecognized tax benefits at December 31, 2014. 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 2001 through 2014
remain open to examination by the federal and state taxing jurisdictions to which the Company is subject.
Below is a reconciliation of the reported amount of income tax expense attributable to continuing operations 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)
Other
Effective income tax rate
For the Year Ended December 31,
2013
2014
2012
35%
—%
1%
—%
2%
—%
38%
35%
(8)%
4%
5%
6%
—%
42%
35%
(22)%
6%
2%
22%
4%
47%
83
Components of income tax expense
Current state income tax expense
Deferred federal income tax expense
Deferred state income tax expense
Total income tax expense
Note 12 - Asset Retirement Obligations
For the Year Ended December 31,
2013
2014
2012
$
$
— $
22,373
761
23,134 $
326 $
2,652
126
3,104 $
110
1,777
336
2,223
The table below summarizes the activity for the Company’s asset retirement obligations:
Asset retirement obligations at January 1, 2014
Accretion expense
Liabilities incurred
Liabilities assumed
Liabilities settled
Liabilities related to oil and gas properties sold
Revisions to estimate
Asset retirement obligations at end of period
Less: Current asset retirement obligations
Long-term asset retirement obligations at December 31, 2014
For the Year Ended December 31,
2014
2013
6,732 $
826
638
140
(2,130)
—
468
6,674
(4,747)
1,927 $
13,301
1,785
679
—
(457)
(4,765)
(3,811)
6,732
(4,120)
2,612
$
$
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, 2014 as long-term restricted investments were $3,810. 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.
Note 13 – Supplemental Information on Oil and Natural Gas Properties (Unaudited)
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
Beginning of period balance
Capitalized G&A
Property acquisition costs (a)
Exploration costs
Development costs
End of period balance
Unevaluated Properties
Beginning of period balance
Property acquisition costs (a)
Exploration costs
Capitalized interest
Transfers to evaluated
End of period balance
Accumulated depreciation, depletion and amortization
Beginning of period balance
Provision charged to expense
Sale of mineral interests
End of period balance
(a) For more information on acquisitions refer to Note 3
$
$
$
$
$
$
84
For the Year Ended December 31,
2013
2014
2012
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 $
1,497,010 $
10,014
10,885
147,164
36,504
1,701,577 $
68,776 $
2,259
10,767
4,410
(42,990)
43,222 $
1,421,640
12,148
2,075
22,703
38,444
1,497,010
2,603
29,590
34,674
2,109
(200)
68,776
1,296,265 $
42,251
82,096
1,420,612 $
1,208,331
48,524
39,410
1,296,265
Unevaluated property costs primarily include lease acquisition costs, unevaluated drilling costs, seismic, capitalized interest
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 Company expects that the
majority of these costs will be evaluated over the next three but within five years.
Subsequent to December 31, 2014 and through February 27, 2015, the Company completed five horizontal wells, drilled four
horizontal wells and had two horizontal wells in progress.
Depletion per unit-of-production, on a BOE basis, amounted to $27.51, $31.12 and $31.56 for the years ended December 31,
2014, 2013, and 2012, respectively. Lease operating expenses per unit-of-production, on a BOE basis, amounted to
$10.85, $14.00, and $14.81 for the years ended December 31, 2014, 2013, and 2012, respectively.
Under the 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 generally require pricing based on the preceding 12-months’ average oil and
natural gas market 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. Given the volatility of oil and natural
gas prices, it is reasonably possible that the Company’s estimate of discounted future net cash flows from proved oil and
natural gas reserves could change in the near term. If oil and natural gas prices remain at current levels or decline further,
even if only for a short period of time, write-downs of oil and natural gas properties could occur in the future.
Estimated Reserves
The Company’s proved oil and natural gas reserves at December 31, 2014 have been estimated by DeGolyer and
MacNaughton, the Company’s current independent petroleum engineers. The Company’s proved oil and natural gas reserves
at December 31, 2013 and 2012 were estimated by Huddleston & Co., Inc. 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.
Changes in the estimated net quantities of oil and natural gas reserves, all of which are located onshore within the continental
United States and offshore within the Gulf of Mexico (prior to December 31, 2013), are as follows:
85
Reserve Quantities
For the Year Ended December 31,
2013
2014
2012
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
11,898
(243)
3,223
-
12,547
(1,692)
25,733
17,751
(215)
8,591
-
18,641
(2,220)
42,548
5,960
14,006
9,059
25,171
7,470
18,201
5,938
11,727
8,692
17,377
7,387
14,623
10,780
(2,540)
150
(3,294)
7,713
(911)
11,898
19,753
(5,351)
317
(4,576)
10,619
(3,011)
17,751
4,955
5,960
10,680
9,059
6,735
7,470
5,825
5,938
9,073
8,692
7,337
7,387
10,075
(488)
38
(504)
2,636
(977)
10,780
35,118
(10,838)
115
(4,404)
3,350
(3,588)
19,753
5,069
4,955
11,605
10,680
7,003
6,735
5,006
5,825
23,513
9,073
8,925
7,337
Total Proved Reserves: 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, on which 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.
The Company ended 2013 with estimated net proved reserves of 14,857 MBOE, representing a 6% increase over 2012 year-
end estimated net proved reserves of 14,072 MBOE. The increase was primarily due the Company’s development of its
properties in the Permian Basin offset by the sale of the Company’s interest in the Medusa field and due to the Company’s
reclassification of certain vertical PUD locations to the horizontal probable and PUD categories.
The Company ended 2012 with estimated net proved reserves of 14,072 MBOE, representing a 12% decrease over 2011
year-end estimated net proved reserves of 15,928 MBOE. The decrease was primarily due to the sale of the Company's
86
interest in the Habanero field and the downward revision of our Haynesville Shale undeveloped reserves at year-end 2012,
which were reduced due to low natural gas prices. These decreases were partially offset by the Company’s development of a
portion of its Permian Basin, on which it drilled a total of 27 oil wells during 2012.
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 onshore 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 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.
The Company’s PUDs increased 1% to 7,387 MBOE from 7,337 MBOE at December 31, 2013 and 2012, respectively. The
Company added 5,168 MBOE to its PUDs, primarily from the continued horizontal development of its Permian Basin
properties. The increase in Permian Basin PUDs was partially offset by 3,724 MBOE, or 51%, included in the year-end 2012
PUD reserves related to vertical PUD locations that were reclassified to horizontal probable reserves, and to a small extent,
horizontal PDP and PUD categories. The reclassified vertical PUDs include locations that included certain target zones that
were expected to be more efficiently developed by the Company’s multi-level horizontal drilling programs initiated in 2012.
Also offsetting the Permian Basin PUD growth were the sale of 1,297 MBOE, or 18%, included in the year-end 2012 PUD
reserves related to our Medusa field and the conversion of a small portion of 2012 PUD reserves to PDPs during 2013 from
the drilling of vertical wells.
The Company's PUDs decreased 18% to 7,337 MBOE from 8,925 MBOE at December 31, 2012 and 2011, respectively.
Additions during the year added 2,344 MBOE to the Company's PUDs, offset by (1) 557 MBOE primarily comprised of
transfers to PDPs as a result of our development program, (2) 1,148 MBOE related to the sale of Habanero, and (3) 2,227
MBOE related to reductions in our PUD reserves, primarily related to the Haynesville Shale, by amounts no longer deemed
to be economic PUDs at year-end. Of the Company's year-end 2011 PUD reserves, 6% were converted to proved developed
producing reserves by year end 2012, at a total cost of approximately $19 million, net.
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, 2014. 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
Average 12-month price, net of differentials, per barrel of oil
$
$
6.38 $
86.30 $
5.45 $
92.16 $
2014
2013
2012
4.81
94.68
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.
87
Natural gas production from our Permian Basin and former deepwater offshore properties has a high Btu content of separator
natural gas. The natural gas per Mcf prices of $6.38, $5.45 and $4.81 used in the 2014, 2013 and 2012, respectively, reserve
estimates include adjustments to reflect the Btu content, transportation charges and other fees specific to the individual
properties. The oil prices per Bbl of $86.30, $92.16 and $94.68 used in the 2014, 2013 and 2012 reserve estimates have been
adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs,
location differentials and crude quality.
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 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
Note 14 – Other
Commitments and contingencies
$
$
$
$
Standardized Measure
For the Year Ended December 31,
2013
1,193,299 $
2014
2,492,178 $
2012
1,115,570
(873,469)
(288,081)
1,330,628
(164,490)
1,166,138
(586,596)
579,542 $
(357,005)
(155,667)
680,627
(68,239)
612,388
(328,442)
283,946 $
(249,329)
(273,817)
592,424
(55,772)
536,652
(305,504)
231,148
Changes in Standardized Measure
For the Year Ended December 31,
2013
2014
2012
283,946 $
(120,518)
(156,066)
111,331
299,192
186,605
(7,673)
30,114
(32,940)
(14,449)
295,596
579,542 $
231,148
(78,661)
(46,088)
(145,711)
212,431
153,983
(68,958)
25,010
1,751
(959)
52,798
283,946 $
270,357
(84,044)
47,261
(35,665)
53,446
39,815
(77,322)
30,989
13,969
(27,658)
(39,209)
231,148
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.
88
Operating leases
In April 2012, the Company contracted a drilling rig (the “Cactus 1 Rig”), which it subsequently renewed in December 2014
for a term of two years ending November 2016. In April 2014, the Company contracted an additional horizontal drilling rig
(the “Cactus 2 Rig”), which it subsequently renewed in December 2014 for a term of two years ending in November 2016.
The Cactus 2 Rig replaced a previously contracted horizontal drilling rig, which was cancelled in March 2014. In August
2014, the Company signed a one-year contract for a vertical drilling rig to be used as part of its horizontal drilling program,
drilling the vertical section of horizontal wells. The rig lease agreements include early termination provisions that would
reduce the minimum rentals under the agreement, and also include provisions that would reduce the minimal rental payments
assuming the lessor is able to re-charter the rig and staffing personnel to another lessee. Subsequent to December 31, 2014,
the Company decided to terminate its one-year contract for the vertical rig effective April 2015 and currently may be required
to pay approximately $3,733 in reduced rental payments over the remainder of the lease term. Also subsequent to December
31, 2014, the Company extended the terms of its Cactus 1 Rig and Cactus 2 Rig to end in July 2018 and August 2018,
respectively. Lease payments in 2014 were $17,877 and are expected to approximate $16,893 (including early termination
payments), $10,980, $10,950 and $6,510 in 2015, 2016, 2017 and 2018, respectively.
Other property and equipment
During 2012, the Company sold certain specialized deep water property and equipment valued at $527 and determined that
certain equipment components were not usable without additional rework and thus recorded an impairment charge to with
respect to such equipment of $1,177. During 2013, after selling certain specialized deep water property and equipment valued
at $114, the Company made a decision to abandon the equipment. As such the Company recorded an impairment charge of
$1,707 representing the remaining value of this equipment. During 2014, the Company entered into an agreement to sell the
property and equipment to a third party. As a result of the subsequent sale of the property and equipment, the Company
recognized a gain of $1,080.
Note 15 – Summarized Quarterly Financial Information (Unaudited)
2014
Total revenues
Income from operations
Net income
Income (loss) available to common shares
$
Income (loss) per common share - basic
$
Income (loss) per common share - diluted
First Quarter Second Quarter Third Quarter Fourth Quarter
38,418
$
7,983
18,962
16,988
0.31
0.30
39,657 $
11,562
12,201
10,227
0.24 $
0.23 $
40,502 $
12,080
4,740
2,767
0.07 $
0.07 $
33,285 $
6,645
1,863
(111)
0.00 $
0.00 $
2013
Total revenues
Income from operations
Net income (loss)
Income (loss) available to common shares
$
Income (loss) per common share - basic
$
Income (loss) per common share - diluted
First Quarter Second Quarter Third Quarter Fourth Quarter
26,471
$
2,464
3,264
1,291
0.03
0.03
30,797 $
6,345
1,082
(892)
(0.02) $
(0.02) $
22,541 $
898
(800)
(800)
(0.02) $
(0.02) $
22,760 $
957
758
78
— $
— $
89
ITEM 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
There have been no disagreements with the independent auditors on any matters of accounting principles or practices,
financial statement disclosure, or auditing scope or procedures.
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, 2014.
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, 2014 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, 2014.
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, 2014, which follows Part II, Item 9B of this filing.
Additionally, the financial statements for each of the years covered in this Annual Report on Form 10-K have been audited
by an 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.
ITEM 9A (T). Controls and Procedures
See Item 9A.
ITEM 9B. Other Information
Submissions of matters to a vote of the security holders
None.
90
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of
Callon Petroleum Company
We have audited Callon Petroleum Company’s internal control over financial reporting as of December 31, 2014 based on
criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (2013 framework)(the COSO criteria). Callon Petroleum 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, Callon Petroleum Company maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2014, based on the COSO criteria.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
the consolidated balance sheets of Callon Petroleum Company as of December 31, 2014 and 2013, and the related
consolidated statements of operations, comprehensive income, stockholders’ equity and cash flows for each of the three years
in the period ended December 31, 2014, and our report dated March 4, 2015 expressed an unqualified opinion thereon.
/s/Ernst & Young LLP
New Orleans, Louisiana
March 4, 2015
91
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 14, 2015 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 14, 2015 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 14, 2015 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 14, 2015 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 14, 2015 which will be filed with the Securities and Exchange Commission and
is incorporated herein by reference.
92
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
1
Description
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.
2
3
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2014 and 2013
Consolidated Statements of Operations for each of the three years in the period ended December 31,
2014
Consolidated Statements of Stockholders’ Equity (Deficit) for each of the three years in the Period
Ended December 31, 2014
Consolidated Statements of Cash Flows for each of the three years in the period ended December 31,
2014
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.
Exhibits
2
3
Plan of acquisition, reorganization, arrangement, liquidation or succession*
Articles of Incorporation and Bylaws
3.1
3.2
3.3
4.1
4.2
Certificate of Incorporation of the Company, as amended through January 17, 2014 (incorporated by
reference to Exhibit 3.1 of the Company’s Form 10-Q filed on August 6, 2014
Certificate of Designation of Rights and Preferences of 10% 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 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 August 4, 1994, Reg. No. 33-82408)
Certificate for the Company’s 10% Cumulative Preferred Stock (incorporated by reference to
Exhibit 4.1 of the Company’s Form 8-A filed May 23, 2013
4
9
10
Voting trust agreement
None
Material contracts
10.1
10.2
10.3
10.4
10.5
Callon Petroleum Company 1996 Stock Incentive Plan as amended on May 9, 2000 (incorporated by
reference from Appendix I of the Company’s Definitive Proxy Statement on Schedule 14A, filed
March 28, 2000, File No. 001-14039)
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, File No.
001-14039)
Amendment No. 3 to the Callon Petroleum Company 1996 Stock Incentive Plan (incorporated by
reference from Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed January 5, 2009,
File No. 001-14039)
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 January 5, 2009,
File No. 001-14039)
Callon Petroleum Company Amended and Restated 2006 Stock Incentive Plan (incorporated by
reference from Exhibit 10.3 of the Company’s Current Report on Form 8-K, filed January 5, 2009,
File No. 001-14039)
93
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
Callon Petroleum Company 2009 Stock Incentive Plan effective as of April 30, 2009 (incorporated
by reference from Exhibit A to the Company’s Definitive Proxy Statement on Schedule 14A, filed
March 30, 2009, File No. 001-14039)
Amendment to the Callon Petroleum Company 1996 Stock Incentive Plan effective as of August 7,
2009 (incorporated by reference from Exhibit 10.1 of the Company’s Quarterly Report on Form 10-
Q for the period ended September 30, 2009, File No. 001-14039)
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, File No. 001-14039)
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 March 21, 2011, File No.
14039)
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 on
Form 8-K, filed on March 10, 2014, File No. 001-14039)
Fifth Amended and Restated Credit Agreement among Callon Petroleum Company, JPMorgan
Chase Bank, National Association, as administrative agent and the Lenders and parties named
therein dated March 11, 2014 (incorporated by reference to Exhibit 10.1 to the Company’s Report
on Form 10-Q/A filed June 11, 2014)
Operator Resignation and Transition Agreement between Callon Petroleum Operating Company and
Henry Resources LLC dated August 29, 2014 (incorporated by reference to Exhibit 10.1 of the
Company’s Report on Form 8-K filed October 14, 2014)
Purchase and Sale Agreement between Callon Petroleum Operating Company, as Purchaser, and
NAWAB energy partners, lp and NAWAB WI, lp, as Sellers, dated August 29, 2014 (incorporated
by reference to Exhibit 10.2 of the Company’s Report on Form 8-K filed October 14, 2014)
Purchase and Sale Agreement between Callon Petroleum Operating Company, as Purchaser, and
Hedloc Investment Co. LP, as Seller, dated August 29, 2014 (incorporated by reference to Exhibit
10.3 of the Company’s Report on Form 8-K filed October 14, 2014)
Amendment No. 2 to Fifth Amended and Restated Credit Agreement among Callon Petroleum
Company, JPMorgan Chase Bank, National Association, as administrative agent and the Lenders
and parties named therein dated October 8, 2014 (incorporated by reference to Exhibit 10.4 of the
Company’s Report on Form 8-K filed October 14, 2014)
Second Lien Credit Agreement among Callon Petroleum Company, Royal Bank of Canada and the
Lenders party thereto, dated October 8, 2014 (incorporated by reference to Exhibit 10.5 of the
Company’s Report on Form 8-K filed October 14, 2014)
Second Lien Intercreditor Agreement among Callon Petroleum Company, JPMorgan Chase Bank,
National Association, Royal Bank of Canada, and the other parties named therein dated October 8,
2014 (incorporated by reference to Exhibit 10.6 of the Company’s Report on Form 8-K filed
October 14, 2014)
11
12
13
Statement re computation of per share earnings*
Statements re computation of ratios*
Annual Report to security holders, Form 10-Q or quarterly reports*
94
14
Code of Ethics
14.1
16
18
21
21.1
22
23
23.1
23.2
23.3
24
31
31.1
31.2
32
99
99.1
101
*
**
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, File No. 001-14039)
Letter re change in certifying accountant*
Letter re change in accounting principles*
Subsidiaries of the Company
Subsidiaries of the Company
Published report regarding matters submitted to vote of security holders*
Consents of experts and counsel
Consent of Ernst & Young LLP
Consent of DeGolyer and MacNaughton, Inc.
Consent of Huddleston & Co., Inc.
Power of attorney*
Rule 13a-14(a) Certifications
Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)
Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)
Section 1350 Certifications of Chief Executive and Financial Officers pursuant to
Rule 13(a)-14(b)
Additional Exhibits
Reserve Report Summary prepared by DeGolyer and MacNaughton, Inc. as of December 31, 2014
Interactive Data Files **
Not applicable to this filing
Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of
a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933
or Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to
liability.
95
SIGNATURES
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.
Date:
March 4, 2015
Callon Petroleum Company
/s/ Joseph C. Gatto, Jr.
By: Joseph C. Gatto, Jr., senior vice 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:
March 4, 2015
Date:
March 4, 2015
Date:
March 4, 2015
Date:
March 4, 2015
Date:
March 4, 2015
Date:
March 4, 2015
Date:
March 4, 2015
Date:
March 4, 2015
Date:
March 4, 2015
/s/ Fred L. Callon
Fred L. Callon (principal executive officer, director)
/s/ Joseph C. Gatto, Jr.
Joseph C. Gatto, Jr. (principal financial officer)
/s/ Mitzi P. Conn
Mitzi P. Conn (principal accounting officer)
/s/ L. Richard Flury
L. Richard Flury (director)
/s/ John C. Wallace
John C. Wallace (director)
/s/ Anthony J. Nocchiero
Anthony J. Nocchiero (director)
/s/ Larry D. McVay
Larry McVay (director)
/s/ Matthew R. Bob
Matthew R. Bob (director)
/s/ James M. Trimble
James M. Trimble (director)
96
Corporate Data
Board of Directors
Fred L. Callon
Chairman, President
and Chief Executive Officer
L. Richard Flury
Former Chief Executive
Gas, Power & Renewables (Retired)
British Petroleum plc
Larry D. McVay
Former Chief Operating Officer
TNK-BP Holdings (Retired)
British Petroleum plc Joint Venture
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
London, England
Matthew R. Bob
President, Eagle Oil & Gas Company
James M. Trimble
Chief Executive Officer and President
of PDC Energy (Retired)
Officers of the Company
Fred L. Callon
Chairman, President
and Chief Executive Officer
Gary A. Newberry
Senior Vice President, Operations
Joseph C. Gatto, Jr.
Chief Financial Officer,
Senior Vice President and Treasurer
B.F. Weatherly
Corporate Secretary
Jerry A. Weant
Vice President, Land
Mitzi P. Conn
Corporate Controller
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
Ernst & Young LLP
New Orleans, Louisiana
Administrative Agent Bank
JPMorgan Chase Bank, N.A.
New York, New York
Corporate Offices
Callon Headquarters Building
200 North Canal Street
Natchez, Mississippi 39120
Mailing Address:
Callon Petroleum Company
PO Box 1287
Natchez, Mississippi 39121
Callon Petroleum Company
1401 Enclave Parkway, Suite 600
Houston, Texas 77077
Callon Petroleum Company
4305 North Garfield Street, Suite 235
Midland, Texas 79705
Form 10-K
The Company’s annual
report on Form 10-K,
excluding exhibits, has been incorporated into this
Annual Report.
Callon Website
at
The Company website
www.callon.com.
releases,
corporate governance materials, the annual report,
recent investor presentations, stock quotes and a link
to SEC filings.
can be
contains news
found
It
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.”
of
our
Preferred Stock Dividend Policy
Holders
stock
preferred
Series A
(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.
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
to
was filed and
such certification. On behalf of Fred L. Callon,
the Company filed the required certification on
March 4, 2015 without qualification.
to state any qualifications
Notice of Annual
Shareholders’ Meeting
The Annual Meeting of Shareholders will be held Thursday,
May 14, 2015 at 9:00 a.m. 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 27, 2015.
The 2014 Annual Report is not to be considered a part of
the proxy soliciting materials.
2014 Annual Report
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 77077 Phone: (281) 589-5200.
In accordance with SEC rules, you may access the Annual Report at www.callon.com, which does not have “cookies”
that identify visitors to the site.
Security analysts and investment professionals should direct written inquiries to Joe Gatto, Chief Financial
Officer and Treasurer, Callon Petroleum Company, 1401 Enclave Parkway, Suite 600, Houston, TX 77077
Phone: (281) 589-5200, Fax: (281) 589-5215
Callon Petroleum Company
200 North Canal Street
Natchez, MS 39120
www.callon.com
NYSE: CPE / CPE.A