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eNhANCeMeNT
ANNUAL REPORT
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INFORMATION
BOARD OF DIRECTORS
CORPORATE OFFICE
717 Texas Avenue, Suite 2900
Houston, Texas 77002
Phone: 713.236.7400
Fax: 713.236.4424
OUTSIDE COUNSEL
Vinson & Elkins
First City Tower
1001 Fannin Street, Suite 2500
Houston, Texas 77002
COMMON STOCK INFORMATION
The Common Stock is traded on the
NYSE MKT under the symbol “MCF”
TRANSFER AGENT
Continental Stock & Trust Company
17 Battery Place
New York, New York 10004
212.509.4000
AUDITORS
Grant Thornton LLP
700 Milam Street, Suite 300
Houston, Texas 77002
FORM 10-K
Additional copies of the Company’s Form 10-K
as filed with the Securities and Exchange
Commission, are available at our website
www.contango.com under Investor Relations
Joseph J. Romano
Chairman of the Board
Allan D. Keel
B.A. Berilgen
B. James Ford
Ellis L. McCain
Charles M. Reimer
Steven L. Schoonover
MANAGEMENT TEAM
Allan D. Keel
President and Chief Executive Officer
Thomas H. Atkins
Senior Vice President, Exploration
E. Joseph Grady
Senior Vice President and Chief Financial Officer
A. Carl Isaac
Senior Vice President, Operations
Jay S. Mengle
Senior Vice President, Engineering
John A. Thomas
Vice President, General Counsel
and Corporate Secretary
Michael J. Autin
Vice President, Production
Sergio Castro
Vice President and Treasurer
Jeff Sikora
Vice President, Land
Edward Skrljac
Vice President, Onshore Completions
Patrick Webb
Vice President, Business Development
Company
PROFILE
Contango Oil & Gas Company, based in Houston, Texas,
is an independent energy company engaged in the acquisition,
exploration, development, exploitation and production of
crude oil and natural gas properties offshore in the shallow
waters of the Gulf of Mexico and in the onshore Texas Gulf Coast
and Rocky Mountain regions of the United States.
Contango Oil & Gas Company
Dear Fellow
1
SHAREHOLDERS
Our pride in the operational goals achieved and the progress made in positioning the Company for
long term growth during 2014 were unceremoniously overshadowed by the sudden downturn in
commodity prices that began mid-summer and that have continued to adversely impact the industry
through the first quarter of 2015. However, the diligent efforts of our entire team in quickly reacting
to the downturn has positioned Contango to endure, and potentially benefit from, the down cycle
and has prepared us to resume the development of our asset base when commodity prices improve,
and/or when service costs decline to levels commensurate with and appropriate for today’s commodity
prices. Our balanced portfolio of producing oil and gas assets, our deep inventory of exploration
and development projects, and our strong liquidity position establish the foundation for Contango’s
long-term sustainability and capacity to create shareholder value.
Today our proved reserve asset base is roughly 52% shallow
one well in Zavala and Dimmit counties was drilled as a
water Gulf of Mexico and 48% onshore unconventional
vertical pilot well to test the viability of the Eagle Ford Shale
and conventional Texas Gulf Coast, and from a commodity
and other formations in the area; and four wells in Fayette and
standpoint, is approximately 65% natural gas and 35%
Gonzales counties, Texas were drilled on our new Elm Hill
crude oil and natural gas liquids. Our legacy natural gas
project. Of these 40 wells, 26 were on production by
operations in the Gulf of Mexico continue to provide
December 31, 2014, with 12 more to be placed on production
us stable cash flows that we will use to test our oil and
at various times in the first or second quarters of this year.
liquids weighted onshore exploration projects, and our
development projects when commodity prices improve.
We are excited about the progress made derisking and
further delineating parts of our portfolio during the year.
During 2014, we drilled 40 onshore wells, which included
We will continue to do that in 2015, but at a reduced
18 wells targeting the Woodbine formation in Southeast
pace as we balance the desire to continue to exploit the
Texas; 19 wells targeting multiple formations in South
potential of our inventory with the desire to maintain our
Texas; two wells targeting the James Lime formation in San
strong financial condition during this low commodity price
Augustine County, Texas; and one well on our new FRAMS
environment. We have elected to defer any development-
project in Natrona County, Wyoming targeting the Mowry
type drilling programs until a combination of higher
Shale. In the Woodbine, six of the wells drilled were on
commodity prices and/or lower capital costs provide
two multi-well pads to test the net recovery efficiency
superior return on investment economics over the longer
of 500-foot downspacing in our Chalktown area while
term, i.e. rather than internal rates of return economics on
another well in our Iola Grimes area targeted the Upper
high decline rate unconventional wells as many resource
Lewisville formation using twice the number of frac stages,
wells produce 60% to 70% of their PV-10 value in the first
four times the amount of proppant, and fifty percent longer
18 months. Consequently, in this period of low commodity
effective lateral lengths than our two previous attempts in
prices, and the associated lag on declining service costs still
the Iola Grimes area. In South Texas, 14 wells in Zavala
to be fully realized, we believe it is prudent from a value-
and Dimmit counties targeted the Buda formation;
add perspective to delay development drilling until prices
2014 Annual Report
2
improve and/or service costs decline further. However, we
do have the flexibility, liquidity and inventory to significantly
increase our level of spending should circumstances change
over the course of the year.
For 2015, we have budgeted approximately $51 million to
be spent over three strategic exploratory or exploitation
areas: 1) finish the test of downspacing strategy in our
Madison/Grimes area using multi-well pads; 2) continue
to test multiple formations in our new Elm Hill project in
Fayette and Gonzales counties in South Texas; and 3) finish
the drilling and completion of our initial tests in our Mowry
and Muddy Sandstone exploration programs in Wyoming.
This budget is approximately 73% less than 2014 levels,
TOTAL PROVED RESERVES*
275Bcfe
180 Bcfe (65%)
Natural Gas
16 MMBbls (35%)
Crude Oil and
Natural Gas Liquids
TOTAL 2014 PRODUCTION
40 Bcfe
26 Bcfe (64%)
Natural Gas
2 MMBbls (36%)
Crude Oil and
Natural Gas Liquids
* As of December 31, 2014, based on SEC pricing
hopefully adding high-value assets to our portfolio through
both strategies. This is a cyclical business, and we will
continue to manage our diversified portfolio and our
financial condition to ensure the long-term sustainability
of our company. We are optimistic about our long-term
potential to fulfill our mission and create shareholder value.
Our interests are aligned with yours; as the management
team, the Board of Directors, and all of our valuable
employees are shareholders in Contango. We thank you
for your ongoing support.
and is less than our forecasted cash flow, therefore we
Allan D. Keel
plan to use the excess cash flow generated to improve our
President and Chief Executive Officer
already strong balance sheet.
We remain very opportunistic about our 2015 projects.
We will be dedicating a lot of effort to identifying new
Joseph J. Romano
prospects, evaluating acquisition opportunities and
Chairman of the Board
* As of December 31, 2014, based on SEC pricing
D
B
C
A
427
Producing Onshore Wells
13/3
Company-Operated Wells and
Production Platforms
92% of production operated
100% of production operated
74% avg. working interest
61% avg. working interest
>200,000
Net Developed and
Undeveloped Acres
G
F
E
Houston
Headquarters
2
H
1
3
3
ROCKY MOUNTAINS
ONSHORE GULF COAST
GULF OF MEXICO
Total Proved Reserves*: 5 Bcfe
Percent Developed:*
44%
Percent Natural Gas*: 52%
2014 Production*:
<1 Bcfe
Total Proved Reserves: 126 Bcfe
Percent Developed:
Percent Natural Gas:
2014 Production:
50%
49%
16 Bcfe
Total Proved Reserves: 144 Bcfe
Percent Developed:
Percent Natural Gas:
2014 Production:
100%
80%
24 Bcfe
1 Eugene Island 11
(Dutch/Mary Rose)
Proved Reserves of 128 Bcfe
2 Vermilion 170
Proved Reserves of 14 Bcfe
3 Other
Proved Reserves of 2 Bcfe
A Colorado
Formation Target: Niobrara
Net Acres: 11,200
B FRAMS Project (New)
Wyoming
Formation Target: Mowry Shale
Right-to-Earn Net Acres: 69,900
C North Cheyenne Project (New)
Wyoming
Formation Target: Muddy Sandstone
Right-to-Earn Net Acres: 35,000
D Exaro Energy III
Wyoming
Formation Target: Jonah Field
37% Equity Investment
* Excludes our 37% equity interest in Exaro
E South Texas
Formation Targets: Buda, Eagle Ford,
Elm Hill Project, Conventional
Net Acres: 83,200
Proved Reserves: 55 Bcfe
F Southeast Texas
Formation Targets: Woodbine,
Eagle Ford, Conventional
Net Acres: 23,000
Proved Reserves of 64 Bcfe
G East Texas
Formation Targets: Haynesville,
Mid-Bossier, James Lime
Net Acres: 4,300
Proved Reserves of 7 Bcfe
H East Louisiana
Formation Target: Tuscaloosa
Marine Shale
Net Acres: 29,000
Proved Reserves of <1 Bcfe
68%
Increase in
Total Revenues
4
Fi na ncial
138%
Increase in Crude Oil
Production
43%
Increase in Natural Gas
Equivalent Production
PERFORMANCE
PROVED RESERVES (SEC PRICING)
Crude Oil (MBbls)
Natural Gas (Mmcf)
Natural Gas Liquids (MBbls)
Natural Gas Equivalent (Mmcfe)
2014
2013
2012
8,415
179,651
7,509
275,193
9,698
207,930
7,958
313,866
2,514
174,032
5,330
221,096
FUTURE NET REVENUE FROM PROVED RESERVES (SEC PRICING):
Undiscounted Before Income Taxes ($000)
Discounted at 10% After Income Taxes ($000)
$ 1,188,749
648,016
$
$ 1,441,658
771,443
$
$
$
857,644
388,012
PRODUCTION (NET SALES VOLUME)
Crude Oil (MBbls)
Natural Gas (Mmcf)
Natural Gas Liquids (MBbls)
Natural Gas Equivalent (Mmcfe)
AVERAGE PRICES FOR THE YEAR
Crude Oil ($/Bbl)
Natural Gas ($/Mcf)
Natural Gas Liquids ($/Bbl)
PRICES USED FOR YEAR-END RESERVES:
Crude Oil ($/Bbl)
Natural Gas ($/Mcf)
Natural Gas Liquids ($/Bbl)
TOTAL REVENUES ($000)
TOTAL EXPENSES ($000)
Lease Operating Expenses and Production Taxes
Exploration Expenses
DD&A and Impairment
G&A
Other Income (Expenses)
Income (Loss) from Continuing Operations Before Taxes
Income Tax (Expense) Benefit
Net Income (Loss) from Continuing Operations
NET INCOME (LOSS) FROM CONTINUING OPERATIONS PER SHARE
Basic
Diluted
WEIGHTED AVERAGE SHARES OUTSTANDING (000’S)
Basic
Diluted
1,401
25,875
1,008
40,323
92.98
4.36
33.27
92.89
4.38
33.45
276,458
(47,236)
(33,387)
(203,810)
(34,045)
4,236
(37,784)
15,910
(21,874)
(1.15)
(1.15)
19,059
19,059
$
$
$
$
$
$
$
$
$
$
589
20,624
677
28,220
101.21
3.84
37.26
106.80
3.73
35.92
164,121
(36,784)
(1,811)
(66,305)
(26,512)
31,792
64,501
(23,139)
41,362
2.56
2.56
16,156
16,158
$
$
$
$
$
$
$
$
$
$
507
21,570
660
28,752
110.92
2.79
43.85
114.24
2.85
58.39
145,868
(23,720)
(51,903)
(58,975)
(11,265)
(307)
(302)
(605)
(907)
(0.06)
(0.06)
15,295
15,295
$
$
$
$
$
$
$
$
$
$
TOTAL ASSETS ($000)
LONG-TERM DEBT, INCLUDING CURRENT PORTION ($000)
SHAREHOLDERS’ EQUITY ($000)
$
$
$
843,415
63,359
567,466
$
$
$
910,304
90,000
593,050
$
$
$
561,106
0
403,929
DisciplineD
Value
14
enhancement
2014 FORM 10-K
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
(cid:2)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
(cid:1)
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
For the fiscal year ended December 31, 2014
For the transition period from to
Commission file number 001-16317
CONTANGO OIL & GAS COMPANY
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
95-4079863
(IRS Employer Identification No.)
717 Texas Avenue, Suite 2900
Houston, Texas 77002
(Address of principal executive offices)
(713) 236-7400
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock, Par Value $0.04 per share
Securities registered pursuant to Section 12(g) of the Act: None
Name of exchange on which registered
NYSE MKT
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes (cid:2) No (cid:1)
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes (cid:1) No (cid:2)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject
to such filing requirements for the past 90 days. Yes (cid:2) No (cid:1)
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 (cid:2) No (cid:1)
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. (cid:2)
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
(Check one):
Large accelerated filer (cid:1)
Accelerated filer (cid:2)
Non-accelerated filer (cid:1)
Smaller reporting company (cid:1)
(Do not check if 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 (cid:1) No (cid:2)
At June 30, 2014, the aggregate market value of the registrant’s common stock held by non-affiliates (based upon the closing sale price of
shares of such common stock as reported on the NYSE MKT, was $618 million. As of February 27, 2015, there were 19,155,847 shares of the
registrant’s common stock outstanding.
Items 10, 11, 12, 13 and 14 of Part III have been omitted from this report since the registrant will file with the Securities and Exchange
Commission, not later than 120 days after the close of its fiscal year, a definitive proxy statement, pursuant to Regulation 14A. The information
required by Items 10, 11, 12, 13 and 14 of this report, which will appear in the definitive proxy statement, is incorporated by reference into this Form
10-K.
Documents Incorporated by Reference
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
ANNUAL REPORT ON FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2014
TABLE OF CONTENTS
Page
Item 1.
Business
PART I
Overview
Our Strategy
Properties
Onshore Investments
Outlook
Title to Properties
Marketing and Pricing
Competition
Governmental Regulations and Industry Matters
Risk and Insurance Program
Employees
Directors and Executive Officers
Corporate Offices
Code of Ethics
Available Information
Seasonal Nature of Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2.
Properties
Development, Exploration and Acquisition Expenditures
Property Dispositions
Drilling Activity
Exploration and Development Acreage
Production, Price and Cost History
Productive Wells
Natural Gas and Oil Reserves
PV-10
Proved Developed Reserves
Proved Undeveloped Reserves
Significant Properties
Item 3.
Item 4.
Legal Proceedings
Mine Safety Disclosures
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
PART II
General
Amended & Restated 2009 Incentive Compensation Plan
2005 Stock Incentive Plan
Share Repurchase Program
Stock Performance Graph
Selected Financial Data
Item 6.
ii
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47
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview
Results of Operations
Capital Resources and Liquidity
Contractual Obligations
Application of Critical Accounting Policies and Management’s Estimates
Recent Accounting Pronouncements
Off Balance Sheet Arrangements
Item 7A. Quantitative and Qualitative Disclosure about Market Risk
Financial Statements and Supplementary Data
Item 8.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
Certain Relationships and Related Transactions, and Director Independence
Principal Accountant Fees and Services
Item 15.
Exhibits and Financial Statement Schedules
PART IV
48
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61
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iii
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Certain statements contained in this report may contain “forward-looking statements” within the meaning of Section 27A of
the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934, as amended. The words and phrases “should be”,
“will be”, “believe”, “expect”, “anticipate”, “estimate”, “forecast”, “goal” and similar expressions identify forward -looking statements
and express our expectations about future events. Although we believe the expectations reflected in such forward-looking statements
are reasonable, such expectations may not occur. These forward-looking statements are made subject to certain risks and uncertainties
that could cause actual results to differ materially from those stated. Risks and uncertainties that could cause or contribute to such
differences include, without limitation, those discussed in the section entitled “Risk Factors” included in this report and those factors
summarized below:
•
•
our financial position;
our business strategy, including outsourcing;
• meeting our forecasts and budgets;
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
expectations regarding natural gas and oil markets in the United States;
natural gas and oil price volatility;
operational constraints, start-up delays and production shut-ins at both operated and non-operated production platforms,
pipelines and natural gas processing facilities;
the risks associated with acting as operator of deep high pressure and high temperature wells, including well blowouts
and explosions;
the risks associated with exploration, including cost overruns and the drilling of non-economic wells or dry holes,
especially in prospects in which we have made a large capital commitment relative to the size of our capitalization
structure;
the timing and successful drilling and completion of natural gas and oil wells;
availability of capital and the ability to repay indebtedness when due;
availability and cost of rigs and other materials and operating equipment;
timely and full receipt of sale proceeds from the sale of our production;
the ability to find, acquire, market, develop and produce new natural gas and oil properties;
interest rate volatility;
uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of
development expenditures;
operating hazards attendant to the natural gas and oil business including weather, environmental risks, accidental spills,
blowouts and pipeline ruptures, and other risks;
downhole drilling and completion risks that are generally not recoverable from third parties or insurance;
potential mechanical failure or under-performance of significant wells, production facilities, processing plants or pipeline
mishaps;
actions or inactions of third-party operators of our properties;
actions or inactions of third-party operators of pipelines or processing facilities;
the ability to find and retain skilled personnel;
strength and financial resources of competitors;
federal and state legislative and regulatory developments and approvals;
• worldwide economic conditions;
•
the ability to construct and operate infrastructure, including pipeline and production facilities;
iv
•
•
•
•
the continued compliance by us with various pipeline and gas processing plant specifications for the gas and condensate
produced by us;
operating costs, production rates and ultimate reserve recoveries of our natural gas and oil discoveries;
expanded rigorous monitoring and testing requirements; and
ability to obtain insurance coverage on commercially reasonable terms.
Any of these factors and other factors contained in this report could cause our actual results to differ materially from the
results implied by these or any other forward-looking statements made by us or on our behalf. Although we believe our estimates and
assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our
control. Our assumptions about future events may prove to be inaccurate. We caution you that the forward-looking statements
contained in this report are not guarantees of future performance, and we cannot assure you that those statements will be realized or
the forward-looking events and circumstances will occur. All forward-looking statements speak only as of the date of this report.
Reserve engineering is a process of estimating underground accumulations of oil, natural gas and natural gas liquids that
cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation
of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production
activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any
further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural
gas and natural gas liquids that are ultimately recovered.
All forward-looking statements, expressed or implied, in this report are expressly qualified in their entirety by this cautionary
statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking
statements that we or person acting on our behalf may issue.
We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or
otherwise, except as required by law. These cautionary statements qualify all forward-looking statements attributable to us or persons
acting on our behalf.
All references in this Form 10-K to the “Company”, “Contango”, “we”, “us” or “our” are to Contango Oil & Gas
Company and wholly-owned subsidiaries. Unless otherwise noted, all information in this Form 10-K relating to natural gas and oil
reserves and the estimated future net cash flows attributable to those reserves is based on estimates prepared by independent
engineers, and is net to our interest.
v
Item 1. Business
Overview
PART I
We are a Houston, Texas based independent energy company engaged in the acquisition, exploration, development,
exploitation and production of crude oil and natural gas properties offshore in the shallow waters of the Gulf of Mexico (“GOM”) and
in the onshore Texas Gulf Coast and Rocky Mountain regions of the United States.
On October 1, 2013, we completed a merger with Crimson Exploration Inc. (“Crimson”), in an all-stock transaction pursuant
to which Crimson became a wholly-owned subsidiary of Contango (the “Merger"). Accordingly, we issued approximately 3.9 million
shares of common stock in exchange for all of Crimson's outstanding capital stock, resulting in Crimson stockholders owning 20.3%
of the post-Merger Contango. The Company has its headquarters and principal corporate office in Houston, Texas.
On October 1, 2013, our Board of Directors approved a change in fiscal year end from June 30 to December 31. On March 3,
2014, we filed a Transition Report on Form 10-KT which covered the transition period of July 1, 2013 through December 31, 2013,
which included six months of Contango activity (July - December) and three months of post-Merger Crimson activity (October -
December). Also, on March 28, 2014 we filed an Annual Report on Form 10-K/A to present the financial statements of the Company
on a calendar year basis which included the twelve months ended December 31, 2013 and 2012. This Annual report on Form 10-K
presents our information for the twelve-month periods ended December 31, 2014, 2013 and 2012. Unless otherwise noted, all
references to "years" in this report refer to the twelve-month periods ended December 31 of each year.
We have historically focused our operations in the GOM, but our merger with Crimson has given us access to lower risk,
long life, onshore resource plays. In 2014, our drilling activity focused primarily on the Woodbine oil and liquids-rich play in Madison
and Grimes counties, Texas (our Southeast Texas Region), on the Buda Limestone oil and liquids-rich play in Zavala and Dimmit
counties, Texas (our South Texas Region), in the Cretaceous Sands in Fayette and Gonzales counties, Texas (also in our South Texas
Region) and the late 2014/early 2015 commencement of drilling in Wyoming where we are targeting the Mowry Shale and the Muddy
Sandstone formations. We believe these areas provide long-term growth potential from multiple formations that we believe to be
productive for oil and natural gas.
Additionally, we have (i) a 37% equity investment in Exaro Energy III LLC (“Exaro”) that is primarily focused on the
development of proved natural gas reserves in the Jonah Field in Wyoming; (ii) leasehold positions and minor non-operated producing
properties in Louisiana and Mississippi targeting the Tuscaloosa Marine Shale (“TMS”); (iii) operated properties producing from
various conventional formations in various counties along the Texas Gulf Coast; (iv) operated producing properties in the Denver
Julesburg Basin (“DJ Basin”) in Weld and Adams counties in Colorado, which we believe may also be prospective in the Niobrara
Shale oil play; (v) operated producing properties in the Haynesville Shale, Mid Bossier and James Lime formations in East Texas; and
(vi) six exploratory prospects in the shallow waters of the GOM.
Our production for the year ended December 31, 2014 was approximately 40.3 Bcfe (or 110.5 Mmcfed), was 61% from our
offshore properties and was 64% natural gas. Our production for the three months ended December 31, 2014 was approximately 9.8
Bcfe (or 106.2 Mmcfed), was 64% from our offshore properties and was 68% natural gas. As of December 31, 2014, our proved
reserves were approximately 76% proved developed, were 52% offshore, were 65% natural gas and were 96% attributed to wells and
properties operated by us.
As of December 31, 2014, our proved reserves, as estimated by Netherland, Sewell & Associates, Inc. (“NSAI”) and William
M. Cobb and Associates (“Cobb”), our independent petroleum engineering firms for our onshore and offshore properties, respectively,
in accordance with reserve reporting guidelines required by the Securities and Exchange Commission (“SEC”), were approximatel y
275.2 Bcfe, consisting of 179.7 Bcf of natural gas, 8.4 MMBbl of crude oil and condensate and 7.5 MMBbl of natural gas liquids
(“NGLs”), with a present value, discounted at a 10% rate (PV-10), of $796.9 million, and a Standardized Measure of Discounted
Future Net Cash Flows (“Standardized Measure”) of $648.0 million. PV-10 is a non-GAAP financial measure. A reconciliation of our
Standardized Measure to PV-10 is provided under Item 2. Properties - PV-10.
1
The following summary table sets forth certain information with respect to our proved reserves as of December 31, 2014
(excluding our reserves attributable to our investment in Exaro, as estimated by NSAI and Cobb) and our net average daily production
for the year ended December 31, 2014:
Region
Offshore GOM
Southeast Texas
South Texas
Other (1)
Total
Estimated Proved
Reserves (Bcfe)
% Crude Oil /
Condensate
% Natural
Gas
% Natural Gas
Liquids
% Proved
Developed
Average Daily
Production (Mmcfe/d)
143.8
63.8
54.8
12.8
275.2
5 %
43 %
23 %
31 %
80 %
36 %
60 %
63 %
15 %
21 %
17 %
6 %
100 %
40 %
53 %
33 %
67.1
25.9
14.5
3.0
110.5
(1) East Texas, Mississippi, Louisiana, and Colorado
Our Strategy
Recently, our strategy has been to grow reserves and production by developing our existing property base, by utilizing our
cash flow to drill selected high-potential Gulf of Mexico exploratory prospects, to exploit our lower-risk unproved oil and liquids
resource potential in our onshore resource plays, and to pursue new onshore resource play opportunities organically, or through
acquisition, that are complementary to our existing asset base. Due to the current low price environment, and the uncertainty for prices
for the immediate future, our 2015 strategy will be to limit drilling to that which is necessary to fulfill commitments, preserve core
acreage or test the geological viability of new plays or untested formations. Our priorities for 2015 will be to limit drilling until
commodity prices improve and/or service costs decline, to preserve our healthy balance sheet by limiting capital expenditures to a
level below cash flow, and to identify strategic opportunities for growth in this low price environment.
Specific key elements of our long-term business strategy have been:
•
•
•
Enhance our portfolio by dedicating the majority of our drilling capital to our oil and liquids-rich opportunities. Due to
the superior economics of oil production, as compared to natural gas, we have allocated the majority of our recent capital
budget to oil and liquids-weighted opportunities as we strive to transition from a heavily weighted natural gas production
profile to a more balanced reserve and production profile between oil/liquids and natural gas. Our long term strategy is to
continue to develop the oil and natural gas liquids resource potential that we believe exists in numerous formations
within our various oil/liquids weighted resource plays.
Pursue accretive, opportunistic acquisitions that meet our strategic and financial objectives. We intend to continue
evaluating opportunistic acquisitions of crude oil and natural gas properties, both undeveloped and developed, in areas
where we currently have a presence and/or specific operating expertise, and pursue sizable undeveloped acreage
positions, at reasonable cost, in new areas that we feel have significant exploration, exploitation or operational upside.
Selectively exploit, under a higher commodity price environment, our existing onshore producing conventional natural
gas property portfolio to generate additional cash flows. We believe our multi-year drilling inventory of exploitation
opportunities on our existing onshore conventional natural gas oriented producing properties provides us with a solid,
dependable platform for future reserve and production growth. We have 3D seismic data that covers substantially all of
our Liberty County acreage in Southeast Texas, giving us a higher degree of confidence in the potential in this area.
However, as a result of our desire to more extensively develop our resource plays, we do not expect to allocate
significant drilling capital to further develop these assets in 2015.
In 2014 specifically, we focused on our inventory of crude oil and liquids-rich projects with drilling programs in each of the
Woodbine play in Madison and Grimes counties, Texas, the Buda play in Dimmit County, Texas and initiated drilling in our newly
acquired acreage in the Fayette County, Texas, and Wyoming plays. We have developed a significant inventory of quality drilling
opportunities on our existing property base that we believe should provide multiyear reserve growth.
Our 2015 Strategy
As a result of the dramatic downturn in crude oil, natural gas and natural gas liquids prices in 2014 and early 2015, the
negative impact of those price declines on the economics of most domestic resource plays, and the continuing uncertainty as to when,
2
or how much, the commodity price environment might improve, our capital expenditure program for 2015 is expected to be focused
on: (i) the preservation of our strong and flexible financial position, including limiting our overall capital expenditure budget to no
more than internally generated cash flow; (ii) focusing drilling expenditures on strategic projects; (iii) identification of opportunities
for cost efficiencies in all areas of our operations; and (iv) continuing to identify and, when appropriate, pursue new resource potential
opportunities, internally and through acquisition. Our current capital budget for 2015 should allow us to meet our contractual
requirements, remain in position to preserve our term acreage where we deem appropriate and maintain our already strong financial
profile. We will continuously monitor the commodity price environment, stability and forecast, and if warranted, make adjustments to
our investment strategy as the year progresses.
We believe that a continuing low commodity price environment could put pressure on over-leveraged or under-funded oil
and natural gas exploration and production companies to consider asset sales or strategic combinations. Should a complementary and
accretive opportunity materialize, our strong financial profile, cash flow and liquidity should position us to capitalize on such an
opportunity. Accordingly, we plan to closely monitor the industry to identify and evaluate appropriate acquisition opportunities. Our
acquisition efforts will typically be focused on areas in which we can leverage our geographic and geological expertise, and where we
can develop an inventory of additional drilling prospects that we believe will enable us to grow production and add reserves.
Properties
Offshore Gulf of Mexico
As of December 31, 2014, our offshore production consisted of seven federal and six State of Louisiana Company-operated
wells in the shallow waters of the GOM. These 13 wells produce from four fields. The following summary table sets forth certain
information with respect to our offshore reserves as of December 31, 2014 and average daily production for the year ended
December 31, 2014:
Field
Dutch and Mary Rose
Vermilion 170
Other Offshore
Total
Estimated Proved
Reserves (Bcfe)
% Crude Oil /
Condensate
128.0
14.1
1.7
143.8
5 %
2 %
2 %
% Natural Gas
80 %
82 %
97 %
% Natural Gas
Liquids
% Proved
Developed
15 %
16 %
1 %
100 %
100 %
100 %
Average Daily
Production
(Mmcfe/d)
56.4
7.5
3.2
67.1
Dutch and Mary Rose Field
We operate five federal wells located at Eugene Island 10 (“Dutch”), and five state wells located in adjacent state of
Louisiana waters (“Mary Rose”). These ten wells produce to a Company-owned and operated production platform at Eugene Island
11. While we do not own the lease for the Eugene Island 11 block, this does not impact our ability to operate our facilities located on
that block. Operators in the GOM may place platforms and facilities on any location without having to own the lease, provided that
permission and proper permits from the Bureau of Safety and Environmental Enforcement (“BSEE”) have been obtained. We have
obtained such permission and permits. We installed our facilities at Eugene Island 11 because that was the optimal gathering location
in proximity to our wells and marketing pipelines.
From our production platform we are able to access two separate markets which minimizes downtime risk and provides the
ability for us to select the best sales price for our oil and natural gas production. Oil and natural gas production can flow via a TC
Offshore (formerly ANR) pipeline to third-party owned and operated onshore processing facilities near Patterson, Louisiana.
Alternatively, natural gas can flow to the American Midstream (Seacrest), LP pipeline via our 8” pipeline, which has been designed
with a capacity of 80 Mmcfd, and from there to a third-party owned and operated onshore processing facility at Burns Point,
Louisiana. Condensate can also flow via an ExxonMobil Pipeline Company pipeline to onshore markets and multiple refineries.
We installed a turbine type compressor of sufficient capacity, based on normal production decline rates, to ultimately service
all ten Dutch and Mary Rose wells at the Eugene Island 11 platform in July 2014. As of December 31, 2014, we had incurred
approximately $11.7 million to design, build and install the compressor. We started central compression at the platform during the
third quarter of 2014.
3
In December 2013, we exercised a preferential right and purchased an additional 7.84% working interest and 6.53% net
revenue interest in the five Company-operated Dutch wells from an independent oil and gas company for approximately $15 million,
net after customary purchase price adjustments.
Vermilion 170 Field
We operate one well at Vermilion 170 which flows to a Company-owned and operated production platform at the same
location. This platform services natural gas and condensate production, which flow via the Sea Robin Pipeline to a third-party owned
and operated onshore processing plants. Based on production and decline rates, we designed, built and installed a compressor in 2013
at a cost of approximately $1.4 million. We anticipate commencing compression in late 2015 or early 2016.
In January 2013, sustained casing pressure was identified between the production tubing and the production casing at our
Vermilion 170 well. Diagnostic tests revealed that the production tubing had parted downhole requiring a workover of the well. Well
production was shut-in in January, and the original tubing and casing were successfully removed. Operations were conducted to
replace the tubing and restore the well, which resumed production in June 2013. During December 2014, our Vermillion 170 well
production was shut-in for fourteen days due to issues with the Sea Robin Pipeline.
Other Offshore
Our Ship Shoal 263 and South Timbalier 17 fields have been included in “Other Offshore." We operate one well at Ship
Shoal 263, which produces to a Company-owned and operated production platform at the same location.
On April 29, 2014, we reached total depth on our Ship Shoal 255 prospect in the GOM, and no commercial hydrocarbons
were found. As a result, for the twelve months ended December 31, 2014, we recognized $31.5 million in exploration expense for the
cost of drilling the well plus $15.6 million in impairment expense associated with $3.5 million of leasehold costs and $12.1 million
related to a platform located in Block Ship Shoal 263 that was expected to be used by the Ship Shoal 255 well had it been successful.
On July 30, 2013, we spud our South Timbalier 17 prospect in state of Louisiana offshore waters, and on August 22, 2013 we
announced completion of a successful well at a total measured depth of approximately 11,400 feet. After we completed the well and
laid flowlines to a third-party owned facility, we commenced production in July 2014. Our net costs incurred to drill, complete and
bring this well on production were $15.9 million as of December 31, 2014. We have a 75% working interest (53.3% net revenue
interest) before payout, and a 59.3% working interest (42.1% net revenue interest) after payout. In December 2014, due to the low
price environment, the net book value of our South Timbalier 17 exceeded the future undiscounted cash flows associated with its
recoverable reserves, and we recognized an impairment expense of approximately $7.7 million during the year ended December 31,
2014.
During the year ended December 31, 2012, we spud our Ship Shoal 134 and South Timbalier 75 prospects, and no
commercial hydrocarbons were found. The Company has plugged and abandoned both wells. We incurred approximately $50.0
million to drill, plug and abandon these wells, including approximately $6.6 million in leasehold costs.
We currently hold six untested exploratory prospects on 15 offshore lease blocks. During the year ended December 31, 2014,
we recognized full impairment related to the prospects which we do not currently intend to drill. We will pursue opportunities to
realize future value from these leases through farmout, a sale or a possible trade for onshore opportunities.
Onshore Properties
Southeast Texas (Woodbine)
As of December 31, 2014, our Southeast Texas region included approximately 39,900 gross (23,000 net) acres, proven
reserves of 63.8 Bcfe, and 91 gross (50.7 net) producing wells. Crimson has been active in this area since 2008, primarily focusing on
conventional wells in the Yegua and Cook Mountain sands in Liberty County until 2012. In 2012, Crimson shifted its focus to the
horizontal development of the Woodbine formation in Madison and Grimes counties. During 2013, Crimson, and subsequently
Contango, drilled 12 gross (8.0 net) wells on acreage targeting the Woodbine formation. During 2014, we drilled 18 gross (11.6 net)
wells on acreage targeting the Woodbine formation. As of December 31, 2014, eight of these wells were producing, two were being
evaluated and eight were in various stages of drilling or completion.
4
For 2015, our current budget includes completing the six wells initiated in late 2014 utilizing a pad drilling strategy on 500
foot spacing in the Chalktown area. When drilling from pads, several wells are drilled in succession, then completed in succession,
and then put on production simultaneously to maximize recovery. Our 2015 budget also includes a single well in our Chalktown area
that satisfies a farm-in commitment and a horizontal test of the previously untested Lower Lewisville formation in our Grimes County
area. Should commodity prices improve and/or service costs decline meaningfully, we may increase our activity in this area. We
currently have approximately 16,100 net acres in Madison and Grimes counties (approximately 50% of which is held by production),
with a multi-year inventory of potential drilling locations, including the Woodbine, Eagle Ford Shale and Georgetown/Buda
formations. As of December 31, 2014, we had 28 gross wells (17.9 net) producing in the Woodbine formation, including 20 gross
wells (12.9 net) in the Force area, four gross wells (2.2 net) in the Iola/Grimes area and four gross wells (2.8 net) in the Chalktown
area.
On December 31, 2013, we sold to an independent oil and gas company approximately 7.1% of our interest in all developed
and undeveloped properties in Madison and Grimes Counties for approximately $20.4 million, or $91,007 per flowing barrel of
equivalent daily production and $47.32 per equivalent barrel of proved reserves.
South Texas (Buda/Eagle Ford)
As of December 31, 2014, our South Texas region included approximately 165,800 gross (83,200 net) acres, proven reserves
of 53.7 Bcfe, and 273 gross (143.4 net) producing wells. Of this, approximately 41,300 gross (21,400 net) acres are targeting the Buda
and Eagle Ford Shale plays, approximately 70% of which is held by production. Crimson began development of the Eagle Ford Shale
in Bee County in 2010 and in Karnes, Zavala and Dimmit counties in 2011. During 2013, Contango and Crimson drilled seven gross
wells (3.3 net) in the Buda formation in Zavala and Dimmit counties. Six of the wells were successful, while one was a mechanical
failure which was side tracked in 2014. During 2014, we drilled 14 gross wells (6.8 net) in the Buda formation in Zavala and Dimmit
counties, all of which are currently producing. We drilled one additional well in Zavala and Dimmit counties during the fourth quarter
of 2014 as a vertical pilot well to test the viability of the Eagle Ford and other formations in the area. We are evaluating the recovered
cores before deciding on a development strategy for these areas. Our current capital program does not contemplate further drilling in
Zavala and Dimmit counties in 2015 without improvement in the commodity price environment and/or service cost structure. Our
estimated net proven Buda/Eagle Ford reserves in this area were 15.4 Bcfe, comprised of 76% liquids, with 26 gross (13.3 net)
producing wells, as of December 31, 2014.
South Texas (Elm Hill Project)
As of December 31, 2014, we held approximately 55,900 gross acres (25,100 net) in Fayette, Gonzales, Caldwell and Bastrop
counties, Texas. We believe that the current acreage position, if the play is successful, could add up to 200 gross drilling locations to
our drilling inventory. During 2014, we drilled four gross wells (2.0 net) in this area, two of which commenced production during the
fourth quarter of 2014, with the other two expected to commence production in early 2015. We currently plan to drill one more well
during the first quarter of 2015 and then monitor area results before determining future plans for the area.
The remaining 68,600 gross (36,700 net) acres in our South Texas region are located in our conventional fields that produce
primarily from the Wilcox, Frio, and Vicksburg sands. Our estimated net proved conventional reserves in this region were 38.3 Bcfe,
comprised of 76% gas, with 245 gross (129.1 net) producing wells, as of December 31, 2014.
Natrona County, Wyoming (FRAMS Project)
In 2014, we acquired the right to earn approximately 119,300 gross acres (93,000 net acres with an 80% working interest) in
Natrona County, Wyoming. During the fourth quarter of 2014, we sold a 20% working interest in this prospect to an independent oil
and gas company, reducing our potential ownership to approximately 69,900 net acres with a 60% working interest. We spud our first
well in this play during the fourth quarter of 2014 targeting the Mowry Shale, and expect to complete that well late in the first quarter
or early second quarter of 2015. We will evaluate results from the first well for a number of months and determine future drilling plans
for this area.
5
Weston County, Wyoming (N. Cheyenne Project)
In 2014, we acquired the right to earn approximately 49,000 gross acres (44,000 net acres with a 90% to 100% working
interest) in Weston County, Wyoming. During the fourth quarter of 2014, we sold a 20% working interest in this prospect to an
independent oil and gas company, reducing our potential ownership to approximately 35,000 net acres with a 72% to 80% working
interest. We spud our first well in this play during the first quarter of 2015 targeting the Muddy Sandstone formation, and currently
plan to complete that well early in the second quarter of 2015. We will evaluate results from the first well for a number of months and
determine future drilling plans for this area. This acreage is approximately 125 miles to the northeast of our Natrona County acreage.
Other (East Texas)
As of December 31, 2014, our East Texas region included approximately 7,400 gross (4,300 net) acres primarily in San
Augustine County, with proven reserves of 8.3 Bcfe comprised of 65% gas, and ten gross (5.1 net) producing wells. Crimson actively
developed the dry gas Haynesville and Mid-Bossier Shales in this area in 2009 through 2011 during a more favorable natural gas price
environment. During 2014, we drilled two gross (1.2 net) wells targeting the shallower, liquids-rich James Lime formation on our
acreage in San Augustine County. We believe that the further exploitation of our acreage in the Haynesville, Mid-Bossier and James
Lime formations will provide long-term natural gas reserve and production growth potential in the future; however, we do not
anticipate devoting drilling capital to these formations until we see a sustained meaningful improvement in the natural gas price
environment. As of December 31, 2014, approximately 69% of our acreage in our East Texas region is held by production.
Other (Colorado)
We hold approximately 16,100 gross (11,200 net) acres in the DJ Basin in Colorado (mostly in Adams and Weld counties).
There has been sporadic activity since 2011 in the vicinity of our Colorado acreage in pursuit of the Niobrara Shale oil formation.
Recent industry activity in the area has established that the application of horizontal drilling technology for oil in the shallower
Niobrara Shale may provide attractive return possibilities; however, the prospect for full-scale economic development of this play is
still uncertain due to the limited activity in the area and the current commodity price environment. Substantially all of our acreage in
the DJ Basin is held by production. We plan to monitor the 2015 industry activity and results of our peers in the Niobrara Shale to
determine our future strategy for maximizing the value of our position in the area.
Other (Tuscaloosa Marine Shale “TMS”)
We own a 25% non-operated working interest in the Crosby 12H-1 well in Wilkinson County, Mississippi, and an average
non-operated working interest of less than 2.0% in three other wells in Mississippi, all targeting the TMS, an oil-focused shale play in
central Louisiana and Mississippi. The Crosby 12H-1well is operated by Goodrich Petroleum Company LLC ("Goodrich”).
In addition, as of December 31, 2014, we have approximately 40,800 gross (29,000 net) undeveloped acres under lease in the
TMS. To date, we have elected to participate in three non-operated wells (excluding the Crosby 12H-1 discussed above) where our
acreage has been pooled into units: (i) the Goodrich-operated CMR Foster Creek 20-7H #1 well, where we own less than a 1%
working interest; (ii) the Goodrich-operated Huff 18-7H #1 well, where we own approximately a 3% working interest; and (iii) the
Goodrich-operated CMR Foster Creek 24-13H #1 well, where we own less than a 2% working interest. Due to the poor economics we
have experienced in the area related to high drilling and completion costs and the current low oil price environment, we do not expect
to drill TMS wells in the near future. Given the low likelihood that we will devote any capital to this area prior to lease expirations in
2015 and 2016, we recognized impairment of certain unproved properties in the third and fourth quarters of 2014. We plan to continue
to evaluate participation in third-party operated wells with a small working interest as a means to obtain data from these wells to assist
us in evaluating, and maximizing value, from our TMS acreage.
Other
As of December 31, 2014, we held approximately 3,300 gross (620 net) acres in small non-operated working interests in the
Fenton field area of Calcasieu Parish, Louisiana and a minor operated crude oil property in Mississippi.
6
Onshore Investments
Kaybob Duvernay – Alberta, Canada
In 2011, we invested in Alta Resources Investments, LLC (“Alta”). On August 1, 2013, Alta sold its interest in the liquids-
rich Kaybob Duvernay Play in Alberta, Canada, where we had invested approximately $15.2 million, for approximately $30.5 million
net to us. Of this amount, we have received $28.5 million, and we expect to receive the remaining $2.0 million within the next twelve
months.
Jonah Field – Sublette County, Wyoming
In April 2012, we, through our wholly-owned subsidiary, Contaro Company (“Contaro”), entered into a Limited Liability
Company Agreement (as amended, the “LLC Agreement”) in connection with the formation of Exaro. Pursuant to the LLC
Agreement, we have committed to invest up to $67.5 million in cash in Exaro for a 37% ownership interest. As of December 31, 2014,
we had invested approximately $46.9 million in Exaro. We account for Contaro’s ownership in Exaro using the equity method of
accounting, and therefore, do not include its share of individual operating results, reserves or production in those reported for our
consolidated results.
As of December 31, 2014, Exaro had 625 wells on production over its 1,040 net acres, with a working interest between
14.4% and 32.5%. These wells were producing at a rate of approximately 41 Mmcfed, net to Exaro, plus an additional four wells that
are either in the completion or fracture stimulation phase. The operator expects to have two drilling rigs running on this project during
2015. For the year ended December 31, 2014, the Company recognized a net investment gain of approximately $6.9 million, net of tax
expense of $3.8 million, as a result of its investment in Exaro. As of December 31, 2014, reserves attributable to our investment in
Exaro were 70.2 Bcfe. We do not anticipate making any additional equity contributions during 2015 as Exaro estimates that drilling
capital will be funded through internally generated cash flow and borrowings under its revolving credit facility. See Note 11 to our
Financial Statements - “Investment in Exaro Energy III LLC” for additional details related to this investment.
Outlook
As a result of the dramatic downturn in crude oil, natural gas and natural gas liquids pricing in late 2014 and early in 2015,
the negative impact of those price declines on the economics of most domestic resource plays, and the continuing uncertainty as to
when, or how much, the price environment might improve, our capital expenditure program for 2015 will be focused on: (i) the
preservation of our strong and flexible financial position, including limiting our 2015 capital expenditure budget to no more than
internally generated cash flow; (ii) focusing drilling expenditures on strategic projects; (iii) identification of opportunities for cost
efficiencies in all areas of our operations; and (iv) continuing to identify new resource potential opportunities, internally and through
acquisition. Our current capital budget for 2015 should allow us to meet our contractual requirements, remain in position to preserve
our term acreage where appropriate and maintain our strong financial profile. We will continuously monitor the commodity price
environment, stability and forecast, and if warranted, make adjustments to that strategy as the year progresses. Our capital expenditure
budget is currently forecasted at approximately $50.6 million; a decrease of over 73% compared to our 2014 capital expenditures, and
is expected to be funded from internally generated cash flow. Primary drilling activity is currently planned as follows:
• Woodbine – We forecast capital expenditures of approximately $21.3 million in Madison and Grimes counties to complete six
gross wells (3.9 net) in our Chalktown area that we began drilling in 2014, and to drill an additional four gross wells (2.8 net).
South Texas - We forecast capital expenditures of approximately $5.5 million in Fayette and Gonzales counties to complete a
well that was in progress at year-end and to drill one additional gross well (0.5 net).
•
• Wyoming – We forecast capital expenditures of approximately $10.7 million to drill and complete two gross wells (1.4 net) in
Natrona and Weston counties, targeting the Mowry Shale and Muddy Sandstone Formation, respectively.
Title to Properties
From time to time, we are involved in legal proceedings relating to claims associated with ownership interests in our
properties. We believe we have satisfactory title to all of our producing properties in accordance with standards generally accepted in
the oil and gas industry. Our properties are subject to customary royalty interests, liens incident to operating agreements, and liens for
current taxes and other burdens, which we believe do not materially interfere with the use of or affect the value of such properties. As
7
is customary in the industry in the case of undeveloped properties, little investigation of record title is made at the time of acquisition
(other than a preliminary review of local records). Detailed investigations, including a title opinion rendered by a licensed independent
third party attorney, are typically made before commencement of drilling operations.
We have granted mortgage liens on substantially all of our natural gas and crude oil properties to secure our senior secured
revolving credit facility. These mortgages and the related credit agreement contain substantial restrictions and operating covenants that
are customarily found in credit agreements of this type. See Note 13 to our Financial Statements - “Long-Term Debt” for further
information.
Marketing and Pricing
We derive our revenue principally from the sale of natural gas and oil. As a result, our revenues are determined, to a large
degree, by prevailing natural gas and oil prices. We sell a portion of our natural gas production to purchasers pursuant to sales
agreements which contain a primary term of up to three years and crude oil and condensate production to purchasers under sales
agreements with primary terms of up to one year. The sales prices for natural gas are tied to industry standard published index prices,
subject to negotiated price adjustments, while the sale prices for crude oil are tied to industry standard posted prices subject to
negotiated price adjustments.
We typically utilize commodity price hedge instruments to minimize exposure to declining prices on our crude oil, natural
gas and natural gas liquids production, by using a series of swaps and costless collars. As of December 31, 2014, however, we had no
commodity price hedges in place. Unrealized gains or losses vary period to period, and will be a function of hedges in place, the strike
prices of those hedges and the forward curve pricing for the commodities and interest rates being hedged.
Price decreases would adversely affect our revenues, profits and the value of our proved reserves. Historically, the prices
received for natural gas and oil have fluctuated widely. Among the factors that can cause these fluctuations are:
•
The domestic and foreign supply of natural gas and oil.
• Overall economic conditions.
•
The level of consumer product demand.
• Adverse weather conditions and natural disasters.
•
•
•
The price and availability of competitive fuels such as heating oil and coal.
Political conditions in the Middle East and other natural gas and oil producing regions.
The level of LNG imports/exports.
• Domestic and foreign governmental regulations.
•
•
Special taxes on production.
The loss of tax credits and deductions.
Historically, we have been dependent upon a few purchasers for a significant portion of our revenue. Major purchasers of our
natural gas, oil and natural gas liquids for the year ended December 31, 2014, calculated on an equivalent basis, were ConocoPhillips
Company (31%), Sunoco Inc. (27%), Shell Trading US Company (10%), Exxon Mobil Oil Corporation (7%), and Enterprise Products
Operating LLC (5%). This concentration of purchasers may increase our overall exposure to credit risk, and our purchasers will likely
be similarly affected by changes in economic and industry conditions. Our financial condition and results of operations could be
materially adversely affected if one or more of our significant purchasers fails to pay us or ceases to acquire our production on terms
that are favorable to us. However, we believe our current purchasers could be replaced by other purchasers under contracts with
similar terms and conditions.
Competition
The oil and gas industry is highly competitive and we compete with numerous other companies. Our competitors in the
exploration, development, acquisition and production business include major integrated oil and gas companies as well as numerous
independent companies, including many that have significantly greater financial resources.
8
The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage
for our drilling and development operations, locating and acquiring attractive producing oil and gas properties, and obtaining
purchasers and transporters for the natural gas and crude oil we produce. There is also competition between producers of natural gas
and crude oil and other industries producing alternative energy and fuel. Furthermore, competitive conditions may be substantially
affected by various forms of energy legislation and/or regulation considered from time to time by federal, state and local governments;
however, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon
our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or
producing natural gas and crude oil and may prevent or delay the commencement or continuation of a given operation. The effect of
these risks cannot be accurately predicted.
Governmental Regulations and Industry Matters
Federal Income Tax
Federal income tax laws significantly affect our operations. The principal provisions affecting us are those that permit us,
subject to certain limitations, to deduct as incurred, rather than to capitalize and amortize, its domestic “intangible drill ing and
development costs” and to claim depletion on a portion of our domestic natural gas and oil properties and to claim a manufacturing
deduction based on qualified production activities.
Industry Regulations
The availability of a ready market for crude oil, natural gas and natural gas liquids production depends upon numerous
factors beyond our control. These factors include regulation of crude oil, natural gas, and natural gas liquids production, federal, state
and local regulations governing environmental quality and pollution control, state limits on allowable rates of production by well or
proration unit, the amount of crude oil, natural gas and natural gas liquids available for sale, the availability of adequate pipeline and
other transportation and processing facilities, and the marketing of competitive fuels. For example, a productive natural gas well may
be “shut-in” because of an oversupply of natural gas or lack of an available natural gas pipeline in the area in which the well is
located. State and federal regulations generally are intended to prevent waste of crude oil, natural gas, and natural gas liquids, protect
rights to produce crude oil, natural gas and natural gas liquids between owners in a common reservoir, control the amount of crude oil,
natural gas and natural gas liquids produced by assigning allowable rates of production, and protect the environment. Pipelines are
subject to the jurisdiction of various federal, state and local agencies. We are also subject to changing and extensive tax laws, the
effects of which cannot be predicted.
The following discussion summarizes the regulation of the U.S. oil and gas industry. We believe that we are in substantial
compliance with the various statutes, rules, regulations and governmental orders to which our operations may be subject, although
there can be no assurance that this is or will remain the case. Moreover, such statutes, rules, regulations and government orders may be
changed or reinterpreted from time to time in response to economic or political conditions, and there can be no assurance that such
changes or reinterpretations will not materially adversely affect our results of operations and financial condition. The following
discussion is not intended to constitute a complete discussion of the various statutes, rules, regulations and governmental orders to
which our operations may be subject.
Regulation of Crude Oil, Natural Gas and Natural Gas Liquids Exploration and Production
Our operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes
requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the
location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled,
the plugging and abandoning of wells and the disposal of fluids used in connection with operations. Our operations are also subject to
various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and
the density of wells that may be drilled in and the unitization or pooling of crude oil and natural gas properties. In this regard, some
states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on
voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units, and therefore more
difficult to develop a project, if the operator owns less than 100% of the leasehold. In addition, state conservation laws, which
establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas and
impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of crude oil,
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natural gas and natural gas liquids we can produce from our wells and may limit the number of wells or the locations at which we can
drill. The regulatory burden on the oil and gas industry increases our costs of doing business and, consequently, affects our
profitability. Inasmuch as such laws and regulations are frequently expanded, amended and interpreted, we are unable to predict the
future cost or impact of complying with such regulations.
Regulation of Sales and Transportation of Natural Gas
Federal legislation and regulatory controls have historically affected the price of natural gas produced by us, and the manner
in which such production is transported and marketed. Under the Natural Gas Act of 1938 (the “NGA”), the Federal Energy
Regulatory Commission (the “FERC”) regulates the interstate transportation and the sale in interstate commerce for resale of natural
gas. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act (the “Decontrol Act”) deregulated natural gas prices for all
“first sales” of natural gas, including all sales by us of our own production. As a result, all of our domestically produced natural gas
may now be sold at market prices, subject to the terms of any private contracts that may be in effect. However, the Decontrol Act did
not affect the FERC’s jurisdiction over natural gas transportation.
Under the provisions of the Energy Policy Act of 2005 (the “2005 Act”), the NGA has been amended to prohibit market
manipulation by any person, including marketers, in connection with the purchase or sale of natural gas, and the FERC has issued
regulations to implement this prohibition. The Commodity Futures Trading Commission (the “CFTC”) also holds authority to monitor
certain segments of the physical and futures energy commodities market including oil and natural gas. With regard to physical
purchases and sales of natural gas and other energy commodities, and any related hedging activities that we undertake, we are thus
required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC. These agencies hold
substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation.
Under the 2005 Act, the FERC has also established regulations that are intended to increase natural gas pricing transparency
through, among other things, new reporting requirements and expanded dissemination of information about the availability and prices
of gas sold. For example, on December 26, 2007, FERC issued a final rule on the annual natural gas transaction reporting
requirements, as amended by subsequent orders on rehearing, or Order No. 704. Order No. 704 requires buyers and sellers of natural
gas above a de minimis level, including entities not otherwise subject to FERC jurisdiction, to submit on May 1 of each year an annual
report to FERC describing their aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the
extent such transactions utilize, contribute to or may contribute to the formation of price indices. Order No. 704 also requires market
participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s
policy statement on price reporting. It is the responsibility of the reporting entity to determine which individual transactions should be
reported based on the guidance of Order No. 704 as clarified in orders on clarification and rehearing. In addition, to the extent that we
enter into transportation contracts with interstate pipelines that are subject to FERC regulation, we are subject to FERC requirements
related to use of such interstate capacity. Any failure on our part to comply with the FERC’s regulations could result in the imposition
of civil and criminal penalties.
Our natural gas sales are affected by intrastate and interstate gas transportation regulation. Following the Congressional
passage of the Natural Gas Policy Act of 1978 (the “NGPA”), the FERC adopted a series of regulatory changes that have significantly
altered the transportation and marketing of natural gas. Beginning with the adoption of Order No. 436, issued in October 1985, the
FERC has implemented a series of major restructuring orders that have required interstate pipelines, among other things, to perform
“open access” transportation of gas for others, “unbundle” their sales and transportation functions, and allow shippers to release their
unneeded capacity temporarily and permanently to other shippers. As a result of these changes, sellers and buyers of gas have gained
direct access to the particular interstate pipeline services they need and are better able to conduct business with a larger number of
counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially
increasing competition in the natural gas marketplace. It remains to be seen, however, what effect the FERC’s other activitie s will
have on access to markets, the fostering of competition and the cost of doing business. We cannot predict what new or different
regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. We
do not believe that we will be affected by any such new or different regulations materially differently than any other seller of natural
gas with which we compete.
In the past, Congress has been very active in the area of gas regulation. However, as discussed above, the more recent trend
has been in favor of deregulation, or “lighter handed” regulation, and the promotion of competition in the gas industry. There regularly
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are other legislative proposals pending in the federal and state legislatures that, if enacted, would significantly affect the petroleum
industry. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various
state legislatures and what effect, if any, such proposals might have on us. Similarly, and despite the trend toward federal deregulation
of the natural gas industry, we cannot predict whether or to what extent that trend will continue, or what the ultimate effect will be on
our sales of gas. Again, we do not believe that we will be affected by any such new legislative proposals materially differently than
any other seller of natural gas with which we compete.
Oil Price Controls and Transportation Rates
Sales prices of crude oil, condensate and gas liquids by us are not currently regulated and are made at market prices. Our
sales of these commodities are, however, subject to laws and to regulations issued by the Federal Trade Commission (the “FTC”)
prohibiting manipulative or fraudulent conduct in the wholesale petroleum market. The FTC holds substantial enforcement authority
under these regulations, including the ability to assess civil penalties of up to $1 million per day per violation. Our sales of these
commodities, and any related hedging activities, are also subject to CFTC oversight as discussed above.
The price we receive from the sale of these products may be affected by the cost of transporting the products to market. Much
of the transportation is through interstate common carrier pipelines. Effective as of January 1, 1995, the FERC implemented
regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for
those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. The
FERC’s regulation of crude oil and natural gas liquids transportation rates may tend to increase the cost of transporting crude oil and
natural gas liquids by interstate pipelines, although the annual adjustments may result in decreased rates in a given year. Every five
years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes
experienced in the oil pipeline industry. We are not able at this time to predict the effects of these regulations or FERC proceedings, if
any, on the transportation costs associated with crude oil production from our crude oil producing operations.
Environmental and Occupational Health and Safety Matters
Our crude oil and natural gas exploration, development and production operations are subject to stringent federal, regional,
state and local laws and regulations governing occupational health and safety aspects of our operations, the discharge of materials into
the environment, or otherwise relating to environmental protection. Numerous governmental authorities, including the U.S.
Environmental Protection Agency (the “EPA”) and analogous state agencies, have the power to enforce compliance with these laws
and regulations and the permits issued under them, often requiring difficult and costly actions. These laws and regulations may require
the acquisition of a permit to conduct drilling and other regulated activities, restrict the types, quantities and concentration of various
substances that may be released into the environment in connection with drilling and production activities, limit or prohibit drilling
activities on certain lands within wilderness, wetlands and other protected areas, require remedial measures to mitigate pollution from
current or former operations; impose specific health and safety criteria addressing worker protection; and impose substantial liabilities
for pollution resulting from production and drilling operations. Failure to comply with these laws and regulations may result in the
assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of orders enjoining
some or all of our operations in affected areas. Public interest in the protection of the environment has increased dramatically in recent
years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas
industry could continue in the future, resulting in increased costs of doing business and consequently affecting profitability. To the
extent laws are enacted or other governmental actions are taken that result in more stringent and costly well drilling, construction,
completion, water management activities, waste handling, storage, transport, disposal or remediation requirements, our business and
prospects could be materially and adversely affected.
Our domestic natural gas and oil operations, including those involving federal and state leases in the U.S. Gulf of Mexico, are
subject to extensive federal and state regulation and imposition of environmental liabilities or possible interruption or termination of
leasing activities by governmental authorities. The Comprehensive Environmental Response, Compensation and Liability Act, as
amended, (“CERCLA”), also known as the “Superfund Law”, and similar state laws, impose liability, without regard to fault or the
legality of the original conduct, on certain classes of potentially responsible persons that are considered to have contributed to the
release of a “hazardous substance” into the environment. These potentially responsible persons include the current or past owner or
operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the
hazardous substances released at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA
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may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the
environment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances
released into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.
We also generate wastes that are subject to the federal Resource Conservation and Recovery Act, as amended (the “RCRA”),
and comparable state statutes. The RCRA imposes strict requirements on the generation, storage, treatment, transportation and
disposal of nonhazardous and hazardous wastes, and the EPA and analogous state agencies stringently enforce the approved methods
of management and disposal of these wastes. While the RCRA currently exempts certain drilling fluids, produced waters, and other
wastes associated with exploration, development and production of crude oil and natural gas from regulation as hazardous wastes, we
can provide no assurance that this exemption will be preserved in the future. Repeal or modification of this exclusion or similar
exemptions under federal or state law could increase the amount of waste we are required to manage and dispose of as hazardous
waste rather than non-hazardous waste, and could cause us to incur increased operating costs, which could have a significant impact
on us as well as the natural gas and oil industry in general. In any event, these excluded wastes are subject to regulation as
nonhazardous wastes.
We currently own, lease or operate numerous properties that for many years have been used for the exploration and
production of crude oil and natural gas. Although we believe that we have used good operating and waste disposal practices that were
standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the
properties owned or leased by us or on or under locations where such wastes have been taken for recycling or disposal. In addition,
many of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons or
wastes was not under our control. These properties and the petroleum hydrocarbons or wastes disposed thereon may be subject to the
CERCLA, RCRA and analogous state laws as well as state laws governing the management of crude oil and natural gas wastes. Under
such laws, which may impose strict, joint and several liability, we could be required to remove or remediate previously disposed
wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater
contamination) or to perform remedial plugging operations to prevent future contamination.
The Clean Air Act, as amended (the “CAA”), and comparable state laws and regulations restrict the emission of air pollutants
from many sources and also impose various monitoring and reporting requirements. These laws and regulations may require us to
obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase
air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control
emissions. Obtaining permits has the potential to delay the development of crude oil and natural gas projects. Over the next several
years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related
issues. For example, in December 2014, the EPA published a proposed rulemaking that it expects to finalize by October 1, 2015,
which rulemaking proposes to revise the National Ambient Air Quality Standard for ozone between 65 to 70 parts per billion (“ppb”)
for both the 8-hour primary and secondary standards. Compliance with this or other regulatory initiatives could directly impact us by
requiring installation of new emission controls on some of our equipment, resulting in longer permitting timelines and significantly
increasing our capital expenditures and operation costs, which could adversely impact our business.
Based on findings made by the EPA that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present
an endangerment to public health and the environment, the EPA adopted regulations under existing provisions of the CAA that,
among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit revie ws for
GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant
emissions. Facilities required to obtain PSD permits for their GHG emissions will also be required to meet “best available control
technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA
rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources,
should such sources exceed threshold emission levels. In addition, the EPA has adopted rules requiring the monitoring and reporting
of GHG emissions from specified sources in the United States on an annual basis, which include the majority of our operations. We
are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our
monitoring activities are in substantial compliance with applicable reporting obligations.
While Congress has, from time to time considered legislation to reduce emissions of GHGs, there has not been significant
activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal
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climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by
means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances
in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be
adopted to address GHG emissions would impact our business, any such future federal laws or regulations that impose reporting
obligations on us with respect to, or require the elimination of GHG emissions from, our equipment or operations could require us to
incur increased operating costs and could adversely affect demand for the oil and natural gas we produce. For example, on January 14,
2015, the Obama Administration announced that the EPA is expected to propose in the summer of 2015 and finalize in 2016 new
regulations that will set methane emission standards for new and modified oil and gas production and natural gas processing and
transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45
percent from 2012 levels by 2025. Finally, it should be noted that some scientists have concluded that increasing concentrations of
greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased
frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an
adverse effect on our assets and operations.
The Federal Water Pollution Control Act, as amended (the “Clean Water Act”) and analogous state laws impose restrictions
and strict controls regarding the discharge of pollutants into state waters and waters of the United States. Any such discharge of
pollutants into regulated waters is prohibited except in accordance with the terms of a permit issued by the EPA or the analogous state
agency. 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. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for
discharges of storm water runoff from certain types of facilities. The Clean Water Act also prohibits the discharge of dredge and fill
material in regulated waters, including wetlands, unless authorized by permit. Federal and state regulatory agencies can impose
administrative, civil and criminal penalties for noncompliance with discharge permits or other requirements of the Clean Water Act
and analogous state laws and regulations.
Our oil and natural gas exploration and production operations generate produced water, drilling muds, and other waste
streams, some of which may be disposed via injection in underground wells situated in non-producing subsurface formations. The
disposal of oil and natural gas wastes into underground injection wells are subject to the Safe Drinking Water Act, as amended, or
SDWA, and analogous state laws. The Underground Injection Well Program under the SDWA requires that we obtain permits from
the EPA or analogous state agencies for our disposal wells, establishes minimum standards for injection well operations, restricts the
types and quantities that may be injected, and prohibits the migration of fluid containing any contaminants into underground sources
of drinking water. Any leakage from the subsurface portions of the injection wells may cause degradation of freshwater, potentially
resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of
expenditures for remediation of the affected resource, and imposition of liability by third parties for alternative water supplies,
property damages and personal injuries. While we believe that we have obtained the necessary permits from the applicable regulatory
agencies for our underground injection wells and that we are in substantial compliance with applicable permit conditions and federal
and state rules, a change in disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect
our ability to dispose of salt water and ultimately increase the cost of our operations. For example, there exists a growing concern that
the injection of saltwater and other fluids into belowground disposal wells triggers seismic activity in certain areas, including Texas,
where we operate. In response to these concerns, in October 2014, the Texas Railroad Commission (“TRC”) published a final rule
governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on
seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure
maps relating to the disposal area in question. If the permittee or an applicant of a disposal well fails to demonstrate that the injected
fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be
contributing to seismic activity, then the TRC may deny, modify, suspend or terminate the permit application or existing operating
permit for that well. These new seismic permitting requirements applicable to disposal wells impose more stringent permitting
requirements and likely to result in added costs to comply or, perhaps, may require alternative methods of disposing of salt water and
other fluids, which could delay production schedules and also result in increased costs..
The Oil Pollution Act of 1990 (the “OPA”) and regulations thereunder impose a variety of regulations on “responsible
parties” related to the prevention of oil spills and liability for damages resulting from such spills in U.S. waters. The OPA applies to
vessels, onshore facilities, and offshore facilities, including exploration and production facilities that may affect waters of the United
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States. Under OPA, responsible parties including owners and operators of onshore facilities and lessees and permittees of offshore
leases may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages
that may result from oil spills. In December 2014, the Bureau of Ocean Energy Management (the “BOEM”) issued a final rule,
effective January 12, 2015, which raises OPA’s damages liability cap from $75 million to $133.65 million. While liability limits apply
in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful
misconduct or resulted from violation of federal safety, construction or operating regulations. Few defenses exist to the liability
imposed by the OPA. In addition, to the extent the Company’s offshore lease operations affect state waters, the Company may b e
subject to additional state and local clean-up requirements or incur liability under state and local laws. The OPA also imposes ongoing
requirements on responsible parties, including preparation of oil spill response plans for responding to a worst-case discharge of oil
into waters of the U.S., and proof of financial responsibility to cover at least some costs in a potential spill. The Company believes that
it currently has established adequate proof of financial responsibility in the form of a Certificate of Financial Responsibility ("COFR")
for its offshore facilities. However, the Company cannot predict whether significantly higher COFR amounts under any future OPA
amendments will result in the imposition of substantial additional annual costs to the Company in the future or otherwise materially
adversely affect the Company. The impact, however, should not be any more adverse to the Company than it will be to other similarly
situated or less capitalized owners or operators in the Gulf of Mexico.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or crude oil
from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemical additives
under pressure into targeted subsurface formations to stimulate production. We routinely use hydraulic fracturing techniques in many
of our completion programs. Hydraulic fracturing typically is regulated by state oil and gas commissions, or other similar state
agencies, but several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has
issued final Clean Air Act regulations governing performance standards, including standards for the capture of air emissions released
during hydraulic fracturing; announced its intent to propose in the first half of 2015 effluent limit guidelines that wastewater from
shale gas extraction operations must meet before discharging to a treatment plant; and issued in May 2014 a prepublication of its
Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures
used in hydraulic fracturing. Also, the federal Bureau of Land Management (“BLM”) issued a revised proposed rule containing
disclosure requirements and other mandates for hydraulic fracturing on federal lands and the agency is now analyzing comments to the
proposed rulemaking and is expected to promulgate a final rule in the first half of 2015.
In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing
and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states, including Texas,
where we operate, have adopted, and other states are considering adopting legal requirements that could impose more stringent
permitting, public disclosure, or well construction requirements on hydraulic fracturing activities. States could elect to prohibit
hydraulic fracturing altogether, such as the State of New York announced in December 2014. Local government may also seek to
adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing
activities in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater
protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating
to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply
with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and
perhaps even be precluded from drilling or completing wells.
In addition, certain governmental reviews are underway that focus on environmental aspects of hydraulic fracturing practices.
The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices.
The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater,
with a draft report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be
available for public comment and peer review the first half of 2015. These ongoing or any future studies, depending on their degree of
pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing.
To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our hydraulic
fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to
hydraulic fracturing operations; however, we believe our general liability and excess liability insurance policies would cover third-
party pollution claims in accordance with, and subject to the terms of such policies.
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Oil and natural gas exploration, development and production activities on federal lands, including Indian lands and lands
administered by the BLM, are subject to the National Environmental Policy Act, as amended (“NEPA”). NEPA requires federal
agencies, including the BLM, 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. Currently, we have minimal exploration and production activities on federal lands.
However, for those current activities as well as for future or proposed exploration and development plans on federal lands,
governmental permits or authorizations that are subject to the requirements of NEPA are required. This process has the potential to
delay, limit or increase the cost of developing oil and natural gas projects. Authorizations under NEPA are also subject to protest,
appeal or litigation, any or all of which may delay or halt projects.
Environmental laws such as the Endangered Species Act, as amended (“ESA”), may impact exploration, development and
production activities on public or private lands. The ESA provides broad protection for species of fish, wildlife and plants that are
listed as threatened or endangered in the United States, and prohibits taking of endangered species. Similar protections are offered to
migratory birds under the Migratory Bird Treaty Act. Federal agencies are required to ensure that any action authorized, funded or
carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of
our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in
substantial compliance with the ESA. If endangered species are located in areas of the underlying properties where we wish to conduct
seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed or expensive mitigation
may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September
2011, the U.S. Fish and Wildlife Service (the “FWS”) is required to make a determination on listing of numerous species as
endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. For example, in March 2014,
the FWS announced the listing of the lesser prairie chicken, whose habitat is over a five-state region, including Texas, where we
conduct operations, as a threatened species under the ESA. However, the FWS also announced a final rule that will limit regulatory
impacts on landowners and businesses from the listing if those landowners and businesses have entered into certain range-wide
conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies, pursuant to
which such parties agreed to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee if its ac tions harm the
lesser prairie chicken’s habitat. The designation of previously unprotected species as threatened or endangered in areas where
underlying property operations are conducted could cause us to incur increased costs arising from species protection measures, time
delays or limitations on our drilling program activities, which costs delays or limitation could have an adverse impact on our ability to
develop and produce reserves.
We are subject to the requirements of the federal Occupational Safety and Health Act, as amended (“OSHA”), and
comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication
standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act
and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our
operations and that this information be provided to employees, state and local government authorities and citizens. We believe that we
are in substantial compliance with all applicable laws and regulations relating to worker health and safety.
In response to the Deepwater Horizon drilling rig explosive incident and resulting oil spill in the United States Gulf of
Mexico in 2010, the BOEM and the Bureau of Safety and Environmental Enforcement (the “BSEE”), each agencies of the U.S.
Department of the Interior, have imposed new and more stringent permitting procedures and regulatory safety and performance
requirements for new wells to be drilled in federal waters. These governmental agencies have implemented and enforced new rules,
Notices to Lessees and Operators and temporary drilling moratoria that imposed safety and operational performance measures on
exploration, development and production operators in the Gulf of Mexico or otherwise resulted in a temporary cessation of drilling
activities. In addition, states may adopt and implement similar or more stringent legal requirements applicable to exploration and
production activities in state waters. Compliance with these added and more stringent regulatory restrictions, in addition to any
uncertainties or inconsistencies in current decisions and rulings by governmental agencies and delays in the processing and approval
of drilling permits and exploration, development and oil spill-response plans could adversely affect or delay new drilling and ongoing
development efforts, which could have a material adverse impact on our business. Moreover, these governmental agencies are
continuing to evaluate aspects of safety and operational performance in the Gulf of Mexico and, as a result, developing and
implementing new, more restrictive requirements. One example is the 2013 amendments to the federal Workplace Safety Rule
15
regarding the utilization of a more comprehensive safety and environmental management system (“SEMS”), which amended rule is
sometimes referred to as SEMS II. A second, and more recent, example is the August 2014 Advanced Notice of Proposed
Rulemaking that ultimately seeks to bolster the offshore financial assurance and bonding program. Among other adverse impacts,
these additional measures could delay or disrupt our operations, increase the risk of expired leases due to the time required to develop
new technology, result in increased supplemental bonding requirements and incurrence of associated added costs, limit operational
activities in certain areas, or cause us to incur penalties, fines, or shut-in production. If material spill incidents similar to the
Deepwater Horizon incident were to occur in the future, the United States could elect to again issue directives to temporarily cease
drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding
offshore oil and natural gas exploration and development, any of which developments could have a material adverse effect on our
business.
Other Laws and Regulations
Various laws and regulations often require permits for drilling wells and also cover spacing of wells, the prevention of waste
of natural gas and oil including maintenance of certain gas/oil ratios, rates of production and other matters. The effect of these laws
and regulations, as well as other regulations that could be promulgated by the jurisdictions in which the Company has production,
could be to limit the number of wells that could be drilled on the Company’s properties and to limit the allowable production from the
successful wells completed on the Company’s properties, thereby limiting the Company’s revenues.
The BOEM administers the natural gas and oil leases held by the Company on federal onshore lands and offshore tracts in the
Outer Continental Shelf. The BOEM holds a royalty interest in these federal leases on behalf of the federal government. While the
royalty interest percentage is fixed at the time that the lease is entered into, from time to time the BOEM changes or reinterprets the
applicable regulations governing its royalty interests, and such action can indirectly affect the actual royalty obligation that the
Company is required to pay. However, the Company believes that the regulations generally do not impact the Company to any greater
extent than other similarly situated producers. At the end of lease operations, oil and gas lessees must plug and abandon wells, remove
platforms and other facilities, and clear the lease site sea floor. The BOEM requires companies operating on the Outer Continental
Shelf to obtain surety bonds to ensure performance of these obligations. As an operator, the Company is required to obtain surety
bonds of $200,000 per lease for exploration and $500,000 per lease for developmental activities. However, in August 2014, BOEM
published an Advance Notice of Proposed Rulemaking, pursuant to which it seeks to bolster its current bonding requirements for
offshore oil and gas operations.
Risk and Insurance Program
In accordance with industry practice, we maintain insurance against many, but not all, potential perils confronting our
operations and in coverage amounts and deductible levels that we believe to be economic. Consistent with that profile, our insurance
program is structured to provide us financial protection from significant losses resulting from damages to, or the loss of, physical
assets or loss of human life, and liability claims of third parties, including such occurrences as well blowouts and weather events that
result in oil spills and damage to our wells and/or platforms. Our goal is to balance the cost of insurance with our assessment of the
potential risk of an adverse event. We maintain insurance at levels that we believe are appropriate and consistent with industry
practice and we regularly review our risks of loss and the cost and availability of insurance and revise our insurance program
accordingly.
We continuously monitor regulatory changes and regulatory responses and their impact on the insurance market and our
overall risk profile, and adjust our risk and insurance program to provide protection at a level that we can afford considering the cost
of insurance, against the potential and magnitude of disruption to our operations and cash flows. Changes in laws and regulations
regarding exploration and production activities in the Gulf of Mexico could lead to tighter underwriting standards, limitations on
scope and amount of coverage, and higher premiums, including possible increases in liability caps for claims of damages from oil
spills.
We maintain significant insurance coverage attributable to our net share of any potential financial losses occurring as a result
of potential perils, including well control coverage of $75 million, which covers control of well, pollution cleanup and consequential
damages. We also maintain $150 million of general liability coverage, which covers pollution cleanup, consequential damages
16
coverage, and third party personal injury and death, and $35 million of Oil Spill Financial Responsibility coverage, which covers
additional pollution cleanup and third party claims coverage.
Health, Safety and Environmental Program
Our Health, Safety and Environmental (“HS&E”) Program is supervised by an operating committee of senior management to
insure compliance with all state and federal regulations. In support of the operating committee, we have contracted with J. Connor
Consulting (“JCC”) to coordinate the regulatory process relative to our offshore assets. JCC is a regulatory consulting firm
specializing in the offshore Gulf of Mexico. They provide preparation of incident response plans, safety and environmental services
and facilitation of comprehensive oil spill response training and drills on behalf of oil and gas companies and pipeline operators.
Additionally, in support of our Gulf of Mexico operations, we have established a Regional Oil Spill Plan which has been
approved by the BOEM. Our response team is trained annually and is tested through in-house spill drills. We have also contracted
with O’Brien’s Response Management (“O’Brien’s”), who maintains an incident command center on 24 hour alert in Slidell, LA. In
the event of an oil spill, the Company’s response program is initiated by notifying O’Brien’s any incident while the Company
response team is mobilized to focus on source control and containment of the spill. O’Brien’s would coordinate communications with
state and federal agencies and would provide subject matter expertise in support of the response team.
We have also contracted with Clean Gulf Associates (“CGA”) to assist with equipment and personnel needs in the event of a
spill. CGA specializes in onsite control and cleanup and is on 24 hour alert with equipment currently stored at six bases along the gulf
coast (Ingleside and Galveston, TX; Lake Charles, Houma, and Venice, LA; and Pascagoula, MS). CGA is opening new sites in
Leeville, Morgan City and Harvey, LA. The CGA equipment stockpile is available to serve member oil spill response needs and
includes open seas skimmers, and shoreline protection boom, communications equipment, dispersants with application systems,
wildlife rehabilitation and a forward command center. CGA has retainers with aerial dispersant and mechanical recovery equipment
contractors for spill response.
In addition to our membership in CGA, the Company has contracted with Wild Well Control for source control at the
wellhead, if required. Wild Well Control is one of the world’s leading providers of firefighting and well control services.
We also have a full time health, safety and environmental professional who supports our operations and oversees the
implementation of our onshore HS&E policies.
Safety and Environmental Management System
We have developed and implemented a Safety and Environmental Management System (“SEMS”) to address oil and gas
operations in the Outer Continental Shelf (“OCS”), as required by the BSEE. Our SEMS identifies and mitigates safety and
environmental hazards and the impacts of these hazards on design, construction, start-up, operation, inspection, and maintenance of all
new and existing facilities. The Company has established goals, performance measures, training and accountability for SEMS
implementation. We also provide the necessary resources to maintain an effective SEMS and we review the adequacy and
effectiveness of the SEMS program annually. Company facilities are designed, constructed, maintained, monitored, and operated in a
manner compatible with industry codes, consensus standards, and all applicable governmental regulations. We have contracted with
Island Technologies Inc. to coordinate our SEMS program and to track compliance for production operations.
The BSEE enforces the SEMS requirements through regular audits. Failure of an audit may result in an Incident of Non-
Compliance and could ultimately require a shut-in our Gulf of Mexico operations if not resolved within the required time.
Employees
On December 31, 2014, we had 92 full time employees, of which 23 were field personnel. We have been able to attract and
retain a talented team of industry professionals that have been successful in achieving significant growth and success in the past. As
such, we are well-positioned to adequately manage and develop our existing assets and also to increase our proved reserves and
production through exploitation of our existing asset base, as well as the continuing identification, acquisition, and development of
new growth opportunities. None of our employees are covered by collective bargaining agreements. We believe our relationship with
our employees is good.
17
In addition to our employees, we use the services of independent consultants and contractors to perform various professional
services. As a working interest owner, we rely on certain outside operators to drill, produce and market our natural gas and oil where
we are a non-operator. In prospects where we are the operator, we rely on drilling contractors to drill and sometimes rely on
independent contractors to produce and market our natural gas and oil. In addition, we frequently utilize the services of independent
contractors to perform field and on-site drilling and production operation services and independent third party engineering firms to
evaluate our reserves.
Directors and Executive Officers
See “Item 10. Directors, Executive Officers and Corporate Governance”, which information is incorporated herein by
reference.
Corporate Offices
Effective October 1, 2013, we moved our corporate offices to 717 Texas Avenue in downtown Houston, Texas, under a lease
that expires March 31, 2019. Rent, including parking, related to this office space for the year ended December 31, 2014 was
approximately $2.1 million. We remain responsible for the rent at our previous corporate office at 3700 Buffalo Speedway in Houston,
Texas, through February 29, 2016. Effective January 1, 2014, we subleased our previous corporate offices through February 29, 2016
and expect to recover the substantial majority of the rent we pay at that location.
Code of Ethics
We adopted a Code of Ethics for senior management in December 2002. In January 2014, our board of directors adopted a
new Code of Business Conduct and Ethics ("Code of Conduct") that applies to all directors, officers and employees of the Company.
Our Code of Conduct is available on the Company's website at www.contango.com. Any shareholder who so requests may obtain a
copy of the Code of Conduct by submitting a request to the Company's corporate secretary at the address on the cover of this Form 10-
K. Changes in and waivers to the Code of Conduct for the Company's directors, chief executive officer and certain senior financial
officers will be posted on the Company's website within five business days and maintained for at least 12 months. Information on our
website or any other website is not incorporated by reference into, and does not constitute a part of, this Report on Form 10-K.
Available Information
You may read and copy all or any portion of this report on Form 10-K, our quarterly reports on Form 10-Q and current
reports on Form 8-K, as well as any amendments and exhibits to those reports, without charge at the office of the Securities and
Exchange Commission (the “SEC”) in Public Reference Room, 100 F Street NE, Washington, DC, 20549. Information regarding the
operation of the public reference rooms may be obtained by calling the SEC at 1-800-SEC-0330. In addition, filings made with the
SEC electronically are publicly available
the SEC's website at http://www.sec.gov, and at our website at
http://www.contango.com. This report on Form 10-K, including all exhibits and amendments, has been filed electronically with the
SEC.
through
Seasonal Nature of Business
The demand for oil and natural gas fluctuates depending on the time of year. Seasonal anomalies such as mild winters or hot
summers sometimes lessen this fluctuation. In addition, pipelines, utilities, local distribution companies, and industrial end users
utilize oil and natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can
also lessen seasonal demand.
Item 1A. Risk Factors
In addition to the other information set forth elsewhere in this Form 10-K, you should carefully consider the following factors
when evaluating the Company. An investment in the Company is subject to risks inherent in our business. The trading price of the
shares of the Company is affected by the performance of our business relative to, among other things, competition, market conditions
and general economic and industry conditions. The value of an investment in the Company may decrease, resulting in a loss.
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RISK FACTORS RELATING TO OUR BUSINESS
We have no ability to control the market price for natural gas and oil. Natural gas and oil prices fluctuate widely, and a
substantial or extended decline in natural gas and oil prices would adversely affect our revenues, profitability and growth and
could have a material adverse effect on the business, the results of operations and financial condition of the Company.
Our revenues, profitability and future growth depend significantly on natural gas and crude oil prices. The markets for these
commodities are volatile and prices received affect the amount of future cash flow available for capital expenditures and repayment of
indebtedness and our ability to raise additional capital. Lower prices may also affect the amount of natural gas and oil that we can
economically produce. Factors that can cause price fluctuations include:
• Overall economic conditions, domestic and global.
•
•
The domestic and foreign supply of natural gas and oil.
The level of consumer product demand.
• Adverse weather conditions and natural disasters.
•
•
•
The price and availability of competitive fuels such as LNG, heating oil and coal.
Political conditions in the Middle East and other natural gas and oil producing regions.
The level of LNG imports and any LNG exports.
• Domestic and foreign governmental regulations.
•
Special taxes on production.
• Access to pipelines and gas processing plants.
•
The loss of tax credits and deductions.
A substantial or extended decline in natural gas and oil prices could have a material adverse effect on our access to capital
and the quantities of natural gas and oil that may be economically produced by us. A significant decrease in price levels for an
extended period would negatively affect us. The Company has, in the past, utilized financial derivative contracts, such as swaps,
costless collars and puts on commodity prices, to reduce exposure to potential declines in commodity prices. We currently do not have
derivative arrangements in place on any post-2014 production.
Part of our strategy involves drilling in new or emerging plays; therefore, our drilling results in these areas are not certain.
The results of our drilling in new or emerging plays, such as in our South Texas and Wyoming resource plays, are more
uncertain than drilling results in areas that are more developed and with longer production history. Since new or emerging plays and
new formations have limited production history, we are less able to use past drilling results in those areas to help predict our future
drilling results. The ultimate success of these drilling and completion strategies and techniques in these formations will be better
evaluated over time as more wells are drilled and production profiles are better established. Accordingly, our drilling results are
subject to greater risks in these areas and could be unsuccessful. We may be unable to execute our expected drilling program in these
areas because of disappointing drilling results, capital constraints, lease expirations, access to adequate gathering systems or pipeline
take-away capacity, availability of drilling rigs and other services or otherwise, and/or crude oil, natural gas and natural gas liquids
price declines. To the extent we are unable to execute our expected drilling program in these areas, our return on investment may not
be as attractive as we anticipate and our common stock price may decrease. We could incur material write-downs of unevaluated
properties, and the value of our undeveloped acreage could decline in the future if our drilling results are unsuccessful.
Initial production rates in shale plays tend to decline steeply in the first twelve months of production and are not necessarily
indicative of sustained production rates.
Our future cash flows are subject to a number of variables, including the level of production from existing wells. Initial
production rates in shale plays tend to decline steeply in the first twelve months of production and are not necessarily indicative of
sustained production rates. As a result, we generally must locate and develop or acquire new crude oil or natural gas reserves to offset
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declines in these initial production rates. If we are unable to do so, these declines in initial production rates may result in a decrease in
our overall production and revenue over time.
Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or
financing on satisfactory terms, which could lead to a loss of undeveloped acreage and a decline in our crude oil, natural gas
and natural gas liquids reserves.
The oil and gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our
business and operations for the exploration, development, production and acquisition of crude oil, natural gas and natural gas liquids
reserves. We intend to finance our future capital expenditures primarily with cash flow from operations and borrowings under our
senior secured revolving credit agreement. Our cash flow from operations and access to capital is subject to a number of variables,
including:
• Our proved reserves.
•
•
The level of crude oil, natural gas and natural gas liquids we are able to produce from existing wells.
The prices at which crude oil, natural gas and natural gas liquids are sold.
• Our ability to acquire, locate and produce new reserves.
If our revenues decrease as a result of lower crude oil, natural gas and natural gas liquids 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, to further develop and exploit our current properties, or to conduct exploratory activity. In order to fund our capital
expenditures, we may need to seek additional financing. Our credit agreements contain covenants restricting our ability to incur
additional indebtedness without the consent of the lenders. Our lenders may withhold this consent in their sole discretion. In addition,
if our borrowing base redetermination results in a lower borrowing base under our senior secured revolving credit agreement, we may
be unable to obtain financing otherwise available under our senior secured revolving credit agreement. Since the last regularly
scheduled redetermination of our borrowing base, effective through May 1, 2015, commodity prices have continued to decline. The
decline in prices will likely negatively impact the price decks utilized by banks in their calculation of the Company’s borrowing base
at May 1, 2015. It is not possible to forecast what that adjustment to the borrowing base might be at that time, and because of that
uncertainty, the Company has currently limited its planned 2015 capital expenditure budget to a level that can be funded by internally
generated cash flows. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital
Resources and Liquidity.”
Furthermore, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. In particular, the cost
of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets
generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency
of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and
institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity on
terms that are similar to existing debt, and reduced, or in some cases ceased, to provide funding to borrowers. The failure to obtain
additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in
turn could lead to a possible loss of properties and a decline in our crude oil, natural gas and natural gas liquids reserves.
We assume additional risk as operator in drilling high pressure and high temperature wells in the Gulf of Mexico.
We continue to drill and operate exploration wells in the Gulf of Mexico. Drilling activities are subject to numerous risks,
including the significant risk that no commercially productive hydrocarbon reserves will be encountered. The cost of drilling,
completing and operating wells and of installing production facilities and pipelines is often uncertain. Drilling costs could be
significantly higher if we encounter difficulty in drilling offshore exploration wells. The Company’s drilling operations may be
curtailed, delayed, canceled or negatively impacted as a result of numerous factors, including title problems, weather conditions,
compliance with governmental requirements and shortages or delays in the delivery or availability of material, equipment and
fabrication yards. In periods of increased drilling activity resulting from high commodity prices, demand exceeds availability for
drilling rigs, drilling vessels, supply boats and personnel experienced in the oil and gas industry in general, and the offshore oil and
gas industry in particular. This may lead to difficulty and delays in consistently obtaining certain services and equipment from
vendors, obtaining drilling rigs and other equipment at favorable rates and scheduling equipment fabrication at factories and
20
fabrication yards. This, in turn, may lead to projects being delayed or experiencing increased costs. The cost of drilling, completing,
and operating wells is often uncertain, and new wells may not be productive or we may not recover all or any of our investment. The
risk of significant cost overruns, curtailments, delays, inability to reach our target reservoir and other factors detrimental to drilling
and completion operations may be higher due to our inexperience as an operator.
We rely on third-party operators to operate and maintain some of our wells, production platforms, pipelines and processing
facilities and, as a result, we have limited control over the operations of such facilities. The interests of an operator may differ
from our interests.
We depend upon the services of third-party operators to operate some production platforms, pipelines, gas processing
facilities and the infrastructure required to produce and market our natural gas, condensate and oil. We have limited influence over the
conduct of operations by third-party operators. As a result, we have little control over how frequently and how long our production is
shut-in when production problems, weather and other production shut-ins occur. Poor performance on the part of, or errors or
accidents attributable to, the operator of a project in which we participate may have an adverse effect on our results of operations and
financial condition. Also, the interest of an operator may differ from our interests.
Repeated offshore production shut-ins can possibly damage our well bores.
Our offshore well bores are required to be shut-in from time to time due to a variety of issues, including a combination of
weather, mechanical problems, sand production, bottom sediment, water and paraffin associated with our condensate production, as
well as downstream third-party facility and pipeline shut-ins. In addition, shut-ins are necessary from time to time to upgrade and
improve the production handling capacity at related downstream platform, gas processing and pipeline infrastructure. In addition to
negatively impacting our near term revenues and cash flow, repeated production shut-ins may damage our well bores if repeated
excessively or not executed properly. The loss of a well bore due to damage could require us to drill additional wells.
Natural gas and oil reserves are depleting assets and the failure to replace our reserves would adversely affect our production
and cash flows.
Our future natural gas and oil production depends on our success in finding or acquiring new reserves. If we fail to replace
reserves, our level of production and cash flows will be adversely impacted. Production from natural gas and oil properties decline as
reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves
are produced unless we conduct other successful exploration and development activities or acquire properties containing proved
reserves, or both. Further, the majority of our reserves are proved developed producing. Accordingly, we do not have significant
opportunities to increase our production from our existing proved reserves. Our ability to make the necessary capital investment to
maintain or expand our asset base of natural gas and oil reserves would be impaired 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. If we are not successful, our future production and revenues will be adversely affected.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve
estimates or underlying assumptions could materially affect the quantities of our reserves.
There are numerous uncertainties in estimating crude oil and natural gas reserves and their value, including many factors that
are beyond our control. It requires interpretations of available technical data and various assumptions, including assumptions relating
to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated
quantities of reserves shown in this report.
In order to prepare these estimates, our independent third-party petroleum engineers must project production rates and timing
of development expenditures as well as analyze available geological, geophysical, production and engineering data, and the extent,
quality and reliability of this data can vary. The process also requires economic assumptions relating to matters such as natural gas and
oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and
quantities of recoverable natural gas and oil reserves most likely will vary from our estimates. Any significant variance could
materially affect the estimated quantities and pre-tax net present value of reserves shown in a reserve report. In addition, estimates of
21
our proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing natural gas and
oil prices and other factors, many of which are beyond our control and may prove to be incorrect over time. As a result, our estimates
may require substantial upward or downward revisions if subsequent drilling, testing and production reveal different results.
Furthermore, some of the producing wells included in our reserve report have produced for a relatively short period of time.
Accordingly, some of our reserve estimates are not based on a multi-year production decline curve and are calculated using a reservoir
simulation model together with volumetric analysis. Any downward adjustment could indicate lower future production and thus
adversely affect our financial condition, future prospects and market value.
Approximately 24% of our total estimated proved reserves at December 31, 2014 were proved undeveloped reserves.
Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The
reserve data included in the reserve engineer reports assumes that substantial capital expenditures are required to develop such
reserves. Although cost and reserve estimates attributable to our crude oil, natural gas and natural gas liquids reserves have been
prepared in accordance with industry standards, we cannot be sure that the estimated costs are accurate, that development will occur as
scheduled or that the results of such development will be as estimated.
The present value of future net cash flows from our proved reserves will not necessarily be the same as the current market
value of our estimated crude oil, natural gas and natural gas liquids reserves.
You should not assume that the present value of future net revenues from our proved reserves referred to in this report is the
current market value of our estimated crude oil, natural gas and natural gas liquids reserves. In accordance with the requirements of
the SEC, the estimated discounted future net cash flows from our proved reserves are based on prices and costs on the date of the
estimate, held flat for the life of the properties. Actual future prices and costs may differ materially from those used in the present
value estimate. The present value of future net revenues from our proved reserves as of December 31, 2014 was based on the 12-
month unweighted arithmetic average of the first-day-of-the-month price for the period January through December 2014. For our
condensate and natural gas liquids, the average West Texas Intermediate (Cushing) posted price was $94.99 per barrel for offshore
volumes and the average West Texas Intermediate (Plains) posted price was $91.48 per barrel for onshore volumes. For our natural
gas, the average Henry Hub spot price was $4.30 per MMBtu for offshore volumes and the average Henry Hub spot price was $4.35
per MMBtu for onshore volumes. The following sensitivity analyses for condensate, crude oil and natural gas do not include the
volatility reducing effects of our derivative hedging instruments in place at December 31, 2014. If condensate and crude oil prices
were $1.00 per Bbl lower than the prices used, our PV-10 as of December 31, 2014 would have decreased from $796.9 million to
$790.0 million. If natural gas prices were $0.10 per Mcf lower than the price used, our PV-10 as of December 31, 2014, would have
decreased from $796.9 million to $785.1 million. Any adjustments to the estimates of proved reserves or decreases in the price of
crude oil or natural gas may decrease the value of our common stock. A reconciliation of our Standardized Measure to PV-10 is
provided under "Item 2. Properties - Proved Reserves".
Actual future net cash flows will also be affected by increases or decreases in consumption by oil and gas purchasers and
changes in governmental regulations or taxation. The timing of both the production and the incurrence of expenses in connection with
the development and production of oil and gas properties affects the timing of actual future net cash flows from proved reserves. The
effective interest rate at various times and the risks associated with our business or the oil and gas industry in general will affect the
accuracy of the 10% discount factor.
Our use of 2D and 3D seismic data is subject to interpretation and may not accurately identify the presence of crude oil,
natural gas and natural gas liquids. In addition, the use of such technology requires greater predrilling expenditures, which
could adversely affect the results of our drilling operations.
Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through
geophysical and geological analyses, production data and engineering studies, the results of which are uncertain. For example, we
have over 4,000 square miles of 3D data in the South Texas and Gulf Coast regions. However, even when used and properly
interpreted, 3D seismic data and visualization techniques only assist geoscientists and geologists in identifying subsurface structures
and hydrocarbon indicators. They do not allow the interpreter to know if hydrocarbons are present or producible economically. Other
geologists and petroleum professionals, when studying the same seismic data, may have significantly different interpretations than our
professionals.
22
In addition, the use of 3D seismic and other advanced technologies requires greater predrilling expenditures than traditional
drilling strategies, and we could incur losses due to such expenditures. As a result, our drilling activities may not be geologically
successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area may not
improve.
Drilling for and producing crude oil, natural gas and natural gas liquids are high risk activities with many uncertainties that
could adversely affect our business, financial condition or results of operations.
Our drilling and operating activities are subject to many risks, including the risk that we will not discover commercially
productive reservoirs. Drilling for crude oil, natural gas and natural gas liquids can be unprofitable, not only from dry holes, but from
productive wells that do not produce sufficient revenues to return a profit. In addition, our drilling and producing operations may be
curtailed, delayed or canceled as a result of other factors, including:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
unusual or unexpected geological formations and miscalculations;
pressures;
fires;
explosions and blowouts;
pipe or cement failures;
environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring
radioactive materials, and unauthorized discharges of toxic gases, brine, well stimulation and completion fluids, or other
pollutants into the surface and subsurface environment;
loss of drilling fluid circulation;
title problems;
facility or equipment malfunctions;
unexpected operational events;
shortages of skilled personnel;
shortages or delivery delays of equipment and services or of water used in hydraulic fracturing activities;
compliance with environmental and other regulatory requirements;
natural disasters; and
adverse weather conditions.
Any of these risks can cause substantial losses, including personal injury or loss of life; severe damage to or destruction of
property, natural resources and equipment, pollution, environmental contamination, clean-up responsibilities, loss of wells, repairs to
resume operations; and regulatory fines or penalties.
Insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe
that the cost of available insurance is excessive relative to the perceived risks presented. We carry limited environmental insurance,
thus, losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of
an event that is not covered in full or in part by insurance could have a material adverse impact on our business activities, financial
condition and results of operations.
The potential lack of availability of, or high cost of, drilling rigs, equipment, supplies, personnel and crude oil field services
could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget.
When the prices of crude oil, natural gas and natural gas liquids increase, or the demand for equipment and services is greater
than the supply in certain areas, we typically encounter an increase in the cost of securing drilling rigs, equipment and supplies. In
addition, larger producers may be more likely to secure access to such equipment by offering more lucrative terms. If we are unable to
acquire access to such resources, or can obtain access only at higher prices, our ability to convert our reserves into cash flow could be
23
delayed and the cost of producing those reserves could increase significantly, which would adversely affect our results of operations
and financial condition.
Our hedging activities could result in financial losses or reduce our income.
To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of crude oil, natural
gas and natural gas liquids, as well as interest rates, we have, and may in the future, enter into derivative arrangements for a portion of
our crude oil, natural gas and/or natural gas liquids production and our debt that could result in both realized and unrealized hedging
losses. We typically utilize financial instruments to hedge commodity price exposure to declining prices on our crude oil, natural gas
and natural gas liquids production. We typically use a combination of puts, swaps and costless collars. We currently do not have
derivative arrangements in place on any post-2014 production.
Our actual future production may be significantly higher or lower than we estimate at the time we enter into hedging
transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we
intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be
forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the
underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging
activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually
increase the volatility of our cash flows.
The enactment of derivatives legislation 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.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in 2010, established federal
oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-
Frank Act requires the Commodities Futures Trading Commission (CFTC) and the SEC to promulgate rules and regulations
implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented
and it is not possible at this time to predict when this will be accomplished.
In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major
energy markets and for swaps that are their economic equivalents. The initial position-limits rule was vacated by the U.S. District
Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place
limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to
exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions
on us is uncertain at this time.
The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules
also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take
steps to qualify for an exemption to such requirements. Although we expect to qualify for the end-user exception from the mandatory
clearing requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution
requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for
hedging. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support
documentation and/or post initial and variation margin. Posting of collateral could impact liquidity and reduce cash available to us for
capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows. The proposed margin rules
are not yet final, and therefore the impact of those provisions on us is uncertain at this time. The Dodd-Frank Act and regulations may
also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which
may not be as creditworthy as the current counterparties.
The full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be known until the
regulations are implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and regulations could
significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of
derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts or
increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and
regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely
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affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of
investors.
Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some
legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. 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 us, our financial condition, and our results of operations.
We may incur substantial impairment of proved properties.
If management’s estimates of the recoverable proved reserves on a property are revised downward or if oil and/or natural gas
prices decline as they have done in late 2014 and early 2015, and stay low for the remainder of 2015, we may be required to record
non-cash impairment write-downs in the future, which would result in a negative impact to our financial results. Furthermore, any
sustained decline in oil and/or natural gas prices may require us to make further impairments. We review our proved oil and gas
properties for impairment on a depletable unit basis when circumstances suggest there is a need for such a review. To determine if a
depletable unit is impaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying
management’s estimates of future oil and natural gas prices to the estimated future production of oil and gas reserves over t he
economic life of the property. Future net cash flows are based upon our independent reservoir engineers’ estimates of proved reserves.
In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions.
For each property determined to be impaired, we recognize an impairment loss equal to the difference between the estimated fair value
and the carrying value of the property on a depletable unit basis.
Fair value is estimated to be the present value of expected future net cash flows. Any impairment charge incurred is recorded
in accumulated depreciation, depletion, and amortization to reduce our recorded basis in the asset. Each part of this calculation is
subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, future cash flows and
fair value.
Management’s assumptions used in calculating oil and gas reserves or regarding the future cash flows or fair value of our
properties are subject to change in the future. Any change could cause impairment expense to be recorded, impacting our net income
or loss and our basis in the related asset. Any change in reserves directly impacts our estimate of future cash flows from the property,
as well as the property’s fair value. Additionally, as management’s views related to future prices change, the c hange will affect the
estimate of future net cash flows and the fair value estimates. Changes in either of these amounts will directly impact the calculation
of impairment.
Production activities in the Gulf of Mexico increase our susceptibility to pollution and natural resource damage.
A blowout, rupture or spill of any magnitude would present serious operational and financial challenges. All of the
Company’s operations in the Gulf of Mexico shelf are in water depths of less than 300 feet and less than 50 miles from the coast. Such
proximity to the shore-line increases the probability of a biological impact or damaging the fragile eco-system in the event of released
condensate.
Climate change legislation and regulatory initiatives restricting emissions of greenhouse gases (“GHGs”) could result in
increased operating costs and reduced demand for the oil and natural gas that we produce.
In response to findings that emissions of GHGs present an endangerment to public health and the environment, the EPA has
adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration
(“PSD”) and Title V permit reviews for GHG emissions from certain large stationary sources that already are potential major sources
of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be
required to meet “best available control technology” standards that typically will be established by the states. The EPA has also
adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among
others, certain oil and natural gas production facilities on an annual basis, which includes certain of our operations.
While, Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant
activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal
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climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by
means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances
in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be
adopted to address GHG emissions would impact our business, any such future laws and regulations that require reporting of GHGs or
otherwise limit emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG
emissions or reduce emissions of GHGs associated with our operations, and such requirements also could adversely affect demand for
the oil and natural gas that we produce. For example, on January 14, 2015, the Obama Administration announced that the EPA is
expected to propose in the summer of 2015 and finalize in 2016 new regulations that will set methane emission standards for new and
modified oil and gas production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce
methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025. Finally, it should be noted that some
scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that h ave
significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any
such effects were to occur, they could have an adverse effect on our financial condition and results of operations.
The natural gas and oil business involves many operating risks that can cause substantial losses and our insurance coverage
may not be sufficient to cover some liabilities or losses that we may incur.
The natural gas and oil business involves a variety of operating risks, including:
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Blowouts, fires and explosions.
Surface cratering.
• Uncontrollable flows of underground natural gas, oil or formation water.
• Natural disasters.
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Pipe and cement failures.
Casing collapses.
Stuck drilling and service tools.
Reservoir compaction.
• Abnormal pressure formations.
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Environmental hazards such as natural gas leaks, oil spills, pipeline ruptures or unauthorized discharges of toxic gases.
Capacity constraints, equipment malfunctions and other problems at third-party operated platforms, pipelines and gas
processing plants over which we have no control.
Repeated shut-ins of our well bores could significantly damage our well bores.
Required workovers of existing wells that may not be successful.
If any of the above events occur, we could incur substantial losses as a result of:
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Injury or loss of life.
Reservoir damage.
Severe damage to and destruction of property or equipment.
Pollution and other environmental and natural resources damage.
Clean-up responsibilities.
Regulatory investigations and penalties.
Suspension of our operations or repairs necessary to resume operations.
Offshore operations are subject to a variety of operating risks peculiar to the marine environment, such as capsizing and
collisions. In addition, offshore operations, and in some instances operations along the Gulf Coast, are subject to damage or loss from
hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production.
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As a result, we could incur substantial liabilities that could reduce the funds available for exploration, development or leasehold
acquisitions, or result in loss of properties.
If we were to experience any of these problems, it could affect well bores, platforms, gathering systems and processing
facilities, any one of which could adversely affect our ability to conduct operations. In accordance with customary industry practices,
we maintain insurance against some, but not all, of these risks. Losses could occur for uninsurable or uninsured risks or in amounts in
excess of existing insurance coverage. We may not be able to maintain adequate insurance in the future at rates we consider
reasonable, and particular types of coverage may not be available. An event that is not fully covered by insurance could have a
material adverse effect on our financial position and results of operations.
Our ability to market our natural gas and oil may be impaired by capacity constraints and equipment malfunctions on the
platforms, gathering systems, pipelines and gas plants that transport and process our natural gas and oil.
All of our natural gas and oil is transported through gathering systems, pipelines and processing plants. Transportation
capacity on gathering system pipelines and platforms is occasionally limited and at times unavailable due to repairs or improvements
being made to these facilities or due to capacity being utilized by other natural gas or oil shippers that may have priority transportation
agreements. If the gathering systems, processing plants, platforms or our transportation capacity is materially restricted or is
unavailable in the future, our ability to market our natural gas or oil could be impaired and cash flow from the affected properties
could be reduced, which could have a material adverse effect on our financial condition and results of operations. Further, repeated
shut-ins of our wells could result in damage to our well bores that would impair our ability to produce from these wells and could
result in additional wells being required to produce our reserves.
If our access to sales markets is restricted, it could negatively impact our production, our income and ultimately our ability to
retain our leases.
Market conditions or the unavailability of satisfactory crude oil, natural gas and natural gas liquids transportation
arrangements may hinder our access to crude oil, natural gas and natural gas liquids markets or delay our production. The availability
of a ready market for our crude oil, natural gas and natural gas liquids production depends on a number of factors, including the
demand for and supply of crude oil, natural gas and natural gas liquids and the proximity of reserves to pipelines and terminal
facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems,
pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could
materially harm our business. Our productive properties may be located in areas with limited or no access to pipelines, thereby
necessitating delivery by other means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our
crude oil, natural gas and natural gas liquids may have several adverse effects, including higher transportation costs, fewer potential
purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production
from a particular lease for an extended time, possible loss of a lease due to lack of production.
We may not have title to our leased interests and if any lease is later rendered invalid, we may not be able to proceed with our
exploration and development of the lease site.
Our practice in acquiring exploration leases or undivided interests in natural gas and oil leases is to not incur the expense of
retaining title lawyers to examine the title to the mineral interest prior to executing the lease. Instead, we rely upon the judgment of
consultants and others to perform the field work in examining records in the appropriate governmental, county or parish clerk’s office
before leasing a specific mineral interest. This practice is widely followed in the industry. Prior to the drilling of an exploration well
the operator of the well will typically obtain a preliminary title review of the drillsite lease and/or spacing unit within which the
proposed well is to be drilled to identify any obvious deficiencies in title to the well and, if there are deficiencies, to identify measures
necessary to cure those defects to the extent reasonably possible. However, such deficiencies may not have been cured by the operator
of such wells. It does happen, from time to time, that the examination made by title lawyers reveals that the lease or leases are invalid,
having been purchased in error from a person who is not the rightful owner of the mineral interest desired. In these circumstances, we
may not be able to proceed with our exploration and development of the lease site or may incur costs to remedy a defect. It may also
happen, from time to time, that the operator may elect to proceed with a well despite defects to the title identified in the preliminary
title opinion.
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Competition in the natural gas and oil industry is intense, and we are smaller and have a more limited operating history than
many of our competitors.
We compete with a broad range of natural gas and oil companies in our exploration and property acquisition activities. We
also compete for the equipment and labor required to operate and to develop these properties. Many of our competitors have
substantially greater financial resources than we do. These competitors may be able to pay more for exploratory prospects and
productive natural gas and oil properties. Further, they may be able to evaluate, bid for and purchase a greater number of properties
and prospects than we can. Our ability to explore for natural gas and oil and to acquire additional properties in the future depends on
our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In
addition, many of our competitors have been operating for a much longer time than we have and have substantially larger staffs. We
may not be able to compete effectively with these companies or in such a highly competitive environment.
Proposed U.S. federal budgets and pending legislation contain certain provisions that, if passed as originally submitted, will
have an adverse effect on our financial position, results of operations, and cash flows.
The federal administration has released repeated budget proposals over the past few years which include numerous proposed
tax changes. The proposed budgets and legislation would repeal many tax incentives and deductions that are currently used by oil and
gas companies in the United States and impose new taxes. Among others, the provisions include: elimination of the ability to fully
deduct intangible drilling costs in the year incurred; repeal of the percentage depletion deduction for oil and gas properties; repeal of
the manufacturing tax deduction for oil and gas companies; increase in the geological and geophysical amortization period for
independent producers; and implementation of a fee on non-producing leases located on federal lands. Should some or all of these
provisions become law, taxes on the E&P industry would increase, which could have a negative impact on our results of operations
and cash flows. Although these proposals initially were made in 2009, none have become law. It is still, however, the federal
administration’s stated intention to enact legislation to repeal tax incentives and deductions and impose new taxes on oil and gas
companies.
We are subject to stringent laws and regulations, including environmental requirements that can adversely affect the cost,
manner or feasibility of doing business.
Our operations are subject to numerous federal, state and local laws and regulations governing the operation and maintenance
of our facilities, the discharge of materials into the environment and environmental protection. Failure to comply with such rules and
regulations could result in the assessment of substantial penalties, imposition of investigatory or remedial obligations, and the issuance
of orders limiting or prohibiting some or all of our operations. These laws and regulations:
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Require that we obtain permits before commencing drilling or other regulated 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 or wilderness areas.
Require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells.
• Apply specific health and safety criteria addressing worker protection.
Under these laws and regulations, we could be liable for personal injury and clean-up costs and other environmental and
property damages, as well as administrative, civil and criminal penalties. We maintain only limited insurance coverage for sudden and
accidental environmental damages. Accordingly, we may be subject to liability, or we may be required to cease production from
properties in the event of environmental damages. These laws and regulations have been changed frequently in the past. In general,
these changes have imposed more stringent requirements that increase operating costs or require capital expenditures in order to
remain in compliance. It is also possible that unanticipated developments could cause us to make environmental expenditures that are
significantly different from those we currently expect. Existing laws and regulations could be changed and any such changes could
have an adverse effect on our business and results of operations. For example, in December 2014, the EPA published a proposed
rulemaking that it expects to finalize by October 1, 2015, which rulemaking proposes to revise the National Ambient Air Quality
Standard for ozone between 65 to 70 ppb for both the 8-hour primary and secondary standards.
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Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews
of such activities, could result in increased costs, additional operating restrictions or delays, and adversely affect our
production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from
dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure
into targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing
techniques in many of our drilling and completion programs. Hydraulic fracturing typically is regulated by state oil and natural gas
commissions, or other similar state agencies, but several federal agencies have asserted regulatory authority over certain aspects of the
process. For example, the EPA has issued final Clean Air Act regulations governing performance standards, including standards for
the capture of air emissions released during hydraulic fracturing; announced its intent to propose in the first half of 2015 effluent limit
guidelines that wastewater from shale gas extraction operations must meet before discharging to a treatment plant; and issued in May
2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the
chemical substances and mixtures used in hydraulic fracturing. Also, the BLM issued a revised proposed rule containing disclosure
requirements and other mandates for hydraulic fracturing on federal lands and the agency is now analyzing comments to the proposed
rulemaking and is expected to promulgate a final rule in the first half of 2015. Moreover, from time to time, Congress has considered
adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used
in the hydraulic fracturing process. In addition to any actions by Congress, certain states, including Texas, where we conduct
operations, have adopted and other states are considering adopting legal requirements that could impose new or more stringent
permitting, public disclosure, and well construction requirements on hydraulic fracturing activities. States could elect to prohibit
hydraulic fracturing altogether, such as the State of New York announced in December 2014. Local government also may seek to
adopt ordinances within their jurisdictions regulating the time, place or manner of drilling activities in general or hydraulic fracturing
activities in particular. In the event that new or more stringent federal, state, or local legal restrictions relating to the hydraulic
fracturing process are adopted in areas where we currently or in the future plan to operate, we could incur potentially significant added
costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production
activities, and perhaps even be precluded from drilling wells.
In addition, certain governmental reviews are underway that focus on environmental aspects of hydraulic fracturing practices.
The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices.
The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater,
with a report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be
available for public comment and peer review in the first half of 2015. These existing or any future studies, depending on their degree
of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing.
Additional offshore drilling laws and regulations, delays in the processing and approval of drilling permits and exploration
and oil spill-response plans, and other related restrictions in the Gulf of Mexico may have a material adverse effect on our
business, financial condition, or results of operations.
In response to the Deepwater Horizon drilling rig explosive incident and resulting oil spill in the United States Gulf of
Mexico in 2010, the BOEM and BSEE, have imposed new and more stringent permitting procedures and regulatory safety and
performance requirements for new wells to be drilled in federal waters. These governmental agencies have implemented and enforced
new rules, Notices to Lessees and Operators and temporary drilling moratoria that imposed safety and operational performance
measures on exploration, development and production operators in the Gulf of Mexico or otherwise resulted in a temporary cessation
of drilling activities. In addition, states may adopt and implement similar or more stringent legal requirements applicable to
exploration and production activities in state waters. Compliance with these added and more stringent regulatory restrictions, in
addition to any uncertainties or inconsistencies in current decisions and rulings by governmental agencies and delays in the processing
and approval of drilling permits and exploration, development and oil spill-response plans could adversely affect or delay new drilling
and ongoing development efforts, which could have a material adverse impact on our business. Moreover, these governmental
agencies are continuing to evaluate aspects of safety and operational performance in the Gulf of Mexico and, as a result, developing
and implementing new, more restrictive requirements. One example is the 2013 amendments to the federal Workplace Safety Rule
regarding the utilization of a more comprehensive SEMS program, which amended rule is sometimes referred to as SEMS II. This
program requires operators to identify, address, and manage safety and environmental hazards during the design, construction, start-
up, operation, inspection, and maintenance of all new and existing facilities. Facilities must be designed, constructed, maintained,
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monitored, and operated in a manner compatible with industry codes, consensus standards, and all applicable governmental
regulations. Failure to comply with the SEMS program may force us to cease operations in the Gulf of Mexico. A second, and more
recent, example is the August 2014 Advanced Notice of Proposed Rulemaking that ultimately seeks to bolster the offshore financial
assurance and bonding program. Changes to the bonding program could result in the increased amounts of bonds to operate in the
Gulf of Mexico. These additional measures could delay or disrupt our operations, increase the risk of expired leases due to the time
required to develop new technology, result in increased supplemental bonding requirements and incurrence of associated added costs,
limit operational activities in certain areas, or cause us to incur penalties, fines, or shut-in production. If material spill incidents
similar to the Deepwater Horizon incident were to occur in the future, the United States could elect to again issue directives to
temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and
regulations regarding offshore oil and natural gas exploration and development, any of which developments could have a material
adverse effect on our business
The BSEE has implemented much more stringent controls and reporting requirements that if not followed, could result in
significant monetary penalties or a shut-in of all or a portion of our Gulf of Mexico operations.
The BSEE is the federal agency responsible for overseeing the safe and environmentally responsible development of energy
and mineral resources on the OCS. They are responsible for leading the most aggressive and comprehensive reforms to offshore oil
and gas regulation and oversight in U.S. history. Their reforms have tightened requirements for everything from well design and
workplace safety to corporate accountability.
Additionally, the OCS Lands Act authorizes and requires the BSEE to provide for both an annual scheduled inspection and a
periodic unscheduled (unannounced) inspection of all oil and gas operations on the OCS. In addition to examining all safety
equipment designed to prevent blowouts, fires, spills, or other major accidents, the inspections focus on pollution, drilling operations,
completions, workovers, production, and pipeline safety. Upon detecting a violation, the inspector issues an Incident of
Noncompliance ("INC") to the operator and uses one of two main enforcement actions (warning or shut-in), depending on the severity
of the violation. If the violation is not severe or threatening, a warning INC is issued. The warning INC must be corrected within a
reasonable amount of time specified on the INC. The shut-in INC may be for a single component (a portion of the facility) or the
entire facility. The violation must be corrected before the operator is allowed to resume the activity in question.
In addition to the enforcement actions specified above, the BSEE can assess a civil penalty of up to $40,000 per violation per
day if: (i) the operator fails to correct the violation in the reasonable amount of time specified on the INC; or (ii) the violation resulted
in a threat of serious harm or damage to human life or the environment. Operators with excessive INCs may be required to cease
operations in the Gulf of Mexico.
We are highly dependent on our senior management team, our exploration partners, third-party consultants and engineers,
and other key personnel and any failure to retain the services of such parties could adversely affect our ability to effectively
manage our overall operations or successfully execute current or future business strategies.
The successful implementation of our business strategy and handling of other issues integral to the fulfillment of our business
strategy is highly dependent on our management team, as well as certain key geoscientists, geologists, engineers and other
professionals engaged by us. The loss of key members of our management team or other highly qualified technical professionals could
adversely affect our ability to effectively manage our overall operations or successfully execute current or future business strategies
which may have a material adverse effect on our business, financial condition and operating results. Our ability to manage our growth,
if any, will require us to continue to train, motivate and manage our employees and to attract, motivate and retain additional qualified
personnel. Competition for these types of personnel is intense and we may not be successful in attracting, assimilating and retaining
the personnel required to grow and operate our business profitably.
Acquisition prospects are difficult to assess and may pose additional risks to our operations.
We expect to evaluate and, where appropriate, pursue acquisition opportunities on terms our management considers
favorable. The successful acquisition of natural gas and oil properties requires an assessment of:
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Recoverable reserves.
Exploration potential.
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Future natural gas and oil prices.
• Operating costs.
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Potential environmental and other liabilities and other factors.
Permitting and other environmental authorizations required for our operations.
In connection with such an assessment, we would expect to perform a review of the subject properties that we believe to be
generally consistent with industry practices. Nonetheless, the resulting conclusions are necessarily inexact and their accuracy
inherently uncertain and such an assessment may not reveal all existing or potential problems, nor will it necessarily permit a buyer to
become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed
on every platform or well, and structural and environmental problems are not necessarily observable even when an inspection is
undertaken. Future acquisitions could pose additional risks to our operations and financial results, including:
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Problems integrating the purchased operations, personnel or technologies.
• Unanticipated costs.
• Diversion of resources and management attention from our exploration business.
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Entry into regions or markets in which we have limited or no prior experience.
Potential loss of key employees of the acquired organization.
We may be unable to successfully integrate the properties and assets we acquire with our existing operations.
Integration of the properties and assets we acquire may be a complex, time consuming and costly process. Failure to timely
and successfully integrate these assets and properties with our operations may have a material adverse effect on our business, financial
condition and result of operations. The difficulties of integrating these assets and properties present numerous risks, including:
• Acquisitions may prove unprofitable and fail to generate anticipated cash flows.
• We may need to (i) recruit additional personnel and we cannot be certain that any of our recruiting efforts will succeed
and (ii) expand corporate infrastructure to facilitate the integration of our operations with those associated with the
acquired properties, and failure to do so may lead to disruptions in our ongoing businesses or distract our management.
• Our management’s attention may be diverted from other business concerns.
We are also exposed to risks that are commonly associated with acquisitions of this type, such as unanticipated liabilities and
costs, some of which may be material. As a result, the anticipated benefits of acquiring assets and properties may not be fully realized,
if at all.
When we acquire properties, in most cases, we are not entitled to contractual indemnification for pre-closing liabilities,
including environmental liabilities.
We generally acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and
warranties, and in these situations we cannot assure you that we will identify all areas of existing or potential exposure. In those
circumstances in which we have contractual indemnification rights for pre-closing liabilities, we cannot assure you that the seller will
be able to fulfill its contractual obligations. In addition, the competition to acquire producing crude oil, natural gas and natural gas
liquids properties is intense and many of our larger competitors have financial and other resources substantially greater than ours. We
cannot assure you that we will be able to acquire producing crude oil, natural gas and natural gas liquids properties that have
economically recoverable reserves for acceptable prices.
RISK FACTORS RELATED TO AN INVESTMENT IN OUR COMMON STOCK
The price of our common stock may fluctuate significantly, and you could lose all or part of your investment.
Volatility in the market price of our common stock may prevent you from being able to sell your common stock at or above
the price you paid for your common stock. The market price for our common stock could fluctuate significantly for various reasons,
including:
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our operating and financial performance and prospects;
our quarterly or annual earnings or those of other companies in our industry;
conditions that impact demand for crude oil, natural gas and natural gas liquids, domestically and globally;
future announcements concerning our business;
changes in financial estimates and recommendations by securities analysts;
actions of competitors;
• market and industry perception of our success, or lack thereof, in pursuing our growth strategy;
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strategic actions by us or our competitors, such as acquisitions or restructurings;
changes in government and environmental regulation;
general market, economic and political conditions, domestically and globally;
changes in accounting standards, policies, guidance, interpretations or principles;
sales of common stock by us, our significant stockholders or members of our management team; and
natural disasters, terrorist attacks and acts of war.
In addition, in recent years, the stock market has experienced significant price and volume fluctuations. This volatility has
had a significant impact on the market price of securities issued by many companies, including companies in our industry. The
changes frequently appear to occur without regard to the operating performance of the affected companies. Hence, the price of our
common stock could fluctuate based upon factors that have little or nothing to do with our company, and these fluctuations could
materially reduce our share price.
We have no plans to pay regular dividends on our common stock, so you may not receive funds without selling your common
stock.
Our board of directors presently intends to retain all of our earnings for the expansion of our business; therefore, we have no
plans to pay regular dividends on our common stock. Any payment of future dividends will be at the discretion of our board of
directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness,
statutory and contractual restrictions applying to the payment of dividends, and other considerations that our board of directors deems
relevant. Also, the provisions of our senior secured revolving credit agreement and second lien credit agreement restrict the payment
of dividends. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your
investment.
Future sales or the possibility of future sales of a substantial amount of our common stock may depress the price of shares of
our common stock.
Future sales or the availability for sale of substantial amounts of our common stock in the public market could adversely
affect the prevailing market price of our common stock and could impair our ability to raise capital through future sales of equity
securities.
We may issue shares of our common stock or other securities from time to time as consideration for future acquisitions and
investments. If any such acquisition or investment is significant, the number of shares of our common stock, or the number or
aggregate principal amount, as the case may be, of other securities that we may issue may in turn be substantial. We may also grant
registration rights covering those shares of our common stock or other securities in connection with any such acquisitions and
investments.
As of December 31, 2014, we had 129,934 options to purchase shares of our common stock outstanding, all of which were
fully vested.
We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of our
common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including
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shares of our common stock issued in connection with an acquisition), or the perception that such sales could occur, may adversely
affect prevailing market prices for our common stock.
Our organizational documents may impede or discourage a takeover, which could deprive our investors of the opportunity to
receive a premium for their shares.
Provisions of our certificate of incorporation and bylaws may make it more difficult for, or prevent a third party from,
acquiring control of us without the approval of our board of directors. These provisions:
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permit us to issue, without any further vote or action by the stockholders, shares of preferred stock in one or more series
and, with respect to each such series, to fix the number of shares constituting the series and the designation of the series,
the voting powers (if any) of the shares of the series, and the preferences and relative, participating, optional, and other
special rights, if any, and any qualification, limitations or restrictions of the shares of such series;
require special meetings of the stockholders to be called by the Chairman of the Board, the Chief Executive Officer, the
President, or by resolution of a majority of the board of directors;
require business at special meetings to be limited to the stated purpose or purposes of that meeting;
require that stockholder action be taken at a meeting rather than by written consent, unless approved by our board of
directors;
require that stockholders follow certain procedures, including advance notice procedures, to bring certain matters before
an annual meeting or to nominate a director for election; and
permit directors to fill vacancies in our board of directors.
We are subject to the Delaware business combination law.
We are subject to the provisions of Section 203 of the Delaware General Corporation Law. In general, Section 203 prohibits a
publicly held Delaware corporation from engaging in a “business combination” with an “interested stockholder” for a period of three
years after the date of the transaction in which the person became an interested stockholder, unless the business combination is
approved in a prescribed manner.
Section 203 defines a “business combination” as a merger, asset sale or other transaction resulting in a financial benefit to the
interested stockholders. Section 203 defines an “interested stockholder” as a person who, together with affiliates and associates, owns,
or, in some cases, within three years prior, did own, 15% or more of the corporation’s voting stock. Under Section 203, a business
combination between us and an interested stockholder is prohibited unless:
•
•
•
our board of directors approved either the business combination or the transaction that resulted in the stockholders
becoming an interested stockholder prior to the date the person attained the status;
upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested
stockholder owned at least 85% of our voting stock outstanding at the time the transaction commenced, excluding, for
purposes of determining the number of shares outstanding, shares owned by persons who are directors and also officers
and issued employee stock plans, under which employee participants do not have the right to determine confidentially
whether shares held under the plan will be tendered in a tender or exchange offer; or
the business combination is approved by our board of directors on or subsequent to the date the person became an
interested stockholder and authorized at an annual or special meeting of the stockholders by the affirmative vote of the
holders of at least 66 2/3% of the outstanding voting stock that is not owned by the interested stockholder.
This provision has an anti-takeover effect with respect to transactions not approved in advance by our board of directors,
including discouraging takeover attempts that might result in a premium over the market price for the shares of our common
stock. With approval of our stockholders, we could amend our certificate of incorporation in the future to elect not to be governed by
the anti-takeover law.
33
Our business could be negatively affected by security threats, including cybersecurity threats and other disruptions.
As an oil and gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to
sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third party
facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security
threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our
implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information
facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such
procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur,
they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a
material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are
becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and
systems and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or
otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of
business or potential liability.
Item 1B. Unresolved Staff Comments
None
34
Item 2. Properties
As of December 31, 2014, we operated all of our offshore wells, with an average working interest of 61%, and operated 56%
of our onshore wells with an average working interest of 74%. As of December 31, 2014, our properties were located in the following
regions: Offshore Gulf of Mexico, Southeast Texas, South Texas and Other.
Development, Exploration and Acquisition Expenditures
The following table presents information regarding our net costs incurred in the purchase of proved and unproved properties
and in exploration and development activities for the periods indicated (in thousands):
Property acquisition costs:
Unproved
Proved
Exploration costs
Development costs
Total costs
2014
2013
2012
Year Ended December 31,
$
$
22,087
—
49,680
120,630
192,397
$
$
8,134
428,925
15,551
35,363
487,973
$
$
19,982
280
41,265
16,090
77,617
Included in unproved property acquisition costs for the year ended December 31, 2014, is $7.0 million related to the
acquisition of the right to earn acreage in Natrona and Weston counties, Wyoming. Included in the exploration costs for the year
ended December 31, 2014, is $28.0 million related to drilling our offshore Ship Shoal 255 well.
Included in proved property acquisition costs for the year ended December 31, 2013, is $413.9 million related to the
acquisition of Crimson properties as a result of the Merger. Also included is $15 million related to exercising a preferential right and
purchasing an additional 7.84% working interest and 6.53% net revenue interest in the five Company-operated Dutch wells from an
independent oil and gas company for $18.8 million; adjustments reduced the purchase price to a total of $14.7 million, net to us during
2014.
Included in the exploration costs for the year ended December 31, 2013, is $10.6 million related to drilling our offshore
South Timbalier 17 and Ship Shoal 255 wells.
The following table presents information regarding our share of the net costs incurred by Exaro in the purchase of proved and
unproved properties and in exploration and development activities for the periods indicated (in thousands):
Property acquisition costs
Exploration costs
Development costs
Total costs incurred
Property Dispositions
2014
Year Ended December 31,
2013
2012
— $
—
30,288
30,288
$
— $
—
51,014
51,014
$
—
—
20,528
20,528
$
$
On December 31, 2013, we sold to an independent oil and gas company approximately 7.1% of our interest in all developed
and undeveloped properties in Madison and Grimes counties for approximately $20.3 million. Metrics for the sale were approximately
$91,007 per flowing barrel of equivalent daily production and $47.32 per equivalent barrel of proved reserves. A loss of
approximately $0.2 million and a gain of approximately $6.6 million related to this sale were recognized in the years ended December
31, 2014 and 2013, respectively. See Note 5 to our Financial Statements - "Acquisitions, Dispositions and Gains from Affiliates" for a
detailed description of this disposition.
Drilling Activity
As of December 31, 2014, we had 11 wells in various stages of drilling and completing, whose results are not included
below. The following tables show our exploratory and developmental drilling activity for the periods indicated. In the tables, “gross”
35
wells refer to wells in which we have a working interest, and “net” wells refer to gross wells multiplied by our working interest in
such wells.
Exploratory Wells:
Productive (onshore)
Productive (offshore)
Non-productive (onshore)
Non-productive (offshore)
Total
2014
Gross
Net
Year Ended December 31,
2013
Gross
Net
2012
Gross
Net
3
—
1
1
5
1.3
—
0.6
1.0
2.9
3
1
—
—
4
0.3
0.8
—
—
1.1
—
—
—
2
2
—
—
—
2.0
2.0
For the year ended December 31, 2014, included in productive (onshore) exploratory wells is one well drilled on our Buda
acreage and two wells drilled in Fayette and Gonzales counties, Texas. Included in non-productive (offshore) exploratory wells is our
unsuccessful well at Ship Shoal 255.
2014
Gross
Net
Year Ended December 31,
2013
Gross
Net
2012
Gross
Net
24
—
1
—
25
13.1
—
0.7
—
13.8
5
—
—
—
5
3.2
—
—
—
3.2
—
—
—
—
—
—
—
—
—
—
Development Wells:
Productive (onshore)
Productive (offshore)
Non-productive (onshore)
Non-productive (offshore)
Total
Exploration and Development Acreage
Developed acreage is acreage spaced or assigned to productive wells. Undeveloped acreage is acreage on which wells have
not been drilled or completed to a point that would form the basis to determine whether the property is capable of production of
commercial quantities of crude oil, natural gas and natural gas liquids. Gross acres are the total acres in which we own a working
interest. Net acres are the sum of the fractional working interests we own in gross acres. The following table shows the approximate
developed and undeveloped acreage that we have an interest in, by region, at December 31, 2014.
Offshore GOM
Southeast Texas
South Texas
Other (6)
Total
Developed Acreage (1)(2)
Gross (4)
Net (5)
Undeveloped Acreage (1)(3)
Gross (4)
Net (5)
14,618
26,164
95,367
16,609
152,758
11,828
15,092
46,797
8,706
82,423
34,692
13,710
70,472
56,482
175,356
34,692
7,915
36,376
40,922
119,905
(1) Excludes any interest in acreage in which we have no working interest before payout or before initial production.
(2) Developed acreage consists of acres spaced or assignable to productive wells.
(3) Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of
commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.
(4) Gross acres refer to the number of acres in which we own a working interest.
(5) Net acres represent the number of acres attributable to our proportionate working interest in a lease (e.g., a 50% working interest in a lease covering 320 acres is
equivalent to 160 net acres).
(6) Other includes acreage in Louisiana, Colorado, Mississippi, Wyoming, and East Texas
Included in the Offshore GOM acres in the table above are the beneficial interests we have in the offshore acreage owned by
Republic Exploration LLC (“REX”). The above table includes our 32.3% interest in REX’s 625 net developed acres.
36
Some of our offshore and onshore leases will expire over the next three years as follows, unless we establish production or
take action to extend the terms of these leases:
Offshore GOM
Southeast Texas
South Texas
Other (1)
Total
2015
Year ending December 31,
2016
2017
Gross Acres
Net Acres
Gross Acres
Net Acres
Gross Acres
Net Acres
—
2,700
—
30,608
33,308
—
1,320
—
24,351
25,671
—
2,871
5,039
10,373
18,283
—
1,982
2,833
5,065
9,880
20,000
358
36,259
115
56,732
20,000
270
18,239
48
38,557
(1) Relates primarily to Louisiana and Mississippi.
Production, Price and Cost History
See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Productive Wells
Productive wells are producing wells and wells capable of producing commercial quantities. Completed but marginally
producing wells are not considered here as a “productive” well. The following table sets forth the number of gross and net productive
natural gas and oil wells in which we owned an interest as of December 31, 2014:
Offshore GOM
Southeast Texas
South Texas
Other
Total
Natural Gas Wells
Oil Wells
Gross Wells (1)
Net Wells (2)
Gross Wells (1)
Net Wells (2)
12
48
227
54
341
7.3
26.6
121.5
26.2
181.6
—
43
46
9
98
—
24.1
21.9
2.6
48.6
(1) A gross well is a well in which we own an interest.
(2) The number of net wells is the sum of our fractional working interests owned in gross wells.
Natural Gas and Oil Reserves
Estimates of proved reserves and future net revenue as of December 31, 2014 and 2013 were prepared by NSAI and Cobb,
our independent petroleum engineering firms. Approximately 52% and 48% of the proved reserves estimates shown herein at
December 31, 2014 have been independently prepared by Cobb and NSAI, respectively. Cobb prepared the proved reserves estimates
as of December 31, 2014 and 2013 for all of our offshore properties and NSAI prepared the proved reserves estimates as of December
31, 2014 and 2013 for all of our onshore properties.
Estimates of proved reserves and future net revenue as of December 31, 2012 were prepared by Cobb, all in accordance with
the definitions and regulations of the SEC. The scope and results of their procedures are summarized in their reports, which are
included as exhibits to this Form 10-K. The technical persons responsible for preparing the reserve estimates are independent
petroleum engineers and geoscientists that meet the requirements regarding qualifications, independence, objectivity, and
confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated
by the Society of Petroleum Engineers.
The estimates of proved reserves and future net revenue as of December 31, 2014 and 2013 were reviewed by our corporate
reservoir engineering department that is independent of the operations department. The corporate reservoir engineering department
interacts with geoscience, operating, accounting, and marketing departments to review the integrity, accuracy and timeliness of the
data, methods, and assumptions used in the preparation of the reserves estimates. All relevant data is compiled in a computer database
application to which only authorized personnel are given access rights. Our Senior Vice President - Engineering is the person
primarily responsible for overseeing the preparation of our internal reserve estimates and for reviewing any reserves estimates
prepared by an independent petroleum engineering firm. Our Senior Vice President - Engineering has a Bachelor of Science degree in
37
Petroleum Engineering from the University of Texas and over 35 years of industry experience with positions of increasing
responsibility. He reports directly to our President and Chief Executive Officer. Reserves are also reviewed internally with senior
management and presented to our Board of Directors in summary form on a quarterly basis.
The estimates of proved reserves and future net revenues as of December 31, 2012 were the responsibility of our
management, and members of our management met regularly with our independent third-party engineers to review these reserve
estimates. Mr. Joseph J. Romano, the Company’s then-Chief Executive Officer, had primary responsibility for the preparation of the
reserve report. Mr. Romano has been in the energy industry for over 35 years, but also relied on others with technical backgrounds in a
collaborative effort, all of whom provided input to the independent third-party engineers. Mr. Brad Juneau, one of the Company’s
directors at the time, monitored production and pressure data daily and provided the majority of the input. Mr. Juneau holds a BS
degree in Petroleum Engineering from Louisiana State University. Mr. Juneau has over 30 years of experience in the oil and gas
industry and was a former registered petroleum engineer in the State of Texas. Other executives in accounting and production have
advanced degrees and specialty licenses and also provided input to the independent third-party engineers and assisted in reviewing the
reports.
We maintain adequate and effective internal controls over the underlying data upon which reserves estimates are based. The
primary inputs to the reserve estimation process are comprised of technical information, financial data, ownership interests and
production data. All field and reservoir technical information, which is communicated to our reservoir engineers quarterly, is
confirmed when our third-party reservoir engineers hold technical meetings with geologists, operations and land personnel to discuss
field performance and to validate future development plans. Current revenue and expense information is obtained from our accounting
records, which are subject to external quarterly reviews, annual audits and our own set of internal controls over financial reporting.
Internal controls over financial reporting are assessed for effectiveness annually using criteria set forth in Internal Controls - Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. All data such as commodity prices,
lease operating expenses, production taxes, field level commodity price differentials, ownership percentages, and well production data
are updated in the reserve database by our third-party reservoir engineers and then analyzed by management to ensure that they have
been entered accurately and that all updates are complete. Once the reserve database has been entirely updated with current
information, and all relevant technical support material has been assembled, our independent engineering firms prepare their
independent reserve estimates and final report.
The following table reflects our estimated proved reserves as of the dates indicated:
Crude Oil and Condensate (MBbl) (1)
Developed
Undeveloped
Total
Natural Gas (MMcf) (1)
Developed
Undeveloped
Total
Natural Gas Liquids (MBbl) (1)
Developed
Undeveloped
Total
Total MMcfe
Developed
Undeveloped
Total (2)
Proved developed reserves percentage
Prices utilized in estimates (3):
Crude oil ($/Bbl)
Natural gas ($/MMBtu)
Natural gas liquids ($/Bbl)
December 31,
2013
5,223
4,475
9,698
185,535
22,395
207,930
6,453
1,505
7,958
255,591
58,275
313,866
81
106.80
3.73
35.92
%
$
$
$
2014
4,114
4,301
8,415
150,235
29,416
179,651
5,637
1,872
7,509
208,734
66,459
275,193
76
92.89
4.38
33.45
$
$
$
38
2012
2,514
—
2,514
166,307
7,725
174,032
5,103
227
5,330
212,009
9,087
221,096
%
96 %
$
$
$
114.24
2.85
58.39
(1) Excludes reserves attributable to our 37% interest in Exaro.
(2) During the year ended December 31, 2014, proved reserves decreased by approximately 38.7 Bcfe primarily due to a 22.4 Bcfe negative revision of proved
developed producing reserves at our Eugene Island 11 field and normal depletion. The negative revision at Eugene Island 11 was due to a change in forecasted
condensate yield and ultimate field abandonment pressure, as determined by our third party engineers taking into account recent field performance.
(3) Under SEC rules, prices used in determining our proved reserves are based upon an unweighted 12-month first day of the month average price per MMBtu (Henry
Hub spot) of natural gas and per barrel of oil (West Texas Intermediate posted). Prices for natural gas liquids in the table represent average prices for natural gas
liquids used in the proved reserve estimates, calculated in accordance with applicable SEC rules. All prices were adjusted for quality, energy content,
transportation fees and regional price differentials in determining proved reserves.
PV-10
PV-10 at year-end is a non-GAAP financial measure and represents the present value, discounted at 10% per year, of
estimated future cash inflows from proved natural gas and crude oil reserves, less future development and production costs using
pricing assumptions in effect at the end of the period. PV-10 differs from Standardized Measure of Discounted Net Cash Flows
because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure of Discounted
Net Cash Flows represents an estimate of fair market value of our natural gas and crude oil properties. PV-10 is used by the industry
and by our management as an arbitrary reserve asset value measure to compare against past reserve bases and the reserve bases of
other business entities that are not dependent on the taxpaying status of the entity.
The following table provides a reconciliation of our Standardized Measure to PV-10 (in thousands):
Pre-tax net present value, discounted at 10%
Future income taxes, discounted at 10%
Standardized measure of discounted future net cash flows
December 31,
2014
2013
$
$
796,871
(148,855)
648,016
$
$
987,213
(215,770)
771,443
The following table reflects our estimated proved reserves by category as of December 31, 2014 (dollars in thousands):
Proved developed producing
Proved developed non-producing
Proved undeveloped
Total
Crude Oil and
Condensate (MBbl)
3,896
218
4,301
8,415
Natural Gas
(MMcf)
140,423
9,812
29,416
179,651
Natural Gas
Liquids (MBbl)
5,073
564
1,872
7,509
Total (MMcfe) % of Total Proved
PV - 10
194,231
14,503
66,459
275,193
71 % $ 626,562
31,427
5 %
138,882
24 %
100 % $ 796,871
Our estimated net proved reserves as of December 31, 2014 were approximately 18% crude oil and condensate, 65% natural
gas and 17% natural gas liquids.
Proved Developed Reserves
Total proved developed reserves decreased from 255.6 Bcfe at December 31, 2013 to 208.7 Bcfe at December 31, 2014
primarily as a result of normal production.
Proved Undeveloped Reserves
The Company annually reviews any proved undeveloped reserves (“PUDs”) to ensure their development within five years
from the date of originally booking the reserves. As of December 31, 2014, the Company had approximately 66.5 Bcfe of PUDs
related to its onshore activities. Development costs related to these PUDs are projected to be approximately $197 million over the next
five years. Our financial resources are expected to be sufficient and within our budget to drill all of the remaining 66.5 Bcfe of proved
undeveloped reserves within the five year period.
39
The following table presents the changes in our total proved undeveloped reserves for the year ended December 31, 2014:
Proved Undeveloped Reserves (Mmcfe)
Proved undeveloped reserves at December 31 2013
Revisions of previous estimates (1)
Extensions, discoveries and other additions (2)
Purchase of minerals in place
Disposition of reserves in place
Conversion to proved developed
Proved undeveloped reserves at December 31 2014
58,275
(17,174)
26,997
—
—
(1,639)
66,459
(1)
Includes previously planned rate acceleration well in our Dutch and Mary Rose field that will no longer be drilled as well as revisions of previous estimates due to
a revised type curve for our Force Area of our Madison/Grimes acreage and lower commodity prices.
(2) Attributable to our onshore drilling program during the year ended December 31, 2014.
Significant Properties
Summary proved reserve information for our properties as of December 31, 2014, by region, is provided below (excluding
reserves attributable to our investment in Exaro) (dollars in thousands):
Regions
Crude Oil (MBbl)
Natural Gas (MMcf)
Offshore GOM
Southeast Texas
South Texas
Other
Total
1,071
4,603
2,084
657
8,415
115,609
23,174
32,853
8,015
179,651
Proved Reserves
Natural Gas Liquids
(MBbl)
3,621
2,172
1,573
143
7,509
Total (Mmcfe)
PV - 10 (1)
143,758
63,824
54,796
12,815
275,193
$
$
450,115
204,200
126,134
16,422
796,871
(1) Under SEC rules, prices used in determining our proved reserves are based upon an unweighted 12-month first day of the month average price per MMBtu (Henry
Hub spot) of natural gas and per barrel of oil (West Texas Intermediate posted). Prices for natural gas liquids in the table represent average prices for natural gas
liquids used in the proved reserve estimates, calculated in accordance with applicable SEC rules. All prices, using SEC rules, are adjusted for quality, energy
content, transportation fees and regional price differentials in determining proved reserves.
While we are reasonably certain of recovering our calculated reserves, the process of estimating natural gas and oil reserves
is complex. It requires various assumptions, including natural gas and oil prices, drilling and operating expenses, capital expenditures,
taxes and availability of funds. Our third party engineers must project production rates, estimate timing and amount of development
expenditures, analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of all
of this data may vary. Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating
expenses and quantities of recoverable natural gas and oil reserves most likely will vary from estimates. Any significant variance
could materially affect the estimated quantities and net present value of reserves. In addition, estimates of proved reserves may be
adjusted to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors,
many of which are beyond our control.
Reserves Attributable to our Investment in Exaro
Estimates of proved reserves and future net revenue as of December 31, 2014 and 2013 associated with our investment in
Exaro, which we account for using the equity method, were prepared by W.D. Von Gonten and Associates (“Von Gonten”) in
accordance with the definitions and regulations of the SEC. The technical persons responsible for preparing the reserve estimates are
independent petroleum engineers and geoscientists that meet the requirements regarding qualifications, independence, objectivity, and
confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated
by the Society of Petroleum Engineers.
Reserves as of December 31, 2014 and 2013 were reviewed by our corporate reservoir engineering department as described
above. The technical individual at Von Gonten responsible for overseeing the preparation of our reserve estimates as of December 31,
40
2014 and December 31, 2013 has over 14 years of practical experience in the estimation and evaluation of reserves; is a registered
professional engineer in the state of Texas; holds a Bachelor of Science Degree in Petroleum Engineering for Texas A&M University;
and is a member in good standing of the Society of Petroleum Engineers.
The following table reflects the estimated proved reserves attributable to our Investment in Exaro:
December 31 2014
December 31 2013
December 31 2012 (3)
Crude Oil (MBbl)
Developed
Undeveloped
Total
Natural Gas (MMcf)
Developed
Undeveloped
Total
Total MMcfe
Developed
Undeveloped
Total
529
262
791
45,127
20,285
65,412
48,301
21,857
70,158
439
—
439
39,068
—
39,068
41,702
—
41,702
Proved developed reserves percentage
Standardized measure (1)
Prices utilized in estimates (2)
Crude oil ($/Bbl)
Natural gas ($/MMBtu)
$
$
$
69 %
100,607
85.46
4.96
$
$
$
100 %
63,906
87.89
4.04
$
$
$
133
—
133
11,055
—
11,056
11,854
—
11,854
100 %
13,661
85.71
2.78
(1) The Company's share of the standardized measure of discounted future net cash flows attributable to our investment in Exaro does not include the effect of income
taxes because Exaro is treated a partnership for tax purposes. Exaro allocates any income or expense for tax purposes to its partners.
(2) Under SEC rules, prices used in determining our proved reserves are based upon an unweighted 12-month first day of the month average price per MMBtu (Henry
Hub spot) of natural gas and per barrel of oil (West Texas Intermediate posted). Prices for natural gas liquids in the table represent average prices for natural gas
liquids used in the proved reserve estimates, calculated in accordance with applicable SEC rules. All prices are adjusted for quality, energy content, transportation
fees and regional price differentials in determining proved reserves.
(3) Reserve amounts and standardized measure as of December 31, 2012 revised by immaterial amount compared to amounts previously stated in the Annual Report
on Form 10-K/A for the year ended December 31, 2013.
Prior Year Reserves
Our estimated net proved natural gas, oil and natural gas liquids reserves as of December 31, 2013, 2012 and 2011 are
disclosed in “Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Disclosures (Unaudited)”. Reserves
as of December 31, 2013 were based on reserve reports generated by NSAI and Cobb. Reserves as of December 31, 2012 and 2011
were based on reserve reports generated by Cobb, while the reserves associated with our 37% investment in Exaro were prepared by
Von Gonten.
Item 3. Legal Proceedings
From time to time, we are involved in legal proceedings relating to claims associated with our properties, operations or
business or arising from disputes with vendors in the normal course of business, including the material matters discussed below.
Mineral interest owners in South Louisiana filed suit against a subsidiary of the Company and several co-defendants in June
2009 in the 31st Judicial District Court situated in Jefferson Davis Parish, Louisiana alleging failure to act as a reasonably prudent
operator, failure to explore, waste, breach of contract, etc. in connection with two wells located in Jefferson Davis Parish. Many of the
alleged improprieties occurred prior to our ownership of an interest in the wells at issue, although we may have assumed liability
otherwise attributable to our predecessors-in-interest through the acquisition documents relating to the acquisition of our interest in
these wells. We and our co-defendants obtained a favorable judgment from the trial court following a bench trial. On October 1, 2014,
the Louisiana Third Circuit Court of Appeals issued an opinion reversing the trial court’s rulings and rendering judgment in favor of
the plaintiffs for approximately $13.4 million. The decision by the court of appeals did not allocate liability among the defendants
41
although we would likely be responsible for at least one-half, and possibly as much as two-thirds, of the judgment if it stands. We and
our co-defendants have filed an application for a writ of certiorari to the Louisiana Supreme Court seeking review of this case by the
state’s highest court. While there is uncertainty whether the Louisiana Supreme Court will accept our application and, if accepted, rule
in our favor, we believe that the decision by the court of appeals presents issues that will resonate with the Louisiana Supreme Court
and are of precedential significance sufficient to warrant review by that court. We and our co-defendants are vigorously defending this
lawsuit and believe that we have a meritorious position. A companion case involving the same set of facts was filed in the same trial
court on April 19, 2013 on behalf of additional mineral interest owners but has been inactive pending the appeal of the original case.
Our potential exposure in this companion case is expected to be affected by the outcome of our appeal of the original case.
In November 2010, a subsidiary of the Company, several predecessor operators and several product purchasers were named
in a lawsuit filed in the District Court for Lavaca County in Texas by an entity alleging that it owns a working interest in two wells
that has not been recognized by us or by predecessor operators to which we have granted indemnification rights. In dispute is whether
ownership rights were transferred through a number of decade-old poorly documented transactions. Based on prior summary
judgments, the trial court recently entered a final judgment in the case in favor of the plaintiffs for approximately $5.3 million, plus
post-judgment interest. We are vigorously defending this lawsuit, believe that we have meritorious defenses and are appealing the trial
court’s decision to the applicable state Court of Appeals.
In September 2012, a subsidiary of the Company was named as defendant in a lawsuit filed in district court for Harris County
in Texas involving a title dispute over a 1/16th mineral interest in the producing intervals of certain wells operated by us in the
Catherine Henderson “A” Unit in Liberty County in Texas. This case was subsequently transferred to the district court for Liberty
County, Texas and combined with a suit filed by other parties against the plaintiff claiming ownership of the disputed interest. The
plaintiff has alleged that, based on its interpretation of a series of 1972 deeds, it owns an additional 1/16th unleased mineral interest in
the producing intervals of these wells on which it has not been paid (this claimed interest is in addition to a 1/16th unleased mineral
interest on which it has been paid). We have made royalty payments with respect to the disputed interest in reliance, in part, upon
leases obtained from successors to the grantors under the aforementioned deeds, who claim to have retained the disputed mineral
interests thereunder. The plaintiff previously alleged damages of approximately $10.7 million although the plaintiff’s claim increases
as additional hydrocarbons are produced from the subject wells. We are vigorously defending this lawsuit and believe that we have
meritorious defenses. We believe if this matter were to be determined adversely, amounts owed to the plaintiff could be partially offset
by recoupment rights we may have against other working interest and/or royalty interest owners in the unit.
In connection with our Merger, several class action lawsuits were brought by Crimson stockholders in Delaware and Texas
seeking damages and injunctive relief. Each of these merger-related cases has now been dismissed by the respective court without
liability to the Company.
In February 2011, a subsidiary of the Company and certain of its working interest partners and insurance carriers brought suit
against a marine construction, dredging and tunneling company and an instrumentality of the United States of America in the U.S.
District Court for the Southern District of Texas – Houston Division seeking monetary damages for damage to an offshore pipeline
which was struck by a dredge. Following a bench trial in December 2013, the Company and its co-defendants obtained a favorable
judgment from the trial court. The defendants are appealing the trial court’s judgment to the U.S. Court of Appeals for the 5th Circuit.
While many of these matters involve inherent uncertainty and we are unable at the date of this filing to estimate an amount of
possible loss with respect to certain of these matters, we believe that the amount of the liability, if any, ultimately incurred with
respect to these proceedings or claims will not have a material adverse effect on our consolidated financial position as a whole or on
our liquidity, capital resources or future annual results of operations. We maintain various insurance policies that may provide
coverage when certain types of legal proceedings are determined adversely.
Item 4. Mine Safety Disclosures
Not applicable.
42
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Our common stock was listed on the NYSE MKT (previously the American Stock Exchange) in January 2001 under the
symbol “MCF”. The table below shows the high and low sales prices per share of our common stock for the periods indicated.
Year Ended December 31, 2014:
Quarter Ended March 31, 2014
Quarter Ended June 30, 2014
Quarter Ended September 30, 2014
Quarter Ended December 31, 2014
Year Ended December 31, 2013:
Quarter Ended March 31, 2013
Quarter Ended June 30, 2013
Quarter Ended September 30, 2013
Quarter Ended December 31, 2013
High
Low
$
$
$
$
$
$
$
$
50.44
49.28
42.98
38.96
46.05
40.49
40.06
48.80
$
$
$
$
$
$
$
$
40.09
39.08
32.80
28.07
36.27
33.50
33.22
36.46
From the period from January 1, 2015 to February 27, 2015, our common stock traded at prices between $23.17 and $33.17
per share.
General
The following descriptions are summaries of material terms of our common stock, preferred stock, certificate of
incorporation and bylaws. This summary is qualified by reference to our certificate of incorporation, bylaws and the designations of
our preferred stock, which are filed as exhibits to this report on Form 10-K, and by the provisions of applicable law.
Common Stock
We are authorized to issue up to 50 million shares of common stock. As of February 27, 2015, there were approximately 24.4
million shares of common stock issued and 19.2 million shares of common stock outstanding held by approximately 133 registered
shareholders. Approximately 0.1 million shares are in reserve for outstanding stock options under our 2005 Stock Incentive Plan,
which we adopted from Crimson in connection with the Merger.
Holders of common stock are entitled to one vote for each share held of record on each matter submitted to a vote of
stockholders and, in the event of liquidation, to share ratably in the distribution of assets remaining after payment of liabilities
(including preferential distribution and dividend rights of holders of preferred stock). Holders of common stock have no cumulative
rights. The holders of a plurality of the outstanding shares of the common stock have the ability to elect all of the directors.
Holders of common stock have no preemptive or other rights to subscribe for shares. Holders of common stock are entitled to
such dividends as may be declared by the board of directors out of funds legally available therefor. The Company paid a special one-
time dividend of $30.5 million, or $2 per share during the year ended December 31, 2012. Any decision to pay future dividends on our
common stock will be at the discretion of our board and will depend upon our financial condition, results of operations, capital
requirements, and other factors our board may deem relevant. We do not anticipate paying any cash dividends on our common stock
in the foreseeable future, as we currently intend to retain all future earnings to fund the development and growth of our business. Our
credit facility with Royal Bank of Canada and other lenders currently restricts our ability to pay cash dividends on our common stock,
and we may also enter into credit agreements or other borrowing arrangements in the future that restrict or limit our ability to pay cash
dividends on our common stock.
43
Preferred Stock
Our board of directors is authorized, without further stockholder action, to issue preferred stock in one or more series and to
designate the dividend rate, voting rights and other rights, preferences and restrictions of each such series. We are authorized to issue
up to five million shares of preferred stock. No preferred stock was outstanding at December 31, 2014.
Share-Based Compensation
The following table sets forth information about our equity compensation plans at December 31, 2014:
Plan Category
2009 Equity Compensation Plan - approved by
security holders
2005 Stock Incentive Plan (“Crimson Plan”)
Number of
securities to be issued upon
exercise of outstanding
options
Weighted-average
exercise price of
outstanding options
Number of securities remaining
available for future issuance
under equity
— $
$
129,934
—
53.85
1,143,006
7,030
Amended and Restated 2009 Incentive Compensation Plan
On September 15, 2009, the Company’s Board of Directors (the “Board”) adopted the Contango Oil & Gas Company Equity
Compensation Plan (the “Original 2009 Plan”), which was approved by shareholders on November 19, 2009. On April 10, 2014, the
Board amended and restated the Original 2009 Plan through the adoption of the Contango Oil & Gas Company Amended and Restated
2009 Incentive Compensation Plan (the “2009 Plan”), which was approved by shareholders on May 20, 2014. The 2009 Plan provides
for both cash awards and equity awards (such as restricted stock and options) to officers, directors, employees or consultants of the
Company. Awards made under the 2009 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as
may be determined by the Board.
Under the terms of the 2009 Plan, up to 1,500,000 shares of the Company’s common stock may be issued for plan awards.
Stock options issued under the 2009 Plan must have an exercise price of each option equal to or greater than the market price of the
Company’s common stock on the date of grant. The Company may grant officers and employees both incentive stock options intended
to qualify under Section 422 of the Internal Revenue Code of 1986, as amended, and stock options that are not qualified as incentive
stock options. Stock option grants to non-employees, such as directors and consultants, can only be stock options that are not qualified
as incentive stock options. Options granted generally expire after five or ten years. The vesting schedule varies, and can vest over a
two, three or four-year period.
During the year ended December 31, 2014, the Company granted 26,386 restricted stock awards under the 2009 Plan to
officers, employees and directors of the Company. Additionally, 7,230 restricted shares that were previously issued were canceled due
to employee terminations and are available to be reissued. During the year ended December 31, 2013, 312,838 restricted stock awards
were granted under the 2009 Plan to officers, employees and directors of the Company. Of this amount, 63,667 shares were fully
vested, of which 17,459 shares were withheld by the Company to satisfy certain officer's tax liability resulting from the vesting of
these shares, as provided in the restricted stock agreement, with the vested balance released to the officers. No shares of restricted
stock or stock options were issued during the year ended December 31, 2012, and as of December 31, 2012, there were no options or
restricted shares of common stock outstanding under the 2009 Plan.
Effective January 1, 2014, the Company implemented performance-based long-term bonus plans under the 2009 Plan for the
benefit of all employees through a Cash Incentive Bonus Plan (“CIBP”) and the Long-Term Incentive Plan (“LTIP”). The specific
targeted performance measures under theses sub-plans are approved by the Compensation Committee and/or the Board. Upon
achieving the performance levels established each year, bonus awards under the CIBP and LTIP will be calculated as a percentage of
base salary of each employee for the plan year. The CIBP and LTIP plan awards for each year are expected to be disbursed in the first
quarter of the following year. Employees must be employed by the Company at the time that awards are disbursed to be eligible.
The CIBP awards will be paid in cash while the LTIP awards will consist of restricted common stock and/or stock options.
The stock and/or option awards are expected to vest 25% per year, over the first through fourth anniversaries from the date of grant.
44
The number of shares of restricted common stock and the number of shares underlying the stock options granted will be determined
based upon the fair market value of the common stock on the date of the grant.
2005 Stock Incentive Plan
The 2005 Plan was adopted by the Company's Board in conjunction with the Merger with Crimson. Under the 2005 Plan, the
Board may grant incentive stock options, nonstatutory stock options, restricted awards, unrestricted awards, performance awards,
stock appreciation rights and dividend equivalent rights to officers, directors, employees or consultants of the Company and its
affiliates. Awards made under the 2005 Plan are subject to such terms and conditions, without limitation, as may be determined by the
Board. Options granted generally expire after ten years. The vesting schedule varies but generally vests over a one or four-year period.
Upon adoption of the 2005 Plan at the Merger closing date, a total of 135,898 stock option awards and 136,428 shares of restricted
stock (as converted, which all fully vested upon the Merger) were already issued and outstanding, leaving a balance of 43,472 shares
of common stock or stock options available to be granted to Company employees and directors.
During the year ended December 31, 2014, the Company did not issue any shares of restricted common stock under the 2005
Plan, but 4,165 stock options previously issued under the 2005 Plan were exercised, leaving 129,934 stock options vested and
exercisable at December 31, 2014. The exercise price for such options range from $25.70 to $60.33 per share, with an average
remaining contractual life of six years. As of December 31, 2014, there were 7,030 shares of common stock or stock options available
to be granted under the 2005 Plan. On February 24, 2015, the Company granted 7,030 restricted stock awards under the 2005 Plan to a
new employee. This plan expired on February 25, 2015.
During the year ended December 31, 2013, the Company issued 43,461 shares of restricted common stock to Company
employees under the 2005 Plan. These shares vest 25% each year over the four years following the date of the grant. Additionally, 791
stock options were exercised. No shares of restricted stock or stock options were issued during the year ended December 31, 2012.
Shortly after completion of the Merger, certain officers and employees sold 34,911 Contango shares with the total value of
$1.3 million back to the Company to satisfy the employees’ tax liability resulting from the vesting of their restricted shares on October
1, 2013. These shares were recognized in the Company balance sheet in Treasury Shares.
Share Repurchase Program
In September 2011, the Company’s board of directors approved a $50 million share repurchase program. All shares are to be
purchased in the open market from time to time by the Company or through privately negotiated transactions. The purchases are
subject to market conditions and certain volume, pricing and timing restrictions to minimize the impact of the purchases upon the
market. For the years ended December 31, 2014, 2013 and 2012, we purchased the following shares under the $50 million share
repurchase program:
Period
May 2012
June 2012
October 2012
November 2014
Total Number of Shares
Purchased
Average Price Paid
Per Share
Total Number of Shares
Purchased as Part of
Publicly Announced Program
Approximate Dollar Value
of Shares that may yet
be Purchased Under Program
36,098 $
28,620 $
97,496 $
205,457 $
53.56
51.92
50.82
35.89
71,761 $
100,381 $
197,877 $
403,334 $
45.7 million
44.2 million
39.2 million
31.8 million
Additionally, in February 2012, the Company net-settled 45,000 stock options from two officers. In October 2014, the
Company amended its revolving credit facility with Royal Bank of Canada to, among other things, allow for share repurchases under
certain circumstances.
45
Stock Performance Graph
The following graph compares the yearly percentage change from June 30, 2009 until December 31, 2014 in the cumulative
total stockholder return on our common stock to the cumulative total return on the S&P Smallcap 600 Index and a peer group of
companies consisting of Petroquest Energy, Inc., Swift Energy Company, Callon Petroleum, Energy XXI (Bermuda) Limited and
W&T Offshore, Inc.
Our common stock began trading on the NYSE MKT (previously American Stock Exchange) on January 19, 2001 and before
that had traded on the Nasdaq over-the-counter Bulletin Board. The graph assumes that a $100 investment was made in our common
stock and each index on December 31, 2009, adjusted for stock splits and dividends. The stock performance for our common stock is
not necessarily indicative of future performance.
Contango Oil & Gas Company
S&P Smallcap 600
Peer Group Composite
6/30/2009
100.00
100.00
100.00
6/30/2010
105.32
123.64
160.19
6/30/2011
137.54
169.41
296.29
6/30/2012
139.33
171.84
212.23
6/30/2013
83.59
215.10
165.17
12/31/2013
117.05
12/31/2014
72.42
261.60
200.29
276.66
66.85
46
Item 6. Selected Financial Data
On October 1, 2013 the Company's board of directors approved a change in fiscal year end from June 30 to December 31.
Unless otherwise noted, all references to "years" in this report refer to the twelve-month period which ends on December 31 of each
year. The following selected financial data for the year ended December 31, 2014 has been derived from the audited consolidated
financial statements of Contango contained in this Form 10-K. The following selected financial data for the years ended December 31,
2013, 2012 and 2011 have been derived from the audited consolidated financial statements of Contango contained in our Form 10-
K/A for the applicable fiscal year. The selected financial data for the year ended December 31, 2010 has not been audited. The
selected consolidated financial data (not including proved reserve information) set forth below is for continuing operations and should
be read in conjunction with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and
with the consolidated financial statements and notes to those consolidated financial statements included elsewhere in this Form 10-K.
Selected financial data for the year ended December 31, 2014 and 2013 includes results of operations and cash flows of
Crimson starting from October 1, 2013, the date of the Merger. Consolidated balance sheet and reserves information as of December
31, 2014 and 2013 include the balance sheet and reserves information of Crimson and its subsidiaries adjusted in accordance with the
acquisition method of accounting, which requires that assets acquired and liabilities assumed in the Merger be recorded at their fair
value at the date of acquisition with the difference between the purchase price and value of assets and liabilities be recorded as
goodwill. No goodwill was recognized as a result of the Merger between Contango and Crimson.
Selected financial information for the five years ended December 31, 2014 is as follows (dollars in thousands, except per
share amounts):
Natural gas and oil sales (1)
Income (loss) from continuing operations (2)
Discontinued operations, net of income taxes
Net income (loss) attributable to common stock
Net income (loss) per share:
Basic
Continuing operations
Discontinued operations
Total
Diluted
Continuing operations
Discontinued operations
Total
Weighted average shares outstanding:
Basic
Diluted
2014
2013
2012
2011
2010
Year Ended December 31,
$
$
$
$
$
$
$
276,458
$
164,121
(21,874) $
—
(21,874) $
41,362
—
41,362
(1.15) $
—
(1.15) $
(1.15) $
—
(1.15) $
2.56
—
2.56
2.56
—
2.56
$
$
$
$
$
$
$
145,868
$
198,498
(907) $
(29)
(936) $
69,909
(1,204)
68,705
(0.06) $
(0.00)
(0.06) $
(0.06) $
(0.00)
(0.06) $
4.49
(0.08)
4.41
4.49
(0.08)
4.41
(unaudited)
180,331
46,831
983
47,814
2.97
0.06
3.03
2.93
0.06
2.99
$
$
$
$
$
$
$
19,059
19,059
16,156
16,158
15,295
15,295
15,582
15,585
15,747
15,957
47
Year Ended December 31,
2014
2013
2012
2011
2010
(65,975) $
(33,162) $
100,901
188,529
62,552
Working capital (deficit) (3)
Capital expenditures
Cash dividends (4)
Long term debt (5)
Shareholders’ equity
Total assets
Proved Reserve Data:
Total proved reserves (Mmcfe) (6)
Pre-tax net present value (discounted 10%)
Standardized measure (6)
$
$
$
$
$
$
$
$
$
— $
$
$
— $
$
63,359
90,000
567,466
843,415
275,193
796,871
648,016
$
$
$
$
593,050
910,304
313,866
987,213
771,443
$
$
$
$
$
$
78,549
30,510
$
— $
$
(unaudited)
163,245
$
61,716
40,330
$
— $
— $
$
132,413
6
—
392,298
403,929
444,003
561,106
$
621,817
$
579,075
221,096
594,397
388,012
$
$
261,201
909,675
591,833
297,791
912,066
603,408
(1) The increase in natural gas and oil sales for the years ended December 31, 2014 and 2013 are attributable to the merger with Crimson.
(2) During the year ended December 31, 2014, we reached a total depth on our Ship Shoal 255 well, and no hydrocarbons were found. As a result, we recognized
$31.5 million in exploration expense for the cost of drilling the well and $15.6 million in impairment expense, including $3.5 million related to leasehold costs and
$12.1 million related to the platform located in Ship Shoal 263 block which was expected to be used by the Ship Shoal 255 had it been successful. Additionally,
during the year ended December 31, 2014, we revised estimated proved reserves for South Timbalier 17 and our Tuscaloosa Marine Shale properties, resulting in
non-cash impairment expenses of approximately $11.4 million. During the year ended December 31, 2014, we also recognized impairment expense of
approximately $20.1 million related to full or partial impairment of certain unproved properties due to expiring leases and leases not likely to be drilled.
During the year ended December 31, 2013 we completed a workover on our Vermilion 170 well at a cost of approximately $12.0 million. During the year ended
December 31, 2012, we drilled two unsuccessful exploratory wells resulting in exploration expenses of approximately $50.0 million, including leasehold costs.
Also during the year ended December 31, 2012, we revised estimated proved reserves at Ship Shoal 263, resulting in non-cash impairment expenses of
approximately $12.0 million.
(3) The increase in the working capital deficit for the year ended December 31, 2014 is primarily attributable to the decrease in trade receivable associated with the
decline in commodity prices during the fourth quarter of 2014. The decrease in working capital for the year ended December 31, 2013 is attributable to using all of
our cash reserves to pay down Crimson debt at the time of the Merger.
(4) On November 29, 2012, the board of directors declared a one-time special dividend of $2.00 per share of common stock which was paid on December 17, 2012.
(5) On October 1, 2013, in connection with the Merger, we entered into a revolving credit facility with Royal Bank of Canada and other lenders. The borrowing base
was reaffirmed on October 28, 2014. As of December 31, 2014, we had approximately $63.4 million outstanding under such facility.
(6) During the year ended December 31, 2014, our proved reserves decreased by approximately 38.7 Bcfe and our standardized measure decreased by approximately
$0.1 million. This decrease is primarily attributable to a 22.4 Bcfe negative revision of proved developed producing reserves at our Eugene Island 11 field and
normal production. The negative revision at Eugene Island 11 was due to a change in forecasted condensate yield and ultimate field abandonment pressure, as
determined by our third party engineers related to recent field performance.
During the year ended December 31, 2013, our proved reserves increased by approximately 92.8 Bcfe and our standardized measure increased by approximately
$383.4 million, primarily as a result of our merger with Crimson. Also contributing to the increase was the exercise of our preferential right to purchase
approximately 17.0 Bcfe related to our five Contango-operated Dutch wells, slightly offset by 28.2 Bcfe of production, a 19.2 Bcfe decrease in our Dutch and
Mary Rose reserve estimates based upon additional pressure data, and a 2.5 Bcfe decrease in our Vermilion 170 reserve estimates, as determined by our reservoir
engineer.
During the year ended December 31, 2012, our proved reserves decreased by approximately 40.1 Bcfe and our standardized measure decreased by approximately
$203.8 million. The major contributors to this decrease include normal production of 28.8 Bcfe during the year, a 9.2 Bcfe decrease in our Ship Shoal 263 reserve
estimates, and an 11.5 Bcfe decrease in our Vermilion 170 reserve estimates, slightly offset by an increase in our Dutch and Mary Rose reserve estimates, all as
determined by our reservoir engineer.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with
the financial statements and the related notes and other information included elsewhere in this report. On October 1, 2013 the
Company's Board of Directors approved a change in fiscal year end from June 30 to December 31. Unless otherwise noted, all
references to "years" in this report refer to the twelve-month period which ends on December 31 of each year. This Form 10-K covers
the three year period ended December 31, 2014.
48
Overview
We are a Houston, Texas based independent energy company engaged in the acquisition, exploration, development,
exploitation and production of crude oil and natural gas properties offshore in the shallow waters of the Gulf of Mexico (“GOM”) and
in the onshore Texas Gulf Coast and Rocky Mountain regions of the United States.
On October 1, 2013, we completed a merger with Crimson in an all-stock transaction pursuant to which Crimson became a
wholly-owned subsidiary of Contango. The merger with Crimson gave us access to high rate of return onshore prospects in known,
prolific producing areas as well as long-life resource plays. In 2014, our drilling activity focused primarily on the Woodbine oil and
liquids-rich play in Madison and Grimes counties, Texas (our Southeast Texas Region), on the Buda Limestone oil and liquids-rich
play in Zavala and Dimmit counties, Texas (our South Texas Region), in the Cretaceous Sands in Fayette and Gonzales counties,
Texas (also in our South Texas Region) and the late 2014/early 2015 commencement of drilling on our new acreage position in
Wyoming where we are targeting the Mowry Shale and the Muddy Sandstone formations. We believe these areas provide long-term
growth potential from multiple formations that we believe to be productive for oil and natural gas.
Additionally, we have (i) a 37% equity investment in Exaro Energy III LLC (“Exaro”) that is primarily focused on the
development of proved natural gas reserves in the Jonah Field in Wyoming; (ii) leasehold positions and minor non-operated producing
properties in Louisiana and Mississippi targeting the Tuscaloosa Marine Shale (“TMS”); (iii) operated properties producing from
various conventional formations in various counties along the Texas Gulf Coast; (iv) operated producing properties in the Denver
Julesburg Basin (“DJ Basin”) in Weld and Adams counties in Colorado, which we believe may also be prospective in the Niobrara
Shale oil play; (v) operated producing properties in the Haynesville Shale, Mid Bossier and James Lime formations in East Texas; and
(vi) six exploratory prospects in the shallow waters of the GOM.
Our production for the year ended December 31, 2014 was approximately 40.3 Bcfe (or 110.5 Mmcfed) and was 61%
offshore and 39% onshore. Our production for the three months ended December 31, 2014 was approximately 9.8 Bcfe (or 106.2
Mmcfed) and was 64% offshore and 36% onshore. As of December 31, 2014, our proved reserves were approximately 52% offshore
and 48% onshore and were 76% proved developed, which were approximately 69% offshore and 31% onshore.
Revenues and Profitability
Our revenues, profitability and future growth depend substantially on our ability to find, develop and acquire natural gas and
oil reserves that are economically recoverable, as well as prevailing prices for natural gas and oil.
Reserve Replacement
Generally, producing properties offshore in the Gulf of Mexico have high initial production rates, followed by steep declines.
Likewise, initial production rates on new wells in the onshore resource plays start out at a relatively high rate with a decline curve
which results in 60% to 70% of the ultimate recovery of present value occurring in the first eighteen months of the well’s life. We
must locate and develop, or acquire, new natural gas and oil reserves to replace those being depleted by production. Substantial capital
expenditures are required to find, develop and/or acquire natural gas and oil reserves. The Merger with Crimson allowed the Company
to add significant proved developed and undeveloped reserves (see “Item 2. Properties”, for details of reserves acquired) and provided
the Company with access to several onshore resource plays which have substantial reserve growth potential, including in oil and
liquids rich plays that position us to move to a more balanced oil/gas profile.
Use of Estimates
The preparation of our financial statements requires the use of 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 periods. Actual results could differ from those estimates. Significant estimates with
regard to these financial statements include estimates of remaining proved natural gas and oil reserves, the timing and costs of our
future drilling, development and abandonment activities, and income taxes.
49
Related Party Transactions
The Company has historically relied on Juneau Exploration L.P. (“JEX”) and REX to generate its offshore and onshore
domestic natural gas and oil prospects. In addition to generating new prospects, JEX occasionally evaluated offshore and onshore
exploration prospects generated by third-party independent companies for us to purchase. With the merger with Crimson, and the
technical team obtained in the merger, the Company will be more active in identifying drilling opportunities through efforts of its own
personnel. See Note 17 to our Financial Statements - "Related Party Transactions" for a detailed description of our transactions with
JEX and REX.
See “Risk Factors” on page 18 for a more detailed discussion of a number of other factors that affect our business, financial
condition and results of operations.
Results of Operations
The table below sets forth our average net daily production data in Mmcfed from our fields for each of the periods indicated:
March 31,
2013
June 30, 2013
September 30,
2013
December 31,
2013
March 31,
2014
June 30, 2014
September 30,
2014
December 31,
2014
Three Months Ended
Offshore GOM
Dutch and Mary Rose
Vermilion 170
Other offshore (1)
Southeast Texas (2)
South Texas (2)
Other (2)(3)
59.5
3.6
1.5
—
—
—
64.6
57.2
4.0
1.0
—
—
—
62.2
61.7
9.6
0.7
—
—
—
72.0
59.1
9.6
0.8
24.3
14.7
1.7
110.2
66.7
9.0
0.4
26.4
12.6
2.4
117.5
60.9
7.2
0.6
27.1
16.0
4.2
116.0
42.3
8.0
5.2
26.6
17.4
2.8
102.3
55.9
5.7
6.5
23.6
12.2
2.3
106.2
(1) The “Other offshore” line includes Ship Shoal 263 and South Timbalier 17.
(2)
“Southeast Texas”, “South Texas” and “Other” production are not included in the table above for periods prior to quarter ended December 31, 2013, as a result of
acquiring these producing properties effective October 1, 2013 through the Merger.
(3) The “Other” line includes onshore wells in East Texas, Louisiana, Mississippi and Colorado for periods after the quarter ended September 30, 2013.
The table below sets forth our pro forma average net daily production data in Mmcfed from our fields for each of the periods
indicated as if the Merger took place on January 1, 2013:
March 31,
2013
June 30, 2013
September 30,
2013
December 31,
2013
March 31,
2014
June 30, 2014
September 30,
2014
December 31,
2014
Three Months Ended
Offshore GOM
Dutch and Mary Rose
Vermilion 170
Other offshore (1)
Southeast Texas
South Texas
Other (2)
59.5
3.6
1.5
19.7
13.9
2.3
57.2
4.0
1.0
27.9
14.2
2.1
61.7
9.6
0.7
25.4
13.0
1.9
59.1
9.6
0.8
24.3
14.7
1.7
66.7
9.0
0.4
26.4
12.6
2.4
60.9
7.2
0.6
27.1
16.0
4.2
42.3
8.0
5.2
26.6
17.4
2.8
55.9
5.7
6.5
23.6
12.2
2.3
100.5
106.4
112.3
110.2
117.5
116.0
102.3
106.2
(1) The “Other offshore” line includes Ship Shoal 263 and South Timbalier 17.
(2) The “Other” line includes onshore wells in East Texas, Louisiana, Mississippi and Colorado.
50
Vermilion 170 Well
In January 2013, we identified sustained casing pressure between the production tubing and the production casing at our
Vermilion 170 well. Diagnostic tests revealed that the production tubing had parted downhole requiring a workover of the well. Well
production was shut-in and the original tubing and completion assembly were successfully removed. Operations were conducted to
replace the tubing and restore the well, which resumed production in June 2013. During December 2014, our Vermilion 170 well
production was shut-in for fourteen days due to issues with the Sea Robin Pipeline, our third-party transporter.
Other Offshore
For all of the periods presented, Other offshore includes our Ship Shoal 263 well for all periods presented and South
Timbalier 17 for the quarters ended September 30, 2014 and December 31, 2014, as it commenced production in July 2014.
Production at Ship Shoal 263 has been negatively impacted since 2011 by overheating, scaling problems, and water production. The
well has also been shut-in several times for production logging and chemical treatment.
Southeast Texas
For the quarter ended December 31, 2013, Southeast Texas production averaged approximately 24.3 Mmcfed. Crimson, and
subsequently Contango, actively developed this area during 2013, focusing on the horizontal development of the Woodbine formation
in Madison and Grimes counties. During 2013, Crimson, and then Contango, drilled 12 gross (eight net) wells on acreage targeting the
Woodbine formation. During 2014, Contango drilled 18 gross (11.6 net) wells on acreage targeting the Woodbine formation.
South Texas
For the quarter ended December 31, 2013, South Texas production averaged approximately 14.7 Mmcfed. During 2013,
Crimson, and then Contango drilled six gross operated wells (three net) and one gross non-operated well (0.25 net) in the Buda
formation in Zavala and Dimmit counties. During 2014, Contango drilled 14 gross operated wells (6.8 net) in the Buda formation,
which are all on production. We drilled one additional well during the fourth quarter of 2014 as a vertical pilot well to test the viability
of the Eagle Ford and other formations in Zavala and Dimmit counties. We are evaluating the recovered cores before deciding on a rig
and development strategy for these areas.
51
Year Ended December 31, 2014 Compared to Year Ended December 31, 2013; and Year Ended December 31, 2013
Compared to Year Ended December 31, 2012
The table below sets forth revenue, production data, average sales prices and average production costs associated with our
sales of natural gas, oil and natural gas liquids ("NGLs") from continuing operations for the years ended December 31, 2014, 2013 and
2012. Oil, condensate and NGLs are compared with natural gas in terms of cubic feet of natural gas equivalents. One barrel of oil,
condensate or NGL is the energy equivalent of six Mcf of natural gas. Reported lease operating expenses include production taxes,
such as ad valorem and severance. Information for the year ended December 31, 2013 includes twelve months of Contango activity
(January - December) and three months of post-merger Crimson activity (October - December).
Year Ended December 31,
Year Ended December 31,
2014
2013
%
2013
2012
%
Revenues:
(thousands)
(thousands)
Oil and condensate sales
$
130,238
$
59,608
118 % $
59,608
$
56,237
Natural gas sales
NGL sales
Total revenues
112,695
33,525
79,289
25,224
42 %
33 %
79,289
25,224
60,691
28,940
$
276,458
$ 164,121
68 % $ 164,121
$ 145,868
Production:
Oil and condensate (thousand barrels)
Dutch and Mary Rose
Vermilion 170
Southeast Texas
South Texas
Other
Total oil and condensate
Natural gas (million cubic feet)
Dutch and Mary Rose
Vermilion 170
Southeast Texas
South Texas
Other
Total natural gas
Natural gas liquids (thousand barrels)
Dutch and Mary Rose
Vermilion 170
Southeast Texas
South Texas
Other
Total natural gas liquids
Total (million cubic feet equivalent)
Dutch and Mary Rose
Vermilion 170
Southeast Texas
South Texas
Other
Total production
(16)%
(3)%
359 %
255 %
115 %
138 %
(4)%
16 %
270 %
308 %
509 %
25 %
(3)%
— %
361 %
377 %
267 %
49 %
(5)%
11 %
324 %
294 %
341 %
43 %
220
37
734
337
73
1,401
16,257
2,108
3,234
2,541
1,735
262
38
160
95
34
589
17,018
1,823
875
623
285
25,875
20,624
501
68
304
124
11
1,008
514
68
66
26
3
677
20,578
21,674
2,738
9,461
5,309
2,237
2,459
2,231
1,349
507
40,323
28,220
52
6 %
31 %
(13)%
13 %
(13)%
(65)%
100 %
100 %
(64)%
16 %
(47)%
100 %
100 %
(79)%
(5)%
2 %
(52)%
100 %
100 %
(81)%
3 %
(1)%
(50)%
100 %
100 %
(75)%
(2)%
16,954
*
262
38
160
95
34
589
17,018
1,823
875
623
285
20,624
514
68
66
26
3
677
302
110
—
—
95
507
3,449
—
—
1,347
21,750
503
141
—
—
16
660
21,674
21,784
2,459
2,231
1,349
507
28,220
4,955
—
—
2,013
28,752
Year Ended December 31,
Year Ended December 31,
2014
2013
%
2013
2012
%
(14)%
— %
18 %
(10)%
100 %
6 %
(5)%
16 %
(6)%
3 %
161 %
2 %
— %
— %
14 %
— %
100 %
8 %
(5)%
12 %
7 %
(1)%
130 %
2 %
0.7
0.1
1.7
1.0
0.1
3.6
46.6
5.0
9.5
6.8
1.8
69.7
1.4
0.2
0.7
0.3
—
2.6
59.4
6.7
24.3
14.7
2.7
107.8
Daily Production:
Oil and condensate (thousand barrels per day)
Dutch and Mary Rose
Vermilion 170
Southeast Texas
South Texas
Other
Total oil and condensate
Natural gas (million cubic feet per day)
Dutch and Mary Rose
Vermilion 170
Southeast Texas
South Texas
Other
Total natural gas
Natural gas liquids (thousand barrels per day)
Dutch and Mary Rose
Vermilion 170
Southeast Texas
South Texas
Other
Total natural gas liquids
Total (million cubic feet equivalent per day)
Dutch and Mary Rose
Vermilion 170
Southeast Texas
South Texas
Other
Total production
Average Sales Price:
Oil and condensate (per barrel)
Natural gas (per thousand cubic feet)
Natural gas liquids (per barrel)
Total (per thousand cubic feet equivalent)
Expenses (thousands):
Operating expenses
Exploration expenses
Depreciation, depletion and amortization
Impairment and abandonment of oil and gas
ti
General and administrative expenses
Gain from investment in affiliates (net of taxes)
Loss (gain) from sale of assets and other expense
(income)
$
$
$
$
$
$
$
$
$
$
$
0.6
0.1
2.0
0.9
0.2
3.8
44.5
5.8
8.9
7.0
4.7
70.9
1.4
0.2
0.8
0.3
0.1
2.8
56.4
7.5
25.9
14.5
6.2
0.7
0.1
1.7
1.0
0.1
3.6
46.6
5.0
9.5
6.8
1.8
69.7
1.4
0.2
0.7
0.3
—
2.6
59.4
6.7
24.3
14.7
2.7
110.5
107.8
92.98
4.36
33.27
6.86
47,236
33,387
156,117
47,693
34,045
6,923
$
$
$
$
$
$
$
$
$
$
101.21
3.84
37.26
5.82
36,784
1,811
65,529
776
26,512
2,310
(8)% $
101.21
13 % $
(11)% $
18 % $
3.84
37.26
5.82
28 % $
36,784
**
$
1,811
138 % $
65,529
**
$
776
28 % $
26,512
200 % $
2,310
$
$
$
$
$
$
$
$
$
$
110.92
2.79
43.85
5.07
23,720
51,903
44,896
14,079
11,265
60
(2,687) $ (29,482)
(91)% $ (29,482) $
367
53
0.8
0.3
—
—
0.3
1.4
(13)%
(67)%
100 %
100 %
(67)%
157 %
46.4
*
9.4
—
—
3.7
59.5
1.4
0.4
—
—
—
1.8
59.7
13.6
—
—
5.5
78.8
(47)%
100 %
100 %
(51)%
17 %
— %
(50)%
100 %
100 %
— %
44 %
(1)%
(51)%
100 %
100 %
(51)%
37 %
(9)%
38 %
(15)%
15 %
55 %
(97)%
46 %
(94)%
135 %
**
**
Year Ended December 31,
Year Ended December 31,
2014
2013
%
2013
2012
%
$
$
$
1.17
0.84
3.87
$
$
$
1.30
0.94
2.32
(10)% $
(10)% $
67 % $
1.30
0.94
2.32
$
$
$
0.82
0.39
1.56
59 %
141 %
49 %
Selected data per Mcfe:
Operating expenses
General and administrative expenses
Depreciation, depletion and amortization
*
Less than 1%
** Greater than 1,000%
Natural Gas, Oil and NGL Sales and Production
All of our revenues are from the sale of our natural gas, oil and natural gas liquids production. Our revenues may vary
significantly from year to year depending on changes in commodity prices, which fluctuate widely, and production volumes. Our
production volumes are subject to wide swings as a result of new discoveries, weather and mechanical related problems. In addition,
the production rate associated with our oil and gas properties declines over time as we produce our reserves.
We reported revenues of approximately $276.5 million for the year ended December 31, 2014, compared to revenues of
approximately $164.1 million for the year ended December 31, 2013. This increase in revenues was primarily attributable to our
merger with Crimson, to additional interests purchased in our Dutch wells in December 2013, to production from our South Timbalier
17 discovery which began producing in July 2014, and to new natural gas, oil, condensate and NGL production from our 2014 drilling
program, partially offset by lower oil, condensate and NGL prices. Revenue for 2013 was also negatively impacted by our Vermilion
170 well shut-in for approximately half of 2013 for workover.
Our net natural gas production for the year ended December 31, 2014 was approximately 70.9 Mmcfd, up from
approximately 69.7 Mmcfd for the year ended December 31, 2013. Additionally, net oil production increased from 3,600 barrels per
day to 3,800 barrels per day, while NGL production increased from approximately 2,600 barrels per day to 2,800 barrels per day. In
total, equivalent production increased from 107.8 Mmcfed to 110.5 Mmcfed. This increase in natural gas, oil and NGL production was
primarily attributable to our merger with Crimson, our 2014 drilling program, the resumption of production at Vermillion 170 and the
additional interests in our Dutch well discussed above. This increase was partially offset by a decrease in production attributable to the
shut-in for approximately three weeks and subsequent ramp up during the third quarter 2014 to install compression for the Dutch and
Mary Rose wells.
We reported revenues of approximately $164.1 million for the year ended December 31, 2013, compared to revenues of
approximately $145.9 million for the year ended December 31, 2012. This increase in revenues was primarily attributable to increased
natural gas, oil, condensate and NGL production due to our merger with Crimson, offset by decreased production from our Vermilion
170 well, which was shut-in for approximately half of 2013, further aided by a higher average equivalent sales price received for the
period.
Our net natural gas production for the year ended December 31, 2013 was approximately 69.7 Mmcfd, up from
approximately 59.5 Mmcfd for the year ended December 31, 2012. Additionally, net oil production increased from 1,400 barrels per
day to 3,600 barrels per day, while NGL production increased from approximately 1,800 barrels per day to 2,600 barrels per day. In
total, equivalent production increased from 78.8 Mmcfed to 107.8 Mmcfed. This increase in natural gas, oil and NGL production was
attributable to our merger with Crimson.
Average Sales Prices
For the year ended December 31, 2014, the price of natural gas was $4.36 per Mcf while the price for oil and NGLs was
$92.98 per barrel and $33.27 per barrel, respectively. For the year ended December 31, 2013, the price of natural gas was $3.84 per
Mcf while the prices for oil and NGLs were $101.21 per barrel and $37.26 per barrel, respectively. For the year ended December 31,
2012, the price of natural gas was $2.79 per Mcf while the prices for oil and NGLs were $110.92 per barrel and $43.85 per barrel,
respectively.
54
Operating Expenses (including production taxes)
Operating expenses for the year ended December 31, 2014 were approximately $47.2 million, which included approximately
$27.3 million of lease operating expenses, $11.5 million of production and ad valorem taxes, $5.8 million related to transportation and
processing costs and $2.6 million of workover costs. Recurring lease operating expenses are higher than 2013 due to the increased
operational activity as a result of our merger with Crimson.
Operating expenses for the year ended December 31, 2013 were approximately $36.8 million, which included approximately
$15.8 million of lease operating expenses, $4.7 million of production and severance taxes, $4.3 million related to transportation and
processing costs and $12.0 million in workover costs for Vermilion 170. Recurring lease operating expenses are higher than 2012 due
to the increased operational activity as a result of our merger with Crimson.
Operating expenses for the year ended December 31, 2012 were approximately $23.7 million, which included approximately
$14.2 million of lease operating expense, $3.6 million of production and severance taxes, $4.1 million related to transportation and
processing costs and $1.8 million in workover costs.
Exploration Expenses
We reported approximately $33.4 million of exploration expenses for the year ended December 31, 2014, compared to $1.8
million for the year ended December 31, 2013. The higher costs incurred in 2014 include $31.5 million related to our dry hole at Ship
Shoal 255 and $1.9 million for geological and geophysical activities, seismic data and delay rentals.
We reported approximately $1.8 million of exploration expenses for the year ended December 31, 2013, compared to $51.9
million for the year ended December 31, 2012. The costs incurred in 2012 included $50.0 million for dry holes at Ship Shoal 134 and
South Timbalier 75, $1.4 million related to an unsuccessful drilling program in Jim Hogg County, Texas and $0.3 million for
geological and geophysical activities, seismic data and delay rentals.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for the fiscal year ended December 31, 2014 was approximately $156.1 million.
This compares to approximately $65.5 million for the year ended December 31, 2013, an increase primarily attributable to the
expanded asset base subsequent to our merger with Crimson, which contributed $105.8 million to this expense for the twelve month
period ended December 31, 2014.
Depreciation, depletion and amortization for the fiscal year ended December 31, 2013 was approximately $65.5 million. This
compares to approximately $44.9 million for the year ended December 31, 2012. The increase in depreciation, depletion and
amortization was primarily attributable to increased production as a result of our merger with Crimson.
Impairment of Natural Gas and Oil Properties
Impairment expenses for the year ended December 31, 2014 included producing property impairments of $7.7 million for
South Timbalier 17 and $3.7 million for TMS proved properties due to performance and commodity price declines in 2014, $3.5
million impairment of unproved leasehold cost related to the dry hole on our Ship Shoal 255 block and $12.1 million for impairment
of an existing platform which was expected to be used by the Ship Shoal 255 well if it had been successful. Impairment expenses for
the year ended December 31, 2014 also included a $20.1 million impairment charge for certain unproved prospects due to expiring
leases and leases not likely to be drilled, primarily related to GOM leases and unproved TMS leases.
For the year ended December 31, 2013, the Company recorded impairment expense of approximately $0.8 million, related to
leasehold costs on our Ship Shoal 83 prospect which we relinquished in August 2013, and leasehold costs on our Brazos Area 543
prospect.
For the year ended December 31, 2012, the Company recorded impairment expense of approximately $14.1 million. Of this
amount, approximately $12.0 million related to our Ship Shoal 263 well and $2.1 million related to the Eugene Island 24 platform and
other properties.
55
General and Administrative Expenses
General and administrative expenses for the year ended December 31, 2014 were approximately $34.0 million, compared to
$26.5 million for the year ended December 31, 2013. Major components of general and administrative expenses for the year ended
December 31, 2014 included approximately $20.3 million in salaries and benefits ($4.5 million of which was non-cash stock based
compensation) and $5.5 million in accounting, legal, tax and professional services.
General and administrative expenses for the year ended December 31, 2013 were approximately $26.5 million, compared to
$11.3 million for the year ended December 31, 2012. Major components of general and administrative expenses for the year ended
December 31, 2013 included approximately $12.1 million in salaries and benefits ($3.2 million of which was non-cash stock based
compensation), $6.3 million in accounting, legal, tax and professional services and $3.9 million attributable to the merger with
Crimson.
General and administrative expenses for the year ended December 31, 2012 were approximately $11.3 million. Major
components of general and administrative expenses for the year ended December 31, 2012 included approximately $5.6 million in
salaries and benefits and $3.3 million in accounting, legal, tax and professional services.
Gain from Affiliates
For the year ended December 31, 2014, the Company recorded a gain from affiliates of approximately $6.9 million, net of
taxes of $3.8 million, related to our investment in Exaro.
For the year ended December 31, 2013, the Company recorded a gain from affiliates of approximately $2.3 million, net of
taxes of $1.2 million, related to our investment in Exaro.
Loss (gain) from sale of assets and other expense (income)
A loss from the sale of assets and other expenses for the year ended December 31, 2014 was approximately $2.7 million,
which is primarily related to interest expense.
A gain from the sale of assets and other expenses for the year ended December 31, 2013 was approximately $29.5 million,
which consisted of $15.3 million gain related to our equity investment in Alta Resources, Inc., a $6.6 million gain related to the
disposition of a minority interest in all developed and undeveloped properties in Madison and Grimes counties, and included the
proceeds of a $10 million life insurance policy for the Company's former Chairman, President and Chief Executive Officer, Mr.
Kenneth Peak, who passed away on April 19, 2013.
Capital Resources and Liquidity
Our primary cash requirements are for capital expenditures, working capital, operating expenses, acquisitions and principal
and interest payments on indebtedness. Our primary sources of liquidity are cash generated by operations, net of the realized effect of
our hedging agreements, and amounts available to be drawn under our credit facility.
The table below summarizes certain measures of liquidity and capital expenditures, as well as our sources of capital from
internal and external sources, for the periods indicated, in thousands.
Net cash provided by operating activities
Net cash used in investing activities
Net cash used in financing activities
Cash and cash equivalents at the end of the period
Year ended December 31,
2014
2013
2012
$
$
$
$
209,960
(175,057)
(34,903)
$
$
$
— $
105,037
(34,795)
(149,729)
$
$
$
— $
90,122
(123,945)
(38,630)
79,487
Cash flow from operating activities provided approximately $210.0 million in cash for the year ended December 31, 2014
compared to $105.0 million for the year ended December 31, 2013. This increase in cash provided by operating activities was
primarily attributable to our merger with Crimson.
56
Cash flow from operating activities provided approximately $105.0 million in cash for the year ended December 31, 2013
compared to $90.1 million for the year ended December 31, 2012. This increase in cash provided by operating activities was primarily
attributable to our merger with Crimson, as well as not having any taxes due for the year ended December 31, 2013.
Cash used in investing activities was approximately $175.1 million in cash for the year ended December 31, 2014, which
included approximately $180.4 million for capital expenditures, partially offset by approximately $5.4 million related to the sale of
assets and distributions from affiliates.
Cash used in investing activities was approximately $34.8 million in cash for the year ended December 31, 2013, which
included approximately $62.6 million for capital expenditures and approximately $15.4 million for investments in affiliates, partially
offset by approximately $43.2 million related to the sale of assets and distributions from affiliates.
Cash used in investing activities was approximately $123.9 million in cash for the year ended December 31, 2012, which
included approximately $78.5 million for capital expenditures, approximately $54.8 million for investments in affiliates, partially
offset by $9.0 million related to sale of assets and distributions from affiliates.
Cash used in financing activities was approximately $34.9 million for the year ended December 31, 2014 compared to $149.7
million used in financing activities in 2013. This decrease in cash used in financing activities was primarily attributable to the payment
of Crimson's existing debt upon closing of the Merger, partially offset by borrowings under our RBC Credit Facility (defined below).
Cash used in financing activities was approximately $149.7 million for the year ended December 31, 2013 compared to $38.6
million used in financing activities in 2012. This increase in cash used in financing activities was primarily attributable to the payment
of Crimson's existing debt upon closing of the Merger, partially offset by borrowings under our RBC Credit Facility (defined below).
Credit Facility
In connection with the Merger, the Company assumed and immediately repaid Crimson’s $175.0 million second lien term
loan with Barclays Bank PLC ("Barclays") and other lenders, and Crimson’s $58.6 million senior secured revolving credit facility
with Wells Fargo and other lenders, which included $1.8 million in accrued interest and prepayment premiums. In order to refinance
the assumed debt, the Company entered into a $500 million four-year revolving credit facility with Royal Bank of Canada and other
lenders (the “RBC Credit Facility”) with an initial hydrocarbon-supported borrowing base of $275 million, which was reaffirmed on
October 28, 2014 and is effective through May 1, 2015. The borrowing base under our RBC Credit Facility is redetermined each
November 1 and May 1. The RBC Credit Facility replaced the Company's $40 million facility with Amegy Bank. The Company
incurred $2.2 million of arrangement and upfront fees in connection with the RBC Credit Facility. Proceeds of the RBC Credit Facility
were, or may be used (i) to finance working capital and for general corporate purposes, (ii) for permitted acquisitions, and (iii) to
finance transaction expenses in connection with the RBC Credit Facility and the Merger. The RBC Credit Facility is collateralized by
substantially all of the assets of the Company and its subsidiaries. Borrowings under the RBC Credit Facility bear interest at a rate that
is dependent upon LIBOR or the U.S. prime rate of interest, plus a margin dependent upon the amount outstanding.
On October 1, 2013, the $235.4 million of assumed debt, accrued interest, the prepayment premium and $2.2 million of
arrangement and upfront fees under the RBC Credit Facility were paid with the Company's existing cash of $127.6 million and
drawings under our RBC Credit Facility of $110.0 million.
On October 28, 2014, the Company entered into a second amendment to the RBC Credit Facility, which reduces the effective
interest rate on borrowings and provides for the repurchase by the Company of common shares under its 2011 Share Repurchase Plan,
subject to certain limitations. As of December 31, 2014, we had $63.4 million outstanding under the RBC Credit Facility. As of
February 27, 2015, we had $86.0 million outstanding under the RBC Credit Facility.
The RBC Credit Facility requires us to maintain compliance with specified financial ratios. Our compliance with these
covenants is tested each quarter. At December 31, 2014, we were in compliance with the covenants under the RBC Credit Facility.
See Note 13 to our Financial Statements -“Long-Term Debt” for a more detailed description of terms and provisions of our credit
agreement.
57
Future Capital Requirements
Our future crude oil, natural gas and natural gas liquids reserves and production, and therefore our cash flow and results of
operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding
or acquiring additional recoverable reserves. We intend to grow our reserves and production by further exploiting our existing
property base through drilling opportunities in our resource plays and in our conventional onshore inventory in the Texas Gulf Coast,
with activity in any particular area to be a function of market and field economics. We anticipate that acquisitions, including those of
undeveloped leasehold interests, will continue to play a role in our business strategy as those opportunities arise from time to time.
There can be no assurance that we will invest, or that any investment entered into will be successful. These potential acquisitions are
not part of our current capital budget and would require additional capital. Natural gas and oil prices continue to be volatile and our
financial resources may be insufficient to fund any of these opportunities. While there are currently no unannounced agreements for
the acquisition of any material businesses or assets, such transactions can be effected quickly and could occur at any time.
We believe that our internally generated cash flow, combined with availability under our RBC Credit Facility will be
sufficient to meet the liquidity requirements necessary to fund our daily operations and planned capital development and to meet our
debt service requirements for the next twelve months. We currently plan to limit our 2015 capital expenditures to a level within our
forecasted cash flow from operations for the year; however, we do possess the capacity, through forecasted excess cash flow and
through our RBC Credit Facility, to increase and/or accelerate drilling on any particular area should we determine that market and
project economics so warrant. Our ability to execute on our growth strategy will be determined, in large part, by our cash flow and the
availability of debt and equity capital at that time. Any decision regarding a financing transaction, and our ability to complete such a
transaction, will depend on prevailing market conditions and other factors.
Our 2015 capital budget is currently forecasted to be approximately $50.6 million, exclusive of acquisitions, if any, and due
to the current commodity price environment will be focused primarily on: (i) the preservation of our strong and flexible financial
position, including limiting our overall capital expenditure budget to no more than internally generated cash flow; (ii) focusing drilling
expenditures on strategic projects; (iii) identification of opportunities for cost efficiencies in all areas of our operations; and (iv)
continuing to identify and, when appropriate, pursue new resource potential opportunities, internally and through acquisition. Our
current capital budget for 2015 should allow us to meet our contractual requirements, remain in position to preserve our term acreage
where appropriate and maintain our already strong financial profile. We will continuously monitor the commodity price environment,
stability and forecast, and if warranted, make adjustments to our investment strategy as the year progresses.
Inflation and Changes in Prices
While the general level of inflation affects certain costs associated with the energy industry, factors unique to the industry
result in independent price fluctuations. Such price changes have had, and will continue to have, a material effect on our operations;
however, we cannot predict these fluctuations.
Income Taxes
During the years ended December 31, 2014, 2013 and 2012, we paid approximately $0.2 million, $0.3 million and
$24.3 million, respectively, in federal and state income taxes, net of cash refunds received.
58
Contractual Obligations
The following table summarizes our known contractual obligations as of December 31, 2014:
Payment due by period (thousands)
Total
Less than
1 year
1 - 3 years
3 - 5 years
Long term debt and interest (1)
$
66,770
$
1,241
$
65,529
$
Delay rentals
Asset retirement obligations
Employment agreements
Operating leases (2)
Drilling Rig (3)
Uncertain income tax positions (4)
589
25,746
4,017
9,494
6,624
518
243
4,123
2,570
3,624
6,624
—
346
2,875
1,447
3,760
—
—
— $
—
1,405
—
2,110
—
—
More than
5 years
—
—
17,343
—
—
—
518
Total
$
113,758
$
18,425
$
73,957
$
3,515
$
17,861
(1) Estimated interest is based on the outstanding debt at December 31, 2014 using the interest rate in effect at that time.
(2) Operating leases include contracts related to office space, compressors, vehicles, office equipment and other. Operating lease commitments from our previous
office space are expected to be substantially recovered by the subleases that we have entered into for the remainder of our lease term.
(3) Relates to a contract for an active drilling rig.
(4) We cannot predict at this time when, or if, this obligation may be required to be paid.
In addition to the above, we have also committed to invest up to an additional $20.6 million in Exaro.
Application of Critical Accounting Policies and Management’s Estimates
The discussion and analysis of the Company’s financial condition and results of operations is based upon the consolidated
financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The
preparation of these consolidated financial statements requires the Company to make estimates and judgments that affect the reported
amounts of assets, liabilities, revenues and expenses. The Company’s significant accounting policies are described in Note 2 of Not es
to Consolidated Financial Statements included as part of this Form 10-K. We have identified below the policies that are of particular
importance to the portrayal of our financial position and results of operations and which require the application of significant
judgment by management. The Company analyzes its estimates, including those related to natural gas and oil reserve estimates, on a
periodic basis and bases its estimates on historical experience, independent third party reservoir engineers and various other
assumptions that management believes to be reasonable under the circumstances. Actual results may differ from these estimates under
different assumptions or conditions. The Company believes the following critical accounting policies affect its more significant
judgments and estimates used in the preparation of the Company’s consolidated financial statements:
Oil and Gas Properties - Successful Efforts
Our application of the successful efforts method of accounting for our natural gas and oil exploration and production
activities requires judgments as to whether particular wells are developmental or exploratory, since exploratory costs and the costs
related to exploratory wells that are determined to not have proved reserves must be expensed whereas developmental costs are
capitalized. The results from a drilling operation can take considerable time to analyze, and the determination that commercial
reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are
assumed to be productive and actually deliver natural gas and oil in quantities insufficient to be economic, which may result in the
abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both
developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results.
Delineation seismic costs incurred to select development locations within a productive natural gas and oil field are typically treated as
development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas and therefore
management must estimate the portion of seismic costs to expense as exploratory. The evaluation of natural gas and oil leasehold
acquisition costs included in unproved properties requires management's judgment of exploratory costs related to drilling activity in a
given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.
59
Reserve Estimates
While we are reasonably certain of recovering our reported reserves, the Company’s estimates of natural gas and oil reserves
are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such
data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a
subjective process of estimating underground accumulations of natural gas and oil that are difficult to measure. The accuracy of any
reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of
economically recoverable natural gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors
and assumptions, such as historical production from the area compared with production from other producing areas, the assumed
effect of regulations by governmental agencies, and assumptions governing future natural gas and oil prices, future operating costs,
severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The future
development costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these
reserves are later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected
natural gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and
estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the
estimated quantity and value of the reserves, which could affect the carrying value of the Company’s natural gas and oil properties
and/or the rate of depletion of such natural gas and oil properties.
Actual production, revenues and expenditures with respect to the Company’s reserves will likely vary from estimates, and
such variances may be material. Holding all other factors constant, a reduction in the Company’s proved reserve estimate at December
31, 2014 of 5%, 10% and 15% would affect depreciation, depletion and amortization expense by approximately $2.2 million,
$4.6 million and $7.3 million, respectively.
Impairment of Natural Gas and Oil Properties
The Company reviews its proved natural gas and oil properties for impairment whenever events and circumstances indicate a
potential decline in the recoverability of their carrying value. The Company compares expected undiscounted future net cash flows
from each field to the unamortized capitalized cost of the asset. If the future undiscounted net cash flows, based on the Company’s
estimate of future natural gas and oil prices and operating costs and anticipated production from proved reserves, are lower than the
unamortized capitalized cost, then the capitalized cost is reduced to fair market value. The factors used to determine fair value include,
but are not limited to, estimates of reserves, future commodity pricing, future production estimates, and anticipated capital
expenditures. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any
such impairment charged to expense in the period. Drilling activities in an area by other companies may also effectively impair
leasehold positions. Given the complexities associated with natural gas and oil reserve estimates and the history of price volatility in
the natural gas and oil markets, events may arise that will require the Company to record an impairment of its natural gas and oil
properties and there can be no assurance that such impairments will not be required in the future nor that they will not be material.
Derivative Instruments
At the end of each reporting period we record on our balance sheet the mark-to-market valuation of our derivative
instruments. The estimated change in fair value of the derivatives, along with the realized gain or loss for settled derivatives, is
reported in Other Income (Expense) as Gain (loss) on derivatives, net.
Income Taxes
Income taxes are provided for the tax effects of transactions reported in the financial statements and consists of taxes
currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and
income tax reporting purposes. Deferred income taxes are measured by applying currently enacted tax rates to the differences between
financial statements and income tax reporting. Numerous judgments and assumptions are inherent in the determination of deferred
income tax assets and liabilities as well as income taxes payable in the current period. We are subject to taxation in several
jurisdictions, and the calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax laws and
regulations in various taxing jurisdictions.
60
Accounting for uncertainty in income taxes prescribes a recognition threshold and a measurement attribute for the financial
statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those
benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities.
In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of
the deferred tax assets will not be realized. Deferred tax assets are reduced by a valuation allowance when, in the opinion of
management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Estimating the amount of
the valuation allowance is dependent on estimates of future taxable income, alternative minimum taxable income and changes in
stockholder ownership that limit the use of net operating losses under the Internal Revenue Code Section 382 (“Section 382”).
Our federal and state income tax returns are generally not filed before the consolidated financial statements are prepared.
Therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax
credits and net operating and capital loss carryforwards and carrybacks. Adjustments related to differences between the estimates we
used and actual amounts we reported are recorded in the period in which we file our income tax returns.
We have a significant deferred tax asset associated with the net tax operating losses acquired in the Merger. The amount of
the deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the
carryforward period are reduced. We expect we will be able to utilize all deferred tax assets despite the limitations of Internal Revenue
Code Section 382, except those for which a valuation allowance has been provided. We will continue to assess the need for a valuation
allowance against deferred tax assets considering all available evidence obtained in future reporting periods. Any adjustments or
changes in our estimates of asset recovery could have an impact on our results of operations. See Note 16 - "Income Taxes” to our
consolidated financial statements.
Business Combinations
Accounting for business combinations requires that the various assets acquired and liabilities assumed in a business
combination be recorded at their respective acquisition date fair values. The most significant estimates to us typically relate to the
value assigned to future recoverable oil and gas reserves and unproved properties. Deferred taxes are recorded for any differences
between fair value and tax basis of assets acquired and liabilities assumed. To the extent the purchase price plus the liabilities assumed
(including deferred income taxes recorded in connection with the transaction) exceeds the fair value of the net assets acquired, we are
required to record the excess as goodwill. As the fair value of assets acquired and liabilities assumed is subject to significant estimates
and subjective judgments, the accuracy of this assessment is inherently uncertain. The value assigned to recoverable oil and gas
reserves is subject to the impairment test when facts or circumstances indicate that the value of the properties may be impaired, and
the value assigned to unproved properties is assessed at least annually to ascertain whether impairment has occurred. If the initial
accounting for the business combination is not complete, the amounts recognized for assets acquired and liabilities assumed in the
financial statements may be adjusted during the measurement period of up to one year as specified by Accounting Standards
Codification (“ASC”) 805, Business Combinations.
Recent Accounting Pronouncements
In January 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2015-01:
Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating
the Concept of Extraordinary Items (ASU 2015-01). ASU 2015-01 is part of an initiative to reduce complexity in accounting
standards. This update eliminates from generally accepted accounting principles the concept of extraordinary items, which eliminates
the requirements for reporting entities to consider whether an underlying event or transaction is extraordinary. However, this will not
result in a loss of information as the presentation and disclosure guidance for items that are unusual in nature or occur infrequently
will be retained. ASU 2015-01 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15,
2015; early application is permitted. The provisions of this accounting update are not expected to have a material impact on our
financial position or results of operations.
In November 2014, the FASB issued Accounting Standards Update No. 2014-17: Business Combinations (Topic 805):
Pushdown Accounting (ASU 2014-17). ASU 2014-17 addresses the limited guidance available for determining whether and at what
threshold pushdown accounting should be established in an acquired entity’s separate financial statements. Thus, the amendments in
this update provide an acquired entity with an option to apply pushdown accounting upon occurrence of an event in which an acquirer
61
obtains control of the acquired entity. Furthermore, the amendments in this update provide specific guidance on pushdown accounting
for all entities, and the threshold for pushdown accounting is consistent with the threshold for change-in-control events in Topic 805,
Business Combinations, and Topic 810, Consolidation. ASU 2014-17 became effective on November 18, 2014. The provisions of this
accounting update are not expected to have a material impact on our financial position or results of operations.
In August 2014, the FASB issued Accounting Standards Update No. 2014-15: Presentation of Financial Statements – Going
Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (ASU 2014-15).
ASU 2014-15 asserts that management should evaluate whether there are relevant condition or events that are known and reasonably
knowable that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date the
financial statements are issued or are available to be issued when applicable. If conditions or events at the date the financial statements
are issued raise substantial doubt about an entity’s ability to continue as a going concern, disclosures are required which will enable
users of the financial statements to understand the conditions or events as well as management’s evaluation and plan. ASU 2014-15 is
effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter; early application is
permitted. The provisions of this accounting update are not expected to have a material impact on our financial position or results of
operations.
In May 2014, the FASB and the International Accounting Standards Board (“IASB”) jointly issued new accounting guidance
for recognition of revenue Accounting Standards Update No. 2014-09: Revenue from Contracts with Customers (Topic 606) (ASU
2014-09). This new guidance replaces virtually all existing US GAAP and IFRS guidance on revenue recognition. ASU 2014-09 is
effective for fiscal years beginning after December 15, 2016. This new guidance applies to all periods presented. Therefore, when the
Company issues its financial statements on Forms 10-Q and 10-K for periods included in its year ended December 31, 2017, its
comparative periods that are presented from the years ended December 31, 2015 and 2016, must be retrospectively presented in
compliance with this new guidance. Early adoption is not allowed for US GAAP. The new guidance requires companies to make more
estimates and use more judgment than under current accounting guidance. The Company does not anticipate that this new guidance
will have a material impact on the Company’s consolidated financial position or results of operations for the periods presented.
In April 2014, the FASB issued Accounting Standards Update No. 2014-08: Presentation of Financial Statements (Topic 205)
and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of
an Entity (ASU 2014-08). ASU 2014-08 changes the criteria for reporting discontinued operations while enhancing disclosures in this
area. The amended guidance requires that a disposal representing a strategic shift that has (or will have) a major effect on an entity’s
financial results or a business activity classified as held for sale should be reported as discontinued operations. The amendments also
expand the disclosure requirements for discontinued operations and add new disclosures for individually significant dispositions that
do not qualify as discontinued operations. ASU 2014-08 is effective for annual and interim periods beginning after December 15,
2014 (early adoption is permitted only for disposals that have not been previously reported). The implementation of the amended
guidance of ASU 2014-08 is not expected to have a material impact on the Company’s consolidated financial position or results of
operations.
In May 2013, the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"), revised its criteria
related to internal controls over financial reporting from the originally established 1992 Internal Control - Integrated Framework with
2013 Internal Control - Integrated Framework. The modified framework provides enhanced guidance that ties control objectives to
the related risk, enhancement of governance concepts, increased emphasis on globalization of markets and operations, increased
recognition of use and reliance on information technology, increased discussion of fraud as it relates to internal control, changes of
control deficiency descriptions, and that internal reporting is included in both financial and nonfinancial objectives. The revised
framework is effective for interim and annual periods beginning after December 15, 2013, with early adoption being permitted. We
implemented the changes required by the new COSO framework during the year ended December 31, 2014. We will continue to
assess the impact, if any, it may have on our internal control structure.
In February 2013, the FASB issued Accounting Standards Update No. 2013-04 Liabilities (Topic 405): Obligations Resulting
from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (ASU
2013-04). ASU 2013-04 provides guidance for the recognition, measurement, and disclosure of obligations resulting from joint and
several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting
date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update
include debt arrangements, other contractual obligations, and settled litigation and judicial rulings. U.S. GAAP does not include
62
specific guidance on accounting for such obligations with joint and several liability, which has resulted in diversity in practice. The
accounting update is effective for interim and annual periods beginning after December 15, 2013. We evaluated the provisions of this
accounting update and do not believe that it has a material impact on our financial position and results of operations.
Off Balance Sheet Arrangements
We may enter into off-balance sheet arrangements that can give rise to off-balance sheet obligations. As of December 31,
2014, the primary off-balance sheet arrangements that we have entered into included short-term drilling rig contracts and operating
lease agreements, all of which are customary in the oil and gas industry. Other than the off-balance sheet arrangements shown under
operating leases and drilling rig in the commitments and contingencies table, we have no other arrangements that are reasonably likely
to materially affect our liquidity or availability of or requirements for capital resources.
Item 7A. Quantitative and Qualitative Disclosure about Market Risk
Commodity Risk
We are exposed to various risks including energy commodity price risk for our oil, natural gas and natural gas liquids
production. When oil, natural gas, and natural gas liquids prices decline significantly our ability to finance our capital budget and
operations may be adversely impacted. Our major commodity price risk exposure is to the prices received. Realized commodity prices
received for our production are tied to the spot prices applicable to natural gas and crude oil at the applicable delivery points. Prices
received for oil, natural gas and natural gas liquids are volatile and unpredictable. For the year ended December 31, 2014, a 10%
fluctuation in the prices received for oil, natural gas and natural gas liquids production would have had an approximately $28.0 million
impact on our revenues.
Derivative Instruments and Hedging Activity
We expect commodity prices to remain volatile and unpredictable, therefore we have designed a risk management strategy
which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by
reducing the risk of price volatility and the affect it could have on our operations. The types of derivative instruments that we typically
utilize include swaps and costless collars. The total volumes which we have historically hedged through the use of our derivative
instruments varied from period to period, however, generally our objective has been to potentially hedge approximately 40% to 50%
of our current and anticipated production for the next 12 to 18 months, excluding offshore production during hurricane season. As of
December 31, 2014, we did not have any commodity price hedges in place. Our hedge strategy and objectives may change
significantly as our operational profile changes and/or commodities prices change.
We were exposed to market risk on our previously open derivative contracts related to potential non-performance by our
counterparties. It is our policy to enter into derivative contracts, including interest rate swaps, only with counterparties that are
creditworthy financial institutions deemed by management as competent and competitive market makers. The counterparties to the
Company's previous derivative contracts were large financial institutions and also lenders or affiliates of lenders in our RBC Credit
Facility. We did not post collateral under any of these contracts as they are secured under our RBC Credit Facility. See Note 7 to our
Financial Statements - "Derivative Instruments" for additional information.
We have also been exposed to interest rate risk on our variable interest rate debt. If interest rates increase, our interest
expense would increase and our available cash flow would decrease. As of December 31, 2014, we have not entered into any
derivative contracts to reduce the exposure to market rate fluctuations. We continue to monitor our risk exposure as we incur future
indebtedness at variable interest rates and will look to continue our risk management policy as situations present themselves.
We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging, (ASC 815). ASC 815
establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability
measured at fair value. The estimated fair values for financial instruments under ASC 825, Financial Instruments (ASC 825) are
determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be
determined with precision. The estimated fair value of cash, cash equivalents, accounts receivable and accounts payable approximates
their carrying value due to their short-term nature. See Note 7 to our Financial Statements - "Derivative Instruments" for more details.
63
Interest Rate Sensitivity
We are exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily
from fluctuations in short-term rates, which are LIBOR and the U.S. prime rate based and may result in reductions of earnings or cash
flows due to increases in the interest rates we pay on these obligations.
As of December 31, 2014, our total long-term debt was $63.4 million, which bears interest at a floating or market interest rate
that is tied to the prime rate or LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. During the
year ended December 31, 2014 our effective rate fluctuated between 1.7 percent and 4.3 percent, depending on the term of the specific
debt drawdowns. At December 31, 2014, we did not have any outstanding interest rate swap agreements. As of December 31, 2014,
the weighted average interest rate on our variable rate debt was 2.0% per year. Assuming our current level of borrowings, a 100 basis
point increase in the interest rates we pay under our RBC Credit Facility would result in an increase of our interest expense by
$0.6 million for a twelve month period.
Other Financial Instruments
As of December 31, 2014, we had no cash or cash equivalents. Investments in fixed-rate, interest-earning instruments carry a
degree of interest rate and credit rating risk. Fixed-rate securities may have their fair market value adversely impacted because of
changes in interest rates and credit ratings. Additionally, the value of our investments may be impaired temporarily or permanently.
Due in part to these factors, our investment income may decline and we may suffer losses in principal. Currently, we do not use any
derivative or other financial instruments or derivative commodity instruments to hedge any market risks, including changes in interest
rates or credit ratings, and we do not plan to employ these instruments in the future. Because of the nature of the issuers of the
securities that we may invest in, we do not believe that we have any cash flow exposure arising from changes in credit ratings. Based
on a sensitivity analysis performed on the financial instruments held as of December 31, 2014, an immediate 10% change in interest
rates is not expected to have a material effect on our near-term financial condition or results of operations.
Item 8. Financial Statements and Supplementary Data
The financial statements and supplemental information required to be filed under Item 8 of Form 10-K are presented on
pages F-1 through F-44 of this Form 10-K.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
An evaluation was performed under the supervision and with the participation of the Company’s senior management of the
effectiveness of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of
1934 (the “Exchange Act”)) as of December 31, 2014, the end of the period covered by this report. Based on that evaluation, the
Company’s management, including the President and Chief Executive Officer and the Chief Financial Officer, concluded that the
Company’s disclosure controls and procedures were effective as of such date to ensure that information required to be disclosed in the
reports that the Company files under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods
specified in the SEC’s rules and forms, and (ii) accumulated and communicated to the Company’s management, including the
President and Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow timely decisions regarding required
disclosures.
Changes in Internal Control Over Financial Reporting
There was no change in our internal controls over financial reporting during the fiscal quarter ended December 31, 2014 that
materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
64
Management’s Report on Internal Control Over Financial Reporting
The Company’s management is responsible for establishing and maintaining adequate internal control over financial
reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of the Company’s
management, including the President and Chief Executive Officer and Chief Financial Officer, the Company conducted an evaluation
of the effectiveness of its internal control over financial reporting based on the framework in 2013 Internal Control-Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Company’s evaluation
under the framework in 2013 Internal Control-Integrated Framework, the Company’s management concluded that its internal control
over financial reporting was effective as of December 31, 2014.
Grant Thornton LLP, the independent registered public accounting firm that audited our consolidated financial statements
included in this Form 10-K, has audited the effectiveness of our internal control over financial reporting as of December 31, 2014, as
stated in their report which is included herein.
65
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Contango Oil & Gas Company
We have audited the internal control over financial reporting of Contango Oil & Gas Company (a Delaware corporation) and
subsidiaries (the “Company”) as of December 31, 2014, based on criteria established in the 2013 Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s
management is responsible for maintaining effective internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control
Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based
on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over
financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of
internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances.
We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the
maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect
on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections
of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31,
2014, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the
consolidated financial statements of the Company as of and for the year ended December 31, 2014, and our report dated March 2,
2015 expressed an unqualified opinion on those financial statements.
/s/ GRANT THORNTON LLP
Houston, Texas
March 2, 2015
66
Item 9B. Other Information
Amendment to Bylaws
On February 25, 2015, the Board of Directors (the “Board”) of the Company adopted the Third Amended and Restated
Bylaws (the “Bylaws”) of the Company. The amendment and restatement of the Bylaws was effective immediately and includes,
among other things, the following changes:
•
Providing for additional disclosure requirements for notices of director nominations and stockholder proposals.
• Modifying the time period during which notice of director nominations and stockholder proposals may be given.
•
•
•
•
Clarifying the procedures relating to the appointment of the chairman of a meeting of stockholders and the powers of the
chairman of a meeting to conduct such a meeting.
Clarifying that the Board has the power to fix the record date, meeting date, time and place for each special meeting of
stockholders.
Removing certain obsolete provisions arising from and relating to our merger with Crimson Exploration Inc.
Clarifying the requirements for removal of a director for cause by stockholders of the Company.
• Designating the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain legal action,
unless the Company consents in writing to the selection of an alternative forum.
The foregoing description of the Bylaws is not complete and is qualified in its entirety by reference to the complete text of
the Bylaws, a copy of which is filed as Exhibit 3.2 to this Annual Report on Form 10-K and incorporated by reference herein.
Item 10. Directors, Executive Officers and Corporate Governance
PART III
The information regarding directors, executive officers, promoters and control persons required under Item 10 of Form 10-K
will be contained in our Definitive Proxy Statement for our 2015 Annual Meeting of Stockholders (the “Proxy Statement”) under the
headings “Proposal 1: Election of Directors”, “Executive Compensation”, “Section 16(a) Beneficial Ownership Reporting
Compliance” and “Corporate Governance and our Board” and is incorporated herein by reference. The Proxy Statement will be filed
with the SEC pursuant to Regulation 14A of the Exchange Act, not later than 120 days after December 31, 2014.
Item 11. Executive Compensation
The information required under Item 11 of Form 10-K will be contained in the Proxy Statement under the heading
“Executive Compensation” and is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required under Item 12 of Form 10-K will be contained in the Proxy Statement under the heading “Security
Ownership of Certain Other Beneficial Owners and Management” and is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required under Item 13 of Form 10-K will be contained in the Proxy Statement under the headings
“Corporate Governance and our Board”, “Transactions with Related Persons” and “Executive Compensation” and is incorporated
herein by reference.
Item 14. Principal Accountant Fees and Services
The information required under Item 14 of Form 10-K will be contained in the Proxy Statement under the subheading
“Principal Accountant Fees and Services” and is incorporated herein by reference.
67
The following is a description of the meanings of some of the oil and gas industry terms used in this report.
GLOSSARY OF SELECTED TERMS
2D seismic or 3D seismic. Geophysical data that depict the subsurface strata in two dimensions or three dimensions,
respectively. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D seismic.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, in reference to crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet of natural gas.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or
natural gas liquids.
Boe. Barrel of oil equivalent per day determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate
or natural gas liquids.
Boe/d. Boe per day.
Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree
Fahrenheit.
Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of
natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.
Development well. A well drilled into a proved natural gas or oil reservoir to the depth of a stratigraphic horizon known to be
productive.
Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of
such production exceed production expenses and taxes.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of
natural gas or crude oil in another reservoir.
Field. An area consisting of either a single reservoir or multiple reservoirs all grouped on or related to the same individual
geological structural feature and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. Thousand cubic feet of natural gas.
Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil,
condensate or natural gas liquids.
MMBbls. million barrels of crude oil or other liquid hydrocarbons.
MMBtu. million British Thermal Units. One MMBtu equates to one Mcf.
MMcf. million cubic feet of natural gas.
MMcfe. million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate
or natural gas liquids.
68
MMcfe/d. Mmcfe per day.
Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.
Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one
stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds
from the sale of the production exceed production expenses and taxes.
Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary
economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial
hydrocarbons.
Proved developed producing reserves. Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Proved developed reserves. Has the meaning given to such term in Rule 4-10(a)(3) of Regulation S-X, which defines proved
developed reserves as reserves that can be expected to be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery
techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves
only after testing by a pilot project or after the operation of an installed program has confirmed through production response that
increased recovery will be achieved.
Proved reserves. Has the meaning given to such term in Rule 4-10(a)(2) of Regulation S-X, which defines proved reserves
as the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e.,
prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by
contractual arrangements, but not on escalations based upon future conditions.
Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation
test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water
contacts, if any, and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically
productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known
structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection)
are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the
reservoir, provides support for the engineering analysis on which the project or program was based.
Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is
classified separately as indicated additional reserves; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is
subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural
gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
Proved undeveloped reserves. Has the meaning given to such term in Rule 4-10(a)(4) of Regulation S-X, which defines
proved undeveloped reserves as reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells
where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units
offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be
claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.
Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of
fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual
tests in the area and in the same reservoir.
69
PV-10. A non-GAAP financial measure that represents the present value, discounted at 10% per year, of estimated future
cash inflows from proved natural gas and crude oil reserves, less future development and production costs using pricing assumptions
in effect at the end of the period. PV-10 differs from Standardized Measure of Discounted Net Cash Flows because it does not include
the effects of income taxes or non-property related expenses such as general and administrative expenses and debt service or
depreciation, depletion and amortization on future net revenues. Neither PV-10 nor Standardized Measure of Discounted Net Cash
Flows represents an estimate of fair market value of natural gas and crude oil properties. PV-10 is used by the industry as an arbitrary
reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities that are not
dependent on the taxpaying status of the entity.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas
and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Trucking. The provision of trucks to move our drilling rigs from one well location to another and to deliver water and
equipment to the field.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the
production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on
the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.
70
Item 15. Exhibits and Financial Statement Schedules
(a) Financial Statements and Schedules:
PART IV
The financial statements are set forth in pages F-1 to F-37 of this Form 10-K. Financial statement schedules have been
omitted since they are either not required, not applicable, or the information is otherwise included.
(b) Exhibits:
The following is a list of exhibits filed as part of this Form 10-K. Where so indicated by a footnote, exhibits, which were
previously filed, are incorporated herein by reference.
Exhibit
Number
2.1
3.1
3.2
3.3
4.1
4.2
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14
10.15
Description
Agreement and Plan of Merger, among Contango Oil & Gas Company, Contango Acquisition, Inc. and Crimson
Exploration Inc., dated as of April 29, 2013. (24)
Certificate of Incorporation of Contango Oil & Gas Company. (5)
Third Amended and Restated Bylaws of Contango Oil & Gas Company. †
Amendment to the Certificate of Incorporation of Contango Oil & Gas Company. (8)
Facsimile of common stock certificate of Contango Oil & Gas Company. (1)
Registration Rights Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, OCM Crimson
Holdings, LLC and OCM GW Holdings, LLC. (24)
Agreement, dated effective as of September 1, 1999, between Contango Oil & Gas Company and Juneau Exploration,
L.L.C. (2)
Amendment dated August 14, 2000 to agreement between Contango Oil & Gas Company and Juneau Exploration
Company, LLC. dated effective as of September 1, 1999. (4)
Asset Purchase Agreement by and among Juneau Exploration, L.P. and Contango Oil & Gas Company dated January 4,
2002. (6)
Asset Purchase Agreement by and among Mark A. Stephens, John Miller, The Hunter Revocable Trust, Linda G. Ferszt,
Scott Archer and the Archer Revocable Trust and Contango Oil & Gas Company dated January 9, 2002. (7)
Second Amended and Restated Credit Agreement dated as of October 1, 2010 among Contango Oil & Gas Company,
Contango Operators, Inc. and Amegy Bank National Association, as Administrative Agent and Letter of Credit Issuer,
together with First Amendment to Second Amended and Restated Credit Agreement dated October 20, 2010 among
Contango Oil & Gas Company, Contango Operators, Inc. and Amegy Bank National Association. (18)
Purchase and Sale Agreement between Juneau Exploration, L.P. and Contango Operators, Inc. dated October 1, 2010.
(19)
Purchase and Sale Agreement between Conterra Company as Seller, and Patara Oil & Gas LLC as Purchaser, dated
April 22, 2011. (20)
Limited Liability Company Agreement of Republic Exploration LLC dated August 24, 2000. (10)
Amendment to Limited Liability Company Agreement and Additional Agreements of Republic Exploration LLC dated
as of September 1, 2005. (10)
Limited Liability Company Agreement of Contango Offshore Exploration LLC dated November 1, 2000. (10)
First Amendment to Limited Liability Company Agreement and Additional Agreements of Contango Offshore
Exploration LLC dated as of September 1, 2005. (10)
Assignment of Operating Rights Interest between CGM, LP and Contango Operators, Inc., dated as of January 3, 2008.
(13)
Partial Assignment of Oil and Gas Leases between CGM, LP and Contango Operators, Inc., dated as of January 3, 2008.
(13)
Assignment of Operating Rights Interest between CGM, LP and Contango Operators, Inc., dated as of January 3, 2008.
(13)
Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated
as of January 3, 2008. (13)
71
10.16
10.17
10.18
10.19
10.20
10.21
10.22
10.23
10.24
10.25
10.26
10.27
10.28
10.29
10.30
10.31
10.32
10.33
10.34
10.35
Partial Assignment of Oil and Gas Leases between Olympic Energy Partners, LLC and Contango Operators, Inc. dated
as of January 3, 2008. (13)
Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated
as of January 3, 2008. (13)
Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of
January 3, 2008. (13)
Partial Assignment of Oil and Gas Leases between Juneau Exploration, LP and Contango Operators, Inc., dated as of
January 3, 2008. (13)
Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of
January 3, 2008. (13)
Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of
April 3, 2008. (14)
Partial Assignment of Oil and Gas Leases between Juneau Exploration, LP and Contango Operators, Inc., dated as of
April 3, 2008. (14)
Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of
April 3, 2008. (14)
Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated
as of April 3, 2008. (14)
Partial Assignment of Oil and Gas Leases between Olympic Energy Partners, LLC and Contango Operators, Inc. dated
as of April 3, 2008. (14)
Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated
as of April 3, 2008. (14)
Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango
Operators, Inc., dated as of February 8, 2008. (15)
Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango
Operators, Inc., dated as of February 8, 2008. (15)
Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango
Operators, Inc., dated as of February 8, 2008. (15)
Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango
Operators, Inc., dated as of February 8, 2008. (15)
Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango
Operators, Inc., dated as of February 8, 2008. (15)
Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango
Operators, Inc., dated as of February 8, 2008. (15)
Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango
Operators, Inc., dated as of February 8, 2008. (15)
Amended and Restated Limited Liability Company Agreement of Republic Exploration LLC, dated April 1, 2008. (14)
Amended and Restated Limited Liability Company Agreement of Contango Offshore Exploration LLC, dated April 1,
2008. (15)
10.36 * Amended and Restated 2005 Stock Incentive Plan (28)
10.37 * Contango Oil & Gas Company Amended and Restated 2009 Incentive Compensation Plan. (11)
10.38
10.39
10.40
10.41
10.42
10.43
10.44
Conterra Joint Venture Development Agreement effective October 1, 2009 between Conterra Company and Patara Oil
& Gas LLC. (12)
First Amended and Restated Limited Liability Company Agreement dated as of March 31, 2012. (21)
Participation Agreement covering OCS-G 27927, Ship Shoal Block 263, South Addition, dated as of October 9, 2008
between Contango Offshore Exploration LLC and Contango Operators, Inc. (23)
Amendment to Participation Agreement covering OCS-G 27927, Ship Shoal Block 263, South Addition, dated as of
October 7, 2009 between Contango Offshore Exploration LLC and Contango Operators, Inc. (23)
Amendment to Participation Agreement covering OCS-G 27927, Ship Shoal Block 263, South Addition, dated as of
January 29, 2010 between Contango Offshore Exploration LLC and Contango Operators, Inc. (23)
Participation Agreement covering OCS-G 33596, Vermilion 170, dated as of July 1, 2010 between Republic
Exploration LLC and Contango Operators, Inc. (23)
Participation Agreement covering OCS-G 33640, Ship Shoal 121; OCS-G 33641, Ship Shoal 122; and OCS-G 22701,
Ship Shoal 134, dated as of July 1, 2010 between Republic Exploration LLC and Contango Operators, Inc. (23)
72
10.45
10.46
10.47
10.48
10.49
10.50
10.51
10.52
10.53
10.54
10.55
10.56
10.57
10.58
10.59
10.60
10.61
10.62
10.63
10.64
10.65
10.66
10.67
10.68
10.69
14.1
21.1
21.2
23.1
23.2
23.3
23.4
31.1
31.2
32.1
Amendment to Participation Agreement covering OCS-G 33640, Ship Shoal 121; OCS-G 33641, Ship Shoal 122; and
OCS-G 22701, Ship Shoal 134, dated as of June 30, 2012 between Republic Exploration LLC and Contango Operators,
Inc. (23)
Participation Agreement covering OCS-G 22738, South Timbalier 75, dated as of July 26, 2011 between Republic
Exploration LLC and Contango Operators, Inc. (23)
Amendment to Participation Agreement covering OCS-G 22738, South Timbalier 75, dated as of August 21, 2012
between Republic Exploration LLC and Contango Operators, Inc. (23)
Participation Agreement covering Tuscaloosa Marine Shale, dated as of August 27, 2012 between Juneau Exploration
LP and Contango Operators, Inc. (23)
Letter Agreement dated as of June 8, 2012 between Juneau Exploration LP and Contango Operators, Inc. (23)
Participation Agreement covering Central Gulf of Mexico Lease Sale 216/222, dated as of August 27, 2012 between
Republic Exploration LLC and Contango Operators, Inc. (23)
Participation Agreement covering Central Gulf of Mexico Lease Sale 216/222, dated as of August 27, 2012 between
Juneau Exploration LP and Contango Operators, Inc. (23)
Agreement to Purchase Overriding Royalty Interest, dated March 1, 2010 between Contango Offshore Exploration LLC
and Juneau Exploration LP. (23)
Employment Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company and Allan D. Keel. (24)
Employment Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company and E. Joseph Grady. (24)
First Right of Refusal Agreement between Contango Oil & Gas Company and Juneau Exploration, L.P., entered into as
of January 1, 2013. (25)
Advisory Agreement between Contaro Company and Juneau Exploration, L.P., entered into as of January 1, 2013. (25)
Employment Agreement, dated as of June 10, 2013, among Contango Oil & Gas Company and Jeffrey A. Sikora. (26)
Employment Agreement, dated as of June 7, 2013, among Contango Oil & Gas Company and A. Carl Isaac. (26)
Employment Agreement, dated as of June 7, 2013, among Contango Oil & Gas Company and John A. Thomas. (26)
Employment Agreement, dated as of June 7, 2013, among Contango Oil & Gas Company and Jay S. Mengle. (26)
Employment Agreement, dated as of June 7, 2013, among Contango Oil & Gas Company and Thomas H. Atkins. (26)
Transition Agreement, dated as of June 10, 2013, between Contango Oil & Gas Company and Marc Duncan. (27)
Participation Agreement covering Central Gulf of Mexico Lease Sale 227, dated as of March 21, 2013 between Republic
Exploration LLC and Contango Operators, Inc. (22)
Participation Agreement covering Timbalier Island Prospect, South Timbalier Area Block 17, S.L. 21906, dated April 3,
2013 between Republic Exploration LLC, Juneau Exploration, L.P. and Contango Operators, Inc. (22)
Credit Agreement among Contango Oil & Gas Company, as Borrower, Royal Bank of Canada, as Administrative Agent,
and the Lenders Signatory Hereto dated October 1, 2013. (28)
First Amendment to Credit Agreement among Contango Oil & Gas Company, as Borrower, Royal Bank of Canada, as
Administrative Agent, and the Lenders Signatory Hereto. (30)
Second Amendment to Credit Agreement among Contango Oil & Gas company, as Borrower, Royal Bank of Canada, as
Administrative Agent, and the Lenders Signatory Hereto. (31)
Termination Agreement between Juneau Exploration LP and Contaro Company, dated July 15, 2014. (32)
* Contango Oil & Gas Company Director Compensation Plan. (33)
Code of Ethics. (29)
List of Subsidiaries. †
Organizational Chart. †
Consent of William M. Cobb & Associates, Inc. †
Consent of Netherland, Sewell & Associates, Inc. †
Consent of W.D. Von Gonten & Co. †
Consent of Grant Thornton LLP. †
Certification of Chief Executive Officer required by Rules 13a-14 and 15d-14 under the Securities Exchange Act of
1934. †
Certification of Chief Financial Officer required by Rules 13a-14 and 15d-14 under the Securities Exchange Act of
1934. †
Certification of Chief Executive Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002. †
73
32.2
99.1
99.2
99.3
Certification of Chief Financial Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002. †
Report of William M. Cobb & Associates, Inc. †
Report of Netherland, Sewell & Associates. †
Report of W.D. Von Gonten and Company †
* Indicates a management contract or compensatory plan or arrangement.
† Filed herewith
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
22.
23.
24.
Filed as an exhibit to the Company’s Form 10-SB Registration Statement, as filed with the Securities and Exchange
Commission on October 16, 1998.
Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended September 30, 1999, as filed with
the Securities and Exchange Commission on November 11, 1999.
Reserved
Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2000, as filed
with the Securities and Exchange Commission on September 27, 2000.
Filed as an exhibit to the Company’s report on Form 8-K, dated December 1, 2000, as filed with the Securities and
Exchange Commission on December 15, 2000.
Filed as an exhibit to the Company’s report on Form 8-K, dated January 4, 2002, as filed with the Securities and
Exchange Commission on January 8, 2002.
Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended March 31, 2002, as filed with the
Securities and Exchange Commission on February 14, 2002.
Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended December 31, 2002, dated
November 14, 2002, as filed with the Securities and Exchange Commission.
Reserved
Filed as an exhibit to the Company’s report on Form 8-K, dated September 2, 2005, as filed with the Securities and
Exchange Commission on September 8, 2005.
Filed as an exhibit to the Company’s Schedule 14A on Definitive Proxy Statement for 2014, as filed with the
Securities and Exchange Commission on April 11, 2014
Filed as an exhibit to the Company’s report on Form 8-K, dated October 22, 2009, as filed with the Securities and
Exchange Commission on October 28, 2009.
Filed as an exhibit to the Company’s report on Form 8-K, dated January 3, 2008, as filed with the Securities and
Exchange Commission on January 9, 2008.
Filed as an exhibit to the Company’s report on Form 8-K, dated April 3, 2008, as filed with the Securities and
Exchange Commission on April 9, 2008.
Filed as an exhibit to the Company’s report on Form 10-K for the fiscal year ended June 30, 2008, as filed with the
Securities and Exchange Commission on August 29, 2008.
Reserved
Reserved
Filed as an exhibit to the Company’s report on Form 8-K, dated October 20, 2010 as filed with the Securities and
Exchange Commission on October 25, 2010.
Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended September 30, 2010, as filed with the
Securities and Exchange Commission on November 9, 2010.
Filed as an exhibit to the Company’s report on Form 8-K, dated May 13, 2011 as filed with the Securities and
Exchange Commission on May 18, 2011.
Filed as an exhibit to the Company’s report on Form 8-K, dated as of March 31, 2012, as filed with the Securities and
Exchange Commission on April 5, 2012.
Filed as an exhibit to the Company’s report on Form 10-K for the fiscal year ended June 30, 2013, as filed with the
Securities and Exchange Commission on August 29, 2013.
Filed as an exhibit to the Company’s report on Form 10-K for the fiscal year ended June 30, 2012, as filed with the
Securities and Exchange Commission on August 29, 2012.
Filed as an exhibit to the Company’s report on Form 8-K, dated as of April 29, 2013, as filed with the Securities and
Exchange Commission on May 1, 2013.
74
25.
26.
27.
28.
29.
30.
31.
32.
33.
Filed as an exhibit to the Company's report on Form 10-Q for the quarter ended December 31, 2012, as filed with the
Securities and Exchange Commission on February 11, 2013.
Filed as an exhibit to the Company's Registration Statement on Form S-4, as filed with the Securities and Exchange
Commission on June 13, 2013.
Filed as an exhibit to the Company’s report on Form 8-K, dated as of June 7, 2013, as filed with the Securities and
Exchange Commission on June 14, 2013.
Filed as an exhibit to the Company’s Current Report on Form 8-K dated as of October 1, 2013, as filed with the
Securities and Exchange Commission on October 2, 2013.
Filed as an exhibit to the Company’s report on Form 8-K dated as of January 30, 2014, as filed with the Securities and
Exchange Commission on January 30, 2014
Filed as an exhibit to the Company’s report on Form 8-K dated as of April 11, 2014, as filed with the Securities and
Exchange Commission on April 15, 2014.
Filed as an exhibit to the Company’s report on Form 8-K dated as of October 28, 2014, as filed with the Securities and
Exchange Commission on October 31, 2014.
Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended June 30, 2014, as filed with the
Securities and Exchange Commission on August 11, 2014.
Filed as an exhibit to the Company’s Transition Report on Form 10-KT for the six months ended December 31, 2013,
as filed with the Securities and Exchange Commission on March 28, 2014.
75
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its
SIGNATURES
behalf by the undersigned, thereunto duly authorized.
CONTANGO OIL & GAS COMPANY
Signature
Title
Date
/s/ ALLAN D. KEEL
Allan D. Keel
Chief Executive Officer (principal executive officer)
March 3, 2015
/s/ E. JOSEPH GRADY
E. Joseph Grady
Chief Financial Officer (principal financial officer and
principal accounting officer)
March 3, 2015
POWER OF ATTORNEY
Know all men by these presents, that the undersigned constitutes and appoints Allan D. Keel as his true and lawful attorneys-
in-fact and agent, with full power of substitution for him and in his name, place and stead, in any and all capacities to sign any and all
amendments or supplements to this Annual Report on Form 10-K, and to file the same, and with all exhibits thereto and other
documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent full
power and authority to do and perform each and every act and thing requisite and necessary to be done as fully to all intents and
purposes as he might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent or his substitute or
substitutes, may lawfully do or cause to be done by virtue hereof.
In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant
and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ALLAN D. KEEL
Allan D. Keel
Chief Executive Officer (principal executive officer)
and Director
/s/ JOSEPH J. ROMANO
Joseph J. Romano
/s/ B.A. BERILGEN
B. A. Berilgen
/s/ B. JAMES FORD
B. James Ford
/s/ ELLIS L. MCCAIN
Ellis L. McCain
/s/ CHARLES M. REIMER
Charles M. Reimer
/s/ STEVEN L. SCHOONOVER
Steven L. Schoonover
Director
Director
Director
Director
Director
Director
76
March 3, 2015
March 3, 2015
March 3, 2015
March 3, 2015
March 3, 2015
March 3, 2015
March 3, 2015
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Cash Flows
Consolidated Statement of Shareholders’ Equity
Notes to Consolidated Financial Statements
Supplemental Oil and Gas Disclosures (Unaudited)
Quarterly Results of Operations (Unaudited)
Page
F-2
F-3
F-4
F-5
F-6
F-7
F-38
F-44
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Contango Oil & Gas Company
We have audited the accompanying consolidated balance sheets of Contango Oil & Gas Company (a Delaware corporation) and
subsidiaries (the “Company”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, shareholders’
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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of
Contango Oil & Gas Company and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted
in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the
Company’s internal control over financial reporting as of December 31, 2014, based on criteria established in the 2013 Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and
our report dated March 2, 2015 expressed an unqualified opinion.
/s/ GRANT THORNTON LLP
Houston, Texas
March 2, 2015
F-2
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except shares)
December 31,
2014
December 31,
2013
CURRENT ASSETS:
Cash and cash equivalents
Accounts receivable, net
Prepaid expenses and other
Inventory
Current deferred tax asset
Total current assets
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, successful efforts method of accounting:
Proved properties
Unproved properties
Other property and equipment
Accumulated depreciation, depletion and amortization
Total property, plant and equipment, net
OTHER NON-CURRENT ASSETS:
Investments in affiliates
Other
Total other non-current assets
TOTAL ASSETS
CURRENT LIABILITIES:
Accounts payable and accrued liabilities
Current derivative liability
Current asset retirement obligations
Total current liabilities
NON-CURRENT LIABILITIES:
Long-term debt
Deferred tax liability
Asset retirement obligations
Total non-current liabilities
Total liabilities
COMMITMENTS AND CONTINGENCIES (NOTE 14)
SHAREHOLDERS’ EQUITY:
Common stock, $0.04 par value, 50 million shares authorized, 24,372,538 shares issued and
19,148,000 shares outstanding at December 31, 2014, 24,356,236 shares issued and 19,363,711
shares outstanding at December 31, 2013
Additional paid-in capital
Treasury shares at cost (5,224,538 shares at December 31, 2014 and 4,992,525 shares at December
31, 2013)
Retained earnings
Total shareholders’ equity
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
$
$
$
$
— $
25,309
1,941
2,166
1,624
31,040
1,138,054
35,783
1,084
(426,298)
748,623
62,085
1,667
63,752
843,415
92,892
—
4,123
97,015
63,359
93,952
21,623
178,934
275,949
$
$
—
60,613
2,031
2,147
1,326
66,117
1,001,361
49,443
900
(260,681)
791,023
50,901
2,263
53,164
910,304
96,833
1,131
1,315
99,279
90,000
105,956
22,019
217,975
317,254
963
233,278
(127,525)
460,750
567,466
843,415
$
962
228,644
(119,180)
482,624
593,050
910,304
The accompanying notes are an integral part of these consolidated financial statements.
F-3
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
REVENUES:
Oil and condensate sales
Natural gas sales
Natural gas liquids sales
Total revenues
EXPENSES:
Operating expenses
Exploration expenses
Depreciation, depletion and amortization
Impairment and abandonment of oil and gas properties
General and administrative expenses
Total expenses
OTHER INCOME (EXPENSE):
Gain from investment in affiliates (net of income taxes)
Interest income (expense)
Loss on derivatives, net
Other income (expense)
Total other income (expense)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
Income tax benefit (provision)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS
DISCONTINUED OPERATIONS, NET OF INCOME TAX
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK
NET INCOME (LOSS) PER SHARE:
Basic
Continuing operations
Discontinued operations
Total
Diluted
Continuing operations
Discontinued operations
Total
Year Ended December 31
2013
2014
2012
$
$
$
$
$
$
130,238
112,695
33,525
276,458
47,236
33,387
156,117
47,693
34,045
318,478
6,923
(2,658)
(153)
124
4,236
(37,784)
15,910
(21,874)
—
(21,874)
(1.15)
—
(1.15)
(1.15)
—
(1.15)
$
$
$
$
$
$
59,608
79,289
25,224
164,121
36,784
1,811
65,529
776
26,512
131,412
2,310
(1,171)
(1,132)
31,785
31,792
64,501
(23,139)
41,362
—
41,362
2.56
—
2.56
2.56
—
2.56
$
$
$
$
$
$
56,237
60,691
28,940
145,868
23,720
51,903
44,896
14,079
11,265
145,863
60
96
—
(463)
(307)
(302)
(605)
(907)
(29)
(936)
(0.06)
(0.00)
(0.06)
(0.06)
(0.00)
(0.06)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic
Diluted
19,059
19,059
16,156
16,158
15,295
15,295
The accompanying notes are an integral part of these consolidated financial statements.
F-4
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Year Ended December 31,
2013
2014
2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Income (loss) from continuing operations
Income (loss) from discontinued operations, net of taxes
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
$
$
(21,874)
—
(21,874)
$
41,362
—
41,362
Depreciation, depletion and amortization
Impairment of natural gas and oil properties
Exploration expenses
Deferred income taxes
Gain on sale of assets
Gain from investment in affiliates
Stock-based compensation
Excess tax benefit from exercise of stock options
Unrealized loss (gain) on derivative instruments
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable and other
Decrease (increase) in prepaid expenses
Decrease in accounts payable and advances from joint owners
Increase (decrease) in other accrued liabilities
Increase (decrease) in income taxes payable, net
Other
Net cash provided by operating activities
CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration and development expenditures
Sale of oil and gas properties
Advance under note receivable
Repayment of note receivable
Investment in affiliates
Distributions from affiliates
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility
Repayments under credit facility
Payment of long-term debt
Cash dividends paid
Purchase of common stock
Proceeds from exercised options
Excess tax benefit from exercise/cancellation of stock options
Debt issuance costs
Net cash used in financing activities
NET DECREASE IN CASH AND CASH EQUIVALENTS
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD
CASH AND CASH EQUIVALENTS, END OF PERIOD
$
$
$
$
$
$
$
156,117
47,075
31,488
(12,284)
—
(10,651)
4,515
—
(1,131)
28,942
(19)
(8,322)
(4,236)
884
(544)
209,960
(180,422)
—
—
—
—
5,365
(175,057)
491,257
(517,898)
—
—
(8,344)
120
—
(38)
(34,903)
$
$
$
$
$
— $
—
— $
65,529
767
(9)
13,159
(21,961)
(3,554)
3,180
—
1,410
(6,285)
30
(4,720)
3,569
11,778
782
105,037
(62,552)
20,000
—
—
(15,397)
23,154
(34,795)
180,394
(90,394)
(235,373)
—
(2,017)
31
—
(2,370)
(149,729)
(79,487)
79,487
$
$
$
$
$
$
— $
(907)
(29)
(936)
44,896
14,078
51,379
(8,569)
—
(92)
(154)
(254)
—
19,894
(347)
(10,918)
(877)
(15,117)
(2,861)
90,122
(78,549)
—
(500)
900
(54,765)
8,969
(123,945)
—
—
—
(30,510)
(8,374)
—
254
—
(38,630)
(72,453)
151,940
79,487
The accompanying notes are an integral part of these consolidated financial statements.
F-5
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
(in thousands, expect per share amounts)
Common Stock
Shares
Amount
Additional
Paid-in
Capital
Treasury
Stock
Retained
Earnings
Total
Shareholders’
Equity
Balance at December 31, 2011
15,357,166 $
Tax benefit from exercise of stock options
Treasury shares at cost
Dividends
Net loss
Balance at December 31, 2012
Acquisition of Crimson
Exercise of stock options
Treasury shares at cost
Stock-based compensation
Net income
Balance at December 31, 2013
Exercise of stock options
Treasury shares at cost
Restricted shares activity
Stock-based compensation
Net loss
—
(162,214)
—
—
15,194,952 $
3,864,039
791
(52,370)
356,299
—
19,363,711 $
4,165
(232,013)
12,137
—
—
Balance at December 31, 2014
19,148,000 $
805 $
—
—
—
—
805 $
154
3
—
—
—
962 $
—
—
1
—
—
963 $
79,279 $ (108,789) $
472,708 $
(254)
—
—
—
—
(8,374)
—
—
79,025 $ (117,163) $
146,414
26
—
3,179
—
—
—
(2,017)
—
—
228,644 $ (119,180) $
120
—
(1)
4,515
—
—
(8,345)
—
—
—
233,278 $ (127,525) $
—
—
(30,510)
(936)
441,262 $
—
—
—
—
41,362
482,624 $
—
—
—
—
(21,874)
460,750 $
444,003
(254)
(8,374)
(30,510)
(936)
403,929
146,568
29
(2,017)
3,179
41,362
593,050
120
(8,345)
—
4,515
(21,874)
567,466
The accompanying notes are an integral part of these consolidated financial statements.
F-6
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Business
Contango Oil & Gas Company (collectively with its subsidiaries, “Contango” or the “Company”) is a Houston, Texas based,
independent oil and natural gas company. The Company’s business is to explore, develop, exploit, produce and acquire crude oil and
natural gas properties in the shallow waters of the Gulf of Mexico ("GOM") and in the onshore Texas Gulf Coast and Rocky Mountain
regions of the United States.
On October 1, 2013, the Company completed a merger with Crimson Exploration Inc. ("Crimson"), in an all-stock
transaction pursuant to which Crimson became a wholly-owned subsidiary of Contango (the "Merger"). As a result of the Merger, the
Company issued approximately 3.9 million shares of common stock in exchange for all of Crimson's outstanding capital stock. See
Note 4 - "Merger with Crimson Exploration, Inc." for additional information.
The Company has historically focused operations in the GOM, but the Merger has given the Company access to lower risk,
long life resource plays. In 2014, the Company’s drilling activity focused primarily on the Woodbine oil and liquids-rich play in
Madison and Grimes counties, Texas (the Southeast Texas Region), on the Buda Limestone oil and liquids-rich play in Zavala and
Dimmit counties, Texas (the South Texas Region), in the Cretaceous Sands in Fayette and Gonzales counties, Texas (also the South
Texas Region) and the late 2014 commencement of drilling in Wyoming where the Company is targeting multiple formations. The
Company believes these plays provide long-term growth potential from multiple formations that it believes to be productive for oil
and natural gas.
Additionally, the Company has (i) a 37% equity investment in Exaro Energy III LLC (“Exaro”) that is primarily focused on
the development of proved natural gas reserves in the Jonah Field in Wyoming; (ii) leasehold positions and minor non-operated
producing properties in Louisiana and Mississippi targeting the Tuscaloosa Marine Shale (“TMS”); (iii) operated properties producing
from various conventional formations in various counties along the Texas Gulf Coast; (iv) operated producing properties in the
Denver Julesburg Basin (“DJ Basin”) in Weld and Adams counties in Colorado, which the Company believes may also be prospective
in the Niobrara Shale oil play; (v) operated producing properties in the Haynesville Shale, Mid Bossier and James Lime formations in
East Texas; and (vi) six exploratory prospects in the shallow waters of the GOM.
2. Summary of Significant Accounting Policies
Basis of Presentation
The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally
accepted in the United States of America and include the accounts of Contango Oil & Gas Company and its subsidiaries, after
elimination of all material intercompany balances and transactions. All wholly-owned subsidiaries are consolidated. Oil and gas
exploration and development affiliates which are not controlled by the Company, such as REX, are proportionately consolidated.
Financial statements as of December 31, 2014 and 2013 and for the three years ended December 31, 2014 contained herein, include
consolidated results of operations of both Contango Oil & Gas Company and Crimson for the period from the closing date of the
Merger to December 31, 2014 and only consolidated financial statements of Contango for all other the periods presented herein.
Change of Year-End
On October 1, 2013 the Company's board of directors approved a change in fiscal year end from June 30 to December 31,
commencing with the twelve-month period beginning on January 1, 2014. Unless otherwise noted, all references to "years" in this
report refer to the twelve-month period which ends on December 31 of each year.
Other Investments
Contango’s 19.5% ownership of Moblize Inc. (“Moblize”) and 2.0% indirect ownership of Alta Energy Canada Partnership,
LLC ("Alta") are accounted for using the cost method. Under the cost method, Contango records an investment at cost, and recognizes
dividends or distributions received as income. Dividends received in excess of earnings subsequent to the date of investment are
F-7
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
considered a return of investment and are recorded as reductions of cost of the investment. During the year ended December 31, 2013,
the Company had a significant distribution from Alta in excess of its original investment. The gain in excess of the original investment
is included in the Other income (expense) line item in the Company's statement of operations and in the investing cash flows in the
Company's statement of cash flow for the year ended December 31, 2013.
The Company has two seats on the board of directors of Exaro and has significant influence, but not control, over the
company. As a result, the Company's 37% ownership in Exaro is accounted for using the equity method. Under the equity method, the
Company's proportionate share of Exaro's net income increases the balance of its investment in Exaro, while a net loss or payment of
dividends decreases its investment. In the consolidated statement of operations, the Company’s proportionate share of Exaro's net
income or loss is reported as a single line-item in Gain from investment in affiliates (net of income taxes).
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of
America 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 periods. The most significant estimates include oil and gas revenues, income taxes, stock-based compensation,
reserve estimates, impairment of natural gas and oil properties, valuation of derivatives, and accrued liabilities. Actual results could
differ from those estimates.
Revenue Recognition
Revenues from the sale of natural gas and oil produced are recognized upon the passage of title, net of royalties. Revenues
from natural gas production are recorded using the sales method. When sales volumes exceed the Company’s entitled share,
production imbalance occurs. If production imbalance exceeds the Company’s share of the remaining estimated proved natural ga s
reserves for a given property, the Company records a liability. As of December 31, 2014, 2013 and 2012, the Company had no
significant imbalances.
Cash Equivalents
Cash equivalents are considered to be highly liquid investment grade debt investments having an original maturity of 90 days
or less. As of December 31, 2014, the Company had no cash and cash equivalents. Under the Company’s cash management system,
checks issued but not presented to banks frequently result in book overdraft balances for accounting purposes and are classified in
accounts payable in the consolidated balance sheets. At December 31, 2014, accounts payable included $12.1 million representing
outstanding checks that had not been presented for payment net of cash balance in the bank as of December 31, 2014. At December
31, 2013, accounts payable included $5.9 million representing outstanding checks that had not been presented for payment net of cash
balance in the bank as of December 31, 2013.
Accounts Receivable
The Company sells natural gas and crude oil to a limited number of customers. In addition, the Company participates with
other parties in the operation of natural gas and crude oil wells. Substantially all of the Company’s accounts receivables are due from
either purchasers of natural gas and crude oil or participants in natural gas and crude oil wells for which the Company serves as the
operator. Generally, operators of natural gas and crude oil properties have the right to offset future revenues against unpaid charges
related to operated wells.
The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The Company
periodically reviews the accounts receivable from customers for any collectability issues. An allowance for doubtful accounts is
established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent
factors. Amounts deemed uncollectible are charged to the allowance.
Accounts receivable allowance for bad debt was $0.6 million, as of December 31, 2014 and 2013, respectively. At
December 31, 2014 and 2013 the carrying value of the Company’s accounts receivable approximated fair value.
F-8
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Oil and Gas Properties - Successful Efforts
The Company follows the successful efforts method of accounting for its natural gas and oil activities. Under the successful
efforts method, lease acquisition costs and all development costs are capitalized. Exploratory drilling costs are capitalized until the
results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs, such
as seismic costs and other geological and geophysical expenses, are expensed as incurred. Depreciation, depletion and amortization is
calculated on a field by field basis using the unit of production method, with lease acquisition costs amortized over total proved
reserves and other capitalized costs amortized over proved developed reserves.
Depreciation, depletion and amortization ("DD&A") of capitalized drilling and development costs of producing natural gas
and crude oil properties, including related support equipment and facilities net of salvage value, are computed using the unit-of-
production method on a field basis based on total estimated proved developed natural gas and crude oil reserves. Amortization of
producing leaseholds is based on the unit-of-production method using total estimated proved reserves. Upon sale or retirement of
properties, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the accounts and the
resulting gain or loss, if any, is recognized. Unit-of-production rates are revised whenever there is an indication of a need, but at least
annually. Revisions are accounted for prospectively as changes in accounting estimates.
Other property and equipment are depreciated using the straight-line method over their estimated useful lives which range
between three and 13 years.
Impairment of Oil and Gas Properties
When circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future
cash flows on a field by field basis to the unamortized capitalized cost of the asset. If the estimated future undiscounted cash flows,
based on the Company’s estimate of future reserves, natural gas and oil prices, operating costs and production levels from oil and
natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to its fair value. For the year
ended December 31, 2014, the Company recorded an impairment expense of approximately $11.4 million related to proved properties.
Of this amount, $7.7 million related to South Timbalier 17 and $3.7 million related to TMS. No impairment of proved properties was
recognized during the year ended December 31, 2013. For the year ended December 31, 2012, the Company recorded an impairment
expense of approximately $14.1 million related to proved properties. Of this amount, approximately $12.0 million related to the Ship
Shoal 263 well and $2.1 million related to the Eugene Island 24 platform and other properties. Despite the write-down of Ship Shoal
263, this well reached payout during the year ended December 31, 2012.
Unproved properties are reviewed quarterly to determine if there has been an impairment of the carrying value, and any such
impairment is charged to expense in the period.
On April 29, 2014, the Company reached total depth on its Ship Shoal 255 well, and no commercial hydrocarbons were
found. As a result, for the year ended December 31, 2014, the Company recognized $31.5 million in exploration expense for the cost
of drilling the well and $15.6 million in impairment expense, including $3.5 million related to leasehold costs and $12.1 million
related to the platform located in Ship Shoal 263 block which was expected to be used by the Ship Shoal 255 well had it been
successful.
During the year ended December 31, 2014, the Company also recognized impairment expense of approximately $20.1
million related to impairment and partial impairment of certain unproved properties due to expiring leases and leases not likely to be
drilled. Of this amount, approximately $9.7 million relates to undrilled offshore leases and approximately $9.7 million relates to
undeveloped TMS acreage.
For the year ended December 31, 2013, the Company recorded an impairment expense on unproved properties of $0.6
million related to leasehold costs on the Ship Shoal 83 prospect which it relinquished in August 2013, and $0.2 million related to
leasehold costs on the Brazos Area 543 prospect. The Company did not recognize any impairment of unproved properties for the year
ended December 31, 2012.
F-9
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Asset Retirement Obligations
ASC 410, Asset Retirement and Environmental Obligations (ASC 410) requires that the fair value of an asset retirement cost,
and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense
using a systematic and rational method. The Company records asset retirement obligations to reflect the Company's legal obligations
related to future plugging and abandonment of its oil and natural gas wells, platforms and associated pipelines and equipment. The
Company estimates the expected cash flows associated with the obligation and discounts the amounts using a credit-adjusted, risk-free
interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is
necessary. The Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have
materially changed. Should these indicators suggest the estimated obligation may have materially changed on an interim basis
(quarterly), the Company will accordingly update its assessment. Additional retirement obligations increase the liability associated
with new oil and natural gas wells, platforms, and associated pipelines and equipment as these obligations are incurred. The liability is
accreted to its present value each period and the capitalized cost is depleted over the useful life of the related asset. The accretion
expense is included in depreciation, depletion and amortization expense.
The estimated liability is based on historical experience in plugging and abandoning wells. The estimated remaining lives of
the wells is based on reserve life estimates and federal and state regulatory requirements. The liability is discounted using an assumed
credit-adjusted risk-free rate.
Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, changes in the risk-free
rate or changes in the remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements.
At the time of abandonment, the Company recognizes a gain or loss on abandonment to the extent that actual costs do not equal the
estimated costs. This gain or loss on abandonment is included in impairment and abandonment of oil and gas properties expense. See
Note 12 - "Asset Retirement Obligations" for additional information.
Income Taxes
The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are
recognized for the future tax consequences of (i) temporary differences between the tax basis of assets and liabilities and their reported
amounts in the financial statements and (ii) operating loss and tax credit carryforwards for tax purposes. Deferred tax assets are
reduced by a valuation allowance when, based upon management’s estimates, it is more likely than not that a portion of the deferred
tax assets will not be realized in a future period. The Company reviews its tax positions quarterly for tax uncertainties. The Company
did not have significant uncertain tax positions as of December 31, 2014. The amount of unrecognized tax benefits did not materially
change from December 31, 2013. The amount of unrecognized tax benefits may change in the next twelve months; however, the
Company does not expect the change to have a significant impact on its financial position or results of operations. The Company
includes interest and penalties in interest income and general and administrative expenses, respectively, in its statement of operations.
The Company files income tax returns in the United States and various state jurisdictions. The Company’s federal tax returns
for 1998 – 2014, and state tax returns for 2009 – 2014, remain open for examination by the taxing authorities in the respective
jurisdictions where those returns were filed.
Concentration of Credit Risk
Substantially all of the Company’s accounts receivable result from natural gas and oil sales or joint interest billings to a
limited number of third parties in the natural gas and oil industry. This concentration of customers and joint interest owners may
impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions.
See Note 3 - "Concentration of Credit Risk" for additional information.
Debt Issuance Costs
Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt. During the year
ended December 31, 2013 the Company incurred $2.2 million of debt issuance costs in relation to the new RBC credit facility entered
into in conjunction with the Merger with Crimson. The debt issuance costs will be amortized over the original four year term of the
F-10
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
credit line with amortization expense included in Depreciation, Depletion and Amortization line item in the Company's income
statement for the years ended December 31, 2014 and 2013.
Stock-Based Compensation
The Company applies the fair value based method to account for stock based compensation. Under this method,
compensation cost is measured at the grant date based on the fair value of the award and is recognized over the requisite service
period, which generally aligns with the award vesting period. The Company classifies the benefits of tax deductions in excess of the
compensation cost recognized for the options (excess tax benefit) as financing cash flows. The fair value of each award is estimated as
of the date of grant using the Black-Scholes option-pricing model.
Inventory
Inventory primarily consists of casing and tubing which will be used for drilling or completion of wells. Also, included in
inventory are items for the repair and maintenance of equipment used on wells and facilities that the Company operates. Inventory is
recorded at the lower of cost or market using specific identification method.
Derivative Instruments and Hedging Activities
The Company accounts for its derivative activities under the provisions of ASC 815, Derivatives and Hedging (ASC 815).
ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or
liability measured at fair value. As of December 31, 2014, the Company has not entered into any derivative contracts to reduce
exposure to interest rate risk. However, from time to time, the Company may hedge a portion of its forecasted oil and natural gas
production. Derivative contracts entered into by the Company have consisted of transactions in which the Company hedges the
variability of cash flow related to a forecasted transactions using variable to fixed swaps and collars. The Company elected to not
designate any of its derivative positions for hedge accounting. Accordingly, the net change in the mark-to-market valuation of these
positions as well as all payments and receipts on settled derivative contracts are recognized in "Loss on derivatives, net" on the
consolidated statements of operations for the years ended December 31, 2014 and 2013. The Company did not have any derivative
instruments or hedging activities for the year ending December 31, 2012. Derivative instruments with settlement date within one year
are included in current assets or liabilities, whereas derivative instruments with settlement dates exceeding one year are included in
non-current assets or liabilities. The Company calculates a net asset or liability for current and non-current derivative instruments for
each counterparty based on the settlement dates within the respective contracts. As of December 31, 2014, there were no commodity
hedges in place.
Reclassifications
Certain reclassifications have been made to the presentation of certain balance sheet, income statement and cash flow items in
the respective statements for the year ended December 31, 2012 in order to conform to the presentation for the years ended December
31, 2014 and 2013. These reclassifications were not material.
Subsidiary Guarantees
Contango Oil & Gas Company, as the parent company (the “Parent Company”), filed a registration statement on Form S-3
with the SEC to register, among other securities, debt securities that the Parent Company may issue from time to time. Crimson
Exploration Inc., Crimson Exploration Operating, Inc., Contango Energy Company, Contango Operators, Inc., Contango Mining
Company, Conterra Company, Contaro Company, Contango Alta Investments, Inc., Contango Venture Capital Corporation and any
other of the Company’s future subsidiaries specified in the prospectus supplement (each a “Subsidiary Guarantor”) are Co-Registrants
with the Parent Company under the registration statement, and the registration statement also registered guarantees of debt securities
by the Subsidiary Guarantors. The Subsidiary Guarantors are wholly-owned by the Parent Company, either directly or indirectly, and
any guarantee by the Subsidiary Guarantors will be full and unconditional. The Parent Company has no assets or operations
independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to
distribute funds to the Parent Company. The Parent Company has one other wholly-owned subsidiary that is inactive. Finally, the
Parent Company’s wholly-owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal
F-11
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by such subsidiary
without the consent of a third party.
Recent Accounting Pronouncements
In January 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2015-01:
Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating
the Concept of Extraordinary Items (ASU 2015-01). ASU 2015-01 is part of an initiative to reduce complexity in accounting
standards. This update eliminates from generally accepted accounting principles the concept of extraordinary items, which eliminates
the requirements for reporting entities to consider whether an underlying event or transaction is extraordinary. However, this will not
result in a loss of information as the presentation and disclosure guidance for items that are unusual in nature or occur infrequently
will be retained. ASU 2015-01 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15,
2015; early application is permitted. The provisions of this accounting update are not expected to have a material impact on the
Company’s financial position or results of operations.
In November 2014, the FASB issued Accounting Standards Update No. 2014-17: Business Combinations (Topic 805):
Pushdown Accounting (ASU 2014-17). ASU 2014-17 addresses the limited guidance available for determining whether and at what
threshold pushdown accounting should be established in an acquired entity’s separate financial statements. Thus, the amendments in
this update provide an acquired entity with an option to apply pushdown accounting upon occurrence of an event in which an acquirer
obtains control of the acquired entity. Furthermore, the amendments in this update provide specific guidance on pushdown accounting
for all entities, and the threshold for pushdown accounting is consistent with the threshold for change-in-control events in Topic 805,
Business Combinations, and Topic 810, Consolidation. ASU 2014-17 became effective on November 18, 2014. The provisions of this
accounting update are not expected to have a material impact on the Company’s financial position or results of operations.
In August 2014, the FASB issued Accounting Standards Update No. 2014-15: Presentation of Financial Statements – Going
Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (ASU 2014-15).
ASU 2014-15 asserts that management should evaluate whether there are relevant condition or events that are known and reasonably
knowable that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date the
financial statements are issued or are available to be issued when applicable. If conditions or events at the date the financial statements
are issued raise substantial doubt about an entity’s ability to continue as a going concern, disclosures are required which will enable
users of the financial statements to understand the conditions or events as well as management’s evaluation and plan. ASU 2014-15 is
effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter; early application is
permitted. The provisions of this accounting update are not expected to have a material impact on the Company’s financial position or
results of operations.
In May 2014, the FASB and the International Accounting Standards Board (“IASB”) jointly issued new accounting guidance
for recognition of revenue Accounting Standards Update No. 2014-09: Revenue from Contracts with Customers (Topic 606) (ASU
2014-09). This new guidance replaces virtually all existing US GAAP and IFRS guidance on revenue recognition. ASU 2014-09 is
effective for fiscal years beginning after December 15, 2016. This new guidance applies to all periods presented. Therefore, when the
Company issues its financial statements on Forms 10-Q and 10-K for periods included in its year ended December 31, 2017, its
comparative periods that are presented from the years ended December 31, 2015 and 2016, must be retrospectively presented in
compliance with this new guidance. Early adoption is not allowed for US GAAP. The new guidance requires companies to make more
estimates and use more judgment than under current accounting guidance. The Company does not anticipate that this new guidance
will have a material impact on the Company’s consolidated financial position or results of operations for the periods presented.
In April 2014, the FASB issued Accounting Standards Update No. 2014-08: Presentation of Financial Statements (Topic 205)
and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of
an Entity (ASU 2014-08). ASU 2014-08 changes the criteria for reporting discontinued operations while enhancing disclosures in this
area. The amended guidance requires that a disposal representing a strategic shift that has (or will have) a major effect on an entity’s
financial results or a business activity classified as held for sale should be reported as discontinued operations. The amendments also
expand the disclosure requirements for discontinued operations and add new disclosures for individually significant dispositions that
do not qualify as discontinued operations. ASU 2014-08 is effective for annual and interim periods beginning after December 15,
F-12
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
2014 (early adoption is permitted only for disposals that have not been previously reported). The implementation of the amended
guidance of ASU 2014-08 is not expected to have a material impact on the Company’s consolidated financial position or results of
operations.
In May 2013, the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"), revised its criteria
related to internal controls over financial reporting from the originally established 1992 Internal Control - Integrated Framework with
2013 Internal Control - Integrated Framework. The modified framework provides enhanced guidance that ties control objectives to
the related risk, enhancement of governance concepts, increased emphasis on globalization of markets and operations, increased
recognition of use and reliance on information technology, increased discussion of fraud as it relates to internal control, changes of
control deficiency descriptions, and that internal reporting is included in both financial and nonfinancial objectives. The revised
framework is effective for interim and annual periods beginning after December 15, 2013, with early adoption being permitted. The
Company implemented the changes required by the new COSO framework during the year ended December 31, 2014. The Company
will continue to assess the impact, if any, it may have on its internal control structure.
In February 2013, the FASB issued Accounting Standards Update No. 2013-04 Liabilities (Topic 405): Obligations Resulting
from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (ASU
2013-04). ASU 2013-04 provides guidance for the recognition, measurement, and disclosure of obligations resulting from joint and
several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting
date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update
include debt arrangements, other contractual obligations, and settled litigation and judicial rulings. U.S. GAAP does not include
specific guidance on accounting for such obligations with joint and several liability, which has resulted in diversity in practice. The
accounting update is effective for interim and annual periods beginning after December 15, 2013. The Company evaluated the
provisions of this accounting update and does not believe it has a material impact on its financial position and results of operations.
Further, management is closely monitoring the joint standard-setting efforts of the FASB and the International Accounting
Standards Board. There are a large number of pending accounting standards that are being targeted for completion in 2015 and
beyond, including, but not limited to, accounting for leases, fair value measurements, accounting for financial instruments, disclosure
of loss contingencies and financial statement presentation. Because these pending standards have not yet been finalized, management
is not able to determine the potential future impact that these standards will have, if any, on the Company's financial position, results
of operations, or cash flows.
3. Concentration of Credit Risk
The customer base for the Company is concentrated in the natural gas and oil industry. Major purchasers of the Company’s
natural gas, oil and natural gas liquids for the year ended December 31, 2014 were ConocoPhillips Company (31%), Sunoco Inc.
(27%), Shell Trading US Company (10%), ExxonMobil Oil Corp. (7%) and Enterprise Products Operating LLC (5%). The
Company’s sales to these companies are not secured with letters of credit and in the event of non-payment, the Company could lose up
to two months of revenues. The loss of two months of revenues would have a material adverse effect on the Company’s financial
position. There are numerous other potential purchasers of the Company’s production.
4. Merger with Crimson Exploration Inc.
On October 1, 2013, the Company completed the Merger with Crimson. The Merger was effected pursuant to an Agreement
and Plan of Merger, dated as of April 29, 2013, by and among Contango, Crimson and certain subsidiaries (the “Merger Agreement”).
As a result of the Merger, each share of Crimson common stock was converted into 0.08288 shares of common stock of
Contango, and the Company issued approximately 3.9 million shares of common stock in exchange for all of Crimson's outstanding
capital stock, resulting in Crimson stockholders owning 20.3% of the post-merger Contango.
The Merger qualified as a tax-free reorganization for U.S. federal income tax purposes, so that none of the Company,
Crimson, or any of its stockholders recognized any gain or loss in the Merger, except that Crimson's stockholders may have
recognized gain or loss with respect to cash received in lieu of fractional shares of Company common stock.
F-13
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The Merger was accounted for as a business combination in accordance with ASC 805 which, among other things, requires
assets acquired and liabilities assumed to be measured at their acquisition date fair values. Crimson's results of operations are reflected
in the Company's consolidated statement of operations, beginning October 1, 2013.
The following table summarizes the consideration transferred and the fair value of assets acquired, and liabilities assumed as
of the date of the Merger (in thousands, except for number of shares and share price):
Consideration transferred:
Crimson common stock to be acquired by the Company
Exchange ratio of the Company common shares for each Crimson common share
The Company common stock to be issued to Crimson stockholders
Closing price of the Company common stock on October 1, 2013
Fair value of common stock issued
Cash paid for partial shares
Fair value of stock options issued
Total estimated consideration transferred
Fair value of other liabilities assumed:
Current liabilities
Long-term debt
Asset retirement obligations and other non-current liabilities
Amount attributable to liabilities assumed
Total consideration including liabilities assumed
Fair value of assets acquired:
Current assets
Current and non-current deferred tax asset, net
Natural gas and oil properties, net
Other non-current assets
Amount attributable to net assets acquired
Goodwill
46,624,721
0.08288
3,864,101
37.75
145,870
6
698
146,574
60,124
235,373
12,967
308,464
455,038
13,492
24,905
416,433
208
455,038
—
$
$
$
$
$
$
$
$
As of December 31, 2013, estimates of the fair value of assets acquired and liabilities assumed were preliminary and based
on information available at that time. The fair value estimate of certain of Crimson's assets and liabilities, including asset retirement
obligations and current and deferred tax balances, could not be finalized at December 31, 2013 due to information not being available
to the Company. During the quarter ended June 30, 2014, the Company completed an analysis of Crimson’s asset retirement
obligations as of the acquisition date. Based on this analysis, the Company recorded a measurement period adjustment of $2.5 million
to increase the asset retirement obligations liability. As of September 30, 2014, the Company had finalized the purchase price
allocation for the Merger.
Consideration paid by the Company consisted of approximately 3.9 million shares of Contango’s common stock issued in
exchange for 46.6 million of Crimson’s shares outstanding as of September 30, 2013, including restricted stock vesting at the
Transaction date and approximately 136,000 of vested Contango stock options issued to Crimson’s employees in exchange for all
Crimson stock options issued and outstanding as of September 30, 2013. The number of options granted and the strike price of the
options was adjusted using the same conversion ratio as for the exchange of common stock. All of Crimson’s restricted shares and
stock options vested immediately prior to the merger.
F-14
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The purchase price was calculated assuming fair value of the Company’s stock of $37.75 per share based upon the closing
price of the Company’s common stock as of October 1, 2013.
Fair value of the Company’s options issued in exchange for Crimson’s stock options was calculated using the Black-Scholes
Model by applying the following weighted-average assumptions: (a) risk-free interest rate of 0.62% to 1.35%; (b) expected life of 2.70
to 4.79 years; (c) expected volatility of 29.3% to 38.6%; and (d) expected dividend yield of 0%. The weighted average fair value per
share for the options was estimated to be $5.14.
Immediately subsequent to the closing of the Merger, the Company assumed and immediately repaid Crimson’s $175.0
million term loan with Barclays Bank PLC ("Barclays") and other lenders, its $58.6 million in loans outstanding under its senior
revolving credit facility with Wells Fargo and other lenders, and $1.8 million in accrued interest and prepayment premiums.
In order to finance the assumed debt, the Company entered into a $500 million four-year revolving credit facility with Royal
Bank of Canada and other lenders (the “RBC Credit Facility”) with an initial hydrocarbon supported borrowing base of $275 million.
The RBC Credit Facility replaced the Company's $40 million revolving credit facility with Amegy Bank. The Company incurred $2.2
million of arrangement and upfront fees in connection with the RBC Credit Facility. Borrowings under the RBC Credit Facility bear
interest at a rate that is dependent upon LIBOR or the U.S. prime rate of interest, plus a margin dependent upon the amount
outstanding. On October 1, 2013, the $235.4 million of assumed debt, accrued interest, and prepayment premium and $2.2 million of
arrangement and upfront fees under the RBC Credit Facility were paid with the Company's existing cash of $127.6 million and
drawings under the Company’s RBC Credit Facility of $110.0 million. For the period from October 1, 2013 through December 31,
2013, the effective interest rate on the facility was 2.2%.
Fair value of the deferred tax liabilities was calculated giving the tax effect of step-up adjustment for oil and gas properties.
Contango received carryover tax basis in Crimson’s assets and liabilities because the merger is not a taxable transaction under the
United States Internal Revenue Code. Based upon the purchase price allocation, a step-up in financial reporting carrying value related
to the property to be acquired from Crimson resulted in an additional deferred tax liability of approximately $42.8 million assuming a
37% expected effective tax rate of the combined company.
Additionally, fair value of the deferred tax assets was increased by approximately $10.2 million due to elimination of a
valuation allowance included in the historical financial statements of Crimson. This adjustment is based on the expectation that it is
more likely than not that the majority of $110 million of Crimson’s accumulated Net Operating Losses ("NOLs") will be realized by
the combined company in the foreseeable future. The fair value of Crimson’s oil and gas properties acquired was determined by using
commodity prices based on future expected prices for oil, natural gas and NGLs, after adjustment for transportation fees and regional
price differentials.
There is no goodwill attributable to the Merger as the consideration transferred did not exceed the fair value of Crimson's net
assets acquired on October 1, 2013.
Crimson contributed revenues of $143.4 million and pre-tax income of $4.9 million to the Company for the year ended
December 31, 2014. Crimson contributed revenues of $33.4 million and a loss of $0.7 million to the Company for the period from
October 1, 2013 to December 31, 2013. The following unaudited pro forma summary presents consolidated information of the
Company as if the Merger had occurred on January 1, 2012 (in thousands):
Revenue
Net income (loss)
Year Ended December 31
2013
2012
$
$
(Unaudited)
256,594
40,166
$
$
261,772
(83,912)
The unaudited pro forma amounts have been calculated after applying the Company's accounting policies and adjusting the
results of Crimson to reflect the additional depletion that would have been charged assuming the fair value adjustment to oil and gas
properties had been applied from January 1, 2012, together with the consequential tax effects. The pro forma depletion for each period
F-15
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
presented was calculated based on the value of the oil and gas properties acquired giving effect to the fair value adjustments as a result
of acquisition accounting and estimated DD&A rate for each period. This depletion rate was calculated by dividing production for the
period by the beginning of the period proved reserves (calculated by adding back production to the ending proved reserves as of
December 31, 2013). The combined historical depreciation, depletion and amortization expenses for the year ended December 31,
2013 and 2012 were increased by $1.9 million and $7.5 million, respectively, including $0.6 million and $0.4 million related to
amortization of debt issuance costs for a new credit facility.
The pro forma interest expense for each period presented was adjusted to reflect the results of the repayment of the $175
million principal balance of the Second Lien Loan using cash available at the Merger date and total borrowings of $110.0 million
under the new RBC Credit Facility, as if such repayment had occurred on January 1, 2012, which reduced total combined interest
expenses for the years ended December 31, 2013 and 2012 by $16.0 million and $21.3 million, respectively. The expense related to
the amortization of the original issue discount on the Second Lien Loan was also eliminated for each period. The reduction in interest
expense is offset by amortization of the debt issuance costs related to the debt refinancing which took take place at the Merger date,
net of amortization related to the debt issuance costs for the historical Crimson First and Second Lien agreement that was refinanced
upon closing of the Merger.
The pro forma net income was not adjusted for combined historical impairment charges of $2.9 million and $132.0 million
for the years ended December 31, 2013 and 2012, respectively.
Historical financial statements of Contango for the year ended December 31, 2013 include approximately $6.8 million of
Merger related costs, including bankers success fees of $2.8 million and an accrued expense of $1.3 million related to bonus payable
to Mr. Joseph J. Romano as a result of successfully completing the Merger. These expenses are included in general and administrative
expense in the Company's consolidated statements of income for the respective periods.
Pro forma net income for the year ended December 31, 2013 does not include $5.7 million of stock based compensation
expenses related to vesting of Crimson stock options on October 1, 2013 as a result of the Merger, amortization of debt issuance cost
of $0.8 million, amortization of the remaining balance of debt discount of $3.7 million for Crimson debt as of the date of the Merger,
and other Merger related costs, including $2.8 million bankers success fees, which were recognized in Crimson's results of operations
for the period October 1, 2013, which is not included in consolidated financial statements of the Company. Pro forma net income also
does not include benefit related to release of valuation allowance of $10.2 million in relation with the Merger. Although such expenses
relate to the Merger, they do not represent recurring expenses and, therefore, are not included in the pro forma results of operations.
5. Acquisitions, Dispositions and Gains from Affiliates
Acquisition of Additional Interest in Dutch
In December 2013, the Company exercised a preferential right and purchased an additional 7.84% working interest and
6.53% net revenue interest in the five Contango-operated Dutch wells from an independent oil and gas company for $18.8 million,
subject to a purchase price adjustment, based on production and operating expenses between the effective date of July 1, 2013 and the
closing date of December 12, 2013. During 2014, a purchase price adjustment of approximately $4.1 million reduced the purchase
price to a total of $14.7 million, net to the Company.
Southeast Texas Disposition
On December 31, 2013, the Company sold to an independent oil and gas company approximately 7.1% of its interest in all
developed and undeveloped properties in Madison and Grimes Counties for $20 million, subject to a purchase price adjustment, based
on production and operating expenses between the effective date of July 1, 2013 and the closing date of December 31, 2013. A
preliminary estimated adjustment to the sales price of approximately $0.4 million to increase the purchase price was recorded in 2013,
and an adjustment of approximately $0.1 million to reduce the purchase price was recorded in 2014 resulting in final proceeds of
$20.3 million. A loss of approximately $0.2 million and a gain of approximately $6.6 million related to this sale were recognized in
the years ended December 31, 2014 and 2013, respectively.
F-16
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Proceeds from Alta
In August 2013, Alta sold its interest in the liquids-rich Kaybob Duvernay, which closed in October 2013 for approximately
$30.5 million, net to Contango. Contango has a 2% interest in Alta and a 5% interest in the Kaybob Duvernay project. The total
distribution received from Alta during the year ended December 31, 2013 was approximately $23.1 million. An additional $5.4
million was received during 2014. The Company expects to receive the remaining $2.0 million within the next twelve months. The
total distributions from Alta are expected to exceed the Company’s original investment by $15.3 million.
6. Fair Value Measurements
Pursuant to ASC 820, Fair Value Measurements and Disclosures (ASC 820), the Company's determination of fair value
incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on
the Company's consolidated balance sheets, but also the impact of the Company's nonperformance risk on its own liabilities. ASC 820
defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between
market participants at the measurement date (exit price). ASC 820 establishes a fair value hierarchy that prioritizes the inputs to
valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active
markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are
inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The
Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions
about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated,
or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.
The following table sets forth by level within the fair value hierarchy the Company's financial assets and liabilities that were
accounted for at fair value as of December 31, 2013. As required by ASC 820, a financial instrument's level within the fair value
hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the
significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and
liabilities and their placement within the fair value hierarchy levels. There have been no transfers between Level 1, Level 2 or Level 3.
Fair value information for financial assets and (liabilities) was as follows at December 31, 2013 (in thousands):
Total
Fair Value Measurements Using
Carrying Value
Level 1
Level 2
Level 3
Derivatives
Commodity price contracts - assets
Commodity price contracts - liabilities
$
$
76
(1,207)
$
$
— $
— $
76
(1,207)
$
$
—
—
The Company did not have any outstanding commodity price contracts as of December 31, 2014.
Derivatives listed above include swaps and collars that are carried at fair value. The Company records the net change in the
fair value of these positions in "Gain (loss) on derivatives, net" in the Company's consolidated statements of operations. The Company
is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company
reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted markets
prices and implied volatility factors related to changes in the forward curves. See Note 7 - "Derivative Instruments" for additional
discussion of derivatives.
As of December 31, 2013, the Company's derivative contracts were with major financial institutions with investment grade
credit ratings which are believed to have a minimal credit risk. As such, the Company is exposed to credit risk to the extent of
nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate such
nonperformance. Some of the counterparties to the Company's current derivative contracts are lenders in the Company's RBC Credit
Facility. The Company did not post collateral under any of these contracts as they are secured under the RBC Credit Facility.
F-17
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Estimates of the fair value of financial instruments are made in accordance with the requirements of ASC 825, Financial
Instruments. The estimated fair value amounts have been determined at discrete points in time based on relevant market information.
These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable
and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company's RBC
Credit Facility approximates carrying value because the interest rate approximates current market rates and are re-set at least every
three months. See Note 13 - "Long-Term Debt" for further information.
Fair value estimates used for non-financial assets are evaluated at fair value on a non-recurring basis include oil and gas
properties evaluated for impairment when facts and circumstances indicate that there may be an impairment. If the unamortized cost of
properties exceeds the undiscounted cash flows related to the properties, the value of the properties is compared to the fair value
estimated as discounted cash flows related to the risk-adjusted proved, probable and possible reserves related to the properties. Fair
value measurements based on these inputs are classified as Level 3.
Impairments
Contango tests proved oil and gas properties for impairment when events and circumstances indicate a decline in the
recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity
prices. The Company estimates the undiscounted future cash flows expected in connection with the oil and gas properties on a field by
field basis and compares such future cash flows to the unamortized capitalized costs of the properties. If the estimated future
undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to its fair value. The factors
used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the
timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining
for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. Because
these significant fair value inputs are typically not observable, impairments of long-lived assets are classified as a Level 3 fair value
measure.
Asset Retirement Obligations
The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and based on internal
estimates of future retirement costs associated with oil and gas properties. The factors used to determine fair value include, but are not
limited to, estimated future plugging and abandonment costs and expected lives of the related reserves.
7. Derivative Instruments
The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative
contracts are utilized to hedge the Company's exposure to price fluctuations and reduce the variability in the Company's cash flows
associated with anticipated sales of future oil and natural gas production. Recently, the Company had hedged a substantial, but
varying, portion of anticipated oil and natural gas production for future periods. The Company believes that these derivative
arrangements, although not free of risk, allowed us to achieve a more predictable cash flow and to reduce exposure to commodity
price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of crude oil, natural gas and natural
gas liquids sales. Moreover, the Company’s derivative arrangements applied only to a portion of its production and provided only
partial protection against declines in commodity prices. Such arrangements may expose us to risk of financial loss in certain
circumstances. The Company continuously reevaluates its hedging programs in light of changes in production, market conditions, and
commodity price forecasts.
As of December 31, 2014, the Company did not have any outstanding derivative positions. Swaps are designed so that the
Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. A
costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract and
a purchased put that establishes a minimum price. A sold put option limits the exposure of the counterparty's risk should the price fall
below the strike price. Sold put options limit the effectiveness of purchased put options at the low end of the put/call collars to market
prices in excess of the strike price of the put option sold.
F-18
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
It is the Company's policy to enter into derivative contracts only with counterparties that are creditworthy financial
institutions deemed by management as competent and competitive market makers. The counterparties to the Company's previous
derivative contracts were lenders or affiliates of lenders in the RBC Credit Facility. The Company did not post collateral under any of
these contracts as they are secured under the RBC Credit Facility.
The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, derivatives are
carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the
consolidated statements of operations for the period in which the change occurs. The Company records the net change in the mark-to-
market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in "Gain (loss) on
derivatives, net" on the consolidated statements of operations. See Note 6 – “Fair Value Measurements” for additional information.
There was no activity or outstanding derivative contracts during the year ended December 31, 2012.
The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31,
2013 (in thousands):
Assets
Liabilities
Gross
Netting (1)
Total
$
$
76
(1,207)
$
$
(76)
76
$
$
—
(1,131)
(1) Represents counterparty netting under agreements governing such derivatives
F-19
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The following table summarizes the effect of derivative contracts on the Consolidated Statements of Operations for the years
ended December 31, 2014 and 2013 (in thousands):
Contract Type
2014
2013
Year ended December 31,
Crude oil contracts
Natural gas contracts
Realized gain (loss)
Crude oil contracts
Natural gas contracts
Unrealized gain (loss)
Gain (loss) on derivatives, net
$
$
$
$
$
276
(1,560)
(1,284)
1,183
(52)
1,131
(153)
$
$
$
$
$
180
98
278
(1,179)
(231)
(1,410)
(1,132)
There were no gains or losses related to derivative instruments for the year ended December 31, 2012.
8. Stock Based Compensation
As of December 31, 2014, the Company had in place a share-based compensation program which allows for stock options
and/or restricted stock to be awarded to officers, directors and employees as a performance-based award or granted upon initial
employment as part of their overall compensation package. This program includes (i) the Company's Amended and Restated 2009
Incentive Compensation Plan (the “2009 Plan”); and (ii) the Crimson 2005 Stock Incentive Plan (the “2005 Plan” or "Crimson Plan")
adopted in conjunction with the Merger.
Amended and Restated 2009 Incentive Compensation Plan
On September 15, 2009, the Company’s Board of Directors (the “Board”) adopted the Contango Oil & Gas Company Equity
Compensation Plan (the “Original 2009 Plan”). On April 10, 2014, the Board amended and restated the Original 2009 Plan thorugh
the adoption of the Contango Oil & Gas Company Amended and Restated 2009 Incentive Compensation Plan. The 2009 Plan provides
for both cash awards and equity awards (such as restricted stock and options) to officers, directors, employees or consultants of the
Company. Awards made under the 2009 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as
may be determined by the Board.
Under the terms of the 2009 Plan, up to 1,500,000 shares of the Company’s common stock may be issued for plan awards.
Stock options under the 2009 Plan must have an exercise price of each option equal to or greater than the market price of the
Company’s common stock on the date of grant. The Company may grant officers and employees both incentive stock options intended
to qualify under Section 422 of the Internal Revenue Code of 1986, as amended, and stock options that are not qualified as incentive
stock options. Stock option grants to non-employees, such as directors and consultants, can only be stock options that are not qualified
as incentive stock options. Options granted generally expire after five or ten years. The vesting schedule varies, and can vest over a
two, three or four-year period.
As of December 31, 2014, the Company had approximately 1.1 million shares of common stock and stock options available
for future grant under the 2009 Plan. On February 24, 2014, the Company granted 1,103 restricted stock awards under the 2009 Plan.
Effective January 1, 2014, the Company implemented performance-based long-term bonus plans under the 2009 Plan for the
benefit of all employees through a Cash Incentive Bonus Plan (“CIBP”) and a Long-Term Incentive Plan (“LTIP”). The specific
targeted performance measures under these sub-plans are approved by the Compensation Committee and/or the Board. Upon
achieving the performance levels established each year, bonus awards under the CIBP and LTIP will be calculated as a percentage of
base salary of each employee for the plan year. The CIBP and LTIP plan awards for each year are expected to be disbursed in the first
quarter of the following year. Employees must be employed by the Company at the time that awards are disbursed to be eligible.
The CIBP awards will be paid in cash while LTIP awards will consist of restricted common stock and/or stock options. The
stock and/or option awards are expected to vest 25% per year, over the first through fourth anniversaries from the date of grant. The
F-20
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
number of shares of restricted common stock and the number of shares underlying the stock options granted will be determined based
upon the fair market value of the common stock on the date of the grant.
2005 Stock Incentive Plan
The 2005 Plan was adopted by the Company's Board in conjunction with the Merger with Crimson. Under the 2005 Plan, the
Board may grant incentive stock options, nonstatutory stock options, restricted awards, unrestricted awards, performance awards,
stock appreciation rights and dividend equivalent rights to eligible officers, directors, employees or consultants of the Company and its
affiliates. Awards made under the 2005 Plan are subject to such terms and conditions, without limitation, as may be determined by the
Board. Options granted generally expire after ten years. The vesting schedule varies but generally vests over a one or four-year period.
Upon adoption of the 2005 Plan at the Merger closing date, a total of 135,898 stock option awards and 136,428 shares of restricted
stock (as converted, which all fully vested upon the Merger) were already issued and outstanding, leaving a balance of 43,472 shares
of common stock or stock options available to be granted to Company employees and directors.
As of December 31, 2014, there were 7,030 shares of common stock and stock options available to be granted under the 2005
Plan. On February 24, 2015, the Company granted 7,030 restricted stock awards under the 2005 Plan to a new employee. This plan
expired on February 25, 2015.
1999 Stock Incentive Plan
The Company’s 1999 Stock Incentive Plan (the “1999 Plan”) expired in August 2009. The final 45,000 outstanding options
issued under the 1999 Plan were exercised and sold to the Company in February 2012.
Stock Options
During the year ended December 31, 2014, the Company did not issue any stock options. However, 4,165 stock options that
were previously issued were exercised and the resulting shares of common stock were sold in the open market, leaving 129,934 stock
options vested and exercisable at December 31, 2014, with exercise prices ranging from $25.70 to $60.33 per share, with an average
remaining contractual life of six years.
During the year ended December 31, 2013, employees exercised 791 stock options to purchase shares of the Company’s
common stock that were sold in the open market.
F-21
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
A summary of the stock options granted under the 1999 Plan, 2009 Plan, and 2005 Plan as of and for the years ended
December 31, 2014, 2013, and 2012 is presented in the table below (dollars in thousands, except per share data):
Year Ended December 31,
2014
2013
2012
Shares
Under
Options
Weighted
Average
Exercise
Price
Shares
Under
Options
Weighted
Average
Exercise
Price
Shares
Under
Options
Weighted
Average
Exercise
Price
Outstanding, beginning of the period
135,107 $
53.00
— $
Options assumed due to Merger
— $
—
135,898 $
Exercised
Canceled / Forfeited (1)
Outstanding, end of year
Aggregate intrinsic value
Exercisable, end of year
Aggregate intrinsic value
Available for grant, end of the period
Weighted average fair value of options granted
during the period
(4,165) $
(1,008) $
129,934 $
4
28.93
42.39
53.85
129,934 $
53.85
4
1,143,006
—
$
$
$
—
52.90
36.16
—
45,000 $
54.21
— $
— $
—
—
(45,000) $
54.21
(791) $
— $
135,107 $
53.00
459
135,107 $
53.00
459
1,162,173
—
— $
—
— $
—
1,475,000
—
$
$
$
$
$
$
—
—
(1) For the year ended December 31, 2012, forfeited options consist of options that were net-settled for cash with the Company.
Under the fair value method of accounting for stock options, cash flows from the exercise of stock options resulting from tax
benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing cash flows. For the year
ended December 31, 2014, there was an insignificant excess tax benefit recognized. For the year ended December 31, 2013, there was
no excess tax benefits recognized. For the year ended December 31, 2012, approximately $0.3 million of such excess tax benefits were
classified as financing cash flows, respectively. See Note 2 – "Summary of Significant Accounting Policies".
Compensation expense related to employee stock option grants are recognized over the stock option’s vesting period based
on the fair value at the date the options are granted. The fair value of each option is estimated as of the date of grant using the Black-
Scholes options-pricing model.
During the years ended December 31, 2014 and 2013, the Company did not recognize any stock option expense. During the
year ended December 31, 2012, the Company recognized a stock option gain of approximately $154,000 due to evaluating the market
price of options on a quarterly basis. The aggregate intrinsic value of stock options exercised/forfeited during the years ended
December 31, 2014, 2013 and 2012 was approximately $59,009, $7,721 and $0.5 million, respectively.
Restricted Stock
During the year ended December 31, 2014, the Company issued 10,714 restricted stock awards to new and existing
employees, which vest over four years, plus an additional 15,672 restricted stock awards to the board of directors which vest on the
one-year anniversary of the date of grant. The weighted average fair value of the restricted shares granted during the year, was $40.83
with a total fair value of approximately $1.1 million after adjustment for estimated weighted average forfeiture rate of 2.2%.
In November 2013, the Company issued 254,677 shares of restricted common stock to senior officers and certain other vice
presidents, of which 25 percent vested immediately and the remaining balance vests over a three-year period. Also in November 2013,
the Company issued 1,802 shares of restricted common stock to newly hired employees as part of their compensation package, which
vest over a four-year period. In December 2013, the Company issued 88,466 shares of restricted common stock to Company
employees which vest over a four-year period, plus an additional 11,354 shares of restricted common stock to the board of directors as
F-22
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
compensation pursuant to the Company’s new director compensation plan which vest on the one-year anniversary of the date of grant.
The weighted average fair value of the restricted shares granted during the fourth quarter of 2013, was $44.10 with a total fair value of
approximately $8.1 million after adjustment for estimated weighted average forfeiture rate of 5.7%.
The Company did not grant any shares of restricted stock for the year ended December 31, 2012 and did not have any
restricted shares outstanding as of December 31, 2012.
Restricted stock activity as of December 31, 2014 and 2013 and for the years then ended is presented in the table below
(dollars in thousands, except per share data):
2014
Weighted
2013
Weighted
Restricted Average
Aggregate
Restricted Average
Aggregate
Shares
Fair Value
Intrinsic Value
Shares
Fair Value
Intrinsic Value
Outstanding, beginning of the period
292,632 $
44.38 $
13,830
— $
— $
Granted
Vested
Canceled / Forfeited
Not vested, end of the period
Vested, end of the period
Expected to vest, end of the period
26,386
(94,807)
(14,249)
209,962
—
192,570
40.83
44.11
47.30
43.86
—
43.84
1,073
3,454
579
6,139
—
5,631
356,299
(63,667)
—
292,632
—
260,359
44.10
42.80
—
44.38
—
44.36
—
15,723
2,725
—
13,830
—
12,305
During the year ended December 31, 2014, the Company recognized approximately $4.5 million in stock compensation
expense. During the quarter ended December 31, 2013, the Company recognized approximately $3.2 million in stock compensation
expense for restricted shares granted to its officers, employees and directors. An additional $7.7 million of compensation expense will
be recognized over the remaining vesting period.
9. Share Repurchase Program
In September 2011, the Company’s board of directors approved a $50 million share repurchase program. All shares are to be
purchased in the open market or through privately negotiated transactions. Purchases are made subject to market conditions and
certain volume, pricing and timing restrictions to minimize the impact of the purchases upon the market, and when the Company
believes its stock price to be undervalued. Repurchased shares of common stock became authorized but unissued shares, and may be
issued in the future for general corporate and other purposes. During the year ended December 31, 2014, the Company purchased
205,457 shares at an average price of $35.89 per share, for a total of approximately $7.4 million. No shares were purchased during the
year ended December 31, 2013. During the year ended December 31, 2012, the Company purchased 162,214 shares at an average
price of $51.62 per share, for a total of approximately $8.4 million, plus it net-settled 45,000 stock options from two employees for a
total of $465,000.
As of December 31, 2014, the Company had invested $18.2 million in this share repurchase program to purchase 403,334
shares and net-settled 45,000 stock options from two officers, leaving $31.8 million available for future purchases.
In October 2014, the Company amended its revolving credit facility with Royal Bank of Canada to, among other things,
allow for share repurchases subject to certain conditions. The Company is currently in compliance with these additional restrictions.
F-23
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
10. Other Financial Information
The following table provides additional detail for accounts receivable, prepaids, and accounts payable and accrued liabilities
which are presented on the consolidated balance sheets (in thousands):
December 31,
2014
December 31,
2013
Accounts receivable:
Trade receivable
Receivable for Alta Resources distribution
Joint interest billing
Income taxes receivable
Other receivables
Allowance for doubtful accounts
Total accounts receivable
Prepaid expenses and other:
Prepaid insurance
Other
Total prepaid expenses and other
Accounts payable and accrued liabilities:
Royalties and revenue payable
Accrued exploration and development
Trade payable
Advances from partners
Accrued general and administrative expenses
Other accounts payable and accrued liabilities
Total accounts payable and accrued liabilities
$
$
$
$
$
$
13,926
1,993
4,096
3,274
2,610
(590)
25,309
1,242
699
1,941
31,653
26,538
17,282
8,334
6,258
2,827
92,892
$
$
$
$
$
$
42,196
7,358
5,172
4,293
2,172
(578)
60,613
1,113
918
2,031
44,933
17,803
11,589
6,538
10,872
5,098
96,833
Included in the table below is supplemental information about non-cash transactions during the years ended December 31,
2014, 2013 and 2012, in thousands:
Year Ended December 31,
2013
2014
2012
Cash payments:
Interest payments
Income tax payments, net of cash refunds
Non-cash items excluded from investing activities in the consolidated statements of cash flows:
Increase in accrued capital expenditures
Assets acquired & liabilities assumed in the Merger:
Accounts receivable
Prepaids
Proved natural gas and oil properties
Deferred tax asset and other
Accounts payable and accrued liabilities
Other non-current liabilities
Long-term debt
Asset retirement obligations
Non-cash items excluded from financing activities in the consolidated statements of cash flows:
Issuance of common stock in connection with the merger
F-24
$
2,786 $
241
1,056 $
341
71
24,307
8,735
7,004
1,192
—
—
2,517
—
12,955
639
413,916
24,940
—
(60,110)
—
(256)
— (235,373)
(11,183)
(2,517)
— 145,870
—
—
—
—
—
—
—
—
—
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
11. Investment in Exaro Energy III LLC
In April 2012, the Company entered into a Limited Liability Company Agreement (the “LLC Agreement”) in connection
with the formation of Exaro. Pursuant to the LLC Agreement, as amended, the Company has committed to invest up to $67.5 million
in Exaro for an ownership interest of approximately 37%. The aggregate commitment of all the Exaro investors was approximately
$183 million. The Company did not make any contributions during the year ended December 31, 2014. As of December 31, 2014, the
Company had invested approximately $46.9 million.
The following table presents condensed balance sheet data for Exaro as of December 31, 2014 and December 31, 2013. The
balance sheet data was derived from the Exaro balance sheet as of December 31, 2014 and December 31, 2013 and was not adjusted to
represent Contango’s percentage of ownership interest in Exaro. Contango’s share in the equity of Exaro at December 31, 2014 was
approximately $61.2 million.
December 31,
2014
December 31,
2013
Current assets
Non-current assets:
Net property and equipment
Restricted cash escrow account
Other non-current assets
Total non-current assets
Total assets
Current liabilities
Non-current liabilities:
Long-term debt
Other non-current liabilities
Total non-current liabilities
Members' equity
Total liabilities & members' equity
$
$
$
$
35,013
$
233,997
577
1,779
236,353
271,366
9,405
94,500
1,084
95,584
166,377
271,366
$
$
$
30,284
182,226
8,732
1,103
192,061
222,345
13,717
70,000
923
70,923
137,705
222,345
The following table presents the condensed results of operations for Exaro for the years ended December 31, 2014 and 2013
and for the period from the inception of Exaro, March 19, 2012, to December 31, 2012. The results of operations for the years ended
December 31, 2014 and 2013 and the period from inception of Exaro, March 19, 2012, to December 31, 2012 were derived from
Exaro's financial statements for the respective periods. The income statement data below was not adjusted to represent Contango’s
ownership interest but rather reflects the results of Exaro as a Company. The Company's share in Exaro's results of operations
recognized for the years ended December 31, 2014, 2013 and 2012 was a gain of $6.9 million, net of tax expense of $3.8 million; a
gain of $2.3 million, net of tax expense of $1.2 million; and a gain of $60 thousand, net of tax expense of $32 thousand, respectively.
Oil and natural gas sales
Other gain (loss)
Less:
Lease operating expenses
Depreciation, depletion, amortization & accretion
General & administrative expense
Income (loss) from continuing operations
Net interest income (expense)
Net income (loss)
Year Ended December 31,
2014
2013
79,536
5,069
$
22,452
26,036
3,484
32,633
(3,861)
28,772
$
Period from
inception to
December 31,
2012
7,514
(3,269)
2,035
2,350
2,872
(3,012)
25
(2,987)
52,698
(544)
$
16,136
16,058
3,294
16,666
(3,536)
13,130
$
$
$
F-25
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Included in Other losses are realized and unrealized losses attributable to derivatives, whose value is likely to change based
on future oil and gas prices. Exaro's results of operations do not include income taxes, because Exaro is treated as a partnership for tax
purposes.
12. Asset Retirement Obligation
The Company accounts for its retirement obligation of long lived assets by recording the net present value of a liability for an
asset retirement obligation (“ARO”) in the period in which it is incurred. When the liability is initially recorded, a compan y increases
the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the
capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the
obligation for its recorded amount or incurs a gain or loss upon settlement. Activities related to the Company’s ARO during the year
ended December 31, 2014 and 2013 were as follows (in thousands):
Balance as of the beginning of the period
Liabilities incurred during period
Liabilities settled during period
Accretion
Sales
Change in estimate
Balance as of the end of the period
Year ended December 31,
2014
2013
$
$
$
23,334
3,123
(1,963)
1,303
(69)
18
25,746
$
8,678
14,145
(207)
660
—
58
23,334
Of the total liabilities incurred during the year ended December 31, 2014, $2.5 million was due to a purchase price
adjustment for the merger with Crimson and $0.6 million related to new wells drilled during the period. All of the total liabilities
settled during the year ended December 31, 2014 related to wells plugged and abandoned during the period.
Of the total liabilities incurred during the year ended December 31, 2013, $11.2 million were assumed in conjunction with
the merger with Crimson and $2.9 million related to new wells drilled during the period. Of the total liabilities settled during the year
ended December 31, 2013, approximately $137,000 related to wells plugged and abandoned during the period and approximately
$70,000 related to the sale of assets in Madison and Grimes County to a third party. See Note 5 - "Acquisitions, Dispositions and
Gains from Affiliates."
13. Long-Term Debt
RBC Credit Facility
In connection with the Merger during 2013, the Company assumed and immediately repaid $235.4 million of Crimson debt,
including Crimson’s $175.0 million second lien term loan with Barclays Bank PLC ("Barclays") and other lenders, Crimson’s $58.6
million senior secured revolving credit facility with Wells Fargo Bank and other lenders, and a $1.8 million prepayment premium for
the second lien term loan and accrued interest. Of the amount repaid, $127.6 million was made from existing cash with the remainder
financed through new borrowing arrangements.
In order to finance the assumed debt, the Company entered into a $500 million four-year secured revolving credit facility
with Royal Bank of Canada and other lenders (the “RBC Credit Facility”) on October 1, 2013, with an initial hydrocarbon -supported
borrowing base of $275 million, which was reaffirmed on October 28, 2014 and is effective through May 1, 2015. The borrowing base
under the RBC Credit Facility is redetermined each November 1 and May 1. The Company incurred $2.2 million of arrangement and
upfront fees in connection with the RBC Credit Facility which will be amortized over the original four-year term of the RBC Credit
Facility. Proceeds of the RBC Credit Facility were, or may be used (i) to finance working capital and for general corporate purposes,
F-26
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(ii) for permitted acquisitions, and (iii) to finance transaction expenses in connection with the RBC Credit Facility and the Merger.
The total amount borrowed on October 1, 2013 was $110.0 million.
As of December 31, 2014, the Company had $63.4 million outstanding under the RBC Credit Facility, which is due by
October 1, 2017, and $1.9 million in outstanding letters of credit. As of December 31, 2013, the Company had $90.0 million
outstanding under the RBC Credit Facility and $1.9 million in outstanding letters of credit. As of December 31, 2014 borrowing
availability under the RBC Credit Facility was $209.7 million.
The RBC Credit Facility is collateralized by a lien on substantially all the assets of the Company and its subsidiaries,
including a security interest in the stock of Contango’s subsidiaries and a security interest in the Company’s oil and gas properties.
Borrowings under the RBC Credit Facility bear interest at a rate that is dependent upon LIBOR, the U.S. prime rate, or the
federal funds rate, plus a margin dependent upon the amount outstanding. Additionally, the Company must pay a commitment fee on
the amount of the facility that remains unused, which varies from .375% to .5%, depending on the amount of the credit facility that is
unused. Total interest expense under the RBC Credit Facility, including commitment fees, for the years ended December 31, 2014 and
2013 was approximately $2.7 million and $1.2 million, respectively.
The RBC Credit Facility contains restrictive covenants which, among other things, restrict the declaration or payment of
dividends by Contango and require the maintenance of a minimum current ratio and a maximum leverage ratio. As of December 31,
2014, the Company was in compliance with all covenants under the RBC Credit Facility. The RBC Credit Facility also contains events
of default that may accelerate repayment of any borrowings and/or termination of the facility. Events of default include, but are not
limited to, payment defaults, breach of certain covenants, bankruptcy, insolvency or change of control events.
Amegy Bank Credit Facility
The RBC Credit Facility replaced the Company's $40 million credit facility with Amegy Bank. On October 22, 2010, the
Company completed the arrangement of a secured revolving credit agreement with Amegy Bank (the “Amegy Credit Agreement”) to
replace its expiring credit agreement with BBVA Compass Bank. The Amegy Credit Agreement had a $40 million hydrocarbon
borrowing base and was available to fund the Company’s exploration and development activities, as well as repurchase shares o f
common stock, pay dividends, and fund working capital as needed. The Amegy Credit Agreement was secured by substantially all of
the assets of the Company. Borrowings under the Amegy Credit Agreement would bear interest at LIBOR plus 2.5%, subject to a
LIBOR floor of 0.75%. The principal was due October 1, 2014, and could be prepaid at any time with no prepayment penalty. An
arrangement fee of $300,000 was paid in connection with the facility and a commitment fee of 0.125% was owed on unused
borrowing capacity. The Amegy Credit Agreement contained customary covenants including limitations on the Compnay’s current
ratio and additional indebtedness. Upon termination of the Amegy Credit Agreement, the Company was in compliance with all
covenants and had no amounts outstanding. No early termination penalty was incurred as a result of the termination of the Amegy
Credit Agreement. Interest expense under the Amegy Credit Agreement for the years ended December 31, 2013 and 2012 was
approximately $37,000 and $50,000, respectively.
14. Commitments and Contingencies
Contango pays delay rentals on its offshore leases and leases its office space and certain other equipment. Effective October
1, 2013, the Company moved its corporate offices to 717 Texas Avenue in downtown Houston, Texas, under a lease that expires
March 31, 2019. The Company remains responsible for the rent at its previous corporate office at 3700 Buffalo Speedway in Houston,
Texas, through February 29, 2016; however, effective January 1, 2014, it subleased the previous corporate offices through February
29, 2016 and expects to recover the substantial majority of the rent it pays at that location.
F-27
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
As of December 31, 2014, minimum future lease payments for delay rentals and operating leases for Contango’s fiscal years
are as follows (in thousands):
Fiscal years ending December 31,
2015
2016
2017
2018
2019
2020 and thereafter
Total
$
$
3,867
2,158
1,948
1,694
416
—
10,083
The amount incurred under operating leases and delay rentals during the years ended December 31, 2014, 2013, and 2012
were approximately $6.0 million, $1.0 million and $0.5 million, respectively. As of December 31, 2014, the Company’s commitment
for potential future equity contributions with Exaro Energy III, LLC to develop onshore natural gas assets, was $20.6 million.
In July 2012, the Company granted year-end bonuses to employees and certain consultants to incentivize the individuals to
remain with the Company. The final portion of these bonuses were paid on June 30, 2014.
In conjunction with the merger with Crimson (See Note 4 - "Merger with Crimson Exploration Inc."), certain employees did
not remain with the Company. The Company entered into agreements with these individuals and paid approximately $0.4 million in
severance payments during 2013.
Legal Proceedings
From time to time, the Company is involved in legal proceedings relating to claims associated with its properties, operations
or business or arising from disputes with vendors in the normal course of business, including the material matters discussed below.
Mineral interest owners in South Louisiana filed suit against a subsidiary of the Company and several co-defendants in June
2009 in the 31st Judicial District Court situated in Jefferson Davis Parish, Louisiana alleging failure to act as a reasonably prudent
operator, failure to explore, waste, breach of contract, etc. in connection with two wells located in Jefferson Davis Parish. Many of the
alleged improprieties occurred prior to the Company’s ownership of an interest in the wells at issue, although the Company may have
assumed liability otherwise attributable to its predecessors-in-interest through the acquisition documents relating to the acquisition of
the Company’s interest in these wells. The Company and its co-defendants obtained a favorable judgment from the trial court
following a bench trial. On October 1, 2014, the Louisiana Third Circuit Court of Appeals issued an opinion reversing the trial court’s
rulings and rendering judgment in favor of the plaintiffs for approximately $13.4 million. The decision by the court of appeals did not
allocate liability among the defendants although the Company would likely be responsible for at least one-half, and possibly as much
as two-thirds, of the judgment if it stands. The Company and its co-defendants have filed an application for a writ of certiorari to the
Louisiana Supreme Court seeking review of this case by the state’s highest court. While there is uncertainty whether the Loui siana
Supreme Court will accept the Company’s application and, if accepted, rule in its favor, the Company believes that the decision by the
court of appeals presents issues that will resonate with the Louisiana Supreme Court and are of precedential significance sufficient to
warrant review by that court. The Company and its co-defendants are vigorously defending this lawsuit and believe that they have a
meritorious position. A companion case involving the same set of facts was filed in the same trial court on April 19, 2013 on behalf of
additional mineral interest owners but has been inactive pending the appeal of the original case. The Company’s potential exposure in
this companion case is expected to be affected by the outcome of the Company’s appeal of the original case.
In November 2010, a subsidiary of the Company, several predecessor operators and several product purchasers were named
in a lawsuit filed in the District Court for Lavaca County in Texas by an entity alleging that it owns a working interest in two wells
that has not been recognized by us or by predecessor operators to which the Company had granted indemnification rights. In dispute is
whether ownership rights were transferred through a number of decade-old poorly documented transactions. Based on prior summary
judgments, the trial court recently entered a final judgment in the case in favor of the plaintiffs for approximately $5.3 million, plus
F-28
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
post-judgment interest. The Company is vigorously defending this lawsuit, believes that it has meritorious defenses and is appealing
the trial court’s decision to the applicable state Court of Appeals.
In September 2012, a subsidiary of the Company was named as defendant in a lawsuit filed in district court for Harris County
in Texas involving a title dispute over a 1/16th mineral interest in the producing intervals of certain wells operated by us in the
Catherine Henderson “A” Unit in Liberty County in Texas. This case was subsequently transferred to the district court for Liberty
County, Texas and combined with a suit filed by other parties against the plaintiff claiming ownership of the disputed interest. The
plaintiff has alleged that, based on its interpretation of a series of 1972 deeds, it owns an additional 1/16th unleased mineral interest in
the producing intervals of these wells on which it has not been paid (this claimed interest is in addition to a 1/16th unleased mineral
interest on which it has been paid). The Company has made royalty payments with respect to the disputed interest in reliance, in part,
upon leases obtained from successors to the grantors under the aforementioned deeds, who claim to have retained the disputed mineral
interests thereunder. The plaintiff previously alleged damages of approximately $10.7 million although the plaintiff’s claim increases
as additional hydrocarbons are produced from the subject wells. The Company is vigorously defending this lawsuit and believes that it
has meritorious defenses. The Company believes if this matter were to be determined adversely, amounts owed to the plaintiff could
be partially offset by recoupment rights the Company may have against other working interest and/or royalty interest owners in the
unit.
In connection with the Merger, several class action lawsuits were brought by Crimson stockholders in Delaware and Texas
seeking damages and injunctive relief. Each of these merger-related cases has now been dismissed by the respective court without
liability to the Company.
In February 2011, a subsidiary of the Company and certain of its working interest partners and insurance carriers brought suit
against a marine construction, dredging and tunneling company and an instrumentality of the United States of America in the U.S.
District Court for the Southern District of Texas – Houston Division seeking monetary damages for damage to an offshore pipeline
which was struck by a dredge. Following a bench trial in December 2013, the Company and its co-defendants obtained a favorable
judgment from the trial court. The defendants are appealing the trial court’s judgment to the U.S. Court of Appeals for the 5th Circuit.
While many of these matters involve inherent uncertainty and the Company is unable at the date of this filing to estimate an
amount of possible loss with respect to certain of these matters, the Company believes that the amount of the liability, if any,
ultimately incurred with respect to these proceedings or claims will not have a material adverse effect on its consolidated financial
position as a whole or on its liquidity, capital resources or future annual results of operations. The Company maintains various
insurance policies that may provide coverage when certain types of legal proceedings are determined adversely.
Employment Agreements
As a result of successfully completing the Merger, Mr. Joseph J. Romano, the Company's Chairman and former Chief
Executive Officer received a $4.0 million bonus payment in July 2014.
In connection with the Merger, Contango entered into employment agreements with each of Allan D. Keel, E. Joseph Grady,
A. Carl Isaac, Jay S. Mengle and Thomas H. Atkins, which all became effective on October 1, 2013. The employment agreements
provide for a term of three years with automatic two-year extensions of the initial term, unless Contango or the executive provides
prior notice of intention not to extend the agreement. The employment agreements replaced the June 29, 2011 employment agreements
between Crimson and Messrs. Keel, Grady, Mengle and Atkins, and the April 18, 2012 employment agreement between Crimson and
Mr. Isaac, except as described below.
Under the new employment agreements, Mr. Keel is entitled to a base salary of $600,000, Mr. Grady is entitled to a base
salary of $400,000, Mr. Isaac is entitled to a base salary of $320,000, Mr. Mengle is entitled to a base salary of $300,000 and Mr.
Atkins is entitled to a base salary of $310,000. Each executive shall participate in the CIBP and the LTIP. With respect to the CIBP,
these employee agreements provide that the executives are eligible to receive a cash bonus based upon minimum, target and maximum
award levels of not less than 50%, 100% and 150% for Mr. Keel; 50%, 90% and 130% for Mr. Grady; and 50%, 80% and 120% for
Messrs. Isaac, Mengle and Atkins, respectively, of such executive’s base salary. With respect to the LTIP, these employee agreements
provide that the executives are eligible to receive stock option awards, restricted stock awards or a combination of both upon
F-29
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
minimum, target and maximum award levels of not less than 75%, 350% and 450% for Mr. Keel; 75%, 250% and 450% for Mr.
Grady; and 75%, 250% and 350% for Messrs. Isaac, Mengle and Atkins, respectively, of such executive’s base salary.
15. Net Income (Loss) Per Common Share
A reconciliation of the components of basic and diluted net income per common share for the years ended December 31,
2014, 2013 and 2012 is presented below (in thousands):
Basic Earnings per Share:
Net loss attributable to common stock
Diluted Earnings per Share:
Effect of potential dilutive securities:
Stock options, weighted average of incremental shares
Net loss attributable to common stock
Basic Earnings per Share:
Net income attributable to common stock
Diluted Earnings per Share:
Effect of potential dilutive securities:
Stock options, weighted average of incremental shares
Net income attributable to common stock
Basic Earnings per Share:
Loss from continuing operations
Discontinued operations, net of income taxes
Net loss attributable to common stock
Diluted Earnings per Share:
Loss from continuing operations
Discontinued operations, net of income taxes
Net loss attributable to common stock
Year Ended December 31, 2014
Net Loss
Shares
Per Share
(21,874)
19,059 $
(1.15)
—
(21,874)
—
19,059 $
—
(1.15)
Year Ended December 31, 2013
Net Income
Shares
Per Share
41,362
16,156 $
2.56
—
41,362
2
16,158 $
—
2.56
Year Ended December 31, 2012
Net Loss
Shares
Per Share
(907)
(29)
(936)
(907)
(29)
(936)
15,295 $
15,295
15,295 $
15,295 $
15,295
15,295 $
(0.06)
—
(0.06)
(0.06)
—
(0.06)
$
$
$
$
$
$
$
$
The numerator for basic earnings per share is net income (loss) attributable to common stockholders. The numerator for
diluted earnings per share is net income unless there is a loss and then is (loss) available to common stockholders, due to antidilution.
Potential dilutive securities (stock options, stock warrants and convertible preferred stock) have not been considered when
their effect would be antidilutive. The potentially dilutive shares, including both stock options and restricted shares, would have been
339,896 shares for the year ended December 31, 2014. The potentially dilutive shares would have been 187,302 shares for the year
ended December 31, 2013. The Company had no potentially dilutive securities for the year ended December 31, 2012.
F-30
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
16. Income Taxes
Actual income tax expense from continuing operations differs from income tax expense from continuing operations
computed by applying the U.S. federal statutory corporate rate of 35 percent to pretax income as follows (dollars in thousands):
Year Ended December 31,
2014
2013
2012
Provision/(benefit) at statutory tax rate
$
(11,920)
35.00 % $
23,011
35.00 % $
State income tax provision, net of federal benefit
Permanent differences
State depletion deductions
Other
1,028
202
(1,723)
230
(3.00)%
(0.60)%
5.10 %
(0.70)%
2,928
(1,559)
—
4
4.45 %
(2.37)%
—%
0.01 %
Income tax provision /(benefit)
$
(12,183)
35.80 % $
24,384
37.09 % $
(94)
654
450
—
(373)
637
35.00 %
(241.84)%
(166.34)%
—%
137.65 %
(235.53)%
The effective tax rate for December 31, 2014 varies from the statutory rate primarily due to the effect of state income tax
expenses. During 2014, the Company reassessed depletion deductions for Louisiana income tax purposes for all tax years open under
the Louisiana statute of limitations. These additional deductions allowed under the Louisiana state statutes resulted in a reduction of
cash taxes of $1.7 million. The effective tax rate for December 31, 2013 varied from the statutory rate due to the effect of state income
taxes and a benefit for tax exempt life insurance proceeds of $10 million offset by non-deductible merger related expenses of $3.0
million and non-deductible compensation expenses of $1.4 million.
The provision (benefit) for income taxes from continuing operations for the periods indicated are comprised of the following
(in thousands):
Current tax provision (benefit):
Federal
State
Total
Deferred tax provision (benefit):
Federal
State
Total
Total tax provision (benefit):
Federal
State
Total
Included in gain from investment in affiliates
Total income tax provision (benefit)
Year Ended December 31,
2014
2013
2012
(392)
$
478
86
(11,518)
(751)
(12,269)
(11,910)
(273)
(12,183)
3,727
(15,910)
$
$
$
$
$
$
$
8,739
3,857
12,596
11,361
427
11,788
20,100
4,284
24,384
1,245
23,139
$
$
$
$
$
$
$
$
7,038
2,168
9,206
(8,343)
(226)
(8,569)
(1,305)
1,942
637
32
605
$
$
$
$
$
$
$
$
F-31
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The net deferred tax liability is comprised of the following (in thousands):
Deferred tax assets:
Net operating loss carryforward
Income tax credits
Derivative instruments
Deferred compensation
Other
Total deferred tax assets before valuation allowance
Valuation allowance
Net deferred tax assets
Deferred tax liability:
Oil and gas properties
Investment in affiliates
Other
Deferred tax liability
Total net deferred tax liability
December 31,
2014
2013
$
$
$
$
$
$
39,085
$
661
165
465
1,953
42,329
(2,161)
40,168
$
$
(104,209)
$
(28,287)
—
(132,496)
(92,328)
$
$
49,204
2,676
564
406
1,165
54,015
(2,552)
51,463
(133,894)
(21,681)
(518)
(156,093)
(104,630)
In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some
portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the
generation of future taxable income during the periods in which those temporary differences become deductible. The Company
considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this
assessment. Based upon the amount of deferred tax liabilities, level of historical taxable income and projections for future taxable
income over the periods in which the deferred tax assets are deductible, the Company believes it is more likely than not that it will
realize the benefits of these deductible differences of a $6.2 million valuation allowance.
As of December 31, 2014, the Company had federal net operating loss (“NOL") carryforwards of approximately $112.3
million and state NOLs of $10.2 million. All NOL carryforwards were acquired in a Merger with Crimson. These NOLs are available
to reduce future taxable income and the related income tax liability of the combined company. At the date of the Merger, Crimson had
a valuation allowance of approximately $36.4 million, or $12.8 million tax-adjusted. As part of acquisition accounting for the Merger,
the Company released valuation allowances of approximately $29.2 million, or $10.2 million tax-adjusted. The remaining valuation
allowance of $7.3 million, or $2.6 million tax-adjusted, was due to Internal Revenue Code Section 382 (“Section 382”) limitations on
utilization of NOLs acquired by Crimson in previous acquisitions. As of December 31, 2014 the remaining valuation allowance
decreased to $6.2 million, or $2.2 million tax-adjusted, due to an adjustment to reflect expired NOLs of $1.1 million. The utilization of
NOL carryforwards acquired in the Merger with Crimson is limited by Section 382 as discussed below.
Federal NOL carryforwards of $112.3 million expire at various dates beginning in 2018 and ending in 2034. NOL
carryforwards of $6.2 million impacted by Crimson's Section 382 limitations, which are not expected to be realized, will expire in
2018 through 2020. Federal NOL carryforwards of $106.1 million, associated with Crimson's losses incurred in recent years, which
are also impacted by Section 382 limitations and expected to be realized, will expire at various dates beginning in 2029 and ending in
2033. The Company believes that it will be able to utilize all of the NOL carryforwards, as discussed above, before they expire.
ASC 740, Income Taxes ("ASC 740") prescribes a recognition threshold and a measurement attribute for the financial
statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those
benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing
authorities. As a result of the Merger, the Company acquired certain tax positions taken by Crimson in prior years. These positions are
F-32
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
not expected to have a material impact on results of operations, financial position or cash flows. A reconciliation of the beginning and
ending amount of unrecognized income tax benefits is as follows (in thousands):
Unrecognized Tax Benefits
Balance at December 31, 2013
Additions based on tax positions related to the current year
Additions based on tax positions related to prior years
Additions due to acquisitions
Reductions due to a lapse of the applicable statute of limitations
Balance at December 31, 2014
$
$
518
—
—
—
—
518
The Company's policy is to recognize interest and penalties related to uncertain tax positions as income tax benefit (expense)
in the Company’s Consolidated Statements of Operations. The Company had no interest or penalties related to unrecognized tax
benefits for the year ended December 31, 2014 or any prior years. The total amount of unrecognized tax benefit if recognized that
would affect the effective tax rate was zero.
The Company's tax returns are subject to periodic audits by the various jurisdictions in which the Company operates. These
audits can result in adjustments of taxes due or adjustments of the NOL carryforwards that are available to offset future taxable
income. The Company does not anticipate that the total unrecognized tax benefits will significantly change due to the settlement of
audits and the expiration of statute of limitations prior to December 31, 2014.
Generally, the Company's income tax years of 1998 through the current year remain open and subject to examination by
Federal tax authorities, and the tax years of 2009 through current remain open and subject to examination by the tax authorities in
Texas and Louisiana which are the jurisdictions where the Company carries its principal operations.
17. Related Party Transactions
Juneau Exploration L.P.
In April 2012, the Company announced that Mr. Brad Juneau, the sole manager of the general partner of JEX, had joined the
Company’s board of directors and that the Company had entered into an advisory agreement with JEX (the "Advisory Agreement"),
whereby in addition to generating and evaluating exploration prospects for the Company, JEX would direct Contango’s staff on
operational matters including drilling, completions and production. Pursuant to the Advisory Agreement, JEX was to be paid an
annual fee of $2.0 million.
In August 2012, the Company's founder, Chairman and Chief Executive Officer, Mr. Kenneth R. Peak, took a medical leave
of absence and the board of directors of the Company appointed Mr. Juneau as President and Acting Chief Executive Officer of the
Company, which he held until December 2012.
Effective January 1, 2013, the Advisory Agreement was terminated, and the Company and JEX entered into a First Right of
Refusal Agreement (the "First Right Agreement"). Under the First Right Agreement, JEX granted a first right of refusal to Contango
to purchase any exploration prospects generated and recommended by JEX. Pursuant to the First Right Agreement, JEX was to be
paid an annual fee of $0.5 million. The First Right Agreement was terminated effective as of March 31, 2013.
Effective January 1, 2013, Contaro Company, a wholly-owned subsidiary of the Company, entered into an advisory
agreement with JEX (the "Contaro Advisory Agreement"). Under the Contaro Advisory Agreement, JEX provided advisory services
to Contaro in connection with Contaro's investment in Exaro, and Mr. Juneau served on the Board of Managers of Exaro and
performed such duties as described in the limited liability company operating agreement of Exaro. Pursuant to the Contaro Advisory
Agreement, JEX was paid a monthly fee of $10,000 and was entitled to receive a one percent (1%) fee of the cash profit earned by
Contaro.
F-33
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
On March 19, 2014, Mr. Juneau resigned from the board of directors and no longer provides services under the Contaro
Advisory Agreement. As a result, the Contaro Advisory Agreement was terminated effective as of March 19, 2014.
Olympic Energy Partners
In December 2012, Mr. Joseph J. Romano was elected President and Chief Executive Officer of the Company. Mr. Peak
passed away on April 19, 2013 and Mr. Romano was named Chairman of the Company. Upon the Merger with Crimson on October 1,
2013, Mr. Romano resigned as President and Chief Executive Officer, but continued as Chairman. Mr. Romano is also the President
and Chief Executive Officer of Olympic Energy Partners LLC ("Olympic").
JEX, affiliates of JEX, and Olympic have historically participated with the Company in the drilling and development of
certain prospects through participation agreements and joint operating agreements, which specify each participant’s working i nterest
("WI"), net revenue interest ("NRI"), and describe when such interests are earned, as well as allocate an overriding royalty interest
("ORRI") of up to 3.33% to benefit the employees of JEX, excluding Mr. Juneau, except where otherwise noted. Olympic last
participated with the Company in the drilling of wells in March 2010, and its ownership in Company-operated wells is limited to its
Dutch and Mary Rose wells.
Republic Exploration LLC
In his capacity as sole manager of the general partner of JEX, Mr. Juneau also controls the activities of Republic Exploration
LLC ("REX"), an entity owned 34.4% by JEX, 32.3% by Contango, and 33.3% by a third party which contributed other assets to
REX. REX generates and evaluates offshore exploration prospects and has historically participated with the Company in the drilling
and development of certain prospects through participation agreements and joint operating agreements, which specify each
participant’s working interest, net revenue interest, and describe when such interests are earned, as well as allocate an overriding
royalty interest of up to 3.33% to benefit the employees of JEX. The Company proportionately consolidates the results of REX in its
consolidated financial statements.
As of December 31, 2014, Contango, Olympic, JEX, REX and JEX employees owned the following interests in the
Company's offshore wells.
Dutch #1 - #5
Mary Rose #1
Mary Rose #2 - #3
Mary Rose #4
Mary Rose #5
Ship Shoal 263
Vermilion 170
Olympic
JEX
REX
JEX Employees
WI
NRI
WI
NRI
3.53%
3.61%
3.61%
2.34%
2.56%
—%
—%
2.84%
2.70%
2.58%
1.70%
1.87%
—%
—%
1.88%
2.01%
2.01%
1.31%
1.43%
—%
4.30%
1.51%
1.51%
1.44%
0.95%
1.04%
—%
3.35%
WI
—%
—%
—%
—%
—%
—%
12.50%
NRI
—%
—%
—%
—%
—%
—%
9.74%
ORRI
2.02%
2.79%
2.79%
1.82%
1.54%
3.33%
3.33%
Prior to December 2013, Contango, Olympic, and JEX had the following lower WI and NRI in Dutch #1-#5, as a result of
exercising a preferential right in December 2013:
Dutch #1 - #5
Olympic
WI
3.02%
NRI
2.42%
JEX
WI
1.61%
NRI
1.29%
During the year ended December 31, 2014, Mr. Romano earned $105 thousand and Mr. Juneau earned $12 thousand in cash,
for their service as a director of the Company. In April 2014, the board of directors accelerated the vesting of Mr. Juneau’s 1,622
shares which would have otherwise been forfeited upon his resignation in March 2014. The Company recognized compensation
F-34
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
expense of approximately $71 thousand related to the shares granted to Mr. Juneau for the three months ended March 31, 2014.
Additionally, during the year ended December 31, 2014, Mr. Romano received 2,612 shares of restricted stock, which vest 100% on
the one-year anniversary of the date of grant, as part of his board of director compensation. Below is a summary of transactions
between the Company, Olympic, JEX, and REX during the years ended December 31, 2014, 2013 and 2012.
•
•
•
•
•
•
•
•
•
In February 2011 the Company spud Vermilion 170 which was owned 100% by the Company. Under the terms of the
applicable participation agreement, Contango had a 100% working interest through casing point. Once casing point was
reached, JEX and REX each exercised their option to back-in for a 2.6% and 7.5% working interest, respectively. Once
production began, JEX and REX each received their carried working interest of 1.7% and 5.0%, respectively, resulting in
JEX having a final working interest of 4.3% and REX having a final working interest of 12.5%. The Company owns the
remaining working interests in this well. The Company paid JEX a prospect fee of $250,000 for generating this prospect.
In July 2011, the Company recompleted its Eloise South well uphole in the Cib-Op sands as its Dutch #5 well. Under the
terms of the applicable joint operating agreement, all Dutch #5 well owners were required to purchase the Eloise South
well bore from the Eloise South owners (the "Dutch Well Cost Adjustment"). All Eloise South and Dutch #5 well owners
paid and/or received their proportionate share of the Dutch Well Cost Adjustment based on their ownership percentage in
each well. At the time of the Dutch Well Cost Adjustment, JEX had a 1.6% working interest in Dutch #5; Olympic had a
3.02% working interest in Dutch #5 and a 3.33% working interest in Eloise South; REX had a 9.6% working interest in
Eloise South; and Contango had a 47.05% working interest in Dutch #5 and a 23.8% working interest in Eloise South.
In December 2011, the Company purchased an additional working interest in Mary Rose #5 (see below) from an existing
partner. The Company then sold to Olympic and JEX its proportionate share of the existing partner's interest, based on
Olympic and JEX's ownership percentage in the well.
In January 2012, the Company recompleted its Eloise North well uphole in the Cib-Op sands as its Mary Rose #5 well.
Under the terms of the applicable joint operating agreement, all Mary Rose #5 well owners were required to purchase the
Eloise North well bore from the Eloise North owners. (the "Mary Rose Well Cost Adjustment"). All Eloise North and
Mary Rose #5 well owners paid and/or received their proportionate share of the Mary Rose Well Cost Adjustment based
on their ownership percentage in each well. JEX had a 1.4% working interest in Mary Rose #5 and a 0.1% working
interest in Eloise North; Olympic had a 2.56% working interest in Mary Rose #5 and a 4.79% working interest in Eloise
North; REX had a 13.2% working interest in Eloise North; and the Company had a 37.8% working interest in Mary Rose
#5 and a 35.8% working interest in Eloise North.
In July 2012 the Company spud the Ship Shoal 134 prospect which was owned 100% by the Company. The Company
paid 100% of the costs to drill, plug and abandon this well. The Company paid JEX a prospect fee of $250,000 for
generating this prospect.
In July 2012 the Company spud the South Timbalier 75 prospect which was farmed-in 100% by the Company and REX.
Under the terms of the applicable participation agreement, the Company paid 100% of the costs to drill, plug and
abandon this well. The Company paid JEX a prospect fee of $250,000 for generating this prospect.
For the five REX-generated lease blocks that the Company purchased at the June 20, 2012 lease sale, the Company will
have a 100% working interest through first production. At first production (if successful), REX will receive a carried
working interest of 10%. Once payout of post casing point costs has been reached, REX will have an option to back-in
for up to 12.5% working interest, resulting in REX having a final working interest of up to 22.5% (17.5% net revenue
interest) and the Company owning the remaining working interests. JEX employees will receive an ORRI of 3.33% in
these prospects. The Company will pay JEX a prospect fee of $250,000 for each prospect the Company drills. Should the
Company not drill these prospects within 48 months of the effective date of each lease, the Company shall assign such
lease to REX.
For the one JEX-generated lease block that the Company purchased at the June 20, 2012 lease sale, the Company will
carry JEX for 10% through first production and JEX employees will receive an ORRI of 3.33%. The Company paid JEX
a prospect fee of $250,000 in December 2013 upon spudding this prospect.
For the three REX-generated lease blocks that the Company purchased at the March 20, 2013 lease sale, the Company
will have a 100% working interest through first production. At first production (if successful), REX will receive a carried
F-35
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
working interest of 10%. Once payout of post casing point costs has been reached, REX will have an option to back-in
for up to 12.5% working interest, resulting in REX having a final working interest of up to 22.5% (17.5% net revenue
interest) and the Company owning the remaining working interests. JEX employees will receive an ORRI of 3.33% in
these prospects. The Company paid JEX two prospect fees of $250,000 each, for evaluating these two prospects located
on three leases. Should the Company not drill these prospects within 48 months of the effective date of each lease, the
Company shall assign such lease to REX.
In June 2013, the Company purchased South Timbalier 17 from an independent oil and gas company. Under the terms of
the applicable participation agreement, the Company will have a 75% working interest in this well, with several other
owners owning the remainder, until payout of all costs is reached. Once payout of all costs has been reached, REX will
have an option to back-in for up to a 9.4% working interest, (6.7% net revenue interest), resulting in the Company
owning a 56.3% working interest (39.9% net revenue interest). The Company paid JEX a prospect fee of $250,000 for
evaluating this prospect. There are no JEX employee ORRIs on this prospect.
In the Tuscaloosa Marine Shale ("TMS"), a shale play in central Louisiana and Mississippi, the Company has a 100%
working interest through first production. JEX will receive a carried working interest of 10% in certain of the Company’s
TMS wells, and JEX employees will receive an ORRI of 2%, of which Mr. Juneau receives 0.75%, to reimburse Mr.
Juneau for out-of-pocket costs incurred in order for Contango to participate in the prospect. An additional 2% ORRI was
granted to the geologist who generated the TMS prospect for us. The geologist has subsequently been employed by
Contango.
Effective January 1, 2014, the Company subleased to JEX a portion of its previous office space at 3700 Buffalo
Speedway, Houston, Texas for approximately $0.1 million per year, which approximates its rental liability for that space.
•
•
•
Below is a summary of payments the Company received from (paid to) Olympic, JEX, and REX in the ordinary course of
business in its capacity as operator of the wells and platforms for the periods indicated. The Company made and received similar types
of payments with other well owners (in thousands):
Olympic
2014
JEX
REX
Year ended December 31,
2013
JEX
Olympic
REX
Olympic
2012
JEX
REX
Revenue payments as well owners
$
(7,349) $
(4,882) $
(2,270) $
(6,859) $
(4,628) $
(1,932) $
(6,888) $
(5,230) $
(4,308)
Joint interest billing receipts
Mary Rose well cost adjustment
673
—
521
—
322
—
945
—
1,201
2,090
—
—
1,081
(201)
724
118
885
(1,185)
Below is a summary of payments the Company received from (paid to) Olympic, JEX and REX as a result of specific
transactions between the Company, Olympic, JEX and REX. While these payments are in the ordinary course of business, the
Company did not have similar transactions with other well owners (in thousands):
Olympic
2014
JEX
REX
Olympic
2013
JEX
REX
Olympic
2012
JEX
REX
Year ended December 31,
Reimbursement of certain costs
$
(54) $
(29) $
— $
— $
(115) $
(4) $
— $
(496) $
Rent received for sublease
Prospect fees
Advisory Agreements
REX distribution to members
—
—
—
—
142
—
—
—
—
—
—
—
—
—
—
—
—
(1,000)
(361)
—
—
—
—
(197)
—
—
—
—
F-36
(9)
—
—
—
—
—
(1,530)
—
1,469
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
As of December 31, 2014 and 2013, the Company's consolidated balance sheets reflected the following balances (in
thousands):
Accounts receivable:
Joint interest billing
Accounts payable:
Olympic
December 31, 2014
JEX
REX
Olympic
December 31, 2013
JEX
REX
48
42
12
34
87
116
Royalties and revenue payable
(1,006)
(620)
(175)
(1,293)
(877)
(466)
Oaktree Capital Management L.P.
Oaktree Capital Management L.P. ("Oaktree"), through various funds, owns approximately 6.7% of the Company's stock. On
October 1, 2013 following the closing of the Merger, Mr. James Ford, a Manging Director and Portfolio Manager within Oaktree, was
elected to the Company's board of directors. Mr. Ford was previously a member of Crimson's board of directors from February 2005
until the closing of the Merger.
As part of Mr. Ford's director compensation, all cash and equity awards payable to Mr. Ford, are instead granted to an
affiliate of Oaktree. During the year ended December 31, 2014, an affiliate of Oaktree earned $64 thousand in cash and 2,612 shares
of restricted common stock as a result of Mr. Ford's board participation. These shares vest one year from the date of grant.
Prior to the Merger, Crimson maintained a second lien credit agreement with Barclays Bank Plc, as agent, and other parties,
including an affiliate of Oaktree, which was Crimson’s largest stockholder at the time (the “Second Lien Credit Agreement”). The
Second Lien Credit Agreement provided for a term loan, made to Crimson in a single draw, in an aggregate principal amount of
$175.0 million. In connection with the Merger, the Company assumed and immediately repaid Crimson’s $175.0 million loan under
the Second Lien Credit Agreement, plus $1.8 million in interest and prepayment premiums.
Contango ORE, Inc.
In November 2011, the Company executed a $1.0 million Revolving Line of Credit Promissory Note to lend money to
Contango ORE, Inc. (the “CORE Note”). The Company and Contango ORE, Inc. (“CORE”) shared executive officers at that time.
The CORE Note contained covenants limiting CORE’s ability to enter into additional indebtedness and prohibiting liens on any of its
assets or properties. Borrowings under the CORE Note bore interest at 10% per annum. On March 30, 2012 the Company received
repayment of the $500,000 it had advanced under the CORE Note, plus accrued interest of approximately $15,000. The CORE Note
was terminated on December 31, 2012.
Equity Compensation
In February 2012, the Company net-settled 45,000 stock options from two employees for a total of approximately $465,000.
All settlements were approved by the Company’s board of directors and were completed at the closing price of the Company’s
common stock on the date of settlement.
18. Subsequent Events
The Company has evaluated subsequent events through the date the financial statements were available to be issued. Nothing
that would require recognition or disclosure in the financial statements was identified in addition to the items disclosed in the financial
statements.
F-37
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)
In accordance with U.S. GAAP for disclosures regarding oil and gas producing activities, and SEC rules for oil and gas
reporting disclosures, we are making the following disclosures regarding our natural gas and oil reserves and exploration and
production activities.
Capitalized Costs Related to Oil and Gas Producing Activities
The following table presents information regarding our net capitalized costs related to oil and gas producing activities as of
the date indicated (in thousands):
Proved oil and gas properties
Unproved oil and gas properties
Less accumulated depreciation, depletion, amortization and impairment
Net capitalized costs
Costs Incurred
December 31,
2014
2013
$
$
1,138,054
$
35,783
1,173,837
(425,890)
747,947
$
1,001,361
49,443
1,050,804
(260,438)
790,366
The following table presents information regarding our net costs incurred in the purchase of proved and unproved properties
and in exploration and development activities for the periods indicated (in thousands):
Property acquisition costs:
Unproved
Proved
Exploration costs
Development costs
Total costs incurred
Year Ended December 31,
2014
2013
2012
$
$
22,087 $
—
49,680
120,630
8,134 $
428,925
15,551
35,363
192,397 $
487,973 $
19,982
280
41,265
16,090
77,617
The following table presents information regarding our share of the net costs incurred by Exaro in the purchase of proved and
unproved properties and in exploration and development activities for the periods indicated (in thousands):
Property acquisition costs
Exploration costs
Development costs
Total costs incurred
Natural Gas and Oil Reserves
Year Ended December 31,
2014
2013
2012
$
$
— $
—
30,288
30,288
$
— $
—
51,014
51,014
$
—
—
20,528
20,528
Proved reserves are the estimated quantities of natural gas, oil and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating
conditions and current regulatory practices. Proved developed reserves are proved reserves which are expected to be produced from
existing completion intervals with existing equipment and operating methods.
Proved natural gas and oil reserve quantities at December 31, 2012 and 2011, and the related discounted future net cash flows
before income taxes are based on estimates prepared by William M. Cobb & Associates, Inc. Proved natural gas and oil reserve
quantities at December 31, 2014 and 2013, and the related discounted future net cash flows before income taxes are based on
F-38
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)
estimates prepared by William M. Cobb & Associates, Inc. and Netherland, Sewell & Associates, Inc. All estimates have been
prepared in accordance with guidelines established by the Securities and Exchange Commission.
The below table summarizes the Company’s net ownership interests in estimated quantities of proved natural gas, oil and
natural gas liquids (“NGLs”) reserves and changes in net proved reserves as of December 31, 2014, 2013, 2012 and 2011, all of which
are located in the continental United States.
Proved Developed and Undeveloped Reserves as of:
December 31, 2011
Revisions of previous estimates
Production
December 31, 2012
Sale of minerals in place
Extensions and discoveries
Purchases of minerals in place
Revisions of previous estimates
Production
December 31, 2013
Sale of minerals in place
Extensions and discoveries
Revisions of previous estimates
Production
December 31, 2014
Proved Developed Reserves as of:
December 31, 2011
December 31, 2012
December 31, 2013
December 31, 2014
Proved Undeveloped Reserves as of:
December 31, 2011
December 31, 2012
December 31, 2013
December 31, 2014
Oil and
Condensate
(MBbls)
NGLs
(MBbls)
Natural
Gas
(MMcf)
Total
(MMcfe)
3,493
(472)
(507)
2,514
(323)
2,199
6,839
(942)
(589)
9,698
(1)
2,940
(2,821)
(1,401)
8,415
3,539
2,514
5,223
4,114
(46)
—
4,475
4,301
4,570
1,420
(660)
5,330
(49)
436
3,151
(233)
(677)
7,958
—
932
(373)
(1,008)
7,509
4,343
5,103
6,453
5,637
227
227
1,505
1,872
212,823
(17,041)
(21,750)
174,032
(356)
5,431
65,186
(15,739)
(20,624)
207,930
(161)
12,899
(15,142)
(25,875)
179,651
209,903
166,307
185,535
150,235
2,920
7,725
22,395
29,416
261,201
(11,353)
(28,752)
221,096
(2,588)
21,241
125,126
(22,789)
(28,220)
313,866
(164)
36,130
(34,316)
(40,323)
275,193
257,195
212,009
255,591
208,734
4,006
9,087
58,275
66,459
During the year ended December 31, 2014, our proved reserves decreased by approximately 38.7 Bcfe. This decrease is
primarily attributable to a 22.4 Bcfe negative revision of proved developed producing reserves at our Eugene Island 11 field and
normal production declines. The negative revision at Eugene Island 11 was due to a change in forecasted condensate yield and
ultimate field abandonment pressure, as determined by our third party engineers related to recent field performance.
During the year ended December 31, 2013, our proved reserves increased by approximately 92.8 Bcfe. This increase is
primarily attributable to our merger with Crimson, offset by normal production of 28.2 Bcfe during the year, a 19.2 Bcfe decrease in
our Dutch and Mary Rose reserve estimates based upon additional pressure data, and a 2.5 Bcfe decrease in our Vermilion 170 reserve
estimates, as determined by our reservoir engineer.
F-39
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)
During the year ended December 31, 2012, our proved reserves decreased by approximately 40.1 Bcfe. The major
contributors to this decrease include normal production of 28.8 Bcfe during the year, a 9.2 Bcfe decrease in our Ship Shoal 263
reserve estimates, and an 11.5 Bcfe decrease in our Vermilion 170 reserve estimates, as determined by our reservoir engineer.
The below table summarizes the Company’s net ownership interests in estimated quantities of proved natural gas, oil and
natural gas liquids (“NGLs”) reserves and changes in net proved reserves as of December 31, 2014, 2013 and 2012 attributable to its
Investment in Exaro.
Proved Developed and Undeveloped Reserves as of:
Oil and
Condensate
(MBbls)
NGLs
(MBbls)
Natural
Gas
(MMcf)
Total
(MMcfe)
December 31, 2011
Extensions and discoveries
Production
December 31, 2012
Sale of minerals in place
Extensions and discoveries
Purchases of minerals in place
Revisions of previous estimates
Production
December 31, 2013
Sale of minerals in place
Extensions and discoveries
Revisions of previous estimates
Production
Decenber 31, 2014
Proved Developed Reserves as of:
December 31, 2012
December 31, 2013
December 31, 2014
Proved Undeveloped Reserves as of:
December 31, 2012
December 31, 2013
December 31, 2014
—
142
(9)
133
—
66
—
288
(48)
439
—
329
86
(63)
791
133
439
529
—
—
262
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
11,583
(527)
11,056
—
4,282
—
27,339
(3,609)
39,068
—
26,173
5,102
(4,931)
65,412
11,056
39,068
45,127
—
—
—
12,434
(580)
11,854
—
4,675
—
29,066
(3,893)
41,702
—
28,147
5,617
(5,308)
70,158
11,854
41,702
48,301
—
—
20,285
21,857
F-40
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)
Standardized Measure
The standardized measure of discounted future net cash flows relating to the Company’s ownership interests in proved
natural gas and oil reserves as of December 31, 2014, 2013 and 2012 are shown below (in thousands):
Future cash inflows
Future production costs
Future development costs
Future income tax expenses
Future net cash flows
10% annual discount for estimated timing of cash flows
As of December 31,
2014
2013
2012
$
1,820,954 $
2,098,788 $
1,094,986
(412,607)
(219,598)
(232,648)
956,101
(308,085)
(473,801)
(183,329)
(323,210)
1,118,448
(347,005)
(212,732)
(24,610)
(301,862)
555,782
(167,770)
388,012
Standardized measure of discounted future net cash flows
$
648,016 $
771,443 $
Future cash inflows represent expected revenues from production and are computed by applying certain prices of natural gas
and oil to estimated quantities of proved natural gas and oil reserves. Prices are based on the first-day-of-the-month prices for the
previous 12 months. As of December 31, 2014, future cash inflows were based on unadjusted prices of $4.32 per MMbtu of natural
gas, $93.32 per barrel of oil, and $33.45 per barrel of NGLs. As of December 31, 2013, future cash inflows were based on unadjusted
prices of $3.66 per MMbtu of natural gas, $97.33 per barrel of oil, and $37.39 per barrel of NGLs. As of December 31, 2012, future
cash inflows were based on unadjusted prices of $2.75 per MMBtu of natural gas, $95.05 per barrel of oil, and $58.39 per barrel of
natural gas liquids.
The standardized measure of discounted future net cash flows relating to the Company’s ownership interests in proved
natural gas and oil reserves as of December 31, 2014, 2013 and 2012 attributable to its Investment in Exaro are shown below (in
thousands):
As of December 31,
2014
2013
2012
Future cash inflows
Future production costs
Future development costs
Future income tax expenses
Future net cash flows
10% annual discount for estimated timing of cash flows
$
392,238 $
196,515 $
(147,473)
(39,523)
—
205,242
(104,635)
(82,071)
(2,466)
—
111,978
(48,072)
Standardized measure of discounted future net cash flows
$
100,607 $
63,906 $
41,424
(19,021)
(508)
—
21,895
(8,234)
13,661
Realized Prices
The average realized prices for the year ended December 31, 2014 production were $4.36 per MCF of gas, $92.98 per barrel
of oil, and $33.27 per barrel of NGL. Sales are based on market prices and do not include the effects of realized derivative hedging
losses of $1.3 million for the year ended December 31, 2014.
Future production and development costs are estimated expenditures to be incurred in developing and producing the
Company’s proved natural gas and oil reserves based on historical costs and assuming continuation of existing economic conditions.
Future development costs relate to compression charges at our platforms, abandonment costs, recompletion costs, and additional
development costs for new facilities.
F-41
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)
Future income taxes are based on year-end statutory rates, adjusted for tax basis and applicable tax credits. A discount factor
of 10 percent was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is
not intended to represent the replacement cost or fair value of the Company’s natural gas and oil properties. An estimate of fair value
would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future
changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve
estimates of natural gas and oil producing operations.
The Company's share of the standardized measure of discounted future net cash flows attributable to our investment in Exaro
does not include the effect of income taxes because Exaro is treated a partnership for tax purposes. Exaro allocates any income or
expense for tax purposes to its partners.
Change in Standardized Measure
Changes in the standardized measure of future net cash flows relating to proved natural gas and oil reserves are summarized
below (in thousands):
Year Ended December 31,
2014
2013
2012
Changes in standardized measure due to current year operation:
Sales of natural gas and oil produced during the period, net of production
expenses
$
(229,222) $
(86,939) $
Extensions and discoveries
Net change in prices and production costs
Changes in estimated future development costs
Revisions in quantity estimates
Purchase of reserves
Sale of reserves
Accretion of discount
Changes in income taxes
Change in the timing of production rates and other
Net change
Beginning of year
End of year
102,024
(43,214)
7,064
(107,934)
—
(195)
98,721
66,918
(17,588)
(123,426)
771,442
120,709
(11,469)
20,282
(3,627)
408,990
(15,555)
37,099
(22,952)
(32,613)
413,925
357,517
$
648,016
$
771,442
$
(122,149)
—
(182,879)
5,665
(46,304)
—
—
90,968
111,458
(60,580)
(203,821)
591,833
388,012
During the year ended December 31, 2014, our proved reserves decreased by approximately 38.7 Bcfe and our standardized
measure decreased by approximately $0.1 million. This decrease is primarily attributable to a 22.4 Bcfe negative revision of proved
developed producing reserves at our Eugene Island 11 field and normal production declines. The negative revision at Eugene Island 11
was due to a change in forecasted condensate yield and ultimate field abandonment pressure, as determined by our third party
engineers related to recent field performance.
During the year ended December 31, 2013, our proved reserves increased by approximately 92.8 Bcfe and our standardized
measure increased by approximately $383.4 million. This increase is primarily attributable to our merger with Crimson as well as the
acquisition of additional interests in our operated Dutch offshore reserves, offset by normal production of 28.2 Bcfe during the year, a
19.2 Bcfe decrease in our Dutch and Mary Rose reserve estimates based upon additional pressure data, and a 2.5 Bcfe decrease in our
Vermilion 170 reserve estimates, as determined by our reservoir engineer. The "Sale of reserves" line includes the sale of a partial
interest in the Company's properties located in Madison and Grimes Counties.
During the year ended December 31, 2012, our proved reserves decreased by approximately 40.1 Bcfe and our standardized
measure decreased by approximately $203.8 million. The major contributors to this decrease include normal production of 28.8 Bcfe
F-42
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)
during the year, a 9.2 Bcfe decrease in our Ship Shoal 263 reserve estimates, and an 11.5 Bcfe decrease in our Vermilion 170 reserve
estimates, as determined by our reservoir engineer.
Changes in the standardized measure of future net cash flows relating to proved natural gas and oil reserves attributable to the
Company’s Investment in Exaro are summarized below (in thousands):
Year Ended December 31,
2014
2013
2012
Changes in standardized measure due to current year operation:
Sales of natural gas and oil produced during the period, net of production
expenses
$
(21,356) $
(13,509) $
Extensions and discoveries
Net change in prices and production costs
Changes in estimated future development costs
Revisions in quantity estimates
Purchase of reserves
Sale of reserves
Accretion of discount
Changes in income taxes
Change in the timing of production rates and other
Net change
Beginning of year
End of year
.
26,241
18,040
354
9,379
—
—
6,391
—
(2,348)
36,701
63,906
8,039
10,131
(433)
44,544
—
—
1,366
—
107
50,245
13,661
$
100,607
$
63,906
$
(1,868)
15,529
—
—
—
—
—
—
—
—
13,661
—
13,661
F-43
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
QUARTERLY RESULTS OF OPERATIONS (Unaudited)
Quarterly Results of Operations
The following table sets forth the results of operations by quarter for the fiscal years ended December 31, 2014 and 2013, (in
thousands, except per share amounts):
Year ended December 31, 2014:
Revenues from continuing operations
Net income (loss) from continuing operations (1)
Net income (loss) attributable to common stock
Net income (loss) per share (2):
Basic:
Diluted:
Year ended December 31, 2013:
Revenues from continuing operations
Net income from continuing operations (1)
Net income attributable to common stock
Net income per share (2):
Basic:
Diluted:.
March 31
June 30
September 30
December 31
Quarter Ended
$
$
$
$
$
$
$
$
80,257 $
78,419 $
67,552 $
(10,193) $
(10,193) $
4,581 $
4,581 $
3,664 $
3,664 $
50,230
(19,926)
(19,926)
(0.53) $
(0.53) $
0.24 $
0.24 $
0.19 $
0.19 $
(1.05)
(1.05)
31,787 $
30,709 $
34,722 $
66,903
3,869
3,869
11,356
11,356
19,740
19,740
0.25 $
0.25 $
0.75 $
0.75 $
1.30 $
1.30 $
6,396
6,396
0.34
0.34
(1) Represents natural gas and oil sales, less operating expenses, exploration expenses, depreciation, depletion and amortization, lease
expirations and relinquishments, impairment of natural gas and oil properties, general and administrative expense, and other
income and expense before income taxes.
(2) The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share as each quarterly
computation is based on the income for that quarter and the weighted average number of common shares outstanding during that
quarter.
F-44
[THIS PAGE INTENTIONALLY LEFT BLANK]
Cor p ora t e
INFORMATION
BOARD OF DIRECTORS
CORPORATE OFFICE
717 Texas Avenue, Suite 2900
Houston, Texas 77002
Phone: 713.236.7400
Fax: 713.236.4424
OUTSIDE COUNSEL
Vinson & Elkins
First City Tower
1001 Fannin Street, Suite 2500
Houston, Texas 77002
COMMON STOCK INFORMATION
The Common Stock is traded on the
NYSE MKT under the symbol “MCF”
TRANSFER AGENT
Continental Stock & Trust Company
17 Battery Place
New York, New York 10004
212.509.4000
AUDITORS
Grant Thornton LLP
700 Milam Street, Suite 300
Houston, Texas 77002
FORM 10-K
Additional copies of the Company’s Form 10-K
as filed with the Securities and Exchange
Commission, are available at our website
www.contango.com under Investor Relations
Joseph J. Romano
Chairman of the Board
Allan D. Keel
B.A. Berilgen
B. James Ford
Ellis L. McCain
Charles M. Reimer
Steven L. Schoonover
MANAGEMENT TEAM
Allan D. Keel
President and Chief Executive Officer
Thomas H. Atkins
Senior Vice President, Exploration
E. Joseph Grady
Senior Vice President and Chief Financial Officer
A. Carl Isaac
Senior Vice President, Operations
Jay S. Mengle
Senior Vice President, Engineering
John A. Thomas
Vice President, General Counsel
and Corporate Secretary
Michael J. Autin
Vice President, Production
Sergio Castro
Vice President and Treasurer
Jeff Sikora
Vice President, Land
Edward Skrljac
Vice President, Onshore Completions
Patrick Webb
Vice President, Business Development
Company
PROFILE
Contango Oil & Gas Company, based in Houston, Texas,
is an independent energy company engaged in the acquisition,
exploration, development, exploitation and production of
crude oil and natural gas properties offshore in the shallow
waters of the Gulf of Mexico and in the onshore Texas Gulf Coast
and Rocky Mountain regions of the United States.
717 Texas Avenue, Suite 2900
Houston, Texas 77002
Phone: 713.236.7400
www.contango.com