717 Texas Avenue, Suite 2900
Houston, Texas 77002
Phone: 713.236.7400
Fax: 713.236.4424
www.contango.com
C
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A
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267166_Contango_Cov_R1.indd 1-3
4/3/14 1:18 PM
2 0 1 3 A n n u A l R e P o R T
Company
Profile
ConTAngo oil & gAS ComPAny iS An indePendenT oil And gAS ComPAny bASed in HouSTon,
TexAS, FoCuSed on THe exPloRATion, develoPmenT, PRoduCTion And ACquiSiTion oF nATuRAl
gAS And oil PRoPeRTieS boTH onSHoRe, PRimARily in THe TexAS gulF CoAST Region, And
oFFSHoRe in THe SHAllow wATeRS oF THe gulF oF mexiCo. ConTAngo HAS oveR 400 PRoduCing
onSHoRe wellS, wiTH PRoduCTion FRom THe woodbine FoRmATion in mAdiSon And gRimeS
CounTieS TexAS, THe eAgle FoRd And budA FoRmATionS in ZAvAlA And dimmiTT CounTieS
TexAS, THe HAyneSville SHAle, mid-boSSieR And JAmeS lime PlAyS in eAST TexAS, THe
denveR JuleSbuRg bASin in ColoRAdo, And in vARiouS ConvenTionAl FieldS loCATed PRimARily
Along THe TexAS gulF CoAST. ConTAngo AlSo ownS APPRoximATely 29,000 undeveloPed ACReS
in THe develoPing TuSCAlooSA mARine SHAle PlAy in louiSiAnA And miSSiSSiPPi. ConTAngo’S
oFFSHoRe oPeRATionS ARe ConCenTRATed in THe SHAllow wATeRS oF THe gulF oF mexiCo
And ConSiST oF 13 ComPAny-oPeRATed wellS And THRee PRoduCTion PlATFoRmS. ConTAngo
HAS A bAlAnCed ASSeT PRoFile wiTH APPRoximATely 60% oF ReSeRveS And PRoduCTion
in THe SHAllow gulF oF mexiCo, And beTween 60–65% oF PRoduCTion FRom nATuRAl gAS.
ConTAngo HAS A STRong FinAnCiAl PoSiTion And CASH Flow THAT PoSiTionS iT well To
PuRSue longeR-TeRm gRowTH oF ReSeRveS And PRoduCTion THRougH THe develoPmenT
oF iTS oil And liquidS RiCH onSHoRe ReSouRCe PlAyS, ComPlemenTed by A numbeR oF
PoTenTiAlly HigH-imPACT oFFSHoRe PRoSPeCTS.
Corporate
Information
BOArd OF dIreCTOrS
Joseph J. romano
Chairman
Allan d. Keel
B.A. Berilgen
B. James Ford
Lon 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 & Chief Financial officer
A. Carl Issac
Senior vice President—operations
J. Stephen Mengle
Senior vice President—engineering
Yaroslava Makalskaya
vice President, Chief Accounting officer & Controller
John A. Thomas
vice President, general Counsel & Corporate Secretary
Michael J. Autin
vice President—offshore Production
Sergio Castro
vice President & Treasurer
Jeffrey A. Sikora
vice President—land
edward Skrljac
vice President—onshore Completions
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”
Auditors
grant Thornton llP
700 milam Street, Suite 300
Houston, Texas 77002
Transfer Agent
Continental Stock Transfer &
Trust Company
17 battery Place
new york, new york 10004
212.509.4000
Form 10-K, 10-K/A
Additional copies of the Company’s
Form 10-K and 10-K/A, as filed
with the Securities and exchange
Commission, are available at our
website www.contango.com under
investor Relations.
Annual Report Design by Curran & Connors, Inc. / www.curran-connors.com
267166_Contango_Cov_R1.indd 4-6
4/3/14 1:18 PM
Dear Fellow
Shareholders
The first thing we would like to say here is that we express our deepest
condolences to the family of Ken Peak, and all those who have had the
pleasure of knowing Ken, upon his passing last April. Ken, the founder and
CEO of Contango, was a smart, engaging, well-liked and respected mem-
ber of the oil and gas community. His willingness to sometimes operate
“outside the conventional box” served him well, as he successfully built
Contango from scratch to a billion dollar market-cap company. All who knew
Ken will miss his presence.
The October merger with Crimson Exploration was
an exciting transformational event for the Company,
resulting in a combined entity with a more balanced
profile from a couple of key perspectives. Prior to
the merger, from a reserve and production stand-
point, the Company was substantially all offshore
and was approximately 80% natural gas; while
today we are roughly 60% shallow water Gulf of
Mexico and 40% onshore unconventional and con-
ventional Texas Gulf Coast, and from a commodity
standpoint, are approximately 60% natural gas and
40% crude oil and natural gas liquids. We have a
strong balance sheet, robust cash flow generation
and an inventory of organic growth possibilities from
Crimson’s oil and liquids-rich onshore resource
plays, complemented by Contango’s seven poten-
tially high-impact shallow water Gulf of Mexico
exploratory prospects. The merger of the two com-
panies should provide a win-win opportunity for our
united shareholder base as we continue that transi-
tion to a more equally weighted onshore/offshore
and gas/liquids profile through aggressive develop-
ment of our onshore liquids-weighted resource plays.
The teams of both companies have been integrated,
are working well together, and are extremely excited
about the future possibilities for the new Contango.
As part of the merger, the Company’s reporting
cycle was changed to a calendar year-end in order
to provide reported results on the same timeline as
that utilized by most of our peers. We will increase
our efforts to enhance the visibility of the Contango
name and story in the investment community during
2014. Making it easier to compare our performance
with that of our competitors will be useful to both
analysts and investors. As you will note herein, our
prior financial results have been recast on a calen-
dar year-end basis.
Operationally, it was a fairly quiet year for Contango
until the merger was completed. We drilled only one
exploratory well, our South Timbalier 17 discovery
in August, with production likely to commence by
mid-2014. During 2013, Crimson added 12 new wells
in the Woodbine formation in Madison and Grimes
counties, Texas and seven new wells in the Buda
formation in Dimmitt County, Texas. As the merger
process progressed during the year, we started
developing a definitive plan for a more aggressive
capital program for the fourth calendar quarter of
2013 and for fiscal 2014. For 2014, we currently
forecast a capital program of approximately $216
million, including 19–20 wells in Madison and
Grimes counties, 19 wells in Dimmitt County, and a
few additional wells to try previously untested ideas
in new and existing areas. While our 2014 capital
1
program is initially expected to be funded by inter-
nally generated cash flow, to the extent that success
in some of these new formations or areas supports
it, we have the financial capacity, and the desire, to
commit additional capital to the development of
those new areas.
We believe that steadily growing reserves and pro-
duction through the drill bit, as well as continuing
to build an inventory of opportunities for long-term
organic growth, are the keys to success in increas-
ing shareholder value. While we will endeavor to
accomplish that growth through our existing pros-
pect inventory, we will also continue to analyze,
evaluate, and potentially pursue, producing property
or acreage acquisitions in our existing areas of
focus, and/or new frontiers, that could complement
organic growth. In the event that we identify a com-
plementary acquisition target, we have a $500 mil-
lion revolving credit facility in place, with a current
borrowing base of $275 million, and current out-
standings of approximately $60 million, so our
liquidity position is very strong.
This is an exciting time for the shareholders of
Contango, as we consider the future to be bright.
We, the Contango Board and management, and all
Contango employees are loyal, dedicated share-
holders of the Company focused on building share-
holder value. Thank you for being a shareholder
and partner in Contango.
Allan D. Keel
President and Chief Executive Officer
Joseph J. Romano
Chairman of the Board
267166_Contango_Narr_R1.indd 1
4/3/14 1:17 PM
Exploration
& Development
Contango Oil & Gas has a diverse asset base with onshore and offshore production and
drilling opportunities. With the merger between Contango and Crimson Exploration completed
as of October 1st, 2013, only the fourth quarter of 2013 will show the effect of the business
combination. For 2014, the Company’s primary focus will be on developing the liquids rich
inventory of onshore drilling opportunities to drive production growth and cash flow.
Oil & Gas Revenues ($MM)
& Average Realized Prices ($/Mcfe)
Production (Bcfe)
Oil & Gas Revenues ($MM)
Production (Bcfe)
Average Realized Prices ($/Mcfe)
$6.58
$5.82
$5.07
$250
$200
$150
$100
$50
0
35
30
25
20
15
10
5
0
2011
2012
2013
2011
2012
2013
Gas Revenue
Oil Revenue
NGL Revenue
Average Realized Price
Gas Production
NGL Production
Oil Production
Proved Reserves (Bcfe)
Cost Incurred in Oil & Gas Activities ($MM)
350
300
250
200
150
100
50
0
$500
$400
$300
$200
$100
0
2011
2012
2013
2011
2012
2013
Natural Gas
Natural Gas Liquids
Crude Oil
Development Costs
Exploration Costs
Property Acquisition Costs—Proved
Property Acquisition Costs—Unproved
2
250
200
150
100
50
0
350
300
250
200
150
100
50
0
Proved Reserves (Bcfe)
Cost Incurred in Oil & Gas Activities ($MM)
8
7
6
5
4
3
2
1
0
35
30
25
20
15
10
5
0
500000
400000
300000
200000
100000
0
267166_Contango_Narr_R1.indd 2
4/3/14 1:17 PM
OnshOre OperatiOns
suMMary
south texas
Buda, Eagle Ford, Conventional
(55,885 net acres)
Proved reserves of 63.3 Bcfe
southeast texas
Woodbine, Eagle Ford, Conventional
(26,476 net acres)
Proved reserves of 52.3 Bcfe
east texas
Haynesville, Mid-Bossier, James Lime
(4,833 net acres)
Proved reserves of 1.5 Bcfe
tuscaloosa Marine shale
(29,065 net acres)
Colorado
Niobrara
(11,229 net acres)
Jonah field
Exaro Energy III JV
(37% Equity Investment)
3
OffshOre
OperatiOns
south timbalier 17
Proved reserves of 2.2 Bcfe
ship shoal 263
Proved reserves of 0.2 Bcfe
Vermilion 170
Proved reserves of 17.7 Bcfe
eugene island 11
(Dutch/Mary Rose)
Proved reserves of 170.4 Bcfe
267166_Contango_Narr_R1.indd 3
4/3/14 1:17 PM
Exploration & Development Financial
Performance
99%
Proved reserves PV-10
increased 99% to
$771 million
125%
Net liquids reserves
increased 125% to
17.7 million barrels
Proved reserves (SEC pricing)
Crude Oil (MBbls)
Natural Gas (Mmcf)
Natural Gas Liquid (MBbls)
Natural Gas Equivalent (Mmcfe)
2013
2012
2011
9,698
207,930
7,958
313,866
2,514
174,032
5,330
221,096
3,493
212,823
4,570
261,201
Future net revenue from proved reserves (SEC pricing):
Undiscounted before income taxes ($000)
Discounted at 10% after income taxes ($000)
$ 1,441,658
$ 771,443
$ 857,644
$ 388,012
$ 1,286,736
591,833
$
Production (net sales volume):
Crude Oil (MBbls)
Natural Gas (Mmcf)
Natural Gas Liquid (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
Less: Lease operating expenses and production taxes
Less: Exploration expenses
Less: DD&A and Impairment
Less: G&A
Other Income (expense)
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 (dollars)
589
20,624
677
28,220
101.21
3.84
37.26
106.80
3.73
35.92
$
$
$
$
$
$
(x1000)
$ 164,121
(36,784)
(1,811)
(66,305)
(26,512)
31,792
64,501
(23,139)
41,362
$
507
21,750
660
28,752
$ 110.92
$
2.79
$ 43.85
$ 114.24
$
2.85
$ 58.39
(x1000)
$ 145,868
(23,720)
(51,903)
(58,975)
(11,265)
(307)
(302)
(605)
(907)
$
624
22,797
607
30,183
108.32
4.15
59.70
104.24
4.37
59.37
$
$
$
$
$
$
(x1000)
$ 198,498
(28,285)
—
(50,668)
(10,614)
(201)
108,730
(38,821)
69,909
$
$
$
2.56
2.56
$
$
(0.06)
(0.06)
$
$
4.49
4.49
16,156
16,158
15,295
15,295
15,582
15,585
(x1000)
$ 910,304
$
90,000
$ 593,050
(x1000)
$ 561,106
$ — $
$ 403,929
(x1000)
$ 621,817
—
$ 444,003
13%
Total revenues increased
13% to $164 million
Basic
Diluted
Weighted average shares outstanding
Basic
Diluted
Total assets
Long-term debt, including current portion
Stockholders’ equity
4
267166_Contango_Narr_R1.indd 4
4/3/14 1:17 PM
2013
FORM 10–K/A
[ This page intentionally left blank ]
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
(Mark One)
[ X ]
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2013
[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from July 1, 2013 to December 31, 2013
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
Name of exchange on which registered
NYSE MKT
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes [X] No [ ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the
Act. Yes [ ] No [X]
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 [X] No [ ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such
files). Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained
herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]
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 [ ] Accelerated filer [X] Non-accelerated filer [ ] Smaller reporting company [ ]
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 [ ] No [X]
At June 30, 2013, 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 $455 million. As of March 27, 2014,
there were 19,367,411 shares of the registrant’s common stock outstanding.
Documents Incorporated by Reference
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/A.
2
Explanatory Note
On October 1, 2013, Contango Oil & Gas Company (“Contango”, "we" or the “Company”) completed a merger with
Crimson Exploration Inc. (“Crimson”) under an all-stock transaction pursuant to which Crimson became a wholly-owned subsidiary
of the Company (the “Merger”). The Merger is described in greater detail within this Annual Report on Form 10-K/A.
In connection with the closing of the Merger, our Board of Directors approved a change of our fiscal year end from
June 30 to December 31, commencing with the twelve-month period beginning on January 1, 2014. As a result of this change,
on March 3, 2014 we filed a Transition Report on Form 10-K for the six-month period ended December 31, 2013 (the “Original
Filing”). This Annual Report on Form 10-K/A is filed to present a recast of historical financial information for the three-year
period ended December 31, 2013. Financial statements as of December 31, 2013 and 2012 and for the three years ended
December 31, 2013 include consolidated results of operations of both Contango and Crimson for the period from the closing of
the Merger on October 1, 2013 to December 31, 2013 and consolidated financial statements of Contango only for all other
periods.
This Annual Report on Form 10-K/A should be read in conjunction with the Original Filing. This Annual Report on
Form 10-K/A does not generally reflect events that occurred after the filing date of the Original Filing although certain
provisions have been updated or otherwise modified where we believe appropriate to give proper context to the results for the
periods included herein. In addition, the following provisions of the Original Filing have also been amended:
• Cover page. We have updated the shares of common stock outstanding as of March 27, 2014.
•
•
•
Part II. Item 5. General. We have updated the shares of common stock outstanding and issued as of March 27, 2014.
Part II. Item 7. Capital Resources and Liquidity. We have updated the amount of debt outstanding as of March 27,
2014.
Part IV. Item 15(b). Exhibits. We have amended the exhibits to reference the current version of the Company’s
Bylaws.
• We have updated the Annual Report to reference the resignation of Mr. Brad Juneau from the board of directors.
Other than as described in this explanatory note, this Annual Report on Form 10-K/A does not modify or update the disclosures
in the Original Filing.
i
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
ANNUAL REPORT ON FORM 10-K/A FOR THE FISCAL YEAR ENDED DECEMBER 31, 2013
TABLE OF CONTENTS
PART I
Page
Item 1.
Business
Overview
Our Strategy
Offshore Gulf of Mexico
Onshore Properties
Onshore Investments and Joint Ventures
Outlook
Discontinued Operations
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. Mine Safety Disclosures
Legal Proceedings
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
PART II
Purchases of Equity Securities
General
2009 Equity Compensation Plan
2005 Stock Incentive Plan
ii
1
2
3
5
6
7
7
8
8
8
15
16
17
17
17
17
17
18
32
32
33
33
34
35
35
35
36
37
37
38
40
41
41
41
42
42
1999 Stock Incentive Plan
Share Repurchase Program
Stock Performance Graph
Item 6.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Selected Financial Data
Overview
Impact of Deepwater Horizon
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
Item 8.
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9.
Item 9A. Controls and Procedures
Item 9B. Other Information
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14.
Principal Accountant Fees and Services
Item 15. Exhibits and Financial Statement Schedules
PART IV
43
43
44
45
47
47
48
48
53
55
56
58
58
58
59
59
60
62
62
62
62
62
62
65
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 the operator in drilling deep high pressure and 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;
• 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.
iv
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. On October 1, 2013 the Company's board of directors approved a change in fiscal year
end from June 30 to December 31.
All references in this Form 10-K/A 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/A relating to natural gas
and oil reserves and the estimated future net cash flows attributable to those reserves are based on estimates prepared by independent
engineers and are net to our interest.
v
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Item 1. Business
Overview
PART I
Contango is a Houston, Texas based independent energy company engaged in the acquisition, exploration, development,
exploitation and production of crude oil and natural gas offshore in the shallow waters of the Gulf of Mexico and in the onshore
Gulf Coast region of the United States and Colorado.
On October 1, 2013 the Company's board of directors approved a change in fiscal year end from June 30 to December
31. On March 3, 2014 we filed a Form 10-K 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 Exploration Inc.
activity (October - December). This Form 10-K/A presents our information for the twelve months ended December 31, 2013,
2012 and 2011. Unless otherwise noted, all references to "years" in this report refer to the twelve-month periods ended December
31 of each year.
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"). As a result of the Merger, each share
of Crimson common stock was converted into the right to receive 0.08288 shares of common stock of the Company. As a result,
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 approximately 20.3% of the post-Merger Contango. We also assumed $235.4 million in debt,
including accrued interest and repayment premium, and issued 135,898 options in exchange for the outstanding options held by
Crimson employees.
The Merger qualified as a tax-free reorganization for U.S. federal income tax purposes, so that none of Contango, Crimson,
or any of their respective stockholders recognized any gain or loss in the Merger, except that Crimson's stockholders may have
recognized a gain or loss with respect to cash received in lieu of fractional shares of Company common stock.
Following the Merger, the newly constituted board of directors of the Company consisted of Joseph J. Romano, Allan D.
Keel, B.A. Berilgen, B. James Ford, Brad Juneau, Ellis L. McCain, Charles M. Reimer, and Steven L. Schoonover. The board of
directors appointed Allan D. Keel as President and Chief Executive Officer and E. Joseph Grady as Senior Vice President and
Chief Financial Officer of the Company. Joseph J. Romano has continued as Chairman of the Board. Messrs. Keel, Grady and
certain other employees of Crimson entered into employment agreements with the Company that became effective upon the
consummation of the Merger. The combined company has its headquarters and principal corporate office in Houston, Texas.
We have historically focused our operations in the Gulf of Mexico (“GOM”), but our recent merger with Crimson has
given us access to lower risk, long life resource plays in Southeast Texas (the Woodbine oil and liquids-rich play), in South Texas
(the Eagle Ford Shale and Buda oil and liquids-rich plays) and in East Texas (the James Lime liquids-rich play, and under an
improved natural gas price environment, the Haynesville/Mid-Bossier gas play). We believe these plays provide long-term growth
potential from multiple formations.
Our production for the year ended December 31, 2013 was approximately 87% offshore and 13% onshore, and 73%
natural gas and 27% oil and natural gas liquids. Our production for the three months ended December 31, 2013 was approximately
63% offshore and 37% onshore, and 66% natural gas and 34% oil and natural gas liquids. As of December 31, 2013, our proved
reserves were approximately 61% offshore and 39% onshore, and 66% natural gas and 34% oil and natural gas liquids.
Additionally, we have (i) a 37% equity investment in Exaro Energy III LLC (“Exaro”), which participates in a joint
venture with Encana Oil & Gas (USA) Inc. (“Encana”) that is primarily focused on the development of proved natural gas reserves
in the Jonah Field in Wyoming; (ii) an approximate 29,000 net acre position, and 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 are prospective in the Niobrara Shale oil play, and (v) seven
exploratory prospects in the shallow waters of the Gulf of Mexico.
We intend to grow reserves and production by developing our existing producing property base, by exploiting our oil/
liquids resource potential, and by pursuing opportunistic acquisitions in areas where we have current operations and specific
operating expertise, as well as new areas we identify that we feel have significant exploration and operational upside. We have
developed a significant inventory of quality drilling opportunities on our existing property base that we believe should position
us for multiyear reserve growth. Until we see improvement in natural gas prices, we will concentrate our drilling activity
predominantly on further developing our oil and liquids-rich onshore assets in Southeast Texas and South Texas, complemented
1
by offshore exploratory drilling. In 2014 specifically, we will focus on our inventory of crude oil and liquids-rich projects with
rig programs targeting the Woodbine in Madison and Grimes Counties, Texas, the Buda in Dimmit County, Texas and the James
Lime in San Augustine County, Texas. We also currently plan to drill a number of other wells testing new formations in existing
areas and one to two exploratory wells in the shallow waters of the Gulf of Mexico.
We will continue to monitor expanding industry activity in the oil-weighted TMS and in the Niobrara Shale to determine
the future potential and strategy for optimizing value in each play prior to committing significant drilling capital.
As of December 31, 2013, our proved reserves, as estimated by Netherland, Sewell & Associates, Inc. (“NSAI”) and
William M. Cobb and Associates (“Cobb”), our independent petroleum engineering firms, in accordance with reserve reporting
guidelines required by the Securities and Exchange Commission (“SEC”), were approximately 313.9 Bcfe, consisting of 207.9
Bcf of natural gas and 17.7 MMBbl of crude oil, condensate and natural gas liquids, with a
of $987.2 million, and a
Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”) of $771.4 million. As of December 31,
2013, 66% of our proved reserves were natural gas, 81% were proved developed and 96.6% were attributed to wells and properties
operated by us. PV-10 is a non-GAAP financial measure. A reconciliation of our Standardized Measure to
is provided
under Item 2. Properties PV-10.
The following summary table sets forth certain information with respect to our proved reserves as of December 31, 2013,
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, 2013:
Region
Offshore GOM
Southeast Texas
South Texas
Other (1)
Total
Estimated
Proved
Reserves
(Bcfe)
190.5
52.3
63.3
7.8
313.9
% Crude Oil /
Condensate
% Natural
Gas
% Natural
Gas Liquids
% Proved
Developed
Average Daily
Production (2)
(Mmcfe/d)
6%
53%
25%
28%
79%
32%
58%
59%
15%
15%
17%
13%
99%
58%
51%
63%
67.1
24.3
14.7
1.7
107.8
(1) East Texas, Mississippi, Louisiana, TMS and Colorado
(2) Offshore GOM daily production is averaged over 365 days. Southeast Texas, South Texas and Other daily production is
averaged over 92 days (the post-Merger period).
Our Strategy
Key elements of our business strategy are:
• Enhance our portfolio by dedicating the majority of our drilling capital to our oil and liquids-rich opportunities. Due
to the superior economics from oil production, we will allocate most of our 2014 onshore capital budget to oil and liquids-
weighted opportunities as we transition from a natural gas weighted production profile to a more balanced reserve and
production profile between oil/liquids and natural gas. We currently plan to develop the oil and natural gas liquids resource
potential that we believe exists, from numerous formations, on our Madison and Grimes County acreage in Southeast
Texas, our Zavala and Dimmit County acreage in South Texas and our San Augustine County acreage in East Texas. If
warranted by market conditions, success in these areas and capital availability, we may further accelerate our drilling
program in one or more areas. Until the outlook for natural gas prices for a sustained period of time improves significantly,
we do not plan to further develop our acreage position in the Haynesville/Mid-Bossier natural gas play in East Texas.
For the year ended December 31, 2013, our production profile was approximately 73% natural gas and 27% oil and
natural gas liquids, on an equivalent Mcfe basis. For the three months ended December 31, 2013, our production profile
was approximately 66% natural gas and 34% oil and natural gas liquids.
• Complement the exploitation of our lower-risk onshore resource plays with potentially high-impact offshore exploration.
We have historically depended upon Juneau Exploration, L.P. (“JEX”) for offshore prospect generation expertise and to
review prospects submitted by third parties. JEX is a private company formed for the purpose of generating offshore and
onshore domestic natural gas and oil prospects and is experienced and has a successful track record in exploration. We
currently have seven offshore prospects and intend to continue to review and consider offshore exploration opportunities
generated by JEX to increase our reserves base. Until his resignation on March 19, 2014, Mr. Brad Juneau, the sole
manager of the general partner of JEX, was a member of the Company’s board of directors.
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• 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, including both undeveloped and developed
reserves, in areas where we currently have a presence and/or specific operating expertise, as well as new areas that we
feel have significant exploration, exploitation or operational upside.
• Reduce near-term commodity price exposure through hedging. We utilize commodity derivative instruments to minimize
exposure to declining prices on our crude oil, natural gas and natural gas liquids production. We currently use a series
of swaps and costless collars to accomplish our commodity price hedging strategy. As of December 31, 2013, we have
9.5 Bcfe of equivalent production hedged between January 1, 2014 and December 31, 2014. For 2014 production we
have 0.2 MMBbl of crude oil hedges at an average Brent floor price of $104.29/Bbl, 0.3 MMBbl of crude oil hedges at
an average WTI floor price of $95.05/Bbl and 6.9 Bcf of natural gas hedges at an average floor price of $3.94 /MMBtu.
•
Selectively exploit our existing onshore producing conventional property base to generate additional cash flows. We
believe our multi-year drilling inventory of exploitation opportunities on our existing onshore conventional producing
properties provides us with a solid, dependable platform for future reserve and production growth. We own 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 2014.
Offshore Gulf of Mexico
As of December 31, 2013, the Company's offshore production consisted of seven federal and five State of Louisiana
Company-operated wells in the shallow waters of the Gulf of Mexico. These 12 wells produce from three fields. The following
summary table sets forth certain information with respect to our offshore reserves as of and for the year ended December 31, 2013:
Estimated
Proved
Reserves
(Bcfe)
170.4
17.7
2.4
190.5
% Crude Oil /
Condensate
%
Natural
Gas
% Natural
Gas Liquids
% Proved
Developed
Average Daily
Production
(Mmcfe/d)
7%
5%
9%
79%
77%
91%
14%
18%
—%
99%
100%
8%
59.4
6.7
1.0
67.1
Field
Dutch and Mary Rose
Vermilion 170
Other Offshore
Total
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 Eugene Island 11 block, this does not impact our ability to operate our facilities located on that block.
Operators in the Gulf of Mexico 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 this platform we are able to access two separate markets which minimizes downtime risk and provides the ability
to select the best sales price. Oil and gas production can flow via a TC Offshore (formerly ANR) pipeline to third-party owned and
operated onshore processing facilities near Patterson, Louisiana. Alternatively, 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 on-shore processing facility at Burns Point, Louisiana. Condensate can also flow via an ExxonMobil Pipeline Company
pipeline to onshore markets and multiple refineries.
Based on production and normal decline, we anticipate placing our Dutch and Mary Rose wells on central compression
at the Eugene Island 11 platform in 2014. We have designed a turbine type compressor for the platform which will be of sufficient
capacity to service all ten of our Dutch and Mary Rose wells. As of December 31, 2013, we had incurred approximately $8.8
million to design and build the compressor, and have budgeted an additional $0.8 million for the installation anticipated in June
2014.
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 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. Preliminary estimated adjustments of approximately $3.8 million reduce the purchase price to a total
of $15 million, net to the Company. The purchase price is expected to be finalized in the first quarter of 2014.
3
Vermilion 170 Field
We operate one well at Vermilion 170 which flows to a Company-owned and operated production platform at the same
location. Based on current production and decline rates, we have determined the need to place our Vermilion 170 well on compression
in 2014, at a cost of $1.4 million, net to the Company. As of December 31, 2013, we had incurred all of the $1.4 million to design,
build and install the compressor.
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 and the original tubing and casing were successfully removed. Operations were conducted to replace
the tubing and restore the well to production in June 2013. For the year ended December 31, 2013, approximately $12.0 million
was spent on these workover operations, net to the Company.
Other Offshore
Our Ship Shoal 263 and South Timbalier 17 fields have been included in “Other Offshore." The Company operates one
well at Ship Shoal 263, which produces to a Company-owned and operated production platform at the same location. This well
reached payout in 2012. We will continue producing this well as long as it is economical.
In September 2012 and December 2012, due to the decline in production and high water levels from our Ship Shoal 263
well, our reservoir engineer revised his estimated net proved natural gas and oil reserves from this well. As a result, the net book
value of our Ship Shoal 263 well exceeded the future undiscounted cash flows associated with its reserves. Accordingly, we
recognized an impairment expense of approximately $12.0 million during the year ended December 31, 2012 for this well.
On July 30, 2013, we spud our South Timbalier 17 prospect in state of Louisiana offshore waters, and on August 22, 2013
we announced a successful well. The well was drilled to a total measured depth of approximately 11,400 feet and the wireline logs
of the well indicate the presence of hydrocarbons. We are proceeding with development, including installation of production
facilities. Estimated costs net to Contango to drill, complete and bring this well to full production status are $12.6 million, $10.3
million of which has been incurred as of December 31, 2013. 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. We expect this well to commence production in
mid-2014.
In December 2013, we spud our Ship Shoal 255 prospect. We have budgeted $23.0 million to drill this well, with total
drilling operations forecasted to conclude in March 2014. Contingent on success, additional capital will be invested to complete
and tie-in the well. We will transport the new production through our nearby platform at Ship Shoal 263. We have currently classified
the platform as unproved properties, as its cost is expected to be recovered through our Ship Shoal 255 prospect.
The interests above include our ownership interest in Republic Exploration LLC ("REX"), an entity owned 34.4% by JEX,
32.3% by Contango, and 33.3% by a third party. 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 ("ORRI") of up to 3.33% to benefit the employees of JEX. In his capacity
as sole manager of the general partner of JEX, Mr. Brad Juneau also controls the activities of REX. The Company proportionately
consolidates its interest in REX in its consolidated financial statements.
Other Activities
During the year ended December 31, 2013, the Company was awarded three lease blocks, Eugene Island 23, Ship Shoal
52 and Ship Shoal 59, by the Bureau of Ocean Energy Management ("BOEM"), which were bid at the Central Gulf of Mexico
Lease Sale 227 held on March 20, 2013. We now own 16 offshore lease blocks.
Prior Year Activities
In July 2012, we spud our Ship Shoal 134 and South Timbalier 75 prospects. In October 2012, we announced that we had
reached total depth on each 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.
In July 2011, we recompleted our Eloise South well uphole in the Cib-Op sands as our Dutch #5 well, at a cost of
approximately $5.7 million, while in January 2012 we recompleted our Eloise North well uphole in the Cib-Op sands as our Mary
Rose #5 well, at a cost of approximately $0.5 million. The Mary Rose #5 is currently flowing intermittently awaiting compression.
4
Onshore Properties
Our onshore areas of operation consist primarily of:
•
•
Southeast Texas. As of December 31, 2013, our Southeast Texas region included approximately 42,580 gross (26,476
net) acres, proven reserves of 52.3 Bcfe, and 79 gross (44.3 net) producing wells. Crimson has actively developed 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, where there has recently been significant industry activity pursuing the Woodbine and Eagle Ford Shale
oil plays near our leasehold positions. During 2013, Crimson, and then Contango, drilled 12 gross (eight net) wells on
acreage targeting the Woodbine formation. We will continue our focus on further developing our inventory of crude oil
and liquids-rich projects in the Woodbine formation with a continuous rig program planned for 2014. We currently have
approximately 19,000 net acres, with a multi-year inventory of potential drilling locations, in Madison and Grimes
counties, which includes the Woodbine, Eagle Ford Shale and Georgetown formations.
On December 31, 2013, we sold to an independent third party approximately 7.1% of our interest in all developed and
undeveloped properties in Madison and Grimes Counties. The sales price of $20 million is 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. The current estimated sales price after preliminary adjustments is $20.4 million, or $91,007 per
flowing barrel of equivalent daily production and $47.32 per equivalent barrel of proved reserves.
South Texas. As of December 31, 2013, our South Texas region included approximately 105,364 gross (55,885 net) acres,
proven reserves of 63.3 Bcfe, and 274 gross (144.7 net) producing wells. Of this, approximately 25,880 gross (13,978 net)
acres are targeting the Buda and Eagle Ford Shale plays, approximately 80% 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 six gross operated wells (three net) and one gross non-operated well (0.25 net)
in the Buda formation in Zavala and Dimmit counties. Six of the wells were successful, while one was a mechanical
failure which may be side tracked in the future. Initial thirty-day average production rates for each of the first five wells
was 730 boed while the sixth well continues to clean up. We have one additional well in process at December 31, 2013
and expect to have at least one rig running full-time in 2014. Our estimated net proven Buda/Eagle Ford reserves in this
area were 23.5 Bcfe, comprised of 74.4% liquids, with 17 gross (8.9 net) producing wells, as of December 31, 2013.
The remaining 79,484 gross (41,907 net) acres in South Texas are located in our conventional fields that produce primarily
from the Wilcox, Frio, and Vicksburg sands. Our estimated net proved conventional reserves in this area were 39.8 Bcfe,
comprised of 76.3% gas, with 257 gross (135.8 net) producing wells, as of December 31, 2013.
• Other (East Texas). As of December 31, 2013, our East Texas region included approximately 7,904 gross (4,833 net)
acres primarily in San Augustine County, proven reserves of 1.5 Bcfe comprised of 99% gas, and eight gross (3.9 net)
producing wells. Crimson actively developed the Haynesville and Mid-Bossier Shales in this area in 2009 through 2011
during a more favorable natural gas price environment. We believe that the further exploitation of our acreage in the
Haynesville and Mid-Bossier Shale dry gas formations will provide long-term natural gas reserve and production growth
in the future; however, we do not anticipate devoting drilling capital to these formations until we see a sustained
improvement in the natural gas price environment. During 2014, we will initiate development of the shallower liquids
rich James Lime formation on our acreage in San Augustine County. We anticipate that we will drill up to two wells in
that area during 2014, where the offset operator has experienced excellent results in recent drilling. As of December 31,
2013, approximately 80% of our acreage in East Texas is held by production.
• Other (Tuscaloosa Marine Shale). We own a 25% non-operated working interest in the Crosby 12H-1 well in Wilkinson
County, Mississippi, targeting the TMS, an oil-focused shale play in central Louisiana and Mississippi. This well is
operated by Goodrich Petroleum Company LLC ("Goodrich"). As of December 31, 2013, the Crosby 12H-1 well was
producing at an 8/8ths rate of approximately 200 barrels of oil per day, with cumulative production of approximately
136,000 barrels of oil from the commencement of production through December 31, 2013.
In addition, as of December 31, 2013, we had leased approximately 40,492 gross (29,065 net) undeveloped acres 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 Horseshoe Hill #1 well, where our working interest is still being
determined and which will likely be drilled in 2014. We plan to continue to evaluate participation in third-party operated
5
wells with a small working interest as a means to obtain data from these wells to assist us in evaluating our TMS acreage
and develop a plan for potentially drilling and operating future wells.
• Other (Colorado). We hold approximately 16,080 gross (11,229 net) acres in the DJ Basin in Colorado (mostly in Adams
and Weld counties). There has been increasing 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 proven 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 is still uncertain. Substantially all of our net acres in the Niobrara Shale are held by
production. We plan to monitor the 2014 industry activity and results of our peers in the Niobrara Shale to determine our
strategy for maximizing the value of our position in the area.
• Other. As of December 31, 2013, we held approximately 3,302 gross (621 net) acres in small non-operating working
interests in the Fenton field area of Calcasieu Parish, Louisiana and a minor crude oil property in Mississippi.
Onshore Investments and Joint Ventures
• Kaybob Duvernay - Alberta, Canada. In mid-2011, we began investing 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. We expect to receive approximately $30.5 million from the sales proceeds. Of this
amount, $23.1 million was received in September 2013, $5.4 million was received in February 2014, and the remaining
$2.0 million is expected to be received by the end of 2014.
•
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, together with other parties for an aggregate commitment of approximately $183 million, resulting in a 37%
ownership interest in Exaro. As of December 31, 2013, we had invested approximately $46.9 million in Exaro.
Exaro has entered into an Earning and Development Agreement with Encana to provide funding of up to $380 million
to continue the development drilling program in a defined area of Encana's Jonah Field located in Sublette County,
Wyoming. This funding will be comprised of the $182.5 million investment described above, debt, and cash flow from
operations. Encana will continue to be the operator of the field. Upon investing the full amount of the $380 million, Exaro
will have earned 32.5% of Encana's working interest in a defined joint venture area that comprises approximately 5,760
gross acres.
As of December 31, 2013 the Exaro-Encana venture had 83 new wells on production, producing at a rate of approximately
38 Mmcfed, net to Exaro, plus an additional 14 wells that are either in the completion or fracture stimulation phase.
Encana has indicated that they expect to have three drilling rigs running on this project during 2014. For the year ended
December 31, 2013, the Company recognized a gain of approximately $2.3 million, net of tax expense of $1.2 million,
as a result of its investment in Exaro. As of December 31, 2013, reserves attributable to our investment in Exaro were
41.7 Bcfe. We do not anticipate making any additional equity contributions during 2014. See Note 11 to our Financial
Statements - “Investment in Exaro Energy III LLC” for additional details related to this investment.
We intend to continue to evaluate potential acquisition opportunities to expand our presence in our Southeast and South
Texas resource plays, to exploit our oil and liquids-rich positions, and to continue to develop exploration and exploitation
opportunities where commodity price-justified. Acquisition efforts will typically be focused on areas in which we can
leverage our geographic and geological expertise to exploit identified drilling opportunities, and where we can develop
an inventory of additional drilling prospects that we believe will enable us to grow production and add reserves.
6
Outlook
Our capital expenditure budget for 2014 is currently forecasted at approximately $216 million, and is expected to be
funded primarily from internally generated cash flow. Our plans include the drilling of 47 gross wells (28 net). Expenditures
planned for 2014 include:
• Gulf of Mexico - We forecast capital expenditures of approximately $39 million for 2014. The largest components of this
amount include $23 million to drill our Ship Shoal 255 exploratory prospect and $12 million to commence drilling an additional
exploratory well in the shallow waters of the Gulf of Mexico late in the year.
• Woodbine - We forecast capital expenditures of approximately $89 million in Madison and Grimes Counties to drill 19-20
wells. We currently anticipate 11 wells in our Force area, six wells in our Chalktown area and two wells in our Iola / Grimes
area, all of which will target the Woodbine formation. Additionally, we will drill one or more additional wells to test other
reservoir-maximization strategies in the area.
• Buda - We forecast capital expenditures of approximately $33 million in Zavala and Dimmit Counties to drill 14 operated
and five non-operated wells targeting the Buda formation.
•
James Lime - We forecast capital expenditures of approximately $9 million in St. Augustine County to drill two wells targeting
the James Lime formation.
• Other - We also forecast spending an additional $46 million in 2014 on the acquisition of undeveloped acreage in existing
and new areas, initial test wells on other formations in current areas or new acreage, on seismic data and for potential completion/
facility costs on Gulf of Mexico prospects.
Discontinued Operations
Patara and Rexer Assets
In October 2009, the Company entered into a joint venture with Patara Oil & Gas LLC ("Patara") to develop Cotton Valley
gas reserves in Panola County, Texas. B.A. Berilgen, a member of the Company’s board of directors, was the Chief Executive
Officer of Patara at the time. In May 2011, the Company sold to Patara its interest in the wells drilled under this joint venture
program, as well as its interest in two wells we drilled in Texas (Rexer #1 and Rexer-Tusa #2).
Contango Mining Company
Contango Mining Company (“Contango Mining”), a wholly-owned subsidiary of the Company was initially formed in
October 2009 for the purpose of engaging in exploration in the State of Alaska for gold and rare earth elements. Contango Mining
held leasehold interests in native, Federal, and State of Alaska acreage. In November 2010, Contango ORE, Inc. ("CORE"), then
another wholly-owned subsidiary of the Company, acquired the assets and acreage of Contango Mining in exchange for its common
stock which was subsequently distributed to the Company’s stockholders. The Company also contributed $3.5 million in cash to
CORE immediately prior to the distribution and no longer has an ownership in CORE.
We have accounted for these transactions as discontinued operations and have included the results of these operations in
discontinued operations for all periods presented. See Note 18 to our Financial Statements - "Discontinued Operations" for a
description of these transactions.
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 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.
7
Marketing and Pricing
We currently 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 utilize commodity price hedge instruments to minimize exposure to declining prices on our crude oil, natural gas and
natural gas liquids production. We use a series of swaps and costless collars to accomplish our commodity hedging strategy.
Unrealized gains or losses will 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
•
• The level of LNG imports/exports
• Domestic and foreign governmental regulations
•
• The loss of tax credits and deductions
Special taxes on production
Political conditions in the Middle East and other natural gas and oil producing regions
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, 2013, calculated on an equivalent basis, were
ConocoPhillips Company (48%), Shell Trading US Company (16%), Sunoco, Inc. (9%), Enterprise Products Operating LLC (7%),
and Exxon Mobil Oil Corporation (7%). 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 and in-house technical expertise.
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 the government
of the United States; 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 drilling and
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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
and state 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, 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.
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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 activities 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 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.
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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 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 found at the site. Persons who are or were responsible for releases of hazardous substances under
CERCLA 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 2012, the EPA published final rules under the CAA that subject oil and
natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards
(“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. With regards to production
11
activities, these final rules require, among other things, the reduction of volatile organic compound emissions from three
subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory)
and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured
gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using
a combustion device such as a flare. However, the “other” wells must use reduced emission completions, also known as “green
completions,” with or without combustion devices, after January 1, 2015. These regulations also establish specific new requirements
regarding emissions from production-related wet seal and reciprocating compressors, pneumatic controllers and storage vessels.
We are currently reviewing this new rule and assessing its potential impacts on our operations. Compliance with these requirements
could increase our costs of development and production, which costs could be significant.
Based on findings made by the EPA in December 2009 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 reviews for certain large stationary sources that are potential major sources of GHG 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 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, such as electric power
plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive
tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs
on operations and reduce demand for refined products. 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. 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, any changes in the laws or regulations or the inability to obtain permits for new
12
injection wells in the future may affect our ability to dispose of produced waters and ultimately increase the cost of our operations,
which costs could be significant. Furthermore, in response to recent seismic events near underground injection wells used for the
disposal of oil and gas-related wastewaters, federal and some state agencies, including the Texas Railroad Commission, have
begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed
moratoria on the use of such injection wells. If new regulatory initiatives are implemented that restrict or prohibit the use of
underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly
increase and our ability to conduct continue production may be delayed or limited, which could have a material adverse effect on
our results of operations and financial position.
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 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. 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 be 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, but
the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act ("SDWA"), regarding hydraulic fracturing
involving the use of diesel fuels and issued revised permitting guidance in February 2014 addressing the performance of such
activities using diesel fuels. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic
Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the
agency continues to project the issuance of a Notice of Proposed Rulemaking that would seek public input on the design and scope
of such disclosure regulations. In addition, Congress has from time to time considered legislation to provide for federal regulation
of hydraulic fracturing under the SDWA 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. 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 have been conducted or 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 in 2014. Moreover, the EPA is developing
effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose
these standards in 2014. The U.S. Department of Energy has conducted an investigation into practices the agency could recommend
to better protect the environment from drilling using hydraulic fracturing completion methods and issued a report in 2011 on
immediate and longer-term actions that may be taken to reduce environmental and safety risks of shale gas development. Also,
in May 2013, the federal Bureau of Land Management published a supplemental notice of proposed rulemaking governing hydraulic
fracturing on federal and Indian oil and gas leases that would require public disclosure of chemicals used in hydraulic fracturing,
confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate
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plans for managing flowback water that returns to the surface. These ongoing or proposed studies, depending on their degree of
pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SWDA or
other regulatory mechanisms.
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.
Oil and natural gas exploration, development and production activities on federal lands, including Indian lands and lands
administered by the federal Bureau of Land Management (“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 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. 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 or could result in limitations on our exploration and
production activities that 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.
Impact of Deepwater Horizon Incident
In response to an April 2010 fire and explosion aboard the Deepwater Horizon drilling rig and resulting oil spill from the
Macondo well operated by a third party in ultra-deepwater in the Gulf of Mexico, federal authorities have pursued a series of
regulatory initiatives to address the direct impact of that incident and to prevent similar incidents in the future. Beginning in 2010
and continuing through 2013, the federal government, acting through the U.S. Department of the Interior (“DOI”) and its
implementing agencies, BOEM and BSEE, has issued various rules, Notices to Lessees and Operators (“NTLs”) and temporary
drilling moratoria that impose or result in added environmental and safety measures upon exploration, development and production
operators in the Gulf of Mexico. These new regulatory requirements include the following:
• The Environmental NTL, which imposes more stringent requirements for documenting the environmental impacts
potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements;
• The Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well
design, construction and flow intervention processes and also requires certifications of compliance from senior corporate
officers;
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• The Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of
drilling fluids to maintain well bore integrity, and stiffens oversight requirements relating to blowout preventers and their
components, including shear and pipe rams; and
• The Workplace Safety Rule, which requires operators to employ a comprehensive safety and environmental management
system, known as “SEMS,” to reduce human and organizational errors as root causes of work-related accidents and
offshore spills, which rule was subsequently amended in April 2013 to require operators to, among other things, establish
procedures providing all personnel with “stop work” authority, develop protocols as to whom at the facility has the
ultimate operational safety and decision-making authority, and establish an independent auditing regimen whereby facility
audits are conducted by a service provider accredited by BSEE that is unaffiliated with the operator.
These regulatory initiatives may serve to effectively delay the pace of exploration and production operations in the Gulf
of Mexico due to adjustments in operating procedures and certification practices as well as increased lead times to obtain exploration
and production plan reviews, develop drilling applications, and apply for and receive new well permits. These new requirements
also increase the cost of preparing permit applications and will increase the cost of each new well, particularly for wells drilled
in deeper waters on the Outer Continental Shelf. We could become subject to fines, penalties or orders requiring us to modify or
suspend our operations in the Gulf of Mexico if we fail to comply with these requirements. Legislation has been considered that
would require each company doing business in the Gulf of Mexico to establish and maintain a significantly higher COFR amount
to pay for cleanup costs and damages arising from oil spills under the OPA, which, if ever adopted, could cause us and similarly
situated offshore operators to incur significantly higher operating costs or adversely affect the ability to continue to conduct offshore
operations. In any event, if similar oil spill incidents were to occur in the future in the Gulf of Mexico or elsewhere where we
conduct operations, 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 regulatory initiatives regarding offshore oil and gas exploration and
development activities, which any one or more of such events could have a material adverse effect on our volume of business as
well as our financial position, results of operations and liquidity. Our ability to obtain insurance or additional insurance coverage
on commercially reasonable terms to protect against any increase in liability is uncertain.
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.
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,
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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 up to $100 million on certain wells, 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 coverage, and third party personal injury and death, and $150 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 addition, to support the operating committee, we have contracted
with J. Connor Consulting (“JCC”) to manage our regulatory process relating to our offshore assets. JCC is a regulatory consulting
firm specializing in the offshore Gulf of Mexico regulatory process, preparation of incident response plans, safety and environmental
services and facilitation of comprehensive oil spill response training and drills to oil and gas companies and pipeline operators.
In addition, for our Gulf of Mexico operations, we have a Regional Oil Spill Plan in place with the BOEM. Our response
team is trained annually and is tested through annual spill drills given by the BOEM. In addition, we have in place a contract with
O’Brien’s Response Management (“O’Brien’s”). O’Brien’s maintains a 24/7 manned incident command center located in Slidell,
LA. Upon the occurrence of an oil spill, the Company’s spill program is initiated by notifying O’Brien’s that we have an emergency.
While the Company would focus on source control of the spill, O’Brien’s would handle all communication with state and federal
agencies as well as U.S. Coast Guard notifications.
If an offshore spill were to occur, we have contracted with Clean Gulf Associates (“CGA”) to assist with equipment and
personnel needs. CGA specializes in onsite control and cleanup and is on 24 hour alert with equipment currently stored at six bases
(Ingleside and Galveston, TX; Lake Charles, Houma, and Venice, LA; and Pascagoula, MS), and is opening new sites in Leeville,
Morgan City and Harvey, LA. The CGA equipment stockpile is available to serve member oil spill response needs including
blowouts; open seas, near shore and shallow water skimming; open seas and shoreline booming; communications; dispersants;
boat spray systems to apply dispersants; wildlife rehabilitation; and a forward command center. CGA has retainers with an aerial
dispersant company and a company that provides mechanical recovery equipment for spill responses.
In addition to being a member of 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, well control, engineering, and
training services.
We also have a full time manager of health, safety and environmental matters that 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 program identifies, addresses, and manages
safety, environmental hazards, and its impacts during the design, construction, start-up, operation, inspection, and maintenance
of all new and existing facilities. The Company has established goals, performance measures, training, accountability for its
implementation, and provides necessary resources for an effective SEMS, as well as reviews the adequacy and effectiveness of
the SEMS program. Facilities must be 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 manage our SEMS program for production operations.
The BSEE enforces the SEMS requirements through regular audits. Failure of an audit may force us to shut-in our Gulf
of Mexico operations until the audit finding is resolved.
Employees
On December 31, 2013, we had 79 full time employees, of which 21were field personnel. Following our merger with
Crimson, we terminated our human resources relationship with Insperity, Inc. and began to manage the human resources function
internally. 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.
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In addition to our employees, we use the services of independent consultants and contractors to perform various
professional services. We generally rely on JEX for offshore prospect generation and evaluation. 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 and Executive Officers of the Registrant,” 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 new office space for the three months ended December
31, 2013 was approximately $0.3 million. We remain responsible for the rent at our previous corporate office at 3700 Buffalo
Speedway in Houston, Texas, through February 29, 2016. Rent, including parking, related to this previous office space for the
year ended December 31, 2013 was approximately $0.7 million. 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/A. 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/A.
Available Information
You may read and copy all or any portion of this report on Form 10-K/A, 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 through the SEC's website at http://www.sec.gov, and at our website at http://
www.contango.com. This report on Form 10-K/A, including all exhibits and amendments, has been filed electronically with the
SEC.
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.
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Item 1A. Risk Factors
In addition to the other information set forth elsewhere in this Form 10-K/A, 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.
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.
• 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.
•
• The level of LNG imports and any LNG exports.
• Domestic and foreign governmental regulations.
•
• Access to pipelines and gas processing plants.
• The loss of tax credits and deductions.
Special taxes on production.
Political conditions in the Middle East and other natural gas and oil producing regions.
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.
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 East Texas and South Texas resource plays and the
horizontal redevelopment of the Woodbine and other formations in Southeast Texas, 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 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.
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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. 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
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,
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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 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 19% of our total estimated proved reserves at December 31, 2013 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
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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, 2013 was based
on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January through December 2013.
For our offshore condensate and natural gas liquids volumes, the average West Texas Intermediate (Cushing) posted price was
$97.33 per barrel. For our onshore crude oil and natural gas liquids volumes, the average West Texas Intermediate (Plains) posted
price was $93.42 per barrel. For our natural gas volumes, the average Henry Hub spot price was $3.67 per MMBtu. 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, 2013. If condensate and crude oil prices were $1.00 per Bbl lower than the prices used, our
as of December 31, 2013 would have decreased from $987.2 million to $979.1 million. If natural gas prices were $0.10
per Mcf lower than the price used, our
as of December 31, 2013, would have decreased from $987.2 million to
$972.7 million. Any adjustments to the estimates of proved reserves or decreases in the price of crude oil or natural gas may
is provided under "Item 2.
decrease the value of our common stock. A reconciliation of our Standardized Measure to
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. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash
flows for reporting purposes, is not necessarily the most appropriate discount factor. 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.
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:
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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 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;
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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 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 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 currently, 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 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.
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
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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 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, 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 the 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 change
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 GHGs could result in increased operating
costs and reduced demand for the oil and natural gas that we produce.
In December 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and
the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere
and other climatic changes. Based on these findings, the EPA adopted regulations under existing provisions of the CAA that
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establish PSD and Title V permit reviews for GHG emissions from certain large stationary sources. Facilities required to obtain
PSD permits for their GHG emissions also will 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. 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 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, such as electric power
plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive
tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs
on operations and reduce demand for refined products. 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. 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 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 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:
Surface cratering.
Pipe and cement failures.
• Blowouts, fires and explosions.
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• Uncontrollable flows of underground natural gas, oil or formation water.
• Natural disasters.
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• Casing collapses.
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• Reservoir compaction.
• Abnormal pressure formations.
• Environmental hazards such as natural gas leaks, oil spills, pipeline ruptures or discharges of toxic gases.
• Capacity constraints, equipment malfunctions and other problems at third-party operated platforms, pipelines and gas
Stuck drilling and service tools.
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:
Severe damage to and destruction of property or equipment.
Pollution and other environmental damage.
Injury or loss of life.
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• Reservoir damage.
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• Clean-up responsibilities.
• Regulatory investigations and penalties.
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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. 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
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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 JEX 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.
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.
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Proposed United States 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:
• 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; and
• 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.
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, but the EPA has asserted federal regulatory authority under the SDWA over certain hydraulic fracturing
activities involving the use of diesel fuels and issued revised permitting guidance in February 2014 addressing the performance
of such activities using diesel fuels. Also, in November 2011, the EPA announced its intent to develop and issue regulations under
the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing
and the agency continues to project the issuance of a Notice of Proposed Rulemaking that would seek public input on the design
and scope of such disclosure regulations. 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 have adopted or are considering adopting legal requirements that
could impose new or more stringent permitting, public disclosure, and well construction requirements on hydraulic fracturing
activities. 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 either underway or being proposed that focus on environmental aspects of
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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 2014. Moreover, the EPA is developing
effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose
these standards by 2014. The U.S. Department of Energy has conducted an investigation into practices the agency could recommend
to better protect the environment from drilling using hydraulic fracturing completion methods and issued a report in 2011 on
immediate and longer-term actions that may be taken to reduce environmental and safety risks of shale gas development. Also,
in May 2013, the federal Bureau of Land Management published a supplemental notice of proposed rulemaking governing hydraulic
fracturing on federal and Indian oil and gas leases that would require public disclosure of chemicals used in hydraulic fracturing,
confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate
plans for managing flowback water that returns to the surface. These studies, depending on their degree of pursuit and any meaningful
results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.
More stringent regulatory initiatives relating to offshore exploration and production activities may have an adverse effect
on our results of operations, financial position and liquidity.
In response to an April 2010 fire and explosion aboard the Deepwater Horizon drilling rig and resulting oil spill from the
Macondo well operated by a third party in ultra-deepwater in the Gulf of Mexico, federal authorities have pursued a series of
regulatory initiatives to address the direct impact of that incident and to prevent similar incidents in the future. Beginning in 2010
and continuing through 2013, the federal government, acting through the DOI and its implementing agencies, the BOEM and
BSEE, has issued various rules, NTLs and temporary drilling moratoria that impose or result in added environmental and safety
measures upon exploration, development and production operators in the Gulf of Mexico. These new regulatory requirements
include the following:
• The Environmental NTL, which imposes more stringent requirements for documenting the environmental impacts
potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements;
• The Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well
design, construction and flow intervention processes and also requires certifications of compliance from senior corporate
officers;
• The Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling
fluids to maintain well bore integrity, and stiffens oversight requirements relating to blowout preventers and their
components, including shear and pipe rams; and
• The Workplace Safety Rule, which requires operators to employ a comprehensive safety and environmental management
system, often referred to as SEMS, to reduce human and organizational errors as root causes of work-related accidents
and offshore spills, which rule was subsequently amended as published on April 5, 2013 (sometimes referred to as the
“SEMS II” rule) to require operators to, among other things, establish procedures providing all personnel with “stop
work” authority, develop protocols as to whom at the facility has the ultimate operational safety and decision-making
authority, and establish an independent auditing regimen whereby facility audits are conducted by a service provider
accredited by BSEE that is unaffiliated with the operator.
These regulatory initiatives may serve to effectively slow down the pace of drilling and production operations in the Gulf
of Mexico due to adjustments in operating procedures and certification practices as well as increased lead times to obtain exploration
and production plan reviews, develop drilling applications, and apply for and receive new well permits. These new requirements
also increase the cost of preparing permit applications and will increase the cost of each new well, particularly for wells drilled in
deeper waters on the Outer Continental Shelf. We could become subject to fines, penalties or orders requiring us to modify or
suspend our operations in the Gulf of Mexico if we fail to comply with these requirements. Also, legislation has been considered
that would require each company doing business in the Gulf of Mexico to establish and maintain a significantly higher COFR
amount to pay for cleanup costs and damages arising from oil spills under the OPA, which, if ever adopted, could cause us and
similarly situated offshore operators to incur significantly higher operating costs or adversely affect the ability to continue to
conduct offshore operations. In any event, if similar oil spill incidents were to occur in the future in the Gulf of Mexico or elsewhere
where we conduct operations, the United States or other countries 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 regulatory initiatives regarding offshore
oil and gas exploration and development activities, which any one or more of such events could have a material adverse effect on
our volume of business as well as our financial position, results of operations and liquidity. Our ability to obtain insurance or
additional insurance coverage on commercially reasonable terms to protect against any increase in liability may be precluded or
infeasible.
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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. One of the many reforms includes implementing a SEMS program. 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, 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.
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: 1) the operator fails to correct the violation in the reasonable amount of time specified on the INC; or 2) 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, JEX, 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, JEX 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:
Future natural gas and oil prices.
• Recoverable reserves.
• Exploration potential.
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• 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:
Problems integrating the purchased operations, personnel or technologies.
•
• Unanticipated costs.
• Diversion of resources and management attention from our exploration business.
28
• 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:
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;
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;
•
•
•
•
•
•
strategic actions by us or our competitors, such as acquisitions or restructurings;
changes in government and environmental regulation;
general market, economic and political conditions;
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.
29
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, 2013, we had 135,107 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 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:
•
•
•
•
•
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.
30
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.
RISK FACTORS RELATED TO OUR RECENTLY COMPLETED MERGER
Uncertainties associated with the Merger may cause a loss of management personnel and other key employees.
We are dependent on the experience and industry knowledge of our officers and other key employees to execute our
business plans. The combined company's success depends in part upon the ability of the Company to retain key management
personnel and other key employees. Current and prospective employees may experience uncertainty about their roles within the
combined company following the Merger, which may have an adverse effect on our ability to attract or retain key management
and other key personnel. Accordingly, no assurance can be given that we will be able to attract or retain key management personnel
and other key employees.
The failure to integrate successfully the businesses of Contango and Crimson could adversely affect the combined
company's future results.
The Merger involves the integration of two companies that have previously operated independently. The success of the
Merger will depend, in large part, on the ability of the combined company to realize the anticipated benefits, including synergies,
cost savings, innovation and operational efficiencies, from combining the businesses of Contango and Crimson. To realize these
anticipated benefits, the businesses of Contango and Crimson must be successfully integrated. This integration will be complex
and time-consuming. The failure to integrate successfully and to manage successfully the challenges presented by the integration
process may result in the combined company not achieving the anticipated benefits of the Merger.
The future results of the combined company could suffer if the combined company does not effectively manage its
expanded operations.
Following the Merger, the size of the business of the combined company increased significantly beyond the previous size
of either Contango's or Crimson's business. The combined company's future success depends, in part, upon its ability to manage
this expanded business, which could pose challenges for management, including challenges related to the management and
monitoring of new operations and associated increased costs and complexity. There can be no assurances that the combined
company will be successful or that it will realize the expected operating efficiencies, cost savings, revenue enhancements and
other benefits currently anticipated from the Merger.
The combined company's debt may limit its financial flexibility.
Contango previously had no amounts outstanding under its credit facility and traditionally has carried minimal balances
of long-term debt. Following the Merger, the combined company has more long-term debt. In addition, the combined company
may incur additional debt from time to time in connection with the financing of operations, acquisitions, recapitalizations and
31
refinancing. The level of the combined company's debt could have several important effects on future operations, including, among
others:
•
If a portion of the combined company's cash is applied to the payment of principal or interest on the debt, less will be
available for other purposes;
• Credit-rating agencies may change in the future with respect to the combined company, their ratings of that entity's
debt and other obligations, which in turn impacts the costs, terms and conditions and availability of financing;
• Covenants contained in the combined company's existing and future debt arrangements will require the combined
company to meet financial tests that may affect its flexibility in planning for and reacting to changes in its business,
including possible acquisition opportunities;
• The combined company's ability to obtain additional financing for capital expenditures, acquisitions, general corporate
and other purposes may be limited or burdened by increased costs or more restrictive covenants;
• The combined company may be at a competitive disadvantage to similar companies that have less debt;
• The combined company's vulnerability to adverse economic and industry conditions may increase; and
• The combined company may face limitations on its flexibility to plan for and react to changes in its business and the
industries in which it operates.
Item 1B. Unresolved Staff Comments
None
Item 2. Properties
As of December 31, 2013, we operated all of our offshore wells, with an average working interest of 59%, and operated
55% of our onshore wells with an average working interest of 71%. As of December 31, 2013, our properties were located in
the following regions: Offshore Gulf of Mexico, Southeast Texas, South Texas and Other. We intend to allocate a substantial
portion of our drilling capital budget in 2014 to the development of the potential that we believe exists in our resource play position
and offshore prospects, depending on commodity price environment, drilling and service costs, success rates, and capital
availability.
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
Year Ended December 31,
2013
2012
2011
$
8,134
$
19,982
$
428,925
15,551
35,363
280
41,265
16,090
3,035
2,660
7,622
23,013
$
487,973
$
77,617
$
36,330
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 Contango-operated Dutch wells
from an independent oil and gas company for $18.8 million. Preliminary estimated adjustments of approximately ($3.8 million)
will reduce the purchase price to a total of $15 million, net to the Company. The purchase price adjustment is expected to be
finalized in the first quarter of 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.
32
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
Year Ended December 31,
2013
2012
2011
$
— $
— $
—
—
51,014
20,528
Company's 37% share of costs incurred
$ 51,014
$ 20,528
$
Property Dispositions
—
—
—
—
On December 31, 2013, the Company sold to an independent third party approximately 7.1% of its interest in all developed
and undeveloped properties in Madison and Grimes Counties. The total sales price of $20 million is 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. Preliminary estimated adjustments to the sales price of approximately $0.4 million will increase the total proceeds from
sales of these properties to $20.4 million, and is expected to be finalized in the first quarter of 2014. 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
gain of approximately $6.6 million related to this sale was recognized in the year ended December 31, 2013.
We had additional property dispositions during the years ended December 31, 2012 and 2011, which were all classified
as discontinued operations for all periods presented. See Note 18 to our Financial Statements - "Discontinued Operations" for a
detailed description of these dispositions.
Drilling Activity
As of December 31, 2013, we were drilling one offshore well, Ship Shoal 255, with drilling operations forecasted to
conclude in March 2014. We were also drilling two onshore wells, one in the Woodbine area and one in the Buda area, whose
results are not included below. The following table shows our exploratory and developmental drilling activity for the periods
indicated. In the table, “gross” 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
Year Ended December 31,
2013
2012
2011
Gross
Net
Gross Net Gross
Net
3
1
—
—
4
0.3
0.8
—
—
1.1
—
—
—
2
2
—
—
—
2.0
2.0
—
1
—
—
1
—
1.0
—
—
1.0
Included in productive (onshore) wells for the year ended December 31, 2013 are three non-operated wells drilled in the
TMS. Included in productive (offshore) wells for the year ended December 31, 2013 is the Company's South Timbalier 17 prospect
we expect will begin production in mid-2014.
33
Development Wells:
Productive (onshore)
Productive (offshore)
Non-productive (onshore)
Non-productive (offshore)
Total
Year Ended December 31,
2013
2012
2011
Gross
Net
Gross
Net
Gross
Net
5
—
—
—
5
3.2
—
—
—
3.2
—
—
—
—
—
—
—
—
—
—
1
—
—
—
1
0.3
—
—
—
0.3
Included in productive (onshore) wells for the year ended December 31, 2013 are five onshore wells drilled after October
1, 2013, the date of the Merger. For the fiscal year ended December 31, 2011, the one productive (onshore) well relates to the
Rexer-Tusa #2, which was sold October 2011. The Rexer-Tusa #2 is classified as discontinued operations in our financial statements
for all periods presented.
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, 2013.
Offshore GOM
Southeast Texas
South Texas
Other (6)
Total
Developed Acreage (1)(2)
Net (5)
Gross (4)
Undeveloped Acreage (1)(3)
Net (5)
Gross (4)
14,618
24,239
85,771
17,229
141,857
11,828
14,805
44,329
9,180
80,142
39,692
18,341
19,593
52,281
129,907
39,692
11,671
11,556
36,911
99,830
(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 an owner’s 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 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 REX. The above table includes our 32.3% interest in REX’s 625 net developed acres.
Our offshore Gulf of Mexico leases expire in 2017 and 2018. Our onshore leases will expire over the next three years as
follows, unless we establish production or take action to extend the terms of our leases:
2014
2015
2016
Gross Acres
Net Acres
Gross Acres
Net Acres
Gross Acres
Net Acres
Year ending December 31,
Southeast Texas
South Texas
Other
Total
6,652
2,698
1,697
11,047
4,450
547
753
5,750
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
34
Production, Price and Cost History
See “Part I, 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, 2013:
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)
13
51
244
61
369
7.7
28.6
130.7
26.9
193.9
—
28
30
9
67
—
15.7
14.1
2.8
32.6
(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, 2013 were prepared by NSAI and Cobb, our
independent petroleum engineering firms. Approximately 61% and 39% of the proved reserves estimates shown herein at
December 31, 2013 have been independently prepared by Cobb and NSAI, respectively. Cobb prepared the proved reserves
estimates as of December 31, 2013 for all of our offshore properties and NSAI prepared the proved reserves estimates as of
December 31, 2013 for all of our onshore properties.
Estimates of proved reserves and future net revenue as of December 31, 2012 and 2011 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/A. 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, 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 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 and 2011 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, 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.
35
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
December 31,
2013
2012
2011
5,223
4,475
9,698
185,535
22,395
207,930
6,453
1,505
7,958
255,591
58,275
313,866
2,514
—
2,514
166,307
7,725
174,032
5,103
227
5,330
212,009
9,087
221,096
3,539
(46)
3,493
209,903
2,920
212,823
4,343
227
4,570
257,195
4,006
261,201
Proved developed reserves percentage
Prices utilized in estimates (2):
Crude oil ($/Bbl)
Natural gas ($/MMBtu)
Natural gas liquids ($/Bbl)
81%
96%
98%
$
$
$
106.80
3.73
35.92
$
$
$
114.24
2.85
58.39
$
$
$
104.24
4.37
59.37
(1) Excludes reserves attributable to our 37% investment in Exaro.
(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.
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
36
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
(in thousands):
December 31,
2013
2012
Pre-tax net present value, discounted at 10%
Future income taxes, discounted at 10%
Standardized measure of discounted future net cash flows
$
$
987,213
(215,770)
771,443
$
$
594,397
(206,385)
388,012
The following table reflects our estimated proved reserves by category as of December 31, 2013 (dollars in thousands):
Crude Oil
and
Condensate
(MBbl)
Natural Gas
(MMcf)
Natural
Gas
Liquids
(MBbl)
Total
(MMcfe)
% of
Total
Proved
Proved developed producing
Proved developed non-producing
Proved undeveloped
Total
4,342
881
4,475
9,698
128,738
56,797
22,395
207,930
4,531
1,922
1,505
7,958
181,976
73,615
58,275
313,866
58% $
635,075
23%
19%
159,683
192,455
100% $
987,213
Our estimated net proved reserves as of December 31, 2013, were approximately 19% crude oil and condensate, 66%
natural gas and 15% natural gas liquids.
Proved Developed Reserves
Total proved developed reserves increased from 212.0 Bcfe at December 31, 2012 to 255.6 Bcfe at December 31, 2013
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.
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, 2013, the Company had approximately 58.3 Bcfe of
PUDs related to its onshore activities. Development costs related to these PUDs are projected to be approximately $162 million
over the next five years, including $48.9 million estimated for expenditures in 2014. Our financial resources are expected to be
sufficient and within our budget to drill all of the remaining 58.3 Bcfe of proved undeveloped reserves within the five year period.
The following table presents the changes in our total proved undeveloped reserves for the year ended December 31, 2013:
Proved undeveloped reserves at December 31, 2012 (1)
Revisions of previous estimates (2)
Extensions, discoveries and other additions (3)
Purchase of minerals in place (4)
Disposition of reserves in place
Conversion to proved developed
Proved undeveloped reserves at December 31, 2013
37
Proved
Undeveloped
Reserves
(Mmcfe)
9,087
(6,525)
15,024
44,289
(1,500)
(2,100)
58,275
(1) Attributable to a rate acceleration well in our Dutch and Mary Rose field. This well will be drilled in the main Cib Op reservoir. The
acceleration benefits of drilling this well are an incremental net positive PV-10, but only a modest incremental volumetric reserves,
because the main Cib Op reservoir is a depletion drive retrograde gas reservoir. Our reservoir engineer’s simulation model indicates
that the timing of the pressure depletion, and the distribution of that depletion across the field, will have an effect on all of the wells
in communication with this rate acceleration well.
The reserves attributable to this rate acceleration well are calculated incrementally. The field-wide simulation model is run first without
this well to generate a total field gas and condensate projection. The model is then run again with the rate acceleration well included.
The difference between these two cases is the incremental PUD reserve case. Of the gas volumes the rate acceleration well is projected
to produce, the majority comes from other wells in the field, such that the incremental gas recovery for the rate acceleration well is
much less, and results in a negative condensate volume as of December 31, 2011.
(2) Of this amount, approximately 6.0 Bcfe is attributable to the rate acceleration well in our Dutch and Mary Rose field, as a result of
additional information obtained from the other wells in that field.
(3) Of this amount, 2.2 Bcfe is attributable to our South Timbalier 17 well, which we expect to begin production in mid-2014, while the
remaining 12.8 Bcfe is attributable to onshore drilling during the quarter ended December 31, 2013.
(4) Attributable to our Merger with Crimson and the purchase of additional interests in our operated Dutch wells.
Significant Properties
Summary proved reserve information for our properties as of December 31, 2013, by region, is provided below, excluding
reserves attributable to our investment in Exaro (dollars in thousands):
Regions
Crude Oil
(MBbl)
Natural Gas
(MMcf)
Natural Gas
Liquids (MBbl)
Total
(Mmcfe)
Proved Reserves
Offshore GOM
Southeast Texas
South Texas
Other
Total
2,032
4,645
2,661
360
9,698
150,495
16,388
36,382
4,665
207,930
4,643
1,332
1,820
163
7,958
190,545
$
52,250
63,268
7,803
313,866
$
987,213
(1)
554,576
264,320
150,386
17,931
(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, 2013 and 2012 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.
38
Reserves as of December 31, 2013 were reviewed by our corporate reservoir engineering department as described above.
Reserves as of December 31, 2012 were reviewed by members of the Company’s management, including Mr. Joseph J. Romano,
the Company’s then-Chief Executive Officer, and Mr. Brad Juneau, as described above. The technical individual at Von Gonten
responsible for overseeing the preparation of our reserve estimates as of December 31, 2013 and December 31, 2012 has over 13
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; and is a member in good standing of the Society of Petroleum
Engineers.
The following table reflects our estimated proved reserves attributable to our Investment in Exaro:
December 31, 2013
December 31, 2012
Crude Oil (MBbl)
Developed
Undeveloped
Total
Natural Gas (MMcf)
Developed
Undeveloped
Total
Total MMcfe
Developed
Undeveloped
Total
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)
$
$
$
100%
63,906
87.89
4.04
$
$
$
133
124
257
11,056
5,771
16,827
11,854
6,515
18,369
65%
5,270
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.
Prior Year Reserves
Our estimated net proved natural gas, oil and natural gas liquids reserves as of December 31, 2012, 2011 and 2010 are
disclosed in Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Disclosures (Unaudited), and were
based on reserve reports generated by Cobb, while the reserves associated with our 37% investment in Exaro were prepared by
Von Gonten. The reserve estimates as of December 31, 2010 also include the reserves associated with the Joint Venture Assets
which were prepared exclusively by Lonquist & Co. LLC (“Lonquist”). These Joint Venture Asset reserves account for
approximately 7% of our total reserves as of December 31, 2010 and were sold on May 13, 2011. The technical person at Lonquist
responsible for overseeing the preparation of our Joint Venture Asset reserve estimates had over 23 years of practical experience
in the estimation and evaluation of reserves, is a registered professional engineer in the state of Texas, has a BS in Petroleum
Engineering, and is a member in good standing of the Society of Petroleum Engineers and the Society of Petroleum Evaluation
Engineers. This individual meets or exceeds the education, training, and experience requirements set forth in the standards pertaining
to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is
proficient in the application of industry standard practices to engineering evaluations as well as the application of SEC and other
industry definitions and guidelines.
39
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. The damages most recently alleged by the plaintiffs are approximately $13.4 million. We and our
co-defendants are vigorously defending this lawsuit and believe that we have meritorious defenses. We and our co-defendants
obtained a favorable judgment from the trial court following a trial, but the judgment is being appealed by the plaintiffs. A
companion case involving the same claims, wells, etc. was filed in the same court on April 19, 2013 on behalf of additional mineral
interest owners.
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. The trial
court has granted the plaintiffs motion for partial summary judgment as to liability (but not damages). The Plaintiff recently
asserted damages of approximately $6.0 million, inclusive of interest but exclusive of legal fees which may be recoverable by the
plaintiff if it ultimately prevails in this case. We are vigorously defending this lawsuit, believe that we have meritorious defenses
and intend to appeal the aforementioned decision.
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 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. In their initial pleading the plaintiff alleges damages in excess of $6.0 million,
which is generally in line with amounts received on its undisputed 1/16th mineral interest as of the date the suit was filed. As of
January 2014, the Plaintiff had received approximately $8.5 million in royalties in respect of its undisputed interest. 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 have been brought by Crimson stockholders in Delaware
Chancery Court seeking damages and injunctive relief including, among other things, compensatory damages and costs and
disbursements relating to the lawsuits. Various combinations of the Company, certain subsidiaries of the Company, members of
Crimson’s pre-merger board of directors, members of Crimson’s pre-merger management team and Oaktree Capital Management
L.P. have been named as defendants in these lawsuits. The Delaware lawsuits have been consolidated into a single action referred
to as In Re: Crimson Exploration Inc. Stockholder Litigation; C.A. 8541-VCP. Additionally, on July 13, 2013, a separate and
similar complaint was filed in the District Court of Harris County Texas, in the matter of Fisichella Family Trust v. Crimson
Exploration Inc. It is possible that additional similar lawsuits may be filed.
The merger-related lawsuits allege, among other things, that Crimson’s board of directors failed to take steps to obtain a
fair price, failed to properly value Crimson, failed to protect against alleged conflicts of interest, failed to conduct a reasonably
informed evaluation of whether the transaction was in the best interests of stockholders, failed to fully disclose all material
information to stockholders, acted in bad faith and for improper motives, engaged in self-dealing, discouraged other strategic
alternatives, took steps to avoid competitive bidding, and agreed to allegedly unreasonable deal protection mechanisms, including
the no-shop, fiduciary-out provisions and termination fee. The lawsuits also allege that Contango and certain other defendants
aided and abetted the other defendants in violating duties to the Crimson stockholders. The known plaintiffs in these lawsuits
collectively owned a very small percentage of the total outstanding shares of Crimson common stock at the time of the Merger,
which was approved by Contango’s pre-merger shareholders (89% of outstanding shares and 99% of voted shares were voted in
40
favor of the Merger) and Crimson’s pre-merger shareholders (69% of outstanding shares and 88% of voted shares were voted in
favor of the Merger). The Company believes that these merger-related lawsuits are without merit and intends to contest them
vigorously. The Company has maintained an officers and directors liability insurance policy for Crimson former directors and
officers and has made a claim under the policy for coverage of these merger-related lawsuits.
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.
Item 4. Mine Safety Disclosures
Not applicable.
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, 2013:
Quarter ended March 31, 2013
Quarter ended June 30, 2013
Quarter ended September 30, 2013
Quarter ended December 31, 2013
Year Ended December 31, 2012:
Quarter ended March 31, 2012
Quarter ended June 30, 2012
Quarter ended September 30, 2012
Quarter ended December 31, 2012
High
Low
$
$
$
$
$
$
$
$
46.05
40.49
40.06
48.80
65.08
60.24
61.16
52.64
$
$
$
$
$
$
$
$
36.27
33.50
33.22
36.46
56.73
51.00
49.11
38.10
From the period from January 1, 2014 to March 27, 2014, our common stock traded at prices between $40.09 and $50.44
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/A, and by the provisions of applicable law.
Common Stock
We are authorized to issue up to 50 million shares of common stock. As of March 27, 2014, there were approximately
24.4 million shares of common stock issued and 19.4 million shares of common stock outstanding held by approximately 284
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
41
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.
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, 2013.
Share-Based Compensation
The following table sets forth information about our equity compensation plans at December 31, 2013:
Plan Category
2009 Equity Compensation Plan - approved by security holders
2005 Stock Incentive Plan (“Crimson Plan”)
2009 Equity Compensation Plan
Number of
securities to be
issued upon
exercise of
outstanding
options
—
135,107
Weighted-
average
exercise price of
outstanding
Number of securities
remaining
available for future
issuance under equity
compensation plans
options
$0.00
$53.00
1,162,162
11
On September 15, 2009, the Company’s board of directors (the “Board”) adopted the Contango Oil & Gas Company
Equity Compensation Plan (the “2009 Plan”), which was approved by shareholders on November 19, 2009. Under the 2009 Plan,
the Board may grant restricted stock and option awards 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 original terms of the 2009 Plan, the Company may issue up to 1,500,000 shares of common stock or stock
options with 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, 2012, there were no options or restricted shares of common stock outstanding under the
2009 Plan.
During the quarter 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.
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 quarter 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 next four years. Additionally, 791 stock options were
exercised, leaving 135,107 stock options vested and exercisable at December 31, 2013. The converted exercise price for such
42
options range from $25.70 to $60.33 per share, with an average remaining contractual life of seven years. As of December 31,
2013, there were 11 shares of common stock or stock options available to be granted under the 2005 Plan.
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.
1999 Stock Incentive Plan
The Company’s 1999 Stock Incentive Plan (the “1999 Plan”) expired in August 2009. The final remaining outstanding
options were net-settled with the Company in February 2012 and no options remain outstanding.
Incentive Compensation Plans effective January 1, 2014
Beginning in 2014 the Company will provide performance-based long-term bonus plans for the benefit of all employees,
the Cash Incentive Bonus Plan (“CIBP”) and the Long-Term Incentive Plan (“LTIP”). Both plans, and specific targeted
performance measures under those plans, will be approved by the Compensation Committee and the Board. Upon achieving the
performance levels established each year, bonus awards will be calculated as a percentage of base salary of each employee for the
plan year. The plan awards for each year are disbursed in the first quarter of the following year. Employees must be employed
by the Company at the time that plan awards are disbursed to be eligible.
The CIBP awards will be paid in cash. The LTIP bonus awards can be paid in restricted common stock and/or stock
options. The stock awards and options are expected to vest 25% per year, over the first through fourth anniversaries from the
date of grant. 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. The stock awards and options
awards granted pursuant to the LTIP will be granted under the 2009 Plan.
Share Repurchase Programs
$100 Million Share Repurchase Program
In September 2008, our board of directors approved a $100 million share repurchase program which concluded in October
2011. Under this share repurchase program, we purchased a total of 2,157,278 shares of common stock at an average price of
$46.35 per share. All shares were purchased in the open market or through privately negotiated transactions. The purchases were
made subject to market conditions and certain volume, pricing and timing restrictions to minimize the impact of the purchases
upon the market, and when we believed our 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.
$50 Million Share Repurchase Program
In September 2011, our board of directors approved a $50 million share repurchase program, effective upon completion
of the $100 million share repurchase program. The repurchases are subject to the same terms and conditions as repurchases under
the $100 million share repurchase program. No shares were purchased during the year ended December 31, 2013. For the year
ended December 31, 2012, we purchased the following shares under the $50 million share repurchase program:
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
$
$
$
53.56
51.92
50.82
71,761
100,381
197,877
$45.7 million
$44.2 million
$39.2 million
Period
May 9 - 31, 2012
June 1-4, 2012
October 2-5, 2012
Additionally, in February 2012, the Company net-settled 45,000 stock options from two officers for $0.5 million. As of
December 31, 2013, the Company had invested $10.8 million in this share repurchase program to purchase 197,877 shares and
net-settle 45,000 stock options from two officers, leaving $39.2 million available for future purchases.
Under the terms of our credit facility with Royal Bank of Canada entered into on October 1, 2013, share repurchases are
limited to $1 million per calendar year, and may only be purchased from officers, directors, employees and consultants upon their
death, disability, retirement or termination, in accordance with any termination agreement or employment agreement.
43
Stock Performance Graph
The following graph compares the yearly percentage change from December 31, 2008 until December 31, 2013 in the
cumulative total stockholder return on our common stock to the cumulative total return on the S&P Smallcap 600 Index, a pre-
Merger peer group of companies and a post-Merger group of companies.
Prior to the Merger, we compared our return to a selected peer group which included Stone Energy Corporation, SandRidge
Energy Inc., Callon Petroleum, Energy XXI (Bermuda) Limited, and W&T Offshore, Inc. ("Pre-Merger Peer Group"). As a result
of our Merger with Crimson, we made changes to our peer group to remove Stone Energy Corporation and SandRidge Energy
Inc. due to dissimilarities to our operational and financial characteristics, and added Petroquest Energy, Inc. and Swift Energy
Company. After the change in companies, our peer group consists of Petroquest Energy, Inc., Swift Energy Company, Callon
Petroleum, Energy XXI (Bermuda) Limited and W&T Offshore, Inc. ("Post-Merger Peer Group").
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, 2008, 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
Pre-Merger Peer Group
Post-Merger Peer Group
12/31/2008 12/31/2009 12/31/2010 12/31/2011 12/31/2012 12/31/2013
88.34
263.37
171.14
152.21
102.90
158.60
168.02
192.49
100.00
100.00
100.00
100.00
79.18
186.37
164.64
164.33
103.34
160.22
193.16
197.52
83.50
125.57
130.63
109.35
44
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 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 years ended December 31, 2010 and 2009 have 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/A.
Selected financial data for the year ended December 31, 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,
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 a goodwill.
No goodwill was recognized as a results of the Merger between Contango and Crimson.
Selected financial information for the five years ended December 31, 2013 is as follows (dollars in thousands, except
per share amounts):
Year Ended December 31,
2013
2012
2011
2010
2009
(unaudited)
(unaudited)
Natural gas and oil sales (a)
$ 164,121 $ 145,868 $ 198,498 $
180,331 $
154,101
Income (loss) from continuing operations (b)
Discontinued operations, net of income taxes
$
41,362 $
(907) $
69,909 $
46,831 $
38,605
—
(29)
(1,204)
983
—
Net income (loss) attributable to common stock
$
41,362 $
(936) $
68,705 $
47,814 $
38,605
Net income (loss) per share:
Basic
Continuing operations
Discontinued operations
Total
Diluted
Continuing operations
Discontinued operations
Total
Weighted average shares outstanding:
Basic
Diluted
$
$
$
$
2.56
—
(0.06) $
4.49 $
2.97 $
—
(0.08)
0.06
2.56 $
(0.06) $
4.41 $
3.03 $
2.56 $
(0.06) $
4.49 $
2.93 $
—
—
(0.08)
0.06
2.56 $
(0.06) $
4.41 $
2.99 $
2.43
—
2.43
2.38
—
2.38
16,156
16,158
15,295
15,295
15,582
15,585
15,747
15,957
15,912
16,219
45
Working capital (deficit ) (c)
Capital expenditures
Cash dividends (d)
Long term debt (e)
Shareholders’ equity
Total assets
Proved Reserve Data:
Total proved reserves (Mmcfe) (f)
Year Ended December 31,
2013
2012
2011
2010
2009
(unaudited)
(unaudited)
$ (33,162) $ 100,901 $ 163,245 $
61,716 $
60,039
$
$
$
62,552 $
78,549 $
40,330 $
132,413 $
33,163
— $
30,510 $
90,000 $
— $
— $
— $
6 $
— $
—
—
$ 593,050 $ 403,929 $ 444,003 $
392,298 $
382,409
$ 910,304 $ 561,106 $ 621,817 $
579,075 $
584,926
313,866
221,096
261,201
297,791
353,385
Pre-tax net present value (discounted 10%)
$ 987,213 $ 594,397 $ 909,675 $
912,066
Standardized measure (f)
$ 771,443 $ 388,012 $ 591,833 $
603,408
(a) The increase in natural gas and oil sales for the year ended December 31, 2013 is attributable to the merger with Crimson.
(b) During the year ended December 31, 2012, we drilled two unsuccessful exploratory wells resulting in exploration expenses of
approximately $50 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. During the year ended December
31, 2013 we completed a workover on our Vermilion 170 well at a cost of approximately $12.0 million.
(c) 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.
(d) 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.
(e) On October 1, 2013, in connection with the Merger, we entered into a revolving credit facility with Royal Bank of Canada and other
lenders. As of December 31, 2013, we had $90 million outstanding under such facility.
(f) 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.
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.
46
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/A covers the three year period ended December 31, 2013.
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 offshore in the shallow waters of the Gulf of Mexico and in the onshore
Gulf Coast regions of the United States and Colorado.
On October 1, 2013, we completed a merger with Crimson, under an all-stock transaction pursuant to which Crimson
became a wholly-owned subsidiary of Contango. The Merger with Crimson has given us access to high rate of return onshore
prospects in known, prolific producing areas as well as long-life resource plays in Southeast Texas (the Woodbine oil and liquids-
rich play) and South Texas (the Buda and Eagle Ford Shale oil and liquids-rich plays). We believe these areas provide significant
long-term growth potential from multiple formations. Our production for the year ended December 31, 2013 was approximately
87% offshore and 13% onshore. Our production for the three months ended December 31, 2013 was approximately 63% offshore
and 37% onshore. As of December 31, 2013, our proved reserves were approximately 61% offshore and 39% onshore and our
proved developed reserves were approximately 74% offshore and 26% onshore.
Additionally, we have (i) an equity investment in Exaro Energy III LLC ("Exaro"), which is primarily focused on the
development of proved natural gas reserves in the Jonah Field in Wyoming; (ii) acreage positions and non-operated producing
properties in Louisiana and Mississippi targeting the Tuscaloosa Marine Shale (“TMS”); (iii) operated producing properties in the
James Lime play in East Texas and (iv) operated producing properties in the Denver Julesburg Basin (“DJ Basin”) in Weld and
Adams counties in Colorado, which we believe are prospective in the Niobrara Shale oil play.
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. 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 Company drilled
one productive offshore well in each of the years ended December 31, 2011 and 2013. For the year ended December 31, 2012,
however, the Company drilled two unsuccessful exploratory wells at Ship Shoal 134 and South Timbalier 75. In June 2012 and
March 2013, the Company successfully acquired nine lease blocks at two Gulf of Mexico lease sales. Our plan is to apply for
permits to drill these prospects during the next several years.
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.
Related Party Transactions
The Company has historically relied on 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
47
generated by third-party independent companies for us to purchase. With the merger with Crimson, and the technical teams obtained
in the merger, the Company will be active in identifying onshore opportunities, while continuing its relationship with JEX and
REX for potential new offshore drilling prospects. 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.
Impact of Deepwater Horizon Incident
We believe that the Deepwater Horizon incident continues to have a significant and lasting effect on the U.S. offshore
energy industry, and will result in a number of fundamental changes, including heightened regulatory scrutiny, more stringent
operating and safety standards, changes in equipment requirements and the availability and cost of insurance, as well as increased
politicization of the industry. A significant delay of planned exploratory activities has reduced our longer term ability to replace
reserves, resulting in a negative impact on production, including a reduction in operating results and cash flows as we deplete our
reserves. There may be other impacts of which we are not aware at this time.
The potential for removal of the liability cap for claims of damages from oil spills, and/or the enactment of onerous rules
and regulations regarding activities in the Gulf of Mexico could significantly alter our industry. Such rules could effectively limit
which companies can operate in the Gulf of Mexico. Small and medium-sized oil and gas companies may not be able to obtain
insurance coverage at economically appropriate levels or meet financial responsibility requirements and would be forced to exit
operations in the Gulf of Mexico. Potentially less attractive economics for offshore exploration and development programs going
forward will require companies retaining operations in the Gulf of Mexico to review their business models. We have drilled, and
believe we can continue to drill, safely in the Gulf of Mexico. However, exploration and production companies will be able to
continue doing business in the Gulf of Mexico only to the extent it remains economically viable.
Delays and volatility are inherent in our business. We have maintained a capital structure with a strong liquidity position
allowing us to manage during periods of uncertainty. We believe we are well-positioned to respond to the increasingly complex
regulatory framework for the Gulf of Mexico.
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:
Dutch and Mary
Rose
Vermilion 170
Southeast Texas (1)
South Texas (1)
Other (1)
Three Months Ended
March 31,
2012
June 30,
2012
September
30, 2012
December
31, 2012
March 31,
2013
June 30,
2013
September
30, 2013
December
31, 2013
59.3
15.3
—
—
8.1
82.7
67.5
15.5
—
—
7.8
90.8
54.2
10.5
—
—
3.5
68.2
57.2
12.9
—
—
2.6
72.7
59.5
3.6
—
—
1.5
64.6
57.2
4.0
—
—
1.0
62.2
61.7
9.6
—
—
0.7
59.1
9.6
24.3
14.7
2.5
72.0
110.2
(1) Southeast Texas and South Texas production is 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 due to the Merger. Additionally, the "Other" field only
includes Ship Shoal 263 for periods prior to the quarter ended December 31, 2013, and includes additional onshore wells for the quarter
ended December31, 2013.
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.
48
Southeast Texas
During 2012, Crimson's Southeast Texas production averaged approximately 19 Mmcfed. For the quarter ended December
31, 2013, Southeast Texas production averaged approximately 24.3 Mmcfed. Crimson, and then 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. We will
continue our focus on further developing our inventory of crude oil and liquids-rich projects in the Woodbine formation with a
continuous rig program planned for 2014.
South Texas
During 2012, Crimson's South Texas production averaged approximately 15 Mmcfed. 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,
which have recently come on production. We have one well in process at year-end 2013 and expect to have at least one rig running
full-time in 2014.
Other
For all of the periods presented, Other includes our Ship Shoal 263 well, the TMS, East Texas and Colorado. 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. The well reached payout during fiscal year 2012.
We will continue producing this well as long as it is economical.
Year Ended December 31, 2013 Compared to Year Ended December 31, 2012; and Year Ended December 31, 2012
Compared to Year Ended December 31, 2011
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, 2013,
2012 and 2011. 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 thousand cubic feet (“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,
2013
2012
%
Year Ended December 31,
2011
%
2012
Revenues:
Natural gas sales
Condensate sales
NGL sales
Total revenues
Annual Production:
Natural gas (million cubic feet)
Dutch and Mary Rose field
Vermilion 170 field
Southeast Texas field
South Texas field
Other fields
Total natural gas
Oil and condensate (thousand barrels)
Dutch and Mary Rose field
Vermilion 170 field
Southeast Texas field
South Texas field
Other fields
Total oil and condensate
(thousands)
(thousands)
79,289
$ 60,691
31 % $ 60,691
59,608
$ 56,237
6 % $ 56,237
25,224
$ 28,940
(13)% $ 28,940
$
$
$
94,666
67,594
36,238
164,121
$ 145,868
13 % $ 145,868
$ 198,498
$
$
$
$
17,018
1,823
16,954
3,449
*
(47)%
16,954
3,449
875
623
285
20,624
— 100 %
— 100 %
—
—
1,347
21,750
(79)%
(5)%
1,347
21,750
262
38
160
95
34
589
49
302
110
(13)%
(65)%
— 100 %
— 100 %
95
507
(64)%
16 %
302
110
—
—
95
507
18,872
1,212
—
—
2,713
22,797
394
50
—
—
180
624
(36)%
(17)%
(20)%
(27)%
(10)%
185 %
— %
— %
(50)%
(5)%
(23)%
120 %
— %
— %
(47)%
(19)%
Year Ended December 31,
2013
2012
%
Year Ended December 31,
2011
%
2012
Natural gas liquids (thousand barrels)
Dutch and Mary Rose field
Vermilion 170 field
Southeast Texas field
South Texas field
Other fields
Total natural gas liquids
Total (million cubic feet equivalent)
Dutch and Mary Rose field
Vermilion 170 field
Southeast Texas field
South Texas field
Other fields
Total production
Daily Production:
Natural gas (million cubic feet per day)
Dutch and Mary Rose field
Vermilion 170 field
Southeast Texas field
South Texas field
Other fields
Total natural gas
Oil and condensate (thousand barrels per day)
Dutch and Mary Rose field
Vermilion 170 field
Southeast Texas field
South Texas field
Other fields
Total oil and condensate
Natural gas liquids (thousand barrels per day)
Dutch and Mary Rose field
Vermilion 170 field
Southeast Texas field
South Texas field
Other fields
Total natural gas liquids
Total (million cubic feet equivalent per day)
Dutch and Mary Rose field
Vermilion 170 field
Southeast Texas field
South Texas field
Other fields
Total production
514
68
66
26
3
677
21,674
2,459
2,231
1,349
507
28,220
46.6
5.0
9.5
6.8
1.8
69.7
0.7
0.1
1.7
1.0
0.1
3.6
1.4
0.2
0.7
0.3
—
2.6
59.4
6.7
24.3
14.7
2.7
107.8
50
503
141
2 %
(52)%
— 100 %
— 100 %
16
660
(81)%
3 %
503
141
—
—
16
660
21,784
4,955
(1)%
(50)%
21,784
4,955
— 100 %
— 100 %
—
—
2,013
28,752
(75)%
(2)%
2,013
28,752
*
46.4
46.4
9.4
(47)%
— 100 %
— 100 %
3.7
59.5
0.8
0.3
(51)%
17 %
(13)%
(67)%
— 100 %
— 100 %
0.3
1.4
1.4
0.4
(67)%
157 %
— %
(50)%
— 100 %
— 100 %
—
1.8
59.7
13.6
— %
44 %
(1)%
(51)%
— 100 %
— 100 %
5.5
78.8
(51)%
37 %
9.4
—
—
3.7
59.5
0.8
0.3
—
—
0.3
1.4
1.4
0.4
—
—
—
1.8
59.7
13.6
—
—
5.5
78.8
532
48
—
—
27
607
24,428
1,800
—
—
3,955
30,183
51.7
3.3
—
—
7.4
62.4
1.1
0.1
—
—
0.5
1.7
1.5
0.1
—
—
0.1
1.7
66.9
4.9
—
—
10.8
82.6
(5)%
194 %
— %
— %
(41)%
9 %
(11)%
175 %
— %
— %
(49)%
(5)%
(10)%
185 %
— %
— %
(50)%
(5)%
(23)%
120 %
— %
— %
(47)%
(19)%
(5)%
194 %
— %
— %
(41)%
9 %
(11)%
175 %
— %
— %
(49)%
(5)%
Year Ended December 31,
2013
2012
%
Year Ended December 31,
2011
%
2012
Average Sales Price:
Natural gas (per thousand cubic feet)
Oil and condensate (per barrel)
Natural gas liquids (per barrel)
Total (per thousand cubic feet equivalent)
Expenses (thousands):
Operating expenses (including production taxes)
Exploration expenses
Depreciation, depletion and amortization
Impairment of natural gas and oil properties
General and administrative expenses
Gain from affiliates (net of taxes)
Loss (gain) from sale of assets and other expense (income)
Selected data per Mcfe:
Operating expenses
General and administrative expenses
Depreciation, depletion and amortization of natural gas and
oil properties
* Less than 1%
** Greater than 1,000%
$
$
$
$
$
$
$
$
$
$
$
$
$
$
3.84
$
2.79
38 % $
2.79
101.21
$ 110.92
(9)% $ 110.92
37.26
5.82
$
$
43.85
5.07
(15)% $
43.85
15 % $
5.07
$
$
$
$
4.15
108.32
59.70
6.58
36,784
1,811
65,529
776
26,512
2,310
(29,482) $
23,720
51,903
44,896
14,079
11,265
60
367
55 %
(97)%
46 %
(94)%
135 %
**
**
$
23,720
51,903
44,896
14,079
11,265
60
367
28,285
—
48,988
1,680
10,614
—
201
1.30
0.94
2.32
$
$
$
0.82
0.39
59 % $
141 % $
0.82
0.39
1.56
49 % $
1.56
$
$
$
0.94
0.35
1.62
(33)%
2 %
(27)%
(23)%
(16)%
100 %
(8)%
738 %
6 %
100 %
83 %
(13)%
11 %
(4)%
Not included in the table above is production information from our discontinued operations. For the year ended December
31, 2011, our discontinued operations produced approximately 0.9 Mmcf of natural gas, 6,000 thousand barrels of condensate,
and 27,000 barrels of natural gas liquids at average prices of $3.81 per Mcf, $102.83 per Bbl and $45.48 per Bbl, respectively.
The Company did not have any production from discontinued operations for the years ended December 31, 2013 or 2012.
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,
our production declines over time as we produce our reserves.
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.
We reported revenues of approximately $145.9 million for the year ended December 31, 2012, down from approximately
$198.5 million reported for the year ended December 31, 2011. This decrease in revenues was principally attributable to lower
equivalent production for the period as well as a lower average equivalent sales price received for the period.
Our net natural gas production for the year ended December 31, 2012 was approximately 59.5 Mmcfd, down from
approximately 62.4 Mmcfd for the year ended December 31 2011. Net oil and condensate production for the comparable periods
also decreased from approximately 1,700 barrels per day to approximately 1,400 barrels per day, and our NGL production slightly
51
increased from 1,700 barrels per day to 1,800 barrels per day. In total, equivalent production decreased from 82.6 Mmcfed to 78.8
Mmcfed, principally attributable to our Eloise North well which stopped producing in October 2011 and was subsequently
recompleted as our Mary Rose #5 well in early 2012, but has only produced intermittently since recompletion. Partially offsetting
this decrease in production is our Vermilion 170 well which began producing in September 2011.
Average Sales Prices
For the year ended December 31, 2013, the price of natural gas was $3.84 per Mcf while the price for oil and NGLs was
$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 price for oil and NGLs was $110.92 per barrel and $43.85 per barrel, respectively. For the year ended December
31, 2011, the price of natural gas was $4.15 per Mcf while the price for oil and NGLs was $108.32 per barrel and $59.70 per barrel,
respectively.
Operating Expenses (including production taxes)
Operating expenses for the year ended December 31, 2013 were approximately $36.8 million, which included
approximately $4.7 million in production and severance taxes and $12.0 million in workover costs for Vermilion 170. The remaining
$20.1 million is related to well insurance and recurring lease operating expenses and is 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 $3.6 million in production and severance taxes and $1.8 million in workover costs. The remaining $18.3 million
is related to well insurance and recurring lease operating expenses. Operating expenses for the year ended December 31, 2011
were approximately $28.3 million, which included approximately $4.5 million in severance taxes and $2.6 million in workover
costs. The remaining $21.2 million is related to well insurance and recurring lease operating expenses.
Exploration Expenses
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 higher costs incurred in 2012 consist of $50.0 million for our dry holes
at Ship Shoal 134 and South Timbalier 75, $1.4 million related to an unsuccessful drilling program at 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, 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.
Depreciation, depletion and amortization for the year ended December 31, 2012 was approximately $44.9 million. This
compares to approximately $49.0 million for the year ended December 31, 2011. The decrease in depreciation, depletion and
amortization was primarily attributable to an overall decrease in production due to our Eloise North well which stopped producing
in October 2011 and was subsequently recompleted as our Mary Rose #5 well in early 2012, but has only produced intermittently
since recompletion. Partially offsetting this decreased production is our Vermilion 170 well which began producing in September
2011.
Impairment of Natural Gas and Oil Properties
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. For the year ended December 31, 2011, the Company recorded impairment expense of approximately
$1.7 million related to the relinquishment of 14 lease blocks owned by Contango and REX.
General and Administrative Expenses
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 $1.2 million in State of Louisiana franchise taxes, $12.1 million in salaries and
52
benefits ($3.2 million of which was non-cash stock based compensation), $0.7 million in insurance costs, $6.3 million in accounting,
legal, tax and professional services, $1.8 million in office and other administrative expenses, $0.5 million in board of directors
compensation, 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, compared
to $10.6 million for the year ended December 31, 2011. Major components of general and administrative expenses for the year
ended December 31, 2012 included approximately $0.8 million in State of Louisiana franchise taxes, $5.6 million in salaries and
benefits, $0.4 million in insurance costs, $3.3 million in accounting, legal, tax and professional services, $0.7 million in office
and other administrative expenses, and $0.5 million in board of directors compensation.
General and administrative expenses for the year ended December 31, 2011 were approximately $10.6 million. Major
components of general and administrative expenses for the year ended December 31, 2011 included approximately $0.7 million
in State of Louisiana franchise taxes, $7.7 million in salaries and benefits, $0.4 million in insurance costs, $1.2 million in accounting,
tax, legal and consulting expenses, $0.3 million in administrative costs, and $0.3 million related to board of directors compensation.
Gain from Affiliates
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 gain from the sale of assets and other for the year ended December 31, 2013 was approximately $29.5 million, which
consisted of $15.3 million related to our investment in Alta, $6.6 million related to the disposition of a portion of our South East
Texas acreage, and includes the proceeds of a $10 million life insurance policy for the Company's former Chairman, President
and Chief Executive Officer, Mr. Peak, who passed away on April 19, 2013.
Discontinued Operations
The table and discussions above, along with our financial statements, discuss only continuing operations for all fiscal
years presented. Not reflected are the Company’s sold producing properties which generated approximately 0%, 0% and 2.5% of
combined revenues for the year ended December 31, 2013, 2012 and 2011, respectively. See Note 18 to our Financial Statements
– "Discontinued Operations" for a discussion of our discontinued operations.
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.
Year ended December 31,
2012
2011
2013
Net cash provided by operating activities
Net cash used in investing activities
Net cash used in financing activities
$
$
105,037
$
90,122
$
128,100
(34,795) $ (123,945) $
(2,558)
$ (149,729) $ (38,630) $
(17,037)
Cash and cash equivalents at the end of the period
$
— $
79,487
$
151,940
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 flow from operating activities provided approximately $90.1 million in cash for the year ended December 31, 2012
compared to $128.1 million for the year ended December 31, 2011. This decrease in cash provided by operating activities was
primarily attributable to the timing of payments of the Company's obligations.
53
Cash used in investing activities was approximately $34.8 million in cash for the year ended December 31, 2013 compared
to $123.9 million for the year ended December 31, 2012. This decrease in cash used in investing activities was primarily attributable
to $16.3 million less in capital expenditures for 2013, $39.4 million less in investment in affiliates for 2013, and $43.2 million in
proceeds from the sale of assets and distributions from affiliates during the year ended December 31, 2013.
Cash used in investing activities for the year ended December 31, 2012 was approximately $123.9 million compared to
$2.6 million for the year ended December 31, 2011. This increase in cash used in investing activities was primarily attributable
to $38.3 million more in capital expenditures in 2012 as a result of drilling two dry holes at Ship Shoal 134 and South Timbalier
75, $54.3 million more in investment in affiliates in 2012 as a result of our investment in Alta and Exaro, and $38.7 million in
proceeds from the sale of assets during the year ended December 31, 2011.
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.
Cash used in financing activities for the year ended December 31, 2012 was approximately $38.6 million, compared to
$17.0 million used in financing activities in 2011. This increase in cash used is attributable to paying a $30.5 million dividend to
shareholders in December 2012.
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. 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. As of December 31, 2013, we had $90 million outstanding under the
RBC Credit Facility. As of March 27, 2014, we had $60 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, 2013, 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.
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 offshore and those identified in our resource plays in Southeast, South and
East Texas and Colorado and in our conventional inventory, 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 2014 capital expenditures to our forecasted
cash flow from operations for the year; however, we do possess the capacity, through our RBC Credit Facility, to increase and/or
54
accelerate drilling on any particular area should we determine that market and project economics so warrant. The substantial
majority of our planned capital expenditures for 2014 are on acreage that is currently held by existing production, therefore, we
also possess the flexibility of reducing our capital expenditures, if deemed appropriate. 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 2014 capital budget is currently forecasted to be approximately $216 million, exclusive of acquisitions, if any, and
will be focused primarily on our onshore inventory of crude oil and liquids-rich projects in the Buda and Woodbine formations
with at least one rig running full time in each of the Buda and Woodine, complemented by one to two exploratory wells in the
shallow waters of the Gulf of Mexico.
Inflation and Changes in Prices
While the general level of inflation affects certain costs associated with the petroleum 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, 2013, 2012 and 2011, we paid approximately $0.3 million, $24.3 million and
$30.0 million, respectively, in federal and state income taxes, net of cash refunds received.
Discontinued Operations
The table below sets forth the proceeds received from discontinued operations for the year ended December 31, 2011,
the impact of the sale on our developed reserve quantities, and a measure of our developed reserves held at the end of the year.
See the reserve activity reported in Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Disclosures
(Unaudited) for a more detailed discussion regarding our standardized measure. The Company did not have any material
discontinued operations for the years ended December 31, 2013 or 2012.
Year of Property Sale
Proceeds
Received
Reserves
Sold
(Bcfe)
Reserves at e
nd of
Fiscal Year
(Bcfe)
Standardized Measure of
Discounted Future Net
Cash Flows at end of
Fiscal Year
(thousands)
2011
$38.7 million
17.2
261.2
$
591,833
For the year ended December 31, 2011, we realized approximately $6.3 million in operating cash flows from discontinued
operations, $10.9 million in investing cash flows from discontinued operations and used $17.1 million in financing cash flows
from discontinued operations.
Contractual Obligations
The following table summarizes our known contractual obligations as of December 31, 2013:
Payment due by period (thousands)
Total
Less than
1 year
1 - 3 years
3 - 5 years
More than
5 years
Long term debt and interest (1)
$
100,132
$
2,699
$
5,399
$
92,034
$
Delay rentals
Asset retirement obligations
Employment agreements
Operating leases (2)
Uncertain income tax positions (3)
Total
936
38,751
10,719
10,021
518
278
2,506
6,700
4,226
—
556
9,551
4,019
3,142
—
102
670
—
2,384
—
—
—
26,024
—
269
518
$
161,077
$
16,409
$
22,667
$
95,190
$
26,811
(1) Estimated interest is based on the outstanding debt at December 31, 2013 using the interest rate in effect at that time.
55
(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) 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 Notes to Consolidated Financial Statements included as part of this Form 10-K/A. 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.
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, 2013 of 5%, 10% and 15% would affect depreciation, depletion and amortization expense by approximately
$3.3 million, $6.9 million and $11.0 million, respectively.
56
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 condemn 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 is reported in Other Income and Expense as unrealized (gain)
loss on derivative instruments.
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.
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 tax income and
changes in stockholder ownership that limit the use of net operating losses under the Internal Revenue Code 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 valuation allowance was 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
57
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. Our consolidated balance sheet presented as of December 31, 2013 reflects the preliminary purchase price allocations
based on available information. Management is reviewing the valuation and conforming results to determine the final purchase
price allocation. 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 ASC 805, Business combinations.
Recent Accounting Pronouncements
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 are currently evaluating the provisions of the revised framework and assessing the impact, if any, it may have on
our internal control structure.
In February 2013, the Financial Accounting Standards Board ("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. We are currently evaluating the provisions of this accounting update and assessing the impact,
if any, it may have 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, 2013, 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 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 natural gas and oil 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 natural gas and oil are volatile and unpredictable. For the year ended December 31, 2013, a 10% fluctuation in the prices
received for natural gas and oil production would have had an approximately $16.4 million impact on our revenues.
Derivative Instruments and Hedging Activity
We expect energy 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 hedge through the use of our derivative instruments
varies from period to period, however, generally our objective is to hedge approximately 40% to 50% of our current and anticipated
58
production for the next 18 to 24 months. Our hedge strategy and objectives may change significantly as our operational profile
changes and/or commodities prices change.
We are exposed to market risk on our 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
current derivative contracts are large financial institutions and also lenders or affiliates of lenders in its 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. Currently we did not enter into any derivative contracts to
reduce the exposure to market rate fluctuations. At December 31, 2013, we did not have any open positions that converted our
variable interest rate debt to fixed interest rates. 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 9 to our Financial Statements - "Derivative Instruments"
for more details.
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 US Prime 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, 2013, our total long-term debt was $90 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 quarter ended December 31, 2013 our effective rates fluctuated between 2.2 percent and 4.5 percent, depending on the
term of the specific debt drawdowns. At December 31, 2013, we did not have any outstanding interest rate swap agreements. As
of December 31, 2013, the weighted average interest rate on our variable rate debt was 2.2% 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 $0.9 million for a twelve month period.
Other Financial Instruments
As of December 31, 2013, 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 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, 2013, 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-47 of this Form 10-K/A.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
59
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, 2013, the end of the period covered by this report. Based on that evaluation,
the Company’s management, including the Chairman and Chief Executive Officer, Chief Financial Officer, and Chief Accounting
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 Chairman, Acting Chief Executive Officer, Chief Financial Officer and Chief Accounting 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, 2013
that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
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 Chairman and Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, the
Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in
1992 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 1992 Internal Control-Integrated Framework, the Company’s
management concluded that its internal control over financial reporting was effective as of December 31, 2013.
Grant Thornton LLP, the independent registered public accounting firm that audited our consolidated financial statements
included in this Form 10-K/A, has audited the effectiveness of our internal control over financial reporting as of December 31,
2013, as stated in their report which is included herein.
60
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, 2013, based on criteria established in 1992 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, 2013, based on criteria established in 1992 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, 2013, and our report dated March
28, 2014 expressed an unqualified opinion on those financial statements.
/s/ GRANT THORNTON LLP
Houston, Texas
March 28, 2014
61
Item 9B. Other Information
None
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 2013 Annual Meeting of Stockholders (the “Proxy Statement”)
under the headings “Election of Directors”, “Executive Compensation”, “Section 16(a) Beneficial Ownership Reporting
Compliance” and “Corporate Governance” 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, 2013.
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 heading “Certain
Relationships and Related Transactions, and Director Independence” 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 heading
“Principal Accountant Fees and Services” and is incorporated herein by reference.
62
GLOSSARY OF SELECTED TERMS
The following is a description of the meanings of some of the oil and gas industry terms used in this report.
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.
63
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.
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
64
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.
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-42 of this Form 10-K/A. 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/A. Where so indicated by a footnote, exhibits, which
were previously filed, are incorporated herein by reference.
Exhibit
Number
2.1
Description
Agreement and Plan of Merger, among Contango Oil & Gas Company, Contango Acquisition, Inc. and Crimson
Exploration Inc., dated as of April 29, 2013. (26)
3.1 Certificate of Incorporation of Contango Oil & Gas Company. (5)
3.2 Second Amended and Restated Bylaws of Contango Oil & Gas Company. (16)
3.3 Amendment to the Certificate of Incorporation of Contango Oil & Gas Company. (8)
4.1 Facsimile of common stock certificate of Contango Oil & Gas Company. (1)
4.2
Registration Rights Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, OCM
Crimson Holdings, LLC and OCM GW Holdings, LLC. (26)
10.1
10.2
10.3
10.4
10.5
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. (19)
65
10.6
10.7
Purchase and Sale Agreement between Juneau Exploration, L.P. and Contango Operators, Inc. dated October 1,
2010. (20)
Purchase and Sale Agreement between Conterra Company as Seller, and Patara Oil & Gas LLC as Purchaser,
dated April 22, 2011. (21)
10.8 Limited Liability Company Agreement of Republic Exploration LLC dated August 24, 2000. (10)
10.9
Amendment to Limited Liability Company Agreement and Additional Agreements of Republic Exploration LLC
dated as of September 1, 2005. (10)
10.10 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
10.11
Exploration LLC dated as of September 1, 2005. (10)
10.12
10.13
10.14
10.15
10.16
10.17
10.18
10.19
10.20
10.21
10.22
10.23
10.24
10.25
10.26
10.27
10.28
10.29
10.30
10.31
10.32
10.33
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)
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)
66
10.34
10.35
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 (30)
10.37 * Contango Oil & Gas Company 2009 Equity Compensation Plan. (22)
10.38
Conterra Joint Venture Development Agreement effective October 1, 2009 between Conterra Company and
Patara Oil & Gas LLC. (18)
10.39
10.40
10.41
10.42
10.43
10.44
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
First Amended and Restated Limited Liability Company Agreement dated as of March 31, 2012. (23)
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. (25)
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. (25)
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. (25)
Participation Agreement covering OCS-G 33596, Vermilion 170, dated as of July 1, 2010 between Republic
Exploration LLC and Contango Operators, Inc. (25)
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. (25)
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. (25)
Participation Agreement covering OCS-G 22738, South Timbalier 75, dated as of July 26, 2011 between
Republic Exploration LLC and Contango Operators, Inc. (25)
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. (25)
Participation Agreement covering Tuscaloosa Marine Shale, dated as of August 27, 2012 between Juneau
Exploration LP and Contango Operators, Inc. (25)
Letter Agreement dated as of June 8, 2012 between Juneau Exploration LP and Contango Operators, Inc. (25)
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. (25)
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. (25)
Agreement to Purchase Overriding Royalty Interest, dated March 1, 2010 between Contango Offshore
Exploration LLC and Juneau Exploration LP. (25)
Employment Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company and Allan D. Keel.
(26)
Employment Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company and E. Joseph
Grady. (26)
First Right of Refusal Agreement between Contango Oil & Gas Company and Juneau Exploration, L.P., entered
into as of January 1, 2013. (27)
Advisory Agreement between Contaro Company and Juneau Exploration, L.P., entered into as of January 1,
2013. (27)
Employment Agreement, dated as of June 10, 2013, among Contango Oil & Gas Company and Jeffrey A.
Sikora. (28)
Employment Agreement, dated as of June 7, 2013, among Contango Oil & Gas Company and A. Carl Isaac. (28)
Employment Agreement, dated as of June 7, 2013, among Contango Oil & Gas Company and John A. Thomas.
(28)
Employment Agreement, dated as of June 7, 2013, among Contango Oil & Gas Company and Jay S. Mengle.
(28)
Employment Agreement, dated as of June 7, 2013, among Contango Oil & Gas Company and Thomas H.
Atkins. (28)
67
10.62
10.63
10.64
10.65
Transition Agreement, dated as of June 10, 2013, between Contango Oil & Gas Company and Marc Duncan.
(29)
Participation Agreement covering Central Gulf of Mexico Lease Sale 227, dated as of March 21, 2013 between
Republic Exploration LLC and Contango Operators, Inc. (24)
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. (24)
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. (30)
10.66 * Contango Oil & Gas Company Director Compensation Plan †
14.1 Code of Ethics. (31)
21.1 List of Subsidiaries. †
21.2 Organizational Chart. †
23.1 ** Consent of William M. Cobb & Associates, Inc.
23.2 ** Consent of Netherland, Sewell & Associates, Inc.
23.3 ** Consent of Lonquist & Co. LLC.
23.4 ** Consent of W.D. Von Gonten & Co.
23.5 ** Consent of Grant Thornton LLP.
31.1
31.2
32.1
32.2
**
**
**
**
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.
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.
99.1 Report of William M. Cobb & Associates, Inc. †
99.2
Report of Netherland, Sewell & Associates. †
99.3
Report of W.D. Von Gonten and Company †
Filed with Original Filing
Indicates a management contract or compensatory plan or arrangement.
†
*
**
Filed herewith
1.
2.
3.
4.
5.
6.
7.
8.
9.
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.
Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2003, as
filed with the Securities and Exchange Commission on September 22, 2003.
68
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
22.
23.
24.
25.
26.
27.
28.
29.
30
31
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.
Reserved
Reserved
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.
Filed as an exhibit to the Company’s report on Form 8-K, dated March 19, 2014, as filed with the Securities and
Exchange Commission on March 21, 2014.
Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended March 31, 2009, as filed with
the Securities and Exchange Commission on May 11, 2009.
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 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 10-K for the fiscal year ended June 30, 2010, as filed with
the Securities and Exchange Commission on September 13, 2010.
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.
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
69
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on
SIGNATURES
its behalf by the undersigned, thereunto duly authorized.
CONTANGO OIL & GAS COMPANY
/s/ ALLAN D. KEEL
Allan D. Keel
Chief Executive Officer
(principal executive officer)
/s/ E. JOSEPH GRADY
E. Joseph Grady
Chief Financial Officer
(principal financial officer)
/s/ YAROSLAVA MAKALSKAYA
Yaroslava Makalskaya
Chief Accounting Officer
(principal accounting officer)
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.
Name
Title
Date
/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
March 28, 2014
March 28, 2014
March 28, 2014
Director
March 28, 2014
Director
March 28, 2014
Director
March 28, 2014
70
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 Statement of Shareholders’ Equity
Consolidated Statements of Cash Flows
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-39
F-43
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, 2013 and 2012, and the related consolidated statements of
operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2013. 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, 2013 and 2012, and the results of their operations
and their cash flows for each of the three years in the period ended December 31, 2013 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, 2013, based on criteria established in 1992
Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO) and our report dated March 28, 2014 expressed an unqualified opinion.
/s/ GRANT THORNTON LLP
Houston, Texas
March 28, 2014
F-2
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except shares)
CURRENT ASSETS:
Cash and cash equivalents
Accounts receivable, net
Prepaid expenses
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
NON-CURRENT ASSETS:
Investment in affiliates
Other
Total non-current assets
TOTAL ASSETS
CURRENT LIABILITIES:
Accounts payable and accrued liabilities
Current derivative liability
Current asset retirement obligation
Total current liabilities
NON-CURRENT LIABILITIES:
Long-term debt
Deferred tax liability
Asset retirement obligation
Total non-current liabilities
Total liabilities
COMMITMENTS AND CONTINGENCIES (NOTE 14)
SHAREHOLDERS’ EQUITY:
Common stock, $0.04 par value, 50 million shares authorized,
24,356,236 shares issued and 19,363,711 shares outstanding at December 31, 2013,
20,135,107 shares issued and 15,194,952 shares outstanding at December 31, 2012
Additional paid-in capital
Treasury stock at cost (4,992,525 shares at December 31, 2013 and 4,940,155 shares at
December 31, 2012)
Retained earnings
Total shareholders’ equity
December 31,
2013
2012
$
— $
79,487
60,613
48,850
2,031
2,147
1,326
2,479
2,757
—
66,117
133,573
1,001,361
49,443
900
554,967
22,661
227
(260,681)
(197,874)
791,023
379,981
50,901
2,263
53,164
$
910,304
$
47,327
225
47,552
561,106
$
96,833
$
32,672
1,131
1,315
99,279
90,000
105,956
22,019
217,975
317,254
—
—
32,672
—
115,858
8,647
124,505
157,177
962
228,644
805
79,025
(119,180)
(117,163)
482,624
593,050
441,262
403,929
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
$
910,304
$
561,106
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:
Crude oil and condensate sales
Natural gas sales
Natural gas liquids sales
Total revenues
EXPENSES:
Lease operating expenses
Production and ad valorem taxes
Exploration expenses
Depreciation, depletion and amortization
Impairment of oil and gas properties
General and administrative expense
Total expenses
OTHER INCOME (EXPENSE):
Gain from investment in affiliates (net of income taxes)
Gain (loss) from sale of assets and return on investments
Interest income/(expense)
Net loss on derivatives
Total other income/(expense)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
Provision for income taxes
NET INCOME (LOSS) FROM CONTINUING OPERATIONS
DISCONTINUED OPERATIONS, NET OF INCOME TAX (NOTE 18)
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 COMMON SHARES OUTSTANDING:
Basic
Diluted
Year Ended December 31,
2013
2012
2011
$
59,608
$
56,237
$
79,289
25,224
60,691
28,940
67,594
94,666
36,238
164,121
145,868
198,498
32,091
4,693
1,811
65,529
776
26,512
131,412
2,310
31,785
(1,171)
(1,132)
31,792
64,501
(23,139)
41,362
—
20,118
3,602
51,903
44,896
14,079
11,265
145,863
60
(463)
96
—
(307)
(302)
(605)
(907)
(29)
23,745
4,540
—
48,988
1,680
10,614
89,567
—
4
(205)
—
(201)
108,730
(38,821)
69,909
(1,204)
$
41,362
$
(936) $
68,705
$
$
$
$
2.56
—
2.56
2.56
—
2.56
$
$
$
$
(0.06) $
0.00
(0.06) $
(0.06) $
0.00
(0.06) $
4.49
(0.08)
4.41
4.49
(0.08)
4.41
16,156
16,158
15,295
15,295
15,582
15,585
The accompanying notes are an integral part of these consolidated financial statements.
F-4
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
(in thousands)
Balance at December 31, 2010
15,665
$
805
$
79,279
$
(91,789) $
404,003
$
392,298
Common Stock
Shares
Amount
Additional
Paid-in
Capital
Treasury
Stock
Retained
Earnings
Total
Shareholders’
Equity
Treasury shares at cost
Net income
(308)
—
—
—
—
—
(17,000)
—
—
68,705
(17,000)
68,705
Balance at December 31, 2011
15,357
$
805
$
79,279
$
(108,789) $
472,708
$
444,003
Tax benefit from exercise of stock options
Treasury shares at cost
Dividends
Net loss
—
(162)
—
—
—
—
—
—
(254)
—
—
—
—
(8,374)
—
—
— $
—
(30,510)
(936)
(254)
(8,374)
(30,510)
(936)
Balance at December 31, 2012
15,195
$
805
$
79,025
$
(117,163) $
441,262
$
403,929
Acquisition of Crimson
Exercise of stock options
Treasury shares at cost
Stock-based compensation
Net income
3,864
154
146,414
1
(52)
356
—
3
—
—
—
26
—
3,179
—
—
—
(2,017)
—
—
—
—
—
—
41,362
146,568
29
(2,017)
3,179
41,362
Balance at December 31, 2013
19,364
$
962
$
228,644
$
(119,180) $
482,624
$
593,050
The accompanying notes are an integral part of these consolidated financial statements.
F-5
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
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:
Year Ended December 31,
2013
2012
2011
$
$
41,362
—
41,362
(907) $
(29)
(936)
69,909
(1,204)
68,705
Depreciation, depletion and amortization
Impairment of natural gas and oil properties
Exploration expenses
Deferred income taxes
Loss (gain) on sale of assets
Loss (gain) from investment in affiliates
Stock-based compensation
Tax benefit from exercise of stock options
Unrealized loss on derivative instruments
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable and other
Decrease (increase) in inventory
Decrease (increase) in prepaids and other receivables
Increase (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
Sale of oil and gas properties
Advance under note receivable
Repayment of note receivable
Investments in affiliates
Distributions from affiliates
Additions to furniture and equipment
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility
Repayments under credit facility
Payment of long-term debt
Dividends
Purchase of common stock
Proceeds from exercise of stock options
Tax benefit from exercise/cancellation of stock options
Debt issuance costs
Net cash used in financing activities
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD
65,529
767
(9)
13,159
(21,961)
(3,554)
3,180
—
1,410
(6,285)
610
30
(4,720)
3,569
11,778
172
105,037
(62,208)
20,000
—
—
(15,397)
23,154
(344)
(34,795)
180,394
(90,394)
(235,373)
—
(2,017)
31
—
(2,370)
(149,729)
(79,487)
79,487
CASH AND CASH EQUIVALENTS, END OF PERIOD
$
— $
44,896
14,078
51,379
(8,569)
—
(92)
(154)
(254)
—
19,894
(2,497)
(347)
(10,918)
(877)
(15,117)
(364)
90,122
(78,536)
—
(500)
900
(54,765)
8,969
(13)
(123,945)
—
—
—
(30,510)
(8,374)
—
254
—
(38,630)
52,398
3,240
(477)
(6,382)
1,094
—
179
—
—
(2,789)
470
2,828
583
(958)
9,204
5
128,100
(40,229)
38,671
(400)
—
(499)
—
(101)
(2,558)
—
—
—
—
(17,000)
—
—
(37)
(17,037)
(72,453)
151,940
79,487
$
108,505
43,435
151,940
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 natural gas and oil company. The Company’s business is to explore, develop, produce and acquire natural gas
and oil properties in the shallow waters of the Gulf of Mexico ("GOM") and in the Gulf Coast region of the United States and
Colorado.
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,
each share of Crimson common stock was converted into the right to receive 0.08288 shares of common stock of Contango. As
a result, 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. See Note 4 - "Merger with Crimson Exploration,
Inc." for additional information.
Contango has historically focused its operations offshore in the Gulf of Mexico ("GOM") in water-depths of less than
300 feet, but the Merger has given the Company access to lower risk, long life resource plays in Southeast Texas (the Woodbine
oil and liquids rich play), South Texas (the Eagle Ford Shale and Buda oil and liquids rich plays), and East Texas (the James Lime
liquids rich play and, under an improved natural gas price environment, the Haynesville/Mid-Bossier gas play). The Company
believes these plays provide significant long-term growth potential from multiple formations.
The Company intends to grow reserves and production by developing its existing producing property base, by exploiting
its oil/liquids resource potential, by drilling in the GOM, and by pursuing opportunistic acquisitions in areas where the Company
has current operations and specific operating expertise, as well as additional areas the Company identifies that they have significant
exploration and/or operational upside. The Company has developed a significant inventory of high quality drilling opportunities
on its existing property base that should provide multi-year reserve growth, and until improvement is seen in natural gas prices,
we will concentrate drilling activity on further developing the oil and liquids-rich onshore assets in Southeast Texas and South
Texas, complemented by some potentially high-impact offshore exploratory drilling. In 2014 specifically, the Company will focus
on its inventory of crude oil and liquids-rich projects with a continuous rig targeting each of the Woodbine in Madison and Grimes
counties, Texas, the Buda in Dimmit County, Texas, and the James Lime in San Augustine County, Texas. The Company also
plans to drill a number of other wells testing new formations in existing areas and one to two exploratory wells in the shallow
waters of the Gulf of Mexico. Contango has additional onshore investments in i) Alta Resources Investments, LLC, whose primary
area of focus is the liquids-rich Kaybob Duvernay in Alberta, Canada, which was sold in August 2013; ii) Exaro Energy III LLC
("Exaro"), which is primarily focused on the development of proved natural gas reserves in the Jonah Field in Wyoming; and iii)
the Tuscaloosa Marine Shale ("TMS"), where the Company owns approximately 29,000 net acres.
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, 2013 and 2012 and for the three years ended December 31, 2013 contained herein, include
consolidated results of operations of both Contango Oil and Gas Company ("Contango") and Crimson for the period from the
closing date of the Merger to December 31, 2013 and only consolidated financial statements of Contango for all other the periods
presented herein.
Financial statements as of December 31, 2013 and 2012 and for the three years ended December 31, 2013 include
consolidated results of operations of both Contango and Crimson for the period from the closing of the Merger on October 1, 2013
to December 31, 2013 and consolidated financial statements of Contango only for all other periods.
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. As a result of this change, on March 3, 2014
F-7
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
we filed a Transition Report on Form 10-K for the six-month period ended December 31, 2013. This Annual Report on Form 10-
K/A is filed to present a recast of historical financial information for the three-year period ending on December 31, 2013.
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 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 Gain (loss) from sale of assets and return on investments line item in the
Company's income statement and in the investing cash flows in the Company's Cash Flow Statement 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 our investment in Exaro, while a net loss or
payment of dividends decreases our investment. In our consolidated statement of operations, our proportionate share of Exaro's
net income or loss is reported as a single line-item in Gain (loss) 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
gas reserves for a given property, the Company records a liability. As of December 31, 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, 2013, 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, 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.
There were no outstanding checks that had not been presented for payment included in accounts payable at December 31, 2012.
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.
F-8
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Accounts receivable allowance for bad debt was $0.6 million and zero, as of December 31, 2013 and 2012, respectively.
At December 31, 2013 and 2012 the carrying value of the Company’s accounts receivable approximated fair value.
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 and 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 and operating costs and anticipated
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. No impairment of proved properties was recognized during the years ended December 31, 2013 or 2011.
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 our 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 impairment of the carrying value, and any such
impairment is charged to expense in the period. The Company did not recognize any impairment of unproved properties for the
year ended December 31, 2012. For the year ended December 31, 2013, we recorded an impairment expense on unproved properties
of $0.6 million related to leasehold costs on our Ship Shoal 83 prospect which we relinquished in August 2013, and $0.2 million
related to leasehold costs on our Brazos Area 543 prospect. For the year ended December 31, 2011, we recorded impairment
expense on unproved properties of approximately $1.7 million, related to the relinquishment of 14 unproved lease blocks owned
by Republic Exploration, LLC ("REX") and Contango.
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.
F-9
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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, 2013. The amount of unrecognized tax benefits
did not materially change from December 31, 2012. The amount of unrecognized tax benefits may change in the next twelve
months; however, we do not expect the change to have a significant impact on our 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 2009 – 2013, and state tax returns for 2008 - 2013, 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 credit line with amortization expense included in Depreciation, Depletion and Amortization line item in the Company's
income statement for the year ended December 31, 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 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
F-10
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
asset or liability measured at fair value. 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 "Net loss on derivatives" on
the consolidated statements of operations for the year ended December 31, 2013. The Company did not have any derivative
instruments or hedging activities for the year ending December 31, 2012 or 2011. 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.
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 and 2011 in order to conform to the presentation for the
year ended December 31, 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 our 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 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 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 will implement any changes required by the new COSO framework during the year ended December 31, 2014.
Currently we are evaluating the provisions of the revised framework and continue to assess the impact, if any, it may have on our
internal control structure.
In February 2013, the Financial Accounting Standards Board (“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. We are currently evaluating the provisions of this accounting update and assessing the impact,
if any, it may have on our 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 2014 and
F-11
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
beyond, including, but not limited to, standards relating to revenue recognition, 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, at this time 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 our natural
gas, oil and natural gas liquids for the year ended December 31, 2013 were ConocoPhillips Company (48%), Shell Trading US
Company (16%), Sunoco Inc (9%), Enterprise Products Operating LLC (7%), and ExxonMobil Oil Corp. (7%). Our sales to these
companies are not secured with letters of credit and in the event of non-payment, we could lose up to two months of revenues.
The loss of two months of revenues would have a material adverse effect on our financial position. There are numerous other
potential purchasers of our 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 the right to receive 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.
Upon consummation of the Merger, the newly constituted board of directors of the Company consisted of Joseph J.
Romano, Allan D. Keel, B.A. Berilgen, B. James Ford, Brad Juneau, Ellis L. McCain, Charles M. Reimer, and Steven L. Schoonover.
The board of directors has appointed Allan D. Keel as President and Chief Executive Officer and E. Joseph Grady as Senior Vice
President and Chief Financial Officer of the Company. Joseph J. Romano remains as Chairman of the Board. Messrs. Keel, Grady
and certain other employees of Crimson entered into employment agreements with the Company that became effective upon the
consummation of the Merger. The combined company has its headquarters and principal corporate office in Houston, Texas.
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.
F-12
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The following table summarizes the consideration transferred and preliminary estimates of 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
10,450
305,947
452,521
13,492
24,905
413,916
208
452,521
—
$
$
$
$
$
$
$
$
Estimates of the fair value of assets acquired and liabilities assumed are preliminary and based on information currently
available. The fair value estimate of certain of Crimson's assets and liabilities, including asset retirement obligations and current
and deferred tax balances, cannot be currently finalized due to information not being available to the Company. The Company
expects to be able to obtain the necessary information to finalize the valuation of assets acquired and liabilities assumed by the
end of the second quarter of 2014.
In accordance with the Merger Agreement, Contango issued 0.08288 shares for each of the common shares of Crimson.
Additionally, as a result of the merger, all restricted shares of Crimson previously issued to its directors and employees were
exchanged for shares of Contango’s common stock using the same conversion factor.
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.
The purchase price is 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
F-13
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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 our 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 $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 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
F-14
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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, $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, we 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. Preliminary estimated adjustments of approximately $3.8 million reduced the purchase price
to a total of $15.0 million, net to the Company. The purchase price adjustment is expected to be finalized in the first quarter of
2014.
Southeast Texas Disposition
On December 31, 2013, the Company sold to an independent third party approximately 7.1% of its interest in all developed
and undeveloped properties in Madison and Grimes Counties. The total sales price of $20 million is 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. Preliminary estimated adjustment to the sales price of approximately $0.4 million increased the total proceeds from
sales of these properties and is expected to be finalized in the first quarter of 2014. A gain of approximately $6.6 million related
to this sale was recognized in the year ended December 31, 2013.
Proceeds from Alta
In August 2013, Alta sold its interest in the liquids-rich Kaybob Duvernay, which closed in October 2013. Proceeds from
the sale are expected to be 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 in February 2014. The total distributions from Alta are expected to exceed
our 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,
F-15
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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):
Derivatives
Commodity price contracts - assets
Commodity price contracts - liabilities
Total
Carrying
Value
Fair Value Measurements Using
Level 1
Level 2
Level 3
$
$
76
$
(1,207) $
— $
— $
76
$
(1,207) $
—
—
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 "Net loss on derivatives" 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.
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 facilities 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 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 compare 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 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
F-16
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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, 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. The Company generally hedges a substantial,
but varying, portion of anticipated oil and natural gas production for future periods. We believe that these derivative arrangements,
although not free of risk, allow 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, because our derivative arrangements apply only to a portion of our production and provide only partial
protection against declines in commodity prices. Such arrangements may expose us to risk of financial loss in certain
circumstances. We continuously reevaluate our hedging programs in light of changes in production, market conditions, and
commodity price forecasts.
As of December 31, 2013, the Company's crude oil and natural gas derivative positions consisted of swaps and costless
put/call "collars". 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.
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 current
derivative contracts are 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 "Net gain
(loss) on derivatives" on the consolidated statements of operations. See Note 6 - Fair Value Measurements for additional information.
The following derivative contracts were in place at December 31, 2013, (fair value in thousands):
Commodity
Period
Derivative
Volume/Month (1)
Price/Unit (2)
Fair Value
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Jan 2014-Dec 2014
Jan 2014-Jun 2014
Jan 2014-Dec 2014
Jan 2014-Mar 2014
Apr 2014-May 2014
Jun 2014-Sep 2014
Oct 2014-Dec 2014
Jan 2014-May 2014
Jun 2014-Dec 2014
Jan 2014-Dec 2014
Jan 2014-Dec 2014
Swap
Swap
Swap
Swap
Swap
Swap
Swap
Collar
Collar
Collar
Collar
7,500 Bbls
2,000 Bbls
6,000 Bbls
40,000 Bbls
32,000 Bbls
13,000 Bbls
11,000 Bbls
$
$102.10 (4)
$108.07 (4)
$106.40 (4)
$97.00 (3)
$95.17 (3)
$93.22 (3)
$90.61 (3)
1,000,000 MMBtu
$4.00 - $4.425 (5)
120,000 MMBtu
$4.00 - $4.415 (5)
42,500 MMBtu
$3.75 - $4.60 (5)
42,500 MMBtu
$3.50 - $5.00 (5)
(558)
(21)
(139)
(171)
(142)
(91)
(60)
68
7
(14)
(10)
Total net fair value of derivative instruments $
(1,131)
(1) Average volume per month for the remaining contract term
F-17
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(2) Average price per unit for the remaining contract term
(3) Commodity derivative based on NYMEX West Texas Intermediate crude oil prices
(4) Commodity derivative based on Brent crude oil prices
(5) Commodity derivative based on Henry Hub NYMEX natural gas prices
There was no activity or outstanding derivative contracts during the year ended December 31, 2012 or 2011.
The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December
31, 2013 (in thousands):
Gross
December 31, 2013
Netting (1)
Total
Assets
Liabilities
$
$
76
(1,207)
$
$
(76)
76
$
$
—
(1,131)
(1) Represents counterparty netting under agreements governing such derivatives
The following table summarizes the effect of derivative contracts on the Consolidated Statements of Operations for the
year ended December 31, 2013 (in thousands):
Contract Type
Crude oil contracts
Natural gas contracts
Realized gain
Crude oil contracts
Natural gas contracts
Unrealized loss
Net loss on derivatives
Year ended
December 31,
2013
$
$
$
$
$
180
98
278
(1,179)
(231)
(1,410)
(1,132)
There were no gains or losses related to derivative instruments for the years ended December 31, 2012 or 2011.
8. Stock Based Compensation
As of December 31, 2013, 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 original 2009 Equity 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.
2009 Equity Compensation Plan
The 2009 Plan was adopted by the Company’s Board of Directors (the “Board”) on September 15, 2009. Under the 2009 Plan,
the Board may grant restricted stock and option awards 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 original terms of the 2009 Plan, the Company may issue up to 1,500,000 shares of common stock or stock options
with 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.
F-18
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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 for in the restricted stock
agreement, with the vested balance released to the officers.
As of December 31, 2013, the Company had approximately 1.2 million shares of common stock and stock options available
for future grant under the 2009 Plan.
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 quarter 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 next four years. Additionally, 791 stock options were exercised
and sold in the open market, leaving 135,107 stock options vested and exercisable at December 31, 2013. The converted exercise price
for such options range from $25.70 to $60.33 per share, with an average remaining contractual life of seven years. As of December 31,
2013, there were 11 shares of common stock or stock options available to be granted under the 2005 Plan.
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.
1999 Stock Incentive Plan
The Company’s 1999 Stock Incentive Plan (the “1999 Plan”) expired in August 2009. There were no outstanding options issued
under the 1999 Plan as of December 31, 2013.
Stock Options
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,
2013, 2012, and 2011 is presented in the table below (dollars in thousands, except per share data):
2013
Year Ended December 31,
2012
2011
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
Options assumed due to Merger
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
—
135,898
$
(791) $
—
135,107
$
—
52.90
36.16
53.00
45,000
$
— $
— $
(45,000) $
— $
54.21
—
—
54.21
—
45,000
$
— $
— $
— $
$
45,000
54.21
—
—
—
54.21
$
53.00
$
$
$
—
— $
—
1,475,000
—
$
179
45,000
$
179
1,475,000
$
54.21
—
$
—
$
459
135,107
$
459
1,162,173
$
—
F-19
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(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 years
ended December 31, 2013 and 2011, there were 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. 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. In November 2010, the Company’s Board of Directors approved the immediate vesting of all outstanding stock
options under both the 1999 Plan and the 2009 Plan. Additionally, the Board authorized management to net-settle any outstanding stock
options in cash. The option holder had a choice of receiving cash upon net settlement of options or to settle options for shares of the
Company. Such modification of the stock options resulted in recognizing a liability equal to the portion of each award attributable to
past service multiplied by the modified awards fair value, and was adjusted quarterly. The accelerated vesting and modification affected
no other terms or conditions of the options, including the number of outstanding options or exercise price.
During the years ended December 31, 2013 and 2011, the Company recognized stock option expense of approximately zero
and $179,000, respectively. 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, 2013 and 2012 was approximately $7,721 and $0.5 million, respectively.
Restricted Stock
The Company did not grant any shares of restricted stock for the years ended December 31, 2012 or 2011 and did not have
any restricted shares outstanding as of December 31, 2012.
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 compensation
pursuant to our new director compensation plan which vest on the one-year anniversary of the date of grant. The weighted average fair
value of the of the restricted shares granted during the quarter, was $44.10 with a total fair value of approximately $8.1 million after
adjustment for estimated weighted average forfeiture rate of 5.7%.
Restricted stock activity as of December 31, 2013 and for the year then ended is presented in the table below (dollars in
thousands, except per share data):
Outstanding, beginning of the period
Granted
Vested
Canceled / Forfeited
Not vested, end of the period
Vested, end of the period
Expected to vest, end of the period
Weighted
Average
Fair Value
Aggregate
Intrinsic
Value
Restricted
Shares
—
356,299
$
44.10
$
(63,667)
—
292,632
—
260,359
42.80
—
44.38
—
44.36
$0
15,723
2,725
—
13,830
—
12,305
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 $11.1 million of compensation expense will
be recognized over the remaining vesting period.
During the first quarter of 2014, the Company issued 3,700 restricted shares to employees under the 2009 Plan, with 1,158,473
shares remaining available for grant under the 2009 Plan as of February 28, 2013.
F-20
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Incentive Compensation Plans effective January 1, 2014
Beginning in 2014 the Company will provide performance-based long-term bonus plans for the benefit of all employees - the
Cash Incentive Bonus Plan (“CIBP”) and the Long-Term Incentive Plan (“LTIP”). Both plans, and specific targeted performance
measures under those plans, will be approved by the Compensation Committee and the Board. Upon achieving the performance levels
established each year, bonus awards will be calculated as a percentage of base salary of each employee for the plan year. The plan
awards for each year are disbursed in the first quarter of the following year. Employees must be employed by the Company at the time
that final plan awards are disbursed to be eligible.
The CIBP awards will be paid in cash. The LTIP bonus awards can be paid in restricted common stock and/or stock options.
The stock awards and options are expected to vest 25% per year, over the first through fourth anniversaries from the date of grant. The
number of shares of restricted common stock and the number of shares underlying the stock options granted as Stock Awards will be
determined based upon the fair market value of the common stock on the date of the grant. The stock awards to be granted pursuant to
the LTIP will be granted under the 2009 Plan.
9. Share Repurchase Programs
$100 Million Share Repurchase Program
In September 2008, the Company’s board of directors approved a $100 million share repurchase program which concluded
in October 2011. Under this share repurchase program, the Company purchased a total of 2,157,278 shares of common stock at
an average price of $46.35 per share. All shares were purchased in the open market or through privately negotiated transactions.
The purchases were made subject to market conditions and certain volume, pricing and timing restrictions to minimize the impact
of the purchases upon the market, and when we believed the Company's 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.
$50 Million Share Repurchase Program
In September 2011, the Company’s board of directors approved a $50 million share repurchase program, effective upon
completion of purchases under the Company’s $100 million share repurchase program. The purchases made under the $50 million
share repurchase program are subject to the same terms and conditions as purchases made under the $100 million share repurchase
program. 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, under the $50 million share repurchase program.
As of December 31, 2013, the Company had invested $10.8 million in this share repurchase program to purchase 197,877
shares and net-settle 45,000 stock options from two officers, leaving $39.2 million available for future purchases.
As of December 31, 2013, under both share repurchase programs combined, the Company has purchased approximately
2.4 million shares of its common stock at an average cost per share of $46.84 and 45,000 stock options from two employees for
$465,000, for a total of approximately $110.8 million.
Under the terms of our revolving credit facility with Royal Bank of Canada entered into on October 1, 2013, share
repurchases are limited to $1 million per calendar year, and may only be purchased from officers, directors, employees and
consultants upon their death, disability, retirement or termination, in accordance with any termination agreement or employment
agreement.
F-21
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):
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:
Prepaid insurance
Prepaid capital costs
Prepaid vendors
Other prepaid expenses
Total Prepaid Expenses
Accounts Payable and Accrued Liabilities:
Royalties and revenue payable
Accrued exploration and development
Trade payable
Advances from partners
Accrued bonus and severance
Accrued general and administrative expenses
Accrued lease operating and workover expense
Taxes payable
Other accounts payable and accrued liabilities
December 31,
2013
2012
$
42,196
$
28,091
$
$
$
$
7,358
5,172
4,293
2,172
(578)
—
3,848
16,177
734
—
60,613
$
48,850
1,113
$
108
486
324
396
1,727
—
356
2,031
$
2,479
44,933
$
22,281
17,803
11,589
6,538
7,273
3,599
3,529
236
1,333
1,208
4,335
—
949
1,279
2,608
—
12
Total Accounts Payable and Accrued Liabilities
$
96,833
$
32,672
F-22
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Included in the table below is supplemental information about non-cash transactions related to the Merger during the
year ended December 31, 2013, in thousands:
Cash payments:
Interest payments
Income tax payments
Non-cash items excluded from investing activities in the
consolidated statements of cash flows:
Years Ended December 31,
2013
2012
2011
$
1,056
$
71
$
49
341
24,307
29,961
Increase (decrease) in accrued capital expenditures
7,004
1,192
(2,315)
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
12,955
639
413,916
24,940
(60,110)
(256)
(235,373)
(11,183)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Non-cash items excluded from financing activities in the
consolidated statements of cash flows:
Issuance of common stock in connection with the merger
145,870
—
—
F-23
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 partners was
approximately $183 million. As of December 31, 2013, the Company had invested approximately $46.9 million, including $13.1
million during the year ended December 31, 2013.
The following table presents condensed balance sheet data for Exaro as of December 31, 2013 and December 31, 2012.
The balance sheet data was derived from the Exaro balance sheet as of December 31, 2013 and December 31, 2012 and was not
adjusted to represent our percentage of ownership interest in Exaro. Our share in the equity of Exaro at December 31, 2013 was
approximately $50.5 million.
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
Member's equity
Total liabilities & member's equity
December 31,
2013
2012
30,284
$
14,377
182,226
8,732
1,103
192,061
222,345
$
$
55,709
40,014
4,886
100,609
114,986
13,717
$
17,674
70,000
923
70,923
$
137,705
222,345
$
8,000
297
8,297
89,015
114,986
$
$
$
$
$
$
The following table presents the condensed results of operations for Exaro for the year ended December 31, 2013 and
for the period from the inception of Exaro, March 19, 2012, to December 31, 2012. The results of operations for the year ended
December 31, 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 our 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, 2013 and 2012 was 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.
F-24
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Year ended
December 31, 2013
Period from
inception to
December 31, 2012
Oil and natural gas sales
$
52,698
$
Other loss
Less:
Lease operating expenses
Depreciation, depletion, amortization &
accretion
General & administrative expense
(544)
16,136
16,058
3,294
Income/(loss) from continuing operations
Net interest income/(expense)
Net income (loss)
$
$
16,666
(3,536)
13,130
$
$
7,514
(3,269)
2,035
2,350
2,872
(3,012)
25
(2,987)
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 company
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, 2013 and 2012 were as follows (in thousands):
Year ended December 31,
2013
2012
Balance as of the beginning of the period
Liabilities incurred during period
Liabilities settled during period
Accretion
Change in estimate
Balance as of the end of the period
$
$
8,678
$
14,145
(207)
660
58
23,334
$
8,704
2,005
(2,037)
478
(472)
8,678
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 Return on Investments."
13. Long-Term Debt
RBC Credit Facility
In connection with the Merger, 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.
F-25
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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. 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, (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, 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, 2013 borrowing availability under the RBC Credit Facility was $183.1 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 year ended
December 31, 2013 was approximately $1.2 million.
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,
2013, we were 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 of 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
our 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, 2012
and 2011 was approximately $37,000, $50,000, and $133,000, respectively.
As of December 31, 2013 and 2012, the Company had the following debt balances (in thousands):
RBC Credit Facility (weighted average interest rate in effect at December 31, 2013 was 2.1875%)
90,000
Total long-term debt
$
90,000
$
—
—
December 31,
2013
2012
This $90 million balance is due by October 1, 2017.
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, we moved our corporate offices to 717 Texas Avenue in downtown Houston, Texas, under a lease that expires
March 31, 2019. We remain responsible for the rent at our previous corporate office at 3700 Buffalo Speedway in Houston, Texas,
through February 29, 2016, however, 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.
F-26
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
As of December 31, 2013, minimum future lease payments for delay rentals and operating leases for our fiscal years
are as follows (in thousands):
Fiscal years ending December 31,
2014
2015
2016
2017
2018
2019 and thereafter
Total
$
4,503
2,103
1,595
1,378
1,109
269
$
10,957
The amount incurred under operating leases and delay rentals during the years ended December 31, 2013, 2012, and 2011
were approximately $1.0 million, $0.5 million, $0.2 million, respectively. As of December 31, 2013, our 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. A portion of these bonuses
have already been paid, with the remainder to vest and be paid on June 30, 2014, to incentivize the individuals to remain with the
Company. As of December 31, 2013, approximately $230,000 of compensation remained to be vested, which will vest and be
paid on June 30, 2014, as long as the employees are employed by the Company on the vesting date.
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.
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. The damages most recently alleged by the plaintiffs are approximately $13.4 million. We and our
co-defendants are vigorously defending this lawsuit and believe that we have meritorious defenses. We and our co-defendants
obtained a favorable judgment from the trial court following a trial, but the judgment is being appealed by the plaintiffs. A
companion case involving the same claims, wells, etc. was filed in the same court on April 19, 2013 on behalf of additional mineral
interest owners.
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. The trial
court has granted the plaintiffs motion for partial summary judgment as to liability (but not damages). The Plaintiff recently
asserted damages of approximately $6.0 million, inclusive of interest but exclusive of legal fees which may be recoverable by the
plaintiff if it ultimately prevails in this case. We are vigorously defending this lawsuit, believe that we have meritorious defenses
and intend to appeal the aforementioned decision.
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 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
F-27
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
retained the disputed mineral interests thereunder. In their initial pleading the plaintiff alleges damages in excess of $6.0 million,
which is generally in line with amounts received on its undisputed 1/16th mineral interest as of the date the suit was filed. As of
January 2014, the Plaintiff had received approximately $8.5 million in royalties in respect of its undisputed interest. 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 have been brought by Crimson stockholders in Delaware
Chancery Court seeking damages and injunctive relief including, among other things, compensatory damages and costs and
disbursements relating to the lawsuits. Various combinations of the Company, certain subsidiaries of the Company, members of
Crimson’s pre-merger board of directors, members of Crimson’s pre-merger management team and Oaktree Capital Management
L.P. have been named as defendants in these lawsuits. The Delaware lawsuits have been consolidated into a single action referred
to as In Re: Crimson Exploration Inc. Stockholder Litigation; C.A. 8541-VCP. Additionally, on July 13, 2013, a separate and
similar complaint was filed in the District Court of Harris County Texas, in the matter of Fisichella Family Trust v. Crimson
Exploration Inc. It is possible that additional similar lawsuits may be filed.
The merger-related lawsuits allege, among other things, that Crimson’s board of directors failed to take steps to obtain a
fair price, failed to properly value Crimson, failed to protect against alleged conflicts of interest, failed to conduct a reasonably
informed evaluation of whether the transaction was in the best interests of stockholders, failed to fully disclose all material
information to stockholders, acted in bad faith and for improper motives, engaged in self-dealing, discouraged other strategic
alternatives, took steps to avoid competitive bidding, and agreed to allegedly unreasonable deal protection mechanisms, including
the no-shop, fiduciary-out provisions and termination fee. The lawsuits also allege that Contango and certain other defendants
aided and abetted the other defendants in violating duties to the Crimson stockholders. The known plaintiffs in these lawsuits
collectively owned a very small percentage of the total outstanding shares of Crimson common stock at the time of the Merger,
which was approved by Contango's pre-merger shareholders (89% of outstanding shares and 99% of voted shares were voted in
favor of the Merger) and Crimson's pre-merger shareholders (69% of outstanding shares and 88% of voted shares were voted in
favor of the Merger). The Company believes that these merger-related lawsuits are without merit and intends to contest them
vigorously.
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. The Company has maintained an officers and directors
liability insurance policy for Crimson former directors and officers and has made a claim under the policy for coverage of these
merger related lawsuits.
Employment Agreements
As a result of successfully completing the Merger, Mr. Joseph J. Romano, the Company's Chairman and former Chief
Executive Officer is entitled to receive a $4.0 million bonus payment. This payment is expected to paid 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 replace 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,
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, the executives are eligible to receive stock option awards,
restricted stock awards or a combination of both upon 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.
In addition, as of December 31, 2013, the Company had entered into employment agreements with two other employees,
which provide for a term of two years with automatic one-year extensions of the initial term, unless Contango or the employee
F-28
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
provides prior notice of intention not to extend the agreement. One employee is entitled to a base salary of $270,000 per year
while the other is entitled to a base salary of $250,000 per year, with minimum, target and maximum CIBP targets of 30%, 50%
and 75% for both, based on each employees' base salary. Minimum, target and maximum LTIP incentive equity plan targets for
both are 40%, 100%, and 200% of each employee's base salary.
Effective January 1, 2014, the Company entered into an employment agreement with another employee, which provides
for a term of two years with an automatic one-year extensions of the initial term, unless Contango or the employee provides prior
notice of intention not to extend the agreement. The employee's base salary is $250,000 per year, with minimum, target and
maximum CIBP targets of 30%, 50% and 75%; and minimum, target and maximum LTIP incentive equity plan targets of 40%,
100%, and 200% of the employee'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, 2013, 2012 and 2011 is presented below (in thousands, except per share amounts):
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
Basic Earnings per Share:
Income from continuing operations
Discontinued operations, net of income taxes
Net income attributable to common stock
Diluted Earnings per Share
Effect of potential dilutive securities:
Stock options, weighted average of incremental shares
Income from continuing operations
Discontinued operations, net of income taxes
Net income attributable to common stock
F-29
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)
0.00
(0.06)
(0.06)
0.00
(0.06)
Year Ended December 31, 2011
Net Income
(loss)
Shares
Per Share
69,909
(1,204)
68,705
69,909
(1,204)
68,705
15,582
15,582
15,582
3
15,585
15,585
15,585
$
$
$
$
4.49
(0.08)
4.41
4.49
(0.08)
4.41
$
$
$
$
$
$
$
$
$
$
$
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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 would have been 187,302 shares for the year ended
December 31, 2013. Prior to this period, the Company had no potentially dilutive securities.
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,
2013
2012
2011
Provision/(benefit) at statutory tax rate
$
23,011
35.00 % $
State income tax provision, net of federal benefit
Permanent differences
Other
Income tax provision /(benefit)
2,928
(1,559)
4
4.45 %
(2.37)%
0.01 %
(94)
654
450
35.00 % $ 38,056
35.00 %
(241.84)%
2,960
2.72 %
(166.34)%
(2,223)
(2.04)%
(373)
137.65 %
28
0.03 %
$
24,384
37.09 % $
637
(235.53)% $ 38,821
35.71 %
Included in permanent differences for the fiscal year ended December 31, 2013, is $10 million in proceeds from life
insurance, offset by $3 million in non-deductible expenses related to the Merger. Included in permanent differences for the fiscal
year ended December 31, 2011, is the IRC Section 199 benefit.
The provision (benefit) for income taxes from continuing operations for the periods indicated are comprised of the
following (in thousands):
Year Ended December 31,
2012
2013
2011
Current:
Federal
State
Total
Deferred:
Total:
Federal
State
Total
Federal
State
Total
Included in gain/loss from affiliates
Total income tax provision (benefit)
$
$
$
$
$
$
$
$
$
$
$
$
$
8,739
3,857
12,596
11,361
427
11,788
20,100
4,284
24,384
1,245
7,038
2,168
9,206
$
$
31,743
3,461
35,204
(8,343) $
4,599
(226)
(982)
(8,569) $
3,617
(1,305) $
36,342
1,942
2,479
637
$
38,821
32
—
23,139
$
605
$
38,821
F-30
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
$
49,204
$
December 31,
2013
2012
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
$
$
$
$
$
2,676
564
406
1,165
54,015
$
(2,552)
51,463
$
—
—
—
—
—
—
—
—
(133,894) $
(109,538)
(21,681)
(518)
(6,320)
—
(156,093) $
(115,858)
(104,630) $
(115,858)
As of December 31, 2013, the Company had federal and state net operating loss (“NOL") carryforwards of
approximately $132.3 million. All NOL were acquired in a Merger with Crimson. These NOL are available to reduce future
taxable income and the related income tax liability of combined company. At the date of the Merger Crimson had 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 allowance of approximately $29.2 million, or $10.2 million tax-adjusted. 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 NOL acquired by Crimson in previous acquisitions. Utilization of NOL acquired in a Merger with
Crimson is limited by Section 382 as discussed below.
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. 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. We consider
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, we believe it is more likely than not that we
will realize the benefits of these deductible differences net of a tax-adjusted $2.6 million valuation allowance.
Federal NOL carryforwards of $132.3 million expire at various dates beginning in 2014 and ending in 2033. NOL
carryforwards of $7.3 million impacted by Crimson's Section 382 limitations, which are not expected to be realized, will expire
between 2014 and 2016. Federal NOL carryforwards of $131.0 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
2026 and ending in 2033. We believe that we will be able to utilize most 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 results of the Merger, we acquired certain tax positions taken by Crimson in prior years. These
positions are 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):
F-31
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Balance at December 31, 2012
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, 2013
Unrecognized Tax
Benefits
$
$
—
—
—
518
—
518
Company's policy is to recognize interest and penalties related to uncertain tax positions as income tax benefit
(expense) in our Consolidated Statements of Operations. The Company had no interest or penalties related to unrecognized tax
benefits for the year ended December 31, 2013 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. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of
audits and the expiration of statute of limitations prior to December 31, 2013.
Generally, the Company's income tax years of 2009 through the current year remain open and subject to examination
by Federal tax authorities or the tax authorities in Texas and Louisiana which are the jurisdictions where the Company carries
its principal operations. These audits can result in adjustments of taxes due or adjustments of the net operating loss
carryforwards that are available to offset future taxable income.
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 offshore and onshore 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. Prospects were presented along with terms
and conditions for purchasing each prospect and Contango had the first right of refusal to purchase the prospect from JEX, subject
to mutually acceptable terms. Pursuant to the First Right Agreement, JEX was to be paid an annual fee of $0.5 million, which
approximates the costs incurred by JEX for its support to the Company in the areas of operations, engineering, and land functions.
JEX and its employees continued to be eligible to receive overriding royalty interests, carried interests and certain back-in rights.
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 will provide advisory
services to Contaro in connection with Contaro's investment in Exaro, and Mr. Juneau will serve on the Board of Managers of
Exaro and perform such duties as described in the limited liability company operating agreement of Exaro. Pursuant to the Contaro
Advisory Agreement, JEX will be paid a monthly fee of $10,000 and shall be entitled to receive a one percent (1%) fee of the cash
profit earned by Contaro. Cash profit is defined as the amount of cash received by Contango as a result of its investment in Contaro,
less the cash invested by the Company as a result of its investment in Contaro.
On March 19, 2014, Mr. Juneau resigned from the board of directors.
F-32
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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 remains 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
interest ("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 our 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, 2013, Contango, Olympic, JEX, REX and JEX employees owned the following interests in the
Company's offshore wells.
Contango
Dutch #1 - #5
Mary Rose #1
Mary Rose #2 - #3
Mary Rose #4
Mary Rose #5
Ship Shoal 263
Vermilion 170
Olympic
WI
JEX
REX
WI
WI
NRI
NRI
NRI
NRI
WI
—% —%
54.89% 44.65% 3.53% 2.84% 1.88% 1.51%
—% —%
53.21% 40.44% 3.61% 2.70% 2.01% 1.51%
—% —%
53.21% 38.67% 3.61% 2.58% 2.01% 1.44%
—% —%
34.58% 25.49% 2.34% 1.70% 1.31% 0.95%
—% —%
37.80% 27.88% 2.56% 1.87% 1.43% 1.04%
—% —% —% —%
100.00% 80.00%
—% —%
—% —% 4.30% 3.35% 12.50% 9.74%
83.20% 64.83%
JEX Employees
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
Contango
Olympic
JEX
WI
47.05%
NRI
38.12%
WI
3.02%
NRI
2.42%
WI
1.61%
NRI
1.29%
During the year ended December 31, 2013, Mr. Romano earned $26,000 and Mr. Juneau earned $97,500 in cash, and
each received 1,622 shares of restricted stock, which vest 100% on the one-year anniversary of the date of grant, as part of their
board of director compensation. Below is a summary of transactions between the Company, Olympic, JEX, and REX during the
years ended December 31, 2013, 2012 and 2011.
•
•
In March 2010 the Company spud the Eloise South well. All owners paid for their proportionate share of drilling and
completion costs based on their ownership percentage. The Company had a 23.8% working interest in this well, Olympic
had a 3.33% working interest, and REX had a 9.6% working interest. Once production began, JEX employees received
an ORRI of 1.33%.
In June 2010 the Company spud its Rexer #1 well. Under the terms of the applicable participation agreement, the Company
had a 100% working interest through payout of all costs. In May 2011, the Company sold Rexer #1 (See Note 18 -
"Discontinued Operations") prior to reaching payout. Once payout is reached with the new operator, JEX will have an
F-33
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
•
•
•
•
•
•
•
•
•
option to back-in for a 10% working interest (7.25% net revenue interest). Other third-parties own the remaining working
interests. JEX employees maintained a 2.5% ORRI in this well. The Company paid JEX a prospect fee of $250,000 for
generating this prospect.
Prior to its dissolution, Contango Offshore Exploration LLC owed the Company $5.9 million in principal and interest
under a promissory note (the “COE Note”) payable on demand. In connection with the dissolution, the Company assumed
its 65.63% share of the obligation under the COE Note, while JEX assumed the remaining 34.37%, or approximately $2
million. This $2 million was paid to the Company in October 2010.
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 May 2011 the Company spud its Rexer-Tusa #2 well. Under the terms of the applicable participation agreement, the
Company had a 25% working interest through payout of all costs. In October 2011, the Company completed selling
Rexer-Tusa #2 (See Note 18 - "Discontinued Operations") prior to reaching payout. Once payout is reached with the
new operator, JEX will have an option to back-in for a 10% working interest (7.36% net revenue interest). Other third-
parties own the remaining working interests. JEX employees maintained a 2.92% ORRI in this well.
In July 2011, the Company recompleted its Eloise South well uphole in the Cib-Op sands as our 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 our 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
F-34
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
•
•
•
•
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
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 interests (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. Beginning with production from the fourth well on the existing acreage (if
successful), JEX will receive a carried working interest of 10% 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% was granted to the geologist who generated the TMS prospect for us. The geologist
has subsequently been employed by Contango. Should the Company not drill on its TMS acreage within six months of
the leases expiring, the Company shall assign such leases to JEX.
•
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 our rental liability for that space.
Below is a summary of payments received from (paid to) Olympic, JEX, and REX in the ordinary course of business in
our 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):
Year ended December 31,
2013
2012
Olympic
JEX
REX
Olympic
JEX
REX
Olympic
2011
JEX
REX
Revenue payments as well owners
$
(6,859) $ (4,628) $ (1,932) $
(6,888) $ (5,230) $ (4,308) $ (9,669) $ (5,393) $
(816)
Joint interest billing receipts
945
1,201
2,090
1,081
Dutch well cost adjustment
Mary Rose well cost adjustment
—
—
—
—
—
—
—
(201)
724
—
118
885
—
(1,185)
1,867
1,069
3,229
(389)
—
161
—
(957)
—
Below is a summary of payments 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):
F-35
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Year ended December 31,
2013
Olympic
JEX
REX
Olympic
2012
JEX
2011
REX
Olympic
JEX
REX
Sale of interest in Mary Rose #5
$
— $ — $ — $
— $
— $ — $
— $
8 $ —
Reimbursement of certain costs
Prospect fees
Advisory Agreements
REX distribution to members
—
(115)
— (1,000)
(361)
—
—
(4)
—
—
—
—
(496)
—
— (1,530)
(9)
—
—
—
(197)
—
— 1,469
—
—
—
—
(185)
(149)
(250) —
—
—
—
—
As of December 31, 2013 and 2012, the Company's consolidated balance sheets reflected the following balances (in
thousands):
December 31, 2013
December 31, 2012
Olympic
JEX
REX
Olympic
JEX
REX
$
— $
— $ — $
2 $
1 $
34
87
116
79
85
1
78
Accounts receivable:
Trade receivable
Joint interest billing
Accounts payable:
Royalties and revenue payable
(1,293)
(877)
(466)
(1,133)
Joint interest billings
—
—
—
—
(842)
(101)
(642)
—
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, 2013, an affiliate of Oaktree earned $17,000 in cash and 1,622 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.
Contango Mining Company (“Contango Mining”), a wholly owned subsidiary of the Company, was formed in
October 2009 for the purpose of engaging in exploration on properties in the state of Alaska for (i) gold ore and associated minerals
and (ii) rare earth elements. Contango Mining initially acquired a 50% interest in these properties in Alaska from JEX in exchange
for $1 million and a 1% ORRI in the properties under a Joint Exploration Agreement (the “Joint Exploration Agreement”). We
believe JEX expended approximately $1 million on exploratory activities and related work on the properties prior to selling the
initial 50% interest to Contango Mining.
In September 2010, Contango Mining acquired the remaining 50% interest in the properties by increasing the ORRI in
the properties granted to JEX to 3% pursuant to an Amended and Restated Conveyance of Overriding Royalty Interest (the
“Amended ORRI Agreement”). Contango Mining assumed control of the exploration activities and JEX and Contango Mining
terminated the Joint Exploration Agreement.
F-36
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Contango ORE, Inc. ("CORE") was formed on September 1, 2010 as a wholly-owned subsidiary of the Company and in
November 2010, Contango Mining assigned the properties and certain other assets and liabilities to Contango. Contango contributed
the properties and $3.5 million of cash to CORE, pursuant to the terms of a Contribution Agreement (the “Contribution Agreement”),
in exchange for approximately 1.6 million shares of CORE's common stock. The transactions took place between companies under
common control. Contango distributed all of CORE's common stock to Contango’s stockholders of record as of October 15, 2010,
promptly after the effective date of CORE's Registration Statement Form 10 on the basis of one share of common stock for each
ten (10) shares of Contango’s common stock then outstanding.
In November 2011, the Company executed a $1.0 million Revolving Line of Credit Promissory Note to lend money to
CORE (the “CORE Note”). The Company and 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. Discontinued Operations
Joint Venture Assets
In October 2009, the Company entered into a joint venture with Patara Oil & Gas LLC (“Patara”) to develop proved
undeveloped reserves. B.A. Berilgen, a member of the Company’s board of directors, was the Chief Executive Officer of Patara
at the time. In May 2011, the Company sold to Patara its 90% working interest and 5% overriding royalty interest in the 21 wells
drilled under this joint venture for approximately $36.2 million and recognized a pre-tax loss of approximately $0.7 million. These
21 wells had proved reserves of approximately 16,700 Mmcfe, net to Contango. The Company accounted for this sale as discontinued
operations as of December 31, 2011 and has included the results of the joint venture operations in discontinued operations for all
periods presented. The summarized financial results for the joint venture assets for the periods ended December 31, 2012 and
2011 are as follows (in thousands):
Revenues
Operating expenses
Depletion expenses
Loss on sale
Income (loss) before income taxes
Benefit (provision) for income taxes
Income (loss) from discontinued operations, net of income taxes
December 31,
2012
2011
$
$
$
— $
(40)
—
—
(40) $
14
(26)
3,939
(827)
(1,755)
(651)
706
(459)
247
Rexer Assets
In May 2011, the Company sold to Patara its (i) 100% working interest (72.5% net revenue interest) in Rexer #1 drilled
in south Texas; and (ii) 75% working interest (54.4% net revenue interest) in Rexer-Tusa #2 for approximately $2.5 million and
recognized a pre-tax loss of approximately $0.3 million. The Rexer #1 well had proved reserves of approximately 0.5 Bcfe, net
to Contango, while the Rexer-Tusa #2 had not been spud at the time of sale.
In October 2011, the Company sold its remaining 25% working interest (18.4% net revenue interest) in Rexer-Tusa #2
for $10,000 to Patara. The Company has accounted for the sale of the Rexer #1 and Rexer-Tusa #2 as discontinued operations as
of December 31, 2012 and has included the results of these operations as discontinued operations for all periods presented. The
summarized financial results for these Rexer assets for the periods ended December 31, 2012 and 2011 are as follows (in thousands):
F-37
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Revenues
Operating expenses
Depletion expenses
Impairment of natural gas and oil properties
Exploration expenses
Loss on sale
Loss before income taxes
Benefit for income taxes
Loss from discontinued operations, net of income taxes
Contango Mining Company
December 31,
2012
2011
$
$
$
— $
(5)
—
—
—
— $
(5) $
2
(3) $
1,175
(169)
(1,821)
(1,031)
(8)
(273)
(2,127)
744
(1,383)
On September 29, 2010, Contango ORE, Inc. (“CORE”), then a wholly-owned subsidiary of the Company, filed with
the Securities and Exchange Commission a Registration Statement on Form 10 which became effective November 29, 2010.
Following the effective date, CORE acquired the assets and assumed the liabilities of Contango Mining Company (“Contango
Mining”), another wholly-owned subsidiary of the Company. Additionally, subsequent to the effective date, the Company
contributed $3.5 million of cash to CORE. In exchange, CORE issued 1,566,367 shares of its common stock to the Company in
addition to the 100 shares which the Company held prior to that date. The Company distributed all its shares of CORE, valued at
approximately $7.3 million, to its stockholders of record as of October 15, 2010 on the basis of one share of common stock of
CORE for each ten shares of the Company’s common stock then outstanding. In addition to the distribution of shares of CORE,
in 2010 the Company paid $6,213 in cash to its stockholders of record in exchange for partial shares. As of December 31, 2013
and 2011, the assets and liabilities of Contango Mining were excluded from the Company’s financial statements. No income or
expenses related to CORE were recognized for the year ended December 31, 2013, 2012 or 2011.
19. Subsequent Events
We have 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 were identified in addition to the items disclosed in the
financial statements.
F-38
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
December 31,
2013
2012
1,001,361
49,443
1,050,804
(260,438)
554,967
22,661
577,628
(197,801)
$
790,366
$
379,827
Costs Incurred
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,
2013
2012
2011
$
8,134
$ 19,982
$
3,035
428,925
15,551
35,363
280
41,265
16,090
2,660
7,622
23,013
$ 487,973
$ 77,617
$ 36,330
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
Year Ended December 31,
2013
2012
2011
$
— $
— $
—
—
51,014
20,528
Company's 37% share of costs incurred
$ 51,014
$ 20,528
$
Natural Gas and Oil Reserves
—
—
—
—
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, 2011 and 2010, 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, 2013, and the related discounted future net cash flows before income taxes are based on 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.
F-39
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)
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, 2013, 2012, 2011, and 2010, all of
which are located in the continental United States.
Proved Developed and Undeveloped Reserves as of:
Oil and
Condensate
(MBbls)
NGLs
(MBbls)
Natural
Gas
(MMcf)
Total
(MMcfe)
December 31, 2010
Sale of minerals in place
Extensions and discoveries
Revisions of previous estimates
Production
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
Proved Developed Reserves as of:
December 31, 2010
December 31, 2011
December 31, 2012
December 31, 2013
Proved Undeveloped Reserves as of:
December 31, 2010
December 31, 2011
December 31, 2012
December 31, 2013
4,083
(113)
506
(353)
(630)
3,493
(472)
(507)
2,514
(323)
2,199
6,839
(942)
(589)
9,698
4,072
3,539
2,514
5,223
11
(46)
—
6,428
(626)
266
(864)
(634)
4,570
1,420
(660)
5,330
(49)
436
3,151
(233)
(677)
7,958
6,366
4,343
5,103
6,453
62
227
227
234,725
(15,901)
39,192
(21,537)
(23,656)
212,823
(17,041)
(21,750)
174,032
(356)
5,431
65,186
(15,739)
(20,624)
207,930
233,206
209,903
166,307
185,535
1,519
2,920
7,725
4,475
1,505
22,395
297,791
(20,331)
43,816
(28,835)
(31,240)
261,201
(11,353)
(28,752)
221,096
(2,588)
21,241
125,126
(22,789)
(28,220)
313,866
295,834
257,195
212,009
255,591
1,957
4,006
9,087
58,275
Company's Share of Proved Developed Reserves attributable to
our 37% investment in Exaro:
December 31, 2012
December 31, 2013
133
439
—
—
11,056
39,068
11,854
41,702
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.
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.
During the year ended December 31, 2011, the most significant changes were associated with our discovery at Vermilion
170 and the sale of our Joint Venture Asset reserves (see Note 18 – "Discontinued Operations").
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, 2013, 2012 and 2011 are shown below (in thousands):
Future cash inflows
Future production costs
Future development costs
Future income tax expenses
Future net cash flows
As of December 31,
2012
2011
2013
$
2,098,788
$
1,094,986
$
1,564,889
(473,801)
(183,329)
(323,210)
1,118,448
(212,732)
(24,610)
(301,862)
555,782
(245,006)
(33,147)
(449,786)
836,950
(245,117)
10% annual discount for estimated timing of cash flows
(347,005)
(167,770)
Standardized measure of discounted future net cash flows
Contango's share of standardized measure of discounted future net cash
flows attributable to our 37% investment in Exaro
$
$
771,443
$
388,012
$
591,833
63,906
$
5,270
$
—
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, 2013, future cash inflows were based on 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 $2.75 per
MMBtu of natural gas, $95.05 per barrel of oil, and $58.39 per barrel of natural gas liquids. As of December 31, 2011, future cash
inflows were based on of $4.15 per MMBtu of natural gas, $96.04 per barrel of oil, and $59.37 per barrel of natural gas liquids, in
each case before adjustments for basis, transportation costs and BTU content.
Realized Prices
The average realized prices for the year ended December 31, 2013 production were $3.84 per MCF of gas, $101.21 per
barrel of oil, and $37.26 per barrel of NGL. Sales are based on market prices and do not include the effects of realized derivative
hedging gains of $0.3 million for the year ended December 31, 2013.
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.
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.
F-41
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)
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):
Changes in standardized measure due to current year operation:
Sales of natural gas and oil produced during the period, net of
production expenses
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
Year Ended December 31, 201
2013
2012
2011
$
(86,939) $
(122,149) $
(174,931)
120,709
(11,469)
20,282
(3,627)
408,990
(15,555)
37,099
(22,952)
(32,613)
413,925
357,517
—
(182,879)
5,665
(46,304)
—
—
90,968
111,458
(60,580)
(203,821)
591,833
$
771,442
$
388,012
$
180,441
32,063
5,051
(98,630)
—
(37,435)
91,207
(9,185)
(39,837)
(51,256)
643,089
591,833
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, as determined by our reservoir engineer.
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.
F-42
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, 2013 and
2012, (in thousands, except per share amounts):
March 31
June 30
September 30
December 31
Quarter Ended
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:
Year ended December 31, 2012:
Revenues from continuing operations
Income (loss) from continuing operations (1)
Net loss from discontinued operations, net of taxes
Net income (loss) attributable to common stock
Net income (loss) per share (2):
Basic:
Diluted:.
$
$
$
$
$
$
$
$
31,787
3,869
3,869
0.25
0.25
$
$
$
$
$
30,709
11,356
11,356
0.75
0.75
$
$
$
$
$
34,722
19,740
19,740
1.30
1.30
$
$
$
$
$
41,339
$
39,823
$
29,765
$
14,699
(26)
14,673
9,339
(2)
9,337
(27,549)
—
(27,549)
0.96
0.96
$
$
0.61
0.61
$
$
(1.80) $
(1.80) $
66,903
6,396
6,396
0.34
0.34
34,940
2,604
—
2,604
0.17
0.17
(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-43
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Company
Profile
ConTAngo oil & gAS ComPAny iS An indePendenT oil And gAS ComPAny bASed in HouSTon,
TexAS, FoCuSed on THe exPloRATion, develoPmenT, PRoduCTion And ACquiSiTion oF nATuRAl
gAS And oil PRoPeRTieS boTH onSHoRe, PRimARily in THe TexAS gulF CoAST Region, And
oFFSHoRe in THe SHAllow wATeRS oF THe gulF oF mexiCo. ConTAngo HAS oveR 400 PRoduCing
onSHoRe wellS, wiTH PRoduCTion FRom THe woodbine FoRmATion in mAdiSon And gRimeS
CounTieS TexAS, THe eAgle FoRd And budA FoRmATionS in ZAvAlA And dimmiTT CounTieS
TexAS, THe HAyneSville SHAle, mid-boSSieR And JAmeS lime PlAyS in eAST TexAS, THe
denveR JuleSbuRg bASin in ColoRAdo, And in vARiouS ConvenTionAl FieldS loCATed PRimARily
Along THe TexAS gulF CoAST. ConTAngo AlSo ownS APPRoximATely 29,000 undeveloPed ACReS
in THe develoPing TuSCAlooSA mARine SHAle PlAy in louiSiAnA And miSSiSSiPPi. ConTAngo’S
oFFSHoRe oPeRATionS ARe ConCenTRATed in THe SHAllow wATeRS oF THe gulF oF mexiCo
And ConSiST oF 13 ComPAny-oPeRATed wellS And THRee PRoduCTion PlATFoRmS. ConTAngo
HAS A bAlAnCed ASSeT PRoFile wiTH APPRoximATely 60% oF ReSeRveS And PRoduCTion
in THe SHAllow gulF oF mexiCo, And beTween 60–65% oF PRoduCTion FRom nATuRAl gAS.
ConTAngo HAS A STRong FinAnCiAl PoSiTion And CASH Flow THAT PoSiTionS iT well To
PuRSue longeR-TeRm gRowTH oF ReSeRveS And PRoduCTion THRougH THe develoPmenT
oF iTS oil And liquidS RiCH onSHoRe ReSouRCe PlAyS, ComPlemenTed by A numbeR oF
PoTenTiAlly HigH-imPACT oFFSHoRe PRoSPeCTS.
Corporate
Information
BOArd OF dIreCTOrS
Joseph J. romano
Chairman
Allan d. Keel
B.A. Berilgen
B. James Ford
Lon 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 & Chief Financial officer
A. Carl Issac
Senior vice President—operations
J. Stephen Mengle
Senior vice President—engineering
Yaroslava Makalskaya
vice President, Chief Accounting officer & Controller
John A. Thomas
vice President, general Counsel & Corporate Secretary
Michael J. Autin
vice President—offshore Production
Sergio Castro
vice President & Treasurer
Jeffrey A. Sikora
vice President—land
edward Skrljac
vice President—onshore Completions
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”
Auditors
grant Thornton llP
700 milam Street, Suite 300
Houston, Texas 77002
Transfer Agent
Continental Stock Transfer &
Trust Company
17 battery Place
new york, new york 10004
212.509.4000
Form 10-K, 10-K/A
Additional copies of the Company’s
Form 10-K and 10-K/A, as filed
with the Securities and exchange
Commission, are available at our
website www.contango.com under
investor Relations.
Annual Report Design by Curran & Connors, Inc. / www.curran-connors.com
267166_Contango_Cov_R1.indd 4-6
4/3/14 1:18 PM
717 Texas Avenue, Suite 2900
Houston, Texas 77002
Phone: 713.236.7400
Fax: 713.236.4424
www.contango.com
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