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717 Texas Avenue, Suite 2900
Houston, Texas 77002
Phone: 713.236.7400
www.contango.com
2015 ANNUAL
REPORT
DISCIPLINED VALUE ENHANCEMENT
COMPANY
PROFILE
Contango Oil & Gas Company, based in Houston, Texas,
is an independent energy company engaged in the acquisition,
exploration, development, exploitation and production of
crude oil and natural gas properties offshore in the shallow
waters of the Gulf of Mexico and in the onshore Texas Gulf
Coast and Rocky Mountain regions of the United States.
Houston
Headquarters
GULF OF MEXICO
ONSHORE GULF COAST
ROCKY MOUNTAINS
Total Proved Reserves: 114 Bcfe
Percent Developed:
Percent Natural Gas:
2015 Production:
100%
81%
22 Bcfe
Total Proved Reserves: 67 Bcfe
Percent Developed:
Percent Natural Gas:
2015 Production:
60%
48%
12 Bcfe
Total Proved Reserves*: 6 Bcfe
Percent Developed:*
43%
Percent Natural Gas*: 33%
2015 Production*:
<1 Bcfe
* Excludes our 37% equity interest in Exaro Energy III
CORPORATE
INFORMATION
BOARD OF DIRECTORS
CORPORATE OFFICE
717 Texas Avenue, Suite 2900
Houston, Texas 77002
Phone: 713.236.7400
Fax: 713.236.4424
OUTSIDE COUNSEL
Vinson & Elkins
First City Tower
1001 Fannin Street, Suite 2500
Houston, Texas 77002
COMMON STOCK INFORMATION
The Common Stock is traded on the
NYSE MKT under the symbol “MCF”
TRANSFER AGENT
Continental Stock & Trust Company
17 Battery Place
New York, New York 10004
212.509.4000
AUDITORS
Grant Thornton LLP
700 Milam Street, Suite 300
Houston, Texas 77002
FORM 10-K
Additional copies of the Company’s Form 10-K
as fi led with the Securities and Exchange
Commission, are available at our website
www.contango.com under Investor Relations
Joseph J. Romano
Chairman of the Board
Allan D. Keel
B.A. Berilgen
B. James Ford
Ellis L. McCain
Charles M. Reimer
Steven L. Schoonover
MANAGEMENT TEAM
Allan D. Keel
President and Chief Executive Offi cer
Thomas H. Atkins
Senior Vice President, Exploration
E. Joseph Grady
Senior Vice President
and Chief Financial Offi cer
A. Carl Isaac
Senior Vice President, Operations
J. Steven Mengle
Senior Vice President, Engineering
John A. Thomas
Vice President, General Counsel
and Corporate Secretary
Michael J. Autin
Vice President, Production
Sergio Castro
Vice President and Treasurer
Jeff Sikora
Vice President, Land
Edward Skrljac
Vice President, Onshore Completions
Patrick Webb
Vice President, Business Development
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DEAR FELLOW
SHAREHOLDERS
Amid a growing global oversupply of crude oil and the
possibility of a lower for longer commodity price scenario,
we took immediate action in 2015 to endure the current
down cycle for commodity prices, maintain our fi nancial
strength, preserve value and position ourselves for
growth when prices improve.
We lowered our 2015 capital expenditure budget to less
than internally generated cash fl ow. Total 2015 capital
expenditures totaled $55.6 million representing a 71%
decrease from 2014 spending levels. Our disciplined
approach to allocating capital focused on drilling our
most strategic projects in Texas and Wyoming, and
resulted in a new play discovery in Wyoming, bringing
new wells on production from wells drilled in late 2014
and 2015, and on keeping our valuable leasehold intact.
Notably, in 2015 we announced the discovery and
successful completion of the Elliot #1H and Popham
#1H wells in the Muddy Sandstone formation at our
North Cheyenne Project in Weston County, Wyoming.
These wells came online at peak 24-hour rates
of 907 and 970 barrels of oil equivalent per day
(98% oil), respectively, exceeding our initial expectations.
A third well, the Christensen #1H well was drilled in the
fourth quarter of 2015 and has recently commenced
production. We are excited about the potential for this
39,000 net acre position that could ultimately add
200-300 drilling locations to our inventory from the
Muddy alone. Additionally, we brought seven wells
on-line in our Madisonville area that were drilled in late
2014 and early 2015 using a pad drilling strategy, which
might be a viable strategy to improve ultimate recovery in
a better oil price environment. In addition to our drill bit
success, we reduced production costs by approximately
10% during 2015 and cash G&A costs by 35% by
implementing cost control and operational effi ciencies.
We experienced increased success as the year went on,
as evidenced by a 15% decrease in per unit production
costs, despite an 18% decrease in production during the
quarter, when compared to the prior year quarter.
Our swift and proactive approach to implement a
more conservative capex strategy and reduce costs in
2015 helped strengthen our fi nancial position. After a
temporary jump in natural gas prices in December, we
opportunistically added another defensive measure by
hedging a majority of our 2016 gas production with a
fi xed fl oor of $2.53/MMBtu. We had approximately $115
million outstanding on our credit facility at year-end 2015
and had additional borrowing capacity of approximately
$73 million under our $190 million borrowing base.
While that borrowing base will likely come down some
in our May redetermination cycle, we will continue to
focus on balance sheet improvement in 2016 to provide
us the fl exibility to restart our drilling program if prices
improve, or to potentially take advantage of acquisition
opportunities that might arise during the year.
As mentioned, 2015 was about asset value and balance
sheet preservation. In 2016, we believe we can actually
enhance shareholder value by staying committed to the
same successful and conservative capital investment
strategy we used in 2015 and by being opportunistic in
the acquisition market, both of which should position us
to enhance value for our shareholders as commodity
prices improve. We will preserve our balance sheet
strength by limiting drill bit capital expenditures to a
minimum and use excess cash to improve our fi nancial
profi le by lowering overall liabilities. Since a vast majority
of the PV-10 value of a typical resource well is produced
within the fi rst 12-18 months, we believe that the deferral
of further drilling in our areas pending a better price
environment is the appropriate approach for maximum
value optimization from our portfolio. Our fi nancial
position affords us the luxury of being opportunistic in
this diffi cult market. We will continue to identify growth
prospects fi tting our core investment hurdles that might
surface in the near future as capital-stressed companies
shed assets, look for joint venture partners or pursue
other long term strategic alternatives.
In summary, we continue to focus on creating long-term
shareholder value rather than maintaining marginal
production levels. As we move forward in 2016, we will
continuously monitor commodity prices and service/
supply costs, and if deemed appropriate, may reevaluate
our capital strategy in the latter part of the year. We have
the fl exibility, liquidity and inventory to increase our level
of spending during the year should we see improvement
and stability in commodity prices.
Thank you for your continued support as shareholders
during these volatile times.
Sincerely,
Sincerely,
Allan D. Keel
President and Chief Executive Offi cer
Joseph J. Romano
Joseph J. Romano
Chairman of the Board
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FINANCIAL
PERFORMANCE
NYSE MKT: MCF
PROVED RESERVES (SEC PRICING)
Crude Oil (MBbls)
Natural Gas (Mmcf)
Natural Gas Liquids (MBbls)
Natural Gas Equivalent (Mmcfe)
2015
2014
2013
4,791
126,128
5,394
187,238
8,415
179,651
7,509
275,193
9,698
207,930
7,958
313,866
FUTURE NET REVENUE FROM PROVED RESERVES:
Undiscounted before income taxes ($000)
Discounted at 10% after income taxes ($000)
$ 352,914
$ 249,406
$ 956,101
$ 648,016
$ 1,118,448
$ 771,443
PRODUCTION (NET SALES VOLUME)
Crude Oil (MBbls)
Natural Gas (Mmcf)
Natural Gas Liquids (MBbls)
Natural Gas Equivalent (Mmcfe)
AVERAGE PRICES FOR THE YEAR
Crude Oil ($/Bbl)
Natural Gas ($/Mcf)
Natural Gas Liquids ($/Bbl)
PRICES USED FOR YEAR-END RESERVES:
Crude Oil ($/Bbl)
Natural Gas ($/Mcf)
Natural Gas Liquids ($/Bbl)
TOTAL REVENUES ($000)
TOTAL EXPENSES ($000)
Lease Operating Expenses and Production Taxes
Exploration Expenses
DD&A and Impairment
G&A
Other Income (Expenses)
Income (Loss) from Continuing Operations Before Taxes
Income Tax (Expense) Benefi t
924
22,614
968
33,961
46.80
2.61
14.68
44.53
2.63
14.41
$
$
$
$
$
$
1,401
25,875
1,008
40,323
92.98
4.36
33.27
92.89
4.38
33.45
$
$
$
$
$
$
589
20,624
677
28,220
101.21
3.84
37.26
106.80
3.73
35.92
$
$
$
$
$
$
$
116,505
$ 276,458
$ 164,121
(37,840)
(11,979)
(419,257)
(26,402)
(31,301)
(410,274)
75,226
(47,236)
(33,387)
(203,810)
(34,045)
4,236
(37,784)
15,910
(36,784)
(1,811)
(66,305)
(26,512)
31,792
64,501
(23,139)
Net Income (Loss) from Continuing Operations
$ (335,048)
$
(21,874)
$
41,362
NET INCOME (LOSS) FROM CONTINUING OPERATIONS
PER SHARE (DOLLARS)
Basic
Diluted
WEIGHTED AVERAGE SHARES OUTSTANDING (000’S)
Basic
Diluted
$
$
(17.67)
(17.67)
$
$
(1.15)
(1.15)
$
$
2.56
2.56
18,965
18,965
19,059
19,059
16,156
16,158
TOTAL ASSETS ($000)
LONG-TERM DEBT, INCLUDING CURRENT PORTION ($000)
SHAREHOLDERS’ EQUITY ($000)
$
$
$
416,756
115,446
237,843
$ 843,415
$
63,359
$ 567,466
$ 910,304
$
90,000
$ 593,050
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
For the fiscal year ended December 31, 2015
For the transition period from to
Commission file number 001-16317
CONTANGO OIL & GAS COMPANY
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
95-4079863
(IRS Employer Identification No.)
717 Texas Avenue, Suite 2900
Houston, Texas 77002
(Address of principal executive offices)
(713) 236-7400
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock, Par Value $0.04 per share
Securities registered pursuant to Section 12(g) of the Act: None
Name of exchange on which registered
NYSE MKT
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject
to such filing requirements for the past 90 days. Yes No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive
Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or
for such shorter period that the registrant was required to submit and post such files). Yes No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See 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
Non-accelerated filer
Smaller reporting company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No
At June 30, 2015, 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 $155.2 million. As of March 9, 2016, there were 19,408,841 shares of the
registrant’s common stock outstanding.
(Do not check if smaller reporting company)
Items 10, 11, 12, 13 and 14 of Part III have been omitted from this report since the registrant will file with the Securities and Exchange
Commission, not later than 120 days after the close of its fiscal year, a definitive proxy statement, pursuant to Regulation 14A. The information
required by Items 10, 11, 12, 13 and 14 of this report, which will appear in the definitive proxy statement, is incorporated by reference into this Form
10-K.
Documents Incorporated by Reference
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
ANNUAL REPORT ON FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2015
TABLE OF CONTENTS
Page
Item 1.
Business
PART I
Overview
Our Strategy
Properties
Onshore Investments
Outlook
Title to Properties
Marketing and Pricing
Competition
Governmental Regulations and Industry Matters
Risk and Insurance Program
Employees
Directors and Executive Officers
Corporate Offices
Code of Ethics
Available Information
Seasonal Nature of Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2.
Properties
Development, Exploration and Acquisition Expenditures
Drilling Activity
Exploration and Development Acreage
Production, Price and Cost History
Productive Wells
Natural Gas and Oil Reserves
PV-10
Proved Developed Reserves
Proved Undeveloped Reserves
Significant Properties
Item 3.
Item 4.
Legal Proceedings
Mine Safety Disclosures
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
PART II
General
Amended & Restated 2009 Incentive Compensation Plan
2005 Stock Incentive Plan
Share Repurchase Program
Stock Performance Graph
Selected Financial Data
Item 6.
ii
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48
49
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview
Results of Operations
Capital Resources and Liquidity
Contractual Obligations
Application of Critical Accounting Policies and Management’s Estimates
Recent Accounting Pronouncements
Off Balance Sheet Arrangements
Item 7A. Quantitative and Qualitative Disclosure about Market Risk
Financial Statements and Supplementary Data
Item 8.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
Certain Relationships and Related Transactions, and Director Independence
Principal Accountant Fees and Services
Item 15.
Exhibits and Financial Statement Schedules
PART IV
51
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52
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61
61
64
65
66
67
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70
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71
75
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;
further or sustained declines in natural gas and oil prices;
operational constraints, start-up delays and production shut-ins at both operated and non-operated production platforms,
pipelines and natural gas processing facilities;
the risks associated with acting as operator of deep high pressure and high temperature wells, including well blowouts
and explosions;
the risks associated with exploration, including cost overruns and the drilling of non-economic wells or dry holes,
especially in prospects in which we have made a large capital commitment relative to the size of our capitalization
structure;
the timing and successful drilling and completion of natural gas and oil wells;
availability of capital and the ability to repay indebtedness when due;
availability and cost of rigs and other materials and operating equipment;
timely and full receipt of sale proceeds from the sale of our production;
the ability to find, acquire, market, develop and produce new natural gas and oil properties;
interest rate volatility;
uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of
development expenditures;
the need to take impairments on our properties due to lower commodity prices;
the ability to post additional collateral for current bonds or comply with new supplemental bonding requirements
imposed by the Bureau of Ocean Energy Management;
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;
iv
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.
Reserve engineering is a process of estimating underground accumulations of oil, natural gas and natural gas liquids that
cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation
of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production
activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any
further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural
gas and natural gas liquids that are ultimately recovered.
All forward-looking statements, expressed or implied, in this report are expressly qualified in their entirety by this cautionary
statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking
statements that we or any person acting on our behalf may issue.
We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or
otherwise, except as required by law. These cautionary statements qualify all forward-looking statements attributable to us or persons
acting on our behalf.
All references in this Form 10-K to the “Company”, “Contango”, “we”, “us” or “our” are to Contango Oil & Gas
Company and wholly-owned subsidiaries. Unless otherwise noted, all information in this Form 10-K relating to natural gas and oil
reserves and the estimated future net cash flows attributable to those reserves is based on estimates prepared by independent
engineers, and is net to our interest.
v
Item 1. Business
Overview
PART I
We are a Houston, Texas based independent oil and natural gas company. Our business is to maximize production and cash
flow from our offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore properties in various plays, and
use that cash flow to explore, develop, exploit and acquire crude oil and natural gas properties in the onshore Texas Gulf Coast and
Rocky Mountain regions of the United States.
On October 1, 2013, we completed a merger with Crimson Exploration Inc. (“Crimson”), in an all-stock transaction pursuant
to which Crimson became a wholly-owned subsidiary of Contango (the “Merger"). Accordingly, we issued approximately 3.9 million
shares of common stock in exchange for all of Crimson's outstanding capital stock, resulting in Crimson stockholders owning 20.3%
of the post-Merger Contango.
On October 1, 2013, our board of directors approved a change in fiscal year end from June 30 to December 31. On March 3,
2014, we filed a Transition Report on Form 10-KT which covered the transition period of July 1, 2013 through December 31, 2013,
which included six months of Contango activity (July - December) and three months of post-Merger Crimson activity (October -
December). Also, on March 28, 2014, we filed an Annual Report on Form 10-K/A to present the financial statements of the Company
on a calendar year basis which included the twelve months ended December 31, 2013 and 2012. This Annual report on Form 10-K
presents our information for the twelve-month periods ended December 31, 2015, 2014 and 2013. Unless otherwise noted, all
references to "years" in this report refer to the twelve-month periods ended December 31 of each year.
The following table lists our primary producing areas as of December 31, 2015:
Location
Gulf of Mexico
Madison and Grimes counties, Texas
Zavala and Dimmit counties, Texas
Weston County, Wyoming
Texas Gulf Coast
Sublette County, Wyoming
Formation
Offshore Louisiana - water depths less than 300 feet
Woodbine (Upper Lewisville)
Buda / Austin Chalk
Muddy Sandstone
Conventional formations
Jonah Field (1)
(1) Through a 37% equity investment in Exaro Energy III LLC (“Exaro”). Production from this investment is not included in our reported production results or
in our reported reserves for any periods reported herein.
Additionally, we have (i) operated properties producing from various conventional formations in various counties along the
Texas Gulf Coast; (ii) operated producing properties in the Denver Julesburg Basin (“DJ Basin”) in Weld and Adams counties in
Colorado, which we believe may also be prospective in the Niobrara Shale oil play; and (iii) operated producing properties in the
Haynesville Shale, Mid Bossier and James Lime formations in East Texas.
Due to the current challenging commodity price environment, we focused our 2015 capital program on: (i) the preservation
of our strong and flexible financial position, including limiting our overall capital expenditure budget; (ii) dedicating capital primarily
to de-risking and/or delineating strategic projects (i.e. versus field development); (iii) the identification of opportunities for cost and
production efficiencies in all areas of our operations; and (iv) continuing to identify and, when appropriate, pursue the expansion of
our resource potential through opportunistic acquisitions.
The following table lists the primary areas to which we allocated capital during 2015:
Location
Madison and Grimes counties, Texas
Weston County, Wyoming
Fayette and Gonzales counties, Texas
Formation
Woodbine (Upper Lewisville)
Muddy Sandstone
Navarro / Buda / Austin Chalk
1
Our production for the year ended December 31, 2015 was approximately 34.0 Bcfe (or 93.0 Mmcfe/d), was 63% from our
offshore properties and was 67% natural gas. Our production for the three months ended December 31, 2015 was approximately 8.0
Bcfe (or 86.7 Mmcfe/d), was 65% from our offshore properties and was 68% natural gas. As of December 31, 2015, our proved
reserves were approximately 84% proved developed, were 61% offshore, were 68% natural gas and were 96% attributed to wells and
properties operated by us.
As of December 31, 2015, our proved reserves, as estimated by Netherland, Sewell & Associates, Inc. (“NSAI”) and William
M. Cobb and Associates (“Cobb”), our independent petroleum engineering firms for our onshore and offshore properties, respectively,
in accordance with reserve reporting guidelines required by the Securities and Exchange Commission (“SEC”), were approximately
187.2 Bcfe, consisting of 126.1 Bcf of natural gas, 4.8 MMBbl of crude oil and condensate and 5.4 MMBbl of natural gas liquids
(“NGLs”), with a present value, discounted at a 10% rate (PV-10), of $249.4 million, and a Standardized Measure of Discounted
Future Net Cash Flows (“Standardized Measure”) of $249.4 million. PV-10 is a non-GAAP financial measure. A reconciliation of our
Standardized Measure to PV-10 is provided under “Item 2. Properties - PV-10”.
The following summary table sets forth certain information with respect to our proved reserves as of December 31, 2015
(excluding 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, 2015:
Region
Offshore GOM
Southeast Texas
South Texas
Other (1)
Total
Estimated Proved
Reserves (Bcfe)
% Crude Oil /
Condensate
% Natural
Gas
% Natural Gas
Liquids
% Proved
Developed
Average Daily
Production (Mmcfe/d)
114.0
32.4
33.4
7.4
187.2
4 %
35 %
26 %
54 %
81 %
39 %
56 %
37 %
15 %
26 %
18 %
9 %
100 %
67 %
53 %
52 %
59.0
22.6
9.3
2.1
93.0
(1) East Texas, Mississippi, Louisiana, Colorado and Wyoming
The following summary table sets forth certain information with respect to the proved reserves attributable to our investment
in Exaro, as of December 31, 2015, as estimated by W.D. Von Gonten and Associates (“Von Gonten”), and our net share of Exaro’s
average daily production for the year ended December 31, 2015:
Region
Investment in Exaro
Our Strategy
Estimated Proved
Reserves (Bcfe)
% Crude Oil /
Condensate
% Natural
Gas
% Natural Gas
Liquids
% Proved
Developed
Average Daily
Production (Mmcfe/d)
38.7
7 %
93 %
— %
100 %
14.2
Due to the current low commodity price environment, and the uncertainty for improvement in commodity prices in the
immediate future, our 2016 capital expenditure program is expected to be very conservative as we will limit expenditures to those
which are necessary to fulfill commitments, preserve core acreage and, where determined appropriate to do so, test the geological
viability of new plays or untested formations. Until we believe stability and improvement in commodity prices are likely, our priorities
for 2016 will be to preserve our balance sheet strength by limiting capital expenditures to a level below cash flow, to identify new
organic opportunities for growth, and to pursue stressed or distressed acquisition opportunities that may arise in this low price
environment.
Specific key elements of our long-term business strategy include:
Enhancing our portfolio by dedicating the majority of our drilling capital to our oil and liquids-rich opportunities. Due
to the current superior economics of oil production, as compared to natural gas, we allocated the majority of our 2015
capital budget to oil and liquids-weighted opportunities as we strive to transition from a heavily weighted natural gas
production profile to a more balanced reserve and production profile between oil/liquids and natural gas. Our long term
strategy is to continue to develop the oil and natural gas liquids resource potential that we believe exists in numerous
formations within our various oil/liquids weighted resource plays.
Pursuing accretive, opportunistic acquisitions that meet our strategic and financial objectives. We intend to continue
evaluating opportunistic acquisitions of crude oil and natural gas properties, both undeveloped and developed, in areas
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where we currently have a presence and/or specific operating expertise, and to pursue undeveloped acreage positions, at
reasonable cost, in new areas that we feel have significant exploration, exploitation or operational upside. We believe
that the ongoing depressed commodity price environment might provide growth opportunities for us through potential
corporate combinations.
Selectively exploiting, in a higher commodity price environment, our existing onshore producing conventional natural
gas property portfolio to generate additional cash flows. We believe our multi-year drilling inventory of exploitation
opportunities on our existing onshore conventional natural gas oriented producing properties provides us with a solid,
dependable platform for future reserve and production growth. We will continuously monitor the commodity price
environment, and if warranted, make adjustments to our investment strategy as the year progresses.
We believe that a continuing low commodity price environment could put pressure on over-leveraged or under-funded oil
and natural gas exploration and production companies to consider asset sales or strategic combinations. Should a complementary and
accretive opportunity materialize, our healthy financial profile, cash flow and liquidity should position us to capitalize on such an
opportunity. Accordingly, we plan to closely monitor the industry to identify and evaluate appropriate acquisition opportunities. Our
acquisition efforts will typically be focused on areas in which we can leverage our geographic and geological expertise, and where we
can develop an inventory of additional drilling prospects that we believe will enable us to grow production and add reserves.
Properties
Offshore Gulf of Mexico
As of December 31, 2015, our offshore assets consisted of seven federal and six State of Louisiana company-operated wells
in the shallow waters of the GOM. These 13 wells are located in four fields. The following summary table sets forth certain
information with respect to our offshore reserves as of December 31, 2015 and average daily offshore production for the year ended
December 31, 2015:
Field
Dutch and Mary Rose
Vermilion 170
Other Offshore
Total
Estimated Proved
Reserves (Bcfe)
% Crude Oil /
Condensate
104.0
9.6
0.4
114.0
4 %
3 %
1 %
% Natural Gas
81 %
82 %
99 %
% Natural Gas
Liquids
% Proved
Developed
15 %
15 %
— %
100 %
100 %
100 %
Average Daily
Production
(Mmcfe/d)
50.5
7.0
1.5
59.0
Dutch and Mary Rose Field
We operate five federal wells located at Eugene Island 10 (“Dutch”), and five state wells located in adjacent Louisiana state
waters (“Mary Rose”). All Dutch and Mary Rose wells flow to a Company-owned and operated production platform at Eugene Island
11. While we do not own the lease for the Eugene Island 11 block, this does not impact our ability to operate our facilities located on
that block. Operators in the GOM may place platforms and facilities on any location without having to own the lease, provided that
permission and proper permits from the Bureau of Safety and Environmental Enforcement (“BSEE”) have been obtained. We have
obtained such permission and permits. We installed our facilities at Eugene Island 11 because that was the optimal gathering location
in proximity to our wells and marketing pipelines.
From our production platform we are able to access two separate markets thereby minimizing downtime risk and providing
the ability to select the best sales price for our oil and natural gas production. Oil and natural gas production can flow to third-party
owned and operated onshore processing facilities near Patterson, Louisiana. Alternatively, natural gas can flow via our 8” pipeline,
which has been designed with a capacity of 80 Mmcf/d, to a third-party owned and operated onshore processing facility at Burns
Point, Louisiana. Condensate can also flow to onshore markets and multiple refineries.
In July 2014, we installed a turbine type compressor capable of servicing all ten Dutch and Mary Rose wells at the Eugene
Island 11 platform. We invested approximately $11.7 million to design, build and install the compressor, which began operating at the
platform during the third quarter of 2014.
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In December 2013, we exercised a preferential right and purchased an additional 7.84% working interest and 6.53% net
revenue interest in the five Company-operated Dutch wells from an independent oil and gas company for approximately $15 million,
net after customary purchase price adjustments.
Vermilion 170 Field
We own and operate one well with a dedicated production facility at Vermilion 170. This platform services natural gas and
condensate production, which flow via the Sea Robin Pipeline to a third-party owned and operated onshore processing plant. Based on
production and decline rates, we designed, built and installed for later use a compressor in 2013 at a cost of approximately $1.4
million. We commenced compression in 2015.
In January 2013, production was shut-in at our Vermilion 170 well and operations were conducted to replace the tubing and
casing and restore the well, which resumed production in June 2013. During December 2014, our Vermilion 170 well was shut-in for
fourteen days due to issues with the Sea Robin Pipeline.
Other Offshore
Our Ship Shoal 263 and South Timbalier 17 fields are included in “Other Offshore." In September 2015, our Ship Shoal 263
well reached the end of its estimated useful life and was permanently shut-in. We have budgeted approximately $2.9 million to plug
and abandon this well, which we expect to conclude in 2017.
On April 29, 2014, we reached total depth on our Ship Shoal 255 prospect in the GOM, and no commercial hydrocarbons
were found. As a result, for the twelve months ended December 31, 2014, we recognized $31.5 million in exploration expense for the
cost of drilling the well plus $15.6 million in impairment expense associated with $3.5 million of leasehold costs and $12.1 million
related to the platform located in Block Ship Shoal 263 that was expected to be used by the Ship Shoal 255 well had it been
successful. For the twelve months ended December 31, 2015, we recognized an additional $0.5 million in impairment expense for the
Ship Shoal 263 platform.
On July 30, 2013, we spud a successful well on our South Timbalier 17 prospect in State of Louisiana offshore waters which
commenced production in July 2014. We have a 75% working interest (53.3% net revenue interest) in this well. Due to the low price
environment, the net book value of our South Timbalier 17 well exceeded the future undiscounted cash flows associated with its
recoverable reserves, and we recognized an impairment expense of approximately $7.7 million and $0.5 million during the years
ended December 31, 2014 and 2015, respectively.
We currently hold six untested exploratory prospects on 15 offshore lease blocks. During the year ended December 31, 2014,
we recognized full impairment related to the prospects which we do not currently intend to drill.
Onshore Properties
Southeast Texas (Woodbine)
As of December 31, 2015, our Southeast Texas region included approximately 36,200 gross (21,800 net) acres, proven
reserves of 32.4 Bcfe, and 86 gross (50.7 net) producing wells. During 2013, Crimson, and subsequently Contango, drilled 12 gross
(8.0 net) wells on acreage targeting the Woodbine formation. During 2014, we drilled 18 gross (11.6 net) wells on acreage targeting
the Woodbine formation. In 2015, we brought seven gross wells (3.9 net) on production which we initiated in late 2014 utilizing a pad
drilling strategy on 500 foot spacing, plus an additional one gross well (0.9 net) in our Iola/Grimes area. We also drilled one gross (0.7
net) well in our Chalktown area to satisfy a farm-in commitment and one gross (0.7 net) horizontal well testing a more aggressive
completion design in the Lower Lewisville formation in our Grimes County area, as we limited our 2015 capital expenditures to
strategic projects and to stay within internally generated cash flows.
Due to the low commodity price forecasts for 2016, our current budget includes no drilling in this area, but should
commodity prices improve meaningfully, we may increase our activity in this area late in the year. We currently have approximately
15,400 net acres in Madison and Grimes counties, with a multi-year inventory of potential drilling locations, including the Woodbine,
Eagle Ford Shale and Georgetown/Buda formations.
4
On December 31, 2013, we sold to an independent oil and gas company approximately 7.1% of our interest in all developed
and undeveloped properties in Madison and Grimes counties for approximately $20.4 million, or $91,007 per flowing barrel of
equivalent daily production and $47.32 per equivalent barrel of proved reserves.
Weston County, Wyoming (N. Cheyenne Project)
In 2014, we acquired the right to earn approximately 49,000 gross acres (44,000 net acres with a 90% to 100% working
interest) in Weston County, Wyoming. During the fourth quarter of 2014, we sold a 20% working interest in this prospect to an
independent oil and gas company, reducing our potential ownership to approximately 35,000 net acres with a 72% to 80% working
interest. In June 2015, we announced the discovery and successful completion of the Elliot #1 well (80% working interest) in the
Muddy Sandstone formation. Based on the encouraging results from this well, we spud two more wells in September 2015, the WC
45N-66W-35 1H (“Popham 1H”) and the WC 44N-66W-9 1H (“Christensen 1H”). The Popham 1H well was completed during the
fourth quarter of 2015 and during February 2016 produced at an average rate of 221 BOe/d (approximately 99% liquids), while the
Christensen 1H well will be completed in the first quarter of 2016. As a result of drilling these wells, we have satisfied the right to
earn the 35,000 net acres (approximately 4% of which is held by production).
South Texas (Buda/Eagle Ford)
As of December 31, 2015, our South Texas region included approximately 166,600 gross (81,900 net) acres, proven reserves
of 33.4 Bcfe, and 272 gross (145.6 net) producing wells. We believe approximately 20,400 gross (8,900 net) acres to be prospective
for the Buda and Eagle Ford Shale plays. During 2013, Crimson, and subsequently Contango, drilled seven gross wells (3.3 net) in the
Buda formation in Zavala and Dimmit counties. Six of the wells were successful, while one was a mechanical failure which was side
tracked in 2014. During 2014, we drilled 14 gross wells (6.8 net) in the Buda formation in Zavala and Dimmit counties. During the
fourth quarter of 2014, we drilled one additional well in Dimmit County as a vertical pilot well to test the viability of the Eagle Ford
and other formations in the area. Though core analysis indicates the viability of the Eagle Ford formation in the area, no drilling
activity was conducted in this area in 2015, or is planned for 2016, because of the low commodity price environment.
Our estimated net proven Buda/Eagle Ford reserves in this area were 11.5 Bcfe, comprised of 77% liquids, with 26 gross
(13.3 net) producing wells, as of December 31, 2015.
South Texas (Elm Hill Project)
As of December 31, 2015, we held approximately 57,000 gross acres (27,000 net) in Fayette, Gonzales, Caldwell and Bastrop
counties, Texas. During 2014, we drilled four gross wells (2.0 net) in this area, two of which commenced production during the fourth
quarter of 2014, while the other two were not commercial successes. During 2015, we drilled one gross well (0.5 net) that was not a
commercial success. The Company and its partner are currently evaluating options for future testing of the Navarro, Buda and Austin
Chalk, or for monetization of the acreage position.
The remaining 89,200 gross (46,000 net) acres in our South Texas region are located in our conventional fields that produce
primarily from the Wilcox, Frio, and Vicksburg sands. Our estimated net proved conventional reserves in this region were 21.9 Bcfe,
comprised of 72% gas, with 242 gross (130.7 net) producing wells, as of December 31, 2015.
Natrona County, Wyoming (FRAMS Project)
In 2014, we acquired the right to earn approximately 119,300 gross acres (93,000 net acres with an 80% working interest) in
Natrona County, Wyoming. During the fourth quarter of 2014, we sold a 20% working interest in this prospect to an independent oil
and gas company, reducing our potential ownership to approximately 69,900 net acres with a 60% working interest. We spud our first
well in this play, the State #1H well, during the fourth quarter of 2014 targeting the Mowry Shale. In April 2015, initial flowback
began and no hydrocarbons were produced during the testing period. As a result, for the year ended December 31, 2015, we
recognized $6.7 million in exploration expenses for the cost of drilling the well. Though this well was not a commercial success, we
did earn approximately 23,000 net acres in the prospect area under a drill-to-earn arrangement and will continue to evaluate the
possibility of testing other formations on the acreage earned.
5
Other (East Texas)
As of December 31, 2015, our East Texas region included approximately 7,500 gross (4,500 net) acres primarily in San
Augustine County, with proven reserves of 0.7 Bcfe comprised of 84% gas, and 10 gross (5.1 net) producing wells. During 2014, we
drilled two gross (1.2 net) wells targeting the shallower, liquids-rich James Lime formation on our acreage in San Augustine County.
We believe that the further exploitation of our acreage in the Haynesville, Mid-Bossier and James Lime formations may provide long-
term natural gas reserve and production growth potential in the future; however, we do not anticipate devoting drilling capital to these
formations until we see a sustained, meaningful improvement in the natural gas price environment. As of December 31, 2015,
substantially all of our acreage in our East Texas region is held by production.
Other (Colorado)
We hold approximately 16,100 gross (11,200 net) acres in the DJ Basin in Colorado (mostly in Adams and Weld counties).
There has been sporadic activity since 2011 in the vicinity of our Colorado acreage in pursuit of the Niobrara Shale oil formation.
Recent industry activity in the area has established that the application of horizontal drilling technology for oil in the shallower
Niobrara Shale may provide attractive return possibilities; however, the prospect for full-scale economic development of this play is
still uncertain due to the limited activity in the area and the current commodity price environment. Substantially all of our acreage in
the DJ Basin is held by production.
Other
As of December 31, 2015, we held approximately 15,400 gross (4,800 net) mostly undeveloped acres under lease in the
Tuscaloosa Marine Shale (“TMS”) and approximately 9,400 gross (6,400 net) acres in Southwest Louisiana, Mississippi, and North
Texas.
Impairment of Long-Lived Assets
We recognized approximately $285.9 million in non-cash impairment charges in 2015 primarily related to the reduction in
the estimated value of future net cash flows of the Company’s risk adjusted proved, probable and possible reserves (3P reserves) due
to the recent dramatic decline in commodity prices for crude oil and natural gas. Under Financial Accounting Standards Board
Accounting Codifications, an impairment charge is required when the unamortized capital cost of any individual property within the
Company’s producing property base exceeds the risked estimated future net cash flows from the 3P reserves for that property.
Substantially all of the impairment expense recognized during 2015 related to the onshore properties acquired via the Merger with
Crimson Exploration, Inc. in October 2013. Pursuant to accounting principles generally accepted in the United States of America
(“GAAP”) merger accounting rules, we were required to allocate the purchase price to the fair market value of the Crimson properties
as our capitalized producing property cost for each property, i.e. rather than Crimson’s actual unamortized cash historical finding and
development cost. The commodity price environment used for determining the fair market value of each property at the time of the
Merger was considerably higher than it is currently; therefore, we recorded an incremental $195.7 million in asset cost in excess of
Crimson’s unamortized capital cost (an upward purchase price adjustment “PPA”) for Crimson’s highest value properties, and that
incremental value has been subject to amortization post-merger. Approximately $64.6 million of the PPA for those properties has been
amortized post-merger through quarterly depreciation, depletion and amortization (“DD&A”), thereby reflecting a higher overall
DD&A rate than would have been recognized through amortization of the actual cash cost incurred in finding and developing those
assets. Substantially all of the impairment charge during 2015 is directly related to the decline in commodity prices and the resulting
impact on estimated future net cash flows from associated reserves. Approximately $235.8 million of the $285.9 million total
impairment is attributable to these properties, including approximately $131.1 million of which is the unamortized PPA recorded on
those properties as part of the merger accounting. Also included in the impairment charge for the year is approximately $10.0 million
related to producing property impairment and $9.3 million related to unproved lease cost amortization on our Elm Hill project in
Fayette and Gonzales counties, Texas.
If oil and/or natural gas prices decline further from prices at December 31, 2015, upon which the fourth quarter impairment
was calculated, we may be required to record additional non-cash impairment in the future, thereby impacting our financial results for
that period.
6
Onshore Investments
Kaybob Duvernay – Alberta, Canada
In 2011, we invested in Alta Resources Investments, LLC (“Alta”). On August 1, 2013, Alta sold its interest in the liquids-
rich Kaybob Duvernay Play in Alberta, Canada, where we had invested approximately $15.2 million, for approximately $30.5 million
net to us. Of this amount, we have received $28.5 million, and we expect to receive the remaining $2.0 million once approved by
Canadian regulatory officials.
Jonah Field – Sublette County, Wyoming
In April 2012, we, through our wholly-owned subsidiary, Contaro Company (“Contaro”), entered into a Limited Liability
Company Agreement (as amended, the “LLC Agreement”) in connection with the formation of Exaro. Pursuant to the LLC
Agreement, we have committed to invest up to $67.5 million in cash in Exaro for a 37% ownership interest. As of December 31, 2015,
we had invested approximately $46.9 million in Exaro. We account for Contaro’s ownership in Exaro using the equity method of
accounting, and therefore, do not include its share of individual operating results, reserves or production in those reported for our
consolidated results.
As of December 31, 2015, Exaro had 645 wells on production over its 5,760 gross acres (1,040 net acres), with a working
interest between 14.6% and 32.5%. These wells were producing at a rate of approximately 35.5 Mmcfe/d, net to Exaro. Due to the
persistent decline in natural gas prices, the operator does not expect to have any drilling rigs running on this project during 2016. For
the year ended December 31, 2015, Exaro recognized an impairment of its oil and gas properties as a result of the recent dramatic
decline in natural gas prices, and the Company recognized a net investment loss of approximately $30.6 million, net of tax benefit of
$16.5 million, as a result of its investment in Exaro. As of December 31, 2015, reserves attributable to our investment in Exaro were
38.7 Bcfe. We do not anticipate making any additional equity contributions during 2016 as Exaro estimates that working capital will
be funded through internally generated cash flow. See Note 11 to our Financial Statements - “Investment in Exaro Energy III LLC”
for additional details related to this investment.
Outlook
As a result of the dramatic downturn in crude oil, natural gas and natural gas liquids pricing in late 2014 through the present,
the negative impact of those price declines on the economics of most domestic resource plays, and the continuing uncertainty as to
when, or how much, the price environment might improve, our capital expenditure program for 2016 will be focused on: (i) the
preservation of our healthy financial position, including limiting our 2016 capital expenditure budget to a minimal amount; (ii)
focusing drilling expenditures, if any, on strategic projects only; (iii) identification of opportunities for cost efficiencies in all areas of
our operations; and (iv) continuing to identify new resource potential opportunities, internally and through acquisition. Our current
capital budget for 2016 should allow us to meet our contractual leasehold requirements, remain in position to preserve our term
acreage where appropriate, and maintain our strong financial profile. We will continuously monitor the commodity price environment,
stability and forecast, and, if warranted, make adjustments to that strategy as the year progresses. Our 2016 capital expenditure budget
is expected to be funded from internally generated cash flow and at least initially, will include the following:
Madison/Grimes counties, Southeast Texas – We forecast capital expenditures of approximately $1.0 million for extending,
leasing or re-leasing core acreage in this area.
Wyoming – We plan to complete the Christensen 1H well drilled in late 2015 in Weston County, targeting the Muddy Sandstone
formation, and estimate $2.0 million to extend a large portion of our leasehold position for an additional three to five years.
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
7
(other than a preliminary review of local records). Detailed investigations, including a title opinion rendered by a licensed independent
third party attorney, are typically made before commencement of drilling operations.
We have granted mortgage liens on substantially all of our natural gas and crude oil properties to secure our senior secured
revolving credit facility. These mortgages and the related credit agreement contain substantial restrictions and operating covenants that
are customarily found in credit agreements of this type. See Note 13 to our Financial Statements - “Long-Term Debt” for further
information.
Marketing and Pricing
We derive our revenue principally from the sale of natural gas and oil. As a result, our revenues are determined, to a large
degree, by prevailing natural gas and oil prices. We sell a portion of our natural gas production to purchasers pursuant to sales
agreements which contain a primary term of up to three years and crude oil and condensate production to purchasers under sales
agreements with primary terms of up to one year. The sales prices for natural gas are tied to industry standard published index prices,
subject to negotiated price adjustments, while the sale prices for crude oil are tied to industry standard posted prices subject to
negotiated price adjustments.
We typically utilize commodity price hedge instruments to minimize exposure to declining prices on our crude oil, natural
gas and natural gas liquids production, by using a series of swaps and/or costless collars. As of December 31, 2015, we had no
commodity price hedges in place. In January 2016, we entered into financial derivative contracts with a member of our bank group
resulting in 1,300,000 MMBtus of natural gas per month being hedged from February 2016 through July 2016 and November 2016
through December 2016 and 250,000 MMBtus of natural gas per month being hedged from August 2016 through October 2016
through swaps that provide for a fixed price of $2.53 per MMBtu on the contract volumes. Unrealized gains or losses associated with
hedges 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.
Decreases to commodity prices would adversely affect our revenues, profits and the value of our proved reserves.
Historically, the prices received for natural gas and oil have fluctuated widely. Among the factors that can cause these fluctuations are:
The domestic and foreign supply of natural gas and oil.
Overall economic conditions.
The level of consumer product demand.
Adverse weather conditions and natural disasters.
The price and availability of competitive fuels such as heating oil and coal.
Political conditions in the Middle East and other natural gas and oil producing regions.
The level of LNG imports/exports.
Domestic and foreign governmental regulations.
Special taxes on production.
The loss of tax credits and deductions.
Historically, we have been dependent upon a few purchasers for a significant portion of our revenue. Major purchasers of our
natural gas, oil and natural gas liquids for the year ended December 31, 2015, calculated on an equivalent basis, were ConocoPhillips
Company (48.3%), Sunoco Inc. (22.8%), Energy Transfer Company (5.5%), Shell Trading US Company (5.2%) and Exxon Mobil Oil
Corporation (5.1%). 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.
8
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.
The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage
for our drilling and development operations, locating and acquiring attractive producing oil and gas properties, and obtaining
purchasers and transporters for the natural gas and crude oil we produce. There is also competition between producers of natural gas
and crude oil and other industries producing alternative energy and fuel. Furthermore, competitive conditions may be substantially
affected by various forms of energy legislation and/or regulation considered from time to time by federal, state and local governments;
however, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon
our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or
producing natural gas and crude oil and may prevent or delay the commencement or continuation of a given operation. The effect of
these risks cannot be accurately predicted.
Governmental Regulations and Industry Matters
Industry Regulations
The availability of a ready market for crude oil, natural gas and natural gas liquids production depends upon numerous
factors beyond our control. These factors include regulation of crude oil, natural gas, and natural gas liquids production, federal, state
and local regulations governing environmental quality and pollution control, state limits on allowable rates of production by well or
proration unit, the amount of crude oil, natural gas and natural gas liquids available for sale, the availability of adequate pipeline and
other transportation and processing facilities, and the marketing of competitive fuels. For example, a productive natural gas well may
be “shut-in” because of an oversupply of natural gas or lack of an available natural gas pipeline in the area in which the well is
located. State and federal regulations generally are intended to prevent waste of crude oil, natural gas, and natural gas liquids, protect
rights to produce crude oil, natural gas and natural gas liquids between owners in a common reservoir, control the amount of crude oil,
natural gas and natural gas liquids produced by assigning allowable rates of production, and protect the environment. Pipelines are
subject to the jurisdiction of various federal, state and local agencies. We are also subject to changing and extensive tax laws, the
effects of which cannot be predicted.
The following discussion summarizes the regulation of the U.S. oil and gas industry. We believe that we are in substantial
compliance with the various statutes, rules, regulations and governmental orders to which our operations may be subject, although
there can be no assurance that this is or will remain the case. Moreover, such statutes, rules, regulations and government orders may be
changed or reinterpreted from time to time in response to economic or political conditions, and there can be no assurance that such
changes or reinterpretations will not materially adversely affect our results of operations and financial condition. The following
discussion is not intended to constitute a complete discussion of the various statutes, rules, regulations and governmental orders to
which our operations may be subject.
Regulation of Crude Oil, Natural Gas and Natural Gas Liquids Exploration and Production
Our operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes
requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the
location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled,
the plugging and abandoning of wells and the disposal of fluids used in connection with operations. Our operations are also subject to
various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and
the density of wells that may be drilled in and the unitization or pooling of crude oil and natural gas properties. In this regard, some
states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on
voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units, and therefore more
difficult to develop a project, if the operator owns less than 100% of the leasehold. In addition, state conservation laws, which
establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas and
impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of crude oil,
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
9
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.
Section 1(b) of the NGA exempts gas gathering facilities from the FERC's jurisdiction. We believe that the gas gathering
facilities we own meet the traditional tests the FERC has used to establish a pipeline system's status as a non-jurisdictional gatherer.
There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities. Moreover, the distinction between
FERC-regulated transmission services and federally unregulated gathering services is the subject of litigation from time to time, so the
classification and regulation of some of our gathering facilities may be subject to change based on future determinations by the FERC
and the courts. While we own some gas gathering facilities, we also depend on gathering facilities owned and operated by third parties
to gather production from our properties, and therefore, we are affected by the rates charged by these third parties for gathering
services. To the extent that changes in federal or state regulation affect the rates charged for gathering services, we also may be
affected by these changes. Accordingly, we do not anticipate that we would be affected any differently than similarly situated gas
producers.
Under the provisions of the Energy Policy Act of 2005 (the “2005 Act”), the NGA has been amended to prohibit market
manipulation by any person, including marketers, in connection with the purchase or sale of natural gas, and the FERC has issued
regulations to implement this prohibition. The Commodity Futures Trading Commission (the “CFTC”) also holds authority to monitor
certain segments of the physical and futures energy commodities market including oil and natural gas. With regard to physical
purchases and sales of natural gas and other energy commodities, and any related hedging activities that we undertake, we are thus
required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC. These agencies hold
substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation.
Under the 2005 Act, the FERC has also established regulations that are intended to increase natural gas pricing transparency
through, among other things, new reporting requirements and expanded dissemination of information about the availability and prices
of gas sold. For example, on December 26, 2007, FERC issued a final rule on the annual natural gas transaction reporting
requirements, as amended by subsequent orders on rehearing, or Order No. 704. Order No. 704 requires buyers and sellers of natural
gas above a de minimis level, including entities not otherwise subject to FERC jurisdiction, to submit on May 1 of each year an annual
report to FERC describing their aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the
extent such transactions utilize, contribute to or may contribute to the formation of price indices. Order No. 704 also requires market
participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s
policy statement on price reporting. It is the responsibility of the reporting entity to determine which individual transactions should be
reported based on the guidance of Order No. 704 as clarified in orders on clarification and rehearing. In addition, to the extent that we
enter into transportation contracts with interstate pipelines that are subject to FERC regulation, we are subject to FERC requirements
related to use of such interstate capacity. Any failure on our part to comply with the FERC’s regulations could result in the imposition
of civil and criminal penalties.
Our natural gas sales are affected by intrastate and interstate gas transportation regulation. Following the Congressional
passage of the Natural Gas Policy Act of 1978 (the “NGPA”), the FERC adopted a series of regulatory changes that have significantly
altered the transportation and marketing of natural gas. Beginning with the adoption of Order No. 436, issued in October 1985, the
FERC has implemented a series of major restructuring orders that have required interstate pipelines, among other things, to perform
“open access” transportation of gas for others, “unbundle” their sales and transportation functions, and allow shippers to release their
unneeded capacity temporarily and permanently to other shippers. As a result of these changes, sellers and buyers of gas have gained
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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
including the U.S.
the environment, or otherwise relating to environmental protection. Numerous governmental authorities,
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, which may cause us to incur significant capital expenditures or costly actions to
achieve and maintain compliance. Failure to comply with these laws and regulations may result in the assessment of administrative,
civil and criminal penalties, the imposition of remedial and corrective action obligations, the occurrence of delays or restrictions in
permitting or performance of projects 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 in environmental legislation and
regulations is to place more and stringent restrictions and limitations on activities that may affect the environment, which is expected
to result in increased costs of doing business and consequently affect profitability.
The Comprehensive Environmental Response, Compensation and Liability Act, as amended, (“CERCLA”), also known as
the “Superfund Law”, and similar state laws, impose strict joint and several 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
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disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances
released at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to
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,
allowing us to manage these wastes under RCRA’s less stringent non-hazardous waste requirements, we can provide no assurance that
this exemption will be preserved in the future. For example, in August 2015, several non-governmental organizations filed notice of
intent to sue the EPA under RCRA for, among other things, the agency’s alleged failure to reconsider whether such RCRA exclusion
should continue to apply. Any removal of this exclusion 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.
The Clean Air Act, as amended (the “CAA”), and comparable state laws 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.
Based on findings made by the EPA that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present
an endangerment to public health and the environment, the EPA adopted regulations under existing provisions of the CAA that,
among other things restrict emissions of GHGs from certain sources. These EPA regulations could adversely affect our operations and
restrict or delay our ability to obtain air permits for new or modified sources. 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 and reporting on GHG emissions from 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 to acquire and surrender emission allowances
in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be
adopted to address GHG emissions would impact our business, any such future federal laws or regulations that impose reporting
obligations on us with respect to, or require the elimination of GHG emissions from, our equipment or operations could require us to
incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.
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 an issued permit. Spill prevention, control and
countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the
contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. 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.
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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 (the
“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. Furthermore, there exists a growing concern that the injection of saltwater and other fluids
into belowground disposal wells triggers seismic activity in certain areas, including Texas, where we operate. In response to these
concerns, the Texas Railroad Commission (“TRC”) published a final rule governing permitting or re-permitting of disposal wells that
would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal
well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an
applicant of a disposal well fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates
such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRC may deny, modify, suspend or
terminate the permit application or existing operating permit for that well. These new seismic permitting requirements applicable to
disposal wells impose more stringent permitting requirements and likely to result in added costs to comply or, perhaps, may require
alternative methods of disposing of salt water and other fluids, which could delay production schedules and also result in increased
costs.
The Oil Pollution Act of 1990 (the “OPA”) and regulations thereunder impose a variety of regulations on “responsible
parties” related to the prevention of oil spills and liability for damages resulting from such spills in U.S. waters. The OPA applies to
vessels, onshore facilities, and offshore facilities, including exploration and production facilities that may affect waters of the United
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.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or crude oil
from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemical additives
under pressure into targeted subsurface formations to stimulate production. We routinely use hydraulic fracturing techniques in many
of our completion programs. Hydraulic fracturing typically is regulated by state oil and gas commissions, or other similar state
agencies, but several federal agencies have asserted regulatory authority over certain aspects of the process, including a suite of
proposed rulemakings and final rules issued by the EPA and the federal Bureau of Land Management (the “BLM”), which legal
requirements, to the extent in effect, may impose more stringent requirements relating to emissions and discharges from hydraulic
fracturing, chemical disclosures, and performances of fracturing activities on federal and Indian lands.
Congress has from time to time considered, but not enacted, legislation to provide for federal regulation of hydraulic
fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process while, at the state level, several states,
including Texas and Wyoming, where we operate, have adopted, and other states are considering adopting legal requirements that
could impose more stringent permitting, public disclosure, or well construction requirements on hydraulic fracturing activities. States
could elect to prohibit hydraulic fracturing altogether, following the lead of the State of New York. 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. 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,
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experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded
from drilling or completing wells.
In addition, certain governmental reviews are underway that focus on environmental aspects of hydraulic fracturing practices
including the EPA and the White House Council on Environmental Quality. These ongoing or any future studies, depending on their
degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing.
Oil and natural gas exploration, development and production activities on federal lands, including Indian lands and lands
administered by the BLM, are subject to the National Environmental Policy Act, as amended (“NEPA”). NEPA requires federal
agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact the environment. In the
course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and
cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be
made available for public review and comment. Governmental permits or authorizations that are subject to the requirements of NEPA
are required for exploration and development projects on federal and Indian lands. 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. Some of our facilities may be located in areas that are designated as habitat for
endangered or threatened species. If endangered species are located in areas of the underlying properties where we wish to conduct
seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed or expensive mitigation
may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September
2011, the U.S. Fish and Wildlife Service (the “FWS”) is required to make a determination on listing of numerous species as
endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. For example, in March 2014,
the FWS announced the listing of the lesser prairie chicken, whose habitat is over a five-state region, including Texas, where we
conduct operations, as a threatened species under the ESA. However, on September 1, 2015, the U.S. District Court for the Western
District of Texas vacated the FWS’ rule listing the lesser prairie chicken in its entirety, concluding that the decision to list the species
was arbitrary and capricious. Whether the lesser prairie chicken or other species will be listed in the future under the ESA is currently
unknown but the designation of previously unprotected species as threatened or endangered in areas where underlying property
operations are conducted could cause us to incur increased costs arising from species protection measures, time delays or limitations
on our drilling program activities, which costs delays or limitation could have an adverse impact on our ability to develop and produce
reserves.
We are subject to the requirements of the federal Occupational Safety and Health Act, as amended (“OSHA”), and
comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication
standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act
and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our
operations and that this information be provided to employees, state and local government authorities and citizens.
In response to the Deepwater Horizon drilling rig explosive incident and resulting oil spill in the United States Gulf of
Mexico in 2010, the Bureau of Ocean Energy Management (the “BOEM”) and the Bureau of Safety and Environmental Enforcement
(the “BSEE”), each agencies of the U.S. Department of the Interior, have imposed new and more stringent permitting procedures and
regulatory safety and performance requirements for new wells to be drilled in federal waters. In addition, states may adopt and
implement similar or more stringent legal requirements applicable to exploration and production activities in state waters. Compliance
with these more stringent regulatory restrictions, together with any uncertainties or inconsistencies in current decisions and rulings by
governmental agencies, delays in the processing and approval of drilling permits or exploration, development, oil spill-response and
decommissioning plans could adversely affect or delay new drilling and ongoing development efforts. In addition, new regulatory
initiatives may be adopted or enforced by the BOEM or the BSEE in the future that could result in additional delays, restrictions or
obligations with respect to oil and natural gas exploration and production operations conducted offshore. Any new rules, regulations or
legal initiatives could delay or disrupt our operations, increase the risk of expired leases due to the time required to develop new
technology, result in increased supplemental bonding requirements and limit activities in certain areas, or cause us to incur penalties,
14
fines, or shut-in production at one or more of our facilities. If the BOEM determines that increased financial assurance is required in
connection with our offshore facilities but we are unable to provide the necessary supplemental bonds or other forms of financial
assurance, the BOEM could impose monetary penalties or require our operations on federal leases to be suspended or cancelled. Also,
if material spill incidents similar to the Deepwater Horizon incident were to occur in the future, the United States could elect to again
issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental
laws and regulations regarding offshore oil and natural gas exploration and development, any of which developments could have a
material adverse effect on our business. Any one or more of the offshore-related matters described above could have a material
adverse effect on our business, financial condition and results of operations.
See “Item 1A. Risk Factors” for further discussion on hydraulic fracturing; ozone standards; climate change, including
methane or other greenhouse gas emissions; releases of regulated substances; and other aspects of compliance with legal requirements
or relating to environmental protection, including with respect to offshore leases.
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.
Whereas the BLM administers oil and natural gas leases held by the Company on federal onshore lands, 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 “OCS”). The Office of Natural Resources Revenue (the “ONRR”) collects 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
ONRR 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.
The BOEM is currently seeking to bolster its financial assurance requirements imposed on offshore operators on the OCS.
Although we believe we are currently in compliance with the supplemental bonding requirements, the BOEM may in the future
continue to review our plugging, abandonment, decommissioning and removal obligations; re-evaluate the adequacy of our financial
assurances; and require us to provide additional supplemental bonding or other surety for most or all of our properties. In August
2014, the BOEM issued an Advanced Notice of Proposed Rulemaking (“ANPR”) in which the agency indicated that it was
considering increasing the financial assurance requirements. While the BOEM has yet to propose rules pursuant to the ANPR, in
September 2015, it issued draft guidance (“Draft Guidance”) describing revised supplemental bonding procedures the agency plans to
use to impose financial assurance obligations for decommissioning activities on the OCS. The BOEM is also considering revising its
supplemental bonding procedures by shifting from the current “waiver” model for self-insurance to a credit-based model. The cost of
compliance with our existing supplemental bonding requirements or any other changes to the BOEM’s current bonding requirements
or regulations applicable to us or our properties could be substantial and could materially and adversely affect our financial condition,
cash flows, and results of operations. If we are unable to obtain any additional required bonds or assurances as requested, the BOEM
may require certain of our operations on federal leases to be suspended or cancelled or otherwise impose monetary penalties. See
“Item 1A. Risk Factors” for further discussion on decommissioning obligations on offshore leases.
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.
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We continuously monitor regulatory changes and regulatory responses and their impact on the insurance market and our
overall risk profile, and adjust our risk and insurance program to provide protection at a level that we can afford considering the cost
of insurance, against the potential and magnitude of disruption to our operations and cash flows. Changes in laws and regulations
regarding exploration and production activities in the Gulf of Mexico could lead to tighter underwriting standards, limitations on
scope and amount of coverage, and higher premiums, including possible increases in liability caps for claims of damages from oil
spills.
Health, Safety and Environmental Program
Our Health, Safety and Environmental (“HS&E”) Program is supervised by an operating committee of senior management to
insure compliance with all state and federal regulations. In support of the operating committee, we have contracted with J. Connor
Consulting (“JCC”) to coordinate the regulatory process relative to our offshore assets. JCC is a regulatory consulting firm
specializing in the offshore Gulf of Mexico. They provide preparation of incident response plans, safety and environmental services
and facilitation of comprehensive oil spill response training and drills on behalf of oil and gas companies and pipeline operators.
Additionally, in support of our Gulf of Mexico operations, we have established a Regional Oil Spill Plan which has been
approved by the BSEE. Our response team is trained annually and is tested through in-house spill drills. We have also contracted with
O’Brien’s Response Management (“O’Brien’s”), who maintains an incident command center on 24 hour alert in Slidell, LA. In the
event of an oil spill, the Company’s response program is initiated by notifying O’Brien’s of any incident while the Company response
team is mobilized to focus on source control and containment of the spill. O’Brien’s would coordinate communications with state and
federal agencies and would provide subject matter expertise in support of the response team.
We also have contracted with Clean Gulf Associates (“CGA”) to assist with equipment and personnel needs in the event of a
spill. CGA specializes in onsite control and cleanup and is on 24-hour alert with equipment currently stored at six bases along the gulf
coast (Ingleside and Galveston, TX; Lake Charles, Houma, and Venice, LA; and Pascagoula, MS). CGA is opening new sites in
Leeville, Morgan City and Harvey, LA. The CGA equipment stockpile is available to serve member oil spill response needs and
includes open seas skimmers, and shoreline protection boom, communications equipment, dispersants with application systems,
wildlife rehabilitation and a forward command center. CGA has retainers with aerial dispersant and mechanical recovery equipment
contractors for spill response.
In addition to our membership in CGA, the Company has contracted with Wild Well Control for source control at the
wellhead, if required. Wild Well Control is one of the world’s leading providers of firefighting and well control services.
We also have a full time health, safety and environmental professional who supports our operations and oversees the
implementation of our onshore HS&E policies.
Safety and Environmental Management System
We have developed and implemented a Safety and Environmental Management System (“SEMS”) to address oil and gas
operations in the OCS, as required by the BSEE. Our SEMS identifies and mitigates safety and environmental hazards and the impacts
of these hazards on design, construction, start-up, operation, inspection, and maintenance of all new and existing facilities. The
Company has established goals, performance measures, training and accountability for SEMS implementation. We also provide the
necessary resources to maintain an effective SEMS and we review the adequacy and effectiveness of the SEMS program annually.
Company facilities are designed, constructed, maintained, monitored, and operated in a manner compatible with industry codes,
consensus standards, and all applicable governmental regulations. We have contracted with Island Technologies Inc. to coordinate our
SEMS program and to track compliance for production operations.
The BSEE enforces the SEMS requirements through regular audits. Failure of an audit may result in an Incident of Non-
Compliance and could ultimately require a shut-in our Gulf of Mexico operations if not resolved within the required time.
Employees
On December 31, 2015, we had 73 full time employees, of which 24 were field personnel. We have been able to attract and
retain a talented team of industry professionals that have been successful in achieving significant growth and success in the past. As
such, we are well-positioned to adequately manage and develop our existing assets and also to increase our proved reserves and
16
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.
In addition to our employees, we use the services of independent consultants and contractors to perform various professional
services. As a working interest owner, we rely on certain outside operators to drill, produce and market our natural gas and oil where
we are a non-operator. In prospects where we are the operator, we rely on drilling contractors to drill and sometimes rely on
independent contractors to produce and market our natural gas and oil. In addition, we frequently utilize the services of independent
contractors to perform field and on-site drilling and production operation services and independent third party engineering firms to
evaluate our reserves.
Directors and Executive Officers
See “Item 10. Directors, Executive Officers and Corporate Governance”, which information is incorporated herein by
reference.
Corporate Offices
Effective October 1, 2013, we moved our corporate offices to 717 Texas Avenue in downtown Houston, Texas, under a lease
that expires March 31, 2019. Rent, including parking, related to this office space for the year ended December 31, 2015 was
approximately $2.2 million. We remained responsible for the rent at our previous corporate office at 3700 Buffalo Speedway in
Houston, Texas, through February 29, 2016, at which time the lease expired. Effective January 1, 2014, we subleased our previous
corporate offices through expiration and expect to recover the substantial majority of the rent we paid for that location.
Code of Ethics
We adopted a Code of Ethics for senior management in December 2002. In January 2014, our board of directors adopted a
new Code of Business Conduct and Ethics ("Code of Conduct") that applies to all directors, officers and employees of the Company.
Our Code of Conduct is available on the Company's website at www.contango.com. Any shareholder who so requests may obtain a
copy of the Code of Conduct by submitting a request to the Company's corporate secretary at the address on the cover of this Form 10-
K. Changes in and waivers to the Code of Conduct for the Company's directors, chief executive officer and certain senior financial
officers will be posted on the Company's website within five business days and maintained for at least 12 months. Information on our
website or any other website is not incorporated by reference into, and does not constitute a part of, this Report on Form 10-K.
Available Information
You may read and copy all or any portion of this report on Form 10-K, our quarterly reports on Form 10-Q and current
reports on Form 8-K, as well as any amendments and exhibits to those reports, without charge at the office of the Securities and
Exchange Commission (the “SEC”) in Public Reference Room, 100 F Street NE, Washington, DC, 20549. Information regarding the
operation of the public reference rooms may be obtained by calling the SEC at 1-800-SEC-0330. In addition, filings made with the
SEC electronically are publicly available through the SEC's website at http://www.sec.gov, and we make these documents available
free of charge at our website at http://www.contango.com as soon as reasonably practicable after they are filed or furnished with the
SEC. This report on Form 10-K, 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, 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
continued 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. Natural gas and crude
oil prices declined severely during 2015 and have declined even further through 2016 to date. 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 also affect the amount of natural gas and oil that we can economically produce.
Factors that can cause price fluctuations include:
Overall economic conditions, domestic and global.
The domestic and foreign supply of natural gas and oil.
The level of consumer product demand.
Adverse weather conditions and natural disasters.
The price and availability of competitive fuels such as LNG, heating oil and coal.
Political conditions in the Middle East and other natural gas and oil producing regions.
The level of LNG imports and any LNG exports.
Domestic and foreign governmental regulations.
Special taxes on production.
Access to pipelines and gas processing plants.
The loss of tax credits and deductions.
A substantial or extended decline in natural gas and oil prices could have a material adverse effect on our access to capital
and the quantities of natural gas and oil that may be economically produced by us. The Company may utilize financial derivative
contracts, such as swaps, costless collars and puts on commodity prices, to reduce exposure to potential declines in commodity prices.
As of December 31, 2015, we did not have derivative arrangements in place on any post-2015 production. During January 2016, we
entered into financial derivative contracts with a member of our bank group resulting in 1,300,000 MMBtus of natural gas per month
being hedged from February 2016 through July 2016, and from November 2016 through December 2016, and 250,000 MMBtus of
natural gas per month being hedged from August 2016 through October 2016 through swaps that provide for a fixed price of $2.53 per
MMBtu on the contract volumes.
Part of our strategy involves drilling in new or emerging plays; therefore, our drilling results in these areas are not certain.
The results of our drilling in new or emerging plays, such as in our South Texas and Wyoming resource plays, are more
uncertain than drilling results in areas that are more developed and with longer production history. Since new or emerging plays and
new formations have limited production history, we are less able to use past drilling results in those areas to help predict our future
drilling results. The ultimate success of these drilling and completion strategies and techniques in these formations will be better
evaluated over time as more wells are drilled and production profiles are better established. Accordingly, our drilling results are
subject to greater risks in these areas and could be unsuccessful. We may be unable to execute our expected drilling program in these
areas because of disappointing drilling results, capital constraints, lease expirations, access to adequate gathering systems or pipeline
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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.
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/or 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 currently available under our senior secured revolving credit agreement. As part of the regular
redetermination schedule, the borrowing base on our revolving credit agreement was redetermined at $225 million effective May 8,
2015, and $190 million effective November 13, 2015 due primarily to lower commodity prices and the impact of the significant
reduction in the Company’s drilling program in 2015. Since the last regularly scheduled redetermination of our borrowing base,
effective through May 1, 2016, commodity prices have continued to decline. The decline in prices will likely negatively impact the
price decks utilized by banks in their calculation of the Company’s borrowing base at May 1, 2016. It is not possible to forecast what
that adjustment to the borrowing base might be at that time, and because of that uncertainty, the Company has currently limited its
planned 2016 capital expenditure budget to a level that is below our projected internally generated cash flows, thereby allowing for the
repayment of a portion of the outstanding debt under our revolving credit facility. See “Item 7. Management’s Discussion and
Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity.”
In addition, our ability to comply with the financial and other restrictive covenants in our indebtedness is unceratain and will
be affected by our future performance and events or circumstances beyond our control. Failure to comply with these covenants could
result in an event of default under such indebtedness and the potential foreclosure on the collateral securing such debt, and could cause
a cross-default under any of our other outstanding indebtedness.
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
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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 rely on third-party operators to operate and maintain some of our wells, production platforms, pipelines and processing
facilities and, as a result, we have limited control over the operations of such facilities. The interests of an operator may differ
from our interests.
We depend upon the services of third-party operators to operate some production platforms, pipelines, gas processing
facilities and the infrastructure required to produce and market our natural gas, condensate and oil. We have limited influence over the
conduct of operations by third-party operators. As a result, we have little control over how frequently and how long our production is
shut-in when production problems, weather and other production shut-ins occur. Poor performance on the part of, or errors or
accidents attributable to, the operator of a project in which we participate may have an adverse effect on our results of operations and
financial condition. Also, the interest of an operator may differ from our interests.
Failure of our working interest partners to fund their share of development costs could result in the delay or cancellation of
future projects, which could have a materially adverse effect on our financial condition and results of operations.
Natural gas and crude oil prices declined significantly during 2015 and have declined even further through 2016 to date. An
extended or more severe downturn could have material adverse effects on the liquidity of our working interest partners. Our working
interest partners must be able to fund their share of investment costs through cash flow from operations, external credit facilities, or
other sources. If our partners are not able to fund their share of costs, it could result in the delay or cancellation of future projects,
resulting in a reduction of our reserves and production, which could have a materially adverse effect on our financial condition and
results of operations.
We are exposed to the credit risks of our customers and derivative counterparties, and any material nonpayment or
nonperformance by our customers or derivative counterparties could have a materially adverse effect on our financial
condition and results of operations.
We are subject to risks of loss resulting from nonpayment or nonperformance by our customers, which risks may increase
during periods of economic uncertainty. Furthermore, some of our customers may be highly leveraged and subject to their own
operating and regulatory risks, which increases the risk that they may default on their obligations to us. To the extent one or more of
our significant customers is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject
to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. In addition, our risk management
activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the
terms of the derivative instruments are imperfect, and our risk management policies and procedures are not properly followed. Any
material nonpayment or nonperformance by our customers or our derivative counterparties could have a materially adverse effect on
our financial condition and results of operations.
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.
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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 16% of our total estimated proved reserves at December 31, 2015 were proved undeveloped reserves. The
development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital
expenditures that we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately
developed or produced.
Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The
reserve data included in the reserve 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. Delays in the development of our reserves, increases in costs to
drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped
reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition,
delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.
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The present value of future net cash flows from our proved reserves will not necessarily be the same as the current market
value of our estimated crude oil, natural gas and natural gas liquids reserves.
You should not assume that the present value of future net revenues from our proved reserves referred to in this report is the
current market value of our estimated crude oil, natural gas and natural gas liquids reserves. In accordance with the requirements of
the SEC, the estimated discounted future net cash flows from our proved reserves are based on prices and costs on the date of the
estimate, held flat for the life of the properties. Actual future prices and costs may differ materially from those used in the present
value estimate. The present value of future net revenues from our proved reserves as of December 31, 2015 was based on the 12-
month unweighted arithmetic average of the first-day-of-the-month price for the period January through December 2015. For our
condensate and natural gas liquids, the average West Texas Intermediate (Cushing) posted price was $50.28 per barrel for offshore
volumes and the average West Texas Intermediate (Plains) posted price was $46.79 per barrel for onshore volumes. For our natural
gas, the average Henry Hub spot price was $2.587 per MMBtu for offshore volumes and the average Henry Hub spot price was $2.587
per MMBtu for onshore volumes. Assuming strip pricing as of March 1, 2016 through 2020 and keeping pricing flat thereafter, instead
of 2015 SEC pricing, while leaving all other parameters unchanged, the Company’s proved reserves would have been 185.4 Bcfe and
the PV-10 value of proved reserves would have been $226.3 million. Any adjustments to the estimates of proved reserves or decreases
in the price of crude oil or natural gas may decrease the value of our common stock. A reconciliation of our Standardized Measure to
PV-10 is provided under "Item 2. Properties – PV-10".
Actual future net cash flows will also be affected by increases or decreases in consumption by oil and gas purchasers and
changes in governmental regulations or taxation. The timing of both the production and the incurrence of expenses in connection with
the development and production of oil and gas properties affects the timing of actual future net cash flows from proved reserves. The
effective interest rate at various times and the risks associated with our business or the oil and gas industry in general will affect the
accuracy of the 10% discount factor.
Our use of 2D and 3D seismic data is subject to interpretation and may not accurately identify the presence of crude oil,
natural gas and natural gas liquids. In addition, the use of such technology requires greater predrilling expenditures, which
could adversely affect the results of our drilling operations.
Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through
geophysical and geological analyses, production data and engineering studies, the results of which are uncertain. For example, we
have over 4,000 square miles of 3D data in the South Texas and Gulf Coast regions. However, even when used and properly
interpreted, 3D seismic data and visualization techniques only assist geoscientists and geologists in identifying subsurface structures
and hydrocarbon indicators. They do not allow the interpreter to know if hydrocarbons are present or producible economically. Other
geologists and petroleum professionals, when studying the same seismic data, may have significantly different interpretations than our
professionals.
In addition, the use of 3D seismic and other advanced technologies requires greater predrilling expenditures than traditional
drilling strategies, and we could incur losses due to such expenditures. As a result, our drilling activities may not be geologically
successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area may not
improve.
Drilling for and producing crude oil, natural gas and natural gas liquids are high risk activities with many uncertainties that
could adversely affect our business, financial condition or results of operations.
Our drilling and operating activities are subject to many risks, including the risk that we will not discover commercially
productive reservoirs. Drilling for crude oil, natural gas and natural gas liquids can be unprofitable, not only from dry holes, but from
productive wells that do not produce sufficient revenues to return a profit. In addition, our drilling and producing operations may be
curtailed, delayed or canceled as a result of other factors, including:
unusual or unexpected geological formations and miscalculations;
pressures;
fires;
explosions and blowouts;
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pipe or cement failures;
environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring
radioactive materials, and unauthorized discharges of toxic gases, brine, well stimulation and completion fluids, or other
pollutants into the surface and subsurface environment;
loss of drilling fluid circulation;
title problems;
facility or equipment malfunctions;
unexpected operational events;
shortages of skilled personnel;
shortages or delivery delays of equipment and services or of water used in hydraulic fracturing activities;
compliance with environmental and other regulatory requirements;
natural disasters; and
adverse weather conditions.
Any of these risks can cause substantial losses, including personal injury or loss of life; severe damage to or destruction of
property, natural resources and equipment, pollution, environmental contamination, clean-up responsibilities, loss of wells, repairs to
resume operations; and regulatory fines or penalties.
Insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe
that the cost of available insurance is excessive relative to the perceived risks presented. We carry limited environmental insurance,
thus, losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of
an event that is not covered in full or in part by insurance could have a material adverse impact on our business activities, financial
condition and results of operations.
The potential lack of availability of, or high cost of, drilling rigs, equipment, supplies, personnel and crude oil field services
could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget.
When the prices of crude oil, natural gas and natural gas liquids increase, or the demand for equipment and services is greater
than the supply in certain areas, we typically encounter an increase in the cost of securing drilling rigs, equipment and supplies. In
addition, larger producers may be more likely to secure access to such equipment by offering more lucrative terms. If we are unable to
acquire access to such resources, or can obtain access only at higher prices, our ability to convert our reserves into cash flow could be
delayed and the cost of producing those reserves could increase significantly, which would adversely affect our results of operations
and financial condition.
Our hedging activities could result in financial losses or reduce our income.
To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of crude oil, natural
gas and natural gas liquids, as well as interest rates, we have, and may in the future, enter into derivative arrangements for a portion of
our crude oil, natural gas and/or natural gas liquids production and our debt that could result in both realized and unrealized hedging
losses. We typically utilize financial instruments to hedge commodity price exposure to declining prices on our crude oil, natural gas
and natural gas liquids production. We typically use a combination of puts, swaps and costless collars. As of December 31, 2015, we
did not have any derivatives in place. In January 2016, we entered into financial derivative contracts with a member of our bank group
resulting in 1,300,000 MMBtus of natural gas per month being hedged from February 2016 through July 2016, and from November
2016 through December 2016, and 250,000 MMBtus of natural gas per month being hedged from August 2016 through October 2016
through swaps that provide for a fixed price of $2.53 per MMBtu on the contract volumes.
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
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underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging
activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually
increase the volatility of our cash flows.
The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the
effect of commodity price, interest rate, and other risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in 2010, established federal
oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-
Frank Act requires the Commodities Futures Trading Commission (CFTC) and the SEC to promulgate rules and regulations
implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented
and it is not possible at this time to predict when this will be accomplished.
In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major
energy markets and for swaps that are their economic equivalents. The initial position-limits rule was vacated by the U.S. District
Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place
limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to
exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions
on us is uncertain at this time.
The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules
also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take
steps to qualify for an exemption to such requirements. Although we expect to qualify for the end-user exception from the mandatory
clearing requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution
requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for
hedging. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support
documentation and/or post initial and variation margin. Posting of collateral could impact liquidity and reduce cash available to us for
capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows. The proposed margin rules
are not yet final, and therefore the impact of those provisions on us is uncertain at this time. The Dodd-Frank Act and regulations may
also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which
may not be as creditworthy as the current counterparties.
The full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be known until the
regulations are implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and regulations could
significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of
derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts or
increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and
regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely
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.
If prices remain at current levels or decline further, we will likely incur substantial further 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 further in 2016 as they have done in 2014 and 2015, we will likely be required to record further 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
24
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 cost 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 greenhouse gases (“GHGs”) could result in
increased operating costs and reduced demand for the oil and natural gas that we produce.
Based on findings that emissions of GHGs present an endangerment to public health and the environment, the EPA has
adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration
(“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that already are
potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG
emissions also will be required to meet “best available control technology” standards that typically will be established by the states. In
addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified sources in the
United States, including, among others, certain oil and natural gas production facilities, 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 to acquire and surrender emission allowances
in return for emitting those GHGs. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise
restricts emissions of GHGs from our equipment and operations could require us to incur increased operating costs, such as costs to
purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting
requirements, including the imposition of a carbon tax. For example, in August 2015, the EPA announced proposed rules, expected to
be finalized in 2016, that would establish new controls for methane emissions from certain new, modified or reconstructed equipment
and processes in the oil and natural gas source category, including production activities, as part of an overall effort to reduce methane
emissions by up to 45 percent in 2025. On an international level, the United States is one of almost 200 nations that agreed in
December 2015 to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions
targets and be transparent about the measures each country will use to achieve its GHG emissions targets. Although it is not possible
at this time to predict how new methane restrictions would impact our business or how or when the United State might impose
restrictions on GHGs as a result of the international agreement agreed to in Paris, any new legal requirements that impose more
stringent requirements on the emission of GHGs from our operations could result in increased compliance costs or additional
operating restrictions, which could have an adverse effect on our business, financial condition and results of operations. Moreover,
25
such new legislation or regulatory programs could also increase the cost to the consumer, and thereby reduce demand for oil and gas,
which could reduce the demand for the oil and natural gas 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.
Should we fail to comply with all applicable statutes, rules, regulations and orders of the FERC, the CFTC, or the FTC, we
could be subject to substantial penalties and fines.
Section 1(b) of the NGA exempts natural gas gathering facilities from FERC’s jurisdiction. We believe that the gas gathering
facilities we own meet the traditional tests the FERC has used to establish a pipeline system’s status as a non-jurisdictional gatherer.
Under the 2005 Act and implementing regulations, the FERC prohibits market manipulation in connection with the purchase or sale of
natural gas. The CFTC has similar authority under the Commodity Exchange Act and regulations it has promulgated thereunder with
respect to certain segments of the physical and futures energy commodities market including oil and natural gas. The FTC also
prohibits manipulative or fraudulent conduct in the wholesale petroleum market with respect to sales of commodities, including crude
oil, condensate and natural gas liquids. These agencies have substantial enforcement authority, including the ability to impose
penalties for current violations of up to $1 million per day for each violation. The FERC has also imposed requirements related to
reporting of natural gas sales volumes that may impact the formation of prices indices. Additional rules and legislation pertaining to
these and other matters may be considered or adopted from time to time. Our failure to comply with these or other laws and
regulations administered by these agencies could subject us to criminal and civil penalties, as described in Part I, Item 1: “Business—
Governmental Regulations and Industry Matters.”
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:
Blowouts, fires and explosions.
Surface cratering.
Uncontrollable flows of underground natural gas, oil or formation water.
Natural disasters.
Pipe and cement failures.
Casing collapses.
Stuck drilling and service tools.
Reservoir compaction.
Abnormal pressure formations.
Environmental hazards such as natural gas leaks, oil spills, pipeline and tank ruptures or unauthorized discharges of
brine, toxic gases or well fluids.
Capacity constraints, equipment malfunctions and other problems at third-party operated platforms, pipelines and gas
processing plants over which we have no control.
Repeated shut-ins of our well bores could significantly damage our well bores.
Required workovers of existing wells that may not be successful.
If any of the above events occur, we could incur substantial losses as a result of:
Injury or loss of life.
Reservoir damage.
Severe damage to and destruction of property or equipment.
Pollution and other environmental and natural resources damage.
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Restoration, decommissioning or clean-up responsibilities.
Regulatory investigations and penalties.
Suspension of our operations or repairs necessary to resume operations.
Offshore operations are subject to a variety of operating risks peculiar to the marine environment, such as capsizing and
collisions. In addition, offshore operations, and in some instances operations along the Gulf Coast, are subject to damage or loss from
hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production.
As a result, we could incur substantial liabilities that could reduce the funds available for exploration, development or leasehold
acquisitions, or result in loss of properties.
If we were to experience any of these problems, it could affect well bores, platforms, gathering systems and processing
facilities, any one of which could adversely affect our ability to conduct operations. In accordance with customary industry practices,
we maintain insurance against some, but not all, of these risks. Losses could occur for uninsurable or uninsured risks or in amounts in
excess of existing insurance coverage. We may not be able to maintain adequate insurance in the future at rates we consider
reasonable, and particular types of coverage may not be available. An event that is not fully covered by insurance could have a
material adverse effect on our financial position and results of operations.
Our ability to market our natural gas and oil may be impaired by capacity constraints and equipment malfunctions on the
platforms, gathering systems, pipelines and gas plants that transport and process our natural gas and oil.
All of our natural gas and oil is transported through gathering systems, pipelines and processing plants. Transportation
capacity on gathering system pipelines and platforms is occasionally limited and at times unavailable due to repairs or improvements
being made to these facilities or due to capacity being utilized by other natural gas or oil shippers that may have priority transportation
agreements. If the gathering systems, processing plants, platforms or our transportation capacity is materially restricted or is
unavailable in the future, our ability to market our natural gas or oil could be impaired and cash flow from the affected properties
could be reduced, which could have a material adverse effect on our financial condition and results of operations. Further, repeated
shut-ins of our wells could result in damage to our well bores that would impair our ability to produce from these wells and could
result in additional wells being required to produce our reserves.
If our access to sales markets is restricted, it could negatively impact our production, our income and ultimately our ability to
retain our leases.
Market conditions or the unavailability of satisfactory crude oil, natural gas and natural gas liquids transportation
arrangements may hinder our access to crude oil, natural gas and natural gas liquids markets or delay our production. The availability
of a ready market for our crude oil, natural gas and natural gas liquids production depends on a number of factors, including the
demand for and supply of crude oil, natural gas and natural gas liquids and the proximity of reserves to pipelines and terminal
facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems,
pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could
materially harm our business. Our productive properties may be located in areas with limited or no access to pipelines, thereby
necessitating delivery by other means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our
crude oil, natural gas and natural gas liquids may have several adverse effects, including higher transportation costs, fewer potential
purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production
from a particular lease for an extended time, possible loss of a lease due to lack of production.
We may not have title to our leased interests and if any lease is later rendered invalid, we may not be able to proceed with our
exploration and development of the lease site.
Our practice in acquiring exploration leases or undivided interests in natural gas and oil leases is to not incur the expense of
retaining title lawyers to examine the title to the mineral interest prior to executing the lease. Instead, we rely upon the judgment of
consultants and others to perform the field work in examining records in the appropriate governmental, county or parish clerk’s office
before leasing a specific mineral interest. This practice is widely followed in the industry. Prior to the drilling of an exploration well
the operator of the well will typically obtain a preliminary title review of the drillsite lease and/or spacing unit within which the
proposed well is to be drilled to identify any obvious deficiencies in title to the well and, if there are deficiencies, to identify measures
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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.
Proposed U.S. federal budgets and pending legislation contain certain provisions that, if passed as originally submitted, will
have an adverse effect on our financial position, results of operations, and cash flows.
The federal administration has released repeated budget proposals over the past few years which include numerous proposed
tax changes. The proposed budgets and legislation would repeal many tax incentives and deductions that are currently used by oil and
gas companies in the United States and impose new taxes. Among others, the provisions include: elimination of the ability to fully
deduct intangible drilling costs in the year incurred; repeal of the percentage depletion deduction for oil and gas properties; repeal of
the manufacturing tax deduction for oil and gas companies; increase in the geological and geophysical amortization period for
independent producers; and implementation of a fee on non-producing leases located on federal lands. Should some or all of these
provisions become law, taxes on the E&P industry would increase, which could have a negative impact on our results of operations
and cash flows. Although these proposals initially were made in 2009, none have become law. It is still, however, the federal
administration’s stated intention to enact legislation to repeal tax incentives and deductions and impose new taxes on oil and gas
companies.
We are subject to stringent laws and regulations, including environmental requirements that can adversely affect the cost,
manner or feasibility of doing business.
Our oil and natural gas exploration, development and production operations are subject to stringent federal, regional, 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
sanctions, including administrative, civil and criminal penalties, investigatory, remedial and corrective action obligations, the
occurrence of delays or restrictions in permitting or performance of projects and the issuance of orders limiting or prohibiting some or
all of our operations in affected areas. 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.
Impose substantial penalties for pollution resulting from drilling and production operations.
Under these laws and regulations, we could be liable for personal injury and clean-up costs and other environmental natural
resource and property damages. We maintain insurance coverage for sudden and accidental environmental damages; however, it is
possible that coverage might not be sufficient in a catastrophic event. Accordingly, we may be subject to liability, or we may be
required to cease production from properties in the event of environmental damages. The trend in environmental laws and regulations
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is to place more stringent restrictions and limitations on activities that may affect the environment. For example, in October 2015, the
EPA issued a final rule lowering the National Ambient Air Quality Standard for ground-level ozone to 70 parts per billion for the 8-
hour primary and secondary ozone standards. The EPA is required to make attainment and non-attainment designations for specific
geographic locations under the revised standards by October 1, 2017. With EPA lowering the ground-level ozone standard, states may
be required to implement more stringent regulations, which could apply to our operations and require the installation of , resulting in a
need to install new emissions controls, longer permitting timelines and significant increases in our capital or operating expenditures.
In another example, the EPA issued a final rule in May 2015 that attempts to clarify the federal jurisdictional reach over waters of the
United States but this rule has been stayed nationwide by the U.S. Sixth Circuit Court of Appeals as that appellate court and numerous
district courts ponder lawsuits opposing implementation of the rule. To the extent the rule expands the scope of the Clean Water Act’s
jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.
Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, we can
provided no assurance that our future compliance with existing laws and regulations, these recently adopted rulemakings, or any new
or amended legal requirements will not have a material adverse effect on our business, financial condition and results of operations.
An accidental release of pollutants into the environment may cause us to incur significant costs and liabilities.
We may incur significant environmental costs liabilities in our business as a result of our handling of petroleum hydrocarbons
and wastes, because of air emissions and waste water discharges related to our operations, and due to historical industry operations
and waste disposal practices. We currently own, operate or lease numerous properties that for many years have been used for the
exploration and production of crude oil and natural gas. 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. An accidental release such, for example,
while drilling a well, could subject us to substantial liabilities arising from environmental cleanup, restoration costs and natural
resource damages, claims made by neighboring landowners and other third parties for personal injury and property and natural
resource damages as well as monetary fines or penalties for related violations of environmental laws or regulations. Moreover, certain
environmental statutes impose strict, joint and several liability for these costs and liabilities without regard to fault or the legality of
our conduct. Under these environmental laws and regulations, we could be required to remove 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 or other decommissioning activities to prevent future contamination. We may not be
able to recover some or any of these costs from insurance.
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 crude oil
from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under
pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic
fracturing techniques in many of our drilling and completion programs. Hydraulic fracturing typically is regulated by state oil and
natural gas commissions, or other similar state agencies, but several federal agencies have asserted regulatory authority over certain
aspects of the process. For example, the EPA issued CAA final regulations in 2012 and proposed additional CAA regulations in
August 2015 governing performance standards for the oil and natural gas industry; proposed in April 2015 effluent limitations
guidelines that waste water from shale natural gas extraction operations must meet before discharging to a treatment plant; and issued
in 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the
chemical substances and mixtures used in hydraulic fracturing. Also, the BLM published a final rule in March 2015 that establishes
new or more stringent standards for performing hydraulic fracturing on federal and Indian lands but, in September 2015, the U.S.
District Court of Wyoming issued a preliminary injunction barring implementation of this rule, which order the BLM could appeal and
is being separately appealed by certain environmental groups. Moreover, from time to time, Congress has considered, but not enacted,
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, certain states, including Texas and Wyoming, where we conduct operations, have adopted
and other states are considering adopting legal requirements that could impose new or more stringent permitting, public disclosure,
and well construction requirements on hydraulic fracturing activities. States could elect to prohibit hydraulic fracturing altogether,
following the approach of the State of New York in 2015. 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
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event that new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in
areas where we currently or in the future plan to operate, we could incur potentially significant added costs to comply with such
requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even
be precluded from drilling wells.
In addition, certain governmental reviews are underway that focus on environmental aspects of hydraulic fracturing practices.
The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices.
Also, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources in June 2015,
which report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water sources in
the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential
to impact drinking water sources. However, in January 2016, the EPA’s Science Advisory Board provided its comments on the draft
study, indicating its concern that EPA’s conclusion of no widespread, systemic impacts on drinking water sources arising from
fracturing activities did not reflect the uncertainties and data limitations associated with such impacts, as described in the body of the
draft report. The final version of this EPA report remains pending and is expected to be completed in 2016. Such EPA final report,
when issued, as well as any future studies, depending on their degree of pursuit and any meaningful results obtained, could spur
initiatives to further regulate hydraulic fracturing.
We may be subject to increased supplemental bonding under the BOEM financial assurance requirements.
Energy companies conducting oil and natural gas lease operations offshore on the OCS are required by the BOEM, among
other obligations, to conduct decommissioning within specified times following cessation of offshore producing activities, which
decommissioning includes the plugging of wells, removal of platforms and other facilities, and the clearing of obstacles from the lease
site sea floor. To cover a lease operator’s decommissioning obligations, the BOEM generally requires that lessees demonstrate
financial strength and reliability according to regulations or otherwise post bonds or other acceptable financial assurances that such
future obligations will be satisfied. As an operator, we are required to post surety bonds of $200,000 per lease for exploration and
$500,000 per lease for developmental activities as part of our general bonding requirements, as well as the posting of additional
supplemental bonds to cover, among other things, our decommissioning obligations. We typically post surety bonds with the BOEM
to satisfy our general and supplemental bonding requirements.
In recent years, the BOEM has sought to bolster its financial assurance requirements imposed on offshore operators on the
OCS. For example, in August 2014, the BOEM published an Advance Notice of Proposed Rulemaking (“ANPR”), pursuant to which
it seeks to bolster its current bonding requirements established under its rules. While the BOEM is yet to propose rules pursuant to the
ANPR, in September 2015, it issued draft guidance (“Draft Guidance”) describing revised supplemental bonding procedures the
agency plans to use to impose financial assurance obligations for decommissioning activities on the OCS. Once the Draft Guidance is
finalized, the BOEM will issue these supplemental bonding changes in a revised notice to lessees (“NTL”) that will replace an existing
2008 NTL that covers supplemental bonding requirements and related exemptions regarding such external financial assurances.
Among other things, the Draft Guidance proposes to eliminate a “waiver” exemption currently allowed by the BOEM, whereby
operators on the OCS meeting certain relatively large net worth and other criteria have the option of being exempted from posting
supplemental bonds or other acceptable financial assurances for such operator’s decommissioning obligations. Under the existing
2008 NTL, qualifying operators may self-insure to meet supplemental bonding requirements, but only to the extent the estimated
cumulative decommissioning liability is no more than 50% of the operator’s net worth. Under the Draft Guidance, this waiver option
would be eliminated and qualifying operators would only be able to self-insure for an amount that is no more than 10% of their
tangible net worth. In addition, the Draft Guidance would implement a phase-in period for establishing compliance with supplemental
bonding obligations, whereby operators may seek payment of estimated costs of decommissioning obligations owed under a “tailored
plan” that is approved by the BOEM and would require payment of the supplemental bonding amount in three approximately equal
installments during a one year period from the date of BOEM approval of the tailored plan. It is expected that the revised NTL will be
issued by the BOEM by summer 2016. While we have satisfied past secondary bonding obligations imposed by the BOEM, the
revised NTL, once it is issued and implemented by the BOEM, could result in our having to post additional supplemental bonds to the
extent that we no longer have the opportunity to obtain waivers from supplemental bonding. The cost of posting additional
supplemental bonds or other financial assurances can be substantial, and there is no assurance that they can be obtained in all cases.
Obtaining such bonds may require us to provide other financial assurances to the surety company, such as bank letters of credit, which
can limit available liquidity.
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Moreover, notwithstanding any issuance of a revised NTL, the effect of the significant reduction in oil and natural gas pricing
since mid-2014 on operators of, and other owners of interests in, offshore federal leases has impacted the BOEM’s financial assurance
determinations with respect to such operators and owners. In those cases where the BOEM determines that a company can no longer
demonstrate the requisite financial strength and reliability to maintain a waiver from supplemental bonding, the BOEM may direct
such operator to relinquish such waiver and instead post increased supplemental bonding amounts. In the event any such increases in
supplemental bonding were required of us, such increases could have a material adverse effect on our business, prospects, results of
operations, financial condition, and liquidity. A failure by an operator to post required supplemental bonding or other financial
assurances required by the BOEM could result in the BOEM assessing monetary penalties or requiring any on an operator’s federal
lease to be suspended or cancelled or otherwise subject an operator to monetary penalties. Any one or more such actions imposed on
us could materially adversely affect our financial condition and results of operations.
The BSEE has implemented much more stringent controls and reporting requirements that if not followed, could result in
significant monetary penalties or a shut-in of all or a portion of our Gulf of Mexico operations.
The BSEE is the federal agency responsible for overseeing the safe and environmentally responsible development of energy
and mineral resources on the OCS. They are responsible for leading the most aggressive and comprehensive reforms to offshore oil
and gas regulation and oversight in U.S. history. Their reforms have tightened requirements for everything from well design and
workplace safety to corporate accountability.
Additionally, the OCS Lands Act authorizes and requires the BSEE to provide for both an annual scheduled inspection and a
periodic unscheduled (unannounced) inspection of all oil and gas operations on the OCS. In addition to examining all safety
equipment designed to prevent blowouts, fires, spills, or other major accidents, the inspections focus on pollution, drilling operations,
completions, workovers, production, and pipeline safety. Upon detecting a violation,
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.
the inspector
In addition to the enforcement actions specified above, the BSEE can assess a civil penalty of up to $40,000 per violation per
day if: (i) the operator fails to correct the violation in the reasonable amount of time specified on the INC; or (ii) the violation resulted
in a threat of serious harm or damage to human life or the environment. Operators with excessive INCs may be required to cease
operations in the Gulf of Mexico.
Additional deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration,
oil spill-response and decommissioning plans, and other related restrictions arising after the Deepwater Horizon incident in
the Gulf of Mexico may have a material adverse effect on our business, financial condition, or results of operations.
In response to the Deepwater Horizon explosive incident and resulting oil spill in the United States Gulf of Mexico in 2010,
the BOEM and the BSEE have imposed more stringent permitting procedures and regulatory safety and performance requirements for
new wells to be drilled in federal waters. Compliance with these more stringent regulatory restrictions, in addition to any uncertainties
or inconsistencies in current decisions and rulings by governmental agencies, delays in the processing and approval of drilling permits
and exploration, development, oil spill-response and decommissioning plans and possible additional regulatory initiatives could
adversely affect or delay new drilling and ongoing development efforts. Moreover, new regulatory initiatives may be adopted or
enforced by the BOEM and/or the BSEE in the future that could result in additional delays, restrictions or obligations with respect to
oil and natural gas exploration and production operations conducted offshore. For example, in April 2015, the BSEE issued a notice
of proposed rulemaking, expected to be finalized in 2016, that focuses on well blowout preventer systems and well control with
respect to operations on the OCS. The proposed rule requires, among other things, incorporation of the latest industry standards
establishing minimum baseline standards for the design, manufacture, repair, and maintenance of blowout preventers, as well as more
controls over the maintenance and repair of blowout preventers. These recent or any new rules, regulations or legal initiatives could
delay or disrupt our operations, increase the risk of expired leases due to the time required to develop new technology, result in
increased supplemental bonding and costs, and limit activities in certain areas, or cause us to incur penalties, fines, or shut-in
production at one or more of our facilities, any one or more of which developments could have a material adverse effect on our
business, financial condition and results of operations.. Also, if material spill events similar to the Deepwater Horizon incident were
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to occur in the future, the United States or other countries could elect to issue directives to temporarily cease drilling activities and, in
any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and gas
exploration and development, any of which developments could have a material adverse effect on our business. We cannot predict
with any certainty the full impact of any new laws, regulations or legal initiatives on our drilling operations or on the cost or
availability of insurance to cover the risks associated with such operations.
We are highly dependent on our senior management team, our exploration partners, third-party consultants and engineers,
and other key personnel and any failure to retain the services of such parties could adversely affect our ability to effectively
manage our overall operations or successfully execute current or future business strategies.
The successful implementation of our business strategy and handling of other issues integral to the fulfillment of our business
strategy is highly dependent on our management
team, as well as certain key geoscientists, geologists, engineers and other
professionals engaged by us. The loss of key members of our management team or other highly qualified technical professionals could
adversely affect our ability to effectively manage our overall operations or successfully execute current or future business strategies
which may have a material adverse effect on our business, financial condition and operating results. Our ability to manage our growth,
if any, will require us to continue to train, motivate and manage our employees and to attract, motivate and retain additional qualified
personnel. Competition for these types of personnel is intense and we may not be successful in attracting, assimilating and retaining
the personnel required to grow and operate our business profitably.
Acquisition prospects are difficult to assess and may pose additional risks to our operations.
We expect to evaluate and, where appropriate, pursue acquisition opportunities on terms our management considers
favorable. The successful acquisition of natural gas and oil properties requires an assessment of:
Recoverable reserves.
Exploration potential.
Future natural gas and oil prices.
Operating costs.
Potential environmental and other liabilities and other factors.
Permitting and other authorizations, including environmental permits and 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.
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.
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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, domestically and globally;
future announcements concerning our business;
changes in financial estimates and recommendations by securities analysts;
actions of competitors;
market and industry perception of our success, or lack thereof, in pursuing our growth strategy;
strategic actions by us or our competitors, such as acquisitions or restructurings;
changes in government and environmental regulation;
general market, economic and political conditions, domestically and globally;
changes in accounting standards, policies, guidance, interpretations or principles;
sales of common stock by us, our significant stockholders or members of our management team; and
natural disasters, terrorist attacks and acts of war.
Natural gas and crude oil prices declined severely during 2015 and have declined even further through 2016 to date. In
addition, in recent years, the stock market has experienced significant price and volume fluctuations. This decline in commodity prices
and stock market 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.
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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, 2015, we had 116,461 stock options outstanding 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 of directors, 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.
34
We are subject to the Delaware business combination law.
We are subject to the provisions of Section 203 of the Delaware General Corporation Law. In general, Section 203 prohibits a
publicly held Delaware corporation from engaging in a “business combination” with an “interested stockholder” for a period of three
years after the date of the transaction in which the person became an interested stockholder, unless the business combination is
approved in a prescribed manner.
Section 203 defines a “business combination” as a merger, asset sale or other transaction resulting in a financial benefit to the
interested stockholders. Section 203 defines an “interested stockholder” as a person who, together with affiliates and associates, owns,
or, in some cases, within three years prior, did own, 15% or more of the corporation’s voting stock. Under Section 203, a business
combination between us and an interested stockholder is prohibited unless:
our board of directors approved either the business combination or the transaction that resulted in the stockholders
becoming an interested stockholder prior to the date the person attained the status;
upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested
stockholder owned at least 85% of our voting stock outstanding at the time the transaction commenced, excluding, for
purposes of determining the number of shares outstanding, shares owned by persons who are directors and also officers
and issued employee stock plans, under which employee participants do not have the right to determine confidentially
whether shares held under the plan will be tendered in a tender or exchange offer; or
the business combination is approved by our board of directors on or subsequent to the date the person became an
interested stockholder and authorized at an annual or special meeting of the stockholders by the affirmative vote of the
holders of at least 66 2/3% of the outstanding voting stock that is not owned by the interested stockholder.
This provision has an anti-takeover effect with respect to transactions not approved in advance by our board of directors,
including discouraging takeover attempts that might result in a premium over the market price for the shares of our common
stock. With approval of our stockholders, we could amend our certificate of incorporation in the future to elect not to be governed by
the anti-takeover law.
Our business could be negatively affected by security threats, including cybersecurity threats and other disruptions.
As an oil and gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to
sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third party
facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security
threats has subjected our operations to increased risks that could have a material adverse effect on our business.
In particular, our
implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information
facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such
procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur,
they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a
material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are
becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and
systems and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or
otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of
business or potential liability.
Item 1B. Unresolved Staff Comments
None
35
Item 2. Properties
As of December 31, 2015, we operated all of our offshore wells, with an average working interest of 59%, and operated 60%
of our onshore wells with an average working interest of 74%. As of December 31, 2015, our properties were located in the following
regions: Offshore Gulf of Mexico, Southeast Texas, South Texas, and Other.
Development, Exploration and Acquisition Expenditures
The following table presents information regarding our net costs incurred in the purchase of proved and unproved properties,
exploration costs incurred in the search for new reserves from unproved properties, and costs incurred in the development of those
properties for the periods indicated (in thousands):
Property acquisition costs:
Unproved
Proved
Exploration costs
Development costs
Total costs
2015
2014
2013
Year Ended December 31,
$
$
11,453
—
29,477
20,120
61,050
$
$
22,087
—
49,680
120,630
192,397
$
$
8,134
428,925
15,551
35,363
487,973
Included in unproved property acquisition costs for the year ended December 31, 2015, is $5.0 million related to Natrona and
Weston counties, Wyoming.
Included in unproved property acquisition costs for the year ended December 31, 2014, is $7.0 million related to the
acquisition of the right to earn acreage in Natrona and Weston counties, Wyoming. Included in the exploration costs for the year
ended December 31, 2014, is $28.0 million related to the drilling of our unsuccessful offshore Ship Shoal 255 prospect.
Included in proved property acquisition costs for the year ended December 31, 2013, is $413.9 million related to the
acquisition of Crimson properties as a result of the Merger. Also included is $15 million related to exercising a preferential right and
purchasing an additional 7.84% working interest and 6.53% net revenue interest in the five Company-operated Dutch wells in our
Eugene Island 10 Field from an independent oil and gas company for $18.8 million, $14.7 million net of normal purchase price
adjustments.
Included in the exploration costs for the year ended December 31, 2013, is $10.6 million related to the drilling of our
successful offshore South Timbalier 17 well and the unsuccessful Ship Shoal 255 prospect.
The following table presents information regarding our share of the net costs incurred by Exaro in the purchase of proved and
unproved properties and in exploration and development activities for the periods indicated (in thousands):
Property acquisition costs
Exploration costs
Development costs
Total costs incurred
2015
Year Ended December 31,
2014
2013
— $
—
4,503
4,503
$
— $
—
30,288
30,288
$
—
—
51,014
51,014
$
$
36
Drilling Activity
The following tables show our exploratory and developmental drilling activity for the periods indicated. In the tables, “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. As of December 31, 2015, we had one well awaiting to be completed, whose result is not included below.
Exploratory Wells:
Productive (onshore)
Productive (offshore)
Non-productive (onshore)
Non-productive (offshore)
Total
2015
Gross
Net
Year Ended December 31,
2014
Gross
Net
2013
Gross
Net
5
—
1
—
6
2.9
—
0.8
—
3.7
3
—
1
1
5
1.3
—
0.6
1.0
2.9
3
1
—
—
4
0.3
0.8
—
—
1.1
Included in productive (onshore) exploratory wells for the year ended December 31, 2015, are two wells drilled on our
Weston County, Wyoming acreage and three wells drilled in Fayette and Gonzales counties, Texas. Included in non-productive
(offshore) exploratory wells for the periods presented is our unsuccessful well at Ship Shoal 255.
2015
Gross
Net
Year Ended December 31,
2014
Gross
Net
2013
Gross
Net
9
—
—
—
9
5.3
—
—
—
5.3
24
—
1
—
25
13.1
—
0.7
—
13.8
5
—
—
—
5
3.2
—
—
—
3.2
Development Wells:
Productive (onshore)
Productive (offshore)
Non-productive (onshore)
Non-productive (offshore)
Total
Exploration and Development Acreage
Developed acreage is acreage spaced or assigned to productive wells. Undeveloped acreage is acreage on which wells have
not been drilled or completed to a point that would form the basis to determine whether the property is capable of production of
commercial quantities of crude oil, natural gas and natural gas liquids. Gross acres are the total acres in which we own a working
interest. Net acres are the sum of the fractional working interests we own in gross acres. The following table shows the approximate
developed and undeveloped acreage that we have an interest in, by region, at December 31, 2015.
Offshore GOM
Southeast Texas
South Texas
Other (6)
Total
Developed Acreage (1)(2)
Gross (4)
Net (5)
Undeveloped Acreage (1)(3)
Gross (4)
Net (5)
14,618
24,418
98,377
17,233
154,646
11,828
14,381
46,224
9,570
82,003
34,692
11,740
68,208
165,134
279,774
34,692
7,448
35,638
75,905
153,683
(1) Excludes any interest in acreage in which we have no working interest before payout or before initial production.
(2) Developed acreage consists of acres spaced or assignable to productive wells.
(3) Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of
commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.
(4) Gross acres refer to the number of acres in which we own a working interest.
(5) Net acres represent the number of acres attributable to our proportionate working interest in a lease (e.g., a 50% working interest in a lease covering 320 acres is
equivalent to 160 net acres).
(6) Other includes acreage in Louisiana, Colorado, Mississippi, Wyoming, North Texas, and East Texas.
37
Some of our offshore and onshore leases will expire over the next three years as follows, unless we establish production or
take action to extend the terms of these leases:
Offshore GOM
Southeast Texas
South Texas
Other (1)
Total
2016
Year ending December 31,
2017
2018
Gross Acres
Net Acres
Gross Acres
Net Acres
Gross Acres
Net Acres
—
2,621
6,268
28,818
37,707
—
1,900
3,924
24,154
29,978
20,000
1,270
42,392
8,928
72,590
20,000
1,081
21,317
7,146
49,544
14,692
270
3,878
34,083
52,923
14,692
199
1,939
14,498
31,328
(1) Relates primarily to our acreage position that was acquired in Louisiana and Mississippi as part of our Tuscaloosa Marine Shale play. It is not expected that those
leases will be extended or renewed.
Production, Price and Cost History
See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Productive Wells
Productive wells are producing wells and wells capable of producing commercial quantities. Completed but marginally
producing wells are not considered here as a “productive” well. The following table sets forth the number of gross and net productive
natural gas and oil wells in which we owned an interest as of December 31, 2015:
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)
11
40
222
55
328
6.9
23.9
122.4
26.1
179.3
—
46
50
10
106
—
26.8
23.2
3.4
53.4
(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, 2015, 2014 and 2013 were prepared by Netherland,
Sewell & Associates, Inc. (“NSAI”) and William M. Cobb and Associates (“Cobb”), our independent petroleum engineering firms 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 (“SPE”). Approximately 61% and 39% of the proved reserves estimates shown herein at
December 31, 2015 have been independently prepared by Cobb and NSAI, respectively. Cobb prepared the proved reserves estimates
as of December 31, 2015, 2014 and 2013 for all of our offshore properties and NSAI prepared the proved reserves estimates as of
December 31, 2015, 2014 and 2013 for our onshore properties.
The technical individual at NSAI responsible for the preparation of our reserve estimates as of December 31, 2015, 2014, and
2013 has over 15 years of experience in the estimation and evaluation of reserves; is a licensed professional engineer in the state of
Texas; and holds a Bachelor of Science Degree in Petroleum Engineering from the University of Tulsa. The technical individual at
Cobb responsible for overseeing the preparation of our reserve estimates as of December 31, 2015, 2014, and 2013 has 40 years of
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 from Texas A&M University; is a member of the Society of Petroleum Engineers; and is a
member of the Society of Petroleum Evaluation Engineers.
The estimates of proved reserves and future net revenue as of December 31, 2015, 2014 and 2013 were reviewed by our
corporate reservoir engineering department that is independent of the operations department. The corporate reservoir engineering
38
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.
We maintain adequate and effective internal controls over the underlying data upon which reserves estimates are based. The
primary inputs to the reserve estimation process are comprised of technical information, financial data, ownership interests and
production data. All field and reservoir technical information, which is communicated to our reservoir engineers quarterly, is
confirmed when our third-party reservoir engineers hold technical meetings with geologists, operations and land personnel to discuss
field performance and to validate future development plans. Current revenue and expense information is obtained from our accounting
records, which are subject to external quarterly reviews, annual audits and our own set of internal controls over financial reporting.
Internal controls over financial reporting are assessed for effectiveness annually using criteria set forth in Internal Controls - Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. All data such as commodity prices,
lease operating expenses, production taxes, field level commodity price differentials, ownership percentages, and well production data
are updated in the reserve database by our third-party reservoir engineers and then analyzed by management to ensure that they have
been entered accurately and that all updates are complete. Once the reserve database has been entirely updated with current
information, and all relevant technical support material has been assembled, our independent engineering firms prepare their
independent reserve estimates and final report.
The following table reflects our estimated proved reserves as of the dates indicated:
Crude Oil and Condensate (MBbl) (1)
Developed
Undeveloped
Total
Natural Gas (MMcf) (1)
Developed
Undeveloped
Total
Natural Gas Liquids (MBbl) (1)
Developed
Undeveloped
Total
Total MMcfe
Developed
Undeveloped
Total (2)
Proved developed reserves percentage
Prices utilized in estimates (3):
Crude oil ($/Bbl)
Natural gas ($/MMBtu)
Natural gas liquids ($/Bbl)
$
$
$
(1) Excludes reserves attributable to our 37% interest in Exaro.
2015
2,869
1,922
4,791
113,952
12,176
126,128
4,354
1,040
5,394
157,288
29,950
187,238
84
44.53
2.63
14.41
December 31,
2014
4,114
4,301
8,415
150,235
29,416
179,651
5,637
1,872
7,509
208,734
66,459
275,193
76
92.89
4.38
33.45
%
$
$
$
2013
5,223
4,475
9,698
185,535
22,395
207,930
6,453
1,505
7,958
255,591
58,275
313,866
%
81 %
$
$
$
106.80
3.73
35.92
(2) During the year ended December 31, 2015, proved reserves decreased by approximately 88.0 Bcfe primarily due to the impact of the dramatic decline in
commodity prices on the value and volume of our proved reserves, and in part to the impact of the significant reduction in our capital spending in response to the
commodity price environment.
39
(3) Under SEC rules, prices used in determining our proved reserves are based upon an unweighted 12-month first day of the month average price per MMBtu (Henry
Hub spot) of natural gas and per barrel of oil (West Texas Intermediate posted). Prices for natural gas liquids in the table represent average prices for natural gas
liquids used in the proved reserve estimates, calculated in accordance with applicable SEC rules. All prices were adjusted for quality, energy content,
transportation fees and regional price differentials in determining proved reserves.
PV-10
PV-10 at year-end is a non-GAAP financial measure and represents the present value, discounted at 10% per year, of
estimated future cash inflows from proved natural gas and crude oil reserves, less future development and production costs using
pricing assumptions in effect at the end of the period. PV-10 differs from Standardized Measure of Discounted Net Cash Flows
because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure of Discounted
Net Cash Flows represents an estimate of fair market value of our natural gas and crude oil properties. PV-10 is used by the industry
and by our management as an arbitrary reserve asset value measure to compare against past reserve bases and the reserve bases of
other business entities that are not dependent on the taxpaying status of the entity.
The following table provides a reconciliation of our Standardized Measure to PV-10 (in thousands):
Pre-tax net present value, discounted at 10%
Future income taxes, discounted at 10%
Standardized measure of discounted future net cash flows
December 31,
2015
2014
249,406
—
249,406
$
$
796,871
(148,855)
648,016
$
$
The following table reflects our estimated proved reserves by category as of December 31, 2015 (dollars in thousands):
Proved developed producing
Proved developed non-producing
Proved undeveloped
Total
Crude Oil and
Condensate (MBbl)
2,694
175
1,922
4,791
Natural Gas
(MMcf)
104,731
9,221
12,176
126,128
Natural Gas
Liquids (MBbl)
3,809
545
1,040
5,394
Total (MMcfe) % of Total Proved
PV - 10
143,749
13,539
29,950
187,238
77 % $ 218,025
11,782
7 %
19,599
16 %
100 % $ 249,406
Our estimated net proved reserves as of December 31, 2015 were approximately 15% crude oil and condensate, 68% natural
gas and 17% natural gas liquids.
Proved Developed Reserves
Total proved developed reserves decreased from 208.7 Bcfe at December 31, 2014 to 157.2 Bcfe at December 31, 2015. This
decline can be attributed to 34.0 Bcfe of production during the year, 15.6 Bcfe of negative revisions related to the reduction in the
economic life of certain properties due to the decrease in commodity prices, and 6.9 Bcfe of negative revisions related to performance,
partially offset by 5.0 Bcfe in extensions and new discoveries, and conversions from proved undeveloped reserves, from our reduced
2015 drilling program.
Proved Undeveloped Reserves
Total proved undeveloped reserves (“PUDs”) decreased from 66.5 Bcfe at December 31, 2014 to 30.0 Bcfe at December 31,
2015. As noted in the table below, this decrease was primarily attributable to negative revisions on certain 2014 PUDs that are no
longer economical to develop under current commodity pricing.
Future drilling plans and timelines are re-evaluated at the end of each calendar year based on updated reserve reports, current
drilling cost estimates and product price forecast. Our development plan prioritizes reserves based on the capital requirements and net
present value of potential wells. Generally, the plan is to convert PUDs to developed reserves in an order that is based on their
economic importance and impact on production and cash flow, but other factors may be considered such as technical merit, product
type, location, and available working interest partners. The PUD conversion rate in 2015 and 2014 was 26% and 29%, respectively, of
the total net present value of the Company’s total PUDs at the beginning of the applicable year.
40
The Company annually reviews any PUDs to ensure their development within five years from the date of originally adding
the reserves. Although the Company’s drilling and completion budget for 2016 has been reduced due to the continued drop in oil and
gas prices, the Company’s financial resources are expected to be sufficient and within budget to drill all of the remaining 30.0 Bcfe of
proved undeveloped reserves within the five year period. Development costs relating to the 30.0 Bcfe at December 31, 2015 are
projected to be approximately $50 million over the next five years.
The following table presents the changes in our total proved undeveloped reserves for the year ended December 31, 2015:
Proved Undeveloped Reserves (Mmcfe)
Proved undeveloped reserves at December 31, 2014
Revisions of previous estimates (1)
Extensions, discoveries and other additions (2)
Purchase of minerals in place
Disposition of reserves in place
Conversion to proved developed
Proved undeveloped reserves at December 31, 2015
66,459
(30,520)
1,045
—
—
(7,034)
29,950
(1) Substantially all of the negative revisions related to reduction in economic life of certain reserves due to lower commodity prices.
(2) Attributable to our limited onshore drilling program during the year ended December 31, 2015.
Significant Properties
Summary proved reserve information for our properties as of December 31, 2015, by region, is provided below (excluding
reserves attributable to our investment in Exaro) (dollars in thousands):
Regions
Crude Oil (MBbl)
Natural Gas (MMcf)
Offshore GOM
Southeast Texas
South Texas
Other
Total
757
1,911
1,457
666
4,791
92,168
12,645
18,556
2,759
126,128
Proved Reserves
Natural Gas Liquids
(MBbl)
2,882
1,383
1,022
107
5,394
Total (Mmcfe)
PV - 10 (1)
114,003
32,409
33,429
7,397
187,238
$
$
170,691
42,625
27,375
8,715
249,406
(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, 2015 and 2014 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
41
independent petroleum engineers and geoscientists that meet the requirements regarding qualifications, independence, objectivity, and
confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated
by the Society of Petroleum Engineers.
Reserves as of December 31, 2015 and 2014 were reviewed by our corporate reservoir engineering department as described
above. The technical individual at Von Gonten responsible for overseeing the preparation of our reserve estimates as of December 31,
2015 and December 31, 2014 has over 16 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 from Texas A&M
University; and is a member in good standing of the Society of Petroleum Engineers.
The following table reflects the estimated proved reserves attributable to our Investment in Exaro:
December 31, 2015
December 31, 2014
December 31, 2013
Crude Oil (MBbl)
Developed
Undeveloped
Total
Natural Gas (MMcf)
Developed
Undeveloped
Total
Total MMcfe
Developed
Undeveloped
Total (3)
442
—
442
36,074
—
36,074
38,724
—
38,724
529
262
791
45,127
20,285
65,412
48,301
21,857
70,158
Proved developed reserves percentage
Standardized measure (1)
Prices utilized in estimates (2)
Crude oil ($/Bbl)
Natural gas ($/MMBtu)
$
$
$
100 %
31,298
44.28
2.71
$
$
$
69 %
100,607
85.46
4.96
$
$
$
439
—
439
39,068
—
39,068
41,702
—
41,702
100 %
63,906
87.89
4.04
(1) The Company's share of the standardized measure of discounted future net cash flows attributable to our investment in Exaro does not include the effect of income
taxes because Exaro is treated a partnership for tax purposes. Exaro allocates any income or expense for tax purposes to its partners.
(2) Under SEC rules, prices used in determining our proved reserves are based upon an unweighted 12-month first day of the month average price per MMBtu (Henry
Hub spot) of natural gas and per barrel of oil (West Texas Intermediate posted). Prices for natural gas liquids in the table represent average prices for natural gas
liquids used in the proved reserve estimates, calculated in accordance with applicable SEC rules. All prices are adjusted for quality, energy content, transportation
fees and regional price differentials in determining proved reserves.
(3) During the year ended December 31, 2015, Exaro’s proved reserves decreased by approximately 31.4 Bcfe attributable to the impact of the dramatic decline in
commodity prices on the value and volume of proved reserves, and the impact of the significant reduction in capital spending in response to the low and uncertain
commodity price environment.
Prior Year Reserves
Our estimated net proved natural gas, oil and natural gas liquids reserves as of December 31, 2014, 2013 and 2012 are
disclosed in “Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Disclosures (Unaudited)”. Reserves
as of December 31, 2014 and 2013 were based on reserve reports generated by NSAI and Cobb. Reserves as of December 31, 2012
are based on reserve reports generated by Cobb, while the reserves associated with our 37% investment in Exaro were prepared by
Von Gonten.
Item 3. Legal Proceedings
From time to time, we are involved in legal proceedings relating to claims associated with our properties, operations or
business or arising from disputes with vendors in the normal course of business, including the material matters discussed below.
42
In July 2010, several parties associated with a limited partnership formed to invest in oil and gas properties that was
dissolved in 1995 filed suit against a subsidiary of the Company and several co-defendants in the district court for Madison County in
Texas. The plaintiffs claim to own or have rights in certain oil and gas properties situated in Madison County, Texas by virtue of the
partnership having interests in addition to those it held of record at the time of its dissolution, which were distributed to the partners in
connection with such dissolution. A predecessor of the subsidiary of the Company involved in this case acquired a portion of the
interests now claimed by the plaintiffs from a successor to the general partner of the aforementioned partnership in 2000. The
plaintiffs’ expert has recently provided a range of estimated monetary damages of up to approximately $9.4 million as to our
subsidiary. We are vigorously defending this lawsuit and believe we have meritorious defenses.
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 had granted indemnification rights. In dispute is whether
ownership rights were transferred through a number of decade-old poorly documented transactions. Based on summary judgment, in
late 2014 the trial court entered a final judgment in the case in favor of the plaintiffs for approximately $5.3 million, plus post-
judgment interest. We are vigorously defending this lawsuit, believe we have meritorious defenses and are appealing the trial court’s
decision to the applicable state Court of Appeals.
In September 2012, a subsidiary of the Company was named as defendant in a lawsuit filed in district court for Harris County
in Texas involving a title dispute over a 1/16th mineral interest in the producing intervals of certain wells operated by us in the
Catherine Henderson “A” Unit in Liberty County in Texas. This case was subsequently transferred to the district court for Liberty
County, Texas and combined with a suit filed by other parties against the plaintiff claiming ownership of the disputed interest. The
plaintiff has alleged that, based on its interpretation of a series of 1972 deeds, it owns an additional 1/16th unleased mineral interest in
the producing intervals of these wells on which it has not been paid (this claimed interest is in addition to a 1/16th unleased mineral
interest on which it has been paid). We have made royalty payments with respect to the disputed interest in reliance, in part, upon
leases obtained from successors to the grantors under the aforementioned deeds, who claim to have retained the disputed mineral
interests thereunder. The plaintiff previously alleged damages of approximately $10.7 million although the plaintiff’s claim increases
as additional hydrocarbons are produced from the subject wells. The trial court entered judgment in favor of the Company’s subsidiary
and the successors to the grantors under the aforementioned deeds and the plaintiff has appealed the trial court’s decision to the
applicable state Court of Appeals. We are vigorously defending this lawsuit and believe 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.
Mineral interest owners in South Louisiana filed suit against a subsidiary of the Company and several co-defendants in April
2013 in the 31st Judicial District Court situated in Jefferson Davis Parish, Louisiana alleging failure to act as a reasonably prudent
operator, failure to explore, waste, breach of contract, etc. in connection with two wells located in Jefferson Davis Parish. Many of the
alleged improprieties occurred prior to the Company’s ownership of an interest in the wells at issue, although we may have assumed
liability otherwise attributable to its predecessors-in-interest through the acquisition documents relating to the acquisition of the
Company’s interest in these wells. This case is based on the same actions and allegations as a prior case in which the Company and its
co-defendants prevailed. The plaintiffs claim damages of approximately $2.5 million against a subsidiary of the Company and its co-
defendants. The Company and its co-defendants are vigorously defending this lawsuit and believe that they have a meritorious
position.
While many of these matters involve inherent uncertainty and the Company is unable at the date of this filing to estimate an
amount of possible loss with respect to certain of these matters, the Company believes that the amount of the liability, if any,
ultimately incurred with respect to these proceedings or claims will not have a material adverse effect on its consolidated financial
position as a whole or on its liquidity, capital resources or future annual results of operations. The Company maintains various
insurance policies that may provide coverage when certain types of legal proceedings are determined adversely.
Item 4. Mine Safety Disclosures
Not applicable.
43
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, 2015:
Quarter Ended March 31, 2015
Quarter Ended June 30, 2015
Quarter Ended September 30, 2015
Quarter Ended December 31, 2015
Year Ended December 31, 2014:
Quarter Ended March 31, 2014
Quarter Ended June 30, 2014
Quarter Ended September 30, 2014
Quarter Ended December 31, 2014
High
Low
$
$
$
$
$
$
$
$
33.17
25.41
12.34
10.46
50.44
49.28
42.98
38.96
$
$
$
$
$
$
$
$
20.25
11.32
6.60
5.73
40.09
39.08
32.80
28.07
From the period from January 1, 2016 to March 9, 2016, our common stock traded at prices between $3.68 and $8.39 per
share.
General
The following descriptions are summaries of material
terms of our common stock, preferred stock, certificate of
incorporation and bylaws. This summary is qualified by reference to our certificate of incorporation, bylaws and the designations of
our preferred stock, which are filed as exhibits to this report on Form 10-K, and by the provisions of applicable law.
Common Stock
We are authorized to issue up to 50 million shares of common stock. As of March 9, 2016, there were approximately 24.7
million shares of common stock issued and 19.4 million shares of common stock outstanding held by approximately 120 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 of directors and will depend upon our financial condition, results of operations,
capital requirements, and other factors our board of directors may deem relevant. We do not anticipate paying any cash dividends on
our common stock in the foreseeable future, as we currently intend to retain all future earnings to fund the development and growth of
our business. Our credit facility with Royal Bank of Canada and other lenders currently restricts our ability to pay cash dividends on
our common stock, and we may also enter into credit agreements or other borrowing arrangements in the future that restrict or limit
our ability to pay cash dividends on our common stock.
44
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, 2015.
Share-Based Compensation
The following table sets forth information about our equity compensation plans at December 31, 2015:
Plan Category
Amended and Restated 2009 Incentive
Compensation Plan - approved by security holders
2005 Stock Incentive Plan (“Crimson Plan”)
Number of
securities to be issued upon
exercise of outstanding
options
Weighted-average
exercise price of
outstanding options
Number of securities remaining
available for future issuance
under equity compensation plans
— $
$
116,461
—
53.03
885,449
—
Amended and Restated 2009 Incentive Compensation Plan
On September 15, 2009, the Company’s board of directors (the “Board”) adopted the Contango Oil & Gas Company Equity
Compensation Plan (the “Original 2009 Plan”), which was approved by shareholders on November 19, 2009. On April 10, 2014, the
Board amended and restated the Original 2009 Plan through the adoption of the Contango Oil & Gas Company Amended and Restated
2009 Incentive Compensation Plan (the “2009 Plan”), which was approved by shareholders on May 20, 2014. The 2009 Plan provides
for both cash awards and equity awards (such as restricted stock and options) to officers, directors, employees and consultants of the
Company. Awards made under the 2009 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as
may be determined by the Board.
Under the terms of the 2009 Plan, up to 1,500,000 shares of the Company’s common stock may be issued for plan awards.
Stock options issued under the 2009 Plan must have an exercise price 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 for all equity awards varies from
immediately to over a four-year period.
Effective January 1, 2014, the Company implemented performance-based long-term bonus plans under the 2009 Plan for the
benefit of all employees through a Cash Incentive Bonus Plan (“CIBP”) and a Long-Term Incentive Plan (“LTIP”). The specific
targeted performance measures under theses sub-plans are approved by the Compensation Committee and/or the Board. Upon
achieving the performance levels established each year, bonus awards under the CIBP and LTIP will be calculated as a percentage of
base salary of each employee for the plan year. The CIBP and LTIP plan awards for each year are expected to be disbursed in the first
quarter of the following year. Employees must be employed by the Company at the time that awards are disbursed to be eligible.
The CIBP awards will be paid in cash while the LTIP awards will consist of restricted common stock and/or stock options.
The stock and/or option awards are expected to vest 25% per year, over the first through fourth anniversaries from the date of grant.
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.
During the year ended December 31, 2015, the Company granted 270,091 restricted stock awards under the 2009 Plan to
officers, employees and directors of the Company pursuant to the LTIP, while 12,534 restricted shares were forfeited by former
employees and are available to be reissued. During the year ended December 31, 2014, 26,386 restricted stock awards were granted
under the 2009 Plan to officers, employees and directors of the Company pursuant to the LTIP, while 7,230 restricted shares were
forfeited by former employees and are available to be reissued. During the year ended December 31, 2013, 312,838 restricted stock
awards were granted under the 2009 Plan to officers, employees and directors of the Company.
45
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 for all equity awards varies from immediately to over a
four-year period. Upon adoption of the 2005 Plan at the Merger closing date, a total of 135,898 stock option awards and 136,428
shares of restricted stock (as converted, which all fully vested upon the Merger) were already issued and outstanding, leaving a
balance of 43,472 shares of common stock or stock options available to be granted to Company employees and directors.
During the year ended December 31, 2015, the Company granted 7,030 restricted stock awards under the 2005 Plan to a new
employee pursuant to the LTIP, while 189 restricted stock awards were forfeited by former employees. Additionally, during the year
ended December 31, 2015, 13,473 stock options previously issued under the 2005 Plan were forfeited, leaving 116,461 stock options
vested and exercisable at December 31, 2015. The exercise price for such options range from $28.96 to $60.33 per share, with an
average remaining contractual life of five years. The 2005 Plan expired on February 25, 2015 and therefore no additional shares are
available for grant.
During the year ended December 31, 2014, the Company did not issue any shares of restricted common stock under the 2005
Plan, but 4,165 stock options previously issued under the 2005 Plan were exercised. During the year ended December 31, 2013, the
Company issued 43,461 shares of restricted common stock to Company employees under the 2005 Plan pursuant to the LTIP.
Additionally, 791 stock options were exercised.
Share Repurchase Program
In September 2011, the Company’s board of directors approved a $50 million share repurchase program. All shares are to be
purchased in the open market from time to time by the Company or through privately negotiated transactions. The purchases are
subject to market conditions and certain volume, pricing and timing restrictions to minimize the impact of the purchases upon the
market. In October 2014, the Company amended its revolving credit facility with Royal Bank of Canada to, among other things, allow
for share repurchases under certain circumstances. No shares were purchased for the years ended December 31, 2015 and 2013. For
the year ended December 31, 2014, we purchased the following shares under the $50 million share repurchase program:
Period
November 2014
Total Number of Shares
Purchased
Average Price Paid
Per Share
Total Number of Shares
Purchased as Part of
Publicly Announced Program
Approximate Dollar Value
of Shares that may yet
be Purchased Under Program
205,457 $
35.89
403,334 $
31.8 million
46
In addition, the Company repurchased the following shares from employees for the payment of withholding taxes due on
shares of restricted stock issued under our stock-based compensation plans:
Period
October 2013
November 2013
July 2014
November 2014
December 2014
January 2015
February 2015
June 2015
August 2015
October 2015
November 2015
December 2015
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
34,911 $
17,459 $
95 $
21,097 $
5,364 $
262 $
24 $
70 $
9,330 $
325 $
17,451 $
3,790 $
37.75
42.80
38.98
37.24
33.64
26.03
28.15
12.73
6.83
7.41
7.57
7.45
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
47
Stock Performance Graph
The following graph compares the yearly percentage change from June 30, 2010 until December 31, 2015 in the cumulative
total stockholder return on our common stock to the cumulative total return on the S&P Smallcap 600 Index and a peer group of
independent oil & gas exploration companies selected by us.
For the year ended December 31, 2014, the companies in our selected peer group included Petroquest Energy, Inc., Swift
Energy Company, Callon Petroleum, Energy XXI (Bermuda) Limited and W&T Offshore, Inc. (“Old Peer Group”). Due to our focus
on onshore resource plays, the reorganization of Swift Energy Company under Chapter 11 of the Bankruptcy Code and the financial
uncertainty of other companies in our Old Peer Group, we have selected a new peer group of companies. As of December 31, 2015,
the companies in our selected peer group included Resolute Energy, EXCO Resources, Comstock Resources, Sanchez Energy,
Abraxas Petroleum and Gastar Exploration (“New 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 June 30, 2010, adjusted for stock splits and dividends. The stock performance for our common stock is not
necessarily indicative of future performance.
Contango Oil & Gas Company
6/30/2010
100.00
6/30/2011
130.59
6/30/2012
132.29
6/30/2013
79.37
12/31/2013
111.14
12/31/2014
68.76
12/31/2015
15.07
S&P Smallcap 600
Old Peer Group
New Peer Group
100.00
100.00
100.00
137.03
184.96
118.52
138.99
132.49
60.76
173.98
103.11
59.96
211.59
125.03
62.79
223.77
41.73
24.44
219.36
20.22
11.39
48
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, 2015 and 2014 have been derived from the audited
consolidated financial statements of Contango contained in this Form 10-K. The following selected financial data for the years ended
December 31, 2013, 2012 and 2011 have been derived from the audited consolidated financial statements of Contango contained in
our Form 10-K/A for the applicable fiscal year. The selected consolidated financial data (not including proved reserve information) set
forth below is for continuing operations and should be read in conjunction with Item 7. “Management’s Discussion and Analysis of
Financial Condition and Results of Operations” and with the consolidated financial statements and notes to those consolidated
financial statements included elsewhere in this Form 10-K.
Selected financial data for the years ended December 31, 2015, 2014 and 2013 include 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, 2015, 2014 and 2013 include the balance sheet and reserves information of Crimson and its subsidiaries adjusted in accordance
with the acquisition method of accounting, which requires that assets acquired and liabilities assumed in the Merger be recorded at
their fair value at the date of acquisition with the difference between the purchase price and value of assets and liabilities be recorded
as goodwill. No goodwill was recognized as a result of the Merger between Contango and Crimson.
Selected financial information for the five years ended December 31, 2015 is as follows (dollars in thousands, except per
share amounts):
2015
2014
2013
2012
2011
Year Ended December 31,
Natural gas and oil sales (1)
Income (loss) from continuing operations (2)
Discontinued operations, net of income taxes
Net income (loss) attributable to common stock
Net income (loss) per share:
Basic
Continuing operations
Discontinued operations
Total
Diluted
Continuing operations
Discontinued operations
Total
Weighted average shares outstanding:
Basic
Diluted
$
$
$
$
$
$
$
116,505
$
(335,048) $
276,458
$
(21,874) $
164,121
41,362
—
—
—
(335,048) $
(21,874) $
41,362
(17.67) $
—
(17.67) $
(1.15) $
—
(1.15) $
(17.67) $
(1.15) $
—
—
(17.67) $
(1.15) $
2.56
—
2.56
2.56
—
2.56
$
$
$
$
$
$
$
145,868
$
(907) $
198,498
69,909
(29)
(936) $
(1,204)
68,705
(0.06) $
(0.00)
(0.06) $
(0.06) $
(0.00)
(0.06) $
4.49
(0.08)
4.41
4.49
(0.08)
4.41
18,965
18,965
19,059
19,059
16,156
16,158
15,295
15,295
15,582
15,585
49
Year Ended December 31,
2015
2014
2013
2012
2011
Working capital (deficit) (3)
Capital expenditures
Cash dividends (4)
Long term debt (5)
Shareholders’ equity
Total assets
Proved Reserve Data:
Total proved reserves (Mmcfe) (6)
Pre-tax net present value (discounted 10%)
Standardized measure (6)
$
$
$
$
$
$
$
$
(18,689) $
(65,975) $
(33,162) $
100,901
55,565
$
— $
188,529
$
— $
62,552
$
— $
78,549
30,510
$
$
$
163,245
40,330
—
115,446
237,843
416,756
187,238
249,406
249,406
$
$
$
$
$
63,359
567,466
843,415
275,193
796,871
648,016
$
$
$
$
$
90,000
593,050
910,304
313,866
987,213
771,443
$
$
$
$
$
— $
—
403,929
561,106
$
$
444,003
621,817
221,096
594,397
388,012
261,201
909,675
591,833
(1) The decrease in natural gas and oil sales for the year ended December 31, 2015 is attributable to the decline in commodity prices during the fourth quarter of 2014
and during 2015, combined with underperformance from various 2015 budgeted new wells. The increase in natural gas and oil sales for the years ended December
31, 2014 and 2013 are attributable to the merger with Crimson.
(2) During the year ended December 31, 2015, we recognized approximately $269.6 million for impairment of proved properties, substantially all of which was
directly related to the decline in commodity prices and the resulting impact on estimated future net cash flows from the associated reserves. Additionally, we
recognized approximately $16.3 million for impairment and partial impairment of certain unproved properties and onshore prospects primarily due to the
sustained low commodity price environment and expiring leases.
During the year ended December 31, 2014, we reached a total depth on our Ship Shoal 255 well, and no hydrocarbons were found. As a result, we recognized
$31.5 million in exploration expense for the cost of drilling the well and $15.6 million in impairment expense, including $3.5 million related to leasehold costs and
$12.1 million related to the platform located in Ship Shoal 263 block which was expected to be used by the Ship Shoal 255 had it been successful. Additionally,
during the year ended December 31, 2014, we revised estimated proved reserves for South Timbalier 17 and our Tuscaloosa Marine Shale properties, resulting in
non-cash impairment expenses of approximately $11.4 million. During the year ended December 31, 2014, we also recognized impairment expense of
approximately $20.1 million related to full or partial impairment of certain unproved properties due to expiring leases and leases not likely to be drilled.
During the year ended December 31, 2013, we completed a workover on our Vermilion 170 well at a cost of approximately $12.0 million. During the year ended
December 31, 2012, we drilled two unsuccessful exploratory wells resulting in exploration expenses of approximately $50.0 million, including leasehold costs.
Also, during the year ended December 31, 2012, we revised estimated proved reserves at Ship Shoal 263, resulting in non-cash impairment expenses of
approximately $12.0 million.
(3) The decrease in the deficit in working capital during 2015 was a result of the decrease in drilling activity and the satisfaction of trade obligations existing at the
beginning of the year, which were attributable to a more active drilling program in late 2014. The increase in the working capital deficit for the year ended
December 31, 2014 was primarily attributable to the higher trade obligations associated with the drilling program in late 2014 and a decrease in trade receivables
associated with the decline in commodity prices during the fourth quarter of 2014. The decrease in working capital for the year ended December 31, 2013,
compared to the balance at the end of 2012, was attributable to the utilization of cash on hand at the time of the Merger to retire Crimson debt assumed in the
Merger.
(4) On November 29, 2012, the board of directors declared a one-time special dividend of $2.00 per share of common stock which was paid on December 17, 2012.
(5) On October 1, 2013, in connection with the Merger, we entered into a revolving credit facility with Royal Bank of Canada and other lenders.
(6) During the year ended December 31, 2015, our proved reserves decreased by approximately 88.0 Bcfe and our standardized measure decreased by approximately
$398.6 million. This decrease is primarily attributable to the impact of the dramatic decline in commodity prices on the value and volume of our proved reserves
and in part to the impact of the significant reduction in our capital spending in response to the low and uncertain commodity price environment.
During the year ended December 31, 2014, our proved reserves decreased by approximately 38.7 Bcfe and our standardized measure decreased by approximately
$123.4 million. This decrease is primarily attributable to 40.3 Bcfe of production and a 22.4 Bcfe negative revision of proved developed producing reserves at our
Eugene Island 11 field due to a change in forecasted condensate yield and ultimate field abandonment pressure; these decreases were partially offset by 36.1 Bcfe
for extensions and discoveries.
During the year ended December 31, 2013, our proved reserves increased by approximately 92.8 Bcfe and our standardized measure increased by approximately
$383.4 million, primarily as a result of our merger with Crimson. Also contributing to the increase was the exercise of our preferential right to purchase
approximately 17.0 Bcfe related to our five Contango-operated Dutch wells, slightly offset by 28.2 Bcfe of production, a 19.2 Bcfe decrease in our Dutch and
Mary Rose reserve estimates based upon additional pressure data, and a 2.5 Bcfe decrease in our Vermilion 170 reserve estimates, as determined by our reservoir
engineer.
During the year ended December 31, 2012, our proved reserves decreased by approximately 40.1 Bcfe and our standardized measure decreased by approximately
$203.8 million. The major contributors to this decrease include normal production of 28.8 Bcfe during the year, a 9.2 Bcfe decrease in our Ship Shoal 263 reserve
estimates, and an 11.5 Bcfe decrease in our Vermilion 170 reserve estimates, slightly offset by an increase in our Dutch and Mary Rose reserve estimates, all as
determined by our reservoir engineer.
50
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with
the financial statements and the related notes and other information included elsewhere in this report. On October 1, 2013 the
Company's board of directors approved a change in fiscal year end from June 30 to December 31. Unless otherwise noted, all
references to "years" in this report refer to the twelve-month period which ends on December 31 of each year. This Form 10-K covers
the three year period ended December 31, 2015.
Overview
We are a Houston, Texas based independent oil and natural gas company. Our business is to maximize production and cash
flow from our offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore properties in various plays, and
use that cash flow to explore, develop, exploit and acquire crude oil and natural gas properties in the onshore Texas Gulf Coast and
Rocky Mountain regions of the United States.
On October 1, 2013, we completed a merger with Crimson Exploration Inc. (“Crimson”) in an all-stock transaction pursuant
to which Crimson became a wholly-owned subsidiary of Contango (the “Merger”). The Merger gave us access to high rate of return
onshore prospects in known, prolific producing areas as well as long-life resource plays. In 2015, our drilling activity focused
primarily on the Woodbine oil and liquids-rich play in Madison and Grimes counties, Texas (our Southeast Texas Region), in the
Cretaceous Sands in Fayette and Gonzales counties, Texas (in our South Texas Region) and the late 2014/early 2015 commencement
of drilling on our new acreage position in Wyoming where we are targeting the Mowry Shale and the Muddy Sandstone formations.
We believe these areas could provide long-term growth potential from multiple formations that we believe to be productive for oil and
natural gas.
Additionally, we have (i) a 37% equity investment in Exaro Energy III LLC (“Exaro”), which is primarily focused on the
development of proved natural gas reserves in the Jonah Field in Wyoming; (ii) operated properties producing from various
conventional formations in various counties along the Texas Gulf Coast; (iii) operated producing properties in the Denver Julesburg
Basin (“DJ Basin”) in Weld and Adams counties in Colorado, which we believe may also be prospective in the Niobrara Shale oil
play; and (iv) operated producing properties in the Haynesville Shale, Mid Bossier and James Lime formations in East Texas.
Natural gas and crude oil prices declined severely during 2015 and have declined even further through 2016 to date. Due to
the current challenging commodity price environment, we focused our 2015 capital program on: (i) the preservation of our strong and
flexible financial position, including limiting our overall capital expenditure budget; (ii) dedicating capital primarily to de-risking
and/or delineating strategic projects (i.e. versus field development); (iii) the identification of opportunities for cost and production
efficiencies in all areas of our operations; and (iv) continuing to identify and, when appropriate, pursue the expansion of our resource
potential through opportunistic acquisitions.
Our production for the year ended December 31, 2015 was approximately 34.0 Bcfe (or 93.0 Mmcfe/d) and was 63%
offshore and 37% onshore. Our production for the three months ended December 31, 2015 was approximately 8.0 Bcfe (or 86.7
Mmcfe/d) and was 65% offshore and 35% onshore. As of December 31, 2015, our proved reserves were approximately 61% offshore
and 39% onshore and were 84% proved developed, which were approximately 72% offshore and 28% onshore.
Revenues and Profitability
Our revenues, profitability and future growth depend substantially on our ability to find, develop and acquire natural gas and
oil reserves that are economically recoverable, as well as prevailing prices for natural gas and oil.
Reserve Replacement
Generally, producing properties offshore in the Gulf of Mexico have high initial production rates, followed by steep declines.
Likewise, initial production rates on new wells in the onshore resource plays start out at a relatively high rate with a decline curve
which results in 60% to 70% of the ultimate recovery of present value occurring in the first eighteen months of the well’s life. We
must locate and develop, or acquire, new natural gas and oil reserves to replace those being depleted by production. Substantial capital
expenditures are required to find, develop and/or acquire natural gas and oil reserves. A prolonged period of depressed commodity
prices could have a significant impact on the value and volumetric quantities of our proved reserve portfolio, assuming no other
51
changes in our development plans. 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
Effective as of the close of business on December 31, 2015, the Company and the other members of Republic Exploration LLC
(“REX”) agreed to dissolve and liquidate REX. REX’s assets are being distributed proportionately to its members. See Note 17 to
our Financial Statements - "Related Party Transactions" for a detailed description of our transactions with REX.
See “Item 1A. Risk Factors” for a more detailed discussion of a number of other factors that affect our business, financial
condition and results of operations.
Results of Operations
The table below sets forth our average net daily production data in Mmcfe/d from our fields for each of the periods indicated:
March 31,
2014
June 30, 2014
September 30,
2014
December 31,
2014
March 31,
2015
June 30, 2015
September 30,
2015
December 31,
2015
Three Months Ended
Offshore GOM
Dutch and Mary Rose
Vermilion 170
Other offshore (1)
Southeast Texas (2)
South Texas (3)
Other (4)
66.7
9.0
0.4
26.4
12.6
2.4
117.5
60.9
7.2
0.6
27.1
16.0
4.2
116.0
42.3 (5)
8.0
5.2
26.6
17.4
2.8
102.3
55.9
5.7
6.5
23.6
12.2
2.3
106.2
53.3
7.7
3.2
19.3
10.8
2.0
96.3
50.8
6.3
1.6
28.2
9.3
2.2
98.4
49.5
7.0
0.5
22.9
8.9
2.1
90.9
48.6
6.9
0.5
20.1
8.1
2.5
86.7
Includes Ship Shoal 263 and South Timbalier 17.
Includes Madison and Grimes counties, among others.
Includes Zavala and Dimmit counties, among others.
Includes onshore wells in East Texas, Colorado, Wyoming and Tuscaloosa Marine Shale regions, among others.
(1)
(2)
(3)
(4)
(5) Lower mainly due to shut-in for approximately three weeks to install compression.
Vermilion 170 Well
During December 2014, our Vermilion 170 well production was shut-in for fourteen days due to issues with the Sea Robin
Pipeline, our third-party transporter.
Other Offshore
Other offshore includes our Ship Shoal 263 well for all periods presented, except for periods after it was shut-in in September
2015 and for South Timbalier 17 for all quarters ended after June 30, 2014, as it commenced production in July 2014.
52
Southeast Texas
During 2014, Contango drilled 18 gross (11.6 net) wells on acreage targeting the Woodbine formation. During 2015, we
brought seven gross wells (3.9 net) on production which we initiated in late 2014 utilizing a pad drilling strategy on 500 foot spacing,
plus an additional one gross well (0.9 net) in our Iola/Grimes area. We also drilled one gross (0.7 net) well in our Chalktown area to
satisfy a farm-in commitment and one gross (0.7 net) horizontal well testing a more aggressive completion design in the Lower
Lewisville formation in our Grimes County area, as we limited our 2015 capital expenditures to strategic projects and to stay within
internally generated cash flows.
South Texas
During 2014, Contango drilled 14 gross operated wells (6.8 net) in the Buda formation, which are all on production. We
drilled one additional well during the fourth quarter of 2014 as a vertical pilot well to test the viability of the Eagle Ford and other
formations in Zavala and Dimmit counties. Though core analysis indicates the viability of the Eagle Ford formation in the area, no
drilling activity was conducted in this area in 2015, or is planned for 2016, because of the low commodity price environment.
53
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014; and Year Ended December 31, 2014
Compared to Year Ended December 31, 2013
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, 2015, 2014 and
2013. Oil, condensate and NGLs are compared with natural gas in terms of cubic feet of natural gas equivalents. One barrel of oil,
condensate or NGL is the energy equivalent of six Mcf of natural gas. Reported lease operating expenses include production taxes,
such as ad valorem and severance. Information for the year ended December 31, 2013 includes twelve months of Contango activity
(January - December) and three months of post-merger Crimson activity (October - December).
Revenues (thousands):
Oil and condensate sales
Natural gas sales
NGL sales
Total revenues
Production:
Oil and condensate (thousand barrels)
Dutch and Mary Rose
Vermilion 170
Southeast Texas
South Texas
Other
Total oil and condensate
Natural gas (million cubic feet)
Dutch and Mary Rose
Vermilion 170
Southeast Texas
South Texas
Other
Total natural gas
Natural gas liquids (thousand barrels)
Dutch and Mary Rose
Vermilion 170
Southeast Texas
South Texas
Other
Total natural gas liquids
Total (million cubic feet equivalent)
Dutch and Mary Rose
Vermilion 170
Southeast Texas
South Texas
Other
Total production
Year Ended December 31,
Year Ended December 31,
2015
2014
%
2014
2013
%
$
43,230
$ 130,238
(67)% $ 130,238
$
59,608
118 %
59,058
14,217
112,695
33,525
(48)%
(58)%
112,695
33,525
79,289
25,224
$
116,505
$ 276,458
(58)% $ 276,458
$ 164,121
(26)%
(41)%
(33)%
(47)%
(8)%
(34)%
(9)%
(3)%
(3)%
(30)%
(48)%
(13)%
(9)%
(12)%
18 %
(30)%
(27)%
(4)%
(10)%
(7)%
(13)%
(36)%
(40)%
(16)%
220
37
734
337
73
1,401
16,257
2,108
3,234
2,541
1,735
262
38
160
95
34
589
17,018
1,823
875
623
285
25,875
20,624
501
68
304
124
11
1,008
20,578
2,738
9,461
5,309
2,237
514
68
66
26
3
677
21,674
2,459
2,231
1,349
507
40,323
28,220
164
22
493
178
67
924
220
37
734
337
73
1,401
14,736
16,257
2,050
3,136
1,788
904
2,108
3,234
2,541
1,735
22,614
25,875
454
60
359
87
8
968
18,443
2,545
8,249
3,379
1,345
501
68
304
124
11
1,008
20,578
2,738
9,461
5,309
2,237
33,961
40,323
54
42 %
33 %
68 %
(16)%
(3)%
359 %
255 %
115 %
138 %
(4)%
16 %
270 %
308 %
509 %
25 %
(3)%
— %
361 %
377 %
267 %
49 %
(5)%
11 %
324 %
294 %
341 %
43 %
Year Ended December 31,
Year Ended December 31,
2015
2014
%
2014
2013
%
Daily Production:
Oil and condensate (thousand barrels per day)
Dutch and Mary Rose
Vermilion 170
Southeast Texas
South Texas
Other
Total oil and condensate
Natural gas (million cubic feet per day)
Dutch and Mary Rose
Vermilion 170
Southeast Texas
South Texas
Other
Total natural gas
Natural gas liquids (thousand barrels per day)
Dutch and Mary Rose
Vermilion 170
Southeast Texas
South Texas
Other
Total natural gas liquids
Total (million cubic feet equivalent per day)
Dutch and Mary Rose
Vermilion 170
Southeast Texas
South Texas
Other
Total production
Average Sales Price:
Oil and condensate (per barrel)
Natural gas (per thousand cubic feet)
Natural gas liquids (per barrel)
Total (per thousand cubic feet equivalent)
Expenses (thousands):
Operating expenses
Exploration expenses
Depreciation, depletion and amortization
Impairment and abandonment of oil and gas
properties
General and administrative expenses
Gain (Loss) from investment in affiliates
(net of taxes)
$
$
$
$
$
$
$
$
$
$
0.6
0.1
2.0
0.9
0.2
3.8
44.5
5.8
8.9
7.0
4.7
70.9
1.4
0.2
0.8
0.3
0.1
2.8
56.4
7.5
25.9
14.5
6.2
110.5
92.98
4.36
33.27
6.86
0.4
0.1
1.4
0.5
0.1
2.5
40.4
5.6
8.6
4.9
2.4
61.9
1.2
0.2
1.0
0.2
—
2.6
50.5
7.0
22.6
9.3
3.6
93.0
46.80
2.61
14.68
3.43
37,840
11,979
$
$
$
$
$
$
(26)%
(41)%
(33)%
(47)%
(8)%
(34)%
(9)%
(3)%
(3)%
(30)%
(48)%
(13)%
(9)%
(12)%
18 %
(30)%
(27)%
(4)%
(10)%
(7)%
(13)%
(36)%
(40)%
(16)%
0.6
0.1
2.0
0.9
0.2
3.8
44.5
5.8
8.9
7.0
4.7
70.9
1.4
0.2
0.8
0.3
0.1
2.8
56.4
7.5
25.9
14.5
6.2
0.7
0.1
1.7
1.0
0.1
3.6
46.6
5.0
9.5
6.8
1.8
69.7
1.4
0.2
0.7
0.3
—
2.6
59.4
6.7
24.3
14.7
2.7
110.5
107.8
(50)% $
(40)% $
(56)% $
(50)% $
92.98
4.36
33.27
6.86
(14)%
— %
18 %
(10)%
100 %
6 %
(5)%
16 %
(6)%
3 %
161 %
2 %
— %
— %
14 %
— %
100 %
8 %
(5)%
12 %
7 %
(1)%
130 %
2 %
(8)%
13 %
(11)%
18 %
28 %
**
138 %
**
28 %
101.21
3.84
37.26
5.82
36,784
1,811
65,529
776
26,512
$
$
$
$
$
$
$
$
$
$
2,310
200 %
47,236
33,387
(20)% $
(64)% $
47,236
33,387
133,380
$ 156,117
(15)% $ 156,117
285,877
26,402
$
$
47,693
34,045
499 % $
47,693
(22)% $
34,045
(30,582) $
6,923
(542)% $
6,923
55
Year Ended December 31,
Year Ended December 31,
2015
(719) $
2014
(2,687)
%
(73)% $
2014
(2,687) $
2013
29,482
%
(91)%
1.11
0.78
3.93
$
$
$
1.17
0.84
3.87
(5)% $
(7)% $
2 % $
1.17
0.84
3.87
$
$
$
1.30
0.94
2.32
(10)%
(10)%
67 %
Other Income (Expense)
Selected data per Mcfe:
Operating expenses
General and administrative expenses
Depreciation, depletion and amortization
** Greater than 1,000%
$
$
$
$
Natural Gas, Oil and NGL Sales and Production
All of our revenues are from the sale of our natural gas, crude oil and natural gas liquids production. Our revenues may vary
significantly from year to year depending on changes in commodity prices, which fluctuate widely, and production volumes. Our
production volumes are subject to wide swings as a result of new discoveries, weather and mechanical related problems. In addition,
the production rate associated with our oil and gas properties declines over time as we produce our reserves.
We reported revenues of approximately $116.5 million for the year ended December 31, 2015, compared to revenues of
approximately $276.5 million for the year ended December 31, 2014. This decrease in revenues was primarily attributable to lower oil
and natural gas prices in 2015 and lower production resulting from the significant reduction in our capital program because of the
dramatic decline in, and uncertain outlook for, commodity prices.
Total production for the year ended December 31, 2015 was approximately 34.0 Bcfe, or 93.0 Mmcfe/d, compared to
approximately 40.3 Bcfe, or 110.5 Mmcfe/d, in the prior year, a decline attributable in large part to our limited drilling activity in 2015
due to the low commodity price environment. Net natural gas production for the year ended December 31, 2015 was approximately
61.9 Mmcf/d, compared with approximately 70.9 Mmcf/d for the year ended December 31, 2014, due to normal decline in production
from our offshore properties. Net oil production declined from 3,800 barrels per day to 2,500 barrels per day, while NGL production
decreased from approximately 2,800 barrels per day to 2,600 barrels per day, both decreases as a result of normal decline that was not
offset by new production from a limited 2015 capital program.
We reported revenues of approximately $276.5 million for the year ended December 31, 2014, compared to revenues of
approximately $164.1 million for the year ended December 31, 2013. This increase in revenues was primarily attributable to our
merger with Crimson, to additional interests purchased in our Dutch wells in December 2013, to production from our South Timbalier
17 discovery which began producing in July 2014, and to new natural gas, oil, condensate and NGL production from our 2014 drilling
program, partially offset by lower oil, condensate and NGL prices. Revenue for 2013 was also negatively impacted by our Vermilion
170 well shut-in for the first half of 2013 for workover.
Total production for the year ended December 31, 2014 was approximately 40.3 Bcfe, or 110.5 Mmcfe/d, compared to
approximately 28.2 Bcfe, or 107.8 Mmcfe/d, for the year ended December 31, 2013, an increase primarily attributable to our merger
with Crimson, new production from our 2014 drilling program, the resumption of production at Vermilion 170 and the additional
interests purchased in our Dutch wells discussed above. This increase was partially offset by the shut-in for approximately three
weeks, and subsequent ramp up during the third quarter 2014, to install compression for the Dutch and Mary Rose wells. Our net
natural gas production for the year ended December 31, 2014 was 70.9 Mmcf/d, up from approximately 69.7 Mmcf/d for the year
ended December 31, 2013. Additionally, net oil production increased from 3,600 barrels per day to 3,800 barrels per day, while NGL
production increased from approximately 2,600 barrels per day to 2,800 barrels per day.
Average Sales Prices
The average equivalent sales price realized for the years ended December 31, 2015, 2014 and 2013 were $3.43 per Mcfe,
$6.86 per Mcfe and $5.82 per Mcfe, respectively. For the year ended December 31, 2015, the price of natural gas was $2.61 per Mcf
while the price for oil and NGLs was $46.80 per barrel and $14.68 per barrel, respectively. For the year ended December 31, 2014, the
price of natural gas was $4.36 per Mcf while the prices for oil and NGLs were $92.98 per barrel and $33.27 per barrel, respectively.
56
For the year ended December 31, 2013, the price of natural gas was $3.84 per Mcf while the prices for oil and NGLs were $101.21 per
barrel and $37.26 per barrel, respectively.
Operating Expenses (including production taxes)
Operating expenses for the year ended December 31, 2015 were approximately $37.8 million, or $1.11 per Mcfe, compared
to approximately $47.2 million, or $1.17 per Mcfe, for the year ended December 31, 2014. Operating expenses for the year ended
December 31, 2013 were approximately $36.8 million, or $1.30 per Mcfe. The table below provides additional detail of operating
expenses for the years ended December 31, 2015, 2014 and 2013.
Twelve Months Ended December 31,
2015
2014
2013
Lease operating expenses
Production & ad valorem taxes
Transportation & processing costs
Workover costs
Total operating expenses
(in thousands)
(per Mcfe)
(in thousands)
(per Mcfe)
(in thousands)
(per Mcfe)
$
$
25,124 $
4,747
4,714
3,255
37,840 $
0.74
0.14
0.13
0.10
1.11
$
$
27,271 $
11,513
5,855
2,597
47,236 $
0.68
0.29
0.14
0.06
1.17
$
$
15,682 $
4,693
4,336
12,073
36,784 $
0.55
0.17
0.15
0.43
1.30
Lease operating expenses decreased by 8% for the year ended December 31, 2015, compared to the year ended December 31,
2014, as a direct result of our efforts to reduce costs during the second half of 2015 during this challenging commodity price
environment. Production and ad valorem taxes decreased by 59% for the year ended December 31, 2015, compared to the prior year,
primarily due to the decrease in revenues for the same period.
Lease operating expenses increased for the year ended December 31, 2014, compared to the year ended December 31, 2013,
primarily due to the incremental operational activity associated with the expanded asset base as a result of our merger with Crimson.
Production and ad valorem taxes increased for the year ended December 31, 2014, compared to the prior year, primarily due to the
increase in revenues related to the Merger. The $12.0 million in workover costs for the year ended December 31, 2013, was associated
with the tubing and casing replacement at Vermilion 170.
Exploration Expenses
We reported approximately $12.0 million of exploration expenses for the year ended December 31, 2015, which included
$6.7 million in dry-hole costs related to our State #1H well in Natrona County, Wyoming, and $2.8 million related to the early
termination of a drilling rig contract, compared to $33.4 million for the year ended December 31, 2014. The 2014 costs include $31.5
million related to our exploratory dry hole at Ship Shoal 255 and $1.9 million for geological and geophysical activities, seismic data
and delay rentals. We reported approximately $1.8 million of exploration expenses for the year ended December 31, 2013.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for the year ended December 31, 2015 was approximately $133.4 million, or $3.93
per Mcfe, compared with approximately $156.1 million, or $3.87 per Mcfe, for the year ended December 31, 2014, a decrease
primarily attributable to lower production during 2015. The rate was reduced substantially for the fourth quarter 2015 as a result of
the impairment recorded in the quarter ended September 30, 2015, as discussed below.
Depreciation, depletion and amortization for the year ended December 31, 2014 was approximately $156.1 million, or $3.87
per Mcfe, compared to approximately $65.5 million, or $2.32 per Mcfe, for the year ended December 31, 2013, an increase primarily
attributable to the expanded asset base and production levels subsequent to our merger with Crimson.
Impairment and Abandonment of Oil and Gas Properties
Impairment and abandonment expenses for the year ended December 31, 2015 included producing property impairment of
$269.6 million related to the decline in commodity prices and the resulting impact on estimated future net cash flows from associated
reserves. Approximately $235.8 million of the total producing property impairment for the year ended December 31, 2015 is
57
attributable to the Madison/Grimes counties and Zavala/Dimmit/Karnes counties properties, our highest valued properties stemming
from the Merger with Crimson. Impairment expenses for the year ended December 31, 2015 included a $16.3 million impairment of
certain unproved properties and onshore prospects due primarily to the sustained low commodity price environment and expiring
leases. Approximately $9.3 million of the total for the year ended December 31, 2015 is related to unproved lease cost amortization of
the Elm Hill project in Fayette and Gonzales counties, Texas.
Impairment and abandonment expenses for the year ended December 31, 2014 included producing property impairments of
$7.7 million for South Timbalier 17 and $3.7 million for the Tuscaloosa Marine Shale (“TMS”) proved properties due to performance
and commodity price declines in 2014, $3.5 million impairment of unproved leasehold cost related to the dry hole on our Ship Shoal
255 block and $12.1 million for impairment of an existing platform which was expected to be used by the Ship Shoal 255 well if it had
been successful. Impairment expenses for the year ended December 31, 2014 also included a $20.1 million impairment charge for
certain unproved prospects due to expiring leases and leases not likely to be drilled, primarily related to GOM leases and unproved
TMS leases.
For the year ended December 31, 2013, the Company recorded impairment expense of approximately $0.8 million, related to
expiring leasehold costs in our Ship Shoal 83 and Brazos 543 prospects.
General and Administrative Expenses
General and administrative expenses for the year ended December 31, 2015 were approximately $26.4 million, compared to
$34.0 million for the year ended December 31, 2014. Included in our current year expense was approximately $0.6 million in cash
severance costs resulting from an August 2015 reduction in force and $6.5 million in non-cash stock based compensation. Included in
the prior year expense was approximately $4.5 million in non-cash stock based compensation and $2.6 million in merger-related costs.
Exclusive of the stock compensation and severance related costs, cash general and administrative expenses for the current year were
$19.3 million, compared to cash expenses of $29.5 million for the prior year. The 2015 reduction in force was a major step in our
ongoing cost cutting efforts necessitated by the current challenging commodity price environment.
General and administrative expenses for the year ended December 31, 2014 were approximately $34.0 million, compared to
$26.5 million for the year ended December 31, 2013. General and administrative expenses for the year ended December 31, 2014
included approximately $4.5 million in non-cash stock based compensation and $2.6 million in merger-related costs. General and
administrative expenses for the year ended December 31, 2013 included approximately $3.2 million in non-cash stock based
compensation and $3.9 million attributable to the merger with Crimson.
Gain (loss) from Affiliates
For the year ended December 31, 2015, the Company recorded a loss from affiliates of approximately $30.6 million, net of
tax benefit of $16.5 million, related to our equity investment in Exaro, compared with a gain from affiliates of approximately $6.9
million, net of taxes of $3.8 million, for the year ended December 31, 2014. The decline in 2015 was related primarily to an
impairment of Exaro’s oil and gas properties as a result of the recent dramatic decline in commodity prices.
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.
Other Income (Expense)
Other expense for the year ended December 31, 2015 was approximately $0.7 million, which is primarily related to $5.6
million of costs incurred in pursuit of an unsuccessful acquisition in the fourth quarter and interest expense of $3.2 million, partially
offset by $6.1 million in proceeds related to favorable outcomes in two lawsuits and realized gains on derivatives of $2.3 million.
Other expense for the year ended December 31, 2014 was approximately $2.7 million, which is primarily related to interest
expense.
Other income for the year ended December 31, 2013 was approximately $29.5 million, which included a $15.3 million gain
on the sale of assets related to our equity investment in Alta Resources, Inc., a $6.6 million gain related to the disposition of a minority
working interest in all developed and undeveloped properties in Madison and Grimes counties, and the proceeds from a $10 million
58
key-man life insurance policy on the Company's former Chairman, President and Chief Executive Officer, Mr. Kenneth Peak, who
passed away on April 19, 2013.
Capital Resources and Liquidity
Our primary cash requirements are for capital expenditures, working capital, operating expenses, acquisitions and principal
and interest payments on indebtedness. Our primary sources of liquidity are cash generated by operations, net of the realized effect of
our hedging agreements, and amounts available to be drawn under our credit facility.
The table below summarizes certain measures of liquidity and capital expenditures, as well as our sources of capital from
internal and external sources, for the periods indicated, in thousands.
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by (used in) financing activities
Cash and cash equivalents at the end of the period
Year ended December 31,
2015
2014
2013
24,955
(76,806)
51,851
$
$
$
— $
209,960
(175,057)
(34,903)
$
$
$
— $
105,037
(34,795)
(149,729)
—
$
$
$
$
Cash flow from operating activities, including changes in working capital, provided approximately $25.0 million in cash for
the year ended December 31, 2015 compared to $210.0 million for the year ended December 31, 2014. The deficit in working capital
was reduced by approximately $27.2 million during 2015, compared to an increase in 2014 of approximately $16.7 million. Cash flow
from operating activities, excluding changes in working capital, provided approximately $52.2 million in cash for the year ended
December 31, 2015 compared to $193.3 million for the year ended December 31, 2014. This decrease in cash provided by operating
activities was primarily attributable to lower oil and natural gas prices for 2015, as well as a decline attributable to our reduced drilling
activity in 2015 due to the low commodity price environment.
Cash flow from operating activities provided approximately $210.0 million in cash for the year ended December 31, 2014
compared to $105.0 million for the year ended December 31, 2013. This increase in cash provided by operating activities was
primarily attributable to our merger with Crimson.
Cash used in investing activities was approximately $76.8 million for the year ended December 31, 2015, which included
approximately $77.8 million for capital expenditures, partially offset by approximately $1.0 million in distributions from REX as a
result the dissolution of that entity.
Cash used in investing activities was approximately $175.1 million for the year ended December 31, 2014, which included
approximately $180.4 million for capital expenditures, partially offset by approximately $5.4 million related to the sale of assets and
distributions from affiliates.
Cash used in investing activities was approximately $34.8 million for the year ended December 31, 2013, which included
approximately $62.6 million for capital expenditures and approximately $15.4 million for investments in affiliates, partially offset by
approximately $43.2 million related to the sale of assets and distributions from affiliates.
Cash provided by financing activities was approximately $51.9 million for the year ended December 31, 2015 compared to
$34.9 million used in financing activities in 2014. The cash provided by financing activities in 2015 was primarily attributable to net
borrowings under our RBC Credit Facility (defined below) used to reduce the working capital deficit at December 31, 2014, while the
cash used in financing activities in 2014 reflected the net repayment of borrowings under the RBC Credit Facility that existed at the
beginning of that year.
Cash used in financing activities was approximately $34.9 million for the year ended December 31, 2014 compared to $149.7
million used in financing activities in 2013, a change primarily attributable to the retirement of a portion of Crimson's debt assumed
upon closing of the Merger, partially offset by post-merger borrowings under our RBC Credit Facility.
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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 balance under its senior secured revolving
credit facility with Wells Fargo and other lenders, and $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”), which matures on October 1, 2017, with an initial hydrocarbon-supported borrowing base of $275
million. As part of the regular redetermination schedule, the borrowing base was redetermined at $225 million effective May 8, 2015,
and $190 million effective November 13, 2015 due primarily to lower commodity prices and the impact of the significant reduction in
the Company’s drilling program in 2015. The borrowing base under our RBC Credit Facility is redetermined each November 1 and
May 1. Since the last regularly scheduled redetermination of our borrowing base, effective through May 1, 2016, commodity prices
have continued to decline. The decline in prices will likely negatively impact the price decks utilized by banks in their calculation of
the Company’s borrowing base at May 1, 2016. If our next borrowing base redetermination results in a lower borrowing base, we may
be unable to obtain financing otherwise currently available under the RBC Credit Facility.
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 producing 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 0.50% to 2.50% margin
dependent upon the amount of borrowings outstanding.
On October 28, 2014, the Company entered into a second amendment to the RBC Credit Facility, which reduced the effective
interest rate on borrowings and provided for the repurchase by the Company of common shares under its 2011 Share Repurchase Plan,
subject to certain limitations. As of December 31, 2015, we had $115.4 million outstanding under the RBC Credit Facility, compared
with $63.4 million outstanding under the RBC Credit Facility at the end of 2014.
The RBC Credit Facility requires us to maintain a Current Ratio of greater than or equal to 1.0 and a Leverage Ratio of less
than or equal to 3.50, both as defined in the RBC Credit Facility Agreement. Our compliance with these covenants is tested each
quarter. At December 31, 2015, we were in compliance with the covenants under the RBC Credit Facility, and at current commodity
prices, we do not except any covenant compliance issues over the next twelve months. 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 in our resource plays and in our conventional onshore inventory in the Texas Gulf Coast,
with activity in any particular area and period of time 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; however, there can be no assurance that we will be successful in consummating any acquisitions, or that any such
acquisition 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 2016 capital expenditures to a level within our
forecasted cash flow from operations for the year; however, we do possess the capacity, through forecasted excess cash flow and
through our RBC Credit Facility, to increase and/or accelerate drilling on any particular area should we determine that market and
project economics so warrant. Our ability to execute on our growth strategy will be determined, in large part, by our cash flow and the
60
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 2016 capital budget is expected to be funded from internally generated cash flow, exclusive of acquisitions, if any, and
due to the current commodity price environment will be focused primarily on: (i) the preservation of our strong and flexible financial
position by limiting our overall capital expenditure budget to no more than internally generated cash flow; (ii) focusing expenditures
on strategic projects only, and (iii) identification of opportunities for cost efficiencies in all areas of our operations. Our current capital
budget for 2016 should allow us to meet our contractual requirements, remain in position to preserve our term acreage where
appropriate and maintain our already healthy financial profile during this challenging period for our industry. We will continuously
monitor the commodity price environment, and if warranted, make adjustments to our investment strategy as the year progresses.
Inflation and Changes in Prices
While the general level of inflation affects certain costs associated with the energy industry, factors unique to the industry
result in independent price fluctuations. Such price changes have had, and will continue to have, a material effect on our operations;
however, we cannot predict these fluctuations.
Income Taxes
During the year ended December 31, 2015, we received a refund of approximately $0.2 million in federal and state income
taxes. During the years ended December 31, 2014 and 2013, we paid approximately $0.2 million and $0.3 million, respectively, in
federal and state income taxes, net of cash refunds received.
Contractual Obligations
The following table summarizes our known contractual obligations as of December 31, 2015:
Payment due by period (thousands)
Long term debt and interest (1)
Delay rentals
Asset retirement obligations
Employment agreements
Operating leases (2)
Hardware/software
Uncertain income tax positions (3)
Total
$
$
$
Total
121,446
1,068
27,109
2,088
7,182
203
Less than
1 year
2,839
345
4,603
2,088
3,182
113
1 - 3 years
3 - 5 years
$
118,607
308
$
— $
205
2,636
—
3,584
90
1,291
—
416
—
—
1,912
More than
5 years
—
210
18,579
—
—
—
360
159,456
$
—
13,170
$
—
125,225
$
360
19,149
$
(1) Estimated interest is based on the outstanding debt at December 31, 2015 using the interest rate in effect at that time.
(2) Operating leases include contracts related to office space, compressors, vehicles, office equipment and other. Operating lease commitments from our previous
office space are expected to be substantially recovered by the subleases that we have entered into for the remainder of our lease term.
(3) 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. 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
61
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, 2015 of 5%, 10% and 15% would affect depreciation, depletion and amortization expense by approximately $1.0 million,
$2.2 million and $3.4 million, respectively.
Impairment of Natural Gas and Oil Properties
The Company reviews its proved natural gas and oil properties for impairment whenever events and circumstances, such as
the current low commodity price environment, indicate a potential decline in the recoverability of their carrying value. An impairment
loss associated with an asset group is the amount by which the carrying amount of a long-lived asset is not recoverable and exceeds its
fair value. An asset’s fair value is preferably indicated by a quoted market price in the asset’s principal market. Unlike many
businesses where independent appraisals can be obtained for items such as equipment, oil and gas proved reserves are unique assets.
Most oil and gas valuations are based on a combination of the income approach and market approach methodologies. We utilize the
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income approach also known as the discounted cash flow (“DCF”) approach. Under the DCF method in determining fair value, there
are specific guidelines and ranges within the evaluation that we can consider and estimate.
The Company compares expected undiscounted future net cash flows from each field to the unamortized capitalized cost of
the asset. If the future undiscounted net cash flows, based on the Company’s estimate of future natural gas and oil prices and operating
costs and anticipated production from proved reserves, are lower than the unamortized capitalized cost, then the capitalized cost is
reduced to fair market value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future
commodity pricing, future production estimates, and anticipated capital expenditures. Unproved properties are reviewed quarterly to
determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Drilling
activities in an area by other companies may also effectively impair leasehold positions. Given the complexities associated with
natural gas and oil reserve estimates and the history of price volatility in the natural gas and oil markets, events may arise that will
require the Company to record an impairment of its natural gas and oil properties and there can be no assurance that such impairments
will not be required in the future nor that they will not be material. Assuming strip pricing as of March 1, 2016 through 2020 and
keeping pricing flat thereafter, instead of 2015 SEC pricing, while leaving all other parameters unchanged, the Company’s proved
reserves would have been 185.4 Bcfe and the PV-10 value of proved reserves would have been $226.3 million.
Derivative Instruments
At the end of each reporting period we record on our balance sheet the mark-to-market valuation of our derivative
instruments. The estimated change in fair value of the derivatives, along with the realized gain or loss for settled derivatives, is
reported in Other Income (Expense) as Gain (loss) on derivatives, net.
Income Taxes
Income taxes are provided for the tax effects of transactions reported in the financial statements and consist 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. As of December 31, 2015, we had federal net operating loss (“NOL”) carryforwards of
$140.4 million which occurred due to the Merger, and subsequent taxable losses in 2014 and 2015 due to lower commodity prices and
impairment of oil and gas property. Generally, these NOLs are available to reduce future taxable income and the related income tax
liability subject to the limitations set forth in Internal Revenue Code Section 382. Given the uncertainty of our ability to generate
taxable income, a valuation allowance of $57.5 million has been recorded for the year ended December 31, 2015 against the deferred
tax assets, reduced by the amount of the deferred tax liability.
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. 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
63
between fair value and tax basis of assets acquired and liabilities assumed. To the extent the purchase price plus the liabilities assumed
(including deferred income taxes recorded in connection with the transaction) exceeds the fair value of the net assets acquired, we are
required to record the excess as goodwill. As the fair value of assets acquired and liabilities assumed is subject to significant estimates
and subjective judgments, the accuracy of this assessment is inherently uncertain. The value assigned to recoverable oil and gas
reserves is subject to the impairment test when facts or circumstances indicate that the value of the properties may be impaired, and
the value assigned to unproved properties is assessed at least annually to ascertain whether impairment has occurred. If the initial
accounting for the business combination is not complete, the amounts recognized for assets acquired and liabilities assumed in the
financial statements may be adjusted during the measurement period of up to one year as specified by Accounting Standards
Codification (“ASC”) 805, Business Combinations.
Recent Accounting Pronouncements
In February 2016, the FASB issued Accounting Standards Update No. 2016-02: Leases (Topic 842) (ASU 2016-02). The
main objective of ASU 2016-02 is to increase transparency and comparability among organizations by recognizing lease assets and
lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between
previous GAAP and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating
leases. ASU 2016-02 requires lessees to recognize assets and liabilities arising from leases on the balance sheet. ASU 2016-02 further
defines a lease as a contract that conveys the right to control the use of identified property, plant, or equipment for a period of time in
exchange for consideration. Control over the use of the identified asset means that the customer has both (1) the right to obtain
substantially all of the economic benefit from the use of the asset and (2) the right to direct the use of the asset. ASU 2016-02 requires
disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and
uncertainty of cash flows arising from leases. In transition, lessees and lessors are required to recognize and measure leases at the
beginning of the earliest period presented using a modified retrospective approach. For public entities, ASU 2016-02 is effective for
financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years;
early application is permitted. The Company will continue to assess the impact this may have on its financial position, results of
operations, and cash flows.
In January 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update No. 2016-01:
Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (ASU
2016-01). The main objective of ASU 2016-01 is enhancing the reporting model for financial instruments to provide users of financial
statements with more decision-useful information. The amendments in ASU 2016-01 make targeted improvements to GAAP by: (i)
requiring equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of
the investee) be measured at fair value with changes in fair value recognized in net income; (ii) simplifying the impairment assessment
of equity investments without readily determinable fair values by requiring a qualitative assessment to identify impairment; (iii)
exempting all non-public business entities from disclosing fair value information for financial instruments measured at amortized cost;
(iv) eliminating requirement for public business entities to disclose the methods and significant assumptions used to estimate the fair
value for financial instruments measured at amortized cost on the balance sheet: (v) requiring public business entities to use the exit
price notion when measuring the fair value of financial instruments for disclosure purposes; (vi) requiring separate presentation in
other comprehensive income the portion of the total change in fair value of a liability resulting from a change in the instrument-
specific credit risk when the entity has elected to measure the liability at fair value in accordance with the fair value option for
financial instruments; (vii) requiring separate presentation of financial assets and financial liabilities by measurement category and
form of financial asset; and (viii) clarifying that an entity should evaluate the need for a valuation allowance on a deferred tax asset
related to available-for-sale securities in combination with the entity’s other deferred tax assets. For public entities, ASU 2016-01 is
effective for financial statements issued for fiscal years beginning after December 15, 2017, including interim periods within those
fiscal years; early application is permitted. The provisions of this accounting update are not expected to have a material impact on the
Company’s financial position or results of operations.
In November 2015, the FASB issued Accounting Standards Update No. 2015-17: Income Taxes (Topic 740): Balance Sheet
Classification of Deferred Taxes (ASU 2015-17). ASU 2015-17 is part of an initiative to reduce complexity in accounting standards.
Current GAAP requires an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a
classified statement of financial position. However, this classification does not generally align with the time period in which the
recognized deferred tax amounts are expected to be recovered or settled. To simplify the presentation of the deferred income taxes,
ASU 2015-17 requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position.
64
The current requirement that deferred tax liabilities and assets of an entity be offset and presented as a single amount is not affected by
the amendments of ASU 2015-17. For public entities, ASU 2015-17 is effective for financial statements issued for fiscal years
beginning after December 15, 2016, and interim periods within those fiscal years; early application is permitted. The Company has
selected early application starting with the financial statements issued for the year ended December 31, 2015. The provisions of this
accounting update do not have a material impact on the Company’s financial position or results of operations. Accordingly, the
deferred tax liability and the valuation allowance are classified as non-current.
In September 2015, the FASB issued Accounting Standards Update No. 2015-16: Business Combinations (Topic 805):
Simplifying the Accounting for Measurement-Period Adjustments (ASU 2015-16). ASU 2015-16 is part of an initiative to reduce
complexity in accounting standards, and requires that an acquirer recognize adjustments to provisional amounts that are identified
during the measurement period in the reporting period in which the adjustment amounts are determined. In addition, the amendments
of this update require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in
depreciation, amortization, or other income effects, if any, as a result of the changes to the provisional amounts, calculated as if the
accounting had been completed at the acquisition date. Furthermore, ASU 2015-16 requires an entity to present separately on the face
of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would
have been recorded in previous reporting periods if the adjustments to the provisional amounts had been recognized as of the
acquisition date. For public entities, ASU 2015-16 is effective for fiscal years beginning after December 15, 2015, including interim
periods within those fiscal years. The provisions of this accounting update are not expected to have a material impact on the
Company’s financial position or results of operations.
In August 2014, the FASB issued Accounting Standards Update No. 2014-15: Presentation of Financial Statements – Going
Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (ASU 2014-15).
ASU 2014-15 asserts that management should evaluate whether there are relevant condition or events that are known and reasonably
knowable that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date the
financial statements are issued or are available to be issued when applicable. If conditions or events at the date the financial statements
are issued raise substantial doubt about an entity’s ability to continue as a going concern, disclosures are required which will enable
users of the financial statements to understand the conditions or events as well as management’s evaluation and plan. ASU 2014-15 is
effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter; early application is
permitted. The provisions of this accounting update are not expected to have a material impact on our financial position or results of
operations.
In May 2014, the FASB and the International Accounting Standards Board jointly issued new accounting guidance for
recognition of revenue Accounting Standards Update No. 2014-09: Revenue from Contracts with Customers (Topic 606) (ASU 2014-
09). This new guidance replaces virtually all existing US GAAP and International Financial Reporting Standards guidance on revenue
recognition. ASU 2014-09 is effective for fiscal years beginning after December 15, 2017. This new guidance applies to all periods
presented. Therefore, when the Company issues its financial statements on Forms 10-Q and 10-K for periods included in its year
ended December 31, 2017, its comparative periods that are presented from the years ended December 31, 2015 and 2016, must be
retrospectively presented in compliance with this new guidance. Early adoption is not allowed for US GAAP. The new guidance
requires companies to make more estimates and use more judgment than under current accounting guidance. The Company does not
anticipate that this new guidance will have a material impact on the Company’s consolidated financial position or results of operations
for the periods presented.
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,
2015, the primary off-balance sheet arrangements that we have entered into included short-term drilling rig contracts and operating
lease agreements, all of which are customary in the oil and gas industry. Other than the off-balance sheet arrangements shown under
operating leases and drilling rig in the commitments and contingencies table, we have no other arrangements that are reasonably likely
to materially affect our liquidity or availability of or requirements for capital resources.
65
Item 7A. Quantitative and Qualitative Disclosure about Market Risk
Commodity Risk
We are exposed to various risks including energy commodity price risk for our oil, natural gas and natural gas liquids
production. When oil, natural gas, and natural gas liquids prices decline significantly our ability to finance our capital budget and
operations may be adversely impacted. Our major commodity price risk exposure is to the prices received. Realized commodity prices
received for our production are tied to the spot prices applicable to natural gas and crude oil at the applicable delivery points. Prices
received for oil, natural gas and natural gas liquids are volatile and unpredictable. For the year ended December 31, 2015, a 10%
fluctuation in the prices received for oil, natural gas and natural gas liquids production would have had an approximately $11.6 million
impact on our revenues.
Derivative Instruments and Hedging Activity
We expect commodity prices to remain volatile and unpredictable, therefore we have designed a risk management strategy
which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by
reducing the risk of price volatility and the affect it could have on our operations. The types of derivative instruments that we typically
utilize include swaps and costless collars. The total volumes which we hedge through the use of our derivative instruments varies from
period to period, however, since the Merger, our objective has generally been to potentially hedge approximately 40% to 50% of our
current and anticipated production for the next 12 to 18 months, excluding offshore production during hurricane season. As of
December 31, 2015, we did not have any commodity price hedges in place. In January 2016, we entered into financial derivative
contracts with a member of our bank group resulting in 1,300,000 MMBtus of natural gas per month being hedged from February
2016 through July 2016 and from November 2016 through December 2016, and 250,000 MMBtus of natural gas per month being
hedged from August 2016 through October 2016 through swaps. 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 institutions
deemed by management as competent and competitive market makers. The counterparties to the Company's current and previous
derivative contracts are large financial institutions and also lenders or affiliates of lenders in our RBC Credit Facility. We do 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 are also exposed to interest rate risk on our variable interest rate debt. If interest rates increase, our interest expense
would increase and our available cash flow would decrease. As of December 31, 2015, we have not entered into any derivative
contracts to reduce the exposure to market rate fluctuations. We continue to monitor our risk exposure as we incur future indebtedness
at variable interest rates and will look to continue our risk management policy as situations present themselves.
We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging, (ASC 815). ASC 815
establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability
measured at fair value. The estimated fair values for financial instruments under ASC 825, Financial Instruments (ASC 825) are
determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be
determined with precision. The estimated fair value of cash, cash equivalents, accounts receivable and accounts payable approximates
their carrying value due to their short-term nature. See Note 7 to our Financial Statements - "Derivative Instruments" for more details.
Interest Rate Sensitivity
We are exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily
from fluctuations in short-term rates, which are LIBOR and the U.S. prime rate based and may result in reductions of earnings or cash
flows due to increases in the interest rates we pay on these obligations.
As of December 31, 2015, our total long-term debt was $115.4 million, which bears interest at a floating or market interest
rate that is tied to the prime rate or LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate.
During the year ended December 31, 2015 our effective rate fluctuated between 1.7 percent and 4.5 percent, depending on the term of
66
the specific debt drawdowns. At December 31, 2015, we did not have any outstanding interest rate swap agreements. As of December
31, 2015, the weighted average interest rate on our variable rate debt was 2.4% 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 $1.2 million for a twelve month period.
Other Financial Instruments
As of December 31, 2015, 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 to hedge any changes in interest rates or credit ratings, and we do not plan to employ these
instruments in the future. Because of the nature of the issuers of the securities that we may invest in, we do not believe that we have
any cash flow exposure arising from changes in credit ratings. Based on a sensitivity analysis performed on the financial instruments
held as of December 31, 2015, 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-43 of this Form 10-K.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
An evaluation was performed under the supervision and with the participation of the Company’s senior management of the
effectiveness of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of
1934 (the “Exchange Act”)) as of December 31, 2015, the end of the period covered by this report. Based on that evaluation, the
Company’s management, including the President and Chief Executive Officer and the Chief Financial Officer, concluded that the
Company’s disclosure controls and procedures were effective as of such date to ensure that information required to be disclosed in the
reports that the Company files under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods
specified in the SEC’s rules and forms, and (ii) accumulated and communicated to the Company’s management, including the
President and Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow timely decisions regarding required
disclosures.
Changes in Internal Control Over Financial Reporting
There was no change in our internal controls over financial reporting during the fiscal quarter ended December 31, 2015 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 President and Chief Executive Officer and Chief Financial Officer, the Company conducted an evaluation
of the effectiveness of its internal control over financial reporting based on the framework in 2013 Internal Control-Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Company’s evaluation
under the framework in 2013 Internal Control-Integrated Framework, the Company’s management concluded that its internal control
over financial reporting was effective as of December 31, 2015.
67
Grant Thornton LLP, the independent registered public accounting firm that audited our consolidated financial statements
included in this Form 10-K, has audited the effectiveness of our internal control over financial reporting as of December 31, 2015, as
stated in their report which is included herein.
68
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, 2015, based on criteria established in the 2013 Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s
is responsible for maintaining effective internal control over financial reporting and for its assessment of the
management
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,
2015, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the
consolidated financial statements of the Company as of and for the year ended December 31, 2015, and our report dated March 14,
2016 expressed an unqualified opinion on those financial statements.
/s/ GRANT THORNTON LLP
Houston, Texas
March 14, 2016
69
Item 9B. Other Information
Amendment to Bylaws
On February 25, 2015, the board of directors of the Company adopted the Third Amended and Restated Bylaws (the
“Bylaws”) of the Company. The amendment and restatement of the Bylaws was effective immediately and includes, among other
things, the following changes:
Providing for additional disclosure requirements for notices of director nominations and stockholder proposals.
Modifying the time period during which notice of director nominations and stockholder proposals may be given.
Clarifying the procedures relating to the appointment of the chairman of a meeting of stockholders and the powers of the
chairman of a meeting to conduct such a meeting.
Clarifying that the board of directors has the power to fix the record date, meeting date, time and place for each special
meeting of stockholders.
Removing certain obsolete provisions arising from and relating to our merger with Crimson Exploration Inc.
Clarifying the requirements for removal of a director for cause by stockholders of the Company.
Designating the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain legal action,
unless the Company consents in writing to the selection of an alternative forum.
The foregoing description of the Bylaws is not complete and is qualified in its entirety by reference to the complete text of
the Bylaws, a copy of which is filed as Exhibit 3.2 to this Annual Report on Form 10-K and incorporated by reference herein.
Item 10. Directors, Executive Officers and Corporate Governance
PART III
The information regarding directors, executive officers, promoters and control persons required under Item 10 of Form 10-K
will be contained in our Definitive Proxy Statement for our 2016 Annual Meeting of Stockholders (the “Proxy Statement”) under the
headings “Proposal 1: Election of Directors”, “Executive Compensation”, “Section 16(a) Beneficial Ownership Reporting
Compliance” and “Corporate Governance and our Board” and is incorporated herein by reference. The Proxy Statement will be filed
with the SEC pursuant to Regulation 14A of the Exchange Act, not later than 120 days after December 31, 2015.
Item 11. Executive Compensation
The information required under Item 11 of Form 10-K will be contained in the Proxy Statement under the heading
“Executive Compensation” and is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required under Item 12 of Form 10-K will be contained in the Proxy Statement under the heading “Security
Ownership of Certain Other Beneficial Owners and Management” and is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required under Item 13 of Form 10-K will be contained in the Proxy Statement under the headings
“Corporate Governance and our Board”, “Transactions with Related Persons” and “Executive Compensation” and is incorporated
herein by reference.
70
Item 14. Principal Accountant Fees and Services
The information required under Item 14 of Form 10-K will be contained in the Proxy Statement under the subheading
“Principal Accountant Fees and Services” and is incorporated herein by reference.
71
The following is a description of the meanings of some of the oil and gas industry terms used in this report.
GLOSSARY OF SELECTED TERMS
2D seismic or 3D seismic. Geophysical data that depict the subsurface strata in two dimensions or three dimensions,
respectively. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D seismic.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, in reference to crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet of natural gas.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or
natural gas liquids.
Boe. Barrel of oil equivalent per day determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate
or natural gas liquids.
Boe/d. Boe per day.
Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree
Fahrenheit.
Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of
natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.
Development well. A well drilled into a proved natural gas or oil reservoir to the depth of a stratigraphic horizon known to be
productive.
Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of
such production exceed production expenses and taxes.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of
natural gas or crude oil in another reservoir.
Field. An area consisting of either a single reservoir or multiple reservoirs all grouped on or related to the same individual
geological structural feature and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. Thousand cubic feet of natural gas.
Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil,
condensate or natural gas liquids.
MMBbls. million barrels of crude oil or other liquid hydrocarbons.
MMBtu. million British Thermal Units. One MMBtu equates to one Mcf.
MMcf. million cubic feet of natural gas.
MMcfe. million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate
or natural gas liquids.
72
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)(6) 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, or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed
extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a
well.
Proved reserves. Has the meaning given to such term in Rule 4-10(a)(22) 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 economically producible in future years from known reservoirs under existing economic conditions,
operating methods and government regulations. Existing economic conditions include prices and costs at which economic
producibility from a reservoir is to be determined. The prices include consideration of changes in existing prices provided only by
contractual arrangements, but not on escalations based upon future conditions.
The area of a reservoir considered proved includes (A) the area identified by drilling and limited by fluid contacts, if any, and
(B) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain
economically producible oil and gas on the basis of available geological and engineering data. In the absence of data on fluid contacts,
proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geological,
engineering or performance data and reliable technology establishes a lower contact with reasonable certainty.
Reserves which can be produced economically through application of improved recovery techniques (including, but not
limited to, fluid injection) are included in the proved classification when successful testing by a pilot project, the operation of an
installed program in the reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering
analysis on which the project or program was based; and the project has been approved for development by all necessary parties and
entities, including governmental entities.
Proved undeveloped reserves. Has the meaning given to such term in Rule 4-10(a)(31) 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 directly
offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology
exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as
having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five
years, unless the specific circumstances, justify a longer time. 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 projects in the same reservoir, or by other evidence using
reliable technology establishing reasonable certainty.
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
73
in effect at the end of the period. PV-10 differs from Standardized Measure of Discounted Net Cash Flows because it does not include
the effects of income taxes or non-property related expenses such as general and administrative expenses and debt service or
depreciation, depletion and amortization on future net revenues. Neither PV-10 nor Standardized Measure of Discounted Net Cash
Flows represents an estimate of fair market value of natural gas and crude oil properties. PV-10 is used by the industry as an arbitrary
reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities that are not
dependent on the taxpaying status of the entity.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas
and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Trucking. The provision of trucks to move our drilling rigs from one well location to another and to deliver water and
equipment to the field.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the
production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on
the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.
74
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-36 of this Form 10-K. Financial statement schedules have been
omitted since they are either not required, not applicable, or the information is otherwise included.
(b) Exhibits:
The following is a list of exhibits filed as part of this Form 10-K. Where so indicated by a footnote, exhibits, which were
previously filed, are incorporated herein by reference.
Exhibit
Number
2.1
3.1
3.2
3.3
4.1
4.2
10.1
10.2
10.3
10.9
10.10
10.11
10.12
10.13
10.14
10.15
10.16
10.17
10.18
Description
Agreement and Plan of Merger, among Contango Oil & Gas Company, Contango Acquisition, Inc. and Crimson
Exploration Inc., dated as of April 29, 2013. (11)
Certificate of Incorporation of Contango Oil & Gas Company. (2)
Third Amended and Restated Bylaws of Contango Oil & Gas Company. (21)
Amendment to the Certificate of Incorporation of Contango Oil & Gas Company. (3)
Facsimile of common stock certificate of Contango Oil & Gas Company. (1)
Registration Rights Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, OCM Crimson
Holdings, LLC and OCM GW Holdings, LLC. (11)
Purchase and Sale Agreement between Juneau Exploration, L.P. and Contango Operators, Inc. dated October 1, 2010.
(7)
Limited Liability Company Agreement of Republic Exploration LLC dated August 24, 2000. (4)
Amendment to Limited Liability Company Agreement and Additional Agreements of Republic Exploration LLC dated
as of September 1, 2005. (4)
Amended and Restated Limited Liability Company Agreement of Republic Exploration LLC, dated April 1, 2008. (6)
10.4
10.5 * Amended and Restated 2005 Stock Incentive Plan (15)
10.6 * Contango Oil & Gas Company Amended and Restated 2009 Incentive Compensation Plan. (5)
10.7
10.8
First Amended and Restated Limited Liability Company Agreement dated as of March 31, 2012. (8)
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. (10)
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. (10)
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. (10)
Participation Agreement covering OCS-G 33596, Vermilion 170, dated as of July 1, 2010 between Republic
Exploration LLC and Contango Operators, Inc. (10)
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. (10)
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. (10)
Participation Agreement covering OCS-G 22738, South Timbalier 75, dated as of July 26, 2011 between Republic
Exploration LLC and Contango Operators, Inc. (10)
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. (10)
Participation Agreement covering Tuscaloosa Marine Shale, dated as of August 27, 2012 between Juneau Exploration
LP and Contango Operators, Inc. (10)
Letter Agreement dated as of June 8, 2012 between Juneau Exploration LP and Contango Operators, Inc. (10)
Participation Agreement covering Central Gulf of Mexico Lease Sale 216/222, dated as of August 27, 2012 between
75
10.19
10.20
10.21
10.22
10.23
10.24
10.25
10.26
10.27
10.28
10.29
10.30
10.31
10.32
10.33
10.34
10.35
10.36
10.37
10.38
14.1
21.1
21.2
23.1
23.2
23.3
23.4
23.5
24.1
31.1
31.2
32.1
32.2
99.1
99.2
99.3
99.4
Republic Exploration LLC and Contango Operators, Inc. (10)
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. (10)
Agreement to Purchase Overriding Royalty Interest, dated March 1, 2010 between Contango Offshore Exploration LLC
and Juneau Exploration LP. (10)
Employment Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company and Allan D. Keel. (11)
Employment Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company and E. Joseph Grady. (11)
First Right of Refusal Agreement between Contango Oil & Gas Company and Juneau Exploration, L.P., entered into as
of January 1, 2013. (12)
Advisory Agreement between Contaro Company and Juneau Exploration, L.P., entered into as of January 1, 2013. (12)
Employment Agreement, dated as of June 10, 2013, among Contango Oil & Gas Company and Jeffrey A. Sikora. (13)
Employment Agreement, dated as of June 7, 2013, among Contango Oil & Gas Company and A. Carl Isaac. (13)
Employment Agreement, dated as of June 7, 2013, among Contango Oil & Gas Company and John A. Thomas. (13)
Employment Agreement, dated as of June 7, 2013, among Contango Oil & Gas Company and Jay S. Mengle. (13)
Employment Agreement, dated as of June 7, 2013, among Contango Oil & Gas Company and Thomas H. Atkins. (13)
Transition Agreement, dated as of June 10, 2013, between Contango Oil & Gas Company and Marc Duncan. (14)
Participation Agreement covering Central Gulf of Mexico Lease Sale 227, dated as of March 21, 2013 between Republic
Exploration LLC and Contango Operators, Inc. (9)
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. (9)
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. (15)
First Amendment to Credit Agreement among Contango Oil & Gas Company, as Borrower, Royal Bank of Canada, as
Administrative Agent, and the Lenders Signatory Hereto. (17)
Second Amendment to Credit Agreement among Contango Oil & Gas company, as Borrower, Royal Bank of Canada, as
Administrative Agent, and the Lenders Signatory Hereto. (18)
Termination Agreement between Juneau Exploration LP and Contaro Company, dated July 15, 2014. (19)
* Contango Oil & Gas Company Director Compensation Plan. (20)
Liquidation Agreement between Juneau Exploration LP, Contango Operators, Inc and Fairfield Industries Incorporated,
dated December 31, 2015. †
Code of Ethics. (16)
List of Subsidiaries. †
Organizational Chart. †
Consent of William M. Cobb & Associates, Inc. †
Consent of Netherland, Sewell & Associates, Inc. †
Consent of W.D. Von Gonten & Co. †
Consent of Grant Thornton LLP. †
Consent of BDO USA, LLP. †
Powers of Attorney (included on signature page). †
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. †
Report of William M. Cobb & Associates, Inc. †
Report of Netherland, Sewell & Associates. †
Report of W.D. Von Gonten and Company †
Exaro Energy III LLC Financial Statements as of and for the years ended December 31, 2015 (Unaudited) †
76
99.5
99.6
Exaro Energy III LLC Financial Statements as of and for the year ended December 31, 2014 (Audited) †
Exaro Energy III LLC Financial Statements as of and for the years ended December 31, 2013 and 2012 (Unaudited) †
*
Indicates a management contract or compensatory plan or arrangement.
† Filed herewith
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
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 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 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 report on Form 8-K, dated September 2, 2005, as filed with the Securities and
Exchange Commission on September 8, 2005.
Filed as an exhibit to the Company’s Schedule 14A on Definitive Proxy Statement for 2014, as filed with the
Securities and Exchange Commission on April 11, 2014
Filed as an exhibit to the Company’s report on Form 8-K, dated 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-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 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
Filed as an exhibit to the Company’s report on Form 8-K dated as of April 11, 2014, as filed with the Securities and
Exchange Commission on April 15, 2014.
Filed as an exhibit to the Company’s report on Form 8-K dated as of October 28, 2014, as filed with the Securities and
Exchange Commission on October 31, 2014.
Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended June 30, 2014, as filed with the
Securities and Exchange Commission on August 11, 2014.
Filed as an exhibit to the Company’s Transition Report on Form 10-KT for the six months ended December 31, 2013,
as filed with the Securities and Exchange Commission on March 28, 2014.
Filed as an exhibit to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, as filed
with the Securities and Exchange Commission on March 3, 2015.
77
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its
SIGNATURES
behalf by the undersigned, thereunto duly authorized.
CONTANGO OIL & GAS COMPANY
By:
/s/ ALLAN D. KEEL
Allan D. Keel
Chief Executive Officer
Date: March 14, 2016
POWER OF ATTORNEY
Know all men by these presents, that the undersigned constitutes and appoints Allan D. Keel as his true and lawful attorneys-
in-fact and agent, with full power of substitution for him and in his name, place and stead, in any and all capacities to sign any and all
amendments or supplements to this Annual Report on Form 10-K, and to file the same, and with all exhibits thereto and other
documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent full
power and authority to do and perform each and every act and thing requisite and necessary to be done as fully to all intents and
purposes as he might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent or his substitute or
substitutes, may lawfully do or cause to be done by virtue hereof.
In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant
and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ ALLAN D. KEEL
Allan D. Keel
/s/ JOSEPH GRADY
E. Joseph Grady
/s/ DENISE DUBARD
Denise DuBard
/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
Chief Executive Officer (principal executive officer)
and Director
March 14, 2016
Chief Financial Officer (principal financial officer)
March 14, 2016
Chief Accounting Officer (principal accounting
officer)
Director
Director
Director
Director
Director
Director
78
March 14, 2016
March 14, 2016
March 14, 2016
March 14, 2016
March 14, 2016
March 14, 2016
March 14, 2016
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Cash Flows
Consolidated Statement of Shareholders’ Equity
Notes to Consolidated Financial Statements
Supplemental Oil and Gas Disclosures (Unaudited)
Quarterly Results of Operations (Unaudited)
Page
F-2
F-3
F-4
F-5
F-6
F-7
F-37
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, 2015 and 2014, and the related consolidated statements of operations, shareholders’
equity, and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are the
responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management,
as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the 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, 2015 and 2014, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted
in the United States of America.
As discussed in Note 2 to the consolidated financial statements, the Company adopted new accounting guidance in 2015, related to the
presentation of deferred income taxes.
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, 2015, based on criteria established in the 2013 Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and
our report dated March 14, 2016 expressed an unqualified opinion.
/s/ GRANT THORNTON LLP
Houston, Texas
March 14, 2016
F-2
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except shares)
December 31,
2015
December 31,
2014
CURRENT ASSETS:
Cash and cash equivalents
Accounts receivable, net
Prepaid expenses and other
Inventory
Current deferred tax asset
Total current assets
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, successful efforts method of accounting:
Proved properties
Unproved properties
Other property and equipment
Accumulated depreciation, depletion and amortization
Total property, plant and equipment, net
OTHER NON-CURRENT ASSETS:
Investments in affiliates
Other
Total other non-current assets
TOTAL ASSETS
CURRENT LIABILITIES:
Accounts payable and accrued liabilities
Current asset retirement obligations
Total current liabilities
NON-CURRENT LIABILITIES:
Long-term debt
Deferred tax liability
Asset retirement obligations
Total non-current liabilities
Total liabilities
COMMITMENTS AND CONTINGENCIES (NOTE 14)
SHAREHOLDERS’ EQUITY:
Common stock, $0.04 par value, 50 million shares authorized, 24,636,936 shares issued and
19,381,146 shares outstanding at December 31, 2015, 24,372,538 shares issued and 19,148,000
shares outstanding at December 31, 2014
Additional paid-in capital
Treasury shares at cost (5,255,790 shares at December 31, 2015 and 5,224,538 shares at December
31, 2014)
Retained earnings
Total shareholders’ equity
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
$
$
$
$
— $
20,504
1,228
540
—
22,272
1,187,707
16,439
1,081
(826,022)
379,205
14,222
1,057
15,279
416,756
36,358
4,603
40,961
115,446
—
22,506
137,952
178,913
$
$
—
25,309
1,941
2,166
1,624
31,040
1,138,054
35,783
1,084
(426,298)
748,623
62,085
1,667
63,752
843,415
92,892
4,123
97,015
63,359
93,952
21,623
178,934
275,949
974
239,524
(127,760)
125,105
237,843
416,756
$
963
233,278
(127,525)
460,750
567,466
843,415
The accompanying notes are an integral part of these consolidated financial statements.
F-3
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
REVENUES:
Oil and condensate sales
Natural gas sales
Natural gas liquids sales
Total revenues
EXPENSES:
Operating expenses
Exploration expenses
Depreciation, depletion and amortization
Impairment and abandonment of oil and gas properties
General and administrative expenses
Total expenses
OTHER INCOME (EXPENSE):
Gain (loss) from investment in affiliates (net of income taxes)
Interest expense
Gain (loss) on derivatives, net
Other income
Total other income (expense)
NET INCOME (LOSS) BEFORE INCOME TAXES
Income tax benefit (provision)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK
NET INCOME (LOSS) PER SHARE:
Basic
Diluted
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic
Diluted
Year Ended December 31,
2014
2015
2013
$
$
$
$
$
$
$
$
43,230
59,058
14,217
116,505
37,840
11,979
133,380
285,877
26,402
495,478
(30,582)
(3,164)
2,348
97
(31,301)
(410,274)
75,226
(335,048)
(17.67)
(17.67)
18,965
18,965
$
$
$
$
130,238
112,695
33,525
276,458
47,236
33,387
156,117
47,693
34,045
318,478
6,923
(2,658)
(153)
124
4,236
(37,784)
15,910
(21,874)
(1.15)
(1.15)
19,059
19,059
59,608
79,289
25,224
164,121
36,784
1,811
65,529
776
26,512
131,412
2,310
(1,171)
(1,132)
31,785
31,792
64,501
(23,139)
41,362
2.56
2.56
16,156
16,158
The accompanying notes are an integral part of these consolidated financial statements.
F-4
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Year Ended December 31,
2014
2015
2013
(335,048)
(21,874)
41,362
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
Unrealized loss (gain) on derivative instruments
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable and other
Decrease (increase) in prepaid expenses
Decrease in accounts payable and advances from joint owners
Increase (decrease) in other accrued liabilities
Increase in income taxes payable, net
Other
Net cash provided by operating activities
CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration and development expenditures
Sale of oil and gas properties
Return of investment in affiliates
Investment in affiliates
Distributions from affiliates
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility
Repayments under credit facility
Payment of long-term debt
Purchase of common stock
Proceeds from exercised options
Debt issuance costs
Net cash provided by (used in) financing activities
NET DECREASE IN CASH AND CASH EQUIVALENTS
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD
CASH AND CASH EQUIVALENTS, END OF PERIOD
$
$
$
$
$
$
$
133,380
285,870
6,494
(92,329)
231
47,049
6,516
—
4,261
714
(28,672)
(5,711)
886
1,314
24,955
(77,820)
—
1,014
—
—
(76,806)
356,102
(304,016)
—
(235)
—
—
51,851
$
$
$
$
156,117
47,075
31,488
(12,284)
—
(10,651)
4,515
(1,131)
28,942
(19)
(8,322)
(4,236)
884
(544)
209,960
(180,422)
—
—
—
5,365
(175,057)
491,257
(517,898)
—
(8,344)
120
(38)
(34,903)
$
$
$
$
$
— $
—
— $
$
— $
—
— $
65,529
767
(9)
13,159
(21,961)
(3,554)
3,180
1,410
(6,285)
30
(4,720)
3,569
11,778
782
105,037
(62,552)
20,000
—
(15,397)
23,154
(34,795)
180,394
(90,394)
(235,373)
(2,017)
31
(2,370)
(149,729)
(79,487)
79,487
—
The accompanying notes are an integral part of these consolidated financial statements.
F-5
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
(in thousands, expect share amounts)
Balance at December 31, 2012
Acquisition of Crimson
Exercise of stock options
Treasury shares at cost
Stock-based compensation
Net income
Balance at December 31, 2013
Exercise of stock options
Treasury shares at cost
Restricted shares activity
Stock-based compensation
Net loss
Balance at December 31, 2014
Treasury shares at cost
Restricted shares activity
Stock-based compensation
Dissolution of REX
Net loss
Balance at December 31, 2015
Common Stock
Shares
Amount
Additional
Paid-in
Capital
Treasury
Stock
Retained
Earnings
Total
Shareholders’
Equity
15,194,952 $
3,864,039
791
(52,370)
356,299
—
19,363,711 $
4,165
(232,013)
12,137
—
—
19,148,000 $
(31,252)
264,398
—
—
—
19,381,146 $
805 $
154
3
—
—
—
962 $
—
—
1
—
—
963 $
—
11
—
—
—
974 $
79,025 $ (117,163) $
146,414
26
—
3,179
—
—
—
(2,017)
—
—
228,644 $ (119,180) $
120
—
(1)
4,515
—
—
(8,345)
—
—
—
233,278 $ (127,525) $
—
(10)
6,256
—
—
(235)
—
—
—
—
239,524 $ (127,760) $
441,262 $
—
—
—
—
41,362
482,624 $
—
—
—
—
(21,874)
460,750 $
—
—
—
(597)
(335,048)
125,105 $
403,929
146,568
29
(2,017)
3,179
41,362
593,050
120
(8,345)
—
4,515
(21,874)
567,466
(235)
1
6,256
(597)
(335,048)
237,843
The accompanying notes are an integral part of these consolidated financial statements.
F-6
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Business
Contango Oil & Gas Company (collectively with its subsidiaries, “Contango” or the “Company”) is a Houston, Texas based,
independent oil and natural gas company. The Company’s business is to maximize production and cash flow from its offshore
properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore properties in various plays, and use that cash flow to
explore, develop, exploit, produce and acquire crude oil and natural gas properties in the onshore Texas Gulf Coast and Rocky
Mountain regions of the United States.
On October 1, 2013, the Company completed a merger with Crimson Exploration Inc. ("Crimson"), in an all-stock
transaction pursuant to which Crimson became a wholly-owned subsidiary of Contango (the "Merger"). As a result of the Merger, the
Company issued approximately 3.9 million shares of common stock in exchange for all of Crimson's outstanding capital stock. See
Note 4 - "Merger with Crimson Exploration Inc." for additional information.
The Company has historically focused operations in the GOM, but the Merger has given the Company access to lower risk,
long life resource plays. In 2015, the Company’s drilling activity focused primarily on the Woodbine oil and liquids-rich play in
Madison and Grimes counties, Texas (the Southeast Texas Region), in the Cretaceous Sands in Fayette and Gonzales counties, Texas
(the South Texas Region) and in Wyoming where the Company is initially targeting the Muddy Sandstone. The Company believes
these plays could provide long-term growth potential from multiple formations that it believes to be productive for oil and natural gas.
Additionally, the Company has (i) a 37% equity investment in Exaro Energy III LLC (“Exaro”) that is primarily focused on
the development of proved natural gas reserves in the Jonah Field in Wyoming; (ii) operated properties producing from various
conventional formations in various counties along the Texas Gulf Coast; (iii) operated producing properties in the Denver Julesburg
Basin (“DJ Basin”) in Weld and Adams counties in Colorado, which the Company believes may also be prospective in the Niobrara
Shale oil play; and (iv) operated producing properties in the Haynesville Shale, Mid Bossier and James Lime formations in East
Texas.
Due to the current challenging commodity price environment, the Company focused its 2015 capital program on: (i) the
preservation of its healthy financial position, including limiting its overall capital expenditure budget to internally generated cash
flow; (ii) dedicating capital primarily to de-risking and/or delineating strategic projects (i.e. versus field development); (iii) the
identification of opportunities for cost and production efficiencies in all areas of its operations; and (iv) continuing to identify and,
when appropriate, pursue the expansion of its resource potential through opportunistic acquisitions.
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 Republic Exploration LLC (“REX”), are
proportionately consolidated. Financial statements as of December 31, 2015 and 2014 and for the three years ended December 31,
2015 contained herein, include consolidated results of operations of both Contango Oil & Gas Company and Crimson for the period
from the closing date of the Merger to December 31, 2015 and only consolidated financial statements of Contango for all other the
periods presented herein.
Change of Year-End
On October 1, 2013, the Company's board of directors approved a change in fiscal year end from June 30 to December 31,
commencing with the twelve-month period beginning on January 1, 2014. Unless otherwise noted, all references to "years" in this
report refer to the twelve-month period which ends on December 31 of each year.
F-7
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Other Investments
The Company has two seats on the board of directors of Exaro and has significant influence, but not control, over the
company. As a result, the Company's 37% ownership in Exaro is accounted for using the equity method. Under the equity method, the
Company's proportionate share of Exaro's net income increases the balance of its investment in Exaro, while a net loss or payment of
dividends decreases its investment. In the consolidated statement of operations, the Company’s proportionate share of Exaro's net
income or loss is reported as a single line-item in Gain (loss) from investment in affiliates (net of income taxes).
Contango’s 21.9% ownership of Moblize Inc. (“Moblize”) and 2.0% indirect ownership of Alta Energy Canada Partnership,
LLC ("Alta") are accounted for using the cost method, as the Company does not exercise significant influence over either company.
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 Other income line item in the
Company's statement of operations and in the investing cash flows in the Company's statement of cash flow for the year ended
December 31, 2013.
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, 2015, 2014 and 2013, 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, 2015, the Company had no cash and cash equivalents, as cash balances at the end of each day are
transferred to reduce outstanding debt under our revolving credit facility to minimize debt service costs. Under the Company’s cash
management system, checks issued but not yet presented to banks by the payee frequently result in book overdraft balances for
accounting purposes and are classified in accounts payable in the consolidated balance sheets. At December 31, 2015, accounts
payable included $6.8 million representing outstanding checks that had not been presented for payment net of cash balance in the bank
as of December 31, 2015. At December 31, 2014, accounts payable included $12.1 million representing outstanding checks that had
not been presented for payment net of cash balance in the bank as of December 31, 2014.
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.
F-8
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The Company
periodically reviews the accounts receivable from customers for any collectability issues. An allowance for doubtful accounts is
established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent
factors. Amounts deemed uncollectible are charged to the allowance.
Accounts receivable allowance for bad debt was $0.7 million and $0.6 million, as of December 31, 2015 and 2014,
respectively. At December 31, 2015 and 2014, 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 net of salvage value, are computed using the unit-of-
production method on a field basis based on total estimated proved developed natural gas and crude oil reserves. Amortization of
producing leaseholds is based on the unit-of-production method using total estimated proved reserves. Upon sale or retirement of
properties, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the accounts and the
resulting gain or loss, if any, is recognized. Unit-of-production rates are revised whenever there is an indication of a need, but at least
annually. Revisions are accounted for prospectively as changes in accounting estimates.
Other property and equipment are depreciated using the straight-line method over their estimated useful lives which range
between three and 13 years.
Impairment of Oil and Gas Properties
When circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future
cash flows on a field by field basis to the unamortized capitalized cost of the asset. If the estimated future undiscounted cash flows,
based on the Company’s estimate of future reserves, natural gas and oil prices, operating costs and production levels from oil and
natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to its fair value. The factors
used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the
timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining
for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. For the
year ended December 31, 2015, the Company recorded an impairment expense of approximately $269.6 million related to proved
properties. Approximately $235.8 million of this amount is attributable to the Madison/Grimes counties and Zavala/Dimmit/Karnes
counties properties. For the year ended December 31, 2014, the Company recorded an impairment expense of approximately $11.4
million related to proved properties. Of this amount, $7.7 million related to South Timbalier 17 and $3.7 million related to the
Tuscaloosa Marine Shale (“TMS”), a shale play in central Louisiana and Mississippi. No impairment of proved properties was
recognized during the year ended December 31, 2013.
Unproved properties are reviewed quarterly to determine if there has been an impairment of the carrying value, and any such
impairment is charged to expense in the period. During the year ended December 31, 2015, the Company recognized impairment
expense of approximately $16.3 million related to impairment and partial impairment of certain unproved properties and onshore
prospects due primarily to the sustained low commodity price environment and expiring leases. Approximately $9.3 million of this
amount is related to unproved lease cost amortization of the Elm Hill project in Fayette and Gonzales counties, Texas.
On April 29, 2014, the Company reached total depth on its Ship Shoal 255 well, and no commercial hydrocarbons were
found. As a result, for the year ended December 31, 2014, the Company recognized $31.5 million in exploration expense for the cost
of drilling the well and $15.6 million in impairment expense, including $3.5 million related to leasehold costs and $12.1 million
F-9
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
related to the platform located in Ship Shoal 263 block which was expected to be used by the Ship Shoal 255 well had it been
successful.
During the year ended December 31, 2014, the Company also recognized impairment expense of approximately $20.1
million related to impairment and partial impairment of certain unproved properties due to expiring leases and leases not likely to be
drilled. Of this amount, approximately $9.7 million relates to undrilled offshore leases and approximately $9.7 million relates to
undeveloped TMS acreage.
For the year ended December 31, 2013, the Company recorded an impairment expense on unproved properties of $0.6
million related to leasehold costs on the Ship Shoal 83 prospect which it relinquished in August 2013, and $0.2 million related to
leasehold costs on the Brazos Area 543 prospect.
Asset Retirement Obligations
ASC 410, Asset Retirement and Environmental Obligations (ASC 410) requires that the fair value of an asset retirement cost,
and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense
using a systematic and rational method. The Company records asset retirement obligations to reflect the Company's legal obligations
related to future plugging and abandonment of its oil and natural gas wells, platforms and associated pipelines and equipment. The
Company estimates the expected cash flows associated with the obligation and discounts the amounts using a credit-adjusted, risk-free
interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is
necessary. The Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have
materially changed. Should these indicators suggest the estimated obligation may have materially changed on an interim basis
(quarterly), the Company will accordingly update its assessment. Additional retirement obligations increase the liability associated
with new oil and natural gas wells, platforms, and associated pipelines and equipment as these obligations are incurred. The liability is
accreted to its present value each period and the capitalized cost is depleted over the useful life of the related asset. The accretion
expense is included in depreciation, depletion and amortization expense.
The estimated liability is based on historical experience in plugging and abandoning wells. The estimated remaining lives of
the wells is based on reserve life estimates and federal and state regulatory requirements. The liability is discounted using an assumed
credit-adjusted risk-free rate.
Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, changes in the risk-free
rate or changes in the remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements.
At the time of abandonment, the Company recognizes a gain or loss on abandonment to the extent that actual costs do not equal the
estimated costs. This gain or loss on abandonment is included in impairment and abandonment of oil and gas properties expense. See
Note 12 - "Asset Retirement Obligation" 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, 2015. The amount of unrecognized tax benefits did not materially
change from December 31, 2014. The amount of unrecognized tax benefits may change in the next twelve months; however, the
Company does not expect the change to have a significant impact on its financial position or results of operations. The Company
includes interest and penalties in interest income and general and administrative expenses, respectively, in its statement of operations.
The Company files income tax returns in the United States and various state jurisdictions. The Company’s federal tax returns
for 1998 – 2014, and state tax returns for 2009 – 2014, remain open for examination by the taxing authorities in the respective
jurisdictions where those returns were filed.
F-10
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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 relating 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 the Depreciation, Depletion and Amortization line item in the Company's income
statement for the years ended December 31, 2015, 2014 and 2013.
Stock-Based Compensation
The Company applies the fair value based method to account for stock based compensation. Under this method,
compensation cost is measured at the grant date based on the fair value of the award and is recognized over the requisite service
period, which generally aligns with the award vesting period. The Company classifies the benefits of tax deductions in excess of the
compensation cost recognized for the options (excess tax benefit) as financing cash flows. The fair value of each award is estimated as
of the date of grant using the Black-Scholes option-pricing model.
Inventory
Inventory primarily consists of casing and tubing which will be used for drilling or completion of wells. Inventory is recorded
at the lower of cost or market using specific identification method.
Derivative Instruments and Hedging Activities
The Company accounts for its derivative activities under the provisions of ASC 815, Derivatives and Hedging (ASC 815).
ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or
liability measured at fair value. As of December 31, 2015, the Company had not entered into any derivative contracts to reduce
exposure to interest rate risk. However, from time to time, the Company hedges 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 "Gain (loss) on derivatives, net" on the
consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013. Derivative instruments with settlement
date within one year are included in current assets or liabilities, whereas derivative instruments with settlement dates exceeding one
year are included in non-current assets or liabilities. The Company calculates a net asset or liability for current and non-current
derivative instruments for each counterparty based on the settlement dates within the respective contracts. As of December 31, 2015,
there were no commodity hedges in place. In January 2016, the Company entered into financial derivative contracts with a member of
its bank group resulting in 1,300,000 MMBtus of natural gas per month being hedged from February 2016 through July 2016 and from
November 2016 through December 2016, and 250,000 MMBtus of natural gas per month being hedged from August 2016 through
October 2016 through swaps. See Note 7 - "Derivative Instruments" for additional information.
Reclassifications
Certain reclassifications have been made to the presentation of certain, income statement and cash flow items in the
respective statements for the year ended December 31, 2013 in order to conform to the presentation for the year ended December 31,
2014. These reclassifications were not material.
F-11
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Subsidiary Guarantees
Contango Oil & Gas Company, as the parent company (the “Parent Company”), filed a registration statement on Form S-3
with the SEC to register, among other securities, debt securities that the Parent Company may issue from time to time. Crimson
Exploration Inc., Crimson Exploration Operating, Inc., Contango Energy Company, Contango Operators, Inc., Contango Mining
Company, Conterra Company, Contaro Company, Contango Alta Investments, Inc., Contango Venture Capital Corporation and any
other of the Company’s future subsidiaries specified in the prospectus supplement (each a “Subsidiary Guarantor”) are Co-Registrants
with the Parent Company under the registration statement, and the registration statement also registered guarantees of debt securities
by the Subsidiary Guarantors. The Subsidiary Guarantors are wholly-owned by the Parent Company, either directly or indirectly, and
any guarantee by the Subsidiary Guarantors will be full and unconditional. The Parent Company has no assets or operations
independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to
distribute funds to the Parent Company. The Parent Company has one other wholly-owned subsidiary that is inactive. Finally, the
Parent Company’s wholly-owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal
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 February 2016, the FASB issued Accounting Standards Update No. 2016-02: Leases (Topic 842) (ASU 2016-02). The
main objective of ASU 2016-02 is to increase transparency and comparability among organizations by recognizing lease assets and
lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between
previous GAAP and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating
leases. ASU 2016-02 requires lessees to recognize assets and liabilities arising from leases on the balance sheet. ASU 2016-02 further
defines a lease as a contract that conveys the right to control the use of identified property, plant, or equipment for a period of time in
exchange for consideration. Control over the use of the identified asset means that the customer has both (1) the right to obtain
substantially all of the economic benefit from the use of the asset and (2) the right to direct the use of the asset. ASU 2016-02 requires
disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and
uncertainty of cash flows arising from leases. In transition, lessees and lessors are required to recognize and measure leases at the
beginning of the earliest period presented using a modified retrospective approach. For public entities, ASU 2016-02 is effective for
financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years;
early application is permitted. The Company will continue to assess the impact this may have on its financial position, results of
operations, and cash flows.
In January 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update No. 2016-01:
Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (ASU
2016-01). The main objective of ASU 2016-01 is enhancing the reporting model for financial instruments to provide users of financial
statements with more decision-useful information. The amendments in ASU 2016-01 make targeted improvements to GAAP by: (i)
requiring equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of
the investee) be measured at fair value with changes in fair value recognized in net income; (ii) simplifying the impairment assessment
of equity investments without readily determinable fair values by requiring a qualitative assessment to identify impairment; (iii)
exempting all non-public business entities from disclosing fair value information for financial instruments measured at amortized cost;
(iv) eliminating requirement for public business entities to disclose the methods and significant assumptions used to estimate the fair
value for financial instruments measured at amortized cost on the balance sheet: (v) requiring public business entities to use the exit
price notion when measuring the fair value of financial instruments for disclosure purposes; (vi) requiring separate presentation in
other comprehensive income the portion of the total change in fair value of a liability resulting from a change in the instrument-
specific credit risk when the entity has elected to measure the liability at fair value in accordance with the fair value option for
financial instruments; (vii) requiring separate presentation of financial assets and financial liabilities by measurement category and
form of financial asset; and (viii) clarifying that an entity should evaluate the need for a valuation allowance on a deferred tax asset
related to available-for-sale securities in combination with the entity’s other deferred tax assets. For public entities, ASU 2016-01 is
effective for financial statements issued for fiscal years beginning after December 15, 2017, including interim periods within those
F-12
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
fiscal years; early application is permitted. The provisions of this accounting update are not expected to have a material impact on the
Company’s financial position or results of operations.
In November 2015, the FASB issued Accounting Standards Update No. 2015-17: Income Taxes (Topic 740): Balance Sheet
Classification of Deferred Taxes (ASU 2015-17). ASU 2015-17 is part of an initiative to reduce complexity in accounting standards.
Current GAAP requires an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a
classified statement of financial position. However, this classification does not generally align with the time period in which the
recognized deferred tax amounts are expected to be recovered or settled. To simplify the presentation of the deferred income taxes,
ASU 2015-17 requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position.
The current requirement that deferred tax liabilities and assets of an entity be offset and presented as a single amount is not affected by
the amendments of ASU 2015-17. For public entities, ASU 2015-17 is effective for financial statements issued for fiscal years
beginning after December 15, 2016, and interim periods within those fiscal years; early application is permitted. The Company has
selected early application starting with the financial statements issued for the year ended December 31, 2015. The provisions of this
accounting update do not have a material impact on the Company’s financial position or results of operations. Accordingly, the
deferred tax liability and valuation allowance are classified as non-current.
In September 2015, the FASB issued Accounting Standards Update No. 2015-16: Business Combinations (Topic 805):
Simplifying the Accounting for Measurement-Period Adjustments (ASU 2015-16). ASU 2015-16 is part of an initiative to reduce
complexity in accounting standards, and requires that an acquirer recognize adjustments to provisional amounts that are identified
during the measurement period in the reporting period in which the adjustment amounts are determined. In addition, the amendments
of this update require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in
depreciation, amortization, or other income effects, if any, as a result of the changes to the provisional amounts, calculated as if the
accounting had been completed at the acquisition date. Furthermore, ASU 2015-16 requires an entity to present separately on the face
of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would
have been recorded in previous reporting periods if the adjustments to the provisional amounts had been recognized as of the
acquisition date. For public entities, ASU 2015-16 is effective for fiscal years beginning after December 15, 2015, including interim
periods within those fiscal years. The provisions of this accounting update are not expected to have a material impact on the
Company’s financial position or results of operations.
In August 2014, the FASB issued Accounting Standards Update No. 2014-15: Presentation of Financial Statements – Going
Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (ASU 2014-15).
ASU 2014-15 asserts that management should evaluate whether there are relevant condition or events that are known and reasonably
knowable that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date the
financial statements are issued or are available to be issued when applicable. If conditions or events at the date the financial statements
are issued raise substantial doubt about an entity’s ability to continue as a going concern, disclosures are required which will enable
users of the financial statements to understand the conditions or events as well as management’s evaluation and plan. ASU 2014-15 is
effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter; early application is
permitted. The provisions of this accounting update are not expected to have a material impact on the Company’s financial position or
results of operations.
In May 2014, the FASB and the International Accounting Standards Board (“IASB”) jointly issued new accounting guidance
for recognition of revenue Accounting Standards Update No. 2014-09: Revenue from Contracts with Customers (Topic 606) (ASU
2014-09). This new guidance replaces virtually all existing US GAAP and IFRS guidance on revenue recognition. ASU 2014-09 is
effective for fiscal years beginning after December 15, 2016. This new guidance applies to all periods presented. Therefore, when the
Company issues its financial statements on Forms 10-Q and 10-K for periods included in its year ended December 31, 2017, its
comparative periods that are presented for the years ended December 31, 2015 and 2016, must be retrospectively presented in
compliance with this new guidance. Early adoption is not allowed for US GAAP. The new guidance requires companies to make more
estimates and use more judgment than under current accounting guidance. The Company does not anticipate that this new guidance
will have a material impact on the Company’s consolidated financial position or results of operations for the periods presented.
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 2016 and
F-13
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
beyond. Because these pending standards have not yet been finalized, management is not able to determine the potential future impact
that these standards will have, if any, on the Company's financial position, results of operations, or cash flows.
3. Concentration of Credit Risk
The customer base for the Company is concentrated in the natural gas and oil industry. Major purchasers of the Company’s
natural gas, oil and natural gas liquids for the year ended December 31, 2015 were ConocoPhillips Company (48.3%), Sunoco Inc.
(22.8%), Energy Transfer Company (5.5%) Shell Trading US Company (5.2%) and ExxonMobil Oil Corp. (5.1%). The Company’s
sales to these companies are not secured with letters of credit and in the event of non-payment, the Company could lose up to two
months of revenues. The loss of two months of revenues would have a material adverse effect on the Company’s financial position.
There are numerous other potential purchasers of the Company’s production.
4. Merger with Crimson Exploration Inc.
On October 1, 2013, the Company completed the Merger with Crimson. The Merger was effected pursuant to an Agreement
and Plan of Merger, dated as of April 29, 2013, by and among Contango, Crimson and certain subsidiaries (the “Merger Agreement”).
As a result of the Merger, each share of Crimson common stock was converted into 0.08288 shares of common stock of
Contango, and the Company issued approximately 3.9 million shares of common stock in exchange for all of Crimson's outstanding
capital stock, resulting in Crimson stockholders owning 20.3% of the post-merger Contango.
The Merger qualified as a tax-free reorganization for U.S. federal income tax purposes, so that none of the Company,
Crimson, or any of its stockholders recognized any gain or loss in the Merger, except that Crimson's stockholders may have
recognized gain or loss with respect to cash received in lieu of fractional shares of Company common stock.
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-14
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The following table summarizes the consideration transferred and the fair value of assets acquired, and liabilities assumed as
of the date of the Merger (in thousands, except for number of shares and share price):
Consideration transferred:
Crimson common stock to be acquired by the Company
Exchange ratio of the Company common shares for each Crimson common share
The Company common stock to be issued to Crimson stockholders
Closing price of the Company common stock on October 1, 2013
Fair value of common stock issued
Cash paid for partial shares
Fair value of stock options issued
Total estimated consideration transferred
Fair value of other liabilities assumed:
Current liabilities
Long-term debt
Asset retirement obligations and other non-current liabilities
Amount attributable to liabilities assumed
Total consideration including liabilities assumed
Fair value of assets acquired:
Current assets
Current and non-current deferred tax asset, net
Natural gas and oil properties, net
Other non-current assets
Amount attributable to net assets acquired
Goodwill
46,624,721
0.08288
3,864,101
37.75
145,870
6
698
146,574
60,124
235,373
12,967
308,464
455,038
13,492
24,905
416,433
208
455,038
—
$
$
$
$
$
$
$
$
As of December 31, 2013, estimates of the fair value of assets acquired and liabilities assumed were preliminary and based
on information available at that time. The fair value estimate of certain of Crimson's assets and liabilities, including asset retirement
obligations and current and deferred tax balances, could not be finalized at December 31, 2013 due to information not being available
to the Company. During the quarter ended June 30, 2014, the Company completed an analysis of Crimson’s asset retirement
obligations as of the acquisition date. Based on this analysis, the Company recorded a measurement period adjustment of $2.5 million
to increase the asset retirement obligations liability. As of September 30, 2014, the Company had finalized the purchase price
allocation for the Merger.
Consideration paid by the Company consisted of approximately 3.9 million shares of Contango’s common stock issued in
exchange for 46.6 million of Crimson’s shares outstanding as of September 30, 2013, including restricted stock vesting at the
transaction date and approximately 136,000 of vested Contango stock options issued to Crimson’s employees in exchange for all
Crimson stock options issued and outstanding as of September 30, 2013. The number of options granted and the strike price of the
options was adjusted using the same conversion ratio as for the exchange of common stock. All of Crimson’s restricted shares and
stock options vested immediately prior to the merger.
The purchase price was calculated assuming fair value of the Company’s stock of $37.75 per share based upon the closing
price of the Company’s common stock as of October 1, 2013.
Fair value of the Company’s options issued in exchange for Crimson’s stock options was calculated using the Black-Scholes
Model by applying the following weighted-average assumptions: (a) risk-free interest rate of 0.62% to 1.35%; (b) expected life of 2.70
F-15
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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 0.5% to 2.5% margin dependent upon the
amount outstanding. On October 1, 2013, the $235.4 million of assumed debt, accrued interest, and prepayment premium and $2.2
million of arrangement and upfront fees under the RBC Credit Facility were paid with the Company's existing cash of $127.6 million
and drawings under the Company’s RBC Credit Facility of $110.0 million.
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 was 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. At December 31, 2015, the Company has recorded a valuation allowance due to
losses incurred post-merger. 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.
5. Acquisitions, Dispositions and Gains from Affiliates
Acquisition of Additional Interest in Dutch Wells
In December 2013, the Company exercised a preferential right and purchased an additional 7.84% working interest and
6.53% net revenue interest in the five Contango-operated Dutch wells from an independent oil and gas company for $18.8 million,
subject to a purchase price adjustment, based on production and operating expenses between the effective date of July 1, 2013 and the
closing date of December 12, 2013. During 2014, a purchase price adjustment of approximately $4.1 million reduced the purchase
price to a total of $14.7 million, net to the Company.
Southeast Texas Disposition
On December 31, 2013, the Company sold to an independent oil and gas company approximately 7.1% of its interest in all
developed and undeveloped properties in Madison and Grimes Counties for $20 million, subject to a purchase price adjustment, based
on production and operating expenses between the effective date of July 1, 2013 and the closing date of December 31, 2013. A
preliminary estimated adjustment to the sales price of approximately $0.4 million to increase the purchase price was recorded in 2013,
and an adjustment of approximately $0.1 million to reduce the purchase price was recorded in 2014 resulting in final proceeds of
$20.3 million. A loss of approximately $0.2 million and a gain of approximately $6.6 million related to this sale were recognized in
the years ended December 31, 2014 and 2013, respectively.
F-16
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Proceeds from Alta
In August 2013, Alta sold its interest in the liquids-rich Kaybob Duvernay, which closed in October 2013 for approximately
$30.5 million, net to Contango. Contango has a 2% interest in Alta and a 5% interest in the Kaybob Duvernay project. The total
distribution received from Alta during the year ended December 31, 2013 was approximately $23.1 million. An additional $5.4
million was received during 2014. The Company expects to receive the remaining $2.0 million once approved by Canadian regulatory
officials. The total distributions from Alta are expected to exceed the Company’s original investment by $15.3 million.
6. Fair Value Measurements
Pursuant to ASC 820, Fair Value Measurements and Disclosures (ASC 820), the Company's determination of fair value
incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on
the Company's consolidated balance sheets, but also the impact of the Company's nonperformance risk on its own liabilities. ASC 820
defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between
market participants at the measurement date (exit price). ASC 820 establishes a fair value hierarchy that prioritizes the inputs to
valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active
markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are
inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The
Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions
about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated,
or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.
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.
The Company had outstanding commodity price contracts during the years ended December 31, 2015 and 2014, which were
settled prior to each year end. Thus, the Company did not have any outstanding commodity price contracts as of December 31, 2015
and 2014. In January 2016, the Company entered into financial derivative contracts with a member of its bank group resulting in
1,300,000 MMBtus of natural gas per month being hedged from February 2016 through July 2016 and from November 2016 through
December 2016, and 250,000 MMBtus of natural gas per month being hedged from August 2016 through October 2016 through
swaps.
Derivatives above are swaps that are carried at fair value for the appropriate period. The Company records the net change in
the fair value of these positions in "Gain (loss) on derivatives, net" in the Company's consolidated statements of operations. The
Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the
Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted
markets prices and implied volatility factors related to changes in the forward curves. See Note 7 - "Derivative Instruments" for
additional discussion of derivatives.
During the year ended December 31, 2015, the Company's derivative contracts were with major financial institutions with
investment grade credit ratings which were believed to have a minimal credit risk. As such, the Company was exposed to credit risk to
the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company did not
anticipate any nonperformance. The counterparties to the Company's current and previous derivative contracts are lenders in the
Company's RBC Credit Facility. The Company did not post collateral under any of these contracts as they were 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
F-17
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Credit Facility approximates carrying value because the interest rate approximates current market rates and are re-set at least every
three months. See Note 13 - "Long-Term Debt" for further information.
Fair value estimates used for non-financial assets are evaluated at fair value on a non-recurring basis include oil and gas
properties evaluated for impairment when facts and circumstances indicate that there may be an impairment. If the unamortized cost of
properties exceeds the undiscounted cash flows related to the properties, the value of the properties is compared to the fair value
estimated as discounted cash flows related to the risk-adjusted proved, probable and possible reserves related to the properties. Fair
value measurements based on these inputs are classified as Level 3.
Impairments
Contango tests proved oil and gas properties for impairment when events and circumstances indicate a decline in the
recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity
prices. The Company estimates the undiscounted future cash flows expected in connection with the oil and gas properties on a field by
field basis and compares such future cash flows to the unamortized capitalized costs of the properties. If the estimated future
undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to its fair value. The factors
used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the
timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining
for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. Because
these significant fair value inputs are typically not observable, impairments of long-lived assets are classified as a Level 3 fair value
measure.
Asset Retirement Obligations
The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and based on internal
estimates of future retirement costs associated with oil and gas properties. The factors used to determine fair value include, but are not
limited to, estimated future plugging and abandonment costs and expected lives of the related reserves.
7. Derivative Instruments
The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative
contracts are utilized to hedge the Company's exposure to price fluctuations and reduce the variability in the Company's cash flows
associated with anticipated sales of future oil and natural gas production. The Company believes that derivative arrangements,
although not free of risk, allowed us to achieve a more predictable cash flow and to reduce exposure to commodity price
fluctuations. However, derivative arrangements limit the benefit of increases in the prices of crude oil, natural gas and natural gas
liquids sales. Moreover, the Company’s derivative arrangements applied only to a portion of its production and provided only partial
protection against declines in commodity prices. Such arrangements may expose us to risk of
loss in certain
circumstances. The Company continuously reevaluates its hedging programs in light of changes in production, market conditions, and
commodity price forecasts.
financial
The Company had outstanding commodity price contracts during the year ended December 31, 2015, which were settled
prior to year end. Thus, the Company did not have any outstanding derivative positions as of December 31, 2015. In January 2016, the
Company entered into financial derivative contracts with a member of its bank group resulting in 1,300,000 MMBtus of natural gas
per month being hedged from February 2016 through July 2016 and from November 2016 through December 2016, and 250,000
MMBtus of natural gas per month being hedged from August 2016 through October 2016 through swaps. Swaps are designed so that
the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. A
costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract and
a purchased put that establishes a minimum price. A sold put option limits the exposure of the counterparty's risk should the price fall
below the strike price. Sold put options limit the effectiveness of purchased put options at the low end of the put/call collars to market
prices in excess of the strike price of the put option sold.
F-18
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
It is the Company's practice to enter into derivative contracts only with counterparties that are creditworthy institutions
deemed by management as competent and competitive market makers. The counterparties to the Company's current and previous
derivative contracts are lenders or affiliates of lenders in the RBC Credit Facility. The Company does not post collateral under any of
these contracts as they are secured under the RBC Credit Facility.
The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, derivatives are
carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the
consolidated statements of operations for the period in which the change occurs. The Company records the net change in the mark-to-
market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in "Gain (loss) on
derivatives, net" on the consolidated statements of operations. See Note 6 – “Fair Value Measurements” for additional information.
There were no derivative contracts in place as of December 31, 2015 and 2014.
The following table summarizes the effect of derivative contracts on the Consolidated Statements of Operations for the years
ended December 31, 2015, 2014 and 2013 (in thousands):
Contract Type
2015
2014
2013
Year ended December 31,
Crude oil contracts
Natural gas contracts
Realized gain (loss)
Crude oil contracts
Natural gas contracts
Unrealized gain (loss)
Gain (loss) on derivatives, net
$
$
$
$
$
2,348
—
2,348
$
$
— $
—
— $
2,348
$
276
(1,560)
(1,284)
1,183
(52)
1,131
(153)
$
$
$
$
$
180
98
278
(1,179)
(231)
(1,410)
(1,132)
In January 2016, the Company entered into the following financial derivative contracts with a member of its bank group:
Commodity
Natural Gas
Natural Gas
Natural Gas
Period
Derivative
Volume/Month
Feb 2016 - July 2016
Aug 2016 - Oct 2016
Nov 2016 - Dec 2016
Swap
Swap
Swap
1,300,000 MMBtu
250,000 MMBtu
1,300,000 MMBtu
Price/Unit (1)
$2.53
$2.53
$2.53
(1)
Commodity price derivatives based on Henry Hub NYMEX natural gas prices.
8. Stock Based Compensation
As of December 31, 2015, 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. This program includes (i) the
Company's Amended and Restated 2009 Incentive Compensation Plan (the “2009 Plan”); and (ii) the Crimson 2005 Stock Incentive
Plan (the “2005 Plan” or "Crimson Plan") adopted in conjunction with the Merger.
Amended and Restated 2009 Incentive Compensation Plan
On September 15, 2009, the Company’s board of directors (the “Board”) adopted the Contango Oil & Gas Company Equity
Compensation Plan (the “Original 2009 Plan”). On April 10, 2014, the Board amended and restated the Original 2009 Plan through
the adoption of the Contango Oil & Gas Company Amended and Restated 2009 Incentive Compensation Plan. The 2009 Plan provides
for both cash awards and equity awards (such as restricted stock and options) to officers, directors, employees or consultants of the
Company. Awards made under the 2009 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as
may be determined by the Board.
F-19
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Under the terms of the 2009 Plan, up to 1,500,000 shares of the Company’s common stock may be issued for plan awards.
Stock options under the 2009 Plan must have an exercise price of each option equal to or greater than the market price of the
Company’s common stock on the date of grant. The Company may grant officers and employees both incentive stock options intended
to qualify under Section 422 of the Internal Revenue Code of 1986, as amended, and stock options that are not qualified as incentive
stock options. Stock option grants to non-employees, such as directors and consultants, can only be stock options that are not qualified
as incentive stock options. Options granted generally expire after five or ten years. The vesting schedule for all equity awards varies
from immediately to over a four-year period.
As of December 31, 2015, the Company had approximately 0.9 million shares of common stock and stock options available
for future grant under the 2009 Plan. In January 2016, the Company granted 38,943 stock awards to employees and 1,745 stock
awards to its board of directors under the 2009 Plan as a result of the Salary Replacement Program. See Note 14 - “Commitments and
Contingencies” for a description of the Salary Replacement Program.
Effective January 1, 2014, the Company implemented performance-based long-term bonus plans under the 2009 Plan for the
benefit of all employees through a Cash Incentive Bonus Plan (“CIBP”) and a Long-Term Incentive Plan (“LTIP”). The specific
targeted performance measures under these sub-plans are approved by the Compensation Committee and/or the Board. Upon
achieving the performance levels established each year, bonus awards under the CIBP and LTIP will be calculated as a percentage of
base salary of each employee for the plan year. The CIBP and LTIP plan awards for each year are expected to be disbursed in the first
quarter of the following year. Employees must be employed by the Company at the time that awards are disbursed to be eligible.
The CIBP awards will be paid in cash while LTIP awards will consist of restricted common stock and/or stock options. The
number of shares of restricted common stock and the number of shares underlying the stock options granted will be determined based
upon the fair market value of the common stock on the date of the grant.
2005 Stock Incentive Plan
The 2005 Plan was adopted by the Company's Board in conjunction with the Merger with Crimson. Under the 2005 Plan, the
Board may grant incentive stock options, nonstatutory stock options, restricted awards, unrestricted awards, performance awards,
stock appreciation rights and dividend equivalent rights to eligible officers, directors, employees or consultants of the Company and its
affiliates. Awards made under the 2005 Plan are subject to such terms and conditions, without limitation, as may be determined by the
Board. Options granted generally expire after ten years. The vesting schedule for all equity awards varies from immediately to over a
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.
On February 24, 2015, the Company granted 7,030 restricted stock awards under the 2005 Plan to a new employee pursuant
to the LTIP. This plan expired on February 25, 2015 and therefore no additional shares are available for grant.
Stock Options
During the years ended December 31, 2015 and 2014, the Company did not issue any stock options. However, 13,473 stock
options that were previously issued were forfeited, leaving 116,461 stock options vested and exercisable at December 31, 2015, with
exercise prices ranging from $28.96 to $60.33 per share, with an average remaining contractual life of five years.
During the year ended December 31, 2014, employees exercised 4,165 stock options to purchase shares of the Company’s
common stock that were sold in the open market.
During the year ended December 31, 2013, employees exercised 791 stock options to purchase shares of the Company’s
common stock that were sold in the open market.
F-20
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
A summary of the stock options granted under the 2009 Plan and 2005 Plan as of and for the years ended December 31,
2015, 2014, and 2013 is presented in the table below (dollars in thousands, except per share data):
Year Ended December 31,
2015
2014
2013
Shares
Under
Weighted
Average
Exercise
Options
Price
Shares
Under
Options
Weighted
Average
Exercise
Price
Shares
Under
Options
Outstanding, beginning of the period
129,934 $
53.85
135,107 $
53.00
— $
Options assumed due to Merger
Exercised
Canceled / Forfeited
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
— $
— $
(13,473) $
116,461 $
—
—
—
43.65
55.03
116,461 $
55.03
—
885,449
—
$
$
$
$
$
$
— $
—
135,898 $
(4,165) $
(1,008) $
129,934 $
4
28.93
42.39
53.85
129,934 $
53.85
4
1,143,006
—
(791) $
— $
135,107 $
53.00
459
135,107 $
53.00
459
1,162,173
—
$
$
$
Weighted
Average
Exercise
Price
—
52.90
36.16
—
Under the fair value method of accounting for stock options, cash flows from the exercise of stock options resulting from tax
benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing cash flows. For the year
ended December 31, 2015, there was no excess tax benefit recognized. For the year ended December 31, 2014, there was an
insignificant excess tax benefit recognized. For the year ended December 31, 2013, there was no excess tax benefit recognized. See
Note 2 – "Summary of Significant Accounting Policies".
Compensation expense related to employee stock option grants are recognized over the stock option’s vesting period based
on the fair value at the date the options are granted. The fair value of each option is estimated as of the date of grant using the Black-
Scholes options-pricing model.
During the years ended December 31, 2015, 2014 and 2013, the Company did not recognize any stock option expense. The
aggregate intrinsic value of stock options exercised/forfeited during the years ended December 31, 2015, 2014 and 2013 was
approximately zero, $59,009 and $7,721, respectively.
Restricted Stock
During the year ended December 31, 2015, the Company issued 249,917 restricted stock awards to new and existing
employees, which vest over four years, plus an additional 27,204 restricted stock awards to the members of the board of directors
which vest on the one-year anniversary of the date of grant. The weighted average fair value of the restricted shares granted during
the year was $22.02, with a total grant date fair value of approximately $6.1 million after adjustment for estimated weighted average
forfeiture rate of 4.9%.
During the year ended December 31, 2014, the Company issued 10,714 restricted stock awards to new and existing
employees pursuant to the LTIP, which vest over four years, plus an additional 15,672 restricted stock awards to the board of directors
which vest on the one-year anniversary of the date of grant. The weighted average fair value of the restricted shares granted during the
year was $40.83, with a total grant date fair value of approximately $1.1 million after adjustment for estimated weighted average
forfeiture rate of 2.2%.
F-21
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
In November 2013, the Company issued 254,677 shares of restricted common stock to senior officers and certain other vice
presidents pursuant to the LTIP, 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 pursuant to the
LTIP, which vest over a four-year period. In December 2013, the Company also issued 88,466 shares of restricted common stock to
Company employees pursuant to the LTIP, 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 the Company’s new director compensation plan which vest on the one-year
anniversary of the date of grant. The weighted average fair value of the restricted shares granted during the fourth quarter of 2013 was
$44.10, with a total grant date 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, 2015, 2014 and 2013 and for the years then ended is presented in the table below
(dollars in thousands, except per share data):
2015
2014
2013
Restricted Average
Shares
Weighted Aggregate
Intrinsic
Value
Fair
Value
Weighted Aggregate
Restricted Average Intrinsic
Value
Fair
Value
Shares
Weighted Aggregate
Restricted Average Intrinsic
Value
Fair
Value
Shares
Outstanding, beginning of the period
209,962 $
43.86 $
Granted
Vested
Canceled / Forfeited
Not vested, end of the period
Vested, end of the period
Expected to vest, end of the period
277,121
(137,195)
(12,723)
337,165
21.83
39.35
32.97
28.16
6,139
6,049
1,169
154
2,161
292,632 $
44.38 $
13,830
—$
— $
—
26,386
(94,807)
(14,249)
209,962
40.83
44.11
47.30
43.86
1,073
3,454
579
6,139
356,299
(63,667)
44.10
42.80
15,723
2,725
—
—
—
292,632
44.38
13,830
—
—
—
—
—
—
—
—
—
312,986
28.17
2,006
192,570
43.84
5,631
260,359
44.36
12,305
The Company recognized approximately $6.5 million, $4.5 million and $3.2 million in stock compensation expense during
the years ended December 31, 2015, 2014 and 2013, respectively, for restricted shares granted to its officers, employees and directors.
An additional $7.2 million of compensation expense will be recognized over the remaining vesting period.
9. Share Repurchase Program
In September 2011, the Company’s board of directors approved a $50 million share repurchase program. All shares are to be
purchased in the open market or through privately negotiated transactions. Purchases are made subject to market conditions and
certain volume, pricing and timing restrictions to minimize the impact of the purchases upon the market, and when the Company
believes its stock price to be undervalued. Repurchased shares of common stock became authorized but unissued shares, and may be
issued in the future for general corporate and other purposes. During the year ended December 31, 2014, the Company purchased
205,457 shares at an average price of $35.89 per share, for a total of approximately $7.4 million. No shares were purchased during the
years ended December 31, 2015 and 2013. As of December 31, 2015, the Company had $31.8 million available under the share
repurchase program for future purchases.
In October 2014, the Company amended its revolving credit facility with Royal Bank of Canada to, among other things,
allow for share repurchases subject to certain conditions. The Company is currently in compliance with these conditions.
F-22
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
10. Other Financial Information
The following table provides additional detail for accounts receivable, prepaids, and accounts payable and accrued liabilities
which are presented on the consolidated balance sheets (in thousands):
December 31,
2015
December 31,
2014
Accounts receivable:
Trade receivables
Receivable for Alta Resources distribution
Joint interest billings
Income taxes receivable
Other receivables
Allowance for doubtful accounts
Total accounts receivable
Prepaid expenses and other:
Prepaid insurance
Other
Total prepaid expenses and other
Accounts payable and accrued liabilities:
Royalties and revenue payable
Accrued exploration and development
Trade payables
Advances from partners
Accrued general and administrative expenses
Other accounts payable and accrued liabilities
Total accounts payable and accrued liabilities
$
$
$
$
$
$
7,530
1,993
7,366
2,868
1,448
(701)
20,504
900
328
1,228
17,906
3,659
8,053
950
2,596
3,194
36,358
$
$
$
$
$
$
13,926
1,993
4,096
3,274
2,610
(590)
25,309
1,242
699
1,941
31,653
26,538
17,282
8,334
6,258
2,827
92,892
Included in the table below is supplemental information about non-cash transactions during the years ended December 31,
2015, 2014 and 2013, in thousands:
Year Ended December 31,
2014
2013
2015
Cash payments:
Interest payments
Income tax payments (refunds), net of cash refunds
Non-cash items excluded from investing activities in the consolidated statements of cash flows:
Increase (decrease) in accrued capital expenditures
Assets acquired & liabilities assumed in the Merger:
Accounts receivable
Prepaids
Proved natural gas and oil properties
Deferred tax asset and other
Accounts payable and accrued liabilities
Other non-current liabilities
Long-term debt
Asset retirement obligations
Non-cash items excluded from financing activities in the consolidated statements of cash flows:
Issuance of common stock in connection with the merger
F-23
$
3,147 $
(180)
2,786 $
241
1,056
341
(22,879)
8,735
7,004
—
—
—
—
—
—
—
—
—
—
—
2,517
—
12,955
639
413,916
24,940
—
(60,110)
(256)
—
— (235,373)
(2,517)
(11,183)
— 145,870
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
11. Investment in Exaro Energy III LLC
In April 2012, the Company entered into a Limited Liability Company Agreement (the “LLC Agreement”) in connection
with the formation of Exaro. Pursuant to the LLC Agreement, as amended, the Company has committed to invest up to $67.5 million
in Exaro for an ownership interest of approximately 37%. The aggregate commitment of all the Exaro investors was approximately
$183 million. The Company did not make any contributions during the year ended December 31, 2015. As of December 31, 2015, the
Company had invested approximately $46.9 million.
The following table presents condensed balance sheet data for Exaro as of December 31, 2015 and December 31, 2014. The
balance sheet data was derived from the Exaro balance sheet as of December 31, 2015 and December 31, 2014 and was not adjusted to
represent Contango’s percentage of ownership interest in Exaro. Contango’s share in the equity of Exaro at December 31, 2015 was
approximately $14.1 million.
December 31,
2015
December 31,
2014
Current assets (1)
Non-current assets:
Net property and equipment
Restricted cash escrow account
Other non-current assets
Total non-current assets
Total assets
Current liabilities
Non-current liabilities:
Long-term debt
Other non-current liabilities
Total non-current liabilities
Members' equity
Total liabilities & members' equity
$
$
$
$
(in thousands)
23,664
$
101,459
—
486
101,945
125,609
5,272
78,500
2,891
81,391
38,946
125,609
$
$
$
35,013
233,997
577
1,779
236,353
271,366
9,405
94,500
1,084
95,584
166,377
271,366
(1) Approximately $14.4 million of current assets as of December 31, 2015, is cash.
F-24
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The following table presents the condensed results of operations for Exaro for the years ended December 31, 2015, 2014 and
2013. The results of operations for the years ended December 31, 2015, 2014 and 2013 were derived from Exaro's financial statements
for the respective periods. The income statement data below was not adjusted to represent Contango’s ownership interest but rather
reflects the results of Exaro as a Company. The Company's share in Exaro's results of operations recognized for the years ended
December 31, 2015, 2014 and 2013 was a loss of $30.6 million, net of tax benefit of $16.5 million; a gain of $6.9 million, net of tax
expense of $3.8 million; and a gain of $2.3 million, net of tax expense of $1.2 million, respectively.
Production:
Oil (MBbls)
Gas (MMcf)
Total (Mmcfe)
Oil and natural gas sales
Other gain (loss)
Less:
Lease operating expenses
Depreciation, depletion, amortization & accretion
Impairment expense
General & administrative expense
Income (loss) from continuing operations
Net interest expense
Net income (loss)
2015
Year Ended December 31,
2014
2013
($ in thousands)
166
13,059
14,055
170
13,355
14,375
40,474
6,358
$
79,536
5,069
$
20,922
29,417
118,000
3,255
(124,762)
(2,910)
(127,672)
$
22,452
26,036
—
3,484
32,633
(3,861)
28,772
$
$
$
129
9,731
10,506
52,698
(544)
16,136
16,058
—
3,294
16,666
(3,536)
13,130
Included in Other gain (loss) 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, 2015 and 2014 were as follows (in thousands):
Balance as of the beginning of the period
Liabilities incurred during period
Liabilities settled during period
Accretion
Sales
Change in estimate
Other adjustments
Balance as of the end of the period
Year ended December 31,
2015
2014
25,746
$
349
(254)
1,219
—
167
(118)
27,109
$
23,334
3,123
(1,963)
1,303
(69)
18
—
25,746
$
$
F-25
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
All of the total liabilities incurred during the year ended December 31, 2015 were related to new wells drilled during the
period. All of the total liabilities settled during the year ended December 31, 2015, related to wells plugged and abandoned during the
period.
Of the total liabilities incurred during the year ended December 31, 2014, $2.5 million was due to a purchase price
adjustment for the merger with Crimson and $0.6 million related to new wells drilled during the period. All of the total liabilities
settled during the year ended December 31, 2014 related to wells plugged and abandoned during the period.
13. Long-Term Debt
RBC Credit Facility
In connection with the Merger during 2013, the Company assumed and immediately repaid $235.4 million of Crimson debt,
including Crimson’s $175.0 million second lien term loan with Barclays and other lenders, Crimson’s $58.6 million balance under its
senior secured revolving credit facility with Wells Fargo Bank and other lenders, and a $1.8 million prepayment premium for the
second lien term loan and accrued interest. Of the amount repaid, $127.6 million was made from existing cash with the remainder
financed through new borrowing arrangements.
In order to finance the retirement of the assumed debt, the Company entered into a $500 million four-year secured revolving
credit facility with Royal Bank of Canada and other lenders on October 1, 2013, with an initial hydrocarbon-supported borrowing base
of $275 million. As part of the regular redetermination schedule, the Company’s bank group redetermined the Company’s borrowing
base at $225 million effective May 8, 2015, and $190 million effective November 13, 2015, primarily to reflect lower commodity
prices and the impact of the significant reduction in the Company’s drilling program in 2015 because of the low price environment.
The borrowing base under the facility is redetermined each November 1 and May 1. Since the last regularly scheduled redetermination
of our borrowing base, effective through May 1, 2016, commodity prices have continued to decline. The decline in prices will likely
negatively impact the price decks utilized by banks in their calculation of the Company’s borrowing base at May 1, 2016. If our next
borrowing base redetermination results in a lower borrowing base, we may be unable to obtain financing otherwise currently available
under the RBC Credit Facility. The Company incurred $2.2 million of arrangement and upfront fees in connection with the facility
which will be amortized over the original four-year term of the 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 facility and the Merger.
As of December 31, 2015, the Company had $115.4 million outstanding under the RBC Credit Facility, which matures on
October 1, 2017, and $1.9 million in outstanding letters of credit. As of December 31, 2014, the Company had $63.4 million
outstanding under the RBC Credit Facility and $1.9 million in outstanding letters of credit. As of December 31, 2015, borrowing
availability under the RBC Credit Facility was $72.7 million.
The RBC Credit Facility is collateralized by a lien on substantially all the producing assets of the Company and its
subsidiaries, including a security interest in the stock of Contango’s subsidiaries and a lien on the Company’s oil and gas properties.
Borrowings under the RBC Credit Facility bear interest at LIBOR, the U.S. prime rate, or the federal funds rate, plus a 0.5%
to 2.5% margin, dependent upon the amount outstanding. Additionally, the Company must pay a commitment fee on the amount of the
facility that remains unused, which varies from .375% to .5%, depending on the amount of the credit facility that is unused. Total
interest expense under the RBC Credit Facility, including commitment fees, for the years ended December 31, 2015, 2014 and 2013
was approximately $3.2 million, $2.7 million and $1.2 million, respectively.
The RBC Credit Facility contains restrictive covenants which, among other things, restrict the declaration or payment of
dividends by Contango and require a Current Ratio of greater than or equal to 1.0 and a Leverage Ratio of less than or equal to 3.50,
both as defined in the RBC Credit Facility Agreement. As of December 31, 2015, the Company was in compliance with all covenants
under the RBC Credit Facility, and at current commodity prices, we do not expect any covenant compliance issues over the next
twelve months. The RBC Credit Facility also contains events of default that may accelerate repayment of any borrowings and/or
F-26
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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”).
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 year ended December 31, 2013 was approximately $37,000.
14. Commitments and Contingencies
Contango pays delay rentals on its offshore leases and leases its office space and certain other equipment. Effective October
1, 2013, the Company moved its corporate offices to 717 Texas Avenue in downtown Houston, Texas, under a lease that expires
March 31, 2019. The Company remains responsible for the rent at its previous corporate office at 3700 Buffalo Speedway in Houston,
Texas, through February 29, 2016; however, effective January 1, 2014, it subleased the previous corporate offices through February
29, 2016 and expects to recover the substantial majority of the rent it pays at that location.
As of December 31, 2015, minimum future lease payments for delay rentals and operating leases for Contango’s fiscal years
are as follows (in thousands):
Fiscal years ending December 31,
2016
2017
2018
2019
2020
2021 and thereafter
Total
$
$
3,641
2,154
1,828
519
103
209
8,454
The amounts incurred under operating leases and delay rentals during the years ended December 31, 2015, 2014, and 2013
were approximately $6.3 million, $6.0 million and $1.0 million, respectively. As of December 31, 2015, the Company’s commitment
for potential future equity contributions with Exaro Energy III, LLC to develop onshore natural gas assets, was $20.6 million.
Legal Proceedings
From time to time, the Company is involved in legal proceedings relating to claims associated with its properties, operations
or business or arising from disputes with vendors in the normal course of business, including the material matters discussed below.
In July 2010, several parties associated with a limited partnership formed to invest in oil and gas properties that was
dissolved in 1995 filed suit against a subsidiary of the Company and several co-defendants in district court for Madison County in
Texas. The plaintiffs claim to own or have rights in certain oil and gas properties situated in Madison County, Texas by virtue of the
partnership having interests in addition to those it held of record at the time of its dissolution, which were distributed to the partners in
connection with such dissolution. A predecessor of the subsidiary of the Company involved in this case acquired a portion of the
interests now claimed by the plaintiffs from a successor to the general partner of the aforementioned partnership in 2000. The
plaintiffs’ expert has recently provided a range of estimated monetary damages of up to approximately $9.4 million as to our
Subsidiary. The Company is vigorously defending this lawsuit and believes that it has meritorious defenses.
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
F-27
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
that has not been recognized by us or by predecessor operators to which the Company had granted indemnification rights. In dispute is
whether ownership rights were transferred through a number of decade-old poorly documented transactions. Based on summary
judgment, in late 2014 the trial court entered a final judgment in the case in favor of the plaintiffs for approximately $5.3 million, plus
post-judgment interest. The Company is vigorously defending this lawsuit, believes that it has meritorious defenses and is appealing
the trial court’s decision to the applicable state Court of Appeals.
In September 2012, a subsidiary of the Company was named as defendant in a lawsuit filed in district court for Harris County
in Texas involving a title dispute over a 1/16th mineral interest in the producing intervals of certain wells operated by us in the
Catherine Henderson “A” Unit in Liberty County in Texas. This case was subsequently transferred to the district court for Liberty
County, Texas and combined with a suit filed by other parties against the plaintiff claiming ownership of the disputed interest. The
plaintiff has alleged that, based on its interpretation of a series of 1972 deeds, it owns an additional 1/16th unleased mineral interest in
the producing intervals of these wells on which it has not been paid (this claimed interest is in addition to a 1/16th unleased mineral
interest on which it has been paid). The Company has made royalty payments with respect to the disputed interest in reliance, in part,
upon leases obtained from successors to the grantors under the aforementioned deeds, who claim to have retained the disputed mineral
interests thereunder. The plaintiff previously alleged damages of approximately $10.7 million although the plaintiff’s claim increases
as additional hydrocarbons are produced from the subject wells. The trial court entered judgment in favor of the Company’s subsidiary
and the successors to the grantors under the aforementioned deeds and the plaintiff has appealed the trial court’s decision to the
applicable state Court of Appeals. The Company is vigorously defending this lawsuit and believes that it has meritorious defenses.
The Company believes if this matter were to be determined adversely, amounts owed to the plaintiff could be partially offset by
recoupment rights the Company may have against other working interest and/or royalty interest owners in the unit.
Mineral interest owners in South Louisiana filed suit against a subsidiary of the Company and several co-defendants in April
2013 in the 31st Judicial District Court situated in Jefferson Davis Parish, Louisiana alleging failure to act as a reasonably prudent
operator, failure to explore, waste, breach of contract, etc. in connection with two wells located in Jefferson Davis Parish. Many of the
alleged improprieties occurred prior to the Company’s ownership of an interest in the wells at issue, although the Company may have
assumed liability otherwise attributable to its predecessors-in-interest through the acquisition documents relating to the acquisition of
the Company’s interest in these wells. This case is based on the same actions and allegations as a prior case in which the Company
and its co-defendants prevailed. The plaintiffs claim damages of approximately $2.5 million against a subsidiary of the Company and
its co-defendants. The Company and its co-defendants are vigorously defending this lawsuit and believe that they have a meritorious
position.
While many of these matters involve inherent uncertainty and the Company is unable at the date of this filing to estimate an
amount of possible loss with respect to certain of these matters, the Company believes that the amount of the liability, if any,
ultimately incurred with respect to these proceedings or claims will not have a material adverse effect on its consolidated financial
position as a whole or on its liquidity, capital resources or future annual results of operations. The Company maintains various
insurance policies that may provide coverage when certain types of legal proceedings are determined adversely.
Employment Agreements
As a result of successfully completing the Merger, Mr. Joseph J. Romano, the Company's Chairman and former Chief
Executive Officer received a $4.0 million bonus payment in July 2014.
Also 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, all of which became effective on October 1, 2013. The employment
agreements provide for an initial 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.
Under the 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. The aforementioned executives entered into a Limited Waiver on or about September 1, 2015 to
participate in a salary replacement program (the “Salary Replacement Program”) effective September 1, 2015 and expected to
F-28
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
continue through December 31, 2016. The Salary Replacement Program reduces all office employees’ base salary by 10% and all
board of director retainer and committee chairman fees by 10% and replaces annually the portion of the salary/fees being reduced with
common stock in a number of shares commensurate with the salary/fees reduction amount. While the executives are participating in
the Salary Replacement Program, Mr. Keel is entitled to a cash base salary of $540,000, Mr. Grady is entitled to a cash base salary of
$360,000, Mr. Isaac is entitled to a cash base salary of $288,000, Mr. Mengle is entitled to a cash base salary of $270,000 and Mr.
Atkins is entitled to a cash base salary of $279,000.
Per the employee agreements, each executive shall participate in the CIBP and the LTIP. With respect to the CIBP, these
employee agreements provide that the executives are eligible to receive a cash bonus based upon minimum, target and maximum
award levels of 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 effective prior to the executive’s participation in the Salary
Replacement Program. With respect to the LTIP, these employee agreements provide that the executives are eligible to receive stock
option awards, restricted stock awards or a combination of both based upon minimum, target and maximum award levels of 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 effective prior to the executive’s participation in the Salary Replacement Program. Actual
awards for executives under the CIBP and the LTIP are subject to attainment of pre-determined corporate and personal goals for
minimum, target or maximum levels of performance as determined by the board of directors for the performance period. Performance
levels below the minimum threshold in any performance metric result in forfeiture of that portion of the CIBP and/or LTIP award,
unless otherwise determined by the board of directors.
F-29
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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,
2015, 2014 and 2013 is presented below (in thousands):
Basic Earnings per Share:
Net loss attributable to common stock
Diluted Earnings per Share:
Effect of potential dilutive securities:
Year Ended December 31, 2015
Net Loss
Shares
Per Share
$
(335,048)
18,965 $
(17.67)
Stock options, weighted average of incremental shares
Net loss attributable to common stock
—
—
—
$
(335,048)
18,965 $
(17.67)
Basic Earnings per Share:
Net loss attributable to common stock
Diluted Earnings per Share:
Effect of potential dilutive securities:
Year Ended December 31, 2014
Net Loss
Shares
Per Share
$
(21,874)
19,059 $
(1.15)
Stock options, weighted average of incremental shares
Net loss attributable to common stock
—
—
$
(21,874)
19,059 $
—
(1.15)
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
Year Ended December 31, 2013
Net Income
Shares
Per Share
41,362
16,156 $
2.56
—
41,362
2
16,158 $
—
2.56
$
$
The numerator for basic earnings per share is net income (loss) attributable to common stockholders. The numerator for
diluted earnings per share is net income unless there is a loss and then is (loss) available to common stockholders, due to antidilution.
Potential dilutive securities (stock options, stock warrants and convertible preferred stock) have not been considered when
their effect would be antidilutive. The potentially dilutive shares, including both stock options and restricted shares, would have been
453,626 shares for the year ended December 31, 2015. The potentially dilutive shares, including both stock options and restricted
shares, would have been 339,896 shares for the year ended December 31, 2014. The potentially dilutive shares, including both stock
options and restricted stock, would have been 187,302 shares for the year ended December 31, 2013.
F-30
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
16. Income Taxes
Actual income tax expense differs from income tax expense 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,
2015
2014
2013
Provision/(benefit) at statutory tax rate
$
(148,925)
35.00 % $
(11,920)
35.00 % $
23,011
State income tax provision, net of federal benefit
Permanent differences
State depletion deductions
Valuation allowance
Other
(116)
30
—
55,310
2,008
0.03 %
(0.01)%
—%
(13.00)%
(0.47)%
1,028
202
(1,723)
—
230
(3.00)%
(0.60)%
5.10 %
—%
(0.70)%
2,928
(1,559)
—
—
4
Income tax provision /(benefit)
$
(91,693)
21.55 % $
(12,183)
35.80 % $
24,384
35.00 %
4.45 %
(2.37)%
—%
—%
0.01 %
37.09 %
The effective tax rate for December 31, 2015 varies from the statutory rate primarily as a result of recording a valuation
allowance. The effective tax rate for December 31, 2014 varies from the statutory rate primarily due to the effect of state income tax
expenses.
The provision (benefit) for income taxes for the periods indicated are comprised of the following (in thousands):
Current tax provision (benefit):
Federal
State
Total
Deferred tax provision (benefit):
Federal
State
Total
Total tax provision (benefit):
Federal
State
Total
Included in gain (loss) from investment in affiliates
Total income tax provision (benefit)
Year Ended December 31,
2015
2014
2013
— $
636
636
(92,329)
—
(92,329)
(92,329)
636
(91,693)
(16,467)
(75,226)
$
$
$
$
$
$
$
(392)
478
86
(11,518)
(751)
(12,269)
(11,910)
(273)
(12,183)
3,727
(15,910)
$
$
$
$
$
$
$
$
8,739
3,857
12,596
11,361
427
11,788
20,100
4,284
24,384
1,245
23,139
$
$
$
$
$
$
$
$
F-31
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The net deferred tax liability is comprised of the following (in thousands):
Deferred tax assets:
Net operating loss carryforward
Income tax credits
Derivative instruments
Deferred compensation
Oil and gas properties
Other
Total deferred tax assets before valuation allowance
Valuation allowance
Net deferred tax assets
Deferred tax liability:
Oil and gas properties
Investment in affiliates
Other
Deferred tax liability
Total net deferred tax liability
December 31,
2015
2014
49,249
1,010
—
498
12,941
1,007
64,705
(57,471)
7,234
$
$
$
— $
(7,234)
—
(7,234)
$
— $
39,085
661
165
465
—
1,953
42,329
(2,161)
40,168
(104,209)
(28,287)
—
(132,496)
(92,328)
$
$
$
$
$
$
In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some
portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the
generation of future taxable income during the periods in which those temporary differences become deductible. The Company
considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this
assessment. Based upon the amount of deferred tax liabilities, level of historical taxable income and projections for future taxable
income over the periods in which the deferred tax assets are deductible, the Company believes it is less-than-more-likely-than-not that
it will realize the benefits of these deductible differences and has recorded a valuation allowance of $57.5 million.
As of December 31, 2015, the Company had federal net operating loss (“NOL”) carryforwards of approximately $140.4
million and state NOLs of $12.0 million. The federal NOL carryforwards reported as of December 31, 2014 were acquired in the 2013
merger with Crimson. A valuation allowance was recorded at the time of the Merger to reflect the impact of Internal Revenue Code
Section 382 limitations on the use of the federal NOLs acquired. The federal NOL carryforwards expire at various dates beginning in
2018 and ending in 2035.
F-32
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
ASC 740, Income Taxes ("ASC 740") prescribes a recognition threshold and a measurement attribute for the financial
statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those
benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing
authorities. As a result of the Merger, the Company acquired certain tax positions taken by Crimson in prior years. These positions are
not expected to have a material impact on results of operations, financial position or cash flows. A reconciliation of the beginning and
ending amount of unrecognized income tax benefits is as follows (in thousands):
Unrecognized Tax Benefits
Balance at December 31, 2014
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, 2015
$
$
518
—
—
—
(158)
360
The Company's policy is to recognize interest and penalties related to uncertain tax positions as income tax benefit (expense)
in the Company’s Consolidated Statements of Operations. The Company had no interest or penalties related to unrecognized tax
benefits for the year ended December 31, 2015 or any prior years. The total amount of unrecognized tax benefit if recognized that
would affect the effective tax rate was zero.
The Company's tax returns are subject to periodic audits by the various jurisdictions in which the Company operates. These
audits can result in adjustments of taxes due or adjustments of the NOL carryforwards that are available to offset future taxable
income. The Company does not anticipate that the total unrecognized tax benefits will significantly change due to the settlement of
audits and the expiration of statute of limitations prior to December 31, 2015.
Generally, the Company's income tax years of 1998 through the current year remain open and subject to examination by
Federal tax authorities, and the tax years of 2009 through current remain open and subject to examination by the tax authorities in
Texas and Louisiana which are the jurisdictions where the Company carries its principal operations.
17. Related Party Transactions
Juneau Exploration L.P.
In April 2012, the Company announced that Mr. Brad Juneau, the sole manager of the general partner of Juneau Exploration
L.P. (“JEX”), had joined the Company’s board of directors. In January 2013, Contaro Company, a wholly-owned subsidiary of the
Company, entered into an advisory agreement with JEX (the "Contaro Advisory Agreement"). Under the Contaro Advisory
Agreement, JEX provided advisory services to Contaro in connection with Contaro's investment in Exaro, and Mr. Juneau served on
the Board of Managers of Exaro and performed such duties as described in the limited liability company operating agreement of
Exaro. Pursuant to the Contaro Advisory Agreement, JEX was paid a monthly fee of $10,000 and was entitled to receive a one percent
(1%) fee of the cash profit earned by Contaro.
On March 19, 2014, Mr. Juneau resigned from the Company’s board of directors and no longer provides services under the
Contaro Advisory Agreement. As a result, the Contaro Advisory Agreement was terminated effective as of March 19, 2014.
Olympic Energy Partners
Mr. Joseph J. Romano was elected President and Chief Executive Officer of the Company in December 2012, and named
Chairman of the Company in April 2013. Upon the Merger with Crimson on October 1, 2013, Mr. Romano resigned as President and
Chief Executive Officer, but continued as Chairman. Mr. Romano is also the President and Chief Executive Officer of Olympic
Energy Partners LLC ("Olympic").
F-33
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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 its
Dutch and Mary Rose wells.
Republic Exploration LLC
In his capacity as sole manager of the general partner of JEX, Mr. Juneau also controlled 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 generated and evaluated offshore exploration prospects and 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.
Effective as of the close of business on December 31, 2015, the Company, and the other members of REX agreed to dissolve
and liquidate REX. REX’s assets are being distributed proportionately to its members.
As of December 31, 2015, Contango, Olympic, JEX, REX and JEX employees owned the following interests in the
Company's offshore wells.
Dutch #1 - #5
Mary Rose #1
Mary Rose #2 - #3
Mary Rose #4
Mary Rose #5
Ship Shoal 263
Vermilion 170
Olympic
JEX
REX
JEX Employees
WI
3.53%
3.61%
3.61%
2.34%
2.56%
—%
—%
NRI
2.84%
2.70%
2.58%
1.70%
1.87%
—%
—%
WI
1.88%
2.01%
2.01%
1.31%
1.43%
—%
4.30%
NRI
WI
NRI
1.51%
1.51%
1.44%
0.95%
1.04%
—%
3.35%
—%
—%
—%
—%
—%
—%
—%
—%
—%
—%
—%
12.50%
—%
9.74%
ORRI
2.02%
2.79%
2.79%
1.82%
1.82%
3.33%
3.33%
Prior to December 2013, Contango, Olympic, and JEX had the following lower WI and NRI in Dutch #1-#5, as a result of
exercising a preferential right in December 2013:
Dutch #1 - #5
Olympic
WI
3.02%
NRI
2.42%
JEX
WI
1.61%
NRI
1.29%
During the year ended December 31, 2015, Mr. Romano earned $79 thousand for his service as a director of the Company.
During the year ended December 31, 2014, Mr. Romano earned $105 thousand for his service as a director of the Company. In April
2014, the board of directors accelerated the vesting of Mr. Juneau’s 1,622 shares which would have otherwise been forfeited upon his
resignation in March 2014. The Company recognized compensation expense of approximately $71 thousand related to the shares
granted to Mr. Juneau for the three months ended March 31, 2014. Additionally, during the years ended December 31, 2015 and 2014,
Mr. Romano received 4,534 and 2,612 shares of restricted stock, respectively, which both vest 100% on the one-year anniversary of
the date of grant, as part of his board of director compensation. The Company recognized compensation expense of $99 thousand and
$124 thousand related to shares granted to Mr. Romano during the years ended December 31, 2015 and 2014, respectively. Below is a
summary of transactions between the Company, Olympic, JEX, and REX during the years ended December 31, 2015, 2014 and 2013.
F-34
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
In June 2012, the Company purchased five federal lease blocks that were generated by REX. In connection with the
dissolution and liquidation of REX, all participation agreements for these blocks that discussed carried interest
arrangements, prospect fee payments, etc. are being terminated effective as of the date of the dissolution.
In June 2012, the Company purchased one federal lease block that was generated by REX. The Company paid JEX a
prospect fee of $250,000 in December 2013 upon spudding this unsuccessful prospect.
In March 2013, the Company purchased three federal lease blocks that were generated by REX. In connection with the
dissolution and liquidation of REX, all participation agreements for these blocks that discussed carried interest
arrangements, prospect fee payments, etc. are being terminated effective as of the date of the dissolution. The Company
paid JEX two prospect fees of $250,000 each in 2013, for evaluating these two prospects located on three leases.
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 has a 75% working interest in this well, with several other owners
owning the remainder. The Company paid JEX a prospect fee of $250,000 for evaluating this prospect.
In the Tuscaloosa Marine Shale the Company has a 100% working interest through first production. JEX will receive a
carried working interest of 10% in certain of the Company’s TMS wells, and JEX employees will receive an ORRI of
2%, of which Mr. Juneau receives 0.75%, to reimburse Mr. Juneau for out-of-pocket costs incurred in order for
Contango to participate in the prospect. An additional 2% ORRI was granted to the geologist who generated the TMS
prospect for us. The geologist has subsequently been employed by Contango.
Effective January 1, 2014, the Company subleased to JEX a portion of its previous office space at 3700 Buffalo
Speedway, Houston, Texas for approximately $0.1 million per year, which approximates its rental liability for that space.
The sublease expires in February 2016.
Below is a summary of payments the Company received from (paid to) Olympic, JEX, and REX in the ordinary course of
business in its capacity as operator of the wells and platforms for the periods indicated. The Company made and received similar types
of payments with other well owners (in thousands):
Olympic
2015
JEX
REX
Year ended December 31,
2014
JEX
Olympic
REX
Olympic
2013
JEX
REX
Revenue payments as well owners
$
(4,115) $
(2,639) $
(1,077) $
(7,349) $
(4,882) $
(2,270) $
(6,859) $
(4,628) $
(1,932)
Joint interest billing receipts
531
386
1,246
673
521
322
945
1,201
2,090
Below is a summary of payments the Company received from (paid to) Olympic, JEX and REX as a result of specific
transactions between the Company, Olympic, JEX and REX. While these payments are in the ordinary course of business, the
Company did not have similar transactions with other well owners (in thousands):
Olympic
2015
JEX
REX
Olympic
2014
JEX
REX
Olympic
2013
JEX
Year ended December 31,
Reimbursement of certain costs
$
— $
— $
— $
(54) $
(29) $
— $
— $
(115) $
Rent received for sublease
Prospect fees
Advisory Agreements
REX distribution to members
—
—
—
—
119
—
—
—
—
—
—
—
—
—
—
—
142
—
—
—
—
—
—
—
—
—
—
—
—
(1,000)
(361)
—
REX
(4)
—
—
—
(197)
F-35
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
As of December 31, 2015 and 2014, the Company's consolidated balance sheets reflected the following balances (in
thousands):
Accounts receivable:
Joint interest billing
Accounts payable:
Olympic
December 31, 2015
JEX
REX
Olympic
December 31, 2014
JEX
REX
26
25
27
48
42
12
Royalties and revenue payable
(451)
(279)
(83)
(1,006)
(620)
(175)
Oaktree Capital Management L.P.
Oaktree Capital Management L.P. ("Oaktree"), through various funds, owns approximately 6.6% of the Company's stock. On
October 1, 2013 following the closing of the Merger, Mr. James Ford, a Managing Director and Portfolio Manager within Oaktree at
the time, 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, have been instead granted to an
affiliate of Oaktree. During the year ended December 31, 2015, an affiliate of Oaktree earned $61 thousand in cash and 4,534 shares
of restricted common stock as a result of Mr. Ford's board participation. During the year ended December 31, 2014, an affiliate of
Oaktree earned $64 thousand in cash and 2,612 shares of restricted common stock as a result of Mr. Ford’s board participation. These
shares vest one year from the date of grant. During the years ended December 31, 2015 and 2014, the Company recognized
compensation expense of approximately $99 thousand and $124 thousand, respectively, related to the shares of restricted stock
previously granted to an affiliate of Oaktree under the Director Compensation Plan
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.
18. Subsequent Events
The Company has evaluated subsequent events through the date the financial statements were available to be issued. Nothing
that would require recognition or disclosure in the financial statements was identified in addition to the items disclosed in the financial
statements.
F-36
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURE (Unaudited)
In accordance with U.S. GAAP for disclosures regarding oil and gas producing activities, and SEC rules for oil and gas
reporting disclosures, we are making the following disclosures regarding our natural gas and oil reserves and exploration and
production activities.
Capitalized Costs Related to Oil and Gas Producing Activities
The following table presents information regarding our net capitalized costs related to oil and gas producing activities as of
the date indicated (in thousands):
Proved oil and gas properties
Unproved oil and gas properties
Less accumulated depreciation, depletion, amortization and impairment
Net capitalized costs
Costs Incurred
December 31,
2015
2014
$
$
1,187,707
16,439
1,204,146
(825,201)
378,945
$
$
1,138,054
35,783
1,173,837
(425,890)
747,947
The following table presents information regarding our net costs incurred in the purchase of proved and unproved properties
and in exploration and development activities for the periods indicated (in thousands):
Property acquisition costs:
Unproved
Proved
Exploration costs
Development costs
Total costs incurred
Year Ended December 31,
2014
2015
2013
$
$
11,453 $
—
29,477
20,120
61,050 $
22,087 $
—
49,680
120,630
192,397 $
8,134
428,925
15,551
35,363
487,973
The following table presents information regarding our share of the net costs incurred by Exaro in the purchase of proved and
unproved properties and in exploration and development activities for the periods indicated (in thousands):
Property acquisition costs
Exploration costs
Development costs
Total costs incurred
Natural Gas and Oil Reserves
Year Ended December 31,
2015
2014
2013
$
$
— $
—
4,503
4,503
$
— $
—
30,288
30,288
$
—
—
51,014
51,014
Proved reserves are the estimated quantities of natural gas, oil and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating
conditions and current regulatory practices. Proved developed reserves are proved reserves which are expected to be produced from
existing completion intervals with existing equipment and operating methods.
Proved natural gas and oil reserve quantities at December 31, 2012, and 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
F-37
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURE (Unaudited)
December 31, 2015, 2014 and 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.
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, 2015, 2014, 2013 and 2012, all of which
are located in the continental United States.
Proved Developed and Undeveloped Reserves as of:
December 31, 2012
Sale of minerals in place
Extensions and discoveries
Purchases of minerals in place
Revisions of previous estimates
Production
December 31, 2013
Sale of minerals in place
Extensions and discoveries
Revisions of previous estimates
Production
December 31, 2014
Sale of minerals in place
Extensions and discoveries
Revisions of previous estimates
Production
December 31, 2015
Proved Developed Reserves as of:
December 31, 2012
December 31, 2013
December 31, 2014
December 31, 2015
Proved Undeveloped Reserves as of:
December 31, 2012
December 31, 2013
December 31, 2014
December 31, 2015
Oil and
Condensate
(MBbls)
NGLs
(MBbls)
Natural
Gas
(MMcf)
Total
(MMcfe)
2,514
(323)
2,199
6,839
(942)
(589)
9,698
(1)
2,940
(2,821)
(1,401)
8,415
—
460
(3,160)
(924)
4,791
2,514
5,223
4,114
2,869
—
4,475
4,301
1,922
5,330
(49)
436
3,151
(233)
(677)
7,958
—
932
(373)
(1,008)
7,509
—
81
(1,229)
(967)
5,394
5,103
6,453
5,637
4,354
227
1,505
1,872
1,040
174,032
(356)
5,431
65,186
(15,739)
(20,624)
207,930
(161)
12,899
(15,142)
(25,875)
179,651
—
543
(31,451)
(22,615)
126,128
166,307
185,535
150,235
113,952
7,725
22,395
29,416
12,176
221,096
(2,588)
21,241
125,126
(22,789)
(28,220)
313,866
(164)
36,130
(34,316)
(40,323)
275,193
—
3,788
(57,782)
(33,961)
187,238
212,009
255,591
208,734
157,288
9,087
58,275
66,459
29,950
During the year ended December 31, 2015, our proved reserves decreased by approximately 88.0 Bcfe attributable primarily
to the impact of the dramatic decline in commodity prices on the value and volume of our proved reserves, and in part to the impact of
the significant reduction in our capital spending in response to the low and uncertain commodity price environment.
During the year ended December 31, 2014, our proved reserves decreased by approximately 38.7 Bcfe. This decrease is
primarily attributable to 40.3 Bcfe of production and a 22.4 Bcfe negative revision of proved developed producing reserves at our
F-38
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURE (Unaudited)
Eugene Island 11 field due to a change in forecasted condensate yield and ultimate field abandonment pressure; these decreases were
partially offset by 36.1 Bcfe for extensions and discoveries.
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.
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, 2015, 2014, 2013and 2012, attributable
to its Investment in Exaro.
Proved Developed and Undeveloped Reserves as of:
Oil and
Condensate
(MBbls)
NGLs
(MBbls)
Natural
Gas
(MMcf)
Total
(MMcfe)
December 31, 2012
Sale of minerals in place
Extensions and discoveries
Purchases of minerals in place
Revisions of previous estimates
Production
December 31, 2013
Sale of minerals in place
Extensions and discoveries
Revisions of previous estimates
Production
December 31, 2014
Sale of minerals in place
Extensions and discoveries
Revisions of previous estimates
Production
December 31, 2015
Proved Developed Reserves as of:
December 31, 2012
December 31, 2013
December 31, 2014
December 31, 2015
Proved Undeveloped Reserves as of:
December 31, 2012
December 31, 2013
December 31, 2014
December 31, 2015
133
—
66
—
288
(48)
439
—
329
86
(63)
791
—
1
(289)
(61)
442
133
439
529
442
—
—
262
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
11,056
—
4,282
—
27,339
(3,609)
39,068
—
26,173
5,102
(4,931)
65,412
—
120
(24,637)
(4,821)
36,074
11,056
39,068
45,127
36,074
—
—
20,285
—
11,854
—
4,675
—
29,066
(3,893)
41,702
—
28,147
5,617
(5,308)
70,158
—
128
(26,373)
(5,189)
38,724
11,854
41,702
48,301
38,724
—
—
21,857
—
During the year ended December 31, 2015, Exaro’s proved reserves decreased by approximately 31.4 Bcfe attributable to the
impact of the dramatic decline in commodity prices on the value and volume of proved reserves, and the impact of the significant
reduction in capital spending in response to the low and uncertain commodity price environment.
F-39
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURE (Unaudited)
The increase in Exaro’s extensions and discoveries in 2014 is due to the increase in the number of wells drilled in
conjunction with higher development costs spent in 2013 and 2014. Exaro began operations in 2012.
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, 2015, 2014 and 2013 are shown below (in thousands):
Future cash inflows
Future production costs
Future development costs
Future income tax expenses
Future net cash flows
10% annual discount for estimated timing of cash flows
As of December 31,
2015
2014
2013
$
623,014 $
1,820,954 $
2,098,788
(200,953)
(69,147)
—
352,914
(103,508)
(412,607)
(219,598)
(232,648)
956,101
(308,085)
(473,801)
(183,329)
(323,210)
1,118,448
(347,005)
771,443
Standardized measure of discounted future net cash flows
$
249,406 $
648,016 $
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, 2015, future cash inflows were based on unadjusted prices of $2.59 per MMbtu of natural
gas, $47.36 per barrel of oil, and $14.41 per barrel of NGLs. As of December 31, 2014, future cash inflows were based on unadjusted
prices of $4.32 per MMbtu of natural gas, $93.32 per barrel of oil, and $33.45 per barrel of NGLs. As of December 31, 2013, future
cash inflows were based on unadjusted prices of $3.66 per MMbtu of natural gas, $97.33 per barrel of oil, and $37.39 per barrel of
NGLs.
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, 2015, 2014 and 2013 attributable to its Investment in Exaro are shown below (in
thousands):
As of December 31,
2015
2014
2013
Future cash inflows
Future production costs
Future development costs
Future income tax expenses
Future net cash flows
10% annual discount for estimated timing of cash flows
$
117,211 $
392,238 $
(65,042)
(2,399)
—
49,770
(18,472)
(147,473)
(39,523)
—
205,242
(104,635)
Standardized measure of discounted future net cash flows
$
31,298 $
100,607 $
196,515
(82,071)
(2,466)
—
111,978
(48,072)
63,906
Realized Prices
The average realized prices for the year ended December 31, 2015 production were $2.61 per MCF of gas, $46.80 per barrel
of oil, and $14.68 per barrel of NGL. Sales are based on market prices and do not include the effects of realized derivative hedging
gains of $2.3 million for the year ended December 31, 2015.
F-40
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURE (Unaudited)
The average realized prices for the year ended December 31, 2014 production were $4.36 per MCF of gas, $92.98 per barrel
of oil, and $33.27 per barrel of NGL. Sales are based on market prices and do not include the effects of realized derivative hedging
gains of $1.3 million for the year ended December 31, 2014.
Future production and development costs are estimated expenditures to be incurred in developing and producing the
Company’s proved natural gas and oil reserves based on historical costs and assuming continuation of existing economic conditions.
Future development costs relate to compression charges at our platforms, abandonment costs, recompletion costs, and additional
development costs for new facilities.
Future income taxes are based on year-end statutory rates, adjusted for tax basis and applicable tax credits. A discount factor
of 10 percent was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is
not intended to represent the replacement cost or fair value of the Company’s natural gas and oil properties. An estimate of fair value
would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future
changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve
estimates of natural gas and oil producing operations.
The Company's share of the standardized measure of discounted future net cash flows attributable to our investment in Exaro
does not include the effect of income taxes because Exaro is treated a partnership for tax purposes. Exaro allocates any income or
expense for tax purposes to its partners.
Change in Standardized Measure
Changes in the standardized measure of future net cash flows relating to proved natural gas and oil reserves are summarized
below (in thousands):
Year Ended December 31,
2014
2015
2013
Changes in standardized measure due to current year operation:
Sales of natural gas and oil produced during the period, net of production
expenses
$
(78,651) $
(229,222) $
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
8,584
(420,890)
23,771
(156,249)
—
—
79,687
148,854
(3,716)
(398,610)
102,024
(43,214)
7,064
(107,934)
—
(195)
98,721
66,918
(17,588)
(123,426)
648,016
249,406
$
771,442
648,016
$
$
(86,939)
120,709
(11,469)
20,282
(3,627)
408,990
(15,555)
37,099
(22,952)
(32,613)
413,925
357,517
771,442
During the year ended December 31, 2015, our proved reserves decreased by approximately 88.0 Bcfe and our standardized
measure decreased by approximately $398.6 million. This decrease is attributable primarily to the impact of the dramatic decline in
commodity prices on the value and volume of our proved reserves, and in part to the impact of the significant reduction in our capital
spending in response to the low and uncertain commodity price environment.
During the year ended December 31, 2014, our proved reserves decreased by approximately 38.7 Bcfe and our standardized
measure decreased by approximately $123.4 million. This decrease is primarily attributable to 40.3 Bcfe of production and a 22.4 Bcfe
F-41
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURE (Unaudited)
negative revision of proved developed producing reserves at our Eugene Island 11 field due to a change in forecasted condensate yield
and ultimate field abandonment pressure; these decreases were partially offset by 36.1 Bcfe for extensions and discoveries.
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.
Changes in the standardized measure of future net cash flows relating to proved natural gas and oil reserves attributable to the
Company’s investment in Exaro are summarized below (in thousands):
Changes in standardized measure due to current year operation:
Sales of natural gas and oil produced during the period, net of production
expenses
$
(8,745) $
(21,356) $
(13,509)
Year Ended December 31,
2015
2014
2013
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
161
(49,933)
3,958
(22,973)
—
—
10,061
—
(1,838)
(69,309)
100,607
31,298
$
26,241
18,040
354
9,379
—
—
6,391
—
(2,348)
36,701
63,906
100,607
$
$
8,039
10,131
(433)
44,544
—
—
1,366
—
107
50,245
13,661
63,906
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, 2015 and 2014, (in
thousands, except per share amounts):
Year ended December 31, 2015:
Revenues
Net loss attributable to common stock (1)
Net loss per share (2):
Basic:
Diluted:
Year ended December 31, 2014:
Revenues
Net income (loss) attributable to common stock (1)
Net income (loss) per share (2):
Basic:
Diluted:
March 31
June 30
September 30
December 31
Quarter Ended
$
$
$
$
$
$
$
30,647 $
35,334 $
29,035 $
21,489
(18,564) $
(19,528) $
(185,685) $
(111,271)
(0.98) $
(0.98) $
(1.03) $
(1.03) $
(9.79) $
(9.79) $
(5.85)
(5.85)
80,257 $
78,419 $
67,552 $
(10,193)
4,581
3,664
50,230
(19,926)
(0.53) $
(0.53) $
0.24 $
0.24 $
0.19 $
0.19 $
(1.05)
(1.05)
(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, based in Houston, Texas,
is an independent energy company engaged in the acquisition,
exploration, development, exploitation and production of
crude oil and natural gas properties offshore in the shallow
waters of the Gulf of Mexico and in the onshore Texas Gulf
Coast and Rocky Mountain regions of the United States.
Houston
Headquarters
GULF OF MEXICO
ONSHORE GULF COAST
ROCKY MOUNTAINS
Total Proved Reserves: 114 Bcfe
Percent Developed:
Percent Natural Gas:
2015 Production:
100%
81%
22 Bcfe
Total Proved Reserves: 67 Bcfe
Percent Developed:
Percent Natural Gas:
2015 Production:
60%
48%
12 Bcfe
Total Proved Reserves*: 6 Bcfe
Percent Developed:*
43%
Percent Natural Gas*: 33%
2015 Production*:
<1 Bcfe
* Excludes our 37% equity interest in Exaro Energy III
CORPORATE
INFORMATION
BOARD OF DIRECTORS
CORPORATE OFFICE
717 Texas Avenue, Suite 2900
Houston, Texas 77002
Phone: 713.236.7400
Fax: 713.236.4424
OUTSIDE COUNSEL
Vinson & Elkins
First City Tower
1001 Fannin Street, Suite 2500
Houston, Texas 77002
COMMON STOCK INFORMATION
The Common Stock is traded on the
NYSE MKT under the symbol “MCF”
TRANSFER AGENT
Continental Stock & Trust Company
17 Battery Place
New York, New York 10004
212.509.4000
AUDITORS
Grant Thornton LLP
700 Milam Street, Suite 300
Houston, Texas 77002
FORM 10-K
Additional copies of the Company’s Form 10-K
as fi led with the Securities and Exchange
Commission, are available at our website
www.contango.com under Investor Relations
Joseph J. Romano
Chairman of the Board
Allan D. Keel
B.A. Berilgen
B. James Ford
Ellis L. McCain
Charles M. Reimer
Steven L. Schoonover
MANAGEMENT TEAM
Allan D. Keel
President and Chief Executive Offi cer
Thomas H. Atkins
Senior Vice President, Exploration
E. Joseph Grady
Senior Vice President
and Chief Financial Offi cer
A. Carl Isaac
Senior Vice President, Operations
J. Steven Mengle
Senior Vice President, Engineering
John A. Thomas
Vice President, General Counsel
and Corporate Secretary
Michael J. Autin
Vice President, Production
Sergio Castro
Vice President and Treasurer
Jeff Sikora
Vice President, Land
Edward Skrljac
Vice President, Onshore Completions
Patrick Webb
Vice President, Business Development
C
O
N
T
A
N
G
O
O
I
L
&
G
A
S
C
O
M
P
A
N
Y
2
0
1
5
A
N
N
U
A
L
R
E
P
O
R
T
717 Texas Avenue, Suite 2900
Houston, Texas 77002
Phone: 713.236.7400
www.contango.com
2015 ANNUAL
REPORT
DISCIPLINED VALUE ENHANCEMENT