Contango Oil & Gas Company Annual Report 2010

FY2010 Annual Report · Contango Oil & Gas Company

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended June 30, 2010

FORM 10-K

[ ]

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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.)

3700 Buffalo Speedway, Suite 960
Houston, Texas 77098
(Address of principal executive offices)

(713) 960-1901
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Common Stock, Par Value $0.04 per share

NYSE Amex

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the

Securities Act. Yes [ ] No [X]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of

the Act. Yes [ ] No [X]

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d)
of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web

site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T
(§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was
required to submit and post such files). Yes [ ] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not

contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

DB2/21043537.7

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated

filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer [ ] Accelerated filer [X] Non-accelerated filer [ ] Smaller reporting company [ ]

(Do not check if smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange

Act). Yes [ ] No [X]

At December 31, 2009, 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 Amex was $589,189,869.
As of August 31, 2010, there were 15,664,666 shares of the registrant’s common stock outstanding.

Documents Incorporated by Reference

Items 10, 11, 12, 13 and 14 of Part III have been omitted from this report since 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.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
ANNUAL REPORT ON FORM 10-K FOR THE FISCAL YEAR ENDED JUNE 30, 2010

TABLE OF CONTENTS

PART I

Page

Item 1.

Business

1
Overview .....................................................................................................................................
1
Our Strategy ................................................................................................................................
2
Exploration Alliance with JEX ....................................................................................................
2
Offshore Gulf of Mexico Exploration Joint Ventures .................................................................
2
Contango Operators, Inc.. ............................................................................................................
5
Offshore Properties .....................................................................................................................
6
Onshore Exploration and Properties ............................................................................................
7
Contango Venture Capital Corporation .......................................................................................
7
Property Sales and Discontinued Operations ..............................................................................
8
Marketing and Pricing .................................................................................................................
8
Competition .................................................................................................................................
Governmental Regulations ..........................................................................................................
8
Risk and Insurance Program ........................................................................................................ 10
Employees ................................................................................................................................... 11
Directors and Executive Officers ................................................................................................ 11
Corporate Offices ........................................................................................................................ 13
Code of Ethics ............................................................................................................................. 13
Available Information ................................................................................................................. 13
Item 1A. Risk Factors ........................................................................................................................................ 14
Item 1B. Unresolved Staff Comments ............................................................................................................... 22
Item 2.

Properties

Production, Prices and Operating Expenses ................................................................................ 23
Development, Exploration and Acquisition Expenditures .......................................................... 23
Drilling Activity .......................................................................................................................... 24
Exploration and Development Acreage ....................................................................................... 24
Productive Wells ......................................................................................................................... 25
Natural Gas and Oil Reserves ..................................................................................................... 25
Legal Proceedings .............................................................................................................................. 27
Reserved ............................................................................................................................................. 27

Item 3.
Item 4.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of

Equity Securities ................................................................................................................................. 27
Selected Financial Data ...................................................................................................................... 30

Item 6.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview ..................................................................................................................................... 31
Impact of Deepwater Horizon Incident and Federal Deepwater Moratorium ............................. 31
Results of Operations .................................................................................................................. 32
Capital Resources and Liquidity ................................................................................................. 36
Off Balance Sheet Arrangements ................................................................................................ 38
Contractual Obligations ............................................................................................................... 38
Share Repurchase Program ......................................................................................................... 38
Credit Facility .............................................................................................................................. 38
Application of Critical Accounting Policies and Management’s Estimate ................................. 39
Recent Accounting Pronouncements ........................................................................................... 40
Item 7A. Quantitative and Qualitative Disclosure about Market Risk .............................................................. 41
Financial Statements and Supplementary Data .................................................................................. 41
Item 8.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ............. 42
Item 9A. Controls and Procedures ..................................................................................................................... 42

Item 9B. Other Information ............................................................................................................................... 44

PART III

Item 10. Directors, Executive Officers and Corporate Governance ................................................................ 44
Item 11. Executive Compensation .................................................................................................................... 45
Item 12. Security Ownership of Certain Beneficial Owners and Management and

Related Stockholder Matters .............................................................................................................. 45
Item 13. Certain Relationships and Related Transactions, and Director Independence ................................... 45
Item 14. Principal Accountant Fees and Services ............................................................................................. 45

Item 15. Exhibits and Financial Statement Schedules ...................................................................................... 45

PART IV

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Some of the statements made 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. These include such matters as:

• Our financial position
• Business strategy, including outsourcing
• Meeting our forecasts and budgets
• Anticipated capital expenditures
• Drilling of wells
• Natural gas and oil production and reserves
• Timing and amount of future discoveries (if any) and production of natural gas and oil
• Operating costs and other expenses
• Cash flow and anticipated liquidity
• Prospect development
• Property acquisitions and sales
• New governmental laws and regulations

Although we believe the expectations reflected in such forward-looking statements are reasonable,

such expectations may not occur. These forward-looking statements involve known and unknown risks,
uncertainties and other factors that may cause our actual results, performance or achievements to be materially
different from actual future results expressed or implied by the forward-looking statements. These factors
include among others:

• Low and/or declining prices for natural gas and oil
• Natural gas and oil price volatility
• Operational constraints, start-up delays and production shut-ins at both operated and non-

operated production platforms, pipelines and gas processing facilities

• The risks associated with acting as the operator in drilling deep high pressure and temperature

wells in the Gulf of Mexico

• The risks associated with exploration, including cost overruns and the drilling of non-economic
wells or dry holes, especially in prospects in which the Company has made a large capital
commitment relative to the size of the Company’s 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 of rigs and other operating equipment

iii

• Ability to raise capital to fund capital expenditures
• 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
•
• Uncertainties in the estimation of proved reserves and in the projection of future rates of

Interest rate volatility

production and timing of development expenditures

• Operating hazards attendant to the natural gas and oil business
• 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

• Weather
• Availability and cost of material and equipment
• Delays in anticipated start-up dates
• Actions or inactions of third-party operators of our properties
• Actions or inactions of third-party operators of pipelines or processing facilities
• Ability to find and retain skilled personnel
• Strength and financial resources of competitors
• Federal and state regulatory developments and approvals
• Environmental risks
• Worldwide economic conditions
• The ability to construct and operate offshore infrastructure, including pipeline and production

facilities

• The continued compliance by the Company with various pipeline and gas processing plant

specifications for the gas and condensate produced by the Company

• Drilling and operating costs, production rates and ultimate reserve recoveries in our Eugene

Island 10 (“Dutch”) and State of Louisiana (“Mary Rose”) acreage

• Restrictions on permitting activities
• Expanded rigorous monitoring and testing requirements
• Legislation that may regulate drilling activities and increase or remove liability caps for claims

of damages from oil spills

• Ability to obtain insurance coverage on commercially reasonable terms
• Accidental spills, blowouts and pipeline ruptures
•

Impact of potential legislative and regulatory changes on Gulf of Mexico operating and safety
standards due to the Deepwater Horizon incident

You should not unduly rely on these forward-looking statements in this report, as they speak only as

of the date of this report. Except as required by law, we undertake no obligation to publicly release any
revisions to these forward-looking statements to reflect events or circumstances occurring after the date of this
report or to reflect the occurrence of unanticipated events. See the information under the heading “Risk
Factors” referred to on page 14 of this report for some of the important factors that could affect our financial
performance or could cause actual results to differ materially from estimates contained in forward-looking
statements.

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 are based on estimates prepared by independent engineers and are net to our interest.

PART I

Item 1. Business

Overview

Contango is a Houston-based, independent natural gas and oil company. The Company’s business is

to explore, develop, produce and acquire natural gas and oil properties primarily offshore in the Gulf of
Mexico. Contango Operators, Inc. (“COI”), our wholly-owned subsidiary, acts as operator on certain offshore
prospects.

Our Strategy

Our exploration strategy is predicated upon two core beliefs: (1) that the only competitive advantage

in the commodity-based natural gas and oil business is to be among the lowest cost producers and (2) that
virtually all the exploration and production industry’s value creation occurs through the drilling of successful
exploratory wells. As a result, our business strategy includes the following elements:

Funding exploration prospects generated by Juneau Exploration, L.P., our alliance partner. We

depend primarily upon our alliance partner, Juneau Exploration, L.P. (“JEX”), for prospect generation
expertise. JEX is experienced and has a successful track record in exploration.

Using our limited capital availability to increase our reward/risk potential on selective prospects. We
have concentrated our risk investment capital in our offshore Gulf of Mexico prospects. Exploration prospects
are inherently risky as they require large amounts of capital with no guarantee of success. COI drills and
operates our offshore prospects. Should we be successful in any of our offshore prospects, we will have the
opportunity to spend significantly more capital to complete development and bring the discovery to producing
status.

Operating in the Gulf of Mexico. COI was formed for the purpose of drilling and operating
exploration wells in the Gulf of Mexico. While the Company has historically drilled turnkey wells, adverse
weather conditions as well as difficulties encountered while drilling our offshore wells could cause our
contracts to come off turnkey and thus lead to significantly higher drilling costs.

Sale of proved properties. From time-to-time as part of our business strategy, we have sold and in the

future expect to continue to sell some or a substantial portion of our proved reserves and assets to capture
current value, using the sales proceeds to further our offshore exploration activities. Since its inception, the
Company has sold approximately $484 million worth of natural gas and oil properties, and views periodic
reserve sales as an opportunity to capture value, reduce reserve and price risk, and as a source of funds for
potentially higher rate of return natural gas and oil exploration opportunities.

Controlling general and administrative and geological and geophysical costs. Our goal is to be

among the most efficient in the industry in revenue and profit per employee and among the lowest in general
and administrative costs. We plan to continue outsourcing our geological, geophysical, and reservoir
engineering and land functions, and partnering with cost efficient operators. We have eight employees.

Structuring transactions to share risk. JEX, our alliance partner, shares in the upfront costs and the

risk of our exploration prospects.

Structuring incentives to drive behavior. We believe that equity ownership aligns the interests of our
employees and stockholders. Our directors and executive officers beneficially own or have voting control over
approximately 22% of our common stock.

Exploration Alliance with JEX

JEX is a private company formed for the purpose of assembling domestic natural gas and oil prospects.

Under our agreement with JEX, JEX generates natural gas and oil prospects and evaluates exploration
prospects generated by others. JEX focuses on the Gulf of Mexico, and generates offshore exploration
prospects either individually, or via our affiliated company, Republic Exploration, LLC (“REX”) (see
“Offshore Gulf of Mexico Exploration Joint Ventures” below). Prior to June 1, 2010, JEX would also generate
offshore exploration prospects via a second company affiliated with us, Contango Offshore Exploration, LLC
(“COE”). Effective June 1, 2010, COE was dissolved and all properties owned by COE were transferred to its
respective members. We do not have a written agreement with JEX which contractually obligates them to
provide us their services.

Offshore Gulf of Mexico Exploration Joint Ventures

Contango, through its wholly-owned subsidiary COI, and its partially-owned affiliate, REX, conducts
exploration activities in the Gulf of Mexico. As of August 31, 2010, Contango, through COI and REX, had an
interest in 28 offshore leases. See “Offshore Properties” below for additional information on our offshore
properties.

Contango Operators, Inc

COI, a wholly-owned subsidiary of the Company, was formed for the purpose of drilling and

operating wells in the Gulf of Mexico. Additionally, COI expects to acquire significant working interests in
offshore exploration and development opportunities in the Gulf of Mexico, usually under a farm-out
agreement, or similar agreement, with REX. COI may also acquire and operate significant working interests in
offshore exploration and development opportunities under farm-in agreements with third parties.

The Company’s offshore production consists of 11 wells located on federal and State of Louisiana
leases in the shallow waters of the Gulf of Mexico. These 11 wells produce via the following three platforms:

Eugene Island 11 Platform

As of August 31, 2010, the Company-owned and operated platform at Eugene Island 11 was

processing approximately 54 Mmcfed, net to Contango. This platform was designed with a capacity of 500
million cubic feet per day (“Mmcfd”) and 6,000 barrels of oil per day (“bopd”). This platform services
production from the Company’s four Mary Rose wells and Eloise North well, which are all located in State of
Louisiana waters, as well as our Dutch #4 well and Eloise South well, which are both located in federal waters.
From the Eugene Island 11 platform, the gas and condensate flow to our Eugene Island 63 auxiliary platform
via our 20” pipeline, which has been designed with a capacity of 330 Mmcfd and 6,000 bopd, and then from
the Eugene Island 63 auxiliary platform to third-party owned and operated on-shore processing facilities near
Patterson, Louisiana.

On February 24, 2010, a dredge contracted by the Army Corps of Engineers to dredge the
Atchafalaya River Channel ruptured the Company’s 20” pipeline that runs from our Eugene Island 11gathering
platform to our Eugene Island 63 auxiliary platform. All wells serviced by the platform were immediately
shut-in upon pipeline rupture, and we immediately implemented our spill response plan. The Company
estimates that a minimal and immaterial quantity of production was lost. The pipeline was repaired and
production resumed on March 31, 2010. We believe the repairs will be covered by our insurance policy
subject to a deductible. We have an approximate 53% ownership interest in the pipeline.

Eugene Island 24 Platform

The third-party owned and operated production platform at Eugene Island 24 was processing
approximately 30 Mmcfed, net to Contango as of August 31, 2010. This platform was designed with a
capacity of 100 Mmcfd and 3,000 bopd. This platform services production from the Company’s Dutch #1, #2
and #3 federal wells.

Ship Shoal 263 Platform

Ship Shoal 263 (“Nautilus”) was spud in October 2009 and announced as a discovery in January

2010. The Company-owned and operated Ship Shoal 263 platform was designed with a capacity of 40 Mmcfd
and 5,000 bopd. This platform services production from our Nautilus well which began producing in June
2010 and is currently producing approximately 18 Mmcfed, net to Contango.

Other Activities

In March 2010, we obtained a farm-in and spud a well on block Eugene Island 10 to drill a well on
our Eloise South prospect. This well was spud in March 2010, announced as a discovery in June 2010, and
began producing in July 2010. The well tested the Rob L sands identified in our Eloise North well, and was
drilled in a location so that upon depletion of our Eloise South well, our well bore may be completed up-hole
and produce in the Cib-op sand as our Dutch #5 well. The Company has a 26.9% working interest (21.5% net
revenue interest) in Eloise South, inclusive of our ownership interest in REX, and a 47.05% working interest
(38.1% net revenue interest) in Dutch #5. As of August 31, 2010, the Company had invested approximately
$12.7 million, inclusive of our ownership interest in REX, to drill, complete and bring the well to production.

In the third quarter of the fiscal year ended June 30, 2010 we drilled two dry holes in the Gulf of

Mexico. The first was on a farm-in we obtained on block Vermillion 155 (“Paisano”). This well had a dry
hole cost of approximately $5.3 million and the Company had a 100% working interest. The second was our
Matagorda Island 617 well (“Dude”), which was drilled in mid-February 2010 and determined to be a dry hole
in April 2010. This well had a dry hole cost of approximately $14.9 million and the Company had a 100%
working interest.

During the fiscal year ended June 30, 2010, COI was awarded three lease blocks from the Western
Gulf of Mexico Lease Sale No. 210 held on August 19, 2009, five leases from the State of Texas Lease Sale
held on October 6, 2009, and three lease blocks from the Central Gulf of Mexico Lease Sale No. 213 held on
March 17, 2010. COI was awarded the following leases for the following bid amounts:

• Matagorda Island Block 607………………. $317,000
• Matagorda Island Block 616………………. $317,000
• Matagorda Island Block 617………………. $1,017,000
• Galveston Area 248L……………………… $144,000
• Galveston Area 276L……………………… $144,000
• Galveston Area 277L (N/2 of NE/4)……… $291,787
• Galveston Area 277 L (S/2 of NE/4)…….... $144,000
• Galveston Area 338S……………………… $64,000
• Ship Shoal 121…………………………….. $3,017,777
• Ship Shoal 122…………………………….. $277,777
• Vermillion 170…………………………….. $3,017,777

During the fiscal year ended June 30, 2009, the Company’s Mary Rose #1 well was successfully

worked over at a cost of approximately $11.5 million ($6.1 million net to Contango), to reduce water
production from a water bearing sand above our production reservoir. We also installed line heaters at the
Eugene Island 11 platform which allowed us to further increase our production rate. Production had been
constrained due to entrained water that attached to the paraffin in our condensate. The line heaters were
installed at a cost of approximately $1.9 million ($0.9 million net to Contango).

The Company’s Mary Rose #2 well was successfully worked over in May 2009 at a cost of

approximately $5.6 million ($3.0 million net to Contango), to also reduce water production from a water
bearing sand above our production reservoir.

In September 2008, COI purchased additional working interests in nine offshore lease blocks from
existing owners for a total of $2.1 million. See “Offshore Properties” below for a detailed description of the
interests owned in our offshore properties.

During the fiscal year ended June 30, 2008, the Company acquired additional working interests in the

Republic Exploration LLC (REX)

West Delta 36, a REX prospect, is operated by a third party. The Company depends on a third-party
operator for the operation and maintenance of this production platform. As of August 31, 2010, the well was
temporarily shut-in. As of August 25, 2010 however, the well was producing at an 8/8ths rate of
approximately 2.9 million cubic feet equivalent per day (“Mmcfed”). REX has a 25.0% working interest
(“WI”), and a 20.0% net revenue interest (“NRI”), in this well.

During the fiscal year ended June 30, 2009, COI spud Eugene Island 56 #1 (“High Country West”)

and West Delta 77 (“Devil’s Elbow”), both REX prospects, which were both determined to be dry holes. COI
had a 100% WI and paid 100% of the drilling costs for both wells totaling approximately $16.5 million. These
costs together with associated leasehold costs and prospect fees of approximately $2.3 million are reflected as
exploration expenses in the Company’s Consolidated Statements of Operations for the fiscal year ended June
30, 2009.

During the fiscal year ended June 30, 2009, the Company sold a portion of its ownership interest in

REX to an existing member of REX for approximately $0.8 million. This sale decreased the Company’s
equity ownership interest in REX to its present 32.3%. REX was formed for the purpose of generating
exploration opportunities in the Gulf of Mexico. REX focuses on identifying prospects, acquiring leases at
federal and state lease sales and then selling the prospects to third parties, including Contango, subject to timed
drilling obligations plus retained reversionary interests in favor of REX. See Exhibit 21.2 for an organizational
chart of our subsidiaries.

During the fiscal year ended June 30, 2008, the members of REX entered into an Amended and

Restated Limited Liability Company Agreement (the “REX LLC Agreement”), effective as of April 1, 2008,
to, among other things, distribute REX’s interest in Dutch and Mary Rose to the individual members of REX
or their designees. In connection with this distribution, REX repaid in full all amounts owed by REX to a
private investment firm under a $50.0 million demand promissory note with such private investment firm (the
“REX Demand Note”). All security interests and other liens granted in favor of such private investment firm
as security for the obligations under the REX Demand Note have been released and terminated. The
Company’s portion of such repayment was approximately $22.5 million.

Contango Offshore Exploration LLC (COE)

Prior to its dissolution on June 1, 2010, the Company owned a 65.6% equity interest in COE. As of
June 1, 2010, COE had borrowed $4.3 million from the Company under a non-recourse promissory note (the
“Note”) payable on demand. As of June 1, 2010, accrued and unpaid interest on the Note was approximately
$1.6 million. In connection with the dissolution, the Company assumed its 65.6% share of the obligation under
the Note, while the other member of COE assumed the remaining 34.4%, or approximately $2 million. This $2
million is reflected as a receivable in the Consolidated Balance Sheet of the Company as of June 30, 2010.

Prior to its dissolution, COE had generated three prospects which were all drilled by COI: Ship Shoal

263, Grand Isle 70 and Grand Isle 72. In connection with its dissolution, COE distributed its ownership
interest in Ship Shoal 263 to its members. As a result, Contango has a working interest of approximately
92.46% and a net revenue interest of approximately 74% in this well. As of August 31, 2010 we had invested
approximately $38.2 million to drill, complete and bring Ship Shoal 263 to full production status.

Grand Isle 70 (“Red Queen”) was drilled in July 2006 and was temporarily abandoned while
alternative development scenarios were being evaluated. Effective December 1, 2009 the Company and COE
sold their respective interests in Grand Isle 70 to an independent third-party oil and gas company in exchange
for an overriding royalty interest. The Company subsequently sold its overriding royalty interests to JEX for a
gain of $112,868.

Grand Isle 72 (“Liberty”) ceased producing in October 2009 and the well was plugged and abandoned

in June 2010. The Company invested approximately $500,000 to permanently abandon the site. This lease
was relinquished to the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”)
(previously the Minerals Management Service) during the fourth quarter of our fiscal year ending June 30,
2010.

In June 2010, the Company withdrew from Ship Shoal 358, a COE prospect, and transferred all

future plugging and abandonment liabilities to the third party operator responsible for operation and
maintenance of the production platform.

Impact of Hurricanes Gustav and Ike

During the fiscal year ended June 2009, Hurricanes Gustav and Ike moved through the Gulf of

Mexico and it was necessary for us to shut-in our Dutch and Mary Rose production at various times before,
during and after the storms. Our offshore facilities sustained minor damage from Hurricane Ike. Repairs were
completed on the damaged wells at an 8/8ths cost of approximately $2.4 million, which was covered by the
Company’s insurance subject to a deductible. The on-shore third-party processing and pipeline facilities on
which we rely, however, incurred significant damage from Hurricane Ike and necessitated approximately three
months of downtime for our production while repairs were being made.

Offshore Properties

Producing Properties. The following table sets forth the interests owned by Contango through its

related entities in the Gulf of Mexico which were producing natural gas or oil as of August 31, 2010:

Area/Block
Contango Operators, Inc.:
Eugene Island 10 #D-1 (Dutch #1)………… 47.05%
Eugene Island 10 #E-1 (Dutch #2)………… 47.05%
Eugene Island 10 #F-1 (Dutch #3)………… 47.05%
Eugene Island 10 #G-1 (Dutch #4)………… 47.05%
Eugene Island 10 #I-1 (Eloise South)……… 23.76%
S-L 18640 #1 (Mary Rose #1)……………… 53.21%
S-L 19266 #1 (Mary Rose #2)……………… 53.21%
S-L 19266 #2 (Mary Rose #3)……………… 53.21%
S-L 18860 #1 (Mary Rose #4)……………… 34.58%
S-L 19266 #3 (Eloise North)…………………36.90%
Ship Shoal 263……………………………… 92.46%

NRI

38.1%
38.1%
38.1%
38.1%
19.0%
40.5%
38.7%
38.7%
25.5%
26.9%
74.0%

Status

Producing
Producing
Producing
Producing
Producing
Producing
Producing
Producing
Producing
Producing
Producing

Republic Exploration LLC
West Delta 36……………………………… 25.0%

20.0%

Producing

Leases. The following table sets forth the interests owned by Contango through its related entities in

leases in the Gulf of Mexico as of August 31, 2010:

Lease Date

Expiration Date

May-06
Jun-06
Feb 07
Jun 07
Dec 07
Dec-03
Dec-03
Oct-09
Oct-09
Oct-09
Oct-09
Oct-09
Nov-09
Nov-09
Nov-09
Jul-10
Jul-10
Jul-10
Nov-05
Nov-05

May-06
Jun-09
Jun-09

May-11
Jun-11
Feb 12
Jun 12
Dec-12
Dec-13
Dec-13
Oct-14
Oct-14
Oct-14
Oct-14
Oct-14
Nov-14
Nov-14
Nov-14
Jul-15
Jul-15
Jul-15
Nov-15
Nov-15

May-11
Jun-14
Jun-14

Area/Block
Contango Operators, Inc.:
Ship Shoal 14 ……………………………… 50.00%
Viosca Knoll 383 (1) ……………………… (2)
S-L 19261…………………………………… 53.21%
S-L 19396…………………………………… 53.21%
Eugene Island 11…………………………… 53.21%
East Breaks 369 (1)(3)……………………… (4)
East Breaks 370 (1)………………………… 65.63%
Galveston Area 248L…………………………100.00%
Galveston Area 276L…………………………100.00%
Galveston Area 277L (N/2 of NE/4)…………100.00%
Galveston Area 277L (S/2 of NE/4)…………100.00%
Galveston Area 338S…………………………100.00%
Matagorda Island 607……………………… 100.00%
Matagorda Island 616……………………… 100.00%
Matagorda Island 617 (3)……………………100.00%
Ship Shoal 121……………………………… 100.00%
Ship Shoal 122……………………………… 100.00%
Vermillion 170……………………………… 100.00%
East Breaks 366 (1) ………………………… 65.63%
East Breaks 410 (1) ………………………… 65.63%

Republic Exploration LLC
Ship Shoal 14 ……………………………… 50.00%
East Cameron 210……………………………100.00%
South Timbalier 97………………………… 100.00%

(1) Previously owned by COE
(2) Farm out. COI retains a 1.75% ORRI
(3) Dry Hole
(4) Farm out. COI retains a 2.41% ORRI

Onshore Exploration and Properties

Conterra Company

Effective October 1, 2009, the Company’s wholly-owned subsidiary, Conterra Company
(“Conterra”), entered into a joint venture with Patara Oil & Gas LLC (“Patara”), a privately held oil and gas
company, to develop proved undeveloped Cotton Valley gas reserves in Panola County, Texas. B.A. Berilgen,
a member of the Company’s board of directors, is the Chief Executive Officer of Patara.

Under the terms of the joint venture agreement (the “Joint Venture Agreement”), Conterra will fund

100% of the drilling and completion costs in exchange for 90% of the net revenues. The Joint Venture
Agreement contemplates drilling up to 15 wells, at an estimated 8/8ths cost of approximately $1.65 million per
well. The average 8/8ths reserves per well are approximately 1.5 Bcfe (1.125 net Bcfe after a 25% royalty). In
July 2010, both Conterra and Patara agreed to enter into a second joint venture agreement to drill up to an
additional 15 wells, bringing the total expected number of wells to 30.

By paying all of the drilling and completion costs, the Company will be able to benefit from the

associated tax deductions which are estimated to be about 75% of total drilling costs, or approximately $1.2
million per well. Upon the Company achieving a 15% per annum cash-on-cash rate of return on the basket of
15 wells, the Company’s net revenue interest converts into a 5% overriding royalty interest.

As of August 31, 2010, we were producing at a rate of approximately 5.6 Mmcfed, net to Contango,

from 12 wells. Three additional wells have been logged and are waiting to be fracture stimulated while another
one well is drilling ahead. As of August 31, 2010 we have invested approximately $25.8 million in this
drilling program.

South Texas

In July 2010, the Company announced a discovery at its on-shore wildcat exploration well (Rexer #1)
in south Texas. The Company has a 100% working interest (72.5% net revenue interest) in this well before
payout, and a 75% working interest (54.4% net revenue interest) after payout. Production is expected to begin
by the end of October 2010. As of June 30, 2010, the Company had invested approximately $4.2 million to
drill, complete and prepare to bring this well to production.

Contango Mining Company

During the fiscal year ended June 30, 2010, the Company created a new wholly-owned subsidiary,
Contango Mining Company (“Contango Mining”), to initially invest up to $3.0 million to conduct mineral
exploration activities on approximately 647,000 acres of Alaska Native and State of Alaska lands located in
interior Alaska (“Mineral Exploration Lands”). Contango Mining purchased a 50% ownership from a private
company for $1.0 million, together with our commitment to invest the next $2.0 million of capital expenditures
to fund the expenses associated with the initial mineral exploration phase on this acreage. Contango Mining
and its partner will share expenses on a 50/50 basis thereafter and each will own a 50% working interest
burdened by varying amounts of a production royalty and a 1% overriding royalty interest. To date, Contango
Mining has invested a total of $2.6 million.

Contango Mining has also assembled with the private company approximately 100,000 acres of State
of Alaska and Federal unpatented mining claims for the purpose of conducting exploration work for rare earth
minerals. Our decision to acquire the mining claims is based, in part, on the results of several surveys
performed by the United States Geological Survey in the 1970’s and 1980’s.

The Company anticipates reorganizing Contango Mining in order to pursue additional exploration

activities in the state of Alaska.

Contango Venture Capital Corporation

During the fiscal year ended June 30, 2008, Contango Venture Capital Corporation (“CVCC”), our

wholly-owned subsidiary, sold its direct and indirect investments in several alternative energy investments for
approximately $3.4 million, recognizing a loss of approximately $2.9 million. CVCC’s only remaining
investment is Moblize, Inc. (“Moblize”). As of August 31, 2010, CVCC owned 443,648 shares of Moblize
convertible preferred stock, which represents an approximate 19.5% ownership interest. Moblize develops real
time diagnostics and field optimization solutions for the oil and gas and other industries using open-standards
based technologies.

Property Sales and Discontinued Operations

Freeport LNG Development, L.P.

sale. Freeport LNG is a limited partnership formed to develop, construct and operate a 1.75 billion cubic feet
per day (“Bcfd”) liquefied natural gas (“LNG”) receiving and gasification terminal on Quintana Island, near
Freeport, Texas.

Arkansas Fayetteville Shale

During the fiscal year ended June 30, 2008, the Company sold its Arkansas Fayetteville Shale
properties to Petrohawk Energy Corporation and XTO Energy, Inc. for a total of approximately $327.2 million.
The Company sold approximately 25,400 acres with 9.4 Mmcfd of production, net to Contango. The
Company recognized a gain of approximately $262.3 million as a result of this sale.

Texas and Louisiana

During the fiscal year ended June 30, 2008, the Company sold its interest in two onshore wells to Alta

Resources LLC. The Alta-Ellis#1 in Texas and the Temple-Inland in Louisiana were sold for approximately
$1.1 million.

Marketing and Pricing

The Company currently derives its revenue principally from the sale of natural gas and oil. As a

result, the Company’s revenues are determined, to a large degree, by prevailing natural gas and oil prices. The
Company currently sells its natural gas and oil on the open market at prevailing market prices. Major
purchasers of our natural gas, oil and natural gas liquids for the fiscal year ended June 30, 2010 were
ConocoPhillips Company (37%), Shell Trading US Company (24%), Atmos Energy Marketing, LLC (16%)
and Enterprise Products Operating LLC (13%). Market prices are dictated by supply and demand, and the
Company cannot predict or control the price it receives for its natural gas and oil. The Company has
outsourced the marketing of its offshore natural gas and oil production volume to a privately-held third party
marketing firm. The Company has a policy not to hedge its natural gas and oil production.

Price decreases would adversely affect our revenues, profits and the value of our proved reserves.
Historically, the prices received for natural gas and oil have fluctuated widely. Among the factors that can
cause these fluctuations are:

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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
Domestic and foreign governmental regulations
Special taxes on production
The loss of tax credits and deductions

Competition

The Company competes with numerous other companies in all facets of its business. Our competitors

in the exploration, development, acquisition and production business include major integrated oil and gas
companies as well as numerous independents, including many that have significantly greater financial
resources and in-house technical expertise.

Governmental Regulations

Federal Income Tax. Federal income tax laws significantly affect the Company’s operations. The

principal provisions affecting the Company are those that permit the Company, subject to certain limitations, to
deduct as incurred, rather than to capitalize and amortize, its domestic “intangible drilling and development

costs” and to claim depletion on a portion of its domestic natural gas and oil properties based on 15% of its
natural gas and oil gross income from such properties (up to an aggregate of 1,000 barrels per day of domestic
crude oil and/or equivalent units of domestic natural gas).

Environmental Matters. Domestic natural gas and oil operations are subject to extensive federal

regulation and, with respect to federal leases, to interruption or termination by governmental authorities on
account of environmental and other considerations such as the Comprehensive Environmental Response,
Compensation and Liability Act (“CERCLA”) also known as the “Super Fund Law”. The trend towards
stricter standards in environmental legislation and regulation could increase costs to the Company and others in
the industry. Natural gas and oil lessees are subject to liability for the costs of clean-up of pollution resulting
from a lessee’s operations, and may also be subject to liability for pollution damages. The Company maintains
insurance against costs of clean-up operations, but is not fully insured against all such risks. A serious incident
of pollution may also result in the Department of the Interior requiring lessees under federal leases to suspend
or cease operation in the affected area.

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 assigns liability to each responsible party for oil removal costs and a variety of
public and private damages. 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 proof of financial responsibility to
cover at least some costs in a potential spill. The Company believes that it currently has established adequate
proof of financial responsibility for its offshore facilities. However, the Company cannot predict whether these
financial responsibility requirements under any OPA amendments will result in the imposition of substantial
additional annual costs to the Company in the future or otherwise materially adversely affect the Company.
The impact, however, should not be any more adverse to the Company than it will be to other similarly situated
or less capitalized owners or operators in the Gulf of Mexico.

The Company’s operations are subject to numerous federal, state and local laws and regulations

controlling the discharge of materials into the environment or otherwise relating to the protection of the
environment. Such laws and regulations, among other things, impose absolute liability on the lessee for the
cost of clean-up of pollution resulting from a lessee’s operations, subject the lessee to liability for pollution
damages, may require suspension or cessation of operations in affected areas, and impose restrictions on the
injection of liquids into subsurface aquifers that may contaminate groundwater. Such laws could have a
significant impact on the operating costs of the Company, as well as the natural gas and oil industry in general.
Federal, state and local initiatives to further regulate the disposal of natural gas and oil wastes are also pending
in certain jurisdictions, and these initiatives could have a similar impact on the Company. The Company’s
operations are also subject to additional federal, state and local laws and regulations relating to protection of
human health, natural resources, and the environment pursuant to which the Company may incur compliance
costs or other liabilities.

Impact of Deepwater Horizon Incident. In April 2010, the deepwater Gulf of Mexico drilling rig
Deepwater Horizon sank after an apparent blowout and fire. The accident resulted in the loss of life and a
significant oil spill. In response to the Incident, the President of the United States has announced a six-month
moratorium on drilling in the deepwater Gulf of Mexico and imposed new restrictions on permitting activities
on the Outer Continental Shelf. Although the root cause, or causes, of the Deepwater Horizon Incident are
unclear at this time, we believe there is a high likelihood of regulatory and/or legislative changes that will
impact operations in the Gulf of Mexico. Various Congressional committees have already begun pursuing
legislation to change existing governmental regulations. We will continue to monitor the expected regulatory
and legislative response and its impact on our operations.

Other Laws and Regulations. Various laws and regulations often require permits for drilling wells

and also cover spacing of wells, the prevention of waste of natural gas and oil including maintenance of certain

gas/oil ratios, rates of production and other matters. The effect of these laws and regulations, as well as other
regulations that could be promulgated by the jurisdictions in which the Company has production, could be to
limit the number of wells that could be drilled on the Company’s properties and to limit the allowable
production from the successful wells completed on the Company’s properties, thereby limiting the Company’s
revenues.

The BOEMRE administers the natural gas and oil leases held by the Company on federal onshore

lands and offshore tracts in the Outer Continental Shelf. The BOEMRE holds a royalty interest in these federal
leases on behalf of the federal government. While the royalty interest percentage is fixed at the time that the
lease is entered into, from time to time the BOEMRE changes or reinterprets the applicable regulations
governing its royalty interests, and such action can indirectly affect the actual royalty obligation that the
Company is required to pay. However, the Company believes that the regulations generally do not impact the
Company to any greater extent than other similarly situated producers. At the end of lease operations, oil and
gas lessees must plug and abandon wells, remove platforms and other facilities, and clear the lease site sea
floor. The BOEMRE requires companies operating on the Outer Continental Shelf to obtain surety bonds to
ensure performance of these obligations. As an operator, the Company is required to obtain surety bonds of
$200,000 per lease for exploration and $500,000 per lease for developmental activities.

The Federal Energy Regulatory Commission (the “FERC”) has embarked on wide-ranging regulatory

initiatives relating to natural gas transportation rates and services, including the availability of market-based
and other alternative rate mechanisms to pipelines for transmission and storage services. In addition, the
FERC has announced and implemented a policy allowing pipelines and transportation customers to negotiate
rates above the otherwise applicable maximum lawful cost-based rates on the condition that the pipelines
alternatively offer so-called recourse rates equal to the maximum lawful cost-based rates. With respect to
gathering services, the FERC has issued orders declaring that certain facilities owned by interstate pipelines
primarily perform a gathering function, and may be transferred to affiliated and non-affiliated entities that are
not subject to the FERC’s rate jurisdiction. The Company cannot predict the ultimate outcome of these
developments, or the effect of these developments on transportation rates. Inasmuch as the rates for these
pipeline services can affect the natural gas prices received by the Company for the sale of its production, the
FERC’s actions may have an impact on the Company. However, the impact should not be substantially
different for the Company than it would be for other similarly situated natural gas producers and sellers.

Risk and Insurance Program

In accordance with industry practices, 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 an economically
appropriate level of financial protection from significant unfavorable losses resulting from damages to, or the
loss of, physical assets or loss of human life and liability claims of third parties. We maintain insurance at
levels that we believe are appropriate and consistent with industry practice.

We expect the future availability and cost of insurance to be impacted by the recent Deepwater

Horizon incident. Impacts could include: tighter underwriting standards, limitations on scope and amount of
coverage, and higher premiums, and will depend, in part, on future changes in laws and regulations regarding
exploration and production activities in the Gulf of Mexico, including possible increases in liability caps for
claims of damages from oil spills.

Recently, various Congressional committees have begun pursuing legislation to increase or remove
liability caps for Gulf of Mexico drilling. The current $75 million liability limit under the Oil Pollution Act is
likely to be materially increased or lifted in its entirety. Such a requirement could ultimately require a
company to maintain either an insurance coverage minimum larger than Contango is able or willing to meet, or
a financial size and equity position significantly larger than Contango is able to meet. The insurance market
may be unable to provide coverage enhancements to address any significant increases in liability caps going
forward. In all likely legislative outcomes, we anticipate that insurance coverage will be at a higher cost.

Gulf of Mexico drilling entails significant inherent risks and increasingly, political risk as well. If an

event occurs that is not covered by insurance or not fully protected by insured limits, it would likely have a
material adverse impact on our financial condition, results of operations and cash flows.

Employees

We have eight employees, all of whom are full time. Effective March 1, 2010, the Company

outsourced its human resources function to Administaff Companies II, LP (“Administaff”) and all of the
Company’s employees became co-employees of Administaff. In addition to our employees, we use the
services of independent consultants and contractors to perform various professional services, including
reservoir engineering, land, legal, environmental and tax services. We are dependent on JEX for prospect
generation, evaluation and prospect leasing. As a working interest owner, we rely on outside operators to drill,
produce and market our natural gas and oil for our onshore prospects and certain offshore prospects where we
are a non-operator. In the offshore prospects where we are the operator, we rely on a turn-key contractor to
drill and rely on independent contractors to produce and market our natural gas and oil. In addition, we utilize
the services of independent contractors to perform field and on-site drilling and production operation services
and independent third party engineering firms to calculate our reserves.

Directors and Executive Officers

The following table sets forth the names, ages and positions of our directors and executive officers:

Name

Age

Position

Chairman, Chief Executive Officer and Director
65
Kenneth R. Peak ........................................
President and Chief Operating Officer
57
Marc Duncan…………………………….
Chief Financial Officer
41
Sergio Castro .............................................
Vice President and Controller
41
Slava Makalskaya………………………..
Vice President of Operations
43
Charles A. Cambron……………………..
Director
B.A. Berilgen……………………………. 62
Jay D. Brehmer .........................................
Director
45
Charles M. Reimer………………………. 65 Director
Director
Steven L. Schoonover ...............................

Kenneth R. Peak. Mr. Peak is the founder of the Company and has been Chairman and Chief

Executive Officer since its formation in September 1999. Mr. Peak entered the energy industry in 1973 as a
commercial banker and held a variety of financial and executive positions in the oil and gas industry prior to
starting Contango in 1999. Mr. Peak served as an officer in the U.S. Navy from 1968 to 1971. Mr. Peak
received a BS in physics from Ohio University in 1967, and an MBA from Columbia University in 1972. He
currently serves as a director of Patterson-UTI Energy, Inc., a provider of onshore contract drilling services to
exploration and production companies in North America.

Marc Duncan. Mr. Duncan joined Contango in June 2005 as President and Chief Operating Officer of
Contango Operators, Inc. and was appointed President and Chief Operating Officer of Contango Oil & Gas
Company in October 2006. Mr. Duncan has over 26 years of experience in the energy industry and has held a
variety of domestic and international engineering and senior-level operations management positions relating to
natural gas and oil exploration, project development, and drilling and production operations. Prior to joining
Contango, Mr. Duncan served as Chief Operating Officer of USENCO International, Inc. and its subsidiaries
and affiliates in China and Ukraine from February 2000 to July 2004 and as a senior project and drilling
engineer for Hunt Oil Company from July 2004 to June 2005. He holds an MBA in Engineering Management
from the University of Dallas, an MEd from the University of North Texas and a BS in Science and Education
from Stephen F. Austin University.

Sergio Castro. Mr. Castro joined Contango in March 2006 as Treasurer and was appointed Vice
President and Treasurer in April 2006 and Chief Financial Officer in June 2010. Prior to joining Contango,
Mr. Castro spent two years (April 2004 to March 2006) as a consultant for UHY Advisors TX, LP. From
January 2001 to April 2004, Mr. Castro was a lead credit analyst for Dynegy Inc. From August 1997 to
January 2001, Mr. Castro worked as an auditor for Arthur Andersen LLP, where he specialized in energy
companies. Mr. Castro was honorably discharged from the U.S. Navy in 1993 as an E-6, where he served
onboard a nuclear powered submarine. Mr. Castro received a BBA in Accounting in 1997 from the University
of Houston, graduating summa cum laude. Mr. Castro is a CPA and a Certified Fraud Examiner.

Yaroslava Makalskaya. Ms. Makalskaya joined Contango in March 2010 and was appointed Vice

President and Controller in June 2010. Prior to joining Contango, Ms. Makalskaya was a director of the
Transaction Services practice at PricewaterhouseCoopers, where she assisted clients with M&A transactions as
well as advised clients with complex accounting and financial reporting issues. Ms.Makalskaya holds a MS
degree in economics from Novosibirsk State University in Russia. Ms. Makalskaya is a CPA and has
approximately 18 years of work experience in accounting and finance, including 13 years in public
accounting. During her work in the audit practice of PricewaterhouseCoopers and Arthur Andersen, her clients
included many US and international companies in energy, utilities and mining and other sectors.

Charles A. Cambron. Mr. Cambron joined Contango in August 2010 as Vice President of Operations.

Mr. Cambron has 19 years of experience in the Gulf of Mexico oil and gas industry. Most recently he was
employed by Applied Drilling Technology, Inc. (ADTI) as an Operations Manager from August 1995 until
August 2010. He also held various positions in engineering and offshore supervision over a 15 year period.
Prior to ADTI, Mr. Cambron began his career with Rowan Petroleum, Inc. as a Drilling Engineer working in
both the Gulf of Mexico and North Sea. Mr. Cambron received a B.S. degree in Petroleum Engineering from
the University of Oklahoma in 1991.

B.A. Berilgen. Mr. Berilgen was appointed a director of Contango in July 2007. Mr. Berilgen has
served in a variety of senior positions during his 39 year career. Most recently, he became Chief Executive
Officer of Patara Oil & Gas LLC in April 2008. Prior to that he was Chairman, Chief Executive Officer and
President of Rosetta Resources Inc., a company he founded in June 2005, until his resignation in July 2007,
and then he was an independent consultant from July 2007 through April 2008. Mr. Berilgen was also
previously the Executive Vice President of Calpine Corp. and President of Calpine Natural Gas L.P. from
October 1999 through June 2005. In June 1997, Mr. Berilgen joined Sheridan Energy, a public oil and gas
company, as its President and Chief Executive Officer. Mr. Berilgen attended the University of Oklahoma,
receiving a B.S. in Petroleum Engineering in 1970 and a M.S. in Industrial Engineering / Management Science.

Jay D. Brehmer. Mr. Brehmer has been a director of Contango since October 2000. Mr. Brehmer is a

co-founding partner of Southplace, LLC, a provider of private-company middle-market corporate finance
advisory services. Mr. Brehmer founded Southplace, LLC in November 2002. In August 2004, Mr. Brehmer
became Managing Director of Houston Capital Advisors LP, a boutique financial advisory, merger and
acquisition investment bank, while still retaining his membership in Southplace, LLC. Mr. Brehmer resigned
from Houston Capital Advisors LP in January 2008 and is currently associated with Southplace, LLC in a full-
time capacity. From May 1998 until November 2002, Mr. Brehmer was responsible for structured-finance
energy related transactions at Aquila Energy Capital Corporation. Prior to joining Aquila, Mr. Brehmer
founded Capital Financial Services, which provided mid-cap companies with strategic merger and acquisition
advice coupled with prudent financial capitalization structures. Mr. Brehmer holds a BBA from Drake
University in Des Moines, Iowa.

Charles M. Reimer. Mr. Reimer was elected a director of Contango in November 2005. Mr. Reimer
is President of Freeport LNG Development, L.P., and has experience in exploration, production, liquefied
natural gas (“LNG”) and business development ventures, both domestically and abroad. From 1986 until 1998,
Mr. Reimer served as the senior executive responsible for the VICO joint venture that operated in Indonesia,
and provided LNG technical support to P. T. Badak. Additionally, during these years he served, along with
Pertamina executives, on the board of directors of the P.T. Badak LNG plant in Bontang, Indonesia. Mr.
Reimer began his career with Exxon Company USA in 1967 and held various professional and management
positions in Texas and Louisiana. Mr. Reimer was named President of Phoenix Resources Company in 1985

and relocated to Cairo, Egypt, to begin eight years of international assignments in both Egypt and Indonesia.
Prior to joining Freeport LNG Development, L.P. in December 2002, Mr. Reimer was President and Chief
Executive Officer of Cheniere Energy, Inc.

Steven L. Schoonover. Mr. Schoonover was elected a director of Contango in November 2005. Mr.

Schoonover was most recently Chief Executive Officer of Cellxion, L.L.C., a company he founded in
September 1996 and sold in September 2007, which specialized in construction and installation of
telecommunication buildings and towers, as well as the installation of high-tech telecommunication equipment.
Since the sale in September 2007, Mr. Schoonover continues to serve as a consultant to the current
management team of Cellxion, L.L.C. From 1990 until its sale in November 1997 to Telephone Data Systems,
Inc., Mr. Schoonover served as President of Blue Ridge Cellular, Inc., a full-service cellular telephone
company he co-founded. From 1983 to 1996, he served in various positions, including President and Chief
Executive Officer, with Fibrebond Corporation, a construction firm involved in cellular telecommunications
buildings, site development and tower construction. Mr. Schoonover has been awarded, on two occasions with
two different companies, Entrepreneur of the Year, sponsored by Ernst & Young, Inc Magazine and USA
Today.

Directors of Contango serve as members of the board of directors until the next annual stockholders

meeting, until successors are elected and qualified or until their earlier resignation or removal. Officers of
Contango are elected by the board of directors and hold office until their successors are chosen and qualified,
until their death or until they resign or have been removed from office. All corporate officers serve at the
discretion of the board of directors. In fiscal year 2010, each outside director of the Company received a
quarterly retainer of $20,000 payable in cash, with no stock option or common stock grants. There were no
additional payments for meetings attended or being chairman of a committee. There are no family
relationships between any of our directors or executive officers.

In fiscal year 2009 and 2008, each outside director of the Company received a quarterly retainer of

$8,000 payable in cash and $36,000 payable annually in Company common stock. Each outside director also
received a $1,000 cash payment for each board meeting and separately scheduled Audit Committee meeting
attended. The Chairman of the Audit Committee received an additional quarterly cash payment of $3,000.

Corporate Offices

We lease our corporate offices at 3700 Buffalo Speedway, Suite 960, Houston, Texas 77098. Our

existing 60 month lease agreement expires on October 31, 2011.

Code of Ethics

We adopted a Code of Ethics for senior management in December 2002. A copy of our Code of

Ethics is filed as an exhibit to this Form 10-K and is also available on our Website at www.contango.com.

Available Information

General information about us can be found on our Website at www.contango.com. Our annual
reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any
amendments and exhibits to those reports, are available free of charge through our Website as soon as
reasonably practicable after we file or furnish them to the Securities and Exchange Commission (“SEC”).

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.

We have no ability to control the prices that we receive for natural gas and oil. Natural gas and oil prices
fluctuate widely, and a substantial or extended decline in natural gas and oil prices would adversely affect
our revenues, profitability and growth and could have a material adverse effect on the business, the results
of operations and financial condition of the Company.

Our revenues, profitability and future growth depend significantly on natural gas and crude oil prices.

Prices received affect the amount of future cash flow available for capital expenditures and repayment of
indebtedness and our ability to raise additional capital. We do not expect to hedge our production to protect
against price decreases. Lower prices may also affect the amount of natural gas and oil that we can
economically produce. Factors that can cause price fluctuations include:

The domestic and foreign supply of natural gas and oil.

•
• Overall economic conditions.

• The level of consumer product demand.

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.

• Adverse weather conditions and natural disasters.
•
•
•
• Domestic and foreign governmental regulations.
•
• Access to pipelines and gas processing plants.
• The loss of tax credits and deductions.

Special taxes on production.

A substantial or extended decline in natural gas and oil prices could have a material adverse effect on

our access to capital and the quantities of natural gas and oil that may be economically produced by us. A
significant decrease in price levels for an extended period would negatively affect us.

We depend on the services of our Chairman and Chief Executive Officer, and implementation of our
business plan could be seriously harmed if we lost his services.

We depend heavily on the services of Kenneth R. Peak, our chairman and chief executive officer. We
do not have an employment agreement with Mr. Peak, and the proceeds from a $10.0 million “key person” life
insurance policy on Mr. Peak may not be adequate to cover our losses in the event of Mr. Peak’s death.

We are highly dependent on the technical services provided by JEX and could be seriously harmed if JEX
terminated its services with us or became otherwise unavailable.

Because we employ no geoscientists or petroleum engineers, we are dependent upon JEX for the

success of our natural gas and oil exploration projects and expect to remain so for the foreseeable future. We
do not have a written agreement with JEX which contractually obligates JEX to provide us with its services in
the future. Highly qualified explorationists and engineers are difficult to attract and retain. As a result, the loss
of the services of JEX could have a material adverse effect on us and could prevent us from pursuing our
business plan. Additionally, the loss by JEX of certain explorationists could have a material adverse effect on
our operations as well.

Our ability to successfully execute our business plan is dependent on our ability to obtain adequate
financing.

Our business plan, which includes participation in 3-D seismic shoots, lease acquisitions, the drilling

of exploration prospects and producing property acquisitions, has required and is expected to continue to

require substantial capital expenditures. We may require additional financing to fund our planned growth. Our
ability to raise additional capital will depend on the results of our operations and the status of various capital
and industry markets at the time we seek such capital. Accordingly, additional financing may not be available
to us on acceptable terms, if at all. In the event additional capital resources are unavailable, we may be
required to curtail our exploration and development activities or be forced to sell some of our assets in an
untimely fashion or on less than favorable terms.

It is difficult to quantify the amount of financing we may need to fund our planned growth. The

amount of funding we may need in the future depends on various factors such as:

• Our financial condition.
• The prevailing market price of natural gas and oil.
• The type of projects in which we are engaging.
• The lead time required to bring any discoveries to production.

We frequently obtain capital through the sale of our producing properties.

The Company, since its inception in September 1999, has raised approximately $484 million from

various property sales. These sales bring forward future revenues and cash flows, but our longer term liquidity
could be impaired to the extent our exploration efforts are not successful in generating new discoveries,
production, revenues and cash flows. Additionally, our longer term liquidity could be impaired due to the
decrease in our inventory of producing properties that could be sold in future periods. Further, as a result of
these property sales the Company’s ability to collateralize bank borrowings is reduced which increases our
dependence on more expensive mezzanine debt and potential equity sales. The availability of such funds will
depend upon prevailing market conditions and other factors over which we have no control, as well as our
financial condition and results of operations.

We assume additional risk as Operator in drilling high pressure and high temperature wells in the Gulf of
Mexico.

COI, a wholly-owned subsidiary of the Company, was formed for the purpose of drilling and
operating exploration wells in the Gulf of Mexico. Drilling activities are subject to numerous risks, including
the significant risk that no commercially productive hydrocarbon reserves will be encountered. The cost of
drilling, completing and operating wells and of installing production facilities and pipelines is often uncertain.
Drilling costs could be significantly higher if we encounter difficulty in drilling offshore exploration wells.
The Company’s drilling operations may be curtailed, delayed, canceled or negatively impacted as a result of
numerous factors, including title problems, weather conditions, compliance with governmental requirements
and shortages or delays in the delivery or availability of material, equipment and fabrication yards. In periods
of increased drilling activity resulting from high commodity prices, demand exceeds availability for drilling
rigs, drilling vessels, supply boats and personnel experienced in the oil and gas industry in general, and the
offshore oil and gas industry in particular. This may lead to difficulty and delays in consistently obtaining
certain services and equipment from vendors, obtaining drilling rigs and other equipment at favorable rates and
scheduling equipment fabrication at factories and fabrication yards. This, in turn, may lead to projects being
delayed or experiencing increased costs. The cost of drilling, completing, and operating wells is often
uncertain, and new wells may not be productive or we may not recover all or any of our investment. The risk of
significant cost overruns, curtailments, delays, inability to reach our target reservoir and other factors
detrimental to drilling and completion operations may be higher due to our inexperience as an operator.

Additionally, we use turnkey contracts that may cost more than drilling contracts at daily rates. Under

certain conditions, the turnkey contract can be terminated by the turnkey drilling contractor, which could lead
to materially higher risks and costs for the Company.

We rely on third-party operators to operate and maintain some of our production 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 production platforms, pipelines, gas
processing facilities and the infrastructure required to produce and market our natural gas, condensate and oil.
We have limited influence over the conduct of operations by third-party operators. As a result, we have little
control over how frequently and how long our production is shut-in when production problems, weather and
other production shut-ins occur. Poor performance on the part of, or errors or accidents attributable to, the
operator of a project in which we participate may have an adverse effect on our results of operations and
financial condition. Also, the interest of an operator may differ from our interests.

Repeated production shut-ins can possibly damage our well bores.

Our 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 at our Eugene Island 11 platform, 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.

Concentrating our capital investment in the Gulf of Mexico increases our exposure to risk.

Our capital investments are focused in offshore Gulf of Mexico prospects. However, our exploration
prospects in the Gulf of Mexico may not lead to significant revenues. Furthermore, we may not be able to drill
productive wells at profitable finding and development costs.

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.

In June 2010, the Company revised its offshore reserves downward by approximately 48.5 Bcfe.

This revision was attributable to newly learned bottom hole pressure data as a result of a recent field wide shut-
in and a “P/Z pressure test” that indicated fewer reserves than originally estimated.

The Company’s reserves and revenues are concentrated in one field.

The proved reserves assigned to our Dutch and Mary Rose discoveries have ten producing well bores
concentrated in two reservoirs on one field, and are producing via two pipelines and two production platforms.
Reserve assessments based on only ten well bores in two reservoirs with relatively limited production history
are subject to significantly greater risk of downward revision than multiple well bores from a variety of mature
producing reservoirs.

We rely on the accuracy of the estimates in the reservoir engineering reports provided to us by our outside
engineers.

We have no in house reservoir engineering capability, and therefore rely on the accuracy of the

periodic reservoir reports provided to us by our independent third-party reservoir engineers. If those reports
prove to be inaccurate, our financial reports could have material misstatements. Further, we use the reports of
our independent reservoir engineers in our financial planning. If the reports of the outside reservoir engineers
prove to be inaccurate, we may make misjudgments in our financial planning.

Exploration is a high risk activity, and our participation in drilling activities may not be successful.

Our future success largely depends on the success of our exploration drilling program. Participation in

exploration drilling activities involves numerous risks, including the significant risk that no commercially
productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing and operating wells
is uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors,
including:

Pressure, temperature or other irregularities in formations.
Equipment failures and/or accidents caused by human error.
Tropical storms, hurricanes and other adverse weather conditions.

• Unexpected drilling conditions.
• Blowouts, fires or explosions with resultant injury, death or environmental damage.
•
•
•
• Compliance with governmental requirements and laws, present and future.
•
• Our turnkey drilling contracts reverting to a day rate contract or our turnkey contractor

Shortages or delays in the availability of drilling rigs and the delivery of equipment.

electing to terminate the turnkey contract would significantly increase the cost and risk to the
Company.
Problems at third-party operated platforms, pipelines and gas processing facilities over
which we have no control.

•

Even when properly used and interpreted, 3-D seismic data and visualization techniques are only tools

used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow

the interpreter to know conclusively if hydrocarbons are present or economically producible. Poor results from
our drilling activities would materially and adversely affect our future cash flows and results of operations.

In addition, as a “successful efforts” company, we choose to account for unsuccessful exploration
efforts (the drilling of “dry holes”) and seismic costs as a current expense of operations, which immediately
impacts our earnings. Significant expensed exploration charges in any period would materially adversely affect
our earnings for that period and cause our earnings to be volatile from period to period.

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. Most of the Company’s operations are on the Gulf of Mexico shelf in water depths less than 200
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.

The natural gas and oil business involves many operating risks that can cause substantial losses.

The natural gas and oil business involves a variety of operating risks, including:

Surface cratering.

Pipe and cement failures.

• Blowouts, fires and explosions.
•
• Uncontrollable flows of underground natural gas, oil or formation water.
• Natural disasters.
•
• Casing collapses.
•
• Reservoir compaction.
• Abnormal pressure formations.
•

Stuck drilling and service tools.

Environmental hazards such as natural gas leaks, oil spills, pipeline ruptures or discharges of
toxic gases.

• Capacity constraints, equipment malfunctions and other problems at third-party operated

platforms, pipelines and gas processing plants over which we have no control.
• Repeated shut-ins of our well bores could significantly damage our well bores.
• Required workovers of existing wells that may not be successful.

If any of the above events occur, we could incur substantial losses as a result of:

Severe damage to and destruction of property or equipment.
Pollution and other environmental damage.

Injury or loss of life.

•
• Reservoir damage.
•
•
• Clean-up responsibilities.
• Regulatory investigations and penalties.
•

Suspension of our operations or repairs necessary to resume operations.

Offshore operations are subject to a variety of operating risks peculiar to the marine environment,

such as capsizing and collisions. In addition, offshore operations, and in some instances, operations along the
Gulf Coast, are subject to damage or loss from hurricanes or other adverse weather conditions. These
conditions can cause substantial damage to facilities and interrupt production. 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.

Not hedging our production may result in losses.

Due to the significant volatility in natural gas prices and the potential risk of significant hedging

losses if our production should be shut-in during a period when NYMEX natural gas prices increase, our policy
is to hedge only through the purchase of puts. By not hedging our production, we may be more adversely
affected by declines in natural gas and oil prices than our competitors who engage in hedging arrangements.

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, processing plants,
and offshore platforms. 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.

We may not have title to our leased interests and if any lease is later rendered invalid, we may not be able to
proceed with our exploration and development of the lease site.

Our practice in acquiring exploration leases or undivided interests in natural gas and oil leases is to

not incur the expense of retaining title lawyers to examine the title to the mineral interest prior to executing the
lease. Instead, we rely upon the judgment of JEX and others to perform the field work in examining records in
the appropriate governmental, county or parish clerk’s office before leasing a specific mineral interest. This
practice is widely followed in the industry. Prior to the drilling of an exploration well the operator of the well
will typically obtain a preliminary title review of the drillsite lease and/or spacing unit within which the
proposed well is to be drilled to identify any obvious deficiencies in title to the well and, if there are
deficiencies, to identify measures necessary to cure those defects to the extent reasonably possible. However,
such deficiencies may not have been cured by the operator of such wells. It does happen, from time to time,
that the examination made by title lawyers reveals that the lease or leases are invalid, having been purchased in
error from a person who is not the rightful owner of the mineral interest desired. In these circumstances, we
may not be able to proceed with our exploration and development of the lease site or may incur costs to
remedy a defect. It may also happen, from time to time, that the operator may elect to proceed with a well
despite defects to the title identified in the preliminary title opinion.

Competition in the natural gas and oil industry is intense, and we are smaller and have a more limited
operating history than many of our competitors.

We compete with a broad range of natural gas and oil companies in our exploration and property

acquisition activities. We also compete for the equipment and labor required to operate and to develop these
properties. Many of our competitors have substantially greater financial resources than we do. These
competitors may be able to pay more for exploratory prospects and productive natural gas and oil properties.
Further, they may be able to evaluate, bid for and purchase a greater number of properties and prospects than
we can. Our ability to explore for natural gas and oil and to acquire additional properties in the future depends
on our ability to evaluate and select suitable properties and to consummate transactions in this highly
competitive environment. In addition, many of our competitors have been operating for a much longer time
than we have and have substantially larger staffs. We may not be able to compete effectively with these
companies or in such a highly competitive environment.

We are subject to complex laws and regulations, including environmental regulations that can adversely
affect the cost, manner or feasibility of doing business.

Our operations are subject to numerous laws and regulations governing the operation and maintenance

of our facilities and the discharge of materials into the environment. Failure to comply with such rules and
regulations could result in substantial penalties and have an adverse effect on us. These laws and regulations:

• Require that we obtain permits before commencing drilling.
• 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.

Under these laws and regulations, we could be liable for personal injury and clean-up costs and other
environmental and property damages, as well as administrative, civil and criminal penalties. We maintain only
limited insurance coverage for sudden and accidental environmental damages. Accordingly, we may be subject
to liability, or we may be required to cease production from properties in the event of environmental damages.
These laws and regulations have been changed frequently in the past. In general, these changes have imposed
more stringent requirements that increase operating costs or require capital expenditures in order to remain in
compliance. It is also possible that unanticipated developments could cause us to make environmental
expenditures that are significantly different from those we currently expect. Existing laws and regulations
could be changed and any such changes could have an adverse effect on our business and results of operations.

Our operations in the Gulf of Mexico could be adversely affected by changes in laws and regulations which
are expected to occur as a result of the Deepwater Horizon Incident.

In April 2010, the deepwater Gulf of Mexico drilling rig Deepwater Horizon was engaged in drilling
operations for another operator and sank after an apparent blowout and fire. The accident resulted in the loss
of life and a significant oil spill. On May 27, 2010, in response to the incident, the President of the United
States announced a six-month moratorium on drilling in the deepwater Gulf of Mexico and imposed new
restrictions on permitting activities on the Outer Continental Shelf. On July 12, 2010, the Secretary of the
Interior revised the moratorium that is scheduled to end November 30, 2010. In conjunction with the
moratorium, the Department of the Interior issued a directive calling for additional safety and performance
standards as well as rigorous monitoring and testing requirements. More recently, various Congressional
committees have begun pursuing legislation to regulate drilling activities and increase liability for oil spills.

We are monitoring legislative and regulatory developments; however, the full legislative

and regulatory response to the incident is not yet known. An expansion of safety and performance regulations
or an increase in liability for drilling activities may have one or more of the following impacts on our business:

Increase the costs of drilling exploratory and development wells.

•
• Cause delays in, or preclude, the development of projects in the Gulf of Mexico
• Result in higher operating costs.
•
• Limit our ability to obtain additional insurance coverage on commercially reasonable terms to

Increase or remove liability caps for claims of damages from oil spills.

protect against any increase in liability.

Any of the above factors may result in a reduction of our cash flows, profitability, and the fair value

of our properties.

We do not control the activities on properties we do not operate.

Other companies may from time to time drill, complete and operate properties in which we have an

interest. As a result, we have a limited ability to exercise influence over operations for these properties or their
associated costs. Our dependence on the operator and other working interest owners for these projects and our
limited ability to influence operations and associated costs could materially adversely affect the realization of

our targeted returns on capital in drilling or acquisition activities. The success and timing of our drilling and
development activities on properties operated by others therefore depend upon a number of factors that are
outside of our control, including:

Timing and amount of capital expenditures.
The operator’s expertise and financial resources.

•
•
• Approval of other participants in drilling wells.
•

Selection of technology.

We are highly dependent on our management team, JEX, exploration partners and third-party consultants
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. We are highly dependent on the
services provided by JEX and we do not have any written agreements contractually obligating them to provide
us with their services in the future. The loss of key members of our management team, JEX or other highly
qualified technical professionals could adversely affect our ability to effectively manage our overall operations
or successfully execute current or future business strategies which may have a material adverse effect on our
business, financial condition and operating results.

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 environmental authorizations required for our operations.

In connection with such an assessment, we would expect to perform a review of the subject properties

that we believe to be generally consistent with industry practices. Nonetheless, the resulting conclusions are
necessarily inexact and their accuracy inherently uncertain and such an assessment may not reveal all existing
or potential problems, nor will it necessarily permit a buyer to become sufficiently familiar with the properties
to fully assess their merits and deficiencies. Inspections may not always be performed on every platform or
well, and structural and environmental problems are not necessarily observable even when an inspection is
undertaken.

Future acquisitions could pose additional risks to our operations and financial results, including:

Problems integrating the purchased operations, personnel or technologies.

•
• Unanticipated costs.
• Diversion of resources and management attention from our exploration business.
Entry into regions or markets in which we have limited or no prior experience.
•
Potential loss of key employees of the acquired organization.
•

The risks and challenges inherent in mineral exploration are quite different from our natural gas and oil
exploration and we have no mineral expertise.

Our investment in Contango Mining does not represent a change in our natural gas and oil exploration
business model. We recognize that the risks and challenges inherent in mineral exploration are quite different
from our natural gas and oil exploration business. Our 2009 and early 2010 exploration programs found
relatively few samples of commercial grade minerals but we believe our results merit continued exploration.

At this early exploration stage our investment should be considered speculative and the probability of

ultimately being successful in finding gold or other minerals in a volume sufficient to support a commercial
mining operation are quite low. We have little or no experience in mining and mineral development and will be
highly dependent upon the advice of consultants.

Anti-takeover provisions of our certificate of incorporation, bylaws and Delaware law could adversely effect
a potential acquisition by third-parties that may ultimately be in the financial interests of our stockholders.

Our Certificate of Incorporation, Bylaws and the Delaware General Corporation Law contain

provisions that may discourage unsolicited takeover proposals. These provisions could have the effect of
inhibiting fluctuations in the market price of our common stock that could result from actual or rumored
takeover attempts, preventing changes in our management or limiting the price that investors may be willing to
pay for shares of common stock.

The Company adopted a Stockholders Rights Plan in September 2008 that is designed to ensure that
all stockholders of the Company receive fair value for their shares of common stock in a proposed takeover of
the Company and to guard against coercive takeover tactics to gain control of the Company. In addition, these
provisions, among other things, authorize the board of directors to:

• Designate the terms of and issue new series of preferred stock.
•
•
•
•

Limit the personal liability of directors.
Limit the persons who may call special meetings of stockholders.
Prohibit stockholder action by written consent.
Establish advance notice requirements for nominations for election of the board of directors
and for proposing matters to be acted on by stockholders at stockholder meetings.

• Require us to indemnify directors and officers to the fullest extent permitted by applicable

law.
Impose restrictions on business combinations with some interested parties.

•

Our common stock is thinly traded.

Contango has approximately 15.7 million shares of common stock outstanding. Directors and officers

own or have voting control over approximately 3.2 million shares. Since our common stock is not heavily
traded, the purchase or sale of relatively small common stock positions may result in disproportionately large
increases or decreases in the price of our common stock.

Item 1B. Unresolved Staff Comments

None

Item 2. Properties

Production, Prices and Operating Expenses

The following table presents information from continuing operations regarding the production

volumes, average sales prices received and average production costs associated with our sales of natural gas,
oil and natural gas liquids (“NGLs”) for the periods indicated. Oil, condensate and NGLs are compared with
natural gas in terms of cubic feet of natural gas equivalents. One barrel of oil, condensate or NGL is the
energy equivalent of six thousand cubic feet (“Mcf”) of natural gas. Reported lease operating expenses include
property and severance taxes.

Year Ended June 30,

2010

2009

2008

Production:
Natural gas (million cubic feet)…………………………..………
Oil and condensate (thousand barrels)……………………………
Natural gas liquids (thousand gallons)…………………………

Total (million cubic feet equivalent)………………….………

Natural gas (million cubic feet per day)……………………...…
Oil and condensate (thousand barrels per day)……...………….
Natural gas liquids (thousand gallons per day)……...………….

Total (million cubic feet equivalent per day)…………………

21,385
505
25,117

28,003

58.6
1.4
68.8

76.8

20,535
515
24,803

27,168

56.3
1.4
68.0

74.4

9,089
185
4,968

10,909

24.8
0.5
13.6

29.7

Average sales price:

Natural gas (per thousand cubic feet)…………..………………
Oil and condensate (per barrel)……...…………..………………
Natural gas liquids (per gallon)……...…………..………………

$
$
$

4.47
77.18
1.04

$
$
$

6.34
67.72
1.03

$
$
$

9.77
108.36
1.55

Total (per thousand cubic feet equivalent)……………………

5.74

7.02

10.68

Selected data per Mcfe:

Total lease operating expenses………………………………...…
General and administrative expenses…………………..………
Depreciation, depletion and amortization of

$
$

0.61
0.16

$
$

0.87
0.35

$
$

0.62
1.50

natural gas and oil properties………………………...………

1.25

1.17

1.01

Development, Exploration and Acquisition Expenditures

The following table presents information regarding our net costs incurred in the purchase of proved

and unproved properties and in exploration and development activities for the periods indicated:

Year Ended June 30,

2010

2009

2008

Property acquisition costs:
11,318,349
Unproved…………………………………………………
Proved………………………………………………………
2,009,330
Exploration costs……………………………………………
52,805,270
Developmental costs………………………………………… 40,901,582

$
-

1,131,582
23,284,970
22,889,629

309,000,000
45,243,651
76,025,586

Total costs………………………………………………… 107,034,531

47,306,181

430,269,237

Drilling Activity

The following table shows our drilling activity for the periods indicated. In the table, “gross” wells

refer to wells in which we have a working interest, and “net” wells refer to gross wells multiplied by our
working interest in such wells.

Year Ended June 30,

2010

2009

2008

Gross

Net

Gross

Net

Gross

Net

Exploratory Wells:

Productive (onshore)…………………
Productive (offshore)…………………
Non-productive (onshore)……………
Non-productive (offshore)……………

Total………………………………

14
2

14.0
1.3
-
2.0

17.3

-
0.8
-
2.0

2.8

34
4
19
1

2.2
2.0
3.9
1.0

9.1

For the fiscal year ended June 31, 2008, the onshore wells listed above relate to our investment in the

Arkansas Fayetteville Shale. At the time the Company sold its interest in the Arkansas Fayetteville Shale
wells, the Company had 16 wells that were being drilled. We have classified those 16 wells as non-productive.

Exploration and Development Acreage

Our principal natural gas and oil properties consist of natural gas and oil leases. The following table

indicates our interests in developed and undeveloped acreage as of June 30, 2010:

Developed

Acreage (1)(2)

Undeveloped

Acreage (1)(3)

Gross (4)

Net (5)

Gross (4)

Net (5)

Onshore Texas………………………………………………
Offshore Gulf of Mexico………...………………………..

Total……………………………………………………

10,075
16,897

26,972

9,115
8,547

17,662

535
61,272

61,807

535
46,983

47,518

(1) Excludes any interest in acreage in which we have no working interest before payout or before initial production.
(2) Developed acreage consists of acres spaced or assignable to productive wells.
(3) Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a

point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such
acreage contains proved reserves.

(4) Gross acres refer to the number of acres in which we own a working interest.
(5) Net acres represent the number of acres attributable to an owner’s proportionate working interest in a lease (e.g., a

50% working interest in a lease covering 320 acres is equivalent to 160 net acres).

Included in the Offshore Gulf of Mexico acres shown in the table above are the beneficial interests

Contango has in the offshore acreage owned by REX. The above table includes our 32.3% interest in REX’s
1,163 net developed acres and 11,619 net undeveloped acres. In addition, the Company holds royalty interests
in 4,538 gross undeveloped acres (79 net undeveloped acres), offshore in the Gulf of Mexico.

Productive Wells

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 June 30, 2010:

Total Productive

Wells (1)

Gross (2)

Net (3)

Natural gas (onshore)……………………………………………………
Natural gas (offshore)……………………………………………………
Oil………………………………………………………………………

Total…………………………………………………………………

14
12

12.7
5.4
-

18.1

(1) 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.

(2) A gross well is a well in which we own an interest.
(3) The number of net wells is the sum of our fractional working interests owned in gross wells.

Natural Gas and Oil Reserves

The following table presents our estimated net proved natural gas and oil reserves and the pre-tax net

present value of our reserves at June 30, 2010, based on reserve reports generated by William M. Cobb &
Associates, Inc. (“Cobb”) and Lonquist & Co. LLC (“Lonquist”). The Company believes that having
independent and well respected third-party engineering firms prepare its reserve reports enhances the
credibility of its reported reserve estimates. Management is responsible for the reserve estimate disclosures in
this filing, and meets regularly with our independent third-party engineers to review these reserve estimates.
The qualifications of the technical person at each of these firms primarily responsible for overseeing his firm’s
preparation of the company’s reserve estimates are set forth below.

William M. Cobb & Associates, Inc.

• Over 30 years of practical experience in the estimation and evaluation of reserves
• A registered professional engineer in the state of Texas
• Bachelor of Science Degree in Petroleum Engineering
• Member in good standing of the Society of Petroleum Engineers and the Society of Petroleum

Evaluation Engineers.

Lonquist & Co. LLC

• Over 21 years of practical experience in the estimation and evaluation of reserves
• A registered professional engineer in the state of Texas
• Bachelor of Science Degree in Petroleum Engineering
• Member in good standing of the Society of Petroleum Engineers and the Society of Petroleum

Evaluation Engineers.

Each of Cobb and Lonquist has informed us that the technical person primarily responsible for the

reserve estimates meets or exceeds the education, training, and experience requirements set forth in the
standards pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the
Society of Petroleum Engineers and is proficient in the application of industry standard practices to
engineering evaluations as well as the application of SEC and other industry definitions and guidelines.

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.

Total Proved Reserves as of June 30, 2010

Producing

Non-Producing

Total

Offshore

Natural gas (MMcf)…………………………...………………
Oil and condensate (MBbls)…………...……………………
Natural gas liquids (MBbls)…………………………...……

Total proved reserves (MMcfe)……………...………………

177,418
3,675
4,657

227,410

68,593
923
2,081

86,617

246,011
4,598
6,738

314,027

Pre-tax net present value ($000) (discounted @ 10%)………

812,044

158,398

970,442

In December 2008, the SEC released the final rule for Modernization of Oil and Gas Reporting. The

new rule requires disclosure of oil and gas proved reserves using the 12-month average beginning-of-month
price for the year, rather than year-end prices, and allows the use of reliable technologies to estimate proved oil
and gas reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves
volumes. In addition, companies are required to report on the independence and qualifications of its reserves
preparer or auditor, and file reports when a third party is relied upon to prepare reserves estimates or conduct a
reserves audit. The reserves information above is presented consistent with the requirements of the new rule.
The new rule does not allow prior-year reserve information to be restated, so all information related to periods
prior to June 30, 2010 is presented consistent with prior SEC rules for the estimation of proved reserves. In
January 2010, the Financial Accounting Standards Board (“FASB”) adopted the SEC’s final rule for
Modernization of Oil and Gas Reporting.

The line item “Pre-tax net present value, discounted at 10%” in the table above, is not intended to

represent the current market value of the estimated natural gas and oil reserves we own. The pre-tax net
present value of future cash flows attributable to our proved reserves as of June 30, 2010 was based on $4.09
per million British thermal units (“MMbtu”) for natural gas at the NYMEX, $76.21 per barrel of oil at the West
Texas Intermediate Posting, and $44.62 per barrel of NGLs, in each case before adjusting for basis,
transportation costs and British thermal unit (“BTU”) content. The pre-tax net present value is a non-GAAP
financial measure as defined in Item 10(e) of Regulation S-K. The table below reconciles our calculation of
pre-tax net present value to the standardized measure of discounted future net cash flows, which is the most
directly comparable GAAP financial measure. Management believes that pre-tax net present value is an
important non-GAAP financial measure used by analysts, investors and independent oil and gas producers for
evaluating the relative value of oil and natural gas properties and acquisitions because the tax characteristics of
comparable companies can differ materially. The reconciliation of the pre-tax net present value to the
standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves at
June 30, 2010 is as follows (in thousands):

June 30, 2010

Pre-tax net present value ($000) (discounted @ 10%)……………
Future income taxes, discounted at 10%.......................................

970,442
(258,348)

Standardized measure of discounted future net cash flows………

712,094

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.

Item 3. Legal Proceedings

From time to time, we are party to litigation or other legal and administrative proceedings that we

consider to be a part of the ordinary course of business. As of the date of this Form 10-K, we are not a party to
any material legal proceedings and we are not aware of any material proceedings contemplated against us, that
could individually or in the aggregate, reasonably be expected to have a material adverse effect on our
financial condition, cash flows or results of operations.

Item 4. Reserved

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 Amex (previously the American Stock Exchange) in

January 2001 under the symbol “MCF”. The table below shows the high and low closing prices of our
common stock for the periods indicated.

High

Low

Fiscal Year 2009:

Quarter ended September 30, 2008 ..................................................................... $ 94.40
Quarter ended December 31, 2008 ...................................................................... $ 56.30
Quarter ended March 31, 2009 ............................................................................ $ 57.15
Quarter ended June 30, 2009 ............................................................................... $ 49.87

Fiscal Year 2010:

Quarter ended September 30, 2009 ..................................................................... $ 51.06
Quarter ended December 31, 2009 ...................................................................... $ 54.09
Quarter ended March 31, 2010 ............................................................................ $ 55.00
Quarter ended June 30, 2010 ............................................................................... $ 60.03

$
$
$
$

48.11
36.55
32.20
35.87

40.40
44.38
47.07
44.28

On August 31, 2010, the closing price of our common stock on the NYSE Amex was $43.85 per

share, and there were 15,664,666 shares of Contango common stock outstanding, held by approximately 79
holders of record.

We have not declared or paid any dividends on our shares of common stock. Any future decision to
pay dividends on our common stock will be at the discretion of our board and will depend upon our financial
condition, results of operations, capital requirements, and other factors our board may deem relevant.

During the fiscal year ended 2007, we sold $30.0 million of our Series E preferred stock to a group of
private investors. During the fiscal year ended 2008, all Series E preferred stockholders converted their Series
E preferred stock into 789,468 shares of our common stock.

The following table sets forth information about our equity compensation plans at June 30, 2010:

Plan Category

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 (excluding
securities

reflected in column (b))

1999 Stock Incentive Plan -
approved by security holders…..

2009 Equity Compensation Plan -
approved by security holders…..

Equity compensation plans not
approved by security holders…..

280,334

$ 26.76

25,000

$ 49.29

1,475,000

The Company’s 1999 Stock Incentive Plan (the “1999 Plan”) expired in August 2009. The 280,334

outstanding options issued under the 1999 Plan will be converted into securities if exercised prior to their
expiration dates, which range from December 2010 to September 2013.

On September 15, 2009, the Company’s Board of Directors adopted the Contango Oil & Gas

Company Equity Compensation Plan (the “2009 Plan”), which was approved by shareholders on November
19, 2009. Under the 2009 Plan, the Company’s Board of Directors can grant restricted stock and option
awards to officers, directors, employees or consultants of the Company. Awards made under the 2009 Plan are
subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the
Board.

During the fiscal year ended June 30, 2010, the Company purchased 115,454 shares of its common
stock from three officers of the Company and two members of its board of directors for approximately $6.4
million. During the fiscal year ended June 30, 2009, the Company purchased 21,754 shares of its common
stock from one member of its board of directors for approximately $1.3 million. During the fiscal year ended
June 30, 2008, Company purchased 10,000 shares of its common stock from one member of its board of
directors and 99,333 stock options from three officers of the Company and one member of its board of
directors for approximately $6.6 million. All purchases were approved by the Company’s board of directors
and were completed at the closing price of the Company’s common stock on the date of purchase.

The following graph compares the yearly percentage change from June 30, 2005 until June 30, 2010
in the cumulative total stockholder return on our common stock to the cumulative total return on the Russell
2000 Stock Index and a peer group of five independent oil and gas exploration companies selected by us. The
companies in our selected peer group are ATP Oil & Gas Corp., Callon Petroleum, Energy XXI (Bermuda)
Limited, McMoRan Exploration Company, and W&T Offshore, Inc. Our common stock began trading on the
NYSE Amex (previously American Stock Exchange) on January 19, 2001 and before that 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, 2005 and that all dividends were reinvested. The stock performance for our
common stock is not necessarily indicative of future performance. For companies that did not exist as of June
30, 2005, we used the initial public price for all periods that an actual price did not exist.

Comparison of Fiscal Year 2010 Cumulative Total Return

Peer Group Composite

Russell 2000 Stock Index

Contango Oil & Gas Co.

s
r
a

l
l

o
D

1,250

1,050

850

650

450

250

06/30/2005

6/30/2006

6/30/2007

6/30/2008

6/30/2009

6/30/2010

Peer Group Composite
Russell 2000 Stock Index
Contango Oil & Gas Co.

06/30/2005 6/30/2006 6/30/2007 6/30/2008
183
108
1,010

141
113
154

127
130
394

100
100
100

6/30/2009
29
79
462

6/30/2010
46
95
486

Item 6. Selected Financial Data

Financial Data:
Revenues:

Year Ended June 30,

2010

2009

2008

2007

2006

(Dollar amounts in 000s, except per share amounts)

Natural gas and oil sales…………………………...

160,681

190,656

116,498

14,140

776

Total revenues…………………………………… 160,681

190,656

116,498

14,140

776

Income (loss) from continuing operations…………
Discontinued operations, net of income taxes………

Net income (loss)………………………………………
Preferred stock dividends……………………………

49,686
-

55,861
-

83,221
173,685

(1,078)
(1,617)

(6,888)
6,681

55,861
-

256,906
1,548

(2,695)
540

(207)
601

Net income (loss) attributable

to common stock……………………………………

49,686

55,861

255,358

(3,235)

(808)

Net income (loss) per share:

Basic
Continuing operations…………………………
Discontinued operations………………………

3.14
-

3.41
-

5.05
10.73

(0.03)
(0.18)

(0.50)
0.45

Total……………………………………………

3.14

3.41

15.78

(0.21)

(0.05)

Diluted
Continuing operations…………………………
Discontinued operations………………………

3.08
-

3.35
-

4.82
10.06

(0.03)
(0.18)

(0.50)
0.45

Total……………………………………………

3.08

3.35

14.88

(0.21)

(0.05)

Weighted average shares outstanding:

Basic…………………………………………………
Diluted………………………………………………

15,831
16,157

16,363
16,690

16,185
17,263

15,430
15,430

14,760
14,760

41,385
$
Working capital (deficit)………………………………
97,699
$
Capital expenditures…………………………………
$
-
Long term debt……………….………………………
$
Stockholders' equity…………….……………………
377,330
Total assets……...……………………..……………… 592,266
$

43,232
$
45,742
$
$
-
$
349,364
$
517,042

$
$
$
$
$

29,913
119,929
15,000
341,998
599,974

$
$
$
$
$

(4,088)
77,688
20,000
90,804
153,936

$
$
$
$
$

18,333
33,805
10,000
62,540
89,385

Proved Reserve Data:

314,027
Total proved reserves (Mmcfe)……………………
Pre-tax net present value (SEC at 10%)……………
970,442
Standardized Measure……………………………… 712,094

$
$

355,046
889,865
638,091

$
$

369,076
3,183,843
2,233,918

$
$

84,876
329,179
252,297

$
$

3,430
8,852
7,734

$
$

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.

Overview

Contango is a Houston-based, independent natural gas and oil company. The Company’s business is

to explore, develop, produce and acquire natural gas and oil properties primarily offshore in the Gulf of
Mexico. COI, our wholly-owned subsidiary, acts as operator on certain offshore prospects.

Revenues and Profitability. Our revenues, profitability and future growth depend substantially on

prevailing prices for natural gas and oil and on our ability to find, develop and acquire natural gas and oil
reserves that are economically recoverable. The preparation of our financial statements in conformity with
generally accepted accounting principles requires us to make estimates and assumptions that affect our
reported results of operations and the amount of reported assets, liabilities and proved natural gas and oil
reserves. We use the successful efforts method of accounting for our natural gas and oil activities.

Reserve Replacement. Generally, our producing properties offshore in the Gulf of Mexico have high

initial production rates, followed by steep declines. As a result, 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 acquire natural gas and oil reserves.

Sale of proved properties. From time-to-time as part of our business strategy, we have sold, and in
the future may continue to sell some or a substantial portion of our proved reserves to capture current value,
using the sales proceeds to reduce debt and further our exploration activities.

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.

Please see “Risk Factors” on page 14 for a more detailed discussion of a number of other factors that

affect our business, financial condition and results of operations.

Impact of Deepwater Horizon Incident and Federal Deepwater Moratorium

In April 2010, the deepwater Gulf of Mexico drilling rig Deepwater Horizon, engaged in drilling

operations for another operator, sank after an apparent blowout and fire. On May 27, 2010, in response to the
incident, the President of the United States announced a six-month moratorium on drilling in the deepwater
Gulf of Mexico (the “Moratorium”), which followed a one-month suspension in activity announced in May
2010, immediately following the spill. Under the Moratorium, no new drilling, including sidetracks and
bypasses of wells, is allowed in water depths greater than 500 feet for six months, or until November 27, 2010.
For operators such as Contango that operate in less than 500 feet of water, there are new, more restrictive
requirements, on permitting activities on the Outer Continental Shelf.

On July 12, 2010, the Secretary of the Interior announced a revised moratorium that is scheduled to

extend through November 30, 2010 that focuses on drilling configurations and technologies rather than on
water depth. The revised moratorium applies to all Gulf of Mexico drilling operations. Some companies may
be able to resume drilling sooner under certain conditions. To qualify, operators must certify that they have
adequate plans in place to quickly shut down an out-of-control well, that the blowout preventers atop the wells
it drills have passed rigorous new tests, and that sufficient cleanup resources are on hand in the event of a spill.

Business Impact

In the near-term, we do not expect a material impact on our production. It is our understanding that

workover operations, operations necessary to sustain reservoir pressure, and plugging and abandonment
operations are still allowed, to the extent they comply with applicable regulations and permits. Therefore, we
do not expect production for the remainder of calendar year 2010 to be impacted.

Over a longer period of time, however, we believe that the Deepwater Horizon incident is likely to
have a significant and lasting effect on the US offshore energy industry, and will likely result in a number of
fundamental changes, including heightened regulatory scrutiny, more stringent operating and safety standards,
changes in equipment requirements and the availability and cost of insurance, as well as increased
politicization of the industry. A significant delay of planned exploratory activities will reduce our longer term
ability to replace reserves, resulting in a negative impact on production, including a reduction in operating
results and cash flows as we deplete our reserves. There may be other impacts of which we are not aware at
this time.

Finally, the potential for removal of the liability cap for claims of damages from oil spills, and/or the
enactment of onerous rules and regulations regarding activities in the Gulf of Mexico could significantly alter
our industry. Such rules could effectively limit which companies can operate in the Gulf of Mexico. Small and
medium-sized oil and gas companies may not be able to obtain insurance coverage at economically appropriate
levels or meet financial responsibility requirements and would be forced to exit operations in the Gulf of
Mexico. Potentially less attractive economics for exploration and development programs going forward will
require companies retaining operations in the Gulf of Mexico to review their business models. We have drilled,
and believe we can continue to drill, safely in the Gulf of Mexico. However, exploration and production
companies will be able to continue doing business in the Gulf of Mexico only to the extent it remains
economically viable.

Delays and volatility are inherent in our business. We have maintained a capital structure with a

strong liquidity position allowing us to manage during periods of uncertainty. We believe we are well-
positioned to respond to the increasingly complex regulatory framework for the Gulf of Mexico.

Results of Operations

The following is a discussion of the results of our continuing operations for the fiscal year ended June

30, 2010, compared to the fiscal year ended June 30, 2009, and for the fiscal year ended June 30, 2009,
compared to the fiscal year ended June 30, 2008.

Revenues. All of our revenues are from the sale of our natural gas and oil production. Our revenues
may vary significantly from year to year depending on changes in commodity prices, which fluctuate widely,
and production volumes. Our production volumes are subject to wide swings as a result of new discoveries,
weather and mechanical related problems. In addition, our production declines over time as we produce our
reserves.

The table below sets forth revenue and production data for continuing operations for the fiscal years

ended June 30, 2010, 2009 and 2008.

Revenues:

($000)

Year ended June 30,

2010

2009

2008

Natural gas and oil sales………………...……………………

160,681

190,656

-16%

190,656

116,498

64%

Total revenues……………………………………………

160,681

190,656

116,498

Production:

Natural gas (million cubic feet)………………………………
Oil and condensate (thousand barrels)………………………
Natural gas liquids (thousand gallons)………………………

Total (million cubic feet equivalent)…………………..

Natural gas (million cubic feet per day)……………………
Oil and condensate (thousand barrels per day)………………
Natural gas liquids (thousand gallons per day)………………

Total (million cubic feet per day equivalent)……………

21,385
505
25,117

28,003

58.6
1.4
68.8

76.8

Average Sales Price:

20,535
515
24,803

27,168

56.3
1.4
68.0

74.4

4%
-2%
1%

4%
0%
1%

20,535
515
24,803

27,168

56.3
1.4
68.0

74.4

9,089
185
4,968

10,909

24.8
0.5
13.6

29.7

Natural gas (per thousand cubic feet)………………………
Oil and condensate (per barrel)………………………………
Natural gas liquids (per gallon)………………………………

$
$
$

4.47
77.18
1.04

$
$
$

6.34
67.72
1.03

Total (per thousand cubic feet equivalent)………………

5.74

7.02

Operating expenses……………………………………………
Exploration expenses…………………………………………
Depreciation, depletion and amortization………………………
Lease expirations and relinquishments……………………….
Impairment of natural gas and oil properties……………..
General and administrative expenses…………………………
Interest expense, net of interest capitalized……………………
Interest income…………………………………………………
Gain (loss) on sale of assets and other…………………………

$
17,040
$
21,939
$
35,374
$
952
$
-
$
4,616
$
518
$
915
$
113

$
$
$
$
$
$
$
$
$

23,684
20,603
32,673
5,208
5,866
9,467
741
926
(530)

-29%
14%
1%

-18%

-28%
6%
8%
-82%
-100%
-51%
-30%
-1%
-121%

$
$
$

6.34
67.72
1.03

$
$
$

9.77
108.36
1.55

7.02

10.68

$
$
$
$
$
$
$
$
$

23,684
20,603
32,673
5,208
5,866
9,467
741
926
(530)

$
6,777
$
5,729
$
11,900
$
642
$
-
$
16,929
$
3,933
$
1,969
$
62,314

126%
178%
399%

149%

127%
179%
401%

150%

-35%
-38%
-34%

-34%

249%
260%
175%
711%
100%
-44%
-81%
-53%
-101%

Natural Gas, Oil and NGL Sales. We reported revenues of approximately $160.7 million for the year

ended June 30, 2010, down from approximately $190.7 million reported for the year ended June 30, 2009.
This decrease in sales was primarily attributable to the significant decline in natural gas prices received for the
year ended June 30, 2010. Also contributing was a reduction in production as a result of our ruptured 20”
pipeline which shut-in production from our four Mary Rose wells, Dutch #4 and our Eloise North wells for
approximately 35 days in fiscal year 2010. This decreased production was partially offset by increased
production from our Eloise North well which began producing in December 2008 and our Dutch #4 well which
began producing in January 2009. The decrease in production was also offset by increased production from
our Dutch #1, #2 and #3 wells which increased production in fiscal year 2010, as compared to prior year when
they were shut-in during all of September, October and the majority of November 2008 due to Hurricane Ike.

We reported revenues of approximately $190.7 million for the year ended June 30, 2009, up from
approximately $116.5 million reported for the year ended June 30, 2008. This increase was attributable to
increased natural gas, oil and NGL sales from our Mary Rose #4 discovery which began producing in July
2008, our Eloise North discovery which began producing in December 2008, and our Dutch #4 discovery
which began producing in January 2009. This increase was partially offset by reduced sales from our Dutch

#1, #2 and #3 wells which were shut-in during all of September, October and the majority of November 2008
due to Hurricane Ike. The increase was also attributable to the additional interest we purchased in our Dutch
and Mary Rose discoveries, effective January 1, 2008.

Natural Gas, Oil and NGL Production and Average Sales Prices. Our net natural gas production for

the year ended June 30, 2010 was approximately 58.6 Mmcfd, up from approximately 56.3 Mmcfd for the year
ended June 30, 2009. Net oil production and NGL production remained relatively stable for the comparable
periods. Net oil production remained flat at approximately 1,400 bopd for both periods, while NGL production
went from approximately 68,000 gallons per day to approximately 68,800 gallons per day. This increase in
natural gas production was principally attributable to our Eloise North well which began producing in
December 2008 and our Dutch #4 well which began producing in January 2009. The increase in production
was also attributable to our Dutch #1, #2 and #3 wells which were shut-in during all of September, October and
the majority of November 2008 due to Hurricane Ike. This increase in production was partially offset by our
ruptured 20” pipeline which shut-in production from our four Mary Rose wells, Dutch #4 and our Eloise North
wells for approximately 35 days in 2010.

For the year ended June 30, 2010, the price of natural gas was $4.47 per Mcf while the price for oil

and NGLs was $77.18 per barrel and $1.04 per gallon, respectively. For the year ended June 30, 2009, the
price of natural gas was $6.34 per Mcf while the price for oil and NGLs was $67.72 per barrel and $1.03 per
gallon, respectively.

Our net natural gas production for the year ended June 30, 2009 was approximately 56.3 Mmcfd, up
from approximately 24.8 Mmcfd for the year ended June 30, 2008. Net oil production for the period was up
from approximately 500 bopd to 1,400 bopd, and NGL production was up from approximately 13,600 gallons
per day to 68,000 gallons per day for the same period. The increase in natural gas, oil and NGL production
was principally attributable to a full year of production from our Mary Rose #4 discovery which began
producing in July 2008, our Eloise North discovery which began producing in December 2008, and our Dutch
#4 discovery which began producing in January 2009. This increase was partially offset by reduced production
from our Dutch #1 - #3 wells which were shut-in during all of September, October and the majority of
November 2008 due to Hurricane Ike. The increase in production was also attributable to the additional
interest we purchased in our Dutch and Mary Rose discoveries, effective January 1, 2008.

For the year ended June 30, 2009, the price of natural gas was $6.34 per Mcf while the price for oil

and NGLs was $67.72 per barrel and $1.03 per gallon, respectively. For the year ended June 30, 2008, the
price of natural gas was $9.77 per Mcf while the price for oil and NGLs was $108.36 per barrel and $1.55 per
gallon, respectively.

Operating Expenses. Operating expenses for the year ended June 30, 2010 were approximately $17.0

million, which included approximately $5.3 million of Louisiana state severance taxes and $0.7 million in
workover costs. The remaining $11.0 million related mainly to continuing operations from nine wells,
compared to operating expenses for the year ended June 30, 2009 of approximately $23.7 million which
included approximately $3.7 million in Louisiana severance taxes and $10.7 million for workover costs. The
remaining $9.3 million related mainly to continuing operations from seven wells, plus an additional two wells
that were only producing for a portion of the year. Operating expenses for the year ended June 30, 2008 were
approximately $6.8 million which related to continuing operations from only six wells.

Exploration Expense. We reported approximately $21.9 million of exploration expenses for the year

ended June 30, 2010. Of this amount, approximately $14.9 million related to the dry hole the Company drilled
at Matagorda Island 617, $5.3 million related to the dry hole the Company drilled at Vermillion 155, and the
remaining $1.7 million related to various geological and geophysical activities, seismic data and delay rentals.

We reported approximately $20.6 million of exploration expenses for the year ended June 30, 2009.

Of this amount, approximately $7.1 million related to the dry hole the Company drilled at West Delta 77, $12.5
million related to the dry hole the Company drilled at Eugene Island 56, and the remaining $1.0 million related
to various geological and geophysical activities, seismic data and delay rentals.

We reported approximately $5.7 million of exploration expenses for the year ended June 30, 2008.

Of this amount, approximately $4.2 million was related to the dry hole the Company drilled at High Island
A198, approximately $0.6 million was attributable to the cost to acquire and reprocess 3-D seismic data
offshore in the Gulf of Mexico, and approximately $0.9 million was attributable to the payment of delay
rentals.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the year

ended June 30, 2010 was approximately $35.4 million. For the year ended June 30, 2009, we recorded
approximately $32.7 million of depreciation, depletion and amortization. The increase in depreciation,
depletion and amortization was primarily attributable to an overall increase in production from our Eloise
North and Dutch #4 wells, an increase in production from our Dutch #1, #2 and #3 wells which were shut-in
during three months in fiscal year 2009 due to Hurricane Ike, and an increase in reserves due to new
discoveries. This increase in production was partially offset by our ruptured 20” pipeline which shut-in
production from our Mary Rose wells, Dutch #4 and Eloise North wells for approximately 35 days in fiscal
year 2010, as well as by a downward revision of our reserves in June 2010.

Depreciation, depletion and amortization for the year ended June 30, 2009 was approximately $32.7

million. For the year ended June 30, 2008, we recorded approximately $11.9 million of depreciation, depletion
and amortization. The increase in depreciation, depletion and amortization was primarily attributable to added
production from newly added reserves from our Mary Rose #4, Eloise North and Dutch #4 discoveries, as well
as from the additional interest we purchased in our Dutch and Mary Rose discoveries, effective January 1,
2008.

Lease Expiration and Relinquishment Expense. For the year ended June 30, 2010, the Company

recorded lease expiration and relinquishment expense of approximately $0.9 million, related to the
relinquishment of six lease blocks owned by REX and COE. For the year ended June 30, 2009, the Company
recorded lease expiration and relinquishment expense of approximately $5.2 million due to the expiration and
relinquishment of 44 lease blocks owned by REX and COE. For the year ended June 30, 2008, the Company
recorded lease expiration and relinquishment expense of approximately $0.6 million related to the expiration of
Eugene Island 209 and Viosca Knoll 161, two leases held by COE.

Impairment of Natural Gas and Oil Properties. The Company did not report an impairment charge for

the year ended June 30, 2010 or 2008. For the year ended June 30, 2009, the Company recorded impairment
expense of approximately $5.9 million. Of this amount, approximately $2.5 million related to the impairment
of Grand Isle 70 and $3.4 million related to the impairment of Grand Isle 72, as a result of the expected future
undiscounted net cash flows of these wells being lower than the unamortized capitalized cost.

General and Administrative Expenses. General and administrative expenses for the year ended June

30, 2010 were approximately $4.6 million, down from approximately $9.5 million for the year ended June 30,
2009. The decrease is principally attributable to lower bonus payments and stock and stock option expenses in
the year ended June 30, 2010. Major components of general and administrative expenses for the year ended
June 30, 2010 included approximately $3.0 million in salaries, benefits and board compensation (includes $0.7
million in non-cash expenses related to restricted stock and option awards), $0.5 million in office
administration and other expenses, $0.5 million in insurance costs, $0.2 million in accounting and tax services,
and $0.4 million in legal, consulting and other administrative expenses.

General and administrative expenses for the year ended June 30, 2009 were approximately $9.5

million, down from $16.9 million for the year ended June 30, 2008. The decrease is principally attributable to
higher bonus payments in fiscal year 2008. Major components of general and administrative expenses for the
year ended June 30, 2009 included approximately $5.3 million in salaries, benefits and bonuses (includes $1.4
million in non-cash expenses related to restricted stock and option awards), $1.7 million in office
administration and other expenses, $0.5 million in insurance costs, $0.7 million in accounting and tax services,
and $1.3 million in legal and other administrative expenses.

General and administrative expenses for the year ended June 30, 2008 were approximately $16.9

million. Major components of general and administrative expenses for the year ended June 30, 2008 included
approximately $1.0 million in salaries, $12.1 million in benefits and bonuses (includes $1.5 million in non-cash
expenses to restricted stock and option awards), $1.1 million in office administration and other expenses, $0.4
million in insurance costs, $0.9 million in accounting and tax services, and $1.4 million in legal and other
administrative expenses.

Interest Expense. Interest expense for the fiscal years ended June 30, 2010, 2009 and 2008 were

approximately $0.5 million, $0.7 million, and $3.9 million, respectively. The lower levels of interest expense
for the fiscal years ended 2010 and 2009 relate mainly to the Company’s portion of COE’s interest expense on
the Note as a result of our proportionate consolidation of COE. The higher level of interest expense for the
fiscal year ended 2008 was attributable to bank debt outstanding during the period. The Company retired all of
its long term debt during the fiscal year ended 2009.

Interest Income. Interest income for the fiscal years ended June 30, 2010, 2009 and 2008 were

approximately $0.9 million, $0.9 million, and $1.9 million, respectively. The higher level of interest income
for fiscal year 2008 was attributable to loans made to related parties and interest earned on the proceeds from
our various property sales.

Gain on Sale of Assets and Other. For the year ended June 30, 2010, we reported a gain on sale of

assets and other of approximately $0.1 million related to the sale of our Grand Isle 70 well. For the year ended
June 30, 2009, we reported a loss on sale of assets and other of approximately $0.5 million related to a post-
closing adjustment for the sale of our Arkansas Fayetteville Shale properties.

For the year ended June 30, 2008, we reported a gain on sale of assets and other of approximately

$62.3 million. Of this amount, approximately $63.4 million relates to the gain on the sale of the Company’s
10% limited partnership interest in Freeport LNG, $2.1 million relates to a payment from a stockholder related
to a short swing profit liability, $0.3 million relates to the gain on the sale of certain overriding royalty interests
and onshore properties, offset by a $2.9 million loss recognized on the sale of certain assets held by CVCC and
a $0.6 million loss attributable to the write-down of the Company’s investment in Moblize.

Discontinued Operations. The Company did not have any discontinued operations for the year ended

June 30, 2010 or 2009. The table and discussions above, along with our financial statements, discuss only
continuing operations for all fiscal years presented. Not reflected are the Company’s sold producing properties
which generated 7.7% of combined revenues for the fiscal year ended June 30, 2008. Please see Note 6 – Sale
of Properties – Discontinued Operations of Notes to Consolidated Financial Statements included as part of this
Form 10-K, for a discussion of our discontinued operations.

Capital Resources and Liquidity

Cash From Operating Activities. Cash flow from operating activities provided approximately
$128.2 million in cash for the year ended June 30, 2010 compared to $95.4 million for the same period in
2009. This increase in cash provided by operating activities was primarily attributable to increased natural gas,
oil and NGL production attributable to our Eloise North and Dutch #4 well. The increase in production was
also attributable to our Dutch #1, #2 and #3 wells which were shut-in during all of September, October and the
majority of November 2008 due to Hurricane Ike.

Cash flow from operating activities provided approximately $95.4 million in cash for the year ended
June 30, 2009 compared to $112.7 million for the same period in 2008. This decrease in net cash provided by
operating activities was primarily attributable to lower sales as a result of lower natural gas and oil prices
during 2009, partially offset by increased production from our Mary Rose #4, Eloise North and Dutch #4
discoveries which began producing during the year ended June 30, 2009.

Cash From Investing Activities. Cash flows used in investing activities for the year ended June 30,
2010 were approximately $97.7 million, compared to $45.8 million used in investing activities for the year

ended June 30, 2009. The higher level of cash flows used in investing activities in 2010 was primarily
attributable to increased capital expenditures for drilling exploration and development wells.

Cash flows used in investing activities for the year ended June 30, 2009 were approximately $45.8
million, compared to $38.9 million used in investing activities for the year ended June 30, 2008. The lower
level of cash flows used in investing activities in 2008 was due primarily to the proceeds received from the sale
of certain assets.

Cash From Financing Activities. Cash flows used in financing activities for the year ended June 30,

2010 were approximately $22.4 million, compared to $65.1 million used in financing activities for the same
period in 2009. This $65.1 million of cash flows used in financing activities for the year ended June 30, 2009
is primarily composed of purchasing approximately $51.8 million of our common stock and the repayment of
$15.0 million of debt. There were no credit facility payments and fewer purchases of common stock during the
year ended June 30, 2010.

Cash flows used in financing activities for the year ended June 30, 2009 were approximately $65.1

million, compared to $20.2 million used in financing activities for the same period in 2008. This $65.1 million
of cash flows used in financing activities for the year ended June 30, 2009 is primarily composed of purchasing
approximately $51.8 million of our common stock and the repayment of $15.0 million of debt.

Income Taxes. During the year ended June 30, 2010, 2009 and 2008, we paid approximately $11.5

million, $45.6 million and $22.0 million, respectively, in estimated income taxes.

Capital Budget. For the remainder of fiscal year 2011, our capital expenditure budget calls for us to

invest approximately $85 million from cash flow from operations and cash on hand as follows:

• We plan to invest approximately $60 million to drill up to four wildcat exploration wells in
the Gulf of Mexico, at an estimated dry hole cost of approximately $15 million each, net to
Contango.

• We plan to invest approximately $22.5 million to drill and complete 15 additional on-shore

wells in Panola County, Texas under our joint venture with Patara Oil & Gas LLC.

The Company often reviews acquisitions and prospects presented to us by third parties and may

decide to invest in one or more of these opportunities. There can be no assurance that we will invest, or that
any investment entered into will be successful. These potential investments are not part of our current capital
budget and would require us to invest additional capital. Natural gas and oil prices continue to be volatile and
our resources may be insufficient to fund any of these opportunities. As of August 31, 2010, we had
approximately $45.5 million in cash and cash equivalents and no debt outstanding.

Discontinued Operations. The Company, since its inception in September 1999, has raised
approximately $484.0 million in proceeds from twelve separate property sales, and views periodic reserve sales
as an opportunity to capture value, reduce reserve and price risk, in addition to being a source of funds for
potentially higher rate of return natural gas and oil exploration investments. We believe these periodic natural
gas and oil property sales are an efficient strategy to meet our cash and liquidity needs by providing us with
immediate cash, which would otherwise take years to realize through the production lives of the fields sold.
We have in the past and expect to in the future to continue to rely heavily on the sales of assets to generate cash
to fund our exploration investments and operations.

These sales bring forward future revenues and cash flows, but our longer term liquidity could be
impaired to the extent our exploration efforts are not successful in generating new discoveries, production,
revenues and cash flows. Additionally, our longer term liquidity could be impaired due to the decrease in our
inventory of producing properties that could be sold in future periods. Further, as a result of these property
sales the Company’s ability to collateralize bank borrowings is reduced which increases our dependence on
more expensive mezzanine debt and potential equity sales. The availability of such funds will depend upon
prevailing market conditions and other factors over which we have no control, as well as our financial
condition and results of operations.

We had no discontinued operations for the fiscal year ended June 30, 2010 or 2009. The table below

sets forth the proceeds received from natural gas and oil property sales for the year ended June 30, 2008, the
impact of these sales on our developed reserve quantities, and a measure of our developed reserves held at the
end of each such fiscal year. Please see the reserve activity reported in the Supplemental Oil and Gas
Disclosures on pages F-23 through F-26 for a more detailed discussion regarding our standardized measure.

Fiscal Year of
Property Sale

Proceeds
Received

Reserves
Sold (Mmcfe)

Reserves at end of
Fiscal Year (Mmcfe)

Standardized Measure of
Discounted Future Net Cash
Flows at end of Fiscal Year

2008

328,300,000

13,789

369,076

2,233,918,129

For fiscal year 2008, the Company realized approximately $8.1 million in operating cash flows from
discontinued operations, approximately $319.0 million in investing cash flows from discontinued operations
and zero in financing cash flows from discontinued operations.

Off Balance Sheet Arrangements

None.

Contractual Obligations

The following table summarizes our known contractual obligations as of June 30, 2010:

Payment due by period

Total

Less than 1
year

1-3 years

3-5 years

Long term debt…………………
Delay rentals…………………… 1,944,240
Asset retirement obligations…… 5,156,642
Operating leases…………………
291,438

$
-
$
$
$

$
-
$
542,838
$
-
$
198,114

$
-
$
999,792
$
-
$
83,550

$
-
$
401,610
$
-
$
9,774

More than 5
years

$
-
$
-
$
$
-

5,156,642

Total…………………………

7,392,320

740,952

1,083,342

411,384

5,156,642

Share Repurchase Program

In September 2008, the Company’s board of directors approved a $100 million share repurchase

program. Under the program, all shares are purchased in the open market from time to time by the Company
or through privately negotiated transactions. The purchases will be made subject to market conditions and
certain volume, pricing and timing restrictions to minimize the impact of the purchases upon the market.
Repurchased shares of common stock become authorized but unissued shares, and may be issued in the future
for general corporate and other purposes. As of August 31, 2010, we have purchased approximately 1.7
million shares of our common stock at an average cost per share of $43.88, for a total expenditure of
approximately $75 million. As at August 31, 2010, we have 15,664,666 shares of common stock outstanding
and 15,970,000 fully diluted shares.

Credit Facility

On October 3, 2008, the Company and its wholly owned subsidiaries completed the arrangement of a
$50 million Hydrocarbon Borrowing Base secured revolving credit facility pursuant to a credit agreement with
BBVA Compass Bank (successor in interest to Guaranty Bank, as administrative agent and issuing lender) (the
“Compass Agreement”). The credit facility is secured by substantially all of the Company’s assets and is
available to fund the Company’s exploration and development activities, as well as the repurchase of shares of
the Company’s common stock, the payment of dividends, and working capital as needed. Borrowings under
the Compass Agreement bear interest at LIBOR plus 2.0% per annum and are due October 3, 2010. An

arrangement fee of 0.5%, or $250,000, was paid in connection with the facility and a commitment fee of 0.5%
is paid on the unused commitment amount. As of August 31, 2010 the Company was in compliance with all
financial covenants, ratios and other provisions of the Compass Agreement. No amounts have been drawn on
the credit facility.

On August 24, 2010, the Company signed a commitment letter with Amegy Bank National
Association (“Amegy”) to arrange for a four-year $40 million hydrocarbon borrowing base senior revolving
credit facility (the “Amegy Agreement”) to replace the expiring Compass Agreement. Under the terms and
conditions of the term sheet with Amegy, the facility will be secured by substantially all of the Company’s
assets and will be available to fund the Company’s exploration and development activities, as well as the
repurchase of shares of the Company’s common stock, the payment of dividends, and working capital as
needed. Borrowings under the Amegy Agreement will bear interest at LIBOR plus 2.5% per annum. An
arrangement fee of 0.75%, or $300,000, will be paid in connection with the facility and a commitment fee of
0.375% will be paid on the unused commitment amount. The Amegy Agreement will contain customary
covenants including limitations on additional indebtedness.

In August 2008, the Company prepaid in full the $15.0 million it had outstanding under its $30.0
million loan agreement with a private investment firm (the “Term Loan Agreement”) and terminated the Term
Loan Agreement. In February 2008, using the proceeds from our $68.0 million sale of Freeport LNG, the
Company prepaid in full the $20.0 million it had outstanding under its three-year $20.0 million secured term
loan facility with The Royal Bank of Scotland plc (the “RBS Facility”) and terminated the RBS Facility.

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 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:

Successful Efforts Method of Accounting. Our application of the successful efforts method of
accounting for our natural gas and oil business 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 to estimate the fair value 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 drilling 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. In June 2010, the Company revised its offshore reserves downward by approximately 48.5
Bcfe. This revision was attributable to newly obtained bottom hole pressure data as a result of a recent field
wide shut-in and a “P/Z pressure test” that indicated fewer reserves than was originally estimated.

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 June 30, 2010 of 5%, 10% and 15% would affect depreciation, depletion
and amortization expense by approximately $1.6 million, $3.6 million, and $5.8 million, respectively.

Impairment of Natural Gas and Oil Properties. The Company reviews its proved natural gas and oil

properties for impairment on an annual basis or whenever events and circumstances indicate a potential decline
in the recoverability of their carrying value. The Company compares expected undiscounted future net cash
flows on a cost center basis 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, anticipated capital expenditures, and a
discount rate commensurate with the risk associated with realizing the expected cash flows projected.
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. 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.

Income Taxes. Income taxes are provided for the tax effects of transactions reported in the financial

statements and consists of taxes currently payable plus deferred income taxes related to certain income and
expenses recognized in different periods for financial and income tax reporting purposes. Deferred income
taxes are measured by applying currently enacted tax rates to the differences between financial statements and
income tax reporting. Numerous judgments and assumptions are inherent in the determination of deferred
income tax assets and liabilities as well as income taxes payable in the current period. We are subject to
taxation in several jurisdictions, and the calculation of our tax liabilities involves dealing with uncertainties in
the application of complex tax laws and regulations in various taxing jurisdictions.

Recent Accounting Pronouncements

In February 2010, the FASB amended its guidance on subsequent events to remove the requirement

for SEC filers to disclose the date through which an entity has evaluated subsequent events. The guidance was
effective upon issuance. We adopted this guidance for the fiscal year ended June 30, 2010.

In January 2010, the FASB adopted the SEC’s Modernization of Oil & Gas Reporting: Final Rule

requirements to modernize the oil and gas company reserve reporting requirements. The most significant
amendments to the requirements include the following:

• Commodity Prices – Economic producibility of reserves and discounted cash flows will be based on a
12-month average commodity price calculated as the un-weighted arithmetic average of the first-day-
of-the-month price for each month within the 12-month period prior to the end of the reporting period,
unless contractual arrangements designate the price to be used.

• Proved Undeveloped Reserve Guidelines – Reserves may be classified as proved undeveloped if there

is a high degree of confidence that the quantities will be recovered.

• Reserve Personnel and Estimation Process – Additional disclosure is required regarding the

qualifications of the chief technical person who oversees our reserves estimation process. We will
also be required to provide a general discussion of our internal controls used to assure the objectivity
of the reserves estimate.

The Company adopted the new rules effective June 30, 2010, and as a result, it (i) prepared its reserve
estimates as of June 30, 2010 based on the new reserves definitions, (ii) has estimated its June 30, 2010 reserve
quantities using the 12-month average price and (iii) included additional disclosures as required by the new
rule. As a result of the change in reserve pricing from year-end oil and gas prices to now using the 12-month
average prices, the Company’s total proved reserves at June 30, 2010 were 3.8 Bcfe higher than they would
have otherwise been if year-end oil and gas prices were used. Oil and gas reserve quantities or their values are
a significant component of the Company’s depreciation, depletion and amortization (“DD&A”), asset
retirement obligation, and impairment analysis. The Company’s adoption of the SEC’s Modernization of Oil
and Gas Reporting: Final Rule had an immaterial impact on the Company’s DD&A expense, asset retirement
obligation, and impairment analysis.

Effective July 1, 2009, the Company adopted new accounting guidance on fair value measurements
which require additional disclosures about the Company’s nonfinancial assets and liabilities, which adoption
had no impact on the Company’s financial position, results of operations or cash flows.

In June 2009, the FASB issued new accounting guidance on the FASB Accounting Standards
Codification and the hierarchy of GAAP. This new accounting guidance codifies existing GAAP and
recognizes only two levels of GAAP, authoritative and nonauthoritative. Rules and interpretive releases of the
SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. This
new accounting guidance is effective for financial statements issued for interim and annual periods ending after
September 15, 2009. The Company’s adoption of this new guidance did not have any impact on its financial
position, results of operations or cash flows.

Item 7A. Quantitative and Qualitative Disclosure about Market Risk

Commodity Risk. Our major commodity price risk exposure is to the prices received for our natural

gas and oil production. Realized commodity prices received for our production are tied to the spot prices
applicable to natural gas and crude oil at the applicable delivery points. Prices received for natural gas and oil
are volatile and unpredictable. We do not hedge against price risk exposure. For the year ended June 30,
2010, a 10% fluctuation in the prices received for natural gas and oil production would have had an
approximate $16.0 million impact on our revenues.

Interest Rate Risk. As of August 31, 2010, we have no long-term debt subject to the risk of loss

associated with movements in interest rates.

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-27 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 June 30, 2010, the end
of the period covered by this report. Based on that evaluation, the Company’s management, including the
Chairman and Chief Executive Officer, Chief Financial Officer, and Controller, concluded that the Company’s
disclosure controls and procedures were effective as of such date to ensure that information required to be
disclosed in the reports that the Company files under the Exchange Act is (i) recorded, processed, summarized
and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and
communicated to the Company’s management, including the Chairman, Chief Executive Officer, Chief
Financial Officer and Controller, as appropriate, to allow timely decisions regarding required disclosures.

Management’s Report on Internal Control Over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control

over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and
with the participation of the Company’s management, including the Chairman, Chief Executive Officer, Chief
Financial Officer and Controller, the Company conducted an evaluation of the effectiveness of its internal
control over financial reporting based on the framework in 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 Internal Control—Integrated Framework, the Company’s management
concluded that its internal control over financial reporting was effective as of June 30, 2010.

Grant Thornton LLP, the independent registered public accounting firm that audited our consolidated
financial statements included in this Annual Report on Form 10-K, has audited the effectiveness of our internal
control over financial reporting as of June 30, 2010, as stated in their report which is included herein.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders
Contango Oil & Gas Company

We have audited Contango Oil & Gas Company (a Delaware corporation) and subsidiaries’ internal control
over financial reporting as of June 30, 2010, based on criteria established in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).
Contango Oil & Gas Company's management is responsible for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness of internal control over financial reporting,
included in the accompanying management’s report on internal control over financial reporting. Our
responsibility is to express an opinion on Contango Oil & Gas 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, Contango Oil & Gas Company and subsidiaries maintained, in all material respects, effective
internal control over financial reporting as of June 30, 2010, based on criteria established in 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 balance sheets of Contango Oil & Gas Company and subsidiaries as of June
30, 2010 and 2009, and the related consolidated statements of operations, shareholders' equity, and cash flows
for each of the three years in the period ended June 30, 2010 and our report dated September 13, 2010
expressed an unqualified opinion on those financial statements.

/s/ GRANT THORNTON LLP

Houston, Texas
September 13, 2010

Changes in Internal Control Over Financial Reporting

There was no change in our internal controls over financial reporting during the period covered by

this annual report on Form 10-K that materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting.

Item 9B. Other Information

On September 30, 2008, the Company adopted a Stockholder Rights Plan (the “Plan”) that is designed

to ensure that all stockholders of Contango receive fair value for their shares of common stock in the event of
any proposed takeover of Contango and to guard against the use of partial tender offers or other coercive
tactics to gain control of Contango without offering fair value to all of Contango’s stockholders. The Plan is
not intended, nor will it operate, to prevent an acquisition of Contango on terms that are favorable and fair to
all stockholders.

Under the terms of the Plan, each right (a “Right”) will entitle the holder to buy 1/100 of a share of
Series F Junior Preferred Stock of Contango (the “Preferred Stock”) at an exercise price of $200 per share.
The Rights will be exercisable and will trade separately from the shares of common stock only if a person or
group acquires beneficial ownership of 20% or more of Contango’s common stock or commences a tender or
exchange offer that would result in such a person or group owning 20% or more of the common stock (the
“Triggering Event”).

Under the terms of the Plan, Rights have been distributed as a dividend at the rate of one Right for

each share of common stock held as of the close of business on October 1, 2008. Stockholders will not
actually receive certificates for the Rights at this time, but the Rights will become part of each outstanding
share of common stock. An additional Right will be issued along with each share of common stock that is
issued or sold by Contango after October 1, 2008. The Rights may only be exercised during a three-year
period and are scheduled to expire on September 30, 2011. Upon a Triggering Event, Contango stockholders
will receive certificates for the Rights.

If any person actually acquires 20% or more of shares of common stock -- other than through a tender
or exchange offer for all shares of common stock that provides a fair price and other acceptable terms for such
shares, as determined by the board of directors of Contango -- or if a 20%-or-more stockholder engages in
certain “self-dealing” transactions or engages in a merger or other business combination in which Contango
survives and its shares of common stock remain outstanding, the other Contango stockholders will be able to
exercise the Rights and buy shares of common stock of Contango having approximately twice the value of the
exercise price of the Rights. Additionally, if Contango is involved in certain other mergers where its shares are
exchanged or certain major sales of its assets occur, Contango stockholders will be able to purchase a certain
number of the other party’s common stock in an amount equal to approximately twice the value of the exercise
price of the Rights.

Contango will be entitled to redeem the Rights at $0.01 per Right at any time until the earlier of (i) the

tenth day following public announcement that a person has acquired a 20% ownership position in shares of
common stock of Contango or (ii) the final expiration date of the Rights. Contango in its discretion may
extend the period during which it may redeem the Rights.

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 2010 Annual Meeting of
Stockholders (the “Proxy Statement”) under the headings “Election of Directors”, “Executive Compensation”,
“Section 16(a) Beneficial Ownership Reporting Compliance” and “Corporate Governance” and is incorporated
herein by reference. The Proxy Statement will be filed with the SEC pursuant to Regulation 14A of the
Exchange Act, not later than 120 days after June 30, 2010.

Item 11. Executive Compensation

The information required under Item 11 of Form 10-K will be contained in the Proxy Statement under

the heading “Executive Compensation” and is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder

Matters

The information required under Item 12 of Form 10-K will be contained in the Proxy Statement under

the heading “Security Ownership of Certain Other Beneficial Owners and Management” and is incorporated
herein by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required under Item 13 of Form 10-K will be contained in the Proxy Statement under

the heading “Certain Relationships and Related Transactions, and Director Independence” and “Executive
Compensation” and is incorporated herein by reference.

Item 14. Principal Accountant Fees and Services

The information required under Item 14 of Form 10-K will be contained in the Proxy Statement under

the heading “Principal Accountant Fees and Services” and is incorporated herein by reference.

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) Financial Statements and Schedules:

The financial statements are set forth in pages F-1 to F-22 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

2.2

2.3

2.4

2.5

3.1
3.2
3.3

Description
Purchase and Sale Agreement, by and between Juneau Exploration, L.P. and REX Offshore
Corporation, dated as of September 1, 2005. (11)
Purchase and Sale Agreement, by and between Juneau Exploration, L.P. and COE Offshore, LLC dated
as of September 1, 2005. (11)
Asset Purchase Agreement by and among Petrohawk Energy Corporation and Contango Operators Inc.
(successor-in-interest to Contango Gas Solutions, L.P.), Alta Resources, L.L.C., GPM Energy, LLC,
MND Partners, L.P. and Tepee Petroleum Company, Inc., dated as of November 26, 2007. (17)
Asset Purchase Agreement by and among XTO Energy Inc. and Contango Operators, Inc., Alta
Resources, L.L.C., GPM Energy, LLC, MND Partners, L.P. and Tepee Petroleum Company, Inc., dated
as of January 4, 2008. (18)
Partnership Interest Purchase Agreement by and among Turbo LNG LLC, Contango Sundance, Inc. and
Osaka Gas Co., Ltd., as Guarantor, dated January 7, 2008. (19)
Certificate of Incorporation of Contango Oil & Gas Company. (5)
Bylaws of Contango Oil & Gas Company. (5)
Agreement of Plan of Merger of Contango Oil & Gas Company, a Delaware corporation, and Contango

4.5

4.4

10.5

4.3

10.4

10.2

10.3

10.1

3.4
4.1
4.2

Oil & Gas Company, a Nevada corporation. (5)
Amendment to the Certificate of Incorporation of Contango Oil & Gas Company. (8)
Facsimile of common stock certificate of Contango Oil & Gas Company. (1)
Certificate of Designations, Preferences and Relative Rights and Limitations for Series E Perpetual
Cumulative Convertible Preferred Stock of Contango Oil & Gas Company. (14)
Securities Purchase Agreement, dated as of May 11, 2007, among Contango Oil & Gas Company and
the Purchasers Named Therein, relating to the Series E Perpetual Cumulative Convertible Preferred
Stock. (14)
Certificate of Designation of Series F Junior Preferred Stock of Contango Oil & Gas Company dated
September 30, 2008. (25)
Rights Agreement, dated as of September 30, 2008, between Contango Oil & Gas Company and
Computershare Trust Company, N.A., as Rights Agent. (25)
Agreement, dated effective as of September 1, 1999, between Contango Oil & Gas Company and
Juneau Exploration, L.L.C. (2)
Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company
and Trust Company of the West. (3)
Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company
and Fairfield Industries Incorporated. (3)
Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company
and Juneau Exploration Company, L.L.C. (3)
Amendment dated August 14, 2000 to agreement between Contango Oil & Gas Company and Juneau
Exploration Company, LLC. dated effective as of September 1, 1999. (4)
Asset Purchase Agreement by and among Juneau Exploration, L.P. and Contango Oil & Gas Company
dated January 4, 2002. (6)
Asset Purchase Agreement by and among Mark A. Stephens, John Miller, The Hunter Revocable Trust,
Linda G. Ferszt, Scott Archer and the Archer Revocable Trust and Contango Oil & Gas Company dated
January 9, 2002. (7)
Freeport LNG Development, L.P. Amended and Restated Limited Partnership Agreement dated
February 27, 2003. (10)
Partnership Purchase Agreement among Contango Sundance, Inc., Contango Oil & Gas, Cheniere LNG,
Inc. and Cheniere Energy, Inc. dated March 1, 2003. (10)
First Amendment, dated December 19, 2003, to Freeport LNG Development, L.P. Amended and
Restated Limited Partnership Agreement dated February 27, 2003. (10)
Limited Liability Company Agreement of Republic Exploration LLC dated August 24, 2000. (11)
Amendment to Limited Liability Company Agreement and Additional Agreements of Republic
Exploration LLC dated as of September 1, 2005. (11)
Limited Liability Company Agreement of Contango Offshore Exploration LLC dated November 1,
2000. (11)
First Amendment to Limited Liability Company Agreement and Additional Agreements of Contango
Offshore Exploration LLC dated as of September 1, 2005. (11)
10.15* Contango Oil & Gas Company 1999 Stock Incentive Plan. (12)
10.16* Amendment No. 1 to Contango Oil & Gas Company 1999 Stock Incentive Plan dated as of March 1,

10.11
10.12

10.14

10.10

10.13

10.7

10.9

10.8

10.6

10.17

10.18
10.19

10.20
10.21

10.22

10.23

10.24

2001. (12)
Term Loan Agreement between Contango Oil & Gas Company and The Royal Bank of Scotland plc,
dated April 27, 2006. (13)
Demand Promissory Note dated October 26, 2006 with Schedules I, II and III. (15)
Term Loan Agreement between Contango Oil & Gas Company and Centaurus Capital LLC, dated
January 30, 2007. (16)
Form of Pledge Agreement. (16)
Assignment of Operating Rights Interest between CGM, LP and Contango Operators, Inc., dated as of
January 3, 2008. (20)
Partial Assignment of Oil and Gas Leases between CGM, LP and Contango Operators, Inc., dated as of
January 3, 2008. (20)
Assignment of Operating Rights Interest between CGM, LP and Contango Operators, Inc., dated as of
January 3, 2008. (20)
Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango

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

10.39

10.40

10.41

10.42

10.43

10.44

10.45

10.46

10.47

10.48

Operators, Inc., dated as of January 3, 2008. (20)
Partial Assignment of Oil and Gas Leases between Olympic Energy Partners, LLC and Contango
Operators, Inc. dated as of January 3, 2008. (20)
Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango
Operators, Inc., dated as of January 3, 2008. (20)
Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc.,
dated as of January 3, 2008. (20)
Partial Assignment of Oil and Gas Leases between Juneau Exploration, LP and Contango Operators,
Inc., dated as of January 3, 2008. (20)
Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc.,
dated as of January 3, 2008. (20)
Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc.,
dated as of April 3, 2008. (22)
Partial Assignment of Oil and Gas Leases between Juneau Exploration, LP and Contango Operators,
Inc., dated as of April 3, 2008. (22)
Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc.,
dated as of April 3, 2008. (22)
Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango
Operators, Inc., dated as of April 3, 2008. (22)
Partial Assignment of Oil and Gas Leases between Olympic Energy Partners, LLC and Contango
Operators, Inc. dated as of April 3, 2008. (22)
Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango
Operators, Inc., dated as of April 3, 2008. (22)
Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP
and Contango Operators, Inc., dated as of February 8, 2008. (24)
Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP
and Contango Operators, Inc., dated as of February 8, 2008. (24)
Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP
and Contango Operators, Inc., dated as of February 8, 2008. (24)
Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP
and Contango Operators, Inc., dated as of February 8, 2008. (24)
Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP
and Contango Operators, Inc., dated as of February 8, 2008. (24)
Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP
and Contango Operators, Inc., dated as of February 8, 2008. (24)
Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP
and Contango Operators, Inc., dated as of February 8, 2008. (24)
Amended and Restated Limited Liability Company Agreement of Republic Exploration LLC, dated
April 1, 2008. (22)
Amended and Restated Limited Liability Company Agreement of Contango Offshore Exploration LLC,
dated April 1, 2008. (24)
Third Amendment to Term Loan Agreement, dated as of January 17, 2008, between Contango Oil &
Gas Company, as Borrower, and Centaurus Capital LLC, as Lender. (21)
Fourth Amendment to Term Loan Agreement, dated as of February 13, 2008, between Contango Oil &
Gas Company, as Borrower, and Centaurus Capital LLC, as Lender. (23)
Amended and Restated Term Loan Agreement, dated June 5, 2008, between Contango Oil & Gas
Company, as Borrower, and Centaurus Capital LLC, as Lender. (24)
$50,000,000 Amended and Restated Credit Agreement dated as of March 31, 2009 among Contango Oil
& Gas Company, Contango Energy Company and Contango Operators Inc. as Borrowers, Guaranty
Bank, as administrative agent and issuing lender, and the lenders party thereto from time to time. (26)

10.49 * Contango Oil & Gas Company Annual Incentive Plan. †
10.50 * Contango Oil & Gas Company 2009 Equity Compensation Plan. †
10.51

Conterra Joint Venture Development Agreement effective October 1, 2009 between Conterra Company
and Patara Oil & Gas LLC. (27)
Code of Ethics. (12)
List of Subsidiaries. †

14.1
21.1

21.2
23.1
23.2
23.3
31.1

31.2

32.1

32.2

Organizational Chart. †
Consent of William M. Cobb & Associates, Inc. †
Consent of Grant Thornton LLP. †
Consent of Lonquist & Co. LLC. †
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 Lonquist & Co. LLC. †

99.1
99.2
__________
† Filed herewith.
* Indicates a management contract or compensatory plan or arrangement.

1. 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.

2. Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended December 31, 1999, as filed

with the Securities and Exchange Commission on November 11, 1999.

3. Filed as an exhibit to the Company’s report on Form 8-K, dated August 24, 2000, as filed with the Securities and

Exchange Commission of September 8, 2000.

4. Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2000, as

filed with the Securities and Exchange Commission on September 27, 2000.

5. 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.

6. Filed as an exhibit to the Company’s report on Form 8-K, dated January 4, 2002, as filed with the Securities and

Exchange Commission on January 8, 2002.

7. Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended March 31, 2002, as filed with

the Securities and Exchange Commission on February 14, 2002.

8. 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.

9. Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2003, as

filed with the Securities and Exchange Commission on September 22, 2003.

10. Filed as an exhibit to the Company’s report on Form 8-K, dated December 19, 2003, as filed with the Securities

and Exchange Commission on December 23, 2003.

11. 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.

12. Filed as an exhibit to the Company’s report on Form 10-K for the fiscal year ended June 30, 2005, as filed

with the Securities and Exchange Commission on September 13, 2005.

13. Filed as Exhibit 10.1 to the Company’s report on Form 10-Q for the quarter ended March 31, 2006, dated

May 15, 2006, as filed with the Securities and Exchange Commission.

14. Filed as an exhibit to the Company’s report on Form 8-K, dated May 11, 2007, as filed with the Securities and

Exchange Commission on May 17, 2007.

15. Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended September 30, 2006, dated

November 8, 2006, as filed with the Securities and Exchange Commission.

16. Filed as an exhibit to the Company’s report on Form 8-K, dated January 30, 2007, as filed with the Securities and

Exchange Commission on February 5, 2007.

17. Filed as an exhibit to the Company’s report on Form 8-K, dated November 26, 2007, as filed with the Securities

and Exchange Commission on November 29, 2007.

18. Filed as an exhibit to the Company’s report on Form 8-K, dated January 4, 2008, as filed with the Securities and

Exchange Commission on January 10, 2008.

19. Filed as an exhibit to the Company’s report on Form 8-K, dated February 5, 2008, as filed with the Securities and

Exchange Commission on February 8, 2008.

20. Filed as an exhibit to the Company’s report on Form 8-K, dated January 3, 2008, as filed with the Securities and

Exchange Commission on January 9, 2008.

21. Filed as an exhibit to the Company’s report on Form 8-K, dated January 17, 2008, as filed with the Securities and

Exchange Commission on January 24, 2008.

22. 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.

23. Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended March 31, 2008, as filed with the

Securities and Exchange Commission on May 12, 2008.

24. Filed as an exhibit to the Company’s report on Form 10-K for the fiscal year ended June 30, 2008, as filed

with the Securities and Exchange Commission on August 29, 2008.

25. Filed as an exhibit to the Company’s report on Form 8-K, dated September 30, 2008, as filed with the Securities

and Exchange Commission on October 1, 2008.

26. Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended March 31, 2009, as filed with the

Securities and Exchange Commission on May 11, 2009.

27. Filed as an exhibit to the Company’s report on Form 8-K, dated October 22, 2009, as filed with the Securities and

Exchange Commission on October 28, 2009.

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to

be signed on its behalf by the undersigned, thereunto duly authorized.

CONTANGO OIL & GAS COMPANY

/s/ KENNETH R. PEAK /s/ SERGIO CASTRO /s/ YAROSLAVA MAKALSKAYA
Kenneth R. Peak Sergio Castro
Chief Executive Officer Chief Financial Officer Vice President and Controller
(principal executive officer) (principal financial officer) (principal accounting officer)

Yaroslava Makalskaya

In accordance with the Exchange Act, this report has been signed below by the following persons on

behalf of the registrant and in the capacities and on the dates indicated.

Name

Title

Date

/s/ KENNETH R. PEAK
Kenneth R. Peak

/s/ B.A. BERILGEN
B.A. Berilgen

/s/ JAY D. BREHMER
Jay D. Brehmer

/s/ CHARLES M. REIMER
Charles M. Reimer

/s/ STEVEN L. SCHOONOVER
Steven L. Schoonover

Chairman of the Board

September 13, 2010

Director

September 13, 2010

Director

September 13, 2010

Director

September 13, 2010

Director

September 13, 2010

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Page

Report of Independent Registered Public Accounting Firm ....................................................................... F-2

Consolidated Balance Sheets as of June 30, 2010 and 2009 ...................................................................... F-3

Consolidated Statements of Operations for the Years Ended June 30, 2010, 2009 and 2008 .................... F-5

Consolidated Statements of Cash Flows for the Years Ended June 30, 2010, 2009 and 2008 ................... F-6

Consolidated Statement of Shareholders’ Equity for the Years

Ended June 30, 2010, 2009 and 2008 .................................................................................................. F-7

Notes to Consolidated Financial Statements .............................................................................................. F-8

Supplemental Oil and Gas Disclosures (Unaudited) .................................................................................. F-23

Quarterly Results of Operations (Unaudited) ............................................................................................. F-27

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 as of June 30, 2010 and 2009, and the related consolidated
statements of operations, shareholders’ equity and cash flows for each of the three years in the period ended
June 30, 2010. These financial statements are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects,
the financial position of Contango Oil & Gas Company and subsidiaries as of June 30, 2010 and 2009, and
the results of their operations and their cash flows for each of the three years in the period ended June 30,
2010 in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), Contango Oil & Gas Company and subsidiaries’ internal control over
financial reporting as of June 30, 2010, based on criteria established in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)
and our report dated September 13, 2010 expressed an unqualified opinion on the internal control over
financial reporting.

As discussed in Note 2 to the consolidated financial statements, the Company has changed its
reserve estimates and related disclosures as a result of adopting new oil & gas reserve estimation and
disclosure requirements as of June 30, 2010.

/s/ GRANT THORNTON LLP
Houston, Texas
September 13, 2010

F-2

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

ASSETS

June 30,

2010

2009

CURRENT ASSETS:

Cash and cash equivalents…………………………………..……………………… 52,469,144
Accounts receivable:
Trade receivable…………………………………………………………………… 41,938,567
Advances to affiliates………………………………………………………………
Joint interest billings……………………………………………………………… 11,758,980
Severance taxes receivable…………………………………………………………
Income taxes……………………………………………………………………...
5,410,577
Other receivable….………………………………………………………………… 3,164,604
Notes receivable……………………………………………………………………… 2,027,590
Other.………………………………………………………….……………………… 3,103,927
Total current assets……………………………………………….………………… 119,873,389

44,371,324

32,809,165
5,494,747
4,515,660
3,528,402
4,221,644
824,197
-
710,333
96,475,472

PROPERTY, PLANT AND EQUIPMENT:

Natural gas and oil properties, successful efforts method of accounting:

Proved properties………………………………………………...………………… 540,215,841
Unproved properties……………………………….……………………………… 10,825,074
Furniture and equipment………………………………………….…………………
276,817
Accumulated depreciation, depletion and amortization……………………………… (78,998,049)
Total property, plant and equipment, net……………………….………………… 472,319,683

460,881,471
2,911,258
273,185
(44,952,301)
419,113,613

OTHER ASSETS:

Cash and other assets held by affiliates……...………...………………………..……
Other…………………………………………………………………………………
Total other assets………………………………………..…………………………

39,731
32,944
72,675
TOTAL ASSETS…………………………………………………….………………… 592,265,747

1,128,110
324,712
1,452,822
517,041,907

The accompanying notes are an integral part of these consolidated financial statements.

F-3

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDERS’ EQUITY

June 30,

2010

2009

CURRENT LIABILITIES:
Accounts payable………………………………………….………………………… 34,219,769
Royalties and working interests payable……………………………………………… 30,774,444
2,647,435
Accrued liabilities……………………………………………………………………
Joint interest advances…………………………………………………………………
739,464
Accrued exploration and development……………….……………………………… 9,263,438
-
Debt of affiliates………………………………………………………………………
Income tax payable……………………………………………………………………
843,755
Total current liabilities……………………………………...……………………… 78,488,305

8,812,677
32,781,712
3,867,579
4,056,991
120,300
3,604,609

53,243,868

DEFERRED TAX LIABILITY………………………………………………………… 131,290,992
ASSET RETIREMENT OBLIGATION………..……………………………………… 5,156,642

110,964,147
3,469,624

COMMITMENTS AND CONTINGENCIES (NOTE 14)

SHAREHOLDERS' EQUITY:

Common stock, $0.04 par value, 50,000,000 shares authorized,

19,982,563 shares issued and 15,684,666 outstanding at June 30, 2010,
19,638,334 shares issued and 15,828,980 outstanding at June 30, 2009,

799,300
Additional paid-in capital…………………………………………..………………… 77,967,702
Treasury stock at cost (4,297,897 and 3,809,354 shares, respectively)……………… (82,019,429)
Retained earnings…………..………………………………………...……………… 380,582,235
Total shareholders' equity………………………………………………………… 377,329,808
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY………………………… 592,265,747

785,533
76,321,911
(58,639,644)
330,896,468
349,364,268
517,041,907

The accompanying notes are an integral part of these consolidated financial statements.

F-4

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

REVENUES:

Natural gas and oil sales…………………………..………… 160,680,691
Total revenues……………………………………….…… 160,680,691

190,655,605
190,655,605

116,497,713
116,497,713

Year Ended June 30,

2010

2009

2008

EXPENSES:

Operating expenses……………………...………………… 17,039,599
Exploration expenses……………………………………… 21,938,539
Depreciation, depletion and amortization…………………… 35,373,873
Lease expirations and relinquishments………………………
951,582
Impairment of natural gas and oil properties………………
General and administrative expense………….……………

4,615,512
Total expenses…………………………………………… 79,919,105

23,684,159
20,602,915
32,673,191
5,208,491
5,866,287
9,467,113
97,502,156

6,776,757
5,728,600
11,899,620
642,374
-

16,928,760
41,976,111

INCOME FROM CONTINUING OPERATIONS
BEFORE OTHER INCOME AND INCOME TAXES……… 80,761,586

93,153,449

74,521,602

OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized……………………
Interest income……...………………………………………..
Gain (loss) on sale of assets and other…………………………
INCOME FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES………………………………… 81,272,349
Provision for income taxes…………………...……………… (31,586,582)

(517,550)
915,445
112,868

INCOME FROM CONTINUING OPERATIONS…………… 49,685,767
DISCONTINUED OPERATIONS (Note 6)
Discontinued operations, net of income taxes……………

NET INCOME……………………..………………..…….… 49,685,767
Preferred stock dividends…………………………….………
NET INCOME ATTRIBUTABLE
TO COMMON STOCK……………………………………… 49,685,767

(741,011)
925,505
(530,260)

(3,933,309)
1,969,145
62,314,188

92,807,683
(36,946,481)

134,871,626
(51,650,422)

55,861,202

83,221,204

173,685,065

55,861,202

256,906,269
1,547,777

55,861,202

255,358,492

NET INCOME PER SHARE:

Basic
Continuing operations……………………………………
Discontinued operations…………………………………
Total………………………………………………………
Diluted
Continuing operations……………………………………
Discontinued operations…………………………………
Total………………………………………………………

3.14
-
3.14

3.08
-
3.08

3.41
-
3.41

3.35
-
3.35

5.05
10.73
15.78

4.82
10.06
14.88

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:

Basic……………………………………………………...… 15,830,529
Diluted…………………………………………..…………… 16,157,030

16,362,719
16,690,426

16,184,517
17,262,715

The accompanying notes are an integral part of these consolidated financial statements.

F-5

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended June 30,

2010

2009

2008

CASH FLOWS FROM OPERATING ACTIVITIES:
Income from continuing operations…………………………………………………………………
Plus income from discontinued operations, net of income taxes……………………………………

49,685,767

55,861,202

83,221,204
173,685,065

Net income……………………………………………………………………………………………
Adjustments to reconcile net income to net cash provided by operating activities:

49,685,767

55,861,202

256,906,269

Depreciation, depletion and amortization………………………………………………………
Impairment / expiration of natural gas and oil properties………………………………………
Exploration expenditures………………………….……………………………………..………
Deferred income taxes…………………………………………………………..…..……………
Gain on sale of assets…………………………………………………………..………………
Stock-based compensation………………….……………………………………………………
Tax benefit from exercise of stock options………………………………………………………
Changes in operating assets and liabilities:

35,373,873
951,582
20,502,517
19,398,868
(112,868)
667,077
(79,283)

32,673,191
11,074,778
19,038,463
(1,225,537)

1,381,797
(264,187)

Decrease (increase) in accounts receivable and other…………………………………………
Increase in notes receivable……………………………………………………………………
Increase in prepaid insurance and other receivable……………………………………………
Increase in inventory…………………………………………………………………………
Increase (decrease) in accounts payable and advances from joint owners……………………
Increase (decrease) in other accrued liabilities……………………………..…………………
Increase (decrease) in income taxes receivable, net…………………………………………
Other………………………………………………………...…………………...……………

(9,129,402)

39,688,876

(3,233,931)
(470,318)
14,846,244
300,990
662,072
(1,175,512)

-
(19,366)
-

(11,597,588)
(43,819,351)
(7,420,632)

15,173,285
1,234,111
4,747,798
115,952,055
(326,337,749)
1,476,988
(1,080,562)

(67,279,024)
(250,000)
(447,202)
-

26,152,482
75,997,351
7,210,622
3,286,631

Net cash provided by operating activities………………………………………………..… 128,187,676

95,371,646

112,743,055

CASH FLOWS FROM INVESTING ACTIVITIES:

Natural gas and oil exploration and development expenditures…………….……………………
Sale of short-term investments, net…………………………………………………………………
Additions to furniture and equipment………………………………………………………………
Investment in Contango Venture Capital Corporation……………………………………………
Acquisition of natural gas and oil producing properties…………………………………….……
Sale/Acquisition costs………………………………………………………………………………
Proceeds from the sale of assets……………..…………………………………………..…………

(97,698,930)

(45,741,659)

-
(3,632)
-
-
-
-

-
(16,025)
-
-
-
-

(119,928,546)
2,200,576
(43,225)
(1,166,624)
(309,000,000)
(7,847,613)
396,925,821

Net cash used in investing activities…………………………………………..………………… (97,702,562)

(45,757,684)

(38,859,611)

CASH FLOWS FROM FINANCING ACTIVITIES:

Borrowings under credit facility………………………………………………………………..…
Repayments under credit facility………………………………………………………………..…
Borrowings (repayments) by affiliates……………………………………………………………
Preferred stock dividends……………………………………………………………………...…
Repurchase/cancellation of stock options…………………………………………………………
Purchase of common stock………………………………………………………………………… (23,379,775)
913,198
Proceeds from exercised options…………………………………………………………………
79,283
Tax benefit from exercise/cancellation of stock options…………………………………………
-
Debt issuance costs…………………………………………………………………………..……

-
-
-
-
-

(15,000,000)

-
-
-

(51,795,744)
1,654,345
264,187
(250,000)

35,000,000
(40,000,000)
(8,540,091)
(1,547,777)
(5,922,532)
(663,900)
580,760
1,080,562
(163,510)

Net cash used in financing activities…………………………………...………………………

(22,387,294)

(65,127,212)

(20,176,488)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS…………………………
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD…………………………………

8,097,820
44,371,324

(15,513,250)
59,884,574

53,706,956
6,177,618

CASH AND CASH EQUIVALENTS, END OF PERIOD…………………………………………

52,469,144

44,371,324

59,884,574

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:

Cash paid for taxes, net of cash received…………………………………………………………
Cash paid for interest………………………………………………………………………………

$
$

11,535,121
250,000

$
$

45,592,652
397,579

$
$

21,974,825
4,305,336

SUPPLEMENTAL NON-CASH ACTIVITY:

Increase in non-recourse demand promissory note…..……………………………………………

2,027,590

$
-

The accompanying notes are an integral part of these consolidated financial statements.

F-6

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

Preferred Stock

Common Stock

Amount

Paid-in

Capital

Comprehensive

Treasury

Income

Stock

Retained

Earnings

Shareholders'

Comprehensive

Equity

Income

Accumulated

Other

Total

Balance at June 30, 2007………….……… ………………………… 6,000

240

15,964,807

741,591

75,849,506

715,659

(6,180,000)

19,676,774

90,803,770

Exercise of stock options……………………………………………

Tax benefit from exercise of stock options…………………………

Cancellation of stock options, net of tax benefit of $468,836 ………

Treasury shares at cost………………………………………………

Amortization of restricted stock……………………………………

Conversion of Series E preferred stock

71,000

2,840

(10,000)

4,471

179

252,257

to common stock………………………………………………… (6,000)

(240)

789,468

31,579

577,920

611,726

(5,453,696)

(31,339)

1,224,552

(715,659)

(663,900)

580,760

611,726

(5,453,696)

(663,900)

252,436

1,224,552

256,906,269

(1,547,777)

(715,659)

256,190,610

Expense of stock options ……………………………………………

Net income…………………………………….……………………

Preferred stock dividends…………….………………………………

Unrealized gain on available for sale securities, net of tax…………

Comprehensive income………………………………………………

Balance at June 30, 2008………….……… …………………………

Exercise of stock options……………………………………………

Tax benefit from exercise of stock options…………………………

Amortization of restricted stock……………………………………

Treasury shares at cost………………………………………………

Expense of stock options ……………………………………………

Net income…………………………………….……………………

Balance at June 30, 2009………….……… …………………………

Exercise of stock options……………………………………………

Tax benefit from exercise of stock options…………………………

Amortization of restricted stock……………………………………

Treasury shares at cost………………………………………………

Expense of stock options ……………………………………………

Net income…………………………………….……………………

Balance at June 30, 2010………….……… …………………………

$
-

16,819,746

776,189

73,030,926

$
-

(6,843,900)

275,035,266

341,998,481

230,500

3,088

(1,224,354)

9,220

124

1,645,125

264,187

240,457

1,141,216

(51,795,744)

55,861,202

1,654,345

264,187

240,581

(51,795,744)

1,141,216

55,861,202

$
-

15,828,980

785,533

76,321,911

$
-

(58,639,644)

330,896,468

349,364,268

344,229

13,767

(488,543)

899,431

79,283

72,182

594,895

(23,379,785)

49,685,767

913,198

79,283

72,182

(23,379,785)

594,895

49,685,767

$
-

15,684,666

799,300

77,967,702

$
-

(82,019,429)

380,582,235

377,329,808

The accompanying notes are an integral part of this consolidated financial statement.

F-7

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-based, independent natural gas and oil company. The Company’s business is to explore, develop, produce
and acquire natural gas and oil properties primarily offshore in the Gulf of Mexico.

2. Summary of Significant Accounting Policies

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 income taxes, stock-based compensation, reserve estimates and impairment of natural
gas and oil properties. 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, an overproduced imbalance occurs. To the extent the
overproduced imbalance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a
given property, the Company records a liability. At June 30, 2010 and 2009, 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 June 30, 2010, the Company had $52.5 million in cash and
cash equivalents. Of this amount, approximately $31.7 million was invested in U.S. Treasury money market funds
and the remaining $20.8 million was invested in overnight U.S. Treasury funds.

Accounts Receivable. The Company sells natural gas and crude oil to a limited number of customers. In

addition, the Company participates with other parties in the operation of natural gas and crude oil wells.
Substantially all of the Company’s accounts receivables are due from either purchasers of natural gas and crude oil
or participants in natural gas and crude oil wells for which the Company serves as the operator. Generally, operators
of natural gas and crude oil properties have the right to offset future revenues against unpaid charges related to
operated wells.

The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The

Company periodically reviews the accounts receivable from customers for any collectability issues. An allowance
for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience,
current economic conditions, and other pertinent factors. Amounts deemed uncollectible are charged to the
allowance.

Accounts receivable allowance for bad debt was $0 at June 30, 2010 and 2009. At June 30, 2010 and 2009,

the carrying value of the Company’s accounts receivable approximated fair value.

Net Income (Loss) per Common Share. Basic net income (loss) per common share is computed by dividing

income (loss) attributable to common stock by the weighted average number of common shares outstanding for the
period. Diluted net income per common share reflects the potential dilution that could occur if securities or other
contracts to issue common stock were exercised or converted into common stock. See Note 8 – Net Income Per
Common Share for the calculations of basic and diluted net income per common share.

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

DB2/21043537.7

F-8

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

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 June 30, 2010. The amount of unrecognized tax benefits did not
materially change as of June 30, 2010. The amount of unrecognized tax benefits may change in the next twelve
months; however, we do not expect the change to have a significant impact on our results of operations or our
financial position or results of operations. The Company includes interest and penalties in interest income and
general and administrative expenses, respectively, in its statement of operations.

The Company files income tax returns in the United States and various state jurisdictions. The Company’s

tax returns for 2007, 2008 and 2009 remain open for examination by the taxing authorities in the respective
jurisdictions where those returns were filed.

Concentration of Credit Risk. Substantially all of the Company’s accounts receivable result from natural

gas and oil sales or joint interest billings to a limited number of third parties in the natural gas and oil industry. This
concentration of customers and joint interest owners may impact the Company’s overall credit risk in that these
entities may be similarly affected by changes in economic and other conditions.

Consolidated Statements of Cash Flows. For the purpose of cash flows, the Company considers all highly
liquid investments with a maturity date of three months or less when purchased to be cash equivalents. Significant
transactions may occur that do not directly affect cash balances and, as such, are not disclosed in the Consolidated
Statements of Cash Flows. Certain such non-cash transactions are disclosed in the Consolidated Statements of
Shareholders’ Equity, including shares issued as compensation and issuance of stock options.

Fair Value of Financial Instruments. The carrying amounts of the Company’s short-term financial

instruments, including cash equivalents, short-term investments, trade accounts receivable and accounts payable,
approximate their fair values based on the short maturities of those instruments.

Successful Efforts Method of Accounting. 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. Unproved properties are reviewed quarterly to determine if there has been
impairment of the carrying value, and any such impairment is charged to expense in the period. 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.

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 future
undiscounted cash flows, based on the Company’s estimate of future reserves, natural gas and oil prices and
operating costs and anticipated production levels from oil and natural gas reserves, are lower than the unamortized
capitalized cost, then the capitalized cost is reduced to its fair value.

Impairment of Long-Lived Assets. The Company did not report an impairment charge for the year ended

June 30, 2010 or 2008. For the fiscal year ended June 30, 2009, the Company’s analysis determined that Grand Isle
70 and Grand Isle 72 were impaired. The Company recorded an impairment charge of approximately $2.5 million
and $3.4 million, respectively, related to these wells. Additionally, the Company recorded $5.2 million in lease
expiration and relinquishment expense related to the expiration and relinquishment of 44 lease blocks owned by our
partially-owned affiliate, Republic Exploration LLC (“REX”), and Contango Offshore Exploration LLC (“COE”).

For the fiscal year ended June 30, 2008, the Company classified the following asset sales as discontinued
operations: its $128.0 million Western core Arkansas Fayetteville Shale sale effective October 1, 2007, its $199.2

F-9

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

million Eastern core Arkansas Fayetteville Shale sale effective December 1, 2007, and its $1.1 million Alta-Ellis #1
and Temple Inland sale effective February 1, 2008. An integral and on-going part of our business strategy is to sell
our proved reserves from time to time in order to generate additional capital to reinvest in our onshore and offshore
exploration programs.

Principles of Consolidation. The Company’s consolidated financial statements include the accounts of

Contango Oil & Gas Company and its wholly and partially-owned subsidiaries, after elimination of all intercompany
balances and transactions. Wholly-owned subsidiaries are fully consolidated. Exploration and development
affiliates not wholly owned, such as REX, are not controlled by the Company and are proportionately consolidated.

For the periods ending June 30, 2008 and June 30, 2009, the company also proportionately consolidated the

results of COE. Effective June 1, 2010 COE was dissolved, and all assets and liabilities owned by COE were
distributed to its members.

Contango’s 19.5% ownership of Moblize Inc. (“Moblize”) is accounted for using the cost method. Under

the cost method, Contango records an investment in the stock of an investee at cost, and recognizes dividends
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. In fiscal year 2010, the Company
recognized a $190,000 impairment of its investment in Moblize.

Reclassifications. Certain reclassifications have been made to the fiscal year 2009 and 2008 amounts in

order to conform with the 2010 presentation. These reclassifications were not material.

Recent Accounting Pronouncements In February 2010, the Financial Accounting Standards Board
(“FASB”) amended its guidance on subsequent events to remove the requirement for SEC filers to disclose the date
through which an entity has evaluated subsequent events. The guidance was effective upon issuance. We adopted
this guidance for the fiscal year ended June 30, 2010.

In January 2010, the FASB adopted the SECs changes to modernize the oil and gas company reserve

reporting requirements. The most significant amendments to the requirements include the following:

• Commodity Prices – Economic producibility of reserves and discounted cash flows will be based on a 12-
month average commodity price calculated as the un-weighted arithmetic average of the first-day-of-the-
month price for each month within the 12-month period prior to the end of the reporting period, unless
contractual arrangements designate the price to be used.

• Proved Undeveloped Reserve Guidelines – Reserves may be classified as proved undeveloped if there is a

high degree of confidence that the quantities will be recovered.

• Reserve Personnel and Estimation Process – Additional disclosure is required regarding the qualifications
of the chief technical person who oversees our reserves estimation process. We will also be required to
provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.

The Company adopted the new rules effective June 30, 2010, and as a result, it (i) prepared its reserve
estimates as of June 30, 2010 based on the new reserves definitions, (ii) has estimated its June 30, 2010 reserve
quantities using the 12-month average price and (iii) included additional disclosures as required by the new rule. As
a result of the change in reserve pricing from year-end oil and gas prices to now using the 12-month average prices,
the Company’s total proved reserves at June 30, 2010 were 3.8 Bcfe higher than they would have otherwise been if
year-end oil and gas prices were used. Oil and gas reserve quantities or their values are a significant component of
the Company’s depreciation, depletion and amortization (“DD&A”), asset retirement obligation, and impairment
analysis. The Company’s adoption of the SEC’s Modernization of Oil and Gas Reporting: Final Rule had an
immaterial impact on the Company’s DD&A expense, asset retirement obligation, and impairment analysis.

F-10

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

Effective July 1, 2009, the Company adopted new accounting guidance on fair value measurements which

require additional disclosures about the Company’s nonfinancial assets and liabilities, which adoption had no impact
on the Company’s financial position, results of operations or cash flows.

In June 2009, the FASB issued new accounting guidance on the FASB Accounting Standards Codification
and the hierarchy of GAAP. This new accounting guidance codifies existing GAAP and recognizes only two levels
of GAAP, authoritative and nonauthoritative. Rules and interpretive releases of the SEC under authority of federal
securities laws are also sources of authoritative GAAP for SEC registrants. This new accounting guidance is
effective for financial statements issued for interim and annual periods ending after September 15, 2009. The
Company’s adoption of this new guidance did not have any impact on its financial position, results of operations or
cash flows.

Stock-Based Compensation. The Company applies the fair value based method to account for stock based

compensation. Under this method, compensation cost is measured at the grant date based on the fair value of the
award and is recognized over the award vesting period. The fair value of each award is estimated as of the date of
grant using the Black-Scholes options-pricing model. The Company also 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 option is estimated as of the date of grant using the Black-Scholes option-pricing model. The
following weighted-average assumptions were used for the 25,000 options granted during the fiscal year ended June
30, 2010 and the 60,000 options granted during the fiscal year ended June 30, 2009: (i) risk-free interest rate of 0.25
percent and 3.01 percent, respectively; (ii) expected life of five years; (iii) expected volatility of 35 percent and 53
percent, respectively and (iv) expected dividend yield of zero percent. No options were granted for the fiscal year
ended June 30, 2008.

The Company did not grant any shares of restricted stock for the fiscal year ended June 30, 2010. During

the fiscal year ended June 30, 2009 and 2008, the Company granted 3,088 shares and 4,140 shares of restricted
stock, respectively, to its Board of Directors as part of its annual compensation. Grants of service-based restricted
stock awards are valued at our common stock price at the date of grant. The shares of restricted stock granted to the
board of directors vested over a period of one year.

During the fiscal years ended June 30, 2010, 2009 and 2008, the Company recorded stock-based
compensation charges of $0.7 million, $1.4 million, and $1.5 million, respectively, to general and administrative
expense for restricted stock and option awards. These amounts do not reflect compensation actually received by the
individuals, but rather represent expense recognized in the Company’s consolidated financial statements that relate
to restricted stock and option awards granted in current and previous fiscal years.

Derivative Instruments and Hedging Activities. The Company did not enter into any derivative
instruments or hedging activities for the fiscal years ended June 30, 2010, 2009 or 2008, nor did we have any open
commodity derivative contracts at June 30, 2010.

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 June 30, 2010 and 2009 were as follows:

F-11

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

Year Ended June 30,

Balance as of July 1………………………………………
Liabilities incurred during period…………………………
Liabilities settled during period…………………………
Accretion…………………………………..………………
Change in estimate………………………………….

Balance as of June 30…………………………………

3. Natural Gas and Oil Exploration and Production Risk

2010
3,469,624
1,665,178
(399,954)
176,737
245,057
5,156,642

2009
1,949,881
853,940
-
159,470
506,333
3,469,624

The Company’s future financial condition and results of operations will depend upon prices received for its

natural gas and oil production and the cost of finding, acquiring, developing and producing reserves. Substantially
all of its production is sold under various terms and arrangements at prevailing market prices. Prices for natural gas
and oil are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors
beyond the Company’s control.

Other factors that have a direct bearing on the Company’s financial condition are uncertainties inherent in
estimating natural gas and oil reserves and future hydrocarbon production and cash flows, particularly with respect
to wells that have not been fully tested and with wells having limited production histories; the timing and costs of
our future drilling; development and abandonment activities; access to additional capital; changes in the price of
natural gas and oil; availability and cost of services and equipment; and the presence of competitors with greater
financial resources and capacity. The preparation of our financial statements in conformity with generally accepted
accounting principles requires us to make estimates and assumptions that affect our reported results of operations,
the amount of reported assets, liabilities and contingencies, and proved natural gas and oil reserves. We use the
successful efforts method of accounting for our natural gas and oil activities.

4. Customer Concentration Credit Risk

The customer base for the Company is concentrated in the natural gas and oil industry. Major purchasers

of our natural gas, oil and natural gas liquids for the fiscal year ended June 30, 2010 were ConocoPhillips Company
(37%), Shell Trading US Company (24%), Atmos Energy Marketing, LLC (16%) and Enterprise Products Operating
LLC (13%). Our sales to these companies are not secured with letters of credit and in the event of non-payment, we
could lose up to two months of revenues. The loss of two months of revenues would have a material adverse effect
on our financial position. There are numerous other potential purchasers of our production.

5. Other Receivable

On February 24, 2010, a dredge contracted by the Army Corps of Engineers to dredge the Atchafalaya

River Channel ruptured the Company’s 20” pipeline that runs from our Eugene Island 11 gathering platform to our
Eugene Island 63 auxiliary platform where our pipeline joins a third-party pipeline that transports our production to
shore. The pipeline was repaired and production resumed on March 31, 2010. We believe the repairs will be
covered by our insurance policy, subject to a deductible, and have recorded a receivable of approximately $3.2
million related to this incident in the Consolidated Balance Sheet as of June 30, 2010.

F-12

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

6. Sale of Properties - Discontinued Operations

The Company did not have any discontinued operations for the fiscal year ended June 30, 2010 or 2009.

During the fiscal year ended June 30, 2008, the Company sold its Arkansas Fayetteville Shale properties,

an on-shore well in Texas and an on-shore well in Louisiana for approximately $328.3 million, in the aggregate,
recognizing a gain of approximately $262.3 million. We classify our property sales as discontinued operations in
our financial statements for all periods presented. The summarized financial results for discontinued operations for
the period ended June 30, 2008 are as follows:

Operating Results:

June 30,

2008

Revenues………………………………………………………………
Operating expenses……………………………………………………
Depletion expenses……………………………………………………
Exploration expenses……………………………………………………
Impairment………………………………………………………………
Gain on sale of discontinued operations………………………………

9,679,330
(1,144,786)
(3,273,655)
(359,888)
(591,737)
262,898,530

Gain before income taxes…………………………………………
Provision for income taxes……………………………………………

267,207,794
(93,522,729)

Gain from discontinued operations, net of income taxes………………

173,685,065

7. Sale of Properties – Other

Freeport LNG Development, L.P.

During the fiscal year ended June 30, 2008, the Company sold its ten percent (10%) limited partnership
interest in Freeport LNG Development L.P. (“Freeport LNG”) to Turbo LNG LLC, an affiliate of Osaka Gas Co.,
Ltd., for $68.0 million, and recognized a pre-tax gain of approximately $63.4 million on the sale. Freeport LNG is a
limited partnership formed to develop, construct and operate a 1.75 billion cubic feet per day (“Bcfd”) liquefied
natural gas (“LNG”) receiving and gasification terminal on Quintana Island, near Freeport, Texas.

Contango Venture Capital Corporation

During the fiscal year ended June 30, 2008, Contango Venture Capital Corporation (“CVCC”), our wholly-

owned subsidiary, sold its direct and indirect investments in several alternative energy investments for
approximately $3.4 million, recognizing a loss of approximately $2.9 million. CVCC’s only remaining investment
is Moblize, Inc. (“Moblize”). As of June 30, 2010, CVCC owned 443,648 shares of Moblize convertible preferred
stock, which represents an approximate 19.5% ownership interest. Moblize develops real time diagnostics and field
optimization solutions for the oil and gas and other industries using open-standards based technologies. During the
fiscal year ended June 30, 2010, the Company recognized an impairment of $190,000 related to its investment in
Moblize, reducing its investment to $0 as of June 30, 2010.

F-13

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

8. Net Income Per Common Share

A reconciliation of the components of basic and diluted net income per common share for the fiscal years

ended June 30, 2010, 2009 and 2008 is presented below:

Income from continuing operations………………...………………………

49,685,767

15,830,529

3.14

Basic Earnings per Share:

Year Ended June 30, 2010

Net

Income

Per

Net income attributable to common stock……………………………………
Effect of Potential Dilutive Securities:

49,685,767

15,830,529

3.14

Stock options…………………………………………………..…………
Shares assumed purchased…………………………………………………
Restricted shares……………………………………………………………

-
-
-

586,318
(260,203)
386

Income from continuing operations…………………………………………

49,685,767

16,157,030

3.08

Diluted Earnings per Share:

Net income attributable to common stock……………………………………

49,685,767

16,157,030

3.08

Income from continuing operations………………...………………………

55,861,202

16,362,719

3.41

Basic Earnings per Share:

Year Ended June 30, 2009

Net

Income

Per

Net income attributable to common stock……………………………………
Effect of Potential Dilutive Securities:

55,861,202

16,362,719

3.41

-
-
-

640,167
(314,004)
1,544

Income from continuing operations…………………………………………

55,861,202

16,690,426

3.35

Diluted Earnings per Share:

Net income attributable to common stock……………………………………

55,861,202

16,690,426

3.35

F-14

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

8. Net Income Per Common Share - continued

Year Ended June 30, 2008

Net Income

Per Share

Income from continuing operations, including preferred dividends…………
Discontinued operations, net of income taxes………………………………

$
$

81,673,427
173,685,065

16,184,517
16,184,517

$
$

5.05
10.73

Basic Earnings per Share:

Net income attributable to common stock…………………………………… 255,358,492
Effect of Potential Dilutive Securities:

16,184,517

15.78

Stock options…………………………………………………..…………
Restricted shares……………………………………………………………
Series E preferred stock……………………………………………………

-
-

1,547,777

448,264
7,570
622,364

Income from continuing operations…………………………………………
Discontinued operations, net of income taxes………………………………

$
$

83,221,204
173,685,065

17,262,715
17,262,715

$
$

4.82
10.06

Diluted Earnings per Share:

Net income attributable to common stock…………………………………… 256,906,269

17,262,715

14.88

Options to purchase 70,000 and 45,000 shares of common stock were outstanding as of June 30, 2010 and
2009, respectively, but were not included in the computation of diluted earnings per share for the fiscal year ended
June 30, 2010 or 2009. These options were excluded because either (i) the options’ exercise price was greater than
the average market price of the common shares, or (ii) application of the treasury method to in-the-money options
made some of the options anti-dilutive. All outstanding options as of June 30, 2008 were included in the
computation of diluted earnings per share for the fiscal year ended June 30, 2008.

9. Change in Ownership of Partially-Owned Subsidiaries and Overriding Royalties

Effective June 1, 2010, COE was dissolved and all assets and liabilities owned by COE were transferred to

its respective members. Contango had a 65.6% equity interest in COE. In connection with its dissolution, COE
distributed its ownership interest in Ship Shoal 263 and all of its unevaluated leases to its members. As a result,
Contango has a working interest of approximately 92.46% and a net revenue interest of approximately 74% in this
well. Additionally, beginning in 2006, COE had borrowed $4.3 million in principal from the Company plus accrued
and unpaid interest of approximately $1.6 million. In connection with the dissolution, the Company assumed its
65.6% of the obligation of COE, while the other member of COE assumed the remaining 34.4%, or approximately
$2 million. This $2 million is reflected as a receivable in the Consolidated Balance Sheet of the Company as of June
30, 2010.

During the fiscal year ended June 30, 2008, the members of REX entered into an Amended and Restated

Limited Liability Company Agreement (the “REX LLC Agreement”), effective as of April 1, 2008, to, among other
things, distribute REX’s interest in Dutch and Mary Rose to the individual members of REX or their designees. In
connection with this distribution, REX repaid in full all amounts owing by REX to a private investment firm under a
$50.0 million demand promissory note with such private investment firm (the “REX Demand Note”), and all
security interests and other liens granted in favor of such private investment firm as security for the obligations
under the REX Demand Note have been released and terminated. The Company’s portion of such repayment was
approximately $22.5 million.

Effective April 1, 2008, in connection with the REX LLC Agreement, the Company sold a portion of its

membership interest in REX to an existing member of REX for approximately $0.8 million. As a result of the sale,
the Company’s equity ownership interest in REX has decreased from 42.7% to 32.3%. Also effective April 1, 2008,
the Company sold a portion of its membership interest in COE to an existing member of COE for approximately
$0.9 million. As a result of the sale, the Company’s equity ownership interest in COE has decreased from 76.0% to
65.6%.

F-15

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

10. Acquisitions

During the fiscal year ended June 30, 2008, the Company acquired additional working interests in the

Eugene Island 10 (“Dutch”) and State of Louisiana (“Mary Rose”) discoveries in a like-kind exchange, using funds
from the sale of its Arkansas Fayetteville Shale properties held by a qualified intermediary. The Company
purchased an additional 12.5 % working interest and 10.0% net revenue interest in Dutch and an additional average
13.67% working interest and 10.0% net revenue interest in Mary Rose from three different companies for $300
million. Of these three companies, one of them was the managing member of REX, who exchanged an ownership
interest in REX for a direct working interest in Dutch and Mary Rose. The Company purchased a 2.45% working
interest in Dutch and a 2.68% working interest in Mary Rose from this company for approximately $58.9 million.
The Company also purchased an additional 0.3% overriding royalty interest in the Dutch and Mary Rose discoveries
for $9.0 million.

11. Series E Perpetual Cumulative Convertible Preferred Stock

During the fiscal year ended June 30, 2007, we sold $30.0 million of our Series E preferred stock to a group

of private investors. Dividends on the Series E preferred stock were paid quarterly in cash at a rate of 6.0% per
annum. During the fiscal year ended June 30, 2008, all Series E preferred stockholders converted their Series E
preferred stock into 789,486 shares of our common stock.

12. Income Taxes

Actual income tax expense from continuing operations differs from income tax expense from continuing
operations computed by applying the U.S. federal statutory corporate rate of 35 percent to pretax income as follows:

Year Ended June 30,

2010

2009

2008

Provision at statutory tax rate……………………………… 28,445,322
State income tax provision, net of federal benefit………… 1,414,744
(465,232)
Permanent differences ……………………………………
2,191,748
Other………………………………………………………

35.0%
1.74%
-0.57%
2.70%

32,482,689
4,120,324
343,468
-

35.0%
4.44%
0.37%
-

47,205,069
1,526,658
2,393,765
524,930

35.0%
1.13%
1.78%
0.39%

Income tax provision…………………………………… 31,586,582

38.87%

36,946,481

39.81%

51,650,422

38.30%

F-16

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

The provision for income taxes for the periods indicated are comprised of the following:

Year Ended June 30,

2010

2009

2008

Current:

Federal…………………………………………………
State……………………………………………………

11,590,121
597,593

31,224,546
6,947,472

25,364,147

Total…………………………………………………

12,187,714

38,172,018

25,364,147

Deferred:

Federal…………………………………………………
State……………………………………………………

18,323,227
1,075,641

(617,027)
(608,510)

23,937,570
2,348,705

Total…………………………………………………

19,398,868

(1,225,537)

26,286,275

Total:

Federal…………………………………………………
State……………………………………………………

29,913,348
1,673,234

30,607,519
6,338,962

49,301,717
2,348,705

Total…………………………………………………

31,586,582

36,946,481

51,650,422

The net deferred tax liability is comprised of the following:

Deferred tax liability:

Net operating loss carryover………………………………
Temporary basis differences in

Year Ended June 30,

2010

2009

2008

$
-

natural gas and oil properties and other………………… (131,290,992)

(110,964,147)

(112,189,684)

Net deferred tax liability

(131,290,992)

(110,964,147)

(112,189,684)

13. Long-Term Debt

On October 3, 2008, the Company and its wholly-owned subsidiaries completed the arrangement of a $50

million hydrocarbon borrowing base secured revolving credit facility pursuant to a credit agreement with BBVA
Compass (successor in interest to Guaranty Bank, as administrative agent and issuing lender) (the “Compass
Agreement”). The credit facility is secured by substantially all of the Company’s assets and is available to fund the
Company’s exploration and development activities, as well as the repurchase of shares of the Company’s common
stock, the payment of dividends, and working capital as needed. Borrowings under the Compass Agreement bear
interest at LIBOR plus 2.0% per annum. The outstanding principal amount and any accrued interest thereon is due
October 3, 2010, and may be prepaid at any time in accordance with the Compass Agreement with no prepayment
penalty. An arrangement fee of 0.5%, or $250,000, was paid in connection with the facility and a commitment fee
of 0.5% is paid on the unused commitment amount. As of June 30, 2010 the Company was in compliance with all
financial covenants, ratios and other provisions of the Compass Agreement. As of June 30, 2010 and 2009, no
amounts had been drawn on the credit facility.

The Compass Agreement contains certain negative covenants that, among other things, restrict or limit our
ability to incur indebtedness, sell certain assets, and pay dividends. Failure to maintain required working capital or
comply with certain covenants in the Compass Agreement could result in a default and funds not being available for
borrowing. As of June 30, 2010, the Company was in compliance with its financial covenants, ratios and other
provisions of the Compass Agreement.

F-17

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

In August 2008, the Company prepaid the $15.0 million it had outstanding under its $30.0 million loan
agreement with a private investment firm (the “Term Loan Agreement”) and terminated the Term Loan Agreement.
In February 2008, using the proceeds from our $68.0 million sale of Freeport LNG, the Company prepaid in full the
$20.0 million it had outstanding under its three-year $20.0 million secured term loan facility with The Royal Bank
of Scotland plc (the “RBS Facility”) and terminated the RBS Facility.

14. Commitments and Contingencies

Operating Leases. Contango leases its office space and certain other equipment and pays delay rentals on

certain oil and gas leases. As of June 30, 2010, minimum future lease payments are as follows:

Fiscal years Ending June 30,

2011………………………………………………………
2012………………………………………………………
2013………………………………………………………
2014………………………………………………………
2015 and thereafter………………………………………

Total

740,952
573,252
510,090
339,560
71,824
2,235,678

The amount incurred under operating leases during the years ended June 30, 2010, 2009 and 2008 was
$160,717, $160,405 and $149,782, respectively. Additionally, the amount incurred for delay rentals during the
years ended June 30, 2010, 2009 and 2008 was approximately $0.5 million, $1.1 million and $0.9 million,
respectively.

15. Stock Based Compensation

The Company’s 1999 Stock Incentive Plan (the “1999 Plan”) expired in August 2009. All 280,334
outstanding options issued under the 1999 Plan will be converted into common shares of the Company if the options
are exercised prior to their expiration dates, which range from December 2010 to September 2013.

On September 15, 2009, the Company’s Board of Directors adopted the Contango Oil & Gas Company

Equity Compensation Plan (the “2009 Plan”), which was approved by shareholders on November 19, 2009. Under
the 2009 Plan, the Company’s Board of Directors can grant restricted stock and option awards to officers, directors,
employees or consultants of the Company. Awards made under the 2009 Plan are subject to such restrictions, terms
and conditions, including forfeitures, if any, as may be determined by the Board.

Under the 2009 Plan, the Company may issue up to 2,500,000 shares of common stock with an exercise

price of each option equal to or greater than the market price of the Company’s common stock on the date of grant,
but in no event less than $2.00 per share. The Company may grant key 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 generally expire after five or ten
years. The vesting schedule varies, and can vest over a two, three or four-year period. As of June 30, 2010, options
under the 2009 Plan to acquire 25,000 shares of common stock at $49.29 were outstanding.

F-18

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

A summary of the status of stock options granted under the 1999 Plan and 2009 Plan as of June 30, 2010,

2009 and 2008, and changes during the fiscal years then ended, is presented in the table below:

2010

Year Ended June 30,
2009

Outstanding, beginning of year……………...…
Granted………………………...………………
Exercised………………………..………………
Forfeited…………………………………………
Cancelled………………………….………...…
Outstanding, end of year…………...………….…
Aggregate intrinsic value………………………

Shares
Under
Options

685,167
25,000
(344,229)
(60,604)
-
305,334
4,928,091

Weighted
Average
Exercise
Price
16.49
$
49.29
$
9.24
$
10.20
$
$
-
$
28.61

Weighted
Average
Exercise
Price
11.57
$
50.91
$
$
7.18
$
-
$
-
$
16.49

Shares
Under
Options

855,667
60,000
(230,500)
-
-
685,167
17,814,342

2008

Shares
Under
Options

1,026,000

-
(71,000)
-
(99,333)
855,667
69,608,510

Weighted
Average
Exercise
Price

$
10.87
$
-
$
8.18
$
-
$
6.77
$
11.57

Exercisable, end of year………………...………
Aggregate intrinsic value………………………

240,334
5,289,751

22.74

625,167
18,317,393

13.19

686,167
56,300,002

10.87

Available for grant, end of year………………..
Weighted average fair value of

2,475,000

508,666

568,666

options granted during the year (1)……………

15.39

24.91

$
-

_______________
(1) The fair value of each option is estimated as of the date of grant using the Black-Scholes option-pricing model with the
following weighted-average assumptions used for grants during the years ended June 30, 2010 and 2009, respectively: (i)
risk-free interest rate of 0.25 percent and 3.01 percent; (ii) expected lives of five years; (iii) expected volatility of 35 percent
and 53 percent; and (iv) expected dividend yield of zero percent.

The following table summarizes information regarding stock options that were outstanding at June 30,

2010:

Options Outstanding

Options Exercisable

Range of Exercise Price
$11.00 - $11.99…………………………………
$12.00 - $12.99…………………………………
$14.00 - $14.99…………………………………
$21.00 - $21.99…………………………………
$41.00 - $41.99…………………………………
$49.00 - $49.99…………………………………
$54.00 - $54.99…………………………………

Weighted
Average
Exercise
Price
$
$
$
$
$
$
$
$

11.58
12.95
14.14
21.00
41.01
49.29
54.21
28.61

Number of
Shares
Under
Outstanding
Options

14,334
3,000
3,000
200,000
5,000
-
15,000
240,334

Weighted
Average
Exercise
Price
11.58
$
12.95
$
14.14
$
21.00
$
$
41.01
$
-
$
54.21
$
22.74

Number of
Shares
Under
Outstanding
Options

Weighted
Average
Remaining
Contractual
Life

0.8
0.7
1.0
1.6
3.2
4.7
3.2
2.1

14,334
3,000
3,000
200,000
15,000
25,000
45,000
305,334

F-19

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

The Company applies the fair value method to account for stock based compensation. Under this method,

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 fiscal years ended June 30,
2010, 2009 and 2008, approximately $0.1 million, $0.3 million and $1.1 million, respectively, of such excess tax
benefits were classified as financing cash flows. See Note 2 – Summary of Significant Accounting Policies.

All employee stock option grants are expensed 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 fiscal year-ended June 30, 2010, 2009 and 2008, the Company
recorded stock option expense of $0.6 million, $1.1 million and $1.2 million, respectively.

As of June 30, 2010, we have approximately $1.3 million of total unrecognized compensation cost related

to non-vested awards granted under our various share-based plans, which we expect to recognize over a two-year
period.

The aggregate intrinsic values of the options exercised during fiscal years 2010, 2009 and 2008 were

approximately $15.3 million, $12.2 million and $1.9 million, respectively.

The Company did not grant any shares of restricted stock for the fiscal year ended June 30, 2010. For the

fiscal year ended June 30, 2009, the Company awarded a total of 3,088 shares of restricted stock under the 1999
Plan to its board of directors. Of these 3,088 shares of restricted stock, 1,544 shares vested on the date of grant, and
the remaining 1,544 shares vested one year thereafter. The fair value of restricted stock was approximately
$144,000. For the fiscal year ended June 30, 2008, the Company awarded a total of 4,140 shares of restricted stock
under the 1999 Plan to its board of directors. Of these 4,140 shares of restricted stock, 2,070 shares vested on the
date of grant, and the remaining 2,070 shares vested one year thereafter. The fair value of restricted stock was
approximately $180,000.

For the year ended June 30, 2010, 2009 and 2008, the Company recognized $72,182, $240,581 and
$252,435, respectively, in compensation expense relating to restricted stock awards. A summary of the Company’s
restricted stock as of June 30, 2010, is as follows:

Nonvested balance at June 30, 2008………………………………
Granted……………………………………………………………
Vested……………………………………………………………
Forfeited……………………………………………………………

Weighted
Average
Number of Fair Value
Per Share
22.16
$
46.75
26.29
-

7,654
3,088
(9,198)
-

Nonvested balance at June 30, 2009………………………………
Granted……………………………………………………………
Vested……………………………………………………………
Forfeited……………………………………………………………

1,544
-
(1,544)
-

46.75
-
46.75
-

Nonvested balance at June 30, 2010………………………………

$
-

F-20

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

16. Related Party Transactions

Effective October 1, 2009, the Company’s wholly-owned subsidiary, Conterra Company (“Conterra”),

entered into a joint venture with Patara Oil & Gas LLC (“Patara”), a privately held oil and gas company, to develop
proved undeveloped Cotton Valley gas reserves in Panola County, Texas. B.A. Berilgen, a member of the
Company’s board of directors, is the Chief Executive Officer of Patara.

During the fiscal year ended June 30, 2010, the Company purchased 115,454 shares of its common stock

from three officers of the Company and two members of its board of directors for approximately $6.4 million.
During the fiscal year ended June 30, 2009, the Company purchased 21,754 shares of its common stock from one
member of its board of directors for approximately $1.3 million. During the fiscal year ended June 30, 2008,
Company purchased 10,000 shares of its common stock from one member of its board of directors and 99,333 stock
options from three officers of the Company and one member of its board of directors for approximately $6.6 million.
All purchases were approved by the Company’s board of directors and were completed at the closing price of the
Company’s common stock on the date of purchase.

During the fiscal year June 30, 2008, the members of REX entered into the REX LLC Agreement, effective

as of April 1, 2008, to, among other things, distribute REX’s interest in Dutch and Mary Rose to the individual
members of REX or their designees. In connection with this distribution, REX repaid in full all amounts owing by
REX under the REX Demand Note, and all security interests and other liens granted in favor of such private
investment firm as security for the obligations under the REX Demand Note were released and terminated. As a
result of our proportionate consolidation of REX, the Company’s portion of such repayment was approximately
$22.5 million. For the fiscal year ended June 30, 2008, the Company’s proportionate share of such interest expense
was approximately $1.3 million.

In March 2006, COE executed a Promissory Note (the “COE Note”) to the Company to finance its share of
development costs in Grand Isle 72. The COE Note was payable upon demand and carried an annual interest rate of
10%. As of May 31, 2010, COE owed COI $4.3 million under the COE Note, and owed an additional $1.6 million
in accrued and unpaid interest. Effective June 1, 2010, COE was dissolved and the Company assumed its 65.6% of
the obligation of COE, while the other member of COE assumed the remaining 34.4%, or approximately $2 million.
This $2 million is reflected as a note receivable in the Consolidated Balance Sheet of the Company as of June 30,
2010. The new note receivable is payable on demand and bears no interest.

17. Share Repurchase Program

In September 2008, the Company’s board of directors approved a $100 million share repurchase program.

All shares are purchased in the open market from time to time by the Company or through privately negotiated
transactions. The purchases will be made subject to market conditions and certain volume, pricing and timing
restrictions to minimize the impact of the purchases upon the market. Repurchased shares of common stock become
authorized but unissued shares, and may be issued in the future for general corporate and other purposes. As of June
30, 2010, we have purchased approximately 1.7 million shares of our common stock at an average cost per share of
$43.89, for a total expenditure of approximately $75 million. As at June 30, 2010, we have 15,684,666 shares of
common stock outstanding and 15,990,000 fully diluted shares.

F-21

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

18. Subsequent Events

On August 24, 2010, the Company signed a commitment letter with Amegy Bank National Association

(“Amegy”) to arrange for a four-year $40 million hydrocarbon borrowing base senior revolving credit facility (the
“Amegy Agreement”) to replace the expiring Compass Agreement. Under the terms and conditions of the term
sheet with Amegy, the facility will be secured by substantially all of the Company’s assets and will be available to
fund the Company’s exploration and development activities, as well as the repurchase of shares of the Company’s
common stock, the payment of dividends, and working capital as needed. Borrowings under the Amegy Agreement
will bear interest at LIBOR plus 2.5% per annum. An arrangement fee of 0.75%, or $300,000, will be paid in
connection with the facility and a commitment fee of 0.375% will be paid on the unused commitment amount. The
Amegy Agreement will contain customary covenants including limitations on additional indebtedness.

In July 2010, both Conterra and Patara agreed to enter into a second joint venture agreement to drill up to

an additional 15 wells, bringing the total expected number of wells to 30.

During July 2010, we purchased an additional 20,000 shares of our common stock under our $100 million

share repurchase program for approximately $0.9 million, bringing the total number of shares outstanding to
15,664,666 and our fully diluted shares to 15,970,000 as of August 31, 2010.

F-22

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

The following disclosures provide required unaudited information.

Costs Incurred. The following table presents information regarding our net costs incurred in the purchase

of proved and unproved properties and in exploration and development activities for the periods indicated:

Year Ended June 30,

2010

2009

2008

Property acquisition costs:
11,318,349
Unproved………………………………………………………
2,009,330
Proved…………………………………………………………
Exploration costs…………………………………………………
52,805,270
Developmental costs……………………………………………… 40,901,582

$
-

1,131,582
23,284,970
22,889,629

309,000,000
45,243,651
76,025,586

Total costs……………………………………………………… 107,034,531

47,306,181

430,269,237

Natural Gas and Oil Reserves. Proved reserves are estimated quantities of natural gas and oil that
geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that
reasonably can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved natural gas and oil reserve quantities at June 30, 2010, 2009 and 2008, and the related discounted
future net cash flows before income taxes are based on estimates prepared by William M. Cobb & Associates, Inc.
and Lonquist & Co. LLC. Such estimates have been prepared in accordance with guidelines established by the
Securities and Exchange Commission.

F-23

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

The Company’s net ownership interests in estimated quantities of proved natural gas and oil reserves and

changes in net proved reserves as of June 30, 2010, 2009 and 2008, all of which are located in the continental United
States, are summarized below:

Oil and

Condensate

(MBbls)

NGL's

(MBbls)

Natural

Gas

(MMcf)

Proved Developed and Undeveloped Reserves as of:

June 30, 2007…………………………………….……………………………
Sale of reserves……………………………………………………………
Extensions and discoveries…………………………………………………
Purchases……………………………………………………………………
Recoveries and revisions……………………………………………………
Production…………………………………………………………………

June 30, 2008…………………………………….……………………………
Sale of reserves……………………………………………………………
Extensions and discoveries…………………………………………………
Purchases……………………………………………………………………
Recoveries and revisions……………………………………………………
Production…………………………………………………………………

June 30, 2009…………………………………….……………………………
Sale of reserves……………………………………………………………
Extensions and discoveries…………………………………………………
Purchases……………………………………………………………………
Recoveries and revisions……………………………………………………
Production…………………………………………………………………

June 30, 2010…………………………………….……………………………

Proved Developed Reserves as of:

June 30, 2007……………………………………………………..…………
June 30, 2008……………………………………………………..…………
June 30, 2009……………………………………………………..…………
June 30, 2010……………………………………………………..…………

1,164
-
2,200
1,496
806
(187)

5,479
-
104
-
(64)
(515)

5,004
-
1,276
-
(1,177)
(505)

4,598

827
5,479
5,004
4,598

-
-
3,186
2,015
2,350
(112)

7,439
-
69

-
483
(590)

7,401
-
1,081
-
(1,146)
(598)

6,738

-
7,439
7,401
6,738

77,892
(13,789)
117,999
78,745
41,309
(10,588)

291,568
-
2,148
-
7,437
(20,537)

280,616
-
40,635
-
(53,855)
(21,385)

246,011

57,721
291,568
280,616
246,011

During the fiscal year ended June 30, 2010, included in the recoveries and revisions line item is a revision
of approximately 48.5 Bcfe related to our Dutch and Mary Rose field reserves. As a result of newly learned bottom
hole pressure data determined during a recent field wide shut-in and a “P/Z pressure test”, our independent third-
party engineer concluded that we had less reserves than originally estimated.

During the fiscal year ended June 30, 2008, the large adjustment related to discoveries is due to the
exploration discoveries at Mary Rose #1, #2, #3 and #4 on our State of Louisiana State leases. The large adjustment
related to purchases is due to the additional working interest the Company purchased in the Eugene Island 10 and
State of Louisiana. The Company purchased an additional 12.5% working interest and 10% net revenue interest in
Dutch and an additional average 13.67% working interest and 10% net revenue interest in Mary Rose for $300
million. The Company also purchased an additional 0.3% overriding royalty interest in the Dutch and Mary Rose
discoveries for $9.0 million.

F-24

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

Standardized Measure. The standardized measure of discounted future net cash flows relating to the
Company’s ownership interests in proved natural gas and oil reserves as of June 30, 2010, 2009 and 2008 are shown
below:

As of June 30,

2010

2009

2008

Future cash flows………………………………...……… 1,720,888,280
Future operating expenses……………...………………… (232,641,231)
(66,236,936)
Future development costs…………………………………
(399,755,146)
Future income tax expenses………………...……………

1,750,118,803
(248,468,246)
(16,225,612)
(447,934,853)

5,635,443,766
(211,104,075)
(20,712,845)
(1,733,031,168)

Future net cash flows…………………………..……… 1,022,254,967

1,037,490,092

3,670,595,678

10% annual discount for

estimated timing of cash flows……………...………

(310,160,823)

(399,398,648)

(1,436,677,549)

Standardized measure

of discounted future net cash flows……………..……… 712,094,144

638,091,444

2,233,918,129

Future cash flows represent expected revenues from production and are computed by applying certain

prices of natural gas and oil to fiscal year-end quantities of proved natural gas and oil reserves. For the fiscal year
ended June 30, 2010, future cash flows were based on the first-day-of-the-month prices for the previous 12 months
of $4.09 per MMBtu of natural gas, $76.21 per barrel of oil, and $44.62 per barrel of natural gas liquids. For the
fiscal years ended June 30, 2009 and 2008, future cash flows were based on fiscal year-end prices of $3.89 and
$13.095 per MMBtu for natural gas, respectively; $69.89 and $140.00 per barrel of oil, respectively; and $35.66 and
$98.00 per barrel of natural gas liquids, respectively, in each case before adjusting for basis, transportation costs and
BTU content.

Future operating expenses and development costs are computed primarily by the Company’s petroleum

engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved natural
gas and oil reserves at the end of the year, based on year-end costs and assuming continuation of existing economic
conditions. Future development costs relate to compression charges at our EI-11H platform, abandonment costs,
and recompletion costs.

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.

F-25

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

Change in Standardized Measure. Changes in the standardized measure of future net cash flows relating to

proved natural gas and oil reserves are summarized below:

Year Ended June 30,

2010

2009

2008

Changes due to current year operation:
Sales of natural gas and oil, net of

natural gas and oil operating expenses…………………...…
Extensions and discoveries……………………………………
Net change in prices and production costs………………...…
Change in future development costs………………………..…
Revisions of quantity estimates…………………………...……
Purchase of reserves……………………………………………
Sale of reserves……………………………………………….
Accretion of discount…………………………………………
Change in the timing of production rates and other……………
Changes in income taxes………………………………………

(143,641,092)
151,760,465
108,882,767
7,968,517
(190,840,383)

(166,971,446)
9,053,412
(2,246,528,398)
5,274,099
24,805,146

-
-

88,986,475
57,460,335
(6,574,384)

318,384,235
(237,994,644)
698,150,911

(118,255,500)
1,320,872,171
393,348,968
50,366,258
641,122,998
868,101,751
(26,923,252)
32,917,957
(306,888,418)
(873,042,079)

Net change………………………………………………………
Beginning of year…………………………………………………

74,002,700
638,091,444

(1,595,826,685)
2,233,918,129

1,981,620,854
252,297,275

End of year………………………………………………….……

712,094,144

638,091,444

2,233,918,129

For the fiscal year ended June 30, 2009 and 2008, the standardized measure decreased by approximately

$238.0 million, and $307 million, respectively, due to a change in the timing of production rates and other. This is
mainly attributable to production profile differences and other imprecise assumptions. We had six wells producing
in 2008, nine wells producing in 2009 and nine wells producing in 2010.

F-26

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 years ended June 30, 2010 and 2009:

Quarter Ended

Sept. 30,

Dec. 31,

Mar. 31,

June 30,

($000, except per share amounts)

Fiscal Year 2010:

Revenues from continuing operations……………………… 35,602

46,080

37,846

41,153

Income from continuing operations (1)…………………...… 21,377
13,466
Net income attributable to common stock…………………

$
$

30,661
19,111

$
$

2,792
1,742

$
$

26,442
15,367

Net income per share (2):
Basic:
Diluted:

Fiscal Year 2009:

$
$

0.85
0.83

$
$

1.21
1.18

$
$

0.11
0.11

$
$

0.97
0.95

Revenues from continuing operations……………………… 72,721

45,517

36,133

36,285

Income from continuing operations (1)…………………...… 51,326
30,920
Net income attributable to common stock…………………

$
$

31,292
18,917

$
$

2,032
848

$
$

8,158
5,176

Net income per share (2):
Basic:
Diluted:

$
$

1.83
1.80

$
$

1.14
1.12

$
$

0.05
0.05

$
$

0.33
0.32

(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-27