Exhibit 99.2
CONTANGO OIL AND GAS COMPANY
Estimated Future Reserves and Revenues
As of July 1, 2010
SEC Guideline Case
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September 7, 2010
Mr. Kenneth R. Peak
Contango Oil & Gas Company
3700 Buffalo Speedway, Suite 960
Houston, Texas 77098
| | | | |
| | Re: | | Contango Oil & Gas Company |
| | | | Proved Reserve Update |
| | | | As of July 1, 2010 |
| | | | SEC Guideline Case |
Dear Mr. Peak:
Pursuant to your request, Lonquist & Co. LLC (“L&Co”) has estimated the future hydrocarbon Reserves and projected the associated future revenues net to the interests owned by Contango Oil and Gas Company (“Contango”) as of July 1, 2010. The assets evaluated in this report are in the Contango Oil & Gas Co./Patara Oil & Gas LLC Joint Venture in Panola County, Texas. As shown in the following table, Proved Developed Producing (“PDP”), Proved Developed Non-Producing (“PDNP”), and Proved Undeveloped (“PUD”) Reserves were evaluated for this report.
Our conclusions, as of July 1, 2010, are summarized below:
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| | Net to Contango Oil and Gas Company | |
| | Proved Developed | | | Proved Undeveloped | | | Total Proveda | | | Total Probable | | Total Possible | | Grand Totalb | |
SEC Pricing | | Producing | | Non-Producinga | | | | | | |
| | | | | | | |
Estimated Future Net Oil/Condensate, bbl | | 45,417 | | (1,155 | ) | | 94,225 | | | 138,487 | | | 0 | | 0 | | 138,487 | |
Estimated Future Net Gas, MMcf | | 6,922 | | (461 | ) | | 12,235 | | | 18,697 | | | 0 | | 0 | | 18,697 | |
Estimated Future Net NGL, bbl | | 262,561 | | (17,476 | ) | | 464,094 | | | 709,179 | | | 0 | | 0 | | 709,179 | |
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Total Future Gross Revenue, $ | | 38,106,010 | | (2,400,487 | ) | | 68,369,417 | | | 104,074,945 | | | 0 | | 0 | | 104,074,945 | |
Estimated Future Production Taxes, $ | | 1,697,670 | | 49,545 | | | 2,624,478 | | | 4,371,692 | | | 0 | | 0 | | 4,371,692 | |
Estimated Future Operating Expenses, $ | | 6,881,899 | | 482,426 | | | 7,441,993 | | | 14,806,318 | | | 0 | | 0 | | 14,806,318 | |
Estimated Future Capital Costs, $ | | 0 | | 2,020,500 | | | 31,500,000 | | | 33,520,500 | | | 0 | | 0 | | 33,520,500 | |
Estimated Future Net Revenue (“FNR”), $ | | 29,526,441 | | (4,952,955 | ) | | 26,802,939 | | | 51,376,426 | | | 0 | | 0 | | 51,376,426 | |
Discounted FNR at 10%, $ | | 16,156,662 | | 6,538,868 | | | 5,540,298 | | | 28,235,834 | | | 0 | | 0 | | 28,235,834 | |
Discounted FNR at 15%, $ | | 13,348,307 | | 7,717,241 | | | 155,903 | | | 21,221,451 | | | 0 | | 0 | | 21,221,451 | |
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Estimated Net Revenues by Year, $ | | | | | | | | | | | | | | | | | | |
2010 | | 2,928,490 | | 805,378 | | | (12,812,009 | ) | | (9,078,140 | ) | | 0 | | 0 | | (9,078,140 | ) |
2011 | | 3,478,893 | | 4,494,567 | | | (7,834,320 | ) | | 139,139 | | | 0 | | 0 | | 139,139 | |
2012 | | 2,483,596 | | 5,591,715 | | | 8,125,118 | | | 16,200,429 | | | 0 | | 0 | | 16,200,429 | |
Subtotal | | 8,890,979 | | 10,891,660 | | | (12,521,211 | ) | | 7,261,428 | | | 0 | | 0 | | 7,261,428 | |
Thereafter | | 20,635,462 | | (15,844,615 | ) | | 39,324,150 | | | 44,114,998 | | | 0 | | 0 | | 44,114,998 | |
Total | | 29,526,441 | | (4,952,955 | ) | | 26,802,939 | | | 51,376,426 | | | 0 | | 0 | | 51,376,426 | |
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Estimated Average Net Production Rate - 2010 | | | | | | | | | | | | | | | | | | |
Oil/Condensate, B/D | | 23 | | 9 | | | 10 | | | 42 | | | 0 | | 0 | | 42 | |
Gas, Mcf/D | | 3,329 | | 1,208 | | | 1,295 | | | 5,833 | | | 0 | | 0 | | 5,833 | |
NGL, B/D | | 126 | | 46 | | | 49 | | | 221 | | | 0 | | 0 | | 221 | |
a | Column includes the Proved Developed Non-Producing, shut-in and behind- pipe volumes and cash flows. |
b | Totals might not match detailed cash flows due to computer rounding. |
Contango Oil & Gas Company
July 1, 2010 Reserve Update
Contango/Patara JV Properties
September 7, 2010
Page 2 of 4
Purpose of Report and Standards of Practice
This report was prepared to provide the management of Contango with a projection of estimated remaining hydrocarbon Reserves and projected future net revenues, effective July 1, 2010. These estimates have not been adjusted for risk.
This report has been prepared in accordance with our understanding of the Securities and Exchange Commission (“SEC”), SX Reg. § 210.4-10, dated November 18, 1981 as amended September 19, 1989, requiring adherence to definitions of “Proved” oil and gas Reserves. Additionally, this report conforms to the most recently adopted SEC guidelines in theModernization of Oil and Gas Reporting; Final Rule (January 14, 2009). The SEC oil and gas Reserve definitions are attached hereto.
Liquid hydrocarbon volumes are expressed in standard 42-gallon barrels. All natural gas volumes are sales gas expressed at the official pressure and temperature bases of the areas in which the gas Reserves are located.
All currencies in this report are expressed in U.S. dollars.
Reserve Estimates
Well-by-well production data in this report were updated through June 30, 2010, where applicable. Extrapolation of historical production data was utilized for those producing properties where sufficient data were available to suggest decline trends. Reserves assigned to the remaining producing properties and the non-producing assets were determined by analogy to offset wells producing from similar formations or by volumetric analysis. Reserves assigned by analogy and volumetric analysis are subject to greater revision than those projected using established performance trends.
The properties evaluated in this report are located in the Carthage Field in Panola County, Texas and are a joint venture (“JV”) entered into/with Patara Oil and Gas LLC (“Patara”). The JV agreement calls for 15 total Cotton Valley wells to be drilled and completed by the end of 2010. At the time of this report, 11 Cotton Valley wells have been drilled and completed and are in the Proved Developed Producing category (“PDP”). One additional well has been drilled and is waiting on completion and is in the Proved Developed Non-Producing (“PDNP”) category. Five wells within the Proved Undeveloped (“PUD”) category are scheduled to be drilled and completed before the end of the year, thus satisfying the terms of the JV.
Under the JV, Contango owns a 90% working interest and a 67.5% average net revenue interest in the properties until they accumulate a 15% rate of return on their investment, at which time their working interest reverts to a 5% overriding royalty interest.
As of July 1, 2010, the total Proved net remaining Reserves were estimated to be 138,487 barrels of oil, 18,697 MMcf of gas, and 709,179 barrels of NGL. The net present value, discounted at 10%, of the remaining Reserves is $28,235,834. Of the total discounted net revenue, approximately 57% is generated by the PDP Reserves.
Product Prices and Differentials
The base oil price of $76.21 per barrel and $4.09 per MMBTU in this evaluation is the un-weighted arithmetic average of the closing NYMEX West Texas Intermediate (“WTI”) oil price and the Henry Hub gas price on the first trading day of the preceding 12-month period, as reported on the websitewww.tax.alaska.gov. As required by SEC regulations, no price escalations are included in this report. Realized product prices in this report reflect adjustments for basis differentials and include transportation costs, where applicable.
Contango Oil & Gas Company
July 1, 2010 Reserve Update
Contango/Patara JV Properties
September 7, 2010
Page 3 of 4
Operating Costs and Expenditures
The direct operating expenses were input as dollars per month and were estimated on an individual well basis utilizing data provided by Contango and/or Patara. The individual well projections of oil and gas ceased when the operating expenses exceeded the gross revenues. Compression fees were scheduled as an operating expense of $0.15/Mcf where applicable. Salt water disposal charges were on a unit volume basis and were scheduled as $1.05/bbl. Expenses were not escalated in this report.
Development costs included in this report were provided by Contango and were based on authorizations for expenditures for the proposed work or actual costs for similar projects. The timing of investments were also supplied by Contango based upon their long-range plans and experience in the area. Development costs were not escalated in this report. Any changes in the costs or investment timing from the assumptions in this report will impact the net present value. The wells drilled in 2010 under the JV agreement included $1,650,000 for drilling and completion costs, and an additional $100,000 drilling fee to Patara, all paid for by Contango.
Values Not Considered
In all cases, we have attempted to account for all deductions from gross revenues except for the following:
| • | | Depreciation, depletion, and/or amortization, if any |
| • | | Costs in excess of revenues of uneconomic leases |
| • | | Plugging and abandonment costs in excess of salvage value |
| • | | Environmental restoration costs, if any |
| • | | Product price hedges, if any |
No value has been assigned to non-producing leaseholds or to acreage held by production.
Report Qualifications
Estimates of future revenues were based on projections of recoverable hydrocarbons, rates of production, timing of recompletions and drilling, proration by state and federal agencies, operating costs, direct taxes, and product prices. Any unusual combination of the many factors, including weather, political risk, or acts of terrorism could result in future receipts being considerably less or more than those estimated herein.
THE REVENUES AND PRESENT WORTH OF FUTURE NET REVENUES ARE NOT REPRESENTED TO BE MARKET VALUES EITHER FOR THE INDIVIDUAL PROPERTIES OR IN A TOTAL PROPERTY BASIS.
The Reserves and revenues for specific properties should be considered in context with the overall report.
Contango Oil & Gas Company
July 1, 2010 Reserve Update
Contango/Patara JV Properties
September 7, 2010
Page 4 of 4
Data Sources
Key data, including well information, geologic interpretations, direct operating costs, historical production data, and realized product prices were supplied by Contango. Ownership data was supplied by Contango. The ownership interests and other factual data were accepted without independent verification.
We retain in our files digital databases for all properties and certain other hard copy information that we believe pertinent. We have not inspected the properties evaluated in this report, nor have we conducted independent well tests.
Independent Evaluation
Neither Lonquist & Co. LLC nor any of its employees have any interest or ownership in the subject properties, and neither our employment nor compensation is contingent on our findings herein.
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| Richard R. Lonquist, P.E. Petroleum Engineer Texas License No. 73008 Date Signed: September 7, 2010 Austin, Texas |
OIL AND GAS RESERVE DEFINITIONS
The Securities and Exchange Commission, SX Reg. § 210.4-10 dated November 18, 1981 as amended September 19, 1989 requires adherence to the following definitions of “Proved” oil and gas reserves:
Definitions:
(2)Proved oil and gas reserves.Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.
(3)Proved developed oil and gas reserves.Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
(4)Proved undeveloped reserves.Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates, for proved undeveloped reserves be attributable to any acreage or which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
Amended SEC guidelines Reg. § 210.4-10 definitions (Modernization of Oil and Gas Reporting; Final Rule; January 14, 2009):
(17)Possible reserves.Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10 percent probability that the total quantities ultimately recovered will equal or exceed the estimated proved plus probable plus possible reserves estimates.
(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by defined project.
(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves, but which, together with proved reserves, are as likely as not to be recovered.
(i) When deterministic methods are used, that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus reserves. When probabilistic methods are used, there should be at least a 50 percent probability that the quantities actually recovered will equal or exceed the proved plus probable reserves estimates.
(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.