Contango Oil and Gas Co Reports Operating Results (10-Q)

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May 11, 2009
Contango Oil and Gas Co (MCF, Financial) filed Quarterly Report for the period ended 2009-03-31.

Contango Oil & Gas is a Houston-based independent natural gas and oil company. The Company explores develops produces and acquires natural gas and oil properties primarily onshore in the Gulf Coast and offshore in the Gulf of Mexico. Contango Oil and Gas Co has a market cap of $694 million; its shares were traded at around $42.53 with a P/E ratio of 5.79 and P/S ratio of 5.96.

Highlight of Business Operations:

In August 2008 and September 2008, Hurricanes Gustav and Ike, respectively, 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 only minor damage from Hurricane Ike, and was limited to our Dutch and Mary Rose wells, affecting mainly SCADA control systems, helideck skirting, risers, and disrupted flowlines. Repairs have been completed on the damaged wells at an 8/8ths cost of approximately $2.4 million, which is covered by the Companys insurance after an 8/8ths deductible of $500,000. The third-party processing and pipeline facilities on which we rely, however, incurred significant damage from Hurricane Ike and necessitated significant downtime for our production while repairs were being made. All third-party facilities have now been repaired and we have resumed production from our Gulf of Mexico assets.

In March 2009, COI spud Eugene Island 56 #1 (High Country West), a REX prospect, which has been determined to be a dry hole. COI has a 100% working interest (WI) and paid 100% of the drilling costs of approximately $12.0 million. These costs together with associated leasehold costs and prospect fees of approximately $0.5 million are reflected as exploration expenses in the Companys Consolidated Statements of Operations for the three and nine months ended March 31, 2009.

In October 2008, COI spud West Delta 77 (Devils Elbow), a REX prospect, which has been determined to be a dry hole. COI has a 100% working interest and paid 100% of the drilling costs of approximately $5.4 million. These costs together with associated leasehold costs of approximately $1.7 million are reflected as exploration expenses in the Companys Consolidated Statements of Operations for the nine months ended March 31, 2009.

Grand Isle 72 (Liberty), a COE prospect operated by COI, began producing in March 2007. COE has a 50% WI and a 40% NRI in this well. As of March 31, 2009, COE had borrowed $4.3 million from the Company under a promissory note (the Note) to fund a portion of its share of development costs at Grand Isle 72. The Note bears interest at a per annum rate of 10% and is payable upon demand. As of March 31, 2009, accrued and unpaid interest on the Note was $1.1 million. In March 2009, COE completed the top-most zone and increased production on this well. The estimated cost on an 8/8ths basis was approximately $0.8 million, or $0.3 million net to the Companys ownership percentage in COE.

The Companys Mary Rose #1 well was recently worked over at a cost of approximately $10.0 million ($5.3 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 $0.3 million ($0.1 million net to Contango). Currently, the Companys Mary Rose #2 well is shut-in for workover operations which are scheduled to begin in May 2009.

Reserve Estimates. While we are reasonably certain of recovering our reported reserves, the Companys 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 Companys natural gas and oil properties and/or the rate of depletion of such natural gas and oil properties. Actual production, revenues and expenditures with respect to the Companys reserves will likely vary from estimates, and such variances may be material. Holding all other factors constant, a reduction in the Companys proved reserve estimate at March 31, 2009 of 1% would not have a material effect on depreciation, depletion and amortization expense. Holding all other factors constant, a reduction in the Companys proved reserve estimate at March 31, 2009 of 5%, 10% and 15% would affect depreciation, depletion and amortization expense by approximately $1.1 million, $2.3 million and $3.6 million, respectively.

Read the The complete ReportMCF is in the portfolios of John Keeley of Keeley Fund Management.