William M. Cobb & Associates, Inc.

Worldwide Petroleum Consultants

 

 

12770 Coit Road, Suite 907(972) 385-0354

Dallas,  TexasFax: (972) 788-5165

E-Mail: office@wmcobb.com

 

 

January 16, 2015

 

 

 

Mr. Steve Mengle

Contango Oil & Gas Company

717 Texas Avenue, Suite 2900

Houston, TX  77002

 

Dear Mr. Mengle:

 

In accordance with your request, William M. Cobb & Associates, Inc. (Cobb & Associates) has estimated the proved reserves and future income as of January 1, 2015, attributable to the interest of Contango Oil & Gas Company and its subsidiaries (Contango) in certain oil and gas properties located in state and federal waters of the Gulf of Mexico and onshore in Mississippi. This report was completed on January 15, 2015.

 

Table 1 summarizes our estimate of the proved oil and gas reserves and their pre-federal income tax value undiscounted and discounted at ten percent.  Due to operational updates and the removal of a proved undeveloped (PUD) acceleration case from the 2013 year-end report, all reserves in this report are now proved producing (PDP).  Values shown are determined utilizing constant oil and gas prices and well operating expenses.  The discounted present worth of future income values shown in Table 1 are not intended to necessarily represent an estimate of fair market value. These estimates were prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Certification Topic 932, Extraction Activities – Oil and Gas. 

 

TABLE 1

 

CONTANGO  - NET RESERVES AND VALUE

AS OF JANUARY 1, 2015

CONSTANT SEC OIL AND GAS PRICES

 

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Total proved reserves as of January 1, 2015 are 144,010 MMCFE.  This amount is calculated using a  six MCF per barrel ratio applied to condensate and NGL volumes.

 

Oil and NGL volumes are expressed in thousands of stock tank barrels (MBBL).  A stock tank barrel is equivalent to 42 United States gallons.  Gas volumes are expressed in millions of standard cubic feet (MMCF) as determined at 60o Fahrenheit and the legal pressure base for the specific location of the gas reserves.

 

DISCUSSION

 

Eugene Island 10

 

Eugene Island 10 is located in federal and state waters of the Gulf of Mexico, at a water depth of approximately 13 feet.  Production is primarily from a single CibOp sand, the JRM-1 sand, at a depth of approximately 15,000 feet.  The field was discovered in September, 2006 by the Contango Operators Dutch  1 well.  Contango has since drilled four more wells, the Dutch 2, 3, 4 and 5, on Federal acreage. 

 

Contango’s Louisiana State leases in this field are referred to as the Mary Rose prospect.  Five Mary Rose wells have been drilled to date.  Four Mary Rose wells, numbers 1 through 4, produce from the main CibOp sand.  The Mary Rose 5 well produces from a separate, and much smaller, CibOp reservoir.

 

All wells now produce to the Contango ‘H’ platform located in Eugene Island Block 11.  The
Dutch 1, 2, and 3 wells previously produced to the Chevron EI-24 platform but were switched to the Contango ‘H’ platform in 2013.

 

Proved reserves for the Eugene Island 10 main CibOp sand are based on a field-wide P/Z performance plot, supplemented by volumetric calculations of original-gas-in-place (OGIP) using all available well log data coupled with 3D seismic data.  The reservoir has been effectively drilled to the lowest structural datum and no significant aquifer has been found.  Performance to date indicates a depletion drive system.    In 2014, compression was installed on the ‘H’ platform and the Mary Rose wells now send their gas through it.  Compression is expected to be initiated on the Dutch wells as needed.  Delivery pressures with compression will be initially lowered to 700 psi, eventually going to 200 psi.    There is no remaining capital and start up costs for compression on the ‘H’ platform.    Compression fuel charges are calculated based on a conservative historical operating volume of 950 MCFPD.   The fuel volume is allocated annually to each well based on its proportion of projected gas production to the field total.    The allocated volume is then multiplied by the well’s revenue interest and the SEC gas price, adjusted for pricing differential, to determine the annual fuel charges.

 

In the 2013 year-end report, Contango had scheduled the Dutch 6 well as a PUD acceleration well in the main CibOp reservoir.  This PUD provided significant acceleration benefits but minimal incremental reserves.  Contango now believes that it is unlikely that the Dutch 6 well will be drilled, so it has been removed from this report.

 

Contango’s working interest ownership is approximately 55 percent in the Dutch wells and 53 percent in the Mary Rose 1 through 3 wells.  The Contango working interest in the Mary Rose 4 and 5 wells is approximately 35 and 38 percent, respectively.  Based on future net income, discounted at ten percent

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(PV10), approximately 92.3 percent of the Contango proved reserve value is attributable to the Eugene Island 10 wells.

 

Two wells on the State acreage originally produced from gas reservoirs separate from the main CibOp reservoir.  The Eloise 3 well produced and depleted a lower RobL sand and was recompleted to  an isolated CibOp sand during the last quarter of 2011.  This stray CibOp producer, now called the Mary Rose 5, began producing in January 2012.    The Eloise 5 well has also produced and depleted a lower RobL sand and was recompleted to the main CibOp reservoir mid-year 2011.  The Eloise 5 was renamed the Dutch 5 well and began producing from the main CibOp reservoir in July 2011.

 

Ship Shoal 263

 

Contango drilled the Ship Shoal 263 B-1 well in 2009 and completed the well for production in a gas sand at 15,850 feet.  The well began producing on June 30, 2010 and has produced approximately
8.7 BCF of gas and 556 MBBL of condensate to date.  The well is currently producing at a rate of about 400  MCF per day with 26 barrels of condensate.  The remaining reserves for Ship Shoal 263 were determined using decline curve analysis.

 

Vermilion 170

 

Contango drilled the OCS-G-33596 #1 in March of 2011 and successfully completed the well in the Big A sand at a depth of approximately 13,800 feet.  Production started in September 2011 upon installation of a production platform in 87 feet of water.  Current production rates are 10.1 MMCF per day with 135 barrels of condensate.  Cumulative production to date is approximately 14.7 BCF of gas and 379 MBBL of condensate.  Proved producing reserves,  which include benefits of recently installed compression, are based on a reservoir simulation model history matched to actual production and pressure performance.

 

South Timbalier 17-1

 

In mid to late 2013, Contango drilled and tested a well on its South Timbalier 17 lease.  The South Timbalier 17-1 was drilled to a total measured depth of 11,432 feet, and was completed in a sand from 11,174 - 11,200 feet.  The well tested in September of 2013 at a rate of 12.7 MMCF per day, but required facilities to be brought to normal production.    Facilities were installed in 2014 and the well commenced production in July of 2014, with peak daily rates of 15.0 MMCF per day with 166 BBL of condensate.  Current production rates are 8.3 MMCF per day with 42 barrels of condensate.  Cumulative production to date is approximately 1.8 BCF of gas and 15 MBBL of condensate.  Proved reserves included in this report are based on volumetric calculations to lowest known gas (LKG) in the 17-1 wellbore.

 

Tuscaloosa Marine Shale Wells

 

Contango owns a working interest in four Tuscaloosa Marine Shale (TMS) wells drilled from 2012 to 2014, which are operated by Goodrich Petroleum.  The wells are located in Wilkinson and Amite Counties, Mississippi, and they produce from the Cretaceous aged TMS at a true vertical depth of approximately 12,000 feet.  The wells were drilled horizontally with variable lateral lengths that average approximately 6,000’.  The wells were hydraulically fracture stimulated to increase well deliverability.  Peak oil rates for the wells ranged from 6,872 - 26,632 BBL of oil per month, and averaged 17,808 BBL of oil per month.  The wells are on hydraulic pump and in November of 2014, they produced at a combined rate of approximately 854  BBL of oil per day with 678 MCF of solution

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gas per day.  The wells have a combined cumulative recovery through November 2014 of approximately 337 MBBL of oil and 215 MMCF of solution gas.  Currently, only the first well drilled is selling gas volumes to market.  The Crosby Minerals 12-1 has a high gas shrink value due to lease fuel and NGL processing shrinkage, but it has a very favorable differential due to the NGL content in the gas.

 

OIL AND GAS PRICING

 

Projections of proved reserves contained in this report utilize constant product prices of $4.30 per MMBTU of gas and $94.99 per barrel of oil.    These are the average first-of-month prices for the prior 12-month period for Henry Hub gas and West Texas Intermediate (WTI) oil.  Appropriate oil and gas pricing differentials, residue gas shrink, NGL yields, and NGL pricing as a fraction of WTI were calculated for each field.    Table 2 summarizes these values. 

 

TABLE 2

 

CONTANGO – PRODUCT PRICE DIFFERENTIALS

AND NGL YIELD BY FIELD

 

 

*The Crosby Minerals 12-1 NGL value is included in the gas differential.

 

OPERATING COSTS

 

Future operating costs for each of the Contango wells are held constant at current values for the life of the property.  Following is a brief description of the gross operating cost projections for each of the Contango properties:

 

For the 12 months of lease operating expense (LOE) data analyzed, the Dutch and Mary Rose ‘H’ platform had an average monthly operating cost of $930,999, or $103,444 per producing well.  For compression, there is a yearly operating expense of $542,800 which is escalated at 3.5 percent per year, in accordance with a contract.

 

For wells producing to the ‘H’ platform, certain transportation and processing fees are applied.    Transportation and processing fees of $0.238 per net barrel of oil  and $2.344 per net barrel of NGL were scheduled.  A gas processing fee of $0.054 per net produced MCF was also scheduled.  For compression, a daily gross fuel volume of 950 MCF is charged at the prevailing gas price, with the gas differential applied.

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For Ship Shoal 263,  a  fixed operating cost of $121,350 per month was scheduled based on historical data provided by Contango.  Variable costs were also scheduled as follows:  $0.141 per net MCF of produced gas, $7.129 per net barrel of oil, and $1.811 per net barrel of NGL.

 

For Vermilion 170, operating costs were determined using the available historical expense data provided by Contango.  A fixed monthly operating cost of $158,185 was scheduled.  Variable costs of $0.115 per net MCF of produced gas, $1.462 per net barrel of oil, and $1.983 per net barrel of NGL were scheduled.

 

For the recently completed South Timbalier 17-1, only four months of expense data were available, and the data did not include production and handling fees (PHA).  Based on the available data, a fixed monthly operating cost of $21,593 was scheduled with additional PHA fees of $0.25 per MCF of produced gas, $1.75 per barrel of oil, and $1.75 per barrel of water.  The total projected gross LOE for 2015 is estimated to be $63,652 per month,  compared with the 2013 year-end report assumption of $75,000 per month.  In addition to the PHA fees, product transportation and processing fees of
$0.068 per net MCF of produced gas and $9.102 per net barrel oil were scheduled. 

 

Three of the four TMS wells had sufficient expense history to estimate LOE.  The Crosby
Minerals 12-1,  Foster Creek 20-7, and Huff 18-7 had fixed operating costs of $39,093, $32,117, and $23,982 per month, respectively.  The Foster Creek 24-13 received the average LOE from the other three wells of $31,731 per month.  There were no variable costs as all costs were considered fixed; additional history may allow for some fixed costs to be moved to variable.

 

RESERVE AND CASH FLOW PROJECTIONS

 

Projections of future oil and gas reserves and cash flow for the Contango properties are presented in Tables 3 through 24.  Table 25 is a one-line summary for all of the Contango wells.  This table is arranged with the wells listed in order of decreasing value (PV10%).

 

OTHER

 

Our definition of reserves may be found in Appendix A of this report.  It is similar to and consistent with reserve definitions used throughout the industry.  We have not made any field examination of the Contango properties; therefore, operating ability and condition of the production equipment have not been considered.  No consideration was given in this report to potential environmental liabilities which may exist, nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices.

 

In evaluating the information at our disposal concerning this appraisal, we have excluded from our consideration all matters as to which legal or accounting interpretation, rather than engineering, may be controlling.  As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering data and such conclusions necessarily represent only informed professional judgments.

 

The reserves included in this report are estimates only and should not be construed as being exact quantities.  The revenues from such reserves and the actual costs related thereto could be more or less than the estimated amounts.  Because of governmental policies and uncertainties of supply and demand, the prices actually received for the reserves evaluated in this report, and the costs incurred in

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recovering such reserves, may vary from the price and cost assumptions used in this report.  Our estimates are based upon the assumption that the properties will be operated in a prudent manner and that no government regulations and controls will be instituted that would impact the ability of Contango to recover the reserves. In any case, estimates of reserves may increase or decrease as a result of future operations.

 

Titles to the appraised properties have not been examined by Cobb & Associates, nor has the actual degree of interest owned been independently confirmed.  The data used in our evaluation were obtained from Contango and the nonconfidential files of Cobb & Associates and were considered accurate.  Basic field performance data, together with our engineering work sheets, are maintained on file in our office.

 

BP:ar

Attachments

COI SEC Jan 2015 011615.docx

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