[Company Letterhead]
September 28, 2010
VIA EDGAR AND UPS OVERNIGHT COURIER
Mr. Brad Skinner
Senior Assistant Chief Accountant
Securities and Exchange Commission
Division of Corporation Finance
Mail Stop 7010
Washington, D.C. 20549-7010
| Re: | Quicksilver Resources Inc. | |
Form 10-K for the Fiscal Year Ended December 31, 2009 Filed March 15, 2010 | ||
Form 10-Q for the Quarterly Period Ended June 30, 2010 Filed August 9, 2010 File No. 1-14837 |
Dear Mr. Skinner:
This letter sets forth the response of Quicksilver Resources Inc. to the comment provided by the staff (the “Staff”) of the Securities and Exchange Commission (the “Commission”) in its comment letter dated September 15, 2010 (the “Comment Letter”). For your convenience, we have repeated the comment of the Staff in bold type face exactly as given in the Comment Letter and set forth below such comment is our response.
Form 10-K for Fiscal Year Ended December 31, 2009
Exhibits 99.1, 99.2 and 99.4
| 1. | We note your response to prior comment ten of our letter dated July 2, 2010 and your related request to remove such limiting language from the reports in future filings. As these reports limit an investor's reliance on the estimation of proved reserves as of a point in time, we reissue our prior comment. Please obtain and file revised reports which retain no language that could suggest either a limited audience or a limit on potential investor reliance. |
Response: In response to the Staff’s comment, we have obtained revised drafts of reserve engineer reports from Schlumberger Data and Consulting Services and LaRoche Petroleum Consultants, Ltd., which do not contain the referenced language. Attached are marked copies of these draft reports reflecting the changes from the reports filed with our 2009 Form 10-K. Please advise us whether these revisions are acceptable. Assuming that you find them acceptable, we will file the revised reports as Exhibits 99.1, 99.2 and 99.4 in an amendment to our 2009 Form 10-K.
Mr. Brad Skinner September 28, 2010 Page 2 |
If you have any questions or comments regarding any of the foregoing, please contact me at 817-665-5000.
Very truly yours, /s/ Philip Cook Philip Cook Senior Vice President – Chief Financial Officer |
| cc: | Bob Carroll |
Shannon Buskirk U. S. Securities and Exchange Commission |
DRAFT
Exhibit 99.1
Data and Consulting Services
Division of Schlumberger Technology Corporation
Schlumberger
Two Robinson Plaza, Suite 200
6600 Steubenville Pike
Pittsburgh, Pennsylvania 15205
Tel: 412-787-5403
Fax: 412-787-2906
15 February23 September, 2010
Quicksilver Resources, Inc.
777 West Rosedale801 Cherry Street, Suite 3700 Unit 19
Fort Worth, Texas 761042
Dear Gentlemen:
At the request of Quicksilver Resources, Inc. (QRI), through their letter of engagement, Data & Consulting Services (DCS) Division of Schlumberger Technology Corporation has evaluated the proved reserves of certain QRI oil and gas interests located in the United States (US) as of 31 December 2009. The evaluated properties are located in Colorado, Montana, Texas, and Wyoming. This report was completed as of the date of this letter and has been prepared using constant prices and costs and conforms to our understanding of the U.S. Securities and Exchange Commission (SEC) guidelines and applicable financial accounting rules. All prices, costs, and cash flow estimates are expressed in US dollars (US$). It is our understanding that the properties evaluated by DCS compris e one hundred percent (100%) of QRI’s proved reserves located in the US and comprise approximately ninety percent (90%) of QRI’s total proved reserves. We believe that the assumptions, data, methods, and procedures used in preparing this report are appropriate for the purpose of this report. The Lead Evaluator for this evaluation was Charles M. Boyer II, PG, CPG, and his qualifications, independence, objectivity, and confidentiality meet the requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
Table 1 summarizes the estimates of the net reserves and future net revenue, as of 31 December 2009, for the QRI US evaluated properties. Unescalated prices and costs were used for all properties contained in this evaluation.
Table 1
Estimated Net Reserves And Future Net Revenue
Certain Proved Oil And Gas Interests
Quicksilver Resources, Inc.
United States Producing Properties
As Of 31 December 2009
| Proved | Proved | Proved | Total | |||||||||||||
| Producing | Nonproducing | Undeveloped | Proved | |||||||||||||
| Reserves | Reserves | Reserves | Reserves | |||||||||||||
| Remaining Net Reserves | ||||||||||||||||
| Oil, MBbls | 1,863.3 | 603.4 | 391.4 | 2,858.0 | ||||||||||||
| Gas, MMscf | 636,332.4 | 407,807.2 | 511,894.3 | 1,556,034.0 | ||||||||||||
| NGL, MBbls | 50,150.3 | 10,846.2 | 37,264.9 | 98,261.4 | ||||||||||||
| Income Data (M$) | ||||||||||||||||
| Future Net Revenue | 3,474,639.8 | 1,644,471.0 | 2,668,310.5 | 7,787,422.0 | ||||||||||||
| Future Net Cashflow | 1,493,605.4 | 610,957.2 | 574,400.9 | 2,678,963.8 | ||||||||||||
| Discounted PV @ 10% (M$) | 765,019.1 | 235,575.0 | 2,933.9 | 1,003,528.1 | ||||||||||||
Data & Consulting Services
Division of Schlumberger Technology Corporation
Schlumberger
15 February23 September, 2010
Page 2
Values in the tables of this report may not add up arithmetically due to rounding procedure in the computer software program used to prepare the economic projections. All hydrocarbon liquids are reported as 42 gallon barrels. Gas volumes are reported at the standard pressure and temperature bases of the area where the gas is sold.
We are independent with respect to QRI as provided in the SEC regulations. Neither the employment of nor the compensation received by DCS was contingent upon the values estimated for the properties included in this report.
Oil and gas reserves by definition fall into one of the following categories: proved, probable, and possible. The proved category is further divided into: developed and undeveloped. The developed reserve category is even further divided into the appropriate reserve status subcategories: producing and non-producing. Non-producing reserves include shut-in and behind-pipe reserves. The reserves included in this report include only proved reserves and do not include probable or possible reserves. QRI has an active exploration and development program to develop their interests in certain tracts not classified as proved at this time. Future drilling may result in the reclassification of additional volumes to the proved reserve category. &# 160;However, changes in the regulatory requirements for oil and gas operations may impact future development plans and the ability of the company to recover the estimated proved undeveloped reserves. The reserves and income attributable to the various reserve categories included in this report have not been adjusted to reflect the varying degrees of risk associated with them.
Reserve estimates are strictly technical judgments. The accuracy of any reserve estimate is a function of the quality and quantity of data available and of the engineering and geological interpretations. The reserve estimates presented in this report are believed reasonable; however, they are estimates only and should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify their revision. A portion of these reserves are for undeveloped locations and producing or non-producing wells that lack sufficient production history to utilize conventional performance-based reserve estimates. In these cases, the reserves are based on volumetric estimates and recovery efficiencies along with analogies to similar producing areas. These res erve estimates are subject to a greater degree of uncertainty than those based on substantial production and pressure data. As additional production and pressure data becomes available, these estimates may be revised up or down. Actual future prices may vary significantly from the prices used in this evaluation; therefore, future hydrocarbon volumes recovered and the income received from these volumes may vary significantly from those estimated in this report. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.
Standard geological and engineering methods generally accepted by the petroleum industry were used in the estimation of QRI’s reserves. Deterministic methods were used for all reserves included in this report. The appropriate combination of conventional decline curve analysis (DCA), production data analysis, volumetrics, reservoir simulation, and type curves were used to estimate the remaining reserves in the various producing areas. Volumetric calculations were based on data and maps provided by QRI. Any reservoir simulation efforts were conducted using EclipseTM, which is DCS’s multi-phase reservoir simulator designed specifically for evaluating fractured shale formations. Comparisons were made to similar properties for which more complete data were available for areas of new development.
Data & Consulting Services
Division of Schlumberger Technology Corporation
Schlumberger
15 February23 September, 2010
Page 3
All prices used in preparation of this report were based on the twelve month unweighted arithmetic average of the first day of the month price for the period January through December 2009. The resulting Henry Hub gas price used was $3.870/MMBtu and the resulting West Texas Intermediate oil price used was $61.18/Bbl. The prices were adjusted for local differentials, gravity and Btu where applicable. As required by SEC guidelines, all pricing was held constant for the life of the projects (no escalation).
Operating costs used in this report were based on values reported by QRI and reviewed by DCS. Well costs include direct expenses, allocated general and administrative overhead (G&A), production taxes, marketing, transportation, and compression charges. QRI’s estimates for capital costs for all non-producing and undeveloped wells are included in the evaluation. QRI has indicated to us that they have the ability and intent to implement their capital expenditure program as scheduled. Operating costs and capital costs were held constant for the life of the projects (no escalation).
Net revenue (sales) is defined as the total proceeds from the sale of oil, condensate, natural gas liquids (NGL), and gas adjusted for commodity price basis differential and gathering/ transportation expense. Future net income (cashflow) is future net revenue less net lease operating expenses, state severance or production taxes, operating/development capital expenses and net salvage. Future net income (cashflow) for nonoperated wells includes those general and administrative (G&A) deductions charged by the operator for a particular well or project on a monthly basis; operated well G&A deductions include only those expenses estimated as necessary to continue production activities. Future plugging, abandonment, and salvage costs are included at the economic life of each well or unit. N o provisions for State or Federal income taxes have been made in this evaluation. The present worth (discounted cashflow) at various discount rates is calculated on a monthly basis.
In the conduct of our evaluation, we have not independently verified the accuracy and completeness of information and data furnished by QRI with respect to ownership interests, historical gas production, costs of operation and development, product prices, payout balances, and agreements relating to current and future operations and sales of production. If in the course of our examination something came to our attention which brought into question the validity or sufficiency of any of the information or data provided by QRI, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or independently verified such information or data.
In our opinion the above-described estimates of QRI’s proved reserves and supporting data are, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles. It is also our opinion that the above-described estimates of QRI’s proved reserves conform to the definitions of proved oil and gas reserves promulgated by the SEC. These reserves definitions are provided at the conclusion of this letter.
All data used in this study were obtained from QRI, public industry information sources, or the non-confidential files of DCS. A field inspection of the properties was not made in connection with the preparation of this report. The potential environmental liabilities attendant to ownership and/or operation of the properties have not been addressed in this report. Abandonment and clean-up costs and possible salvage value of the equipment were considered in this report.
Data & Consulting Services
Division of Schlumberger Technology Corporation
Schlumberger
15 February23 September, 2010
Page 4
In evaluating the information at our disposal related to this report, we have excluded from our consideration all matters which require a legal or accounting interpretation, or any interpretation other than those of an engineering or geological nature. In assessing the conclusions expressed in this report pertaining to all aspects of oil and gas evaluations, especially pertaining to reserve evaluations, there are uncertainties inherent in the interpretation of engineering data, and such conclusions represent only informed professional judgments.
This report was prepared solely for the use of the party to whom it is addressed and any disclosure made of this report and/or the contents by said party thereof shall be solely the responsibility of said party and shall in no way constitute any representation of any kind whatsoever of the undersigned with respect to the matters being addressed.
Data and worksheets used in the preparation of this evaluation will be maintained in our files in Pittsburgh and will be available for inspection by anyone having proper authorization from QRI.
Sincerely yours,
| /s/ Denise L. Delozier | /s/ Charles M. Boyer | |||
| Denise L. Delozier | Charles M. Boyer II, PG, CPG | |||
| Senior Engineer | Scientific Advisor | |||
| Unconventional Reservoirs |
| /s/ Walter K. Sawyer | /s/ Jeron R. Williamson | |||
| Walter K. Sawyer, PE | Jeron R. Williamson | |||
| Principal Consultant | Senior Engineer |
DRAFT
Exhibit 99.2
January 20September 22, 2010
Mr. Robert N. WagnerChris Mundy
Quicksilver Resources, Inc.
Suite 3700, Unit 19
777 West Rosedale Street, Suite 300801 Cherry Street
Fort Worth, Texas 76104 76102
Dear Mr. WagnerMundy:
At your request, LaRoche Petroleum Consultants, Ltd. (LPC) has estimated the proved reserves and future cash flow, as of December 31, 2009, to the Quicksilver Resources, Inc. (Quicksilver) interest in certain properties located in Alberta and British Columbia Provinces, Canada. This report was completed as of the date of this letter. This report was prepared to provide Quicksilver with U.S. Securities and Exchange Commission (SEC) compliant reserve estimates. It is our understanding that the properties evaluated by LPC comprise one hundred percent (100%) of Quicksilver’s proved reserves located in Canada. We believe that the assumptions, data, methods, and procedures used in preparing this report, as set out below, are appropriate for the purpose of this report. This report has been prepared using constant prices and costs and conforms to our understanding of the SEC guidelines and applicable financial accounting rules. All prices, costs, and cash flow estimates are expressed in United States dollars (US$)
It is our understanding that the reserves for the properties located in Canada represent twelve percent (12%) of Quicksilver’s aggregate proved reserves.
Summarized below are our estimates of net reserves and future net cash flow. Future net revenue is after deducting estimated Crown royalties but prior to deducting freehold mineral taxes. Future net cash flow is after deducting freehold mineral taxes, operating expenses, future capital expenditures, and abandonment costs but before consideration of Canadian or United States income taxes. The discounted cash flow values included in this report are intended to represent the time value of money and should not be construed to represent an estimate of fair market value. All prices, costs, and cash flow estimates are expressed in United States dollars (US$). We estimate the net reserves and future net cash flow to the Quicksilver interest, as of December 31, 2009, to be:
Net Proved Reserves and Net Cash Flow(1) | ||||||||||||||||
| Category | Producing | Non-Producing | Undeveloped | Total(2) | ||||||||||||
| Net Remaining Reserves | ||||||||||||||||
| Oil - MBbl | 0 | 0 | 0 | 0 | ||||||||||||
| Gas - MMcf | 201,325 | 21,974 | 29,753 | 253,053 | ||||||||||||
| NGL - MBbl | 13 | 0 | 0 | 13 | ||||||||||||
| Income Data (US M$) | ||||||||||||||||
| Future Net Revenue (US M$) | 365,252 | 32,138 | 21,912 | 419,302 | ||||||||||||
| Discounted PV @ 10% (US M$) | 224,497 | 17,239 | 1,173 | 242,909 | ||||||||||||
| (1) | Includes reserves and cash flow attributable to split-title properties. For proved developed producing, split-title cases contribute 4,008 MMCF of net gas reserves and M $5,284 of the PV discounted at 10%. For proved developed non-producing, the contribution is 3,978 MMCF of net gas reserves and M $2,762 of the PV discounted at 10%. For proved undeveloped, the contribution is 18,244 MMCF of net gas and M$ -63 of the PV10%. |
| (2) | The total proved column may not match the sum of the detailed economic summaries by reserve category due to rounding by the economics program. |
The oil reserves include crude oil and condensate. Oil and NGL reserves are expressed in barrels, which are equivalent to 42 United States gallons. Gas reserves are expressed in thousands of standard cubic feet (Mcf) at the contract temperature and pressure bases.
The estimated reserves and future cash flow shown in this report are for proved developed producing reserves and, for certain properties, proved developed non-producing and proved undeveloped reserves. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.
Both the gross and net gas reserves presented in this report are after shrinkage. All prices, revenues, expenses, and cash flows referenced in this report are in United States dollars which have been converted from Canadian currency using the December 31, 2009 exchange rate.
Estimates of reserves were prepared using standard geological and engineering methods generally accepted by the petroleum industry. The reserves in this report have been estimated using deterministic methods. The method or combination of methods utilized in the evaluation of each reservoir included consideration of the stage of development of the reservoir, quality and completeness of basic data, and production history. Recovery from various reservoirs and leases was estimated after consideration of the type of energy inherent in the reservoirs, the structural positions of the properties, and reservoir and well performance. In some instances, comparisons were made to similar properties for which more complete data were available. We have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting, rather than engineering or geoscience.
The estimated reserves and future cash flow amounts in this report are related to hydrocarbon prices. Historical prices through December 2009 were used in the preparation of this report as required by SEC guidelines; however, actual future prices may vary significantly from the SEC prices. In addition, future changes in environmental and administrative regulations may significantly affect the ability of Quicksilver to produce oil and gas at the projected levels. Therefore, volumes of reserves actually recovered and amounts of cash flow actually generated may differ significantly from the estimated quantities presented in this report.
Prices used in this report are based on the twelve-month unweighted arithmetic average of the first day of the month price for the period January through December 2009. Gas prices are referenced to an AECO price of US $3.76 per MMBtu adjusted for energy content, transportation fees, and regional price differentials. Oil and NGL prices used in this report are referenced to a West Texas Intermediate crude oil price of US $61.18 per barrel adjusted for gravity, transportation fees, and regional price differentials. These reference prices are held constant in accordance with SEC guidelines.
Lease and well operating expenses are based on data obtained from Quicksilver. Expenses for the properties operated by Quicksilver include allocated overhead costs, direct lease and field level costs as well as compression costs and marketing expenses. Wells operated by others include all direct expenses as well as general, administrative, and overhead costs allowed under the specific joint operating agreements. Lease and well operating costs are held constant in accordance with SEC guidelines.
Capital costs and timing of all investments have been provided by Quicksilver and are included as required for workovers, new development wells, and production equipment. Quicksilver has represented to us that they have the ability and intent to implement their capital expenditure program as scheduled. These costs are held constant.
LPC has made no investigation of possible gas volume and value imbalances that may have resulted from the overdelivery or underdelivery to the Quicksilver interest. Our projections are based on the Quicksilver interest receiving its net revenue interest share of estimated future gross oil and gas production.
Technical information necessary for the preparation of the reserve estimates herein was furnished by Quicksilver or was obtained from state regulatory agencies and commercially available data sources. No special tests were obtained to assist in the preparation of this report. For the purpose of this report, the individual well test and production data as reported by the above sources were accepted as represented together with all other factual data presented by Quicksilver including the extent and character of the interest evaluated. The reserves in this report include volumes subject to “split-title” issues for which we have accepted the ownership as presented by Quicksilver.
An on-site inspection of the properties has not been performed nor have we examined the mechanical operation or condition of the wells and their related facilities. Quicksilver’s estimates of the cost to plug and abandon the wells net of salvage value are included at the end of the economic life of each well. However, the costs associated with the continued operation of uneconomic properties are not reflected in the cash flows.
The evaluation of potential environmental liability from the operation and abandonment of the properties is beyond the scope of this report. In addition, no evaluation was made to determine the degree of operator compliance with current environmental rules, regulations, and reporting requirements. Therefore, no estimate of the potential economic liability, if any, from environmental concerns is included in the projections presented herein.
The reserves included in this report are estimates only and should not be construed as exact quantities. They may or may not be recovered; if recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. These estimates should be accepted with the understanding that future development, production history, changes in regulations, product prices, and operating expenses would probably cause us to make revisions in subsequent evaluations. A portion of these reserves are for behind-pipe zones, undeveloped locations, and producing wells that lack sufficient production history to utilize performance-related reserve estimates. Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogies to sim ilar production. These reserve estimates are subject to a greater degree of uncertainty than those based on substantial production and pressure data. It may be necessary to revise these estimates up or down in the future as additional performance data become available. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geological data; therefore, our conclusions represent informed professional judgments only, not statements of fact.
This report is solely for the use of Quicksilver, its agents, and its representatives in their evaluation of these properties and is not to be used, circulated, quoted, or otherwise referenced for any other purpose without the express written consent of the undersigned. Persons other than those to whom this report is addressed shall not be entitled to rely upon the report unless it is accompanied by such consent.
The results of our third party study were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Quicksilver.
Quicksilver makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Quicksilver has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Quicksilver of the references to our name as well as to the references to our third party report for Quicksilver which appears in the December 31, 2009 annual report on Form 10-K and/or 10-K/A of Quicksilver. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Quicksilver.
We have provided Quicksilver with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Quicksilver and the original signed report letter, the original signed report letter shall control and supersede the digital version.
The technical persons responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We are independent petroleum engineers, geologists and geophysicists and are not employed on a contingent basis. Data pertinent to this report are maintained on file in our office.
Very truly yours, LaRoche Petroleum Consultants, Ltd. State of Texas Registration Number F-1360 Joe A. Young Licensed Professional Engineer State of Texas No. 62866 Stephen W. Daniel Licensed Professional Engineer State of Texas No. 58581 |
JAY:lbm
09-910
Exhibit 99.4
Data and Consulting Services
Division of Schlumberger Technology Corporation
Schlumberger
Two Robinson Plaza, Suite 200
6600 Steubenville Pike
Pittsburgh, Pennsylvania 15205
Tel: 412-787-5403
Fax: 412-787-2906
29 January28 September, 2010
Mark L. Pease
Executive Vice President, Chief Operating Officer
BreitBurn GP, LLC
600 Travis Street, Suite 4800
Houston, Texas 77002
Dear Mr. Pease:
At the request of BreitBurn Management Company, LLC (BreitBurn), through their letter of engagement, Data & Consulting Services (DCS) Division of Schlumberger Technology Corporation has evaluated the proved reserves of certain BreitBurn oil and gas interests as of 31 December 2009. The evaluated properties are located in Indiana, Kentucky, and Michigan. This report was completed as of the date of this letter and has been prepared using constant prices and costs and conforms to our understanding of the U.S. Securities and Exchange Commission (SEC) guidelines and applicable financial accounting rules. All prices, costs, and cash flow estimates are expressed in U.S. dollars (US$). The reserves and future net revenue are to the interest of BreitBurn Operating L.P. (BOLP). It is our understanding that the properties evaluated by DCS comprise seventy percent (70%) of BreitBurn’s proved reserves. We believe that the assumptions, data, methods, and procedures used in preparing this report are appropriate for the purpose of this report. The Lead Evaluator for this evaluation was Charles M. Boyer II, PG, CPG, and his qualifications, independence, objectivity, and confidentiality meet the 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.
Table 1 summarizes the estimates of the net reserves and future net revenue, as of 31 December 2009, for the BreitBurn U.S. evaluated properties. Unescalated prices and costs were used for all properties contained in this evaluation.
DRAFT - FOR DISCUSSION PURPOSES ONLY
Data & Consulting Services
Division of Schlumberger Technology Corporation
Schlumberger
29 January28 September, 2010
Page 2
Table 1
Estimated Net Reserves And Future Net Revenue
Certain Proved Oil And Gas Interests
BreitBurn Management Company, LLC
United States Producing Properties
As Of 31 December 2009
| Proved | Proved | Proved | Total | |||||||||||||
| Producing | Non-producing | Undeveloped | Proved | |||||||||||||
| Reserves | Reserves | Reserves | Reserves | |||||||||||||
| Remaining Net Reserves | ||||||||||||||||
| Oil/Cond/Ngl – Mbbls | 3,297.05 | 690.23 | 1,089.11 | 5,076.38 | ||||||||||||
| Gas – MMscf | 344,412.27 | 53,621.83 | 35,539.94 | 433,574.03 | ||||||||||||
| Income Data (M$) | ||||||||||||||||
| Future Net Revenue | 1,509,569.96 | 247,452.44 | 195,321.36 | 1,952,343.75 | ||||||||||||
| Deductions | ||||||||||||||||
| Operating Expense | 771,394.25 | 54,440.91 | 35,926.54 | 861,761.69 | ||||||||||||
| Production Taxes | 93,124.03 | 14,469.43 | 12,305.25 | 119,898.71 | ||||||||||||
| Investment | 37,918.42 | 28,932.05 | 42,783.13 | 109,633.60 | ||||||||||||
| Future Net Cashflow | 607,133.26 | 149,610.05 | 104,306.44 | 861,049.75 | ||||||||||||
| Discounted PV @ 10% (M$) | 285,350.31 | 55,444.17 | 31,426.74 | 372,221.22 | ||||||||||||
Values in the tables of this report may not add up arithmetically due to rounding procedure in the computer software program used to prepare the economic projections. All hydrocarbon liquids are reported as 42 gallon barrels. Gas volumes are reported at the standard pressure and temperature bases of the area where the gas is sold.
We are independent with respect to BreitBurn as provided in the SEC regulations. Neither the employment of nor the compensation received by DCS was contingent upon the values estimated for the properties included in this report.
DRAFT - FOR DISCUSSION PURPOSES ONLY
Data & Consulting Services
Division of Schlumberger Technology Corporation
Schlumberger
29 January28 September, 2010
Page 3
Oil and gas reserves by definition fall into one of the following categories: proved, probable, and possible. The proved category is further divided into: developed and undeveloped. The developed reserve category is even further divided into the appropriate reserve status subcategories: producing and non-producing. Non-producing reserves include shut-in and behind-pipe reserves. The reserves included in this report include only proved reserves and do not include probable or possible reserves. BreitBurn has an active exploration and development program to develop their interests in certain tracts not classified as proved at this time. Future drilling may result in the reclassification of additional volumes to the proved reserve category.&# 160; However, changes in the regulatory requirements for oil and gas operations may impact future development plans and the ability of the company to recover the estimated proved undeveloped reserves. The reserves and income attributable to the various reserve categories included in this report have not been adjusted to reflect the varying degrees of risk associated with them.
Reserve estimates are strictly technical judgments. The accuracy of any reserve estimate is a function of the quality and quantity of data available and of the engineering and geological interpretations. The reserve estimates presented in this report are believed reasonable; however, they are estimates only and should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify their revision. A portion of these reserves are for undeveloped locations and producing or non-producing wells that lack sufficient production history to utilize conventional performance-based reserve estimates. In these cases, the reserves are based on volumetric estimates and recovery efficiencies along with analogies to similar producing areas. These res erve estimates are subject to a greater degree of uncertainty than those based on substantial production and pressure data. As additional production and pressure data becomes available, these estimates may be revised up or down. Actual future prices may vary significantly from the prices used in this evaluation; therefore, future hydrocarbon volumes recovered and the income received from these volumes may vary significantly from those estimated in this report. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.
Standard geological and engineering methods generally accepted by the petroleum industry were used in the estimation of BreitBurn’s reserves. Deterministic methods were used for all reserves included in this report. The appropriate combination of conventional decline curve analysis (DCA), production data analysis, volumetrics, reservoir simulation, and type curves were used to estimate the remaining reserves in the various producing areas. Volumetric calculations were based on data and maps provided by BreitBurn.
All prices used in preparation of this report were based on the twelve month unweighted arithmetic average of the first day of the month price for the period January through December 2009. The resulting gas price used was $3.866/MMBtu and the resulting oil price used was $61.18/Bbl. The prices were adjusted for local differentials, gravity and Btu where applicable. As required by SEC guidelines, all pricing was held constant for the life of the projects (no escalation).
DRAFT - FOR DISCUSSION PURPOSES ONLY
Data & Consulting Services
Division of Schlumberger Technology Corporation
Schlumberger
29 January28 September, 2010
Page 4
Operating costs used in this report were based on values reported by BreitBurn and reviewed by DCS. BreitBurn’s estimates for capital costs for all non-producing and undeveloped wells are included in the evaluation. BreitBurn has indicated to us that they have the ability and intent to implement their capital expenditure program as scheduled. Operating costs and capital costs were held constant for the life of the projects (no escalation).
Net revenue (sales) is defined as the total proceeds from the sale of oil, condensate, natural gas liquids (NGL), and gas adjusted for commodity price basis differential and gathering/ transportation expense. Future net income (cashflow) is future net revenue less net lease operating expenses, state severance or production taxes, operating/development capital expenses and net salvage. Future plugging, abandonment, and salvage costs are included at the economic life of each well or unit. No provisions for State or Federal income taxes have been made in this evaluation. The present worth (discounted cashflow) at various discount rates is calculated on a monthly basis.
In the conduct of our evaluation, we have not independently verified the accuracy and completeness of information and data furnished by BreitBurn with respect to ownership interests, historical gas production, costs of operation and development, product prices, payout balances, and agreements relating to current and future operations and sales of production. If in the course of our examination something came to our attention which brought into question the validity or sufficiency of any of the information or data provided by BreitBurn, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or independently verified such information or data.
In our opinion the above-described estimates of BreitBurn’s proved reserves and supporting data are, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation methods and procedures. It is also our opinion that the above-described estimates of BreitBurn’s proved reserves conform to the definitions of proved oil and gas reserves promulgated by the Securities and Exchange Commission. These reserves definitions are provided at the conclusion of this letter.
All data used in this study were obtained from BreitBurn, public industry information sources, or the non-confidential files of DCS. A field inspection of the properties was not made in connection with the preparation of this report. The potential environmental liabilities attendant to ownership and/or operation of the properties have not been addressed in this report. Abandonment and clean-up costs and possible salvage value of the equipment were considered in this report.
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Data & Consulting Services
Division of Schlumberger Technology Corporation
Schlumberger
29 January28 September, 2010
Page 5
In evaluating the information at our disposal related to this report, we have excluded from our consideration all matters which require a legal or accounting interpretation, or any interpretation other than those of an engineering or geological nature. In assessing the conclusions expressed in this report pertaining to all aspects of oil and gas evaluations, especially pertaining to reserve evaluations, there are uncertainties inherent in the interpretation of engineering data, and such conclusions represent only informed professional judgments.
This report was prepared solely for the use of the party to whom it is addressed and any disclosure made of this report and/or the contents by said party thereof shall be solely the responsibility of said party and shall in no way constitute any representation of any kind whatsoever of the undersigned with respect to the matters being addressed.
Data and worksheets used in the preparation of this evaluation will be maintained in our files in Pittsburgh and will be available for inspection by anyone having proper authorization from BreitBurn.
Sincerely yours,
/s/ Denise L. Delozier | /s/ Charles M. Boyer | |||
Denise L. Delozier | Charles M. Boyer II, PG, CPG | |||
| Senior Engineer | Scientific Advisor | |||
| Unconventional Reservoirs |
/s/ Walter K. Sawyer | /s/ Jeron R. Williamson | |||
Walter K. Sawyer, P.E. | Jeron R. Williamson | |||
Principal Consultant | Senior Engineer |
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SECURITIES AND EXCHANGE COMMISION
REGULATION S-X, RULE 210.4-10 (a)
RESERVES DEFINITIONS
(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:
(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
(ii) Same environment of deposition;
(iii) Similar geological structure; and
(iv) Same drive mechanism.
Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.
(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.
(16) Oil and gas producing activities.
(i) Oil and gas producing activities include:
(A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;
(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
(1) Lifting the oil and gas to the surface; and
(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
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Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:
a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.
(ii) Oil and gas producing activities do not include:
(A) Transporting, refining, or marketing oil and gas;
(B) Processing of produced oil, gas or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
(D) Production of geothermal steam.
(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% probability that the total quantities ultimately recovered will equal or exceed the 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 a defined project.
(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable
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technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
(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, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities 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.
(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
(21) Proved area. The part of a property to which proved reserves have been specifically attributed.
(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology
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establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
(23) Proved properties. Properties with proved reserves.
(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category 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.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
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(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
(32) Unproved properties. Properties with no proved reserves.
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