Exhibit 99.1
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
February 18, 2013
GeoMet, Inc.
909 Fannin
Suite 1850
Houston, Texas 77010
Ladies and Gentlemen:
Pursuant to your request, we have prepared estimates of the extent and value of the net proved developed natural gas reserves, as of December 31, 2012, of certain coal bed methane properties owned by GeoMet, Inc. (GeoMet). Because GeoMet indicated that it does not have a commitment to drill wells in the appraised fields, no undeveloped reserves were estimated. This evaluation was completed on February 18, 2013. GeoMet has represented that these properties account for 83.4 percent of GeoMet’s net proved reserves as of December 31, 2012. The properties appraised consist of working interests in wells located in the Gurnee and White Oak Creek fields in Alabama and the Pond Creek and Lasher fields in West Virginia and Virginia. The net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4—10(a) (1)—(32) of Regulation S—X of the Securities and Exchange Commission (SEC) of the United States. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by GeoMet.
Reserves included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2012. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by GeoMet after deducting all interests owned by others.
Estimates of gas reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information
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become available. Not only are such reserves and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.
Data used in this evaluation were obtained from reviews with GeoMet personnel, GeoMet files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by GeoMet with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.
Methodology and Procedures
Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principals and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.
White Oak Creek Field
The properties evaluated in the White Oak Creek field in Alabama produce from the Pratt, New Castle, Mary Lee, and Black Creek coal seams and are located in the western portion of the Black Warrior basin. The composite thickness of these coal seams in this area varies from 10 feet to more than 15 feet. The coal in this area is water saturated and requires stimulation and a dewatering period before maximum gas rates are achieved. This area is predominately being developed on an 80-acre well spacing.
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Production-decline curves for all of the coal bed methane wells in the immediate six township areas surrounding these properties were analyzed, using production data available as of the date of this report, to determine the typical production profile for the wells in this area. The producing rates for wells in this area typically incline for several years as the area is being dewatered. The rates then either decline immediately or remain flat for several years and then decline depending on the rate of dewatering and, consequently, the drawdown in reservoir pressure.
The volumetric method was used to estimate original gas in place (OGIP) for each of the 80-acre tracts in which GeoMet owns an interest. Isopach maps were used to estimate coal volume, and the gas content of the coal was obtained from canister tests performed on various cores taken in the area.
Estimates of ultimate recovery were obtained after applying recovery factors to OGIP. Recovery factors were based on analogy with older wells in the area for which the producing trends disclosed a reliable decline that could be extrapolated to an economic limit.
Proved developed producing reserves were estimated for the older wells by extrapolating production-decline curves to an economic limit based on existing economic conditions. For producing wells where the rates of production were inclining or flat, the volumetric method was used to estimate the reserves and the type curves were used to project the future rates of production.
All properties evaluated in the White Oak Creek field are currently producing.
Gurnee Field
All of the properties evaluated in the Gurnee field in Alabama are producing or will produce from the Gholson, Coke, Jones/Alice, Big Bone/J, and Big Dirty coal seams and are located in the Gurnee basin. The composite thickness of these coal seams in this area varies from 25 feet to more than 85 feet. Average composite thickness is approximately 50 feet. The coal in this area is water saturated and requires stimulation and a dewatering period before maximum gas rates are achieved. This area is predominately being developed on an 80-acre well spacing.
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Production-decline curves for all of the coal bed methane wells in the immediate five township areas surrounding GeoMet’s Gurnee properties were analyzed, using production data available as of the date of this report, to determine the typical production profile for the wells in this area. The producing rates for wells in this area typically incline for several years as the area is being dewatered. The rates then either decline immediately or remain flat for several years and then decline depending on the rate of dewatering and, consequently, the drawdown in reservoir pressure.
The volumetric method was used to estimate OGIP for each of the 80-acre tracts in which GeoMet owns an interest. Isopach maps were used to estimate coal volume, and the gas content of the coal was obtained from canister tests performed on various cores taken in the area.
Estimates of ultimate recovery were obtained after applying recovery factors to OGIP. Recovery factors were based on experience and general knowledge of established coal bed methane projects in the Gurnee basin and adjacent Black Warrior basin.
Proved developed producing reserves were estimated for the older wells by extrapolating production-decline curves to an economic limit based on existing economic conditions. For producing wells where the rates of production were inclining or flat, the volumetric method was used to estimate the reserves and the type curves were used to project the future rates of production.
All properties evaluated in the Gurnee field are currently producing.
Pond Creek Field
All of the properties in the Pond Creek field in West Virginia and Virginia evaluated in this report are producing or will produce from the Pocahontas coal seams 1 through 10 in the Central Appalachian basin. The composite thickness of the coal seams in this area varies from 15 feet to more than 35 feet. The coal in this area is partially water saturated and requires stimulation and a dewatering period before maximum gas rates are achieved. This area is predominately being developed on 60-acre well spacing.
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Production-decline curves for coal bed methane wells in McDowell County in West Virginia and Buchanan County in Virginia were analyzed, using production data available as of the date of this report, to determine the typical production profile for the wells in this area. The gas producing rates in this area typically incline for several years as the area is being dewatered. The rates then either decline immediately or remain flat for several years and then decline depending on the rate of dewatering and, consequently, the drawdown in reservoir pressure.
The volumetric method was used to estimate the OGIP for each 60-acre tract in which GeoMet owns an interest. Isopach maps were used to estimate coal volume. Gas content of the coal was obtained from canister tests performed on cores taken in the area.
Estimates of ultimate recovery were obtained after applying recovery factors to OGIP. Recovery factors were based on experience and general knowledge of established coal bed methane projects in the Central Appalachian basin.
Proved developed producing reserves were estimated for the older wells by extrapolating production-decline curves to an economic limit based on existing economic conditions. For producing wells where the rates of production were inclining or flat, the volumetric method was used to estimate the reserves and the type curves were used to project the future rates of production.
All properties evaluated in the Pond Creek field are currently producing.
Lasher Field
All of the properties in the Lasher field in West Virginia evaluated in this report are producing from the Fire Creek coal seams and Pocahontas coal seams 1 through 10 in the Central Appalachian basin. The composite thickness of the coal seams in this area varies from 10 feet to more than 18 feet. The coal in this area is partially water saturated and requires stimulation and a dewatering period before maximum gas rates are achieved. This area is predominately being developed on 60-acre well spacing.
The volumetric method was used to estimate the OGIP for each 60-acre tract in which GeoMet owns an interest. Isopach maps were used to estimate coal volume.
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Gas content of the coal was obtained from canister tests performed on cores taken in the area.
Estimates of ultimate recovery were obtained after applying recovery factors to OGIP. Recovery factors were based on experience and general knowledge of established coal bed methane projects in the Central Appalachian basin.
Proved developed producing reserves were estimated for the older wells by extrapolating production-decline curves to an economic limit based on existing economic conditions. For producing wells where the rates of production were inclining or flat, the volumetric method was used to estimate the reserves and the type curves were used to project the future rates of production.
All properties evaluated in the Lasher field are currently producing.
Definition of Reserves
Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4—10(a) (1)—(32) of Regulation S—X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:
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
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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 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
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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.
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.
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 [section 210.4—10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.
The development status shown herein represents the status applicable on December 31, 2012. In the preparation of this study, data available from wells drilled on the appraised properties through December 31, 2012, were used in estimating gross ultimate recovery. When applicable, gross production estimated to December 31, 2012, was deducted from gross ultimate recovery to arrive at the estimates of gross reserves as of December 31, 2012. Production data through October 2012 were available for most properties.
While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2012, estimated oil and gas volumes. The reserves estimated in this report can be produced under current regulatory guidelines.
Our estimates of GeoMet’s net proved reserves attributable to the reviewed properties are based on the definitions of proved reserves of the SEC and are as follows, expressed in millions of cubic feet (MMcf).
| | Estimated by
DeGolyer and MacNaughton
Net Proved Reserves
as of December 31, 2012 | |
| | Natural
Gas
(MMcf) | |
| | | |
Proved Developed Producing | | 114,403 | |
Proved Developed Non-Producing | | 0 | |
| | | |
Total Proved Developed | | 114,403 | |
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Primary Economic Assumptions
Revenue values in this report are expressed in terms of estimated future gross revenue, future net revenue, and present worth of future net revenue. These values are based on the economic conditions as defined by the SEC.
Future gross revenue is defined as that revenue to be realized from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated production taxes, ad valorem taxes, operating, gathering, processing expenses, and capital costs from the future gross revenue. Present worth of future net revenue is calculated by discounting the future net revenue at the arbitrary rate of 10 percent per year compounded monthly over the expected period of realization.
Revenue values in this report were estimated using the initial prices and expenses provided by GeoMet. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The prices used in this report are based on SEC guidelines. The assumptions used for estimating future prices and expenses are as follows:
Natural Gas Prices
GeoMet has represented that the natural gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. The gas prices were calculated for each property using differentials and heating value adjustments to the Henry Hub reference price of $2.76 per million British thermal units furnished by GeoMet and held constant thereafter. After adjustment for heating value, the volume-weighted average price was $2.938 per thousand cubic feet.
Operating Expenses and Capital Costs
Operating expenses and capital costs, based on information provided by GeoMet, were used in estimating future costs required to operate the properties. In certain cases, future
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costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation.
The estimated future revenue and expenditures attributable to the production and sale of GeoMet’s net proved developed reserves of the properties appraised, as of December 31, 2012, is summarized in thousands of dollars (M$) as follows:
| | Proved | |
| | Developed
Producing | | Developed
Nonproducing | | Total
Proved | |
| | | | | | | |
Future Gross Revenue, M$ | | 336,160 | | 0 | | 336,160 | |
Production and Ad Valorem Taxes, M$ | | 20,397 | | 0 | | 20,397 | |
Operating Expenses, M$ | | 204,101 | | 0 | | 204,101 | |
Capital Costs, M$ | | 6,921 | | 0 | | 6,921 | |
Future Net Revenue*, M$ | | 104,741 | | 0 | | 104,741 | |
Present Worth at 10 Percent*, M$ | | 51,151 | | 0 | | 51,151 | |
* Future income taxes have not been taken into account in the preparation of these estimates.
In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries — Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4—10(a) (1)—(32) of Regulation S—X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S—K of the Securities and Exchange Commission; provided, however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein and (ii) estimates of the proved developed reserves are not presented at the beginning of the year.
To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.
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DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in GeoMet. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of GeoMet. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.
| Submitted, |
| |
| /s/ DeGOLYER and MacNAUGHTON |
| |
| DeGOLYER and MacNAUGHTON |
| Texas Registered Engineering Firm F-716 |
| |
| |
| /s/ Paul J. Szatkowski, P.E. |
| Paul J. Szatkowski, P.E. |
| Senior Vice President |
| DeGolyer and MacNaughton |
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CERTIFICATE of QUALIFICATION
I, Paul J. Szatkowski, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:
1. That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to GeoMet dated February 18, 2013 and that I, as Senior Vice President, was responsible for the preparation of this report.
2. That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1974; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists; and that I have in excess of 38 years of experience in oil and gas reservoir studies and reserves evaluations.
| /s/ Paul J. Szatkowski, P.E. |
| Paul J. Szatkowski, P.E. |
| Senior Vice President |
| DeGolyer and MacNaughton |
