CORRESP 1 filename1.htm Response letter to the SEC

 

LOGO

October 22, 2010

Via EDGAR

Mark Wojciechowski

Staff Accountant

United States Securities and Exchange Commission

Division of Corporation Finance

Mail Stop 7010

150 F. Street, N.E.

Washington, D.C. 20549-7010

 

  Re: GeoMet, Inc. (the “Company”)
    Form 10-K for Fiscal Year Ended December 31, 2009
    Filed March 31, 2010
    Amendment No. 1 to Form 10-K for Fiscal Year Ended December 31, 2009
    Filed April 30, 2010
    Form 10-Q for Fiscal Quarterly Period Ended June 30, 2010
    Filed July 27, 2010
    File No. 0-52155

Dear Mr. Wojciechowski:

GeoMet, Inc. (the “Company”, “we” or “us”) is pleased to provide the United States Securities and Exchange Commission (the “Commission”) with the following responses to the comments included in the Commission’s letter dated September 17, 2010 regarding the captioned matter. The comments from that letter are set forth below, along with our responses.

Form 10-K for Fiscal Year Ended December 31, 2009

Business and Properties, page 8

Overview, page 8

 

1. We note your discussion of the downward revision in the proved reserves attributable to your Gurnee property. Describe for us, in reasonable detail, the material information and assumptions you relied on in determining the proved reserves for this property as of December 31, 2008. Explain your basis for concluding that the information and assumptions were sufficient to establish reasonable certainty for these reserve quantities as of December 31, 2008. Tell us how the information and assumptions as of December 31, 2008 differed from the information and assumptions used to determine the revised proved reserve quantities as of September 30, 2009.

Mark Wojciechowski

U. S. Securities and Exchange Commission

October 22, 2010

Page 2

 

 

Explain how you determined the isotherm(s) and gas content of the Gurnee CBM reservoir. Address whether you used adsorption or desorption techniques for gas content analysis. Furnish to us the current rate vs. time and rate vs. cumulative production plots/extrapolations for the field, including gas and water production, with narratives for negative revision events and other events you believe to be pertinent. You may contact us for guidance in this matter.

Please direct these items to:

Ronald M. Winfrey

Petroleum Engineer

Division of Corporation Finance

U.S. Securities & Exchange Commission

100 F Street, N.E.

Washington, DC 20549-4628

(202) 551-3704

Response

We have provided the requested information separately in hardcopy pursuant to a request for confidential treatment.

 

2. Please include disclosure regarding your proved undeveloped reserves pursuant to Item 1203(b)-1203(d) of Regulation S-K.

Response

Item 1203(b)

No proved undeveloped reserves as of December 31, 2008 were converted into proved developed reserves in 2009 because we did not drill any new wells during 2009 due to low natural gas prices and capital availability. Our proved undeveloped reserves as of December 31, 2009 were 20,159,649 Mcf less than the our proved undeveloped reserves as of December 31, 2008, approximately 6.2% of total proved reserves at December 31, 2008, due to the lower natural gas price used at December 31, 2009 and the lower recovery factor used in the Gurnee field at December 31, 2009. We discuss the downward revisions of our total proved reserves reported as of September 30, 2009 and December 31, 2009 on page 10 of our Annual Report on Form 10-K for the year ended December 31, 2009. We did not delineate between declines in our total proved reserves and proved undeveloped reserves in that discussion because the factors that resulted in downward revision of our total proved reserves were the very same factors that resulted in the downward revision of our proved undeveloped reserves. We therefore believed that no further disclosure was required under Item1203(b). In future filings when discussing changes in our proved reserves, we will include a separate discussion of material changes to our proved undeveloped reserves.

 

Mark Wojciechowski

U. S. Securities and Exchange Commission

October 22, 2010

Page 3

 

 

Item 1203(c)

As previously stated, we did not drill any new wells in 2009 (although we completed four wells in 2009 that were drilled in 2008, converting them from proved developed non-producing reserves as of December 31, 2008 to proved developed producing reserves in 2009). Because of lower natural gas prices and liquidity constraints, no investments or expenditures were made during 2009 to convert proved undeveloped reserves to proved developed reserves. Therefore, we concluded that no disclosure was required under Item 1203(c).

Item 1203(d)

Seven of 69 proved undeveloped locations (consisting of two of 26 proved undeveloped locations in the Pond Creek field and five of 43 proved undeveloped locations in the Gurnee field) included in our proved undeveloped reserves as of December 31, 2004 remain in our proved undeveloped reserves as of December 31, 2009. Those seven locations have proved reserves of 3.1 Bcf as of December 31, 2009, representing only 1.5% of our total proved reserves as of December 31, 2009, and we do not consider such amount of proved undeveloped reserves to be material. We will continue to monitor and disclose the information required by Item 1203(d) as it becomes material.

 

3. Further, please present disclosure regarding your present activities pursuant to Item 1206 of Regulation S-K.

Response

We note your comment and direct you to Items 1 and 2 of our Annual Report on Form 10-K for the year ended December 31, 2009. Under the caption “Areas of Operation” beginning on page 12 of such Annual Report, we disclose by field or project area our present activities and our plans for future development in fiscal year 2010. We identify the activities conducted at each of these fields or project areas as of December 31, 2009, including the number of wells being produced. Our capital expenditures during 2009 and budgeted capital expenditures for 2010 were reduced from prior years and, consequently, our present and anticipated future activities were significantly limited and, in our view, did not merit significant disclosure. The relevant disclosures under Items 1 and 2 of our Annual Report, which we believe are responsive to the disclosure requirements of Item 1206 in light of our limited activity levels in 2009, include the following:

Cahaba Basin

“At December 31, 2009, approximately 38% of our estimated proved reserves, or 79 Bcf, were located in the Gurnee field, of which approximately 85% were classified as proved developed. We are the operator and own a 100% working interest in the area. As of December 31, 2009, we had 245 productive wells in the Gurnee field. Net daily sales of gas averaged 5,804 Mcf for 2009.”

“We own and operate an approximate 38.5-mile pipeline from the Cahaba Basin to the Black Warrior River for the disposal of produced water under a permit issued by the Alabama Department of Environmental Management. This pipeline has a maximum design capacity of approximately 45,000 barrels of water per day, but would require

 

Mark Wojciechowski

U. S. Securities and Exchange Commission

October 22, 2010

Page 4

 

additional pump stations and looping a portion of the line in order to reach the maximum design capacity, if needed. We are currently transporting less than 10,000 barrels of produced water per day through this line and we believe we have adequate takeaway capacity to meet our future needs.”

Garden City

“At December 31, 2009, we have approximately 62,000 net acres of leasehold. As of December 31, 2009, we have no proved reserves booked for our Garden City Chattanooga Shale prospect. An economic solution to dispose of produced water will be necessary to develop this prospect and we intend to pursue various produced water disposal options in 2010.”

Pond Creek

“At December 31, 2009, approximately 61% of our estimated proved reserves, or 127 Bcf, were located within the Pond Creek field, of which approximately 68% were classified as proved developed. As of December 31, 2009, we are the operator and own an average 99% working interest in 245 gross productive wells in the Pond Creek field. Net daily sales of gas averaged 14,319 Mcf for 2009. In 2010, we intend to drill at least 8 wells and construct related infrastructure in the Pond Creek field.”

Lasher

“At December 31, 2009, approximately 1% of our estimated proved reserves, or 3 Bcf, were located within the Lasher field, of which 100% were classified as proved developed. As of December 31, 2009, we are the operator and own a 100% working interest in 18 productive wells. Our gas from the Lasher field is delivered into a Columbia Gas Transmission pipeline. We believe we have adequate takeaway capacity to meet our future needs.”

British Columbia

“As of December 31, 2009, we own a 50% working interest in eight gross productive wells and we are the operator. Our gas from Peace River is delivered on a Spectra Energy Corp pipeline. There are two primary delivery options, namely Westcoast Station 2 in British Columbia and Sumas, located near the U.S. and Canadian border. We believe we have adequate takeaway capacity to meet our future needs. We are planning to shut in the eight producing wells in our Peace River Project prior to May 1, 2010 as a result of decreased natural gas prices and longer than expected dewatering time.”

 

Mark Wojciechowski

U. S. Securities and Exchange Commission

October 22, 2010

Page 5

 

 

4. Please provide the disclosure required by Item 1207 of Regulation S-K, or tell us why such disclosure is not required.

Response

Our natural gas production is generally sold to end-users or their marketing affiliates under short-term contracts at market-based prices adjusted for location and quality. We are not a party to any contract or other agreement requiring us to deliver a fixed and determinable quantity of natural gas and therefore we believe that no disclosure is required under Item 1207 of Regulation S-K.

Estimated Proved Reserves, page 14

 

5. Disclosure under this section indicates that the role of the technical person primarily responsible for overseeing the preparation of your reserve estimates has been delegated to two independent directors. If this is not the case, revise the disclosure to clarify, and describe the qualifications the technical person primarily responsible for overseeing the preparation of your reserve estimates. However, if this is the case, expand your disclosure to describe, with reasonable specificity, the qualifications of these directors.

Response

We note your comment and direct you to the disclosures included in Items 1 and 2 under the captions “Qualifications of Third Party Engineer” and “Internal Controls” on page 11 of our Annual Report on Form 10-K for the year ended December 31, 2009, which describe the qualifications of our internal reserve engineer who is primarily responsible for overseeing the preparation of our reserve estimates by DeGolyer and MacNaughton as follows:

“Our internal reserve engineer accumulates and reviews the inputs and assumptions used by the third party engineer firm to estimate our year-end reserves and assesses them for reasonableness. Our internal reserve engineer has a Bachelor of Science degree in Mineral Engineering with an emphasis in Petroleum Engineering, is a Certified Professional Engineer in the state of Alabama and has 24 years of experience.”

We believe that these disclosures, when read in conjunction with the disclosure referenced by the Commission on page 14 of our Annual Report, clarify that our internal reserve engineer bears primary responsibility for oversight of the preparation of our proved reserves. We will consolidate these disclosures and clarify the respective roles of our internal reserve engineer and our Audit Committee in future annual reports on Form 10-K and anticipate that such disclosure will resemble the following:

“The technical person primarily responsible for preparation of our internal reserve estimates and overseeing the reserve estimates prepared by DeGolyer & MacNaughton (“D&M”), an independent petroleum engineering consulting firm, is John Hollingshead, GeoMet’s reservoir engineer. Mr. Hollingshead received a Bachelors of Mineral Engineering (Petroleum) degree in December 1983 from the University of Alabama and is a Certified Professional Engineer in the state of Alabama. He has worked as a petroleum engineer for approximately 24 years, including nine years with River Gas Corporation in Northport, Alabama from 1992 to 2001 and the previous eight years with

 

Mark Wojciechowski

U. S. Securities and Exchange Commission

October 22, 2010

Page 6

 

GeoMet in Hoover, Alabama. Mr. Hollingshead also worked briefly with Phillips Petroleum following its acquisition of River Gas Corporation. During the last 15 years, Mr. Hollingshead’s primary responsibility has been methane reservoir characterization and evaluation. As such, he has had the opportunity to participate in the development and evaluation of over 2,000 coalbed methane wells located in the Black Warrior basin, the Cahaba basin, the Central Appalachian basin in West Virginia and Virginia, and the Uintah basin in Utah. Mr. Hollingshead accumulates and reviews the inputs and assumptions used by D&M to estimate our year-end reserves and assesses them for reasonableness.

Estimates of our proved reserves at December 31, 2009, 2008, and 2007 were prepared by D&M. The technical persons at D&M responsible for preparing the reserve estimates are independent petroleum engineers and geoscientists that 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. The Audit Committee of our Board of Directors has delegated the responsibility of reviewing the reserve reporting process to two independent directors, both of whom have experience in reserve evaluations. Additionally, both the Company’s Chief Executive Officer and Chief Financial Officer are charged with the responsibility of reviewing and approving the natural gas reserve estimates prepared by D&M.”

 

6. Based on disclosure in various parts of your filing, we understand that you will require significant additional capital to fund the development of your proved undeveloped reserves. We also understand that there is significant uncertainty as to whether you will be able to obtain the required additional capital. In view of these factors, explain your basis for concluding that your proved undeveloped reserves meet the reasonable certainty standard as of December 31, 2009. See Rule 4-10(a)(22) of Regulation S-X.

Response

As of March 31, 2010, the filing date of our Annual Report on Form 10-K for the year ended December 31, 2009, GeoMet had entered into commitment letters with NGP Capital Resources Company (“NGPC”) and North Shore Energy LLC (“North Shore”), evidencing their commitment to provide up to $40 million in financing to the Company as disclosed on page 57 of our Form 10-K. NGPC is an affiliate of Natural Gas Partners and is a recognized and reputable investor in smaller oil and gas companies. North Shore is an affiliate of Yorktown Energy Partners, an affiliate of our largest shareholder. Although we were confident in the ability of NGPC and North Shore to provide additional capital to the Company and in our ability to raise capital from alternative sources in the event they failed to do so, we had not yet entered into final definitive agreements with those parties. Consequently, we deemed it prudent to include cautionary statements in our public disclosures regarding the certainty of the closing of this financing transaction. However, we have a successful track record of raising capital and were reasonably certain that financing would be available to us, although the timing and terms of such alternative financing were not certain.

 

Mark Wojciechowski

U. S. Securities and Exchange Commission

October 22, 2010

Page 7

 

 

As we have disclosed in previous filings with the Commission, in June 2010 we entered into a definitive agreement with Sherwood Energy, LLC that we believed offered financing on more favorable terms than the original commitments from NGPC and North Shore, and we completed the $40 million rights offering and backstop transaction on September 14, 2010. We believe the rights offering, backstop commitment, the new credit facility we entered into in connection therewith, and internally generated cash flow provide us with the financial flexibility to support our anticipated capital requirements.

 

7. Disclosure in your 10-Q for the period ended June 30, 2010 indicates that you do not plan to drill any wells on your Gurnee property during 2010. With respect to this property, provide us the following supplemental information:

 

  •  

Explain to us why you do not plan to drill this property in 2010;

 

  •  

Tell us when, and under what conditions, you expect to drill this property;

 

  •  

Tell us whether the decision to not drill the property during 2010 had been made at the time your reserve estimates as of December 31, 2009 had been made; and,

 

  •  

Given the lack of drilling, explain your basis for concluding that your proved undeveloped reserves meet the reasonable certainty standard as of December 31, 2009. See Rule 4-10(a)(22) of Regulation S-X.

Response

We did not plan to drill proved undeveloped locations in the Gurnee field in 2010 for several reasons including issues related to capital allocation and lower natural gas prices. At the time the reserves were determined, we were in the process of negotiating with standby financing parties and due to the uncertainty around the timing and final terms of the proposed financing, we elected to allocate our available capital to meet our drilling obligations in the Pond Creek field. We were also cognizant of the short-term outlook for natural gas prices and wanted to conduct further testing of a new hydraulic fracturing technique in the Gurnee field, which we had reason to believe would yield better economic results, before drilling additional wells in the Gurnee field.

The decision not to drill proved undeveloped locations in the Gurnee field in 2010, although subject to change, had been made at the time our reserve estimates were completed. Accordingly, our reserve estimates assumed that we would not drill any proved undeveloped locations in the Gurnee field for the year 2010. However, following the closing of our financing transaction and successful testing of a new hydraulic fracturing technique, we have drilled one new well in the Gurnee field and will complete this well

 

Mark Wojciechowski

U. S. Securities and Exchange Commission

October 22, 2010

Page 8

 

using this new fracturing technique. We currently plan capital spending of approximately $2.5 million in the Gurnee field in 2011 and $5 million in 2012. The number of proved undeveloped locations scheduled in the reserve report for the Gurnee field for years beyond 2010 is consistent with our current expenditure plans for the field.

We believe that we met the reasonable certainty standard in the reserve report for proved undeveloped reserves in the Gurnee field because we excluded from the report proved undeveloped locations for the Gurnee field in the year 2010 that we did not intend to drill. We did, however, include proved undeveloped locations for years beyond 2010 which we believed to be economically producible under current economic conditions and for which the Company had a reasonable expectation to drill. In connection with this expectation, we were reasonably certain we could raise additional capital and we expected to generate sufficient internal operating cash flows to enable us to drill these undeveloped locations. Note, as indicated in response to comment number 6, that the Company was successful in raising additional capital subsequent to December 31, 2009 and the Company continues to believe that internally generated cash flows will be sufficient to provide capital to drill these undeveloped locations.

 

8. We note you provide a price sensitivity analysis on page 15 of your estimated proved reserves using a price other than the price used to determine your reserves as of December 31, 2009. Please tell us how your disclosure complies with the requirement of Item 1202(b)(3) of Regulation S-K to disclose the cost schedules and assumptions on which the disclosed values are based.

Response

We note your comment regarding our presentation of a price sensitivity analysis on page 15 of our Annual Report on Form 10-K for the year ended December 31, 2009. In that disclosure, we note that the information presented is based on a natural gas price of $6.00 per thousand cubic feet. In that presentation, we used the same cost estimates and assumptions that were used in calculating our proved reserves as of December 31, 2009, in accordance with Commission guidelines; therefore, we did not note any different cost estimates or assumption when presenting the price sensitivity analysis.

We will revise any subsequent presentations of price sensitivity analyses in future Annual Reports on Form 10-K to include the cost schedules and assumptions upon which the analyses are based.

 

Mark Wojciechowski

U. S. Securities and Exchange Commission

October 22, 2010

Page 9

 

 

9. In addition, please move your price sensitivity analysis under its own separate heading and remove any table headings that would suggest to investors that the analysis represents your proved reserves. For example, remove the heading “Estimated Proved Reserves.”

Response

We note your comment regarding placement of the price sensitivity analysis disclosure. In the event that we include such disclosure in future annual reports on Form 10-K, we will include such disclosure under a separate heading and remove the table heading “Estimated Proved Reserves.”

 

10. Disclosure in the notes to your financial statements indicates that virtually all of your production for each of the last three years has been sold to a single customer. Explain to us how you have considered the disclosure requirements of Item 101(c)(1)(vii) of Regulation S-K.

Response

Although most of our natural gas production for each of the last three years has been sold to a single marketing affiliate of a large end-user customer, there are other customers to whom we can market and sell our natural gas production at substantially similar prices and on similar terms. It has been our preference to market and sell significantly all of our natural gas production to Sequent Energy Management, LP (“Sequent”), a wholly owned subsidiary of AGL Resources Company, with whom we have a long-standing relationship. Sequent is a customer of high credit quality and provides us certain other benefits related to operational flexibility and reliability of service. In the event that Sequent chooses not to purchase our production, we believe that we have a number of alternative purchasers available to us and that such alternate arrangements would not have a material impact on our sales volumes, revenues and related metrics.

Risk Factors, page 26

Obtaining production from our additional drilling locations could take five years or Longer, page 33

 

11. Please tell us if you have recorded proved reserves related to these drilling locations. Please also tell us if you have recorded proved reserves that will remain in the undeveloped category for periods extending beyond five years. If so, please tell us why you believe it is appropriate to classify these as proved reserves by describing to us in more detail the “specific circumstances” that apply to these projects under Rule 4-10(31)(ii) of Regulation S-X. Refer to questions 108.01 and 131.03 through 131.06 of our Compliance and Disclosure Interpretations. You can find these interpretations at: http://www.sec.gov/divisions/corpfin/guidance/oilandgas-interp.htm.

Response

We refer you to page 5 of our Annual Report on Form 10-K for the year ended December 31, 2009, wherein we define “additional drilling locations” as follows:

“Additional drilling locations. Identified potential drilling locations on our existing acreage that are not included in our proved undeveloped reserves.”

 

Mark Wojciechowski

U. S. Securities and Exchange Commission

October 22, 2010

Page 10

 

 

The “additional drilling locations” discussed in the above-referenced risk factor are not, by definition, included in our proved reserves as of December 31, 2009, and we have not recorded proved reserves related to those additional drilling locations.

The company intends to drill all proved undeveloped locations included in the proved reserves within five years; therefore, we do not anticipate any of such wells will remain in the undeveloped category for periods extending beyond five years.

Selected Financial Data, page 42

Reconciliation of non-GAAP Financial Measures, page 43

 

12. Certain amounts presented in this table do not appear to be consistent with corresponding amounts appealing in the standardized measure included in the notes to your financial statements. In this regard, we note that the line item Undiscounted Taxes, as presented on page 43, appears to agree with the line item 10% Annual Discount to Reflect the Timing of Cash Flows in your standardized measure. Similarly, the net discount reflected on page 43 appears to agree to future income taxes in your standardized measure. Please review your presentations and revise as necessary to resolve these apparent inconsistencies.

Response

We note your comment that there is an inconsistency with the line items future income taxes and 10% annual discount to reflect timing of cash flows in our Standard Measure-U.S. on page 100 with the Reconciliation of Non-GAAP Financial Measures line items Less: Undiscounted income taxes on page 43 of our Annual Report on Form 10-K for the year ended December 31, 2009. However, the net effect on line item Discounted income taxes on the Reconciliation of Non-GAAP Financial Measures remains correct. Please note that a change in the line item Less: Undiscounted income taxes will have a corresponding change to the line item Plus: 10% discount factor. As a result, the aforementioned line items (in bold type below) in the two tables referenced above will be agreed in future filings as follows:

 

Future cash inflows

    $ 849,379   

Less: Future production costs

      426,105   

Less: Future development costs

      68,321   
        

Future net cash flows

      354,953   

Less: 10% discount factor

      257,287   
        

PV-10

      97,666   
        

Less: Undiscounted income taxes

      (47,935 )

Plus: 10% discount factor

      99,467   
        

Discounted income taxes

      51,532   
        

Standardized measure of discounted future net cash flows

    $ 149,198   
        

 

Mark Wojciechowski

U. S. Securities and Exchange Commission

October 22, 2010

Page 11

 

 

13. The presentation of your standardized measure as of December 31, 2009 appearing in the notes to your financial statements reflects a deduction for income taxes. However, the reconciliation appearing on page 43 indicates that PV-10 as of December 31, 2009 is less than the standardized measure, which suggests that the impact of income taxes increased, rather than decreased, your standardized measure. Provide us with an additional reconciliation or other analysis that resolves this apparent inconsistency and clarifies the impact that income taxes had on your standardized measure as of December 31, 2009. Please note that we would not ordinarily expect the impact of taxes to increase the standardized measure over the amount that would otherwise be reported.

Response

We also would not ordinarily expect to see the impact of taxes increasing the standard measure over the PV-10 with the exception of being in a year that included significant increases in deferred tax assets resulting from pervasive ceiling impairments. As a result, we have included in our calculation of our standardized measure the impact of the future recognition of our deferred tax assets. Our calculation assumed (1) existing tax basis in evaluated properties is deductible at year end, (2) future development costs are deductible in the year incurred and (3) deferred tax assets are recognized. In applying this approach consistently, we calculate income taxes on an undiscounted basis after recovering our tax basis in gas properties and NOL carryover at the end of year estimated effective tax rate. However, on a discounted basis or on a PV-10 basis, we calculate a benefit instead of a liability because of the excess of tax assets over the PV-10. This benefit is consistent with the Deferred Tax Asset recognized on the financial statements in conjunction with the impairment of our gas properties. In addition, we believe the impact of taxes impact the standard measure both negatively and positively depending on whether we are in a tax liability position or in a tax asset position.

Notes to Consolidated Financial Statements, page 72

Note 11 — Income Taxes, page 88

 

14. We note that you report cumulative losses for the three and five year periods ended December 31, 2009. In view of this, explain to us your basis for concluding that it is more likely than not that your deferred tax assets will be realized and that a valuation allowance is not required. As part of your response, describe the positive and negative evidence you considered in evaluating the need for a valuation allowance and explain the relative weight given to this evidence. In this regard, please note that a cumulative loss in recent years is a significant piece of negative evidence that is difficult to overcome. See ASC paragraphs 740-10-30-16 through 740-10-30-23.

 

Mark Wojciechowski

U. S. Securities and Exchange Commission

October 22, 2010

Page 12

 

 

Response

We have recorded a valuation allowance relating to deferred tax assets for certain state and international tax loss carry-forwards.

At December 31, 2009, we had a three-year cumulative pre-tax loss of $280.5 million from continuing operations. This amount includes $308 million in charges relating to the impairment of our gas properties as calculated in accordance with SEC Regulation S-X Rule 4-10. Net of these impairment charges, we had three-year cumulative pre-tax income of $27.5 million from continuing operations.

In performing our analysis to determine the recoverability of our deferred tax asset we followed the relevant guidance below from Accounting Standards Codification 740, Income Taxes (ASC 740), which states, in part:

ASC 740-10-30-5 states that a company should,

Reduce deferred tax assets by a valuation allowance if, based on the weight of available evidence, it is more likely than not (a likelihood of more than 50 percent) that some portion or all of the deferred tax assets will not be realized. The valuation allowance should be sufficient to reduce the deferred tax asset to the amount that is more likely than not to be realized.

ASC 740-10-30-17 goes on to say that,

All available evidence, both positive and negative, should be considered to determine whether, based on the weight of that evidence, a valuation allowance is needed. Information about an enterprise’s current financial position and its results of operations for the current and preceding years ordinarily is readily available. That historical information is supplemented by all currently available information about future years.

ASC 740-10-30-21 states however that,

Forming a conclusion that a valuation allowance is not needed is difficult when there is negative evidence such as cumulative losses in recent years. Other examples of negative evidence include (but are not limited to) the following:

 

  a. A history of operating loss or tax credit carry forwards expiring unused.

 

  b. Losses expected in early future years (by a presently profitable entity).

 

  c. Unsettled circumstances that, if unfavorably resolved, would adversely affect future operations and profit levels on a continuing basis in future years.

 

  d. A carry-back, carry-forward period that is so brief that it would limit realization of tax benefits if (1) a significant deductible temporary difference is expected to reverse in a single year or (2) the enterprise operates in a traditionally cyclical business.

Additionally ASC 740-10-30-22 provides,

Examples (not prerequisites) of positive evidence that might support a conclusion that a valuation allowance is not needed when there is negative evidence include (but are not limited to) the following:

 

  a. Existing contracts or firm sales backlog that will produce more than enough taxable income to realize the deferred tax asset based on existing sales prices and cost structures.

 

Mark Wojciechowski

U. S. Securities and Exchange Commission

October 22, 2010

Page 13

 

 

  b. An excess of appreciated asset value over the tax basis of the entity’s net assets in an amount sufficient to realize the deferred tax assets.

 

  c. A strong earnings history exclusive of the loss that created the future deductible amount (tax loss carryforward or deductible temporary difference) coupled with evidence indicating that the loss (for example, an unusual, infrequent, or extraordinary item) is an aberration rather than a continuing condition.

ASC 740-10-30-23 concludes,

An enterprise must use judgment in considering the relative impact of negative and positive evidence. The weight given to the potential effect of negative and positive evidence should be commensurate with the extent to which it can be objectively verified. The more negative evidence that exists (a) the more positive evidence is necessary and (b) the more difficult it is to support a conclusion that a valuation allowance is not needed for some portion or the entire deferred tax asset.

We considered the following negative evidence when determining whether a valuation allowance was necessary in relation to its net deferred tax asset:

 

  •  

ASC 740-10-30-21: Absent the consideration of the ceiling test impairment charges, we have a three-year cumulative pre-tax loss of $280.5 million from continuing operations.

 

  •  

ASC 740-10-30-21(c): At the time of filing our 10-K for the year ended December 31, 2009, there was some uncertainty regarding our liquidity position as it related to our expiring credit facility in 2011. While we had commitments from investors to invest money in the Company related to a planned rights offering, the transaction had not closed by December 31, 2009, and as a result there was a level of uncertainty. The transaction was subsequently consummated in September 2010 which has abated any liquidity concerns.

Positive Evidence:

 

  •  

ASC 740-10-30-22(a): We currently sell the majority of our output to a single customer and although there is no fixed contract, our product is a commodity which we believe could be readily sold to another customer if needed.

 

  •  

ASC 740-10-30-22(c): As noted above, excluding the non-cash impairment charges we have three-year cumulative pre-tax income of $27.5 million from continuing operations. The situation that caused the impairments was the unprecedented economic downtown which began in the fourth quarter of 2008 and resulted in the price of natural gas falling from a high of $13.11 in the second quarter of 2008 to a low of $5.38 in the fourth quarter of 2008 and prices dropped to a low of $3.63 in the first quarter of 2009. Since then prices, although remaining low compared to the highs seen in 2008, have remained relatively stable and well above the minimum prices needed for us to maintain a profit. Furthermore, note that the price of natural gas used in the impairment test at 2009 was a 12 month historical average price, which is not comparable to the third party forward strip pricing used as the basis for assessing future taxable profitability.

 

Mark Wojciechowski

U. S. Securities and Exchange Commission

October 22, 2010

Page 14

 

 

  •  

Other: In order to estimate if we would be able to realize the deferred tax asset in full prior to expiration we prepared a forecast of future profitability. This forecast substantially relied on market inputs as it related to pricing and future estimates of our reserves that were certified by a third party engineer. Specifically, the primary inputs were as follows:

 

  •  

Price: We used market strip pricing as published by a third party source. To be conservative, we held prices constant in the latter years.

 

  •  

Production: We used the production as estimated by our third party reserve engineers in the year-end reserve report. We noted that the estimates are conservative because the pricing included in the reserve report is held constant at $4.06 and as such does not include reserves that would become economically viable as prices rise as projected by the third party pricing source.

 

  •  

Margins: To further add an element of objectivity and conservatism, rather than use the higher margins embedded in the reserve report results, we used a three-year average historical margin. In addition, we factored in the reduction in income due to the future intangible drilling costs deductions that are projected to be utilized by us in the future.

 

  •  

Cost Reductions: In April 2009, we implemented a company-wide cost reduction program and have been able to reduce costs significantly. However, to be conservative, we have not factored in the anticipated cost reductions in our future estimates of profitability.

  •  

Sensitivity Testing: To further subject our analysis to testing we noted that the pricing used in our analysis could decrease by approximately 15% before it would results in any portion of our net operating loss expiring unused. If we used future projected margins rather than historical, the price could drop 34% before any portion of our net operating loss expiring unused.

 

  •  

Liquidity: At the time of filing we had signed financial commitments from investors to provide up to $40 million in standby financing in conjunction with a shareholder rights offering, which upon consummation would alleviate the liquidity concerns in conjunction with extending our revolving credit facility through three years from the date of the completion of the rights offering. Such transaction was consummated in September 2010.

The result of our internal analysis performed as described above identified that the net operating loss would be fully utilized in five (using future margins) or 11 years (using historical margins) well before any material portion of our net operating loss carry-forward expires.

 

Mark Wojciechowski

U. S. Securities and Exchange Commission

October 22, 2010

Page 15

 

 

In accordance with ASC 740-10-30-23 above, we used our best judgment in considering the relative impact of negative and positive evidence described above. In considering the weight given to the potential effect of objectively verifiable negative evidence we took into consideration the fact that the impairment charges and cumulative losses are primarily caused by factors that are not necessarily indicative of future taxable profitability. That is due to the fact that the impairment test is required to be performed using an average historical price without escalation or any consideration of future market strip pricing. In considering the weight given to the positive evidence we note that our future forecast of profitability was conservative and based on information either from historical results or third parties, which is objectively verifiable and results in the deferred tax asset associated with our net operating loss carryforward being realized well before expiration. As the evidence related to this analysis is consistent with our reserve report provided by an independent petroleum engineer and analyzed by our internal engineer as well as the future strip pricing available on a third party exchange, the information appears reliable for the purposes of this analysis.

In conclusion, we concluded that based on the weight of the evidence above, that it was more likely than not that our net deferred tax asset would be realized in full prior to expiration and as such, have not recorded a valuation allowance.

Supplementary Financial and Operating Information on Gas Exploration, Development and Producing Activities (Unaudited), page 97

Changes in Standardized Measure, page 101

 

15. In the paragraph below the table presenting the changes in the standardized measure, you explain that the tables were calculated using natural gas prices in effect at the balance sheet date. However, it appears that amounts as of December 31, 2009 were based on the average prices on the first day of each month for the 12-month period ended December 31, 2009. Review your disclosure and revise as necessary.

We have reviewed our disclosure on page 101 and note that on the Columns for 2008 and 2007 should indicate the use of natural gas prices in effect at the balance sheet date and that the 2009 data should indicate the amounts were based on the average prices on the first day of each month for the 12-month period ended December 31, 2009. However, it should be noted that the description of the price used in the valuation of our proved reserves throughout our Annual Report on Form 10-K for the year ended December 31, 2009 was as follows, “Proved reserve estimates are based on the unweighted arithmetic average prices on the first day of each month, adjusted for regional price differentials, for the 12-month period ended December 31, 2009.” This description may be found on pages 9, 11, 15, 46, 64, 77, 80, 99 and 100.

Additionally it can be found in DeGolyer & MacNaughton’s Report (Exhibit 99.1) on pages 3, 4 and 9. The incorrect description on page 101 related to December 31, 2009 is the only instance in the document where the guidance was not updated and we will update future disclosure accordingly.

 

Mark Wojciechowski

U. S. Securities and Exchange Commission

October 22, 2010

Page 16

 

 

Exhibit 99.1

 

16. The closing paragraph states that “[t]his letter report has been prepared at the request of GeoMet and should not be used for purposes other than those for which it is intended.” As Item 1202(a)(8) of Regulation S-K requires, please revise the third party report so it retains no language that could suggest either a limited audience or a limit on potential investor reliance.

Response

We note your comment and will ensure that subsequent reports of our third party engineer filed with the Commission do not retain language suggesting either a limited audience or a limit on potential investor reliance. DeGolyer and McNaughton has provided us with a revised letter, in compliance with Item 1202(a)(8) of Regulation S-K, in which the closing paragraph has been revised as follows:

“DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 70 years. 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 and should not be used for purposes other than those for which it is intended. DeGolyer and MacNaughton has used all procedures and methods that it considers necessary to prepare this report.”

 

17. Please revise your third party report to include a statement that the assumptions, data, methods, and procedures used in connection with the preparation of the report are appropriate for the purpose served by the report. See Item 1202(a)(8)(iv) of Regulation S-K.

Response

We note your comment and will ensure that subsequent reports of our third party engineer filed with the Commission include a statement that the assumptions, data, methods, and procedures used in connection with the preparation of the report are appropriate for the purpose served by the report. We have advised DeGolyer and McNaughton, our current third party engineer, and they have agreed to provide a letter report in compliance with Item 1202(a)(8)(iv) of Regulation S-K.

 

Mark Wojciechowski

U. S. Securities and Exchange Commission

October 22, 2010

Page 17

 

 

Amendment No. 1 to Form 10-K for the Fiscal Year Ended December 31, 2009

Compensation Committee, page 9

 

18. We note your statement that “[t]he Compensation Committee on occasion meets with our Chief Executive Officer and other executives to obtain recommendations with respect to our compensation programs, practices and packages for executives, other employees and directors.” Please revise to disclose whether any of your named executive officers make recommendations to your Compensation Committee regarding their own compensation.

Response

We note your comment and will revise the disclosure as follows:

“The Compensation Committee on occasion meets with our Chief Executive Officer and other executives to obtain recommendations with respect to our compensation programs, practices and packages for executives, other employees and directors. No executive officer makes recommendations regarding their own compensation other than the Chief Executive Officer. Although management makes recommendations to the Compensation Committee on executive compensation, the Compensation Committee is not bound by and does not always accept management’s recommendations. The Compensation Committee also seeks input from an independent compensation consultant prior to making any final determinations. Our Chief Executive Officer attends some of the Compensation Committee meetings, but the Compensation Committee also regularly holds executive sessions not attended by members of management or non-independent directors.”

We have included the foregoing disclosure in our definitive proxy statement, filed with the Commission and will include in future filings with the Commission.

Certain Relationships and Related Transactions, and Director Independence, page 28

 

19. Please disclose the standards to be applied pursuant to your policies and procedures for the review, approval or ratification of transactions with related persons. See Item 404(b) of Regulation S-K.

Response

We note your comment and will include the following disclosure where required in future filings with the Commission:

“Review and Approval of Transactions with Related Persons”

 

Mark Wojciechowski

U. S. Securities and Exchange Commission

October 22, 2010

Page 18

 

 

As set forth in our Audit Committee Charter, a current copy of which is available on our website at http://www.geometinc.com, any related party transaction that is required to be disclosed pursuant to SEC regulations must be reviewed and approved by our Audit Committee. Our Audit Committee has adopted a written checklist that governs its review of related party transactions. Our Audit Committee reviews information from our directors, executive officers and other related persons with respect to related person transactions and then determines, based on the facts and circumstances, whether the Company or a related person has a direct or indirect material interest in the transaction. In the course of its review and approval or ratification of a disclosable related person transaction, consideration is given to:

 

  •  

the nature of the related person’s interest in the transaction;

 

  •  

the material terms of the transaction, including, without limitation, the amount and type of transaction;

 

  •  

the importance of the transaction to the related person;

 

  •  

the importance of the transaction to the Company;

 

  •  

whether the transaction would impair the judgment of a director or executive officer to act in the best interest of the Company; and

 

  •  

any other matters deemed appropriate.

Any director who is a related person with respect to a transaction under review may not participate in the deliberations or vote respecting approval or ratification of the transaction; provided, however, that such director may be counted in determining the presence of a quorum at the meeting where the transaction is considered.

All of our employees, including our executive officers and directors, are subject to our Code of Business Conduct and Ethics, which is also available on our website. Our Code of Business Conduct and Ethics sets forth policy guidelines aimed at preventing any conflicts of interest with our company. Our Code of Business Conduct and Ethics further imposes prohibitions and duties designed to prevent employees, officers and directors from taking personal advantage of corporate opportunities. Any exceptions to these policies require management and the Board of Directors to be fully informed and to determine that any undertaking is consistent with the Company’s business objectives.”

We have included the foregoing disclosure in our definitive proxy statement, filed with the Commission on October 4, 2010, and will include in future filings with the Commission.

Should any member of the Staff have a question regarding our responses to the comments set forth above, or need additional information, please do not hesitate to call J. Darby Seré at (713) 287-2253 or me at (713) 287-2257, or you may contact our outside counsel Harry R. Beaudry at (713) 653-8826 at Thompson & Knight LLP.

 

Mark Wojciechowski

U. S. Securities and Exchange Commission

October 22, 2010

Page 19

 

 

As you requested in the comment letter, we acknowledge that:

 

  •  

the Company is responsible for the adequacy and accuracy of the disclosure in the filing;

 

  •  

Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and

 

  •  

the Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

 

Very truly yours,
By:   /s/ William C. Rankin
  William C. Rankin
  Executive Vice President and
      Chief Financial Officer