November 14, 2011
Via EDGAR and Federal Express
Mr. H. Roger Schwall
Assistant Director, Natural Resources
United States Securities and Exchange Commission
100 F Street, NE
Washington DC 20549
| Re: | Matador Resources Company |
| Registration Statement on Form S-1 |
| Filed August 12, 2011 |
| File No. 333-176263 |
Dear Mr. Schwall:
On behalf of Matador Resources Company (the “Company”), we are submitting the Company’s responses to comments received from the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “SEC”) by letter dated September 29, 2011, with respect to the Company’s Registration Statement on Form S-1, File No. 333-176263, initially filed with the SEC on August 12, 2011 (the “Registration Statement”).
Concurrently with the submission of this letter, we are filing through EDGAR Amendment No. 1 to the Registration Statement (“Amendment No. 1”). For your convenience, we will hand deliver three full copies of Amendment No. 1, as well as three copies of Amendment No. 1 that are marked to show all changes made since the initial filing of the Registration Statement.
As you will note in connection with your review, prior to commencing the offering, the Company will file additional amendments to the Registration Statement to, among things, update the financial information and complete the information relating to the selling shareholders. Also, the Company’s use of the proceeds from the offering is dependent on (i) the Company’s financial needs at the time of the offering, (ii) the outstanding balances under its revolving credit agreement at the time of the offering and (iii) the specific capital expenditure requirements at the time of the offering. As a result, the Company will provide additional particulars regarding its use of the offering proceeds at a time closer to the potential offering.
For your convenience, each response is prefaced by the exact text of the Staff’s corresponding comment in bold text. All references to page numbers and captions correspond to the marked version of Amendment No. 1 unless otherwise specified.
Mr. H. Roger Schwall
November 14, 2011
Page 2
| 1. | Where comments on a section also relate to disclosure in another section, please make parallel changes to all affected disclosure. This will eliminate the need for us to repeat similar comments. |
Response: The Company acknowledges the Staff’s comment and has made parallel changes in Amendment No. 1 where appropriate.
| 2. | If a numbered comment in this letter raises more than one question or lists various items in bullet points, ensure that you fully respond to each question and bullet point. Make sure that your letter of response indicates precisely where responsive disclosure to each numbered comment and each point may be found in the marked version of the amendment. |
Response: The Company acknowledges the Staff’s comment and has responded to each question and bullet accordingly.
| 3. | In the amended registration statement, please fill in all blanks other than the information that Rule 430A permits you to omit. |
Response: The Company acknowledges the Staff’s comment and has provided in Amendment No. 1 certain information that it is not entitled to omit pursuant to Rule 430A, and the Company undertakes to provide in future amendments to the Registration Statement all remaining information that it is not entitled to omit pursuant to Rule 430A.
| 4. | Prior to submitting a request for accelerated effectiveness of the registration statement, ensure that we have received a letter or call from the Financial Industry Regulatory Authority (FINRA) which confirms that it (a) has finished its review and (b) has no additional concerns with respect to the underwriting arrangements. Please provide us with a copy of that letter, or ensure that FINRA calls us for that purpose. |
Response: Prior to submitting a request for accelerated effectiveness, the Company will provide the Staff with the letter from the Financial Industry Regulatory Authority (“FINRA”) or arrange for a representative of FINRA to call a representative of the Staff to confirm that FINRA has finished its review and has no additional concerns with respect to the underwriting arrangements.
| 5. | We note that you have not provided most of your exhibits. Please submit all material exhibits, including, without limitation, the legality opinion and lock-up |
Mr. H. Roger Schwall
November 14, 2011
Page 3
| agreements, in order to facilitate our review of your filing. We may have further comment upon our review. |
Response: The Company acknowledges the Staff’s comment and has filed with Amendment No. 1 the exhibits that are currently available. The Company undertakes to file with future amendments to the Registration Statement all other omitted exhibits. Further, the Company will allow sufficient time for the Staff to review all newly filed exhibits and for the Company to respond to any comments that may result from the Staff’s review.
| 6. | You do not yet provide a range for the potential offering price per share. Because other, related disclosure likely will be derived from the midpoint of the range, we remind you to provide the range once it becomes available so that you will have time to respond to any resulting staff comments. |
Response: The Company acknowledges the Staff’s comment and will include an estimated price range in a future amendment to the Registration Statement. The Company will allow sufficient time for the Staff to review its complete disclosure and for the Company to respond to any comments that may result from the Staff’s review.
| 7. | We note your disclosure at page 3 that you are active both as an operator and as a co-working interest owner and that a portion of your acreage is operated by other companies. Please provide the basis for not filing any related agreement. |
Response: As disclosed on pages 4 and 87 of Amendment No. 1, as of September 30, 2011, the Company was the operator for approximately 82% of its Eagle Ford and 71% of its Haynesville acreage, which plays represented the Company’s primary operations. With respect to the acreage in which the Company is a co-working interest owner, the Company does not always enter into formal operating agreements with the operator. In such cases, the Company relies on applicable legal and statutory authority to govern its relationship with the operator who manages the acreage in accordance with industry standard practices. This is particularly true where the Company’s working interest in the acreage is small. While the Company has entered into operating agreements with certain operators, including EOG Resources, Inc. and subsidiaries of Chesapeake Energy Corporation, such agreements are not required to be filed under Item 601(b)(10) of Regulation S-K for the following reasons. First, the Company’s business is not substantially dependent (as contemplated by Item 601(b)(10)(ii)(B) of Regulation S-K) upon any of these agreements. Furthermore, these agreements are entered into in the ordinary course of business and are generally based on an AAPL Model Form Operating
Mr. H. Roger Schwall
November 14, 2011
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Agreement. Because this standard form agreement is typical of the types of operating agreements entered into by similarly situated domestic onshore oil and gas companies in the ordinary course of business, filing of the Company’s contracts with these operators would provide no material additional information to investors.
Prospectus Summary, page 1
| 8. | We note your disclosure at page 1 that unless the context otherwise requires, the terms “we,” “our,” and “the company” refer to Matador Resources Company and its subsidiaries before the completion of your corporate reorganization and Matador Holdco, Inc. and its subsidiaries after the completion of your corporate reorganization. However, this does not appear to be consistent with the disclosure provided elsewhere in your filing, including the organizational chart at page 11. |
Response: As discussed on the call between the SEC and Mr. W. Bruce Newsome of Haynes and Boone, LLP on September 22, 2011, the Company understands that the Staff has withdrawn this comment.
| 9. | Please explain and support your reference at page 7 to your “low cost structure.” |
Response: The Company has revised the referenced disclosure on pages 8 and 90 as follows:
Maintain Our Low Cost Structure and Financial Discipline.
As an operator, we seek to manage aggressively our costs by
leveragingleverage advanced technologies and integratingintegrate the knowledge,
judgment and experience of our management and technical teams. We believe our team demonstrates financial discipline that is reflected in the improvements it has achieved on reducing unit costs and is achieved by
our approach to evaluating and analyzing prospects and prior drilling and completion results before allocating capital and is reflected in the improvements our team has
attained on reducing unit costs. When we are not the operator, we proactively engage with the operators in an effort to ensure similar financial discipline and cost-focused operations and results. Additionally, we conduct
our own internal geological and engineering studies on these prospects and provide input on the drilling, completion and operation of many of these non-operated wells pursuant to our agreements and relationships with the operators. Through these
methods and
Mr. H. Roger Schwall
November 14, 2011
Page 5
practices, we believe we are well-positioned to control the expenses and timing of development and exploitation of our properties.
| 10. | We note the disclosure on page three, and elsewhere in your filing, indicating that almost 5,500 net acres of your Haynesville shale properties are in what you believe to be the “core” area of the play. Expand this disclosure to explain the basis for, and significance of, this belief. |
Response: The Company has added the following disclosure to pages 3 and 87:
In addition, at June 30, 2011, we had approximately 23,000 gross acres and 15,000 net acres in the Haynesville shale play in
northwest Louisiana and east Texas, including almost 5,500. Based on our analysis of geologic and petrophysical information (including total organic carbon content and
maturity, resistivity, porosity and permeability, among other information), well performance data and information available to us related to drilling activity and results from wells drilled across the Haynesville shale play, almost 5,500 of
our net acres are located in what we believe is the core area of the play. We believe the core area
of the play includes that area in which the most Haynesville wells have been drilled by operators and from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well.
In addition, the Company is providing separately to the Staff a map sourced from the U.S. Department of Energy/Energy Information Administration (the “EIA”) and various operators and other information (showing outlines of the Haynesville shale play and dots for wells drilled) that has been modified to include an overlay showing the approximate location of the Company’s acreage. Based on this map, the Company notes the density of wells drilled and the outline of the prospective area of the play which the EIA has sourced from several different operators. The Company has also overlaid the area that it defines as the core area of the play, which also corresponds to that area of the play in which the most Haynesville wells have been drilled by operators and from which the Company anticipates natural gas recoveries would likely exceed 6 Bcf per well. Approximately 5,500 net acres of the Company’s Haynesville acreage fall within the area that it has defined as the core area of the play. The map is being provided to the Staff pursuant to Rule 418 under the Securities Act of 1933, as amended. In accordance with Rule 418, the Company is requesting that the annexed map be returned promptly following completion of the Staff’s review thereof. The Company is providing a pre-paid self-addressed Federal Express envelope for the return of the map.
Mr. H. Roger Schwall
November 14, 2011
Page 6
| 11. | We note your disclosure regarding drilling locations identified in your Eagle Ford and Haynesville acreages. Expand this disclosure to explain, in reasonable detail, the processes and criteria through which these locations were identified. |
Response: The Company has expanded its disclosure on pages 3-4 and 86-87 with respect to its identified drilling locations as follows.
We have
identified 192 gross locations for potential future drilling in our Eagle Ford acreage.We have identified 192 gross locations and 157 net locations for potential future drilling
on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated recoveries from nearby wells based on
available public data, drilling densities observed from other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among others. At June 30, 2011, we have
identified potential drilling locations on approximately 75% of our net Eagle Ford acreage. As we explore and develop our Eagle Ford acreage further, we believe it is possible that we may identify additional locations for drilling. At June 30,
2011, these identified potential future drilling locations in the Eagle Ford shale play included 2 gross and 2 net locations to which we have assigned proved undeveloped reserves.
Our Haynesville acreage is approximately 10% developed and we have identified 557 gross locations for potential future drilling in
our Haynesville acreage. At June 30, 2011, our Haynesville acreage was approximately 10% developed, and we have identified 557 gross locations and 106 net locations for
potential future drilling in our Haynesville acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated recoveries from our
producing Haynesville wells and other nearby wells based on available public data, drilling densities observed from other operators including on some of our non-operated properties, estimated drilling and completion costs, spacing and other rules
established by regulatory authorities and surface conditions, among others. Of the 557 gross locations identified for future drilling, 482 of these locations (55 net locations) have been identified within the 5,500 net acres that we believe are
located in the core area of the Haynesville play. As we explore and develop our
Mr. H. Roger Schwall
November 14, 2011
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Haynesville acreage further, we believe that it is possible that we may identify additional locations for future drilling. At June 30, 2011, these identified potential future drilling locations in the Haynesville shale play included 94 gross and 15 net locations to which we have assigned proved undeveloped reserves.
| 12. | Please expand your table to present the number of “Total Identified Drilling Locations” to which you have booked proved undeveloped reserves for each the four plays. |
Response: In response to the Staff’s comment, the Company has added the following disclosure as a footnote to the table presenting the “Total Identified Drilling Locations” on pages 2 and 86:
At June 30, 2011, these identified drilling locations included 2 gross and 2 net locations to which we have assigned proved undeveloped reserves in the Eagle Ford and 94 gross and 15 net locations to which we have assigned proved undeveloped reserves in the Haynesville. We have no proved undeveloped reserves assigned to identified drilling locations in the Austin Chalk or Cotton Valley at June 30, 2011.
| 13. | We note your statements, “We believe that almost 85% of our Eagle Ford acreage is prospective predominantly for oil or significant liquids production.” and “Where the formation is shallow, it is less thermally mature and therefore more oil prone, and where it is more thermally mature, the Eagle Ford is more natural gas prone.” on page 96. With a view toward possible disclosure, please support your belief concerning significant future liquids production on your acreage. |
Response: The Company is providing separately to the Staff a map sourced from the U.S. Department of Energy/EIA and various operators and other information showing the extent, structure and thickness of the Eagle Ford shale play in south Texas. The map shows several Eagle Ford “petroleum windows” where oil, wet gas/condensate or dry gas are expected to be the predominant reservoir fluids produced from wells drilled in these areas. The windows are defined based on results from numerous wells drilled across the play as further noted on the map. On this map, the Company has overlaid its acreage position in the Eagle Ford play. Based upon the overlay, we have determined that almost 85% of our Eagle Ford net acreage falls within the “oil window” or the “wet gas/condensate window.” The Company believes it is reasonable to expect that wells
Mr. H. Roger Schwall
November 14, 2011
Page 8
drilled on its acreage in these “petroleum windows” will produce similar fluids to those produced from wells drilled by other operators in the trend and from which these “petroleum windows” were defined. This map also shows that where the Eagle Ford shale is shallower (and less thermally mature), it is more oil prone and where it is deeper (and more thermally mature) it is more natural gas prone. The map is being provided to the Staff pursuant to Rule 418 under the Securities Act of 1933, as amended. In accordance with Rule 418, the Company is requesting that the annexed map be returned promptly following completion of the Staff’s review thereof. The Company is providing a pre-paid self-addressed Federal Express envelope for the return of the map.
We recognize that the use of the word “significant” could be confusing. To remove the potential confusion, we have deleted the word “significant” from the referenced disclosures.
In response to the Staff’s comment, the Company has revised each of the statements referenced above on pages 3, 86 and 97 as follows:
Pages 3 and 86
We believe that approximately 85% of our Eagle Ford acreage is prospective predominantly for oil or significant liquids
production.
Page 97
Where the formation is shallow, it is less thermally mature and therefore more oil prone, and whereas it
isgets deeper and becomes more thermally mature, the Eagle Ford shale is more natural gas
prone. The transition between the two typically includes a mixture of natural gas and oil depending on the degree of thermal maturitybeing more oil prone and more
natural gas prone includes an interval that typically produces wet gas with condensate. We believe that almost 85% of our Eagle Ford acreage lies within those portions of the Eagle Ford shale that are prone to produce oil or wet gas with
condensate.
| 14. | We note your statements, “In addition, at June 30, 2011, we had approximately 23,000 gross acres and 15,000 net acres in the Haynesville shale play in northwest Louisiana and east Texas, including almost 5,500 net acres in what we believe is the core area of the play.” and “Although production rates vary widely across the [Haynesville] play, in the core area of the play, initial production rates of 20.0 to 25.0 MMcf per day of natural gas have been reported by operators.” on page 98. |
Mr. H. Roger Schwall
November 14, 2011
Page 9
| Please amend your document to describe the determinant characteristics of the “core area of the play.” With a view toward possible disclosure, please support your belief concerning future initial production rates from your acreage. |
Response: The Company has made changes to the disclosure on pages 3 and 87 in response to Comment 10 to explain its basis for defining the “core area” of the Haynesville play and has separately provided the Staff with additional supporting information, as explained in response to Comment 10. In addition, in response to the Staff’s comment, the Company has eliminated in Amendment No. 1 all references concerning initial production rates that it believes its wells were or may be capable of delivering in the future. Further, the Company has modified its statement on page 99 to remove any implication that the referenced production rates are representative of the Company’s expectations and to clarify that such production rates are representative of those of other operators in the Haynesville shale. The disclosure on page 99 now reads as follows:
Although
initial production rates vary widely across the play, in the core area of the play, initial production rates
ofas high as 20.0 to 25.0 MMcf per day of natural gas have been reported by operators from
horizontal wells drilled and completed in the Haynesville shale.
| 15. | We note your statement “From January 1, 2011 through July 31, 2011, we spent approximately $84.2 million in capital expenditures (or 57% of our 2011 capital expenditures budget). Approximately 70% and 23% of these expenditures were spent in the development of our acreage in the Eagle Ford shale play and the core area of the Haynesville shale play, respectively. From August 1, 2011 through December 31, 2011, we anticipate that our capital expenditures will be approximately $64.7 million.” “Development” implies activity to gain access to proved reserves. Please expand the table here to present separate development costs figures under “Anticipated Capital Expenditures Budgets” and separate development well counts under “2011-2012 Anticipated Drilling”. |
Response: In response to the Staff’s comment, the Company has modified the statement above on pages 5 and 89 to remove the reference to “development” activities. The Company has also made other modifications in this paragraph unrelated to the Staff’s comment. In addition, as requested by the Staff, the Company has expanded the referenced table on pages 5 and 89 to break up into separate columns the 2012 capital
Mr. H. Roger Schwall
November 14, 2011
Page 10
expenditure budget and wells being drilled based on whether the wells and related expenditures are deemed to be development or exploration wells and expenditures.
| 16. | You state “We began producing this [Williams 17 H#1] well at a constrained rate of about 10.0 MMcf natural gas per day that we believe optimizes overall well economics, even though we believe that this well was initially capable of delivering 20.0 to 25.0 MMcf of natural gas per day.” Please amend your document to explain how the reduced production optimizes the well economics. With a view to possible disclosure, explain to us your belief that this well is capable of 20 MMCFG flow rates. |
Response: Given the additional disclosure that would be required, the Company has determined that it is more appropriate to revise the referenced text on pages 6 and 93 to remove the disclosure relating to the optimization of overall well economics and the Company’s belief that the Williams 17 H#1 well was initially capable of delivering 20.0 to 25.0 MMcf of natural gas per day.
| 17. | You state “We currently participate in various drilling activities with larger industry participants, including affiliates of Chesapeake Energy Corporation, EOG Resources, Inc., Royal Dutch Shell plc and others.” Please amend your document to explain your access to the operator’s development schedules/plans for your non-operated PUD locations. Address the non-consent provisions and penalties in your operating agreements. |
Response: In response to the Staff’s comment, the Company has revised its disclosure on page 88 to add the following disclosure. The Company has not included the below disclosure in the “Overview” or under “Business Strategies” sections because it does not believe that such level of detail was appropriate in such sections.
We are a non-operating working interest participant with affiliates of Chesapeake Energy Corporation, Royal Dutch Shell plc and several other companies in the Haynesville shale and with EOG Resources, Inc. in the Eagle Ford shale. We have entered into a joint operating agreement with an affiliate of Chesapeake Energy Corporation governing the Haynesville operations underlying our Elm Grove/Caspiana properties in southern Caddo Parish, Louisiana (see “Other Significant Prior Events – Chesapeake Transaction”) and a joint operating agreement with EOG Resources, Inc. governing all operations on our joint acreage in Atascosa County, Texas. We have not entered into a joint operating agreement with Royal Dutch Shell plc
Mr. H. Roger Schwall
November 14, 2011
Page 11
or certain other operators of wells in the Haynesville area in which we have a minority working interest. Particularly when our working interest is small, we do not always enter into formal operating agreements with the operators, and in such cases, we rely on applicable legal and statutory authority to govern our arrangement in accordance with industry standard practices.
Where we do have joint operating agreements with affiliates of Chesapeake Energy Corporation and EOG Resources, Inc., these agreements call for significant penalties should we elect not to participate in the drilling and completion of a well proposed by the operator, or a non-consent well. These non-consent penalties typically allow the operator to recover up to 400% of its costs to drill, complete and equip the non-consent well from the well’s future net revenue prior to us being allowed to participate in the non-consent well for our original working interest. Ultimately, the amount of these penalties may result in us having no participation at all in the non-consent well. We also have the right to propose wells under these joint operating agreements, and the same non-consent penalties apply to the operator should it elect not to consent to a well that we propose.
While we do not have direct access to our operating partners’ drilling plans with respect to future well locations, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations. We review these locations with Netherland, Sewell & Associates, Inc., our independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of those drilling plans and our approach to booking these reserves.
Certain Risk Factors, page 10
| 18. | We note your statement at page 43 under “Risk Factors—If one or more material weaknesses persist…” that your auditors have identified a material weakness. Please revise the last bullet in this section state this fact. |
Mr. H. Roger Schwall
November 14, 2011
Page 12
Response: The Company has revised the last bullet on page 12 and the heading of the corresponding risk factor on page 42 to read as follows:
If one or
moreany of the material weaknesses previously identified by our independent registered public
accountants persist or if we fail to establish and maintain effective internal control over financial reporting in the future, our ability to accurately report our
financial results could be adversely affected.
Organizational Structure, page 11
| 19. | We note your disclosure that the shareholder ownership information set forth on page 11 is based on your reasonable judgment and reflects an approximation of the beneficial ownership of your common stock. Please tell us, with a view toward disclosure, why you are not able to provide more certainty with respect to the beneficial ownership of your common stock. |
Response: The Company notes that the referenced disclosure on page 13 will be finalized at a later date but prior to the effective date of the Registration Statement. In response to the Staff’s comment, the Company has revised the disclosure on page 13 as follows:
The shareholder ownership information set forth below is based on our reasonable judgment and reflects an approximation of the beneficial ownership of our common stock after consummation
of this offering based on the number of shares beneficially owned by our current shareholders at —, 2011.
| 20. | Please revise to enlarge the structure chart so that it is legible. |
Response: The Company has enlarged the structure chart on page 13 in response to the Staff’s comment.
Reserves Data, page 18
| 21. | As we requested in our September 6, 2011 teleconference, please furnish to us the petroleum engineering reserve reports you used as the basis for your March 31, 2011 proved reserves disclosures. We are continuing our engineering examination. Please include prepaid return shipping packaging and direct these engineering items to: |
U.S. Securities and Exchange Commission
100 F Street NE
Washington, DC 20549-4628
Mr. H. Roger Schwall
November 14, 2011
Page 13
Attn: Ronald M. Winfrey
Response: The Company has furnished the requested reserve reports for March 31, 2011. Since the Company’s June 30, 2011 proved reserves are disclosed in Amendment No. 1, the Company is providing separately the June 30, 2011 petroleum engineering reserve reports to Mr. Winfrey. The reserve reports have been and are being provided to the Staff pursuant to Rule 418 under the Securities Act of 1933, as amended. In accordance with Rule 418, the Company is requesting that all the reserve reports be returned promptly following completion of the Staff’s review thereof. The Company is providing a pre-paid self-addressed Federal Express envelope for the return of the reserve reports.
Risk Factors, page 20
General
| 22. | As appropriate, please ensure that each risk factor does not assert multiple risks that should be set forth in individual risk factors. For example, and without limitation, we note the risk factor at page 21 beginning “Drilling for and producing oil and natural gas are high-risk activities…” contains a separate risk in its penultimate and final paragraphs. |
Response: The Company has revised its risk factors in Amendment No. 1 to separate multiple risk factors.
| 23. | Similarly, please combine duplicative risk factors. For example, and without limitation, we note the risks asserted under “—Drilling and producing oil and natural gas are high-risk activities…” at page 21 and under “Exploration is a high-risk activity…” at page 26. |
Response: The Company has revised its risk factors in Amendment No. 1 to combine duplicative risk factors.
| 24. | Please revise generally to state the risks plainly and directly, without the use of mitigating text and “no assurance” and “cannot guarantee” language. For example, clauses which begin “although” or “while” often include disclosure which mitigates the identified risk. For example, and without limitation, we note the sentence beginning “While we believe the net proceeds from this offering…will be adequate…” under “—Our exploration, development and exploitation projects…” at page 25. |
Mr. H. Roger Schwall
November 14, 2011
Page 14
Response: The Company has revised its risk factors in Amendment No. 1 to state the risks plainly and directly, without the use of mitigating text.
Low Natural Gas Prices in the Future…, page 21
| 25. | We note your statement, “Should natural gas prices remain at current levels for an extended period of time, our future natural gas revenues, as well as the economic viability of our natural gas prospect inventory, will be adversely impacted. We may also elect to delay some of our exploration and development plans for these prospects until natural gas prices improve.” The average natural gas prices for 2011 are at about the same level as those you used for estimating proved reserves at year-end 2010 and March 31, 2011. This seems to indicate that you may not carry out your proved undeveloped drilling schedule. With a view to possible disclosure, please explain why you have doubts about developing these PUD reserves at prices similar to those used for booking. |
Response: The Company intends to drill or participate in the drilling of the wells to which it has booked proved undeveloped reserves so long as natural gas and oil prices remain at or above the prices used for booking these reserves. The Company does, however, attempt to allocate its capital whenever possible to those opportunities providing the highest anticipated return on investment. To the extent that other investment opportunities provide for better anticipated returns in the future, at that time the Company may shift its focus to these opportunities and adjust its current PUD development schedule accordingly. In response to the Staff’s comment, the Company has included the following disclosure in its risk factor disclosure on page 22:
Declines in oil or natural gas prices would not only reduce our revenue, but could reduce the amount of oil and natural gas that we can produce economically. Should natural gas or oil prices decrease from current levels and remain there for an extended period of time, we may elect in the future to delay some of our exploration and development plans for our prospects or to cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities, each of which would have a material adverse effect on our business, financial condition, results of operations and reserves.
Mr. H. Roger Schwall
November 14, 2011
Page 15
Because our reserves and production are concentrated…, page 23
| 26. | We note your disclosure that “[a]lmost all of [y]our current oil and natural gas production and [y]our proved reserves are attributable to producing properties….” However, this does not appear to be consistent with your related disclosure at page 10 and under “—Approximately 65% of our total proved reserves at March 31, 2011…” at page 25. Please revise your disclosure to clarify the distinction. |
Response: The Company has revised the referenced text on page 23 to delete the word “producing.”
We Have Limited Control over Activities on Properties We Do Not Operate, page 28
| 27. | Please revise this risk factor to incorporate the information provided at page F-16 regarding your sale of certain assets to Chesapeake Louisiana, L.P. |
Response: The Company has revised the risk factor on page 28 to incorporate the referenced information as follows:
We are not the operator on many of our properties. As a
resultsome of our properties, particularly in the Haynesville shale. As a result of our sale of certain assets to a subsidiary of Chesapeake Energy Corporation in 2008, we do
not operate one of our most significant natural gas assets in the Haynesville shale. We also acquired other non-operated acreage positions in north Louisiana. Because we are not the operator for these properties, our ability to
exercise influence over the operations of these properties or their associated costs is limited.
Hedging transactions, or the lack thereof…, page 31
| 28. | Please revise to briefly describe in this section a “costless collar” transaction. |
Response: The Company has revised the referenced risk factor on pages 30-31 as follows:
To manage our exposure to price risk, we, from time to time, enter into hedging arrangements, using primarily put and call options
in the form of “costless collars,” with respect to a portion of our future production.
The goal of theseA costless collar provides us with downside price protection through the purchase of a put option which is financed through the sale of a call option.
Because the call option proceeds are used to offset the cost of the put option,
Mr. H. Roger Schwall
November 14, 2011
Page 16
this arrangement is initially “costless” to us. The goal of these and other hedges is to lock in a range of prices so as to mitigate price volatility and increase the
predictability of cash flows. These transactions limit our potential gains if oil and natural gas prices rise above the maximum price established by the optionscall option and may offer protection if prices fall below
the minimum price established by the optionsput option only to the extent of the volumes then hedged.
Cautionary Note Regarding Forward-Looking Statements, page 47
| 29. | Please remove “will” from your list of forward-looking statements. |
Response: The Company has removed “will” from its list of forward-looking statements on page 46.
| 30. | We note your disclosure at page 48 that you do not undertake any obligation to update or revise publicly any forward-looking statements. Please revise to state, if true, that you will update or revise such statements as required by law. |
Response: The Company has revised the disclosure on page 47 as follows:
We do not undertake any obligation to update or revise publicly any forward-looking statements except as required by law, including the securities laws of the United States and the rules and regulations of the SEC.
Use of Proceeds, page 49
| 31. | Once you know the expected size of the offering, and no later than when you provide the price range for the offering, you will need to provide the estimated amounts you intend to allocate to each of the identified uses. Please provide necessary detail for each use, including with respect to “the other general corporate purposes” that you reference at page 49. In addition, please present the information in tabular form to facilitate clarity. |
Mr. H. Roger Schwall
November 14, 2011
Page 17
Response: The Company acknowledges the Staff’s comments and undertakes to provide the estimated amounts it intends to allocate to each identified use when the price range for the offering is provided. In addition, the Company has removed the reference to “other general corporate purposes” from page 48 and added the following tabular presentation:
| Use of Net Proceeds |
Amount (in millions) |
|||
| Repayment of term loan |
$ | 25.0 | ||
| Repayment of revolving credit facility |
60.0 | |||
| Payment of a portion of 2012 capital expenditure requirements |
— | |||
|
|
|
|||
| Total |
$ | — | ||
| 32. | We note that you intend to use the proceeds received from the offering to repay borrowings under your credit facility. We also note that you intend on using the proceeds from the offering and from “future potential borrowings” under your revolving credit loan for capital expenditures. Please revise to disclose whether, upon repayment of the credit facility, you have any plans to immediately draw down on the credit facility, and if so, for what purposes. |
Response: The Company has revised the disclosure on page 48 to include the following:
Upon consummation of this offering and application of the net proceeds we receive in the manner described above, we anticipate that we may need to access future borrowings under our credit agreement within 60 to 90 days following completion of this offering to fund a portion of our 2012 capital expenditures in excess of amounts available from our cash flows and the proceeds of this offering.
| 33. | We note your disclosure that the ultimate uses of your capital may differ depending on market conditions and the outcome of your drilling results. We also note your related risk factor disclosure at page 42. Please revise your Use of Proceeds section to provide all the information required by Instruction 7 to Item 504 of Regulation S-K. |
Response: In response to the Staff’s comment, the Company has revised the last paragraph on page 49 as follows:
While we expect to use the proceeds from this offering in the manner set forth above, the ultimate
usesamount of our capital may differ dependingwe will expend may
fluctuate materially based on market conditions and our drilling results. Our future financial condition and liquidity will be impacted by, among other factors, our level of
production of oil and natural gas and the prices we receive from the sale thereof, the outcome of our exploration and
Mr. H. Roger Schwall
November 14, 2011
Page 18
drilling programs, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, and the actual cost of exploration and development of our oil and natural gas assets. Until the actual use of our net proceeds from this offering as described above, we intend to invest such net proceeds in U.S. treasury bonds or investment grade instruments.
Changes in Accountants, page 84
| 34. | We note your disclosure regarding discussions with Grant Thornton prior to their reengagement. Describe for us, in reasonable detail, the facts and circumstances surrounding these discussions. As part of your response, tell us the specific subject matters discussed, the purpose and timing of the discussions, and the conclusions reached. |
Response: Effective at February 28, 2011, our Audit Committee unanimously approved the reappointment of Grant Thornton as our independent accountant to audit our financial statements for the year ended December 31, 2010. Prior to our reengagement of Grant Thornton, we had discussions with Grant Thornton regarding whether they had the capacity, availability and desire to reengage as our auditors going forward. We discussed in detail the reasons for our initial auditor change and the reasons for our decision to discuss reengaging Grant Thornton. Prior to these reengagement discussions, during the period from approximately the middle of December 2010 through the end of January 2011, there were also discussions related to the accounting for our outstanding stock options, specifically regarding the liability versus equity classification of the outstanding options, and our accounting for income taxes related to the calculation of deferred taxes related to our statutory depletion calculation in 2008 and 2009. These discussions were initiated to ensure that the accounting treatment for the historical periods continued to be appropriate. Based on discussions held prior to our reengagement of Grant Thornton, it was concluded that the accounting treatment continued to be appropriate with no adjustments to the previously issued financial statements necessary. The aforesaid discussions did not address any accounting issues related to the fiscal year 2010. Other subjects discussed with Grant Thornton included their reengagement procedures, their verification that there were no conflicts in their reengagement and the timing of the proposed audit for 2010. The reengagement discussions were undertaken solely for the purpose of establishing that Grant Thornton was able to accept the reengagement and had the requisite available personnel to perform the 2010 audit.
Mr. H. Roger Schwall
November 14, 2011
Page 19
The Company has revised its disclosures on page 84 to describe the nature of the discussions consistent with the information above.
Business, page 85
| 35. | We note the discussion on page 87, and elsewhere in your filing, of your planned drilling activity and related capital budgets. To aid investor understanding of your plans, revise this presentation to separately show activities and amounts related to exploration and development drilling. |
Response: In response to the Staff’s comment, the Company has expanded the referenced table on pages 5 and 89 to present exploration and development wells and anticipated exploration and development capital expenditures separately.
Estimated Proved Reserves, page 106
| 36. | Please furnish to us the producing rate vs. time plots for these wells/locations included in your March 31, 2011 reserve report: Bradway 24-15-12 H #01(Carried), Caspiana 14-15-12 H #01(Carried), Peironnet 26H(S26-15N-12W) #01(Carried), Bradway 24-15-12 H #02PUD, Caspiana 14-15-12 H #02 PUD, Peironnet 26H(S26-15N-12W) #02 PUD. Please ensure that the decline parameters, EURs and reserves are included as well as the completion reports for the three producing wells. |
Response: The Company is providing the requested information separately to the Staff for June 30, 2011 since the March 31, 2011 proved reserves have been replaced in Amendment No. 1 by the June 30, 2011 reserves. The information is being provided to the Staff pursuant to Rule 418 under the Securities Act of 1933, as amended. In accordance with Rule 418, the Company is requesting that the information be returned promptly following completion of the Staff’s review thereof. The Company is providing a pre-paid self-addressed Federal Express envelope for the return of the information.
| 37. | It appears the terminal decline rate used in your Haynesville projections is six percent or less. Please explain to us the evidence for this rate. |
Response: Terminal decline rates of various low permeability reservoirs have been observed to be between 1.6% and 6.2% as reflected in the table below. The Company has used a 5% terminal decline rate for its Haynesville projections, which it considers to be reasonable in light of the data from other low permeability formations. The Company’s understanding is that other Haynesville operators are using the same or a
Mr. H. Roger Schwall
November 14, 2011
Page 20
similar terminal decline rate for their Haynesville wells. In addition, Netherland, Sewell and Associates, Inc. believes the 5% terminal decline rate for our Haynesville projections is reasonable.
Terminal Decline Rates of Low Permeability Reservoirs*
| Field |
Formation |
Terminal Decline Rate |
||||
| Appalachian Huron Field |
Lower Huron Shale |
2.10 | % | |||
| Wamsutter Field |
Almond/Mesaverde |
1.60 | % | |||
| Sahara Field |
Chester/Mississippi/Hunton |
1.90 | % | |||
| Giddings Field |
Austin Chalk |
2.40 | % | |||
| Jonah Field |
Lance/Mesaverde |
3.70 | % | |||
| TX Panhandle Lipscomb Field |
Cleveland |
2.40 | % | |||
| Barnett Vertical Field |
Barnett Shale |
3.10 | % | |||
| Barnett Horizontal Field |
Barnett Shale |
6.20 | % | |||
| * | Source: Chesapeake Energy’s 2009 Investor and Analyst Meeting Presentation. |
| 38. | We note your statement, “Our proved undeveloped reserves increased from 84.3 Bcfe at December 31, 2010 to 98.7 Bcfe at March 31, 2011 due primarily to our drilling operations in Haynesville. The increase in our proved undeveloped oil reserves specifically from zero to 377 MBbls at March 31, 2011 is attributable to our drilling operations in the Eagle Ford shale play.” Please amend your document to disclose: material changes to proved undeveloped reserves that occurred during the year due to revisions, drilling, acquisitions/divestment and conversion of proved undeveloped reserves into proved developed reserves; investments and progress made in the conversion of proved undeveloped reserves to developed status; the reasons, if any, that material amounts of proved undeveloped reserves remain undeveloped for five years or more after booking. Refer to Item 1203 of Regulation S-K. |
Response: In response to the Staff’s comment, the Company has updated the referenced disclosure on page 107 to include reserve estimates at June 30, 2011 as follows:
Our proved undeveloped
reserves increased from 84.3 Bcfe at December 31, 2010 to 98.7104.3 Bcfe at
March 31,June 30, 2011 due primarily to our drilling
Mr. H. Roger Schwall
November 14, 2011
Page 21
operations in the Haynesville shale. The increase in our proved undeveloped oil reserves specifically from zero to
377478 MBbls at March 31,June
30, 2011 is attributable to our drilling operations in the Eagle Ford shale play. OurThe net
increase of 20.0 Bcfe in our proved undeveloped reserves at March 31, 2011 were made up of about 97% natural gas and 3%
oilfrom December 31, 2010 to June 30, 2011 is composed of (1) additions of 25.3 Bcfe to proved undeveloped reserves identified through drilling
operations, less (2) the conversion of 1.2 Bcfe of proved undeveloped reserves to proved developed reserves, less (3) the downward revisions of proved undeveloped reserves by 2.3 Bcfe in the period. During this period, we recorded no
changes to proved undeveloped reserves as a result of the acquisition or divestment of reserves. We had no proved undeveloped reserves assigned to our properties at December 31, 2008, and hence, all of our proved undeveloped reserves have been
added since that time. Thus, at June 30, 2011, we had no proved reserves in our estimates that remained undeveloped for five years or more following their initial booking.
Internal Control over Reserves Estimation Process, page 108
| 39. | You state, “Following the preparation of our reserves estimates, for the years ended December 31, 2010 and 2009 and for the three month period ended March 31, 2011, we had our reserves estimates audited for their reasonableness and conformance with generally accepted petroleum engineering and evaluation principles by Netherland, Sewell & Associates, Inc., our independent petroleum engineers.” While we understand that there are fundamental of physics, mathematics and economics that are applied in the estimation of reserves, we are not aware of an official industry compilation of such “generally accepted petroleum engineering and evaluation principles.” With a view toward possible disclosure, please explain to us the basis for concluding that such principles have been sufficiently established so as to judge that the reserve information had been prepared in conformity with such principles. Refer us to a compilation of these principles. |
Response: In response to the comment, the Company has removed the underlined disclosure from page 109.
Management, page 122
Mr. H. Roger Schwall
November 14, 2011
Page 22
| 40. | Please revise your disclosure to quantify the amount of time that David F. Nicklin devotes to the company in view of his role at Salt Creek Petroleum and his consulting company. |
Response: In response to the Staff’s comment, the Company has revised its disclosure on page 125 to quantify the amount of time that David F. Nicklin devotes to the Company as follows:
Since 2009, Mr. Nicklin has consulted almost exclusively for us, with the primary exception of the minimal time he has devoted to Salt Creek Petroleum. Mr. Nicklin worked approximately 210 days for us in each of 2009 and 2010 and is expected to work a similar number of days for us in 2011.
| 41. | Please revise the biographies of Gregory E. Mitchell and Margaret B. Shannon to briefly discuss the specific experience, qualifications, attributes or skills that led to the conclusion that each such officer should serve as one of your directors in light of your business and structure. See-Item 401(e) of-Regulation S-K. |
Response: The Company has revised the biographies of Mr. Mitchell and Ms. Shannon on page 129 and page 130, respectively, to briefly discuss the specific experience, qualifications, attributes and/or skills that led to the conclusion that each should serve as one of the Company’s directors. The new disclosures are set forth below for the Staff’s convenience. The Company also notes that on September 14, 2011, the Company’s board of directors increased the size of the board from seven directors to eight, and the board appointed Charles L. Gummer to serve as a Class I director. Mr. Gummer’s biography is included on pages 126-127.
Mr. Gregory E. Mitchell
Mr. Mitchell’s experience as President and CEO of his large family business and as a director of several companies provides our board of directors with extensive business, strategic and executive leadership experience.
Mrs. Margaret B. Shannon
Mrs. Shannon’s experience as an attorney, as a partner with Andrews Kurth LLP, as general counsel for a public company for more than 15 years and as a director for numerous other organizations provides our board of directors
Mr. H. Roger Schwall
November 14, 2011
Page 23
with important insights into public company obligations, corporate governance and board functions.
| 42. | Please revise your disclosure at page 129 to state whether there is a written agreement memorializing the arrangement you have with each of the special board advisors. |
Response: The Company has revised the disclosure on page 131 to state that, other than indemnification agreements in form similar to those entered into with its directors and officers, it has not entered into written agreements with any of its special board advisors. The revised disclosure is set forth below:
These individuals serveOther than indemnification
agreements in form similar to those entered into with our directors and officers, we have not entered into written agreements with these individuals with respect to their service as special advisors to our board of directors and
certain of the board’s committees.
Committees of the Board of Directors, page 130
| 43. | We note your disclosure in this section regarding actions that you intend to take prior to the completion of the offering. Please ensure that you include relevant updates with each amendment. |
Response: The Company acknowledges the Staff’s comment and has updated, where applicable, various actions that the Company has taken since filing the Registration Statement. The Company undertakes to provide updates to such other disclosure in future amendments to the Registration Statement.
Compensation of Named Executive Officers, page 135
2010, page 136
| 44. | Please revise to identify the members of your Planning and Compensation Committee that determined compensation for the periods presented. |
Response: The Company has identified on page 138 the members of its Planning and Compensation Committee that determined compensation for the periods presented in Amendment No. 1, which were Messrs. Foran, Laney, Ryan and Scott and Dr. Holditch.
Mr. H. Roger Schwall
November 14, 2011
Page 24
| 45. | We note your disclosure that the number of stock options awarded to each named executive officer was based upon an evaluation of such officer’s performance and relative contributions to your growth. We also note your disclosure that the amounts of the 2010 cash bonus granted to each named executive officer was based on an evaluation of such officer’s performance and contributions to your growth and achievement of your performance objectives in 2010 considered in relation to all elements of such officer’s overall compensation. Please expand your disclosure to describe, for each named executive officer, the specific performance and contributions to your growth and achievement of your performance objectives that had a material impact on the number of stock options and amount of 2010 cash bonus awarded to such officer. |
Response: In response to the Staff’s comment, the Company has revised the disclosure on pages 139-141 as follows:
Pages 139-140
The number of stock options awarded to each Named Executive Officer was based upon an evaluation of each Named Executive Officer’s performance and relative contributions to our growth over the previous two years, 2008 and 2009, as determined by Mr. Foran in consultation with the chairman of the Planning and Compensation Committee. The Named Executive Officers’ stock option awards reflected each officer’s contributions to the following company-wide accomplishments:
| • | increasing our annual production to approximately 5.0 Bcfe for the year ended December 31, 2009 from approximately 3.3 Bcfe for the year ended December 31, 2008; |
| • | more than doubling our average daily production to 23.8 MMcfe per day for the month of December 2009 as compared to 9.6 MMcfe per day for the month of December 2008; and |
| • | increasing our proved oil and natural gas reserves by more than three-fold to 64.5 Bcfe at December 31, 2009 from 20.0 Bcfe at December 31, 2008. |
Mr. H. Roger Schwall
November 14, 2011
Page 25
In addition to their contributions towards meeting the above objectives, the Named Executive Officers’ stock option awards reflected the following individual contributions:
| • | Mr. Lancaster’s specific contributions to the closing of the Chesapeake transaction in 2008 and his efforts related to planning the strategic reinvestment of the proceeds from the transaction; |
| • | Mr. Hairford’s efforts in planning and conducting our 2008 and 2009 Cotton Valley drilling and completion program in north Louisiana, for the cost savings achieved in that program on a well-by-well basis and for his leadership of the operations and land staff in saving key leasehold tracts set to expire in 2008 in our Elm Grove/Caspiana area; |
| • | Mr. Robinson’s efforts in planning and conducting our 2008 and 2009 Cotton Valley drilling and completion program in north Louisiana; and |
| • | Mr. Nicklin’s leadership of the exploration staff in identifying the Eagle Ford shale as a potential new exploration play for the company. |
The members of the Planning and Compensation Committee and the board of directors unanimously agreed with the recommendations of Mr. Foran and the chairman of the Planning and Compensation Committee.
Pages 140-141
In December 2010, Mr. Foran, in consultation with the
chairman of the Planning and Compensation Committee, awarded a special performance bonus of $50,000 to Mr. Hairford, in recognition of Mr. Hairford’s effort to negotiate and consummate the acquisition of approximately
8,892 gross and net acres in the Eagle Ford play in Zavala County, Texas. See “Business — Other Significant Prior Events.” In addition, in
December 2010, Mr. Foran evaluated the other Named Executive Officers, and, based on his knowledge of compensation levels in the oil and natural gas industry, recommended to the chairman of the Planning and Compensation
Committee the appropriate 2010 bonuses for the Named Executive Officers, other than himself. The reasons we paid discretionary cash bonuses to our executive officers in 2010 are described above under “Compensation Discussion and Analysis —
Elements of Our 2010 Compensation Program and Why We Pay Each Element — Discretionary Cash Bonuses.” Mr. Foran and the chairman of the Planning and Compensation Committee discussed Mr. Foran’s evaluation of the
other Named Executive Officers and made any appropriate adjustments to the recommended bonuses. The amounts of the bonuses for each Named Executive Officer were based upon an evaluation of each Named Executive Officer’s performance and
contributions to our growth and
Mr. H. Roger Schwall
November 14, 2011
Page 26
achievement of our performance objectives in 2010 considered in relation to all elements of the Named Executive Officer’s overall compensation. The chairman of the Planning and
Compensation Committee and Mr. Foran made their joint recommendations of the bonus amount to both the Planning and Compensation Committee and the board of directors. However, Mr. Foran was not present when the chairman of the Planning and
Compensation Committee made his recommendations regarding Mr. Foran’s bonus. After receiving the recommendations from Mr. Foran and the chairman of the Planning and Compensation Committee for the
other Named Executive Officers and from the chairman of the Planning and Compensation Committee for Mr. Foran, the Planning and Compensation Committee and the board of directors unanimously (other than with
respect to Mr. Foran on his bonus) agreed with the recommendations. Named Executive Officers’ cash bonuses in 2010 reflected each officer’s contributions to
meeting our company-wide 2010 performance objectives which included the following:
| • | increasing proved oil and natural gas reserves at December 31, 2010 to at least 100 Bcfe, a target we exceeded by increasing our proved oil and natural gas reserves at December 31, 2010 to 128.3 Bcfe; |
| • | increasing annual production for 2010 to at least 8 Bcfe, a target we exceeded by increasing our annual production for 2010 to 8.6 Bcfe; |
| • | reducing operating cash costs (excluding unit depletion, depreciation and amortization costs) below $2.00 per Mcfe in 2010, a target we achieved by realizing operating cash costs of $1.97 per Mcfe in 2010; |
| • | making a significant discovery in a new exploration play, a target we achieved with the drilling of our first operated Eagle Ford shale wells; and |
| • | securing a joint venture participant for the exploration of the Meade Peak shale in southwest Wyoming and adjacent areas in Utah and Idaho, a target we achieved with the closing of our participation agreement with Alliance Capital Real Estate, Inc. in May 2010. |
Also, the Named Executive Officers’ cash bonuses reflected each officer’s contributions to the successful acquisition of additional leasehold acreage in both the Haynesville and Eagle Ford plays throughout 2010. In addition to their contributions toward meeting the above objectives and the acquisition of additional Haynesville and Eagle Ford acreage, the Named Executive
Mr. H. Roger Schwall
November 14, 2011
Page 27
Officers’ cash bonuses in 2010 reflected the following individual contributions:
| • | Mr. Foran’s efforts in the successful outcome of our October 2010 through January 2011 private placement offering of 1,922,199 shares of our Class A common stock and the leadership he provided to the attainment of our 2010 performance objectives identified above; |
| • | Mr. Lancaster’s efforts in the increase in the borrowing base under our credit agreement from $20,000,000 to $55,000,000 in 2010 and the leadership he provided to the attainment of our 2010 operational and financial objectives identified above; |
| • | Mr. Hairford’s bonus included a special performance bonus of $50,000 in recognition of Mr. Hairford’s effort to negotiate and consummate the acquisition of approximately 8,892 gross and net acres in the Eagle Ford play in Zavala County, Texas and his bonus also reflected his efforts in the successful drilling and completion of our first operated wells in the core area of the Haynesville shale and in the Eagle Ford shale; |
| • | Mr. Nicklin’s leadership of the exploration staff in developing in-house processes for the geosteering of long, horizontal laterals in the Eagle Ford and Haynesville plays and his specific contributions to securing the joint participation agreement with Alliance Capital Real Estate, Inc. for the exploration of our Meade Peak shale prospect; and |
| • | Mr. Robinson’s specific contributions to identifying Alliance Capital Real Estate, Inc. as a potential joint venture partner for the exploration of our Meade Peak shale prospect and for assuming the leadership role in coordinating our non-operated participation interests in the Haynesville play in north Louisiana. |
Summary Compensation Table, page 149
| 46. | Please revise note 4 to the table to include the per diem base rate under Mr. Nicklin’s consulting agreement. |
Response: The Company has revised note 4 to the table on page 152 to include the $1,500 per diem rate under Mr. Nicklin’s consulting agreement.
Corporate Reorganization, page 160
Mr. H. Roger Schwall
November 14, 2011
Page 28
| 47. | We note your disclosure that it was “determined it was in the best interests of the corporation and its shareholders that the company reorganize into a holding company structure....” Please expand your disclosure to briefly describe why such action was determined to be in the best interests of the corporation and its shareholders. |
Response: The Company has expanded the disclosure on page 163 as follows:
TheTo accommodate growth through acquisitions, provide
potential protection from liability and facilitate future sales or spinoffs of subsidiaries and holding company financing arrangements, the former Matador Resources Company, now known as MRC Energy Company, determined it was in the best
interests of the corporation and its shareholders that the company reorganize into a holding company structure pursuant to Section 10.005 of the Texas Business Organizations Code.
Material U.S. Federal Income and Estate Tax Considerations to Non-U.S. Holders, page 170
| 48. | We note your statement at page 170 that you “urge each prospective investor to consult a tax advisor regarding the U.S. federal, state, local and non-U.S. income and other tax consequences of acquiring, holding and disposing of shares of our common stock.” Please revise your disclosure to remove any implication that investors are not entitled to rely on your disclosure. For example, you may instead state to the effect that investors considering the purchase of securities should consult their tax advisors regarding the application of the U.S. federal income tax laws to their particular situations as well as any tax consequences arising under U.S. estate tax laws and under the laws of any state, local or foreign taxing jurisdiction or under any applicable tax treaty. |
Response: The Company has revised its disclosure on page 174 to remove any implication that investors are not entitled to rely on such disclosure. The revised disclosure is set forth below:
We urgeThis section does not address all U.S.
federal income and estate tax matters applicable to a non-U.S. holder. Because each prospective investor may have unique circumstances beyond the scope of the discussion herein, we encourage each prospective investor to consult
atheir own tax advisor regarding the application of
the U.S. federal, state, local and non-U.S. income and other tax consequences of acquiring, holding and disposing of shares of our
Mr. H. Roger Schwall
November 14, 2011
Page 29
common stock. income tax laws to their particular situations as well as any tax consequences arising under U.S.
estate laws and under the laws of any state, local or foreign taxing jurisdiction or under any applicable tax treaty.
Annual Financial Statements, page F-1
Consolidated Balance Sheets, page F-3
| 49. | Confirm to us supplementally that the balance sheet caption Unproved and Unevaluated properties includes only properties for which it has not yet been determined whether or not proved reserves can be assigned, and that properties for which the determination has been made have been transferred to the amortization base on a well-by-well or property-by-property basis as the projects have been evaluated. |
Response: The Company confirms that the balance sheet caption “Unproved and Unevaluated” properties includes only properties for which it has not yet been determined whether or not proved reserves can be assigned, and that properties for which the determination has been made have been transferred to the amortization base on a well-by-well or property-by-property basis as the projects have been evaluated. As wells are drilled and proved reserves are assigned, unproved and unevaluated costs associated therewith are transferred to the amortization base on a well-by-well basis. In some instances, the Company may decide not to drill a particular property to which it has acquired the rights to drill, and once that determination has been made, the unproved and undeveloped costs associated with the entire property are transferred to the amortization base.
Consolidated Statements of Operations, page F-4
| 50. | We note you have reported the line item “Net (loss) gain on asset sales and inventory impairment” as a non-operating item. Based on the nature of the underlying transactions, we would expect these items to be included in the calculation of operating income (loss), as required by ASC 360-10-45-5. Revise your presentation accordingly, or explain to us why you believe no revision is necessary. |
Response: As disclosed, in July 2008, the Company signed an agreement with Chesapeake for the joint exploration and development of the Haynesville shale underlying its existing Cotton Valley production on the Company’s leasehold in north Louisiana. The Company recorded a gain on this sale of approximately $138,000,000.
Mr. H. Roger Schwall
November 14, 2011
Page 30
At the time of the transaction, the Company had no production from and no reserves assigned to the Haynesville shale. Given the extraordinary nature and size of this transaction which the Company considered to be outside the course of its normal oil and natural gas operations, the Company determined that including the gain from this transaction in the computation of “Operating income (loss)” would significantly distort comparisons with previous and future periods and was, therefore, best included with “Other income.” Besides the gain recorded on this transaction, the majority of the other income (loss) included in “Net (loss) gain on asset sales and inventory impairment” relates to the impairment of drilling rig parts purchased by the Company in 2006, but which the Company has marked for sale and does not consider to be part of its normal oil and natural gas operations. For these reasons, the Company believes that its presentation of these items as “Other income (expense)” is appropriate and that no further revision to its financial statements is necessary.
Notes to Consolidated Financial Statements, page F-7
Note 2 — Summary of Significant Accounting Policies, page F-7
Property and Equipment, page F-9
| 51. | We note the disclosure indicating that, “if the net capitalized costs of evaluated oil and natural gas properties less related deferred income taxes exceed the estimated present value of after-tax future net cash flows from proved oil and natural gas reserves, discounted at 10%, such excess is charged to operations as a full-cost ceiling impairment.” Explain how this policy takes into consideration the calculations identified in items (B) and (C) in Rule 4-10(c)(4)(i) of Regulation S-X. |
Response: The Company’s policy for computing the cost center ceiling takes into consideration items (B) and (C) in Rule 4-10(c)(4)(i) of Regulation S-X. The Company acknowledges, however, that its disclosure may not make this clear and has revised its disclosure on pages F-9 - F-10 as follows:
The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of
accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred. Internal costs are capitalized
only to the extent they are and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs
include
Mr. H. Roger Schwall
November 14, 2011
Page 31
lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both
productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration,
or and development activities and,
but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $1,604,682, $1,642,868 and $1,679,992 of
these internalits general and administrative costs in 2010, 2009 and 2008, respectively.
If the net capitalized costs of evaluated oil and natural gas properties less related deferred income taxes exceed the estimated
present value of after-tax future net cash flows fromThe net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related
deferred income taxes or the cost center ceiling, with any excess above the cost center ceiling charged to operations as a full-cost ceiling impairment. The cost center ceiling is defined as the sum of (a) the present value discounted at 10
percent of future net revenues of proved oil and natural gas reserves, discounted at 10%, such excess is charged to operations as a full-cost ceiling impairment. A discount factor of 10% is used for purposes of computing the
full-cost ceiling in accordance with SEC guidelines. The present value at 10% discount of future after-tax net cash flows is not intended to represent the replacement cost or fair market value of the Company’s
oil and natural gas properties. plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved
and unevaluated properties included in the costs being amortized, if any, less (d) income tax effects related to differences between the book and tax basis of the properties involved. Future net revenues from proved non-producing and proved
undeveloped reserves are reduced by the estimated costs for developing these reserves. The fair value of the Company’s derivative instruments is not included in the ceiling test computation as the Company does not designate these instruments as
hedge instruments for accounting purposes.
Income Taxes, page F-13
| 52. | We note your disclosure that “the Company evaluated all tax position for which the statue of limitations remained open, and management believes that the material positions taken by the Company would more likely than not be sustained by examination.” Based on this disclosure, please tell us how you have considered the |
Mr. H. Roger Schwall
November 14, 2011
Page 32
| disclosure required by ASC 740-10-50-15A regarding a tabular reconciliation of the total amounts of your unrecognized tax benefits. |
Response: In response to the Staff’s comment, the Company has revised its disclosure on page F-13 as follows.
Following adoption, the Company evaluated all tax positions for which the statute of limitations remained open, and management believes
that the material positions taken by the Company would more likely than not be sustained by examination. TheTherefore, at December 31, 2010, the Company
does not expect any change inhad not established any reserves for, nor recorded any unrecognized tax benefits in the next 12
monthsrelated to, uncertain tax positions.
Note 3 — Property and Equipment, page F-20
| 53. | With respect to costs not subject to amortization as of December 31, 2010, provide a description of the current status of the significant properties or projects involved, including the anticipated timing of the inclusion of the costs in the amortization computation. See Rule 4-10(c)(7)(ii) of Regulation S-X. |
Response: The Company has revised its disclosure beginning on page F-21 as follows:
Property acquisition costs primarily include leasehold costs paid to secure oil and gas mineral leases, but may also include broker and legal expenses, geological and geophysical expenses and capitalized
internal costs associated with developingdefining oil and natural gas prospects on these properties.
Property acquisition costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is
determined. Unproved and undeveloped properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions.
Property acquisition costs incurred in 2010 were primarily related to the Company’s leasing activities in the Eagle Ford shale play in south Texas and the Haynesville shale play in north Louisiana. At December 31, 2010, the Company had only just begun drilling wells on its Eagle Ford shale acreage. Portions of these costs will be transferred to the amortization base periodically as the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot
Mr. H. Roger Schwall
November 14, 2011
Page 33
be assigned proved reserves. The same is true for the Haynesville acreage acquired in 2010, although some portions of the Company’s Haynesville acreage acquired in 2010 have already been assigned proved reserves and the corresponding leasehold acquisition costs have been transferred to the amortization base. The Company estimates that evaluation of most of these properties and the inclusion of their costs in the amortization base is expected to be completed within five years.
The 2009 and 2008 property acquisition costs were related primarily related to the Company’s leasing activities
in the Haynesville playshale play. These costs are associated with acreage for which proved reserves have
yet to be assigned. The Company estimates that evaluation of most of these properties and the inclusion of their costs in the amortization base is expected to be completed within three to five years. Property acquisition costs incurred in
2007 and prior years were related primarily related to the Company’s leasing activities in southwest Wyoming, northeast Utah and southeast Idaho.
Property acquisition costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for
possible impairment on a periodic basis based upon changes in operating or economic conditions. The majority of the leases acquired in these areas have primary expiration terms
of five to ten years and do not begin to expire until various times in 2012. At December 31, 2010, the Company was preparing to drill its first exploration well on this acreage in southwest
Wyoming. The Company estimates that evaluation of most of these properties and the inclusion of their costs in the
amortization base is expected to be completed within two to five years.
Unproved and unevaluated property
costsCosts excluded from amortization also include those costs associated with
exploratoryexploration and development wells in progress that were drilling or awaiting completion at year-end and for
which proved reserves had yet to be determined. These costs totaled $35,906,656 at December 31, 2010 as compared with $6,379,008 at December 31,
2009. These costs are transferred into the amortization base on an ongoing basis, as exploratory and
developmentthese wells are completed and proved reserves are established. Exploratory dry holes are included in the amortization base
immediately upon determination that the well is not productive. or confirmed.
These costs totaled $35,906,656 at December 31, 2010
and were all associated
Mr. H. Roger Schwall
November 14, 2011
Page 34
with exploration wells. The Company anticipates that the entire $35,906,656 associated with these wells in progress at
December 31, 2010 will be transferred to the amortization base during 2011. At December 31, 2010, there were no exploratory or development well costs included in unproved and unevaluated property
costsexcluded from amortization that were incurred in years prior to 2010.
| 54. | Revise your detailed presentation of costs not subject to amortization to separately present amounts incurred for exploration and development wells. See Rule 4-10(c)(7)(ii)(2) of Regulation S-X. |
Response: In response to the Staff’s comment, on page F-20 the Company has revised its detailed description of costs not subject to amortization to separately present the amounts incurred for exploration and development wells. The revised table is presented below:
| Description |
2010 | 2009 | 2008 | 2007 and prior |
Total | |||||||||||||||
| Costs incurred for |
||||||||||||||||||||
| Property acquisition |
$ | 86,043,632 | $ | 14,267,810 | $ | 26,155,365 | $ | 10,077,986 | $ | 136,544,793 | ||||||||||
| Exploration wells |
35,906,656 | — | — | — | 35,906,656 | |||||||||||||||
| Development wells |
— | — | — | — | — | |||||||||||||||
| Capitalized interest |
— | — | — | — | — | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
$ | 121,950,288 | $ | 14,267,810 | $ | 26,155,365 | $ | 10,077,986 | $ | 172,451,449 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Note 8 — Employee Benefit Plans, page F-26
| 55. | We note your disclosure on page F-26 that “at December 31, 2010, the Company measured and recognized the fair value of the liability associated with its outstanding stock options using an estimated fair value of $11.00 per share for the Company’s Class A common stock.” Explain to us how you have valued the liability as of the end of your most recent interim period. |
Response: At June 30, 2011, the Company recognized the fair value of the liability associated with its outstanding stock options using an estimated fair value of $11.00 per share for the Company’s Class A common stock. In January 2011, we completed a private placement offering of 1,922,199 shares of our Class A common stock at $11.00 per share for an aggregate amount of $21,144,189. The Company has neither purchased nor issued shares of its Class A common stock since that time, other than shares issued upon the exercise of previously issued stock options and the issuance of shares related to the routine service of the
Mr. H. Roger Schwall
November 14, 2011
Page 35
Company’s Board of Directors and advisors. In determining the estimated fair value of its Class A common stock to compute its liability associated with outstanding stock options at June 30, 2011, the Company considered the improvements made in its production and reserves since December 31, 2010, as well as the additional leasehold interests it has acquired, particularly in the Eagle Ford shale. The Company also considered the increased borrowings under its credit agreement of approximately $60,000,000 since December 31, 2010. Any increase in share price that might be associated with improvements in the Company’s production, reserves and leasehold interests was likely offset, in part or in whole, by the Company’s increased borrowings at June 30, 2011. Taking these factors into consideration, and because the Company is privately held and its shares are not actively traded, the Company believes that the $11.00 per share realized in its most recent private placement offering completed in January 2011 continues to represent the best estimate of the fair value for the Company’s Class A common stock at June 30, 2011.
Note 16 — Supplemental Oil and Natural Gas Disclosures (Unaudited), page F-40
Oil and Natural Gas Reserves, page F-42
| 56. | Please expand your table to include the net quantities of your proved developed reserves as of the beginning and the end of the year as required by ASC 932-235-50-4. Refer also to Example 1 in ASC 932-235-55-2. |
Mr. H. Roger Schwall
November 14, 2011
Page 36
Response: In response to the Staff’s comment, the Company has expanded the referenced table on page F-43 to include the requested disclosure. The expanded table is presented below:
| Net Proved Reserves | ||||||||||||
| Oil | Gas | Gas Equivalent |
||||||||||
| (Mbbl) | (MMcf) | (MMcfe) | ||||||||||
| Proved Developed and Proved Undeveloped Reserves |
||||||||||||
| Total at December 31, 2007 |
136 | 33,280 | 34,098 | |||||||||
| Revisions of prior estimates |
12 | (17,492 | ) | (17,426 | ) | |||||||
| Extensions and discoveries |
20 | 6,493 | 6,614 | |||||||||
| Production |
(37 | ) | (3,085 | ) | (3,307 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Total at December 31, 2008 |
131 | 19,196 | 19,979 | |||||||||
| Revisions of prior estimates |
(13 | ) | (811 | ) | (883 | ) | ||||||
| Extensions and discoveries |
15 | 50,367 | 50,454 | |||||||||
| Production |
(30 | ) | (4,823 | ) | (5,002 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Total at December 31, 2009 |
103 | 63,929 | 64,548 | |||||||||
| Revisions of prior estimates |
66 | 874 | 1,265 | |||||||||
| Extensions and discoveries |
16 | 71,009 | 71,107 | |||||||||
| Production |
(33 | ) | (8,400 | ) | (8,597 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Total at December 31, 2010 |
152 | 127,412 | 128,323 | |||||||||
| Proved Developed Reserves |
||||||||||||
| December 31, 2007 |
129 | 14,271 | 15,042 | |||||||||
| December 31, 2008 |
131 | 19,196 | 19,979 | |||||||||
| December 31, 2009 |
103 | 25,369 | 25,988 | |||||||||
| December 31, 2010 |
152 | 43,143 | 44,054 | |||||||||
| Proved Undeveloped Reserves |
||||||||||||
| December 31, 2007 |
7 | 19,009 | 19,056 | |||||||||
| December 31, 2008 |
— | — | — | |||||||||
| December 31, 2009 |
— | 38,560 | 38,560 | |||||||||
| December 31, 2010 |
— | 84,269 | 84,269 | |||||||||
Mr. H. Roger Schwall
November 14, 2011
Page 37
Condensed Consolidated Financial Statements, page F-48
| 57. | Please update your financial statements to comply with Rule 3-12 of Regulation S-X and provide corresponding updated disclosures throughout your filing. |
Response: The Company acknowledges the Staff’s comment and has filed with Amendment No. 1 the financial statements required by Rule 3-12 of Regulation S-X and corresponding updated disclosure throughout Amendment No. 1.
Exhibits
General
| 58. | Please ensure that you have filed all material contracts. See Item 601(b)(10) of Regulation S-K. For example, and without limitation, please tell us whether you will file the natural gas transportation agreements that you have referenced at page 111. |
Response: The Company acknowledges the Staff’s comment and has filed with Amendment No. 1 all material contracts that are currently available. The Company undertakes to file with future amendments to the Registration Statement all other material contracts that are identified or become available. As indicated on page 112, the two natural gas transportation agreements that require the Company to deliver a specified volume of natural gas for a fixed period of time do not constitute material commitments and were entered into in the ordinary course of business. As a result, the agreements do not constitute material contracts required to be filed pursuant to Item 601(b)(10) of Regulation S-K.
Exhibit 99.1
| 59. | Please furnish a third party reserve report that includes the technical qualifications of the person primarily responsible for the report. |
Response: The Company acknowledges the Staff’s comment and has furnished as Exhibit 99.1 to Amendment No. 1 the Audit Report of Netherland, Sewell & Associates, Inc. for reserves at June 30, 2011, which audit report includes the technical qualifications of the person primarily responsible for the report. The Company notes that former Exhibit 99.1 to the Registration Statement, which was the Audit Report of Netherland, Sewell & Associates, Inc. for
Mr. H. Roger Schwall
November 14, 2011
Page 38
reserves at March 31, 2011, is no longer furnished as an exhibit to the Registration Statement because the Company’s reserves information at March 31, 2011 is no longer included in Amendment No. 1.
Enclosed herewith is a statement from the Company regarding (i) the responsibility of the Company for the adequacy and accuracy of the disclosure in the filings; (ii) the fact that the Staff’s comments or changes in disclosures in response to Staff comments do not foreclose the SEC from taking any action with respect to the filing; and (iii) the fact that the Company may not assert Staff comments as a defense in any proceeding initiated by the SEC or any person under the federal securities law of the United States.
Please let me know if the responses are acceptable. You can reach me at 214.651.5562.
Very truly yours,
/s/ Janice V. Sharry
Janice V. Sharry
Direct Phone Number: 214.651.5562
Direct Fax Number: 214.200.7065
Janice.sharry@haynesboone.com
| cc: | Joseph Wm. Foran |
David E. Lancaster
Doug Berman
Daryl Robertson