SEC Company Response from SM Energy Co (SM) (CIK 0000893538) (SM) — Jun 16, 2006
SM Energy Co (SM) (CIK 0000893538)
Date: June 16, 2006 · CIK: 0000893538 · Accession: 0000893538-06-000142
AI Filing Summary & Sentiment
Reasoning
Referenced dates: June 2, 2006
Letter
Division of Corporation Finance United States Securities and Exchange Commission Letter dated June 2, 2006 to St. Mary Land & Exploration Company Form 10-K for the fiscal year ended December 31, 2005 Filed February 27, 2006 File No. 1-31539
Dear Mr. Schwall:
Please find our response to the above captioned comment letter dated June 2, 2006. As a courtesy, we have reproduced the applicable portion of the letter in our responses. The comments are in bold text and our responses are incorporated within the document in normal text.
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 2
1.
In response to your response number 3 please provide the technical evidence that supports the attribution of proved undeveloped reserves more than one offset location away from a producing location in your coal bed methane properties. Please include a map showing the proved undeveloped locations in question, the location of the water monitoring wells; the location of the nearest producing wells with their current gas and water production rates, and their cumulative gas and water production; the pressure changes over time in the field as determined by the water monitoring wells and any other information you deem relevant. We may have further comments.
The requested technical documentation that supports the attribution of proved undeveloped reserves more than one offset location away from a producing location in our coal bed methane properties has been supplementally submitted to Mr. James Murphy of the Staff.
2.
Regarding response number 4, included in Revisions of previous estimates should be reserves added through development drilling due to the approval of decreased spacing within a field. In the Extensions and discoveries category, only include reserves from past drilling that extend the limits of a previously proved reservoir, reserves from the discovery of new fields with proved reserves or a new reservoir in an old field. Please confirm to us that your reserves additions meet these criteria.
The point we were trying to articulate in our prior response is that the language in paragraph 11 of SFAS No. 69 distinguished between the two categories based on one important concept. This concept is that for an item to be included in the revision line it has to have been previously included in the proved reserves. We were attempting to communicate that the reserves we have classified as an Extension and discovery are new proved reserves that have been added to our proved reserve database. Definitionally, the word extension matches much more closely with the reality of how we are recording proved reserves. If we believed that the reserves qualified for a proved classification in a prior period, then in a subsequent period any change would be recorded to this Revisions line item. The fact however is that the reserves we have included in the Extension and discovery line are new reserves that have been added.
We do not believe that the FASB definition states nor implies that only reserves from development drilling are classified in the Revision line, nor do we believe that the FASB implies that only the results from exploratory drilling activities should be classified in the Extension and discovery line. Accordingly, we believe that the final classification or reserves requires the use of management judgment and we believe our presentation is accurate and does not require revision.
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 3
3.
Regarding response number 5, we are still considering your response.
We note the Staff’s comment.
4.
As to response number 6, please provide the independent petrophysical evaluation, geological mapping and decline curve analysis that you state Ryder Scott generated as part of their evaluation. Also provide the Ryder Scott reserve report and the properties and the reserves for each party where significant variances existed between the company's numbers and the third party engineer's estimate.
As discussed with Mr. James Murphy in a telephone conference on June 14, 2006, we do not require that Ryder Scott formalize their analysis in a bound report for the reserves that they prepare. Summaries of the requested technical information have been supplementally submitted to Mr. Murphy.
5.
Confirm to us that all of your proved undeveloped locations in both 2004 and 2005 complied with the existing field rules for their respective fields at the time they were booked as proved reserves.
Some well locations in both Oklahoma and Louisiana that are included as Proved Undeveloped Reserves in our 2004 and 2005 reserve reports did not have approval from the appropriate regulatory agencies for certain increased density applications or alternate well unit designations for certain of these proved undeveloped locations at the time of publishing the reserves.
We note that in making the decision as whether or not to include these well locations in our yearend reserve disclosures we considered the location of the wells, our history of development in the specific area, the history of regulatory approval in the specific area, we polled other operators in the area, we considered our ability and intent to drill the location and we considered the applicable guidance of the SEC staff. All of these considerations led us to the conclusion that these specific well locations should be included in our yearend reserves. The SEC Staff guidance we are referring to was issued on February 21, 2001, and is set forth under Item II.F.3 of the Division of Corporation Finance’s Requested Accounting and Financial Reporting Interpretations and Guidelines on the SEC’s website, as shown below:
Issue 3. d. Paragraph 4 – The history of issuance and continued recognition of permits, concessions and commerciality agreements by regulatory bodies and governments should be considered when determining whether hydrocarbon accumulations can be classified as proved reserves. Automatic renewal of such agreements cannot be expected if the regulatory body has the authority to end the agreement unless there is a long and clear track record which supports the conclusion that such approvals and renewal are a matter of course.
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 4
Based on our observed long and clear track record of receiving approval of increased density applications from the regulatory agencies described below, we believe there is only a remote possibility that these locations will not be approved and drilled by the Company, accordingly, we believe the classification of these reserves as Proved Undeveloped Reserves was appropriate in each respective reserve report. The specifics of these particular well locations are described below.
At Elm Grove Field in Louisiana, our research has indicated that 100 percent of alternate unit designations have been approved by the Louisiana Office of Conservation allowing for 40 acre drilling density. Over 200 alternate well unit applications were obtained in 2005 by the operators of our Elm Grove Field leases with no denied applications. We have consulted specialists who focus on alternate well unit applications in Louisiana, who have confirmed 100% approval of over 300 applications per year since 1985 in various fields in Louisiana. We have operated in Louisiana since 1992 and 100 percent of our applications for alternate well unit designations have been approved by the Louisiana Office of Conservation. Given this long and clear track record of approvals in the area we are drilling as well as our observed history of obtaining these approvals, we concluded that the classification of our PUD reserves at Elm Grove Field and other Louisiana fields on well locations that are adjacent to productive wells is appropriate. Although our ownership in Elm Grove Field dates back only to December 2004 when we acquired our interests in the field, our experience to date has been consistent and we have no reason to believe it will not continue.
Similarly, our evaluation of increased density applications with the Oklahoma Corporation Commission has yielded similar approval history. Specifically, from 1998 through 2003, our research concluded that 97% of the increased density applications in Beckham (NE Mayfield) and Coal (Centrahoma) Counties were approved. Since 2003, 100% of St. Mary’s increased density applications have been approved. The PUD well locations for these areas are adjacent to productive wells in the associated field. As a company, we have had operations in Oklahoma for over 15 years and our Mid-Continent region has been the most active drilling region of our Company. As such, our experience with these regulatory matters is extensive. With our expertise, history and the realized results of the regulatory approval process, we have concluded that the classification of the reserves associated with these well locations as Proved Undeveloped is appropriate.
6.
Regarding response number 8 please provide the fields, the quantity of net proved reserves you attributed to each field and under which criteria in the FASB 69 reserve reconciliation table you attributed the reserves to down spacing of drilling locations that had not yet been approved in each of the years 2004 and 2005. We may have further comments.
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 5
This comment response should be read in conjunction with response number 2 and response number 5. The table below has been supplementally provided to the Staff in response to the comment. The table presents a summary of the reserves as well as the PV-10 value included in each year that were subject to down spacing approval. As described in response number 2 and response number 5, we believe that the inclusion of these reserves in each year’s reserve disclosures is appropriate and we believe that the classification as an Extension and discovery is also appropriate.
Reserve added and the associated PV-10 are as follow ($’s in millions):
BCFE
PV-10
BCFE
PV-10
Centrahoma Field, OK
0.9
$ 0.6
20.3
$31.8
NE Mayfield Field, OK
2.9
3.4
0.9
0.3
Middleburg Field, OK
1.1
1.4
-
-
Elm Grove Field, LA
-
-
25.6
39.5
Spider Field, LA
-
-
3.9
14.3
Field Totals
4.8
$ 5.3
50.6
$85.8
Percent of St. Mary Totals
0.7%
0.4%
6.4%
3.4%
7.
We note that in the last three years you have averaged $47 million per year in exploration costs and $184 million per year in development costs. We also note that in the reserve report for 2005 you identify a total of $171 million in development costs. However, in your 10-K you indicate that your 2006 drilling budget has been increased to $500 million. This suggests that about two-thirds of the 2006 drilling budget will be for more risky drilling in unproved areas. Please advise or revise your document to include this information.
The magnitudes of the numbers you point out have not been much different for St. Mary from year to year. The following table reflects the initial total proved capital development costs for the ensuing year and the initial capital budget for the corresponding year. The derived percentage is recalculated.
Undiscounted capital per the reserve report (millions)
$
$ 171
Capital budget for the related year (millions)
$ 293
$ 500
Derived percentage
25.9%
34.2%
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 6
Our capital budgeting process includes anticipated capital spending that includes Proved Developed Non Producing, Proved Undeveloped, Probable and Possible reserves. Often times in the period between reporting yearend reserves we will develop a Proved Undeveloped location that will allow us to move Probable or Possible locations into the Proved category during the year. Our budget process has historically included the capital costs associated with these Probable and Possible locations. Our capital budget process also contemplates forecasts of costs that we expect to be paying based on industry trends of service, equipment, chemical and personnel costs over the ensuing period, rather than being based solely on the costs in effect as of yearend, as reflected in the reserve case published in the Form 10-K.
As a Company, our business has been predominately related to development activity and in our budgeting activity we contemplate the success we expect to achieve in our drilling results and may include activities in our budget that are more than one offset location away, as mentioned earlier. Our success ratio from drilling has been 93.5 percent, 88.2 percent, and 82.5 percent in 2005, 2004 and 2003, respectively. Through the first quarter of 2006, our success ratio has been 89.9 percent, including recompletions and 98 percent on conventional wells, excluding recompletions.
We believe that this information supports that our risk profile is consistent with our disclosures that “we have assembled a balanced program of low-to-medium-risk development and exploitation projects that provide the foundation for steady growth”
As such, we do not believe that supplemental disclosure is necessary. In the event that St. Mary does change its focus to higher risk projects that would generally be characterized more as wildcat exploration, we will appropriately include disclosure in our filings at such time.
8.
Tell us if all of the proved undeveloped wells in your 2004 and 2005 reserve reports met your internal corporate investment hurdle rates or criteria for each of those years.
Supplementally, we confirm to the Staff that all of the proved undeveloped wells in our 2004 and 2005 reserve reports meet or exceed our internal investment hurdle rates and we intend to invest to develop these reserves.
The Proved Undeveloped reserves in the 2004 and 2005 reserve reports are economic based on the cash flow models and produce a positive return on investment.
9.
Reconcile for us the fact that you have attributed 50 MMCF of proved producing reserves to the Fontana 1-27 well in Pittsburg County, OK but for the 12 proved undeveloped wells in Pittsburg County you have attributed anywhere from six to ten times the amount of proved reserves per well. Tell us the cumulative production from the Fontana 1-27 from the coal bed completion as of December 31, 2005.
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 7
In response to Comments #9 and #10, please note that St. Mary owns an interest in numerous wells in Pittsburg County, OK and that the Fontana 1-27 well is not used in the justification of our CBM PUD reserves, as it is in a different field and produces from a conventional reservoir, the Wapanucka formation. We realize that confusion has been created by utilizing the field na
Show Raw Text
CORRESP
1
filename1.htm
June 16, 2006
By EDGAR and by fax (202) 772-9369
Mr. H. Roger Schwall
Assistant Director
Division of Corporation Finance
United States Securities and Exchange Commission
100 F Street, N.E.
Washington, D.C.
20549-7010
Re:
Letter dated June 2, 2006 to St. Mary Land & Exploration Company
Form 10-K for the fiscal year ended December 31, 2005
Filed February 27, 2006
File No. 1-31539
Dear Mr. Schwall:
Please find our response to the above captioned comment letter dated June 2, 2006. As a courtesy, we have reproduced the applicable portion of the letter in our responses. The comments are in bold text and our responses are incorporated within the document in normal text.
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 2
1.
In response to your response number 3 please provide the technical evidence that supports the attribution of proved undeveloped reserves more than one offset location away from a producing location in your coal bed methane properties. Please include a map showing the proved undeveloped locations in question, the location of the water monitoring wells; the location of the nearest producing wells with their current gas and water production rates, and their cumulative gas and water production; the pressure changes over time in the field as determined by the water monitoring wells and any other information you deem relevant. We may have further comments.
The requested technical documentation that supports the attribution of proved undeveloped reserves more than one offset location away from a producing location in our coal bed methane properties has been supplementally submitted to Mr. James Murphy of the Staff.
2.
Regarding response number 4, included in Revisions of previous estimates should be reserves added through development drilling due to the approval of decreased spacing within a field. In the Extensions and discoveries category, only include reserves from past drilling that extend the limits of a previously proved reservoir, reserves from the discovery of new fields with proved reserves or a new reservoir in an old field. Please confirm to us that your reserves additions meet these criteria.
The point we were trying to articulate in our prior response is that the language in paragraph 11 of SFAS No. 69 distinguished between the two categories based on one important concept. This concept is that for an item to be included in the revision line it has to have been previously included in the proved reserves. We were attempting to communicate that the reserves we have classified as an Extension and discovery are new proved reserves that have been added to our proved reserve database. Definitionally, the word extension matches much more closely with the reality of how we are recording proved reserves. If we believed that the reserves qualified for a proved classification in a prior period, then in a subsequent period any change would be recorded to this Revisions line item. The fact however is that the reserves we have included in the Extension and discovery line are new reserves that have been added.
We do not believe that the FASB definition states nor implies that only reserves from development drilling are classified in the Revision line, nor do we believe that the FASB implies that only the results from exploratory drilling activities should be classified in the Extension and discovery line. Accordingly, we believe that the final classification or reserves requires the use of management judgment and we believe our presentation is accurate and does not require revision.
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 3
3.
Regarding response number 5, we are still considering your response.
We note the Staff’s comment.
4.
As to response number 6, please provide the independent petrophysical evaluation, geological mapping and decline curve analysis that you state Ryder Scott generated as part of their evaluation. Also provide the Ryder Scott reserve report and the properties and the reserves for each party where significant variances existed between the company's numbers and the third party engineer's estimate.
As discussed with Mr. James Murphy in a telephone conference on June 14, 2006, we do not require that Ryder Scott formalize their analysis in a bound report for the reserves that they prepare. Summaries of the requested technical information have been supplementally submitted to Mr. Murphy.
5.
Confirm to us that all of your proved undeveloped locations in both 2004 and 2005 complied with the existing field rules for their respective fields at the time they were booked as proved reserves.
Some well locations in both Oklahoma and Louisiana that are included as Proved Undeveloped Reserves in our 2004 and 2005 reserve reports did not have approval from the appropriate regulatory agencies for certain increased density applications or alternate well unit designations for certain of these proved undeveloped locations at the time of publishing the reserves.
We note that in making the decision as whether or not to include these well locations in our yearend reserve disclosures we considered the location of the wells, our history of development in the specific area, the history of regulatory approval in the specific area, we polled other operators in the area, we considered our ability and intent to drill the location and we considered the applicable guidance of the SEC staff. All of these considerations led us to the conclusion that these specific well locations should be included in our yearend reserves. The SEC Staff guidance we are referring to was issued on February 21, 2001, and is set forth under Item II.F.3 of the Division of Corporation Finance’s Requested Accounting and Financial Reporting Interpretations and Guidelines on the SEC’s website, as shown below:
Issue 3. d. Paragraph 4 – The history of issuance and continued recognition of permits, concessions and commerciality agreements by regulatory bodies and governments should be considered when determining whether hydrocarbon accumulations can be classified as proved reserves. Automatic renewal of such agreements cannot be expected if the regulatory body has the authority to end the agreement unless there is a long and clear track record which supports the conclusion that such approvals and renewal are a matter of course.
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 4
Based on our observed long and clear track record of receiving approval of increased density applications from the regulatory agencies described below, we believe there is only a remote possibility that these locations will not be approved and drilled by the Company, accordingly, we believe the classification of these reserves as Proved Undeveloped Reserves was appropriate in each respective reserve report. The specifics of these particular well locations are described below.
At Elm Grove Field in Louisiana, our research has indicated that 100 percent of alternate unit designations have been approved by the Louisiana Office of Conservation allowing for 40 acre drilling density. Over 200 alternate well unit applications were obtained in 2005 by the operators of our Elm Grove Field leases with no denied applications. We have consulted specialists who focus on alternate well unit applications in Louisiana, who have confirmed 100% approval of over 300 applications per year since 1985 in various fields in Louisiana. We have operated in Louisiana since 1992 and 100 percent of our applications for alternate well unit designations have been approved by the Louisiana Office of Conservation. Given this long and clear track record of approvals in the area we are drilling as well as our observed history of obtaining these approvals, we concluded that the classification of our PUD
reserves at Elm Grove Field and other Louisiana fields on well locations that are adjacent to productive wells is appropriate. Although our ownership in Elm Grove Field dates back only to December 2004 when we acquired our interests in the field, our experience to date has been consistent and we have no reason to believe it will not continue.
Similarly, our evaluation of increased density applications with the Oklahoma Corporation Commission has yielded similar approval history. Specifically, from 1998 through 2003, our research concluded that 97% of the increased density applications in Beckham (NE Mayfield) and Coal (Centrahoma) Counties were approved. Since 2003, 100% of St. Mary’s increased density applications have been approved. The PUD well locations for these areas are adjacent to productive wells in the associated field. As a company, we have had operations in Oklahoma for over 15 years and our Mid-Continent region has been the most active drilling region of our Company. As such, our experience with these regulatory matters is extensive. With our expertise, history and the realized results of the regulatory approval process, we have concluded that the classification of the reserves associated with these well locations as
Proved Undeveloped is appropriate.
6.
Regarding response number 8 please provide the fields, the quantity of net proved reserves you attributed to each field and under which criteria in the FASB 69 reserve reconciliation table you attributed the reserves to down spacing of drilling locations that had not yet been approved in each of the years 2004 and 2005. We may have further comments.
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 5
This comment response should be read in conjunction with response number 2 and response number 5. The table below has been supplementally provided to the Staff in response to the comment. The table presents a summary of the reserves as well as the PV-10 value included in each year that were subject to down spacing approval. As described in response number 2 and response number 5, we believe that the inclusion of these reserves in each year’s reserve disclosures is appropriate and we believe that the classification as an Extension and discovery is also appropriate.
Reserve added and the associated PV-10 are as follow ($’s in millions):
2004
2005
BCFE
PV-10
BCFE
PV-10
Centrahoma Field, OK
0.9
$ 0.6
20.3
$31.8
NE Mayfield Field, OK
2.9
3.4
0.9
0.3
Middleburg Field, OK
1.1
1.4
-
-
Elm Grove Field, LA
-
-
25.6
39.5
Spider Field, LA
-
-
3.9
14.3
Field Totals
4.8
$ 5.3
50.6
$85.8
Percent of St. Mary Totals
0.7%
0.4%
6.4%
3.4%
7.
We note that in the last three years you have averaged $47 million per year in exploration costs and $184 million per year in development costs. We also note that in the reserve report for 2005 you identify a total of $171 million in development costs. However, in your 10-K you indicate that your 2006 drilling budget has been increased to $500 million. This suggests that about two-thirds of the 2006 drilling budget will be for more risky drilling in unproved areas. Please advise or revise your document to include this information.
The magnitudes of the numbers you point out have not been much different for St. Mary from year to year. The following table reflects the initial total proved capital development costs for the ensuing year and the initial capital budget for the corresponding year. The derived percentage is recalculated.
2004
2005
Undiscounted capital per the reserve report (millions)
$
76
$ 171
Capital budget for the related year (millions)
$ 293
$ 500
Derived percentage
25.9%
34.2%
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 6
Our capital budgeting process includes anticipated capital spending that includes Proved Developed Non Producing, Proved Undeveloped, Probable and Possible reserves. Often times in the period between reporting yearend reserves we will develop a Proved Undeveloped location that will allow us to move Probable or Possible locations into the Proved category during the year. Our budget process has historically included the capital costs associated with these Probable and Possible locations. Our capital budget process also contemplates forecasts of costs that we expect to be paying based on industry trends of service, equipment, chemical and personnel costs over the ensuing period, rather than being based solely on the costs in effect as of yearend, as reflected in the reserve case published in the Form 10-K.
As a Company, our business has been predominately related to development activity and in our budgeting activity we contemplate the success we expect to achieve in our drilling results and may include activities in our budget that are more than one offset location away, as mentioned earlier. Our success ratio from drilling has been 93.5 percent, 88.2 percent, and 82.5 percent in 2005, 2004 and 2003, respectively. Through the first quarter of 2006, our success ratio has been 89.9 percent, including recompletions and 98 percent on conventional wells, excluding recompletions.
We believe that this information supports that our risk profile is consistent with our disclosures that “we have assembled a balanced program of low-to-medium-risk development and exploitation projects that provide the foundation for steady growth”
As such, we do not believe that supplemental disclosure is necessary. In the event that St. Mary does change its focus to higher risk projects that would generally be characterized more as wildcat exploration, we will appropriately include disclosure in our filings at such time.
8.
Tell us if all of the proved undeveloped wells in your 2004 and 2005 reserve reports met your internal corporate investment hurdle rates or criteria for each of those years.
Supplementally, we confirm to the Staff that all of the proved undeveloped wells in our 2004 and 2005 reserve reports meet or exceed our internal investment hurdle rates and we intend to invest to develop these reserves.
The Proved Undeveloped reserves in the 2004 and 2005 reserve reports are economic based on the cash flow models and produce a positive return on investment.
9.
Reconcile for us the fact that you have attributed 50 MMCF of proved producing reserves to the Fontana 1-27 well in Pittsburg County, OK but for the 12 proved undeveloped wells in Pittsburg County you have attributed anywhere from six to ten times the amount of proved reserves per well. Tell us the cumulative production from the Fontana 1-27 from the coal bed completion as of December 31, 2005.
Mr. Roger Schwall
Securities and Exchange Commission
June 16, 2006
Page 7
In response to Comments #9 and #10, please note that St. Mary owns an interest in numerous wells in Pittsburg County, OK and that the Fontana 1-27 well is not used in the justification of our CBM PUD reserves, as it is in a different field and produces from a conventional reservoir, the Wapanucka formation. We realize that confusion has been created by utilizing the field na