August 2, 2016
Loan Lauren P. Nguyen
Legal Branch Chief
Division of Corporation Finance
Office of Natural Resources
United States Securities and Exchange Commission
100 F. Street, N.E.
Washington, D.C. 20549
Re: SM Energy Company
Form 10-K for the Fiscal Year Ended December 31, 2015
Filed February 24, 2016
Form 8-K filed February 24, 2016
File No. 01-31539
Dear Ms. Nguyen:
Set forth below are the responses of SM Energy Company, a Delaware corporation (the “Company,” “we,” “us” or “our”), to comments received from the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) by letter dated July 19, 2016, with respect to the review of the Company’s Form 10-K for the fiscal year ended December 31, 2015 (File No. 01-31539) filed with the Commission on February 24, 2016 (the “2015 Form 10-K”) and the Form 8-K filed with the Commission on February 24, 2016 (the “Form 8-K”). For your convenience, each response is prefaced by the exact text of the Staff’s corresponding comment in bold text.
* * * * * *
Form 10-K for the Fiscal Year Ended December 31, 2015
Reserves, page 8
Proved Undeveloped Reserves, page 10
1. We note that drilled but uncompleted wells represented approximately 26% of total proved undeveloped reserves at December 31, 2015. Please revise to provide additional detail regarding the planned timing and the
expected capital expenditures necessary to complete these wells. In addition, if any of these wells are located on acreage scheduled to expire during the next three fiscal years, describe your plans to retain this acreage if the wells will not be completed prior to lease expiration.
Response: The Company provided this supplemental detail to increase the effectiveness of the disclosure regarding the proved undeveloped reserve volumes in progress of being converted to proved developed producing reserves at December 31, 2015. As these reserves are a subset of the Company’s total proved undeveloped reserves, the expected capital expenditures to develop these drilled but uncompleted proved undeveloped reserves are included in the total estimated future development costs relating to total proved undeveloped reserves on page 11 of the 2015 Form 10-K. Except as otherwise specifically disclosed on page 10 of the 2015 Form 10-K, all proved undeveloped reserves, including those associated with drilled but uncompleted wells, are scheduled to be developed within five years from initial booking in accordance with Rule 4-10(a)(31)(ii). None of the drilled but uncompleted wells are located on acreage scheduled to expire during the next three fiscal years. In future filings, when drilled but uncompleted wells represent a meaningful portion of proved undeveloped reserves, we will provide disclosure explaining that the capital expenditures associated with drilled but uncompleted wells are included in the total estimated future development costs relating to total proved undeveloped reserves and that such wells are not located on acreage that is expected to expire within three years.
Major Customers, page 16
2. We note that one individual customer accounted for 21% and 19% of your 2015 and 2014 net revenues, respectively. It appears that this customer is also your joint venture partner and you indicate that you share the risk of non-performance by this customer’s counterparty purchasers. Please revise to disclose the name and the relationship, if any, with such customer, or tell us how you concluded you are not required to do so. Refer to Item 101(c)(1)(vii) of Regulation S-K. We further note your disclosure on page 96 discussing your dependence on your key customer. In addition, please tell us what consideration you gave to filing any agreements with this customer as a material contract pursuant to Item 601(b)(10) of Regulation S-K.
Response: We confirm that the customer that accounts for 21% and 19% of the Company’s 2015 and 2014 net revenues respectively is one of the Company’s joint venture partners. We respectfully note that Item 101(c)(1)(vii) of Regulation S-K does not require the identification of a customer if the loss of that customer would not have a material adverse effect on the Company. On page 16 of the 2015 Form 10-K, we disclose “[w]e do not believe the loss of any single purchaser of our crude oil, natural gas, and NGLs would materially impact our operating results, as these are products with well-established markets and numerous purchasers are present in our operating regions.”
Because the loss of this customer would not have a material impact, we do not believe we are required to disclose the name of this customer or its counterparty purchasers under Item 101(c)(1)(vii) of Regulation S-K.
Item 601(b)(10)(ii)(B) of Regulation S-K requires disclosure of any contract entered into in the ordinary course of business upon which the registrant’s business is substantially dependent. The Company enters into contracts to market its crude oil, natural gas and NGL production in the ordinary course of its business, and for the reasons discussed above concerning the marketability of these commodities, the Company is not substantially dependent on these marketing contracts with the joint venture partner. Therefore, we do not believe that these contracts are material, and are not required to be filed.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 58
Critical Accounting Policies and Estimates, page 81
Oil and Gas Reserve Quantities, page 81
3. Disclosure showing the estimated change to your total reported reserve volumes from a 10% decrease in SEC pricing is shown on page 82 of your filing. Revise your disclosure to clarify, if true, that this hypothetical change in the commodity prices used to estimate your proved reserves is based on your expectations for future commodity prices. Otherwise, revise to provide disclosure addressing the impact of known material trends in commodity prices and quantifying the reasonably likely impact these prices will have on your reserve quantities. Refer to Item 303 of Regulation S-K and Section III.B.3. of SEC Release 33-8350.
Response: The Company acknowledges the requirement under Item 303 of Regulation S-K and Section III.B.3 of SEC Release 33-8350 to disclose any known trends or uncertainties that have had or that are reasonably expected to have a material favorable or unfavorable future impact on the Company. The disclosure on page 82 of the 2015 Form 10-K with regard to the impact a 10% decrease in SEC pricing would have on total reported reserve volumes was intended to provide disclosure of the impact commodity price volatility has on the Company’s reserve quantities and was not based on management’s expectations for future commodity prices. As the Company is not able to predict the future prices it will receive for the sale of its products, this disclosure was intended only to show the sensitivity of the Company’s reserve quantities to changes in commodity pricing. It was not meant to be predicative because management does not believe it can reasonably predict future commodity prices. In future filings, the Company will disclose that it cannot reasonably predict future commodity prices and will present
both the impact of a 10% decrease in commodity prices on total reported reserve volumes as well as the impact on the Company’s total reported reserve volumes using NYMEX strip pricing as a basis for evaluating trends as of the end of the fiscal year. The Company believes that together these analyses provide reasonable disclosure of the impact of changes in pricing on total proved reserves.
Impairment of Oil and Gas Properties, page 82
4. You recorded impairment charges of $547.3 million to your proved and unproved properties in 2015. In addition, you state the following in your Form 10-K: “If commodity prices remain at levels near those as of January 31, 2016, we would expect to incur impairments in the first quarter of 2016 of up to approximately $250 million.” Revise to provide a more robust discussion of your critical accounting policies and estimates that focuses on the assumptions and uncertainties that underlie the process through which you evaluate your properties for impairment. Your revised disclosure should qualitatively and quantitatively analyze the sensitivity of reported results to changes in your assumptions, judgments, and estimates, including the likelihood of obtaining materially different results if different assumptions are applied. Refer to section V of SEC Release No. 33-8350.
Response: As noted on page 83 of the 2015 Form 10-K under the section titled, “Critical Accounting Policies and Estimates”, the Company references the “Impairment of Proved and Unproved Properties” section in Note 1 — Summary of Significant Accounting Policies in Part II, Item 8 of the 2015 Form 10-K where the Company further discloses details of the critical accounting policies and estimates that underlie the process through which the Company evaluates properties for impairment. The Company further describes its accounting policies and estimates in Note 11 — Fair Value Measurements. While the Company believes all required disclosure of the Company’s critical accounting policies underlying its impairment analysis are included in the 2015 Form 10-K, the Company acknowledges the Staff’s comment and will consolidate disclosure from the three sections noted, to the section titled, “Critical Accounting Policies and Estimates” in future filings.
Prior to filing the 2015 Form 10-K, the Company performed an analysis using its disclosed assumptions, judgments, and estimates underlying the impairment calculation, as outlined in the 10-K sections noted above. The Company identified pricing as the assumption with the highest risk. Based on its additional impairment analysis as of January 31, 2016, the Company provided disclosure that it “would expect to incur impairments in the first quarter of 2016 of up to approximately $250 million” if prices remained at levels near those as of January 31, 2016. During the first quarter of 2016, as a result of commodity prices remaining at lower levels than at December 31, 2015, and declining further after
January 31, 2016, the Company recorded impairment of proved properties expense of $269.8 million. The Company believes that its risk-based approach for evaluating the assumptions, judgments, and estimates resulted in adequate disclosure. The Company proposes providing in future filings supplemental disclosure with regard to changes or the risk of changes to the assumptions and the related impact of a change on its future reported results. The proposed additional disclosure of the analysis outlined under comment number three above will be expanded in future filings to include the impact on the Company’s property and equipment balance as of the end of the applicable reporting period.
Supplemental Oil & Gas Information, page 137
Standardized Measure of Discounted Future Net Cash Flows, page 139
5. Future development costs used to calculate the standardized measure of discounted future net cash flows totaled $2.0 billion as of December 31, 2015 compared to $3.3 billion as of December 31, 2014. Provide us with an explanation for this change considering both recent changes in proved undeveloped reserves and development costs actually incurred during 2015.
Response: The Company confirms that undiscounted future development cost estimates for all proved reserve categories decreased approximately 39% from $3.3 billion at December 31, 2014, to $2.0 billion at December 31, 2015. As page 11 of the 2015 Form 10-K illustrates, proved undeveloped reserves over the same timeframe decreased 13% from 260.9 MMBOE at December 31, 2014, to 226.8 MMBOE at December 31, 2015. As the Company disclosed on page 32 of its 2014 Form 10-K and page 33 of its 2015 Form 10-K, estimated future development costs associated with proved undeveloped reserves were $3.1 billion as of December 31, 2014, and $1.9 billion as of December 31, 2015. Using the estimates disclosed in our 2014 and 2015 Form 10-K filings, future development costs per BOE of proved undeveloped reserves were approximately $11.99/BOE at December 31, 2014 and approximately $8.19/BOE at December 31, 2015, a 31% decrease year-over-year.
The primary drivers behind this reduction in estimated future development costs per BOE of proved undeveloped reserves are discussed in Significant Developments in 2015 on page 4 of the Company’s 2015 Form 10-K, which states, “We had strong reserve additions as a result of our success in reducing costs, optimizing completions, and generating better well results in our core development programs…” The Company also states the following on page 11 of its 2015 Form 10-K in the footnote section to the table reconciling beginning and ending year proved undeveloped reserves:
“(2) We added 98.6 MMBOE of infill proved undeveloped reserves primarily in our Eagle Ford shale and Bakken/Three Forks resource plays, as well as an
additional 21.0 MMBOE of proved undeveloped reserves through extensions and discoveries, primarily in our Eagle Ford shale play.”
“(3) Proved undeveloped reserves were reduced by 79.4 MMBOE due to changes in our development plan, which caused these locations to be reclassified primarily to the probable reserves category due to the five-year rule. These locations were replaced by higher quality proved undeveloped reserves, which are classified as extensions or infills in the table above, and resulted from our testing and delineation programs implemented during 2015.”
The Company removed proved undeveloped reserves with future development costs based on estimates from year-end 2014 from the calculation of standardized measure of discounted future net cash flows and added new proved undeveloped reserves based on much lower year-end 2015 cost estimates. The 31% reduction in future development cost estimates per BOE for undeveloped reserves is supported by the actual cost reductions the Company realized from year-end 2014 to year-end 2015 and is discussed in more detail below.
Below is a reconciliation highlighting the changes in future development costs for proved undeveloped reserves compared to the overall change in proved undeveloped reserves from year-end 2014 to year-end 2015:
Reconciliation of Changes in Proved Undeveloped Reserves and Future Development Costs from 2014 to 2015
|
| Proved Undeveloped |
| Undiscounted Future |
| |
|
| (MMBOE) |
| (in millions) |
| |
Beginning of year |
| 260.9 |
| $ | 3,127.94 |
|
Revisions of previous estimates - Price |
| -57.0 |
| (500.11 | ) | |
Revisions of previous estimates - Performance |
| 21.6 |
| — |
| |
Additions from discoveries, extensions and infills |
| 119.6 |
| 903.48 |
| |
Sales of reserves |
| -4.3 |
| (30.93 | ) | |
Purchase of minerals in place |
| 0.9 |
| 13.97 |
| |
Removed for five year rule |
| -79.4 |
| (982.90 | ) | |
Conversions to proved developed |
| -35.5 |
| (314.50 | ) | |
Costs Incurred on DUCs during 2015 |
| — |
| (127.03 | ) | |
Reduction in future cost estimates (1) |
| — |
| (225.23 | ) | |
Misc. adjustments not included in the above categories |
| — |
| (8.24 | ) | |
End of year |
| 226.8 |
| $ | 1,856.43 |
|
(1) Reduction in estimated future costs for proved undeveloped reserves that did not change categories from year-end 2014 to year-end 2015 (excluding DUCs).
The Company saw drill and complete (D&C) costs decrease significantly throughout 2015. Specifically for those areas in which the Company was most active during 2015, the Company saw actual costs for D&C costs in its operated Eagle Ford play decrease from approximately $1,235 per lateral foot for wells completed in 2014, to approximately
$1,019 per lateral foot for wells completed in 2015, a 17% reduction year-over-year. For wells the Company completed in Q4 2015, average costs per lateral foot were $723, which is a 42% decrease from the $1,249 average for wells that completed in Q4 2014. D&C costs in the Company’s operated Bakken and Three Forks play decreased from approximately $750 per lateral foot for wells completed in 2014 to approximately $655 per lateral foot for wells completed in 2015, a 14% reduction year-over-year. For wells the Company completed in Q4 2015, average costs per lateral foot were $554, which is a 17% decrease from the $671 average for wells that completed in Q4 2014. Additionally, as required by FASB ASC 932-235-50-31 paragraph (b), the Company calculates its standardized measure of discounted future net cash flows using estimates based on year-end costs.
6. Please revise to provide disclosure explaining why future income taxes used to calculate the standardized measure of discounted future net cash flows as of December 31, 2015 are $0. Refer to FASB ASC 932-235-50-31 and 36. Also, tell us why PV-10, which is reconciled to the standardized measure of discounted future net cash flows on page 10 of your Form 10-K, is not equal to the standardized measure of discounted future net cash flows as of December 31, 2015 considering that future income taxes are $0.
Response: The Company refers to FASB ASC 932-235-50-31 paragraph (c), and notes compliance with the requirements by giving effect to tax basis, future tax deductions, and available tax credits. As of December 31, 2015, the Company generated its future income tax estimate at then current reserve pricing levels and under authoritative tax legislation then in effect. This evaluation resulted in $0 of income tax for the life of the reserves included in its standardized measure of discounted future net cash flows as of December 31, 2015. Given the interaction between declining price and future income taxes payable included in the standardized measure of discounted future net cash flows, the Company does not believe the original presentation to be misleading for this item; however, the Company would propose to add the following disclosure in future filings:
“Regarding the calculation for December 31, 2015, after evaluating all factors and giving effect to tax basis, future tax deductions, and available tax credits, the Company determined that at price levels for that period it would not be subject to Federal or State income tax for the projected life of the reserves under authoritative tax legislation as of December 31, 2015.”
Further, as noted in the Staff’s comment regarding page 10 of the 2015 Form 10-K, the pre-tax PV-10 of total proved reserves does not equal the standardized measure of discounted future net cash flows as of December 31, 2015, even though future income taxes are $0. Upon further investigation, the Company determined it inadvertently reported an incorrect amount for the decrease in discounted income taxes from December
31, 2014 to December 31, 2015, resulting in an approximate net $78.4 million effect to the Company’s standardized measure of discounted future net cash flows. This amount represents approximately 4% of the total for that disclosure. In consideration that the amount is not material to the standardized measure of discounted future net cash flows disclosure, the Company proposes revising its 2015 disclosure in future filings. Below are the proposed revised versions of the related tables from page 10 and page 140 of the 2015 Form 10-K, respectively:
Reconciliation of the Standardized Measure of Discounted Future Net Cash Flows to PV-10, page 10
|
| For the Year Ended December 31, |
| ||||
|
| 2015 |
| 2015 |
| ||
|
| (in millions) |
| ||||
|
| (as reported) |
| (as adjusted) |
| ||
Standardized measure of discounted future net cash flows |
| $ | 1,868.9 |
| $ | 1,790.5 |
|
Add: 10 percent annual discount, net of income taxes |
| 1,228.7 |
| 1,307.1 |
| ||
Add: future undiscounted income taxes |
| — |
| — |
| ||
Undiscounted future net cash flows |
| 3,097.6 |
| 3,097.6 |
| ||
Less: 10 percent annual discount without tax effect |
| (1,307.1 | ) | (1,307.1 | ) | ||
PV-10 |
| $ | 1,790.5 |
| $ | 1,790.5 |
|
Standardized Measure of Discounted Future Net Cash Flows, page 140
|
| For the Year Ended December 31, |
| ||||
|
| 2015 |
| 2015 |
| ||
|
| (in thousands) |
| ||||
|
| (as reported) |
| (as adjusted) |
| ||
Future cash inflows |
| $ | 11,337,865 |
| $ | 11,337,865 |
|
Future production costs |
| (6,234,687 | ) | (6,234,687 | ) | ||
Future development costs |
| (2,005,599 | ) | (2,005,599 | ) | ||
Future income taxes |
| — |
| — |
| ||
Future net cash flows |
| 3,097,579 |
| 3,097,579 |
| ||
10 percent annual discount |
| (1,228,671 | ) | (1,307,053 | ) | ||
Standardized measure of discounted future net cash flows |
| $ | 1,868,908 |
| $ | 1,790,526 |
|
|
| For the Year Ended December 31, |
| ||||
|
| 2015 |
| 2015 |
| ||
|
| (in thousands) |
| ||||
|
| (as reported) |
| (as adjusted) |
| ||
Standardized measure, beginning of year |
| $ | 5,698,783 |
| $ | 5,698,783 |
|
Sales of oil, gas, and NGLs produced, net of production costs |
| (776,272 | ) | (776,272 | ) | ||
Net changes in prices and production costs |
| (4,709,908 | ) | (4,709,908 | ) | ||
Extensions, discoveries and other including infill reserves in an existing proved field, net of related costs |
| 386,069 |
| 386,069 |
| ||
Sales of reserves in place |
| (262,210 | ) | (262,210 | ) | ||
Purchase of reserves in place |
| 4,686 |
| 4,686 |
| ||
Previously estimated development costs incurred during the period |
| 449,738 |
| 449,738 |
| ||
Changes in estimated future development costs |
| 191,447 |
| 191,447 |
| ||
Revisions of previous quantity estimates |
| (1,819,639 | ) | (1,819,639 | ) | ||
Accretion of discount |
| 761,746 |
| 761,746 |
| ||
Net change in income taxes |
| 1,863,868 |
| 1,918,670 |
| ||
Changes in timing and other |
| 80,600 |
| (52,584 | ) | ||
Standardized measure, end of year |
| $ | 1,868,908 |
| $ | 1,790,526 |
|
Form 8-K filed February 24, 2016
7. We note your presentation of “production replacement,” a metric defined as reserve additions and performance revisions divided by 2015 total production. Address the following regarding the presentation of this metric:
· Tell us why you believe this metric is useful to investors and the reasons you began disclosing it;
· Describe how showing “production replacement” for 2015 of 324% is a relevant data point considering that your proved reserves decreased by 10%, primarily due to 149 MMBoe net negative revisions of previous estimates; and
· Explain why this metric does not reflect management’s decision to defer the development of certain proved undeveloped reserves in favor of reserve additions from “recent pilots and testing programs.”
In addition, we note your statement that this metric exceeded 250% in each of the last six years. Provide us with the calculations supporting this statement together with a reconciliation of beginning and ending proved reserves for each of the six years.
Response: The valuation of a company in our industry is generally based upon several important components. A company’s proved reserve base and its ability to maintain and grow proved reserves in spite of depletion are both important valuation components. Investors and research analysts often analyze complementary metrics such as average finding and development costs, the ratio of proved reserves to production and reserve replacement ratios, when evaluating proved reserves and the ability to maintain and grow proved reserves, because these metrics provide additional insight and detail concerning this aspect of a company’s valuation.
Reserve replacement, also known as production replacement, is one such complementary measure that provides additional detail for the investor. Providing the production replacement ratio over an extended period of time demonstrates whether a company is able to consistently replace reserves in excess of annual production, which is a rational metric to evaluate the long-term sustainability of a company.
The dramatic drop in the commodity prices used to calculate reserves between year-end 2014 and year-end 2015 resulted in revisions to proved reserves based on pricing (due to proved reserves becoming uneconomic) and revisions to reserves related to “the five-year rule” (due to lower capital expenditure budgets as a result of lower expected cash flows). When these commodity price-based revisions are combined with the performance
revisions, the net result (-149 MMBoe revisions) masks useful information that the Company’s well performance was meaningfully improved, an important and material consideration in valuing the Company’s assets. We believe that investors and research analysts appreciate additional data that separates commodity price influence from performance metrics. This additional data allows these parties to better understand the Company’s individual performance independent of commodity prices, which are outside the Company’s control.
We acknowledge that while this metric intentionally did not adjust for reserve revisions due to the “five-year rule” because those revisions were the result of commodity price changes, our disclosure in the release did not clearly explain that point. In future disclosures, we will explain that the production replacement ratio does not take into account revisions due to commodity prices.
The requested six years of calculations and related proved reserve reconciliations is attached as Annex A hereto.
8. We note that you are subject to a financial covenant under your credit facility based on the non-GAAP measure “Adjusted EBITDAX.” Revise your disclosure to address the actual or reasonably likely effects of compliance or non-compliance with the covenant on your financial condition and liquidity. Refer to Question 102.09 of the Compliance and Disclosure Interpretations for Non- GAAP Financial Measures.
Response: Our credit facility provides a material source of liquidity for the Company. Under the terms of our credit agreement (as amended on April 8, 2016), if we fail to comply with the covenants that establish a maximum permitted ratio of senior secured debt to adjusted EBITDAX and a minimum permitted ratio of interest to adjusted EBITDAX, we will be in default, an event that would prevent us from borrowing under our credit facility and would therefore materially limit our sources of liquidity. In addition, if we were in default under our credit facility and unable to obtain a waiver of that default from the lenders, the lenders under that facility and under the indentures governing our outstanding Senior Notes would be entitled to exercise all of their remedies for a default. In future disclosures, we will clarify that failing to comply with this covenant would have the impacts discussed above.
9. You describe “Adjusted net income (loss)” as a non-GAAP measure that provides useful information to investors for analysis of your fundamental business on a recurring basis. However, numerous adjustments to this non-GAAP measure relate to expenses that occur in multiple periods (e.g., impairment of proved properties, abandonment and impairment of unproved properties, etc). Tell us how these types of adjustments are consistent with your definition of “Adjusted net income (loss).”
Response: SM Energy’s disclosure relating to Adjusted net income as a non-GAAP measure states, “Items excluded generally are non-recurring items or are items whose timing and/or amount cannot be reasonably estimated. These items include non-cash and other adjustments, such as . . . impairments . . . .” Impairment expense and abandonment expenses are difficult to estimate. While impairment expenses may occur in repeated quarters, particularly in a downward commodity price environment, these expenses are non-recurring in the normal course of business in a normalized commodity price environment and are generally caused by factors outside a company’s control. In addition, because they frequently relate to unpredictable changes in commodity prices, these impairment expenses cannot be reasonably estimated.
10. You have presented the non-GAAP measure “Adjusted net earnings (loss) per diluted common share” without direct reconciliation to the most directly comparable per share amount calculated in accordance with GAAP. Revise to include a reconciliation of the non-GAAP per share amounts presented in your Form 8-K. Refer to Item 10(e)(i)(B) of Regulation S-K and, for further guidance, Question 102.05 of the Compliance and Disclosure Interpretations for Non- GAAP Financial Measures.
Response: The Company acknowledges the Staff’s comment and, in future disclosures, will provide a reconciliation of adjusted net income (loss) to net income (loss), as well as a reconciliation of the number of diluted shares outstanding for adjusted net income purposes to the number of diluted shares outstanding for GAAP purposes.
11. You disclose non-GAAP measures in your earnings release headlines without also presenting the comparable GAAP measures and show non-GAAP measures that precede the most directly comparable GAAP measures in your earnings release. In addition, adjustments to arrive at non-GAAP measures are presented “net of tax.” Your presentation appears to be inconsistent with the updated Compliance and Disclosure Interpretations the Division issued on May 17, 2016. Please review this guidance when preparing your next earnings release.
Response: We have revised the presentation of these non-GAAP measures in our second quarter of 2016 earnings release.
* * * * * *
We formally acknowledge that:
· The adequacy and accuracy of the disclosure in the 2015 Form 10-K and the 8-K is the responsibility of SM Energy Company.
· Comments of the Staff or changes to disclosure in response to comments from the Staff do not foreclose the Commission from taking any action with respect to the 2015 Form10-K or the 8-K.
· SM Energy Company may not assert Staff comments and the declaration of effectiveness as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.
Please feel free to contact A. Wade Pursell, Chief Financial Officer, who can be reached at (303) 864-2555 or David W. Copeland, Executive Vice President and General Counsel, who can be reached at (303) 863-4325, if you should have any questions regarding the responses contained herein.
| Very truly yours, | |
|
| |
|
| |
| SM Energy Company | |
|
| |
| By: | /s/ A. Wade Pursell |
|
| A. Wade Pursell |
|
| Its: Chief Financial Officer |
cc: Wei Lu, Commission Staff Accountant
Ethan Horowitz, Accounting Branch Chief
Parhaum J. Hamidi, Commission Attorney-Adviser
David W. Copeland, SM Energy Company
Lucy Schlauch Stark, Holland & Hart LLP
ANNEX A
Reserve Replacement Ratio Calculation
MMBoe |
|
|
| 2015 |
| 2014 |
| 2013 |
| 2012 |
| 2011 |
| 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
| A |
| (64 | ) | (55 | ) | (48 | ) | (36 | ) | (28 | ) | (18 | ) |
Extensions, Discoveries and Infills |
| B |
| 161 |
| 144 |
| 196 |
| 150 |
| 88 |
| 64 |
|
3 Stream Conversion |
| C |
| — |
| — |
| — |
| — |
| 10 |
| — |
|
Performance Revision |
| D |
| 47 |
| 11 |
| 7 |
| (8 | ) | (4 | ) | (2 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserve Replacement Ratio |
|
|
| 324 | % | 282 | % | 419 | % | 389 | % | 332 | % | 339 | % |
The reserve replacement ratio is calculated as (Extensions, Discoveries and Infills + 3 Stream Conversion + Performance Revision)/Production. Using the row identifiers in the chart above the formula is:
Reserve Reconciliation
Please see page 137 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2012, and page 138 of the 2015 Form 10-K for the reconciliations of beginning and ending proved reserves for 2010 – 2015.