CONSOL Energy, Inc.
CNX Center
1000 CONSOL Energy Drive
Canonsburg, PA 15317-6506
April 25, 2017
Mr. John Reynolds
Assistant Director
Office of Beverages, Apparel and Mining
United States Securities and Exchange Commission
100 F Street, N.W., Mail Stop 7010
Washington, D.C. 20549
Re: CONSOL Energy Inc.
Form 10-K for the Year Ended December 31, 2016
Filed February 8, 2017
File No. 001-14901
Dear Mr. Reynolds:
Below sets forth the responses of CONSOL Energy (the "Company" or "we" or "our") to the specific comments of the staff of the U.S. Securities and Exchange Commission (the "Commission") contained in your letter dated April 13, 2017. The Company's responses set forth below correspond to the comments as numbered in the staff's letter.
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| 1. | Please expand the disclosure of your expiring acreage to provide the gross amounts of such acreage. Refer to the disclosure requirements pursuant to Item 1208(b) of Regulation S-K. |
Response: We acknowledge the Staff’s comment. We respectfully submit that this disclosure was not previously included because we determined that net acres represent the development area. We have not historically provided gross acreage given materiality considerations, but have provided net acres in this voluntary disclosure in accordance with our letter dated April 7, 2014 to the Staff. The following table represents the gross acres associated with the net expiring acres, which we are proposing to include in future filings:
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| | | | | | | | | |
| | | Gross Unproved Acres | | Net Unproved Acres | | Net Proved Undeveloped Acres |
| Held by production/fee | | 4,633,262 |
| | 3,644,799 |
| | 13,967 |
|
| Expiration within 2 years | | 106,947 |
| | 68,084 |
| | 9,347 |
|
| Expiration beyond 2 years | | 64,595 |
| | 32,650 |
| | 6,724 |
|
| Total Acreage | | 4,804,804 |
| | 3,745,533 |
| | 30,038 |
|
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| 2. | The disclosure provided as part of the discussion of the development wells drilled during 2016 indicates there were 68 gross wells that had been drilled but that remained uncompleted as of December 31, 2016. Please provide us with the net quantities of proved undeveloped reserves attributable to those wells as of December 31, 2016 which are not scheduled to be completed and the related reserves converted to developed status within five years of the initial disclosure as proved undeveloped reserves. To the extent that there are any such reserves, please tell us the specific circumstances that justify a time longer than five years. |
Response: We acknowledge the Staff’s comment. We respectfully submit that of the 68 gross Drilled Uncompleted Wells (DUCs) only 41 of those are currently booked as proved undeveloped reserves and have net reserves reported of 616,101 MMcfe. All of the 41 wells are scheduled to be converted to developed status within five years of the initial disclosure with 34 scheduled to be completed and producing by December 31, 2017.
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| 3. | We note the tabular presentations on pages 12 and 13 that set forth the net sales volumes of natural gas liquids, crude oil and condensate and the average sales price per unit of natural gas liquids, crude oil and condensate produced are provided solely as gas equivalent figures. Please refer to the disclosure requirements pursuant to Item 1204(a) and Item 1204(b)(1) of Regulation S-K and expand your disclosure to present the production figures and average sales prices for natural gas liquids, crude oil and condensate in terms of the barrels of liquids produced and sold. |
Response: We acknowledge the Staff’s comment. We respectfully submit that the production figures and average sales prices for natural gas liquids, crude oil, and condensate in barrels of liquids sold has been provided on page 54 of our Annual Report on Form 10-K, which has been reproduced in the table below. We also included on pages 12 and 13 a footnote that described the conversion ratios from Mcf to barrels so that a reader can calculate the applicable per barrel measure. In future filings, we will present the information included within the tabular presentations on page 12 and 13 on a similar basis.
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| | | | | | | | | | | | | | | |
| | | For the Years Ended December 31, |
| in thousands (unless noted) | | 2016 | | 2015 | | Variance | | Percent
Change |
| LIQUIDS | | | | | | | | |
| NGLs: | | | | | | | | |
| Sales Volume (MMcfe) | | 40,260 |
| | 33,180 |
| | 7,080 |
| | 21.3 | % |
| Sales Volume (Mbbls) | | 6,710 |
| | 5,530 |
| | 1,180 |
| | 21.3 | % |
| Gross Price ($/Bbl) | | $ | 14.52 |
| | $ | 12.30 |
| | $ | 2.22 |
| | 18.0 | % |
| Gross Revenue | | $ | 97,580 |
| | $ | 68,057 |
| | $ | 29,523 |
| | 43.4 | % |
| | | | | | | | | |
| Oil: | | | | | | | | |
| Sales Volume (MMcfe) | | 410 |
| | 592 |
| | (182 | ) | | (30.7 | )% |
| Sales Volume (Mbbls) | | 68 |
| | 99 |
| | (31 | ) | | (31.3 | )% |
| Gross Price ($/Bbl) | | $ | 36.90 |
| | $ | 47.94 |
| | $ | (11.04 | ) | | (23.0 | )% |
| Gross Revenue | | $ | 2,521 |
| | $ | 4,736 |
| | $ | (2,215 | ) | | (46.8 | )% |
| | | | | | | | | |
| Condensate: | | | | | | | | |
| Sales Volume (MMcfe) | | 4,964 |
| | 7,598 |
| | (2,634 | ) | | (34.7 | )% |
| Sales Volume (Mbbls) | | 827 |
| | 1,266 |
| | (439 | ) | | (34.7 | )% |
| Gross Price ($/Bbl) | | $ | 27.48 |
| | $ | 26.52 |
| | $ | 0.96 |
| | 3.6 | % |
| Gross Revenue | | $ | 22,748 |
| | $ | 33,586 |
| | $ | (10,838 | ) | | (32.3 | )% |
| | | | | | | | | |
| GAS | | | | | | | | |
| Sales Volume (MMcf) | | 348,753 |
| | 287,287 |
| | 61,466 |
| | 21.4 | % |
| Sales Price ($/Mcf) | | $ | 1.92 |
| | $ | 2.17 |
| | $ | (0.25 | ) | | (11.5 | )% |
| Gross Revenue | | $ | 670,823 |
| | $ | 622,080 |
| | $ | 48,743 |
| | 7.8 | % |
| | | | | | | | | |
| Hedging Impact ($/Mcf) | | $ | 0.70 |
| | $ | 0.68 |
| | $ | 0.02 |
| | 2.9 | % |
| Gain on Commodity Derivative Instruments - Cash Settlement | | $ | 245,212 |
| | $ | 196,348 |
| | $ | 48,864 |
| | 24.9 | % |
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| 4. | According to the information provided on page 52, it appears that the certain figures presented in the table on page 13, e.g. the total average sales price per Mcfe, include the effect of derivative transactions. Please expand the disclosure provided on page 13 pursuant to Item 1204(b)(1) of Regulation S-K to provide the sales prices by final product sold exclusive of the effects of derivative transactions. If your prices are defined by contractual arrangements that are specific to a property (e.g. field specific hedges), please expand your disclosure to provide an appropriate narrative explanation. |
Response: We acknowledge the Staff’s comment. We respectfully submit that the average sales price by final product sold on page 13 is presented exclusive of the impact of our hedges and the hedging impact per Mcf is disclosed separately in the table on page 13. Our pricing includes hedging activity that is managed at the field level to appropriately hedge basis risk by delivery point. Below is a table that shows the per Mcfe impact of derivative transactions. We intend to adjust our future filings to expand our disclosure in the manner set forth in the table below.
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| | | | | | | | | | | | |
| | | For the Year |
| | | Ended December 31, |
| | | 2016 | | 2015 | | 2014 |
| Average Sales Price - Gas (Mcf) | | $ | 1.92 |
| | $ | 2.17 |
| | $ | 4.02 |
|
| Gain on Commodity Derivative Instruments - Cash Settlement- Gas (Mcf) | | $ | 0.70 |
| | $ | 0.68 |
| | $ | 0.11 |
|
| Average Sales Price - NGLs (Mcfe)* | | $ | 2.42 |
| | $ | 2.05 |
| | $ | 5.95 |
|
| Average Sales Price - Oil (Mcfe)* | | $ | 6.15 |
| | $ | 7.99 |
| | $ | 14.85 |
|
| Average Sales Price - Condensate (Mcfe)* | | $ | 4.58 |
| | $ | 4.42 |
| | $ | 11.16 |
|
| | | | | | | |
| Total Average Sales Price (per Mcfe) Including Effect of Derivative Instruments | | $ | 2.63 |
| | $ | 2.81 |
| | $ | 4.37 |
|
| Total Average Sales Price (per Mcfe) Excluding Effect of Derivative Instruments | | $ | 2.01 |
| | $ | 2.22 |
| | $ | 4.27 |
|
| Average Lifting Costs Excluding Ad Valorem and Severance Taxes (per Mcfe) | | $ | 0.24 |
| | $ | 0.37 |
| | $ | 0.59 |
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| | | | | | | |
| Average Sales Price - NGLs (Bbl) | | $ | 14.52 |
| | $ | 12.30 |
| | $ | 35.70 |
|
| Average Sales Price - Oil (Bbl) | | $ | 36.90 |
| | $ | 47.94 |
| | $ | 89.10 |
|
| Average Sales Price - Condensate (Bbl) | | $ | 27.48 |
| | $ | 26.52 |
| | $ | 66.96 |
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| 5. | The condensate and crude oil and the natural gas liquids production figures presented as barrels and the natural gas production figures presented as cubic feet for the periods ending December 31, 2016 and 2015 on page 169 appear to be inconsistent with the comparable figures presented elsewhere on page 54. Please tell us and expand your disclosure to explain the reason(s) for the differences or revise your disclosure to resolve the inconsistencies in your figures. |
Response: We acknowledge the Staff’s comment. We acknowledge the differences in certain production figure components contained in the tables on pages 54 and 169 and respectfully submit that, after reviewing the qualitative and quantitative differences in the tables, we have concluded that such inconsistencies are immaterial and were due to a clerical error. The table on page 54 contains the correct information. Since the table shown on page 169 includes correct equivalent production, even though the components of the production contained certain immaterial differences as compared to the information on page 54, we propose to correct these inconsistencies in future filings. The revised table for page 169 is shown below:
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| | | | | | | | | | | | |
| | | | | | | Condensate | | Consolidated |
| | | Natural Gas | | NGLs | | & Crude Oil | | Operations |
| | | (MMcf) | | (Mbbls) | | (Mbbls) | | (MMcfe) |
| Balance December 31, 2013 (a) | | 5,585,107 |
| | 21,546 |
| | 2,806 |
| | 5,731,214 |
|
| Revisions (b) | | (46,557 | ) | | 40,363 |
| | 3,757 |
| | 218,171 |
|
| Price Changes | | 15,509 |
| | — |
| | — |
| | 15,509 |
|
| Extensions and Discoveries (c) | | 979,801 |
| | 18,459 |
| | 1,314 |
| | 1,098,436 |
|
| Production | | (216,260 | ) | | (2,578 | ) | | (664 | ) | | (235,714 | ) |
| Balance December 31, 2014 (a) | | 6,317,600 |
| | 77,790 |
| | 7,213 |
| | 6,827,616 |
|
| Revisions (d) | | 1,055,225 |
| | 45,711 |
| | 6,569 |
| | 1,368,909 |
|
| Price Changes | | (2,866,123 | ) | | (45,675 | ) | | (3,208 | ) | | (3,159,421 | ) |
| Extensions and Discoveries (e) | | 840,800 |
| | 13,916 |
| | 1,707 |
| | 934,542 |
|
| Production | | (287,287 | ) | | (5,530 | ) | | (1,365 | ) | | (328,657 | ) |
| Balance December 31, 2015 (a) | | 5,060,215 |
| | 86,212 |
| | 10,916 |
| | 5,642,989 |
|
| Revisions (f) | | 11,559 |
| | (19,078 | ) | | 510 |
| | (99,849 | ) |
| Price Changes | | (179,914 | ) | | (1,647 | ) | | (35 | ) | | (190,009 | ) |
| Extensions and Discoveries (g) | | 643,688 |
| | 10,960 |
| | 1,783 |
| | 720,146 |
|
| Production | | (348,753 | ) | | (6,710 | ) | | (895 | ) | | (394,387 | ) |
| Purchases of Reserves In-Place (h) | | 1,352,759 |
| | 13,177 |
| | 1,970 |
| | 1,443,642 |
|
| Sales of Reserves In-Place (h) | | (711,155 | ) | | (22,382 | ) | | (4,240 | ) | | (870,884 | ) |
| Balance December 31, 2016 (a) | | 5,828,399 |
| | 60,532 |
| | 10,009 |
| | 6,251,648 |
|
| | | | | | | | | |
| Proved developed reserves (i): | | | | | | | | |
| December 31, 2014 | | 2,979,906 |
| | 32,405 |
| | 4,061 |
| | 3,198,706 |
|
| December 31, 2015 | | 3,310,894 |
| | 59,196 |
| | 5,180 |
| | 3,697,152 |
|
| December 31, 2016 | | 3,478,464 |
| | 30,666 |
| | 3,474 |
| | 3,683,302 |
|
| | | | | | | | | |
| Proved undeveloped reserves: | | | | | | | | |
| December 31, 2014 | | 3,337,694 |
| | 45,385 |
| | 3,151 |
| | 3,628,910 |
|
| December 31, 2015 | | 1,749,320 |
| | 27,016 |
| | 5,736 |
| | 1,945,837 |
|
| December 31, 2016 | | 2,349,934 |
| | 29,866 |
| | 6,536 |
| | 2,568,346 |
|
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| 6. | The revisions in your previous estimates of total proved reserves presented on page 169 for the periods ending December 31, 2014, 2015 and 2016 appear to be attributable to two or more unrelated factors, for example changes in efficiencies in operations, changes in well performance, and changes in plans related to future locations. Please expand your disclosure to indicate the net amount attributable to each individual factor accompanied by a narrative explanation, so that the change in net reserves between periods is fully explained. Refer to FASB ASC 932-235-50-5. Provide comparable disclosure under “Proved Undeveloped Reserves (MMcfe)” beginning on page 170 regarding revisions in the previous estimates for the period ending December 31, 2016. See also Item 1203(b) of Regulation S-K. |
Response: We acknowledge the Staff’s comment. We respectfully submit that we believe that the downward revisions of 99.8 Bcfe in 2016 were immaterial and didn’t constitute the need for a more detailed disclosure as these revisions represented only 1.6% of our total year end reserves. Similarly, the components comprising the net change attributable to revisions were not material to our year-end reserves. In 2016 the net downward revision of 99.8 Bcfe was the result of 255 Bcfe downward revision for wells that were removed from both internal and JV partner development plans, 113 Bcfe downward revision related to economics for producing properties offset by 268 bcfe of improved analog performance. The upward revisions in 2015 of 1,369 Bcfe were due to 611 Bcfe increase in both performance and operating cost reductions for developed properties, a 1,200 Bcfe increase for undeveloped properties due to operating cost reductions and expected increases in well performance. These upward revisions in 2015 were offset by a 442 Bcfe downward revision for undeveloped properties that were removed from our operational plans due to "high-grading" and selecting our highest rate of return properties for future development. The upward revisions in 2014 of 218 Bcfe were due to 120 Bcfe increase due to efficiencies in operations and well optimization (well performance) and a 207 Bcfe increase due to the reclassification of ethane volumes from natural gas to NGLs. These upward revisions in 2014 were offset by 109 Bcfe decrease in our revisions due to changes in our development plans. In future filings, we will expand our disclosure to more fully explain the reasons for the change in net reserves, when material.
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| 7. | Footnote (i) on page 170 appears to indicate the proved developed reserves disclosed at December 31, 2016 included reserves attributed to “producing wells with negative undiscounted cash flows.” Please tell us how you considered the requirements in the definitions of economically producible, proved reserves, and reserves in Rule 4-10(a)(10), (a)(22) and (a)(26) of Regulation S-X in classifying the 199.3 Bcfe of natural gas and equivalents as proved reserves. |
Response: We acknowledge the Staff’s comment. We respectfully submit that the 199.3 Bcfe of proved developed reserves disclosed at December 31, 2016 had negative undiscounted cash flows of ($167 million) and negative discounted cash flows of ($15 million). These reserves were calculated in accordance with Rule 4-10 of Regulation S-X, taking into consideration the definitions of economically producible, proved reserves and reserves as set forth in Sections 4-10 (a)(10), (a)(22) and (a)(26) of Regulation S-X and are attributable to wells that have been and are currently producing natural gas. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Economically producible is further defined as, a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. These reserves otherwise satisfy the definition of “proved reserves,” as the producing properties have positive undiscounted cash flows with SEC pricing for future revenues and operating costs. The producing wells associated with these reserves only produced negative undiscounted cash flows due to the voluntarily inclusion of Plugging and Abandonment capital, which is our practice with respect to all of our assets. At the point where the costs of the operation exceeds the revenues expected to be generated reserves are no longer booked. In consideration of these factors, we believe that these properties continue to meet the definition of economically producible. Moreover, as these wells continue to produce, we believe that it would be inconsistent to include the production in our operating results but exclude them from the Company’s reported reserves.
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| 8. | We note disclosure on page 169 of an overall positive change in total proved reserves for the period ending December 31, 2016 relating to extensions and discoveries. However, the corresponding change in the standardized measure of future net cash flows presented on page 172 relating to extensions and discoveries appears to be a negative figure. Please refer to the disclosure requirements pursuant to FASB 932-235-50-36 and expand your disclosure to explain the reason(s) for the negative change in the standardized measure. |
Response: We acknowledge the Staff’s comment. We had 720,146 MMcfe of Extensions and Discoveries that are expected to generate positive future net revenue but generate negative present value at SEC pricing criteria discounted at 10 percent at December 31, 2016. Of the 720,146 MMcfe, 669,266 MMcfe are associated with Proved Undeveloped locations. We acknowledge the requirements of FASB ASC paragraph 932-235-50-36 and respectfully note that, in our assessment of future development plans and reserve recognition, we consider the economic development of reserves based upon future commodity pricing and differentials, our most likely estimate of future production and other economic factors that are not included in the SEC-reserve model. These other factors include items such as expected operational efficiencies and reductions in capital intensity. Consequently, we respectfully submit that while using the SEC-pricing model provides negative present worth discounted at 10 percent for these wells, they are nonetheless economic under our internal modeling. In future filings, we will expand our disclosure to more fully explain the reasons for the inclusion of these Proved Undeveloped Locations and their impact on the Company’s standardized measure of future net cash flows.
Revised future disclosure (revision components in bold): “Included in proved undeveloped reserves at December 31, 2016 are 175 gross proved undeveloped locations that generate positive future net revenue but have negative present worth discounted at 10 percent as of December 31, 2016, representing 58.9% of our total proved undeveloped reserves. Additionally, the 1,511.8 Bcfe of natural gas and equivalents attributable to these locations represent approximately 24.2% of our total proved reserves. The Company includes these well sites in its current drilling plans and currently intends to drill these sites as our economic modeling of these well locations generate positive future cash flows. The negative change in standardized measure of future cash flows in 2016 are due to the required use of SEC pricing (previous 12 month arithmetic average) which are low as compared to the general economic (i.e. published market data) and Company-specific future outlook for commodity prices, resulting in an impact of $54.6 million on the standardized measure of future net cash flows.
* * * * *
We believe these satisfy the Staff’s requests. We would welcome the opportunity to discuss the matters further with the Staff upon your receipt and review of this information.
Additionally, the Company acknowledges that (i) it is responsible for the adequacy and accuracy of the disclosure in its filings; (ii) Staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking action with respect to the filing; and (iii) it may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.
Please direct any additional questions or comments to me at (724) 485-3030
Very truly yours,
/s/ David M. Khani
David M. Khani
Executive Vice President and Chief Financial Officer
