Tengasco, Inc.
11121 Kingston Pike, Suite E
Knoxville, TN 37934
865.675.1554
865.675.1621 (facsimile)
December 30, 2010
Mr. Karl Hiller, Branch Chief, Division of Corporation Finance
U.S. Securities and Exchange Commission
100 F Street, N.E.
Washington, D. C. 20549 VIA EDGAR FILING
Re: Tengasco, Inc. Form 10-K for the Year Ended December 31, 2009
File No. 1-15555
Dear Mr. Hiller:
Tengasco, Inc. hereby responds as follows to each of the six numbered items in your letter dated December 8, 2010.
We believe that disclosure needed for sound investment decisions was in fact made in our original filings of our Form 10-K for the year ending December 31, 2009. However, in order to enhance the disclosure made in our original filings, we are willing to amend our Form 10-K as set out below and as may be further suggested following your consideration of our responses and the receipt of any additional comments you may have.
For your convenience, we include the text of each of your comments underlined for reference, together with our corresponding responses, below:
Form 10-K for the Fiscal Year Ended December 31, 2009 Properties, page 31
Reserve Analyses, page 34
| 1. | We note your disclosure indicating that-your reserves estimates were prepared by LaRoche Petroleum Consultants, Ltd. (LaRoche). Please file as an exhibit to your Form 10-K the reserve report from LaRoche; including all the information required by Item 1202(a)(8) of Regulation S-K. |
OUR RESPONSE: We will add the attached report prepared by LaRoche as an exhibit – we have redacted references to probable and possible reserves as we had elected to not include this information in our original 10-K filing. In addition, the consent letter from LaRoche only references use of the proved reserve information.
| | Total Proved Reserves as of December 31, 2009, page 35 |
| 2. | Please expand your disclosure to discuss all the information about your proved undeveloped reserves (PUD) as required by Item 1203 of Regulation S-K. We note from your disclosure on page F-38 that PUD make up 26% of your total proved reserves as of December 31, 2009. |
OUR RESPONSE: We will add the following language after the reserve tables on page 35:
Historically, all drilling has primarily been funded by cash flows from operations. At price levels used in the December 31, 2008 reserve report, cash flows generated from oil and gas properties as well as availability under the Company’s credit facility were insufficient to develop the Company’s proved undeveloped prospects within a five year period and therefore the associated proved undeveloped reserves were not included in the Company’s report at December 31, 2008. At 2009 price levels, cash flows generated from oil and gas properties were again sufficient to develop the Company’s proved undeveloped prospects within a five year period and therefore the associated proved undeveloped reserves were included in the Company’s report at December 31, 2009. All proved undeveloped reserves included in the Company’s report related to oil prospects in Kansas. During 2008, oil price realization ranged from a high of $127.29 per barrel in June 2008 to a low of $31.69 per barrel in December 2008. Prior to the significant drop in oil prices, approximately 50 MBbl of proved undeveloped reserves from the McElhaney A#1, Veverka B#1, and Veverka B#2 were converted into proved developed reserves. During 2009, no proved undeveloped reserves were converted into proved developed reserves.
| 3. | Please expand your disclosure on page 36 to discuss the qualifications of the technical person(s) primarily responsible for overseeing the preparation of your reserves estimates to comply with Item 1202(a)(7) of Regulation S-K. |
OUR RESPONSE: We will modify the last paragraph under the Reserve Analysis section on page 36 (additions to existing language and/or modifications are highlighted):
Management has established, and is responsible for, internal controls designed to provide reasonable assurance that the estimates of proved reserves are computed and reported in accordance with SEC rules and regulations as well as with established industry practices. The Company’s CEO and the Vice President responsible for management of properties located onshore Texas Gulf Coast and offshore Texas/Louisiana each have extensive professional engineering experience evaluating both domestic and international reserves on a well by well basis and on a company wide basis. On a semi-annual basis, management and staff meet with LaRoche to review properties and discuss assumptions to be used in the calculation of reserves. Management reviews all information submitted to LaRoche to ensure the accuracy of the data. Management also reviews and compares the final report from LaRoche with the Company’s in-house reserve calculations and discusses any differences with LaRoche.
In addition we will add the following language to the reserve analysis paragraph on page 34:
The technical persons at LaRoche responsible for preparing the Company’s reserve estimates meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the standards pertaining to the estimating and auditing of oil and gas reserves information promulgated by the Society of Petroleum Engineers. Our independent third party engineers do not own an interest in any of our properties and are not employed by the company on a contingent basis.
Financial Statements
Note 1 -- Description of Business and Significant Accounting Policies, page F-10 Revenue Recognition, page F-10
| 4. | We note your disclosure stating that revenues are recognized based on actual volumes of oil and gas sold to purchasers. Please expand your disclosure to discuss conditions that must be met before you consider the transaction a sale, noting the guidance in FASB ASC Sections 605-10-S25 and S99. |
OUR RESPONSE: We will add the following language to the end of the Revenue Recognition disclosure on page 45 and F-10:
Revenues are recognized based on actual volumes of oil and gas sold to purchasers at a fixed or determinable price, when delivery has occurred and title has transferred, and collectability is reasonably assured.
Oil and Gas Properties, page F-11,
| 5. | Please expand your disclosure under this heading, as well as on page 46, to discuss how the cost or estimated fair value of unproven properties affects the limitation of your net capitalized costs. Please be sure that your disclosures address both points (B) and (C) of Rule 4-10(c)(4) of Regulation S-X. |
OUR RESPONSE: We will modify the ceiling limitation language on page 46 to read as follows (additions to existing language and/or modifications are highlighted):
The capitalized oil and gas property, less accumulated depreciation, depletion and amortization and related deferred income taxes, if any, are generally limited to an amount (the ceiling limitation) equal to the sum of: (a) the present value of estimated future net revenues computed by applying an average price (arithmetic average of the beginning of the month prices for the prior 12 months) to estimated future production of proved oil and gas reserves, less estimated future expenditures (based on current costs) to be incurred in developing and producing the reserves using a discount factor of 10% and assuming continuation of existing economic conditions; and (b) cost of properties not being amortized; and (c) the lower of cost or estimated fair value of unproven properties. Prior to the year ending December 31, 2009, the ceiling limitation was calculated using the year-end price. The change from using the year-end price to using the average price was based on adoption of ASU 2010-03, Extractive Activities – Oil and Gas (“Topic 932”); Oil and Gas Reserve Estimation and Disclosures (see page 48 of the Recent Accounting Pronouncements section).
We will modify the ceiling limitation language on page F-11 to read as follows (additions and/or modifications are highlighted):
This test compares the net capitalized cost (capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes) to the present value of estimated future net revenues from oil and gas properties using an average price (arithmetic average of the beginning of month prices for the prior 12 months) and current costs discounted at 10%, plus cost of properties not being amortized and the lower of cost or estimated fair value of unproven properties (ceiling). Prior to the year ending December 31, 2009, the ceiling was calculated using the year-end price. The change from using the year-end price to using the average price was based on adoption of ASU 2010-03, Extractive Activities – Oil and Gas (“Topic 932”); Oil and Gas Reserve Estimation and Disclosures (see page F-15 of the Recent Accounting Pronouncements section).
Note 23 -- Supplemental Oil and Gas Information (Unaudited), page F-35 Estimated Quantities of Oil and Gas Reserves, page F-37
| 6. | Please expand your disclosure to explain the reasons for the significant revisions of your previous reserves estimates for all periods presented to comply with FASB ASC paragraph 932-235-50-5. |
OUR RESPONSE: We will modify the Estimated Quantities of Oil and Gas Reserves disclosure on page F-37 to read as follows (additions to existing language and/or modifications are highlighted):
Estimated Quantities of Oil and Gas Reserves
The following table sets forth the Company’s net proved oil and gas reserves and the changes in net proved oil and gas reserves for the years ended December 31, 2009, 2008 and 2007.
| | Oil (MBbl) | Gas (MMcf) | MBOE |
| | | | |
| Proved reserves at December 31, 2006 | 1,712 | 1,307 | 1,930 |
Revisions of previous estimates (1) | 700 | (46) | 692 |
| Improved recovery | 19 | - | 19 |
| Purchase of reserves in place | 16 | - | 16 |
| Extensions and discoveries | 14 | - | 14 |
| Production | (185) | (127) | (206) |
| Sales of reserves in place | - | - | - |
| | | | |
| Proved reserves at December 31, 2007 | 2,276 | 1,134 | 2,465 |
Revisions of previous estimates (2) | (1,313) | (120) | (1,333) |
| Improved recovery | 59 | - | 59 |
| Purchase of reserves in place | 234 | - | 234 |
| Extensions and discoveries | 154 | - | 154 |
| Production | (162) | (104) | (180) |
| Sales of reserves in place | - | - | |
| | | | |
| Proved reserves at December 31, 2008 | 1,248 | 910 | 1,399 |
Revisions of previous estimates (3) | 1,203 | (721) | 1,084 |
| Improved recovery | - | - | - |
| Purchase of reserves in place | - | - | - |
| Extensions and discoveries | - | - | - |
| Production | (171) | (73) | (183) |
| Sales of reserves in place | (7) | -- | (7) |
| | | | |
| Proved reserves at December 31, 2009 | 2,273 | 116 | 2,293 |
| | | | |
| Proved developed reserves at: | | | |
| December 31, 2007 | 1,605 | 1,131 | 1,793 |
| December 31, 2008 | 1,240 | 907 | 1,391 |
| December 31, 2009 | 1,579 | 116 | 1,598 |
| | | | |
| Proved undeveloped reserves at: | | | |
| December 31, 2007 | 664 | - | 664 |
| December 31, 2008 | - | - | - |
| December 31, 2009 | 694 | - | 694 |
| (1) | The 700 MBbl upward revision in oil reserves was primarily due to higher oil prices used at December 31, 2007 compared to prices used at December 31, 2006. The higher prices used caused the upward revision for two reasons. First, the higher prices used allowed the inclusion of the estimates of some wells that at lower prices were uneconomic to be produced. Second, the higher oil prices used postponed the date all wells would eventually be shut down as unprofitable and thus extended the economic life of all wells for the purpose of the calculations of estimates. Therefore, both the increased number of economically producible wells, and the incremental volumes resulting from a longer economic production period are included in the reserve report. |
| (2) | The proved undeveloped reserve volumes decreased 664 MBbl. At 2008 price levels, cash flows generated from oil and gas properties as well as availability under the Company’s credit facility were insufficient to develop the Company’s proved undeveloped prospects that existed at December 31, 2008 within a five year period and therefore the associated proved undeveloped reserves were required to be and were dropped for our report. The remaining 649 MBbl downward revision in oil reserves was primarily due to lower oil prices used at December 31, 2008 compared to prices used at December 31, 2007. The lower oil prices decreased the economic life of Company wells. In addition, certain wells that were economic at higher prices would not be able to be produced economically at decreased price levels. Therefore, the decremental volumes resulting from a shorter economic production period as well as the decreased number of economically producible wells were excluded from the reserve report. |
| (3) | The proved undeveloped reserve volumes increased 694 MBbl. At 2009 price levels, cash flows generated from oil and gas properties were sufficient to develop the Company’s proved undeveloped prospects within a five year period and therefore the associated proved undeveloped reserves were included in our report at December 31, 2009. The remaining 509 MBbl upward revision in oil reserves were primarily due to higher oil prices used at December 31, 2009 compared to prices used at December 31, 2008. The higher oil prices extended the economic life of certain Company wells. In addition, certain wells that were uneconomic at lower prices were able to be produced economically at increased price levels. Therefore, the incremental volumes resulting from a longer production period as well as the increased number of economically producible wells were included in the reserve report. The 721 MMcf downward revision in gas reserves was primarily due to lower gas prices used at December 31, 2009 compared to prices used at December 31, 2008. The lower gas prices decreased the economic life of certain Company wells. In addition, certain wells that were economic at higher prices were not able to be produced economically at decreased price levels. Therefore, the decremental volumes resulting from a shorter production period as well as the decreased number of economically producible wells were excluded from the reserve report. |
Tengasco, Inc. acknowledges that it is responsible for the adequacy and accuracy of the disclosure in the filing, that SEC staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and 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.
We will await further comment from you with regard to each these matters before preparing and filing any amended pages of the Form 10-K as may be indicated in response to items 1-6 above to enhance the overall disclosure currently provided therein. The Company continues to believe that the disclosure contained in the filings is sufficient to provide all information required to provide investors with the opportunity to make informed investment decisions.
Very truly yours,
TENGASCO, INC.
BY:
s/Jeffrey R. Bailey
JEFFREY R. BAILEY, Chief Executive Officer
January 29, 2010
Mr. Jeff Bailey, CEO
Tengasco, Inc.
10215 Technology Drive, Suite 301
Knoxville, TN 37932
Dear Mr. Bailey:
At your request, LaRoche Petroleum Consultants, Ltd. (LPC) has estimated the proved, probable, and possible reserves and future cash flow, as of December 31, 2009, to the Tengasco, Inc. (Tengasco) interest in certain properties located in Kansas and Tennessee. This report was completed as of the date of this letter. This report was prepared to provide Tengasco with Securities and Exchange Commission (SEC) compliant reserve estimates. It is our understanding that the properties evaluated by LPC comprise 100 percent (100%) of Tengasco’s proved, probable, and possible reserves. We believe that the assumptions, data, methods, and procedures used in preparing this report, as set out below, are appropriate for the purpose of this report. This report has been prepared using constant prices and costs and conforms to our understanding of the SEC guidelines and applicable accounting rules.
Summarized below are LPC’s estimates of net reserves and future net cash flow. Future net revenue is prior to deducting estimated production and ad valorem taxes. Future net cash flow is after deducting these taxes, operating expenses, and future capital expenditures but before consideration of federal income taxes. The discounted cash flow values included in this report are intended to represent the time value of money and should not be construed to represent an estimate of fair market value. We estimate the net reserves and future net cash flow to the Tengasco interest, as of December 31, 2009, to be:
| | | Net Reserves | | Future Net Cash Flow ($) |
Category | | Oil (Barrels) | | Gas (Mcf) | | Total | | Present Worth at 10% |
| Proved Developed | | | | | | | | |
| Producing | | 1,340,390 | | 115,869 | | $ 26,970,105 | | $ 15,698,494 |
| Non-Producing | | 238,363 | | 0 | | $ 9,333,602 | | $ 5,184,949 |
| Proved Undeveloped | | 694,431 | | 0 | | $ 18,951,307 | | $ 7,303,340 |
| | | | | | | | | |
Total Proved(1) | | 2,273,184 | | 115,869 | | $ 55,255,014 | | $ 28,186,783 |
| | | | | | | | | |
Probable(2) | | 520,889 | | 0 | | $ 11,085,309 | | $ 2,792,148 |
| | | | | | | | | |
Possible(2) | | 534,741 | | 0 | | $ 10,497,702 | | $ 2,476,819 |
| | | | | | | | | |
(1) The total proved values above may or may not match those values on the total proved summary page that follows this letter due to rounding by the economics program. (2) These reserves and future cash flow are not risk weighted. |
| 4600 Greenville Avenue, Suite 160 ● Dallas, Texas 75206 |
| Phone (214) 363-3337 ● Fax (214) 363-1608 |
The oil reserves include crude oil and condensate. Oil reserves are expressed in barrels, which are equivalent to 42 United States gallons. Gas reserves are expressed in thousands of standard cubic feet (Mcf) at the contract temperature and pressure bases.
The estimated reserves and future cash flow shown in this report are for proved developed producing reserves and, for certain properties, proved developed non-producing and proved undeveloped reserves. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.
Estimates of reserves were prepared using standard geological and engineering methods generally accepted by the petroleum industry. The reserves in this report have been estimated using deterministic methods. The method or combination of methods utilized in the evaluation of each reservoir included consideration of the stage of development of the reservoir, quality and completeness of basic data, and production history. Recovery from various reservoirs and leases was estimated after consideration of the type of energy inherent in the reservoirs, the structural positions of the properties, and reservoir and well performance. In some instances, comparisons were made to similar properties where more complete data were available. We have excluded from our consideration all matters to which the controlling interpretation may be legal or accounting rather than engineering or geoscience.
The estimated reserves and future cash flow amounts in this report are related to hydrocarbon prices. Historical prices through December 2009 were used in the preparation of this report as required by SEC guidelines; however, actual future prices may vary significantly from the SEC prices. In addition, future changes in environmental and administrative regulations may significantly affect the ability of Tengasco to produce oil and gas at the projected levels. Therefore, volumes of reserves actually recovered and amounts of cash flow actually received may differ significantly from the estimated quantities presented in this report.
Prices used in this report are based on the twelve-month unweighted arithmetic average of the first day of the month price for the period January through December 2009. Gas prices used in this report are referenced to a Henry Hub price of $3.87 per MMBtu, as posted by Platts Gas Daily, adjusted for energy content, transportation fees, and regional price differentials. Oil and NGL prices used in this report are referenced to a West Texas Intermediate (WTI) crude oil price of $57.65 per barrel, as posted by Plains All American Pipeline, L.P., adjusted for gravity, crude quality, transportation fees, and regional price differentials. These reference prices are held constant in accordance with SEC guidelines.
Lease and well operating expenses are based on data obtained from Tengasco. Expenses for the properties operated by Tengasco include allocated overhead costs, direct lease and field level costs as well as compression costs and marketing expenses. Wells operated by others include all direct expenses as well as general, administrative, and overhead costs allowed under the specific joint operating agreements. Lease and well operating costs are held constant in accordance with SEC guidelines.
Capital costs and timing of all investments have been provided by Tengasco and are included as required for workovers, new development wells, and production equipment. Tengasco has represented to us that they have the ability and intent to implement their capital expenditure program as scheduled. These costs are also held constant.
LPC made no investigation of possible gas volume and value imbalances that may have been the result of overdelivery or underdelivery to the Tengasco interest. Our projections are based on the Tengasco interest receiving its net revenue interest share of estimated future gross oil and gas production.
Technical information necessary for the preparation of the reserve estimates herein was furnished by Tengasco or was obtained from state regulatory agencies and commercially available data sources. No special tests were obtained to assist in the preparation of this report. For the purpose of this report, the individual well test and production data as reported by the above sources were accepted as represented together with all other factual data presented by Tengasco including the extent and character of the interest evaluated.
An on-site inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined by LPC. Tengasco’s estimates of the cost to plug and abandon the wells net of salvage value are included at the end of the economic life of the well. In addition, the costs associated with the continued operation of uneconomic properties are not reflected in the cash flows.
The evaluation of potential environmental liability from the operation and abandonment of the properties is beyond the scope of this report. In addition, no evaluation was made to determine the degree of operator compliance with current environmental rules, regulations, and reporting requirements. Therefore, no estimate of the potential economic liability, if any, from environmental concerns is included in the projections presented herein.
The reserves included in this report are estimates only and should not be construed as exact quantities. They may or may not be recovered; if recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. These estimates should be accepted with the understanding that future development, production history, changes in regulations, product prices, and operating expenses would probably cause us to make revisions in subsequent evaluations. A portion of these reserves are for behind-pipe zones, undeveloped locations, and producing wells that lack sufficient production history to utilize performance-related reserve estimates. Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogies to similar production. These reserve estimates are subject to a greater degree of uncertainty than those based on substantial production and pressure data. It may be necessary to revise these estimates up or down in the future as additional performance data become available. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geological data; therefore, our conclusions represent informed professional judgments only, not statements of fact.
This report is solely for the use of Tengasco, its agents, and its representatives in their evaluation of these properties and is not to be used, circulated, quoted, or otherwise referenced for any other purpose without the express written consent of the undersigned except. Persons other than those to whom this report is addressed or those authorized by the addressee shall not be entitled to rely upon the report unless it is accompanied by such consent.
The technical persons responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We are independent petroleum engineers, geologists, and geophysicists; and are not employed on a contingent basis. Data pertinent to this report are maintained on file in our office.
Very truly yours,
LaRoche Petroleum Consultants, Ltd.
State of Texas Registration Number F-1360
/s/ Stephen W. Daniel
By:
Stephen W. Daniel
Licensed Professional Engineer
State of Texas No. 58581
SWD:pt
Job 09-908
LaRoche Petroleum Consultants, Ltd.
Please be advised that the digital document you are viewing is provided by LaRoche Petroleum Consultants, Ltd. (LPC) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by LPC. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.
LaRoche Petroleum Consultants, Ltd.
