Torchlight Energy Resources, Inc.

5700 Plano Parkway, Suite 3600

Plano, Texas 75093

Telephone: (214) 432-8002

June 10, 2014

H. Roger Schwall

Division of Corporation Finance

United States Securities and Exchange Commission

100 F. Street NE

Washington, D.C. 20549

Re:  Torchlight Energy Resources, Inc. Registration Statement on Form S-1 Filed April 22, 2014 File No. 333-195423 Form 10-K for Fiscal Year Ended December 31, 2013 Filed March 31, 2014 File No. 001-36247

Dear Mr. Schwall,

Set forth below are Torchlight Energy Resources, Inc.’s (the “Company,” “we” and “us”) responses to the comments of the Staff of the Securities and Exchange Commission (the “Staff”) to the Company’s Registration Statement on Form S-1, filed April 22, 2014.  The Staff’s comments were contained in the letter to the Company dated May 20, 2014.

Registration Statement on Form S-1

Cover Page

1. Revise the Cover Page to indicate the exercise price of the Warrants.

In response to the Staff’s Comment 1, we have revised the cover page to include this disclosure.

Risk Factors, page 5

2. In the first full risk factors on pages 8 and 9, you disclose the dangers associated with your operations as well as regulatory risks.  In the Current Projects section of your Form 10-K for the fiscal year ended December 31, 2013, you also disclose your operations involve hydraulic fracturing.  Please revise your risk factor disclosure to specifically discuss the operational and regulatory risks associated with hydraulic fracturing, such as the underground migration and the surface spillage or mishandling of fracturing fluids, including chemical additives. Please also make corresponding changes to future periodic reports.

Page 1 of 31

In response to the Staff’s Comment 2, we have added additional disclosure on page 7 under the risk factor titled “Because of the inherent dangers involved in oil and gas operations, there is a risk that we may incur liability or damages as we conduct our business operations, which could force us to expend a substantial amount of money in connection with litigation and/or a settlement,” and we have added a new risk factor on page 9 titled “Government regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.”  We will also make corresponding changes to future periodic reports.

Selling Stockholders, page 12

3. For each of your selling stockholders that are entities, please revise to disclose the name of the natural persons who hold or share voting or investment power.  Please see Regulation S-K Compliance and Disclosure Interpretations, Section 240.04.

In response to the Staff’s Comment 3, we have revised the “Selling Stockholder” section starting on page 13 to include this disclosure.  Please also note that we have added additional warrant holders as selling stockholders, and there is corresponding disclosure throughout the amended Registration Statement.

Description of Securities to be Registered, page 22

4. Indicate the market price of your common stock on the dates that the Series B and Unit Warrants were issued.

In response to the Staff’s Comment 4, we have revised the “Description of Securities to be Registered” section on page 23 to include this disclosure.

Recent Sales of Unregistered Securities, page 26

5. Tell us which of your recent offerings represent the securities being offered for resale in this registration statement.

In response to the Staff’s Comment 5, we have revised the “Recent Sales of Unregistered Securities” on page 27 section to include this disclosure.

6. In December 2013, you issued $10,895,773 in principal value of 2% (sic) Series A Secured Convertible Promissory Notes which are convertible at $1.75 per share or the issuance of approximately 6.2 million shares.   In that same transaction, you issued 1,308,082 five- year warrants to purchase common stock at $2 per share or the issuance of 654,041 shares.  Finally, you also issued 8,000 warrants for each $70,000 of principal purchased exercisable at $2 per share which, by staff calculations, would result in the issuance of 12.45 million shares of common stock. This would appear to represent a significant market overhang of securities. Tell us whether any of these have been converted or exercised and are included in your common stock outstanding as of March 31, 2014. Also, provide a risk factor addressing this market overhang or tell us why you do not believe one is appropriate.

Page 2 of 31

In response to the Staff’s Comment 6, the sale of the $10,895,773 in 12% Series A Promissory Notes referenced by the Staff from a paragraph in the “Recent Sales of Unregistered Securities” section, did not occur during December 2013.  Rather, the paragraph stated that this sale occurred during “the year ended December 31, 2013.”  We have revised this paragraph on page 27 in response to the Staff’s comment.  Additionally, the Staff’s calculations are incorrect regarding the referenced sales, and we have also revised the paragraph to clarify the number of securities issued.  The exercise and conversion of all securities issued in the referenced paragraph would result in the issuance of approximately 8.09 million shares of common stock.  Additionally, in December 2012, we sold a total of $1,102,500 in 12% Series A Secured Convertible Promissory Notes and 125,999 Series A Warrants (which sales of were disclosed in a paragraph further down in the “Recent Sales of Unregistered Securities” section), the exercise and conversion of which would result in the issuance of approximately 756,000 shares of common stock. Of the total 8.84 million shares of common stock issuable, approximately 2.21 million have been issued to date.  In addition, in response to the Staff’s comment 6, we have expanded the risk factor on page 12 titled “Offers or Availability for Sale of a Substantial Number of Shares of our Common Stock May Cause the Price of our Common Stock to Decline”.

Signatures, page 33

7. Please revise the first paragraph of this section to comply with Form S-1 and delete the following statement “certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form S-1 and…”

In response to the Staff’s Comment 7, we have revised the first paragraph of this section on page 34 to comply with Form S-1.

Page 3 of 31

Exhibit 23.1

8. Please revise to have the auditors consent to inclusion of both years of financial statements covered by the relevant auditor’s report (i.e. December 31, 2013 and December 31, 2012).

In response to the Staff’s Comment 8, we have included a new Exhibit 23.1 wherein the auditors have consented to inclusion of both years of financial statements covered by the relevant auditor’s report.

Form 10-K for Fiscal Year Ended December 31, 2013

Item 2 Properties, page 18

Oil and Natural Gas Reserves, page 18

Reserve Estimates, page 18

9. We note your qualitative discussion of PV-10 as a non-GAAP financial measure.  However, the quantitative disclosures of PV-10 are labeled “Present Worth at 10%”. Please clarify the labeling of your PV-10 measures in the tables presented on page 19 and provide a reconciliation of PV-10 to the standard measure of discounted future cash flows, the nearest GAAP measurement for each period presented, as required by Item 10(e) of Regulation S-X.

In response to the Staff’s Comment 9, we have revised the tables presented on page 19 and have revised the “Oil and Natural Gas Reserves” section starting on page 18, which revised section is included in its entirety immediately below our response to the Staff’s Comment 17 .

10. We note the presentation of “gross” reserve quantities under the heading “Net Reserves” for the fiscal years ending December 31, 2013 and 2012.  Please refer to the definitional requirements of Rule 4-10(a)(26) of Regulation S-X and revise your presentation to remove the disclosure of reserve quantity information unrelated to your direct revenue interests.

In response to the Staff’s Comment 10, we have revised the tables presented on page 19 and have revised the “Oil and Natural Gas Reserves” section starting on page 18, which revised section is included in its entirety immediately below our response to the Staff’s Comment 17.

11. We also note the disclosure of your net proved and probable reserves as of December 31, 2013 as an aggregation of the net quantities of oil and natural gas expressed in terms of barrels of oil equivalent (“BOE”).  Please refer to Instruction 3 to paragraph (a)(2) in Item 1202 of Regulation S-K and clarify your disclosure to provide the basis for determining the equivalent amounts. Additionally, please expand your disclosure to provide the net quantities of your oil and natural gas reserves as separate product types to comply with the presentation requirements in Item 1202(a)(4) of Regulation S-K.

Page 4 of 31

In response to the Staff’s Comment 11, we have revised the tables presented on page 19 and have revised the “Oil and Natural Gas Reserves” section starting on page 18, which revised section is included in its entirety immediately below our response to the Staff’s Comment 17.

12. Based on the reserve quantities disclosed in Exhibit 99.1, it appears that the proved undeveloped reserves, disclosed on page 19 and elsewhere on page 21 for the fiscal year ending December 31, 2013, represents the summation of proved undeveloped and proved developed non-producing reserves.  The staff considers proved developed non-producing reserves to be proved developed reserves for the purpose of disclosure under Item 1202(a)(2) of Regulation S-K.  Please recalculate the net quantities and revise the disclosure of your proved developed and undeveloped reserves in each occurrence throughout your filing on Form 10-K.  Alternatively, please tell us why you consider your proved developed non-producing reserves to be undeveloped reserves.

In response to the Staff’s Comment 12, we have revised the “Oil and Natural Gas Reserves” section starting on page 18, which revised section is included in its entirety immediately below our response to the Staff’s Comment 17.

13. Please expand the disclosure relating to your reserve estimates to provide an explanation for why there were no proved or probable natural gas reserves in 2012.

In response to the Staff’s Comment 13, we have revised the disclosure on page 19 and have revised the “Oil and Natural Gas Reserves” section starting on page 18, which revised section is included in its entirety immediately below our response to the Staff’s Comment 17.

14. Please refer to the requirements in FASB ASC paragraph 932-235-50-5 and expand your disclosure of the changes in net quantities of proved reserves for the periods ending December 31, 2013 and 2012 to include an appropriate explanation of the significant changes relating to purchases of minerals in place.  Also tell us the extent to which there were any changes in the opening balance of proved reserves attributable to extensions and discoveries related to drilling or revisions in the previous estimates of such reserves that occurred during 2013.

Page 5 of 31

In response to the Staff’s Comment 14, we have revised the “Oil and Natural Gas Reserves” section starting on page 18, which revised section is included in its entirety immediately below our response to the Staff’s Comment 17 .

15. The discussion on page 20 relating to the uncertainty in the estimation of probable reserves states in part that “probable reserves involve less certainty with reserves supporting a probable classification from a probabilistic analysis where those reserves are as likely as not to be recovered.”  This statement conflicts with the statement in the NSAI report which indicates that the reserves “have been estimated using deterministic methods.”  Please advise or revise.  Furthermore, please clarify for us the extent to which any of your probable reserves were determined using probabilistic methods; otherwise, refer to Rule 4-10(a)(18)(i) of Regulation S-X and revise your disclosure to refer to the uncertainty of such estimates using deterministic methods.

In response to the Staff’s Comment 15, we have expanded the disclosure on page 21 “Oil and Natural Gas Reserves” section, which revised section is included in its entirety immediately below our response to the Staff’s Comment 17. All of our reserves are obtained by deterministic methods.  Based on the categories into which those wells and their reserves fall, their probability is estimated by their geological and geographical location with respect to the data that was used to determine the type decline profile curve.

16. Please expand your discussion of probable reserves to provide a cautionary statement to prospective investors regarding the different levels of uncertainty relating to the estimates of proved and probable net present worth discounted at 10% as presented. Your statement for example should indicate the reserves and net present worth discounted at 10% relating to the different categories of proved and probable have not been adjusted for risk due to their uncertainty of recovery and thus are not comparable and should not be summed into total amounts.

In response to the Staff’s Comment 16, we have expanded the disclosure on page 21 “Oil and Natural Gas Reserves” section, which revised section is included in its entirety immediately below our response to the Staff’s Comment 17 .

17. Please expand the disclosure on page 21 of the internal controls used in your reserves estimation effort to include the qualifications of the technical person for each of the third party engineering firms that is primarily responsible for the reserves estimates disclosed in your filing on Form 10-K.  Refer to the requirements set forth in Item 1202(a)(7) of Regulation S-K.  For additional guidance relating to this disclosure, please refer to Part IV, B.3.d. of the Modernization of Oil and Gas Reporting; Final Rule, available on our website at the following address: http://www.sec.gov/rules/final/2009/33-8995fr.pdf.

In response to the Staff’s Comment 17, we have expanded the disclosure on page 21 in the revised the “Oil and Natural Gas Reserves” section, which revised section is included in its entirety below.

The revised section “Oil and Natural Gas Reserves” is set forth immediately below:

Page 6 of 31

Oil and Natural Gas Reserves

Reserve Estimates

SEC Case. The following tables sets forth, as of December 31, 2013, our estimated net proved oil and natural gas reserves, the estimated present value (discounted at an annual rate of 10%) of estimated future net revenues before future income taxes (PV-10) and after future income taxes (Standardized Measure) of our proved reserves and our estimated net probable oil and natural gas reserves, each prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with assumptions prescribed by the Securities and Exchange Commission (“SEC”).  All of our reserves are located in the United States.

The PV-10 value is a widely used measure of value of oil and natural gas assets and represents a pre-tax present value of estimated cash flows discounted at ten percent. PV-10 is considered a non-GAAP financial measure as defined by the SEC. We believe that our PV-10 presentation is relevant and useful to our investors because it presents the estimated discounted future net cash flows attributable to our proved reserves before taking into account the related future income taxes, as such taxes may differ among various companies.  We believe investors and creditors use PV-10 as a basis for comparison of the relative size and value of our proved reserves to the reserve estimates of other companies. PV-10 is not a measure of financial or operating performance under GAAP and neither it nor the Standardized Measure is intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.

The estimates of our proved reserves and the PV-10 set forth herein reflect estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions at December 31, 2013. For purposes of determining prices, we used the average of prices received for each month within the 12-month period ended December 31, 2013, adjusted for quality and location differences, which was $97.08 per barrel of oil and $5.85 per MCF of gas.  This average historical price is not a prediction of future prices. The amounts shown do not give effect to non-property related expenses, such as corporate general administrative expenses and debt service, future income taxes or to depreciation, depletion and amortization.

	December 31, 2013						December 31, 2013
	Reserves (BOE)						Future Net Revenue (M$)
	Gross				Net		Gross		Present Value
Category	Oil (BBLS)		Gas (MCF)		(BOE)		Oil (BBLS)		Discounted at 10%
Proved Developed		2,355,218		14,111,745		165,319	$	4,407	$	3,215
Proved Undeveloped		5,779,871		27,254,004		1,401,126		49,153		23,310
Total Proved		8,135,089		41,365,749		1,566,445	$	53,560	$	26,525
Standardized Measure of Future Net Cash Flows Related to Proved Oil and Gas Properties									$	19,691
Probable Undeveloped		1,309,900		0		657,800	$	33,571	$	16,253

BOE equivalents are determined by combining barrels of oil with MCF of gas divided by six.

Page 7 of 31

	December 31, 2012						December 31, 2012
	Reserves (BBL)						Future Net Revenue (M$)
	Gross				Net				Present Value
Category	Oil (BBL)		Gas (MCF)		(BBL)		Total		Discounted at 10%
Proved Developed		55,800		0		24,800	$	1,397	$	1,169
Proved Undeveloped		751,000		0		392,700		8,538		2,131
Total Proved		806,800		0		417,500	$	9,935	$	3,300
Standardized Measure of Future Net Cash Flows Related to Proved Oil and Gas Properties									$	2,909
Probable Undeveloped		1,875,300		0		937,100	$	30,986	$	12,237

For the year ended December 31, 2012 all of the Company’s Oil and Gas properties were located in the Marcelina Project in Texas which produces no gas.

Standardized Measure of Oil & Gas Quantities - Volume Rollforward
Year Ended December 31, 2013 and 2012
The following table sets forth the Company’s net proved reserves, including the changes therein, and proved developed reserves:
	2013						2012
	Crude Oil (Bbls)			Natural Gas (Mcf)			Crude Oil (Bbls)			Natural Gas (Mcf)
TOTAL PROVED RESERVES:
Beginning of period		417,549			-			-			-
Acquisition		572,461			3,139,595			-			-
Extensions and discoveries		805,800			-			428,204			-
Revisions of previous estimates		(739,661	)		3,539			-			-
Production		(12,970	)		(3,540	)		(10,655	)		-
End of period		1,043,179			3,139,594			417,549			-
PROVED DEVELOPED RESERVES
Proved developed producing		64,858			108,001			24,804			-
Proved developed nonproducing		48,234			205,250			-			-
Total		113,092			313,251			24,804			-
Total PUD		930,087			2,826,343			392,745			-

Page 8 of 31

Standardized Measure of Oil & Gas Quantities
Year Ended December 31, 2013 & 2012
The standardized measure of discounted future net cash flows relating
to proved oil and natural gas reserves is as follows :	2013			2012
Future cash inflows	$	119,629,906		$	41,103,000
Future production costs		(31,656,853	)		(12,413,000	)
Future development costs		(34,152,898	)		(18,755,000	)
Future income tax expense		(11,264,101	)		(1,012,000	)
Future net cash flows		42,556,054			8,923,000
10% annual discount for estimated
timing of cash flows		(22,865,456	)		(6,014,000	)
Standardized measure of discounted future
net cash flows related to proved reserves	$	19,690,598		$	2,909,000
A summary of the changes in the standardized measure of discounted
future net cash flows applicable to proved oil and natural gas reserves
is as follows :
Balance, beginning of year	$	2,909,000		$	-
Sales and transfers of oil and gas produced during the period		(905,125	)		-
Net change in sales and transfer prices and in production (lifting) costs related to future production		(1,647,568	)		-
Net change due to purchases of minerals in place		30,474,988			-
Net change due to extensions and discoveries		22,411,372			-
Changes in estimated future development costs		(17,355,723	)		-
Previously estimated development costs incurred during the period		(3,181,356	)		-
Net change due to revisions in quantity estimates		(4,633,853	)		-
Other		(1,468,500	)		-
Accretion of discount		(318,085	)		-
Net change in income taxes		(6,594,552	)		-
Balance, end of year	$	19,690,598		$	-

Due to the inherent uncertainties and the limited nature of reservoir data, both proved and probable reserves are subject to change as additional information becomes available. The estimates of reserves, future cash flows and present value are based on various assumptions, including those prescribed by the SEC, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

In estimating probable reserves, it should be noted that those reserve estimates inherently involve greater risk and uncertainty than estimates of proved reserves. While analysis of geoscience and engineering data provides reasonable certainty that proved reserves can be economically producible from known formations under existing conditions and within a reasonable time, probable reserves involve less certainty than reserves with a higher classification due to less data to support their ultimate recovery. Probable reserves have not been discounted for the additional risk associated with future recovery.  Prospective investors should be aware that as the categories of reserves decrease with certainty, the risk of recovering reserves at the PV-10 calculation increases.  The reserves and net present worth discounted at 10% relating to the different categories of proved and probable have not been adjusted for risk due to their uncertainty of recovery and thus are not comparable and should not be summed into total amounts.

Reserve Estimation Process, Controls and Technologies

The reserve estimates, including PV-10 estimates, set forth above were prepared by Netherland, Sewell & Associates, Inc. and Wright & Company, Inc.  A copy of their full reports with regard to our reserves is attached as Exhibit 99.1 to this annual report on Form 10-K.  These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards.

Page 9 of 31

Our Chief Executive Officer is an experienced and qualified geoscience professional with a degree in geophysical science, but we do not have any employees with specific reservoir engineering qualifications in the company.  Our Chief Executive Officer worked closely with Netherland, Sewell & Associates, Inc. and Wright & Company Inc. in connection with their preparation of our reserve estimates, including assessing the integrity, accuracy and timeliness of the methods and assumptions used in this process.

Netherland, Sewell & Associates, Inc. (“NSAI”) is a large Texas-based professional engineering firm specializing in technical and financial evaluation of oil and gas assets.  NSAI used a combination of performance analysis and analogy, using technical and economic data including but not limited to well logs, well test data, and production data.  Within NSAI, the technical person primarily responsible for preparing the estimates set forth in the NSAI reserves report is C. Ashley Smith.  Mr. Smith has been practicing consulting petroleum engineering at NSAI since 2006.  Mr. Smith is a Licensed Professional Engineer in the State of Texas (No. 100560) and has over 13 years of practical experience in petroleum engineering, with over 7 years experience in the estimation and evaluation of reserves.  He graduated from University of Missouri-Rolla (Missouri University of Science & Technology) in 2000 with a Bachelor of Science Degree in Petroleum Engineering.  Mr. Smith meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; Mr. Smith is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Wright & Company Inc. (“Wright”) is a Tennessee based professional engineering firm made up of petroleum engineers, geologists, geophysicists and petro physicists that specialize in technical and financial evaluation of oil and gas assets.  They used a combination of production and pressure performance, simulation studies, offset analogies, seismic data and interpretation, geophysical logs and other relevant field data to calculate our reserves estimates.  D. Randall Wright is the primary technical person in charge of the estimates of reserves and associated cash flow and economics on behalf of Wright for the results presented in its reserves report to us.  He has a Master of Science degree in Mechanical Engineering from Tennessee Technological University.  He is a qualified Reserves Estimator as set forth in the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers.  This qualification is based on more than 40 years of practical experience in the estimation and evaluation of petroleum reserves with Texaco, Inc., First City National Bank of Houston, Sipes, Williamson & Associates, Inc., Williamson Petroleum Consultants, Inc., and Wright which he founded in 1988.  He is a registered Professional Engineer in the state of Texas (TBPE #43291), granted in 1978, a member of the Society of Petroleum Engineers and a member of the Order of the Engineer.

Page 10 of 31

Proved Undeveloped Reserves, page 21

18. Based on the tabular disclosure provided on page 19, there appears to be a material change in your proved undeveloped reserves during 2013.  Item 1203(b) of Regulation S-K requests that registrants “[d]isclose material changes in proved undeveloped reserves that occurred during the year, including proved undeveloped reserves converted to developed reserves.”  Please expand your disclosure to present the changes in proved undeveloped reserves relating to such causes as revisions, extensions/discoveries, acquisition/divestiture, improved recovery and the amounts converted during the year from proved undeveloped to proved developed.

In response to the Staff’s Comment 18, we believe the revisions we made to the “Oil and Natural Gas Reserves” section above, in connection with the Staff’s Comment 12, also address the Staff’s Comment 18.

19. Further to the previous comment, Item 1203(c) of Regulation S-K requests that registrants “[d]iscuss investments and progress made during the year to convert proved undeveloped reserves to proved developed reserves, including, but not limited to, capital expenditures.”  Please expand your disclosure to explain the progress you have made during the year to convert your proved undeveloped reserves to developed.  As part of your expanded disclosure, please provide the capital expenditures incurred in converting your proved undeveloped reserves to developed.

In response to the Staff’s Comment 19, we have revised the “Proved Undeveloped Reserves” section on page 21, which revised section is included in its entirety immediately below our response to the Staff’s Comment 20.

20. Please refer to Item 1203(d) of Regulation S-K and tell us the extent to which the proved undeveloped reserves disclosed as of December 31, 2013 will not be developed within five years since your initial disclosure of these reserves.

In response to the Staff’s Comment 20, we have revised the “Proved Undeveloped Reserves” section on page 21, which revised section is included in its entirety below.

The revised section “Proved Undeveloped Reserves” is set forth immediately below:

Page 11 of 31

Proved Undeveloped Reserves

As of December 31, 2013, our proved undeveloped reserves totaled  1.401MM barrels of oil equivalents.  These proved undeveloped reserves at December 31, 2013 were associated with our Marcelina Creek Field property and our Hunton projects.    These numbers are taken from the third party reserves studies by Netherland, Sewell and Associates and Wright & Company.

Our current drilling plans, subject to sufficient capital resources and the periodic evaluation of interim drilling results and other potential investment opportunities, include drilling substantially all of the Buda wells in our proved undeveloped reserves during 2014 and 2015.  We do not currently have plans to drill the Eagle Ford shale wells in the next year.  The area of the Marcelina Creek Field is an active area of Eagle Ford shale development, and we intend to actively explore our options with regard to these proved undeveloped locations and other potential Eagle Ford drilling locations on our acreage.  Further we will maintain our continuous drilling program in the Hunton projects for the foreseeable future.

We made various investments and progress during 2013 to convert proved undeveloped reserves to proved developed reserves.  Wells that were converted from proved undeveloped reserves to developed include the Hancock, Robinson, Boeckman, Stevens and School Land. The capital expenditures incurred in converting our proved undeveloped reserves to developed were approximately $ 1,198,130.  We believe that nearly all of our proved undeveloped reserves as of December 31, 2013 will be developed within five years.  Limitations on our ability to develop proved undeveloped reserves within five years would likely be due to restraints on our capital and/or personnel moving forward.  The restraints, however, could be alleviated through increased revenue or additional funding.

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Production, Price and Production Cost History, page 21

21. Please refer to Item 1204(a) of Regulation S-K and tell us the extent to which the annual net oil and natural gas production disclosed on page 21 is attributable to any field that contains 15% or more of your total proved reserves.  Also revise your disclosure to address the production from any such field(s).

In response to the Staff’s Comment 21, we have revised the “Production, Price and Production Cost History” section on page 22, which revised section is included in its entirety below.

Page 13 of 31

Production, Price and Production Cost History

During the year ended December 31, 2013, we produced and sold 13,286 barrels of oil net to our interest at an average sale price of $100.67 per bbl. We produced and sold 3,540 MCF of gas net to our interest at an average sales price of $5.68 per MCF.  Our average production cost including lease operating expenses and direct production taxes was $31.29 per bbl.  Our depreciation, depletion and amortization expense was $49.09 per bbl.

During the year ended December 31, 2012, we produced and sold 10,655 barrels of oil net to our interest at an average sale price of $97.35 per bbl.  We had no gas production.  Our average production cost including lease operating expenses and direct production taxes was $46.93 per bbl.  Our depreciation, depletion and amortization expense was $51.80 per bbl.

Our production is from properties concentrated in central Oklahoma and in southern Texas. Reserves from each of these areas comprise more than 15% of total reserves. For 2012, 100% of our production came from Marcelina Creek.  For 2013, approximately 88 BOPD was being produced at Marcelina Creek and approximately 47 BOEPD in Oklahoma, or 65% from Marcelina Creek and 35% from Oklahoma.

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Drilling Activity and Productive Wells, page 21

22. Please revise or otherwise expand the disclosure of your drilling activity for each period through December 31, 2013 to provide the total number of net productive and dry exploratory and/or development wells drilled each year.  For additional guidance relating to this disclosure, please refer to Item 1205 and the definitions contained in Item 1205(b) of Regulation S-K.

In response to the Staff’s Comment 22, we have revised the “Drilling Activity and Productive Wells” section starting on page 22, which revised section is included in its entirety immediately below our response to the Staff’s Comment 24.

23. We note your disclosure that as of December 31, 2012 there were three productive wells (1.75 net wells) located in the Marcelina Creek Field.  Based on the disclosure of the 2013 quarterly production provided on page 24, you also appear to have productive wells located in Oklahoma.  To comply with the disclosure requirements in Item 1208(a) of Regulation S-K, please revise or otherwise expand your disclosure to provide the total number of gross and net productive wells as of December 31, 2013 expressed separately for oil and natural gas.

In response to the Staff’s Comment 23, we have revised the “Drilling Activity and Productive Wells” section starting on page 22, which revised section is included in its entirety immediately below our response to the Staff’s Comment 24.

24. Further to the previous comment, Item 1208 of Regulation S-K also requires the disclosure of the total gross and net developed and undeveloped acreage and the disclosure relating to the expiration dates of material amounts of your undeveloped acreage.  For additional guidance relating to providing this disclosure, please refer to Item 1208 and the definitions contained in Item 1208(c) of Regulation S-K.

In response to the Staff’s Comment 24, we have revised the “Drilling Activity and Productive Wells” section starting on page 22, which revised section is included in its entirety below.

The revised section “Drilling Activity and Productive Wells” is set forth immediately below:

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Drilling Activity and Productive Wells

Marcelina Creek Project - Texas

During the year ended December 31, 2010, the Company participated in drilling operations of one re-entry and horizontal extension to an existing well bore (50% working interest).  This well was recompleted in 2012 as a successful producing oil well.

During the year ended December 31, 2011, the Company drilled one well (75% working interest).  This well was successfully completed as an oil well.

During the year ended December 31, 2012, the Company participated in another re-entry and horizontal extension to the same well drilled in 2010 (50% working interest).  This operation was successful and the well is currently a producing oil well.  We also participated in a re-entry and horizontal extension of another well (40% working interest), the Coulter #1.  This well is currently testing as described above.  For 2012, in Marcelina Creek the Company had a total of three producing wells at year end

During the year ended December 31, 2013, the Company drilled one well in the Marcelina Project (75% working interest). This well was successfully completed as an oil well.

As of December 31, 2013, we had three productive wells in the Marcelina Creek Field (1.75 net wells) and one well which was in the process of being tested in the Coulter Field (.40 net well).  Net wells consist of the sum of our fractional working interests in these wells.

Central Oklahoma Projects

During the year ended December 31, 2013, the Company began participating in development wells in the Hunton Play. Two producing wells were acquired and three wells were drilled and completed in 2013.  As of December 31, 2013 these five wells were producing and the Company was a participant in six additional wells that were either drilling or in the process of completing at year end.

Combined Well Status

Our combined well status at December 31, 2013 is summarized as follows:

Producing Wells: 5

Development Wells: 6

Our producing wells included the Hancock (0.01 WI, 0.8 BOEPD), the Robinson (0.0025 WI, 0.2 BOEPD), the Boeckman (0.1891 WI, 33.4 BOEPD), the Stevens (0.0173 WI, 7.2 BOEPD) and the School Land (0.005 WI, 6.4 BOEPD), amounting to net producing wells of 22.39% of one well.

Our testing wells included the CW (0.0225 WI), the Mel B (0.075 WI), the Jet (0.0191 WI), the Rosemary (0.1246 WI), the Jones (0.0213 WI) and the Liebhart (0.0308 WI), amounting to net testing wells of 29.33% of one well.

Our acreage positions at December 31, 2013 are summarized as follows:

Marcelina Creek Project consists of 1,045 acres all of which are held by production.

The Central Oklahoma Projects acreage is in three AMI’s as of December 31, 2013 with a combined total of 17,671 gross acres.  Producing wells and wells under development comprise 7,040 acres with the balance subject to a managed drilling program to retain leases for long term development.  Net acres approximate 3,500 at December 31, 2013.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 23

Historical Results for the Years Ended December 31, 2013 and 2012, page 23

General and Administrative Expenses, page 24

25. You briefly discuss the various business reasons behind the change in general and administrative expenses from the prior year.  However, where there is more than one driver behind the change, you should quantify the incremental impact of each individual driver in your discussion.  Please revise your disclosure in both your Form 10-K for the fiscal year ended December 31, 2013 and your Form 10-Q for the fiscal quarter ended March 31, 2014.  Also, please revise your Liquidity and Capital Resources discussion in both filings.  Please see Item 303(a)(3) of Regulation S-K and SEC Release No. 33-8350.

In response to the Staff’s Comment 25, we have revised the “General and Administrative Expenses” and the “Liquidity and Capital Resources” sections of the Form 10-K for the fiscal year ended December 31, 2013 and the Form 10-Q for the fiscal quarter ended March 31, 2014, which revised sections are included in their entirety below.

Revisions to Form 10-K:

Page 17 of 31

General and Administrative Expenses

Our general and administrative expenses for the years ended December 31, 2013 and 2012 were $6,682,377 and $2,430,884, respectively, an increase of $4,251,493. Our general and administrative expenses consisted of consulting and compensation expense, substantially all of which was non-cash or deferred, accounting and administrative costs, professional consulting fees and other general corporate expenses.  The increase in general and administrative expenses for the year ended December 31, 2013 compared to 2012 is primarily related to a $408,117 increase in investor relations expense and a $3,062,427 increase in stock based compensation.

Liquidity and Capital Resources

At December 31, 2013, we had working capital of $(468,453), current assets of $2,250,556 consisting of cash, accounts receivable and prepaid expenses and total assets of $16,743,321 consisting of current assets, investments in oil and gas properties and goodwill. As of December 31, 2013, we had current liabilities of $2,719,009, consisting of, accounts payable, payables to related parties, notes payable and accrued interest and stockholders’ equity was $9,197,219.

Cash flow used in operating activities for the years ended December 31, 2013, was $2,262,636 compared to $130,274 for the year ended December 31, 2012, an increase of $2,132,362. Cash flow used in operating activities during 2013 can be primarily attributed to net losses from operations of $10,418,662, which consists primarily of $6,682,377 in general and administrative expenses ($4,331,143 of which are non-cash stock based compensation), depreciation, depletion and amortization of $652,179, and accretion of convertible note discounts $3,894,389. Cash flow used in operating activities during 2012 can be primarily attributed to net losses from operations of $2,808,803, which consists primarily of $2,430,884 in general and administrative expenses ($1,268,216 of which are non-cash  stock based compensation), depreciation, depletion and amortization of $551,890 and accretion of convertible note discounts $313,963. We expect to continue to use cash flow in operating activities until such time as we achieve sufficient commercial oil and gas production to cover all of our cash costs.

Cash flow used in investing activities for year ended December 31, 2013 was $8,587,104 compared to $830,755 for the year ended December 31, 2012.  Cash flow used in investing activities consists primarily of oil and gas investments in the Johnson wells in the Marcelina Creek Field and the Oklahoma properties acquired during the year ended December 31, 2013.

Cash flow provided by financing activities for the year ended December 31, 2013 was $12,598,201 as compared to $506,000 for the year ended December 31, 2012.  Cash flow provided by financing activities in 2013 consists of convertible promissory notes issued for cash, net of repayments of debt, and proceeds from common stock issues and warrant exercises.  We expect to continue to have cash flow provided by financing activities as we seek new rounds of financing and continue to develop our oil and gas investments.

Our current assets are insufficient to meet our current obligations or to satisfy our cash needs over the next twelve months and as such we will require additional debt or equity financing. Subsequent to December 31, 2013, we received net proceeds of approximately $6.15 million from the offering of units of equity consisting of our common stock and warrants, but these proceeds will not be sufficient to fund all of our proposed drilling operations and operating needs during 2014. We will seek additional financing to meet these plans and needs.  We face obstacles in continuing to attract new financing due to our history and current record of net losses and working capital deficits. Therefore, despite our efforts we can provide no assurance that we will be able to obtain the financing required to meet our stated objectives or even to continue as a going concern.

We do not expect to pay cash dividends in the foreseeable future.

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Revisions to Form 10-Q:

Page 19 of 31

General and Administrative Expenses

Our general and administrative expenses for the quarters ended March 31, 2014 and 2013 were $5,821,068 and $533,549, respectively. An increase of $5,287,519.  Our general and administrative expenses consisted of consulting and compensation expense, substantially all of which was non-cash or deferred, accounting and administrative costs, professional consulting fees and other general corporate expenses.  The increase in general and administrative expenses for the quarters ended March 31, 2014 compared to 2013 is primarily related to a $338,796  increase in investor relations expense  and a $4,262,270 increase in stock based compensation.

Liquidity and Capital Resources

At March 31, 2014, we had working capital of ($6,648,543), current assets of $2,686,667 consisting of cash, accounts receivable, notes receivable, and prepaid expenses and total assets of $22,199,849 consisting of current assets, investments in oil and gas properties and goodwill. As of March 31, 2014, we had current liabilities of $9,335,210, consisting of, accounts payable (principally for development costs), payables to related parties, notes payable and accrued interest. The remaining balance of convertible notes payable (which mature on March 15, 2015) were reclassified from long term liabilities to current liabilities as of March 31, 2014 which accounts for $5,425,910 of negative working capital at March 31, 2014. Stockholders’ equity was $12,839,723.

Cash flow used in operating activities for the quarters ended March 31, 2014 was $444,017 compared to $58,733 for the quarter ended March 31, 2013, an increase of $385,284.. Cash flow used in operating activities for the quarter ended March 31, 2014  can be primarily attributed to net losses from operations of $7,561,752 which consists primarily of $5,821,068 in general and administrative expenses, $4,393,375 of which are non-cash stock based compensation,  , depreciation, depletion and amortization of $334,331, and accretion of convertible note discounts $1,605,025 Cash flow used in operating activities for the quarter ended March 31, 2012 can be primarily attributed to net losses from operations of $658,193, which consists primarily of $533,549 in general and administrative expenses, $131,105 of which are non-cash stock based compensation,  depreciation, depletion and amortization of $116,847 and accretion of convertible note discounts $138,194. We expect to continue to use cash flow in operating activities until such time as we achieve sufficient commercial oil and gas production to cover all of our cash costs.

Cash flow used in investing activities for quarter ended March 31, 2014 was $5,263,091 compared to $198,918 for the quarter ended March 31, 2013.  Cash flow used in investing activities consists primarily of oil and gas investments in Oklahoma and Kansas properties acquired during the quarter ended March 31, 2014.

Cash flow provided by financing activities for the quarter ended March 31, 2014 was $5,768,784 as compared to $1,576,680 for the quarter ended March 31, 2013.  Cash flow provided by financing activities consists primarily of proceeds from common stock issues and warrant exercises.  We expect to continue to have cash flow provided by financing activities as we seek new rounds of financing and continue to develop our oil and gas investments.

Our current assets are insufficient to meet our current obligations or to satisfy our cash needs over the next twelve months and as such we will require additional debt or equity financing. Subsequent to December 31, 2013, we received net proceeds of approximately $5.57 million from the offering of units of equity consisting of our common stock and warrants, but these proceeds will not be sufficient to fund all of our proposed drilling operations and operating needs during 2014. We will seek additional financing to meet our drilling plans and needs.  We face obstacles in continuing to attract new financing due to our history and current record of net losses and working capital deficits. Therefore, despite our efforts we can provide no assurance that we will be able to obtain the financing required to meet our stated objectives or even to continue as a going concern.

We do not expect to pay cash dividends in the foreseeable future.

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Report of Independent Registered Public Accounting Firm, page F-1

26. We note your going concern disclosure in Note 2 “Going Concern” on F-6 as well as in Item 1A, Risk Factors in light of accumulated losses and unprofitable operations. Please tell us why your independent accountant did not include a going concern explanatory paragraph within in its audit report dated March 31, 2014.

In response to the Staff’s Comment 26, our independent accountant stated,

“We as the auditors of Torchlight Energy Resources, Inc. determined, after consideration of management’s plans, that substantial doubt about the entity’s ability to continue as a going concern for a reasonable period of time had been alleviated.  We considered it necessary to disclose the principal conditions that initially caused us to believe there was substantial doubt and disclose management’s plans.  This is why our opinion did not include an emphasis of matter paragraph within our audit report, but we did feel the need to disclose the conditions and managements plans per the guidance in AU-C Section 570 ‘The Auditor’s Consideration of an Entity’s Ability to Continue as a Going Concern’”.

Also in response to the Staff’s Comment 26, we have revised Note 2 “Going Concern” on F-6, and the referenced risk factor, which risk factor has been renamed.  We have also revised a similar risk factor in the S-1 registration statement.

The revised Note 2 “Going Concern” is set forth immediately below:

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2. GOING CONCERN

These consolidated financial statements have been prepared in accordance with generally accepted accounting principles applicable to a going concern, which assumes that the Company will be able to meet its obligations and continue its operations for its next fiscal year.

At December 31, 2013, the Company had not yet achieved profitable operations, had accumulated losses of $15,840,959 since its inception and expects to incur further losses in the development of its business.  The Company’s ability to continue as a going concern is dependent on its ability to generate future profitable operations and/or to obtain the necessary financing to meet its obligations and repay its liabilities arising from normal business operations when they come due.  Management’s plan to address the Company’s ability to continue as a going concern includes:  (1) obtaining debt or equity funding from private placement or institutional sources; (2) obtain loans from financial institutions, where possible, or (3) participating in joint venture transactions with third parties.  Although management believes that it will be able to obtain the necessary funding to allow the Company to remain a going concern through the methods discussed above, there can be no assurances that such methods will prove successful.  The accompanying consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

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The revised risk factor in the Form 10-K is set forth immediately below:

Page 23 of 31

We have not yet achieved profitable operations, have significant accumulated losses since our inception, and expect to incur further losses in the development of our business

At December 31, 2013, we had not yet achieved profitable operations, had accumulated losses of $15,840,959 since our inception, and expect to incur further losses in the development of our business.  Our ability to continue as a going concern is dependent upon our ability to generate future profitable operations and/or to obtain the necessary financing to meet our obligations and repay our liabilities arising from normal business operations when they come due. Management's plan to address our ability to continue as a going concern includes: (1) obtaining debt or equity funding from private placement or institutional sources; (2) obtaining loans from financial institutions, where possible, or (3) participating in joint venture transactions with third parties. Although management believes that it will be able to obtain the necessary funding to allow us to remain a going concern through the methods discussed above, there can be no assurances that such methods will prove successful. The accompanying financial statements do not include any adjustments that might result from the outcome of this uncertainty.

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Notes to Consolidated Financial Statements

Note 1, Nature of Business, F-6

27. You have disclosed that TEI, your wholly-owned operating subsidiary, is an exploration stage energy company. Please tell us the events and circumstances that led to the conclusion you are no longer in the exploration stage and no longer present the disclosures required by FASB ASC 915-205-45-2 through 45-4 and 915-235-50-1.

In response to the Staff’s Comment 27, the disclosure stating that TEI is an exploration stage company was made inadvertently, and we have revised this disclosure in Note 1.  Neither we nor TEI are or were as of December 31, 2013 an exploration stage company.  Under the SEC’s Industry Guide 7(a), exploration stage companies are defined as “all issuers engaged in the search for mineral deposits (reserves) which are not in either the development or production stage.”  The Company was spending significant amounts of capital on development and started to have material amounts of production in 2013.  Accordingly, we believe the Company should no longer be deemed an exploration stage company.

28. Please provide the disclosures required by FASB ASC 932-235-50.  In addition, please provide your ceiling test calculation to support your capitalized oil and gas property costs for fiscal years 2013 and 2012.

In response to the Staff’s Comment 28, we believe the revisions we made to the “Oil and Natural Gas Reserves” section above, in connection with the Staff’s Comments 11, 12, 13 and 14, provide the disclosures required by FASB ASC 932-235-50.  We have included our ceiling test calculation as an attachment to this letter.

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Item 11. Executive Compensation, page 29

29. You disclose in footnote 5 to the summary compensation table that you did not include Mr. McAndrew’s 1,500,000 options granted in September 2013 as they had not vested as of December 2013.  Please revise to include these options in the summary compensation table.  Please see Item 402(n)(2)(vi) of Regulation S-K.

In response to the Staff’s Comment 29, we have revised the “Summary Executive Compensation Table” on page 29, which revised table is included in its entirety below.

The revised “Summary Executive Compensation Table” is set forth immediately below:

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Summary Executive Compensation Table

Name and Principal Position	Year	Salary ($)	Bonus ($)	Stock Awards ($)	Option Awards ($)	Non-Equity Incentive Plan Compensation ($)	Change in Pension Value and Nonqualified Deferred Compensation ($)	All Other Compensation ($)	Total ($)
Thomas Lapinski CEO/Director	2013	180,000	-	-	355,250 (1)	-	-	-	535,250
	2012	240,000 (2)	-	-	-	-	-	-	240,000
John A. Brda President/Director	2013	205,000	-	-	355,250 (3)	-	-	-	560,250
	2012	240,000 (4)	-	-	-	-	-	-	240,000
Willard G. McAndrew III	2013	60,000	-	-	2,225,000 (5)	-	-	75,000 (6)	2,360,000
COO/Director	2012	-	-	-	-	-	-	-	-
Roger Wurtele CFO	2013	40,000	-	-	180,000 (7)	-	-	52,500 (6)	272,500
	2012	-	-	-	-	-	-	-	-

(1) On September 4, 2013, we granted Mr. Lapinski a fully vested option to purchase 245,000 shares of stock at an exercise price of $2.00 per share.  The value of these options was determined using the Black Scholes Method.

(2) In September 2013, Mr. Lapinski forgave a total of $489,000 in outstanding indebtedness in connection with his then accrued and unpaid compensation, which included this unpaid salary for 2012.

(3) On September 4, 2013, we granted Mr. Brda a fully vested option to purchase 245,000 shares of stock at an exercise price of $2.00 per share.  The value of these options was determined using the Black Scholes Method.

(4) In September 2013, Mr. Brda forgave a total of $240,000 in outstanding indebtedness in connection with his then accrued and unpaid compensation, which included this unpaid salary for 2012.

(5) Prior to his appointment as COO in September, 2013, during 2013 we granted him a fully vested warrant to purchase 1,000,000 shares of stock at an exercise price of $2.09 per share as consideration for consulting services, valued at $890,000. In September 2013, we granted Mr. McAndrew an option to purchase 1,500,000 shares of stock at an exercise price of $2.09 per share, which was to vest over upon certain performance thresholds and was valued at $1,335,000. The value of the options was determined using the Black Scholes Method.

(6) This amount represents consulting fees paid prior to the effective date of employment with the Company.

(7) In October 2013, we granted Mr. Wurtele an option to purchase 300,000 shares of stock at an exercise price of $2.09 per share.  100,000 of the options vested immediately, with the remaining options to vest on the first and second anniversaries of his employment. The value of these options was determined using the Black Scholes Method.

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30. Please revise to briefly discuss how the amount of options granted to each named executive officer was determined.  Please see Item 402(o)(1) of Regulation S-K.

In response to the Staff’s Comment 30, we have added a new section, “Setting Executive Compensation” on page 30, after the “Summary Executive Compensation Table,” which new section is included in its entirety below.

The revised “Setting Executive Compensation” section is set forth immediately below:

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Setting Executive Compensation

We fix executive base compensation at a level we believe enables us to hire and retain individuals in a competitive environment and to reward satisfactory individual performance and a satisfactory level of contribution to our overall business goals. We also take into account the compensation that is paid by companies that we believe to be our competitors and by other companies with which we believe we generally compete for executives.

In establishing compensation packages for executive officers, numerous factors are considered, including the particular executive’s experience, expertise and performance, our company’s overall performance and compensation packages available in the marketplace for similar positions. In arriving at amounts for each component of compensation, our Compensation Committee strives to strike an appropriate balance between base compensation and incentive compensation. The Compensation Committee also endeavors to properly allocate between cash and non-cash compensation (including without limitation stock and stock option awards) and between annual and long-term compensation.

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Security Ownership of Certain Beneficial Owners and Management, page 32

31. It is not clear whether the table reflects all shares issuable upon conversion of notes or exercise of warrants within the next 60 days.  Please advise or revise.

In response to the Staff’s Comment 31, we have revised the sentence in the first paragraph under Item 12 on page 33.  The sentence was previously: “In computing the number of shares of common stock beneficially owned by a person and the percentage ownership of that person, we deemed outstanding shares of common stock subject to stock options or warrants held by that person that are currently exercisable or exercisable within 60 days of March 20, 2014.”  The sentence as revised is:

“In computing the number of shares of common stock beneficially owned by a person and the percentage ownership of that person, we deemed outstanding shares of common stock subject to stock options or warrants held by that person that are currently exercisable or exercisable within 60 days of March 20, 2014 and shares of common stock issuable upon conversion of other securities held by that person that are currently convertible or convertible within 60 days of March 20, 2014.”

Item 15. Exhibits, page 36

32. We note the Form 10-K is incorporated by reference into your Form S-1.  Please obtain and file as an exhibit the consents Netherland, Sewell & Associates, Inc. and Wright & Company, Inc. regarding the references to such firms, the use of information contained in and the inclusion of the reserve reports filed as Exhibit 99.1 to the annual filing on Form 10-K and incorporated into a registration statement.

In response to the Staff’s Comment 32, we have filed as an exhibit to the Form S-1/A the consents Netherland, Sewell & Associates, Inc. and Wright & Company, Inc.

33. Please file all material exhibits including the following:

· the Coulter Limited Partnership Agreement;

· the  promissory note and amendment referenced on page 8;

· the promissory notes discussed in Note 8 to the financial statements; and

· the relevant securities purchase agreement and registration rights agreement associated with the private placements conducted in December 2013 and January 2014.

Please see Item 601(b)(4) and (b)(10) of Regulation S-K.

Page 30 of 31

In response to the Staff’s Comment 33, we will file the requested document as exhibits with the Form 10-K/A.

The Company acknowledges that:

· should the Commission or the Staff, acting pursuant to delegated authority, declare the filing effective, it does not foreclose the Commission from taking any action with respect to the filing;

· the action of the Commission or the Staff, acting pursuant to delegated authority, in declaring the filing effective, does not relieve the Company from its full responsibility for the adequacy and accuracy of the disclosure in the filing; and

· the 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.

If you should need clarification or any additional information in connection with your inquiries, please contact me.  Thank you for your help in this matter.

Very truly yours,

/s/ John A. Brda

John A. Brda,

President

cc:  Angie Kim Division of Corporation Finance U.S. Securities & Exchange Commission 100 F Street, NE Washington, D.C.  20549

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