CORRESP 1 filename1.htm

January 20, 2016

Securities and Exchange Commission

Judiciary Plaza

450 Fifth Street, NW

Washington, DC 20549

Attention: H. Roger Schwall

Re:	EnerJex Resources, Inc.
	Form 10-K for the Fiscal Year Ended December 31, 2014
	Filed March 31, 2015
	Definitive Proxy Statement on Schedule 14A
	Filed April 3, 2015
	File No. 1-36492

Dear Mr. Schwall

In response to your letter dated December 21, 2015, set forth below are your comments concerning the EnerJex Resources, Inc.'s Form 10-K and Definitive Proxy Statement referred to above, and our responses. Your comments are in italics and are followed by our response.

Form 10-K for the Fiscal Year Ended December 31, 2014

Business and Properties, page 4

Reserves, page 11

Please expand the tabular presentations on pages 11, 34 and F-19 to separately disclose material reserves by product type of crude oil including condensate, natural gas liquids and natural gas. You may refer to Item 1202(a)(1) of Regulation S-K and FASB ASC 932-235-55-2 for illustrations of the presentation requirements of Item 1202(a)(4) of Regulation S-K and FASB ASC 932-235-50-4 and 50-5.

EnerJex response:

We plan to include the following information in our Form 10-K for the fiscal year ended December 31, 2014, under Business and Properties – Reserves, and to include similar information in other future filings:

4040 Broadway, Suite 508 | San Antonio, TX 78209 | 210-451-5545 (P) | 210-463-9297 (F)

Summary of Proved Oil and Gas Reserves

as of December 31, 2014

	Gross								Net								PV10 (before tax)
	Crude Oil		Natural Gas Liquids		Natural Gas		Oil Equivalents		Crude Oil		Natural Gas Liquids		Natural Gas		Oil Equivalents
Proved Reserves Category	BBL		BBL		MCF		BOE		BBL		BBL		MCF		BOE
Proved, Developed		3,067,808		114,021		8,387,078		4,579,675		2,271,183		90,851		4,117,356		3,048,261		51,942,200
Proved, Undeveloped		931,287		-		4,940,000		1,754,621		675,266		-		4,059,920		1,351,919		12,376,500
Total Proved		3,999,096		114,021		13,327,079		6,334,296		2,946,449		90,851		8,177,276		4,400,180		64,318,700

Based on the disclosure provided on page F-19, there appears to be a material change in proved undeveloped reserves compared to the disclosure of such reserves as of December 31, 2013. Under Item 1203(b) of Regulation S-K you are required to disclose material changes in proved undeveloped reserves that occurred during the year, including proved undeveloped reserves that were converted to developed reserves. Please expand your disclosure to provide both a tabulation and narrative explanation for the net changes in reserve quantities relating to revisions, extensions/discoveries, acquisition/divestiture, improved recovery and the amounts converted during the year from proved undeveloped to proved developed, including sufficient details to reconcile and understand the overall change in net reserves.

EnerJex response:

We respectfully submit that at the time of preparation and filing of our Annual Report, we considered the referenced regulations. The downward revisions in previous reserve estimates is primarily related in revised forecasted declines rates in the Cherokee Project. Our third party engineering firm, MHA Petroleum Consultants revised their decline curve forecast methodology in response to actual 2014 production performance data that fell short of forecasts using the original methodology. These revisions resulted in a decrease in the estimated proved developed reserves of approximately 600,000 BOE and proved undeveloped reserves of approximately 600,000 BOE. We sold the Cherokee Project assets in the second quarter of 2015.

Please expand your disclosure to include the information required under Item 1203(c) of Regulation S-K, regarding “…investments and progress made during the year to convert proved undeveloped reserves to proved developed reserves, including, but not limited to, capital expenditures.” This should include a discussion of the progress you have made during the year to convert your proved undeveloped reserves to developed and quantify the capital expenditures incurred in converting your proved undeveloped reserves to developed for this period of time.

EnerJex response:

4040 Broadway, Suite 508 | San Antonio, TX 78209 | 210-451-5545 (P) | 210-463-9297 (F)

In 2014 of the $7.1 million of capital invested on oil and gas properties, approximately $6.4mm was spent developing oil and gas assets the remaining amount was spent acquiring leasehold positions. Approximately $2.0 million was spent drilling and completing proved undeveloped location in the Company’s Kansas properties with $1.4 million allocated to its Mississippian project and $.6 million allocated to its Cherokee project. In Colorado approximately $1.0mm was invested in an oil trunk line in the Adena field and a gas tap and pipeline in the Amherst field. Approximately $3.4mm was invested recompleting and reactivating well in the Adena field. The proved undeveloped investment rate was dramatically decreased in the fourth quarter in response to falling commodity prices. The Company’s reserve report estimates $13.5 million of remaining future development costs. The Company will have $3.1 million of cash on hand and estimates approximately $3.0 million of unrealized hedge gains at year end. Given that the Company expects to have approximately fifty percent of cash and liquid assets on hand to meet future estimated development costs, we believe that the readers of our financial statement are best served by an expanded disclosure in the 2015 Annual Report on Form 10-K and all subsequent interim 2016 interim reporting that specifically addresses: (1) our liquidity position, (2) our rationale as to why we choose not to deploy capital until there has been a recovery in commodity prices, and (3) a full discussion of any deterioration to our liquidity position should that occur in 2016 and the impact on our ability to convert proved undeveloped reserves into proved producing reserves in compliance with item 1203 (c) of Regulation S-K.

We note you disclose that proved undeveloped reserves at December 31, 2014 represent approximately 31% of total proved reserves. Please expand your disclosure to explain your development plans sufficiently to understand how you have complied with the timeframe stipulated for development within Rule 4-10(a)(31)(ii) of Regulation S-X, and how you have formulated a reasonable expectation that any financing necessary to proceed with development will be available, as required by Rule 4-10(a)(26) of Regulation S-X, prior to reporting these reserves. You should also disclose the information required by Item 1203(d) of Regulation S-K, regarding the extent to which any of your proved undeveloped reserves will not be developed within five years of your initial disclosure of these reserves.

If you expect that any of your proved undeveloped reserves will take more than five years to develop since initial disclosure, please refer to the answer to question 131.03 in our Compliance and Disclosure Interpretations (C&DIs), and describe for us the specific circumstances that you believe justify an extended period of time. You may find the C&DIs on our website at http://www.sec.gov/divisions/corpfin/guidance/oilandgas-interp.htm.

EnerJex response:

When we file our 2015 Annual Report on Form10-K, we will report over $3.1 million of cash and approximately $3.0 million of unrealized hedge gains at December 31, 2015. We also believe working capital at year end will be positive and the current ratio will be greater than 1:1. Therefore at year-end the Company will have half of the funds on hand necessary for future development costs estimated in 2014 to be $13.5 million. While oil and gas prices are volatile and unpredictable, we believe in the next four years prices will increase sufficiently to warrant the prudent deployment of capital to finish these development plans. Further, if this doesn’t occur, we have the ability to enter into joint ventures (as we have done with other oil and gas assets) with these assets to complete the conversion of these undeveloped locations. We believe our balance sheet provides us the wherewithal to develop these reserves in the next four years. Should there be a protracted delay in commodity prices recovery lasting four years we would implement a joint venture to complete the development of these reserves.

4040 Broadway, Suite 508 | San Antonio, TX 78209 | 210-451-5545 (P) | 210-463-9297 (F)

We respectfully submit that instead of expanding our prior disclosures that we could better serve the readers of our Annual Report and financial statements with an expanded discussion of future development plans for the next four years in the Company’s annual and quarterly reports that specifically address: (1) liquidity, (2) our position and rationale as to our decision to deploy or not deploy capital at that time and (3) a full discussion of any deterioration to our liquidity should that occur and how this would impact our ability to convert proved undeveloped reserves into proved producing reserves within the four year time frame.

We note the disclosures on pages 22, 34 and F-19 indicate the estimates of reserves and future net cash flows attributable to those reserves at December 31, 2014 were prepared by MHA Petroleum Consultants LLC, an independent petroleum consultant. Please obtain and file a report from that firm, including all of the information specified in Item 1202(a)(8) of Regulation S-K.

EnerJex response:

We plan to include as an exhibit to our Form 10-K for the fiscal year ended December 31, 2014 the letter from MHA Petroleum Consultants LLC attached hereto as Exhibit A.

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 33

We note your disclosures among Risk Factors on pages 20 and 21 stating “Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our planned operations and financial condition” and “A substantial or extended decline in oil and gas prices would materially and adversely affect our future business enough to potentially force us to cease our business operations.”

The disclosures in your third quarter report indicate that the decline in commodity prices has led to substantial curtailment of capital expenditures, impairment of your oil and gas properties of $37.5 million (58% of the property account at the beginning of the year), and the sale of producing assets to fund cash obligations.

However, we do not see any disclosure in the MD&A of your periodic filings explaining how known trends, demands, commitments, events and uncertainties are reasonably likely to affect your liquidity, capital resources and results of operations, or are reasonably likely to cause your reported financial information not to be necessarily indicative of your future operations or future financial condition.

Please comply with Item 303(a) and (b) of Regulation S-K. You may find the guidance in Instructions 2, 3, 4 and 5 helpful in formulating your disclosures and quantifying the reasonably likely effects of known trends, demands, commitments, events and uncertainties on your reserves, development plans and accounting.

You may also refer to the guidance in FRC §§ 501.12.a, 501.12.b.3, and 501.14 (Sections III.A, III.B.3, and V of SEC Release Nos. 33-8350; 34-48960; FR-72), as it relates to disclosures in an introductory section or overview, the effects of material trends and uncertainties, and critical accounting estimates.

EnerJex response:

We respectfully submit that at the time of preparation and filing of our Annual Report, we considered the referenced regulations and guidance and determined that we did not have a reasonable basis to quantify known trends, demands, commitments, events and uncertainties that are reasonably likely to affect our liquidity, capital resources and results of operations, or that are reasonably likely to cause our reported financial information not to be necessarily indicative of our future operations or future financial condition.

4040 Broadway, Suite 508 | San Antonio, TX 78209 | 210-451-5545 (P) | 210-463-9297 (F)

At the time the referenced risk factors were prepared and disclosed in our 2014 Annual Report, pricing determined pursuant to SEC guidelines ranged from $53.27 to $50.09. We believe the risk factors are true in the long term but due to the unpredictability of commodity prices could just as likely ameliorate over the short term. We note that the cited MD&A regulations and guidance as to reasonably likely impacts of known trends and uncertainties do not mandate quantifying estimates if not reasonably available. We further submit that a reasonable basis would be required for determining and disclosing such forward–looking quantitative information. We interpreted the disclosure requirements as requiring a basis that results in information that would be reasonably meaningful to investors, which would not include arbitrary single point estimates or ranges of outcomes that would be so broad as to be more confusing than informative.

Therefore we believed it prudent to wait for a trend to develop given our confidence in our strong balance sheet to outlast the market declines in crude oil prices.

On March 31, 2015 the Company reported almost $1 million in cash, $4.7 million of unrealized hedge gains and working capital of $3.3 million and a working capital ratio of 1.8:1.

By May 15, 2015 the Company liquidity and capital resources improved as $2.9 million of cash, $4.6 million of unrealized hedge gains and working capital of $6.3 million and a working capital ratio of 2.8:1 was reported. Additionally, first of month prices improved ranging from $59.15 to $60.20.

By mid-year our liquidity and capital resources decreased slightly as on August 14, 2015 we reported $1.9 million of cash, $2.6 million of unrealized hedge gains and working capital of $4.1 million and a working capital ratio of 2.1:1 in our quarterly report on Form 10-Q for the second quarter of 2015, and first of month pricing ranged between $47.12 and 45.41. Although liquidity had trended down it still reflected a stable financial condition for the Company.

At the end of our third quarter in 2015 we saw an improvement in our liquidity and capital resources reporting $3.0 million of cash, $3.1 million of unrealized hedge gains and working capital of $5.6 million and a working capital ratio of 3.1:1 in our quarterly report on Form 10-Q for the third quarter of 2015.

On page 13 of each of our first, second and third quarter interim reports we discuss potential negative impacts to future results of operations, and on page 17 of our third quarter interim report we expanded on this theme.

Throughout all of 2015 we maintained or improved our working capital and improved our liquidity from yearend 2014 to year end 2015.

We respectfully submit that our quarterly reporting regarding liquidity and capital resources adequately disclosed an improving situation while acknowledging risk did not unduly emphasize the negative potentially misleading readers of the financial statements. Further, in light of the passage of a significant amount of time since the preparation and filing of our 2014 Annual Report, we believe that the actual outcomes in the first, second and third quarters of 2015 supported our concern that providing such quantifying estimates in the Annual Report based on the information we had at the time would not have been informative and could have been potentially misleading.

When we file our 2015 10-K, we will report over $3.1 million of cash and approximately $3.0 million of unrealized hedge gains at December 31, 2015. We also believe working capital at year end will be positive and the current ratio will also be good.

Because of these facts and our belief that we will be able to maintain a strong balance sheet though out 2016, we respectfully submit that your comment will be addressed more appropriately in our 2015 Annual Report on Form 10-K and all subsequent interim reporting to occur in 2016, in which we will specifically address in each report: (1) our liquidity, (2) our position and rationale as to why we choose not to deploy capital until there has been a recover in commodity prices, and (3) a full discussion of any deterioration to our liquidity position should that occur in 2016 and the impact it would have on results of operations and future results of operations in accordance with Item 303 (a) and (b) of Regulation S-K

4040 Broadway, Suite 508 | San Antonio, TX 78209 | 210-451-5545 (P) | 210-463-9297 (F)

Definitive Proxy Statement on Schedule 14A

Executive Compensation, page 13

Please ensure your executive compensation table discloses compensation earned for each named executive officer rather than an annual compensation rate. See Item 402(n)(2)(iii) of Regulation S-K. In that regard, we note footnotes (1) and (2) to your executive compensation table reflect that compensation figures for Mr. Kunovic in 2013 and Mr. Roach in 2014 represent an annual compensation rate rather than the compensation earned.

EnerJex response:

We plan to revise the executive compensation table in our 2015 Definitive Proxy Statement on Schedule 14A to read as follows, and to include similar information in other future filings:

	Fiscal Year		Salary		Bonus		Stock Awards		Option Awards		All Other Compensation		Total
Name and Principal Position			($)		($)		($)		($)		($)		($)
Robert G. Watson, Jr.
President, Chief Executive Officer		2014		225,000				—		76,900		—		301,900
		2013		225,000		35,000		—		76,900		—		336,900

Douglas M. Wright
Chief Financial Officer		2014		168,000		—				95,800		—		263,800
		2013		150,000		—		132,000		53,200		—		335,200

David L. Kunovic⁽¹⁾
Executive Vice President,		2014		168,000		—		—		94,700		—		262,700
Exploration
		2013		43,077		—		—		23,700		—		66,777

Kent A. Roach⁽²⁾
Executive Vice President,		2014		45,127		—								45,127
Engineering

Ryan A. Lowe
Senior Vice President of		2014		80,000		—		—		—		—		80,000
Corporate Development		2013		80,000		25,000		__		__		__		105,000

(1) David L. Kunovic was hired on September 27, 2013, and the compensation figures in the table above represent his actual compensation rate for 2013.

(2) Kent Roach was hired on October 15, 2014, and the compensation figures in the table above represent his actual compensation rate.

4040 Broadway, Suite 508 | San Antonio, TX 78209 | 210-451-5545 (P) | 210-463-9297 (F)

We hereby acknowledge that:

the Company is responsible for the adequacy and accuracy of the disclosure in the filing;

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

the Company 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.

If you have any questions or would like to discuss our responses above, you may contact our outside counsel, Fernando Velez, Jr. of Reicker, Pfau, Pyle & McRoy, LLP, at 805-966-2440, or me at 210-451-5545.

	Very truly yours,

	/s/ Douglas M. Wright

	Douglas M. Wright
	Chief Financial Officer

Exhibit A – Letter from MHA Petroleum Consultants dated January 11, 2016

cc: Fernando Velez – via email

4040 Broadway, Suite 508 | San Antonio, TX 78209 | 210-451-5545 (P) | 210-463-9297 (F)

Exhibit A

Letter from MHA Petroleum Consultants, LLC

MHA Logo Final

January 11, 2016

Mr. Robert Watson Jr.

President and CEO

Enerjex Resources

4040 Broadway, Suite 508

San Antonio, Texas 78209

Dear Mr. Watson:

In accordance with your request, we have evaluated the assets of Enerjex Resources (Enerjex), as of January 1, 2015. This includes the proved, probable and possible reserves and future revenue to the Enerjex interest’s in certain oil and gas properties located in Colorado, Nebraska, Kansas, and Texas. It is our understanding that the proved reserves estimated herein constitute all of the proved reserves owned by Enerjex. We have examined the estimates with respect to reserves quantities, reserves categorization, future producing rates, future net revenue, and the present value of such future net revenue, using the definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a). The estimates of reserves and future revenue have been prepared in accordance with the definitions and regulations of the SEC and conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas, except that per-well overhead expenses are excluded for the operated properties and future income taxes are excluded for all properties. We completed our analysis on or about the date of this letter. This report has been prepared for Enerjex's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

The following table sets forth our estimates of the net reserves and future net revenue, as of January 1, 2015 for the proved, probable and possible properties:

Enerjex Resources Proved Plus Probable Plus Possible Reserves Estimated Net Reserve and Income Data As of January 1, 2015
	Net Remaining Reserves
Reserve Category	Oil MBBL	Gas MMCF	NGL MBBL	Future Net Income M$	Direct Operating Expense & Taxes M$	Equity Investment M$	Undisc. Net Cash Flow M$	Discounted Net Cash Flow @ 10% M$
PDP	1,844.7	1,804.2	76.7	164,938.8	64,623.1	9.0	100,306.8	42,258.7
PNP	426.5	2,313.3	14.2	42,386.2	15,277.2	3,178.1	23,930.9	9,683.5
PUD	675.3	4,059.9	0.0	75,232.8	21,219.2	10,549.5	43,464.2	12,376.5
Total Proved	2,946.5	8,177.4	90.9	282,557.8	101,119.5	13,736.6	167,701.9	64,318.7
PRB	503.5	16,170.5	10.8	111,811.2	26,527.4	15,560.0	69,723.8	23,461.3
POS	1,390.1	39,897.8	6.5	286,879.1	69,643.8	34,457.7	182,777.6	65,327.0
Infrastructure Costs	0.0	0.0	0.0	0.0	0.0	3,991.5	-3,991.5	-3,991.5
Total	4,840.1	64,245.7	108.2	681,248.1	197,290.7	67,745.8	416,211.8	149,115.5

The oil volumes shown include crude oil and condensate. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

When compared on a well-by-well basis, some of the estimates of Enerjex are greater and some are less than the estimates of MHA Petroleum Consultants, LLC (MHA). However, in our opinion the estimates of proved reserves and future revenue shown herein are, in the aggregate, reasonable and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards.

Oil and gas prices used are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period covering 2014.

Operating costs are based on historical operating expense records. For the nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs for the operated properties include only direct lease- and field-level costs. Operating costs have been divided into per-well costs and per-unit-of-production costs for those properties reported on a lease basis. Capital costs are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Operating costs and capital costs are not escalated for inflation. Estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, estimates of MHA are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Enerjex, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing these estimates.

MHA uses standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to establish the conclusions set forth herein. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

Supporting data documenting this evaluation, along with data provided by Enerjex, are on file in our office. The technical person primarily responsible for conducting this analysis meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards.

We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,

MHA Petroleum Consultants, LLC

Leslie S. O’Connor

Managing Partner

CERTIFICATION OF QUALIFICATION

LESLIE S. O’CONNOR

Managing Partner

Petroleum Consultant

MHA Petroleum Consultants LLC

730 17^th Street, Suite 410

Denver, CO 80202

Phone: +1 303 277 0270

e-mail: loconnor@mhausa.com

EDUCATION

Extended BSc Geology with Applied Engineering, North Arizona University, 1978

Graduate Studies in Petroleum Engineering, Colorado School of Mines

PROFESSIONAL PROFILE

In excess of 35 years of petroleum engineering experience

Project management

Oil and gas field studies; United States, China, Mexico, South America, Western and Eastern Europe and Asia

Petrophysical studies

Unitization studies

Workover opportunity identification

Property evaluation, acquisition and divestitures

Reservoir and economic evaluation

Expert witness testimony

Gas deliverability and gas storage

Coal bed methane studies

Reservoir simulation

Waterflood feasibility studies

Development of reservoir engineering courses for industry

Studied fields in the United States (essentially all oil and gas areas), U.K. Offshore, China, Mexico, South America, Western and Eastern Europe and Asia

WORK EXPERIENCE

MHA PETROLEUM CONSULTANTS LLC, Denver, Colorado:

(August 2011) Managing Partner and Petroleum Consultant

(March 2008) President and Petroleum Consultant

(May 2006) Vice President and Petroleum Consultant

Responsible for Denver and International operations: project manager, reserve and economic evaluations, litigation support, reservoir studies, acquisition and divestiture support. Manages an organization of approximately 30 people with active engineering projects worldwide. In charge of staff recruitment, development of new business and new business contacts, as well as maintaining relationships with the company’s existing client base.

SPROULE ASSOCIATES INC., Denver, Colorado

(February, 1997 to May, 2006) U. S. Manager and Petroleum Consultant

Responsible for U. S. operations; opened U. S. office for Sproule Associates Ltd. Project manager, reservoir studies, property evaluations, litigation support, acquisition and divestiture support, CBM studies, petrophysical studies, feasibility studies, reservoir and economic studies of properties throughout the U. S.

GEOQUEST RESERVOIR TECHNOLOGIES, DENVER, Colorado:

(Formerly Intera Petroleum and Jerry R. Bergeson & Associates, Inc.)

(January, 1981 to January, 1997) Petroleum Consultant

Technical reservoir studies, property evaluations, secondary recovery studies, gas deliverability and gas storage, petrophysical studies, unitization studies, expert testimony, reservoir and economic studies of properties in Williston Basin, Rocky Mountain, Mid-Continent, West Coast and Gulf Coast areas of the U. S.

THUMS LONG BEACH COMPANY, Long Beach, California:

(January, 1980 to January, 1981) Development/Drilling Engineer

Responsible for design of highly deviated wellbores, completion design, field operations.

Dresser Atlas, Long Beach, California:

(August, 1978 to December, 1979) Field Engineer

Open hole logging operations and log interpretation. Supervised field crew, planned and operated offshore skid unit on Exxon’s offshore Belmont Island platform.

PROFESSIONAL MEMBERSHIPS:

Society of Petroleum Engineers – Recipient of the 1995 Regional Service Award

Society of Petroleum Engineers -Recipient of the 1990 Denver Section Service Award

Society of Petroleum Engineers-Recipient of the 2014 Regional Service Award

Society of Petroleum Evaluation Engineers

American Association of Petroleum Geologists

Society of Professional Well Log Analysts

Rocky Mountain Association of Geologists

AAPG Certified Petroleum Geologist #5270; Board Certified by Division of Professional Affairs

Licensed Professional Geoscientist, Texas #181

Licensed Professional Geologist, Wyoming #PG-3059

Licensed Professional Geologist, Utah #5207412-2250

Licensed Professional Geoscientist, Louisiana #14