Exhibit 99.3

 

AMERICAN EAGLE ENERGY CORPORATION

 

 

Estimated

 

Future Reserves and Income

 

Attributable to Certain

 

Leasehold Interests

 

 

SEC Parameters

 

 

As of

 

June 30, 2014

 

 

James L. Baird, P.E.		Clark D. Parrott, P.E.
Colorado License No. 41521		Colorado License No. 35262
Managing Senior Vice President		Petroleum Engineer

 

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

  

 

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

 

 

July 14, 2014

 

American Eagle Energy Corporation

2549 West Main Street, Suite 202

Littleton, CO 80120

 

Gentlemen:

 

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved, probable and possible reserves, future production, and income attributable to certain leasehold interests of American Eagle Energy Corporation (AEE) as of June 30, 2014. The subject properties are located in the state of North Dakota and province of Saskatchewan, Canada. The proved reserves were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). The probable and possible reserves were estimated based on the definitions and disclosure guidelines contained in the Society of Petroleum Engineers (SPE), World Petroleum Council (WPC), American Association of Petroleum Geologists (AAPG), and Society of Petroleum Evaluation Engineers (SPEE) Petroleum Resources Management System (SPE-PRMS). The income data for all categories of reserves were estimated using the SEC requirements for future price and cost parameters. The results of our third party study, completed on July 14, 2014, are presented herein.

 

The properties evaluated by Ryder Scott represent 100 percent of the total net proved, probable and possible liquid hydrocarbon reserves and 100 percent of the total net proved, probable and possible gas reserves of AEE as of June 30, 2014.

 

The estimated reserves and future income amounts presented in this report, as of June 30, 2014, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on SEC parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.

 

 

American Eagle Energy Corporation

July 14, 2014

Page 2

 

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold Interests of

American Eagle Energy Corporation

As of June 30, 2014

		Proved – SEC Definitions
		Developed												Total
		Producing				Non-Producing				Undeveloped				Proved
Net Remaining Reserves
Oil/Condensate – MBarrels			4,671				699				8,373				13,743
Gas – MMCF			3,480				485				6,078				10,043
Income Data (M$)
Future Gross Revenue		$	386,497			$	57,672			$	692,082			$	1,136,251
Deductions			93,995				14,261				335,185				443,441
Future Net Income (FNI)		$	292,502			$	43,411			$	356,897			$	692,810
Discounted FNI @ 10%		$	169,168			$	26,205			$	140,663			$	336,036

 

		SPE-PRMS Definitions
		Total				Total
		Probable				Possible
		Undeveloped				Undeveloped
Net Remaining Reserves
Oil/Condensate – MBarrels			2,222				2,487
Gas – MMCF			1,624				1,818
Income Data (M$)
Future Gross Revenue		$	183,761			$	205,657
Deductions			102,701				106,273
Future Net Income (FNI)		$	81,060			$	99,384
Discounted FNI @ 10%		$	26,655			$	35,847

 

Liquid hydrocarbons are expressed in standard 42 gallon barrels and shown herein as thousands of barrels (MBarrels). All gas volumes are reported on an “as sold” basis expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).

 

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package Aries^TM System Petroleum Economic Evaluation Software, a copyrighted program of Halliburton. The program was used at the request of AEE. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

 

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

 

 

American Eagle Energy Corporation

July 14, 2014

Page 3

 

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells and development costs. The future net income is before the deduction of U.S. state and federal or foreign income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income.

 

Liquid hydrocarbon reserves account for approximately 96 percent of the total future gross revenue from proved reserves and gas reserves account for the remaining 4 percent of total future gross revenue from proved reserves. Liquid hydrocarbon reserves account for approximately 96 percent of the total future gross revenue from probable reserves and gas reserves account for the remaining 4 percent of total future gross revenue from probable reserves. Liquid hydrocarbon reserves account for approximately 96 percent of the total future gross revenue from possible reserves and gas reserves account for the remaining 4 percent of total future gross revenue from possible reserves.

 

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

 

		Discounted Future Net Income (M$)
		As of June 30, 2014
Discount Rate		Total				Total				Total
Percent		Proved				Probable				Possible
9		$	356,328			$	29,718			$	39,478
12		$	300,723			$	21,362			$	29,550
15		$	257,988			$	15,046			$	21,987
18		$	224,208			$	10,154			$	16,085

 

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

 

Reserves Included in This Report

 

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10 (a). The probable reserves and possible reserves included herein conform to definitions of probable and possible reserves sponsored and approved by the Society of Petroleum Engineers (SPE), the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG) and the Society of Petroleum Evaluation Engineers (SPEE) as set forth in the 2007 SPE/WPC/AAPG/SPEE Petroleum Resources Management System (SPE-PRMS). An abridged version of the SEC proved reserves definitions from 210.4-10(a) and the SPE/WPC/AAPG/SPEE probable and possible reserves from the SPE-PRMS entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

 

The various reserve status categories are defined in the attachment to this report entitled “Petroleum Reserves Status Definitions and Guidelines.” The developed proved non-producing reserves included herein consist of the behind pipe category.

 

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

 

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

 

 

American Eagle Energy Corporation

July 14, 2014

Page 4

 

Reserves Uncertainty

 

All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. Estimates will generally be revised only as additional geologic or engineering data becomes available or as economic conditions change.

 

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.

 

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

 

For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.”

 

Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Probable reserves are “those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves.” For probable reserves, it is “equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves” (cumulative 2P volumes). Possible reserves are “those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than probable reserves.” For possible reserves, the “total quantities ultimately recovered from the project have a low probability to exceed the sum of the proved plus probable plus possible reserves” (cumulative 3P volumes).

 

The reserves included herein were estimated using deterministic methods and presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty.

 

The reserves and income quantities attributable to the different reserve classifications that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable. Petroleum quantities classified as reserves should not be aggregated with each other without due consideration of the significant differences in the criteria associated with their classification. Moreover, estimates of reserves may increase or decrease as a result of future operations, effects of regulation by governmental agencies or geopolitical risks. As a result, the estimates of oil and gas reserves have an intrinsic uncertainty. The reserves included in this report are therefore estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts.

 

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

 

 

American Eagle Energy Corporation

July 14, 2014

Page 5

 

Possible Effects of Regulation

 

Ryder Scott did not evaluate the country and geopolitical risks in the countries where AEE operates or has interests. AEE’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and investment and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of reserves actually recovered and amounts of income actually received to differ significantly from the estimated quantities.

 

The estimates of reserves presented herein were based upon a detailed study of the properties in which AEE owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

 

Methodology Employed for Estimates of Reserves

 

The estimation of reserve quantities involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities. The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

 

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of recoverable hydrocarbons is identified, the evaluator must determine the uncertainty associated with the incremental quantities of those recoverable hydrocarbons. If the quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of incremental recoverable quantities that addresses the inherent uncertainty in the estimated quantities reported.

 

Estimates of reserve quantities and their associated categories or classifications may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of the recoverable quantities and their associated categories or classifications may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

 

The reserves for the properties included herein were estimated by performance methods, analogy, or a combination of methods. In general, reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis which utilized extrapolations of historical production and pressure data available through May 2014 in those cases where such data were considered to be definitive. The data used in this analysis were furnished to Ryder Scott by AEE or obtained from public data sources and were considered sufficient for the purpose thereof. In certain cases, producing reserves were estimated by analogy. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the estimates was considered to be inappropriate.

 

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

 

 

American Eagle Energy Corporation

July 14, 2014

Page 6

 

Reserves attributable to non-producing and undeveloped reserves included herein were estimated by analogy.

 

Assumptions and Data Considered for Estimates of Reserves

 

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. We have applied the same criteria for economic producibility to the probable and possible reserves included in this report.

 

AEE has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by AEE with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, production taxes, development costs, product prices based on the SEC regulations and adjustments or differentials to product prices. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by AEE. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

 

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein.

 

Future Production Rates

 

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

 

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by AEE. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

 

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

 

 

American Eagle Energy Corporation

July 14, 2014

Page 7

 

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

 

Hydrocarbon Prices

 

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

 

These initial SEC hydrocarbon prices, in effect on June 30, 2014, were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

 

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by AEE. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by AEE to determine these differentials.

 

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves by reserves category for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

 

Geographic Area	Product	Price Reference	Avg Benchmark Prices	Avg Proved Realized Prices	Avg Probable Realized Prices	Avg Possible Realized Prices
North America
United States	Oil/Condensate	WTI Cushing	$100.11/Bbl	$89.22/Bbl	$89.30/Bbl	$89.30/Bbl
	Gas	Henry Hub	$4.10/MMBTU	$5.08/MCF	$5.08/MCF	$5.08/MCF

 

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

 

 

American Eagle Energy Corporation

July 14, 2014

Page 8

 

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

 

While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may also increase or decrease from existing levels, such changes were omitted from consideration in making this evaluation.

 

Costs

 

Operating costs for the leases and wells in this report were furnished by AEE and are based on the operating expense reports of AEE and include only those costs directly applicable to the leases or wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operating costs furnished by AEE were reviewed by us for their reasonableness using information furnished by AEE for this purpose. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

 

Development costs were furnished to us by AEE and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by AEE were reviewed by us for their reasonableness using information furnished by AEE for this purpose. AEE’s estimates of zero abandonment costs after salvage value for onshore properties were used in this report. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for AEE’s estimate.

 

The developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with AEE’s plans to develop these reserves as of June 30, 2014. The implementation of AEE’s development plans as presented to us and incorporated herein is subject to the approval process adopted by AEE’s management. As the result of our inquiries during the course of preparing this report, AEE has informed us that the development activities included herein have been subjected to and received the internal approvals required by AEE’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to AEE. Additionally, AEE has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

 

Current costs were held constant throughout the life of the properties.

 

Standards of Independence and Professional Qualification

 

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy-five years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

 

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

 

 

American Eagle Energy Corporation

July 14, 2014

Page 9

 

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

 

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

 

We are independent petroleum engineers with respect to AEE. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

 

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

 

Terms of Usage

 

This report was prepared for the exclusive use and sole benefit of American Eagle Energy Corporation and may not be put to other use without our prior written consent for such use. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

 

	Very truly yours,
	RYDER SCOTT COMPANY, L.P.
	TBPE Firm Registration No. F-1580
	James L. Baird, P.E.
	Colorado License No. 41521
	Managing Senior Vice President
	Clark D. Parrott, P.E.
	Colorado License No. 35262
	Petroleum Engineer

 

JLB-CDP (DPR)/pl

 

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

 

  

Professional Qualifications of Primary Technical Person

 

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. James Larry Baird was the primary technical person responsible for overseeing the estimate of the reserves.

 

Mr. Baird, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President and also serves as Manager of the Denver office, responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Baird served in a number of engineering positions with Gulf Oil Corporation (1970-1973), Northern Natural Gas (1973-1975) and Questar Exploration & Production (1975-2006). For more information regarding Mr. Baird’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

 

Mr. Baird earned a Bachelor of Science degree in Petroleum Engineering from the University of Missouri at Rolla in 1970 and is a registered Professional Engineer in the States of Colorado and Utah. He is also a member of the Society of Petroleum Engineers.

 

In addition to gaining experience and competency through prior work experience, the Colorado and Utah Board of Professional Engineers recommend continuing education annually, including at least one hour in the area of professional ethics, which Mr. Baird fulfills. As part of his 2011 continuing education hours, Mr. Baird attended an internally presented sixteen hours of formalized training as well as an eight hour public forum. Mr. Baird attended the 2010 and 2011 RSC Reserves Conference and various professional society presentations specifically on the new SEC regulations relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Baird attended an additional sixteen hours of formalized in-house and external training during 2011, 2012 and 2013 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, reserve reconciliation processes, overviews of the various productive basins of North America, evaluations of resource play reserves, procedures and software and ethics for consultants. Mr. Baird was a keynote speaker, presenting the Changing Landscape of the SEC Reporting, at the 2009 Unconventional Gas International Conference held in Fort Worth, Texas.

 

Based on his educational background, professional training and more than 43 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Baird has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

 

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS