Current Report Filing (8-k)

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

 

FORM 8-K

 

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

Date of Report (Date of earliest event reported): March 2, 2015

 

 

AMERICAN EAGLE ENERGY CORPORATION

 

(Exact name of registrant as specified in its charter)

  

Nevada	000-50906	20-0237026
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

 

2549 W. Main Street, Suite 202, Littleton, CO	80120
(Address of principal executive offices)	(Zip Code)

 

 

Registrant’s telephone number, including area code: [phone]

 

(Former name or former address, if changed since last report)

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

 

¨

Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

¨

Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

 

¨

Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

¨

Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

  

 

SECTION 7 – REGULATION FD

 

Item 7.01. Regulation FD Disclosure

 

On March 2, 2015, American Eagle Energy Corporation (“AMZG,” “we,” or “our”) provided an operations update and production guidance for our fourth quarter ending December 31, 2014, capital spending and production guidance, and estimated proved reserves for year-end 2014. We also announced that we (i) deferred the March 2, 2015, semi-annual $9.8 million interest payment in respect of the bonds that we sold in August 2014, (ii) continue to assess our near- and mid-term liquidity, (iii) in consultation with our standard advisors, as well as two newly engaged, experienced investment banks, continue to explore options to strengthen our balance sheet, and (iv) will utilize the 30-day grace period provided in the related bond indenture to determine whether to make the interest payment.

 

On March 2, 2015, we also disclosed that our estimated total proved reserves, as of December 31, 2014, and based on SEC pricing guidelines, were 15.5 million barrels of equivalent with an associated Pre-Tax PV-10 value of approximately $277.4 million. The reserve estimate was engineered by an independent petroleum engineering firm, Ryder Scott Company, L.P. (“Ryder Scott”). On February 23, 2015, we received Ryder Scott’s reserve report as of December 31, 2014 (the “Reserve Report”). In the Reserve Report, Ryder Scott estimated our proved, probable, and possible reserves, future production, and income attributable to certain of our leasehold interests as of December 31, 2014. The properties evaluated by Ryder Scott represent 100 percent of our total net proved, probable, and possible liquid hydrocarbon reserves and 100 percent of our total net proved, probable, and possible gas reserves as of December 31, 2014.

 

On March 2, 2015, we issued a press release announcing such updates and disclosures. A copy of the press release is attached hereto as Exhibit 99.1. That press release includes “safe harbor” language pursuant to the Private Securities Litigation Reform Act of 1995, as amended, indicating that certain statements contained in the press release are “forward-looking” rather than historical. A copy of the Reserve Report is attached hereto as Exhibit 99.2. Investors are cautioned to review the Reserve Report in its entirety. We undertake no duty or obligation to update or revise information included in this Current Report on Form 8-K or the Exhibits.

 

SECTION 8 — OTHER EVENTS

 

Item 8.01. Other Events.

 

We incorporate by reference the disclosure in Item 7.01 in respect of the Reserve Report. As noted in such Item, we attached a copy of the Reserve Report hereto as Exhibit 99.2 and cautioned investors to review the Reserve Report in its entirety. We undertake no duty or obligation to update or revise information included in this Current Report on Form 8-K or the Exhibits.

 

SECTION 9 – FINANCIAL STATEMENTS AND EXHIBITS 

 

Item 9.01 Financial Statements and Exhibits.

 

(d)

Exhibits

 

Exhibit

Description of Exhibit

 

99.1	Press release of American Eagle Energy Corporation, dated March 2, 2015.
99.2	Report of Ryder Scott Company, L.P., as of December 31, 2014.

 

 

SIGNATURE

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 

Date:  March 2, 2015	AMERICAN EAGLE ENERGY CORPORATION
	By:	/s/ Bradley Colby
		Bradley Colby
		President and Chief Executive Officer

 

 

Exhibit 99.1

 

 

American Eagle Energy Announces Operations and Reserves Update and Guidance

 

DENVER, CO—March 2, 2015—American Eagle Energy Corporation (NYSE MKT: AMZG) (“American Eagle” or the “Company”), announces an operations update for the fourth quarter ending December 31, 2014, capital spending and production guidance, and estimated proved reserves for year-end 2014.

 

Operated Well Development

 

During the fourth quarter ended December 31, 2014, American Eagle added three gross (1.8 net) wells to production. As announced previously, the Donald 15-33S (Three Forks long lateral) well, the last of six wells developed under the Company’s Farm-Out program, produced an average of 312 barrels of oil equivalent per day (“BOEPD”) during the first 30 days of production. The Rick 13-31 (Three Forks short-lateral) well produced an average of 267 BOEPD during the first 30 days of production. The Huffman 15-34S (Three Forks long-lateral) well, in which the Company owns a 94% working interest (“WI”), was the second well stimulated by American Eagle using slickwater stimulation. The Huffman well was brought on production in December 2014 and averaged 261 BOEPD during the first 30 days of production. The Huffman well has averaged 266 BOEPD during February 2015, which is similar to the flat, stable production behavior observed in the Eli 8-1E (Bakken long-lateral) well, which was the Company’s initial slickwater completion.

 

Remedial completions, designed to correct problems with faulty stimulation sleeves, were performed during the quarter on the Shelly 3-2N (Three Forks short-lateral, 97% WI) and the La Plata State 2-16 (Three Forks long lateral, 39% WI) wells. The work on the Shelly 3-2N well was partially successful and established an initial 30 day production rate of approximately 61 BOEPD. The recompletion of the La Plata State 2-16 well was unsuccessful in isolating communication with an overlying zone and stimulating the Three Forks Formation.

 

2015 Capital Spending Guidance

 

The Company is focused on capital discipline and maintaining liquidity in the current price environment. In light of the decreasing crude oil price trend, American Eagle stopped drilling in November 2014, after the Huffman 15-34S well, and has suspended its 2015 capital plans until the oil price and service cost environment come into balance. The Company has two gross (1.9 net) wells (the Byron 4-4 and the Shelley Lynn 4-4N) that were drilled during the fourth quarter and are awaiting completion. These wells will not be completed until pricing conditions improve.

 

 

Production Volume and Lease Operating Expense Guidance

 

American Eagle estimates that its average production for the fourth quarter ended December 31, 2014, was approximately 2,588 BOEPD. The Company estimates that average production for the first quarter ended March 31, 2015, will be approximately 1,900 BOEPD. The lower estimated quarterly production reflects the loss of production from the previously announced non-core asset sale, normal production decline, increased downtime from workovers associated with the conversion of six wells from higher cost submersible pumps to rod pumps and from winter weather.

 

American Eagle calculated an average lease operating expense (“LOE”) for the fourth quarter of approximately $25 per barrel of equivalent (“BOE”), which was significantly elevated from previous periods due to year-end adjustments and utilization of higher cost submersible pumps. The Company estimates that LOE expenses will trend downward in 2015 from approximately $20 per BOE to a likely range of $15 to $17 per BOE, reflecting savings from the full utilization of the installed salt water disposal pipelines, arrival of the electrical infrastructure and conversion of submersible pumps to more cost efficient rod pumps. American Eagle is also in the early stages of exploring options to connect to a crude oil gathering system in the area.

 

December 31, 2014 Estimated Proved Reserves Using SEC Pricing

 

American Eagle’s estimated total proved reserves as of December 31, 2014, based on SEC pricing guidelines, were 15.5 million barrels of equivalent (“MMBoe”) with an associated Pre-Tax PV-10 value of approximately $277.4 million. This represents a 21% increase over the Company’s estimated prior year total proved reserves after accounting for 2014 production of 770 MBoe. Proved developed reserves of 6.3 MMBoe (associated Pre-Tax PV-10 of $178.5 million) represented a 60% increase over the estimated prior year proved developed reserves. Reserve estimates for both periods were engineered by Ryder Scott.

 

Proved Reserves and Pre-Tax PV-10 Value¹ as of December 31, 2014

 

	Crude Oil (MBbls)	Natural Gas (MMcf)	Total (MBoe)	Pre-Tax PV-10 Value ($000s)
Proved Developed Properties2	5,495	4,820	6,298	$     178,501
PUD Properties3	8,184	6,000	9,184	$       98,928
Total Estimated Proved Properties	13,679	10,820	15,482	$    277,429

 

1

Ryder Scott used SEC pricing for oil and natural gas in calculating Pre-Tax PV-10. Pre-Tax PV-10 is a non-GAAP financial measure. See additional disclosures at end of release.

2

Proved Developed Properties includes Proved Developed Producing (“PDP”) and Proved Developed Nonproducing (“PDNP”).

3

Proved Undeveloped.

 

 

Pro Forma January 31, 2015 Estimated Proved Reserves Using Recent Oil Prices

 

Based on the year end 2014 proved reserves, American Eagle estimated total proved reserves on a pro forma basis at January 31, 2015, adjusting for non-core assets that were sold in January 2015 and using approximately $53 per barrel for oil during 2015 and using recent futures oil prices for periods thereafter. On the pro forma basis, the Company estimates that total proved reserves were approximately 8.9 MMBoe with an associated Pre-Tax PV-10 value of approximately $102.2 million. Proved developed reserves were approximately 5.6 MMBoe (associated Pre-Tax PV-10 of approximately $98.9 million).

 

Pro Forma Proved Reserves and Pre-Tax PV-10 Value¹ as of January 31, 2015 Using Recent Oil Prices

 

	Crude Oil (MBbls)	Natural Gas (MMcf)	Total (MBoe)	Pre-Tax PV-10 Value ($000s)
Proved Developed Properties2	4,922	4,350	5,647	$       98,940
PUD Properties3	2,885	2,108	3,236	$         3,236
Total Estimated Proved Properties	7,807	6,458	8,883	$     102,176

 

1

Oil price forecast based on $53 per barrel for oil ($43 per barrel net to the Company after an estimated $10 per barrel differential discount) for 2015 and recent futures oil prices using an estimated $8 per barrel differential discount for periods thereafter and SEC pricing for natural gas in calculating Pre-Tax PV-10. Pre-Tax PV-10 is a non-GAAP financial measure. See additional disclosures at end of release.

2

Proved Developed Properties includes Proved Developed Producing (“PDP”) and Proved Developed Nonproducing (“PDNP”).

3

Proved Undeveloped.

 

Liquidity and Shares Outstanding

 

As of December 31, 2014, American Eagle had approximately $25.9 million in cash, $175.0 million total debt outstanding, comprised solely of the bonds that the Company sold in August 2014, and 30.4 million shares of common stock outstanding. The Company ended the fourth quarter of 2014 with approximately $13.6 million of negative working capital. Current assets consisted primarily of approximately $25.9 million in cash and approximately $9.5 million in receivables. Current liabilities consisted primarily of approximately $42.4 million in accounts payable and accruals and approximately $6.6 million in accrued interest.

 

As of December 31, 2014, American Eagle has no outstanding indebtedness under its senior secured revolving credit facility (“Credit Facility”), which had an initial borrowing base of up to $60 million as of August 27, 2014. Effective December 24, 2014, the borrowing base was reduced to zero. The Company’s Credit Facility was amended to waive compliance with the covenants governing its current ratio and ratio of total debt to EBITDAX for the quarter ending December 30, 2014.

 

 

Interest Payment

 

A $9.8 million semi-annual interest payment related to the bonds was due on March 2, 2015. As American Eagle continues to assess its near- and mid-term liquidity, and, in consultation with its standard advisors, as well as two newly engaged, experienced investment banks, to explore options to strengthen its balance sheet, it will utilize the 30-day grace period provided in the related bond indenture to determine whether to make the interest payment.

 

Conference Call

 

American Eagle will host a conference call on Monday, March 16, 2015 at 10:00 a.m. Eastern Time (8:00 a.m. Mountain Time) to discuss financial and operational results for the fourth quarter.

 

American Eagle Energy Corporation 4Q 2014 Financial and Operational Results Conference Call
Date:		Monday, March 16, 2015
Time:		10:00 a.m. Eastern Time
		9:00 a.m. Central Time
		8:00 a.m. Mountain Time
		7:00 a.m. Pacific Time
Webcast:		Live and rebroadcast over the Internet at American Eagle website
Website:		www.americaneagleenergy.com
Telephone Dial-In:		877-407-9171 (toll-free) and 201-493-6757 (international)
Telephone Replay:		Available through Monday, March 23, 2015
		877-660-6853 (toll-free) and 201-612-7415 (international)
		Passcode: 13572777

 

Pre-Tax PV-10 Disclosures Using SEC Pricing

 

Pre-Tax PV-10 values oil and natural gas reserve quantities and related discounted future net cash flows as of December 31, 2014 assuming average constant realized prices of $82.36 per barrel of oil and $5.08 per thousand cubic feet (“Mcf”) for natural gas. The average natural gas price reflects the value of processed natural gas sales and natural gas liquids. Under SEC guidelines, these prices represent the average prices per barrel of oil and per Mcf of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period, which averages are then adjusted to reflect applicable transportation and quality differentials. Barrels of equivalent (“Boe”) are computed based on a conversion ratio of one Boe for each barrel of oil and one Boe for every 6,000 cubic feet (6 Mcf) of natural gas.

 

The Company’s Pre-Tax PV-10 assumes prices and costs discounted using an annual discount rate of 10% without future escalation and without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization. The Pre-Tax PV-10 values of the Company's estimated proved reserves may be considered a non-GAAP financial measure as defined by the SEC.

 

 

Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond the Company's control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner. As a result, estimates of proved reserves may vary depending upon the engineer valuing the reserves. Further, the Company's actual realized price for its oil and natural gas is not likely to average the pricing parameters used to calculate its proved reserves. As such, the oil and natural gas quantities and the value of those commodities ultimately recovered from the Company's properties will vary from reserve estimates.

 

 

ABOUT AMERICAN EAGLE ENERGY CORPORATION

 

American Eagle Energy Corporation is an independent exploration and production operator that is focused on acquiring acreage and developing wells in the Williston Basin of North Dakota, targeting the Bakken and Three Forks shale oil formations. The Company is based in Denver, CO. More information about American Eagle can be found at www.americaneagleenergy.com or by contacting investor relations at 303-798-5235 or [e-mail]. Company filings with the Securities and Exchange Commission can be obtained free of charge at the SEC’s website at www.sec.gov.

 

SAFE HARBOR

 

This press release may contain forward-looking statements regarding future events and the Company’s future results that are subject to the safe harbors created under the Securities Act of 1933 (the “Securities Act”) and the Securities Exchange Act of 1934 (the “Exchange Act”). All statements other than statements of historical facts included in this press release regarding the Company’s financial position, business strategy, plans and objectives of management for future operations, industry conditions, and indebtedness covenant compliance are forward-looking statements. When used in this report, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “possible,” “target,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about, actual or potential future sales, market size, collaborations, and trends or operating results also constitute such forward-looking statements.

 

Forward-looking statements involve inherent risks and uncertainties and important factors (many of which are beyond the Company’s control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the amount we may invest, the location, and the scale of the drilling projects in which we intend to participate; our beliefs with respect to the potential value of drilling projects; our beliefs with regard to the impact of environmental and other regulations on our business; our beliefs with respect to the strengths of our business model; our assumptions, beliefs, and expectations with respect to future market conditions; our plans for future capital expenditures; and our capital needs, the adequacy of our capital resources, and potential sources of capital.

 

 

The Company has based these forward-looking statements on its current expectations and assumptions about future events. While management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory, and other risks, contingencies, and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control. The Company does not assume any obligations to update any of these forward-looking statements.

 

CORPORATE CONTACT:

 

Marty Beskow, CFA

Vice President of Capital Markets and Strategy

American Eagle Energy Corporation

720-330-8378

[e-mail]

www.americaneagleenergy.com

 

 

 

Exhibit 99.2

 

FAX [phone]

  

 

621 SEVENTEENTH STREET SUITE 1550 DENVER, COLORADO 80293 TELEPHONE [phone]

 

February 23, 2015

 

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 December 31, 2014. The subject properties are located in the state of North Dakota. The reserves and income data 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). Our third party study, completed on February 23, 2015 and presented herein, was prepared for public disclosure by AEE in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

 

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 December 31, 2014.

 

The estimated reserves and future income amounts presented in this report, as of December 31, 2014, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of 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, 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

February 23, 2015

Page 2

 

 

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold Interests of

American Eagle Energy Corporation

As of December 31, 2014

 

		Proved
		Developed												Total
		Producing				Non-Producing				Undeveloped				Proved
Net Remaining Reserves
Oil/Condensate – MBarrels			5,031				465				8,184				13,680
Gas – MMCF			4,480				341				5,999				10,820
Income Data (M$)
Future Gross Revenue		$	389,043			$	35,583			$	626,468			$	1,051,094
Deductions			111,779				11,409				335,775				458,963
Future Net Income (FNI)		$	277,264			$	24,174			$	290,693			$	592,131
Discounted FNI @ 10%		$	164,508			$	13,993			$	98,928			$	277,429

 

 

		Total				Total
		Probable				Possible
		Undeveloped				Undeveloped
Net Remaining Reserves
Oil/Condensate – MBarrels			2,525				989
Gas – MMCF			1,846				724
Income Data (M$)
Future Gross Revenue		$	193,256			$	75,692
Deductions			114,039				51,083
Future Net Income (FNI)		$	79,217			$	24,609
Discounted FNI @ 10%		$	20,326			$	3,555

 

 

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.

 

 

American Eagle Energy Corporation

February 23, 2015

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 state and federal 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 95 percent and gas reserves account for the remaining 5 percent of total future gross revenue from proved reserves. Liquid hydrocarbon reserves account for approximately 96 percent 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 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 December 31, 2014
Discount Rate		Total		Total		Total
Percent		Proved		Probable		Possible
9		$295,099		$23,361		$ 4,523
12		$246,879		$15,224		$ 1,981
15		$210,359		$  9,427		$    295
18		$181,979		$  5,215		$  (833)

 

 

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, probable and possible reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

 

The various reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. The proved developed 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 proved, probable and possible gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

 

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.” 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. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. 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. At AEE’s request, this report addresses the proved, probable and possible reserves attributable to the properties evaluated herein.

 

 

American Eagle Energy Corporation

February 23, 2015

Page 4

 

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 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.” Probable reserves are “those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” Possible reserves are “those additional reserves which are less certain to be recovered than probable reserves” and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low.

 

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. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserve categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable.

 

Reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. 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.” Moreover, estimates of proved, probable and possible reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved, probable and possible reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

 

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 are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved, probable and possible reserves actually recovered and amounts of proved, probable and possible 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.

 

 

American Eagle Energy Corporation

February 23, 2015

Page 5

 

 

Estimates of Reserves

 

The estimation of reserves 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 in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). 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 reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

 

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories 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 proved, probable and possible reserves for the properties included herein were estimated by performance methods, analogy, or a combination of methods. Approximately 100 percent of the proved producing 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 December, 2014 for operated properties and November, 2014 for non-operated properties in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by AEE or obtained from public data sources and were considered sufficient for the purpose thereof.

 

 

American Eagle Energy Corporation

February 23, 2015

Page 6

  

Approximately 100 percent of the proved developed non-producing and undeveloped reserves and 100 percent of the probable and possible undeveloped reserves included herein were estimated by analogy.

 

To estimate economically recoverable proved, probable and possible 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 which 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, probable and possible 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. 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 increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

 

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, probable and possible 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, other costs such as transportation and/or processing fees, production taxes, development costs, development plans, product prices based on the SEC regulations, adjustments or differentials to product prices, and pressure measurements. 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. The proved, probable and possible reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved, probable and possible reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

 

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.

 

 

American Eagle Energy Corporation

February 23, 2015

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 “as of date” of 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.

 

AEE furnished us with the above mentioned average prices in effect on December 31, 2014. These initial SEC hydrocarbon prices 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	$94.99/Bbl	$82.36/Bbl	$82.36/Bbl	$82.36/Bbl
	Gas	Henry Hub	$4.35/MMBTU	$5.08/MCF	$5.08/MCF	$5.08/MCF

 

 

American Eagle Energy Corporation

February 23, 2015

Page 8

  

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

 

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. The operating costs 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 operating cost data used by AEE. 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 proved developed non-producing and proved, probable and possible undeveloped reserves in this report have been incorporated herein in accordance with AEE’s plans to develop these reserves as of December 31, 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 or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2014, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

 

Current costs used by AEE 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 since 1937. 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 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.

 

 

American Eagle Energy Corporation

February 23, 2015

Page 9

 

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 financial 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

 

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by AEE.

 

We have provided AEE with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by AEE and the original signed report letter, the original signed report letter shall control and supersede the digital version.

 

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
		s James L. Baird
		James L. Baird, P.E.
	[Seal]	Colorado License No. 41521
		Managing Senior Vice President
		s Clark D. Parrott
		Clark D. Parrott, P.E.
	[Seal]	Colorado License No. 35262
		Petroleum Engineer
JLB-CDP (DPR)/pl

 

 

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 (1970-73), Northern Natural Gas (1973-75) 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 RSC Reserves Conferences 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 2013 and 2014 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.

 

Based on his educational background, professional training and more than 45 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.