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): August 4, 2014

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: (303) 798-5235

(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 2 – FINANCIAL INFORMATION

Item 2.02. Results of Operations and Financial Condition.

On August 4, 2014, American Eagle Energy Corporation (“AMZG,” “we,” “us,” or “our”) provided a periodic operations update and reported the results for the quarter ended June 30, 2014. We also announced that we will be hosting a conference call to discuss the results. A copy of our press release of that update and our results is furnished and 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.

SECTION 7 – REGULATION FD

Item 7.01. Regulation FD Disclosure.

On August 4, 2014, we announced a proposed offering of $175 million aggregate principal amount of our senior secured notes in a private placement to eligible purchasers. A copy of our press release of that announcement is furnished and attached hereto as Exhibit 99.2. 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.

The information referenced under Item 2.02 and Item 7.01 in this Current Report on Form 8-K (including Exhibits 99.1 and 99.2 attached hereto) is being “furnished” thereunder and, as such, shall not be deemed to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section. The information set forth in this Current Report on Form 8-K (including Exhibits 99.1 and 99.2 referenced in Item 9.01 below) shall not be incorporated by reference into any registration statement, report, or other document filed by AMZG pursuant to the Securities Act of 1933, as amended, except as shall be expressly set forth by specific reference in such filing. AMZG undertakes no duty or obligation to update or revise information included in this Current Report on Form 8-K or any of the Exhibits.

SECTION 8 – OTHER EVENTS

Item 8.01. Other Events

On July 14, 2014, we received the reserve report as of June 30, 2014 (the “Reserve Report”) prepared for us by our independent petroleum engineering firm, Ryder Scott Company, L.P. (“Ryder Scott”).

In the Reserve Report, Ryder Scott estimated the proved, probable, and possible reserves, future production, and income attributable to certain leasehold interests of AMZG as of June 30, 2014. 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 AMZG as of June 30, 2014.

A copy of the Reserve Report is attached hereto as Exhibit 99.3. Investors are cautioned to review the Reserve Report in its entirety.

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 August 4, 2014.

99.2	Press release of American Eagle Energy Corporation, dated August 4, 2014.

99.3	Report of Ryder Scott Company, L.P., as of June 30, 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: August 4, 2014	AMERICAN EAGLE ENERGY CORPORATION

	By:	/s/ Bradley Colby
		Bradley Colby
		President and Chief Executive Officer

EXHIBIT INDEX

Exhibit	Description of Exhibit

99.1	Press release of American Eagle Energy Corporation, dated August 4, 2014.

99.2	Press release of American Eagle Energy Corporation, dated August 4, 2014.

99.3	Report of Ryder Scott Company, L.P., as of June 30, 2014.

Exhibit 99.1

American Eagle Energy Announces Operations Update and

Reports Results for Second Quarter 2014

DENVER, CO—August 4, 2014—American Eagle Energy Corporation (NYSE MKT: AMZG) (“American Eagle” or the “Company”), announces an operational update and discussion of its financial results for the second quarter ended June 30, 2014, along with an update of its mid-year 2014 estimated proved reserves. The Company intends to file its Quarterly Report on Form 10-Q with the U.S. Securities and Exchange Commission today.

Highlights

American Eagle added 8 gross (4.0 net) operated wells to production during the quarter;

Production of 182,522 barrels of oil equivalent (“BOE”), or an average of 2,006 BOEPD:

year-over-year increase of 56% from the 1,288 BOEPD (117,164 BOE)

sequential quarterly increase of 22% from 1,645 BOEPD (148,048 BOE)

Second quarter 2014 oil and gas sales of $16.5 million:

a year-over-year increase of 59%

a sequential quarterly increase of 31%

Adjusted EBITDA* of $9.6 million;

Adjusted Cash Flow* of $6.7 million or $0.22 per diluted share;

Adjusted Net Income* of $2.3 million or $0.07 per diluted share; and

American Eagle’s mid-year proved reserves engineered by Ryder Scott Company, L.P. (“Ryder Scott”) were estimated at 15.4 million barrels of oil equivalent (“MMBoe”) (89% oil) with an associated Pre-Tax PV-10 of $336 million

* Non-GAAP financial measure. Please see Adjusted EBITDA, Adjusted Cash Flow and Adjusted Net Income descriptions and tables later in this earnings release for a reconciliation of these measures to their nearest comparable GAAP measure.

Management Comments

Brad Colby, President and CEO of American Eagle, said, “We are excited about the opportunities in front of us as we prepare to complete and bring onto production our 4-well pad that has an average working interest of 88% and is located in an area where we have had very good recent well results, most notably from the Murielle, Taylor and Bryce wells. The 4-well pad should add significant production and showcase our potential to realize cost savings relating to continued pad development. Continued drilling efficiency will allow us to drill more wells without increasing rig count and improved weather conditions should provide an opportunity to decrease well completion costs. We anticipate that our current development program will allow us to add to our proved reserve base during the second half of 2014 and position us for significant reserve growth in 2015.”

Second Quarter 2014 Financial and Operational Results

For the quarter ended June 30, 2014, the Company had oil and gas sales of $16.5 million, which represented an increase of 59% over the $10.4 million reported for the second quarter ended June 30, 2013 and an increase of 31% over the $12.5 million reported for the first quarter ended March 31, 2014. This increase in sales on both an annual and sequential quarterly basis is primarily due to an increase in production as 43 gross (24.0 net) operated wells were producing in the Bakken and Three Forks formations during the second quarter 2014, compared to production from 20 gross (6.4 net) operated wells at the end of June 30, 2013 and 35 gross (20.0 net) operated wells as of March 31, 2014. During the second quarter 2014, oil production represented 99% of total oil and gas sales revenue and 96% of total production.

American Eagle’s second quarter 2014 realized oil price per barrel prior to the effect of hedges was positively impacted by a lower differential discount of approximately $10.87 relative to WTI due to an agreement that locks in a $10.75 discount to WTI for the Company’s 2014 operated oil production and compares with a differential discount of approximately $11.57 during the first quarter 2014.

Adjusted EBITDA for second quarter 2014 was $9.6 million, representing an increase of 49% from $6.4 million reported for the second quarter ended June 30, 2013 and an increase of 29% from $7.4 million reported for the first quarter ended March 31, 2014. Relative to the second quarter ending June 30, 2013, the increase in Adjusted EBITDA is primarily due to higher oil and gas sales from increased production, operating leverage realization in general and administrative (“G&A”) expenses (excluding stock-based compensation), and an increase in realized oil prices before including the negative effect of hedges realized during the quarter. However, the improvement in Adjusted EBITDA was partially offset by a higher differential when comparing realized oil price to benchmark oil prices such as West Texas Intermediate (“WTI”) and higher lease operating expenses. Similarly, in comparison to the quarter ending March 31, 2014, the 29% increase in Adjusted EBITDA is due primarily to an increase in average daily oil equivalent production, higher realized oil prices and lower relative G&A expenses, which were partially offset by lease operating expenses and higher production taxes, for production volumes realized in the quarter.

Lease operating Expense (“LOE”) for the quarter ended June 30, 2014 was $18.15 per BOE, which was higher than normal and resulted from challenging weather conditions that required a significant increase in site and road maintenance expenses that accounted for approximately $2.65 per BOE, as well as increased workover expenses that accounted for approximately $2.37 per BOE. Higher production levels helped to reduce per unit G&A expenses on both an annual and sequential quarter comparison, as G&A, excluding stock-based compensation, was $6.67 per BOE during the second quarter 2014 compared to $8.31 per BOE for the prior year and $10.56 per BOE for the prior quarter. Adjusted EBITDA per BOE for the quarter ended June 30, 2014 was $52.53, as compared to $54.99 per BOE for the second quarter ended June 30, 2013 and $50.29 per BOE for the first quarter ended March 31, 2014.

	Three Months Ended
	Jun. 30,			Mar. 31,			Dec. 31,			Sep. 30,			Jun. 30,
	2014			2014			2013			2013			2013
Crude Oil Revenues ($000s)	$	16,225		$	12,267		$	13,272		$	11,585		$	10,366
Natural Gas Revenues ($000s)	$	106		$	72		$	114		$	26		$	4
Natural Gas Liquids Revenues ($000s)	$	132		$	206		$	115		$	28		$	0

Net Production:
Crude Oil (Barrels)		175,509			140,841			164,923			123,343			117,001
Crude Oil Mix		96	%		95	%		95	%		98	%		100	%
Natural Gas (Mcf)		16,977			11,370			20,055			6,333			980
Natural Gas Liquids (Barrels)		4,183			5,312			4,563			944			0

Total Net Production (BOE)		182,522			148,048			172,829			125,343			117,164
Quarter-Over-Quarter Increase		23	%		-14	%		38	%		7	%		34	%

Average Daily Production (BOEPD)		2,006			1,645			1,879			1,362			1,288
Quarter-Over-Quarter Increase		22	%		-12	%		38	%		6	%		32	%

Average Sales Prices:
Crude Oil Per Barrel	$	92.45		$	87.10		$	80.48		$	93.92		$	88.60
Effect of Settled Oil Derivatives Per Barrel	$	(2.60	)	$	0.82		$	4.16		$	0.94		$	0.00
Crude Oil Net of Settled Derivatives Per Barrel	$	89.85		$	87.92		$	84.64		$	94.86		$	88.60
Natural Gas Per Mcf	$	6.25		$	6.37		$	5.67		$	4.09		$	4.40
Natural Gas Liquids Per Barrel	$	31.44		$	38.83		$	25.27		$	29.67		$	0.00
Realized Price Per BOE	$	87.69		$	85.52		$	82.10		$	93.78		$	88.51

Average Per BOE:
Lease Operating Expenses	$	18.15		$	15.36		$	13.59		$	14.09		$	15.31
Production Taxes	$	10.34		$	9.32		$	9.28		$	10.28		$	9.90
G&A Expenses, Excluding Stock-Based Compensation	$	6.67		$	10.56		$	15.07		$	12.04		$	8.31
Total	$	35.16		$	35.24		$	37.94		$	36.41		$	33.52

Adjusted EBITDA per BOE	$	52.53		$	50.29		$	44.16		$	57.36		$	54.99

Well Development Activity

Since the Company’s July 16, 2014 operations update, it has continued to drill and complete wells successfully. Concurrent with that update, American Eagle released preliminary results on wells that had not yet produced for a full 30 days. The operated wells listed below have produced an average of 20 days and are listed from the most westerly located well to the most easterly located well:

Well

Formation

20-Day
IP Rate
BOEPD¹

Lateral
Length
Feet

Approximate
DSU² Acres

Infill
Number
in DSU²

Murielle 16-1E-163-101 (5 & 6)⁽³⁾

Three Forks

389

9,950

1,280

3^rdwell in DSU, 2^nd Three Forks

Richard 2-13N-163-101 (1 & 12)⁽³⁾

Three Forks

196

10,158

1,280

5^thwell in DSU, 3^rd Three Forks

¹ IP Rate BOEPD is calculated taking the cumulative production from each well divided by the number of days each well has been on production.

² Drill spacing unit (“DSU”)

³ Based on first 20 days of production.

The Murielle 16-1E is a Three Forks infill well in the Stanley 8-1E spacing unit. The initial well productivity and oil cut of the Murielle well essentially mirrors the performance of the Stanley well which has recorded cumulative production of approximately 77,000 BOE for the first year of operation. The Richard 2-13N is the third Three Forks well completed in the Christianson 15-12 and Megan 13-12 spacing unit. The Richard 2-13N was put on pump following completion and has been showing an increasing oil flow rate as well as oil cuts approaching that of the offset wells, which are currently averaging between 50% and 55%.

In addition, two more operated wells have also been recently put on production:

Well

Formation

5-Day
IP Rate
BOEPD¹

Lateral
Length
Feet

Approximate
DSU² Acres

Infill
Number
in DSU²

Annie 15-32-164-101 (29 & 32)⁽³⁾

Three Forks

255

6,112

800

2^ndwell in DSU, 2^nd Three Forks

James 15-20-163-102 (17 & 20)⁽³⁾

Three Forks

341

9,492

1,280

1^stwell in DSU, 1^st Three Forks

¹ IP Rate BOEPD is calculated taking the cumulative production from each well divided by the number of days each well has been on production.

² Drill spacing unit (“DSU”)

³ Based on first 5 days of production.

The Annie 15-32, a Three Forks infill well, has shown similar initial performance to its offset, the Lynda 15-32 that has produced over 40,000 BOE in its first 5 months of production. The James 15-20 is a west offset to the DeWitt State spacing unit and establishes production in a new DSU. Early performance indications are encouraging with the well cleaning in accordance with expectations, and averaging 341 BOEPD over the first 5 days on pump.

Operated Well Development Guidance

The Company currently has 6 gross (4.9 net) operated wells in the central portion of the Spyglass acreage that are awaiting completion, of which 4 gross (3.5 net) operated wells are on a 4-well pad and 2 gross (1.4 net) operated wells that are infill wells on separate DSUs.

The four wells on the single drill pad are located between the Bryce (Three Forks) well and the DSU with the Stanley (Three Forks), Taylor (Bakken) and Murielle (Three Forks) wells, all of which have exhibited strong production results. The wells on the 4-well pad are now expected to begin fracturing operations in mid-August. The other two wells awaiting completion, the Rick 13-31 and Eli 8-1E, are infill wells to the Tangedal 13-31 and the Taylor 16-1E, respectively. The Eli 8-1E is scheduled for stimulation in early August and the Rick 13-31 is scheduled for stimulation later this month. American Eagle plans to announce results of the wells once it has achieved approximately 30 days of cumulative production. The Company anticipates releasing these well results in an operations update near or after the end of September 2014, but prior to announcing third quarter 2014 results in November.

Thus far during the third quarter, American Eagle has added 2 gross (1.0 net) operated wells to production, has 6 gross (4.9 net) operated wells that are awaiting completion and is currently drilling its 52^nd operated well in its Spyglass area. As discussed in the Company’s prior operations update, American Eagle has continued to improve drilling efficiencies and has been averaging approximately 24 days per well from spud-to-spud for wells drilling on separate drill pads. This has allowed the Company the ability to drill more wells than originally forecast.

At the Company’s current pace of development, American Eagle anticipates that it will drill approximately 28 gross (18 net) operated wells in 2014, spending approximately $113 million. The Company also plans to participate in the development of select non-operated interests in its Spyglass area and has allocated approximately $2 million to such development activities. American Eagle’s total well development budget for 2014 is approximately $115 million. At the Company’s current pace of development and assuming it maintains its existing two rig drilling program, American Eagle anticipates drilling approximately 30 gross (20 net) operated wells for a total cost of approximately $120 million during 2015 and participating in approximately 10 gross (0.3 net) non-operated wells for approximately $2 million.

Production Volume Guidance

American Eagle has reaffirmed its production volume guidance to exit 2014 at over 3,000 BOEPD. As discussed in the Company’s prior operations update, second quarter 2014 production was impacted by a number of road closures in Divide County due to heavy rains that required wells to be shut in when storage tanks were full. With improving weather in the basin, the Company estimates that its current production is approximately 2,200 to 2,300 BOEPD. American Eagle anticipates significant sequential quarterly production volume growth throughout the remainder of 2014 as a number of high working interest wells are anticipated to be brought onto production, including the 4-well pad that has an average working interest of 88%.

June 30, 2014 Estimated Proved Reserves

American Eagle’s estimated total proved reserves at June 30, 2014 were 15.4 MMBoe with an associated Pre-Tax PV-10 value of approximately $336.0 million. This represents a 14% increase over the Company’s estimated total proved reserves of 13.6 MMBoe (associated Pre-Tax PV-10 value of $308.1 million) for the period ending December 31, 2013. Proved developed reserves of 6.0 MMBoe (associated Pre-Tax PV-10 of $195.4 MM), represented a 28% increase over the period ending December 31, 2013, and reflect the focus of the 2014 drilling program on accelerating development of PUD locations, primarily in the Spyglass Area. Reserve estimates for both periods were engineered by Ryder Scott.

Proved Reserves and Pre-Tax PV-10 Value¹as of June 30, 2014

	Crude Oil (MBbls)		Natural Gas (MMcf)		Total (MBoe)		Pre-Tax PV-10 Value ($000s)
Proved Developed Properties²		5,370		3,965		6,031	$	195,373
PUD Properties³		8,373		6,078		9,386	$	140,663

Total Estimated Proved Properties		13,743		10,043		15,417	$	336,036

¹Ryder 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.

²Proved Developed Properties includes Proved Developed Producing (“PDP”) and Proved Developed Nonproducing (“PDNP”).

³Proved Undeveloped.

Liquidity and Shares Outstanding

As of June 30, 2014, American Eagle had approximately $22.2 million in cash, $108.0 million total debt outstanding and 30.4 million shares of common stock outstanding. Due to increased efficiencies in drilling and weather impacts during the first half of 2014 that increased well completion costs and delayed production, the Company ended the second quarter of 2014 with approximately $20.8 million of negative working capital when classifying marketable securities as current assets and excluding its debt and commodity derivative liabilities from current liabilities. American Eagle’s Credit Agreement was amended in part to defer compliance with the covenant governing its current ratio until the quarter ending September 30, 2014

Conference Call

American Eagle will host a conference call on Monday, August 4, 2014 at 8:00 a.m. Eastern Time (6:00 a.m. Mountain Time) to discuss financial and operational results for the quarter.

American Eagle Energy Corporation 2Q 2014 Financial and Operational Results Conference Call
Date:		Monday, August 4, 2014
Time:		8:00 a.m. Eastern Time
		7:00 a.m. Central Time
		6:00 a.m. Mountain Time
		5:00 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 Friday, August 11, 2014
		877-660-6853 (toll-free) and 201-612-7415 (international)
		Passcode: 13572777

Pre-Tax PV-10 Disclosures

Pre-Tax PV-10 values oil and natural gas reserve quantities and related discounted future net cash flows as of June 30, 2014 assuming average constant realized prices of $89.22 per Bbl of oil and $5.08 per 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 Bbl 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. 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 ir@amzgcorp.com. 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.

AMERICAN EAGLE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	June 30,			December 31,
	2014			2013
Current assets:
Cash	$	22,187,502		$	31,850,161
Trade receivables		21,054,292			17,919,518
Income tax receivable		25,000			-
Prepaid expenses		124,727			68,194
Total current assets		43,391,521			49,837,873
Equipment and leasehold improvements, net of accumulated depreciation and amortization of $390,261 and $322,437, respectively		296,950			173,516
Oil and gas properties, full-cost method – subject to amortization, net of accumulated depletion of $22,236,408 and $12,849,063, respectively		265,552,093			155,145,039
Oil and gas properties, full-cost method – not subject to amortization		2,487,322			2,487,158
Marketable securities		1,418,446			1,049,944
Other assets		6,740,115			7,503,612
Total assets	$	319,886,447		$	216,197,142

Current liabilities:
Accounts payable and accrued liabilities	$	65,573,253		$	41,842,068
Derivative liability		3,959,643			64,737
Current portion of long-term debt		108,000,000			3,000,000
Total current liabilities		177,532,896			44,906,805
Asset retirement obligation		1,405,488			1,059,689
Noncurrent portion of long-term debt		-			105,000,000
Noncurrent derivative liability		4,878,187			749,872
Deferred taxes		2,650,619			5,385,954
Total liabilities		186,467,190			157,102,320
Stockholders’ equity:
Common stock, $.001 par value, 48,611,111 shares authorized, 30,436,766 and 17,712,151 shares outstanding		30,437			17,712
Additional paid-in capital		146,381,963			67,197,521
Accumulated other comprehensive loss		49,783			(5,747	)
Accumulated deficit		(13,042,926	)		(8,114,664	)
Total stockholders’ equity		133,419,257			59,094,822
Total liabilities and stockholders’ equity	$	319,886,447		$	216,197,142

AMERICAN EAGLE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	For the Three-Month Period Ended June 30,						For the Six-Month Period Ended June 30,
	2014			2013			2014			2013
Oil and gas sales	$	16,462,664		$	10,369,993		$	29,008,143		$	17,998,700

Operating expenses:
Oil and gas production costs		5,200,481			2,953,522			8,853,357			4,602,056
General and administrative		1,662,493			1,260,329			3,680,031			2,567,662
Depletion, depreciation and amortization expense		5,706,588			2,116,378			9,342,507			3,391,301
Impairment of oil and gas properties, subject to amortization		-			-			-			1,525,027

Total operating expenses		12,569,562			6,330,229			21,875,895			12,086,046

Total operating income		3,893,102			4,039,764			7,132,248			5,912,654

Interest income		-			1,472			642			4,628
Dividend income		11,685			16,982			27,481			34,222
Interest expense		(3,250,568	)		(414,797	)		(6,465,520	)		(833,137	)
Loss on settlement of derivatives		(457,008	)		-			(341,360	)		-
Change in fair value of derivatives		(6,200,119	)		186,754			(8,023,221	)		159,247

Income (loss) before taxes		(6,002,908	)		3,830,175			(7,669,730	)		5,277,614

Income tax expense (benefit)		(2,103,093	)		1,192,691			(2,741,468	)		2,284,783

Net income (loss)	$	(3,899,815	)	$	2,637,484		$	(4,928,262	)	$	2,992,831

Net income (loss) per common share:
Basic	$	(0.13	)	$	0.21		$	(0.20	)	$	0.24
Diluted	$	(0.13	)	$	0.20		$	(0.20	)	$	0.23

Weighted average number of shares outstanding -
Basic		30,436,424			12,517,087			24,529,013			12,494,987
Diluted		30,436,424			12,992,218			24,529,013			12,944,561

AMERICAN EAGLE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF

COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

	For the Three-Month Period Ended June 30,						For the Six-Month Period Ended June 30,
	2014			2013			2014			2013
Net income (loss)	$	(3,899,815	)	$	2,637,484		$	(4,928,262	)	$	2,992,831

Other comprehensive income (loss), net of tax:
Unrealized foreign exchange gains (losses)		(272,769	)		42,220			(116,573	)		12,783
Unrealized gains (losses) on securities		214,963			(32,999	)		172,103			(33,817	)
Total other comprehensive income (loss), net of tax		(57,806	)		9,221			55,530			(21,034	)

Comprehensive income (loss)	$	(3,957,621	)	$	2,646,705		$	(4,872,732	)	$	2,971,797

AMERICAN EAGLE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	For the Six-Month Periods Ended June 30,
	2014			2013
Cash flows provided by operating activities:
Net income (loss)	$	(4,928,262	)	$	2,992,831
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Non-cash transactions:
Stock-based compensation		898,674			524,520
Depletion, depreciation and amortization		9,342,507			3,391,301
Accretion of discount on asset retirement obligation		51,491			27,303
Amortization of deferred financing costs		763,497			112,175
Provision for deferred income tax expense (benefit)		(2,735,335	)		2,278,509
Impairment of oil and gas properties		-			1,525,027
Change in fair value of derivatives		8,023,221			(159,247	)
Foreign currency transaction gains		-			2,121
Changes in operating assets and liabilities:
Prepaid expense		(56,484	)		(199,492	)
Trade receivables		(3,612,973	)		(1,255,617	)
Income taxes receivable		(25,000	)		-
Accounts payable and accrued liabilities		1,512,529			4,621,105

Net cash provided by operating activities		9,233,865			13,860,536

Cash flows used for investing activities:
Additions to oil and gas properties		(96,784,537	)		(16,986,731	)
Additions to equipment and leasehold improvements		(191,258	)		(10,318	)
Decrease in amounts due to Carry Agreement partner		-			(2,283,973	)
Purchase of marketable securities		(196,400	)		-
Net cash used for investing activities		(97,172,195	)		(19,281,022	)

Cash flows provided by financing activities:
Proceeds from issuance of stock		78,298,493			4,000,000
Proceeds from issuance of long-term debt		-			2,000,000
Repayment of long-term debt		-			(2,611,463	)
Net cash provided by financing activities		78,298,493			3,388,537
Effect of exchange rate changes on cash		(22,822	)		26,278
Net change in cash		(9,662,659	)		(2,005,671	)
Cash - beginning of period		31,850,161			19,057,727
Cash - end of period	$	22,187,502		$	17,052,056

Non-GAAP Financial Measures

Adjusted EBITDA

In addition to reporting net income (loss) as defined under GAAP, American Eagle also presents net earnings before interest income, dividend income, interest expense, income taxes, depletion, depreciation, and amortization, non-cash expenses related to stock-based compensation, impairment of oil and gas properties, loss on early extinguishment of debt, and change in value of derivatives recognized under ASC Topic 718 (“Adjusted EBITDA”), which is a non-GAAP performance measure. Adjusted EBITDA consists of net earnings after adjustment for those items described in the table below. Adjusted EBITDA does not represent, and should not be considered an alternative to GAAP measurements, such as net income (loss) (its most directly comparable GAAP measure), and the calculations thereof may not be comparable to similarly titled measures reported by other companies. By eliminating the items described below, American Eagle believes the measure is useful in evaluating its fundamental core operating performance. The Company also believes that Adjusted EBITDA is useful to investors because similar measures are frequently used by securities analysts, investors, and other interested parties in their evaluation of companies in similar industries. American Eagle’s management uses Adjusted EBITDA to manage its business, including in preparing its annual operating budget and financial projections. Management does not view Adjusted EBITDA in isolation and also uses other measurements, such as net income (loss) and revenues to measure operating performance. The following table provides a reconciliation of net income (loss) to Adjusted EBITDA for the periods presented:

	Three Months Ended
	June 30,			March 31,			December 31,			September 30,			June 30,
	2014			2014			2013			2013			2013

Net income (loss)	$	(3,899,815	)	$	(1,028,447	)	$	(462,160	)	$	(936,237	)	$	2,637,484
Less: Interest income		-			(641	)		(6,964	)		(1,700	)		(1,472	)
Less: Dividend income		(11,685	)		(15,797	)		(16,523	)		(16,697	)		(16,982	)
Add: Interest expense		3,250,568			3,214,952			3,207,039			1,315,865			414,797
Add: Income tax expense (benefit)		(2,103,093	)		(638,375	)		130,056			(646,123	)		1,192,691
Add: Depletion, depreciation and amortization		5,706,588			3,635,919			4,158,124			2,524,039			2,116,378
Add: Stock-based compensation		444,648			454,026			375,756			302,842			287,172
Add: Impairment of oil and gas properties		-			-			206,508			-			-
Add: Loss on early extinguishment of debt		-			-			-			3,713,972			-
Add: Change in value of derivatives		6,200,119			1,823,102			39,569			934,287			(186,754	)
Adjusted EBITDA	$	9,587,330		$	7,444,739		$	7,631,405		$	7,190,248		$	6,443,314

Adjusted Cash Flow

In addition to reporting net income (loss) as defined under GAAP, American Eagle also presents cash flow after paying interest expense (“Adjusted Cash Flow”), which is a non-GAAP performance measure. Adjusted Cash Flow consists of Adjusted EBITDA after adjustment for those items described in the table below. Adjusted EBITDA does not represent, and should not be considered an alternative to GAAP measurements, such as net income (loss) (its most directly comparable GAAP measure), and the calculations thereof may not be comparable to similarly titled measures reported by other companies. By eliminating the items described below, American Eagle believes the measure is useful in evaluating its fundamental core operating performance. The Company also believes that Adjusted Cash Flow is useful to investors because similar measures are frequently used by securities analysts, investors, and other interested parties in their evaluation of companies in similar industries. American Eagle’s management uses Adjusted Cash Flow to manage its business, including in preparing its annual operating budget and financial projections. Management does not view Adjusted Cash Flow in isolation and also uses other measurements, such as net income (loss) and revenues to measure operating performance. The following table provides a reconciliation of Adjusted EBITDA to Adjusted Cash Flow for the periods presented:

	Three Months Ended
	June 30,			March 31,			December 31,			September 30,			June 30,
	2014			2014			2013			2013			2013

Adjusted EBITDA ⁽¹⁾	$	9,587,330		$	7,444,739		$	7,631,405		$	7,190,248		$	6,443,314
Less: Interest expense		(3,250,568	)		(3,214,952	)		(3,207,039	)		(1,315,865	)		(414,797	)
Add: Amortization of deferred financing costs (non-cash)		383,857			379,640			327,922			161,758			66,944
Adjusted Cash Flow	$	6,720,619		$	4,609,427		$	4,752,288		$	6,036,141		$	6,095,461

Adjusted Cash Flow per share - basic	$	0.22		$	0.25		$	0.34		$	0.46		$	0.49
Adjusted Cash Flow per share - diluted	$	0.22		$	0.24		$	0.33		$	0.44		$	0.47

Weighted average shares - basic		30,436,424			18,556,695			13,961,688			13,223,608			12,517,087
Weighted average shares - diluted		31,017,574			19,205,118			14,598,836			13,732,595			12,992,218

(1) See previous table for reconciliation of net income (loss) to Adjusted EBITDA.

Adjusted Income

In addition to reporting net income (loss) as defined under GAAP, American Eagle also presents net earnings before the impairment of oil and gas properties, loss on early extinguishment of debt, and non-cash expenses related to the change in fair value of derivatives (“adjusted income (loss)”), which is a non-GAAP performance measure. Adjusted income (loss) consists of net earnings after adjustment for those items described in the table below. Adjusted income (loss) does not represent, and should not be considered an alternative to GAAP measurements, such as net income (loss), and the calculations thereof may not be comparable to similarly titled measures reported by other companies. By eliminating the items described below, American Eagle believes the measure is useful in evaluating its fundamental core operating performance. The Company also believes that adjusted income (loss) is useful to investors because similar measures are frequently used by securities analysts, investors, and other interested parties in their evaluation of companies in similar industries. American Eagle’s management uses adjusted income (loss) to manage its business, including in preparing its annual operating budget and financial projections. Management does not view adjusted income (loss) in isolation and also uses other measurements, such as net income (loss) and revenues to measure operating performance. The following table provides a reconciliation of net income (loss), to adjusted income (loss) for the periods presented:

	Three Months Ended
	June 30,			March 31,			December 31,			September 30,			June 30,
	2014			2014			2013			2013			2013

Net income (loss)	$	(3,899,815	)	$	(1,028,447	)	$	(462,160	)	$	(936,237	)	$	2,637,484
Add: Impairment of oil and gas properties		-			-			206,508			-			-
Add: Loss on early extinguishment of debt		-			-			-			3,713,972			-
Add: Change in fair value of derivatives		6,200,119			1,823,102			39,569			934,287			(186,754	)
Adjusted Income / (Loss)	$	2,300,303		$	794,655		$	(216,083	)	$	3,712,022		$	2,450,730

Adjusted Income (Loss) per share - basic	$	0.08		$	0.04		$	(0.02	)	$	0.28		$	0.20
Adjusted Income (Loss) per share - diluted	$	0.07		$	0.04		$	(0.01	)	$	0.27		$	0.19

Weighted average shares - basic		30,436,424			18,556,695			13,961,688			13,223,608			12,517,087
Weighted average shares - diluted		31,017,574			19,205,118			14,598,836			13,732,595			12,992,218

CORPORATE CONTACT:

Marty Beskow, CFA

Vice President of Capital Markets and Strategy

American Eagle Energy Corporation

720-330-8378

ir@amzgcorp.com

www.americaneagleenergy.com

Exhibit 99.2

American Eagle Energy Announces Proposed Offering of Senior Secured Notes

DENVER, CO—August 4, 2014—American Eagle Energy Corporation (NYSE MKT: AMZG) (“American Eagle” or the “Company”), announces today that the Company intends to offer $175 million in aggregate principal amount of senior secured notes due 2019 (the “Notes”) in a private placement to eligible investors, subject to market conditions. The Company also intends to put in place a senior secured revolving credit facility with approximate borrowing capacity of up to $60 million, in conjunction with or soon after the Notes offering.

American Eagle plans to use the proceeds from the Notes to refinance its existing credit facility, for general corporate purposes (including working capital), and to pay fees and expenses associated with the offering of the Notes and those related to its existing credit facility.

This press release does not constitute an offer to sell or the solicitation of an offer to buy securities. Any offers of the Notes will be made only by means of a private offering circular. The Notes and related guarantees have not been registered under the Securities Act of 1933, as amended (the “Securities Act”), or the securities laws of any other jurisdiction and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements. The Notes are being offered and sold only to qualified institutional buyers under Rule 144A and to non-U.S. persons outside the United States under Regulation S. This notice is being issued in accordance with Rule 135c under the Securities Act.

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. 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

CORPORATE CONTACT:

Marty Beskow, CFA

Vice President of Capital Markets and Strategy

American Eagle Energy Corporation

720-330-8378

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
United States	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

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