UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

FORM 10-Q

 

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended June 30, 2014.

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from                                                      to                                                    

 

Commission File Number:  000-50906

 

 

AMERICAN EAGLE ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

 

Nevada	20-0237026
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

 

2549 West Main Street, Suite 202, Littleton, Colorado	80120
(Address of principal executive offices)	(Zip Code)

 

(303) 798-5235

(Registrant’s telephone number, including area code)

 

Indicate by check mark whether the registrant:  (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

(Check one):

 

Large accelerated filer o	Accelerated filer o
Non-accelerated filer o	Smaller reporting company x

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

 Yes o No x

 

Indicate the number of shares outstanding of each of the issuer’s classes of common equity, as of the latest practicable date:

30,448,185 shares of common stock issued and outstanding at August 1, 2014.

 

 

INDEX

 

A Note About Forward Looking Statements	2
PART I - FINANCIAL INFORMATION
Item 1 – Condensed Consolidated Financial Statements (Unaudited)	3
Condensed Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013 (Unaudited)	5
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) for the Three-Month and Six-Month Periods Ended June 30, 2014 and 2013 (Unaudited)	6
Condensed Consolidated Statements of Cash Flows for the Six-Month Periods Ended June 30, 2014 and 2013 (Unaudited)	8
Notes to the Condensed Consolidated Financial Statements (Unaudited)	9
Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 4 – Controls and Procedures	33
PART II – OTHER INFORMATION
Item 6 – Exhibits	34
Signatures	38

 

 

A Note About Forward Looking Statements

 

This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 that are based on management’s current expectations.  These statements may be identified by their use of words like “plans,” “expect,” “aim,” “believe,” “projects,” “anticipate,” “intend,” “estimate,” “will,” “should,” “could” and other expressions that indicate future events and trends.  All statements that address expectations or projections about the future, including statements about our business strategy, expenditures, and financial results, are forward-looking statements.  We believe that the expectations reflected in such forward-looking statements are accurate.  However, we cannot assure the reader that such expectations will occur.

 

Actual results could differ materially from those in the forward-looking statements due to a number of uncertainties including, but not limited to, those discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations.  Factors that could cause future results to differ from these expectations include general economic conditions; further changes in our business direction or strategy; competitive factors; market uncertainties; and an inability to attract, develop, or retain consulting or managerial agents or independent contractors.  As a result, the identification and interpretation of data and other information and their use in developing and selecting assumptions from and among reasonable alternatives requires the exercise of judgment.  To the extent that the assumed events do not occur, the outcome may vary substantially from anticipated or projected results, and accordingly, no opinion is expressed on the achievability of those forward-looking statements.  No assurance can be given that any of the assumptions relating to the forward-looking statements specified in the following information are accurate, and we assume no obligation to update any such forward-looking statements.  The reader should not unduly rely on these forward-looking statements, which speak only as of the date of this Quarterly Report.  Except as required by law, we are not obligated to release publicly any revisions to these forward-looking statements to reflect events or circumstances occurring after the date of this report or to reflect the occurrence of unanticipated events.

 

 

PART I – FINANCIAL INFORMATION

 

ITEM 1. FINANCIAL STATEMENTS

 

  

American Eagle Energy Corporation

 

Condensed Consolidated Financial Statements

 

As of June 30, 2014 and December 31, 2013 and

For the Three-Month and Six-Month Periods Ended June 30, 2014 and 2013

 

 

American Eagle Energy Corporation

 

Index to the Financial Statements

 

As of June 30, 2014 and December 31, 2013 and

For the Three-Month and Six-Month Periods Ended June 30, 2014 and 2013

 

Condensed Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013 (Unaudited)	5
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) for the Three-Month and Six-Month Periods Ended June 30, 2014 and 2013 (Unaudited)	6
Condensed Consolidated Statements of Cash Flows for the Six-Month Periods Ended June 30, 2014 and 2013 (Unaudited)	8
Notes to the Condensed Consolidated Financial Statements (Unaudited)	9

  

 

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 income (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

 

The accompanying notes are an integral part of the condensed consolidated financial statements.

 

 

American Eagle Energy Corporation

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

(Unaudited)

 

		For the Three-Month Period								For the Six-Month Period
		Ended June 30,								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			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	)
Losses 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

 

The accompanying notes are an integral part of the condensed consolidated financial statements.

 

  

American Eagle Energy Corporation

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

(Unaudited)

 

		For the Three-Month Period								For the Six-Month Period
		Ended June 30,								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

 

The accompanying notes are an integral part of the condensed consolidated financial statements.

 

 

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

 

The accompanying notes are an integral part of the condensed consolidated financial statements.

 

 

American Eagle Energy Corporation

Notes to the Condensed Consolidated Financial Statements

As of June 30, 2013 and December 31, 2012 and

For the Three-Month and Six-Month Periods Ended June 30, 2013 and 2012

 

1.

Description of Business

 

American Eagle Energy Corporation (the “Company”) was incorporated in the state of Nevada in March 2003 under the name Golden Hope Resources. In July 2005, the Company changed its name to Eternal Energy Corp. In December 2011, the Company changed its name to American Eagle Energy Corporation, in connection with its acquisition of, and merger with, American Eagle Energy Inc.

 

The Company engages in the acquisition, exploration and development of oil and gas properties, and is primarily focused on extracting proved oil reserves from those properties. As of June 30, 2014, the Company had entered into participation agreements related to oil and gas exploration and development projects in the Spyglass Area, located in Divide County, North Dakota, and Sheridan County, Montana, and the Hardy Property, located in southeastern Saskatchewan, Canada. In addition, the Company owns working interests in mineral leases located in Richland, Roosevelt and Toole Counties in Montana.

 

2.

Summary of Significant Accounting Policies

 

Interim Financial Information

 

The unaudited condensed consolidated financial statements included herein have been prepared in accordance with generally accepted accounting principles for interim financial statements in accordance with Regulation S-X. Accordingly, they do not include all of the information and footnotes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring adjustments) considered necessary for the fair presentation have been included. Operating results for the three-month and six-month periods ended June 30, 2014 are not necessarily indicative of results that may be expected for the year ended December 31, 2014. The condensed, consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Form 10-K for the year ended December 31, 2013. The December 31, 2013 condensed consolidated balance sheet was derived from audited financial statements.

 

Basis of Presentation

 

The accompanying condensed consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, AMZG, Inc., EERG Energy ULC (Canadian) and AEE Canada Inc. (Canadian). All material intercompany accounts, transactions and profits have been eliminated.

 

Certain reclassifications have been made to prior year balances to conform to the current year’s presentation. Such reclassifications had no effect on the Company’s net income for the prior period.

 

 

 

American Eagle Energy Corporation

Notes to the Condensed Consolidated Financial Statements

As of June 30, 2013 and December 31, 2012 and

For the Three-Month and Six-Month Periods Ended June 30, 2013 and 2012

 

3.

Marketable Securities and Fair Value of Financial Instruments

 

Available-for-sale marketable securities at June 30, 2014 and December 31, 2013 consist of the following:

 

Gains in

Losses in

Accumulated

Accumulated

Estimated

Other

Other

Fair

Comprehensive

Comprehensive

Value

Income

Income

June 30, 2014

Noncurrent assets:

Common stock

$

1,418,446

$

187,446

$

-

December 31, 2013

Noncurrent assets:

Common stock

$

1,049,944

$

76,881

$

-

 

The fair value of all securities is determined by quoted market prices. There were no sales of marketable securities during the three-month or six month periods ended June 30, 2014.

 

Fair value is the price that would be received from the sale of an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 or 3 are terms for the priority of inputs to valuation techniques used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.

 

The fair value of the Company’s financial instruments, measured on a recurring basis at June 30, 2014 and December 31, 2013, were as follows:

 

		Level 1				Level 2				Level 3				Total
June 30, 2014
Marketable securities		$	1,418,446			$	-			$	-			$	1,418,446
Current derivative liability			-				(3,959,643	)			-				(3,959,643	)
Noncurrent derivative liability			-				(4,878,187	)			-				(4,878,187	)
December 31, 2013
Marketable securities		$	1,049,944			$	-			$	-			$	1,049,944
Current derivative asset			-				210,779				-				210,779
Current derivative liability			-				(275,516	)			-				(275,516	)
Noncurrent derivative liability			-				(749,872	)			-				(749,872	)

 

  

American Eagle Energy Corporation

Notes to the Condensed Consolidated Financial Statements

As of June 30, 2013 and December 31, 2012 and

For the Three-Month and Six-Month Periods Ended June 30, 2013 and 2012

 

4.

Purchases of Property Interests

 

In January 2013, the Company purchased additional net revenue and working interests in several key, non-operated spacing units within the Spyglass Area from SM Energy Company. The purchase price totaled approximately $3.9 million in cash, which was paid at closing.

 

In October 2013, the Company purchased additional net revenue and working interests in proved producing and proved undeveloped properties located within the Spyglass Area from a certain working interest partner. The transaction closed on October 2, 2013 with an effective date of June 1, 2013. The gross purchase price for the acquired interests totaled $47 million. The net purchase prices, after taking into consideration revenues and operating expenses associated with the acquired interests from the period June 1, 2013 through the closing date, totaled $41.4 million. To finance the acquisition, the Company sold shares of its common stock, through two public offerings (See Note 11), and borrowed an additional $40 million under its existing credit facility with Morgan Stanley Capital Group, Inc. (“MSCG”)(See Note 8). The agreement contained the option to purchase additional net revenue and working interests in the same producing and proved undeveloped properties at a later date.

 

In March 2014, the Company exercised its option to purchase the additional net revenue and working interests in proved producing and proved undeveloped properties located within the Spyglass Area from the same working interest partner. The transaction closed on March 26, 2014 with an effective date of June 1, 2013. The gross purchase price for the acquired interests totaled $47 million. The purchase price is subject to adjustments for revenues, operating expenses and capital expenditures associated with the acquired interests from the period June 1, 2013 through the closing date. The acquisition of the additional net revenue and working interests was funded with proceeds received from a March 2014 public offering, as discussed in Note 11).

 

Supplemental Pro Forma Information (Unaudited)

 

The Company’s condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2014 include revenues and oil and gas operating expenses related to the net revenue and working interests acquired via the exercise of the purchase option, for the period April 1, 2014 through June 30, 2014.

 

Had the purchase of these additional net revenue and working interests occurred on January 1, 2013, the Company’s consolidated financial statements for the six-month periods ended June 30, 2014 and 2013 would have been as follows:

 

 

American Eagle Energy Corporation

Notes to the Condensed Consolidated Financial Statements

As of June 30, 2013 and December 31, 2012 and

For the Three-Month and Six-Month Periods Ended June 30, 2013 and 2012

 

		2014				2013
Pro forma revenues		$	32,182,138			$	20,182,301
Pro forma net income (loss)		$	(4,420,703	)		$	2,291,484
Pro forma income (loss) per share - basic		$	(0.16	)		$	0.09
Pro forma income (loss) per share – diluted		$	(0.16	)		$	0.09

 

The acquisition of the working interests could not have been completed without an initial acquisition of related working interests that occurred in October 2013. Accordingly, the pro forma effect of the initial acquisition of working interests has also been included in the pro forma information presented above for the six-month period ended June 30, 2013.

 

Also in March 2014, the Company acquired certain undeveloped acreage from the same working interest partner at a price of approximately $7.5 million.

 

5.

Carry Agreement

 

On April 16, 2012, the Company entered into a Carry Agreement with a third-party working interest partner (the “Carry Agreement Partner”), pursuant to which (i) the Carry Agreement Partner agreed to fund 100% of the Company’s working interest share of the drilling and completion costs of up to six new oil and gas wells within our Spyglass Area, up to 120% of the original AFE amount, and (ii) the Company agreed to convey, for a limited duration, a portion of its revenue interest in the pre-payout revenues of each carried well and a portion of its working interest in the pre-payout operating costs of each carried well, to the Carry Agreement Partner. In the event that the gross drilling and completion cost of a carried well exceeds 120% of the AFE amount, the Company and the Carry Agreement Partner would share in the excess costs based on the working interests stipulated in the Carry Agreement.

 

Pursuant to the terms of the Carry Agreement, the portion of the Company’s net revenue interest in each well to be conveyed to the Carry Agreement Partner followed a graduated scale, whereby 50% of the Company’s net revenue and working interests are assigned to the Carry Agreement Partner during the first year of the well’s production or until the carried costs, plus the 12% return, have been achieved, whichever occurs first. In the event that the Carry Agreement Partner had not recouped all of the carried costs plus the 12% return by the end of the first year of production, the assignment of the Company’s net revenue and working interests in the well would increase from 50% to 75% for the second year of production or until the carried costs, plus the 12% return, had been achieved, whichever occurs first. In the event that the Carry Agreement Partner had not recouped all of the carried costs, plus the 12% return, by the end of the second year of production, the assignment of the Company’s net revenue and working interests in the well would increase to 100% until the carried costs, plus the 12% return, had been achieved. Once payout has occurred (112% of the costs on a well-by-well basis), the respective working interests in the revenues from each carried well would revert to the original working interests in each such well.

 

 

American Eagle Energy Corporation

Notes to the Condensed Consolidated Financial Statements

As of June 30, 2013 and December 31, 2012 and

For the Three-Month and Six-Month Periods Ended June 30, 2013 and 2012

 

Effective July 15, 2012, the Company amended the Carry Agreement with the third-party to include an additional four oil and gas wells.

 

In August 2013, the Company entered into a second carry agreement (the “Second Carry Agreement”) with the Carry Agreement Partner, pursuant to which (i) that Carry Agreement Partner agreed to fund 100% of the Company’s working interest share of the drilling and completion costs of up to five new oil and gas wells to be located within the Spyglass Area, up to 120% of the original AFE amount, and (ii) the Company agreed to convey, for a limited duration, 50% of its revenue interest in the pre-payout revenues of each carried well and 50% of its working interest in the pre-payout operating costs of each carried well, to the Carry Agreement Partner.  In the event that the gross drilling and completion cost of a carried well exceeds 120% of the AFE amount, the Company and the Carry Agreement Partner will share in the excess costs based on the working interests stipulated in the Carry Agreement. 

 

Pursuant to the terms of the Second Carry Agreement, 50% of the Company’s net revenue interest in each well will be conveyed to the Carry Agreement Partner for a period of two years or until such a time when the working interest partner has recouped 112% of the carried drilling and completion costs of the well, whichever occurs sooner.  In the event that the Carry Agreement Partner has not recouped 112% of the carried drilling and completion costs by the end of the second year of production, the Company has agreed to make cash payments to the Carry Agreement Partner in the amount of the shortfall.  Once the Carry Agreement Partner has recouped 112% of the carried drilling and completion costs of a well, the conveyed working interest and net revenue interest will revert to the Company. 

 

As discussed in Note 4, the Company acquired net revenue and working interests associated with certain properties, in March 2014, which included 100% of the net revenue and working interests that had been conveyed to the Carry Agreement Partner, which effectively terminated the Carry Agreement.

 

As of June 30, 2014, all five of the wells to be drilled pursuant to the Second Carry Agreement have been completed. To date, the Company has received approximately $15.1 million of funding under the Second Carry Agreement. As of June 30, 2014, the cost of drilling and completing one of the five wells exceeded the 120% of AFE cost threshold. Accordingly, the Company has recorded its portion of excess drilling and completion costs associated with this well, totaling approximately $373,000 as of June 30, 2014. None of the five wells covered by the Second Carry Agreement has achieved payout as of June 30, 2014.

 

 

American Eagle Energy Corporation

Notes to the Condensed Consolidated Financial Statements

As of June 30, 2013 and December 31, 2012 and

For the Three-Month and Six-Month Periods Ended June 30, 2013 and 2012

 

6.

Farm-Out Agreement

 

In August 2013, the Company entered into a Farm-Out Agreement (the “Farm-Out Agreement”) with the Carry Agreement Partner, pursuant to which (i) that Carry Agreement Partner agreed to fund 100% of the Company’s working interest share of the drilling and completion costs of up to six new oil and gas wells to be located within the original Spyglass and West Spyglass sections of the Spyglass Area and (ii) the Company agreed to convey, for a period of time, 100% of its net revenue interest in the pre-payout revenues of each farm-out well and 100% of its working interest in the pre-payout operating costs of each farm-out well, to the Carry Agreement Partner, until such a time when the Carry Agreement Partner has recouped 112% of the drilling and completion costs associated with each well.  Once the Carry Agreement Partner has recouped 112% of the drilling and completion costs of a well, the Carry Agreement Partner will convey 30% of the Company’s original working and net revenue interests in each farm-out well back to the Company.

 

As of June 30, 2014, five of the six wells drilled pursuant to the Farm-Out Agreement have been completed. The remaining well is awaiting drilling. None of the six wells covered by the Farm-Out Agreement has achieved payout as of June 30, 2014.

 

7.

Swap Facility

 

On December 28, 2012, the Company entered into a prepaid Swap Facility with Macquarie Bank Limited (“MBL”), pursuant to which MBL agreed to advance up to $18 million, of which $16 million was received at closing. The remaining $2 million was received in January 2013.

 

Funds received under the Swap Facility were accounted for as debt and were scheduled to be repaid through a series of monthly payments from the sale of approximately 212,000 barrels of oil over the five-year period from January 2013 to December 2017, with a final balloon payment of $2 million, due in February 2018.

 

The annual interest rate associated with the Swap Facility approximated 7.4%. The Company recognized interest expense related to the Swap Facility totaling approximately $299,000 and $591,000 for the three-month and six-month periods ended June 30, 2013, respectively. 

 

The Company incurred investment banking fees and closing costs totaling $780,000 in connection with the negotiation and closing of the MBL Swap Facility. The Company capitalized these items as deferred financing costs, to be amortized over the life of the Swap Facility. The Company recognized approximately $67,000 and $112,000 of amortization expense related to the deferred financing costs for the three-month and six-month periods ended June 30, 2013, respectively. The amortization of deferred loan costs is included as an additional component of interest expense for the respective periods.

 

On August 19, 2013, the Company repaid in full the outstanding balance under the Swap Facility using proceeds received from a new Credit Facility (see Note 8). The total payoff amount was approximately $18.0 million, which included 100% of the then outstanding principal balance, the settlement of all outstanding swap agreements, and certain prepayment penalties. The Company recognized a loss on the early extinguishment of debt of approximately $3.7 million, which includes prepayment penalties, the termination of related price swap agreements and the write-off of deferred financing costs associated with the Swap Facility.

 

 

American Eagle Energy Corporation

Notes to the Condensed Consolidated Financial Statements

As of June 30, 2013 and December 31, 2012 and

For the Three-Month and Six-Month Periods Ended June 30, 2013 and 2012

 

8.

Credit Facility

 

In August 2013, the Company entered into a $200 million Credit Facility with MSCG, which is comprised of an initial $68 million term loan (the “Initial Term Loan”), a $40 million term loan to be used to fund certain working interest purchases (the “Spyglass Tranche A Loan”) and an uncommitted term loan of up to $92 million (the “Tranche B Loan”). The Credit Facility is collateralized by, among other things, the Company’s oil and gas properties and future oil and gas sales derived from such properties.

 

Proceeds from borrowings under the Initial Term Loan totaling $68 million were used: (i) to repay amounts outstanding under the Swap Facility, thus fully extinguishing the Swap Facility, (ii) to reduce the Company’s payables, (iii) to develop its Spyglass Area in North Dakota to increase production of hydrocarbons, (iv) to acquire new oil and gas properties within the Spyglass Area and (v) to fund general corporate purposes that are usual and customary in the oil and gas exploration and production business.

 

Proceeds from borrowings under the Spyglass Tranche A Loan totaling $40 million were used to purchase additional net revenue and working interests in the Spyglass Area (See Note 4).

 

The Credit facility has a five-year term and carries a variable interest rate ranging from approximately 5.5% to 10.5%. The variable interest rate is based primarily on the ratio of the Company’s proved developed reserves to its debt for a given period. As of June 30, 2014, the applicable variable interest rate on the Credit Facility was 10.5%. Interest expense related to the Initial Term Loan and Spyglass Tranche A Loan totaled approximately $2.9 million and $5.7 million for the three-month and six-month periods ended June 30, 2014, respectively.

 

The Company incurred investment banking fees and closing costs totaling approximately $7.8 million in connection with the negotiation and closing of the Initial Term Loan and Spyglass Tranche A Loan. The Company has capitalized these items as deferred financing costs, and amortizes these costs over the life of the Credit Facility using the effective interest method. The amortization of deferred financing costs is included as a component of the Company’s interest expense for the period. The Company amortized approximately $383,000 and $763,000 of deferred financing costs related to the Credit Facility during the three-month and six-month periods ended June 30, 2014, respectively.

 

Scheduled principal repayments under the Credit Facility begin in August 2014. The amount of each monthly principal payment is dependent on the ratio of the present value of the Company’s proved developed reserves, discounted at a rate of 9%, to the amount of borrowing outstanding under the Credit Facility as of certain predetermined dates. The minimum monthly amortization applicable to the Initial Term Loan and the Spyglass Tranche A Loan is $600,000.

 

 

American Eagle Energy Corporation

Notes to the Condensed Consolidated Financial Statements

As of June 30, 2013 and December 31, 2012 and

For the Three-Month and Six-Month Periods Ended June 30, 2013 and 2012

 

The Credit Facility contains customary affirmative and negative covenants for borrowings of this type, including limitations on the Company with respect to transactions with affiliates, hedging agreements, dividends and distributions, operations in respect of the property that secures its collective obligations under the Credit Facility, liens and encumbrances in respect of the property that secures the Company’s collective obligations under the Credit Facility, subsidiaries and divestitures, indebtedness, investments, and changes in business.

 

The Credit Agreement also contains a number of financial covenants, including the maintaining of an adjusted minimum working capital ratio of 1.0. The adjusted minimum working capital ratio is calculated by dividing current assets, less any current derivative assets, by current liabilities, less the current portion of debt outstanding under the Credit Agreement, unpaid deferred loan costs and any current derivative liability. As of June 30, 2014, the Company’s adjusted minimum working capital ratio was less than 1.0. MSGC has waived compliance with the adjusted working capital ratio as of June 30, 2014. The Company is not subject to the measurement of the adjusted current ratio requirement again until September 30, 2014.

 

The Company’s management is currently seeking additional, alternative financing that it believes will enable the Company to either comply with the minimum adjusted working capital ratio covenant at September 30, 2014 or to fully repay the outstanding balance of the existing Credit Facility. In the event that the Company is unable to secure alternative financing before then, it is likely that it will be in technical default of the adjusted working capital covenant under the Credit Facility as of September 30, 2014. Accordingly, the Company has classified the entire balance outstanding under the Credit Facility as a current liability on its June 30, 2014 condensed, consolidated balance sheet. The Company’s management does not believe that it will be required to repay the entire amount outstanding under the Credit Facility during the ensuing twelve months.

 

9.

Price Swap Agreements

 

As a condition of closing for the Swap Facility (see Note 7), the Company entered into various commodity derivative contracts to mitigate the effects of potential downward pricing on the Company’s oil and gas revenues. The contracts included floating vs. fixed price swaps for the Company’s produced oil. The Company did not designate the price swap agreements as hedges. Accordingly, management elected not to apply hedge accounting to these derivatives but, instead, recognized the changes in the fair value of the price swap agreements in its statement of operations in the period for which such unrealized changes occurred. The Company recognized gains from the change in fair value of the price swap agreements associated with the Swap Facility of approximately $187,000 and $159,000 for the three-month and six-month periods ended June 30, 2013, respectively. These price swaps were closed in August 2013 concurrent with the full repayment of the Swap Facility.

 

 

American Eagle Energy Corporation

Notes to the Condensed Consolidated Financial Statements

As of June 30, 2013 and December 31, 2012 and

For the Three-Month and Six-Month Periods Ended June 30, 2013 and 2012

 

As a condition of the Credit Facility (see Note 8), the Company is required to enter into commodity price swap agreements covering up to 85% of its projected five-year future production on its proved, developed, producing properties. The Company has not designated the price swap agreements as hedges. Accordingly, management has elected not to apply hedge accounting to these derivatives but will, instead, recognize the changes in the fair value of the price swap agreements in its statement of operations in the period in which such unrealized changes in fair value occur. The Company recognized losses of approximately $457,000 and $341,000 on the settlement of price swap agreements during the three-month and six-month periods ended June 30, 2014. The Company also recognized losses of approximately $6.2 million and $8.0 million due to changes in the fair value of price swap agreements associated with the Credit Facility for the three-month and six-month periods ended June 30, 2014, respectively.

 

The Company’s outstanding price swap agreements had the following net fair market values as of June 30, 2014 and December 31, 2013:

 

		June 30,				December 31,
		2014				2013
Current derivative asset		$	-			$	210,779
Current derivative liability			(3,959,643	)			(275,516	)
Noncurrent derivative liability			(4,878,187	)			(749,872	)
Net derivative liability		$	(8,837,830	)		$	(814,609	)

 

10.

Asset Retirement Obligation

 

The Company has recorded estimated asset retirement obligations for the future plugging and abandonment of operated and non-operated wells within its Spyglass and Hardy Properties. As of June 30, 2014 and December 31, 2013, the Company’s asset retirement obligation approximated $1.4 million and $1.1 million, respectively. The projected plugging dates for wells in which the Company owns a working interest ranges from December 31, 2015 to June 30, 2035.

 

11.

Equity Transactions

 

Reverse Split

 

In March 2014, the Company completed a 1-for-4 reverse split of its common stock. Pursuant to accounting guidelines, all historical share and per-share data contained in these financial statements have been restated to reflect the reverse split for all periods presented.

 

 

American Eagle Energy Corporation

Notes to the Condensed Consolidated Financial Statements

As of June 30, 2013 and December 31, 2012 and

For the Three-Month and Six-Month Periods Ended June 30, 2013 and 2012

  

Private Placement

  

In January 2013, the Company sold 1,000,000 shares of its common stock in a private placement at a price of $4.00 per share. Proceeds from the sale totaled $4,000,000.

  

Public Offerings

  

 In August 2013, the Company sold 1,250,000 shares of its common stock in a public offering at a price of $8.00 per share. Proceeds from the sale totaled $9.9 million, net of investment banking fees.

 

 In October 2013, the Company sold 3,941,449 shares of its common stock at a price of $6.80 per share in two public offerings. The sales were completed pursuant to the then-current shelf registration, which was filed in August 2013. Proceeds from the sales, net of expenses, broker fees and commissions, totaled approximately $25.0 million.

 

In March 2014, the Company sold 12,650,000 shares of its common stock in a public offering at a price of $6.60 per share. The sale of stock was completed pursuant to the Company’s December 2013 shelf registration. Proceeds from the sale, net of expenses, broker fees and commissions, totaled approximately $78.0 million.

 

Stock Options

 

During the year ended December 31, 2013, the Company granted 440,000 stock options to members of its Board of Directors, employees and certain key third-party consultants. The options have exercise prices ranging from $5.84 to $9.28 per share. Each of the stock options granted has a five-year life and vest 50% on the one-year anniversary of the grant date, with the remaining 50% vesting on the second-year anniversary date.

 

The assumptions used in the Black-Scholes Option Pricing Model for the stock options granted during the 2013 were as follows:

 

Risk-free interest rate	0.23 to 0.35%
Expected volatility of common stock	62% to 84%
Dividend yield	$0.00
Expected life of options	5 years

 

During the six-month period ended June 30, 2014, the Company granted 37,500 stock options to certain employees. The options have exercise prices ranging from $6.18 to $7.05 per share. Each of the stock options granted has a five-year life and vest 50% on the one-year anniversary of the grant date, with the remaining 50% vesting on the second-year anniversary date.

 

 

American Eagle Energy Corporation

Notes to the Condensed Consolidated Financial Statements

As of June 30, 2013 and December 31, 2012 and

For the Three-Month and Six-Month Periods Ended June 30, 2013 and 2012

 

The assumptions used in the Black-Scholes Option Pricing Model for the stock options granted during the 2014 were as follows:

 

Risk-free interest rate	0.43 to 0.48%
Expected volatility of common stock	59% to 61%
Dividend yield	$0.00
Expected life of options	5 years

 

The options outstanding as of June 30, 2014 and December 31, 2013 have an intrinsic value of $2.69 and $4.12 per share and an aggregate intrinsic value of approximately $5.3 million and $7.9 million, respectively.

  

Shares Reserved for Future Issuance

  

As of June 30, 2014 and December 31, 2012, the Company had reserved 1,963,025 and 1,926,775 shares, respectively, for future issuance upon exercise of outstanding options.

 

12.

Earnings Per Share

 

The following is a reconciliation of the number of shares used in the calculation of basic and diluted earnings per share for the three-month periods ended June 30, 2014 and 2013:

 

		Three Months								Six Months Ended
		Ended June 30,								Ended June 30,
		2014				2013				2014				2013
Net income (loss)		$	(3,899,815	)		$	2,637,484			$	(4,928,262	)		$	2,992,831
Weighted average number of common shares outstanding			30,436,424				12,517,087				24,529,013				12,494,987
Incremental shares from the assumed exercise of dilutive stock options			-				475,132				-				449,574
Diluted common shares outstanding			30,436,424				12,992,219				24,529,013				12,944,561
Earnings (loss) per share – basic		$	(0.13	)		$	0.21			$	(0.20	)		$	0.24
Earnings (loss) per share – diluted		$	(0.13	)		$	0.20			$	(0.20	)		$	0.23

 

Because the Company recognized a net loss for the three-month and six-month periods ended June 30, 2014, the calculation of diluted loss per share is the same as the calculation of basis loss per share, as the effect of including any incremental shares from the assumed exercise of dilutive stock options would be anti-dilutive. The number of anti-dilutive shares that have been excluded from the calculation of diluted loss per share for the three month-period and six-month periods ended June 30, 2014 is 581,150 and 614,964, respectively.

 

 

American Eagle Energy Corporation

Notes to the Condensed Consolidated Financial Statements

As of June 30, 2013 and December 31, 2012 and

For the Three-Month and Six-Month Periods Ended June 30, 2013 and 2012

 

13.

Related Party Transactions

 

The Company is under contract through February 2016 to sell 100% of its oil, gas and liquids production to Power Energy Partners LP (“Power Energy”). As of June 30, 2014, Power Energy holds 2,250,000 shares of our common stock.

 

The Company routinely obtains legal services from a firm for whom one of its directors serves as a principal. Fees paid this firm approximated $12,000 and $33,000 for the six-month periods ended June 30, 2014 and 2013, respectively.

 

The Company receives monthly geological consulting services from Synergy Energy Resources LLC (“Synergy”). One of the Company’s current directors and one current officer own material ownership interests in Synergy. The Company incurred $42,000 and $84,000 of consulting expenses from Synergy during the three-month and six-month periods ending June 30, 2014 and 2013, respectively. The Company terminated its consulting agreement with Synergy on June 30, 2014.

 

The Company’s Chairman and Chief Operating Officer each owns overriding royalty interests in certain of the Company’s operated wells. The overriding royalty interests were obtained prior the Company’s acquisition of AEE, Inc. in December 2011. Royalties paid to these individuals totaled approximately $86,000 and $135,000 for the three-month period ended June 30, 2014, respectively, and approximately $252,000 and $304,000 for the six-month period ended June 30, 2013, respectively.

 

13.

Subsequent Events

 

In July 2014, the Company sold its interest in its Canadian oil and gas properties. Net proceeds received from the sale totaled approximately $1.8 million.

 

 

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

 

THE FOLLOWING PRESENTATION OF OUR MANAGEMENT'S DISCUSSION AND ANALYSIS SHOULD BE READ IN CONJUNCTION WITH THE FINANCIAL STATEMENTS AND OTHER FINANCIAL INFORMATION INCLUDED ELSEWHERE IN THIS REPORT.

 

A Note About Forward-Looking Statements

 

This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 that are based on current management's expectations. These statements may be identified by their use of words like “plans,” “expect,” “aim,” “believe,” “projects,” “anticipate,” “intend,” “estimate,” “will,” “should,” “could,” and other expressions that indicate future events and trends. All statements that address expectations or projections about the future, including statements about our business strategy, expenditures, and financial results are forward-looking statements. We believe that the expectations reflected in such forward-looking statements are accurate. However, we cannot assure the reader that such expectations will occur.

 

Actual results could differ materially from those in the forward-looking statements due to a number of uncertainties, including, but not limited to, those discussed in this section. Factors that could cause future results to differ from these expectations include general economic conditions, further changes in our business direction or strategy, competitive factors, oil and gas exploration uncertainties, and an inability to attract, develop, or retain technical, consulting, or managerial agents or independent contractors. As a result, the identification and interpretation of data and other information and their use in developing and selecting assumptions from and among reasonable alternatives requires the exercise of judgment. To the extent that the assumed events do not occur, the outcome may vary substantially from anticipated or projected results, and, accordingly, no opinion is expressed on the achievability of those forward-looking statements. No assurance can be given that any of the assumptions relating to the forward-looking statements specified in the following information are accurate, and we assume no obligation to update any such forward-looking statements. The reader should not unduly rely on these forward-looking statements, which speak only as of the date of this Quarterly Report, except as required by law; we are not obligated to release publicly any revisions to these forward-looking statements to reflect events or circumstances occurring after the date of this Quarterly Report or to reflect the occurrence of unanticipated events.

 

Industry Outlook

 

The petroleum industry is highly competitive and subject to significant volatility due to numerous market forces. Crude oil and natural gas prices are affected by market fundamentals such as weather, inventory levels, competing fuel prices, overall demand, and the availability of supply.

 

Oil prices cannot be predicted with any certainty and have significantly affected profitability and returns for upstream producers. Historically, West Texas Intermediate (“WTI”) crude oil prices have averaged approximately $90.20 per barrel over the past five years, per the U.S. Energy Information Administration. However, during that time, WTI oil prices have experienced wide fluctuations in prices, ranging from $59.62 per barrel to $113.39 per barrel, with the median price of $92.19 per barrel. The daily WTI oil prices averaged approximately $101.05 and $94.18 for the six-month periods ended June 30, 2014 and 2013, respectively.

 

 

While local supply/demand fundamentals are a decisive factor affecting domestic natural gas prices over the long term, day-to-day prices may be more volatile in the futures markets and other exchanges, making it difficult to forecast prices with any degree of confidence.

 

Company Overview

 

The address of our principal executive office is 2549 W. Main Street, Suite 202, Littleton, Colorado, 80120. Our telephone number is 303-798-5235. Our current operations consist of 24 full-time employees.

 

Since November 20, 2013, our common stock has been listed on the NYSE MKT LLC under the symbol “AMZG.” Prior to that, it was quoted on the OTC Bulletin Board and the OTC Markets Group Inc.’s OTCQX tier under the symbol “AMZG”.

 

Our Company was incorporated in the State of Nevada under the name “Golden Hope Resources Corp.” on July 25, 2003. We are engaged in the acquisition, exploration, and development of natural resource properties and are primarily focused on extracting proved oil reserves from those properties. On November 7, 2005, we filed documents with the Nevada Secretary of State to change our name to “Eternal Energy Corp.” by way of a merger with our wholly-owned subsidiary, Eternal Energy Corp., which was formed solely to facilitate the name change. In December 2011, we again filed documents with the Nevada Secretary of State to change our name to “American Eagle Energy Corporation” in conjunction with our acquisition of, and merger with, American Eagle Energy Inc.

 

We are principally engaged in exploration and production activities in the northwest portion of Divide County, North Dakota, where we target the extraction of oil and natural gas reserves from the Three Forks and Middle Bakken formations. We are aggressively pursuing the development of our Spyglass Area, to which virtually all of our capital is being deployed. Our Spyglass Area generated 99% of our revenue for the six-month period ended June 30, 2014 and represents 99% of our estimated proved reserves as of June 30, 2014. As of June 30, 2014, we also held an interest in a small number of wells located in southeastern Saskatchewan, Canada. We sold all of our interests in the Canadian oil and gas properties in July 2014.

 

In addition to our existing wells, we own undeveloped acreage interests located in Sheridan, Daniels and Richland Counties, Montana. We currently do not plan to devote capital to any of these areas over the next twelve months.

 

Oil & Gas Wells

 

We are primarily focused on drilling and completing wells located within our Spyglass Area, located in northwestern Divide County, North Dakota. As of June 30, 2014, 43 gross (24.0 net) of our operated Spyglass wells were producing, in which we own working interests ranging from approximately 5% to 97%, with an average working interest of approximately 56%. At June 30, 2014, there were 30 gross (18.1 net) operated wells producing from the Three Forks formation and 13 gross (6.0 net) operated wells producing from the Middle Bakken formation. During the six-month period ended June 30, 2014, we added 15 gross (7.3 net) operated wells to production in our Spyglass Area. In addition, we added 3.7 net operated wells to production as a result of acquiring additional working interests in our existing operated wells.

 

We have elected to participate as a non-operating working interest partner in the drilling of 81 gross (3.9 net) wells within the Spyglass Area, of which 77 gross (3.7 net) were producing as of June 30, 2014. Our working interest ownership in these non-operated wells ranges from less than 1% to approximately 28%, with an average working interest of approximately 5%.

 

 

The following table summarizes our Spyglass Area well activity for the three-month period ended June 30, 2014:

 

						Non-				Total
		Operated				Operated				Spyglass
Gross Wells
Wells producing at beginning of period			35				77				112
Wells added to production during the period			8				-				8
Wells producing at end of period			43				77				120
Net Wells
Wells producing at beginning of period			20.0				3.7				23.7
Wells added to production during the period			4.0								4.0
Wells producing at end of period			24.0				3.7				27.7

 

As of June 30, 2014, we also operated three gross (2.50 net) wells and participated as a non-operating working interest partner in a fourth well (50% net working interest) located in southeastern Saskatchewan (the “Hardy Property”). Our working interests in these four gross (3.00 net) wells ranged from 50% to 100%, with an average of approximately 78%. The financial results stemming from the operation of our Canadian wells are significantly less favorable than those of our US wells. As of June 30, 2014, two of the operated Hardy wells were shut in. In July 2014, we sold all of our interest in the Hardy Property for cash consideration of approximately $1.8 million.

 

Our capital expenditures related to well development totaled approximately $59.7 million for the six-month period ended June 30, 2014. The cost of drilling and completing successful wells is dependent on a number of factors including, among other things, the vertical depth of the well, the lateral length of the well, the geological zone targeted for development, the methods used to complete the wells and the weather conditions at the time the wells are drilled and completed. In general, our costs of drilling wells that we operate decreased during 2014 as a result of more efficient drilling operations, which has decreased the average number of days it takes for us to reach total depth on our wells.

 

During the six-month period ended June 30, 2014, we spent approximately $60.1 million to acquire additional working and net revenue interests in existing producing wells, as well as to expand our overall acreage position in areas containing proved oil and gas reserves. Of this amount, approximately $47 million was spent to acquire additional working and net revenue interests from one of our working interest partners. The acquisition of the additional working and net revenue interests was funded from proceeds received from a public offering of our common stock in March 2014.

 

Oil and Gas Reserves

 

As of June 30, 2014, the date of our most recent reserve report, our estimated proved oil and gas reserves consisted of approximately 15.4 million barrels of oil equivalent (“BOE”). The estimated pre-tax present value of our proved oil and gas reserves, discounted at an annual rate of 10% (“PV10”), was approximately $336 million as of June 30, 2014.

 

  

Operating Results

 

For the purpose of furthering the reader’s understanding of the results of our operations, we have elected to present certain non-GAAP financial measures that are commonly used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies, to analyze the results of our operations for the three-month and six-month periods ended June 30, 2014 and 2013. Specific non-GAAP financial measures presented include Adjust Net Income, Adjusted Net Income per Share, Adjusted EBITDA and Adjusted Cash Flow from Operations. A description of each non-GAAP financial measure presented is provided below.

 

We define Adjusted Net Income as net income excluding any loss from the impairment of oil and gas properties and changes in the fair value of our outstanding commodity derivatives. We believe that this financial measure is meaningful because it excludes the effects of non-cash items that are primarily based on predicted future commodity prices, over which management has no control.

 

Adjusted Net Income per Share is calculated by dividing Adjusted Net Income by the weighted average shares of our common stock that were outstanding for the period. GAAP requires the use of basic weighted average shares outstanding for the period to calculate both basic and diluted net loss per share for periods in which an entity recognizes a net loss, as the use of the diluted weighted average shares outstanding for the period would have an anti-dilutive effect. In the event that we recognize a net loss for the period (GAAP basis), but Adjusted Net Income for the period, as described above, we present Adjusted Net Income Per Share on both a basic and diluted basis using the appropriate weighted average shares outstanding figure as the denominator.

 

We define Adjusted EBITDA as net income before depletion, depreciation and amortization, impairment of oil and natural gas properties, asset retirement obligation accretion expense, gain (loss) on derivative activities, net cash receipts (payments) on settled derivative instruments, premiums (paid) received on options that settled during the period, interest expense, and income tax expense.

 

Management believes Adjusted EBITDA is useful because it allows it management evaluate our operating performance more effectively and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures, and the methods by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance or liquidity.

 

  

Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which is a component of Adjusted EBITDA. The Adjusted EBITDA presented in this below may not be comparable to similarly titled measures presented by other companies, and may not be identical to corresponding measures used in the our various agreements, including the agreements governing the Credit Facility. We have included a reconciliation of Adjusted EBITDA to net income, the most directly comparable GAAP financial measure, below.

 

We believe that Adjusted Cash Flow from Operations is a meaningful financial measure because it excludes the majority of non-cash charges from EBITDA, yet includes the portion of interest expense that paid in cash, thus providing a measurement of our ability to service our outstanding debt.

 

The following table summarizes our consolidated revenue, production data, and operating expenses for the three-month and six-month periods ended June 30, 2014 and 2013:

 

		For the three-month period								For the six-month period
		ended June 30,								ended June 30,
		2014				2013				2014				2013
Revenues:
Oil sales		$	16,225,086			$	10,365,681			$	28,491,920			$	17,993,324
Gas sales			106,077				4,312				178,492				5,376
Liquids sales			131,501				-				337,731				-
Total revenues		$	16,462,664			$	10,369,993			$	29,008,143			$	17,998,700
Volumes:
Oil (barrels)			175,509				117,001				316,350				204,441
Gas (Mcf)			16,977				980				28,347				1,167
Liquids (barrels)			4,183				-				9,495				-
Total barrels of oil equivalent (“BOE)			182,522				117,164				330,570				204,636
Average daily sales volumes
Average sales prices:
Oil sales (per barrel)		$	92.45			$	88.60			$	90.06			$	88.01
Effect of settled derivatives (per barrel)			(2.60	)			-				(1.08	)			-
Oil sales, net of settled derivatives (per barrel)			89.85				88.60				89.98				88.01
Gas sales (per mcf)			6.25				4.40				6.30				4.61
Liquids sales (per barrel)			31.44				-				35.57				-
Oil equivalent sales (per BOE)			87.69				88.51				86.72				87.95
Operating expenses:
Lease operating expenses		$	3,312,951			$	1,794,279			$	5,586,422			$	2,604,901
Production taxes			1,887,530				1,159,243				3,266,935				1,997,155
Total oil and gas operating expenses			5,200,481				2,953,522				8,853,357				4,602,056
General and administrative expenses, excluding stock-based compensation			1,217,845				973,157				2,781,357				2,043,142
Stock-based compensation (non-cash)			444,648				287,172				898,674				524,520
Depletion, depreciation and amortization			5,706,588				2,116,378				9,342,507				3,391,301
Impairment of oil and gas properties			-				-				-				1,525,027
Total operating expenses		$	12,569,562			$	6,330,229			$	21,875,895			$	12,086,046

 

  

		For the three-month period								For the six-month period
		ended June 30,								ended June 30,
		2014				2013				2014				2013
Costs and expenses per BOE:
Lease operating expenses		$	18.15			$	15.31			$	16.90			$	12.73
Production taxes			10.34				9.90				9.88				9.76
Total oil and gas operating expenses			28.49				25.21				26.78				22.49
General and administrative expenses, excluding stock-based compensation			6.67				8.31				8.42				9.99
Stock-based compensation (non-cash)			2.44				2.45				2.72				2.56
Depletion, depreciation and amortization			31.27				18.06				28.26				16.57
Impairment of oil and gas properties			-				-				-				7.45
Total operating expenses		$	68.87			$	54.03			$	66.18			$	59.06
Adjusted net income (Non-GAAP):
Net income (loss)		$	(3,899,815	)		$	2,637,484			$	(4,928,262	)		$	2,992,831
Add:  Impairment of oil and gas properties			-				-				-				1,525,027
Add:  Changes in fair value of derivatives			6,200,119				(186,754	)			8,023,221				(159,247	)
Adjusted net income		$	2,300,304			$	2,450,730			$	3,094,959			$	4,358,611
Adjusted net income per share (Non-GAAP):
Basic		$	0.08			$	0.20			$	0.13			$	0.35
Diluted		$	0.07			$	0.19			$	0.12			$	0.34
Weighted average number of shares outstanding:
Basic			30,436,424				12,517,087				24,529,013				12,494,987
Diluted			31,017,574				12,992,218				25,143,977				12,944,561
Adjusted EBITDA (Non-GAAP):
Net income (loss)		$	(3,899,815	)		$	2,637,484			$	(4,928,262	)		$	2,992,831
Less: Interest income			-				(1,472	)			(642	)			(4,628	)
Less: Dividend income			(11,685	)			(16,982	)			(27,481	)			(34,222	)
Add: Interest expense			3,250,568				414,797				6,465,520				833,137
Add: Income tax expense (benefit)			(2,103,093	)			1,192,691				(2,741,468	)			2,284,783
Add: Depletion, depreciation and amortization (non-cash)			5,706,588				2,116,378				9,342,507				3,391,301
Add: Stock-based compensation (non-cash)			444,648				287,172				898,674				524,520
Add: Impairment of oil and gas properties (non-cash)			-				-				-				1,525,027
Add: Changes in fair value of derivatives			6,200,119				(186,754	)			8,023,221				(159,247	)
Adjusted EBITDA		$	9,587,330			$	6,443,314			$	17,032,069			$	11,353,502
Adjusted cash flow from operations (Non-GAAP):
Adjusted EBITDA		$	9,587,330			$	6,443,314			$	17,032,069			$	11,353,502
Less: Interest expense			(3,250,568	)			(414,797	)			(6,465,520	)			(833,137	)
Add:  Amortization of deferred financing costs (non-cash)			383,857				66,944				763,497				112,175
Adjusted cash flow		$	6,720,619			$	6,095,461			$	11,330,046			$	10,632,540

 

Results of Operations for the three-month period ended June 30, 2014 vs June 30, 2013

 

The following discussion is based on our consolidated results of operations, which includes our US oil and gas activities, as well as well as those of our Canadian subsidiaries. As indicated above, our US operations are responsible for the vast majority of our revenues, oil and gas operating costs and general and administrative expenses, and are the primary focus of our going-forward operations.

 

 

Revenues from the sale of oil, natural gas and liquids totaled $16.5 million for the three-month period ended June 30, 2014, compared to approximately $10.4 million for the three-month period ended June 30, 2013, an increase of 59%. This increase was driven primarily by a 56% increase in production by volume. Oil and gas sales for the three-month period ended June 30, 2014 were lower than expected due to unseasonably high rains in the area, which caused delays in the delivery of oil from our tanks and forced us to periodically shut in our wells once the tanks reached capacity. The average sales price of oil, after taking into consideration the effects of price hedges in place, was relatively flat for the three-month period ended June 30, 2014 compared to the same period in 2013. Our wells continue to be primarily oil-producing wells, with 99% of total revenues for the three-month periods ended June 30, 2014 and 2013 resulting from oil sales. Production primarily increased due to the addition of 23 gross (17.6 net) productive operated wells and 16 gross (0.6 net) productive non-operated wells in the Williston Basin from July 1, 2013 to June 30, 2014. During the three-month period ended June 30, 2014, our average realized price per barrel of oil was $92.45 ($89.85 after considering the effects of settled derivatives) compared to an average realized price of $88.60 per barrel for the three-month period ended June 30, 2013. Our US wells accounted for 99% of our consolidated sales for the three-month period ended June 30, 2014, compared to 97% of our consolidated sales for the three-month period ended June 30, 2013.

 

Lease operating expenses were approximately $3.3 million for the three-month period ended June 30, 2014 compared to approximately $1.8 million for the three-month period ended June 30, 2013. On a per-unit basis, LOE was $18.15 per BOE for the three-month period ended June 30, 2014 compared to $15.31 per BOE for the three-month period ended June 30, 2014. The increase in LOE per BOE from 2013 to 2014 is primarily due to location expense associated with road repairs that were necessary due to unseasonably high rainfall during the period and increased workover expenses.

 

Production taxes were approximately $1.9 million for the three-month period ended June 30, 2014, compared to approximately $1.2 million for the three-month period ended June 30, 2013. Production taxes, as a percentage of total revenues were approximately 11.5% and 11.2% for the three-month periods ended June 30, 2014 and 2013, respectively. The statutory production tax rate for our North Dakota wells is 11.5%.

 

General and administrative expenses, excluding stock based compensation, totaled approximately $1.2 million for the three-month period ended June 30, 2014, compared to approximately $1.0 million for the three-month period ended June 30, 2013. The increase is largely attributable to additional payroll, employee benefit expenses, and office-related expenses as the number of our employees grew from 19 as of June 30, 2013 to 24 as of June 30, 2014. Included in general and administrative expenses is stock-based compensation totaling approximately $445,000 and $287,000 for the three-month periods ended June 30, 2014 and 2013, respectively. Stock-based compensation is a non-cash charge to earnings.

 

  

Depletion, depreciation and amortization expense totaled approximately $5.7 million ($31.27 per BOE) for the three-month period ended June 30, 2014, compared to approximately $2.1 million ($18.06 per BOE) for the three-month period ended June 30, 2013. Our depletion expense is based on the capitalized costs related to oil and gas properties for which proved reserves have been assigned, plus the estimated future development costs necessary to convert undeveloped proved reserves to proved producing reserves. Our gross capitalized costs related to amortizable oil and gas properties increased from approximately $94.8 million at June 30, 2013 to approximately $287.8 million at June 30, 2014. The increase in depletion expense was due primarily to the addition productive operated wells in the Williston Basin since July 1, 2013, as well as to the identification of up to new future drill sites, for which proved, undeveloped reserves (and estimated future development costs) have been assigned.

 

In August 2013, we entered into $200 million Credit Facility with MSCG, at which time we borrowed $68 million. We used a portion of these funds to repay in full the then-outstanding balance of our Swap Facility with MBL. In October 2013, we borrowed an additional $40 million under the MSGC Credit Facility to acquire certain working and net revenue interests in the Spyglass Property from one of our working interest partners. As discussed above, additional working and net revenue interests were acquired from this same working interest partner in March 2014 using proceeds from a public offering of our common stock.

 

We recognized interest expense of approximately $3.3 million during the three-month period ended June 30, 2014 related to our Credit Facility. We recognized aggregate interest expense totaling approximately $415,000 during the three-month period ended June 30, 2013 related to our then-outstanding Swap Facility. Included in the aggregate interest expense figures for the three-month periods ended June 30, 2014 and 2013 is amortization expense related to deferred financing costs, totaling approximately $383,000 and $67,000, respectively. The amortization of deferred financing costs is a non-cash item. The specific terms of the Swap Facility and the Credit Facility are discussed in the “Liquidity and Capital Resources” section, below.

 

In connection with our Credit Facility, we are required to enter into price swap agreements covering up to 85% of the anticipated production from our estimated proved developed reserves over the remaining life of the Credit Facility. The purpose of the price swap agreements is limit our potential exposure to falling oil prices. Sustained oil prices above the pre-determined terms of our price-swap agreements result in realized and unrealized losses, while sustained oil prices below the pre-determined terms of our price swap agreements result in realized and unrealized gains. The price swap agreements are considered derivatives under generally accepted accounting principles. We recognized losses on the settlement of the price swaps of approximately $457,000, and unrealized losses related to changes in the fair value of price swap agreements of approximately $6.2 million for the three-month period ended June 30, 2014. Additional losses or offsetting gains could be recognized in the future, depending on projected future oil prices.

 

We were also required to enter into certain price swap agreements in connection with our then-outstanding Swap Facility, prior to repayment. We recognized unrealized gains related to changes in the fair value of these price swap agreements of approximately $187,000 for the three-month period ended June 30, 2013. The price swaps agreements associated with the Swap Facility were settled upon repayment of the Swap Facility in August 2013.

 

  

We recognized an estimated income tax benefit of approximately $2.1 million for the three-month period ended June 30, 2014, compared to income tax expense of approximately $1.2 million for the corresponding period in 2013. Our estimated effective tax rates for the periods were 35.0% and 31.1%, respectively.

 

Our basic and diluted loss per share was ($0.13) for the three-month period ended June 30, 2014, compared to basic income per share of $0.21 and diluted income per share of $0.20 for the three-month period ended June 30, 2013. Because we recognized a net loss for the current period, diluted income per share is calculated using the basic weighted average number of weighted shares outstanding for the period, as the effect of including potentially dilutive items would be anti-dilutive.

 

Our adjusted net income for the three-month periods ended June 30, 2014 and 2013 was approximately $2.3 million and $2.5 million, respectively. Adjusted net income is derived by adding back unrealized, changes in fair value of commodity derivatives (non-cash) to net income or adjusting for other non-recurring gains or losses during the period. Adjusted net income is a non-GAAP financial measure.

 

Our adjusted EBITDA for the three-month periods ended June 30, 2014 and 2013 was approximately $9.6 million and $6.4 million, respectively. Adjusted EBITDA represents 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 changes in fair value of commodity derivatives (non-cash). Adjusted EBITDA is a non-GAAP financial measure.

 

Results of Operations for the six-month period ended June 30, 2014 vs June 30, 2013

 

Revenues from the sale of oil, natural gas and liquids totaled $29.0 million for the six-month period ended June 30, 2014, compared to approximately $18.0 million for the six-month period ended June 30, 2013, an increase of 61%. This increase was driven primarily by a 62% increase in production by volume. Oil and gas sales for the six-month period ended June 30, 2014 were lower than expected due to extreme winter weather conditions during the first quarter, followed by unseasonably high rains during the second quarter. The extremely cold temperatures during the winter months caused a number of our operated wells to be shut in due to mechanical issues. The unseasonably high rains in the second quarter caused delays in the delivery of oil from our tanks and forced us to periodically shut in our wells once the tanks reached capacity. In addition, a number of our wells were intentionally shut-in while hydraulic stimulation of neighboring wells was performed, in order to prevent a loss of pressure in our existing wells.

   

The average sales price of oil, after taking into consideration the effects of price hedges in place, was relatively flat for the six-month period ended June 30, 2014 compared to the same period in 2013. Production primarily increased due to the addition of 23 gross (17.6 net) productive operated wells and 16 gross (0.6 net) productive non-operated wells in the Williston Basin from July 1, 2013 to June 30, 2014. During the six-month period ended June 30, 2014, our average realized price per barrel of oil was $90.06 ($89.98 after considering the effects of settled derivatives) compared to an average realized price of $88.01 per barrel for the six-month period ended June 30, 2013. Our US wells accounted for 99% of our consolidated sales for the six-month period ended June 30, 2014, compared to 96% of our consolidated sales for the six-month period ended June 30, 2013.

 

 

Lease operating expenses were approximately $5.6 million for the six-month period ended June 30, 2014 compared to approximately $2.6 million for the six-month period ended June 30, 2013. The increase in overall lease operating expense dollars is directly related to the large number of operated wells that were added to production since July 1, 2013. On a per-unit basis, LOE was $16.90 per BOE for the six-month period ended June 30, 2014 compared to $12.73 per BOE for the six-month period ended June 30, 2014. The increase in the average LOE per BOE from 2013 to 2014 is primarily due to extreme weather conditions, which negatively affected our 2014 production, increased workovers of certain of our more mature operated wells, and location maintenance costs associated with road repairs made necessary by the unseasonably rainy conditions in the latter part of spring.

 

Production taxes were approximately $3.3 million for the six-month period ended June 30, 2014, compared to approximately $2.0 million for the six-month period ended June 30, 2013. Production taxes represented 11.3% and 11.1% of gross revenues for the six-month periods ended June 30, 2014 and 2013. The statutory production tax rate for our North Dakota wells is 11.5%.

 

General and administrative expenses totaled $3.7 million for the six-month period ended June 30, 2014, compared to approximately $2.6 million for the six-month period ended June 30, 2013. The increase is largely attributable to additional payroll, employee benefit expenses, and office-related expenses as the number of our employees grew from 19 as of July 1, 2013 to 24 as of June 30, 2014. We also incurred higher legal and accounting fees during the first quarter of 2014 in anticipation of equity financing and acquisitions. Our general and administrative expenses for the six-month periods ended June 30, 2014 and 2013 includes stock-based compensation totaling approximately $899,000 and $525,000 for the six-month periods ended June 30, 2014 and 2013, respectively. Stock-based compensation is a non-cash charge to earnings.

 

Depletion, depreciation and amortization expense was approximately $9.3 million ($28.26 per BOE) for the six-month period ended June 30, 2014, compared to approximately $3.5 million ($16.57 per BOE) for the six-month period ended June 30, 2013. Our capitalized costs related to amortizable oil and gas properties increased from approximately $94.8 million at June 30, 2013 to approximately $287.8 million at June 30, 2014. This increase in depletion expense was due primarily to the addition of productive operated wells in the Williston Basin since July 1, 2013, as well as to the identification of future drill sites, for which proved, undeveloped reserves (and estimated future development costs) have been assigned.

 

Due to lower than anticipate production volumes from our Hardy Property wells and declining oil prices during the period, we were required to write-down the value of our Canadian oil and gas properties at March 31, 2013, pursuant to full-cost accounting rules. In doing so, we recognized an impairment expense of approximately $1.5 million related to our Hardy Property during the six-month period ended June 30, 2013. The impairment expense represented a non-cash charge against our earnings. We did not recognize any such impairment during the six-month period ended June 30, 2014. As noted above, we sold our interest in the Hardy Property in July 2014.

 

  

We recognized aggregate interest expense of approximately $833,000 during the six-month period ended June 30, 2013 related to our then-outstanding Swap Facility. Included in this figure is amortization expense related to deferred financing costs of approximately $112,000. The amortization of deferred financing costs is a non-cash item. We fully repaid the outstanding balance of our Swap Agreement in August 2013 using proceeds received from our Credit Agreement with MSGC. Year-to-date interest associated with our Credit Facility approximated $6.5 million for the six-month period ended June 30, 2014. Included in this figure is approximately $763,000 of amortization related to deferred financing costs. The specific terms of the Swap Facility and the Credit Facility are discussed in the “Liquidity and Capital Resources” section, below.

 

We recognized losses on the settlement of price swap agreements of approximately $341,000, and unrealized losses related to changes in the fair value of price swaps of approximately $8.0 million for the six-month period ended June 30, 2014, in connection with price swap agreements entered into pursuant to our Credit Facility. Additional losses or offsetting gains could be recognized in the future, depending on projected future oil prices. We recognized unrealized gains related to changes in the fair value of price swaps of approximately $159,000 for the six-month period ended June 30, 2013 in connection with price swaps agreements entered into pursuant to our Swap Facility. The price swap agreements associated with the Swap Facility were settled upon the full repayment of the Swap Facility in August 2013.

 

We recognized an estimated income tax benefit of approximately $2.7 million for the six-month period ended June 30, 2014, compared to income tax expense of approximately $2.3 million for the corresponding period in 2013. Our estimated effective tax rates for the periods were 35.7% and 43.3%, respectively.

 

Our basic and diluted loss per share was ($0.20) for the six-month period ended June 30, 2014, compared to basic income per share of $0.24 and diluted income per share of $0.23 for the six-month period ended June 30, 2013. Because we recognized a net loss for the current period, diluted income per share is calculated using the basic weighted average number of weighted shares outstanding for the period, as the effect of including potentially dilutive items would be anti-dilutive.

 

Our adjusted net income for the six-month periods ended June 30, 2014 and 2013 was approximately $3.1 million and $4.4 million, respectively. Adjusted net income is derived by adding back unrealized changes in fair value of commodity derivatives to net income or adjusting for other non-recurring gains or losses during the period. Adjusted net income is a non-GAAP financial measure.

 

Our adjusted EBITDA for the six-month periods ended June 30, 2014 and 2013 was approximately $17.0 million and $11.4 million, respectively. Adjusted EBITDA represents 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 unrealized changes in fair value of commodity derivatives. Adjusted EBITDA is a non-GAAP financial measure.

 

  

Liquidity and Capital Resources

 

On August 19, 2013, we entered into a $200.0 million Credit Facility with MSCG, which is comprised of an initial $68.0 million term loan (the “Initial Term Loan”), an available term loan of up to $40.0 million to be used to fund a potential future acquisition (the “Spyglass Tranche A Loan”), and an uncommitted term loan of up to $92.0 million (the “Tranche B Loan”). The Credit Facility is collateralized by, among other things, our oil and gas properties and future oil and gas sales derived from such properties. A portion of the funds received from the Initial Term Loan were used to repay in full the then-outstanding balance under the Swap Facility. The remaining proceeds from the Initial Term Loan were or will be used (i) to reduce our outstanding payables, (ii) to further develop our Spyglass Area in North Dakota, (iii) to acquire new oil and gas properties within the Spyglass Area and (iv) to fund general corporate purposes.

 

On October 7, 2013, we closed the $40.0 million Spyglass Tranche A Loan. As of June 30, 2014, the principal amount outstanding under our Credit Facility is $108.0 million.

 

The Credit Facility contains customary affirmative and negative covenants for borrowings of this type, including limitations on the Company with respect to transactions with affiliates, hedging agreements, dividends and distributions, operations in respect of the property that secures its collective obligations under the Credit Facility, liens and encumbrances in respect of the property that secures our collective obligations under the Credit Facility, subsidiaries and divestitures, indebtedness, investments, and changes in business.

 

The Credit Agreement also contains a number of financial covenants, including the maintaining of an adjusted minimum working capital ratio of 1.0. The adjusted minimum working capital ratio is calculated by dividing current assets, less any current derivative assets, by current liabilities, less the current portion of debt outstanding under the Credit Agreement, unpaid deferred loan costs and any current derivative liability. As of June 30, 2014, our adjusted minimum working capital ratio was less than 1.0. The Credit Agreement was amended in July 2014 so as to not require a minimum adjusted working capital ratio as of June 30, 2014.

 

We are currently seeking additional, alternative financing that we believe will enable us to either comply with the minimum adjusted working capital ratio covenant at September 30, 2014 or to fully repay the outstanding balance of the existing Credit Facility. In the event that we are unable to secure alternative financing before then, it is likely that we will be in technical default of the adjusted working capital covenant under the Credit Facility as of September 30, 2014. Accordingly, we have classified the entire balance outstanding under the Credit Facility as a current liability on our June 30, 2014 condensed consolidated balance sheet. However, we do not believe that we will be required to repay the entire amount outstanding under the Credit Facility during the ensuing twelve months. Should circumstances dictate otherwise, or should we be unsuccessful in our current pursuit of alternative financing, we will consider additional financing sources to repay the debt including, but not limited to, potential future equity offerings and/or the issuance of additional debt securities.

 

  

On March 24, 2014, we sold 12,650,000 shares of our common stock in a transaction utilizing our shelf registration. Proceeds received from the sale of equity, net of expenses and broker fees and commissions, totaled approximately $78.3 million. A portion of the net proceeds from the public offering were used to close the second half of our previously announced working interest acquisition. The remaining funds will be used (i) to execute our 2014 drilling program, (ii) to fund further development of wells within our Spyglass Area, (iii) to acquire additional working interests in undeveloped properties, and (iv) to provide working capital for operations.

 

As of June 30, 2014, our assets totaled approximately $319.9 million which includes, among other items, cash balances of approximately $22.2 million, trade receivables totaling approximately $21.1 million and marketable securities valued at approximately $1.4 million. The marketable securities are classified as non-current. Although we have the ability to liquidate these investments quickly, it is not our current intent to do so.

 

As of June 30, 2014, our current assets total approximately $43.4 million. Our current liabilities as of June 30, 2014 include accounts payable and accrued liabilities totaling approximately $65.6 million, amounts outstanding under our Credit Facility totaling $108.0 million and estimated current derivative liabilities of approximately $4.0 million from current liabilities. As of June 30, 2014, we have a working capital deficit of approximately $134.0 million. However, as discussed above, we do not believe that we will be required to repay the $108.0 million outstanding under our Credit Facility during the next twelve months. Including the $1.4 million of marketable securities as current assets, and excluding the amounts outstanding under our Credit Facility and short-term derivative liabilities, our adjusted working capital deficit would be approximately $20.8 million.

 

It is possible that we will seek additional financing, or raise capital through the sale of additional shares of our common stock in the future, in order to replace our current debt, to fund future drilling activities, to develop our existing acreage further, or to acquire acreage or interests in other oil and gas properties.

 

Litigation

 

As of June 30, 2014, we were not subject to any known, pending or threatened material litigation.

 

Off-Balance Sheet Arrangements

 

We have no off-balance sheet arrangements.

 

ITEM 4. CONTROLS AND PROCEDURES

 

The Company, under the supervision and with the participation of its management, including the Chief Executive Officer and the Principal Accounting Officer, evaluated the effectiveness of the design and operation of the Company’s “disclosure controls and procedures” (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended, as of the end of the period covered by this report.  Based on that evaluation, the Chief Executive Officer and the Principal Accounting Officer concluded that the Company’s internal controls over financial reporting were effective as of June 30, 2014.

 

 

PART II – OTHER INFORMATION

 

ITEM 6. EXHIBITS.

 

Exhibit		Description of Exhibit
2.1		Agreement and Plan of Merger among Eternal Energy Corp., Eternal Sub Corp. and American Eagle Energy Inc., dated April 8, 2011. (Incorporated by reference to Exhibit 2.1 of our Registration Statement on Form S-4 filed May 4, 2011.)
2.1(a)		First Amendment to Agreement and Plan of Merger among Eternal Energy Corp., Eternal Sub Corp. and American Eagle Energy Inc., dated September 28, 2011. (Incorporated by reference to Exhibit 2.1(a) of our Current Report on Form 8-K filed September 28, 2011.)
3(i).1		Articles of Incorporation filed with the Nevada Secretary of State on July 25, 2003. (Incorporated by reference to Exhibit 3.1 of our Form 10-SB filed August 18, 2004.)
3(i).2		Certificate of Change filed with the Nevada Secretary of State effective November 7, 2005. (Incorporated by reference to Exhibit 3(i).2 of our Current Report on Form 8-K filed November 9, 2005.)
3(i).3		Articles of Merger filed with the Nevada Secretary of State effective November 7, 2005. (Incorporated by reference to Exhibit 3(i).3 of our Current Report on Form 8-K filed November 9, 2005.)
3(i).4		Articles of Merger filed with the Nevada Secretary of State effective November 30, 2011. (Incorporated by reference to Exhibit 3(i).4 of our Current Report on Form 8-K filed December 20, 2011.)
3(i).5		Articles of Merger filed with the Nevada Secretary of State effective November 30, 2011. (Incorporated by reference to Exhibit 3(i).5 of our Current Report on Form 8-K filed December 20, 2011.)
3(i).6		Certificate of Change filed with the Nevada Secretary of State effective November 30, 2011. (Incorporated by reference to Exhibit 3(i).6 of our Current Report on Form 8-K filed December 20, 2011.)
3(i).7		Certificate of Change filed with the Nevada Secretary of State effective March 18, 2014. (Incorporated by reference to Exhibit 3(i).7 of our Current Report on Form 8-K filed on March 21, 2014.)
3(ii).1		Bylaws, adopted July 18, 2003. (Incorporated by reference to Exhibit 3.2 of our Form 10-SB filed August 18, 2004.)
3(ii).2		Amendment No. 1 to Bylaws, adopted November 4, 2005. (Incorporated by reference to Exhibit 3(ii) of our Current Report on Form 8-K filed November 9, 2005.)
3(ii).3		Amendment No. 2 to Bylaws, adopted February 22, 2011. (Incorporated by reference to Exhibit 3(ii).3 of our Current Report on Form 8-K filed February 23, 2011.)
4.1		American Eagle Energy Corporation 2012 Equity Incentive Plan. (Incorporated by reference to Exhibit 4.1 of our Registration Statement on Form S-8 filed February 28, 2012.)
4.2		Non-qualified Stock Option Agreement, dated as of October 30, 2009, by and between the Registrant and Bradley M. Colby. (Incorporated by reference to Exhibit 4.2 of our Registration Statement on Form S-8 filed February 28, 2012.)
4.3		Non-qualified Stock Option Agreement, dated as of October 30, 2009, by and between the Registrant and John Anderson. (Incorporated by reference to Exhibit 4.3 of our Registration Statement on Form S-8 filed February 28, 2012.)
4.4		Non-qualified Stock Option Agreement, dated as of October 30, 2009, by and between the Registrant and Paul E. Rumler. (Incorporated by reference to Exhibit 4.4 of our Registration Statement on Form S-8 filed February 28, 2012.)
4.5		Non-qualified Stock Option Agreement, dated as of December 30, 2010, by and between the Registrant and Bradley M. Colby. (Incorporated by reference to Exhibit 4.5 of our Registration Statement on Form S-8 filed February 28, 2012.)
4.6		Non-qualified Stock Option Agreement, dated as of December 30, 2010, by and between the Registrant and Thomas G. Lantz. (Incorporated by reference to Exhibit 4.6 of our Registration Statement on Form S-8 filed February 28, 2012.)
4.7		American Eagle Energy Corporation 2013 Equity Incentive Plan. (Incorporated by reference to Exhibit 4.7 of our Annual Report on Form 10-K filed March 28, 2014.)
4.8		Non-qualified Stock Option Agreement, dated as of December 30, 2010, by and between the Registrant and Richard Findley. (Incorporated by reference to Exhibit 4.8 of our Registration Statement on Form S-8 filed February 28, 2012.)
4.9		Non-qualified Stock Option Agreement, dated as of December 28, 2011, by and between the Registrant and Paul E. Rumler. (Incorporated by reference to Exhibit 4.9 of our Registration Statement on Form S-8 filed February 28, 2012.)
4.10		Non-qualified Stock Option Agreement, dated as of December 28, 2011, by and between the Registrant and John Anderson. (Incorporated by reference to Exhibit 4.10 of our Registration Statement on Form S-8 filed February 28, 2012.)
4.11		Reserved for future use.
4.12		Non-qualified Stock Option Agreement, dated as of December 28, 2011, by and between the Registrant and Kirk Stingley. (Incorporated by reference to Exhibit 4.12 of our Registration Statement on Form S-8 filed February 28, 2012.)
4.13		Non-qualified Stock Option Agreement, dated as of December 14, 2012, by and between the Registrant and Bradley M. Colby. (Incorporated by reference to Exhibit 4.13 of our Annual Report on Form 10-K filed March 28, 2014.)
4.14		Non-qualified Stock Option Agreement, dated as of December 14, 2012, by and between the Registrant and Thomas G. Lantz. (Incorporated by reference to Exhibit 4.14 of our Annual Report on Form 10-K filed March 28, 2014.)

 

 

4.15		Non-qualified Stock Option Agreement, dated as of December 14, 2012, by and between the Registrant and Kirk A. Stingley. (Incorporated by reference to Exhibit 4.15 of our Annual Report on Form 10-K filed March 28, 2014.)
4.16		Non-qualified Stock Option Agreement, dated as of December 14, 2012, by and between the Registrant and Richard Findley.  (Incorporated by reference to Exhibit 4.16 of our Annual Report on Form 10-K filed March 28, 2014.)
4.17		Non-qualified Stock Option Agreement, dated as of December 14, 2012, by and between the Registrant and Paul E. Rumler. (Incorporated by reference to Exhibit 4.17 of our Annual Report on Form 10-K filed March 28, 2014.)
4.18		Non-qualified Stock Option Agreement, dated as of December 14, 2012, by and between the Registrant and John Anderson. (Incorporated by reference to Exhibit 4.18 of our Annual Report on Form 10-K filed March 28, 2014.)
4.19		Non-qualified Stock Option Agreement, dated as of February 21, 2012, by and between the Registrant and Andrew P. Calerich. (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed February 21, 2012.)
4.20		Non-qualified Stock Option Agreement, dated as of November 14, 2013, by and between the Registrant and James N. Whyte. (Incorporated by reference to Exhibit 4.20 of our Current Report on Form 8-K filed November 14, 2013.)
4.21		Non-qualified Stock Option Agreement, dated as of December 14, 2012, by and between the Registrant and Andrew P. Calerich. (Incorporated by reference to Exhibit 4.21 of our Annual Report on Form 10-K filed March 28, 2014.)
4.22		Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and Bradley M. Colby. (Incorporated by reference to Exhibit 4.22 of our Annual Report on Form 10-K filed March 28, 2014.)
4.23		Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and Thomas G. Lantz. (Incorporated by reference to Exhibit 4.23 of our Annual Report on Form 10-K filed March 28, 2014.)
4.24		Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and Kirk A. Stingley. (Incorporated by reference to Exhibit 4.24 of our Annual Report on Form 10-K filed March 28, 2014.)
4.25		Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and Richard Findley. (Incorporated by reference to Exhibit 4.25 of our Annual Report on Form 10-K filed March 28, 2014.)
4.26		Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and Paul E. Rumler. (Incorporated by reference to Exhibit 4.26 of our Annual Report on Form 10-K filed March 28, 2014.)
4.27		Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and John Anderson. (Incorporated by reference to Exhibit 4.27 of our Annual Report on Form 10-K filed March 28, 2014.)
4.28		Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and Andrew P. Calerich. (Incorporated by reference to Exhibit 4.28 of our Annual Report on Form 10-K filed March 28, 2014.)
4.29		Non-qualified Stock Option Agreement, dated as of December 13, 2013, by and between the Registrant and James N. Whyte. (Incorporated by reference to Exhibit 4.29 of our Annual Report on Form 10-K filed March 28, 2014.)
10.1		Agreement and Plan of Merger between Golden Hope Resources Corp. (renamed Eternal Energy Corp.) and Eternal Energy Corp., filed with the Nevada Secretary of State effective November 7, 2005. (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed November 9, 2005.)
10.2		Reserved for future use.
10.3		Purchase and Sale Agreement between Eternal Energy Corp. and American Eagle Energy Inc. dated June 18, 2010. (Incorporated by reference to Exhibit 10.3 of our Quarterly Report on Form 10-Q filed August 16, 2010.)
10.4		Restricted Common Stock Purchase Agreement by and between American Eagle Energy Corporation and Power Energy Holdings, LLC, dated January 4, 2013. (Incorporated by reference to Exhibit 10.4 of our Quarterly Report on Form 10-Q filed May 14, 2013.)
10.5		Common Stock Purchase Agreement by and between American Eagle Energy Corporation and Power Energy Holdings, LLC, dated August 9, 2013. (Incorporated by reference to Exhibit 10.5 of our Quarterly Report on Form 10-Q filed August 19, 2013.)
10.6		Purchase, Sale and Option Agreement by and between American Eagle Energy Corporation and USG Properties Bakken I, LLC, dated August 12, 2013. (Incorporated by reference to Exhibit 10.6 of our Quarterly Report on Form 10-Q filed November 14, 2013.)
10.6a		First Amendment to Purchase, Sale and Option Agreement by and between American Eagle Energy Corporation and USG Properties Bakken I, LLC, dated September 30, 2013. (Incorporated by reference to Exhibit 10.6a of our Quarterly Report on Form 10-Q filed November 14, 2013.)
10.6b		Second Amendment to Purchase, Sale and Option Agreement by and between American Eagle Energy Corporation and USG Properties Bakken I, LLC, dated October 2, 2013. (Incorporated by reference to Exhibit 10.6b of our Quarterly Report on Form 10-Q filed November 14, 2013.)
10.6c		Notice of Exercise pursuant to the Purchase and Sale and Option Agreement by and between American Eagle Energy Corporation and USG Properties Bakken I, LLC, dated October 2, 2013. (Incorporated by reference to Exhibit 10.6c of our Quarterly Report on Form 10-Q filed November 14, 2013.)
10.6d		Third Amendment to the Purchase, Sale and Option Agreement by and between American Eagle Energy Corporation and USG Properties Bakken I, LLC, dated March 27, 2014. (Incorporated by reference to Exhibit 10.6d of our Annual Report on Form 10-K filed March 28, 2014.)
10.7		Underwriting Agreement by and between American Eagle Energy Corporation and Johnson Rice & Company LLC, dated March 18, 2014. (Incorporated by reference to Exhibit 1.1 to our Current Report on Form 8-K, filed March 19, 2014.)
10.8		Purchase Agreement by and between American Eagle Energy Corporation and Northland Securities, Inc. dated October 2, 2013 (Incorporated by reference to Exhibit 1.1 to our Current Report on Form 8-K filed on October 2, 2013.)

 

 

10.9		Purchase Agreement by and between American Eagle Energy Corporation and Northland Securities, Inc. dated October 9, 2013 (Incorporated by reference to Exhibit 1.1 to our Current Report on Form 8-K filed on October 10, 2013.)
10.10		Reserved for future use.
10.11		Amended and Restated Employment Agreement by and between the Registrant and Bradley M. Colby effective May 1 2013. (Incorporated by reference to Exhibit 10.11 of our Annual Report on Form 10-K filed March 28, 2014.)
10.12		Employment Agreement by and between the Registrant and Thomas G. Lantz, effective May 1, 2013. (Incorporated by reference to Exhibit 10.12 of our Annual Report on Form 10-K filed March 28, 2014.)
10.13		Employment Agreement by and between the Registrant and Kirk Stingley, effective May 1, 2013. (Incorporated by reference to Exhibit 10.13 of our Annual Report on Form 10-K filed March 28, 2014.)
10.14		Consulting Agreement by and between the Registrant and Richard Findley, effective November 30, 2011. (Incorporated by reference to Exhibit 10.41 of our Annual Report on Form 10-K filed April 16, 2012.)
10.15		Reserved for future use.
10.16		Reserved for future use.
10.17		Carry Agreement by and among American Eagle Energy Corporation, AMZG, Inc. and USG Properties Bakken I, LLC, dated August 12, 2013. (Incorporated by reference to Exhibit 10.20 of our Quarterly Report on Form 10-Q filed August 19, 2013.)
10.18		Farm-Out Agreement by and among American Eagle Energy Corporation, AMZG, Inc. and USG Properties Bakken I, LLC, dated August 12, 2013. (Incorporated by reference to Exhibit 10.21 of our Quarterly Report on Form 10-Q, filed August 19, 2013.)
10.19		Letter Agreement by and between American Eagle Energy Corporation and USG Properties Bakken I, LLC, dated March 21, 2014. (Incorporated by reference to Exhibit 10.19 of our Annual Report on Form 10-K filed March 28, 2014.)
10.19a		Amendment and Addendum to Letter Agreement among American Eagle Energy Corporation and USG Properties Bakken I, LLC, dated March 27, 2014. (Incorporated by reference to Exhibit 10.19a of our Annual Report on Form 10-K filed March 28, 2014.)
10.20		Credit Agreement, dated as of August 19, 2013, among American Eagle Energy Corporation, the lenders parties thereto, and Morgan Stanley Capital Group Inc., as administrative agent for such lenders. (Incorporated by reference to Exhibit 10.20 of our Form 8-K filed August 23, 2013.)
10.20a		First Amendment to the Credit Agreement among American Eagle Energy Corporation, the lenders parties thereto, and Morgan Stanley Capital Group Inc., dated October 2, 2013.
10.20b		Second Amendment to the Credit Agreement among American Eagle Energy Corporation, the lenders parties thereto, and Morgan Stanley Capital Group Inc., dated October 2, 2013.
10.20c*		Third Amendment to the Credit Agreement among American Eagle Energy Corporation, the lenders parties thereto, and Morgan Stanley Capital Group Inc., dated July 21, 2014.
10.21		Promissory Note by American Eagle Energy Corporation, dated as of August 19, 2013, payable to the order of Morgan Stanley Capital Group Inc. in the principal amount of $200,000,000. (Incorporated by reference to Exhibit 10.21 of our Form 8-K filed August 23, 2013.)
10.22		Pledge and Security Agreement, dated as of August 19, 2013, among American Eagle Energy Corporation, AMZG, Inc., AEE Canada, Inc., EERG Energy ULC, and Morgan Stanley Capital Group Inc. (Incorporated by reference to Exhibit 10.22 of our Form 8-K filed August 23, 2013.)
10.23		Mortgage-Collateral Real Estate Mortgage, Deed of Trust, Indenture, Security Agreement, Fixture Filing, As-Extracted Collateral Filing, Financing Statement and Assignment of Production, dated as of August 19, 2013, by American Eagle Energy Corporation, AMZG, Inc., and Morgan Stanley Capital Group Inc. (Incorporated by reference to Exhibit 10.23 of our Form 8-K filed August 23, 2013.)
10.24		Guaranty Agreement, dated as of August 19, 2013, among AMZG, Inc., AEE Canada Inc., EERG Energy ULC, and Morgan Stanley Capital Group Inc. (Incorporated by reference to Exhibit 10.24 of our Form 8-K filed August 23, 2013.)
10.25		Form of Warrant of American Eagle Energy Corporation. (Incorporated by reference to Exhibit 10.25 of our Form 8-K filed August 23, 2013.)
10.26		Reserved for future use.
10.27		Lease Agreement dated January 1, 2009 by and between Eternal Energy Corp. and Oakley Ventures, LLC. (Incorporated by reference to Exhibit 10.27 of our Annual Report on Form 10-K filed March 23, 2010.)
10.27a		Lease Addendum, dated October 1, 2011 by and between Eternal Energy Corp. and Oakley Ventures, LLC, and Exhibit A thereto. (Incorporated by reference to Exhibit 10.27a of our Annual Report on Form 10-K filed April 16, 2012.)
10.27b		Lease Addendum, dated July 1, 2012 by and between American Eagle Energy Corporation and Oakley Ventures, LLC. (Incorporated by reference to Exhibit 10.27b of our Quarterly Report on Form 10-Q filed on August 20, 2012.)
10.27c		Lease Addendum, dated November 1, 2013 by and between American Eagle Energy Corporation and Oakley Ventures, LLC.
10.28		Reserved for future use.
10.29		Reserved for future use.
10.30		Reserved for future use.
10.31		Reserved for future use.

 

 

10.32		Reserved for future use.
10.33		Reserved for future use.
10.34		Reserved for future use.
10.35		Reserved for future use.
10.36		Letter of Intent between Eternal Energy Corp. and American Eagle Energy Inc. dated February 22, 2011. (Incorporated by reference to Exhibit 10.36 of our Annual Report on Form 10-K filed March 23, 2011.)
10.37		Engagement Letter for Professional Services between Eternal Energy Corp. and C.K. Cooper & Company, dated February 25, 2011. (Incorporated by reference to Exhibit 10.37 of our Annual Report on Form 10-K filed March 23, 2011.)
10.38		Participation and Operating Agreement among Eternal Energy Corp., AEE Canada Inc. and Passport Energy Inc., dated April 15, 2011. (Incorporated by reference to Exhibit 10.38 of our Registration Statement on Form S-4 filed May 4, 2011.)
10.38a		Amendment to the participation and operating agreement among Eerg Energy Ulc, Aee Canada Inc. and Passport Energy Inc., dated February 1, 2012. (Incorporated by reference to Exhibit 10.38a of our Annual Report on Form 10-K/A filed April 10, 2012.)
10.39^		Purchase and Sale Agreement among Eternal Energy Corp., American Eagle Energy Inc., and NextEra Energy Gas Producing, LLC, dated May 17, 2011. (Incorporated by reference to Exhibit 10.39 of our Amended Quarterly Report on Form 10-Q/A filed October 11, 2011.)
10.40^		Purchase and Sale Agreement among Eternal Energy Corp., American Eagle Energy Inc., and NextEra Energy Gas Producing, LLC, dated May 17, 2011. (Incorporated by reference to Exhibit 10.40 of our Amended Quarterly Report on Form 10-Q/A filed October 11, 2011.)
10.40a		First Amendment to Purchase and Sale Agreement among Eternal Energy Corp., American Eagle Energy Inc., and NextEra Energy Gas Producing, LLC, dated June 14, 2011. (Incorporated by reference to Exhibit 10.40a of our Quarterly Report on Form 10-Q filed August 18, 2011.)
10.40b		Second Amendment to Purchase and Sale Agreement among Eternal Energy Corp., American Eagle Energy Inc., and NextEra Energy Gas Producing, LLC, dated July 25, 2011. (Incorporated by reference to Exhibit 10.40b of our Quarterly Report on Form 10-Q filed August 18, 2011.)
10.41^		Purchase and Sale Agreement among Eternal Energy Corp., American Eagle Energy Inc., and NextEra Energy Gas Producing, LLC, dated November 15, 2011. (Incorporated by reference to Exhibit 10.38a of our Annual Report on Form 10-K/A filed April 10, 2012.)
10.42^		Carry Agreement by and among American Eagle Energy Corporation, American Eagle Energy Inc., and NextEra Energy Gas Producing, LLC, dated as of April 16, 2012, and Exhibit C thereto. (Incorporated by reference to Exhibit 10.42 of our Quarterly Report on Form 10-Q filed on August 20, 2012.
10.43		First Amendment to Carry Agreement by and among American Eagle Energy Corporation, American Eagle Energy Inc., and NextEra Energy Gas Producing, LLC, dated as of July 15, 2012. (Incorporated by reference to Exhibit 10.43 of our Quarterly Report on Form 10-Q filed on August 20, 2012.)
10.44		ISDA Master Agreement by and among American Eagle Energy Corporation, AMZG, Inc., and Macquarie Bank Limited, dated December 27, 2012. (Incorporated by reference to Exhibit 10.44 of our Annual Report on Form 10-K filed on April 16, 2013.)
10.44a		Schedule to the 2002 ISDA Master Agreement by and among American Eagle Energy Corporation, AMZG, Inc., and Macquarie Bank Limited, dated December 27, 2012. (Incorporated by reference to Exhibit 10.44a of our Annual Report on Form 10-K filed on April 16, 2013.)
10.45		Commodity Swap Transaction Confirmation by and among American Eagle Energy Corporation, AMZG, Inc., and Macquarie Bank Limited, dated December 27, 2012. (Incorporated by reference to Exhibit 10.45 of our Annual Report on Form 10-K filed on April 16, 2013.)
10.46		Security Agreement by and among American Eagle Energy Corporation, AMZG, Inc., and Macquarie Bank Limited, dated December 27, 2012. (Incorporated by reference to Exhibit 10.46 of our Annual Report on Form 10-K filed on April 16, 2013.)
10.47		Mortgage, Security Agreement, Fixture Filing, Financing Statement and Assignment of Production and Revenue by and among American Eagle Energy Corporation, AMZG, Inc., and Macquarie Bank Limited, dated December 27, 2012. (Incorporated by reference to Exhibit 10.47 of our Annual Report on Form 10-K filed on April 16, 2013.)
10.48		Purchase and Sale Agreement by and between USG Properties Bakken I, LLC and American Eagle Energy Corporation, dated December 20, 2012. (Incorporated by reference to Exhibit 10.48 of our Annual Report on Form 10-K filed on April 16, 2013.)
10.49		Purchase and Sale Agreement Between SM Energy Company and American Eagle Energy Corporation, dated November 20, 2012. (Incorporated by reference to Exhibit 10.49 of our Annual Report on Form 10-K filed on April 16, 2013.)
21.1		List of Subsidiaries. (Incorporated by reference to Exhibit 21.1 of our Annual Report on Form 10-K filed April 16, 2013.)
31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*		Certification of Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

*          Filed herewith.

^          Portions omitted pursuant to a request for confidential treatment.

 

 

SIGNATURES

 

In accordance with the requirements of the Exchange Act, the registrant caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

AMERICAN EAGLE ENERGY CORPORATION
(Registrant)
August 4, 2014	/s/ Bradley M. Colby
	Bradley M. Colby
	President and Chief Executive Officer