Our financial statements required to be
included in Item 8 are set forth in the Index to Financial Statements on page 31 of this Annual Report.
The accompanying notes are an integral part
of the consolidated financial statements.
The accompanying notes are an integral part
of the consolidated financial statements.
The accompanying notes are an integral part
of the consolidated financial statements.
The accompanying notes are an integral part
of the consolidated financial statements.
The accompanying notes are an integral part
of the consolidated financial statements.
The accompanying notes are an integral part
of the consolidated financial statements.
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
|
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, development and producing of oil and gas properties. The Company is primarily focused on extracting proved oil
reserves. At December 31, 2013, the Company had entered into participation agreements related to oil and gas exploration
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
|
Basis of Presentation
The accompanying consolidated financial statements
include the accounts of the Company and its wholly-owned first-tier subsidiaries, AMZG, Inc., EERG Energy ULC (“EERG”
- Canadian) and AEE Canada Inc. (“AEE Canada” - 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. These reclassifications had no effect on net income (loss) for
the year ended December 31, 2012.
Revenue Recognition
Revenue from the sale of produced oil and gas is recognized
when the terms of the sale have been finalized and the oil has been delivered to the purchaser. The Company accrues estimated oil
and gas sales for production periods that have not yet been settled in cash.
Concentration of Credit Risk
At any point throughout the year, the Company may
have amounts that exceed the United States (FDIC) federally insurance limit of $250,000 per bank.
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
Foreign Currency Adjustments
The functional currency of EERG and AEE Canada is
the Canadian Dollar. EERG’s and AEE Canada’s asset and liability account balances are translated into US Dollars at
the exchange rate in effect as of the balance sheet dates. Gains and losses realized upon the settlement of foreign currency transactions
are included in the Company’s results of operations. Foreign currency translation adjustments are presented as other comprehensive
income.
Components of Other Comprehensive Income
Comprehensive income consists of net income and other
gains and losses affecting stockholders’ equity that, under generally accepted accounting principles, are excluded from net
income. For the Company, such items consist of unrealized gains (losses) on marketable securities and foreign currency translation
adjustments.
Cash and Cash Equivalents
Cash equivalents consist of time deposits and liquid
debt investments with original maturities of three months or less at the time of purchase.
Receivables
Receivables are stated at the amount the Company
expects to collect. In certain instances, the Company has the legal right to offset undistributed revenues from its operated wells
against uncollected receivables from its working interest partners. The Company considers the following factors when evaluating
the collectability of specific receivable balances: credit-worthiness of the debtor, past transaction history with the debtor,
current economic industry trends, and changes in debtor payment terms. If the financial condition of the Company’s debtors
were to deteriorate, adversely affecting their ability to make payments, additional allowances would be required.
The Company maintains an allowance for doubtful accounts
for estimated losses resulting from the inability of its customers to make required payments. Changes to the allowance for doubtful
accounts made as a result of management’s determination regarding the ultimate collectability of such accounts are recognized
as a charge to the Company’s earnings. Specific receivable balances that remain outstanding after the Company has used reasonable
collection efforts are written off through a charge to the valuation allowance and a credit to the receivable.
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
At December 31, 2013 and 2012, the Company has determined
that all receivable balances are fully collectible and, accordingly, no allowance for doubtful accounts has been recorded.
Equipment and Leasehold Improvements
Equipment and leasehold improvements are recorded
at cost. Expenditures for major additions and improvements are capitalized and depreciated or amortized over the estimated useful
lives of the related assets using the straight-line method for financial reporting purposes. The estimated useful lives for significant
property and equipment categories are as follows:
Furniture and equipment
|
3 years
|
Leasehold improvements
|
lesser of useful life or lease term
|
When equipment and improvements are retired or otherwise
disposed of, the cost and the related accumulated depreciation are removed from the Company’s accounts and any resulting
gain or loss is included in the results of operations for the respective period.
Expenditures for minor replacements, maintenance and
repairs are charged to expense as incurred.
Oil and Gas Properties and Prospects
The Company follows the full-cost method of accounting
for its investments in oil and gas properties. Under the full-cost method, all costs associated with the acquisition, exploration
or development of properties, are capitalized into appropriate cost centers within the full-cost pool. Internal costs that are
capitalized are limited to those costs that can be directly identified with acquisition, exploration, and development activities
undertaken and do not include any costs related to production, general corporate overhead, or similar activities. Cost centers
are established on a country-by-country basis.
Capitalized costs and estimated future development
and abandonment costs for each of the Company’s cost centers are amortized on the unit-of-production basis using proved oil
and gas reserves. The cost of investments in unproved properties and major development projects are excluded from capitalized costs
to be amortized until it is determined that proved reserves can be assigned to the properties. Until such a determination is made,
the properties are assessed annually to ascertain whether impairment has occurred. The costs of drilling exploratory dry holes
are included in the amortization base immediately upon determination that the well is dry.
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
As of the
end of each reporting period, the capitalized costs of each cost center are subject to a ceiling test, in which the costs may not
exceed the cost center ceiling. The cost center ceiling is equal to (i) the present value of estimated future net revenues computed
by applying average monthly prices of oil and gas reserves (with consideration of price changes only to the extent provided by
contractual arrangements) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet
presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves
computed using a discount factor of ten percent and assuming continuation of existing economic conditions; plus (ii) the cost of
properties not being amortized; plus (iii) the lower of cost or estimated fair value of unproven properties included in the costs
being amortized; less (iv) income tax effects related to differences between the book and tax basis of the properties. If unamortized
costs capitalized within a cost center, less related deferred income taxes, exceed the cost center ceiling, the excess is charged
to expense and separately disclosed during the period in which the excess occurs. The Company recognized impairment losses totaling
approximately $1.7 million and approximately $10.6 million associated with its Canadian cost center for the years ended December
31, 2013 and 2012, respectively.
Proceeds received
from the disposal of oil and gas properties are credited against accumulated costs, except when the sale represents a significant
disposal of reserves, in which case a gain or loss is recognized.
Deferred Loan Costs
The Company
capitalizes costs that are directly related to securing bank loans and other types of long-term financing and amortizes such costs
over the life of the corresponding debt using the effective interest method.
Derivatives
The Company
reports its price swap derivatives at its fair market value as of the end of each reporting period. Unrealized gains (losses) for
the period associated with the price swap derivative are included in the Company’s results of operations.
Asset Retirement Obligations
The Company records estimated asset retirement obligations
related to the future plugging and abandoning of its existing wells in the period in which the wells are completed. The initial
recording of an asset retirement obligation results in an increase in the carrying amount of the related long-lived asset and the
creation of a liability. The portion of the asset retirement obligation expected to be realized during the next 12-month period
is classified as a current liability, while the portion of the asset retirement obligation expected to be realized during subsequent
periods is discounted and recorded at its net present value. The discount factors used to determine the net present value of the
Company’s asset retirement obligation range from 4.2% to 10.5%, which represented the Company’s estimated incremental
borrowing rate as of the dates that the corresponding wells were put on production.
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
Changes in
the noncurrent portion of the asset retirement obligation due to the passage of time are accreted using the interest method. The
amount of change is recognized as an increase in the liability and an accretion expense in the statement of operations. Changes
in either the current or noncurrent portion of the Company’s asset retirement obligation resulting from revisions to the
timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying
amount of the liability and the related long-lived asset.
Stock-Based Compensation
The Company measures compensation cost for all stock-based
awards at fair value on the date of grant and recognizes compensation expense in its statements of operations over the service
period that the awards are expected to vest. The Company has elected to recognize compensation cost for all options with graded
vesting on a straight-line basis over the vesting period of the entire option. The Company recognized stock-based compensation
expense of approximately $1.2 million and $0.8 million for the years ended December 31, 2013 and 2012, respectively.
Fair Value of Financial Instruments
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 Company
uses Level 2 inputs to determine the fair value of certain warrants to purchase shares of common stock of an entity that is traded
on the Canadian National Stock Exchange. The warrants are valued using the Black Scholes Option Pricing Model, which includes a
calculation of volatility of the Company’s stock.
Basic and Diluted Earnings Per Share
Basic earnings per common share is computed by dividing
net earnings available to common stockholders by the weighted average number of common shares outstanding during the period. For
periods in which the Company recognizes net income, diluted earnings per common share is computed in the same way as basic earnings
per common share except that the denominator is increased to include the number of additional common shares that would be outstanding
if all potential common shares had been issued that were dilutive. For periods in which the Company recognizes losses, the calculation
of diluted earnings per share is the same as the calculation of basic earnings per share. See Note 14 for the calculation of basic
and diluted weighted average common shares outstanding for the years ended December 31, 2013 and 2012.
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
Income Taxes
The Company follows the liability method of accounting
for income taxes. Under this method, deferred income tax assets and liabilities are recognized for the future tax benefits and
consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and
their respective tax balances. Deferred income tax assets and liabilities are measured using enacted or substantially enacted tax
rates expected to apply to the taxable income in the years in which those differences are expected to be recovered or settled.
The effect on deferred income tax assets and liabilities of a change in tax rates is recognized in income in the period that includes
the date of enactment or substantive enactment. Net operating loss carry forwards and other deferred tax assets are reviewed annually
for recoverability and, if necessary, are recorded net of a valuation allowance. See Note 13 for a summary of the Company’s
income tax expense (benefit) for the years ended December 31, 2013 and 2012.
Liquidity
The Company finances its oil and gas exploration and
development activities and corporate operations through a combination of internally generated funds, external debt financing and
sales of its common stock. As of December 31, 2013, the Company had working capital of approximately $4.9 million.
Use of Estimates and Assumptions
The preparation of financial statements in conformity
with accounting principles generally accepted in the United States requires the use of estimates and assumptions that affect the
reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent obligations in the financial statements
and accompanying notes. The Company’s most significant assumptions are the estimates used in the determination of the deferred
income tax asset valuation allowance and the valuation of oil and gas reserves to which the Company owns rights. The estimation
process requires assumptions to be made about future events and conditions, and as such, is inherently subjective and uncertain.
Actual results could differ materially from these estimates.
New Accounting Pronouncements
In January 2013, the Financial Accounting Standards
Board (“FASB”) issued ASC Update No. 2013-01 (“ASC No. 2013-01”), The objective of ASC No. 2013-01 is to
clarify that the scope of Accounting Standards Update No. 2011-11
, Disclosures about Offsetting Assets and Liabilities
(“ASC
No. 2011-11”), would apply to derivatives including bifurcated embedded derivatives, repurchase agreements and reverse repurchase
agreements, and securities borrowing and securities lending transactions that are either offset or are subject to a master netting
arrangement or similar agreement. ASC No. 2011-11, issued in December 2011, requires that entities disclose both gross and net
information about instruments and transactions eligible for offset in the statement of financial position as well as instruments
and transactions subject to an agreement similar to a master netting arrangement. In addition, the standard requires disclosure
of collateral received and posted in connection with master netting agreements or similar arrangements. The amendments are effective
for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. The disclosures
required by the amendments are required to be applied retrospectively for all comparative periods presented. The Company does not
believe the adoptions of this update will have a material impact on the Company’s consolidated financial statements.
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
|
3.
|
Marketable Securities and Fair Value Measurements
|
Available-for-sale marketable securities at December
31, 2013 and 2012 consist of the following:
|
|
|
|
|
Gains in
|
|
|
Losses in
|
|
|
|
|
|
|
Accumulated
|
|
|
Accumulated
|
|
|
|
Estimated
|
|
|
Other
|
|
|
Other
|
|
|
|
Fair
|
|
|
Comprehensive
|
|
|
Comprehensive
|
|
|
|
Value
|
|
|
Income
|
|
|
Income
|
|
December 31, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock
|
|
$
|
1,049,944
|
|
|
$
|
76,881
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2012
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock
|
|
$
|
1,049,859
|
|
|
$
|
76,796
|
|
|
$
|
-
|
|
The fair value of substantially all securities is
determined by quoted market prices. The estimated fair value of securities for which there are no quoted market prices is based
on similar types of securities that are traded in the market. There were no sales of marketable securities for the years ended
December 31, 2013 or 2012.
The fair value of the Company’s financial instruments,
measured on a recurring basis at December 31, 2013 and 2012, were as follows:
December 31, 2013
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
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
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketable securities
|
|
|
1,049,859
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,049,859
|
|
Current derivative liability
|
|
|
-
|
|
|
|
(122,651
|
)
|
|
|
-
|
|
|
|
(122,651
|
)
|
|
4.
|
Purchases of Royalty and Property Interests
|
In December 2012, the Company purchased additional
net revenue and working interests in several key, non-operated spacing units within the Spyglass Area from its Carry Agreement
partner. The purchase price totaled $8 million in cash, of which $2.4 million was paid at closing. The remaining $5.6 million was
paid in September, 2013.
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
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 12), and
borrowed an additional $40 million under its existing credit facility with Morgan Stanley Capital Group, Inc. (See Note 8).
Supplemental Pro Forma Information (Unaudited)
The Company’s consolidated statement of income for the
year ended December 31, 2013 includes revenues and oil and gas operating expenses related to the net revenue and working interests
acquired in October 2013 for the period October 2, 2013 through December 31, 2013 of approximately $4.2 million and $1.0 million,
respectively.
Had the purchase of these additional net revenue and working
interests occurred on January 1, 2012, the Company’s consolidated financial statements for the years ended December 31, 2013
and 2012 would have been as follows:
|
|
2013
|
|
|
2012
|
|
Pro forma revenues
|
|
$
|
57,823,375
|
|
|
$
|
15,988,431
|
|
|
|
|
|
|
|
|
|
|
Pro forma net income (loss)
|
|
$
|
4,134,461
|
|
|
$
|
(10,872,966
|
)
|
On April 16, 2012,
the Company entered into a carry agreement (the “First Carry Agreement”) with a third-party working interest partner
(“Carry Agreement Partner”), pursuant to which (i) that 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 will 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 will share in the excess costs based on the working interests stipulated
in the First Carry Agreement.
Pursuant to the
terms of the First Carry Agreement, the portion of the Company’s net revenue interest in each well to be conveyed to the
Carry Agreement Partner follows a graduated scale, whereby 50% of the Company’s net revenue and working interests is 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 has 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 will increase from 50% to 75% for the second year of production or until the carried costs, plus the 12% return, have
been achieved, whichever occurs first. In the event that the Carry Agreement Partner has 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 will increase to 100% until the carried costs, plus the 12% return, have 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 will revert
to the original working interests in each such well.
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
Drilling of the
first two carried wells commenced prior to the final closing of the First Carry Agreement. As of the date of closing, the Company
had incurred drilling costs associated with the first two wells to be covered under the First Carry Agreement totaling approximately
$3.8 million. Upon execution of the First Carry Agreement, these costs were removed from the Company’s books and an offsetting
receivable was created. The receivable has since been fully collected. Pursuant to accounting rules, the assignment of a portion
of the Company’s working interests in certain existing and future wells under the First Carry Agreement has been treated
as a conveyance of the working interests. The Company’s share of the revenues and operating costs of the carried wells for
the years ended December 31, 2013 and 2012, as adjusted pursuant to the graduated conveyance schedule per the First Carry Agreement,
have been included in the Company’s results of operations for the corresponding period. In addition, the Company has disclosed
the transfer of the drilling costs to the financing partner as a source of cash from investing activities on its consolidated statement
of cash flows for the years ended December 31, 2013 and 2012.
Effective July
15, 2012, the Company amended the First Carry Agreement with the Carry Agreement Partner to include an additional four oil and
gas wells. As of December 31, 2013, the Company has received approximately $28.5 million of funding under the First Carry Agreement,
as amended. Proceeds received pursuant to the terms of the First Carry Agreement, subsequent to the closing, are applied against
the drilling and completion costs to which they relate. Additions to oil and gas properties that occurred subsequent to the closing
of the First Carry Agreement are presented net of proceeds received under the First Carry Agreement on the consolidated statement
of cash flows. Funds received pursuant to the First Carry Agreement, prior to the incurrence of related drilling costs, are presented
as amounts due to working interest partners on the consolidated balance sheet.
As of December
31, 2013, all ten of the wells drilled pursuant to the First Carry Agreement were producing. As of December 31, 2013, the gross
drilling and completion costs of five of the carried wells had exceeded the 120% of AFE limit. Accordingly, the Company has recorded
its working interest share in the excess drilling and completion costs which, as of December 31, 2013, totaled approximately $2.5
million. None of the ten wells covered by the First Carry Agreement has achieved payout as of December 31, 2013.
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 will 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.
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
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 of December
31, 2013, two of the five wells drilled pursuant to the Second Carry Agreement were producing. The remaining three wells were either
in the process of being completed or awaiting drilling. To date, the Company has received approximately $4.1 million of funding
under the Second Carry Agreement. As of December 31, 2013, the cost of drilling and completing each of these five wells has not
exceeded the 120% of AFE cost threshold. Accordingly, the Company has not recorded any drilling and completion costs associated
with these five wells as of December 31, 2013. None of the five wells covered by the Second Carry Agreement has achieved payout
as of December 31, 2013.
In August 2013,
the Company entered into a Farm-Out Agreement (the “Farm-Out Agreement”) with the same 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 will 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 December
31, 2013, two of the six wells drilled pursuant to the Farm-Out Agreement were producing. The remaining four wells were either
in the process of being completed or awaiting drilling. To date, the Company has received approximately $5.1 million of funding
under the Farm-Out Agreement. None of the six wells covered by the Farm-Out Agreement has achieved payout as of December 31, 2013.
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
On December 28, 2012, the Company entered into a
prepaid Swap Facility with 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 are 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 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
$151,000 of amortization expense related to the deferred financing costs for the year ended December 31, 2013. 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.
The annual interest rate associated with the Swap
Facility approximated 7.4%. The Company recognized interest expense related to the Swap Facility totaling approximately $903,000
and $183,000 for the years ended December 31, 2013 and 2012, respectively.
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 reduce the Company’s payables, (ii) to develop its Spyglass Area in North Dakota
to increase production of hydrocarbons, (iii) to acquire new oil and gas properties within the Spyglass Area and (iv) to fund
general corporate purposes that are usual and customary in the oil and gas exploration and production business.
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
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 December 31, 2013, 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 $3.8 million for the year ended December 31, 2013.
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 will amortize 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 $451,000 of deferred financing costs
related to the Credit Facility during the year ended December 31, 2013.
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.
Accordingly, the Company has classified $3.0 million of the debt outstanding under the Credit Facility as a current liability.
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. As of December 31, 2013, the
Company was in compliance with these covenants.
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
Future minimum principal payments under the Credit
Facility are as follows:
|
|
Amount
|
|
2014
|
|
$
|
3,000,000
|
|
2015
|
|
|
7,200,000
|
|
2016
|
|
|
7,200,000
|
|
2017
|
|
|
7,200,000
|
|
2018
|
|
|
83,400,000
|
|
Total
|
|
$
|
108,000,000
|
|
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 unrealized gains (losses) associated with the derivative in its statement of operations
in the period for which such unrealized gains (losses) occur. These price swaps were closed at the time that the Swap Facility
was repaid in full. The Company recognized realized losses on the price swap agreements associated with the Swap Facility of approximately
$37,000 for the year ended December 31, 2013.
As a condition of closing for the Credit Facility
(see Note 8), the Company entered into a commodity price swap agreement covering 85% of its projected five-year future production
on its proved, developed, producing properties. The Company has not designated the price swap agreement as a hedge. Accordingly,
management has elected not to apply hedge accounting to this derivative but will, instead, recognize unrealized gains (losses)
associated with the derivative in its statement of operations in the period for which such unrealized gains (losses) will occur.
The Company recognized realized gains on the price swap agreements associated with the Credit Facility totaling approximately $766,000
for the year ended December 31, 2013.
The Company’s outstanding price swap agreements
had the following net fair market values as of December 31, 2013 and 2012:
|
|
2013
|
|
|
2012
|
|
Current derivative asset
|
|
$
|
210,779
|
|
|
$
|
-
|
|
Current derivative liability
|
|
|
(275,516
|
)
|
|
|
(122,651
|
)
|
Non-current derivative liability
|
|
|
(749,872
|
)
|
|
|
-
|
|
Net derivative liability
|
|
$
|
(814,609
|
)
|
|
$
|
(122,651
|
)
|
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
|
10.
|
Asset Retirement Obligations
|
During the years ended December 31, 2013 and 2012,
the Company recorded initial, estimated asset retirement obligations totaling approximately $569,000 and $403,000, respectively,
in connection with wells that were drilled and completed during the period. The asset retirement obligations represent the discounted
future plugging and abandonment costs for operated and non-operated wells located within its Spyglass Area and Hardy Property. As
of December 31, 2013 and 2012, the consolidated discounted value of the Company’s asset retirement obligations was approximately
$1.1 million and $442,000, respectively. The projected plugging dates for wells in which the Company owns a working interest ranges
from December 31, 2015 to December 31, 2032.
|
11.
|
Commitments and Contingencies
|
Drilling Obligations
The Company has the option to participate in the drilling
of future non-operated, development wells related to its working interest in the Spyglass Area, should any such wells be proposed
by the other working interest owners. As of December 31, 2013, the Company has elected to participate in 76 wells located within
the Spyglass Area. As such, the Company is currently obligated to fund its non-operating working interest portion of the drilling
and future operations costs of these wells. The Company’s working interests in the Spyglass wells range from 0.04% to 28.34%.
Additional wells could be proposed in the future, at which time the Company may or may not elect to participate in such additional
wells.
The Company intends to drill and operate additional
horizontal and/or vertical wells to be located within the Spyglass Area and has contracted for the use of a drilling
rig for the foreseeable future. The Company is obligated to pay its proportionate share of the costs related to the use of the
drilling rig in connection with the drilling of future wells, some of which are subject to the Second Carry Agreement (see Note
5).
Employment Contracts
The Company has entered into employment agreements
with its President, its Chief Operating Officer, its Chief Financial Officer and three other members of management, which stipulate,
among other things, severance payments in the event that employment is terminated without cause or as a result of a change in control,
as defined by the employment agreements. As of December 31, 2013, the amount of severance payments that the Company would be obligated
to make under the terms of the employment agreements would total approximately $1.1 million.
Lease Obligation
The Company currently leases office space pursuant
to the terms of a three-year lease agreement. Future lease payments related to the Company’s office lease as of December
31, 2013 are as follows:
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
|
|
Amount
|
|
2014
|
|
$
|
177,798
|
|
2015
|
|
|
183,855
|
|
2016
|
|
|
96,305
|
|
Total
|
|
$
|
457,958
|
|
Rent expense for
the years ended December 31, 2013 and 2012 totaled approximately $146,000 and $110,000, respectively.
Shares Issued in Connection with Swap Facility
As discussed
in Note 7, the Company issued 56,391 shares of its common stock in connection with the Swap Facility with MBL.
Private Placements
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 $4.0 million.
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 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 sale of stock
was completed pursuant to the Company’s August 2, 2013 shelf registration. Proceeds from the sale, net of expenses and broker
fees, totaled approximately $25.0 million.
Stock Options
During the years ended December 31, 2013 and 2012,
the Company granted 440,000 and 648,125 stock options to members of its Board of Directors, employees and certain key third-party
consultants. Each of the stock options granted have 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 of the grant date.
The assumptions used in the Black-Scholes Option Pricing
Model for the stock options granted were as follows:
|
|
2013
|
|
2012
|
Risk-free interest rate
|
|
0.23% to 0.35%
|
|
0.22% to 0.92%
|
Expected volatility of common stock
|
|
62% to 84%
|
|
79% to 196%
|
Dividend yield
|
|
$0.00
|
|
$0.00
|
Expected life of options
|
|
5 years
|
|
5 years
|
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
A summary of stock option activity for the years ended
December 31, 2013 and December 31, 2012 is presented below:
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Weighted
|
|
|
Average
|
|
|
|
|
|
|
Average
|
|
|
Remaining
|
|
|
|
|
|
|
Exercise
|
|
|
Contract
|
|
|
|
Options
|
|
|
Price ($)
|
|
|
Term
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2011
|
|
|
448,861
|
|
|
$
|
0.90
|
|
|
|
3.8
years
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AEE Inc. options converted
|
|
|
433,248
|
|
|
|
2.96
|
|
|
|
3.2 years
|
|
Options granted
|
|
|
440,000
|
|
|
|
3.24
|
|
|
|
4.8 years
|
|
Options exercised
|
|
|
(38,459
|
)
|
|
|
0.90
|
|
|
|
3.8 years
|
|
Options expired
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Options
forfeited
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2012
|
|
|
1,283,650
|
|
|
$
|
3.12
|
|
|
|
3.6
years
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options granted
|
|
|
648,125
|
|
|
|
8.48
|
|
|
|
4.8 years
|
|
Options exercised
|
|
|
(5,000
|
)
|
|
|
3.12
|
|
|
|
4.0 years
|
|
Options expired
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Options
forfeited
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December
31, 2013
|
|
|
1,926,775
|
|
|
$
|
4.92
|
|
|
|
3.4
years
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at December
31, 2013
|
|
|
1,068,650
|
|
|
$
|
3.12
|
|
|
|
2.4
years
|
|
The options
outstanding as of December 31, 2013 and December 31, 2012 have an intrinsic value of $4.12 and $0.48 per share and an aggregate
intrinsic value of approximately $7.9 million and $616,000, respectively.
Shares Reserved for Future Issuance
As of December
31, 2013 and December 31, 2012, the Company had reserved 1,926,775 and 1,283,650 shares, respectively, for future issuance upon
exercise of outstanding options.
The Company recognized
stock-based compensation expense of approximately $1.2 million and $800,000 for the years ended December 31, 2013 and 2012, respectively.
The Company recognized income tax expense (benefit)
of approximately $1.8 million and ($1.2 million) for the years ended December 31, 2013 and December 31, 2012, respectively. Income
tax expense (benefit) for the years ended December 31, 2013 and 2012 consisted of the following:
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
|
|
2013
|
|
|
2012
|
|
Current income tax expense (benefit):
|
|
|
|
|
|
|
|
|
Domestic
|
|
$
|
(17,346
|
)
|
|
$
|
(301,533
|
)
|
Foreign
|
|
|
(77,174
|
)
|
|
|
(32,268
|
)
|
Total current income tax benefit
|
|
|
(94,520
|
)
|
|
|
(333,801
|
)
|
|
|
|
|
|
|
|
|
|
Deferred income tax expense (benefit):
|
|
|
|
|
|
|
|
|
Domestic
|
|
|
1,863,236
|
|
|
|
348,510
|
|
Foreign
|
|
|
-
|
|
|
|
(1,254,719
|
)
|
Total deferred income tax expense (benefit)
|
|
|
1,863,236
|
|
|
|
(906,209
|
)
|
|
|
|
|
|
|
|
|
|
Total income tax expense (benefit)
|
|
$
|
1,768,716
|
|
|
$
|
(1,240,010
|
)
|
Significant components of the Company’s deferred
income tax assets and liabilities at December 31, 2013 and 2012 are as follows:
|
|
2013
|
|
|
2012
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Foreign tax credits
|
|
$
|
52,261
|
|
|
$
|
32,275
|
|
Unrealized hedging loss
|
|
|
301,327
|
|
|
|
44,520
|
|
Asset retirement obligations
|
|
|
308,475
|
|
|
|
112,608
|
|
Net operating losses – domestic
|
|
|
5,688,168
|
|
|
|
4,075,159
|
|
Net operating losses – foreign
|
|
|
864,374
|
|
|
|
716,967
|
|
Foreign fixed assets
|
|
|
1,936,859
|
|
|
|
1,448,717
|
|
Stock options
|
|
|
1,213,480
|
|
|
|
757,432
|
|
Marketable securities
|
|
|
47,633
|
|
|
|
-
|
|
Other
|
|
|
160,209
|
|
|
|
-
|
|
Total deferred tax assets
|
|
|
10,572,786
|
|
|
|
7,187,678
|
|
Valuation allowance
|
|
|
(2,858,328
|
)
|
|
|
(2,165,684
|
)
|
Net deferred income tax assets
|
|
$
|
7,714,458
|
|
|
$
|
5,021,994
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Deferred gain
|
|
$
|
-
|
|
|
|
-
|
|
Investment in foreign subsidiary
|
|
|
321,673
|
|
|
|
181,548
|
|
Domestic fixed assets
|
|
|
12,778,739
|
|
|
|
8,353,909
|
|
Marketable securities
|
|
|
-
|
|
|
|
6,031
|
|
Deferred tax liabilities
|
|
$
|
13,100,412
|
|
|
$
|
8,541,488
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liabilities
|
|
$
|
5,385,954
|
|
|
$
|
3,519,494
|
|
A reconciliation between the amount of income tax
expense for the years ended December 31, 2013 and 2012, determined by applying the appropriate applicable statutory income tax
rates, is as follows:
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
|
|
2013
|
|
|
2012
|
|
U.S. Statutory tax expense (benefit)
|
|
$
|
1,143,472
|
|
|
$
|
(3,581,180
|
)
|
State income taxes, net of federal expense (benefit)
|
|
|
95,728
|
|
|
|
(242,104
|
)
|
Foreign taxes paid
|
|
|
12,360
|
|
|
|
-
|
|
Permanent differences
|
|
|
10,843
|
|
|
|
8,003
|
|
Change in valuation allowance
|
|
|
640,894
|
|
|
|
2,165,684
|
|
True-up of prior year amounts
|
|
|
243,794
|
|
|
|
(536,758
|
)
|
Foreign operations
|
|
|
(235,630
|
)
|
|
|
908,878
|
|
Rate change
|
|
|
(142,745
|
)
|
|
|
39,421
|
|
Other
|
|
|
-
|
|
|
|
(1,954
|
)
|
Total income tax
expense (benefit)
|
|
$
|
1,768,716
|
|
|
$
|
(1,240,010
|
)
|
|
|
|
|
|
|
|
|
|
Effective tax rate
|
|
|
52.59
|
%
|
|
|
(11.77
|
)%
|
The following is a reconciliation of the number of
shares used in the calculation of basic and diluted earnings per share for the years ended December 31, 2013 and 2012:
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
1,594,434
|
|
|
$
|
(9,292,874
|
)
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding
|
|
|
13,961,688
|
|
|
|
11,448,048
|
|
Incremental shares from the assumed exercise of dilutive stock options
|
|
|
637,148
|
|
|
|
-
|
|
Diluted common shares outstanding
|
|
|
14,598,836
|
|
|
|
11,448,048
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per share - basic
|
|
$
|
0.11
|
|
|
$
|
(0.81
|
)
|
Earnings (loss) per share - diluted
|
|
$
|
0.11
|
|
|
$
|
(0.81
|
)
|
Because the Company
recognized a net loss for the year ended December 31, 2012, the calculation of diluted loss per share is the same as the calculation
of basic 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 year ended December 31, 2012 is 468,775.
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
|
15.
|
Related Party Transactions
|
The Company is under contract through February
2015 to sell 100% of its oil, gas and liquids production to Power Energy Partners LP (“Power Energy”). In January 2014,
Power Energy purchased 1,000,000 shares of our common stock at price of $4.00 per share via a private placement. In August 2013,
Power Energy purchased an additional 1,250,000 shares of our common stock at a price of $8.00 per share via a public offering.
The Company routinely obtains legal services from
a firm for whom one of its directors serves as a principal. Fees paid this firm approximated $37,000 and $24,000 for the years
ended December 31, 2013 and 2012, 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 $168,000 of consulting expenses from Synergy during each
of the years ended December 31, 2013 and 2012.
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. Revenues paid to these individuals totaled approximately
$608,000 and $540,000 for the year ended December 31, 2013, and approximately $67,000 and $52,000 for the year ended December 31,
2012, respectively.
Reverse Stock
Split
On March 18, 2014,
the Company completed a 1-for-4 reverse split of the Company’s common stock. Pursuant to accounting guidelines, all historical
share and per-share data contained in these financial statements has been restated to reflect the reverse stock split as if it
had occurred on January 1, 2012.
Public Offering
On March 24,
2014, the Company closed on a public stock offering, pursuant to which the Company sold 12,650,000 shares of its common
stock. 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.
Working Interest
Acquisition
On March 27, 2014, the Company closed on its
option to purchase 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 gross purchase price for the acquired interests of
$47 million 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 working interests was funded with
proceeds received from the March 2014 public offering, as discussed above.
Also on March 27, 2014, the Company
purchased approximately 5,000 net unproved acres located within the Spyglass Area from the same working interest partner, for
cash consideration of approximately $7.5 million.
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
|
17.
|
Supplemental Oil and Gas Information (Unaudited)
|
During the years ended December 31, 2013 and 2012,
the Company incurred the following costs associated with the acquisition, exploration and development of oil and gas properties:
|
|
2013
|
|
|
2012
|
|
Acquisition costs
|
|
$
|
62,859,262
|
|
|
|
16,671,183
|
|
Exploration costs
|
|
|
32,053,227
|
|
|
|
-
|
|
Development costs
|
|
|
28,543,201
|
|
|
|
27,914,011
|
|
Total costs
|
|
$
|
123,455,690
|
|
|
$
|
44,585,194
|
|
The net capitalized cost of the Company’s oil
and gas properties, subject to amortization, as of December 31, 2013 and 2012 is summarized below:
|
|
2013
|
|
|
2012
|
|
Acquisition costs
|
|
$
|
88,909,755
|
|
|
$
|
26,050,493
|
|
Exploration costs
|
|
|
-
|
|
|
|
-
|
|
Development costs
|
|
|
93,696,371
|
|
|
|
33,099,942
|
|
Impairments and sales
|
|
|
(14,612,024
|
)
|
|
|
(12,880,489
|
)
|
Gross capitalized costs
|
|
|
167,994,102
|
|
|
|
46,269,946
|
|
Accumulated depletion
|
|
|
(12,849,063
|
)
|
|
|
(2,978,403
|
)
|
Net capitalized costs
|
|
$
|
155,145,039
|
|
|
$
|
43,291,543
|
|
The Company owns mineral interests in both operated
and non-operated producing wells, as well as in undeveloped acreage, for which proved oil and gas reserves have been assigned,
the vast majority of which are located in the United States. The Company also owns mineral interests in a small number of operated
and non-operated properties located in Canada. Pursuant to full-cost accounting rules, the Company maintains separate cost centers
for its US and Canadian oil and gas properties and related costs. The proved reserves associated with the Company’s US cost
center represents 99.5% of the Company’s total proved reserves, both on a volume and discounted, future cash flow (PV10)
basis as of December 31, 2013. Furthermore, revenues generated from the Company’s US oil and gas properties accounted for
97.1% of the Company’s total revenue for the year ended December 31, 2013. Because the result of operations and proved reserves
associated with the Company’s Canadian oil and gas operations is properties is not material to the Company’s overall
results of operations and reserves, the Company has elected to present the following supplemental oil and gas information on a
consolidated basis, rather than by cost center.
The Company recognized the following revenues and
expenses associated with its oil and gas producing activities for the years ended December 31, 2013 and 2012:
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
|
|
2013
|
|
|
2012
|
|
Oil and gas revenues
|
|
$
|
43,138,957
|
|
|
$
|
10,713,946
|
|
Oil and gas production costs
|
|
|
11,609,106
|
|
|
|
3,200,171
|
|
Net oil and gas revenues
|
|
$
|
31,529,851
|
|
|
$
|
7,513,775
|
|
|
|
|
|
|
|
|
|
|
Oil production (barrels)
|
|
|
492,706
|
|
|
|
134,314
|
|
Gas production (mcf)
|
|
|
27,556
|
|
|
|
2,306
|
|
Liquids production (barrels)
|
|
|
5,507
|
|
|
|
-
|
|
Barrels of Oil Equivalent (BOE)
|
|
|
502,806
|
|
|
|
134,698
|
|
|
|
|
|
|
|
|
|
|
Depletion expense
|
|
$
|
9,978,094
|
|
|
$
|
2,800,393
|
|
Impairment expense
|
|
|
1,731,535
|
|
|
|
10,361,345
|
|
|
|
|
|
|
|
|
|
|
Average sales price per BOE
|
|
$
|
85.80
|
|
|
$
|
79.58
|
|
Oil and gas production costs per BOE
|
|
|
23.09
|
|
|
|
23.77
|
|
Depletion expense per BOE
|
|
|
19.84
|
|
|
|
20.81
|
|
Impairment expense per BOE
|
|
|
3.44
|
|
|
|
76.96
|
|
The tables presented below set forth the Company’s
net interests in quantities of proved developed and undeveloped reserves of crude oil, condensate and natural gas and changes in
such quantities from the prior period. Crude oil reserves estimates include condensate.
The reserve estimation process involves reservoir
engineers, geoscientists, planning engineers and financial analysts. As part of this process, all reserves volumes are estimated
by a forecast of production rates, operating costs and capital expenditures. Estimated future cash flows were computed by applying
an average of the monthly oil prices for the year to the Company’s share of estimated annual future production from proved
oil and gas reserves, net of royalties. Production rate forecasts are derived by a number of methods, including estimates from
decline curve analyses, material balance calculations that take into account the volume of substances replacing the volumes produced
and associated reservoir pressure changes, or computer simulation of the reservoir performance. Operating costs and capital costs
are forecast based on past experience combined with expectations of future cost for the specific reservoirs. In many cases, activity-based
cost models for a reservoir are utilized to project operating costs as production rates and the number of wells for production
and injection vary.
The Company has retained an independent petroleum
engineering firms to determine its annual estimate of oil and gas reserves as of December 31, 2013 and 2012. The independent petroleum
engineering firms estimated the oil and gas reserves associated with the Company’s US and Canadian oil and gas properties
using generally accepted industry standards, which include the review of technical data, methods and procedures used in estimating
reserves volumes, the economic evaluations and reserves classifications.
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
The Company believes that the methodologies used by
the independent petroleum engineering firms in preparing the relevant estimates comply with current Securities and Exchange Commission
standards for preparing such estimates. The Company has implemented internal controls regarding the development of reasonable oil
and gas reserves estimates. These controls include, among other things, a thorough review of the estimated future development costs
and estimated production costs associated with the reserves and a comparison of such estimated future costs to actual development
and production costs incurred during the current period. In addition, the Company’s operational team compares the average
prices used to estimate discounted net future cash flows from proved reserves to actual prices received during the period for reasonableness.
The internal control procedures described above were performed by the Company’s operational team, which includes petroleum
engineers having in excess of 80 years of oil and gas exploration and production experience, collectively. Based on the performance
of these internal controls, the Company’s management believes that the underlying data provided by the Company to the independent
petroleum engineering firm for the purpose of preparing its estimates, is reasonable Furthermore, the estimated reserves as of
December 31, 2013 and 2012, as described in the final report issued by the independent petroleum engineering firm, were reviewed
by members of the Company’s operational management and determined to be reasonable based on the underlying data.
The following tables summarize the Company’s
proved oil and gas reserves, annual production and other changes in the Company’s proved oil and gas reserves for the years
ended December 31, 2013 and 2012:
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
|
(Barrels)
|
|
|
(Mcf)
|
|
|
(BOE)
|
|
For the year ended December 31, 2013:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves, beginning of year
|
|
|
5,397,542
|
|
|
|
2,139,067
|
|
|
|
5,754,053
|
|
Revisions
|
|
|
(1,614,155
|
)
|
|
|
308,004
|
|
|
|
(1,562,821
|
)
|
Extensions and discoveries
|
|
|
7,411,947
|
|
|
|
5,333,628
|
|
|
|
8,300,885
|
|
Purchases of reserves in place
|
|
|
1,411,387
|
|
|
|
898,849
|
|
|
|
1,561,195
|
|
Production
|
|
|
(498,213
|
)
|
|
|
(27,556
|
)
|
|
|
(502,806
|
)
|
Proved reserves, end of year
|
|
|
12,108,508
|
|
|
|
8,651,992
|
|
|
|
13,550,506
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves
|
|
|
4,206,422
|
|
|
|
3,046,787
|
|
|
|
4,714,219
|
|
Proved undeveloped reserves
|
|
|
7,902,086
|
|
|
|
5,605,205
|
|
|
|
8,836,287
|
|
Total proved reserves
|
|
|
12,108,508
|
|
|
|
8,651,992
|
|
|
|
13,550,506
|
|
As a result of participating in
19 new wells, the Company converted 956,515 barrels of oil and 340,926 mcf of gas from proved undeveloped reserves to proved developed
reserves during the year ended December 31, 2013. The Company incurred $19,826,083 of capitalized expenditures to drill these wells.
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
|
(Barrels)
|
|
|
(Mcf)
|
|
|
(BOE)
|
|
For the year ended December 31, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves, beginning of year
|
|
|
1,511,238
|
|
|
|
416,900
|
|
|
|
1,580,721
|
|
Revisions
|
|
|
(687,083
|
)
|
|
|
(190,856
|
)
|
|
|
(718,893
|
)
|
Extensions and discoveries
|
|
|
4,428,960
|
|
|
|
1,774,297
|
|
|
|
4,724,676
|
|
Purchases of reserves in place
|
|
|
478,596
|
|
|
|
247,780
|
|
|
|
519,893
|
|
Sale of reserves in place
|
|
|
(199,924
|
)
|
|
|
(106,748
|
)
|
|
|
(217,715
|
)
|
Production
|
|
|
(134,245
|
)
|
|
|
(2,306
|
)
|
|
|
(134,629
|
)
|
Proved reserves, end of year
|
|
|
5,397,542
|
|
|
|
2,139,067
|
|
|
|
5,754,053
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves
|
|
|
2,387,283
|
|
|
|
1,074,362
|
|
|
|
2,566,343
|
|
Proved undeveloped reserves
|
|
|
3,010,259
|
|
|
|
1,064,705
|
|
|
|
3,187,710
|
|
Total proved reserves
|
|
|
5,397,542
|
|
|
|
2,139,067
|
|
|
|
5,754,053
|
|
As a result of participating in
15 new wells, the Company converted 351,883 barrels of oil and 195,092 mcf of gas from proved undeveloped reserves to proved developed
reserves during the year ended December 31, 2012. The Company incurred $2,897,436 of capitalized expenditures to drill these wells.
Standardized Measure, Including Year-to-Year Changes
Therein, of Discounted Future Net Cash Flows
For purposes of the following disclosures, estimates
were made of quantities of proved reserves and the periods during which they are expected to be produced. Estimated future cash
flows were computed by applying a 12-month average of oil prices, except in those instances where future oil or natural gas sales
are covered by physical contract terms providing for higher or lower prices, to the Company’s share of estimated annual future
production from proved oil and gas reserves, net of royalties. Future development and production costs were computed by applying
year-end costs to be incurred in producing and further developing the proved reserves. Future income tax expenses were computed
by applying, generally, year-end statutory tax rates (adjusted for permanent differences, tax credits, allowances and foreign income
repatriation considerations) to the estimated net future pre-tax cash flows. The discount was computed by application of a 10 %
discount factor. The calculations assumed the continuation of existing economic, operating and contractual conditions at December
31, 2013 and 2012, respectively.
American Eagle Energy Corporation
Notes to the Consolidated Financial
Statements
As of December 31, 2013 and
2012 and
For Each of the Two Years in
the Period Ended December 31, 2013
Standardized Measure of Discounted Future Net Cash
Flows
|
|
At December 31,
|
|
|
|
2013
|
|
|
2012
|
|
Future cash flows
|
|
$
|
1,141,907,375
|
|
|
$
|
448,623,295
|
|
Future costs:
|
|
|
|
|
|
|
|
|
Production costs
|
|
|
(307,092,719
|
)
|
|
|
(99,410,979
|
)
|
Development costs
|
|
|
(177,750,094
|
)
|
|
|
(50,693,286
|
)
|
Income taxes
|
|
|
(184,362,116
|
)
|
|
|
(104,826,989
|
)
|
Future net cash flows
|
|
|
472,702,446
|
|
|
|
193,692,041
|
|
Ten percent discount factor
|
|
|
(250,648,070
|
)
|
|
|
(116,784,091
|
)
|
Standardized measure of discounted future net cash flows
|
|
$
|
222,054,376
|
|
|
$
|
76,907,950
|
|
The following table summarizes the changes in the
Company’s standardized measure of discounted future net cash flows for the years ended December 31, 2013 and 2012:
|
|
At December 31,
|
|
|
|
2013
|
|
|
2012
|
|
Extensions and discoveries
|
|
$
|
167,599,587
|
|
|
$
|
84,275,965
|
|
Net changes in sales prices and production costs
|
|
|
1,000,967
|
|
|
|
(2,939,472
|
)
|
Oil and gas sales, net of production costs
|
|
|
(31,529,851
|
)
|
|
|
(7,513,775
|
)
|
Change in estimated future development costs
|
|
|
(5,658,987
|
)
|
|
|
12,376,364
|
|
Revision of quantity estimates
|
|
|
(34,499,036
|
)
|
|
|
(22,267,585
|
)
|
Purchases of mineral interests
|
|
|
35,496,098
|
|
|
|
12,776,983
|
|
Previously estimated development costs incurred in the current period
|
|
|
14,256,379
|
|
|
|
2,897,436
|
|
Changes in production rates, timing and other
|
|
|
21,691,900
|
|
|
|
1,947,497
|
|
Changes in income taxes
|
|
|
(35,913,703
|
)
|
|
|
(33,864,445
|
)
|
Accretion of discount
|
|
|
12,703,072
|
|
|
|
3,993,945
|
|
Net increase
|
|
|
145,146,426
|
|
|
|
51,682,913
|
|
Standardized measure of discounted future cash flows:
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
76,907,950
|
|
|
|
25,225,037
|
|
End of year
|
|
$
|
222,054,376
|
|
|
$
|
76,907,950
|
|
Assumed prices used to calculate future cash flows
|
|
At December 31,
|
|
|
|
2013
|
|
|
2012
|
|
Oil price per barrel
|
|
$
|
90.63
|
|
|
$
|
81.78
|
|
Gas price per mcf
|
|
$
|
5.15
|
|
|
$
|
3.38
|
|