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
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.
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
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.
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
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.
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.
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.
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.
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.