SYNERGY RESOURCES CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited; in thousands, except share data)
|
|
|
|
|
|
|
|
|
ASSETS
|
June 30, 2016
|
|
December 31, 2015
|
Current assets:
|
|
|
|
Cash and cash equivalents
|
$
|
78,634
|
|
|
$
|
66,499
|
|
Accounts receivable:
|
|
|
|
Oil and gas sales
|
11,715
|
|
|
12,527
|
|
Trade
|
13,178
|
|
|
12,156
|
|
Commodity derivative assets
|
1,456
|
|
|
6,572
|
|
Escrow deposit
|
18,214
|
|
|
—
|
|
Other current assets
|
876
|
|
|
1,944
|
|
Total current assets
|
124,073
|
|
|
99,698
|
|
|
|
|
|
Property and equipment:
|
|
|
|
Oil and gas properties, full cost method:
|
|
|
|
Unproved properties, not subject to depletion
|
434,483
|
|
|
98,945
|
|
Proved properties, net of accumulated depletion
|
384,350
|
|
|
422,778
|
|
Oil and gas properties, net
|
818,833
|
|
|
521,723
|
|
Other property and equipment, net
|
5,456
|
|
|
5,124
|
|
Total property and equipment, net
|
824,289
|
|
|
526,847
|
|
|
|
|
|
Commodity derivative assets
|
355
|
|
|
2,996
|
|
Goodwill
|
40,711
|
|
|
40,711
|
|
Other assets
|
2,328
|
|
|
2,364
|
|
|
|
|
|
Total assets
|
$
|
991,756
|
|
|
$
|
672,616
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS' EQUITY
|
|
|
|
Current liabilities:
|
|
|
|
Accounts payable and accrued expenses
|
$
|
24,435
|
|
|
$
|
36,573
|
|
Revenue payable
|
12,671
|
|
|
13,603
|
|
Production taxes payable
|
16,387
|
|
|
24,530
|
|
Asset retirement obligations
|
695
|
|
|
—
|
|
Total current liabilities
|
54,188
|
|
|
74,706
|
|
|
|
|
|
Revolving credit facility
|
—
|
|
|
78,000
|
|
Notes payable, net of issuance costs
|
75,860
|
|
|
—
|
|
Commodity derivative liabilities
|
168
|
|
|
—
|
|
Asset retirement obligations
|
11,699
|
|
|
13,400
|
|
Total liabilities
|
141,915
|
|
|
166,106
|
|
|
|
|
|
Commitments and contingencies (See Note 16)
|
|
|
|
|
|
|
|
|
|
Shareholders' equity:
|
|
|
|
Preferred stock - $0.01 par value, 10,000,000 shares authorized:
no shares issued and outstanding
|
—
|
|
|
—
|
|
Common stock - $0.001 par value, 300,000,000 shares authorized:
200,486,623 an
d 110,033,601 shares issued and outstanding, respectively
|
200
|
|
|
110
|
|
Additional paid-in capital
|
1,144,161
|
|
|
595,671
|
|
Retained deficit
|
(294,520
|
)
|
|
(89,271
|
)
|
Total shareholders' equity
|
849,841
|
|
|
506,510
|
|
|
|
|
|
Total liabilities and shareholders' equity
|
$
|
991,756
|
|
|
$
|
672,616
|
|
The accompanying notes are an integral part of these condensed consolidated financial statements
SYNERGY RESOURCES CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited; in thousands, except share and per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
Oil and gas revenues
|
$
|
23,947
|
|
|
$
|
28,286
|
|
|
$
|
42,220
|
|
|
$
|
47,224
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
Lease operating expenses
|
6,845
|
|
|
3,745
|
|
|
11,144
|
|
|
7,866
|
|
Production taxes
|
2,137
|
|
|
2,579
|
|
|
3,970
|
|
|
4,386
|
|
Depreciation, depletion, and accretion
|
11,274
|
|
|
15,737
|
|
|
23,366
|
|
|
29,814
|
|
Full cost ceiling impairment
|
144,149
|
|
|
3,000
|
|
|
189,770
|
|
|
3,000
|
|
Transportation commitment charge
|
232
|
|
|
—
|
|
|
300
|
|
|
—
|
|
General and administrative
|
7,520
|
|
|
6,242
|
|
|
14,963
|
|
|
10,323
|
|
Total expenses
|
172,157
|
|
|
31,303
|
|
|
243,513
|
|
|
55,389
|
|
|
|
|
|
|
|
|
|
Operating loss
|
(148,210
|
)
|
|
(3,017
|
)
|
|
(201,293
|
)
|
|
(8,165
|
)
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
Commodity derivatives loss
|
(5,704
|
)
|
|
(4,383
|
)
|
|
(4,024
|
)
|
|
(922
|
)
|
Interest expense, net
|
—
|
|
|
(121
|
)
|
|
—
|
|
|
(160
|
)
|
Interest income
|
167
|
|
|
30
|
|
|
169
|
|
|
54
|
|
Total other expense
|
(5,537
|
)
|
|
(4,474
|
)
|
|
(3,855
|
)
|
|
(1,028
|
)
|
|
|
|
|
|
|
|
|
Loss before income taxes
|
(153,747
|
)
|
|
(7,491
|
)
|
|
(205,148
|
)
|
|
(9,193
|
)
|
|
|
|
|
|
|
|
|
Income tax expense (benefit)
|
101
|
|
|
(2,903
|
)
|
|
101
|
|
|
(3,612
|
)
|
Net loss
|
$
|
(153,848
|
)
|
|
$
|
(4,588
|
)
|
|
$
|
(205,249
|
)
|
|
$
|
(5,581
|
)
|
|
|
|
|
|
|
|
|
Net loss per common share:
|
|
|
|
|
|
|
|
Basic
|
$
|
(0.89
|
)
|
|
$
|
(0.04
|
)
|
|
$
|
(1.40
|
)
|
|
$
|
(0.06
|
)
|
Diluted
|
$
|
(0.89
|
)
|
|
$
|
(0.04
|
)
|
|
$
|
(1.40
|
)
|
|
$
|
(0.06
|
)
|
|
|
|
|
|
|
|
|
Weighted-average shares outstanding:
|
|
|
|
|
|
|
|
Basic
|
172,013,551
|
|
|
104,562,662
|
|
|
146,703,144
|
|
|
100,922,206
|
|
Diluted
|
172,013,551
|
|
|
104,562,662
|
|
|
146,703,144
|
|
|
100,922,206
|
|
The accompanying notes are an integral part of these condensed consolidated financial statements
SYNERGY RESOURCES CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited; in thousands)
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
2016
|
|
2015
|
Cash flows from operating activities:
|
|
|
|
Net loss
|
$
|
(205,249
|
)
|
|
$
|
(5,581
|
)
|
Adjustments to reconcile net loss to net cash provided by operating activities:
|
|
|
|
Depletion, depreciation, and accretion
|
23,366
|
|
|
29,814
|
|
Full cost ceiling impairment
|
189,770
|
|
|
3,000
|
|
Provision for deferred taxes
|
—
|
|
|
(3,612
|
)
|
Stock-based compensation
|
4,911
|
|
|
5,839
|
|
Mark-to-market of commodity derivative contracts:
|
|
|
|
Total loss on commodity derivatives contracts
|
4,024
|
|
|
922
|
|
Cash settlements on commodity derivative contracts
|
4,651
|
|
|
18,165
|
|
Cash premiums paid for commodity derivative contracts
|
—
|
|
|
(4,117
|
)
|
Changes in operating assets and liabilities:
|
|
|
|
Accounts receivable
|
|
|
|
Oil and gas sales
|
812
|
|
|
13,490
|
|
Trade
|
(1,771
|
)
|
|
13,468
|
|
Accounts payable and accrued expenses
|
859
|
|
|
(524
|
)
|
Revenue payable
|
(1,305
|
)
|
|
(7,973
|
)
|
Production taxes payable
|
(8,498
|
)
|
|
(1,703
|
)
|
Other
|
665
|
|
|
(595
|
)
|
Net cash provided by operating activities
|
12,235
|
|
|
60,593
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
Acquisition of oil and gas properties
|
(496,261
|
)
|
|
—
|
|
Well costs and other capital expenditures
|
(49,851
|
)
|
|
(96,293
|
)
|
Earnest money deposit
|
(18,212
|
)
|
|
—
|
|
Proceeds from sales of oil and gas properties
|
23,496
|
|
|
6,239
|
|
Net cash used in investing activities
|
(540,828
|
)
|
|
(90,054
|
)
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
Proceeds from sale of stock
|
565,398
|
|
|
200,100
|
|
Offering costs
|
(21,898
|
)
|
|
(9,255
|
)
|
Shares withheld for payment of employee payroll taxes
|
(408
|
)
|
|
(543
|
)
|
Proceeds from revolving credit facility
|
55,000
|
|
|
—
|
|
Principal repayments on revolving credit facility
|
(133,000
|
)
|
|
(59,000
|
)
|
Financing fees on revolving credit facility
|
(196
|
)
|
|
—
|
|
Proceeds from issuance of notes payable
|
80,000
|
|
|
—
|
|
Financing fees on issuance of notes payable
|
(4,168
|
)
|
|
—
|
|
Net cash provided by financing activities
|
540,728
|
|
|
131,302
|
|
|
|
|
|
Net increase in cash and equivalents
|
12,135
|
|
|
101,841
|
|
|
|
|
|
Cash and equivalents at beginning of period
|
66,499
|
|
|
39,570
|
|
|
|
|
|
Cash and equivalents at end of period
|
$
|
78,634
|
|
|
$
|
141,411
|
|
Supplemental Cash Flow Information (See Note
17
)
The accompanying notes are an integral part of these condensed consolidated financial statements
SYNERGY RESOURCES CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
|
|
1
.
|
Organization and Summary of Significant Accounting Policies
|
Organization
: Synergy Resources Corporation (the "Company," "we," "us," or "our") is engaged in oil and gas acquisition, exploration, development, and production activities, primarily in the Denver-Julesburg Basin ("D-J Basin") of Colorado. The Company’s common stock is listed and traded on the NYSE MKT under the symbol "SYRG."
Basis of Presentation:
The Company operates in
one
business segment, and all of its operations are located in the United States of America.
At the directive of the Securities and Exchange Commission ("SEC") to use "plain English" in public filings, the Company will use such terms as "we," "our," or the "Company" in place of Synergy Resources Corporation. When such terms are used in this manner throughout this document, they are in reference only to the corporation, Synergy Resources Corporation, and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees.
The Company prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States of America ("US GAAP").
Change of Year End:
On February 25, 2016, the Company's board of directors approved a change in fiscal year end from August 31 to December 31 effective with the fiscal year ending December 31, 2016. The prior year figures presented herein have been recast to conform to the new fiscal year end.
Interim Financial Information:
The unaudited condensed consolidated interim financial statements included herein have been prepared by the Company pursuant to the rules and regulations of the SEC as promulgated in Rule 10-01 of Regulation S-X. The condensed consolidated balance sheet as of
December 31, 2015
was derived from the Company's Transition Report on Form 10-K for the four months ended
December 31, 2015
as filed with the SEC on April 22, 2016. Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with US GAAP have been condensed or omitted pursuant to such SEC rules and regulations. The Company believes that the disclosures included are adequate to make the information presented not misleading and recommends that these condensed financial statements be read in conjunction with the audited financial statements and notes thereto for the four months ended
December 31, 2015
.
In our opinion, the unaudited condensed consolidated financial statements contained herein reflect all adjustments, consisting solely of normal recurring items, which are necessary for the fair presentation of the Company's financial position, results of operations, and cash flows on a basis consistent with that of its prior audited financial statements. However, the results of operations for interim periods may not be indicative of results to be expected for the full fiscal year. We have evaluated subsequent events through the date of this filing.
Major Customers:
The Company sells production to a limited number of customers. Customers representing 10% or more of our oil and gas revenue for each of the periods presented are shown in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
Major Customers
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Company A
|
|
42%
|
|
*
|
|
43%
|
|
*
|
Company B
|
|
17%
|
|
*
|
|
21%
|
|
*
|
Company C
|
|
14%
|
|
*
|
|
10%
|
|
*
|
Company D
|
|
12%
|
|
*
|
|
11%
|
|
*
|
Company E
|
|
10%
|
|
21%
|
|
*
|
|
18%
|
Company F
|
|
*
|
|
58%
|
|
*
|
|
52%
|
* less than
10%
Based on the current demand for oil and natural gas, the availability of other buyers, and the Company having the option to sell to other buyers if conditions warrant, the Company believes that its oil and gas production can be sold in the market in the event that it is not sold to the Company’s existing customers.
Accounts receivable consist primarily of receivables from oil and gas sales and amounts due from other working interest owners who are liable for their proportionate share of well costs. The Company typically has the right to withhold future revenue disbursements to recover outstanding joint interest billings on outstanding receivables from joint interest owners.
Customers with balances greater than
10%
of total receivable balances as of each of the periods presented are shown in the following table:
|
|
|
|
|
|
|
|
As of
|
|
As of
|
Major Customers
|
|
June 30, 2016
|
|
December 31, 2015
|
Company A
|
|
27%
|
|
*
|
Company B
|
|
*
|
|
13%
|
Company C
|
|
*
|
|
13%
|
Company D
|
|
*
|
|
13%
|
* less than
10%
The Company operates exclusively within the United States of America and, except for cash and short-term investments, all of the Company’s assets are utilized in, and all of its revenues are derived from, the oil and gas industry.
Goodwill:
The Company’s goodwill represents the excess of the purchase price over the fair value of net identifiable assets acquired in a business combination. Goodwill is not amortized and is tested for impairment annually or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. When evaluating goodwill for impairment, the Company may first perform an assessment of qualitative factors to determine if the fair value of the reporting unit is more-likely-than-not greater than its carrying amount. If, based on the review of the qualitative factors, the Company determines it is not more-likely-than-not that the fair value of a reporting unit is less than its carrying value, the required two-step impairment test can be bypassed. If the Company does not perform a qualitative assessment or if the fair value of the reporting unit is not more-likely-than-not greater than its carrying value, the Company must perform the first step of the two-step impairment test and calculate the estimated fair value of the reporting unit. If the carrying value of the reporting unit exceeds the estimated fair value, there is an indication that impairment may exist, and the second step must be performed to measure the amount of impairment loss. The amount of impairment for goodwill is measured as the amount by which the carrying amount of the goodwill exceeds the implied fair value of the goodwill.
As a result of declining oil prices, the Company performed an interim goodwill test as of March 31, 2016 which did not result in an impairment. The Company utilized a market approach in estimating the fair value of the reporting unit. Th
e primary assumptions used in the Company's impairment evaluations are based on the best available market information at the time and reflect significant management judgments. Changes in these assumptions or future economic conditions could impact the Company's conclusion regarding an impairment of goodwill and potentially result in a non-cash impairment loss in a future period.
Recently Issued Accounting Pronouncements:
We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new accounting pronouncements on us.
In March 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-09, "Improvements to Employee Share-Based Payment Accounting" ("ASU 2016-09"), which intends to improve the accounting for share-based payment transactions. The ASU changes several aspects of the accounting for share-based payment award transactions, including: (1) Accounting and Cash Flow Classification for Excess Tax Benefits and Deficiencies, (2) Forfeitures, and (3) Tax Withholding Requirements and Cash Flow Classification. ASU 2016-09 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the impact of the adoption on our consolidated financial statements.
In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" ("ASU 2016-02"), which establishes a comprehensive new lease standard designed to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous US GAAP. ASU 2016-02 is effective for public business for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the impact of the adoption of this standard on our consolidated financial statements.
In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)" ("ASU 2014-09"), which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current revenue recognition guidance. ASU 2014-09 allows for the use of either the full or modified retrospective transition method, and the standard will be effective for annual reporting periods beginning after December 15, 2017 including interim periods within that period, with early adoption permitted for annual reporting periods beginning after December 15, 2016. We are currently evaluating which transition approach to use and the impact of the adoption of this standard on our consolidated financial statements.
There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations, or cash flows.
|
|
2
.
|
Property and Equipment
|
The capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
As of
|
|
As of
|
|
June 30, 2016
|
|
December 31, 2015
|
Oil and gas properties, full cost method:
|
|
|
|
Costs of unproved properties, not subject to depletion:
|
|
|
|
Lease acquisition and other costs
|
$
|
415,736
|
|
|
$
|
89,122
|
|
Wells in progress
|
18,747
|
|
|
9,823
|
|
Subtotal, unproved properties
|
434,483
|
|
|
98,945
|
|
|
|
|
|
Costs of proved properties:
|
|
|
|
Producing and non-producing
|
868,958
|
|
|
691,659
|
|
Wells in progress
|
11,683
|
|
|
11,487
|
|
Less, accumulated depletion and full cost ceiling impairments
|
(496,291
|
)
|
|
(280,368
|
)
|
Subtotal, proved properties, net
|
384,350
|
|
|
422,778
|
|
|
|
|
|
Costs of other property and equipment:
|
|
|
|
Land
|
4,478
|
|
|
4,478
|
|
Other property and equipment
|
1,563
|
|
|
1,270
|
|
Less, accumulated depreciation
|
(585
|
)
|
|
(624
|
)
|
Subtotal, other property and equipment, net
|
5,456
|
|
|
5,124
|
|
|
|
|
|
Total property and equipment, net
|
$
|
824,289
|
|
|
$
|
526,847
|
|
The Company periodically reviews its oil and gas properties to determine if the carrying value of such assets exceeds estimated fair value. For proved producing and non-producing properties, the Company performs a ceiling test each quarter to determine whether there has been an impairment to its capitalized costs. Under the ceiling test, the value of the Company’s reserves is calculated using the average of the published spot prices for WTI oil (per barrel) as of the first day of each of the previous twelve months, as well as the average of the published spot prices for Henry Hub (per MMBtu) as of the first day of each of the previous twelve months, each adjusted by lease or field for quality, transportation fees, and regional price differentials. As a result of these periodic reviews, the Company concluded that its net capitalized costs of oil and natural gas properties exceeded the ceiling amount, resulting in the recognition of ceiling test impairments totaling
$189.8 million
during the
six months ended June 30, 2016
. During the
six months ended June 30, 2015
, the Company's ceiling tests resulted in total impairments of
$3.0 million
.
The Company also reviews the fair value of its unproved properties. The reviews as of
June 30, 2016
indicated that the carrying values of such assets exceeded the estimated fair values. Therefore,
$17.7 million
of costs were moved into the full cost pool and subject to the aforementioned ceiling test.
No
such impairments were recognized during the
six months ended June 30, 2015
.
Capitalized Overhead:
A portion of the Company’s overhead expenses are directly attributable to acquisition, exploration, and development activities. Under the full cost method of accounting, these expenses, in the amounts shown in the table below, were capitalized in the full cost pool (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Capitalized overhead
|
$
|
2,339
|
|
|
$
|
466
|
|
|
$
|
2,988
|
|
|
$
|
1,051
|
|
|
|
3
.
|
Acquisitions and Divestitures
|
Acquisitions
The Company acquired certain oil and gas and other assets that affect the comparability between the
six months ended June 30, 2016
and
2015
, as described below.
On February 4, 2016, the Company completed the acquisition of certain assets for a total purchase price of
$10.0 million
. The acquisition comprised solely of undeveloped oil and gas leasehold interests in the D-J Basin of Colorado. The purpose of the transaction was to provide additional mineral acres upon which the Company could drill wells and produce hydrocarbons. The purchase price has been allocated as
$8.6 million
to proved oil and gas properties and
$1.4 million
to unproved oil and gas properties on a preliminary basis and includes significant use of estimates.
GC Acquisition
On
May 2, 2016
, we entered into a purchase and sale agreement ("GC Agreement") with a large publicly-traded company, pursuant to which we have agreed to acquire approximately
72,000
gross (
33,100
net) acres in an area referred to as the Greeley-Crescent project in the Wattenberg Field for
$505 million
(the "GC Acquisition").
Estimated net daily production from the properties to be acquired was approximately
2,400
barrels of oil equivalent ("BOE") at the time of entering into the GC Agreement.
The acquisition will have
two
separate closing dates. On
June 14, 2016
, the Company closed on the portion of the assets comprised of the undeveloped oil and gas leasehold interests and non-operated production. The effective date of this part of the transaction was April 1, 2016. The second closing will cover the operated producing properties and is expected to be completed in the fourth quarter of 2016 or first quarter of 2017. For this part of the transaction, the effective date will be April 1, 2016 for the horizontal wells to be acquired, and the first day of the calendar month in which the closing for such properties occurs for the vertical wells. The second closing is subject to certain closing conditions, including the receipt of regulatory approval. Accordingly, the second closing of the transaction may not close in the expected time frame or at all.
The first closing on
June 14, 2016
was for a total purchase price of
$487.3 million
, net of customary closing adjustments. The purchase price was composed of
$486.3 million
in cash plus the assumption of certain liabilities.
The first closing encompassed approximately
33,100
net acres of oil and gas leasehold interests and related assets in the D-J Basin of Colorado and net production of approximately
800
BOE per day ("BOED") at the time of
entering into the GC Agreement.
The purpose of the transaction was to provide additional mineral acres upon which the Company could drill wells and produce hydrocarbons.
The first closing was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of
June 14, 2016
. Transaction costs of
$0.1 million
r
elated to the acquisition were expensed as incurred. The following allocation of the purchase price is preliminary and includes significant use of estimates. The fair values of the assets acquired and liabilities assumed are preliminary and are subject to revision as the Company continues to evaluate the fair value of this acquisition. Accordingly, the allocation will change as additional information becomes available and is assessed, and the impact of such changes may be material. The following table summarizes the preliminary purchase price and preliminary estimated fair values of assets acquired and liabilities assumed (in thousands):
|
|
|
|
|
Preliminary Purchase Price
|
June 14, 2016
|
Consideration given:
|
|
Cash
|
$
|
486,261
|
|
Net liabilities assumed, including asset retirement obligations
|
1,063
|
|
Total consideration given
|
$
|
487,324
|
|
|
|
Preliminary Allocation of Purchase Price
|
|
Proved oil and gas properties
(1)
|
$
|
133,813
|
|
Unproved oil and gas properties
|
353,511
|
|
Total fair value of assets acquired
|
$
|
487,324
|
|
(1)
Proved oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rat
e of
11.5%
, a
nd assumptions regarding the timing and amount of future development and operating costs.
The results of operations of the acquired assets from the
June 14, 2016
closing date through
June 30, 2016
, representing approximately
$0.6 million
of revenue and
$0.5 million
of operating income, have been included in the Company's condensed consolidated statements of operations for the
three and six months ended
June 30, 2016
.
The following table presents the unaudited pro forma combined results of operations for the
three and six months ended
June 30, 2016
as if the first closing had occurred on January 1, 2015. The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through cash, additional depreciation expense, costs directly attributable to the acquisition, and operating costs incurred as a result of the assets acquired. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
(in thousands)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Oil and gas revenues
|
$
|
25,589
|
|
|
$
|
32,562
|
|
|
$
|
45,706
|
|
|
$
|
56,620
|
|
Net loss
|
$
|
(155,380
|
)
|
|
$
|
(5,518
|
)
|
|
$
|
(208,538
|
)
|
|
$
|
(7,657
|
)
|
|
|
|
|
|
|
|
|
Net loss per common share
|
|
|
|
|
|
|
|
Basic
|
$
|
(0.63
|
)
|
|
$
|
(0.03
|
)
|
|
$
|
(0.94
|
)
|
|
$
|
(0.04
|
)
|
Diluted
|
$
|
(0.63
|
)
|
|
$
|
(0.03
|
)
|
|
$
|
(0.94
|
)
|
|
$
|
(0.04
|
)
|
KPK Acquisition
On
October 20, 2015
, the Company closed the acquisition of certain assets ("KPK Acquisition") from a private company for a total purchase price of
$85.2 million
, net of customary closing adjustments. The purchase price was composed of
$35.0 million
in cash and
$49.8 million
in restricted common stock plus the assumption of certain liabilities.
The KPK Acquisition encompassed approximately
4,300
net acres of oil and gas leasehold interests and related assets in the D-J Basin of Colorado and net production of approximately
1,200
BOED at the time of purchase. The purpose of the transaction was to provide additional mineral acres upon which the Company could drill wells and produce hydrocarbons.
The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of
October 20, 2015
. Transaction costs related to the acquisition were expensed as incurred. The following allocation of the purchase price is preliminary and includes significant use of estimates. The fair values of the assets acquired and liabilities assumed are preliminary and are subject to revision as the Company continues to evaluate the fair value of this acquisition. Accordingly, the allocation will change as additional information becomes available and is assessed, and the impact of such changes may be material. The following table summarizes the preliminary purchase price and preliminary estimated fair values of assets acquired and liabilities assumed (in thousands):
|
|
|
|
|
Preliminary Purchase Price
|
October 20, 2015
|
Consideration given:
|
|
Cash
|
$
|
35,045
|
|
Synergy Resources Corp. common stock
(1)
|
49,840
|
|
Net liabilities assumed, including asset retirement obligations
|
284
|
|
Total consideration given
|
$
|
85,169
|
|
|
|
Preliminary Allocation of Purchase Price
|
|
Proved oil and gas properties
(2)
|
$
|
46,333
|
|
Unproved oil and gas properties
|
37,766
|
|
Other assets, including accounts receivable
|
1,070
|
|
Total fair value of assets acquired
|
$
|
85,169
|
|
(1)
The fair value of the consideration attributed to the common stock under ASC 805 was based on the Company's closing stock price on the measurement date of
October 20, 2015
(
4,418,413
shares at
$11.28
per share).
(2)
Proved oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rate of
12%
, and assumptions regarding the timing and amount of future development and operating costs.
The results of operations of the acquired assets, representing approxim
ately
$1.2 million
and
$2.3 million
of revenue and
$1.1 million
and
$1.7 million
of
operating income, have been included in the Company's condensed consolidated statements of operations for the
three and six months ended
June 30, 2016
, respectively.
The following table presents the unaudited pro forma combined results of operations for the
three and six months ended
June 30, 2015
as if the transaction had occurred on January 1, 2015. The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through the issuance of common stock and cash, additional depreciation expense, costs directly attributable to the acquisition, and operating costs incurred as a result of the assets acquired. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.
|
|
|
|
|
|
|
|
|
(in thousands)
|
Three Months Ended June 30, 2015
|
|
Six Months Ended June 30, 2015
|
Oil and gas revenues
|
$
|
31,708
|
|
|
$
|
54,891
|
|
Net loss
|
$
|
(4,343
|
)
|
|
$
|
(5,366
|
)
|
|
|
|
|
Net loss per common share
|
|
|
|
Basic
|
$
|
(0.04
|
)
|
|
$
|
(0.05
|
)
|
Diluted
|
$
|
(0.04
|
)
|
|
$
|
(0.05
|
)
|
Divestitures
During the second quarter of 2016, the Company closed on
two
transactions involving the divestiture of approximately
3,700
net undeveloped acres and
107
vertical wells primarily in Adams County, Colorado for total consideration of
$27.1 million
, subject to customary purchase price adjustments. We received
$23.5 million
in cash and transferred liabilities of
$0.5 million
to the buyers. The buyer of the undeveloped acreage has placed
$3.1 million
in cash in escrow pending the final resolution of its due diligence procedures. The divested assets had associated production of approximately
200
BOED at the time of sale. The vertical well transaction closed in April 2016, and the undeveloped acreage transaction closed in June 2016.
|
|
4
.
|
Depletion, depreciation, and accretion ("DD&A")
|
Depletion, depreciation, and accretion consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Depletion of oil and gas properties
|
$
|
10,965
|
|
|
$
|
15,534
|
|
|
$
|
22,708
|
|
|
$
|
29,414
|
|
Depreciation and accretion
|
309
|
|
|
203
|
|
|
658
|
|
|
400
|
|
Total DD&A Expense
|
$
|
11,274
|
|
|
$
|
15,737
|
|
|
$
|
23,366
|
|
|
$
|
29,814
|
|
Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on a depletion rate, which is calculated by comparing production volumes for the quarter to estimated total reserves at the beginning of the quarter. For the
three and six months ended
June 30, 2016
, production of
1,010
MBOE and
2,057
MBOE, respectively, represented
1.0%
and
2.0%
of estimated total proved reserves, respectively. For the
three and six months ended
June 30, 2015
, production of
755
MBOE and
1,388
MBOE, respectively, represented
1.6%
and
2.9%
of estimated total proved reserves, respectively. DD&A expense was
$11.16
per BOE and
$20.84
per BOE for the
three months ended June 30, 2016
and
2015
, respectively. For the
six months ended June 30, 2016
and
2015
, DD&A expense was
$11.36
per BOE and
$21.48
per BOE, respectively.
|
|
5
.
|
Asset Retirement Obligations
|
The following table summarizes the changes in asset retirement obligations associated with the Company's oil and gas properties (in thousands).
|
|
|
|
|
Asset retirement obligations, December 31, 2015
|
$
|
13,400
|
|
Obligations incurred with development activities
|
366
|
|
Obligations assumed with acquisitions
|
1,692
|
|
Accretion expense
|
499
|
|
Obligations discharged with asset retirements and divestitures
|
(3,563
|
)
|
Revisions in previous estimates
|
—
|
|
Asset retirement obligations, June 30, 2016
|
$
|
12,394
|
|
Less, current portion
|
(695
|
)
|
Long-term portion
|
$
|
11,699
|
|
|
|
6
.
|
Revolving Credit Facility
|
The Company maintains a revolving credit facility ("Revolver") with a bank syndicate. The Revolver is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes, and to support letters of credit. As of
June 30, 2016
, the terms of the Revolver provide for up to
$500 million
in borrowings, subject to a borrowing base limitation, which was
$145 million
. As of
June 30, 2016
, there was no outstanding principal balance. The maturity date of the Revolver is
December 15, 2019
.
On January 28, 2016, the Revolver was amended in connection with the semi-annual redetermination. The borrowing base was reduced from
$163 million
to
$145 million
, and the Revolver was further amended to (i) delete the minimum interest rate floor, (ii) delete the minimum liquidity covenant, (iii) add a current ratio covenant of
1.0
to 1.0, and (iv) delete the minimum
hedging requirement. In January 2016, the Company reduced its outstanding borrowings under the Revolver from
$78 million
to
nil
.
Interest under the Revolver is payable monthly and accrues at a variable rate. For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin or the London Interbank Offered Rate ("LIBOR") plus a margin. The interest rate margin, as well as other bank fees, varies with utilization of the Revolver. The average annual interest rate for borrowings during the
six months ended June 30, 2016
was
2.63%
.
Certain of the Company’s assets, including substantially all of the producing wells and developed oil and gas leases, have been designated as collateral under the Revolver. The borrowing commitment is subject to scheduled redeterminations on a semi-annual basis. If certain events occur, or if the bank syndicate so elects, an unscheduled redetermination could be prepared. As of
June 30, 2016
, based on a borrowing base of
$145 million
and no outstanding principal balance, the unused borrowing base available for future borrowing totaled approximately
$145 million
. The next semi-annual redetermination is scheduled for November 2016.
The Revolver also contains covenants that, among other things, restrict the payment of dividends. Additionally, as of
June 30, 2016
, the Revolver required an overall commodity derivative position that covers a rolling
24
months of estimated future production with a maximum position of
85%
of hydrocarbon production as projected in the semi-annual reserve report.
Furthermore, the Revolver requires the Company to maintain compliance with certain financial and liquidity ratio covenants. Under the requirements, the Company, on a quarterly basis, must not (a) at any time permit its ratio of total funded debt as of such time to EBITDAX, as defined in the agreement, to be greater than or equal to
4.0
to 1.0; or (b) as of the last day o
f any fiscal quarter permit its current ratio, as defined in the agreement, to be less than
1.0
to 1.0. As of
June 30, 2016
, the most recent compliance date, the C
ompany was in compliance with these loan covenants and expects to remain in compliance throughout the next 12-month period.
On June 14, 2016, the Company issued
$80 million
aggregate principal amount of
9.00%
Senior Unsecured Notes ("Senior Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is June 13, 2021. Interest on the Notes accrues at
9.00%
and began accruing on June 14, 2016. Interest is payable on June 15 and December 15 of each year, beginning on December 15, 2016. The Senior Notes were issued pursuant to an indenture dated as of June 14, 2016 (the "Indenture") and are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the revolving credit facility. The net proceeds from the sale of the Senior Notes were
$75.8 million
after deductions of
$4.2 million
for expenses and underwriting discounts and commissions. The net proceeds were used to fund the GC Acquisition as discussed further in Note
3
.
At any time prior to December 14, 2018, the Company may redeem all or a part of the Senior Notes subject to the Make-Whole Price (as defined in the Indenture) and accrued and unpaid interest. On and after December 14, 2018, the Company may redeem all or a part of the Senior Notes at the redemption price at a specified percentage of the principal amount of the redeemed notes (
104.50%
for 2018,
102.25%
for 2019, and
100.0%
for 2020 and thereafter, during the twelve-month period beginning on December 14 of each applicable year), plus accrued and unpaid interest. Additionally, prior to December 14, 2018, the Company can, on one or more occasions, redeem up to
35%
of the principal amount of the Senior Notes with all or a portion of the net cash proceeds of one or more Equity Offerings (as defined in the Indenture) at a redemption price equal to
109.00%
of the principal amount of the redeemed notes, plus accrued and unpaid interest, subject to certain conditions.
The Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to, among other restrictions and limitations: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities. These covenants are subject to a number of exceptions and qualifications.
As of
June 30, 2016
, the most recent compliance date, the C
ompany was in compliance with these loan covenants and expects to remain in compliance throughout the next 12-month period.
|
|
8
.
|
Commodity Derivative Instruments
|
The Company has entered into commodity derivative instruments, as described below. Our commodity derivative instruments may include but are not limited to "collars," "swaps," and "put" positions. Our derivative strategy, including the volume amounts, whether we utilize oil and/or natural gas instruments, and the relevant commodity prices, is based in part on our view of expected future market conditions and our analysis of well-level economic return potential. In addition, our use of derivative contracts is subject to stipulations set forth in the Revolver.
A "put" option gives the owner the right, but not the obligation, to sell the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may, at times, purchase put options, which require us to pay premiums at the time we purchase the contracts. These premiums represent the fair value of the purchased put as of the date of purchase. Conversely, a "call" option gives the owner the right, but not the obligation, to purchase the underlying commodity at a specified price (strike price) within a specific time period.
Depending on market conditions, strike prices, and the value of the contracts, we may, at times, sell call options in conjunction with the purchase of put options to create "collars." We regularly utilize "no premium" (a.k.a. zero cost) collars where we receive the difference between the published index price and a floor price if the index price is below the floor. We pay the difference between the ceiling price and the index price if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the floor and the ceiling price.
Additionally, at times, we may enter into swaps. Swaps are derivative contracts which obligate two counterparties to effectively trade the underlying commodity at a set price over a specified term.
The Company may, from time to time, add incremental derivatives to cover additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.
The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with four counterparties and an exchange.
Two
of the counterparties are lenders in the Revolver. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.
The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as commodity derivative assets or liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from contract settlement of derivatives are recorded in the consolidated statements of operations. The Company’s cash flow is only impacted when the actual settlements under commodity derivative contracts result in making or receiving a payment to or from the counterparty. Actual cash settlements can occur at either the scheduled maturity date of the contract or at an earlier date if the contract is liquidated prior to its scheduled maturity. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows.
The Company’s commodity derivative contracts as of
June 30, 2016
are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlement Period
|
|
Derivative
Instrument
|
|
Average Volumes
(Bbls
per month)
|
|
Floor
Price
|
|
Ceiling
Price
|
Crude Oil - NYMEX WTI
|
|
|
|
|
|
|
|
|
Jul 1, 2016 - Dec 31, 2016
|
|
Purchased Put
|
|
25,000
|
|
|
$
|
50.00
|
|
|
—
|
|
Jul 1, 2016 - Dec 31, 2016
|
|
Purchased Put
|
|
10,000
|
|
|
$
|
45.00
|
|
|
—
|
|
Jul 1, 2016 - Dec 31, 2016
|
|
Collar
|
|
20,000
|
|
|
$
|
45.00
|
|
|
$
|
65.00
|
|
Aug 1, 2016 - Dec 31, 2016
|
|
Collar
|
|
30,600
|
|
|
$
|
40.00
|
|
|
$
|
60.00
|
|
|
|
|
|
|
|
|
|
|
Jan 1, 2017 - Apr 30, 2017
|
|
Purchased Put
|
|
20,000
|
|
|
$
|
50.00
|
|
|
—
|
|
May 1, 2017 - Aug 31, 2017
|
|
Purchased Put
|
|
20,000
|
|
|
$
|
55.00
|
|
|
—
|
|
Jan 1, 2017 - Dec 31, 2017
|
|
Collar
|
|
20,000
|
|
|
$
|
45.00
|
|
|
$
|
70.00
|
|
Jan 1, 2017 - Dec 31, 2017
|
|
Collar
|
|
30,417
|
|
|
$
|
40.00
|
|
|
$
|
60.00
|
|
|
|
|
|
|
|
|
|
|
Settlement Period
|
|
Derivative
Instrument
|
|
Average Volumes
(MMBtu
per month)
|
|
Floor
Price
|
|
Ceiling
Price
|
Natural Gas - NYMEX Henry Hub
|
|
|
|
|
|
|
|
|
Jul 1, 2016 - Aug 31, 2016
|
|
Collar
|
|
60,000
|
|
|
$
|
3.90
|
|
|
$
|
4.14
|
|
|
|
|
|
|
|
|
|
|
Natural Gas - CIG Rocky Mountain
|
|
|
|
|
|
|
|
|
Jul 1, 2016 - Dec 31, 2016
|
|
Collar
|
|
100,000
|
|
|
$
|
2.65
|
|
|
$
|
3.10
|
|
|
|
|
|
|
|
|
|
|
Jan 1, 2017 - Apr 30, 2017
|
|
Collar
|
|
100,000
|
|
|
$
|
2.80
|
|
|
$
|
3.95
|
|
May 1 2017 - Aug 31, 2017
|
|
Collar
|
|
110,000
|
|
|
$
|
2.50
|
|
|
$
|
3.06
|
|
Jan 1, 2017 - Dec 31, 2017
|
|
Collar
|
|
200,000
|
|
|
$
|
2.50
|
|
|
$
|
3.27
|
|
Subsequent to
June 30, 2016
, the Company added the following positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlement Period
|
|
Derivative
Instrument
|
|
Average Volumes
(MMBtu
per month)
|
|
Floor
Price
|
|
Ceiling
Price
|
Natural Gas - CIG Rocky Mountain
|
|
|
|
|
|
|
|
|
Jan 1, 2017 - Dec 31, 2017
|
|
Collar
|
|
100,000
|
|
|
$
|
2.60
|
|
|
$
|
3.20
|
|
Offsetting of Derivative Assets and Liabilities
As of
June 30, 2016
and
December 31, 2015
, all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of either party, for transactions that occur on the same date and in the same currency. The Company’s agreements also provide that, in the event of an early termination, each party has the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to offset these positions in its consolidated balance sheets.
The following table provides a reconciliation between the net assets and liabilities reflected on the accompanying consolidated balance sheets and the potential effect of master netting arrangements on the fair value of the Company’s derivative contracts (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of June 30, 2016
|
Underlying
|
|
Balance Sheet
Location
|
|
Gross Amounts of Recognized Assets and Liabilities
|
|
Gross Amounts Offset in the
Balance Sheet
|
|
Net Amounts of Assets and Liabilities Presented in the
Balance Sheet
|
Commodity derivative contracts
|
|
Current assets
|
|
$
|
2,825
|
|
|
$
|
(1,369
|
)
|
|
$
|
1,456
|
|
Commodity derivative contracts
|
|
Noncurrent assets
|
|
$
|
1,601
|
|
|
$
|
(1,246
|
)
|
|
$
|
355
|
|
Commodity derivative contracts
|
|
Current liabilities
|
|
$
|
1,369
|
|
|
$
|
(1,369
|
)
|
|
$
|
—
|
|
Commodity derivative contracts
|
|
Noncurrent liabilities
|
|
$
|
1,414
|
|
|
$
|
(1,246
|
)
|
|
$
|
168
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2015
|
Underlying
|
|
Balance Sheet
Location
|
|
Gross Amounts of Recognized Assets and Liabilities
|
|
Gross Amounts Offset in the
Balance Sheet
|
|
Net Amounts of Assets and Liabilities Presented in the
Balance Sheet
|
Commodity derivative contracts
|
|
Current assets
|
|
$
|
6,719
|
|
|
$
|
(147
|
)
|
|
$
|
6,572
|
|
Commodity derivative contracts
|
|
Noncurrent assets
|
|
$
|
3,354
|
|
|
$
|
(358
|
)
|
|
$
|
2,996
|
|
Commodity derivative contracts
|
|
Current liabilities
|
|
$
|
147
|
|
|
$
|
(147
|
)
|
|
$
|
—
|
|
Commodity derivative contracts
|
|
Noncurrent liabilities
|
|
$
|
358
|
|
|
$
|
(358
|
)
|
|
$
|
—
|
|
The amount of gain recognized in the consolidated statements of operations related to derivative financial instruments was as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Realized gain on commodity derivatives
|
$
|
436
|
|
|
$
|
3,775
|
|
|
$
|
2,881
|
|
|
$
|
17,317
|
|
Unrealized loss on commodity derivatives
|
(6,140
|
)
|
|
(8,158
|
)
|
|
(6,905
|
)
|
|
(18,239
|
)
|
Total loss
|
$
|
(5,704
|
)
|
|
$
|
(4,383
|
)
|
|
$
|
(4,024
|
)
|
|
$
|
(922
|
)
|
Realized gains include cash received from the monthly settlement of derivative contracts at their scheduled maturity date, the proceeds from early liquidation of in-the-money derivative contracts, and the previously incurred premiums attributable to settled commodity contracts. During the
six months ended June 30, 2015
, the Company liquidated oil derivatives with an average strike price of
$85.00
and covering
361,500
bbls of oil and received cash settlements of approximately
$11.3 million
. The following table summarizes derivative realized gains during the periods presented (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Monthly settlement
|
$
|
946
|
|
|
$
|
1,484
|
|
|
$
|
3,901
|
|
|
$
|
6,848
|
|
Previously incurred premiums attributable to settled commodity contracts
|
(510
|
)
|
|
(648
|
)
|
|
(1,020
|
)
|
|
(848
|
)
|
Early liquidation
|
—
|
|
|
2,939
|
|
|
—
|
|
|
11,317
|
|
Total realized gain
|
$
|
436
|
|
|
$
|
3,775
|
|
|
$
|
2,881
|
|
|
$
|
17,317
|
|
Credit Related Contingent Features
As of
June 30, 2016
,
two
of the
five
counterparties to the Company's derivative instruments were members of the Company’s credit facility syndicate. The Company’s obligations under the credit facility and its derivative contracts are secured by liens on substantially all of the Company’s producing oil and gas properties. The agreement with the third and fourth counterparties, which are not lenders under the credit facility, are unsecured and do not require the posting of collateral. The agreement with the fifth counterparty is subject to an inter-creditor agreement between the counterparty and the Company’s lenders under the credit facility.
|
|
9
.
|
Fair Value Measurements
|
ASC Topic 820,
Fair Value Measurements and Disclosure
, establishes a hierarchy for inputs used in measuring fair value for financial assets and liabilities that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:
|
|
•
|
Level 1: Quoted prices available in active markets for identical assets or liabilities;
|
|
|
•
|
Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; and
|
|
|
•
|
Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash or valuation models.
|
The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
The Company’s non-recurring fair value measurements include asset retirement obligations and purchase price allocations for the fair value of assets and liabilities acquired through business combinations.
The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using Level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit-adjusted risk-free rate, inflation rates, and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period, and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method. See Note
5
for additional information.
The acquisition of a group of assets in a business combination transaction requires fair value estimates for assets acquired and liabilities assumed. The fair value of assets and liabilities acquired through business combinations is calculated using a net discounted cash flow approach for the producing properties. The discounted cash flows are developed using the income approach and are based on management’s expectations for the future. Unobservable inputs include estimates of future oil and gas production from the Company’s reserve reports, commodity prices based on the NYMEX forward price curves as of the date of the estimate (adjusted for basis differentials), estimated operating and development costs, and a risk-adjusted discount rate (all of which are designated as Level 3 inputs within the fair value hierarchy). For unproved properties, fair value is determined using market comparables. For the asset retirement liability assumed, the fair value is determined using the same inputs as described in the paragraph above. See Note
3
for additional information.
The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of
June 30, 2016
and
December 31, 2015
by level within the fair value hierarchy (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at June 30, 2016
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Financial assets and liabilities:
|
|
|
|
|
|
|
|
Commodity derivative asset
|
$
|
—
|
|
|
$
|
1,811
|
|
|
$
|
—
|
|
|
$
|
1,811
|
|
Commodity derivative liability
|
$
|
—
|
|
|
$
|
168
|
|
|
$
|
—
|
|
|
$
|
168
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2015
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Financial assets and liabilities:
|
|
|
|
|
|
|
|
Commodity derivative asset
|
$
|
—
|
|
|
$
|
9,568
|
|
|
$
|
—
|
|
|
$
|
9,568
|
|
Commodity derivative liability
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Commodity Derivative Instruments
The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparties to its derivative contracts would default by failing to make any contractually required payments. The Company considers the counterparties to be of substantial credit quality and believes that they have the financial resources and willingness to meet their potential repayment obligations associated with the derivative transactions. At
June 30, 2016
, derivative instruments utilized by the Company consist of puts and collars. The crude oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are based on several factors, including public indices, the instruments themselves are primarily traded with third-party counterparties. As such, the Company has classified these instruments as Level 2.
Fair Value of Financial Instruments
The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above), notes payable, and credit facility borrowings. The carrying values of cash and cash equivalents, accounts receivable, and accounts payable are representative of their fair values due to their short-term maturities. Due to the variable interest rate paid on the credit facility borrowings, the carrying value is representative of its fair value.
The fair value of the notes payable is estimated to be
$78.4 million
at
June 30, 2016
. The Company determined the fair value of its notes payable at
June 30, 2016
by using observable market based information for debt instruments of similar amounts and duration. The Company has classified the notes as Level 2.
The components of interest expense are (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Revolving bank credit facility
|
$
|
13
|
|
|
$
|
910
|
|
|
$
|
154
|
|
|
$
|
1,731
|
|
Notes payable
|
320
|
|
|
—
|
|
|
320
|
|
|
—
|
|
Amortization of issuance costs
|
314
|
|
|
249
|
|
|
609
|
|
|
491
|
|
Less, interest capitalized
|
(647
|
)
|
|
(1,038
|
)
|
|
(1,083
|
)
|
|
(2,062
|
)
|
Interest expense, net
|
$
|
—
|
|
|
$
|
121
|
|
|
$
|
—
|
|
|
$
|
160
|
|
|
|
11
.
|
Shareholders’ Equity
|
The Company's classes of stock are summarized as follows:
|
|
|
|
|
|
|
|
|
|
As of
|
|
As of
|
|
June 30, 2016
|
|
December 31, 2015
|
Preferred stock, shares authorized
|
10,000,000
|
|
|
10,000,000
|
|
Preferred stock, par value
|
$
|
0.01
|
|
|
$
|
0.01
|
|
Preferred stock, shares issued and outstanding
|
nil
|
|
|
nil
|
|
Common stock, shares authorized
|
300,000,000
|
|
|
300,000,000
|
|
Common stock, par value
|
$
|
0.001
|
|
|
$
|
0.001
|
|
Common stock, shares issued and outstanding
|
200,486,623
|
|
|
110,033,601
|
|
Preferred stock may be issued in series with such rights and preferences as may be determined by the Board of Directors. Since inception, the Company has not issued any preferred shares.
Shares of the Company’s common stock were issued during the
six months ended June 30, 2016
as described further below.
Sales of common stock
In January 2016, the Company completed a public offering of its common stock in an underwritten public offering. The Company agreed to sell
14,000,000
shares of its common stock to the Underwriters at a price of
$5.545
per share. In addition, pursuant to the Underwriting Agreement, the Underwriters were granted an option, exercisable within
30
days, to purchase up to an additional
2,100,000
shares of common stock on the same terms and conditions. The option was exercised on January 26, 2016, bringing the total number of shares issued to
16,100,000
. Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were
$89.2 million
. Proceeds were used to repay amounts borrowed under the Revolver and general corporate purposes, which included continuing to develop our acreage position in the Wattenberg Field in Colorado and funding a portion of our 2016 capital expenditure program.
In April 2016, the Company completed a public offering of its common stock in an underwritten public offering. The Company agreed to sell
19,500,000
shares of its common stock to the Underwriters at a price of
$7.3535
per share. In addition, pursuant to the Underwriting Agreement, the Underwriters were granted an option, exercisable within
30
days, to purchase up to an additional
2,925,000
shares of common stock on the same terms and conditions. The option was exercised on April 12, 2016, bringing the total number of shares issued to
22,425,000
. Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $
164.8 million
. The Company used a portion of the proceeds of the offering to pay a portion of the purchase price of the GC Acquisition described in Note
3
.
In May 2016, the Company completed a public offering of its common stock in an underwritten public offering. The Company agreed to sell
45,000,000
shares of its common stock to the Underwriters at a price of
$5.597
per share. In addition, pursuant to the Underwriting Agreement, the Underwriters were granted an option, exercisable within
30
days, to purchase up to an additional
6,750,000
shares of common stock on the same terms and conditions. The option was exercised on June 6, 2016, bringing the total number of shares issued to
51,750,000
. Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were
$289.4 million
. The Company used a portion of the proceeds of the offering to pay a portion of the purchase price of the GC Acquisition described in Note
3
.
Basic earnings per share includes no dilution and is computed by dividing net income by the weighted-average number of shares outstanding during the period. Diluted earnings per share reflects the potential dilution of securities that could share in the earnings of the Company. The number of potential shares outstanding relating to stock options, performance stock units, and non-vested restricted stock units and stock bonus shares is computed using the treasury stock method. Potentially dilutive securities outstanding are not included in the calculation when such securities would have an anti-dilutive effect on earnings per share.
The following table sets forth the share calculation of diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Weighted-average shares outstanding - basic
|
172,013,551
|
|
|
104,562,662
|
|
|
146,703,144
|
|
|
100,922,206
|
|
Potentially dilutive common shares from:
|
|
|
|
|
|
|
|
Stock options
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Performance stock units
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Restricted stock units and stock bonus shares
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Weighted-average shares outstanding - diluted
|
172,013,551
|
|
|
104,562,662
|
|
|
146,703,144
|
|
|
100,922,206
|
|
The following potentially dilutive securities outstanding for the periods presented were not included in the respective earnings per share calculation above, as such securities had an anti-dilutive effect on earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Potentially dilutive common shares from:
|
|
|
|
|
|
|
|
Stock options
|
5,589,500
|
|
|
4,041,500
|
|
|
5,589,500
|
|
|
4,041,500
|
|
Performance stock units
1
|
478,510
|
|
|
—
|
|
|
478,510
|
|
|
—
|
|
Restricted stock units and stock bonus shares
|
1,069,890
|
|
|
—
|
|
|
1,069,890
|
|
|
—
|
|
Total
|
7,137,900
|
|
|
4,041,500
|
|
|
7,137,900
|
|
|
4,041,500
|
|
1
The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from
zero
to
two
, depending on the level of satisfaction of the vesting condition.
|
|
13
.
|
Stock-Based Compensation
|
In addition to cash compensation, the Company may compensate certain service providers, including employees, directors, consultants, and other advisors, with equity-based compensation in the form of stock options, restricted stock units, stock bonus shares, warrants, and other equity awards. The Company records its equity compensation by pro-rating the estimated grant date fair value of each grant over the period of time that the recipient is required to provide services to the Company (the "vesting phase"). The calculation of fair value is based, either directly or indirectly, on the quoted market value of the Company’s common stock. Indirect valuations are calculated using the Black-Scholes-Merton option pricing model or a Monte Carlo Model. For the periods presented, all stock-based compensation was classified either as a component within general and administrative expense in the Company's consolidated statements of operations, or, for that portion which is directly attributable to individuals performing acquisition, exploration, and development activities, was capitalized to the full cost pool.
The amount of stock-based compensation was as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Stock options
|
$
|
1,423
|
|
|
$
|
2,700
|
|
|
$
|
2,833
|
|
|
$
|
3,290
|
|
Performance stock units
|
338
|
|
|
—
|
|
|
338
|
|
|
—
|
|
Restricted stock units and stock bonus shares
|
1,106
|
|
|
1,535
|
|
|
2,318
|
|
|
2,549
|
|
Total stock-based compensation
|
$
|
2,867
|
|
|
$
|
4,235
|
|
|
$
|
5,489
|
|
|
$
|
5,839
|
|
Less: stock-based compensation capitalized
|
(475
|
)
|
|
(169
|
)
|
|
(578
|
)
|
|
(422
|
)
|
Total stock-based compensation expensed
|
$
|
2,392
|
|
|
$
|
4,066
|
|
|
$
|
4,911
|
|
|
$
|
5,417
|
|
Stock options
During the
three and six months ended
June 30, 2016
and
2015
, the Company granted the following stock options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Number of options to purchase common shares
|
105,000
|
|
|
1,842,500
|
|
|
594,500
|
|
|
2,032,500
|
|
Weighted-average exercise price
|
$
|
6.93
|
|
|
$
|
11.49
|
|
|
$
|
7.58
|
|
|
$
|
11.55
|
|
Term (in years)
|
10 years
|
|
|
10 years
|
|
|
10 years
|
|
|
10 years
|
|
Vesting Period (in years)
|
5 years
|
|
|
3 - 5 years
|
|
|
3 - 5 years
|
|
|
1 - 5 years
|
|
Fair Value (in thousands)
|
$
|
399
|
|
|
$
|
10,232
|
|
|
$
|
2,128
|
|
|
$
|
11,315
|
|
The assumptions used in valuing stock options granted during each of the periods presented were as follows:
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
2016
|
|
2015
|
Expected term
|
6.3 years
|
|
|
6.5 years
|
|
Expected volatility
|
55
|
%
|
|
47
|
%
|
Risk free rate
|
1.50 - 1.75%
|
|
|
1.35 - 1.86%
|
|
Expected dividend yield
|
—
|
%
|
|
—
|
%
|
The following table summarizes activity for stock options for the
six months ended June 30, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Shares
|
|
Weighted-Average Exercise Price
|
|
Weighted-Average Remaining Contractual Life
|
|
Aggregate Intrinsic Value (thousands)
|
Outstanding, December 31, 2015
|
5,056,000
|
|
|
$
|
9.71
|
|
|
8.7 years
|
|
$
|
4,351
|
|
Granted
|
594,500
|
|
|
7.58
|
|
|
|
|
|
Exercised
|
—
|
|
|
—
|
|
|
|
|
—
|
|
Expired
|
—
|
|
|
—
|
|
|
|
|
|
Forfeited
|
(61,000
|
)
|
|
9.71
|
|
|
|
|
|
Outstanding, June 30, 2016
|
5,589,500
|
|
|
$
|
9.48
|
|
|
8.3 years
|
|
$
|
2,274
|
|
Outstanding, Exercisable at June 30, 2016
|
1,982,950
|
|
|
$
|
8.16
|
|
|
7.3 years
|
|
$
|
1,715
|
|
Outstanding, Vested and expected to vest at June 30, 2016
|
5,505,318
|
|
|
$
|
9.45
|
|
|
8.3 years
|
|
$
|
2,274
|
|
The following table summarizes information about issued and outstanding stock options as of
June 30, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding Options
|
|
Exercisable Options
|
Range of Exercise Prices
|
|
Options
|
Weighted-Average Remaining Contractual Life
|
Weighted-Average Exercise Price per Share
|
|
Options
|
Weighted-Average Exercise Price per Share
|
|
|
|
|
|
|
|
|
Under $5.00
|
|
650,000
|
|
5.2 years
|
$
|
3.51
|
|
|
523,000
|
|
$
|
3.50
|
|
$5.00 - $6.99
|
|
645,000
|
|
7.4 years
|
6.31
|
|
|
430,000
|
|
6.51
|
|
$7.00 - $10.99
|
|
1,516,500
|
|
8.9 years
|
9.48
|
|
|
179,450
|
|
9.41
|
|
$11.00 - $13.46
|
|
2,778,000
|
|
8.9 years
|
11.61
|
|
|
850,500
|
|
11.59
|
|
Total
|
|
5,589,500
|
|
8.3 years
|
$
|
9.48
|
|
|
1,982,950
|
|
$
|
8.16
|
|
The estimated unrecognized compensation cost from stock options not vested as of
June 30, 2016
, which will be recognized ratably over the remaining vesting phase, is as follows:
|
|
|
|
|
Unrecognized compensation, net of estimated forfeitures (in thousands)
|
$
|
16,265
|
|
Remaining vesting phase
|
3.5 years
|
|
Restricted stock units and stock bonus awards
The Company grants restricted stock units and stock bonus awards to directors, eligible employees and officers as a part of its equity incentive plan. Restrictions and vesting periods for the awards are determined by the Compensation Committee of the Board of Directors and are set forth in the award agreements. Each restricted stock unit or stock bonus award represents one share of the Company’s common stock to be released from restrictions upon completion of the vesting period. The awards typically vest in equal increments over
three
to
five years
. Restricted stock units and stock bonus awards are valued at the closing price of the Company’s common stock on the grant date and are recognized over the vesting period of the award.
The following table summarizes activity for restricted stock units and stock bonus awards for the
six months ended June 30, 2016
:
|
|
|
|
|
|
|
|
|
Number of Shares
|
|
Weighted-Average Grant-Date Fair Value
|
Not vested, December 31, 2015
|
915,867
|
|
|
$
|
10.63
|
|
Granted
|
438,778
|
|
|
7.70
|
|
Vested
|
(239,018
|
)
|
|
10.32
|
|
Forfeited
|
(45,737
|
)
|
|
8.33
|
|
Not vested, June 30, 2016
|
1,069,890
|
|
|
$
|
9.60
|
|
The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of
June 30, 2016
, which will be recognized ratably over the remaining vesting phase, is as follows:
|
|
|
|
|
Unrecognized compensation, net of estimated forfeitures (in thousands)
|
$
|
8,653
|
|
Remaining vesting phase
|
3.1 years
|
|
Performance-vested stock units
In March 2016, the Company granted performance-vested stock units ("PSUs") to certain executives under its long term incentive plan. The number of shares of the Company’s common stock that may be issued to settle PSUs ranges from
zero
to
two
times the number of PSUs awarded. The shares issued for PSUs are determined based on the Company’s performance over a
three
-year measurement period and vest in their entirety at the end of the measurement period. The PSUs will be settled in shares of the Company’s common stock following the end of the
three
-year performance cycle. Any PSUs that have not vested at the end of the applicable measurement period are forfeited. The vesting criterion for the PSUs is based on a comparison of the Company’s total shareholder return ("TSR") for the measurement period compared with the TSRs of a group of peer companies for the same measurement period. As the vesting criterion is linked to the Company's share price, it is considered a market condition for purposes of calculating the grant-date fair value of the awards.
The fair value of the PSUs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Monte Carlo Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurement period, as well as the volatilities for each of the Company’s peers.
The assumptions used in valuing the PSUs granted were as follows:
|
|
|
|
|
Six Months Ended June 30, 2016
|
Weighted average expected term
|
2.7 years
|
|
Weighted average expected volatility
|
58
|
%
|
Weighted average risk free rate
|
0.87
|
%
|
During the
six months ended June 30, 2016
, the Company granted
490,713
PSUs to certain executives. The fair value of the PSUs granted during the
six months ended June 30, 2016
was
$4.0 million
. As of
June 30, 2016
, unrecognized compensation expense for PSUs was
$3.5 million
and will be amortized through 2018. A summary of the status and activity of PSUs is presented in the following table:
|
|
|
|
|
|
|
|
|
Number of Units
1
|
|
Weighted-Average Grant-Date Fair Value
|
Not vested, December 31, 2015
|
—
|
|
|
$
|
—
|
|
Granted
|
490,713
|
|
|
8.10
|
|
Vested
|
—
|
|
|
—
|
|
Forfeited
|
(12,203
|
)
|
|
8.22
|
|
Not vested, June 30, 2016
|
478,510
|
|
|
$
|
8.09
|
|
1
The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to
two
, depending on the level of satisfaction of the vesting condition.
We evaluate and update our estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of our actual earnings compared to annual projections, our effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. A tax expense or benefit unrelated to the current year income or loss is recognized in its entirety as a discrete item of tax in the period identified. The quarterly income tax provision is generally comprised of tax expense on income or benefit on loss at the most recent estimated annual effective tax rate, adjusted for the effect of discrete items.
The effective tax rate for the
six months ended June 30, 2016
was
0%
compared to
39%
for the
six months ended June 30, 2015
. The effective tax rate for the
six months ended June 30, 2016
is based upon a full year forecasted tax provision and differs from the statutory rate, primarily due to the recognition of a valuation allowance recorded against deferred tax assets. The effective tax rate for the
six months ended June 30, 2015
differs from the statutory rate primarily due to state taxes and nondeductible officers' compensation, partially offset by percentage depletion. There were no significant discrete items recorded during the
three and six months ended
June 30, 2016
and
2015
.
As of
June 30, 2016
, we had no liability for unrecognized tax benefits. The Company believes that there are no new items, nor changes in facts or judgments that should impact the Company’s tax position. Given the substantial NOL carryforwards at both the federal and state levels, it is anticipated that any changes resulting from a tax examination would simply adjust the carryforwards, and would not result in significant interest expense or penalties. Most of the Company's tax returns filed since August 31, 2011 are still subject to examination by tax authorities. As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions, and we are not currently under any state income tax examinations.
No significant uncertain tax positions were identified as of any date on or before
June 30, 2016
. The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of
June 30, 2016
, the Company has not recognized any interest or penalties related to uncertain tax benefits.
Each period, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Based upon our cumulative losses through
June 30, 2016
, we have provided a full valuation allowance reducing the net realizable benefits.
|
|
15
.
|
Related Party Transactions
|
Consulting agreements:
Subsequent to their tenure as co-CEOs, which ended on December 31, 2015, the Company entered into consulting agreements with Ed Holloway and William Scaff, Jr. through May 31, 2016. During this period, each was paid
$70,000
per month, or
$140,000
and
$350,000
for the
three and six months ended
June 30, 2016
, respectively.
|
|
16
.
|
Other Commitments and Contingencies
|
Volume Commitments
During 2014, the Company entered into crude oil transportation agreements with
three
counterparties and a volume commitment to a third party refiner. Deliveries under
two
of the transportation agreements commenced during 2015. Deliveries under the third transportation agreement are not expected to commence until late in 2016. The third party refinery volume commitment expired on December 31, 2015.
Pursuant to these agreements, we must deliver specific amounts of crude oil either from our own production or from oil we acquire from third parties. If we are unable to fulfill all of our contractual obligations, we may be required to pay penalties or damages pursuant to these agreements. As of
June 30, 2016
, our commitments over the next five years are as follows:
|
|
|
|
|
Year ending December 31,
|
(in MBbls/year)
|
Remainder of 2016
|
|
1,438
|
|
2017
|
|
4,072
|
|
2018
|
|
4,072
|
|
2019
|
|
4,072
|
|
2020
|
|
3,517
|
|
Thereafter
|
|
1,520
|
|
Total
|
|
18,691
|
|
During the
six months ended June 30, 2016
, the Company incurred transportation deficiency charges of
$300,000
as we were unable to meet all of the obligations during the quarter. As of
June 30, 2016
, our current production exceeds our delivery obligations.
Office and yard leases
The Company leases its Platteville offices and other facilities from HS Land & Cattle, LLC ("HSLC"). HSLC is controlled by Ed Holloway and William Scaff, Jr., members of the Company's board of directors through June 22, 2016. The most recent lease, dated June 30, 2014, is currently on a month-to-month basis and requires payments of $15,000 per month. In July 2016, the Company entered into a new office lease in Greeley with an unrelated party with the intention of canceling the Platteville office lease once the move is completed. The Greeley office lease will require monthly payments of approximately
$7,500
and will terminate in October 2026. In addition, the Company maintains its principal offices in Denver. The Denver office lease requires monthly payments of approximately
$30,000
and terminates in October 2016. The Company is currently exploring its options for a new lease in Denver.
Litigation
From time to time, the Company is a party to various commercial and regulatory claims, pending or threatened legal action, and other proceedings that arise in the ordinary course of business. It is the opinion of management that none of the current matters of contention are reasonably likely to have a material adverse impact on our business, financial position, results of operations, or cash flows.
On June 1, 2015, the Company filed a complaint in the District Court of Weld County, Colorado, against Briller, Inc., R.W.L. Enterprises and Robert W. Loveless (together, the "Defendants") arising from a dispute concerning the validity of certain leases covering properties in Weld County. On June 23, 2015, the Defendants removed the case to the Federal District Court of Colorado and filed an answer and counterclaims against the Company and two officers of the Company. The officers have since been dismissed from the case, and the Court has ruled that the Defendant's lease is valid. The essence of the Defendants’ counterclaims are that the Company unlawfully drilled wells through properties leased by the Defendants causing physical damage
and economic damages measured by the value of hydrocarbons under the Defendant's lease. To date, no hydrocarbons have been produced from these wells. Although the Company believes Defendants’ counterclaims are without merit, it is not possible at this time to predict the outcome of this matter.
Environmental
Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable, and the costs can be reasonably estimated. As of
June 30, 2016
, we had accrued environmental liabilities in the amount of
$0.9 million
, included in accounts payable and accrued expenses on the condensed consolidated balance sheet. We are not aware of any environmental claims existing as of
June 30, 2016
which have not been provided for or would otherwise have a material impact on our consolidated financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown past non-compliance with environmental laws or unknown historic releases will not be discovered on our properties.
In addition, in July 2016, we were informed by the Colorado Department of Public Health and Environment's Air Quality Control Commission's Air Pollution Control Division ("CDPHE") that it expects to expand its inspection of the Company's facilities in connection with a Compliance Advisory previously issued by the CDPHE and subsequent inspections conducted by the CDPHE. The Compliance Advisory alleged issues at five Company facilities regarding leakages of volatile organic compounds from storage tanks, all of which were promptly addressed.
We understand that many other operators in the D-J basin are subject to similar investigations and Compliance Advisories, and we have no reason to believe that we have greater potential liability in this regard than other operators with similar numbers of facilities.
We are working with the CDPHE to respond to any continuing concerns, but have not yet been informed of additional facilities to be inspected or additional issues that have been identified. We cannot predict the outcome of this matter.
|
|
17
.
|
Supplemental Schedule of Information to the Condensed Consolidated Statements of Cash Flows
|
The following table supplements the cash flow information presented in the condensed consolidated financial statements for the periods presented (in thousands):
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
Supplemental cash flow information:
|
2016
|
|
2015
|
Interest paid
|
$
|
159
|
|
|
$
|
1,802
|
|
Income taxes paid
|
101
|
|
|
—
|
|
|
|
|
|
Non-cash investing and financing activities:
|
|
|
|
Accrued well costs as of period end
|
$
|
18,349
|
|
|
$
|
40,019
|
|
Assets acquired in exchange for common stock
|
—
|
|
|
9,840
|
|
Asset retirement obligations incurred with development activities
|
366
|
|
|
424
|
|
Asset retirement obligations assumed with acquisitions
|
1,692
|
|
|
—
|
|
|
|
ITEM
2
.
|
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
Cautionary Statement Concerning Forward-Looking Statements
This report contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management and information currently available to management. The use of words such as "believes," "expects," "anticipates," "intends," "plans," "estimates," "should," "likely," or similar expressions indicate forward-looking statements. Forward-looking statements included in this report include statements relating to future capital expenditures and projects, the adequacy and nature of future sources of financing, possible future impairment charges, midstream capacity issues, future differentials, future production relative to volume commitments, and the closing and effect of proposed transactions.
The identification in this report of factors that may affect our future performance and the accuracy of forward-looking statements is meant to be illustrative and by no means exhaustive. All forward-looking statements should be evaluated with the understanding of their inherent uncertainty.
See "
Risk Factors"
in this report and in Item 1A of our Transition Report on Form 10-K for the four months ended December 31, 2015 filed with the SEC on April 22, 2016, for a discussion of risk factors that affect our business, financial condition, and results of operations. These forward-looking statements include, among others, the following:
|
|
•
|
extended or further decline in oil and natural gas prices;
|
|
|
•
|
operating hazards that adversely affect our ability to conduct business;
|
|
|
•
|
uncertainties in the estimates of proved reserves;
|
|
|
•
|
the effect of seasonal weather conditions and wildlife restrictions on our operations;
|
|
|
•
|
our ability to fund, develop, produce, and acquire additional oil and natural gas reserves that are economically recoverable;
|
|
|
•
|
our ability to obtain adequate financing;
|
|
|
•
|
the availability and capacity of gathering systems and pipelines for our production;
|
|
|
•
|
our ability to complete the second closing of the Greeley-Crescent acquisition ("GC Acquisition") discussed in "Significant Developments" and integrate the acquired properties, and the risks associated with liabilities assumed or other problems relating to that acquisition;
|
|
|
•
|
our ability to successfully identify, execute, or effectively integrate future acquisitions;
|
|
|
•
|
the effect of federal, state, and local laws and regulations;
|
|
|
•
|
the effects of, including cost to comply with, new environmental legislation or regulatory initiatives, including those related to hydraulic fracturing;
|
|
|
•
|
the effects of local moratoria or bans on our business, including the ballot initiatives discussed in the "Risk Factors" section of this report;
|
|
|
•
|
the amount of our indebtedness and ability to maintain compliance with debt covenants;
|
|
|
•
|
the geographic concentration of our principal properties; and
|
|
|
•
|
the availability of water for use in our operations.
|
The following discussion and analysis was prepared to supplement information contained in the accompanying unaudited condensed consolidated financial statements and is intended to explain certain items regarding the Company's financial condition as of
June 30, 2016
, and its results of operations for the
three and six months ended
June 30, 2016
and
2015
. It should be read in conjunction with the accompanying unaudited condensed consolidated financial statements and related notes thereto contained in this report as well as the audited financial statements included in the Transition Report on Form 10-K for the four months ended
December 31, 2015
filed with the SEC on April 22, 2016.
Overview
Synergy Resources Corporation is a growth-oriented independent oil and natural gas company engaged in the acquisition, development, and production of crude oil and natural gas in and around the D-J Basin, which we believe to be one of the premier, liquids-rich oil and gas resource plays in the United States. The D-J Basin generally extends from the Denver metropolitan area throughout northeast Colorado into Wyoming, Nebraska, and Kansas. It contains hydrocarbon-bearing deposits in several formations, including the Niobrara, Codell, Greenhorn, Shannon, Sussex, J-Sand and D-Sand. The area has produced oil and gas for over fifty years and benefits from established infrastructure including midstream and refining capacity, long reserve life, and multiple service providers.
Our drilling and completion activities are focused in the Wattenberg Field, an area that covers the western flank of the D-J Basin, predominantly in Weld County, Colorado. Currently, we are focused on the horizontal development of the Codell and Niobrara formations, which are characterized by relatively high liquids content. We operate the majority of the horizontal wells we have working interests in, and we strive to maintain a high net revenue interest in all of our operations.
Substantially all of our producing wells are either in or adjacent to the Wattenberg Field. We operate approximately
66%
of our proved producing reserves, and our planned fiscal
2016
drilling and completion expenditures are focused on the Wattenberg Field. This gives us both operational focus and development flexibility to maximize returns on our leasehold position.
Market Conditions
Market prices for our products significantly impact our revenues, net income, and cash flow. The market prices for crude oil and natural gas are inherently volatile. To provide historical perspective, the following table presents the average annual NYMEX prices for oil and natural gas for each of the last five fiscal years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Four Months Ended December 31,
|
|
Year Ended August 31,
|
|
2015
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
Average NYMEX prices
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
$
|
42.82
|
|
|
$
|
60.65
|
|
|
$
|
100.39
|
|
|
$
|
94.58
|
|
|
$
|
94.88
|
|
|
$
|
91.79
|
|
Natural gas (per Mcf)
|
$
|
2.26
|
|
|
$
|
3.12
|
|
|
$
|
4.38
|
|
|
$
|
3.55
|
|
|
$
|
2.82
|
|
|
$
|
4.12
|
|
For the periods presented in this report, the following table presents the Reference Price (derived from average NYMEX prices weighted to reflect monthly sales volumes) as well as the differential between the Reference Price and the wellhead prices realized by us.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Oil (NYMEX WTI)
|
|
|
|
|
|
|
|
Average NYMEX Price
|
$
|
45.59
|
|
|
$
|
57.94
|
|
|
$
|
39.39
|
|
|
$
|
53.28
|
|
Realized Price
|
$
|
35.06
|
|
|
$
|
50.47
|
|
|
$
|
29.37
|
|
|
$
|
44.75
|
|
Differential
|
$
|
(10.53
|
)
|
|
$
|
(7.47
|
)
|
|
$
|
(10.02
|
)
|
|
$
|
(8.53
|
)
|
|
|
|
|
|
|
|
|
Gas (NYMEX Henry Hub)
|
|
|
|
|
|
|
|
Average NYMEX Price
|
$
|
2.15
|
|
|
$
|
2.70
|
|
|
$
|
2.07
|
|
|
$
|
2.73
|
|
Realized Price
|
$
|
2.04
|
|
|
$
|
2.72
|
|
|
$
|
1.93
|
|
|
$
|
3.02
|
|
Differential
|
$
|
(0.11
|
)
|
|
$
|
0.02
|
|
|
$
|
(0.14
|
)
|
|
$
|
0.29
|
|
Market conditions in the Wattenberg Field require us to sell oil at prices less than the prices posted by the NYMEX. The negative differential between the prices actually received by us at the wellhead and the published indices reflects deductions imposed upon us by the purchasers for location and quality adjustments. We continue to negotiate with crude oil purchasers to obtain better differentials on any barrels above our pipeline commitments. With regard to the sale of natural gas and liquids, we have historically been able to sell production at prices greater than the prices posted for dry gas, primarily because prices that we receive include payment for a percentage of the value attributable to the natural gas liquids produced with the gas.
Price fluctuations can impact many aspects of our operations. For additional discussion concerning the potential impacts from declining commodity prices, please see "Drilling and Completion Operations," "Liquidity and Capital Resources - Oil and Gas Commodity Contracts," and "Trends and Outlook."
Core Operations
The following
table p
rovides details about our ownership interests with respect to vertical and horizontal producing wells as of
June 30, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vertical Wells
|
Operated Wells
|
|
Non-Operated Wells
|
|
Totals
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
233
|
|
|
200
|
|
|
164
|
|
|
46
|
|
|
397
|
|
|
246
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Horizontal Wells
|
Operated Wells
|
|
Non-Operated Wells
|
|
Totals
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
96
|
|
|
91
|
|
|
127
|
|
|
19
|
|
|
223
|
|
|
110
|
|
In addition to the producing wells summarized in the preceding table, as of
June 30, 2016
, we were th
e operator of
20
gross (
18
net) wells in progress, which excludes 8 gross (6 net) wells on the Evans pad for which we have recently set surface casings.
Production
For the three months ended
June 30, 2016
, our average daily production increased to
11,098
BOED as compared to
8,299
BOED for the three months ended
June 30, 2015
. During the first
six
months of
2016
, our average net daily production was
11,304
BOED. By comparison, during the
six months ended June 30, 2015
, our average production rate was
7,668
BOED. As of
June 30, 2016
, approximatel
y
95%
of
our daily production was from horizontal wells.
Strategy
Our primary objective is to enhance shareholder value by increasing our net asset value, net reserves and cash flow through development, exploitation, exploration, and acquisitions of oil and gas properties. With current economic conditions, we intend to follow a balanced risk strategy by allocating capital expenditures to lower risk development and exploitation activities. Key elements of our business strategy include the following:
|
|
•
|
Concentrate on our existing core area in and around the D-J Basin, where we have significant operating experience.
All of our current wells and our undeveloped acreage is located either in or adjacent to the Wattenberg Field. Focusing our operations in this area leverages our management, technical and operational experience in the basin.
|
|
|
•
|
Develop and exploit existing oil and natural gas properties.
Since inception, our principal growth strategy has been to develop and exploit our properties to add reserves. In the Wattenberg Field, we target three benches of the Niobrara formation as well as the Codell formation for horizontal drilling and production. We believe horizontal drilling is the most efficient way to recover the potential hydrocarbons and consider the Wattenberg Field to be relatively low-risk because information gained from the large number of existing wells can be applied to potential future wells. There is enough similarity between wells in the Wattenberg Field that the exploitation process is generally repeatable.
|
|
|
•
|
Improve hydrocarbon recovery through increased well density.
We utilize the best available industry practices in our effort to determine the optimal recovery area for each well. When we began our operated horizontal well development program in the Wattenberg Field, we assumed spacing of 16 wells per 640 acre section. With increased experience and industry knowledge, we are now testing up to 24 horizontal wells per section.
|
|
|
•
|
Complete selective acquisitions.
We seek to acquire developed and undeveloped oil and gas properties, primarily in the core Wattenberg Field. We generally seek acquisitions that will provide us with opportunities for reserve additions and increased cash flow through production enhancement and additional development and exploratory prospect generation.
|
|
|
•
|
Retain control over the operation of a substantial portion of our production.
As operator of a majority of our wells and undeveloped acreage, we control the timing and selection of new wells to be drilled or existing wells to be re-completed. This allows us to modify our capital spending as our financial resources and underlying lease terms allow and market conditions permit.
|
|
|
•
|
Maintain financial flexibility while focusing on operational cost control.
We strive to be a cost-efficient operator and to maintain a relatively low utilization of debt, which enhances our financial flexibility. Our high degree of operational control, as well as our focus on operating efficiencies and short return on investment cycle times, is central to our operating strategy.
|
|
|
•
|
Use the latest technology to maximize returns.
Our primary focus is drilling wells that have 7,000' to 10,000' of lateral as opposed to the 4,000' laterals that were initially drilled in the Wattenberg Field. Increasing the number of wells drilled within a given drilling section, drilling longer laterals, and applying technical advances in drilling and completion designs is leading to enhanced productivity. Production results from various well designs are analyzed, and the conclusions from each analysis are factored into future well designs that take into account spacing between hydraulic fracturing stages, potential communication between wellbores, lateral length, timing and economics.
|
Significant Developments
Acquisition and Divestiture Activity
On May 2, 2016, the Company entered into an agreement to purchase approximately
72,000
gross (
33,100
net) acres located in an area known as the Greeley-Crescent project in Weld County Colorado, primarily in and around the city of Greeley, for
$505 million
. The Company has identified over 900 gross drilling locations on the acquired lands using an initial assumption of horizontal development with 20-24 wells per drilling unit. Estimated net daily production from the properties to be acquired was approximately
2,400
BOE
at the time of entering into the GC Agreement
. The acquisition will have two separate closing dates. On
June 14, 2016
, the Company closed on the portion of the assets comprised of the undeveloped lands and non-operated production. The effective date of this part of the transaction was April 1, 2016, and the purchase price was
$487.3 million
, comprised of
$486.3 million
in cash and the assumption of certain liabilities. The second closing will cover the operated producing properties and is expected to be completed in the fourth quarter of 2016 or first quarter of 2017. For this part of the transaction, the effective date will be April 1, 2016 for the horizontal wells to be acquired and the first day of the calendar month in which the closing for such properties occurs for the vertical wells. The second closing is subject to certain closing conditions, including the receipt of a regulatory approval. Accordingly, the second closing of the transaction may not close in the expected time frame or at all.
In April 2016, the Company agreed to divest approximately
3,700
net undeveloped acres and 107 vertical wells primarily in Adams County, Colorado for total consideration of approximately
$27.1 million
in cash, subject to customary purchase price adjustments. We have received $23.5 million in cash and transferred liabilities of $0.5 million to the buyers. The buyer of the undeveloped acreage has placed $3.1 million in cash in escrow pending the final resolution of its due diligence procedures. The divested assets had associated production of approximately 200 BOED. The vertical well transaction closed in April 2016, and the undeveloped acreage transaction closed in June 2016.
Financing and Other
Equity offerings
On January 27, 2016, the Company closed on the sale of
16,100,000
shares of common stock pursuant to an underwriting agreement with Credit Suisse Securities (USA) LLC, acting severally on behalf of itself and the other underwriters. The price to the Company was
$5.545
per share and net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were
$89.2 million
. Proceeds were used to repay amounts borrowed under the Revolver and for general corporate purposes, which included continuing to develop our acreage position in the Wattenberg Field in Colorado and funding a portion of our 2016 capital expenditure program.
On April 14, 2016, the Company closed on the sale of an additional
22,425,000
shares of common stock pursuant to an underwriting agreement with the same underwriters. The price to the Company was
$7.3535
per share and net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were
$164.8 million
. The proceeds of this offering were used for general corporate purposes, including to fund the GC Acquisition.
In May and June 2016, the Company closed on the sale of an additional
51,750,000
shares of common stock pursuant to an underwriting agreement with the same underwriters. The price to the Company was
$5.597
per share and net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were
$289.4 million
. The proceeds of this offering were used for general corporate purposes, including to fund the GC Acquisition.
Revolving Credit Facility
We continue to maintain a borrowing arrangement with our bank syndicate to provide us with liquidity, which could be used to develop oil and gas properties, acquire new oil and gas properties, and for working capital and other general corporate purposes. As of
June 30, 2016
, this revolving credit facility (sometimes referred to as the "Revolver") provides for maximum borrowings of
$500 million
, subject to adjustments based upon a borrowing base calculation, which is re-determined semi-annually using updated reserve reports. The Revolver is collateralized by certain of our assets, including producing properties, and bears a variable interest rate on borrowings, with the effective rate varying with utilization. The Revolver expires on
December 15, 2019
.
On January 28, 2016, the Revolver was amended in connection with the semi-annual borrowing base redetermination. The borrowing base was reduced from
$163 million
to
$145 million
, and the Revolver was further amended to (i) delete the minimum interest rate floor, (ii) delete the minimum liquidity covenant, (iii) add a current ratio covenant of 1.0 to 1.0, and (iv) delete the minimum hedging requirement. As of
June 30, 2016
, there were no outstanding borrowings under the Revolver, and
the entire
$145 million
borrowing base was available to us for future borrowings. See further discussion in Note
6
to our condensed consolidated financial statements.
On May 3, 2016, the Revolver was further amended to, among other things, permit the issuance of senior unsecured notes, subject to certain conditions. Pursuant to the amendment, if the aggregate amount of senior unsecured notes issued from time to time exceeds $100 million, then the borrowing base will automatically be reduced by an amount equal to 25% of the stated principal amount of the senior unsecured notes in excess of $100 million.
Senior Notes
On June 14, 2016, the Company issued $80 million aggregate principal amount of 9.00% Senior Unsecured Notes ("Senior Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is June 13, 2021. Interest on the Notes accrues at 9.00% and began accruing on June 14, 2016. Interest is payable on June 15 and December 15 of each year, beginning on December 15, 2016. The Senior Notes were issued pursuant to an indenture dated as of June 14, 2016 (the "Indenture") and are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the revolving credit facility. The net proceeds from the sale of the Senior Notes were $75.8 million after deductions of $4.2 million for expenses and underwriting discounts and commissions. The net proceeds were used to fund the GC Acquisition. The Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to, among other restrictions and limitations: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities. These covenants are subject to a number of exceptions and qualifications.
Impairment of full cost pool
Every quarter, we perform a ceiling test as prescribed by SEC regulations for entities following the full cost method of accounting. This test determines a limit on the book value of oil and gas properties using a formula to estimate future net cash flows from oil and gas reserves. This formula is dependent on several factors and assumes future oil and natural gas prices to be equal to an unweighted arithmetic average of oil and natural gas prices derived from each of the 12 months prior to the reporting period. During the
six months ended June 30, 2016
, these calculations indicated that the ceiling amount had declined, largely as a result of the decline in oil and natural gas prices, such that the ceiling was less than the net book value of oil and gas properties. As a result, we recorded ceiling test impairments totaling
$189.8 million
for the
six months ended June 30, 2016
. This full cost ceiling impairment is recognized as a charge to earnings and may not be reversed in future periods, even if oil and natural gas prices subsequently increase. Declining commodity prices, other adverse market conditions, acquisitions, or divestitures could result in further ceiling test write-downs in the future.
Drilling and Completion Operations
Our drilling and completion schedule has a material impact on our production forecast and a corresponding impact on our expected future cash flows. As commodity prices have fallen, we have been able to reduce per-well drilling and completion costs. We believe that at current drilling and completion cost levels and with currently prevailing commodity prices, we can achieve reasonable well-level rates of return when drilling mid-length or long laterals. Should commodity prices weaken further our operational flexibility will allow us to adjust our drilling and completion schedule, if prudent. If management believes the well-level internal rate of return will be at or below our weighted-average cost of capital, we may choose to delay completions and/or forego drilling altogether.
During the
six months ended June 30, 2016
, we completed the drilling of 10 horizontal wells on the Vista pad and 11 of 14 horizontal wells on the Fagerberg pad with the drilling of the remaining 3 horizontal wells being completed shortly after quarter end. Upon completion of the Fagerberg pad, the rig will be moved to the Evans pad, where we have begun to set the surface casings. As of
June 30, 2016
, there are
20
gr
oss horizontal wells in various stages of completion
, which excludes 8 gross horizontal wells on the Evans pad for which we have recently set surface casings
. For 2016 as a whole, we expect to drill 55 gross (52 net) horizontal wells of mostly mid-length and long laterals targeting the Codell and Niobrara zones.
Other Operations
We continue to be opportunistic with respect to acquisition efforts. In an effort to extend the length of laterals in our wells, we continue to enter into land and working interest swaps to increase our overall leasehold interest.
Trends and Outlook
Oil traded at
$37.13
per Bbl on
December 31, 2015
, but increased approximately
30%
through
June 30, 2016
to
$48.27
. Natural gas traded at
$2.34
per Mcf on
December 31, 2015
, but increased approximately
25%
through
June 30, 2016
to
$2.92
. Although prices have risen in the last three
months, prices continue to remain significantly lower than their 2014 levels, which were near $100/bbl, and early 2015 levels, which were near $55/bbl. These lower oil and gas prices (i) will reduce our cash flow which, in turn, will reduce the funds available for exploring and replacing oil and gas reserves, (ii) will potentially reduce our current Revolver borrowing base capacity and increase the difficulty of obtaining equity and debt financing and worsen the terms on which such financing may be obtained, (iii) will reduce the number of oil and gas prospects which have reasonable economic returns, (iv) may cause us to allow leases to expire based upon the value of potential oil and gas reserves in relation to the costs of exploration, (v) may result in marginally productive oil and gas wells being abandoned as non-commercial, and (vi) may cause a ceiling test impairment. However, price declines reduce the competition for oil and gas properties and correspondingly reduce the prices paid for leases and prospects.
Other factors that will most significantly affect our results of operations include (i) activities on properties that we operate, (ii) the marketability of our production, (iii) our ability to satisfy our financial and transportation obligations, (iv) completion of acquisitions of additional properties and reserves, and (v) competition from larger companies. Our revenues will also be significantly impacted by our ability to maintain or increase oil or gas production through exploration and development activities.
Horizontal well development in the Wattenberg Field is enabling operators to utilize higher density drilling within designated spacing units. When we began our operated horizontal well development program in the Wattenberg Field, we allowed for up to 16 wells per 640 acre section, but we are now testing up to 24 horizontal wells per section.
The decline in commodity prices during 2015 and early 2016 has led to a corresponding decline in service costs, which directly relate to our drilling and completion costs. We have been able to reduce drilling and completion costs during the first half of 2016 due to a combination of optimizing well designs, moving to day-rate drilling, lower contract rates for drilling rigs, fewer average days to drill, and lower completion costs. This focus on cost reduction has supported well-level economics in spite of the severe drop in the prices of crude oil and natural gas. We continue to strive to reduce drilling and completion costs going forward to offset the negative impacts associated with lower commodity prices, but we do not believe that we will achieve the same percentage reduction of costs during the remainder of 2016, and well-level rates of return may be lower, particularly if commodity prices continue to decline.
From time to time, our production has been adversely impacted by high natural gas gathering line pressures, especially in the northern area of the Wattenberg Field. Where it is cost effective, we install wellhead compression to enhance our ability to inject gas into the gathering system and, in some instances, install larger gathering lines to help mitigate the impacts. Additionally, midstream companies that operate the gas gathering pipelines in the area continue to make significant capital investments to increase their capacities. While these actions have helped reduce overall line pressures in the field, several of our producing locations have been shut-in on occasion due to line pressures exceeding system limits.
We have begun the use of oil gathering lines to certain production locations. We anticipate that these gathering systems would be owned and operated by independent third party companies, but that we would commit specific wellhead production to these systems. We believe that oil gathering lines would have several benefits including, a) reduced need to use trucks to gather our oil, thereby reducing truck traffic in and around our production locations, b) potentially lower gathering costs as pipeline gathering tends to be more efficient, c) less on-site oil storage capacity, resulting in lower production location facility costs, and d) generally less noise and dust.
Oil transportation and takeaway capacity has recently increased with the expansion of certain interstate pipelines servicing the Wattenberg Field. This has reversed the prior imbalance of oil production exceeding the combination of local refinery demand and the capacity of pipelines to move the oil to other markets. Depending on transportation commitments, local refinery demand, and our production volumes, we may be able to reduce the negative differential that we have historically realized on our oil production. We anticipate that there will continue to be excess pipeline takeaway capacity as additional pipelines are expected to begin operations in the second half of calendar 2016. Further details regarding posted prices and average realized prices are discussed in the section entitled "Market Conditions," presented in this Item 2.
We believe that the GC Acquisition will allow us to achieve significant efficiencies through the establishment of a contiguous acreage position in an attractive area in the Wattenberg Field, which should facilitate the drilling of longer lateral wells and high-grading of our drilling inventory.
As discussed in the "Risk Factors" section of this report, certain groups opposed to oil and natural gas development generally, and hydraulic fracturing in particular, are attempting to seek the required number of signatures to have two initiatives placed on the November 2016 ballot. One of the initiatives would impose a minimum distance of 2,500 feet between wells and any occupied structures or other sensitive areas. The second would give local governmental authorities the ability to regulate, or to ban, oil and gas exploration, development and production activities within their boundaries notwithstanding state rules and approvals to the contrary. Either initiative, if implemented, could have severely adverse effects on our operations, reserves and financial condition.
Other than the foregoing, we do not know of any trends, events, or uncertainties that will have had or are reasonably expected to have a material impact on our sales, revenues, expenses, liquidity, or capital resources.
Results of Operations
Material changes of certain items in our consolidated statements of operations included in our consolidated financial statements for the periods presented are discussed below.
For the
three months ended June 30, 2016
, compared to the
three months ended June 30, 2015
For the
three months ended June 30, 2016
, we reported a net
loss
of
$153.8 million
compared to net
loss
of
$4.6 million
during the
three months ended June 30, 2015
. Net
loss
per basic and diluted share (including the ceiling test impairment of
$144.1 million
) was
$(0.89)
for the
three months ended June 30, 2016
compared to net
loss
per basic and diluted share of
$(0.04)
for the
three months ended June 30, 2015
. Net
loss
per basic share for the
three months ended June 30, 2016
increased
by
$0.85
primarily due to the ceiling test impairment of
$144.1 million
incurred during the
three months ended June 30, 2016
. Revenues
decreased
15%
during the
three months ended June 30, 2016
compared with the
three months ended June 30, 2015
due to the rapid decline of commodity prices, as discussed previously. As of
June 30, 2016
, we had
620
gross producing wells, compared with
563
gross producing wells as of
June 30, 2015
. The impact of changing prices on our commodity derivative positions and a full cost ceiling impairment also drove significant differences in our results of operations between the two periods.
Oil and Gas Production and Revenues
- For the
three months ended June 30, 2016
, we recorded total oil and gas revenues of
$23.9 million
compared to
$28.3 million
for the
three months ended June 30, 2015
,
a decrease
of
$4.3 million
or
15%
. The following table summarizes key production and revenue statistics:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Percentage
|
|
2016
|
|
2015
|
|
Change
|
Production:
|
|
|
|
|
|
Oil (MBbls
1
)
|
508
|
|
|
468
|
|
|
9
|
%
|
Gas (MMcf
2
)
|
3,015
|
|
|
1,725
|
|
|
75
|
%
|
MBOE
3
|
1,010
|
|
|
755
|
|
|
34
|
%
|
BOED
4
|
11,098
|
|
|
8,299
|
|
|
34
|
%
|
|
|
|
|
|
|
Revenues (in thousands):
|
|
|
|
|
|
Oil
|
$
|
17,793
|
|
|
$
|
23,598
|
|
|
(25
|
)%
|
Gas
|
6,154
|
|
|
4,688
|
|
|
31
|
%
|
|
$
|
23,947
|
|
|
$
|
28,286
|
|
|
(15
|
)%
|
Average sales price:
|
|
|
|
|
|
Oil
|
$
|
35.06
|
|
|
$
|
50.47
|
|
|
(31
|
)%
|
Gas
|
$
|
2.04
|
|
|
$
|
2.72
|
|
|
(25
|
)%
|
BOE
|
$
|
23.71
|
|
|
$
|
37.45
|
|
|
(37
|
)%
|
1
"MBbl" refers to one thousand stock tank barrels, or 42,000 U.S. gallons liquid volume in reference to crude oil or other liquid hydrocarbons.
2
"MMcf" refers to one million cubic feet of natural gas.
3
"MBOE" refers to one thousand barrels of oil equivalent, which combines MBbls of oil and MMcf of gas by converting each six MMcf of gas to one MBbl of oil.
4
"BOED" refers to the average number of barrels of oil equivalent produced in a day for the period.
Net oil and gas production for the
three months ended June 30, 2016
averaged
11,098
BOED, an increase of
34%
over average production of
8,299
BOED in the
three months ended June 30, 2015
. From
June 30, 2015
to
June 30, 2016
, we added
48
net horizontal wells, including 6 (net) horizontal wells acquired in the KPK Acquisition, increasing our reserves, producing wells, and daily production totals. However, the
37%
decline in average sales prices more than offset the effects of increased production, resulting in an overall reduction of revenues.
Lease Operating Expenses ("LOE")
- Direct operating costs of producing oil and natural gas are reported as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
2016
|
|
2015
|
Production costs
|
$
|
5,267
|
|
|
$
|
3,202
|
|
Remediation
|
1,402
|
|
|
35
|
|
Workover
|
176
|
|
|
508
|
|
Total LOE
|
$
|
6,845
|
|
|
$
|
3,745
|
|
|
|
|
|
Per BOE:
|
|
|
|
Production costs
|
$
|
5.21
|
|
|
$
|
4.24
|
|
Remediation
|
1.39
|
|
|
0.05
|
|
Workover
|
0.17
|
|
|
0.67
|
|
Total LOE
|
$
|
6.77
|
|
|
$
|
4.96
|
|
Lease operating and workover costs tend to increase or decrease primarily in relation to the number of wells in production, and, to a lesser extent, to fluctuations in oil field service costs and changes in the production mix of crude oil and natural gas. The
$3.1 million
increase in lease operating expenses during the
three months ended June 30, 2016
compared to the
three months ended June 30, 2015
was primarily due to a
$1.4 million
increase in environmental remediation and regulatory compliance projects. The related costs per BOE
increased
by
$1.81
primarily as a result of increased remediation work during the
three months ended June 30, 2016
.
Production taxes
- During the
three months ended June 30, 2016
, production taxes were
$2.1 million
, or
$2.12
per BOE, compared to
$2.6 million
, or
$3.42
per BOE, during the
three months ended June 30, 2015
. Taxes tend to increase or decrease primarily based on the value of oil and gas sold. As a percentage of revenues, production taxes were
8.9%
and
9.1%
for the
three months ended June 30, 2016
and
2015
, respectively.
Depletion, Depreciation, and Accretion ("DD&A")
- The following table summarizes the components of DD&A:
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
(in thousands)
|
2016
|
|
2015
|
Depletion of oil and gas properties
|
$
|
10,965
|
|
|
$
|
15,534
|
|
Depreciation and accretion
|
309
|
|
|
203
|
|
Total DD&A
|
$
|
11,274
|
|
|
$
|
15,737
|
|
|
|
|
|
DD&A expense per BOE
|
$
|
11.16
|
|
|
$
|
20.84
|
|
For the
three months ended June 30, 2016
, depletion of oil and gas properties was
$11.16
per BOE compared to
$20.84
per BOE for the
three months ended June 30, 2015
. The decrease in the DD&A rate was the result of a decrease in the ratio of total costs capitalized in the full cost pool to the estimated recoverable reserves. This ratio was significantly reduced due to the impairments of our full cost pool, which primarily occurred during the second half of calendar 2015 and the first quarter of 2016, and the increase in our total proved reserves. Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning of quarter estimated total reserves determine the depletion rate.
Full cost ceiling impairment
- During the
three months ended June 30, 2016
, we recognized a total impairment of
$144.1 million
as compared to an impairment of
$3.0 million
for the
three months ended June 30, 2015
, representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling. See Note
2
, "Property and Equipment," to the consolidated financial statements included as part of this report.
General and Administrative ("G&A")
- The following table summarizes G&A expenses incurred and capitalized during the periods presented:
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
(in thousands)
|
2016
|
|
2015
|
G&A costs incurred
|
$
|
9,859
|
|
|
$
|
6,708
|
|
Capitalized costs
|
(2,339
|
)
|
|
(466
|
)
|
Total G&A
|
$
|
7,520
|
|
|
$
|
6,242
|
|
|
|
|
|
Non-Cash G&A
|
$
|
2,391
|
|
|
$
|
4,066
|
|
Cash G&A
|
$
|
5,129
|
|
|
$
|
2,176
|
|
Total G&A
|
$
|
7,520
|
|
|
$
|
6,242
|
|
|
|
|
|
Non-Cash G&A per BOE
|
$
|
2.37
|
|
|
$
|
5.39
|
|
Cash G&A per BOE
|
$
|
5.08
|
|
|
$
|
2.88
|
|
G&A Expense per BOE
|
$
|
7.45
|
|
|
$
|
8.27
|
|
G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. During the
three months ended June 30, 2016
, we increased our employee count, which was 62 as of December 31, 2015 to 73, while reducing the number of consultants, advisors, and contractors that had historically been used for certain tasks.
Our G&A expense for the
three months ended June 30, 2016
includes stock-based compensation of
$2.4 million
compared to
$4.1 million
for the
three months ended June 30, 2015
. Stock-based compensation includes a calculated value for stock options or shares of common stock that we grant for compensatory purposes. It is a non-cash charge. For stock options, the fair value is estimated using the Black-Scholes-Merton option pricing model. For restricted stock units and stock bonus shares, the fair value is estimated using the closing stock price on the grant date. Amounts are pro-rated over the vesting terms of the award agreements, which are generally three to five years.
Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the exploration and development of properties. Those costs are reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from the
three months ended June 30, 2015
to the
three months ended June 30, 2016
reflects our increased headcount of individuals performing activities to maintain and acquire leases and develop our properties.
Commodity derivative losses
- As more fully described in Item 1. Financial Statements – Note
8
,
Commodity Derivative Instruments
, we use commodity contracts to help mitigate the risks inherent in the price volatility of oil and natural gas. For the
three months ended June 30, 2016
, we realized a cash settlement
gain
of
$0.4 million
, net of previously incurred premiums attributable to the settled commodity contracts. For the prior comparable period, we realized a cash settlement
gain
of
$3.8 million
.
In addition, for the
three months ended June 30, 2016
, we recorded an unrealized
loss
of
$6.1 million
to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the
three months ended June 30, 2015
, we reported an unrealized
loss
of
$8.2 million
. Unrealized losses are non-cash items.
Income taxes
- We reported income tax
expense
of
$0.1 million
for the
three months ended June 30, 2016
, calculated at an effective tax rate of
0%
. During the comparable prior year period, we reported income tax
benefit
of
$2.9 million
, calculated at an effective tax rate of
39%
. As explained in more detail below, during the period ended
June 30, 2016
, the effective tax rate was substantially reduced by recognition of a full valuation allowance on the net deferred tax assets. During the
three months ended June 30, 2016
, the effective tax rate differed from the statutory rate, primarily due to the recognition of a valuation allowance recorded against deferred tax assets.
For tax purposes, we have a net operating loss ("NOL") carryover of $44.2 million, which is available to offset future taxable income. The NOLs will begin to expire, if not used, in 2031. As a result of the NOLs and other tax strategies, it appears that payment of any tax liability will be substantially deferred into future years.
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. Based on the level of losses in the current period and the level of uncertainty with respect to future taxable income over the period in which the deferred tax assets are deductible, a valuation allowance has been provided as of
June 30, 2016
. During the 2015 comparable period, we reached the opposite conclusion; therefore, we did not record a valuation allowance against any of our deferred tax assets in that period.
For the
six months ended June 30, 2016
, compared to the
six months ended June 30, 2015
For the
six months ended June 30, 2016
, we reported net
loss
of
$205.2 million
compared to net
loss
of
$5.6 million
during the
six months ended June 30, 2015
. Net
loss
per basic and diluted share (including a ceiling test impairment of
$189.8 million
) was
$(1.40)
for the
three months ended June 30, 2016
compared to net loss per basic and diluted share of
$(0.06)
for the
six months ended June 30, 2015
. Net
loss
per basic share for the
six months ended June 30, 2016
increased
by
$1.34
primarily due to the ceiling test impairment of
$189.8 million
incurred during the
three months ended June 30, 2016
. Revenues decreased
11%
during the
six months ended June 30, 2016
compared with the
six months ended June 30, 2015
due to the rapid decline of commodity prices, as discussed previously. As of
June 30, 2016
, we had
620
gross producing wells, compared with
563
gross producing wells as of
June 30, 2015
. The impact of changing prices on our commodity derivative positions and a full cost ceiling impairment also drove significant differences in our results of operations between the two periods.
Oil and Gas Production and Revenues
- For the
six months ended June 30, 2016
, we recorded total oil and gas revenues of
$42.2 million
compared to
$47.2 million
for the
six months ended June 30, 2015
,
a decrease
of
$5.0 million
or
11%
. The following table summarizes key production and revenue statistics:
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
Percentage
|
|
2016
|
|
2015
|
|
Change
|
Production:
|
|
|
|
|
|
Oil (MBbls)
|
1,035
|
|
|
829
|
|
|
25
|
%
|
Gas (MMcf)
|
6,136
|
|
|
3,355
|
|
|
83
|
%
|
MBOE
|
2,057
|
|
|
1,388
|
|
|
48
|
%
|
BOED
|
11,304
|
|
|
7,668
|
|
|
47
|
%
|
|
|
|
|
|
|
Revenues (in thousands):
|
|
|
|
|
|
Oil
|
$
|
30,387
|
|
|
$
|
37,082
|
|
|
(18
|
)%
|
Gas
|
11,833
|
|
|
10,142
|
|
|
17
|
%
|
|
$
|
42,220
|
|
|
$
|
47,224
|
|
|
(11
|
)%
|
Average sales price:
|
|
|
|
|
|
Oil
|
$
|
29.37
|
|
|
$
|
44.75
|
|
|
(34
|
)%
|
Gas
|
$
|
1.93
|
|
|
$
|
3.02
|
|
|
(36
|
)%
|
BOE
|
$
|
20.52
|
|
|
$
|
34.03
|
|
|
(40
|
)%
|
Net oil and gas production for the
six months ended June 30, 2016
averaged
11,304
BOED, an increase of
47%
over average production of
7,668
BOED in the
six months ended June 30, 2015
. From
June 30, 2015
to
June 30, 2016
, we added
48
net horizontal wells, including 6 (net) horizontal wells acquired in the KPK Acquisition, increasing our reserves, producing wells, and daily production totals. However, the
40%
decline in average sales prices more than offset the effects of increased production, resulting in an overall reduction of revenues.
Lease Operating Expenses ("LOE")
- Direct operating costs of producing oil and natural gas are reported as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
2016
|
|
2015
|
Production costs
|
$
|
9,393
|
|
|
$
|
7,191
|
|
Remediation
|
1,542
|
|
|
102
|
|
Workover
|
209
|
|
|
573
|
|
Total LOE
|
$
|
11,144
|
|
|
$
|
7,866
|
|
|
|
|
|
Per BOE:
|
|
|
|
Production costs
|
$
|
4.57
|
|
|
$
|
5.18
|
|
Remediation
|
0.75
|
|
|
0.07
|
|
Workover
|
0.10
|
|
|
0.41
|
|
Total LOE
|
$
|
5.42
|
|
|
$
|
5.66
|
|
Lease operating and workover costs tend to increase or decrease primarily in relation to the number of wells in production, and, to a lesser extent, on fluctuation in oil field service costs and changes in the production mix of crude oil and natural gas. The
$3.3 million
increase in lease operating expenses during the
six months ended June 30, 2016
compared to the
six months ended June 30, 2015
was primarily due to a
$1.4 million
increase in
e
nvironmental remediation and regulatory compliance projects. The related costs per BOE
decreased
by
$0.24
primarily as a result of increased production during the
six months ended June 30, 2016
.
Production taxes
- During the
six months ended June 30, 2016
, production taxes were
$4.0 million
, or
$1.93
per BOE,
compared to
$4.4 million
, or
$3.16
per BOE, during the
six months ended June 30, 2015
. Taxes tend to increase or decrease primarily based on the value of oil and gas sold. As a percentage of revenues, production taxes were
9.4%
and
9.3%
for the
six months ended June 30, 2016
and
2015
, respectively.
Depletion, Depreciation, and Accretion ("DD&A")
- The following table summarizes the components of DD&A:
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
(in thousands)
|
2016
|
|
2015
|
Depletion of oil and gas properties
|
$
|
22,708
|
|
|
$
|
29,414
|
|
Depreciation and accretion
|
658
|
|
|
400
|
|
Total DD&A
|
$
|
23,366
|
|
|
$
|
29,814
|
|
|
|
|
|
DD&A expense per BOE
|
$
|
11.36
|
|
|
$
|
21.48
|
|
For the
six months ended June 30, 2016
, depletion of oil and gas properties was
$11.36
per BOE compared to
$21.48
per BOE for the
six months ended June 30, 2015
. The decrease in the DD&A rate was the result of a decrease in the ratio of total costs capitalized in the full cost pool to the estimated recoverable reserves. This ratio was significantly reduced due to the impairments of our full cost pool, which primarily occurred during the second half of calendar 2015, and the increase in our total proved reserves. Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning of quarter estimated total reserves determine the depletion rate.
Full cost ceiling impairment
- During the
six months ended June 30, 2016
, we recognized a total impairment of
$189.8 million
as compared to an impairment of
$3.0 million
for the
six months ended June 30, 2015
, representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling. See Note
2
, "Property and Equipment," to the consolidated financial statements included as part of this report.
General and Administrative ("G&A")
- The following table summarizes G&A expenses incurred and capitalized during the periods presented:
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
(in thousands)
|
2016
|
|
2015
|
G&A costs incurred
|
$
|
17,951
|
|
|
$
|
11,374
|
|
Capitalized costs
|
(2,988
|
)
|
|
(1,051
|
)
|
Total G&A
|
$
|
14,963
|
|
|
$
|
10,323
|
|
|
|
|
|
Non-Cash G&A
|
$
|
4,910
|
|
|
$
|
5,417
|
|
Cash G&A
|
$
|
10,053
|
|
|
$
|
4,906
|
|
Total G&A
|
$
|
14,963
|
|
|
$
|
10,323
|
|
|
|
|
|
Non-Cash G&A per BOE
|
$
|
2.39
|
|
|
$
|
3.90
|
|
Cash G&A per BOE
|
$
|
4.89
|
|
|
$
|
3.53
|
|
G&A Expense per BOE
|
$
|
7.28
|
|
|
$
|
7.43
|
|
G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. During the
six months ended June 30, 2016
, we increased our employee count from 62 as of December 31, 2015 to 73, while reducing the number of consultants, advisors, and contractors that had historically been used for certain tasks.
Our G&A expense for the
six months ended June 30, 2016
includes stock-based compensation of
$4.9 million
compared to
$5.4 million
for the
six months ended June 30, 2015
.
Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the exploration and development of
properties. Those costs are reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from the
six months ended June 30, 2015
to the
six months ended June 30, 2016
reflects our increased headcount of individuals performing activities to maintain and acquire leases and develop our properties.
Commodity derivative losses
- As more fully described in Item 1. Financial Statements – Note
8
,
Commodity Derivative Instruments,
we use commodity contracts to help mitigate the risks inherent in the price volatility of oil and natural gas. For the
six months ended June 30, 2016
, we realized a cash settlement
gain
of
$2.9 million
, net of previously incurred premiums attributable to the settled commodity contracts. For the prior comparable period, we realized a cash settlement
gain
of
$17.3 million
.
In addition, for the
six months ended June 30, 2016
, we recorded an unrealized
loss
of
$6.9 million
to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the
six months ended June 30, 2015
, we reported an unrealized
loss
of
$18.2 million
. Unrealized losses are non-cash items.
Income taxes
- We reported income tax
expense
of
$0.1 million
for the
six months ended June 30, 2016
, calculated at an effective tax rate of
0%
. During the comparable prior year period, we reported income tax
benefit
of
$3.6 million
, calculated at an effective tax rate of
39%
. During the period ended
June 30, 2016
, the effective tax rate was substantially reduced by recognition of a full valuation allowance on the net deferred tax assets. During the
six months ended June 30, 2016
, the effective tax rate differed from the statutory rate, primarily due to the recognition of a valuation allowance recorded against deferred tax assets.
Liquidity and Capital Resources
Historically, our primary sources of capital have been net cash provided by the sale of equity and debt securities, cash flow from operations, proceeds from the sale of properties, and borrowings under bank credit facilities. Our primary use of capital has been for the exploration, development, and acquisition of oil and natural gas properties. Our future success in growing proved reserves and production will be highly dependent on capital resources available to us.
We believe that our capital resources, including cash on hand, amounts available under our revolving credit facility, and cash flow from operating activities will be sufficient to fund our planned capital expenditures and operating expenses for the next twelve months. We funded the purchase price of the GC Acquisition through a combination of cash on hand and proceeds of financing transactions, including the issuance of the Senior Notes. We do not expect to commence drilling activities on the properties acquired in the GC Acquisition until 2017. To the extent actual operating results differ from our anticipated results, available borrowings under our credit facility are reduced, or we experience other unfavorable events, our liquidity could be adversely impacted. Our liquidity would also be affected if we increase our capital expenditures or complete one or more additional acquisitions. Terms of future financings may be unfavorable, and we cannot assure investors that funding will be available on acceptable terms.
As operator of the majority of our wells and undeveloped acreage, we control the timing and selection of new wells to be drilled or existing wells to be recompleted. This allows us to modify our capital spending as our financial resources allow and market conditions support. Additionally, our relatively low utilization of debt enhances our financial flexibility as it provides a potential source of future liquidity while currently not overly burdening us with restrictive financial covenants and mandatory repayment schedules.
Sources and Uses
Our sources and uses of capital are heavily influenced by the prices that we receive for our production. During the first half of 2016, the NYMEX-WTI oil price ranged from a high of
$51.23
per Bbl on
Wednesday, June 8, 2016
to a low of
$26.19
per Bbl on
Thursday, February 11, 2016
, while the NYMEX-Henry Hub natural gas price ranged from a low of
$1.64
per MMBtu on
Thursday, March 3, 2016
to a high of
$2.92
per MMBtu on
June 30, 2016
. These markets will likely continue to be volatile in the future. To deal with the volatility in commodity prices, we maintain a flexible capital investment program and seek to maintain a high operating interest in our leaseholds with limited long-term capital commitments. This enables us to accelerate or decelerate our activities quickly in response to changing industry environments.
At
June 30, 2016
, we had cash and cash equivalents of
$78.6 million
and no outstanding balance under our revolving credit facility. Our sources and (uses) of funds for the
six months ended
June 30, 2016
and
2015
are summarized below (in thousands):
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
2016
|
|
2015
|
Cash provided by operations
|
$
|
12,235
|
|
|
$
|
60,593
|
|
Acquisitions and development of oil and gas properties and equipment
|
(546,112
|
)
|
|
(96,293
|
)
|
Net cash provided by other investing activities
|
5,284
|
|
|
6,239
|
|
Net cash provided by equity financing activities
|
543,092
|
|
|
190,302
|
|
Net cash used in debt financing activities
|
(2,364
|
)
|
|
(59,000
|
)
|
Net increase in cash and equivalents
|
$
|
12,135
|
|
|
$
|
101,841
|
|
Net cash provided by operating activities was
$12.2 million
and
$60.6 million
for the
six months ended
June 30, 2016
and
2015
, respectively. The decline in cash from operating activities reflects the decline in commodity prices, which was partially offset by the increase in production.
During the
six months ended
June 30, 2016
, we received cash proceeds from, and used cash proceeds in, the following financing activities:
|
|
•
|
On January 27, 2016, we received cash proceeds of approximately
$89.2 million
(after underwriting discounts, commissions and expenses) from our public offering of
16,100,000
shares (including the shares sold pursuant to an over-allotment option exercised by the underwriters) at a price to us of
$5.545
per share. Proceeds were used to repay amounts borrowed under the Revolver and for general corporate purposes, which included continuing to develop our acreage position in the Wattenberg Field in Colorado and funding a portion of our 2016 capital expenditure program.
|
|
|
•
|
In January 2016, the Company repaid its outstanding borrowings under the Revolver of
$78 million
. In addition, on June 13, 2016, the Company borrowed approximately $55 million under the Revolver in order to pay a portion of the purchase price for the GC Acquisition pending receipt of proceeds from the issuance of the Senior Notes. The full amount borrowed was repaid on June 14, 2016.
|
|
|
•
|
On April 14, 2016, we received cash proceeds of approximately
$164.8 million
(after underwriting discounts, commissions and expenses) from our public offering of
22,425,000
shares (including the shares sold pursuant to an over-allotment option exercised by the underwriters) at a price to us of
$7.3535
per share. These proceeds were used for general corporate purposes, including to fund the GC Acquisition.
|
|
|
•
|
In May and June 2016, we received cash proceeds of approximately
$289.4 million
(after underwriting discounts, commissions and expenses) from our public offering of
51,750,000
shares (including the shares sold pursuant to an over-allotment option exercised by the underwriters) at a price to us of
$5.597
per share. These proceeds were used for general corporate purposes, including to fund the GC Acquisition.
|
|
|
•
|
On June 14, 2016, the Company issued $80 million aggregate principal amount of 9.00% Senior Unsecured Notes ("Senior Notes") in a private placement to qualified institutional buyers. See "- Senior Notes" below. The net proceeds from the sale of the Senior Notes were $75.8 million after deductions of $4.2 million for expenses and underwriting discounts and commissions. The net proceeds were used to fund the GC Acquisition.
|
Credit Facility
We maintain a borrowing arrangement with a banking syndicate. The arrangement, in the form of a revolving credit facility, was most recently amended with the Eighth Amendment to the credit facility on May 3, 2016. The arrangement provides for a maximum loan commitment of $500 million; however, the maximum amount we can borrow at any one time is subject to a borrowing base limitation, which stipulates that we may borrow up to the lesser of the maximum loan commitment or the borrowing base. The borrowing base can increase or decrease based upon the value of the collateral, which secures any amounts borrowed under the line of credit. The value of the collateral will generally be derived with reference to the estimated future net cash flows from our proved oil and gas reserves, discounted by 10%. Amounts borrowed under the facility are secured by substantially all of our producing wells and developed oil and gas leases.
As of
December 31, 2015
, our borrowing base was
$163 million
, and we had $78 million outstanding under the facility, which was fully repaid during the three months ended March 31, 2016. The maturity date of the facility is
December 15, 2019
. On January 28, 2016, the borrowing base was reduced from
$163 million
to
$145 million
. As of
June 30, 2016
, the total of the
$145 million
was available to us for future borrowings. The next semi-annual redetermination has been scheduled for
November 2016
.
As of
June 30, 2016
, interest on our revolving line of credit accrues at a variable rate. The interest rate pricing grid contains a graduated escalation in applicable margin for increased utilization.
On January 28, 2016, the Revolver was amended to (i) delete the minimum interest rate floor, (ii) delete the minimum liquidity covenant, (iii) add a current ratio covenant of 1.0 to 1.0, and (iv) delete the minimum hedging requirement.
The Revolver requires the Company to maintain compliance with certain financial and liquidity ratio covenants. Under the requirements, the Company, on a quarterly basis, must not (a) at any time permit its ratio of total funded debt as of such time to EBITDAX, as defined in the agreement, to be greater than or equal to
4.0
to 1.0; or (b) as of the last day o
f any fiscal quarter permit its current ratio, as defined in the agreement, to be less than
1.0
to 1.0.
Senior Notes
On June 14, 2016, the Company issued $80 million aggregate principal amount of the Senior Notes in a private placement to qualified institutional buyers. The maturity for the payment of principal is June 13, 2021. Interest on the Notes accrues at 9.00% and began accruing on June 14, 2016. Interest is payable on June 15 and December 15 of each year, beginning on December 15, 2016. The Senior Notes were issued pursuant to an indenture dated as of June 14, 2016 (the "Indenture") and are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the revolving credit facility. At any time prior to December 14, 2018, the Company may redeem all or a part of the Senior Notes subject to the Make-Whole Price (as defined in the Indenture) and accrued and unpaid interest. On and after December 14, 2018, the Company may redeem all or a part of the Senior Notes at the redemption price at a specified percentage of the principal amount of the redeemed notes (104.50% for 2018, 102.25% for 2019, and 100.0% for 2020 and thereafter, during the twelve-month period beginning on December 14 of each applicable year), plus accrued and unpaid interest. Additionally, prior to December 14, 2018, the Company can, on one or more occasions, redeem up to 35% of the principal amount of the Senior Notes with all or a portion of the net cash proceeds of one or more Equity Offerings (as defined in the Indenture) at a redemption price equal to 109.00% of the principal amount of the redeemed notes, plus accrued and unpaid interest, subject to certain conditions.
The Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to, among other restrictions and limitations: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities. These covenants are subject to a number of exceptions and qualifications.
Reconciliation of Cash Payments to Capital Expenditures
Capital expenditures reported in the consolidated statements of cash flows are calculated on a strict cash basis, which differs from the accrual basis used to calculate other amounts reported in our consolidated financial statements. Specifically, cash payments for acquisition of property and equipment as reflected in the consolidated statements of cash flows excludes non-cash capital expenditures and includes an adjustment (plus or minus) to reflect the timing of when the capital expenditure obligations are incurred and when the actual cash payment is made. On an accrual basis, capital expenditures totaled
$537.5 million
and
$94.7 million
for the
six months ended June 30, 2016
and
2015
, respectively. A reconciliation of the differences between cash payments and the accrual basis amounts is summarized in the following table (in thousands):
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
2016
|
|
2015
|
Cash payments for acquisitions
|
$
|
496,261
|
|
|
$
|
—
|
|
Asset retirement obligations assumed with acquisitions
|
1,692
|
|
|
—
|
|
Cash payments for capital expenditures
|
49,851
|
|
|
96,293
|
|
Accrued costs, beginning of period
|
(31,414
|
)
|
|
(52,747
|
)
|
Accrued costs, end of period
|
18,349
|
|
|
40,019
|
|
Non-cash acquisitions, common stock
|
—
|
|
|
9,840
|
|
Other
|
2,763
|
|
|
1,337
|
|
Accrual basis capital expenditures
|
$
|
537,502
|
|
|
$
|
94,742
|
|
Capital Expenditures
The majority of capital expenditures during the
six months ended
June 30, 2016
were associated with the acquisition of certain acreage and the costs of drilling and completing wells. During the
six months ended
June 30, 2016
, we compl
eted the 10 horizontal wells on the Vista pad, began the drilling of 12 horizontal wells on the Fagerberg pad, and set surface casings on 8 horizontal wells on the Evans pad. The Fagerberg pad will have a total of 14 horizontal wells, and the Evans pad will have a total of 22 horizontal wells. In total, we had drilled
20
gross (
18
net) we
lls that had not been brought into productive status as of
June 30, 2016
, which excludes 8 gross (6 net) wells on the Evans pad for which we have recently set surface casings
. All but eight of the wells in progress are scheduled to commence production before December 31, 2016.
With respect to our ownership interest in wells operated by other companies, we participated in drilling and completion activities
on 1 gross (0.24 net) wells d
uring the
second
quarter.
Capital Requirements
Our level of exploration, development, and acreage expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows, and development results, among other factors. Our primary need for capital will be to fund our anticipated drilling and completion activities, the second closing on the GC Acquisition, and any other acquisitions that we may complete during the remainder of the year ending
December 31, 2016
.
In the six months ended June 30, 2016, we operated one drilling rig for the execution of our capital expenditure plan. Consistent with our plan, we added a second rig in July 2016 to drill the adjoining Evans East and Evans West pads in order to minimize the impact on the local municipality. We also regularly review capital expenditures throughout the year, as has been our historical practice, and will adjust our program based on changes in commodity prices, service costs, drilling success, and capital availability. Our total anticipated capital program for the year ended
December 31, 2016
is estimated at a range between $130 million and $150 million, including approximately $30 million for discretionary seismic and land leasing, but excluding the GC Acquisition and any other potential acquisitions that we may execute. Capital expenditures for the
six months ended
June 30, 2016
were approximately
$37 million
.
For the near term, we believe that we have sufficient liquidity to fund our needs through cash on hand, cash flow from operations, and additional borrowings available under our revolving credit facility. However, to meet all of our long-term goals, we may need to raise additional funds to drill new wells through the sale of our securities, from third parties willing to pay our share of drilling and completing wells, or from other sources. We may not be successful in raising the capital needed to drill or acquire oil or gas wells.
Oil and Gas Commodity Contracts
We use derivative contracts to protect against the variability in cash flows created by short-term price fluctuations associated with the sale of future oil and gas production. At
June 30, 2016
, we had open positions covering
1.2 million
barrels of oil and
3,960
MMcf of natural gas. We do not use derivative instruments for speculative purposes. Subsequent to June 30, 2016, we entered into additional positions covering 1,200 MMcf of natural gas.
During the
six months ended June 30, 2016
, we reported an unrealized commodity activity
loss
of
$6.9 million
. Unrealized gains and losses are non-cash items. We also reported a realized
gain
of
$2.9 million
, representing the cash settlement of commodity contracts settled during the period, net of previously incurred premiums attributable to the settled commodity contracts.
At
June 30, 2016
, we estimated that the fair value of our various commodity derivative contracts was a net asset of
$1.6 million
. See Item 1. Financial Statements – Note
9
,
Fair Value Measurements
, for a description of the methods we use to estimate the fair values of commodity derivative instruments.
Non-GAAP Financial Measures
In addition to financial measures presented on the basis of accounting principles generally accepted in the United States of America ("US GAAP"), we present certain financial measures which are not prescribed by US GAAP ("non-GAAP"). In the future, we may disclose different non-GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our consolidated financial statements and publicly filed reports in their entirety and to not rely on any single financial measure. A summary of the non-GAAP measure that we currently use is described below.
Adjusted EBITDA
We use "adjusted EBITDA," a non-GAAP financial measure, for internal managerial purposes
because it allows us to more effectively evaluate our operating performance 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 in the table below from net 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 method by which the assets were acquired.
This measure is not a measure of financial performance under US GAAP and should be considered in addition to, not as a substitute for, cash flows from operations, investing, or financing activities, and it should not be viewed as a liquidity measure or indicator of cash flows reported in accordance with US GAAP. Our definition of adjusted EBITDA may not be comparable to measures with similar titles reported by other companies.
We believe that adjusted EBITDA is a widely used in our industry as a measure of operating performance and may also be used by investors to measure our ability to meet debt covenant requirements.
We define adjusted EBITDA as net loss adjusted to exclude the impact of the items set forth in the table below.
The following table presents a reconciliation of adjusted EBITDA, a non-GAAP financial measure, to net loss, its nearest GAAP measure:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Adjusted EBITDA:
|
|
|
|
|
|
|
|
Net loss
|
$
|
(153,848
|
)
|
|
$
|
(4,588
|
)
|
|
$
|
(205,249
|
)
|
|
$
|
(5,581
|
)
|
Depreciation, depletion, and accretion
|
11,274
|
|
|
15,737
|
|
|
23,366
|
|
|
29,814
|
|
Full cost ceiling impairment
|
144,149
|
|
|
3,000
|
|
|
189,770
|
|
|
3,000
|
|
Income tax expense (benefit)
|
101
|
|
|
(2,903
|
)
|
|
101
|
|
|
(3,612
|
)
|
Stock-based compensation
|
2,392
|
|
|
4,235
|
|
|
4,911
|
|
|
5,839
|
|
Mark-to-market of commodity derivative contracts:
|
|
|
|
|
|
|
|
Total loss on commodity derivatives contracts
|
5,704
|
|
|
4,383
|
|
|
4,024
|
|
|
922
|
|
Cash settlements on commodity derivative contracts
|
1,592
|
|
|
4,423
|
|
|
4,651
|
|
|
18,165
|
|
Cash premiums paid for commodity derivative contracts
|
—
|
|
|
(619
|
)
|
|
—
|
|
|
(4,117
|
)
|
Interest expense (income)
|
(167
|
)
|
|
91
|
|
|
(169
|
)
|
|
106
|
|
Adjusted EBITDA
|
$
|
11,197
|
|
|
$
|
23,759
|
|
|
$
|
21,405
|
|
|
$
|
44,536
|
|
Critical Accounting Policies
We prepare our consolidated financial statements and the accompanying notes in conformity with US GAAP, which requires management to make estimates and assumptions about future events that affect the reported amounts in the consolidated financial statements and the accompanying notes. We identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our financial condition, results of operations, or liquidity and the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection, and disclosure of each of the critical accounting policies.
There have been no significant changes to our critical accounting policies and estimates or in the underlying accounting assumptions and estimates used from those disclosed in the "Management’s Discussion and Analysis of Financial Condition and Results of Operations" section of the Transition Report on Form 10-K filed with the SEC on April 22, 2016 and in the financial statements and accompanying notes contained in that report. However, certain events during the first quarter increased the significance of our policies with respect to the evaluation of goodwill. This item is discussed in Item 1. Financial Statements – Note
1
,
Organization and Summary of Significant Accounting Policies,
to the accompanying condensed consolidated financial statements included elsewhere in this report. Note 1 also provides information regarding recently issued accounting pronouncements.
We call your attention to the increased significance of the ceiling test as disclosed in Item 1. Financial Statements – Note
2
,
Property and Equipment,
to the accompanying condensed consolidated financial statements included els
ewhere in this report.
During the quarter ended
June 30, 2016
, we recorded an impairment in conjunction with performing a ceiling test as prescribed by SEC Regulation S-X Rule 4-05.