10-Q 1 q11710-qsci20170331.htm 10-Q Document

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2017

OR

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

For the transition period from _______________________ to _______________________

Commission file number:  001-35245

logovrt4c.jpg

SYNERGY RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)
(Doing Business as SRC ENERGY INC.)

COLORADO
20-2835920
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)

1675 Broadway, Suite 2600, Denver, CO
80202
(Address of principal executive offices) 
(Zip Code)

Registrant's telephone number, including area code: (720) 616-4300


Indicate by check mark whether the registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý   No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such filing). Yes ý  No o

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



Large accelerated filer  ý
Accelerated filer  o
 
 
Non-accelerated filer  o   (Do not check if a smaller reporting company)    
Smaller reporting company  o
 
 
 
Emerging growth company  o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act):  Yes o No ý

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: 200,828,968 outstanding shares of common stock as of April 30, 2017.



SYNERGY RESOURCES CORPORATION
(dba SRC ENERGY INC.)
Index

 
 
 
Page
Part I - FINANCIAL INFORMATION
 
 
 
 
 
 
Item 1.
Financial Statements (unaudited)
 
 
 
 
 
 
 
Condensed Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016
 
 
 
 
 
 
Condensed Consolidated Statements of Operations for the three months ended March 31, 2017 and 2016
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2017 and 2016
 
 
 
 
 
 
Notes to Condensed Consolidated Financial Statements
 
 
 
 
 
Item 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
 
 
 
 
 
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
 
 
 
 
 
Item 4.
Controls and Procedures
 
 
 
 
 
Part II - OTHER INFORMATION
 
 
 
 
 
 
Item 1.
Legal Proceedings
 
 
 
 
 
Item 1A.
Risk Factors
 
 
 
 
 
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
 
 
 
 
 
Item 3.
Defaults of Senior Securities
 
 
 
 
 
Item 4.
Mine Safety Disclosures
 
 
 
 
 
Item 5.
Other Information
 
 
 
 
 
Item 6.
Exhibits
 
 
 
 
 
SIGNATURES
 





SYNERGY RESOURCES CORPORATION
(dba SRC ENERGY INC.)
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited; in thousands, except share data)


ASSETS
March 31, 2017
 
December 31, 2016
Current assets:
 
 
 
Cash and cash equivalents
$
33,197

 
$
18,615

Accounts receivable:
 
 
 
Oil, natural gas, and NGL sales
21,924

 
25,728

Trade
18,894

 
6,805

Commodity derivative assets
622

 
297

Other current assets
4,566

 
2,739

Total current assets
79,203

 
54,184

Property and equipment:
 
 
 
Oil and gas properties, full cost method:
 
 
 
Unproved properties and land, not subject to depletion
355,267

 
398,547

Proved properties, net of accumulated depletion
502,329

 
424,082

Wells in progress
82,664

 
81,780

Oil and gas properties, net
940,260

 
904,409

Other property and equipment, net
6,113

 
4,327

Total property and equipment, net
946,373

 
908,736

 
 
 
 
Cash held in escrow and other deposits
18,219

 
18,248

Goodwill
40,711

 
40,711

Other assets
2,077

 
2,234

Total assets
$
1,086,583

 
$
1,024,113

 
 
 
 
LIABILITIES AND SHAREHOLDERS' EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
97,726

 
$
52,453

Revenue payable
19,044

 
16,557

Production taxes payable
13,097

 
17,673

Asset retirement obligations
1,508

 
2,683

Commodity derivative liabilities
45

 
2,874

Total current liabilities
131,420

 
92,240

 
 
 
 
Revolving credit facility

 

Notes payable, net of issuance costs
75,809

 
75,614

Asset retirement obligations
13,955

 
13,775

Other liabilities
1,981

 
1,745

Total liabilities
223,165

 
183,374

 
 
 
 
Commitments and contingencies (See Note 14)


 


 
 
 
 
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: 200,806,149 and 200,647,572 shares issued and outstanding, respectively
201

 
201

Additional paid-in capital
1,151,899

 
1,148,998

Retained deficit
(288,682
)
 
(308,460
)
Total shareholders' equity
863,418

 
840,739

Total liabilities and shareholders' equity
$
1,086,583

 
$
1,024,113

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

2

SYNERGY RESOURCES CORPORATION
(dba SRC ENERGY INC.)
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited; in thousands, except share and per share data)

 
Three Months Ended March 31,
 
2017
 
2016
Oil, natural gas, and NGL revenues
$
43,790

 
$
18,273

Sales of purchased oil
1,268

 

Total revenues
45,058

 
18,273

 
 
 
 
Expenses:
 
 
 
Lease operating expenses
3,722

 
4,299

Production taxes
1,466

 
1,833

Costs of purchased oil
1,518

 

Depreciation, depletion, and accretion
13,229

 
12,092

Full cost ceiling impairment

 
45,621

Unused commitment charge
669

 
68

General and administrative
8,200

 
7,443

Total expenses
28,804

 
71,356

 
 
 
 
Operating income (loss)
16,254

 
(53,083
)
 
 
 
 
Other income (expense):
 
 
 
Commodity derivatives gain
3,379

 
1,680

Interest expense, net of amounts capitalized

 

Interest income
11

 
8

Other income (expense)
236

 
(6
)
Total other income
3,626

 
1,682

 
 
 
 
Income (Loss) before income taxes
19,880

 
(51,401
)
 
 
 
 
Income tax expense

 

Net income (loss)
$
19,880

 
$
(51,401
)
 
 
 
 
Net income (loss) per common share:
 
 
 
Basic
$
0.10

 
$
(0.42
)
Diluted
$
0.10

 
$
(0.42
)
 
 
 
 
Weighted-average shares outstanding:
 
 
 
Basic
200,707,891

 
121,392,736

Diluted
201,309,251

 
121,392,736

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

3

SYNERGY RESOURCES CORPORATION
(dba SRC ENERGY INC.)
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited; in thousands)

 
Three Months Ended March 31,
 
2017
 
2016
Cash flows from operating activities:
 
 
 
Net income (loss)
$
19,880

 
$
(51,401
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Depletion, depreciation, and accretion
13,229

 
12,092

Full cost ceiling impairment

 
45,621

Stock-based compensation
2,675

 
2,519

Mark-to-market of commodity derivative contracts:
 
 
 
Total gain on commodity derivatives contracts
(3,379
)
 
(1,680
)
Cash settlements on commodity derivative contracts
81

 
3,059

Changes in operating assets and liabilities:
 
 
 
Accounts receivable
(3,745
)
 
557

Accounts payable and accrued expenses
5,293

 
(1,075
)
Revenue payable
2,486

 
(3,132
)
Production taxes payable
(4,807
)
 
1,602

Other
(2,355
)
 
(40
)
Net cash provided by operating activities
29,358

 
8,122

 
 
 
 
Cash flows from investing activities:
 
 
 
Acquisitions of oil and gas properties and leaseholds
(25,082
)
 
(10,645
)
Capital expenditures for drilling and completion activities
(55,464
)
 
(22,581
)
Other capital expenditures
(2,416
)
 
(722
)
Land and other property and equipment
(2,101
)
 
(426
)
Cash held in escrow
29

 

Proceeds from sales of oil and gas properties
70,689

 

Net cash used in investing activities
(14,345
)
 
(34,374
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from equity offerings

 
92,575

Offering costs

 
(3,409
)
Payment of employee payroll taxes in connection with shares withheld
(431
)
 
(284
)
Proceeds from revolving credit facility
20,000

 

Principal repayments on revolving credit facility
(20,000
)
 
(78,000
)
Financing fees on amendments to revolving credit facility

 
(192
)
Net cash (used in) provided by financing activities
(431
)
 
10,690

 
 
 
 
Net increase (decrease) in cash and equivalents
14,582

 
(15,562
)
Cash and equivalents at beginning of period
18,615

 
66,499

Cash and equivalents at end of period
$
33,197

 
$
50,937

Supplemental Cash Flow Information (See Note 15)

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

4

SYNERGY RESOURCES CORPORATION
(dba SRC ENERGY INC.)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)




1.
Organization and Summary of Significant Accounting Policies

Organization: Synergy Resources Corporation, doing business as SRC Energy Inc., (the "Company") is a growth-oriented, independent oil and natural gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and natural gas liquids ("NGLs"), primarily in the Denver-Julesburg Basin ("D-J Basin") of Colorado. The Company has proposed to its shareholders that they approve a change in its legal name to "SRC Energy Inc." at its 2017 annual meeting. Pending the shareholder vote on the proposal, the Company began using the new name on a "doing business as" basis beginning on March 6, 2017. In addition to using the new name on a "doing business as" basis, the Company’s common stock, which is listed and traded on the NYSE MKT, changed to the new symbol "SRCI." Unless the context otherwise requires, references to "SRC Energy" and "SRC Energy Inc." in this report refer to the registrant, Synergy Resources Corporation and its consolidated subsidiaries.

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 to use "plain English" in public filings, the Company will use such terms as "we," "our," "us," or the "Company" in place of SRC Energy Inc. When such terms are used in this manner throughout this document, they are in reference only to the corporation, SRC Energy Inc., and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees.

The condensed consolidated financial statements include the accounts of the Company, including its wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.  The Company prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“US GAAP”).

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, 2016 was derived from the Company's Annual Report on Form 10-K for the year ended December 31, 2016 as filed with the SEC on February 23, 2017.  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 year ended December 31, 2016.

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.

Major Customers: The Company sells production to a small number of customers as is customary in the industry. Customers representing 10% or more of its oil, natural gas, and NGL revenue (“major customers”) for each of the periods presented are shown in the following table:
 
 
Three Months Ended March 31,
Major Customers
 
2017
 
2016
Company A
 
*
 
42%
Company B
 
22%
 
25%
Company C
 
31%
 
*
Company D
 
*
 
12%
Company E
 
23%
 
*
* less than 10%


5


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, natural gas, and NGL 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, natural gas, and NGL 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
 
March 31, 2017
 
December 31, 2016
Company A
 
24%
 
43%
Company B
 
*
 
10%
Company C
 
18%
 
23%
Company D
 
12%
 
*
* less than 10%

The Company operates exclusively within the United States of America and, except for cash and cash equivalents, all of the Company’s assets are utilized in, and all of its revenues are derived from, the oil and gas industry.

Recently Adopted Accounting Pronouncements:
    
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. ASU 2016-09 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 adopted this pronouncement effective January 1, 2017. Upon adoption of this standard, we no longer estimate the total number of awards for which the requisite service period will not be rendered, and effective January 1, 2017, we will account for forfeitures when they occur. We applied this accounting change on a modified retrospective basis with a cumulative-effect adjustment of $0.1 million to retained earnings as of the date of adoption. The adoption of the other provisions did not materially impact the consolidated financial statements.

In January 2017, the FASB issued ASU 2017-04, "Simplifying the Test for Goodwill Impairment" ("ASU 2017-04"), which removes the requirement to compare the implied fair value of goodwill with its carrying amount as part of step 2 of the goodwill impairment test. We adopted ASU 2017-04 on January 1, 2017, and it will be applied for any interim or annual goodwill impairment tests subsequent to that date. The adoption of this guidance is not expected to materially impact the consolidated financial statements.

Recently Issued Accounting Pronouncements:   We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new accounting pronouncements on us. 

In November 2016, the FASB issued ASU 2016-18, "Restricted Cash" ("ASU 2016-18"), which amends ASC 230 to add or clarify guidance on the classification and presentation of restricted cash in the statement of cash flows. Key requirements of ASU 2016-18 are as follows: 1) An entity should include in its cash and cash-equivalent balances in the statement of cash flows those amounts that are deemed to be restricted cash and restricted cash equivalents. ASU 2016-18 does not define the terms “restricted cash” and “restricted cash equivalents” but states that an entity should continue to provide appropriate disclosures about its accounting policies pertaining to restricted cash in accordance with other GAAP. ASU 2016-18 also states that any change in accounting policy will need to be assessed under ASC 250; 2) A reconciliation between the statement of financial position and the statement of cash flows must be disclosed when the statement of financial position includes more than one line item for cash, cash equivalents, restricted cash, and restricted cash equivalents; 3) Changes in restricted cash and restricted cash equivalents that result from transfers between cash, cash equivalents, and restricted cash and restricted cash equivalents should not be presented as cash flow activities in the statement of cash flows; and 4) An entity with a material balance of amounts generally described as restricted cash and restricted cash equivalents must disclose information about the nature of the restrictions. The guidance is effective for

6


fiscal years beginning after December 15, 2017, including interim periods therein. Early adoption is permitted, and we must apply the guidance retrospectively to all periods presented. We are currently evaluating the impact of the adoption of this standard 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 businesses 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 condensed 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. In March 2016, the FASB released certain implementation guidance through ASU 2016-08 (collectively with ASU 2014-09, the "Revenue ASUs") to clarify principal versus agent considerations. The Revenue ASUs allow 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. Currently, we have not identified any contracts that would require a change from the entitlements method, historically used for certain domestic natural gas sales, to the sales method of accounting. We are continuing to evaluate the provisions of these ASUs as pertinent to certain sales contracts and in particular as they relates to disclosure requirements.

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.

Change in estimate: During the three months ended March 31, 2017, the Company reduced its estimate for production taxes based on recent historical experience and additional information received during the period. As a result, the Company decreased the accrual for production taxes to be paid by approximately $2.0 million, which increased our operating income for the three months ended March 31, 2017 by a corresponding amount, or $0.01 per basic and diluted common share.


7


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
 
March 31, 2017
 
December 31, 2016
Oil and gas properties, full cost method:
 
 
 
Costs of unproved properties and land, not subject to depletion:
 
 
 
Lease acquisition and other costs
$
349,036

 
$
392,561

Land
6,231

 
5,986

Subtotal, unproved properties and land
355,267

 
398,547

 
 
 
 
Costs of wells in progress
82,664

 
81,780

 
 
 
 
Costs of proved properties:
 
 
 
Producing and non-producing
1,061,023

 
969,239

Less, accumulated depletion and full cost ceiling impairments
(558,694
)
 
(545,157
)
Subtotal, proved properties, net
502,329

 
424,082

 
 
 
 
Costs of other property and equipment:
 
 
 
Other property and equipment
6,939

 
5,063

Less, accumulated depreciation
(826
)
 
(736
)
Subtotal, other property and equipment, net
6,113

 
4,327

 
 
 
 
Total property and equipment, net
$
946,373

 
$
908,736


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. At March 31, 2017, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary. At March 31, 2016, the carrying value of our oil and gas properties subject to the test exceeded the calculated value of the ceiling limitation, resulting in an impairment of $45.6 million.

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 March 31,
 
2017
 
2016
Capitalized overhead
$
2,680

 
$
649


3.
Acquisitions and Divestitures

Acquisitions

The Company seeks to acquire developed and undeveloped oil and gas properties, primarily in the core Wattenberg Field. The objective of these acquisitions is to provide additional mineral acres upon which the Company can drill wells and produce hydrocarbons.

March 2017 Acquisition

In March 2017, we closed an acquisition comprised primarily of developed and undeveloped oil and gas leasehold interests for a total purchase price of $25.7 million, composed of cash and assumed liabilities.


8


Acquisitions in the Second Half of 2016

In August and October 2016, the Company completed four acquisitions of certain assets for a total purchase price of $13.5 million, composed of cash, forgiven receivables, and assumed liabilities. The acquired properties were comprised primarily of undeveloped oil and gas leasehold interests and additional interests in developed properties operated by the Company.

June 2016 Acquisition

In May 2016, we entered into a purchase and sale agreement (the "GC Agreement") with a large publicly-traded company pursuant to which we agreed to acquire a total of approximately 72,000 gross (33,100 net) acres in an area referred to as the Greeley-Crescent development area in the Wattenberg Field for $505.0 million (the "GC Acquisition").  Estimated net daily production from the acquired properties was approximately 2,400 BOE at the time of entering into the GC Agreement.

In June 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. A second closing will cover the operated producing properties and is expected to be completed in 2017. The Company has placed $18.2 million in escrow to be released upon the second closing. For the second closing, 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 $486.4 million, net of customary closing adjustments. The purchase price was composed of $485.1 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 and net production of approximately 800 BOED at the time of entering into the GC Agreement.

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 $0.5 million related to the acquisition were expensed as incurred. The following table summarizes the purchase price and final fair values of assets acquired and liabilities assumed (in thousands):
Preliminary Purchase Price
June 14, 2016
Consideration given:
 
Cash
$
485,141

Net liabilities assumed, including asset retirement obligations
1,273

Total consideration given
$
486,414

 
 
Preliminary Allocation of Purchase Price
 
Proved oil and gas properties (1)
$
132,903

Unproved oil and gas properties
353,511

Total fair value of assets acquired
$
486,414

(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 rate of 11.5%, and assumptions regarding the timing and amount of future development and operating costs.

For the three months ended March 31, 2017, the results of operations of the acquired assets, representing approximately $2.2 million of revenue and $1.8 million of operating income, respectively, have been included in the Company's condensed consolidated statements of operations.


9


The following table presents the unaudited pro forma combined results of operations for the three months ended March 31, 2016 as if the first closing had occurred on January 1, 2016.  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.
(in thousands)
Three Months Ended March 31, 2016
Oil, natural gas, and NGLs revenues
$
20,117

Net loss
$
(53,013
)
 
 
Net loss per common share
 
Basic
$
(0.27
)
Diluted
$
(0.27
)

February 2016 Acquisition

In February 2016, the Company completed the acquisition of undeveloped oil and gas leasehold interests for a total purchase price of $10.0 million. 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. This allocation reflects significant use of estimates.

Divestitures

During the three months ended March 31, 2017, we completed divestitures of acreage outside of the Company's core development area. The transactions resulted in the Company divesting approximately 10,600 net undeveloped acres and approximately 700 BOED of associated production for $76.8 million, comprised of cash and liabilities transferred to the buyers.

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 $24.7 million in cash and the assumption by the buyer of $0.5 million in liabilities. 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. In accordance with full cost accounting guidelines, the net proceeds were credited to the full cost pool.

4.
Depletion, depreciation, and accretion ("DD&A")

DD&A consisted of the following (in thousands):
 
Three Months Ended March 31,
 
2017
 
2016
Depletion of oil and gas properties
$
12,703

 
$
11,743

Depreciation and accretion
526

 
349

Total DD&A Expense
$
13,229

 
$
12,092


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 months ended March 31, 2017, production of 1,597 MBOE represented 1.1% of estimated total proved reserves. For the three months ended March 31, 2016, production of 1,047 MBOE represented 1.5% of estimated total proved reserves. DD&A expense was $8.28 per BOE and $11.55 per BOE for the three months ended March 31, 2017 and 2016, respectively.



10


5.
Asset Retirement Obligations

Upon completion or acquisition of a well, the Company recognizes obligations for its oil and natural gas operations for anticipated costs to remove and dispose of surface equipment, plug and abandon the wells, and restore the drilling site to its original use.  The estimated present value of such obligations is determined using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in regulations.  Changes in estimates are reflected in the obligations as they occur.  If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the capitalized asset retirement cost.  The following table summarizes the changes in asset retirement obligations associated with the Company's oil and gas properties (in thousands):
 
Three Months Ended March 31, 2017
Beginning asset retirement obligation, December 31, 2016
$
16,458

Obligations incurred with development activities
882

Obligations assumed with acquisitions
1,098

Accretion expense
312

Obligations discharged with sales, asset retirements, and settlements
(3,287
)
Revisions in previous estimates

Ending asset retirement obligation, March 31, 2017
$
15,463


6.
Revolving Credit Facility

The Company maintains a revolving credit facility (sometimes referred to as the "Revolver") with a bank syndicate with a maturity date of December 15, 2019. The Revolver is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes, and to support letters of credit. As of March 31, 2017, the terms of the Revolver provide for up to $500 million in borrowings, subject to a borrowing base limitation of $160 million. There was no outstanding principal balance as of March 31, 2017 and December 31, 2016. The Company has an outstanding letter of credit of approximately $0.5 million.

In April 2017, the lenders under our Revolver completed their regular semi-annual redetermination of our borrowing base.  The borrowing base was increased from $160 million to $225 million; however, the Company chose to limit its elected commitments to $210 million. The next semi-annual redetermination is scheduled for November 2017. As of April 30, 2017, the Company's outstanding principal balance was $25 million.

Interest under the Revolver accrues monthly 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 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 three months ended March 31, 2017 and 2016 was 2.8% and 2.5%, respectively.

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 or the Company so elects, an unscheduled redetermination could be undertaken.

The Revolver contains covenants that, among other things, restrict the payment of dividends and limit our overall commodity derivative position to a maximum position that varies over 5 years as a percentage of estimated proved developed producing or total proved reserves 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 of any fiscal quarter permit its current ratio, as defined in the agreement, to be less than 1.0 to 1.0. As of March 31, 2017, the most recent compliance date, the Company was in compliance with these covenants and expects to remain in compliance throughout the next 12-month period.


11


7.
Notes Payable

In June 2016, the Company issued $80 million aggregate principal amount of 9% Senior 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 Senior Notes accrues at 9% 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 $75.2 million after deductions of $4.8 million for expenses and underwriting discounts and commissions. The associated expenses and underwriting discounts and commissions are amortized using the interest method at an effective interest rate of 10.6%. 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% 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% 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 things: (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 March 31, 2017, the most recent compliance date, the Company 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 volumes and commodities covered and the relevant strike 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, at settlement, 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

12


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 condensed 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 condensed 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 condensed consolidated statements of cash flows.

The Company’s commodity derivative contracts as of March 31, 2017 are summarized below:
Settlement Period
 
Derivative
Instrument
 
Average Volumes
(Bbls
per month)
 
Floor
Price
 
Ceiling
Price
Oil - NYMEX WTI
 
 
 
 
 
 
 
 
Apr 1, 2017 - Dec 31, 2017
 
Collar
 
30,556
 
$
40.00

 
$
60.00

Apr 1, 2017 - Dec 31, 2017
 
Collar
 
20,000
 
$
45.00

 
$
70.00

Apr 1, 2017 - Dec 31, 2017
 
Collar
 
30,556
 
$
40.00

 
$
65.00

Apr 1, 2017 - Apr 30, 2017
 
Put
 
20,000
 
$
50.00

 
$

May 1, 2017 - Aug 31, 2017
 
Put
 
20,000
 
$
55.00

 
$

Apr 1, 2017 - Dec 31, 2017
 
Collar
 
30,556
 
$
40.00

 
$
65.00

Apr 1, 2017 - Dec 31, 2017
 
Collar
 
15,278
 
$
45.00

 
$
65.00

Apr 1, 2017 - Dec 31, 2017
 
Collar
 
15,278
 
$
45.00

 
$
65.10

 
 
 
 
 
 
 
 
 
Settlement Period
 
Derivative
Instrument
 
Average Volumes
(MMBtu
per month)
 
Floor
Price
 
Ceiling
Price
Natural Gas - NYMEX Henry Hub
 
 
 
 
 
 
 
 
Apr 1, 2017 - Dec 31, 2017
 
Collar
 
100,000
 
$
2.75

 
$
4.00

Apr 1, 2017 - Dec 31, 2017
 
Collar
 
152,778
 
$
2.75

 
$
3.90

Sep 1, 2017 - Dec 31, 2017
 
Collar
 
91,500
 
$
2.75

 
$
4.10

Sep 1, 2017 - Dec 31, 2017
 
Collar
 
15,250
 
$
3.00

 
$
4.31

Apr 1, 2017 - Dec 31, 2017
 
Collar
 
110,000
 
$
3.00

 
$
4.30

 
 
 
 
 
 
 
 
 
Natural Gas - CIG Rocky Mountain
 
 
 
 
 
 
 
 
Apr 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

Apr 1, 2017 - Dec 31, 2017
 
Collar
 
200,000
 
$
2.50

 
$
3.27

Apr 1, 2017 - Dec 31, 2017
 
Collar
 
100,000
 
$
2.60

 
$
3.20


13



Subsequent to March 31, 2017, the Company added the following positions:
Settlement Period
 
Derivative
Instrument
 
Average Volumes
(MMBtu
per month)
 
Floor
Price
 
Ceiling
Price
Natural Gas - NYMEX Henry Hub
 
 
 
 
 
 
 
 
May 1, 2017 - Dec 31, 2017
 
Collar
 
199,063
 
$
3.00

 
$
3.88

May 1, 2017 - Dec 31, 2017
 
Collar
 
199,063
 
$
3.00

 
$
3.91


Offsetting of Derivative Assets and Liabilities

As of March 31, 2017 and December 31, 2016, 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 condensed consolidated balance sheets.

The following table provides a reconciliation between the net assets and liabilities reflected on the accompanying condensed 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 March 31, 2017
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
 
$
1,740

 
$
(1,118
)
 
$
622

Commodity derivative contracts
 
Noncurrent assets
 
$

 
$

 
$

Commodity derivative contracts
 
Current liabilities
 
$
1,163

 
$
(1,118
)
 
$
45

Commodity derivative contracts
 
Noncurrent liabilities
 
$

 
$

 
$


 
 
 
 
As of December 31, 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
 
$
2,045

 
$
(1,748
)
 
$
297

Commodity derivative contracts
 
Noncurrent assets
 
$

 
$

 
$

Commodity derivative contracts
 
Current liabilities
 
$
4,622

 
$
(1,748
)
 
$
2,874

Commodity derivative contracts
 
Noncurrent liabilities
 
$

 
$

 
$


The amount of gain (loss) recognized in the condensed consolidated statements of operations related to derivative financial instruments was as follows (in thousands):
 
Three Months Ended March 31,
 
2017
 
2016
Realized gain (loss) on commodity derivatives
$
(119
)
 
$
2,445

Unrealized gain (loss) on commodity derivatives
3,498

 
(765
)
Total gain
$
3,379

 
$
1,680



14


Realized gains and losses include cash received from the monthly settlement of derivative contracts at their scheduled maturity date and the previously incurred premiums attributable to settled commodity contracts. The following table summarizes derivative realized gains and losses during the periods presented (in thousands):
 
Three Months Ended March 31,
 
2017
 
2016
Monthly settlement
$
225

 
$
2,955

Previously incurred premiums attributable to settled commodity contracts
(344
)
 
(510
)
Total realized (loss) gain
$
(119
)
 
$
2,445


Credit Related Contingent Features

As of March 31, 2017, 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 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 unproved properties, asset retirement obligations, and purchase price allocations for the fair value of assets and liabilities acquired through business combinations. Please refer to Notes 2, 3, and 5 for further discussion of unproved properties, business combinations, and asset retirement obligations, respectively.

The Company determines the estimated fair value of its unproved properties using market comparables which are deemed to be a Level 3 input. See Note 2 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 natural 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, the fair value is determined using the same inputs as described in the paragraph above. For the asset retirement liability assumed, the fair value is determined using the same inputs as described in the paragraph below. See Note 3 for additional information.

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

15


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 following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2017 and December 31, 2016 by level within the fair value hierarchy (in thousands):
 
Fair Value Measurements at March 31, 2017
 
Level 1
 
Level 2
 
Level 3
 
Total
Financial assets and liabilities:
 
 
 
 
 
 
 
Commodity derivative asset
$

 
$
622

 
$

 
$
622

Commodity derivative liability
$

 
$
45

 
$

 
$
45

 
Fair Value Measurements at December 31, 2016
 
Level 1
 
Level 2
 
Level 3
 
Total
Financial assets and liabilities:
 
 
 
 
 
 
 
Commodity derivative asset
$

 
$
297

 
$

 
$
297

Commodity derivative liability
$

 
$
2,874

 
$

 
$
2,874


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 March 31, 2017, derivative instruments utilized by the Company consist of puts and collars. The 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 and are not openly traded on an exchange. 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, cash held in escrow, accounts receivable, accounts payable, commodity derivative instruments (discussed above), notes payable, and credit facility borrowings. The carrying values of cash and cash equivalents, cash held in escrow, 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 $85.9 million at March 31, 2017. The Company determined the fair value of its notes payable at March 31, 2017 by using observable market based information for debt instruments of similar amounts and duration. The Company has classified the notes as Level 2.

10.
Interest Expense

The components of interest expense are (in thousands):
 
Three Months Ended March 31,
 
2017
 
2016
Revolving bank credit facility
$
43

 
$
141

Notes payable
1,800

 

Amortization of issuance costs
500

 
295

Less, interest capitalized
(2,343
)
 
(436
)
Interest expense, net
$

 
$



16


11.
Weighted-Average Shares Outstanding

The following table sets forth the Company's outstanding equity grants which have a dilutive effect on earnings per share:
 
Three Months Ended March 31,
 
2017
 
2016
Weighted-average shares outstanding - basic
200,707,891

 
121,392,736

Potentially dilutive common shares from:
 
 
 
Stock options
461,103

 

Restricted stock units and stock bonus shares
140,257

 

Performance-vested stock units1

 

Weighted-average shares outstanding - diluted
201,309,251

 
121,392,736

1 The number of awards assumes that the associated vesting condition is met at the respective period end. 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.

The following potentially dilutive securities outstanding for the periods presented were not included in the respective weighted-average shares outstanding-diluted calculation above as such securities had an anti-dilutive effect on earnings per share:
 
Three Months Ended March 31,
 
2017
 
2016
Potentially dilutive common shares from:
 
 
 
Stock options
4,722,500

 
5,545,500

Restricted stock units and stock bonus shares
605,252

 
1,136,401

Performance stock units 1
951,884

 
464,946

Total
6,279,636

 
7,146,847

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.

12.
Stock-Based Compensation

In addition to cash compensation, the Company may compensate employees and directors with equity-based compensation in the form of stock options, performance-vested stock units, 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 either classified as a component within general and administrative expense in the Company's condensed 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 March 31,
 
2017
 
2016
Stock options
$
1,246

 
$
1,410

Performance stock units
525

 

Restricted stock units and stock bonus shares
1,346

 
1,212

Total stock-based compensation
$
3,117

 
$
2,622

Less: stock-based compensation capitalized
(442
)
 
(103
)
Total stock-based compensation expensed
$
2,675

 
$
2,519



17


General Description of Stock Award Plans

In December 2015, the Company's shareholders approved the 2015 Equity Incentive Plan (the "2015 Plan"). The 2015 Plan replaced three equity compensation plans: (i) a 2011 non-qualified stock option plan, (ii) a 2011 incentive stock option plan, and (iii) a 2011 stock bonus plan (the "2011 Plans").  No additional options or stock bonus shares will be issued under the 2011 Plans.

The 2015 Plan authorizes stock options, stock appreciation rights, restricted stock, restricted stock units, stock bonuses, and other forms of awards that may be granted or denominated in the Company’s common stock or units of the Company’s common stock as well as cash bonus awards.  Employees, directors, officers, consultants, and advisors are eligible to receive such awards, provided that bona fide services are rendered by such consultants or advisors (other than services in connection with the offering or sale of securities or as a market maker or promoter of securities of the Company).

As of March 31, 2017, there were 4,500,000 common shares authorized for grant under the 2015 Plan, of which 1,165,432 shares were remaining for future issuance.

Stock options

During the periods presented, the Company granted the following stock options:
 
Three Months Ended March 31,
 
2017
 
2016
Number of options to purchase common shares

 
489,500

Weighted-average exercise price
$

 
$
7.72

Term (in years)

 
10 years

Vesting Period (in years)

 
3 - 5 years

Fair Value (in thousands)
$

 
$
1,729


The assumptions used in valuing stock options granted during each of the periods presented were as follows:
 
Three Months Ended March 31,
 
2017
 
2016
Expected term

 
6.3 years

Expected volatility
%
 
55
%
Risk free rate

 
1.50 - 1.75%

Expected dividend yield
%
 
%

The following table summarizes activity for stock options for the periods presented:
 
Number of Shares
 
Weighted-Average Exercise Price
 
Weighted-Average Remaining Contractual Life
 
Aggregate Intrinsic Value (thousands)
Outstanding, December 31, 2016
6,001,500

 
$
9.27

 
8.0 years
 
$
6,515

Granted

 

 
 
 
 
Exercised
(30,000
)
 
3.79

 
 
 
140

Expired
(30,000
)
 
12.35

 
 
 
 
Forfeited
(68,000
)
 
11.78

 
 
 
 
Outstanding, March 31, 2017
5,873,500

 
$
9.25

 
7.7 years
 
$
5,343

Outstanding, Exercisable at March 31, 2017
2,529,861

 
$
8.42

 
6.8 years
 
$
3,783



18


The following table summarizes information about issued and outstanding stock options as of March 31, 2017:
 
 
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
 
600,000

4.4 years
$
3.49

 
559,000

$
3.47

$5.00 - $6.99
 
1,012,000

7.7 years
6.38

 
480,000

6.45

$7.00 - $10.99
 
1,594,500

8.2 years
9.34

 
484,661

9.48

$11.00 - $13.46
 
2,667,000

8.2 years
11.57

 
1,006,200

11.61

Total
 
5,873,500

7.7 years
$
9.25

 
2,529,861

$
8.42


The estimated unrecognized compensation cost from stock options not vested as of March 31, 2017, which will be recognized ratably over the remaining vesting phase, is as follows:
Unrecognized compensation (in thousands)
$
13,891

Remaining vesting phase
3.0 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 three months ended March 31, 2017:
 
Number of Shares
 
Weighted-Average Grant-Date Fair Value
Not vested, December 31, 2016
890,336

 
$
9.55

Granted
531,454

 
8.61

Vested
(180,927
)
 
8.86

Forfeited
(14,022
)
 
10.59

Not vested, March 31, 2017
1,226,841

 
$
9.22


The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of March 31, 2017, which will be recognized ratably over the remaining vesting phase, is as follows:
Unrecognized compensation (in thousands)
$
9,798

Remaining vesting phase
2.7 years


Performance-vested stock units

The Company grants 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

19


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:
 
Three Months Ended March 31,
 
2017
 
2016
Weighted average expected term
2.9 years

 
2.8 years

Weighted average expected volatility
59
%
 
58
%
Weighted average risk free rate
1.34
%
 
0.87
%

During the three months ended March 31, 2017, the Company granted 473,374 PSUs to certain executives. The fair value of the PSUs granted during the three months ended March 31, 2017 was $5.1 million. As of March 31, 2017, unrecognized compensation expense for PSUs was $7.4 million and will be amortized through 2018. A summary of the status and activity of PSUs is presented in the following table:
 
Number of Units1
 
Weighted-Average Grant-Date Fair Value
Not vested, December 31, 2016
478,510

 
$
8.09

Granted
473,374

 
10.79

Vested

 

Forfeited

 

Not vested, March 31, 2017
951,884

 
$
9.44

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.
Income Taxes

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. 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 three months ended March 31, 2017 was nil compared to nil for the three months ended March 31, 2016. The effective tax rate for the three months ended March 31, 2017 and 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. There were no significant discrete items recorded during the three months ended March 31, 2017 and 2016.

As of March 31, 2017, 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

20


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 March 31, 2017.  The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of March 31, 2017, 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 March 31, 2017, we have provided a full valuation allowance reducing the net realizable benefits.

14.
Other Commitments and Contingencies

Volume Commitments

During 2014, the Company entered into firm sales agreements for its oil production with three counterparties. Deliveries under two of the agreements commenced in 2015. Deliveries under the third agreement commenced in 2016. Pursuant to these agreements, we must deliver specific amounts of oil either from our own production or from oil that 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. Our commitments over the next five years, excluding the contingent commitment described below, are as follows:
Year ending December 31,
 
Oil
 
(MBbls)
Remainder of 2017
 
3,030

2018
 
4,255

2019
 
4,255

2020
 
3,700

2021
 
1,672

Thereafter
 

Total
 
16,912


During the three months ended March 31, 2017, the Company incurred deficiency charges of $0.7 million as we were unable to meet all of the obligations during the period. We anticipate that our current gross operated production will meet our delivery obligations beginning in the second quarter of 2017.

In collaboration with several other producers and DCP Midstream, we have agreed to participate in the expansion of natural gas gathering and processing capacity in the D-J Basin.  The plan includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system, both currently expected to be completed by late 2018, although the start-up date is undetermined at this time. Our share of the commitment will require 46.4 MMcf per day to be delivered after the plant in-service date for a period of 7 years. This contractual obligation can be reduced by the collective volumes delivered to the plant by other producers in the D-J Basin that are in excess of such producers' total commitment.


21


Office leases

In September 2016, the Company entered into a new sixty-five-month lease for the Company’s principal office space located in Denver, which commenced in the first quarter of 2017. Rent under the new lease is approximately $62,000 per month. In July 2016, the Company entered into a field office lease in Greeley which requires monthly payments of $7,500 through October 2021. A schedule of the minimum lease payments under non-cancelable operating leases as of March 31, 2017 follows (in thousands):
Year ending December 31,
 
Rent
 
Remainder of 2017
 
$
377

2018
 
840

2019
 
859

2020
 
878

2021
 
875

Thereafter
 
477

Total
 
$
4,306


Rent expense for offices leases was $0.4 million and $0.1 million for three months ended March 31, 2017 and 2016, respectively.

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.
    
In July 2016, the Company was informed by the 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. A subsequent February 2017 tolling agreement between the Company and CDPHE addressed alleged similar storage tank leakage issues at other Company facilities in Colorado. We are working with the CDPHE to respond to any continuing concerns. We cannot predict the outcome of this matter, but we expect that any potential resolution of these claims would be on a field-wide basis.

15.
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):
 
Three Months Ended March 31,
Supplemental cash flow information:
2017
 
2016
Interest paid
$
43

 
$
146

 
 
 
 
Non-cash investing and financing activities:
 
 
 
Accrued well costs as of period end
$
81,722

 
$
15,324

Obligations incurred with development activities
882

 

Obligations assumed with acquisitions
1,098

 

Obligations discharged with asset retirements and divestitures
(3,287
)
 



22


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

Introduction

The following discussion and analysis was prepared to supplement information contained in the accompanying condensed consolidated financial statements and is intended to explain certain items regarding the Company's financial condition as of March 31, 2017, and its results of operations for the three months ended March 31, 2017 and 2016.  It should be read in conjunction with the “Selected Financial Data” and the accompanying audited consolidated financial statements and related notes thereto contained in the Annual Report on Form 10-K for the year ended December 31, 2016 filed with the SEC on February 23, 2017. Unless the context otherwise requires, references to "SRC Energy," "SRC Energy Inc.," "we," "us," "our," or the "Company" in this report refer to the registrant, Synergy Resources Corporation, doing business as SRC Energy Inc., and its subsidiaries.

This section and other parts of this Quarterly Report on Form 10-Q contain forward-looking statements that involve risks and uncertainties.  See the “Cautionary Statement Concerning Forward-Looking Statements” elsewhere in this Quarterly Report on Form 10-Q.  Forward-looking statements are not guarantees of future performance, and our actual results may differ significantly from the results discussed in the forward-looking statements.  Factors that might cause such differences include, but are not limited to, those discussed in “Risk Factors”.  We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law.

As of January 1, 2017, our natural gas processing agreements with DCP Midstream had been modified to allow us to take title to the NGLs resulting from the processing of our natural gas. Based on this, we began reporting reserves, sales volumes, prices, and revenues for natural gas and NGLs separately for periods after January 1, 2017. For periods prior to January 1, 2017, we did not separately report reserves, sales volumes, prices, and revenues for NGLs as we did not take title to these NGLs. Instead, the value attributable to these unrecognized NGL volumes was included within natural gas revenues as an increase to the overall price received. This change impacts the comparability of 2017 with prior periods.

Overview

SRC Energy is a growth-oriented, independent oil and gas company engaged in the acquisition, development, and production of oil, natural gas, and NGLs in the D-J Basin, which we believe to be one of the premier, liquids-rich oil and natural gas resource plays in the United States. 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 natural 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 in Weld County, Colorado, an area that covers the western flank of the D-J Basin. Currently, we are focused on the horizontal development of the Codell and Niobrara formations, which are characterized by relatively high liquids content.

In order to maintain operational focus while preserving developmental flexibility, we strive to attain operational control of a majority of the wells in which we have a working interest. We currently operate approximately 88% of our proved producing reserves and anticipate operating substantially all of our future net drilling locations. Additionally, our current development plan anticipates that all of our future activities will be concentrated in the Wattenberg Field.

Market Conditions

Market prices for our products significantly impact our revenues, net income, and cash flow.  The market prices for oil, natural gas, and NGL 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 years.
 
Year Ended December 31,
 
Year Ended August 31,
 
2016
 
2015
 
2015
 
2014
 
2013
 
2012
Average NYMEX prices
 
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
$
43.20

 
$
48.73

 
$
60.65

 
$
100.39

 
$
94.58

 
$
94.88

Natural gas (per Mcf)
$
2.52

 
$
2.58

 
$
3.12

 
$
4.38

 
$
3.55

 
$
2.82



23


For the periods presented in this report, the following table presents the Reference Price (derived from average NYMEX prices) as well as the differential between the Reference Price and the prices realized by us.
 
Three Months Ended March 31,
Oil (NYMEX WTI)
2017
 
2016
Average NYMEX Price
$
51.91

 
$
33.18

Realized Price
$
42.87

 
$
23.89

Differential
$
(9.04
)
 
$
(9.29
)
 
 
 
 
Natural Gas (NYMEX Henry Hub)
 
 
 
Average NYMEX Price
$
3.01

 
$
2.00

Realized Price
$
2.66

 
$
1.82

Differential
$
(0.35
)
 
$
(0.18
)
 
 
 
 
NGL Realized Price
$
15.94

 
$


Market conditions in the Wattenberg Field require us to sell oil at prices less than the prices posted by the NYMEX. The 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. With regard to the sale of oil, substantially all of the Company's oil production was sold to the counterparties of its firm sales commitments. Beginning in the second quarter of 2017, the Company anticipates that its oil production will exceed its firm sales commitments. Any surplus oil production is expected to be sold at a reduced differential as compared to our committed volumes. With regard to the sale of natural gas, prior to January 1, 2017, the price we received included payment for a percentage of the value attributable to the natural gas liquids produced with the natural gas. Beginning in first quarter 2017, natural gas liquids and dry natural gas volumes are disclosed separately, and NGL revenues will replace the premium to dry natural gas prices that the Company historically realized on its wet natural gas sales volumes.

There has been significant volatility in the price of oil and natural gas since mid-2014.  As reflected in published data, the price for WTI oil settled at $53.75 per Bbl on Friday, December 30, 2016.  Comparably, the price of oil settled at $50.54 per Bbl on Friday, March 31, 2017, a decline of 6% from December 30, 2016. Our revenues, results of operations, profitability and future growth, and the carrying value of our oil and gas properties depend primarily on the prices that we receive for our oil, natural gas, and NGL production.

A decline in oil and natural gas prices will adversely affect our financial condition and results of operations.  Furthermore, low oil and natural gas prices can result in an impairment of the value of our properties and impact the calculation of the “ceiling test” required under the accounting principles for companies following the “full cost” method of accounting. At March 31, 2017, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary.   However, if pricing conditions decline, we may incur a full cost ceiling impairment related to our oil and gas properties in future quarters.

Core Operations

The following table provides details about our ownership interests with respect to vertical and horizontal producing wells as of March 31, 2017:
Vertical Wells
Operated Wells
 
Non-Operated Wells
 
Totals
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
175

 
153

 
129

 
31

 
304

 
184

Horizontal Wells
Operated Wells
 
Non-Operated Wells
 
Totals
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
137

 
132

 
158

 
29

 
295

 
161



24


In addition to the producing wells summarized in the preceding table, as of March 31, 2017, we were the operator of 51 gross (46 net) wells in progress, which excludes 21 gross (13 net) wells for which we have only set surface casings.

As we develop our acreage through horizontal drilling, we have an active program for plugging and abandoning vertical wellbores with a vast majority of the operated wells planned to be plugged over the next year. During the three months ended March 31, 2017, we plugged 26 wells and returned the associated acreage to the property owners.

Production

For the three months ended March 31, 2017, our average daily production increased to 17,743 BOED as compared to 11,510 BOED for the three months ended March 31, 2016. For periods prior to January 1, 2017, we presented our production for natural gas and NGLs on a combined basis and did not separately report NGLs. This change impacts the comparability of 2017 with prior periods. As of March 31, 2017, approximately 98% 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. 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 gas properties.  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 what we believe to be industry best practices in our effort to determine the optimal recovery area for each well. Early horizontal well development in the Wattenberg Field generally assumed optimal recoveries would be obtained utilizing between 12 and 16 wells per 640-acre section. As horizontal well development has matured, well density assumptions have generally increased beyond 16 wells per section depending on the specific area of the field being drilled.
 
Complete selective acquisitions.  We seek to acquire developed and undeveloped oil and gas properties, primarily in the 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.  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 development objective for individual well optimization is to drill and complete wells with lateral lengths of 7,000' to 10,000'. Utilizing petrophysical and seismic data, a 3-D model is developed for each leasehold section to assist in determining optimal wellbore placement, well spacing, and stimulation design. This process is augmented with formation-specific drilling and completion execution designs and coupled with localized production results to provide a continuous improvement philosophy in optimizing the value per acre of our leasehold throughout our development program.


25


Significant Developments

We continue to be opportunistic with respect to acquisition efforts to increase our working interests and drilling location inventory. Further, in an effort to extend the length of laterals and/or increase working interests in our wells, we will continue to enter into land and working interest swaps.

Acquisitions

In March 2017, we closed an acquisition comprised primarily of developed and undeveloped oil and gas leasehold interests for a total purchase price of $25.7 million, composed of cash and assumed liabilities.

Divestitures

During the three months ended March 31, 2017, we completed divestitures of acreage outside of the Company's core development area. The transactions resulted in the Company divesting approximately 10,600 net undeveloped acres and approximately 700 BOED of associated production for $76.8 million, comprised of cash and liabilities transferred to the buyers.
 
Revolving Credit Facility

In April 2017, the lenders under our revolving credit facility (sometimes referred to as the "Revolver") completed their regular semi-annual redetermination of our borrowing base.  The borrowing base was increased from $160 million to $225 million; however, the Company chose to limit aggregate elected commitments to $210 million. The next semi-annual redetermination is scheduled for November 2017. Due to outstanding letters of credit, approximately $159.5 million of the borrowing base was available to use for future borrowings as of March 31, 2017. As of April 30, 2017, we have borrowed $25 million under the Revolver.

Drilling and Completion Operations

Our drilling and completion schedule drives our production forecast and our expected future cash flows. We have been able to reduce per-well drilling and completion costs significantly over the past two years. 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. Should commodity prices weaken further or our costs escalate significantly, our operational flexibility will allow us to adjust our drilling and completion schedule, if prudent. If the well-level internal rate of return is at or below our weighted-average cost of capital, we may choose to delay completions and/or forego drilling altogether. Conversely, if commodity prices move higher, we may choose to accelerate drilling and completion activities.

During the three months ended March 31, 2017, we drilled 31 operated horizontal wells and completed 25 operated horizontal wells. As of March 31, 2017, we are the operator of 51 gross (46 net) horizontal wells in progress, which excludes 21 gross (13 net) horizontal wells for which we have only set surface casings. For 2017, we expect to drill 116 gross operated horizontal wells, primarily mid-length and long laterals targeting the Codell and Niobrara formations.

As of March 31, 2017, we are participating in 28 gross (2 net) non-operated horizontal wells in progress.

Trends and Outlook

Oil traded at $53.75 per Bbl on December 30, 2016, but has since declined approximately 6% as of March 31, 2017 to $50.54. Natural gas traded at $3.72 per Mcf on December 30, 2016, but declined approximately 16% as of March 31, 2017 to $3.13. Oil prices continue to remain significantly lower than they were in the first half of 2014, when they were near $100/bbl. Lower oil prices (i) reduce our cash flow which, in turn, could reduce the funds available for exploring and replacing oil and natural gas reserves, (ii) 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) 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 natural gas reserves in relation to the costs of exploration, (v) may result in marginally productive oil and natural gas wells being abandoned as non-commercial, and (vi) may cause ceiling test impairments.

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 volume commitment obligations, (iv) completion of acquisitions of additional properties and reserves, and (v) competition from other oil and gas companies.


26


We utilize what we believe to be industry best practices in our effort to achieve optimal hydrocarbon recoveries.  Currently, our practice is to drill 16 to 24 horizontal wells per 640-acre section depending upon specific geologic attributes and existing vertical wellbore development.  Some operators are testing higher density programs, but we believe that it is too early to determine whether the recoveries justify the additional capital cost.

The decline in commodity prices since mid-2014 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 due to a combination of optimizing well designs, 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 oil and natural gas. We continue to strive to reduce drilling and completion costs going forward, but as commodity prices improve and industry activity increases, we are experiencing higher service costs causing well-level rates of return to be lower.

From time to time, our production has been adversely impacted by high natural gas gathering line pressures. Where it is cost effective, we install wellhead compression to enhance our ability to inject natural gas into the gathering system and, in some instances, install larger gathering lines to help mitigate the impact of high line pressures. Additionally, midstream companies that operate the natural gas gathering pipelines in the area continue to make significant capital investments to increase the capacity of their systems. While these actions have helped reduce overall line pressures in the field, some of our producing locations have been curtailed on occasion due to line pressures exceeding system limits.

To address natural gas production in the D-J Basin, DCP Midstream has announced plans for multiple projects including new processing plants, low pressure gathering systems, additional compression, and plant bypass infrastructure. Most notably, in collaboration with DCP Midstream, we and several other producers have agreed to participate in the expansion of natural gas gathering and processing capacity in the D-J Basin.  The initial plan includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system, both expected to be completed by late 2018. Additionally, through the same framework, all of the parties are working to form a cooperative development plan to add another 200 MMcf/d plant by mid-2019.

We have extended the use of oil gathering lines to certain production locations. These gathering systems are owned and operated by independent third parties, and we commit specific wells to these systems. We believe that oil gathering lines 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) reduced on-site oil storage capacity, resulting in lower production location facility costs, and d) generally improved community relations.

Oil transportation and takeaway capacity has 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. We strive to reduce the negative differential that we have historically realized on our oil production depending on transportation commitments, local refinery demand, and our production volumes, . Further details regarding posted prices and average realized prices are discussed in "-Market Conditions."

As of March 31, 2017, we have identified over 1,200 drilling locations across our acreage position. For 2017, we expect to drill 116 gross operated horizontal wells of mostly mid-length and long laterals targeting the Codell and Niobrara zones. We anticipate this drilling and completion program will cost between $320 million and $340 million and will lead to a significant increase in production and associated proved developed producing reserves while allowing us to retain significant operational and financial flexibility to reduce or accelerate activity in response to changing economic conditions. Full-year 2017 production is forecasted to be between 25,000 BOED and 27,000 BOED.

Other than the foregoing, we do not know of any trends, events, or uncertainties that 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 condensed consolidated statements of operations included in our condensed consolidated financial statements for the periods presented are discussed below.

For the three months ended March 31, 2017 compared to the three months ended March 31, 2016

For the three months ended March 31, 2017, we reported net income of $19.9 million compared to net loss of $51.4 million during the three months ended March 31, 2016. Net income per basic and diluted share was $0.10 for the three months ended March 31, 2017 compared to net loss per basic and diluted share of $0.42 for the three months ended March 31, 2016. Net income per basic share for the three months ended March 31, 2017 increased by $0.52 primarily due to the ceiling test impairment

27


of $45.6 million incurred during the three months ended March 31, 2016 and the fact that no ceiling test impairment occurred during the three months ended March 31, 2017. Revenues increased 140% during the three months ended March 31, 2017 compared with the three months ended March 31, 2016 due to a 57% increase of realized prices and a 54% increase in production. As of March 31, 2017, we had 599 gross producing wells, of which 295 were horizontal, compared with 618 gross producing wells, of which 216 were horizontal, as of March 31, 2016.

Oil, Natural Gas, and NGL Production and Revenues - For the three months ended March 31, 2017, we recorded total oil, natural gas, and NGL revenues of $43.8 million compared to $18.3 million for the three months ended March 31, 2016, an increase of $25.5 million or 140%. The following table summarizes key production and revenue statistics:
 
Three Months Ended March 31,
 
Percentage
 
2017
 
2016
 
Change
Production:
 
 
 
 
 
Oil (MBbls) 1
680

 
527

 
29
%
Natural Gas (MMcf) 2
3,446

 
3,121

 
10
%
NGLs (MBbls) 3
343

 

 
nm

MBOE 4
1,597

 
1,047

 
53
%
    BOED 5
17,743

 
11,510

 
54
%
 
 
 
 
 
 
Revenues (in thousands):
 
 
 
 
 
Oil
$
29,149

 
$
12,594

 
131
%
Natural Gas
$
9,179

 
$
5,679

 
62
%
NGLs
$
5,462

 
$

 
nm

 
$
43,790

 
$
18,273

 
140
%
Average sales price:
 
 
 
 
 
Oil
$
42.87

 
$
23.89

 
79
%
Natural Gas
$
2.66

 
$
1.82

 
46
%
NGLs
$
15.94

 
$

 
nm

BOE
$
27.42

 
$
17.45

 
57
%
1 "MBbl" refers to one thousand stock tank barrels, or 42,000 U.S. gallons liquid volume in reference to oil or other liquid hydrocarbons.
2 "MMcf" refers to one million cubic feet of natural gas.
3 For periods prior to January 1, 2017, we did not separately report sales volumes, prices, and revenues for NGLs as we did not take title to these NGLs. Instead, the value attributable to these unrecognized NGL volumes was included within natural gas revenues as an increase to the overall price received. This change impacts the comparability of the two periods presented.
4 "MBOE" refers to one thousand barrels of oil equivalent, which combines MBbls of oil and MMcf of natural gas by converting each six MMcf of natural gas to one MBbl of oil.
5 "BOED" refers to the average number of barrels of oil equivalent produced in a day for the period.

Net oil, natural gas, and NGL production for the three months ended March 31, 2017 averaged 17,743 BOED, an increase of 54% over average production of 11,510 BOED in the three months ended March 31, 2016. From March 31, 2016 to March 31, 2017, our well count increased by 58 net horizontal wells, growing our reserves and daily production totals. Additionally, our conversion to three stream accounting positively impacted production in the current period. The 57% increase in average sales prices and increased production resulted in a significant increase in revenues.


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Lease Operating Expense ("LOE") - Direct operating costs of producing oil and natural gas are reported as follows (in thousands):
 
Three Months Ended March 31,
 
2017
 
2016
Production costs
$
3,473

 
$
4,266

Workover
249

 
33

Total LOE
$
3,722

 
$
4,299

 
 
 
 
Per BOE:
 
 
 
Production costs
$
2.17

 
$
4.07

Workover
0.16

 
0.03

Total LOE
$
2.33

 
$
4.10


Lease operating and workover costs tend to increase or decrease primarily in relation to the number and type of wells in production and, to a lesser extent, on fluctuations in oil field service costs and changes in the production mix of oil and natural gas. During the three months ended March 31, 2017, we experienced decreased production expense compared to March 31, 2016 primarily due to efforts by the operations group on cost management, the consolidation of our operations into a more central geographic operating area, and reduction of our total number of vertical wells through divestitures and plugging activities. Unit operating costs benefited from significant increases in production from 25 horizontal wells turning to sales during the quarter in addition to the wells turned to sales after the first quarter of 2016.

Production taxes - During the three months ended March 31, 2017, the Company reduced its estimate for production taxes based on recent historical experience and additional information received during the period. Based on this analysis, the Company's prior year accruals were reduced, resulting in an approximate $2.0 million reduction to our production taxes. During the three months ended March 31, 2017, production taxes were $1.5 million, or $0.92 per BOE, compared to $1.8 million, or $1.75 per BOE, during the prior year period. Taxes tend to increase or decrease primarily based on the value of production sold. As a percentage of revenues, production taxes were 3.3% and 10.0% for the three months ended March 31, 2017 and 2016, respectively.

DD&A - The following table summarizes the components of DD&A:
 
Three Months Ended March 31,
(in thousands)
2017
 
2016
Depletion of oil and gas properties
$
12,703

 
$
11,743

Depreciation and accretion
526

 
349

Total DD&A
$
13,229

 
$
12,092

 
 
 
 
DD&A expense per BOE
$
8.28

 
$
11.55


For the three months ended March 31, 2017, DD&A was $8.28 per BOE compared to $11.55 per BOE for the three months ended March 31, 2016. 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 that primarily occurred during the first half of 2016, and the increase in our total proved reserves. These impacts were partially offset by recent drilling and completion activities which increased the amortization base. 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 March 31, 2017, we had no impairment as compared to an impairment of $45.6 million for the three months ended March 31, 2016, representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling.


29


General and Administrative ("G&A") - The following table summarizes G&A expenses incurred and capitalized during the periods presented:
 
Three Months Ended March 31,
(in thousands)
2017
 
2016
G&A costs incurred
$
10,880

 
$
8,092

Capitalized costs
(2,680
)
 
(649
)
Total G&A
$
8,200

 
$
7,443

 
 
 
 
Non-Cash G&A
$
2,675

 
$
2,519

Cash G&A
$
5,525

 
$
4,924

Total G&A
$
8,200

 
$
7,443

 
 
 
 
Non-Cash G&A per BOE
$
1.68

 
$
2.41

Cash G&A per BOE
$
3.46

 
$
4.70

G&A Expense per BOE
$
5.14

 
$
7.11


G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. Total G&A costs of $8.2 million for the first three months of 2017 were 10% higher than G&A for the same period of 2016. This increase is primarily due to a 44% increase in employee headcount from 73 to 105 at March 31, 2017.

Our G&A expense for the three months ended March 31, 2017 includes stock-based compensation of $2.7 million compared to $2.5 million for the three months ended March 31, 2016. Stock-based compensation is a non-cash charge that is based on the calculated fair value of stock options, performance stock units, restricted share units, and stock bonus shares that we grant for compensatory purposes. For stock options, the fair value is estimated using the Black-Scholes-Merton option pricing model. For performance stock units, the fair value is estimated using the Monte Carlo 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 March 31, 2016 to the three months ended March 31, 2017 reflects our increased headcount of individuals performing activities to maintain and acquire leases and develop our properties.

Commodity derivative gains (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 March 31, 2017, we realized a cash settlement loss of $0.1 million, net of previously incurred premiums attributable to the settled commodity contracts. For the prior comparable period, we realized a cash settlement gain of $2.4 million, net of previously incurred premiums attributable to the settled commodity contracts.

In addition, for the three months ended March 31, 2017, we recorded an unrealized gain of $3.5 million to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the three months ended March 31, 2016, we reported an unrealized loss of $0.8 million. Unrealized gains and losses are non-cash items.

Income taxes - We reported no income tax expense for the three months ended March 31, 2017 or the prior year period. As explained in more detail below, during the period ended March 31, 2017 and 2016, the effective tax rates were substantially reduced by recognition of a full valuation allowance on the net deferred tax assets. During the three months ended March 31, 2017 and 2016, the effective tax rate differed from the statutory rate, primarily due to the recognition of a valuation allowance recorded against deferred tax assets.

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

30


been provided as of March 31, 2017. During the 2016 comparable period, we reached the same conclusion; therefore, a valuation allowance has been provided as of March 31, 2016.

Liquidity and Capital Resources

Historically, our primary sources of capital have been net cash provided by cash flow from operations, proceeds from the sale of properties, the sale of equity and debt securities, and borrowings under bank credit facilities.  Our primary use of capital has been for the exploration, development, and acquisition of oil and gas properties.  Our future success in growing proved reserves and production will be highly dependent on the 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. 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. 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 three months ended March 31, 2017, the NYMEX-WTI oil price ranged from a low of $47.00 per Bbl on Thursday, March 23, 2017 to a high of $54.48 per Bbl on Thursday, February 23, 2017, while the NYMEX-Henry Hub natural gas price ranged from a low of $2.44 per MMBtu on Monday, February 27, 2017 to a high of $3.71 per MMBtu on January 2, 2017. 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 March 31, 2017, we had cash and cash equivalents of $33.2 million, $80 million outstanding on our Senior Notes, and no outstanding balance under our revolving credit facility (as of April 30, 2017, the outstanding balance under revolving credit facility was $25 million). Our sources and (uses) of funds for the three months ended March 31, 2017 and 2016 are summarized below (in thousands):
 
Three Months Ended March 31,
 
2017
 
2016
Net cash provided by operations
$
29,358

 
$
8,122

Capital expenditures
(85,063
)
 
(34,374
)
Net cash provided by other investing activities
70,718