SRC Energy Inc. - FORM 10-Q

Attached files

file	filename
EX-31.2 - EXHIBIT 31.2 - SRC Energy Inc.	exhibit31220160331.htm
EX-31.1 - EXHIBIT 31.1 - SRC Energy Inc.	exhibit31120160331.htm
EX-3.2 - EXHIBIT 3.2 - SRC Energy Inc.	exhibit32bylawsofthecompan.htm
EX-32 - EXHIBIT 32 - SRC Energy Inc.	exhibit32120160331.htm

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, 2016



	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

SYNERGY RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)



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



1625 Broadway, Suite 300, 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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer ý	Accelerated filer o

Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company 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: 148,695,805 outstanding shares of common stock as of April 29, 2016.

SYNERGY RESOURCES CORPORATION

Index



		Page
Part I - FINANCIAL INFORMATION

Item 1.	Financial Statements

	Condensed Balance Sheets as of March 31, 2016 (unaudited) and December 31, 2015	2

	Condensed Statements of Operations for the three months ended March 31, 2016 and March 31, 2015 (unaudited)	3

	Condensed Statements of Cash Flows for the three months ended March 31, 2016 and March 31, 2015 (unaudited)	4

	Notes to Condensed Financial Statements (unaudited)	5

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	24

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40

Item 4.	Controls and Procedures	41

Part II - OTHER INFORMATION

Item 1.	Legal Proceedings	42

Item 1A.	Risk Factors	42

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44

Item 3.	Defaults of Senior Securities	44

Item 4.	Mine Safety Disclosures	44

Item 5.	Other Information	44

Item 6.	Exhibits	45

SIGNATURES		49

SYNERGY RESOURCES CORPORATION

CONDENSED BALANCE SHEETS

(in thousands, except share data)



ASSETS	March 31, 2016			December 31, 2015
	(unaudited)
Current assets:
Cash and cash equivalents	$	50,937		$	66,499
Accounts receivable:
Oil and gas sales	10,539			12,527
Joint interest billing and other	13,484			12,156
Commodity derivative contracts	6,066			6,572
Other current assets	1,940			1,944
Total current assets	82,966			99,698

Property and equipment:
Oil and gas properties, full cost method:
Proved properties, net	378,536			422,778
Unproved properties, not subject to depletion	103,997			98,945
Oil and gas properties, net	482,533			521,723
Other property and equipment, net	5,477			5,124
Total property and equipment, net	488,010			526,847

Commodity derivative contracts	2,227			2,996
Goodwill	40,711			40,711
Other assets	2,386			2,364

Total assets	$	616,300		$	672,616

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Trade accounts payable	$	3,157		$	4,350
Well costs payable	15,324			31,414
Revenue payable	10,471			13,603
Production taxes payable	26,132			24,530
Other accrued expenses	927			809
Total current liabilities	56,011			74,706

Revolving credit facility	—			78,000
Asset retirement obligations	13,676			13,400
Total liabilities	69,687			166,106

Commitments and contingencies (See Note 15)

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: 126,245,686 and 110,033,601 shares issued and outstanding, respectively	126			110
Additional paid-in capital	687,159			595,671
Retained deficit	(140,672		)	(89,271		)
Total shareholders' equity	546,613			506,510

Total liabilities and shareholders' equity	$	616,300		$	672,616

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

SYNERGY RESOURCES CORPORATION

CONDENSED STATEMENTS OF OPERATIONS

(unaudited; in thousands, except share and per share data)



	Three Months Ended March 31,
	2016			2015

Oil and gas revenues	$	18,273		$	18,938

Expenses:
Lease operating expenses	4,299			4,121
Production taxes	1,833			1,807
Depreciation, depletion, and accretion	12,092			14,077
Full cost ceiling impairment	45,621			—
Transportation commitment charge	68			—
General and administrative	7,443			4,081
Total expenses	71,356			24,086

Operating loss	(53,083		)	(5,148		)

Other income (expense):
Commodity derivatives gain	1,680			3,461
Interest expense, net	—			(39		)
Interest income	2			24
Total other income	1,682			3,446

Loss before income taxes	(51,401		)	(1,702		)

Income tax benefit	—			(709		)
Net loss	$	(51,401	)	$	(993	)

Net loss per common share:
Basic	$	(0.42	)	$	(0.01	)
Diluted	$	(0.42	)	$	(0.01	)

Weighted-average shares outstanding:
Basic	121,392,736			97,241,301
Diluted	121,392,736			97,241,301

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

SYNERGY RESOURCES CORPORATION

CONDENSED STATEMENTS OF CASH FLOWS

(unaudited; in thousands)



	Three Months Ended March 31,
	2016			2015
Cash flows from operating activities:
Net loss	$	(51,401	)	$	(993	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation, and accretion	12,092			14,077
Full cost ceiling impairment	45,621			—
Provision for deferred taxes	—			(709		)
Stock-based compensation	2,519			1,604
Mark to market of commodity derivative contracts:
Total gain on commodity derivatives contracts	(1,680		)	(3,461		)
Cash settlements on commodity derivative contracts	3,059			13,742
Cash premiums paid for commodity derivative contracts	—			(3,498		)
Changes in operating assets and liabilities:
Accounts receivable
Oil and gas sales	1,988			12,748
Joint interest billing and other	(1,431		)	8,529
Accounts payable
Trade	(1,193		)	171
Revenue	(3,132		)	(4,356		)
Production taxes	1,602			2,449
Accrued expenses	118			(56		)
Other	(40		)	(488		)
Total adjustments	59,523			40,752
Net cash provided by operating activities	8,122			39,759

Cash flows from investing activities:
Acquisition of oil and gas properties	(10,000		)	—
Well costs and other capital expenditures	(24,374		)	(57,811		)
Net proceeds from sales of oil and gas properties	—			3,696
Net cash used in investing activities	(34,374		)	(54,115		)

Cash flows from financing activities:
Proceeds from sale of stock	92,575			200,100
Offering costs	(3,409		)	(9,255		)
Shares withheld for payment of employee payroll taxes	(284		)	(71		)
Principal repayments on revolving credit facility	(78,000		)	—
Financing fee	(192		)	—
Net cash provided by financing activities	10,690			190,774

Net (decrease) increase in cash and equivalents	(15,562		)	176,418

Cash and equivalents at beginning of period	66,499			39,570

Cash and equivalents at end of period	$	50,937		$	215,988

Supplemental Cash Flow Information (See Note 16)

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

SYNERGY RESOURCES CORPORATION

NOTES TO CONDENSED FINANCIAL STATEMENTS

(unaudited)


1.	Organization and Summary of Significant Accounting Policies

Organization: Synergy Resources Corporation (the “Company”) is engaged in oil and gas acquisition, exploration, development, and production activities, primarily in the Denver-Julesburg Basin ("D-J Basin") of Colorado. The Company’s common stock is listed and traded on the NYSE MKT under the symbol “SYRG.”

Basis of Presentation: The Company does not utilize any special purpose entities. The Company operates in one business segment, and all of its operations are located in the United States of America.

At the directive of the Securities and Exchange Commission ("SEC") to use "plain English" in public filings, the Company will use such terms as "we," "our," or the "Company" in place of Synergy Resources Corporation. When such terms are used in this manner throughout this document, they are in reference only to the corporation, Synergy Resources Corporation, and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees.

The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States of America (“US GAAP”).

Change of Year End: On February 25, 2016, the Company's board of directors approved a change in fiscal year end from August 31 to December 31 effective with the fiscal year ending December 31, 2016.

Interim Financial Information: The unaudited condensed 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 balance sheet as of December 31, 2015 was derived from the Company's Transition Report on Form 10-K for the four months ended December 31, 2015 as filed with the SEC on April 22, 2016. Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with US GAAP have been condensed or omitted pursuant to such SEC rules and regulations. The Company believes that the disclosures included are adequate to make the information presented not misleading and recommends that these condensed financial statements be read in conjunction with the audited financial statements and notes thereto for the four months ended December 31, 2015.

In management's opinion, the unaudited condensed 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 and gas revenue (“major customers”) for each of the periods presented are shown in the following table:



	Three Months Ended March 31,
Major Customers	2015	2014
Company A	42%	*
Company B	25%	15%
Company C	12%	60%
Company D	*	13%

* less than 10%

Based on the current demand for oil and natural gas, the availability of other buyers, and the Company having the option to sell to other buyers if conditions warrant, the Company believes that its oil and gas production can be sold in the market in the event that it is not sold to the Company’s existing customers. However, in some circumstances, a change in customers may entail significant transition costs and/or shutting in or curtailing production for weeks or even months during the transition to a new customer.

Accounts receivable consist primarily of trade receivables from oil and gas sales and amounts due from other working interest owners who are liable for their proportionate share of well costs. The Company typically has the right to withhold future revenue disbursements to recover outstanding joint interest billings on outstanding receivables from joint interest owners.

Customers with balances greater than 10% of total receivable balances as of each of the periods presented are shown in the following table:



	As of	As of
Major Customers	March 31, 2016	December 31, 2015
Company A	20%	*
Company B	16%	13%
Company C	*	13%
Company D	*	13%

* less than 10%

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

Goodwill: The Company’s goodwill represents the excess of the purchase price over the fair value of net identifiable assets acquired in a business combination. Goodwill is not amortized and is tested for impairment annually or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. When evaluating goodwill for impairment, the Company may first perform an assessment of qualitative factors to determine if the fair value of the reporting unit is more-likely-than-not greater than its carrying amount. If, based on the review of the qualitative factors, the Company determines it is not more-likely-than-not that the fair value of a reporting unit is less than its carrying value, the required two-step impairment test can be bypassed. If the Company does not perform a qualitative assessment or if the fair value of the reporting unit is not more-likely-than-not greater than its carrying value, the Company must perform the first step of the two-step impairment test and calculate the estimated fair value of the reporting unit. If the carrying value of the reporting unit exceeds the estimated fair value, there is an indication that impairment may exist, and the second step must be performed to measure the amount of impairment loss. The amount of impairment for goodwill is measured as the amount by which the carrying amount of the goodwill exceeds the implied fair value of the goodwill. As a result of declining oil prices, the Company performed an interim goodwill test in conjunction with the preparation of its financial statements for the three months ended March 31, 2016 which did not result in an impairment. The Company utilized a market approach in estimating the fair value of the reporting unit. The primary assumptions used in the Company's impairment evaluations are based on the best available market information at the time and contain considerable management judgments. Changes in these assumptions or future economic conditions could impact the Company's conclusion regarding an impairment of goodwill and potentially result in a non-cash impairment loss in a future period.

Transportation Commitment Charge: The Company has entered into several agreements that require us to deliver minimum amounts of crude oil to a third party marketer and/or other counterparties that transport crude oil via pipelines. See Note 15 for additional information. Pursuant to these agreements, we must deliver specific amounts, either from our own production or from oil we acquire. If we are unable to fulfill all of our contractual delivery obligations from our own production, we may be required to pay penalties or damages pursuant to these agreements, or we may have to purchase oil from third parties to fulfill our delivery obligations. When we incur penalties of this type, we recognize the expense as a transportation commitment charge in the Statement of Operations.

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

In March 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-09, "Improvements to Employee Share-Based Payment Accounting" ("ASU 2016-09"), which intends to improve the accounting for share-based payment transactions. The ASU changes several aspects of the accounting for share-based payment award transactions, including: (1) Accounting and Cash Flow Classification for Excess Tax Benefits and Deficiencies, (2) Forfeitures, and (3) Tax Withholding Requirements and Cash Flow Classification. ASU 2016-09 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the impact of the adoption on our financial statements.

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" ("ASU 2016-02"), which establishes a comprehensive new lease standard designed to increase transparency and comparability among organizations by recognizing lease

assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous US GAAP. ASU 2016-02 is effective for public business for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the impact of the adoption of this standard on our financial statements.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”), which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current revenue recognition guidance. ASU 2014-09 allows for the use of either the full or modified retrospective transition method, and the standard will be effective for annual reporting periods beginning after December 15, 2017 including interim periods within that period, with early adoption permitted for annual reporting periods beginning after December 15, 2016. We are currently evaluating which transition approach to use and the impact of the adoption of this standard on our consolidated financial statements.

There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations, or cash flows.


2.	Property and Equipment

The capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):



	As of			As of
	March 31, 2016			December 31, 2015
Oil and gas properties, full cost method:
Costs of unproved properties, not subject to depletion:
Lease acquisition and other costs	$	93,696		$	89,122
Unproved wells in progress	10,301			9,823
Subtotal, unproved properties	103,997			98,945

Costs of proved properties:
Producing and non-producing	698,564			691,659
Proved wells in progress	17,665			11,487
Less, accumulated depletion and full cost ceiling impairments	(337,693		)	(280,368		)
Subtotal, proved properties, net	378,536			422,778

Costs of other property and equipment:
Land	4,478			4,478
Other property and equipment	1,696			1,270
Less, accumulated depreciation	(697		)	(624		)
Subtotal, other property and equipment, net	5,477			5,124

Total property and equipment, net	$	488,010		$	526,847

The Company periodically reviews its oil and gas properties to determine if the carrying value of such assets exceeds estimated fair value. For proved producing and non-producing properties, the Company performs a ceiling test each quarter to determine whether there has been an impairment to its capitalized costs. Under the ceiling test, the value of the Company’s reserves is calculated using the average of the published spot prices for WTI oil (per barrel) as of the first day of each of the previous twelve months, as well as the average of the published spot prices for Henry Hub (per MMBtu) as of the first day of each of the previous twelve months, each adjusted by lease or field for quality, transportation fees and regional price differentials. The ceiling test as of March 31, 2016 used average realized prices of $37.32 per barrel and $2.41 per Mcf. The oil prices used at March 31, 2016 were approximately 10% lower than the December 31, 2015 price of $41.33, and the gas prices were approximately 7% lower than the

December 31, 2015 price of $2.60. Using these prices, the Company's net capitalized costs for oil and natural gas properties exceeded the ceiling amount by $45.6 million, resulting in an immediate recognition of a ceiling test impairment. No such ceiling test impairment was recognized during the three months ended March 31, 2015.

The Company also reviews the fair value of its unproved properties. The reviews for the three months ended March 31, 2016 and 2015 indicated that estimated fair values of such assets exceeded the carrying values. Therefore, no reclassifications to proved property were recognized during either period to impair the carrying value of the unproved properties.

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,
	2016		2015
Capitalized overhead	$	649	$	585


3.	Acquisitions

The Company acquired certain oil and gas and other assets that affect the comparability between the three months ended March 31, 2016, and the three months ended March 31, 2015, as described below.

On February 4, 2016, the Company completed the acquisition of certain assets for a total purchase price of $10.0 million. The acquisition comprised solely of undeveloped oil and gas leasehold interests in the D-J Basin of Colorado. The purpose of the transaction was to provide additional mineral acres upon which the Company could drill wells and produce hydrocarbons. It is believed that the transaction will improve the Company's cash flow as it is developed. The purchase price has been allocated as $6.8 million to proved oil and gas properties and $3.2 million to unproved oil and gas properties on a preliminary basis and includes significant use of estimates.

Kauffman Acquisition

On October 20, 2015, the Company closed the acquisition of certain assets from K.P. Kauffman Company, Inc. ("Kauffman") for a total purchase price of $85.2 million, net of customary closing adjustments. The purchase price was composed of $35.0 million in cash and $49.8 million in restricted common stock plus the assumption of certain liabilities.

The Kauffman acquisition encompassed approximately 4,300 net acres of oil and gas leasehold interests and related assets in the D-J Basin of Colorado and net production of approximately 1,200 barrels of oil equivalent per day (BOED) at the time of purchase. The purpose of the transaction was to provide additional mineral acres upon which the Company could drill wells and produce hydrocarbons. It is believed that the transaction will improve the Company's cash flow.

The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of October 20, 2015. Transaction costs related to the acquisition were expensed as incurred. The following allocation of the purchase price is preliminary and includes significant use of estimates. The fair values of the assets acquired and liabilities assumed are preliminary and are subject to revision as the Company continues to evaluate the fair value of this acquisition. Accordingly, the allocation will change as additional information becomes available and is assessed, and the impact of such changes may be material. The following table summarizes the preliminary purchase price and preliminary estimated fair values of assets acquired and liabilities assumed (in thousands):



Preliminary Purchase Price	October 20, 2015
Consideration given:
Cash	$	35,045
Synergy Resources Corp. Common Stock ⁽¹⁾	49,840
Net liabilities assumed, including asset retirement obligations	299
Total consideration given	$	85,184

Preliminary Allocation of Purchase Price
Proved oil and gas properties ⁽²⁾	$	46,342
Unproved oil and gas properties	37,766
Other assets, including accounts receivable	1,076
Total fair value of assets acquired	$	85,184

⁽¹⁾ The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of October 20, 2015 (4,418,413 shares at $11.28 per share).

⁽²⁾ Proved oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rate of 12%, and assumptions regarding the timing and amount of future development and operating costs.

The results of operations of the acquired assets from the October 20, 2015 closing date through March 31, 2016, representing approximately $2.4 million of revenue and $2.2 million of operating income, have been included in the Company's consolidated statement of operations for the three months ended March 31, 2016.

The following table presents the unaudited pro forma combined results of operations for the three months ended March 31, 2015 as if the Kauffman transaction had occurred on January 1, 2015. The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through the issuance of common stock and cash, additional depreciation expense, costs directly attributable to the acquisition, and operating costs incurred as a result of the assets acquired. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.



(in thousands)	Three Months Ended March 31, 2015
Oil and gas revenues	$	23,183
Net (loss) income	$	(1,067	)

Net (loss) income per common share
Basic	$	(0.01	)
Diluted	$	(0.01	)


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

Depletion, depreciation, and accretion consisted of the following (in thousands):



	Three Months Ended March 31,
	2016		2015
Depletion of oil and gas properties	$	11,743	$	13,880
Depreciation and accretion	349		197
Total DD&A Expense	$	12,092	$	14,077

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, 2016, production of 1,047 MBOE represented 1.5% of estimated total proved reserves. For the three months ended March 31, 2015, production of 633 MBOE represented 1.6% of estimated total proved reserves. DD&A expense was $11.55 per BOE and $22.24 per BOE for the three months ended March 31, 2016 and 2015, respectively.


5.	Asset Retirement Obligations

The following table summarizes the changes in asset retirement obligations associated with the Company's oil and gas properties (in thousands).



Asset retirement obligations, December 31, 2015	$	13,400
Obligations incurred with development activities	—
Obligations assumed with acquisitions	—
Accretion expense	276
Obligations discharged with asset retirements	—
Revisions in previous estimates	—
Asset retirement obligations, March 31, 2016	$	13,676


6.	Revolving Credit Facility

The Company maintains a revolving credit facility ("Revolver") with a bank syndicate. The Revolver is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes, and to support letters of credit. As of March 31, 2016, the terms of the Revolver provide for up to $500 million in borrowings, subject to a borrowing base limitation, which was $145 million. As of March 31, 2016, there was no outstanding principal balance. The maturity date of the Revolver is December 15, 2019.

On January 28, 2016, the Revolver was amended in connection with the semi-annual redetermination. The borrowing base was reduced from $163 million to $145 million, and the Revolver was further amended to (i) delete the minimum interest rate floor, (ii) delete the minimum liquidity covenant, (iii) add a current ratio covenant of 1.0 to 1.0, and (iv) delete the minimum hedging requirement. In January 2016, the Company reduced its outstanding borrowings under the Revolver from $78 million to nil.

Interest under the Revolver is payable monthly and accrues at a variable rate. For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin or the London Interbank Offered Rate (“LIBOR”) plus a margin. The interest rate margin, as well as other bank fees, varies with utilization of the Revolver. The average annual interest rate for borrowings during the three months ended March 31, 2016 was 2.5%.

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. In certain events, and at the discretion of the bank syndicate, an unscheduled redetermination could be prepared. As of March 31, 2016, based on a borrowing base of $145 million and no outstanding principal balance, the unused borrowing base available for future borrowing totaled approximately $145 million. The next semi-annual redetermination has been scheduled for May 2016.

The Revolver also contains covenants that, among other things, restrict the payment of dividends. Additionally, as of March 31, 2016, the Revolver required an overall commodity derivative position that covers a rolling 24 months of estimated future production with a maximum position of 85% of hydrocarbon production as projected in the semi-annual reserve report.

Furthermore, the Revolver requires the Company to maintain compliance with certain financial and liquidity ratio covenants. Under the requirements, the Company, on a quarterly basis, must (a) not, 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; and (b) not, 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, 2016, the most recent compliance date, the Company was in compliance with these loan covenants.


7.	Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, as described below. Our commodity derivative instruments may include but are not limited to “collars,” “swaps,” and “put” positions. Our derivative strategy, including the volume amounts, whether we utilize oil and/or natural gas instruments, and at what commodity prices the instruments are associated with, 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. The ownership of put options is consistent with our derivative strategy inasmuch as the value of the puts will increase as commodity prices decline, helping to offset the cash flow impact of a decline in realized prices for the underlying commodity. However, if the underlying commodity increases in value, there is a risk that the put option will expire worthless and the net premiums paid would be recognized as a loss.

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 constructed by selling call options while simultaneously buying put options, in which the premiums paid for the puts is offset by the premiums received for the calls. Collars are consistent with our derivative strategy inasmuch as the they establish a known range of prices to be received for the associated volume equivalents, that being bound at the upper end by the call’s strike price (the “ceiling”) and at the lower end by the put’s strike price (the “floor.”)

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. Swaps are consistent with our derivative strategy inasmuch as they establish a known future price to be received for the associated equivalent volumes.

The Company may, from time to time, add incremental derivatives to cover additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with four counterparties and an exchange. Two of the counterparties are lenders in the Revolver. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets. 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 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 statements of cash flows.

The Company’s valuation estimate takes into consideration the counterparty’s creditworthiness, the Company’s

creditworthiness, and the time value of money. The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments.

The Company’s commodity derivative contracts as of March 31, 2016 are summarized below:



Settlement Period	Derivative Instrument	Average Volumes (Bbls per month)	Floor Price		Ceiling Price
Crude Oil - NYMEX WTI
Apr 1, 2016 - Dec 31, 2016	Purchased Put	25,000	$	50.00	—
Apr 1, 2016 - Dec 31, 2016	Purchased Put	10,000	$	45.00	—
Apr 1, 2016 - Dec 31, 2016	Collar	20,000	$	45.00	$	65.00

Jan 1, 2017 - Apr 30, 2017	Purchased Put	20,000	$	50.00	—
May 1, 2017 - Aug 31, 2017	Purchased Put	20,000	$	55.00	—
Jan 1, 2017 - Dec 31, 2017	Collar	20,000	$	45.00	$	70.00

Settlement Period	Derivative Instrument	Average Volumes (MMBtu per month)	Floor Price		Ceiling Price
Natural Gas - NYMEX Henry Hub
Apr 1, 2016 - May 31, 2016	Collar	60,000	$	4.05	$	4.54
Jun 1, 2016 - Aug 31, 2016	Collar	60,000	$	3.90	$	4.14

Natural Gas - CIG Rocky Mountain
Apr 1, 2016 - Dec 31, 2016	Collar	100,000	$	2.65	$	3.10

Jan 1, 2017 - Apr 30, 2017	Collar	100,000	$	2.80	$	3.95
May 1 2017 - Aug 31, 2017	Collar	110,000	$	2.50	$	3.06

Offsetting of Derivative Assets and Liabilities

As of March 31, 2016 and December 31, 2015, all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, 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, the counterparties have 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 accompanying Balance Sheets.

The following table provides a reconciliation between the net assets and liabilities reflected on the accompanying 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, 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	$	6,201	$	(135	)	$	6,066
Commodity derivative contracts	Noncurrent assets	$	2,445	$	(218	)	$	2,227
Commodity derivative contracts	Current liabilities	$	135	$	(135	)	$	—
Commodity derivative contracts	Noncurrent liabilities	$	218	$	(218	)	$	—



		As of December 31, 2015
Underlying	Balance Sheet Location	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Commodity derivative contracts	Current assets	$	6,719	$	(147	)	$	6,572
Commodity derivative contracts	Noncurrent assets	$	3,354	$	(358	)	$	2,996
Commodity derivative contracts	Current liabilities	$	147	$	(147	)	$	—
Commodity derivative contracts	Noncurrent liabilities	$	358	$	(358	)	$	—

The amount of gain recognized in the statements of operations related to derivative financial instruments was as follows (in thousands):



	Three Months Ended March 31,
	2016			2015
Realized gain on commodity derivatives	$	2,445		$	13,542
Unrealized loss on commodity derivatives	(765		)	(10,081		)
Total gain	$	1,680		$	3,461

Realized gains and losses include cash received from the monthly settlement of derivative contracts at their scheduled maturity date, the proceeds from early liquidation of in-the-money derivative contracts, and the previously incurred premiums attributable to settled commodity contracts. During the three months ended March 31, 2015, the Company liquidated oil derivatives with an average strike price of $85.81 and covering 269,000 bbls of oil and received cash settlements of approximately $8.4 million. The following table summarizes derivative realized gains and losses during the periods presented (in thousands):



	Three Months Ended March 31,
	2016			2015
Monthly settlement	$	2,955		$	5,364
Previously incurred premiums attributable to settled commodity contracts	(510		)	(200		)
Early liquidation	—			8,378
Total realized gain	$	2,445		$	13,542

Credit Related Contingent Features

As of March 31, 2016, two of the four 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 counterparty, which is not a lender under the credit facility, is unsecured and does not require the posting of collateral. The agreement with the fourth counterparty is subject to an inter-creditor agreement between the counterparty and the Company’s lenders under the credit facility.


8.	Fair Value Measurements

ASC Topic 820, Fair Value Measurements and Disclosure, establishes a hierarchy for inputs used in measuring fair value for financial assets and liabilities that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:


•	Level 1: Quoted prices available in active markets for identical assets or liabilities;


•	Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability;


•	Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash or valuation models.

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The Company’s non-recurring fair value measurements include asset retirement obligations and purchase price allocations for the fair value of assets and liabilities acquired through business combinations. Please refer to Notes 3 and 5 for further discussion of business combinations and asset retirement obligations, respectively.

The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using Level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit-adjusted risk-free rate, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period, and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method. See Note 5 for additional information.

The acquisition of a group of assets in a business combination transaction requires fair value estimates for assets acquired and liabilities assumed. The fair value of assets and liabilities acquired through business combinations is calculated using a net discounted cash flow approach for the producing properties. The discounted cash flows are developed using the income approach and are based on management’s expectations for the future. Unobservable inputs include estimates of future oil and gas production from the Company’s reserve reports, commodity prices based on the NYMEX forward price curves as of the date of the estimate (adjusted for basis differentials), estimated operating and development costs, and a risk-adjusted discount rate (all of which are designated as Level 3 inputs within the fair value hierarchy). For unproved properties, fair value is determined using market comparables. For the asset retirement liability assumed, the fair value is determined using the same inputs as described in the paragraph above. See Note 3 for additional information.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2016 and December 31, 2015 by level within the fair value hierarchy (in thousands):



	Fair Value Measurements at March 31, 2016
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	—	$	8,293	$	—	$	8,293
Commodity derivative liability	$	—	$	—	$	—	$	—



	Fair Value Measurements at December 31, 2015
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	—	$	9,568	$	—	$	9,568
Commodity derivative liability	$	—	$	—	$	—	$	—

Commodity Derivative Instruments

The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparties to its derivative contracts would default by failing to make any contractually required payments. The Company considers the counterparties to be of substantial credit quality and believes that they have the financial resources and willingness to meet their potential repayment obligations associated with the derivative transactions. At March 31, 2016, derivative instruments utilized by the Company consist of puts and collars. The crude oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are based on several factors, including public indices, the instruments themselves are primarily traded with third-party counterparties. As such, the Company has classified these instruments as Level 2.

Fair Value of Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and credit facility borrowings. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short-term maturities.


9.	Interest Expense

The components of interest expense are (in thousands):



	Three Months Ended March 31,
	2016			2015
Revolving bank credit facility	$	141		$	821
Amortization of debt issuance costs	295			242
Less, interest capitalized	(436		)	(1,024		)
Interest expense, net	$	—		$	39


10.	Shareholders’ Equity

The Company's classes of stock are summarized as follows:



	As of March 31, 2016		As of December 31, 2015
Preferred stock, shares authorized	10,000,000		10,000,000
Preferred stock, par value	$	0.01	$	0.01
Preferred stock, shares issued and outstanding	nil		nil
Common stock, shares authorized	300,000,000		300,000,000
Common stock, par value	$	0.001	$	0.001
Common stock, shares issued and outstanding	126,245,686		110,033,601

Preferred stock may be issued in series with such rights and preferences as may be determined by the Board of Directors. Since inception, the Company has not issued any preferred shares.

Shares of the Company’s common stock were issued during three months ended March 31, 2016 as described further below.

Sales of common stock

In January 2016, the Company completed a public offering of its common stock in an underwritten public offering led by Credit Suisse Securities (USA) LLC. The Company agreed to sell 14,000,000 shares of its common stock to the Underwriters at a price of $5.545 per share. In addition, pursuant to the Underwriting Agreement, the Underwriters were granted an option, exercisable within 30 days, to purchase up to an additional 2,100,000 shares of common stock on the same terms and conditions. The option was exercised on January 26, 2016, bringing the total number of shares issued to 16,100,000. Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $89.2 million. Proceeds from the offering are expected to be used for general corporate purposes, which may include continuing to develop our acreage position in the Wattenberg Field in Colorado, repaying amounts borrowed under the Revolver, funding a portion of our capital expenditure program for the remainder of 2016, or other uses. Initially, proceeds were used to repay amounts borrowed under the Revolver.

Subsequent to March 31, 2016, shares of the Company's common stock were issued as described further below.

Sales of common stock

In April 2016, the Company completed a public offering of its common stock in an underwritten public offering led by Credit Suisse Securities (USA) LLC. The Company agreed to sell 19,500,000 shares of its common stock to the Underwriters at a price of $7.3535 per share. In addition, pursuant to the Underwriting Agreement, the Underwriters were granted an option, exercisable within 30 days, to purchase up to an additional 2,925,000 shares of common stock on the same terms and conditions. The option was exercised on April 12, 2016, bringing the total number of shares issued to 22,425,000. Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $164.8 million. Proceeds from the offering are expected to be used for general corporate purposes, including potential acquisitions. The Company expects to use a portion of the proceeds of the offering to pay a portion of the purchase price of the proposed acquisition described in Note 17.


11.	Earnings per Share

Basic earnings per share includes no dilution and is computed by dividing net income by the weighted-average number of shares outstanding during the period. Diluted earnings per share reflects the potential dilution of securities that could share in the earnings of the Company. The number of potential shares outstanding relating to stock options, performance stock units, non-vested restricted stock and stock bonus shares, and warrants is computed using the treasury stock method. Potentially dilutive securities outstanding are not included in the calculation when such securities would have an anti-dilutive effect on earnings per share.

The following table sets forth the share calculation of diluted earnings per share:



	Three Months Ended March 31,
	2016	2015
Weighted-average shares outstanding - basic	121,392,736	97,241,301
Potentially dilutive common shares from:
Stock options	—	—
Performance stock units	—	—
Restricted stock and stock bonus shares	—	—
Weighted-average shares outstanding - diluted	121,392,736	97,241,301

The following potentially dilutive securities outstanding for the periods presented were not included in the respective earnings per share calculation above, as such securities had an anti-dilutive effect on earnings per share:



	Three Months Ended March 31,
	2016	2015
Potentially dilutive common shares from:
Stock options	5,545,500	2,274,000
Performance stock units ¹	464,946	—
Restricted stock and stock bonus shares	1,136,401	—
Total	7,146,847	2,274,000

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 certain service providers, including employees, directors, consultants, and other advisors, with equity-based compensation in the form of stock options, restricted stock, 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. For the periods presented, all stock-based compensation expense was classified either as a component within general and administrative expense in the Company's 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,
	2016			2015
Stock options	$	1,410		$	590
Performance stock units	—			—
Restricted stock and stock bonus shares	1,212			1,014
Total stock-based compensation	$	2,622		$	1,604
Less: stock-based compensation capitalized	(103		)	(253		)
Total stock-based compensation expensed	$	2,519		$	1,351

Stock options

During the three months ended March 31, 2016 and 2015, the Company granted the following stock options:



	Three Months Ended March 31,
	2016		2015
Number of options to purchase common shares	489,500		190,000
Weighted-average exercise price	$	7.72	$	12.09
Term (in years)	10 years		10 years
Vesting Period (in years)	3 - 5 years		1 - 5 years
Fair Value (in thousands)	$	1,729	$	1,083

The assumptions used in valuing stock options granted during each of the periods presented were as follows:



	Three Months Ended March 31,
	2016		2015
Expected term	6.3 years		6.1 years
Expected volatility	55	%	48	%
Risk free rate	1.50 - 1.75%		1.35 - 1.86%
Expected dividend yield	0.0	%	0.0	%

The following table summarizes activity for stock options for the three months ended March 31, 2016:



	Number of Shares	Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life	Aggregate Intrinsic Value (thousands)
Outstanding, December 31, 2015	5,056,000	$	9.71	8.7 years	$	4,351
Granted	489,500	7.72
Exercised	—	—			—
Expired	—	—
Forfeited	—	—
Outstanding, March 31, 2016	5,545,500	$	9.53	8.5 years	$	3,717
Outstanding, Exercisable at March 31, 2016	1,595,450	$	7.44	7.1 years	$	2,721
Outstanding, Vested and expected to vest at March 31, 2016	5,446,636	$	9.50	8.5 years	$	3,716

The following table summarizes information about issued and outstanding stock options as of March 31, 2016:



	Outstanding Options				Exercisable Options
Range of Exercise Prices	Options	Weighted-Average Remaining Contractual Life	Weighted-Average Exercise Price per Share		Options	Weighted-Average Exercise Price per Share

Under $5.00	654,000	5.5 years	$	3.51	509,000	$	3.50
$5.00 - $6.99	630,000	7.6 years	6.34		425,000	6.51
$7.00 - $10.99	1,459,500	9.1 years	9.60		173,450	9.38
$11.00 - $13.46	2,802,000	9.2 years	11.62		488,000	11.68
Total	5,545,500	8.5 years	$	9.53	1,595,450	$	7.44

The estimated unrecognized compensation cost from stock options not vested as of March 31, 2016, which will be recognized ratably over the remaining vesting phase, is as follows:



	Unvested Options at March 31, 2016
Unrecognized compensation, net of estimated forfeitures (in thousands)	$	17,612
Remaining vesting phase	3.7 years

Restricted stock and stock bonus awards

The Company grants shares of restricted stock 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 share of restricted stock 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. Shares of restricted stock 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 and stock bonus awards for the three months ended March 31, 2016:



	Number of Shares		Weighted-Average Grant-Date Fair Value
Not vested, December 31, 2015	915,867		$	10.63
Granted	397,221		7.81
Vested	(153,153	)	10.40
Forfeited	(23,534	)	8.47
Not vested, March 31, 2016	1,136,401		$	9.72

The estimated unrecognized compensation cost from restricted stock and stock bonus awards not vested as of March 31, 2016, which will be recognized ratably over the remaining vesting phase, is as follows:



Unrecognized compensation, net of estimated forfeitures (in thousands)	$	9,670
Remaining vesting phase	3.2 years

Performance-vested stock units

In March 2016, the Company granted performance-vested stock units (“PSUs”) to certain executives under its long term incentive plan. The number of shares of the Company’s common stock that may be issued to settle PSUs ranges from zero to two times the number of PSUs awarded. The PSUs granted are determined based on the Company’s performance over a three-year measurement period and vest in their entirety at the end of the measurement period. The PSUs will be settled in shares of the Company’s common stock following the end of the three-year performance cycle. Any PSUs that have not vested at the end of the applicable measurement period are forfeited. The vesting criterion for the PSUs is based on a comparison of the Company’s total shareholder return (“TSR”) for the measurement period compared with the TSRs of a group of peer companies for the same measurement period. As the vesting criterion is linked to the Company's share price, it is considered a market condition for purposes of calculating the grant-date fair value of the awards.

The fair value of the PSUs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Monte Carlo Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurement period, as well as the volatilities for each of the Company’s peers.

The following table presents the assumptions used to determine the fair value of the PSUs granted during the three months ended March 31, 2016:



	Three Months Ended March 31, 2016
Expected term	2.8 years
Expected volatility	58	%
Risk free rate	0.87	%

During the three months ended March 31, 2016, the Company granted 464,946 PSUs to certain executives. The fair value of the PSUs granted during the three months ended March 31, 2016 was $3.8 million. The Company did not recognize any compensation expense for the three months ended March 31, 2016. As of March 31, 2016, unrecognized compensation expense for PSUs was $3.8 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, 2015	—	$	—
Granted	464,946	8.22
Vested	—	—
Forfeited	—	—
Not vested, March 31, 2016	464,946	$	8.22


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. A tax expense or benefit unrelated to the current year income or loss is recognized in its entirety as a discrete item of tax in the period identified. The quarterly income tax provision is generally comprised of tax expense on income or benefit on loss at the most recent estimated annual effective tax rate, adjusted for the effect of discrete items.

The effective tax rate for the three months ended March 31, 2016 was 0% compared to 42% for the three months ended March 31, 2015. The effective tax rate for the three months ended March 31, 2016 is based upon a full year forecasted tax provision and differs from the statutory rate, primarily due to the recognition of a valuation allowance recorded against deferred tax assets. The effective tax rate for the three months ended March 31, 2015 differs from the statutory rate primarily due to state taxes and nondeductible officers' compensation, partially offset by percentage depletion. There were no significant discrete items recorded during the three months ended March 31, 2016 and 2015.

As of March 31, 2016, we had no liability for unrecognized tax benefits. The Company believes that there are no new items, nor changes in facts or judgments that should impact the Company’s tax position. Given the substantial NOL carryforwards at both the federal and state levels, it is anticipated that any changes resulting from a tax examination would simply adjust the carryforwards, and would not result in significant interest expense or penalties. Most of the Company's tax returns filed since August 31, 2011 are still subject to examination by tax authorities. As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions, and we are not currently under any state income tax examinations.

No significant uncertain tax positions were identified as of any date on or before March 31, 2016. The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of March 31, 2016, the Company has not recognized any interest or penalties related to uncertain tax benefits.

Each period, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income

during the periods in which those temporary differences become deductible. Based upon our cumulative losses through March 31, 2016, we have provided a full valuation allowance reducing the net realizable benefits.


14.	Related Party Transactions

Whenever the Company engages in transactions with its officers, directors, or other related parties, the terms of the transaction are reviewed by the disinterested directors. All transactions must be on terms no less favorable to the Company than similar transactions with unrelated parties.

Lease Agreement: The Company leases its Platteville facilities under a lease agreement with HS Land & Cattle, LLC (“HSLC”). HSLC is controlled by Ed Holloway and William Scaff, Jr., members of the Company's board of directors. The most recent lease, dated June 30, 2014, is currently on a month-to-month basis and requires payments of $15 thousand per month. Historically, the lease has been renewed annually. Under this agreement, the Company incurred the following expenses to HSLC for the periods presented (in thousands):



	Three Months Ended March 31,
	2016		2015
Rent expense	$	45	$	45

Revenue Distribution Processing: The Company processes revenue distribution payments to all persons that own a mineral interest in wells that it operates. Payments to mineral interest owners included payments to two of the Company’s officers, directors or their affiliates: Ed Holloway, and William Scaff Jr. The following table summarizes the aggregate royalty payments made to officers, directors or their affiliates for the periods presented (in thousands):



	Three Months Ended March 31,
	2016		2015
Total royalty payments	$	18	$	8


15.	Other Commitments and Contingencies

Volume Commitments

During 2015, the Company entered into crude oil transportation agreements with three counterparties and a volume commitment to a third party refiner. Deliveries under two of the transportation agreements commenced during 2015. Deliveries under the third transportation agreement are not expected to commence until late in 2016. The third party refinery volume commitment expired on December 31, 2015.

Pursuant to these agreements, we must deliver specific amounts of crude oil either from our own production or from oil we acquire from third parties. If we are unable to fulfill all of our contractual obligations, we may be required to pay penalties or damages pursuant to these agreements. As of March 31, 2016, our commitments over the next five years are as follows:



Year ending December 31,
(in MBbls/year)
Remainder of 2016		1,998
2017		4,072
2018		4,072
2019		4,072
2020		3,517
Thereafter		1,090
Total		18,821

During the quarter ended March 31, 2016, the Company incurred a transportation deficiency charge of $68,000 as we were unable to meet all of the obligations during the quarter. As of March 31, 2016, our current production exceeds our delivery obligations.

Office leases

The Company leases its Platteville offices and other facilities from a related party, as described in Note 14. In addition, the Company maintains its principal offices in Denver. The Denver office lease requires monthly payments of approximately $30 thousand and terminates in October 2016.

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 its business, financial position, results of operations, or cash flows.


16.	Supplemental Schedule of Information to the Statements of Cash Flows

The following table supplements the cash flow information presented in the financial statements for the periods presented (in thousands):



	Three Months Ended March 31,
Supplemental cash flow information:	2016		2015
Interest paid	$	146	$	923
Income taxes (refunded) paid	—		—

Non-cash investing and financing activities:
Accrued well costs	$	15,324	$	33,077
Assets acquired in exchange for common stock	—		70
Asset retirement costs and obligations	—		—


17.	Subsequent Events

In April 2016, the Company completed a public offering of its common stock, which resulted in the issuance of an additional 22,425,000 shares at a price of $7.3535 per share. This transaction is described more fully in Note 10.

In April 2016, the Company agreed to divest approximately 3,700 net undeveloped acres and 107 vertical wells primarily in Adams County, Colorado for total consideration of approximately $27 million in cash, subject to customary purchase price adjustments, in two transactions. The divested assets had associated production of approximately 200 BOED. The vertical well transaction closed in April 2016, and the undeveloped acreage transaction is expected to close in the second quarter of 2016.

On May 2, 2016, we entered into a purchase and sale agreement with a large publicly-traded company, pursuant to which we have agreed to acquire approximately 72,000 gross (33,100 net) acres in an area referred to as the Greeley-Crescent project in the Wattenberg Field for $505 million, subject to customary closing conditions and purchase price adjustments (the "GC Agreement"). Estimated net daily production from the properties to be acquired was approximately 2,400 BOE in the three months ended March 31, 2016. The acquisition is expected close on two separate dates, with the undeveloped lands and non-operated production expected to close in the second quarter of 2016 with an effective date of April 1, 2016, followed by the operated producing properties (assuming regulatory approval is obtained) later in 2016 with an effective date for horizontal wells of April 1, 2016, and an effective date for vertical wells of the first day of the calendar month in which the closing for such properties occurs. The closings are subject to the completion of customary due diligence and closing conditions, and in the case of the second closing, receipt of a regulatory approval. Accordingly, the transactions may not close in the expected timeframes or at all. We expect to fund the acquisition using a combination of cash on hand and proceeds from financing transactions, including the issuance of Senior Notes as described below.

On May 3, 2016, the Company entered into a commitment letter (the “Commitment Letter”) with two investors (the “Investors”) pursuant to which the Investors have agreed to purchase $80 million aggregate principal amount of 9% senior unsecured notes of the Company (the “Senior Notes”). The Senior Notes will mature five years from the date of issuance. The Senior Notes will be issued, subject to the satisfaction of certain conditions, contemporaneously with the first closing under the agreement governing the GC Acquisition. The Commitment Letter provides that the terms of the Senior Notes will be set forth in definitive documentation to be entered into at or prior to the time of issuance. Such terms will include customary covenants limiting the

Company’s ability to incur additional indebtedness, sell assets, make certain restricted payments and incur liens on its properties, and customary provisions regarding redemptions, repurchases following a change of control event and events of default.

On May 3, 2016, the Company entered into an amendment to its revolving credit facility the effect of which, among other things, is to permit the issuance by the Company of the Senior Notes.


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

Cautionary Statement Concerning Forward-Looking Statements

This report contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management and information currently available to management. The use of words such as “believes,” “expects,” “anticipates,” “intends,” “plans,” “estimates,” “should,” “likely,” or similar expressions indicate forward-looking statements. Forward-looking statements included in this report include statements relating to future capital expenditures and projects, the adequacy and nature of future sources of financing, possible future impairment charges, midstream capacity issues, future differentials, future production relative to volume commitments, and the closing and effect of proposed transactions.

The identification in this report of factors that may affect our future performance and the accuracy of forward-looking statements is meant to be illustrative and by no means exhaustive. All forward-looking statements should be evaluated with the understanding of their inherent uncertainty.

Important factors that could cause our actual results to differ materially from those expressed or implied by forward-looking statements include, but are not limited to:


•	extended or further decline in oil and natural gas prices;


•	operating hazards that adversely affect our ability to conduct business;


•	uncertainties in the estimates of proved reserves;


•	the effect of seasonal weather conditions and wildlife restrictions on our operations;


•	our ability to fund, develop, produce and acquire additional oil and natural gas reserves that are economically recoverable;


•	our ability to obtain adequate financing;


•	the effect of local and regional factors on oil and natural gas prices;


•	incurrence of ceiling test write-downs;


•	our inability to control operations on properties that we do not operate;


•	the availability and capacity of gathering systems and pipelines for our production;


•	the strength and financial resources of our competitors;


•	our ability to complete the acquisition discussed in “Significant Developments” and integrate the acquired properties, and the risks associated with liabilities assumed or other problems relating to that acquisition;


•	our ability to successfully identify, execute, or effectively integrate future acquisitions;


•	the effect of federal, state, and local laws and regulations;


•	the effects of, including cost to comply with, new environmental legislation or regulatory initiatives, including those related to hydraulic fracturing;


•	our ability to market our production;


•	the effects of local moratoria or bans on our business;


•	the effect of environmental liabilities;


•	the effect of the adoption and implementation of new statutory and regulatory requirements for derivative transactions;


•	changes in U.S. tax laws;


•	our ability to satisfy our contractual obligations and commitments;


•	the amount of our indebtedness and ability to maintain compliance with debt covenants;


•	the effectiveness of our disclosure controls and our internal controls over financial reporting;


•	the geographic concentration of our principal properties;


•	our ability to protect critical data and technology systems;


•	the availability of water for use in our operations; and


•	the risks and uncertainties described and referenced in the "Risk Factors."

Introduction

The following discussion and analysis was prepared to supplement information contained in the accompanying unaudited condensed financial statements and is intended to explain certain items regarding the Company's financial condition as of March 31, 2016, and its results of operations for the three months ended March 31, 2016 and 2015. It should be read in conjunction with the accompanying unaudited condensed financial statements and related notes thereto contained in this report as well as the audited

financial statements included in the Transition Report on Form 10-K for the four months ended December 31, 2015 filed with the SEC on April 22, 2016.

Overview

Synergy Resources Corporation ("we," "us," "Synergy," or the "Company") is a growth-oriented independent oil and natural gas company engaged in the acquisition, development, and production of crude oil and natural gas in and around the D-J Basin, which we believe to be one of the premier, liquids-rich oil and gas resource plays in the United States. The D-J Basin generally extends from the Denver metropolitan area throughout northeast Colorado into Wyoming, Nebraska, and Kansas. It contains hydrocarbon-bearing deposits in several formations, including the Niobrara, Codell, Greenhorn, Shannon, Sussex, J-Sand and D-Sand. The area has produced oil and gas for over fifty years and benefits from established infrastructure including midstream and refining capacity, long reserve life, and multiple service providers.

Our drilling and completion activities are focused in the Wattenberg Field, an area that covers the western flank of the D-J Basin, predominantly in Weld County, Colorado. Currently, we are focused on the horizontal development of the Codell and Niobrara formations, which are characterized by relatively high liquids content. We operate the majority of the horizontal wells we have working interests in, and we strive to maintain a high net revenue interest in all of our operations.

Substantially all of our producing wells are either in or adjacent to the Wattenberg Field. We operate approximately 75% of our proved producing reserves, and our planned fiscal 2016 drilling and completion expenditures are focused on the Wattenberg Field. This gives us both operational focus and development flexibility to maximize returns on our leasehold position.

Core Operations

The following table provides details about our ownership interests with respect to vertical and horizontal producing wells as of March 31, 2016:

Vertical Wells

Operated Wells

Non-Operated Wells

Totals

Gross

Net

Gross

Net

Gross

Net

331

285

402

306

Horizontal Wells

Operated Wells

Non-Operated Wells

Totals

Gross

Net

Gross

Net

Gross

Net

130

216

103

In addition to the producing wells summarized in the preceding table, as of March 31, 2016, we were the operator of 21 gross (17 net) wells in progress.

During the first three months of 2016, our average net daily production was 11,510 BOED. By comparison, during the three months ended March 31, 2015, our average production rate was 7,029 BOED. By March 31, 2016, approximately 90% of our daily production was from horizontal wells as compared to less than 10% as of August 31, 2013.

During the three months ended March 31, 2016, crude oil prices declined by approximately 1% and gas prices declined by approximately 16%. Price declines can impact many aspects of our operations. For additional discussion concerning the potential impacts from declining commodity prices, please see "Drilling and Completion Operations," "Market Conditions," "Oil and Gas Commodity Contracts," and "Trends and Outlook."

Strategy

Our primary objective is to enhance shareholder value by increasing our net asset value, net reserves and cash flow through development, exploitation, exploration, and acquisitions of oil and gas properties. With current economic conditions, we intend to follow a balanced risk strategy by allocating capital expenditures to lower risk development and exploitation activities. Key elements of our business strategy include the following:


•	Concentrate on our existing core area in and around the D-J Basin, where we have significant operating experience. All of our current wells are located within the D-J Basin, and our undeveloped acreage is located either in or adjacent to the D-J Basin. Focusing our operations in this area leverages our management, technical and operational experience in the basin.

•

Develop and exploit existing oil and natural gas properties. Since inception, our principal growth strategy has been to develop and exploit our properties to add reserves. In the Wattenberg Field, we target three benches of the Niobrara formation as well as the Codell formation for horizontal drilling and production. We believe horizontal drilling is the most efficient way to recover the potential hydrocarbons and consider the Wattenberg Field to be relatively low-risk because information gained from the large number of existing wells can be applied to potential future wells. There is enough similarity between wells in the Wattenberg Field that the exploitation process is generally repeatable.

•

Improve hydrocarbon recovery through increased well density. We utilize the best available industry practices in our effort to determine the optimal recovery area for each well. When we began our operated horizontal well development program in the Wattenberg Field, we assumed spacing of 16 wells per 640 acre section. With increased experience and industry knowledge, we are now testing up to 24 horizontal wells per section.


•	Complete selective acquisitions. We seek to acquire developed and undeveloped oil and gas properties, primarily in the core Wattenberg Field. We generally seek acquisitions that will provide us with opportunities for reserve additions and increased cash flow through production enhancement and additional development and exploratory prospect generation.


•	Retain control over the operation of a substantial portion of our production. As operator of a majority of our wells and undeveloped acreage, we control the timing and selection of new wells to be drilled or existing wells to be re-completed. This allows us to modify our capital spending as our financial resources and underlying lease terms allow and market conditions permit.


•	Maintain financial flexibility while focusing on operational cost control. We strive to be a cost-efficient operator and to maintain a relatively low utilization of debt, which enhances our financial flexibility. Our high degree of operational control, as well as our focus on operating efficiencies and short return on investment cycle times, is central to our operating strategy.

•

Use the latest technology to maximize returns. Our primary focus is drilling wells that have 7,000' to 10,000' of lateral as opposed to the 4,000' laterals that were initially drilled in the Wattenberg Field. Increasing the number of wells drilled within a given drilling section, drilling longer laterals, and applying technical advances in drilling and completion designs is leading to enhanced productivity. Production results from various well designs are analyzed, and the conclusions from each analysis are factored into future well designs that take into account spacing between hydraulic fracturing stages, potential communication between wellbores, lateral length, timing and economics. Similarly, we evaluate the use of different completion fluids.

Significant Developments

Acquisition and Divestiture Activity

On May 2, 2016, the Company entered into an agreement to purchase approximately 72,000 gross (33,100 net) acres located in an area known as the Greeley-Crescent project in Weld County Colorado, primarily in and around the city of Greeley, for $505 million (the “GC Acquisition”). The Company has identified over 900 gross drilling locations on the acquired lands using an initial assumption of horizontal development with 20-24 wells per drilling unit. Estimated net daily production from the properties to be acquired was approximately 2,400 BOE in the three months ended March 31, 2016. The acquisition is expected close on two separate dates, with the undeveloped lands and non-operated production expected to close in the second quarter of 2016 with an effective date of April 1, 2016, followed by the operated producing properties (assuming regulatory approval is obtained) later in 2016 with an effective date for horizontal wells of April 1, 2016, and an effective date for vertical wells of the first day of the calendar month in which the closing for such properties occurs. The closings are subject to the completion of

customary due diligence and closing conditions, and in the case of the second closing, receipt of a regulatory approval. Accordingly, the transactions may not close in the expected timeframes or at all. The Company entered into the Commitment Letter described under “-Financing and Other” in connection with the GC Acquisition.

Financing and Other

Equity offerings

On January 27, 2016, the Company closed on the sale of 16,100,000 shares of common stock pursuant to an underwriting agreement with Credit Suisse Securities (USA) LLC, acting severally on behalf of itself and the other underwriters. The price to the Company was $5.545 per share and net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company were $89.2 million. Proceeds from the offering are expected to be used for general corporate purposes, including continuing to develop our acreage position in the Wattenberg Field in Colorado, repaying amounts borrowed under the Revolver, funding a portion of our capital expenditure program for the remainder of 2016, or other uses. Initially, proceeds were used to repay amounts borrowed under the Revolver.

On April 14, 2016, the Company closed on the sale of an additional 22,425,000 shares of common stock pursuant to an underwriting agreement with the same underwriters. The price to the Company was $7.3535 per share and net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company were $164.8 million. The proceeds of this offering are also expected to be used for general corporate purposes, including to fund development activities and/or potential future acquisitions, including a portion of the purchase price for the GC Acquisition.

Revolving Credit Facility

We continue to maintain a borrowing arrangement with our bank syndicate to provide us with liquidity, which could be used to develop oil and gas properties, acquire new oil and gas properties, and for working capital and other general corporate purposes. As of March 31, 2016, this revolving credit facility (sometimes referred to as the "Revolver") provides for maximum borrowings of $500 million, subject to adjustments based upon a borrowing base calculation, which is re-determined semi-annually using updated reserve reports. The Revolver is collateralized by certain of our assets, including producing properties, and bears a variable interest rate on borrowings, with the effective rate varying with utilization. The Revolver expires on December 15, 2019.

On January 28, 2016, the Revolver was amended in connection with the semi-annual borrowing base redetermination. The borrowing base was reduced from $163 million to $145 million, and the Revolver was further amended to (i) delete the minimum interest rate floor, (ii) delete the minimum liquidity covenant, (iii) add a current ratio covenant of 1.0 to 1.0, and (iv) delete the minimum hedging requirement. As of March 31, 2016, there were no outstanding borrowings under the Revolver. As of March 31, 2016, the entire $145 million borrowing base was available to us for future borrowings. See further discussion in Note 6 to our financial statements.

On May 3, 2016, the Revolver was further amended to, among other things, permit the issuance of senior unsecured notes, subject to certain conditions. Pursuant to the amendment, if the aggregate amount of senior unsecured notes issued from time to time exceeds $100 million, then the borrowing base will automatically be reduced by an amount equal to 25% of the stated principal amount of the senior unsecured notes in excess of $100 million.

Commitment Letter

Impairment of full cost pool

Every quarter, we perform a ceiling test as prescribed by SEC regulations for entities following the full cost method of accounting. This test determines a limit on the book value of oil and gas properties using a formula to estimate future net cash flows from oil and gas reserves. This formula is dependent on several factors and assumes future oil and natural gas prices to be equal to an unweighted arithmetic average of oil and natural gas prices derived from each of the 12 months prior to the reporting period. During the first quarter of 2016, this calculation indicated that the ceiling amount had declined, largely as a result of the decline in oil and natural gas prices, such that the ceiling was less than the net book value of oil and gas properties. As a result, we recorded a ceiling test impairment totaling $45.6 million for the three months ended March 31, 2016. This full cost ceiling impairment is recognized as a charge to earnings and may not be reversed in future periods, even if oil and natural gas prices subsequently increase.

Drilling and Completion Operations

Our drilling and completion schedule has a material impact on our production forecast and a corresponding impact on our expected future cash flows. As commodity prices have fallen, we have been able to reduce per-well drilling and completion costs. We believe that at current drilling and completion cost levels and with currently prevailing commodity prices, we can achieve reasonable well-level rates of return when drilling mid or long laterals. Should commodity prices weaken further, our operational flexibility will allow us to adjust our drilling and completion schedule, if prudent. If management believes the well-level internal rate of return will be at or below our weighted-average cost of capital, we may choose to further delay completions and/or forego drilling altogether.

During February 2016, the Company acquired undeveloped oil and gas leasehold interests in the Wattenberg field, referred to as the Fagerberg pad, for a total purchase price of approximately $10.0 million, including lands, permits, and certain surface improvements. The Company is currently drilling 14 mid-length lateral wells on part of the acquired lands.

During the three months ended March 31, 2016, we completed the drilling of 10 horizontal wells on the Vista pad. Drilling on the pad commenced in November 2015 but was halted in December 2015 when the rig contract was terminated. In January 2016, a new design rig was contracted and completed drilling operations on the pad. That rig was then moved to the Fagerberg pad and described above. During this period, we did not complete any horizontal wells. As of March 31, 2016, there are 21 gross horizontal wells in various stages of completion. For 2016, we expect to drill 55 gross (52 net) horizontal wells of mostly mid and long laterals, targeting the Codell and Niobrara zones.

Other Operations

We continue to be opportunistic with respect to acquisition efforts. In an effort to extend the length of laterals in our wells, we continue to enter into land and working interest swaps to increase our overall leasehold interest.

Production

For the three months ended March 31, 2016, our average daily production increased to 11,510 BOED as compared to 7,029 BOED for the three months ended March 31, 2015. The additional production volumes from recently completed wells more than offset the natural decline of our existing wells. The increase was achieved despite continuing mid-stream constraints, high line pressures in the northern portion of the Wattenberg Field, and the temporary suspension of production from shut-in wells due to offset operator completion activities.

Market Conditions

Market prices for our products significantly impact our revenues, net income, and cash flow. The market prices for crude oil and natural gas are inherently volatile. To provide historical perspective, the following table presents the average annual NYMEX prices for oil and natural gas for each of the last five fiscal years.



	Four Months Ended December 31,		Year Ended August 31,
	2015		2015		2014		2013		2012		2011
Average NYMEX prices
Oil (per Bbl)	$	42.82	$	60.65	$	100.39	$	94.58	$	94.88	$	91.79
Natural gas (per Mcf)	$	2.26	$	3.12	$	4.38	$	3.55	$	2.82	$	4.12

For the periods presented in this report, the following table presents the Reference Price (derived from average NYMEX prices weighted to reflect monthly sales volumes) as well as the differential between the Reference Price and the wellhead prices realized by us.



	Three Months Ended March 31,
	2016			2015
Oil (NYMEX WTI)
Average NYMEX Price	$	33.18		$	46.87
Realized Price	$	23.89		$	37.35
Differential	$	(9.29	)	$	(9.52	)

Gas (NYMEX Henry Hub)
Average NYMEX Price	$	2.00		$	2.99
Realized Price	$	1.82		$	3.35
Differential	$	(0.18	)	$	0.36

Market conditions in the Wattenberg Field require us to sell oil at prices less than the prices posted by the NYMEX. The negative differential between the prices actually received by us at the wellhead and the published indices reflects deductions imposed upon us by the purchasers for location and quality adjustments. We continue to negotiate with crude oil purchasers to obtain better differentials. With regard to the sale of natural gas and liquids, we have historically been able to sell production at prices greater than the prices posted for dry gas, primarily because prices that we receive include payment for a percentage of the value attributable to the natural gas liquids produced with the gas.

There has been a significant decline in the price of oil since the summer of 2014. Our revenues, results of operations, profitability and future growth, and the carrying value of our oil and natural gas properties, depend primarily on the prices that we receive for our oil and natural gas production. A further 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 the calculation of the “ceiling test” required under the accounting principles for companies following the “full cost” method of accounting. Our ceiling tests resulted in a total impairment charge of $45.6 million for the three months ended March 31, 2016, and additional impairments may occur in the future.

Trends and Outlook

Oil traded at $37.13 per Bbl on December 31, 2015, but declined approximately 1% through March 31, 2016 to $36.94. Natural gas traded at $2.34 per Mcf on December 31, 2015, but declined approximately 16% through March 31, 2016 to $1.96. A continuing decline in oil and gas prices (i) will reduce our cash flow which, in turn, will reduce the funds available for exploring and replacing oil and gas reserves, (ii) will potentially reduce our current Revolver borrowing base capacity and increase the difficulty of obtaining equity and debt financing and worsen the terms on which such financing may be obtained, (iii) will reduce the number of oil and gas prospects which have reasonable economic returns, (iv) may cause us to allow leases to expire based upon the value of potential oil and gas reserves in relation to the costs of exploration, (v) may result in marginally productive oil and gas wells being abandoned as non-commercial, and (vi) may cause a ceiling test impairment. However, price declines reduce the competition for oil and gas properties and correspondingly reduce the prices paid for leases and prospects.

Other factors that will most significantly affect our results of operations include (i) activities on properties that we operate, (ii) the marketability of our production, (iii) our ability to satisfy our financial and transportation obligations, (iv) completion of acquisitions of additional properties and reserves, and (v) competition from larger companies. Our revenues will also be significantly impacted by our ability to maintain or increase oil or gas production through exploration and development activities.

Horizontal well development in the Wattenberg Field is enabling operators to utilize higher density drilling within designated spacing units. When we began our operated horizontal well development program in the Wattenberg Field, we allowed for up to 16 wells per 640 acre section, but we are now testing up to 24 horizontal wells per section.

The recent decline in commodity prices has led to a corresponding decline in service costs, which directly relate to our drilling and completion costs. We have been able to reduce drilling and completion costs during the three months ended March 31, 2016 due to a combination of optimizing well designs, moving to day-rate drilling, lower contract rates for drilling rigs, fewer average days to drill, and lower completion costs. This focus on cost reduction has supported well-level economics in spite of the severe price drop in crude oil and natural gas. We continue to strive to reduce drilling and completion costs going forward to offset the negative impacts associated with lower commodity prices, but we do not believe that we will achieve the same percentage reduction of costs during 2016, and well-level rates of return may be lower, particularly if commodity prices continue to decline.

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

We have begun the use of oil gathering lines to certain production locations. We anticipate that these gathering systems would be owned and operated by independent third party companies, but that we would commit specific wellhead production to these systems. We believe that oil gathering lines would have several benefits including, a) reduced need to use trucks to gather our oil, thereby reducing truck traffic in and around our production locations, b) potentially lower gathering costs as pipeline gathering tends to be more efficient, c) less on-site oil storage capacity, resulting in lower production location facility costs, and d) generally less noise and dust.

Oil transportation and takeaway capacity has recently increased with the expansion of certain interstate pipelines servicing the Wattenberg Field. This has reversed the prior imbalance of oil production exceeding the combination of local refinery demand and the capacity of pipelines to move the oil to other markets. Depending on transportation commitments, local refinery demand, and our production volumes, we may be able to reduce the negative differential that we have historically realized on our oil production. We anticipate that there will continue to be excess pipeline takeaway capacity as additional pipelines are expected to begin operations in the second half of calendar 2016. Further details regarding posted prices and average realized prices are discussed in the section entitled “Market Conditions,” presented in this Item 2.

We believe that the GC Acquisition, if completed, will allow us to achieve significant efficiencies through the establishment of a contiguous acreage position in an attractive area in the Wattenberg Field, which should facilitate the drilling of longer lateral wells and high-grading of our drilling inventory. As discussed in “-Liquidity and Capital Resources”, completion of the acquisition will require additional financing.

Other than the foregoing, we do not know of any trends, events, or uncertainties that will have had or are reasonably expected to have a material impact on our sales, revenues, expenses, liquidity, or capital resources.

Liquidity and Capital Resources

Historically, our primary sources of capital have been net cash provided by the sale of equity and debt securities, cash flow from operations, proceeds from the sale of properties, and borrowings under bank credit facilities. Our primary use of capital has been for the exploration, development, and acquisition of oil and natural gas properties. Our future success in growing proved reserves and production will be highly dependent on capital resources available to us.

Exclusive of the GC Acquisition, we believe that our capital resources, including cash on hand, amounts available under our revolving credit facility, proceeds from the sale of equity, and cash flow from operating activities, will be sufficient to fund our planned capital expenditures and operating expenses for the next twelve months. We intend to fund the purchase price of the GC Acquisition through a combination of cash on hand and proceeds of financing transactions, including the issuance of the Senior

Notes. We would not expect to commence drilling activities on the properties to be acquired in the GC Acquisition until 2017. Assuming we finance the purchase price for the GC Acquisition as anticipated, we believe that we will have adequate liquidity to fund our planned activities 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 or existing wells to be recompleted. This allows us to modify our capital spending as our financial resources allow and market conditions support. Additionally, our relatively low utilization of debt enhances our financial flexibility as it provides a potential source of future liquidity while currently not overly burdening us with restrictive financial covenants and mandatory repayment schedules.

Sources and Uses

Our sources and uses of capital are heavily influenced by the prices that we receive for our production. During the first quarter of 2016, the NYMEX-WTI oil price ranged from a high of $41.45 per Bbl on Tuesday, March 22, 2016 to a low of $26.19 per Bbl on Thursday, February 11, 2016, while the NYMEX-Henry Hub natural gas price ranged from a high of $2.47 per MMBtu on Friday, January 8, 2016 to a low of $1.64 per MMBtu on Thursday, March 3, 2016. These markets will likely continue to be volatile in the future. To deal with the volatility in commodity prices, we maintain a flexible capital investment program and seek to maintain a high operating interest in our leaseholds with limited long-term capital commitments. This enables us to accelerate or decelerate our activities quickly in response to changing industry environments.

At March 31, 2016, we had cash and cash equivalents of $50.9 million and no outstanding balance under our revolving credit facility. Our sources and (uses) of funds for the three months ended March 31, 2016 and 2015 are summarized below (in thousands):



	Three Months Ended March 31,
	2016			2015
Cash provided by operations	$	8,122		$	39,759
Acquisitions and development of oil and gas properties and equipment	(34,374		)	(57,811		)
Net cash provided by other investing activities	—			3,696
Net cash provided by equity financing activities	88,882			190,774
Net cash used in debt financing activities	(78,192		)	—
Net (decrease) increase in cash and equivalents	$	(15,562	)	$	176,418

Net cash provided by operating activities was $8.1 million and $39.8 million for the three months ended March 31, 2016 and 2015, respectively. The decline in cash from operating activities reflects the decline in commodity prices, which was partially offset by the increase in production.

During the three months ended March 31, 2016, we received cash proceeds from and used in the following financing activities:

•

On January 27, 2016, we received cash proceeds of approximately $89.2 million (after underwriting discounts, commissions and expenses) from our public offering of 16,100,000 shares (including the shares sold pursuant to an over-allotment option exercised by the underwriters) at a price to us of $5.545 per share. These proceeds have been or are expected to be used for general corporate purposes, which may include continuing to develop our acreage position in the Wattenberg Field in Colorado, repaying amounts borrowed under the Revolver, funding a portion of our capital expenditure program for the remainder of 2016, or other uses. As discussed below, proceeds were initially used to repay amounts borrowed under the Revolver.


•	In January 2016, the Company repaid its outstanding borrowings under the Revolver of $78 million.

Subsequent to March 31, 2016, we received cash proceeds from the following financing activities:

•

On April 14, 2016, we received cash proceeds of approximately $164.8 million (after underwriting discounts, commissions and expenses) from our public offering of 22,425,000 shares (including the shares sold pursuant to an over-allotment option exercised by the underwriters) at a price to us of $7.3535 per share. These proceeds are also expected to be used for general corporate purposes, including to fund development activities and/or potential future acquisitions.

Credit Arrangements

We maintain a borrowing arrangement with a banking syndicate. The arrangement, in the form of a revolving credit facility, was most recently amended with the Eighth Amendment to the credit facility on May 3, 2016. The arrangement provides for a maximum loan commitment of $500 million; however, the maximum amount we can borrow at any one time is subject to a borrowing base limitation, which stipulates that we may borrow up to the lesser of the maximum loan commitment or the borrowing base. The borrowing base can increase or decrease based upon the value of the collateral, which secures any amounts borrowed under the line of credit. The value of the collateral will generally be derived with reference to the estimated future net cash flows from our proved oil and gas reserves, discounted by 10%. Amounts borrowed under the facility are secured by substantially all of our producing wells and developed oil and gas leases.

As of December 31, 2015, our borrowing base was $163 million, and we had $78 million outstanding under the facility, which was fully repaid during the three months ended March 31, 2016. The maturity date of the facility is December 15, 2019. On January 28, 2016, the borrowing base was reduced from $163.0 million to $145.0 million. As of March 31, 2016, the total of the $145.0 million was available to us for future borrowings. The next semi-annual redetermination has been scheduled for May 2016.

As of March 31, 2016, interest on our revolving line of credit accrues at a variable rate. The interest rate pricing grid contains a graduated escalation in applicable margin for increased utilization. Prior to the Seventh Amendment discussed below, the minimum interest rate was 2.5%.

On January 28, 2016, the Revolver was amended to (i) delete the minimum interest rate floor, (ii) delete the minimum liquidity covenant, (iii) add a current ratio covenant of 1.0 to 1.0, and (iv) delete the minimum hedging requirement.

Reconciliation of Cash Payments to Capital Expenditures

Capital expenditures reported in the statement of cash flows are calculated on a strict cash basis, which differs from the accrual basis used to calculate other amounts reported in our financial statements. Specifically, cash payments for acquisition of property and equipment as reflected in the statement of cash flows excludes non-cash capital expenditures and includes an adjustment (plus or minus) to reflect the timing of when the capital expenditure obligations are incurred and when the actual cash payment is made. On an accrual basis, capital expenditures totaled $18.6 million and $38.4 million for the three months ended March 31, 2016 and 2015, respectively. A reconciliation of the differences between cash payments and the accrual basis amounts is summarized in the following table (in thousands):



	Three Months Ended March 31,
	2016			2015
Cash payments for acquisitions	$	10,000		$	—
Cash payments for capital expenditures	24,374			57,811
Accrued costs, beginning of period	(31,414		)	(52,747		)
Accrued costs, end of period	15,324			33,077
Non-cash acquisitions, common stock	—			70
Other	277			224
Accrual basis capital expenditures	$	18,561		$	38,435

Capital Expenditures

The majority of capital expenditures during the three months ended March 31, 2016 were associated with the acquisition of certain acreage assets and the costs of drilling and completing wells that we operate. During the three months ended March 31, 2016, we completed the drilling of 10 horizontal wells on the Vista pad and began the drilling of 14 horizontal wells on the Fagerberg pad. In total, we had drilled 21 gross (17 net) wells that had not been brought into productive status as of March 31, 2016. All but eight of the wells in progress are scheduled to commence production before December 31, 2016.

With respect to our ownership interest in wells operated by other companies, we participated in drilling and completion activities on 10 gross (0.1 net) wells during the first quarter.

Capital Requirements

Our level of exploration, development, and acreage expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows, and development results, among other factors. Our primary need for capital will be to fund our anticipated drilling and completion activities, the GC Acquisition, and any other acquisitions that we may complete during the remainder of our year ending December 31, 2016.

Our preliminary capital expenditure plan continues to anticipate the use of one drilling rig during the remainder of the year ending December 31, 2016, except for a short period which we anticipate adding a second rig to drill adjoining pads to minimize the impact on the local municipality. We also regularly review capital expenditures, as has been our historical practice, throughout the year and will adjust our program based on changes in commodity prices, service costs, drilling success, and capital availability. Our total anticipated capital program for the year ended December 31, 2016 is estimated at a range between $130 million and $150 million, including approximately $30 million for discretionary seismic and land leasing, but excluding the GC Acquisition and any other potential acquisitions that we may execute.

For the near term and exclusive of the GC Acquisition as discussed above, we believe that we have sufficient liquidity to fund our needs through cash on hand, cash flow from operations, and additional borrowings available under our revolving credit facility. However, to meet all of our long-term goals, we may need to raise additional funds to drill new wells through the sale of our securities, from our revolving credit facility or from third parties willing to pay our share of drilling and completing wells. We may not be successful in raising the capital needed to drill or acquire oil or gas wells. Any wells which may be drilled by us may not produce oil or gas in commercial quantities.

Oil and Gas Commodity Contracts

We use derivative contracts to protect against the variability in cash flows created by short-term price fluctuations associated with the sale of future oil and gas production. At March 31, 2016, we had open positions covering 0.9 million barrels of oil and 2,040 MMcf of natural gas. We do not use derivative instruments for speculative purposes.

Our commodity derivative instruments may include but are not limited to “collars,” “swaps,” and “put” positions. Our derivative strategy, including the volume amounts, whether we utilize oil and/or natural gas instruments, and at what commodity prices the instruments are associated with, 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 our credit facility.

strategy inasmuch as the they establish a known range of prices to be received for the associated volume equivalents, that being bound at the upper end by the call’s strike price (the “ceiling”) and at the lower end by the put’s strike price (the “floor.”)

During periods of significant price declines, for settled contracts structured as “collars,” we will receive settlement payments from the contracts’ counterparties for the difference between the contracted “floor” price and the average posted price for the contract period. For settled “swaps,” we will receive the difference between the contracted swap price and the average posted price for the contract period, if lower. For settled “put” contracts, we will receive the difference between the put’s strike price and the average posted price for the contract period. If we decide to liquidate an “in-the-money” position prior to settlement date, we will receive the approximate fair value of the contract at that time. These realized gains increase our cash flows for the period in which they are recognized.

Conversely, during periods of significant price increases, upon settlement, we would be obligated to pay the counterparties the difference between the contract’s “ceiling” and/or swap price and the average posted price for the contract period. If liquidated prior to settlement, we would pay the approximate fair market value to close the position at that time. These realized losses decrease our cash flows for the period in which they are recognized. Losses associated with puts that expire out-of-the-money are simply the original premium paid for the contract and are recognized upon expiration.

The fair values of our open, but not yet settled, derivative contracts are estimated by obtaining independent market quotes, as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors, as well as other relevant economic measures. We compare the valuations calculated by us to valuations provided by the counterparties to assess the reasonableness of each valuation. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or us, as appropriate.

The mark-to-market fair value of the open commodity derivative contracts will generally be inversely related to the price movement of the underlying commodity. If commodity price trends reverse from period to period, prior unrealized gains may become unrealized losses and vice versa. Higher underlying commodity price volatility will generally lead to higher volatility in our unrealized gains and losses and by association, the fair value of our commodity derivative contracts. These unrealized gains and losses will also impact our net income in the period recorded.

We do not designate our commodity contracts as accounting hedges. Accordingly, we use mark-to-market accounting to value the portfolio at the end of each reporting period. Mark-to-market accounting can create non-cash volatility in our reported earnings during periods of commodity price volatility. We have experienced such volatility in the past and are likely to experience it in the future. Mark-to-market accounting treatment results in volatility of our results as unrealized gains and losses from derivatives are reported. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Gains on our derivatives generally indicate lower wellhead revenues in the future while losses indicate higher future wellhead revenues.

During the three months ended March 31, 2016, we reported an unrealized commodity activity loss of $0.8 million. Unrealized gains and losses are non-cash items. We also reported a realized gain of $2.4 million, representing the cash settlement of commodity contracts settled during the period, net of previously incurred premiums attributable to the settled commodity contracts.

At March 31, 2016, we estimated that the fair value of our various commodity derivative contracts was a net asset of $8.3 million. We value these contracts using fair value methodology that considers various inputs including a) quoted forecast prices, b) time value, c) volatility factors, d) counterparty risk, and e) other relevant factors. The fair value of these contracts as estimated at March 31, 2016 may differ significantly from the realized values at their respective settlement dates.

Our commodity derivative contracts as of March 31, 2016 are summarized below:



	Volumes		Average Collar Prices ⁽¹⁾		Average Put Prices ⁽¹⁾
Month	Oil (Bbl)	Gas (MMBtu)	Average Oil (Bbl) Price	Average Gas (MMBtu) Price	Average Oil (Bbl) Price	Average Gas (MMBtu) Price
Apr 1 to Dec 31, 2016	495,000	1,200,000	$45.00 - 65.00	$2.98 - 3.40	$48.57	N/A
Jan 1 to Aug 31, 2017	400,000	840,000	$45.00 - 70.00	$2.64 - 3.48	$52.50	N/A

⁽¹⁾ Price is at NYMEX WTI and NYMEX Henry Hub and CIG Rocky Mountain.

Results of Operations

Material changes of certain items in our statements of operations included in our financial statements for the periods presented are discussed below.

For the three months ended March 31, 2016, compared to the three months ended March 31, 2015

For the three months ended March 31, 2016, we reported net loss of $51.4 million compared to net loss of $1.0 million during the three months ended March 31, 2015. Net loss per basic and diluted share (including a ceiling test impairment of $45.6 million) were $(0.42) for the three months ended March 31, 2016 compared to net loss per share of $(0.01) per basic and diluted share for the three months ended March 31, 2015. Net loss per basic share for the three months ended March 31, 2016 decreased by $0.41 primarily due to the ceiling test impairment of $45.6 million incurred during the three months ended March 31, 2016. Revenues decreased 4% during the three months ended March 31, 2016 compared with the three months ended March 31, 2015 due to the rapid decline of commodity prices, as discussed previously. As of March 31, 2016, we had 618 gross producing wells, compared with 538 gross producing wells as of March 31, 2015. The impact of changing prices on our commodity derivative positions and a full cost ceiling impairment also drove significant differences in our results of operations between the two periods.

Oil and Gas Production and Revenues - For the three months ended March 31, 2016, we recorded total oil and gas revenues of $18.3 million compared to $18.9 million for the three months ended March 31, 2015, a decrease of $0.7 million or 4%. The following table summarizes key production and revenue statistics:



	Three Months Ended March 31,
	2016		2015		Change
Production:
Oil (MBbls ¹)	527		361		46	%
Gas (MMcf ²)	3,121		1,630		91	%
MBOE ³	1,047		633		65	%
BOED⁴	11,510		7,029		64	%

Revenues (in thousands):
Oil	$	12,594	$	13,484	(7	)%
Gas	5,679		5,454		4	%
	$	18,273	$	18,938	(4	)%
Average sales price:
Oil	$	23.89	$	37.35	(36	)%
Gas	$	1.82	$	3.35	(46	)%
BOE	$	17.45	$	29.94	(42	)%

¹"MBbl” refers to one thousand stock tank barrels, or 42,000 U.S. gallons liquid volume in reference to crude oil or other liquid hydrocarbons.

²"MMcf” refers to one million cubic feet of natural gas.

³"MBOE” refers to one thousand barrels of oil equivalent, which combines MBbls of oil and MMcf of gas by converting each six MMcf of gas to one MBbl of oil.

⁴"BOED” refers to the average number of barrels of oil equivalent produced in a day for the period.

Net oil and gas production for the three months ended March 31, 2016 averaged 11,510 BOED, an increase of 64% over average production of 7,029 BOED in the three months ended March 31, 2015. From March 31, 2015 to March 31, 2016, we added 55 net horizontal wells, including 6 (net) horizontal wells acquired in the K.P. Kaufman transaction, increasing our reserves, producing wells, and daily production totals. This decline in average sales prices by approximately 42% more than offset the effects of increased production, resulting in an overall reduction of revenues.

Lease Operating Expenses (“LOE”) - Direct operating costs of producing oil and natural gas are reported as follows (in thousands):



	Three Months Ended March 31,
	2016		2015
Production costs	$	4,266	$	4,056
Workover	33		65
Total LOE	$	4,299	$	4,121

Per BOE:
Production costs	$	4.07	$	6.41
Workover	0.03		0.10
Total LOE	$	4.10	$	6.51

Lease operating and workover costs tend to increase or decrease primarily in relation to the number of wells in production, and, to a lesser extent, on fluctuation in oil field service costs and changes in the production mix of crude oil and natural gas. During the first quarter of 2016, we experienced decreased production costs per BOE primarily as a result of increased production.

Production taxes - During the three months ended March 31, 2016, production taxes were $1.8 million, or $1.75 per BOE, compared to $1.8 million, or $2.86 per BOE, during the three months ended March 31, 2015. Taxes tend to increase or decrease primarily based on the value of oil and gas sold. As a percent of revenues, production taxes were 10.0% and 9.5% for the three months ended March 31, 2016 and 2015, respectively.

Depletion, Depreciation, and Accretion (“DD&A”) - The following table summarizes the components of DD&A:



	Three Months Ended March 31,
(in thousands)	2016		2015
Depletion of oil and gas properties	$	11,743	$	13,880
Depreciation and accretion	349		197
Total DD&A	$	12,092	$	14,077

DD&A expense per BOE	$	11.55	$	22.24

For the three months ended March 31, 2016, depletion of oil and gas properties was $11.55 per BOE compared to $22.24 per BOE for the three months ended March 31, 2015. The decrease in the DD&A rate was the result of a decrease in the ratio of total costs capitalized in the full cost pool to the estimated recoverable reserves. This ratio was significantly reduced due to the impairments of our full cost pool, which primarily occurred during the second half of calendar 2015, and the increase in our total proved reserves. Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning of quarter estimated total reserves determine the depletion rate.

Full cost ceiling impairment - During the three months ended March 31, 2016, we recognized a total impairment of $45.6 million, representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling. See Note 2, "Property and Equipment," to the Financial Statements included as part of this report.

General and Administrative (“G&A”) - The following table summarizes G&A expenses incurred and capitalized during the periods presented:



	Three Months Ended March 31,
(in thousands)	2016			2015
G&A costs incurred	$	8,092		$	4,666
Capitalized costs	(649		)	(585		)
Total G&A	$	7,443		$	4,081

Non-Cash G&A	$	2,519		$	1,351
Cash G&A	$	4,924		$	2,730
Total G&A	$	7,443		$	4,081

Non-Cash G&A per BOE	$	2.41		$	2.14
Cash G&A per BOE	$	4.70		$	4.31
G&A Expense per BOE	$	7.11		$	6.45

G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. During the three months ended March 31, 2016, we increased our employee count from 62 as of December 31, 2015 to 73, while reducing the number of consultants, advisors, and contractors that had historically been used for certain tasks.

Our G&A expense for the three months ended March 31, 2016 includes stock-based compensation of $2.5 million compared to $1.4 million for the three months ended March 31, 2015. Stock-based compensation includes a calculated value for stock options or shares of common stock that we grant for compensatory purposes. It is a non-cash charge. For stock options, the fair value is estimated using the Black-Scholes-Merton option pricing model. For restricted stock units and stock bonus shares, the fair value is estimated using the closing stock price on the grant date. Amounts are pro-rated over the vesting terms of the award agreements, which are generally three to five years.

Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the exploration and development of properties. Those costs are reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from the three months ended March 31, 2015 to the three months ended March 31, 2016 reflects our increased headcount of individuals performing activities to maintain and acquire leases and develop our properties.

Commodity derivative gains - As more fully described in the paragraphs titled “Oil and Gas Commodity Contracts” located in “Liquidity and Capital Resources,” 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, 2016, we realized a cash settlement gain of $2.4 million, net of previously incurred premiums attributable to the settled commodity contracts. For the prior comparable period, we realized a cash settlement gain of $13.5 million.

In addition, for the three months ended March 31, 2016, we recorded an unrealized loss of $0.8 million to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the three months ended March 31, 2015, we reported an unrealized loss of $10.1 million. Unrealized losses are non-cash items.

Income taxes - We reported no income tax benefit for the three months ended March 31, 2016, calculated at an effective tax rate of 0%. During the comparable prior year period, we reported income tax benefit of $0.7 million, calculated at an effective tax rate of 42%. As explained in more detail below, during the period ended March 31, 2016, the effective tax rate was substantially reduced by recognition of a full valuation allowance on the net deferred tax assets. During the three months ended March 31, 2016, the effective tax rate differed from the statutory rate, primarily due to the recognition of a valuation allowance recorded against deferred tax assets.

For tax purposes, we have a net operating loss (“NOL”) carryover of $44.2 million, which is available to offset future taxable income. The NOLs will begin to expire, if not used, in 2031. As a result of the NOLs and other tax strategies, it appears that payment of any tax liability will be substantially deferred into future years.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. Based on the level of losses in the current period and the level of uncertainty with respect to future taxable income over the period in which the deferred tax assets are deductible, a valuation allowance has been provided as of March 31, 2016. During the 2015 comparable period, we reached the opposite conclusion; therefore, we did not record a valuation allowance against any of our deferred tax assets in that period.

Non-GAAP Financial Measures

In addition to financial measures presented on the basis of accounting principles generally accepted in the United States of America ("US GAAP"), we present certain financial measures which are not prescribed by US GAAP ("non-GAAP"). A summary of these measures is described below.

Adjusted EBITDA

We use "adjusted EBITDA," a non-GAAP financial measure, for internal managerial purposes when evaluating period-to-period comparisons. This measure is not a measure of financial performance under US GAAP and should be considered in addition to, not as a substitute for, cash flows from operations, investing, or financing activities, and it should not be viewed as a liquidity measure or indicator of cash flows reported in accordance with US GAAP. Our definition of adjusted EBITDA may not be comparable to measures with similar titles reported by other companies. Also, in the future, we may disclose different non-GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure.

We define adjusted EBITDA as net loss adjusted to exclude the impact of the items set forth in the table below. We believe that adjusted EBITDA is relevant because similar measures are widely used in our industry.

The following table presents a reconciliation of adjusted EBITDA, a non-GAAP financial measure, to net loss, its nearest GAAP measure:



	Three Months Ended March 31,
	2016			2015
Adjusted EBITDA:
Net loss	$	(51,401	)	$	(993	)
Depreciation, depletion, and accretion	12,092			14,077
Full cost ceiling impairment	45,621			—
Income tax benefit	—			(709		)
Stock-based compensation	2,519			1,604
Mark to market of commodity derivative contracts:
Total gain on commodity derivatives contracts	(1,680		)	(3,461		)
Cash settlements on commodity derivative contracts	3,059			13,742
Cash premiums paid for commodity derivative contracts	—			(3,498		)
Interest expense (income)	(2		)	15
Adjusted EBITDA	$	10,208		$	20,777

Critical Accounting Policies

We prepare our financial statements and the accompanying notes in conformity with US GAAP, which requires management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. We identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our financial condition, results of operations, or liquidity and the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection, and disclosure of each of the critical accounting policies.

There have been no significant changes to our critical accounting policies and estimates or in the underlying accounting assumptions and estimates used from those disclosed Management’s Discussion and Analysis of Financial Condition and Results of Operations and in the consolidated financial statements and accompanying notes contained in the Transition Report on Form 10-K filed with the SEC on April 22, 2016. However, certain events during the first quarter increased the significance of our policies with respect to the evaluation of goodwill. This item is discussed in Note 1, Organization and Summary of Significant Accounting Policies, to the accompanying condensed financial statements included elsewhere in this report. Note 1 also provides information regarding recently issued accounting pronouncements.

We call your attention to the increased significance of the ceiling test as disclosed in Note 2, Property and Equipment, to the accompanying condensed financial statements included elsewhere in this report. During the quarter ended March 31, 2016, we recorded an impairment in conjunction with performing a ceiling test as prescribed by SEC Regulation S-X Rule 4-05.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS

Commodity Price Risk - Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. The volatility of oil prices affects our results to a greater degree than the volatility of gas prices, as approximately 69% of our revenue during the three months ended March 31, 2016 was from the sale of oil. A $10 per barrel change in our realized oil price would have resulted in a $5.3 million change in revenues during the three months ended March 31, 2016, while a $0.50 per Mcf change in our realized gas price would have resulted in a $1.6 million change in our natural gas revenues for the three months ended March 31, 2016.

During the three months ended March 31, 2016, the price of oil and natural gas declined significantly. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the levels of demand and supply for oil (in global or local markets), the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels, the strength of the US dollar compared to other currencies, and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations, and capital resources.

We attempt to mitigate fluctuations in short-term cash flow resulting from changes in commodity prices by entering into derivative positions on a portion of our expected oil and gas production. We use derivative contracts to cover up to 85% of expected proved developed producing production as projected in our semi-annual reserve report, generally over a period of two years. We do not enter into derivative contracts for speculative or trading purposes. As of March 31, 2016, we had open crude oil derivatives in a net asset position with a fair value of $8.3 million. A hypothetical upward or downward shift of 10% in the NYMEX forward curve of crude oil and natural gas prices would change the fair value of our position by approximately $1.5 million.

Interest Rate Risk - At March 31, 2016, we had no debt outstanding under our bank credit facility. Interest on our credit facility accrues at a variable rate, based upon either the Prime Rate or the London InterBank Offered Rate (“LIBOR”) plus an applicable margin. At March 31, 2016, we were incurring interest at a rate of 2.5%. We are exposed to interest rate risk on the bank credit facility if the variable reference rates increase. Historically, a decrease in the variable interest rates would not have a significant impact on us, as the bank credit facility had a minimum interest rate of 2.5%. As of January 28, 2016, the minimum interest rate was removed from the credit facility. If interest rates increase, our monthly interest payments would increase and our available cash flow would decrease. We estimate that if market interest rates increased by 1% to an annual rate of 3.5%, or decreased by 1% to an annual rate of 1.5%, our interest payments in the three months ended March 31, 2016 would have changed by approximately $0.1 million.

Under current market conditions, we do not anticipate significant changes in prevailing interest rates for the next year and we have not undertaken any activities to mitigate potential interest rate risk. There was no material change in interest rate risk during the quarter ended March 31, 2016.

Counterparty Risk - As described in the discussion about Commodity Price Risk, we enter into commodity derivative agreements to mitigate short-term price volatility. These derivative financial instruments present certain counterparty risks. We are exposed to potential loss if a counterparty fails to perform according to the terms of the agreement. The failure of any of the counterparties to fulfill their obligations to us could adversely affect our results of operations and cash flows. We do not require collateral or other security to be furnished by counterparties. We seek to manage the counterparty risk associated with these contracts by limiting transactions to well capitalized, well established, and well known counterparties that have been approved by our senior officers. There can be no assurance, however, that our practice effectively mitigates counterparty risk.

Our exposure to counterparty risk has slightly declined during the last period as the amounts due to us from counterparties has decreased.


ITEM 4.	CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered by this report on Form 10-Q (the “Evaluation Date”). Based on such evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of the Evaluation Date, our disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II


Item 1.	Legal Proceedings

During the quarter, there were no material developments regarding legal matters, which were previously described under Item 3, Legal Proceedings, of the Transition Report on Form 10-K filed with the Securities and Exchange Commission on April 22, 2016. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.


Item 1A.	Risk Factors

We face many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity, and the trading price of our common stock are described under Item 1A, Risk Factors, of the Transition Report on Form 10-K filed with the Securities and Exchange Commission on April 22, 2016. This information should be considered carefully, together with other information in this report and other reports and materials that we file with the SEC. In addition, there are numerous risks and uncertainties associated with the GC Acquisition, including those set forth below:

If completed, the GC Acquisition may not achieve its intended results and may result in us assuming unanticipated liabilities. To date, we have conducted only limited diligence regarding the assets and liabilities we would assume in the transaction. These risks are heightened because the GC Acquisition, if consummated, would involve our acquisition of a material amount of acreage relative to our current acreage position.

We entered into the GC Agreement with the expectation that the GC Acquisition would result in various benefits, growth opportunities and synergies. Achieving the anticipated benefits of the transaction is subject to a number of risks and uncertainties. For example, under the GC Agreement, we have the opportunity to conduct customary environmental and title due diligence following the execution of the agreement, but our diligence efforts to date have been limited. As a result, we may discover title defects or adverse environmental or other conditions of which we are currently unaware. Environmental, title and other problems could reduce the value of the properties to us, and, depending on the circumstances, we could have limited or no recourse to the sellers with respect to those problems. We would assume substantially all of the liabilities associated with the acquired properties and would be entitled to indemnification in connection with those liabilities in only limited circumstances and in limited amounts. We cannot assure that such potential remedies will be adequate for any liabilities we incur, and such liabilities could be significant. In addition, certain of the properties to be acquired are subject to consents to assign. If the sellers cannot obtain all applicable consents, we may not be able to acquire certain properties as originally contemplated and our expected benefits of the GC Acquisition may be adversely affected. Similarly, if the second closing under the purchase and sale agreement for the acquisition (the “GC Agreement”) is delayed for a substantial period, we will not be able to control operations on those properties during that period, which would increase the risk that certain leases will expire before production is established, and this could materially detract from the value of the properties to be acquired pursuant to either closing. Also, it is uncertain whether our existing operations and the acquired properties and assets can be integrated in an efficient and effective manner. The integration of operations following the GC Acquisition will require the dedication of management and other personnel, which may distract their attention from our day-to-day business and operations and prevent us from realizing benefits from other opportunities. Completing the integration process may be more expensive than anticipated, and we cannot assure you that we will be able to effect the integration of these operations smoothly or efficiently or that the anticipated benefits of the transaction will be achieved.

The risks involved in the GC Acquisition are heightened due to the size of the acquisition. The GC Acquisition, if consummated, would involve our acquisition of approximately 33,100 net acres in the Wattenberg Field, which is a material amount of acreage relative to our current acreage position.

Actual reserves and production associated with the properties to be acquired in the GC Acquisition may be substantially less than we expect.

As with other acquisitions, the success of the GC Acquisition depends on, among other things, the accuracy of our assessment of the number and quality of the drilling locations associated with the properties to be acquired, future oil and natural gas prices, reserves and production, and future operating costs and various other factors. These assessments are necessarily inexact. Our assessment of certain of these factors is based in part on information provided to us by the sellers, including historical production data. Our independent reserve engineers have not provided a report regarding the estimates of reserves with respect to the properties subject to the GC Acquisition. The assumptions on which our internal estimates have been based may prove to be incorrect in a number of material ways, resulting in our not realizing the expected benefits of the acquisition. In addition, the representations, warranties and indemnities of the sellers contained in the GC Agreement are limited, and we may not have recourse against the sellers in the event that the acreage is less valuable than we currently believe. As a result, we may not recover the purchase price

for the acquisition from the sale of production from the properties being acquired or recognize an acceptable return from such sales.

The development of the properties to be acquired will be subject to all of the risks and uncertainties associated with oil and natural gas activities as described in the “Risk Factors” section of our Transition Report on Form 10-K for the period ended December 31, 2015.

A significant portion of the value of the GC Acquisition is associated with undeveloped acreage that may not be economic.

A large portion of the acreage we are acquiring in the GC Acquisition is undeveloped, and our plans, development schedule and production schedule associated with the acreage may fail to materialize. As a result, our investment in these areas may not be as economic as we anticipate, and we could incur material writedowns of unevaluated properties.

We will incur significant transaction expenses and costs in connection with the GC Acquisition, and completion of the acquisition will increase our indebtedness.

We expect to incur a number of significant transaction-related costs associated with the GC Acquisition, including costs associated with the issuance of the Senior Notes. We continue to assess the magnitude of these costs, and additional unanticipated costs may be incurred in the integration of the properties to be acquired, which may be significant.

In addition, the issuance of the Senior Notes in connection with the closing of the GC Acquisition will increase our indebtedness. As a result, the risks described in the “Risk Factors” section of our Transition Report on Form 10-K for the period ended December 31, 2015 relating to indebtedness will be increased. In particular, see the risk factors entitled, “-Risks Relating to Our Business and the Industry-Potential indebtedness may adversely affect our cash flow and our ability to operate our business, remain in compliance with debt covenants and make payments on our debt”, “-Risks Relating to Our Business and the Industry -A significant amount of cash may be required to service our indebtedness. Our ability to generate cash depends on many factors beyond our control, and any failure to meet our debt obligations could harm our business, financial condition, and results of operations”, and “-Risks Relating to Our Business and the Industry-Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions, and engage in other business activities that may be in our best interests”.

The GC Agreement contains conditions to closing, some of which are beyond our control, and we may be unable to consummate the GC Acquisition in its entirety or with respect to the second closing.

The GC Agreement contains closing conditions, including, with respect to the second closing only, obtaining a release of a consent decree burdening certain of the properties to be acquired, as well as customary closing conditions. It is possible that one or more of the conditions in the GC Agreement will not be satisfied, and we may be unable or unwilling to consummate the GC Acquisition. If the acquisition is not closed on account of a breach of any representations, warranties or covenants in the GC Agreement on our part, we may be required to forfeit our $50.5 million earnest money deposit as liquidated damages.

Failure to complete the GC Acquisition could negatively affect our stock price as well as our business and financial results.

If either or both of the closings under the GC Agreement are not completed, we will be subject to a number of risks, including but not limited to the following:


•	We must pay costs related to the acquisition including, among others, legal, accounting and financial advisory fees, whether the acquisition is completed or not.


•	We may experience negative reactions from the financial markets.


•	We could be subject to litigation related to the failure to complete the acquisition.

Each of these factors may adversely affect our business, financial results and stock price. If either of the closings under the GC Agreement are not consummated, holders of our common stock would be exposed to the risks described above and various other risks.


Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds

Purchases of equity securities by the Company



Period	Total Number of Shares Purchased	Average Price Paid per Share
January 1, 2016 - January 31, 2016 ⁽¹⁾	—	$	—
February 1, 2016 - February 29, 2016 ⁽¹⁾	21,003	$	6.34
March 1, 2016 - March 31, 2016 ⁽¹⁾	20,062	$	7.51
Total	41,065

(1) Pursuant to statutory minimum withholding requirements, certain of our employees exercised their right to "withhold to cover" as a tax payment method for the vesting and exercise of certain shares. These elections were outside of any publicly announced repurchase plan.


Item 3.	Defaults Upon Senior Securities

None.


Item 4.	Mine Safety Disclosures

Not applicable


Item 5.	Other Information

None.

Item 6. Exhibits



Exhibit Number	Exhibit
3.2	Bylaws of the Company, as amended by the First Amendment to the Bylaws dated January 21, 2016
31.1	Certification of the Principal Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification of the Principal Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32	Certifications of the Principal Executive Officer and Principal Financial Officer pursuant to 18 USC 1350, as adopted, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase
101.LAB	XBRL Taxonomy Extension Label Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

SIGNATURES

Pursuant to the requirements of Section 13 or 15(a) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized on the 3rd day of May, 2016.



	SYNERGY RESOURCES CORPORATION

	/s/ Lynn A. Peterson
	Lynn A. Peterson, President and Chief Executive Officer (Principal Executive Officer)

	/s/ James P. Henderson
	James P. Henderson, Executive Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer)

	/s/ Frank L. Jennings
	Frank L. Jennings, Vice President and Chief Accounting Officer (Principal Accounting Officer)

SRC Energy Inc. - FORM 10-Q - May 3, 2016

Attached files

SRC Energy Inc. Reports