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

Attached files

file	filename
EX-99.1 - EXHIBIT 99.1 - SRC Energy Inc.	ninthamendmentcreditagreem.htm
EX-32 - EXHIBIT 32 - SRC Energy Inc.	exhibit3220160930.htm
EX-31.2 - EXHIBIT 31.2 - SRC Energy Inc.	exhibit31220160930.htm
EX-31.1 - EXHIBIT 31.1 - SRC Energy Inc.	exhibit31120160930.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 September 30, 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: 200,577,084 outstanding shares of common stock as of October 28, 2016.

SYNERGY RESOURCES CORPORATION

Index



		Page
Part I - FINANCIAL INFORMATION

Item 1.	Financial Statements (unaudited)

	Condensed Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015	2

	Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2016 and 2015	3

	Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2016 and 2015	4

	Notes to Condensed Consolidated Financial Statements	5

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	25

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43

Item 4.	Controls and Procedures	44

Part II - OTHER INFORMATION

Item 1.	Legal Proceedings	45

Item 1A.	Risk Factors	45

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46

Item 3.	Defaults of Senior Securities	46

Item 4.	Mine Safety Disclosures	46

Item 5.	Other Information	46

Item 6.	Exhibits	47

SIGNATURES		48

SYNERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited; in thousands, except share data)



ASSETS	September 30, 2016			December 31, 2015
Current assets:
Cash and cash equivalents	$	63,757		$	66,499
Accounts receivable:
Oil and gas sales	11,925			12,527
Trade	8,738			12,156
Commodity derivative assets	1,610			6,572
Escrow deposit	18,244			—
Other current assets	2,612			1,944
Total current assets	106,886			99,698

Property and equipment:
Oil and gas properties, full cost method:
Unproved properties and land, not subject to depletion	458,802			103,423
Proved properties, net of accumulated depletion	382,180			422,778
Oil and gas properties, net	840,982			526,201
Other property and equipment, net	1,626			646
Total property and equipment, net	842,608			526,847

Commodity derivative assets	22			2,996
Goodwill	40,711			40,711
Other assets	2,392			2,364

Total assets	$	992,619		$	672,616

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	42,415		$	36,573
Revenue payable	13,614			13,603
Production taxes payable	14,177			24,530
Asset retirement obligations	2,319			—
Total current liabilities	72,525			74,706

Revolving credit facility	—			78,000
Notes payable, net of issuance costs	75,424			—
Commodity derivative liabilities	80			—
Asset retirement obligations	11,529			13,400
Total liabilities	159,558			166,106

Commitments and contingencies (See Note 16)

Shareholders' equity:
Preferred stock - $0.01 par value, 10,000,000 shares authorized: no shares issued and outstanding	—			—
Common stock - $0.001 par value, 300,000,000 shares authorized: 200,537,625 and 110,033,601 shares issued and outstanding, respectively	201			110
Additional paid-in capital	1,146,621			595,671
Retained deficit	(313,761		)	(89,271		)
Total shareholders' equity	833,061			506,510

Total liabilities and shareholders' equity	$	992,619		$	672,616

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

SYNERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015

Oil and gas revenues	$	26,234		$	33,378		$	68,454		$	80,602

Expenses:
Lease operating expenses	3,819			5,078			14,963			12,944
Production taxes	(1,461		)	3,099			2,509			7,485
Depreciation, depletion, and accretion	9,635			18,417			33,001			48,231
Full cost ceiling impairment	25,453			96,340			215,223			99,340
Transportation commitment charge	205			—			505			—
General and administrative	8,236			5,432			23,199			15,755
Total expenses	45,887			128,366			289,400			183,755

Operating loss	(19,653		)	(94,988		)	(220,946		)	(103,153		)

Other income (expense):
Commodity derivatives gain (loss)	407			6,619			(3,617		)	5,697
Interest expense, net	—			(87		)	—			(247		)
Interest income	10			15			179			69
Total other income (expense)	417			6,547			(3,438		)	5,519

Loss before income taxes	(19,236		)	(88,441		)	(224,384		)	(97,634		)

Income tax expense (benefit)	5			(10,520		)	106			(14,132		)
Net loss	$	(19,241	)	$	(77,921	)	$	(224,490	)	$	(83,502	)

Net loss per common share:
Basic	$	(0.10	)	$	(0.74	)	$	(1.36	)	$	(0.82	)
Diluted	$	(0.10	)	$	(0.74	)	$	(1.36	)	$	(0.82	)

Weighted-average shares outstanding:
Basic	200,515,555			105,100,849			164,771,544			102,329,504
Diluted	200,515,555			105,100,849			164,771,544			102,329,504

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

SYNERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited; in thousands)



	Nine Months Ended September 30,
	2016			2015
Cash flows from operating activities:
Net loss	$	(224,490	)	$	(83,502	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation, and accretion	33,001			48,231
Full cost ceiling impairment	215,223			99,340
Provision for deferred taxes	—			(38,097		)
Stock-based compensation	7,285			7,688
Mark-to-market of commodity derivative contracts:
Total loss (gain) on commodity derivatives contracts	3,617			(5,697		)
Cash settlements on commodity derivative contracts	5,137			28,343
Cash premiums paid for commodity derivative contracts	—			(4,562		)
Changes in operating assets and liabilities:
Accounts receivable
Oil and gas sales	602			8,678
Trade	2,679			12,686
Accounts payable and accrued expenses	1,761			663
Revenue payable	(363		)	(5,886		)
Production taxes payable	(10,158		)	2,695
Other	(1,101		)	(827		)
Net cash provided by operating activities	33,193			69,753

Cash flows from investing activities:
Acquisition of oil and gas properties	(499,831		)	—
Well costs and other capital expenditures	(82,318		)	(110,224		)
Earnest money deposit	(18,244		)	(5,850		)
Proceeds from sales of oil and gas properties	24,223			6,239
Net cash used in investing activities	(576,170		)	(109,835		)

Cash flows from financing activities:
Proceeds from sale of stock	565,398			200,100
Offering costs	(21,987		)	(9,255		)
Shares withheld for payment of employee payroll taxes	(510		)	(621		)
Proceeds from revolving credit facility	55,000			—
Principal repayments on revolving credit facility	(133,000		)	(68,000		)
Financing fees on revolving credit facility	(269		)	—
Proceeds from issuance of notes payable	80,000			—
Financing fees on issuance of notes payable	(4,397		)	—
Net cash provided by financing activities	540,235			122,224

Net increase (decrease) in cash and equivalents	(2,742		)	82,142

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

Cash and equivalents at end of period	$	63,757		$	121,712

Supplemental Cash Flow Information (See Note 17)

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

SYNERGY RESOURCES CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)


1.	Organization and Summary of Significant Accounting Policies

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

Basis of Presentation: The Company operates in one business segment, and all of its operations are located in the United States of America.

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

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

Change of Year End: On February 25, 2016, the Company's board of directors approved a change in fiscal year end from August 31 to December 31 effective with the fiscal year ending December 31, 2016. The prior year figures presented herein have been recast to conform to the new fiscal year end.

Interim Financial Information: The unaudited condensed consolidated interim financial statements included herein have been prepared by the Company pursuant to the rules and regulations of the SEC as promulgated in Rule 10-01 of Regulation S-X. The condensed consolidated balance sheet as of December 31, 2015 was derived from the Company's Transition Report on Form 10-K for the four months ended December 31, 2015 as filed with the SEC on April 22, 2016. Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with US GAAP have been condensed or omitted pursuant to such SEC rules and regulations. The Company believes that the disclosures included are adequate to make the information presented not misleading and recommends that these condensed financial statements be read in conjunction with the audited financial statements and notes thereto for the four months ended December 31, 2015.

In our opinion, the unaudited condensed consolidated financial statements contained herein reflect all adjustments, consisting solely of normal recurring items, which are necessary for the fair presentation of the Company's financial position, results of operations, and cash flows on a basis consistent with that of its prior audited financial statements. However, the results of operations for interim periods may not be indicative of results to be expected for the full fiscal year.

Major Customers: The Company sells production to a limited number of customers. Customers representing 10% or more of our oil and gas revenue for each of the periods presented are shown in the following table:



	Three Months Ended September 30,		Nine Months Ended September 30,
Major Customers	2016	2015	2016	2015
Company A	27%	*	38%	*
Company B	20%	14%	20%	11%
Company C	12%	*	*	*
Company D	10%	*	11%	*
Company E	*	72%	*	65%
Company F	*	*	*	12%

* less than 10%

Based on the current demand for oil and natural gas, the availability of other buyers, and the Company having the option to sell to other buyers if conditions warrant, the Company believes that its oil and gas production can be sold in the market in the event that it is not sold to the Company’s existing customers.

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

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



	As of	As of
Major Customers	September 30, 2016	December 31, 2015
Company A	24%	*
Company B	17%	*
Company C	15%	13%
Company D	*	13%
Company E	*	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. We have historically performed the annual impairment assessment as of August 31^st. During 2016, we changed the date of our annual goodwill impairment assessment to October 1^st. With respect to its annual goodwill testing date, management believes that this voluntary change in accounting method is preferable as it better aligns the annual impairment testing date with the Company’s new fiscal year end, which was also changed in 2016. This change in assessment date was applied prospectively and did not delay, accelerate or avoid a potential impairment charge.

When evaluating goodwill for impairment, the Company may first perform an assessment of qualitative factors to determine if the fair value of the reporting unit is more-likely-than-not greater than its carrying amount. If, based on the review of the qualitative factors, the Company determines it is not more-likely-than-not that the fair value of a reporting unit is less than its carrying value, the required two-step impairment test can be bypassed. If the Company does not perform a qualitative assessment or if the fair value of the reporting unit is not more-likely-than-not greater than its carrying value, the Company must perform the first step of the two-step impairment test and calculate the estimated fair value of the reporting unit. If the carrying value of the reporting unit exceeds the estimated fair value, there is an indication that impairment may exist, and the second step must be performed to measure the amount of impairment loss. The amount of impairment for goodwill is measured as the amount by which the carrying amount of the goodwill exceeds the implied fair value of the goodwill. As a result of declining oil prices, the Company performed an interim goodwill test as of March 31, 2016 which did not result in an impairment. The Company utilized a market approach in estimating the fair value of the reporting unit. The primary assumptions used in the Company's impairment evaluations are based on the best available market information at the time and reflect significant management judgments. Changes in these assumptions or future economic conditions could impact the Company's conclusion regarding an impairment of goodwill and potentially result in a non-cash impairment loss in a future period.

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

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

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" ("ASU 2016-02"), which establishes a comprehensive new lease standard designed to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In transition, lessees

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

In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)" ("ASU 2014-09"), which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current revenue recognition guidance. 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 condensed 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.

Change in estimate: During the three months ended September 30, 2016, the Company reduced its estimate for production taxes based on recent historical experience and additional information received during the period. As a result, the Company decreased the accrual for production taxes to be paid by approximately $3.6 million which reduced our operating loss for the three- and nine-months ended September 30, 2016 by a corresponding amount, or $0.02 per basic and diluted common share.

Reclassifications: We have reclassified costs attributable to surface locations of $4.5 million from "Other property and equipment, net" to "Unproved properties and land, not subject to depletion" within the accompanying condensed consolidated balance sheets to conform prior period balances to current period presentation.


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
	September 30, 2016			December 31, 2015
Oil and gas properties, full cost method:
Costs of unproved properties and land, not subject to depletion:
Lease acquisition, land, and other costs	$	401,103		$	93,600
Wells in progress	57,699			9,823
Subtotal, unproved properties	458,802			103,423

Costs of proved properties:
Producing and non-producing	900,958			691,659
Wells in progress	12,594			11,487
Less, accumulated depletion and full cost ceiling impairments	(531,372		)	(280,368		)
Subtotal, proved properties, net	382,180			422,778

Costs of other property and equipment:
Other property and equipment	2,188			1,270
Less, accumulated depreciation	(562		)	(624		)
Subtotal, other property and equipment, net	1,626			646

Total property and equipment, net	$	842,608		$	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 September 30, 2016 ceiling test used average realized prices of $31.95 per barrel and $2.21 per Mcf as compared to the June 30, 2016 prices of $33.82 per barrel and $2.16 per Mcf, a change of approximately (6)% and 2%, respectively. As a result of these periodic reviews, the Company concluded that its net capitalized costs of oil and natural gas properties exceeded the ceiling amount, resulting in the recognition of ceiling test impairments totaling $25.5 million and $215.2 million during the three and nine months ended September 30, 2016, respectively. During the three and nine months ended September 30, 2015, the Company's ceiling tests resulted in total impairments of $96.3 million and $99.3 million, respectively.

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 September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Capitalized overhead	$	1,757	$	589	$	4,745	$	1,640


3.	Acquisitions and Divestitures

Acquisitions

As a strategy, the Company seeks to acquire developed and undeveloped oil and gas properties, primarily in the core Wattenberg Field. The objective of these acquisitions is to provide additional mineral acres upon which the Company can drill wells and produce hydrocarbons. The Company acquired certain oil and gas and other assets that affect the comparability between the nine months ended September 30, 2016 and 2015, as described below.

August 2016 Acquisition

During August 2016, the Company completed two acquisitions of certain assets for a total purchase price of $3.9 million composed of cash and assumed liabilities. The acquired properties were comprised primarily of undeveloped oil and gas leasehold interests.

June 2016 Acquisition

On May 2, 2016, we entered into a purchase and sale agreement ("GC Agreement") with a large publicly-traded company, pursuant to which we agreed to acquire a total of approximately 72,000 gross (33,100 net) acres in an area referred to as the Greeley-Crescent project in the Wattenberg Field for $505 million (the "GC Acquisition"). Estimated net daily production from the acquired properties was approximately 2,400 barrels of oil equivalent ("BOE") at the time of entering into the GC Agreement.

On June 14, 2016, the Company closed on the portion of the assets comprised of the undeveloped oil and gas leasehold interests and non-operated production. The effective date of this part of the transaction was April 1, 2016. A second closing will cover the operated producing properties and is expected to be completed in 2017. The Company has placed $18.2 million in escrow to be released upon the second closing. For the second closing, the effective date will be April 1, 2016 for the horizontal wells to be acquired, and the first day of the calendar month in which the closing for such properties occurs for the vertical wells. The second closing is subject to certain closing conditions, including the receipt of regulatory approval. Accordingly, the second closing of the transaction may not close in the expected time frame or at all.

The first closing on June 14, 2016 was for a total purchase price of $487.4 million, net of customary closing adjustments. The purchase price was composed of $486.3 million in cash plus the assumption of certain liabilities. The first closing encompassed approximately 33,100 net acres of oil and gas leasehold interests and related assets and net production of approximately 800 BOE per day ("BOED") at the time of entering into the GC Agreement.

The first closing was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of June 14, 2016. Transaction costs of $0.5 million related to the acquisition were expensed as incurred. The following allocation of the purchase price is preliminary

and includes significant use of estimates. The fair values of the assets acquired and liabilities assumed are preliminary and are subject to revision as the Company continues to evaluate the fair value of this acquisition. Accordingly, the allocation will change as additional information becomes available and is assessed, and the impact of such changes may be material. The following table summarizes the preliminary purchase price and preliminary estimated fair values of assets acquired and liabilities assumed (in thousands):



Preliminary Purchase Price	June 14, 2016
Consideration given:
Cash	$	486,261
Net liabilities assumed, including asset retirement obligations	1,120
Total consideration given	$	487,381

Preliminary Allocation of Purchase Price
Proved oil and gas properties ⁽¹⁾	$	133,870
Unproved oil and gas properties	353,511
Total fair value of assets acquired	$	487,381

⁽¹⁾ Proved oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rate of 11.5%, and assumptions regarding the timing and amount of future development and operating costs.

For the three and nine months ended September 30, 2016, the results of operations of the acquired assets, representing approximately $2.0 million and $2.6 million of revenue and $1.8 million and $2.3 million of operating income, respectively, have been included in the Company's condensed consolidated statements of operations.

The following table presents the unaudited pro forma combined results of operations for the three and nine months ended September 30, 2016 as if the first closing had occurred on January 1, 2015. The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through cash, additional depreciation expense, costs directly attributable to the acquisition, and operating costs incurred as a result of the assets acquired. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.



	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2016			2015			2016			2015
Oil and gas revenues	$	26,234		$	36,481		$	71,940		$	89,998
Net loss	$	(19,241	)	$	(79,471	)	$	(227,479	)	$	(87,104	)

Net loss per common share
Basic	$	(0.10	)	$	(0.44	)	$	(1.14	)	$	(0.49	)
Diluted	$	(0.10	)	$	(0.44	)	$	(1.14	)	$	(0.49	)

February 2016 Acquisition

On February 4, 2016, the Company completed the acquisition of undeveloped oil and gas leasehold interests for a total purchase price of $10.0 million. The purchase price has been allocated as $8.6 million to proved oil and gas properties and $1.4 million to unproved oil and gas properties on a preliminary basis. This allocation reflects significant use of estimates.

October 2015 Acquisition

On October 20, 2015, the Company closed the acquisition of certain assets ("KPK Acquisition") from a private company for a total purchase price of $85.2 million, net of customary closing adjustments. The purchase price was composed of $35.0 million in cash and $49.8 million in restricted common stock of the Company plus the assumption of certain liabilities. The KPK Acquisition encompassed approximately 4,300 net acres of oil and gas leasehold interests and related assets and net production

of approximately 1,200 BOED at the time of purchase.

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 table summarizes the final purchase price and final fair values of assets acquired and liabilities assumed (in thousands):



Purchase Price	October 20, 2015
Consideration given:
Cash	$	35,045
Synergy Resources Corp. common stock ⁽¹⁾	49,840
Net liabilities assumed, including asset retirement obligations	284
Total consideration given	$	85,169

Allocation of Purchase Price
Proved oil and gas properties ⁽²⁾	$	46,333
Unproved oil and gas properties	37,766
Other assets, including accounts receivable	1,070
Total fair value of assets acquired	$	85,169

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

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

For the three and nine months ended September 30, 2016, the results of operations of the acquired assets, representing approximately $1.2 million and $3.7 million of revenue and $1.0 million and $3.3 million of operating income, respectively, have been included in the Company's condensed consolidated statements of operations.

The following table presents the unaudited pro forma combined results of operations for the three and nine months ended September 30, 2015 as if the transaction had occurred on January 1, 2015. The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through the issuance of common stock and cash, additional depreciation expense, costs directly attributable to the acquisition, and operating costs incurred as a result of the assets acquired. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.



(in thousands)	Three Months Ended September 30, 2015			Nine Months Ended September 30, 2015
Oil and gas revenues	$	35,785		$	90,676
Net loss	$	(77,556	)	$	(82,923	)

Net loss per common share
Basic	$	(0.71	)	$	(0.78	)
Diluted	$	(0.71	)	$	(0.78	)

Divestitures

During the second quarter of 2016, the Company closed on two transactions involving the divestiture of approximately 3,700 net undeveloped acres and 107 vertical wells primarily in Adams County, Colorado for total consideration of $25.2 million, subject to customary purchase price adjustments. We received $24.2 million in cash and transferred liabilities of $0.5 million to the buyers, and $0.5 million in cash was released to us from escrow in October 2016. The divested assets had associated production of approximately 200 BOED at the time of sale. The vertical well transaction closed in April 2016, and the undeveloped acreage transaction closed in June 2016.


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

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Depletion of oil and gas properties	$	9,273	$	18,148	$	31,981	$	47,562
Depreciation and accretion	362		269		1,020		669
Total DD&A Expense	$	9,635	$	18,417	$	33,001	$	48,231

Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on a depletion rate, which is calculated by comparing production volumes for the quarter to estimated total reserves at the beginning of the quarter. For the three and nine months ended September 30, 2016, production of 993 MBOE and 3,050 MBOE, respectively, represented 0.8% and 2.4% of estimated total proved reserves, respectively. For the three and nine months ended September 30, 2015, production of 1,102 MBOE and 2,490 MBOE, respectively, represented 1.9% and 4.3% of estimated total proved reserves, respectively. DD&A expense was $9.70 per BOE and $16.71 per BOE for the three months ended September 30, 2016 and 2015, respectively. For the nine months ended September 30, 2016 and 2015, DD&A expense was $10.82 per BOE and $19.37 per BOE, respectively.


5.	Asset Retirement Obligations

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



Asset retirement obligations, December 31, 2015	$	13,400
Obligations incurred with development activities	366
Obligations assumed with acquisitions	2,046
Accretion expense	755
Obligations discharged with asset retirements and divestitures	(3,997		)
Revisions in previous estimates	1,278
Asset retirement obligations, September 30, 2016	$	13,848
Less, current portion	(2,319		)
Long-term portion	$	11,529


6.	Revolving Credit Facility

The Company maintains a revolving credit facility ("Revolver") with a bank syndicate with a maturity date of December 15, 2019. The Revolver is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes, and to support letters of credit. As of September 30, 2016, the terms of the Revolver provide for up to $500 million in borrowings, subject to a borrowing base limitation of $145 million. As of September 30, 2016, there was no outstanding principal balance as compared to a principal balance of $78.0 million as of December 31, 2015. The Company has an outstanding letter of credit of approximately $0.5 million. On October 14, 2016, the Revolver was increased from $145 million to $160 million in connection with the semi-annual redetermination of the borrowing base. The next semi-annual redetermination is scheduled for May 2017.

Interest under the Revolver accrues monthly at a variable rate. For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin or 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 nine months ended September 30, 2016 and 2015 was 2.63% and 2.5%, respectively.

Certain of the Company’s assets, including substantially all of the producing wells and developed oil and gas leases, have been designated as collateral under the Revolver. The borrowing commitment is subject to scheduled redeterminations on a semi-annual basis. If certain events occur, or if the bank syndicate or the Company so elects, an unscheduled redetermination could be prepared.

The Revolver contains covenants that, among other things, restrict the payment of dividends and limits our overall commodity derivative position to a maximum position that varies over 5 years as a percentage of estimated proved developed producing or total proved reserves as projected in the semi-annual reserve report.

Furthermore, the Revolver requires the Company to maintain compliance with certain financial and liquidity ratio covenants. Under the requirements, the Company, on a quarterly basis, must not (a) at any time permit its ratio of total funded debt as of such time to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0; or (b) as of the last day of any fiscal quarter permit its current ratio, as defined in the agreement, to be less than 1.0 to 1.0. As of September 30, 2016, the most recent compliance date, the Company was in compliance with these loan covenants and expects to remain in compliance throughout the next 12-month period.


7.	Notes Payable

At any time prior to December 14, 2018, the Company may redeem all or a part of the Senior Notes subject to the Make-Whole Price (as defined in the Indenture) and accrued and unpaid interest. On and after December 14, 2018, the Company may redeem all or a part of the Senior Notes at the redemption price at a specified percentage of the principal amount of the redeemed notes (104.50% for 2018, 102.25% for 2019, and 100.0% for 2020 and thereafter, during the twelve-month period beginning on December 14 of each applicable year), plus accrued and unpaid interest. Additionally, prior to December 14, 2018, the Company can, on one or more occasions, redeem up to 35% of the principal amount of the Senior Notes with all or a portion of the net cash proceeds of one or more Equity Offerings (as defined in the Indenture) at a redemption price equal to 109.00% of the principal amount of the redeemed notes, plus accrued and unpaid interest, subject to certain conditions.

The Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to, among other restrictions and limitations: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities. These covenants are subject to a number of exceptions and qualifications.

As of September 30, 2016, the most recent compliance date, the Company was in compliance with these loan covenants and expects to remain in compliance throughout the next 12-month period.


8.	Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, as described below. Our commodity derivative instruments may include but are not limited to "collars," "swaps," and "put" positions. Our derivative strategy, including the volume amounts, whether we utilize oil and/or natural gas instruments, and the relevant commodity prices, is based in part on our view of expected future market conditions and our analysis of well-level economic return potential. In addition, our use of derivative contracts is subject to stipulations set forth in the Revolver.

A "put" option gives the owner the right, but not the obligation, to sell the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may,

at times, purchase put options, which require us to pay premiums at the time we purchase the contracts. These premiums represent the fair value of the purchased put as of the date of purchase. Conversely, a "call" option gives the owner the right, but not the obligation, to purchase the underlying commodity at a specified price (strike price) within a specific time period.

Depending on market conditions, strike prices, and the value of the contracts, we may, at times, sell call options in conjunction with the purchase of put options to create "collars." We regularly utilize "no premium" (a.k.a. zero cost) collars where, at settlement, we receive the difference between the published index price and a floor price if the index price is below the floor. We pay the difference between the ceiling price and the index price if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the floor and the ceiling price.

Additionally, at times, we may enter into swaps. Swaps are derivative contracts which obligate two counterparties to effectively trade the underlying commodity at a set price over a specified term.

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

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

The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying condensed consolidated balance sheets as commodity derivative assets or liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from contract settlement of derivatives are recorded in the condensed consolidated statements of operations. The Company’s cash flow is only impacted when the actual settlements under commodity derivative contracts result in making or receiving a payment to or from the counterparty. Actual cash settlements can occur at either the scheduled maturity date of the contract or at an earlier date if the contract is liquidated prior to its scheduled maturity. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s condensed consolidated statements of cash flows.

The Company’s commodity derivative contracts as of September 30, 2016 are summarized below:



Settlement Period	Derivative Instrument	Average Volumes (Bbls per month)	Floor Price		Ceiling Price
Crude Oil - NYMEX WTI
Oct 1, 2016 - Dec 31, 2016	Purchased Put	25,000	$	50.00	—
Oct 1, 2016 - Dec 31, 2016	Purchased Put	10,000	$	45.00	—
Oct 1, 2016 - Dec 31, 2016	Collar	20,000	$	45.00	$	65.00
Oct 1, 2016 - Dec 31, 2016	Collar	30,667	$	40.00	$	60.00

Jan 1, 2017 - Apr 30, 2017	Purchased Put	20,000	$	50.00	—
May 1, 2017 - Aug 31, 2017	Purchased Put	20,000	$	55.00	—
Jan 1, 2017 - Dec 31, 2017	Collar	20,000	$	45.00	$	70.00
Jan 1, 2017 - Dec 31, 2017	Collar	30,417	$	40.00	$	60.00

Settlement Period	Derivative Instrument	Average Volumes (MMBtu per month)	Floor Price		Ceiling Price
Natural Gas - CIG Rocky Mountain
Oct 1, 2016 - Dec 31, 2016	Collar	100,000	$	2.65	$	3.10

Jan 1, 2017 - Apr 30, 2017	Collar	100,000	$	2.80	$	3.95
May 1 2017 - Aug 31, 2017	Collar	110,000	$	2.50	$	3.06
Jan 1, 2017 - Dec 31, 2017	Collar	200,000	$	2.50	$	3.27
Jan 1, 2017 - Dec 31, 2017	Collar	100,000	$	2.60	$	3.20

Subsequent to September 30, 2016, the Company added the following positions:



Settlement Period	Derivative Instrument	Average Volumes (MMBtu per month)	Floor Price		Ceiling Price
Crude Oil - NYMEX WTI
Jan 1, 2017 - Dec 31, 2017	Collar	30,417	$	40.00	$	65.00

Natural Gas - NYMEX Henry Hub
Jan 1, 2017 - Dec 31, 2017	Collar	100,000	$	2.75	$	4.00

Offsetting of Derivative Assets and Liabilities

As of September 30, 2016 and December 31, 2015, all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of either party, for transactions that occur on the same date and in the same currency. The Company’s agreements also provide that, in the event of an early termination, each party has the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to offset these positions in its condensed consolidated balance sheets.

The following table provides a reconciliation between the net assets and liabilities reflected on the accompanying condensed consolidated balance sheets and the potential effect of master netting arrangements on the fair value of the Company’s derivative contracts (in thousands):



		As of September 30, 2016
Underlying	Balance Sheet Location	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Commodity derivative contracts	Current assets	$	2,943	$	(1,333	)	$	1,610
Commodity derivative contracts	Noncurrent assets	$	627	$	(605	)	$	22
Commodity derivative contracts	Current liabilities	$	1,333	$	(1,333	)	$	—
Commodity derivative contracts	Noncurrent liabilities	$	685	$	(605	)	$	80



		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 (loss) recognized in the condensed consolidated statements of operations related to derivative financial instruments was as follows (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Realized gain (loss) on commodity derivatives	$	(13	)	$	9,579		$	2,868		$	26,896
Unrealized gain (loss) on commodity derivatives	420			(2,960		)	(6,485		)	(21,199		)
Total gain (loss)	$	407		$	6,619		$	(3,617	)	$	5,697

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 nine months ended September 30, 2015, the Company liquidated oil derivatives with an average strike price of $82.79 and covering 372,500 bbls of oil and received cash settlements of approximately $20.5 million. The following table summarizes derivative realized gains and losses during the periods presented (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Monthly settlement	$	497		$	986		$	4,398		$	7,834
Previously incurred premiums attributable to settled commodity contracts	(510		)	(599		)	(1,530		)	(1,447		)
Early liquidation	—			9,192			—			20,509
Total realized gain (loss)	$	(13	)	$	9,579		$	2,868		$	26,896

Credit Related Contingent Features

As of September 30, 2016, two of the five counterparties to the Company's derivative instruments were members of the Company’s credit facility syndicate. The Company’s obligations under the credit facility and its derivative contracts are secured by liens on substantially all of the Company’s producing oil and gas properties. The agreement with the third and fourth counterparties, which are not lenders under the credit facility, are unsecured and do not require the posting of collateral. The agreement with the fifth counterparty is subject to an inter-creditor agreement between the counterparty and the Company’s lenders under the credit facility.


9.	Fair Value Measurements

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


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


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


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

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

The Company’s non-recurring fair value measurements include asset retirement obligations and purchase price allocations for the fair value of assets and liabilities acquired through business combinations.

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

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

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2016 and December 31, 2015 by level within the fair value hierarchy (in thousands):



	Fair Value Measurements at September 30, 2016
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	—	$	1,632	$	—	$	1,632
Commodity derivative liability	$	—	$	80	$	—	$	80



	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 September 30, 2016, derivative instruments utilized by the Company consist of puts and collars. The crude oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are based on several factors, including public indices, the instruments themselves are primarily traded with third-party counterparties. As such, the Company has classified these instruments as Level 2.

Fair Value of Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above), notes payable, and credit facility borrowings. The carrying values of cash and cash equivalents, accounts receivable, and accounts payable are representative of their fair values due to their short-term maturities. Due to the variable interest rate paid on the credit facility borrowings, the carrying value is representative of its fair value.

The fair value of the notes payable is estimated to be $78.0 million at September 30, 2016. The Company determined the fair value of its notes payable at September 30, 2016 by using observable market based information for debt instruments of similar amounts and duration. The Company has classified the notes as Level 2.


10.	Interest Expense

The components of interest expense are (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Revolving bank credit facility	$	—		$	529		$	154		$	2,260
Notes payable	1,800			—			2,120			—
Amortization of issuance costs	467			249			1,076			740
Less, interest capitalized	(2,267		)	(691		)	(3,350		)	(2,753		)
Interest expense, net	$	—		$	87		$	—		$	247


11.	Shareholders’ Equity

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



	As of		As of
	September 30, 2016		December 31, 2015
Preferred stock, shares authorized	10,000,000		10,000,000
Preferred stock, par value	$	0.01	$	0.01
Preferred stock, shares issued and outstanding	nil		nil
Common stock, shares authorized	300,000,000		300,000,000
Common stock, par value	$	0.001	$	0.001
Common stock, shares issued and outstanding	200,537,625		110,033,601

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

Shares of the Company’s common stock were issued during the nine months ended September 30, 2016 as described further below.

Sales of common stock

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

In April 2016, the Company completed a public offering of its common stock in an underwritten public offering. The Company agreed to sell 19,500,000 shares of its common stock to the Underwriters at a price of $7.3535 per share. In addition, pursuant to the Underwriting Agreement, the Underwriters were granted an option, exercisable within 30 days, to purchase up to an additional 2,925,000 shares of common stock on the same terms and conditions. The option was exercised on April 12, 2016, bringing the total number of shares issued to 22,425,000. Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $164.8 million. The Company used a portion of the proceeds of the offering to pay a portion of the purchase price of the GC Acquisition described in Note 3.

In May 2016, the Company completed a public offering of its common stock in an underwritten public offering. The Company agreed to sell 45,000,000 shares of its common stock to the Underwriters at a price of $5.597 per share. In addition, pursuant to the Underwriting Agreement, the Underwriters were granted an option, exercisable within 30 days, to purchase up to an additional 6,750,000 shares of common stock on the same terms and conditions. The option was exercised on June 6, 2016, bringing the total number of shares issued to 51,750,000. Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $289.4 million. The Company used a portion of the proceeds of the offering to pay a portion of the purchase price of the GC Acquisition described in Note 3.


12.	Weighted-Average Shares Outstanding

For the three and nine months ended September 30, 2016 and 2015, none of the Company's outstanding equity grants had a dilutive effect on earnings per share. The following potentially dilutive securities outstanding for the periods presented were not included in the respective weighted-average shares outstanding-diluted calculation, as such securities had an anti-dilutive effect on earnings per share:



	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
Potentially dilutive common shares from:
Stock options	5,903,500	4,476,500	5,903,500	4,476,500
Performance stock units ¹	478,510	—	478,510	—
Restricted stock units and stock bonus shares	1,003,879	714,000	1,003,879	714,000
Total	7,385,889	5,190,500	7,385,889	5,190,500

¹ The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the vesting condition.


13.	Stock-Based Compensation

In addition to cash compensation, the Company may compensate employees and directors with equity-based compensation in the form of stock options, restricted stock units, stock bonus shares, warrants, and other equity awards. The Company records its equity compensation by pro-rating the estimated grant date fair value of each grant over the period of time that the recipient is required to provide services to the Company (the "vesting phase"). The calculation of fair value is based, either directly or indirectly, on the quoted market value of the Company’s common stock. Indirect valuations are calculated using the Black-Scholes-Merton option pricing model or a Monte Carlo Model. For the periods presented, all stock-based compensation was classified either as a component within general and administrative expense in the Company's condensed consolidated statements of operations, or, for that portion which is directly attributable to individuals performing acquisition, exploration, and development activities, was capitalized to the full cost pool.

The amount of stock-based compensation was as follows (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Stock options	$	1,274		$	1,110		$	4,107		$	4,400
Performance stock units	354			—			692			—
Restricted stock units and stock bonus shares	1,023			739			3,341			3,288
Total stock-based compensation	$	2,651		$	1,849		$	8,140		$	7,688
Less: stock-based compensation capitalized	(278		)	(81		)	(856		)	(503		)
Total stock-based compensation expensed	$	2,373		$	1,768		$	7,284		$	7,185

Stock options

During the three and nine months ended September 30, 2016 and 2015, the Company granted the following stock options:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Number of options to purchase common shares	350,000		450,000		944,500		2,482,500
Weighted-average exercise price	$	6.55	$	10.31	$	7.20	$	11.33
Term (in years)	10 years		10 years		10 years		10 years
Vesting Period (in years)	5 years		3 - 5 years		3 - 5 years		1 - 5 years
Fair Value (in thousands)	$	1,253	$	2,377	$	3,381	$	13,692

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



	Nine Months Ended September 30,
	2016		2015
Expected term	6.4 years		6.5 years
Expected volatility	55	%	48	%
Risk free rate	1.25 - 1.75%		1.35 - 2.02%
Expected dividend yield	—	%	—	%

The following table summarizes activity for stock options for the nine months ended September 30, 2016:



	Number of Shares		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life	Aggregate Intrinsic Value (thousands)
Outstanding, December 31, 2015	5,056,000		$	9.71	8.7 years	$	4,351
Granted	944,500		7.20
Exercised	—		—			—
Expired	—		—
Forfeited	(97,000	)	10.50
Outstanding, September 30, 2016	5,903,500		$	9.29	8.2 years	$	2,763
Outstanding, Exercisable at September 30, 2016	2,223,950		$	8.20	7.1 years	$	2,194
Outstanding, Vested and expected to vest at September 30, 2016	5,829,108		$	9.27	8.2 years	$	2,763

The following table summarizes information about issued and outstanding stock options as of September 30, 2016:



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

Under $5.00	650,000	5.0 years	$	3.51	583,000	$	3.47
$5.00 - $6.99	965,000	8.1 years	6.37		430,000	6.51
$7.00 - $10.99	1,546,500	8.7 years	9.43		334,450	9.63
$11.00 - $13.46	2,742,000	8.7 years	11.61		876,500	11.63
Total	5,903,500	8.2 years	$	9.29	2,223,950	$	8.20

The estimated unrecognized compensation cost from stock options not vested as of September 30, 2016, which will be recognized ratably over the remaining vesting phase, is as follows:



Unrecognized compensation, net of estimated forfeitures (in thousands)	$	16,100
Remaining vesting phase	3.4 years

Restricted stock units and stock bonus awards

The Company grants restricted stock units and stock bonus awards to directors, eligible employees and officers as a part of its equity incentive plan. Restrictions and vesting periods for the awards are determined by the Compensation Committee of the Board of Directors and are set forth in the award agreements. Each restricted stock unit or stock bonus award represents one share of the Company’s common stock to be released from restrictions upon completion of the vesting period. The awards typically vest in equal increments over three to five years. Restricted stock units and stock bonus awards are valued at the closing price of the Company’s common stock on the grant date and are recognized over the vesting period of the award.

The following table summarizes activity for restricted stock units and stock bonus awards for the nine months ended September 30, 2016:



	Number of Shares		Weighted-Average Grant-Date Fair Value
Not vested, December 31, 2015	915,867		$	10.63
Granted	451,347		7.68
Vested	(305,598	)	10.12
Forfeited	(57,737	)	9.06
Not vested, September 30, 2016	1,003,879		$	9.55

The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of September 30, 2016, which will be recognized ratably over the remaining vesting phase, is as follows:



Unrecognized compensation, net of estimated forfeitures (in thousands)	$	7,575
Remaining vesting phase	2.9 years

Performance-vested stock units

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

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

The assumptions used in valuing the PSUs granted were as follows:



	Nine Months Ended September 30, 2016
Weighted average expected term	2.7 years
Weighted average expected volatility	58	%
Weighted average risk free rate	0.87	%

During the nine months ended September 30, 2016, the Company granted 490,713 PSUs to certain executives. The fair value of the PSUs granted during the nine months ended September 30, 2016 was $4.0 million. As of September 30, 2016, unrecognized compensation expense for PSUs was $3.2 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	490,713		8.10
Vested	—		—
Forfeited	(12,203	)	8.22
Not vested, September 30, 2016	478,510		$	8.09


14.	Income Taxes

We evaluate and update our estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of our actual earnings compared to annual projections, our effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. The quarterly income tax provision is generally comprised of tax expense on income or benefit on loss at the most recent estimated annual effective tax rate, adjusted for the effect of discrete items.

The effective tax rate for the nine months ended September 30, 2016 was 0% compared to 14% for the nine months ended September 30, 2015. The effective tax rate for the nine months ended September 30, 2016 is based upon a full year forecasted tax provision and differs from the statutory rate, primarily due to the recognition of a valuation allowance recorded against deferred tax assets. The effective tax rate for the nine months ended September 30, 2015 differs from the statutory rate primarily due to state taxes and nondeductible officers' compensation, partially offset by percentage depletion. There were no significant discrete items recorded during the three and nine months ended September 30, 2016 and 2015.

As of September 30, 2016, we had no liability for unrecognized tax benefits. The Company believes that there are no new items, nor changes in facts or judgments that should impact the Company’s tax position. Given the substantial NOL carryforwards at both the federal and state levels, it is anticipated that any changes resulting from a tax examination would simply adjust the carryforwards, and would not result in significant interest expense or penalties. Most of the Company's tax returns filed since August 31, 2011 are still subject to examination by tax authorities. As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions, and we are not currently under any state income tax examinations.

No significant uncertain tax positions were identified as of any date on or before September 30, 2016. The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of September 30, 2016, the Company has not recognized any interest or penalties related to uncertain tax benefits.

Each period, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Based upon our cumulative losses through September 30, 2016, we have provided a full valuation allowance reducing the net realizable benefits.


15.	Related Party Transactions

Consulting agreements: Subsequent to their tenure as co-CEOs, which ended on December 31, 2015, the Company entered into consulting agreements with Ed Holloway and William Scaff, Jr. through May 31, 2016. During this period, each was paid $70,000 per month, or $350,000 for the nine months ended September 30, 2016.


16.	Other Commitments and Contingencies

Volume Commitments

The Company has crude oil transportation agreements with three counterparties. 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.

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 September 30, 2016, our commitments over the next five years are as follows:



Year ending December 31,
(in MBbls/year)
Remainder of 2016		704
2017		3,944
2018		4,255
2019		4,255
2020		3,700
Thereafter		1,672
Total		18,530

During the nine months ended September 30, 2016, the Company incurred transportation deficiency charges of $505,000 as we were unable to meet all of the obligations during the period. We anticipate that our current gross operated production will be near our delivery obligations for the fourth quarter of 2016.

Office and yard leases

In September 2016, the Company entered into a new sixty-five-month lease for the Company’s principal office space located in Denver, which is expected to commence in the first quarter of 2017. At the Company's current location, lease expense is approximately $50,000 per month which will continue until the new space is ready to be occupied. Rent under the new lease is approximately $62,000 per month. In July 2016, the Company entered into a field office lease in Greeley which requires monthly payments of $7,500 through October 2021. The Company intends to terminate its current Platteville office lease once the field personnel are fully relocated to the Greeley office, which is anticipated to occur by year end 2016. The Platteville lease expense is currently $15,000 per month on a month-to-month basis and is leased from two former members of the Company’s board of directors.

Litigation

From time to time, the Company is a party to various commercial and regulatory claims, pending or threatened legal action, and other proceedings that arise in the ordinary course of business. It is the opinion of management that none of the current matters of contention are reasonably likely to have a material adverse impact on our business, financial position, results of operations, or cash flows.

On June 1, 2015, the Company filed a complaint in the District Court of Weld County, Colorado, against Briller, Inc., R.W.L. Enterprises, and Robert W. Loveless (together, the "Defendants") arising from a dispute concerning the validity of certain leases covering oil and gas properties in Weld County, Colorado. In June 2015, the Defendants removed the case to the Federal District Court of Colorado and filed an answer and counterclaims including claims for trespass. In May 2016, the Court ruled that the Defendants’ lease is valid. In October 2016, a jury heard evidence on the trespass issue and found against the Company. The Company and Defendants are in negotiations to settle this matter, but cannot guarantee that a settlement will be reached. The Company does not believe that any terms reached in a settlement would have a material effect on the Company. If no settlement is reached, the equitable remedy awarded to Defendants, if any, would be determined by the judge in the case. At this time, it is not possible to estimate what the equitable remedy, if any, would be.

Environmental

Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable, and the costs can be reasonably estimated. As of September 30, 2016, we had accrued environmental liabilities in the amount of $0.4 million, included in accounts payable and accrued expenses on the condensed consolidated balance sheet. We are not aware of any environmental claims existing as of September 30, 2016 which have not been provided for or would otherwise have a material impact on our condensed consolidated financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown past non-compliance with environmental laws or unknown historic releases will not be discovered on our properties.

In addition, in July 2016, we were informed by the Colorado Department of Public Health and Environment's Air Quality Control Commission's Air Pollution Control Division ("CDPHE") that it expects to expand its inspection of the Company's facilities in connection with a Compliance Advisory previously issued by the CDPHE and subsequent inspections conducted by the CDPHE. The Compliance Advisory alleged issues at five Company facilities regarding leakages of volatile organic compounds from storage tanks, all of which were promptly addressed. A subsequent August 2016 tolling agreement between the Company and CDPHE alleged similar storage tank leakage issues at three additional Company facilities, all of which were also promptly addressed. We are working with the CDPHE to respond to any continuing concerns, but have not yet been informed of additional facilities to be inspected or additional issues that have been identified. We cannot predict the outcome of this matter.


17.	Supplemental Schedule of Information to the Condensed Consolidated Statements of Cash Flows

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



	Nine Months Ended September 30,
Supplemental cash flow information:	2016			2015
Interest paid	$	159		$	2,328
Income taxes paid	106			92

Non-cash investing and financing activities:
Accrued well costs as of period end	$	32,299		$	26,997
Assets acquired in exchange for common stock	—			9,097
Asset retirement obligations incurred with development activities	366			4,806
Asset retirement obligations assumed with acquisitions	2,046			—
Obligations discharged with asset retirements and divestitures	(3,997		)	—


18.	Subsequent Event

On September 26, 2016, the Company entered into two purchase and sale agreements for certain assets for a total purchase price of $8.0 million, subject to customary closing conditions and purchase price adjustments. The acquired properties were comprised solely of oil and gas leasehold interests in the D-J Basin of Colorado. The acquisition's preliminary closing was on October 21, 2016 with an effective date of July 1, 2016.


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

The following discussion and analysis was prepared to supplement information contained in the accompanying unaudited condensed consolidated financial statements and is intended to explain certain items regarding the Company's financial condition as of September 30, 2016, and its results of operations for the three and nine months ended September 30, 2016 and 2015. It should be read in conjunction with the accompanying unaudited condensed consolidated financial statements and related notes thereto contained in this report as well as the audited financial statements included in the Transition Report on Form 10-K for the four months ended December 31, 2015 filed with the SEC on April 22, 2016.

Overview

Synergy Resources Corporation is a growth-oriented independent oil and natural gas company engaged in the acquisition, development, and production of crude oil and natural gas in 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, predominantly in Weld County, Colorado, an area that covers the western flank of the D-J Basin. Currently, we are focused on the horizontal development of the Codell and Niobrara formations, which are characterized by relatively high liquids content.

All of our producing wells are either in or adjacent to the Wattenberg Field. We strive to maintain a high net revenue interest in all of our operations and currently operate approximately 66% of our proved producing reserves, and our planned fiscal 2016 and 2017 drilling and completion expenditures are focused on the Wattenberg Field. This gives us both operational focus and development flexibility to maximize returns on our leasehold position.

Market Conditions

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



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

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Oil (NYMEX WTI)
Average NYMEX Price	$	44.90		$	46.42		$	41.23		$	51.00
Realized Price	$	35.67		$	39.05		$	31.47		$	42.16
Differential	$	(9.23	)	$	(7.37	)	$	(9.76	)	$	(8.84	)

Gas (NYMEX Henry Hub)
Average NYMEX Price	$	2.88		$	2.74		$	2.34		$	2.73
Realized Price	$	2.73		$	2.59		$	2.18		$	2.84
Differential	$	(0.15	)	$	(0.15	)	$	(0.16	)	$	0.11

Market conditions in the Wattenberg Field require us to sell oil at prices less than the prices posted by the NYMEX. The negative differential between the prices actually received by us at the wellhead and the published indices reflects deductions imposed upon us by the purchasers for location and quality adjustments. We continue to negotiate with crude oil purchasers to obtain better differentials on any barrels above our pipeline commitments. With regard to the sale of natural gas, our received prices include payment for a percentage of the value attributable to the natural gas liquids produced with the gas.

Price fluctuations can impact many aspects of our operations. For additional discussion concerning the potential impacts from declining commodity prices, please see "Drilling and Completion Operations," "Liquidity and Capital Resources - Oil and Gas Commodity Contracts," and "Trends and Outlook."

Core Operations

The following table provides details about our ownership interests with respect to vertical and horizontal producing wells as of September 30, 2016:

Vertical Wells

Operated Wells

Non-Operated Wells

Totals

Gross

Net

Gross

Net

Gross

Net

226

193

164

390

239

Horizontal Wells

Operated Wells

Non-Operated Wells

Totals

Gross

Net

Gross

Net

Gross

Net

149

245

136

In addition to the producing wells summarized in the preceding table, as of September 30, 2016, we were the operator of 44 gross (41 net) wells in progress, which excludes 9 gross (9 net) wells for which we have only set surface casings.

Production

For the three months ended September 30, 2016, our average daily production decreased to 10,794 BOED as compared to 11,975 BOED for the three months ended September 30, 2015. During the first nine months of 2016, our average net daily production was 11,133 BOED. By comparison, during the nine months ended September 30, 2015, our average production rate was 9,119 BOED. As of September 30, 2016, approximately 93% of our daily production was from horizontal wells.

Strategy

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


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

•

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

•

Improve hydrocarbon recovery through increased well density. We utilize what we believe to be industry best practices in our effort to determine the optimal recovery area for each well. Early horizontal well development in the Wattenberg Field generally assumed optimal recoveries would be obtained utilizing between 12 and 16 wells per 640-acre section. As horizontal well development has matured, well density assumptions have generally increased beyond 16 wells per section depending on the specific area of the field being drilled.


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


•	Retain control over the operation of a substantial portion of our production. As operator of a majority of our wells and undeveloped acreage, we control the timing and selection of new wells to be drilled 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 development objective for individual well execution optimization is to drill and complete wells with lateral lengths of 7,000' to 10,000' as opposed to the 4,000' laterals that were initially drilled in the Wattenberg Field. Utilizing petrophysical and seismic data, a 3-D model is developed for each section to assist in determining optimal wellbore placement, well spacing, and stimulation design. This process is augmented with formation specific drilling and completion execution designs and coupled with localized production results to provide a continuous improvement philosophy in optimizing the value per acre of our leasehold throughout our development program.

Significant Developments

Acquisition and Divestiture Activity

Acquisitions

On May 2, 2016, the Company entered into an agreement to purchase a total of 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. Estimated net daily production from the acquired properties was approximately 2,400 BOE at the time of entering into the GC Agreement.

On June 14, 2016, the Company closed on the portion of the assets comprised of the undeveloped lands and non-operated production. The effective date of this part of the transaction was April 1, 2016, and the purchase price was $487.4 million,

comprised of $486.3 million in cash and the assumption of certain liabilities. The second closing will cover the operated producing properties and is expected to be completed in 2017. The Company has placed $18.2 million in escrow to be released upon the second closing. For the second closing, the effective date will be April 1, 2016 for the horizontal wells to be acquired and the first day of the calendar month in which the closing for such properties occurs for the vertical wells. The second closing is subject to certain closing conditions, including the receipt of a regulatory approval. Accordingly, the second closing of the transaction may not close in the expected time frame or at all.

On February 4, 2016, the Company completed the acquisition of undeveloped oil and gas leasehold interests in the D-J Basin for a total purchase price of $10.0 million. The purchase price has been allocated as $8.6 million to proved oil and gas properties and $1.4 million to unproved oil and gas properties on a preliminary basis. This allocation reflects significant use of estimates.

Divestitures

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 $25.2 million in cash, subject to customary purchase price adjustments. We have received $24.2 million in cash and transferred liabilities of $0.5 million to the buyers, and $0.5 million in cash was released to us from escrow in October 2016. The divested assets had associated production of approximately 200 BOED. The vertical well transaction closed in April 2016, and the undeveloped acreage transaction closed in June 2016.

Financing and Other

Equity offerings

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

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

In May and June 2016, the Company closed on the sale of an additional 51,750,000 shares of common stock pursuant to an underwriting agreement with the same underwriters. The price to the Company was $5.597 per share and net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $289.4 million. The proceeds of this offering were used for general corporate purposes, including to fund the GC Acquisition.

Revolving Credit Facility

We continue to maintain a borrowing arrangement with our bank syndicate to provide us with liquidity, which could be used to develop oil and gas properties, acquire new oil and gas properties, and for working capital and other general corporate purposes. As of September 30, 2016, this revolving credit facility (sometimes referred to as the "Revolver") provides for maximum borrowings of $500 million, subject to adjustments based upon a borrowing base calculation, which is re-determined semi-annually using updated reserve reports. The Revolver is collateralized by certain of our assets, including producing properties, and bears a variable interest rate on borrowings, with the effective rate varying with utilization. The Revolver expires on December 15, 2019. See further discussion in Note 6 to our condensed consolidated financial statements

On October 14, 2016, the Revolver was amended in connection with the semi-annual redetermination of the borrowing base. The borrowing base was increased from $145 million to $160 million. Approximately $159.5 million of the borrowing base was available to use for future borrowings subsequent to this redetermination.

The Revolver also contains covenants that, among other things, restrict the payment of dividends and limits our overall commodity derivative position to a maximum position that varies over 5 years as a percentage of estimated proved reserves as projected in the semi-annual reserve report.

Senior Notes

On June 14, 2016, the Company issued $80 million aggregate principal amount of 9.00% Senior Unsecured Notes ("Senior Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is June 13, 2021. Interest on the Notes accrues at 9.00% and began accruing on June 14, 2016. Interest is payable on June 15 and December 15 of each year, beginning on December 15, 2016. The Senior Notes were issued pursuant to an indenture dated as of June 14, 2016 (the "Indenture") and are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the revolving credit facility. The net proceeds from the sale of the Senior Notes were $75.2 million after deductions of $4.8 million for expenses and underwriting discounts and commissions. The net proceeds were used to fund the GC Acquisition. The Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to, among other restrictions and limitations: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities. These covenants are subject to a number of exceptions and qualifications.

Impairment of full cost pool

Every quarter, we perform a ceiling test as prescribed by SEC regulations for entities following the full cost method of accounting. This test determines a limit on the book value of oil and gas properties using a formula to estimate future net cash flows from oil and gas reserves. This formula is dependent on several factors and assumes future oil and natural gas prices to be equal to an unweighted arithmetic average of oil and natural gas prices derived from each of the 12 months prior to the reporting period. During the nine months ended September 30, 2016, these calculations indicated that the ceiling amount had declined, largely as a result of the decline in oil and natural gas prices, such that the ceiling was less than the net book value of oil and gas properties. The September 30, 2016 ceiling test used average realized prices of $31.95 per barrel and $2.21 per Mcf as compared to the June 30, 2016 prices of $33.82 per barrel and $2.16 per Mcf, a change of approximately (6)% and 2%, respectively. As a result, we recorded a non-cash ceiling test impairments totaling $25.5 million and $215.2 million for the three and nine months ended September 30, 2016, respectively. If we would have used NYMEX strip pricing instead of the pricing prescribed by SEC regulations, we would not have incurred an impairment at September 30, 2016. Each of these full cost ceiling impairments is recognized as a charge to earnings and may not be reversed in future periods, even if oil and natural gas prices subsequently increase. Declining commodity prices, other adverse market conditions, acquisitions, or divestitures could result in further ceiling test write-downs in the future.

Drilling and Completion Operations

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

During the nine months ended September 30, 2016, we drilled 35 operated horizontal wells, completing 10 of them. As of September 30, 2016, we are the operator of 44 gross (41 net) horizontal wells in progress, which excludes 9 gross (9 net) horizontal wells for which we have only set surface casings. For 2016 as a whole, we expect to drill 55 gross (52 net) operated horizontal wells of mostly mid-length and long laterals targeting the Codell and Niobrara zones.

In addition, we participated in drilling and completion activities on 2 gross (0.19 net) non-operated horizontal wells during the third quarter. As of September 30, 2016, we are participating in 17 gross (1.58 net) non-operated horizontal wells in progress.

Other Operations

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

Trends and Outlook

Oil traded at $37.13 per Bbl on December 31, 2015, but increased approximately 29% through September 30, 2016 to $47.72. Natural gas traded at $2.34 per Mcf on December 31, 2015, but increased approximately 24% through September 30, 2016 to $2.91. Although oil prices have risen in the last six months, oil prices continue to remain significantly lower than their 2014 levels, which were near $100/bbl, and early 2015 levels, which were near $55/bbl. Lower oil prices (i) will reduce our cash flow which, in turn, could reduce the funds available for exploring and replacing oil and gas reserves, (ii) could 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) could 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.

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.

We utilize what we believe to be industry best practices in our effort to determine the optimal recovery area for each well. Early horizontal well development in the Wattenberg Field generally assumed optimal recoveries would be obtained utilizing between 12 and 16 wells per 640-acre section. As horizontal well development has matured, well density assumptions have generally increased beyond 16 wells per section depending on the specific area of the field being drilled.

The decline in commodity prices since late 2014 has led to a corresponding decline in service costs, which directly relate to our drilling and completion costs. We have been able to reduce drilling and completion costs due to a combination of optimizing well designs, lower contract rates for drilling rigs, fewer average days to drill, and lower completion costs. This focus on cost reduction has supported well-level economics in spite of the severe drop in the prices of crude oil and natural gas. We continue to strive to reduce drilling and completion costs going forward to offset the negative impacts associated with lower commodity prices, but we do not believe that we will achieve the same percentage reduction of costs during the remainder of 2016, and well-level rates of return may be lower, particularly if service costs start to escalate and/or commodity prices decline.

From time to time, our production has been adversely impacted by high natural gas gathering line pressures. Where it is cost effective, we install wellhead compression to enhance our ability to inject 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, some of our producing locations have been curtailed 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 parties, but that we would commit specific wells to these systems. We believe that oil gathering lines have several benefits including, a) reduced need to use trucks to gather our oil, thereby reducing truck traffic in and around our production locations, b) potentially lower gathering costs as pipeline gathering tends to be more efficient, c) reduced on-site oil storage capacity, resulting in lower production location facility costs, and d) generally 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 will begin operations in the fourth quarter 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.

As of September 30, 2016, the Company has identified over 1,000 gross mid- to long-lateral (~7,500’ to ~9,500’) drilling locations across its consolidated GC acreage position. Our 2017 preliminary drilling and completion capital budget contemplates

drilling 68 gross mid-length lateral and 34 gross long length lateral wells while completing 52 gross mid-length and 43 gross long length wells. While retaining significant operational and financial flexibility to reduce or accelerate activity in response to changing economic conditions, the Company anticipates this drilling and completion schedule will cost between $260 million and $300 million and will lead to a significant increase in production and associated proved developed producing reserves. Initial estimates place full-year 2017 production between 17,500 BOE/day and 20,000 BOE/day.

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

Results of Operations

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

For the three months ended September 30, 2016, compared to the three months ended September 30, 2015

For the three months ended September 30, 2016, we reported a net loss of $19.2 million compared to net loss of $77.9 million during the three months ended September 30, 2015. Net loss per basic and diluted share (including the ceiling test impairment of $25.5 million) was $(0.10) for the three months ended September 30, 2016 compared to net loss per basic and diluted share of $(0.74) for the three months ended September 30, 2015. Net loss per basic share for the three months ended September 30, 2016 increased by $0.64 primarily due to the ceiling test impairment of $96.3 million incurred during the three months ended September 30, 2015 as compared to the ceiling test impairment of $25.5 million during the three months ended September 30, 2016. Revenues decreased 21% during the three months ended September 30, 2016 compared with the three months ended September 30, 2015 due to the rapid decline of commodity prices, as discussed previously. As of September 30, 2016, we had 635 gross producing wells, compared with 582 gross producing wells as of September 30, 2015. The impact of changing prices on our commodity derivative positions and changes in estimated production taxes also drove significant differences in our results of operations between the two periods.

Oil and Gas Production and Revenues - For the three months ended September 30, 2016, we recorded total oil and gas revenues of $26.2 million compared to $33.4 million for the three months ended September 30, 2015, a decrease of $7.1 million or 21%. The following table summarizes key production and revenue statistics:



	Three Months Ended September 30,				Percentage
	2016		2015		Change
Production:
Oil (MBbls ¹)	517		692		(25	)%
Gas (MMcf ²)	2,855		2,458		16	%
MBOE ³	993		1,102		(10	)%
BOED⁴	10,794		11,975		(10	)%

Revenues (in thousands):
Oil	$	18,451	$	27,025	(32	)%
Gas	7,783		6,353		23	%
	$	26,234	$	33,378	(21	)%
Average sales price:
Oil	$	35.67	$	39.05	(9	)%
Gas	$	2.73	$	2.59	5	%
BOE	$	26.42	$	30.30	(13	)%

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 September 30, 2016 averaged 10,794 BOED, a decrease of 10% over average production of 11,975 BOED in the three months ended September 30, 2015. From September 30, 2015 to September 30, 2016, we added 54 net horizontal wells, including 6 (net) horizontal wells acquired in the KPK Acquisition, increasing our reserves and producing wells. The 13% decline in average sales prices compounded the effects of decreased 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 September 30,
	2016		2015
Production costs	$	3,529	$	4,385
Workover	290		693
Total LOE	$	3,819	$	5,078

Per BOE:
Production costs	$	3.55	$	3.98
Workover	0.29		0.63
Total LOE	$	3.84	$	4.61

Lease operating and workover costs tend to increase or decrease primarily in relation to the number of wells in production, and, to a lesser extent, to fluctuations in oil field service costs and changes in the production mix of crude oil and natural gas. The $1.3 million decrease in lease operating expenses during the three months ended September 30, 2016 compared to the three months ended September 30, 2015 was primarily due to decreased production during the three months ended September 30, 2016. This was partially attributable to fewer horizontal wells coming online during the current period as compared to the three months ended September 30, 2015. Fewer new wells reduced costs associated with contract labor and water hauling. In addition, sales and trades of vertical wells during the second quarter of 2016 resulted in reduced lease operating expense for the three months ended September 30, 2016.

Production taxes - During the three months ended September 30, 2016, the Company reduced its estimate for production taxes based on recent historical experience and additional information received during the period. Based on this analysis, the Company's accrual was reduced, resulting in an approximate $3.6 million reduction to our production taxes. Production taxes were $(1.5) million, or $(1.47) per BOE, for the three months ended September 30, 2016, compared to $3.1 million, or $2.81 per BOE, for the three months ended September 30, 2015. Taxes tend to increase or decrease primarily based on the value of oil and gas sold. As a percentage of revenues, production taxes were (5.6)% and 9.3% for the three months ended September 30, 2016 and 2015, respectively.

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



	Three Months Ended September 30,
(in thousands)	2016		2015
Depletion of oil and gas properties	$	9,273	$	18,148
Depreciation and accretion	362		269
Total DD&A	$	9,635	$	18,417

DD&A expense per BOE	$	9.70	$	16.71

For the three months ended September 30, 2016, depletion of oil and gas properties was $9.70 per BOE compared to $16.71 per BOE for the three months ended September 30, 2015. The decrease in the DD&A rate was the result of a decrease in the ratio of total costs capitalized in the full cost pool to the estimated recoverable reserves. This ratio was significantly reduced due to the impairments of our full cost pool, which primarily occurred during the second half of calendar 2015 and the first half of 2016, and the increase in our total proved reserves. Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning of quarter estimated total reserves determine the depletion rate.

Full cost ceiling impairment - During the three months ended September 30, 2016, we recognized an impairment of $25.5 million as compared to an impairment of $96.3 million for the three months ended September 30, 2015, representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling. See Note 2, "Property and Equipment," to the condensed consolidated financial statements included as part of this report.

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



	Three Months Ended September 30,
(in thousands)	2016			2015
G&A costs incurred	$	9,993		$	6,021
Capitalized costs	(1,757		)	(589		)
Total G&A	$	8,236		$	5,432

Non-Cash G&A	$	2,375		$	1,768
Cash G&A	$	5,861		$	3,664
Total G&A	$	8,236		$	5,432

Non-Cash G&A per BOE	$	2.39		$	1.60
Cash G&A per BOE	$	5.90		$	3.32
G&A Expense per BOE	$	8.29		$	4.92

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 September 30, 2016, we increased our employee count, which was 62 as of December 31, 2015 to 89, while reducing the number of consultants, advisors, and contractors that had historically been used for certain tasks. G&A for the three months ended September 30, 2016 was elevated by expenses incurred in support of Colorado oil and gas legislative activities.

Our G&A expense for the three months ended September 30, 2016 includes stock-based compensation of $2.4 million compared to $1.8 million for the three months ended September 30, 2015. Stock-based compensation includes a calculated value for stock options or shares of common stock that we grant for compensatory purposes. It is a non-cash charge. For stock options, the fair value is estimated using the Black-Scholes-Merton option pricing model. For restricted stock units and stock bonus shares, the fair value is estimated using the closing stock price on the grant date. Amounts are pro-rated over the vesting terms of the award agreements, which are generally three to five years.

Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the exploration and development of properties. Those costs are reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from the three months ended September 30, 2015 to the three months ended September 30, 2016 reflects our increased headcount of individuals performing activities to maintain and acquire leases and develop our properties.

Commodity derivatives - As more fully described in Item 1. Financial Statements – Note 8, Commodity Derivative Instruments, we use commodity contracts to help mitigate the risks inherent in the price volatility of oil and natural gas. For the three months ended September 30, 2016, we realized a cash settlement loss of $13,000, net of previously incurred premiums attributable to the settled commodity contracts. For the prior comparable period, we realized a cash settlement gain of $9.6 million.

In addition, for the three months ended September 30, 2016, we recorded an unrealized gain of $0.4 million to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the three months ended September 30, 2015, we reported an unrealized loss of $3.0 million. Unrealized gains and losses are non-cash items.

Income taxes - We reported income tax expense of $5,000 for the three months ended September 30, 2016, calculated at an effective tax rate of 0%. During the comparable prior year period, we reported income tax benefit of $10.5 million, calculated at an effective tax rate of 12%. As explained in more detail below, during the period ended September 30, 2016 and 2015, the effective tax rates were substantially reduced by recognition of a full valuation allowance on the net deferred tax assets. During the three months ended September 30, 2016 and 2015, the effective tax rate differed from the statutory rate, primarily due to the

recognition of a valuation allowance recorded against deferred tax assets.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. Based on the level of losses in the current period and the level of uncertainty with respect to future taxable income over the period in which the deferred tax assets are deductible, a valuation allowance has been provided as of September 30, 2016. During the 2015 comparable period, we reached the same conclusion; therefore, a valuation allowance has been provided as of September 30, 2015.

For the nine months ended September 30, 2016, compared to the nine months ended September 30, 2015

For the nine months ended September 30, 2016, we reported net loss of $224.5 million compared to net loss of $83.5 million during the nine months ended September 30, 2015. Net loss per basic and diluted share (including a ceiling test impairment of $215.2 million) was $(1.36) for the three months ended September 30, 2016 compared to net loss per basic and diluted share of $(0.82) for the nine months ended September 30, 2015. Net loss per basic share for the nine months ended September 30, 2016 increased by $0.54 primarily due to the ceiling test impairment of $215.2 million incurred during the nine months ended September 30, 2016. Revenues decreased 15% during the nine months ended September 30, 2016 compared with the nine months ended September 30, 2015 due to the rapid decline of commodity prices, as discussed previously. As of September 30, 2016, we had 635 gross producing wells, compared with 582 gross producing wells as of September 30, 2015. The impact of changing prices on our commodity derivative positions also drove significant differences in our results of operations between the two periods.

Oil and Gas Production and Revenues - For the nine months ended September 30, 2016, we recorded total oil and gas revenues of $68.5 million compared to $80.6 million for the nine months ended September 30, 2015, a decrease of $12.1 million or 15%. The following table summarizes key production and revenue statistics:



	Nine Months Ended September 30,				Percentage
	2016		2015		Change
Production:
Oil (MBbls)	1,552		1,521		2	%
Gas (MMcf)	8,991		5,813		55	%
MBOE	3,050		2,490		22	%
BOED	11,133		9,119		22	%

Revenues (in thousands):
Oil	$	48,838	$	64,107	(24	)%
Gas	19,616		16,495		19	%
	$	68,454	$	80,602	(15	)%
Average sales price:
Oil	$	31.47	$	42.16	(25	)%
Gas	$	2.18	$	2.84	(23	)%
BOE	$	22.44	$	32.38	(31	)%

Net oil and gas production for the nine months ended September 30, 2016 averaged 11,133 BOED, an increase of 22% over average production of 9,119 BOED in the nine months ended September 30, 2015. However, the 31% decline in average sales prices more than offset the effects of increased production, resulting in an overall reduction of revenues.

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



	Nine Months Ended September 30,
	2016		2015
Production costs	$	14,464	$	11,678
Workover	499		1,266
Total LOE	$	14,963	$	12,944

Per BOE:
Production costs	$	4.74	$	4.69
Workover	0.16		0.51
Total LOE	$	4.90	$	5.20

Lease operating and workover costs tend to increase or decrease primarily in relation to the number of wells in production, and, to a lesser extent, on fluctuation in oil field service costs and changes in the production mix of crude oil and natural gas. The $2.0 million increase in lease operating expenses during the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015 was primarily due to operating more horizontal wells, increased production, and an increase in environmental remediation and regulatory compliance projects.

Production taxes - During the three months ended September 30, 2016, the Company reduced its estimate for production taxes based on recent historical experience and additional information received during the period. Based on this analysis, the Company's accrual was reduced, resulting in an approximate $3.6 million reduction to our production taxes. Production taxes were $2.5 million, or $0.82 per BOE for the nine months ended September 30, 2016, compared to $7.5 million, or $3.01 per BOE, for the nine months ended September 30, 2015. Taxes tend to increase or decrease primarily based on the value of oil and gas sold. As a percentage of revenues, production taxes were 3.7% and 9.3% for the nine months ended September 30, 2016 and 2015, respectively.

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



	Nine Months Ended September 30,
(in thousands)	2016		2015
Depletion of oil and gas properties	$	31,981	$	47,562
Depreciation and accretion	1,020		669
Total DD&A	$	33,001	$	48,231

DD&A expense per BOE	$	10.82	$	19.37

For the nine months ended September 30, 2016, depletion of oil and gas properties was $10.82 per BOE compared to $19.37 per BOE for the nine months ended September 30, 2015. The decrease in the DD&A rate was the result of a decrease in the ratio of total costs capitalized in the full cost pool to the estimated recoverable reserves. This ratio was significantly reduced due to the impairments of our full cost pool, which primarily occurred during the second half of calendar 2015, and the increase in our total proved reserves. Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning of quarter estimated total reserves determine the depletion rate.

Full cost ceiling impairment - During the nine months ended September 30, 2016, we recognized a total impairment of $215.2 million as compared to an impairment of $99.3 million for the nine months ended September 30, 2015, representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling. See Note 2, "Property and Equipment," to the condensed consolidated financial statements included as part of this report.

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



	Nine Months Ended September 30,
(in thousands)	2016			2015
G&A costs incurred	$	27,944		$	17,395
Capitalized costs	(4,745		)	(1,640		)
Total G&A	$	23,199		$	15,755

Non-Cash G&A	$	7,285		$	7,185
Cash G&A	$	15,914		$	8,570
Total G&A	$	23,199		$	15,755

Non-Cash G&A per BOE	$	2.39		$	2.89
Cash G&A per BOE	$	5.22		$	3.44
G&A Expense per BOE	$	7.61		$	6.33

G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. During the nine months ended September 30, 2016, we increased our employee count from 62 as of December 31, 2015 to 89, while reducing the number of consultants, advisors, and contractors that had historically been used for certain tasks. G&A for the nine months ended September 30, 2016 was elevated was elevated by expenses incurred in support of Colorado oil and gas legislative activities.

Our G&A expense for the nine months ended September 30, 2016 includes stock-based compensation of $7.3 million compared to $7.2 million for the nine months ended September 30, 2015.

Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the exploration and development of properties. Those costs are reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from the nine months ended September 30, 2015 to the nine months ended September 30, 2016 reflects our increased headcount of individuals performing activities to maintain and acquire leases and develop our properties.

Commodity derivatives - As more fully described in Item 1. Financial Statements – Note 8, Commodity Derivative Instruments, we use commodity contracts to help mitigate the risks inherent in the price volatility of oil and natural gas. For the nine months ended September 30, 2016, we realized a cash settlement gain of $2.9 million, net of previously incurred premiums attributable to the settled commodity contracts. For the prior comparable period, we realized a cash settlement gain of $26.9 million.

In addition, for the nine months ended September 30, 2016, we recorded an unrealized loss of $6.5 million to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the nine months ended September 30, 2015, we reported an unrealized loss of $21.2 million. Unrealized losses are non-cash items.

Income taxes - We reported income tax expense of $0.1 million for the nine months ended September 30, 2016, calculated at an effective tax rate of 0%. During the comparable prior year period, we reported income tax benefit of $14.1 million, calculated at an effective tax rate of 14%. During the periods ended September 30, 2016 and 2015, the effective tax rate was substantially reduced by recognition of a full valuation allowance on the net deferred tax assets. During the nine months ended September 30, 2016 and 2015, the effective tax rate differed from the statutory rate, primarily due to the recognition of a valuation allowance recorded against deferred tax assets.

Liquidity and Capital Resources

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

We believe that our capital resources, including cash on hand, amounts available under our revolving credit facility, and cash flow from operating activities will be sufficient to fund our planned capital expenditures and operating expenses for the next twelve months. We funded the purchase price of the GC Acquisition through a combination of cash on hand and proceeds of financing transactions, including the issuance of the Senior Notes. 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 nine months ended September 30, 2016, the NYMEX-WTI oil price ranged from a high of $51.23 per Bbl on Wednesday, June 8, 2016 to a low of $26.19 per Bbl on Thursday, February 11, 2016, while the NYMEX-Henry Hub natural gas price ranged from a low of $1.64 per MMBtu on Thursday, March 3, 2016 to a high of $3.06 per MMBtu on September 21, 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 September 30, 2016, we had cash and cash equivalents of $63.8 million and no outstanding balance under our revolving credit facility. Our sources and (uses) of funds for the nine months ended September 30, 2016 and 2015 are summarized below (in thousands):



	Nine Months Ended September 30,
	2016			2015
Cash provided by operations	$	33,193		$	69,753
Acquisitions and development of oil and gas properties and equipment	(582,149		)	(110,224		)
Net cash provided by other investing activities	5,979			389
Net cash provided by equity financing activities	542,901			190,224
Net cash used in debt financing activities	(2,666		)	(68,000		)
Net increase (decrease) in cash and equivalents	$	(2,742	)	$	82,142

Net cash provided by operating activities was $33.2 million and $69.8 million for the nine months ended September 30, 2016 and 2015, respectively. The decline in cash from operating activities reflects the decline in commodity prices, which was partially offset by the increase in production.

During the nine months ended September 30, 2016, we received cash proceeds from, and used cash proceeds in, the following financing activities:

•

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


•	In January 2016, the Company repaid its outstanding borrowings under the Revolver of $78 million. In addition, on June 13, 2016, the Company borrowed approximately $55 million under the Revolver in order to pay a portion of the purchase price for the GC Acquisition pending receipt of proceeds from the issuance of the Senior Notes. The full amount borrowed was repaid on June 14, 2016.


•	On April 14, 2016, we received cash proceeds of approximately $164.8 million (after underwriting discounts, commissions and expenses) from our public offering of 22,425,000 shares (including the shares sold pursuant

to an over-allotment option exercised by the underwriters) at a price to us of $7.3535 per share. These proceeds were used for general corporate purposes, including to fund the GC Acquisition.

•

In May and June 2016, we received cash proceeds of approximately $289.4 million (after underwriting discounts, commissions and expenses) from our public offering of 51,750,000 shares (including the shares sold pursuant to an over-allotment option exercised by the underwriters) at a price to us of $5.597 per share. These proceeds were used for general corporate purposes, including to fund the GC Acquisition.

•

On June 14, 2016, the Company issued $80 million aggregate principal amount of 9.00% Senior Unsecured Notes ("Senior Notes") in a private placement to qualified institutional buyers. See "- Senior Notes" below. The net proceeds from the sale of the Senior Notes were $75.2 million after deductions of $4.8 million for expenses and underwriting discounts and commissions. The net proceeds were used to fund the GC Acquisition.

Credit Facility

We maintain a borrowing arrangement with a banking syndicate with a maturity date of December 15, 2019. The arrangement, in the form of a revolving credit facility, was most recently amended with the Ninth Amendment to the credit facility on October 14, 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.

The terms of the Revolver provide for up to $500 million in borrowings, subject to a borrowing base limitation, which was increased to $160 million on October 14, 2016. As of October 31, 2016, there was no outstanding principal balance, $0.5 million in letters of credit was applied against the Revolver, and $159.5 million was available to us for future borrowings. The next semi-annual redetermination of the borrowing base has been scheduled for May 2017. 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.

The Revolver requires the Company to maintain compliance with certain financial and liquidity ratio covenants. Under the requirements, the Company, on a quarterly basis, must not (a) at any time permit its ratio of total funded debt as of such time to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0; or (b) as of the last day of any fiscal quarter permit its current ratio, as defined in the agreement, to be less than 1.0 to 1.0.

Senior Notes

On June 14, 2016, the Company issued $80 million aggregate principal amount of the Senior Notes in a private placement to qualified institutional buyers. The maturity for the payment of principal is June 13, 2021. Interest on the Notes accrues at 9.00% and began accruing on June 14, 2016. Interest is payable on June 15 and December 15 of each year, beginning on December 15, 2016. The Senior Notes were issued pursuant to an indenture dated as of June 14, 2016 (the "Indenture") and are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the revolving credit facility. At any time prior to December 14, 2018, the Company may redeem all or a part of the Senior Notes subject to the Make-Whole Price (as defined in the Indenture) and accrued and unpaid interest. On and after December 14, 2018, the Company may redeem all or a part of the Senior Notes at the redemption price at a specified percentage of the principal amount of the redeemed notes (104.50% for 2018, 102.25% for 2019, and 100.0% for 2020 and thereafter, during the twelve-month period beginning on December 14 of each applicable year), plus accrued and unpaid interest. Additionally, prior to December 14, 2018, the Company can, on one or more occasions, redeem up to 35% of the principal amount of the Senior Notes with all or a portion of the net cash proceeds of one or more Equity Offerings (as defined in the Indenture) at a redemption price equal to 109.00% of the principal amount of the redeemed notes, plus accrued and unpaid interest, subject to certain conditions.

Reconciliation of Cash Payments to Capital Expenditures

Capital expenditures reported in the condensed consolidated statements of cash flows are calculated on a strict cash basis, which differs from the accrual basis used to calculate other amounts reported in our condensed consolidated financial statements. Specifically, cash payments for acquisition of property and equipment as reflected in the condensed consolidated statements of cash flows excludes non-cash capital expenditures and includes an adjustment (plus or minus) to reflect the timing of when the capital expenditure obligations are incurred and when the actual cash payment is made. On an accrual basis, capital expenditures totaled $591.7 million and $100.4 million for the nine months ended September 30, 2016 and 2015, respectively. A reconciliation of the differences between cash payments and the accrual basis amounts is summarized in the following table (in thousands):



	Nine Months Ended September 30,
	2016			2015
Cash payments for acquisitions	$	499,831		$	—
Asset retirement obligations assumed with acquisitions	2,046			—
Cash payments for capital expenditures	82,318			110,224
Accrued costs, beginning of period	(31,414		)	(52,747		)
Accrued costs, end of period	32,299			26,997
Non-cash acquisitions, common stock	—			9,840
Other	6,655			6,049
Accrual basis capital expenditures	$	591,735		$	100,363

Capital Expenditures

Excluding the GC Acquisition, the majority of capital expenditures during the nine months ended September 30, 2016 were associated with the costs of drilling and completing wells. During the nine months ended September 30, 2016, we drilled 35 operated horizontal wells, completing 10 of them. As of September 30, 2016, we are the operator of 44 gross (41 net) horizontal wells in progress, which excludes 9 gross (9 net) horizontal wells for which we have only set surface casings. 14 of the wells in progress are scheduled to commence production before December 31, 2016.

Capital Requirements

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

Consistent with our plan, during the three months ended September 30, 2016, we operated two drilling rigs for the execution of our capital expenditure plan. We also regularly review capital expenditures 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. Capital expenditures for the nine months ended September 30, 2016 were approximately $83.2 million.

Our preliminary 2017 drilling and completion capital program is anticipated to be between $260 million and $300 million. Should commodity prices and/or economic conditions change, we can decelerate or accelerate our drilling and completion activities, which could have a material impact on our anticipated capital requirements.

For the near term, we believe that we have sufficient liquidity to fund our needs through cash on hand, cash flow from operations, and additional borrowings available under our revolving credit facility. In contemplating our planned 2017 capital program, we expect the borrowing base under our revolving credit facility to increase due to the anticipated significant growth in our production and associated proved developed producing reserves. However, should this not occur and/or to meet all of our

long-term goals, we may need to raise additional funds to drill new wells through the sale of our securities, from third parties willing to pay our share of drilling and completing wells, or from other sources. We may not be successful in raising the capital needed to drill or acquire oil or gas wells.

Oil and Gas Commodity Contracts

We use derivative contracts to protect against the variability in cash flows created by short-term price fluctuations associated with the sale of future oil and gas production. At September 30, 2016, we had open positions covering 1.0 million barrels of oil and 4,740 MMcf of natural gas. We do not use derivative instruments for speculative purposes. Subsequent to September 30, 2016, we entered into additional positions covering 0.4 million barrels of oil and 1,200 MMcf of natural gas.

During the nine months ended September 30, 2016, we reported an unrealized commodity activity loss of $6.5 million. Unrealized losses are non-cash items. We also reported a realized gain of $2.9 million, representing the cash settlement of commodity contracts settled during the period, net of previously incurred premiums attributable to the settled commodity contracts.

At September 30, 2016, we estimated that the fair value of our various commodity derivative contracts was a net asset of $1.6 million. See Item 1. Financial Statements – Note 9, Fair Value Measurements, for a description of the methods we use to estimate the fair values of commodity derivative instruments.

Non-GAAP Financial Measures

In addition to financial measures presented on the basis of accounting principles generally accepted in the United States of America ("US GAAP"), we present certain financial measures which are not prescribed by US GAAP ("non-GAAP"). In the future, we may disclose different non-GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our condensed consolidated financial statements and publicly filed reports in their entirety and to not rely on any single financial measure. A summary of the non-GAAP measure that we currently use is described below.

Adjusted EBITDA

We use "adjusted EBITDA," a non-GAAP financial measure, for internal managerial purposes because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed in the table below from net loss in arriving at adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. This measure is not a measure of financial performance under US GAAP and should be considered in addition to, not as a substitute for, cash flows from operations, investing, or financing activities, and it should not be viewed as a liquidity measure or indicator of cash flows reported in accordance with US GAAP. Our definition of adjusted EBITDA may not be comparable to measures with similar titles reported by other companies. We believe that adjusted EBITDA is a widely used in our industry as a measure of operating performance and may also be used by investors to measure our ability to meet debt covenant requirements. We define adjusted EBITDA as net loss adjusted to exclude the impact of the items set forth in the table below.

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Adjusted EBITDA:
Net loss	$	(19,241	)	$	(77,921	)	$	(224,490	)	$	(83,502	)
Depreciation, depletion, and accretion	9,635			18,417			33,001			48,231
Full cost ceiling impairment	25,453			96,340			215,223			99,340
Income tax expense (benefit)	5			(10,520		)	106			(14,132		)
Stock-based compensation	2,374			1,849			7,285			7,688
Mark-to-market of commodity derivative contracts:
Total loss (gain) on commodity derivatives contracts	(407		)	(6,619		)	3,617			(5,697		)
Cash settlements on commodity derivative contracts	486			10,178			5,137			28,343
Cash premiums paid for commodity derivative contracts	—			(445		)	—			(4,562		)
Interest expense (income)	(10		)	72			(179		)	178
Adjusted EBITDA	$	18,295		$	31,351		$	39,700		$	75,887

Critical Accounting Policies

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

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

We call your attention to the increased significance of the ceiling test as disclosed in Item 1. Financial Statements – Note 2, Property and Equipment, to the accompanying condensed consolidated financial statements included elsewhere in this report. During the nine months ended September 30, 2016, we recorded impairments in conjunction with performing ceiling tests as prescribed by SEC Regulation S-X Rule 4-05.

Cautionary Statement Concerning Forward-Looking Statements

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

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

See "Risk Factors" in this report and in Item 1A of our Transition Report on Form 10-K for the four months ended December 31, 2015 filed with the SEC on April 22, 2016, for a discussion of risk factors that affect our business, financial condition, and results of operations. These risks include, among others, those associated with the following:


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


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


•	uncertainties in the estimates of proved reserves;


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


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


•	our ability to obtain adequate financing;


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


•	our ability to complete the second closing of the GC Acquisition and integrate the acquired properties, and the risks associated with liabilities assumed or other problems relating to that acquisition;


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


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


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


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


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


•	the geographic concentration of our principal properties; and


•	the availability of water for use in our operations.


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 70% and 71% of our revenue during the three and nine months ended September 30, 2016, respectively, was from the sale of oil. A $10 per barrel change in our realized oil price would have resulted in a $5.2 million and $15.5 million change in revenues during the three and nine months ended September 30, 2016, respectively, while a $0.50 per Mcf change in our realized gas price would have resulted in a $1.4 million and $4.5 million change in our natural gas revenues for the three and nine months ended September 30, 2016, respectively.

During the three months ended September 30, 2016, the price of oil and natural gas increased slightly. 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 can use derivative contracts to cover up to 85% of expected proved developed producing production as projected in our semi-annual reserve report over a period of two years. We do not enter into derivative contracts for speculative or trading purposes. As of September 30, 2016, we had open crude oil derivatives in a net asset position with a fair value of $1.6 million. A hypothetical upward shift of 10% in the NYMEX forward curve of crude oil and natural gas prices would decrease the fair value of our position by approximately $1.3 million. A hypothetical downward shift of 10% in the NYMEX forward curve of crude oil and natural gas prices would increase the fair value of our position by approximately $1.4 million. A summary of our open positions as of September 30, 2016 is set forth in Item 1. Financial Statements - Note 8, Commodity Derivative Instruments.

Interest Rate Risk - At September 30, 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 plus an applicable margin. We are exposed to interest rate risk on the bank credit facility if the variable reference rates increase. 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 or decreased by 1%, our interest payments in the nine months ended September 30, 2016 would have changed by less than $0.1 million.

Counterparty Risk - As described in "- Commodity Price Risk" above, 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 slightly declined during the third quarter of 2016 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

Except as disclosed in Note 16 to the accompanying condensed consolidated financial statements, 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, you should consider the following risks:

Risks Related to the GC Acquisition

The GC Acquisition may not achieve its intended results and may result in us assuming unanticipated liabilities. These risks are heightened because the GC Acquisition involved our acquisition of a material amount of acreage relative to our prior acreage position.

We entered into the purchase and sale agreement related to the GC Acquisition (the "GC Agreement") with the expectation that the 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, we may discover title defects or adverse environmental or other conditions related to the acquired properties 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 assumed 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, if the second closing under 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 acquired pursuant to either closing. The second closing is subject to certain closing conditions, including our receipt of a release of a consent decree burdening certain of the properties to be acquired, and these conditions may not be satisfied in the time frame we expect or at all. 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 involved a material amount of acreage relative to our prior 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 write-downs of unevaluated properties.

Other Risks

Future ballot initiatives in Colorado, if approved, could have severe adverse effects on our operations, reserves and financial condition.

Certain groups opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have from time to time advanced various proposed ballot initiatives that would limit or prohibit oil and natural gas development activities in Colorado. Proponents attempted to collect the required number of signatures to have two such proposals included on the ballot for the November 2016 election. One would have amended the Colorado constitution to impose a minimum distance of 2,500 feet between wells and any occupied structures or "areas of special concern". If implemented, this proposal would have made the vast majority of the surface area of the state ineligible for drilling, including substantially all of our planned future drilling locations. The second proposal would have amended the state constitution to give local governmental authorities the ability to regulate, or to ban, oil and gas exploration, development and production activities within their boundaries notwithstanding state rules and approvals to the contrary. If implemented, this proposal could have resulted in us becoming subject to onerous, and possibly inconsistent, regulations that vary from jurisdiction to jurisdiction, or to outright bans on our activities in various jurisdictions. The proponents of these initiatives failed to obtain enough valid signatures to have the initiatives included on the November 2016 ballot. However, similar proposals, or other proposals that would limit or prohibit oil and gas development activity, may be made in the future. Because all of our operations and reserves are located in Colorado, the passage and implementation of any such proposal could have a materially adverse effect on our operations, reserves, financial condition and business generally.


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
July 1, 2016 - July 31, 2016 ⁽¹⁾	—	$	—
August 1, 2016 - August 31, 2016 ⁽¹⁾	10,675	$	6.64
September 1, 2016 - September 30, 2016 ⁽¹⁾	4,902	$	6.45
Total	15,577

(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
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
99.1		Ninth Amendment to Credit Agreement, dated as of October 14, 2016, among Synergy Resources Corporation, SunTrust Bank as Administrative Agent and as an Issuing Bank, and the lenders party thereto.
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 November, 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/ Jared C. Grenzenbach
	Jared C. Grenzenbach, Vice President and Chief Accounting Officer (Principal Accounting Officer)

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

Attached files

SRC Energy Inc. Reports