10-Q 1 q31610-qsyrg20160930.htm 10-Q Document


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

FORM 10-Q

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

For the quarterly period ended September 30, 2016

OR

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

For the transition period from _______________________ to _______________________

Commission file number:  001-35245

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
 
 
 
 
 
 
Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2016 and 2015
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2016 and 2015
 
 
 
 
 
 
Notes to Condensed Consolidated Financial Statements
 
 
 
 
 
Item 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
 
 
 
 
 
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
 
 
 
 
 
Item 4.
Controls and Procedures
 
 
 
 
 
Part II - OTHER INFORMATION
 
 
 
 
 
 
Item 1.
Legal Proceedings
 
 
 
 
 
Item 1A.
Risk Factors
 
 
 
 
 
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
 
 
 
 
 
Item 3.
Defaults of Senior Securities
 
 
 
 
 
Item 4.
Mine Safety Disclosures
 
 
 
 
 
Item 5.
Other Information
 
 
 
 
 
Item 6.
Exhibits
 
 
 
 
 
SIGNATURES
 





SYNERGY RESOURCES CORPORATION
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

2

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

3

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

4



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.
 

5



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 31st. During 2016, we changed the date of our annual goodwill impairment assessment to October 1st. 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

6



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

7



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

8



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

9



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
)


10



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.


11



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

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 as discussed further in Note 3.

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

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

As of 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,

12



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.




13



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.

14




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



15



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


16



 
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



17



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.


18



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



19



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.


20



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
%


21



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

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.

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.


22



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.
    

23



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.


24



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



25



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

 
46

 
390

 
239

Horizontal Wells
Operated Wells
 
Non-Operated Wells
 
Totals
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
96

 
91

 
149

 
45

 
245

 
136