10-Q 1 q31710-qsci20170930.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, 2017

OR

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

For the transition period from _______________________ to _______________________

Commission file number:  001-35245

logovrt4ca02.jpg
SRC ENERGY INC.
(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.)

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

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


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

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

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




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

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


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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: 201,089,000 outstanding shares of common stock as of October 31, 2017.




SRC ENERGY INC.

Index

 
 
 
Page
Part I - FINANCIAL INFORMATION
 
 
 
 
 
 
Item 1.
Financial Statements (unaudited)
 
 
 
 
 
 
 
Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016
 
 
 
 
 
 
Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2017 and 2016
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2017 and 2016
 
 
 
 
 
 
Notes to Condensed Consolidated Financial Statements
 
 
 
 
 
Item 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
 
 
 
 
 
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
 
 
 
 
 
Item 4.
Controls and Procedures
 
 
 
 
 
Part II - OTHER INFORMATION
 
 
 
 
 
 
Item 1.
Legal Proceedings
 
 
 
 
 
Item 1A.
Risk Factors
 
 
 
 
 
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
 
 
 
 
 
Item 3.
Defaults of Senior Securities
 
 
 
 
 
Item 4.
Mine Safety Disclosures
 
 
 
 
 
Item 5.
Other Information
 
 
 
 
 
Item 6.
Exhibits
 
 
 
 
 
SIGNATURES
 





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


ASSETS
September 30, 2017
 
December 31, 2016
Current assets:
 
 
 
Cash and cash equivalents
$
21,325

 
$
18,615

Accounts receivable:
 
 
 
Oil, natural gas, and NGL sales
72,309

 
25,728

Trade
45,280

 
6,805

Commodity derivative assets

 
297

Other current assets
6,289

 
2,739

Total current assets
145,203

 
54,184

 
 
 
 
Property and equipment:
 
 
 
Oil and gas properties, full cost method:
 
 
 
Unproved properties and land, not subject to depletion
327,154

 
398,547

Proved properties, net of accumulated depletion
758,135

 
424,082

Wells in progress
158,192

 
81,780

Oil and gas properties, net
1,243,481

 
904,409

Other property and equipment, net
6,152

 
4,327

Total property and equipment, net
1,249,633

 
908,736

Cash held in escrow and other deposits

 
18,248

Goodwill
40,711

 
40,711

Other assets
2,359

 
2,234

Total assets
$
1,437,906

 
$
1,024,113

 
 
 
 
LIABILITIES AND SHAREHOLDERS' EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
134,144

 
$
52,453

Revenue payable
58,742

 
16,557

Production taxes payable
37,017

 
17,673

Asset retirement obligations
2,738

 
2,683

Commodity derivative liabilities
786

 
2,874

Total current liabilities
233,427

 
92,240

 
 
 
 
Revolving credit facility
150,000

 

Notes payable, net of issuance costs
76,216

 
75,614

Commodity derivative liabilities
394

 

Asset retirement obligations
33,981

 
13,775

Other liabilities
2,268

 
1,745

Total liabilities
496,286

 
183,374

 
 
 
 
Commitments and contingencies (See Note 14)


 


 
 
 
 
Shareholders' equity:
 
 
 
Preferred stock - $0.01 par value, 10,000,000 shares authorized: no shares issued and outstanding

 

Common stock - $0.001 par value, 300,000,000 shares authorized: 200,909,101 and 200,647,572 shares issued and outstanding as of September 30, 2017 and December 31, 2016, respectively
201

 
201

Additional paid-in capital
1,158,317

 
1,148,998

Retained deficit
(216,898
)
 
(308,460
)
Total shareholders' equity
941,620

 
840,739

 
 
 
 
Total liabilities and shareholders' equity
$
1,437,906

 
$
1,024,113


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

2

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

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
 
 
 
 
 
 
 
 
Oil, natural gas, and NGL revenues
$
103,593

 
$
26,234

 
$
222,419

 
$
68,454

Sales of purchased oil

 

 
1,268

 

Total revenues
103,593

 
26,234

 
223,687

 
68,454

 
 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
 
Lease operating expenses
5,154

 
3,819

 
13,894

 
14,963

Production taxes
10,083

 
(1,461
)
 
21,013

 
2,509

Costs of purchased oil

 

 
1,518

 

Depreciation, depletion, and accretion
33,740

 
9,635

 
73,396

 
33,001

Full cost ceiling impairment

 
25,453

 

 
215,223

Unused commitment charge

 
205

 
669

 
505

General and administrative
8,484

 
8,236

 
24,289

 
23,199

Total expenses
57,461

 
45,887

 
134,779

 
289,400

 
 
 
 
 
 
 
 
Operating income (loss)
46,132

 
(19,653
)
 
88,908

 
(220,946
)
 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
Commodity derivatives gain (loss)
(2,383
)
 
407

 
2,324

 
(3,617
)
Interest expense, net of amounts capitalized

 

 

 

Interest income
16

 
11

 
47

 
176

Other income (expense)
83

 
(1
)
 
385

 
3

Total other income (expense)
(2,284
)
 
417

 
2,756

 
(3,438
)
 
 
 
 
 
 
 
 
Income (Loss) before income taxes
43,848

 
(19,236
)
 
91,664

 
(224,384
)
 
 
 
 
 
 
 
 
Income tax expense

 
5

 

 
106

Net income (loss)
$
43,848

 
$
(19,241
)
 
$
91,664

 
$
(224,490
)
 
 
 
 
 
 
 
 
Net income (loss) per common share:
 
 
 
 
 
 
 
Basic
$
0.22

 
$
(0.10
)
 
$
0.46

 
$
(1.36
)
Diluted
$
0.22

 
$
(0.10
)
 
$
0.46

 
$
(1.36
)
 
 
 
 
 
 
 
 
Weighted-average shares outstanding:
 
 
 
 
 
 
 
Basic
200,881,447

 
200,515,555

 
200,807,436

 
164,771,544

Diluted
201,460,915

 
200,515,555

 
201,326,129

 
164,771,544


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

3

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

 
Nine Months Ended September 30,
 
2017
 
2016
Cash flows from operating activities:
 
 
 
Net income (loss)
$
91,664

 
$
(224,490
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Depletion, depreciation, and accretion
73,396

 
33,001

Full cost ceiling impairment

 
215,223

Settlement of asset retirement obligation
(4,077
)
 
(196
)
Stock-based compensation
8,390

 
7,285

Mark-to-market of commodity derivative contracts:
 
 
 
Total (gain) loss on commodity derivatives contracts
(2,324
)
 
3,617

Cash settlements on commodity derivative contracts
778

 
5,137

Changes in operating assets and liabilities:
 
 
 
Accounts receivable
 
 
 
Oil, natural gas, and NGL sales
(46,581
)
 
602

Trade
(38,446
)
 
2,679

Accounts payable and accrued expenses
1,413

 
1,761

Revenue payable
41,997

 
(363
)
Production taxes payable
17,548

 
(10,158
)
Other
(941
)
 
(905
)
Net cash provided by operating activities
142,817

 
33,193

 
 
 
 
Cash flows from investing activities:
 
 
 
Acquisition of oil and gas properties and leaseholds
(62,562
)
 
(503,357
)
Capital expenditures for drilling and completion activities
(305,636
)
 
(72,375
)
Other capital expenditures
(11,198
)
 
(3,078
)
Land and other property and equipment
(4,087
)
 
(3,339
)
Cash held in escrow
18,248

 
(18,244
)
Proceeds from sales of oil and gas properties and other
77,017

 
24,223

Net cash used in investing activities
(288,218
)
 
(576,170
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from the sale of stock

 
565,398

Offering costs

 
(21,987
)
Proceeds from the employee exercise of stock options
114

 

Payment of employee payroll taxes in connection with shares withheld
(631
)
 
(510
)
Proceeds from the revolving credit facility
170,000

 
55,000

Principal repayments on the revolving credit facility
(20,000
)
 
(133,000
)
Financing fees on amendments to the revolving credit facility
(1,372
)
 
(269
)
Proceeds from issuance of the notes payable

 
80,000

Financing fees on issuance of the notes payable

 
(4,397
)
Net cash provided by financing activities
148,111

 
540,235

 
 
 
 
Net increase (decrease) in cash and equivalents
2,710

 
(2,742
)
 
 
 
 
Cash and equivalents at beginning of period
18,615

 
66,499

 
 
 
 
Cash and equivalents at end of period
$
21,325

 
$
63,757

Supplemental Cash Flow Information (See Note 15)

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

4


SRC ENERGY INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

1.
Organization and Summary of Significant Accounting Policies

Organization:  SRC Energy Inc. (the "Company," "SRC Energy," "we," "us," or "our") is an independent oil and natural gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and natural gas liquids ("NGLs"), primarily in the Denver-Julesburg Basin ("D-J Basin") of Colorado. On June 15, 2017, our shareholders approved an amendment to the Amended and Restated Articles of Incorporation of the Company to change the name of the Company from Synergy Resources Corporation to SRC Energy Inc. The Company had been using the new name on a "doing business as" basis since March 6, 2017. In addition to using the new name, the Company’s common stock, which is listed and traded on the NYSE MKT, changed to the new symbol "SRCI."

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

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

Interim Financial Information:  The unaudited condensed consolidated interim financial statements included herein have been prepared by the Company pursuant to the rules and regulations of the SEC as promulgated in Rule 10-01 of Regulation S-X.  The condensed consolidated balance sheet as of December 31, 2016 was derived from the Company's Annual Report on Form 10-K for the year ended December 31, 2016 as filed with the SEC on February 23, 2017.  Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with US GAAP have been condensed or omitted pursuant to such SEC rules and regulations.  The Company believes that the disclosures included are adequate to make the information presented not misleading and recommends that these condensed financial statements be read in conjunction with the audited financial statements and notes thereto for the year ended December 31, 2016.

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

Major Customers: The Company sells production to a small number of customers as is customary in the industry. Customers representing 10% or more of our oil, natural gas, and NGL revenue (“major customers”) for each of the periods presented are shown in the following table:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Major Customers
 
2017
 
2016
 
2017
 
2016
Company A
 
30%
 
*
 
27%
 
*
Company B
 
27%
 
20%
 
26%
 
20%
Company C
 
13%
 
12%
 
15%
 
*
Company D
 
*
 
10%
 
*
 
11%
Company E
 
*
 
27%
 
*
 
38%
* less than 10%

Based on the current demand for oil and natural gas, the availability of other buyers, the multiple contracts for sales of our products, and the Company having the option to sell to other buyers if conditions warrant, the Company believes that the loss of our existing customers or individual contract would not have a material adverse effect on us. Our oil and natural gas production

5


is a commodity with a readily available market, and we sell our products under many distinct contracts. In addition, there are several oil and natural gas purchasers and processors within our area of operations to whom our production could be sold.
 
Accounts receivable consist primarily of receivables from oil, natural gas, and NGL sales and amounts due from other working interest owners who are liable for their proportionate share of well costs. The Company typically has the right to withhold future revenue disbursements to recover outstanding joint interest billings on outstanding receivables from joint interest owners.

Customers with balances greater than 10% of total receivable balances as of each of the periods presented are shown in the following table (these companies do not necessarily correspond to those presented above):
 
 
As of
 
As of
Major Customers
 
September 30, 2017
 
December 31, 2016
Company A
 
25%
 
23%
Company B
 
16%
 
*
Company C
 
*
 
43%
Company D
 
*
 
10%
* less than 10%

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

Recently Adopted Accounting Pronouncements:
    
In March 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-09, “Improvements to Employee Share-Based Payment Accounting” (“ASU 2016-09”), which intends to improve the accounting for share-based payment transactions. ASU 2016-09 changes several aspects of the accounting for share-based payment award transactions, including: (1) Accounting and Cash Flow Classification for Excess Tax Benefits and Deficiencies, (2) Forfeitures, and (3) Tax Withholding Requirements and Cash Flow Classification. ASU 2016-09 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We adopted this pronouncement effective January 1, 2017. Upon adoption of this standard, we no longer estimate the total number of awards for which the requisite service period will not be rendered, and effective January 1, 2017, we began accounting for forfeitures when they occur. We applied this accounting change on a modified retrospective basis with a cumulative-effect adjustment of $0.1 million to retained earnings as of the date of adoption. The adoption of the other provisions did not materially impact the consolidated financial statements.

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

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

In November 2016, the FASB issued ASU 2016-18, "Restricted Cash" ("ASU 2016-18"), which amends ASC 230 to add or clarify guidance on the classification and presentation of restricted cash in the statement of cash flows. Key requirements of ASU 2016-18 are as follows: 1) An entity should include in its cash and cash-equivalent balances in the statement of cash flows those amounts that are deemed to be restricted cash and restricted cash equivalents. ASU 2016-18 does not define the terms “restricted cash” and “restricted cash equivalents” but states that an entity should continue to provide appropriate disclosures about its accounting policies pertaining to restricted cash in accordance with other GAAP. ASU 2016-18 also states that any change in accounting policy will need to be assessed under ASC 250; 2) A reconciliation between the statement of financial position and the statement of cash flows must be disclosed when the statement of financial position includes more than one line item for cash, cash equivalents, restricted cash, and restricted cash equivalents; 3) Changes in restricted cash and restricted cash equivalents that result from transfers between cash, cash equivalents, and restricted cash and restricted cash equivalents should not be presented as cash flow activities in the statement of cash flows; and 4) An entity with a material balance of amounts generally described as restricted cash and restricted cash equivalents must disclose information about the nature of the restrictions. The guidance is effective for fiscal years beginning after December 15, 2017, including interim periods therein. Early adoption is permitted, and we must apply

6


the guidance retrospectively to all periods presented. We are currently evaluating the impact of the adoption of this standard 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. In March 2016, the FASB released certain implementation guidance through ASU 2016-08 (collectively with ASU 2014-09, the "Revenue ASUs") to clarify principal versus agent considerations. The Revenue ASUs allow for the use of either the full or modified retrospective transition method, and the standard will be effective for annual reporting periods beginning after December 15, 2017 including interim periods within that period, with early adoption permitted for annual reporting periods beginning after December 15, 2016. While the Company does not expect net income (loss) or cash flows to be impacted, the Company is currently analyzing whether changes to total revenues and total expenses will be necessary to properly reflect revenue for certain pipeline gathering, transportation, and gas processing agreements. The Company continues to evaluate the expected disclosure requirements, changes to relevant business practices, accounting policies, and control activities that will occur as a result of the adoption of this ASU. The Company plans to adopt the guidance using the modified retrospective method on the effective date of January 1, 2018.

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 estimates: During the nine months ended September 30, 2017, the Company adjusted its estimate for production taxes based on recent historical experience and additional information received during the period. During the nine months ended September 30, 2017, the Company decreased the accrual for production taxes to be paid by approximately $1.1 million, which increased our operating income by a corresponding amount, or $0.01 per basic and diluted common share. During the three months ended September 30, 2016, the Company reduced its estimate for ad valorem taxes based on additional information received during that period. As a result, the Company decreased 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.


7


2.
Property and Equipment

The capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):
 
As of
 
As of
 
September 30, 2017
 
December 31, 2016
Oil and gas properties, full cost method:
 
 
 
Costs of unproved properties and land, not subject to depletion:
 
 
 
Lease acquisition and other costs
$
319,954

 
$
392,561

Land
7,200

 
5,986

Subtotal, unproved properties and land
327,154

 
398,547

 
 
 
 
Costs of wells in progress
158,192

 
81,780

 
 
 
 
Costs of proved properties:
 
 
 
Producing and non-producing
1,375,937

 
969,239

Less, accumulated depletion and full cost ceiling impairments
(617,802
)
 
(545,157
)
Subtotal, proved properties, net
758,135

 
424,082

 
 
 
 
Costs of other property and equipment:
 
 
 
Other property and equipment
7,790

 
5,063

Less, accumulated depreciation
(1,638
)
 
(736
)
Subtotal, other property and equipment, net
6,152

 
4,327

 
 
 
 
Total property and equipment, net
$
1,249,633

 
$
908,736


The Company periodically reviews its oil and gas properties to determine if the carrying value of such assets exceeds estimated fair value. For proved producing and non-producing properties, the Company performs a ceiling test each quarter to determine whether there has been an impairment to its capitalized costs. At September 30, 2017, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary. At September 30, 2016, the carrying value of our oil and gas properties subject to the test exceeded the calculated value of the ceiling limitation, resulting in an impairment of $25.5 million for the three months ended September 30, 2016. Impairments for the nine months ended September 30, 2016 totaled $215.2 million. No impairments were recognized for the comparable 2017 periods.

Capitalized Overhead: A portion of the Company’s overhead expenditures are directly attributable to acquisition, exploration, and development activities.  Under the full cost method of accounting, these expenditures, 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,
 
2017
 
2016
 
2017
 
2016
Capitalized overhead
$
2,518

 
$
1,757

 
$
7,729

 
$
4,745


3.
Acquisitions, Swaps, and Divestitures

Acquisitions and Swaps

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

September 2017 Acquisition

In September 2017, we completed the second closing of the GC Acquisition (as defined in "-June 2016 Acquisition" below). At the second closing, we acquired 335 operated vertical wells and 7 operated horizontal wells. The effective date of the second closing was April 1, 2016 for the horizontal wells acquired and September 1, 2017 for the vertical wells acquired. At the second closing, the escrow balance of $18.2 million was released and $11.4 million of that amount was returned to the Company.

8


The total purchase price for the second closing was $31.3 million, composed of cash of $6.8 million and assumed liabilities of $24.5 million. The assumed liabilities included $20.9 million for asset retirement obligations.

August 2017 Acquisition and Swap

In August 2017, we acquired approximately 1,000 net acres of developed and undeveloped leasehold and mineral interests, along with the associated production, for a total purchase price of $22.6 million, composed of cash and assumed liabilities.

In August 2017, we also entered into an agreement with another party to trade approximately 4,000 net acres of the Company's non-contiguous acreage for approximately 4,000 net acres within the Company's core operating area. This transaction is expected to close in the fourth quarter of 2017.

March 2017 Acquisition

In March 2017, we closed an acquisition comprised primarily of developed and undeveloped oil and gas leasehold interests for a total purchase price of $25.0 million, composed of cash and assumed liabilities.

Acquisitions in the Second Half of 2016

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

June 2016 Acquisition

In May 2016, we entered into a purchase and sale agreement (the "GC Agreement") 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").

In June 2016, the Company closed on the portion of the assets comprised of undeveloped oil and gas leasehold interests and non-operated production. The effective date of this part of the transaction was April 1, 2016. As discussed above in "- September 2017 Acquisition" above, we closed on the second part of this transaction covering the operated producing properties in September 2017.

The first closing on June 14, 2016 was for a total purchase price of $486.4 million, net of customary closing adjustments. The purchase price was composed of $485.1 million in cash plus the assumption of certain liabilities. The first closing encompassed approximately 33,100 net acres of oil and gas leasehold interests and related assets and net production of approximately 800 BOED at the time of entering into the GC Agreement.

The first closing was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of June 14, 2016. Transaction costs of $0.5 million related to the acquisition were expensed as incurred. The following table summarizes the purchase price and final fair values of assets acquired and liabilities assumed (in thousands):
Purchase Price
June 14, 2016
Consideration given:
 
Cash
$
485,141

Net liabilities assumed, including asset retirement obligations
1,273

Total consideration given
$
486,414

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

Unproved oil and gas properties
353,511

Total fair value of assets acquired
$
486,414

(1) Proved oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement.

9


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, 2017, the results of operations of the acquired assets, representing approximately $1.4 million and $5.5 million of revenue, respectively, and $0.9 million and $5.0 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.
(in thousands)
Three Months Ended September 30, 2016
 
Nine Months Ended September 30, 2016
Oil, natural gas, and NGL revenues
$
26,234

 
$
71,940

Net loss
$
(19,241
)
 
$
(227,479
)
 
 
 
 
Net loss per common share
 
 
 
Basic
$
(0.10
)
 
$
(1.14
)
Diluted
$
(0.10
)
 
$
(1.14
)

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. See Note 9 for further details as to the preparation of these significant estimates.

Divestitures

In October 2017, we executed a purchase and sale agreement with a private party resulting in the divestiture of approximately 1,100 net acres and 22 gross (4 net) non-operated wells in progress for $11.6 million. The transaction is expected to close in the fourth quarter of 2017. Additionally, we completed an additional divestiture to a separate private party of 37 operated vertical wells for total consideration of approximately $0.7 million in cash and the assumption by the buyers of $2.3 million in liabilities.

During the nine months ended September 30, 2017, we completed divestitures of approximately 10,700 net undeveloped acres, along with associated production, outside of the Company's core development area for approximately $75.1 million in cash and the assumption by the buyers of $1.7 million in asset retirement obligations and $0.6 million in other liabilities. In accordance with full cost accounting guidelines, the net proceeds were credited to the full cost pool.

In April 2016, the Company agreed to divest approximately 3,700 net undeveloped acres and 107 vertical wells, along with the associated production, primarily in Adams County, Colorado for total consideration of approximately $24.7 million in cash and the assumption by the buyers of $0.5 million in liabilities and $3.6 million in asset retirement obligations. The vertical well transaction closed in April 2016, and the undeveloped acreage transaction closed in June 2016. In accordance with full cost accounting guidelines, the net proceeds were credited to the full cost pool.


10


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

DD&A consisted of the following (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
Depletion of oil and gas properties
$
32,944

 
$
9,273

 
$
71,389

 
$
31,981

Depreciation and accretion
796

 
362

 
2,007

 
1,020

Total DD&A Expense
$
33,740

 
$
9,635

 
$
73,396

 
$
33,001


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, 2017, production of 3,715 MBOE and 8,280 MBOE, respectively, represented 2.2% and 4.8% of estimated total proved reserves, respectively. 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. DD&A expense was $9.08 per BOE and $9.70 per BOE for the three months ended September 30, 2017 and 2016, respectively, and was $8.86 per BOE and $10.82 per BOE for the nine months ended September 30, 2017 and 2016, respectively.

5.
Asset Retirement Obligations

Upon completion or acquisition of a well, the Company recognizes obligations for its oil and natural gas operations for anticipated costs to remove and dispose of surface equipment, plug and abandon the wells, and restore the drilling site to its original use.  The estimated present value of such obligations is determined using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in regulations.  Changes in estimates are reflected in the obligations as they occur.  If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the capitalized asset retirement cost.  The following table summarizes the changes in asset retirement obligations associated with the Company's oil and gas properties (in thousands):
 
Nine Months Ended September 30, 2017
Asset retirement obligations, December 31, 2016
$
16,458

Obligations incurred with development activities
2,782

Obligations assumed with acquisitions
23,521

Accretion expense
981

Obligations discharged with asset retirements and divestitures
(7,023
)
Asset retirement obligation, September 30, 2017
$
36,719

Less, current portion
(2,738
)
Long-term portion
$
33,981


6.
Revolving Credit Facility

The Company maintains a revolving credit facility (sometimes referred to as the "Revolver") with a bank syndicate with a maturity date of December 15, 2019. The Revolver is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes, and to support letters of credit. As of September 30, 2017, the terms of the Revolver provide for up to $500 million in borrowings, subject to a borrowing base limitation of $400 million. There was a $150.0 million outstanding principal balance as of September 30, 2017 and no outstanding principal balance as of December 31, 2016. The Company has an outstanding letter of credit of approximately $0.5 million.

In September 2017, the lenders under the Revolver completed their regular semi-annual redetermination of our borrowing base.  The borrowing base was increased from $225 million to $400 million. The next semi-annual redetermination is scheduled for April 2018.

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, 2017 and 2016 was 3.3% and 2.6%, respectively.

11



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

The Revolver contains covenants that, among other things, restrict the payment of dividends and limit our overall commodity derivative position to a maximum position that varies over 5 years as a percentage of estimated proved developed producing or total proved reserves as projected in the semi-annual reserve report.
  
Furthermore, the Revolver requires the Company to maintain compliance with certain financial and liquidity ratio covenants. In particular, the Company must not (a) permit its ratio of total funded debt to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0 as of the end of any fiscal quarter; 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, 2017, the most recent compliance date, the Company was in compliance with these loan covenants and expects to remain in compliance throughout the next 12-month period.

7.
Notes Payable

In June 2016, the Company issued $80 million aggregate principal amount of 9% Senior Notes ("Senior Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is June 13, 2021. Interest on the Senior Notes accrues at 9% and began accruing on June 14, 2016. Interest is payable on June 15 and December 15 of each year. The Senior Notes were issued pursuant to an indenture dated as of June 14, 2016 (the "Indenture") and will be guaranteed on a senior unsecured basis by any future subsidiaries of the Company that incur or guarantee certain indebtedness, including indebtedness under the revolving credit facility. The net proceeds from the sale of the Senior Notes were $75.2 million after deductions of $4.8 million for expenses and underwriting discounts and commissions. The associated expenses and underwriting discounts and commissions are amortized using the interest method at an effective interest rate of 10.6%. The net proceeds were used to fund the GC Acquisition as discussed further in Note 3.

At any time prior to December 14, 2018, the Company may redeem all or a part of the Senior Notes at 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 a redemption price equal to a specified percentage of the principal amount of the redeemed notes (104.50% for 2018, 102.25% for 2019, and 100% for 2020 and thereafter, during the twelve-month period beginning on December 14 of each applicable year), plus accrued and unpaid interest. Additionally, prior to December 14, 2018, the Company can, on one or more occasions, redeem up to 35% of the principal amount of the Senior Notes with all or a portion of the net cash proceeds of one or more Equity Offerings (as defined in the Indenture) at a redemption price equal to 109% of the principal amount of the redeemed notes, plus accrued and unpaid interest, subject to certain conditions.

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

As of September 30, 2017, the most recent compliance date, the Company was in compliance with these covenants and expects to remain in compliance throughout the next 12-month period.

8.
Commodity Derivative Instruments

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

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


12


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 the cost of the put is offset by the proceeds of the call. 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 five counterparties and an exchange. Three 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 it 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, 2017 are summarized below:
Settlement Period
 
Derivative
Instrument
 
Average Volumes
(Bbls
per month)
 
Floor
Price
 
Ceiling
Price
Crude Oil - NYMEX WTI
 
 
 
 
 
 
 
 
Oct 1, 2017 - Dec 31, 2017
 
Collar
 
30,667

 
$
40.00

 
$
60.00

Oct 1, 2017 - Dec 31, 2017
 
Collar
 
20,000

 
$
45.00

 
$
70.00

Oct 1, 2017 - Dec 31, 2017
 
Collar
 
30,667

 
$
40.00

 
$
65.00

Oct 1, 2017 - Dec 31, 2017
 
Collar
 
30,667

 
$
40.00

 
$
65.00

Oct 1, 2017 - Dec 31, 2017
 
Collar
 
15,333

 
$
45.00

 
$
65.00

Oct 1, 2017 - Dec 31, 2017
 
Collar
 
15,333

 
$
45.00

 
$
65.10

Jan 1, 2018 - Dec 31, 2018
 
Collar
 
76,042

 
$
40.00

 
$
57.60

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

 
$
2.75

 
$
4.00

Oct 1, 2017 - Dec 31, 2017
 
Collar
 
153,333

 
$
2.75

 
$
3.90

Oct 1, 2017 - Dec 31, 2017
 
Collar
 
92,000

 
$
2.75

 
$
4.10

Oct 1, 2017 - Dec 31, 2017
 
Collar
 
15,333

 
$
3.00

 
$
4.31

Oct 1, 2017 - Dec 31, 2017
 
Collar
 
110,400

 
$
3.00

 
$
4.30

Oct 1, 2017 - Dec 31, 2017
 
Collar
 
199,333

 
$
3.00

 
$
3.88

Oct 1, 2017 - Dec 31, 2017
 
Collar
 
199,333

 
$
3.00

 
$
3.91

 
 
 
 
 
 
 
 
 
Natural Gas - CIG Rocky Mountain
 
 
 
 
 
 
 
 
Oct 1, 2017 - Dec 31, 2017
 
Collar
 
200,000

 
$
2.50

 
$
3.27

Oct 1, 2017 - Dec 31, 2017
 
Collar
 
100,000

 
$
2.60

 
$
3.20

Jan 1, 2018 - Dec 31, 2018
 
Collar
 
456,250

 
$
2.25

 
$
2.81


Subsequent to September 30, 2017, the Company added the following positions:
Settlement Period
 
Derivative
Instrument
 
Average Volumes
(Bbls
per month)
 
Floor
Price
 
Ceiling
Price
Crude Oil - NYMEX WTI
 
 
 
 
 
 
 
 
Jan 1, 2018 - Dec 31, 2018
 
Collar
 
76,042

 
$
45.00

 
$
58.00


Offsetting of Derivative Assets and Liabilities

As of September 30, 2017 and December 31, 2016, all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of either party, for transactions that occur on the same date and in the same currency. The Company’s agreements also provide that, in the event of an early termination, each party has the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to offset these positions in its condensed consolidated balance sheets.

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, 2017
Underlying
 
Balance Sheet
Location
 
Gross Amounts of Recognized Assets and Liabilities
 
Gross Amounts Offset in the
Balance Sheet
 
Net Amounts of Assets and Liabilities Presented in the
Balance Sheet
Commodity derivative contracts
 
Current assets
 
$
1,214

 
$
(1,214
)
 
$

Commodity derivative contracts
 
Noncurrent assets
 
$
502

 
$
(502
)
 
$

Commodity derivative contracts
 
Current liabilities
 
$
2,000

 
$
(1,214
)
 
$
786

Commodity derivative contracts
 
Noncurrent liabilities
 
$
896

 
$
(502
)
 
$
394

 
 
 
 
As of December 31, 2016
Underlying
 
Balance Sheet
Location
 
Gross Amounts of Recognized Assets and Liabilities
 
Gross Amounts Offset in the
Balance Sheet
 
Net Amounts of Assets and Liabilities Presented in the
Balance Sheet
Commodity derivative contracts
 
Current assets
 
$
2,045

 
$
(1,748
)
 
$
297

Commodity derivative contracts
 
Noncurrent assets
 
$

 
$

 
$

Commodity derivative contracts
 
Current liabilities
 
$
4,622

 
$
(1,748
)
 
$
2,874

Commodity derivative contracts
 
Noncurrent liabilities
 
$

 
$

 
$


The amount of gain (loss) recognized in the condensed consolidated statements of operations related to derivative financial instruments was as follows (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
Realized gain (loss) on commodity derivatives
$
116

 
$
(13
)
 
$
(26
)
 
$
2,868

Unrealized gain (loss) on commodity derivatives
(2,499
)
 
420

 
2,350

 
(6,485
)
Total gain (loss)
$
(2,383
)
 
$
407

 
$
2,324

 
$
(3,617
)

Realized gains and losses include cash received from the monthly settlement of derivative contracts at their scheduled maturity date and the previously incurred premiums attributable to settled commodity contracts. The following table summarizes derivative realized gains and losses during the periods presented (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
Monthly settlement
$
376

 
$
497

 
$
927

 
$
4,398

Previously incurred premiums attributable to settled commodity contracts
(260
)
 
(510
)
 
(953
)
 
(1,530
)
Total realized gain (loss)
$
116

 
$
(13
)
 
$
(26
)
 
$
2,868



15


Credit Related Contingent Features

As of September 30, 2017, three of the six 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 fourth counterparty, which is not a lender under the credit facility, is unsecured and does not require the posting of collateral. The agreement with the fifth counterparty, which is not a lender under the credit facility, may require the posting of collateral if in a liability position. The agreement with the sixth counterparty is subject to an inter-creditor agreement between the counterparty and the Company’s lenders under the credit facility.

9.
Fair Value Measurements

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

Level 1: Quoted prices available in active markets for identical assets or liabilities;
Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; and
Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow or other valuation models.

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

The Company’s non-recurring fair value measurements include unproved properties, asset retirement obligations, and purchase price allocations for the fair value of assets and liabilities acquired through business combinations and certain asset acquisitions. Please refer to Notes 2, 3, and 5 for further discussion of unproved properties, business combinations and asset acquisitions, and asset retirement obligations, respectively.

The Company determines the estimated fair value of its unproved properties using market comparables, which are deemed to be a Level 3 input. See Note 2 for additional information.

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

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 Notes 3 and 5 for additional information.


16


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, 2017 and December 31, 2016 by level within the fair value hierarchy (in thousands):
 
Fair Value Measurements at September 30, 2017
 
Level 1
 
Level 2
 
Level 3
 
Total
Financial assets and liabilities:
 
 
 
 
 
 
 
Commodity derivative asset
$

 
$

 
$

 
$

Commodity derivative liability
$

 
$
1,180

 
$

 
$
1,180

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

 
$
297

 
$

 
$
297

Commodity derivative liability
$

 
$
2,874

 
$

 
$
2,874


Commodity Derivative Instruments

The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparties to its derivative contracts would default by failing to make any contractually required payments. The Company considers the counterparties to be of substantial credit quality and believes that they have the financial resources and willingness to meet their potential repayment obligations associated with the derivative transactions. At September 30, 2017, derivative instruments utilized by the Company consist of puts and collars. The oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are based on several factors including public indices, the instruments themselves are 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, cash held in escrow, accounts receivable, and accounts payable are representative of their fair values due to their short-term maturities. Due to the variable interest rate paid on credit facility borrowings, the carrying value is representative of its fair value.

The fair value of the Senior Notes is estimated to be $84.8 million at September 30, 2017. The Company determined the fair value of its notes payable at September 30, 2017 by using observable market based information for debt instruments of similar amounts and duration. The Company has classified the notes as Level 2.

10.
Interest Expense

The components of interest expense are (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
Revolving bank credit facility
$
1,016

 
$

 
$
1,286

 
$
154

Notes payable
1,800

 
1,800

 
5,400

 
2,120

Amortization of issuance costs
1,090

 
467

 
2,267

 
1,076

Less, interest capitalized
(3,906
)
 
(2,267
)
 
(8,953
)
 
(3,350
)
Interest expense, net of amounts capitalized
$

 
$

 
$

 
$



17


11.
Weighted-Average Shares Outstanding

The following table sets forth the Company's outstanding equity grants which have a dilutive effect on earnings per share:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
Weighted-average shares outstanding - basic
200,881,447

 
200,515,555

 
200,807,436

 
164,771,544

Potentially dilutive common shares from:
 
 
 
 
 
 
 
Stock options
415,524

 

 
412,902

 

Restricted stock units and stock bonus shares
163,944

 

 
105,791

 

Weighted-average shares outstanding - diluted
201,460,915

 
200,515,555

 
201,326,129

 
164,771,544


The following potentially dilutive securities outstanding for the periods presented were not included in the respective weighted-average shares outstanding-diluted calculation above as such securities had an anti-dilutive effect on earnings per share:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
Potentially dilutive common shares from:
 
 
 
 
 
 
 
Stock options
4,726,500

 
5,903,500

 
4,756,500

 
5,903,500

Performance-vested stock units 1
951,884

 
478,510

 
951,884

 
478,510

Restricted stock units and stock bonus shares
308,094

 
1,003,879

 
497,806

 
1,003,879

Total
5,986,478

 
7,385,889

 
6,206,190

 
7,385,889

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

12.
Stock-Based Compensation

In addition to cash compensation, the Company may compensate employees and directors with equity-based compensation in the form of stock options, performance-vested stock units, restricted stock units, stock bonus shares, warrants, and other equity awards. The Company records its equity compensation by pro-rating the estimated grant date fair value of each grant over the period of time that the recipient is required to provide services to the Company (the "vesting phase").  The calculation of fair value is based, either directly or indirectly, on the quoted market value of the Company’s common stock.  Indirect valuations are calculated using the Black-Scholes-Merton option pricing model or a Monte Carlo Model. For the periods presented, all stock-based compensation was either classified as a component within general and administrative expense in the Company's condensed consolidated statements of operations or, for that portion which is directly attributable to individuals performing acquisition, exploration, and development activities, was capitalized to the full cost pool. As of September 30, 2017, there were 4,500,000 common shares authorized for grant under the 2015 Plan, of which 86,464 shares were available for future grants. The shares available for future grant exclude 951,884 shares which have been reserved for future vesting of performance-vested stock units under the assumption that these awards met the criterion to vest at their maximum multiplier.

The amount of stock-based compensation was as follows (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
Stock options
$
1,277

 
$
1,274

 
$
3,825

 
$
4,107

Performance-vested stock units
807

 
354

 
2,130

 
692

Restricted stock units and stock bonus shares
1,386

 
1,023

 
3,779

 
3,341

Total stock-based compensation
$
3,470

 
$
2,651

 
$
9,734

 
$
8,140

Less: stock-based compensation capitalized
(440
)
 
(278
)
 
(1,344
)
 
(856
)
Total stock-based compensation expensed
$
3,030

 
$
2,373

 
$
8,390

 
$
7,284



18


Stock options

No stock options were granted during the three and nine months ended September 30, 2017. During the periods presented, the Company granted the following stock options:
 
Three Months Ended September 30, 2016
 
Nine Months Ended September 30, 2016
Number of options to purchase common shares
350,000

 
944,500

Weighted-average exercise price
$
6.55

 
$
7.20

Term (in years)
10 years

 
10 years

Vesting Period (in years)
5 years

 
3 - 5 years

Fair Value (in thousands)
$
1,253

 
$
3,381


The assumptions used in valuing stock options granted during each of the periods presented were as follows:
 
Nine Months Ended September 30, 2016
Expected term
6.4 years

Expected volatility
55
%
Risk free rate
1.25 - 1.75%

Expected dividend yield
%

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

 
$
9.27

 
8.0 years
 
$
6,515

Granted

 

 
 
 
 
Exercised
(30,000
)
 
3.79

 
 
 
140

Expired
(41,000
)
 
11.98

 
 
 
 
Forfeited
(104,000
)
 
11.60

 
 
 
 
Outstanding, September 30, 2017
5,826,500

 
$
9.23

 
7.2 years
 
$
8,076

Outstanding, Exercisable at September 30, 2017
3,146,361

 
$
8.77

 
6.6 years
 
$
5,660


The following table summarizes information about issued and outstanding stock options as of September 30, 2017:
 
 
Outstanding Options
 
Exercisable Options
Range of Exercise Prices
 
Options
 
Weighted-Average Exercise Price per Share
 
Weighted-Average Remaining Contractual Life
 
Options
 
Weighted-Average Exercise Price per Share
 
Weighted-Average Remaining Contractual Life
Under $5.00
 
600,000

 
$
3.49

 
3.9 years
 
574,000

 
$
3.46

 
3.8 years
$5.00 - $6.99
 
1,012,000

 
6.38

 
7.2 years
 
549,000

 
6.45

 
6.0 years
$7.00 - $10.99
 
1,592,500

 
9.34

 
7.7 years
 
658,661

 
9.50

 
7.3 years
$11.00 - $13.46
 
2,622,000

 
11.58

 
7.7 years
 
1,364,700

 
11.58

 
7.6 years
Total
 
5,826,500

 
$
9.23

 
7.2 years
 
3,146,361

 
$
8.77

 
6.6 years

The estimated unrecognized compensation cost from stock options not vested as of September 30, 2017, which will be recognized ratably over the remaining vesting phase, is as follows:
Unrecognized compensation cost (in thousands)
$
11,101

Remaining vesting phase
2.5 years


19



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, 2017:
 
Number of Shares
 
Weighted-Average Grant-Date Fair Value
Not vested, December 31, 2016
890,336

 
$
9.54

Granted
669,323

 
8.27

Vested
(336,445
)
 
9.17

Forfeited
(24,807
)
 
9.85

Not vested, September 30, 2017
1,198,407

 
$
8.93


The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of September 30, 2017, which will be recognized ratably over the remaining vesting phase, is as follows:
Unrecognized compensation cost (in thousands)
$
8,232

Remaining vesting phase
2.3 years


Performance-vested stock units

The Company grants performance-vested stock units ("PSUs") to certain executives under its long-term incentive plan. The number of shares of the Company’s common stock that may be issued to settle PSUs ranges from zero to two times the number of PSUs awarded. The shares issued for PSUs are determined based on the Company’s performance over a three-year measurement period and vest in their entirety at the end of the measurement period. The PSUs will be settled in shares of the Company’s common stock following the end of the three-year performance cycle. Any PSUs that have not vested at the end of the applicable measurement period are forfeited. The vesting criterion for the PSUs is based on a comparison of the Company’s total shareholder return ("TSR") for the measurement period compared with the TSRs of a group of peer companies for the same measurement period. As the 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.


20


The assumptions used in valuing the PSUs granted were as follows:
 
Nine Months Ended September 30,
 
2017
 
2016
Weighted-average expected term
2.9 years

 
2.7 years

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

The fair value of the PSUs granted during the nine months ended September 30, 2017 and 2016 was $5.1 million and $4.0 million, respectively. As of September 30, 2017, unrecognized compensation cost for PSUs was $5.8 million and will be amortized through 2019. A summary of the status and activity of PSUs is presented in the following table:
 
Number of Units1
 
Weighted-Average Grant-Date Fair Value
Not vested, December 31, 2016
478,510

 
$
8.09

Granted
473,374

 
10.79

Vested

 

Forfeited

 

Not vested, September 30, 2017
951,884

 
$
9.44

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

13.
Income Taxes

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

The effective tax rates for the three and nine months ended September 30, 2017 and 2016 were nil. The effective tax rates for the three and nine months ended September 30, 2017 and 2016 were based upon a full year forecasted tax provision and differs from the statutory rate primarily due to the recognition of a valuation allowance recorded against deferred tax assets. There were no significant discrete items recorded during the three and nine months ended September 30, 2017 and 2016.

As of September 30, 2017, we had no liability for unrecognized tax benefits. The Company believes that there are no new items nor changes in facts or judgments that should impact the Company’s tax position.  Given the substantial NOL carryforwards at both the federal and state levels, it is anticipated that any changes resulting from a tax examination would simply adjust the carryforwards and would not result in significant interest expense or penalties.  Most of the Company's tax returns filed since 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, 2017.  The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of September 30, 2017, the Company has not recognized any interest or penalties related to uncertain tax benefits.

    Each period, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Based upon our cumulative losses through September 30, 2017, we have provided a full valuation allowance reducing the net realizable benefits.


21


14.
Other Commitments and Contingencies

Volume Commitments

The Company entered into firm sales agreements for its oil production with three counterparties during 2014 and entered into an additional firm sales agreement for its oil production in the third quarter 2017. Deliveries under two of the sales agreements commenced during 2015. Deliveries under the third agreement commenced in 2016. Deliveries under the fourth agreement are expected to commence in the second quarter of 2018. Pursuant to these agreements, we must deliver specific amounts of oil either from our own production or from oil that we acquire from third parties. If we are unable to fulfill all of our contractual obligations, we may be required to pay penalties or damages pursuant to these agreements. Our commitments over the next five years, excluding the contingent commitment described below, are as follows:
Year ending December 31,
 
Oil
 
(MBbls)
Remainder of 2017
 
1,072

2018
 
4,942

2019
 
5,167

2020
 
4,003

2021
 
1,672

Thereafter
 

Total
 
16,856


During the nine months ended September 30, 2017, the Company incurred deficiency charges of $0.7 million as we were unable to meet all of the obligations during the period. During the third quarter of 2017, we were able to meet all of our delivery obligations, and we anticipate that our current gross operated production will continue to meet our future delivery obligations, although this cannot be guaranteed.

In collaboration with several other producers and DCP Midstream, LP ("DCP Midstream"), we have agreed to participate in the expansion of natural gas gathering and processing capacity in the D-J Basin.  The first agreement includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system. Both are currently expected to be completed by late 2018, although the start-up date is undetermined at this time. Our share of the commitment will require 46.4 MMcf per day to be delivered after the plant in-service date for a period of 7 years. The second agreement also includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system. Both are currently expected to be completed in 2019, although the start-up date is undetermined at this time. Our share of the commitment will require 43.8 MMcf per day to be delivered after the plant in-service date for a period of 7 years. These contractual obligations can be reduced by the collective volumes delivered to the plants by other producers in the D-J Basin that are in excess of such producers' total commitment. We expect that our development plan will support the utilization of this capacity.

Office leases

In September 2016, the Company entered into a new 65-month lease for the Company’s principal office space located in Denver, which commenced in the first quarter of 2017. Rent under the new lease is approximately $62,000 per month. In July 2016, the Company entered into a field office lease in Greeley which requires monthly payments of $7,500 through October 2021. A schedule of the minimum lease payments under non-cancelable operating leases as of September 30, 2017 follows (in thousands):
Year ending December 31,
 
Rent
Remainder of 2017
 
$
208

2018
 
840

2019
 
859

2020
 
878

2021
 
875

Thereafter
 
477

Total
 
$
4,137



22


Rent expense for offices leases was $0.2 million for the three months ended September 30, 2017 and 2016, respectively. For the nine months ended September 30, 2017 and 2016, rent expense for office leases was $0.9 million and $0.5 million, respectively.

Litigation

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

15.
Supplemental Schedule of Information to the Condensed Consolidated Statements of Cash Flows

The following table supplements the cash flow information presented in the condensed consolidated financial statements for the periods presented (in thousands):
 
Nine Months Ended September 30,
Supplemental cash flow information:
2017
 
2016
Interest paid
$
4,796

 
$
159

Income taxes paid

 
106

 
 
 
 
Non-cash investing and financing activities:
 
 
 
Accrued well costs as of period end
$
122,387

 
$
32,299

Asset retirement obligations incurred with development activities
2,782

 
366

Asset retirement obligations assumed with acquisitions
23,521

 
2,046

Obligations discharged with asset retirements and divestitures
(7,023
)
 
(3,997
)


23


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

Introduction

The following discussion and analysis was prepared to supplement information contained in the accompanying condensed consolidated financial statements and is intended to explain certain items regarding the Company's financial condition as of September 30, 2017 and its results of operations for the three and nine months ended September 30, 2017 and 2016.  It should be read in conjunction with the “Selected Financial Data” and the accompanying audited consolidated financial statements and related notes thereto contained in the Annual Report on Form 10-K for the year ended December 31, 2016 filed with the SEC on February 23, 2017. Unless the context otherwise requires, references to "SRC Energy," "we," "us," "our," or the "Company" in this report refer to the registrant, SRC Energy Inc., and its subsidiaries.

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

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

Overview

SRC Energy is an independent oil and gas company engaged in the acquisition, development, and production of oil, natural gas, and NGLs in the D-J Basin, which we believe to be one of the premier, liquids-rich oil and natural gas resource plays in the United States. It contains hydrocarbon-bearing deposits in several formations, including the Niobrara, Codell, Greenhorn, Shannon, Sussex, J-Sand, and D-Sand. The area has produced oil and natural gas for over fifty years and benefits from established infrastructure including midstream and refining capacity, long reserve life, and multiple service providers.

Our drilling and completion activities are focused in the Wattenberg Field in Weld County, Colorado, an area that covers the western flank of the D-J Basin. Currently, we are focused on the horizontal development of the Codell and Niobrara formations, which are characterized by relatively high liquids content.

In order to maintain operational focus while preserving developmental flexibility, we strive to attain operational control of a majority of the wells in which we have a working interest. We currently operate approximately 90% of our proved producing reserves and anticipate operating substantially all of our future net drilling locations. Additionally, our current development plan anticipates that all of our future activities will be concentrated in the Wattenberg Field.

Market Conditions

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

 
$
48.73

 
$
60.65

 
$
100.39

 
$
94.58

Natural gas (per Mcf)
$
2.52

 
$
2.58

 
$
3.12

 
$
4.38

 
$
3.55



24


For the periods presented in this report, the following table presents the Reference Price (derived from average NYMEX prices) as well as the differential between the Reference Price and the prices realized by us.
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
Oil (NYMEX WTI)
 
 
 
 
 
 
 
Average NYMEX Price
$
48.18

 
$
44.90

 
$
49.44

 
$
41.23

Realized Price
42.37

 
35.67

 
42.04

 
31.47

Differential
$
(5.81
)
 
$
(9.23
)
 
$
(7.40
)
 
$
(9.76
)
 
 
 
 
 
 
 
 
Gas (NYMEX Henry Hub)
 
 
 
 
 
 
 
Average NYMEX Price
$
2.99

 
$
2.88

 
$
3.03

 
$
2.34

Realized Price
2.35

 
2.73

 
2.39

 
2.18

Differential
$
(0.64
)
 
$
(0.15
)
 
$
(0.64
)
 
$
(0.16
)
 
 
 
 
 
 
 
 
NGL Realized Price
$
17.32

 
$

 
$
15.49

 
$


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

There has been significant volatility in the price of oil and natural gas since mid-2014.  During the nine months ended September 30, 2017, the NYMEX-WTI oil price ranged from a high of $54.48 per Bbl on February 23, 2017 to a low of $42.48 per Bbl on June 21, 2017, and the NYMEX-Henry Hub natural gas price ranged from a low of $2.56 per MMBtu on February 21, 2017 to a high of $3.42 per MMBtu on May 12, 2017. As reflected in published data, the price for WTI oil settled at $53.75 per Bbl on Friday, December 30, 2016.  Comparably, the price of oil settled at $51.67 per Bbl on Friday, September 29, 2017, a decline of 4% from December 30, 2016. Our revenues, results of operations, profitability and future growth, and the carrying value of our oil and gas properties depend primarily on the prices that we receive for our oil, natural gas, and NGL production.

A decline in oil and natural gas prices will adversely affect our financial condition and results of operations.  Furthermore, low oil and natural gas prices can result in an impairment of the value of our properties and impact the calculation of the “ceiling test” required under the accounting principles for companies following the “full cost” method of accounting.  At September 30, 2017, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary.   However, if pricing conditions decline, we may incur a full cost ceiling impairment related to our oil and gas properties in future quarters.


25


Core Operations

The following table provides details about our ownership interests with respect to vertical and horizontal producing wells as of September 30, 2017:
Vertical Wells
Operated Wells
 
Non-Operated Wells
 
Totals
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
482

 
456

 
135

 
32

 
617

 
488

Horizontal Wells
Operated Wells
 
Non-Operated Wells
 
Totals
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
208

 
194

 
191

 
33

 
399

 
227


In addition to the producing wells summarized in the preceding table, as of September 30, 2017, we were the operator of 46 gross (36 net) horizontal wells in progress, which excludes 19 gross (14 net) wells for which we have only set surface casings. As of September 30, 2017, we are participating in 107 gross (22 net) non-operated horizontal wells in progress. The Company is actively conveying its interests in many of the underlying non-operated wells in progress through signed or anticipated agreements.

As we develop our acreage through horizontal drilling, we have an active program for plugging and abandoning the vast majority of the operated vertical wellbores. During the nine months ended September 30, 2017, we plugged 86 wells and returned the associated acreage to the property owners.

On May 2, 2017, the Colorado Oil and Gas Conservation Commission issued a Notice to Operators (NTO) to verify the location of all flowlines associated with operated wells and the integrity of those flowlines. The Company has completed all field work associated with the NTO and filed the required paperwork regarding its operations ahead of the June 30, 2017 deadline.

Production

For the three months ended September 30, 2017, our average daily production increased to 40,378 BOED as compared to 10,794 BOED for the three months ended September 30, 2016. During the first nine months of 2017, our average net daily production was 30,331 BOED. By comparison, during the nine months ended September 30, 2016, our average production rate was 11,133 BOED. As of September 30, 2017, approximately 99% of our daily production was from horizontal wells.

Strategy

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

Concentrate on our existing core area in and around the D-J Basin, where we have significant operating experience.  All of our current wells and our planned acreage development is located either in or adjacent to the Wattenberg Field.  Focusing our operations in this area leverages our management, technical, and operational experience in the basin.
 
Develop and exploit existing oil and gas properties.  Our principal growth strategy has been to develop and exploit our properties to add reserves.  In the Wattenberg Field, we target three benches of the Niobrara formation as well as the Codell formation for horizontal drilling and production. We believe horizontal drilling is the most efficient way to recover the potential hydrocarbons and consider the Wattenberg Field to be relatively low-risk because information gained from the large number of existing wells can be applied to potential future wells.  There is enough similarity between wells in the Wattenberg Field that the exploitation process is generally repeatable.

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

26


section depending on the specific area of the field being drilled.
 
Complete selective acquisitions.  We seek to acquire developed and undeveloped oil and gas properties, primarily in the Wattenberg Field.  We generally seek acquisitions that will provide us with opportunities for reserve additions and increased cash flow through production enhancement and additional development and exploratory prospect generation.
 
Retain control over the operation of a substantial portion of our production. As operator of a majority of our wells and undeveloped acreage, we control the timing and selection of new wells to be drilled.  This allows us to modify our capital spending as our financial resources and underlying lease terms allow and market conditions permit.

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