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

FORM 10-Q

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

For the quarterly period ended September 30, 2017March 31, 2019

OR

 oTRANSITION 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

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SRC ENERGY INC.
(Exact name of registrant as specified in its charter)

COLORADO20-2835920
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)

1675 Broadway, Suite 2600, Denver, CO80202
(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)files). 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 outstanding243,392,175 outstanding shares of common stock as of October 31, 2017.April 29, 2019.


SRC ENERGY INC.

Index

   Page
Part I - FINANCIAL INFORMATION  
    
Item 1.Financial Statements (unaudited)  
    
 Condensed Consolidated Balance Sheets as of September 30, 2017March 31, 2019 and December 31, 20162018 
2
    
 Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2017March 31, 2019 and 20162018 
3
    
 Condensed Consolidated Statements of Cash Flows for the ninethree months ended September 30, 2017March 31, 2019 and 20162018 
4
Condensed Consolidated Statements of Changes in Shareholders’ Equity for the three months ended March 31, 2019 and 2018
5
    
 Notes to Condensed Consolidated Financial Statements 
56
    
Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations 
2421
    
Item 3.Quantitative and Qualitative Disclosures About Market Risk 
4134
    
Item 4.Controls and Procedures 
4235
    
Part II - OTHER INFORMATION  
    
Item 1.Legal Proceedings 
4336
    
Item 1A.Risk Factors 
4336
    
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds 
4336
    
Item 3.Defaults of Senior Securities 
4336
    
Item 4.Mine Safety Disclosures 
4336
    
Item 5.Other Information 
4336
    
Item 6.Exhibits 
4437
    
SIGNATURES 
4538




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


ASSETSSeptember 30, 2017 December 31, 2016March 31, 2019 December 31, 2018
Current assets:      
Cash and cash equivalents$21,325
 $18,615
$56,813
 $49,609
Accounts receivable:      
Oil, natural gas, and NGL sales72,309
 25,728
102,096
 100,973
Trade45,280
 6,805
29,775
 39,415
Commodity derivative assets—
 297
7,081
 34,906
Other current assets6,289
 2,739
8,610
 7,537
Total current assets145,203
 54,184
204,375
 232,440
      
Property and equipment:      
Oil and gas properties, full cost method:      
Unproved properties and land, not subject to depletion327,154
 398,547
Proved properties, net of accumulated depletion758,135
 424,082
1,663,635
 1,545,445
Wells in progress158,192
 81,780
192,459
 227,262
Unproved properties and land, not subject to depletion722,388
 740,453
Oil and gas properties, net1,243,481
 904,409
2,578,482
 2,513,160
Other property and equipment, net6,152
 4,327
5,218
 5,540
Total property and equipment, net1,249,633
 908,736
2,583,700
 2,518,700
Cash held in escrow and other deposits—
 18,248
Goodwill40,711
 40,711
Other assets2,359
 2,234
8,588
 3,574
Total assets$1,437,906
 $1,024,113
$2,796,663
 $2,754,714
      
LIABILITIES AND SHAREHOLDERS' EQUITY      
Current liabilities:      
Accounts payable and accrued expenses$134,144
 $52,453
$118,981
 $150,010
Revenue payable58,742
 16,557
92,027
 97,030
Production taxes payable37,017
 17,673
102,072
 95,099
Asset retirement obligations2,738
 2,683
13,495
 11,694
Commodity derivative liabilities786
 2,874
Total current liabilities233,427
 92,240
326,575
 353,833
      
Revolving credit facility150,000
 —
195,000
 195,000
Notes payable, net of issuance costs76,216
 75,614
539,666
 539,360
Commodity derivative liabilities394
 —
Asset retirement obligations33,981
 13,775
36,093
 40,052
Deferred taxes56,002
 37,967
Other liabilities2,268
 1,745
3,747
 2,210
Total liabilities496,286
 183,374
1,157,083
 1,168,422
      
Commitments and contingencies (See Note 14)

 

Commitments and contingencies (See Note 15)

 

      
Shareholders' equity:      
Preferred stock - $0.01 par value, 10,000,000 shares authorized: no shares issued and outstanding—
 —
—
 —
Common stock - $0.001 par value, 300,000,000 shares authorized: 200,909,101 and 200,647,572 shares issued and outstanding as of September 30, 2017 and December 31, 2016, respectively201
 201
Common stock - $0.001 par value, 400,000,000 shares authorized: 243,317,326 and 242,608,284 shares issued and outstanding as of March 31, 2019 and December 31, 2018, respectively243
 243
Additional paid-in capital1,158,317
 1,148,998
1,495,644
 1,492,107
Retained deficit(216,898) (308,460)
Retained earnings143,693
 93,942
Total shareholders' equity941,620
 840,739
1,639,580
 1,586,292
      
Total liabilities and shareholders' equity$1,437,906
 $1,024,113
$2,796,663
 $2,754,714

The accompanying notes are an integral part of these condensed consolidated financial statements
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 2016Three Months Ended March 31,
       2019 2018
Oil, natural gas, and NGL revenues$103,593
 $26,234
 $222,419
 $68,454
$189,455
 $147,233
Sales of purchased oil—
 —
 1,268
 —
Total revenues103,593
 26,234
 223,687
 68,454
          
Expenses:          
Lease operating expenses5,154
 3,819
 13,894
 14,963
17,360
 7,896
Transportation and gathering4,054
 1,855
Production taxes10,083
 (1,461) 21,013
 2,509
7,086
 13,443
Costs of purchased oil—
 —
 1,518
 —
Depreciation, depletion, and accretion33,740
 9,635
 73,396
 33,001
60,918
 37,081
Full cost ceiling impairment—
 25,453
 —
 215,223
Unused commitment charge—
 205
 669
 505
General and administrative8,484
 8,236
 24,289
 23,199
9,469
 9,600
Total expenses57,461
 45,887
 134,779
 289,400
98,887
 69,875
          
Operating income (loss)46,132
 (19,653) 88,908
 (220,946)
Operating income90,568
 77,358
          
Other income (expense):          
Commodity derivatives gain (loss)(2,383) 407
 2,324
 (3,617)
Commodity derivatives loss(22,913) (5,781)
Interest expense, net of amounts capitalized—
 —
 —
 —
—
 —
Interest income16
 11
 47
 176
69
 9
Other income (expense)83
 (1) 385
 3
Total other income (expense)(2,284) 417
 2,756
 (3,438)
Other income61
 21
Total other expense(22,783) (5,751)
          
Income (Loss) before income taxes43,848
 (19,236) 91,664
 (224,384)
Income before income taxes67,785
 71,607
          
Income tax expense—
 5
 —
 106
18,034
 5,811
Net income (loss)$43,848
 $(19,241) $91,664
 $(224,490)
Net income$49,751
 $65,796
          
Net income (loss) per common share:       
Net income per common share:   
Basic$0.22
 $(0.10) $0.46
 $(1.36)$0.20
 $0.27
Diluted$0.22
 $(0.10) $0.46
 $(1.36)$0.20
 $0.27
          
Weighted-average shares outstanding:          
Basic200,881,447
 200,515,555
 200,807,436
 164,771,544
243,290,734
 241,751,915
Diluted201,460,915
 200,515,555
 201,326,129
 164,771,544
244,091,516
 243,166,897

The accompanying notes are an integral part of these condensed consolidated financial statements
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 accretion73,396
 33,001
Full cost ceiling impairment—
 215,223
Settlement of asset retirement obligation(4,077) (196)
Stock-based compensation8,390
 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 contracts778
 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 expenses1,413
 1,761
Revenue payable41,997
 (363)
Production taxes payable17,548
 (10,158)
Other(941) (905)
Net cash provided by operating activities142,817
 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 escrow18,248
 (18,244)
Proceeds from sales of oil and gas properties and other77,017
 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 options114
 —
Payment of employee payroll taxes in connection with shares withheld(631) (510)
Proceeds from the revolving credit facility170,000
 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 activities148,111
 540,235
    
Net increase (decrease) in cash and equivalents2,710
 (2,742)
    
Cash and equivalents at beginning of period18,615
 66,499
    
Cash and equivalents at end of period$21,325
 $63,757
 Three Months Ended March 31,
 2019 2018
Cash flows from operating activities:   
Net income$49,751
 $65,796
Adjustments to reconcile net income to net cash provided by operating activities:   
Depletion, depreciation, and accretion60,918
 37,081
Settlement of asset retirement obligations(2,066) (2,461)
Provision for deferred taxes18,034
 5,811
Stock-based compensation expense3,683
 2,796
Mark-to-market of commodity derivative contracts:   
Total loss on commodity derivatives contracts22,913
 5,781
Cash settlements on commodity derivative contracts4,626
 (1,555)
Cash premiums paid for commodity derivative contracts(319) —
Changes in operating assets and liabilities3,133
 14,432
Net cash provided by operating activities160,673
 127,681
    
Cash flows from investing activities:   
Acquisition of oil and gas properties and leaseholds2,623
 (1,329)
Capital expenditures for drilling and completion activities(148,904) (100,347)
Other capital expenditures(6,245) (3,640)
Acquisition of land and other property and equipment(133) (317)
Proceeds from sales of oil and gas properties and other124
 728
Net cash used in investing activities(152,535) (104,905)
    
Cash flows from financing activities:   
Proceeds from the employee exercise of stock options—
 1,063
Payment of employee payroll taxes in connection with shares withheld(876) (475)
Fees on debt and equity issuances and revolving credit facility amendments—
 (306)
Capital lease payments(58) (87)
Net cash provided by (used in) financing activities(934) 195
    
Net increase in cash and cash equivalents7,204
 22,971
    
Cash and cash equivalents at beginning of period49,609
 48,772
    
Cash and cash equivalents at end of period$56,813
 $71,743
Supplemental Cash Flow Information (See Note 15)16)

The accompanying notes are an integral part of these condensed consolidated financial statements
SRC ENERGY INC.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
(unaudited; in thousands, except share data)

 Number of Common
Shares		 Par Value
Common Stock		 Additional
Paid-In Capital		 Retained
Deficit		 Total Shareholders'
Equity
Balance, December 31, 2017241,365,522
 $241
 $1,474,273
 $(166,080) $1,308,434
Shares issued under stock bonus and equity incentive plans268,676
 1
 (1) —
 —
Shares issued for exercise of stock options268,303
 —
 1,064
 —
 1,064
Stock-based compensation—
 —
 3,395
 —
 3,395
Payment of tax withholdings using withheld shares—
 —
 (705) —
 (705)
Other activity—
 —
 (73) —
 (73)
Net income—
 —
 —
 65,796
 65,796
Balance, March 31, 2018241,902,501
 $242
 $1,477,953
 $(100,284) $1,377,911
 Number of Common
Shares		 Par Value
Common Stock		 Additional
Paid-In Capital		 Retained
Earnings		 Total Shareholders'
Equity
Balance, December 31, 2018242,608,284
 $243
 $1,492,107
 $93,942
 $1,586,292
Shares issued under stock bonus and equity incentive plans709,042
 —
 —
 —
 —
Stock-based compensation—
 —
 4,413
 —
 4,413
Payment of tax withholdings using withheld shares—
 —
 (876) —
 (876)
Net income—
 —
 —
 49,751
 49,751
Balance, March 31, 2019243,317,326
 $243
 $1,495,644
 $143,693
 $1,639,580



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 toAmerican under 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 condensed 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, 20162018 was derived from the Company's annual consolidated financial statements included within its Annual Report on Form 10-K for the year ended December 31, 20162018 as filed with the SEC on February 23, 2017.20, 2019.  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, 2016.2018.

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 revenuerevenues (“major customers”) for each of the periods presented are shown in the following table:
 Three Months Ended September 30, Nine Months Ended September 30, Three Months Ended March 31,
Major Customers 2017 2016 2017 2016 2019 2018
Company A 30% * 27% * 28% 31%
Company B 27% 20% 26% 20% 25% *
Company C 13% 12% 15% * 20% 19%
Company D * 10% * 11% * 13%
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 contractcontracts would not have a material adverse effect on us. Our oil and natural gas production

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 As of As of
Major Customers September 30, 2017 December 31, 2016 March 31, 2019 December 31, 2018
Company A 25% 23% 24% 15%
Company B 16% * 14% 12%
Company C * 43% 14% 12%
Company D * 10% 11% 13%
Company E 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 MarchFebruary 2016, the Financial Accounting Standards Board ("FASB") issued Accounting StandardsStandard Update ("ASU") 2016-09, “ImprovementsNo. 2016-02, Leases (Topic 842), followed by other related ASUs that provided targeted improvements and additional practical expedient options (collectively “ASC 842”). ASC 842 requires lessees to Employee Share-Based Payment Accounting”recognize right-of-use (“ASU 2016-09”ROU”), which intends assets and lease payment liabilities on the balance sheet for leases representing the Company’s right to improveuse the underlying assets over the lease term. Each lease that is recognized on the balance sheet will be classified as either finance or operating, with such classification affecting the pattern and classification of expense recognition in the consolidated statements of operations and presentation within the statements of cash flows.

The Company adopted ASC 842 on January 1, 2019 using the modified retrospective method. The Company elected as part of its adoption to also use the optional transition methodology whereby previously reported periods continue to be reported in accordance with historical accounting guidance for leases that were in effect for those prior periods. Policy elections and practical expedients that the Company has implemented as part of adopting ASC 842 include (a) excluding from the balance sheet leases with terms that are less than or equal to one year, (b) for all existing asset classes that contain both lease and non-lease components, combining these components together and accounting for share-based payment transactions. ASU 2016-09 changes several aspectsthem as a single lease component, (c) the package of practical expedients, which among other things, allows the Company to avoid reassessing contracts that commenced prior to adoption that were properly evaluated under legacy GAAP, and (d) excluding land easements, which were not accounted for under the previous leasing guidance, that existed or expired before adoption of ASC 842. The scope of ASC 842 does not apply to leases used in the exploration or use of minerals, oil, and natural gas.

The Company's adoption of ASC 842 resulted in an increase in other assets, accounts payable and accrued expenses, and other liabilities line items on the accompanying condensed consolidated balance sheets as a result of the accounting for share-based payment award transactions, including: (1) Accountingadditional ROU assets 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 earlyrelated lease liabilities. Upon adoption permitted. We adopted this pronouncement effectiveon January 1, 2017. Upon2019, the Company recognized approximately $2.4 million in ROU assets and $4.3 million in liabilities for its operating leases. There was no cumulative effect to retained earnings upon the adoption of this standard, we no longer estimateguidance. See Note 14 for 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.new disclosures required by ASC 842.

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

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:estimate: During the nine months ended September 30, 2017, the Company adjusted its estimate for productionProduction taxes based on recent historical experienceare comprised primarily of two elements: severance tax 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.ad valorem tax. During the three months ended September 30, 2016,March 31, 2019, the Company reduced its estimate for 2018 severance taxes. When preparing the 2018 severance tax return, the credit for ad valorem taxes basedwas greater than originally estimated, resulting in a reduction of 2018 severance taxes. Based on additional information received during that period. As a result,this analysis, the Company decreasedCompany's prior year accrual was reduced, resulting in an approximate $7.9 million reduction to our production taxes, to be paid by approximately $3.6 million which reducedincreased our operating lossincome for the three and nine months ended September 30, 2016March 31, 2019 by a corresponding amount, or $0.02$0.03 per basic and diluted common share.


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, 2016As of As of
Oil and gas properties, full cost method:   March 31, 2019 December 31, 2018
Costs of proved properties:   
Producing and non-producing$2,565,319
 $2,385,958
Less, accumulated depletion and full cost ceiling impairments(901,684) (840,513)
Subtotal, proved properties, net1,663,635
 1,545,445
   
Costs of wells in progress192,459
 227,262
   
Costs of unproved properties and land, not subject to depletion:      
Lease acquisition and other costs$319,954
 $392,561
712,993
 731,058
Land7,200
 5,986
9,395
 9,395
Subtotal, unproved properties and land327,154
 398,547
722,388
 740,453
   
Costs of wells in progress158,192
 81,780
   
Costs of proved properties:   
Producing and non-producing1,375,937
 969,239
Less, accumulated depletion and full cost ceiling impairments(617,802) (545,157)
Subtotal, proved properties, net758,135
 424,082
      
Costs of other property and equipment:      
Other property and equipment7,790
 5,063
9,803
 9,642
Less, accumulated depreciation(1,638) (736)(4,585) (4,102)
Subtotal, other property and equipment, net6,152
 4,327
5,218
 5,540
      
Total property and equipment, net$1,249,633
 $908,736
$2,583,700
 $2,518,700

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,March 31, 2019 and December 31, 2018, 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.necessary.

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
 Three Months Ended March 31,
 2019 2018
Capitalized overhead$3,667
 $3,113

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.

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 PriceJune 14, 2016
Consideration given: 
Cash$485,141
Net liabilities assumed, including asset retirement obligations1,273
Total consideration given$486,414
  
Allocation of Purchase Price 
Proved oil and gas properties (1)
$132,903
Unproved oil and gas properties353,511
Total fair value of assets acquired$486,414
(1) Proved oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement.

The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rate of11.5%, and assumptions regarding the timing and amount of future development and operating costs.

For thethree and nine months endedSeptember 30, 2017, the results of operations of the acquired assets, representing approximately$1.4 millionand$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.


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,Three Months Ended March 31,
2017 2016 2017 20162019 2018
Depletion of oil and gas properties$32,944
 $9,273
 $71,389
 $31,981
$59,428
 $36,102
Depreciation and accretion796
 362
 2,007
 1,020
1,490
 979
Total DD&A Expense$33,740
 $9,635
 $73,396
 $33,001
$60,918
 $37,081

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.


5.4.Asset Retirement Obligations

Upon completion or acquisition of a well, theThe Company recognizes obligations for its oil and natural gas operations for anticipated costs to remove and dispose of surface equipment, plugremediate the well, and abandon the wells, and restorereclaim 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, 2017Three Months Ended March 31, 2019
Asset retirement obligations, December 31, 2016$16,458
Asset retirement obligations, December 31, 2018$51,746
Obligations incurred with development activities2,782
747
Obligations assumed with acquisitions23,521
Accretion expense981
904
Obligations discharged with asset retirements and divestitures(7,023)(3,809)
Asset retirement obligation, September 30, 2017$36,719
Asset retirement obligation, March 31, 2019$49,588
Less, current portion(2,738)(13,495)
Long-term portion$33,981
$36,093

6.5.Revolving Credit Facility

On April 2, 2018, the Company entered into a second amended and restated credit agreement (the “Restated Credit Agreement”) with certain banks and other lenders. The Company maintainsRestated Credit Agreement provides a revolving credit facility (sometimes referred to as the "Revolver") withand a bank syndicate$25 million swingline facility with a maturity date of December 15, 2019.April 2, 2023. The Revolver is available for working capital requirements, capital expenditures,for exploration and production operations, acquisitions of oil and gas properties, and general corporate purposes and to support letters of credit. As of September 30, 2017,At March 31, 2019, the terms of the Revolver provideprovided for up to $1.5 billion in borrowings, an aggregate elected commitment of $500 million, in borrowings, subject toand a borrowing base limitation of $400$650 million. There was a $150.0 millionAs of March 31, 2019 and December 31, 2018, the outstanding principal balance as of September 30, 2017was $195.0 million. At March 31, 2019 and no outstanding principal balance as of December 31, 2016. The2018, the Company has an outstanding letterhad no letters of credit of approximately $0.5 million.issued. The average annual interest rate for borrowings during the three months ended March 31, 2019 was 4.5%.

In September 2017,April 2019, the lenders under the Revolver completed their regular semi-annual redetermination of our borrowing base. The borrowing base was increased from $225$650 million to $400$700 million, and we increased our aggregate elected commitment from $500 million to $550 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.

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

The RevolverRestated Credit Agreement 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 requirespositions, and require the Company to maintain compliance with certain financial and liquidity ratio covenants. In particular, the Company must not (a) permit its ratioAs 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 than1.0to 1.0. As ofSeptember 30, 2017,March 31, 2019, the most recent compliance date, the CompanyCompany was in compliance with these loan covenants and expects to remain in compliance throughout the next 12-month period.

7.6.Notes Payable

2025 Senior Notes

In June 2016,November 2017, the Company issued $80$550 million aggregate principal amount of 9%6.25% Senior Notes ("due 2025 (the "2025 Senior Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is June 13, 2021.December 1, 2025. Interest on the 2025 Senior Notes accrues at 9% and began accruing on June 14, 2016.6.25%. Interest is payable on June 151 and December 151 of each year. The 2025 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. November 29, 2017. The associated expenses and underwriting discounts and commissions are amortized using the effective 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. 6.6%.

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 restrictedcertain of its subsidiaries to, among other things: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. The indenture governing the 2025 Senior Notes provides that, in certain circumstances, the notes will be guaranteed by one or more subsidiaries of the Company, in which case such guarantee would be made on a full and unconditional and joint and several senior unsecured basis. As of March 31, 2019, none of the Company's subsidiaries met the criteria outlined within the Indenture to be considered a guarantors of the 2025 Senior Notes.

AsAs of September 30, 2017,March 31, 2019, 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.

8.7.Commodity Derivative Instruments

The Company has entered into commodity derivative instruments as described below. Our commodity derivative instruments may include but are not limited to "collars," "swaps," and "put" positions. Our derivative strategy, including the 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.


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.


The Company’s commodity derivative contracts as of September 30, 2017March 31, 2019 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
Settlement Period 
Derivative
Instrument
 
Volumes
(Bbls per day)
 
Weighted-Average
Floor Price
 Weighted-Average Ceiling Price
Crude Oil - NYMEX WTI        
Apr 1, 2019 - Dec 31, 2019 Collar 11,000
 $55.00
 $70.08
         
Settlement Period 
Derivative
Instrument
 
Volumes
(MMBtu per day)
 Weighted-Average
Floor Price		 Weighted-Average Ceiling Price
Natural Gas - NYMEX Henry Hub        
Apr 1, 2019 - Dec 31, 2019 Collar 30,000
 $3.00
 $3.50
         
Settlement Period 
Derivative
Instrument
 
Volumes
(MMBtu per day)
 Fixed Basis Difference  
Natural Gas - CIG Rocky Mountain        
Apr 1, 2019 - Dec 31, 2019 Swap 30,000
 $(0.75)  
         
Settlement Period 
Derivative
Instrument
 Volumes
(Bbls per day)		 Weighted-Average Fixed Price  
Propane - Mont Belvieu        
Apr 1, 2019 - Dec 31, 2019 Swap 2,000
 $37.52
  


Subsequent to September 30, 2017,March 31, 2019, the Company added the following positions:
Settlement Period 
Derivative
Instrument
 Average Volumes
(Bbls
per month)		 
Floor
Price
 
Ceiling
Price
 
Derivative
Instrument
 Volumes
(Bbls per day)		 Weighted-Average
Floor Price		 Weighted-Average Ceiling Price
Crude Oil - NYMEX WTI                
Jan 1, 2018 - Dec 31, 2018 Collar 76,042
 $45.00
 $58.00
May 1, 2019 - Dec 31, 2019 Collar 5,000
 $55.00
 $71.90


Offsetting of Derivative Assets and Liabilities

As of September 30, 2017March 31, 2019 and December 31, 2016,2018, all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of either party, for transactions that occur on the same date and in the same currency. The Company’s agreements also provide that, in the event of an early termination, each party has the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to offset these positions in its condensed consolidated balance sheets.

The following table provides a reconciliation between the net assets and liabilities reflected on the accompanying condensed consolidated balance sheets and the potential effect of master netting arrangements on the fair value of the Company’s derivative contracts (in thousands):
 As of September 30, 2017 As of March 31, 2019
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
 
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) $—
 Current assets $13,051
 $(5,970) $7,081
Commodity derivative contracts Noncurrent assets $502
 $(502) $—
 Noncurrent assets —
 —
 —
Commodity derivative contracts Current liabilities $2,000
 $(1,214) $786
 Current liabilities 5,970
 (5,970) —
Commodity derivative contracts Noncurrent liabilities $896
 $(502) $394
 Noncurrent liabilities $—
 $—
 $—
 As of December 31, 2016 As of December 31, 2018
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
 
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
 Current assets $39,485
 $(4,579) $34,906
Commodity derivative contracts Noncurrent assets $—
 $—
 $—
 Noncurrent assets —
 —
 —
Commodity derivative contracts Current liabilities $4,622
 $(1,748) $2,874
 Current liabilities 4,579
 (4,579) —
Commodity derivative contracts Noncurrent liabilities $—
 $—
 $—
 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)
 Three Months Ended March 31,
 2019 2018
Realized gain (loss) on commodity derivatives$4,913
 $(2,072)
Unrealized loss on commodity derivatives(27,826) (3,709)
Total loss$(22,913) $(5,781)


Realized gains and losses include cash received fromrepresent the monthly settlement of derivative contracts at their scheduled maturity date, andnet of 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,Three Months Ended March 31,
2017 2016 2017 20162019 2018
Monthly settlement$376
 $497
 $927
 $4,398
$5,232
 $(2,072)
Previously incurred premiums attributable to settled commodity contracts(260) (510) (953) (1,530)
Premiums paid(319) —
Total realized gain (loss)$116
 $(13) $(26) $2,868
$4,913
 $(2,072)

Credit Related Contingent Features

As of September 30, 2017, threeMarch 31, 2019, five of the sixseven 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,sixth and seventh counterparties, which isare not a lenderlenders 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.

9.8.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,measurement includes asset retirement obligations, and purchase price allocations for the fair value of assets and liabilities acquired through business combinations and certain asset acquisitions. Please referobligations. Refer to Notes 2, 3, and 5Note 4 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.obligations.

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 abandonmentreclamation 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.reclamation. 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 5Note 4 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, 2017 and December 31, 2016 by level within the fair value hierarchy (in thousands):
Fair Value Measurements at September 30, 2017Fair Value Measurements at March 31, 2019
Level 1 Level 2 Level 3 TotalLevel 1 Level 2 Level 3 Total
Financial assets and liabilities:              
Commodity derivative asset$—
 $—
 $—
 $—
$—
 $7,081
 $—
 $7,081
Commodity derivative liability$—
 $1,180
 $—
 $1,180
$—
 $—
 $—
 $—

Fair Value Measurements at December 31, 2016Fair Value Measurements at December 31, 2018
Level 1 Level 2 Level 3 TotalLevel 1 Level 2 Level 3 Total
Financial assets and liabilities:              
Commodity derivative asset$—
 $297
 $—
 $297
$—
 $34,906
 $—
 $34,906
Commodity derivative liability$—
 $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,March 31, 2019, derivative instruments utilized by the Company consist of putsswaps and collars. The oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are valued 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 the credit facility borrowings, the carrying value is representative of its fair value.

The fair value of the Senior Notesnotes payable is estimated to be $84.8$491.0 million at September 30, 2017.March 31, 2019. The Company determined the fair value of its notes payable at September 30, 2017March 31, 2019 by using observable market basedmarket-based information for these debt instruments of similar amounts and duration.instruments. The Company has classified the notes payable as Level 2.1.

10.9.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
 $154
Notes payable1,800
 1,800
 5,400
 2,120
Amortization of issuance costs1,090
 467
 2,267
 1,076
Less, interest capitalized(3,906) (2,267) (8,953) (3,350)
Interest expense, net of amounts capitalized$—
 $—
 $—
 $—


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 - basic200,881,447
 200,515,555
 200,807,436
 164,771,544
Potentially dilutive common shares from:       
Stock options415,524
 —
 412,902
 —
Restricted stock units and stock bonus shares163,944
 —
 105,791
 —
Weighted-average shares outstanding - diluted201,460,915
 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 options4,726,500
 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 shares308,094
 1,003,879
 497,806
 1,003,879
Total5,986,478
 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.
 Three Months Ended March 31,
 2019 2018
Revolving credit facility$2,173
 $—
Notes payable8,594
 8,594
Amortization of issuance costs and other797
 887
Less: interest capitalized(11,564) (9,481)
Interest expense, net of amounts capitalized$—
 $—

12.10.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,March 31, 2019, there were 4,500,00010,500,000 common shares authorized for grant under the 2015 Equity Incentive Plan, of which 86,4641,097,165 shares were available for future grants.grant. The shares available for future grant exclude 951,8841,973,768 shares which have been reserved for future vesting of performance-vested stock units underin the assumptionevent that these awards metmeet the criterioncriteria 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,Three Months Ended March 31,
2017 2016 2017 20162019 2018
Stock options$1,277
 $1,274
 $3,825
 $4,107
$1,027
 $1,203
Performance-vested stock units807
 354
 2,130
 692
1,071
 856
Restricted stock units and stock bonus shares1,386
 1,023
 3,779
 3,341
2,315
 1,336
Total stock-based compensation$3,470
 $2,651
 $9,734
 $8,140
$4,413
 $3,395
Less: stock-based compensation capitalized(440) (278) (1,344) (856)(730) (599)
Total stock-based compensation expensed$3,030
 $2,373
 $8,390
 $7,284
Total stock-based compensation expense$3,683
 $2,796

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 shares350,000
 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 term6.4 years
Expected volatility55%
Risk free rate1.25 - 1.75%
Expected dividend yield—%

March 31, 2019 or 2018. The following table summarizes activity for stock options for the periodsperiod presented:
Number of Shares Weighted-Average Exercise Price Weighted-Average Remaining Contractual Life Aggregate Intrinsic Value (thousands)Number of Shares Weighted-Average Exercise Price Weighted-Average Remaining Contractual Life Aggregate Intrinsic Value (thousands)
Outstanding, December 31, 20166,001,500
 $9.27
 8.0 years $6,515
Outstanding, December 31, 20184,652,634
 $10.06
 6.4 years $49
Granted—
 —
  —
 —
  
Exercised(30,000) 3.79
 140
—
 —
 —
Expired(41,000) 11.98
  —
 —
  
Forfeited(104,000) 11.60
  —
 —
  
Outstanding, September 30, 20175,826,500
 $9.23
 7.2 years $8,076
Outstanding, Exercisable at September 30, 20173,146,361
 $8.77
 6.6 years $5,660
Outstanding, March 31, 20194,652,634
 $10.06
 6.2 years $63
Outstanding, Exercisable at March 31, 20193,414,834
 $10.21
 6.0 years $63

The following table summarizes information about issued and outstanding stock options as of September 30, 2017:March 31, 2019:
 Outstanding Options Exercisable Options 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 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 35,000
 $3.31
 3.3 years 35,000
 $3.31
 3.3 years
$5.00 - $6.99 1,012,000
 6.38
 7.2 years 549,000
 6.45
 6.0 years 723,800
 6.30
 6.2 years 428,600
 6.26
 5.5 years
$7.00 - $10.99 1,592,500
 9.34
 7.7 years 658,661
 9.50
 7.3 years 1,360,334
 9.42
 6.2 years 986,134
 9.42
 6.0 years
$11.00 - $13.46 2,622,000
 11.58
 7.7 years 1,364,700
 11.58
 7.6 years 2,533,500
 11.57
 6.2 years 1,965,100
 11.58
 6.1 years
Total 5,826,500
 $9.23
 7.2 years 3,146,361
 $8.77
 6.6 years 4,652,634
 $10.06
 6.2 years 3,414,834
 $10.21
 6.0 years

The estimated unrecognized compensation cost from stock options not vested as of September 30, 2017,March 31, 2019, which will be recognized ratably over the remaining vesting phase,period, is as follows:
Unrecognized compensation cost (in thousands)$11,101
Remaining vesting phase2.5 years
Unrecognized compensation (in thousands)$3,477
Remaining vesting period1.6 years


Restricted stock units and stock bonus awards

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

The following table summarizes activity for restricted stock units and stock bonus awards for the ninethree months ended September 30, 2017:March 31, 2019:
Number of Shares Weighted-Average Grant-Date Fair ValueNumber of Shares Weighted-Average Grant-Date Fair Value
Not vested, December 31, 2016890,336
 $9.54
Not vested, December 31, 20181,639,918
 $8.07
Granted669,323
 8.27
1,525,976
 4.87
Vested(336,445) 9.17
(499,330) 8.28
Forfeited(24,807) 9.85
(13,921) 6.67
Not vested, September 30, 20171,198,407
 $8.93
Not vested, March 31, 20192,652,643
 $6.19

The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of September 30, 2017,March 31, 2019, which will be recognized ratably over the remaining vesting phase,period, is as follows:
Unrecognized compensation cost (in thousands)$8,232
$14,012
Remaining vesting phase2.3 years
Remaining vesting period2.4 years

Performance-vested stock units

The Company grantshas granted three types of 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. TheFor the years prior to 2019, the PSUs will be settled in shares of the Company’s common stock followingstock. For PSUs granted in 2019, if the PSUs vested are in an amount equal to or less than the target amount, they will be settled in shares of the Company's common stock. If the PSUs vested are in an amount greater than the target amount, then at the discretion of of the Board of Directors, the value of the vested amount of PSUs in excess of the value of the PSU target amount may be paid wholly or partially in cash. All PSUs are settled at the end of the three-year performance cycle. Any PSUs that have not vested at the end of the applicable measurement period are forfeited.

Goal-Based PSUs - These PSUs are earned and vested after 2020 based on a discretionary assessment by the Compensation Committee. This assessment is anticipated to measure the performance of the Company and the executives over the defined vesting period. As vesting is based on the discretion of the Compensation Committee, we have not yet met the requirements of establishing an accounting grant date for them.  This will occur when the Compensation Committee determines and communicates the vesting percentage to the award recipients, which will then trigger the service inception date, the fair value of the awards, and the associated expense recognition period.  As of March 31, 2019, 274,898 Goal-Based PSUs had been awarded to certain executives.

Relative Total Shareholder Return ("Relative TSR") PSUs - The vesting criterion for the Relative TSR 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.

Absolute Total Shareholder Return ("Absolute TSR") PSUs - The vesting criterion for the Absolute TSR PSUs is based on a comparison of the Company’s TSR for the measurement period compared to the absolute TSR goals outlined in the award. 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 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.awards.


The assumptions used in valuing the TSR PSUs granted were as follows:
Nine Months Ended September 30,Three Months Ended March 31,
2017 20162019 2018
Weighted-average expected term2.9 years
 2.7 years
2.9 years
 2.8 years
Weighted-average expected volatility59% 58%48% 52%
Weighted-average risk-free rate1.34% 0.87%2.49% 2.41%

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,March 31, 2019, unrecognized compensation cost for TSR PSUs was $5.8$8.9 million and will be amortized through 2019. A summary of2021. The following table summarizes activity for TSR PSUs for the status and activity of PSUs is presented in the following table:three months ended March 31, 2019:
Number of Units1
 Weighted-Average Grant-Date Fair Value
Number of Units1
 Weighted-Average Grant-Date Fair Value
Not vested, December 31, 2016478,510
 $8.09
Not vested, December 31, 2018780,028
 $11.73
Granted473,374
 10.79
918,842
 5.74
Vested—
 —
—
 —
Forfeited—
 —
—
 —
Not vested, September 30, 2017951,884
 $9.44
Not vested, March 31, 20191,698,870
 $8.49
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.

13.11.Weighted-Average Shares Outstanding

The following table sets forth the Company's outstanding equity grants which have a dilutive effect on earnings per share:
 Three Months Ended March 31,
 2019 2018
Weighted-average shares outstanding — basic243,290,734
 241,751,915
Potentially dilutive common shares from:   
Stock options11,339
 347,391
TSR PSUs 1
615,516
 810,128
Restricted stock units and stock bonus shares173,927
 257,463
Weighted-average shares outstanding — diluted244,091,516
 243,166,897
1 The number of awards assumes that the associated vesting condition is met at the respective period end based on market prices as of the respective period end. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the vesting condition.

The following potentially dilutive securities outstanding for the periods presented were not included in the respective weighted-average shares outstanding-diluted calculation above:
 Three Months Ended March 31,
 2019 2018
Potentially dilutive common shares from:   
Stock options 1
4,617,634
 4,127,834
TSR PSUs 1,2
1,233,375
 —
Goal-Based PSUs 2,3
274,898
 281,872
Restricted stock units and stock bonus shares 1
784,662
 398,561
Total6,910,569
 4,808,267
1 Potential common shares excluded from the weighted-average shares outstanding-diluted calculation as the securities had an anti-dilutive effect on earnings per share.
2 The number of awards reflects the target amount of shares granted. 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.
3 Potential common shares excluded from the weighted-average shares outstanding-diluted calculation as the securities are considered contingently issuable, and the performance criteria are not considered met as of period end.

12.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 combined U.S. federal and state income tax ratesrate for the three and nine months ended September 30, 2017 and 2016 were nil.March 31, 2019 was 27%. For the three months ended March 31, 2018, the effective tax rate was 8%. 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 differsMarch 31, 2019 differed from the statutory rate primarily due to state income taxes, non-deductible expenses, and tax deficiencies recognized with the recognitionvesting of astock awards. The 2018 differed from the statutory rates due primarily to the release of valuation allowanceallowances previously 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,March 31, 2019, we had no liability for unrecognized tax benefits. The Company believes that there are no new items noror 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.March 31, 2019.  The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of September 30, 2017,March 31, 2019, 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 uponAs of March 31, 2019, the Company believes it will be able to generate sufficient future positive income within the carryforward periods and, accordingly, believes that it is more likely than not that its net deferred income tax assets will be fully realized. In addition to the future positive net income, the temporary deferred tax liabilities exceed the deferred tax assets resulting in the ability to utilize all deferred tax assets to offset future taxable income resulting from the reversal of the deferred tax liabilities.

13.    Revenue from Contracts with Customers

Sales of oil, natural gas, and NGLs are recognized at the point control of the product is transferred to the customer and collectability is reasonably assured. All of our cumulative losses through September 30, 2017, wecontracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies.
 Three Months Ended March 31,
Revenues (in thousands):2019 2018
Oil$147,080
 $116,204
Natural Gas and NGLs42,375
 31,029
 $189,455
 $147,233

14.    Leases

The Company evaluates contractual arrangements at inception to determine if individual agreements are a lease or contain an identifiable lease component as defined by ASC 842. When evaluating contracts to determine appropriate classification and recognition under ASC 842, significant judgment may be necessary to determine, among other criteria, if an embedded leasing arrangement exists, the length of the term, classification as either an operating or financing lease, whether renewal or termination options are reasonably certain to be exercised, and future lease payments to be included in the initial measurement of the ROU asset. Certain assumptions and judgments made by the Company when evaluating contracts that meet the definition of a lease under ASC 842 include:

Discount Rate - Unless implicitly defined, the Company will determine the present value of future lease payments using an estimated incremental secured borrowing rate based on a yield curve analysis that factors in certain assumptions, including the term of the lease and credit rating of the Company at lease commencement.
Lease Term - The Company evaluates each contract containing a lease arrangement at inception to determine the length of the lease term when recognizing a ROU asset and corresponding lease liability. When determining the lease term,

options available to extend or early terminate the arrangement are evaluated and included when it is reasonably certain these options will be exercised. There are no available options to extend that the Company is reasonably certain to exercise.

Currently, the Company has operating leases for asset classes that include office space, drilling rigs, and equipment rentals primarily used in development and field operations. The Company has financing leases for vehicles. We have provided a full valuation allowance reducingresidual value guarantee for our vehicle leases. Certain leases also contain optional extension periods that allow for lease terms to be extended for up to an additional 5 years.

Costs associated with the net realizable benefits.Company’s operating leases are either expensed or capitalized depending on how the underlying asset is utilized. For example, costs associated with drilling rigs are capitalized as part of the development of the Company’s oil and gas properties. Refer to the Company’s 2018 Form 10-K for additional information on its accounting policies for oil and gas development and producing activities. When calculating the Company’s ROU asset and liability, the Company considers all the necessary payments made or that are expected to be made upon commencement of the lease. Excluded from the initial measurement are certain variable lease payments.

The Company’s total lease cost were as follows (in thousands):
 Three Months Ended March 31, 2019
Finance lease cost: 
Amortization of ROU assets$60
Interest on lease liabilities8
  
Operating lease cost604
Short-term lease cost 1
42,063
Total Lease Cost$42,735
1 Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. These costs primarily include drilling activities and field equipment rentals. It is expected this amount will fluctuate primarily with the number of drilling rigs that the Company is operating under short-term agreements.

Other information related to the Company’s leases is as follows (in thousands, except lease terms and discount rates):
 Three Months Ended March 31, 2019
Cash paid for amounts included in the measurement of lease liabilities 
       Operating cash flows from operating leases$604
       Financing cash flows from finance leases58
  
ROU assets obtained in exchange for new finance lease liabilities95
ROU assets obtained in exchange for new operating lease liabilities4,532
As of
March 31, 2019
Weighted-average remaining lease term - finance leases3.2 years
Weighted-average remaining lease term - operating leases2.4 years
Weighted-average discount rate - finance leases4.75%
Weighted-average discount rate - operating leases4.75%


As of March 31, 2019, and through the filing of this report, the Company has no material lease arrangements which are scheduled to commence in the future. Maturities for the Company’s operating and finance lease liabilities included on the accompanying condensed balance sheets as of March 31, 2019 were as follows (in thousands):
Year Finance Leases Operating Leases
2019 $135
 $2,110
2020 180
 2,588
2021 208
 990
2022 178
 500
2023 16
 —
Thereafter —
 —
Total lease payments $717
 $6,188
Less imputed interest (61) (339)
Total lease liability $656
 $5,849

As of December 31, 2018, minimum future contractual payments were as follows (in thousands):
Year Rig Contracts Capital Leases Operating Leases
2019 $11,102
 $183
 $896
2020 —
 186
 916
2021 —
 204
 913
2022 —
 167
 500
2023 —
 —
 —
Thereafter —
 —
 —

Amounts recorded on the Company’s accompanying condensed balance sheets were as follows (in thousands):
As of March 31, 2019 Financing Leases Operating Leases
Other property and equipment, net $775
 $—
Other assets —
 4,108
     
Accounts payable and accrued expenses 153
 2,605
Other liabilities 503
 3,244
  $656
 $5,849

14.15.Other Commitments and Contingencies

VolumeOil 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.four counterparties. 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.have commenced. 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
Year ending December 31, 2019 Oil
 (MBbls)
Remainder of 2019 3,893
2020 4,003
2021 1,672
Total 9,568


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 thirdfirst quarter of 2017,2019, 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, althoughobligations. However, this cannot be guaranteed.

Natural Gas Commitments

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 newthe 200 MMcf per day processing plant ("Mewbourn 3") as well as the expansion of a related gathering system. Both are currently expected to be completed by lateStarting in August 2018, although the start-up date is undetermined at this time.Mewbourn 3 was complete and in service. Our share of the commitment will requirerequires 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 newan additional 200 MMcf per day processing plant ("O'Connor 2") as well as an incremental 100 MMcf per day of bypass and the expansion of a related gathering system. Both are currentlyConstruction of the plant is underway, and it is expected to be completedplaced into service late in 2019, although the start-up date is undetermined at this time.second quarter of 2019. Our share of the commitment will require an additional 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 thatIf we are unable to fulfill all of our development plan will supportcontractual obligations and our obligations are not sufficiently reduced by the utilizationcollective volumes delivered by other producers, we may be required to pay penalties or damages pursuant to these agreements. Our share of this capacity.

Office leases

In September 2016, the Company entered intocommitment does not guarantee us a new 65-month leasecorresponding capacity for the Company’s principal office space located in Denver, which commenced infuture deliveries to system. During 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 payments2019, we were able to meet all 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


Rent expense for offices leases was $0.2 million for the three months ended September 30, 2017our delivery obligations, 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.we anticipate that our current gross operated production will continue to meet our future delivery obligations. However, this cannot be guaranteed.

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 contentionproceedings are reasonably likely to have a material adverse impact on ourthe Company's business, financial position, results of operations, or cash flows.

15.16.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,Three Months Ended March 31,
Supplemental cash flow information:2017 20162019 2018
Interest paid$4,796
 $159
$2,136
 $69
Income taxes paid—
 106
      
Non-cash investing and financing activities:      
Accrued well costs as of period end$122,387
 $32,299
$89,489
 $66,823
Asset retirement obligations incurred with development activities2,782
 366
747
 223
Asset retirement obligations assumed with acquisitions23,521
 2,046
—
 5
Obligations discharged with asset retirements and divestitures(7,023) (3,997)$(3,809) $(2,860)
   
Net changes in operating assets and liabilities:   
Accounts receivable$2,547
 $(8,227)
Accounts payable and accrued expenses(843) 4,420
Revenue payable(5,020) 13,060
Production taxes payable6,319
 5,295
Other130
 (116)
Changes in operating assets and liabilities$3,133
 $14,432


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, 2017March 31, 2019 and its results of operations for the three and nine months ended September 30, 2017March 31, 2019 and 2016.2018.  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, 20162018 filed with the SEC on February 23, 2017.20, 2019. 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 and referenced 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 producedOur 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, All of our activities and planned drilling locations are located in Weld County, Colorado, and we are focused on the horizontal development of the Codell andformation as well as the three benches of the Niobrara formations,formation, which are all 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%91% of our proved producingdeveloped reserves and anticipate operating substantially alla majority 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, cash flow, future growth, and cash flow.carrying value of our oil and gas properties.  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 fiscalfour years.
Year Ended December 31, Year Ended August 31,Year Ended December 31,
2016 2015 2015 2014 20132018 2017 2016 2015
Average NYMEX prices                
Oil (per Bbl)$43.20
 $48.73
 $60.65
 $100.39
 $94.58
$64.94
 $50.93
 $43.20
 $48.73
Natural gas (per Mcf)$2.52
 $2.58
 $3.12
 $4.38
 $3.55
$3.09
 $3.00
 $2.52
 $2.58


For the periods presented in this report, the following table presents the Reference Price (derived from average NYMEX prices)prices as well as the differential between the Reference PriceNYMEX prices 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
 $41.23
Realized Price42.37
 35.67
 42.04
 31.47
Differential$(5.81) $(9.23) $(7.40) $(9.76)
        
Gas (NYMEX Henry Hub)       
Average NYMEX Price$2.99
 $2.88
 $3.03
 $2.34
Realized Price2.35
 2.73
 2.39
 2.18
Differential$(0.64) $(0.15) $(0.64) $(0.16)
        
NGL Realized Price$17.32
 $—
 $15.49
 $—
 Three Months Ended March 31,
 2019 2018
Oil (NYMEX-WTI)   
Average NYMEX Price$54.83
 $62.89
Realized Price *48.33
 56.01
Differential *$(6.50) $(6.88)
    
Natural Gas (NYMEX-Henry Hub)   
Average NYMEX Price$3.15
 $3.00
Realized Price *2.52
 2.14
Differential *$(0.63) $(0.86)
    
NGL Realized Price$12.59
 $19.15
* Adjusted to include the effect of transportation and gathering expenses.

Market conditions in the Wattenberg Field can 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 toTo 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,extent the Company's oil production exceeded its firm sales commitments andduring the three months ended March 31, 2019, the surplus oil production was sold at a reduced differential as compared to our committed volumes. Relating to the sale of

Our natural gas priorsales tend to January 1, 2017, the price we received included paymenttrend closely with Colorado Interstate Gas – Rocky Mountains as published in Inside FERC’s Gas Market Report, published by Platts ("CIG"). Average CIG prices 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 premium2019 decreased to dry natural gas prices that the Company historically realized on its wet natural gas sales volumes.

There has been significant volatility$2.95 from $3.06 in the pricefourth quarter of oil and natural gas since mid-2014.  During2018, resulting in the nine months ended September 30, 2017, the NYMEX-WTI oil price ranged from a high of $54.48 per Bbl on February 23, 2017basis difference for CIG to a low of $42.48 per Bbl on June 21, 2017, and the NYMEX-Henry Hub natural gas price rangeddecreasing from a low of $2.56 per MMBtu on February 21, 2017$0.58 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.$0.20.

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,March 31, 2019, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary.   However, if pricing conditions decline, we may incur a full cost ceiling impairment related to our oil and gas properties in future quarters.


Core Operations

The following table provides details about our ownership interests with respect to vertical and horizontal producing wells as of September 30, 2017:March 31, 2019:
Vertical Wells
Operated WellsOperated Wells Non-Operated Wells TotalsOperated Wells Non-Operated Wells Totals
GrossGross Net Gross Net Gross NetGross Net Gross Net Gross Net
482
 456
 135
 32
 617
 488
581
 562
 195
 55
 776
 617
Horizontal Wells
Operated WellsOperated Wells Non-Operated Wells TotalsOperated Wells Non-Operated Wells Totals
GrossGross Net Gross Net Gross NetGross Net Gross Net Gross Net
208
 194
 191
 33
 399
 227
425
 402
 387
 59
 812
 461

In addition to the producing wells summarized in the preceding table, as of September 30, 2017,March 31, 2019, we were the operator of 4666 gross (36(56 net) horizontal wells in progress, which excludes 19 gross (14 net) wells for which we have only set surface casings.progress. As of September 30, 2017,March 31, 2019, we are participating in 10717 gross (22(2 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 pluggingthe remediation and abandoningreclamation

of the vast majority of the operated vertical wellbores. During the ninethree months ended September 30, 2017,March 31, 2019, we plugged 86reclaimed 34 wells and returned the associated acreage to the property owners.

On May 2, 2017,
Drilling and Completion Operations

Our drilling and completion schedule drives our production forecast and our expected future cash flows. We believe that at current drilling and completion cost levels and with currently prevailing commodity prices, we can achieve attractive well-level rates of return. Should commodity prices weaken or our costs escalate significantly, our operational flexibility will allow us to adjust our drilling and completion schedule, if prudent. If the Colorado Oilwell-level internal rate of return is at or below our weighted-average cost of capital, we may choose to delay completions and/or forego drilling altogether. Conversely, if commodity prices move higher and Gas Conservation Commission issued a Noticeoperating conditions are favorable, we may choose to Operators (NTO) to verifyaccelerate drilling and completion activities, assuming adequate gas processing capacity is available at the location of all flowlines associated withtime.

During the three months ended March 31, 2019, we drilled 28 operated horizontal wells and turned 33 operated horizontal wells to sales. As of March 31, 2019, the integrityCompany had 18 gross (16 net) wells that were drilled and completed, but not producing. These wells are expected to be turned to sales during the second quarter. As of those flowlines. The Company has completed all field work associatedMarch 31, 2019, we are the operator of 66 gross (56 net) horizontal wells in progress. All of this activity was funded through cash flows from operations. For 2019 as a whole, we expect to drill 99 gross (90 net) operated horizontal wells and complete approximately 68 gross (62 net) operated horizontal wells with mid-length and long laterals targeting the NTOCodell and filedNiobrara formations.

For the required paperwork regarding its operations aheadthree months ended March 31, 2019, we participated in the completion of the June 30, 2017 deadline.7gross (0.1net) non-operated horizontal wells. As ofMarch 31, 2019, we are participating in17gross (2net) non-operated horizontal wells in progress.

Production

For the three months ended September 30, 2017,March 31, 2019, our average daily production increased to 40,37865,771 BOED as compared to 10,79445,397 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.March 31, 2018. As of September 30, 2017, approximatelMarch 31, 2019, over 98% oyf99%ofour daily production was from horizontal wells.

As of March 31, 2019, we had 137 wells shut-in, due primarily to the lack of capacity to process gas. Throughout 2018, we continued to drill and complete wells in an attempt to maintain oil volumes and to limit the potential impact of Proposition 112, a ballot measure voted on in November 2018 that, if it had passed, would have severely limited our future drilling locations. In light of our 2018 activity levels and the voting down of Proposition 112, we planned our 2019 budgeted activity to adjust the cadence of both drilling and completion operations and reduced our year-over-year capital expenditures budget by approximately 35% in order to optimize capital efficiency. The aggregate volumes that were being produced at the time that these wells were shut-in was approximately 20,000 BOED with an approximate 40% oil cut.

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 plannedproved undeveloped acreage development isare located either in or adjacent to the Wattenberg Field.Field, and we seek to acquire developed and undeveloped oil and gas properties in the same contiguous area. Focusing our operations in this area leverages our management, technical, and operational experience in the basin.

Maximize shareholder value and maintain financial flexibility by limiting the need for external capital.  We seek to align our capital expenditures with our cash flows by adjusting our operating activities depending on commodity prices and infrastructure capacity. We strive to be a cost-efficient operator and to maintain a relatively low utilization of debt, which allows sufficient financial capacity to pursue strategic acquisitions.

Develop and exploit existing oil and gas properties.  OurA 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 safest and most efficient and economical 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.

Use the latest technology to maximize returns and improve hydrocarbon recovery.  Our development objective for individual well optimization is to primarily drill and complete wells with lateral lengths of 7,000' to 10,000'. Utilizing petrophysical and seismic data, a 3-D model is developed for each leasehold section to assist in determining optimal wellbore placement, well spacing, and stimulation design. This process is augmented with formation-specific drilling and completion execution designs, coupled with production results, to implement a continuous improvement philosophy in optimizing the value per acre of our leasehold throughout our development program.

Improve hydrocarbon recovery through increased well density.Control and reduce emissions from our production facilities. We utilize what we believeplace high importance on achieving compliance with all applicable air quality rules and regulations and further reducing emissions continues to be industrya top priority. To minimize emissions, we employ best management practices insuch as using available direct pipeline take-away access and pneumatic actuated instrument devices and by working with suppliers to deploy diesel engines that meet the U.S. Environmental Protection Agency Tier 4 standard. We control emissions and minimize flaring of gas during the drilling and completion process. We use additional vapor recovery equipment during production for further emissions reduction. We continue to evolve the design of our effortproduction facilities to determine the optimal recovery areaproduce oil and natural gas with fewer air emissions, including those emissions for each well. Early horizontal well development in the Wattenberg Field generally assumed optimal recoveries would be obtained utilizing between 12which there are public health standards (e.g. ozone and 16 wells per 640-acre section. As horizontal well development has matured, well density assumptions have generally increased beyond 16 wells perparticulate matter).

section depending
Operate in a safe manner and work in partnership with our surrounding stakeholders.  While our scale of operations has increased significantly, we continue to focus on the specific area of the field being drilled.
Complete selective acquisitions.  Wemaintaining a safe workplace for our employees and contractors. Further, as technology for resource development has advanced, we seek to acquire developedutilize best industry practices to meet or exceed regulatory requirements while reducing our impacts on neighboring communities. Such practices include building our infrastructure out ahead of operations to minimize traffic, working with our service providers to minimize dust and undeveloped oillighting issues, and gas properties, primarilyconstructing sound walls to minimize noise.  We value our positive relationship with local governing entities and the communities in the Wattenberg Field.  We generallywhich we operate and 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.to continually achieve a status of operator of choice.

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, including midstream availability, 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 andthat provide short return on investment cycle times, is central to our operating strategy.

Use the latest technologyAcquire and develop assets near established infrastructure. We target acquisitions of contiguous acreage to maximize returns.  Our development objective for individual well optimization is to drill and complete wells with lateral lengths of 7,000' to 10,000'. Utilizing petrophysical and seismic data, a 3-D model is developed for each leasehold section to assist in determining optimal wellbore placement, well spacing, and stimulation design. This process is augmented with formation-specific drilling and completion execution designs and coupled with localized production results to implement a continuous improvement philosophy in optimizing the value per acre of our leasehold throughoutfocus our development program.plans on areas where technically-capable, financially-stable midstream companies have existing assets and plans for additional investment. We work collaboratively with these companies to proactively identify expansion opportunities that complement our development plans. This enables the use of gathering pipelines, which reduces the need to use trucks and thereby reduces traffic and noise.

Significant Developments

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

Acquisitions

In September, we completedThe Colorado General Assembly passed SB19-181, titled "Protect Public Welfare Oil And Gas Operations" in April 2019. Among other things, SB19-181 provides that local governments have land use authority to regulate the second closingsiting of the GC Acquisition. 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. The purchase and sale agreement for the GC Acquisition was signed in May 2016, and the first closing was completed in June 2016. 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. 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.


In August 2017, we executed a purchase and sale agreement with a private party for the acquisition of 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 March 2017, we acquired developed and undeveloped oil and gas leasehold interests for a total purchase price of $25.0 million, composed of cash and assumed liabilities.

Divestitures

In October 2017, we executed a purchase and sale agreement with a private party resultinglocations, states that it is in the divestiturepublic interest to regulate the development of approximately 1,100 net acresoil and 22 gross (4 net) non-operated wellsgas resources in progress for $11.6 million. The transaction is expecteda manner that protects public health, safety, and welfare, including protection of the environment and wildlife resources, and modifies the requirements related to close instatutory pooling. There will be significant rule making associated with this legislation that will affect the fourth quarterimplementation and effect of 2017. Additionally,the law. SB19-181 could have a variety of effects on our operations, but we completed an additional divestiture to a separate private partybelieve that some of 37 operated vertical wells for total consideration of approximately $0.7 million in cash and the assumptionthese impacts may be mitigated by the buyersfact that the statute places a significant emphasis on local control of $2.3 millionoil and gas regulatory matters, and all of our planned future development activities are in liabilities.

During the nine months ended September 30, 2017, we completed divestitures of approximately 10,700 net undeveloped acres, along with associated production, outsideWeld County, a jurisdiction in which there is a strong support of the Company's core development area for approximately $75.1 million in cashoil and the assumption by the buyers of $1.7 million in asset retirement obligations and $0.6 million in other liabilities.
gas industry.

Revolving Credit Facility

In September 2017,April 2019, the lenders under our revolving credit facility (sometimes referred to as the "Revolver")Revolver completed their regular semi-annual redetermination of our borrowing base. The borrowing base was increased from $225$650 million to $400$700 million, and we increased our aggregate elected commitment from $500 million to $550 million. The next semi-annual redetermination is scheduled for April 2018. Due to the outstanding principal balance and letters of credit, approximately $249.5 million of the borrowing base was available to use for future borrowings as of September 30, 2017, subject to our covenant requirements.

Drilling and Completion Operations

Our drilling and completion schedule drives our production forecast and our expected future cash flows. We believe that at current drilling and completion cost levels and with currently prevailing commodity prices, we can achieve reasonable well-level rates of return. Should commodity prices weaken further or our costs escalate significantly, our operational flexibility will allow us to adjust our drilling and completion schedule, if prudent. If the well-level internal rate of return is at or below our weighted-average cost of capital, we may choose to delay completions and/or forego drilling altogether. Conversely, if commodity prices move higher, we may choose to accelerate drilling and completion activities.

During the nine months ended September 30, 2017, we drilled 87 operated horizontal wells and completed 87 operated horizontal wells. As ofSeptember 30, 2017, we are the operator of 46 gross (36 net) horizontal wells in progress, which excludes19gross (14net) horizontal wells for which we have only set surface casings. For 2017 as a whole, we expect to drill 118 gross operated horizontal wells, primarily mid-length and long laterals targeting the Codell and Niobrara formations.

For the nine months ended September 30, 2017, we participated in the completion of 16 gross (1 net) non-operated horizontal wells. As ofSeptember 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.

Trends and Outlook

OilNYMEX-WTI oil traded at $53.7545.15 per Bbl on December 30, 2016,28, 2018, but has since declinedincreased approximately 4%33% as of SeptemberMarch 29, 20172019 to $51.67. Natural60.19. NYMEX-Henry Hub natural gas traded at $3.723.25 per Mcf on December 30, 2016,28, 2018, but declined approximately 19%16% as of SeptemberMarch 29, 20172019 to $3.01. Lower$2.73. Although NYMEX-WTI oil prices have increased over the first quarter in 2019, they continue to be volatile and are out of our control. If oil prices decrease, this could (i) reduce our cash flow which could, in turn, could reduce the funds available for exploringthe exploration and replacingreplacement of oil and natural gas reserves, (ii) reduce our Revolver borrowing base capacity and increase the difficulty of obtaining equity and debt financing and worsen the terms on which such financing may be obtained, (iii) reduce the number of oil and gas prospects which have reasonable economic returns, (iv) may cause us to allow leases to expire based upon the value of potential oil and natural gas reserves in relation to the costs of exploration, (v) may result in marginally productive oil and natural gas wells being abandonedshut-in as non-commercial, and (vi) may cause ceiling test impairments.

Other factors that will most significantly affect our results of operations include (i) activitiesWe continually focus on properties that we operate, (ii) the marketability of our production, (iii) our ability to satisfy our financial and volume commitment obligations, (iv) completion of acquisitions of additional properties and reserves, and (v) competition from other oil and gas companies.

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

We have been able to reducemanaging drilling and completion costs due tothrough a combination of optimizing well designs, lower contract rates for drilling rigs, fewerdesign optimization, reductions in the average days to drill, and lower completion costs.employment of current technological advancements. This focus on cost reduction has supportedmanagement helps support well-level economics giving consideration to the current prices ofunder varying oil and natural gas. We continue to strive to reduce drilling and completion costs going forward, but as commodity prices improve and industry activity increases, we may experience higher service costs, causing well-level rates of return to be lower.gas pricing environments.

From time to time, our production has been adversely impacted by high natural gas gathering line pressures. Where it is cost effective, we install wellhead compression to enhance our ability to inject natural gas into the gathering system and, in some instances, install larger gathering lines to help mitigate the impact of high line pressures. Additionally,Multiple midstream companies that operate the natural gas processing facilities and gathering pipelines in the areaWattenberg Field continue to make significant capital investments to increase the capacity of their systems. WhileUntil such time that these actions have helped to increase capacity for natural gas processing, wefacilities are operational, our production has been, and most likely will continue to experience line pressures exceeding system limits primarily due to further growth in field-wide production volumes.be, adversely impacted by a lack of available processing capacity.

To address the growing volumes of natural gas production in the D-J Basin, DCP Midstream has announced plans forbeen developing multiple projects including new processing plants, an expansion of its low and high pressure gathering systems, additional compression, and plant bypass infrastructure. Most notably, in collaboration with DCP Midstream, we and several other producers have agreed to participate insupport the expansion of natural gas gathering and processing capacity in the D-J Basin.  The initial plan includes a newthrough agreements that impose baseline and incremental volume commitments, which we are currently exceeding.  Current plans are to add another 200 MMcf per day processing plant ("O'Connor 2") as well as the expansionan incremental 100 MMcf per day of a related gathering system, bothbypass. The O'Connor plant is expected to be completedin service in the second quarter followed by late 2018. Additionally, through the same framework, allbypass later in the year. In addition, DCP Midstream has announced that it has secured the land and permits for the development of a third facility ("Bighorn"), which could have processing capacity of up to 1 Bcf per day, including bypass, and is expected to be placed into service in phases with the initial in-service date in mid-2020.

As a result of the parties agreed tocurrent lack of gas processing capacity, a development plan to add another 200 MMcf/d plantsystem-wide volume allocation limiting each producer’s throughput was implemented in 2019. These agreements impose a baselineNovember 2017 and incremental volume commitment which we are currently exceeding.has not since been lifted.

We have extended the use of oil and water gathering lines to certain production locations. These gathering systems are owned and operated by independent third parties, and we commit specific leases or areas to these systems. We believe that oilthese gathering lines have several benefits, including a) reduced need to use trucks, to gather our oil, thereby reducing truck traffic and noise in and around our production locations, b) potentially lower gathering costs as pipeline gathering tends to be more efficient, c) reduced on-site oil storage capacity, resulting in lower production location facility costs, and d) generally improved community relations. As these gathering lines continue to be expanded, we have experienced and may continue to experience some delays in placing our pads on production.

Oil transportation andpipeline takeaway capacity utilization has increased withas oil production in the basin has grown. However, the capacity will decrease in the second quarter of 2019 when a portion of a third-party crude oil pipeline system is converted to NGL service. To address the projected demand for additional capacity, several open seasons have been announced for the expansion of certain interstate pipelines servicing the Wattenberg Field. This has reversed the prior imbalance of oil production exceeding the combination of local refinery demand and the capacity of pipelines to move the oil to other markets. We continuously strive to reduce the negative differential that we have historically realized on our oil production depending on transportation commitments, local refinery demand, and our production volumes. Further details regarding posted prices and average realized prices are discussed in "-Market Conditions."

As of September 30, 2017, we have identified over 1,100 drilling locations across our acreage position. ForFor 2017,2019, we expect to drill 118 drill 99 gross operated horizontal wells (28 of which were drilled through March 31, 2019) with mostly mid-length and long laterals targeting the Codell and Niobrara zones. We anticipate thisthat total capital expenditures, including operated drilling and completion programcosts, limited leasehold acquisition costs and selected non-operated drilling and completion costs, will cost approximately $360be between $425 million and $450 million and will lead to a significantan increase in production and associated proved developed producing reserves while allowing us to retain significant operational and financial flexibility to reduce or accelerate activity in response to changing economic conditions. Additionally, 2017 drilling and completion expenditures associated with non-operated properties are expected to be approximately $60 million, whichreserves. Our current estimate is net of capital we expect to recover as described in "- Capital Expenditures" below. Full-year 2017that full-year 2019 production is forecasted to bewill average between 33,00063,000 BOED and 35,000 BOED. Assuming a 2018 development program similar66,000 BOED with oil making up 42% to what the Company has done in 2017, we expect to achieve year-over-year production growth45% of 25% or greater, while funding a majority of our expenditures through internally generated cash flow. production.

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


Results of Operations

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

For the three months ended September 30, 2017March 31, 2019 compared to the three months ended September 30, 2016March 31, 2018

For the three months ended September 30, 2017,March 31, 2019, we reported net income of $43.8$49.8 million compared to net lossincome of $19.2$65.8 million during the three months ended September 30, 2016.March 31, 2018. Net income per basic and diluted share was $0.22$0.20 for the three months ended September 30, 2017March 31, 2019 compared to net lossincome per basic and diluted share of $0.10$0.27 for the three months ended September 30, 2016. Net income per basic share for the three months ended September 30, 2017 increased by $0.32 primarily due to the ceiling test impairment of $25.5 million incurred during the three months ended September 30, 2016 (whereas no ceiling test impairment was recognized during the three months ended September 30, 2017) and the 295% increase in revenues period over period. Revenues increased during the three months ended September 30, 2017 compared with the three months ended September 30, 2016 due to a 274% increase in production and a 6% increase in realized prices. As of September 30, 2017, we had 1,016 gross producing wells, of which 399 were horizontal, compared with 635 gross producing wells, of which 245 were horizontal, as of September 30, 2016.

March 31, 2018.

Oil, Natural Gas, and NGL Production and Revenues - For the three months ended September 30, 2017,March 31, 2019, we recorded total oil, natural gas, and NGL revenues of $103.6$189.5 million compared to $26.2$147.2 million for the three months ended September 30, 2016,March 31, 2018, an increase of $77.4$42.2 million or 295%29%. The following table summarizes key production and revenue statistics:

Three Months Ended September 30, PercentageThree Months Ended March 31, Percentage
2017 2016 Change2019 2018 Change
Production:          
Oil (MBbls) 1
1,726
 517
 234 %2,967
 2,041
 45 %
Natural Gas (MMcf) 2
7,412
 2,855
 160 %11,391
 7,719
 48 %
NGLs (MBbls) 3
753
 —
 nm
MBOE 4
3,715
 993
 274 %
BOED 5
40,378
 10,794
 274 %
NGLs (MBbls) 1
1,054
 758
 39 %
MBOE 3
5,919
 4,086
 45 %
BOED 4
65,771
 45,397
 45 %
          
Revenues (in thousands):          
Oil$73,144
 $18,451
 296 %$147,080
 $116,204
 27 %
Natural Gas17,402
 7,783
 124 %29,104
 16,517
 76 %
NGLs 3
13,047
 —
 nm
NGLs13,271
 14,512
 (9)%
$103,593
 $26,234
 295 %$189,455
 $147,233
 29 %
Average sales price:          
Oil$42.37
 $35.67
 19 %
Natural Gas2.35
 2.73
 (14)%
NGLs 3
17.32
 —
 nm
BOE$27.89
 $26.42
 6 %
Oil 5
$48.33
 $56.01
 (14)%
Natural Gas 5
2.52
 2.14
 18 %
NGLs12.59
 19.15
 (34)%
BOE 5
$31.32
 $35.58
 (12)%
1"MBbl" "MBbl" refers to one thousand stock tank barrels, or 42,000 U.S. gallons liquid volume in reference to crude oil or other liquid hydrocarbons.
2 "MMcf" refers to one million cubic feet of natural gas.
3 For periods prior to January 1, 2017, we did not separately report sales volumes, prices, and revenues for NGLs as we did not take title to these NGLs. Instead, the value attributable to these unrecognized NGL volumes was included within natural gas revenues as an increase to the overall price received. This change impacts the comparability of the two periods presented.
4 "MBOE" refers to one thousand barrels of oil equivalent, which combines MBbls of oil and MMcf of natural gas by converting each six MMcf of natural gas to one MBbl of oil.
54 "BOED" refers to the average number of barrels of oil equivalent produced in a day for the period.
5 Adjusted to include the effect of transportation and gathering expenses.

Net oil, natural gas, and NGL production for the three months ended September 30, 2017March 31, 2019 averaged 40,37865,771 BOED, an increase of 274%45% over average production of 10,79445,397 BOED in the three months ended September 30, 2016.March 31, 2018. From September 30, 2016March 31, 2018 to September 30, 2017,March 31, 2019, our well count increased by 91181 net horizontal wells, growing our reserves and daily production totals. Additionally, our conversion to three stream accounting positively impacted reported production in the current period. The 274%45% increase in production andresulted in an increase in revenues which was partially offset by the 6% increase12% decrease in average sales prices resulted in a significant increase in revenues.prices.


Lease Operating Expenses ("LOE")LOE - Direct operating costs of producing oil and natural gas are reported as follows (in thousands):
Three Months Ended September 30,Three Months Ended March 31,
2017 20162019 2018
Production costs$4,223
 $3,529
$17,281
 $7,714
Workover93
 290
79
 182
Transportation and gathering838
 —
Total LOE$5,154
 $3,819
$17,360
 $7,896
      
Per BOE:      
Production costs$1.14
 $3.55
$2.92
 $1.89
Workover0.03
 0.29
0.01
 0.04
Transportation and gathering0.23
 —
Total LOE$1.40
 $3.84
$2.93
 $1.93

Lease operating and workover costs tend to increase or decrease primarily in relation to the number and type of wells and our overall production volumes and, to a lesser extent, on fluctuations in oil field service costs and changes in the production mix of oil and natural gas. During the three months ended September 30, 2017,March 31, 2019, we experienced increased production expense compared to the three months ended March 31, 2018 due to an 88% increase in net operated wells.

Transportation and gathering - Transportation and gathering was $4.1 million, or $0.68 per BOE, for the three months ended September 30, 2016March 31, 2019due, compared to a 113% increase$1.9 million, or $0.45 per BOE, for the three months ended March 31, 2018. Coinciding with the increasing production in horizontal operated wells2018, the Company has increased the volume of its production that is sold and a274%increase indelivered at the downstream interconnect. This has the effect of increasing both the net price received for the production volumes. In addition, in the third quarter, we began delivering under new gathering agreements which resulted inand transportation and gathering charges. Unit operatingcosts. While costs benefited from largerattributable to volumes sold at the interconnect of early productionthe pipeline are reported as an expense, the Company analyzes these charges on the horizontal wells turned to sales during the quarter in addition to the production from wells turned to sales after the third quarter of 2016.a net basis within revenue for comparability with wellhead sales.

Production taxes - Production taxes are comprised primarily of two elements: severance tax and ad valorem tax. During the three months ended September 30, 2017,March 31, 2019, the Company reduced its estimate for 2018 severance taxes. When preparing the 2018 severance tax return, we determined that the credit for ad valorem taxes would be greater than originally estimated, resulting in a reduction of 2018 severance taxes. Based on this analysis, the Company's prior year accrual was reduced, resulting in an approximate $7.9 million reduction to our production taxes. Production taxes were $10.1$7.1 million, or $2.71$1.20 per BOE, for the three months ended March 31, 2019, compared to $(1.5)$13.4 million, or $(1.47)$3.29 per BOE, during the prior year period. Taxes tend to increase or decrease primarily based on the value of production sold.three months ended March 31, 2018. As a percentage of revenues, production taxes were 9.7%3.7% and (5.6)%9.1% for the three months ended September 30, 2017March 31, 2019 and 2016, respectively. During2018, respectively, with the three months ended September 30, 2017,2019 period reflecting the production tax rate reflectseffect of the significant increasechange in new production and its impact on severance tax. As discussed in Note 1, during the three months ended September 30, 2016, the Company reduced its estimate for ad valorem taxes, resulting in an approximate $3.6 million reduction to our production taxes.estimate.

DD&A - The following table summarizes the components of DD&A:
Three Months Ended September 30,Three Months Ended March 31,
(in thousands)2017 20162019 2018
Depletion of oil and gas properties$32,944
 $9,273
$59,428
 $36,102
Depreciation and accretion796
 362
1,490
 979
Total DD&A$33,740
 $9,635
$60,918
 $37,081
      
DD&A expense per BOE$9.08
 $9.70
$10.29
 $9.08

For the three months ended September 30, 2017,March 31, 2019, DD&A was $9.08$10.29 per BOE compared to $9.70$9.08 per BOE for the three months ended September 30, 2016.March 31, 2018. The decreaseincrease in the DD&A rate was the result of a decrease in the ratio of total costs capitalized in the full cost pool to the estimated recoverable reserves. This ratio was significantly reduced due to the impairments of our full cost pool that primarily occurred during the first half of 2016 and the increase in our total proved reserves. These impacts were partially offset by recentrecent drilling and completion activities which increased the amortization base. Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, whereinwhereby the ratio of production volumes for the quarter to the beginning of the quarter estimated total reserves determines the depletion rate.

Full cost ceiling impairment - During the three months ended September 30, 2017, we had no impairment as compared to an impairment of $25.5 million for the three months ended September 30, 2016, representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling.


General and Administrative ("G&A") - The following table summarizes G&A expenses incurred and capitalized during the periods presented:
Three Months Ended September 30,Three Months Ended March 31,
(in thousands)2017 20162019 2018
G&A costs incurred$11,002
 $9,993
$13,163
 $12,741
Capitalized costs(2,518) (1,757)(3,694) (3,141)
Total G&A$8,484
 $8,236
$9,469
 $9,600
      
Non-Cash G&A$3,030
 $2,375
$3,683
 $2,796
Cash G&A5,454
 5,861
5,786
 6,804
Total G&A$8,484
 $8,236
$9,469
 $9,600
      
Non-Cash G&A per BOE$0.82
 $2.39
$0.62
 $0.68
Cash G&A per BOE1.47
 5.90
0.98
 1.67
G&A Expense per BOE$2.29
 $8.29
$1.60
 $2.35

G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. Total G&A costs of $8.5$9.5 million for the thirdfirst quarter of 20172019 were 3% higher1% lower than G&A for the same period of 2016. This increase is primarily due to a 32% increase in employee headcount from 89 at September 30, 2016 to 117 at September 30, 2017, which was offset by a reduction in professional fees incurred due to decreased deal activity and contract services during 2017.2018.

Our G&A expense for the three months ended September 30, 2017March 31, 2019 includes stock-based compensation of $3.0$3.7 million compared to $2.4$2.8 million for the three months ended September 30, 2016. Stock-based compensation is a non-cash charge that is based on the calculated fair value of stock options, performance-vested stock units, restricted share units, and stock bonus shares that we grant for compensatory purposes. For stock options, the fair value is estimated using the Black-Scholes-Merton option pricing model. For performance-vested stock units, the fair value is estimated using the Monte Carlo model. For restricted stock units and stock bonus shares, the fair value is estimated using the closing stock price on the grant date. Amounts are pro-rated over the vesting terms of the award agreements, which are generally three to five years.March 31, 2018.

Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the exploration and development of properties. Those costs are reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from the three months ended September 30, 2016March 31, 2018 to the three months ended September 30, 2017March 31, 2019 reflects our overall increase in G&A activity.increased headcount of individuals performing activities to maintain and acquire leases and develop our properties.

Commodity derivative gains (losses) - As more fully described in Item 1. Financial Statements – Note 8,7, Commodity Derivative Instruments, we use commodity contracts to help mitigate the risks inherent in the price volatility of oil and natural gas. For the three months ended September 30, 2017,March 31, 2019, we realized a cash settlement gain of $0.1 million, net of previously incurred premiums attributable to the settled commodity contracts. $4.9 million. For the prior comparable period, we realized a cash settlementlossof $13.0 thousand, net of previously incurred premiums attributable to the settled commodity contracts.$2.1 million.

In addition, for the three months ended September 30, 2017,March 31, 2019, we recorded an unrealized loss of $2.5$27.8 million to recognize the mark-to-market change in fair value of our commodity contracts. InBy comparison, in the three months ended September 30, 2016,March 31, 2018, we reported an unrealized gainloss of $0.4$3.7 million. Unrealized gains and losses are non-cash items.

Income taxes - We reported no income tax expense for the three months ended September 30, 2017 or the prior year period. During the three months ended September 30, 2017 and 2016, the effective tax rates were substantially reduced by recognition of a full valuation allowance on the net deferred tax assets. During the three months ended September 30, 2017 and 2016, the effective tax rate differed from the statutory rate primarily due to the recognition of the valuation allowance recorded against deferred tax assets.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. Based on the level of cumulative losses in the prior periods and the level of uncertainty with respect to future taxable income over the period in which the deferred tax assets are deductible, a valuation

allowance has been provided as of September 30, 2017. During the 2016 comparable period, we reached the same conclusion; therefore, a valuation allowance has been provided as of September 30, 2016.

For the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016

For the nine months ended September 30, 2017, we reported net income of $91.7 million compared to net loss of $224.5 million during the nine months ended September 30, 2016. Net income per basic and diluted share was $0.46 for the nine months ended September 30, 2017 compared to net loss per basic and diluted share of $1.36 for the nine months ended September 30, 2016. Net income per basic share for the nine months ended September 30, 2017 increased by $1.82 primarily due to the ceiling test impairment of $215.2 million incurred during the nine months ended September 30, 2016 (whereas no ceiling test impairment was recognized during the nine months ended September 30, 2017) and the 225% increase in revenues period over period. Revenues increased during the nine months ended September 30, 2017 compared with the nine months ended September 30, 2016 due to a 171% increase in production and a 20% increase in realized prices. As of September 30, 2017, we had 1,016 gross producing wells, of which 399 were horizontal, compared with 635 gross producing wells, of which 245 were horizontal, as of September 30, 2016.

Oil, Natural Gas, and NGL Production and Revenues - For the nine months ended September 30, 2017, we recorded total oil, natural gas, and NGL revenues of $222.4 million compared to $68.5 million for the nine months ended September 30, 2016, an increase of $154.0 million or 225%. The following table summarizes key production and revenue statistics:
 Nine Months Ended September 30, Percentage
 2017 2016 Change
Production:     
Oil (MBbls)3,668
 1,552
 136%
Natural Gas (MMcf)17,122
 8,991
 90%
NGLs (MBbls) 1
1,758
 —
 nm
MBOE8,280
 3,050
 171%
    BOED30,331
 11,133
 172%
      
Revenues (in thousands):     
Oil$154,232
 $48,838
 216%
Natural Gas40,945
 19,616
 109%
NGLs 1
27,242
 —
 nm
 $222,419
 $68,454
 225%
Average sales price:     
Oil$42.04
 $31.47
 34%
Natural Gas2.39
 2.18
 10%
NGLs 1
15.49
 —
 nm
BOE$26.86
 $22.44
 20%
1 For periods prior to January 1, 2017, we did not separately report sales volumes, prices, and revenues for NGLs as we did not take title to these NGLs. Instead, the value attributable to these unrecognized NGL volumes was included within natural gas revenues as an increase to the overall price received. This change impacts the comparability of the two periods presented.

Net oil, natural gas, and NGL production for the nine months ended September 30, 2017 averaged 30,331 BOED, an increase of 172% over average production of 11,133 BOED in the nine months ended September 30, 2016. From September 30, 2016 to September 30, 2017, our well count increased by 91 net horizontal wells, growing our reserves and daily production totals. Additionally, our conversion to three stream accounting positively impacted reported production in the current period. The 171% increase in production and the 20% increase in average sales prices resulted in a significant increase in revenues.


LOE - Direct operating costs of producing oil and natural gas are reported as follows (in thousands):
 Nine Months Ended September 30,
 2017 2016
Production costs$12,511
 $14,464
Workover$497
 $499
Transportation and gathering$886
 $—
Total LOE$13,894
 $14,963
    
Per BOE:   
Production costs$1.51
 $4.74
Workover0.06
 0.16
Transportation and gathering0.11
 —
Total LOE$1.68
 $4.90

Lease operating and workover costs tend to increase or decrease primarily in relation to the number and type of wells and our overall production volumes and, to a lesser extent, on fluctuations in oil field service costs and changes in the production mix of oil and natural gas.During thenine months ended September 30, 2017, we experienceddecreasedproduction expense compared to thenine months ended September 30, 2016primarily due to significantly less expense related to environmental remediation and regulatory compliance projects during 2017 and theconsolidation of our operations into a more central geographic operating area. This decrease was partially offset by transportation and gathering charges resulting from new gathering agreements. Unit operating costs benefited from larger volumes of early production on the 87 horizontal wells turned to sales during thenine months ended September 30, 2017in addition to the production on wells turned to sales after thethirdquarter of2016.

Production taxes - Production taxes are comprised primarily of two elements: severance tax and ad valorem tax. Production taxes were $21.0 million, or $2.54 per BOE, for the nine months ended September 30, 2017, compared to $2.5 million, or $0.82 per BOE, for the nine months ended September 30, 2016. Taxes tend to increase or decrease primarily based on the value of production sold. As a percentage of revenues, production taxes were 9.4% and 3.7% for the nine months ended September 30, 2017 and 2016, respectively. During the nine months ended September 30, 2017, the Company adjusted its estimates for production taxes to reflect a significant increase in new production. As discussed in Note 1, during the nine months ended September 30, 2016, the Company reduced its estimate for ad valorem taxes, resulting in an approximate $3.6 million reduction to our production taxes.

DD&A - The following table summarizes the components of DD&A:
 Nine Months Ended September 30,
(in thousands)2017 2016
Depletion of oil and gas properties$71,389
 $31,981
Depreciation and accretion2,007
 1,020
Total DD&A$73,396
 $33,001
    
DD&A expense per BOE$8.86
 $10.82

For the nine months ended September 30, 2017, DD&A was $8.86 per BOE compared to $10.82 per BOE for the nine months ended September 30, 2016. The decrease in the DD&A rate was the result of a decrease in the ratio of total costs capitalized in the full cost pool to the estimated recoverable reserves. This ratio was significantly reduced due to the impairments of our full cost pool that primarily occurred during the first half of 2016 and the increase in our total proved reserves. These impacts were partially offset by recent drilling and completion activities which increased the amortization base. Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning of quarter estimated total reserves determined the depletion rate.

Full cost ceiling impairment - During the nine months ended September 30, 2017, we had no impairment as compared to an impairment of $215.2 million for the nine months ended September 30, 2016, representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling.

G&A - The following table summarizes G&A expenses incurred and capitalized during the periods presented:
 Nine Months Ended September 30,
(in thousands)2017 2016
G&A costs incurred$32,018
 $27,944
Capitalized costs(7,729) (4,745)
Total G&A$24,289
 $23,199
    
Non-Cash G&A$8,390
 $7,285
Cash G&A15,899
 15,914
Total G&A$24,289
 $23,199
    
Non-Cash G&A per BOE$1.01
 $2.39
Cash G&A per BOE1.92
 5.22
G&A Expense per BOE$2.93
 $7.61

G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. Total G&A costs of $24.3 million for the third quarter of 2017 were 5% higher than G&A for the same period of 2016. This increase is primarily due to a 32% increase in employee headcount from 89 at September 30, 2016 to 117 at September 30, 2017, which was offset by a reduction in professional fees incurred due to decreased deal activity and contract services during 2017.

Our G&A expense for the nine months ended September 30, 2017 includes stock-based compensation of $8.4 million compared to $7.3 million for the nine months ended September 30, 2016.

Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the exploration and development of properties. Those costs are reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from the nine months ended September 30, 2016 to the nine months ended September 30, 2017 reflects our increased headcount of individuals performing activities to maintain and acquire leases and develop our properties.

Commodity derivatives - As more fully described in Item 1. Financial Statements – Note 8,12, Commodity Derivative Instruments,Income Taxes we use commodity contracts to help mitigate the risks inherent in the price volatility of oil and natural gas. For the nine months ended September 30, 2017, we realized a cash settlement loss of $26.0 thousand, net of previously incurred premiums attributable to the settled commodity contracts. For the prior comparable period, we realized a cash settlement gain of $2.9 million.

In addition, for the nine months ended September 30, 2017, we recorded an unrealized gain of $2.4 million to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the nine months ended September 30, 2016,, we reported an unrealized loss of $6.5 million. Unrealized gains and losses are non-cash items.

Income taxes - We reported no income tax expense of $18.0 million for the ninethree months ended September 30, 2017 orMarch 31, 2019 as compared to $5.8 million for the comparable prior year period. As explained in more detail inThe effective tax rate for the "-Income taxes" section above, during the ninethree months ended September 30, 2017 and 2016, the effective tax rates were substantially reduced by recognition of a full valuation allowance on the net deferred tax assets. During the nine months ended September 30, 2017 and 2016, the effective tax rateMarch 31, 2018 differed from the statutory raterates due primarily due to the recognitionrelease of the valuation allowanceallowances previously recorded against deferred tax assets.

Liquidity and Capital Resources

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

We believe that our current capital resources, including cash flows from operating activities, cash on hand, and amounts available under our revolving credit facility and cash flow from operating activities will be sufficient to fund our planned capital expenditures and operating expenses for the next

twelve months. During the three months ended March 31, 2019, our cash provided by operating activities exceeded our cash used in investing activities. To the extent actual operating results differ from our anticipated results, available borrowings under our credit facility are reduced, or we experience other unfavorable events, our liquidity could be adversely impacted.  Our

liquidity would also be affected if we increase our capital expenditures or complete one or more additional acquisitions. Terms of future financings may be unfavorable, and we cannot assure investors that funding will be available on acceptable terms.

As operator of the majority of our wells and undeveloped acreage, we control the timing and selection of new wells to be drilled. This allows us to modify our capital spending as our financial resources allow and market conditions, including midstream availability, support. Additionally, our relatively low utilization of debt enhances our financial flexibility as it provides a potential source of future liquidity while currently not overly burdening us with restrictive financial covenants and mandatory repayment schedules.

Sources and Uses

Our sources and uses of capital are heavily influenced by the prices that we receive for our production. During the nine months ended September 30, 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, while the NYMEX-Henry Hub naturalOil and 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. These markets will likely continue to be volatile in the future. To deal with the volatility in commodity prices, we maintain a flexible capital investment program and seek to maintain a high operating interest in our leaseholds with limited long-term capital commitments. This enables us to accelerate or decelerate our activities quickly in response to changing industry environments.

At September 30, 2017,March 31, 2019, we had cash and cash equivalents of $21.3$56.8 million, $80.0$550.0 million outstanding on our Senior 2025 Notes, and a $150.0$195.0 million balance outstanding balance under our revolving credit facility. Our sources and (uses) of funds for the ninethree months ended September 30, 2017March 31, 2019 and 20162018 are summarized below (in thousands):
Nine Months Ended September 30,Three Months Ended March 31,
2017 20162019 2018
Net cash provided by operations$142,817
 $33,193
$160,673
 $127,681
Capital expenditures(383,483) (582,149)(152,659) (105,633)
Net cash provided by other investing activities95,265
 5,979
124
 728
Net cash (used in) provided by equity financing activities(517) 542,901
Net cash provided by (used in) debt financing activities148,628
 (2,666)
Net increase (decrease) in cash and equivalents$2,710
 $(2,742)
Net cash provided by (used in) equity financing activities(876) 431
Net cash used in debt financing activities(58) (236)
Net increase in cash, cash equivalents, and restricted cash$7,204
 $22,971

Net cash provided by operating activities was $142.8$160.7 million and $33.2$127.7 million for the ninethree months ended September 30, 2017March 31, 2019 and 2016, respectively.2018, respectively. The increase in cash from operating activities reflects the increasegrowth in realized commodity prices andour production.

Net cash provided by other investing activities was $95.3 million and $6.0 million for the nine months ended September 30, 2017 and 2016, respectively. For the nine months ended September 30, 2017, we received proceeds from the sale of oil and gas properties and other of $77.0 million, and $18.2 million was released from an escrow account relating to an acquisition. For the nine months ended September 30, 2016, we received proceeds from the sale of oil and gas properties of $24.2 million; these inflows were offset by net cash deposited in escrow of $18.2 million.

During the nine months ended September 30, 2017, we received cash proceeds from borrowing $170.0 million under the Revolver and used cash proceeds from a divestiture to repay $20.0 million of these borrowings.

Credit Facility

The Revolver has a maturity date of December 15, 2019.  The agreement was most recently amended in September 2017.April 2, 2023.  The Revolver has a maximum loan commitment of $500 million;$1.5 billion; however, the maximum amount that we can borrowavailable to be borrowed at any one time is subject to a borrowing base limitation, which stipulates that we may borrow up to the lesserleast of the aggregate maximum loancredit amount, the aggregate elected commitment, or the borrowing base.  The borrowing base can increase or decrease based upon the value of the collateral which secures any amounts borrowed under the Revolver.  The value of the collateral will generally be derived with reference to the estimated discounted future net cash flows from our proved oil and natural gas reserves. The collateral includes substantially all of our producing wells and developed oil and gas leases.


As a result of the regular semi-annual redetermination of our borrowing base on September 27, 2017,In April 2019, the borrowing base was increased from $225650 million to $400700 million, and our elected commitment amount was increased to $550 million from $500 million. As ofSeptember 30, 2017, March 31, 2019, there was a$150.0 $195.0 millionoutstanding principal balance outstanding and $0.5 millionno in letters of credit outstanding, leaving $249.5305.0 million available to us for future borrowings. The next semi-annual redetermination is scheduled for April 2018.October 2019. Interest on the Revolver accrues at a variable rate. The interest rate pricing grid contains a graduatedprovides for an escalation in applicable margin forbased on increased utilization.

utilization of the Revolver. 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 endlast day of any fiscal quarter or (b) as of the last day of any fiscal quarter permit its ratio of current ratio,assets to current liabilities, each as defined in the agreement, to be less than 1.0 to 1.0.1.0as of the last day of any fiscal quarter.

2025 Senior Notes

On June 14, 2016,In November 2017, the Company issued $80$550 million aggregate principal amount of the6.25% Senior Notes due 2025 (the "2025 Senior Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is June 13, 2021.

December 1, 2025. Interest on the 2025 Senior Notes accrues at 9% and began accruing on June 14, 2016.6.25%. Interest is payable on June 151 and December 151 of each year.

The 2025 Senior Notes were issued pursuant to an indenture dated as of June 14, 2016November 29, 2017 (the "Indenture") and will beare guaranteed on a senior unsecured basis by anythe Company’s existing and future subsidiaries of the Company that incur or guarantee certain indebtedness, including indebtedness under the revolving credit facility. At any time prior to December 14, 2018, the Company may redeem all or a part of the Senior Notes 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 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.

Revolver. The Indenture contains covenants that restrict the Company’s ability and the ability of any restrictedcertain of its subsidiaries to, among other things: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.

Capital Expenditures

Capital expenditures for drilling and completion activities totaled $159.5$110.2 million and $383.0$111.0 million for the three and nine months ended September 30, 2017,March 31, 2019 and 2018, respectively. The following table summarizes our capital expenditures for oil and gas properties (in thousands):
 Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017
Capital expenditures for drilling and completion activities   
Operated$94,971
 $290,717
Non-operated64,561
 92,311
Total159,532
 383,028
    
Acquisitions of oil and gas properties and leasehold*56,835
 89,677
Capitalized interest, capitalized G&A, and other5,718
 17,514
Accrual basis capital expenditures**$222,085
 $490,219
 Three Months Ended March 31,
 2019 2018
Capital expenditures for drilling and completion activities$110,170
 $111,009
Acquisitions of oil and gas properties and leasehold1
(1,938) 9,284
Capitalized interest, capitalized G&A, and other16,676
 13,346
Accrual basis capital expenditures2
$124,908
 $133,639
*1 Acquisitions of oil and gas properties and leasehold reflects the full purchase price of our various acquisitions which includes non-cash additions for liabilities assumed in the transaction such as asset retirement obligations.
**2Capital expenditures reported in the condensed consolidated statement of cash flows are calculated on a cash basis, which differs from the accrual basis used to calculate the capital expenditures.

The year-to-date non-operated capital expenditures are driven by the Company's decision to participate in several wells located within our core operating area. The Company is actively conveying its interests in many of the underlying non-operated wells in progress through signed or anticipated agreements. If successful, the Company anticipates recovering approximately 50% of the year-to-date non-operated capital expenditures.

During the ninethree months ended September 30, 2017,March 31, 2019, we drilled 8728 operated horizontal wells and completed 87turned 33 operated horizontal wells. wells to sales. As ofSeptember 30, 2017, March 31, 2019, the Company had 18 gross (16 net) wells that were drilled and completed, but not producing. These wells are expected to be turned to sales during the second quarter. As of March 31, 2019, we are the operator of 46of 66 gross (36(56 net) horizontalhorizontal wells in progress. All of the wells in progress. at March 31, 2019 are scheduled to commence production before December 31, 2020. The majority of this activity was funded through cash flows from operations.

For the ninethree months ended September 30, 2017,March 31, 2019, we have participated in 12324 gross (23(2 net) non-operatednon-operated horizontal wells.

Capital Requirements

Our level of exploration, development, and acreage expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows, development results, acquisitions and divestitures, and downstream infrastructure and commitments, among other factors. Our primary need for capital will be to fund our anticipated drilling and completion activities and any other acquisitions that we may complete during the remainder of 2017.2019.

We anticipate that our 2017full-year 2019 capital expenditures, including operated drilling and completion capital expenditures for operated wellscosts, limited leasehold acquisition costs and selected non-operated drilling and completion costs, will be approximately $360between $425 million for the year.and $450 million. However, should commodity prices and/or economic conditions change, we can reduce or accelerate our drilling and completion activities depending on midstream constraints, which could have a material impact on our anticipated capital requirements. Additionally, 2017 drilling and completion expenditures associated with non-operated properties are expected to be approximately $60 million, which is net of capital we expect to recover as described in "- Capital Expenditures" above. Assuming a 2018 development program similar to what the Company has done in 2017, we expect to achieve year-over-year production growth of 25% or greater, while funding a majority of our expenditures through internally generated cash flow.

For the near term, we believe that we have sufficient liquidity to fund our needs through cash on hand, cash flow from operations, and additional borrowings available under our revolving credit facility.  However, should this not meet all of our long-term needs, we may need to raise additional funds to drill new wells through the sale of our securities, from third parties willing to pay our share of drilling and completing wells, or from other sources.  We may not be successful in raising the capital needed to drill or acquire oil or natural gas wells. We may seek to raise funds in capital markets transactions from time to time if we believe market conditions to be favorable.


Oil and Natural Gas Commodity Contracts

We use derivative contracts to help protect against the variability in cash flows created by short-term price fluctuations associated with the sale of future oil and natural gas production.  At September 30, 2017,March 31, 2019, we had open positions covering 1.33.0 million barrels of oil and 8,984 M16.5 BMcfcf of natural gas. We do not use derivative instruments for speculative purposes.

Our commodity derivative instruments may include but are not limited to “collars,” “swaps,” and “put” positions. Our derivative strategy, including the 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 our credit facility.

During the ninethree months ended September 30, 2017,March 31, 2019, we reported an unrealized commodity activity gainloss of $2.4$27.8 million.  Unrealized gainslosses are non-cash items.  We also reported a realized lossgain of $26.0 thousand,$4.9 million, representing the cash settlement of commodity contracts settled during the period, net of previously incurred premiums attributable to the settled commodity contracts.period.

At September 30, 2017,March 31, 2019, we estimated that the fair value of our various commodity derivative contracts was a net liabilityasset of $1.2$7.1 million. See Item 1. Financial Statements – Note 9,8, Fair Value Measurements, for a description of the methods we use to estimate the fair values of commodity derivative instruments.

Non-GAAP Financial MeasuresMeasure

In addition to financial measures presented on the basis of accounting principles generally accepted in the United States of America ("US GAAP"), we present certain financial measures which are not prescribed by US GAAP ("non-GAAP"). The following is a summary of the measure that we currently report.

Adjusted EBITDA

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

requirements. However, our definition of adjusted EBITDA may not be fully comparable to measures with similar titles reported by other companies. We define adjusted EBITDA as net income (loss) adjusted to exclude the impact of the items set forth in the table below (amounts in(in thousands):
Three Months Ended September 30, Nine Months Ended September 30,Three Months Ended March 31,
2017 2016 2017 20162019 2018
Adjusted EBITDA:          
Net income (loss)$43,848
 $(19,241) $91,664
 $(224,490)
Net income$49,751
 $65,796
Depreciation, depletion, and accretion33,740
 9,635
 73,396
 33,001
60,918
 37,081
Full cost ceiling impairment—
 25,453
 —
 215,223
Stock-based compensation expense3,683
 2,796
Mark-to-market of commodity derivative contracts:   
Total loss on commodity derivatives contracts22,913
 5,781
Cash settlements on commodity derivative contracts4,626
 (1,555)
Cash premiums paid for commodity derivative contracts(319) —
Interest income(69) (9)
Income tax expense—
 5
 —
 106
18,034
 5,811
Stock-based compensation3,030
 2,374
 8,390
 7,285
Mark-to-market of commodity derivative contracts:       
Total (gain) loss on commodity derivatives contracts2,383
 (407) (2,324) 3,617
Cash settlements on commodity derivative contracts544
 486
 778
 5,137
Interest income, net of interest expense(16) (11) (47) (176)
Adjusted EBITDA$83,529
 $18,294
 $171,857
 $39,703
$159,537
 $115,701

Critical Accounting Policies

We prepare our condensed consolidated financial statements and the accompanying notes in conformity with US GAAP, which requires management to make estimates and assumptions about future events that affect the reported amounts in the condensed

consolidated financial statements and the accompanying notes. We identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our financial condition, results of operations, or liquidity and the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management discusses the development, selection, and disclosure of each of the critical accounting policies.

There have been no significant changes to our critical accounting policies and estimates or in the underlying accounting assumptions and estimates used from those disclosed in the "Management’s Discussion and Analysis of Financial Condition and Results of Operations" section of the Annual Report on Form 10-K filed with the SEC on February 23, 201720, 2019 and in the financial statements and accompanying notes contained in that report. Item 1. Financial Statements – Note 1, Organization and Summary of Significant Accounting Policies, to the accompanying condensed consolidated financial statements included elsewhere in this report provides information regarding recently issued accounting pronouncements.



Cautionary Statement Concerning Forward-Looking Statements

This report contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management and information currently available to management. The use of words such as "believes," "expects," "anticipates," "intends," "plans," "estimates," "should," "likely," or similar expressions indicate forward-looking statements. Forward-looking statements included in this report include statements relating to future production, future capital expenditures and projects, the adequacy and nature of future sources of financing, possible future impairment charges, midstream capacity issues, future differentials, future production relative to volume commitments, and the closingimplementation and effecteffects of proposed transactions.SB19-181 and our responses thereto.

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

See "Risk Factors" in this report and in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 20162018 filed with the SEC on February 23, 201720, 2019 for a discussion of risk factors that affect our business, financial condition, and results of operations. These risks include, among others, those associated with the following:

declines in oil and natural gas prices;
the effects of, changes in and the costs of compliance with federal, state, and local regulations applicable to our business, including those related to hydraulic stimulation and SB19-181;
operating hazards that adversely affect our ability to conduct business;
uncertainties in the estimates of proved reserves;
the availability and capacity of gathering and processing systems, pipelines, and other midstream infrastructure for our production;
the effect of seasonal weather conditions and wildlife and plant species restrictions on our operations;
our ability to fund, develop, produce, and acquire additional oil and natural gas reserves that are economically recoverable;
our ability to obtain adequate financing;
the effect of local and regional factors on oil and natural gas prices;
incurrence of ceiling test write-downs;
our inability to control operations on properties that we do not operate;
the availability and capacity of gathering systems, pipelines, and other midstream infrastructure for our production;
the strength and financial resources of our competitors;
our ability to complete, and the effect of, pending and planned transactions;
our ability to successfully identify, execute, and effectively integrate acquisitions;
the effect of federal, state, and local laws and regulations;
the effects of, including costs to comply with, environmental legislation or regulatory initiatives, including those related to hydraulic fracturing;
our ability to market our production;
the effects of local moratoria or bans on our business;
the effect of environmental liabilities;
the effect of the adoption and implementation of statutory and regulatory requirements for derivative transactions;
changes in U.S. tax laws;
our ability to satisfy our contractual obligations and commitments;
the amount of our indebtedness and our ability to maintain compliance with debt covenants;
the effectiveness of our disclosure controls and our internal controls over financial reporting;
the geographic concentration of our principal properties;
our ability to protect critical data and technology systems;
the availability of water for use in our operations; and
the risks and uncertainties described and referenced in "Risk Factors."



ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS

Commodity Price Risk - Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. The volatility of oil prices affects our results to a greater degree than the volatility of natural gas prices, as approximately 71% and 69%78% of our revenue during the three and nine months ended September 30, 2017, respectively,March 31, 2019 was from the sale of oil. A $5 per barrel change in our realized oil price would have resulted in a $8.6 million and $18.3$14.8 million change in revenues during the three and nine months ended September 30, 2017, respectively,March 31, 2019; a $0.25 per Mcf change in our realized natural gas price would have resulted in a $1.9 million and $4.3$2.8 million change in our natural gas revenues for the three and nine months ended September 30, 2017, respectively,March 31, 2019; and a $5 per barrel change in our realized NGL price would have resulted in a $3.8 million and $8.8$5.3 million change in our NGL revenues for the three and nine months ended September 30, 2017, respectively.March 31, 2019.

During the three months ended September 30, 2017,March 31, 2019, the price of oil, natural gas, and NGLs increaseddecreased relative to the thirdfourth quarter of 2016.2018.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil, natural gas, and NGL prices include the levels of demand and supply for oil (in global or local markets), the establishment of and compliance with production quotas by oil exporting countries, weather conditions which influence the demand for natural gas, the price and availability of alternative fuels, the strength of the US dollar compared to other currencies, and overall economic conditions. It is impossible to predict future oil, natural gas, and NGLs prices with any degree of certainty. Sustained weakness in oil, natural gas, and NGL prices may adversely affect our financial condition and results of operations and may also reduce the amount of oil, natural gas, and NGL reserves that we can produce economically. Any reduction in our oil, natural gas, and NGL reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities.  Similarly, any improvements in oil, natural gas, and NGL prices can have a favorable impact on our financial condition, results of operations, and capital resources.

We attempt to mitigate fluctuations in short-term cash flow resulting from changes in commodity prices by entering into derivative positions on a portion of our expected oil and natural gas production.  Under the Revolver, we can use derivative contracts to cover up to 85% of expected proved developed producing production as projected in our semi-annual reserve report, generally over a period of two years.  We do not enter into derivative contracts for speculative or trading purposes. As of September 30, 2017,March 31, 2019, we had open oil and natural gas derivatives in a net liabilityasset position with a fair value of $1.2$7.1 million.  A hypothetical upward shift of 10% in the NYMEX forward curve of oil and natural gas prices would decrease the fair value of our position by $1.4$11.7 million. A hypothetical downward shift of 10% in the NYMEX forward curve of oil and natural gas prices would increase the fair value of our position by $1.2$14.8 million. A summary of our open positions as of September 30, 2017 is set forth in Item 1. Financial Statements - Note 8, Commodity Derivative Instruments.

Interest Rate Risk - At September 30, 2017,March 31, 2019, we had $150$195.0 million in debt outstanding under our revolving credit facility.  Interest on amounts borrowed under our credit facility accrues at a variable rate, based upon either the Prime Rate or LIBOR plus an applicable margin.  During the ninethree months ended September 30, 2017,March 31, 2019, we incurred interest at an annualized rateexpense of 3.3%. We$2.2 million on our revolving credit facility. When we have balances outstanding under the revolving credit facility, we are exposed to interest rate risk on the credit facility if the variable reference rates increase. If interest rates increase, our monthly interest payments would increase and our available cash flow would decrease.  We estimate that if market interest rates increased or decreased by 1%, our interest paymentsexpense in each of the three and nine months ended September 30, 2017March 31, 2019 would have changed by $0.3 million and $0.4 million, respectively.approximately $0.5 million.

Under current market conditions, we do not anticipate significant changes in prevailing interest rates for the next year, and we have not undertaken any activities to mitigate potential interest rate risk due to restrictions imposed by the Revolver.

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

We believe that our exposure to counterparty risk increaseddecreased slightly during the thirdfirst quarter of 20172019 as the amounts due to us from counterparties has increased.decreased.



ITEM 4.CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

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


PART II

Item 1.Legal Proceedings

Except as disclosed in Note 14 toDuring the accompanying condensed consolidated financial statements, during the quarter ended March 31, 2019, there were no material developments regarding the legal matters, which were previously described under Item 3, Legal Proceedings, of the Annual Report on Form 10-K filed with the Securities and Exchange Commission on February 23, 2017.20, 2019. This information should be considered carefully together with other information in this report and other reports and materials we file with the SEC. We are subject to various legal proceedings from time to time in the ordinary course of our business, but there are currently no pending legal proceedings to which we are subject that we believe to be material.

Item 1A.Risk Factors

We face many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock are described under Item 1A, Risk Factors, of the Annual Report on Form 10-K filed with the SEC on February 23, 2017.20, 2019. This information should be considered carefully together with other information in this report and other reports and materials that we file with the SEC.

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

Purchases of equity securities by the Company
Period Total Number of Shares Purchased Average Price Paid per Share
July 1, 2017 - July 31, 2017 (1)
 —
 $—
August 1, 2017 - August 31, 2017 (1)
 5,167
 $7.68
September 1, 2017 - September 30, 2017 (1)
 3,235
 $7.95
   Total 8,402
  
Period Total Number of Shares Purchased Average Price Paid per Share
January 1, 2019 - January 31, 2019 (1)
 15,178
 $4.70
February 1, 2019 - February 28, 2019 (1)
 162,789
 4.89
March 1, 2019 - March 31, 2019 (1)
 1,449
 $4.93
   Total 179,416
  

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

Item 3.Defaults Upon Senior Securities

None.

Item 4.Mine Safety Disclosures

Not applicableapplicable.

Item 5.Other Information

On August 18, 2017, the Company amended its bylaws to, among other things, include advance notice provisions pursuant to which a shareholder seeking to propose a candidate for election as director or other business at a meeting of the Company’s shareholders is required to provide advance notice of the proposal to the Company. This notice must contain specified information regarding the shareholder and the proposal and must generally be provided (i) in the case of an annual meeting, not earlier than the 120th day, and not later than the 90th day, prior to the first anniversary of the preceding year’s annual meeting and (ii) in the case of a special meeting, not earlier than the 90th day, and not later than the 80th day, prior to such meeting. Subject to certain possible exceptions set forth in the amended and restated bylaws, notice of proposals to be made at the Company’s 2018 annual meeting of shareholders must be provided no earlier than February 15, 2018 and no later than March 19, 2018.None.

Item 6.        Exhibits

Exhibit
Number
 Exhibit
3.2
Amended and Restated Bylaws of SRC Energy Inc., effective as of August 18, 2017
31.1 
Certification of the Principal Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 *
31.2 
Certification of the Principal Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 *
32.1 
Certifications of the Principal Executive Officer and Principal Financial Officer pursuant to 18 USC 1350, as adopted, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 **
99.1
Eleventh Amendment to Amended and Restated Credit Agreement, dated as of September 27, 2017, among SRC Energy Inc. (formerly known as Synergy Resources Corporation), SunTrust Bank as Administrative Agent and as an Issuing Bank, and the lenders party thereto *
101.INS 
XBRL Instance Document
101.SCH XBRL Taxonomy Extension Schema
101.CAL XBRL Taxonomy Extension Calculation Linkbase
101.DEF XBRL Taxonomy Extension Definition Linkbase
101.LAB XBRL Taxonomy Extension Label Linkbase
101.PRE XBRL Taxonomy Extension Presentation Linkbase
   
   
* Filed herewith
** Furnished herewith



SIGNATURES

Pursuant to the requirements of Section 13 or 15(a) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized on the 1st day of November, 2017.May, 2019.

 SRC Energy Inc.
  
 /s/ Lynn A. Peterson
 
Lynn A. Peterson, President and Chief Executive Officer
(Principal Executive Officer)
  
 /s/ James P. Henderson
 
James P. Henderson, Executive Vice President and Chief Financial Officer and Treasurer
(Principal Financial Officer)
  
 /s/ Jared C. Grenzenbach
 
Jared C. Grenzenbach, Vice President and Chief Accounting Officer
(Principal Accounting Officer)