10-Q 1 q11910-qsci20190331.htm 10-Q Document


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

FORM 10-Q

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

For the quarterly period ended March 31, 2019

OR

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

For the transition period from _______________________ to _______________________

Commission file number:  001-35245

logovrt4ca21.jpg
SRC ENERGY INC.
(Exact name of registrant as specified in its charter)

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

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

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


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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such 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 
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: 243,392,175 outstanding shares of common stock as of April 29, 2019.




SRC ENERGY INC.

Index

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





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


ASSETS
March 31, 2019
 
December 31, 2018
Current assets:
 
 
 
Cash and cash equivalents
$
56,813

 
$
49,609

Accounts receivable:
 
 
 
Oil, natural gas, and NGL sales
102,096

 
100,973

Trade
29,775

 
39,415

Commodity derivative assets
7,081

 
34,906

Other current assets
8,610

 
7,537

Total current assets
204,375

 
232,440

 
 
 
 
Property and equipment:
 
 
 
Oil and gas properties, full cost method:
 
 
 
Proved properties, net of accumulated depletion
1,663,635

 
1,545,445

Wells in progress
192,459

 
227,262

Unproved properties and land, not subject to depletion
722,388

 
740,453

Oil and gas properties, net
2,578,482

 
2,513,160

Other property and equipment, net
5,218

 
5,540

Total property and equipment, net
2,583,700

 
2,518,700

Other assets
8,588

 
3,574

Total assets
$
2,796,663

 
$
2,754,714

 
 
 
 
LIABILITIES AND SHAREHOLDERS' EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
118,981

 
$
150,010

Revenue payable
92,027

 
97,030

Production taxes payable
102,072

 
95,099

Asset retirement obligations
13,495

 
11,694

Total current liabilities
326,575

 
353,833

 
 
 
 
Revolving credit facility
195,000

 
195,000

Notes payable, net of issuance costs
539,666

 
539,360

Asset retirement obligations
36,093

 
40,052

Deferred taxes
56,002

 
37,967

Other liabilities
3,747

 
2,210

Total liabilities
1,157,083

 
1,168,422

 
 
 
 
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, 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, respectively
243

 
243

Additional paid-in capital
1,495,644

 
1,492,107

Retained earnings
143,693

 
93,942

Total shareholders' equity
1,639,580

 
1,586,292

 
 
 
 
Total liabilities and shareholders' equity
$
2,796,663

 
$
2,754,714


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

2

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

 
Three Months Ended March 31,
 
2019
 
2018
Oil, natural gas, and NGL revenues
$
189,455

 
$
147,233

 
 
 
 
Expenses:
 
 
 
Lease operating expenses
17,360

 
7,896

Transportation and gathering
4,054

 
1,855

Production taxes
7,086

 
13,443

Depreciation, depletion, and accretion
60,918

 
37,081

General and administrative
9,469

 
9,600

Total expenses
98,887

 
69,875

 
 
 
 
Operating income
90,568

 
77,358

 
 
 
 
Other income (expense):
 
 
 
Commodity derivatives loss
(22,913
)
 
(5,781
)
Interest expense, net of amounts capitalized

 

Interest income
69

 
9

Other income
61

 
21

Total other expense
(22,783
)
 
(5,751
)
 
 
 
 
Income before income taxes
67,785

 
71,607

 
 
 
 
Income tax expense
18,034

 
5,811

Net income
$
49,751

 
$
65,796

 
 
 
 
Net income per common share:
 
 
 
Basic
$
0.20

 
$
0.27

Diluted
$
0.20

 
$
0.27

 
 
 
 
Weighted-average shares outstanding:
 
 
 
Basic
243,290,734

 
241,751,915

Diluted
244,091,516

 
243,166,897


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

3

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

 
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 accretion
60,918

 
37,081

Settlement of asset retirement obligations
(2,066
)
 
(2,461
)
Provision for deferred taxes
18,034

 
5,811

Stock-based compensation expense
3,683

 
2,796

Mark-to-market of commodity derivative contracts:
 
 
 
Total loss on commodity derivatives contracts
22,913

 
5,781

Cash settlements on commodity derivative contracts
4,626

 
(1,555
)
Cash premiums paid for commodity derivative contracts
(319
)
 

Changes in operating assets and liabilities
3,133

 
14,432

Net cash provided by operating activities
160,673

 
127,681

 
 
 
 
Cash flows from investing activities:
 
 
 
Acquisition of oil and gas properties and leaseholds
2,623

 
(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 other
124

 
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 equivalents
7,204

 
22,971

 
 
 
 
Cash and cash equivalents at beginning of period
49,609

 
48,772

 
 
 
 
Cash and cash equivalents at end of period
$
56,813

 
$
71,743

Supplemental Cash Flow Information (See Note 16)

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

4

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, 2017
241,365,522

 
$
241

 
$
1,474,273

 
$
(166,080
)
 
$
1,308,434

Shares issued under stock bonus and equity incentive plans
268,676

 
1

 
(1
)
 

 

Shares issued for exercise of stock options
268,303

 

 
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, 2018
241,902,501

 
$
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, 2018
242,608,284

 
$
243

 
$
1,492,107

 
$
93,942

 
$
1,586,292

Shares issued under stock bonus and equity incentive plans
709,042

 

 

 

 

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, 2019
243,317,326

 
$
243

 
$
1,495,644

 
$
143,693

 
$
1,639,580




5


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

1.
Organization and Summary of Significant Accounting Policies

Organization:  SRC Energy Inc. 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. The Company’s common stock is listed and traded on the NYSE American under the 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, 2018 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, 2018 as filed with the SEC on February 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, 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 revenues (“major customers”) for each of the periods presented are shown in the following table:
 
 
Three Months Ended March 31,
Major Customers
 
2019
 
2018
Company A
 
28%
 
31%
Company B
 
25%
 
*
Company C
 
20%
 
19%
Company D
 
*
 
13%
* 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 contracts 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.
 

6


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

Customers with balances greater than 10% of total receivable balances as of each of the periods presented are shown in the following table (these companies do not necessarily correspond to those presented above):
 
 
As of
 
As of
Major Customers
 
March 31, 2019
 
December 31, 2018
Company A
 
24%
 
15%
Company B
 
14%
 
12%
Company C
 
14%
 
12%
Company D
 
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 February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update ("ASU") No. 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 recognize right-of-use (“ROU”) assets and lease payment liabilities on the balance sheet for leases representing the Company’s right to use 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 them 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 additional ROU assets and related lease liabilities. Upon adoption on January 1, 2019, 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 guidance. See Note 14 for the new disclosures required by ASC 842.

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

Change in estimate: Production taxes are comprised primarily of two elements: severance tax and ad valorem tax. During the three months ended 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 was 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, which increased our operating income for the three months ended March 31, 2019 by a corresponding amount, or $0.03 per basic and diluted common share.


7


2.
Property and Equipment

The capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):
 
As of
 
As of
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, net
1,663,635

 
1,545,445

 
 
 
 
Costs of wells in progress
192,459

 
227,262

 
 
 
 
Costs of unproved properties and land, not subject to depletion:
 
 
 
Lease acquisition and other costs
712,993

 
731,058

Land
9,395

 
9,395

Subtotal, unproved properties and land
722,388

 
740,453

 
 
 
 
Costs of other property and equipment:
 
 
 
Other property and equipment
9,803

 
9,642

Less, accumulated depreciation
(4,585
)
 
(4,102
)
Subtotal, other property and equipment, net
5,218

 
5,540

 
 
 
 
Total property and equipment, net
$
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 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 impairments were 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 March 31,
 
2019
 
2018
Capitalized overhead
$
3,667

 
$
3,113


3.
Depletion, depreciation, and accretion ("DD&A")

DD&A consisted of the following (in thousands):
 
Three Months Ended March 31,
 
2019
 
2018
Depletion of oil and gas properties
$
59,428

 
$
36,102

Depreciation and accretion
1,490

 
979

Total DD&A Expense
$
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.


8


4.
Asset Retirement Obligations

The Company recognizes obligations for its oil and natural gas operations for anticipated costs to remove and dispose of surface equipment, remediate the well, and reclaim 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):
 
Three Months Ended March 31, 2019
Asset retirement obligations, December 31, 2018
$
51,746

Obligations incurred with development activities
747

Accretion expense
904

Obligations discharged with asset retirements and divestitures
(3,809
)
Asset retirement obligation, March 31, 2019
$
49,588

Less, current portion
(13,495
)
Long-term portion
$
36,093


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 Restated Credit Agreement provides a revolving credit facility (sometimes referred to as the "Revolver") and a $25 million swingline facility with a maturity date of April 2, 2023. The Revolver is available for working capital for exploration and production operations, acquisitions of oil and gas properties, and general corporate purposes and to support letters of credit. At March 31, 2019, the terms of the Revolver provided for up to $1.5 billion in borrowings, an aggregate elected commitment of $500 million, and a borrowing base limitation of $650 million. As of March 31, 2019 and December 31, 2018, the outstanding principal balance was $195.0 million. At March 31, 2019 and December 31, 2018, the Company had no letters of credit issued. The average annual interest rate for borrowings during the three months ended March 31, 2019 was 4.5%.

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

Certain of the Company’s assets, including substantially all of its producing wells and developed oil and gas leases, have been designated as collateral under the Restated Credit Agreement. The amount 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 Restated Credit Agreement contains covenants that, among other things, restrict the payment of dividends, limit our overall commodity derivative positions, and require the Company to maintain compliance with certain financial and liquidity ratio covenants. As of March 31, 2019, the most recent compliance date, the Company was in compliance with these loan covenants and expects to remain in compliance throughout the next 12-month period.

6.
Notes Payable

2025 Senior Notes

In November 2017, the Company issued $550 million aggregate principal amount of 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 December 1, 2025. Interest on the 2025 Senior Notes accrues at 6.25%. Interest is payable on June 1 and December 1 of each year. The 2025 Senior Notes were issued pursuant to an indenture dated as of November 29, 2017. The associated expenses and underwriting discounts and commissions are amortized using the effective interest method at an effective interest rate of 6.6%.


9


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

As of 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.

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.

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 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 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 March 31, 2019 are summarized below:
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

 
 


10


Subsequent to March 31, 2019, the Company added the following positions:
Settlement Period
 
Derivative
Instrument
 
Volumes
(Bbls per day)
 
Weighted-Average
Floor Price
 
Weighted-Average Ceiling Price
Crude Oil - NYMEX WTI
 
 
 
 
 
 
 
 
May 1, 2019 - Dec 31, 2019
 
Collar
 
5,000

 
$
55.00

 
$
71.90



Offsetting of Derivative Assets and Liabilities

As of March 31, 2019 and December 31, 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 of the Company’s derivative contracts (in thousands):
 
 
 
 
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
Commodity derivative contracts
 
Current assets
 
$
13,051

 
$
(5,970
)
 
$
7,081

Commodity derivative contracts
 
Noncurrent assets
 

 

 

Commodity derivative contracts
 
Current liabilities
 
5,970

 
(5,970
)
 

Commodity derivative contracts
 
Noncurrent liabilities
 
$

 
$

 
$

 
 
 
 
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
Commodity derivative contracts
 
Current assets
 
$
39,485

 
$
(4,579
)
 
$
34,906

Commodity derivative contracts
 
Noncurrent assets
 

 

 

Commodity derivative contracts
 
Current liabilities
 
4,579

 
(4,579
)
 

Commodity derivative contracts
 
Noncurrent liabilities
 
$

 
$

 
$


The amount of gain (loss) recognized in the condensed consolidated statements of operations related to derivative financial instruments was as follows (in thousands):
 
Three Months Ended 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
)


11


Realized gains and losses represent the monthly settlement of derivative contracts at their scheduled maturity date, net 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 March 31,
 
2019
 
2018
Monthly settlement
$
5,232

 
$
(2,072
)
Premiums paid
(319
)
 

Total realized gain (loss)
$
4,913

 
$
(2,072
)

Credit Related Contingent Features

As of March 31, 2019, five of the seven 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 sixth and seventh counterparties, which are not lenders under the credit facility, is unsecured and does not require the posting of collateral.

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 or valuation models.

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

The Company’s non-recurring fair value measurement includes asset retirement obligations. Refer to Note 4 for further discussion of asset retirement 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 reclamation 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 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 Note 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 by level within the fair value hierarchy (in thousands):
 
Fair Value Measurements at March 31, 2019
 
Level 1
 
Level 2
 
Level 3
 
Total
Financial assets and liabilities:
 
 
 
 
 
 
 
Commodity derivative asset
$

 
$
7,081

 
$

 
$
7,081

Commodity derivative liability
$

 
$

 
$

 
$


12


 
Fair Value Measurements at December 31, 2018
 
Level 1
 
Level 2
 
Level 3
 
Total
Financial assets and liabilities:
 
 
 
 
 
 
 
Commodity derivative asset
$

 
$
34,906

 
$

 
$
34,906

Commodity derivative liability
$

 
$

 
$

 
$


Commodity Derivative Instruments

The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparties to its derivative contracts would default by failing to make any contractually required payments. The Company considers the counterparties to be of substantial credit quality and believes that they have the financial resources and willingness to meet their potential repayment obligations associated with the derivative transactions. At March 31, 2019, derivative instruments utilized by the Company consist of swaps 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, accounts receivable, and accounts payable are representative of their fair values due to their short-term maturities. Due to the variable interest rate paid on the credit facility borrowings, the carrying value is representative of its fair value.

The fair value of the notes payable is estimated to be $491.0 million at March 31, 2019. The Company determined the fair value of its notes payable at March 31, 2019 by using observable market-based information for these debt instruments. The Company has classified the notes payable as Level 1.

9.
Interest Expense

The components of interest expense are (in thousands):
 
Three Months Ended March 31,
 
2019
 
2018
Revolving credit facility
$
2,173

 
$

Notes payable
8,594

 
8,594

Amortization of issuance costs and other
797

 
887

Less: interest capitalized
(11,564
)
 
(9,481
)
Interest expense, net of amounts capitalized
$

 
$


10.
Stock-Based Compensation

As of March 31, 2019, there were 10,500,000 common shares authorized for grant under the 2015 Equity Incentive Plan, of which 1,097,165 shares were available for future grant. The shares available for future grant exclude 1,973,768 shares which have been reserved for future vesting of performance-vested stock units in the event that these awards meet the criteria to vest at their maximum multiplier.


13


The amount of stock-based compensation was as follows (in thousands):
 
Three Months Ended March 31,
 
2019
 
2018
Stock options
$
1,027

 
$
1,203

Performance-vested stock units
1,071

 
856

Restricted stock units and stock bonus shares
2,315

 
1,336

Total stock-based compensation
$
4,413

 
$
3,395

Less: stock-based compensation capitalized
(730
)
 
(599
)
Total stock-based compensation expense
$
3,683

 
$
2,796


Stock options

No stock options were granted during the three months ended March 31, 2019 or 2018. The following table summarizes activity for stock options for the period presented:
 
Number of Shares
 
Weighted-Average Exercise Price
 
Weighted-Average Remaining Contractual Life
 
Aggregate Intrinsic Value (thousands)
Outstanding, December 31, 2018
4,652,634

 
$
10.06

 
6.4 years
 
$
49

Granted

 

 
 
 
 
Exercised

 

 
 
 

Expired

 

 
 
 
 
Forfeited

 

 
 
 
 
Outstanding, March 31, 2019
4,652,634

 
$
10.06

 
6.2 years
 
$
63

Outstanding, Exercisable at March 31, 2019
3,414,834

 
$
10.21

 
6.0 years
 
$
63


The following table summarizes information about issued and outstanding stock options as of March 31, 2019:
 
 
Outstanding Options
 
Exercisable Options
Range of Exercise Prices
 
Options
 
Weighted-Average Exercise Price per Share
 
Weighted-Average Remaining Contractual Life
 
Options
 
Weighted-Average Exercise Price per Share
 
Weighted-Average Remaining Contractual Life
Under $5.00
 
35,000

 
$
3.31

 
3.3 years
 
35,000

 
$
3.31

 
3.3 years
$5.00 - $6.99
 
723,800

 
6.30

 
6.2 years
 
428,600

 
6.26

 
5.5 years
$7.00 - $10.99
 
1,360,334

 
9.42

 
6.2 years
 
986,134

 
9.42

 
6.0 years
$11.00 - $13.46
 
2,533,500

 
11.57

 
6.2 years
 
1,965,100

 
11.58

 
6.1 years
Total
 
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 March 31, 2019, which will be recognized ratably over the remaining vesting period, is as follows:
Unrecognized compensation (in thousands)
$
3,477

Remaining vesting period
1.6 years



14


Restricted stock units and stock bonus awards

The following table summarizes activity for restricted stock units and stock bonus awards for the three months ended March 31, 2019:
 
Number of Shares
 
Weighted-Average Grant-Date Fair Value
Not vested, December 31, 2018
1,639,918

 
$
8.07

Granted
1,525,976

 
4.87

Vested
(499,330
)
 
8.28

Forfeited
(13,921
)
 
6.67

Not vested, March 31, 2019
2,652,643

 
$
6.19


The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of March 31, 2019, which will be recognized ratably over the remaining vesting period, is as follows:
Unrecognized compensation cost (in thousands)
$
14,012

Remaining vesting period
2.4 years


Performance-vested stock units

The Company has 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. For the years prior to 2019, the PSUs will be settled in shares of the Company’s common stock. 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 awards.


15


The assumptions used in valuing the TSR PSUs granted were as follows:
 
Three Months Ended March 31,
 
2019
 
2018
Weighted-average expected term
2.9 years

 
2.8 years

Weighted-average expected volatility
48
%
 
52
%
Weighted-average risk-free rate
2.49
%
 
2.41
%

As of March 31, 2019, unrecognized compensation cost for TSR PSUs was $8.9 million and will be amortized through 2021. The following table summarizes activity for TSR PSUs for the three months ended March 31, 2019:
 
Number of Units1
 
Weighted-Average Grant-Date Fair Value
Not vested, December 31, 2018
780,028

 
$
11.73

Granted
918,842

 
5.74

Vested

 

Forfeited

 

Not vested, March 31, 2019
1,698,870

 
$
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.

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 — basic
243,290,734

 
241,751,915

Potentially dilutive common shares from:
 
 
 
Stock options
11,339

 
347,391

TSR PSUs 1
615,516

 
810,128

Restricted stock units and stock bonus shares
173,927

 
257,463

Weighted-average shares outstanding — diluted
244,091,516

 
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

Total
6,910,569

 
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.

16



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 rate for the three months ended 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 months ended March 31, 2019 differed from the statutory rate primarily due to state income taxes, non-deductible expenses, and tax deficiencies recognized with the vesting of stock awards. The 2018 differed from the statutory rates due primarily to the release of valuation allowances previously recorded against deferred tax assets.

As of March 31, 2019, we had no liability for unrecognized tax benefits. The Company believes that there are no new items or changes in facts or judgments that should impact the Company’s tax position. No significant uncertain tax positions were identified as of any date on or before March 31, 2019.  The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of 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. As 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 contracts’ 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 NGLs
42,375

 
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,

17


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 residual 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 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 liabilities
8

 
 
Operating lease cost
604

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 leases
58

 
 
ROU assets obtained in exchange for new finance lease liabilities
95

ROU assets obtained in exchange for new operating lease liabilities
4,532

 
As of
March 31, 2019
Weighted-average remaining lease term - finance leases
3.2 years

Weighted-average remaining lease term - operating leases
2.4 years

Weighted-average discount rate - finance leases
4.75
%
Weighted-average discount rate - operating leases
4.75
%


18


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


15.
Other Commitments and Contingencies

Oil Commitments

The Company entered into firm sales agreements for its oil production with four counterparties. Deliveries under the sales agreements 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, excluding the contingent commitment described below, are as follows:
Year ending December 31, 2019
 
Oil
 
(MBbls)
Remainder of 2019
 
3,893

2020
 
4,003

2021
 
1,672

Total
 
9,568



19


During the first quarter of 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. 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 the 200 MMcf per day processing plant ("Mewbourn 3") as well as the expansion of a related gathering system. Starting in August 2018, Mewbourn 3 was complete and in service. Our share of the commitment requires 46.4 MMcf per day to be delivered after the plant in-service date for a period of 7 years.
The second agreement includes an 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. Construction of the plant is underway, and it is expected to be placed into service late in the 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. If we are unable to fulfill all of our contractual obligations and our obligations are not sufficiently reduced by the collective volumes delivered by other producers, we may be required to pay penalties or damages pursuant to these agreements. Our share of the commitment does not guarantee us a corresponding capacity for future deliveries to system. During the first quarter of 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. 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 proceedings are reasonably likely to have a material adverse impact on the Company's business, financial position, results of operations, or cash flows.

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):
 
Three Months Ended March 31,
Supplemental cash flow information:
2019
 
2018
Interest paid
$
2,136

 
$
69

 
 
 
 
Non-cash investing and financing activities:
 
 
 
Accrued well costs as of period end
$
89,489

 
$
66,823

Asset retirement obligations incurred with development activities
747

 
223

Asset retirement obligations assumed with acquisitions

 
5

Obligations discharged with asset retirements and divestitures
$
(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 payable
6,319

 
5,295

Other
130

 
(116
)
Changes in operating assets and liabilities
$
3,133

 
$
14,432


20


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 March 31, 2019 and its results of operations for the three months ended March 31, 2019 and 2018.  It should be read in conjunction with 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, 2018 filed with the SEC on February 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.

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. Our oil and natural gas activities are focused in the Wattenberg Field, an area that covers the western flank of the D-J Basin. 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 formation as well as the three benches of the Niobrara 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 91% of our proved developed reserves and anticipate operating a majority of our future net drilling locations.

Market Conditions

Market prices for our products significantly impact our revenues, net income, cash flow, future growth, and 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 four years.
 
Year Ended December 31,
 
2018
 
2017
 
2016
 
2015
Average NYMEX prices
 
 
 
 
 
 
 
Oil (per Bbl)
$
64.94

 
$
50.93

 
$
43.20

 
$
48.73

Natural gas (per Mcf)
$
3.09

 
$
3.00

 
$
2.52

 
$
2.58



21


For the periods presented in this report, the following table presents the average NYMEX prices as well as the differential between the NYMEX prices and the prices realized by us.
 
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 and the published indices reflects deductions imposed upon us by the purchasers for location and quality adjustments. To the extent the Company's oil production exceeded its firm sales commitments during the three months ended March 31, 2019, the surplus oil production was sold at a reduced differential as compared to our committed volumes.

Our natural gas sales tend to trend closely with Colorado Interstate Gas – Rocky Mountains as published in Inside FERC’s Gas Market Report, published by Platts ("CIG"). Average CIG prices for the first quarter of 2019 decreased to $2.95 from $3.06 in the fourth quarter of 2018, resulting in the basis difference for CIG to NYMEX-Henry Hub decreasing from $0.58 to $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 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.

Core Operations

The following table provides details about our ownership interests with respect to vertical and horizontal producing wells as of March 31, 2019:
Vertical Wells
Operated Wells
 
Non-Operated Wells
 
Totals
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
581

 
562

 
195

 
55

 
776

 
617

Horizontal Wells
Operated Wells
 
Non-Operated Wells
 
Totals
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
425

 
402

 
387

 
59

 
812

 
461


In addition to the producing wells summarized in the preceding table, as of March 31, 2019, we were the operator of 66 gross (56 net) horizontal wells in progress. As of March 31, 2019, we are participating in 17 gross (2 net) non-operated horizontal wells in progress.

As we develop our acreage through horizontal drilling, we have an active program for the remediation and reclamation

22


of the vast majority of the operated vertical wellbores. During the three months ended March 31, 2019, we reclaimed 34 wells and returned the associated acreage to the property owners.

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 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 and operating conditions are favorable, we may choose to accelerate drilling and completion activities, assuming adequate gas processing capacity is available at the time.

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 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 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 Codell and Niobrara formations.

For the three months ended March 31, 2019, we participated in the completion of 7 gross (0.1 net) non-operated horizontal wells. As of March 31, 2019, we are participating in 17 gross (2 net) non-operated horizontal wells in progress.

Production

For the three months ended March 31, 2019, our average daily production increased to 65,771 BOED as compared to 45,397 BOED for the three months ended March 31, 2018. As of March 31, 2019, over 98% of our 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, 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 the D-J Basin, where we have significant operating experience.  All of our current wells and our proved undeveloped acreage are located in the Wattenberg 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.  A 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

23


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.

Control and reduce emissions from our production facilities. We place high importance on achieving compliance with all applicable air quality rules and regulations and further reducing emissions continues to be a top priority. To minimize emissions, we employ best management practices such 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 production facilities to produce oil and natural gas with fewer air emissions, including those emissions for which there are public health standards (e.g. ozone and particulate matter).

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 maintaining a safe workplace for our employees and contractors. Further, as technology for resource development has advanced, we seek to utilize 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 lighting issues, and constructing sound walls to minimize noise.  We value our positive relationship with local governing entities and the communities in which we operate and seek 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. Our high degree of operational control, as well as our focus on operating efficiencies that provide short return on investment cycle times, is central to our operating strategy.

Acquire and develop assets near established infrastructure. We target acquisitions of contiguous acreage to focus our development 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

Legislative Matters

The 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 siting of oil and gas locations, states that it is in the public interest to regulate the development of oil and gas resources in a manner that protects public health, safety, and welfare, including protection of the environment and wildlife resources, and modifies the requirements related to statutory pooling. There will be significant rule making associated with this legislation that will affect the implementation and effect of the law. SB19-181 could have a variety of effects on our operations, but we believe that some of these impacts may be mitigated by the fact that the statute places a significant emphasis on local control of oil and gas regulatory matters, and all of our planned future development activities are in Weld County, a jurisdiction in which there is a strong support of the oil and gas industry.

Revolving Credit Facility

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


24


Trends and Outlook

NYMEX-WTI oil traded at $45.15 per Bbl on December 28, 2018, but has since increased approximately 33% as of March 29, 2019 to $60.19. NYMEX-Henry Hub natural gas traded at $3.25 per Mcf on December 28, 2018, but declined approximately 16% as of March 29, 2019 to $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, reduce the funds available for the exploration and replacement 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) 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) result in marginally productive oil and natural gas wells being shut-in as non-commercial, and (vi) cause ceiling test impairments.

We continually focus on managing drilling and completion costs through a combination of well design optimization, reductions in the average days to drill, and employment of current technological advancements. This focus on cost management helps support well-level economics under varying oil and natural gas pricing environments.

Multiple midstream companies that operate natural gas processing facilities and gathering pipelines in the Wattenberg Field continue to make significant capital investments to increase the capacity of their systems. Until such time that these facilities are operational, our production has been, and most likely will continue to 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 been 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 support the expansion of natural gas gathering and processing capacity through agreements that impose baseline and incremental volume commitments, which we are currently exceeding.  Current plans are to add another 200 MMcf per day plant ("O'Connor 2") as well as an incremental 100 MMcf per day of bypass. The O'Connor plant is expected to be in service in the second quarter followed by the bypass 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 current lack of gas processing capacity, a system-wide volume allocation limiting each producer’s throughput was implemented in November 2017 and 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 these gathering lines have several benefits, including a) reduced need to use trucks, 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 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 pipeline takeaway capacity utilization has increased as 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. We continuously strive to reduce the negative differential 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."

For 2019, we expect to 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 that total capital expenditures, including operated drilling and completion costs, limited leasehold acquisition costs and selected non-operated drilling and completion costs, will be between $425 million and $450 million and will lead to an increase in production and associated proved developed producing reserves. Our current estimate is that full-year 2019 production will average between 63,000 BOED and 66,000 BOED with oil making up 42% to 45% of 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.


25


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 March 31, 2019 compared to the three months ended March 31, 2018

For the three months ended March 31, 2019, we reported net income of $49.8 million compared to net income of $65.8 million during the three months ended March 31, 2018. Net income per basic and diluted share was $0.20 for the three months ended March 31, 2019 compared to net income per basic and diluted share of $0.27 for the three months ended March 31, 2018.

Oil, Natural Gas, and NGL Production and Revenues - For the three months ended March 31, 2019, we recorded total oil, natural gas, and NGL revenues of $189.5 million compared to $147.2 million for the three months ended March 31, 2018, an increase of $42.2 million or 29%. The following table summarizes key production and revenue statistics:
 
Three Months Ended March 31,
 
Percentage
 
2019
 
2018
 
Change
Production:
 
 
 
 
 
Oil (MBbls) 1
2,967

 
2,041

 
45
 %
Natural Gas (MMcf) 2
11,391

 
7,719

 
48
 %
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
$
147,080

 
$
116,204

 
27
 %
Natural Gas
29,104

 
16,517

 
76
 %
NGLs
13,271

 
14,512

 
(9
)%
 
$
189,455

 
$
147,233

 
29
 %
Average sales price:
 
 
 
 
 
Oil 5
$
48.33

 
$
56.01

 
(14
)%
Natural Gas 5
2.52

 
2.14

 
18
 %
NGLs
12.59

 
19.15

 
(34
)%
BOE 5
$
31.32

 
$
35.58

 
(12
)%
1 "MBbl" refers to one thousand stock tank barrels, or 42,000 U.S. gallons liquid volume in reference to crude oil or other liquid hydrocarbons.
2 "MMcf" refers to one million cubic feet of natural gas.
3 "MBOE" refers to one thousand barrels of oil equivalent, which combines MBbls of oil and MMcf of natural gas by converting each six MMcf of natural gas to one MBbl of oil.
4 "BOED" refers to the average number of barrels of oil equivalent produced in a day for the period.
5 Adjusted to include the effect of transportation and gathering expenses.

Net oil, natural gas, and NGL production for the three months ended March 31, 2019 averaged 65,771 BOED, an increase of 45% over average production of 45,397 BOED in the three months ended March 31, 2018. From March 31, 2018 to March 31, 2019, our well count increased by 181 net horizontal wells, growing our reserves and daily production totals. The 45% increase in production resulted in an increase in revenues which was partially offset by the 12% decrease in average sales prices.


26


LOE - Direct operating costs of producing oil and natural gas are reported as follows (in thousands):
 
Three Months Ended March 31,
 
2019
 
2018
Production costs
$
17,281

 
$
7,714

Workover
79

 
182

Total LOE
$
17,360

 
$
7,896

 
 
 
 
Per BOE:
 
 
 
Production costs
$
2.92

 
$
1.89

Workover
0.01

 
0.04

Total LOE
$
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, 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 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 March 31, 2019, compared to $1.9 million, or $0.45 per BOE, for the three months ended March 31, 2018. Coinciding with the increasing production in 2018, the Company has increased the volume of its production that is sold and delivered at the downstream interconnect. This has the effect of increasing both the net price received for the production and transportation and gathering costs. While costs attributable to volumes sold at the interconnect of the pipeline are reported as an expense, the Company analyzes these charges on 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 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 $7.1 million, or $1.20 per BOE, for the three months ended March 31, 2019, compared to $13.4 million, or $3.29 per BOE, during the three months ended March 31, 2018. As a percentage of revenues, production taxes were 3.7% and 9.1% for the three months ended March 31, 2019 and 2018, respectively, with the 2019 period reflecting the effect of the change in estimate.

DD&A - The following table summarizes the components of DD&A:
 
Three Months Ended March 31,
(in thousands)
2019
 
2018
Depletion of oil and gas properties
$
59,428

 
$
36,102

Depreciation and accretion
1,490

 
979

Total DD&A
$
60,918

 
$
37,081

 
 
 
 
DD&A expense per BOE
$
10.29

 
$
9.08


For the three months ended March 31, 2019, DD&A was $10.29 per BOE compared to $9.08 per BOE for the three months ended March 31, 2018. The increase in the DD&A rate was the result of 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, whereby the ratio of production volumes for the quarter to the beginning of the quarter estimated total reserves determines the depletion rate.


27


General and Administrative ("G&A") - The following table summarizes G&A expenses incurred and capitalized during the periods presented:
 
Three Months Ended March 31,
(in thousands)
2019
 
2018
G&A costs incurred
$
13,163

 
$
12,741

Capitalized costs
(3,694
)
 
(3,141
)
Total G&A
$
9,469

 
$
9,600

 
 
 
 
Non-Cash G&A
$
3,683

 
$
2,796

Cash G&A
5,786

 
6,804

Total G&A
$
9,469

 
$
9,600

 
 
 
 
Non-Cash G&A per BOE
$
0.62

 
$
0.68

Cash G&A per BOE
0.98

 
1.67

G&A Expense per BOE
$
1.60

 
$
2.35


G&A includes overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. Total G&A costs of $9.5 million for the first quarter of 2019 were 1% lower than G&A for the same period of 2018.

Our G&A expense for the three months ended March 31, 2019 includes stock-based compensation of $3.7 million compared to $2.8 million for the three months ended 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 March 31, 2018 to the three months ended March 31, 2019 reflects our 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 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 March 31, 2019, we realized a settlement gain of $4.9 million. For the prior comparable period, we realized a settlement loss of $2.1 million.

In addition, for the three months ended March 31, 2019, we recorded an unrealized loss of $27.8 million to recognize the mark-to-market change in fair value of our commodity contracts. By comparison, in the three months ended March 31, 2018, we reported an unrealized loss