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FANG Diamondback Energy

Filed: 7 Nov 18, 5:32pm



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

 
 
FORM 10-Q

 
ýQUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED September 30, 2018
OR
oTRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
Commission File Number 001-35700
 
 
Diamondback Energy, Inc.
(Exact Name of Registrant As Specified in Its Charter)
 
 

Delaware 45-4502447
(State or Other Jurisdiction of
Incorporation or Organization)
 
(IRS Employer
Identification Number)
  
500 West Texas, Suite 1200
Midland, Texas
 79701
(Address of Principal Executive Offices) (Zip Code)
(432) 221-7400
(Registrant Telephone Number, Including Area Code)
 
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 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  ¨

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ý    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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. (Check One):
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 Exchange Act).    Yes  ¨    No  ý
As of November 2, 2018, 101,257,911 shares of the registrant’s common stock were outstanding.





DIAMONDBACK ENERGY, INC.
FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2018
TABLE OF CONTENTS
 








GLOSSARY OF OIL AND NATURAL GAS TERMS
The following is a glossary of certain oil and gas terms that are used in this Quarterly Report on Form 10-Q (this “report”):
BasinA large depression on the earth’s surface in which sediments accumulate.
BblStock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
BOEBarrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/dBOE per day.
British Thermal Unit or BtuThe quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
CompletionThe process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Crude oilLiquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
Finding and development costsCapital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.
Gross acres or gross wellsThe total acres or wells, as the case may be, in which a working interest is owned.
Horizontal drillingA drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle with a specified interval.
Horizontal wellsWells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.
Mb/dThousand barrels per day.
McfThousand cubic feet of natural gas.
Mineral interestsThe interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
MMBtuMillion British Thermal Units.
Net acres or net wellsThe sum of the fractional working interest owned in gross acres.
Oil and natural gas propertiesTracts of land consisting of properties to be developed for oil and natural gas resource extraction.
Plugging and abandonmentRefers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
ProspectA specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved reservesThe estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
ReservesThe estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves are not assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
ReservoirA porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Royalty interestAn interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development.
SpacingThe distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.

ii



Working interestAn operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

iii



GLOSSARY OF CERTAIN OTHER TERMS
The following is a glossary of certain other terms that are used in this report.
CompanyDiamondback Energy, Inc., a Delaware corporation.
Equity PlanThe Company’s Equity Incentive Plan.
Exchange ActThe Securities Exchange Act of 1934, as amended.
GAAPAccounting principles generally accepted in the United States.
General PartnerViper Energy Partners GP LLC, a Delaware limited liability company and the General Partner of the Partnership.
NYMEXNew York Mercantile Exchange.
PartnershipViper Energy Partners LP, a Delaware limited partnership.
Partnership AgreementThe first amended and restated agreement of limited partnership, dated June 23, 2014, entered into by the General Partner and Diamondback in connection with the closing of the Viper Offering.
Operating CompanyViper Energy Partners LLC, a Delaware limited liability company and a subsidiary of the Partnership.
SECUnited States Securities and Exchange Commission.
Securities ActThe Securities Act of 1933, as amended.
2024 Senior NotesThe Company’s 4.750% senior unsecured notes due 2024 in the aggregate principal amount of $500 million.
2025 Senior NotesThe Company’s 5.375% senior unsecured notes due 2025 in the aggregate principal amount of $500 million.
Senior NotesThe 2024 Senior Notes and the 2025 Senior Notes.
Viper LTIPViper Energy Partners LP Long Term Incentive Plan.
Viper OfferingThe Partnerships’ initial public offering.
Wells FargoWells Fargo Bank, National Association.


iv



CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act, and Section 21E of the Exchange Act. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed in this report and detailed under Part II, Item 1A. Risk Factors in this report and our Annual Report on Form 10–K for the year ended December 31, 2017 could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements.

Forward-looking statements may include statements about our:

business strategy;

exploration and development drilling prospects, inventories, projects and programs;

oil and natural gas reserves;

acquisitions, including our recent acquisition of certain leasehold acres and other assets from Ajax Resources, LLC and our pending acquisition of Energen Corporation discussed elsewhere in this report;

identified drilling locations;

ability to obtain permits and governmental approvals;

technology;

financial strategy;

realized oil and natural gas prices;

production;

lease operating expenses, general and administrative costs and finding and development costs;

future operating results; and

plans, objectives, expectations and intentions.

All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities laws. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.


v

Diamondback Energy, Inc. and Subsidiaries
Consolidated Balance Sheets
(Unaudited)



 September 30,December 31,
 20182017
 (In thousands, except par values and share data)
Assets  
Current assets:  
Cash and cash equivalents$508,446
$112,446
Accounts receivable:  
Joint interest and other81,955
73,038
Oil and natural gas sales182,362
158,575
Inventories14,815
9,108
Derivative instruments
531
Prepaid expenses and other8,111
4,903
Total current assets795,689
358,601
Property and equipment:  
Oil and natural gas properties, full cost method of accounting ($4,283,629 and $4,105,865 excluded from amortization at September 30, 2018 and December 31, 2017, respectively)10,818,378
9,232,694
Midstream assets355,758
191,519
Other property, equipment and land85,882
80,776
Accumulated depletion, depreciation, amortization and impairment(2,545,412)(2,161,372)
Net property and equipment8,714,606
7,343,617
Funds held in escrow62,034
6,304
Deferred tax asset95,551

Investment in real estate, net106,834

Other assets31,859
62,463
Total assets$9,806,573
$7,770,985
Liabilities and Stockholders’ Equity  
Current liabilities:  
Accounts payable-trade$85,869
$94,590
Accrued capital expenditures292,700
221,256
Other accrued liabilities143,792
92,512
Revenues and royalties payable75,600
68,703
Derivative instruments123,826
100,367
Total current liabilities721,787
577,428
Long-term debt2,332,359
1,477,347
Derivative instruments5,931
6,303
Asset retirement obligations23,897
20,122
Deferred income taxes292,795
108,048
Other long-term liabilities7

Total liabilities3,376,776
2,189,248
Commitments and contingencies (Note 16)  
Stockholders’ equity:  
Common stock, $0.01 par value, 200,000,000 shares authorized, 98,673,563 issued and outstanding at September 30, 2018; 98,167,289 issued and outstanding at December 31, 2017987
982
Additional paid-in capital5,464,542
5,291,011
Retained earnings (accumulated deficit)467,830
(37,133)
Total Diamondback Energy, Inc. stockholders’ equity5,933,359
5,254,860
Non-controlling interest496,438
326,877
Total equity6,429,797
5,581,737
Total liabilities and equity$9,806,573
$7,770,985
See accompanying notes to consolidated financial statements.

1

Diamondback Energy, Inc. and Subsidiaries
Consolidated Statements of Operations
(Unaudited)



 Three Months Ended September 30, Nine Months Ended September 30,
 20182017 20182017
 (In thousands, except per share amounts)
Revenues:     
Oil sales$454,644
$259,049
 $1,334,349
$704,007
Natural gas sales14,814
14,922
 40,557
37,537
Natural gas liquid sales57,610
25,266
 133,858
57,625
Lease bonus1,322
322
 2,250
2,507
Midstream services7,280
1,694
 26,658
4,241
Other operating income2,359

 6,825

Total revenues538,029
301,253
 1,544,497
805,917
Costs and expenses:     
Lease operating expenses49,111
32,498
 129,103
88,113
Production and ad valorem taxes33,536
18,371
 93,042
49,975
Gathering and transportation6,976
3,476
 18,074
9,110
Midstream services19,725
4,445
 48,515
7,127
Depreciation, depletion and amortization146,318
87,579
 391,401
221,681
General and administrative expenses (including non-cash equity-based compensation, net of capitalized amounts, of $5,350 and $6,187 for the three months ended September 30, 2018 and 2017, respectively, and $18,451 and $19,418 for the nine months ended September 30, 2018 and 2017, respectively)14,185
11,888
 45,039
37,524
Asset retirement obligation accretion387
357
 1,107
1,030
Other operating expense940

 2,416

Total costs and expenses271,178
158,614
 728,697
414,560
Income from operations266,851
142,639
 815,800
391,357
Other income (expense):     
Interest expense, net(18,548)(9,192) (49,345)(29,662)
Other income, net1,962
3
 89,170
9,472
Gain (loss) on derivative instruments, net(48,373)(50,645) (139,305)20,376
Gain (loss) on revaluation of investment(199)
 5,165

Total other income (expense), net(65,158)(59,834) (94,315)186
Income before income taxes201,693
82,805
 721,485
391,543
Provision for income taxes42,276
857
 82,750
4,393
Net income159,417
81,948
 638,735
387,150
Net income attributable to non-controlling interest2,363
8,924
 99,723
19,448
Net income attributable to Diamondback Energy, Inc.$157,054
$73,024
 $539,012
$367,702
Earnings per common share:

 

Basic$1.59
$0.74
 $5.47
$3.81
Diluted$1.59
$0.74
 $5.45
$3.80
Weighted average common shares outstanding:     
Basic98,638
98,144
 98,603
96,491
Diluted98,818
98,369
 98,820
96,752
Dividends declared per share$0.125
$
 $0.375
$





See accompanying notes to consolidated financial statements.

2

Diamondback Energy, Inc. and Subsidiaries
Consolidated Statements of Stockholders’ Equity
(Unaudited)


 Common StockAdditional Paid-in CapitalRetained Earnings (Accumulated Deficit)Non-Controlling InterestTotal
 SharesAmount
 (In thousands)
Balance December 31, 201690,144$901
$4,215,955
$(519,394)$320,830
$4,018,292
Net proceeds from issuance of common units - Viper Energy Partners LP



369,896
369,896
Unit-based compensation



2,039
2,039
Common units issued for acquisition



3,050
3,050
Stock-based compensation

23,790


23,790
Distribution to non-controlling interest



(27,640)(27,640)
Common shares issued in public offering, net of offering costs

14


14
Common shares issued for acquisition7,68677
809,096


809,173
Exercise of stock options and vesting of restricted stock units3374
355


359
Net income


367,702
19,448
387,150
Balance September 30, 201798,167$982
$5,049,210
$(151,692)$687,623
$5,586,123
       
Balance December 31, 201798,167$982
$5,291,011
$(37,133)$326,877
$5,581,737
Impact of adoption of ASU 2016-01, net of tax 

(9,393)(6,671)(16,064)
Net proceeds from issuance of common units - Viper Energy Partners LP 


303,137
303,137
Unit-based compensation



2,166
2,166
Stock-based compensation

23,613


23,613
Distribution to non-controlling interest



(68,801)(68,801)
Dividend paid


(24,656)
(24,656)
Exercise of stock options and vesting of restricted stock units5065
(5)
140
140
Change in ownership of consolidated subsidiaries, net 
149,923

(160,133)(10,210)
Net income


539,012
99,723
638,735
Balance September 30, 201898,674$987
$5,464,542
$467,830
$496,438
$6,429,797


















See accompanying notes to consolidated financial statements.

3

Diamondback Energy, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(Unaudited)

 Nine Months Ended September 30,
 20182017
   
 (In thousands)
Cash flows from operating activities:  
Net income$638,735
$387,150
Adjustments to reconcile net income to net cash provided by operating activities:  
Provision for deferred income taxes81,573
3,313
Asset retirement obligation accretion1,107
1,030
Depreciation, depletion and amortization391,401
221,681
Amortization of debt issuance costs2,291
2,828
Change in fair value of derivative instruments23,618
(9,365)
Income from equity investment
(309)
Gain on revaluation of investment(5,165)
Equity-based compensation expense18,451
19,418
Loss (gain) on sale of assets, net3,071
(386)
Changes in operating assets and liabilities:  
Accounts receivable(21,611)(23,422)
Accounts receivable-related party
283
Restricted cash
500
Inventories(14,196)(2,700)
Prepaid expenses and other(5,813)(9,242)
Accounts payable and accrued liabilities18,383
18,305
Accounts payable and accrued liabilities-related party
(2)
Accrued interest12,663
(1,738)
Income tax payable311
1,017
Revenues and royalties payable6,897
29,657
Net cash provided by operating activities1,151,716
638,018
Cash flows from investing activities:  
Additions to oil and natural gas properties(1,010,325)(531,489)
Additions to midstream assets(129,820)(22,491)
Purchase of other property, equipment and land(2,049)(21,534)
Acquisition of leasehold interests(185,658)(1,892,864)
Acquisition of mineral interests(335,574)(370,855)
Acquisition of midstream assets
(50,279)
Proceeds from sale of assets6,771
3,584
Investment in real estate(110,654)
Funds held in escrow(51,045)121,391
Equity investments(604)(188)
Net cash used in investing activities(1,818,958)(2,764,725)
Cash flows from financing activities:  
Proceeds from borrowings under credit facility1,027,500
533,000
Repayment under credit facility(1,221,500)(383,500)
Proceeds from senior notes1,062,000

Debt issuance costs(14,578)(1,714)
Public offering costs(2,636)(510)
Proceeds from public offerings305,773
370,344
Proceeds from exercise of unit options140

Proceeds from exercise of stock options
358
Dividends to stockholders(24,656)

4

Diamondback Energy, Inc. and Subsidiaries
Consolidated Statements of Cash Flows - Continued
(Unaudited)

 Nine Months Ended September 30,
 20182017
   
Distributions to non-controlling interest(68,801)(27,640)
Net cash provided by financing activities1,063,242
490,338
Net increase (decrease) in cash and cash equivalents396,000
(1,636,369)
Cash and cash equivalents at beginning of period112,446
1,666,574
Cash and cash equivalents at end of period$508,446
$30,205
   
Supplemental disclosure of cash flow information:  
Interest paid, net of capitalized interest$51,658
$28,702
Supplemental disclosure of non-cash transactions:  
Change in accrued capital expenditures$71,444
$129,105
Capitalized stock-based compensation$7,328
$6,411
Common stock issued for oil and natural gas properties$
$809,173
Asset retirement obligations acquired$270
$2,411




































See accompanying notes to consolidated financial statements.

5

Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements
(Unaudited)



1.    DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION

Organization and Description of the Business

Diamondback Energy, Inc. (“Diamondback” or the “Company”), together with its subsidiaries, is an independent oil and gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. Diamondback was incorporated in Delaware on December 30, 2011.

The wholly-owned subsidiaries of Diamondback, as of September 30, 2018, include Diamondback E&P LLC, a Delaware limited liability company, Diamondback O&G LLC, a Delaware limited liability company, Viper Energy Partners GP LLC, a Delaware limited liability company, Rattler Midstream LLC (formerly known as White Fang Energy LLC), a Delaware limited liability company, and Tall City Towers LLC, a Delaware limited liability company. The consolidated subsidiaries include these wholly-owned subsidiaries as well as Viper Energy Partners LP, a Delaware limited partnership (the “Partnership”), and the Partnership’s wholly-owned subsidiary Viper Energy Partners LLC, a Delaware limited liability company (the “Operating Company”).

Basis of Presentation

The consolidated financial statements include the accounts of the Company and its subsidiaries after all significant intercompany balances and transactions have been eliminated upon consolidation.

The Partnership is consolidated in the financial statements of the Company. As of September 30, 2018, the Company owned approximately 59% of the Partnership’s total units outstanding. The Company’s wholly-owned subsidiary, Viper Energy Partners GP LLC, is the General Partner of the Partnership.

These financial statements have been prepared by the Company without audit, pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been omitted pursuant to such rules and regulations, although the Company believes the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10–Q should be read in conjunction with the Company’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, 2017, which contains a summary of the Company’s significant accounting policies and other disclosures.

2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Certain amounts included in or affecting the Company’s consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates.

The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations, the fair value determination of acquired assets and liabilities assumed, equity-based compensation, fair value estimates of commodity derivatives and estimates of income taxes.

6


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)



Investments

The Partnership has an equity interest in a limited partnership that is so minor that the Partnership has no influence over the limited partnership’s operating and financial policies. This interest was acquired during the year ended December 31, 2014 and is accounted for under the cost method. Effective January 1, 2018, the Partnership adopted Accounting Standards Update 2016-01 which requires the Partnership to measure this investment at fair value which resulted in a downward adjustment of $18.7 million to record the impact of this adoption. For the three months and nine months ended September 30, 2018, the Partnership recorded a gain (loss) of $(0.2) million and $5.2 million, respectively. The Partnership’s investment balance as of September 30, 2018 was $20.2 million, which is included in other assets in the accompanying consolidated balance sheets.

Funds Held in Escrow

The funds held in escrow represent amounts in deposit to fund acquisitions. During the nine months ended September 30, 2018, there was $62.0 million in deposit to be applied to the purchase price for the acquisition of leasehold interests and related assets from Ajax Resources, LLC that closed on October 31, 2018. See Note 4— Acquisitions for information relating to this acquisition. During the nine months ended September 30, 2017, there was $6.3 million in deposit to fund other acquisitions which closed in the first quarter of 2018.

New Accounting Pronouncements

Recently Adopted Pronouncements

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. This standard included a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Among other things, the standard also eliminated industry-specific revenue guidance, required enhanced disclosures about revenue, provided guidance for transactions that were not previously addressed comprehensively and improved guidance for multiple-element arrangements. The Company adopted this Accounting Standards Update effective January 1, 2018 using the modified retrospective approach. The Company utilized a bottom-up approach to analyze the impact of the new standard by reviewing its current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard to its revenue contracts and the impact of adopting this standards update on its total revenues, operating income and its consolidated balance sheet. The adoption of this standard did not result in a cumulative-effect adjustment.

In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that holds financial assets or owes financial liabilities. This update requires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. The Partnership adopted this standard effective January 1, 2018 by means of a negative cumulative-effect adjustment totaling $18.7 million.

In August 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-15, “Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments”. This update apples to all entities that are required to present a statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The Company adopted this update effective January 1, 2018 using the retrospective transition method. Adoption of this standard did not have an effect on the presentation on the Statement of Cash Flows.


7


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


In November 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-18, “Statement of Cash Flows - Restricted Cash”. This update affects entities that have restricted cash or restricted cash equivalents. The Company adopted this update effective January 1, 2018. The adoption of this update did not have an effect on the presentation on the Statement of Cash Flows.

In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying the Definition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The Company adopted this update prospectively effective January 1, 2018. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.

Accounting Pronouncements Not Yet Adopted

In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases. The Company is still evaluating the impact of this standard.

In January 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-01, “Leases - Land Easement Practical Expedient for Transition to Topic 842”. This update applies to any entity that holds land easements. The update allows entities to adopt a practical expedient to not evaluate existing or expired land easements under Topic 842 that were not previously accounted for as leases under the current leases guidance. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. The Company believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-10, “Codification Improvements to Topic 842, Leases”. This update provides clarification and corrects unintended application of certain sections in the new lease guidance. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases. The Company is still evaluating the impact of this standard.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-11, “Lease (Topic 842): Targeted Improvements”. This update provides another transition method of allowing entities to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases. The Company is still evaluating the impact of this standard.


8


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believe the adoption of this standard will have a material impact on the Company’s consolidated financial statements since the Company does not have a history of credit losses.

In June 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-07, “Stock Compensation - Improvements to Nonemployee Share-Based Payment Accounting”. This update applies the existing employee guidance to nonemployee share-based transactions, with the exception of specific guidance related to the attribution of compensation cost. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-09, “Codification Improvements”. This update provides clarification and corrects unintended application of the guidance in various sections. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

In August 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-13, “Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement”. This update modifies the fair value measurement disclosure requirements specifically related to Level 3 fair value measurements and transfers between levels. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied prospectively. The Company is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

In August 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-15, “Intangibles - Goodwill and Other - Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract”. This update requires the capitalization of implementation costs incurred in a hosting arrangement that is a service contract for internal-use software. Training and certain data conversion costs cannot be capitalized. The entity is required to expense the capitalized implementation costs over the term of the hosting agreement. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update should be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. The Company believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity.

3.    REVENUE FROM CONTRACTS WITH CUSTOMERS

Revenue from Contracts with Customers

Sales of oil, natural gas and natural gas liquids are recognized at the point control of the product is transferred to the customer. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas and the prevailing supply and demand conditions. As a result, the price of the oil, natural gas and natural gas liquids fluctuates to remain competitive with other available oil, natural gas and natural gas liquids supplies.

Oil sales

The Company’s oil sales contracts are generally structured where it delivers oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, the Company or a third party transports the product to the delivery point and receives a specified index price from the purchaser with no deduction. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of any third-party transportation fees and other applicable differentials in the Company’s consolidated statements of operations.


9


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Natural gas and natural gas liquids sales

Under the Company’s natural gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead, battery facilities or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of natural gas liquids and residue gas. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For those contracts where the Company has concluded it is the principal and the ultimate third party is its customer, the Company recognizes revenue on a gross basis, with transportation, gathering, processing, treating and compression fees presented as an expense in its consolidated statements of operations.

In certain natural gas processing agreements, the Company may elect to take its residue gas and/or natural gas liquids in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing, treating and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing, treating and compression expense in its consolidated statements of operations.

Midstream Revenue

Substantially all revenues from gathering, compression, water handling, disposal and treatment operations are derived from intersegment transactions for services Rattler Midstream LLC (“Rattler”) provides to exploration and production operations. The portion of such fees shown in the Company’s consolidated financial statements represent amounts charged to interest owners in the Company’s operated wells, as well as fees charged to other third parties for water handling and treatment services provided by Rattler or usage of Rattler’s gathering and compression systems. For gathering and compression revenue, Rattler satisfies its performance obligations and recognizes revenue when low pressure volumes are delivered to a specified delivery point. Revenue is recognized based on the per MMbtu gathering fee or a per barrel gathering fee charged by Rattler in accordance with the gathering and compression agreement. For water handling and treatment revenue, Rattler satisfies its performance obligations and recognizes revenue when the fresh water volumes have been delivered to the fracwater meter for a specified well pad and the wastewater volumes have been metered downstream of the Company’s facilities. For services contracted through third party providers, Rattler’s performance obligation is satisfied when the service performed by the third party provider has been completed. Revenue is recognized based on the per barrel fresh water delivery or a wastewater gathering and disposal fee charged by Rattler in accordance with the water services agreement.

Transaction price allocated to remaining performance obligations

The Company’s upstream product sales contracts do not originate until production occurs and, therefore, are not considered to exist beyond each days’ production. Therefore, there are no remaining performance obligation under any of our product sales contracts.
The majority of the Company’s midstream revenue agreements have a term greater than one year, and as such Rattler LLC has utilized the practical expedient in ASC 606, which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under its revenue agreements, each delivery generally represents a separate performance obligation; therefore, future volumes delivered are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
The remainder of the Company’s midstream revenue agreements, which relate to agreements with third parties, are short-term in nature with a term of one year or less. Rattler LLC has utilized an additional practical expedient in ASC 606 which exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of an agreement that has an original expected duration of one year or less.


10


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Contract balances

Under the Company’s product sales contracts, it has the right to invoice its customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606.

Prior-period performance obligations

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the three months ended September 30, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Company believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the revenue related to expected sales volumes and prices for those properties are estimated and recorded.

4.    ACQUISITIONS

Tall City Towers LLC

On January 31, 2018, Tall City Towers LLC, a subsidiary of the Company, completed its acquisition of the Fasken Center office buildings in Midland, TX where the Company’s corporate offices are located for a net purchase price of $109.7 million.

Pending Merger with Energen Corporation

On August 14, 2018, the Company entered into a definitive merger agreement providing for the Company’s acquisition of Energen Corporation (“Energen”) in an all-stock transaction valued at approximately $9.2 billion including Energen’s net debt of $831.0 million as of June 30, 2018 (the “Pending Merger”). The addition of Energen’s assets will increase the Company’s assets to: (i) over 273,000 net Tier One acres in the Permian Basin, an increase of 57% from its current Tier One acreage of approximately 174,000 net acres, (ii) approximately 7,200 estimated total net horizontal Permian locations, an increase of over 120% from its current estimated net locations and (iii) approximately 394,000 net acres across the Midland and Delaware Basins, an increase of 82% from our approximately 216,000 net acres as September 30, 2018, in each case after giving effect to the Company’s recently completed Ajax Resources, LLC, ExL Management, LLC and EnergyQuest II LLC acquisitions described below.

The completion of the Pending Merger is subject to the satisfaction or waiver of certain customary mutual closing conditions. The Company’s registration statement on Form S-4 relating to the Pending Merger was declared effective by the SEC on October 24, 2018, and the Pending Merger is expected to be completed at the end of November of 2018.


11


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Under the terms of the merger agreement relating to the Pending Merger, the Company has agreed to assume Energen’s outstanding debt, which as of June 30, 2018 was approximately $831.0 million. This amount consists of $301.0 million of borrowings under Energen’s existing credit facility, $400.0 million aggregate principal amount of 4.625% Notes, due September 1, 2021, $20.0 million aggregate principal amount of 7.32% Medium-term Notes, Series A, due July 28, 2022, $10.0 million aggregate principal amount of 7.35% Medium-term Notes, Series A, due July 28, 2027, and $100.0 million aggregate principal amount of 7.125% Medium-term Notes, Series B, due February 15, 2028 (collectively, the “Energen Notes”). The Company may choose to refinance the Energen credit facility and the Company’s credit facility into a combined credit facility in connection with the consummation of the Pending Merger or the Company may choose to repay the outstanding borrowings under the Energen credit facility using cash on hand or borrowings under the Company’s revolving credit facility. With respect to the outstanding Energen Notes, the Company may take no action, or the Company may seek to amend the terms of the indenture governing the Energen Notes or engage in liability management transactions with respect to, repay or refinance any or all of the Energen Notes, with any repayment coming from cash on hand or borrowings under the Company’s revolving credit facility.

Ajax Resources, LLC

On July 22, 2018, the Company entered into a definitive purchase agreement to acquire all leasehold interests and related assets of Ajax Resources, LLC, which include approximately 25,493 net leasehold acres in the Northern Midland Basin, for $900.0 million in cash, subject to certain adjustments, and approximately 2.6 million shares of the Company’s common stock (the “Ajax acquisition”). This transaction closed on October 31, 2018 and was effective as of July 1, 2018. The cash portion of this transaction was funded through a combination of cash on hand, proceeds from the sale of mineral interests to the Partnership (described below), borrowing under the Company’s revolving credit facility and a portion of the proceeds from the Company’s September 2018 senior note offering. See Note 9—Debt for information relating to this offering.

In connection with the closing of the Ajax acquisition on October 31, 2018, the Company entered into a registration rights agreement with Ajax Resources, LLC and certain other holders of the Company’s common stock. Pursuant to this agreement, the Company agreed to (i) file with the SEC a shelf registration statement to facilitate the resale of common stock issued in the Ajax acquisition and any shares of common stock that may be issued or distributed in respect of such shares upon certain events and (ii) use its reasonable best efforts to cause such registration statement to become effective by November 30, 2018. Pursuant to this registration rights agreement, the Company also agreed to provide certain demand and piggyback registration rights to such holders.

ExL Petroleum Management, LLC and EnergyQuest II LLC

On September 21, 2018, the Company entered into two definitive purchase agreements to acquire leasehold interests and related assets, one with ExL Petroleum Management, LLC and ExL Petroleum Operating, Inc. and one with EnergyQuest II LLC, for an aggregate of approximately 3,646 net leasehold acres in the Northern Midland Basin for a total of $312.5 million in cash, subject to certain adjustments. These transactions closed on October 31, 2018 and were effective as of August 1, 2018. These transactions were funded through a combination of cash on hand, proceeds from the sale of assets to the Partnership (described below) and borrowing under the Company’s revolving credit facility.

Drop-down Transaction

On August 15, 2018, the Company completed a transaction to sell to the Partnership mineral interests underlying 32,424 gross (1,696 net royalty) acres primarily in Pecos County, Texas, in the Permian Basin, approximately 80% of which are operated by the Company, for $175.0 million (the “Drop-down Transaction”).

12


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Oil and Natural Gas Properties

On February 28, 2017, the Company completed its acquisition of certain oil and natural gas properties, midstream assets and other related assets in the Delaware Basin for an aggregate purchase price consisting of $1.74 billion in cash and 7.69 million shares of the Company’s common stock, of which approximately 1.15 million shares were placed in an indemnity escrow. This transaction included the acquisition of (i) approximately 100,306 gross (80,339 net) acres primarily in Pecos and Reeves counties for approximately $2.5 billion and (ii) midstream assets for approximately $47.6 million. The Company used the net proceeds from its December 2016 equity offering, net proceeds from its December 2016 debt offering, cash on hand and other financing sources to fund the cash portion of the purchase price for this acquisition.

The following represents the fair value of the assets and liabilities assumed on the acquisition date. The aggregate consideration transferred was $2.5 billion, resulting in no goodwill or bargain purchase gain.
 (in thousands)
Proved oil and natural gas properties$386,308
Unevaluated oil and natural gas properties2,122,597
Midstream assets47,432
Prepaid capital costs3,460
Oil inventory839
Equipment163
Revenues and royalties payable(9,650)
Asset retirement obligations(1,550)
Total fair value of net assets$2,549,599

The Company included in its consolidated statements of operations revenues of $84.3 million and direct operating expenses of $16.0 million for the period from February 28, 2017 to September 30, 2017 due to the acquisition.

Pro Forma Financial Information

The following unaudited summary pro forma consolidated statement of operations data of Diamondback for the three months and nine months ended September 30, 2017 have been prepared to give effect to the February 28, 2017 acquisition as if it had occurred on January 1, 2016. The pro forma data are not necessarily indicative of financial results that would have been attained had the acquisitions occurred on January 1, 2016. The pro forma data also necessarily exclude various operation expenses related to the properties and the financial statements should not be viewed as indicative of operations in future periods.
 Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017
 (in thousands, except per share amounts)
Revenues$301,253
 $828,846
Income from operations142,639
 405,699
Net income81,948
 382,044
Basic earnings per common share0.74
 3.96
Diluted earnings per common share0.74
 3.95

5.    VIPER ENERGY PARTNERS LP

The Partnership is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Market under the symbol “VNOM”. The Partnership was formed by Diamondback on February 27, 2014, to, among other things, own, acquire and exploit oil and natural gas properties in North America. The Partnership is currently focused on oil and natural gas properties in the Permian Basin and the Eagle Ford Shale. Viper Energy Partners GP LLC, a fully-consolidated subsidiary of Diamondback, serves as the general partner of the Partnership. As of September 30, 2018, the Company owned approximately 59% of the Partnership’s total units outstanding.

Recapitalization, Tax Status Election and Related Transactions by Viper

In March 2018, the Partnership announced that the Board of Directors of the General Partner had unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election. In connection with making this election, on May 9, 2018 the Partnership (i) amended and restated its First Amended and Restated Partnership Agreement, (ii) amended and restated the First Amended and Restated Limited Liability Company Agreement of the Operating Company, (iii) amended and restated its existing registration rights agreement with the Company and (iv) entered into an exchange agreement with the Company, the General Partner and the Operating Company. Simultaneously with the effectiveness of these agreements, the Company delivered and assigned to the Partnership the 73,150,000 common units the Company owned in exchange

13


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


for (i) 73,150,000 of the Partnership’s newly-issued Class B units and (ii) 73,150,000 newly-issued units of the Operating Company pursuant to the terms of a Recapitalization Agreement dated March 28, 2018, as amended as of May 9, 2018 (the “Recapitalization Agreement”). Immediately following that exchange, the Partnership continued to be the managing member of the Operating Company, with sole control of its operations, and owned approximately 36% of the outstanding units issued by the Operating Company, and the Company owned the remaining approximately 64% of the outstanding units issued by the Operating Company. Upon completion of the Partnership’s July 2018 offering of units, it owned approximately 41% of the outstanding units issued by the Operating Company and the Company owned the remaining approximately 59%. The Operating Company units and the Partnership’s Class B units owned by the Company are exchangeable from time to time for the Partnership’s common units (that is, one Operating Company unit and one Partnership Class B unit, together, will be exchangeable for one Partnership common unit).

On May 10, 2018, the change in the Partnership’s income tax status became effective. On that date, pursuant to the terms of the Recapitalization Agreement, (i) the General Partner made a cash capital contribution of $1.0 million to the Partnership in respect of its general partner interest and (ii) the Company made a cash capital contribution of $1.0 million to the Partnership in respect of the Class B units. The Company, as the holder of the Class B units, and the General Partner, as the holder of the general partner interest, are entitled to receive an 8% annual distribution on the outstanding amount of these capital contributions, payable quarterly, as a return on this invested capital. On May 10, 2018, the Company also exchanged 731,500 Class B units and 731,500 units in the Operating Company for 731,500 common units of the Partnership and a cash amount of $10,000 representing a proportionate return of the $1.0 million invested capital in respect of the Class B units. The General Partner continues to serve as the Partnership’s general partner and the Company continues to control the Partnership. After the effectiveness of the tax status election and the completion of related transactions, the Partnership’s minerals business continues to be conducted through the Operating Company, which continues to be taxed as a partnership for federal and state income tax purposes. This structure is anticipated to provide significant benefits to the Partnership’s business, including operational effectiveness, acquisition and disposition transactional planning flexibility and income tax efficiency. For additional information regarding the tax status election and related transactions, please refer to the Partnership’s Definitive Information Statement on Schedule 14C filed with the SEC on April 17, 2018 and the Partnership’s Current Report on Form 8-K filed with the SEC on May 15, 2018.

Partnership Agreement

The second amended and restated agreement of limited partnership, dated as of May 9, 2018, as amended as of May 10, 2018 (the “Partnership Agreement”), requires the Partnership to reimburse the General Partner for all direct and indirect expenses incurred or paid on the Partnership’s behalf and all other expenses allocable to the Partnership or otherwise incurred by the General Partner in connection with operating the Partnership’s business. The Partnership Agreement does not set a limit on the amount of expenses for which the General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for the Partnership or on its behalf and expenses allocated to the General Partner by its affiliates. The General Partner is entitled to determine the expenses that are allocable to the Partnership. For the three months ended September 30, 2018 and 2017, the General Partner allocated $0.6 million to the Partnership. For the nine months ended September 30, 2018 and 2017, the General Partner allocated $1.8 million to the Partnership.

Tax Sharing

In connection with the closing of the Viper Offering, the Partnership entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which the Partnership agreed to reimburse Diamondback for its share of state and local income and other taxes for which the Partnership’s results are included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of any such reimbursement is limited to the tax the Partnership would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which the Partnership may be a member for this purpose, to owe less or no tax. In such a situation, the Partnership agreed to reimburse Diamondback for the tax the Partnership would have owed had the tax attributes not been available or used for the Partnership’s benefit, even though Diamondback had no cash tax expense for that period. For the three months and nine months ended September 30, 2018, the Partnership accrued state income tax expense (benefit) of $(0.1) million and $0.1 million, respectively, for its share of Texas margin tax for which the Partnership’s results are included in a combined tax return filed by Diamondback.


14


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Other Agreements

See Note 12—Related Party Transactions for information regarding the advisory services agreement the Partnership and the General Partner entered into with Wexford Capital LP (“Wexford”).

The Partnership has entered into a secured revolving credit facility with Wells Fargo, as administrative agent sole book runner and lead arranger. See Note 9—Debt for a description of this credit facility.

6.    PROPERTY AND EQUIPMENT

Property and equipment includes the following:
 September 30,December 31,
 20182017
   
 (in thousands)
Oil and natural gas properties:  
Subject to depletion$6,534,749
$5,126,829
Not subject to depletion4,283,629
4,105,865
Gross oil and natural gas properties10,818,378
9,232,694
Accumulated depletion(1,375,163)(1,009,893)
Accumulated impairment(1,143,498)(1,143,498)
Oil and natural gas properties, net8,299,717
7,079,303
Midstream assets355,758
191,519
Other property, equipment and land85,882
80,776
Accumulated depreciation(26,751)(7,981)
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment$8,714,606
$7,343,617
   
Balance of costs not subject to depletion:  
Incurred in 2018$589,352
 
Incurred in 20172,563,902
 
Incurred in 2016714,467
 
Incurred in 2015234,948
 
Incurred in 2014180,960
 
Total not subject to depletion$4,283,629
 


15


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. Costs, including related employee costs, associated with production and operation of the properties are charged to expense as incurred. All other internal costs not directly associated with exploration and development activities are charged to expense as they are incurred. Capitalized internal costs were approximately $6.7 million and $5.7 million for the three months ended September 30, 2018 and 2017, respectively, and $20.4 million and $15.9 million for the nine months ended September 30, 2018 and 2017, respectively. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within three to five years. Acquisition costs not currently being amortized are primarily related to unproved acreage that the Company plans to prove up through drilling. The Company has no plans to let any acreage expire. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas.

Under this method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives, if any, that hedge the Company’s oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required.

At September 30, 2018, there was $50.1 million in exploration costs and development costs and $42.0 million in capitalized interest that was not subject to depletion. At December 31, 2017, there were $26.0 million in exploration costs and development costs and $22.1 million in capitalized interest that was not subject to depletion.

7.    ASSET RETIREMENT OBLIGATIONS

The following table describes the changes to the Company’s asset retirement obligation liability for the following periods:
 Nine Months Ended September 30,
 20182017
   
 (in thousands)
Asset retirement obligations, beginning of period$21,285
$17,422
Additional liabilities incurred2,229
1,196
Liabilities acquired270
2,411
Liabilities settled(1,474)(689)
Accretion expense1,107
1,030
Revisions in estimated liabilities568
4
Asset retirement obligations, end of period23,985
21,374
Less current portion88
1,392
Asset retirement obligations - long-term$23,897
$19,982

The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The Company estimates the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance. The current portion of the asset retirement obligation liability is included in other accrued liabilities in the Company’s consolidated balance sheets.


16


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


8.    EQUITY METHOD INVESTMENTS

In October 2014, the Company obtained a 25% interest in HMW Fluid Management LLC (“HMW LLC”), which was formed to develop, own and operate an integrated water management system to gather, store, process, treat, distribute and dispose of water to exploration and production companies operating in Midland, Martin and Andrews Counties, Texas. On June 30, 2018, HMW LLC’s operating agreement was amended effective January 1, 2018. As a result of the amendment, the Company will no longer recognize an equity investment in HMW LLC but will instead consolidate its interests in the net assets of HMW LLC. In exchange for the Company’s 25% investment, the Company received a 50% undivided ownership interest in two of the four salt water disposal wells and associated assets previously owned by HMW LLC. The Company’s basis in the assets is equivalent to its basis in the equity investment in HMW LLC. During the nine months ended September 30, 2017, the Company invested $0.2 million in this entity and recorded $0.3 million, which is the Company’s share of HMW LLC’s net income, bringing its total investment to $6.8 million at September 30, 2017.

9.    DEBT

Long-term debt consisted of the following as of the dates indicated:
 September 30,December 31,
 20182017
   
 (in thousands)
4.750 % Senior Notes due 2024$1,250,000
$500,000
5.375 % Senior Notes due 2025800,000
500,000
Unamortized debt issuance costs(25,038)(13,153)
Unamortized premium costs10,897

Revolving credit facility
397,000
Partnership revolving credit facility296,500
93,500
Total long-term debt$2,332,359
$1,477,347

2024 Senior Notes

On October 28, 2016, the Company issued $500.0 million in aggregate principal amount of 4.750% Senior Notes due 2024 (the “2024 Senior Notes”). The 2024 Senior Notes bear interest at a rate of 4.750% per annum, payable semi-annually, in arrears on May 1 and November 1 of each year, commencing on May 1, 2017 and will mature on November 1, 2024. All of the Company’s existing and future restricted subsidiaries that guarantee its revolving credit facility or certain other debt guarantee the 2024 Senior Notes; provided, however, that the 2024 Senior Notes are not guaranteed by the Partnership, the General Partner, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of the Company’s future unrestricted subsidiaries.

On September 25, 2018, the Company issued $750.0 million aggregate principal amount of new 4.750% Senior Notes due 2024 (the “New 2024 Notes”) as additional notes under, and subject to the terms of, the 2024 Indenture. The New 2024 Notes were issued in a transaction exempt from the registration requirements under the Securities Act. The Company received approximately $740.7 million in net proceeds, after deducting the initial purchasers’ discount and its estimated offering expenses, but disregarding accrued interest, from the issuance of the New 2024 Notes. The Company used a portion of the net proceeds from the issuance of the New 2024 Notes to repay the outstanding borrowings under its revolving credit facility and intends to use the balance for general corporate purposes, including funding a portion of the cash consideration for the acquisition of assets from Ajax Resources, LLC.


17


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


The 2024 Senior Notes were issued under, and are governed by, an indenture among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented (the “2024 Indenture”). The 2024 Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit the Company’s ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make other distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting the Company’s restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and natural gas business and designate certain of the Company’s subsidiaries as unrestricted subsidiaries.

The Company may on any one or more occasions redeem some or all of the 2024 Senior Notes at any time on or after November 1, 2019 at the redemption prices (expressed as percentages of principal amount) of 103.563% for the 12-month period beginning on November 1, 2019, 102.375% for the 12-month period beginning on November 1, 2020, 101.188% for the 12-month period beginning on November 1, 2021 and 100.000% beginning on November 1, 2022 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to November 1, 2019, the Company may on any one or more occasions redeem all or a portion of the 2024 Senior Notes (including the New 2024 Notes) at a price equal to 100% of the principal amount of the 2024 Senior Notes (including the New 2024 Notes) plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to November 1, 2019, the Company may on any one or more occasions redeem the 2024 Senior Notes (including the New 2024 Notes) in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2024 Senior Notes (including the New 2024 Notes) issued prior to such date at a redemption price of 104.750%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings.

2025 Senior Notes

On December 20, 2016, the Company issued $500.0 million in aggregate principal amount of 5.375% Senior Notes due 2025 (the “2025 Senior Notes”). The 2025 Senior Notes bear interest at a rate of 5.375% per annum, payable semi-annually, in arrears on May 31 and November 30 of each year, commencing on May 31, 2017 and will mature on May 31, 2025. All of the Company’s existing and future restricted subsidiaries that guarantee its revolving credit facility or certain other debt guarantee the 2025 Senior Notes, provided, however, that the 2025 Senior Notes are not guaranteed by the Partnership, the General Partner, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of the Company’s future unrestricted subsidiaries.
On January 29, 2018, the Company issued $300.0 million aggregate principal amount of new 5.375% Senior Notes due 2025 (the “New 2025 Notes”) as additional notes under, and subject to the terms of, the 2025 Indenture. The New 2025 Notes were issued in a transaction exempt from the registration requirements under the Securities Act. The Company received approximately $308.4 million in net proceeds, after deducting the initial purchaser’s discount and its estimated offering expenses, but disregarding accrued interest, from the issuance of the New 2025 Notes. The Company used the net proceeds from the issuance of the New 2025 Notes to repay a portion of the outstanding borrowings under its revolving credit facility.
The 2025 Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit the Company’s ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make other distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting the Company’s restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of the Company’s assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and natural gas business and designate certain of the Company’s subsidiaries as unrestricted subsidiaries.

18


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


The Company may on any one or more occasions redeem some or all of the 2025 Senior Notes (including the New 2025 Notes) at any time on or after May 31, 2020 at the redemption prices (expressed as percentages of principal amount) of 104.031% for the 12-month period beginning on May 31, 2020, 102.688% for the 12-month period beginning on May 31, 2021, 101.344% for the 12-month period beginning on May 31, 2022 and 100.000% beginning on May 31, 2023 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to May 31, 2020, the Company may on any one or more occasions redeem all or a portion of the 2025 Senior Notes (including the New 2025 Notes) at a price equal to 100% of the principal amount of the 2025 Senior Notes (including the New 2025 Notes) plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to May 31, 2020, the Company may on any one or more occasions redeem the 2025 Senior Notes (including the New 2025 Notes) in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2025 Senior Notes (including the New 2025 Notes) issued prior to such date at a redemption price of 105.375%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings.

The Company’s Credit Facility

The Company and Diamondback O&G LLC, as borrower, entered into the second amended and restated credit agreement, dated November 1, 2013, as amended, with a syndicate of banks, including Wells Fargo, as administrative agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger. The credit agreement provides for a revolving credit facility in the maximum credit amount of $5.0 billion, subject to a borrowing base based on the Company’s oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be redetermined, under certain circumstances, annually with an effective date of May 1st, and, under certain circumstances, semi-annually with effective dates of May 1st and November 1st. In addition, the Company and Wells Fargo may each request up to two interim redeterminations of the borrowing base during any 12-month period. As of September 30, 2018, the borrowing base was set at $2.0 billion, the Company had elected a commitment amount of $1.0 billion and the Company had no outstanding borrowings under the revolving credit facility and $1.0 billion available for future borrowings under its revolving credit facility. On October 26, 2018, the credit agreement was amended to increase the borrowing base to $2.5 billion, which was increased further to $2.65 billion on November 6, 2018 following the closing of the Company’s acquisition of assets from Ajax Resources, LLC and satisfaction of certain other conditions. The Company also elected to increase the commitment amount from $1.0 billion to $2.0 billion effective October 26, 2018. In addition, this amendment increased the Company’s flexibility to make restricted payments and redeem senior unsecured notes.
Diamondback O&G LLC is the borrower under the credit agreement. As of December 31, 2017, the credit agreement is guaranteed by the Company, Diamondback E&P LLC and Rattler Midstream LLC (formerly known as White Fang Energy LLC) and will also be guaranteed by any of the Company’s future subsidiaries that are classified as restricted subsidiaries under the credit agreement. The credit agreement is also secured by substantially all of the assets of the Company, Diamondback O&G LLC and the guarantors.
The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by the Company that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5%, and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.25% to 1.25% in the case of the alternate base rate and from 1.25% to 2.25% in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the least of the maximum credit amount, the borrowing base and the elected commitment amount. The Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2022.

19


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.
Financial Covenant Required Ratio
Ratio of total net debt to EBITDAX, as defined in the credit agreementNot greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreementNot less than 1.0 to 1.0

The covenant prohibiting additional indebtedness, as amended in November 2017, allows for the issuance of unsecured debt in the form of senior or senior subordinated notes if no default would result from the incurrence of such debt after giving effect thereto and if, in connection with any such issuance, the borrowing base is reduced by 25% of the stated principal amount of each such issuance.
As of September 30, 2018 and December 31, 2017, the Company was in compliance with all financial covenants under its revolving credit facility, as then in effect. The lenders may accelerate all of the indebtedness under the Company’s revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.

The Partnership’s Credit Agreement

On July 8, 2014, the Partnership entered into a secured revolving credit agreement with Wells Fargo, as administrative agent, certain other lenders and the Operating Company, the Partnership’s consolidated subsidiary, as guarantor. On May 8, 2018, the Operating Company assumed all liabilities as borrower under the credit agreement and the Partnership became a guarantor of the credit agreement. On July 20, 2018, the Operating Company, the Partnership, Wells Fargo and the other lenders amended and restated the credit agreement to reflect the assumption by the Operating Company.

The credit agreement, as amended and restated, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on the Partnership’s oil and natural gas reserves and other factors (the “borrowing base”) of $475.0 million, subject to scheduled semi-annual and other borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and October 26th. In addition, the Operating Company and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12-month period. As of September 30, 2018, the borrowing base was set at $475.0 million, and there was $296.5 million of outstanding borrowings and $178.5 million available for future borrowings under the revolving credit facility. In connection with the Partnership’s fall 2018 redetermination, the Partnership’s borrowing base was increased to $555.0 million effective October 26, 2018.

The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by the Operating Company that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.75% to 1.75% per annum in the case of the alternate base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount and the borrowing base. The Operating Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (i) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (ii) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (iii) at the maturity date of November 1, 2022. The loan is secured by substantially all of the assets of the Partnership and the Operating Company.


20


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, purchases of margin stock, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements, and require the maintenance of the financial ratios described below:
Financial Covenant Required Ratio
Ratio of total net debt to EBITDAX, as defined in the credit agreementNot greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreementNot less than 1.0 to 1.0

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $400.0 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.

The lenders may accelerate all of the indebtedness under the credit agreement upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.

Alliance with Obsidian Resources, L.L.C.
The Company entered into a participation and development agreement (the “DrillCo Agreement”), dated September 10, 2018, with Obsidian Resources, L.L.C. (“CEMOF”) to fund oil and natural gas development. Funds managed by CEMOF and its affiliates have agreed to commit to funding certain costs out of CEMOF’s net production revenue and, for a period of time, to the extent not funded by such revenue, up to an additional $300.0 million, to fund drilling programs on locations provided by the Company. Subject to adjustments depending on asset characteristics and return expectations of the selected drilling plan, CEMOF will fund up to 85% of the costs associated with new wells drilled under the DrillCo Agreement and is expected to receive an 80% working interest in these wells until it reaches certain payout thresholds equal to a cumulative 9% and then 13% internal rate of return. Upon reaching the final internal rate of return target, CEMOF’s interest will be reduced to 15%, while the Company’s interest will increase to 85%.

10.    CAPITAL STOCK AND EARNINGS PER SHARE

Diamondback did not complete any equity offerings during the nine months ended September 30, 2018 and September 30, 2017.

Partnership Equity Offerings

In January 2017, the Partnership completed an underwritten public offering of 9,775,000 common units, which included 1,275,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. The Partnership received net proceeds from this offering of approximately $147.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which the Partnership used $120.5 million to repay the outstanding borrowings under its revolving credit agreement and the balance was used for general partnership purposes, which included additional acquisitions.
In July 2017, the Partnership completed an underwritten public offering of 16,100,000 common units, which included 2,100,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. In this offering, the Company purchased 700,000 common units, an affiliate of the General Partner purchased 3,000,000 common units and certain officers and directors of the Company and the General Partner purchased an aggregate of 114,000 common units, in each case directly from the underwriters. The Partnership received net proceeds from this offering of approximately $232.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which the Partnership used $152.8 million to repay all of the then-outstanding borrowings under the Partnership’s revolving credit facility and the balance was used to fund a portion of the purchase price for acquisitions and for general partnership purposes.
In July 2018, the Partnership completed an underwritten public offering of 10,080,000 common units, which included 1,080,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Following this offering, Diamondback owned approximate 59% of the total Partnership units then outstanding. The Partnership received net proceeds from this offering of approximately $303.1 million, after deducting underwriting discounts and commissions and estimated offering expenses. The Partnership used the net proceeds to purchase units of the Operating Company. The Operating Company in turn used the net proceeds to repay a portion of the $361.5 million then outstanding borrowings under its revolving credit facility.

Earnings Per Share

The Company’s basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted earnings per share include the effect of potentially dilutive shares outstanding for the period. Additionally, for the diluted earnings per share computation, the per share earnings of the Partnership are included in the consolidated earnings per share computation based on the consolidated group’s holdings of the subsidiary.


21


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:
 Three Months Ended September 30, Nine Months Ended September 30,
 20182017 20182017
 (in thousands, except per share amounts)
Net income attributable to common stock$157,054
$73,024
 $539,012
$367,702
Weighted average common shares outstanding     
Basic weighted average common units outstanding98,638
98,144
 98,603
96,491
Effect of dilutive securities:     
Potential common shares issuable180
225
 217
261
Diluted weighted average common shares outstanding98,818
98,369
 98,820
96,752
Basic net income attributable to common stock$1.59
$0.74
 $5.47
$3.81
Diluted net income attributable to common stock$1.59
$0.74
 $5.45
$3.80

For the three months ended September 30, 2018 and 2017, there were 12,699 shares and 52,857 shares, respectively, and during the nine months ended September 30, 2018 and 2017, there were 2,300 and 1,248 shares, respectively, that were not included in the computation of diluted earnings per share because their inclusion would have been anti-dilutive for the periods presented. These shares could dilute basic earnings per share in future periods.

11.    EQUITY-BASED COMPENSATION

The following table presents the effects of the equity compensation plans and related costs:
 Three Months Ended September 30, Nine Months Ended September 30,
 20182017 20182017
 (in thousands)
General and administrative expenses$5,350
$6,187
 $18,451
$19,418
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties2,338
2,167
 7,328
6,411

Restricted Stock Units

The following table presents the Company’s restricted stock units activity under the Equity Plan during the nine months ended September 30, 2018:
 Restricted Stock
Awards & Units
Weighted Average Grant-Date
Fair Value
Unvested at December 31, 2017243,577
$90.88
Granted90,115
$115.03
Vested(170,014)$89.08
Forfeited(7,597)$95.80
Unvested at September 30, 2018156,081
$106.54

The aggregate fair value of restricted stock units that vested during the nine months ended September 30, 2018 and 2017 was $15.1 million and $14.8 million, respectively. As of September 30, 2018, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $13.0 million. Such cost is expected to be recognized over a weighted-average period of 1.4 years.


22


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Performance Based Restricted Stock Units

To provide long-term incentives for the executive officers to deliver competitive returns to the Company’s stockholders, the Company has granted performance-based restricted stock units to eligible employees. The ultimate number of shares awarded from these conditional restricted stock units is based upon measurement of total stockholder return of the Company’s common stock (“TSR”) as compared to a designated peer group during a two-year or three-year performance period.

In February 2018, eligible employees received performance restricted stock unit awards totaling 117,423 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2018 to December 31, 2020 and cliff vest at December 31, 2020.

The fair value of each performance restricted stock unit is estimated at the date of grant using a Monte Carlo simulation, which results in an expected percentage of units to be earned during the performance period.

The following table presents a summary of the grant-date fair values of performance restricted stock units granted and the related assumptions for the February 2018 awards.
 2018
 Three-Year Performance Period
Grant-date fair value$170.45
Risk-free rate1.99%
Company volatility35.90%

The following table presents the Company’s performance restricted stock units activity under the Equity Plan for the nine months ended September 30, 2018:
 Performance Restricted Stock UnitsWeighted Average Grant-Date Fair Value
Unvested at December 31, 2017202,326
$139.83
Granted285,737
$130.96
Vested(168,314)$103.41
Unvested at September 30, 2018(1)
319,749
$151.08
(1)A maximum of 639,498 units could be awarded based upon the Company’s final TSR ranking.

As of September 30, 2018, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $23.0 million. Such cost is expected to be recognized over a weighted-average period of 1.2 years.

Partnership Unit Options

The following table presents the unit option activity under the Viper LTIP for the nine months ended September 30, 2018:
   Weighted Average  
 Unit Options Exercise Price Remaining Term Intrinsic
Value
     (in years) (in thousands)
Outstanding at December 31, 20177,600
 $18.49
    
Exercised(7,600) $18.49
    
Outstanding at September 30, 2018
 $
 0.00 $


23


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


The aggregate intrinsic value of unit options that were exercised during the nine months ended September 30, 2018 were $0.2 million.

Phantom Units

Under the Viper LTIP, the Board of Directors of the General Partner is authorized to issue phantom units to eligible employees. The Partnership estimates the fair value of phantom units as the closing price of the Partnership’s common units on the grant date of the award, which is expensed over the applicable vesting period. Upon vesting the phantom units entitle the recipient one common unit of the Partnership for each phantom unit.

The following table presents the phantom unit activity under the Viper LTIP for the nine months ended September 30, 2018.
 Phantom Units Weighted Average Grant-Date
Fair Value
Unvested at December 31, 2017105,439
 $17.10
Granted119,818
 $24.46
Vested(102,811) $19.23
Unvested at September 30, 2018122,446
 $22.52

The aggregate fair value of phantom units that vested during the nine months ended September 30, 2018 was $2.0 million. As of September 30, 2018, the unrecognized compensation cost related to unvested phantom units was $2.0 million. Such cost is expected to be recognized over a weighted-average period of 1.3 years.

12.    RELATED PARTY TRANSACTIONS

Advisory Services Agreement - The Partnership

In connection with the closing of the Viper Offering, the Partnership and the General Partner entered into an advisory services agreement (the “Viper Advisory Services Agreement”) with Wexford, dated as of June 23, 2014, under which Wexford provides the Partnership and the General Partner with general financial and strategic advisory services related to the business in return for an annual fee of $0.5 million, plus reasonable out-of-pocket expenses. The Viper Advisory Services Agreement had an initial term of two years commencing on June 23, 2014, and will continue for additional one-year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. The Partnership did not pay any amounts during the three months and nine months ended September 30, 2018 or September 30, 2017 under the Viper Advisory Services Agreement.

Lease Bonus - The Partnership
During the three months and nine months ended September 30, 2018, the Company paid the Partnership $2.9 million in lease bonus payments to extend the term of 12 leases, reflecting an average bonus of $6,412 per acre. During the three months ended September 30, 2017, the Company did not pay the Partnership any lease bonus payments. During the nine months ended September 30, 2017, the Company paid the Partnership $0.1 million in lease bonus payments to extend the term of two leases, reflecting an average bonus of $7,459 per acre.

24


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


13.    INCOME TAXES

The Company’s effective income tax rates were 11.5% and 1.2% for the nine months ended September 30, 2018 and 2017, respectively. Total income tax expense for the nine months ended September 30, 2018 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income primarily due to (i) the impact of deferred taxes recognized by the Partnership as a result of its change in tax status, (ii) current and deferred state income taxes, (iii) net income attributable to the non-controlling interest, and (iv) the impact of permanent differences between book and taxable income. The Company recorded a discrete income tax benefit of approximately $0.8 million related to equity-based compensation for the nine months ended September 30, 2018 and a discrete benefit of approximately $72.7 million related to deferred taxes on the Partnership’s investment in the Operating Company arising from the change in the Partnership’s tax status. Total income tax expense for the nine months ended September 30, 2017differed from amounts computed by applying the federal statutory rate to pre-tax income primarily due to state income taxes and the change in the valuation allowance which offset the Company’s federal net deferred tax position in that period.

The Tax Cuts and Jobs Act, a historic reform of the U.S. federal income tax statutes, was enacted on December 22, 2017. As of the completion of the Company’s financial statements for the year ended December 31, 2017, the Company had substantially completed its accounting for the effects of the enactment of the Tax Cuts and Jobs Act and, with respect to those items for which the Company’s accounting was not complete, the Company made reasonable estimates of the effects on its deferred tax balances. At September 30, 2018, the Company had not made an adjustment to the provisional estimates recorded for the year ended December 31, 2017. The Company has considered in its estimated annual effective tax rate for 2018 the impact of the statutory changes enacted by the Tax Cuts and Jobs Act, including reasonable estimates of those provisions effective for the 2018 tax year.

As discussed further in Note 5, on March 29, 2018, the Partnership announced that the Board of Directors of its General Partner had unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity, which change became effective on May 10, 2018. The transactions undertaken in connection with the change in the Partnership’s tax status were not taxable to the Company. Subsequent to the Partnership’s change in tax status, the Partnership’s provision for income taxes for the period ended September 30, 2018 is based on its estimated annual effective tax rate plus discrete items. As such, the Partnership’s provision for income taxes is included in the Company’s consolidated financial statements and to the extent applicable, in net income attributable to the non-controlling interest.

14.    DERIVATIVES

All derivative financial instruments are recorded at fair value. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash changes in fair value in the combined consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”

The Company has used fixed price swap contracts, fixed price basis swap contracts and three-way costless collars with corresponding put, short put and call options to reduce price volatility associated with certain of its oil and natural gas sales. With respect to the Company’s fixed price swap contracts and fixed price basis swap contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap or basis price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap or basis price. The Company has fixed price basis swaps for the spread between the WTI Midland price and the WTI Cushing price.

Under the Company’s costless collar contracts, a three-way collar is a combination of three options: a ceiling call, a floor put, and a short put. The counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the ceiling price to a maximum of the difference between the floor price and the short put price.  The Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the ceiling price. If the settlement price is between the floor and the ceiling price, there is no payment required.

The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing (Cushing and Magellan East Houston) and Crude Oil Brent, and with natural gas derivative settlements based on the New York Mercantile Exchange Henry Hub pricing.

By using derivative instruments to hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are participants in the secured second amended and restated credit agreement, which is secured by substantially all of the assets of the guarantor subsidiaries; therefore, the Company is not required to post any collateral. The Company does not require collateral from its counterparties. The Company has entered into derivative instruments only with counterparties that are also lenders in our credit facility and have been deemed an acceptable credit risk.

25


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)



As of September 30, 2018, the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.
 2018 2019
 Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu)
Oil Swaps - WTI Cushing2,392,000
 $51.27
 1,638,000
 $52.78
Oil Swaps - WTI Magellan East Houston644,000
 $71.06
 1,087,000
 $40.37
Oil Swaps - BRENT920,000
 $62.51
 725,000
 $72.63
Oil Basis Swaps1,380,000
 $(0.88) 270,000
 $(9.42)
Natural Gas Swaps1,840,000
 $3.07
 
 $

 October 2018 - December 2018 January 2019 - December 2019
Oil Three-Way CollarsWTI Magellan East Houston WTI Cushing Brent WTI Magellan East Houston
Volume (Bbls)644,000 1,810,000 2,000,000 994,000
Short put price (per Bbl)$56.43
 $45.00
 $55.00
 $56.82
Floor price (per Bbl)$66.43
 $55.00
 $65.00
 $66.82
Ceiling price (per Bbl)$78.82
 $70.23
 $82.47
 $77.60

Balance sheet offsetting of derivative assets and liabilities

The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions that are with the same counterparty and are subject to contractual terms which provide for net settlement.

The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties and the resulting net amounts presented in the Company’s consolidated balance sheets as of September 30, 2018 and December 31, 2017.
 September 30, 2018December 31, 2017
 (in thousands)
Gross amounts of assets presented in the Consolidated Balance Sheet$
$531
Net amounts of assets presented in the Consolidated Balance Sheet
531
   
Gross amounts of liabilities presented in the Consolidated Balance Sheet129,757
106,670
Net amounts of liabilities presented in the Consolidated Balance Sheet$129,757
$106,670


26


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


The net amounts are classified as current or noncurrent based on their anticipated settlement dates. The net fair value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:
 September 30, 2018December 31, 2017
 (in thousands)
Current assets: derivative instruments$
$531
Noncurrent assets: derivative instruments

Total assets$
$531
Current liabilities: derivative instruments$123,826
$100,367
Noncurrent liabilities: derivative instruments5,931
6,303
Total liabilities$129,757
$106,670

None of the Company’s derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations:
 Three Months Ended September 30, Nine Months Ended September 30,
 20182017 20182017
 (in thousands)
Change in fair value of open non-hedge derivative instruments$(9,913)$(58,645) $(23,618)$9,365
Gain (loss) on settlement of non-hedge derivative instruments(38,460)8,000
 (115,687)11,011
Gain (loss) on derivative instruments$(48,373)$(50,645) $(139,305)$20,376

15.    FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.

The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities.
 
Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.


27


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


The Company estimates the fair values of proved oil and natural gas properties assumed in business combinations using discounted cash flow techniques and based on market assumptions as to the future commodity prices, internal estimates of future quantities of oil and natural gas reserves, future estimated rates of production, expected recovery rates and risk-adjustment discounts. The estimated fair values of unevaluated oil and natural gas properties were based on the location, engineering and geological studies, historical well performance, and applicable mineral lease terms. Given the unobservable nature of the inputs, the estimated fair values of oil and natural gas properties assumed is deemed to use Level 3 inputs. The asset retirement obligations assumed as part of business combinations are estimated using the same assumptions and methodology as described below.

The Company estimates asset retirement obligations pursuant to the provisions of the Financial Accounting Standards Board issued Accounting Standards Codification Topic 410, “Asset Retirement and Environmental Obligations”. The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with the future plugging and abandonment of wells and related facilities. Given the unobservable nature of the inputs, including plugging costs and useful lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 7—Asset Retirement Obligations for further discussion of the Company’s asset retirement obligations.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments and cost method investment. The fair values of the Company’s fixed price swaps, fixed price basis swaps and costless collars are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs.

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2018 and December 31, 2017.


 September 30, 2018
 Level 1Level 2Level 3
 (in thousands)
Assets:   
Investment$20,240
$
$
Liabilities:   
Fixed price swaps$
$(129,757)$

 December 31, 2017
 Level 1Level 2Level 3
 (in thousands)
Assets:   
Investment$
$
$
Liabilities:   
Fixed price swaps$
$(106,139)$



28


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets:
 September 30, 2018December 31, 2017
 Carrying Carrying 
 AmountFair ValueAmountFair Value
 (in thousands)
Debt:    
Revolving credit facility$
$
$397,000
$397,000
4.750% Senior Notes due 2024$1,250,000
$1,252,613
$500,000
$501,855
5.375% Senior Notes due 2025$800,000
$819,000
$500,000
$515,000
Partnership revolving credit facility$296,500
$296,500
$93,500
$93,500

The fair value of the revolving credit facility and the Partnership’s revolving credit facility approximates their carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes was determined using the September 30, 2018 quoted market price, a Level 1 classification in the fair value hierarchy.

16.    COMMITMENTS AND CONTINGENCIES

The Company could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.

17.    SUBSEQUENT EVENTS

Recent Acquisitions and Divestitures

Ajax Resources, LLC

On July 22, 2018, the Company entered into a definitive purchase agreement to acquire all leasehold interests and related assets of Ajax Resources, LLC which includes approximately 25,493 net leasehold acres in the Northern Midland Basin for $900.0 million in cash, subject to certain adjustments, and approximately 2.6 million shares of the Company’s common stock. This transaction closed October 31, 2018, and was effective as of July 1, 2018. See Note 4—Acquisitions for additional information regarding the Ajax acquisition.

The cash portion of the purchase price for the Ajax acquisition was funded through a combination of cash on hand, proceeds from the sale of mineral interests to the Partnership, borrowing under the Company’s revolving credit facility and a portion of the proceeds from the Company’s September 2018 senior note offering. See Note 9—Debt for information relating to this offering.

ExL Petroleum Management, LLC and Energy Quest II LLC

On October 31, 2018, the Company completed the acquisition of approximately 3,646 net leasehold acres and related assets in the Northern Midland Basin from ExL Petroleum Management, LLC, ExL Petroleum Operating, Inc. and EnergyQuest II LLC for $312.5 million in cash, subject to certain adjustments. See Note 4—Acquisitions for additional information regarding this acquisition.


29


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Divestiture of Oil and Natural Gas Properties

On November 1, 2018, the Company completed its divestiture of certain oil and natural gas properties in the Delaware Basin for an aggregate sale price of $62.1 million. This transaction included the divestiture of approximately 2,485 gross (2,072 net) acres primarily in Pecos county, Texas.

Third Quarter Dividend Declaration
On November 5, 2018, the Board of Directors of the Company declared a cash dividend for the third quarter of 2018 of $0.125 per share of common stock, payable on November 26, 2018 to its stockholders of record at the close of business on November 19, 2018.
Commodity Contracts

Subsequent to September 30, 2018, the Company entered into new fixed price basis swaps. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing (Cushing and Magellan East Houston) and Crude Oil Brent.

The following tables present the derivative contracts entered into by the Company subsequent to September 30, 2018. When aggregating multiple contracts, the weighted average contract price is disclosed.
 Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu)
April 2019 - December 2019   
Oil Swaps - WTI Magellan East Houston458,000 $76.18
Oil Swaps - BRENT275,000 $77.58


The Company’s Credit Facility

On October 26, 2018, the Company’s borrowing base under its credit agreement was increased to $2.5 billion and was increased further to $2.65 billion on November 6, 2018 following the closing of the Company’s acquisition of assets from Ajax Resources, LLC and satisfaction of certain other conditions. The Company also elected to increase the commitment amount from $1.0 billion to $2.0 billion effective October 26, 2018.

The Partnership’s Credit Facility

In connection with the Partnership’s fall 2018 redetermination, the Partnership’s borrowing base was increased to $555.0 million effective October 26, 2018.

18.    GUARANTOR FINANCIAL STATEMENTS

As of September 30, 2018, Diamondback E&P LLC and Diamondback O&G LLC (the “Guarantor Subsidiaries”) are guarantors under the indentures relating to the 2024 Senior Notes and the 2025 Senior Notes, as supplemented. In connection with the issuance of the 2024 Senior Notes and the 2025 Senior Notes (including the New 2025 Senior Notes), the Partnership, the General Partner, Viper Energy Partners LLC and Rattler Midstream LLC were designated as Non-Guarantor Subsidiaries. The following presents condensed consolidated financial information for the Company (which for purposes of this Note 18 is referred to as the “Parent”), the Guarantor Subsidiaries and the Non–Guarantor Subsidiaries on a consolidated basis. Elimination entries presented are necessary to combine the entities. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities. The Company has not presented separate financial and narrative information for each of the Guarantor Subsidiaries because it believes such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the Guarantor Subsidiaries.


30


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Condensed Consolidated Balance Sheet
September 30, 2018
(In thousands)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Assets         
Current assets:         
Cash and cash equivalents$471,148
 $20,469
 $16,829
 $
 $508,446
Accounts receivable
 226,299
 38,018
 
 264,317
Accounts receivable - related party
 
 7,758
 (7,758) 
Intercompany receivable3,199,881
 262,503
 
 (3,462,384) 
Inventories
 14,815
 
 
 14,815
Other current assets257
 7,708
 146
 
 8,111
Total current assets3,671,286
 531,794
 62,751
 (3,470,142) 795,689
Property and equipment:         
Oil and natural gas properties, at cost, full cost method of accounting
 9,209,250
 1,612,425
 (3,297) 10,818,378
Midstream assets
 355,758
 
 
 355,758
Other property, equipment and land
 80,194
 5,688
 
 85,882
Accumulated depletion, depreciation, amortization and impairment
 (2,306,710) (230,784) (7,918) (2,545,412)
Net property and equipment
 7,338,492
 1,387,329
 (11,215) 8,714,606
Funds held in escrow
 62,034
 
 
 62,034
Investment in subsidiaries4,631,753
 989
 
 (4,632,742) 
Deferred tax asset
 
 95,551
 
 95,551
Investment in real estate, net
 106,834
 
 
 106,834
Other assets
 8,513
 23,346
 
 31,859
Total assets$8,303,039
 $8,048,656
 $1,568,977
 $(8,114,099) $9,806,573
Liabilities and Stockholders’ Equity         
Current liabilities:         
Accounts payable-trade$
 $85,865
 $4
 $
 $85,869
Intercompany payable
 3,470,142
 
 (3,470,142) 
Other current liabilities41,026
 590,186
 4,706
 
 635,918
Total current liabilities41,026
 4,146,193
 4,710
 (3,470,142) 721,787
Long-term debt2,035,859
 
 296,500
 
 2,332,359
Derivative instruments
 5,931
 
 
 5,931
Asset retirement obligations
 23,897
 
 
 23,897
Deferred income taxes292,795
 
 
 
 292,795
Other long-term liabilities
 7
 
 
 7
Total liabilities2,369,680
 4,176,028
 301,210
 (3,470,142) 3,376,776
Commitments and contingencies         
Stockholders’ equity5,933,359
 3,872,628
 572,217
 (4,444,845) 5,933,359
Non-controlling interest
 
 695,550
 (199,112) 496,438
Total equity5,933,359
 3,872,628
 1,267,767
 (4,643,957) 6,429,797
Total liabilities and equity$8,303,039
 $8,048,656
 $1,568,977
 $(8,114,099) $9,806,573

31


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Condensed Consolidated Balance Sheet
December 31, 2017
(In thousands)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Assets         
Current assets:         
Cash and cash equivalents$54,074
 $34,175
 $24,197
 $
 $112,446
Accounts receivable
 205,859
 25,754
 
 231,613
Accounts receivable - related party
 
 5,142
 (5,142) 
Intercompany receivable2,624,810
 2,267,308
 
 (4,892,118) 
Inventories
 9,108
 
 
 9,108
Other current assets618
 4,461
 355
 
 5,434
Total current assets2,679,502
 2,520,911
 55,448
 (4,897,260) 358,601
Property and equipment:         
Oil and natural gas properties, at cost, full cost method of accounting
 8,129,211
 1,103,897
 (414) 9,232,694
Midstream assets
 191,519
 
 
 191,519
Other property, equipment and land
 80,776
 
 
 80,776
Accumulated depletion, depreciation, amortization and impairment
 (1,976,248) (189,466) 4,342
 (2,161,372)
Net property and equipment
 6,425,258
 914,431
 3,928
 7,343,617
Funds held in escrow
 
 6,304
 
 6,304
Investment in subsidiaries3,809,557
 
 
 (3,809,557) 
Other assets
 25,609
 36,854
 
 62,463
Total assets$6,489,059
 $8,971,778
 $1,013,037
 $(8,702,889) $7,770,985
Liabilities and Stockholders’ Equity         
Current liabilities:         
Accounts payable-trade$1
 $91,629
 $2,960
 $
 $94,590
Intercompany payable132,067
 4,765,193
 
 (4,897,260) 
Other current liabilities7,236
 472,933
 2,669
 
 482,838
Total current liabilities139,304
 5,329,755
 5,629
 (4,897,260) 577,428
Long-term debt986,847
 397,000
 93,500
 
 1,477,347
Derivative instruments
 6,303
 
 
 6,303
Asset retirement obligations
 20,122
 
 
 20,122
Deferred income taxes108,048
 
 
 
 108,048
Total liabilities1,234,199
 5,753,180
 99,129
 (4,897,260) 2,189,248
Commitments and contingencies
 
 
 
 
Stockholders’ equity5,254,860
 3,218,598
 913,908
 (4,132,506) 5,254,860
Non-controlling interest
 
 
 326,877
 326,877
Total equity5,254,860
 3,218,598
 913,908
 (3,805,629) 5,581,737
Total liabilities and equity$6,489,059
 $8,971,778
 $1,013,037
 $(8,702,889) $7,770,985



32


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Condensed Consolidated Statement of Operations
Three Months Ended September 30, 2018
(In thousands)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Revenues:         
Oil sales$
 $391,051
 $
 $63,593
 $454,644
Natural gas sales
 10,891
 
 3,923
 14,814
Natural gas liquid sales
 50,740
 
 6,870
 57,610
Royalty income
 
 74,386
 (74,386) 
Lease bonus
 
 4,205
 (2,883) 1,322
Midstream services
 7,280
 
 
 7,280
Other operating income
 2,347
 12
 
 2,359
Total revenues
 462,309
 78,603
 (2,883) 538,029
Costs and expenses:         
Lease operating expenses
 49,111
 
 
 49,111
Production and ad valorem taxes
 28,509
 5,027
 
 33,536
Gathering and transportation
 6,087
 889
 
 6,976
Midstream services
 19,725
 
 
 19,725
Depreciation, depletion and amortization
 125,627
 16,532
 4,159
 146,318
General and administrative expenses6,862
 6,629
 1,309
 (615) 14,185
Asset retirement obligation accretion
 387
 
 
 387
Other operating expense
 940
 
 
 940
Total costs and expenses6,862
 237,015
 23,757
 3,544
 271,178
Income (loss) from operations(6,862) 225,294
 54,846
 (6,427) 266,851
Other income (expense)         
Interest expense, net(10,868) (3,969) (3,711) 
 (18,548)
Other income (expense), net416
 1,521
 640
 (615) 1,962
Loss on derivative instruments, net
 (48,373) 
 
 (48,373)
Loss on revaluation of investment
 
 (199) 
 (199)
Total other income (expense), net(10,452) (50,821) (3,270) (615) (65,158)
Income (loss) before income taxes(17,314) 174,473
 51,576
 (7,042) 201,693
Provision for income taxes41,512
 
 764
 
 42,276
Net income (loss)(58,826) 174,473
 50,812
 (7,042) 159,417
Net income attributable to non-controlling interest
 
 48,466
 (46,103) 2,363
Net income (loss) attributable to Diamondback Energy, Inc.$(58,826) $174,473
 $2,346
 $39,061
 $157,054


33


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Condensed Consolidated Statement of Operations
Three Months Ended September 30, 2017
(In thousands)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Revenues:         
Oil sales$
 $223,038
 $
 $36,011
 $259,049
Natural gas sales
 11,774
 
 3,148
 14,922
Natural gas liquid sales
 22,214
 
 3,052
 25,266
Royalty income
 
 42,211
 (42,211) 
Lease bonus
 
 322
 
 322
Midstream services
 1,694
 
 
 1,694
Total revenues
 258,720
 42,533
 
 301,253
Costs and expenses:         
Lease operating expenses
 32,498
 
 
 32,498
Production and ad valorem taxes
 15,546
 2,825
 
 18,371
Gathering and transportation
 3,271
 205
 
 3,476
Midstream services
 4,445
 
 
 4,445
Depreciation, depletion and amortization
 74,766
 11,068
 1,745
 87,579
General and administrative expenses6,506
 4,629
 1,368
 (615) 11,888
Asset retirement obligation accretion
 357
 
 
 357
Total costs and expenses6,506
 135,512
 15,466
 1,130
 158,614
Income (loss) from operations(6,506) 123,208
 27,067
 (1,130) 142,639
Other income (expense)         
Interest expense, net(6,393) (1,940) (859) 
 (9,192)
Other income (expense), net9
 210
 399
 (615) 3
Loss on derivative instruments, net
 (50,645) 
 
 (50,645)
Total other income (expense), net(6,384) (52,375) (460) (615) (59,834)
Income (loss) before income taxes(12,890) 70,833
 26,607
 (1,745) 82,805
Provision for income taxes857
 
 
 
 857
Net income (loss)(13,747) 70,833
 26,607
 (1,745) 81,948
Net income attributable to non-controlling interest
 
 
 8,924
 8,924
Net income (loss) attributable to Diamondback Energy, Inc.$(13,747) $70,833
 $26,607
 $(10,669) $73,024

34


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)



Condensed Consolidated Statement of Operations
Nine Months Ended September 30, 2018
(In thousands)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Revenues:         
Oil sales
 1,149,184
 
 185,165
 1,334,349
Natural gas sales
 31,405
 
 9,152
 40,557
Natural gas liquid sales
 116,976
 
 16,882
 133,858
Royalty income
 
 211,199
 (211,199) 
Lease bonus
 
 5,133
 (2,883) 2,250
Midstream services
 26,658
 
 
 26,658
Other operating income
 6,705
 120
 
 6,825
Total revenues
 1,330,928
 216,452
 (2,883) 1,544,497
Costs and expenses:         
Lease operating expenses
 129,103
 
 
 129,103
Production and ad valorem taxes
 78,909
 14,133
 
 93,042
Gathering and transportation
 16,777
 1,297
 
 18,074
Midstream services
 48,515
 
 
 48,515
Depreciation, depletion and amortization
 337,823
 41,317
 12,261
 391,401
General and administrative expenses20,891
 19,763
 6,230
 (1,845) 45,039
Asset retirement obligation accretion
 1,107
 
 
 1,107
Other operating expense
 2,416
 
 
 2,416
Total costs and expenses20,891
 634,413
 62,977
 10,416
 728,697
Income (loss) from operations(20,891) 696,515
 153,475
 (13,299) 815,800
Other income (expense)         
Interest expense, net(29,945) (10,339) (9,061) 
 (49,345)
Other income (expense), net750
 88,786
 1,479
 (1,845) 89,170
Loss on derivative instruments, net
 (139,305) 
 
 (139,305)
Gain on revaluation of investment


 5,165
 
 5,165
Total other income (expense), net(29,195) (60,858) (2,417) (1,845) (94,315)
Income (loss) before income taxes(50,086) 635,657
 151,058
 (15,144) 721,485
Provision for (benefit from) income taxes153,864
 
 (71,114) 
 82,750
Net income (loss)(203,950) 635,657
 222,172
 (15,144) 638,735
Net income attributable to non-controlling interest
 
 77,526
 22,197
 99,723
Net income (loss) attributable to Diamondback Energy, Inc.(203,950) 635,657
 144,646
 (37,341) 539,012


35


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Condensed Consolidated Statement of Operations
Nine Months Ended September 30, 2017
(In thousands)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Revenues:         
Oil sales$
 $607,381
 $
 $96,626
 $704,007
Natural gas sales
 31,088
 
 6,449
 37,537
Natural gas liquid sales
 50,506
 
 7,119
 57,625
Royalty income
 
 110,194
 (110,194) 
Lease bonus
 
 2,613
 (106) 2,507
Midstream services
 4,241
 
 
 4,241
Total revenues
 693,216
 112,807
 (106) 805,917
Costs and expenses:         
Lease operating expenses
 88,113
 
 
 88,113
Production and ad valorem taxes
 42,307
 7,668
 
 49,975
Gathering and transportation
 8,618
 492
 
 9,110
Midstream services
 7,127
 
 
 7,127
Depreciation, depletion and amortization
 190,748
 28,587
 2,346
 221,681
General and administrative expenses20,046
 14,259
 5,064
 (1,845) 37,524
Asset retirement obligation accretion
 1,030
 
 
 1,030
Total costs and expenses20,046
 352,202
 41,811
 501
 414,560
Income (loss) from operations(20,046) 341,014
 70,996
 (607) 391,357
Other income (expense)         
Interest expense, net(23,526) (4,022) (2,114) 
 (29,662)
Other income (expense), net1,101
 9,690
 526
 (1,845) 9,472
Gain on derivative instruments, net
 20,376
 
 
 20,376
Total other income (expense), net(22,425) 26,044
 (1,588) (1,845) 186
Income (loss) before income taxes(42,471) 367,058
 69,408
 (2,452) 391,543
Provision for income taxes4,393
 
 
 
 4,393
Net income (loss)(46,864) 367,058
 69,408
 (2,452) 387,150
Net income attributable to non-controlling interest
 
 
 19,448
 19,448
Net income (loss) attributable to Diamondback Energy, Inc.$(46,864) $367,058
 $69,408
 $(21,900) $367,702



36


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Condensed Consolidated Statement of Cash Flows
Nine Months Ended September 30, 2018
(In thousands)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Net cash provided by operating activities$220
 $975,082
 $176,414
 $
 $1,151,716
Cash flows from investing activities:         
Additions to oil and natural gas properties
 (1,010,325) 
 
 (1,010,325)
Additions to midstream assets
 (129,820) 
 
 (129,820)
Purchase of other property, equipment and land
 2,638
 (4,687) 
 (2,049)
Acquisition of leasehold interests
 (185,658) 
 
 (185,658)
Acquisition of mineral interests
 170,268
 (505,842) 
 (335,574)
Proceeds from sale of assets
 6,206
 565
 
 6,771
Funds held in escrow
 (51,045) 
 
 (51,045)
Equity investments
 (604) 
 
 (604)
Intercompany transfers(22,310) 22,310
 
 
 
Investment in real estate
 (110,654) 
 
 (110,654)
Net cash used in investing activities(22,310) (1,286,684) (509,964) 
 (1,818,958)
Cash flows from financing activities:         
Proceeds from borrowing under credit facility
 470,500
 557,000
 
 1,027,500
Repayment under credit facility
 (867,500) (354,000) 
 (1,221,500)
Proceeds from senior notes1,062,000
 
 
 
 1,062,000
Debt issuance costs(13,723) (232) (623) 
 (14,578)
Public offering costs
 
 (2,636) 
 (2,636)
Proceeds from public offerings
 
 305,773
 
 305,773
Contributions to subsidiaries(1,000) 
 (1,000) 2,000
 
Contributions by members
 
 2,000
 (2,000) 
Distributions from subsidiary112,671
 
 
 (112,671) 
Unit options exercised
 
 140
 
 140
Dividends to stockholders(24,656) 
 
 
 (24,656)
Distributions to non-controlling interest
 
 (181,472) 112,671
 (68,801)
Intercompany transfers(696,128) 695,128
 1,000
 
 
Net cash provided by financing activities439,164
 297,896
 326,182
 
 1,063,242
Net increase (decrease) in cash and cash equivalents417,074
 (13,706) (7,368) 
 396,000
Cash and cash equivalents at beginning of period54,074
 34,175
 24,197
 
 112,446
Cash and cash equivalents at end of period$471,148
 $20,469
 $16,829
 $
 $508,446

37


Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Condensed Consolidated Statement of Cash Flows
Nine Months Ended September 30, 2017
(In thousands)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Net cash provided by (used in) operating activities$(25,369) $569,330
 $94,057
 $
 $638,018
Cash flows from investing activities:         
Additions to oil and natural gas properties
 (531,489) 
 
 (531,489)
Additions to midstream assets
 (22,491) 
 
 (22,491)
Purchase of other property, equipment and land
 (21,534) 
 
 (21,534)
Acquisition of leasehold interests
 (1,892,864) 
 
 (1,892,864)
Acquisition of mineral interests
 (69,722) (301,133) 
 (370,855)
Acquisition of midstream assets
 (50,279) 
 
 (50,279)
Proceeds from sale of assets
 3,584
 
 
 3,584
Funds held in escrow
 121,391
 
 
 121,391
Equity investments
 (188) 
 
 (188)
Intercompany transfers(1,651,328) 1,651,328
 
 
 
Net cash used in investing activities(1,651,328) (812,264) (301,133) 
 (2,764,725)
Cash flows from financing activities:         
Proceeds from borrowing under credit facility
 312,500
 220,500
 
 533,000
Repayment under credit facility
 (78,000) (305,500) 
 (383,500)
Purchase of subsidiary units by parent(10,068) 
 
 10,068
 
Debt issuance costs(744) (790) (180) 
 (1,714)
Public offering costs(77) 
 (433) 
 (510)
Proceeds from public offerings
 
 380,412
 (10,068) 370,344
Distributions from subsidiary64,858
 
 
 (64,858) 
Proceeds from exercise of stock options358
 
 
 
 358
Distributions to non-controlling interest
 
 (92,498) 64,858
 (27,640)
Net cash provided by financing activities54,327
 233,710
 202,301
 
 490,338
Net decrease in cash and cash equivalents(1,622,370) (9,224) (4,775) 
 (1,636,369)
Cash and cash equivalents at beginning of period1,643,226
 14,135
 9,213
 
 1,666,574
Cash and cash equivalents at end of period$20,856
 $4,911
 $4,438
 $
 $30,205



38



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

The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and notes thereto presented in this report as well as our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2017. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See “Part II. Item 1A. Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. Our activities are primarily directed at the horizontal development of the Wolfcamp and Spraberry formations in the Midland Basin and the Wolfcamp and Bone Spring formations in the Delaware Basin. We intend to continue to develop our reserves and increase production through development drilling and exploitation and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves. Substantially all of our revenues are generated through the sale of oil, natural gas liquids and natural gas production.

The following table sets forth our production data for the periods indicated:
 Three Months Ended September 30, Nine Months Ended September 30,
 20182017 20182017
Oil (MBbls)72%73% 73%74%
Natural gas (MMcf)11%13% 12%12%
Natural gas liquids (MBbls)17%14% 15%14%
 100%100% 100%100%

As of September 30, 2018, we had approximately 208,317 net acres, which consisted of approximately 104,973 net acres in the Northern Midland Basin and approximately 103,344 net acres in the Southern Delaware Basin. As of December 31, 2017, we had an estimated 3,800 gross horizontal locations that we believe to be economic at $60 per Bbl West Texas Intermediate, or WTI.

In the third quarter of 2018, we again demonstrated our operational focus on achieving best-in-class execution, low-cost operations and a conservative balance sheet as we continued to execute on our growth plan while maintaining cash operating margins in excess of 80% on a per BOE basis. In doing so, we achieved another quarter of robust production growth within cash flow, which has allowed us to maintain a low leverage ratio, while generating what we believe to be a peer leading return on average capital employed. During the third quarter of 2018, we operated 13 drilling rigs and five dedicated frac spreads, and recently added our 14th operating rigs when we took over operations from Ajax Resources, LLC, or Ajax.

2018 Highlights

Transportation Contracts
In July 2018, we executed agreements to secure firm oil transportation out of the Midland Basin at fixed discounts to Gulf Coast pricing beginning with the third quarter of 2018 and have multiple term sales agreements in place to cover the remainder of our expected Midland production. We also executed an option agreement to acquire up to a 10% equity interest in the EPIC Crude Oil Pipeline project in connection with a 100,000 BOD/d volume commitment, with 50% of the volume covered via a take or pay contract and the remaining 50% covered via an acreage dedication.


39



In October 2018, we executed another agreement to secure firm oil transportation out of the Midland Basin at fixed discounts to Gulf Coast pricing beginning in November 2018 to transport product from the acreage we recently acquired from Ajax (described below) and production growth from our existing assets. This agreement, as well as the agreements executed in July, will provide transportation assurance for the majority of our existing Midland production, production from the Ajax acreage and our estimated production growth for the fourth quarter of 2018.

Ajax Resources, LLC

On July 22, 2018, we entered into a definitive purchase agreement to acquire leasehold interests and related assets of Ajax, which include approximately 25,493 net leasehold acres in the Northern Midland Basin, for $900.0 million in cash, subject to certain adjustments, and approximately 2.6 million shares of our common stock, which we refer to as the Ajax acquisition. The Ajax acquisition closed on October 31, 2018 and was effective as of July 1, 2018. The cash portion of this transaction was funded through a combination of cash on hand, proceeds from the sale of mineral interests to Viper Energy Partners LP, which we refer to as Viper or the Partnership, described below, borrowing under our revolving credit facility and proceeds from our September 2018 senior note offering. See “Our September 2018 Senior Note Offering” below.

In connection with the closing of the Ajax acquisition on October 31, 2018, we entered into a registration rights agreement with Ajax and certain other holders of our common stock pursuant to which we agreed to (i) file with the SEC a shelf registration statement to facilitate the resale of common stock issued in the Ajax acquisition and (ii) use our reasonable best efforts to cause such registration statement to become effective by November 30, 2018. Pursuant to this registration rights agreement, we also agreed to provide certain demand and piggyback registration rights to such holders.

ExL Petroleum Management, LLC and EnergyQuest II LLC Acquisition

On September 21, 2018, we entered into two definitive purchase agreements to acquire leasehold interests and related assets, one with ExL Petroleum Management, LLC and ExL Petroleum Operating, Inc. and one with EnergyQuest II LLC, for an aggregate of approximately 3,646 net leasehold acres in the Northern Midland Basin for a total of $312.5 million in cash, subject to certain adjustments. These transactions closed on October 31, 2018 and were effective as of August 1, 2018. These transactions, which we refer to collectively as the ExL acquisition, were funded through a combination of cash on hand, proceeds from the sale of assets to the Partnership (described below) and borrowing under our revolving credit facility.

Pending Merger with Energen Corporation

On August 14, 2018, we entered into a definitive merger agreement providing for our acquisition of Energen Corporation, or Energen, in an all-stock transaction valued at approximately $9.2 billion including Energen’s net debt of $831.0 million as of June 30, 2018, which we refer to as the Pending Merger. The addition of Energen’s assets will increase our assets to: (i) over 273,000 net Tier One acres in the Permian Basin, an increase of 57% from our current Tier One acreage of approximately 174,000 net acres, (ii) over 7,200 estimated total net horizontal Permian locations, an increase of over 120% from our current estimated net locations, and (iii) approximately 394,000 net acres across the Midland and Delaware Basins, an increase of 82% from our approximately 216,000 net acres as September 30, 2018, in each after giving effect to our recently completed Ajax acquisition and ExL acquisition.

The completion of the Pending Merger is subject to the satisfaction or waiver of certain customary mutual closing conditions. Our registration statement on Form S-4 relating to the Pending Merger was declared effective by the SEC on October 24, 2018, and the Pending Merger is expected to be completed at the end of November of 2018.


40




Under the terms of the merger agreement relating to the Pending Merger, we have agreed to assume Energen’s outstanding debt, which as of June 30, 2018 was approximately $831.0 million. This amount consists of $301.0 million of borrowings under Energen’s existing credit facility, $400.0 millionaggregate principal amount of 4.625% Notes, due September 1, 2021, $20.0 million aggregate principal amount of 7.32% Medium-term Notes, Series A, due July 28, 2022, $10.0 million aggregate principal amount of 7.35% Medium-term Notes, Series A, due July 28, 2027, and $100.0 million aggregate principal amount of 7.125% Medium-term Notes, Series B, due February 15, 2028, which we collectively refer to as the Energen Notes. We may choose to refinance the Energen credit facility and our credit facility into a combined credit facility in connection with the consummation of the Pending Merger or we may choose to repay the outstanding borrowings under the Energen credit facility using cash on hand or borrowings under our revolving credit facility. With respect to the outstanding Energen Notes, we may take no action, or we may seek to amend the terms of the indenture governing the Energen Notes or engage in liability management transactions with respect to, repay or refinance any or all of the Energen Notes, with any repayment coming from cash on hand or borrowings under our revolving credit facility.

Drop-down Transaction

On August 15, 2018, we sold to the Partnership mineral interests underlying 32,424 gross (1,696 net royalty) acres primarily in Pecos County, Texas, in the Permian Basin, approximately 80% of which are operated by us, for $175.0 million, which we refer to as the Drop-down Transaction.

Alliance with Obsidian Resources, L.L.C.
We entered into a participation and development agreement, which we refer to as the DrillCo agreement, dated September 10, 2018, with Obsidian Resources, L.L.C., which we refer to as CEMOF, to fund oil and natural gas development. Funds managed by CEMOF and its affiliates have agreed to commit to funding certain costs out of CEMOF’s net production revenue and, for a period of time, to the extent not funded by such revenue, up to an additional $300.0 million, to fund drilling programs on locations provided by us. Subject to adjustments depending on asset characteristics and return expectations of the selected drilling plan, CEMOF will fund up to 85% of the costs associated with new wells drilled under the DrillCo agreement and is expected to receive an 80% working interest in these wells until it reaches certain payout thresholds equal to a cumulative 9% and then 13% internal rate of return. Upon reaching the final internal rate of return target, CEMOF’s interest will be reduced to 15%, while our interest will increase to 85%.


Third Quarter Dividend Declaration

On November 5, 2018, our board of directors declared a cash dividend for the third quarter of 2018 of $0.125 per share of common stock, payable on November 26, 2018 to our stockholders of record at the close of business on November 19, 2018.

Our September 2018 Senior Note Offering

On September 25, 2018, we issued $750.0 million aggregate principal amount of new 4.750% senior notes due 2024, or the “new 2024 notes”. The new 2024 notes were issued in a transaction exempt from the registration requirements under the Securities Act. We received approximately $740.7 million in net proceeds, after deducting the initial purchasers’ discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of the new 2024 notes. We used a portion of the net proceeds from the issuance of the new 2024 notes to repay a portion of the outstanding borrowings our revolving credit facility and we used the balance for general corporate purposes, including the funding of a portion of the cash consideration for the acquisition of assets from Ajax.

Viper’s July 2018 Equity Offering

In July 2018, Viper completed an underwritten public offering of 10,080,000 common units, which included 1,080,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Following this offering, we owned approximately 59% of Viper’s total units then outstanding. Viper received net proceeds from this offering of approximately $303.1 million, after deducting underwriting discounts and commissions and estimated offering expenses. Viper used the net proceeds to purchase units of the Operating Company. The Operating Company in turn used the net proceeds to repay a portion of the $361.5 million then outstanding borrowings under its revolving credit facility.

41





Operational Update

During the three months ended September 30, 2018, we drilled 40 gross (34 net) operated horizontal wells, of which 20 gross (18 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, and turned 43 gross (38 net) operated horizontal wells into production, of which 30 gross (26 net) wells were in the Midland Basin and the remaining wells were in the Delaware Basin.

During the third quarter of 2018, we operated 13 drilling rigs and five dedicated frac spreads. Upon the closing of the Ajax acquisition on October 31, we took over operations of one operated rig and plan to run an average of 14 drilling rigs for the remainder of 2018. We expect to operate seven of these drilling rigs in the Midland Basin targeting horizontal development of the Wolfcamp and Spraberry formations, while the remainder of the drilling rigs are expected to operate in the Delaware Basin targeting the Wolfcamp and Bone Spring formations.

In the Midland Basin, we continue to see positive well results from our core development areas in Midland, Glasscock, Howard, Andrews and Martin counties. Assuming commodity prices at current levels, we anticipate operating between six and seven drilling rigs across our Northern Midland Basin acreage for the remainder of 2018.

In the Delaware Basin, we are currently operating seven drilling rigs, with plans to operate seven drilling rigs for the remainder of 2018. Our 2018 development plan is primarily focused on long-lateral Wolfcamp A wells in Pecos, Reeves and Ward counties. In the third quarter, we tested the Second Bone Spring in Pecos county by completing two wells with positive early time results.

We continue to focus on low cost operations and best in class execution. In doing so, we are focused on controlling oilfield service costs as our service providers seek additional pricing increases after a prolonged period of declining costs in 2015 and 2016. To combat rising service costs, we have taken proactive measures such as securing frac sand supply for future well completions, locking in costs where feasible and purchasing items such as casing in bulk and in advance. We will continue to seek opportunities to control and de-bundle additional costs where possible, such as diesel and frac sand costs for our completion operations. We believe that our 2018 drilling and completion budget covers potential increases in our service costs during the year.


The following table summarizes our average daily production for the periods presented:
 Three Months Ended September 30, Nine Months Ended September 30,
 20182017 20182017
Oil (Bbls)/d88,26261,720 82,04655,212
Natural Gas (Mcf)/d84,82664,506 79,54953,321
Natural Gas Liquids (Bbls)/d20,57512,558 17,49510,526
Total average production per day (BOE)122,97585,029 112,79974,624

Our average daily production for the three months ended September 30, 2018 as compared to the three months ended September 30, 2017 increased 37,946 BOE/d, or 44.6%.


42




Recapitalization, Tax Status Election and Related Transactions by Viper

In March 2018, Viper announced that the Board of Directors of its general partner had unanimously approved a change of Viper’s federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election. In connection with making this election, on May 9, 2018 Viper (i) amended and restated its First Amended and Restated Partnership Agreement, (ii) amended and restated the First Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC, or the Operating Company, (iii) amended and restated its existing registration rights agreement with us and (iv) entered into an exchange agreement with us, Viper’s general partner, or the General Partner, and the Operating Company. Simultaneously with the effectiveness of these agreements, we delivered and assigned to Viper the 73,150,000 common units we owned in exchange for (i) 73,150,000 of Viper’s newly-issued Class B units and (ii) 73,150,000 newly-issued units of the Operating Company pursuant to the terms of a Recapitalization Agreement dated March 28, 2018, as amended as of May 9, 2018, or the Recapitalization Agreement. Immediately following that exchange, Viper continued to be the managing member of the Operating Company, with sole control of its operations, and owned approximately 36% of the outstanding units issued by the Operating Company, and we owned the remaining approximately 64% of the outstanding units issued by the Operating Company. Upon completion of Viper’s July 2018 offering of units, Viper owned approximately 41% of the outstanding units issued by the Operating Company and we owned the remaining approximately 59%. The Operating Company units and Viper’s Class B units owned by us are exchangeable from time to time for Viper’s common units (that is, one Operating Company unit and one Viper Class B unit, together, will be exchangeable for one Viper common unit).

On May 10, 2018, the change in Viper’s income tax status became effective. On that date, pursuant to the terms of the Recapitalization Agreement, (i) the General Partner made a cash capital contribution of $1.0 million to Viper in respect of its general partner interest and (ii) we made a cash capital contribution of $1.0 million to Viper in respect of the Class B units. We, as the holder of the Class B units, and the General Partner, as the holder of the general partner interest, are entitled to receive an 8% annual distribution on the outstanding amount of these capital contributions, payable quarterly, as a return on this invested capital. On May 10, 2018, we also exchanged 731,500 Class B units and 731,500 units in the Operating Company for 731,500 common units of Viper and a cash amount of $10,000 representing a proportionate return of the $1.0 million invested capital in respect of the Class B units. The General Partner continues to serve as Viper’s general partner and we continue to control Viper. After the effectiveness of the tax status election and the completion of related transactions, Viper’s minerals business continues to be conducted through the Operating Company, which continues to be taxed as a partnership for federal and state income tax purposes. This structure is anticipated to provide significant benefits to Viper’s business, including operational effectiveness, acquisition and disposition transactional planning flexibility and income tax efficiency. For additional information regarding the tax status election and related transactions, please refer to Viper’s Definitive Information Statement on Schedule 14C filed with the SEC on April 17, 2018 and Viper’s Current Report on Form 8-K filed with the SEC on May 15, 2018.

Sources of Our Revenues

Our main sources of revenues are the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from our natural gas during processing. Our oil and natural gas revenues do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold, production mix or commodity prices.

The following table presents the breakdown of our revenues for the following periods:
 Three Months Ended September 30, Nine Months Ended September 30,
 20182017 20182017
Revenues     
Oil sales86%87% 88%88%
Natural gas sales3%5% 3%5%
Natural gas liquid sales11%8% 9%7%
 100%100% 100%100%

Since our production consists primarily of oil, our revenues are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas or natural gas liquids prices. Oil, natural gas and natural gas liquids prices have historically been volatile. During 2017, WTI posted prices ranged from $42.48 to $60.46 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.44 to $3.71 per MMBtu. During the first nine months of 2018, WTI posted prices ranged from $59.20 to $77.41 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.49 to $6.24 per MMBtu. On September 28, 2018, the WTI posted price for crude oil was $73.16 per Bbl and the Henry Hub spot market price of natural gas was $3.01 per MMBtu. Lower commodity prices may not only decrease our revenues, but also potentially the amount of oil and natural gas that we can produce economically. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our credit agreement, which may be redetermined at the discretion of our lenders.


43




Results of Operations

The following table sets forth selected historical operating data for the periods indicated.
 Three Months Ended September 30, Nine Months Ended September 30,
 20182017 20182017
 (in thousands, except Bbl, Mcf and BOE amounts)
Revenues:     
Oil, natural gas and natural gas liquids$527,068
$299,237
 $1,508,764
$799,169
Lease bonus1,322
322
 2,250
2,507
Midstream services7,280
1,694
 26,658
4,241
Other operating income2,359


6,825

Total revenues538,029
301,253
 1,544,497
805,917
Operating expenses:     
Lease operating expenses49,111
32,498
 129,103
88,113
Production and ad valorem taxes33,536
18,371
 93,042
49,975
Gathering and transportation6,976
3,476
 18,074
9,110
Midstream services19,725
4,445
 48,515
7,127
Depreciation, depletion and amortization146,318
87,579
 391,401
221,681
General and administrative expenses14,185
11,888
 45,039
37,524
Asset retirement obligation accretion387
357
 1,107
1,030
Other operating expense940

 2,416

Total expenses271,178
158,614
 728,697
414,560
Income from operations266,851
142,639
 815,800
391,357
Interest expense, net(18,548)(9,192) (49,345)(29,662)
Other income, net1,962
3
 89,170
9,472
Gain (loss) on derivative instruments, net(48,373)(50,645) (139,305)20,376
Gain (loss) on revaluation of investment(199)

5,165

Total other income (expense), net(65,158)(59,834) (94,315)186
Income before income taxes201,693
82,805
 721,485
391,543
Provision for income taxes42,276
857
 82,750
4,393
Net income159,417
81,948
 638,735
387,150
Net income attributable to non-controlling interest2,363
8,924
 99,723
19,448
Net income attributable to Diamondback Energy, Inc.$157,054
$73,024
 $539,012
$367,702


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 Three Months Ended September 30, Nine Months Ended September 30,
 20182017 20182017
 (in thousands)
Production Data:     
Oil (MBbls)8,120
5,678
 22,399
15,073
Natural gas (MMcf)7,804
5,935
 21,717
14,557
Natural gas liquids (MBbls)1,893
1,155
 4,776
2,874
Combined volumes (MBOE)11,314
7,823
 30,794
20,372
Daily combined volumes (BOE/d)122,975
85,029
 112,799
74,624
      
Average Prices:     
Oil (per Bbl)$55.99
$45.62
 $59.57
$46.71
Natural gas (per Mcf)1.90
2.51
 1.87
2.58
Natural gas liquids (per Bbl)30.44
21.87
 28.03
20.05
Combined (per BOE)46.59
38.25
 49.00
39.23
Oil, hedged ($ per Bbl)(1)
51.23
46.90
 54.36
47.35
Natural gas, hedged ($ per MMbtu)(1)
1.93
2.64
 1.92
2.67
Average price, hedged ($ per BOE)(1)
43.19
39.28
 45.24
39.77
      
Average Costs per BOE:     
Lease operating expense$4.34
$4.15
 $4.19
$4.33
Production and ad valorem taxes2.96
2.35
 3.02
2.45
Gathering and transportation expense0.62
0.44
 0.59
0.45
General and administrative - cash component0.78
0.73
 0.86
0.89
Total operating expense - cash$8.70
$7.67
 $8.66
$8.12
      
General and administrative - non-cash component$0.47
$0.79
 $0.60
$0.95
Depreciation, depletion and amortization12.93
11.20
 12.71
10.88
Interest expense, net1.64
1.18
 1.60
1.46
Total expenses$15.04
$13.17
 $14.91
$13.29
      
Average realized oil price ($/Bbl)$55.99
$45.62
 $59.57
$46.71
Average NYMEX ($/Bbl)69.69
48.18
 66.93
49.30
Differential to NYMEX(13.70)(2.56) (7.36)(2.59)
Average realized oil price to NYMEX80%95% 89%95%
      
Average realized natural gas price ($/Mcf)$1.90
$2.51
 $1.87
$2.58
Average NYMEX ($/Mcf)2.93
2.95
 2.95
3.01
Differential to NYMEX(1.03)(0.44) (1.08)(0.43)
Average realized natural gas price to NYMEX65%85% 63%86%
      
Average realized natural gas liquids price ($/Bbl)$30.44
$21.87
 $28.03
$20.05
Average NYMEX oil price ($/Bbl)69.69
48.18
 66.93
49.30
Average realized natural gas liquids price to NYMEX oil price44%45% 42%41%
(1)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects include gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting.

45




Comparison of the Three Months Ended September 30, 2018 and 2017

Oil, Natural Gas and Natural Gas Liquids Revenues. Our oil, natural gas and natural gas liquids revenues increased by approximately $227.8 million, or 76%, to $527.1 million for the three months ended September 30, 2018 from $299.2 million for the three months ended September 30, 2017. Our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 37,946 BOE/d to 122,975 BOE/d during the three months ended September 30, 2018 from 85,029 BOE/d during the three months ended September 30, 2017. The total increase in revenue of approximately $227.8 million is largely attributable to higher oil, natural gas and natural gas liquids production volumes and higher average sales prices for the three months ended September 30, 2018 as compared to the three months ended September 30, 2017. The increases in production volumes were due to a combination of increased drilling activity and growth through acquisitions. Our production increased by 2,441,927 Bbls of oil, 1,869,390 Mcf of natural gas and 737,526 Bbls of natural gas liquids for the three months ended September 30, 2018 as compared to the three months ended September 30, 2017.

The net dollar effect of the increases in prices of approximately $95.7 million (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas and natural gas liquids) and the net dollar effect of the increase in production of approximately $132.2 million (calculated as the increase in period-to-period volumes for oil, natural gas and natural gas liquids multiplied by the period average prices) are shown below.
 Change in prices
Production volumes(1)
Total net dollar effect of change
   (in thousands)
Effect of changes in price:   
Oil$10.37
8,120
$84,206
Natural gas(0.61)7,804
(4,760)
Natural gas liquids8.57
1,893
16,222
Total revenues due to change in price  $95,668
    
 
Change in production volumes(1)
Prior period Average PricesTotal net dollar effect of change
   (in thousands)
Effect of changes in production volumes:   
Oil2,442
$45.62
$111,334
Natural gas1,869
2.51
4,700
Natural gas liquids738
21.87
16,129
Total revenues due to change in production volumes  132,163
Total change in revenues  $227,831
(1)Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.

Lease Bonus Revenue. Lease bonus income increased by $1.0 million for the three months ended September 30, 2018 as compared to the three months ended September 30, 2017. Lease bonus revenue was $1.3 million for the three months ended September 30, 2018 attributable to lease bonus payments to extend the term of 13 leases, reflecting an average bonus of $7,369 per acre. Lease bonus revenue was $0.3 million for the three months ended September 30, 2017 attributable to lease bonus payments to extend the term of one lease, reflecting an average bonus of $10,000 per acre.

Midstream Services Revenue. Midstream services revenue was $7.3 million for the three months ended September 30, 2018, an increase of $5.6 million as compared to $1.7 million for the three months ended September 30, 2017. We began generating midstream services revenue during the first quarter of 2017 and, prior to that period, had no midstream services revenue. Our midstream services revenue represents fees charged to our joint interest owners and third parties for the transportation of oil and natural gas along with water gathering and related disposal facilities. These assets complement our operations in areas where we have significant production.


46




Lease Operating Expense. Lease operating expense was $49.1 million ($4.34 per BOE) for the three months ended September 30, 2018 as compared to $32.5 million ($4.15 per BOE) for the three months ended September 30, 2017. The increase in lease operating expense was a result of nonrecurring charges due to work overs.

Production and Ad Valorem Tax Expense. Production and ad valorem taxes were $33.5 million for the three months ended September 30, 2018, an increase of $15.2 million, or 83%, from $18.4 million for the three months ended September 30, 2017. In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, among other factors, whereas production taxes are based upon current year commodity prices. During the three months ended September 30, 2018, our production and ad valorem taxes per BOE increased by $0.61 as compared to the three months ended September 30, 2017, primarily due to increased commodity prices and production volumes.

Midstream Services Expense. Midstream services expense was $19.7 million for the three months ended September 30, 2018, an increase of $15.3 million as compared to $4.4 million for the three months ended September 30, 2017. Prior to the first quarter of 2017, we had no midstream services expense. Midstream services expense represents costs incurred to operate and maintain our oil and natural gas gathering and transportation systems, natural gas lift, compression infrastructure and water transportation facilities.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $58.7 million, or 67%, to $146.3 million for the three months ended September 30, 2018 from $87.6 million for the three months ended September 30, 2017.

The following table provides the components of our depreciation, depletion and amortization expense for the periods presented:
 Three Months Ended September 30,
 20182017
   
 (in thousands, except BOE amounts)
Depletion of proved oil and natural gas properties$138,402
$86,388
Depreciation of midstream assets5,451
830
Depreciation of other property and equipment2,465
361
Depreciation, depletion and amortization expense$146,318
$87,579
Oil and natural gas properties depreciation, depletion and amortization per BOE$12.23
$11.04

The increase in depletion of proved oil and natural gas properties of $52.0 million for the three months ended September 30, 2018 as compared to the three months ended September 30, 2017 resulted primarily from higher production levels and an increase in net book value on new reserves added.

General and Administrative Expenses. General and administrative expenses increased $2.3 million from $11.9 million for the three months ended September 30, 2017 to $14.2 million for the three months ended September 30, 2018. The increase was primarily due to an increase in employee count.

Net Interest Expense. Net interest expense for the three months ended September 30, 2018 was $18.5 million as compared to $9.2 million for the three months ended September 30, 2017, an increase of $9.4 million. This increase was due to a higher interest rate and increased average borrowings during the three months ended September 30, 2018 as compared to the three months ended September 30, 2017.

Derivatives. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our consolidated statements of operations under the line item captioned “Gain (loss) on derivative instruments, net.” For the three months ended September 30, 2018, we had a cash loss on settlement of derivative instruments of $38.5 million as compared to a cash gain on settlement of derivative instruments of $8.0 million for the three months ended September 30, 2017. For the three months ended September 30, 2018 and 2017, we had a negative change in the fair value of open derivative instruments of $9.9 million and $58.6 million, respectively.


47




Provision for Income Taxes. We recorded an income tax provision of $42.3 million for the three months ended September 30, 2018 as compared to an income tax provision of $0.9 million for the three months ended September 30, 2017. The change in our income tax provision was primarily due to the increase in pre-tax book income for the three months ended September 30, 2018, and the change in the valuation allowance for the three months ended September 30, 2017.

Comparison of the Nine Months Ended September 30, 2018 and 2017

Oil, Natural Gas and Natural Gas Liquids Revenues. Our oil, natural gas and natural gas liquids revenues increased by approximately $709.6 million, or 89%, to $1,508.8 million for the nine months ended September 30, 2018 from $799.2 million for the nine months ended September 30, 2017. Our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 38,175 BOE/d to 112,799 BOE/d during the nine months ended September 30, 2018 from 74,624 BOE/d during the nine months ended September 30, 2017. The total increase in revenue of approximately $709.6 million is largely attributable to higher oil, natural gas and natural gas liquids production volumes and higher average sales prices for the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017. The increases in production volumes were due to a combination of increased drilling activity and growth through acquisitions. Our production increased by 7,325,834 Bbls of oil, 7,160,383 Mcf of natural gas and 1,902,459 Bbls of natural gas liquids for the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017.

The net dollar effect of the increases in prices of approximately $310.7 million (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas and natural gas liquids) and the net dollar effect of the increase in production of approximately $398.9 million (calculated as the increase in period-to-period volumes for oil, natural gas and natural gas liquids multiplied by the period average prices) are shown below.
 Change in prices
Production volumes(1)
Total net dollar effect of change
   (in thousands)
Effect of changes in price:   
Oil$12.86
22,399
$288,046
Natural gas(0.71)21,716
(15,418)
Natural gas liquids7.98
4,776
38,113
Total revenues due to change in price  $310,741
    
 
Change in production volumes(1)
Prior period Average PricesTotal net dollar effect of change
   (in thousands)
Effect of changes in production volumes:   
Oil7,326
$46.71
$342,239
Natural gas7,160
2.58
18,465
Natural gas liquids1,902
20.05
38,150
Total revenues due to change in production volumes  398,854
Total change in revenues  $709,595
(1)Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.

Lease Bonus Revenue. Lease bonus income decreased by $0.3 million for the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017. Lease bonus revenue was $2.3 million for the nine months ended September 30, 2018 attributable to lease bonus payments to extend the term of 16 leases, reflecting an average bonus of $7,090 per acre. Lease bonus revenue was $2.5 million for the nine months ended September 30, 2017 attributable to lease bonus payments to extend the term of four leases, reflecting an average bonus of $3,257 per acre.


48




Midstream Services Revenue. Midstream services revenue was $26.7 million for the nine months ended September 30, 2018, an increase of $22.4 million as compared to $4.2 million for the nine months ended September 30, 2017. We began generating midstream services revenue during the first quarter of 2017 and, prior to that period, had no midstream services revenue. Our midstream services revenue represents fees charged to our joint interest owners and third parties for the transportation of oil and natural gas along with water gathering and related disposal facilities. These assets complement our operations in areas where we have significant production.

Lease Operating Expense. Lease operating expense was $129.1 million ($4.19 per BOE) for the nine months ended September 30, 2018 as compared to $88.1 million ($4.33 per BOE) for the nine months ended September 30, 2017. The increase in lease operating expense was a result of nonrecurring charges due to work overs. The decrease in lease operating expense per BOE was a result of lease operating expenses increasing at a lower percentage than the increase in production volumes.

Production and Ad Valorem Tax Expense. Production and ad valorem taxes were $93.0 million for the nine months ended September 30, 2018, an increase of $43.1 million, or 86%, from $50.0 million for the nine months ended September 30, 2017. In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, among other factors, whereas production taxes are based upon current year commodity prices. During the nine months ended September 30, 2018, our production and ad valorem taxes per BOE increased by $0.57 as compared to the nine months ended September 30, 2017, primarily due to increased commodity prices and production volumes.

Midstream Services Expense. Midstream services expense was $48.5 million for the nine months ended September 30, 2018, an increase of $41.4 million as compared to $7.1 million for the nine months ended September 30, 2017. Prior to the first quarter of 2017, we had no midstream services expense. Midstream services expense represents costs incurred to operate and maintain our oil and natural gas gathering and transportation systems, natural gas lift, compression infrastructure and water transportation facilities.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $169.7 million, or 77%, to $391.4 million for the nine months ended September 30, 2018 from $221.7 million for the nine months ended September 30, 2017.

The following table provides the components of our depreciation, depletion and amortization expense for the periods presented:
 Nine Months Ended September 30,
 20182017
   
 (in thousands, except BOE amounts)
Depletion of proved oil and natural gas properties$370,771
$218,335
Depreciation of midstream assets14,023
2,261
Depreciation of other property and equipment6,607
1,085
Depreciation, depletion and amortization expense$391,401
$221,681
Oil and natural gas properties depreciation, depletion and amortization per BOE$12.04
$10.71

The increase in depletion of proved oil and natural gas properties of $152.4 million for the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017 resulted primarily from higher production levels and an increase in net book value on new reserves added.

General and Administrative Expenses. General and administrative expenses increased $7.5 million from $37.5 million for the nine months ended September 30, 2017 to $45.0 million for the nine months ended September 30, 2018. The increase was primarily due to an increase in employee count.

Net Interest Expense. Net interest expense for the nine months ended September 30, 2018 was $49.3 million as compared to $29.7 million for the nine months ended September 30, 2017, an increase of $19.7 million. This increase was due to a higher interest rate and increased borrowings during the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017.


49




Derivatives. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our consolidated statements of operations under the line item captioned “Gain (loss) on derivative instruments, net.” For the nine months ended September 30, 2018, we had a cash loss on settlement of derivative instruments of $115.7 million as compared to a cash gain on settlement of derivative instruments of $11.0 million for the nine months ended September 30, 2017. For the nine months ended September 30, 2018, we had a negative change in the fair value of open derivative instruments of $23.6 million as compared to a positive change of $9.4 million for the nine months ended September 30, 2017.

Provision for Income Taxes. We recorded an income tax provision of $82.8 million and $4.4 million for the nine months ended September 30, 2018 and 2017, respectively. The change in our income tax provision was primarily due to the increase in pre-tax book income for the nine months ended September 30, 2018, and the change in the valuation allowance for the nine months ended September 30, 2017.

Liquidity and Capital Resources

Historically, our primary sources of liquidity have been proceeds from our public equity offerings, borrowings under our revolving credit facility, proceeds from the issuance of our senior notes and cash flows from operations. Our primary uses of capital have been for the acquisition, development and exploration of oil and natural gas properties. As we pursue reserves and production growth, we regularly consider which capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us.

Liquidity and Cash Flow

Our cash flows for the nine months ended September 30, 2018 and 2017 are presented below:
 Nine Months Ended September 30,
 20182017
 (in thousands)
Net cash provided by operating activities$1,151,716
$638,018
Net cash used in investing activities(1,818,958)(2,764,725)
Net cash provided by financing activities1,063,242
490,338
Net increase (decrease) in cash$396,000
$(1,636,369)

Operating Activities

Net cash provided by operating activities was $1.2 billion for the nine months ended September 30, 2018 as compared to $638.0 million for the nine months ended September 30, 2017. The increase in operating cash flows is primarily the result of an increase in our oil and natural gas revenues due to an increase in average prices and production growth during the nine months ended September 30, 2018.

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas we produce. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. See “—Sources of our revenue” above.

Investing Activities

The purchase and development of oil and natural gas properties accounted for the majority of our cash outlays for investing activities. Net cash used in investing activities was $1.8 billion and $2.8 billion during the nine months ended September 30, 2018 and 2017, respectively.


50




During the nine months ended September 30, 2018, we spent (a) $1.0 billion on capital expenditures in conjunction with our development program, in which we drilled 40 gross (34 net) operated horizontal wells, of which 20 gross (18 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, and turned 43 gross (38 net) operated horizontal wells into production, of which 30 gross (26 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, (b) $129.8 million on additions to midstream assets, (c) $185.7 million on leasehold acquisitions, (d) $335.6 million for the acquisition of mineral interests, (e) $110.7 million in real estate investments, (f) $51.0 million funds held in escrow and (g) $2.0 million for the purchase of other property and equipment.

During the nine months ended September 30, 2017, we spent (a) $531.5 million on capital expenditures in conjunction with our drilling program and related infrastructure projects, in which we drilled 106 gross (94 net) horizontal wells, completed 85 gross (71 net) horizontal wells and participated in the drilling of 12 gross (one net) non-operated wells in the Permian Basin, (b) $22.5 million on additions to midstream assets, (c) $1,892.9 million on leasehold acquisitions, (d) $50.3 million for midstream assets, (e) $21.5 million for the purchase of other property and equipment and (f) $370.9 million for mineral interests acquisitions.

Our investing activities for the nine months ended September 30, 2018 and 2017 are summarized in the following table:
 Nine Months Ended September 30,
 20182017
 (in thousands)
Drilling, completion and infrastructure$(1,010,325)$(531,489)
Additions to midstream assets(129,820)(22,491)
Acquisition of leasehold interests(185,658)(1,892,864)
Acquisition of mineral interests(335,574)(370,855)
Acquisition of midstream assets
(50,279)
Purchase of other property, equipment and land(2,049)(21,534)
Investment in real estate(110,654)
Proceeds from sale of assets6,771
3,584
Funds held in escrow(51,045)121,391
Equity investments(604)(188)
Net cash used in investing activities$(1,818,958)$(2,764,725)

Financing Activities

Net cash provided by financing activities for the nine months ended September 30, 2018 and 2017 was $1.1 billion and $490.3 million, respectively. During the nine months ended September 30, 2018, the amount provided by financing activities was primarily attributable to the issuance of $1.1 billion of new senior notes, partially offset by $194.0 million of repayments, net of aggregate borrowings under our credit facility in January and September 2018, an aggregate of $305.8 million of net proceeds from Viper’s public offerings, $68.8 million of distributions to non-controlling interest and $24.7 million of dividends to stockholders. The 2017 amount provided by financing activities was primarily attributable to $370.3 million of proceeds from Viper’s January and July 2017 equity offerings as well as $149.5 million of borrowings, net of repayments, under Viper’s credit facility and $27.6 million in distributions.

2024 Senior Notes

On October 28, 2016, we issued $500.0 million in aggregate principal amount of 4.750% senior notes due 2024, which we refer to as the existing 2024 senior notes. The existing 2024 senior notes bear interest at a rate of 4.750% per annum, payable semi-annually, in arrears on May 1 and November 1 of each year, commencing on May 1, 2017 and will mature on November 1, 2024. All of our existing and future restricted subsidiaries that guarantee our revolving credit facility or certain other debt guarantee the existing 2024 senior notes; provided, however, that the existing 2024 senior notes are not guaranteed by Viper, Viper Energy Partners GP LLC, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of our future unrestricted subsidiaries.


51




On September 25, 2018, we issued $750.0 million aggregate principal amount of new 4.750% senior notes due 2024, which we refer to as the new 2024 notes and, together with the existing 2024 senior notes, as the 2024 senior notes, as additional notes under, and subject to the terms of, the 2024 Indenture (as defined below). The new 2024 notes were issued in a transaction exempt from the registration requirements under the Securities Act. We received approximately $740.7 million in net proceeds, after deducting the initial purchasers’ discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of the new 2024 notes. We used a portion of the net proceeds from the issuance of the new 2024 notes to repay a portion of the outstanding borrowings our revolving credit facility and the balance for general corporate purposes, including funding a portion of the cash consideration for the acquisition of assets from Ajax.

The 2024 senior notes were issued under, and are governed by, an indenture among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee (which, as may be amended or supplemented from time to time, is referred to as the 2024 Indenture). The 2024 Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make other distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and natural gas business and designate certain of our subsidiaries as unrestricted subsidiaries.

We may on any one or more occasions redeem some or all of the 2024 senior notes at any time on or after November 1, 2019 at the redemption prices (expressed as percentages of principal amount) of 103.563% for the 12-month period beginning on November 1, 2019, 102.375% for the 12-month period beginning on November 1, 2020, 101.188% for the 12-month period beginning on November 1, 2021 and 100.000% beginning on November 1, 2022 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to November 1, 2019, we may on any one or more occasions redeem all or a portion of the 2024 senior notes at a price equal to 100% of the principal amount of the 2024 senior notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to November 1, 2019, we may on any one or more occasions redeem the 2024 senior notes in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2024 senior notes issued prior to such date at a redemption price of 104.750%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings.

Under a registration rights agreement executed in connection with the issuance of the new 2024 notes, we and our subsidiary guarantors agreed to file, subject to certain conditions, a registration statement relating to the new 2024 notes with the SEC pursuant to which we will either offer to exchange the new 2024 notes for registered notes with substantially identical terms or, in certain circumstances, register the resale of the new 2024 notes. Additional interest on the new 2024 notes may become payable if we do not comply with our obligations under the registration rights agreement relating to the new 2024 notes.

2025 Senior Notes

On December 20, 2016, we issued $500.0 million in aggregate principal amount of 5.375% senior notes due 2025, which we refer to as the exiting 2025 notes, under an indenture (which, as may be amended or supplemented from time to time, is referred to as the 2025 Indenture) among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee. On July 27, 2017, we exchanged all of the existing 2025 notes for substantially identical notes in the same aggregate principal amount that were registered under the Securities Act.
On January 29, 2018, we issued $300.0 million aggregate principal amount of new 5.375% senior notes due 2025, which we refer to as the new 2025 notes, as additional notes under the 2025 Indenture. The new 2025 notes were issued in a transaction exempt from the registration requirements under the Securities Act. We refer to the new 2025 notes, together with the existing 2025 notes, as the 2025 senior notes. We received approximately $308.4 million in net proceeds, after deducting the initial purchaser’s discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of the new 2025 notes. We used the net proceeds from the issuance of the new 2025 notes to repay a portion of the outstanding borrowings under our revolving credit facility.
The 2025 senior notes bear interest at a rate of 5.375% per annum, payable semi-annually, in arrears on May 31 and November 30 of each year and will mature on May 31, 2025. All of our existing and future restricted subsidiaries that guarantee our revolving credit facility or certain other debt guarantee the 2025 senior notes; provided, however, that the 2025 senior notes are not guaranteed by Viper, Viper Energy Partners GP LLC, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of our future unrestricted subsidiaries.

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The 2025 Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make other distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and natural gas business and designate certain of our subsidiaries as unrestricted subsidiaries.
We may on any one or more occasions redeem some or all of the 2025 senior notes at any time on or after May 31, 2020 at the redemption prices (expressed as percentages of principal amount) of 104.031% for the 12-month period beginning on May 31, 2020, 102.688% for the 12-month period beginning on May 31, 2021, 101.344% for the 12-month period beginning on May 31, 2022 and 100.000% beginning on May 31, 2023 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to May 31, 2020, we may on any one or more occasions redeem all or a portion of the 2025 senior notes at a price equal to 100% of the principal amount of the 2025 senior notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to May 31, 2020, we may on any one or more occasions redeem the 2025 senior notes in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2025 senior notes issued prior to such date at a redemption price of 105.375%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings.

As required under the terms of the registration rights agreements relating to the new 2025 senior notes, we filed with the SEC our Registration Statement on Form S-4 relating to the exchange offers of the new 2025 senior notes for substantially identical notes registered under the Securities Act. The Registration Statement was declared effective by the SEC on July 18, 2018 and we closed the exchange offer on August 24, 2018.
Second Amended and Restated Credit Facility

Our credit agreement dated November 1, 2013, as amended and restated, with a syndicate of banks, including Wells Fargo, as administrative agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger, provides for a revolving credit facility in the maximum credit amount of $5.0 billion, subject to a borrowing base based on our oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be redetermined, under certain circumstances, annually with an effective date of May 1st, and, under certain circumstances, semi-annually with effective dates of May 1st and November 1st. In addition, we and Wells Fargo may each request up to two interim redeterminations of the borrowing base during any 12-month period. As of September 30, 2018, the borrowing base was set at $2.0 billion, we had elected a commitment amount of $1.0 billion and we had no outstanding borrowings under the revolving credit facility and $1.0 billion available for future borrowings under our revolving credit facility. On October 26, 2018, our credit agreement was further amended to increase the borrowing base to $2.5 billion, which was increased further to $2.65 billion on November 6, 2018 following our closing of the Ajax acquisition and satisfaction of certain other conditions. We also elected to increase the commitment amount from $1.0 billion to $2.0 billion effective October 26, 2018. In addition, this amendment increased our flexibility to make restricted payments and redeem senior unsecured notes.

Diamondback O&G LLC is the borrower under our credit agreement. As of September 30, 2018, the credit agreement is guaranteed by us, Diamondback E&P LLC and Rattler Midstream LLC (formerly known as White Fang Energy LLC) and will also be guaranteed by any of our future subsidiaries that are classified as restricted subsidiaries under the credit agreement. The credit agreement is also secured by substantially all of our assets and the assets of Diamondback O&G LLC and the guarantors.
The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by us that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.25% to 1.25% in the case of the alternative base rate and from 1.25% to 2.25% in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the least of the maximum credit amount, the borrowing base and the elected commitment amount. We are obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2022.


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The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.
Financial CovenantRequired Ratio
Ratio of total net debt to EBITDAX, as defined in the credit agreementNot greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreementNot less than 1.0 to 1.0

The covenant prohibiting additional indebtedness, as amended in November 2017, allows for the issuance of unsecured debt in the form of senior or senior subordinated notes if no default would result from the incurrence of such debt after giving effect thereto and if, in connection with any such issuance, the borrowing base is reduced by 25% of the stated principal amount of each such issuance.
As of September 30, 2018, we were in compliance with all financial covenants under our revolving credit facility. The lenders may accelerate all of the indebtedness under our revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. With certain specified exceptions, the terms and provisions of our revolving credit facility generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.

Viper’s Facility-Wells Fargo Bank

On July 8, 2014, Viper entered into a secured revolving credit agreement, or revolving credit facility, with Wells Fargo, as administrative agent, certain other lenders, and the Operating Company, as guarantor. On May 8, 2018, the Operating Company assumed all liabilities as borrower under the credit agreement and Viper became a guarantor of the credit agreement. On July 20, 2018, the Operating Company, Viper, Wells Fargo and the other lenders amended and restated the credit agreement to reflect the assumption by the Operating Company. The credit agreement, as amended and restated, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on Viper’s oil and natural gas reserves and other factors (the “borrowing base”) of $475.0 million, subject to scheduled semi-annual and other borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and October 26th. In addition, the Operating Company and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12-month period. As of September 30, 2018, the borrowing base was set at $475.0 million, and Viper had $296.5 million of outstanding borrowings and $178.5 million available for future borrowings under its revolving credit facility. In connection with Viper’s fall 2018 redetermination, Viper’s borrowing base was increased to $555.0 million effective October 26, 2018.
The outstanding borrowings under Viper’s credit agreement bear interest at a per annum rate elected by the Operating Company that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.75% to 1.75% per annum in the case of the alternate base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount and the borrowing base. The Operating Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2022. The loan is secured by substantially all of the assets of Viper and the Operating Company.


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The Viper credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements, and require the maintenance of the financial ratios described below:
Financial CovenantRequired Ratio
Ratio of total net debt to EBITDAX, as defined in the credit agreementNot greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreementNot less than 1.0 to 1.0

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $400.0 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.

The lenders may accelerate all of the indebtedness under the revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.

Capital Requirements and Sources of Liquidity

Our board of directors approved a 2018 capital budget for drilling and infrastructure of approximately $1.5 billion to $1.6 billion, representing an increase of 74% over our 2017 capital budget. We estimate that, of these expenditures, approximately:

$1.25 billion to $1.3 billion will be spent on drilling and completing 170 to 175 gross (146 to 163 net) horizontal wells across our operated leasehold acreage in the Northern Midland and Southern Delaware Basins, with an average lateral length of approximately 9.300 feet; and

$225.0 million to $275.0 million will be spent on infrastructure and other expenditures, excluding the cost of any leasehold and mineral interest acquisitions.

During the nine months ended September 30, 2018, our aggregate capital expenditures for our development program were $1.0 billion. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted. During the nine months ended September 30, 2018, we spent approximately $521.2 million in cash on acquisitions of leasehold interests and mineral acres. Subsequently, on October 31, 2018, we purchased certain oil and natural gas assets for an aggregate of $1,212.5 million in cash and approximately 2.6 million shares of our common stock, subject to certain adjustments. We funded the cash portion of the consideration for these acquisitions through a combination of cash on hand, proceeds from the Drop-down Transaction, borrowings under our revolving credit facility and a portion of the proceeds from our issuance of the new 2024 notes. For a discussion of these acquisitions and the Pending Merger to acquire Energen in an all-stock transaction valued at approximately $9.2 billion, including Energen’s net debt of $831.0 million as of June 30, 2018, see “—2018 Highlights” above.

The amount and timing of these capital expenditures are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. We are currently operating 11 drilling rigs and five completion crews. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions.

Based upon current oil and natural gas prices and production expectations for 2018, we believe that our cash flow from operations, cash on hand and borrowings under our revolving credit facility will be sufficient to fund our operations through year-end 2018. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. Further, our 2018 capital expenditure budget does not allocate any funds for leasehold interest and property acquisitions.

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We monitor and adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control. If we require additional capital, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financing, asset sales, offerings of debt and or equity securities or other means. We cannot assure you that the needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our drilling programs, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves. If there is a decline in commodity prices, our revenues, cash flows, results of operations, liquidity and reserves may be materially and adversely affected.

Contractual Obligations

Except as discussed in Note 16 of the Notes to the Consolidated Financial Statements of this report, there were no material changes to our contractual obligations and other commitments, as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017.

Critical Accounting Policies

There have been no changes in our critical accounting policies from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of September 30, 2018. Please read Note 16 included in Notes to the Consolidated Financial Statements set forth in Part I, Item 1 of this report, for a discussion of our commitments and contingencies, some of which are not recognized in the balance sheets under GAAP.


ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control.

We use price swap derivatives, including basis swaps and costless collars, to reduce price volatility associated with certain of our oil and natural gas sales. With respect to these fixed price swap contracts, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap price, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. Our derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate pricing (Cushing and Magellan East Houston) and Crude Oil - Brent and with natural gas derivative settlements based on NYMEX Henry Hub pricing.

At September 30, 2018 and December 31, 2017, we had a net liability derivative position of $129.8 million and $106.7 million, respectively, related to our price swap derivatives. Utilizing actual derivative contractual volumes under our fixed price swaps as of September 30, 2018, a 10% increase in forward curves associated with the underlying commodity would have increased the net liability position to $137.7 million, an increase of $7.9 million, while a 10% decrease in forward curves associated with the underlying commodity would have decreased the net liability derivative position to $121.9 million, a decrease of $7.9 million. However, any cash derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from joint interest receivables (approximately $82.0 million at September 30, 2018) and receivables from the sale of our oil and natural gas production (approximately $182.4 million at September 30, 2018).

We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. For the nine months ended September 30, 2018, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (26%), Koch Supply & Trading LP (18%), and Rio Oil & Gas LLC (11%). For the nine months ended September 30, 2017, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (33%); Koch Supply & Trading LP (20%); and Enterprise Crude Oil LLC (11%). No other customer accounted for more than 10% of our revenue during these periods.
 
Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells. At September 30, 2018, we had seven customers that represented approximately 76% of our total joint operations receivables. At December 31, 2017, we had three customers that represented approximately 74% of our total joint operations receivables.

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Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facility. The terms of our revolving credit facility provide for interest on borrowings at a floating rate equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.25% to 1.25% in the case of the alternative base rate and from 1.25% to 2.25% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base.

As of September 30, 2018, we had no outstanding borrowings under our revolving credit facility. As of October 31, 2018, upon the closing of the Ajax acquisition and the ExL acquisition, we had $748.0 million in outstanding borrowings under our revolving credit facility. Our weighted average interest rate on borrowings under our revolving credit facility was 3.8% as of October 31, 2018. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our interest expense of approximately $7.5 million based on an aggregate of $748.0 million outstanding under our revolving credit facility as of October 31, 2018 upon the closing of the Ajax acquisition and ExL acquisition.

ITEM 4.          CONTROLS AND PROCEDURES

Evaluation of Disclosure Control and Procedures

Under the direction of our Chief Executive Officer and Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, or the Exchange Act, that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

As of September 30, 2018, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as of September 30, 2018, our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There have not been any changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2018 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.


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PART II
ITEM 1. LEGAL PROCEEDINGS

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment related disputes.
In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.
 
ITEM 1A. RISK FACTORS

Our business faces many risks. Any of the risks discussed in this Form 10-Q and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also materially impair our business operations, financial condition or future results.

In addition to the information set forth in this report, you should carefully consider the risk factors discussed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2017. Except as disclosed in our 424(b)(3) prospectus, which we refer to as the merger prospectus, filled by us with the SEC on October 25, 2018 in connection with our pending merger with Energen, which contains, among other things, additional risk factors relating to such merger, there have been no material changes in our risk factors from those described in our Annual Report on Form 10-K for the year ended December 31, 2017.


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ITEM 6.    EXHIBITS
EXHIBIT INDEX
Exhibit NumberDescription
2.1#

3.1
3.2
4.1
4.2
4.3
4.4
4.5

4.6

4.7
4.8
4.9

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Exhibit NumberDescription
4.10*

10.1
31.1*
31.2*
32.1**
32.2**
101.INS*XBRL Instance Document.
101.SCH*XBRL Taxonomy Extension Schema Document.
101.CAL*XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE*XBRL Taxonomy Extension Presentation Linkbase Document.
______________
*Filed herewith.
**The certifications attached as Exhibit 32.1 and Exhibit 32.2 accompany this Annual Report on Form 10-K pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.
#
Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant hereby undertakes to furnish supplementally copies of any of the omitted schedules upon request by the SEC.


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SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

  DIAMONDBACK ENERGY, INC.
  
Date:November 7, 2018/s/ Travis D. Stice
  Travis D. Stice
  Chief Executive Officer
  (Principal Executive Officer)
  
Date:November 7, 2018/s/ Teresa L. Dick
  Teresa L. Dick
  Chief Financial Officer
  (Principal Financial and Accounting Officer)



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