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EX-32.1 - EXHIBIT 32.1 - Diamondback Energy, Inc.exhibitcertification321q22.htm
EX-32.2 - EXHIBIT 32.2 - Diamondback Energy, Inc.exhibitcertification322q22.htm
EX-31.1 - EXHIBIT 31.1 - Diamondback Energy, Inc.exhibitcertification311q22.htm
EX-31.2 - EXHIBIT 31.2 - Diamondback Energy, Inc.exhibitcertification312q22.htm
EX-10.1 - EXHIBIT 10.1 - Diamondback Energy, Inc.ex101viperfirstamendment81.htm
EX-10.2 - EXHIBIT 10.2 - Diamondback Energy, Inc.ex102vipersecondamendment5.htm


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

 
 
FORM 10-Q

 
ý
QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED June 30, 2015
OR
o
TRANSITION 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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).    Yes  ý    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check One):
Large Accelerated Filer
 
ý
 
Accelerated Filer
 
o
 
 
 
 
Non-Accelerated Filer
 
o
 
Smaller Reporting Company
 
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 August 5, 2015, 63,678,945 shares of the registrant’s common stock were outstanding.





 
 
 
 
Page
 
 
ITEM1.
 
 
 
 
 
 
 
 
 
 
 
ITEM 2.
 
ITEM 3.
 
ITEM 4.
 
 
 
ITEM 1.
 
ITEM 1A.
 
ITEM 6.
 
 
 
 
 
 
 








GLOSSARY OF OIL AND NATURAL GAS TERMS
The following is a description of the meanings of some of the oil and natural gas industry terms used throughout this report:
3-D seismic. Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.
Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
Bbls/d. Bbls per day.
Brent. Brent sweet light crude oil.
BOE. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/d. BOE per day.
Completion. The 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.
Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.
Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Finding and development costs. Capital 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.
Fracturing. The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Horizontal drilling. A 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.
LLS. Light Louisiana sweet crude oil.
MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.
MBOE. One thousand barrels of crude oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Mcf. Thousand cubic feet of natural gas.
Mcf/d. Mcf per day.
MMBtu. Million British Thermal Units.
MMcf. Million cubic feet of natural gas.

ii



Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.
Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.
PDP. Proved developed producing.
Play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.
Plugging and abandonment. Refers 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.
PUD. Proved undeveloped.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

Prospect. A 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 developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reserves. The 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.
Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
Reservoir. A 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.
Stratigraphic play. An oil or natural gas formation contained within an area created by permeability and porosity changes characteristic of the alternating rock layer that result from the sedimentation process.
Structural play. An oil or natural gas formation contained within an area created by earth movements that deform or rupture (such as folding or faulting) rock strata.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Working interest. The 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.
WTI. West Texas Intermediate, also known as Texas light sweet crude oil.



iii



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 of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, or 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 Quarterly Report on Form 10–Q 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,
2014 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;
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. 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.


iv

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




                                                                                                          
 
 
June 30,
 
December 31,
 
 
2015
 
2014
 
 
 
 
 
 
 
(In thousands, except par values and share data)
Assets
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
44,678

 
$
30,183

Restricted cash
 
500

 
500

Accounts receivable:
 
 
 
 
Joint interest and other
 
28,032

 
50,943

Oil and natural gas sales
 
42,379

 
43,050

Related party
 

 
4,001

Inventories
 
2,658

 
2,827

Derivative instruments
 
47,910

 
115,607

Prepaid expenses and other
 
4,205

 
4,600

Total current assets
 
170,362

 
251,711

Property and equipment
 
 
 
 
Oil and natural gas properties, based on the full cost method of accounting ($1,071,531 and $773,520 excluded from amortization at June 30, 2015 and December 31, 2014, respectively)
 
3,712,812

 
3,118,597

Pipeline and gas gathering assets
 
7,174

 
7,174

Other property and equipment
 
48,654

 
48,180

Accumulated depletion, depreciation, amortization and impairment
 
(822,243
)
 
(382,144
)
 
 
2,946,397

 
2,791,807

Derivative instruments
 

 
1,934

Other assets
 
54,699

 
50,029

Total assets
 
$
3,171,458

 
$
3,095,481

Liabilities and Stockholders’ Equity
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable-trade
 
$
23,309

 
$
26,230

Accrued capital expenditures
 
24,746

 
129,397

Other accrued liabilities
 
60,471

 
41,149

Revenues and royalties payable
 
19,108

 
30,000

Deferred income taxes
 
15,005

 
39,953

Total current liabilities
 
142,639

 
266,729

Long-term debt
 
718,000

 
673,500

Asset retirement obligations
 
11,851

 
8,447

Deferred income taxes
 
55,349

 
161,592

Total liabilities
 
927,839

 
1,110,268

Commitments and contingencies (Note 14)
 


 


Stockholders’ equity:
 
 
 
 
Common stock, $0.01 par value, 100,000,000 shares authorized, 63,675,209 issued and outstanding at June 30, 2015; 57,887,583 issued and outstanding at December 31, 2014
 
637

 
569

Additional paid-in capital
 
2,019,621

 
1,554,174

Retained earnings (Accumulated deficit)
 
(10,170
)
 
196,268

Total Diamondback Energy, Inc. stockholders’ equity
 
2,010,088

 
1,751,011

Noncontrolling interest
 
233,531


234,202

Total equity
 
2,243,619

 
1,985,213

Total liabilities and equity
 
$
3,171,458

 
$
3,095,481

See accompanying notes to combined consolidated financial statements.


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



 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
 
 
 
 
 
 
 
 
 
(In thousands, except per share amounts)
Revenues:
 
 
 
 
 
 
 
 
Oil sales
 
$
107,627

 
$
115,282

 
200,543

 
205,040

Natural gas sales
 
4,410

 
1,913

 
6,118

 
3,668

Natural gas sales - related party
 

 
2,416

 
2,640

 
3,996

Natural gas liquid sales
 
7,026

 
3,304

 
8,619

 
5,888

Natural gas liquid sales - related party
 

 
4,089

 
2,544

 
6,416

Total revenues
 
119,063

 
127,004

 
220,464

 
225,008

Costs and expenses:
 
 
 
 
 
 
 
 
Lease operating expenses
 
20,472

 
10,425

 
42,928

 
18,232

Lease operating expenses - related party
 

 
71

 

 
179

Production and ad valorem taxes
 
7,675

 
8,106

 
15,917

 
13,684

Production and ad valorem taxes - related party
 

 
448

 
153

 
712

Gathering and transportation
 
1,625

 
102

 
1,686

 
316

Gathering and transportation - related party
 

 
601

 
969

 
969

Depreciation, depletion and amortization
 
57,096

 
40,021

 
116,773

 
70,994

Impairment of oil and gas properties
 
323,451

 

 
323,451

 

General and administrative expenses (including non-cash stock based compensation, net of capitalized amounts, of $4,333 and $1,128 for the three months ended June 30, 2015 and 2014, respectively, and $9,257 and $3,318 for the six months ended June 30, 2015 and 2014, respectively)
 
7,162

 
3,610

 
14,913

 
7,875

General and administrative expenses - related party
 
522

 
324

 
1,007

 
616

Asset retirement obligation accretion expense
 
180

 
104

 
350

 
176

Total costs and expenses
 
418,183

 
63,812

 
518,147

 
113,753

Income (loss) from operations
 
(299,120
)
 
63,192

 
(297,683
)
 
111,255

Other income (expense)
 
 
 
 
 
 
 
 
Interest expense
 
(10,274
)
 
(7,739
)
 
(20,771
)
 
(14,244
)
Other income
 
378

 

 
870

 

Other income - related party
 
55

 
30

 
78

 
60

Other expense
 

 
(1,408
)
 

 
(1,408
)
Loss on derivative instruments, net
 
(19,123
)
 
(11,088
)
 
(769
)
 
(15,486
)
Total other income (expense), net
 
(28,964
)
 
(20,205
)
 
(20,592
)
 
(31,078
)
Income (loss) before income taxes
 
(328,084
)
 
42,987

 
(318,275
)
 
80,177

Provision for (benefit from) income taxes
 
(116,732
)
 
15,163

 
(113,362
)
 
28,764

Net income (loss)
 
(211,352
)
 
27,824

 
(204,913
)
 
51,413

Less: Net income attributable to noncontrolling interest
 
935

 
71

 
1,525

 
71

Net income (loss) attributable to Diamondback Energy, Inc.
 
$
(212,287
)
 
$
27,753

 
(206,438
)
 
51,342

 
 
 
 
 
 
 
 
 
Earnings per common share
 

 

 

 

Basic
 
$
(3.45
)
 
$
0.55

 
$
(3.44
)
 
$
1.03

Diluted
 
$
(3.45
)
 
$
0.54

 
$
(3.44
)
 
$
1.02

Weighted average common shares outstanding
 
 
 
 
 
 
 
 
Basic
 
61,469

 
50,777

 
59,936

 
49,622

Diluted
 
61,469

 
51,142

 
59,936

 
50,047


See accompanying notes to combined consolidated financial statements.

2

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


 
 
 
 
 
 
 
Retained
 
 
 
 
 
 
 
 
Additional
 
Earnings/
 
 
 
 
 
 
Common Stock
 
Paid-in
 
(Accumulated
 
Non-controlling
 
 
 
 
Shares
Amount
 
Capital
 
Deficit)
 
Interest
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance December 31, 2013
 
47,106

$
471

 
$
842,557

 
$
2,513

 
$

 
$
845,541

 
 
 
 
 
 
 
 
 
 
 
 
Net proceeds from issuance of common units - Viper Energy Partners LP
 


 

 

 
137,365

 
137,365

Unit-based compensation
 


 

 

 

 

Stock-based compensation
 


 
5,906

 

 

 
5,906

Common shares issued in public offering, net of offering costs
 
3,450

35

 
208,394

 

 

 
208,429

Exercise of stock options and vesting of restricted stock units
 
251

3

 
3,680

 

 

 
3,683

Net income
 


 

 
51,342

 
71

 
51,413

Balance June 30, 2014
 
50,807

$
509

 
$
1,060,537

 
$
53,855

 
$
137,436

 
$
1,252,337

 
 
 
 
 
 
 
 
 
 
 
 
Balance December 31, 2014
 
56,888

$
569

 
$
1,554,174

 
$
196,268

 
$
234,202

 
$
1,985,213

 
 
 
 
 
 
 
 
 
 
 
 
Unit-based compensation
 


 

 

 
1,878

 
1,878

Stock-based compensation
 


 
10,970

 

 

 
10,970

Distribution to noncontrolling interest
 


 

 

 
(4,074
)
 
(4,074
)
Common shares issued in public offering, net of offering costs
 
6,613

66

 
452,689

 

 

 
452,755

Exercise of stock options and vesting of restricted stock units
 
174

2

 
1,788

 

 

 
1,790

Net income
 


 

 
(206,438
)
 
1,525

 
(204,913
)
Balance June 30, 2015
 
63,675

$
637

 
$
2,019,621

 
$
(10,170
)
 
$
233,531

 
$
2,243,619

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 













See accompanying notes to combined consolidated financial statements.

3

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

-
 
 
Six Months Ended June 30,
 
 
2015
 
2014
 
 
 
 
 
 
 
(In thousands)
Cash flows from operating activities:
 
 
 
 
Net income (loss)
 
$
(204,913
)
 
$
51,413

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
Provision for (benefit from) deferred income taxes
 
(131,191
)
 
28,764

Impairment of oil and gas properties
 
323,451

 

Asset retirement obligation accretion expense
 
350

 
176

Depreciation, depletion, and amortization
 
116,773

 
70,994

Amortization of debt issuance costs
 
1,279

 
946

Change in fair value of derivative instruments
 
69,631

 
10,810

Stock-based compensation expense
 
9,257

 
3,318

(Gain) loss on sale of assets, net
 

 
1,397

Changes in operating assets and liabilities:
 
 
 
 
Accounts receivable
 
9,055

 
(18,584
)
Accounts receivable-related party
 

 
(2,007
)
Inventories
 
169

 
977

Prepaid expenses and other
 
395

 
(219
)
Accounts payable and accrued liabilities
 
16,626

 
2,076

Accounts payable and accrued liabilities-related party
 

 

Accrued interest
 
(204
)
 
3,415

Revenues and royalties payable
 
(10,892
)
 
6,230

Net cash provided by operating activities
 
199,786

 
159,706

Cash flows from investing activities:
 
 
 
 
Additions to oil and natural gas properties
 
(242,281
)
 
(206,779
)
Additions to oil and natural gas properties-related party
 
(7
)
 
(2,571
)
Acquisition of leasehold interests
 
(435,398
)
 
(312,207
)
Pipeline and gas gathering assets
 

 
(1,165
)
Purchase of other property and equipment
 
(604
)
 
(934
)
Proceeds from sale of property and equipment
 

 
11

Equity investments
 
(1,675
)
 

Net cash used in investing activities
 
(679,965
)
 
(523,645
)
Cash flows from financing activities:
 
 
 
 
Proceeds from borrowings on credit facility
 
363,501

 
166,000

Repayment on credit facility
 
(319,001
)
 
(130,000
)
Debt issuance costs
 
(317
)
 
(1,039
)
Public offering costs
 
(285
)
 
(946
)
Proceeds from public offerings
 
453,060

 
347,679

Exercise of stock options
 
1,790

 
3,683

Distribution to non-controlling interest
 
(4,074
)
 

Net cash provided by financing activities
 
494,674

 
385,377

Net increase in cash and cash equivalents
 
14,495

 
21,438

Cash and cash equivalents at beginning of period
 
30,183

 
15,555

Cash and cash equivalents at end of period
 
$
44,678

 
$
36,993





4

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

 
 
Six Months Ended June 30,
 
 
2015
 
2014
 
 
 
 
 
 
 
(In thousands)
Supplemental disclosure of cash flow information:
 
 
 
 
Interest paid, net of capitalized interest
 
$
19,693

 
$
11,409

Supplemental disclosure of non-cash transactions:
 
 
 
 
Asset retirement obligation incurred
 
$
215

 
$
382

Asset retirement obligation revisions in estimated liability
 
$
78

 
$
588

Asset retirement obligation acquired
 
$
2,765

 
$
1,312

Change in accrued capital expenditures
 
$
(104,651
)
 
$
6,901

Capitalized stock-based compensation
 
$
3,591

 
$
2,715











































See accompanying notes to combined consolidated financial statements.

5

Diamondback Energy, Inc. and Subsidiaries
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.
On June 17, 2014, Diamondback entered into a contribution agreement (the “Contribution Agreement”) with Viper Energy Partners LP (the “Partnership”), Viper Energy Partners GP LLC (the “General Partner”) and Viper Energy Partners LLC to transfer Diamondback’s ownership interest in Viper Energy Partners LLC to the Partnership in exchange for 70,450,000 common units. Diamondback also owns and controls the General Partner, which holds a non-economic general partner interest in the Partnership. On June 23, 2014, the Partnership completed its initial public offering (the “Viper Offering”) of 5,750,000 common units, and the Company’s common units represented an approximate 92% limited partner interest in the Partnership. On September 19, 2014, the Partnership completed an underwritten public offering of 3,500,000 common units. At the completion of this offering, the Company owned approximately 88% of the common units of the Partnership. See Note 4—Viper Energy Partners LP for additional information regarding the Partnership.
The wholly-owned subsidiaries of Diamondback, as of June 30, 2015, 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, and White Fang Energy LLC, a Delaware limited liability company. The consolidated subsidiaries include the wholly-owned subsidiaries as well as Viper Energy Partners LP, a Delaware limited partnership, and Viper Energy Partners LLC, a Delaware limited liability 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 June 30, 2015, the Company owned approximately 88% of the common units of the Partnership and 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 Securities and Exchange Commission (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 accounting
principles generally accepted in the United States 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, 2014, 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

6




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


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, stock-based compensation, fair value estimates of commodity derivatives and estimates of income taxes.
New Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers”. ASU 2014-09 supersedes most of the existing revenue recognition requirements in GAAP and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing, and certainty of revenue and cash flows from contracts with customers. The standard will be effective for annual and interim reporting periods beginning after December 15, 2016, with early application not permitted. The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Company is currently evaluating the impact, if any, that the adoption of ASU 2014-09 will have on the Company’s financial position, results of operations, and liquidity.

In April 2015, the FASB issued ASU 2015-03, “Interest—Imputation of Interest”. ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from that debt liability, consistent with the presentation of a debt discount to simplify the presentation of debt issuance costs. The standard will be effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within fiscal years beginning after December 15, 2016. Early application will be permitted for financial statements that have not previously been issued. Adoption of the new guidance will only affect the presentation of the Company’s consolidated balance sheets and will not have a material impact on its consolidated financial statements.

3.    ACQUISITIONS
2015 Activity

Since January 1, 2015, the Company has completed acquisitions from unrelated third party sellers of an aggregate of approximately 15,940 gross (11,864 net) acres in the Midland Basin, primarily in northwest Howard County, in the Permian Basin, for an aggregate purchase price of approximately $435.4 million, subject to certain adjustments. The acquisitions were accounted for according to the acquisition method, which requires the recording of net assets acquired and consideration transferred at fair value. These acquisitions were funded with the net proceeds of the May 2015 equity offering discussed in Note 9 below and borrowings under the Company’s revolving credit facility discussed in Note 8 below.

2014 Activity
On September 9, 2014, the Company completed the acquisition of oil and natural gas interests in the Permian Basin from unrelated third party sellers. The Company acquired approximately 17,617 gross (12,967 net) acres with an approximate 74% working interest (approximately 75% net revenue interest). The acquisition was accounted for according to the acquisition method, which requires the recording of net assets acquired and consideration transferred at fair value. This acquisition was funded with the net proceeds of the July 2014 equity offering discussed in Note 9 below and borrowings under the Company’s revolving credit facility discussed in Note 8 below.
There were no material changes from the purchase price allocation disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.
The Company has included in its consolidated statements of operations revenues of $5.8 million and direct operating expenses of $3.4 million for the three months ended June 30, 2015 due to the acquisition and revenues of $11.0 million and direct operating expenses of $7.1 million for the six months ended June 30, 2015 due to the acquisition. The disclosure of net earnings is impracticable to calculate due to the full cost method of depletion.

7




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


On February 27 and 28, 2014, the Company completed acquisitions of oil and natural gas interests in the Permian Basin from unrelated third party sellers. The Company acquired approximately 6,450 gross (4,785 net) acres with a 74% working interest (56% net revenue interest). The acquisitions were accounted for according to the acquisition method, which requires the recording of net assets acquired and consideration transferred at fair value. These acquisitions were funded with the net proceeds of the February 2014 equity offering discussed in Note 9 below and borrowings under the Company’s revolving credit facility discussed in Note 8 below.
There were no material changes from the purchase price allocation disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.
The Company has included in its consolidated statements of operations revenues of $10.4 million and direct operating expenses of $2.8 million for the three months ended June 30, 2015 and revenues of $14.3 million and direct operating expenses of $3.5 million for the three months ended June 30, 2014, due to the acquisitions. The Company has included in its consolidated statements of operations revenues of $17.2 million and direct operating expenses of $5.8 million for the six months ended June 30, 2015 and revenues of $19.2 million and direct operating expenses of $4.6 million for the period from February 28, 2014 to June 30, 2014, due to the acquisitions. The disclosure of net earnings is impracticable to calculate due to the full cost method of depletion.
Pro Forma Financial Information
The following unaudited summary pro forma combined consolidated statement of operations data of Diamondback for the three months and six months ended June 30, 2014 have been prepared to give effect to the February 27 and 28, 2014 acquisitions and the September 9, 2014 acquisition as if they had occurred on January 1, 2013. The pro forma data are not necessarily indicative of financial results that would have been attained had the acquisitions occurred on January 1, 2013. 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.
 
 
Pro Forma
 
 
(Unaudited)
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30, 2014
 
June 30, 2014
 
 
 
 
 
 
 
(in thousands)
Revenues
 
$
141,527

 
$
261,471

Income from operations
 
68,761

 
123,459

Net income
 
31,229

 
59,026



4.    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. Viper Energy Partners GP LLC, a fully- consolidated subsidiary of Diamondback, serves as the general partner of, and holds a non-economic general partner interest in, the Partnership. As of June 30, 2015, the Company owned approximately 88% of the common units of the Partnership. Prior to the completion on June 23, 2014 of the Viper Offering, Diamondback owned all of the general and limited partner interests in the Partnership.

Prior to the completion on June 23, 2014 of the Viper Offering, Diamondback owned all of the general and limited
partner interests in the Partnership. The Viper Offering consisted of 5,750,000 common units representing
approximately 8% of the limited partner interests in the Partnership at a price to the public of $26.00 per common
unit, which included 750,000 common units issued pursuant to an option to purchase additional common units
granted to the underwriters on the same terms. The Partnership received net proceeds of approximately $137.2
million from the sale of these common units, net of offering expenses and underwriting discounts and commissions.

In connection with the Viper Offering, Diamondback contributed all of the membership interests in Viper Energy Partners LLC to the Partnership in exchange for 70,450,000 common units. In addition, in connection with the

8




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


closing of the Viper Offering, the Partnership agreed to distribute to Diamondback all cash and cash equivalents and
the royalty income receivable on hand in the aggregate amount of approximately $11.3 million and the net proceeds
from the Viper Offering. As of June 30, 2014, the Partnership had distributed $137.5 million to Diamondback and
the Partnership recorded a payable balance of approximately $11.3 million. The contribution of Viper Energy Partners LLC to the Partnership was accounted for as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests. During the three months and six months ended June 30, 2015, the Partnership distributed $13.4 million and $31.0 million, respectively, to Diamondback in respect of its common units.

Partnership Agreement
In connection with the closing of the Viper Offering, the General Partner and Diamondback entered into the first amended and restated agreement of limited partnership (the “Partnership Agreement”), dated June 23, 2014. 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.
Tax Sharing
In connection with the closing of the Viper Offering, the Partnership entered into a tax sharing agreement (the “Tax Sharing Agreement”) with Diamondback pursuant to which the Partnership will 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 would 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.
Other Agreements
See Note 11—Related Party Transactions for details of the advisory services agreement the Partnership and General Partner entered into with Wexford Capital LP (“Wexford”).
The Partnership has entered into a secured revolving credit facility with Wells Fargo Bank, National Association, (“Wells Fargo”) as administrative agent sole book runner and lead arranger. See Note 8—Debt for a description of this credit facility.

9




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


5.    PROPERTY AND EQUIPMENT
Property and equipment includes the following:
 
 
June 30,
 
December 31,
 
 
2015
 
2014
 
 
 
 
 
 
 
(in thousands)
Oil and natural gas properties:
 
 
 
 
Subject to depletion
 
$
2,641,281

 
$
2,345,077

Not subject to depletion-acquisition costs
 
 
 
 
Incurred in 2015
 
384,799

 

Incurred in 2014
 
549,326

 
576,802

Incurred in 2013
 
74,109

 
130,474

Incurred in 2012
 
63,297

 
65,480

Incurred in 2011
 

 
764

Total not subject to depletion
 
1,071,531

 
773,520

Gross oil and natural gas properties
 
3,712,812

 
3,118,597

Accumulated depletion
 
(818,848
)
 
(379,481
)
Oil and natural gas properties, net
 
2,893,964

 
2,739,116

Pipeline and gas gathering assets
 
7,174

 
7,174

Other property and equipment
 
48,654

 
48,180

Accumulated depreciation
 
(3,395
)
 
(2,663
)
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment
 
$
2,946,397

 
$
2,791,807

Accumulated depletion includes an impairment of oil and gas properties of $323.5 million due to the significant decline in prices from over $105.00 per Bbl in June 2014 to a range of prices between $45.00 per Bbl and $60.00 per Bbl during the six months ended June 30, 2015.
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. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized internal costs were approximately $1.5 million and $2.6 million for the three months ended June 30, 2015 and 2014, respectively, and $3.6 million and $4.9 million for the six months ended June 30, 2015 and 2014, 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.


10




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


6.    ASSET RETIREMENT OBLIGATIONS
The following table describes the changes to the Company’s asset retirement obligation liability for the following periods:
 
Six Months Ended June 30,
 
2015
 
2014
 
 
 
 
 
(in thousands)
Asset retirement obligation, beginning of period
$
8,486

 
$
3,029

Additional liability incurred
215

 
382

Liabilities acquired
2,765

 
1,312

Liabilities settled
(4
)
 
(10
)
Accretion expense
350

 
176

Revisions in estimated liabilities
78

 
588

Asset retirement obligation, end of period
11,890

 
5,477

Less current portion
39

 
40

Asset retirement obligations - long-term
$
11,851

 
$
5,437

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.
7.    EQUITY METHOD INVESTMENTS
In October 2014, the Company paid $0.6 million for a minority interest in an entity that 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. The board of this entity may also authorize the entity to offer these services to other counties in the Permian Basin and to pursue other business opportunities. The Company has committed to invest an aggregate amount of $5.0 million in this entity, and several other third parties have committed to invest an aggregate of $15.0 million. For both the three months and six months ended June 30, 2015, the Company invested an additional $1.7 million in this entity. The Company will retain a minority interest after all commitments are received. The entity was formed as a limited liability company and maintains a specific ownership account for each investor, similar to a partnership capital account structure. Therefore the Company accounts for this investment under the equity method of accounting.
8.    DEBT
Long-term debt consisted of the following as of the dates indicated:
 
 
June 30,
 
December 31,
 
 
2015
 
2014
 
 
 
 
 
 
 
(in thousands)
Revolving credit facility
 
$
268,000

 
$
223,500

7.625 % Senior Notes due 2021
 
450,000

 
450,000

Partnership revolving credit facility
 

 

Total long-term debt
 
$
718,000

 
$
673,500

 
 
 
 
 
Senior Notes
On September 18, 2013, the Company completed an offering of $450.0 million in aggregate principal amount of 7.625% senior unsecured notes due 2021 (the “Senior Notes”). The Senior Notes bear interest at the rate of 7.625% per annum, payable semi-annually, in arrears on April 1 and October 1 of each year, commencing on April 1, 2014 and will mature on October 1, 2021. On June 23, 2014, in connection with the Viper Offering, the Company

11




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


designated the Partnership, the General Partner and Viper Energy LLC as unrestricted subsidiaries and, upon such designation, Viper Energy LLC, which was a guarantor under the indenture governing of the Senior Notes, was released as a guarantor under the indenture. As of June 30, 2015, the Senior Notes are fully and unconditionally guaranteed by Diamondback O&G LLC, Diamondback E&P LLC and White Fang Energy LLC and will also be guaranteed by any future restricted subsidiaries of Diamondback. The net proceeds from the Senior Notes were used to fund the acquisition of mineral interests underlying approximately 14,804 gross (12,687 net) acres in Midland County, Texas in the Permian Basin.
The Senior Notes were issued under, and are governed by, an indenture among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as the trustee, as supplemented (the “Indenture”). The 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, or redeem or repurchase, capital stock, prepay subordinated indebtedness, sell assets including capital stock of 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 gas business and designate certain of the Company’s subsidiaries as unrestricted subsidiaries. If the Company experiences certain kinds of changes of control or if it sells certain of its assets, holders of the Senior Notes may have the right to require the Company to repurchase their Senior Notes.
The Company will have the option to redeem the Senior Notes, in whole or in part, at any time on or after October 1, 2016 at the redemption prices (expressed as percentages of principal amount) of 105.719% for the 12-month period beginning on October 1, 2016, 103.813% for the 12-month period beginning on October 1, 2017, 101.906% for the 12-month period beginning on October 1, 2018 and 100.000% beginning on October 1, 2019 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. In addition, prior to October 1, 2016, the Company may redeem all or a part of the Senior Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, plus a “make-whole” premium at the redemption date. Furthermore, before October 1, 2016, the Company may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the Senior Notes with the net cash proceeds of certain equity offerings at a redemption price of 107.625% of the principal amount of the Senior Notes being redeemed plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the Senior Notes originally issued under the Indenture remains outstanding immediately after such redemption and the redemption occurs within 120 days of the closing date of such equity offering.
In connection with the issuance of the Senior Notes, the Company and the subsidiary guarantors entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with the initial purchasers on September 18, 2013, pursuant to which the Company and the subsidiary guarantors agreed to file a registration statement with respect to an offer to exchange the Senior Notes for a new issue of substantially identical debt securities registered under the Securities Act, which registration statement was declared effective by the SEC on September 15, 2014 and the exchange offer completed on October 23, 2014.
Credit Facility-Wells Fargo Bank
On June 9, 2014, Diamondback entered into a first amendment (the “first amendment”) and on November 13, 2014, Diamondback entered into a second amendment (the “second amendment”) to the second amended and restated credit agreement, dated November 1, 2013 (together, the “credit agreement”). The first amendment modified certain provisions of the credit agreement to, among other things, allow the Company to designate one or more of its subsidiaries as “Unrestricted Subsidiaries” that are not subject to certain restrictions contained in the credit agreement. In connection with the Viper Offering, the Company designated the Partnership, the General Partner and Viper Energy LLC as unrestricted subsidiaries under the credit agreement. As of June 30, 2015, the loan is guaranteed by Diamondback, Diamondback E&P LLC and White Fang Energy LLC and will also be guaranteed by any future restricted subsidiaries of Diamondback. The credit agreement is also secured by substantially all of the assets of the Company, Diamondback O&G LLC and the guarantors.

The second amendment increased the maximum amount of the credit facility to $2.0 billion, modified the dates and deadlines of the credit agreement relating to the scheduled borrowing base redeterminations based on the Company’s oil and natural gas reserves and other factors (the “borrowing base”) and added new provisions that allow the Company to elect a commitment amount that is less than its borrowing base as determined by the lenders. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and November 1st. In addition, the Company may request up to three additional redeterminations of the borrowing base during any 12-

12




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


month period. As of June 30, 2015, the borrowing base was set at $725.0 million, of which the Company had elected a commitment amount of $500.0 million, and the Company had outstanding borrowings of $268.0 million.

The outstanding borrowings under the credit agreement bear interest at a rate elected by the Company that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.5% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. 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 borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be paid (a) if the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period) and (b) at the maturity date of November 1, 2018.

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 debt to EBITDAX
 
Not greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreement
 
Not less than 1.0 to 1.0

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $750.0 million in the form of senior or senior subordinated 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. As of June 30, 2015, the Company had $450.0 million of senior unsecured notes outstanding.

As of June 30, 2015 and December 31, 2014, 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.
Partnership Credit Facility-Wells Fargo Bank
On July 8, 2014, the Partnership entered into a secured revolving credit agreement with Wells Fargo, as the administrative agent, sole book runner and lead arranger. The credit agreement, which was amended August 15, 2014 to add additional lenders to the lending group, provides for a revolving credit facility in the maximum amount of $500.0 million, subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based on the Partnership’s oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be re-determined semi-annually with effective dates of April 1st and October 1st. In addition, the Partnership may request up to three additional redeterminations of the borrowing base during any 12-month period. The credit agreement was further amended on May 22, 2015 to, among other things, increase the borrowing base from $110.0 million to $175.0 million and to provide for certain restrictions on purchasing margin stock. As of June 30, 2015, the borrowing base remained at $175.0 million. The Partnership had no outstanding borrowings as of June 30, 2015.
The outstanding borrowings under the credit agreement bear interest at a rate elected by the Partnership that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.5% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The Partnership is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing

13




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


base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be paid (a) if the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period) and (b) at the maturity date of July 8, 2019. The loan is secured by substantially all of the assets of the Partnership and its subsidiaries.
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 debt to EBITDAX
 
Not greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreement
 
Not less than 1.0 to 1.0
EBITDAX is annualized for the four fiscal quarters ending on the last day of the fiscal quarter for which financial statements are available, beginning with the quarter ended September 30, 2014.


The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $250.0 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 Partnership’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.
9.    CAPITAL STOCK AND EARNINGS PER SHARE
As of June 30, 2015, Diamondback had completed the following equity offerings since January 1, 2014:
In February 2014, the Company completed an underwritten public offering of 3,450,000 shares of common stock, which included 450,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the public at $62.67 per share and the Company received net proceeds of approximately $208.4 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.
In July 2014, the Company completed an underwritten public offering of 5,750,000 shares of common stock, which included 750,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the public at $87.00 per share and the Company received net proceeds of approximately $485.0 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.
In January 2015, the Company completed an underwritten public offering of 2,012,500 shares of common stock, which included 262,500 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the underwriters at $59.34 per share and the Company received net proceeds of approximately $119.4 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.
In May 2015, the Company completed an underwritten public offering of 4,600,000 shares of common stock, which included 600,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the underwriters at $72.53 per share and the Company received net proceeds of approximately $333.6 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.



14




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


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. A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:

 
 
 
 
 
 
 
 
 
 
 
Three Months Ended June 30,
 
 
2015
 
2014
 
 
 
 
 
 
Per
 
 
 
 
 
Per
 
 
Income
 
Shares
 
Share
 
Income
 
Shares
 
Share
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(in thousands, except per share amounts)
Basic:
 
 
 
 
 
 
 
 
 
 
 
 
Net income attributable to common stock
 
$
(212,287
)
 
61,469

 
$
(3.45
)
 
27,753

 
50,777

 
$
0.55

Effect of Dilutive Securities:
 
 
 
 
 
 
 
 
 
 
 
 
Dilutive effect of potential common shares issuable
 
$

 

 
 
 
(74
)
 
365

 
 
Diluted:
 
 
 
 
 
 
 
 
 
 
 
 
Net income attributable to common stock
 
$
(212,287
)
 
61,469

 
$
(3.45
)
 
27,679

 
51,142

 
$
0.54

 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30,
 
 
2015
 
2014
 
 
 
 
 
 
Per
 
 
 
 
 
Per
 
 
Income
 
Shares
 
Share
 
Income
 
Shares
 
Share
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(in thousands, except per share amounts)
Basic:
 
 
 
 
 
 
 
 
 
 
 
 
Net income attributable to common stock
 
$
(206,438
)
 
59,936

 
$
(3.44
)
 
51,342

 
49,622

 
$
1.03

Effect of Dilutive Securities:
 
 
 
 
 
 
 
 
 
 
 
 
Dilutive effect of potential common shares issuable
 
$

 

 
 
 
(74
)
 
425

 
 
Diluted:
 
 
 
 
 
 
 
 
 
 
 
 
Net income attributable to common stock
 
$
(206,438
)
 
59,936

 
$
(3.44
)
 
51,268

 
50,047

 
$
1.02


For the three months and six months ended June 30, 2015, there were 283,000 shares and 306,000 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 but could potentially dilute basic earnings per share in future periods.






15




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


10.    STOCK AND UNIT BASED COMPENSATION
The following table presents the effects of the equity and stock based compensation plans and related costs:
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
General and administrative expenses
 
$
4,333

 
$
1,128

 
9,257

 
3,318

Stock based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties
 
1,452

 
1,649

 
3,591

 
2,715

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Stock Options
The following table presents the Company’s stock option activity under the Company’s 2012 Equity Incentive Plan (“2012 Plan”) for the six months ended June 30, 2015.
 
 
 
 
Weighted Average
 
 
 
 
 
 
Exercise
 
Remaining
 
Intrinsic
 
 
Options
 
Price
 
Term
 
Value
 
 
 
 
 
 
(in years)
 
(in thousands)
Outstanding at December 31, 2014
 
313,105

 
$
18.29

 
 
 
 
Granted
 

 
$

 
 
 
 
Exercised
 
(97,605
)
 
$
18.34

 
 
 
 
Expired/Forfeited
 

 
$

 
 
 
 
Outstanding at June 30, 2015
 
215,500

 
$
18.26

 
1.48
 
$
11,097

 
 
 
 
 
 
 
 
 
Vested and Expected to vest at June 30, 2015
 
215,500

 
$
18.26

 
1.48
 
$
11,097

Exercisable at June 30, 2015
 
59,000

 
$
17.50

 
1.37
 
$
1,474

The aggregate intrinsic value of stock options that were exercised during the six months ended June 30, 2015 and 2014 was $5,737,000 and $10,659,000, respectively. As of June 30, 2015, the unrecognized compensation cost related to unvested stock options was $279,000. Such cost is expected to be recognized over a weighted-average period of 1.0 years.
Restricted Stock Units
The following table presents the Company’s restricted stock units activity under the 2012 Plan during the six months ended June 30, 2015.
 
 
 
 
Weighted Average
 
 
Restricted Stock
 
Grant-Date
 
 
Units
 
Fair Value
Unvested at December 31, 2014
 
167,291

 
$
49.99

Granted
 
92,252

 
$
68.67

Vested
 
(77,421
)
 
$
48.73

Forfeited
 
(1,754
)
 
$
74.97

Unvested at June 30, 2015
 
180,368

 
$
52.72

The aggregate fair value of restricted stock units that vested during the six months ended June 30, 2015 and 2014 was $5,253,000 and $3,051,000, respectively. As of June 30, 2015, the Company’s unrecognized compensation cost

16




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


related to unvested restricted stock awards and units was $6,396,000. Such cost is expected to be recognized over a weighted-average period of 1.3 years.
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 three-year performance period. In February 2014, eligible employees received initial performance restricted stock unit awards totaling 79,150 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, 2013 to December 31, 2015 and cliff vest at December 31, 2015. In February 2015, eligible employees received additional performance restricted stock unit awards totaling 90,249 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, 2014 to December 31, 2016 and cliff vest at December 31, 2016.
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 2014 award.
 
 
 
2014
Grant-date fair value
 
$
125.63

Risk-free rate
 
0.30
%
Company volatility
 
39.60
%
 
 
 
 
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 2015 award.
 
 
 
2015
Grant-date fair value
 
$
137.14

Risk-free rate
 
0.49
%
Company volatility
 
43.36
%
 
 
 
 

The following table presents the Company’s performance restricted stock units activity under the 2012 Plan for the six months ended June 30, 2015.
 
 
 
Performance
 
Weighted Average
 
 
 
Restricted Stock
 
Grant-Date
 
 
 
Units
 
Fair Value
Unvested at December 31, 2014
 
79,150

 
$
125.63

Granted
 
90,249

 
$
137.14

Vested
 

 
$

Forfeited
 

 
$

Unvested at June 30, 2015(1)
 
169,399

 
$
131.76

 
 
 
 
 
 
(1)
A maximum of 338,798 units could be awarded based upon the Company’s final TSR ranking.

17




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


As of June 30, 2015, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $12,495,000. Such cost is expected to be recognized over a weighted-average period of 1.3 years.
Partnership Unit Options
In accordance with the Viper Energy Partners LP Long Term Incentive Plan (“Viper LTIP”), the exercise price of unit options granted may not be less than the market value of the common units at the date of grant. The units issued under the Viper LTIP will consist of new common units of the Partnership. On June 17, 2014, the Board of Directors of the General Partner granted 2,500,000 unit options to our executive officers of the General Partner. The unit options vest approximately 33% ratably on each of the next three anniversaries of the date of grant. In the event the fair market value per unit as of the exercise date is less than the exercise price per option unit then the vested options will automatically terminate and become null and void as of the exercise date.
The fair value of the unit options on the date of grant is expensed over the applicable vesting period. The Partnership estimates the fair values of unit options granted using a Black-Scholes option valuation model, which requires the Partnership to make several assumptions. At the time of grant the Partnership did not have a history of market prices, thus the expected volatility was determined using the historical volatility for a peer group of companies. The expected term of options granted was determined based on the contractual term of the awards. The risk-free interest rate is based on the U.S. treasury yield curve rate for the expected term of the unit option at the date of grant. The expected dividend yield was based upon projected performance of the Partnership.
 
 
2014
Grant-date fair value
 
$
4.24

Expected volatility
 
36.0
%
Expected dividend yield
 
5.9
%
Expected term (in years)
 
3.0

Risk-free rate
 
0.99
%
 
 
 
The following table presents the unit option activity under the Viper LTIP for the six months ended June 30, 2015.
 
 
 
 
Weighted Average
 
 
 
 
Unit
 
Exercise
 
Remaining
 
Intrinsic
 
 
Options
 
Price
 
Term
 
Value
 
 
 
 
 
 
(in years)
 
(in thousands)
Outstanding at December 31, 2014
 
2,500,000

 
$
26.00

 
 
 
 
Granted
 

 
$

 
 
 
 
Outstanding at June 30, 2015
 
2,500,000

 
$
26.00

 
1.97

 
$

 
 
 
 
 
 
 
 
 
Vested and Expected to vest at June 30, 2015
 
2,500,000

 
$
26.00

 
1.97

 
$

Exercisable at June 30, 2015
 

 
$

 

 
$

As of June 30, 2015, the unrecognized compensation cost related to unvested unit options was $6.9 million. Such cost is expected to be recognized over a weighted-average period of 2.0 years.
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 unit entitles 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 six months ended June 30, 2015.

18




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


 
 
 
 
Weighted Average
 
 
Phantom
 
Grant-Date
 
 
Units
 
Fair Value
Unvested at December 31, 2014
 
17,776

 
$
19.51

Granted
 

 
$

Vested
 
(8,888
)
 
$
19.51

Forfeited
 

 
$

Unvested at June 30, 2015
 
8,888

 
$
19.51

The aggregate fair value of restricted stock units that vested during the six months ended June 30, 2015 was $0.2 million. As of June 30, 2015, the unrecognized compensation cost related to unvested phantom units was $0.2 million. Such cost is expected to be recognized over a weighted-average period of 1.0 years.
11.    RELATED PARTY TRANSACTIONS

Administrative Services
An entity under common management provided technical, administrative and payroll services to the Company under a shared services agreement that began March 1, 2008. The initial term of this shared service agreement was two years. Since the expiration of such two-year period on March 1, 2010, the agreement, by its terms continued on a month-to-month basis. Effective August 31, 2014, this agreement was mutually terminated.

Effective January 1, 2012, the Company entered into an additional shared services agreement with this entity. Under this agreement, the Company provided this entity and, at its request, certain affiliates, with consulting, technical and administrative services. The initial term of the additional shared services agreement was two years. Thereafter, the agreement continued on a month-to-month basis subject to the right of either party to terminate the agreement upon thirty days prior written notice. Effective August 31, 2014, this agreement was mutually terminated. Costs that are attributable to and billed to other affiliates are reported as other income-related party.
Drilling Services
Bison Drilling and Field Services LLC (“Bison”), an entity controlled by Wexford, has performed drilling and field services for the Company under master drilling and field service agreements. Under the Company’s most recent master drilling agreement with Bison, effective as of January 1, 2013, Bison committed to accept orders from the Company for the use of at least two of its rigs. At June 30, 2015, the Company was not utilizing any Bison rigs. This master drilling agreement is terminable by either party on 30 days’ prior written notice, although neither party will be relieved of its respective obligations arising from a drilling contract being performed prior to the termination of the master drilling agreement. For the three months and six months ended June 30, 2014, the Company incurred total costs for services performed by Bison of $0.9 million and $2.5 million, respectively.
Effective September 9, 2013, the Company entered into a master service agreement with Panther Drilling Systems LLC (“Panther Drilling”), an entity controlled by Wexford, under which Panther Drilling provides directional drilling and other services. This master service agreement is terminable by either party on 30 days’ prior written notice, although neither party will be relieved of its respective obligations arising from work performed prior to the termination of the master service agreement. In the third quarter 2013, the Company began using Panther Drilling’s directional drilling services. For the three months and six months ended June 30, 2014, the Company incurred $0.1 million and $0.3 million, respectively for services performed by Panther Drilling.
Coronado Midstream
The Company is party to a gas purchase agreement, dated May 1, 2009, as amended, with Coronado Midstream LLC (“Coronado Midstream”), formerly known as MidMar Gas LLC, an entity, that owns a gas gathering system and processing plant in the Permian Basin. Under this agreement, Coronado Midstream is obligated to purchase from the Company, and the Company is obligated to sell to Coronado Midstream, all of the gas conforming to certain quality specifications produced from certain of the Company’s Permian Basin acreage. Following the expiration of the initial ten year term, the agreement will continue on a year-to-year basis until terminated by either party on 30 days’ written notice. Under the gas purchase agreement, Coronado Midstream is obligated to pay the

19




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


Company 87% of the net revenue received by Coronado Midstream for all components of the Company’s dedicated gas, including the liquid hydrocarbons, and the sale of residue gas, in each case extracted, recovered or otherwise processed at Coronado Midstream’s gas processing plant, and 94.56% of the net revenue received by Coronado Midstream from the sale of such gas components and residue gas, extracted, recovered or otherwise processed at Chevron’s Headlee plant. An entity controlled by Wexford had owned an approximately 28% equity interest in Coronado Midstream until Coronado Midstream was sold in March 2015. Coronado Midstream is no longer a related party and any revenues, production and ad valorem taxes and gathering and transportation expense after March 2015 are not classified as those attributable to a related party. The Company recognized related party revenues from Coronado Midstream of $5.2 million for the three months ended March 31, 2015. The Company recognized revenues from Coronado Midstream of $6.5 million and $10.4 million for the three months and six months ended June 30, 2014, respectively. The Company recognized production and ad valorem taxes and gathering and transportation expenses from Coronado Midstream of $1.1 million for the three months ended March 31, 2015. The Company recognized production and ad valorem taxes and gathering and transportation expenses from Coronado Midstream of $1.0 million and $1.7 million for the three months and six months ended June 30, 2014, respectively. As of December 31, 2014, Coronado Midstream owed the Company $4.0 million for the Company’s portion of the net proceeds from the sale of gas, gas products and residue gas.
Sand Supply
Muskie Proppant LLC (“Muskie”), an entity controlled by Wexford, processes and sells fracing grade sand for oil and natural gas operations. The Company began purchasing sand from Muskie in March 2013. On May 16, 2013, the Company entered into a master services agreement with Muskie, pursuant to which Muskie agreed to sell custom natural sand proppant to the Company based on the Company’s requirements. The Company is not obligated to place any orders with, or accept any offers from, Muskie for sand proppant. The agreement may be terminated at the option of either party on 30 days’ notice. The Company did not purchase sand from Muskie during the three months and six months ended June 30, 2015 or 2014.
Midland Corporate Lease
Effective May 15, 2011, the Company occupied corporate office space in Midland, Texas under a lease with a five-year term. The office space is owned by an entity controlled by an affiliate of Wexford. The Company paid $0.2 million and $0.4 million for the three months and six months ended June 30, 2015, respectively, under this lease. The Company paid $0.1 million and $0.2 million for the three months and six months ended June 30, 2014, respectively, under this lease. In the second and fourth quarters of 2014, the Company amended this agreement to further increase the size of the leased premises. The monthly rent increased from $25,000 to $27,000 in the second quarter of 2014 and from $27,000 to $53,000 in the fourth quarter of 2014. The monthly rent will continue to increase approximately 4% annually on June 1 of each year during the remainder of the lease term. In November 2014, the Company further amended the lease, including extending the term of the lease for an additional ten-year period. In April 2015, the Company again amended this lease to increase the size of the leased premises. The monthly rent for the additional space is $23,000. Upon commencement of the extension in June 2016, the monthly base rent will increase to $94,000, with an increase of approximately 2% annually.
Field Office Lease
The Company leased field office space in Midland, Texas from an unrelated third party from March 1, 2011 to March 1, 2014. Effective March 1, 2014, the building was purchased by an entity controlled by an affiliate of Wexford. The term of the lease expires on February 28, 2018. The Company paid rent of less than $0.1 million and $0.1 million to the related party for the three months and six months ended June 30, 2015, respectively. The Company paid rent of less than $0.1 million to the related party for both the three months and six months ended June 30, 2014.The monthly base rent is $11,000 which will increase 3% annually on March 1 of each year during the remainder of the lease term. During the third quarter of 2014, the Company negotiated a sublease with Bison, in which Bison will lease the field office space for the same term as the initial lease and will pay the monthly rent of $11,000 which will increase 3% annually on March 1 of each year during the remainder of the lease term.
Oklahoma City Lease
Effective January 1, 2012, the Company occupied corporate office space in Oklahoma City, Oklahoma under a lease with a 67 month term. The office space is owned by an entity controlled by an affiliate of Wexford. The Company paid $0.1 million for both the three months and six months ended June 30, 2014 under this lease. Effective April 1,

20




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


2013, the Company amended this lease to increase the size of the leased premises, at which time the monthly base rent increased to $19,000 for the remainder of the lease term. The Company was also responsible for paying a portion of specified costs, fees and expenses associated with the operation of the premises. Effective September 23, 2014, this lease agreement was mutually terminated.
Advisory Services Agreement & Professional Services from Wexford
The Company entered into an advisory services agreement (the “Advisory Services Agreement”) with Wexford, dated as of October 11, 2012, under which Wexford provides the Company 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 Advisory Services Agreement had an initial term of two years commencing on October 18, 2012, and continues 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. It may be terminated at any time by either party upon 30 days prior written notice. In the event the Company terminates such agreement, it is obligated to pay all amounts due through the remaining term. In addition, the Company agreed to pay Wexford to-be-negotiated market-based fees approved by the Company’s independent directors for such services as may be provided by Wexford at the Company’s request in connection with acquisitions and divestitures, financings or other transactions in which the Company may be involved. The services provided by Wexford under the Advisory Services Agreement do not extend to the Company’s day-to-day business or operations. The Company has agreed to indemnify Wexford and its affiliates from any and all losses arising out of or in connection with the Advisory Services Agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct. The Company incurred total costs of $0.1 million and $0.3 million for the three months and six months ended June 30, 2015, respectively, under the Advisory Services Agreement. The Company incurred total costs of $0.1 million and $0.3 million for the three months and six months ended June 30, 2014, respectively, under the Advisory Services Agreement.
Advisory Services Agreement- Viper Energy Partners LP
In connection with the closing of the Viper Offering, the Partnership and 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 our 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 has 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. It may be terminated at any time by either party upon 30 days prior written notice. In the event the Partnership or General Partner terminates such agreement, the Partnership is obligated to pay all amounts due through the remaining term. In addition, the Partnership and General Partner have agreed to pay Wexford to-be-negotiated market-based fees approved by the conflict committee of the board of directors of our General Partner for such services as may be provided by Wexford at our request in connection with acquisitions and divestitures, financings or other transactions in which we may be involved. The services provided by Wexford under the Viper Advisory Services Agreement do not extend to the Partnership or General Partners day-to-day business or operations. The Partnership and General Partner have agreed to indemnify Wexford and its affiliates from any and all losses arising out of or in connection with the Viper Advisory Services Agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct. For the three months and six months ended June 30, 2015, the Partnership incurred costs of $0.1 million and $0.3 million, respectively, under the Viper Advisory Services Agreement.

12. 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 price swap contracts to reduce price volatility associated with certain of its oil sales. With respect to the Company’s fixed price 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 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 price. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude

21




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


oil derivative settlements based on Argus Louisiana light sweet pricing, New York Mercantile Exchange West Texas Intermediate pricing or Inter–Continental Exchange (“ICE”) pricing for Brent crude oil.
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.
As of June 30, 2015, the Company had open crude oil derivative positions with respect to future production as set forth in the table below. When aggregating multiple contracts, the weighted average contract price is disclosed.
Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap
 
 
 
 
 
 
 
 
Production Period
 
Volume (Bbls)
 
Fixed Swap Price
July- December 2015
 
552,000

 
90.99

 
 
 
 
 
 
 
 
 
 
Crude Oil—NYMEX West Texas Intermediate Fixed Price Swap
 
 
 
 
 
 
 
 
Production Period
 
Volume (Bbls)
 
Fixed Swap Price
July - December 2015
 
920,000

 
84.10

 
 
 
 
 
 
 
 
 
 
Crude Oil—ICE Brent Fixed Price Swap
 
 
 
 
 
 
 
 
Production Period
 
Volume (Bbls)
 
Fixed Swap Price
July - December 2015
 
368,000

 
88.78

January - February 2016
 
91,000

 
88.72

 
 
 
 
 
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 June 30, 2015 and December 31, 2014.

22




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


 
 
June 30, 2015
 
 
 
 
 
 
 
 
 
(in thousands)
 
 
Gross Amounts of Recognized Assets
 
Gross Amounts Offset in the Consolidated Balance Sheet
 
Net Amounts of Assets Presented in the Consolidated Balance Sheet
Derivative assets
 
$
47,910

 
$

 
$
47,910

 
 
 
 
 
 
 
 
 
December 31, 2014
 
 
 
 
 
 
 
 
 
(in thousands)
 
 
Gross Amounts of Recognized Assets
 
Gross Amounts Offset in the Consolidated Balance Sheet
 
Net Amounts of Assets Presented in the Consolidated Balance Sheet
Derivative assets
 
$
117,541

 
$

 
$
117,541

 
 
 
 
 
 
 

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:
 
 
June 30,
 
December 31,
 
 
2015
 
2014
 
 
 
 
 
 
 
(in thousands)
Current Assets: Derivative instruments
 
$
47,910

 
$
115,607

Noncurrent Assets: Derivative instruments
 

 
1,934

Total Assets
 
$
47,910

 
$
117,541

 
 
 
 
 

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 combined consolidated statements of operations:
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Change in fair value of open non-hedge derivative instruments
 
$
(44,425
)
 
$
(7,468
)
 
$
(69,631
)
 
$
(10,810
)
Gain (loss) on settlement of non-hedge derivative instruments
 
25,302

 
(3,620
)
 
68,862

 
(4,676
)
Gain (loss) on derivative instruments
 
$
(19,123
)
 
$
(11,088
)
 
$
(769
)
 
$
(15,486
)


13.    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.

23




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


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.
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. The fair values of the Company’s fixed price crude oil swaps 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 June 30, 2015 and December 31, 2014.
 
 
 
Fair value measurements at June 30, 2015 using:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(in thousands)
 
 
Quoted Prices in Active Markets Level 1
 
Significant Other Observable Inputs
Level 2
 
Significant Unobservable Inputs
 Level 3
 
Total
Assets:
 
 
 
 
 
 
 
 
Fixed price swaps
 
$

 
$
47,910

 
$

 
$
47,910

 
 
 
 
 
 
 
 
 
 
 
 
Fair value measurements at December 31, 2014 using:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(in thousands)
 
 
Quoted Prices in Active Markets Level 1
 
Significant Other Observable Inputs
Level 2
 
Significant Unobservable Inputs
 Level 3
 
Total
Assets: