Diamondback Energy, Inc. - FORM 8-K - EX-99.4 - EXHIBIT

Attached files

file	filename
8-K - 8-K - Diamondback Energy, Inc.	a20148kacquisitionssept2014.htm
EX-23.1 - EXHIBIT - Diamondback Energy, Inc.	ex23_1diamondbackwesttexas.htm
EX-99.1 - EXHIBIT - Diamondback Energy, Inc.	ex99_1statementsofrev.htm
EX-23.2 - EXHIBIT - Diamondback Energy, Inc.	ex23_2diamondbackguarantor.htm
EX-99.3 - EXHIBIT - Diamondback Energy, Inc.	ex99_3x12311310-kguarantor.htm
EX-99.5 - EXHIBIT - Diamondback Energy, Inc.	ex99_5x6301410-qseptguaran.htm
EX-99.2 - EXHIBIT - Diamondback Energy, Inc.	ex99_2proformasept20148-k.htm

Exhibit 99.4

TABLE OF CONTENTS

(Unaudited)
		Page

	Consolidated Financial Statements of Diamondback Energy, Inc. (unaudited)	1
	Consolidated Balance Sheets as of March 31, 2014 and December 31, 2013	1
	Consolidated Statements of Operations for the Three Months Ended March 31, 2014 and 2013	2
	Consolidated Statement of Stockholders’ Equity for the Three Months Ended March 31, 2014	3
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2014 and 2013	4
	Notes to Consolidated Financial Statements	6

Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Consolidated Balance Sheets

(Unaudited)



	March 31,			December 31,
	2014			2013

	(In thousands, except par values and share data)
Assets
Current assets:
Cash and cash equivalents	$	25,314		$	15,555
Accounts receivable:
Joint interest and other	15,920			14,437
Oil and natural gas sales	38,360			23,533
Related party	2,298			1,303
Inventories	5,889			5,631
Deferred income taxes	1,377			112
Derivative instruments	—			213
Prepaid expenses and other	1,495			1,184
Total current assets	90,653			61,968
Property and equipment
Oil and natural gas properties, based on the full cost method of accounting ($485,184 and $369,561 excluded from amortization at March 31, 2014 and December 31, 2013, respectively)	2,065,571			1,648,360
Pipeline and gas gathering assets	6,503			6,142
Other property and equipment	4,635			4,071
Accumulated depletion, depreciation, amortization and impairment	(243,131		)	(212,236		)
	1,833,578			1,446,337
Derivative instruments	—			218
Other assets	12,666			13,091
Total assets	$	1,936,897		$	1,521,614
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	24,487		$	2,679
Accounts payable-related party	313			17
Accrued capital expenditures	68,207			74,649
Other accrued liabilities	46,649			34,750
Revenues and royalties payable	12,645			9,225
Derivative instruments	2,910			—
Total current liabilities	155,211			121,320
Long-term debt	587,000			460,000
Asset retirement obligations	5,147			2,989
Deferred income taxes	106,630			91,764
Total liabilities	853,988			676,073
Contingencies (Note 12)
Stockholders’ equity:
Common stock, $0.01 par value, 100,000,000 shares authorized, 50,700,099 issued and outstanding at March 31, 2014; 47,106,216 issued and outstanding at December 31, 2013	508			471
Additional paid-in capital	1,056,299			842,557
Retained earnings	26,102			2,513
Total stockholders’ equity	1,082,909			845,541
Total liabilities and stockholders’ equity	$	1,936,897		$	1,521,614

See accompanying notes to consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

(Unaudited)



	Three Months Ended March 31,
	2014			2013

	(In thousands, except per share amounts)
Revenues:
Oil sales	$	89,758		$	25,253
Natural gas sales	1,755			739
Natural gas sales - related party	1,580			412
Natural gas liquid sales	2,584			1,822
Natural gas liquid sales - related party	2,327			683
Total revenues	98,004			28,909
Costs and expenses:
Lease operating expenses	7,807			4,706
Lease operating expenses - related party	108			202
Production and ad valorem taxes	5,578			1,878
Production and ad valorem taxes - related party	264			76
Gathering and transportation	214			75
Gathering and transportation - related party	368			58
Depreciation, depletion and amortization	30,973			10,738
General and administrative expenses (including non-cash stock based compensation, net of capitalized amounts, of $2,190 and $458 for the three months ended March 31, 2014 and 2013, respectively)	4,265			2,185
General and administrative expenses - related party	292			286
Asset retirement obligation accretion expense	72			43
Total costs and expenses	49,941			20,247
Income from operations	48,063			8,662
Other income (expense)
Interest expense	(6,505		)	(485		)
Other income - related party	30			389
Loss on derivative instruments, net	(4,398		)	(8		)
Total other income (expense), net	(10,873		)	(104		)
Income before income taxes	37,190			8,558
Provision for income taxes
Deferred	13,601			3,162
Net income	$	23,589		$	5,396

Earnings per common share
Basic	$	0.49		$	0.15
Diluted	$	0.48		$	0.15
Weighted average common shares outstanding
Basic	48,447			37,059
Diluted	48,867			37,206

See accompanying notes to consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Consolidated Statement of Stockholders’ Equity

(Unaudited)



	Common Stock			Additional		Retained
	Shares	Amount		Paid-in Capital		Earnings		Total

	(In thousands)
Balance December 31, 2013	47,106	$	471	$	842,557	$	2,513	$	845,541

Stock based compensation	—	—		3,256		—		3,256
Common shares issued in public offering, net of offering costs	3,450	35		208,410		—		208,445
Exercise of stock options and vesting of restricted stock units	145	2		2,076		—		2,078
Net income	—	—		—		23,589		23,589
Balance March 31, 2014	50,701	$	508	$	1,056,299	$	26,102	$	1,082,909

See accompanying notes to consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)



	Three Months Ended March 31,
	2014			2013

	(In thousands)
Cash flows from operating activities:
Net income	$	23,589		$	5,396
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for deferred income taxes	13,601			3,162
Asset retirement obligation accretion expense	72			43
Depreciation, depletion, and amortization	30,973			10,738
Amortization of debt issuance costs	458			153
Change in fair value of derivative instruments	3,342			(1,537		)
Stock based compensation expense	2,190			655
Gain on sale of assets	(11		)	(9		)
Changes in operating assets and liabilities:
Accounts receivable	(12,490		)	(8,393		)
Accounts receivable-related party	(995		)	3,908
Inventories	(258		)	(89		)
Prepaid expenses and other	(311		)	(415		)
Accounts payable and accrued liabilities	7,590			3,243
Accounts payable and accrued liabilities-related party	296			(108		)
Revenues and royalties payable	3,420			108
Net cash provided by operating activities	71,466			16,855
Cash flows from investing activities:
Additions to oil and natural gas properties	(84,211		)	(50,094		)
Additions to oil and natural gas properties-related party	(1,650		)	(4,868		)
Acquisition of Gulfport properties	—			(18,550		)
Acquisition of leasehold interests	(312,207		)	—
Pipeline and gas gathering assets	(532		)	—
Purchase of other property and equipment	(595		)	(302		)
Proceeds from sale of property and equipment	11			9
Settlement of non-hedge derivative instruments	—			(289		)
Net cash used in investing activities	(399,184		)	(74,094		)
Cash flows from financing activities:
Proceeds from borrowings on credit facility	127,000			36,500
Debt issuance costs	(82		)	—
Public offering costs	(75		)	(103		)
Proceeds from public offering	208,644			—
Exercise of stock options	1,990			—
Net cash provided by financing activities	337,477			36,397
Net increase (decrease) in cash and cash equivalents	9,759			(20,842		)
Cash and cash equivalents at beginning of period	15,555			26,358
Cash and cash equivalents at end of period	$	25,314		$	5,516

See accompanying notes to consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows - Continued

(Unaudited)



	Three Months Ended March 31,
	2014		2013

	(In thousands)
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest	$	149	$	141
Supplemental disclosure of non-cash transactions:
Asset retirement obligation incurred	$	214	$	62
Asset retirement obligation revisions in estimated liability	$	588	$	—
Asset retirement obligation acquired	$	1,294	$	—

See accompanying notes to consolidated financial statements.

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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.

The subsidiaries of Diamondback, as of March 31, 2014, include Diamondback E&P LLC, a Delaware limited liability company, Diamondback O&G LLC, a Delaware limited liability company, Viper Energy Partners LLC, a Delaware limited liability company, Viper Energy Partners LP, a Delaware limited partnership, and Viper Energy Partners GP LLC, a Delaware limited liability company. The subsidiaries are all wholly owned.

On October 11, 2012, Diamondback acquired from Gulfport Energy Corporation (“Gulfport”) all of its oil and natural gas interests in the Permian Basin (the “Gulfport properties”) in exchange for shares of Diamondback common stock and a promissory note in a transaction referred to as the “Gulfport transaction”. The Gulfport transaction was treated as a business combination accounted for under the acquisition method of accounting with the identifiable assets and liabilities recognized at fair value on the date of transfer.

On May 21, 2013, the Company completed an underwritten primary public offering of 5,175,000 shares of common stock, which included 675,000 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 $29.25 per share and the Company received net proceeds of approximately $144.4 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.

On June 24, 2013, Gulfport and certain entities controlled by Wexford Capital, LP (“Wexford”), our equity sponsor, completed an underwritten secondary public offering of 6,000,000 shares of the Company’s common stock and, on July 5, 2013, the underwriters purchased an additional 869,222 shares of the Company’s common stock from these selling stockholders pursuant to an option to purchase such additional shares granted to the underwriters. The shares were sold to the public at $34.75 per share and the selling stockholders received all proceeds from this offering.

In August 2013, 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 public at $40.25 per share and the Company received net proceeds of approximately $177.5 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.

In September 2013, the Company completed an offering of $450.0 million principal amount of its 7.625% Senior Notes due 2021. See Note 6 below.

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.

Basis of Presentation

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

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

Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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, 2013, which contains a summary of the Company’s significant accounting policies and other disclosures.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

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

3. ACQUISITIONS

2014 Activity

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 in part by the net proceeds of the February 2014 equity offering discussed in Note 1 above.

The following represents the estimated fair values of the assets and liabilities assumed on the acquisition dates. The aggregate consideration transferred was $292,159,000 in cash, subject to post-closing adjustments, resulting in no goodwill or bargain purchase gain.



	(in thousands)
Proved oil and natural gas properties	$	170,174
Unevaluated oil and natural gas properties	123,243
Asset retirement obligations	(1,258		)
Total fair value of net assets	$	292,159

The Company has included in its consolidated statements of operations revenues of $4,898,000 and direct operating expenses of $1,074,000 for the period from February 28, 2014 to March 31, 2014 due to the acquisitions. The disclosure of net earnings is impracticable to calculate due to the full cost method of depletion. The following unaudited summary pro forma combined consolidated statement of operations data of Diamondback for the three months ended March 31, 2014 and 2013 has been prepared to give effect to the acquisitions 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.

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)



	Three Months Ended March 31,
	2014		2013
	(Pro Forma)		(Pro Forma)

	(in thousands, except per share amounts)
Revenues	$	107,979	$	44,391
Income from operations	52,193		14,656
Net income	26,209		9,175
Basic earnings per common share	$	0.54	$	0.25
Diluted earnings per common share	$	0.54	$	0.25

2013 Activity

In September 2013, the Company completed two separate acquisitions of additional leasehold interests in the Permian Basin from unrelated third party sellers for an aggregate purchase price of $165.0 million, subject to certain adjustments. The first of these acquisitions closed on September 4, 2013 when the Company acquired certain assets located in northwestern Martin County, Texas, consisting of a 100% working interest (80% net revenue interest) in 4,506 gross and net acres. The second of these acquisitions closed on September 26, 2013, when the Company acquired certain assets located primarily in southwestern Dawson County, Texas, consisting of a 71% working interest (55% net revenue interest) in 9,390 gross (6,638 net) acres. These acquisitions were funded with a portion of the net proceeds from the August 2013 equity offering discussed in Note 1 above.

On September 19, 2013, the Company completed the acquisition of the mineral interests underlying approximately 14,804 gross (12,687 net) acres in Midland County, Texas in the Permian Basin. The mineral interests entitle the Company to receive an average 21.4% royalty interest on all production from this acreage with no additional future capital or operating expense required. The $440.0 million purchase price was funded with the net proceeds of the Company’s offering of Senior Notes discussed in Note 6 below.

4. PROPERTY AND EQUIPMENT

Property and equipment includes the following:



	March 31,			December 31,
	2014			2013

	(in thousands)
Oil and natural gas properties:
Subject to depletion	$	1,580,387		$	1,278,799
Not subject to depletion-acquisition costs
Incurred in 2014	142,064			—
Incurred in 2013	256,998			279,353
Incurred in 2012	85,358			87,252
Incurred in 2011	764			1,598
Incurred in 2010	—			1,358
Total not subject to depletion	485,184			369,561

Gross oil and natural gas properties	2,065,571			1,648,360
Less accumulated depreciation, depletion, amortization and impairment	(241,514		)	(210,837		)
Oil and natural gas properties, net	1,824,057			1,437,523

Pipeline and gas gathering assets	6,503			6,142
Other property and equipment	4,635			4,071
Less accumulated depreciation	(1,617		)	(1,399		)
Other property and equipment, net	3,018			2,672

Property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	1,833,578		$	1,446,337

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

The average depletion rate per barrel equivalent unit of production was $25.19 and $24.50 for the three months ended March 31, 2014 and 2013, respectively. 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 $2,296,000 and $692,000 for the three months ended March 31, 2014 and 2013, 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.

5. ASSET RETIREMENT OBLIGATIONS

The following table describes the changes to the Company’s asset retirement obligation liability for the following periods:



	Three Months Ended
	March 31,
	2014			2013

	(in thousands)
Asset retirement obligation, beginning of period	$	3,029		$	2,145
Additional liability incurred	214			62
Liabilities acquired	1,294			—
Liabilities settled	(10		)	—
Accretion expense	72			43
Revisions in estimated liabilities	588			—
Asset retirement obligation, end of period	5,187			2,250
Less current portion	40			20
Asset retirement obligations - long-term	$	5,147		$	2,230

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.

6. DEBT

Long-term debt consisted of the following as of the dates indicated:



	March 31,		December 31,
	2014		2013

	(in thousands)
Revolving credit facility	$	137,000	$	10,000
7.625 % Senior Notes due 2021	450,000		450,000
Total long-term debt	$	587,000	$	460,000

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. The Senior Notes are fully and unconditionally guaranteed by the Company’s subsidiaries. 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.

Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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 (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 have 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 filed with the SEC on March 14, 2014. Under the Registration Rights Agreement, the Company also agreed to use its commercially reasonable efforts to cause the exchange offer registration statement to become effective within 360 days after the issue date of the Senior Notes and to consummate the exchange offer 30 days after effectiveness. The Company may be required to file a shelf registration statement to cover resales of the Senior Notes under certain circumstances. If the Company fails to satisfy certain of its obligations under the Registration Rights Agreement, the Company agreed to pay additional interest to the holders of the Senior Notes as specified in the Registration Rights Agreement.

Credit Facility-Wells Fargo Bank

On October 15, 2010, the Company entered into a secured revolving credit agreement with BNP Paribas, or BNP, as the administrative agent, sole book runner and lead arranger. On May 10, 2012, the revolving credit agreement was amended to provide for the resignation of BNP, and the appointment of Wells Fargo Bank, National Association, as administrative agent for the lenders. The credit agreement was amended and restated as of July 24, 2012 and again as of November 1, 2013. The credit agreement, as so amended and restated, provides for a revolving credit facility in the maximum amount of $600 million, subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based on the Company’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 Company may request up to three additional redeterminations of the borrowing base during any 12-month period. As of March 31, 2014 and December 31, 2013, the borrowing base was set at $225.0 million. In connection with our April 2014 redetermination, the administrative agent has informed the Company that it has approved a borrowing base of $450.0 million based on the Company’s current assets. As of March 31, 2014, the Company had outstanding borrowings of $137.0 million which bore interest at a weighted average rate of 2.16%. As of December 31, 2013, the Company had outstanding borrowings of $10.0 million which bore interest at a weighted average rate of 1.67%.

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

The outstanding borrowings under the credit agreement bear interest at a rate elected by the Company that is based on the prime rate or LIBOR plus margins ranging from 0.50% for prime-based loans and 1.50% for LIBOR loans to 1.50% for prime-based loans and 2.50% for LIBOR loans, 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 loan is secured by substantially all of the assets of the Company and its subsidiaries.

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 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 March 31, 2014, the Company had $450 million of senior unsecured notes outstanding.

As of March 31, 2014 and December 31, 2013, 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.

7. EARNINGS PER SHARE

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



	Three Months Ended March 31, 2014
				Per
	Income		Shares	Share
	(in thousands)
Basic:
Net income attributable to common stock	$	23,589	48,446,609	$	0.49
Effect of Dilutive Securities:
Dilutive effect of potential common shares issuable	$	—	420,110
Diluted:
Net income attributable to common stock	$	23,589	48,866,719	$	0.48

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(Unaudited)



	Three Months Ended March 31, 2013
				Per
	Income		Shares	Share
	(in thousands)
Basic:
Net income attributable to common stock	$	5,396	37,059,071	$	0.15
Effect of Dilutive Securities:
Dilutive effect of potential common shares issuable	$	—	146,619
Diluted:
Net income attributable to common stock	$	5,396	37,205,690	$	0.15

8. STOCK BASED COMPENSATION

For the three months ended March 31, 2014 and 2013, the Company incurred $3,256,000 and $655,000, respectively, of stock based compensation, of which the Company capitalized $1,066,000 and $197,000, respectively, pursuant to the full cost method of accounting for oil and natural gas properties.

Stock Options

The following table presents the Company’s stock option activity under the 2012 Plan for the three months ended March 31, 2014.



			Weighted Average
			Exercise		Remaining	Intrinsic
	Options		Price		Term	Value
					(in years)	(in thousands)
Outstanding at December 31, 2013	712,955		$	17.96
Granted	—		$	—
Exercised	(114,050	)	$	18.22
Expired/Forfeited	—		$	—
Outstanding at March 31, 2014	598,905		$	17.91	2.41	$	29,585

Vested and Expected to vest at March 31, 2014	598,905		$	17.91	2.41	$	29,585
Exercisable at March 31, 2014	151,655		$	17.50	1.69	$	7,554

The aggregate intrinsic value of stock options that were exercised during the three months ended March 31, 2014 was $5,310,000. As of March 31, 2014, the unrecognized compensation cost related to unvested stock options was $1,465,000. Such cost is expected to be recognized over a weighted-average period of 1.5 years.

Restricted Stock Units

The following table presents the Company’s restricted stock units activity under the 2012 Plan during the three months ended March 31, 2014.

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			Weighted Average
	Restricted Stock		Grant-Date
	Units		Fair Value
Unvested at December 31, 2013	132,239		$	19.20
Granted	99,150		$	61.59
Vested	(31,383	)	$	61.44
Forfeited	—		$	—
Unvested at March 31, 2014	200,006		$	33.56

The aggregate fair value of restricted stock units that vested during the three months ended March 31, 2014 was $2,003,000. As of March 31, 2014, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $5,619,000. Such cost is expected to be recognized over a weighted-average period of 1.7 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. There were no performance restricted stock units issued or outstanding during the three months ended March 31, 2013.

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.



	2014
Grant-date fair value	$	125.63
Risk-free rate	0.30		%
Company volatility	39.60		%

The following table presents the Company’s performance restricted stock units activity under the 2012 Plan for the three months ended March 31, 2014.



		Performance	Weighted Average
		Restricted Stock	Grant-Date
		Units	Fair Value
Unvested at December 31, 2013		—	$	—
Granted		79,150	$	125.63
Vested		—	$	—
Forfeited		—	$	—
Unvested at March 31, 2014 ⁽¹⁾		79,150	$	125.63

(1)	A maximum of 158,300 units could be awarded based upon the Company’s final TSR ranking.

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As of March 31, 2014, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $9,470,000. Such cost is expected to be recognized over a weighted-average period of 1.8 years.

9. RELATED PARTY TRANSACTIONS

Administrative Services

An entity under common management provided technical, administrative and payroll services to the Company under a shared services agreement which 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 has continued on a month-to-month basis. For the three months ended March 31, 2014 and 2013, the Company incurred total costs of $1,000 and $58,000, respectively. Costs incurred unrelated to drilling activities are expensed and costs incurred in the acquisition, exploration and development of proved oil and natural gas properties have been capitalized. As of March 31, 2014 and December 31, 2013, the Company owed the administrative services affiliate no amounts and $17,000, respectively. These amounts are included in accounts payable-related party in the accompanying consolidated balance sheets.

Effective January 1, 2012, the Company entered into an additional shared services agreement with this entity. Under this agreement, the Company provides 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. The agreement now continues on a month-to-month basis until canceled by either party upon thirty days prior written notice. Costs that are attributable to and billed to other affiliates are reported as other income-related party. For the three months ended March 31, 2014 and 2013, the affiliate reimbursed the Company $30,000 and $389,000, respectively, for services under the shared services agreement. As of March 31, 2014 and December 31, 2013, the affiliate owed the Company $13,000 amounts and no amounts, respectively. These amounts are included in accounts receivable-related party in the accompanying consolidated balance sheets.

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 March 31, 2014, Bison was providing drilling services to the Company using one of its 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. The Company incurred total costs for services performed by Bison of $1,510,000 and $4,968,000 for the three months ended March 31, 2014 and 2013, respectively. The Company owed Bison $313,000 as of March 31, 2014 and no amounts as of December 31, 2013.

Effective September 9, 2013, the Company entered into a master service agreement with Panther Drilling Systems LLC (“Panther Drilling”), an entity controlled by Wexford, 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. The Company incurred $248,000 for services performed by Panther Drilling. The Company owed Panther Drilling no amounts as of March 31, 2014 or December 31, 2013.

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 affiliated with Wexford 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 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

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received by Coronado Midstream from the sale of such gas components and residue gas, extracted, recovered or otherwise processed at Chevron’s Headlee plant. The Company recognized revenues from Coronado Midstream of $3,907,000 and $1,095,000 for the three months ended March 31, 2014 and 2013, respectively. As of March 31, 2014 and December 31, 2013, Coronado Midstream owed the Company $2,285,000 and $1,303,000, respectively, 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 affiliated with 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 incurred no costs and costs of $234,000 for sand purchased from Muskie for the three months ended March 31, 2014 and 2013, respectively. The Company owed Muskie no amounts as of March 31, 2014 or December 31, 2013.

Midland Leases

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 $93,000 and $38,000 for the three months ended March 31, 2014 and 2013, respectively, under this lease. In the second and third quarters of 2013, the Company amended this agreement to increase the size of the leased premises. The monthly rent under the lease increased from $13,000 to $15,000 beginning on August 1, 2013 and increased further to $25,000 beginning on October 1, 2013. The monthly rent will continue to increase approximately 4% annually on June 1 of each year during the remainder of the lease term.

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 remaining term of the lease as of March 1, 2014 is four years. The Company paid rent of $11,000 to the related party for the three months ended March 31, 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.

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 $64,000 and $53,000 for the three months ended March 31, 2014 and 2013, respectively, under this lease. Effective April 1, 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 is also responsible for paying a portion of specified costs, fees and expenses associated with the operation of the premises.

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 $500,000, plus reasonable out-of-pocket expenses. The Advisory Services Agreement has a term of two years commencing on October 18, 2012, 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 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 future 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 $125,000 and $125,000 for the three months ended March 31, 2014 and 2013, respectively, under the Advisory

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Services Agreement. As of March 31, 2014 and December 31, 2013, the Company owed Wexford no amounts for either period.

10. 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 consolidated statements of operations under the caption “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 oil derivative settlements based on Argus Louisiana light sweet pricing or Inter–Continental Exchange (“ICE”) pricing for Brent crude oil. The counterparties to the Company’s derivative contracts are Wells Fargo Bank, N.A., JP Morgan Chase Bank, National Association and The Bank of Nova Scotia who the Company believes are acceptable credit risks.

As of March 31, 2014, the Company had open crude oil derivative positions with respect to future production as set forth in the tables 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
April - December 2014	1,620,000	$	98.67
January - March 2015	211,000	99.54

Crude Oil—ICE Brent Fixed Price Swap

Production Period	Volume (Bbls)	Fixed Swap Price
April 2014	30,000	$	109.70

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 March 31, 2014 and December 31, 2013.

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	March 31, 2014

	(in thousands)
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Consolidated Balance Sheet			Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
Derivative liabilities	$	(3,200	)	$	290		$	(2,910	)

	December 31, 2013

	(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	$	998		$	(567	)	$	431

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:



	March 31,			December 31,
	2014			2013

	(in thousands)
Current Assets: Derivative instruments	$	—		$	213
Noncurrent Assets: Derivative instruments	—			218
Total Assets	$	—		$	431

Current Liabilities: Derivative instruments	$	(2,910	)	$	—
Noncurrent Liabilities: Derivative instruments	—			—
Total Liabilities	$	(2,910	)	$	—

None of the Company’s derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations:



	Three Months Ended March 31,
	2014			2013

	(in thousands)
Non-cash gain (loss) on open non-hedge derivative instruments	$	(3,342	)	$	1,535
Loss on settlement of non-hedge derivative instruments	(1,056		)	(1,543		)
Loss on derivative instruments	$	(4,398	)	$	(8	)

11. 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

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valuation techniques based on available inputs to measure the fair values of its assets and liabilities.

Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

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

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

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

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 March 31, 2014 and December 31, 2013.



		Fair value measurements at March 31, 2014 using:

	(in thousands)
		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2			Significant Unobservable Inputs Level 3		Total
Liabilities:
Fixed price swaps		—		(2,910		)	—		(2,910		)

		Fair value measurements at December 31, 2013 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		$	—	$	431		$	—	$	431

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated financial statements.

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	March 31, 2014				December 31, 2013
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value

	(in thousands)
Debt:
Revolving credit facility	$	137,000	$	137,000	$	10,000	$	10,000
7.625% Senior Notes due 2021	450,000		484,875		450,000		460,406

The fair value of the revolving credit facility approximates its carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes was determined using the March 31, 2014 quoted market price, a Level 1 classification in the fair value hierarchy.

12. CONTINGENCIES

In September 2010, Windsor Permian LLC (“Windsor Permian”) (now known as Diamondback O&G LLC) purchased certain property in Goodhue County, Minnesota, that was prospective for hydraulic fracturing grade sand. Prior to the purchase, the prior owners of the property had entered into a Mineral Development Agreement with the plaintiff and the Company purchased the property subject to that agreement. Windsor Permian subsequently contributed the property to Muskie. In an amended complaint filed in November 2012 by the plaintiff against the prior owners of the property, Windsor Permian and certain affiliates of Windsor Permian in the first judicial district court in Goodhue County, Minnesota, the plaintiff sought damages from the Company and the other defendants alleging, among other things, interference with contractual relationship, interference with prospective advantage and unjust enrichment. In an order filed on May 24, 2013, the judge denied certain motions made by the defendants and set a trial date to determine liability, with a damage phase of the matter to commence on a later date if there is a determination of liability. Following a trial on the liability phase on June 21, 2013, the jury determined that the defendants intentionally interfered with plaintiff’s contract but that the interference did not cause the plaintiff to be unable to acquire mining permits prior to the enactment of the moratorium by Goodhue County. In an order filed on July 10, 2013, the judge ordered the damage phase to be set for trial following a pretrial and scheduling conference. Subsequently, the plaintiff disclosed a new damage theory, and the defendants filed motions with the court to dismiss plaintiff’s claims on the grounds that the damage claim was speculative and that plaintiff could not prove damages as a matter of law. Plaintiff also filed a motion for leave to amend its complaint to assert a punitive damage claim. The motions were argued in December 2013. In March 2014, the judge entered an order granting the defendants’ motions to exclude testimony and for summary judgment. All parties agreed not to pursue an appeal from the order and waived any entitlement to costs, which effectively concluded this matter.

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

13. SUBSEQUENT EVENTS

On each of April 9, 2014 and April 11, 2014, the Company entered into new commodity contracts with The Bank of Nova Scotia. The contracts are both fixed price oil swaps that will settle against the weighted average price per barrel of Argus Louisiana light sweet during the calculation period. The following table presents the terms of the contracts:



		Fixed Swap
	Volumes (Bbls)	Price		Production Period
Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap	365,000	$	100.00	May 2014	-	April 2015

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On May 7, 2014, the Company’s wholly-owned subsidiary Viper Energy Partners LP (“Viper”) filed a registration statement on Form S-1 with the SEC in connection with its proposed initial public offering of limited partner interests. At or prior to the closing of this offering, the Company will contribute to Viper all of the equity interests in the Company’s wholly-owned subsidiary Viper Energy Partners, LLC (“Energy Partners”), in exchange for limited partner interests in Viper. Energy Partners’ assets currently consist of mineral interests underlying approximately 14,804 gross (12,687 net) acres in Midland County, Texas in the Permian Basin, approximately 50% of which are operated by us. Viper intends to distribute the net proceeds from the offering to the Company. A registration statement relating to these securities has been filed with the SEC but has not yet become effective. These securities may not be sold nor may any offers to buy be accepted prior to the time the registration statement becomes effective, and this report does not constitute an offer to sell or a solicitation of any offers to buy these securities.

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14. GUARANTOR FINANCIAL STATEMENTS

Diamondback E&P and Diamondback O&G are unconditional guarantor’s (the “Guarantor Subsidiaries”) of the Senior Notes and the second amended and restated credit agreement. On June 23, 2014, in connection with the initial public offering of Viper Energy Partners LP the Company designated the Partnership, its general partner, Viper Energy Partners GP, and the Partnership’s subsidiary Viper Energy Partners LLC as unrestricted subsidiaries under the Indenture and upon such designation, Viper Energy Partners LLC, which was a guarantor under the Indenture prior to such designation, was released as a guarantor under the Indenture. Viper Energy Partners LLC is a limited liability company formed on September 18, 2013 to own and acquire mineral and other oil and natural gas interests in properties in the Permian Basin in West Texas. The following presents condensed consolidated financial information as of December 31, 2013 and 2012 and for the years ended December 31, 2013, 2012 and 2011 on an issuer (parent company), Guarantor Subsidiaries, Non–Guarantor Subsidiaries and consolidated basis. Elimination entries presented are necessary to combine the entities. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities. The Company has not presented separate financial and narrative information for each of the Guarantor Subsidiaries because it believes such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the Guarantor Subsidiaries.

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Condensed Consolidated Balance Sheet
March 31, 2014
(In thousands)
						Non–
			Guarantor			Guarantor
	Parent		Subsidiaries			Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	18,398	$	6,517		$	399		$	—		$	25,314
Accounts receivable	—		47,649			6,631			—			54,280
Accounts receivable - related party	—		2,298			—			—			2,298
Intercompany receivable	985,692		78,635			—			(1,064,327		)	—
Intercompany note receivable	440,000		—			—			(440,000		)	—
Inventories	—		5,889			—			—			5,889
Deferred income taxes	1,377		—			—			—			1,377
Other current assets	132		1,335			28			—			1,495
Total current assets	1,445,599		142,323			7,058			(1,504,327		)	90,653
Property and equipment
Oil and natural gas properties, at cost, based on the full cost method of accounting	—		1,614,610			450,961			—			2,065,571
Pipeline and gas gathering assets	—		6,503			—			—			6,503
Other property and equipment	—		4,635			—			—			4,635
Accumulated depletion, depreciation, amortization and impairment	—		(233,543		)	(10,766		)	1,178			(243,131		)
	—		1,392,205			440,195			1,178			1,833,578
Investment in subsidiaries	281,130		—			—			(281,130		)	—
Other assets	9,997		2,669			—			—			12,666
Total assets	$	1,736,726	$	1,537,197		$	447,253		$	(1,784,279	)	$	1,936,897
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	—	$	24,487		$	—		$	—		$	24,487
Accounts payable-related party	—		313			—			—			313
Intercompany payable	78,526		985,801			—			(1,064,327		)	—
Other current liabilities	18,661		111,338			412			—			130,411
Total current liabilities	97,187		1,121,939			440,412			(1,504,327		)	155,211
Long-term debt	450,000		137,000			—			—			587,000
Asset retirement obligations	—		5,147			—			—			5,147
Deferred income taxes	106,630		—			—			—			106,630
Total liabilities	653,817		1,264,086			440,412			(1,504,327		)	853,988
Commitments and contingencies
Stockholders’ equity:	1,082,909		273,111			6,841			(279,952		)	1,082,909
Total equity	1,082,909		273,111			6,841			(279,952		)	1,082,909
Total liabilities and equity	$	1,736,726	$	1,537,197		$	447,253		$	(1,784,279	)	$	1,936,897

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Condensed Consolidated Balance Sheet
December 31, 2013
(In thousands)
						Non–
			Guarantor			Guarantor
	Parent		Subsidiaries			Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	526	$	14,267		$	762		$	—		$	15,555
Accounts receivable	—		28,544			—			9,426			37,970
Accounts receivable - related party	—		1,303			—			—			1,303
Royalty income receivable	—		—			9,426			(9,426		)	—
Intercompany receivable	715,169		413,744			—			(1,128,913		)	—
Intercompany note receivable	440,000		—			—			(440,000		)	—
Inventories	—		5,631			—			—			5,631
Deferred income taxes	112		—			—			—			112
Other current assets	—		1,397			—			—			1,397
Total current assets	1,155,807		464,886			10,188			(1,568,913		)	61,968
Property and equipment
Oil and natural gas properties, at cost, based on the full cost method of accounting	—		1,200,326			448,034			—			1,648,360
Pipeline and gas gathering assets	—		6,142			—			—			6,142
Other property and equipment	—		4,071			—			—			4,071
Accumulated depletion, depreciation, amortization and impairment	—		(207,037		)	(5,199		)	—			(212,236		)
	—		1,003,502			442,835			—			1,446,337
Investment in subsidiaries	235,334		—			—			(235,334		)	—
Other assets	10,207		3,102			—			—			13,309
Total assets	$	1,401,348	$	1,471,490		$	453,023		$	(1,804,247	)	$	1,521,614
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	—	$	2,679		$	—		$	—		$	2,679
Accounts payable-related party	—		17			—			—			17
Intercompany payable	3,920		1,115,214			87			(1,119,221		)	—
Intercompany accrued interest	—		—			9,692			(9,692		)	—
Other current liabilities	10,123		108,245			256			—			118,624
Total current liabilities	14,043		1,226,155			10,035			(1,128,913		)	121,320
Long-term debt	450,000		10,000			—			—			460,000
Intercompany note payable	—		—			440,000			(440,000		)	—
Asset retirement obligations	—		2,989			—			—			2,989
Deferred income taxes	91,764		—			—			—			91,764
Total liabilities	555,807		1,239,144			450,035			(1,568,913		)	676,073
Commitments and contingencies
Stockholders’ equity:	845,541		232,346			2,988			(235,334		)	845,541
Total equity	845,541		232,346			2,988			(235,334		)	845,541
Total liabilities and equity	$	1,401,348	$	1,471,490		$	453,023		$	(1,804,247	)	$	1,521,614

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)



Condensed Consolidated Statement of Operations
Three Months Ended March 30, 2014
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues:
Oil sales	$	—		$	75,249		$	—		$	14,509		$	89,758
Natural gas sales	—			2,832			—			503			3,335
Natural gas liquid sales	—			4,070			—			841			4,911
Royalty income	—			—			15,853			(15,853		)	—
Total revenues	—			82,151			15,853			—			98,004
Costs and expenses:
Lease operating expenses	—			7,915			—			—			7,915
Production and ad valorem taxes	—			4,903			921			18			5,842
Gathering and transportation	—			588			—			(6		)	582
Depreciation, depletion and amortization	—			25,801			5,567			(395		)	30,973
General and administrative expenses	3,985			506			66			—			4,557
Asset retirement obligation accretion expense	—			72			—			—			72
Intercompany charges	—			—			78			(78		)	—
Total costs and expenses	3,985			39,785			6,632			(461		)	49,941
Income (loss) from operations	(3,985		)	42,366			9,221			461			48,063
Other income (expense)
Interest income - intercompany	5,368			—			—			(5,368		)	—
Interest expense	(5,887		)	(618		)	—			—			(6,505		)
Interest expense - intercompany	—			—			(5,368		)	5,368			—
Other income - intercompany	—			78			—			(78		)	—
Other income - related party	—			30			—			—			30
Loss on derivative instruments, net	—			(4,398		)	—			—			(4,398		)
Total other expense, net	(519		)	(4,908		)	(5,368		)	(78		)	(10,873		)
Income (loss) before income taxes	(4,504		)	37,458			3,853			383			37,190
Provision for income taxes	13,601			—			—			—			13,601
Net income (loss)	$	(18,105	)	$	37,458		$	3,853		$	383		$	23,589

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)



Condensed Consolidated Statement of Operations
Three Months Ended March 30, 2013
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries		Eliminations		Consolidated
Revenues:
Oil sales	$	—		$	25,253		$	—	$	—	$	25,253
Natural gas sales	—			1,151			—		—		1,151
Natural gas liquid sales	—			2,505			—		—		2,505
Total revenues	—			28,909			—		—		28,909
Costs and expenses:
Lease operating expenses	—			5,435			—		—		5,435
Production and ad valorem taxes	—			1,427			—		—		1,427
Gathering and transportation	—			133			—		—		133
Depreciation, depletion and amortization	—			10,738			—		—		10,738
General and administrative expenses	741			1,730			—		—		2,471
Asset retirement obligation accretion expense	—			43			—		—		43
Total costs and expenses	741			19,506			—		—		20,247
Income (loss) from operations	(741		)	9,403			—		—		8,662
Other income (expense)
Interest expense	—			(485		)	—		—		(485		)
Other income - related party	—			389			—		—		389
Gain (loss) on derivative instruments, net	—			(8		)	—		—		(8		)
Total other expense, net	—			(104		)	—		—		(104		)
Income (loss) before income taxes	(741		)	9,299			—		—		8,558
Provision for income taxes	3,162			—			—		—		3,162
Net income (loss)	$	(3,903	)	$	9,299		$	—	$	—	$	5,396

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)



Condensed Consolidated Statement of Cash Flows
Three Months Ended March 31, 2014
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Net cash provided by operating activities	$	11,805		$	53,416		$	6,543		$	(298	)	$	71,466

Cash flows from investing activities:
Additions to oil and natural gas properties	—			(79,378		)	(6,878		)	395			(85,861		)
Acquisition of leasehold interests	—			(312,207		)	—			—			(312,207		)
Intercompany transfers	(204,544		)	204,544			—			—			—
Other investing activities	—			(1,116		)	—			—			(1,116		)
Net cash used in investing activities	(204,544		)	(188,157		)	(6,878		)	395			(399,184		)
Cash flows from financing activities:
Proceeds from borrowing on credit facility	—			127,000			—			—			127,000
Proceeds from public offerings	208,644			—			—			—			208,644
Other financing activities	1,967			(9		)	(28		)	(97		)	1,833
Net cash provided by (used in) financing activities	210,611			126,991			(28		)	(97		)	337,477

Net increase in cash and cash equivalents	17,872			(7,750		)	(363		)	—			9,759
Cash and cash equivalents at beginning of period	526			14,267			762			—			15,555
Cash and cash equivalents at end of period	$	18,398		$	6,517		$	399		$	—		$	25,314

Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)



Condensed Consolidated Statement of Cash Flows
Three Months Ended March 31, 2013
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries		Eliminations		Consolidated
Net cash provided by operating activities	$	(5	)	$	16,860		$	—	$	—	$	16,855

Cash flows from investing activities:
Additions to oil and natural gas properties	—			(54,962		)	—		—		(54,962		)
Acquisition of leasehold interests	—			(18,550		)	—		—		(18,550		)
Other investing activities	—			(582		)	—		—		(582		)
Net cash used in investing activities	—			(74,094		)	—		—		(74,094		)
Cash flows from financing activities:
Proceeds from borrowing on credit facility	—			36,500			—		—		36,500
Intercompany transfers	103			(103		)	—		—		—
Other financing activities	(103		)	—			—		—		(103		)
Net cash provided by (used in) financing activities	—			36,397			—		—		36,397

Net increase in cash and cash equivalents	(5		)	(20,837		)	—		—		(20,842		)
Cash and cash equivalents at beginning of period	14			26,344			—		—		26,358
Cash and cash equivalents at end of period	$	9		$	5,507		$	—	$	—	$	5,516

Diamondback Energy, Inc. - FORM 8-K - EX-99.4 - EXHIBIT - September 12, 2014

Attached files

Diamondback Energy, Inc. Reports