UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 8-K

 

 

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of report (Date of earliest event reported): September 6, 2013

 

 

DIAMONDBACK ENERGY, INC.

(Exact Name of Registrant as Specified in Charter)

 

 

 

Delaware		001-35700		45-4502447
(State or other jurisdiction of incorporation)		(Commission File Number)		(I.R.S. Employer Identification Number)

 

500 West Texas Suite 1225 Midland, Texas		79701
(Address of principal executive offices)		(Zip code)

(432) 221-7400

(Registrant’s telephone number, including area code)

Not Applicable

(Former name or former address, if changed since last report)

 

 

Check the appropriate box below if the Form 8-K is intended to simultaneously satisfy the filing obligation of the Registrant under any of the following provisions:

 

¨	Written communications pursuant to Rule 425 under the Securities Act

 

¨	Soliciting material pursuant to Rule 14a-12 under the Exchange Act

 

¨	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act

 

¨	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act

 

 

 

---

Item 1.01. Entry into a Material Definitive Agreement.

As of September 6, 2013, we entered into a Fourth Amendment (the “Fourth Amendment”) to the Amended and Restated Credit Agreement, originally dated as of July 24, 2012, as subsequently amended (the “Credit Agreement”), by and among us, as parent guarantor, our wholly-owned subsidiary Diamondback O&G LLC (f/k/a Windsor Permian LLC), as borrower, each of the guarantors party thereto, each of the lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent for the lenders. The Fourth Amendment increases the amount of unsecured senior notes that we are permitted to issue from $250,000,000 to $500,000,000. It also provides that, for the four fiscal quarter periods ending September 30, 2013, December 31, 2013 and March 31, 2014, EBITDAX and Interest Expense (each as defined in the Credit Agreement) shall be calculated by annualizing quarterly EBITDAX and Interest Expense for the one, two and three fiscal quarter periods, respectively, most recently completed, in lieu of using actual EBITDAX and Interest Expense for the preceding four fiscal quarters.

Wells Fargo Bank, N.A. and certain other lenders under the Credit Agreement or their affiliates have provided and/or may in the future provide financial advisory, investment banking and commercial banking services in the ordinary course of business to us and certain of our affiliates, for which they have received, and may in the future receive, customary fees and expense reimbursement. In addition, Wells Fargo Bank, N.A. is the counterparty to certain price swap derivatives that we use to reduce price volatility associated with certain of our oil sales.

The preceding summary of the Fourth Amendment is qualified in its entirety by reference to the full text of such agreement, a copy of which is attached as Exhibit 10.1 hereto and incorporated herein by reference.

Item 8.01 Other Events.

Recent Developments

Pending Midland County Mineral Interest Acquisition

As we previously reported, on August 28, 2013, we entered into a definitive purchase agreement to purchase mineral interests underlying approximately 15,000 gross (12,500 net) acres in Midland County, Texas in the Permian Basin for a purchase price of $440.0 million, subject to certain adjustments. We are the operator of approximately 50% of the acreage associated with these mineral interests. The mineral interests will entitle us to receive an average 20% royalty interest on all production from this acreage with no additional future capital or operating expense required. As of September 1, 2013, there were 183 vertical wells and eight horizontal wells on this acreage and production was approximately 1,600 net barrels of crude oil equivalent (“BOE”) per day during June 2013. This estimated royalty interest, acreage and production data are based on information provided to us in the course of our due diligence but have not yet been verified by us. We expect to close this acquisition by the end of September 2013, however the acquisition remains subject to completion of due diligence and satisfaction of other closing conditions and may not be completed. We intend to fund the purchase price for this acquisition from cash on hand and the net proceeds from our proposed offering of senior notes described below under the heading “– Launch of Notes Offering.” The free cash flow attributable to these mineral interests was approximately $3.7 million in June 2013.

Recent and Pending Martin and Dawson County Leasehold Acquisitions

As we previously reported, we recently entered into two separate definitive agreements to acquire additional leasehold interests in the Permian Basin for an aggregate purchase price of $165.0 million, subject to certain adjustments. On August 2, 2013, we entered into a purchase and sale agreement in which we agreed to acquire from an unrelated third party certain assets located in northwestern Martin County, Texas, consisting of a 100% working interest (80% net revenue interest) in 4,506 gross and net leasehold acres, with 17 gross and net producing vertical wells, an estimated 1,199 thousand barrels of crude oil equivalent (“MBOE”) of proved developed reserves (including 88 MBOE attributable to one proved developed non-producing (“PDNP”) well) as of September 1, 2013 and 457 gross (365 net) BOE per day of production during July 2013. We have identified approximately 96 gross and net horizontal drilling locations on this acreage, of which 32 gross and net locations are located in the Wolfcamp B interval, with lateral lengths expected to range from approximately 5,000 feet to 8,000 feet. This acquisition was completed on September 4, 2013.

In addition, on August 1, 2013, we entered into a purchase and sale agreement in which we agreed to acquire from an unrelated third party certain assets located primarily in southwestern Dawson County, Texas, consisting of a 70% working interest (54% net revenue interest) in 9,390 gross (6,647 net) leasehold acres, with 30 gross (21 net) producing vertical wells, an estimated 907 MBOE of proved developed reserves (including 45 MBOE attributable to one PDNP well) as of September 1, 2013 and 777 gross (417 net) BOE per day of production during

---

June 2013. We have identified approximately 156 gross (109 net) potential horizontal drilling locations on this acreage, of which 53 gross (37 net) locations are located in the Wolfcamp B interval, with lateral lengths ranging from approximately 5,000 feet to 9,500 feet. We expect to close this transaction by the end of September 2013, however the acquisition remains subject to completion of due diligence and satisfaction of other closing conditions and may not be completed.

We will be the operator of all of the acreage acquired in these leasehold acquisitions. The purchase price for these acquisitions will come from cash on hand, including the net proceeds from our August 2013 underwritten public offering of 4,600,000 shares of our common stock.

In this report, we refer to our recent Martin County acquisition and our pending Midland County and Dawson County acquisitions, collectively, as the “Recently Announced Acquisitions.”

Horizontal Wells

In 2012, we began testing the horizontal well potential of our acreage. Our first horizontal well was the Janey 16H in Upton County with a 3,842 foot lateral in the Wolfcamp B interval. We are the operator of this well with a 100% working interest. It was completed in June 2012 and had a peak 24-hour initial production (“IP”) rate of 618 BOE/d and a peak consecutive 30-day average initial production rate of 486 BOE/d, of which 86% was oil. Through June 30, 2013, the Janey 16H had produced a total of 61 thousand barrels (“MBbls”) of oil and 73 million cubic feet (“MMcf”) of natural gas. Our second horizontal well was the Kemmer 4209H in Midland County. It is a non-operated well in which we own a 47% working interest. It was completed in September 2012 in the Wolfcamp B interval with a 3,733 foot lateral. The production as reported to us by the operator was a peak 24-hour initial production rate of 892 BOE/d and a peak consecutive 30-day average initial production rate of 712 BOE/d, of which 85% was oil. Through June 30, 2013, the Kemmer 4209H had produced a total of 63 MBbls of oil and 64 MMcf of natural gas. Based on the decline curve analysis of the current production, we anticipate that the gross estimated ultimate recovery for each of these wells will be in the range of 400 to 500 MBOE.

Subsequent to the Janey 16H and Kemmer 4209H wells, we have drilled or are currently drilling 17 horizontal wells as operator and have participated in one additional horizontal well as a non-operator, all of which are Wolfcamp B wells in various stages of development. The table below presents certain data regarding our horizontal wells.

 

Horizontal Wells: Midland County
Well Name		Lateral Length				Number of Frac Stages		Peak 24-HR IP (BOE/d)				Peak 30 Day IP Rate (BOE/d)				% Oil(a)
Kemmer 4209H(b)			3,733’			15			892				712	(d)			85	%
ST NW 2501H			4,451’			19			1,054				655	(d)			90	%
ST NW 2502H			4,351’			16			651				500	(c)			88	%
Sarah Ann 3812H(b)			4,830’			18			892				711	(d)			88	%
ST W 4301H			7,141’			29			1,136				916	(d)			85	%
ST W 701H			7,280’			29			1,042	(d)			774	(d)			92	%
ST W 4302H			7,071’			30			701	(d)			438	(d)			87	%
ST W 706H			7,541’			Flowback operations underway

 

Horizontal Wells: Upton County
Well Name		Lateral Length				Number of Frac Stages		Peak 24-HR IP (BOE/d)				Peak 30 Day IP Rate (BOE/d)				% Oil(a)
Janey 16H			3,842’			16			618				486	(c)			86	%
Neal A Unit 8-1H			7,441’			32			871				697	(c)			87	%
Janey 3H			4,411’			19			724				488	(d)			82	%
Neal B Unit 8-2H			6,501’			26			1,134				617	(d)			73	%
Kendra A Unit 1H			7,411’			30			970				677	(d)			82	%
Jacee A Unit 1H			7,541’			30			1,085				632	(d)			83	%
Janey 2H			4,572’			19			930	(d)			391	(d)			88	%
Janey 4H			4,564’			10			880	(d)			454	(d)			88	%
Charlotte A Unit 1H			10,353’			Flowback operations underway
Neal C Unit 8 3H			6,851’			Flowback operations underway

---

Horizontal Wells: Andrews County

Well Name

Lateral Length

Number of Frac Stages

Peak 24-HR IP (BOE/d)

Peak 30 Day IP Rate (BOE/d)

% Oil(a)

UL III 4-1H

4,051’

19

613

(d)

N/A

(e)

85

%

UL Viper 6-1H

7,540’

Flowback operations underway

 

(a)	During the period for which the Peak 30 day IP Rate is presented except in the case of the UL III 4-1H well, which is based on the Peak 24-hour IP rate.

(b)	Non-operated.

(c)	On gas lift.

(d)	On sub pump.

(e)	A peak 30 day IP Rate is not available.

In addition, we are currently drilling three additional horizontal wells. Based on the production results from the wells in Midland and Upton Counties, along with geoscience and engineering data that we have gathered and analyzed, we believe that our acreage in Midland and Upton Counties is prospective in the Wolfcamp B interval.

Updates to Operating Information

Based on our evaluation of applicable geologic and engineering data as of June 30, 2013, we had 867 identified potential vertical drilling locations on 40-acre spacing, an additional 1,128 identified potential vertical drilling locations based on 20-acre downspacing and we had also identified 862 potential horizontal drilling locations in multiple horizons on our acreage. With respect to the leasehold acreage subject to the Recently Announced Acquisitions, we would have an additional 252 identified potential horizontal drilling locations in multiple horizons.

The following table summarizes certain operating information of our properties as of June 30, 2013, except as otherwise noted.

 

Basin		Net Acreage(1)				Average Working Interest(1)				Identified Potential Drilling Locations(2)								2013 Budget												Estimated Net Proved Reserves at September 1, 2013(3)								Average Daily Production (BOE/d)(5)
										Gross				Net				Gross Wells(4)				Net Wells(4)				Capex (In millions)				MBOE				% Developed
Permian			54,035				88	%			1,729				1,472				74				65			$	290.0 - $320.0				47,135				40.3				7,189

 

(1)

Does not give effect to the Recently Announced Acquisitions of mineral interests underlying approximately 15,000 gross (12,500 net) acres in Midland County, Texas and approximately 11,150 additional net (13,900 gross) leasehold acres in Martin and Dawson Counties, Texas. Pro forma for the completion of these acquisitions, our average working interest would be 86%.

(2)

Reflects 867 gross (809 net) identified potential vertical drilling locations on 40-acre spacing, and 862 gross (663 net) identified potential horizontal drilling locations ranging in length from 4,500 feet to 9,500 feet in various horizons from the Clearfork to the Cline based on our evaluation of applicable geologic and engineering data. Some of these horizontal drilling locations require pooling acreage with other operators. We have an additional 1,128 gross (1,031 net) identified potential vertical drilling locations based on 20-acre downspacing. Does not include an additional 252 gross (205 net) identified potential horizontal drilling locations ranging in length from 5,000 feet to 9,500 feet in multiple horizons attributable to the leasehold acreage subject to the Recently Announced Acquisitions. The drilling locations on which we actually drill wells will ultimately depend on the availability of capital, regulatory approvals, oil and natural gas prices, costs, actual drilling results and other factors.

(3)

Our estimated proved reserves as of September 1, 2013, pro forma for the Recently Announced Acquisitions, were 57,876 MBOE, of which 43% were developed. The aggregate estimated proved reserves of 10,741 MBOE attributable to the Recently Announced Acquisitions are derived as follows: (a) Martin County acreage: estimated proved reserves of 1,199 MBOE (73% oil), of which 93% are developed; (b) Dawson County acreage: estimated proved reserves of 907 MBOE (81% oil), of which 95% are developed; and (c) mineral interests in Midland County: estimated proved reserves of 8,635 MBOE (66% oil), of which 53% are developed.

(4)	Includes 38 gross (33 net) operated vertical wells, 33 gross (30 net) operated horizontal wells, two gross (one net) non-operated vertical wells and one gross (one net) non-operated horizontal well.

(5)	During July 2013. Does not include 365 BOE/d attributable to production from our Martin County acreage that we acquired on September 4, 2013 with an effective date of July 1, 2013 or any production attributable to the pending Recently Announced Acquisitions in Dawson and Midland Counties, Texas.

Summary Reserve Data

As of September 1, 2013, our estimated proved oil and natural gas reserves were 47,135 MBOE based on a reserve report prepared by our internal reserve engineers and audited by Ryder Scott Company, L.P. (“Ryder Scott”), our independent reserve

---

engineer. Of these reserves, approximately 39.0% are classified as proved developed producing (“PDP”). Proved undeveloped (“PUD”) reserves included in this estimate are from 279 vertical gross well locations on 40-acre spacing and 11 gross horizontal well locations. As of September 1, 2013, these proved reserves were approximately 64% oil, 21% natural gas liquids and 15% natural gas. As of September 1, 2013, our estimated proved reserves, pro forma for the Recently Announced Acquisitions, were 57,876 MBOE based on our reserve report audited by Ryder Scott. Of these reserves, approximately 43.0% are classified as PDP, and approximately 65% were oil, 20% were natural gas liquids and 15% were natural gas.

The following table sets forth estimates of our net proved oil and natural gas reserves (i) on a historic basis as of September 1, 2013 based on a reserve report prepared by our reserve engineers and audited by Ryder Scott and (ii) as of September 1, 2013 on a pro forma basis after giving effect to the Recently Announced Acquisitions based on a reserve report prepared by our reserve engineers and audited by Ryder Scott. The reserve report was prepared in accordance with the rules and regulations of the Securities and Exchange Commission (the “SEC”).

 

		Pro Forma				Historical
		As of September 1, 2013				As of September 1, 2013
Estimated proved developed reserves:
Oil (Bbls)			16,043,800				11,505,300
Natural gas (Mcf)			26,489,300				19,039,900
Natural gas liquids (Bbls)			5,270,700				4,316,000
Total (BOE)			25,729,500				18,994,600
Estimated proved undeveloped reserves:
Oil (Bbls)			21,309,900				18,520,400
Natural gas (Mcf)			27,282,700				24,290,500
Natural gas liquids (Bbls)			6,289,900				5,571,800
Total (BOE)			32,146,900				28,140,600
Estimated Net Proved Reserves:
Oil (Bbls)			37,353,700				30,025,700
Natural gas (Mcf)			53,772,000				43,330,400
Natural gas liquids (Bbls)			11,560,600				9,887,800
Total (BOE)(1)(2)			57,876,400				47,135,200
Percent proved developed			44.5	%			40.3	%
PV-10 value(3)		$	952,331,000			$	647,222,000
Standardized measure(4)		$	750,163,000			$	496,127,000

 

(1)

Estimates of reserves as of September 1, 2013 and as of December 31, 2012, 2011 and 2010 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended September 1, 2013 and December 31, 2012, 2011 and 2010, respectively, in accordance with revised SEC guidelines applicable to reserve estimates as of the end of such periods. The unweighted arithmetic average first day of the month prices were $95.04 per Bbl for oil, $38.05 per Bbl for NGLs and $3.74 per thousand cubic feet (“Mcf”) for natural gas at September 1, 2013 and $88.13 per Bbl for oil, $43.88 per Bbl for NGLs and $2.86 per Mcf for gas at December 31, 2012. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

(2)

The aggregate estimated proved reserves of 10,741 MBOE attributable to the Recently Announced Acquisitions are derived as follows: (a) Martin County acreage: estimated proved reserves of 1,199 MBOE (73% oil), of which 93% are developed; (b) Dawson County acreage: estimated proved reserves of 907 MBOE (81% oil), of which 95% are developed; and (c) mineral interests in Midland County: estimated proved reserves of 8,635 MBOE (66% oil), of which 53% are developed.

(3)

Represents present value, discounted at 10% per annum, of estimated future net revenue before income tax of our estimated proven reserves. The estimated future net revenues set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on certain prevailing economic conditions. The estimated future production in our reserve report as of September 1, 2013 is priced based on the 12-month unweighted arithmetic average of the first-day-of-the month price for each month within such period, unless such prices were defined by contractual arrangements, as required by SEC regulations.

PV-10 is a non-GAAP measure because it excludes income tax effects. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of PV-10 to the most directly comparable GAAP measure-standardized measure of discounted future net cash flows. The following table reconciles the standardized measure of future net cash flows to the PV-10 value:

---

		Pro Forma				Historical
		September 1, 2013				September 1, 2013
Standardized measure of discounted future net cash flows		$	750,163,000			$	496,127,000
Add: Present value of future income tax discounted at 10%		$	202,168,000			$	151,095,000
PV-10 value		$	952,331,000			$	647,222,000

 

(4)

The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

The preceding summary of the reserve report as of September 1, 2013 is qualified in its entirety by reference to the full text of such report, a copy of which is attached as Exhibit 99.1 hereto and incorporated herein by reference.

Launch of Notes Offering

On September 9, 2013, we announced that we propose to offer, subject to market conditions and other factors, $450.0 million aggregate principal amount of senior notes (the “Notes”) to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”), and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. A copy of this press release is attached hereto as Exhibit 99.1.

The Notes will not be registered under the Securities Act or any state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from such registration requirements. This report is neither an offer to sell nor a solicitation of an offer to buy any of these securities and shall not constitute an offer, solicitation or sale in any jurisdiction in which such offer, solicitation or sale is unlawful.

Adjustments to Borrowing Base

The Credit Agreement provides for scheduled semiannual and other elective collateral borrowing base redeterminations based on oil and natural gas reserves and other factors (the “borrowing base”). Upon completion of the offering of the Notes, the borrowing base will be reduced from $180.0 million to $67.5 million, before giving effect to a redetermination to reflect our new reserve report dated as of September 1, 2013 and the completion of the Recently Announced Acquisitions. Wells Fargo Bank, N.A., the administrative agent under our Credit Agreement, has preliminarily indicated that our pro forma September 1, 2013 proved reserves will support a borrowing base ranging from $275.0 to $300.0 million, after giving effect to the offering of the Notes. The final recommended borrowing base is subject to customary due diligence as well as credit approval by Wells Fargo Bank, N.A. and the others syndicate lenders, and may be different than the preliminary indicated range. Wells Fargo Bank, N.A. has indicated that it anticipates the increase in the borrowing base will be finalized in October 2013.

---

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits.

 

---

SIGNATURE

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

 

				DIAMONDBACK ENERGY, INC.
Date: September 9, 2013				By:		/s/ Teresa L. Dick
						Teresa L. Dick Senior Vice President and Chief Financial Officer

---

Exhibit Index

 

Number		Exhibit
10.1		Fourth Amendment to Amended and Restated Credit Agreement, dated as of September 6, 2013, among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC (f/k/a Windsor Permian LLC), as borrower, each of the guarantors party thereto, each of the lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent for the lenders.
99.1		Internal Reserve Report as of September 1, 2013 audited by Ryder Scott Company, L.P.
99.2		Press release dated September 9, 2013 entitled “Diamondback Energy Launches Proposed $450 Million Senior Notes Offering.”

Exhibit 10.1

Execution Version

FOURTH AMENDMENT

TO

AMENDED AND RESTATED

CREDIT AGREEMENT

DATED AS OF SEPTEMBER 6, 2013

AMONG

DIAMONDBACK ENERGY, INC.,

AS PARENT GUARANTOR

DIAMONDBACK O&G LLC (F/K/A WINDSOR PERMIAN LLC),

AS BORROWER,

THE GUARANTORS,

WELLS FARGO BANK, NATIONAL ASSOCIATION,

AS ADMINISTRATIVE AGENT,

AND

THE LENDERS PARTY HERETO

SOLE BOOK RUNNER AND SOLE LEAD ARRANGER

WELLS FARGO SECURITIES, LLC

---

FOURTH AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT

THIS FOURTH AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT (this “Fourth Amendment”) dated as of September 6, 2013, is among: DIAMONDBACK ENERGY, INC., a Delaware corporation, as the Parent Guarantor (the “Parent Guarantor”); DIAMONDBACK O&G LLC, a Delaware limited liability company (f/k/a Windsor Permian LLC, the “Borrower”); each of the undersigned guarantors (together with the Parent Guarantor, the “Guarantors”); each of the lenders party to the Credit Agreement referred to below (collectively, the “Lenders”); and WELLS FARGO BANK, NATIONAL ASSOCIATION (“Wells”), as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the “Administrative Agent”).

RECITALS

A. The Parent Guarantor, the Borrower, the Administrative Agent and the Lenders are parties to that certain Amended and Restated Credit Agreement dated as of July 24, 2012, as amended by that certain First Amendment dated as of July 31, 2012, that certain Second Amendment dated as of September 28, 2012 and that certain Third Amendment dated as of August 30, 2013 (as amended, modified or supplemented, the “Credit Agreement”), pursuant to which the Lenders have made certain credit available to and on behalf of the Borrower.

B. The Borrower has requested and the Majority Lenders have agreed to amend certain provisions of the Credit Agreement as set forth herein.

C. Now, therefore, to induce the Administrative Agent and the Lenders to enter into this Fourth Amendment and in consideration of the premises and the mutual covenants herein contained, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

Section 1. Defined Terms. Each capitalized term used herein but not otherwise defined herein has the meaning given such term in the Credit Agreement, as amended by this Fourth Amendment. Unless otherwise indicated, all section references in this Fourth Amendment refer to sections of the Credit Agreement.

Section 2. Amendments to Credit Agreement.

2.1 Amendments to Section 1.02. Section 1.02 is hereby amended by deleting the definitions of “Agreement” and “Senior Unsecured Notes” in their entirety and replacing them with the following:

“‘Agreement’ means this Amended and Restated Credit Agreement, as amended by the First Amendment dated as of July 31, 2012, the Second Amendment dated as of September 28, 2012, the Third Amendment dated as of August 30, 2013 and the Fourth Amendment dated as of September 6, 2013, as the same may be amended, modified or supplemented from time to time.

 

1

---

‘Senior Unsecured Notes’ means Debt in the form of unsecured senior or senior subordinated notes issued by the Parent Guarantor or the Borrower in an aggregate principal amount not to exceed $500,000,000 at any one time outstanding, including exchange notes issued in exchange therefor pursuant to any registration rights agreement (it being agreed that any such exchange or offer to exchange shall not constitute a Redemption or an offer to Redeem for purposes of this Agreement), and, in each case, any guarantees thereof by the Parent Guarantor, the Borrower or a Guarantor; provided that (a) at the time of incurring such Debt (i) no Default has occurred and is then continuing and (ii) no Default would result from the incurrence of such Debt after giving effect to the incurrence of such Debt (and any concurrent repayment of Debt with the proceeds of such incurrence), (b) such Debt does not have any scheduled amortization prior to 91 days after the Maturity Date, (c) such Debt does not mature sooner than 91 days after the Maturity Date, (d) the terms of such Debt are not materially more onerous, taken as a whole, than the terms of this Agreement and the other Loan Documents, (e) such Debt and any guarantees thereof are on prevailing market terms for similarly situated companies and (f) the Borrowing Base is adjusted as contemplated by Section 2.07(f) and the Borrower makes any prepayment required under Section 3.04(c)(iii).”

2.2 Amendment to Section 9.01. Section 9.01 is hereby amended by adding the following Section 9.01(e):

“(e) Notwithstanding anything to the contrary herein, for purposes of this Section 9.01 Interest Expense and EBITDAX shall be calculated as follows: for the four fiscal quarters ending on (i) September 30, 2013, Interest Expense and EBITDAX shall equal Interest Expense and EBITDAX, as applicable, for the fiscal quarter ending on such date multiplied by 4, (ii) December 31, 2013, Interest Expense and EBITDAX shall equal Interest Expense and EBITDAX, as applicable, for the two fiscal quarters ending on such date multiplied by 2, and (iii) March 31, 2014, Interest Expense and EBITDAX shall equal Interest Expense and EBITDAX, as applicable, for the three fiscal quarters ending on such date multiplied by 4/3.”

Section 3. Conditions Precedent. This Fourth Amendment shall become effective on the date (such date, the “Fourth Amendment Effective Date”), when each of the following conditions is satisfied (or waived in accordance with Section 12.02):

3.1 The Administrative Agent shall have received from the Majority Lenders, the Guarantors and the Borrower, counterparts (in such number as may be requested by the Administrative Agent) of this Fourth Amendment signed on behalf of such Person.

3.2 The Administrative Agent and the Lenders shall have received all fees and other amounts due and payable on or prior to the date hereof, including, to the extent invoiced, reimbursement or payment of all documented out-of-pocket expenses required to be reimbursed or paid by the Borrower under the Credit Agreement.

 

2

---

3.3 No Default shall have occurred and be continuing as of the date hereof, after giving effect to the terms of this Fourth Amendment.

The Administrative Agent is hereby authorized and directed to declare this Fourth Amendment to be effective when it has received documents confirming or certifying, to the satisfaction of the Administrative Agent, compliance with the conditions set forth in this Section 3 or the waiver of such conditions as permitted in Section 12.02. Such declaration shall be final, conclusive and binding upon all parties to the Credit Agreement for all purposes.

Section 4. Miscellaneous.

4.1 Confirmation. The provisions of the Credit Agreement, as amended by this Fourth Amendment, shall remain in full force and effect following the effectiveness of this Fourth Amendment.

4.2 Ratification and Affirmation; Representations and Warranties. Each of the Guarantors and the Borrower hereby (a) ratifies and affirms its obligations under, and acknowledges its continued liability under, each Loan Document to which it is a party and agrees that each Loan Document to which it is a party remains in full force and effect as expressly amended hereby and (b) represents and warrants to the Lenders that as of the date hereof, after giving effect to the terms of this Fourth Amendment:

(i) all of the representations and warranties contained in each Loan Document to which it is a party are true and correct, except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, such representations and warranties shall continue to be true and correct as of such specified earlier date,

(ii) no Default or Event of Default has occurred and is continuing, and

(iii) no event or events have occurred which individually or in the aggregate could reasonably be expected to have a Material Adverse Effect.

4.3 Counterparts. This Fourth Amendment may be executed by one or more of the parties hereto in any number of separate counterparts, and all of such counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of this Fourth Amendment by facsimile or electronic transmission shall be effective as delivery of a manually executed counterpart hereof.

4.4 NO ORAL AGREEMENT. THIS FOURTH AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN DOCUMENTS EXECUTED IN CONNECTION HEREWITH AND THEREWITH REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT UNWRITTEN ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

 

3

---

4.5 GOVERNING LAW. THIS FOURTH AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF TEXAS.

4.6 Payment of Expenses. In accordance with Section 12.03, the Borrower agrees to pay or reimburse the Administrative Agent for all of its reasonable out-of-pocket expenses incurred in connection with this Fourth Amendment, any other documents prepared in connection herewith and the transactions contemplated hereby, including, without limitation, the reasonable fees, charges and disbursements of counsel to the Administrative Agent.

4.7 Severability. Any provision of this Fourth Amendment that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

4.8 Successors and Assigns. This Fourth Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns.

4.9 Loan Document. This Fourth Amendment is a Loan Document.

[SIGNATURES BEGIN NEXT PAGE]

 

4

---

IN WITNESS WHEREOF, the parties hereto have caused this Fourth Amendment to be duly executed as of the date first written above.

 

SIGNATURE PAGE

FOURTH AMENDMENT TO CREDIT AGREEMENT

---

SIGNATURE PAGE

FOURTH AMENDMENT TO CREDIT AGREEMENT

---

SIGNATURE PAGE

FOURTH AMENDMENT TO CREDIT AGREEMENT

---

SIGNATURE PAGE

FOURTH AMENDMENT TO CREDIT AGREEMENT

---

SIGNATURE PAGE

FOURTH AMENDMENT TO CREDIT AGREEMENT

Exhibit 99.1

DIAMONDBACK ENERGY, INC.

Estimated

Future Reserves

Attributable to Certain

Leasehold and Royalty Interests

SEC Parameters

As of

September 1, 2013

\s\ Don P. Griffin

Don P. Griffin, P.E.

TBPE License No. 64150

Senior Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

 

 

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

---

 

September 7, 2013

Diamondback Energy, Inc.

500 West Texas, Suite 1210

Midland, Texas 79701

Gentlemen:

At the request of Diamondback Energy, Inc. (Diamondback), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of September 1, 2013 prepared by Diamondback’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). The estimated reserves shown herein represent Diamondback’s estimated net reserves attributable to the leasehold and royalty interests owned by Diamondback and, at the request of Diamondback, certain interests soon to be conveyed to Diamondback for which purchase and sales agreements exist. The properties reviewed by Ryder Scott incorporate Diamondback’s reserve determinations and are located in the state of Texas.

The properties reviewed by Ryder Scott account for 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of Diamondback as of September 1, 2013. In addition, at the request of Diamondback, its acquisitions of approximately 4506 gross and net acres in Martin County, Texas and approximately 9390 gross (6647 net) acres in Dawson count and certain mineral interests in Midland County, Texas have been included herein. The Dawson County and mineral interest acquisitions are to be conveyed to Diamondback at some point in September 2013. For the purposes of this audit and for simplicity, we have assumed these interestes to be effective as of September 1, 2013.

As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities.”

Based on our review, including the data, technical processes and interpretations presented by Diamondback, it is our opinion that the overall procedures and methodologies utilized by Diamondback in preparing their estimates of the proved reserves as of September 1, 2013 comply with the current SEC regulations and that the overall proved reserves as estimated by Diamondback are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

The estimated reserves presented in this report are related to hydrocarbon prices. Diamondback has informed us that in the preparation of their reserve and income projections, as of September 1, 2013, they used average prices during the 12-month period prior to the ending date of the period covered in this report, (including September 1, 2013 prices), determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as

 

SUITE 600, 1015 4TH STREET, S.W.            CALGARY, ALBERTA T2R 1J4		TEL (403) 262-2799		FAX (403) 262-2790
621 17TH STREET, SUITE 1550              DENVER, COLORADO 80293-1501		TEL (303) 623-9147		FAX (303) 623-4258

 

1

---

Diamondback Energy, Inc.

September 7, 2013

Page 2

 

required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by Diamondback attributable to Diamondback’s interests (and assumed conveyances) are summarized as follows:

SEC PARAMETERS

Estimated Net Reserves

Certain Leasehold and Royalty Interests of

Diamondback Energy, Inc.

 

		As of September 1, 2013
		Proved
		Developed								Undeveloped				Total Proved
		Producing				Non-Producing
Net Reserves of Properties
Audited by Ryder Scott
Oil/Condensate—Mbarrels			15,480				564				21,310				37,354
Plant Products—Mbarrels			5,146				125				6,290				11,561
Gas—MMCF			25,727				762				27,283				53,772
MBOe			24,914				816				32,147				57,877

A detailed breakdown of reserves by acquisition may be found on Table A of this report.

Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (Mbarrels). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the state of Texas. The net remaining reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousand barrels of oil equivalent.

Reserves Included in This Report

In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. The proved developed non-producing reserves included herein consist of the shut-in and behind pipe categories.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

2

---

Diamondback Energy, Inc.

September 7, 2013

Page 3

 

time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Diamondback’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.

Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, could be more or less than the estimated amounts.

Audit Data, Methodology, Procedure and Assumptions

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

3

---

Diamondback Energy, Inc.

September 7, 2013

Page 4

 

those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties that we reviewed were estimated by performance methods, analogy, or a combination of these methods. Approximately 90 percent of the proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods. These performance methods include decline curve analysis which utilized extrapolations of historical production and pressure data available through mid-August 2013, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Diamondback or obtained from public data sources and were considered sufficient for the purpose thereof. The remaining 10 percent of the proved producing reserves that we reviewed were estimated by analogy or a combination of methods. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

All of the proved developed non-producing and undeveloped reserves that we reviewed were estimated by the analogy method. The data utilized from the analogues were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review.

As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Diamondback relating to hydrocarbon prices and costs as noted herein.

The hydrocarbon prices furnished by Diamondback for the properties reviewed by us are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, (including September 1, 2013 prices), determined as the unweighted arithmetic averages of

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

4

---

Diamondback Energy, Inc.

September 7, 2013

Page 5

 

the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

The initial SEC hydrocarbon prices in effect on September 1, 2013 for the properties reviewed by us were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by Diamondback for the geographic area reviewed by us.

The product prices which were actually used by Diamondback to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used by Diamondback were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Diamondback.

The table below summarizes Diamondback’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as Diamondback’s “average realized prices.” The average realized prices shown in the table below were determined from Diamondback’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and Diamondback’s estimate of the total net reserves for the properties reviewed by us for the geographic area. The data shown in the table below is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us.

 

Geographic Area		Product		Price Reference		Average Benchmark Prices		Average Realized Prices
North America
United States		Oil/Condensate		WTI Cushing		$95.04/Bbl		$88.94/Bbl
		NGLs		Mount Belvieu Propane		$38.05/Bbl		$34.76/Bbl
		Gas		Henry Hub		$3.60/MMBTU		$3.74/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in Diamondback’s individual property evaluations.

Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserve estimates reviewed. The proved gas volumes included herein do not attribute gas consumed in operations as reserves.

Operating costs furnished by Diamondback are based on the operating expense reports of Diamondback and include only those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished by Diamondback were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Diamondback.

Development costs furnished by Diamondback are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by Diamondback were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

5

---

Diamondback Energy, Inc.

September 7, 2013

Page 6

 

verification of the data used by Diamondback. Diamondback’s estimates of zero abandonment costs after salvage value for onshore properties were accepted without independent verification. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for Diamondback’s estimate.

The proved developed non-producing and undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with Diamondback’s plans to develop these reserves as of September 1, 2013. The implementation of Diamondback’s development plans as presented to us is subject to the approval process adopted by Diamondback’s management. As the result of our inquiries during the course of our review, Diamondback has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by Diamondback’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Diamondback. Additionally, Diamondback has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by Diamondback were held constant throughout the life of the properties.

Diamondback’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used by Diamondback to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Diamondback. Wells or locations that are not currently producing may start producing earlier or later than anticipated in Diamondback’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

In addition, future capital allocations by Diamondback may delay the drilling of certain vertical undeveloped locations beyond the 5 year limit set by the SEC in preference to more profitable horizontal locations. Such a delay has not been reflected in this report.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Diamondback’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbon, drilling and production practices, environmental protection, marketing and

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

6

---

Diamondback Energy, Inc.

September 7, 2013

Page 7

 

pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Diamondback owns or assumes to be conveyed an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by Diamondback for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Certain technical personnel of Diamondback are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.

Diamondback has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of Diamondback’s forecast of future proved production, we have relied upon data furnished by Diamondback with respect to property interests owned (or assumes to be conveyed), production and well tests from examined wells, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Diamondback. We consider the factual data furnished to us by Diamondback to be appropriate and sufficient for the purpose of our review of Diamondback’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by Diamondback and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.

Audit Opinion

Based on our review, including the data, technical processes and interpretations presented by Diamondback, it is our opinion that the overall procedures and methodologies utilized by Diamondback in preparing their estimates of the proved reserves as of September 1, 2013 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Diamondback are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

We were in reasonable agreement with Diamondback’s estimates of proved reserves, for the properties which we reviewed. As a consequence, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by and assumed to be conveyed to Diamondback.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy-five years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

7

---

Diamondback Energy, Inc.

September 7, 2013

Page 8

 

clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Diamondback. Neither we nor any of our employees have any interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for the review of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations.

We have provided Diamondback with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in presentations made by Diamondback and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

 

[SEAL]

DPG (FWZ)/pl

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

8

---

Diamondback Energy, Inc.

September 7, 2013

Page 9

 

Table A

Detailed Reserve Breakdown by Acquistion and Reserve Category

 

Reserve Category		Interests		OIL Mbarrels				GAS MMCF				NGL Mbarrels				MBOe				Wells
Proved Producing		Diamondback Pre-Aquistion			11088.5				18504.2				4201.7				18374.2				286
		Martin County			805.4				1837				0				1111.6				17
		Dawson County			694.6				1005.2				0				862.1				30
		Minerals			2891.7				4381.1				943.8				4565.7				191
		Total Proved Producing			15480.2				25727.5				5145.5				24913.6
Proved Non-Producing		Diamondback Pre-Aquistion			416.8				535.7				114.3				620.4				4
		Martin County			65.9				131.8				0				87.9				1
		Dawson County			36.6				48.9				0				44.8				1
		Minerals			44.3				45.4				10.9				62.8				2
		Total Proved Non-Producing			563.6				761.8				125.2				815.9
Proved Developed		Diamondback Pre-Aquistion			11505.3				19039.9				4316				18994.6				290
		Martin County			871.3				1968.8				0				1199.5				18
		Dawson County			731.2				1054.1				0				906.9				31
		Minerals			2936				4426.5				954.7				4628.5				193
		Total Proved Developed			16043.8				26489.3				5270.7				25729.5
Proved Undeveloped		Diamondback Pre-Aquistion			18520.4				24290.5				5571.8				28140.6				290
		Martin County			0				0				0				0				0
		Dawson County			0				0				0				0				0
		Minerals			2789.5				2992.2				718.1				4006.3				130
		Total Proved Undeveloped			21309.9				27282.7				6289.9				32146.9
Total Proved		Diamondback Pre-Aquistion			30025.7				43330.4				9887.8				47135.2				580
		Martin County			871.3				1968.8				0				1199.5				18
		Dawson County			731.2				1054.1				0				906.9				31
		Minerals			5725.5				7418.7				1672.8				8634.8				323
		Total Proved			37353.7				53772.0				11560.6				57876.4

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

9

---

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Don P. Griffin was the primary technical person responsible for overseeing the estimate of the reserves, future production and income presented herein.

Mr. Griffin, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1981, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Griffin served in a number of engineering positions with Amoco Production Company. For more information regarding Mr. Griffin’s geographic and job specific experience, please refer to the Ryder Scott Company website at http://www.ryderscott.com/Experience/Employees.php.

Mr. Griffin graduated with honors from Texas Tech University with a Bachelor of Science degree in Electrical Engineering in 1975 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Griffin fulfills. Mr. Griffin attended an additional 15 hours of training during 2012 covering such topics as reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants.

Based on his educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Griffin has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

10

---

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

11

---

PETROLEUM RESERVES DEFINITIONS

Page 2

 

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

(i)

The area of the reservoir considered as proved includes:

 

(A)

The area identified by drilling and limited by fluid contacts, if any, and

 

(B)

Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

 

(ii)

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

 

(iii)

Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

12

---

PETROLEUM RESERVES DEFINITIONS

Page 3

 

 

(iv)

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

 

(A)

Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

 

(B)

The project has been approved for development by all necessary parties and entities, including governmental entities.

 

(v)

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

13

---

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

 

(i)

Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

 

(ii)

Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

 

(1)

completion intervals which are open at the time of the estimate, but which have not started producing;

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

14

---

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

 

 

(2)

wells which were shut-in for market conditions or pipeline connections; or

 

(3)

wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category 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.

 

(i)

Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

 

(ii)

Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

 

(iii)

Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

15

Exhibit 99.2

 

DIAMONDBACK ENERGY LAUNCHES PROPOSED $450 MILLION SENIOR NOTES OFFERING

Midland, TX (September 9, 2013) – Diamondback Energy, Inc. (NASDAQ: FANG) (“Diamondback Energy”) announced today that it proposes to offer, subject to market conditions and other factors, $450 million aggregate principal amount of senior notes due 2021 (the “Notes”) to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”), and to certain non-U.S. persons in accordance with Regulation S under the Securities Act.

Diamondback Energy intends to use the net proceeds from the offering to fund its pending acquisition of mineral interests in the Permian Basin. To the extent the pending acquisition is not consummated, or the applicable purchase price is less than currently estimated, Diamondback Energy intends to use any remaining net proceeds from the offering to fund a portion of its exploration and development activities and for general corporate purposes, which may include leasehold interest and property acquisitions and working capital.

The Notes will be general unsecured senior obligations of Diamondback Energy and will be guaranteed on a senior unsecured basis by all of Diamondback Energy’s current subsidiaries and any future restricted subsidiaries that guarantee Diamondback Energy’s senior credit facility. Interest on the Notes will be payable semi-annually.

The Notes will not be registered under the Securities Act or any state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from such registration requirements.

This press release shall not constitute an offer to sell or the solicitation of an offer to buy nor shall there be any sale of these securities in any state in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such state or jurisdiction.

Forward Looking Statements

This news release contains forward-looking statements within the meaning of the federal securities laws. All statements, other than historical facts, that address activities (including the pending acquisitions) that Diamondback Energy assumes, plans, expects, believes, intends or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward-looking statements are based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events. These forward-looking statements involve certain risks and uncertainties that could cause the results to differ materially from those expected by the management of Diamondback Energy. Information

---

concerning these risks and other factors can be found in Diamondback Energy’s filings with the Securities and Exchange Commission, including its Forms 10-K, 10-Q and 8-K, which can be obtained free of charge on the Securities and Exchange Commission’s web site at http://www.sec.gov. Diamondback Energy undertakes no obligation to update or revise any forward-looking statement.

Investor Contact:

Adam Lawlis

+1 432.221.7467

alawlis@diamondbackenergy.com