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) |
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| 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 | ||||
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| PV-10 value |
$ | 952,331,000 | $ | 647,222,000 | ||||
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| (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.
| 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.” | |
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.” | |