Form 8-K/A Vanguard Natural Resourc For: Oct 09
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E-mailUNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K/A
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Date of Report (Date of earliest event reported): October 9, 2015 (October 5, 2015)
Vanguard Natural Resources, LLC
(Exact name of registrant specified in its charter)
Delaware | 001-33756 | 61-1521161 | ||
(State or Other Jurisdiction | (Commission | (IRS Employer | ||
Of Incorporation) | File Number) | Identification No.) | ||
5847 San Felipe, Suite 3000
Houston, TX 77057
(Address of principal executive offices, zip code)
Registrant’s telephone number, including area code: (832) 327-2255
(Former name or former address, if changed since last report.)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
oWritten communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
oSoliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
oPre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
oPre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
Introductory Note
As reported in a Current Report on Form 8-K filed with the Securities and Exchange Commission (the “SEC”) by Vanguard Natural Resources, LLC, a Delaware limited liability company (“Vanguard”), on October 5, 2015 (the “Original Form 8-K”), on October 5, 2015, Vanguard completed the previously announced transactions contemplated by the Purchase Agreement and Plan of Merger, dated as of April 20, 2015 (the “Merger Agreement”), by and among Vanguard, Lighthouse Merger Sub, LLC, a wholly owned subsidiary of Vanguard (“Merger Sub”), Lime Rock Management LP (“LR Management”), Lime Rock Resources A, L.P. (“LRR A”), Lime Rock Resources B, L.P. (“LRR B”), Lime Rock Resources C, L.P. (“LRR C”), Lime Rock Resources II-A, L.P. (“LRR II-A”), Lime Rock Resources II-C, L.P. (“LRR II-C,” and, together with LRR A, LRR B, LRR C, LRR II-A and LR Management, the “GP Sellers”), LRR Energy, L.P. (“LRE”) and LRE GP, LLC (“LRE GP”). Pursuant to the terms of the Merger Agreement, Merger Sub was merged with and into LRE, with LRE continuing as the surviving entity and as a wholly owned subsidiary of Vanguard (the “Merger”), and, at the same time, Vanguard acquired all of the limited liability company interests in LRE GP from the GP Sellers in exchange for common units representing limited liability company interests in Vanguard (“Vanguard Common Units”).
The Merger was completed following approval, at a special meeting of LRE unitholders on October 5, 2015, of the Merger Agreement and the Merger by holders of a majority of the outstanding common units representing limited partner interests in LRE (“LRE Common Units”). As a result of the Merger, (i) each outstanding LRE Common Unit was converted into the right to receive 0.550 newly issued Vanguard Common Units or, in the case of fractional Vanguard Common Units, cash (without interest and rounded up to the nearest whole cent) and (ii) Vanguard purchased all of the outstanding limited liability company interests in LRE GP in exchange for 12,320 newly issued Vanguard Common Units.
This Current Report on Form 8-K/A is being filed to amend Item 9.01 of the Original Form 8-K to provide the required audited and unaudited financial statements of LRE. The unaudited pro forma financial information related to the Merger is contained in Item 9.01(b) of Vanguard's Current Report on Form 8-K/A filed with the SEC on October 9, 2015.
Item 9.01 Financial Statements and Exhibits
(a) Financial Statements of Businesses Acquired.
The audited consolidated balance sheets of LRE as of December 31, 2014 and 2013 and the annual consolidated statements of operations, consolidated statement of changes in unitholders’ equity and consolidated statements of cash flows of LRE for each of the years ended December 31, 2014, 2013 and 2012, and the notes related thereto, are attached hereto as Exhibit 99.1 and incorporated herein by reference.
The report of Independent Registered Public Accounting Firm, issued by PricewaterhouseCoopers LLP, dated March 4, 2015 relating to LRE’s financial statements described above, is attached hereto as Exhibit 99.2 and incorporated herein by reference.
The unaudited consolidated condensed balance sheets of LRE as of June 30, 2015 and December 31, 2014, the unaudited consolidated condensed statements of operations for the three and six months ended June 30, 2015 and 2014, the unaudited consolidated condensed statement of changes in unitholders’ equity as of June 30, 2015, the unaudited consolidated condensed statements of cash flows for the six months ended June 30, 2015 and 2014, and the notes related thereto, are attached hereto as Exhibit 99.3 and incorporated by reference herein.
The financial statements of LRE attached hereto as Exhibit 99.1 and Exhibit 99.3 are identical to the
financial statements of LRE incorporated by reference into Vanguard’s Registration Statement on Form S-4 (File No. 333-204696) filed with the SEC on August 31, 2015.
(b) Pro Forma Financial Information.
The pro forma financial information contained in Item 9.01(b) of Vanguard's Current Report on Form 8-K/A, which was previously filed with the SEC on October 9, 2015 (File No. 001-33756; Film No. 151152895), and attached thereto as Exhibit 99.1, is incorporated by reference herein.
(d) Exhibits.
Exhibit Number | Description | |
Exhibit 23.1 | Consent of PricewaterhouseCoopers LLP | |
Exhibit 23.2 | Consent of Miller and Lents, Ltd. | |
Exhibit 23.3 | Consent of Netherland, Sewell & Associates, Inc. | |
Exhibit 23.4 | Consent of Ryder Scott Petroleum Consultants | |
Exhibit 99.1 | The audited consolidated balance sheets of LRR Energy, L.P. as of December 31, 2014 and 2013, and the annual consolidated statements of operations, consolidated statement of changes in unitholders’ equity and consolidated statements of cash flows of LRR Energy, L.P. for each of the years ended December 31, 2014, 2013 and 2012, and the notes related thereto | |
Exhibit 99.2 | Report of Independent Registered Public Accounting Firm, issued by PricewaterhouseCoopers LLP, dated March 4, 2015, relating to those LRR Energy, L.P. financial statements described in Exhibit 99.1 | |
Exhibit 99.3 | The unaudited consolidated condensed balance sheets of LRR Energy, L.P. as of June 30, 2015 and December 31, 2014, the unaudited consolidated condensed statements of operations for the three and six months ended June 30, 2015 and 2014, the unaudited consolidated condensed statement of changes in unitholders’ equity as of June 30, 2015, the unaudited consolidated condensed statements of cash flows for the six months ended June 30, 2015 and 2014, and the notes related thereto | |
SIGNATURES
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 hereunto duly authorized.
VANGUARD NATURAL RESOURCES, LLC | |||
Dated: October 9, 2015 | By: | /s/ Richard A. Robert | |
Name: | Richard A. Robert | ||
Title: | Executive Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) | ||
EXHIBIT INDEX
Exhibit Number | Description | |
Exhibit 23.1 | Consent of PricewaterhouseCoopers LLP | |
Exhibit 23.2 | Consent of Miller and Lents, Ltd. | |
Exhibit 23.3 | Consent of Netherland, Sewell & Associates, Inc. | |
Exhibit 23.4 | Consent of Ryder Scott Petroleum Consultants | |
Exhibit 99.1 | The audited consolidated balance sheets of LRR Energy, L.P. as of December 31, 2014 and 2013, and the annual consolidated statements of operations, consolidated statement of changes in unitholders’ equity and consolidated statements of cash flows of LRR Energy, L.P. for each of the years ended December 31, 2014, 2013 and 2012, and the notes related thereto | |
Exhibit 99.2 | Report of Independent Registered Public Accounting Firm, issued by PricewaterhouseCoopers LLP, dated March 4, 2015, relating to those LRR Energy, L.P. financial statements described in Exhibit 99.1 | |
Exhibit 99.3 | The unaudited consolidated condensed balance sheets of LRR Energy, L.P. as of June 30, 2015 and December 31, 2014, the unaudited consolidated condensed statements of operations for the three and six months ended June 30, 2015 and 2014, the unaudited consolidated condensed statement of changes in unitholders’ equity as of June 30, 2015, the unaudited consolidated condensed statements of cash flows for the six months ended June 30, 2015 and 2014, and the notes related thereto | |
Exhibit 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-202064) and the Registration Statement on Form S-8 (No. 333-190102) of Vanguard Natural Resources, LLC of our report dated March 4, 2015 relating to the consolidated financial statements of LRR Energy, L.P., which appears in this Current Report on Form 8-K/A of Vanguard Natural Resources, LLC.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
October 9, 2015
Exhibit 23.2
CONSENT OF MILLER AND LENTS, LTD.
INDEPENDENT PETROLEUM ENGINEERS
As independent petroleum engineers, we hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-202064) and the Registration Statement on Form S-8 (No. 333-190102) of Vanguard Natural Resources, LLC information from our reserves report of LRR Energy, L.P. dated January 7, 2015 included in or made a part of the LRR Energy, L.P. Annual Report on Form 10-K for the year ended December 31, 2014 filed with the Securities and Exchange Commission on March 4, 2015, and our summary report attached as Exhibit 99.1 to such Annual Report on Form 10-K. We also hereby consent to all references to our firm and information from the report appearing in this Current Report on Form 8-K of Vanguard Natural Resources, LLC.
The analysis, conclusions, and methods contained in the report are based upon information that was in existence at the time the report was rendered and Miller and Lents, Ltd. has not updated and undertakes no duty to update anything contained in the report. While the report may be used as a descriptive resource, investors are advised that Miller and Lents, Ltd. has not verified information provided by others except as specifically noted in the report, and Miller and Lents, Ltd. makes no representation or warranty as to the accuracy of such information. Moreover, the conclusions contained in such report are based on assumptions that Miller and Lents, Ltd. believed were reasonable at the time of their preparation and that are described in such report in reasonable detail. However, there are a wide range of uncertainties and risks that are outside of the control of Miller and Lents, Ltd. which may impact these assumptions, including but not limited to unforeseen market changes, actions of governments or individuals, natural events, economic changes, and changes of laws and regulations or interpretation of laws and regulations.
Very truly yours,
MILLER AND LENTS, LTD.
Texas Registered Engineering Firm No. F-1442
By: /s/ Leslie A. Fallon
Leslie A. Fallon, P.E.
Vice President
Houston, Texas
October 8, 2015
Exhibit 23.3
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
As independent oil and gas consultants, Netherland, Sewell & Associates, Inc. hereby consents to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-202064) and the Registration Statement on Form S-8 (No. 333-190102) of Vanguard Natural Resources, LLC of all references to our firm and information from our reserves report of LRR Energy, L.P. dated February 26, 2015, included in or made a part of the LRR Energy, L.P. Annual Report on Form 10-K for the year ended December 31, 2014, filed with the Securities and Exchange Commission on March 4, 2015, and our summary report attached as Exhibit 99.2 to such Annual Report on Form 10-K. We also hereby consent to all references to our firm and information from the report appearing in this Current Report on Form 8-K of Vanguard Natural Resources, LLC.
NETHERLAND, SEWELL & ASSOCIATES, INC.
By: /s/ Danny D. Simmons
Name: Danny D. Simmons, P.E.
Title: President and Chief Operating Officer
Houston, Texas
October 8, 2015
Exhibit 23.4
TBPE REGISTERED ENGINEERING FIRM F-1580 FAX (713) 651-0849
1100 LOUISIANA SUITE 4600 HOUSTON, TEXAS 77002-5294 TELEPHONE (713) 651-9191
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
As independent oil and gas consultants, Ryder Scott Company, L.P. hereby consents to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-202064) and the Registration Statement on Form S-8 (No. 333-190102) of Vanguard Natural Resources, LLC of all references to our firm and information from our reserves report of LRR Energy, L.P. dated January 8, 2015, included in or made a part of the LRR Energy, L.P. Annual Report on Form 10-K for the year ended December 31, 2014 filed with the Securities and Exchange Commission on March 4, 2015, and our summary report attached as Exhibit 99.3 to such Annual Report on Form 10-K. We also hereby consent to all references to our firm and information from the report appearing in this Current Report on Form 8-K of Vanguard Natural Resources, LLC.
The analysis, conclusions, and methods contained in the report are based upon information provided at the time the report was prepared, and Ryder Scott Company, L.P. has not updated and undertakes no duty to update any results contained in the report. While the report may be used as a descriptive resource, investors are advised that we have not verified information provided by others except as specifically noted in the report, and we make no representation or warranty regarding the accuracy of such information. Moreover, the conclusions contained in such report are based on assumptions that we believed were reasonable at the time of their preparation and that are described in such report in reasonable detail. However, there is a wide range of uncertainties and risks that are outside of our control that may impact these assumptions, including but not limited to, unforeseen market changes, economic changes, natural events, actions of governments or individuals, and changes in or the interpretation of laws and regulations.
/s/ Ryder Scott Company, L.P. RYDER SCOTT COMPANY, L.P. TBPE Firm Registration No. F-1580 | ||
Houston, Texas | ||
October 8, 2015 | ||
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 |
Exhibit 99.1
LRR Energy, L.P. | ||||||||||
Consolidated Balance Sheets | ||||||||||
(in thousands, except unit amounts) | ||||||||||
December 31, 2014 | December 31, 2013 | |||||||||
ASSETS | ||||||||||
Current assets: | ||||||||||
Cash and cash equivalents | $ | 3,576 | $ | 4,417 | ||||||
Accounts receivable | 11,124 | 9,867 | ||||||||
Commodity derivative instruments | 45,924 | 9,726 | ||||||||
Due from affiliates | 5,697 | - | ||||||||
Prepaid expenses | 1,840 | 1,603 | ||||||||
Total current assets | 68,161 | 25,613 | ||||||||
Property and equipment (successful efforts method) | 956,326 | 876,674 | ||||||||
Accumulated depletion, depreciation and impairment | (506,368 | ) | (431,837 | ) | ||||||
Total property and equipment, net | 449,958 | 444,837 | ||||||||
Commodity derivative instruments | 38,540 | 16,746 | ||||||||
Deferred financing costs, net of accumulated amortization and other assets | 2,295 | 1,154 | ||||||||
TOTAL ASSETS | $ | 558,954 | $ | 488,350 | ||||||
LIABILITIES AND UNITHOLDERS’ EQUITY | ||||||||||
Current liabilities: | ||||||||||
Accrued liabilities | $ | 5,506 | $ | 2,300 | ||||||
Accrued capital cost | 9,176 | 2,574 | ||||||||
Due to affiliates | — | 255 | ||||||||
Commodity derivative instruments | 556 | 2,217 | ||||||||
Interest rate derivative instruments | 2,327 | 648 | ||||||||
Asset retirement obligations | 1,065 | 488 | ||||||||
Total current liabilities | 18,630 | 8,482 | ||||||||
Long-term liabilities: | ||||||||||
Commodity derivative instruments | 232 | 174 | ||||||||
Interest rate derivative instruments | 817 | 1,554 | ||||||||
Term loan | 50,000 | 50,000 | ||||||||
Revolving credit facility | 230,000 | 200,000 | ||||||||
Asset retirement obligations | 40,539 | 35,838 | ||||||||
Deferred tax liabilities | 99 | 44 | ||||||||
Total long-term liabilities | 321,687 | 287,610 | ||||||||
Total liabilities | 340,317 | 296,092 | ||||||||
Contractual obligations and commitments (Note 13) | ||||||||||
See accompanying notes to the consolidated financial statements.
1
LRR Energy, L.P. | ||||||||
Consolidated Balance Sheets | ||||||||
(in thousands, except unit amounts) | ||||||||
(continued) | ||||||||
December 31, 2014 | December 31, 2013 | |||||||
Unitholders’ equity: | ||||||||
General partner (22,400 units issued and outstanding as of December 31, 2014 and 2013) | $ | 310 | $ | 303 | ||||
Public common unitholders (19,492,291 units issued and outstanding as of December 31, 2014 and 17,710,334 units issued and outstanding as of December 31, 2013) | 208,273 | 181,290 | ||||||
Affiliated common unitholders (4,089,600 units issued and outstanding as of December 31, 2014 and 1,849,600 units issued and outstanding as of December 31, 2013) | 4,643 | 2,093 | ||||||
Subordinated unitholders (4,480,000 units issued and outstanding as of December 31, 2014 and 6,720,000 units issued and outstanding as of December 31, 2013) | 5,411 | 8,572 | ||||||
Total unitholders’ equity | 218,637 | 192,258 | ||||||
TOTAL LIABILITIES AND UNITHOLDERS’ EQUITY | $ | 558,954 | $ | 488,350 | ||||
See accompanying notes to the consolidated financial statements.
2
LRR Energy, L.P. | ||||||||||||
Consolidated Statements of Operations | ||||||||||||
(in thousands, except per unit amounts) | ||||||||||||
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Revenues: | ||||||||||||
Oil sales | $ | 76,662 | $ | 77,181 | $ | 72,916 | ||||||
Natural gas sales | 28,521 | 26,800 | 23,502 | |||||||||
Natural gas liquids sales | 11,362 | 10,147 | 11,627 | |||||||||
Gain (loss) on commodity derivative instruments, net | 71,235 | 781 | 12,748 | |||||||||
Other income | 125 | 186 | 45 | |||||||||
Total revenues | 187,905 | 115,095 | 120,838 | |||||||||
Operating expenses: | ||||||||||||
Lease operating expense | 25,821 | 25,397 | 29,069 | |||||||||
Production and ad valorem taxes | 8,738 | 8,614 | 7,790 | |||||||||
Depletion and depreciation | 36,729 | 43,420 | 46,928 | |||||||||
Impairment of oil and natural gas properties | 37,758 | 63,663 | 3,544 | |||||||||
Accretion expense | 2,071 | 1,924 | 1,575 | |||||||||
Loss (gain) on settlement of asset retirement obligations | 151 | 358 | (31 | ) | ||||||||
General and administrative expense | 11,447 | 11,965 | 13,758 | |||||||||
Total operating expenses | 122,715 | 155,341 | 102,633 | |||||||||
Operating income (loss) | 65,190 | (40,246 | ) | 18,205 | ||||||||
Other income (expense), net | ||||||||||||
Interest expense | (10,472 | ) | (9,235 | ) | (6,596 | ) | ||||||
Gain (loss) on interest rate derivative instruments, net | (1,790 | ) | 1,256 | (4,650 | ) | |||||||
Other income (expense), net | (12,262 | ) | (7,979 | ) | (11,246 | ) | ||||||
Income (loss) before taxes | 52,928 | (48,225 | ) | 6,959 | ||||||||
Income tax expense | (186 | ) | (56 | ) | (172 | ) | ||||||
Net income (loss) | $ | 52,742 | $ | (48,281 | ) | $ | 6,787 | |||||
Net (income) loss attributable to common control operations | — | (448 | ) | (6,790 | ) | |||||||
Net income (loss) available to unitholders | $ | 52,742 | $ | (48,729 | ) | $ | (3 | ) | ||||
Computation of net income (loss) per limited partner unit: | ||||||||||||
General partners’ interest in net income (loss) | $ | 53 | $ | (49 | ) | $ | — | |||||
Limited partners’ interest in net income (loss) | $ | 52,689 | $ | (48,680 | ) | $ | (3 | ) | ||||
Net income (loss) per limited partner unit (basic and diluted) | $ | 1.94 | $ | (1.92 | ) | $ | — | |||||
Weighted average number of limited partner units outstanding (basic and diluted) | 27,092 | 25,372 | 22,425 | |||||||||
See accompanying notes to the consolidated financial statements.
3
LRR Energy, L.P. | ||||||||||||||||||||||||
Consolidated Statement of Changes in Unitholders’ Equity | ||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Limited Partners | ||||||||||||||||||||||||
Predecessors’ | General | Public | Affiliated | |||||||||||||||||||||
Capital | Partner | Common | Common | Subordinated | Total | |||||||||||||||||||
Balance, December 31, 2011 | $ | 118,647 | $ | 438 | $ | 189,537 | $ | 35,007 | $ | 46,521 | $ | 390,150 | ||||||||||||
Contribution to Lime Rock Resources | (5,174 | ) | (5 | ) | (2,241 | ) | (1,061 | ) | (1,409 | ) | (9,890 | ) | ||||||||||||
Book value of transferred properties contributed by Lime Rock Resources | (59,322 | ) | — | — | — | — | (59,322 | ) | ||||||||||||||||
Amortization of equity awards | — | — | 313 | — | — | 313 | ||||||||||||||||||
Distribution | — | (37 | ) | (17,689 | ) | (8,382 | ) | (11,154 | ) | (37,262 | ) | |||||||||||||
Net income (loss) | 6,790 | - | (1 | ) | (1 | ) | (1 | ) | 6,787 | |||||||||||||||
Balance, December 31, 2012 | $ | 60,941 | $ | 396 | $ | 169,919 | $ | 25,563 | $ | 33,957 | $ | 290,776 | ||||||||||||
Contribution to Lime Rock Resources | (734 | ) | — | (445 | ) | 337 | 91 | (751 | ) | |||||||||||||||
Book value of transferred properties contributed by Lime Rock Resources | (60,655 | ) | — | — | — | — | (60,655 | ) | ||||||||||||||||
Equity offering, net of expenses | — | — | 59,513 | — | — | 59,513 | ||||||||||||||||||
Equity offering by limited partners | — | — | 15,281 | (15,281 | ) | — | — | |||||||||||||||||
Amortization of equity awards | — | — | 549 | - | — | 549 | ||||||||||||||||||
Distribution | — | (44 | ) | (30,732 | ) | (5,115 | ) | (13,002 | ) | (48,893 | ) | |||||||||||||
Net income (loss) | 448 | (49 | ) | (32,795 | ) | (3,411 | ) | (12,474 | ) | (48,281 | ) | |||||||||||||
Balance, December 31, 2013 | $ | — | $ | 303 | $ | 181,290 | $ | 2,093 | $ | 8,572 | $ | 192,258 | ||||||||||||
Equity offering, net of expenses | — | — | 25,984 | — | — | 25,984 | ||||||||||||||||||
Amortization of equity awards | — | — | 1,081 | — | — | 1,081 | ||||||||||||||||||
Conversion of subordinated units | — | — | — | 623 | (623 | ) | — | |||||||||||||||||
Distribution | — | (44 | ) | (36,458 | ) | (5,891 | ) | (11,035 | ) | (53,428 | ) | |||||||||||||
Net income (loss) | — | 51 | 36,376 | 7,818 | 8,497 | 52,742 | ||||||||||||||||||
Balance, December 31, 2014 | $ | — | $ | 310 | $ | 208,273 | $ | 4,643 | $ | 5,411 | $ | 218,637 | ||||||||||||
See accompanying notes to the consolidated financial statements.
4
LRR Energy, L.P. | ||||||||||||
Consolidated Statements of Cash Flows | ||||||||||||
(in thousands) | ||||||||||||
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
CASH FLOWS FROM OPERATING ACTIVITES | ||||||||||||
Net income (loss) | $ | 52,742 | $ | (48,281 | ) | $ | 6,787 | |||||
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | ||||||||||||
Depletion and depreciation | 36,729 | 43,420 | 46,928 | |||||||||
Impairment of oil and natural gas properties | 37,758 | 63,663 | 3,544 | |||||||||
Accretion expense | 2,071 | 1,924 | 1,575 | |||||||||
Amortization of equity awards | 1,081 | 549 | 313 | |||||||||
Amortization of derivative contracts | 692 | 1,002 | 20 | |||||||||
Amortization of deferred financing costs and other | 485 | 394 | 367 | |||||||||
Loss (gain) on settlement of asset retirement obligations | 151 | 358 | (31 | ) | ||||||||
Purchase of derivative contracts | — | — | (59 | ) | ||||||||
Changes in operating assets and liabilities: | ||||||||||||
Change in receivables | (1,257 | ) | (2,617 | ) | 5,674 | |||||||
Change in prepaid expenses | (532 | ) | (855 | ) | (170 | ) | ||||||
Change in derivative assets and liabilities | (59,344 | ) | 6,897 | 14,787 | ||||||||
Change in trade accounts payable | — | — | (2,707 | ) | ||||||||
Change in amounts due to/from affiliates | (5,952 | ) | (1,722 | ) | 1,441 | |||||||
Change in accrued liabilities | 3,206 | 885 | (1,331 | ) | ||||||||
Change in deferred tax liability | 55 | (76 | ) | 85 | ||||||||
Net cash provided by (used in) operating activities | 67,885 | 65,541 | 77,223 | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||
Acquisition of oil and natural gas properties | (37,616 | ) | — | (10,020 | ) | |||||||
Development of oil and natural gas properties | (32,389 | ) | (35,805 | ) | (30,397 | ) | ||||||
Disposition of oil and natural gas properties | 55 | — | — | |||||||||
Expenditures for other property and equipment | — | — | (16 | ) | ||||||||
Net cash provided by (used in) investing activities | (69,950 | ) | (35,805 | ) | (40,433 | ) | ||||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||
Borrowings under revolving credit facility | 68,000 | 60,000 | 77,200 | |||||||||
Principal payments on revolving credit facility | (38,000 | ) | (38,000 | ) | (55,000 | ) | ||||||
Equity offering, net of expenses | 25,984 | 59,513 | — | |||||||||
Distributions | (53,428 | ) | (48,893 | ) | (37,262 | ) | ||||||
Deferred financing costs | (1,332 | ) | — | (562 | ) | |||||||
Distribution to Lime Rock Resources | — | (60,672 | ) | (64,038 | ) | |||||||
Contribution to Lime Rock Resources | — | (734 | ) | (5,174 | ) | |||||||
Borrowings under term loan | — | — | 50,000 | |||||||||
Net cash provided by (used in) financing activities | $ | 1,224 | $ | (28,786 | ) | $ | (34,836 | ) | ||||
5
LRR Energy, L.P. | ||||||||||||
Consolidated Statements of Cash Flows | ||||||||||||
(in thousands) | ||||||||||||
(continued) | ||||||||||||
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | $ | (841 | ) | $ | 950 | $ | 1,954 | |||||
CASH AND CASH EQUIVALENTS, BEGINNING OF THE PERIOD | 4,417 | 3,467 | 1,513 | |||||||||
CASH AND CASH EQUIVALENTS, END OF PERIOD | $ | 3,576 | $ | 4,417 | $ | 3,467 | ||||||
Supplemental disclosure of cash flow information | ||||||||||||
Cash paid for taxes during the period | $ | 146 | $ | 132 | $ | 86 | ||||||
Cash paid for interest during the period | 10,058 | 8,786 | 6,547 | |||||||||
Supplemental disclosure of non-cash items to reconcile investing and financing activities | ||||||||||||
Property and equipment: | ||||||||||||
Accrued capital costs | 6,483 | 1,663 | 940 | |||||||||
Asset retirement obligations | (440 | ) | (476 | ) | (364 | ) | ||||||
See accompanying notes to the consolidated financial statements.
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LRR Energy, L.P.
Notes to Consolidated Financial Statements
1. | Organization and Description of Business |
LRR Energy, L.P. (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership formed in April 2011 by Lime Rock Management LP (“Lime Rock Management”), an affiliate of Lime Rock Resources A, L.P. (“LRR A”), Lime Rock Resources B, L.P. (“LRR B”) and Lime Rock Resources C, L.P. (“LRR C”) to operate, acquire, exploit and develop producing oil and natural gas properties in North America with long-lived, predictable production profiles. As used herein, references to "Fund I" refer collectively to LRR A, LRR B and LRR C; references to “Fund II” refer collectively to Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P.; and references to “Fund III” refer collectively to Lime Rock Resources III-A, L.P. and Lime Rock Resources III-C, L.P. References to “Lime Rock Resources” refer collectively to Fund I, Fund II and Fund III.
Our properties are located in the Permian Basin region in West Texas and Southeast New Mexico, the Mid-Continent region in Oklahoma and East Texas and the Gulf Coast region in Texas. We conduct our operations through our wholly owned subsidiary, LRE Operating, LLC (“OLLC”).
We own 100% of LRE Finance Corporation (“LRE Finance”). LRE Finance was organized for the purpose of co-issuing our debt securities and has no material assets or liabilities other than as co-issuer of our debt securities, if and when issued. Its activities will be limited to co-issuing our debt securities and engaging in activities related thereto.
Prior to our initial public offering (“IPO”) on November 16, 2011, Fund I owned 100% of the properties conveyed to us in connection with our IPO. At the closing of our IPO, we entered into a purchase, sale, contribution, conveyance and assumption agreement with Fund I pursuant to which Fund I sold and contributed to us specified oil and natural gas properties and related net profits interests and operations and certain commodity derivative contracts (the “Partnership Properties”). Fund I received total consideration for the Partnership Properties of 5,049,600 common units, 6,720,000 subordinated units, $311.2 million in cash and the assumption of $27.3 million of LRR A’s indebtedness.
2. | Summary of Significant Accounting Policies |
The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2014 and 2013. These financial statements include the consolidated results of our operations, cash flows and changes in unitholders’ equity for the years ended December 31, 2014, 2013, and 2012.
These consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and all intercompany transactions and account balances have been eliminated. We operate oil and natural gas properties as one business segment: the exploration, development and production of oil and natural gas. Our management evaluates performance based on one business segment as there are not different economic environments within the operation of the oil and natural gas properties.
Acquisitions of assets from Lime Rock Resources during 2013 and 2012 were deemed transactions between entities under common control and the net assets acquired during those years were recorded using carryover book value of Lime Rock Resources. Our historical financial statements include the results attributable to previous acquisitions from Lime Rock Resources as if we owned the properties for all periods presented in our consolidated financial statements.
The revised historical consolidated financial statements for periods prior to our acquisitions have been prepared from Lime Rock Resources’ historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if we had owned the assets during the periods reported. See our accounting policy below under “Transactions between Entities under Common Control.”
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Net income attributable to common control operations for periods prior to our acquisition of such assets was not available for distribution to our unitholders. Therefore, this income was not allocated to the limited partners for the purpose of calculating net income per common unit.
Third-Party Acquisitions
Accounting for third-party acquisitions requires that the various assets acquired and liabilities assumed in a business combination be recorded at their respective fair values. The most significant estimates to us typically relate to the value assigned to future recoverable oil and gas reserves and unproved properties. Deferred taxes are recorded for any differences between the fair value and tax basis of assets acquired and liabilities assumed. To the extent the purchase price plus the liabilities assumed (including deferred income taxes recorded in connection with the transaction) exceeds the fair value of the net assets acquired, we are required to record the excess as goodwill. As the fair value of assets acquired and liabilities assumed is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain.
Transactions between Entities under Common Control
Master limited partnerships (“MLPs”) enter into transactions whereby the MLP receives a transfer of certain assets from its sponsor for consideration of either cash, units, assumption of debt, or any combination thereof. We account for the net assets received using the carryover book value of Lime Rock Resources as these were considered to be transactions between entities under common control. Our historical financial statements have been revised to include the results attributable to the assets contributed from Lime Rock Resources as if we owned such assets for all periods presented by us. The following financial statement items were impacted:
Oil and Natural Gas Properties Received. The book value and related activity of oil and natural gas properties received from Lime Rock Resources is determined using the carrying value of the specific assets contributed.
Commodity Derivative Instruments. Reflects the fair value of the commodity derivative contracts associated with the properties acquired from Lime Rock Resources.
Asset Retirement Obligations Received. The book value and related activity of asset retirement obligations received from Lime Rock Resources was determined by using the carrying value of the specific liabilities attributable to the assets contributed.
Oil, Natural Gas and NGL Revenues and Expenses. Oil, natural gas and NGL revenues and expenses related to the properties acquired are based on the actual results of the acquired properties. Historical lease operating statements by individual asset were used as the basis for revenues and direct operating expenses.
Gain on Commodity Derivative Contracts, Net. Reflects the net gain on commodity derivative contracts associated with the properties acquired assuming the contracts were in place as of the date acquired by Lime Rock Resources.
General and Administrative Expense. The general and administrative expense attributable to the properties acquired was determined by the ratio of production for the properties acquired to the total respective Lime Rock Resources’ production for the period presented.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
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Depreciation, depletion and amortization of oil and natural gas properties, the impairment of oil and natural gas properties and the valuation of third-party acquisitions are determined using estimates of oil and natural gas reserves. There are numerous uncertainties in estimating the quantity of reserves and in projecting the future rates of production and timing of development expenditures, including future costs to dismantle, dispose, and restore our properties. Oil and natural gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way.
Cash and Cash Equivalents
We consider all highly liquid instruments purchased with a maturity when acquired of three months or less to be cash equivalents. We continually monitor our positions with, and the credit quality of, the financial institutions with which we invest.
Accounts Receivable
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We use the specific identification method of providing allowances for doubtful accounts. At December 31, 2014 and 2013, we did not have an allowance for doubtful accounts.
Revenue Recognition
Revenues from oil and gas sales are recognized based on the sales method with revenue recognized on actual volumes sold to purchasers. Under this method of revenue recognition, a gas imbalance is created if the quantity sold is greater than or less than our entitlement share in any particular period. To the extent there are sufficient quantities of natural gas remaining to make up the gas imbalance, oil and natural gas reserves are adjusted to reflect the overproduced or underproduced position. In situations where there are insufficient reserves available to make up an overproduced imbalance, a liability is established. As of December 31, 2014 and 2013, we had no significant production imbalances.
Concentrations of Credit and Significant Customers
Financial instruments which potentially subject us to credit risk consist principally of cash balances, accounts receivable and derivative financial instruments. We maintain cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. We have not experienced any significant losses from such investments. We attempt to limit the amount of credit exposure to any one financial institution or company through procedures that include credit approvals, credit limits and terms, letters of credit, prepayments and rights of offset. Our customer base consists primarily of major integrated and international oil and natural gas companies, as well as smaller processors and gatherers. We believe the credit quality of our customer base is high and have not experienced significant write‑downs in our accounts receivable balances.
For the year ended December 31, 2014, purchases by Sunoco Partners Marketing & Terminals L.P. and Phillips 66 Company accounted for 22% and 20% respectively, of our total sales revenues.
For the year ended December 31, 2013, purchases by Phillips 66 Company, Holly Frontier Refining & Marketing LLC, Sunoco Partners Marketing & Terminals L.P. and Seminole Gas Company LLC accounted for 18%, 15%, 14% and 10% respectively, of our total sales revenues.
For the year ended December 31, 2012, purchases by Sunoco Partners Marketing & Terminals L.P., Phillips 66 Company, and Shell Trading (US) Company accounted for 17%, 16% and 10%, respectively, of our total sales revenues.
If we were to lose any one of our customers, the loss could temporarily delay production and sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified. However, if one or more of our larger
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customers ceased purchasing oil or natural gas altogether, the loss of such customer could have a detrimental effect on production volumes in general and on the ability to find substitute customers to purchase production volumes.
Oil and Natural Gas Properties
Proved Properties. We account for our oil and natural gas exploration, development and production activities in accordance with the successful efforts method. Under this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively.
We evaluate the potential impairment of our proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows are less than net book value.
For the years ended December 31, 2014, 2013, and 2012, we recorded non-cash impairment charges on proved oil and natural gas properties of $37.8 million, $63.7 million, and $3.1 million, respectively. These charges are included in “impairment of oil and natural gas properties” on the consolidated statements of operations. Refer to Note 5 for additional information.
Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of proved properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.
Unproved Properties. Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. As of December 31, 2014 and 2013, $1.2 million and $1.3 million, respectively, of oil and natural gas property costs were related to unproved leasehold acquisitions costs and not subject to depletion. We did not reclassify any material amounts from unproved to proved properties during the years ended December 31, 2014 and 2013.
We assess unproved properties for impairment on a quarterly basis. For the year ended December 31, 2012, we recorded an impairment charge for unproved properties in the amount of $0.4 million. No impairments were recorded for unproved properties during 2014 or 2013. The impairment was based on our experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties, and the relative proportion of such properties on which proved reserves have been found in the past. The fair values of unproved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of unproved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market‑based weighted average cost of capital rate. The market‑based weighted average cost of capital rate is subject to additional project‑specific risk factors.
Other Property and Equipment
Other property and equipment is stated at historical cost less accumulated depreciation expense and is comprised primarily of software, computers and office equipment. Depreciation is calculated using the straight-line method based on useful lives of the assets ranging from three to five years. Other property and equipment is evaluated for impairment as necessary to determine if current circumstances and market conditions indicate that the
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carrying amounts of assets may not be recoverable. We did not recognize any impairment loss related to other property and equipment during 2014, 2013, and 2012.
Asset Retirement Obligations
We have obligations under our lease agreements and federal regulations to remove equipment and restore land at the end of oil and natural gas production operations. These asset retirement obligations (“ARO”) are primarily associated with plugging and abandoning wells. Determining the future restoration and removal requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. We record the fair value of a liability for an ARO in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. We typically incur this liability upon acquiring or drilling a well. Over time, the liability is accreted each period toward its future value, and the capitalized cost is depleted as a component of development costs. Upon settlement of the liability, a gain or loss is recognized to the extent the actual costs differ from the recorded liability.
Inherent to the fair value calculation are numerous estimates, assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the abandonment liability, management will make corresponding adjustments to both the ARO and the related oil and natural gas property asset balance. Increases in the discounted retirement obligation liability and related oil and natural gas assets resulting from the passage of time will be reflected as additional accretion and depreciation expense in the consolidated statements of operations.
Derivatives
Our activities primarily consist of acquiring, owning, enhancing and producing oil and natural gas properties. The future results of our operations, cash flows and financial condition may be affected by changes in the market price of oil and natural gas. The availability of a ready market for oil and natural gas products in the future will depend on numerous factors beyond our control, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil, natural gas and liquid products, the regulatory environment, the economic environment and, other regional and political events, none of which can be predicted with certainty.
In order for us to manage our exposure to oil and natural gas price volatility, we enter into commodity derivative instruments such as futures contracts, swaps, or options. We are also exposed to changes in interest rates, primarily as a result of variable rate borrowings under the credit facility. In an effort to reduce this exposure, we have, from time to time, entered into derivative contracts (interest rate swaps) to mitigate the risk of interest rate fluctuations. For commodity derivatives, the net gain or loss on commodity derivative contracts is recorded as a separate component of revenues. For interest rate derivatives, the net gain or loss on interest rate derivatives is recorded as a component of other income (expense) in the consolidated statements of operations.
We elected not to designate any positions as cash flow hedges for accounting purposes and, accordingly, recorded the net change in the mark-to-market valuation of these derivative contracts in the consolidated statements of operations. We record our derivative activities on a mark-to-market or fair value basis. Fair values are based on pricing models that consider various assumptions, including quoted forward prices for commodities, the time value of money and volatility, and are comparable to values obtained from counterparties. We present the fair value of derivative financial instruments on a net basis in the consolidated balance sheets.
Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. All of our derivatives at December 31, 2014 are with parties that are also lenders under our credit facility. The credit worthiness of the counterparties is subject to continual review. We monitor the nonperformance
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risk of ourselves and of each of our counterparties and assesses the possibility of whether each counterparty to the derivative contract would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. We also have master netting arrangements in place with each counterparty to reduce credit exposure.
Equity-Based Compensation
We have granted restricted unit awards which we account for at fair value. Restricted unit awards, net of estimated forfeitures, are expensed over the requisite service period. As each award vests, an adjustment is made to compensation cost for any difference between the estimated forfeitures and the actual forfeitures related to the vested awards. We record these compensation costs as general and administrative expenses. Refer to Note 12 for additional information.
Income Taxes
We are not taxable for federal income tax purposes and do not directly pay federal income tax. Generally, all of our taxable federal income and losses are reported on the income tax returns of our unitholders or partners, and therefore, no provision for federal income taxes has been recorded in our accompanying consolidated financial statements.
We record our obligations under the Texas gross margin tax as “Income tax expense” in the consolidated statements of operations. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period of rate change.
Deferred Financing Costs
Costs incurred in connection with the execution or modification of our debt agreements are capitalized and amortized using the effective interest method over the terms of our respective debt agreements.
Recent Accounting Pronouncements
On April 10, 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” ASU 2014-08 amends the definition of a discontinued operation and requires entities to provide additional disclosures about discontinued operations as well as disposal transactions that do not meet the discontinued-operations criteria. ASU 2014-08 is effective for annual reporting periods beginning on or after December 15, 2014 and early adoption is permitted. We do not expect this guidance have a material impact on our consolidated financial position, results of operations or cash flows.
On May 28, 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers.” ASU No. 2014-09 outlined a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The core principle of the revenue model is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2014-09 is effective for annual reporting periods beginning after December 15, 2016 and early adoption is not permitted. We are still evaluating the impact of our adoption of ASU No. 2014-09.
On August 27, 2014, the FASB issued ASU 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.” ASU No. 2014-15 provides guidance on determining when and how reporting entities must disclose going-concern uncertainties in their financial statements. The new standard requires
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management to perform interim and annual assessments of an entity’s financial statements (or within one year after the date on which the financial statements are available to be issued, when applicable). Further, an entity must provide certain disclosures if there is “substantial doubt about the entity’s ability to continue as a going concern.” ASU No. 2014-15 is effective for annual periods ending after December 15, 2016, and interim periods thereafter; early adoption is permitted. We do not expect the adoption of ASU No. 2014-15 to have a material impact on our financial statement disclosures.
3. | Acquisitions |
Third Party Acquisition
On October 1, 2014, we completed an acquisition of oil and natural gas properties in the Stroud field located in Lincoln and Creek Counties, Oklahoma for a purchase price of $38.0 million, subject to customary purchase price adjustments (the “October 2014 Acquisition”) from an unrelated third party. We paid total cash consideration of $38.2 million at closing. The October 2014 Acquisition was effective September 1, 2014. In January 2015, we paid $0.2 million in cash to the seller related to post-closing adjustments to the purchase price. We financed the acquisition with borrowings under our revolving credit facility (Note 7).
The October 2014 Acquisition was accounted for under the acquisition method of accounting, whereby the purchase price was allocated to the assets acquired and liabilities assumed based on their fair values, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill (or shortfall of purchase price versus net fair value recorded as bargain purchase). Based on the purchase price allocation for October 2014 Acquisition, no goodwill or bargain purchase was recognized. The cash consideration paid for the October 2014 Acquisition and the assets and liabilities recognized are presented in the table below (in thousands):
Property and equipment, net | $ | 38,848 | ||
Asset retirement obligations | $ | (691 | ) | |
Net assets | $ | 38,157 | ||
The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) reserves, including risk adjustments for probable and possible reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; (v) future cash flows; and (vi) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by our management at the time of the valuation and are subject to change.
The results of operations attributable to the October 2014 Acquisition were included in our consolidated statement of operations beginning October 1, 2014. Revenues of $1.7 million and net income of $0.6 million were generated in the year ended December 31, 2014, and are included in the consolidated statement of operations for the year ended December 31, 2014.
The following unaudited pro forma information shows the pro forma effects of the October 2014 Acquisition. The unaudited pro forma information assumes the transaction occurred on January 1, 2013. The pro forma results of operations have been prepared by adjusting our historical results to include the historical results of the acquired assets based on information provided by the seller, our knowledge of the acquired properties and the impact of our purchase price allocation. We believe the assumptions used provide a reasonable basis for reflecting the pro forma significant effects directly attributable to the acquisition. The pro forma results of operations do not include any cost savings or other synergies that may result from the October 2014 Acquisition or any estimated costs that have been or will be incurred to integrate the assets. The following unaudited pro forma information does not purport to
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represent what our results of operations would have been if such acquisition had occurred on January 2013 (in thousands).
Year Ended December 31, | |||||||
2014 | 2013 | ||||||
Total revenues | $ | 194,946 | $ | 124,810 | |||
Net income (loss) available to unitholders | 56,629 | (43,438 | ) | ||||
Basic and diluted net income (loss) per unit | 2.09 | (1.71 | ) | ||||
Acquisition between Entities under Common Control
On June 1, 2012, we completed an acquisition from Fund I of certain oil and natural gas properties located in the Permian Basin region of New Mexico and onshore Gulf Coast region of Texas for $65.1 million in cash (the “June 2012 Acquisition”). The June 2012 Acquisition was effective March 1, 2012. In September 2012, we received $1.1 million in cash from Fund I related to post-closing adjustments to the purchase price. We funded the acquisition with borrowings under our revolving credit facility (Note 7).
The following table presents the net assets conveyed by Fund I to us in the June 2012 Acquisition (in thousands):
Property and equipment, net | $ | 60,365 | ||
Asset retirement obligations and other liabilities | (1,043 | ) | ||
Net assets | $ | 59,322 | ||
On January 3, 2013, we completed an acquisition from Fund I of certain oil and natural gas properties located in the Mid-Continent region in Oklahoma for a purchase price of $21.0 million, subject to customary purchase price adjustments (the “January 2013 Acquisition”). In addition, as part of the January 2013 Acquisition, we acquired in the money commodity hedge contracts valued at approximately $1.7 million as of the closing of the January 2013 Acquisition. The January 2013 Acquisition was effective October 1, 2012. In June 2013, we paid $0.4 million in cash to Fund I related to post-closing adjustments to the purchase price. We funded the January 2013 Acquisition with borrowings under our revolving credit facility (Note 7).
The following table presents the net assets conveyed by Fund I to us in the January 2013 Acquisition (in thousands):
Property and equipment, net | $ | 23,998 | ||
Oil and natural gas commodity hedge contracts | 1,742 | |||
Asset retirement obligations and other liabilities | (1,067 | ) | ||
Net assets | $ | 24,673 | ||
On April 1, 2013, we completed an acquisition of certain oil and natural gas properties located in the Mid-Continent region in Oklahoma and crude oil hedges from Fund II for a purchase price of $38.2 million (the “April 2013 Acquisition”). As part of the April 2013 Acquisition, we acquired in the money crude oil hedges valued at approximately $0.4 million as of the closing of the April 2013 Acquisition. The April 2013 Acquisition was effective April 1, 2013. We funded the April 2013 Acquisition with proceeds from our equity offering described in Note 10.
The following table presents the net assets conveyed by Fund II to us in the April 2013 Acquisition (in thousands):
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Property and equipment, net | $ | 36,586 | ||
Oil and natural gas commodity hedge contracts | 386 | |||
Asset retirement obligations and other liabilities | (990 | ) | ||
Net assets | $ | 35,982 | ||
The net assets of the June 2012 Acquisition, January 2013 Acquisition and April 2013 Acquisition were recorded using carryover book value of Fund I and Fund II as the acquisitions were deemed transactions between entities under common control. Our historical financial statements include the results attributable to previous acquisitions from Fund I and Fund II as if we owned the properties for all periods presented in our consolidated financial statements.
4. | Fair Value Measurements |
Our financial instruments, including cash and cash equivalents and accounts receivable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments. All such financial instruments are considered Level 1 instruments. The carrying value of our senior secured revolving credit facility and term loan, including the current portion, approximates fair value, as interest rates are variable based on prevailing market rates and therefore considered Level 1 instruments. Our financial and non-financial assets and liabilities that are measured on a recurring basis are measured and reported at fair value.
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. GAAP establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of fair value hierarchy are as follows:
Level 1—Defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities.
Level 2—Defined as inputs other than quoted prices in active markets that are either directly or indirectly observable for the asset or liability.
Level 3—Defined as unobservable inputs for use when little or no market data exists, requiring an entity to develop its own assumptions for the asset or liability.
We utilize the most observable inputs available for the valuation technique used. The financial assets and liabilities are classified in their entirety based on the lowest level of input that is of significance to the fair value measurement. The following table describes, by level within the hierarchy, the fair value of our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2014 and 2013(in thousands).
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Level 1 | Level 2 | Level 3 | Total | |||||||||||||
December 31, 2014 | ||||||||||||||||
Assets: | ||||||||||||||||
Commodity derivative instruments | $ | — | $ | 84,464 | $ | — | $ | 84,464 | ||||||||
Liabilities: | ||||||||||||||||
Commodity derivative instruments | — | 788 | — | 788 | ||||||||||||
Interest rate derivative instruments | — | 3,144 | — | 3,144 | ||||||||||||
December 31, 2013 | ||||||||||||||||
Assets: | ||||||||||||||||
Commodity derivative instruments | $ | — | $ | 26,472 | $ | — | $ | 26,472 | ||||||||
Liabilities: | ||||||||||||||||
Commodity derivative instruments | — | 2,391 | — | 2,391 | ||||||||||||
Interest rate derivative instruments | — | 2,202 | — | 2,202 | ||||||||||||
All fair values reflected in the table above and on the consolidated balance sheets have been adjusted for non-performance risk. The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.
Commodity Derivative Instruments—The fair value of the commodity derivative instruments is estimated using a combined income and market valuation methodology based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes.
Interest Rate Derivative Instruments—The fair value of the interest rate derivative instruments is estimated using a combined income and market valuation methodology based upon forward interest rates and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes.
5. | Property and Equipment |
Property and equipment is stated at cost less accumulated depletion, depreciation and impairment and consisted of the following (in thousands):
December 31, 2014 | December 31, 2013 | |||||||
Oil and natural gas properties (successful efforts method) | $ | 954,819 | $ | 875,126 | ||||
Unproved properties | 1,235 | 1,258 | ||||||
Other property and equipment | 272 | 290 | ||||||
956,326 | 876,674 | |||||||
Accumulated depletion, depreciation and impairment | (506,368 | ) | (431,837 | ) | ||||
Total property and equipment, net | $ | 449,958 | $ | 444,837 | ||||
We recorded $36.7 million, $43.4 million, $46.9 million of depletion and depreciation expense for the years ended December 31, 2014, 2013, and 2012, respectively.
We perform an impairment analysis of our oil and natural gas properties on a quarterly basis due to the volatility in commodity prices. For the year ended December 31, 2014, we recorded a total non-cash impairment charge of $37.8 million to impair the value of our proved oil and natural gas properties in the Permian Basin and the Mid-Continent regions. This impairment charge reduced the regions’ carrying values to an estimated fair value of $25.7 million as of December 31, 2014. For the year ended December 31, 2013, we recorded a total non-cash impairment charge of $63.7 million to impair the value of our proved oil and natural gas properties in the Permian Basin and the Gulf Coast regions. This impairment charge reduced the regions’ carrying values to an estimated fair value of $76.2 million as of December 31, 2013. For the year ended December 31, 2012, we recorded a total non-cash impairment
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charge of $3.5 million to impair the value of our unproved properties and proved oil and natural gas properties in the Mid-Continent region. These non-cash charges are included in “Impairment of oil and natural gas properties” line item in our consolidated statements of operations.
These impairments of proved and unproved oil and natural gas properties were recorded because the net capitalized costs of the properties exceeded the fair value of the properties as measured by estimated cash flows reported in an internal reserve report. Further, our unproved properties were impaired based on the drilling locations for the probable and possible reserves becoming uneconomic at the lower future expected natural gas prices and our future expected drilling schedules. These reports are based upon future oil and natural gas prices, which are based on observable inputs, adjusted for basis differentials. These are classified as Level 3 fair value measurements. The fair values of our properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of the properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market‑based weighted average cost of capital rate. The underlying commodity prices embedded in the our estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that management believes will impact realizable prices. Furthermore, significant assumptions in valuing the proved reserves included the reserve quantities, anticipated drilling and operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated drilling schedules, anticipated production declines, and an appropriate discount rate commensurate with the risk of the underlying cash flow estimates. Cash flow estimates for the impairment testing excluded derivative instruments used to mitigate the risk of lower future natural gas prices. Significant assumptions in valuing the unproved reserves included the evaluation of the probable and possible reserves, future expected natural gas prices and basis differentials, and anticipated drilling schedules.
These asset impairments have no impact on cash flows, liquidity positions, or debt covenants. If future oil or natural gas prices decline, the estimated undiscounted future cash flows for the proved oil and natural gas properties may not exceed the net capitalized costs for our properties and a non-cash impairment charge may be required to be recognized in future periods.
6. | Asset Retirement Obligations |
The following is a summary of our asset retirement obligations as of and for the years indicated (in thousands):
December 31, 2014 | December 31, 2013 | |||||||
Beginning of period | $ | 36,326 | $ | 34,091 | ||||
Acquisitions | 691 | — | ||||||
Dispositions | (84 | ) | — | |||||
Revisions to previous estimates | 2,290 | (1) | 197 | |||||
Liabilities incurred | 440 | 476 | ||||||
Liabilities settled | (130 | ) | (362 | ) | ||||
Accretion expense | 2,071 | 1,924 | ||||||
End of period | 41,604 | 36,326 | ||||||
Current portion of asset retirement obligations | (1,065 | ) | (488 | ) | ||||
Asset retirement obligation-non-current | $ | 40,539 | $ | 35,838 | ||||
(1) Primarily due to variations in the reserve lives.
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7. | Long-Term Debt |
Credit Agreement
We, as guarantor, and our wholly owned subsidiary, OLLC, as borrower, are parties to a five-year, $750 million senior secured revolving credit facility, as amended, (the “Credit Agreement”) that matures on October 1, 2019. The Intercreditor Agreement (as described below) limits the amount of indebtedness outstanding at any time under the Credit Agreement (including undrawn amounts under letters of credit) to an amount not to exceed $500 million in the aggregate. The Credit Agreement is reserve-based and we are permitted to borrow under our credit facility an amount up to the borrowing base, which was $260 million as of December 31, 2014. Our borrowing base, which is primarily based on the estimated value of our oil, NGL and natural gas properties and our commodity derivative contracts, is subject to redetermination semi-annually by our lenders at their sole discretion. Unanimous approval by the lenders is required for any increase to the borrowing base.
Borrowings under the Credit Agreement are secured by liens on at least 80% of the PV-10 value of our and our subsidiaries’ oil and natural gas properties and all of our equity interests in OLLC and any future guarantor subsidiaries and all of our and our subsidiaries’ other assets including personal property. Borrowings under the Credit Agreement bear interest, at OLLC’s option, at either (i) the greater of the prime rate as determined by the Administrative Agent, the federal funds effective rate plus 0.50%, and the 30-day adjusted LIBOR plus 1.0%, all of which is subject to a margin that varies from 0.50% to 1.50% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letter of credit exposure to the borrowing base then in effect), or (ii) the applicable reserve-adjusted LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage.
The Credit Agreement requires us to maintain a leverage ratio of Total Debt to EBITDAX (as each term is defined in the Credit Agreement) of not more than 4.0 to 1.0x, and a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0x. Our Credit Agreement defines EBITDAX as consolidated net income plus the sum of interest, income taxes, depreciation, depletion, amortization, accretion, impairment charges, exploration expenses and other noncash charges, minus all noncash income.
Additionally, the Credit Agreement contains various covenants and restrictive provisions which limit our, OLLC’s and any of our subsidiaries’ ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of our production; and prepay certain indebtedness. As of December 31, 2014, we were in compliance with all covenants contained in the Credit Agreement.
Term Loan Agreement
We, as parent guarantor, and our wholly owned subsidiary, OLLC, as borrower, entered into a Second Lien Credit Agreement, as amended, (the “Term Loan Agreement”). The Term Loan Agreement provides for a $50 million senior secured second lien term loan to OLLC. OLLC borrowed $50 million under the Term Loan Agreement and used the borrowings to repay outstanding borrowings under the Credit Agreement.
The obligations under the Term Loan Agreement are guaranteed on a joint and several basis by us. The obligations are secured by a second priority mortgage and security interest in all assets of OLLC and us that secure OLLC’s and our existing indebtedness under the Credit Agreement.
Borrowings under the Term Loan Agreement mature on April 1, 2020, and, subject to the terms of the Intercreditor Agreement (as described below), OLLC has the ability at any time to prepay the Term Loan Agreement without premium or penalty. Borrowings under the Term Loan Agreement bear interest, at OLLC’s option, at either
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• | the greatest of (i) the prime rate as defined in the Term Loan Agreement, (ii) the federal funds effective rate plus 0.50% and (iii) the 30-day adjusted LIBOR plus 1.0%, all of which is subject to an applicable margin of 7.50%; or |
• | the applicable reserve-adjusted LIBOR plus an applicable margin of 8.50% |
The Term Loan Agreement contains various covenants and restrictive provisions which limit the ability of OLLC, us or any of our subsidiaries to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of production; prepay certain indebtedness; and amend the Credit Agreement or grant any liens to secure any indebtedness under the Credit Agreement. The Term Loan Agreement allows us to exclude certain sales of common units representing limited partner interests in us made on and after October 1, 2014 and on and before March 31, 2015 from compliance with the mandatory prepayment provision under the Term Loan Agreement that requires us to use 50% of the net cash proceeds from any equity offering to prepay borrowings outstanding under the Term Loan Agreement.
The Term Loan Agreement also contains covenants that, among other things, require OLLC and us to maintain specified ratios including leverage ratio of Total Debt to EBITDAX of not more than 4.25 to 1.00x; a current ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0x; and an asset coverage ratio of Total Proved PV-10 to Total Debt of not less than 1.50 to 1.00x. As of December 31, 2014, we were in compliance with the leverage and current ratios contained in our Term Loan Agreement. We are required to test the asset coverage ratio at specified intervals as described in the Term Loan Agreement.
The obligations under the Term Loan Agreement and the Credit Agreement are governed by an Intercreditor Agreement with OLLC as borrower and the Partnership as parent guarantor, which (i) provides that any liens on the assets and properties of OLLC, the Partnership or any of their subsidiaries securing the indebtedness under the Term Loan Agreement are subordinate to liens on the assets and properties of OLLC, the Partnership or any of their subsidiaries securing indebtedness under the Credit Agreement and derivative contracts with lenders and their affiliates and (ii) sets forth the respective rights, obligations and remedies of the lenders under the Credit Agreement with respect to their first-priority liens and the lenders under the Term Loan Agreement with respect to their second-priority liens.
As of December 31, 2014, we had $280.0 million of outstanding debt and accrued interest was $0.2 million. As of December 31, 2013, we had $250.0 million of outstanding debt and accrued interest was $0.2 million. Our outstanding debt increased primarily due to our October 2014 acquisition of oil and natural gas properties.
Interest expense for the years ended December 31, 2014, 2013, and 2012 was $10.5 million, $9.2 million, and $6.6 million, respectively. As of December 31, 2014 and 2013, our weighted average interest rate on our outstanding indebtedness was 3.81% and 3.88%, respectively. Please refer to Note 8 below for a discussion of our interest rate derivative contracts.
8. | Derivatives |
We are exposed to commodity price and interest rate risk and consider it prudent to periodically reduce our exposure to cash flow variability resulting from commodity price changes and interest rate fluctuations. Accordingly, we enter into derivative instruments to manage our exposure to commodity price fluctuations, locational differences between a published index and the NYMEX futures on natural gas or crude oil productions, and interest rate fluctuations.
Under commodity swap agreements, we exchange a stream of payments over time according to specified terms with another counterparty. Specifically for commodity price swap agreements, we agree to pay an adjustable or floating price tied to an agreed upon index for the commodity, either gas or oil, and in return receives a fixed price based on notional quantities. Under basis swap agreements, we agree to pay an adjustable or floating price tied to
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two agreed upon indices for gas and in return receive the differential between a floating index and fixed price based on notional quantities.
The interest rate swap agreements effectively fix our interest rate on amounts borrowed under the credit facility. The purpose of these instruments is to mitigate our existing exposure to unfavorable interest rate changes. Under interest rate swap agreements, we pay a fixed interest rate payment on a notional amount in exchange for receiving a floating amount based on LIBOR on the same notional amount.
At December 31, 2014, we had the following open commodity derivative contracts:
Index | 2015 | 2016 | 2017 | 2018 | |||||||||||||
Natural gas positions | |||||||||||||||||
Price swaps (MMBTUs) | NYMEX-HH | 5,500,236 | 5,433,888 | 5,045,760 | 2,374,800 | ||||||||||||
Weighted average price | $ | 5.72 | $ | 4.29 | $ | 4.61 | $ | 4.28 | |||||||||
Basis swaps (MMBTUs) | (1) | 5,326,559 | 2,877,047 | — | — | ||||||||||||
Weighted average price | $ | (0.1661 | ) | $ | (0.1115 | ) | $ | — | $ | — | |||||||
Oil positions | |||||||||||||||||
Price swaps (BBLs) | NYMEX-WTI | 757,321 | 610,131 | 473,698 | 562,524 | ||||||||||||
Weighted average price | $ | 93.16 | $ | 87.27 | $ | 84.34 | $ | 82.26 | |||||||||
Basis swaps (BBLs) | Argus- | 397,035 | — | — | — | ||||||||||||
Weighted average price | Midland-Cushing | $ | (3.4087 | ) | $ | — | $ | — | $ | — | |||||||
NGL positions | |||||||||||||||||
Price swaps (BBLs) | Mont Belvieu | 236,149 | — | — | — | ||||||||||||
Weighted average price | $ | 34.46 | $ | — | $ | — | $ | — | |||||||||
(1) | Our natural gas basis swaps are traded on the following indices: Centerpoint East, Houston Ship Channel, WAHA and TEXOK. |
At December 31, 2013, we had the following open commodity derivative contracts:
Index | 2015 | 2016 | 2017 | 2018 | |||||||||||||
Natural gas positions | |||||||||||||||||
Price swaps (MMBTUs) | NYMEX-HH | 6,077,016 | 5,500,236 | 5,433,888 | 5,045,760 | ||||||||||||
Weighted average price | $ | 5.53 | $ | 5.72 | $ | 4.29 | $ | 4.61 | |||||||||
Basis swaps (MMBTUs) | (1) | 5,876,098 | 5,326,559 | 2,877,047 | — | ||||||||||||
Weighted average price | $ | (0.1521 | ) | $ | (0.1661 | ) | $ | (0.1115 | ) | $ | — | ||||||
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Index | 2015 | 2016 | 2017 | 2018 | |||||||||||||
Oil positions | |||||||||||||||||
Price swaps (BBLs) | NYMEX-WTI | 723,634 | 561,833 | 397,488 | 198,744 | ||||||||||||
Weighted average price | $ | 95.76 | $ | 93.16 | $ | 86.02 | $ | 85.75 | |||||||||
Basis swaps (BBLs) | Argus- | 410,400 | — | — | — | ||||||||||||
Weighted average price | Midland-Cushing | $ | (1.00 | ) | $ | — | $ | — | $ | — | |||||||
NGL positions | |||||||||||||||||
Price swaps (BBLs) | Mont Belvieu | 183,857 | 147,823 | — | — | ||||||||||||
Weighted average price | $ | 34.11 | $ | 34.50 | $ | — | $ | — | |||||||||
(1) Our natural gas basis swaps are traded on the following indices: Centerpoint East, Houston Ship Channel, WAHA and TEXOK.
At December 31, 2014 and 2013, we had the following interest rate swap derivative contracts (in thousands):
Notional | ||||||||||
Effective | Maturity | Amount | Average % | Index | ||||||
February 2012 | February 2015 | $ | 150,000 | 0.51750% | LIBOR | |||||
February 2015 | February 2017 | 75,000 | 1.72500% | LIBOR | ||||||
February 2015 | February 2017 | 75,000 | 1.72750% | LIBOR | ||||||
June 2012 | June 2015 | 70,000 | 0.52375% | LIBOR | ||||||
June 2015 | June 2017 | 70,000 | 1.42750% | LIBOR | ||||||
Effect of Derivative Instruments — Balance Sheets
The fair value of our commodity and interest rate derivative instruments is included in the tables below (in thousands):
As of December 31, 2014 | |||||||||||||||
Current | Long-term | Current | Long-term | ||||||||||||
Assets | Assets | Liabilities | Liabilities | ||||||||||||
Interest rate | |||||||||||||||
Swaps | $ | — | $ | — | $ | 2,327 | $ | 817 | |||||||
Gross fair value | — | — | 2,327 | 817 | |||||||||||
Netting arrangements | — | — | — | — | |||||||||||
Net recorded fair value | $ | — | $ | — | $ | 2,327 | $ | 817 | |||||||
Sale of natural gas production | |||||||||||||||
Price swaps | $ | 14,732 | $ | 9,170 | $ | — | $ | — | |||||||
Basis swaps | 1 | — | 286 | 232 | |||||||||||
Sale of crude oil production | |||||||||||||||
Price swaps | 27,544 | 29,370 | — | — | |||||||||||
Basis swaps | — | — | 271 | — | |||||||||||
Sale of NGLs | |||||||||||||||
Price swaps | 3,648 | — | — | — | |||||||||||
Gross fair value | 45,925 | 38,540 | 557 | 232 | |||||||||||
Netting arrangements | (1 | ) | — | (1 | ) | — | |||||||||
Net recorded fair value | $ | 45,924 | $ | 38,540 | $ | 556 | $ | 232 | |||||||
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As of December 31, 2013 | ||||||||||||||||
Current | Long-term | Current | Long-term | |||||||||||||
Assets | Assets | Liabilities | Liabilities | |||||||||||||
Interest rate | ||||||||||||||||
Swaps | $ | — | $ | 637 | $ | 648 | $ | 2,191 | ||||||||
Gross fair value | — | 637 | 648 | 2,191 | ||||||||||||
Netting arrangements | — | (637 | ) | — | (637 | ) | ||||||||||
Net recorded fair value | $ | — | $ | — | $ | 648 | $ | 1,554 | ||||||||
Sale of natural gas production | ||||||||||||||||
Price swaps | $ | 8,250 | $ | 11,937 | $ | 196 | $ | 73 | ||||||||
Basis swaps | 56 | 211 | 317 | 65 | ||||||||||||
Sale of crude oil production | ||||||||||||||||
Price swaps | 1,564 | 5,042 | 1,519 | 331 | ||||||||||||
Basis swaps | 227 | — | — | — | ||||||||||||
Sale of NGLs | ||||||||||||||||
Price swaps | 106 | 4 | 662 | 153 | ||||||||||||
Gross fair value | 10,203 | 17,194 | 2,694 | 622 | ||||||||||||
Netting arrangements | (477 | ) | (448 | ) | (477 | ) | (448 | ) | ||||||||
Net recorded fair value | $ | 9,726 | $ | 16,746 | $ | 2,217 | $ | 174 | ||||||||
Effect of Derivative Instruments — Statements of Operations
The net gain (loss) amounts and classification related to derivative instruments for the periods indicated are as follows (in thousands):
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Commodity derivatives (revenue) | $ | 71,235 | $ | 781 | $ | 12,748 | ||||||
Interest rate derivatives (other income/expense) | (1,790 | ) | 1,256 | (4,650 | ) | |||||||
Credit Risk. All of our derivative transactions have been carried out in the over-the-counter market. The use of derivative instruments involves the risk that the counterparties may be unable to meet the financial terms of the transactions. We monitor the creditworthiness of each of our counterparties and assess the possibility of whether each counterparty to the derivative contract would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. We also have netting arrangements in place with each counterparty to reduce credit exposure. The derivative transactions are placed with major financial institutions that we believe present minimal credit risks to us. Additionally, we consider ourselves to be of substantial credit quality and have the financial resources and willingness to meet our potential repayment obligations associated with the derivative transactions.
9. | Related Parties |
Ownership in Our General Partner by Lime Rock Management and its Affiliates
As of December 31, 2014 and 2013, Lime Rock Management, an affiliate of Fund I, owned all of the Class A member interests in our general partner, Fund I owned all of the Class B member interests in our general partner and Fund II owned all of the Class C member interests in our general partner. In addition, Fund I owned an aggregate of approximately 17.3% of our outstanding common units and all of our subordinated units, representing an approximate 30.5% limited partner interest in us as of December 31, 2014. Fund I owned an aggregate of approximately 9.5% of our outstanding common units and all of our subordinate units, representing an approximate
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32.6% limited partner interest in us as of December 31, 2013. As of December 31, 2014 and 2013, our general partner owned an approximate 0.1% general partner interest in us, represented by 22,400 general partner units, and all of our incentive distribution rights.
Contracts with our General Partner and its Affiliates
We entered into a services agreement (the “Services Agreement”) by and among Lime Rock Management, Lime Rock Resources Operating Company, Inc. (“ServCo”), LRE GP, LLC (the “General Partner”), the Partnership and OLLC, pursuant to which Lime Rock Management and ServCo provide certain management, administrative and operating services and personnel to our general partner and us to manage and operate our business. Under the Services Agreement, our general partner reimburses Lime Rock Management and ServCo, on a monthly basis, for the allocable expenses they incur in their performance under the Services Agreement, and we reimburse our general partner for such payments it makes to Lime Rock Management and ServCo. These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and other expenses allocated by Lime Rock Management and ServCo to us. Lime Rock Management and ServCo have discretion to determine in good faith the proper allocation of costs and expenses to our general partner for their services. Lime Rock Management and ServCo will not be liable to us for their performance of, or failure to perform, services under the Services Agreement unless their acts or omissions constitute gross negligence or willful misconduct.
We entered into an omnibus agreement (the “Omnibus Agreement”) with our general partner, OLLC, LRR A, LRR B, LRR C, LRR GP, LLC and Lime Rock Management. Under the Omnibus Agreement, none of the parties or their respective affiliates have any obligation to offer, or provide any opportunity to pursue, purchase or invest in, any business opportunity to any other party or their affiliates. The Omnibus Agreement does not restrict any of the parties and their respective affiliates from competing with either Fund I or us, our general partner, OLLC and all of their respective subsidiaries.
Pursuant to the Omnibus Agreement, each entity of Fund I indemnified us, our general partner, OLLC and their respective subsidiaries against (i) title defects, (ii) income taxes attributable to pre-closing ownership or operation of the contributed assets, including any income tax liabilities related to the formation transactions that occurred on or prior to the closing of the IPO, (iii) environmental claims, losses and expenses associated with the operation of our business prior to the closing of the IPO, subject to a maximum of $10,000,000, (iv) all liabilities, other than liabilities covered under the preceding clause, (iii) relating to the operation of the contributed assets prior to the closing that were not disclosed in the most recent pro forma balance sheet included in our Registration Statement on Form S-1, as amended (File No. 333-174017) or incurred in the ordinary course of business thereafter, and (v) losses resulting from the failure of Fund I to have on the closing date any consent, waiver or governmental permit that renders us, general partner, OLLC and their respective subsidiaries unable to own, use or operate the contributed assets in substantially the same manner as they were owned, used or operated immediately prior to the closing of the IPO.
Fund I’s indemnification obligation (i) survives for three years after the closing of the IPO with respect to title defects, (ii) survives for one year after closing with respect to environmental claims, undisclosed liabilities and failure to have any consent, waiver or governmental permits, and (iii) terminates upon the earlier of (y) the expiration of the term of Fund I and (z) sixty days after the expiration of the applicable statute of limitations with respect to income taxes. All claims are subject to a $50,000 per claim de minimus exception, and no claims may be made against Fund I unless such losses exceed $500,000 in the aggregate; thereafter, each entity of Fund I will be liable, severally, in proportion to its contribution percentage, only to the extent that such losses exceed $500,000.
For the years ended December 31, 2014 and 2013, we paid Lime Rock Management $1.6 million and $1.8 million either directly or indirectly related to these agreements, respectively.
In connection with the management of our business, ServCo, an affiliate of our general partner, provides services for invoicing and processing of payments to our vendors. Periodically, ServCo remits cash to us for the net
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working capital received on our behalf. Changes in the affiliates (payable)/receivable balances as of and for the years indicated are included below (in thousands):
Lime Rock | |||||||||||
ServCo | Resources | Total | |||||||||
Balance as of December 31, 2012 | $ | (2,230 | ) | $ | 253 | $ | (1,977 | ) | |||
Expenditures | (99,124 | ) | (1,019 | ) | (100,143 | ) | |||||
Cash paid for expenditures | 95,685 | 1,275 | 96,960 | ||||||||
Revenues and other | 5,151 | (246 | ) | 4,905 | |||||||
Balance as of December 31, 2013 | (518 | ) | 263 | (255 | ) | ||||||
Expenditures | (108,243 | ) | — | (108,243 | ) | ||||||
Cash paid for expenditures | 134,809 | — | 134,809 | ||||||||
Revenues and other | (20,612 | ) | (2 | ) | (20,614 | ||||||
Balance as of December 31, 2014 | $ | 5,436 | $ | 261 | $ | 5,697 | |||||
Distributions of Available Cash to Our General Partner and Affiliates
We will generally make cash distributions to our unitholders and our general partner pro rata. As of December 31, 2014, our general partner and its affiliates held 4,089,600 of our common units, 4,480,000 of our subordinated units and 22,400 general partner units. As of December 31, 2013, our general partner and its affiliates held 1,849,600 of our common units, 6,720,000 of our subordinated units and 22,400 general partner units. During the years ended December 31, 2014, 2013, and 2012, we paid cash distributions of $53.4 million, $48.9, and $37.3 million, respectively, to all unitholders as of the respective record dates.
We announced our fourth quarter 2014 distribution on January 20, 2015 as discussed in Note 15.
10. | Unitholders’ Equity |
At-the-Market Issuance Sales Program
On February 4, 2014, we launched an “at-the-market” offering program (the “ATM Program”) with MLV & Co. LLC (“MLV”) as sales agent. We may sell from time to time through MLV our common units representing limited partner interests having an aggregate offering amount of up to $75.0 million. Any sales of common units under the ATM Program may be made by any method permitted by law deemed to be an “at-the-market offering” defined by Rule 415 of the Securities Act, including, without limitation, sales made directly on the New York Stock Exchange, or any other existing trading market for our common units or to or through a market maker.
Our second lien term loan requires that 50% of the net cash proceeds from any equity offering be used to repay borrowings outstanding under the term loan. In October 2014, we entered into an amendment to our Term Loan to waive this requirement through March 31, 2015. As of December 31, 2014, we received net proceeds from the sale of 1,521,846 issued common units of $26.0 million, after deducting underwriting discounts and commissions and offering expenses of approximately $0.8 million, and used the proceeds for general partnership purposes. For the year ended December 31, 2014, we paid approximately $0.5 million of aggregate compensation to MLV for sales under the ATM Program.
Equity Offering
On March 22, 2013, we closed a public equity offering of 3,700,000 common units representing limited partner interests in the Partnership at a price to the public of $16.84 per common unit, or $16.1664 per common unit after payment of the underwriting discount. We received net proceeds from the sale of 3,700,000 newly issued common units of $59.5 million, after deducting underwriting discounts and commissions and offering expenses of $0.3 million. We used the net proceeds of the offering to fund our April 2013 Acquisition discussed in Note 3 and repay
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borrowings outstanding on our Credit Agreement.
Fund I sold 3,200,000 common units in the equity offering at a price to the public of $16.84 per common unit, or $16.1664 per common unit after payment of the underwriting discount. We did not receive any proceeds from the sale of common units by Fund I; however, the equity balance of Fund I was adjusted for its reduced ownership interest in us.
Units Outstanding
As of December 31, 2014, we had 23,581,891 common units, 4,480,000 subordinated units and 22,400 general partner units outstanding. In addition, as of December 31, 2014, Fund I owned 4,089,600 common units and all of our subordinated units, representing an approximate 30.5% limited partner interest in us.
As of December 31, 2013, we had 19,559,934 common units, 6,720,000 subordinated units and 22,400 general partner units outstanding. In addition, as of December 31, 2013, Fund I owned 1,849,600 common units and all of our subordinated units, representing an approximate 32.6% limited partner interest in us.
Common Units
The common units have limited voting rights as set forth in our partnership agreement.
Subordinated Units
The principal difference between our common units and subordinated units is that in any quarter during the subordination period, the subordinated units are entitled to receive the minimum quarterly distribution only after the common units have received their minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Accordingly, holders of subordinated units may receive a smaller distribution than holders of common units or no distribution at all. Subordinated units will not accrue arrearages.
The subordination period will extend until the first business day of any quarter after December 31, 2014 that we have earned and paid from operating surplus, in the aggregate, distributions on each outstanding common unit, subordinated unit and general partner unit and any other partnership interests that are senior or equal in right of distribution to the subordinated units equaling or exceeding the minimum quarterly distribution payable with respect to a period of twelve consecutive quarters immediately preceding such date, provided there are no arrearages in the minimum quarterly distribution on our common units at that time. However, three separate one third tranches of subordinated units may convert on the first business day after the distribution to unitholders in respect of any quarter ending on or after December 31, 2012, December 31, 2013 and December 31, 2014, respectively, provided that an aggregate amount equal to the minimum quarterly distribution payable with respect to all units that would be payable on four, eight or twelve consecutive quarters, as applicable, has been earned and paid prior to the applicable date, in each case provided there are no arrearages in the minimum quarterly distribution on our common units at that time. We converted 2,240,000 subordinated units on a one-for-one basis into common units pursuant to the terms of our partnership agreement on May 16, 2014. We converted the remaining 4,480,000 subordinated units on a one-for-one basis into common units pursuant to the terms of our partnership agreement on February 13, 2015.
General Partner Interest
Our general partner owns an approximate 0.1% interest in us. This interest entitles our general partner to receive distributions of available cash from operating surplus as discussed further below under Cash Distributions. Our partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, subordinated unitholders and our general partner will receive.
Our general partner has sole responsibility for conducting our business and managing our operations. Our general partner’s board of directors and executive officers will make decisions on our behalf.
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Allocation of Net Income
Net income is allocated between our general partner and the common and subordinated unitholders in proportion to their pro rata ownership during the period.
Cash Distributions
Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date.
Available cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:
• | less, the amount of cash reserves established by our general partner at the date of determination of available cash for the quarter to: |
• | provide for the proper conduct of our business, which could include, but is not limited to, amounts reserved for capital expenditures, working capital and operating expenses; |
• | comply with applicable law, any of our debt instruments or other agreements; or |
• | provide funds for distributions to our unitholders (including our general partner) for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for future distributions on our subordinated units unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for such quarter); |
• | plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. |
Upon the closing of our initial public offering, Fund I received an aggregate of 6,720,000 subordinated units. During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.4750 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed "subordinated" because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions from operating surplus until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units.
The subordination period ended on February 13, 2015, and all subordinated units converted into common units on a one-for-one basis. All common units are no longer entitled to arrearages.
During Subordination Period. Assuming our general partner maintains its approximate 0.1% general partner interest in us, our partnership agreement requires us to distribute all of our available cash from operating surplus for each quarter in the following manner during the subordination period:
• | first, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter; |
• | second, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period; |
• | third, 99.9% to the subordinated unitholders, pro rata, and 0.1% to our general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and |
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• | fourth, 99.9% to all unitholders pro rata, and 0.1% to our general partner, until each unitholder receives a total of $0.54625 per unit for that quarter. |
If cash distributions to our unitholders exceed $0.54625 per common unit and subordinated unit in any quarter, our unitholders and our general partner will receive distributions according to the following percentage allocations:
Total Quarterly Distribution Target Amount | Marginal Percentage Interest in Distributions | |||
Unitholders | General Partner | |||
above $0.54625 up to $0.59375 | 86.9% | 13.1% | ||
above $0.59375 | 76.9% | 23.1% | ||
The percentage interests shown for our general partner include its approximate 0.1% general partner interest. We refer to the additional increasing distributions to our general partner in excess of its approximate 0.1% general partner interest as “incentive distributions.”
After Subordination Period. Our partnership agreement requires us to distribute all of our available cash from operating surplus each quarter in the following manner after the subordination period:
• | first, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter; |
• | second, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until each unitholder receives a total of $0.54625 per unit for that quarter. |
• | thereafter, as provided in the table above. |
11. | Net Income (Loss) Per Limited Partner Unit |
The following sets forth the calculation of net income (loss) per limited partner unit for the following periods (in thousands, except per unit amounts):
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Net income (loss) | $ | 52,742 | $ | (48,281 | ) | $ | 6,787 | |||||
Net income (loss) attributable to common control operations | — | (448 | ) | (6,790 | ) | |||||||
Net income (loss) available to unitholders | 52,742 | (48,729 | ) | (3 | ) | |||||||
Less: General partner’s interest in net (income) loss | (53 | ) | 49 | — | ||||||||
Limited partners’ interest in net income (loss) | $ | 52,689 | $ | (48,680 | ) | $ | (3 | ) | ||||
Weighted average limited partner units outstanding: | ||||||||||||
Common units | 21,777 | 18,652 | 15,705 | |||||||||
Subordinated units | 5,315 | 6,720 | 6,720 | |||||||||
Total | 27,092 | 25,372 | 22,425 | |||||||||
Net income (loss) per limited partner unit (basic and diluted) | $ | 1.94 | $ | (1.92 | ) | $ | 0.00 | |||||
Our subordinated units and restricted unit awards are considered to be participating securities for purposes of calculating our net income (loss) per limited partner unit, and accordingly, are included in basic computation as
27
such. Net income (loss) per limited partner unit is determined by dividing the net income (loss) available to the common unitholders, after deducting our general partner’s approximate 0.1% interest in net income (loss), by the weighted average number of common units and subordinated units outstanding as of December 31, 2014, 2013 and 2012. The aggregate number of common units and subordinated units was 23,581,891 and 4,480,000 as of December 31, 2014. The aggregate number of common units and subordinated units was 19,559,934 and 6,720,000 as of December 31, 2013. The aggregate number of common units and subordinated units was 15,726,342 and 6,720,000 as of December 31, 2012.
12. | Equity-Based Compensation |
On November 10, 2011, our General Partner adopted a long-term incentive plan (“2011 LTIP”) for employees, consultants and directors of our General Partner and its affiliates, including Lime Rock Management and ServCo, who perform services for us. The 2011 LTIP consists of unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, unit awards and other unit-based awards. The 2011 LTIP initially limits the number of units that may be delivered pursuant to vested awards to 1,500,000 common units. As of December 31, 2014, there were 1,037,555 units available for issuance under the 2011 LTIP. The 2011 LTIP will be administered by our General Partner’s board of directors or a committee thereof.
The fair value of restricted units is determined based on the fair market value of the units on the date of grant. The outstanding restricted units vest over three years in equal amounts (subject to rounding) on the date of grant and are entitled to receive quarterly distributions during the vesting period.
A summary of the non-vested units for the year ended December 31, 2014 is presented below:
Number of Non-vested Units | Weighted Average Grant-Date Fair Value | ||||||
Non-vested restricted units at December 31, 2013 | 165,265 | $ | 16.73 | ||||
Granted | 273,802 | 7.10 | |||||
Vested | (63,419 | ) | 17.12 | ||||
Forfeited | (13,691 | ) | 16.54 | ||||
Non-vested units at December 31, 2014 | 361,957 | 9.38 | |||||
As of December 31, 2014, there was $3.0 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over a weighted average period of approximately 2.5 years. There were 104,663 vested restricted units as of December 31, 2014.
13. | Contractual Obligations and Commitments |
In the normal course of business, we enter into contracts that contain a variety of representations and warranties and provide general indemnifications. Our maximum exposure under these arrangements is unknown as this would involve future claims that may be made against us that have not yet occurred. We do not expect to suffer any material losses in connection with these contracts.
Various federal, state and local laws and regulations covering, among other things, the release of waste materials into the environment and state and local taxes affect our operations and costs. Our management believes we are in substantial compliance with applicable federal, state and local laws, and management expects that the ultimate resolution of any claims or legal proceedings instituted against us will not have a material effect on our financial position or results of operations.
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14. | Subsidiary Guarantors |
We and LRE Finance, our 100 percent-owned subsidiary, filed a registration statement on Form S-3 with the Securities and Exchange Commission (“SEC”) on August 28, 2013, and the SEC declared the registration statement effective on September 10, 2013. Securities that may be offered and sold include debt securities that are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933. LRE Finance may co-issue any debt securities issued by us pursuant to the registration statement. LRE Finance was formed solely for the purpose of co-issuing our debt securities and has no material assets or liabilities other than as co-issuer of our debt securities. OLLC, our 100 percent-owned subsidiary, may guarantee any debt securities issued by us and such guarantee will be full and unconditional, subject to customary release provisions. The guarantee will be released (i) automatically upon any sale, exchange or transfer of our equity interests in OLLC, (ii) automatically upon the liquidation and dissolution of OLLC, (iii) following delivery of notice to the trustee under the indenture related to the debt securities of the release of OLLC of its obligations under the Partnership’s revolving credit facility, and (iv) upon legal or covenant defeasance or other satisfaction of the obligations under the related debt securities. Other than LRE Finance, OLLC is our sole subsidiary and thus no other subsidiary will guarantee our debt securities.
Furthermore, we have no assets or operations independent of OLLC, and there are no significant restrictions upon the ability of OLLC to distribute funds to us by dividend or loan. Finally, none of our assets or OLLC represents restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X.
15. | Subsequent Events |
Unit Distribution
On January 20, 2015, we announced that the board of directors of our general partner declared a cash distribution for the fourth quarter of 2014 of $0.4975 per outstanding unit, or $1.99 on an annualized basis. The distribution was paid on February 13, 2015 to all unitholders of record as of the close of business on January 30, 2015. The aggregate amount of the distribution was $14.0 million.
Conversion of Subordinated Units
On February 13, 2015 we converted the remaining 4,480,000 subordinated units on a one-for-one basis into common units pursuant to the terms of our partnership agreement.
16. | Supplemental Information on Oil and Natural Gas Exploration and Production Activities (Unaudited) |
Oil and Natural Gas Capitalized Costs
Capitalized costs relating to oil and natural gas producing activities are as follows (in thousands):
December 31, | ||||||||
2014 | 2013 | |||||||
Proved oil and natural gas properties | $ | 954,819 | $ | 875,126 | ||||
Unproved oil and natural gas properties | 1,235 | 1,258 | ||||||
956,054 | 876,384 | |||||||
Accumulated depletion and depreciation | (506,134 | ) | (431,636 | ) | ||||
Net capitalized costs | $ | 449,920 | $ | 444,748 | ||||
29
Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities
Costs incurred in oil and natural gas property acquisition and development activities are as follows (in thousands):
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Acquisition of oil and natural gas properties | ||||||||||||
Proved | $ | 38,330 | $ | 10 | $ | 9,795 | ||||||
Unproved | — | — | — | |||||||||
Development costs | 41,721 | 36,484 | 31,598 | |||||||||
Total | $ | 80,051 | $ | 36,494 | $ | 41,393 | ||||||
We had immaterial exploration costs for each of the periods during 2014, 2013 and 2012.
Oil and Natural Gas Reserves
The reserve disclosures that follow reflect estimates of proved reserves, proved developed reserves and proved undeveloped reserves, net of third‑party royalty interests, of natural gas, crude oil and condensate, and NGLs owned at each year end and changes in proved reserves during each of those periods. Natural gas volumes are in millions of cubic feet (MMcf) at a pressure base of 14.73 pounds per square inch and volumes for oil, condensate and NGLs are in thousands of barrels (MBbls). Total volumes are presented in thousands of barrels of oil equivalent (MBOE). For this computation, one barrel of oil is assumed to be the equivalent of 6,000 cubic feet of natural gas. Shrinkage associated with NGLs has been deducted from the natural gas reserve volumes.
Our estimates of proved reserves are made using available geological and reservoir data as well as production performance data. These estimates are reviewed on a periodic basis throughout the year by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions, as well as changes in the expected recovery associated with infill drilling.
Our oil and natural gas properties and associated reserves are located in the continental United States. The following table presents the estimated remaining net proved, proved developed and proved undeveloped oil and natural gas reserves as of the periods indicated, and the related summary of changes in estimated quantities of net remaining proved reserves during those periods. Our estimated reserves at December 31, 2014, 2013 and 2012 were based on reserve reports prepared by the independent reserve engineers Miller and Lents, Ltd., Netherland, Sewell & Associates, Inc. and Ryder Scott Petroleum Consultants.
In 2014, we added 2.8 MMBoe of proved reserves through the October 2014 Acquisition. Reserve revisions for 2014 were 2.3 MMBoe and were primarily driven by higher natural gas commodity prices during 2014 and improved well performance. During 2013, our revisions and extensions offset a portion of our production. In 2012, we had net revisions of previous reserves of 0.3 MMBoe, including an increase in oil and NGL reserves of 2.2 MMBoe and a decrease in natural gas reserves of 2.5 MMBoe. The positive revisions in 2012 primarily related to improved production performance and revised prior reserve estimates at our Red Lake field. The negative revisions of natural gas reserves related to the significantly lower natural gas pricing during 2012. We also had 0.3 MMBoe of acquisitions of oil and NGL reserves by Fund II related to our April 2013 Acquisition during 2012.
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Oil | NGL | Gas | Total | |||||||||
(MBbls) | (MBbls) | (MMcf) | (MBoe) | |||||||||
Balance, December 31, 2011 | 9,949 | 3,602 | 118,048 | 33,226 | ||||||||
Revision of previous estimates | 1,776 | 379 | (14,630 | ) | (283 | ) | ||||||
Extensions and discoveries | 546 | 134 | 606 | 781 | ||||||||
Acquisition of minerals in place | 268 | — | — | 268 | ||||||||
Sales of minerals in place | — | — | — | — | ||||||||
Production | (834 | ) | (311 | ) | (8,487 | ) | (2,560 | ) | ||||
Balance, December 31, 2012 | 11,705 | 3,804 | 95,537 | 31,432 | ||||||||
Revision of previous estimates | (288 | ) | 443 | 4,150 | 847 | |||||||
Extensions and discoveries | 118 | 37 | 181 | 185 | ||||||||
Acquisition of minerals in place | — | — | — | — | ||||||||
Sales of minerals in place | — | — | — | — | ||||||||
Production | (837 | ) | (315 | ) | (7,246 | ) | (2,360 | ) | ||||
Balance, December 31, 2013 | 10,698 | 3,969 | 92,622 | 30,104 | ||||||||
Revision of previous estimates | 434 | 635 | 7,484 | 2,316 | ||||||||
Extensions and discoveries | 573 | 182 | 1,138 | 945 | ||||||||
Acquisition of minerals in place | 2,305 | 198 | 1,948 | 2,828 | ||||||||
Sales of minerals in place | — | — | — | — | ||||||||
Production | (904 | ) | (366 | ) | (6,467 | ) | (2,348 | ) | ||||
Balance, December 31, 2014 | 13,106 | 4,618 | 96,725 | 33,845 | ||||||||
Oil | NGL | Gas | Total | |||||||||
(MBbls) | (MBbls) | (MMcf) | (MBoe) | |||||||||
Proved developed reserves: | ||||||||||||
December 31, 2012 | 8,588 | 2,936 | 89,803 | 26,491 | ||||||||
December 31, 2013 | 8,548 | 3,252 | 88,172 | 26,495 | ||||||||
December 31, 2014 | 10,962 | 3,956 | 88,265 | 29,629 | ||||||||
Proved undeveloped reserves: | ||||||||||||
December 31, 2012 | 3,117 | 868 | 5,734 | 4,941 | ||||||||
December 31, 2013 | 2,150 | 717 | 4,450 | 3,609 | ||||||||
December 31, 2014 | 2,144 | 662 | 8,460 | 4,216 | ||||||||
Standardized Measure of Discounted Future Net Cash Flows
Oil and natural gas reserve estimation and disclosure regulations require that reserve estimates and discounted future net cash flows are based on the unweighted average market prices for sales of oil and natural gas on the first calendar day of each month during the year. Cash flows are adjusted for transportation fees and regional price differentials, to the estimated future production of proved oil and natural gas reserves less estimated future expenditures to be incurred in developing and producing the proved reserves, discounted using an annual rate of 10% to reflect the estimated timing of the future cash flows. Income taxes are excluded because we and the Predecessor are non-taxable entities. Generally, all taxable income and losses are reported on the income tax returns of the unitholders and partners, and therefore, no provision for income taxes has been recorded in the accompanying consolidated financial statements. Extensive judgments are involved in estimating the timing of production and the costs that will be incurred throughout the remaining lives of the properties. Accordingly, the estimates of future net
31
cash flows from proved reserves and the present value may be materially different from subsequent actual results. The standardized measure of discounted net cash flows does not purport to present, nor should it be interpreted to present, the fair value of the acquired properties’ oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, and anticipated future changes in prices and costs.
The standardized measure of discounted future net cash flows related to our interest in proved reserves as of the periods indicated are as follows (in thousands):
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Future cash inflows | $ | 1,749,346 | $ | 1,450,007 | $ | 1,488,912 | ||||||
Future costs: | ||||||||||||
Development | (117,473 | ) | (120,339 | ) | (163,316 | ) | ||||||
Production | (687,097 | ) | (526,523 | ) | (521,378 | ) | ||||||
Texas margin tax | (1,236 | ) | (1,187 | ) | — | |||||||
Future net cash flows | 943,540 | 801,958 | 804,218 | |||||||||
10% discount to reflect | ||||||||||||
timing of cash flows | (501,869 | ) | (409,401 | ) | (416,322 | ) | ||||||
Standardized measure of discounted future net cash flows | $ | 441,671 | $ | 392,557 | $ | 387,896 | ||||||
The principal changes in the standardized measure of discounted future net cash flows attributable to our proved reserves as of the periods indicated are as follows (in thousands):
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Beginning of period | 392,557 | 387,896 | 435,789 | ||||||||||
Purchase of reserves in place | 45,665 | (1) | — | 5,866 | (2) | ||||||||
Extensions and discoveries, net of future development costs | 17,979 | 2,034 | 19,381 | ||||||||||
Revisions of quantity estimates | 30,256 | 11,054 | (1,373 | ) | |||||||||
Changes in future development costs, net | (11,897 | ) | 16,600 | (871 | ) | ||||||||
Development costs incurred that reduce future development costs | 27,073 | 25,408 | 12,164 | ||||||||||
Net changes in prices | 584 | 4,363 | (36,843 | ) | |||||||||
Change in future Texas margin tax | (27 | ) | (570 | ) | — | ||||||||
Oil, natural gas and NGL sales, net of production costs | (81,986 | ) | (80,117 | ) | (71,186 | ) | |||||||
Changes in timing and other | (17,846 | ) | (12,901 | ) | (18,610 | ) | |||||||
Accretion of discount | 39,313 | 38,790 | 43,579 | ||||||||||
End of period | $ | 441,671 | $ | 392,557 | $ | 387,896 | |||||||
(1) | Represents the reserves acquired in the October 2014 Acquisition. |
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(2) | Represents a purchase of reserves by Fund II related to our April 2013 Acquisition. |
17. | Selected Quarterly Financial Information (Unaudited) |
Quarterly financial data was as follows for the periods indicated (in thousands):
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||
2014 | ||||||||||||
Revenues | 26,028 | 17,391 | 48,382 | 96,104 | ||||||||
Operating income (loss) | 5,603 | (3,596 | ) | 28,317 | 34,866 | |||||||
Net income (loss) | 2,694 | (7,337 | ) | 26,232 | 31,153 | |||||||
Net income (loss) available to common unitholders | 2,694 | (7,337 | ) | 26,232 | 31,153 | |||||||
Net income (loss) per limited partner unit (basic and diluted) | 0.10 | (0.27 | ) | 0.95 | 1.12 | |||||||
2013 | ||||||||||||
Revenues | 17,780 | 41,379 | 25,195 | 30,741 | ||||||||
Operating income (loss) | (4,847 | ) | 20,177 | 4,069 | (59,645 | ) | ||||||
Net income (loss) | (7,002 | ) | 20,523 | 284 | (62,086 | ) | ||||||
Net income (loss) available to common unitholders | (7,450 | ) | 20,523 | 284 | (62,086 | ) | ||||||
Net income (loss) per limited partner unit (basic and diluted) | (0.32 | ) | 0.78 | 0.01 | (2.37 | ) | ||||||
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Exhibit 99.2
Report of Independent Registered Public Accounting Firm
To Board of Directors of LRE GP, LLC and Unitholders of LRR Energy, L.P.:
We have audited the accompanying consolidated balance sheets of LRR Energy, L.P. and its subsidiaries (the “Company”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, of changes in unitholders’ equity, and of cash flows present fairly for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of LRR Energy, L.P. and its subsidiaries at December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 4, 2015
Exhibit 99.3
LRR Energy, L.P. | |||||||||
Consolidated Condensed Balance Sheets | |||||||||
(Unaudited) | |||||||||
(in thousands, except unit amounts) | |||||||||
June 30, 2015 | December 31, 2014 | ||||||||
ASSETS | |||||||||
Current assets: | |||||||||
Cash and cash equivalents | $ | 7,681 | $ | 3,576 | |||||
Accounts receivable | 8,659 | 11,124 | |||||||
Commodity derivative instruments | 32,087 | 45,924 | |||||||
Due from affiliates | 1,456 | 5,697 | |||||||
Prepaid expenses | 1,240 | 1,840 | |||||||
Total current assets | 51,123 | 68,161 | |||||||
Property and equipment (successful efforts method) | 972,398 | 956,326 | |||||||
Accumulated depletion, depreciation and impairment | (559,893 | ) | (506,368 | ) | |||||
Total property and equipment, net | 412,505 | 449,958 | |||||||
Commodity derivative instruments | 37,159 | 38,540 | |||||||
Deferred financing costs, net of accumulated amortization and other assets | 2,076 | 2,295 | |||||||
TOTAL ASSETS | $ | 502,863 | $ | 558,954 | |||||
LIABILITIES AND UNITHOLDERS’ EQUITY | |||||||||
Current liabilities: | |||||||||
Accrued liabilities | $ | 9,910 | $ | 5,506 | |||||
Accrued capital cost | 7,642 | 9,176 | |||||||
Commodity derivative instruments | 783 | 556 | |||||||
Interest rate derivative instruments | 2,781 | 2,327 | |||||||
Asset retirement obligations | 2,153 | 1,065 | |||||||
Total current liabilities | 23,269 | 18,630 | |||||||
Long-term liabilities: | |||||||||
Commodity derivative instruments | 94 | 232 | |||||||
Interest rate derivative instruments | 960 | 817 | |||||||
Term loan | 50,000 | 50,000 | |||||||
Revolving credit facility | 235,000 | 230,000 | |||||||
Asset retirement obligations | 40,558 | 40,539 | |||||||
Deferred tax liabilities | — | 99 | |||||||
Total long-term liabilities | 326,612 | 321,687 | |||||||
Total liabilities | 349,881 | 340,317 | |||||||
Unitholders’ equity: | |||||||||
General partner (22,400 units issued and outstanding as of June 30, 2015 and December 31, 2014) | (9,139 | ) | 310 | ||||||
Public common unitholders (19,504,833 units issued and outstanding as of June 30, 2015 and 19,492,291 units issued and outstanding | 162,121 | 208,273 | |||||||
Affiliated common unitholders (8,569,600 units issued and outstanding as of June 30, 2015 and 4,089,600 units issued and outstanding as of December 31, 2014) | — | 4,643 | |||||||
Subordinated unitholders (4,480,000 units issued and outstanding as of December 31, 2014) | — | 5,411 | |||||||
Total unitholders’ equity | 152,982 | 218,637 | |||||||
TOTAL LIABILITIES AND UNITHOLDERS’ EQUITY | $ | 502,863 | $ | 558,954 | |||||
See accompanying notes to the unaudited consolidated condensed financial statements.
1
LRR Energy, L.P. | ||||||||||||||||
Consolidated Condensed Statements of Operations | ||||||||||||||||
(Unaudited) | ||||||||||||||||
(in thousands, except per unit amounts) | ||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Revenues: | ||||||||||||||||
Oil sales | $ | 14,227 | $ | 20,354 | $ | 26,291 | $ | 40,510 | ||||||||
Natural gas sales | 3,720 | 7,565 | 7,986 | 15,664 | ||||||||||||
Natural gas liquids sales | 1,661 | 2,760 | 2,832 | 6,124 | ||||||||||||
Gain (loss) on commodity derivative instruments, net | (8,927 | ) | (13,328 | ) | 9,755 | (18,950 | ) | |||||||||
Other income | 26 | 40 | 55 | 71 | ||||||||||||
Total revenues | 10,707 | 17,391 | 46,919 | 43,419 | ||||||||||||
Operating expenses: | ||||||||||||||||
Lease operating expense | 6,008 | 6,829 | 12,780 | 12,664 | ||||||||||||
Production and ad valorem taxes | 1,482 | 2,248 | 2,748 | 4,648 | ||||||||||||
Depletion and depreciation | 8,694 | 8,680 | 17,574 | 17,145 | ||||||||||||
Impairment of oil and natural gas properties | 256 | — | 35,962 | — | ||||||||||||
Accretion expense | 518 | 510 | 1,029 | 1,013 | ||||||||||||
Loss (gain) on settlement of asset retirement obligations | 4 | 21 | 68 | 61 | ||||||||||||
General and administrative expense | 12,673 | 2,699 | 16,464 | 5,881 | ||||||||||||
Total operating expenses | 29,635 | 20,987 | 86,625 | 41,412 | ||||||||||||
Operating income (loss) | (18,928 | ) | (3,596 | ) | (39,706 | ) | 2,007 | |||||||||
Other income (expense), net | ||||||||||||||||
Interest expense | (3,120 | ) | (2,575 | ) | (5,889 | ) | (5,116 | ) | ||||||||
Gain (loss) on interest rate derivative instruments, net | (322 | ) | (1,128 | ) | (1,673 | ) | (1,422 | ) | ||||||||
Other income (expense), net | (3,442 | ) | (3,703 | ) | (7,562 | ) | (6,538 | ) | ||||||||
Income (loss) before taxes | (22,370 | ) | (7,299 | ) | (47,268 | ) | (4,531 | ) | ||||||||
Income tax (expense) benefit | 56 | (38 | ) | 18 | (112 | ) | ||||||||||
Net income (loss) available to unitholders | $ | (22,314 | ) | $ | (7,337 | ) | $ | (47,250 | ) | $ | (4,643 | ) | ||||
Computation of net income (loss) per limited partner unit: | ||||||||||||||||
General partner’s interest in net income (loss) | $ | (7,595 | ) | $ | (7 | ) | $ | (9,434 | ) | $ | (4 | ) | ||||
Limited partners’ interest in net income (loss) | $ | (14,719 | ) | $ | (7,330 | ) | $ | (37,816 | ) | $ | (4,639 | ) | ||||
Net income (loss) per limited partner unit (basic and diluted) | $ | (0.52 | ) | $ | (0.27 | ) | $ | (1.35 | ) | $ | (0.17 | ) | ||||
Weighted average number of limited partner units outstanding (basic and diluted) | 28,074 | 26,733 | 28,073 | 26,539 | ||||||||||||
See accompanying notes to the unaudited consolidated condensed financial statements.
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LRR Energy, L.P. | ||||||||||||||||||||
Consolidated Condensed Statement of Changes in Unitholders’ Equity | ||||||||||||||||||||
(Unaudited) | ||||||||||||||||||||
(in thousands) | ||||||||||||||||||||
Limited Partners | ||||||||||||||||||||
General | Public | Affiliated | ||||||||||||||||||
Partner | Common | Common | Subordinated | Total | ||||||||||||||||
Balance, December 31, 2014 | $ | 310 | $ | 208,273 | $ | 4,643 | $ | 5,411 | $ | 218,637 | ||||||||||
Equity offering, net of expenses | — | 3 | — | — | 3 | |||||||||||||||
Amortization of equity awards | — | 838 | — | — | 838 | |||||||||||||||
Conversion of subordinated units | — | — | 3,182 | (3,182 | ) | — | ||||||||||||||
Distribution | (15 | ) | (14,201 | ) | (2,801 | ) | (2,229 | ) | (19,246 | ) | ||||||||||
Net income (loss) | (9,434 | ) | (32,792 | ) | (5,024 | ) | — | (47,250 | ) | |||||||||||
Balance, June 30, 2015 | $ | (9,139 | ) | $ | 162,121 | $ | — | $ | — | $ | 152,982 | |||||||||
See accompanying notes to the unaudited consolidated condensed financial statements.
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LRR Energy, L.P. | ||||||||
Consolidated Condensed Statements of Cash Flows | ||||||||
(Unaudited) | ||||||||
(in thousands) | ||||||||
Six Months Ended June 30, | ||||||||
2015 | 2014 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||
Net income (loss) | $ | (47,250 | ) | $ | (4,643 | ) | ||
Adjustments to reconcile net income -loss) to net cash provided by | ||||||||
(used in) operating activities: | ||||||||
Depletion and depreciation | 17,574 | 17,145 | ||||||
Impairment of oil and natural gas properties | 35,962 | — | ||||||
Accretion expense | 1,029 | 1,013 | ||||||
Amortization of equity awards | 838 | 534 | ||||||
Amortization of derivative contracts | 243 | 330 | ||||||
Amortization of deferred financing costs and other | 341 | 208 | ||||||
Loss (gain) on settlement of asset retirement obligations | 68 | 61 | ||||||
Changes in operating assets and liabilities: | ||||||||
Change in receivables | 2,465 | 75 | ||||||
Change in prepaid expenses | 483 | (209 | ) | |||||
Change in derivative assets and liabilities | 15,659 | 20,605 | ||||||
Change in amounts due to/from affiliates | 4,241 | (5,992 | ) | |||||
Change in accrued liabilities and deferred tax liabilities | 4,301 | 2,536 | ||||||
Net cash provided by (used in) operating activities | 35,954 | 31,663 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||
Development of oil and natural gas properties | (17,376 | ) | (17,094 | ) | ||||
Acquisition of oil and natural gas properties | (230 | ) | — | |||||
Disposition of oil and natural gas properties | — | 65 | ||||||
Net cash provided by (used in) investing activities | (17,606 | ) | (17,029 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||
Borrowings under revolving credit facility | 10,000 | 20,000 | ||||||
Principal payments on revolving credit facility | (5,000 | ) | (25,000 | ) | ||||
Equity offering, net of expenses | 3 | 14,810 | ||||||
Distributions | (19,246 | ) | (25,990 | ) | ||||
Net cash provided by (used in) financing activities | (14,243 | ) | (16,180 | ) | ||||
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | 4,105 | (1,546 | ) | |||||
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD | 3,576 | 4,417 | ||||||
CASH AND CASH EQUIVALENTS, END OF PERIOD | $ | 7,681 | $ | 2,871 | ||||
See accompanying notes to the unaudited consolidated condensed financial statements.
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LRR Energy, L.P.
Notes to Consolidated Condensed Financial Statements
(unaudited)
1. | Organization and Description of Business |
LRR Energy, L.P. (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership formed in April 2011 by Lime Rock Management LP (“Lime Rock Management”), an affiliate of Lime Rock Resources A, L.P. (“LRR A”), Lime Rock Resources B, L.P. (“LRR B”) and Lime Rock Resources C, L.P. (“LRR C”), to operate, acquire, exploit and develop producing oil and natural gas properties in North America with long-lived, predictable production profiles. As used herein, references to “Fund I” refer collectively to LRR A, LRR B and LRR C; references to “Fund II” refer collectively to Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P.; and references to “Fund III” refer collectively to Lime Rock Resources III-A, L.P. and Lime Rock Resources III-C, L.P. References to “Lime Rock Resources” refer collectively to Fund I, Fund II and Fund III.
Our properties are located in the Permian Basin region in West Texas and Southeast New Mexico, the Mid-Continent region in Oklahoma and East Texas and the Gulf Coast region in Texas. We conduct our operations through our wholly owned subsidiary, LRE Operating, LLC (“OLLC”).
We own 100% of LRE Finance Corporation (“LRE Finance”). LRE Finance was organized for the purpose of co-issuing our debt securities and has no material assets or liabilities other than as co-issuer of our debt securities, if and when issued. Its activities are limited to co-issuing our debt securities and engaging in activities related thereto.
Merger with Vanguard Natural Resources, LLC
On April 20, 2015, we entered into a Purchase Agreement and Plan of Merger (the “Merger Agreement”) with Vanguard Natural Resources, LLC (“Vanguard”), Lighthouse Merger Sub, LLC, a wholly owned indirect subsidiary of Vanguard (“Merger Sub” and together with Vanguard, the “Vanguard Entities”), Lime Rock Management, Fund I, Fund II (together with the Fund I and Lime Rock Management, the “GP Sellers”) and LRE GP, LLC (our “General Partner” and together with the GP Sellers and the Partnership, the “Partnership Entities”). Upon the terms and conditions set forth in the Merger Agreement, Merger Sub will be merged with and into the Partnership, with the Partnership continuing as the surviving entity and as a wholly owned subsidiary of Vanguard (the “Merger”) and, at the same time, all of the limited liability company interests in our General Partner will be acquired by Vanguard. Based upon the recommendation of the conflicts committee of the board of directors of our General Partner (the “Board”), the Board approved the Merger Agreement on April 20, 2015.
At the effective time of the Merger (the “Effective Time”), each of our common units issued and outstanding immediately prior to the Effective Time will be converted into the right to receive 0.550 common units representing limited liability company interests in Vanguard (“Vanguard Units”) or, in the case of fractional Vanguard Units, cash (without interest and rounded up to the nearest whole cent) in an amount equal to the product of (i) such fractional part of a Vanguard Unit multiplied by (ii) the average closing price for a Vanguard Unit as reported on the NASDAQ Global Select Market (the “NASDAQ”) for the ten consecutive full trading days ending at the close of trading on the full trading day immediately preceding the closing date of the transactions contemplated by the Merger Agreement (the “Closing Date”). Each of our restricted common units that is outstanding pursuant to the 2011 LTIP will vest immediately prior to the Effective Time and be converted into the right to receive Vanguard Units. In addition, on the Closing Date, Vanguard will issue and deliver to the GP Sellers 12,320 Vanguard Units in exchange for all of the limited liability interests in our General Partner (the “GP Equity Consideration”).
As a condition to closing of transactions contemplated under the Merger Agreement, the parties have agreed to execute and deliver a Termination and Continuing Obligations Agreement (the “Termination Agreement”) substantially in the form attached as an exhibit to the Merger Agreement. Pursuant to the Termination Agreement, (i) that certain Omnibus Agreement, entered into, and effective as of, November 16, 2011 (the “Omnibus Agreement”), by and among us, our General Partner, OLLC, Fund I, LRR GP, LLC, the ultimate general partner of each of the
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Fund I entities, and Lime Rock Management, will be terminated and (ii) the Fund I entities, severally and in proportion to each entity’s Property Contributor Percentage (as defined in the Omnibus Agreement), will agree to indemnify the Partnership, our General Partner, OLLC and all of our and their respective subsidiaries from and against any losses arising out of any federal, state or local income tax liabilities attributable to the ownership or operation of the oil and natural gas properties owned or leased by any of the Partnership, our General Partner, OLLC or our or their respective subsidiaries prior to the closing of our initial public offering. The indemnification obligations of Fund I under the Termination Agreement will survive until the first anniversary of the Closing Date.
The Partnership Entities and the Vanguard Entities have each made certain representations and warranties and agreed to certain covenants in the Merger Agreement. Each of the Partnership, our General Partner and Vanguard has agreed, among other things, subject to certain exceptions, to conduct its respective business in the ordinary course during the period between the execution of the Merger Agreement and the Effective Time (unless the Merger Agreement is earlier terminated in accordance with its terms). In addition, we have agreed not to solicit alternative business combination transactions during such period, and, subject to certain exceptions, not to engage in discussions or negotiations regarding any alternative business combination transactions during such period.
The closing of the Merger is subject to the satisfaction or waiver of certain customary conditions, including, among others, (i) the approval of the Merger Agreement by our unitholders; (ii) the registration statement on Form S-4 used to register the Vanguard Units to be issued in the Merger being declared effective by the Securities and Exchange Commission (the “SEC”); (iii) the approval for listing on the NASDAQ of the Vanguard Units to be issued in the Merger; (iv) subject to specified materiality standards, the accuracy of the representations and warranties of, and the performance of all covenants by, the parties; (v) the delivery of certain tax opinions; and (vi) entry into the Termination Agreement by the parties thereto.
The Merger Agreement contains certain termination rights for each of the Partnership and Vanguard, including, among others, if (i) the Merger is not consummated on or before December 31, 2015; (ii) the requisite approval of the Merger Agreement by our unitholders is not obtained; and (iii) the other party breaches a representation, warranty or covenant, and such breach results in the failure of certain closing conditions to be satisfied (a “terminable breach”). The Merger Agreement also provides that (a) we may terminate the Merger Agreement to enter into a third party’s “superior proposal” and (b) Vanguard may terminate the Merger Agreement if the Board changes its recommendation to our unitholders to approve the Merger Agreement (a “Partnership Change in Recommendation”); provided, in each case, that we pay Vanguard the Termination Fee (as described below).
The Merger Agreement provides for the payment of a termination fee of approximately $7.3 million (the “Termination Fee”) by the Partnership to Vanguard upon the termination of the Merger Agreement under specified circumstances, including if: (i) (a) prior to our unitholder meeting, a third party proposal has been publicly submitted, publicly proposed or publicly disclosed and has not been withdrawn at the time of such meeting, (b) thereafter, the Merger Agreement is terminated in accordance with its terms under specified circumstances, and (c) prior to the date that is 12 months after the date of the Merger Agreement is terminated, we enter into or consummate any definitive agreement related to a third party proposal; (ii) Vanguard terminates the Merger Agreement due to a Partnership Change in Recommendation; or (iii) we terminate the Merger Agreement to enter into a third party’s “superior proposal.” The Merger Agreement also provides that the non-terminating party may be required to pay the other party’s expenses (up to a maximum of approximately $1.2 million (the “Expenses”)) if either party terminates the Merger Agreement due to a terminable breach by the other party. If the Termination Fee is payable at a time when Vanguard has received or concurrently receives payment from us in respect of Expenses, the Termination Fee will be reduced by the amount of such Expenses received by Vanguard.
The special meeting of unitholders to approve the Merger Agreement is scheduled to occur on September 10, 2015. Our unitholders of record at the close of business on July 24, 2015 will be entitled to receive notice of the special meeting and vote at the special meeting.
2. | Summary of Significant Accounting Policies |
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Our accounting policies are set forth in the audited consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2014 (“2014 Annual Report”) and are supplemented by the notes to these unaudited consolidated condensed financial statements. There have been no significant changes to these policies, and these unaudited consolidated condensed financial statements should be read in conjunction with the audited consolidated financial statements and notes in our 2014 Annual Report.
Basis of presentation
These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the SEC regarding interim financial reporting. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete consolidated financial statements and should be read in conjunction with the audited consolidated financial statements in our 2014 Annual Report. While the year-end condensed balance sheet data was derived from audited financial statements, this interim report does not include all disclosures required by GAAP for annual periods. These unaudited interim consolidated condensed financial statements reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for the periods presented.
Recent accounting pronouncements
On April 10, 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” ASU No. 2014-08 amends the definition of a discontinued operation and requires entities to provide additional disclosures about discontinued operations as well as disposal transactions that do not meet the discontinued-operations criteria. We adopted ASU No. 2014-08 on January 1, 2015. The adoption of ASU No. 2014-08 did not have a material impact on our consolidated condensed financial position, results of operations or cash flows.
On May 28, 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” ASU No. 2014-09 outlined a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The core principle of the revenue model is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In July 2015, the FASB approved a delay in adoption for public entities and ASU No. 2014-09 is effective for annual periods beginning after December 15, 2017.We are still evaluating the impact of our adoption of ASU No. 2014-09.
On August 27, 2014, the FASB issued ASU No. 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.” ASU No. 2014-15 provides guidance on determining when and how reporting entities must disclose going concern uncertainties in their financial statements. The new standard requires management to perform interim and annual assessments of an entity’s financial statements (or within one year after the date on which the financial statements are available to be issued, when applicable). Further, an entity must provide certain disclosures if there is “substantial doubt about the entity’s ability to continue as a going concern.” ASU No. 2014-15 is effective for annual periods ending after December 15, 2016, and interim periods thereafter; early adoption is permitted. We do not expect the adoption of ASU No. 2014-15 to have a material impact on our financial statement disclosures.
On February 18, 2015, the FASB issued No. ASU 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis.” ASU No. 2015-02 applies to entities in all industries and provides a new scope exception to registered money market funds and similar unregistered money market funds. The standard makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the variable interest entities guidance. ASU No. 2015-02 is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015. We are still evaluating the impact of our adoption of ASU No. 2015-02.
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On April 7, 2015, the FASB issued ASU No. 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” ASU No. 2015-03 changes the presentation of debt issuance costs in financial statements. The new standard requires entities to present debt issuance costs as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs is reported as interest expense. ASU No. 2015-03 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, and interim periods beginning after December 15, 2016. Early adoption is allowed for all entities for financial statements that have not been previously issued. Entities would apply the new guidance retrospectively to all prior periods. We do not expect the adoption of ASU No. 2015-03 to have a material impact on our financial statements or disclosures.
3. | Acquisitions |
Third Party Acquisition
On October 1, 2014, we completed an acquisition of oil and natural gas properties in the Stroud field located in Lincoln and Creek Counties, Oklahoma for a purchase price of $38.0 million, subject to customary purchase price adjustments (the “October 2014 Acquisition”) from an unrelated third party. We paid total cash consideration of $38.2 million at closing. The October 2014 Acquisition was effective September 1, 2014. In January 2015, we paid $0.2 million in cash to the seller related to post-closing adjustments to the purchase price. We financed the acquisition with borrowings under our revolving credit facility (Note 7).
The October 2014 Acquisition was accounted for under the acquisition method of accounting, whereby the purchase price was allocated to the assets acquired and liabilities assumed based on their fair values, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill (or shortfall of purchase price versus net fair value recorded as bargain purchase). Based on the purchase price allocation for October 2014 Acquisition, no goodwill or bargain purchase was recognized. The cash consideration paid for the October 2014 Acquisition and the assets and liabilities recognized are presented in the table below (in thousands, except for per unit amounts):
Property and equipment, net | $ | 38,848 | ||
Asset retirement obligations | (691 | ) | ||
Net assets | $ | 38,157 | ||
The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) reserves, including risk adjustments for probable and possible reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; (v) future cash flows; and (vi) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by our management at the time of the valuation and are subject to change.
The following unaudited pro forma information shows the pro forma effects of the October 2014 Acquisition. The unaudited pro forma information assumes the transaction occurred on January 1, 2014. The pro forma results of operations have been prepared by adjusting our historical results to include the historical results of the acquired assets based on information provided by the seller, our knowledge of the acquired properties and the impact of our purchase price allocation. We believe the assumptions used provide a reasonable basis for reflecting the pro forma significant effects directly attributable to the acquisition. The pro forma results of operations do not include any cost savings or other synergies that may result from the October 2014 Acquisition or any estimated costs that have been or will be incurred to integrate the assets. The following unaudited pro forma information does not purport to represent what our results of operations would have been if such acquisition had occurred on January 1, 2014 (in thousands).
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Three Months Ended | Six Months Ended | |||||||
June 30, 2014 | June 30, 2014 | |||||||
Total revenues | $ | 19,770 | $ | 48,113 | ||||
Net income (loss) available to unitholders | (6,049 | ) | (2,052 | ) | ||||
Basic and diluted net income (loss) per unit | (0.23 | ) | (0.08 | ) | ||||
4. | Fair Value Measurements |
Our financial instruments, including cash and cash equivalents and accounts receivable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments. All such financial instruments are considered Level 1 instruments. The carrying value of our senior secured revolving credit facility and term loan, including the current portion, approximates fair value, as interest rates are variable based on prevailing market rates and are therefore considered Level 1 instruments. Our financial and non-financial assets and liabilities that are measured on a recurring basis are measured and reported at fair value.
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. GAAP establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of fair value hierarchy are as follows:
Level 1—Defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities.
Level 2—Defined as inputs other than quoted prices in active markets that are either directly or indirectly observable for the asset or liability.
Level 3—Defined as unobservable inputs for use when little or no market data exists, requiring an entity to develop its own assumptions for the asset or liability.
We utilize the most observable inputs available for the valuation technique used. The financial assets and liabilities are classified in their entirety based on the lowest level of input that is of significance to the fair value measurement. The following table describes, by level within the hierarchy, the fair value of our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2015 and December 31, 2014 (in thousands).
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
June 30, 2015 | ||||||||||||||||
Assets: | ||||||||||||||||
Commodity derivative instruments | $ | — | $ | 69,246 | $ | — | $ | 69,246 | ||||||||
Liabilities: | ||||||||||||||||
Commodity derivative instruments | — | 877 | — | 877 | ||||||||||||
Interest rate derivative instruments | — | 3,741 | — | 3,741 | ||||||||||||
December 31, 2014 | ||||||||||||||||
Assets: | ||||||||||||||||
Commodity derivative instruments | $ | — | $ | 84,464 | $ | — | $ | 84,464 | ||||||||
Liabilities: | ||||||||||||||||
Commodity derivative instruments | — | 788 | — | 788 | ||||||||||||
Interest rate derivative instruments | — | 3,144 | — | 3,144 | ||||||||||||
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All fair values reflected in the table above and on the consolidated condensed balance sheets have been adjusted for non-performance risk. The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.
Commodity Derivative Instruments—The fair value of the commodity derivative instruments is estimated using a combined income and market valuation methodology based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes.
Interest Rate Derivative Instruments—The fair value of the interest rate derivative instruments is estimated using a combined income and market valuation methodology based upon forward interest rates and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes.
5. | Property and Equipment |
Property and equipment is stated at cost less accumulated depletion, depreciation and impairment and consisted of the following (in thousands):
June 30, 2015 | December 31, 2014 | |||||||
Oil and natural gas properties (successful efforts method) | $ | 970,906 | $ | 954,819 | ||||
Unproved properties | 1,220 | 1,235 | ||||||
Other property and equipment | 272 | 272 | ||||||
972,398 | 956,326 | |||||||
Accumulated depletion, depreciation and impairment | (559,893 | ) | (506,368 | ) | ||||
Total property and equipment, net | $ | 412,505 | $ | 449,958 | ||||
We recorded $8.7 million of depletion and depreciation expense for each of the three months ended June 30, 2015 and 2014. We recorded $17.6 million and $17.1 million of depletion and depreciation expense for the six months ended June 30, 2015 and 2014, respectively.
We perform an impairment analysis of our oil and natural gas properties on a quarterly basis due to the volatility in commodity prices. For the three months ended June 30, 2015, we recorded a total non-cash impairment charge of $0.3 million to impair the value of our proved oil and natural gas properties in the Mid-Continent region. We did not record any impairment charges in the three months ended June 30, 2014. For the six months ended June 30, 2015, we recorded a total non-cash impairment charge of $36.0 million to impair the value of our proved oil and natural gas properties in the Permian Basin, Gulf Coast, and the Mid-Continent regions. This impairment charge reduced the regions’ carrying values to an estimated fair value of $411.3 million as of June 30, 2015. We did not record any impairment charges in the six months ended June 30, 2014.
These impairments of proved and unproved oil and natural gas properties were recorded because the net capitalized costs of the properties exceeded the fair value of the properties as measured by estimated cash flows reported in an internal reserve report. Further, our unproved properties were impaired based on the drilling locations for the probable and possible reserves becoming uneconomic at the lower future expected natural gas prices and our future expected drilling schedules. These reports are based upon future oil and natural gas prices, which are based on observable inputs, adjusted for basis differentials. These are classified as Level 3 fair value measurements. The fair values of our properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of the properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market‑based weighted average cost of capital rate. The underlying commodity prices embedded in the our estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that management believes will impact realizable prices. Furthermore, significant assumptions in valuing the proved reserves included the reserve quantities, anticipated drilling and operating costs, anticipated production taxes, future
10
expected natural gas prices and basis differentials, anticipated drilling schedules, anticipated production declines, and an appropriate discount rate commensurate with the risk of the underlying cash flow estimates. Cash flow estimates for the impairment testing excluded derivative instruments used to mitigate the risk of lower future natural gas prices. Significant assumptions in valuing the unproved reserves included the evaluation of the probable and possible reserves, future expected natural gas prices and basis differentials, and anticipated drilling schedules.
These asset impairments have no impact on cash flows, liquidity positions, or debt covenants. If future oil or natural gas prices decline further, the estimated undiscounted future cash flows for the proved oil and natural gas properties may not exceed the net capitalized costs for our properties and a non-cash impairment charge may be required to be recognized in future periods.
6. | Asset Retirement Obligations |
The following is a summary of our asset retirement obligations as of and for the six months ended June 30, 2015 (in thousands):
Beginning of period | $ | 41,604 | |
Acquisitions | 13 | ||
Revisions to previous estimates | 5 | ||
Liabilities incurred | 106 | ||
Liabilities settled | (46 | ) | |
Accretion expense | 1,029 | ||
End of period | 42,711 | ||
Current portion of asset retirement obligations | (2,153 | ) | |
Asset retirement obligations — non-current | $ | 40,558 | |
7. | Long-Term Debt |
Credit Agreement
We, as guarantor, and our wholly owned subsidiary, OLLC, as borrower, are parties to a five-year, $750 million senior secured revolving credit facility, as amended (the “Credit Agreement”), that matures on October 1, 2019. The Intercreditor Agreement (as described below) limits the amount of indebtedness outstanding at any time under the Credit Agreement (including undrawn amounts under letters of credit) to an amount not to exceed $500 million in the aggregate. The Credit Agreement is reserve-based and we are permitted to borrow under our credit facility an amount up to the borrowing base, which was $244 million as of June 30, 2015. Our borrowing base, which is primarily based on the estimated value of our oil, natural gas liquids (“NGL”), and natural gas properties and our commodity derivative contracts, is subject to redetermination semi-annually by our lenders at their sole discretion. As of June 30, 2015, we were in compliance with all covenants contained in the Credit Agreement.
In May 2015, we entered into the Fifth Amendment (“Fifth Credit Agreement Amendment”) to our Credit Agreement. The Fifth Credit Agreement Amendment, among other things, (i) increased the interest rate margins applicable to the loans with margins ranging from 2.00% to 3.10% for Eurodollar loans, and from 1.00% to 2.10% for base rate loans, in each case based on utilization of the credit facility, (ii) increased the commitment fee applicable to the unused portion of the borrowing base with amounts ranging from 0.375% to 0.800% based on utilization of the credit facility, (iii) restricted the payments of distributions to $10.6 million through September 30, 2015; however, after October 1, 2015, distributions are subject to a minimum of 15% availability under a conforming borrowing base amount, and (iv) decreased the borrowing base to $245.0 million. Pursuant to the amendment, the borrowing base began to decrease in the amount of $1.0 million per month, beginning in June 2015 and continuing until the next redetermination of the borrowing base in the fall of 2015. The borrowing base of the Credit Agreement will revert to $195.0 million upon the earlier of November 1, 2015 and a termination of the Merger Agreement.
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Term Loan Agreement
We, as parent guarantor, and our wholly owned subsidiary, OLLC, as borrower, are parties to a Second Lien Credit Agreement (the “Term Loan Agreement”). The Term Loan Agreement provides for a $50 million senior secured second lien term loan to OLLC. OLLC borrowed $50 million under the Term Loan Agreement and used the borrowings to repay outstanding borrowings under the Credit Agreement.
The Term Loan Agreement contains various covenants and restrictive provisions as described in our 2014 Annual Report. As of June 30, 2015, we were in compliance with the leverage and current ratios contained in our Term Loan Agreement. We are required to test the asset coverage ratio at specified intervals as described in the Term Loan Agreement, including during the redetermination of our borrowing base under our Credit Agreement. We were not in compliance with the asset coverage ratio during the borrowing base redetermination in the second quarter of 2015; however, we received a waiver from our lender under the Term Loan Agreement for the asset coverage ratio covenant.
The obligations under the Term Loan Agreement and the Credit Agreement are governed by an Intercreditor Agreement with OLLC as borrower and the Partnership as parent guarantor, which (i) provides that any liens on the assets and properties of OLLC, the Partnership or any of their subsidiaries securing the indebtedness under the Term Loan Agreement are subordinate to liens on the assets and properties of OLLC, the Partnership or any of their subsidiaries securing indebtedness under the Credit Agreement and derivative contracts with lenders and their affiliates and (ii) sets forth the respective rights, obligations and remedies of the lenders under the Credit Agreement with respect to their first-priority liens and the lenders under the Term Loan Agreement with respect to their second-priority liens.
In May 2015, we entered into the Fifth Amendment (“Fifth Term Loan Amendment”) to our Term Loan Agreement. The Fifth Term Loan Amendment, among other things, amended the Term Loan Agreement to (i) increase the interest rate margins applicable to the loan with margins for Eurodollar loans and Alternate Base Rate loans increasing to 9.50% and 8.50%, respectfully, after September 30, 2015, and (ii) restrict the payments of distributions to $10.6 million through September 30, 2015; however, after October 1, 2015, distributions are subject to having a minimum of 15% availability under a conforming borrowing base amount.
As of June 30, 2015, we had $285.0 million of outstanding debt and accrued interest was approximately $0.2 million. As of December 31, 2014, we had $280.0 million of outstanding debt and accrued interest was approximately $0.2 million.
Interest expense for the three months ended June 30, 2015 and 2014 was $3.1 million and $2.6 million, respectively. Interest expense for the six months ended June 30, 2015 and 2014 was $5.9 million and $5.1 million, respectively. As of June 30, 2015 and December 31, 2014, our weighted average interest rate on our outstanding indebtedness was 5.27% and 3.81%, respectively. Please refer to Note 8 below for a discussion of our interest rate derivative contracts.
8. | Derivatives |
We are exposed to commodity price and interest rate risk and consider it prudent to periodically reduce our exposure to cash flow variability resulting from commodity price changes and interest rate fluctuations. Accordingly, we enter into derivative instruments to manage our exposure to commodity price fluctuations, locational differences between a published index and the NYMEX futures on natural gas or crude oil productions, and interest rate fluctuations.
Under commodity swap agreements, we exchange a stream of payments over time according to specified terms with another counterparty. Specifically for commodity price swap agreements, we agree to pay an adjustable or floating price tied to an agreed upon index for the commodity, either gas or oil, and in return receive a fixed price based on notional quantities. Under basis swap agreements, we agree to pay an adjustable or floating price tied to
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two agreed upon indices for gas and in return receive the differential between a floating index and fixed price based on notional quantities.
The interest rate swap agreements effectively fix our interest rate on amounts borrowed under the credit facility. The purpose of these instruments is to mitigate our existing exposure to unfavorable interest rate changes. Under interest rate swap agreements, we pay a fixed interest rate payment on a notional amount in exchange for receiving a floating amount based on LIBOR on the same notional amount.
At June 30, 2015, we had the following open commodity derivative contracts:
Index | 2015 | 2016 | 2017 | 2018 | |||||||||||||
Natural gas positions | |||||||||||||||||
Price swaps (MMBtu) | NYMEX-HH | 2,688,648 | 5,433,888 | 5,045,760 | 3,452,172 | ||||||||||||
Weighted average price | $ | 5.75 | $ | 4.29 | $ | 4.61 | $ | 4.05 | |||||||||
Basis swaps (MMBtu) | (1) | 2,601,807 | 2,877,047 | — | — | ||||||||||||
Weighted average price | $ | (0.1666 | ) | $ | (0.1115 | ) | $ | — | $ | — | |||||||
Oil positions | |||||||||||||||||
Price swaps (Bbl) | NYMEX-WTI | 360,683 | 610,131 | 473,698 | 562,524 | ||||||||||||
Weighted average price | $ | 93.42 | $ | 87.27 | $ | 84.34 | $ | 82.26 | |||||||||
Basis swaps (Bbl) | Argus- | 187,000 | 364,800 | — | — | ||||||||||||
Weighted average price | Midland-Cushing | $ | (3.2500 | ) | $ | (1.0500 | ) | $ | — | $ | — | ||||||
NGL positions | |||||||||||||||||
Price swaps (Bbl) | Mont Belvieu | 112,877 | — | — | — | ||||||||||||
Weighted average price | $ | 34.45 | $ | — | $ | — | $ | — | |||||||||
(1) | Our natural gas basis swaps are traded on the following indices: Centerpoint East, Houston Ship Channel, WAHA and TEXOK. |
At December 31, 2014, we had the following open commodity derivative contracts:
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Index | 2015 | 2016 | 2017 | 2018 | |||||||||||||
Natural gas positions | |||||||||||||||||
Price swaps (MMBtu) | NYMEX-HH | 5,500,236 | 5,433,888 | 5,045,760 | 2,374,800 | ||||||||||||
Weighted average price | $ | 5.72 | $ | 4.29 | $ | 4.61 | $ | 4.28 | |||||||||
Basis swaps (MMBtu) | (1) | 5,326,559 | 2,877,047 | — | — | ||||||||||||
Weighted average price | $ | (0.1661 | ) | $ | (0.1115 | ) | $ | — | $ | — | |||||||
Oil positions | |||||||||||||||||
Price swaps (Bbl) | NYMEX-WTI | 757,321 | 610,131 | 473,698 | 562,524 | ||||||||||||
Weighted average price | $ | 93.16 | $ | 87.27 | $ | 84.34 | $ | 82.26 | |||||||||
Basis swaps (Bbl) | Argus- | 397,035 | — | — | — | ||||||||||||
Weighted average price | Midland-Cushing | $ | (3.4087 | ) | $ | — | $ | — | $ | — | |||||||
NGL positions | |||||||||||||||||
Price swaps (Bbl) | Mont Belvieu | 236,149 | — | — | — | ||||||||||||
Weighted average price | $ | 34.46 | $ | — | $ | — | $ | — | |||||||||
(1) | Our natural gas basis swaps are traded on the following indices: Centerpoint East, Houston Ship Channel, WAHA and TEXOK. |
At June 30, 2015, we had the following interest rate swap derivative contracts (in thousands):
Notional | |||||||||||
Effective | Maturity | Amount | Average % | Index | |||||||
February 2015 | February 2017 | $ | 75,000 | 1.72500 | % | LIBOR | |||||
February 2015 | February 2017 | 75,000 | 1.72750 | % | LIBOR | ||||||
June 2015 | June 2017 | 70,000 | 1.42750 | % | LIBOR | ||||||
At December 31, 2014, we had the following interest rate swap derivative contracts (in thousands):
Notional | |||||||||||
Effective | Maturity | Amount | Average % | Index | |||||||
February 2012 | February 2015 | $ | 150,000 | 0.51750 | % | LIBOR | |||||
February 2015 | February 2017 | 75,000 | 1.72500 | % | LIBOR | ||||||
February 2015 | February 2017 | 75,000 | 1.72750 | % | LIBOR | ||||||
June 2012 | June 2015 | 70,000 | 0.52375 | % | LIBOR | ||||||
June 2015 | June 2017 | 70,000 | 1.42750 | % | LIBOR | ||||||
Effect of Derivative Instruments – Balance Sheet
The fair value of our commodity and interest rate derivative instruments is included in the tables below (in thousands):
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As of December 31, 2014 | ||||||||||||||||
Current | Long-term | Current | Long-term | |||||||||||||
Assets | Assets | Liabilities | Liabilities | |||||||||||||
Interest rate | ||||||||||||||||
Swaps | $ | — | $ | — | $ | 2,781 | $ | 960 | ||||||||
Gross fair value | — | — | 2,781 | 960 | ||||||||||||
Netting arrangements | — | — | — | — | ||||||||||||
Net recorded fair value | $ | — | $ | — | $ | 2,781 | $ | 960 | ||||||||
Sale of natural gas production | ||||||||||||||||
Price swaps | $ | 10,753 | $ | 11,022 | $ | — | $ | — | ||||||||
Basis swaps | — | — | 184 | 89 | ||||||||||||
Sale of crude oil production | ||||||||||||||||
Price swaps | 19,662 | 26,137 | — | — | ||||||||||||
Basis swaps | — | 7 | 599 | 12 | ||||||||||||
Sale of NGLs | ||||||||||||||||
Price swaps | 1,672 | — | — | — | ||||||||||||
Gross fair value | 32,087 | 37,166 | 783 | 101 | ||||||||||||
Netting arrangements | — | (7 | ) | — | (7 | ) | ||||||||||
Net recorded fair value | $ | 32,087 | $ | 37,159 | $ | 783 | $ | 94 | ||||||||
As of December 31, 2014 | ||||||||||||||||
Current | Long-term | Current | Long-term | |||||||||||||
Assets | Assets | Liabilities | Liabilities | |||||||||||||
Interest rate | ||||||||||||||||
Swaps | $ | — | $ | — | $ | 2,327 | $ | 817 | ||||||||
Gross fair value | — | — | 2,327 | 817 | ||||||||||||
Netting arrangements | — | — | — | — | ||||||||||||
Net recorded fair value | $ | — | $ | — | $ | 2,327 | $ | 817 | ||||||||
Sale of natural gas production | ||||||||||||||||
Price swaps | $ | 14,732 | $ | 9,170 | $ | — | $ | — | ||||||||
Basis swaps | 1 | — | 286 | 232 | ||||||||||||
Sale of crude oil production | ||||||||||||||||
Price swaps | 27,544 | 29,370 | — | — | ||||||||||||
Basis swaps | — | — | 271 | — | ||||||||||||
Sale of NGLs | ||||||||||||||||
Price swaps | 3,648 | — | — | — | ||||||||||||
Gross fair value | 45,925 | 38,540 | 557 | 232 | ||||||||||||
Netting arrangements | (1 | ) | — | (1 | ) | — | ||||||||||
Net recorded fair value | $ | 45,924 | $ | 38,540 | $ | 556 | $ | 232 | ||||||||
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Effect of Derivative Instruments – Statements of Operations
The net gain (loss) amounts and classification related to derivative instruments for the periods indicated are as follows (in thousands):
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Commodity derivatives (revenue) | $ | (8,927 | ) | $ | (13,328 | ) | $ | 9,755 | $ | (18,950 | ) | |||||
Interest rate derivatives (other income (expense), net) | (322 | ) | (1,128 | ) | (1,673 | ) | (1,422 | ) | ||||||||
Credit Risk
All of our derivative transactions have been carried out in the over-the-counter market. The use of derivative instruments involves the risk that the counterparties may be unable to meet the financial terms of the transactions. We monitor the creditworthiness of each of our counterparties and assess the possibility of whether each counterparty to the derivative contract would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. We also have netting arrangements in place with each counterparty to reduce credit exposure. The derivative transactions are placed with major financial institutions that present minimal credit risks to us. Additionally, we consider ourselves to be of substantial credit quality and have the financial resources and willingness to meet our potential repayment obligations associated with the derivative transactions.
9. | Related Parties |
Ownership in Our General Partner by Lime Rock Management and its Affiliates
As of June 30, 2015, Lime Rock Management, an affiliate of Fund I, owned all of the Class A member interests in our general partner, Fund I owned all of the Class B member interests in our general partner and Fund II owned all of the Class C member interests in our general partner. In addition, Fund I owned an aggregate of approximately 30.5% of our outstanding common units, representing their limited partner interest in us. As of June 30, 2015, our general partner owned an approximate 0.1% general partner interest in us, represented by 22,400 general partner units, and all of our incentive distribution rights.
As more fully described in our 2014 Annual Report, we converted 2,240,000 subordinated units on a one-for-one basis into common units pursuant to the terms of our partnership agreement on May 16, 2014. We converted the remaining 4,480,000 subordinated units on a one-for-one basis into common units pursuant to the terms of our partnership agreement on February 13, 2015.
Contracts with our General Partner and its Affiliates
As more fully described in our 2014 Annual Report, we have entered into agreements with our general partner and its affiliates. For each of the three months ended June 30, 2015 and 2014, we paid Lime Rock Management approximately $0.4 million either directly or indirectly related to these agreements. For the six months ended June 30, 2015 and 2014, we paid Lime Rock Management approximately $0.8 million and $0.6 million either directly or indirectly related to these agreements, respectively.
In connection with the management of our business, Lime Rock Resources Operating Company, Inc. (“ServCo”), an affiliate of our general partner, provides services for invoicing and processing of payments to our vendors. Periodically, ServCo remits cash to us for the net working capital received on our behalf. Changes in the affiliates (payable)/receivable balances during the six months ended June 30, 2015 are included below (in thousands):
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Lime Rock | ||||||||||||
ServCo | Resources | Total | ||||||||||
Balance as of December 31, 2014 | $ | 5,436 | $ | 261 | $ | 5,697 | ||||||
Expenditures | (90,596 | ) | (263 | ) | (90,859 | ) | ||||||
Cash paid for expenditures | 93,084 | — | 93,084 | |||||||||
Revenues and other | (6,468 | ) | 2 | (6,466 | ) | |||||||
Balance as of June 30, 2015 | $ | 1,456 | $ | — | $ | 1,456 | ||||||
Distributions of Available Cash to Our General Partner and Affiliates
We will generally make cash distributions to our unitholders and our general partner pro rata. As of June 30, 2015, our general partner and its affiliates held 8,569,600 of our common units and 22,400 general partner units. During the six months ended June 30, 2015 and 2014, we paid cash distributions of $19.2 million and $26.0 million, respectively, to all unitholders as of the respective record dates.
We announced our second quarter 2015 distribution on July 17, 2015 as discussed in Note 15.
10. | Unitholders’ Equity |
At-the-Market Offering Program
On February 4, 2014, we launched an “at-the-market” offering program (the “ATM Program”) with MLV & Co. LLC (“MLV”) as sales agent. We may sell from time to time through MLV our common units representing limited partner interests having an aggregate offering amount of up to $75.0 million, subject to limitations as described in the Merger Agreement (described in Note 1). Any sales of common units under the ATM Program may be made by any method permitted by law deemed to be an “at-the-market offering” defined by Rule 415 of the Securities Act of 1933, as amended, (the “Securities Act”), including, without limitation, sales made directly on the New York Stock Exchange, or any other existing trading market for our common units or to or through a market maker.
Our second lien term loan requires that 50% of the net cash proceeds from any equity offering be used to repay borrowings outstanding under the term loan. During the six months ended June 30, 2015, we did not sell common units under the ATM Program.
Units Outstanding
As of June 30, 2015, we had 28,074,433 common units and 22,400 general partner units outstanding. As of June 30, 2015, Fund I owned 8,569,600 common units, representing a 30.5% limited partner interest in us.
General Partner Allocation of Loss
In accordance with our partnership agreement, the allocation of net loss cannot cause a unitholder to have a deficit balance. Deficit balances are carried by our general partner until net income is generated in a taxable period. Our general partner will recover losses from net income generated prior to the net income being allocated to the remaining unitholders.
11. | Net Income (Loss) Per Limited Partner Unit |
The following sets forth the calculation of net income (loss) per limited partner unit for the following periods (in thousands, except per unit amounts):
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Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Net income (loss) available to unitholders | $ | (22,314 | ) | $ | (7,337 | ) | $ | (47,250 | ) | $ | (4,643 | ) | ||||
Less: General partner’s interest in net (income) loss | 7,595 | 7 | 9,434 | 4 | ||||||||||||
Limited partners’ interest in net income (loss) | (14,719 | ) | (7,330 | ) | (37,816 | ) | (4,639 | ) | ||||||||
Weighted average limited partner units outstanding: | ||||||||||||||||
Common units | 28,074 | 21,121 | 26,984 | 20,376 | ||||||||||||
Subordinated units | — | 5,612 | 1,089 | 6,163 | ||||||||||||
Total | $ | 28,074 | $ | 26,733 | $ | 28,073 | $ | 26,539 | ||||||||
Net income (loss) per limited partner | ||||||||||||||||
unit (basic and diluted) | $ | (0.52 | ) | $ | (0.27 | ) | $ | (1.35 | ) | $ | (0.17 | ) | ||||
Our subordinated units and restricted unit awards are considered to be participating securities for purposes of calculating our net income (loss) per limited partner unit, and accordingly, are included in basic computation as such. Net income (loss) per limited partner unit is determined by dividing the net income (loss) available to the common unitholders, after deducting our general partner’s interest in net income (loss), by the weighted average number of common units and subordinated units outstanding as of June 30, 2015 and 2014. The aggregate number of common units outstanding was 28,074,433, as of June 30, 2015. We did not have any subordinated units outstanding as of June 30, 2015. The aggregate number of common units and subordinated units outstanding was 22,674,390 and 4,480,000, respectively, as of June 30, 2014.
12. | Equity-Based Compensation |
On November 10, 2011, our General Partner adopted a long-term incentive plan (“2011 LTIP”) for employees, consultants and directors of our General Partner and its affiliates, including Lime Rock Management and ServCo, who perform services for us. The 2011 LTIP consists of unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, unit awards and other unit-based awards. The 2011 LTIP initially limits the number of units that may be delivered pursuant to vested awards to 1,500,000 common units. As of June 30, 2015, there were 1,025,013 units available for issuance under the 2011 LTIP. The 2011 LTIP is currently administered by our General Partner’s board of directors or a committee thereof.
The fair value of restricted units is determined based on the fair market value of the units on the date of grant. The outstanding restricted units vest in equal amounts (subject to rounding) over a three-year period following the date of grant and are entitled to receive quarterly distributions during the vesting period.
A summary of the status of the non-vested restricted units as of June 30, 2015 is presented below:
Number of Non-vested Restricted Units | Weighted Average Grant-date Fair Value | ||||||
Non-vested restricted units at December 31, 2014 | 361,957 | $ | 9.38 | ||||
Granted | 12,542 | 5.98 | |||||
Vested | (32,066 | ) | 12.53 | ||||
Forfeited | — | — | |||||
Non-vested restricted units at June 30, 2015 | 342,433 | 8.96 | |||||
As of June 30, 2015, there was approximately $2.3 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over a weighted average period of approximately 2.1
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years. There were 132,554 vested restricted units as of June 30, 2015. At the close of the Merger, all unvested restricted units will vest immediately.
13. | Subsidiary Guarantors |
We and LRE Finance, our 100 percent-owned subsidiary, filed a registration statement on Form S-3 with the SEC on August 28, 2013, and the SEC declared the registration statement effective on September 10, 2013. Securities that may be offered and sold include debt securities that are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act. LRE Finance may co-issue any debt securities issued by us pursuant to the registration statement. LRE Finance was formed solely for the purpose of co-issuing our debt securities and has no material assets or liabilities other than as co-issuer of our debt securities, if and when issued. OLLC, our 100 percent-owned subsidiary, may guarantee any debt securities issued by us and such guarantee will be full and unconditional, subject to customary release provisions. The guarantee will be released (i) automatically upon any sale, exchange or transfer of our equity interests in OLLC, (ii) automatically upon the liquidation and dissolution of OLLC, (iii) following delivery of notice to the trustee under the indenture related to the debt securities of the release of OLLC of its obligations under our revolving credit facility, and (iv) upon legal or covenant defeasance or other satisfaction of the obligations under the related debt securities. Other than LRE Finance, OLLC is our sole subsidiary, and thus, no other subsidiary will guarantee our debt securities.
Furthermore, we have no assets or operations independent of OLLC, and there are no significant restrictions upon the ability of OLLC to distribute funds to us by dividend or loan. Finally, none of our or OLLC’s assets represents restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X.
14. | Commitments and Contingencies |
Litigation
The following class action lawsuits (the “Lawsuits”) were filed in connection with the merger by purported LRR Energy, L.P. unitholders against us, our General Partner, our Board, Vanguard, Merger Sub and the other parties to the Merger Agreement (the ‘‘Defendants’’):
• | Barry Miller v. LRR Energy, L.P. et al., Case No. 11087-VCG, filed in the Court of Chancery of the State of Delaware on June 3, 2015 (“Miller Lawsuit”) |
• | Christopher Tiberio v. LRR Energy, L.P. et al., Cause No. 2015-39864, filed in the 334th Judicial District Court of Harris County, Texas on July 10, 2015 (“Tiberio Lawsuit”) |
• | Eddie Hammond v. LRR Energy, L.P. et al., Cause No. 2015-40154, filed in the 295th Judicial District Court of Harris County, Texas on July 13, 2015 (“Hammond Lawsuit”) |
• | Ronald Krieger v. LRR Energy, L.P. et al., Civil Action No. 4:15-cv-2017, filed in the United States District Court for the Southern District of Texas on July 14, 2015 (“Krieger Lawsuit”) |
On July 17, 2015, the Krieger Lawsuit was voluntarily dismissed without prejudice. On July 23, 2015 the Miller Lawsuit was also voluntarily dismissed without prejudice. On July 28, 2015 the Tiberio Lawsuit and the Hammond Lawsuit were both nonsuited without prejudice.
Prior to their dismissals, the Lawsuits alleged that the merger (a) provided inadequate consideration to our unitholders and alleged that we and our Board breached certain fiduciary duties to the common unitholders by accepting such inadequate consideration and (b) contained contractual terms that would dissuade other potential merger partners from making alternative proposals for us, including, but not limited to, the requirement that certain of our unitholders enter into a voting and support agreement, adoption of an allegedly unreasonable no solicitation clause, the notice provisions, and allowing our Board to withdraw its favorable recommendation only under extremely limited circumstances.
Prior to their dismissals, the Tiberio, Hammond, and Krieger Lawsuits also allege that the Vanguard Form S-4 Registration Statement filed with the SEC on June 16, 2015 failed to make all material disclosures and contained
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materially misleading statements about the merger in violation of Sections 14(a) and 20(a) of the Securities and Exchange Act of 1934 and SEC Rule 14a-9.
The Lawsuits sought to be certified as class actions, and asked that the court, among other relief, enjoin the merger, or rescind the merger in the event it was consummated, and award damages, attorneys’ fees and costs. We and the other Defendants believed the Lawsuits were without merit, denied the allegations in their entirety and requested voluntary dismissal from each of the plaintiffs. They were each dismissed. Therefore, neither we nor our General Partner is currently a party to any material legal proceedings.
15. | Subsequent Events |
Unit Distribution
On July 17, 2015, we announced that the Board declared a cash distribution for the second quarter of 2015 of $0.1875 per outstanding unit, or $0.75 on an annualized basis. The distribution will be paid on August 14, 2015 to all unitholders of record as of the close of business on July 31, 2015. The aggregate amount of the distribution will be $5.3 million.
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