(Mark One) | |||
x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||
For the quarterly period ended June 30, 2016 | |||
OR | |||
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Delaware | 61-1521161 | |
(State or Other Jurisdiction of Incorporation or Organization) | (I.R.S. Employer Identification No.) |
5847 San Felipe, Suite 3000 Houston, Texas | 77057 | |
(Address of Principal Executive Offices) | (Zip Code) |
x | Large accelerated filer | o | Accelerated filer | ||
o | Non-accelerated filer | o | Smaller reporting company | ||
(Do not check if a smaller reporting company) |
Page | ||
/day | = per day | Mcf | = thousand cubic feet | |
Bbls | = barrels | Mcfe | = thousand cubic feet of natural gas equivalents | |
Bcf | = billion cubic feet | MMBbls | = million barrels | |
Bcfe | = billion cubic feet equivalents | MMBOE | = million barrels of oil equivalent | |
BOE | = barrel of oil equivalent | MMBtu | = million British thermal units | |
Btu | = British thermal unit | MMcf | = million cubic feet | |
MBbls | = thousand barrels | MMcfe | = million cubic feet equivalent | |
MBOE | = thousand barrels of oil equivalent | NGLs | = natural gas liquids |
• | risks relating to any of our unforeseen liabilities; |
• | further declines in oil, natural gas liquids (“NGLs”) or natural gas prices; |
• | the level of success in exploitation, development and production activities; |
• | adverse weather conditions that may negatively impact development or production activities; |
• | the timing of exploitation and development expenditures; |
• | inaccuracies of reserve estimates or assumptions underlying them; |
• | revisions to reserve estimates as a result of changes in commodity prices; |
• | impacts to financial statements as a result of impairment write-downs; |
• | risks related to level of indebtedness and periodic redeterminations of the borrowing base under our reserve-based credit agreements; |
• | ability to comply with covenants contained in the agreements governing our indebtedness; |
• | ability to generate sufficient cash flows from operations to meet the internally funded portion of any capital expenditures budget; |
• | ability to generate sufficient cash flows to resume cash distributions; |
• | ability to obtain external capital to finance exploitation and development operations and acquisitions; |
• | federal, state and local initiatives and efforts relating to the regulation of hydraulic fracturing; |
• | failure of properties to yield oil or gas in commercially viable quantities; |
• | uninsured or underinsured losses resulting from oil and gas operations; |
• | inability to access oil and gas markets due to market conditions or operational impediments; |
• | the impact and costs of compliance with laws and regulations governing oil and gas operations; |
• | ability to replace oil and natural gas reserves; |
• | any loss of senior management or technical personnel; |
• | competition in the oil and gas industry; |
• | risks arising out of hedging transactions; |
• | the costs and effects of litigation; |
• | sabotage, terrorism or other malicious intentional acts (including cyber-attacks), war and other similar acts that disrupt operations or cause damage greater than covered by insurance; |
• | change to tax treatment; |
• | lack of sufficient cash flow to pay down our borrowing base deficiency; |
• | inability to access debt and equity capital markets and the unreasonable costs of, or our inability to access, alternative sources of capital; and |
• | material restructurings of a significant number of companies in the oil and gas industry, which could result in competitors having significantly less leverage than us and, thus, greater ability to acquire additional oil and gas properties and finance their development. |
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Revenues: | ||||||||||||||||
Oil sales | $ | 49,941 | $ | 44,011 | $ | 85,595 | $ | 79,801 | ||||||||
Natural gas sales | 32,431 | 39,897 | 69,302 | 95,651 | ||||||||||||
NGLs sales | 11,104 | 11,933 | 20,019 | 19,283 | ||||||||||||
Net gains (losses) on commodity derivative contracts | (68,610 | ) | (20,800 | ) | (36,851 | ) | 38,233 | |||||||||
Total revenues | 24,866 | 75,041 | 138,065 | 232,968 | ||||||||||||
Costs and expenses: | ||||||||||||||||
Production: | ||||||||||||||||
Lease operating expenses | 38,515 | 31,600 | 80,842 | 67,078 | ||||||||||||
Production and other taxes | 9,476 | 10,754 | 18,144 | 22,180 | ||||||||||||
Depreciation, depletion, amortization, and accretion | 38,786 | 63,175 | 86,839 | 130,015 | ||||||||||||
Impairment of oil and natural gas properties | 157,894 | 733,365 | 365,658 | 865,975 | ||||||||||||
Selling, general and administrative expenses | 13,408 | 9,142 | 24,430 | 18,193 | ||||||||||||
Total costs and expenses | 258,079 | 848,036 | 575,913 | 1,103,441 | ||||||||||||
Loss from operations | (233,213 | ) | (772,995 | ) | (437,848 | ) | (870,473 | ) | ||||||||
Other income (expense): | ||||||||||||||||
Interest expense | (23,932 | ) | (20,374 | ) | (49,636 | ) | (40,563 | ) | ||||||||
Net losses on interest rate derivative contracts | (2,135 | ) | (281 | ) | (6,825 | ) | (1,484 | ) | ||||||||
Net loss on acquisition of oil and natural gas properties | (1,665 | ) | — | (1,665 | ) | — | ||||||||||
Gain on extinguishment of debt | — | — | 89,714 | — | ||||||||||||
Other | 196 | 5 | 252 | 45 | ||||||||||||
Total other income (expense), net | (27,536 | ) | (20,650 | ) | 31,840 | (42,002 | ) | |||||||||
Net loss | $ | (260,749 | ) | $ | (793,645 | ) | $ | (406,008 | ) | $ | (912,475 | ) | ||||
Less: Net income attributable to non-controlling interests | (40 | ) | — | (64 | ) | — | ||||||||||
Net loss attributable to Vanguard unitholders | (260,789 | ) | (793,645 | ) | (406,072 | ) | (912,475 | ) | ||||||||
Distributions to Preferred unitholders | (6,689 | ) | (6,690 | ) | (13,379 | ) | (13,380 | ) | ||||||||
Net loss attributable to Common and Class B unitholders | $ | (267,478 | ) | $ | (800,335 | ) | $ | (419,451 | ) | $ | (925,855 | ) | ||||
Net loss per Common and Class B unit – basic and diluted | $ | (2.04 | ) | $ | (9.27 | ) | $ | (3.20 | ) | $ | (10.86 | ) | ||||
Weighted average Common units outstanding | ||||||||||||||||
Common units – basic & diluted | 131,015 | 85,875 | 130,772 | 84,816 | ||||||||||||
Class B units – basic & diluted | 420 | 420 | 420 | 420 |
June 30, 2016 | December 31, 2015 | |||||||
Assets | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 31,175 | $ | — | ||||
Trade accounts receivable, net | 87,879 | 115,200 | ||||||
Derivative assets | 116,862 | 236,886 | ||||||
Other current assets | 5,669 | 6,436 | ||||||
Total current assets | 241,585 | 358,522 | ||||||
Oil and natural gas properties, at cost | 4,692,747 | 4,961,218 | ||||||
Accumulated depletion, amortization and impairment | (3,681,745 | ) | (3,239,242 | ) | ||||
Oil and natural gas properties evaluated, net – full cost method | 1,011,002 | 1,721,976 | ||||||
Other assets | ||||||||
Goodwill | 506,046 | 506,046 | ||||||
Derivative assets | 17,176 | 80,161 | ||||||
Other assets | 51,898 | 28,887 | ||||||
Total assets | $ | 1,827,707 | $ | 2,695,592 | ||||
Liabilities and members’ equity | ||||||||
Current liabilities | ||||||||
Accounts payable: | ||||||||
Trade | $ | 2,737 | $ | 22,895 | ||||
Affiliates | 1,480 | 1,757 | ||||||
Accrued liabilities: | ||||||||
Lease operating | 11,705 | 19,910 | ||||||
Development capital | 10,315 | 26,726 | ||||||
Interest | 10,520 | 11,958 | ||||||
Production and other taxes | 34,647 | 40,472 | ||||||
Other | 3,850 | 10,378 | ||||||
Derivative liabilities | 99 | 356 | ||||||
Oil and natural gas revenue payable | 24,786 | 44,823 | ||||||
Distributions payable | — | 5,018 | ||||||
Current portion of long-term debt | 86,040 | — | ||||||
Other current liabilities | 16,023 | 17,715 | ||||||
Total current liabilities | 202,202 | 202,008 | ||||||
Long-term debt, net of current portion (Note 3) | 1,819,844 | 2,277,931 | ||||||
Derivative liabilities | 632 | — | ||||||
Asset retirement obligations, net of current portion | 258,929 | 262,432 | ||||||
Other long-term liabilities | 39,739 | 40,656 | ||||||
Total liabilities | 2,321,346 | 2,783,027 | ||||||
Commitments and contingencies (Note 7) | ||||||||
Members’ deficit (Note 8) | ||||||||
Cumulative Preferred units, 13,881,873 units issued and outstanding at June 30, 2016 and December 31, 2015 | 335,444 | 335,444 | ||||||
Common units, 131,041,849 units issued and outstanding at June 30, 2016 and 130,476,978 at December 31, 2015 | (843,985 | ) | (430,494 | ) | ||||
Class B units, 420,000 issued and outstanding at June 30, 2016 and December 31, 2015 | 7,615 | 7,615 | ||||||
Total VNR members’ deficit | (500,926 | ) | (87,435 | ) | ||||
Non-controlling interest in subsidiary | 7,287 | — | ||||||
Total members’ deficit | (493,639 | ) | (87,435 | ) | ||||
Total liabilities and members’ deficit | $ | 1,827,707 | $ | 2,695,592 |
Cumulative Preferred Units | Common Units | Class B | Non-controlling Interest | Total Members’ Equity (deficit) | ||||||||||||||||
Balance at January 1, 2015 | $ | 335,444 | $ | 1,191,057 | $ | 7,615 | $ | — | $ | 1,534,116 | ||||||||||
Issuance of Common units as consideration for the Eagle Rock Merger, net of merger costs of $5,560 | — | 253,068 | — | — | 253,068 | |||||||||||||||
Issuance of Common units as consideration for the LRE Merger, net of merger costs of $3,961 | — | 119,315 | — | — | 119,315 | |||||||||||||||
Issuance of Common units, net of offering costs of $593 | — | 35,544 | — | — | 35,544 | |||||||||||||||
Repurchase of units under the common unit buyback program | (2,399 | ) | — | — | (2,399 | ) | ||||||||||||||
Distributions to Preferred unitholders (see Note 8) | — | (26,760 | ) | — | — | (26,760 | ) | |||||||||||||
Distributions to Common and Class B unitholders (see Note 8) | — | (134,019 | ) | — | — | (134,019 | ) | |||||||||||||
Unit-based compensation | — | 16,874 | — | — | 16,874 | |||||||||||||||
Net loss | — | (1,883,174 | ) | — | — | (1,883,174 | ) | |||||||||||||
Balance at December 31, 2015 | $ | 335,444 | $ | (430,494 | ) | $ | 7,615 | $ | — | $ | (87,435 | ) | ||||||||
Issuance costs related to prior period equity transactions | — | 67 | — | — | 67 | |||||||||||||||
Distributions to Preferred unitholders (see Note 8) | — | (5,575 | ) | — | — | (5,575 | ) | |||||||||||||
Distributions to Common and Class B unitholders (see Note 8) | — | (8,014 | ) | — | — | (8,014 | ) | |||||||||||||
Unit-based compensation | — | 6,103 | — | — | 6,103 | |||||||||||||||
Net income (loss) | — | (406,072 | ) | — | 64 | (406,008 | ) | |||||||||||||
Non-controlling interest in subsidiary | — | — | — | 7,453 | 7,453 | |||||||||||||||
Potato Hills cash distribution to non-controlling interest | — | — | — | (230 | ) | (230 | ) | |||||||||||||
Balance at June 30, 2016 | $ | 335,444 | $ | (843,985 | ) | $ | 7,615 | $ | 7,287 | $ | (493,639 | ) |
Six Months Ended | ||||||||
June 30, | ||||||||
Operating activities | 2016 | 2015 | ||||||
Net loss | $ | (406,008 | ) | $ | (912,475 | ) | ||
Adjustments to reconcile net loss to net cash provided by operating activities: | ||||||||
Depreciation, depletion, amortization, and accretion | 86,839 | 130,015 | ||||||
Impairment of oil and natural gas properties | 365,658 | 865,975 | ||||||
Amortization of deferred financing costs | 2,348 | 1,937 | ||||||
Amortization of debt discount | 1,783 | 142 | ||||||
Compensation related items | 6,103 | 7,420 | ||||||
Net (gains) losses on commodity and interest rate derivative contracts | 43,676 | (36,749 | ) | |||||
Cash settlements received on matured commodity derivative contracts | 142,476 | 80,620 | ||||||
Cash settlements paid on matured interest rate derivative contracts | (4,727 | ) | (1,980 | ) | ||||
Net loss on acquisition of oil and natural gas properties | 1,665 | — | ||||||
Gain on extinguishment of debt | (89,714 | ) | — | |||||
Changes in operating assets and liabilities: | ||||||||
Trade accounts receivable | 25,427 | 54,263 | ||||||
Other current assets | (96 | ) | (1,852 | ) | ||||
Net premiums received (paid) on commodity derivative contracts | 905 | (794 | ) | |||||
Accounts payable and oil and natural gas revenue payable | (40,220 | ) | (13,491 | ) | ||||
Payable to affiliates | (277 | ) | 443 | |||||
Accrued expenses and other current liabilities | (41,323 | ) | (11,823 | ) | ||||
Other assets | 4,495 | 3,064 | ||||||
Net cash provided by operating activities | 99,010 | 164,715 | ||||||
Investing activities | ||||||||
Additions to property and equipment | (36 | ) | (196 | ) | ||||
Potato Hills Gas Gathering System acquisition | (7,470 | ) | — | |||||
Additions to oil and natural gas properties | (35,469 | ) | (52,100 | ) | ||||
Acquisitions of oil and natural gas properties | — | (1,372 | ) | |||||
Deposits and prepayments of oil and natural gas properties | (5,342 | ) | (3,818 | ) | ||||
Proceeds from the sale of oil and natural gas properties | 285,590 | — | ||||||
Net cash provided by (used in) investing activities | 237,273 | (57,486 | ) | |||||
Financing activities | ||||||||
Proceeds from long-term debt | 93,500 | 117,500 | ||||||
Repayment of long-term debt | (377,228 | ) | (159,636 | ) | ||||
Proceeds from Common unit offerings, net | — | 32,737 | ||||||
Repurchase of units under the Common unit buyback program | — | (2,399 | ) | |||||
Distributions to Preferred unitholders | (6,690 | ) | (13,380 | ) | ||||
Distributions to Common and Class B unitholders | (11,917 | ) | (75,794 | ) | ||||
Potato Hills distribution to non-controlling interest | (230 | ) | — | |||||
Financing fees | (2,543 | ) | (2,125 | ) | ||||
Net cash used in financing activities | (305,108 | ) | (103,097 | ) | ||||
Net increase cash and cash equivalents | 31,175 | 4,132 | ||||||
Cash and cash equivalents, beginning of period | — | — | ||||||
Cash and cash equivalents, end of period | $ | 31,175 | $ | 4,132 |
Supplemental cash flow information: | ||||||||
Cash paid for interest | $ | 47,008 | $ | 38,525 | ||||
Non-cash financing and investing activity: | ||||||||
Asset retirement obligations, net | $ | 10,045 | $ | 789 | ||||
Fair value of derivatives acquired | $ | — | $ | 31,421 | ||||
Fair value of terminated derivative contracts | $ | — | $ | 28,517 |
• | the Green River Basin in Wyoming; |
• | the Permian Basin in West Texas and New Mexico; |
• | the Gulf Coast Basin in Texas, Louisiana, Mississippi and Alabama; |
• | the Anadarko Basin in Oklahoma and North Texas; |
• | the Piceance Basin in Colorado; |
• | the Big Horn Basin in Wyoming and Montana; |
• | the Arkoma Basin in Arkansas and Oklahoma; |
• | the Williston Basin in North Dakota and Montana; |
• | the Wind River Basin in Wyoming; and |
• | the Powder River Basin in Wyoming. |
(a) | Basis of Presentation and Principles of Consolidation: |
(b) | Oil and Natural Gas Properties: |
(c) | New Pronouncement Issued But Not Yet Adopted: |
(d) | Use of Estimates: |
(e) | Prior Year Financial Statement Presentation |
Consideration | ||||
Market value of Vanguard’s common units issued to LRE unitholders | $ | 123,276 | ||
Long-term debt assumed | 290,000 | |||
413,276 | ||||
Add: fair value of liabilities assumed | ||||
Accounts payable and accrued liabilities | 5,606 | |||
Other current liabilities | 9,018 | |||
Asset retirement obligations | 39,595 | |||
Amount attributable to liabilities assumed | 54,219 | |||
Less: fair value of assets acquired | ||||
Cash | 11,532 | |||
Trade accounts receivable | 6,822 | |||
Other current assets | 4,172 | |||
Oil and natural gas properties | 209,463 | |||
Derivative assets | 78,725 | |||
Other assets | 267 | |||
Amount attributable to assets acquired | 310,981 | |||
Goodwill | $ | 156,514 |
Consideration | ||||
Market value of Vanguard’s common units issued to Eagle Rock unitholders | $ | 258,282 | ||
Long-term debt assumed | 156,550 | |||
Replacement unit-based payment awards attributable to pre-combination services | 346 | |||
415,178 | ||||
Add: fair value of liabilities assumed | ||||
Accounts payable and accrued liabilities | 53,255 | |||
Other current liabilities | 2,206 | |||
Derivative liabilities | 2,201 | |||
Asset retirement obligations | 48,633 | |||
Deferred tax liability | 39,327 | |||
Other long-term liabilities | 1,244 | |||
Amount attributable to liabilities assumed | 146,866 | |||
Less: fair value of assets acquired | ||||
Cash | 6,971 | |||
Trade accounts receivable | 15,878 | |||
Other current assets | 15,664 | |||
Oil and natural gas properties | 462,715 | |||
Derivative assets | 90,234 | |||
Other assets | 9,734 | |||
Amount attributable to assets acquired | 601,196 | |||
Bargain Purchase Gain | $ | (39,152 | ) |
Pro forma | ||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
(in thousands, except per unit data) | ||||||||||||||||
Total revenues | $ | 17,480 | $ | 89,272 | $ | 120,523 | $ | 322,641 | ||||||||
Net loss | $ | (269,028 | ) | $ | (844,023 | ) | $ | (425,383 | ) | $ | (1,044,315 | ) | ||||
Net loss per unit | ||||||||||||||||
Common and Class B units - basic and diluted | $ | (2.05 | ) | $ | (6.54 | ) | $ | (3.25 | ) | $ | (8.09 | ) |
Pro forma | ||||||||
Three Months Ended June 30, 2016 | Six Months Ended June 30, 2016 | |||||||
(in thousands) | ||||||||
Revenues | $ | 7,386 | $ | 17,542 | ||||
Excess of revenues over direct operating expenses | $ | 6,222 | $ | 15,278 |
Three Months Ended | Six Months Ended | |||||||
June 30, 2016 | June 30, 2016 | |||||||
(in thousands) | ||||||||
Eagle Rock Merger | ||||||||
Revenues | $ | 14,208 | $ | 33,180 | ||||
Excess of revenues over direct operating expenses | $ | 7,182 | $ | 17,723 | ||||
LRE Merger | ||||||||
Revenues | $ | 11,800 | $ | 16,340 | ||||
Excess of revenues over direct operating expenses | $ | 5,362 | $ | 6,854 |
Amount Outstanding | ||||||||||||
Description | Interest Rate | Maturity Date | June 30, 2016 | December 31, 2015 | ||||||||
(in thousands) | ||||||||||||
Senior Secured Reserve-Based Credit Facility | Variable (1) | April 16, 2018 | $ | 1,406,500 | $ | 1,688,000 | ||||||
Senior Notes due 2019 | 8.375% (2) | June 1, 2019 | 51,120 | 51,120 | ||||||||
Senior Notes due 2020 | 7.875% (3) | April 1, 2020 | 381,830 | 550,000 | ||||||||
Senior Notes due 2023 | 7.00% | February 15, 2023 | 75,634 | — | ||||||||
Lease Financing Obligation | 4.16% | August 10, 2020 (4) | 22,441 | 24,668 | ||||||||
$ | 1,937,525 | $ | 2,313,788 | |||||||||
Less: | ||||||||||||
Current portion of debt under the Reserve-Based Credit Facility (5) | (86,040 | ) | — | |||||||||
Unamortized discount on Senior Notes | (15,131 | ) | (17,651 | ) | ||||||||
Unamortized deferred financing costs (6) | (11,915 | ) | (13,705 | ) | ||||||||
Current portion of Lease Financing Obligation | (4,595 | ) | (4,501 | ) | ||||||||
Total long-term debt | $ | 1,819,844 | $ | 2,277,931 |
(1) | Variable interest rate was 2.96% and 2.90% at June 30, 2016 and December 31, 2015, respectively. |
(2) | Effective interest rate was 21.45% at June 30, 2016 and December 31, 2015. |
(3) | Effective interest rate was 8.00% at June 30, 2016 and December 31, 2015. |
(4) | The Lease Financing Obligations expire on August 10, 2020, except for certain obligations which expire on July 10, 2021. |
(5) | Represents the remaining borrowing base deficiency obligation as of June 30, 2016 payable in five equal monthly installments through November 2016. |
(6) | In order to comply with Accounting Standards Update No. 2015-03, unamortized debt issuance costs have been reclassified from other assets to long-term debt on a retrospective basis. This reclassification had no impact on historical income from continuing operations or members’ equity. |
Borrowing Base Utilization Percentage | <25% | >25% <50% | >50% <75% | >75% <90% | >90% | ||||||||||
Eurodollar Loans Margin | 1.50 | % | 1.75 | % | 2.00 | % | 2.25 | % | 2.50 | % | |||||
ABR Loans Margin | 0.50 | % | 0.75 | % | 1.00 | % | 1.25 | % | 1.50 | % | |||||
Commitment Fee Rate | 0.50 | % | 0.50 | % | 0.375 | % | 0.375 | % | 0.375 | % | |||||
Letter of Credit Fee | 0.50 | % | 0.75 | % | 1.00 | % | 1.25 | % | 1.50 | % |
Gas | Oil | NGLs | |||||||||||||||||||
Contract Period | MMBtu | Weighted Average Fixed Price | Bbls | Weighted Average WTI Price | Bbls | Weighted Average Fixed Price | |||||||||||||||
July 1, 2016 – December 31, 2016 | 36,528,944 | $ | 4.36 | 938,283 | $ | 84.00 | 455,000 | $ | 30.31 | ||||||||||||
January 1, 2017 – December 31, 2017 | 53,725,260 | $ | 3.75 | 749,698 | $ | 85.70 | — | $ | — |
Oil | |||||||
Contract Period | Bbls | Weighted Average Fixed Price | |||||
January 1, 2017 – December 31, 2017 | 168,000 | $ | 91.25 |
Gas | Oil | |||||||||||||
Contract Period | MMBtu | Weighted Average Fixed Price | Bbls | Weighted Average Fixed Price | ||||||||||
July 1, 2016 – December 31, 2016 | 4,600,000 | $ | 4.25 | 312,800 | $ | 50.00 | ||||||||
January 1, 2017 – December 31, 2017 | 11,862,500 | $ | 3.01 | 365,000 | $ | 95.00 |
Gas | |||||||
Contract Period | MMBtu | Weighted Average Fixed Price | |||||
January 1, 2017 – December 31, 2017 | 2,062,500 | $ | 2.74 | ||||
January 1, 2018 – December 31, 2018 | 675,000 | $ | 2.74 |
Gas | |||||||||
Contract Period | MMBtu | Weighted Avg. Basis Differential ($/MMBtu) | Pricing Index | ||||||
July 1, 2016 – December 31, 2016 | 19,320,000 | $ | (0.20 | ) | Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential | ||||
January 1, 2017 – December 31, 2017 | 21,900,000 | $ | (0.20 | ) | Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential | ||||
July 1, 2016 – December 31, 2016 | 477,354 | $ | (0.08 | ) | Houston Ship Channel and NYMEX Henry Hub Basis Differential | ||||
July 1, 2016 – December 31, 2016 | 140,433 | $ | (0.10 | ) | TexOk and NYMEX Henry Hub Basis Differential | ||||
July 1, 2016 – December 31, 2016 | 788,896 | $ | (0.13 | ) | WAHA and NYMEX Henry Hub Basis Differential |
Oil | |||||||||
Contract Period | Bbls | Weighted Avg. Basis Differential ($/Bbl) | Pricing Index | ||||||
July 1, 2016 – December 31, 2016 | 486,000 | $ | (1.01 | ) | WTI Midland and WTI Cushing Basis Differential | ||||
July 1, 2016 – December 31, 2016 | 110,400 | $ | (0.43 | ) | West Texas Sour and WTI Cushing Basis Differential | ||||
July 1, 2016 – December 31, 2016 | 368,000 | $ | (14.25 | ) | WTI and West Canadian Select Basis Differential |
Gas | |||||||||||||||
Contract Period | MMBtu | Floor | Ceiling | Put Sold | |||||||||||
July 1, 2016 – December 31, 2016 | 6,440,000 | $ | 3.95 | $ | 4.25 | $ | 3.00 | ||||||||
January 1, 2017 – December 31, 2017 | 14,600,000 | $ | 3.88 | $ | 4.15 | $ | 3.31 |
Oil | |||||||||||||||
Contract Period | Bbls | Floor | Ceiling | Put Sold | |||||||||||
July 1, 2016 – December 31, 2016 | 533,600 | $ | 90.00 | $ | 96.18 | $ | 73.62 |
Gas | Oil | |||||||||||||
Contract Period | MMBtu | Put Sold ($/MMBtu) | Bbls | Put Sold ($/Bbl) | ||||||||||
July 1, 2016 – December 31, 2016 | 920,000 | $ | 3.00 | 73,600 | $ | 75.00 | ||||||||
January 1, 2017 – December 31, 2017 | 1,825,000 | $ | 3.50 | 73,000 | $ | 75.00 |
Oil | |||||||||||||||
Contract Period | Bbls | Bonus | Range Ceiling | Range Floor | |||||||||||
July 1, 2016 – December 31, 2016 | 92,000 | $ | 4.00 | $ | 100.00 | $ | 75.00 |
Oil | |||||||||||
Contract Period | Bbls | Floor Price ($/Bbl) | Ceiling Price ($/Bbl) | ||||||||
July 1, 2016 – December 31, 2016 | 322,000 | $ | 41.00 | $ | 50.57 |
Oil | |||||||
Contract Period | Bbls | Put Price ($/Bbl) | |||||
July 1, 2016 – December 31, 2016 | 184,000 | $ | 60.00 |
Period | Notional Amount | Fixed LIBOR Rates | |||||
July 1, 2016 to December 10, 2016 | $ | 20,000 | 2.17 | % | |||
July 1, 2016 to October 31, 2016 | $ | 40,000 | 1.65 | % | |||
July 1, 2016 to August 5, 2018 | $ | 30,000 | 2.25 | % | |||
July 1, 2016 to August 6, 2016 | $ | 25,000 | 1.80 | % | |||
July 1, 2016 to October 31, 2016 | $ | 20,000 | 1.78 | % | |||
July 1, 2016 to September 23, 2016 | $ | 75,000 | 1.15 | % | |||
July 1, 2016 to September 7, 2016 | $ | 25,000 | 1.25 | % | |||
July 1, 2016 to December 31, 2019 | $ | 175,000 | 2.32 | % | |||
July 1, 2016 to February 16, 2017 | $ | 75,000 | 1.73 | % | |||
July 1, 2016 to June 16, 2017 | $ | 70,000 | 1.43 | % | |||
July 1, 2016 to February 16, 2017 | $ | 75,000 | 1.73 | % | |||
Total | $ | 630,000 |
June 30, 2016 | ||||||||||||
Offsetting Derivative Assets: | Gross Amounts of Recognized Assets | Gross Amounts Offset in the Consolidated Balance Sheets | Net Amounts Presented in the Consolidated Balance Sheets | |||||||||
Commodity price derivative contracts | $ | 171,889 | $ | (25,165 | ) | $ | 146,724 | |||||
Interest rate derivative contracts | — | (12,686 | ) | (12,686 | ) | |||||||
Total derivative instruments | $ | 171,889 | $ | (37,851 | ) | $ | 134,038 | |||||
Offsetting Derivative Liabilities: | Gross Amounts of Recognized Liabilities | Gross Amounts Offset in the Consolidated Balance Sheets | Net Amounts Presented in the Consolidated Balance Sheets | |||||||||
Commodity price derivative contracts | $ | (25,828 | ) | $ | 25,165 | $ | (663 | ) | ||||
Interest rate derivative contracts | (12,754 | ) | 12,686 | (68 | ) | |||||||
Total derivative instruments | $ | (38,582 | ) | $ | 37,851 | $ | (731 | ) |
December 31, 2015 | ||||||||||||
Offsetting Derivative Assets: | Gross Amounts of Recognized Assets | Gross Amounts Offset in the Consolidated Balance Sheets | Net Amounts Presented in the Consolidated Balance Sheets | |||||||||
Commodity price derivative contracts | $ | 349,281 | $ | (21,834 | ) | $ | 327,447 | |||||
Interest rate derivative contracts | — | (10,400 | ) | (10,400 | ) | |||||||
Total derivative instruments | $ | 349,281 | $ | (32,234 | ) | $ | 317,047 | |||||
Offsetting Derivative Liabilities: | Gross Amounts of Recognized Liabilities | Gross Amounts Offset in the Consolidated Balance Sheets | Net Amounts Presented in the Consolidated Balance Sheets | |||||||||
Commodity price derivative contracts | $ | (21,934 | ) | $ | 21,834 | $ | (100 | ) | ||||
Interest rate derivative contracts | (10,656 | ) | 10,400 | (256 | ) | |||||||
Total derivative instruments | $ | (32,590 | ) | $ | 32,234 | $ | (356 | ) |
Six Months Ended June 30, 2016 | Year Ended December 31, 2015 | ||||||
(in thousands) | |||||||
Derivative asset at beginning of period, net | $ | 316,691 | $ | 220,734 | |||
Purchases | |||||||
Fair value of derivatives acquired | — | 195,273 | |||||
Net premiums and fees (received) paid or deferred for derivative contracts | (1,959 | ) | 7,126 | ||||
Net gains (losses) on commodity and interest rate derivative contracts | (43,676 | ) | 169,569 | ||||
Settlements | |||||||
Cash settlements received on matured commodity derivative contracts | (142,476 | ) | (211,723 | ) | |||
Cash settlements paid on matured interest rate derivative contracts | 4,727 | 5,227 | |||||
Termination of derivative contracts | — | (69,515 | ) | ||||
Derivative asset at end of period, net | $ | 133,307 | $ | 316,691 |
Level 1 | Quoted prices for identical instruments in active markets. |
Level 2 | Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets. |
Level 3 | Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of transparency as to the inputs used. |
June 30, 2016 | ||||||||||||||||
Fair Value Measurements Using | Assets/Liabilities | |||||||||||||||
Level 1 | Level 2 | Level 3 | at Fair Value | |||||||||||||
Assets: | ||||||||||||||||
Commodity price derivative contracts | $ | — | $ | 148,960 | $ | (2,236 | ) | $ | 146,724 | |||||||
Interest rate derivative contracts | — | (12,686 | ) | — | (12,686 | ) | ||||||||||
Total derivative instruments | $ | — | $ | 136,274 | $ | (2,236 | ) | $ | 134,038 | |||||||
Liabilities: | ||||||||||||||||
Commodity price derivative contracts | $ | — | $ | (663 | ) | $ | — | $ | (663 | ) | ||||||
Interest rate derivative contracts | — | (68 | ) | — | (68 | ) | ||||||||||
Total derivative instruments | $ | — | $ | (731 | ) | $ | — | $ | (731 | ) |
December 31, 2015 | ||||||||||||||||
Fair Value Measurements Using | Assets/Liabilities | |||||||||||||||
Level 1 | Level 2 | Level 3 | at Fair Value | |||||||||||||
Assets: | ||||||||||||||||
Commodity price derivative contracts | $ | — | $ | 333,380 | $ | (5,933 | ) | $ | 327,447 | |||||||
Interest rate derivative contracts | — | (10,400 | ) | — | (10,400 | ) | ||||||||||
Total derivative instruments | $ | — | $ | 322,980 | $ | (5,933 | ) | $ | 317,047 | |||||||
Liabilities: | ||||||||||||||||
Commodity price derivative contracts | $ | — | $ | (99 | ) | $ | — | $ | (99 | ) | ||||||
Interest rate derivative contracts | — | (257 | ) | — | (257 | ) | ||||||||||
Total derivative instruments | $ | — | $ | (356 | ) | $ | — | $ | (356 | ) |
Six Months Ended | ||||||||
June 30, | ||||||||
2016 | 2015 | |||||||
(in thousands) | ||||||||
Unobservable inputs, beginning of period | $ | (5,933 | ) | $ | (6,470 | ) | ||
Total gains | 6,922 | 4,417 | ||||||
Settlements | (3,225 | ) | (1,869 | ) | ||||
Unobservable inputs, end of period | $ | (2,236 | ) | $ | (3,922 | ) | ||
Change in fair value included in earnings related to derivatives still held as of June 30, | $ | 589 | $ | 734 |
June 30, 2016 | December 31, 2015 | |||||||
(in thousands) | ||||||||
Asset retirement obligations, beginning of period | $ | 271,456 | $ | 149,062 | ||||
Liabilities added during the current period | 287 | 2,699 | ||||||
Liabilities added from the LRE Merger and the Eagle Rock Merger | — | 88,228 | ||||||
Accretion expense | 6,150 | 10,238 | ||||||
Retirements | (249 | ) | (838 | ) | ||||
Liabilities related to assets divested | (5,964 | ) | (262 | ) | ||||
Change in estimate | (4,368 | ) | 22,329 | |||||
Asset retirement obligation, end of period | 267,312 | 271,456 | ||||||
Less: current obligations | (8,383 | ) | (9,024 | ) | ||||
Long-term asset retirement obligation, end of period | $ | 258,929 | $ | 262,432 |
June 30, 2016 | ||||
(in thousands) | ||||
July 1, 2016 - December 31, 2016 | $ | 6,972 | ||
2017 | 12,512 | |||
2018 | 11,696 | |||
2019 | 9,661 | |||
2020 | 410 | |||
Total | $ | 41,251 |
June 30, 2016 | December 31, 2015 | |||||||||||||||||||
Earliest Redemption Date | Liquidation Preference Per Unit | Distribution Rate | Units Outstanding | Carrying Value (in thousands) | Units Outstanding | Carrying Value (in thousands) | ||||||||||||||
Series A | June 15, 2023 | $25.00 | 7.875% | 2,581,873 | $ | 62,200 | 2,581,873 | $ | 62,200 | |||||||||||
Series B | April 15, 2024 | $25.00 | 7.625% | 7,000,000 | $ | 169,265 | 7,000,000 | $ | 169,265 | |||||||||||
Series C | October 15, 2024 | $25.00 | 7.75% | 4,300,000 | $ | 103,979 | 4,300,000 | $ | 103,979 | |||||||||||
Total Cumulative Preferred Units | 13,881,873 | $ | 335,444 | 13,881,873 | $ | 335,444 |
June 30, 2016 | December 31, 2015 | |||||
Beginning of period | 130,477 | 83,452 | ||||
Issuance of Common units as consideration for the Eagle Rock Merger | — | 27,886 | ||||
Issuance of Common units as consideration for the LRE Merger | — | 15,448 | ||||
Issuance of Common units for cash | — | 2,430 | ||||
Repurchase of units under the Common unit buyback program | — | (157 | ) | |||
Unit-based compensation | 565 | 1,418 | ||||
End of period | 131,042 | 130,477 |
Cash Distributions | ||||||||||
Distribution | Per Unit | Declared Date | Record Date | Payment Date | ||||||
2016 | ||||||||||
First Quarter | ||||||||||
January | $ | 0.0300 | February 18, 2016 | March 1, 2016 | March 15, 2016 | |||||
2015 | ||||||||||
Fourth Quarter | ||||||||||
December | $ | 0.0300 | January 20, 2016 | February 1, 2016 | February 12, 2016 | |||||
November | $ | 0.0300 | December 18, 2015 | January 4, 2016 | January 14, 2016 | |||||
October | $ | 0.1175 | November 20, 2015 | December 1, 2015 | December 15, 2015 | |||||
Third Quarter | ||||||||||
September | $ | 0.1175 | October 19, 2015 | November 2, 2015 | November 13, 2015 | |||||
August | $ | 0.1175 | September 21, 2015 | October 1, 2015 | October 15, 2015 | |||||
July | $ | 0.1175 | August 20, 2015 | September 1, 2015 | September 14, 2015 | |||||
Second Quarter | ||||||||||
June | $ | 0.1175 | July 16, 2015 | August 3, 2015 | August 14, 2015 | |||||
May | $ | 0.1175 | June 18, 2015 | July 1, 2015 | July 15, 2015 | |||||
April | $ | 0.1175 | May 19, 2015 | June 1, 2015 | June 12, 2015 | |||||
First Quarter | ||||||||||
March | $ | 0.1175 | April 15, 2015 | May 1, 2015 | May 15, 2015 | |||||
February | $ | 0.1175 | March 18, 2015 | April 1, 2015 | April 14, 2015 | |||||
January | $ | 0.1175 | February 17, 2015 | March 2, 2015 | March 17, 2015 | |||||
2014 | ||||||||||
Fourth Quarter | ||||||||||
December | $ | 0.2100 | January 22, 2015 | February 2, 2015 | February 13, 2015 |
Number of Non-vested Restricted Units | Weighted Average Grant Date Fair Value | ||||||
Non-vested restricted units at December 31, 2015 | 976,348 | $ | 18.29 | ||||
Granted | 7,500 | $ | 3.11 | ||||
Forfeited | (26,868 | ) | $ | 13.83 | |||
Vested | (255,483 | ) | $ | 16.95 | |||
Non-vested restricted units at June 30, 2016 | 701,497 | $ | 18.83 |
Number of Non-vested Phantom Units | Weighted Average Grant Date Fair Value | ||||||
Non-vested restricted units at December 31, 2015 | 203,221 | $ | 20.99 | ||||
Granted | 3,712,450 | $ | 2.56 | ||||
Forfeited | (20,747 | ) | $ | 2.04 | |||
Vested | (121,273 | ) | $ | 22.24 | |||
Non-vested phantom units at June 30, 2016 | 3,773,651 | $ | 2.93 |
• | the Green River Basin in Wyoming; |
• | the Permian Basin in West Texas and New Mexico; |
• | the Gulf Coast Basin in Texas, Louisiana, Mississippi and Alabama; |
• | the Anadarko Basin in Oklahoma and North Texas; |
• | the Piceance Basin in Colorado; |
• | the Big Horn Basin in Wyoming and Montana; |
• | the Arkoma Basin in Arkansas and Oklahoma; |
• | the Williston Basin in North Dakota and Montana; |
• | the Wind River Basin in Wyoming; and |
• | the Powder River Basin in Wyoming. |
2016 | 2017 | 2018 | 2019 | 2020 | 2021 (1) | |
Oil ($/Bbl) | $45.82 | $49.39 | $51.99 | $53.61 | $54.90 | $55.92 |
Gas ($/MMBtu) | $2.81 | $3.09 | $3.00 | $3.00 | $3.05 | $3.16 |
Net Oil (Bbls) | Net Gas (Mcf) | Net NGL (Bbls) | Net MMcfe | |
Reserve Report at 2Q16 | 55,220 | 1,240,340 | 45,258 | 1,843,207 |
July 21, 2016 NYMEX Strip Price | 62,830 | 1,501,209 | 51,985 | 2,190,098 |
% Difference | 14% | 21% | 15% | 19% |
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2016 (a) | 2015 (b) | 2016 (a) | 2015 (b) | |||||||||||||
Revenues: | ||||||||||||||||
Oil sales | $ | 49,941 | $ | 44,011 | $ | 85,595 | $ | 79,801 | ||||||||
Natural gas sales | 32,431 | 39,897 | 69,302 | 95,651 | ||||||||||||
NGLs sales | 11,104 | 11,933 | 20,019 | 19,283 | ||||||||||||
Oil, natural gas and NGLs sales | 93,476 | 95,841 | 174,916 | 194,735 | ||||||||||||
Net gains (losses) on commodity derivative contracts | (68,610 | ) | (20,800 | ) | (36,851 | ) | 38,233 | |||||||||
Total revenues | $ | 24,866 | $ | 75,041 | $ | 138,065 | $ | 232,968 | ||||||||
Costs and expenses: | ||||||||||||||||
Production: | ||||||||||||||||
Lease operating expenses | $ | 38,515 | $ | 31,600 | $ | 80,842 | $ | 67,078 | ||||||||
Production and other taxes | 9,476 | 10,754 | 18,144 | 22,180 | ||||||||||||
Depreciation, depletion, amortization, and accretion | 38,786 | 63,175 | 86,839 | 130,015 | ||||||||||||
Impairment of oil and natural gas properties | 157,894 | 733,365 | 365,658 | 865,975 | ||||||||||||
Non-cash compensation | 2,578 | 3,866 | 4,975 | 7,827 | ||||||||||||
Other selling, general and administrative expenses | 10,830 | 5,276 | 19,455 | 10,366 | ||||||||||||
Total costs and expenses | $ | 258,079 | $ | 848,036 | $ | 575,913 | $ | 1,103,441 | ||||||||
Other income (expense): | ||||||||||||||||
Interest expense | $ | (23,932 | ) | $ | (20,374 | ) | $ | (49,636 | ) | $ | (40,563 | ) | ||||
Net losses on interest rate derivative contracts | (2,135 | ) | (281 | ) | (6,825 | ) | (1,484 | ) | ||||||||
Net loss on acquisitions of oil and natural gas properties | (1,665 | ) | — | (1,665 | ) | — | ||||||||||
Gain on extinguishment of debt | — | — | 89,714 | — | ||||||||||||
Other | 196 | 5 | 252 | 45 |
(a) | On May 19, 2016, we divested oil and natural gas properties in the SCOOP/STACK area in Oklahoma. We also completed the divestiture of other oil and natural gas properties in our other operating areas during the six months ended June 30, 2016. As such, there are no operating results from these properties included in our operating results from the closing date of the divestitures forward. |
(b) | During 2015, we acquired certain oil and natural gas properties and related assets. The operating results of these properties are included from the closing date of the acquisition forward. |
Three Months Ended | Percentage Increase / (Decrease) | ||||||||||
June 30, | |||||||||||
2016 (a) | 2015 (b) | ||||||||||
Average realized prices, excluding hedges: | |||||||||||
Oil (Price/Bbl) | $ | 39.44 | $ | 50.85 | (22 | )% | |||||
Natural Gas (Price/Mcf) | $ | 1.17 | $ | 1.69 | (31 | )% | |||||
NGLs (Price/Bbl) | $ | 13.05 | $ | 14.98 | (13 | )% | |||||
Average realized prices, including hedges(c): | |||||||||||
Oil (Price/Bbl) | $ | 55.90 | $ | 58.02 | (4 | )% | |||||
Natural Gas (Price/Mcf) | $ | 2.89 | $ | 3.16 | (9 | )% | |||||
NGLs (Price/Bbl) | $ | 14.22 | $ | 16.93 | (16 | )% | |||||
Average NYMEX prices: | |||||||||||
Oil (Price/Bbl) | $ | 45.54 | $ | 57.94 | (21 | )% | |||||
Natural Gas (Price/Mcf) | $ | 1.95 | $ | 2.63 | (26 | )% | |||||
Total production volumes: | |||||||||||
Oil (MBbls) | 1,266 | 866 | 46 | % | |||||||
Natural Gas (MMcf) | 27,820 | 23,543 | 18 | % | |||||||
NGLs (MBbls) | 851 | 796 | 7 | % | |||||||
Combined (MMcfe) | 40,524 | 33,514 | 21 | % | |||||||
Average daily production volumes: | |||||||||||
Oil (Bbls/day) | 13,913 | 9,511 | 46 | % | |||||||
Natural Gas (Mcf/day) | 305,716 | 258,720 | 18 | % | |||||||
NGLs (Bbls/day) | 9,353 | 8,751 | 7 | % | |||||||
Combined (Mcfe/day) | 445,314 | 368,290 | 21 | % |
(a) | During 2016, we divested certain oil and natural gas properties and related assets. As such, there are no operating results from these properties included in our operating results from the closing date of the divestitures forward. |
(b) | During 2015, we acquired certain oil and natural gas properties and related assets. The operating results of these properties are included from the closing date of the acquisition forward. |
(c) | Excludes the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period and the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period. |
Six Months Ended | Percentage Increase / (Decrease) | ||||||||||
June 30, | |||||||||||
2016 (a) | 2015 (b) | ||||||||||
Average realized prices, excluding hedges: | |||||||||||
Oil (Price/Bbl) | $ | 32.82 | $ | 46.52 | (29 | )% | |||||
Natural Gas (Price/Mcf) | $ | 1.23 | $ | 1.90 | (35 | )% | |||||
NGLs (Price/Bbl) | $ | 10.24 | $ | 13.93 | (26 | )% | |||||
Average realized prices, including hedges (c): | |||||||||||
Oil (Price/Bbl) | $ | 51.05 | $ | 56.38 | (9 | )% | |||||
Natural Gas (Price/Mcf) | $ | 2.87 | $ | 3.10 | (7 | )% | |||||
NGLs (Price/Bbl) | $ | 11.85 | $ | 16.01 | (26 | )% | |||||
Average NYMEX prices: | |||||||||||
Oil (Price/Bbl) | $ | 39.20 | $ | 53.31 | (26 | )% | |||||
Natural Gas (Price/Mcf) | $ | 2.03 | $ | 2.82 | (28 | )% | |||||
Total production volumes: | |||||||||||
Oil (MBbls) | 2,608 | 1,715 | 52 | % | |||||||
Natural Gas (MMcf) | 56,211 | 50,403 | 12 | % | |||||||
NGLs (MBbls) | 1,954 | 1,385 | 41 | % | |||||||
Combined (MMcfe) | 83,585 | 69,003 | 21 | % | |||||||
Average daily production volumes: | |||||||||||
Oil (Bbls/day) | 14,331 | 9,477 | 52 | % | |||||||
Natural Gas (Mcf/day) | 308,852 | 278,472 | 12 | % | |||||||
NGLs (Bbls/day) | 10,737 | 7,650 | 41 | % | |||||||
Combined (Mcfe/day) | 459,256 | 381,232 | 21 | % |
(a) | During 2016, we divested certain oil and natural gas properties and related assets. As such, there are no operating results from these properties included in our operating results from the closing date of the divestitures forward. |
(b) | During 2015, we acquired certain oil and natural gas properties and related assets. The operating results of these properties are included from the closing date of the acquisition forward. |
(c) | Excludes the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period and the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period. |
• | refinancing or restructuring our debt; |
• | selling assets; |
• | reducing or delaying our drilling program; or |
• | seeking to raise additional capital through non-traditional lending or other private sources of capital. |
Borrowing Base Utilization Percentage | <25% | >25% <50% | >50% <75% | >75% <90% | >90% | ||||||||||
Eurodollar Loans Margin | 1.50 | % | 1.75 | % | 2.00 | % | 2.25 | % | 2.50 | % | |||||
ABR Loans Margin | 0.50 | % | 0.75 | % | 1.00 | % | 1.25 | % | 1.50 | % | |||||
Commitment Fee Rate | 0.50 | % | 0.50 | % | 0.375 | % | 0.375 | % | 0.375 | % | |||||
Letter of Credit Fee | 0.50 | % | 0.75 | % | 1.00 | % | 1.25 | % | 1.50 | % |
• | the London interbank offered rate, or LIBOR, plus an applicable margin between 1.50% and 2.50% per annum; or |
• | a domestic bank rate plus an applicable margin between 0.50% and 1.50% per annum. |
• | incur indebtedness; |
• | grant certain liens; |
• | make certain loans, acquisitions, capital expenditures and investments; |
• | merge or consolidate; or |
• | engage in certain asset dispositions, including a sale of all or substantially all of our assets. |
• | consolidated current assets, including the unused amount of the total commitments, to consolidated current liabilities of not less than 1.0 to 1.0, excluding non-cash assets and liabilities under ASC Topic 815, “Derivatives and Hedging,” which includes the current portion of derivative contracts; and |
• | consolidated debt to consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization, accretion, changes in fair value of derivative instruments and other similar charges, minus all non-cash income added to consolidated net income, and giving pro forma effect to any acquisitions or capital expenditures of not more than 5.25 to 1.0 in 2016 and 4.5 to 1.0 starting in 2017 and beyond. |
• | failure to pay any principal when due or any interest, fees or other amount within certain grace periods; |
• | a representation or warranty is proven to be incorrect when made; |
• | failure to perform or otherwise comply with the covenants in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods; |
• | default by us on the payment of any other indebtedness in excess of $5.0 million, or any event occurs that permits or causes the acceleration of the indebtedness; |
• | bankruptcy or insolvency events involving us or our subsidiaries; |
• | the entry of, and failure to pay, one or more adverse judgments in excess of 2% of the existing borrowing base (to the extent not covered by independent third party insurance provided by insurers of the highest claims paying rating or financial strength as to which the insurer does not dispute coverage and is not subject to insolvency proceeding) or one or more non-monetary judgments that could reasonably be expected to have a material adverse effect and for which enforcement proceedings are brought or that are not stayed pending appeal; |
• | specified events relating to our employee benefit plans that could reasonably be expected to result in liabilities in excess of $2.0 million in any year; and |
• | a change of control, which includes (1) an acquisition of ownership, directly or indirectly, beneficially or of record, by any person or group (within the meaning of the Securities Exchange Act of 1934, as amended and the rules and regulations of the SEC) of equity interests representing more than 25% of the aggregate ordinary voting power represented by our issued and outstanding equity interests, or (2) the replacement of a majority of our directors by persons not approved by our board of directors. |
Payments Due by Year | ||||||||||||||||||||||||||||
2016 | 2017 | 2018 | 2019 | 2020 | After 2020 | Total | ||||||||||||||||||||||
Management base salaries | $ | 755 | $ | 1,590 | $ | 1,670 | $ | — | $ | — | $ | — | $ | 4,015 | ||||||||||||||
Asset retirement obligations (1) | 4,200 | 8,368 | 8,657 | 9,090 | 9,544 | 227,453 | 267,312 | |||||||||||||||||||||
Derivative liabilities (2) | 12,985 | 20,683 | 2,848 | 2,066 | — | — | 38,582 | |||||||||||||||||||||
Reserve-Based Credit Facility (3) | 86,040 | — | 1,320,460 | — | — | — | 1,406,500 | |||||||||||||||||||||
Senior Notes and related interest (4) | 30,342 | 39,645 | 39,645 | 163,901 | 389,347 | — | 662,880 | |||||||||||||||||||||
Operating leases | 1,642 | 3,487 | 1,652 | 1,149 | 1,135 | 6,877 | 15,942 | |||||||||||||||||||||
Development commitments (5) | 15,742 | — | — | — | — | — | 15,742 | |||||||||||||||||||||
Firm transportation agreements (6) | 6,972 | 12,512 | 11,696 | 9,661 | 410 | — | 41,251 | |||||||||||||||||||||
Lease Financing Obligations (7) | 2,721 | 5,442 | 5,442 | 5,442 | 4,359 | 1,278 | 24,684 | |||||||||||||||||||||
Total | $ | 161,399 | $ | 91,727 | $ | 1,392,070 | $ | 191,309 | $ | 404,795 | $ | 235,608 | $ | 2,476,908 |
(1) | Represents the discounted future plugging and abandonment costs of oil and natural gas wells and decommissioning of our Elk Basin, Big Escambia Creek and Fairway gas plants. Please read Note 6. Asset Retirement Obligations of the Notes to the Consolidated Financial Statements for additional information regarding our asset retirement obligations. |
(2) | Represents liabilities for commodity and interest rate derivative contracts, the ultimate settlement of which are unknown because they are subject to continuing market risk. Please read Part I—Item 3—Quantitative and Qualitative Disclosures About Market Risk and Note 4. Price and Interest Rate Risk Management Activities of the Notes to the Consolidated Financial Statements for additional information regarding our commodity and interest rate derivative contracts. |
(3) | This table does not include interest to be paid on the Reserve-Based Credit Facility principal balances shown as the interest rates are variable. Pursuant to the semi-annual borrowing base redetermination, the Company’s borrowing base under its Reserve-Based Credit Facility was reduced to $1.325 billion effective May 26, 2016. The decline in the borrowing base resulted in a $103.5 million borrowing base deficiency. Under our Credit Agreement, the Company is required to cure the borrowing base deficiency in six equal monthly installments of approximately $17.3 million. Vanguard has paid the first installment due on June 27, 2016. Please read Note 3. Long-Term Debt of the Notes to the Consolidated Financial Statements for additional information regarding our Reserve-Based Credit Facility. |
(4) | Consists of the Senior Notes due 2019, the Senior Notes due 2020, the Senior Secured Second Lien Notes and the related interest thereon. The Senior Secured Second Lien Notes will mature on (i) February 15, 2023 or (ii) December 31, 2019 if, prior to December 31, 2019, we have not repurchased, redeemed or otherwise repaid in full all of the Senior Notes due 2020 outstanding at that time in excess of $50.0 million in aggregate principal amount and, to the extent we repurchased, redeemed or otherwise repaid the Senior Notes due 2020 with proceeds of certain indebtedness, if such indebtedness has a final maturity date no earlier than the date that is 91 days after February 15, 2023. The table has been prepared assuming that the Senior Secured Second Lien Notes will mature on December 31, 2019. |
(5) | Represents authorized expenditures for drilling, completion and major workover projects. |
(6) | Represents transportation demand charges. Please read Note 7. Commitments and Contingencies of the Notes to the Consolidated Financial Statements for additional information regarding our firm transportation agreements. |
(7) | The Lease Financing Obligations are calculated based on the aggregate present value of minimum future lease payments. The amounts presented include interest payable for each year. |
• | Net income (loss) attributable to non-controlling interest. |
• | Net interest expense; |
• | Depreciation, depletion, amortization, and accretion; |
• | Impairment of oil and natural gas properties; |
• | Net gains or losses on commodity derivative contracts; |
• | Cash settlements on matured commodity derivative contracts; |
• | Net gains or losses on interest rate derivative contracts; |
• | Gain on extinguishment of debt; |
• | Net gains or losses on acquisitions of oil and gas properties; |
• | Texas margin taxes; |
• | Compensation related items, which include unit-based compensation expense, unrealized fair value of phantom units granted to officers and cash settlement of phantom units granted to officers; |
• | Transaction costs incurred on acquisitions, mergers and divestitures; and |
• | Non-controlling interest amounts attributable to each of the items above which revert the calculation back to an amount attributable to the Vanguard unitholders. |
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Net loss attributable to Vanguard unitholders | $ | (260,789 | ) | $ | (793,645 | ) | $ | (406,072 | ) | $ | (912,475 | ) | ||||
Add: Net income attributable to non-controlling interests | 40 | — | 64 | — | ||||||||||||
Net loss | $ | (260,749 | ) | $ | (793,645 | ) | $ | (406,008 | ) | $ | (912,475 | ) | ||||
Plus: | ||||||||||||||||
Interest expense | 23,932 | 20,374 | 49,636 | 40,563 | ||||||||||||
Depreciation, depletion, amortization, and accretion | 38,786 | 63,175 | 86,839 | 130,015 | ||||||||||||
Impairment of oil and natural gas properties | 157,894 | 733,365 | 365,658 | 865,975 | ||||||||||||
Net (gains) losses on commodity derivative contracts | 68,610 | 20,800 | 36,851 | (38,233 | ) | |||||||||||
Net cash settlements received on matured commodity derivative contracts (a)(b)(c) | 69,859 | 42,329 | 142,476 | 80,620 | ||||||||||||
Net losses on interest rate derivative contracts (d) | 2,134 | 281 | 6,825 | 1,484 | ||||||||||||
Gain on extinguishment of debt | — | — | (89,714 | ) | — | |||||||||||
Net loss on acquisition of oil and natural gas properties | 1,665 | — | 1,665 | — | ||||||||||||
Texas margin taxes | (699 | ) | 34 | (2,634 | ) | 142 | ||||||||||
Compensation related items | 2,578 | 3,866 | 4,975 | 7,827 | ||||||||||||
Transaction costs incurred on acquisitions, mergers and divestitures | 2,779 | — | 3,123 | — | ||||||||||||
Adjusted EBITDA before non-controlling interest | 106,789 | 90,579 | 199,692 | 175,918 | ||||||||||||
Adjusted EBITDA attributable to non-controlling interest | (116 | ) | — | (232 | ) | — | ||||||||||
Adjusted EBITDA attributable to Vanguard unitholders | $ | 106,673 | $ | 90,579 | $ | 199,460 | $ | 175,918 | ||||||||
(a) Excludes premiums paid, whether at inception or deferred, for derivative contracts that settled during the period. We consider the cost of premiums paid for derivatives as an investment related to our underlying oil and natural gas properties. | $ | 823 | $ | 2,047 | $ | 1,699 | $ | 2,567 | ||||||||
(b) Excludes the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period. We consider the amounts paid to sellers for derivative contracts assumed with business combinations a part of the purchase price of the underlying oil and natural gas properties. Also excludes the fair value of derivative contracts acquired and settled during the period. | $ | 3,866 | $ | 11,732 | $ | 6,375 | $ | 20,281 | ||||||||
(c) Excludes fair value of restructured derivative contracts. | $ | — | $ | — | $ | — | (31,945 | ) | ||||||||
(d) Includes settlements paid on interest rate derivatives | $ | 2,123 | $ | 990 | $ | 4,727 | $ | 1,980 |
• | Fixed-price swaps - where we will receive a fixed-price for our production and pay a variable market price to the contract counterparty. |
• | Basis swap contracts - which guarantee a price differential between the NYMEX prices and our physical pricing points. We receive a payment from the counterparty or make a payment to the counterparty for the difference between the settled price differential and amounts stated under the terms of the contract. |
• | Collars - where we pay the counterparty if the market price is above the ceiling price (short call) and the counterparty pays us if the market price is below the floor (long put) on a notional quantity. |
• | Put options - gives the owner the right, but not the obligation, to sell a specified amount of an underlying security at a specified price. |
• | Three-way collar contracts - which combine a long put, a short put and a short call. The use of the long put combined with the short put allows us to sell a call at a higher price, thus establishing a higher ceiling and limiting our exposure to future settlement payments while also restricting our downside risk to the difference between the long put and the short put if the price drops below the price of the short put. This allows us to settle for market plus the spread between the short put and the long put in a case where the market price has fallen below the short put fixed price. |
• | Swaption agreements - where we provide options to counterparties to extend swap contracts into subsequent periods. |
• | Call options sold - a structure that may be combined with an existing swap to raise the strike price, putting us in either a higher asset position, or a lower liability position. In general, selling a call option is used to enhance an existing position or a position that we intend to enter into simultaneously. |
• | Put options sold - a structure that may be combined with an existing swap to raise the strike price, putting us in either a higher asset position, or a lower liability position. In general, selling a put option is used to enhance an existing position or a position that we intend to enter into simultaneously. |
• | Put or Call spread options - created when we purchase a put/call and sell a put/call simultaneously. |
• | Range bonus accumulators - a structure that allows us to receive a cash payment when the daily average settlement price remains within a predefined range on each expiry date. Depending on the terms of the contract, if the settlement price is below the floor or above the ceiling on any expiry date, we may have to sell at that level. |
July 1 -December 31, 2016 | Year 2017 | |||||||
Gas Positions: | ||||||||
Fixed-Price Swaps: | ||||||||
Notional Volume (MMBtu) | 36,528,944 | 53,725,260 | ||||||
Fixed Price ($/MMBtu) | $ | 4.36 | $ | 3.75 | ||||
Three-Way Collars: | ||||||||
Notional Volume (MMBtu) | 6,440,000 | 14,600,000 | ||||||
Floor Price ($/MMBtu) | $ | 3.95 | $ | 3.88 | ||||
Ceiling Price ($/MMBtu) | $ | 4.25 | $ | 4.15 | ||||
Put Sold ($/MMBtu) | $ | 3.00 | $ | 3.31 |
July 1 -December 31, 2016 | Year 2017 | |||||||
Oil Positions: | ||||||||
Fixed-Price Swaps (West Texas Intermediate): | ||||||||
Notional Volume (Bbls) | 938,283 | 749,698 | ||||||
Fixed Price ($/Bbl) | $ | 84.00 | $ | 85.70 | ||||
Fixed-Price Swaps (Light Louisiana Sweet): | ||||||||
Notional Volume (Bbls) | — | 168,000 | ||||||
Fixed Price ($/Bbl) | $ | — | $ | 91.25 | ||||
Collars: | ||||||||
Notional Volume (Bbls) | 322,000 | — | ||||||
Floor Price ($/Bbl) | $ | 41.00 | $ | — | ||||
Ceiling Price ($/Bbl) | $ | 50.57 | $ | — | ||||
Puts: | ||||||||
Notional Volume (Bbls) | 184,000 | — | ||||||
Put Price ($/Bbl) | $ | 60.00 | $ | — | ||||
Three-Way Collars: | ||||||||
Notional Volume (Bbls) | 533,600 | — | ||||||
Floor Price ($/Bbl) | $ | 90.00 | $ | — | ||||
Ceiling Price ($/Bbl) | $ | 96.18 | $ | — | ||||
Put Sold ($/Bbl) | $ | 73.62 | $ | — |
July 1 -December 31, 2016 | ||||
NGLs Positions: | ||||
Fixed-Price Swaps: | ||||
Mont Belvieu Propane | ||||
Notional Volume (Bbls) | 228,600 | |||
Fixed Price ($/Bbl) | $ | 23.61 | ||
Mont Belvieu N. Butane | ||||
Notional Volume (Bbls) | 101,000 | |||
Fixed Price ($/Bbl) | $ | 28.54 | ||
Mont Belvieu Isobutane | ||||
Notional Volume (Bbls) | 48,000 | |||
Fixed Price ($/Bbl) | $ | 28.53 | ||
Mont Belvieu N. Gasoline | ||||
Notional Volume (Bbls) | 77,400 | |||
Fixed Price ($/Bbl) | $ | 53.50 |
July 1 -December 31, 2016 | Year 2017 | |||||||
Gas Positions: | ||||||||
Notional Volume (MMBtu) | 920,000 | 1,825,000 | ||||||
Put Sold ($/MMBtu) | $ | 3.00 | $ | 3.50 | ||||
Oil Positions: | ||||||||
Notional Volume (Bbls) | 73,600 | 73,000 | ||||||
Put Sold ($/Bbl) | $ | 75.00 | $ | 75.00 |
July 1 -December 31, 2016 | ||||
Oil Positions: | ||||
Notional Volume (Bbls) | 92,000 | |||
Bonus ($/Bbl) | $ | 4.00 | ||
Range Ceiling ($/Bbl) | $ | 100.00 | ||
Range Floor ($/Bbl) | $ | 75.00 |
July 1 -December 31, 2016 | Year 2017 | |||||||
Gas Positions: | ||||||||
Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential | ||||||||
Notional Volume (MMBtu) | 19,320,000 | 21,900,000 | ||||||
Weighted-basis differential ($/MMBtu) | $ | (0.20 | ) | $ | (0.20 | ) | ||
Houston Ship Channel and NYMEX Henry Hub Basis Differential | ||||||||
Notional Volume (MMBtu) | 477,354 | — | ||||||
Weighted-basis differential ($/MMBtu) | $ | (0.08 | ) | $ | — | |||
TexOk and NYMEX Henry Hub Basis Differential | ||||||||
Notional Volume (MMBtu) | 140,433 | — | ||||||
Weighted-basis differential ($/MMBtu) | $ | (0.10 | ) | $ | — | |||
WAHA and NYMEX Henry Hub Basis Differential | ||||||||
Notional Volume (MMBtu) | 788,896 | — | ||||||
Weighted-basis differential ($/MMBtu) | $ | (0.13 | ) | $ | — |
July 1 -December 31, 2016 | ||||
Oil Positions: | ||||
WTI Midland and WTI Cushing Basis Differential | ||||
Notional Volume (Bbls) | 486,000 | |||
Weighted-basis differential ($/Bbl) | $ | (1.01 | ) | |
West Texas Sour and WTI Cushing Basis Differential | ||||
Notional Volume (Bbls) | 110,400 | |||
Weighted-basis differential ($/Bbl) | $ | (0.43 | ) | |
WTI and West Canadian Select Basis Differential | ||||
Notional Volume (Bbls) | 368,000 | |||
Weighted-basis differential ($/Bbl) | $ | (14.25 | ) |
July 1 - December 31, 2016 | Year 2017 | |||||||
Gas Positions: | ||||||||
Notional Volume (MMBtu) | 4,600,000 | 11,862,500 | ||||||
Weighted Average Fixed Price ($/MMBtu) | $ | 4.25 | $ | 3.01 | ||||
Oil Positions: | ||||||||
Notional Volume (Bbls) | 312,800 | 365,000 | ||||||
Weighted Average Fixed Price ($/Bbl) | $ | 50.00 | $ | 95.00 |
Year 2017 | Year 2018 | |||||||
Gas Positions: | ||||||||
Notional Volume (MMBtu) | 2,062,500 | 675,000 | ||||||
Weighted Average Fixed Price ($/MMBtu) | $ | 2.74 | $ | 2.74 |
July 1 - December 31, 2016 | Year 2017 | Year 2018 | Year 2019 | |||||||||||||
Weighted Average Notional Amount | $ | 531,875 | $ | 256,342 | $ | 192,836 | $ | 175,000 | ||||||||
Weighted Average Fixed LIBOR Rate | 1.88 | % | 2.15 | % | 2.31 | % | 2.32 | % |
Current Assets | Long-Term Assets | Current Liabilities | Long-Term Liabilities | Total Amount Due From/(Owed To) Counterparty at June 30, 2016 | ||||||||||||||||
ABN AMRO (A) | $ | 1,330 | $ | 265 | $ | — | $ | — | $ | 1,595 | ||||||||||
Bank of America (A) | 19,800 | 9,227 | — | — | 29,027 | |||||||||||||||
Barclays (A-) | 6,759 | — | — | (59 | ) | 6,700 | ||||||||||||||
BMO (A+) | 2,363 | 579 | — | — | 2,942 | |||||||||||||||
CIBC (A+) | 1,412 | 511 | — | — | 1,923 | |||||||||||||||
Citibank (A) | 4,760 | 1,036 | — | — | 5,796 | |||||||||||||||
Comerica (A-) | 4,878 | — | — | — | 4,878 | |||||||||||||||
Commonwealth Bank of Australia (AA-) | 769 | 275 | — | — | 1,044 | |||||||||||||||
Credit Agricole (A) | — | — | (68 | ) | — | (68 | ) | |||||||||||||
Fifth Third Bank (A-) | 567 | — | — | — | 567 | |||||||||||||||
Huntington Bank (BBB+) | 1,370 | — | — | (344 | ) | 1,026 | ||||||||||||||
ING Financial Markets (A) | 17,256 | — | — | (229 | ) | 17,027 | ||||||||||||||
JP Morgan (A-) | 28,748 | — | — | — | 28,748 | |||||||||||||||
Morgan Stanley (BBB+) | 3,483 | 1,831 | — | — | 5,314 | |||||||||||||||
Natixis (A) | 1,464 | 286 | — | — | 1,750 | |||||||||||||||
NextEra Energy Inc. (A-) | — | — | (31 | ) | — | (31 | ) | |||||||||||||
RBC (AA-) | 5,092 | 1,811 | — | — | 6,903 | |||||||||||||||
Scotia Capital (A+) | 4,768 | 10 | — | — | 4,778 | |||||||||||||||
SunTrust (A-) | 855 | 354 | — | — | 1,209 | |||||||||||||||
Wells Fargo (AA-) | 11,188 | 991 | — | — | 12,179 | |||||||||||||||
Total | $ | 116,862 | $ | 17,176 | $ | (99 | ) | $ | (632 | ) | $ | 133,307 |
Exhibit No. | Exhibit Title | Incorporated by Reference to the Following | ||
10.1 | Tenth Amendment, dated May 26, 2016, to Third Amended and Restated Credit Agreement, by and between Vanguard Natural Gas, LLC, Citibank, N.A., as administrative agent and the lenders party hereto. | Exhibit 10.1 to Form 8-K, filed May 27, 2016 (File No. 001-33756) | ||
31.1 | Certification of Chief Executive Officer Pursuant to Rule 13a -14(a) and Rule 15d-14(a) of the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | Filed herewith | ||
31.2 | Certification of Chief Financial Officer Pursuant to Rule 13a -14(a) and Rule 15d-14(a) of the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | Filed herewith | ||
32.1 | Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | Furnished herewith | ||
32.2 | Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | Furnished herewith | ||
101.INS | XBRL Instance Document | Filed herewith | ||
101.SCH | XBRL Schema Document | Filed herewith | ||
101.CAL | XBRL Calculation Linkbase Document | Filed herewith | ||
101.DEF | XBRL Definition Linkbase Document | Filed herewith | ||
101.LAB | XBRL Label Linkbase Document | Filed herewith | ||
101.PRE | XBRL Presentation Linkbase Document | Filed herewith |
VANGUARD NATURAL RESOURCES, LLC | ||
(Registrant) | ||
Date: July 29, 2016 | ||
/s/ Richard A. Robert | ||
Richard A. Robert | ||
Executive Vice President and Chief Financial Officer | ||
(Principal Financial Officer and Principal Accounting Officer) |
1. | I have reviewed this Quarterly Report on Form 10-Q of Vanguard Natural Resources, LLC (the “registrant”); |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ Scott W. Smith | |
Scott W. Smith | |
President and Chief Executive Officer (Principal Executive Officer) Vanguard Natural Resources, LLC |
1. | I have reviewed this Quarterly Report on Form 10-Q of Vanguard Natural Resources, LLC (the “registrant”); |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ Richard A. Robert | |
Richard A. Robert | |
Executive Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) Vanguard Natural Resources, LLC |
/s/ Scott W. Smith | |
Scott W. Smith | |
President and Chief Executive Officer (Principal Executive Officer) |
1. | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
/s/ Richard A. Robert | |
Richard A. Robert | |
Executive Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) |
Document and Entity Information - shares |
6 Months Ended | |
---|---|---|
Jun. 30, 2016 |
Jul. 27, 2016 |
|
Document and Entity Information [Abstract] | ||
Entity Registrant Name | Vanguard Natural Resources, LLC | |
Entity Central Index Key | 0001384072 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Document Type | 10-Q | |
Document Period End Date | Jun. 30, 2016 | |
Document Fiscal Year Focus | 2016 | |
Document Fiscal Period Focus | Q2 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 131,038,826 |
CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - shares |
Jun. 30, 2016 |
Dec. 31, 2015 |
---|---|---|
Members’ deficit (Note 8) | ||
Preferred units, issued (shares) | 13,881,873 | 13,881,873 |
Preferred units, outstanding (shares) | 13,881,873 | 13,881,873 |
Common Units | ||
Members’ deficit (Note 8) | ||
Common units, issued (shares) | 131,041,849 | 130,476,978 |
Common units, outstanding (shares) | 131,041,849 | 130,476,978 |
Class B | ||
Members’ deficit (Note 8) | ||
Common units, issued (shares) | 420,000 | 420,000 |
Common units, outstanding (shares) | 420,000 | 420,000 |
CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY (Unaudited) (Parenthetical) - Common Units - USD ($) $ in Thousands |
6 Months Ended | 12 Months Ended |
---|---|---|
Jun. 30, 2016 |
Dec. 31, 2015 |
|
Offering costs related to prior period offerings | $ 67 | |
Member Units | ||
Offering costs related to prior period offerings | $ 67 | $ (593) |
EROC Merger [Member] | Member Units | ||
Offering costs related to prior period offerings | (5,560) | |
LRE Merger [Member] | Member Units | ||
Offering costs related to prior period offerings | $ (3,961) |
Description of the Business |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Jun. 30, 2016 | |||||||||||||||||||||||||||||||||||||||||
Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||
Description of Business | Description of the Business: We are a publicly traded limited liability company focused on the acquisition and development of mature, long-lived oil and natural gas properties in the United States. Our primary business objective is to generate stable cash flows allowing us to make monthly cash distributions to our unitholders and, over time, increase our monthly cash distributions through the acquisition of additional mature, long-lived oil and natural gas properties. Through our operating subsidiaries, as of June 30, 2016, we own properties and oil and natural gas reserves primarily located in ten operating areas:
We were formed in October 2006 and completed our initial public offering in October 2007. Our common units are listed on the NASDAQ Global Select Market (“NASDAQ”), an exchange of the NASDAQ OMX Group Inc. (Nasdaq: NDAQ), under the symbol “VNR.” Our 7.875% Series A Cumulative Redeemable Perpetual Preferred Units (“Series A Cumulative Preferred Units”), 7.625% Series B Cumulative Redeemable Perpetual Preferred Units (“Series B Cumulative Preferred Units”) and 7.75% Series C Cumulative Redeemable Perpetual Preferred Units (“Series C Cumulative Preferred Units,” and, collectively with the Series A Units and Series B Units, the “Cumulative Preferred Units”) are also listed on the NASDAQ under the symbols “VNRAP,” “VNRBP” and “VNRCP,” respectively. |
Summary of Significant Accounting Policies |
6 Months Ended | ||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Jun. 30, 2016 | |||||||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||||||||||||
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies The accompanying consolidated financial statements are unaudited and were prepared from our records. We derived the Consolidated Balance Sheet as of December 31, 2015, from the audited financial statements contained in our 2015 Annual Report. Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by generally accepted accounting principles in the United States (“GAAP”). You should read this Quarterly Report on Form 10-Q along with our 2015 Annual Report, which contains a summary of our significant accounting policies and other disclosures. In our opinion, we have made all adjustments which are of a normal, recurring nature to fairly present our interim period results. Information for interim periods may not be indicative of our operating results for the entire year. As of June 30, 2016, our significant accounting policies are consistent with those discussed in Note 1 of our consolidated financial statements contained in our 2015 Annual Report.
The consolidated financial statements as of June 30, 2016 and December 31, 2015 and for the three and six months ended June 30, 2016 and 2015 include our accounts and those of our subsidiaries. We present our financial statements in accordance with GAAP. All intercompany transactions and balances have been eliminated upon consolidation. Additionally, our financial statements for prior periods include reclassifications that were made to conform to the current period presentation. Those reclassifications did not impact our reported net income (loss) or members’ equity. We consolidated Potato Hills Gas Gathering System as of the close date of the acquisition in January 2016 as we have the ability to control the operating and financial decisions and policies of the entity through our 51% ownership and reflected the non-controlling interest as a separate element in our consolidated financial statements.
The full cost method of accounting is used to account for oil and natural gas properties. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil, natural gas and NGLs reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, both dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and ceiling test limitations as discussed below. Capitalized costs associated with proved reserves are amortized over the life of the reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties are excluded from the amortizable base until these properties are evaluated, which occurs on a quarterly basis. Specifically, costs are transferred to the amortizable base when properties are determined to have proved reserves. In addition, we transfer unproved property costs to the amortizable base when unproved properties are evaluated as being impaired and as exploratory wells are determined to be unsuccessful. Additionally, the amortizable base includes estimated future development costs, dismantlement, restoration and abandonment costs net of estimated salvage values. Capitalized costs are limited to a ceiling based on the present value of future net revenues, computed using the 12-month unweighted average of first-day-of-the-month historical price, the “12-month average price” discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the ceiling is less than the total capitalized costs, we are required to write-down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write-downs are included in the Consolidated Statements of Operations as an impairment charge. We recorded a non-cash ceiling test impairment of oil and natural gas properties for the six months ended June 30, 2016 of $365.7 million as a result of a decline in oil and natural gas prices at the measurement dates, March 31, 2016 and June 30, 2016. The impairment for the first quarter of 2016 was $207.8 million and was calculated based on the 12-month average price of $2.41 per MMBtu for natural gas and $46.16 per barrel of crude oil. The impairment for the second quarter of 2016 was $157.9 million and was calculated based on the 12-month average price of $2.24 per MMBtu for natural gas and $42.91 per barrel of crude oil. For the six months ended June 30, 2015, we recorded a non-cash ceiling test impairment of oil and natural gas properties of $866.0 million as a result of a decline in oil and natural gas prices at the measurement dates, March 31, 2015 and June 30, 2015. The impairment for the first quarter of 2015 was $132.6 million and was calculated based on the 12-month average price of $3.91 per MMBtu for natural gas and $82.62 per barrel of crude oil. The impairment for the second quarter of 2015 was $733.4 million and was calculated based on the 12-month average price of $3.44 per MMBtu for natural gas and $71.51 per barrel of crude oil. When we sell or convey interests in oil and natural gas properties, we reduce oil and natural gas reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and natural gas properties unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Sales proceeds on insignificant sales are treated as an adjustment to the cost of the properties.
In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date (“ASU No. 2014-14”) to defer the effective date of ASU No. 2014-09 by one year. Public business entities must apply the guidance in ASU 2014-09 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We are evaluating the impact of the pending adoption of ASU No. 2014-09 on our financial position and results of operations and have not yet determined the method by which we will adopt the standard in 2018. In February 2016, the FASB issued ASU No. 2016-02, "Leases (Topic 842)", which requires lessees to recognize at the commencement date for all leases, with the exception of short-term leases, (a) a lease liability, which is a lessee‘s obligation to make lease payments arising from a lease, measured on a discounted basis, and (b) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The ASU on leases will take effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. We do not expect the adoption of ASU No. 2016-02 will have a material impact on our consolidated financial statements. In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. Under this ASU, the SEC Staff is rescinding certain SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities—Oil and Gas, effective upon adoption of Topic 606. As discussed above, Revenue from Contracts with Customers (Topic 606) is effective for public entities for fiscal years, and interim periods within the fiscal years, beginning after December 15, 2017. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU No. 2016-12”). The amendments under this ASU do not change the core revenue recognition principle in Topic 606. In addition, ASU No. 2016-12 provide clarifying guidance in certain narrow areas and add some practical expedients. These amendments are also effective at the same date that Topic 606 is effective.
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. The most significant estimates pertain to proved oil, natural gas and NGLs reserves and related cash flow estimates used in impairment tests of oil and natural gas properties and goodwill, the acquisition of oil and natural gas properties, the fair value of derivative contracts and asset retirement obligations, accrued oil, natural gas and NGLs revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion. Actual results could differ from those estimates.
Certain prior year balances have been reclassified to conform to the current year presentation of balances as stated in this Quarterly Report on Form 10-Q. Please read Note 3. Long-Term Debt of the Notes to the Consolidated Financial Statements for further discussion regarding this reclassification. |
Acquisitions and Divestitures |
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Business Combinations [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Acquisitions and Divestitures | 2. Acquisitions and Divestitures Our acquisitions are accounted for under the acquisition method of accounting in accordance with ASC Topic 805, “Business Combinations” (“ASC Topic 805”). An acquisition may result in the recognition of a gain or goodwill based on the measurement of the fair value of the assets acquired at the acquisition date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. Any such gain or any loss resulting from the impairment of goodwill is recognized in current period earnings and classified in other income and expense in the accompanying Consolidated Statements of Operations. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. The results of operations of the properties acquired in our acquisitions have been included in the consolidated financial statements since the closing dates of the acquisitions. All our acquisitions were funded with borrowings under our Reserve-Based Credit Facility (defined in Note 3. Long-Term Debt of the Notes to the Consolidated Financial Statements), except for certain acquisitions, in which the Company issued shares or exchanged assets as described below. 2016 Acquisitions and Divestitures In January 2016, we completed the acquisition of a 51% joint venture interest in Potato Hills Gas Gathering System, a gathering system located in Latimer County, Oklahoma, including the acquisition of the compression assets relating to the gathering system, for a total consideration of $7.7 million. As part of the acquisition, Vanguard also acquired the seller’s rights as manager under the related joint venture agreement. The acquisition was funded with borrowings under our existing Reserve-Based Credit Facility. During the six months ended June 30, 2016, we completed the sale of certain of our properties in Eddy County, New Mexico, Martin County, Texas and Pontotoc County, Oklahoma for an aggregate consideration of approximately $21.2 million. All cash proceeds received from the sale of these properties were used to reduce borrowings under our Reserve-Based Credit Facility. In May 2016, we completed the sale of our natural gas, oil and natural gas liquids assets in the SCOOP/STACK area in Oklahoma to entities managed by Titanium Exploration Partners, LLC for $272.5 million, subject to final post-closing adjustments (the “SCOOP/STACK Divestiture”). At closing, we received net cash proceeds of $263.1 million, while $9.4 million of the total consideration is currently held in escrow. The Company used $261.0 million of the cash received to reduce borrowings under our Reserve-Based Credit Facility and $2.1 million to pay for some of the transaction fees related to the sale. 2015 Acquisitions and Mergers On July 31, 2015, we completed the acquisition of additional interests in the same properties located in the Pinedale field of Southwestern Wyoming that were previously acquired in the Pinedale Acquisition in 2014 for an adjusted purchase price of $11.4 million based on an effective date of April 1, 2015. The acquisition was funded with borrowings under our existing Reserve-Based Credit Facility. LRE Merger On October 5, 2015, we completed the transactions contemplated by the Purchase Agreement and Plan of Merger, dated as of April 20, 2015 (the “LRE Merger Agreement”), by and among us, Lighthouse Merger Sub, LLC, our wholly owned subsidiary (“LRE 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”), the general partner of LRE. Pursuant to the terms of the LRE Merger Agreement, LRE Merger Sub was merged with and into LRE, with LRE continuing as the surviving entity and as our wholly owned subsidiary (the “LRE Merger”), and, at the same time, we 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. Under the terms of the LRE Merger Agreement, each common unit representing interests in LRE (the “LRE Common Units”) was converted into the right to receive 0.550 newly issued Vanguard common units. As consideration for the LRE Merger, we issued approximately 15.4 million Vanguard common units valued at $123.3 million based on the closing price per Vanguard common unit of $7.98 at October 5, 2015 and assumed $290.0 million in debt. The debt assumed was extinguished using borrowings under the Company’s Reserve-Based Credit Facility following the close of the LRE Merger. As consideration for our purchase of the limited liability company interests in LRE GP, we issued 12,320 Vanguard common units. The LRE Merger was completed following approval, at a Special Meeting of LRE unitholders on October 5, 2015, of the LRE Merger Agreement and the LRE Merger by holders of a majority of the outstanding LRE Common Units. The following presents the values assigned to the net assets acquired in the LRE Merger as of the merger date (in thousands):
Eagle Rock Merger On October 8, 2015, we completed the transactions contemplated by the Agreement and Plan of Merger, dated as of May 21, 2015 (the “Eagle Rock Merger Agreement”), by and among us, Talon Merger Sub, LLC, our wholly owned subsidiary (“Eagle Rock Merger Sub”), Eagle Rock Energy Partners, L.P. (“Eagle Rock”) and Eagle Rock Energy GP, L.P. (“Eagle Rock GP”). Pursuant to the terms of the Eagle Rock Merger Agreement, Eagle Rock Merger Sub was merged with and into Eagle Rock with Eagle Rock continuing as the surviving entity and as our wholly owned subsidiary (the “Eagle Rock Merger”). Under the terms of the Eagle Rock Merger Agreement, each common unit representing limited partner interests in Eagle Rock (“Eagle Rock Common Unit”) was converted into the right to receive 0.185 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). As consideration for the Eagle Rock Merger, Vanguard issued approximately 27.7 million Vanguard common units valued at $258.3 million based on the closing price per Vanguard common unit of $9.31 at October 8, 2015 and assumed $156.6 million in debt. The Company extinguished $122.3 million of the debt assumed using borrowings under its Reserve-Based Credit Facility following the close of Eagle Rock Merger. The Eagle Rock Merger was completed following (i) approval by holders of a majority of the outstanding Eagle Rock Common Units, at a Special Meeting of Eagle Rock unitholders on October 5, 2015, of the Eagle Rock Merger Agreement and the Eagle Rock Merger and (ii) approval by Vanguard unitholders, at Vanguard’s 2015 Annual Meeting of Unitholders, of the issuance of Vanguard common units to be issued as Eagle Rock Merger consideration to the holders of Eagle Rock Common Units in connection with the Eagle Rock Merger. The following presents the values assigned to the net assets acquired in the Eagle Rock Merger as of the merger date (in thousands):
As a result of the consideration transferred being less than the fair value of net assets acquired, Vanguard reassessed whether it had fully identified all of the assets and liabilities obtained in the acquisition. As part of its reassessment, Vanguard also reevaluated the consideration transferred and whether there were any non-controlling interests in the acquired property. No additional assets or liabilities were identified. Vanguard also determined that there were no non-controlling interests in the Eagle Rock Merger. Vanguard determined that the bargain purchase gain was primarily attributable to unfavorable market trends between the date the parties agreed to the consideration for the Eagle Rock Merger and the date the transaction was completed, resulting in the decline of Vanguard’s unit price. Although the depressed oil and natural gas market also affected the fair value of Eagle Rock’s oil and natural gas properties, it had a more significant impact on Vanguard’s unit price compared to the resulting decrease in the fair value of those properties. As a result, the fair value of the net assets acquired in the Eagle Rock Merger, including the oil and natural gas properties, exceeded the total consideration paid. During the three and six months ended June 30, 2016, Vanguard made an adjustment to the amounts assigned to the net assets acquired based on new information obtained about facts that existed as of the merger date. As a result, the bargain purchase gain was reduced by $1.6 million. This adjustment is included in the net loss on acquisition of oil and natural gas properties for this period. Pro Forma Operating Results In accordance with ASC Topic 805, presented below are unaudited pro forma results for the three and six months ended June 30, 2015 to show the effect on our consolidated results of operations as if our acquisitions and mergers completed in 2015 had occurred on January 1, 2014. The pro forma results also reflect the impact of the SCOOP/STACK Divestiture as if it had occurred on January 1, 2015 The pro forma results reflect the results of combining our statement of operations with the results of operations from the oil and natural gas properties acquired during 2015 and eliminating the results of operations from the oil and natural gas properties divested in the SCOOP/STACK Divestiture, adjusted for (i) the assumption of asset retirement obligations and accretion expense for the properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired, (iii) interest expense on additional debt assumed in the LRE Merger and the Eagle Rock Merger, and (iv) the impact of the common units issued in the LRE Merger and the Eagle Rock Merger. The pro forma information is based upon these assumptions and is not necessarily indicative of future results of operations:
The amount of revenues and excess of revenues over direct operating expenses that were eliminated to reflect the impact of the SCOOP/STACK Divestiture in the pro forma results presented above are as follows (in thousands):
Post-Acquisition Operating Results The amount of revenues and excess of revenues over direct operating expenses included in the accompanying Consolidated Statements of Operations for our 2015 acquisitions are shown in the table that follows. Direct operating expenses include lease operating expenses, selling, general and administrative expenses and production and other taxes.
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Long-Term Debt |
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Long-Term Debt | Long-Term Debt Our financing arrangements consisted of the following as of the date indicated:
Senior Secured Reserve-Based Credit Facility The Company’s Third Amended and Restated Credit Agreement (the “Credit Agreement”) provides a maximum credit facility of $3.5 billion. On May 26, 2016, the Company entered into the Tenth Amendment (the “Tenth Amendment”) to its Credit Agreement which reduced the Company’s borrowing base from $1.78 billion to $1.325 billion (the “Reserve-Based Credit Facility”). As of May 26, 2016, Vanguard had $1.424 billion in outstanding borrowings and approximately $4.5 million in outstanding letters of credit (discussed below), resulting in a deficiency of approximately $103.5 million. Under Vanguard’s Credit Agreement, the Company will make principal payments in an aggregate amount equal to such borrowing base deficiency in six equal monthly installments of approximately $17.3 million with the first payment due and payable within 30 days of the effective date of the Tenth Amendment. Vanguard made the first and second required deficiency payments for a total of $35.0 million on June 27, 2016 and July 26, 2016, respectively, thus reducing the remaining future monthly installments to $17.1 million. The Tenth Amendment also includes, among other provisions, a one-time current ratio waiver for the second quarter of 2016, an increase in the mortgage requirement from 80% to 95% and an additional Event of Default clause. An Event of Default would occur should the Company make any payment of principal, accrued interest or fees to any Senior Notes or Second Lien Debt on or after September 15, 2016 if the Company’s pro forma liquidity after giving pro forma effect to such payment is less than $50 million. Liquidity, as defined under the Credit Agreement, means the sum of (a) the Company’s unrestricted cash and cash equivalents, plus (b) the amount available to be borrowed under our Reserve-Based Credit Facility. Since the Company currently has a borrowing base deficiency, liquidity is equal to the balance of the Company’s unrestricted cash and cash equivalents less the borrowing base deficiency obligation. The mortgage requirement provides that the mortgaged properties under the Credit Agreement must represent at least 95% of the value of the Company’s oil and natural gas properties evaluated based on the Company’s most recently completed engineering report with respect to our oil, natural gas and NGLs reserves. In the event that the mortgage requirement is not met, the Company would be required to provide additional lien interest on its oil and natural gas properties to be in compliance with terms of our Credit Agreement. As of June 30, 2016, there were approximately $1.41 billion of outstanding borrowings and approximately $4.5 million in outstanding letters of credit resulting in a borrowing deficiency of $86.0 million under the Reserve-Based Credit Facility. The Company’s failure to repay any of the installments due related to the borrowing base deficiency shall constitute an event of default under the Credit Agreement and as such, the lenders could declare all outstanding principal and interest to be due and payable, could freeze our accounts, could foreclose against the assets securing their borrowings, and we could be forced into bankruptcy or liquidation. In addition, a payment default under the Reserve Based Credit Facility could result in a cross default under our Senior Notes Due 2020 and Senior Secured Second Lien Notes. In such case, we may not have sufficient assets to repay our creditors, including the holders of our Senior Notes. As a result, there may not be any value remaining attributable to the holders of our Common units and Cumulative Preferred Units. Interest rates under the Reserve-Based Credit Facility are based on Eurodollar (LIBOR) or ABR (Prime) indications, plus a margin. Interest is generally payable quarterly for ABR loans and at the applicable maturity date for LIBOR loans. At June 30, 2016, the applicable margin and other fees increase as the utilization of the borrowing base increases as follows: Borrowing Base Utilization Grid
Our Reserve-Based Credit Facility contains a number of customary covenants that require us to maintain certain financial ratios. Specifically, as of the end of each fiscal quarter, we may not permit the following: (a) our current ratio to be less than 1.0 to 1.0 and (b) our total leverage ratio to be more than 5.25 to 1.0 in 2016 and 4.5 to 1.0 starting in 2017 and beyond. In addition, we are subject to various other covenants including, but not limited to, those limiting our ability to incur indebtedness, enter into commodity and interest rate derivatives, grant certain liens, make certain loans, acquisitions, capital expenditures and investments, merge or consolidate, or engage in certain asset dispositions, including a sale of all or substantially all of our assets. As discussed above, under the Tenth Amendment, the lenders waived the requirement to maintain a current ratio of not less than 1.0 to 1.0 solely for the fiscal quarter ended June 30, 2016. We were in compliance with all of our debt covenants as of June 30, 2016. Letters of Credit At June 30, 2016, we have unused irrevocable standby letters of credit of approximately $4.5 million. The letters are being maintained as security for performance on long-term transportation contracts. Borrowing availability for the letters of credit is provided under our Reserve-Based Credit Facility. The fair value of these letters of credit approximates contract values based on the nature of the fee arrangements with marketing counterparties. 8.375% Senior Notes Due 2019 At June 30, 2016, we had $51.1 million outstanding in aggregate principal amount of 8.375% senior notes due in 2019 (the “Senior Notes due 2019”). The Senior Notes due 2019 were assumed by VO in connection with the Eagle Rock Merger. Interest on the Senior Notes due 2019 is payable on June 1 and December 1 of each year. The Senior Notes due 2019 are fully and unconditionally (except for customary release provisions) and jointly and severally guaranteed on a senior unsecured basis by Vanguard and all of our existing subsidiaries, all of which are 100% owned, and certain of our future subsidiaries (the “Subsidiary Guarantors”). Prior to the Eagle Rock Merger, the parties to the indenture executed a supplemental indenture which eliminated substantially all of the restrictive covenants and certain events of default with respect to the Senior Notes due 2019. We have the option to redeem some or all of the Senior Notes due 2019 at any time at redemption prices equal to the aggregate principal amount multiplied by (i) 102.094% if such Senior Notes due 2019 are redeemed in 2016 and (ii) 100.000% if such Senior Notes due 2019 are redeemed in 2017 and thereafter. 7.875% Senior Notes Due 2020 At June 30, 2016, we had $381.8 million outstanding in aggregate principal amount of 7.875% senior notes due in 2020 (the “Senior Notes due 2020”). The issuers of the Senior Notes due 2020 are VNR and our 100% owned finance subsidiary, VNRF. VNR has no independent assets or operations. Under the indenture governing the Senior Notes due 2020 (the “Senior Notes Indenture”), our Subsidiary Guarantors (other than VNRF) have unconditionally guaranteed, jointly and severally, on an unsecured basis, the Senior Notes due 2020, subject to release under certain of the following circumstances: (i) upon the sale or other disposition of all or substantially all of the subsidiary’s properties or assets, (ii) upon the sale or other disposition of our equity interests in the subsidiary, (iii) upon designation of the subsidiary as an unrestricted subsidiary in accordance with the terms of the Senior Notes Indenture, (iv) upon legal defeasance or covenant defeasance or the discharge of the Senior Notes Indenture, (v) upon the liquidation or dissolution of the subsidiary; (vi) upon the subsidiary ceasing to guarantee any other of our indebtedness and to be an obligor under any of our credit facilities, or (vii) upon such subsidiary dissolving or ceasing to exist after consolidating with, merging into or transferring all of its properties or assets to us. The Senior Notes Indenture also contains covenants that will limit our ability to (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) make distributions on, purchase or redeem our common units or purchase or redeem subordinated indebtedness; (iv) make investments; (v) restrict dividends, loans or other asset transfers from our restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of our properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; (viii) enter into transactions with affiliates; or (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the Senior Notes due 2020 achieve an investment grade rating from each of Standard & Poor’s Rating Services and Moody’s Investors Services, Inc. and no default under the Senior Notes Indenture exists, many of the foregoing covenants will terminate. As of June 30, 2016, based on the most restrictive covenants of the Senior Notes Indenture and as a result of our borrowing base deficiency, we are restricted from making distributions to our unitholders. In addition, a payment default under the Reserve Based Credit Facility could result in a cross default under Senior Notes due 2020. Interest on the Senior Notes due 2020 is payable on April 1 and October 1 of each year. We may redeem some or all of the Senior Notes due 2020 at any one or more occasions on or after April 1, 2016 at redemption prices of 103.93750% of the aggregate principal amount of the Senior Notes due 2020 as of April 1, 2016, plus accrued and unpaid interest, if any, on the Senior Notes due 2020 redeemed, declining to 100% on April 1, 2018 and thereafter. We had the option to redeem some or all of the Senior Notes due 2020 at any one or more occasions prior to April 1, 2016 at a redemption price equal to 100% of the aggregate principal amount of the Senior Notes due 2020 thereof, plus a “make-whole” premium, and accrued and unpaid interest to the redemption date. We did not redeem any of the Senior Notes due 2020 prior to April 1, 2016. If we sell certain of our assets or experience certain changes of control, we may be required to repurchase all or a portion of the Senior Notes due 2020 at a price equal to 100% and 101% of the aggregate principal amount of the Senior Notes due 2020, respectively. 7.0% Senior Secured Second Lien Notes Due 2023 On February 10, 2016, we issued approximately $75.6 million aggregate principal amount of new 7.0% Senior Secured Second Lien Notes due 2023 (the “Senior Secured Second Lien Notes”) to certain eligible holders of our outstanding 7.875% Senior Notes due 2020 in exchange for approximately $168.2 million aggregate principal amount of the Senior Notes due 2020 held by such holders. Interest on the Senior Secured Second Lien Notes is payable on February 15 and August 15 of each year, beginning on August 15, 2016. The Senior Secured Second Lien Notes will mature on (i) February 15, 2023 or (ii) December 31, 2019 if, prior to December 31, 2019, we have not repurchased, redeemed or otherwise repaid in full all of the Senior Notes due 2020 outstanding at that time in excess of $50.0 million in aggregate principal amount and, to the extent we repurchased, redeemed or otherwise repaid the Senior Notes due 2020 with proceeds of certain indebtedness, if such indebtedness has a final maturity date no earlier than the date that is 91 days after February 15, 2023. Under the indenture governing the Senior Secured Second Lien Notes (the “Senior Secured Second Lien Notes Indenture”), the Subsidiary Guarantors (other than VNRF) have unconditionally guaranteed, jointly and severally, the Senior Secured Second Lien Notes, subject to release under certain of the following circumstances: (i) upon the sale or other disposition of all or substantially all of the subsidiary’s properties or assets, (ii) upon the sale or other disposition of our equity interests in the subsidiary, (iii) upon designation of the subsidiary as an unrestricted subsidiary in accordance with the terms of the Senior Secured Second Lien Indenture, (iv) upon legal defeasance or covenant defeasance or the discharge of the Senior Secured Second Lien Notes Indenture, (v) upon the liquidation or dissolution of the subsidiary; (vi) upon the subsidiary ceasing to guarantee any other of our indebtedness and to be an obligor under any of our credit facilities, or (vii) upon such subsidiary dissolving or ceasing to exist after consolidating with, merging into or transferring all of its properties or assets to us. The Senior Secured Second Lien Notes Indenture also contains covenants that will limit our ability to (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) make distributions on, purchase or redeem our common units or purchase or redeem subordinated indebtedness; (iv) make investments; (v) restrict dividends, loans or other asset transfers from our restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of our properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; (viii) enter into transactions with affiliates; or (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the Senior Secured Second Lien Notes achieve an investment grade rating from each of Standard & Poor’s Rating Services and Moody’s Investors Services, Inc. and no default under the Senior Secured Second Lien Notes Indenture exists, many of the foregoing covenants will terminate. As of June 30, 2016, based on the most restrictive covenants of the Senior Secured Second Lien Notes Indenture and as a result of our borrowing base deficiency, we are restricted from making distributions to our unitholders. In addition, a payment default under the Reserve Based Credit Facility could result in a cross default under our Senior Secured Second Lien Notes. The exchanges were accounted for as an extinguishment of debt. As a result, we recorded a gain on extinguishment of debt of $89.7 million for the six months ended June 30, 2016, which is the difference between the aggregate fair market value of the Senior Secured Second Lien Notes issued and the carrying amount of Senior Notes due 2020 extinguished in the exchange, net of unamortized bond discount and deferred financing costs, of $165.3 million. Lease Financing Obligations On October 24, 2014, as part of our acquisition of certain natural gas, oil and NGLs assets in the Piceance Basin, we entered into an assignment and assumption agreement with Bank of America Leasing & Capital, LLC as the lead bank, whereby we acquired compressors and related facilities and assumed the related financing obligations (the “Lease Financing Obligations”). Certain rights, title, interest and obligations under the Lease Financing Obligations have been assigned to several lenders and are covered by separate assignment agreements, which expire on August 10, 2020 and July 10, 2021. We have the option to purchase the equipment at the end of the lease term for the current fair market value. The Lease Financing Obligations also contain an early buyout option whereby the Company may purchase the equipment for $16.0 million on February 10, 2019. The lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 4.16%. |
Price and Interest Rate Risk Management Activities |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Price and Interest Rate Risk Management Activities | Price and Interest Rate Risk Management Activities We have entered into derivative contracts primarily with counterparties that are also lenders under our Reserve-Based Credit Facility to hedge price risk associated with a portion of our oil, natural gas and NGLs production. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated which has, and could, result in overhedged volumes. Pricing for these derivative contracts is based on certain market indexes and prices at our primary sales points. We also enter into fixed LIBOR interest rate swap agreements with certain counterparties that are lenders under our Reserve-Based Credit Facility, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates. At June 30, 2016, the Company had open commodity derivative contracts covering our anticipated future production as follows: Fixed-Price Swaps (NYMEX)
Fixed-Price Swaps (Light Louisiana Sweet)
Call Options Sold
Swaptions
Basis Swaps
Three-Way Collars
Put Options Sold
Range Bonus Accumulators
Collars
Puts
Interest Rate Swaps At June 30, 2016, we had open interest rate derivative contracts as follows (in thousands):
Balance Sheet Presentation Our commodity derivatives and interest rate swap derivatives are presented on a net basis in “derivative assets” and “derivative liabilities” on the Consolidated Balance Sheets as governed by the International Swaps and Derivatives Association Master Agreement with each of the counterparties. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets for the periods indicated (in thousands):
By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, we expose ourselves to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. The majority of our counterparties are participants in our Reserve-Based Credit Facility (see Note 3. Long-Term Debt of the Notes to the Consolidated Financial Statements for further discussion), which is secured by our oil and natural gas properties; therefore, we are not required to post any collateral. The maximum amount of loss due to credit risk that we would incur if our counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $171.9 million at June 30, 2016. In accordance with our standard practice, our commodity and interest rate swap derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of such loss is somewhat mitigated as of June 30, 2016. We minimize the credit risk in derivative instruments by: (i) entering into derivative instruments primarily with counterparties that are also lenders in our Reserve-Based Credit Facility and (ii) monitoring the creditworthiness of our counterparties on an ongoing basis. Changes in fair value of our commodity and interest rate derivatives for the six months ended June 30, 2016 and the year ended December 31, 2015 are as follows:
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Fair Value Measurements |
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Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Measurements | Fair Value Measurements We estimate the fair values of financial and non-financial assets and liabilities under ASC Topic 820 “Fair Value Measurements and Disclosures” (“ASC Topic 820”). ASC Topic 820 provides a framework for consistent measurement of fair value for those assets and liabilities already measured at fair value under other accounting pronouncements. Certain specific fair value measurements, such as those related to share-based compensation, are not included in the scope of ASC Topic 820. Primarily, ASC Topic 820 is applicable to assets and liabilities related to financial instruments, to some long-term investments and liabilities, to initial valuations of assets and liabilities acquired in a business combination, recognition of asset retirement obligations and to long-lived assets written down to fair value when they are impaired. It does not apply to oil and natural gas properties accounted for under the full cost method, which are subject to impairment based on SEC rules. ASC Topic 820 applies to assets and liabilities carried at fair value on the Consolidated Balance Sheets, as well as to supplemental information about the fair values of financial instruments not carried at fair value. We have applied the provisions of ASC Topic 820 to assets and liabilities measured at fair value on a recurring basis, which includes our commodity and interest rate derivatives contracts, and on a nonrecurring basis, which includes goodwill, acquisitions of oil and natural gas properties and other intangible assets. ASC Topic 820 provides a definition of fair value and a framework for measuring fair value, as well as expanding disclosures regarding fair value measurements. The framework requires fair value measurement techniques to include all significant assumptions that would be made by willing participants in a market transaction. ASC Topic 820 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. ASC Topic 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to the “levels” described below. The hierarchy is based on the reliability of the inputs used in estimating fair value and requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The framework for fair value measurement assumes that transparent “observable” (Level 1) inputs generally provide the most reliable evidence of fair value and should be used to measure fair value whenever available. The classification of a fair value measurement is determined based on the lowest level (with Level 3 as the lowest) of significant input to the fair value estimation process. The standard describes three levels of inputs that may be used to measure fair value:
As required by ASC Topic 820, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value: Financing arrangements. The carrying amounts of our bank borrowings outstanding represent their approximate fair value because our current borrowing rates do not materially differ from market rates for similar bank borrowings. We consider this fair value estimate as a Level 2 input. As of June 30, 2016, the fair value of our Senior Notes due 2020 was estimated to be $132.7 million and our Senior Notes due 2019 was estimated to be $16.2 million. Our Senior Secured Second Lien Notes are a private debt and we estimated its fair value to be $26.3 million valued based on the prices used to estimate the fair value of our Senior Notes due 2020. We consider the inputs to the valuation of our Senior Notes to be Level 1 as fair value was estimated based on prices quoted from a third-party financial institution. Derivative instruments. Our commodity derivative instruments consist of fixed-price swaps, basis swaps, call options sold, swaptions, put options sold, call spreads, call options, put options, three-way collars and range bonus accumulators. We account for our commodity derivatives and interest rate derivatives at fair value on a recurring basis. We estimate the fair values of the fixed-price swaps and basis-swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate. We estimate the option value of the contract floors, ceilings and three-way collars using an option pricing model which takes into account market volatility, market prices and contract parameters. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. In order to estimate the fair value of our interest rate swaps, we use a yield curve based on money market rates and interest rate swaps, extrapolate a forecast of future interest rates, estimate each future cash flow, derive discount factors to value the fixed and floating rate cash flows of each swap, and then discount to present value all known (fixed) and forecasted (floating) swap cash flows. We consider the fair value estimate for these derivative instruments as a Level 2 input. We estimate the value of the range bonus accumulators using an option pricing model for both Asian Range Digital options and Asian Put options that takes into account market volatility, market prices and contract parameters. Range bonus accumulators are complex in structure requiring sophisticated valuation methods and greater subjectivity. As such, range bonus accumulators valuation may include inputs and assumptions that are less observable or require greater estimation, thereby resulting in valuations with less certainty. We consider the fair value estimate for range bonus accumulators as a Level 3 input. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Management validates the data provided by third parties by understanding the pricing models used, analyzing pricing data in certain situations and confirming that those securities trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to our commodity derivatives and interest rate derivatives. Financial assets and financial liabilities measured at fair value on a recurring basis are summarized below (in thousands):
The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 (unobservable inputs) in the fair value hierarchy:
During periods of market disruption, including periods of volatile oil and natural gas prices, there may be certain asset classes that were in active markets with observable data that become illiquid due to changes in the financial environment. In such cases, more derivative instruments, other than the range bonus accumulators, may fall to Level 3 and thus require more subjectivity and management judgment. Further, rapidly changing commodity and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within our consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on our results of operations or financial condition. We apply the provisions of ASC Topic 350 “Intangibles-Goodwill and Other.” Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is assessed for impairment annually on October 1 or whenever indicators of impairment exist. The goodwill test is performed at the reporting unit level, which represents our oil and natural gas operations in the United States. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. We utilize a market approach to determine the fair value of our reporting unit. While no goodwill impairment was recognized at June 30, 2016, any further significant decline in prices of oil and natural gas or significant negative reserve adjustments could change our estimate of the fair value of the reporting unit and could result in an impairment charge. Our nonfinancial assets and liabilities that are initially measured at fair value are comprised primarily of assets acquired in business combinations and asset retirement costs and obligations. These assets and liabilities are recorded at fair value when acquired/incurred but not re-measured at fair value in subsequent periods. We classify such initial measurements as Level 3 since certain significant unobservable inputs are utilized in their determination. A reconciliation of the beginning and ending balance of our asset retirement obligations is presented in Note 6, in accordance with ASC Topic 410-20 “Asset Retirement Obligations.” During the six months ended June 30, 2016, in connection with new wells drilled, we incurred and recorded asset retirement obligations totaling $0.3 million, at fair value and also recorded a $4.4 million reduction due to a change in estimate as a result of revisions to the timing or the amount of our original undiscounted estimated asset retirement costs during the six months ended June 30, 2016. During the year ended December 31, 2015, in connection with the oil and natural gas properties acquired in all of our acquisitions, the LRE Merger and the Eagle Rock Merger, as well as new wells drilled, we incurred and recorded asset retirement obligations totaling $90.9 million, at fair value. In addition, we recorded a $22.3 million change in estimate as a result of revisions to the timing or the amount of our original undiscounted estimated asset retirement costs during the year ended December 31, 2015. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Inputs to the valuation include: (1) estimated plug and abandonment cost per well based on our experience; (2) estimated remaining life per well based on average reserve life per field; (3) our credit-adjusted risk-free interest rate ranging between 4.6% and 5.5%; and (4) the average inflation factor (2.0%). These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change. |
Asset Retirement Obligations |
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Asset Retirement Obligation [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligations | Asset Retirement Obligations The asset retirement obligations as of June 30, 2016 and December 31, 2015 reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the six months ended June 30, 2016 and the year ended December 31, 2015 were as follows:
Each year the Company reviews and, to the extent necessary, revises its asset retirement obligation estimates. During the six months ended June 30, 2016 and year ended December 31, 2015, the Company reviewed actual abandonment costs with previous estimates and as a result, decreased its estimates of future asset retirement obligations by $4.4 million and increased its estimates of future asset retirement obligations by $22.3 million, respectively, to reflect revised estimates to be incurred for plugging and abandonment costs. |
Commitments and Contingencies |
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Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||
Commitments and Contingencies | Commitments and Contingencies Transportation Demand Charges As of June 30, 2016, we have contracts that provide firm transportation capacity on pipeline systems. The remaining terms on these contracts range from one month to four years and require us to pay transportation demand charges regardless of the amount of pipeline capacity we utilize. The values in the table below represent gross future minimum transportation demand charges we are obligated to pay as of June 30, 2016. However, our financial statements will reflect our proportionate share of the charges based on our working interest and net revenue interest, which will vary from property to property.
Legal Proceedings We are defendants in certain legal proceedings arising in the normal course of our business. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management does not believe that it is probable that the outcome of these actions will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flow. In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject. We are also a party to separate legal proceedings relating to (i) the LRE Merger, (ii) the Eagle Rock Merger and (iii) our exchange (the “Debt Exchange”) of the Senior Notes due 2020 for the Senior Secured Second Lien Notes (please read Note 3. Long-Term Debt of the Notes to the Consolidated Financial Statements for further discussion). Please read Part II, Item 1, Legal Proceedings for further discussion. |
Members’ Deficit and Net Loss per Common and Class B Unit |
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Equity [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Members’ Deficit and Net Loss per Common and Class B Unit | Members’ Deficit and Net Loss per Common and Class B Unit Cumulative Preferred Units The following table summarizes the Company’s Cumulative Preferred Units outstanding at June 30, 2016 and December 31, 2015:
The Cumulative Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by us or converted into our common units, at our option, in connection with a change of control. The Cumulative Preferred Units can be redeemed, in whole or in part, out of amounts legally available therefore, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. We may also redeem the Cumulative Preferred Units in the event of a change of control. Holders of the Cumulative Preferred Units will have no voting rights except for limited voting rights if we fail to pay dividends for eighteen or more monthly periods (whether or not consecutive) and in certain other limited circumstances or as required by law. The Cumulative Preferred Units have a liquidation preference which is equal to the redemption price described above. On February 25, 2016, our board of directors elected to suspend cash distributions to the holders of our common and Class B units and Cumulative Preferred Units effective with the February 2016 distribution. All preferred distributions will continue to accumulate and must be paid in full before distributions to common and Class B unitholders can resume. As of June 30, 2016, dividends in arrears related to our Cumulative Preferred Units were $1.7 million, $4.4 million and $2.8 million, respectively. Common and Class B Units The common units represent limited liability company interests. Holders of Class B units have substantially the same rights and obligations as the holders of common units. The following is a summary of the changes in our common units issued during the six months ended June 30, 2016 and the year ended December 31, 2015 (in thousands):
There was no change in issued and outstanding Class B units during the six months ended June 30, 2016 or the year ended December 31, 2015. Net Loss per Common and Class B Unit Basic net income per common and Class B unit is computed in accordance with ASC Topic 260 “Earnings Per Share” (“ASC Topic 260”) by dividing net income attributable to common and Class B unitholders, which reflects all accumulated distributions on Cumulative Preferred Units, including distributions in arrears, by the weighted average number of units outstanding during the period. Diluted net income per common and Class B unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. We use the treasury stock method to determine the dilutive effect. Class B units participate in distributions; therefore, all Class B units were considered in the computation of basic net income per unit. The Cumulative Preferred Units have no participation rights and accordingly are excluded from the computation of basic net income per unit. For the three months ended June 30, 2016 and 2015, 2,633,333 and 192,156 phantom units were excluded from the calculation of diluted earnings per unit, respectively, due to their antidilutive effect as we were in a loss position. For the six months ended June 30, 2016 and 2015, 2,633,333 and 211,400 phantom units were excluded from the calculation of diluted earnings per unit, respectively, due to their antidilutive effect as we were also in a loss position. Distributions Declared The Cumulative Preferred Units rank senior to our common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up. Distributions on the Cumulative Preferred Units are cumulative from the date of original issue and will be payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by our board of directors. Distributions on our Cumulative Preferred Units accumulate at a monthly rate of 7.875% per annum of the liquidation preference of $25.00 per Series A Cumulative Preferred Unit, a monthly rate of 7.625% per annum of the liquidation preference of $25.00 per Series B Cumulative Preferred Unit and a monthly rate of 7.75% per annum of the liquidation preference of $25.00 per Series C Cumulative Preferred Unit. The following table shows the distribution amount per unit, declared date, record date and payment date of the cash distributions we paid on each of our common and Class B units attributable to each period presented. Future distributions are at the discretion of our board of directors and will depend on business conditions, earnings, our cash requirements and other relevant factors. As discussed above, our board of directors elected to suspend cash distributions to the holders of our common and Class B units and Cumulative Preferred Units effective with the February 2016 distribution.
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Unit-Based Compensation |
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Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Unit-Based Compensation | Unit-Based Compensation Long-Term Incentive Plan The Vanguard Natural Resources, LLC Long-Term Incentive Plan (the “VNR LTIP”) was adopted by the Board of Directors of the Company to compensate employees and nonemployee directors of the Company and its affiliates who perform services for the Company under the terms of the plan. The VNR LTIP is administered by the compensation committee of the board of directors (the “Compensation Committee”) and permits the grant of unrestricted units, restricted units, phantom units, unit options and unit appreciation rights. Restricted and Phantom Units A restricted unit is a unit grant that vests over a period of time and that during such time is subject to forfeiture. A phantom unit grant represents the equivalent of one common unit of the Company. The phantom units, once vested, are settled through the delivery of a number of common units equal to the number of such vested units, or an amount of cash equal to the fair market value of such common units on the vesting date to be paid in a single lump sum payment, as determined by the compensation committee in its discretion. The Compensation Committee may grant tandem distribution equivalent rights (“DERs”) with respect to the phantom units that entitle the holder to receive the value of any distributions made by us on our units while the phantom units are outstanding. The fair value of restricted unit and phantom unit awards is measured based on the fair market value of the Company units on the date of grant. The values of restricted unit grants and phantom unit grants that are required to be settled in units are recognized as expense over the vesting period of the grants with a corresponding charge to members’ equity. When the Company has the option to settle the phantom unit grants by issuing Company units or through cash settlement, the Company recognizes the value of those grants utilizing the liability method as defined under ASC Topic 718 based on the Company’s historical practice of settling phantom units predominantly in cash. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period. Executive Employment Agreements On March 18, 2016, we and VNRH entered into new amended and restated executive employment agreements (the “Amended Agreements”) with each of our three executive officers, Messrs. Smith, Robert and Pence in order to set forth in writing the revised terms of each executive’s employment relationship with VNRH. The Amended Agreements were effective January 1, 2016 and the initial term of the Amended Agreements ends on January 1, 2019, with a subsequent twelve-month term extension automatically commencing on January 1, 2019 and each successive January 1 thereafter, provided that neither VNRH nor the executives deliver a timely non-renewal notice prior to a term expiration date. The Amended Agreements provide for the executive officers an annual base salary and eligibility to receive an annual performance-based cash bonus award. The annual bonus will be calculated based upon four Company performance components: adjusted EBITDA results, production results, lease operating expenses, and cash general and administrative expenses, as well as a fifth component determined solely in the discretion of our board of directors. As of June 30, 2016 and 2015, we recognized an accrued liability of $0.7 million related to the performance-based bonus award. In addition, compensation expense related to these arrangements of $0.7 million and $0.3 million were recorded for the three months ended June 30, 2016 and 2015, respectively, and $1.2 million and $0.7 million for the six months ended June 30, 2016 and 2015, respectively, which were classified in the selling, general and administrative expenses line item in the Consolidated Statement of Operations. Under the Amended Agreements, the executives are also eligible to receive annual equity-based compensation awards, consisting of restricted units and/or phantom units granted under the VNR LTIP. Any restricted units and phantom units granted to executives under the Amended Agreements are subject to a three-year vesting period. One-third of the aggregate number of the units vest on each one-year anniversary of the date of grant so long as the executive remains continuously employed with the Company. Both the restricted and phantom units include a tandem grant of DERs. 2016 Unit Grants In January 2016, the executives were granted a total of 2,255,033 phantom units in accordance with the Amended Agreements. Also, during the six months ended June 30, 2016, our three independent board members were granted a total of 125,838 phantom units which will vest one year from the date of grant. In addition, VNR employees were granted 1,331,579 phantom units under the VNR LTIP which will vest three years from the date of grant and a VNR employee was granted a total of 7,500 restricted units under the VNR LTIP of which one-third will vest on each one-year anniversary of the date of grant so long as the employee remains continuously employed with the Company. The phantom units include a tandem grant of DERs. Restricted Units A summary of the status of the non-vested restricted units as of June 30, 2016 is presented below:
At June 30, 2016, there was approximately $7.6 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over an average period of approximately 1.4 years. Our Consolidated Statements of Operations reflect non-cash compensation related to restricted unit grants of $1.4 million and $3.4 million in the selling, general and administrative expenses line item for the three months ended June 30, 2016 and 2015, respectively, and $2.6 million and $7.0 million for the six months ended June 30, 2016 and 2015, respectively. Phantom Units A summary of the status of the non-vested phantom units under the VNR LTIP as of June 30, 2016 is presented below:
At June 30, 2016, there was approximately $9.4 million of unrecognized compensation cost related to non-vested phantom units. The cost is expected to be recognized over an average period of approximately 1.4 years. Our Consolidated Statements of Operations reflect non-cash compensation related to phantom unit grants of $1.2 million and $0.4 million in the selling, general and administrative expense line item for the three months ended June 30, 2016 and 2015, respectively, and $2.4 million and $0.8 million for the six months ended June 30, 2016 and 2015, respectively. |
Summary of Significant Accounting Policies (Policies) |
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Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation and Principles of Consolidation | Basis of Presentation and Principles of Consolidation: The consolidated financial statements as of June 30, 2016 and December 31, 2015 and for the three and six months ended June 30, 2016 and 2015 include our accounts and those of our subsidiaries. We present our financial statements in accordance with GAAP. All intercompany transactions and balances have been eliminated upon consolidation. Additionally, our financial statements for prior periods include reclassifications that were made to conform to the current period presentation. Those reclassifications did not impact our reported net income (loss) or members’ equity. We consolidated Potato Hills Gas Gathering System as of the close date of the acquisition in January 2016 as we have the ability to control the operating and financial decisions and policies of the entity through our 51% ownership and reflected the non-controlling interest as a separate element in our consolidated financial statements. |
Oil and Natural Gas Properties | Oil and Natural Gas Properties: The full cost method of accounting is used to account for oil and natural gas properties. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil, natural gas and NGLs reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, both dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and ceiling test limitations as discussed below. Capitalized costs associated with proved reserves are amortized over the life of the reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties are excluded from the amortizable base until these properties are evaluated, which occurs on a quarterly basis. Specifically, costs are transferred to the amortizable base when properties are determined to have proved reserves. In addition, we transfer unproved property costs to the amortizable base when unproved properties are evaluated as being impaired and as exploratory wells are determined to be unsuccessful. Additionally, the amortizable base includes estimated future development costs, dismantlement, restoration and abandonment costs net of estimated salvage values. Capitalized costs are limited to a ceiling based on the present value of future net revenues, computed using the 12-month unweighted average of first-day-of-the-month historical price, the “12-month average price” discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the ceiling is less than the total capitalized costs, we are required to write-down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write-downs are included in the Consolidated Statements of Operations as an impairment charge. We recorded a non-cash ceiling test impairment of oil and natural gas properties for the six months ended June 30, 2016 of $365.7 million as a result of a decline in oil and natural gas prices at the measurement dates, March 31, 2016 and June 30, 2016. The impairment for the first quarter of 2016 was $207.8 million and was calculated based on the 12-month average price of $2.41 per MMBtu for natural gas and $46.16 per barrel of crude oil. The impairment for the second quarter of 2016 was $157.9 million and was calculated based on the 12-month average price of $2.24 per MMBtu for natural gas and $42.91 per barrel of crude oil. For the six months ended June 30, 2015, we recorded a non-cash ceiling test impairment of oil and natural gas properties of $866.0 million as a result of a decline in oil and natural gas prices at the measurement dates, March 31, 2015 and June 30, 2015. The impairment for the first quarter of 2015 was $132.6 million and was calculated based on the 12-month average price of $3.91 per MMBtu for natural gas and $82.62 per barrel of crude oil. The impairment for the second quarter of 2015 was $733.4 million and was calculated based on the 12-month average price of $3.44 per MMBtu for natural gas and $71.51 per barrel of crude oil. When we sell or convey interests in oil and natural gas properties, we reduce oil and natural gas reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and natural gas properties unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Sales proceeds on insignificant sales are treated as an adjustment to the cost of the properties. |
New Pronouncements Issued But Not Yet Adopted | New Pronouncement Issued But Not Yet Adopted: In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date (“ASU No. 2014-14”) to defer the effective date of ASU No. 2014-09 by one year. Public business entities must apply the guidance in ASU 2014-09 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We are evaluating the impact of the pending adoption of ASU No. 2014-09 on our financial position and results of operations and have not yet determined the method by which we will adopt the standard in 2018. In February 2016, the FASB issued ASU No. 2016-02, "Leases (Topic 842)", which requires lessees to recognize at the commencement date for all leases, with the exception of short-term leases, (a) a lease liability, which is a lessee‘s obligation to make lease payments arising from a lease, measured on a discounted basis, and (b) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The ASU on leases will take effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. We do not expect the adoption of ASU No. 2016-02 will have a material impact on our consolidated financial statements. In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. Under this ASU, the SEC Staff is rescinding certain SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities—Oil and Gas, effective upon adoption of Topic 606. As discussed above, Revenue from Contracts with Customers (Topic 606) is effective for public entities for fiscal years, and interim periods within the fiscal years, beginning after December 15, 2017. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU No. 2016-12”). The amendments under this ASU do not change the core revenue recognition principle in Topic 606. In addition, ASU No. 2016-12 provide clarifying guidance in certain narrow areas and add some practical expedients. These amendments are also effective at the same date that Topic 606 is effective. |
Use of Estimates | 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. The most significant estimates pertain to proved oil, natural gas and NGLs reserves and related cash flow estimates used in impairment tests of oil and natural gas properties and goodwill, the acquisition of oil and natural gas properties, the fair value of derivative contracts and asset retirement obligations, accrued oil, natural gas and NGLs revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion. Actual results could differ from those estimates. |
Prior Year Financial Statement Presentation | Prior Year Financial Statement Presentation Certain prior year balances have been reclassified to conform to the current year presentation of balances as stated in this Quarterly Report on Form 10-Q. Please read Note 3. Long-Term Debt of the Notes to the Consolidated Financial Statements for further discussion regarding this reclassification. |
Acquisitions and Divestitures (Tables) |
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Business Acquisition [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair value of assets and liabilities acquired |
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Pro Forma Information | The pro forma results reflect the results of combining our statement of operations with the results of operations from the oil and natural gas properties acquired during 2015 and eliminating the results of operations from the oil and natural gas properties divested in the SCOOP/STACK Divestiture, adjusted for (i) the assumption of asset retirement obligations and accretion expense for the properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired, (iii) interest expense on additional debt assumed in the LRE Merger and the Eagle Rock Merger, and (iv) the impact of the common units issued in the LRE Merger and the Eagle Rock Merger. The pro forma information is based upon these assumptions and is not necessarily indicative of future results of operations:
The amount of revenues and excess of revenues over direct operating expenses that were eliminated to reflect the impact of the SCOOP/STACK Divestiture in the pro forma results presented above are as follows (in thousands):
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Revenues and Excess of Revenues Over Direct Operating Expenses | The amount of revenues and excess of revenues over direct operating expenses included in the accompanying Consolidated Statements of Operations for our 2015 acquisitions are shown in the table that follows. Direct operating expenses include lease operating expenses, selling, general and administrative expenses and production and other taxes.
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Business Acquisition [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair value of assets and liabilities acquired |
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Long-Term Debt (Tables) |
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Debt Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Financing Arrangements | Our financing arrangements consisted of the following as of the date indicated:
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Borrowing Base Utilization Grid | Borrowing Base Utilization Grid
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Price and Interest Rate Risk Management Activities (Tables) |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commodity Derivative Contracts Covering Anticipated Future Production | At June 30, 2016, the Company had open commodity derivative contracts covering our anticipated future production as follows: Fixed-Price Swaps (NYMEX)
Fixed-Price Swaps (Light Louisiana Sweet)
Call Options Sold
Swaptions
Basis Swaps
Three-Way Collars
Put Options Sold
Range Bonus Accumulators
Collars
Puts
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Interest Rate Derivative Contracts | Interest Rate Swaps At June 30, 2016, we had open interest rate derivative contracts as follows (in thousands):
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Fair Value of Derivatives Outstanding | Our commodity derivatives and interest rate swap derivatives are presented on a net basis in “derivative assets” and “derivative liabilities” on the Consolidated Balance Sheets as governed by the International Swaps and Derivatives Association Master Agreement with each of the counterparties. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets for the periods indicated (in thousands):
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Reported Gains and Losses on Derivative Instruments | Changes in fair value of our commodity and interest rate derivatives for the six months ended June 30, 2016 and the year ended December 31, 2015 are as follows:
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Fair Value Measurements (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Financial Assets and Financial Liabilities Measured at Fair Value on a Recurring Basis | Financial assets and financial liabilities measured at fair value on a recurring basis are summarized below (in thousands):
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Reconciliation of changes in the fair value of assets and liabilities classified as Level 3 | The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 (unobservable inputs) in the fair value hierarchy:
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Asset Retirement Obligations (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligation [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Changes in Asset Retirement Obligations | The asset retirement obligations as of June 30, 2016 and December 31, 2015 reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the six months ended June 30, 2016 and the year ended December 31, 2015 were as follows:
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Commitments and Contingencies (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||
Future minimum transportation demand charges | The values in the table below represent gross future minimum transportation demand charges we are obligated to pay as of June 30, 2016. However, our financial statements will reflect our proportionate share of the charges based on our working interest and net revenue interest, which will vary from property to property.
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Members’ Deficit and Net Loss per Common and Class B Unit (Tables) |
6 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cumulative Preferred Units | The following table summarizes the Company’s Cumulative Preferred Units outstanding at June 30, 2016 and December 31, 2015:
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Schedule of Common and Class B Units Outstanding Roll Forward | The following is a summary of the changes in our common units issued during the six months ended June 30, 2016 and the year ended December 31, 2015 (in thousands):
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Distributions Declared | The following table shows the distribution amount per unit, declared date, record date and payment date of the cash distributions we paid on each of our common and Class B units attributable to each period presented. Future distributions are at the discretion of our board of directors and will depend on business conditions, earnings, our cash requirements and other relevant factors. As discussed above, our board of directors elected to suspend cash distributions to the holders of our common and Class B units and Cumulative Preferred Units effective with the February 2016 distribution.
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Unit-Based Compensation (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Jun. 30, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Share-based Compensation, Restricted Stock Units Award Activity | A summary of the status of the non-vested restricted units as of June 30, 2016 is presented below:
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Schedule of Nonvested Phantom Units Activity | A summary of the status of the non-vested phantom units under the VNR LTIP as of June 30, 2016 is presented below:
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Description of the Business (Details) |
6 Months Ended |
---|---|
Jun. 30, 2016
operating_areas
| |
Accounting Policies [Abstract] | |
Number of operating areas | 10 |
Summary of Significant Accounting Policies (Details) $ in Thousands |
3 Months Ended | 6 Months Ended | ||||
---|---|---|---|---|---|---|
Jun. 30, 2016
USD ($)
$ / bbl
$ / MMBTU
|
Mar. 31, 2016
USD ($)
$ / bbl
$ / MMBTU
|
Jun. 30, 2015
USD ($)
$ / bbl
$ / MMBTU
|
Mar. 31, 2015
USD ($)
$ / bbl
$ / MMBTU
|
Jun. 30, 2016
USD ($)
|
Jun. 30, 2015
USD ($)
|
|
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||||
Discount rate used in determining limitation of capitalized costs (in hundredths) | 10.00% | |||||
Impairment of oil and natural gas properties | $ | $ 157,894 | $ 207,800 | $ 733,365 | $ 132,600 | $ 365,658 | $ 865,975 |
Average price of natural gas used in the impairment calculation | $ / MMBTU | 2.24 | 2.41 | 3.44 | 3.91 | ||
Average price of crude oil used in the impairment calculation | $ / bbl | 42.91 | 46.16 | 71.51 | 82.62 | ||
Potato Hills Gas Gathering System [Member] | ||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||||
Ownership interest percent | 51.00% | 51.00% |
Acquisitions and Divestitures (Details) - USD ($) $ in Thousands |
6 Months Ended | |||
---|---|---|---|---|
May 19, 2016 |
Jul. 31, 2015 |
Jun. 30, 2016 |
Jun. 30, 2015 |
|
Business Acquisition [Line Items] | ||||
Ownership interest conveyed | 51.00% | |||
Proceeds from Sale of Oil and Gas Property and Equipment | $ 285,590 | $ 0 | ||
Series of Individually Immaterial Business Acquisitions [Member] | ||||
Business Acquisition [Line Items] | ||||
Fair value of consideration transferred | $ 11,400 | |||
Proceeds from Sale of Oil and Gas Property and Equipment | 21,200 | |||
SCOOP/STACK Divestiture [Member] | ||||
Business Acquisition [Line Items] | ||||
Business acquisitions, Agreed purchase price | $ 272,500 | |||
Proceeds | 263,100 | |||
Held in escrow | 9,400 | |||
Transaction fees | 2,100 | |||
Potato Hills Gas Gathering System [Member] | ||||
Business Acquisition [Line Items] | ||||
Fair value of consideration transferred | $ 7,700 | |||
Senior Secured Reserve-Based Credit Facility | SCOOP/STACK Divestiture [Member] | ||||
Business Acquisition [Line Items] | ||||
Line of credit repayment | $ 261,000 |
Acquisitions and Divestitures - Pro Forma (Details) - USD ($) $ / shares in Units, $ in Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2016 |
Jun. 30, 2015 |
Jun. 30, 2016 |
Jun. 30, 2015 |
|
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items] | ||||
Proforma revenues | $ 17,480 | $ 89,272 | $ 120,523 | $ 322,641 |
Proforma Net income | $ (269,028) | $ (844,023) | $ (425,383) | $ (1,044,315) |
Common and Class B units - basic and diluted (in USD per share) | $ (2.05) | $ (6.54) | $ (3.25) | $ (8.09) |
SCOOP/STACK Divestiture [Member] | ||||
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items] | ||||
Proforma revenues | $ 7,386 | $ 17,542 | ||
Excess of revenues over direct operating expenses | $ 6,222 | $ 15,278 |
Acquisitions and Divestitures - Acquiree Earnings (Details) - USD ($) $ in Thousands |
3 Months Ended | 6 Months Ended |
---|---|---|
Jun. 30, 2016 |
Jun. 30, 2016 |
|
EROC Merger [Member] | ||
Business Acquisition [Line Items] | ||
Revenues | $ 14,208 | $ 33,180 |
Excess of revenues over direct operating expenses | 7,182 | 17,723 |
LRE Merger [Member] | ||
Business Acquisition [Line Items] | ||
Revenues | 11,800 | 16,340 |
Excess of revenues over direct operating expenses | $ 5,362 | $ 6,854 |
Long-Term Debt - Financing Arrangements (Details) $ in Thousands |
6 Months Ended | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Jun. 30, 2016
USD ($)
payment
|
May 26, 2016
payment
|
Feb. 10, 2016 |
Dec. 31, 2015
USD ($)
|
||||||||||
Debt Instrument [Line Items] | |||||||||||||
Debt amount outstanding | $ 1,937,525 | $ 2,313,788 | |||||||||||
Current portion of debt under the Reserve-Based Credit Facility (5) | (86,040) | 0 | |||||||||||
Unamortized discount on Senior Notes | (15,131) | (17,651) | |||||||||||
Unamortized deferred financing costs | (11,915) | (13,705) | |||||||||||
Current portion of Lease Financing Obligation | (4,595) | (4,501) | |||||||||||
Total long-term debt | $ 1,819,844 | $ 2,277,931 | |||||||||||
Senior Secured Reserve-Based Credit Facility | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Interest rate description | [1] | Variable (1) | |||||||||||
Maturity date | Apr. 16, 2018 | ||||||||||||
Variable interest rate | 2.96% | 2.90% | |||||||||||
Debt amount outstanding | $ 1,406,500 | $ 1,688,000 | |||||||||||
Current portion of debt under the Reserve-Based Credit Facility (5) | $ (86,040) | 0 | |||||||||||
Number of monthly installments | payment | 5 | 6 | |||||||||||
Senior Notes due 2019 [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Stated interest rate (in hundredths) | [2] | 8.375% | |||||||||||
Maturity date | Jun. 01, 2019 | ||||||||||||
Debt Instrument, Interest Rate, Effective Percentage | 21.45% | ||||||||||||
Debt amount outstanding | $ 51,120 | 51,120 | |||||||||||
Senior Notes due 2020 [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Stated interest rate (in hundredths) | [3] | 7.875% | |||||||||||
Maturity date | Apr. 01, 2020 | ||||||||||||
Debt Instrument, Interest Rate, Effective Percentage | 8.00% | ||||||||||||
Debt amount outstanding | $ 381,830 | 550,000 | |||||||||||
Subordinated Debt due 2023 | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Stated interest rate (in hundredths) | 7.00% | 7.00% | |||||||||||
Maturity date | Feb. 15, 2023 | ||||||||||||
Debt amount outstanding | $ 75,634 | 0 | |||||||||||
Lease Financing Obligations | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Stated interest rate (in hundredths) | 4.16% | ||||||||||||
Maturity date | [4] | Aug. 10, 2020 | |||||||||||
Debt amount outstanding | $ 22,441 | $ 24,668 | |||||||||||
|
Long-Term Debt - Borrowing Base Utilization Grid (Details) |
6 Months Ended |
---|---|
Jun. 30, 2016 | |
Borrowing Base Utilization Less Than 25% | |
Debt Instrument [Line Items] | |
Commitment fee rate (in hundredths) | 0.50% |
Letter of credit fee (in hundredths) | 0.50% |
Borrowing Base Utilization Less Than 25% | Eurodollar Loans Margin | |
Debt Instrument [Line Items] | |
Loans margin (in hundredths) | 1.50% |
Borrowing Base Utilization Less Than 25% | ABR Loans Margin | |
Debt Instrument [Line Items] | |
Loans margin (in hundredths) | 0.50% |
Borrowing Base Utilization Greater Than Or Equal To 25% But Less Than 50% | |
Debt Instrument [Line Items] | |
Commitment fee rate (in hundredths) | 0.50% |
Letter of credit fee (in hundredths) | 0.75% |
Borrowing Base Utilization Greater Than Or Equal To 25% But Less Than 50% | Eurodollar Loans Margin | |
Debt Instrument [Line Items] | |
Loans margin (in hundredths) | 1.75% |
Borrowing Base Utilization Greater Than Or Equal To 25% But Less Than 50% | ABR Loans Margin | |
Debt Instrument [Line Items] | |
Loans margin (in hundredths) | 0.75% |
Borrowing Base Utilization Greater Than Or Equal To 50% But Less Than 75% | |
Debt Instrument [Line Items] | |
Commitment fee rate (in hundredths) | 0.375% |
Letter of credit fee (in hundredths) | 1.00% |
Borrowing Base Utilization Greater Than Or Equal To 50% But Less Than 75% | Eurodollar Loans Margin | |
Debt Instrument [Line Items] | |
Loans margin (in hundredths) | 2.00% |
Borrowing Base Utilization Greater Than Or Equal To 50% But Less Than 75% | ABR Loans Margin | |
Debt Instrument [Line Items] | |
Loans margin (in hundredths) | 1.00% |
Borrowing Base Utilization Greater Than Or Equal To 75% But Less Than 90% | |
Debt Instrument [Line Items] | |
Commitment fee rate (in hundredths) | 0.375% |
Letter of credit fee (in hundredths) | 1.25% |
Borrowing Base Utilization Greater Than Or Equal To 75% But Less Than 90% | Eurodollar Loans Margin | |
Debt Instrument [Line Items] | |
Loans margin (in hundredths) | 2.25% |
Borrowing Base Utilization Greater Than Or Equal To 75% But Less Than 90% | ABR Loans Margin | |
Debt Instrument [Line Items] | |
Loans margin (in hundredths) | 1.25% |
Borrowing Base Utilization Equal To Or Greater Than 90% | |
Debt Instrument [Line Items] | |
Commitment fee rate (in hundredths) | 0.375% |
Letter of credit fee (in hundredths) | 1.50% |
Borrowing Base Utilization Equal To Or Greater Than 90% | Eurodollar Loans Margin | |
Debt Instrument [Line Items] | |
Loans margin (in hundredths) | 2.50% |
Borrowing Base Utilization Equal To Or Greater Than 90% | ABR Loans Margin | |
Debt Instrument [Line Items] | |
Loans margin (in hundredths) | 1.50% |
Price and Interest Rate Risk Management Activities (Details) $ in Thousands |
6 Months Ended |
---|---|
Jun. 30, 2016
USD ($)
MMBTU
$ / bbl
$ / MMBTU
bbl
| |
Fair value of derivatives [Abstract] | |
Maximum potential loss due to credit risk | $ | $ 171,900 |
Fixed-Price Swaps | Gas | Contract period July 1, 2016 to December 31, 2016 [Member] | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Gas Production Being Hedged | MMBTU | 36,528,944 |
Weighted average fixed price (in dollars per unit) | $ / MMBTU | 4.36 |
Fixed-Price Swaps | Gas | Contract period January 1, 2017 to December 31, 2017 | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Gas Production Being Hedged | MMBTU | 53,725,260 |
Weighted average fixed price (in dollars per unit) | $ / MMBTU | 3.75 |
Fixed-Price Swaps | Oil | Contract period July 1, 2016 to December 31, 2016 [Member] | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Oil and liquids Production Being Hedged | bbl | 938,283 |
Weighted average fixed price (in dollars per unit) | 84.00 |
Fixed-Price Swaps | Oil | Contract period January 1, 2017 to December 31, 2017 | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Oil and liquids Production Being Hedged | bbl | 749,698 |
Weighted average fixed price (in dollars per unit) | 85.70 |
Fixed-Price Swaps | Oil | Contract period January 1, 2017 to December 31, 2017 | Light Louisiana Sweet [Member] | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Oil and liquids Production Being Hedged | bbl | 168,000 |
Weighted average fixed price (in dollars per unit) | 91.25 |
Fixed-Price Swaps | Natural Gas Liquids | Contract period July 1, 2016 to December 31, 2016 [Member] | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Oil and liquids Production Being Hedged | bbl | 455,000 |
Weighted average fixed price (in dollars per unit) | 30.31 |
Fixed-Price Swaps | Natural Gas Liquids | Contract period January 1, 2017 to December 31, 2017 | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Oil and liquids Production Being Hedged | bbl | 0 |
Weighted average fixed price (in dollars per unit) | 0.00 |
Call Option [Member] | Gas | Contract period July 1, 2016 to December 31, 2016 [Member] | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Gas Production Being Hedged | MMBTU | 4,600,000 |
Weighted average fixed price (in dollars per unit) | $ / MMBTU | 4.25 |
Call Option [Member] | Gas | Contract period January 1, 2017 to December 31, 2017 | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Gas Production Being Hedged | MMBTU | 11,862,500 |
Weighted average fixed price (in dollars per unit) | $ / MMBTU | 3.01 |
Call Option [Member] | Oil | Contract period July 1, 2016 to December 31, 2016 [Member] | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Oil and liquids Production Being Hedged | bbl | 312,800 |
Weighted average fixed price (in dollars per unit) | 50.00 |
Call Option [Member] | Oil | Contract period January 1, 2017 to December 31, 2017 | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Oil and liquids Production Being Hedged | bbl | 365,000 |
Weighted average fixed price (in dollars per unit) | 95.00 |
Swaption [Member] | Gas | Contract period January 1, 2017 to December 31, 2017 | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Gas Production Being Hedged | MMBTU | 2,062,500 |
Weighted average fixed price (in dollars per unit) | $ / MMBTU | 2.74 |
Swaption [Member] | Gas | Contract period January 1, 2018 to December 31, 2018 [Member] | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Gas Production Being Hedged | MMBTU | 675,000 |
Weighted average fixed price (in dollars per unit) | $ / MMBTU | 2.74 |
Basis Swaps | Gas | Contract period July 1, 2016 to December 31, 2016 [Member] | NW Rocky Mt-Henry Hub Index | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Gas Production Being Hedged | MMBTU | 19,320,000 |
Weighted average basis differential (in dollars per unit) | $ / MMBTU | (0.20) |
Basis Swaps | Gas | Contract period July 1, 2016 to December 31, 2016 [Member] | Houston Ship Channel-Henry Hub Index [Member] | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Gas Production Being Hedged | MMBTU | 477,354 |
Weighted average basis differential (in dollars per unit) | $ / MMBTU | (0.08) |
Basis Swaps | Gas | Contract period July 1, 2016 to December 31, 2016 [Member] | TexOk- Henry Hub Index [Member] | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Gas Production Being Hedged | MMBTU | 140,433 |
Weighted average basis differential (in dollars per unit) | $ / MMBTU | (0.10) |
Basis Swaps | Gas | Contract period July 1, 2016 to December 31, 2016 [Member] | WAHA - Henry Hub Index [Member] | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Gas Production Being Hedged | MMBTU | 788,896 |
Weighted average basis differential (in dollars per unit) | $ / MMBTU | (0.13) |
Basis Swaps | Gas | Contract period January 1, 2017 to December 31, 2017 | NW Rocky Mt-Henry Hub Index | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Gas Production Being Hedged | MMBTU | 21,900,000 |
Weighted average basis differential (in dollars per unit) | $ / MMBTU | (0.20) |
Basis Swaps | Oil | Contract period July 1, 2016 to December 31, 2016 [Member] | Midland-Cushing Index | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Oil and liquids Production Being Hedged | bbl | 486,000 |
Weighted average basis differential (in dollars per unit) | (1.01) |
Basis Swaps | Oil | Contract period July 1, 2016 to December 31, 2016 [Member] | WTS-Cushing Index | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Oil and liquids Production Being Hedged | bbl | 110,400 |
Weighted average basis differential (in dollars per unit) | (0.43) |
Basis Swaps | Oil | Contract period July 1, 2016 to December 31, 2016 [Member] | WTI-WCS Index | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Oil and liquids Production Being Hedged | bbl | 368,000 |
Weighted average basis differential (in dollars per unit) | (14.25) |
Three-Way Collars | Gas | Contract period July 1, 2016 to December 31, 2016 [Member] | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Gas Production Being Hedged | MMBTU | 6,440,000 |
Weighted average price (in dollars per unit) | $ / MMBTU | 3.00 |
Floor (in dollars per unit) | $ / MMBTU | 3.95 |
Ceiling (in dollars per unit) | $ / MMBTU | 4.25 |
Three-Way Collars | Gas | Contract period January 1, 2017 to December 31, 2017 | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Gas Production Being Hedged | MMBTU | 14,600,000 |
Weighted average price (in dollars per unit) | $ / MMBTU | 3.31 |
Floor (in dollars per unit) | $ / MMBTU | 3.88 |
Ceiling (in dollars per unit) | $ / MMBTU | 4.15 |
Three-Way Collars | Oil | Contract period July 1, 2016 to December 31, 2016 [Member] | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Oil and liquids Production Being Hedged | bbl | 533,600 |
Weighted average price (in dollars per unit) | 73.62 |
Floor (in dollars per unit) | 90.00 |
Ceiling (in dollars per unit) | 96.18 |
Put Options Sold | Gas | Contract period July 1, 2016 to December 31, 2016 [Member] | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Gas Production Being Hedged | MMBTU | 920,000 |
Weighted average price (in dollars per unit) | $ / MMBTU | 3.00 |
Put Options Sold | Gas | Contract period January 1, 2017 to December 31, 2017 | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Gas Production Being Hedged | MMBTU | 1,825,000 |
Weighted average price (in dollars per unit) | $ / MMBTU | 3.50 |
Put Options Sold | Oil | Contract period July 1, 2016 to December 31, 2016 [Member] | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Oil and liquids Production Being Hedged | bbl | 73,600 |
Weighted average price (in dollars per unit) | 75.00 |
Put Options Sold | Oil | Contract period January 1, 2017 to December 31, 2017 | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Oil and liquids Production Being Hedged | bbl | 73,000 |
Weighted average price (in dollars per unit) | 75.00 |
Range Bonus Accumulators | Oil | Contract period July 1, 2016 to December 31, 2016 [Member] | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Floor (in dollars per unit) | 75.00 |
Derivative, Nonmonetary Notional Amount, Volume | bbl | 92,000 |
Ceiling (in dollars per unit) | 100.00 |
Bonus (in dollars per unit) | 4.00 |
Collars | Oil | Contract period July 1, 2016 to December 31, 2016 [Member] | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Oil and liquids Production Being Hedged | bbl | 322,000 |
Floor (in dollars per unit) | 41.00 |
Ceiling (in dollars per unit) | 50.57 |
Puts | Oil | Contract period July 1, 2016 to December 31, 2016 [Member] | |
Commodity derivative contracts covering our anticipated future production [Abstract] | |
Portion of Future Oil and liquids Production Being Hedged | bbl | 184,000 |
Derivative, Price Risk Option Strike Price | 60.00 |
Interest Rate Swaps | |
Interest rate derivative contracts [Abstract] | |
Notional amount | $ | $ 630,000 |
Interest Rate Swaps | Contract period July 1, 2016 to December 10, 2016 [Member] | |
Interest rate derivative contracts [Abstract] | |
Notional amount | $ | $ 20,000 |
Fixed Libor Rates (in hundredths) | 2.17% |
Interest Rate Swaps | Contract period July 1, 2016 to October 31, 2016 Swap A [Member] | |
Interest rate derivative contracts [Abstract] | |
Notional amount | $ | $ 40,000 |
Fixed Libor Rates (in hundredths) | 1.65% |
Interest Rate Swaps | Contract period July 1, 2016 to August 5, 2018 [Member] | |
Interest rate derivative contracts [Abstract] | |
Notional amount | $ | $ 30,000 |
Fixed Libor Rates (in hundredths) | 2.25% |
Interest Rate Swaps | Contract period July 1, 2016 to August 6, 2016 [Member] | |
Interest rate derivative contracts [Abstract] | |
Notional amount | $ | $ 25,000 |
Fixed Libor Rates (in hundredths) | 1.80% |
Interest Rate Swaps | Contract period July 1, 2016 to October 31, 2016 Swap B [Member] | |
Interest rate derivative contracts [Abstract] | |
Notional amount | $ | $ 20,000 |
Fixed Libor Rates (in hundredths) | 1.78% |
Interest Rate Swaps | Contract period July 1, 2016 to September 23, 2016 [Member] | |
Interest rate derivative contracts [Abstract] | |
Notional amount | $ | $ 75,000 |
Fixed Libor Rates (in hundredths) | 1.149% |
Interest Rate Swaps | Contract period July 1, 2016 to September 7, 2016 [Member] | |
Interest rate derivative contracts [Abstract] | |
Notional amount | $ | $ 25,000 |
Fixed Libor Rates (in hundredths) | 1.25% |
Interest Rate Swaps | Contract period July 1, 2016 to December 31, 2019 [Member] | |
Interest rate derivative contracts [Abstract] | |
Notional amount | $ | $ 175,000 |
Fixed Libor Rates (in hundredths) | 2.3195% |
Interest Rate Swaps | Contract period July 1, 2016 to February 16, 2017 Swap A [Member] | |
Interest rate derivative contracts [Abstract] | |
Notional amount | $ | $ 75,000 |
Fixed Libor Rates (in hundredths) | 1.7275% |
Interest Rate Swaps | Contract period July 1, 2016 to June 16, 2017 [Member] | |
Interest rate derivative contracts [Abstract] | |
Notional amount | $ | $ 70,000 |
Fixed Libor Rates (in hundredths) | 1.4275% |
Interest Rate Swaps | Contract period July 1, 2016 to February 16, 2017 Swap B [Member] | |
Interest rate derivative contracts [Abstract] | |
Notional amount | $ | $ 75,000 |
Fixed Libor Rates (in hundredths) | 1.725% |
Price and Interest Rate Risk Management Activities - Balance Sheet Presentation (Details) - USD ($) $ in Thousands |
Jun. 30, 2016 |
Dec. 31, 2015 |
---|---|---|
Offsetting Derivative Assets: | ||
Gross amounts of recognized assets | $ 171,889 | $ 349,281 |
Gross amounts offset in the consolidated balance sheets | (37,851) | (32,234) |
Net Amounts Presented in the Consolidated Balance Sheets | 134,038 | 317,047 |
Offsetting Derivative Liabilities: | ||
Gross amounts of recognized liabilities | (38,582) | (32,590) |
Gross amounts offset in the consolidated balance sheets | 37,851 | 32,234 |
Net Amounts Presented in the Consolidated Balance Sheets | (731) | (356) |
Commodity Contract | ||
Offsetting Derivative Assets: | ||
Gross amounts of recognized assets | 171,889 | 349,281 |
Gross amounts offset in the consolidated balance sheets | (25,165) | (21,834) |
Net Amounts Presented in the Consolidated Balance Sheets | 146,724 | 327,447 |
Offsetting Derivative Liabilities: | ||
Gross amounts of recognized liabilities | (25,828) | (21,934) |
Gross amounts offset in the consolidated balance sheets | 25,165 | 21,834 |
Net Amounts Presented in the Consolidated Balance Sheets | (663) | (100) |
Interest Rate Contract | ||
Offsetting Derivative Assets: | ||
Gross amounts of recognized assets | 0 | 0 |
Gross amounts offset in the consolidated balance sheets | (12,686) | (10,400) |
Net Amounts Presented in the Consolidated Balance Sheets | (12,686) | (10,400) |
Offsetting Derivative Liabilities: | ||
Gross amounts of recognized liabilities | (12,754) | (10,656) |
Gross amounts offset in the consolidated balance sheets | 12,686 | 10,400 |
Net Amounts Presented in the Consolidated Balance Sheets | $ (68) | $ (256) |
Price and Interest Rate Risk Management Activities - Change in Fair Value of Derivatives (Details) - USD ($) $ in Thousands |
6 Months Ended | 12 Months Ended | |
---|---|---|---|
Jun. 30, 2016 |
Jun. 30, 2015 |
Dec. 31, 2015 |
|
Fair Value, Net Derivative Asset (Liability), Reconciliation [Roll Forward] | |||
Derivative asset at beginning of period, net | $ 316,691 | $ 220,734 | $ 220,734 |
Fair value of derivatives acquired | 195,273 | ||
Net premiums and fees (received) paid or deferred for derivative contracts | (1,959) | 7,126 | |
Net gains on commodity and interest rate derivative contracts | (43,676) | 36,749 | 169,569 |
Cash settlement received on matured commodity derivative contracts | (142,476) | (80,620) | (211,723) |
Cash settlements paid on matured interest rate derivative contracts | 4,727 | $ 1,980 | 5,227 |
Termination of derivative contracts | (69,515) | ||
Derivative asset at end of period, net | $ 133,307 | $ 316,691 |
Fair Value Measurements (Details) - USD ($) $ in Thousands |
6 Months Ended | 12 Months Ended |
---|---|---|
Jun. 30, 2016 |
Dec. 31, 2015 |
|
Liabilities: | ||
Asset retirement obligations incurred and recorded | $ 287 | $ 2,699 |
Change in estimate | $ (4,368) | 22,329 |
Asset retirement obligations incurred and assumed from business combinations | 90,900 | |
Average inflation rate (in hundredths) | 1.97% | |
Fair Value Measured on a Recurring Basis | ||
Assets: | ||
Commodity price derivative contracts | $ 146,724 | 327,447 |
Interest Rate Derivative Assets, at Fair Value | (12,686) | (10,400) |
Total derivative instruments | 134,038 | 317,047 |
Liabilities: | ||
Commodity price derivative contracts | (99) | |
Interest rate derivative contracts | (68) | (257) |
Total derivative instruments | (731) | (356) |
Fair Value Measured on a Recurring Basis | Fair Value Measurements Using Level 1 | ||
Assets: | ||
Commodity price derivative contracts | 0 | 0 |
Interest Rate Derivative Assets, at Fair Value | 0 | 0 |
Total derivative instruments | 0 | 0 |
Liabilities: | ||
Commodity price derivative contracts | 0 | |
Interest rate derivative contracts | 0 | 0 |
Total derivative instruments | 0 | 0 |
Fair Value Measured on a Recurring Basis | Fair Value Measurements Using Level 2 | ||
Assets: | ||
Commodity price derivative contracts | 148,960 | 333,380 |
Interest Rate Derivative Assets, at Fair Value | (12,686) | (10,400) |
Total derivative instruments | 136,274 | 322,980 |
Liabilities: | ||
Commodity price derivative contracts | (99) | |
Interest rate derivative contracts | (68) | (257) |
Total derivative instruments | (731) | (356) |
Fair Value Measured on a Recurring Basis | Fair Value Measurements Using Level 3 | ||
Assets: | ||
Commodity price derivative contracts | (2,236) | (5,933) |
Interest Rate Derivative Assets, at Fair Value | 0 | 0 |
Total derivative instruments | (2,236) | (5,933) |
Liabilities: | ||
Commodity price derivative contracts | 0 | |
Interest rate derivative contracts | 0 | 0 |
Total derivative instruments | $ 0 | $ 0 |
Minimum | ||
Liabilities: | ||
Credit-adjusted risk-free interest rate (in hundredths) | 4.60% | |
Maximum | ||
Liabilities: | ||
Credit-adjusted risk-free interest rate (in hundredths) | 5.50% | |
Senior Notes due 2019 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Debt, fair value | $ 16,200 | |
Senior Notes due 2020 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Debt, fair value | 132,700 | |
Subordinated Debt due 2023 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Debt, fair value | $ 26,300 |
Fair Value Measurements - Unobservable Inputs Reconciliation (Details) - Fair Value Measurements Using Level 3 - USD ($) $ in Thousands |
6 Months Ended | |
---|---|---|
Jun. 30, 2016 |
Jun. 30, 2015 |
|
Unobservable inputs reconciliation | ||
Unobservable inputs, beginning of period | $ (5,933) | $ (6,470) |
Total gains | 6,922 | 4,417 |
Settlements | (3,225) | (1,869) |
Unobservable inputs, end of period | (2,236) | (3,922) |
Change in fair value included in earnings related to derivatives still held as of June 30, | $ 589 | $ 734 |
Asset Retirement Obligations (Details) - USD ($) $ in Thousands |
6 Months Ended | 12 Months Ended |
---|---|---|
Jun. 30, 2016 |
Dec. 31, 2015 |
|
Changes in asset retirement obligations [Abstract] | ||
Asset retirement obligations at beginning of period | $ 271,456 | $ 149,062 |
Liabilities added during the current period | 287 | 2,699 |
Asset retirement obligations assumed in a business combination | 0 | 88,228 |
Accretion expense | 6,150 | 10,238 |
Retirements | (249) | (838) |
Disposition of properties | (5,964) | (262) |
Change in estimate | (4,368) | 22,329 |
Total asset retirement obligations at end of period | 267,312 | 271,456 |
Less: current obligations | (8,383) | (9,024) |
Long-term asset retirement obligation at end of period | $ 258,929 | $ 262,432 |
Commitments and Contingencies - Transportation Demand Charges (Details) $ in Thousands |
6 Months Ended |
---|---|
Jun. 30, 2016
USD ($)
| |
Gross future minimum transportation demand | |
July 1, 2016 - December 31, 2016 | $ 6,972 |
Due 2017 | 12,512 |
Due 2018 | 11,696 |
Due 2019 | 9,661 |
Due 2020 | 410 |
Total | $ 41,251 |
Minimum | |
Oil and Gas Delivery Commitments and Contracts | |
Oil and Gas Delivery Commitments and Contracts, Length of Contract | 1 month |
Maximum | |
Oil and Gas Delivery Commitments and Contracts | |
Oil and Gas Delivery Commitments and Contracts, Length of Contract | 4 years |
Members’ Deficit and Net Loss per Common and Class B Unit - Preferred Units Outstanding (Details) - USD ($) $ / shares in Units, $ in Thousands |
6 Months Ended | |
---|---|---|
Jun. 30, 2016 |
Dec. 31, 2015 |
|
Class of Stock [Line Items] | ||
Liquidation Preference Per Share (usd per share) | $ 25.00 | |
Units Outstanding (shares) | 13,881,873 | 13,881,873 |
Carrying Value | $ 335,444 | $ 335,444 |
Series A Preferred Units | ||
Class of Stock [Line Items] | ||
Liquidation Preference Per Share (usd per share) | $ 25.00 | |
Distribution Rate | 7.875% | |
Units Outstanding (shares) | 2,581,873 | 2,581,873 |
Carrying Value | $ 62,200 | $ 62,200 |
Preferred Stock, Amount of Preferred Dividends in Arrears | $ 1,700 | |
Series B Preferred Unit | ||
Class of Stock [Line Items] | ||
Liquidation Preference Per Share (usd per share) | $ 25.00 | |
Distribution Rate | 7.625% | |
Units Outstanding (shares) | 7,000,000 | 7,000,000 |
Carrying Value | $ 169,265 | $ 169,265 |
Preferred Stock, Amount of Preferred Dividends in Arrears | $ 4,400 | |
Series C Preferred Units | ||
Class of Stock [Line Items] | ||
Liquidation Preference Per Share (usd per share) | $ 25.00 | |
Distribution Rate | 7.75% | |
Units Outstanding (shares) | 4,300,000 | 4,300,000 |
Carrying Value | $ 103,979 | $ 103,979 |
Preferred Stock, Amount of Preferred Dividends in Arrears | $ 2,800 |
Members’ Deficit and Net Loss per Common and Class B Unit - Common and Class B Units Rollforward (Details) - shares shares in Thousands |
6 Months Ended | 12 Months Ended |
---|---|---|
Jun. 30, 2016 |
Dec. 31, 2015 |
|
Common Units | ||
Increase (Decrease) in Members' Equity [Roll Forward] | ||
Beginning of period (shares) | 130,477 | 83,452 |
Issuance of Common units for cash (shares) | 0 | 2,430 |
Repurchase of units under the Common unit buyback program (shares) | 0 | (157) |
Unit-based compensation (shares) | 565 | 1,418 |
End of period (shares) | 131,042 | 130,477 |
EROC Merger [Member] | ||
Increase (Decrease) in Members' Equity [Roll Forward] | ||
Partners' Capital Account, Units, Acquisitions | 0 | 27,886 |
LRE Merger [Member] | ||
Increase (Decrease) in Members' Equity [Roll Forward] | ||
Partners' Capital Account, Units, Acquisitions | 0 | 15,448 |
Members’ Deficit and Net Loss per Common and Class B Unit - Net Income per Unit (Details) - shares |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2016 |
Jun. 30, 2015 |
Jun. 30, 2016 |
Jun. 30, 2015 |
|
Equity [Abstract] | ||||
Antidilutive securities excluded from computation (shares) | 2,633,333 | 192,156 | 2,633,333 | 211,400 |
Members’ Deficit and Net Loss per Common and Class B Unit - Distributions Declared (Details) - $ / shares |
1 Months Ended | 6 Months Ended | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Jan. 31, 2016 |
Dec. 31, 2015 |
Nov. 30, 2015 |
Oct. 31, 2015 |
Sep. 30, 2015 |
Aug. 31, 2015 |
Jul. 31, 2015 |
Jun. 30, 2015 |
May 31, 2015 |
Apr. 30, 2015 |
Mar. 31, 2015 |
Feb. 28, 2015 |
Jan. 31, 2015 |
Dec. 31, 2014 |
Jun. 30, 2016 |
|
Class of Stock [Line Items] | |||||||||||||||
Preferred Unit, Liquidation Preference Per Share (usd per share) | $ 25.00 | ||||||||||||||
Common Units | |||||||||||||||
Class of Stock [Line Items] | |||||||||||||||
Cash Distributions per Unit (usd per share) | $ 0.03 | $ 0.03 | $ 0.03 | $ 0.1175 | $ 0.1175 | $ 0.1175 | $ 0.1175 | $ 0.1175 | $ 0.1175 | $ 0.1175 | $ 0.1175 | $ 0.1175 | $ 0.1175 | $ 0.21 | |
Cash distribution, declaration date | Feb. 18, 2016 | Jan. 20, 2016 | Dec. 18, 2015 | Nov. 20, 2015 | Oct. 19, 2015 | Sep. 21, 2015 | Aug. 20, 2015 | Jul. 16, 2015 | Jun. 18, 2015 | May 19, 2015 | Apr. 15, 2015 | Mar. 18, 2015 | Feb. 17, 2015 | Jan. 22, 2015 | |
Cash Distributions Record Date | Mar. 01, 2016 | Feb. 01, 2016 | Jan. 04, 2016 | Dec. 01, 2015 | Nov. 02, 2015 | Oct. 01, 2015 | Sep. 01, 2015 | Aug. 03, 2015 | Jul. 01, 2015 | Jun. 01, 2015 | May 01, 2015 | Apr. 01, 2015 | Mar. 02, 2015 | Feb. 02, 2015 | |
Cash Distributions Payment Date | Mar. 15, 2016 | Feb. 12, 2016 | Jan. 14, 2016 | Dec. 15, 2015 | Nov. 13, 2015 | Oct. 15, 2015 | Sep. 14, 2015 | Aug. 14, 2015 | Jul. 15, 2015 | Jun. 12, 2015 | May 15, 2015 | Apr. 14, 2015 | Mar. 17, 2015 | Feb. 13, 2015 | |
Series A Preferred Units | |||||||||||||||
Class of Stock [Line Items] | |||||||||||||||
Distribution Rate | 7.875% | ||||||||||||||
Preferred Unit, Liquidation Preference Per Share (usd per share) | $ 25.00 | ||||||||||||||
Series B Preferred Unit | |||||||||||||||
Class of Stock [Line Items] | |||||||||||||||
Distribution Rate | 7.625% | ||||||||||||||
Preferred Unit, Liquidation Preference Per Share (usd per share) | $ 25.00 | ||||||||||||||
Series C Preferred Units | |||||||||||||||
Class of Stock [Line Items] | |||||||||||||||
Distribution Rate | 7.75% | ||||||||||||||
Preferred Unit, Liquidation Preference Per Share (usd per share) | $ 25.00 |
Unit-Based Compensation (Details) $ in Millions |
1 Months Ended | 3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|---|
Jan. 31, 2016
shares
|
Jun. 30, 2016
USD ($)
|
Jun. 30, 2015
USD ($)
|
Jun. 30, 2016
USD ($)
officer
shares
|
Jun. 30, 2015
USD ($)
|
|
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Accrued liability | $ | $ 0.7 | $ 0.7 | $ 0.7 | $ 0.7 | |
Restricted Stock Units (RSUs) | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Award vesting percentage | 33.33% | ||||
Restricted Stock Units (RSUs) | Employee [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Units granted (in units) | shares | 7,500 | ||||
Phantom Share Units (PSUs) | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Award vesting percentage | 33.33% | ||||
Phantom Share Units (PSUs) | Executive Officer | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Units granted (in units) | shares | 2,255,033 | ||||
Phantom Share Units (PSUs) | Director | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Units granted (in units) | shares | 125,838 | ||||
Vesting period | 1 year | ||||
Selling, General and Administrative Expenses | Restricted Stock Units (RSUs) | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Allocated Share-based Compensation Expense | $ | 1.4 | 3.4 | $ 2.6 | 7.0 | |
Selling, General and Administrative Expenses | Phantom Share Units (PSUs) | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Allocated Share-based Compensation Expense | $ | 1.2 | 0.4 | $ 2.4 | 0.8 | |
Amended Agreements | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Number of executives in amended agreements | officer | 3 | ||||
Amended Agreements | Executive Officer | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period | 3 years | ||||
Amended Agreements | Selling, General and Administrative Expenses | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Allocated Share-based Compensation Expense | $ | $ 0.7 | $ 0.3 | $ 1.2 | $ 0.7 | |
VNR LTIP | Phantom Share Units (PSUs) | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Units granted (in units) | shares | 1,331,579 | ||||
Vesting period | 3 years |
Unit-Based Compensation - Summary of Non-Vested Restricted Units (Details) - USD ($) $ / shares in Units, $ in Millions |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2016 |
Jun. 30, 2015 |
Jun. 30, 2016 |
Jun. 30, 2015 |
|
Phantom Share Units (PSUs) | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Unrecognized compensation cost | $ 9.4 | $ 9.4 | ||
Unrecognized compensation cost recognition period (in years) | 1 year 5 months | |||
Number of Non-vested Units | ||||
Non-vested units at beginning of period (in units) | 203,221 | |||
Granted (in units) | 3,712,450 | |||
Forfeited (in units) | (20,747) | |||
Vested (in units) | (121,273) | |||
Non-vested units at end of period (in units) | 3,773,651 | 3,773,651 | ||
Weighted Average Grant Date Fair Value | ||||
Non-vested units at beginning of period (in dollars per unit) | $ 20.99 | |||
Granted (in dollars per unit) | $ 2.56 | |||
Forfeited (in dollars per unit) | 2.04 | |||
Vested (in dollars per unit) | 22.24 | |||
Non-vested units at end of period (in dollars per unit) | $ 2.93 | $ 2.93 | ||
Restricted Stock Units (RSUs) | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Unrecognized compensation cost | $ 7.6 | $ 7.6 | ||
Unrecognized compensation cost recognition period (in years) | 1 year 5 months | |||
Number of Non-vested Units | ||||
Non-vested units at beginning of period (in units) | 976,348 | |||
Granted (in units) | 7,500 | |||
Forfeited (in units) | (26,868) | |||
Vested (in units) | (255,483) | |||
Non-vested units at end of period (in units) | 701,497 | 701,497 | ||
Weighted Average Grant Date Fair Value | ||||
Non-vested units at beginning of period (in dollars per unit) | $ 18.29 | |||
Granted (in dollars per unit) | 3.11 | |||
Forfeited (in dollars per unit) | 13.83 | |||
Vested (in dollars per unit) | 16.95 | |||
Non-vested units at end of period (in dollars per unit) | $ 18.83 | $ 18.83 | ||
Selling, General and Administrative Expenses | Phantom Share Units (PSUs) | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Non-cash compensation | $ 1.2 | $ 0.4 | $ 2.4 | $ 0.8 |
Selling, General and Administrative Expenses | Restricted Stock Units (RSUs) | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Non-cash compensation | $ 1.4 | $ 3.4 | $ 2.6 | $ 7.0 |
Unit-Based Compensation - Summary of Non-Vested Phantom Units (Details) - Phantom Share Units (PSUs) - USD ($) $ / shares in Units, $ in Millions |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2016 |
Jun. 30, 2015 |
Jun. 30, 2016 |
Jun. 30, 2015 |
|
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Unrecognized compensation cost | $ 9.4 | $ 9.4 | ||
Unrecognized compensation cost recognition period (in years) | 1 year 5 months | |||
Number of Non-vested Units | ||||
Non-vested units at beginning of period (in units) | 203,221 | |||
Granted (in units) | 3,712,450 | |||
Forfeited (in units) | (20,747) | |||
Non-vested units at end of period (in units) | 3,773,651 | 3,773,651 | ||
Weighted Average Grant Date Fair Value | ||||
Non-vested units at beginning of period (in dollars per unit) | $ 20.99 | |||
Granted (in dollars per unit) | $ 2.56 | |||
Forfeited (in dollars per unit) | 2.04 | |||
Non-vested units at end of period (in dollars per unit) | $ 2.93 | $ 2.93 | ||
Selling, General and Administrative Expenses | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Non-cash compensation | $ 1.2 | $ 0.4 | $ 2.4 | $ 0.8 |
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