DELAWARE | 001-33756 | 61-1521161 | ||
(State or other jurisdiction of incorporation) | (Commission File Number) | (IRS Employer Identification No.) |
EXHIBIT NUMBER | DESCRIPTION | |
Exhibit 99.1 | Press Release dated November 9, 2015 |
VANGUARD NATURAL RESOURCES, LLC | ||||||
By: | /s/ Richard A. Robert | |||||
Name: | Richard A. Robert | |||||
Title: | Executive Vice President and Chief Financial Officer | |||||
November 9, 2015 | (Principal Financial Officer and Principal Accounting Officer) |
EXHIBIT NUMBER | DESCRIPTION | |
Exhibit 99.1 | Press Release dated November 9, 2015 |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
($ in thousands, except per unit data) (Unaudited) | ||||||||||||||||
Production (Mcfe/d) | 386,679 | 321,847 | 383,067 | 301,816 | ||||||||||||
Oil, natural gas and natural gas liquids sales | $ | 90,827 | $ | 153,627 | $ | 285,562 | $ | 467,886 | ||||||||
Net gains (losses) on commodity derivative contracts | $ | 64,328 | $ | 83,311 | $ | 102,561 | $ | (11,125 | ) | |||||||
Operating expenses | $ | 43,251 | $ | 46,141 | $ | 132,509 | $ | 142,419 | ||||||||
Selling, general and administrative expenses | $ | 8,046 | $ | 7,140 | $ | 26,239 | $ | 23,042 | ||||||||
Depreciation, depletion, amortization, and accretion | $ | 52,428 | $ | 55,680 | $ | 182,443 | $ | 150,798 | ||||||||
Impairment of oil and natural gas properties | $ | 491,487 | $ | — | $ | 1,357,462 | $ | — | ||||||||
Net income (loss) attributable to Common and Class B unitholders | $ | (468,967 | ) | $ | 109,150 | $ | (1,394,822 | ) | $ | 112,975 | ||||||
Adjusted Net Income Attributable to Common and Class B Unitholders (1) | $ | 1,606 | $ | 27,916 | $ | 12,995 | $ | 74,483 | ||||||||
Adjusted Net Income Attributable to Common and Class B Unitholders, per unit (1) | $ | 0.02 | $ | 0.34 | $ | 0.15 | $ | 0.92 | ||||||||
Adjusted EBITDA(1) | $ | 88,204 | $ | 108,245 | $ | 264,122 | $ | 295,796 | ||||||||
Interest expense, including settlements paid on interest rate derivative contracts | $ | 22,118 | $ | 17,742 | $ | 64,661 | $ | 52,555 | ||||||||
Estimated maintenance capital expenditures | $ | 28,113 | $ | 32,566 | $ | 80,213 | $ | 92,716 | ||||||||
Distributions to Preferred unitholders | $ | 6,690 | $ | 4,949 | $ | 20,070 | $ | 11,507 | ||||||||
Distributable Cash Flow Available to Common and Class B Unitholders (1) | $ | 31,283 | $ | 52,988 | $ | 99,178 | $ | 140,968 | ||||||||
Distributable Cash Flow per common and Class B unit (1) | $ | 0.36 | $ | 0.63 | $ | 1.15 | $ | 1.73 | ||||||||
Common and Class B unit distribution coverage (1) | 1.02x | 1.00x | 1.09x | 0.91x | ||||||||||||
Weighted average common and Class B units outstanding at record date attributable to distribution period | 87,018 | 83,768 | 86,009 | 81,663 |
(1) | Non-GAAP financial measures. Please see Adjusted EBITDA and Distributable Cash Flow Available to Common and Class B Unitholders tables at the end of this press release for a reconciliation of these measures to their nearest comparable GAAP measure. Supplemental information on Vanguard's financial and operations results, including Adjusted Net Income Available to Common and Class B Unitholders, can be found under "Presentations" on the Investor Relations section of Vanguard’s corporate website, http://www.vnrllc.com. |
• | Adjusted EBITDA (a non-GAAP financial measure defined below) decreased 19% to $88.2 million in the third quarter of 2015 from $108.2 million in the third quarter of 2014 and decreased 3% from the $90.6 million recorded in the second quarter of 2015. |
• | Distributable Cash Flow Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) decreased 41% to $31.3 million from the $53.0 million generated in the third quarter of 2014 and decreased 12% from the $35.5 million generated in the second quarter of 2015. |
• | Adjusted Net Income Available to Common and Class B Unitholders (a non-GAAP financial measure defined in the supplemental presentation posted at www.vnrllc.com) was $1.6 million in the third quarter of 2015, or $0.02 per basic unit, as compared to Adjusted Net Income of $27.9 million, or $0.34 per basic unit, in the third quarter of 2014 and Adjusted Net Loss of $6.6 million, or $0.07 per basic unit, in the second quarter of 2015. The third quarter of 2015 includes net non-cash losses of $470.6 million that are adjustments to arrive at Adjusted Net Income Attributable to Common and Class B Unitholders. The third quarter 2015 adjustments include a $491.5 million impairment charge on our oil and natural gas properties. The third quarter of 2014 results included net non-cash gains of $81.6 million primarily attributable to the change in fair value of commodity derivative contracts. |
Three Months Ended September 30, | Percentage Increase / (Decrease) | Three Months Ended June 30, | Percentage Increase / (Decrease) | |||||||||||||||
2015 (a) | 2014 (a) | 2015 | ||||||||||||||||
Total production volumes: | ||||||||||||||||||
Oil (MBbls) | 839 | 813 | 3 | % | 866 | (3 | )% | |||||||||||
Natural Gas (MMcf) | 26,242 | 20,962 | 25 | % | 23,543 | 11 | % | |||||||||||
NGLs (MBbls) | 717 | 629 | 14 | % | 796 | (10 | )% | |||||||||||
Combined (MMcfe) | 35,574 | 29,610 | 20 | % | 33,514 | 6 | % | |||||||||||
Average daily production volumes: | ||||||||||||||||||
Oil (Bbls/day) | 9,115 | 8,832 | 3 | % | 9,511 | (3 | )% | |||||||||||
Natural Gas (Mcf/day) | 285,236 | 227,850 | 25 | % | 258,720 | 11 | % | |||||||||||
NGLs (Bbls/day) | 7,792 | 6,835 | 14 | % | 8,751 | (10 | )% | |||||||||||
Combined (Mcfe/day) | 386,679 | 321,847 | 20 | % | 368,290 | 6 | % | |||||||||||
Average NYMEX prices: | ||||||||||||||||||
Oil (Price/Bbl) | $ | 46.39 | $ | 97.13 | (52 | )% | $ | 57.94 | (20 | )% | ||||||||
Natural Gas (Price/Mcf) | $ | 2.77 | $ | 4.07 | (32 | )% | $ | 2.63 | 5 | % | ||||||||
Average realized prices, excluding hedges: | ||||||||||||||||||
Oil (Price/Bbl) | $ | 40.10 | $ | 84.96 | (53 | )% | $ | 50.85 | (21 | )% | ||||||||
Natural Gas (Price/Mcf) | $ | 1.94 | $ | 3.24 | (40 | )% | $ | 1.69 | 15 | % | ||||||||
NGLs (Price/Bbl) | $ | 8.86 | $ | 26.66 | (67 | )% | $ | 14.98 | (41 | )% | ||||||||
Average realized prices, including hedges (b): | ||||||||||||||||||
Oil (Price/Bbl) | $ | 53.66 | $ | 84.36 | (36 | )% | $ | 58.02 | (8 | )% | ||||||||
Natural Gas (Price/Mcf) | $ | 3.17 | $ | 3.55 | (11 | )% | $ | 3.16 | — | % | ||||||||
NGLs (Price/Bbl) | $ | 11.23 | $ | 26.70 | (58 | )% | $ | 16.93 | (34 | )% |
(a) | During 2015 and 2014, 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. |
(b) | 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. |
• | Adjusted EBITDA (a non-GAAP financial measure defined below) decreased 11% to $264.1 million in the first nine months of 2015 from $295.8 million in the first nine months of 2014. |
• | Distributable Cash Flow Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) for the first nine months of 2015 decreased 30% to $99.2 million from the $141.0 million generated in the first nine months of 2014. |
• | Adjusted Net Income Attributable to Common and Class B Unitholders (a non-GAAP financial measure defined in the supplemental presentation posted at www.vnrllc.com) was $13.0 million for the first nine months of 2015, or $0.15 per basic unit, as compared to $74.5 million, or $0.92 per basic unit, in the comparable period of 2014. The first nine months of 2015 includes net non-cash losses of $1.4 billion that are adjustments to arrive at Adjusted Net Income Attributable to Common and Class B Unitholders. The net non-cash losses primarily resulted from a $1.4 billion impairment charge on our oil and natural gas properties. Results for the first nine months of 2014 included net non-cash gains of $38.8 million primarily attributable to net gains on acquisitions of oil and natural gas properties recognized during the period. |
Nine Months Ended September 30, | Percentage Increase / (Decrease) | ||||||||||
2015 (a) | 2014 (a) | ||||||||||
Total production volumes: | |||||||||||
Oil (MBbls) | 2,554 | 2,394 | 7 | % | |||||||
Natural Gas (MMcf) | 76,645 | 56,651 | 35 | % | |||||||
NGLs (MBbls) | 2,102 | 1,897 | 11 | % | |||||||
Combined (MMcfe) | 104,577 | 82,396 | 27 | % | |||||||
Average daily production volumes: | |||||||||||
Oil (Bbls/day) | 9,355 | 8,769 | 7 | % | |||||||
Natural Gas (Mcf/day) | 280,751 | 207,512 | 35 | % | |||||||
NGLs (Bbls/day) | 7,698 | 6,949 | 11 | % | |||||||
Combined (Mcfe/day) | 383,067 | 301,816 | 27 | % | |||||||
Average NYMEX prices: | |||||||||||
Oil (Price/Bbl) | $ | 51.04 | $ | 99.62 | (49 | )% | |||||
Natural Gas (Price/Mcf) | $ | 2.80 | $ | 4.57 | (39 | )% | |||||
Average realized prices, excluding hedges: | |||||||||||
Oil (Price/Bbl) | $ | 44.41 | $ | 88.23 | (50 | )% | |||||
Natural Gas (Price/Mcf) | $ | 1.91 | $ | 3.55 | (46 | )% | |||||
NGLs (Price/Bbl) | $ | 12.20 | $ | 29.26 | (58 | )% | |||||
Average realized prices, including hedges (b): | |||||||||||
Oil (Price/Bbl) | $ | 55.49 | $ | 84.36 | (34 | )% | |||||
Natural Gas (Price/Mcf) | $ | 3.13 | $ | 3.49 | (10 | )% | |||||
NGLs (Price/Bbl) | $ | 14.38 | $ | 28.98 | (50 | )% |
(a) | During 2015 and 2014, 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. |
(b) | 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. |
October 1 - December 31, 2015 | Year 2016 | Year 2017 | ||||||||||
Gas Production Hedged: | ||||||||||||
% Anticipated Production Hedged | 88 | % | 68 | % | 41 | % | ||||||
Weighted Average Price ($/MMBtu) | $ | 4.26 | $ | 4.37 | $ | 4.18 | ||||||
Oil Production Hedged: | ||||||||||||
% Anticipated Production Hedged | 79 | % | 50 | % | — | % | ||||||
Weighted Average Price ($/Bbl) | $ | 72.27 | $ | 81.14 | $ | — | ||||||
NGLs Production Hedged: | ||||||||||||
% Anticipated Production Hedged | 9 | % | 21 | % | — | % | ||||||
Weighted Average Price ($/Bbl) | $ | 46.34 | $ | 29.96 | $ | — |
October 1 - December 31, 2015 | Year 2016 | Year 2017 | ||||||||||
Gas Production Hedged: | ||||||||||||
% Anticipated Production Hedged | 85 | % | 69 | % | 39 | % | ||||||
Weighted Average Price ($/MMBtu) | $ | 4.31 | $ | 4.35 | $ | 4.19 | ||||||
Oil Production Hedged: | ||||||||||||
% Anticipated Production Hedged | 78 | % | 59 | % | 17 | % | ||||||
Weighted Average Price ($/Bbl) | $ | 79.64 | $ | 83.27 | $ | 86.71 | ||||||
NGLs Production Hedged: | ||||||||||||
% Anticipated Production Hedged | 24 | % | 21 | % | — | % | ||||||
Weighted Average Price ($/Bbl) | $ | 34.13 | $ | 30.31 | $ | — |
• | 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; |
• | Net gains (losses) on acquisitions of oil and natural 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; and |
• | Material transaction costs incurred on acquisitions. |
• | 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; |
• | 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; and |
• | Material transaction costs incurred on acquisitions; |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Net income (loss) | $ | (462,277 | ) | $ | 114,099 | $ | (1,374,752 | ) | $ | 124,482 | ||||||
Plus: | ||||||||||||||||
Interest expense | 21,130 | 16,721 | 61,693 | 49,529 | ||||||||||||
Depreciation, depletion, amortization, and accretion | 52,428 | 55,680 | 182,443 | 150,798 | ||||||||||||
Impairment of oil and natural gas properties | 491,487 | — | 1,357,462 | — | ||||||||||||
Net (gains) losses on commodity derivative contracts | (64,328 | ) | (83,311 | ) | (102,561 | ) | 11,125 | |||||||||
Net cash settlements received (paid) on matured commodity derivative contracts (a)(b)(c) | 45,368 | 6,033 | 125,988 | (13,347 | ) | |||||||||||
Net (gains) losses on interest rate derivative contracts (d) | 807 | (511 | ) | 2,291 | 1,068 | |||||||||||
Net (gains) losses on acquisitions of oil and natural gas properties | 284 | (2,409 | ) | 284 | (34,523 | ) | ||||||||||
Texas margin taxes | (522 | ) | 156 | (380 | ) | (125 | ) | |||||||||
Compensation related items | 3,827 | 1,438 | 11,654 | 6,440 | ||||||||||||
Material transaction costs incurred on acquisitions | — | 349 | — | 349 | ||||||||||||
Adjusted EBITDA | $ | 88,204 | $ | 108,245 | $ | 264,122 | $ | 295,796 | ||||||||
Less: | ||||||||||||||||
Interest expense, including settlements paid on interest rate derivatives | (22,118 | ) | (17,742 | ) | (64,661 | ) | (52,555 | ) | ||||||||
Estimated maintenance capital expenditures (f) | (28,113 | ) | (32,566 | ) | (80,213 | ) | (92,716 | ) | ||||||||
Distributions to Preferred unitholders | (6,690 | ) | (4,949 | ) | (20,070 | ) | (11,507 | ) | ||||||||
Proceeds from sale of leasehold interests | — | — | — | 1,950 | ||||||||||||
Distributable Cash Flow Available to Common and Class B Unitholders | $ | 31,283 | $ | 52,988 | $ | 99,178 | $ | 140,968 | ||||||||
Distributions to Common and Class B unitholders | 30,674 | 52,774 | 90,955 | 154,139 | ||||||||||||
Excess (shortfall) of distributable cash flow after distributions to unitholders | $ | 609 | $ | 214 | $ | 8,223 | $ | (13,171 | ) | |||||||
Distributable Cash Flow per Common and Class B unit | $ | 0.36 | $ | 0.63 | $ | 1.15 | $ | 1.73 | ||||||||
Common and Class B unit Distribution Coverage | 1.02x | 1.00x | 1.09x | 0.91x | ||||||||||||
(a) Our Adjusted EBITDA should not be considered as an alternative to net income (loss), operating income (loss), cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income (loss) and operating income (loss) and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies. | ||||||||||||||||
(b) 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. | $ | 2,057 | $ | — | $ | 4,624 | $ | — |
(c) 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. | $ | 12,453 | $ | 5,608 | $ | 32,734 | $ | 16,472 | ||||||||
(d) Excludes fair value of restructured derivative contracts. | $ | — | $ | — | $ | (31,945 | ) | $ | — | |||||||
(e) Includes settlements paid on interest rate derivatives. | $ | 988 | $ | 1,021 | $ | 2,968 | $ | 3,026 | ||||||||
(f) Estimated maintenance capital expenditures are intended to represent the amount of capital required to offset the decrease in production from the prior year due to the decline in proved developed producing production. These costs, which are incorporated in our annual capital budget as approved by the board of directors, include development drilling, recompletions, workovers and various other procedures to generate new or improve existing production from both operated and non-operated properties. Actual production decline rates and capital efficiency may materially differ from our projections and such estimated maintenance capital expenditures may not maintain our production. Further, because estimated maintenance capital expenditures are not intended to target specific levels of reserves, if we do not acquire new proved or unproved reserves, our total reserves will decrease over time and we would be unable to sustain production at current levels, which could adversely affect our ability to pay a distribution at the current level or at all. |
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