Vanguard Natural Resources, Inc. Reports Fourth Quarter 2017 Results

HOUSTON – March 21, 2018 (PR NEWSWIRE) – Vanguard Natural Resources, Inc. (OTCQX: VNRR) (“Vanguard,” “VNRR,” or “the Company”) today reported financial and operational results for the quarter ended December 31, 2017.

Key Highlights

  • Initiated strategic shift from an upstream MLP toward a focused, traditional E&P company
  • Preliminary 2018 capital budget of $160 MM focused primarily on the Company’s growth assets in the Pinedale field, Piceance Basin and Arkoma Basin
  • Continued improvement in lease operating expenses as the Company remains focused on cost efficiencies
  • Participated in three successful horizontal wells in the Pinedale field and expecting horizontal activity to increase as Ultra Petroleum focuses more on horizontal development
  • Completed the sale of non-core assets in the Williston Basin in December 2017 for gross proceeds of $38.5 million to reduce debt and improve liquidity
  • Progressing additional asset divestiture opportunities across the portfolio to reduce debt and to refocus the asset base as a traditional E&P company
  • Significantly hedged for 2018 through 2020, with 2018 production hedged 72%, 85% and 42% for natural gas, oil and NGLs, respectively, at the mid-point of previously announced guidance

Mr. R. Scott Sloan, President and CEO, commented, “The close of 2017 signifies a remarkable turn for Vanguard’s corporate journey. I am proud of the hard work and determination that our employees exhibited during the downturn, positioning us for a positive trajectory into 2018. As we have highlighted in our emergence deck and previous releases, we are making a strategic shift in 2018 from an upstream MLP to an E&P company, focusing on organic growth and financial discipline.

During 2018 we will focus on three strategic initiatives: simplifying and refocusing the asset base, increasing liquidity and reducing financial leverage, and assessing organic development opportunities within our portfolio. In our current portfolio of assets, we have identified three core growth areas including the Pinedale field, Piceance Basin and Arkoma Basin. With more than 80% of our 2018 capital budget focused on these key assets, we are showing our commitment to organic growth as we look to efficiently develop these assets to maximize value for the Company.”

Fourth Quarter 2017 Financial Results(a)

Reported average production of 362 MMcfe per day in the fourth quarter of 2017 representing a 7% decrease compared to 389 MMcfe per day produced in the fourth quarter of 2016 and a 3% decrease compared to 372 MMcfe per day for the third quarter of 2017. On a Mcfe basis, crude oil, natural gas, and NGLs accounted for 16%, 69% and 15%, respectively, of our fourth quarter 2017 production. Production for the fourth quarter 2017 was impacted by curtailments in the Permian Basin and a temporary refinery shut down in the Big Horn Basin resulting in lower production during the quarter. Pro forma for the Williston sale, fourth-quarter 2017 production would have been approximately 356 MMcfe per day.

Lease operating expenses of $34.5 million during the fourth quarter of 2017 ($1.04 per Mcfe) were below the guidance range previously provided. Total lease operating expenses were down 12% from $39.4 million for the fourth quarter of 2016 ($1.10 per Mcfe) and down 10% compared to the $38.2 million in the third quarter of 2017 ($1.12 per Mcfe). The decrease in lease operating expenses during the fourth quarter of 2017 is primarily attributable to lower facility costs and lower production. Pro forma for the Williston sale, fourth-quarter 2017 lease operating expenses would have been approximately $32.0 million or $0.98 per Mcfe.

Selling, general and administrative expenses (“SG&A”) were $15.4 million during the fourth quarter of 2017. Excluding non-cash compensation and non-recurring adjustments of approximately $4.8 million, cash SG&A was $10.4 million for the fourth quarter of 2017, near the low end of guidance.

We reported a net loss attributable to Common Stockholders for the fourth quarter of 2017 of $74.1 million. This compares to a net loss attributable to Common and Class B Unitholders of $170.3 million in the fourth quarter of 2016 and net income attributable to Common Stockholders/Unitholders of $925.8 million in the third quarter of 2017.

Adjusted Net Loss Attributable to Common Stockholders (a non-GAAP financial measure defined below) was a loss of $9.7 million in the fourth quarter of 2017. This compares to Adjusted Net Income of $66.2 million in the fourth quarter of 2016 and Adjusted Net Loss of $19.7 million in the third quarter of 2017. The Adjusted Net Loss for the fourth quarter of 2017 included adjustments for net non-cash expenses of $52.7 million primarily comprised of a $47.6 million impairment charge on our oil and natural gas properties, a $4.5 million gain on divestiture of oil and natural gas properties and a $9.5 million loss from the change in fair value of commodity derivative contracts. The fourth quarter 2016 results included net non-cash losses of $233.3 million primarily attributable to a $128.6 million impairment charge on our oil and natural gas properties, a $107.9 million loss from the change in fair value of commodity derivative contracts, $5.3 million for the fair value of derivative contracts acquired that apply to contracts settled during the period, a $1.2 million net loss on the acquisition of oil and gas properties and a $9.8 million gain from the change in fair value of interest rate derivative contracts. The Adjusted Net Loss for the third quarter of 2017 results included adjustments for non-recurring, reorganization items totaling $988.5 million and a change in fair value of commodity derivative contracts of $42.0 million.

Adjusted EBITDA (a non-GAAP financial measure defined below) was $48.8 million in the fourth quarter of 2017 and represents a 63% decline from the same period in 2016 and a 59% increase as compared to the third quarter of 2017. The decrease from the fourth quarter of 2016 is primarily due to a significantly lower realized gain on derivatives as the same period in 2016 included approximately $54.0 million realized gain received from the monetization of commodity hedge contracts. The increase as compared to the third quarter of 2017 is attributable primarily to a 19% and 36% increase in average realized price for sales of oil and natural gas, respectively, combined with a 10% decrease in LOE period over period.

Capital expenditures increased 154% to $39.2 million in the fourth quarter of 2017 from $15.4 million in the fourth quarter of 2016, and also increased 17% from the $33.4 million expended in the third quarter of 2017. Drilling and development in the Pinedale field, located in the Green River Basin, and the Mamm Creek field in the Piceance Basin, accounted for approximately 66% of the Company’s total capital costs for the period. In Pinedale, we participated as a non-operated partner in the drilling and completion of vertical and horizontal natural gas wells, and in Mamm Creek, we accelerated our infill development drilling program that we are continuing to focus on in 2018.

“Due to production curtailments and an unexpected refinery shut down in the fourth quarter, our production came in slightly below our stated guidance for the fourth quarter of 2017. However, our lease operating expenses came in lower than forecasted and SG&A expenses, when adjusting for non-recurring and non-cash items, were at the bottom end of our guidance. While we reported higher capital spending, this was due to an acceleration of the 2018 Piceance drilling program and our participation in three horizontal Pinedale wells, which should lead us into 2018 with positive momentum,” stated Ryan Midgett, Chief Financial Officer.

  • Financial results for the third quarter of 2017 reflect the combined results of the two months ended September 30, 2017 and the one month ended July 31, 2017.

Selected Financial Information

A summary of selected financial information follows:

Three Months Ended
December 31,
2017 2016
($ in thousands)

(Unaudited)

Production (Mcfe/d) 362,011 388,984
Oil, natural gas and natural gas liquids sales $ 125,818 $ 108,578
Net losses on commodity derivative contracts $ (23,505) $ (28,320)
Operating expenses (1) $ 41,937 $ 48,114
Selling, general and administrative expenses $ 15,367 $ 15,634
Net Loss Attributable to Vanguard Common Stockholders/Unitholders $ (74,113) $ (170,310)
Adjusted Net Income (Loss) Attributable to Vanguard Common Stockholders/Unitholders (2) $ (9,681) $ 66,187
Adjusted EBITDA attributable to Vanguard Common Stockholders/Unitholders (2) $ 48,765 $ 133,109
Total Debt (as of December 31, 2017 and 2016, respectively) $ 911,976 $ 1,773,512
Interest expense, including settlements paid on interest rate derivative contracts $ 14,589 $ 29,383
Capital expenditures $ 39,201 $ 15,420
Net cash provided by operating activities $ 24,054 $ 110,703

(1) Includes lease operating expenses and production and other taxes.

(2) Non-GAAP financial measures. Please see Adjusted Net Income Attributable to Common Stockholders/Unitholders and Adjusted EBITDA attributable to Vanguard Stockholders/Unitholders tables at the end of this press release for a reconciliation of these measures to their nearest comparable GAAP measure.

 

Average Prices and Production Volumes

 

Three Months Ended
December 31,(a)
Percentage

Increase / (Decrease)

Three Months Ended

September 30,

Percentage

Increase / (Decrease)

2017 2016 2017 (a)(b)
Average realized prices, excluding hedges:
Oil (Price/Bbl) $ 50.65 $ 42.36 20 % $ 42.62 19 %
Natural Gas (Price/Mcf) $ 2.48 $ 2.14 16 % $ 1.82 36 %
NGLs (Price/Bbl) $ 28.92 $ 15.60 85 % $ 22.77 27 %
Average realized prices, including hedges (c):
Oil (Price/Bbl) $ 41.33 $ 51.40 (20) % $ 40.41 2 %
Natural Gas (Price/Mcf) $ 2.61 $ 2.93 (11) % $ 1.89 38 %
NGLs (Price/Bbl) $ 23.08 $ 16.05 44 % $ 20.22 14 %
Average NYMEX prices:
Oil (Price/Bbl) $ 55.31 $ 49.38 12 % $ 48.22 15 %
Natural Gas (Price/Mcf) $ 2.93 $ 2.98 (2) % $ 3.00 (2) %
Total production volumes:
Oil (MBbls) 893 1,000 (11) % 918 (3) %
Natural Gas (MMcf) 23,097 24,515 (6) % 23,890 (3) %
NGLs (MBbls) 808 879 (8) % 802 1 %
Combined (MMcfe) 33,305 35,787 (7) % 34,208 (3) %
Average daily production volumes:
Oil (Bbls/day) 9,711 10,869 (11) % 9,977 (3) %
Natural Gas (Mcf/day) 251,059 266,465 (6) % 259,672 (3) %
NGLs (Bbls/day) 8,781 9,551 (8) % 8,715 1 %
Combined (Mcfe/day) 362,011 388,984 (7) % 371,824 (3) %

(a) During 2017 and 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) All amounts reflect the combined results of the two months ended September 30, 2017 and the one month ended July 31, 2017.
(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.

 

Asset Divestiture Update

As the Company shifts its strategic focus from an upstream master limited partnership to that of a traditional exploration and production corporation, the Company has identified assets that are not core to its strategy moving forward. Currently, the Company has several divestment packages on the market and has identified additional assets to be actively marketed in the first half of 2018 as it continues to optimize its portfolio.

In December of 2017, the Company completed the sale of its oil and natural gas properties in the Williston Basin for gross proceeds of $38.5 million. Fourth-quarter 2017 production associated with these assets was 1,000 Boe per day and 88% oil. Proceeds from the transaction were used to reduce debt under the Company’s revolving credit facility.

The Company is either actively marketing or currently receiving bids to divest certain properties across the portfolio, including parts of the Permian Basin, Green River Basin, Wind River Basin and Gulf Coast. The Permian Basin properties consist of assets located in Ward County, Texas, and include producing properties and deep-rights leaseholds. Current production from these Ward County properties is approximately 300 Boe per day (87% liquids). The Green River Basin properties currently produce approximately 13,000 Mcfe per day of production (83% gas) and include leasehold rights. For clarity, Vanguard’s interest in the Pinedale field is not included. The Wind River properties include producing properties and leasehold rights in Fremont and Natrona Counties, Wyoming. Current production associated with these properties is 7,000 Mcfe per day (84% gas). In addition to the properties described, the Company is continuing to identify potential options for selling other non-core properties in the first half of 2018.

“Divesting these mature, non-core properties will allow the Company to reduce debt and increase our operational flexibility. As we move forward, we will continue to look for ways to strengthen the Company through portfolio optimization. This will also allow us to sharpen our focus, and concentrate on delivering value from assets with attractive growth potential”, commented Mr. Sloan.

 

Core Growth Areas

In the Pinedale field, the Company owns approximately 14,000 net acres. The Company’s 2018 drilling program includes non-operated vertical and horizontal wells. As a result of the highly encouraging performance of the Lance A horizontal wells recently drilled by Ultra Petroleum, there will be a reduced emphasis on vertical wells and increased focus on horizontal drilling opportunities.

Additionally, the Company holds approximately 15,000 net acres in the Piceance Basin and is allocating 2018 budget capital to drilling and completing 14 wells which will assist in delineating the large drilling location inventory. This contiguous operated acreage position with numerous well locations is expected to give the Company the opportunity to efficiently develop the asset over multiple years.

In the Arkoma Basin, the Company owns approximately 68,000 net acres and plans to participate in wells drilled by Newfield and BP in the Woodford shale. Through these non-operated well activities, the Company plans to further assess its position across the Arkoma Basin and position itself to pursue a potential operated drilling program in the Woodford Shale in 2019.

 

Capital Expenditures

The board of directors approved an initial capital expenditures budget for 2018 of $160.0 million compared to the $109.9 million we spent in 2017. Our initial 2018 capital expenditures budget includes approximately $135.0 million of drilling and completion capital, or 85% of the total capital budget. More than 97% of the drilling and completion capital is focused on the core growth assets of the Green River, Piceance and Arkoma Basins. We expect to spend between $90.0 million to $95.0 million or approximately 69% of the drilling capital budget in the Green River Basin at the Pinedale field where we will participate as a non-operated partner in the drilling and completion of vertical and horizontal wells. Additionally, we expect to spend between $20.0 million to $26.0 million or approximately 15% of the drilling capital budget in the Piceance Basin, at the Mamm Creek field where we will operate a one rig program drilling and completing vertical gas wells. We also expect to spend approximately 13% of our budgeted drilling capital in the Arkoma Basin in Oklahoma where we will be participating as a non-operated partner with Newfield and BP in a one rig program drilling and completing horizontal Woodford wells. The remaining drilling and completion capital will be spent on additional drilling, completion and production uplift projects in the Permian, Big Horn, and Powder River Basins.

The Company intends to release a revised 2018 capital expenditures budget and other guidance with the release of its first quarter results that will include, among other items, the impact of reduced rig counts with increased horizontal development spending in the Pinedale field.

 

Liquidity Update

As of March 20, 2018, we have $715.0 million of outstanding borrowings and $110.0 million of borrowing capacity under the reserve-based credit facility. We also have approximately $6.0 million in available cash.

Ryan Midgett, Chief Financial Officer, commented, “Our portfolio has a strong mix of stable producing assets that can also provide growth through its steady cash flow generation. This cash flow, along with proceeds from divestments and our improved capital structure over the course of 2018, should afford us the liquidity and flexibility needed to meet our financial obligations and fund our ongoing growth strategy.”

 

Year-End 2017 Reserves

For the year-ended December 31, 2017, the Company’s proved reserves totaled 1,821.5 billion cubic feet of gas equivalent (Bcfe) compared to 1,363.2 Bcfe at year-end 2016, an increase of 34%. The 458.3 Bcfe increase in proved reserves was primarily due to additions of proved undeveloped (“PUD”) reserves which were classified as contingent resources at the year-end of 2016. Prior to the filing of and emergence from bankruptcy, there was uncertainty regarding the availability of capital that would have been required to develop these reserves, and therefore the Company reported no PUD reserves for the year-end 2016. The 2017 PUD additions were partially offset by properties divested in the Permian and Williston Basins during 2017. The year-end 2017 pre-tax estimated future net cash flows discounted at ten percent (PV-10) totaled $1.2 billion. Natural gas represents 75% of the Company’s proved reserves, with 67% classified as proved developed.

 

Hedging Activities

The Company has implemented a hedging program for its crude oil and natural gas production through 2021, and NGLs production through 2019. Currently, we use fixed-price swaps and collars to hedge oil, natural gas and NGLs prices. The Company believes its hedging program will provide substantial near-term cash flow visibility regardless of the volatility in commodity prices as management and the board of directors explore options for maximizing stockholder value.

 

 

Commodity derivative contracts in place as of March 20, 2018 are as follows:

Year
2018
Year
2019
Year
2020
Year
2021
Gas Positions:
Fixed-Price Swaps:
Notional Volume (MMBtu) 70,242,000 52,539,000 47,227,500
Fixed Price ($/MMBtu) $ 3.00 $ 2.79 $ 2.75 $
Collars:
Notional Volume (MMBtu) 4,125,000 5,490,000 1,825,000
Floor Price ($/MMBtu) $ $ 2.60 $ 2.60 $ 2.60
Ceiling Price ($/MMBtu) $ $ 3.00 $ 3.00 $ 3.07
Oil Positions:
Fixed-Price Swaps (West Texas Intermediate):
Notional Volume (Bbls) 2,712,450 1,858,200 1,393,800
Fixed Price ($/Bbl) $ 46.59 $ 48.50 $ 49.53 $
Collars:
Notional Volume (Bbls) 575,730 659,340 112,036
Floor Price ($/Bbl) $ $ 43.81 $ 44.17 $ 47.50
Ceiling Price ($/Bbl) $ $ 54.04 $ 55.00 $ 56.05
NGL Positions:
Fixed-Price Swaps:
Mont Belvieu Ethane
Notional Volume (Gallons) 9,198,000 2,494,779
Fixed Price ($/Gallon) $ 0.28 $ 0.29 $ $
Mont Belvieu Propane
Notional Volume (Gallons) 22,995,000 6,270,427
Fixed Price ($/Bbl) $ 0.53 $ 0.71 $ $
Mont Belvieu N. Butane
Notional Volume (Gallons) 7,665,000 2,272,940
Fixed Price ($/Gallon) $ 0.65 $ 0.82 $ $
Mont Belvieu Isobutane
Notional Volume (Gallons) 6,132,000 1,847,179
Fixed Price ($/Gallon) $ 0.65 $ 0.83 $ $
Mont Belvieu N. Gasoline
Notional Volume (Gallons) 10,731,000 3,328,417
Fixed Price ($/Gallon) $ 0.99 $ 1.23 $ $

 

For a summary of all commodity and interest rate derivative contracts in place at December 31, 2017, please refer to our Annual Report on Form 10-K which is expected to be filed on or about March 21, 2018.

 

About Vanguard Natural Resources, Inc.

Vanguard Natural Resources, Inc. is an independent exploration and production company focused on the production and development of oil and natural gas properties in the United States. Vanguard’s assets consist primarily of producing and non-producing oil and natural gas reserves located in the Green River Basin in Wyoming, the Piceance Basin in Colorado, the Permian Basin in West Texas and New Mexico, the Arkoma Basin in Arkansas and Oklahoma, the Gulf Coast Basin in Texas, Louisiana, Mississippi and Alabama, the Big Horn Basin in Wyoming and Montana, the Anadarko Basin in Oklahoma and North Texas, the Wind River Basin in Wyoming and the Powder River Basin in Wyoming. More information on Vanguard can be found at www.vnrenergy.com.

 

Forward-Looking Statements

Statements made by representatives of the Company within this press release that are not historical facts are forward looking statements. Terminology such as “will,” “would,” “should,” “could,” “expect,” “anticipate,” “plan,” “project,” “intend,” “estimate,” “believe,” “target,” “continue,” “on track,” “potential,” the negative of such terms or other comparable terminology are intended to identify forward looking statements. These statements are based on certain assumptions and expectations made by the Company which reflect management’s experience, estimates and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or anticipated in the forward looking statements. These include risks relating to financial performance and results, the ability to improve Vanguard’s results and profitability following its emergence from bankruptcy; our indebtedness under our revolving credit facility, term loan and second lien notes; availability of sufficient cash flow to make payments on our debt obligations and to execute our business plan; our prices and demand for oil, natural gas and natural gas liquids; and our ability to replace reserves and efficiently develop our reserves. These and other important factors could cause actual results to differ materially from those anticipated or implied in the forward looking statements. Please read “Risk Factors” in our most recent annual report on Form 10-K and Item 1A. of Part II “Risk Factors” in our subsequent quarterly reports on Form 10-Q and any other public filings and press releases. Vanguard undertakes no obligation to publicly update any forward looking statements, whether as a result of new information or future events.

 

Adjusted EBITDA

We present Adjusted EBITDA in addition to our reported net income (loss) attributable to Vanguard stockholders/unitholders in accordance with GAAP. Adjusted EBITDA is a non-GAAP financial measure that begins with net income (loss) attributable to Vanguard stockholders/unitholders plus:

  • Net income (loss) attributable to non-controlling interest.

The result is net income (loss) which includes the non-controlling interest. From this we add or subtract the following:

  • Net interest expense;
  • Depreciation, depletion, amortization, and accretion;
  • Impairment of oil and natural gas properties;
  • Change in fair value of commodity derivative contracts;
  • Premiums paid, whether at inception or deferred, for derivative contracts that settled during the period;
  • Fair value of derivative contracts acquired that apply to contracts settled during the period;
  • Cash settlements on termination of derivative contracts;
  • Net gains or losses on interest rate derivative contracts;
  • Net gains or losses on acquisitions and divestitures of oil and natural gas properties;
  • Taxes;
  • Compensation related items, which include share/unit-based compensation expense, unrealized fair value of phantom units granted to officers and cash settlement of phantom units granted to officers;
  • Reorganization and restructuring costs;
  • Material costs incurred on strategic transactions; and
  • Non-controlling interest amounts attributable to each of the items above which revert the calculation back to an amount attributable to the Vanguard stockholders/unitholders.

 

Adjusted EBITDA is a significant performance metric used by management and by external users of our financial statements such as investors, research analysts and others to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and our operating performance and return on capital as compared to those of other companies in our industry.

Adjusted EBITDA is not intended to represent cash flows for the period, nor is it presented as a substitute for net income (loss), operating income, 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 and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies. For example, we fund premiums paid for derivative contracts, acquisitions of oil and natural gas properties, including the assumption of derivative contracts related to these acquisitions, and other capital expenditures primarily with proceeds from debt or equity offerings or with borrowings under our reserve-based credit facility. For the purposes of calculating Adjusted EBITDA, we consider the cost of premiums paid for derivatives and the fair value of derivative contracts acquired as part of a business combination as investments related to our underlying oil and natural gas properties; therefore, they are not deducted in arriving at our Adjusted EBITDA. Our Consolidated Statements of Cash Flows, prepared in accordance with GAAP, present cash settlements on matured derivatives and the initial cash outflows of premiums paid to enter into derivative contracts as operating activities. When we assume derivative contracts as part of a business combination, we allocate a part of the purchase price and assign them a fair value at the closing date of the acquisition. The fair value of the derivative contracts acquired is recorded as a derivative asset or liability and presented as cash used in investing activities in our Consolidated Statements of Cash Flows. As the volumes associated with these derivative contracts, whether we entered into them or we assumed them, are settled, the fair value is recognized in operating cash flows. Whether these cash settlements on derivatives are received or paid, they are reported as operating cash flows.

As noted above, for purposes of calculating Adjusted EBITDA, we consider both premiums paid for derivatives and the fair value of derivative contracts acquired as part of a business combination as investing activities. This is similar to the way the initial acquisition or development costs of our oil and natural gas properties are presented in our Consolidated Statements of Cash Flows; the initial cash outflows are presented as cash used in investing activities, while the cash flows generated from these assets are included in operating cash flows. The consideration of premiums paid for derivatives and the fair value of derivative contracts acquired as part of a business combination as investing activities for purposes of determining our Adjusted EBITDA differs from the presentation in our consolidated financial statements prepared in accordance with GAAP which (i) presents premiums paid for derivatives entered into as operating activities and (ii) the fair value of derivative contracts acquired as part of a business combination as investing activities.

 

VANGUARD NATURAL RESOURCES, INC.
Reconciliation of Net Loss to Adjusted EBITDA (a)
(Unaudited)
(in thousands, except per share/unit amounts)

Three Months Three Months
Ended Ended
December 31, 2017 December 31, 2016
Net loss attributable to Vanguard stockholders/unitholders $ (74,113) $ (163,621)
Add: Net income (loss) attributable to non-controlling interests (71) 9
Net loss $ (74,042) $ (163,630)
Plus:
Interest expense 14,589 22,755
Depreciation, depletion, amortization, and accretion 43,743 30,855
Impairment of oil and natural gas properties 47,640 128,612
Change in fair value of commodity derivative contracts (b) 9,517 107,938
Premiums paid, whether at inception or deferred, for derivative contracts that settled during the period (b) (2,240)
Fair value of derivative contracts acquired that apply to contracts settled during the period (b) 5,349
Cash settlements paid on termination of derivative contracts 4,140
Net gains on interest rate derivative contracts (c) (3,194)
Net (gain) loss on acquisition and divestiture of oil and natural gas properties (4,450) 1,197
Taxes (102)
Compensation related items 81 2,462
Reorganization and restructuring costs 5,585 3,156
Material costs incurred on strategic transactions 2,000 67
Adjusted EBITDA before non-controlling interest $ 48,803 $ 133,225
Adjusted EBITDA attributable to non-controlling interest (38) (116)
Adjusted EBITDA attributable to Vanguard stockholders/unitholders $ 48,765 $ 133,109

 

(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) These items are included in the net losses on commodity derivative contracts line item in the consolidated statements of operations as follows:

Three Months Three Months
Ended Ended
December 31, 2017 December 31, 2016
Net cash settlements received (paid) on matured commodity derivative contracts $ (9,848) $ 28,773
Change in fair value of commodity derivative contracts (9,517) (107,938)
Premiums paid, whether at inception or deferred, for derivative contracts that

settled during the period

2,240
Fair value of derivative contracts acquired that apply to contracts settled during

the period

(5,349)
Cash settlements paid on termination of derivative contracts (4,140)
Fair value of restructured derivative contracts(d) 53,954
Net losses on commodity derivative contracts $ (23,505) $ (28,320)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(c) Net gains on interest rate derivative contracts as shown on the consolidated statements of operations is comprised of the following:

Three Months
Ended
December 31, 2016
Cash settlements paid on interest rate derivative contracts $ (6,628)
Change in fair value of interest rate derivative contracts 9,822
Net gains on interest rate derivative contracts $ 3,194

 

 

 

 

 

 

 

(d) Adjusted EBITDA attributable to Vanguard unitholders for the three months ended December 31, 2016 includes proceeds from the monetization of commodity derivative contracts of $54.0 million of which $37.1 million is attributable to derivative contracts that would have matured in 2017 and 2018. Excluding the proceeds attributable to the 2017 and 2018 commodity derivative contracts, Adjusted EBITDA available to Vanguard unitholders for the three months ended December 31, 2016 amounted to $96.0 million.

Adjusted Net Income (Loss) Attributable to Common Stockholders/Unitholders

We present Adjusted Net Income Available to Common Stockholders/Unitholders in addition to our reported net income (loss) attributable to Common Stockholders/Unitholders in accordance with GAAP. Adjusted Net Income Available to Common Stockholders/Unitholders is a non-GAAP financial measure that is defined as net income available to Common Stockholders/Unitholders plus the following adjustments:

  • Change in fair value of commodity derivative contracts;
  • Change in fair value of interest rate derivative contracts;
  • Fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period. Also excludes the fair value of derivative contracts acquired and settled during the period;
  • Cash settlements on termination of derivative contracts;
  • Net gains or losses on acquisitions and divestitures of oil and natural gas properties;
  • Impairment of oil and natural gas properties;
  • Reorganization and restructuring costs; and
  • Material costs incurred on strategic transactions.

We present Adjusted Net Income Available to Common Stockholders/Unitholders because management believes exclusion of the impact of these items will help investors compare results between periods and identify operating trends that could otherwise be masked by these items and to highlight the significant fluctuations that commodity price volatility has on our results, particularly as it relates to changes in the fair value of our derivative contracts.

In particular, we make the adjustment for the change in fair value of commodity derivative contracts to allow investors to make a comparison of our quarterly results without the non-cash impact of commodity price fluctuations from period to period resulting from changes in the mark-to-market value of our portfolio of commodity derivative contracts. Rather than highlighting the significant fluctuations that commodity price volatility has on Net Income, we are aiming to give investors a meaningful picture of our performance (especially versus prior periods) that shows how the company performed without the impact of the value of our portfolio of commodity derivative contracts. The fluctuations in the value of our portfolio of commodity derivatives contracts is related to futures pricing which is not a good indicator of historical performance of the business during the periods presented. Furthermore, any increases or decreases in the value of our portfolio of commodity derivatives contracts will result in non-cash charges or non-cash income. The inherent value (or cost) of such contracts is the amount of cash which our counterparties pay to us, or, with respect to costs, the amount which we paid to acquire the contracts and the amount that we are required to pay to our counterparties upon settlement.  We believe this non-GAAP measure allows our investors to measure our actual performance without the impact of certain non-cash items that do not actually reflect the performance of the Company for the periods presented.

We also make the adjustment for the change in fair value of interest rate derivative contracts to give investors a period to period comparison without showing the impact of non-cash gains or losses related to the mark-to-market valuation of these derivatives contracts.

Adjusted Net Income (Loss) Attributable to Common Stockholders/Unitholders is not intended to represent cash flows for the period, nor is it presented as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP.

VANGUARD NATURAL RESOURCES, INC.
Reconciliation of Net Loss Attributable to Common Stockholders/Unitholders to
Adjusted Net Income (Loss) Attributable to Common Stockholders/Unitholders
(in thousands, except per share/unit data)
(Unaudited)

Three Months Three Months
Ended Ended
December 31, 2017 December 31, 2016
Net Loss Attributable to Vanguard Common Stockholders/Unitholders $ (74,113) $ (170,310)
Plus (less):
Change in fair value of commodity derivative contracts(a)(b) 9,517 107,938
Change in fair value of interest rate derivative contracts(c)(d) (9,822)
Fair value of derivative contracts acquired that apply to

contracts settled during the period

5,349
Cash settlements paid on termination of derivative contracts 4,140
Net (gain) loss on acquisition and divestiture of oil and natural gas properties (4,450) 1,197
Impairment of oil and natural gas properties 47,640 128,612
Reorganization and restructuring costs 5,585 3,156
Material costs incurred on strategic transactions 2,000 67
Adjusted Net Income (Loss) Attributable to Vanguard Common and Class B Stockholders/Unitholders $ (9,681) $ 66,187

 

Net Loss Attributable to Vanguard Common Stockholders/Unitholders, per share/unit $ (3.69) $ (1.30)
   Plus (less):
Change in fair value of commodity derivative contracts 0.47 0.82
Change in fair value of interest rate derivative contracts (0.07)
Fair value of derivative contracts acquired that apply to

contracts settled during the period

0.04
Cash settlements paid on termination of derivative contracts 0.21
Net (gain) loss on acquisition and divestiture of oil and natural gas properties (0.22) 0.01
Impairment of oil and natural gas properties 2.37 0.98
Reorganization and restructuring costs 0.28 0.02
Material costs incurred on strategic transactions 0.10
Adjusted Net Income (Loss) Attributable to Vanguard Common and Class B Stockholders/Unitholders, per share/unit $ (0.48) $ 0.50
Weighted average common shares/common and Class B units outstanding 20,061 131,446

(a) Change in fair value of commodity derivative contracts reflects the increase or decrease in the mark-to-market value of the commodity derivative contracts. Any increase in value is reduced from Net Income (Loss) Attributable to Common Stockholders/Unitholders, while any decrease is added back into Net Income (Loss) Attributable to Common Stockholders/Unitholders.

(b) Does not include adjustments for premiums paid on derivatives during the period presented, the fair value of acquired derivatives that settled during the period presented or the fair value of restructured derivatives contracts.

(c) Change in fair value of interest rate derivative contracts reflects the increase or decrease in the mark-to-market value of the interest rate derivative contracts. Any increase in the fair value of interest rate derivative contracts is reduced from Net Income (Loss) Attributable to Common Stockholders/Unitholders, while any decrease in the fair value of interest rate derivative contracts is added back into Net Income (Loss) Attributable to Common Stockholders/Unitholders.

(d) Does not include cash settlements paid on interest rate derivatives.


SOURCE: Vanguard Natural Resources, Inc.

CONTACT: Vanguard Natural Resources, Inc.
Investor Relations
Lisa Godfrey, 832-399-3820
ir@vnrenergy.com