Vanguard Natural Resources, Inc. Reports Third Quarter 2018 Results, Asset Divestiture Updates, and Updated 2018 Guidance

HOUSTON – November 12, 2018 (PR NEWSWIRE) – Vanguard Natural Resources, Inc. (OTCQX: VNRR) (“Vanguard,” “VNRR,” or the “Company”) today reported financial results for the quarter ended September 30, 2018, and other operational results.

Key Highlights

  • Closed four divestitures for aggregate gross proceeds of $30.9 million, including its Potato Hills assets in Oklahoma which closed for gross proceeds of $22.9 million, interests in over 145 wells in Texas and Louisiana for gross proceeds of $5.5 million, and interests in five wells and associated undeveloped acreage in the DJ Basin in Colorado for gross proceeds of $2.6 million
  • Additionally, the Company entered into a purchase and sale agreement for the sale of its ownership in natural gas properties in the Arkoma basin of Arkansas in mid-September, which comprise all of its interests located in the state. The sale closed on October 15, 2018 for a total contract price of $12.0 million
  • Reported production volumes of 330 million cubic feet equivalent (MMcfe) per day
  • Lease operating expenses were $35.4 million
  • Selling, general and administrative expenses (excluding non-cash compensation and severance costs) were $9.6 million
  • Continued success in the oil-prone Red Lake area of New Mexico with a total of six recompletes to date with average rate of returns in excess of 90% and additional recomplete candidates and future infill drilling locations identified
  • Updated fourth quarter and full-year 2018 operational and financial guidance for the year, with an updated full year 2018 capital budget of approximately $120.0 million to $125.0 million
  • Remain significantly hedged for the balance of 2018 and through 2020 with the balance of 2018 production hedged 85%, 91% and 42% for natural gas, oil and NGLs, respectively, at the mid-point of announced guidance
  • Added Rockies basis hedges for 2018 and 2019 for a portion of our Rockies production
  • Added Midland-Cushing basis hedges for 2019 for a portion of our Permian production

Mr. R. Scott Sloan, President and CEO, commented, “We continue to be focused on transitioning Vanguard to an exploration and production company focused on organic growth. As we have stated in the past, the first step is divesting non-core assets to decrease outstanding debt and concentrate our technical focus on understanding the future potential value from our operated assets. As we look to the future I am particularly encouraged by our recent results with the San Andres at Red Lake and with the Resh wells in the Arkoma Woodford.”

Third Quarter 2018 Highlights

Reported average production of 330 MMcfe per day in the third quarter of 2018 represents a 9% decrease compared to 363 MMcfe per day for the second quarter of 2018 and was below our third quarter guidance range. The production decrease from the second quarter was primarily attributable to the closing of the Permian, Mississippi and Green River asset divestitures in June 2018, the Potato Hills divestiture in August 2018, and a decline in production from the Pinedale as activity decreases from the first half of the year. As compared to guidance, production was primarily impacted by lower than expected new production from Pinedale. Additionally, fewer NGLs were processed in the Piceance due to short-term downstream capacity issues in the third quarter that have since been resolved. On a Mcfe basis, crude oil, natural gas, and NGLs accounted for 15%, 70% and 15%, respectively, of our third quarter 2018 production.

Lease operating expenses (“LOE”) of $35.4 million during the third quarter of 2018 ($1.17 per Mcfe) decreased 4% compared to the $36.8 million in the second quarter of 2018 ($1.11 per Mcfe). The decrease compared to the second quarter is primarily due to the planned shutdown of the BEC facility and the associated maintenance in Alabama during the second quarter of 2018 along with other seasonal expense items across the portfolio plus the impact of divestments. Third quarter LOE was above guidance due to increased well workover and water handling costs in the Pinedale and  the Permian basin, plugging and abandonment costs, and prior period adjustments related to our non-operated assets.

Transportation and gathering expenses related to certain of our natural gas and NGLs contracts were $9.6 million during the third quarter of 2018 ($0.31 per Mcfe) and are lower as compared to $9.8 million in the second quarter of 2018 ($0.30 per Mcfe).

Selling, general and administrative expenses (“SG&A”) were $10.7 million during the third quarter of 2018 ($0.35 per Mcfe), a 3% decrease compared to the $11.1 million reported in the second quarter of 2018 ($0.34 per Mcfe). Excluding non-cash compensation of $0.6 million and severance costs of approximately $0.5 million, SG&A was $9.6 million for the third quarter of 2018, which was below the mid-point of guidance.

Depreciation, depletion and amortization expenses (“DD&A”) were $35.6 million in the third quarter of 2018 ($1.17 per Mcfe), representing a decrease of 8% from $38.7 million in the second quarter of 2018 ($1.17 per Mcfe). The reported DD&A decreased primarily due to impairment charges and the sale of oil and gas properties in the second quarter and third quarters of 2018, both of which reduced our depletable base for the current period.

We reported a net loss attributable to Common Stockholders for the third quarter of 2018 of $32.1 million compared to a net loss attributable to Common Stockholders of $57.8 million in the second quarter of 2018. The decrease in the Company’s reported net loss for the third quarter of 2018 is primarily attributable to higher revenues due to higher average realized natural gas and NGLs prices combined with a decrease in losses on commodity derivative contracts (realized and unrealized). We also had lower LOE and lower impairment expense, offset by a lower gain on divestitures compared to second quarter.

Adjusted Net Loss Attributable to Common Stockholders (a non-GAAP financial measure defined below) was $22.8 million in the third quarter of 2018 compared to Adjusted Net Loss of $25.2 million in the second quarter of 2018. The Adjusted Net Loss for the third quarter of 2018 included adjustments for net non-cash expenses of $8.2 million primarily comprised of a $2.0 million impairment charge on our oil and natural gas properties and a $8.0 million loss from the change in fair value of commodity derivative contracts, offset by a $1.7 million net gain on asset sales. The Adjusted Net Loss for the second quarter of 2018 included adjustments for net non-cash expenses of $30.1 million primarily comprised of a $7.6 million impairment charge on our oil and natural gas properties and a $27.5 million loss from the change in fair value of commodity derivative contracts, offset by a $4.9 million net gain on asset sales.

Adjusted EBITDA (a non-GAAP financial measure defined below) was $29.7 million in the third quarter of 2018 and represents a 3% decrease as compared to Adjusted EBITDA of $30.5 million for the second quarter of 2018. The decrease as compared to the second quarter of 2018 is attributable primarily to higher realized losses on our commodity derivative contracts, partially offset by higher oil, natural gas, and NGLs revenues.

Capital expenditures for the third quarter of 2018 were $24.1 million, down from $38.4 million in the second quarter of 2018. This $14.3 million decrease from the second quarter is primarily attributable to lower capital spend in the Piceance Basin and in the Pinedale field. During the third quarter, we participated as a non-operated Pinedale partner in the drilling and completion of two horizontal and 20 vertical natural gas wells.  In Mamm Creek, we completed the last three wells of the 2018 development drilling program. The focus for the balance of the year and into 2019 will be to analyze the data from the 14 well program and evaluate how to best proceed in future development of the large resource still in place.

Selected Financial Information

A summary of selected financial information follows (in thousands, except for production data):

Three Months Three Months Three Months
Ended Ended Ended
September 30, 2018 June 30, 2018 September 30, 2017(3)
Production (Mcfe/day) 330,028 363,088 371,824
Oil, natural gas and natural gas liquids sales $ 116,430 $ 111,713 $ 100,824
Net losses on commodity derivative contracts $ (30,887 ) $ (45,332 ) $ (44,371 )
Operating expenses (1) $ 45,172 $ 44,734 $ 45,954
Selling, general and administrative expenses $ 10,733 $ 11,108 $ 15,932
Net Income (Loss) Attributable to Vanguard Common
    Stockholders/Unitholders
$ (32,133 ) $ (57,773 ) $ 925,792
Adjusted Net Loss Attributable to Vanguard Common
Stockholders/Unitholders (2)
$ (22,760 ) $ (25,181 ) $ (19,712 )
Adjusted EBITDA attributable to Vanguard Common
     Stockholders/Unitholders (2)
$ 29,693 $ 30,467 $ 30,785
Total Debt (as of September 30, 2018, June 30, 2018 and
     September 30, 2017, respectively)
$ 870,114 $ 898,697 $ 942,912
Interest expense, including settlements paid on interest rate
     derivative contracts
$ 16,060 $ 15,870 $ 14,618
Capital expenditures $ 24,071 $ 38,444 $ 33,366
Net cash provided by (used in) operating activities $ 11,884 $ 14,859 $ (7,833 )

 

Nine Months Nine Months
Ended Ended
September 30, 2018 September 30, 2017(4)
Production (Mcfe/day) 353,424 378,124
Oil, natural gas and natural gas liquids sales $ 351,418 $ 326,448
Net losses on commodity derivative contracts $ (94,804 ) $ (57,239 )
Operating expenses (1) $ 130,682 $ 140,462
Selling, general and administrative expenses $ 34,577 $ 36,004
Net Income (Loss) Attributable to Vanguard Common
    Stockholders/Unitholders
$ (122,590 ) $ 860,771
Adjusted Net Income (Loss) Attributable to Vanguard Common
     Stockholders/Unitholders (2)
$ (52,621 ) $ 7,984
Adjusted EBITDA attributable to Vanguard Common
     Stockholders/Unitholders (2)
$ 112,138 $ 146,209
Total Debt (as of September 30, 2018 and September 30,
     
2017, respectively)
$ 870,114 $ 942,912
Interest expense, including settlements paid on interest rate
     derivative contracts
$ 46,683 $ 44,891
Capital expenditures $ 104,588 $ 70,691
Net cash provided by operating activities $ 62,992 $ 66,016

 

(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.
(3) All amounts, except Total Debt, reflect the combined results of the two months ended September 30, 2017 (Successor) and the one month ended July 31, 2017 (Predecessor).
(4) All amounts, except Total Debt, reflect the combined results of the two months ended September 30, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor).

Average Prices and Production Volumes

Three Months Ended September 30, Percentage
Increase / (Decrease)
Three Months Ended
June 30,
Percentage
Increase / (Decrease)
2018(b) 2017(b)(d) 2018(b)
Average realized prices, excluding hedges:
Oil (Price/Bbl) $ 58.14 $ 42.62 36 % $ 59.32 (2 )%
Natural Gas (Price/Mcf)(a) $ 2.18 $ 1.82 20 % $ 1.81 20 %
NGLs (Price/Bbl)(a) $ 35.19 $ 22.77 55 % $ 28.45 24 %
Average realized prices, including hedges (c):
Oil (Price/Bbl) $ 37.25 $ 40.41 (8 )% $ 40.65 (8 )%
Natural Gas (Price/Mcf) $ 2.13 $ 1.89 13 % $ 1.88 13 %
NGLs (Price/Bbl) $ 26.71 $ 20.22 32 % $ 22.18 20 %
Average NYMEX prices:
Oil (Price/Bbl) $ 69.48 $ 48.22 44 % $ 67.89 2 %
Natural Gas (Price/Mcf) $ 2.90 $ 3.00 (3 )% $ 2.80 4 %
Total production volumes:
Oil (MBbls) 738 918 (20 )% 784 (6 )%
Natural Gas (MMcf) 21,319 23,890 (11 )% 23,573 (10 )%
NGLs (MBbls) 769 802 (4 )% 794 (3 )%
     Combined (MMcfe) 30,363 34,208 (11 )% 33,041 (8 )%
Average daily production volumes:
Oil (Bbls/day) 8,022 9,977 (20 )% 8,615 (7 )%
Natural Gas (Mcf/day) 231,729 259,672 (11 )% 259,049 (11 )%
NGLs (Bbls/day) 8,361 8,715 (4 )% 8,725 (4 )%
     Combined (Mcfe/day) 330,028 371,824 (11 )% 363,088 (9 )%

(a) In accordance with the adoption of ASC Topic 606, the average realized natural gas and NGLs prices for the three months ended September 30, 2018, the three months ended September 30, 2017, and the three months ended June 30, 2018 exclude gathering, transportation, and processing fees of $9.6 million, $8.0 million, and $9.8 million, respectively, related to certain of our natural gas and NGLs marketing and processing agreements that were reclassified and presented as Transportation, gathering, processing, and compression expense in our condensed consolidated statements of operations. As such, our average realized prices are not comparable with the prior periods. If our natural gas and NGLs revenues are shown net of these fees, the average realized natural gas price and average NGLs price excluding hedges would be as follows:

Three Months Ended September 30, Three Months Ended
June 30,
2018 2017 2018
Average realized prices, excluding hedges:
Natural Gas (Price/Mcf)(a) $ 1.87 $ 1.57 $ 1.49
NGLs (Price/Bbl)(a) $ 31.21 $ 20.28 $ 25.52

 

(b) During 2018 and 2017, 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.
(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.
(d) All amounts reflect the combined results of the two months ended September 30, 2017 (Successor) and the one month ended July 31, 2017 (Predecessor).

Nine Months Ended
September 30,
Percentage
Increase / (Decrease)
2018 (b) 2017 (b)(d)
Average realized prices, excluding hedges:
Oil (Price/Bbl) $ 57.52 $ 43.41 33 %
Natural Gas (Price/Mcf)(a) $ 2.11 $ 2.15 (2 )%
NGLs (Price/Bbl)(a) $ 30.48 $ 19.52 56 %
Average realized prices, including hedges (c):
Oil (Price/Bbl) $ 39.94 $ 42.71 (6 )%
Natural Gas (Price/Mcf) $ 2.22 $ 2.18 2 %
NGLs (Price/Bbl) $ 23.86 $ 18.71 28 %
Average NYMEX prices:
Oil (Price/Bbl) $ 66.62 $ 49.51 35 %
Natural Gas (Price/Mcf) $ 2.89 $ 3.16 (9 )%
Total production volumes:
Oil (MBbls) 2,356 2,875 (18 )%
Natural Gas (MMcf) 68,263 70,911 (4 )%
NGLs (MBbls) 2,348 2,511 (6 )%
     Combined (MMcfe) 96,485 103,228 (7 )%
Average daily production volumes:
Oil (Bbls/day) 8,630 10,530 (18 )%
Natural Gas (Mcf/day) 250,048 259,749 (4 )%
NGLs (Bbls/day) 8,600 9,199 (6 )%
     Combined (Mcfe/day) 353,424 378,124 (7 )%

 

(a) In accordance with the adoption of ASC Topic 606, the average realized natural gas and NGLs prices for the nine months ended September 30, 2018 and 2017 exclude gathering, transportation, and processing fees of $30.8 million and $8.0 million, respectively, related to certain of our natural gas and NGLs marketing and processing agreements that were reclassified and presented as Transportation, gathering, processing, and compression expense in our condensed consolidated statements of operations. As such, our average realized prices are not comparable with the prior periods. If our natural gas and NGLs revenues are shown net of these fees, the average realized natural gas price and average NGLs price excluding hedges would be as follows:

Nine Months Ended September 30,
2018 2017
Average realized prices, excluding hedges:
Natural Gas (Price/Mcf)(a) $ 1.79 $ 2.07
NGLs (Price/Bbl)(a) $ 26.92 $ 18.73

 

(b) During 2018 and 2017, 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.
(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.
(d) All amounts reflect the combined results of the two months ended September 30, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor).

Asset Divestiture Update

During 2018, we completed the sale of certain oil and natural gas properties in the Permian Basin, the Green River Basin and in Mississippi. We also sold our working interests in related oil and natural gas producing properties located in multiple counties in Texas, Louisiana and Colorado. Additionally, we completed the Potato Hills Divestment during the third quarter of 2018. Aggregate net cash proceeds received from the sale of these properties were approximately $92.2 million, subject to customary post-closing adjustments. We incurred costs to sell of approximately $2.4 million. The net cash proceeds from these divestments were used to reduce borrowings under our Successor Credit Facility.

On October 15, 2018, we closed the sale of our Arkoma Basin properties in Arkansas for a contract price of $12.0 million. The sale comprises all of our interests located within the state.

We are in the process of divesting our Greater East Haynesville package which includes certain oil and natural gas properties in East Texas and North Louisiana. Additionally, we are publicly marketing several smaller packages of Permian production and undeveloped acreage with the aim of closing prior to year-end. Finally, we continue to identify and prepare for potential sale other assets. The sales of these properties are anticipated to further reduce debt under our Successor Credit Facility and sharpen the focus of the portfolio.

Operational Update

In the Pinedale field, production decreased to approximately 112 MMcfe per day in the third quarter of 2018 from approximately 117 MMcfe per day in the second quarter of 2018. As one of our operators reduces drilling activity in the field, we anticipate fourth quarter production to decline, with an overall modest decline for the full year. For the remainder of 2018 we expect to participate only in vertical wells, and we are comfortable that these vertical wells represent a high-graded group of wells that should deliver solid economic returns in today’s gas price environment.

In the Arkoma Woodford area, production remained flat at approximately 31 MMcfe per day for both the second and third quarters of 2018. Vanguard participated in the drilling and completion of two wells operated by BP America, Inc. (“BP”). This BP program has come in above our curve type expectations with an average 30 day IP of 8.8 MMcf per day.  In the second half of 2018, the Company will participate in seven additional wells which Newfield Exploration Company (“Newfield”) will operate. Initial production from this program is expected early in the second quarter of 2019. We have a large drilling inventory in the Arkoma basin where we will continue to advance our understanding in preparation for an operated program in late 2019 or early 2020.

The Piceance assets produced approximately 70 MMcfe per day for the third quarter of 2018, down approximately 3% from the second quarter, which was largely driven by less NGLs being processed due to short-term downstream capacity issues that have since been resolved in October. We completed the final three wells of our 14 well program. The focus for the balance of the year and into 2019 will be to analyze the data from the program and evaluate how to best proceed in future development of the large resource still in place.

In the Red Lake field of New Mexico, production remained flat in the second and third quarters of 2018 at approximately 2 MBoe per day (77% liquids). We are seeing significant success with the recompletion program where the Company has performed a total of six recompletes to date with average rate of returns in excess of 90%. Two more recompletions are expected before year-end.  We are preparing a 2019 Red Lake development plan which is expected to include more recompletions as well as a restart of our drilling program.

In the Elk Basin field of Wyoming, production remained flat in the second and third quarters of 2018 at approximately 3 MBoe per day (96% liquids). This field has a low production decline rate, and we have been able to successfully maintain production with minimal capital expenditures.

Capital Expenditures Update

Total capital expenditures were approximately $104.6 million during the nine months ended September 30, 2018. We currently anticipate a total capital expenditures budget ranging from $120.0 million to $125.0 million for the full year of 2018, down from our August 2018 guidance. This capital decrease is primarily due to a decrease in drilling activity in Vanguard’s lease hold in Pinedale and timing changes across other areas in the portfolio.

In the Green River Basin, we are on track to spend between $7.0 million and $8.0 million in the Pinedale Field in Wyoming for the remainder of 2018, where we participate in the drilling of vertical natural gas wells with partners Ultra Petroleum Corporation and Pinedale Energy Partners.  In the Arkoma Basin we expect to spend approximately $7.0 million of our remaining 2018 capital budget where we will be participating as a non-operated partner with Newfield Exploration Company in a one rig program, drilling and completing horizontal Woodford wells. The balance of our remaining drilling and completion capital will be spent on production uplift projects in the Permian and Big Horn Basins.

Revised 2018 Guidance

New guidance is being issued for the fourth quarter and full year of 2018 to reflect the updated investment allocation and to incorporate the operational and financial results of the first nine months of 2018.  Production is now estimated to be in the range of 309 MMcfe per day to 324 MMcfe per day and 342 MMcfe per day to 346 MMcfe per day for the fourth quarter and full year of 2018, respectively.

“Overall, our revised 2018 guidance considers $12.0 million in additional divestments with production of approximately 8 million cubic feet equivalent per day closing in October and a decrease in capital spend for the balance of the year,” commented Mr. Midgett.

The following table sets forth the Company’s revised guidance for 2018 which is based on certain estimates being used by the Company to model its anticipated results of operations for the 2018 fiscal year. These estimates include the recently closed divestment of the Company’s Arkansas properties.

Q4 2018E FY 2018E
Net Production:
Oil (Bbls/day) 7,500 8,200 8,350 8,530
Natural gas (Mcf/day) 212,000 220,000 240,520 242,540
NGLs (Bbls/day) 8,700 9,100 8,630 8,730
     Combined (Mcfe/day) 309,200 323,800 342,400 346,100
Costs ($ in thousands):
Lease operating expenses $ 27,500 $ 32,500 $ 131,000 $ 136,000
Production taxes (% of revenue) 8 % 10 % 8 % 10 %
G&A expenses(1) $ 9,100 $ 12,100 $ 40,500 $ 43,500
Interest expense $ 14,500 $ 17,500 $ 61,500 $ 64,500
Capital expenditures $ 16,500 $ 21,500 $ 120,000 $ 125,000
Average NYMEX Differentials(2):
Oil ($/Bbl) $ (13.50 ) $ (17.50 ) $ (10.20 ) $ (11.20 )
Natural gas ($/MMBtu) $ (0.65 ) $ (1.00 ) $ (1.00 ) $ (1.10 )
NGLs realization of crude oil price (%)(3) 31 % 38 % 38 % 40 %

 

(1) Includes post-emergence restructuring related costs of $1.9 million for the balance of 2018.
(2) Includes impact of transportation and gathering costs that may be classified as operating expenses under ASC Topic 606. In Q3 2018, transportation and gathering expenses related to certain of our natural gas and NGLs contracts were $9.6 million.
(3) Assumes a weighted average product breakout of approximately 37% ethane, 29% propane, 11% isobutane, 8% n-butane and 15% pentane.

Liquidity Update

As of October 31, 2018 we have $654.8 million of outstanding borrowings under the reserve-based credit facility and approximately $39.1 million of liquidity after reflecting a $0.2 million reduction in availability for letters of credit and approximately $5.0 million in available cash.

Ryan Midgett, Chief Financial Officer, commented, “The Company continues to be focused on the balance sheet, and creating flexibility for the Company to execute its future capital program. The team continues to execute on a successful divestment program that will ultimately help the Company achieve these goals. Although leverage continues to be elevated in the near-term, as hedges roll-off there will be a significant improvement in cash flows that will be complemented by future capital spending in our growth areas.”

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, basis swap contracts, 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.

The Company has entered into Rockies natural gas basis hedges for 105,000 MMbtu per day at a weighted average price of ($0.62) per MMbtu for the period of October 2018, 92,185 MMbtu per day at a weighted average price of ($0.46) for the period of November 2018 to March 2019, and 25,000 MMBtu per day at a weighted average price of ($0.58) per MMbtu for the period of April 2019 to December 2019. This equates to approximately 75%, 70%, and 20% of the Company’s Rockies natural gas production for the respective periods. Additionally, the Company has entered into Midland-Cushing basis hedges for 1,250 barrels per day at a weighted average price of ($5.78) per barrel for 2019 and 1,000 barrels per day at a weighted average price of ($0.10) for 2020.

The following tables summarize our current hedge positions:

 

October 1 – December 31, 2018 Year
2019
Year
2020
Year
2021
Gas Positions:
Fixed-Price Swaps:
Notional Volume (MMBtu) 16,928,000 52,539,000 47,227,500
Fixed Price ($/MMBtu) $ 2.89 $ 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

 

October 1 – December 31, 2018 Year
2019
Year
2020
Year
2021
Oil Positions:
Fixed-Price Swaps (West Texas Intermediate):
Notional Volume (Bbls) 654,700 1,858,200 1,393,800
Fixed Price ($/Bbl) $ 46.60 $ 48.50 $ 49.53 $
Collars:
Notional Volume (Bbls) 575,730 659,340 294,536
Floor Price ($/Bbl) $ $ 43.81 $ 44.17 $ 55.25
Ceiling Price ($/Bbl) $ $ 54.04 $ 55.00 $ 63.76

 

 

October 1 – December 31, 2018 Year
2019
NGLs Positions:
   Fixed-Price Swaps:
Mont Belvieu Ethane
Notional Volume (Gallons) 2,318,400 5,177,529
Fixed Price ($/Gallon) $ 0.28 $ 0.34
   Mont Belvieu Propane
Notional Volume (Gallons) 5,796,000 12,402,427
Fixed Price ($/Gallon) $ 0.53 $ 0.80
   Mont Belvieu N. Butane
Notional Volume (Gallons) 1,932,000 4,572,440
Fixed Price ($/Gallon) $ 0.65 $ 0.93
   Mont Belvieu Isobutane
Notional Volume (Gallons) 1,545,600 3,686,779
Fixed Price ($/Gallon) $ 0.65 $ 0.93
   Mont Belvieu N. Gasoline
Notional Volume (Gallons) 2,704,800 6,777,667
Fixed Price ($/Gallon) $ 0.99 $ 1.37

 

October 1 – December 31, 2018 Year
2019
Year
2020
Gas Positions:
Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
Notional Volume (MMBtu) 9,355,000 14,695,000
Weighted-basis differential ($/MMBtu) $ (0.50 ) $ (0.53 ) $
Oil Positions:
WTI Midland and WTI Cushing Basis Differential
Notional Volume (Bbls) 456,250 366,000
Fixed Price ($/Bbl) $ $ (5.78 ) $ (0.10 )

 

For a summary of our current commodity derivative contracts, please refer to our Supplemental Presentation on the Investor Relations section of Vanguard’s corporate website, http://www.vnrenergy.com.

 

Conference Call Information

The Company will host a conference call Monday, November 12, 2018, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time) to discuss the Company’s third quarter 2018 results. There will be prepared remarks by R. Scott Sloan, President & Chief Executive Officer, and Ryan Midgett, Chief Financial Officer, followed by a question and answer session.

Investors and analysts are invited to participate in the call by dialing 1-323-794-2093, or 888-289-0571 for toll free calls using Conference ID: 2518610. Interested parties may also listen over the internet at www.vnrenergy.com. A replay of the call will be available on the Company’s website.

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 Oklahoma, the Gulf Coast Basin in Texas, Louisiana 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 is defined as 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:

  • Interest expense;
  • Depreciation, depletion, amortization, and accretion;
  • Impairment of oil and natural gas properties;
  • Exploration expense;
  • Change in fair value of commodity derivative contracts;
  • Net gains or losses on interest rate derivative contracts;
  • Net gains on divestiture 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 items;
  • Severance 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 used as a quantitative standard by our 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 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.

 

VANGUARD NATURAL RESOURCES, INC.
Reconciliation of Net Income (Loss) to Adjusted EBITDA
(Unaudited)
(in thousands)

Successor Predecessor
Three Months Two Months One Month
Ended Ended Ended
September 30, 2018 September 30, 2017 July 31, 2017
Net income (loss) attributable to Vanguard stockholders/
    unitholders
$ (32,133 ) (37,297 ) 963,089
Add: Net income attributable to non-controlling interests 37 61 1
Net income (loss) $ (32,096 ) $ (37,236 ) $ 963,090
Plus:
Interest expense 16,060 9,615 5,003
Depreciation, depletion, amortization, and accretion 35,568 27,578 7,328
Impairment of oil and natural gas properties 1,965
Exploration expense 219 105
Change in fair value of commodity derivative contracts (a) 7,970 30,026 12,019
Net gain on divestiture of oil and natural gas properties (1,747 )
Taxes 158
Compensation related items 581 711
Reorganization items 732 (988,452 )
Severance costs 453
Material costs incurred on strategic transactions 903
Adjusted EBITDA before non-controlling interest 29,705 30,991 (143 )
Adjusted EBITDA attributable to non-controlling interest (12 ) (24 ) (39 )
Adjusted EBITDA attributable to Vanguard stockholders/
      unitholders
$ 29,693 $ 30,967 $ (182 )

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

Successor Predecessor
Three Months Two Months One Month
Ended Ended Ended
September 30, 2018 September 30, 2017 July 31, 2017
Net cash settlements paid on matured commodity
  derivative contracts
$ (22,917 ) $ (2,326 ) $
Change in fair value of commodity derivative contracts (7,970 ) (30,026 ) (12,019 )
Net losses on commodity derivative contracts $ (30,887 ) $ (32,352 ) $ (12,019 )

 

 

Successor Predecessor
Nine Months Two Months Seven Months
Ended Ended Ended
September 30, 2018 September 30, 2017 July 31, 2017
Net income (loss) attributable to Vanguard stockholders/
     unitholders
$ (122,590 ) (37,297 ) 900,298
Add: Net income attributable to non-controlling interests 226 61 13
Net income (loss) $ (122,364 ) $ (37,236 ) $ 900,311
Plus:
Interest expense 46,683 9,615 35,276
Depreciation, depletion, amortization, and accretion 114,318 27,578 58,384
Impairment of oil and natural gas properties 24,118
Exploration expense 1,965 105
Change in fair value of commodity derivative contracts (a) 44,747 30,026 24,894
Net gains on interest rate derivative contracts (b) (30 )
Net gain on divestiture of oil and natural gas properties (6,647 )
Taxes (634 )
Compensation related items 1,654 5,797
Reorganization items 3,049 (908,485 )
Severance costs 4,554
Material costs incurred on strategic transactions 148 903
Adjusted EBITDA before non-controlling interest 112,225 30,991 115,513
Adjusted EBITDA attributable to non-controlling interest (87 ) (24 ) (271 )
Adjusted EBITDA attributable to Vanguard stockholders/
     unitholders
$ 112,138 $ 30,967 $ 115,242

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

Successor Predecessor
Nine Months Two Months Seven Months
Ended Ended Ended
September 30, 2018 September 30, 2017 July 31, 2017
Net cash settlements received (paid) on matured
    commodity derivative contracts
$ (50,057 ) $ (2,326 ) $ 7
Change in fair value of commodity derivative contracts (44,747 ) (30,026 ) (24,894 )
Net losses on commodity derivative contracts $ (94,804 ) $ (32,352 ) $ (24,887 )

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

Predecessor
Seven Months
Ended
July 31, 2017
Cash settlements paid on interest rate derivative contracts (95 )
Change in fair value of interest rate derivative contracts 125
Net gains on interest rate derivative contracts $ 30

 

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

We present Adjusted Net Income (Loss) Attributable to Common Stockholders/Unitholders in addition to our reported net income (loss) attributable to Common Stockholders/Unitholders in accordance with GAAP.  Adjusted Net Income (Loss) Attributable to Common Stockholders/Unitholders is a non-GAAP financial measure that is defined as net income attributable 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;
  • Net gains on divestiture of oil and natural gas properties;
  • Impairment of oil and natural gas properties;
  • Reorganization items;
  • Severance costs; and
  • Material costs incurred on strategic transactions.

We present Adjusted Net Income (Loss) Attributable 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 (Loss), 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 Income (Loss) Attributable to Common Stockholders/Unitholders to
Adjusted Net Loss Attributable to Common Stockholders/Unitholders
(in thousands, except per share/unit data)
(Unaudited)

Successor Successor Predecessor
Three Months Two Months One Month
Ended Ended Ended
September 30, 2018 September 30, 2017 July 31, 2017
Net Income (Loss) Attributable to Vanguard Common
     Stockholders/Unitholders
$ (32,133 ) $ (37,297 ) $ 963,089
   Plus (less):
Change in fair value of commodity derivative contracts(a) 7,970 30,026 12,019
Net gains on divestitures of oil and natural gas properties (1,747 )
Impairment of oil and natural gas properties 1,965
Reorganization items 732 (988,452 )
Severance costs 453
Material costs incurred on strategic transactions 903
Adjusted Net Loss Attributable to Vanguard Common and
     Class B Stockholders/Unitholders
$ (22,760 ) $ (6,368 ) $ (13,344 )

 

Net Income (Loss) Attributable to Vanguard Common
     Stockholders/Unitholders, per share/unit
$ (1.60 ) $ (1.86 ) $ 7.33
   Plus (less):
Change in fair value of commodity derivative contracts(a) 0.40 1.50 0.09
Net gains on divestitures of oil and natural gas properties (0.09 )
Impairment of oil and natural gas properties 0.10
Reorganization items 0.04 (7.52 )
Severance costs 0.02
Material costs incurred on strategic transactions 0.05
Adjusted Net Loss Attributable to Vanguard Common and
     Class B Stockholders/Unitholders, per share/unit
$ (1.13 ) $ (0.31 ) $ (0.10 )
Weighted average common shares/common and Class B
    units outstanding
20,100 20,056 131,398

(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.

Successor Successor Predecessor
Nine Months Two Months Seven Months
Ended Ended Ended
September 30, 2018 September 30, 2017 July 31, 2017
Net Loss Attributable to Vanguard Common
     Stockholders/Unitholders
$ (122,590 ) $ (37,297 ) $ 898,068
   Plus (less):
Change in fair value of commodity derivative contracts(a) 44,747 30,026 24,894
Change in fair value of interest rate derivative contracts(b) (125 )
Net gain on divestiture of oil and natural gas properties (6,647 )
Impairment of oil and natural gas properties 24,118
Reorganization items 3,049 (908,485 )
Severance costs 4,554
Material costs incurred on strategic transactions 148 903
Adjusted Net Income (Loss) Attributable to Vanguard
     Common and Class B Stockholders/Unitholders
$ (52,621 ) $ (6,368 ) $ 14,352

 

Net Loss Attributable to Vanguard Common Stockholders/Unitholders, per share/unit $ (6.10 ) $ (1.86 ) $ 6.84
   Plus (less):
Change in fair value of commodity derivative contracts(a) 2.23 1.50 0.19
Change in fair value of interest rate derivative contracts(b)
Net gain on divestiture of oil and natural gas properties (0.33 )
Impairment of oil and natural gas properties 1.20
Reorganization items 0.15 (6.91 )
Severance costs 0.23
Material costs incurred on strategic transactions 0.01 0.05
Adjusted Net Income (Loss) Attributable to Vanguard
     Common and Class B Stockholders/Unitholders, per
     share/unit
$ (2.61 ) $ (0.31 ) $ 0.12
Weighted average common shares/common and Class B
    units outstanding
20,100 20,056 131,382

 

(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) 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.


 

SOURCE: Vanguard Natural Resources, Inc.
CONTACT: Vanguard Natural Resources, Inc.
Investor Relations
Ryan Midgett, Chief Financial Officer
IR@vnrenergy.com