First Quarter (1Q) Update | Capital Expenditure | Capital Expenditure - 2018

NuVista Touts Best Montney Well Ever; 16,000 FT Lateral Flowing 1,000 Bbls/d

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   |    Thursday,May 10,2018

[Summary:  NuVista provided the following update for 1Q18.

Quick Read

Successfully drilled, completed and brought on stream the longest horizontal lateral well ever drilled in Canada at almost 3,000 Boe/d, including over 1,000 BBls/d of condensate.

Executed a successful $115 million capital expenditure program for the first quarter running three to four rigs and drilling 8 gross (8 net) successful wells in our Wapiti asset;

Achieved production of 36,100 Boe/d, at the top of the guidance range of 34,500 – 36,000 Boe/d and 35% greater than the comparative quarter in 2017. Condensate volume weighting remained similar to the prior year at 31% but decreased from the short term high of 35% for the fourth quarter of 2017

2018 Capital  and production guidance remains on changed at $270 - $310 million of capital  and 35,000 - 40,000 Boe/d of production.

About the best well.

The 5,000 metre (16,000 ft) well is the longest horizontal lateral well ever drilled in Canada. The wells were completed with high intensity fractures (HIFI), placing approximately 2 tonnes of sand per metre of horizontal length, a total of 88 fracture intervals in each well. The average drill and complete cost for each of these two wells was $14.5MM, or $164,000 per stage which is lower than our budgeted average for 2018.

Bilbo, Elmworth, and Gold Creek Update

Drilling at Bilbo during the quarter continued as planned with one to two rigs operating and wells being brought on stream to maintain production at or near 18,000 Boe/d. Pad sizes for new wells currently range from two to five wells per pad. Four new wells were brought onstream during the quarter, with average IP30’s of 1,972 Boe/d including 46% condensate, or 124 Bbls condensate per MMcf of raw gas. NuVista’s first Lower Montney well which started up at the end of 2017 continues to perform favorably. This quarter the well reached an IP90 condensate rate of 540 Bbls/d, an excellent outcome as compared to the average of all prior NuVista Middle Montney Bilbo wells at 550 Bbls/day condensate. The Bilbo compressor station is performing well, with indications of peak-day production capability as high as 20,000 Boe/d as compared to original nameplate capacity of 18,000 Boe/d.

One rig was deployed at Elmworth during the quarter, currently drilling a four-well pad. Production averaged 14,200 Boe/d for the quarter and is now being restricted to make room for the new Gold Creek wells which have come on stream.

At Gold Creek, volumes have now reached over 5,000 Boe/d. One to two rigs were active, drilling a delineation/expiry well in the North and a record length two-well pad in the South. Building upon the operational success from the last extended reach horizontal (ERH) pad at Gold Creek, the horizontal lengths achieved on these wells were 4,500 and 5,000 metres respectively. The 5,000 metre well is the longest horizontal lateral well ever drilled in Canada. The wells were completed with high intensity fractures (HIFI), placing approximately 2 tonnes of sand per metre of horizontal length, a total of 88 fracture intervals in each well. The average drill and complete cost for each of these two wells was $14.5MM, or $164,000 per stage which is lower than our budgeted average for 2018.

Production from Elmworth is being restricted in order to make room for these new wells which have been brought onstream for initial cleanup flow. We are very pleased to note that the first well has averaged 2,962 Boe/d including 1,056 Bbls/d condensate (condensate gas ratio of 87 Bbls/MMcf) over the first 24 days. The test is particularly encouraging in that gas rates and flowing pressures have been stable to increasing as the high rate of frac water flowback subsides. The upcoming IP90 and IP180 results for these wells will be better indicators of how the first-year capital efficiencies for these ERH wells compare with the historic average.

The Elmworth compressor stations are performing well, handling the production from both Elmworth and Gold Creek wells at the present time. Drilling continues in Elmworth to keep area production pushing up to and beyond nameplate levels, with 18,000+ Boe/d already achieved versus nameplate capacity of 19,000 Boe/d. Drilling in Gold Creek will resume later this year in advance of the startup of the new SemCAMS Wapiti gas plant in early-mid 2019. When the SemCams gas plant starts up, Gold Creek new and existing volumes will be directed there which will provide significant space for continued growth in both Elmworth and Gold Creek.

 

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ORIGINAL RELEASE

NuVista Energy Ltd. (“NuVista” or the “Company”) (TSX:NVA) is pleased to announce results for the three months ended March 31, 2018 and provide an update on our future business plans.

This has been another successful quarter for NuVista, with key operational advancements, the favorable placement of senior unsecured notes and the renewal of our credit facility.  It was also a quarter where despite industry headwinds, we have seen improvement in oil and condensate pricing, and relative steadiness in NYMEX natural gas pricing.  Due to our favorable price diversification and natural gas export position, NuVista has not been materially exposed to the downward pressure affecting AECO natural gas pricing.  As a result, NuVista adjusted funds flow netbacks have continued to strengthen and our balance sheet remains robust as we progress on our 60,000 Boe/d growth plan.

Key Financial and Operational Highlights

During the quarter ended March 31, 2018 NuVista:

  • Achieved production of 36,100 Boe/d, at the top of the guidance range of 34,500 – 36,000 Boe/d and 35% greater than the comparative quarter in 2017.  Condensate volume weighting remained similar to the prior year at 31% but decreased from the short term high of 35% for the fourth quarter of 2017, as expected;
  • Attained adjusted funds flow of $58.7 million for the quarter ($0.34/share, basic), compared to $43.3 million ($0.25/share, basic) for the first quarter of 2017.  Q1 2018 includes approximately $9 million in costs for the early redemption of our prior $70 million term note;
  • Achieved adjusted funds flow netbacks of $18.09/Boe as compared to $17.98/Boe for the first quarter of 2017;
  • Realized operating costs of $10.02/Boe as compared to $10.72 for the comparable quarter in 2017;
  • Continued our downward trend in net G&A expenses, reaching $1.41/Boe, as compared to $1.71 in the first quarter of 2017;
  • Executed a successful $115 million capital expenditure program for the first quarter running three to four rigs and drilling 8 gross (8 net) successful wells in our Wapiti asset; and
  • Successfully drilled, completed and brought on stream the longest horizontal lateral well ever drilled in Canada at almost 3,000 Boe/d, including over 1,000 BBls/d of condensate.

Credit Facility, Senior Notes, and Hedging

  • Exited the first quarter of 2018 with nil drawn on the Company’s $310 million credit facility. Net debt, including senior unsecured notes and working capital deficiency, was $259 million;
  • Achieved net debt to annualized current quarter adjusted funds flow of 1.1 times;
  • During the quarter, NuVista issued $220 million of 6.5% five year senior unsecured notes due March 2, 2023.  The net proceeds were used in part to redeem the Company’s pre-existing 9.875% senior unsecured notes in the amount of $70 million and the excess proceeds were used for a non-permanent repayment of indebtedness under NuVista’s existing credit facility;
  • Subsequent to the first quarter of 2018, NuVista successfully concluded the annual review of our borrowing base with our lenders with no change to the $310 million credit capacity, and;
  • Continued to prudently and selectively add to our hedge positions for 2018 and beyond.  We currently possess hedges which in aggregate cover approximately 70% of 2018 projected liquids production with a price floor of C$70.41/Bbl, and approximately 70% of 2018 projected gas production at a price of C$2.62/Mcf.  Both of these percentage figures relate to production net of royalty volumes.  Early in the second quarter, NuVista added approximately 40 MMcf/d of physical natural gas delivery to the US Pacific NW/Northern California markets with the completion of the NGTL Sundre Crossover Pipeline Project.  This was also our first full quarter utilizing the long term fixed priced (LTFP) contract volumes of 45 MMcf/d on the TCPL pipeline to the Dawn hub.  NuVista has also continued to add long term NYMEX basis hedges for terms out as far as 2024.  Combined with our natural gas pipeline export contracts and NYMEX natural gas basis hedges, NuVista has essentially no exposure to AECO natural gas pricing through the full year of 2018 and a maximum AECO natural gas volume exposure range of approximately 15-25% throughout our 60,000 Boe/d growth plan.

Bilbo, Elmworth, and Gold Creek Update

Drilling at Bilbo during the quarter continued as planned with one to two rigs operating and wells being brought on stream to maintain production at or near 18,000 Boe/d.  Pad sizes for new wells currently range from two to five wells per pad.  Four new wells were brought onstream during the quarter, with average IP30’s of 1,972 Boe/d including 46% condensate, or 124 Bbls condensate per MMcf of raw gas. NuVista’s first Lower Montney well which started up at the end of 2017 continues to perform favorably.  This quarter the well reached an IP90 condensate rate of 540 Bbls/d, an excellent outcome as compared to the average of all prior NuVista Middle Montney Bilbo wells at 550 Bbls/day condensate.  The Bilbo compressor station is performing well, with indications of peak-day production capability as high as 20,000 Boe/d as compared to original nameplate capacity of 18,000 Boe/d. 

One rig was deployed at Elmworth during the quarter, currently drilling a four-well pad.  Production averaged 14,200 Boe/d for the quarter and is now being restricted to make room for the new Gold Creek wells which have come on stream.

At Gold Creek, volumes have now reached over 5,000 Boe/d.  One to two rigs were active, drilling a delineation/expiry well in the North and a record length two-well pad in the South.  Building upon the operational success from the last extended reach horizontal (ERH) pad at Gold Creek, the horizontal lengths achieved on these wells were 4,500 and 5,000 metres respectively.  The 5,000 metre well is the longest horizontal lateral well ever drilled in Canada. The wells were completed with high intensity fractures (HIFI), placing approximately 2 tonnes of sand per metre of horizontal length, a total of 88 fracture intervals in each well. The average drill and complete cost for each of these two wells was $14.5MM, or $164,000 per stage which is lower than our budgeted average for 2018.

Production from Elmworth is being restricted in order to make room for these new wells which have been brought onstream for initial cleanup flow. We are very pleased to note that the first well has averaged 2,962 Boe/d including 1,056 Bbls/d condensate (condensate gas ratio of 87 Bbls/MMcf) over the first 24 days. The test is particularly encouraging in that gas rates and flowing pressures have been stable to increasing as the high rate of frac water flowback subsides. The upcoming IP90 and IP180 results for these wells will be better indicators of how the first-year capital efficiencies for these ERH wells compare with the historic average.

The Elmworth compressor stations are performing well, handling the production from both Elmworth and Gold Creek wells at the present time.  Drilling continues in Elmworth to keep area production pushing up to and beyond nameplate levels, with 18,000+ Boe/d already achieved versus nameplate capacity of 19,000 Boe/d.  Drilling in Gold Creek will resume later this year in advance of the startup of the new SemCAMS Wapiti gas plant in early-mid 2019.  When the SemCams gas plant starts up, Gold Creek new and existing volumes will be directed there which will provide significant space for continued growth in both Elmworth and Gold Creek. 

Year End 2017 Contingent Resource Study Completed

NuVista is pleased to announce that an updated contingent resources report for 2017 year end has been completed by GLJ Petroleum Consultants Ltd (“GLJ”) (the “GLJ Report”), our independent qualified reserves evaluator.  Estimated total gross drilling locations on NuVista’s land base now total 947, including 107 developed locations, 272  proved undeveloped (“PUD”) plus probable undeveloped (“PAUD”) locations and 568 Best Estimate Contingent locations.  Highlights for 2017 are the inclusion of the Lower Montney zone where 150 locations are now booked (1 developed location,  4 PUD+PAUD locations, and  145 Best Estimate Contingent locations) and delineation into Pipestone where 57 Middle Montney zone wells are booked (1 developed location,  36 PUD+PAUD locations, 20 Contingent locations).  Across the three layers of NuVista’s 122,900 acres of land, an average of only 60% of our land has been assigned Reserves or Contingent Resources.  Also of note is that just 30% of our 122,900 gross acres have been assigned Reserves or Contingent Resources in the Lower Montney so far.  New wells are now on average approximately 30% longer than in recent years, therefore the wellcount required for equivalent resource coverage is reduced commensurately.  With 947 gross wells in our Reserves and Contingent Resource, and a drilling pace of 25 to 30 wells per year at our current rate of growth, we have the benefit of long line of sight and ample choice of location to optimize economics as the price of condensate and natural gas varies in future years.

2018 Guidance

Guidance for 2018 remains as previously announced with capital spending anticipated in the range of $270 - $310 million and 2018 production expected in the range of 35,000 – 40,000 Boe/d.  Production for the second quarter of 2018 is anticipated to be in the range of 34,000 – 36,000 Boe/d which includes downtime of approximately 2,000 – 3,000 Boe/d during the quarter for planned outages for routine maintenance at midstreamer facilities and also our NuVista Elmworth compressor station.

Full year 2018 adjusted funds flow is anticipated to be in the range of $210 - $240 million after taking into account the non-recurring cost of refinancing the senior unsecured notes in the first quarter of 2018.  This is based on our 2018 forecast production and strip commodity prices of US$2.78/MMBtu NYMEX natural gas and US$64.00/Bbl WTI oil for the remainder of 2018.  The resulting 2018 net debt to adjusted funds flow ratio is expected to be approximately 1.0 to 1.3 times.

NuVista has top quality assets and every team member is focused upon relentless improvement.  We are excited to continue pursuing our growth plan to 60,000 Boe/d. We would like to thank our staff, contractors, and suppliers for their continued dedication and delivery, and we thank our board of directors and our shareholders for their continued guidance and support.  Please note that our corporate presentation is being updated and will be available at www.nuvistaenergy.com on or before May 9, 2018.  NuVista’s financial statements, notes to the financial statements and management’s discussion and analysis for the first quarter of 2018, will be filed on SEDAR (www.sedar.com) under NuVista Energy Ltd. on or before May 9, 2018 and can also be accessed on NuVista’s website.

Corporate Highlights      
  Three months ended March 31
($ thousands, except per share and per $/Boe) 2018   2017   % Change
FINANCIAL      
Petroleum and natural gas revenues 124,756   84,236   48  
Adjusted funds flow (1) 58,732   43,254   36  
Per share - basic 0.34   0.25   36  
Per share - diluted 0.34   0.25   36  
Net earnings 22,371   38,317   (42 )
Per share - basic 0.13   0.22   (41 )
Per share - diluted 0.13   0.22   (41 )
Total assets 1,281,475   1,054,272   22  
Capital expenditures 115,220   107,412   7  
CAPITAL STRUCTURE      
Adjusted working capital deficit (1) 43,410   28,116   54  
Long-term debt (credit facility)   60,979   (100 )
Senior unsecured notes 215,207   67,257   220  
Total net debt (1) 258,617   156,352   65  
Long-term debt (credit facility) capacity 310,000   200,000   55  
End of period common shares o/s - basic 174,184   172,774   1  
OPERATING      
Daily Production      
Natural gas (MMcf/d) 132.7   99.7   33  
Condensate (Bbls/d) 11,313   8,354   35  
NGLs (Bbls/d) (2) 2,667   1,758   52  
Total (Boe/d) 36,099   26,731   35  
Condensate & NGLs weighting 39 % 38 %  
Condensate weighting 31 % 31 %  
Average selling prices (3) (4)      
Natural gas ($/Mcf) 3.50   3.74   (6 )
Condensate ($/Bbl) 73.69   63.46   16  
NGLs ($/Bbl) 33.31   18.82   77  
Netbacks ($/Boe)      
Petroleum and natural gas revenues 38.40   35.02   10  
Realized gain (loss) on financial derivatives (1.63 ) 0.01    
Royalties (0.56 ) (1.13 ) (50 )
Transportation expenses (2.91 ) (2.51 ) 16  
Operating expenses (10.02 ) (10.72 ) (7 )
Operating netback (1) 23.28   20.67   13  
Adjusted funds flow netback (1) 18.09   17.98   1  
SHARE TRADING STATISTICS      
High 9.16   6.39   43  
Low 6.78   5.33   27  
Close 7.06   6.15   15  
Average daily volume 516,466   399,827   29  

 

            (1)   See "Non-GAAP measurements".
  (2)   Natural gas liquids ("NGLs") include butane, propane and ethane.
  (3)   Product prices exclude realized gains/losses on financial derivatives.
  (4)   The average condensate and NGLs selling price is net of pipeline tariffs and fractionation fees.

Basis of presentation
Unless otherwise noted, the financial data presented in this news release has been prepared in accordance with Canadian generally accepted accounting principles (“GAAP”) also known as International Financial Reporting Standards (“IFRS”). The reporting and measurement currency is the Canadian dollar.

 


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Capital & Finance
        Well Economics
        Rates of Return/ IRR
        Capital Expenditures
        Hedging
        Valuations/PV
        Well Economics - Payout
Data & Charts
        Bar Chart
        Peer Comparison
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        Portfolio Map
Midstream
        Pipelines & Facilities
Portfolio & Operations
        Proved Reserves
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        Drilling Cost
        Completion Cost
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        Drilling - Wells Drilled
        Corporate Production Rates
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Well Information
        Well Cost
        Frac Design - Frac Stages
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