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NuVista Energy Ltd. Announces Year End 2017 Reserves, Financial And Operating Results


CALGARY, Alberta, March 12, 2018 (GLOBE NEWSWIRE) — NuVista Energy Ltd. (“NuVista” or the “Company”) (TSX:NVA) is pleased to announce results for the three months and year ended December 31, 2017 and provide an update on our future business plans.

For NuVista, 2017 was a very active and successful year with significantly increased adjusted funds flow, record production, and material reserves per share growth.  These milestones were reached while advancing significantly on our 60,000 Boe/d five year growth plan.  In 2017, NuVista was able to make meaningful continued improvement in well results through the application of new technologies including higher intensity fracture stimulation (HiFi) and extended reach horizontal wells (ERH) while reducing the total capital cost per stage and per metre completed.  The Company’s balance sheet is strong and the strategic diversification of our gas markets outside of Alberta continued to be advanced materially to protect future cash flows.

NuVista has a material position in the Wapiti Montney play, which with prudent management has delivered solid financial returns to shareholders over the past several years and remains resilient to low natural gas prices.  Our Wapiti position continues to improve with advanced drilling and completion technology.  Our strategy is to maintain a strong balance sheet to allow the flexibility to accelerate spending when returns are strong.  When there is near term commodity price volatility, we can choose to moderate our pace to spend the minimum required while adhering to our long term growth objectives.  We also ensure strong alignment of every employee with our shareholders through our compensation structure which is linked to key financial metrics and shareholder returns.

Strong Fourth Quarter and Full Year 2017 Results

During the quarter and year ended December 31, 2017, NuVista:

  • Produced a record 37,400 Boe/d for the fourth quarter of 2017, near the top of the guidance range of 35,000 – 38,000 Boe/d and 51% greater than the respective quarter in 2016.  Full year 2017 production was approximately 29,800 Boe/d versus full year guidance of 28,000 – 31,000 Boe/d.  This represents production which was 21% greater than the prior year figure;
  • Achieved condensate & oil weighting which was higher than historical levels due to favorable well results, averaging 35% for the fourth quarter and 33% for the full year of 2017;
  • Achieved adjusted funds flow of $75.9 million for the quarter ($0.44/share, basic) due to increased production, improved condensate & oil weighting, and improved realized product pricing.  This represents an increase of 85% versus the prior quarter and also versus the fourth quarter of 2016.  Full year 2017 adjusted funds flow was $200 million ($1.15/share, basic) versus the originally guided range of $160 – $180 million, an increase of 45% versus the prior year adjusted funds flow;
  • Achieved adjusted funds flow netbacks of $18.40/Boe and $22.06/Boe for the full year and fourth quarter of 2017, respectively.  This represents an increase of 20% and 23% respectively, versus the corresponding periods of 2016;
  • Executed a successful capital expenditure program for the fourth quarter of $40 million, spending significantly less than adjusted funds flow.  Full year 2017 capital expenditures were $315 million including facilities expenditures and the drilling of 30 (30 net) wells in our condensate rich Wapiti Montney play.  This capital was slightly higher than guidance of up to $310 million primarily due to earlier phasing of the 2018 winter drilling program which commenced in December of 2017;
  • Successfully drilled our first Lower Montney horizontal well at Bilbo in the fourth quarter with very encouraging results. The well has now been on production for well over one month and the initial IP30 production averaged over 3.6 MMcf/d raw gas and 665 Bbls/d of condensate, while flowing at a restricted rate. This represents a condensate gas ratio of 182 Bbls/MMcf.  The well was drilled to 2,950m horizontal length and completed at regular fracture intensity (1 tonne of proppant per meter of horizontal length). This Lower Montney well result is a very positive step for the continued derisking of this emerging layer of the Montney formation in our area;
  • Realized total annual operating costs of $10.25/Boe, a reduction of 3% versus 2016 operating costs, and;
  • Achieved annual net G&A costs of $1.60/Boe, continuing our long term trend of improvement with a reduction of 13% compared to 2016 G&A costs.

Significant Reserves Highlights for 2017

As previously announced, we have had another significant increase in our reserves value as a result of the 2017 year end independent evaluation of our reserves by GLJ Petroleum Consultants Ltd (“GLJ”) (the “GLJ Report”) which was effective December 31, 2017.  2017 saw significant increases to both Proved Developed Producing (“PDP”) and Total Proved plus Probable (“TP+PA”) reserves. Although GLJ’s assumptions for future commodity prices are lower than year end 2016, the combination of our continued shift to a higher condensate proportion coupled with our access to alternative gas markets outside of Alberta has helped to maintain continued improvement in the reserves value per barrel, leading to material increases to the overall net present value of our reserves. In addition to the growth, a number of strategic accomplishments were delivered including a significant increase to Pipestone reserves, the first booking of undeveloped ERH locations at Gold Creek, and NuVista’s first ever bookings in the Lower Montney zone, at Bilbo. Significant highlights of the evaluation include:

  • Increased PDP reserves 43% from 37.9 to 54.1 MMBoe.  This represents the largest percentage increase in PDP reserves since we began the transition into the Montney.  TP+PA reserves increased 35% from 257 to 347 MMBoe;
  • Increased the respective net present values before tax discounted at 10% (“NPVBT10”) of our PDP and TP+PA reserves materially year over year from $388 million and $1,165 million to $530 million and $1,782 million.  This represented increases of 36% and 53% for the PDP and TP+PA NPVBT10 values, respectively, despite a reduction in the GLJ forecast pricing assumptions as compared to the prior year, particularly for natural gas;
  • Increased Pipestone undeveloped gross drilling location count from 8 to 36. This core area now represents approximately 15% and over 20% of the Company’s TP+PA reserves and NPVBT10, respectively;
  • Booked one PDP and four gross undeveloped drilling locations in the Lower Montney for total TP+PA reserves of 4.2 MMBoe.  This further strengthens our confidence in the future development potential of this emerging horizon and corroborates our belief that the zone is indeed condensate rich in nature;
  • Achieved continued low PDP and TP+PA finding and development (“F&D”) costs in 2017 of $11.35/Boe and $6.95/Boe, respectively. The PDP and TP+PA recycle ratios based on fourth quarter 2017 adjusted funds flow netback were 1.9x and 3.2x, respectively. Based on full year 2017 adjusted funds flow netback the PDP and TP+PA recycle ratios were 1.6x and 2.6x, respectively;
  • Increased TP+PA Future Development Capital (“FDC”) versus 2016, from $1.6 billion to $2.0 billion as a result of the undeveloped reserve adds at Pipestone, Gold Creek, and the Lower Montney. This is accompanied by a continued decrease in the ratio of FDC to adjusted funds flow to 10.0x from 12.9x at year end 2015 and 11.8x at year end 2016;
  • NuVista’s forecast future realized gas prices are impacted less than GLJ’s decrease in AECO gas forecast as NuVista’s firm gas sales market diversification agreements have been reflected in the GLJ Report, and;
  • Achieved positive PDP and TP+PA technical revisions of 7% and 6%, respectively, primarily based on production performance.

NuVista is pleased to note that our TP+PA reserve base has grown consistently over the past 5 years at a compounded annual growth rate of 64% to 347 MMBoe at year end 2017, illustrating the continued advancement of the inventory to underpin our growth strategy to 60,000 Boe/d and beyond. As the proportion of reserves attributed to the Montney has increased, so has the weighting to condensate which now forms 27% of the Company’s PDP reserves, up from 19% in 2015 and 25% last year.  The detailed summary of our year end 2017 reserves disclosure was included in our press release dated February 12, 2018 and can be accessed on SEDAR.

Credit Facility, Senior Notes, and Hedging

  • Exited 2017 with 41% drawn on the Company’s $310 million credit facility. Net debt, including senior unsecured notes and working capital deficiency, was $196 million and net debt to annualized fourth quarter adjusted funds flow was 0.6 times;
  • Subsequent to 2017, NuVista issued $220 million aggregate principal amount of 6.5% five year senior unsecured notes due March 2, 2023.  The net proceeds were used to redeem the Company’s pre-existing 9.875% senior unsecured notes in the aggregate principal amount of $70 million, and the excess proceeds were used for a non-permanent repayment of indebtedness under NuVista’s existing credit facility.  The credit facility will then be redrawn as needed for general corporate purposes, primarily the ongoing development of our Wapiti Montney condensate rich assets.  This private placement is commensurate with the significant increase in value of NuVista’s reserves and production, and;
  • Continued to prudently and selectively add to our hedge positions for 2018 and 2019.  We currently possess hedges which in aggregate cover 64% of 2018 projected liquids production with a price floor of C$69.91/Bbl, and 66% of 2018 projected gas production at a price of C$2.70/Mcf.  Both of these percentage figures relate to production net of royalty volumes. NuVista has also continued to add long term AECO-Nymex basis hedges for terms out to the end of 2024.   Combined with our AECO-NYMEX basis hedges and pipeline export contracts, NuVista has essentially no exposure to AECO pricing through the full year of 2018 and a maximum AECO exposure range of approximately 15-25% throughout our 60,000 Boe/d growth plan at attractive pricing.

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 first quarter of 2018 is anticipated to be in the range of 34,500 – 36,000 Boe/d.  Full year adjusted funds flow is anticipated to be in the range of $200 – $230 million after adjusting for 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 assumed commodity prices of US$3.00/MMBtu NYMEX and US$55/Bbl WTI.  The resulting 2018 net debt to adjusted funds flow ratio is expected to be approximately 1.3 times.  In estimating the figures above we have assumed that our production and condensate ratio moderate slightly as compared to the fourth quarter of 2017, after flush production subsides somewhat from new wells brought onstream in that quarter.

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 March 12, 2018.  NuVista’s financial statements, notes to the financial statements and management’s discussion and analysis for the year ended December 31, 2017, will be filed on SEDAR (www.sedar.com) under NuVista Energy Ltd. on Monday, March 12, 2018 and can also be accessed on NuVista’s website.

Corporate Highlights
Three months ended December 31 Year ended December 31
($ thousands, except per share and per $/Boe) 2017 2016 % Change 2017 2016 % Change
FINANCIAL
Petroleum and natural gas revenues $ 131,009   $ 74,538 76 $ 377,746 $ 257,252 47
Adjusted funds flow (1) 75,932 40,697 87 200,030 137,841 45
Per share – basic 0.44 0.24 83 1.15 0.87 32
Per share – diluted 0.43 0.24 79 1.15 0.87 32
Net earnings (loss) 34,651 1,135 94,368 (1,653 )
Per share – basic 0.20 0.01 0.54 (0.01 )
Per share – diluted 0.20 0.01 0.54 (0.01 )
Total assets 1,186,419 961,240 23
Capital expenditures 40,099 55,785 (28 ) 315,302 189,061 67
Proceeds on property dispositions 2,082 (100 ) 2,241 75,983 (97 )
CAPITAL STRUCTURE
Adjusted working capital deficit (1) 2,784 15,536 (82 )
Long-term debt (credit facility) 125,725
Senior unsecured notes 67,680 67,156 1
Total net debt (1) 196,189 82,692 137
Long-term debt (credit facility) capacity 310,000 200,000 55
End of period common shares o/s – basic 174,004 172,746 1
OPERATING
Daily Production
Natural gas (MMcf/d) 131.7 96.3 37 108.2 97.0 12
Condensate & oil (Bbls/d) 13,087 7,258 80 9,860 6,892 43
NGLs (Bbls/d) (2) 2,397 1,402 71 1,893 1,575 20
Total (Boe/d) 37,435 24,716 51 29,783 24,638 21
Condensate, oil & NGLs weighting 41% 35% 39% 34%
Condensate & oil weighting 35% 29% 33% 28%
Average selling prices (3) (4)
Natural gas ($/Mcf) 3.44 3.74 (8 ) 3.58 3.54 1
Condensate & oil ($/Bbl) 68.36 58.21 17 61.01 49.81 22
NGLs ($/Bbl) 32.09 19.35 66 24.42 10.43 134
Netbacks ($/Boe)
Petroleum and natural gas revenues 38.04 32.78 16 34.75 28.53 22
Realized gain on financial derivatives 0.16 1.02 (84 ) 0.47 2.92 (84 )
Royalties (1.38 ) (0.42 ) 229 (1.12 ) (0.21 ) 433
Transportation expenses (2.57 ) (2.14 ) 20 (2.66 ) (2.34 ) 14
Operating expenses (9.65 ) (10.44 ) (8 ) (10.25 ) (10.52 ) (3 )
Operating netback (1) 24.60 20.80 18 21.19 18.38 15
Adjusted funds flow netback (1) 22.06 17.90 23 18.40 15.28 20
SHARE TRADING STATISTICS
High 8.87 7.80 14 8.87 7.80 14
Low 6.83 6.28 9 5.33 2.72 96
Close 8.02 6.94 16 8.02 6.94 16
Average daily volume 475,615 693,415 (31 ) 462,688 549,049 (16 )

(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 NGLs selling price is net of tariffs and fractionation fees.

 



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