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NuVista Energy Ltd. Announces Record Increase to Reserves, Provides Positive Year End 2018 Financial and Operating Results, Re-Affirms Strong 2019 Production Growth


CALGARY, Alberta, March 05, 2019 (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, 2018 and provide an update on our future business plans.

Record 2018 Results, Strong 2019 Growth

During the quarter and year ended December 31, 2018, NuVista:

  • Produced a record 49,060 Boe/d for the fourth quarter of 2018, above the top of the guidance range of 46,000 – 48,500 Boe/d and 31% greater than the respective quarter in 2017.  Full year 2018 production was a record 40,350 Boe/d versus full year guidance of 38,750 – 40,000 Boe/d.  This represents annual production which was 35% greater than the prior year, or an increase of 23% in production per share;
  • Achieved record 2018 adjusted funds flow of $264 million ($1.39/share, basic), in the middle of the originally guided range of $260 – $270 million, an increase of 32% absolute and an increase of 21% in adjusted funds flow per share versus the prior year.  The increases were due primarily to increased production and commodity pricing, partially offset by losses on financial derivative contracts;
  • Achieved adjusted funds flow netbacks of $17.96/Boe for 2018, a similar result to the $18.40/Boe for the prior year;
  • Executed a successful 2018 capital expenditure program of $341 million including facilities expenditures and the drilling of 26 (25.5 net) wells in our condensate rich Wapiti Montney play.  This level of capital compared well to our previous guidance range of $325 – $350 million;
  • Realized total annual operating expenses of $9.75/Boe, a reduction of 5% versus 2017;
  • Achieved annual net G&A expenses of $1.19/Boe, continuing our long term trend of improvement with a reduction of 26% compared to 2017 G&A per Boe expenses; and
  • Has set a 2019 capital and production budget resulting in forecast annual production per share growth of approximately 13% and fourth quarter 2019 production per share growth of almost 25% as compared to the fourth quarter of 2018.

Significant Low Cost Reserves Growth in 2018

NuVista is pleased to report its 2018 year end independent evaluation of our reserves by GLJ Petroleum Consultants Ltd (“GLJ”) (the “GLJ Report”).  NuVista continued its track record of delivering high-quality reserve results, including a record increase in both our Proved Developed Producing (“PDP”) and Total Proved plus Probable (“TP+PA”) reserves at favorable cost.  The following results illustrate our high-quality Montney resource base and the continued advancement of the inventory to underpin our profitable growth to our 110,000 Boe/d target and beyond:

  • Delivered a record increase in PDP and TP+PA reserves of 55% each to 84 MMBoe and 538 MMBoe, respectively, as compared to the prior year. This growth was driven by NuVista drilling activity, positive technical revisions due to well performance and recovery assumptions, and reserves acquired in the acquisition of the Pipestone North assets (the “Pipestone Acquisition”).  This represents an increase of 20% per share as compared to the prior year;
  • Increased the respective value net present value before tax, discounted at 10% (“NPVBT10”) of our PDP and TP+PA reserves materially year over year from $530 million and $1,782 million to a record high of $879 million and $3,430 million. This growth includes the reserves acquired in the Pipestone Acquisition, and it represents 28% and 49% growth on a per share basis, respectively;
  • Increased TP+PA undeveloped locations by 35% to 367. This reflects 9 years of booked inventory at the planned development pace.  Best estimate contingent resource locations increased by 40% to 798;
  • Achieved robust recycle ratios of 1.4x and 3.3x for PDP and TP+PA reserves respectively, based on our 2018 operating netback of $21.23/Boe.  These were driven by PDP and TP+PA finding and development (“F&D”) costs of $14.90/Boe and $6.43/Boe, respectively.  The three-year average PDP F&D cost was $12.40/Boe and the TP+PA finding, development, and acquisition (“FD&A”) cost was $8.22/Boe;
  • Achieved a reserves replacement ratio of 300% and 1,400% on a PDP and TP+PA basis, respectively, resulting in a TP+PA reserves life index (“RLI”) of over 30 years, and;
  • Booked reserves and undeveloped locations in portions of each of the four developable Montney horizons in Pipestone, which is a positive leading indicator ahead of the results from our first four-layer cube at Pipestone later in 2019.

The detailed summary of our year end 2018 reserves disclosure is included further below, and will be included in our Annual Information Form which will be filed on or before March 29, 2019 at www.SEDAR.com.

A Strong Year in Review

The year 2018 was very active and successful for NuVista with record adjusted funds flow, record production, and material reserves per share growth.  These milestones were reached while advancing significantly on our long term growth plan of 110,000 Boe/d and beyond.  Our 2019 outlook provides for strong production per share growth while spending sustainably within adjusted funds flow in the current commodity price environment.  We have continued to drive capital and operating costs downwards.  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 flow from operating activities.  NuVista completed the strategic Pipestone Acquisition in September of 2018, which included 9,600 Boe/d of production plus many years of future drilling locations, providing long term line of sight for continued high condensate production growth adjacent to our pre-existing Pipestone South property.

NuVista has a material position in the condensate rich greater 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 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 weakness, 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.

Excellence in Operations Continues

We have spud another four-well pad in the northeast area of Bilbo as part of an additional 7 wells to be drilled in Bilbo in 2019.  These will contribute to fourth quarter 2019 and 2020 production.  At Elmworth, we have concluded the drilling of a three and a two well pad.  Both pads will be fractured with higher intensity fracture stimulation (“HiFi”) and brought on stream in the second quarter, and should keep the Elmworth infrastructure at or near capacity until 2020.  At Gold Creek we are commencing the drilling of the next four well pad.  The SemCAMS Wapiti plant construction has concluded on budget and has successfully started up early in the first quarter of 2019, several months ahead of schedule.  As planned, our Gold Creek production has now been switched out of our Elmworth compressor station into the new SemCAMS Wapiti plant.

Our newly acquired Pipestone North property continues to outperform expectations with production ranging from 9,500 to 10,000 Boe/d without decline, as we continue to bring on legacy Montney wells which had been shut in temporarily in mid-2018 by the previous operator to make facility space available for the most recent well pad.  We have reached two exciting milestones as we have spud our first pad in Pipestone South, and we have commenced construction of our Pipestone South compressor station.  The pad will be the largest drilled by NuVista to date, with eight wells spanning all four of the Montney zones from the Lower Montney up to the Middle Montney B, C, and D zones.  The compressor facility construction is proceeding on schedule and on budget with startup expected in the fourth quarter of 2019.

Keeping The Balance Sheet Strong

NuVista exited 2018 with approximately 57% drawn on the Company’s $450 million credit facility. Net debt, including senior unsecured notes and working capital deficiency, was $511 million and net debt to 2018 adjusted funds flow was 1.9 times.  The senior unsecured notes were included in net debt and were issued in 2018, with an aggregate principal of $220 million and a five year term at a 6.5% coupon.  This provides financial flexibility and certainty with a competitive fixed coupon and 5 year term.

Significant Commodity Price Diversification and Risk Management

After a year of strong oil prices, the fourth quarter of 2018 saw significant WTI price volatility as well as a widening differential for heavy oil, light oil, and condensate.  Condensate is an imported product and therefore is not reliant upon export pipelines to get to market.  As a result, condensate was not adversely affected to the same degree as oil.  Although the condensate differential suffered the least of the three products, it was temporarily impacted, averaging a discount from the WTI price of US$13.53/Bbl for the quarter as opposed to the typical average of +/- $3 to $5/Bbl premium or discount to WTI.  With the Alberta Government oil production curtailments, we have seen an immediate improvement in all liquids differentials.  Crude by rail is anticipated to increase and the Enbridge Line 3 pipeline replacement project is anticipated to be in-service by mid-2020 which should provide continued relief for oil differentials.  Since condensate is imported and required by the Alberta oil sands suppliers for diluent purposes, no curtailments to condensate production were mandated.  While some volatility may persist, the condensate differential to WTI has now recovered to nearly normal levels, currently averaging US$2.00 to US$3.00/Bbl discount.

Western Canada experienced relatively warm weather during the fourth quarter, which impacted local gas demand and AECO gas prices which averaged C$1.80/GJ during the period.  Export markets fared much better with cold weather in Eastern Canada and the US Midwest driving strong export prices and strong NYMEX which averaged US$3.64/MMbtu for the quarter.  Due to our significant market diversification, NuVista had minimal exposure to AECO spot prices in the fourth quarter, as evidenced in our average realized selling price of $3.69/Mcf.  Cold weather descended upon Western Canada in the first quarter of 2019, causing AECO prices to increase significantly.

NuVista continues to benefit from the discipline of our strong rolling hedge program during this period of volatile commodity prices.  We currently possess hedges which, in aggregate, cover 61% of projected 2019 liquids production at a WTI floor price of C$79.58/Bbl, and 52% of projected 2019 gas production at a price of C$ 2.02/GJ (hedged and exported volumes converted to an AECO equivalent price).  These percentage figures relate to production net of royalty volumes.  Due to our fixed price hedges, basis differential hedges, and our export pipeline volumes, NuVista is in the enviable position of having only 18% of our projected natural gas volumes exposed to spot AECO prices in 2019, representing a very small proportion of adjusted funds flow.

2019 Guidance Re-Affirmed – Strong Growth And Spending Within Adjusted Funds Flow

We are pleased to note that our 2019 capital and production budget forecasts annual production per share growth of approximately 13% and fourth quarter 2019 production per share growth of almost 25% as compared to the fourth quarter of 2018.  Our production guidance for 2019 is unchanged, with a range of 51,000 to 54,000 Boe/d.  First quarter 2019 production guidance is also unchanged with a range of 43,000 to 46,000 Boe/d.  The remaining quarters of 2019 are all expected to be well above 50,000 Boe/d, and more specific quarterly guidance will be provided as the year unfolds.

We intend to keep net debt levels relatively flat, with capital spending at or near adjusted funds flow at 2019 price expectations of approximately US$55.00/Bbl WTI oil, US$2.85/MMBtu NYMEX natural gas, C$1.30/GJ AECO natural gas, condensate-WTI differential of US$ -1.00/Bbl, and CAD/USD exchange rate of 1.33.  As such, we have set our capital spending for 2019 to a planned range of $300 – $325 million, with flexibility to reduce capital further if pricing unexpectedly falls, while still preserving a healthy growth plan for 2020 if prices remain stable or improve.

NuVista has top quality assets and a management team focused upon relentless improvement.  We are excited to continue pursuing our Montney growth plan to 110,000 Boe/d and beyond, and we will adjust the annual pace of growth as needed to ensure balance sheet strength comes first, and that the profitability of that growth is always maximized. 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 6, 2019.  NuVista’s financial statements, notes to the financial statements and management’s discussion and analysis for the year ended December 31, 2018, will be filed on SEDAR (www.sedar.com) under NuVista Energy Ltd. on March 5, 2019 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 $/Boe) 2018 2017 % Change 2018 2017 % Change
FINANCIAL
Petroleum and natural gas revenues 143,006 131,009 9 555,849 377,746 47
Adjusted funds flow (1) (2) 63,635 75,932 (16 ) 264,448 200,030 32
Per share – basic 0.28 0.44 (36 ) 1.39 1.15 21
Per share – diluted 0.28 0.43 (35 ) 1.38 1.15 20
Net earnings 104,086 34,651 200 136,245 94,368 44
Per share – basic 0.46 0.20 130 0.71 0.54 31
Per share – diluted 0.46 0.20 130 0.71 0.54 31
Total assets 2,180,874 1,186,419 84
Assets acquired 1,679 619,444
Capital expenditures (2) 77,433 40,099 93 340,792 315,302 8
Net debt (1) (2) 511,408 197,936 158
End of period basic common shares o/s 225,306 174,004 29
OPERATING
Daily Production
Natural gas (MMcf/d) 174.3 131.7 32 144.7 108.2 34
Condensate & oil (Bbls/d) 14,766 13,087 13 12,674 9,860 29
NGLs (Bbls/d) (3) 5,246 2,397 119 3,554 1,893 88
Total (Boe/d) 49,060 37,435 31 40,353 29,783 35
Condensate, oil & NGLs weighting 41 % 41 % 40 % 39 %
Condensate & oil weighting 30 % 35 % 31 % 33 %
Average selling prices (4) (5)
Natural gas ($/Mcf) 3.69 3.41 8 3.51 3.55 (1 )
Condensate & oil ($/Bbl) 51.60 68.36 (25 ) 70.92 61.01 16
NGLs ($/Bbl) 28.53 33.17 (14 ) 32.83 25.81 27
Netbacks ($/Boe)
Petroleum and natural gas revenues 31.69 38.04 (17 ) 37.74 34.75 9
Realized gain (loss) on financial derivatives (2.37 ) 0.16 (2.60 ) 0.47
Royalties (1.07 ) (1.38 ) (22 ) (1.10 ) (1.12 ) (2 )
Transportation expenses (2.93 ) (2.57 ) 14 (3.06 ) (2.66 ) 15
Operating expenses (9.06 ) (9.65 ) (6 ) (9.75 ) (10.25 ) (5 )
Operating netback (2) 16.26 24.60 (34 ) 21.23 21.19
Corporate netback (2) 14.11 22.06 (36 ) 17.96 18.40 (2 )
SHARE TRADING STATISTICS
High 7.75 8.87 (13 ) 9.89 8.87 11
Low 3.38 6.83 (51 ) 3.38 5.33 (37 )
Close 4.08 8.02 (49 ) 4.08 8.02 (49 )
Average daily volume 1,153,619 475,615 143 719,389 462,688 55

(1)  Refer to Note 16 “Capital Management” in NuVista’s financial statements and to the sections entitled “Adjusted funds flow” and “Liquidity and capital resources” contained in NuVista’s MD&A for the year ended December 31, 2018.
(2)  Non-GAAP measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other companies where similar terminology is used.  Reference should be made to the section entitled “Non-GAAP measurements” contained in NuVista’s MD&A for the year ended December 31, 2018.
(3)  Natural gas liquids (“NGLs”) include butane, propane and ethane.
(4)  Product prices exclude realized gains/losses on financial derivatives.
(5)  The average condensate and NGLs selling price is net of pipeline tariffs and fractionation fees.

Detailed Summary of Corporate Reserves Data

The following table provides summary reserve information based upon the GLJ Report using the published GLJ January 1, 2019 price forecast:

Natural Gas(2) Natural Gas
Liquids
Oil(3) Total
Reserves category(1) Company
Gross
Interest
(MMcf)
Company
Gross
Interest
(MBbls)
Company
Gross
Interest
(MBbls)
Company
Gross
Interest
(MBoe)
Proved
Developed producing 319,934 29,775 894 83,992
Developed non‑producing 37,530 3,206 29 9,490
Undeveloped 916,870 77,384 903 231,098
Total proved 1,274,334 110,365 1,826 324,580
Probable 856,213 69,847 598 213,148
Total proved plus probable 2,130,548 180,213 2,425 537,728

NOTES:
(1)  Numbers may not add due to rounding.
(2)  Includes conventional natural gas and shale gas and coal bed methane.
(3)  Includes light and medium crude oil.

The following table is a summary reconciliation of the 2018 year end working interest reserves with the working interest reserves reported in the 2017 year end reserves report:

Natural Gas(1)(3)
(MMcf)
Liquids(1)
(MBbls)
Oil(1)(4)
(MBbls)
Total Oil
Equivalent(1)
(MBoe)
Total proved
Balance, December 31, 2017 679,193 57,458 25 170,682
Exploration and development(2) 231,236 22,182 903 61,624
Technical revisions 45,915 5,017   6 12,675
Acquisitions 370,943 31,749 940 94,513
Dispositions
Economic Factors (118 ) (166 )   1 (185 )
Production (52,834 ) (5,875 ) (48 ) (14,729 )
Balance, December 31, 2018 1,274,334 110,365 1,826 324,580
Total proved plus probable
Balance, December 31, 2017 1,375,188 117,454 34 346,685
Exploration and development(2) 172,914 13,253 1,198 43,270
Technical revisions 58,265 5,278   7 14,996
Acquisitions 577,105 50,118 1,234 147,536
Dispositions
Economic Factors (90 ) (15 ) (30 )
Production (52,834 ) (5,875 ) (48 ) (14,729 )
Balance, December 31, 2018 2,130,548 180,213 2,425 537,728

NOTES:
(1)  Numbers may not add due to rounding.
(2)  Reserve additions for drilling extensions, infill drilling and improved recovery.
(3)  Includes conventional natural gas, shale gas and coal bed methane.
(4)  Includes light, medium crude oil.

The following table summarizes the future development capital included in the GLJ Report:

($ thousands, undiscounted) Proved Proved plus
probable
2019 400,712 463,112
2020 533,077 533,077
2021 406,761 427,361
2022 326,171 368,195
2023 169,243 370,950
Remaining 581,104
Total (Undiscounted) 1,835,963 2,743,797

NOTE:
(1)  Numbers may not add due to rounding.

The following table outlines NuVista’s corporate finding and development costs in more detail:

3-Year-Average(1) 2018(1) 2017(1)
Proved Proved plus
probable
Proved Proved plus
probable
Proved Proved plus
probable
After reserve revisions and including changes in future development capital
Finding and development costs ($/Boe) $8.92 $7.06 $7.82 $6.43 $9.70 $6.95
Finding, development and acquisition costs ($/Boe) $10.29 $7.88 $10.34 $8.22 $9.88 $7.01

NOTE:
(1)  F&D costs and FD&A are used as a measure of capital efficiency. The calculation for F&D costs includes all exploration and development capital for that period as outlined in the Company’s year-end financial statements plus the change in future development capital for that period. This total capital including the change in the future development capital is then divided by the change in reserves for that period including revisions for that same period. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for the year.  FD&A costs are calculated in the same manner except in addition to exploration and development capital and the change in future development capital, acquisition capital is also included in the calculation.

Summary of Corporate Net Present Value Data

The estimated net present values of future net revenue before income taxes associated with NuVista’s reserves effective December 31, 2018 and based on published GLJ future price forecast as at January 1, 2019 as set forth below are summarized in the following table:

The estimated future net revenue contained in the following table does not necessarily represent the fair market value of the reserves. There is no assurance that the forecast price and cost assumptions contained in the GLJ Report will be attained and variations could be material. The recovery and reserve estimates described herein are estimates only.  Actual reserves may be greater or less than those calculated.

Before Income Taxes
Discount Factor (%/year)
Reserves category (1) ($ thousands) 0% 5% 10% 15% 20%
Proved
Developed producing 1,423,333 1,086,540 878,857 742,091 646,457
Developed non‑producing 164,585 118,100 91,307 74,343 62,739
Undeveloped 3,311,384 2,015,329 1,320,250 909,209 646,056
Total proved 4,899,303 3,219,969 2,290,415 1,725,643 1,355,252
Probable 4,086,927 1,982,738 1,139,666 737,391 517,169
Total proved plus probable 8,986,230 5,202,707 3,430,081 2,463,034 1,872,421

(1)  Numbers may not add due to rounding.

The following table is a summary of pricing and inflation rate assumptions based on published GLJ forecast prices and costs as at January 1, 2019:

Year AECO
Gas
($Cdn/
MMBtu)
NYMEX
Gas
($US/
MMBtu)
Midwest
Gas at
Chicago
($US/
MMBtu)
Edmonton
C5+
($Cdn/Bbl)
Edmonton
Propane
($Cdn/Bbl)
Edmonton
Butane
($Cdn/Bbl)
WTI
Cushing
Oklahoma
($US/Bbl)
Edmonton
Par Price
40 API
($Cdn/Bbl)
Exchange
Rate(2)
($US/$Cdn)
Forecast
2019 1.85 3.00 2.90 67.67 25.33 21.45 56.25 63.33 0.750
2020 2.29 3.15 3.05 79.22 32.39 37.66 63.00 75.32 0.770
2021 2.67 3.35 3.25 83.54 36.68 47.85 67.00 79.75 0.790
2022 2.90 3.50 3.40 85.49 39.11 57.04 70.00 81.48 0.810
2023 3.14 3.63 3.53 87.80 41.77 58.48 72.50 83.54 0.820
2024 3.23 3.70 3.60 90.30 43.03 60.24 75.00 86.06 0.825
2025 3.34 3.77 3.67 93.33 44.55 62.36 77.50 89.09 0.825
2026 3.41 3.85 3.75 96.86 46.31 64.83 80.41 92.62 0.825
2027 3.48 3.93 3.83 98.81 47.28 66.20 82.02 94.57 0.825
2028 3.54 4.00 3.90 100.80 48.28 67.59 83.66 96.56 0.825
2029+ +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr 0.825

NOTES:
(1)  Costs are inflated at 2% per annum.
(2)  Exchange rate used to generate the benchmark reference prices in this table.
(3)  NuVista’s future realized gas prices are forecasted based on a combination of various benchmark prices in addition to the AECO benchmark in order to reflect the favorable price diversification to other markets which NuVista has undertaken. Pricing at these markets has been accounted for in the GLJ Report. Additional information on NuVista’s gas marketing diversification will be available in our Q4 2018 MD&A as well as in our corporate presentation.



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