CALGARY, Alberta – NuVista Energy Ltd. (“NuVista” or the “Company”) (TSX:NVA) is pleased to announce record-setting reserves, financial and operating results for the three months and year ended December 31, 2021, and to provide a number of updates which demonstrate material advancement of our Pipestone and Wapiti Montney development. 2021 was a year of significant commodity price recovery after the difficult year in 2020 due to the reduction in energy demand as a result of the Covid-19 pandemic. We used our significantly growing adjusted funds flow in a disciplined manner by growing production with new high-return wells to fill and optimize existing facilities while making rapid and meaningful progress in debt reduction. NuVista is now moving forward through 2022 with strength and increasing momentum in this significantly improved commodity price environment.
During the quarter and year ended December 31, 2021, NuVista:
- Produced 60,888 Boe/d in the quarter, well above the guidance range of 56,000 – 58,000 Boe/d, and 19% higher than third quarter 2021 production. Fourth quarter production consisted of 35% condensate, 10% NGLs, and 55% natural gas. Full year production was 4% higher than the prior year at 52,345 Boe/d consisting of 31% condensate, 11% NGLs, and 58% natural gas;
- 2021 net earnings totaled $264.7 million ($1.17/share, basic) compared to a net loss of $197.9 million (($0.88)/share, basic) in 2020;
- Achieved $151.7 million of adjusted funds flow(1) in the fourth quarter ($0.67/share, basic), including over $64.5 million of free adjusted funds flow(1). Full year adjusted funds flow was $321.0 million, or $1.42/share (basic). The fourth quarter adjusted funds flow represented more than a threefold increase over comparable figure for the prior year, and full year 2021 adjusted funds flow was two times the prior year amount;
- Improved upon our net debt(1) reduction target with $118.6 million of reduction during 2021, $65.1 million of which was in the fourth quarter alone. NuVista closed the year with a favorable net debt to annualized fourth quarter adjusted funds flow ratio of 0.8x;
- Successfully extended the tenure of our outstanding senior unsecured notes to July 2026 in the third quarter of 2021;
- Executed a successful 2021 capital expenditure(2) program of $288.8 million, including the drilling of 38 (38.0 net) wells and the completion of 44 (44.0 net) wells in our condensate rich Wapiti Montney play; and
- Continued to significantly advance our progress in the areas of environmental, social and governance (“ESG”), including continued positive strides in reducing GHG and methane emissions.
(1) Each of “adjusted funds flow” and “net debt” are capital management measures. Reference should be made to the section entitled “Non-GAAP and Other Financial Measures” in this press release.
(2) Each of “free adjusted funds flow” and “capital expenditures” are non-GAAP financial measures that do not have any standardized meanings 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 and Other Financial Measures” in this press release.
Record Achievements in Reserve Metrics
NuVista is pleased to report the year end 2021 independent evaluation of our reserves by GLJ Ltd. (“GLJ”) (the “GLJ Report”). With the infrastructure investment in our assets now largely behind us, our focus has shifted to building production volumes and maximizing the velocity at which invested capital is returned through exceptional half-cycle returns. Well costs continue to trend downwards while production performance is dramatically improving. The quality of our asset base is reflected in additional positive technical revisions to our production base and new records in the efficiency with which we are adding additional reserves. Our established track record of improvement and depth of running room in our undeveloped reserves reinforce our ability to provide a differentiated level of value creation for our shareholders.
Highlights of our 2021 reserves report include:
- Proved Developed Producing (“PDP”) reserves increased a record 26% to 122MMBoe;
- PDP Finding and Development Costs (“F&D”) (1) achieved record lows for the fourth consecutive year, reaching $6.12/Boe which is a 36% improvement over 2020;
- PDP Recycle Ratio(1) also achieved new record levels at 4.4x based on our 2021 operating netback(1) of $27.13/Boe;
- Replaced 220% of our production on a PDP basis while only spending 90% of adjusted funds flow;
- PDP NPV10 increased to $1.5 Billion, an increase of 96% from 2020 underpinned by the dramatic growth in reserve volumes and the increase in commodity prices;
- PDP Finding, Development and Acquisition Costs (“FD&A”) (1) were $4.31/Boe after accounting for the Wembley Disposition;
- Technical revisions of +5% were made to 2020 PDP reserves due to continued outperformance of wells and an increase in economic limit due to higher forecast commodity prices; and
- Total proved plus probable additional (“TP+PA”) reserve volumes are 568MMBoe which includes 340 undeveloped locations. An additional 824 Best Estimate Contingent Resource Undeveloped Locations are also booked.
(1) Each of FD&A costs, F&D costs, recycle ratio and operating netback are non-GAAP financial ratios. See “Oil and Gas Advisories” and “Non-GAAP and Other Financial Measures” in this press release for information relating to these specified financial measures.
The detailed summary of our year end 2021 reserves disclosure is included below, and will be included in our Annual Information Form which will be filed on or before March 30, 2022 at www.SEDAR.com.
Excellence in Operations
As noted in our press release dated January 10, 2022, fourth quarter operations went exceptionally well. Despite challenges with extreme cold weather, Covid-19 issues, and supply chain disruptions, record production levels were achieved. The stability and continuity of our three-rig drilling program has continued to reward us as we progress through the first quarter of 2022. Production in the Wapiti area is ramping up with the addition of the latest 4-well pad at Elmworth. Drill, Complete, and Equip (“DCE”) costs for this pad averaged $7MM per well while the 60 day initial production rate averaged 1,282 Boe/d per well including 27% condensate. An additional 6-well pad at Elmworth has been drilled and completed, and is currently being production tested. Estimated DCE cost per well on this pad is expected to be approximately $5.8MM. Drilling operations are in progress on a 4-well pad in the Gold Creek area which will be completed by the end of the first quarter.
Activity levels in the Pipestone area were high in the fourth quarter, and have continued to be high as we proceed into 2022. Pad #8 was drilled and completed in the fourth quarter and is now on production. The wells on this pad were drilled to an average horizontal length of 3000m and reached a new Pipestone record low DCE cost of $1.9MM per 1000 horizontal meter drilled. Pad #9 has been drilled and completion operations have commenced, while drilling operations on pad #10 have just been finished.
Remaining activity in 2022 is planned to include five additional pads with approximately 25 wells, of which two thirds are expected to be in the Pipestone area. The current program would have two to three rigs active throughout the remainder of the year, and due to efficient execution there is the potential opportunity to add a few more wells to the planned capital program to fill in any drilling breaks for maximum three rig schedule efficiency. We have now entered the phase in Pipestone area where we are significantly realizing the benefits of the acquisition we completed three years ago with substantial free adjusted funds flow being generated from this asset.
Balance Sheet Strength and Rapid Debt Reduction
In the fourth quarter of 2021, NuVista reduced bank debt by $69 million by continuing to direct all free adjusted funds flow towards the reduction of net debt. With the benefit of increased production and favorable pricing, this bettered our debt reduction expectations, ending the quarter with bank drawings of $196 million – a reduction of $167 million during the full year of 2021. NuVista’s credit facility capacity was redetermined and maintained at $440 million at the semi-annual review in November. Net debt was reduced during 2021 by a total of $119 million. NuVista closed the year of 2021 with a favorable net debt to annualized fourth quarter adjusted funds flow ratio of 0.8x. These results reaffirm our confidence that we are on track for reduction of net debt below our first targeted milestone of $400 million during the second quarter of 2022. At the present time, 100% of free adjusted funds flow is being directed to the reduction of debt.
ESG Progress Continues
We are proud to continue to demonstrate our commitment to transparency and ethical practices through our ESG performance, and we issued an updated full report to highlight our progress in August of 2021.
Approximately 60% of our current production is comprised of natural gas which has the lowest carbon footprint of any hydrocarbon, leading to our greenhouse gas (“GHG”) performance being better than the North American benchmark. But we will always strive to do more. In our 2021 report, we set seven long term targets for accountability and transparency of the progress we continue to make, and we continue to execute projects in environment, social, and governance to ensure we meet these targets. These include projects to eliminate methane venting, reduce flaring, reduce water consumption, and to responsibly abandon and reclaim legacy wells and facilities. We also progressed in matters of Social and Governance including continued headway on diversity and inclusion on several fronts. More details are available in our fourth quarter 2021 MD&A and our annual ESG report.
2022 Guidance Update
As discussed above, NuVista is pleased to note that operations and performance have been strong while both condensate and natural gas prices have increased significantly. This results in a material increase to projected adjusted funds flows and tremendous progress in reducing our net debt.
NuVista’s recent well performance has exceeded expectations, and in addition the on-stream dates for new wells have been ahead of schedule. As a result, first quarter production guidance is increased to 64,000 – 65,000 Boe/d as compared to the original guidance range of 60,000 – 62,000 Boe/d. Both of these ranges include condensate at approximately 32%, NGLs at 8%, and natural gas at 60%. Full year 2022 production guidance is unchanged at 65,000 – 68,000 Boe/d (condensate 30%, NGLs 8%, natural gas 62%), with a reminder that NuVista has some planned facility maintenance downtime in the second quarter. Capital expenditure guidance for 2022 is unchanged with a range of $290-310 million.
We intend to continue our track record of carefully directing additional available adjusted funds flow towards a prudent balance of debt reduction and production growth until our existing facilities are filled to maximum efficiency. Capital expenditures will continue to be weighted towards Pipestone, as our highest return area, with expected well payouts well below a year. As previously communicated, 100% of free adjusted funds flow will continue to be directed towards the balance sheet until net debt reaches the interim milestone of $400 million. This is expected to be achieved during the second quarter of 2022. Free adjusted funds flow below the milestone is anticipated to be allocated between further debt reduction, the return of capital to shareholders through the buyback of shares, and possibly towards a moderate capital expenditure increase to optimize the operational continuity of our three-rig drilling program even further, if strip commodity prices remain strong. The specific nature of these free adjusted funds flow splits will be determined and communicated during the second quarter of 2022. Our board has approved a long term sustainable net debt target of less than 1.0 times adjusted funds flow in the stress test price environment of US$ 45/Bbl WTI and US$ 2.00/MMBtu NYMEX natural gas. In the context of our 2022 plan, this represents a target net debt level of $200 – $250 million.
NuVista has an exceptional business plan that maximizes free adjusted funds flow and the return of capital to shareholders when our existing facilities are filled to capacity and maximum efficiency at production levels of approximately 85,000 – 90,000 Boe/d. We are confident that the actions described above accelerate the Company towards that goal by as early as 2023, while still providing free adjusted funds flow and net debt reduction concurrent with growing production through 2022-2023. With facilities optimized, returns are enhanced further with corporate netbacks which are expected to grow by approximately $2-$3/Boe due to the efficiencies of scale which will reduce our unit operating, transportation, and interest expenses by this amount.
NuVista has top quality assets and a management team focused on relentless improvement. We have the necessary foundation and liquidity to continue adding significant value for our shareholders. We have set the table for returns-focused profitable growth to between 85,000 – 90,000 Boe/d with only half-cycle spending, since the required facility infrastructure is now in place. We will continue to adjust to this environment in order to maximize the value of our asset base and ensure the long-term sustainability of our business. We would like to thank our staff, contractors, and suppliers for their continued dedication and delivery, and we thank our board of directors and our shareholders for their continued guidance and support. Please note that our corporate presentation is being updated and will be available at www.nuvistaenergy.com on March 9, 2022. NuVista’s financial statements, notes to the financial statements and management’s discussion and analysis for the year ended December 31, 2021, will be filed on SEDAR (www.sedar.com) under NuVista Energy Ltd. on March 9, 2022 and can also be accessed on NuVista’s website.
|Financial and Operating Highlights|
|Three months ended December 31||Year ended December 31|
|($ thousands, except otherwise stated)||2021||2020||% Change||2021||2020||% Change|
|Petroleum and natural gas revenues||323,355||124,378||160||885,290||424,637||108|
|Cash provided by operating activities||110,063||44,719||146||338,578||147,200||130|
|Adjusted funds flow(1) (4)||151,665||49,399||207||320,974||156,866||105|
|Per share, basic||0.67||0.22||205||1.42||0.70||103|
|Per share, diluted||0.64||0.22||191||1.38||0.70||97|
|Net earnings (loss)||113,159||715,435||(84||)||264,672||(197,879||)||234|
|Per share, basic||0.50||3.17||(84||)||1.17||(0.88||)||233|
|Per share, diluted||0.48||3.17||(85||)||1.14||(0.88||)||230|
|Net proceeds on property dispositions||(1,034||)||—||—||92,544||—||—|
|Net debt(1) (4)||480,275||598,835||(20||)|
|Natural gas (MMcf/d)||202.7||183.3||11||183.5||185.7||(1||)|
|Condensate & oil (Bbls/d)||21,072||12,928||63||16,465||14,067||17|
|Condensate, oil & NGLs weighting||45%||38%||42%||39%|
|Condensate & oil weighting||35%||26%||31%||28%|
|Average realized selling prices(6)|
|Natural gas ($/Mcf)||6.09||3.14||94||4.63||2.43||91|
|Condensate & oil ($/Bbl)||96.15||52.59||83||84.35||45.50||85|
|Petroleum and natural gas revenues||57.73||27.40||111||46.34||23.00||101|
|Realized gain (loss) on financial derivatives||(6.69||)||2.77||(342||)||(6.05||)||3.83||(258||)|
|SHARE TRADING STATISTICS|
|Average daily volume (‘000s)||827||1,479||(44||)||1,133||2,030||(44||)|
|Common shares outstanding (‘000s)||227,578||225,837||1|
(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 this MD&A.
(2) Non-GAAP financial 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 and Other Financial Measures”.
(3) Non-GAAP ratio 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 and Other Financial Measures”.
(4) Capital management measure. Reference should be made to the section entitled “Non-GAAP and Other Financial Measures”.
(5) Natural gas liquids (“NGLs”) include butane, propane, ethane and sulphur revenue.
(6) Product prices exclude realized gains/losses on financial derivatives.
Detailed Summary of Corporate Reserves Data
The following table provides summary reserve information based upon the GLJ Report using the published 3 Consultants’ Average January 1, 2022 price forecast:
|Natural Gas(2)||Natural Gas
|Reserves category(1)||Company Gross||Company Gross||Company Gross||Company Gross|
|Total proved plus probable||2,242,907||193,723||–||567,541|
(1) Numbers may not add due to rounding.
(2) Includes conventional natural gas and shale gas.
(3) Includes light and medium crude oil.
The following table is a summary reconciliation of the 2021 year end working interest reserves with the working interest reserves reported in the 2020 year end reserves report:
|Company Gross Interest||Natural Gas(1)(3)
|Balance, December 31, 2020||1,272,751||115,684||5,228||333,038|
|Exploration and development(2)||93,646||9,811||–||25,419|
|Balance, December 31, 2021||1,259,308||115,041||–||324,925|
|Total proved plus probable
Total proved plus probable
|Balance, December 31, 2020||2,284,051||197,819||11,339||589,833|
|Exploration and development(2)||116,399||11,786||–||31,186|
|Balance, December 31, 2021||2,242,908||193,723||–||567,541|
(1) Numbers may not add due to rounding.
(2) Reserve additions for drilling extensions, infill drilling and improved recovery.
(3) Includes conventional natural gas and shale gas.
(4) Includes light, medium crude oil.
(5) During the first quarter of 2021, we completed the divestiture of our non-core Charlie Lake and Cretaceous unit assets in the Wembley area, as well as selected water infrastructure assets in the Wembley/Pipestone area, for total net proceeds of $92.5 million. The sale included production of approximately 1,100 Boe/d and a reduction in our asset retirement obligations of $17.6 million.
The following table summarizes the future development capital included in the GLJ Report:
|($ thousands, undiscounted)||Proved||Proved plus
(1) Numbers may not add due to rounding.
The following table outlines NuVista’s corporate finding, development and acquisition (“FD&A”) costs in more detail:
|Proved plus||Proved plus||Proved plus|
|Finding and development costs ($/Boe)||$4.87||$3.94||$8.36||$8.74||($680.3)||($23.06)|
|Finding, development and acquisition costs ($/Boe)||$2.22||$1.70||($2.40)||$34.98||$173.67||($28.08)|
(1) F&D costs and FD&A are used as a measure of capital efficiency. The calculation for F&D costs includes all exploration and development capital for that period as outlined in the Company’s year-end financial statements plus the change in future development capital for that period. This total capital including the change in the future development capital is then divided by the change in reserves for that period including revisions for that same period. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for the year. FD&A costs are calculated in the same manner except in addition to exploration and development capital and the change in future development capital, acquisition capital is also included in the calculation.
Summary of Corporate Net Present Value Data
The estimated net present values of future net revenue before income taxes associated with NuVista’s reserves effective December 31, 2021 and based on published GLJ future price forecast as at January 1, 2022 as set forth below are summarized in the following table:
The estimated future net revenue contained in the following table does not necessarily represent the fair market value of the reserves. There is no assurance that the forecast price and cost assumptions contained in the GLJ Report will be attained and variations could be material. The recovery and reserve estimates described herein are estimates only. Actual reserves may be greater or less than those calculated.
|Before Income Taxes|
|Discount Factor (%/year)|
|Reserves category(1)($ thousands)||0%||5%||10%||15%||20%|
|Total proved plus probable||10,304,028||6,249,487||4,356,606||3,325,911||2,694,302|
(1) Numbers may not add due to rounding.
The following table is a summary of pricing and inflation rate assumptions based on published 3 Consultants’ Average forecast prices and costs as at January 1, 2022:
|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)|
(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 corporate presentation.
Advisories Regarding Oil And Gas Information
BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
This press release contains a number of oil and gas metrics prepared by management, including F&D costs, FD&A costs, recycle ratio and DC&E costs, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics have been included herein to provide readers with additional measures to evaluate NuVista’s performance on a comparable basis with prior periods; however, such measures are not reliable indicators of the future performance of NuVista and future performance may not compare to the performance in previous periods. Details of how F&D costs, FD&A costs and recycle ratios are calculated are set forth under the heading “Non-GAAP and Other Financial Measure – Non-GAAP Ratios”. DCET includes all capital spent to drill, complete and equip a well.
NuVista has presented certain well economics based on type curves for the Pipestone development block. The type curves are based on initial drilling results but due to the early stage of development, primarily on drilling results from analogous Montney development located in close proximity to such area. Such type curves and well economics are useful in understanding management’s assumptions of well performance in making investment decisions in relation to development drilling in the Montney area and for determining the success of the performance of development wells; however, such type curves and well economics are not necessarily determinative of the production rates and performance of existing and future wells and such type curves do not reflect the type curves used by our independent qualified reserves evaluator in estimating our reserves volumes. The type curves used in the GLJ Report for the Pipestone development blocks had an estimate of estimated ultimate recovery that generally compared well to the type curves used to generate the economics presented herein.
NuVista has presented the term “payout” based on the type curves for the Pipestone development block. Payout means the anticipated years of production from a well required to fully pay for the all capital spent to drill, complete, equip and tie-in a well of such well.
This press release discloses NuVista’s drilling locations in two categories: (i) undeveloped proved plus probable (2P) drilling locations; and (ii) undeveloped contingent resources (2C) drilling locations. Undeveloped 2P drilling locations are derived from a report prepared by GLJ, NuVista’s independent qualified reserves evaluator, evaluating NuVista’s reserves as of December 31, 2021 (the “GLJ Report”), and account for undeveloped drilling locations that have associated proved and/or probable reserves, as applicable. Undeveloped 2C drilling locations are derived from a report prepared by GLJ evaluating NuVista’s contingent resources as of December 31, 2021 (“GLJ Contingent Resource Report”), and account for undeveloped drilling locations that have associated contingent resources based on a best estimate of such contingent resources. There is no certainty that we will drill all drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. In the case of the contingent resources estimated in the GLJ Contingent Resource Report, contingencies include: (i) further delineation of interest lands; (ii) corporate commitment, and; (iii) final development plan. To further delineate interest lands additional wells must be drilled and tested to demonstrate commercial rates on the resource lands. Reserves are only assigned in close proximity to demonstrated productivity. As continued delineation drilling occurs, a portion of the contingent resources are expected to be reclassified as reserves. Confirmation of corporate intent to proceed with remaining capital expenditures within a reasonable timeframe is a requirement for the assessment of reserves. Finalization of a development plan includes timing, infrastructure spending and the commitment of capital.
Any references in this press release to initial production rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for NuVista.
Basis of presentation
Unless otherwise noted, the financial data presented in this press 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. National Instrument 51-101 – “Standards of Disclosure for Oil and Gas Activities” includes condensate within the product type of natural gas liquids. NuVista has disclosed condensate values separate from natural gas liquids herein as NuVista believes it provides a more accurate description of NuVista’s operations and results therefrom.
Production split for Boe/d amounts referenced in the press release are as follows:
|Reference||Total Boe/d||% Natural Gas||% Condensate||% NGLs|
|Q4 2021 production – actual||60,888||55%||35%||10%|
|Q4 2021 production guidance||56,000 – 58,000||62%||30%||8%|
|2021 annual production – actual||52,345||58%||31%||11%|
|2021 annual production guidance||51,000 – 52,000||60%||30%||10%|
|Q1 2022 revised production guidance||64,000 – 65,000||60%||32%||8%|
|Q1 2022 original production guidance||60,000 – 62,000||60%||32%||8%|
|2022 annual production guidance||65,000 – 68,000||62%||30%||8%|
|2024+ production range||85,000 – 90,000||62%||30%||8%|