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NuVista Energy Ltd. Announces Year End 2020 Reserves, Financial and Operating Results

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NuVista Energy Ltd.
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CALGARY, Alberta, March 02, 2021 (GLOBE NEWSWIRE) -- NuVista Energy Ltd. (“NuVista” or the “Company”) (TSX:NVA) is pleased to announce reserves, financial and operating results for the three months and year ended December 31, 2020, and provide a number of updates which demonstrate continued successful advancement of our Pipestone and Wapiti Montney play development. 2020 was an unprecedented year where the world saw the COVID-19 pandemic deeply affecting all economies and temporarily reducing the demand for oil and natural gas worldwide, and this was compounded by the price pressures of the Saudi-Russian oil price war early in the year. Commodity pricing for WTI oil and NYMEX natural gas was highly volatile and averaged at decade low levels for much of the year. NuVista responded quickly and positively by significantly reducing capital, operating, and G&A expenditures to ensure balance sheet protection. We maintained our credit facility at $440 million and we renegotiated our midstream contract minimum volume commitments (MVC’s) for the long term in order to maximize short and long term flexibility for the volatile environment. NuVista also reduced staff, executive, and board compensation to lead in cost reduction discussions with contractors and vendors. We used the resulting free cash flow to significantly reduce net debt in the second half of the year as cash flow began to increase with recovering commodity prices.

All of the aforementioned actions have placed NuVista in the enviable position of moving forward through 2021 with strength and increasing momentum in the significantly improved commodity price environment.

During the quarter and year ended December 31, 2020, NuVista:

  • Produced 49,300 Boe/d, well above the guidance range of 47,000 – 48,000 Boe/d. Full year production was 50,443 Boe/d, which was virtually flat versus the 2019 figure of 50,803 Boe/d;

  • Achieved $49.4 million of cash flow in the quarter ($0.22/share), including over $25 million of free cash flow (cash flow net of capital expenditures). Full year cash flow was $156.9 million, or $0.70/share;

  • Achieved our net debt reduction target of $50 - $60 million in the second half of 2020 with free cash flow achieving $58 million of net debt reduction;

  • Executed a successful and conservative 2020 capital expenditure program of $180.4 million, including the drilling of 25 (25.0 net) wells and the completion of 15 (15.0 net) wells in our condensate rich Wapiti Montney play. This includes $10 million of expenditures which were phased into the fourth quarter of 2020 from the first quarter of 2021 in order to facilitate an earlier commencement of our winter drilling program. A total of 14 drilled uncompleted wells were held for delayed completion in early 2021;

  • Recognized an impairment recovery of $720 million in the fourth quarter, which largely offsets impairment expense of $909 million recognized in Q1 2020;

  • Maintained total annual operating expenses approximately flat at $9.83/Boe despite the deliberate flattening of production during the COVID-19 crisis;

  • Achieved record low G&A expenses of $0.76/Boe in 2020, continuing our long term trend of significant improvement with a reduction of 16% compared to the 2019 result; and

  • Continued to significantly advance our progress and plans in environmental, social and governance (“ESG”), including continued positive strides in reducing GHG and methane emissions.

Positive Reserves Revisions and Cost Reductions Drive Continued Improvements in Finding Costs and Reserves Value

NuVista is pleased to report the 2020 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 continued improvements in finding and development (“F&D”) costs and significant improvement in base decline.

The quality of NuVista's reserves continues to improve. We have pivoted in response to the collapse in commodity prices in early 2020 and maintained our Proved Developed Producing (“PDP”) reserve volumes, while drastically improving the economics of the undeveloped wells in inventory. Looking forward, a greater proportion of the PDP additions will be in the Pipestone area which carry per-well F&D costs that are on average less than $5/Boe. These achievements, when coupled with future annual budgets that will include minimal capital for facility and infrastructure spending, position us well for continued improvements in corporate F&D costs. Highlights of our 2020 reserves include:

  • Held PDP reserves slightly above flat year over year via 103% PDP replacement ratio, at approximately 96 million BOE despite a 40% reduction in annual capital expenditures;

  • Reduced corporate PDP F&D costs for the third consecutive year, reaching $9.44/Boe. This was driven by continued well cost reductions, positive technical revisions to existing reserves of 2% and continued strong well results;

  • Achieved Total Proved Plus Probable (“TP+PA”) 3-year average F&D costs of $6.61/Boe; a reduction of 18% from 2019;

  • Reduced base decline1 from 32% to 28%; and

  • Based on well costs achieved to date, average undeveloped well Drill, Complete, Equip & Tie-in (“DCET”) cost was reduced by 22%.

    1Reflects the forecast first year annual average PDP production decline in the 2020 year end GLJ Report, compared against the forecast first year annual average PDP production decline in the 2019 year end GLJ Report.

The detailed summary of our year end 2020 reserves disclosure is included below, and will be included in our Annual Information Form which will be filed on or before March 30, 2021 at www.SEDAR.com.

Excellence in Operations

We are pleased to report that operations across our entire asset base are currently proceeding ahead of schedule and under budget. A total of 22 new Montney wells are expected to be completed and brought on production from late in the first quarter through early in the second quarter of 2021. 12 of the wells are in our highest return Pipestone North area, 6 in Pipestone South, and 4 in the Bilbo area. Drilling and completions activities are nearing completion and costs are trending 10-15% below our 2020 average on a length/tonnage normalized basis. This is due to continued permanent structural design changes to our drilling and completions programs based on ongoing learnings. In addition, commissioning of the new Pipestone North Compressor Station, the Veresen Hythe Gas Plant expansion, and the associated pipeline are all progressing on schedule for commencement of operations in April.

Divestitures and Keeping The Balance Sheet Strong

The difficult world economic events of 2020 caused debt to rise and cash flow to fall for most exploration and production companies in our industry. NuVista took rapid action by adjusting capital expenditures and initiating cost cutting measures to protect the balance sheet. As noted earlier, we used the proceeds from free cash flow to reduce net debt by $58 million in the second half of 2020. Our debt reduction focus continued with the recently announced successful 2021 divestiture of our non-core Charlie Lake and Cretaceous Unit assets, as well as selected water infrastructure assets in the Wembley/Pipestone area, for total proceeds of $94 million. There was no change to NuVista’s ownership in our core Montney assets in Pipestone, Wapiti, and the surrounding area and no material change to our ownership in the Wembley gas plant. The total associated amount of 2021 production divested was approximately 1,100 Boe/d and there was no material impact on cash flow associated with either transaction. Pro forma the dispositions, NuVista’s bank drawings as at December 31, 2020 were approximately $269 million, significantly expanding the liquidity available within the $440 million credit facility. Pro forma net debt was $505 million, and fourth quarter net debt to annualized cash flow ratio was 2.6x. NuVista’s banking syndicate has reaffirmed the borrowing facility at $440 million. NuVista remains focused upon increasing cash flow as commodity prices continue to recover, and rapidly driving net debt towards a newly reduced long term target of less than 1x net debt to cash flow ratio.

Significant Commodity Price Diversification and Risk Management

NuVista has benefited from the discipline of our strong rolling hedge program during this period of volatile commodity prices. The unexpected onset of the COVID-19 pandemic had an immediate negative effect on world oil demand and prices. Natural gas pricing at NYMEX and other US hubs had in general been weaker lately due to the mild winter, however the recent period of significant cold weather in the US has temporarily increased demand and pricing while reducing supply. With WTI oil and NYMEX natural gas pricing at decade lows in 2020, NuVista relied on the significant hedges we had in place, and we limited our hedging activity during the commodity price lows.

The advances in vaccine delivery are now spurring expectations of increased demand. This, combined with reduced supply from reduced world investment, and OPEC production discipline, have now resulted in significant ongoing recovery in the price of WTI oil. With natural gas storage levels reducing on a significant increase in LNG shipments and the recent cold weather, improved and sustained strength in NYMEX gas pricing is expected through 2021. As commodity prices have now returned to levels that are profitable for NuVista, we have re-engaged our rolling hedging program to ensure attenuation of future price volatility and to underpin our prudently growing capital spending plans. We currently possess hedges which, in aggregate, cover 53% of projected 2021 liquids production (primarily front of year loaded) using a combination of swaps and three-way collars at an average WTI floor price of C$60.76/Bbl. We have hedged 37% of projected 2021 gas production (primarily summer season loaded) at an average floor price of C$2.05/Mcf (hedged and exported volumes converted to an AECO equivalent price) using a combination of swaps and collars. These percentage figures relate to production net of royalty volumes.

ESG Progress Continues

We are proud to continue to demonstrate our commitment to transparency and ethical practices through our ESG performance. Approximately 60% of our current production is comprised of natural gas which has the lowest carbon footprint of any hydrocarbon, leading to our GHG performance being well ahead of the North American benchmark. Canadian ESG standards are among the highest in the world, and NuVista continues to execute projects throughout the year to enhance our ESG progress, particularly in the areas of GHG and methane emissions reduction. We look forward to providing much more information in our updated annual ESG report in the third quarter of 2021.

At the new Pipestone compressor stations, NuVista and its midstream partners have invested $1.2 million to increase our count of waste heat recovery units from 7 to 10. These new units recover waste heat from compressor exhaust, significantly reducing fuel useage. This saves significant costs and avoids a total of approximately 4,500 T CO2e per year of future GHG emissions for the three new units alone. In our effort to reduce greenhouse gas emissions further, another focus has been on establishing ourselves as a frontrunner in eliminating methane emissions. We’ve adopted the design philosophy of incorporating centralized compressed air into the ongoing build out of our Pipestone North and South fields. The new wells we are bringing on-stream in Pipestone are therefore zero routine methane venting emission sites. In our Wapiti field, where centralized compressed air is less viable, we are piloting our first solar powered compressed air solution at one of our well pads. More details on our emissions reduction efforts can be found within our 2020 submission to the Carbon Disclosure Project, and will also be available in our annual ESG report which will be released in late summer.

We also continued our commitment to responsibly abandoning and reclaiming inactive wells and facilities in our legacy areas. In 2020, we spent over $11 million on abandonment and reclamation work. Many of these dollars result in local economic and employment benefits to remote parts of Alberta, and we are actively working with our First Nation partners in these areas to ensure they are participating in these benefits as well. With 2020, COVID-19 became a big part of our normal high focus on Health and Safety, and in addition the $350,000 which NuVista and staff collectively donated to the communities and First Nations where we work and live, was expanded to include a COVID-19 relief element for those in need.

2021 Guidance Update

As discussed above, NuVista is pleased to note that both condensate and natural gas future strip prices have increased significantly in the past quarter, resulting in a significant increase to projected cash flows at the same time as tremendous progress has been made in reducing our net debt. Our continuing efforts are focused on balancing rapid debt repayment, increasing cash flow through prudent production growth, and creating a comfortable cushion above midstream minimum volume commitments. As such, the proceeds from the divestitures allow us room to use up to half in order to prudently increase our capital spending for 2021 and 2022 while maintaining spending below projected 2021 and 2022 cash flow levels. The remainder of the proceeds will continue to be applied towards permanent net debt reduction.

NuVista’s capital spending for 2021 has been increased to a range of $230 - $250 million from the original range of $180 - $200 million. As the spending will be added in the third and fourth quarters of 2021, there is a minimal production impact on 2021 but offsets the reduction from the divested volumes. This is then followed by a significant positive impact to our outlook for 2022 production and corresponding cash flow. 2021 production guidance is re-affirmed at 50,000 - 52,000 Boe/d. The preceding spending level assumes that strip prices remain near current levels, and is expected to result in significant ongoing reduction of net debt as well as dramatic reduction in net debt to cash flow ratio. We intend to continue our track record of carefully directing additional available cash flow towards a prudent balance of debt reduction and production growth until our existing facilities are filled to maximum efficiency, and net debt to cash flow levels reach 1.0x or less. Capital spending will continue to be weighted heavily towards Pipestone, as our highest return area, with expected well payouts well below a year. NuVista retains the flexibility to revise capital spending from the second quarter onwards, should commodity prices increase or retreat significantly from the current positive trend.

NuVista has a solid business plan that maximizes free cash flow and the return of capital to shareholders when our existing facilities are filled to capacity and maximum efficiency at flattened production levels of approximately 80,000 – 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 cash flow and net debt reduction while growing through 2021-2023. With facilities filled, 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 costs by this amount.

NuVista has top quality assets and a management team focused on relentless improvement. We have the necessary foundation and liquidity to add significant value as commodity prices continue to recover. We have set the table for returns-focused profitable growth to between 80,000 – 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, including our outlook for 2022 and beyond, is being updated and will be available at www.nuvistaenergy.com on March 2, 2021. NuVista’s financial statements, notes to the financial statements and management’s discussion and analysis for the year ended December 31, 2020, will be filed on SEDAR (www.sedar.com) under NuVista Energy Ltd. on March 2, 2021 and can also be accessed on NuVista’s website.

Financial and Operating Highlights

Three months ended December 31

Year ended December 31

(Cdn $000s, except otherwise indicated)

2020

2019

% Change

2020

2019

% Change

FINANCIAL

Petroleum and natural gas revenues

124,378

163,278

(24

)

424,637

585,484

(27

)

Adjusted funds flow (1) (2)

49,399

70,080

(30

)

156,866

265,851

(41

)

Per share - basic

0.22

0.31

(29

)

0.70

1.18

(41

)

Per share - diluted

0.22

0.31

(29

)

0.70

1.18

(41

)

Net earnings (loss)

715,435

(29,557

)

(2,521

)

(197,879

)

(63,833

)

210

Per share - basic

3.17

(0.13

)

(2,538

)

(0.88

)

(0.28

)

214

Per share - diluted

3.17

(0.13

)

(2,538

)

(0.88

)

(0.28

)

214

Capital expenditures (2)

23,864

52,814

(55

)

180,442

301,822

(40

)

Net debt (1) (2)

598,835

561,975

7

OPERATING

Daily Production

Natural gas (MMcf/d)

183.3

204.3

(10

)

185.7

182.3

2

Condensate & oil (Bbls/d)

12,928

17,195

(25

)

14,067

15,170

(7

)

NGLs (Bbls/d)

5,863

5,769

2

5,420

5,246

3

Total (Boe/d)

49,348

57,010

(13

)

50,443

50,803

(1

)

Condensate, oil & NGLs weighting

38%

40%

39%

40%

Condensate & oil weighting

26%

30%

28%

30%

Average realized selling prices (4)

Natural gas ($/Mcf)

3.14

2.74

15

2.43

2.78

(13

)

Condensate & oil ($/Bbl)

52.59

65.78

(20

)

45.50

67.44

(33

)

NGLs ($/Bbl) (3)

16.44

14.56

13

12.68

14.01

(9

)

Netbacks ($/Boe)

Petroleum and natural gas revenues

27.40

31.13

(12

)

23.00

31.57

(27

)

Realized gain on financial derivatives

2.77

0.75

269

3.83

0.94

307

Royalties

(0.83

)

(1.82

)

(54

)

(0.92

)

(1.49

)

(38

)

Transportation expenses

(4.97

)

(4.13

)

20

(4.46

)

(4.35

)

3

Operating expenses

(9.68

)

(9.63

)

1

(9.83

)

(9.61

)

2

Operating netback (2)

14.69

16.30

(10

)

11.62

17.06

(32

)

Corporate netback (2)

10.88

13.37

(19

)

8.49

14.34

(41

)

SHARE TRADING STATISTICS

High

1.08

3.24

(67

)

3.36

5.19

(35

)

Low

0.64

1.86

(66

)

0.24

1.39

(83

)

Close

0.94

3.19

(71

)

0.94

3.19

(71

)

Average daily volume ('000s)

1,479

770

92

2,030

1,212

67

Common shares outstanding ('000s)

225,837

225,592

(1) Refer to Note 17 “Capital management” in NuVista's financial statements and to the sections entitled “Adjusted funds flow” and “Liquidity and capital resources” contained in the MD&A for the year ended December 31, 2020.
(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 “Non-GAAP measurements”.
(3) Natural gas liquids (“NGLs”) include butane, propane and ethane and an immaterial amount of sulphur revenue.
(4) 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 GLJ January 1, 2021 price forecast:

Natural Gas(2)

Natural Gas
Liquids

Oil(3)

Total

Reserves category(1)

Company
Gross

Company
Gross

Company
Gross

Company
Gross

Interest

Interest

Interest

Interest

(MMcf)

(MBbls)

(MBbls)

(MBoe)

Proved

Developed producing

366,852

33,965

398

95,505

Developed non-producing

85,468

9,466

295

24,006

Undeveloped

820,432

72,254

4,535

213,527

Total proved

1,272,751

115,684

5,228

333,038

Probable

1,011,300

82,134

6,111

256,795

Total proved plus probable

2,284,051

197,819

11,339

589,833

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 2020 year end working interest reserves with the working interest reserves reported in the 2019 year end reserves report:

Company Gross Interest

Natural
Gas(1)(3)
(MMcf)

Liquids(1)
(MBbls)

Oil(1)(4)
(MBbls)

Total Oil
Equivalent(1)
(MBoe)

Total proved

Balance, December 31, 2019

1,393,425

118,180

3,021

353,438

Exploration and development(2)

72,977

8,963

1,969

23,095

Technical revisions

(108,407

)

(3,159

)

328

(20,899

)

Acquisitions

1,721

170

339

796

Dispositions

(12,941

)

(1,074

)

-

(3,230

)

Economic Factors

(6,045

)

(394

)

(299

)

(1,701

)

Production

(67,978

)

(7,003

)

(130

)

(18,462

)

Balance, December 31, 2020

1,272,751

115,684

5,228

333,038

Total proved plus probable

Balance, December 31, 2019

2,353,534

195,407

6,087

593,749

Exploration and development(2)

71,338

9,446

3,686

25,021

Technical revisions

(46,710

)

1,743

1,082

(4,960

)

Acquisitions

7,383

562

755

2,547

Dispositions

(23,547

)

(1,793

)

-

(5,717

)

Economic Factors

(9,969

)

(544

)

(141

)

(2,346

)

Production

(67,978

)

(7,003

)

(130

)

(18,462

)

Balance, December 31, 2020

2,284,051

197,819

11,339

589,833

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

2021

186,744

194,144

2022

378,352

392,744

2023

362,699

392,431

2024

316,154

341,660

2025

247,780

279,261

Remaining

13,454

919,141

Total (Undiscounted)

1,505,182

2,519,382

NOTE:
(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:

3 Year-Average (1)

2020 (1)

2019 (1)

Proved plus

Proved plus

Proved plus

Proved

probable

Proved

probable

Proved

probable

Finding and development costs ($/Boe)

$5.98

$4.20

$-680.31

$-23.06

$10.30

$8.94

Finding, development and acquisition costs ($/Boe)

$8.85

$6.61

$173.67

$-28.08

$10.30

$8.94

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, 2020 and based on published GLJ future price forecast as at January 1, 2021 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

1,131,492

929,968

761,095

643,433

559,929

Developed non-producing

410,806

306,475

246,387

208,111

181,669

Undeveloped

2,465,039

1,498,026

975,515

668,302

473,810

Total proved

4,007,337

2,734,469

1,982,997

1,519,846

1,215,407

Probable

3,678,075

1,752,607

983,370

623,121

430,852

Total proved plus probable

7,685,412

4,487,076

2,966,367

2,142,967

1,646,259

NOTE:
(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, 2021:

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

2021

2.72

2.75

2.60

60.65

19.43

27.75

48.00

55.49

0.775

2022

2.67

2.80

2.65

65.36

24.31

36.47

51.50

60.78

0.765

2023

2.60

2.85

2.70

70.07

25.53

41.48

54.50

63.82

0.760

2024

2.60

2.90

2.75

74.72

27.26

44.29

57.79

68.14

0.760

2025

2.65

2.95

2.80

76.25

27.87

45.29

58.95

69.67

0.760

2026

2.71

3.01

2.86

77.80

28.49

46.30

60.13

71.22

0.760

2027

2.76

3.07

2.92

79.38

29.12

47.32

61.33

72.80

0.760

2028

2.81

3.13

2.98

81.00

29.77

48.37

62.56

74.42

0.760

2029

2.87

3.19

3.04

82.64

30.43

49.44

63.81

76.07

0.760

2030

2.92

3.25

3.10

84.30

31.03

50.43

65.09

77.59

0.760

2031+

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

0.760

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 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 news release contains a number of oil and gas metrics prepared by management, including F&D costs, FD&A costs and reserves replacement ratio, 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 and FD&A costs have been calculated are included in the body of this news release. Reserves replacement ratio is the sum of changes in reserves (exploration and development, technical revisions, acquisitions, dispositions and economic factors) divided by annual production for the applicable period and reserve category.

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.

The type curves and well economics associated with the Pipestone development block wells have been risked by taking a reduced expected resource recovery from increased horizontal length and frac intensity based on applicable actual well data and applying our planned well design.

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.

Economics presented are based on pricing assumptions of: US$55/Bbl WTI; US$3.00/MMBtu NYMEX; Fx (CAD:USD): 1.28:1, and; a $US0.75/MMBtu AECO to NYMEX basis.

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.

Reserves advisories

The reserves estimates prepared herein have been evaluated by an independent qualified reserves evaluator in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and are effective as of December 31, 2020. All reserves information has been presented on a gross basis, which is the Company's working interest share before deduction of royalties and without including any royalty interests of the Company. The reserves have been categorized accordance with the reserves definitions as set out in the COGE Handbook. The recovery and reserve estimates contained herein are estimates only and there is no guarantee that the estimated reserves will be recovered.

Advisory regarding forward-looking information and statements

This press release contains forward-looking statements and forward-looking information (collectively, “forward-looking statements”) within the meaning of applicable securities laws. The use of any of the words “will”, “expects”, “believe”, “plans”, “potential” and similar expressions are intended to identify forward-looking statements. More particularly and without limitation, this press release contains forward looking statements, including management's assessment of: NuVista’s future focus, strategy, plans, opportunities and operations; projected cash flows at current strip prices; our plans to continue to balance debt repayment, increasing cash flow through prudent production growth, and creating a comfortable cushion above our midstream minimum volume commitments; plans to increase our capital spending for 2021 and 2022 while maintaining spending below projected 2021 and 2022 cash flow levels; the anticipated proceeds from the Wembley divestitures and uses of proceeds plans to reduce net debt; guidance with respect to 2021 capital spending amounts, spending timing and allocation; 2021 and 2022 production and cash flow guidance at current strip prices; expectations with respect to future net debt to cash flow ratio; plans to direct additional available cash flow towards a prudent balance of debt reduction and production growth until our existing facilities are filled to maximum efficiency, and debt to cash flow levels reach 1.0x or less; expectations that Pipestone will continue to be our highest return area; expected well payouts at Pipestone; ESG plans, targets and expected results from our ESG initiatives; that we will have the flexibility to revise capital spending from the second quarter onwards; future commodity prices; plans to maximize free cash flow and the return of capital to shareholders; future capacity of our facilities, that maximum efficiency will be achieved at flattened production levels of approximately 80,000 – 90,000 Boe/d and that this will be achieved as early as 2023; that we will generate free cash flow and debt reduction while growing through 2021-2023; that once existing facilities are filled; returns will be enhanced, corporate netbacks will grow by approximately $2-$3/Boe and unit operating, transportation, and interest costs will be reduced by this amount; the effect of our financial, commodity, and natural gas risk management strategy and market diversification; the quality of our assets, our expectations that a greater proportion of future PDP additions will be in the Pipestone area; expectations with respect to continued improvements in corporate F&D costs; 2021 drilling and completion plans, timing and expected results; anticipated drilling and completions costs; timing for the completion of the Pipestone North Compressor Station, the Veresen Hythe Gas Plant expansion, and the associated pipeline; expectations that NuVista will add significant value if commodity prices continue to recover and will experience returns-focused profitable growth to between 80,000 – 90,000 Boe/d with only half-cycle spending and plans to maximize the value of our asset base and ensure the long term sustainability of our business. Statements relating to "reserves" are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

By their nature, forward-looking statements are based upon certain assumptions and are subject to numerous risks and uncertainties, some of which are beyond NuVista’s control, including the impact of general economic conditions, industry conditions, current and future commodity prices, currency and interest rates, anticipated production rates, borrowing, operating and other costs and adjusted funds flow, the timing, allocation and amount of capital expenditures and the results therefrom, anticipated reserves and the imprecision of reserve estimates, the performance of existing wells, the success obtained in drilling new wells, the sufficiency of budgeted capital expenditures in carrying out planned activities, access to infrastructure and markets, competition from other industry participants, availability of qualified personnel or services and drilling and related equipment, stock market volatility, effects of regulation by governmental agencies including changes in environmental regulations, tax laws and royalties, the ability to access sufficient capital from internal sources and bank and equity markets; that we will complete the announced dispositions on the terms and timing contemplated, and including, without limitation, those risks considered under “Risk Factors” in our Annual Information Form. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. NuVista’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements, or if any of them do so, what benefits NuVista will derive therefrom. NuVista has included the forward-looking statements in this press release in order to provide readers with a more complete perspective on NuVista’s future operations and such information may not be appropriate for other purposes. NuVista disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

Non-GAAP measurements

For ease of readability, in this press release, we have used the term "cash flow" instead of "adjusted funds flow".

Within the press release, references are made to terms commonly used in the oil and natural gas industry. Management uses "cash flow", "cash flow per share", "operating netback", "corporate netback", "capital expenditures", "free cash flow", "cash flow netback","net debt", "net debt to cash flow ratio" and "net debt to annualized cash flow ratio" to analyze performance and leverage. These terms do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. For further information refer to the section "Non-GAAP measures" in our MD&A.

Free cash flow is forecast cash flow less capital expenditures required to maintain production.

FOR FURTHER INFORMATION CONTACT:

Jonathan A. Wright

Ross L. Andreachuk

Mike J. Lawford

President and CEO

VP, Finance and CFO

Chief Operating Officer

(403) 538-8501

(403) 538-8539

(403) 538-1936