NuVista Energy Ltd. Increases Reserves to Record Levels, Provides Positive Year End 2019 Financial and Operating Results, Re-Affirms 2020 Plans

CALGARY, Alberta, March 03, 2020 (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, 2019 and provide a number of updates which demonstrate continued successful advancement of our Pipestone and Wapiti Montney play development.

Record 2019 Production and Adjusted Funds Flow

During the quarter and year ended December 31, 2019, NuVista:

• Produced a record 57,010 Boe/d for the fourth quarter of 2019, or 16% greater than the respective quarter in 2018.  Full year 2019 production was a record 50,803 Boe/d, or 26% greater than 2018 production.  This represents annual production per weighted average share which was 6% greater than the prior year;
• Achieved $70.1 million adjusted funds flow in the quarter, including over $17 million of free adjusted funds flow (net of capital expenditures);
• Achieved record 2019 adjusted funds flow of $266 million ($1.18/share, basic);
• Achieved adjusted funds flow netbacks of $14.34/Boe for 2019;
• Executed a successful 2019 capital expenditure program of $302 million, including $53 million in facilities expenditures and the drilling of 34 (34.0 net) wells in our condensate rich Wapiti Montney play.  This level of capital is at the bottom of our original guidance range of $300 - $325 million;
• Reduced total annual operating expenses to $9.61/Boe; and
• Achieved annual net G&A expenses of $0.91/Boe, continuing our long term trend of significant improvement with a reduction of 24% compared to 2018 G&A per Boe expenses.

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

NuVista is pleased to report the 2019 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, growth in Montney Reserves and addition of reserves and resources in the Charlie Lake, an emerging light oil play.

• Achieved record Proven Developed Producing (“PDP”) F&D costs of $10.26/Boe which was driven by continued well cost reductions, positive technical revisions to existing reserves of 2.3% and continued strong well results; 
• Total Proven Plus Probable (“TP+PA”) F&D costs were $8.94/Boe, driven by positive technical revisions of 3.3% and robust undeveloped Montney location additions in Pipestone;
• Generated PDP and TP+PA recycle ratios of 1.7x and 1.9x based on 2019 operating netback of $17.06/Boe;
• Increased PDP and TP+PA reserves per basic share by 13% and 10% respectively to reach total reserve volumes of 95 MMBoe and 594 MMBoe, respectively;
• Increased our robust inventory of TP+PA undeveloped Montney locations to 376. This reflects 10 years of booked inventory and includes an increase in Pipestone locations by 14% to 144;
• Achieved a reserves replacement ratio of 160% and 400% on a PDP and TP+PA basis, respectively, resulting in a TP+PA reserves life index (“RLI”) of over 27 years, and;
• Recognized the first reserve and resource additions in the emerging Charlie Lake Light Oil Play. Two PDNP and 22 undeveloped locations were booked. The undeveloped locations were booked on a gross TP+PA basis at 363 MBoe per well (51% oil) and $4.2MM cost to drill, complete, equip & tie-in.  In addition, 225 gross locations have been booked in  the  Best Estimate Development Pending Contingent Resource category for a total risked volume of 45.9 MMBoe.

The detailed summary of our year end 2019 reserves disclosure is included further below, and will be included in our Annual Information Form which will be filed on or before March 30, 2020 at www.SEDAR.com.

Excellence in Operations

Despite a late start to the winter drilling season due to adverse weather conditions, we are pleased to report that operations across our entire asset base have caught up to schedule as we progress through the first quarter of 2020. A total of 30 new Montney wells will be rig-released prior to the end of the second quarter.  15 of these wells are expected to be on-stream throughout the first and second quarters of 2020.  The remainder will come on stream towards the end of the year.  Importantly, the majority of the activities which comprise our 2020 production additions will be completed in mid-year, creating ample flexibility to select capital spending levels for the second half of the year commensurate with commodity pricing and adjusted funds flow levels as they unfold.

Pipestone

Production from the greater Pipestone area averaged 19,600 Boe/d in the fourth quarter of 2019 (25% condensate), up from 9,600 Boe/d when the property was purchased in the fourth quarter of 2018.  With new pads coming onstream in Pipestone South and North throughout 2020, production is expected to ramp to well over 25,000 Boe/d by the end of 2020.

At Pipestone North, we currently have two rigs drilling a 12-well pad, with completions scheduled to take place over the summer.  The pad is expected to start up in the mid-fourth quarter of 2020 commensurate with the startup of the new Pipestone North Compressor Station and the new pipeline to the Hythe Gas Plant.  All major project milestones are currently on budget and on schedule.  The capacity for this first phase of the compressor station will be approximately 12,500 Boe/d.

Water sourcing and disposal activities have proceeded exceptionally well in the area. We have successfully completed construction of our water storage complex and are in the process of connecting both a non-potable water source well and a produced water deep disposal well.  These projects reduce completion capital and operating costs while enhancing our ESG performance through the reduction of freshwater use, the elimination of truck traffic dust and noise on local roads, and the commensurate reduction in GHG emissions.

As previously reported, NuVista experienced challenging third-party Pipestone midstream outages during the fourth quarter of 2019, which reduced average quarterly production by approximately 2,000 Boe/d.  Sporadic downtime has continued through the first quarter of 2020 as midstream issues are worked through.

At Pipestone South, our initial 11 wells have now reached IP90 (an 8-well pad and a 3-well pad). Our third pad (6 wells) has been drilled and completed and has recently come on production in the first quarter of 2020. The total cost to drill, complete, equip, and tie-in our third pad averaged $6.5MM per well. On a length-normalized basis, a cost reduction of 11% per well was observed compared to the first 11 wells in Pipestone South despite increasing proppant intensity by 30%. The IP90 results are shown below:

Pipestone South IP90 Table	Average Hz. Length	Raw Gas	Condensate	Condensate Gas Ratio	Total	DCET Capital
	Meters	MMcf/d	Bbls/d	Bbls/MMcf	Boe/d	$MM
11-well Average	2,070	6,000	443	72	1,230	$	6.8
Rich type curve	3,000	7,000	515	74	1,654	$	8.4

Wapiti

Production from the Wapiti area has been steady through the fourth quarter of 2019 and into early 2020 at approximately 35,000 Boe/d including 32% condensate.  Our intention is to keep volumes in the Wapiti area relatively flat by offsetting natural declines with the startup of several newly drilled pads in the first and second quarters of 2020.  A new 2-well pad at Bilbo has recently come online and it is expected to be followed by 4 additional wells in the third quarter. 4 wells at Elmworth and 3 wells at Gold Creek are scheduled to come on-stream during the second quarter. 

Notable performance milestones have been reached in both Bilbo and Elmworth.  Five wells reached IP365 at Bilbo, producing an average of 295 Bbls/d of condensate.  This is within 4% of the Bilbo historic average condensate rate, but these wells were executed with drilling and completion (D&C) cost per horizontal meter 16% lower than our historic average.  At Elmworth, six wells reached their IP180 milestone. The D&C costs for these wells were 34% below our historic average for the area, while condensate rates averaged 324 Bbls/d which is 33% above the historic Elmworth average.

Keeping The Balance Sheet Strong

Continued growth in our Montney resource base through 2019, confidence in its productive characteristics, and the steps taken by NuVista to access a diverse market portfolio has given our lenders the confidence to increase and extend our credit facility in the fourth quarter.  The facility tenure was improved to a two-year term and the borrowing capacity was increased from $500 to $550 million.  As at December 31, 2019, NuVista had drawn approximately 55% of facility capacity.  Including our senior unsecured notes, NuVista’s net debt was $562 million which corresponded to a net debt to 12 month trailing adjusted funds flow ratio of 2.1x.  As the new production from Pipestone North is brought online and adjusted funds flow is increased, NuVista anticipates returning below a net debt to adjusted funds flow ratio of 2.0x as we continue to drive back to our target of 1.5x.

Significant Commodity Price Diversification and Risk Management

NuVista continues to benefit from the discipline of our strong rolling hedge program during this period of volatile commodity prices.  World oil prices had been strengthening based on reduced Permian basin production growth rates, U.S. sanctions upon Venezuela and Iran, and OPEC production discipline.  The unexpected onset of the Coronavirus in Asia then had an immediate negative effect on world oil demand and prices.  While it is not yet known what the duration will be, history leads us to believe that the effect will be reasonably short-lived.  Natural gas pricing at NYMEX and other US hubs has in general been weaker lately due to growth in production and a mild winter.  In contrast, AECO basin prices have been relatively strong as a result of reduced production and storage levels, and the continued debottlenecking and expansions on the NGTL system.  As always, we will rely upon our meaningful price diversification and risk management contracts to attenuate short term volatility in commodity prices.  We currently possess hedges which, in aggregate, cover 57% of projected 2020 liquids production at a WTI floor price of C$77.24/Bbl and 46% of projected 2020 gas production at a price of C$1.90/GJ (hedged and exported volumes converted to an AECO equivalent price).  These percentage figures relate to production net of royalty volumes.

ESG Progress Continues

We are proud to have demonstrated our commitment to transparency and ethical practices in our inaugural Environmental, Social, and Governance (“ESG”) report earlier in 2019.  This report, available for viewing on NuVista’s website, provides a comprehensive look at NuVista’s ESG practices while highlighting the proactivity and excellent execution our teams have always demonstrated in advancement of our ESG performance. Key highlights of the report include our high safety and environmental performance, our long term progress in reducing GHG intensity, and our strong governance and community focus. Approximately 70% 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 below the North American benchmark.  We continue to execute projects to enhance our ESG progress, and we look forward to providing updated ESG reporting in the future.

Board and Committee Changes

In pursuit of board renewal and new exposures, we would like to announce some key board and committee changes.  Mr. Keith MacPhail has decided to step down as board Chair at NuVista’s upcoming annual general meeting in May, but will stand for election again as a director.  We would like to take this opportunity to thank Mr. MacPhail for his long and dedicated leadership as Chair of our board since 2003.  The board is pleased to announce that Mr. Pentti Karkkainen, who has served as a director for NuVista since 2003, has agreed to serve as Chair of the Board commencing in May.

In addition, we are  pleased to announce recent changes to our Board committees in light of our increased focus on ESG initiatives.  We have established an ESG  Committee, the members of which will be: Mr. Sheldon Steeves (Chair), Mr. Brian Shaw, Ms. Debbie Stein and Mr. Grant Zawalsky.  We have also combined our Compensation Committee and our Governance and Nominating Committee into our Corporate Governance & Compensation Committee, the members of which will be: Mr. MacPhail (Chair), Mr. Karkkainen, Mr. Ron Eckhardt and Mr. Ron Poelzer.  There are no changes to the composition or mandates of the other board committees at this time.

2020 Guidance Re-Affirmed, But Monitoring Commodity Price Pressure

NuVista is pleased to provide an update on our 2020 plans in light of the extreme volatility in the current commodity markets. The primary governor on our annual plan will remain as always to maintain the balance between capital spending and adjusted funds flow in order to protect the balance sheet first. This then allows us to grow production volumes at a comfortable pace commensurate with the flexibility in our future volume commitments.

Our 2020 guidance range is for production of 57,000 Boe/d with capital spending of $300 million, and up to 61,000 Boe/d with capital spending of $330 million, representing over 15% annual growth at midpoint.  Although the WTI oil benchmark price has suffered a steep decline recently, our strong current hedge position and improved condensate differentials dampen the impact of pricing volatility. We expect that if current prices prevail, our projected capital spending would need to be adjusted to the bottom of the aforementioned range to ensure it remains within +/-10% of adjusted funds flow.  If prices continue to deteriorate, we can use our significant development plan flexibility to reduce capital spending further.  In this case, we do not anticipate that 2020 production would be suppressed below 57,000 Boe/d since late-year capital spending contributes little to current year production.

As anticipated, we expect capital spending of $200 million in the first half of 2020.  Due to favorable weather, two pads in Elmworth and Gold Creek will be completed by the end of March instead of April, bringing projected first quarter spending up to $150 million, and second quarter down to $50 million.  We will monitor pricing and adjusted funds flow and will provide a spending plan update in the spring.  This will in part be based upon the performance and phasing of the 15 wells which are expected to come online prior to the end of the second quarter.  We believe it is prudent to maintain the winter drilling season unchanged while monitoring commodity price changes, with any potential adjustments to capital spending to take effect after spring breakup.  We will revisit our capital guidance at that time to ensure financial flexibility remains intact, incurring little to no incremental debt during the year.

As previously communicated, we expect the third party downtime issues which are affecting production in the first quarter, to gradually improve towards the spring.  In addition, we have been required to temporarily shut in certain producing wells for fracture treatments on adjacent newly drilled wells in Pipestone and other areas.  As a result, the first quarter is expected to average in the range of 50,000 – 54,000 Boe/d and the second quarter in the range of 58,000 – 62,000 Boe/d.  These figures are unchanged as compared to previous guidance.

NuVista has top quality assets and a management team focused upon relentless improvement. We are excited to continue pursuing our Montney development plan. We will continue to adjust the annual pace of growth as needed to ensure 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 4, 2020.  NuVista’s financial statements, notes to the financial statements and management’s discussion and analysis for the year ended December 31, 2019, will be filed on SEDAR (www.sedar.com) under NuVista Energy Ltd. on March 3, 2020 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 $/Boe)	2019			2018			% Change		2019			2018			% Change
FINANCIAL
Petroleum and natural gas revenues	156,479			143,006			9		561,095			555,849			1
Adjusted funds flow (1) (2)	70,080			63,635			10		265,851			264,448			1
Per share - basic	0.31			0.28			11		1.18			1.39			(15	)
Per share - diluted	0.31			0.28			11		1.18			1.38			(14	)
Net earnings (loss)	(29,557	)		104,086			(128	)	(63,833	)		136,245			(147	)
Per share - basic	(0.13	)		0.46			(128	)	(0.28	)		0.71			(139	)
Per share - diluted	(0.13	)		0.46			(128	)	(0.28	)		0.71			(139	)
Total assets									2,331,361			2,180,874			7
Assets acquired	—			1,679			—		—			619,444			—
Capital expenditures (2)	52,814			77,433			(32	)	301,822			340,792			(11	)
Net debt (1) (2)									561,975			511,408			10
End of period basic common shares outstanding									225,592			225,306			—
OPERATING
Daily Production
Natural gas (MMcf/d)	204.3			174.3			17		182.3			144.7			26
Condensate & oil (Bbls/d)	17,195			14,766			16		15,170			12,674			20
NGLs (Bbls/d) (3)	5,769			5,246			10		5,246			3,554			48
Total (Boe/d)	57,010			49,060			16		50,803			40,353			26
Condensate, oil & NGLs weighting	40		%	41		%			40		%	40		%
Condensate & oil weighting	30		%	30		%			30		%	31		%
Average selling prices (4) (5)
Natural gas ($/Mcf)	2.74			3.69			(26	)	2.78			3.51			(21	)
Condensate & oil ($/Bbl)	62.51			51.60			21		64.06			70.92			(10	)
NGLs ($/Bbl)	11.51			28.53			(60	)	11.06			32.83			(66	)
Netbacks ($/Boe)
Petroleum and natural gas revenues	29.83			31.69			(6	)	30.26			37.74			(20	)
Realized gain (loss) on financial derivatives	0.75			(2.37	)		—		0.94			(2.60	)		—
Royalties	(1.82	)		(1.07	)		70		(1.49	)		(1.10	)		35
Transportation expenses	(2.83	)		(2.93	)		(3	)	(3.04	)		(3.06	)		(1	)
Operating expenses	(9.63	)		(9.06	)		6		(9.61	)		(9.75	)		(1	)
Operating netback (2)	16.30			16.26			—		17.06			21.23			(20	)
Corporate netback (2)	13.37			14.11			(5	)	14.34			17.96			(20	)
SHARE TRADING STATISTICS
High	3.24			7.75			(58	)	5.19			9.89			(48	)
Low	1.86			3.38			(45	)	1.39			3.38			(59	)
Close	3.19			4.08			(22	)	3.19			4.08			(22	)
Average daily volume ('000s)	769,852			1,153,619			(33	)	1,212,077			719,389			68

1. Refer to Note 18 "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.
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". 
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, 2020 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	364,079	33,511	669	94,860
Developed non‑producing	59,375	5,025	279	15,200
Undeveloped	969,971	79,644	2,072	243,379
Total proved	1,393,425	118,180	3,021	353,438
Probable	960,109	77,227	3,066	240,311
Total proved plus probable	2,353,534	195,407	6,087	593,749

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 2019 year end working interest reserves with the working interest reserves reported in the 2018 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, 2018	1,274,334		110,365		1,826		324,580
Exploration and development(2)	120,639		10,395		1,612		32,113
Technical revisions	65,117		4,881		(260	)	15,474
Acquisitions	-		-		-		-
Dispositions	-		-		-		-
Economic Factors	(118	)	(166	)	1		(185	)
Production	(66,548	)	(7,295	)	(157	)	(18,543	)
Balance, December 31, 2019	1,393,425		118,180		3,021		353,438
Total proved plus probable Total proved plus probable
Balance, December 31, 2018	2,130,548		180,213		2,425		537,728
Exploration and development(2)	214,268		16,771		4,230		56,712
Technical revisions	75,355		5,734		(411	)	17,882
Acquisitions	-		-		-		-
Dispositions	-		-		-		-
Economic Factors	(90	)	(15	)	-		(30	)
Production	(66,548	)	(7,295	)	(157	)	(18,543	)
Balance, December 31, 2019	2,353,534		195,407		6,087		593,749

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
2020	156,311	184,740
2021	479,741	516,206
2022	497,545	560,655
2023	494,141	541,459
2024	394,596	429,165
Remaining	-	875,988
Total (Undiscounted)	2,022,335	3,108,211

NOTE:

⁽¹⁾        Numbers may not add due to rounding.

The following table outlines NuVista's corporate finding, development and acquisition costs in more detail:

	3 Year-Average (1)				2019 (1)				2018 (1)
			Proved plus				Proved plus				Proved plus
	Proved		probable		Proved		probable		Proved		probable
Finding and development costs ($/Boe)	$	9.05	$	7.45	$	10.30	$	8.94	$	7.80	$	6.43
Finding, development and acquisition costs ($/Boe)	$	10.24	$	8.04	$	10.30	$	8.94	$	10.33	$	8.22

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, 2019 and based on published GLJ future price forecast as at January 1, 2020 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	1,292,957		1,074,708		894,066		766,667		675,143
Developed non‑producing	235,812		171,698		134,355		110,644		94,428
Undeveloped	3,024,261		1,743,436		1,081,329		705,077		473,909
Total proved	4,553,030		2,989,842		2,109,750		1,582,388		1,243,480
Probable	3,995,971		1,895,163		1,070,610		684,758		477,200
Total proved plus probable	8,549,000		4,885,004		3,180,360		2,267,147		1,720,679

⁽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, 2020:

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
2020		2.08		2.42	2.32		77.80			28.68		48.76	61.00	71.71	0.76
2021		2.35		2.75	2.65		79.22			31.09		51.82	63.00	74.03	0.77
2022		2.55		2.90	2.80		83.33			34.62		54.62	66.00	76.92	0.78
2023		2.65		3.00	2.90		86.54			36.06		56.89	68.00	80.13	0.78
2024		2.75		3.10	3.00		89.10			37.21		58.71	70.00	82.69	0.78
2025		2.85		3.20	3.10		91.67			38.37		60.53	72.00	85.26	0.78
2026		2.91		3.27	3.17		94.23			39.52		62.35	74.00	87.82	0.78
2027		2.97		3.33	3.23		96.55			40.56		64.00	75.81	90.14	0.78
2028		3.03		3.40	3.30		98.50			41.44		65.38	77.33	92.09	0.78
2029		3.09		3.47	3.37		100.49			42.33		66.79	78.88	94.08	0.78
2030+		+2.0%/yr		+2.0%/yr	+2.0%/yr		+2.0%/yr			+2.0%/yr		+2.0%/yr	+2.0%/yr	+2.0%/yr	0.78

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.

Charlie Lake Resource Evaluation

Risked and Unrisked ECR Development Pending (1)(2)(3)(4)(5)	Chance of Development		Best Estimate Unrisked	Best Estimate Risked
Solution Gas (MMcf)	81	%	89.4	72.4
Natural Gas Liquids (MMBbls)	81	%	12.1	9.8
Oil (MMBbls)	81	%	29.7	24.1
Oil Equivalent (MMBoe)	81	%	56.7	45.9
Before tax NPV ($ millions)
Undiscounted			1,210	980
Discounted at 10%			428	347

1. All volumes listed in the table are company gross and sales volumes.
2. Estimated contingent resource as per GLJ Independent Resource Evaluation as of December 31, 2019 and based on GLJ forecast pricing and foreign exchange rates at January 1, 2020.
3. Risk in the above table is the chance of development. In quantifying the chance of development, factors that were assessed quantitatively to be less than one in the risking calculation included the economic status, the development plan and the development time frame.
4. Contingent resources are discovered resources by definition.
5. There is uncertainty that it will be commercially viable to produce any portion of the resources.

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, recycle ratio, reserves replacement ratio and RLI, 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. Recycle ratio has been calculated by dividing operationing netback  (refer to Non-GAAP Measurements) by F&D costs and FD&A costs per Boe for the applicable period.

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. NuVista has presented the Pipestone ‘Rich’ type curve for the Pipestone development block.  For the Pipestone development block the rich type curve presented is based partially on initial drilling results but due to the early stage of development, primarily on drilling results from analogous Montney developments located in close proximity to such area.

Such type curves 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 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 by GLJ Petroleum Consultants Ltd. ("GLJ") for NuVista's most recent independent reserves evaluation as of December 31, 2018 for the Pipestone development block had a lower estimate of estimated ultimate recovery than the type curves presented herein; however, the production forecasts in such independent reserves evaluation are also lower than NuVista's current production as well as the production forecasts prepared by management.

For the Pipestone development block, this release includes wells associated with the Rich type curve which refers to wells that are expected to have a high relative content of condensate production. The type curves and well economics associated with Rich 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 is still in the early days of piloting extended reach horizontals and high intensity facture techniques and in the early stages of development in respect of the Pipestone development block. As such there is no certainty that such results will be achieved or that NuVista will be able to optimize such drilling results to achieve the optimized type curves, well economics and estimated ultimate recoverable volumes described. In this presentation, estimated ultimate recovery represents the estimated ultimate recovery associated with the type curves presented; however, there is no certainty that NuVista will ultimately recover such volumes from the wells it drills.

Resources Disclosure

Resources estimates presented herein have been prepared by GLJ, NuVista’s independent qualified reserves evaluators, in accordance with the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook"), have an effective date of December 31, 2019, based on forecast prices and costs and have been presented on a net basis, representing NuVista’s working interest share before royalties.

Resources volumes attributed to NuVista’s CLLK properties are estimates only. There is no assurance that the estimated resources can or will be recovered. Actual resources may be greater or less than those estimated, and the difference may be material.

The determination of oil and gas resources involves estimating subsurface accumulations of oil, natural gas liquids and natural gas that cannot be exactly measured. The preparation of estimates is subject to an inherent degree of associated risk and uncertainty, including factors that are beyond NuVista’s control. The estimation and classification of resources is a complex process involving the application of professional judgment combined with geological and engineering knowledge to assess whether specific classification criteria have been satisfied. It requires significant judgments based on available geological, geophysical, engineering, and economic data as well as forecasts of commodity prices and anticipated costs. As circumstances change and additional data becomes available, whether through the results of drilling, testing and production or from economic factors such as changes in product prices or development and production costs, reserves estimates also change. Revisions may be positive or negative.

Certain contingencies currently prevent the classification of NuVista’s contingent resources as reserves. The 45.9 MMboe Best Estimate Contingent Resources disclosed in this news release include NuVista’s Risked Best Estimate Development Pending Contingent Resources in NuVista's Charlie Lake properties. The product types associated with NuVista’s contingent resources include approximately 52% light oil, 21% natural gas liquids and 27% natural gas.

All of NuVista’s contingent resources disclosed in this news release have been sub-classified as “Development Pending”, which applies in circumstances where resolution of the final conditions for development is being actively pursued and indicates a relatively high chance of development versus the other sub-classifications.

All of NuVista’s contingent resources have been risked using an 81% chance of development. In quantifying the chance of development, the factors that were assessed quantitatively to be less than one in the development risk calculation included the economic, the development plan, and the development time frame. The chance of development multiplied by the unrisked resource volume estimate yields the risked resource volume estimate. As many of these factors have a wide range of uncertainty and are difficult to quantify, the chance of development is an uncertain value that should be used with caution.

Continuous development through multi-year exploration and development programs and significant levels of future capital expenditures are required in order for additional resources to be recovered in the future. The principal risks that would inhibit the recovery of additional reserves relate to the potential for variations in the quality of the CLLK formation where minimal well data currently exists, access to the capital required to develop the resources, low commodity prices that would curtail the economics of development, future performance of wells, regulatory approvals, access to required services at an appropriate cost, and the effectiveness of well fracturing technology and applications. For contingent resources to be converted to reserves, NuVista must ascertain commercial production rates, then develop firm plans, including with respect to timing, infrastructure and the commitment of capital. Confirmation of commercial productivity is generally required before NuVista can prepare firm development plans and commit required capital for the development of the contingent resources. Additional contingencies relate to infrastructure build-out requirements to develop the resources in a relatively quick time frame. As continued delineation occurs, some resources currently classified as contingent resources are expected to be re-classified to reserves.

The estimated cost reflected in GLJ evaluation of NuVista’s contingent resources to bring on commercial production from the Risked Best Estimate Development Pending Contingent Resources is approximately $791 million (when discounted at 10%, the estimated cost is approximately $473 million). The expected timeline to bring these resources on production is between the years 2021 and 2031 (in accordance with a pre-development study). Best Estimate Development Pending Contingent Resources are expected to be recovered using horizontal drilling and multi-stage fracturing.

The estimates of contingent resources provided herein are estimates only and there is no guarantee that the estimated contingent resources will be recovered. Actual contingent resources may be greater or less than the estimates provided in this news release, and the differences may be material. The estimates of contingent for individual properties may not reflect the same confidence level as estimates of contingent for all properties, due to the effects of aggregation. There is no assurance that the forecast price and cost assumptions applied by GLJ in evaluating NuVista’s contingent resources will be attained and variances could be material. There is uncertainty that it will be commercially viable to produce any portion of the contingent resources described herein, or that NuVista will produce any portion of the volumes currently classified as contingent resources.

Advisory regarding forward-looking information and statements

This news 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 news release contains forward looking statements, including management's assessment of: NuVista’s future focus, strategy, plans, opportunities and operations; production decline rates; Pipestone ‘Rich’ type curve expectations; anticipated costs to drill, complete, equip, and tie in ‘Rich’ type curve wells; expected condensate yields; completion plans and timing; expectations regarding the startup of the new Pipestone North Compressor Station and the new pipeline and Hythe Gas Plant expansion; expected capacity of the Pipestone North Compressor Station; plans to continue with source and disposal water well drilling and completions in Pipestone North, as well as pond infrastructure to underpin low cost operations with minimum trucking traffic for reduced GHG emissions, reduced surface fresh water usage, and diminished community noise in accordance with our ESG initiatives; the benefits of NuVista's rolling hedging program; future AECO exposure; anticipated future third-party Pipestone midstream outages; 2020 production; expected factors affecting first quarter production and the anticipated impact; anticipated on stream dates of the 15 new wells planned in 2020; 2020 capital expenditures and expected adjusted funds flow;  plans to return to targeted net debt to adjusted funds flow ratio of 1.5x to 2.0x; future commodity prices; drilling inventories; plans to continue pursuing our Montney growth plan; plans to adjust the annual pace of growth as needed to ensure balance sheet strength comes first, and that the profitability of that growth per share is always maximized and the timing of the release of our updated corporate presentation.

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, production curtailment and royalties; the ability to access sufficient capital from internal sources and bank and equity markets; 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 news 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

Within the news release, references are made to terms commonly used in the oil and natural gas industry.  Management uses "adjusted funds flow", "adjusted funds flow per share", “adjusted funds flow netback”, "operating netback", "corporate netback", "capital expenditures", "net debt” and “net debt to 12 month trailing adjusted funds flow” 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 measurements" contained in NuVista's MD&A for the year ended December 31, 2019.

Basis of presentation

Unless otherwise noted, the financial data presented 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. Natural gas is converted to a barrel of oil equivalent (“Boe”) using six thousand cubic feet of gas to one barrel of oil. In certain circumstances natural gas liquid volumes have been converted to a thousand cubic feet equivalent (“Mcfe”) on the basis of one barrel of natural gas liquids to six thousand cubic feet of gas.  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, 2019. 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.

This press release discloses drilling inventory in three categories: (i) proved locations; (ii) probable locations, and; (iii) best estimate contingent drilling locations. Proved and probable locations are derived from a report prepared by GLJ, NuVista’s independent qualified reserves evaluator, evaluating NuVista’s reserves as of December 31, 2019, and account for undeveloped drilling locations that have associated proved and/or probable reserves, as applicable. Best estimate contingent drilling locations are derived from a report prepared by GLJ evaluating NuVista’ s contingent resources as of December 31, 2019 ("GLJ Contingent Resource Report"), and account for drilling locations that have associated best estimate 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 including timing, infrastructure spending and the commitment of capital. Determination of productivity levels is generally required before the company can prepare firm development plans and commit required capital for the development of the contingent resources. There is uncertainty that it will be commercially viable to produce any portion of the contingent resources.

FOR FURTHER INFORMATION CONTACT:

Jonathan A. Wright
President and CEO
[phone]     

Ross L. Andreachuk
VP, Finance and CFO
[phone]             

Mike J. Lawford
Chief Operating Officer
[phone]