Market Overview

Baytex Announces First Quarter 2020 Financial and Operating Results

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CALGARY, Alberta, May 07, 2020 (GLOBE NEWSWIRE) -- Baytex Energy Corp. ("Baytex")((TSX, NYSE:BTE) reports its operating and financial results for the three months ended March 31, 2020 (all amounts are in Canadian dollars unless otherwise noted).

"As an industry, we are facing an unprecedented challenge due to the effects of COVID-19 and the significant degradation and volatility in global crude oil prices. In response, Baytex has moved to ensure the safety and health of our people and to maintain liquidity, minimize capital outlays and emphasize cost reductions across all facets of our business. We have taken actions to achieve $135 million of cost reductions and have shut-in approximately 25,000 boe/d of production, which will have a positive impact on our adjusted funds flow and financial liquidity," commented Ed LaFehr, President and Chief Executive Officer.

Q1 2020 Highlights

  • Generated production of 98,452 boe/d (83% oil and NGL).
  • Delivered adjusted funds flow of $133 million ($0.24 per basic share).
  • Issued US$500 million principal amount of 8.75% senior unsecured notes due April 1, 2027.
  • Redeemed US$400 million principal amount of 5.125% senior unsecured notes due 2021 and $300 million principal amount of 6.625% senior unsecured notes due 2022.
  • Extended the maturity of our credit facilities to April 2, 2024. The credit facilities total approximately $1.1 billion and do not require annual or semi-annual reviews.
  • Maintained undrawn credit capacity of $417 million and liquidity, net of working capital, of $315 million.

2020 Outlook

We previously announced a 50% reduction in our capital spending for this year to $260 to $290 million, from $500 to $575 million. With this revised capital program, we have suspended drilling and completion operations in Canada and expect to see a moderated pace of activity in the Eagle Ford. We are also intensely focused on driving further efficiencies in our operations. We have taken actions to achieve $135 million of cost reductions for 2020 relating to operating, transportation and general & administrative expenses.

In order to optimize the value of our resource base, we are voluntarily shutting-in approximately 25,000 boe/d of production (3,500 boe/d previously) of which 80% is heavy oil. At current commodity prices, the shut-in of these barrels will have a positive impact on our adjusted funds flow and improve our financial liquidity. Our current expectation is that the majority of these volumes will remain off-line for the balance of this year. Should operating netbacks change, we have the ability to shut-in additional volumes or restart wells in short order. Taking into account the incremental shut-in volumes, we have revised our production guidance range for 2020 to 70,000 to 74,000 boe/d, from 85,000 to 89,000 boe/d previously.

The situation around the COVID-19 virus continues to evolve. We have implemented a number of measures to foster resilience through these unpredictable times, including a work-from-home program and altering shifts in the field. We are focused on protecting the health and safety of our personnel while maintaining our operations and, to date, have had no positive cases of COVID-19 within the company. 


  Three Months Ended
    March 21, 2020
    December 31, 2019
  March 31, 2019
FINANCIAL              
(thousands of Canadian dollars, except per common share amounts)              
Petroleum and natural gas sales $ 336,614   $ 445,895   $ 453,424  
Adjusted funds flow (1) 132,935   232,147   220,770  
Per share - basic 0.24   0.42   0.4  
Per share - diluted 0.24   0.42   0.4  
Net income (loss) (2,498,217 ) (117,772 ) 11,336  
Per share - basic (4.46 ) (0.21 ) 0.02  
Per share - diluted (4.46 ) (0.21 ) 0.02  
       
Capital Expenditures      
Exploration and development expenditures (1) $ 176,777   $ 153,117   $ 153,843  
Acquisitions, net of divestitures (40 ) 563   -  
Total oil and natural gas capital expenditures $ 176,737   $ 153,680   $ 153,843  
                   
Net Debt                  
Bank loan (2) $ 678,740   $ 506,471   $ 550,751  
Long-term notes (2) 1,270,800   1,337,200   1,569,153  
Long-term debt 1,949,540   1,843,671   2,119,904  
Working capital deficiency 102,077   28,120   55,337  
Net debt (1) $ 2,051,617   $ 1,871,791   $ 2,175,241  
       
Shares Outstanding - basic (thousands)      
Weighted average 559,804   558,228   555,438  
End of period 560,483   558,305   555,872  
                   
                   
BENCHMARK PRICES                
Crude oil                 
WTI (US$/bbl)  $ 46.17   $ 56.96     54.90  
MEH oil (US$/bbl)  49.54   60.04      60.46  
MEH oil differential to WTI (US$/bbl) 3.37   3.08      5.56  
Edmonton par ($/bbl) 51.43   68.10      66.53  
Edmonton par differential to WTI (US$/bbl) (7.92 ) (5.37 )   (4.85 )
WCS heavy oil ($/bbl)  34.48   54.29      56.64  
WCS differential to WTI (US$/bbl) (20.53 ) (15.83 )   (12.29 )
Natural gas              
NYMEX (US$/mmbtu)  $ 1.95   $ 2.50   $ 3.15  
AECO ($/mcf)  2.14     2.34      1.94  
                 
CAD/USD average exchange rate 1.3445     1.3201      1.3293  
               


   
  Three Months Ended
  March 31, 2020
  December 31, 2019   March 31, 2019  
OPERATING      
Daily Production      
Light oil and condensate (bbl/d) 45,717   43,906   45,048  
Heavy oil (bbl/d) 28,854   27,050   26,891  
NGL (bbl/d) 7,822   8,699   11,729  
Total liquids (bbl/d) 82,393   79,655   83,668  
Natural gas (mcf/d) 96,356   100,235   104,682  
Oil equivalent (boe/d @ 6:1) (3) 98,452   96,360   101,115  
       
Netback (thousands of Canadian dollars)      
Total sales, net of blending and other expense (4) $ 315,257   $ 427,728   $ 436,636  
Royalties (56,720 ) (77,282 ) (81,325 )
Operating expense (104,470 ) (99,573 ) (100,292 )
Transportation expense (10,342 ) (8,840 ) (13,330 )
Operating netback (1) $ 143,725   $ 242,033   $ 241,689  
General and administrative (9,775 ) (9,893 ) (14,136 )
Cash financing and interest (28,535 ) (24,389 ) (28,184 )
Realized financial derivatives gain (loss) 26,850   22,956   18,814  
Other (5) 670   1,440   2,587  
Adjusted funds flow (1) $ 132,935   $ 232,147   $ 220,770  
       
Netback (per boe)      
Total sales, net of blending and other expense (4) $ 35.19   $ 48.25   $ 47.98  
Royalties (6.33 ) (8.72 ) (8.94 )
Operating expense (11.66 ) (11.23 ) (11.02 )
Transportation expense (1.15 ) (1.00 ) (1.46 )
Operating netback (1) $ 16.05   $ 27.30   $ 26.56  
General and administrative (1.09 ) (1.12 ) (1.55 )
Cash financing and interest (3.19 ) (2.75 ) (3.10 )
Realized financial derivatives gain (loss) 3.00   2.59   2.07  
Other (5) 0.07   0.16   0.28  
Adjusted funds flow (1) $ 14.84   $ 26.18   $ 24.26  

Notes:

(1)  The terms "adjusted funds flow", "exploration and development expenditures", "net debt" and "operating netback" do not have any standardized meaning as prescribed by Canadian Generally Accepted Accounting Principles ("GAAP") and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. See the advisory on non-GAAP measures at the end of this press release.
(2) Principal amount of instruments. The carrying amount of debt issue costs associated with the bank loan and long-term notes are excluded on the basis that these amounts have been paid by Baytex and do not represent an additional source of capital or repayment obligations.
(3) Barrel of oil equivalent ("boe") amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. The use of boe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(4) Realized heavy oil prices are calculated based on sales dollars, net of blending and other expense. We include the cost of blending diluent in our realized heavy oil sales price in order to compare the realized pricing on our produced volumes to the WCS benchmark.
(5) Other is comprised of realized foreign exchange gain or loss, other income or expense, current income tax expense or recovery and payments on onerous contracts. Refer to the Q1/2020 MD&A for further information on these amounts.
   

Q1/2020 Results

Market conditions changed dramatically over the course of the first quarter and we moved quickly to adjust our business plan. We curtailed exploration and development spending in March, which resulted in first quarter capital spending of $177 million, 12% lower than our original expectation of $200 million. Approximately 70% of our capital was directed toward our operated assets in Canada, where we had an active program in both the Viking and Heavy Oil.   

We successfully executed our first quarter drilling program and delivered operating results consistent with our expectations. We participated in the drilling of 124 (108.0 net) oil wells with a 100% success rate during the first quarter.

Production during the first quarter averaged 98,452 boe/d (83% oil and NGL), as compared to 96,360 boe/d (83% oil and NGL) in Q4/2019. Production in Canada averaged 62,262 boe/d (87% oil and NGL), as compared to 57,794 boe/d in Q4/2019, while production in the Eagle Ford averaged 36,190 boe/d (77% oil and NGL), as compared to 38,566 boe/d in Q4/2019.

We delivered adjusted funds flow of $133 million ($0.24 per basic share) in Q1/2020 and generated an operating netback of $16.05/boe. The Eagle Ford generated an operating netback of $22.78/boe and our Canadian operations generated an operating netback of $12.12/boe.

We identified indicators of impairment in Q1/2020 due to the sharp decline in crude oil prices and the economic uncertainty associated with the COVID-19 pandemic. As a result, we recorded total impairments of $2,716 million as the carrying value of our oil and gas properties exceeded their recoverable amounts. This impairment resulted in a net loss of $2,498 million in the first quarter. Revisions to forecast crude oil prices could result in reversals or additional impairment charges in the future.

Eagle Ford and Viking Light Oil

In the Eagle Ford, strong well performance continued across our acreage position. In Q1/2020, we participated in the drilling of 17 (3.8 net) wells and commenced production from 30 (6.1 net) wells. The wells brought on-stream during Q1/2020 generated an average 30-day initial production rate of approximately 1,875 boe/d per well. We expect to bring approximately 16 to 18 net wells on production in the Eagle Ford in 2020, down from our original guidance of 22 net wells. 

Production in the Viking averaged 24,696 boe/d (92% oil and NGL) during Q1/2020, as compared to 22,050 boe/d in Q4/2019. In Q1/2020, we invested $79 million on exploration and development in the Viking and commenced production from 83 (78.5 net) wells. We have suspended all drilling and completion activity in the Viking. We have also voluntarily shut-in approximately 15% of our Viking production for the months of April and May. These shut-in volumes will be evaluated monthly and we currently anticipate production resuming in the second half of the year.   

Heavy Oil

Our heavy oil assets at Peace River and Lloydminster produced a combined 31,211 boe/d (93% oil and NGL) during the first quarter, as compared to 29,707 boe/d in Q4/2019. In Q1/2020, we invested $37 million on exploration and development, drilled 33 (33.0 net) wells and commenced production from 2 (2.0 net) wells. We have suspended all drilling and completion activity at Peace River and Lloydminster. We have also voluntarily shut-in approximately two-thirds of our heavy oil production, most of which we expect will remain off-line for the balance of this year.   

Across all of our core assets, inventory enhancement continues to be a priority. We are also committed to building and maintaining respectful relationships with Indigenous communities and creating opportunities for meaningful economic participation and inclusion. During Q1/2020, we executed a strategic agreement with the Peavine Metis settlement in the Peace River area that covers 60 sections of land directly to the south of our existing Seal operations. We have identified significant potential for this early stage exploratory play targeting the Spirit River formation, a Clearwater formation equivalent, with first activity planned on the lands for 2021.  

East Duvernay Shale Light Oil

Production in the East Duvernay Shale averaged 1,799 boe/d (81% oil and NGL) during Q1/2020, as compared to 1,305 boe/d in Q4/2019. In Q1/2020, we drilled two wells in the core of our Pembina acreage, bringing total wells drilled to nine in this area. Completion activities, originally scheduled for Q2/2020 have been deferred indefinitely and production in the field has been voluntarily shut-in for April and May.   

Financial Liquidity

During the first quarter, we enhanced our long-term note maturity schedule which provides us with improved flexibility and liquidity.

  • On February 5, 2020, we issued US$500 million principal amount of 8.75% senior unsecured notes maturing April 1, 2027.
  • On February 20, 2020, we redeemed US$400 million principal amount of 5.125% senior unsecured notes due June 1, 2021 at par.
  • On March 6, 2020, we redeemed $300 million principal amount of 6.625% senior unsecured notes due July 19, 2022 at 101.104% of the principal amount.
  • Following these redemptions, our first long-term note maturity of US$400 million is not until June 2024.

We also extended the maturities of our credit facilities to April 2, 2024. The credit facilities are not borrowing base facilities and do not require annual or semi-annual reviews. As of March 31, 2020, we had $417 million of undrawn capacity on our credit facilities resulting in approximately $315 million of liquidity net of working capital.

Our net debt, which includes our bank loan, long-term notes and working capital, totaled $2.1 billion at March 31, 2020.

Financial Covenants

The following table summarizes the financial covenants applicable to the credit facilities and Baytex's compliance therewith as at March 31, 2020.

Covenant Description Position as at March 31, 2020 Covenant
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio) 0.8:1.00 3.50:1.00
Interest Coverage (3) (Minimum Ratio) 8.6:1.00 2.00:1.00

Notes:

(1)  "Senior Secured Debt" is defined as the principal amount of the bank loan and other secured obligations identified in the credit agreement. As at March 31, 2020, the Company's Senior Secured Debt totaled $694.9 million which includes $678.7 million of principal amounts outstanding and $16.2 million of letters of credit.
(2) Bank EBITDA is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions (including depletion, depreciation, exploration and evaluation expenses, unrealized gains and losses on financial derivatives and foreign exchange and share-based compensation) and is calculated based on a trailing twelve month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended March 31, 2020 was $923.8 million.
(3) Interest coverage is computed as the ratio of Bank EBITDA to financing and interest expense, excluding accretion of debt issue costs and asset retirement obligations, and is calculated on a trailing twelve month basis. Financing and interest expenses, excluding accretion of debt issue costs and asset retirement obligations, for the twelve months ended March 31, 2020 were $107.2 million
   

Risk Management

To manage commodity price movements we utilize various financial derivative contracts and crude-by-rail to reduce the volatility in our adjusted funds flow.  We realized a financial derivatives gain of $27 million in Q1/2020.   

For the remainder of 2020, we have entered into hedges on the majority of our net crude oil exposure. This is comprised of WTI-based fixed price swaps on 2,000 bbl/d at US$58.00/bbl and a 3-way option structure on 24,500 bbl/d that at current oil prices will see Baytex receive WTI plus US$7.60/bbl.

We have also entered into additional financial hedges to mitigate the volatility in our adjusted funds flow for the next few months. This includes hedging 11,267 bbl/d at a weighted average price of US$25.43/bbl for Q2/2020 and 20,695 bbl/d at a weighted average price of $24.56/bbl for July.    

For the remainder of 2020, we also have WTI-MSW basis differential swaps for 6,388 bbl/d of our light oil production in Canada at US$5.95/bbl and WCS differential hedges on 6,500 bbl/d at a WTI-WCS differential of US$16.27/bbl.

Crude-by-rail is an integral part of our egress and marketing strategy for our heavy oil production. For 2020, we had originally contracted to deliver approximately 11,500 bbl/d of our heavy oil volumes to market by rail. In the current pricing environment, we expect our crude-by-rail volumes to be significantly reduced.    

A complete listing of our financial derivative contracts can be found in Note 17 to our Q1/2020 financial statements.

2020 Guidance

We have updated our production and cost assumptions to reflect the impact of voluntarily shutting-in approximately 25,000 boe/d of production (3,500 boe/d previously). At current commodity prices, we expect the majority of the shut-in volumes to remain off-line for the balance of this year. The shut-in of these barrels is expected to have a positive impact on our adjusted funds flow and improve our financial liquidity.

We continue to emphasize cost reductions across all facets of our organization. We have identified approximately $135 million of cost reductions for 2020 (operating, transportation and general & administrative expenses). On a per unit basis, our operating expense guidance is unchanged as we drive further efficiencies in our business to mitigate the fixed costs associated with our field operations. In addition, we are realizing an approximate 25% reduction in transportation expenses due to reduced volumes.

We are reducing our general and administrative expense guidance by 11% to $40 million. As a continued cost control measure, all full-time employee salaries and all annual retainers paid to our directors were reduced by 10% effective April 1, 2020.

The following table compares our updated 2020 guidance to our previously announced guidance.

  2020 Guidance (1) 2020 Revised Guidance
Exploration and development expenditures $260 - $290 million no change
Production (boe/d) 85,000 - 89,000 70,000 - 74,000
     
Expenses:    
Royalty rate 19.0 - 19.5% ~ 20%
Operating $11.75 - $12.50/boe no change
Transportation $1.10 - $1.20/boe $0.80 - $0.90/boe
General and administrative $45 million ($1.42/boe) $40 million ($1.52/boe)
Interest $115 million ($3.62/boe) $120 million ($4.57/boe)
     
Leasing expenditures $7  million no change
Asset retirement obligations $10 million no change

Note:

(1)  As announced on March 18, 2020.
   

NYSE Listing Notification and Extension

On March 24, 2020 we received notice from the New York Stock Exchange ("NYSE") that Baytex was no longer in compliance with one of the NYSE's continued listing standards because the average closing price of Baytex's common shares was less than US$1.00 per share over a consecutive 30 trading period.

Under the NYSE's rules, Baytex can avoid delisting if, within six months from the date of the NYSE notification, its common shares have a closing price on the last trading day of any calendar month and a concurrent 30 trading day average closing price of at least US$1.00 per share. On April 21, 2020, the NYSE announced temporary relief to provide noncompliant issuers additional time to cure the noncompliance. As a result, the NYSE has provided Baytex an extension to December 3, 2020 (from September 24, 2020). If at the expiration of this date, Baytex has not regained compliance, the NYSE will commence suspension and delisting procedures.

The NYSE can also commence accelerated delisting action in the event Baytex's common shares trade at levels viewed by the NYSE to be abnormally low, which the NYSE has advised is typically below US$0.16 per share. At this time, Baytex does not expect to propose a share consolidation as a means of curing the deficiency.

Non-compliance with the NYSE's price listing standard does not affect Baytex's business operations or its reporting requirements to the U.S. Securities and Exchange Commission (the "SEC"), nor does it affect the continued listing and trading of Baytex's common shares on the Toronto Stock Exchange (the "TSX").

Baytex's common shares will continue to be listed and traded on the NYSE during the applicable cure period, subject to continued compliance with the NYSE's other continued listing standards, under the symbol "BTE", but the NYSE has assigned a ".BC" indicator to the symbol to denote that Baytex is below the NYSE's price listing standard. This indicator will be removed at such time as Baytex is deemed compliant with the NYSE's price listing standard.

Conference Call Tomorrow
9:00 a.m. MDT (11:00 a.m. EDT)
Baytex will host a conference call tomorrow, May 8, 2020, starting at 9:00am MDT (11:00am EDT). To participate, please dial toll free in North America 1-800-319-4610 or international 1-416-915-3239. Alternatively, to listen to the conference call online, please enter http://services.choruscall.ca/links/baytexq120200508.html in your web browser.

An archived recording of the conference call will be available shortly after the event by accessing the webcast link above. The conference call will also be archived on the Baytex website at www.baytexenergy.com.

Additional Information

Our condensed consolidated interim unaudited financial statements for the three months ended March 31, 2020 and the related Management's Discussion and Analysis of the operating and financial results can be accessed on our website at www.baytexenergy.com and will be available shortly through SEDAR at www.sedar.com and EDGAR at www.sec.gov/edgar.shtml.

Advisory Regarding Forward-Looking Statements

In the interest of providing Baytex's shareholders and potential investors with information regarding Baytex, including management's assessment of Baytex's future plans and operations, certain statements in this press release are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements").  In some cases, forward-looking statements can be identified by terminology such as "anticipate", "believe", "continue", "could", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "project", "plan", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance.  The forward-looking statements contained in this press release speak only as of the date thereof and are expressly qualified by this cautionary statement.

Specifically, this press release contains forward-looking statements relating to but not limited to: our business strategies, plans and objectives; our objective to ensure the health and safety of our people, maintain financial liquidity, deploy capital efficiently and emphasize cost reductions; that we expect to see moderated activity in the Eagle Ford and our expectations for $135 million of cost reductions; that the majority of shut-in barrels will be shut-in for the balance of the year; our ability to re-start shut in wells or shut-in additional volumes; our revised production guidance range; that we will re-evaluate our shut-in Viking production monthly and anticipate production resuming in H2 2020; that we expect shut-in heavy oil production to be shut-in for the rest of 2020; activity is planned for our Peavine Metis lands in 2021; that a majority of our net crude oil exposure is hedged for 2020; that we expect to significantly reduce our crude-by-rail volumes; that shut-in barrels are expected to have a positive impact on our adjusted funds flow and improve our liquidity; our revised guidance for 2020 exploration and development expenditures, production, royalty rate, operating, transportation, general and administration and interest expense and leasing expenditures and asset retirement obligations; and our expectations with respect to the potential de-listing our shares from the NYSE.

These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum and natural gas prices and differentials between light, medium and heavy oil prices; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; our ability to borrow under our credit agreements; the receipt, in a timely manner, of regulatory and other required approvals for our operating activities; the availability and cost of labour and other industry services; interest and foreign exchange rates; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; our ability to develop our crude oil and natural gas properties in the manner currently contemplated; and current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being adopted as anticipated). Readers are cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.

Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: the volatility of oil and natural gas prices and price differentials (including the impacts of COVID-19); availability and cost of gathering, processing and pipeline systems; failure to comply with the covenants in our debt agreements; the availability and cost of capital or borrowing; that our credit facilities may not provide sufficient liquidity or may not be renewed; risks associated with a third-party operating our Eagle Ford properties; the cost of developing and operating our assets; depletion of our reserves; risks associated with the exploitation of our properties and our ability to acquire reserves;  new regulations on hydraulic fracturing; restrictions on or access to water or other fluids; changes in government regulations that affect the oil and gas industry; regulations regarding the disposal of fluids; changes in environmental, health and safety regulations; public perception and its influence on the regulatory regime; restrictions or costs imposed by climate change initiatives; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating oil and natural gas reserves; our inability to fully insure against all risks; risks of counterparty default; risks associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks associated with large projects; risks related to our thermal heavy oil projects; alternatives to and changing demand for petroleum products; risks associated with our use of information technology systems; risks associated with the ownership of our securities, including changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control. 

These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2019, filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission and in our other public filings

The above summary of assumptions and risks related to forward-looking statements has been provided in order to provide shareholders and potential investors with a more complete perspective on Baytex's current and future operations and such information may not be appropriate for other purposes.

There is no representation by Baytex that actual results achieved will be the same in whole or in part as those referenced in the forward-looking statements and Baytex does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities law.

All amounts in this press release are stated in Canadian dollars unless otherwise specified.

Non-GAAP Financial and Capital Management Measures

In this news release, we refer to certain financial measures (such as adjusted funds flow, EBITDA, exploration and development expenditures, net debt and operating netback) which do not have any standardized meaning prescribed by Canadian GAAP ("non-GAAP measures") and are considered non-GAAP measures. While adjusted funds flow, EBITDA, exploration and development expenditures, net debt and operating netback are commonly used in the oil and gas industry, our determination of these measures may not be comparable with calculations of similar measures for other issuers.

Adjusted funds flow is not a measurement based on generally accepted accounting principles ("GAAP") in Canada, but is a financial term commonly used in the oil and gas industry. We define adjusted funds flow as cash flow from operating activities adjusted for changes in non-cash operating working capital and asset retirement obligations settled. Our determination of adjusted funds flow may not be comparable to other issuers. We consider adjusted funds flow a key measure that provides a more complete understanding of operating performance and our ability to generate funds for exploration and development expenditures, debt repayment, settlement of our abandonment obligations and potential future dividends. In addition, we use a ratio of net debt to adjusted funds flow to manage our capital structure. We eliminate settlements of abandonment obligations from cash flow from operations as the amounts can be discretionary and may vary from period to period depending on our capital programs and the maturity of our operating areas. The settlement of abandonment obligations are managed with our capital budgeting process which considers available adjusted funds flow. Changes in non-cash working capital are eliminated in the determination of adjusted funds flow as the timing of collection, payment and incurrence is variable and by excluding them from the calculation we are able to provide a more meaningful measure of our cash flow on a continuing basis. For a reconciliation of adjusted funds flow to cash flow from operating activities, see Management's Discussion and Analysis of the operating and financial results for the three months ended March 31, 2020. 

EBITDA is not a measurement based on GAAP in Canada. EBITDA is defined as net income or loss adjusted for financing and interest expenses, unrealized gains and losses on financial derivatives, income tax, non-recurring losses, payments on lease obligations, certain specific unrealized and non-cash transactions (including depletion, exploration and evaluation expenses, unrealized gains and losses on financial derivatives and foreign exchange and share-based compensation). 

Exploration and development expenditures is not a measurement based on GAAP in Canada. We define exploration and development expenditures as additions to exploration and evaluation assets combined with additions to oil and gas properties. Our definition of exploration and development expenditures may not be comparable to other issuers. We use exploration and development expenditures to measure and evaluate the performance of our capital programs. The total amount of exploration and development expenditures is managed as part of our budgeting process and can vary from period to period depending on the availability of adjusted funds flow and other sources of liquidity.

Net debt is not a measurement based on GAAP in Canada. We define net debt to be the sum of cash, trade and other accounts receivable, trade and other accounts payable, and the principal amount of both the long-term notes and the bank loan. Our definition of net debt may not be comparable to other issuers. We believe that this measure assists in providing a more complete understanding of our cash liabilities and provides a key measure to assess our liquidity. We use the principal amounts of the bank loan and long-term notes outstanding in the calculation of net debt as these amounts represent our ultimate repayment obligation at maturity. The carrying amount of debt issue costs associated with the bank loan and long-term notes is excluded on the basis that these amounts have already been paid by Baytex at inception of the contract and do not represent an additional source of capital or repayment obligation.

Operating netback is not a measurement based on GAAP in Canada, but is a financial term commonly used in the oil and gas industry.  Operating netback is equal to petroleum and natural gas sales less blending expense, royalties, production and operating expense and transportation expense divided by barrels of oil equivalent sales volume for the applicable period.  Our determination of operating netback may not be comparable with the calculation of similar measures for other entities.  We believe that this measure assists in characterizing our ability to generate cash margin on a unit of production basis and is a key measure used to evaluate our operating performance.

Advisory Regarding Oil and Gas Information

Where applicable, oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.  BOEs may be misleading, particularly if used in isolation.  A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

References herein to average 30-day initial production rates and other short-term production rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating aggregate production for us or the assets for which such rates are provided. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, we caution that the test results should be considered to be preliminary.

Throughout this news release, "oil and NGL" refers to heavy oil, bitumen, light and medium oil, tight oil, condensate and natural gas liquids ("NGL") product types as defined by NI 51-101. The following table shows Baytex's disaggregated production volumes for the quarter ended March 31, 2020. The NI 51-101 product types are included as follows: "Heavy Oil" - heavy oil and bitumen, "Light and Medium Oil" - light and medium oil, tight oil and condensate, "NGL" - natural gas liquids and "Natural Gas" - shale gas and conventional natural gas.

    Heavy Oil
(bbl/d)
  Light and Medium Oil
(bbl/d)
  NGL
(bbl/d)
  Natural Gas
(Mcf/d)
  Oil Equivalent
(boe/d)
Canada - Heavy                    
Peace River   14,019   9   13   12,622   16,145
Lloydminster   14,835   18     1,280   15,067
                     
Canada - Light                    
Viking     22,485   114   12,583   24,696
Duvernay     929   521   2,093   1,799
Remaining properties     800   670   18,521   4,556
                     
United States                    
Eagle Ford     21,476   6,505   49,256   36,190
                     
Total   28,854   45,717   7,822   96,356   98,452

Baytex Energy Corp.

Baytex Energy Corp. is an oil and gas corporation based in Calgary, Alberta. The company is engaged in the acquisition, development and production of crude oil and natural gas in the Western Canadian Sedimentary Basin and in the Eagle Ford in the United States. Approximately 83% of Baytex's production is weighted toward crude oil and natural gas liquids. Baytex's common shares trade on the Toronto Stock Exchange and the New York Stock Exchange under the symbol BTE.

For further information about Baytex, please visit our website at www.baytexenergy.com or contact:

Brian Ector, Vice President, Capital Markets

Toll Free Number: 1-800-524-5521
Email: investor@baytexenergy.com

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