BTE Baytex Energy Corporation

Baytex Energy Corp. (“Baytex”) (TSX, NYSE: BTE.BC) announces that its Board of Directors has approved a 2021 capital budget of $225 to $275 million, which is designed to generate free cash flow and average annual production of 73,000 to 77,000 boe/d.

“We have re-set our business in response to a volatile crude oil market brought on by Covid-19 and are poised to deliver free cash flow and stable production in a US$40 to US$45 WTI environment. In 2021, we will benefit from our high graded development opportunities as well as our continued drive to improve cost structure and capital efficiencies. Our disciplined approach to capital allocation is focused on our high netback light oil assets in the Viking and Eagle Ford and will allow us to continue to pay down debt,” commented Ed LaFehr, President and Chief Executive Officer.

Highlights of the 2021 Budget

• Funding of Capital Program. Our capital program is expected to be fully funded from adjusted funds flow at a WTI price of US$35/bbl.
• Free Cash Flow. Based on the forward strip(1), we expect to generate approximately $75 million of free cash flow during 2021. For every US$1/bbl change in WTI, our adjusted funds flow changes by approximately $23 million on an unhedged basis.
• Capital Efficiency. Our capital program is expected to generate strong capital efficiencies of approximately $12,000 per boe/d across the portfolio. This represents a 30% improvement over our 2020 budget and reflects the high grading of our portfolio in response to lower oil prices and our diligent focus on driving further efficiencies in our business.   
• Capital Allocation. Approximately 85% of our capital program will be directed to our high netback light oil assets in the Viking and Eagle Ford and 10% will be directed to our heavy oil assets at Peace River and Lloydminster.  We have the operational flexibility to adjust our spending plans based on changes in commodity prices.
• Risk Management. Approximately 48% of our net crude oil exposure has been hedged for 2021 utilizing a combination of fixed price swaps at US$45/bbl and a 3-way option structure that provides price protection at US$45/bbl with upside participation to US$52/bbl.(1) 2021 pricing assumptions: WTI - US$45/bbl; WCS differential - US$13/bbl; MSW differential – US$6/bbl, NYMEX Gas - US$2.85/mcf; AECO Gas - $2.55/mcf and Exchange Rate (CAD/USD) - 1.29.

The 2021 capital program is expected to be equally weighted to the first and second half of the year. Based on the mid-point of our production guidance of 75,000 boe/d, approximately 60% of our production is in Canada with the remaining 40% in the Eagle Ford. Our production mix is forecast to be 81% liquids (46% light oil and condensate, 26% heavy oil and 9% natural gas liquids) and 19% natural gas, based on a 6:1 natural gas-to-oil equivalency.  

Canada

In Canada, our development activity is largely focused on the Viking, where we expect to invest 45% of our capital and bring approximately 120 net wells onstream. We control 460 net sections of prospective lands in this light oil resource play. The Viking generates the highest operating netback in our portfolio and is expected to generate meaningful free cash flow.

The returns associated with our heavy oil assets are competitive with our other plays in a US$45 WTI pricing environment. We have scheduled minimal heavy oil development for the first half of 2021, but retain significant flexibility to implement a strong program in the second half of the year. Our 2021 program could see upwards of 30 net wells at Lloydminster and 6 net wells at Peace River.

We continue to prudently advance our Pembina Duvernay Shale light oil play. Our most recent two wells were completed in October and initial flow back rates are very encouraging. The first well (10-16) was brought on-stream November 2 and is currently producing 1,300 boe/d (90% liquids). The second well (11-16) was brought on-stream November 17 and is currently producing 950 boe/d (90% liquids). Based on early flowback results, these two wells demonstrate repeatability of our 11-30 pad completed in 2019 with strong economic returns at US$50 WTI. We have the flexibility in 2021 to drill up to 4 net wells in the second half of the year, with the level of activity dependent on crude oil prices.

Eagle Ford

Our Eagle Ford asset in South Texas is one of the premier oil resource plays in North America. We expect this asset to generate 40% of corporate production and substantial free cash flow. Approximately 40% of our 2021 capital program will be directed to the Eagle Ford where we expect to bring 18 net wells onstream. 

2021 Guidance

The following table summarizes our 2021 annual guidance.

Exploration and development capital ($ millions)	$225 - $275
Production (boe/d)	73,000 - 77,000
Expenses:
Royalty rate (%)	18.0 - 18.5%
Operating ($/boe)	$11.50 - $12.25
Transportation ($/boe)	$1.00 - $1.10
General and administrative ($ millions)	$42 ($1.53/boe)
Interest ($ millions)	$105 ($3.84/boe)
Leasing expenditures ($ millions)	$4
Asset retirement obligations ($ millions)	$6

2021 Adjusted Funds Flow Sensitivities

	Excluding Hedges ($ millions)		Including Hedges when WTI is between US$35/bbl and US$45/bbl ($ millions)		Including Hedges when WTI is between US$45/bbl and US$52/bbl ($ millions)
Change of US$1.00/bbl WTI crude oil	$22.7		$12.8		$20.7
Change of US$1.00/bbl WCS heavy oil differential	$7.1		$3.2		$3.2
Change of US$1.00/bbl MSW light oil differential	$6.9		$4.2		$4.2
Change of US$0.25/mcf NYMEX natural gas	$8.7		$5.0		$5.0
Change of $0.01 in the C$/US$ exchange rate	$5.1		$5.1		$5.1

2021 Capital Budget and Wells On-Stream by Operating Area

Operating Area	Amount (1) ($ millions)		Wells On-stream (net)
Canada	$150		150
United States (2)	$100		18
Total	$250		168

(1) Reflects mid-point of capital budget guidance range.

(2) Based on a Canadian-U.S. exchange rate of 1.32 CAD/USD.

2021 Capital Budget Breakdown

Classification	Amount (1)($ millions)
Drill, complete and equip	$235
Facilities	$10
Land and seismic	$5
Total	$250

(1) Reflects mid-point of capital budget guidance range.

Risk Management

To manage commodity price movements, we utilize various financial derivative contracts and crude-by-rail to reduce the volatility of our adjusted funds flow.

For 2021, we have entered into hedges on approximately 48% of our net crude oil exposure utilizing a combination of fixed price swaps at US$45/bbl and a 3-way option structure that provides price protection at US$45/bbl with upside participation to US$52/bbl. We also have WTI-MSW differential hedges on approximately 40% of our expected 2021 Canadian light oil production at US$5.17/bbl and WCS differential hedges on approximately 45% of our expected 2021 heavy oil production at a WTI-WCS differential of approximately US$13.50/bbl.

For 2021, we are contracted to deliver 5,500 bbl/d of our heavy oil volumes to market by rail.

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; for 2021: our capital budget, that the budget is designed to generate free cash flow and the expected range of average annual production ; that we are poised to deliver free cash flow and stable production in a US$40 to US$45 WTI environment; that we will benefit from high graded development opportunities, our continued drive to improve cost structure and capital efficiencies and our disciplined approach to capital allocation will allow us to pay down debt; that our capital program is fully funded from adjusted funds flow at US$35 WTI; the free cash flow we expect to generate and the sensitivity of that free cash flow to a US$1 change in WTI; the expected capital efficiency of our capital program; our capital allocations as between assets for 2021 and that we have operational flexibility to adjust spending plans; the percentage of our net crude exposure that is hedged for 2021; the timing of our capital spending and the geographic breakdown and product mix for 2021 production; the number of wells we plan to drill in the Viking and that the Viking asset generates the highest netback in the company and is expected to generate meaningful cash flow; that returns from our heavy oil assets are competitive with our other plays at US$45 WTI and the number of wells we could drill in 2021; that we continue to prudently advance the Pembina Duvernay, that our most recent Pembina Duvernay wells have strong economic returns at US$50 WTI and we have flexibility to drill up to 4 wells in 2021 dependent on oil prices; that the Eagle Ford is a premier oil resource play, the percentage of corporate production we expect it to contribute, that it will generate substantial free cash flow and the number of net wells we plan to bring on stream in 2021; our expected exploration and development capital spending, production, royalty rate and operating, transportation, general and administrative, interest costs, leasing expenditures and asset retirement obligations for 2021; the sensitivity of our 2021 Adjusted Funds Flow to changes in WTI, WCS, MSW and NYMEX prices and the C$/US$ exchange rate; the expected capital budget and wells on-stream by operating area in 2021 and capital budget by spending type for 2021; the existence, operation and strategy of our risk management program for commodity prices; and the percentage of our net crude oil exposure that is hedged for 2021.

In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future. Although Baytex believes that the expectations and assumptions upon which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because Baytex can give no assurance that they will prove to be correct.

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, as filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission.

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

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 and nine months ended September 30, 2020.

Capital efficiency is not a measurement based on GAAP in Canada. We define capital efficiency as exploration and development expenditures divided by the expected aggregate IP365 rate (boe/d) for all wells coming on production in the year, normalized to a January 1 start-date.

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. 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.

Free cash flow is not a measurement based on GAAP in Canada. We define free cash flow as adjusted funds flow less exploration and development expenditures (both non-GAAP measures discussed above), payments on lease obligations, and asset retirement obligations settled. Our determination of free cash flow may not be comparable to other issuers. We use free cash flow to evaluate funds available for debt repayment, common share repurchases, potential future dividends and acquisition and disposition opportunities.

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. 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.

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.

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 81% of Baytex’s production is weighted toward crude oil and natural gas liquids. Baytex’s common shares trade on the Toronto Stock Exchange under the symbol BTE and the New York Stock Exchange under the symbol BTE.BC.

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

Brian Ector, Vice President, Capital Markets

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