BTE Baytex Energy Corp

Baytex Energy Corp. (“Baytex”) (TSX: BTE) announces that its Board of Directors have approved a 2022 capital budget of $400 to $450 million, which is designed to generate average annual production of 80,000 to 83,000 boe/d.

“I am excited with the momentum we are building in our business. We expect to generate record free cash flow in 2021 and our priorities for 2022 remain much the same. Our 2022 capital program is designed to generate meaningful free cash flow with modest annual production growth driven by exploration success and scaled up development in the Clearwater. In a US$65/bbl WTI pricing environment, we expect to generate approximately $2.1 billion of cumulative free cash flow through our 2021-2025 five-year outlook,” commented Ed LaFehr, President and Chief Executive Officer.

Highlights of the 2022 Budget

• Funding of Capital Program. Our capital program is expected to be fully funded from adjusted funds flow at a WTI price of US$45/bbl. Based on the forward strip(1) our capital program represents approximately 55% of our adjusted funds flow.
• Free Cash Flow. Based on the forward strip(1) we expect to generate approximately $340 million of free cash flow in 2022. For every US$1/bbl change in WTI, our adjusted funds flow changes by approximately $24 million on an unhedged basis ($15 million including 2022 hedges).
• Capital Efficiency. Our capital program is expected to generate strong capital efficiencies of approximately $15,000 per boe/d across the portfolio.
• Capital Allocation. We will direct approximately 60% of our capital program to our high netback light oil assets in the Viking and Eagle Ford, 25% to our heavy oil assets at Peace River and Lloydminster and 10% to the Clearwater.
• Risk Management. Approximately 42% of our net crude oil exposure has been hedged for 2022 utilizing a combination of a 3-way option structure that provides price protection at US$58/bbl with upside participation to US$68/bbl and swaptions at US$53.50/bbl.

The 2022 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 81,500 boe/d, approximately 65% of our production is in Canada with the remaining 35% in the Eagle Ford. Our production mix is forecast to be 83% liquids (43% light oil and condensate, 32% heavy oil and 8% natural gas liquids) and 17% natural gas, based on a 6:1 natural gas-to-oil equivalency.

Note:

(1)   2022 pricing assumptions: WTI - US$66/bbl; WCS differential - US$16/bbl; MSW differential – US$5/bbl, NYMEX Gas - US$4.10/mcf; AECO Gas - $3.50/mcf and Exchange Rate (CAD/USD) - 1.28.

2022 Free Cash Flow

In 2021 we made a commitment to maintain capital discipline, maximize free cash flow and reduce our net debt. We expect to generate record free cashflow in 2021 of approximately $420 million, which is accelerating our debt reduction efforts. As a result, we expect to exit 2021 with net debt of approximately $1.4 billion, which represents a 25% reduction from year-end 2020. Over the past three years, we will have reduced our net debt by approximately $900 million.

Based on the forward strip for 2022, we expect to generate approximately $340 million of free cash flow. We remain committed to further strengthening our balance sheet and providing an enhanced return to our shareholders.

Our priorities for the allocation of free cash flow in 2022 are as follows:

• We will allocate 100% of our free cash flow to reducing net debt until we hit our initial $1.2 billion net debt target. We expect this to occur by mid-2022. This debt target represents a net debt to EBITDA ratio of approximately 1.4x at a US$65 WTI price.
• Upon reaching a net debt level of $1.2 billion, we anticipate announcing a plan for enhanced shareholder returns, which could include share buybacks and/or a dividend, while we continue to reduce our net debt to further strengthen the business.

Five-Year Outlook

Our five-year outlook (2021 to 2025) highlights our financial and operational sustainability and ability to generate meaningful free cash flow. Through this plan period, we are committed to a disciplined, returns based capital allocation philosophy, targeting capital expenditures at approximately 50% of our adjusted funds flow, while optimizing production in the 85,000 to 90,000 boe/d range. This generates annual production growth of 2% to 4% with annual capital spending of $400 to $475 million from 2022 to 2025.

We have updated our five-year outlook to include expected inflationary cost increases along with increased drilling on our Clearwater lands. Our base plan assumes development of 20 sections (of our 80-section land base) which have been delineated to-date and includes the drilling of approximately 80 net wells. With this initial phase of drilling, we expect Clearwater production to increase from zero at the beginning of 2021 to approximately 6,000 bbl/d while generating over $100 million of cumulative free cash flow. With continued success, we believe the play ultimately holds the potential for over 200 drilling locations that could support production increasing to over 10,000 bbl/d.

We have grounded our updated five-year outlook on a constant US$65/bbl WTI price and expect to generate approximately $2.1 billion of cumulative free cash flow. Under a constant US$75/bbl pricing scenario, our expected cumulative free cash flow increases to approximately $2.8 billion.

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 2022, we have entered into hedges on approximately 42% of our net crude oil exposure utilizing a combination of a 3-way option structure that provides price protection at US$58/bbl with upside participation to US$68/bbl and swaptions at US$53.50/bbl. We also have WTI-WCS differential hedges on approximately 70% of our expected net heavy oil exposure at US$12.28/bbl and MSW differential hedges on approximately 25% of our expected net Canadian light oil exposure at a WTI-MSW differential of approximately US$4.43/bbl.

2022 Budget Details

In 2022, we expect to benefit from our diversified oil weighted portfolio and our commitment to allocate capital effectively. Our capital program is designed to generate stable production from our light and heavy assets in Canada and the Eagle Ford in the United States, while scaling up development in the Clearwater.

Eagle Ford and Viking Light Oil

Approximately 60% of our capital program will be directed to our high netback light oil assets in the Viking and Eagle Ford, where we forecast stable production and strong asset level free cash flow. We expect to bring approximately 145 net wells onstream in the Viking and 14 net wells onstream in the Eagle Ford.

Heavy Oil

Approximately 25% of our capital program will be directed to our heavy oil assets at Peace River and Lloydminster. Our 2022 activity reflects a capital efficient drilling program complemented by long life and high value polymer flood projects. In total, we will see approximately 47 net wells drilled at Lloydminster and 9 net Bluesky wells drilled at Peace River.

Clearwater

We will allocate approximately 10% of our 2022 capital budget to the Peace River Clearwater as successful exploration results in 2021 lead to scaling up our development. We expect to bring approximately 18 Clearwater wells onstream in 2022.

We are currently executing our Q4/2021 drilling program and preparing for increased activity in 2022 with our three Q4/2021 Peavine wells scheduled to be onstream in December. In addition, we have drilled our first Clearwater exploration well in the core of our Seal legacy land base and have a follow-up appraisal well planned for H2/2022. During the first quarter of 2022, we anticipate running a two-rig program that will see eight wells drilled on our Peavine lands.

At current commodity prices, the Clearwater generates among the strongest economics within our portfolio with payouts of less than six months and the ability to grow organically while enhancing our free cash flow profile.

Pembina Area Duvernay Light Oil

During the third quarter, we drilled two 100% working interest wells with very encouraging results. The first well (7-8) was brought on-stream October 18 and established a 30-day initial production rate of 944 boe/d (712 bbl/d light oil, 148 bbl/d NGLs and 0.5 mmcf/d of natural gas). The second well (6-8) was brought on-stream October 30 and established a 30-day initial production rate of 1,230 boe/d (814 bbl/d light oil, 265 bbl/d NGLs and 0.9 mmcf/d of natural gas).

We expect to drill three net wells in the Duvernay during 2022 as we follow-up on our successful 2021 program.

Environmental Stewardship

As part of our commitment to enhancing our culture of sustainability, we are investing $30 million to progress our plans to decarbonize and shrink the environmental footprint of our operations. We will invest approximately $10 million as part of our GHG mitigation program and expect to reduce our GHG emissions intensity by 10% over 2021 levels. In addition, we will embark on an active abandonment and reclamation program with approximately $20 million being directed to pipeline, wellbore and facility decommissioning along with well site reclamations.

2022 Guidance

The following table summarizes our 2022 annual guidance.

	Exploration and development capital ($ millions)	$400 - $450
	Production (boe/d)	80,000 - 83,000
	Expenses:
	Royalty rate (%)	18.5 – 19.0%
	Operating ($/boe)	$12.25 - $13.00
	Transportation ($/boe)	$1.20 - $1.30
	General and administrative ($ millions)	$43 ($1.45/boe)
	Interest ($ millions)	$80 ($2.70/boe)
	Leasing expenditures ($ millions)	$3
	Asset retirement obligations ($ millions)	$20

2022 Adjusted Funds Flow Sensitivities

		Excluding Hedges($ millions)	Including Hedges($ millions)
	Change of US$1.00/bbl WTI crude oil	$24.1	$15.1
	Change of US$1.00/bbl WCS heavy oil differential	$8.4	$3.3
	Change of US$1.00/bbl MSW light oil differential	$7.0	$5.3
	Change of US$0.25/mcf NYMEX natural gas	$7.6	$4.8
	Change of $0.01 in the C$/US$ exchange rate	$11.5	$11.5

2022 Capital Budget and Wells On-Stream by Operating Area

	Operating Area	Amount (1)($ millions)	Wells On-stream(net)
	Canada	$335	216
	United States (2)	$90	14
	Total	$425	230

(1)     Reflects mid-point of capital budget guidance range.(2)     Based on a Canadian-U.S. exchange rate of 1.27 CAD/USD.

2022 Capital Budget Breakdown

	Classification	Amount (1)($ millions)
	Drill, complete and equip	$385
	Facilities	$20
	Land and seismic	$10
	GHG Mitigation	$10
	Total	$425

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

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 2022 capital budget of $400-$450 million, that the budget is designed to generate average annual production of 80,000 to 83,000; we expect to generate record free cash flow in 2021; our 2022 budget is designed to generate meaningful free cash flow with modest annual production growth; in a US$65 WTI environment we expect to generate $2.1 billion of cumulative free cash flow through our 2021-2025 five-year outlook; our capital program is fully funded from adjusted funds flow at US$45/bbl WTI; based on the forward strip our capital program represents ~55% of adjusted funds flow and generates ~$340 million of free cash flow; the amount our adjusted funds flow changes based on a US$1/bbl change in WTI unhedged and hedged; our capital program is expected to generate capital efficiencies of $15,000 per boe/d across the portfolio; the percentage of our net crude exposure that is hedged for 2022; the allocation as between certain assets and timing of our capital spending; the geographic breakdown and product type breakdown for 2022 production; our expected 2021 year-end net debt and resulting one year and three year debt reduction; we are committed to further strengthening our balance sheet and providing enhanced return to our shareholders; we will allocated 100% of free cash flow to debt reduction until we hit our initial net debt target of $1.2 billion; our expected net debt to EBITDA ratios at certain WTI prices when we hit our initial debt target; upon reaching our net debt target we anticipate announcing a plan for enhanced shareholder returns, which could include share buybacks and/or a dividend while we continue to reduce our net debt; regarding our five-year outlook: it highlights our financial and operational sustainability and ability to generate meaningful free cash flow,  during the plan period we are committed to a disciplined, returns based capital allocation philosophy, our targeted capital expenditures as a percentage of adjusted funds flow, expected production growth and capital spending; for the Clearwater during our five-year outlook: development assumption, expected production rate and cumulative free cash flow, number of potential drilling locations and that the pay could support production increasing to over 10,000 bbl/d; the expected cumulative free cash flow from during the five-year outlook at US$65 WTI and US$75 WTI; the percentage of our net crude, WTI-WCS differential and WTI-MSW differential exposure that is hedged for 2022; we expect to benefit from our diversified oil weighted portfolio and our commitment to allocate capital effectively; our 2022 plan is designed to generate stable production from our light and heavy assets in Canada and the United States while scaling up development in the Clearwater; the percentage capital allocation and expected wells drilled and onstream by asset; we forecast stable production and strong asset level free cash flow in the Eagle Ford and Viking; the expected on-stream date of our three Q4/2021 Peavine wells; that we will run a two rig program in Q1/2022 in Peavine; at current commodity prices, the Clearwater generates among the strongest economics within our portfolio with payouts of less than six months and has the ability to grow organically while enhancing our free cash flow profile; our GHG emissions reduction and abandonment and reclamation plans and spending commitments; our expected  exploration and development capital spending, production, royalty rate and operating, transportation, general and administrative, interest costs, leasing expenditures and asset retirement obligations for 2022; the sensitivity of our 2022 adjusted funds flow to changes in WTI, WCS, MSW and NYMEX prices and the C$/US$ exchange rate (with and without hedges); the expected capital budget and wells on-stream by operating area in 2022 and capital budget by spending type for 2022. 

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); the availability and cost of capital or borrowing; risks associated with our ability to exploit our properties and add reserves; availability and cost of gathering, processing and pipeline systems; that our credit facilities may not provide sufficient liquidity or may not be renewed; failure to comply with the covenants in our debt agreements; risks associated with a third-party operating our Eagle Ford properties; public perception and its influence on the regulatory regime; restrictions or costs imposed by climate change initiatives and the physical risks of climate change; 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; costs to develop and operate our properties; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; retaining or replacing our leadership and key personnel; 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 related to our thermal heavy oil projects; alternatives to and changing demand for petroleum products; risks associated with our use of information technology systems; results of litigation; risks associated with large projects; 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, 2020, 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

In this news release, we refer to certain financial measures (such as adjusted funds flow, capital efficienty, exploration and development expenditures, free cash flow and net debt) which do not have any standardized meaning prescribed by Canadian GAAP (“non-GAAP measures”) and are considered non-GAAP measures. While these terms 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 and nine months ended September 30, 2021.

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.

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 credit facilities. 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 credit facilities 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 credit facilities 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.

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