# Message
to Shareholders

_Source: `DeepSeekOCR_Ardian_pruned_1k/energy-oil-gas-e-p/NYSE_BTE_2018/NYSE_BTE_2018.mmd` · pages 1-7_

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Message
to Shareholders
4

Management's
Discussion and Analysis
6
Management's
Report
43

Auditors'
Reports
44
Consolidated
Financial Statements
46

Reserves
Information
76

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<table><tr><td rowspan="2"></td><td colspan="2">Years Ended</td></tr><tr><td>December 31, 2018</td><td>December 31, 2017</td></tr><tr><td>FINANCIAL</td><td></td><td></td></tr><tr><td>(thousands of Canadian dollars, except per common share amounts)</td><td></td><td></td></tr><tr><td>Petroleum and natural gas sales</td><td>\( 1,428,870</td><td>\) 1,099,867</td></tr><tr><td>Adjusted funds flow (1)</td><td>472,983</td><td>347,641</td></tr><tr><td>Per share - basic</td><td>1.35</td><td>1.48</td></tr><tr><td>Per share - diluted</td><td>1.35</td><td>1.47</td></tr><tr><td>Net income (loss)</td><td>(325,309)</td><td>87,174</td></tr><tr><td>Per share - basic</td><td>(0.93)</td><td>0.37</td></tr><tr><td>Per share - diluted</td><td>(0.93)</td><td>0.37</td></tr><tr><td>Capital Expenditures</td><td></td><td></td></tr><tr><td>Exploration and development expenditures (1)</td><td>\( 495,721</td><td>\) 326,266</td></tr><tr><td>Acquisitions, net of divestitures</td><td>(1,818)</td><td>59,857</td></tr><tr><td>Total oil and natural gas capital expenditures</td><td>\( 493,903</td><td>\) 386,123</td></tr><tr><td>Net Debt</td><td></td><td></td></tr><tr><td>Bank loan (2)</td><td>\( 522,294</td><td>\) 213,376</td></tr><tr><td>Long-term notes (2)</td><td>1,596,323</td><td>1,489,210</td></tr><tr><td>Long-term debt</td><td>2,118,617</td><td>1,702,586</td></tr><tr><td>Working capital deficiency</td><td>146,550</td><td>31,698</td></tr><tr><td>Net debt (1)</td><td>\( 2,265,167</td><td>\) 1,734,284</td></tr><tr><td>Shares Outstanding - basic (thousands)</td><td></td><td></td></tr><tr><td>Weighted average</td><td>351,542</td><td>234,787</td></tr><tr><td>End of period</td><td>554,060</td><td>235,451</td></tr></table>

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<table><tr><td rowspan="2"></td><td colspan="2">Years Ended</td></tr><tr><td>December 31, 2018</td><td>December 31, 2017</td></tr><tr><td>OPERATING</td><td></td><td></td></tr><tr><td>Daily Production</td><td></td><td></td></tr><tr><td>Light oil and condensate (bbl/d)</td><td>29,264</td><td>21,314</td></tr><tr><td>Heavy oil (bbl/d)</td><td>25,954</td><td>25,326</td></tr><tr><td>NGL (bbl/d)</td><td>9,745</td><td>9,206</td></tr><tr><td>Total liquids (bbl/d)</td><td>64,963</td><td>55,846</td></tr><tr><td>Natural gas (mcf/d)</td><td>92,971</td><td>86,375</td></tr><tr><td>Oil equivalent (boe/d @ 6:1) (3)</td><td>80,458</td><td>70,242</td></tr><tr><td>Netback (thousands of Canadian dollars)</td><td></td><td></td></tr><tr><td>Total sales, net of blending and other expense (4)</td><td>\( 1,360,038</td><td>\) 1,040,522</td></tr><tr><td>Royalties</td><td>(313,754)</td><td>(241,892)</td></tr><tr><td>Operating expense</td><td>(311,592)</td><td>(269,283)</td></tr><tr><td>Transportation expense</td><td>(36,869)</td><td>(33,985)</td></tr><tr><td>Operating netback</td><td>\( 697,823</td><td>\) 495,362</td></tr><tr><td>General and administrative</td><td>(45,825)</td><td>(47,389)</td></tr><tr><td>Cash financing and interest</td><td>(104,318)</td><td>(100,482)</td></tr><tr><td>Realized financial derivatives (loss) gain</td><td>(73,165)</td><td>7,616</td></tr><tr><td>Other (5)</td><td>(1,532)</td><td>(7,466)</td></tr><tr><td>Adjusted funds flow (1)</td><td>\( 472,983</td><td>\) 347,641</td></tr><tr><td>Netback (per boe)</td><td></td><td></td></tr><tr><td>Total sales, net of blending and other expense (4)</td><td>\( 46.31</td><td>\) 40.58</td></tr><tr><td>Royalties</td><td>(10.68)</td><td>(9.43)</td></tr><tr><td>Operating expense</td><td>(10.61)</td><td>(10.50)</td></tr><tr><td>Transportation expense</td><td>(1.26)</td><td>(1.33)</td></tr><tr><td>Operating netback (1)</td><td>\( 23.76</td><td>\) 19.32</td></tr><tr><td>General and administrative</td><td>(1.56)</td><td>(1.85)</td></tr><tr><td>Cash financing and interest</td><td>(3.55)</td><td>(3.92)</td></tr><tr><td>Realized financial derivatives (loss) gain</td><td>(2.49)</td><td>0.30</td></tr><tr><td>Other (5)</td><td>(0.05)</td><td>(0.29)</td></tr><tr><td>Adjusted funds flow (1)</td><td>\( 16.11</td><td>\) 13.56</td></tr></table>

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. We refer you to 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 liquidity 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 2018 MD&A for further information on these amounts.

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## Advisory Regarding Forward-Looking Statements and Initial Production Rates

This report contains forward-looking statements relating to but not limited to: our business strategies, plans and objectives; that current oil prices will have a very positive impact on our adjusted funds flow; that we will strengthen our balance sheet in 2019; the trend for our production volumes; our expected Q1/2019 capital expenditures; that 80% of our capital spending will be directed to high operating netback assets in the Eagle Ford and Viking; our forecast adjusted funds flow, debt repayment, production and net debt to EBITDA ratio for 2019; that 90% of our production is the Viking and Duvernay is light oil; that 2018 repositioned us to have strong free cash flow; our Eagle Ford assets, including our assessment that: it is a premier oil resource play, generates strong operating netbacks and free cash flow and has a significant development inventory; that our extended reach horizontal wells are economic; that our Peace River assets generate some of the strongest capital efficiencies in the oil and gas industry; that we continue to prudently advance the delineation of our East Duvernay Shale assets; that we expect to request an extension to our credit facilities in 2019; our ability to partially reduce the volatility in our adjusted funds flow by utilizing financial derivative contracts for commodity prices, foreign exchange rates and interest rates; the percentage of our net crude oil and natural gas exposure that is hedged for 2019 and the amount and percentage of heavy oil production we expect to delivery by crude by rail and the percentage of crude by rail deliveries that do not have WCS exposure; the expected impact of improved pricing on our adjusted funds flow; that deleveraging remains a priority and our planned uses for adjusted funds flow in 2019; for the Eagle Ford and Viking in Q1/2019: the percentage of our capital spending directed to the assets and the number of drilling rigs and frac crews on our lands; the number of wells to be drilled in the Viking in 2019; the number of wells to be brought on production in the Eagle Ford in 2019; that we will execute a small heavy oil program in the first half of 2019 that could move higher if prices and egress improve; for the East Duvernay Shale in 2019: that we will continue to prudently advance its evaluation, that we will drill four wells in Q1/2019 that if successful will delineate 100 to 125 sections of land; our 2019 production, capital expenditure guidance, adjusted funds flow, adjusted funds flow per share and operating netback guidance; our expected royalty rate and operating, transportation, general and administration and interest expenses for 2019; our expected leasing expenditures and asset retirement obligation spending for 2019; the sensitivity of our 2019 Adjusted Funds Flow to changes in WTI, WCS, MSW and NYMEX prices and the C$/US$ exchange rate; our reserves life index; the net present value before income taxes of the future net revenue attributable to our reserves; forecast prices for petroleum and natural gas; forecast inflation and exchange rates; future development costs; the value of our undeveloped land holdings and our estimated net asset value. In addition, information and statements relating to reserves and contingent resources 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 they can be profitably produced in the future. We refer you to the end of the Management's Discussion and Analysis section of this report for our advisory on forward-looking statements.

This report contains references to average 30-day initial production rates and other short-term production rates which 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.

## 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, asset retirement obligations settled and transaction costs. 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. Transaction costs associated with the Raging River combination are excluded from adjusted funds flow as we consider the costs non-recurring and not reflective of our ability to generate adjusted funds flow on an ongoing 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 and year ended December 31, 2018.

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.

Net debt is not a measurement based on GAAP in Canada. We define net debt to be the sum of monetary working capital (which is current assets less current liabilities excluding current financial derivatives and onerous contracts) and the principal amount of both the long-term notes and the bank loan. 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. The current portion of financial derivatives is excluded as the valuation of the underlying contracts is subject to a high degree of volatility prior to the ultimate settlement. Onerous contracts are excluded from net debt as the underlying contracts do not represent an available source of 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 liquidity 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.

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## MESSAGE TO SHAREHOLDERS

In an environment of volatile commodity prices, 2018 was a defining year for Baytex as we repositioned our company as a North American crude oil producer with strong free cash flow and an improved balance sheet. We delivered on our commitment to grow production and reserves while continuing to drive cost and capital efficiency in our operations, and balance our capital structure.

On August 22, 2018, we completed the transformational combination with Raging River Exploration Inc. ("Raging River"). This $1.6 billion transaction increased our light oil exposure and operational control of our properties and strengthened our balance sheet.

We have successfully integrated the two companies, undertaken a strategic review of our operations, confirmed the organic growth opportunities in our diversified portfolio of assets and delivered on our near-term operational targets. In essence, we have created a new Baytex - with stronger assets and organizational capability than ever before.

One of the key benefits of the combination is strong oil price diversification, which includes light oil and condensate production in the Eagle Ford which commands premium Louisiana Light Sweet ("LLS") based pricing and our high operating netback Viking light oil production in Canada. Today our product mix is approximately 83% liquids (45% light oil, 27% heavy oil and 10% NGLs) and 17% natural gas.

In 2018, our annual production of 80,458 boe/d, exceeded the high end of our guidance, while capital expenditures of \(496 million were in line with our guidance. Our fourth quarter 2018 production increased to 98,890 boe/d. We are very pleased with our operating results. In the Eagle Ford, we continued to see strong well performance driven by enhanced completions in the oil window of our acreage. In the Viking, our expanded use of extended reach horizontal wells continue to exceed expectations with multiple, previously untested sections proving economic. Our heavy oil assets, in both Peace River and Lloydminster, delivered strong results, despite the volatility surrounding heavy oil differentials in Canada. We also continue to prudently advance our Duvernay shale light oil asset, an early stage light oil resource play.

We delivered adjusted funds flow of \(473 million in 2018 and our diligent focus on cost control drove our cash costs (operating, transportation and general and administrative expenses) lower by 4% on a boe basis, as compared to the mid-point of original guidance. We ended 2018 with strong financial liquidity. Our credit facilities are approximately 50% undrawn and our first long-term note maturity is not until 2021. Our net debt totaled \)2.265 billion at December 31, 2018, which includes four series of long-term notes that total $1.6 billion.

In aggregate, we replaced 106% of total 2018 production, adding 31 mmboe of proved plus probable reserves through development activities. Inclusive of the Raging River transaction, we replaced 422% of total 2018 production with 124 mmboe of proved plus probable reserves additions.

We also achieved strong health, safety and environmental performance and strong regulatory compliance across all of our operating jurisdictions. In 2019, we will publish our fourth Corporate Responsibility Report, focusing on environmental, social and economic metrics. We believe that corporate responsibility is a key component to achieving enduring success in resource development.

## Looking Forward

As we look ahead, we are well positioned to execute our business plan and further strengthen our balance sheet. With WTI trading at US$57 at the time of writing, in combination with the narrowing of Canadian differentials, we expect a positive impact on our adjusted funds flow.

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As a result of current activity levels, excellent well performance in the Eagle Ford and outstanding operating efficiency across all of our assets, our first quarter 2019 volumes have exceeded expectations trending above 97,000 boe/d.

We are on pace for $155 million of capital expenditures in Q1 2019, which remains consistent with the mid-point of our guidance range of \(600 million. Approximately 80% of those expenditures are being directed towards our light oil assets in the Eagle Ford and Viking.

Further deleveraging remains a top priority for Baytex. Based on the forward strip for 2019, we are projecting adjusted funds flow of approximately \(800 million – a 32% increase from \)605 million that was forecast at the outset of 2019. This will allow up to \(200 million of debt repayment while maintaining production at the mid-point of our guidance of 95,000 boe/d.

Baytex's success is due to our dedicated and talented team of employees who align with our strategy, consistently deliver on our plans and drive value for our shareholders. Complementing our leadership team and committed employees, our Board of Directors is an indispensable source of guidance and support which contribute greatly to our success. With the combined team, we are confident we have the skills, experience and focus that will create a more prosperous future

We look forward to executing our plans in 2019 for the ongoing benefit of all stakeholders and we thank you for your continued support.

Sincerely,

![](images/6_0.jpg)

Edward D. LaFehr

President and Chief Executive Officer

March 6, 2019