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BTEGF Baytex Energy

Filed: 5 May 21, 11:59am

Exhibit 99.1

 

 

BAYTEX ANNOUNCES FIRST QUARTER 2021 FINANCIAL AND OPERATING RESULTS AND
PROVIDES FIVE YEAR OUTLOOK WITH CUMULATIVE FREE CASH FLOW OF $1 BILLION

 

CALGARY, ALBERTA (April 29, 2021) - Baytex Energy Corp. (“Baytex”)(TSX: BTE) reports its operating and financial results for the three months ended March 31, 2021 (all amounts are in Canadian dollars unless otherwise noted).

 

“We delivered strong first quarter production and free cash flow as we accelerate our deleveraging strategy. At current commodity prices, we expect to generate over $250 million of free cash flow in 2021 and we have an exciting, new, oil exploration discovery in the Clearwater oil play in Peace River with follow-up drilling already scheduled for H2/2021. I am also pleased to announce our five-year outlook which demonstrates our operational and financial strength in a US$55 WTI pricing environment as we target over $1 billion of cumulative free cash flow through 2025,” commented Ed LaFehr, President and Chief Executive Officer.

 

Q1 2021 Highlights

 

Generated production of 78,780 boe/d (81% oil and NGL), a 12% increase over Q4/2020.

Delivered adjusted funds flow of $157 million ($0.28 per basic share), a 91% increase compared to $82 million ($0.15 per basic share) in Q4/2020.

Generated free cash flow of $70 million ($0.13 per basic share).

Realized an operating netback of $29.80/boe, up from $15.19/boe in Q4/2020.

Reduced net debt by $89 million through a combination of free cash flow and the Canadian dollar strengthening relative to the U.S. dollar.

 

2021 Outlook

 

We are benefiting from a disciplined approach to capital allocation and improvements to our cost structure and capital efficiencies along with the recovery in commodity prices. Drilling activity resumed late last year and we are building significant operational momentum with first quarter production up 12% from Q4/2020, largely driven by our light oil business. We are on track to deliver over $250 million ($0.45 per basic share) of free cash flow, which will accelerate our debt reduction efforts.

 

As a result of this operational momentum and the strength in commodity prices, we are increasing both our production and capital spending guidance. This will position our business for continued strong operating performance and free cash flow generation going forward. We are now forecasting 2021 exploration and development expenditures of $285 to $315 million, up from $225 to $275 million, which was set in a US$40 to US$45 pricing environment. The increased expenditures will largely occur in the fourth quarter and will be allocated across our portfolio of light and heavy oil assets, including our emerging Clearwater play at Peace River. Our revised production guidance range is 77,000 to 79,000 boe/d, up from 73,000 to 77,000 boe/d.

 

Five-Year Outlook

 

We are providing a five-year outlook (2021 to 2025) to highlight our financial and operational sustainability and meaningful free cash flow generation. Through this plan period, we will maintain a disciplined and returns based capital allocation philosophy.

 

Assuming a constant US$55/bbl WTI price, we will target capital expenditures at less than 70% of our adjusted funds flow, while optimizing our production in the 80,000 to 85,000 boe/d range. We project annual capital spending of approximately $400 million from 2022 to 2025 and expect to generate over $1 billion of cumulative free cash flow. Our leverage ratios are expected to improve materially as we target a net debt to EBITDA ratio of under 1.5x. Throughout the plan period we will continue to monitor our leverage position and assess market conditions to determine the best methods or combination thereof to enhance shareholder returns. These could include share buy-backs, a dividend or reinvestment for organic growth. 

 

 

  Three Months Ended 
  March 31, 2021  December 31, 2020  March 31, 2020 
FINANCIAL            
(thousands of Canadian dollars, except per common share amounts)            
Petroleum and natural gas sales $384,702  $233,636  $336,614 
Adjusted funds flow (1)  156,582   82,176   132,935 
Per share - basic  0.28   0.15   0.24 
Per share - diluted  0.28   0.15   0.24 
Net income (loss)  (35,352)  221,160   (2,498,217)
Per share - basic  (0.06)  0.39   (4.46)
Per share - diluted  (0.06)  0.39   (4.46)
             
Capital Expenditures            
Exploration and development expenditures (1) $83,588  $77,809  $176,777 
Acquisitions, net of divestitures  (203)  (33)  (40)
Total oil and natural gas capital expenditures $83,385  $77,776  $176,737 
             
Net Debt            
Credit facilities (2) $606,637  $651,173  $678,740 
Long-term notes (2)  1,131,480   1,147,950   1,270,800 
Long-term debt  1,738,117   1,799,123   1,949,540 
Working capital deficiency  20,777   48,478   102,077 
Net debt (1) $1,758,894  $1,847,601  $2,051,617 
             
Shares Outstanding - basic (thousands)            
Weighted average  562,085   561,173   559,804 
End of period  564,111   561,227   560,483 
             
BENCHMARK PRICES            
Crude oil            
WTI (US$/bbl) $57.84  $42.66  $46.17 
MEH oil (US$/bbl)  59.36   43.05   49.54 
MEH oil differential to WTI (US$/bbl)  1.52   0.39   3.37 
Edmonton par ($/bbl)  66.58   50.24   51.43 
Edmonton par differential to WTI (US$/bbl)  (5.27)  (4.11)  (7.92)
WCS heavy oil ($/bbl)  57.46   43.46   34.48 
WCS differential to WTI (US$/bbl)  (12.46)  (9.31)  (20.53)
Natural gas            
NYMEX (US$/mmbtu) $2.69  $2.66  $1.95 
AECO ($/mcf)  2.93   2.77   2.14 
             
CAD/USD average exchange rate  1.2663   1.3031   1.3445 

 

2Baytex Energy Corp. First Quarter Report 2021

 

 

  Three Months Ended 
  March 31, 2021  December 31, 2020  March 31, 2020 
OPERATING            
Daily Production            
Light oil and condensate (bbl/d)  35,430   29,568   45,717 
Heavy oil (bbl/d)  21,989   21,725   28,854 
NGL (bbl/d)  6,238   6,495   7,822 
Total liquids (bbl/d)  63,657   57,788   82,393 
Natural gas (mcf/d)  90,739   76,116   96,356 
Oil equivalent (boe/d @ 6:1) (3)  78,780   70,475   98,452 
             
Netback (thousands of Canadian dollars)            
Total sales, net of blending and other expense (4)  $367,582  $222,745  $315,257 
Royalties  (66,950)  (37,807)  (56,720)
Operating expense  (80,548)  (79,748)  (104,470)
Transportation expense  (8,788)  (6,692)  (10,342)
Operating netback (1) $211,296  $98,498  $143,725 
General and administrative  (8,733)  (9,313)  (9,775)
Cash financing and interest  (24,403)  (25,194)  (28,535)
Realized financial derivatives (loss) gain  (20,768)  17,105   26,850 
Other (5)  (810)  1,080   670 
Adjusted funds flow (1) $156,582  $82,176  $132,935 
             
Netback (per boe)            
Total sales, net of blending and other expense (4)  $51.84  $34.35  $35.19 
Royalties  (9.44)  (5.83)  (6.33)
Operating expense  (11.36)  (12.30)  (11.66)
Transportation expense  (1.24)  (1.03)  (1.15)
Operating netback (1) $29.80  $15.19  $16.05 
General and administrative  (1.23)  (1.44)  (1.09)
Cash financing and interest  (3.44)  (3.89)  (3.19)
Realized financial derivatives (loss) gain  (2.93)  2.64   3.00 
Other (5)  (0.12)  0.17   0.07 
Adjusted funds flow (1) $22.08  $12.67  $14.84 

 

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 credit facilities 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 share-based compensation. Refer to the Q1/2021 MD&A for further information on these amounts.

 

Baytex Energy Corp. First Quarter Report 20213

 

 

Q1/2021 Results

 

During Q1/2021, we executed on our plan to maximize free cash flow and reduce debt. During the quarter, we delivered adjusted funds flow of $157 million ($0.28 per basic share). This resulted in free cash flow of $70 million, which, along with the Canadian dollar strengthening relative to the U.S. dollar, contributed to an $89 million reduction in our net debt.

 

Production during the first quarter averaged 78,780 boe/d (81% oil and NGL), up 12% as compared to 70,475 boe/d (82% oil and NGL) in Q4/2020. The increased production largely reflects the resumption of drilling activity in the Viking and Eagle Ford which began in the fourth quarter. Exploration and development expenditures totaled $84 million in Q1/2021 that included the drilling of 68 (46.5 net) wells with a 100% success rate.

 

2021 Guidance

 

In 2021, we expect to benefit from our diversified oil weighted portfolio and our commitment to allocate capital effectively. Based on the forward strip(1), we expect to generate over $250 million of free cash flow in 2021.

 

As a result of our strong operational momentum and the strength in commodity prices, we are increasing both our production and capital spending guidance. This will position our business for continued strong operating performance and free cash flow generation going forward. We are now forecasting 2021 exploration and development expenditures of $285 to $315 million, up from $225 to $275 million, which was set in a US$40 to US$45 pricing environment. The increased spend will largely occur in the fourth quarter and will be allocated across our portfolio of light and heavy oil assets. Our revised production guidance range is 77,000 to 79,000 boe/d, up from 73,000 to 77,000 boe/d.

 

We have also fine-tuned several of our cost assumptions to reflect higher production volumes and increased activity. In addition, our interest expense guidance is 7% lower due to reduced net debt and the Canadian dollar strengthening relative to the U.S. dollar.

 

The following table highlights our updated 2021 annual guidance.

 

  2021 Guidance (2) 2021 Revised Guidance 
Exploration and development expenditures $225 - $275 million $285 - $315 million 
Production (boe/d) 73,000 - 77,000 77,000 - 79,000 
      
Expenses:     
Royalty rate 18.0% - 18.5% no change 
Operating $11.50 - $12.25/boe $11.25 - $12.00/boe 
Transportation $1.00 - $1.10/boe $1.15 - $1.25/boe 
General and administrative $42 million ($1.53/boe) $42 million ($1.48/boe) 
Interest $105 million ($3.84/boe) $98 million ($3.46/boe) 
      
Leasing expenditures $4 million no change 
Asset retirement obligations $6 million no change 

 

Operating Results

 

Eagle Ford and Viking Light Oil

 

Production in the Eagle Ford averaged 26,741 boe/d (77% oil and NGL) during Q1/2021, as compared to 25,154 boe/d in Q4/2020. During the first quarter, we commenced production from 24 (7.0 net) wells, up from 9 (2.7 net) wells in Q4/2020. In Q1/2021, we invested $41 million on exploration and development in the Eagle Ford and generated an operating netback of $84 million. We expect to bring approximately 20 net wells on production in the Eagle Ford in 2021, up from 18 net wells previously.

 

Notes:

 

(1)2021 full-year pricing assumptions: WTI - US$60/bbl; WCS differential - US$12/bbl; MSW differential – US$4.5/bbl, NYMEX Gas - US$2.80/mcf; AECO Gas - $2.80/mcf and Exchange Rate (CAD/USD) - 1.25.

(2)As announced on December 2, 2020.

 

4Baytex Energy Corp. First Quarter Report 2021

 

 

Production in the Viking averaged 19,403 boe/d (91% oil and NGL) during Q1/2021, as compared to 15,326 boe/d in Q4/2020. During the first quarter, we commenced production from 44 (43.2 net) wells. In Q1/2021, we invested $35 million on exploration and development in the Viking and generated an operating netback of $72 million. We expect to bring approximately 120 net wells on production in the Viking in 2021.

 

Heavy Oil

 

Our heavy oil assets at Peace River and Lloydminster produced a combined 24,395 boe/d (90% oil and NGL) during the Q1/2021, as compared to 24,228 boe/d in Q4/2020. We scheduled minimal heavy oil development for the first half of 2021. Our heavy oil program is expected to kick off in July with 35 net wells planned for the year, including up to six net wells in our Spirit River (Clearwater equivalent) play.

 

Peace River Clearwater

 

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. One year ago, 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. At the time, we identified significant potential for this early stage exploratory play targeting the Spirit River formation, a Clearwater formation equivalent.

 

Our initial exploration well was drilled during the first quarter and has shown promising early results with a 30-day initial production rate of 175 bbl/d from two laterals. With this early success, we are planning up to six additional Clearwater multi-lateral wells for H2/2021. Across our acreage position in northwest Alberta, we estimate that over 100 sections are prospective for Clearwater development.

 

Pembina Area Duvernay Light Oil

 

Production in the Pembina Duvernay averaged 2,138 boe/d (84% oil and NGL) during Q1/2021, as compared to 2,031 boe/d in Q4/2020. We now have nine producing wells in the Pembina area and have significantly de-risked our approximately 38- kilometre long acreage fairway, where we hold 232 sections (100% working interest) of Duvernay land. We plan to drill a further two 100% working interest wells in the second half of the year.

 

Financial Liquidity

 

Our credit facilities total approximately $1.0 billion and have a maturity date of April 2, 2024. These are not borrowing base facilities and do not require annual or semi-annual reviews. As of March 31, 2021, we had $401 million of undrawn capacity on our credit facilities, resulting in liquidity, net of working capital, of $381 million. We are well within our financial covenants and our first long-term note maturity of US$400 million is not until June 2024.

 

Our net debt, which includes our credit facilities, long-term notes and working capital, totaled $1.76 billion at March 31, 2021, down from $1.85 billion at December 31, 2020. Based on the forward strip, we expect to increase our financial liquidity to over $550 million in 2021.

 

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 47% 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$44.71/bbl with upside participation to US$52.42/bbl. We also have WTI-MSW differential hedges on approximately 50% of our expected 2021 Canadian light oil production at US$5.05/bbl and WCS differential hedges on approximately 55% of our expected 2021 heavy oil production at a WTI-WCS differential of approximately US$13.31/bbl.

 

For 2022, we have entered into hedges on approximately 33% of our net crude oil exposure utilizing a combination of swaptions at US$53.50/bbl and a 3-way option structure that provides price protection at US$54.91/bbl with upside participation to US$64.68/bbl. We also have WCS differential hedges on approximately 35% of our expected 2022 heavy oil production at a WTI-WCS differential of approximately US$12.47/bbl.

 

A complete listing of our financial derivative contracts can be found in Note 16 to our Q1/2021 financial statements.

 

Baytex Energy Corp. First Quarter Report 20215

 

 

Additional Information

 

Our condensed consolidated interim unaudited financial statements for the three months ended March 31, 2021 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.

 

Conference Call Tomorrow
9:00 a.m. MDT (11:00 a.m. EDT)

 

Baytex will host a conference call tomorrow, April 30, 2021, 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/baytex20210430.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.

  

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 “believe”, “continue”, “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 2021 plan to maximize free cash flow and accelerate our deleveraging strategy; expected 2021 free cash flow and liquidity; that our 5 year-outlook demonstrates financial and operational sustainability at US$55 WTI and will generate >$1 billion of cumulative free cash flow; our Clearwater drilling plans for H2/2021; our revised capital spending and production guidance for 2021, and the timing and location of our incremental capital spending; for our 2021 outlook: that we will maintain a disciplined and returns based capital allocation philosophy, assumes US $55 WTI constant pricing, targets capital spending at less than 70% of adjusted fund flow; the associated annual capital spending, materially improves our leverage metrics, targets net debt to EBITDA of under 1.5x, positions for enhanced shareholder returns which could be share buy-backs, a dividend or reinvestment for organic growth; in 2021 we expect to benefit from our diversified oil weighted portfolio and our commitment to allocate capital effectively; our priority is to generate stable production, maximize free cash flow and further strengthen our balance sheet; updated guidance for 2021 exploration and development expenditures, production, royalty rate, operating, transportation, general and administration and interest expense and leasing expenditures and asset retirement obligations; in 2021 that we expect to: bring on production 20 net wells in the Eagle Ford and 120 in the Viking, kick off our heavy oil program in July and drill 35 net wells, including 6 additional Clearwater wells, and drill 2 net wells in the Duvernay; that we have 100 sections of highly prospective Clearwater lands and that we have de-risked our approximately 38-kilometer acreage fairway in the Pembina Duvernay; that we expect to maintain our financial liquidity and our expected liquidity at year-end 2021; that we use financial derivative contracts and crude-by-rail to reduce adjusted funds flow volatility, the percentage of our expected production in 2021 and 2022 we have hedged and the percentage of our expected exposure to the light oil differential and heavy oil differential to WTI we have hedged. 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.

 

6Baytex Energy Corp. First Quarter Report 2021

 

 

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, 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, exploration and development expenditures, free cash flow, 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, exploration and development expenditures, free cash flow, 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, 2021.

 

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.

 

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.

 

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.

 

Baytex Energy Corp. First Quarter Report 20217

 

 

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 three months ended March 31, 2021. 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.

 

  Three Months Ended March 31, 2021 
  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  12,170   8   24   12,683   14,316 
Lloydminster  9,819   5      1,529   10,079 
                     
Canada - Light                    
Viking     17,466   133   10,823   19,403 
Duvernay     1,148   657   1,997   2,138 
Remaining Properties     601   1,156   26,077   6,103 
                     
United States                    
Eagle Ford     16,202   4,268   37,630   26,741 
                     
Total  21,989   35,430   6,238   90,739   78,780 

 

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.

 

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

 

8Baytex Energy Corp. First Quarter Report 2021

 

 

Baytex Energy Corp.

Q1 2021 MD&A

 

 

BAYTEX ENERGY CORP. 

Management’s Discussion and Analysis 

For the three months ended March 31, 2021 and 2020
Dated April 29, 2021

 

The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three months ended March 31, 2021. This information is provided as of April 29, 2021. In this MD&A, references to “Baytex”, the “Company”, “we”, “us” and “our” and similar terms refer to Baytex Energy Corp. and its subsidiaries on a consolidated basis, except where the context requires otherwise. The results for the three months ended March 31, 2021 (“Q1/2021”) have been compared with the results for the three months ended March 31, 2020 (“Q1/2020”). This MD&A should be read in conjunction with the Company’s condensed consolidated interim financial statements (“consolidated financial statements”) for the three months ended March 31, 2021, its audited comparative consolidated financial statements for the years ended December 31, 2020 and 2019, together with the accompanying notes, and its Annual Information Form for the year ended December 31, 2020. These documents and additional information about Baytex are accessible on the SEDAR website at www.sedar.com and through the U.S. Securities and Exchange Commission at www.sec.gov. All amounts are in Canadian dollars, unless otherwise stated, and all tabular amounts are in thousands of Canadian dollars, except for percentages and per common share amounts or as otherwise noted.

 

In this MD&A, 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, which represents an energy equivalency conversion method applicable at the burner tip and does not represent a value equivalency at the wellhead. While it is useful for comparative measures, it may not accurately reflect individual product values and may be misleading if used in isolation.

 

This MD&A contains forward-looking information and statements along with certain measures which do not have any standardized meaning prescribed by Canadian Generally Accepted Accounting Principles (“GAAP”). The terms “adjusted funds flow”, “operating netback”, “exploration and development expenditures”, “free cash flow”, “net debt”, and “Bank EBITDA” do not have any standardized meaning as prescribed by GAAP and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. We refer you to our advisory on forward-looking information and statements and a summary of our non-GAAP measures at the end of the MD&A.

 

BAYTEX ENERGY CORP.

 

Baytex Energy Corp. is a North American focused oil and gas company based in Calgary, Alberta. The company operates in Canada and the United States (“U.S”). The Canadian operating segment includes our light oil assets in the Viking and Duvernay, our heavy oil assets in Peace River and Lloydminster and our conventional oil and natural gas assets in Western Canada. The U.S. operating segment includes our Eagle Ford assets in Texas.

 

FIRST QUARTER HIGHLIGHTS

 

During Q1/2021, the global economy continued to show signs of recovery from the impacts of the COVID-19 pandemic. The outlook for crude oil demand has improved due to the easing of restrictions combined with the distribution of vaccines in developed countries and supply concerns have eased due to ongoing OPEC production curtailments. As a result, the average WTI benchmark price for Q1/2021 was US$57.84/bbl which was 25% higher relative to Q1/2020 when WTI averaged US$46.17/bbl. Our disciplined approach to capital allocation and continued focus on reducing our cost structure has improved the results we have achieved as commodity prices have increased.

 

We delivered strong operating and financial results for Q1/2021. Production of 78,780 boe/d was 8,305 boe/d higher than 70,475 boe/d for Q4/2020. This increase in production reflects $83.6 million invested on exploration and development which represents 53% of adjusted funds flow and generated free cash flow of $70.5 million for Q1/2021.

 

In Canada, exploration and development expenditures of $42.5 million for Q1/2021 were focused on our light oil properties. We generated production of 52,039 boe/d for Q1/2021 which was 6,718 boe/d higher than 45,321 boe/d during Q4/2020 and reflects the resumption of drilling activity which began in Q4/2020.

 

In the U.S., we invested $41.1 million on development activity during Q1/2021 and continued with the pace of development after drilling activity resumed during Q4/2020. Production of 26,741 boe/d was up 1,587 boe/d from 25,154 boe/d during Q4/2020 despite the winter storm in Texas which temporarily disrupted operations during February.

 

Adjusted funds flow was $156.6 million in Q1/2021 which is higher than $132.9 million reported for Q1/2020 as a result of the improvement in benchmark prices for Q1/2021 relative to Q1/2020. The increase in crude oil prices and our cost saving initiatives increased operating netback by $67.6 million in Q1/2021 relative to Q1/2020 despite lower production. We recorded a net loss of $35.4 million for Q1/2021 compared to a net loss of $2.5 billion in Q1/2020 which included impairments of $2.7 billion.

 

Baytex Energy Corp. First Quarter Report 20219

 

 

Baytex Energy Corp.

Q1 2021 MD&A

 

 

Net debt was $1.76 billion at March 31, 2021 compared to $1.85 billion at December 31, 2020 representing a reduction of $88.7 million. The reduction in net debt was primarily due to free cash flow of $70.5 million combined with a $18.1 million decrease in the reported amount of our U.S. dollar denominated net debt due to the strengthening of the Canadian dollar relative to the U.S. dollar during Q1/2021.

 

2021 GUIDANCE

 

The following table compares our revised 2021 annual guidance to our previously announced guidance and our Q1/2021 results. As a result of our strong operational performance combined with the improved outlook for commodity prices for the remainder of 2021 we have increased our annual production guidance to 77,000 - 79,000 boe/d with budgeted exploration and development expenditures of $285 - $315 million.

 

We have also adjusted several of our cost assumptions to reflect higher production volumes and increased activity. Our interest expense guidance is 7% lower due to reduced net debt and the Canadian dollar strengthening relative to the U.S. dollar.

 

  2021 Guidance (1)  2021 Revised Guidance Q1/2021 Results 
Exploration and development expenditures  $225 - $275 million  $285 - $315 million  $83.6 million 
Production (boe/d)  73,000 - 77,000  77,000 - 79,000  78,780 
           
Expenses:          
Royalty rate  

18.0% - 18.5%

  

no change

  18.2% 
Operating  $11.50 - $12.25/boe  $11.25 - $12.00/boe  $11.36/boe 
Transportation  $1.00 - $1.10/boe  $1.15 - $1.25/boe  $1.24/boe 
General and administrative  $42 million ($1.53/boe)  $42 million ($1.48/boe)  $8.7 million ($1.23/boe) 
Interest  $105 million ($3.84/boe)  $98 million ($3.46/boe)  $24.4 million ($3.44/boe) 
           
Leasing expenditures  $4 million  no change  $1.1 million 
Asset retirement obligations  $6 million  no change  $1.4 million 

 

(1)As announced on December 2, 2020.

 

10Baytex Energy Corp. First Quarter Report 2021

 

 

Baytex Energy Corp.
Q1 2021 MD&A

 

 

RESULTS OF OPERATIONS

 

The Canadian operating segment includes our light oil assets in Viking and Duvernay, our heavy oil assets in Peace River and Lloydminster and our conventional oil and natural gas assets in Western Canada. The U.S. operating segment includes our Eagle Ford assets in Texas.

 

Production

 

  Three Months Ended March 31 
  2021  2020 
  Canada  U.S.  Total  Canada  U.S.  Total 
Daily Production                        
Liquids (bbl/d)                        
Light oil and condensate  19,228   16,202   35,430   24,241   21,476   45,717 
Heavy oil  21,989      21,989   28,854      28,854 
Natural Gas Liquids (NGL)  1,970   4,268   6,238   1,317   6,505   7,822 
Total liquids (bbl/d)  43,187   20,470   63,657   54,412   27,981   82,393 
Natural gas (mcf/d)  53,109   37,630   90,739   47,100   49,256   96,356 
Total production (boe/d)  52,039   26,741   78,780   62,262   36,190   98,452 
Production Mix                        
Segment as a percent of total  66%  34%  100%  63%  37%  100%
Light oil and condensate  37%  61%  45%  39%  59%  46%
Heavy oil  42%  %  28%  46%  %  29%
NGL  4%  16%  8%  2%  18%  8%
Natural gas  17%  23%  19%  13%  23%  17%

 

Production was 78,780 boe/d for Q1/2021 compared to 98,452 boe/d for Q1/2020. Total production was lower in Q1/2021 compared to Q1/2020 as we reduced exploration and development activity following the sharp decline in commodity prices in March 2020. We restarted activity in Canada and the U.S. late in 2020 as commodity prices began to recover resulting in production of 78,780 boe/d for Q1/2021. As a result of our strong operational performance and an improved outlook for commodity prices for the remainder of 2021 we have increased our annual production guidance to 77,000 - 79,000 boe/d with a modest increase in planned capital spending for the second half of 2021.

 

In Canada, production was 52,039 boe/d for Q1/2021 compared to 62,262 boe/d for Q1/2020. Production for Q1/2021 was lower than Q1/2020 as we limited development spending following the decline in crude oil prices in March 2020. Activity resumed in the second half of 2020 and the pace of development continued during Q1/2021 and resulted in production increasing 6,718 boe/d relative to 45,321 boe/d during Q4/2020.

 

In the U.S., production was 26,741 boe/d for Q1/2021 compared to 36,190 boe/d for Q1/2020. The decrease reflects limited development activity during 2020 along with the impact of the Texas storm that disrupted operations in February 2021. Development activity on our U.S. land resumed in the second half of 2020 and we initiated production from 24 (7.0 net) wells during Q1/2021 which resulted in production increasing 1,587 boe/d relative to 25,154 boe/d during Q4/2020.

 

Commodity Prices

 

The prices received for our crude oil and natural gas production directly impact our earnings, adjusted funds flow and our financial position.

 

Crude Oil

 

Global benchmark prices for crude oil continued to strengthen during Q1/2021 as the outlook for oil demand improved due to the forecasted increase in global economic activity and OPEC has maintained production curtailments that restrict supply. These factors resulted in the WTI benchmark price averaging US$57.84/bbl for Q1/2021 which was 25% higher relative to Q1/2020 when WTI averaged US$46.17/bbl.

 

Baytex Energy Corp. First Quarter Report 202111

 

 

Baytex Energy Corp.
Q1 2021 MD&A

 

 

We compare the price received for our U.S. crude oil production to the Magellan East Houston (“MEH”) stream at Houston, Texas which is a representative benchmark for light oil pricing at the U.S. Gulf coast. The MEH benchmark averaged US$59.36/bbl during Q1/2021 compared to US$49.54/bbl during Q1/2020. The MEH benchmark was at a US$1.52/bbl premium to WTI in Q1/2021 compared to a US$3.37/bbl premium to WTI during Q1/2020. The decrease in the MEH benchmark premium to WTI in Q1/2021 was a result of lower refinery demand on the U.S. Gulf coast due to the Texas storm in February 2021.

 

Prices for Canadian oil trade at a discount to WTI due to a lack of egress to diversified markets from Western Canada. Canadian light and heavy oil differentials to WTI were narrower in Q1/2021 relative to Q1/2020 as a result of lower Canadian oil production.

 

We compare the price received for our light oil production in Canada to the Edmonton par benchmark oil price while pricing for our heavy oil production is based on the WCS benchmark price. The Edmonton par price averaged $66.58/bbl during Q1/2021 compared to $51.43/bbl during Q1/2020 and traded at a discount to WTI of US$5.27/bbl for Q1/2021 compared to a discount of US$7.92/bbl for Q1/2020. The WCS heavy oil price was also stronger in Q1/2021 and averaged $57.46/bbl compared to $34.48/bbl for Q1/2020. The WCS heavy oil differential was US$12.46/bbl in Q1/2021 compared to US$20.53/bbl for Q1/2020.

 

Natural Gas

 

Our U.S. natural gas production is priced in reference to the New York Mercantile Exchange (“NYMEX”) natural gas index. The NYMEX natural gas benchmark averaged US$2.69/mmbtu in Q1/2021 which is higher than US$1.95/mmbtu in Q1/2020. The winter storm in Texas resulted in lower U.S. natural gas production and increased demand which resulted in higher natural gas prices in Q1/2021 relative to Q1/2020.

 

In Canada, we receive natural gas pricing based on the AECO benchmark which continues to trade at a discount to NYMEX as a result of increasing supply and limited market access for Canadian natural gas production. The AECO benchmark averaged $2.93/ mcf during Q1/2021 which is higher than $2.14/mcf for Q1/2020. The AECO gas benchmark was higher in Q1/2021 relative to Q1/2020 as a result of increased North American demand during the winter season.

 

The following tables compare select benchmark prices and our average realized selling prices for the three months ended March 31, 2021 and 2020. 

 

  Three Months Ended March 31 
  2021  2020  Change 
Benchmark Averages            
WTI oil (US$/bbl) (1)  57.84   46.17   11.67 
MEH oil (US$/bbl) (2)  59.36   49.54   9.82 
MEH oil differential to WTI (US$/bbl)  1.52   3.37   (1.85)
Edmonton par oil ($/bbl) (3)  66.58   51.43   15.15 
Edmonton par oil differential to WTI (US$/bbl)  (5.27)  (7.92)  2.65 
WCS heavy oil ($/bbl) (4)  57.46   34.48   22.98 
WCS heavy oil differential to WTI (US$/bbl)  (12.46)  (20.53)  8.07 
AECO natural gas price ($/mcf) (5)  2.93   2.14   0.79 
NYMEX natural gas price (US$/mmbtu) (6)  2.69   1.95   0.74 
CAD/USD average exchange rate  1.2663   1.3445   (0.0782)

 

(1)WTI refers to the arithmetic average of NYMEX prompt month WTI for the applicable period.

(2)MEH refers to arithmetic average of the Argus WTI Houston differential weighted index price for the applicable period.

(3)Edmonton par refers to the average posting price for the benchmark MSW crude oil.

(4)WCS refers to the average posting price for the benchmark WCS heavy oil.

(5)AECO refers to the AECO arithmetic average month-ahead index price published by the Canadian Gas Price Reporter (“CGPR”).

(6)NYMEX refers to the NYMEX last day average index price as published by the CGPR.

  

12Baytex Energy Corp. First Quarter Report 2021

 

 

Baytex Energy Corp.
Q1 2021 MD&A

 

 

  Three Months Ended March 31 
  2021  2020 
  Canada  U.S.  Total  Canada  U.S.  Total 
Average Realized Sales Prices                        
Light oil and condensate ($/bbl) $64.46  $72.42  $68.10  $49.45  $61.99  $55.34 
Heavy oil ($/bbl) (1)  46.45      46.45   20.75      20.75 
NGL ($/bbl)  24.61   34.21   31.18   11.25   14.94   14.31 
Natural gas ($/mcf)  3.03   7.84   5.02   2.00   2.63   2.32 
Weighted average ($/boe) (1) $47.47  $60.36  $51.84  $30.62  $43.05  $35.19 

 

(1)Realized heavy oil prices are calculated based on sales volumes and sales dollars, net of blending and other expense.

 

Average Realized Sales Prices

 

Our weighted average sales price was $51.84/boe for Q1/2021 compared to $35.19/boe for Q1/2020. Our realized price in the U.S. was $60.36/boe in Q1/2021 which is $17.31/boe higher than $43.05/boe in Q1/2020. In Canada, our realized price of $47.47/boe for Q1/2021 was $16.85/boe higher than $30.62/boe for Q1/2020. The increase in our realized price in Canada and the U.S. for Q1/2021 was a result of higher North American benchmark prices relative to Q1/2020.

 

We compare our light oil realized price in Canada to the Edmonton par benchmark price. Our realized light oil and condensate price was $64.46/bbl in Q1/2021 compared to $49.45/bbl in Q1/2020. Our realized light oil and condensate price for Q1/2021 increased with the improvement in the benchmark price and represents a discount of $2.12/bbl to the Edmonton par price which is relatively consistent with the discount of $1.98/bbl experienced in Q1/2020.

 

We compare the price received for our U.S. light oil and condensate production to the MEH benchmark. Our realized light oil and condensate price averaged $72.42/bbl for Q1/2021 compared to $61.99/bbl for Q1/2020. Expressed in U.S. dollars, our realized light oil and condensate price of US$57.19/bbl for Q1/2021 represents a US$2.17/bbl discount to MEH which is narrower than a discount of US$3.43/bbl for Q1/2020 and reflects strong price realizations on our marketing contracts in place during Q1/2021.

 

Our realized heavy oil price, net of blending and other expense averaged $46.45/bbl in Q1/2021 compared to $20.75/bbl in Q1/2020. Our realized heavy oil price for Q1/2021 was $25.70/bbl higher relative to Q1/2020 compared to a $22.98/bbl increase in the WCS benchmark price over the same period. Our realized heavy oil price increased more than the WCS benchmark as a result of stronger price realizations on our marketing contracts in place for 2021.

 

Our realized NGL price as a percentage of WTI can vary from period to period based on the product mix of our NGL volumes and changes in the market prices for the underlying products. Our realized NGL price was $31.18/bbl in Q1/2021 or 43% of WTI (expressed in Canadian dollars) compared to $14.31/bbl or 23% of WTI (expressed in Canadian dollars) in Q1/2020. Our realized NGL price was higher as a percentage of WTI in Q1/2021 relative to Q1/2020 as strong demand along with reduced supply due to the Texas storm combined to increase NGL pricing in Q1/2021.

 

We compare our realized natural gas price in Canada to the AECO benchmark price. Our realized natural gas price was $3.03/mcf for Q1/2021 compared to $2.00/mcf in Q1/2020 and was relatively consistent with the AECO benchmark price in both periods. In the U.S., our realized natural gas price was US$6.19/mcf for Q1/2021 compared to US$1.96/mcf in Q1/2020. A portion of our natural gas production is based on the NYMEX daily index which resulted in a US$3.50/mcf premium to the NYMEX monthly benchmark for Q1/2021 due to the fluctuations in the daily index caused by the winter storm in Texas.

 

Baytex Energy Corp. First Quarter Report 202113

 

 

Baytex Energy Corp.
Q1 2021 MD&A

 

 

Petroleum and Natural Gas Sales 

 

  Three Months Ended March 31 
  2021  2020 
($ thousands) Canada  U.S.  Total  Canada  U.S.  Total 
Oil sales                        
Light oil and condensate $111,546  $105,596  $217,142  $109,084  $121,155  $230,239 
Heavy oil  109,038      109,038   75,843      75,843 
NGL  4,364   13,142   17,506   1,348   8,842   10,190 
Total oil sales  224,948   118,738   343,686   186,275   129,997   316,272 
Natural gas sales  14,475   26,541   41,016   8,569   11,773   20,342 
Total petroleum and natural gas sales  239,423   145,279   384,702   194,844   141,770   336,614 
Blending and other expense  (17,120)     (17,120)  (21,357)     (21,357)
Total sales, net of blending and other expense $222,303  $145,279  $367,582  $173,487  $141,770  $315,257 

 

Total sales, net of blending and other expense, of $367.6 million for Q1/2021 increased $52.3 million from $315.3 million reported for Q1/2020. The increase in total sales in Q1/2021 relative to Q1/2020 is a result of higher realized pricing due to the increase in benchmark pricing which more than offset the impact of lower sales volumes.

 

In Canada, total sales, net of blending and other expense, was $222.3 million for Q1/2021 which is an increase of $48.8 million from $173.5 million reported for Q1/2020. Total petroleum and natural gas sales increased due to higher realized pricing for Q1/2021 relative to Q1/2020. Our average realized price of $47.47/boe for Q1/2021 was higher than the realized price of $30.62/ boe for Q1/2020 due to the increase in benchmark pricing resulting in a $78.9 million increase in total sales, net of blending and other expense. Production in Canada was 10,223 boe/d lower in Q1/2021 which resulted in a $30.1 million decrease in total sales, net of blending and other expense relative to Q1/2020.

 

In the U.S., petroleum and natural gas sales were $145.3 million for Q1/2021 which is an increase of $3.5 million from $141.8 million reported for Q1/2020. Total petroleum and natural gas sales increased due to higher realized pricing for Q1/2021 relative to Q1/2020. Our average realized price of $60.36/boe for Q1/2021 was higher than $43.05/boe for Q1/2020 due to the increase in benchmark pricing and resulted in a $41.7 million increase in total sales, net of blending and other expense. Production in the U.S. was 9,449 boe/d lower in Q1/2021 which resulted in a $38.2 million decrease in total sales, net of blending and other expense relative to Q1/2020.

 

Royalties

 

Royalties are paid to various government entities and to land and mineral rights owners. Royalties are calculated based on gross revenues or on operating netbacks less capital investment for specific heavy oil projects and are generally expressed as a percentage of total sales, net of blending and other expense. The actual royalty rates can vary for a number of reasons, including the commodity produced, royalty contract terms, commodity price level, royalty incentives and the area or jurisdiction. The following table summarizes our royalties and royalty rates for the three months ended March 31, 2021 and 2020.

  

  Three Months Ended March 31 
  2021  2020 
($ thousands except for % and per boe) Canada  U.S.  Total  Canada  U.S.  Total 
Royalties $24,664  $42,286  $66,950  $15,518  $41,202  $56,720 
Average royalty rate (1)  11.1%  29.1%  18.2%  8.9%  29.1%  18.0%
Royalties per boe $5.27  $17.57  $9.44  $2.74  $12.51  $6.33 

 

(1)Average royalty rate is calculated as royalties divided by total sales, net of blending and other expense.

 

Royalties for Q1/2021 were $67.0 million or 18.2% of total sales, net of blending and other expense compared to $56.7 million or 18.0% in Q1/2020. Total royalty expense was higher for Q1/2021 due to the increase in total sales, net of blending and other expense, relative to Q1/2020. Our royalty rate of 18.2% for Q1/2021 was consistent with 18.0% for Q1/2020. Our average royalty rate of 18.2% for Q1/2021 is consistent with expectations and our annual guidance range of 18.0% - 18.5% for 2021.

 

Our Canadian royalty rate of 11.1% for Q1/2021 was higher than 8.9% for Q1/2020 due to higher benchmark commodity prices which resulted in a higher royalty rate on our Canadian properties in Q1/2021 relative to Q1/2020. In the U.S., royalties averaged 29.1% of total sales for Q1/2021 which is consistent with 29.1% for Q1/2020 as the royalty rate on our U.S. production does not vary with price but can vary across our acreage.

 

14Baytex Energy Corp. First Quarter Report 2021

 

 

Baytex Energy Corp.
Q1 2021 MD&A

 

 

Operating Expense

  

  Three Months Ended March 31 
  2021  2020 
($ thousands except for per boe) Canada  U.S.  Total  Canada  U.S.  Total 
Operating expense $61,361  $19,187  $80,548  $78,922  $25,548  $104,470 
Operating expense per boe $13.10  $7.97  $11.36  $13.93  $7.76  $11.66 

 

Total operating expense was $80.5 million ($11.36/boe) for Q1/2021 compared to $104.5 million ($11.66/boe) in Q1/2020. The decrease in total operating expense for Q1/2021 compared to Q1/2020 can be attributed to lower production in addition to our cost savings initiatives which resulted in lower per boe operating expense for Q1/2021. Operating expense of $11.36/boe for Q1/2021 is consistent with expectations and our revised annual guidance range of $11.25 - $12.00/boe.

 

In Canada, operating expense was $61.4 million ($13.10/boe) for Q1/2021 compared to $78.9 million ($13.93/boe) for Q1/2020. Operating expense in Canada has decreased with lower production and our cost savings initiatives which resulted in per unit operating expense of $13.10/boe for Q1/2021 which was lower than $13.93/boe for Q1/2020.

 

U.S. operating expense was $19.2 million ($7.97/boe) for Q1/2021 compared to $25.5 million ($7.76/boe) for Q1/2020. Lower operating expense is primarily a result of lower U.S. production in Q1/2021 relative to Q1/2020. Expressed in U.S. dollars, per unit operating expense was US$6.29/boe in Q1/2021 which was slightly higher than US$5.77/boe for Q1/2020. The increase in per unit operating expense in the U.S. was a result of lower production along with additional costs incurred due to the winter storm in Texas during Q1/2021.

 

Transportation Expense

 

Transportation expense includes the costs to move production from the field to the sales point. The largest component of transportation expense relates to the trucking of oil in Canada to pipeline and rail terminals which can vary from period to period depending on hauling distances as we seek to optimize sales prices and trucking rates.

 

The following table compares our transportation expense for the three months ended March 31, 2021 and 2020.

  

  Three Months Ended March 31 
  2021  2020 
($ thousands except for per boe) Canada  U.S.  Total  Canada  U.S.  Total 
Transportation expense $8,788  $  $8,788  $10,342  $  $10,342 
Transportation expense per boe $1.88  $  $1.24  $1.83  $  $1.15 

 

Transportation expense was $8.8 million ($1.24/boe) for Q1/2021 compared to $10.3 million ($1.15/boe) in Q1/2020. The decrease in total transportation expense is primarily the result of lower production in Canada. Per unit transportation expense in Canada of $1.88/boe for Q1/2021 is relatively consistent with $1.83/boe for Q1/2020. Per unit transportation expense of $1.24/boe for Q1/2021 is consistent with expectations and our revised annual guidance of $1.15 - $1.25/boe.

 

Blending and Other Expense

 

Blending and other expense primarily includes the cost of blending diluent purchased to reduce the viscosity of our heavy oil transported through pipelines in order to meet pipeline specifications. The purchased diluent is recorded as blending and other expense. The price received for the blended product is recorded as heavy oil sales revenue. We net blending and other expense against heavy oil sales to compare the realized price on our produced volumes to benchmark pricing.

 

Blending and other expense was $17.1 million for Q1/2021 compared to $21.4 million for Q1/2020. Lower blending and other expense reflects lower heavy oil sales in Q1/2021 relative to Q1/2020.

 

Baytex Energy Corp. First Quarter Report 202115

 

 

Baytex Energy Corp.
Q1 2021 MD&A

 

 

Financial Derivatives

 

As part of our normal operations, we are exposed to movements in commodity prices, foreign exchange rates, interest rates and changes in our share price. In an effort to manage these exposures, we utilize various financial derivative contracts which are intended to partially reduce the volatility in our adjusted funds flow. Contracts settled in the period result in realized gains or losses based on the market price compared to the contract price and the notional volume outstanding. Changes in the fair value of unsettled contracts are reported as unrealized gains or losses in the period as the forward markets for commodities and currencies fluctuate and as new contracts are executed. The following table summarizes the results of our financial derivative contracts for the three months ended March 31, 2021 and 2020. 

 

  Three Months Ended March 31 
($ thousands) 2021  2020  Change 
Realized financial derivatives gain (loss)            
Crude oil $(20,041) $26,645  $(46,686)

Natural gas

  (727)  210   (937)
Interest and financing     (5)  5 
Total $(20,768) $26,850  $(47,618)
Unrealized financial derivatives gain (loss)            
Crude oil $(85,470) $99,809  $(185,279)
Natural gas  (1,387)  (122)  (1,265)
Interest and financing     (678)  678 
Equity total return swap ("Equity TRS")  873   (3,014)  3,887 
Total $(85,984) $95,995  $(181,979)
Total financial derivatives gain (loss)            
Crude oil $(105,511) $126,454  $(231,965)
Natural gas  (2,114)  88   (2,202)
Interest and financing     (683)  683 
Equity TRS  873   (3,014)  3,887 
Total $(106,752) $122,845  $(229,597)

  

We recorded total financial derivative losses of $106.8 million for Q1/2021 compared to total financial derivative gains of $122.8 million in Q1/2020. Realized financial derivative losses of $20.8 million for Q1/2021 were primarily a result of the market prices for WTI settling at levels above those set in our derivative contracts. Unrealized losses of $86.0 million for Q1/2021 is primarily a result of the increase in forecasted crude oil pricing used to revalue our WTI and WCS contracts in place at March 31, 2021 relative to December 31, 2020 along with the valuation of new contracts entered during the period. The fair value of our financial derivative contracts resulted in a net liability of $107.7 million at March 31, 2021 compared to a net liability of $21.7 million at December 31, 2020.

 

16Baytex Energy Corp. First Quarter Report 2021

 

 

Baytex Energy Corp.
Q1 2021 MD&A

 

 

We had the following commodity financial derivative contracts as at April 29, 2021.

 

  Period Volume Price/Unit (1) Index
Oil        
Basis Swap Apr 2021 to Jun 2021 2,000 bbl/d WTI less US$13.75/bbl WCS
Basis Swap Apr 2021 to Dec 2021 8,000 bbl/d WTI less US$13.41/bbl WCS
Basis Swap Jan 2022 to Dec 2022 8,000 bbl/d WTI less US$12.57/bbl WCS
Basis Swap (4) Jan 2022 to Dec 2022 1,000 bbl/d WTI less US$11.70/bbl WCS
Basis Swap Apr 2021 to Dec 2021 7,500 bbl/d WTI less US$5.03/bbl MSW
Fixed Sell Apr 2021 to Dec 2021 4,000 bbl/d US$45.00/bbl WTI
3-way option (2) Apr 2021 to Dec 2021 500 bbl/d US$35.00/US$45.00/US$49.03 WTI
3-way option (2) Apr 2021 to Dec 2021 1,500 bbl/d US$35.00/US$45.00/US$49.10 WTI
3-way option (2) Apr 2021 to Dec 2021 3,500 bbl/d US$35.00/US$45.00/US$49.50 WTI
3-way option (2) Apr 2021 to Dec 2021 10,000 bbl/d US$35.00/US$45.00/US$55.00 WTI
3-way option (2) Apr 2021 to Dec 2021 2,000 bbl/d US$37.00/US$42.50/US$48.00 WTI
3-way option (2) Jan 2022 to Dec 2022 1,500 bbl/d US$40.00/US$50.00/US$58.10 WTI
3-way option (2) Jan 2022 to Dec 2022 2,000 bbl/d US$46.00/US$56.00/US$66.72 WTI
3-way option (2)(4) Jan 2022 to Dec 2022 2,500 bbl/d US$47.00/US$57.00/US$67.00 WTI
Swaption (3) Jan 2022 to Dec 2022 5,000 bbl/d US$53.00/bbl WTI
Swaption (3) Jan 2022 to Dec 2022 5,000 bbl/d US$54.00/bbl WTI
         
Natural Gas        
Fixed Sell Apr 2021 to Jun 2021 3,000 GJ/d $2.71/GJ AECO 7A
Fixed Sell Apr 2021 to Dec 2021 16,000 GJ/d $2.36/GJ AECO 7A
Fixed Sell (4) Jan 2022 to Dec 2022 2,500 GJ/d $2.40/GJ AECO 7A
Fixed Sell Apr 2021 to Dec 2021 2,500 GJ/d $2.40/GJ AECO 5A
Fixed Sell Apr 2021 to Dec 2021 12,000 mmbtu/d US$2.70/mmbtu NYMEX
3-way option (2) Jan 2022 to Dec 2022 2,500 mmbtu/d US$2.25/US$2.75/US$3.06 NYMEX
3-way option (2) Jan 2022 to Dec 2022 2,500 mmbtu/d US$2.65/US$2.90/US$3.40 NYMEX

 

(1)Based on the weighted average price per unit for the period.

(2)Producer 3-way option consists of a sold put, a bought put and a sold call. To illustrate, in a US$35.00/US$45.00/US$55.00 contract, Baytex receives WTI plus US$10.00/bbl when WTI is at or below US$35.00/bbl; Baytex receives US$45.00/bbl when WTI is between US$35.00/bbl and US$45.00/bbl; Baytex receives the market price when WTI is between US$45.00/bbl and US$55.00/bbl; and Baytex receives US$55.00/ bbl when WTI is above US$55.00/bbl.

(3)For these contracts, the counterparty has the right, if exercised on December 31, 2021, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above.

(4)Contracts entered subsequent to March 31, 2021.

 

Operating Netback

 

The following table summarizes our operating netback on a per boe basis for our Canadian and U.S. operations for the three months ended March 31, 2021 and 2020.

 

  Three Months Ended March 31 
  2021  2020 
($ per boe except for volume) Canada  U.S.  Total  Canada  U.S.  Total 
Total production (boe/d)  52,039   26,741   78,780   62,262   36,190   98,452 
Operating netback:                        
Total sales, net of blending and other expense $47.47  $60.36  $51.84  $30.62  $43.05  $35.19 
Less:                        
Royalties  (5.27)  (17.57)  (9.44)  (2.74)  (12.51)  (6.33)
Operating expense  (13.10)  (7.97)  (11.36)  (13.93)  (7.76)  (11.66)
Transportation expense  (1.88)     (1.24)  (1.83)     (1.15)
Operating netback $27.22  $34.82  $29.80  $12.12  $22.78  $16.05 
Realized financial derivatives (loss) gain        (2.93)        3.00 
Operating netback after financial derivatives $27.22  $34.82  $26.87  $12.12  $22.78  $19.05 

 

Baytex Energy Corp. First Quarter Report 202117

 

 

Baytex Energy Corp.
Q1 2021 MD&A

 

 

Operating netback of $29.80/boe for Q1/2021 was higher than $16.05/boe for Q1/2020 due to the increase in benchmark pricing in Canada and the U.S. which resulted in higher per unit sales net of royalties. Total operating and transportation expense of $12.60/ boe for Q1/2021 reflects our cost savings initiatives which resulted in lower costs relative to $12.81/boe in Q1/2020. Including realized gains and losses on financial derivatives our operating netback was $26.87/boe for Q1/2021 which was $7.82/boe higher than $19.05/boe reported for Q1/2020.

 

General and Administrative Expense

 

General and administrative (“G&A”) expense includes head office and corporate costs such as salaries and employee benefits, public company costs and administrative recoveries earned for operating exploration and development activities on behalf of our working interest partners. G&A expense fluctuates with head office staffing levels and the level of operated exploration and development activity during the period.

 

The following table summarizes our G&A expense for the three months ended March 31, 2021 and 2020. 

 

  Three Months Ended March 31 
($ thousands except for per boe) 2021  2020  Change 
Gross general and administrative expense $9,462  $11,888  $(2,426)
Overhead recoveries  (729)  (2,113)  1,384 
General and administrative expense $8,733  $9,775  $(1,042)
General and administrative expense per boe $1.23  $1.09  $0.14 

 

G&A expense was $8.7 million ($1.23/boe) for Q1/2021 compared to $9.8 million ($1.09/boe) for Q1/2020. G&A expense of $8.7 million for Q1/2021 was lower than $9.8 million for Q1/2020 primarily due to reduced staffing levels along with our cost savings initiatives that resulted in lower gross G&A expense. G&A expense per boe was slightly higher in Q1/2021 due to lower production compared to Q1/2020.

 

G&A expense of $1.23/boe reflects our costs savings initiatives along with temporarily lower staffing levels and is slightly below our revised annual guidance of $1.42/boe for 2021.

 

Financing and Interest Expense

 

Financing and interest expense includes interest on our credit facilities, long-term notes and lease obligations as well as non-cash financing costs which include the accretion on our debt issue costs and asset retirement obligations. Financing and interest expense varies depending on debt levels outstanding during the period, the applicable borrowing rates, CAD/USD foreign exchange rates, along with the carrying amount of asset retirement obligations and the discount rates used to present value these obligations.

 

The following table summarizes our financing and interest expense for the three months ended March 31, 2021 and 2020.

  

  Three Months Ended March 31 
($ thousands except for per boe) 2021  2020  Change 
Interest on credit facilities $3,336  $4,135  $(799)
Interest on long-term notes  21,007   24,273   (3,266)
Interest on lease obligations  60   127   (67)
Cash interest $24,403  $28,535  $(4,132)
Accretion of debt issue costs  749   4,442   (3,693)
Accretion of asset retirement obligations  2,298   2,931   (633)
Early redemption expense     3,312   (3,312)
Financing and interest expense $27,450  $39,220  $(11,770)
Cash interest per boe $3.44  $3.19  $0.25 
Financing and interest expense per boe $3.87  $4.38  $(0.51)

 

Financing and interest expense was $27.5 million ($3.87/boe) for Q1/2021 compared to $39.2 million ($4.38/boe) for Q1/2020.

 

18Baytex Energy Corp. First Quarter Report 2021

 

 

Baytex Energy Corp.
Q1 2021 MD&A

 

 

Cash interest of $24.4 million ($3.44/boe) for Q1/2021 is lower than $28.5 million ($3.19/boe) for Q1/2020 primarily due to lower interest on our long-term notes. The reported interest on our U.S. dollar denominated long-term notes was lower due to a stronger Canadian dollar in Q1/2021 relative to Q1/2020. The average principal amount of long-term notes outstanding was also lower in Q1/2021 as the refinancing transactions completed in Q1/2020 resulted in a temporary increase in principal amounts outstanding. Interest on our credit facilities was lower in Q1/2021 due to lower borrowings and interest rates on our credit facilities which resulted in a weighted average interest rate of 2.1% compared to 3.4% in Q1/2020.

 

Financing and interest expense for Q1/2021 was lower than Q1/2020 which included the accelerated amortization of debt issue costs and $3.3 million of early redemption expense associated with the $300 million principal amount of 6.625% senior unsecured notes which were redeemed on March 5, 2020.

 

Cash interest expense of $3.44/boe for Q1/2021 is consistent with our revised annual guidance of $3.46/boe for 2021.

 

Exploration and Evaluation Expense

 

Exploration and evaluation (“E&E”) expense is related to the expiry of leases and the de-recognition of costs for exploration programs that have not demonstrated commercial viability and technical feasibility. E&E expense will vary depending on the timing of expiring leases, the accumulated costs of the expiring leases and the economic facts and circumstances related to the Company’s exploration programs. Exploration and evaluation expense was $0.9 million for Q1/2021 which is higher than $0.3 million for Q1/2020 due to a higher amount of acreage expiring in 2021 relative to 2020.

 

Depletion and Depreciation

 

Depletion and depreciation expense varies with the carrying amount of the Company’s oil and gas properties, the amount of proved plus probable reserves volumes and the rate of production for the period. The following table summarizes depletion and depreciation expense for the three months ended March 31, 2021 and 2020.

  

  Three Months Ended March 31 
($ thousands except for per boe) 2021  2020  Change 
Depletion $100,739  $179,418  $(78,679)
Depreciation  1,273   1,968   (695)
Depletion and depreciation $102,012  $181,386  $(79,374)
Depletion and depreciation per boe $14.39  $20.25  $(5.86)

 

Depletion and depreciation expense was $102.0 million ($14.39/boe) for Q1/2021 compared to $181.4 million ($20.25/boe) for Q1/2020. Total depletion and depreciation expense and the depletion rate per boe were lower in Q1/2021 compared to Q1/2020 due to lower production in Q1/2021 combined with $2.2 billion of net impairments recorded in 2020 which reduced the depletable base of our oil and gas properties at Q1/2021.

 

Impairment

 

We did not identify indicators of impairment or impairment reversal for any of our cash generating units (“CGU”) at March 31, 2021.

 

At March 31, 2020, we identified indicators of impairment due to the sharp decline in forecasted commodity prices. We performed impairment tests on the E&E assets and oil and gas properties for our six CGUs. We recorded total impairments of $2.7 billion in Q1/2020 as the carrying value of the E&E assets and oil and gas properties exceeded the estimated recoverable amounts of the CGUs. The total impairment recorded at Q1/2020 included $2.6 billion related to oil and gas properties and $0.1 billion related to E&E assets.

 

At December 31, 2020, with updated development plans, including capital efficiencies and reduced well costs, reflected in our reserves along with changes in commodity prices, we estimated the recoverable amount for E&E assets and oil and gas properties in each of our six CGUs. We recorded an impairment reversal of $356.1 million at December 31, 2020 as the estimated recoverable amount of the Viking and Eagle Ford CGUs exceeded their carrying value. The total impairment reversal recorded at Q4/2020 includes $341.3 million related to oil and gas properties and $14.8 million related to E&E assets.

 

Baytex Energy Corp. First Quarter Report 202119

 

 

Baytex Energy Corp.
Q1 2021 MD&A

 

 

Share-Based Compensation Expense

 

Share-based compensation (“SBC”) expense includes expense associated with our Share Award Incentive Plan, Incentive Award Plan, and Deferred Share Unit Plan. SBC expense associated with our Share Award Incentive Plan is recognized in net income or loss over the vesting period of the awards with a corresponding increase in contributed surplus. SBC expense associated with our Incentive Award Plan is recognized in net income or loss over the vesting period of the awards with a corresponding financial liability and includes gains or losses on equity total return swaps used to fix the aggregate cost of new grants made under the plan. SBC expense associated with the Deferred Share Unit Plan is recognized in net income or loss on the grant date with a corresponding financial liability and includes gains or losses on equity total return swaps used to fix the aggregate cost of new grants made under the plan. SBC expense varies with the quantity of unvested share awards outstanding and the grant date fair value assigned to the share awards.

 

We recorded SBC expense of $3.0 million for Q1/2021 compared to $2.8 million for Q1/2020. SBC expense is higher due to the issuance of Deferred Share Units in Q1/2021 which are expensed in full on the grant date. The total expense for Q1/2021 is comprised of non-cash compensation expense of $1.5 million related to the Share Award Incentive Plan and cash compensation expense of $1.5 million related to the Incentive Award Plan and the Deferred Share Unit Plan.

 

Foreign Exchange

 

Unrealized foreign exchange gains and losses are primarily a result of changes in the reported amount of our U.S. dollar denominated long-term notes and our U.S. dollar denominated intercompany notes. The long-term notes and intercompany notes are translated to Canadian dollars on the balance sheet date using the closing CAD/USD exchange rate resulting in unrealized gains and losses. Realized foreign exchange gains and losses are due to day-to-day U.S. dollar denominated transactions occurring in our Canadian functional currency entities.

  

  Three Months Ended March 31 
($ thousands except for exchange rates) 2021  2020  Change 
Unrealized foreign exchange loss - intercompany notes (1) $13,741  $  $13,741 
Unrealized foreign exchange (gain) loss - long-term notes  (16,271)  99,521   (115,792)
Realized foreign exchange (gain) loss  (275)  371   (646)
Foreign exchange (gain) loss $(2,805) $99,892  $(102,697)
CAD/USD exchange rates:            
At beginning of period  1.2755   1.2965     
At end of period  1.2572   1.4120     

 

(1)During 2020, a series of intercompany notes totaling US$751.0 million were issued from a Canadian subsidiary to a U.S. subsidiary. These notes are eliminated upon consolidation within the Condensed Consolidated Statement of Financial Position and are revalued at the relevant foreign exchange rate at each period end. Foreign exchange gains or losses incurred within the Canadian subsidiary are recognized in unrealized foreign exchange gain or loss whereas those within the U.S. subsidiary are recognized in other comprehensive income.

 

We recorded an unrealized foreign exchange gain on our long-term notes of $16.3 million for Q1/2021 due to the strengthening of the Canadian dollar relative to the U.S. dollar at March 31, 2021 compared to December 31, 2020. This compares to an unrealized foreign exchange loss of $99.5 million for Q1/2020 due to the weakening of the Canadian dollar relative to the U.S. dollar at March 31, 2020 compared to December 31, 2019.

 

We recorded an unrealized foreign exchange loss of $13.7 million for Q1/2021 on our intercompany notes issued by our Canadian subsidiary due to the strengthening of the Canadian dollar relative to the U.S. dollar at March 31, 2021 compared to December 31, 2020. There was no unrealized foreign exchange gain or loss on our intercompany notes recorded in Q1/2020 as the notes were issued in September 2020.

 

Realized foreign exchange gains and losses will fluctuate depending on the amount and timing of day-to-day U.S. dollar denominated transactions for our Canadian operations. We recorded a realized foreign exchange gain of $0.3 million for Q1/2021 compared to a loss of $0.4 million for Q1/2020.

 

Income Taxes

 

  Three Months Ended March 31 
($ thousands) 2021  2020  Change 
Current income tax (recovery) expense $(160) $469  $(629)
Deferred income tax expense (recovery)  5,664   (283,179)  288,843 
Total income tax expense (recovery) $5,504  $(282,710) $288,214 

 

20Baytex Energy Corp. First Quarter Report 2021

 

 

Baytex Energy Corp.

Q1 2021 MD&A

 

 

The current income tax recovery was $0.2 million for Q1/2021 compared to an expense of $0.5 million for Q1/2020.

 

We recorded deferred tax expense of $5.7 million for Q1/2021 compared to a $283.2 million recovery for Q1/2020 as the loss before tax was lower in Q1/2021 due to the impairment recorded in Q1/2020.

 

As disclosed in the 2020 annual financial statements, certain indirect subsidiaries received reassessments from the Canada Revenue Agency (the “CRA”) that deny $591.0 million of non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2015. In September 2016, we filed notices of objection with the CRA appealing each reassessment received. There has been no change in the status of these reassessments since an Appeals Officer was assigned to our file in July 2018. We remain confident that our original tax filings are correct and intend to defend these tax filings through the appeals process.

 

Net Income (Loss) and Adjusted Funds Flow

 

The components of adjusted funds flow and net income or loss for the three months ended March 31, 2021 and 2020 are set forth in the following table.

 

  Three Months Ended March 31 
($ thousands) 2021  2020  Change 
Petroleum and natural gas sales $384,702  $336,614  $48,088 
Royalties  (66,950)  (56,720)  (10,230)
Revenue, net of royalties  317,752   279,894   37,858 
             
Expenses            
Operating  (80,548)  (104,470)  23,922 
Transportation  (8,788)  (10,342)  1,554 
Blending and other  (17,120)  (21,357)  4,237 
Operating netback $211,296  $143,725  $67,571 
General and administrative  (8,733)  (9,775)  1,042 
Cash financing and interest  (24,403)  (28,535)  4,132 
Realized financial derivatives (loss) gain  (20,768)  26,850   (47,618)
Realized foreign exchange gain (loss)  275   (371)  646 
Other income  232   2,031   (1,799)
Current income tax expense (recovery)  160   (469)  629 
Cash share-based compensation  (1,477)  (521)  (956)
Adjusted funds flow $156,582  $132,935  $23,647 
Exploration and evaluation  (947)  (260)  (687)
Depletion and depreciation  (102,012)  (181,386)  79,374 
Non-cash share-based compensation  (1,504)  (2,262)  758 
Non-cash financing and accretion  (3,047)  (10,685)  7,638 
Non-cash other income  988      988 
Unrealized financial derivatives (loss) gain  (85,984)  95,995   (181,979)
Unrealized foreign exchange gain (loss)  2,530   (99,521)  102,051 
Gain on dispositions  3,706   137   3,569 
Impairment     (2,716,349)  2,716,349 
Deferred income tax (expense) recovery  (5,664)  283,179   (288,843)
Net loss for the period $(35,352) $(2,498,217) $2,462,865 

 

We generated adjusted funds flow of $156.6 million for Q1/2021 compared to $132.9 million reported for Q1/2020. The increase in adjusted funds flow was primarily due to higher operating netback which increased $67.6 million from Q1/2020 as a result of higher commodity prices which increased revenue, net of royalties which more than offset lower production. The increase in operating netback was partially offset by realized losses on financial derivatives of $20.8 million for Q1/2021 due to the increase in oil and natural gas benchmark prices relative to Q1/2020 when we recorded realized gains on financial derivatives of $26.9 million.

 

Baytex Energy Corp. First Quarter Report 202121

 

 

Baytex Energy Corp.

Q1 2021 MD&A

 

 

We reported a net loss of $35.4 million for Q1/2021 compared to a net loss of $2.5 billion for Q1/2020 which included $2.7 billion of impairment expense.

 

Other Comprehensive Income (Loss)

 

Other comprehensive income or loss is comprised of the foreign currency translation adjustment on U.S. net assets which includes a series of intercompany debt instruments outstanding between our Canadian and U.S. subsidiaries. Foreign exchange gains or losses on the debt owing from the U.S. subsidiary is recorded in other comprehensive income and the offsetting foreign exchange gain or loss on debt owed to the Canadian subsidiary is included in profit and loss for the period.

 

The $7.1 million foreign currency translation loss for Q1/2021 relates to the change in value of our U.S. net assets expressed in Canadian dollars and is due to the Canadian dollar strengthening relative to the U.S. dollar at March 31, 2021 compared to December 31, 2020. The CAD/USD exchange rate was 1.2572 CAD/USD as at March 31, 2021 compared to 1.2755 CAD/USD at December 31, 2020.

 

Capital Expenditures

 

Capital expenditures for the three months ended March 31, 2021 and 2020 are summarized as follows.

 

  Three Months Ended March 31 
  2021  2020 
($ thousands) Canada  U.S.  Total  Canada  U.S.  Total 
Drilling, completion and equipping $39,034  $40,724  $79,758  $99,537  $53,072  $152,609 
Facilities  2,515      2,515   19,003   300   19,303 
Land, seismic and other  954   361   1,315   4,570   295   4,865 
Total exploration and development $42,503  $41,085  $83,588  $123,110  $53,667  $176,777 
Total acquisitions, net of proceeds from divestitures $(203) $  $(203) $(40) $  $(40)

 

Exploration and development expenditures were $83.6 million for Q1/2021 compared to $176.8 million for Q1/2020. Expenditures in Q1/2021 were lower compared to Q1/2020 primarily due to reduced development activity in Canada in addition to a reduction in well costs for our U.S. properties.

 

In Canada, we invested $42.5 million on exploration and development activities in Q1/2021 which is $80.6 million lower than $123.1 million in Q1/2020. Exploration and development expenditures of $42.5 million for Q1/2021 included costs associated with drilling 37 (36.2 net) light oil wells, 5 (1.9 net) heavy oil wells, 1 (1.0 net) natural gas well and investing $2.5 million on facilities. Exploration and development expenditures of $123.1 million for Q1/2020 included costs associated with drilling 74 (71.2 net) light oil wells, 33 (33.0 net) heavy oil wells, 6 (6.0 net) stratigraphic exploration wells and investing $19.0 million on facilities.

 

Total U.S. exploration and development expenditures were $41.1 million for Q1/2021 which is $12.6 million lower than $53.7 million for Q1/2020. Exploration and development expenditures included costs associated with drilling 25 (7.4 net) wells along with 24 (7.0 net) wells that were brought on production. Exploration and development expenditures of $53.7 million for Q1/2020 included costs associated with drilling 17 (3.8 net) wells along with 30 (6.1 net) wells that were brought on production. Expenditures for Q1/2021 were lower than Q1/2020 due to the timing of development activity along with a reduction in drilling and completion costs.

 

Our 2021 revised annual guidance range of $285 - $315 million reflects additional capital spending on our light and heavy oil assets during the fourth quarter.

 

CAPITAL RESOURCES AND LIQUIDITY

 

Our objective for capital management involves maintaining a flexible capital structure and sufficient sources of liquidity to execute our capital programs, while meeting our short and long-term commitments. We strive to actively manage our capital structure in response to changes in economic conditions. At March 31, 2021, our capital structure was comprised of shareholders’ capital, long-term notes, trade and other receivables, trade and other payables and the credit facilities.

 

The capital-intensive nature of our operations requires us to maintain adequate sources of liquidity to fund ongoing capital programs. Our capital resources consist primarily of adjusted funds flow, available credit facilities and proceeds received from the divestiture of oil and gas properties. We believe that internally generated adjusted funds flow and availability under our credit facilities will provide sufficient liquidity to fund our planned capital expenditures. Adjusted funds flow depends on a number of factors, including commodity prices, production and sales volumes, royalties, operating expenses, taxes and foreign exchange rates. In order to manage our capital structure and liquidity, we may from time-to-time issue or repurchase equity or debt securities, enter into business transactions including the sale of assets or adjust capital spending to manage current and projected debt levels. There is no certainty that any of these additional sources of capital would be available if required.

 

22Baytex Energy Corp. First Quarter Report 2021

 

 

Baytex Energy Corp.

Q1 2021 MD&A

 

 

Management of debt levels is a priority for Baytex in order to sustain operations and support our long-term plans. At March 31, 2021, net debt of $1.76 billion was $88.7 million lower than $1.85 billion at December 31, 2020. The decrease in net debt is primarily a result of free cash flow of $70.5 million generated during Q1/2021 along with an $18.1 million decrease in the reported amount of our U.S. dollar denominated net debt due to the strengthening of the Canadian dollar relative to the U.S. dollar at March 31, 2021 compared to December 31, 2020.

 

We monitor our capital structure and liquidity requirements using a net debt to adjusted funds flow ratio calculated on a trailing twelve month basis. At March 31, 2021, our net debt to adjusted funds flow ratio was 5.2 compared to a ratio of 5.9 as at December 31, 2020. The decrease in the net debt to adjusted funds flow ratio relative to December 31, 2020 is attributed to a $88.7 million decrease in net debt as at March 31, 2021 combined with higher adjusted funds flow for the twelve months ended March 31, 2021.

 

Credit Facilities

 

At March 31, 2021, the principal amount of credit facilities and letters of credit outstanding was $621.5 million under our credit facilities that total approximately $1.0 billion. Our credit facilities include US$575 million of revolving credit facilities and a $300 million non-revolving term loan (collectively, the “Credit Facilities”). Our Credit Facilities mature on April 2, 2024 and will automatically be extended to June 4, 2024 providing we have either refinanced, or have the ability to repay, the outstanding 2024 long-term notes with existing credit capacity as of April 1, 2024.

 

The Credit Facilities are not borrowing base facilities and do not require annual or semi-annual reviews. The Credit Facilities contain standard commercial covenants in addition to the financial covenants detailed below. There are no mandatory principal payments required prior to maturity which could be extended upon our request. Advances (including letters of credit) under the Credit Facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’ acceptance discount rates or London Interbank Offered Rates (“LIBOR”), plus applicable margins.

 

The LIBOR benchmark transition begins on December 31, 2021. Certain tenors of the U.S. dollar LIBOR benchmark will no longer be published as of December 31, 2021 while some tenors will continue to be published through mid-2023. We expect the U.S. dollar LIBOR benchmarks to be replaced with an alternative that will apply to our U.S. dollar borrowing at our option. We do not expect this change to have a material impact to Baytex as U.S. dollar borrowings under the credit facilities can also bear interest at the U.S. base loan rate.

 

The agreements and associated amending agreements relating to the Credit Facilities are accessible on the SEDAR website at www.sedar.com.

 

The weighted average interest rate on the Credit Facilities was 2.1% for Q1/2021 compared to 3.4% for Q1/2020.

 

Financial Covenants

 

The following table summarizes the financial covenants applicable to the Credit Facilities and our compliance therewith at March 31, 2021.

 

Covenant Description

  

Position as at
March 31,
2021

   

Covenant

 
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio)  1.4:1.0   3.5:1.0 
Interest Coverage (3) (Minimum Ratio)  4.3:1.0   2.0:1.0 

 

(1)“Senior Secured Debt” is defined as the principal amount of the credit facilities and other secured obligations identified in the credit agreement. As at March 31, 2021, the Company’s Senior Secured Debt totaled $621.5 million which includes $606.6 million of principal amounts outstanding and $14.9 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, impairment, deferred income tax expense and recovery, 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, 2021 was $437.1 million.

(3)“Interest coverage” is computed as the ratio of Bank EBITDA to financing and interest expenses, 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, 2021 were $102.0 million.

 

Baytex Energy Corp. First Quarter Report 202123

 

 

Baytex Energy Corp.

Q1 2021 MD&A

 

 

Long-Term Notes

 

We have two series of long-term notes outstanding that total $1.1 billion as at March 31, 2021. The long-term notes do not contain any financial maintenance covenants but contain a debt incurrence covenant that restricts our ability to raise additional debt beyond our existing Credit Facilities and long-term notes.

 

On June 6, 2014, we issued US$800 million of senior unsecured notes, comprised of US$400 million of 5.125% notes due June 1, 2021 (the “5.125% Notes”), which were redeemed February 20, 2020, and US$400 million of 5.625% notes due June 1, 2024 (the “5.625% Notes”), which remain outstanding. The 5.625% Notes pay interest semi-annually with the principal amount repayable at maturity. As of June 1, 2019, the 5.625% Notes are redeemable at our option, in whole or in part, at specified redemption prices and will be redeemable at par from June 1, 2022 to maturity.

 

On February 5, 2020, we issued US$500 million aggregate principal amount of senior unsecured notes due April 1, 2027 bearing interest at a rate of 8.75% per annum payable semi-annually (the “8.75% Senior Notes)”. The 8.75% Senior Notes are redeemable at our option, in whole or in part, at specified redemption prices after April 1, 2023 and will be redeemable at par from April 1, 2026 to maturity. Transaction costs of $12.5 million were incurred in conjunction with the issuance which resulted in net proceeds of $652.2 million.

 

Shareholders’ Capital

 

We are authorized to issue an unlimited number of common shares and 10.0 million preferred shares. The rights and terms of preferred shares are determined upon issuance. During the three months ended March 31, 2021, we issued 2.9 million common shares pursuant to our share-based compensation program. As at April 29, 2021, we had 564.1 million common shares issued and outstanding and no preferred shares issued and outstanding.

 

Contractual Obligations

 

We have a number of financial obligations that are incurred in the ordinary course of business. These obligations are of a recurring nature and impact our adjusted funds flow in an ongoing manner. A significant portion of these obligations will be funded by adjusted funds flow. These obligations as of March 31, 2021 and the expected timing for funding these obligations are noted in the table below.

 

($ thousands) 

 Total  Less than
1 year
  1-3 years  3-5 years  Beyond 5 years 
Trade and other payables $178,207  $178,207  $  $  $ 
Credit facilities (1) (2)  606,637         606,637    
Long-term notes (2)  1,131,480         502,880   628,600 
Interest on long-term notes (3)  419,905   83,290   166,579   114,732   55,304 
Lease agreements (2)  10,473   4,521   3,715   2,237    
Processing agreements  6,153   836   1,171   473   3,673 
Transportation agreements  93,957   18,214   39,710   21,952   14,081 
Total $2,446,812  $285,068  $211,175  $1,248,911  $701,658 

 

(1)The credit facilities mature on April 2, 2024. Maturity will automatically be extended to June 4, 2024 providing Baytex has either refinanced, or has the ability to repay, the outstanding 2024 long-term notes with existing credit capacity as of April 1, 2024.

(2)Principal amount of instruments.

(3)Excludes interest on our credit facilities as interest payments fluctuate based on a floating rate of interest and changes in the outstanding balances.

 

We also have ongoing obligations related to the abandonment and reclamation of well sites and facilities when they reach the end of their economic lives. Programs to abandon and reclaim well sites and facilities are undertaken regularly in accordance with applicable legislative requirements.

 

24Baytex Energy Corp. First Quarter Report 2021

 

 

Baytex Energy Corp.

Q1 2021 MD&A

 

 

QUARTERLY FINANCIAL INFORMATION

 

  2021  2020 2019
($ thousands, except per common share amounts) Q1  Q4  Q3  Q2  Q1  Q4  Q3  Q2 
Petroleum and natural gas sales  384,702   233,636   252,538   152,689   336,614   445,895   424,600   482,000 
Net income (loss)  (35,352)  221,160   (23,444)  (138,463)  (2,498,217)  (117,772)  15,151   78,826 
Per common share - basic  (0.06)  0.39   (0.04)  (0.25)  (4.46)  (0.21)  0.03   0.14 
Per common share - diluted  (0.06)  0.39   (0.04)  (0.25)  (4.46)  (0.21)  0.03   0.14 
Adjusted funds flow  156,582   82,176   78,508   17,887   132,935   232,147   213,379   236,130 
Per common share - basic  0.28   0.15   0.14   0.03   0.24   0.42   0.38   0.42 
Per common share - diluted  0.28   0.15   0.14   0.03   0.24   0.42   0.38   0.42 
Exploration and development  83,588   77,809   15,902   9,852   176,777   153,117   139,085   106,246 
Canada  42,503   45,030   3,882   2,929   123,110   104,460   96,774   68,259 
U.S.  41,085   32,779   12,020   6,923   53,667   48,657   42,311   37,987 
Acquisitions, net of divestitures  (203)  (33)  (98)  (11)  (40)  563   (30)  1,647 
Net debt  1,758,894   1,847,601   1,906,079   1,994,953   2,051,617   1,871,791   1,971,339   2,028,686 
Total assets  3,338,408   3,408,096   3,156,414   3,267,820   3,441,040   5,914,083   6,233,875   6,222,190 
Common shares outstanding  564,111   561,227   561,163   560,545   560,483   558,305   557,972   556,798 
                                 
Daily production                                
Total production (boe/d)  78,780   70,475   77,814   72,508   98,452   96,360   94,927   98,402 
Canada (boe/d)  52,039   45,321   49,164   37,691   62,262   57,794   58,134   58,580 
U.S. (boe/d)  26,741   25,154   28,650   34,817   36,190   38,566   36,793   39,822 
                                 
Benchmark prices                                
WTI oil (US$/bbl)  57.84   42.66   40.93   27.85   46.17   56.96   56.45   59.81 
WCS heavy ($/bbl)  57.46   43.46   42.40   22.70   34.48   54.29   58.39   65.73 
Edmonton Light ($/bbl)  66.58   50.24   49.83   29.85   51.43   58.10   68.41   73.84 
CAD/USD avg exchange rate  1.2663   1.3031   1.3316   1.3860   1.3445   1.3201   1.3207   1.3376 
AECO gas ($/mcf)  2.93   2.77   2.18   1.91   2.14   2.34   1.04   1.17 
NYMEX gas (US$/mmbtu)  2.69   2.66   1.98   1.72   1.95   2.50   2.23   2.64 
                                 
Sales price ($/boe)  51.84   34.35   33.79   22.31   35.19   48.25   47.14   51.49 
Royalties ($/boe)  (9.44)  (5.83)  (5.59)  (4.42)  (6.33)  (8.72)  (8.59)  (9.67)
Operating expense ($/boe)  (11.36)  (12.30)  (10.26)  (11.17)  (11.66)  (11.23)  (11.15)  (11.22)
Transportation expense ($/boe)  (1.24)  (1.03)  (0.89)  (0.76)  (1.15)  (1.00)  (1.13)  (1.33)
Operating netback ($/boe)  29.80   15.19   17.05   5.96   16.05   27.30   26.27   29.27 
Financial derivatives gain (loss) ($/boe)  (2.93)  2.64   (1.36)  2.06   3.00   2.59   2.39   1.45 
Operating netback after financial derivatives ($/boe)  26.87   17.83   15.69   8.02   19.05   29.89   28.66   30.72 

 

Our results for the previous eight quarters reflect the disciplined execution of our development programs and management of production in response to fluctuations in the prices for the commodities we produce. Production was relatively consistent from Q2/2019 to Q1/2020 as relatively stable crude oil prices supported an active development program in Canada and the U.S. until the sharp decline in crude oil prices in March 2020 when we shut-in production in Canada and moderated the pace of activity in the U.S. Commodity prices began to recover in Q4/2020 and have strengthened in Q1/2021 which supported increased development activity and resulted in production of 78,780 boe/d for Q1/2021.

 

North American benchmark commodity prices were stable throughout 2019 and relatively strong leading into Q1/2020 with the West Texas Intermediate (“WTI”) benchmark price averaging US$57.53/bbl in January 2020. Decisions made by Saudi Arabia and Russia to increase production of crude oil as demand was decreasing due to the spread of COVID-19 resulted in a sharp decline in global crude oil prices with WTI averaging US$27.85/bbl in Q2/2020. Prices improved and were relatively stable through the second half of 2020 as OPEC+ agreed to reinstate production curtailments and measures to control the spread of COVID-19 were relaxed. Commodity prices continued to recover in Q1/2021 with WTI averaging US$57.84/bbl as the outlook for demand improved with increasing global mobility. The impact of increased commodity prices is reflected in our realized sales price of $51.84/boe for Q1/2021 which is our strongest realized pricing since Q2/2019.

 

Baytex Energy Corp. First Quarter Report 202125

 

 

Baytex Energy Corp.

Q1 2021 MD&A

 

 

Adjusted funds flow is directly impacted by our average daily production and changes in benchmark commodity prices which are the basis for our realized sales price. Adjusted funds flow improved for Q1/2021 compared to lows in 2020 due to strong price realizations and our ongoing efforts to control operating and transportation costs.

 

Net debt can fluctuate on a quarterly basis depending on the timing of exploration and development expenditures, changes in our adjusted funds flow and the closing CAD/USD exchange rate which is used to translate our U.S. dollar denominated debt. Net debt has decreased from $2.03 billion at Q2/2019 to $1.76 billion at Q1/2021 as free cash flow of $387.4 million generated over the last eight quarters was directed towards debt repayment. Our net debt has also been reduced by a decrease in the CAD/USD exchange rate used to translate our U.S. dollar denominated debt from 1.3091 CAD/USD at Q2/2019 to 1.2572 CAD/USD at Q1/2021.

 

OFF BALANCE SHEET TRANSACTIONS

 

We do not have any financial arrangements that are excluded from the consolidated financial statements as at March 31, 2021, nor are any such arrangements outstanding as of the date of this MD&A.

 

CRITICAL ACCOUNTING ESTIMATES

 

There have been no changes in our critical accounting estimates in the three months ended March 31, 2021. Further information on our critical accounting policies and estimates can be found in the notes to the audited annual consolidated financial statements and MD&A for the year ended December 31, 2020.

 

NYSE LISTING

 

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-day trading period. Baytex did not regain compliance and its common shares were delisted from the NYSE on December 3, 2020.

 

Baytex’s common shares remain registered with the U.S. Securities and Exchange Commission. However, provided that Baytex remains listed on the TSX and the average daily trading volume of Baytex’s common shares in the U.S. is less than 5% of Baytex’s worldwide average daily trading volume over the 12-month period following the delisting, Baytex may be eligible to deregister its common shares at that time. Deregistration of Baytex’s common shares would terminate its reporting obligations under the Securities Exchange Act of 1934, as amended.

 

NON-GAAP AND CAPITAL MEASUREMENT MEASURES

 

In this MD&A, we refer to certain capital management measures (such as adjusted funds flow, exploration and development expenditures, free cash flow, net debt, operating netback and Bank EBITDA) which do not have any standardized meaning prescribed by Canadian Generally Accepted Accounting Principles (“GAAP”). While adjusted funds flow, exploration and development expenditures, free cash flow, net debt, operating netback and Bank EBITDA are commonly used in the oil and natural gas industry, our determination of these measures may not be comparable with calculations of similar measures presented by other reporting issuers. We believe that inclusion of these non-GAAP financial measures provide useful information to investors and shareholders when evaluating the financial results of the Company.

 

Adjusted Funds Flow

 

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 operations on a continuing basis.

 

Adjusted funds flow should not be construed as an alternative to performance measures determined in accordance with GAAP, such as cash flow from operating activities and net income or loss.

 

26Baytex Energy Corp. First Quarter Report 2021

 

 

Baytex Energy Corp.

Q1 2021 MD&A

 

 

The following table reconciles cash flow from operating activities to adjusted funds flow.

  

  Three Months Ended March 31 
($ thousands) 2021  2020 
Cash flow from operating activities $120,980  $182,567 
Change in non-cash working capital  34,185   (53,873)
Asset retirement obligations settled  1,417   4,241 
Adjusted funds flow $156,582  $132,935 

 

Exploration and Development Expenditures

 

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. We eliminate changes in non-cash working capital, acquisition and dispositions, and additions to other plant and equipment from investing activities as these amounts are generated by activities outside of our programs to explore and develop our existing properties.

 

Changes in non-cash working capital are eliminated in the determination of exploration and development expenditures 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 operations on a continuing basis. Our capital budgeting process is focused on programs to explore and develop our existing properties, accordingly, cash flows arising from acquisition and disposition activities are eliminated as we analyze these activities on a transaction by transaction basis separately from our analysis of the performance of our capital programs. Additions to other plant and equipment is primarily comprised of expenditures on corporate assets which do not generate incremental oil and natural gas production and are therefore analyzed separately from our evaluation of the performance of our exploration and development programs.

 

The following table reconciles cash flow used in investing activities to exploration and development expenditures.

  

  Three Months Ended March 31 
($ thousands) 2021  2020 
Cash flow used in investing activities $77,177  $161,022 
Change in non-cash working capital  6,299   16,327 
Proceeds from dispositions  228   40 
Property acquisitions  (25)   
Additions to other plant and equipment  (91)  (612)
Exploration and development expenditures $83,588  $176,777 

 

Free Cash Flow

 

We define free cash flow as adjusted funds flow less exploration and development expenditures (both non-GAAP measures defined above), payments on lease obligations and asset retirement obligations settled. We use free cash flow to evaluate funds available for debt repayment, common share repurchases, potential future dividends and acquisition opportunities.

 

The following table provides our computation of free cash flow.

  

  Three Months Ended March 31 
($ thousands) 2021  2020 
Adjusted funds flow $156,582  $132,935 
Exploration and development expenditures  (83,588)  (176,777)
Payments on lease obligations  (1,082)  (1,516)
Asset retirement obligations settled  (1,417)  (4,241)
Free cash flow $70,495  $(49,599)

 

Baytex Energy Corp. First Quarter Report 202127

 

 

Baytex Energy Corp.

Q1 2021 MD&A

 

 

Net Debt

 

We believe that net debt assists in providing a more complete understanding of our financial position and provides a key measure to assess our liquidity. We calculate net debt based on the principal amounts of our credit facilities and long-term notes outstanding, including trade and other payables, cash, and trade and other receivables. 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 total repayment obligation at maturity. The carrying amount of debt issue costs associated with the credit facilities and long-term notes are 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.

 

The following table summarizes our calculation of net debt.

 

($ thousands) March 31, 2021  December 31, 2020 
Credit facilities (1) $606,637  $651,173 
Long-term notes (1)  1,131,480   1,147,950 
Trade and other payables  178,207   155,955 
Trade and other receivables  (157,430)  (107,477)
Net debt $1,758,894  $1,847,601 

 

(1)Principal amount of instruments expressed in Canadian dollars.

 

Operating Netback

 

We define operating netback as petroleum and natural gas sales, less blending expense, royalties, operating expense and transportation expense. Operating netback per boe is the operating netback divided by barrels of oil equivalent production volume for the applicable period. We believe that this measure assists in assessing our ability to generate cash margin on a unit of production basis and is a key measure used to evaluate our operating performance.

  

  Three Months Ended March 31 
($ thousands) 2021  2020 
Petroleum and natural gas sales $384,702  $336,614 
Blending and other expense  (17,120)  (21,357)
Total sales, net of blending and other expense  367,582   315,257 
Royalties  (66,950)  (56,720)
Operating expense  (80,548)  (104,470)
Transportation expense  (8,788)  (10,342)
Operating netback  211,296   143,725 
Realized financial derivative (loss) gain  (20,768)  26,850 
Operating netback after realized financial derivatives $190,528  $170,575 

 

28Baytex Energy Corp. First Quarter Report 2021

 

 

Baytex Energy Corp.

Q1 2021 MD&A

 

 

Bank EBITDA

 

Bank EBITDA is used to assess compliance with certain financial covenants contained in our credit facility agreements. Net income is adjusted for the items set forth in the table below as prescribed by the credit facility agreements. The following table reconciles net income or loss to Bank EBITDA on a twelve month rolling basis.

  

  Twelve Months Ended March 31 
($ thousands) 2021  2020 
Net income (loss) $23,901  $(2,522,012)
Plus:        
Financing and interest  113,671   132,343 
Unrealized foreign exchange (gain) loss  (92,819)  63,709 
Unrealized financial derivatives loss (gain)  200,479   (66,439)
Current income tax (recovery) expense  (55)  1,967 
Deferred income tax expense (recovery)  127,876   (337,249)
Depletion and depreciation  407,006   727,718 
Gain on dispositions  (4,470)  (2,375)
Impairment  (356,129)  2,904,171 
Non-cash items (1)  17,659   18,614 
Bank EBITDA $437,119  $920,447 

 

(1)Non-cash items include share-based compensation, exploration and evaluation expense, note redemption premiums, interest on lease obligations, and non-cash other income.

 

INTERNAL CONTROL OVER FINANCIAL REPORTING

 

We are required to comply with Multilateral Instrument 52-109 “Certification of Disclosure in Issuers’ Annual and Interim Filings”. This instrument requires us to disclose in our interim MD&A any weaknesses in or changes to our internal control over financial reporting during the period that may have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. We confirm that no such weaknesses were identified in, or changes were made to, internal controls over financial reporting during the three months ended March 31, 2021.

 

Baytex Energy Corp. First Quarter Report 202129

 

 

Baytex Energy Corp.

Q1 2021 MD&A

 

 

FORWARD-LOOKING STATEMENTS

 

In the interest of providing our shareholders and potential investors with information regarding Baytex, including management’s assessment of the Company’s future plans and operations, certain statements in this document 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”, “plan”, “project”, “should”, “target”, “would”, “will” or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this document speak only as of the date of this document and are expressly qualified by this cautionary statement.

 

Specifically, this document contains forward-looking statements relating to but not limited to: our business strategies, plans and objectives; our 2021 guidance with respect to exploration and development expenditures, average daily production, royalty rate and operating, transportation, general and administrative and interest expenses; the existence, operation and strategy of our risk management program; the reassessment of our tax filings by the Canada Revenue Agency; our intention to defend the reassessments; our view of our tax filing position; that our internally generated adjusted funds flow and our existing undrawn credit facilities will provide sufficient liquidity to sustain our operations and planned capital expenditures; that a significant portion of our financial obligations will be funded by adjusted funds flow; that we intend to deregister our shares with the U.S. Securities and Exchange Commission if eligible.

 

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, 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.

 

30Baytex Energy Corp. First Quarter Report 2021

 

 

Baytex Energy Corp. 

Condensed Consolidated Statements of Financial Position 

(thousands of Canadian dollars) (unaudited)

 

  As at 
  Notes  March 31, 2021  December 31, 2020 
ASSETS         
Current assets           

Trade and other receivables

    $157,430  $107,477 
Financial derivatives 16   239   5,057 
      157,669   112,534 
            
Non-current assets           
Exploration and evaluation assets 4   186,076   191,865 
Oil and gas properties 5   2,969,635   3,077,548 
Other plant and equipment     7,762   7,996 
Lease assets     10,211   11,098 
Deferred income tax asset 13   7,055   7,055 
     $3,338,408  $3,408,096 
            
LIABILITIES           
Current liabilities           
Trade and other payables    $178,207  $155,955 
Financial derivatives 16   105,521   26,792 
Lease obligations     4,342   4,289 
Asset retirement obligations 8   11,744   11,820 
      299,814   198,856 
Non-current liabilities           
Financial derivatives 16   2,437    
Credit facilities 6   604,854   649,221 
Long-term notes 7   1,117,206   1,132,868 
Lease obligations     5,713   6,787 
Asset retirement obligations 8   673,208   748,563 
Deferred income tax liability 13   97,910   93,588 
      2,801,142   2,829,883 
            
SHAREHOLDERS’ EQUITY           
Shareholders’ capital 9   5,736,393   5,729,418 
Contributed surplus     8,874   14,345 
Accumulated other comprehensive income     611,877   618,976 
Deficit     (5,819,878)  (5,784,526)
      537,266   578,213 
     $3,338,408  $3,408,096 

 

See accompanying notes to the condensed consolidated interim financial statements.

 

Baytex Energy Corp. First Quarter Report 202131

 

 

Baytex Energy Corp. 

Condensed Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) 

(thousands of Canadian dollars, except per common share amounts and weighted average common shares) (unaudited)

  

  Three Months Ended March 31 
  Notes  2021  2020 

Revenue, net of royalties

         
Petroleum and natural gas sales 12  $384,702  $336,614 
Royalties     (66,950)  (56,720)
      317,752   279,894 
            
Expenses           
Operating     80,548   104,470 
Transportation     8,788   10,342 
Blending and other     17,120   21,357 
General and administrative     8,733   9,775 
Exploration and evaluation 4   947   260 
Depletion and depreciation     102,012   181,386 
Impairment 4, 5      2,716,349 
Share-based compensation 10   2,981   2,783 
Financing and interest 14   27,450   39,220 
Financial derivatives loss (gain) 16   106,752   (122,845)
Foreign exchange (gain) loss 15   (2,805)  99,892 
Gain on dispositions     (3,706)  (137)
Other income     (1,220)  (2,031)
      347,600   3,060,821 
Net loss before income taxes     (29,848)  (2,780,927)
Income tax expense (recovery) 13         
Current income tax (recovery) expense     (160)  469 
Deferred income tax expense (recovery)     5,664   (283,179)
      5,504   (282,710)
Net loss    $(35,352) $(2,498,217)
Other comprehensive income (loss)           

Foreign currency translation adjustment

     (7,099)  173,939 
Comprehensive loss    $(42,451) $(2,324,278)
            
Net loss per common share 11         
Basic    $(0.06) $(4.46)
Diluted    $(0.06) $(4.46)
            
Weighted average common shares (000’s) 11         
Basic     562,085   559,804 
Diluted     562,085   559,804 

 

See accompanying notes to the condensed consolidated interim financial statements.

 

32Baytex Energy Corp. First Quarter Report 2021

 

 

Baytex Energy Corp.
Condensed Consolidated Statements of Changes in Equity 

(thousands of Canadian dollars) (unaudited)

 

  Notes  Shareholders’
capital
  Contributed
surplus
  Accumulated
other
comprehensive
income
  Deficit  Total equity 
Balance at December 31, 2019    $5,718,835  $17,712  $556,224  $(3,345,562) $2,947,209 
Vesting of share awards     7,630   (7,630)         
Share-based compensation        2,262         2,262 
Comprehensive income (loss)           173,939   (2,498,217)  (2,324,278)
Balance at March 31, 2020    $5,726,465  $12,344  $730,163  $(5,843,779) $625,193 
Balance at December 31, 2020    $5,729,418  $14,345  $618,976  $(5,784,526) $578,213 
Vesting of share awards 9   6,975   (6,975)         
Share-based compensation 10      1,504         1,504 
Comprehensive loss           (7,099)  (35,352)  (42,451)
Balance at March 31, 2021    $5,736,393  $8,874  $611,877  $(5,819,878) $537,266 

 

See accompanying notes to the condensed consolidated interim financial statements.

 

Baytex Energy Corp. First Quarter Report 202133

 

 

Baytex Energy Corp.
Condensed Consolidated Statements of Cash Flows 

(thousands of Canadian dollars) (unaudited)

 

     Three Months Ended March 31 
  Notes  2021  2020 
CASH PROVIDED BY (USED IN):           
Operating activities           
Net loss for the period    $(35,352) $(2,498,217)
Adjustments for:           
Non-cash share-based compensation 10   1,504   2,262 
Unrealized foreign exchange (gain) loss 15   (2,530)  99,521 
Exploration and evaluation 4   947   260 
Depletion and depreciation     102,012   181,386 
Impairment 4, 5      2,716,349 
Non-cash financing, accretion, and early redemption expense 14   3,047   10,685 
Non-cash other income 8   (988)   
Unrealized financial derivatives loss (gain) 16   85,984   (95,995)
Gain on dispositions     (3,706)  (137)
Deferred income tax expense (recovery) 13   5,664   (283,179)
Asset retirement obligations settled 8   (1,417)  (4,241)
Change in non-cash working capital     (34,185)  53,873 
      120,980   182,567 
            
Financing activities           
Increase (decrease) in credit facilities     (42,721)  155,921 
Payments on lease obligations     (1,082)  (1,516)
Net proceeds from issuance of long-term notes        652,150 
Redemption of long-term notes        (833,672)
      (43,803)  (27,117)
            
Investing activities           
Additions to exploration and evaluation assets 4   (216)  (3,788)
Additions to oil and gas properties 5   (83,372)  (172,989)
Additions to other plant and equipment     (91)  (612)
Property acquisitions     (25)   
Proceeds from dispositions     228   40 
Change in non-cash working capital     6,299   16,327 
      (77,177)  (161,022)
            
Change in cash        (5,572)
Cash, beginning of period        5,572 
Cash, end of period    $  $ 
            
            
Supplementary information           
Interest paid    $30,837  $22,597 
Income taxes paid    $  $ 

 

See accompanying notes to the condensed consolidated interim financial statements.

 

34Baytex Energy Corp. First Quarter Report 2021

 

 

Baytex Energy Corp.

Notes to the Condensed Consolidated Interim Financial Statements 

For the periods ended March 31, 2021 and 2020 

(all tabular amounts in thousands of Canadian dollars, except per common share amounts) (unaudited)

 

1.REPORTING ENTITY

 

Baytex Energy Corp. (the “Company” or “Baytex”) is an oil and gas corporation engaged in the acquisition, development and production of oil and natural gas in the Western Canadian Sedimentary Basin and Texas, United States. The Company’s common shares are traded on the Toronto Stock Exchange under the symbol BTE. The Company’s head and principal office is located at 2800, 520 – 3rd Avenue S.W., Calgary, Alberta, T2P 0R3, and its registered office is located at 2400, 525 – 8th Avenue S.W., Calgary, Alberta, T2P 1G1.

 

2.BASIS OF PRESENTATION

 

The condensed consolidated interim financial statements (“consolidated financial statements”) have been prepared in accordance with International Accounting Standards 34, Interim Financial Reporting, under International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (the “IASB”). These condensed consolidated financial statements do not include all the necessary annual disclosures as prescribed by IFRS and should be read in conjunction with the annual consolidated financial statements as at and for the year ended December 31, 2020.

 

The consolidated financial statements were approved by the Board of Directors of Baytex on April 29, 2021.

 

The consolidated financial statements have been prepared on a historical cost basis, with the exception of derivative financial instruments which have been measured at fair value. The consolidated financial statements are presented in Canadian dollars which is the functional currency of the Company. References to “US$” are to United States (“U.S.”) dollars. All financial information is rounded to the nearest thousand, except per share amounts or when otherwise indicated.

 

The audited consolidated financial statements of the Company as at and for the year ended December 31, 2020 are available through its filings on SEDAR at www.sedar.com and through the U.S. Securities and Exchange Commission at www.sec.gov.

 

Significant Accounting Policies

 

The accounting policies, critical accounting judgments and significant estimates used in preparation of the 2020 annual financial statements have been applied in the preparation of these consolidated financial statements.

 

Current Environment and Estimation Uncertainty

 

Management makes judgements and assumptions about the future in deriving estimates used in preparation of these consolidated financial statements in accordance with IFRS. Sources of estimation uncertainty include estimates used to determine economically recoverable oil, natural gas, and natural gas liquids reserves, the recoverable amount of long-lived assets or cash generating units, the fair value of financial derivatives, the provision for asset retirement obligations and the provision for income taxes and the related deferred tax assets and liabilities.

 

During the three months ended March 31, 2021, the global economy continued to show signs of recovery from the impacts of the COVID-19 pandemic. The outlook for crude oil demand has improved due to the easing of restrictions combined with the distribution of vaccines in developed countries. Global spot prices for crude oil have recovered to pre-pandemic levels as optimism for demand recovery improves and OPEC continues to adhere to production curtailments that limit supply. While we have benefited from these recent improvements in crude oil prices there is a degree of uncertainty related to the COVID-19 and OPEC production curtailments that has been considered in our estimates for the period ended March 31, 2021.

 

Baytex Energy Corp. First Quarter Report 202135

 

 

3.SEGMENTED FINANCIAL INFORMATION

 

Baytex’s reportable segments are determined based on the geographic location and nature of the underlying operations:

 

Canada includes the exploration for, and the development and production of, crude oil and natural gas in Western Canada;

U.S. includes the exploration for, and the development and production of, crude oil and natural gas in the U.S.; and

Corporate includes corporate activities and items not allocated between operating segments.

  

  Canada  U.S.  Corporate  Consolidated 
Three Months Ended March 31 2021  2020  2021  2020  2021  2020  2021  2020 

Revenue, net of royalties

                        
Petroleum and natural gas sales $239,423  $194,844  $145,279  $141,770  $  $  $384,702  $336,614 
Royalties  (24,664)  (15,518)  (42,286)  (41,202)        (66,950)  (56,720)
   214,759   179,326   102,993   100,568         317,752   279,894 
                                 

Expenses

                                
Operating  61,361   78,922   19,187   25,548         80,548   104,470 
Transportation  8,788   10,342               8,788   10,342 
Blending and other  17,120   21,357               17,120   21,357 
General and administrative              8,733   9,775   8,733   9,775 
Exploration and evaluation  947   260               947   260 
Depletion and depreciation  70,474   122,748   30,265   56,670   1,273   1,968   102,012   181,386 
Impairment     1,855,000      861,349            2,716,349 
Share-based compensation              2,981   2,783   2,981   2,783 
Financing and interest              27,450   39,220   27,450   39,220 
Financial derivatives loss (gain)              106,752   (122,845)  106,752   (122,845)
Foreign exchange (gain) loss              (2,805)  99,892   (2,805)  99,892 
Gain on dispositions  (3,706)  (137)              (3,706)  (137)
Other income  (988)           (232)  (2,031)  (1,220)  (2,031)
   153,996   2,088,492   49,452   943,567   144,152   28,762   347,600   3,060,821 
Net income (loss) before income taxes  60,763   (1,909,166)  53,541   (842,999)  (144,152)  (28,762)  (29,848)  (2,780,927)
Income tax expense (recovery)                                
Current income tax (recovery) expense  (296)  469   136            (160)  469 
Deferred income tax expense (recovery)  8,420   (91,697)  5,664   (185,996)  (8,420)  (5,486)  5,664   (283,179)
   8,124   (91,228)  5,800   (185,996)  (8,420)  (5,486)  5,504   (282,710)
Net income (loss) $52,639  $(1,817,938) $47,741  $(657,003) $(135,732) $(23,276) $(35,352) $(2,498,217)
                                 
Total oil and natural gas capital expenditures(1) $42,300  $123,070  $41,085  $53,667  $  $  $83,385  $176,737 

  

(1)Includes additions to exploration and evaluation assets, oil and gas properties, and property acquisitions, net of proceeds from divestitures.

 

  March 31, 2021  December 31, 2020 
Canadian assets $1,583,885  $1,646,412 
U.S. assets  1,736,311   1,737,533 
Corporate assets  18,212   24,151 
Total consolidated assets $3,338,408  $3,408,096 

 

36Baytex Energy Corp. First Quarter Report 2021

 

 

4.EXPLORATION AND EVALUATION ASSETS

 

  March 31, 2021  December 31, 2020 
Balance, beginning of period $191,865  $320,210 
Capital expenditures  216   4,490 
Property swaps  (36)  468 
Impairment     (113,058)
Exploration and evaluation expense  (947)  (14,011)
Transfer to oil and gas properties (note 5)  (3,704)  (8,585)
Foreign currency translation  (1,318)  2,351 
Balance, end of period $186,076  $191,865 

 

At March 31, 2021, there were no indicators of impairment or impairment reversal for exploration and evaluation assets in any of the Company’s CGUs.

 

At March 31, 2020, the Company identified indicators of impairment for the exploration and evaluation assets within each of its six CGUs. The estimated recoverable amount was below the carrying value of the exploration and evaluation assets in the Conventional, Peace River, Lloydminster, Viking, and Eagle Ford CGUs and an impairment of $127.9 million was recorded at March 31, 2020. The recoverable amount of each CGU was based on its FVLCD and was estimated with reference to arm’s length transactions in comparable locations and the discounted cash flows associated with the Company’s future development plans. The following table indicates the impairment booked for each CGU at March 31, 2020.

 

  Impairment at 
  March 31, 2020 
Conventional CGU $4,000 
Peace River CGU  20,000 
Lloydminster CGU  42,000 
Viking CGU  13,000 
Eagle Ford CGU  48,861 
  $127,861 

 

At December 31, 2020, the Company estimated the recoverable amount of the exploration and evaluation assets within each of its six CGUs due to the ongoing volatility in future oil and natural gas prices. The recoverable amount supported the carrying amount for the Conventional, Peace River, Lloydminster, and Duvernay CGUs and no impairment or impairment reversal was recorded. The recoverable amount for the Viking and Eagle Ford CGUs exceeded their carrying amounts which resulted in an impairment reversal of $14.8 million at December 31, 2020. The recoverable amount of each CGU was based on its FVLCD and was estimated with reference to arm’s length transaction in comparable locations and the discounted cash flows associated with the Company’s future development plans. The following table indicates the impairment reversal booked for the Viking and Eagle Ford CGUs at December 31, 2020.

 

  

Impairment
Reversal

at December 31,
2020

 
Viking CGU $2,000 
Eagle Ford CGU  12,803 
  $14,803 

 

Baytex Energy Corp. First Quarter Report 202137

 

 

5.OIL AND GAS PROPERTIES

  

  Cost  Accumulated
depletion
  Net book value 
Balance, December 31, 2019 $11,128,297  $(5,740,408) $5,387,889 
Capital expenditures  275,850      275,850 
Transfers from exploration and evaluation assets (note 4)  8,585      8,585 
Change in asset retirement obligations (note 8)  94,994      94,994 
Property swaps  (1,190)  178   (1,012)
Impairment     (2,247,162)  (2,247,162)
Foreign currency translation  (82,860)  120,123   37,263 
Depletion     (478,859)  (478,859)
Balance, December 31, 2020 $11,423,676  $(8,346,128) $3,077,548 
Capital expenditures  83,372      83,372 
Property acquisitions  156      156 
Transfers from exploration and evaluation assets (note 4)  3,704      3,704 
Change in asset retirement obligations (note 8)  (71,324)     (71,324)
Property swaps  (7,353)  7,353    
Foreign currency translation  (59,488)  36,406   (23,082)
Depletion     (100,739)  (100,739)
Balance, March 31, 2021 $11,372,743  $(8,403,108) $2,969,635 

 

At March 31, 2021, there were no indicators of impairment or impairment reversal for oil and gas properties in any of the Company’s CGUs.

 

At March 31, 2020, the Company identified indicators of impairment for each of its six CGUs due to a significant decline in forecasted commodity prices. The recoverable amount was not sufficient to support the carrying amount which resulted in an impairment of $2.6 billion recorded at March 31, 2020. The recoverable amount of each CGU was based on its FVLCD which was estimated using a discounted cash flow model of proved plus probable cash flows from an independent reserve report prepared as at December 31, 2019 and was adjusted for operations between December 31, 2019 and March 31, 2020. The after-tax discount rates applied to the cash flows were between 8% and 14%.

 

The recoverable amount of the Company’s CGUs were calculated at March 31, 2020 using the following benchmark reference prices for the years 2020 to 2029 adjusted for commodity differentials specific to the Company. The prices and costs subsequent to 2029 have been adjusted for inflation at an annual rate of 2%.

 

  2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
WTI crude oil (US$/bbl) 29.17 40.45 49.17 53.28 55.66 56.87 58.01 59.17 60.35 61.56
WCS heavy oil (CA$/bbl) 19.21 34.65 46.34 51.25 54.28 55.72 56.96 58.22 59.51 60.82
LLS crude oil (US$/bbl) 32.17 43.80 52.55 56.68 59.10 60.35 61.52 62.72 63.94 65.19
Edmonton par oil (CA$/bbl) 29.22 46.85 59.27 65.02 68.43 69.81 71.24 72.70 74.19 75.71
Henry Hub gas (US$/mmbtu) 2.10 2.58 2.79 2.86 2.93 3.00 3.07 3.13 3.19 3.25
AECO gas (CA$/mmbtu) 1.74 2.20 2.38 2.45 2.53 2.60 2.66 2.72 2.79 2.85
Exchange rate (CAD/USD) 1.41 1.37 1.34 1.34 1.34 1.33 1.33 1.33 1.33 1.33

 

38Baytex Energy Corp. First Quarter Report 2021

 

 

The following table demonstrates the sensitivity of the estimated recoverable amount of the Company’s CGUs to reasonably possible changes in key assumptions inherent in the estimate.

  

 Recoverable
amount
 Impairment Change in discount
rate of 1%
 Change in oil price
of $2.50/bbl
 Change in gas
price of $0.25/mcf
 
Conventional CGU$37,444 $41,000 $3,000 $3,500 $8,500 
Peace River CGU 109,631  345,000  9,500  53,500  3,000 
Lloydminster CGU 227,967  470,000  25,000  69,500   
Duvernay CGU 61,197  5,000  5,500  9,500  1,500 
Viking CGU 962,134  915,000  57,000  123,000  4,000 
Eagle Ford CGU 1,576,423  812,488  120,750  141,500  32,000 
 $2,974,796 $2,588,488 $220,750 $400,500 $49,000 

 

At December 31, 2020, the Company estimated the recoverable amount of each of its six CGUs due to the volatility in commodity prices during the year and a reduction in future development costs per well for the Viking and Eagle Ford CGUs. The recoverable amount supported the carrying amount for the Conventional, Peace River, Lloydminster, and Duvernay CGUs and no impairment or impairment reversal was recorded. The recoverable amount for the Viking and Eagle Ford CGUs exceeded their carrying amounts which resulted in an impairment reversal of $341.3 million recorded at December 31, 2020. The recoverable amount for each CGU was based on its FVLCD which was estimated using a discounted cash flow model of proved plus probable cash flows from an independent reserve report prepared as at December 31, 2020. The after-tax discount rates applied to the cash flows were between 10% and 17%.

 

The recoverable amount of the Company’s CGUs were calculated at December 31, 2020 using the following benchmark reference prices for the years 2021 to 2030 adjusted for commodity differentials specific to the Company. The prices and costs subsequent to 2030 have been adjusted for inflation at an annual rate of 2%.

 

  2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
WTI crude oil (US$/bbl) 47.17 50.17 53.17 54.97 56.07 57.19 58.34 59.50 60.69 61.91
WCS heavy oil (CA$/bbl) 44.63 48.18 52.10 54.10 55.19 56.29 57.42 58.57 59.74 60.93
LLS crude oil (US$/bbl) 49.50 52.85 55.87 57.69 58.82 59.97 61.15 62.34 63.56 64.83
Edmonton par oil (CA$/bbl) 55.76 59.89 63.48 65.76 67.13 68.53 69.95 71.40 72.88 74.34
Henry Hub gas (US$/mmbtu) 2.83 2.87 2.90 2.96 3.02 3.08 3.14 3.20 3.26 3.33
AECO gas (CA$/mmbtu) 2.78 2.70 2.61 2.65 2.70 2.76 2.81 2.87 2.92 2.98
Exchange rate (CAD/USD) 1.30 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31 1.31

 

The following table demonstrates the sensitivity of the estimated recoverable amount of the Company’s CGUs to reasonably possible changes in key assumptions inherent in the estimate.

 

 Recoverable
amount
 Impairment reversal Change in discount
rate of 1%
 Change in oil price
of $2.50/bbl
 Change in gas
price of $0.25/mcf
 
Conventional CGU$54,265 $ $1,000 $3,000 $9,000 
Peace River CGU 104,225    1,000  49,500  3,000 
Lloydminster CGU 212,979    7,000  57,500  500 
Duvernay CGU 70,491    5,500  12,000  1,500 
Viking CGU 1,026,026  116,000  34,500  106,500  5,000 
Eagle Ford CGU 1,609,562  225,326  91,600  157,500  38,400 
 $3,077,548 $341,326 $140,600 $386,000 $57,400 

 

Baytex Energy Corp. First Quarter Report 202139

 

 

6.CREDIT FACILITIES

 

  March 31, 2021  December 31, 2020 

Credit facilities - U.S. dollar denominated (1)

 $143,196  $140,815 
Credit facilities - Canadian dollar denominated  463,441   510,358 
Credit facilities - principal  606,637   651,173 
Unamortized debt issuance costs  (1,783)  (1,952)
Credit facilities $604,854  $649,221 

 

(1)U.S. dollar denominated credit facilities balance was US$113.9 million as at March 31, 2021 (December 31, 2020 - US$110.4 million).

 

Baytex has US$575 million of revolving credit facilities (the “Revolving Facilities”) and a $300 million non-revolving secured term loan (the “Term Loan”) (collectively the “Credit Facilities”). On March 3, 2020, Baytex amended its Credit Facilities to extend maturity from April 2, 2021 to April 2, 2024. These facilities will automatically be extended to June 4, 2024 providing Baytex has either refinanced, or has the ability to repay, the outstanding 2024 long-term notes with existing credit capacity as of April 1, 2024.

 

The extendible secured Revolving Facilities are comprised of a US$50 million operating loan and a US$325 million syndicated revolving loan for Baytex and a US$200 million syndicated revolving loan for Baytex’s wholly-owned subsidiary, Baytex Energy USA, Inc. The $300 million Term Loan is secured by the assets of Baytex’s wholly-owned subsidiary, Baytex Energy Limited Partnership.

 

The Credit Facilities are not borrowing base facilities and do not require annual or semi-annual reviews. The Credit Facilities contain standard commercial covenants in addition to the financial covenants detailed below. There are no mandatory principal payments required prior to maturity which could be extended upon Baytex’s request. Advances (including letters of credit) under the Credit Facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’ acceptance discount rates or London Interbank Offered Rates (“LIBOR”), plus applicable margins.

 

The LIBOR benchmark transition begins on December 31, 2021. Certain tenors of the U.S. dollar LIBOR benchmark will no longer be published as of December 31, 2021 while some tenors will continue to be published through mid-2023. We expect the U.S. dollar LIBOR benchmarks to be replaced with an alternative that will apply to our U.S. dollar borrowing at our option. We do not expect this change to have a material impact to Baytex as U.S. dollar borrowings under the credit facilities can also bear interest at the U.S. base loan rate.

 

At March 31, 2021, Baytex had $14.9 million of outstanding letters of credit (December 31, 2020 - $15.0 million) under the Credit Facilities.

 

At March 31, 2021, Baytex was in compliance with all of the covenants contained in the Credit Facilities and is forecasting compliance with these covenants based on current forward commodity prices. The following table summarizes the financial covenants applicable to the Credit Facilities and Baytex’s compliance therewith as at March 31, 2021.

 

Covenant Description

  

Position as at
March 31, 2021

   

Covenant

 
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio)  1.4:1.0   3.5:1.0 
Interest Coverage (3) (Minimum Ratio)  4.3:1.0   2.0:1.0 

 

(1)“Senior Secured Debt” is defined as the principal amount of the credit facilities and other secured obligations identified in the credit agreement. As at March 31, 2021, the Company’s Senior Secured Debt totaled $621.5 million which included $606.6 million of principal amounts outstanding and $14.9 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 expense, income tax, non-recurring losses, certain specific unrealized and non-cash transactions (including depletion, depreciation, exploration and evaluation expense, impairment, deferred income tax expense or recovery, 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, 2021 was $437.1 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 expense, excluding accretion of debt issue costs and asset retirement obligations, for the twelve months ended March 31, 2021 was $102.0 million.

 

40Baytex Energy Corp. First Quarter Report 2021

 

 

7.LONG-TERM NOTES

 

  March 31, 2021  December 31, 2020 
5.625% notes (US$400,000 – principal) due June 1, 2024 $502,880  $510,200 
8.75% notes (US$500,000 – principal) due April 1, 2027  628,600   637,750 
Total long-term notes - principal(1)  1,131,480   1,147,950 
Unamortized debt issuance costs  (14,274)  (15,082)
Total long-term notes - net of unamortized debt issuance costs $1,117,206  $1,132,868 

 

(1)The decrease in the principal amount of long-term notes outstanding from December 31, 2020 to March 31, 2021 is the result of foreign exchange which reduced the reported amount of U.S. dollar denominated debt by $16.5 million.

 

The long-term notes do not contain any significant financial maintenance covenants but do contain a debt incurrence covenant that restricts the Company’s ability to raise additional debt beyond the existing Credit Facilities and long-term notes.

 

8.ASSET RETIREMENT OBLIGATIONS

 

  March 31, 2021  December 31, 2020 
Balance, beginning of period $760,383  $667,974 
Liabilities incurred  3,983   15,189 
Liabilities settled  (1,417)  (7,168)
Liabilities acquired from property acquisitions  131    
Liabilities divested     (721)
Property swaps  (3,513)  (525)
Accretion (note 14)  2,298   8,978 
Government grants (1)  (988)  (2,128)
Change in estimate  (214)  (12,771)
Changes in discount rates and inflation rates (2)  (75,093)  92,576 
Foreign currency translation  (618)  (1,021)
Balance, end of period $684,952  $760,383 
Less current portion of asset retirement obligations  11,744   11,820 
Non-current portion of asset retirement obligations $673,208  $748,563 

 

(1)During the three months ended March 31, 2021, Baytex recognized $1.0 million of non-cash other income and a reduction in asset retirement obligations related to government grants provided by the Government of Alberta and the Government of Saskatchewan ($2.1 million for the year ended December 31, 2020).

(2)The discount and inflation rates at March 31, 2021 were 2.0% and 1.7%, respectively, compared to 1.2% and 1.5% at December 31, 2020.

 

9.SHAREHOLDERS’ CAPITAL

 

The authorized capital of Baytex consists of an unlimited number of common shares without nominal or par value and 10.0 million preferred shares without nominal or par value, issuable in series. Baytex establishes the rights and terms of the preferred shares upon issuance. At March 31, 2021, no preferred shares have been issued by the Company and all common shares issued were fully paid.

 

The holders of common shares may receive dividends as declared from time to time and are entitled to one vote per share at any meeting of the holders of common shares. All common shares rank equally with regard to the Company’s net assets in the event the Company is wound-up or terminated.

 

       
   Number of
Common Shares
(000s)
 Amount 
Balance, December 31, 2019   558,305  $5,718,835 
Vesting of share awards   2,922   10,583 
Balance, December 31, 2020   561,227  $5,729,418 
Vesting of share awards   2,884   6,975 
Balance, March 31, 2021   564,111  $5,736,393 

 

Baytex Energy Corp. First Quarter Report 202141

 

 

10.SHARE AWARD INCENTIVE PLAN

 

For the three months ended March 31, 2021 the Company recorded total compensation expense related to the share awards of $3.0 million which includes $1.5 million of cash compensation expense related to the incentive award plan, deferred share unit plan and the associated equity total return swaps (March 31, 2020 - $2.8 million and $0.5 million respectively).

 

Share Award Plans

 

Baytex has a share award plan pursuant to which it issues restricted and performance awards. A restricted award entitles the holder of each award to receive one common share of Baytex at the time of vesting. A performance award entitles the holder of each award to receive between zero and two common shares on vesting; the number of common shares issued is determined by a multiplier. The multiplier, which ranges between zero and two, is calculated based on a number of factors determined and approved by the Board of Directors on an annual basis. The restricted awards and performance awards vest in equal tranches on the first, second and third anniversaries of the grant date.

 

The weighted average fair value of share awards granted was $1.29 per restricted and performance award for the three months ended March 31, 2021 ($1.48 per restricted and performance award for the three months ended March 31, 2020).

 

The number of share awards outstanding is detailed below:

 

(000s)  Number of
restricted awards
   Number of
performance
awards(1)
   Total number of
share awards
 
Balance, December 31, 2019  3,801   3,135   6,936 
Granted  2,239   3,253   5,492 
Vested and converted to common shares  (1,730)  (1,192)  (2,922)
Forfeited  (188)  (1,108)  (1,296)
Balance, December 31, 2020  4,122   4,088   8,210 
Granted     4,023   4,023 
Vested and converted to common shares  (1,768)  (1,143)  (2,911)
Forfeited  (99)  (57)  (156)
Balance, March 31, 2021  2,255   6,911   9,166 

 

(1)Based on underlying awards before applying the payout multiplier which can range from 0x to 2x.

 

Incentive Award Plan

 

Baytex has a cash-settled incentive award plan (the “Incentive Award” plan) whereby the holder of each incentive award is entitled to receive a cash payment equal to the value of one Baytex common share at the time of vesting. The incentive awards vest in equal tranches on the first, second and third anniversaries of the grant date. The cumulative expense is recognized at fair value at each period end and is included in trade and other payables.

 

During the three months ended March 31, 2021, Baytex granted 4.9 million awards under the Incentive Award plan at a fair value of $1.29 per award (2.9 million awards granted at $1.50 per incentive award for the three months ended March 31, 2020). At March 31, 2021 there were 6.5 million awards outstanding under the Incentive Award plan.

 

Deferred Share Unit Plan

 

Baytex has a deferred share unit plant (the “DSU” plan) whereby each Director of Baytex is entitled to receive a cash payment equal to the value of one Baytex common share on the date on which they cease to be a member of the Board. The awards vest immediately upon being granted and are expensed in full on the grant date. The units are recognized at fair value at each period end and are included in trade and other payables.

 

During the three months ended March 31, 2021, Baytex granted 0.9 million awards under the DSU plan at a fair value of $1.29 per award. At March 31, 2021, there were 0.9 million awards outstanding under the DSU plan.

 

The Company uses equity total return swaps on the equivalent number of Baytex common shares in order to fix the aggregate cost of the Incentive Award plan and the DSU plan at the fair value determined on the grant date. The carrying value of the financial derivatives includes the unrealized fair value of the equity total return swaps which was a liability of $0.2 million at March 31, 2021 (December 31, 2020 - liability of $1.1 million).

 

42Baytex Energy Corp. First Quarter Report 2021

 

 

11.NET LOSS PER SHARE

 

Baytex calculates basic income or loss per share based on the net income or loss attributable to shareholders using the weighted average number of shares outstanding during the period. Diluted income or loss per share amounts reflect the potential dilution that could occur if share awards and share options were converted to common shares. The treasury stock method is used to determine the dilutive effect of share awards and share options whereby the potential conversion of share awards and share options and the amount of compensation expense, if any, attributed to future services are assumed to be used to purchase common shares at the average market price during the period.

 

  Three Months Ended March 31 
  2021  2020 
  

Net loss

  Weighted
average
common
shares
(000s)
  

Net loss per

share

  

Net loss

  Weighted
average
common
shares
(000s)
  Net loss per
share
 
Net loss - basic $(35,352)  562,085  $(0.06) $(2,498,217)  559,804  $(4.46)
Dilutive effect of share awards                  
Net loss - diluted $(35,352)  562,085  $(0.06) $(2,498,217)  559,804  $(4.46)

 

For the three months ended March 31, 2021 and March 31, 2020, all share awards were excluded from the calculation of diluted loss per share as their effect was anti-dilutive given the Company recorded a net loss.

 

12.PETROLEUM AND NATURAL GAS SALES

 

Petroleum and natural gas sales from contracts with customers for the Company’s Canadian and U.S. operating segments is set forth in the following table.

 

  Three Months Ended March 31 
  2021  2020 
  Canada  U.S.  Total  Canada  U.S.  Total 
Light oil and condensate $111,546  $105,596  $217,142  $109,084  $121,155  $230,239 
Heavy oil  109,038      109,038   75,843      75,843 
NGL  4,364   13,142   17,506   1,348   8,842   10,190 
Natural gas sales  14,475   26,541   41,016   8,569   11,773   20,342 
Total petroleum and natural gas sales $239,423  $145,279  $384,702  $194,844  $141,770  $336,614 

 

Included in accounts receivable at March 31, 2021 is $141.4 million of accrued production revenue related to delivered volumes (December 31, 2020 - $81.3 million).

 

Baytex Energy Corp. First Quarter Report 202143

 

 

13.INCOME TAXES

 

The provision for income taxes has been computed as follows:

 

  Three Months Ended March 31 
  2021  2020 
Net loss before income taxes $(29,848) $(2,780,927)
Expected income taxes at the statutory rate of 24.89% (2020 – 25.89%)  (7,429)  (719,982)
(Increase) decrease in income tax recovery resulting from:        
Share-based compensation  374   585 
Effect of foreign exchange  (339)  12,846 
Effect of change in income tax rates     20,930 
Effect of rate adjustments for foreign jurisdictions  (871)  31,484 
Effect of change in deferred tax benefit not recognized  13,937   370,542 
Adjustments and assessments  (168)  885 
Income tax expense (recovery) $5,504  $(282,710)

 

At March 31, 2021, a deferred tax asset of $482.7 million remains unrecognized due to uncertainty surrounding future commodity prices and future capital gains (December 31, 2020 - $469.7 million).

 

As disclosed in the 2020 annual financial statements, in June 2016, certain indirect subsidiary entities received reassessments from the Canada Revenue Agency (the “CRA”) that denied $591 million of non-capital loss deductions that relate to the calculation of income taxes for the years 2011 through 2015. In September 2016, Baytex filed notices of objection with the CRA appealing each reassessment received. There has been no change in the status of these reassessments since an Appeals Officer was assigned to the Company’s file in July 2018. Baytex remains confident that the original tax filings are correct and intends to defend those tax filings through the appeals process.

 

14.FINANCING AND INTEREST

 

  Three Months Ended March 31 
  2021  2020 
Interest on credit facilities $3,336  $4,135 
Interest on long-term notes  21,007   24,273 
Interest on lease obligations  60   127 
Non-cash financing  749   4,442 
Accretion on asset retirement obligations (note 8)  2,298   2,931 
Early redemption expense     3,312 
Financing and interest $27,450  $39,220 

 

15.FOREIGN EXCHANGE

 

  Three Months Ended March 31 
  2021  2020 
Unrealized foreign exchange loss - intercompany notes (1) $13,741  $ 
Unrealized foreign exchange (gain) loss - long-term notes  (16,271)  99,521 
Realized foreign exchange (gain) loss  (275)  371 
Foreign exchange (gain) loss $(2,805) $99,892 

 

(1)During 2020, a series of intercompany notes totaling US$751.0 million were issued from a Canadian subsidiary to a U.S. subsidiary. These notes are eliminated upon consolidation within the Condensed Consolidated Statement of Financial Position and are revalued at the relevant foreign exchange rate at each period end. Foreign exchange gains or losses incurred within the Canadian subsidiary are recognized in unrealized foreign exchange gain or loss whereas those within the U.S. subsidiary are recognized in other comprehensive income.

 

44Baytex Energy Corp. First Quarter Report 2021

 

 

16.FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

 

The Company’s financial assets and liabilities are comprised of cash, trade and other receivables, trade and other payables, financial derivatives, credit facilities, and long-term notes. The fair value of the credit facilities is equal to the principal amount outstanding as the credit facilities bear interest at floating rates and credit spreads that are indicative of market rates. The fair value of the long-term notes is determined based on market prices.

 

The carrying value and fair value of the Company’s financial instruments carried on the condensed consolidated statements of financial position are classified into the following categories:

 

  March 31, 2021  December 31, 2020
  Carrying value  Fair value  Carrying value  Fair value  Fair Value
Measurement
Hierarchy
Financial Assets                  
FVTPL                  
Financial derivatives $239  $239  $5,057  $5,057  Level 2
Total $239  $239  $5,057  $5,057   
                   
Financial assets at amortized cost                  
Trade and other receivables $157,430  $157,430  $107,477  $107,477   
Total $157,430  $157,430  $107,477  $107,477   
                   
Financial Liabilities                  
FVTPL                  
Financial derivatives $(107,958) $(107,958) $(26,792) $(26,792) Level 2
Total $(107,958) $(107,958) $(26,792) $(26,792)  
                   
Financial liabilities at amortized cost                  
Trade and other payables $(178,207) $(178,207) $(155,955) $(155,955) 
Credit facilities  (604,854)  (606,637)  (649,221)  (651,173) 
Long-term notes  (1,117,206)  (1,047,106)  (1,132,868)  (761,129) Level 1
Total $(1,900,267) $(1,831,950) $(1,938,044) $(1,568,257)  

 

There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2021 and 2020.

 

Foreign Currency Risk

 

The carrying amounts of the Company’s U.S. dollar denominated monetary assets and liabilities recorded in entities with a Canadian dollar functional currency at the reporting date are as follows:

 

   Assets   Liabilities 
  March 31, 2021  December 31, 2020  March 31, 2021  December 31, 2020 
U.S. dollar denominated US$750,447  US$759,508  US$1,019,250  US$934,731 

 

Baytex Energy Corp. First Quarter Report 202145

 

 

Commodity Price Risk

 

Financial Derivative Contracts

 

Baytex had the following financial derivative contracts outstanding as of April 29, 2021:

 

  Remaining Period Volume Price/Unit (1) Index
Oil        
Basis Swap Apr 2021 to Jun 2021 2,000 bbl/d WTI less US$13.75/bbl WCS
Basis Swap Apr 2021 to Dec 2021 8,000 bbl/d WTI less US$13.41/bbl WCS
Basis Swap Jan 2022 to Dec 2022 8,000 bbl/d WTI less US$12.57/bbl WCS
Basis Swap (4) Jan 2022 to Dec 2022 1,000 bbl/d WTI less US$11.70/bbl WCS
Basis Swap Apr 2021 to Dec 2021 7,500 bbl/d WTI less US$5.03/bbl MSW
Fixed Sell Apr 2021 to Dec 2021 4,000 bbl/d US$45.00/bbl WTI
3-way option (2) Apr 2021 to Dec 2021 500 bbl/d US$35.00/US$45.00/US$49.03 WTI
3-way option (2) Apr 2021 to Dec 2021 1,500 bbl/d US$35.00/US$45.00/US$49.10 WTI
3-way option (2) Apr 2021 to Dec 2021 3,500 bbl/d US$35.00/US$45.00/US$49.50 WTI
3-way option (2) Apr 2021 to Dec 2021 10,000 bbl/d US$35.00/US$45.00/US$55.00 WTI
3-way option (2) Apr 2021 to Dec 2021 2,000 bbl/d US$37.00/US$42.50/US$48.00 WTI
3-way option (2) Jan 2022 to Dec 2022 1,500 bbl/d US$40.00/US$50.00/US$58.10 WTI
3-way option (2) Jan 2022 to Dec 2022 2,000 bbl/d US$46.00/US$56.00/US$66.72 WTI
3-way option (2)(4) Jan 2022 to Dec 2022 2,500 bbl/d US$47.00/US$57.00/US$67.00 WTI
Swaption (3) Jan 2022 to Dec 2022 5,000 bbl/d US$53.00/bbl WTI
Swaption (3) Jan 2022 to Dec 2022 5,000 bbl/d US$54.00/bbl WTI
         
Natural Gas        
Fixed Sell Apr 2021 to Jun 2021 3,000 GJ/d $2.71/GJ AECO 7A
Fixed Sell Apr 2021 to Dec 2021 16,000 GJ/d $2.36/GJ AECO 7A
Fixed Sell (4) Jan 2022 to Dec 2022 2,500 GJ/d $2.40/GJ AECO 7A
Fixed Sell Apr 2021 to Dec 2021 2,500 GJ/d $2.40/GJ AECO 5A
Fixed Sell Apr 2021 to Dec 2021 12,000 mmbtu/d US$2.70/mmbtu NYMEX
3-way option (2) Jan 2022 to Dec 2022 2,500 mmbtu/d US$2.25/US$2.75/US$3.06 NYMEX
3-way option (2) Jan 2022 to Dec 2022 2,500 mmbtu/d US$2.65/US$2.90/US$3.40 NYMEX

 

(1)Based on the weighted average price per unit for the period.

(2)Producer 3-way option consists of a sold put, bought put, and a sold call. To illustrate, in a US$35.00/US$45.00/US$55.00 contract, Baytex receives WTI plus US$10.00/bbl when WTI is at or below US$35.00/bbl; Baytex receives US$45.00/bbl when WTI is between US$35.00/bbl and US$45.00/bbl; Baytex receives the market price when WTI is between US$45.00/bbl and US$55.00/bbl; and Baytex receives US$55.00/bbl when WTI is above US$55.00/bbl.

(3)For these contracts, the counterparty has the right, if exercised on December 31, 2021, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above.

(4)Contracts entered subsequent to March 31, 2021.

 

The following table sets forth the realized and unrealized gains and losses recorded on financial derivatives.

 

  Three Months Ended March 31 
  2021  2020 
Realized financial derivatives loss (gain) $20,768  $(26,850)
Unrealized financial derivatives loss (gain)  85,984   (95,995)
Financial derivatives loss (gain) $106,752  $(122,845)

 

46Baytex Energy Corp. First Quarter Report 2021

 

 

ABBREVIATIONS

 

AECOthe natural gas storage facility located at Suffield, Alberta
bblbarrel
bbl/dbarrel per day
boe*barrels of oil equivalent
boe/dbarrels of oil equivalent per day
COSOCommittee of Sponsoring Organizations of the Treadway Commission
GAAPgenerally accepted accounting principles
GJgigajoule
GJ/dgigajoule per day
IASInternational Accounting Standard
IASBInternational Accounting Standards
 Board
IFRSInternational Financial Reporting Standards
LLSLouisiana Light Sweet
mbblthousand barrels
mboe*thousand barrels of oil equivalent
mcfthousand cubic feet
mcf/dthousand cubic feet per day
mmBtumillion British Thermal Units
mmBtu/dmillion British Thermal Units per day
mmcfmillion cubic feet
mmcf/dmillion cubic feet per day
NGLnatural gas liquids
NYMEXNew York Mercantile Exchange
NYSENew York Stock Exchange
TSXToronto Stock Exchange
WCSWestern Canadian Select
WTIWest Texas Intermediate


*Oil equivalent amounts may be misleading, particularly if used in isolation. In accordance with NI 51-101, a boe conversion ratio for natural gas of 6 Mcf: 1 bbl has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

 

 

CORPORATE INFORMATION

 

BOARD OF DIRECTORS

 

Mark R. Bly
Chair of the Board

 

Edward D. LaFehr
Director

 

Trudy M. Curran(2)(4)
Director

 

Don G. Hrap(1)(3)
Director

 

Jennifer A. Maki(1)(2)
Director

 

Gregory K. Melchin(1)(4)
Director

 

David L. Pearce(2)(3)
Director

 

Steve D.L. Reynish(3)(4)
Director

 

(1)Member of the Audit Committee

(2)Member of the Human Resources and Compensation Committee

(3)Member of the Reserves and Sustainability Committee

(4)Member of the Nominating and Governance Committee

 

HEAD OFFICE

 

Baytex Energy Corp.
Centennial Place, East Tower
2800, 520 – 3rd Avenue SW
Calgary, Alberta T2P 0R3
Toll-free: 1-800-524-5521
T: 587-952-3000

F: 587-952-3001
www.baytexenergy.com

OFFICERS

 

Edward D. LaFehr 

President and Chief Executive Officer

 

Rodney D. Gray
Executive Vice President and
Chief Financial Officer

 

Brian G. Ector 

Vice President, Capital Markets

 

Kendall D. Arthur
Vice President, Heavy Oil

 

Chad L. Kalmakoff
Vice President, Finance

 

Scott Lovett 

Vice President, Corporate Development

 

Chad E. Lundberg
Vice President, Light Oil

 

AUDITORS

KPMG LLP

 

RESERVES ENGINEERS

McDaniel & Associates Consultants Ltd.

 

TRANSFER AGENT

Odyssey Trust Company

 

EXCHANGE LISTING 

Toronto Stock Exchange
Symbol: BTE