BAYTEX ENERGY CORP.
BAYTEX ANNOUNCES THIRD QUARTER 2021 FINANCIAL AND OPERATING RESULTS,
FREE CASH FLOW OF $101 MILLION AND REPURCHASE OF LONG-TERM NOTES
CALGARY, ALBERTA (November 4, 2021) - Baytex Energy Corp. ("Baytex")(TSX: BTE) reports its operating and financial results for the three and nine months ended September 30, 2021 (all amounts are in Canadian dollars unless otherwise noted).
"During the third quarter, we remain focused on strong capital discipline, generating free cash flow and reducing debt. We have already repurchased and cancelled US$200 million of our 2024 bonds this year and at current commodity prices we now expect to generate record levels of free cash flow in excess of $400 million. Our operating results continue to build momentum as we appraise and develop our Clearwater oil play at Peace River. We have some of the best results in all of the Clearwater, and will now drill four additional wells during the fourth quarter, which will enable us to accelerate our development plans in 2022," commented Ed LaFehr, President and Chief Executive Officer.
Q3 2021 Highlights
| · | Generated production of 79,872 boe/d (82% oil and NGL) in Q3/2021 and 79,942 boe/d (81% oil and NGL) for the first nine months of 2021. | |
| · | Delivered adjusted funds flow of $198 million ($0.35 per basic share) in Q3/2021 and $531 million ($0.94 per basic share) for the first nine months of 2021. | |
| · | Generated free cash flow of $101 million ($0.18 per basic share) in Q3/2021 and $284 million ($0.50 per basic share) for the first nine months of 2021. | |
| · | Reduced net debt by $65 million during the third quarter and by $283 million through the first nine months of 2021. | |
| · | Subsequent to quarter-end, repurchased and cancelled US$85 million principal amount of 5.625% long-term notes, bringing the total repurchased and cancelled to US$200 million (50% of the original principal amount outstanding). |
2021 Outlook
As a result of our strong operating performance through the first nine months of 2021, we are tightening our production guidance to 79,500 to 80,000 boe/d, up from 79,000 to 80,000 boe/d, previously.
We are intensely focused on maintaining capital discipline. The Clearwater has emerged as one of the most profitable plays in Canada and our 2021 appraisal program has delivered exceptional results. As a result, we will drill four additional Clearwater wells during the fourth quarter which are expected to be on-stream in late 2021. Accordingly, we are tightening our forecast 2021 exploration and development expenditures range to $300 to $315 million, as compared to $285 to $315 million, previously.
At current commodity prices, we expect to deliver over $400 million ($0.71 per basic share) of free cash flow this year, which has accelerated our debt reduction efforts.
Five-Year Outlook
Our five-year outlook (2021 to 2025) highlights our financial and operational sustainability and meaningful free cash flow generation. Through this plan period, we are committed to a disciplined, returns based capital allocation philosophy. Under constant US$65/bbl and US$75/bbl WTI pricing scenarios, we expect to generate cumulative free cash flow of approximately $2.0 billion and $2.6 billion, respectively.
Based on the strong pricing environment and continued capital discipline, we now anticipate hitting our initial net debt target of $1.2 billion during Q2/2022. Throughout the plan period we will 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 and/or reinvestment for organic growth.
Our 2022 capital budget is expected to be released in early December following approval by our Board of Directors. We will also update our five-year plan to include drilling opportunities on our Clearwater lands.
Baytex Energy Corp.
Press Release - November 4, 2021
| Three Months Ended | Nine Months Ended | |||||||||||||||||||
| September | June 30, | September | September | September | ||||||||||||||||
| 30, 2021 | 2021 | 30, 2020 | 30, 2021 | 30, 2020 | ||||||||||||||||
FINANCIAL (thousands of Canadian dollars, except per common share amounts) | ||||||||||||||||||||
| Petroleum and natural gas sales | $ | 488,736 | $ | 442,354 | $ | 252,538 | $ | 1,315,792 | $ | 741,841 | ||||||||||
| Adjusted funds flow (1) | 198,397 | 175,883 | 78,508 | 530,862 | 229,330 | |||||||||||||||
| Per share - basic | 0.35 | 0.31 | 0.14 | 0.94 | 0.41 | |||||||||||||||
| Per share - diluted | 0.35 | 0.31 | 0.14 | 0.93 | 0.41 | |||||||||||||||
| Net income (loss) | 32,713 | 1,052,999 | (23,444 | ) | 1,050,361 | (2,660,124 | ) | |||||||||||||
| Per share - basic | 0.06 | 1.87 | (0.04 | ) | 1.86 | (4.75 | ) | |||||||||||||
| Per share - diluted | 0.06 | 1.85 | (0.04 | ) | 1.84 | (4.75 | ) | |||||||||||||
| Capital Expenditures | ||||||||||||||||||||
| Exploration and development expenditures (1) | $ | 94,235 | $ | 61,485 | $ | 15,902 | $ | 239,308 | $ | 202,531 | ||||||||||
| Acquisitions, net of divestitures | (612 | ) | (18 | ) | (98 | ) | (833 | ) | (149 | ) | ||||||||||
| Total oil and natural gas capital expenditures | $ | 93,623 | $ | 61,467 | $ | 15,804 | $ | 238,475 | $ | 202,382 | ||||||||||
| Net Debt | ||||||||||||||||||||
| Credit facilities (2) | $ | 546,803 | $ | 486,623 | $ | 624,826 | $ | 546,803 | $ | 624,826 | ||||||||||
| Long-term notes (2) | 1,000,171 | 1,109,211 | 1,199,160 | 1,000,171 | 1,199,160 | |||||||||||||||
| Long-term debt | 1,546,974 | 1,595,834 | 1,823,986 | 1,546,974 | 1,823,986 | |||||||||||||||
| Working capital deficiency | 17,684 | 33,795 | 82,093 | 17,684 | 82,093 | |||||||||||||||
| Net debt (1) | $ | 1,564,658 | $ | 1,629,629 | $ | 1,906,079 | $ | 1,564,658 | $ | 1,906,079 | ||||||||||
| Shares Outstanding - basic(thousands) | ||||||||||||||||||||
| Weighted average | 564,211 | 564,156 | 561,128 | 563,492 | 560,484 | |||||||||||||||
| End of period | 564,213 | 564,182 | 561,163 | 564,213 | 561,163 | |||||||||||||||
| BENCHMARK PRICES | ||||||||||||||||||||
| Crude oil | ||||||||||||||||||||
| WTI (US$/bbl) | $ | 70.56 | $ | 66.07 | $ | 40.93 | $ | 64.82 | $ | 38.32 | ||||||||||
| MEH oil (US$/bbl) | 71.64 | 67.15 | 41.63 | 66.05 | 39.19 | |||||||||||||||
| MEH oil differential to WTI (US$/bbl) | 1.08 | 1.08 | 0.70 | 1.23 | 0.87 | |||||||||||||||
| Edmonton par ($/bbl) | 83.78 | 77.28 | 49.83 | 75.88 | 43.70 | |||||||||||||||
| Edmonton par differential to WTI (US$/bbl) | (4.07 | ) | (3.13 | ) | (3.51 | ) | (4.19 | ) | (6.04 | ) | ||||||||||
| WCS heavy oil ($/bbl) | 71.81 | 67.03 | 42.40 | 65.47 | 33.34 | |||||||||||||||
| WCS differential to WTI (US$/bbl) | (13.57 | ) | (11.48 | ) | (9.09 | ) | (12.51 | ) | (13.70 | ) | ||||||||||
| Natural gas | ||||||||||||||||||||
| NYMEX (US$/mmbtu) | $ | 4.01 | $ | 2.83 | $ | 1.98 | $ | 3.18 | $ | 1.88 | ||||||||||
| AECO ($/mcf) | 3.54 | 2.85 | 2.18 | 3.11 | 2.08 | |||||||||||||||
| CAD/USD average exchange rate | 1.2601 | 1.2279 | 1.3316 | 1.2515 | 1.3541 |
| 2 | Baytex Energy Corp. Third Quarter Report 2021 | |
Baytex Energy Corp.
Press Release - November 4, 2021
| Three Months Ended | Nine Months Ended | |||||||||||||||||||
| September | June 30, | September | September | September | ||||||||||||||||
| 30, 2021 | 2021 | 30, 2020 | 30, 2021 | 30, 2020 | ||||||||||||||||
| OPERATING | ||||||||||||||||||||
| Daily Production | ||||||||||||||||||||
| Light oil and condensate (bbl/d) | 35,614 | 37,134 | 34,101 | 36,060 | 39,570 | |||||||||||||||
| Heavy oil (bbl/d) | 21,996 | 21,269 | 22,138 | 21,752 | 20,946 | |||||||||||||||
| NGL (bbl/d) | 7,174 | 7,563 | 7,417 | 6,995 | 7,624 | |||||||||||||||
| Total liquids (bbl/d) | 64,784 | 65,966 | 63,656 | 64,807 | 68,140 | |||||||||||||||
| Natural gas (mcf/d) | 90,528 | 91,172 | 84,945 | 90,812 | 88,602 | |||||||||||||||
| Oil equivalent (boe/d @ 6:1) (3) | 79,872 | 81,162 | 77,814 | 79,942 | 82,907 | |||||||||||||||
| Netback (thousands of Canadian dollars) | ||||||||||||||||||||
| Total sales, net of blending and other expense (4) | $ | 469,155 | $ | 422,387 | $ | 241,865 | $ | 1,259,124 | $ | 704,351 | ||||||||||
| Royalties | (90,523 | ) | (81,531 | ) | (40,052 | ) | (239,004 | ) | (125,928 | ) | ||||||||||
| Operating expense | (84,196 | ) | (82,901 | ) | (73,447 | ) | (247,645 | ) | (251,597 | ) | ||||||||||
| Transportation expense | (7,818 | ) | (7,486 | ) | (6,372 | ) | (24,092 | ) | (21,745 | ) | ||||||||||
| Operating netback (1) | $ | 286,618 | $ | 250,469 | $ | 121,994 | $ | 748,383 | $ | 305,081 | ||||||||||
| General and administrative | (9,980 | ) | (10,610 | ) | (7,741 | ) | (29,323 | ) | (24,954 | ) | ||||||||||
| Cash financing and interest | (22,793 | ) | (23,554 | ) | (25,418 | ) | (70,750 | ) | (81,340 | ) | ||||||||||
| Realized financial derivatives (loss) gain | (53,905 | ) | (39,024 | ) | (9,743 | ) | (113,697 | ) | 30,731 | |||||||||||
| Other (5) | (1,543 | ) | (1,398 | ) | (584 | ) | (3,751 | ) | (188 | ) | ||||||||||
| Adjusted funds flow (1) | $ | 198,397 | $ | 175,883 | $ | 78,508 | $ | 530,862 | $ | 229,330 | ||||||||||
| Netback (per boe) | ||||||||||||||||||||
| Total sales, net of blending and other expense (4) | $ | 63.85 | $ | 57.19 | $ | 33.79 | $ | 57.69 | $ | 31.01 | ||||||||||
| Royalties | (12.32 | ) | (11.04 | ) | (5.59 | ) | (10.95 | ) | (5.54 | ) | ||||||||||
| Operating expense | (11.46 | ) | (11.22 | ) | (10.26 | ) | (11.35 | ) | (11.08 | ) | ||||||||||
| Transportation expense | (1.06 | ) | (1.01 | ) | (0.89 | ) | (1.10 | ) | (0.96 | ) | ||||||||||
| Operating netback (1) | $ | 39.01 | $ | 33.92 | $ | 17.05 | $ | 34.29 | $ | 13.43 | ||||||||||
| General and administrative | (1.36 | ) | (1.44 | ) | (1.08 | ) | (1.34 | ) | (1.10 | ) | ||||||||||
| Cash financing and interest | (3.10 | ) | (3.19 | ) | (3.55 | ) | (3.24 | ) | (3.58 | ) | ||||||||||
| Realized financial derivatives (loss) gain | (7.34 | ) | (5.28 | ) | (1.36 | ) | (5.21 | ) | 1.35 | |||||||||||
| Other (5) | (0.21 | ) | (0.20 | ) | (0.09 | ) | (0.18 | ) | - | |||||||||||
| Adjusted funds flow (1) | $ | 27.00 | $ | 23.81 | $ | 10.97 | $ | 24.32 | $ | 10.10 |
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 cash share-based compensation. Refer to the Q3/2021 MD&A for further information on these amounts. |
| Baytex Energy Corp. Third Quarter Report 2021 | 3 | |
Baytex Energy Corp.
Press Release - November 4, 2021
Q3/2021 Results
During Q3/2021, we delivered strong operating and financial results and continued to advance our exciting new Clearwater play in northwest Alberta with the two strongest initial rate wells drilled to date in the play.
During the quarter, we delivered adjusted funds flow of $198 million ($0.35 per basic share) and net income of $33 million ($0.06 per basic share). We generated free cash flow of $101 million ($0.18 per basic share), which brings our year-to-date free cash flow to $284 million ($0.50 per basic share). We have directed 100% of our free cash flow this year to reduce our net debt, which now sits at $1.56 billion, down from $1.85 billion at the beginning of the year.
Production during the third quarter averaged 79,872 boe/d (82% oil and NGL), as compared to 81,162 boe/d (81% oil and NGL) in Q2/2021. Our operating results reflect strong performance across our light and heavy oil assets in Canada with volumes up 2% over the second quarter, while Eagle Ford volumes were lower due to the number of wells brought on-stream. Exploration and development expenditures totaled $94 million in Q3/2021 that included the drilling of 57 (46.7 net) wells with a 100% success rate.
2021 Guidance
In 2021, we are benefiting from our diversified oil weighted portfolio and our commitment to allocate capital effectively. Based on the forward strip(1), we expect to generate over $400 million of free cash flow in 2021.
We are intensely focused on maintaining capital discipline. The Clearwater has emerged as one of the most profitable plays in Canada and our 2021 appraisal program has delivered production results beyond our initial expectations. As a result, we have committed to drill four additional Clearwater wells during the fourth quarter with the wells expected to be on-stream in late 2021. Accordingly, we are tightening our forecast 2021 exploration and development expenditures range to $300 to $315 million, as compared to $285 to $315 million, previously.
As a result of our continued strong operating performance through the first nine months of 2021, we are also tightening our production guidance range to 79,500 to 80,000 boe/d, up from 79,000 to 80,000 boe/d, previously.
We have also fine-tuned several of our cost assumptions. Our interest expense guidance is 3% lower due to reduced net debt and the repurchase and cancellation of a portion of the 5.625% long-term notes due 2024.
The following table highlights our updated 2021 annual guidance.
| 2021 Guidance (2) | 2021 Revised Guidance | |||||||
| Exploration and development expenditures | $285 - $315 million | $300 - $315 million | ||||||
| Production (boe/d) | 79,000 - 80,000 | 79,500 - 80,000 | ||||||
| Expenses: | ||||||||
| Royalty rate | 18.0% - 18.5% | 18.5% - 19.0% | ||||||
| Operating | $11.25 - $12.00/boe | $11.25 - $11.75/boe | ||||||
| Transportation | $1.15 - $1.25/boe | $1.10 - $1.15/boe | ||||||
| General and administrative | $42 million ($1.45/boe) | $42 million ($1.44/boe) | ||||||
| Interest | $95 million ($3.27/boe) | $92 million ($3.16/boe) | ||||||
| Leasing expenditures | $4 million | no change | ||||||
| Asset retirement obligations | $6 million | no change |
Notes:
| (1) | 2021 full-year pricing assumptions: WTI - US$68/bbl; WCS differential - US$12/bbl; MSW differential - US$4/bbl, NYMEX Gas - US$3.85/mcf; AECO Gas - $3.50/mcf and Exchange Rate (CAD/USD) - 1.25. |
| (2) | As announced on July 28, 2021. |
| 4 | Baytex Energy Corp. Third Quarter Report 2021 | |
Baytex Energy Corp.
Press Release - November 4, 2021
Operating Results
Eagle Ford and Viking Light Oil
Production in the Eagle Ford averaged 31,748 boe/d (79% oil and NGL) during Q3/2021, as compared to 33,957 boe/d in Q2/2021. The lower volumes reflect level of completion activity during the quarter. We commenced production from 17 (3.4 net) wells during the third quarter, as compared to 62 (17.2 net) wells in the first half of 2021. In Q3/2021, we invested $19 million on exploration and development in the Eagle Ford and generated an operating netback of $117 million. We expect to bring approximately 23 net wells on production in the Eagle Ford in 2021.
Production in the Viking averaged 17,132 boe/d (90% oil and NGL) during Q3/2021, as compared to 16,301 boe/d in Q2/2021. We maintained an active pace of development during the third quarter with 23.0 net wells drilled and 37.0 net wells brought on production. In Q3/2021, we invested $29 million on exploration and development and generated an operating netback of $88 million. We expect to bring approximately 115 net wells on production in the Viking during 2021.
Heavy Oil
Our heavy oil assets at Peace River and Lloydminster (excluding our Clearwater development) produced a combined 22,577 boe/d (91% oil and NGL) during the Q3/2021, as compared to 23,304 boe/d in Q2/2021. After a quiet first half of the year, our heavy oil program kicked off during the third quarter and included drilling 2 net Bluesky wells at Peace River and 14 net wells at Lloydminster. In Q3/2021, we invested $18 million on exploration and development in Peace River and Lloydminster and generated an operating netback of $60 million.
Peace River Clearwater
We are committed to building and maintaining respectful relationships with Indigenous communities and creating opportunities for meaningful economic participation and inclusion. In early 2020, we executed a strategic agreement with the Peavine Métis Settlement in the Peace River area that covered 60 sections of land directly to the south of our existing Seal operations. At the time, we identified significant potential for an early stage exploratory play targeting the Spirit River formation, a Clearwater formation equivalent. In August 2021, we executed a second strategic agreement with the Peavine Métis Settlement that covers an additional 20 sections, bringing our total Peavine acreage to 80 contiguous sections. When combined with our legacy acreage position in northwest Alberta, we estimate that over 120 sections are prospective for Clearwater development.
Production in the Clearwater averaged 1,540 bbl/d during Q3/2021. We currently have five producing wells on our Peavine acreage and production has increased from zero at the beginning of this year to approximately 1,900 bbl/d, currently. Our three eight-lateral wells continue to outperform type curve assumptions and two of our wells rank as the top initial rate wells drilled to-date across the play.
The following table summarizes the results of our 2021 appraisal program.
| Area | Well | Spud | Rig Release | # of Laterals |
30-Day Initial |
Current | ||||||||||||
| Peavine | 100/04-34-078-16W5 | January 7 | January 15 | 2 | 175 | 100 | ||||||||||||
| Peavine | 102/04-34-078-16W5 | June 15 | June 21 | 2 | 175 | 170 | ||||||||||||
| Peavine | 100/13-27-078-16W5 | June 22 | July 6 | 8 | 695 | 700 | ||||||||||||
| Peavine | 100/05-34-078-16W5 | July 8 | July 18 | 8 | 412 | 300 | ||||||||||||
| Peavine | 102/11-31-078-15W5 | July 20 | August 4 | 8 | 930 | 645 |
(1) 30-Day Initial Production Rate (bbl/d) is defined as the average oil rate over the first 720 hours of production following drilling fluid recovery.
As we continue to progress our development plan, we have committed to drill four additional Clearwater wells during the fourth quarter. In addition, as part of our 2022 plan, which is to be confirmed and released in early December 2021, we are working with the Peavine Métis Settlement and are preparing to execute an expanded program of up to 18 wells. To-date, we have de-risked 20 sections of land and pending further success, the play holds the potential for greater than 200 locations. At current commodity prices, the Clearwater generates among the strongest economics within our portfolio with payouts of less than six months and has the ability to grow organically while enhancing our free cash flow profile.
| Baytex Energy Corp. Third Quarter Report 2021 | 5 | |
Baytex Energy Corp.
Press Release - November 4, 2021
Pembina Area Duvernay Light Oil
Production in the Pembina Duvernay averaged 1,528 boe/d (79% oil and NGL) during Q3/2021, as compared to 1,698 boe/d in Q2/2021. During the third quarter, we drilled two 100% working interest wells and initial flow back rates are very encouraging. The first well (7-8) was brought on-stream October 18 and is currently producing 1,010 boe/d (756 bbl/d oil, 162 bbl/d NGLs and 0.6 mmcf/d of natural gas). The second well (6-8) was brought on-stream October 30 and is currently producing 1,500 boe/d (1,270 bbl/d oil, 147 bbl/d NGLs and 0.5 mmcf/d of natural gas). We now have eleven producing wells in the Pembina area and have significantly de-risked our approximately 38-kilometre long acreage fairway, where we hold approximately 200 sections (100% working interest) of Duvernay land.
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 September 30, 2021, we had $471 million of undrawn capacity on our credit facilities, resulting in liquidity, net of working capital, of $454 million.
Our net debt, which includes our credit facilities, long-term notes and working capital, totaled $1.56 billion at September 30, 2021, down from $1.63 billion at June 30, 2021.
During 2021, we have repurchased and cancelled US$200 million of the 5.625% long term notes due June 2024. This represents 50% of the original US$400 million outstanding and includes US$84.5 million repurchased and cancelled subsequent to quarter end.
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 Q4/2021, we have entered into hedges on approximately 45% 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 net Canadian light oil exposure at US$5.03/bbl and WCS differential hedges on approximately 45% of our net expected heavy oil exposure at a WTI-WCS differential of approximately US$13.23/bbl.
For 2022, we have entered into hedges on approximately 42% of our net crude oil exposure utilizing a combination of a 3-way option structure that provides price protection at US$57.76/bbl with upside participation to US$67.51/bbl and swaptions at US$53.50/bbl. We also have WTI-MSW differential hedges on approximately 25% of our expected net Canadian light oil exposure at US$4.43/bbl and WCS differential hedges on approximately 70% of our expected net heavy oil exposure at a WTI-WCS differential of approximately US$12.28/bbl.
A complete listing of our financial derivative contracts can be found in Note 16 to our Q3/2021 financial statements.
Additional Information
Our condensed consolidated interim unaudited financial statements for the three and nine months ended September 30, 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, November 5, 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/baytex20211105.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",
| 6 | Baytex Energy Corp. Third Quarter Report 2021 | |
Baytex Energy Corp.
Press Release - November 4, 2021
"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; that we expect to generate in excess of $400 million of free cash flow in 2021; our plan to drill and bring on-stream four additional wells in the Clearwater in Q4/2021; that our debt reduction will accelerate; our five-year outlook: including that it demonstrates financial and operational sustainability, meaningful free cash flow generation and that we are committed to disciplined and returns based philosophy , the cumulative free cash flow it will generate at certain WTI oil prices and that we anticipate hitting our debt target of $1.2 billion by mid-2022; that we will monitor our leverage position and market conditions to enhance shareholder returns which could be share buy-backs, a dividend or reinvestment for organic growth; that we expect to release our 2022 budget in early December 2021 with an updated five-year plan; we expect to benefit from our diversified oil weighted portfolio and our commitment to allocate capital effectively; our 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 23 net wells in the Eagle Ford and 115 in the Viking; that we are committed to building and maintaining respectful relationships with Indigenous communities and creating opportunities for meaningful economic participation and inclusion; that we have 120 sections of prospective Clearwater lands; that we are preparing to drill up to 18 Clearwater wells in 2022 and believe the play holds the potential for greater than 200 locations; that the Clearwater generates among the strongest economics in our portfolio with payouts of less than six months and has the ability to grow organically while enhancing our free cash flow profile; that we have de-risked our approximately 38-kilometer acreage fairway in the Duvernay; that we use financial derivative contracts and crude-by-rail to reduce adjusted funds flow volatility; the percentage of our net exposure to crude oil, the MTI-MSW differential and WCS differential that we have hedged for Q4/2021 and 2022.
These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum and natural gas prices and differentials between light, medium and heavy oil prices; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; our ability to borrow under our credit agreements; the receipt, in a timely manner, of regulatory and other required approvals for our operating activities; the availability and cost of labour and other industry services; interest and foreign exchange rates; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; our ability to develop our crude oil and natural gas properties in the manner currently contemplated; and current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being adopted as anticipated). Readers are cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.
Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: the volatility of oil and natural gas prices and price differentials (including the impacts of Covid-19); the availability and cost of capital or borrowing; risks associated with our ability to exploit our properties and add reserves; availability and cost of gathering, processing and pipeline systems; that our credit facilities may not provide sufficient liquidity or may not be renewed; failure to comply with the covenants in our debt agreements; risks associated with a third-party operating our Eagle Ford properties; public perception and its influence on the regulatory regime; restrictions or costs imposed by climate change initiatives and the physical risks of climate change; new regulations on hydraulic fracturing; restrictions on or access to water or other fluids; changes in government regulations that affect the oil and gas industry; regulations regarding the disposal of fluids; changes in environmental, health and safety regulations; costs to develop and operate our properties; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; retaining or replacing our leadership and key personnel; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating oil and natural gas reserves; our inability to fully insure against all risks; risks of counterparty default; risks related to our thermal heavy oil projects; alternatives to and changing demand for petroleum products; risks associated with our use of information technology systems; results of litigation; risks associated with large projects; risks associated with the ownership of our securities, including changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control.
These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2020, 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.
| Baytex Energy Corp. Third Quarter Report 2021 | 7 | |
Baytex Energy Corp.
Press Release - November 4, 2021
In addition, we use a ratio of net debt to adjusted funds flow to manage our capital structure. We eliminate settlements of abandonment obligations from cash flow from operations as the amounts can be discretionary and may vary from period to period depending on our capital programs and the maturity of our operating areas. The settlement of abandonment obligations are managed with our capital budgeting process which considers available adjusted funds flow. Changes in non-cash working capital are eliminated in the determination of adjusted funds flow as the timing of collection, payment and incurrence is variable and by excluding them from the calculation we are able to provide a more meaningful measure of our cash flow on a continuing basis. For a reconciliation of adjusted funds flow to cash flow from operating activities, see Management's Discussion and Analysis of the operating and financial results for the three and nine months ended September 30, 2021.
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.
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 and nine months ended September 30, 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.
| 8 | Baytex Energy Corp. Third Quarter Report 2021 | |
Baytex Energy Corp.
Press Release - November 4, 2021
| Three Months Ended September 30, 2021 | Nine Months Ended September 30, 2021 | |||||||||||||||||||||||||||||||||||||||
Heavy Oil (bbl/d) |
Light and Medium Oil (bbl/d) |
NGL (bbl/d) | Natural
Gas | Oil
Equivalent | Heavy Oil (bbl/d) |
Light and Medium Oil (bbl/d) |
NGL (bbl/d) | Natural
Gas | Oil
Equivalent | |||||||||||||||||||||||||||||||
| Canada - Heavy | ||||||||||||||||||||||||||||||||||||||||
| Peace River | 10,020 | 7 | 21 | 11,220 | 11,918 | 11,099 | 8 | 22 | 11,536 | 13,052 | ||||||||||||||||||||||||||||||
| Lloydminster | 10,436 | 3 | - | 1,319 | 10,659 | 10,079 | 4 | - | 1,371 | 10,312 | ||||||||||||||||||||||||||||||
| Peavine | 1,540 | - | - | - | 1,540 | 574 | - | - | - | 574 | ||||||||||||||||||||||||||||||
| Canada - Light | ||||||||||||||||||||||||||||||||||||||||
| Viking | - | 15,193 | 145 | 10,762 | 17,132 | - | 15,639 | 140 | 10,949 | 17,603 | ||||||||||||||||||||||||||||||
| Duvernay | - | 774 | 436 | 1,908 | 1,528 | - | 903 | 553 | 1,979 | 1,786 | ||||||||||||||||||||||||||||||
| Remaining Properties | - | 555 | 628 | 24,988 | 5,347 | - | 576 | 942 | 25,581 | 5,781 | ||||||||||||||||||||||||||||||
| United States | ||||||||||||||||||||||||||||||||||||||||
| Eagle Ford | - | 19,082 | 5,944 | 40,331 | 31,748 | - | 18,930 | 5,338 | 39,396 | 30,834 | ||||||||||||||||||||||||||||||
| Total | 21,996 | 35,614 | 7,174 | 90,528 | 79,872 | 21,752 | 36,060 | 6,995 | 90,812 | 79,942 |
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
| Baytex Energy Corp. Third Quarter Report 2021 | 9 | |
Baytex Energy Corp.
Q3 2021 MD&A
BAYTEX ENERGY CORP.
Management's Discussion and Analysis
For the three and nine months ended September 30, 2021 and 2020
Dated November 4, 2021
The following is management's discussion and analysis ("MD&A") of the operating and financial results of Baytex Energy Corp. for the three and nine months ended September 30, 2021. This information is provided as of November 4, 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 and nine months ended September 30, 2021 ("Q3/2021" and "YTD 2021") have been compared with the results for the three and nine months ended September 30, 2020 ("Q3/2020" and "YTD 2020"). This MD&A should be read in conjunction with the Company's condensed consolidated interim financial statements ("consolidated financial statements") for the three and nine months ended September 30, 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 energy 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.
THIRD QUARTER HIGHLIGHTS
Baytex delivered strong operating and financial results for Q3/2021 as the global economy continued to recover from the impact of the COVID-19 pandemic. The outlook for crude oil demand has improved with the increase in economic activity due to the distribution of vaccines and easing of restrictions. Oil prices were also supported by ongoing OPEC production curtailments and limited supply growth from large independent producers. As a result, the average WTI benchmark price for Q3/2021 was US$70.56/bbl which was US$29.63/bbl higher than Q3/2020 when WTI averaged US$40.93/bbl. With higher commodity prices, we generated adjusted funds flow of $198.4 million and free cash flow of $101.2 million which contributed to a $65.0 million reduction in net debt from Q2/2021. Strong well performance across all of our assets resulted in production of 79,872 boe/d which was at the high end of our annual guidance range of 79,000 - 80,000 boe/d. 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.
Exploration and development expenditures were $94.2 million for Q3/2021 and were focused on our Canadian operations where we spent $75.5 million. In Canada, we drilled 19 (18.7 net) heavy oils wells, including 2 (2.0 net) additional appraisal wells in our developing Clearwater play and 26 (25.0 net) light oil wells during Q3/2021 which resulted in production of 48,124 boe/d that increased 919 boe/d from Q2/2021. After an active first half we moderated the pace of capital activity in the U.S. which resulted in production of 31,748 boe/d in Q3/2021 compared to 33,957 boe/d boe/d in Q2/2021. In Q3/2021, we brought 17 (3.4 net) wells on production and spent $18.7 million compared to Q2/2021 where we brought 38 (10.2 net) wells on stream.
Adjusted funds flow of $198.4 million in Q3/2021 was $119.9 million higher than Q3/2020 and $22.5 million higher than Q2/2021 as a result of higher benchmark prices. The increase in crude oil prices was the primary factor that resulted in a $164.6 million increase in operating netback for Q3/2021 relative to Q3/2020. Our strong operating and financial results contributed to net income of $32.7 million for Q3/2021 compared to a net loss of $23.4 million for Q3/2020.
| 10 | Baytex Energy Corp. Third Quarter Report 2021 | |
Baytex Energy Corp.
Q3 2021 MD&A
We used our free cash flow of $284.2 million generated during the nine months ended September 30, 2021 to reduce our debt. Net debt decreased $282.9 million to $1.56 billion at September 30, 2021 compared to $1.85 billion at December 31, 2020. As part of our debt reduction during YTD 2021 we repurchased and cancelled US$115.5 million of the 5.625% Notes due in 2024 and subsequent to Q3/2021 we repurchased and cancelled an additional US$84.5 million of these notes on October 29, 2021. Following these repurchases US$200.0 million of the 5.625% Notes remain outstanding.
2021 GUIDANCE
The following table compares our revised 2021 annual guidance to our previously announced guidance. As a result of our strong operational performance during the first nine months of 2021 we are tightening our annual production guidance range to 79,500 - 80,000 boe/d, up from 79,000 - 80,000 boe/d, previously. Our 2021 Clearwater appraisal program has delivered production results beyond our initial expectations. As a result, we have committed to drill up to four additional Clearwater wells during the fourth quarter with the wells expected to be on production in late 2021 and early 2022. Accordingly, we are tightening our forecasted 2021 exploration and development expenditures guidance range to $300 - $315 million from $285 - $315 million, previously.
We have also refined our cost assumptions along with our interest expense guidance which is 3% lower due to reduced net debt and the repurchase and cancellation of a portion of the 5.625% Notes. Our revised royalty rate guidance is slightly higher as commodity prices have exceeded our expectations which has resulted in slightly higher royalty rates for our Canadian production.
| Previous Annual | Revised Annual | |||
| Guidance (1) | Guidance | |||
| Exploration and development expenditures | $285 - $315 million | $300 - $315 million | ||
| Production (boe/d) | 79,000 - 80,000 | 79,500 - 80,000 | ||
| Expenses: | ||||
| Royalty rate | 18.0% - 18.5% | 18.5% - 19.0% | ||
| Operating | $11.25 - $12.00/boe | $11.25 - $11.75/boe | ||
| Transportation | $1.15 - $1.25/boe | $1.10 - $1.15/boe | ||
| General and administrative | $42 million ($1.45/boe) | $42 million ($1.44/boe) | ||
| Interest | $95 million ($3.27/boe) | $92 million ($3.16/boe) | ||
| Leasing expenditures | $4 million | no change | ||
| Asset retirement obligations | $6 million | no change |
| (1) | As announced on July 28, 2021. |
| Baytex Energy Corp. Third Quarter Report 2021 | 11 | |
Baytex Energy Corp.
Q3 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 September 30 | ||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||
| Canada | U.S. | Total | Canada | U.S. | Total | |||||||||||||||||||
| Daily Production | ||||||||||||||||||||||||
| Liquids (bbl/d) | ||||||||||||||||||||||||
| Light oil and condensate | 16,532 | 19,082 | 35,614 | 18,248 | 15,853 | 34,101 | ||||||||||||||||||
| Heavy oil | 21,996 | - | 21,996 | 22,138 | - | 22,138 | ||||||||||||||||||
| Natural Gas Liquids (NGL) | 1,230 | 5,944 | 7,174 | 1,281 | 6,136 | 7,417 | ||||||||||||||||||
| Total liquids (bbl/d) | 39,758 | 25,026 | 64,784 | 41,667 | 21,989 | 63,656 | ||||||||||||||||||
| Natural gas (mcf/d) | 50,197 | 40,331 | 90,528 | 44,980 | 39,965 | 84,945 | ||||||||||||||||||
| Total production (boe/d) | 48,124 | 31,748 | 79,872 | 49,164 | 28,650 | 77,814 | ||||||||||||||||||
| Production Mix | ||||||||||||||||||||||||
| Segment as a percent of total | 60 | % | 40 | % | 100 | % | 63 | % | 37 | % | 100 | % | ||||||||||||
| Light oil and condensate | 34 | % | 60 | % | 45 | % | 37 | % | 55 | % | 44 | % | ||||||||||||
| Heavy oil | 46 | % | - | % | 28 | % | 45 | % | - | % | 28 | % | ||||||||||||
| NGL | 3 | % | 19 | % | 9 | % | 3 | % | 22 | % | 10 | % | ||||||||||||
| Natural gas | 17 | % | 21 | % | 18 | % | 15 | % | 23 | % | 18 | % |
| Nine Months Ended September 30 | ||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||
| Canada | U.S. | Total | Canada | U.S. | Total | |||||||||||||||||||
| Daily Production | ||||||||||||||||||||||||
| Liquids (bbl/d) | ||||||||||||||||||||||||
| Light oil and condensate | 17,130 | 18,930 | 36,060 | 20,409 | 19,161 | 39,570 | ||||||||||||||||||
| Heavy oil | 21,752 | - | 21,752 | 20,946 | - | 20,946 | ||||||||||||||||||
| Natural Gas Liquids (NGL) | 1,657 | 5,338 | 6,995 | 1,178 | 6,446 | 7,624 | ||||||||||||||||||
| Total liquids (bbl/d) | 40,539 | 24,268 | 64,807 | 42,533 | 25,607 | 68,140 | ||||||||||||||||||
| Natural gas (mcf/d) | 51,416 | 39,396 | 90,812 | 43,028 | 45,574 | 88,602 | ||||||||||||||||||
| Total production (boe/d) | 49,108 | 30,834 | 79,942 | 49,704 | 33,203 | 82,907 | ||||||||||||||||||
| Production Mix | ||||||||||||||||||||||||
| Segment as a percent of total | 61 | % | 39 | % | 100 | % | 60 | % | 40 | % | 100 | % | ||||||||||||
| Light oil and condensate | 35 | % | 61 | % | 45 | % | 41 | % | 58 | % | 48 | % | ||||||||||||
| Heavy oil | 44 | % | - | % | 27 | % | 42 | % | - | % | 25 | % | ||||||||||||
| NGL | 3 | % | 17 | % | 9 | % | 2 | % | 19 | % | 9 | % | ||||||||||||
| Natural gas | 18 | % | 22 | % | 19 | % | 15 | % | 23 | % | 18 | % |
Production was 79,872 boe/d for Q3/2021 and 79,942 boe/d for YTD 2021 compared to 77,814 boe/d for Q3/2020 and 82,907 boe/ d for YTD 2020. Total production was higher in Q3/2021 compared to Q3/2020 due to increased development activity in Canada and the U.S. during 2021 following the reset of our business in 2020. Total production of 79,942 boe/d for YTD 2021 is at the high end of our revised annual guidance of 79,500 - 80,000 and reflects the strong well performance in the U.S. and Canada.
| 12 | Baytex Energy Corp. Third Quarter Report 2021 | |
Baytex Energy Corp.
Q3 2021 MD&A
In Canada, production of 48,124 boe/d for Q3/2021 and 49,108 boe/d for YTD 2021 was relatively consistent with 49,164 boe/d for Q3/2020 and 49,704 boe/d for YTD 2020. Strong well performance from our successful 2021 development program has restored production for Q3/2021 and YTD 2021 to levels that are relatively consistent with the comparative periods after development activity was limited throughout 2020.
In the U.S., production of 31,748 boe/d for Q3/2021 was higher than 28,650 boe/d for Q3/2020 as development activity in the U.S. increased during Q4/2020 and we continued this pace of development into 2021. Production of 30,834 boe/d during YTD 2021 was lower than 33,203 boe/d for YTD 2020 due to limited development activity during 2020 following the sharp decline in oil prices during Q2/2020. We initiated production from 17 (3.4 net) wells and 79 (20.6 net) wells during Q3/2021 and YTD 2021 respectively compared to 6 (0.8 net) wells and 53 (11.5 net) wells during the comparative periods in 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 Q3/2021. Oil supply has been impacted by OPEC production curtailments and limited production growth from large independent producers while the outlook for oil demand continues to improve as global economic activity increases and economies recover from the pandemic. These factors resulted in the WTI benchmark price averaging US$70.56/bbl for Q3/2021 and US$64.82/bbl for YTD 2021 which was higher relative to Q3/2020 and YTD 2020 when WTI averaged US$40.93/bbl and US$38.32/bbl, respectively.
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$71.64/bbl during Q3/2021 and US$66.05/bbl during YTD 2021 which is higher than the price achieved in 2020 when the benchmark was US$41.63/ bbl during Q3/2020 and US$39.19/bbl during YTD 2020. The MEH benchmark traded at a premium to WTI of US$1.08/bbl in Q3/2021 and a US$1.23/bbl premium YTD 2021 compared to a US$0.70/bbl premium to WTI during Q3/2020 and US$0.87/bbl premium YTD 2020.
Prices for Canadian oil trade at a discount to WTI due to a lack of egress to diversified markets from Western Canada. Differentials for Canadian oil prices relative to WTI fluctuate from period to period based on production and inventory levels in Western Canada.
We compare the price received for our light oil production in Canada to the Edmonton par benchmark oil price. The Edmonton par price averaged $83.78/bbl during Q3/2021 and $75.88/bbl during YTD 2021 compared to $49.83/bbl during Q3/2020 and $43.70/ bbl during YTD 2020. Edmonton par traded at a discount to WTI of US$4.07/bbl for Q3/2021 and US$4.19/bbl for YTD 2021 compared to a discount of US$3.51/bbl for Q3/2020 and US$6.04/bbl for YTD 2020.
We compare the price received for our heavy oil production in Canada to the WCS heavy oil benchmark. The WCS heavy oil price for Q3/2021 and YTD 2021 averaged $71.81/bbl and $65.47/bbl, respectively, compared to $42.40/bbl and $33.34/bbl for the same periods of 2020. The WCS heavy oil differential was US$13.57/bbl in Q3/2021 and US$12.51/bbl in YTD 2021 compared to US$9.09/bbl for Q3/2020 and US$13.70/bbl for YTD 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$4.01/mmbtu for Q3/2021 and US$3.18/mmbtu for YTD 2021 which is higher than US$1.98/mmbtu for Q3/2020 and US$1.88/mmbtu for YTD 2020. Strong demand and lower U.S. production resulted in reduced natural gas inventory levels which contributed to higher NYMEX benchmark prices for YTD 2021 relative to YTD 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 limited market access for Canadian natural gas production. Lower production and an increased demand for natural gas resulted in reduced inventory levels in Canada and contributed to stronger AECO benchmark pricing in 2021 relative to 2020. The AECO benchmark averaged $3.54/mcf during Q3/2021 and $3.11/mcf during YTD 2021 which is higher than $2.18/mcf for Q3/2020 and $2.08/mcf for YTD 2020.
| Baytex Energy Corp. Third Quarter Report 2021 | 13 | |
Baytex Energy Corp.
Q3 2021 MD&A
The following tables compare select benchmark prices and our average realized selling prices for the three and nine months ended September 30, 2021 and 2020.
| Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||||||||||
| 2021 | 2020 | Change | 2021 | 2020 | Change | |||||||||||||||||||
| Benchmark Averages | ||||||||||||||||||||||||
| WTI oil (US$/bbl) (1) | 70.56 | 40.93 | 29.63 | 64.82 | 38.32 | 26.50 | ||||||||||||||||||
| MEH oil (US$/bbl) (2) | 71.64 | 41.63 | 30.01 | 66.05 | 39.19 | 26.86 | ||||||||||||||||||
| MEH oil differential to WTI (US$/bbl) | 1.08 | 0.70 | 0.38 | 1.23 | 0.87 | 0.36 | ||||||||||||||||||
| Edmonton par oil ($/bbl) (3) | 83.78 | 49.83 | 33.95 | 75.88 | 43.70 | 32.18 | ||||||||||||||||||
| Edmonton par oil differential to WTI (US$/bbl) | (4.07 | ) | (3.51 | ) | (0.56 | ) | (4.19 | ) | (6.04 | ) | 1.85 | |||||||||||||
| WCS heavy oil ($/bbl) (4) | 71.81 | 42.40 | 29.41 | 65.47 | 33.34 | 32.13 | ||||||||||||||||||
| WCS heavy oil differential to WTI (US$/bbl) | (13.57 | ) | (9.09 | ) | (4.48 | ) | (12.51 | ) | (13.70 | ) | 1.19 | |||||||||||||
| AECO natural gas price ($/mcf) (5) | 3.54 | 2.18 | 1.36 | 3.11 | 2.08 | 1.03 | ||||||||||||||||||
| NYMEX natural gas price (US$/mmbtu) (6) | 4.01 | 1.98 | 2.03 | 3.18 | 1.88 | 1.30 | ||||||||||||||||||
| CAD/USD average exchange rate | 1.2601 | 1.3316 | (0.0715 | ) | 1.2515 | 1.3541 | (0.1026 | ) |
(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.
| Three Months Ended September 30 | ||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||
| Canada | U.S. | Total | Canada | U.S. | Total | |||||||||||||||||||
| Average Realized Sales Prices | ||||||||||||||||||||||||
| Light oil and condensate ($/bbl) | $ | 82.14 | $ | 88.01 | $ | 85.29 | $ | 46.72 | $ | 51.85 | $ | 49.10 | ||||||||||||
| Heavy oil ($/bbl) (1) | 62.70 | - | 62.70 | 29.03 | - | 29.03 | ||||||||||||||||||
| NGL ($/bbl) | 36.92 | 41.94 | 41.08 | 14.95 | 15.79 | 15.65 | ||||||||||||||||||
| Natural gas ($/mcf) | 3.71 | 5.00 | 4.29 | 2.14 | 2.50 | 2.31 | ||||||||||||||||||
| Weighted average ($/boe) (1) | $ | 61.69 | $ | 67.11 | $ | 63.85 | $ | 32.76 | $ | 35.55 | $ | 33.79 |
| Nine Months Ended September 30 | ||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||
| Canada | U.S. | Total | Canada | U.S. | Total | |||||||||||||||||||
| Average Realized Sales Prices | ||||||||||||||||||||||||
| Light oil and condensate ($/bbl) | $ | 73.29 | $ | 80.98 | $ | 77.33 | $ | 41.08 | $ | 49.11 | $ | 44.97 | ||||||||||||
| Heavy oil ($/bbl) (1) | 55.34 | - | 55.34 | 23.03 | - | 23.03 | ||||||||||||||||||
| NGL ($/bbl) | 27.25 | 36.28 | 34.14 | 12.27 | 14.60 | 14.24 | ||||||||||||||||||
| Natural gas ($/mcf) | 3.26 | 5.42 | 4.20 | 2.01 | 2.50 | 2.26 | ||||||||||||||||||
| Weighted average ($/boe) (1) | $ | 54.41 | $ | 62.92 | $ | 57.69 | $ | 28.60 | $ | 34.61 | $ | 31.01 |
(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 $63.85/boe for Q3/2021 and $57.69/boe for YTD 2021 compared to $33.79/boe for Q3/2020 and $31.01/boe for YTD 2020. In Canada, our realized price of $61.69/boe for Q3/2021 was $28.93/boe higher than $32.76/boe for Q3/2020. Our realized price in the U.S. was $67.11/boe in Q3/2021 which is $31.56/boe higher than $35.55/boe in Q3/2020. The increase in our realized price in Canada and the U.S. for Q3/2021 and YTD 2021 was a result of higher North American benchmark prices relative to the same periods of 2020.
| 14 | Baytex Energy Corp. Third Quarter Report 2021 | |
Baytex Energy Corp.
Q3 2021 MD&A
We compare our light oil realized price in Canada to the Edmonton par benchmark price. Our realized light oil and condensate price was $82.14/bbl for Q3/2021 and $73.29/bbl for YTD 2021 compared to $46.72/bbl for Q3/2020 and $41.08/bbl for YTD 2020. Our realized light oil and condensate price for Q3/2021 and YTD 2021 increased with the improvement in the benchmark price and represents discounts of $1.64/bbl and $2.59/bbl, respectively, to the Edmonton par price, compared to discounts of $3.11/bbl for Q3/2020 and $2.62/bbl for YTD 2020. Our realized light oil price for both periods of 2021 represents a narrower discount to the Edmonton par price than comparative periods of 2020 and reflects strong regional pricing for our Viking light oil production relative to the Edmonton par benchmark during 2021.
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 $88.01/bbl for Q3/2021 and $80.98/bbl for YTD 2021 compared to $51.85/bbl for Q3/2020 and $49.11/ bbl for YTD 2020. Expressed in U.S. dollars, our realized light oil and condensate price of US$69.84/bbl for Q3/2021 and US$64.71/bbl for YTD 2021 represents discounts to MEH of US$1.80/bbl and US$1.34/bbl, respectively. Strong condensate pricing has resulted in improved price realizations for both periods of 2021 relative to Q3/2020 and YTD 2020 when our discount to MEH was US$2.69/bbl and US$2.92/bbl, respectively.
Our realized heavy oil price, net of blending and other expense averaged $62.70/bbl in Q3/2021 and $55.34/bbl in YTD 2021 compared to $29.03/bbl in Q3/2020 and $23.03/bbl in YTD 2020. Our realized heavy oil price for Q3/2021 and YTD 2021 was $33.67/bbl and $32.31/bbl higher relative to Q3/2020 and YTD 2020 compared to a $29.41/bbl and $32.13/bbl increase in the WCS benchmark price relative to Q3/2020. The increase in our realized heavy oil price for YTD 2021 was relatively consistent with change in WCS benchmark pricing relative to YTD 2020 while our realized heavy oil price for Q3/2021 improved more than the increase in the WCS benchmark due to reduced volumes and improved price realizations on our rail deliveries in 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 $41.08/bbl in Q3/2021 or 46% of WTI (expressed in Canadian dollars) compared to $15.65/bbl or 29% of WTI (expressed in Canadian dollars) in Q3/2020. Our realized NGL price was $34.14/bbl in YTD 2021 or 42% of WTI (expressed in Canadian dollars) compared to $14.24/bbl or 27% of WTI (expressed in Canadian dollars) in YTD 2020. Our realized NGL price was higher as a percentage of WTI in Q3/2021 and YTD 2021 relative to the same periods of 2020 due to strong global demand and lower supply of NGLs in 2021.
We compare our realized natural gas price in Canada to the AECO benchmark price. Our realized natural gas price was $3.71/mcf for Q3/2021 and $3.26/mcf for YTD 2021 compared to $2.14/mcf in Q3/2020 and $2.01/mcf for YTD 2020. These realized prices were relatively consistent with the AECO benchmark price in both periods. In the U.S., our realized natural gas price was US$3.97/ mcf for Q3/2021 and US$4.33/mcf for YTD 2021 compared to US$1.88/mcf for Q3/2020 and US$1.85/mcf for YTD 2020. A portion of our natural gas production is based on the NYMEX daily index which resulted in a US$1.15/mcf premium for our realized natural gas price when compared to the NYMEX monthly benchmark for YTD 2021 due to the fluctuations in the daily index caused by severe events which disrupted supply and caused increased demand on the U.S. Gulf coast during 2021.
| Baytex Energy Corp. Third Quarter Report 2021 | 15 | |
Baytex Energy Corp.
Q3 2021 MD&A
PETROLEUM AND NATURAL GAS SALES
| Three Months Ended September 30 | ||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||
| ($ thousands) | Canada | U.S. | Total | Canada | U.S. | Total | ||||||||||||||||||
| Oil sales | ||||||||||||||||||||||||
| Light oil and condensate | $ | 124,930 | $ | 154,511 | $ | 279,441 | $ | 78,432 | $ | 75,620 | $ | 154,052 | ||||||||||||
| Heavy oil | 146,468 | - | 146,468 | 69,791 | - | 69,791 | ||||||||||||||||||
| NGL | 4,177 | 22,932 | 27,109 | 1,762 | 8,914 | 10,676 | ||||||||||||||||||
| Total oil sales | 275,575 | 177,443 | 453,018 | 149,985 | 84,534 | 234,519 | ||||||||||||||||||
| Natural gas sales | 17,148 | 18,570 | 35,718 | 8,846 | 9,173 | 18,019 | ||||||||||||||||||
| Total petroleum and natural gas sales | 292,723 | 196,013 | 488,736 | 158,831 | 93,707 | 252,538 | ||||||||||||||||||
| Blending and other expense | (19,581 | ) | - | (19,581 | ) | (10,673 | ) | - | (10,673 | ) | ||||||||||||||
| Total sales, net of blending and other expense | $ | 273,142 | $ | 196,013 | $ | 469,155 | $ | 148,158 | $ | 93,707 | $ | 241,865 |
| Nine Months Ended September 30 | ||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||
| ($ thousands) | Canada | U.S. | Total | Canada | U.S. | Total | ||||||||||||||||||
| Oil sales | ||||||||||||||||||||||||
| Light oil and condensate | $ | 342,744 | $ | 418,498 | $ | 761,242 | $ | 229,745 | $ | 257,818 | $ | 487,563 | ||||||||||||
| Heavy oil | 385,288 | - | 385,288 | 169,638 | - | 169,638 | ||||||||||||||||||
| NGL | 12,327 | 52,870 | 65,197 | 3,957 | 25,791 | 29,748 | ||||||||||||||||||
| Total oil sales | 740,359 | 471,368 | 1,211,727 | 403,340 | 283,609 | 686,949 | ||||||||||||||||||
| Natural gas sales | 45,812 | 58,253 | 104,065 | 23,660 | 31,232 | 54,892 | ||||||||||||||||||
| Total petroleum and natural gas sales | 786,171 | 529,621 | 1,315,792 | 427,000 | 314,841 | 741,841 | ||||||||||||||||||
| Blending and other expense | (56,668 | ) | - | (56,668 | ) | (37,490 | ) | - | (37,490 | ) | ||||||||||||||
| Total sales, net of blending and other expense | $ | 729,503 | $ | 529,621 | $ | 1,259,124 | $ | 389,510 | $ | 314,841 | $ | 704,351 |
Total sales, net of blending and other expense, of $469.2 million for Q3/2021 increased $227.3 million from $241.9 million reported for Q3/2020 while total sales, net of blending and other expense, of $1,259.1 million for YTD 2021 increased $554.8 million from $704.4 million reported for YTD 2020. The increase in total sales in both periods is a result of higher realized pricing due to the increase in benchmark pricing.
In Canada, total sales, net of blending and other expense, was $273.1 million for Q3/2021 which is an increase of $125.0 million from $148.2 million reported for Q3/2020. The increase in total petroleum and natural gas sales was due to higher realized pricing for Q3/2021 relative to Q3/2020. Our increased realized price resulted in a $128.1 million increase in total sales, net of blending and other expense, while slightly lower production resulted in a $3.1 million decrease in total sales, net of blending and other expense, relative to Q3/2020. Despite lower production, the increase in benchmark prices resulted in our total sales, net of blending and other expense, increasing to $729.5 million in YTD 2021 from $389.5 million in YTD 2020.
In the U.S., petroleum and natural gas sales were $196.0 million for Q3/2021 which is an increase of $102.3 million from $93.7 million reported for Q3/2020. Total petroleum and natural gas sales increased $92.2 million due to higher realized pricing for Q3/2021 relative to Q3/2020 while higher production resulted in a $10.1 million increase in total sales, net of blending and other expense relative to Q3/2020. Higher realized pricing in YTD 2021 resulted in petroleum and natural gas sales of $529.6 million which was $214.8 million higher than $314.8 million in YTD 2020 despite lower production in YTD 2021 relative to YTD 2020.
| 16 | Baytex Energy Corp. Third Quarter Report 2021 | |
Baytex Energy Corp.
Q3 2021 MD&A
ROYALTIES
Royalties are paid to various government entities and to land and mineral rights owners. Royalties are calculated based on gross revenues or on operating netbacks less capital investment for specific heavy oil projects and are generally expressed as a percentage of total sales, net of blending and other expense. The actual royalty rates can vary for a number of reasons, including the commodity produced, royalty contract terms, commodity price level, royalty incentives and the area or jurisdiction. The following table summarizes our royalties and royalty rates for the three and nine months ended September 30, 2021 and 2020.
| Three Months Ended September 30 | ||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||
| ($ thousands except for % and per boe) | Canada | U.S. | Total | Canada | U.S. | Total | ||||||||||||||||||
| Royalties | $ | 32,679 | $ | 57,844 | $ | 90,523 | $ | 12,297 | $ | 27,755 | $ | 40,052 | ||||||||||||
| Average royalty rate (1) | 12.0 | % | 29.5 | % | 19.3 | % | 8.3 | % | 29.6 | % | 16.6 | % | ||||||||||||
| Royalties per boe | $ | 7.38 | $ | 19.80 | $ | 12.32 | $ | 2.72 | $ | 10.53 | $ | 5.59 |
| Nine Months Ended September 30 | ||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||
| ($ thousands except for % and per boe) | Canada | U.S. | Total | Canada | U.S. | Total | ||||||||||||||||||
| Royalties | $ | 83,536 | $ | 155,468 | $ | 239,004 | $ | 33,972 | $ | 91,956 | $ | 125,928 | ||||||||||||
| Average royalty rate (1) | 11.5 | % | 29.4 | % | 19.0 | % | 8.7 | % | 29.2 | % | 17.9 | % | ||||||||||||
| Royalties per boe | $ | 6.23 | $ | 18.47 | $ | 10.95 | $ | 2.49 | $ | 10.11 | $ | 5.54 |
| (1) | Average royalty rate is calculated as royalties divided by total sales, net of blending and other expense. |
Royalties for Q3/2021 were $90.5 million or 19.3% of total sales, net of blending and other expense compared to $40.1 million or 16.6% for Q3/2020. Total royalties for YTD 2021 were $239.0 million or 19.0% of total sales, net of blending and other expense, compared to $125.9 million or 17.9% for YTD 2020. Total royalty expense was higher for Q3/2021 and YTD 2021 due to higher total sales, net of blending and other expense, relative to the same periods of 2020. Our royalty rates of 19.3% for Q3/2021 and 19.0% for YTD 2021 were higher than 16.6% for Q3/2020 and 17.9% for YTD 2020 due to a higher royalty rate on our Canadian properties as a result of higher commodity prices. Our average royalty rate of 19.0% for YTD 2021 is slightly above our annual guidance range of 18.5% - 19.0% for 2021 due to higher than expected benchmark commodity prices and strong realized pricing in Canada.
Our Canadian royalty rates of 12.0% for Q3/2021 and 11.5% for YTD 2021 were higher than 8.3% for Q3/2020 and 8.7% for YTD 2020 due to higher benchmark commodity prices which resulted in a higher royalty rate on our Canadian properties in 2021 relative to 2020. In the U.S., royalties averaged 29.5% and 29.4% of total sales for Q3/2021 and YTD 2021, respectively, which is consistent with 29.6% for Q3/2020 and 29.2% for YTD 2020 as the royalty rate on our U.S. production does not vary with price but can vary across our acreage.
| Baytex Energy Corp. Third Quarter Report 2021 | 17 | |
Baytex Energy Corp.
Q3 2021 MD&A
OPERATING EXPENSE
| Three Months Ended September 30 | ||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||
| ($ thousands except for per boe) | Canada | U.S. | Total | Canada | U.S. | Total | ||||||||||||||||||
| Operating expense | $ | 63,301 | $ | 20,895 | $ | 84,196 | $ | 57,557 | $ | 15,890 | $ | 73,447 | ||||||||||||
| Operating expense per boe | $ | 14.30 | $ | 7.15 | $ | 11.46 | $ | 12.73 | $ | 6.03 | $ | 10.26 |
| Nine Months Ended September 30 | ||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||
| ($ thousands except for per boe) | Canada | U.S. | Total | Canada | U.S. | Total | ||||||||||||||||||
| Operating expense | $ | 186,455 | $ | 61,190 | $ | 247,645 | $ | 185,641 | $ | 65,956 | $ | 251,597 | ||||||||||||
| Operating expense per boe | $ | 13.91 | $ | 7.27 | $ | 11.35 | $ | 13.63 | $ | 7.25 | $ | 11.08 |
Total operating expense was $84.2 million ($11.46/boe) for Q3/2021 and $247.6 million ($11.35/boe) for YTD 2021 compared to $73.4 million ($10.26/boe) for Q3/2020 and $251.6 million ($11.08/boe) for YTD 2020. Total operating expense for Q3/2021 increased with production relative to Q3/2020 while total operating expense for YTD 2021 decreased with production relative to YTD 2020. Operating expense of $11.35/boe for YTD 2021 is consistent with expectations and is at the low end of our annual guidance range of $11.25 - $11.75/boe.
In Canada, operating expense was $63.3 million ($14.30/boe) for Q3/2021 and $186.5 million ($13.91/boe) for YTD 2021 compared to $57.6 million ($12.73/boe) for Q3/2020 and $185.6 million ($13.63/boe) for YTD 2020. Operating expense in Canada has increased for Q3/2021 and YTD 2021 relative to Q3/2020 and YTD 2021 due to an increase in per unit operating expenses as production was relatively consistent over the periods. The increase in per unit operating expense to $14.30/boe for Q3/2021 and $13.91/boe for YTD 2021 relative to $12.73/boe for Q3/2020 and $13.63/boe for YTD 2020 was primarily the result of reactivating higher cost production that was shut-in for a portion of 2020 along with an increase in fuel and electricity costs in 2021.
U.S. operating expense was $20.9 million ($7.15/boe) for Q3/2021 and $61.2 million ($7.27/boe) for YTD 2021 compared to $15.9 million ($6.03/boe) for Q3/2020 and $66.0 million ($7.25/boe) for YTD 2020. Higher operating expense in Q3/2021 is primarily a result of an increase in per unit operating expenses relative to Q3/2020 while a decrease in operating expense for YTD 2021 was a result of lower production relative to YTD 2020. Expressed in U.S. dollars, per unit operating expense was US$5.67/ boe in Q3/2021 and US$5.81/boe for YTD 2021 which was higher than US$4.53/boe for Q3/2020 and US$5.35/boe for YTD 2020 which included a $3.7 million reimbursement of prior period charges. Per unit operating expense for Q3/2021 and YTD 2021 were relatively consistent with the same periods of 2020 excluding the impact of the reimbursement of prior period charges included in the comparative periods.
TRANSPORTATION EXPENSE
Transportation expense includes the costs to move production from the field to the sales point. The largest component of transportation expense relates to the trucking of oil in Canada to pipeline and rail terminals which can vary from period to period depending on hauling distances as we seek to optimize sales prices and trucking rates.
The following table compares our transportation expense for the three and nine months ended September 30, 2021 and 2020.
| Three Months Ended September 30 | ||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||
| ($ thousands except for per boe) | Canada | U.S. | Total | Canada | U.S. | Total | ||||||||||||||||||
| Transportation expense | $ | 7,818 | $ | - | $ | 7,818 | $ | 6,372 | $ | - | $ | 6,372 | ||||||||||||
| Transportation expense per boe | $ | 1.77 | $ | - | $ | 1.06 | $ | 1.41 | $ | - | $ | 0.89 |
| Nine Months Ended September 30 | ||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||
| ($ thousands except for per boe) | Canada | U.S. | Total | Canada | U.S. | Total | ||||||||||||||||||
| Transportation expense | $ | 24,092 | $ | - | $ | 24,092 | $ | 21,745 | $ | - | $ | 21,745 | ||||||||||||
| Transportation expense per boe | $ | 1.80 | $ | - | $ | 1.10 | $ | 1.60 | $ | - | $ | 0.96 |
| 18 | Baytex Energy Corp. Third Quarter Report 2021 | |
Baytex Energy Corp.
Q3 2021 MD&A
Transportation expense was $7.8 million ($1.06/boe) for Q3/2021 and $24.1 million ($1.10/boe) for YTD 2021 compared to $6.4 million ($0.89/boe) for Q3/2020 and $21.7 million ($0.96/boe) for YTD 2020. The increase in total transportation expense in both periods of 2021 relative to 2020 is the result of a higher trucked volumes and higher per unit costs in 2021. Per unit transportation expense in Canada of $1.77/boe for Q3/2021 and $1.80/boe for YTD 2021 is higher than $1.41/boe for Q3/2020 and $1.60/boe for YTD 2020 which is a result of increased trucking distances in 2021 relative to 2020. Per unit transportation expense of $1.10/boe for YTD 2021 is consistent with expectations and was slightly below our revised annual guidance of $1.10 - $1.15/ 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 $19.6 million for Q3/2021 and $56.7 million for YTD 2021 compared to $10.7 million for Q3/2020 and $37.5 million for YTD 2020. Higher blending and other expense reflects an increase in the price of condensate purchased as diluent in 2021 relative to 2020.
FINANCIAL DERIVATIVES
As part of our normal operations, we are exposed to movements in commodity prices, foreign exchange rates, interest rates and changes in our share price. In an effort to manage these exposures, we utilize various financial derivative contracts which are intended to partially reduce the volatility in our adjusted funds flow. Contracts settled in the period result in realized gains or losses based on the market price compared to the contract price and the notional volume outstanding. Changes in the fair value of unsettled contracts are reported as unrealized gains or losses in the period as the forward markets for commodities and currencies fluctuate and as new contracts are executed. The following table summarizes the results of our financial derivative contracts for the three and nine months ended September 30, 2021 and 2020.
| Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||||||||||
| ($ thousands) | 2021 | 2020 | Change | 2021 | 2020 | Change | ||||||||||||||||||
| Realized financial derivatives gain (loss) | ||||||||||||||||||||||||
| Crude oil | $ | (50,384 | ) | $ | (9,530 | ) | $ | (40,854 | ) | $ | (108,658 | ) | $ | 30,640 | $ | (139,298 | ) | |||||||
| Natural gas | (3,521 | ) | 165 | (3,686 | ) | (5,039 | ) | 753 | (5,792 | ) | ||||||||||||||
| Interest and financing | - | (378 | ) | 378 | - | (662 | ) | 662 | ||||||||||||||||
| Total | $ | (53,905 | ) | $ | (9,743 | ) | $ | (44,162 | ) | $ | (113,697 | ) | $ | 30,731 | $ | (144,428 | ) | |||||||
| Unrealized financial derivatives gain (loss) | ||||||||||||||||||||||||
| Crude oil | $ | 1,520 | $ | (717 | ) | $ | 2,237 | $ | (165,019 | ) | $ | 27,155 | $ | (192,174 | ) | |||||||||
| Natural gas | (13,190 | ) | (6,885 | ) | (6,305 | ) | (22,475 | ) | (5,826 | ) | (16,649 | ) | ||||||||||||
| Interest and financing | - | 372 | (372 | ) | - | (101 | ) | 101 | ||||||||||||||||
| Equity total return swap ("Equity TRS") | 2,729 | (54 | ) | 2,783 | 8,086 | (1,803 | ) | 9,889 | ||||||||||||||||
| Total | $ | (8,941 | ) | $ | (7,284 | ) | $ | (1,657 | ) | $ | (179,408 | ) | $ | 19,425 | $ | (198,833 | ) | |||||||
| Total financial derivatives gain (loss) | ||||||||||||||||||||||||
| Crude oil | $ | (48,864 | ) | $ | (10,247 | ) | $ | (38,617 | ) | $ | (273,677 | ) | $ | 57,795 | $ | (331,472 | ) | |||||||
| Natural gas | (16,711 | ) | (6,720 | ) | (9,991 | ) | (27,514 | ) | (5,073 | ) | (22,441 | ) | ||||||||||||
| Interest and financing | - | (6 | ) | 6 | - | (763 | ) | 763 | ||||||||||||||||
| Equity TRS | 2,729 | (54 | ) | 2,783 | 8,086 | (1,803 | ) | 9,889 | ||||||||||||||||
| Total | $ | (62,846 | ) | $ | (17,027 | ) | $ | (45,819 | ) | $ | (293,105 | ) | $ | 50,156 | $ | (343,261 | ) |
We recorded total financial derivative losses of $62.8 million for Q3/2021 and $293.1 million for YTD 2021 compared to a loss of $17.0 million for Q3/2020 and a gain of $50.2 million for YTD 2020. Realized financial derivatives losses of $53.9 million for Q3/2021 and $113.7 million for YTD 2021 were primarily a result of the market prices for crude oil settling at levels above those set in our derivative contracts. Unrealized losses of $179.4 million for YTD 2021 were primarily a result of the increase in forecasted crude oil pricing used to revalue our crude oil contracts in place at September 30, 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 $201.1 million at September 30, 2021 compared to a net liability of $21.7 million at December 31, 2020.
| Baytex Energy Corp. Third Quarter Report 2021 | 19 | |
Baytex Energy Corp.
Q3 2021 MD&A
We had the following commodity financial derivative contracts as at November 4, 2021.
| Period | Volume | Price/Unit (1) | Index | |||||||||
| Oil | ||||||||||||
| Basis Swap | Oct 2021 to Dec 2021 | 8,000 bbl/d | WTI less US$13.41/bbl | WCS | ||||||||
| Basis Swap | Jan 2022 to Dec 2022 | 12,000 bbl/d | WTI less US$12.40/bbl | WCS | ||||||||
| Basis Swap | Oct 2021 to Dec 2021 | 7,500 bbl/d | WTI less US$5.03/bbl | MSW | ||||||||
| Basis Swap | Jan 2022 to Dec 2022 | 4,000 bbl/d | WTI less US$4.43/bbl | MSW | ||||||||
| Fixed Sell | Oct 2021 to Dec 2021 | 4,000 bbl/d | US$45.00/bbl | WTI | ||||||||
| 3-way option (2) | Oct 2021 to Dec 2021 | 500 bbl/d | US$35.00/US$45.00/US$49.03 | WTI | ||||||||
| 3-way option (2) | Oct 2021 to Dec 2021 | 1,500 bbl/d | US$35.00/US$45.00/US$49.10 | WTI | ||||||||
| 3-way option (2) | Oct 2021 to Dec 2021 | 3,500 bbl/d | US$35.00/US$45.00/US$49.50 | WTI | ||||||||
| 3-way option (2) | Oct 2021 to Dec 2021 | 10,000 bbl/d | US$35.00/US$45.00/US$55.00 | WTI | ||||||||
| 3-way option (2) | Oct 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) | Jan 2022 to Dec 2022 | 2,500 bbl/d | US$47.00/US$57.00/US$67.00 | WTI | ||||||||
| 3-way option (2) | Jan 2022 to Dec 2022 | 2,500 bbl/d | US$50.00/US$60.00/US$70.00 | WTI | ||||||||
| 3-way option (2) | Jan 2022 to Dec 2022 | 2,000 bbl/d | US$53.00/US$63.50/US$72.90 | WTI | ||||||||
| 3-way option (2)(4) | Jan 2023 to Dec 2023 | 2,000 bbl/d | US$55.00/US$66.00/US$84.00 | 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 | Oct 2021 to Dec 2021 | 16,000 GJ/d | $2.36/GJ | AECO 7A | ||||||||
| Fixed Sell | Jan 2022 to Dec 2022 | 5,000 GJ/d | $2.53/GJ | AECO 7A | ||||||||
| Fixed Sell | Oct 2021 to Dec 2021 | 2,500 GJ/d | $2.40/GJ | AECO 5A | ||||||||
| Fixed Sell | Jan 2022 to Dec 2022 | 14,250 GJ/d | $2.84/GJ | AECO 5A | ||||||||
| Fixed Sell | Oct 2021 to Dec 2021 | 12,000 mmbtu/d | US$2.70/mmbtu | NYMEX | ||||||||
| Fixed Sell | Jan 2022 to Dec 2022 | 1,000 mmbtu/d | US$2.94/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 | 1,500 mmbtu/d | US$2.60/US$2.91/US$3.56 | NYMEX | ||||||||
| 3-way option (2) | Jan 2022 to Dec 2022 | 2,500 mmbtu/d | US$2.60/US$3.00/US$3.83 | NYMEX | ||||||||
| 3-way option (2) | Jan 2022 to Dec 2022 | 2,500 mmbtu/d | US$2.65/US$2.90/US$3.40 | NYMEX | ||||||||
| 3-way option (2) | Jan 2022 to Dec 2022 | 2,500 mmbtu/d | US$3.00/US$3.75/US$4.40 | 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$50.00/US$60.00/US$70.00 contract, Baytex receives WTI plus US$10.00/bbl when WTI is at or below US$50.00/bbl; Baytex receives US$60.00/bbl when WTI is between US$50.00/bbl and US$60.00/bbl; Baytex receives the market price when WTI is between US$60.00/bbl and US$70.00/bbl; and Baytex receives US$70.00/ bbl when WTI is above US$70.00/bbl. |
| (3) | For these contracts, the counterparty has the right, if exercised on December 31, 2021, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above. |
| (4) | Contracts entered subsequent to September 30, 2021. |
| 20 | Baytex Energy Corp. Third Quarter Report 2021 | |
Baytex Energy Corp.
Q3 2021 MD&A
OPERATING NETBACK
The following table summarizes our operating netback on a per boe basis for our Canadian and U.S. operations for the three and nine months ended September 30, 2021 and 2020.
| Three Months Ended September 30 | ||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||
| ($ per boe except for volume) | Canada | U.S. | Total | Canada | U.S. | Total | ||||||||||||||||||
| Total production (boe/d) | 48,124 | 31,748 | 79,872 | 49,164 | 28,650 | 77,814 | ||||||||||||||||||
| Operating netback: | ||||||||||||||||||||||||
| Total sales, net of blending and other expense | $ | 61.69 | $ | 67.11 | $ | 63.85 | $ | 32.76 | $ | 35.55 | $ | 33.79 | ||||||||||||
| Less: | ||||||||||||||||||||||||
| Royalties | (7.38 | ) | (19.80 | ) | (12.32 | ) | (2.72 | ) | (10.53 | ) | (5.59 | ) | ||||||||||||
| Operating expense | (14.30 | ) | (7.15 | ) | (11.46 | ) | (12.73 | ) | (6.03 | ) | (10.26 | ) | ||||||||||||
| Transportation expense | (1.77 | ) | - | (1.06 | ) | (1.41 | ) | - | (0.89 | ) | ||||||||||||||
| Operating netback | $ | 38.24 | $ | 40.16 | $ | 39.01 | $ | 15.90 | $ | 18.99 | $ | 17.05 | ||||||||||||
| Realized financial derivatives (loss) gain | - | - | (7.34 | ) | - | - | (1.36 | ) | ||||||||||||||||
| Operating netback after financial derivatives | $ | 38.24 | $ | 40.16 | $ | 31.67 | $ | 15.90 | $ | 18.99 | $ | 15.69 |
| Nine Months Ended September 30 | ||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||
| ($ per boe except for volume) | Canada | U.S. | Total | Canada | U.S. | Total | ||||||||||||||||||
| Total production (boe/d) | 49,108 | 30,834 | 79,942 | 49,704 | 33,203 | 82,907 | ||||||||||||||||||
| Operating netback: | ||||||||||||||||||||||||
| Total sales, net of blending and other expense | $ | 54.41 | $ | 62.92 | $ | 57.69 | $ | 28.60 | $ | 34.61 | $ | 31.01 | ||||||||||||
| Less: | ||||||||||||||||||||||||
| Royalties | (6.23 | ) | (18.47 | ) | (10.95 | ) | (2.49 | ) | (10.11 | ) | (5.54 | ) | ||||||||||||
| Operating expense | (13.91 | ) | (7.27 | ) | (11.35 | ) | (13.63 | ) | (7.25 | ) | (11.08 | ) | ||||||||||||
| Transportation expense | (1.80 | ) | - | (1.10 | ) | (1.60 | ) | - | (0.96 | ) | ||||||||||||||
| Operating netback | $ | 32.47 | $ | 37.18 | $ | 34.29 | $ | 10.88 | $ | 17.25 | $ | 13.43 | ||||||||||||
| Realized financial derivatives (loss) gain | - | - | (5.21 | ) | - | - | 1.35 | |||||||||||||||||
| Operating netback after financial derivatives | $ | 32.47 | $ | 37.18 | $ | 29.08 | $ | 10.88 | $ | 17.25 | $ | 14.78 |
Our operating netback of $39.01/boe for Q3/2021 and $34.29/boe for YTD 2021 was higher than $17.05/boe for Q3/2020 and $13.43/boe for YTD 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 $12.52/boe for Q3/2021 and $12.45/boe for YTD 2021 was slightly higher than $11.15/boe for Q3/2020 and $12.04/boe for YTD 2020. Including realized gains and losses on financial derivatives our operating netback was $31.67/boe for Q3/2021 and $29.08/boe for YTD 2021 compared to $15.69/boe for Q3/2020 and $14.78/ boe for YTD 2020.
GENERAL AND ADMINISTRATIVE EXPENSE
General and administrative ("G&A") expense includes head office and corporate costs such as salaries and employee benefits, public company costs and administrative recoveries earned for operating exploration and development activities on behalf of our working interest partners. G&A expense fluctuates with head office staffing levels and the level of operated exploration and development activity during the period.
| Baytex Energy Corp. Third Quarter Report 2021 | 21 | |
Baytex Energy Corp.
Q3 2021 MD&A
The following table summarizes our G&A expense for the three and nine months ended September 30, 2021 and 2020.
| Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||||||||||
| ($ thousands except for per boe) | 2021 | 2020 | Change | 2021 | 2020 | Change | ||||||||||||||||||
| Gross general and administrative expense | $ | 11,251 | $ | 7,790 | $ | 3,461 | $ | 31,871 | $ | 27,153 | $ | 4,718 | ||||||||||||
| Overhead recoveries | (1,271 | ) | (49 | ) | (1,222 | ) | (2,548 | ) | (2,199 | ) | (349 | ) | ||||||||||||
| General and administrative expense | $ | 9,980 | $ | 7,741 | $ | 2,239 | $ | 29,323 | $ | 24,954 | $ | 4,369 | ||||||||||||
| General and administrative expense per boe | $ | 1.36 | $ | 1.08 | $ | 0.28 | $ | 1.34 | $ | 1.10 | $ | 0.24 |
G&A expense was $10.0 million ($1.36/boe) for Q3/2021 and $29.3 million ($1.34/boe) for YTD 2021 compared to $7.7 million ($1.08/boe) for Q3/2020 and $25.0 million ($1.10/boe) for YTD 2020. G&A expense for Q3/2021 and YTD 2021 was higher relative to the same periods of 2020 as employee and director compensation was reduced from Q2/2020 to Q4/2020 and the Company received benefits under the Canadian Emergency Wage Subsidy program in 2020.
G&A expense of $1.34/boe for YTD 2021 is consistent with expectations and is slightly below our revised annual guidance of $1.44/boe for 2021.
FINANCING AND INTEREST EXPENSE
Financing and interest expense includes interest on our credit facilities, long-term notes and lease obligations as well as non-cash financing costs which include the accretion on our debt issue costs and asset retirement obligations. Financing and interest expense varies depending on debt levels outstanding during the period, the applicable borrowing rates, CAD/USD foreign exchange rates, along with the carrying amount of asset retirement obligations and the discount rates used to present value these obligations.
The following table summarizes our financing and interest expense for the three and nine months ended September 30, 2021 and 2020.
| Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||||||||||
| ($ thousands except for per boe) | 2021 | 2020 | Change | 2021 | 2020 | Change | ||||||||||||||||||
| Interest on credit facilities | $ | 3,256 | $ | 3,366 | $ | (110 | ) | $ | 9,842 | $ | 11,749 | $ | (1,907 | ) | ||||||||||
| Interest on long-term notes | 19,481 | 21,943 | (2,462 | ) | 60,734 | 69,231 | (8,497 | ) | ||||||||||||||||
| Interest on lease obligations | 56 | 109 | (53 | ) | $ | 174 | $ | 360 | (186 | ) | ||||||||||||||
| Cash interest | $ | 22,793 | $ | 25,418 | $ | (2,625 | ) | $ | 70,750 | $ | 81,340 | $ | (10,590 | ) | ||||||||||
| Accretion of debt issue costs | 1,733 | 756 | 977 | 3,272 | 5,863 | (2,591 | ) | |||||||||||||||||
| Accretion of asset retirement obligations | 3,273 | 1,788 | 1,485 | 8,938 | 6,897 | 2,041 | ||||||||||||||||||
| Early redemption expense | 1,229 | - | 1,229 | 872 | 3,312 | (2,440 | ) | |||||||||||||||||
| Financing and interest expense | $ | 29,028 | $ | 27,962 | $ | 1,066 | $ | 83,832 | $ | 97,412 | $ | (13,580 | ) | |||||||||||
| Cash interest per boe | $ | 3.10 | $ | 3.55 | $ | (0.45 | ) | $ | 3.24 | $ | 3.58 | $ | (0.34 | ) | ||||||||||
| Financing and interest expense per boe | $ | 3.95 | $ | 3.91 | $ | 0.04 | $ | 3.84 | $ | 4.29 | $ | (0.45 | ) |
Financing and interest expense was $29.0 million ($3.95/boe) for Q3/2021 and $83.8 million ($3.84/boe) for YTD 2021 compared to $28.0 million ($3.91/boe) for Q3/2020 and $97.4 million ($4.29/boe) for YTD 2020.
Cash interest of $22.8 million ($3.10/boe) for Q3/2021 and $70.8 million ($3.24/boe) for YTD 2021 is lower than $25.4 million ($3.55/boe) for Q3/2020 and $81.3 million ($3.58/boe) for YTD 2020 as we had less debt outstanding during 2021. The interest on our U.S. dollar denominated long-term notes was lower as the average principal amount outstanding was lower during YTD 2021 due to the repurchase and redemption of US$115.5 million of long-term notes in YTD 2021. Interest on our credit facilities was lower in Q3/2021 and YTD 2021 compared to the same periods of 2020 due to lower borrowings on our credit facilities and lower effective interest. The weighted average interest rate applicable to our credit facilities was 2.2% YTD 2021 compared to 2.5% for YTD 2020.
Financing and interest expense for YTD 2021 was lower than YTD 2020 which included the accelerated amortization of debt issue costs and $3.3 million of early redemption expense associated with the redemption of notes in Q1/2020.
Cash interest expense of $70.8 million ($3.24/boe) for YTD 2021 is consistent with our revised annual guidance of $92 million ($3.16/boe) for 2021 given we expect interest expense to be lower for the remainder of 2021 due to the additional redemption of the 5.625% Notes on October 29, 2021.
| 22 | Baytex Energy Corp. Third Quarter Report 2021 | |
Baytex Energy Corp.
Q3 2021 MD&A
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 $6.8 million for Q3/2021 and $10.7 million for YTD 2021 which is lower than $8.9 million for Q3/2020 and $11.0 million for YTD 2020 as less acreage expired in both periods of 2021 relative to 2020.
DEPLETION AND DEPRECIATION
Depletion and depreciation expense varies with the carrying amount of the Company's oil and gas properties, the amount of proved plus probable reserves volumes and the rate of production for the period. The following table summarizes depletion and depreciation expense for the three and nine months ended September 30, 2021 and 2020.
| Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||||||||||
| ($ thousands except for per boe) | 2021 | 2020 | Change | 2021 | 2020 | Change | ||||||||||||||||||
| Depletion | $ | 125,681 | $ | 104,547 | $ | 21,134 | $ | 328,171 | $ | 386,587 | $ | (58,416 | ) | |||||||||||
| Depreciation | 1,371 | 1,907 | (536 | ) | 3,948 | 5,793 | (1,845 | ) | ||||||||||||||||
| Depletion and depreciation | $ | 127,052 | $ | 106,454 | $ | 20,598 | $ | 332,119 | $ | 392,380 | $ | (60,261 | ) | |||||||||||
| Depletion and depreciation per boe | $ | 17.29 | $ | 14.87 | $ | 2.42 | $ | 15.22 | $ | 17.27 | $ | (2.05 | ) |
Depletion and depreciation expense was $127.1 million ($17.29/boe) for Q3/2021 and $332.1 million ($15.22/boe) for YTD 2021 compared to $106.5 million ($14.87/boe) for Q3/2020 and $392.4 million ($17.27/boe) for YTD 2020. Total depletion and depreciation expense as well as the depletion rate per boe were higher in Q3/2021 relative to Q3/2020 as a result of a $1.1 billion impairment reversal recorded at Q2/2021 which increased the depletable base of our U.S and Canadian assets.
Total depletion and depreciation expense and the depletion rate per boe were lower in YTD 2021 compared to YTD 2020 as we recorded a $2.2 billion impairment loss to our oil and gas properties at Q1/2020 which reduced the depletable base of our oil and gas properties for YTD 2021 despite the $1.1 billion impairment reversal recorded at the end of Q2/2021.
IMPAIRMENT
We did not identify indicators of impairment or impairment reversal for any of our cash generating units ("CGU") at September 30, 2021.
2021 Impairment Reversal
At June 30, 2021, we identified indicators of impairment reversal for oil and gas properties in each of our six CGU's due to the increase in forecasted commodity prices. We recorded an impairment reversal of $1.1 billion as the estimated recoverable amount of all six CGUs exceeded their carrying value. No indicators of impairment or impairment reversal were identified for the Company's E&E assets at June 30, 2021.
At June 30, 2021, the recoverable amount of the Company's CGUs were calculated using the following benchmark reference prices for the years 2021 to 2030 adjusted for commodity differentials specific to the Company. The prices and costs subsequent to 2030 have been adjusted for inflation at an annual rate of 2.0%.
| 2021 | 2022 | 2023 | 2024 | 2025 | 2026 | 2027 | 2028 | 2029 | 2030 | |||||||||||
| WTI crude oil (US$/bbl) | 71.33 | 67.20 | 63.95 | 63.23 | 64.50 | 65.79 | 67.10 | 68.44 | 69.81 | 71.21 | ||||||||||
| WCS heavy oil (CA$/bbl) | 72.22 | 66.84 | 61.73 | 60.70 | 61.91 | 63.15 | 64.42 | 65.70 | 67.02 | 68.36 | ||||||||||
| LLS crude oil (US$/bbl) | 72.17 | 68.53 | 65.80 | 65.10 | 66.39 | 67.71 | 69.05 | 70.42 | 71.82 | 73.26 | ||||||||||
| Edmonton par oil (CA$/bbl) | 83.20 | 78.27 | 74.06 | 73.05 | 74.51 | 76.00 | 77.52 | 79.07 | 80.66 | 82.27 | ||||||||||
| Henry Hub gas (US$/mmbtu) | 3.42 | 3.19 | 2.92 | 2.96 | 3.02 | 3.08 | 3.14 | 3.21 | 3.27 | 3.34 | ||||||||||
| AECO gas (CA$/mmbtu) | 3.46 | 3.13 | 2.72 | 2.71 | 2.76 | 2.82 | 2.88 | 2.94 | 2.99 | 3.05 | ||||||||||
| Exchange rate (CAD/USD) | 1.24 | 1.25 | 1.25 | 1.25 | 1.25 | 1.25 | 1.25 | 1.25 | 1.25 | 1.25 |
| Baytex Energy Corp. Third Quarter Report 2021 | 23 | |
Baytex Energy Corp.
Q3 2021 MD&A
The following table summarizes the recoverable amount and impairment reversal at June 30, 2021 and demonstrates the sensitivity of the estimated recoverable amount of the Company's CGUs comprising oil and gas properties to reasonably possible changes in key assumptions inherent in the estimate.
| Recoverable | Impairment | Change in discount | Change in oil price | Change in gas | ||||||||||||||||
| amount | reversal | rate of 1% | of $2.50/bbl | price of $0.25/mcf | ||||||||||||||||
| Conventional CGU | $ | 57,891 | $ | 15,000 | $ | 1,000 | $ | 1,000 | $ | 8,000 | ||||||||||
| Peace River CGU | 238,714 | 154,000 | 4,000 | 40,000 | 2,500 | |||||||||||||||
| Lloydminster CGU | 340,730 | 154,000 | 12,500 | 52,000 | - | |||||||||||||||
| Duvernay CGU (1) | 115,157 | 5,000 | 45,000 | 44,500 | 44,500 | |||||||||||||||
| Viking CGU | 1,338,985 | 356,000 | 47,000 | 89,500 | 4,500 | |||||||||||||||
| Eagle Ford CGU | 2,015,118 | 442,415 | 109,400 | 103,900 | 24,400 | |||||||||||||||
| $ | 4,106,595 | $ | 1,126,415 | $ | 218,900 | $ | 330,900 | $ | 83,900 |
(1) The impairment reversal for the Duvernay CGU was limited to total accumulated impairments less subsequent depletion of $5.0 million.
2020 Impairments
We recorded total net impairments of $2.4 billion for the year ended December 31, 2020 due to significant changes in forecasted commodity prices caused by the COVID-19 pandemic.
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 an impairment loss 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 loss 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.
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 $2.5 million for Q3/2021 and $8.3 million for YTD 2021 which is consistent with $2.9 million for Q3/2020 and $8.7 million for YTD 2020. The total expense for YTD 2021 was $8.3 million as compared to $8.7 million for YTD 2020 and is comprised of non-cash compensation expense of $4.6 million related to the Share Award Incentive Plan and cash compensation expense of $3.7 million related to the Incentive Award Plan and the Deferred Share Unit Plan.
FOREIGN EXCHANGE
Unrealized foreign exchange gains and losses are primarily a result of changes in the reported amount of our U.S. dollar denominated long-term notes and our U.S. dollar denominated intercompany notes issued in 2020. The long-term notes and intercompany notes are translated to Canadian dollars on the balance sheet date using the closing CAD/USD exchange rate resulting in unrealized gains and losses. Realized foreign exchange gains and losses are due to day-to-day U.S. dollar denominated transactions occurring in our Canadian functional currency entities.
| 24 | Baytex Energy Corp. Third Quarter Report 2021 | |
Baytex Energy Corp.
Q3 2021 MD&A
| Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||||||||||
| ($ thousands except for exchange rates) | 2021 | 2020 | Change | 2021 | 2020 | Change | ||||||||||||||||||
| Unrealized foreign exchange loss (gain) | $ | 7,545 | $ | (25,880 | ) | $ | 33,425 | $ | 3,223 | $ | 28,125 | $ | (24,902 | ) | ||||||||||
| Realized foreign exchange gain | (79 | ) | (351 | ) | 272 | (818 | ) | (437 | ) | (381 | ) | |||||||||||||
| Foreign exchange loss (gain) | $ | 7,466 | $ | (26,231 | ) | $ | 33,697 | $ | 2,405 | $ | 27,688 | $ | (25,283 | ) | ||||||||||
| CAD/USD exchange rates: | ||||||||||||||||||||||||
| At beginning of period | 1.2405 | 1.3616 | 1.2755 | 1.2965 | ||||||||||||||||||||
| At end of period | 1.2750 | 1.3324 | 1.2750 | 1.3324 |
We recorded foreign exchange losses of $7.5 million for Q3/2021 and $2.4 million for YTD 2021 compared to a gain of $26.2 million for Q3/2020 and a loss of $27.7 million for YTD 2020.
We recorded unrealized foreign exchange losses on our long-term notes, intercompany notes and credit facilities of $7.5 million for Q3/2021 and $3.2 million for YTD 2021 due to changes in the value of the Canadian dollar relative to the U.S. dollar at September 30, 2021 compared to June 30, 2021 and December 31, 2020, respectively. In 2020 unrealized foreign exchange gains and losses relate to changes in our long-term notes and the exchange rates at the end of the period.
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 realized foreign exchange gains of $0.1 million for Q3/2021 and $0.8 million for YTD 2021 compared to $0.4 million for both Q3/2020 and YTD 2020.
INCOME TAXES
| Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||||||||||
| ($ thousands) | 2021 | 2020 | Change | 2021 | 2020 | Change | ||||||||||||||||||
| Current income tax expense | $ | 486 | $ | 322 | $ | 164 | $ | 894 | $ | 880 | $ | 14 | ||||||||||||
| Deferred income tax expense (recovery) | 10,248 | 696 | 9,552 | 71,963 | (261,481 | ) | 333,444 | |||||||||||||||||
| Total income tax expense (recovery) | $ | 10,734 | $ | 1,018 | $ | 9,716 | $ | 72,857 | $ | (260,601 | ) | $ | 333,458 |
Current income tax expense was $0.5 million for Q3/2021 and $0.9 million for YTD 2021 compared to $0.3 million for Q3/2020 and $0.9 million for YTD 2020.
We recorded deferred tax expense of $10.2 million for Q3/2021 and $72.0 million for YTD 2021 compared to an expense of $0.7 million for Q3/2020 and a recovery of $261.5 million for YTD 2020. The deferred tax expense recorded in YTD 2021 is primarily related to the impairment reversal recorded in YTD 2021 whereas the deferred tax recovery recorded in YTD 2020 is primarily related to the impairment loss recorded in YTD 2020.
As disclosed in the 2020 annual financial statements, certain indirect subsidiaries received reassessments from the Canada Revenue Agency (the "CRA") that deny $591.0 million of non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2015. In September 2016, we filed notices of objection with the CRA appealing each reassessment received. There has been no change in the status of these reassessments since an Appeals Officer was assigned to our file in July 2018. We remain confident that our original tax filings are correct and intend to defend these tax filings through the appeals process.
| Baytex Energy Corp. Third Quarter Report 2021 | 25 | |
Baytex Energy Corp.
Q3 2021 MD&A
NET INCOME (LOSS) AND ADJUSTED FUNDS FLOW
The components of adjusted funds flow and net income or loss for the three and nine months ended September 30, 2021 and 2020 are set forth in the following table.
| Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||||||||||
| ($ thousands) | 2021 | 2020 | Change | 2021 | 2020 | Change | ||||||||||||||||||
| Petroleum and natural gas sales | $ | 488,736 | $ | 252,538 | $ | 236,198 | $ | 1,315,792 | $ | 741,841 | $ | 573,951 | ||||||||||||
| Royalties | (90,523 | ) | (40,052 | ) | (50,471 | ) | (239,004 | ) | (125,928 | ) | (113,076 | ) | ||||||||||||
| Revenue, net of royalties | 398,213 | 212,486 | 185,727 | 1,076,788 | 615,913 | 460,875 | ||||||||||||||||||
| Expenses | ||||||||||||||||||||||||
| Operating | (84,196 | ) | (73,447 | ) | (10,749 | ) | (247,645 | ) | (251,597 | ) | 3,952 | |||||||||||||
| Transportation | (7,818 | ) | (6,372 | ) | (1,446 | ) | (24,092 | ) | (21,745 | ) | (2,347 | ) | ||||||||||||
| Blending and other | (19,581 | ) | (10,673 | ) | (8,908 | ) | (56,668 | ) | (37,490 | ) | (19,178 | ) | ||||||||||||
| Operating netback | $ | 286,618 | $ | 121,994 | $ | 164,624 | $ | 748,383 | $ | 305,081 | $ | 443,302 | ||||||||||||
| General and administrative | (9,980 | ) | (7,741 | ) | (2,239 | ) | (29,323 | ) | (24,954 | ) | (4,369 | ) | ||||||||||||
| Cash financing and interest | (22,793 | ) | (25,418 | ) | 2,625 | (70,750 | ) | (81,340 | ) | 10,590 | ||||||||||||||
| Realized financial derivatives (loss) gain | (53,905 | ) | (9,743 | ) | (44,162 | ) | (113,697 | ) | 30,731 | (144,428 | ) | |||||||||||||
| Realized foreign exchange gain | 79 | 351 | (272 | ) | 818 | 437 | 381 | |||||||||||||||||
| Other income (expense) | (78 | ) | - | (78 | ) | (16 | ) | 2,007 | (2,023 | ) | ||||||||||||||
| Current income tax expense | (486 | ) | (322 | ) | (164 | ) | (894 | ) | (880 | ) | (14 | ) | ||||||||||||
| Cash share-based compensation | (1,058 | ) | (613 | ) | (445 | ) | (3,659 | ) | (1,752 | ) | (1,907 | ) | ||||||||||||
| Adjusted funds flow | $ | 198,397 | $ | 78,508 | $ | 119,889 | $ | 530,862 | $ | 229,330 | $ | 301,532 | ||||||||||||
| Exploration and evaluation | (6,766 | ) | (8,909 | ) | 2,143 | (10,718 | ) | (11,000 | ) | 282 | ||||||||||||||
| Depletion and depreciation | (127,052 | ) | (106,454 | ) | (20,598 | ) | (332,119 | ) | (392,380 | ) | 60,261 | |||||||||||||
| Non-cash share-based compensation | (1,453 | ) | (2,336 | ) | 883 | (4,603 | ) | (6,973 | ) | 2,370 | ||||||||||||||
| Non-cash financing and accretion | (6,235 | ) | (2,544 | ) | (3,691 | ) | (13,082 | ) | (16,072 | ) | 2,990 | |||||||||||||
| Non-cash other income | 444 | 293 | 151 | 2,108 | 293 | 1,815 | ||||||||||||||||||
| Unrealized financial derivatives (loss) gain | (8,941 | ) | (7,284 | ) | (1,657 | ) | (179,408 | ) | 19,425 | (198,833 | ) | |||||||||||||
| Unrealized foreign exchange gain (loss) | (7,545 | ) | 25,880 | (33,425 | ) | (3,223 | ) | (28,125 | ) | 24,902 | ||||||||||||||
| Gain on dispositions | 2,112 | 98 | 2,014 | 6,092 | 246 | 5,846 | ||||||||||||||||||
| Impairment | - | - | - | 1,126,415 | (2,716,349 | ) | 3,842,764 | |||||||||||||||||
| Deferred income tax (expense) recovery | (10,248 | ) | (696 | ) | (9,552 | ) | (71,963 | ) | 261,481 | (333,444 | ) | |||||||||||||
| Net income (loss) for the period | $ | 32,713 | $ | (23,444 | ) | $ | 56,157 | $ | 1,050,361 | $ | (2,660,124 | ) | $ | 3,710,485 |
We generated adjusted funds flow of $198.4 million for Q3/2021 and $530.9 million for YTD 2021 compared to $78.5 million for Q3/2020 and $229.3 million for YTD 2020. The increase in adjusted funds flow for both periods of 2021 was primarily due to higher operating netback which increased $164.6 million from Q3/2020 and $443.3 million from YTD 2020 as a result of higher commodity prices which increased revenue, net of royalties. The increase in operating netback was partially offset by realized losses on financial derivatives of $53.9 million for Q3/2021 and $113.7 million for YTD 2021 due to the increase in oil and natural gas benchmark prices relative to Q3/2020 and YTD 2020 when we recorded a realized loss on financial derivatives of $9.7 million and a realized gain of $30.7 million, respectively.
We reported net income of $32.7 million for Q3/2021 and $1.05 billion for YTD 2021 compared to a net loss of $23.4 million reported for Q3/2020 and a net loss of $2.66 billion for YTD 2020. Net income generated for YTD 2021 is the result of an impairment reversal of $1.13 billion recorded in Q2/2021 compared to YTD 2020 when we recorded an impairment loss of $2.72 billion.
| 26 | Baytex Energy Corp. Third Quarter Report 2021 | |
Baytex Energy Corp.
Q3 2021 MD&A
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 foreign currency translation gain of $26.2 million for Q3/2021 and $19.0 million for YTD 2021 relates to the change in value of our U.S. net assets and intercompany notes which are expressed in Canadian dollars and are influenced by changes in the value of the Canadian dollar relative to the U.S. dollar at September 30, 2021 compared to June 30, 2021 and December 31, 2020. The CAD/USD exchange rate was 1.2750 CAD/USD as at September 30, 2021 compared to 1.2405 CAD/USD at June 30, 2021 and 1.2755 CAD/USD at December 31, 2020. Impairment reversals of US$362 million at Q2/2021 increased the value of our U.S. net assets which further contributed to the foreign currency translation gain for YTD 2021.
CAPITAL EXPENDITURES
Capital expenditures for the three and nine months ended September 30, 2021 and 2020 are summarized as follows.
| Three Months Ended September 30 | ||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||
| ($ thousands) | Canada | U.S. | Total | Canada | U.S. | Total | ||||||||||||||||||
| Drilling, completion and equipping | $ | 67,177 | $ | 18,460 | $ | 85,637 | $ | - | $ | 12,020 | $ | 12,020 | ||||||||||||
| Facilities | 5,364 | 11 | 5,375 | 2,056 | - | 2,056 | ||||||||||||||||||
| Land, seismic and other | 2,958 | 265 | 3,223 | 1,826 | - | 1,826 | ||||||||||||||||||
| Total exploration and development | $ | 75,499 | $ | 18,736 | $ | 94,235 | $ | 3,882 | $ | 12,020 | $ | 15,902 | ||||||||||||
| Total acquisitions, net of proceeds from divestitures | $ | (19 | ) | $ | (593 | ) | $ | (612 | ) | $ | (98 | ) | $ | - | $ | (98 | ) |
| Nine Months Ended September 30 | ||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||
| ($ thousands) | Canada | U.S. | Total | Canada | U.S. | Total | ||||||||||||||||||
| Drilling, completion and equipping | $ | 129,230 | $ | 90,092 | $ | 219,322 | $ | 99,545 | $ | 71,859 | $ | 171,404 | ||||||||||||
| Facilities | 12,562 | 25 | 12,587 | 23,753 | 299 | 24,052 | ||||||||||||||||||
| Land, seismic and other | 6,597 | 802 | 7,399 | 6,624 | 451 | 7,075 | ||||||||||||||||||
| Total exploration and development | $ | 148,389 | $ | 90,919 | $ | 239,308 | $ | 129,922 | $ | 72,609 | $ | 202,531 | ||||||||||||
| Total acquisitions, net of proceeds from divestitures | $ | (240 | ) | $ | (593 | ) | $ | (833 | ) | $ | (149 | ) | $ | - | $ | (149 | ) |
Exploration and development expenditures were $94.2 million for Q3/2021 and $239.3 million for YTD 2021 compared to $15.9 million for Q3/2020 and $202.5 million for YTD 2020. Expenditures in Q3/2021 were higher compared to Q3/2020 as development increased in 2021 with the recovery in commodity prices and resumption of activity.
In Canada, we invested $75.5 million on exploration and development activities in Q3/2021 which is $71.6 million higher than $3.9 million in Q3/2020. Exploration and development expenditures of $75.5 million for Q3/2021 included costs associated with drilling 26 (25.0 net) light oil wells, 19 (18.7 net) heavy oil wells, and investing $5.4 million on facilities. Exploration and development expenditures of $3.9 million for Q3/2020 reflected the suspension of drilling and completion operations following the sharp decline in crude oil prices in March 2020. Exploration and development expenditures of $148.4 million for YTD 2021 included costs associated with drilling 79 (77.2 net) light oil wells, 26 (22.5 net) heavy oil wells, 2 (2.0 net) natural gas wells, and investing $12.6 million on facilities. Exploration and development expenditures of $129.9 million for YTD 2020 included costs associated with drilling 74 (71.2 net) light oil wells, 33 (33.0 net) heavy oil wells, and investing $23.8 million on facilities.
Total U.S. exploration and development expenditures were $18.7 million for Q3/2021 which is $6.7 million higher than Q3/2020 when exploration and development expenditures totaled $12.0 million. Exploration and development expenditures for Q3/2021 included costs associated with drilling 11 (2.0 net) wells along with 17 (3.4 net) wells that were brought on production. Exploration and development expenditures of $90.9 million for YTD 2021 included costs associated with drilling 52 (11.2 net) wells along with 79 (20.6 net) wells that were brought on production. Exploration and development expenditures for YTD 2021 were higher than $72.6 million for YTD 2020 that included costs associated with drilling 39 (9.2 net) wells along with 53 (11.5 net) wells that were brought on production. The $18.3 million increase in spending YTD 2021 relative to YTD 2020 is due to higher activity levels that was slightly offset by the strengthening Canadian dollar.
| Baytex Energy Corp. Third Quarter Report 2021 | 27 | |
Baytex Energy Corp.
Q3 2021 MD&A
Our exploration and development expenditures for YTD 2021 are consistent with expectations and we forecast expenditures of $300 - $315 million for 2021.
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 September 30, 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.
Management of debt levels is a priority for Baytex in order to sustain operations and support our long-term plans. At September 30, 2021, net debt of $1.56 billion was $282.9 million lower than $1.85 billion at December 31, 2020. The decrease in net debt is primarily a result of free cash flow of $284.2 million generated during YTD 2021 being allocated to debt repayment.
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 September 30, 2021, our net debt to adjusted funds flow ratio was 2.6 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 higher adjusted funds flow for the twelve months ended September 30, 2021 and lower net debt at September 30, 2021.
Credit Facilities
At September 30, 2021, the principal amount of borrowings and letters of credit outstanding was $561.8 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 2.2% for Q3/2021 and YTD 2021 compared to 1.9% for Q3/2020 and 2.5% for YTD 2020.
| 28 | Baytex Energy Corp. Third Quarter Report 2021 | |
Baytex Energy Corp.
Q3 2021 MD&A
Financial Covenants
The following table summarizes the financial covenants applicable to the Credit Facilities and our compliance therewith at September 30, 2021.
| Covenant Description |
Position as at September 30, 2021 | Covenant | ||||||
| Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio) | 0.8:1.0 | 3.5:1.0 | ||||||
| Interest Coverage (3) (Minimum Ratio) | 7.4:1.0 | 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 September 30, 2021, the Company's Senior Secured Debt totaled $561.8 million which includes $546.8 million of principal amounts outstanding and $15.0 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 September 30, 2021 was $708.4 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 September 30, 2021 were $95.7 million. |
Long-Term Notes
We have two series of long-term notes outstanding that total $1.0 billion as at September 30, 2021. The long-term notes do not contain any financial maintenance covenants but contain a debt incurrence covenant that may restrict 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"). The 5.625% Notes pay interest semi-annually with the principal amount repayable at maturity. The 5.625% Notes are redeemable at our option, in whole or in part, at 100.938% 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.
During the nine months ended September 30, 2021, Baytex repurchased and cancelled US$115.5 million of the 5.625% Notes and recorded early redemption expense of $0.9 million. Subsequent to September 30, 2021, Baytex repurchased and cancelled US$84.5 million of the 5.625% Notes due 2024 at the call price of 100.938%, plus accrued interest, effective October 29, 2021. As at November 4, 2021, there was US$200.0 million of the 5.625% Notes outstanding.
Shareholders' Capital
We are authorized to issue an unlimited number of common shares and 10.0 million preferred shares. The rights and terms of preferred shares are determined upon issuance. During the nine months ended September 30, 2021, we issued 3.0 million common shares pursuant to our share-based compensation program. As at November 4, 2021, we had 564.2 million common shares issued and outstanding and no preferred shares issued and outstanding.
| Baytex Energy Corp. Third Quarter Report 2021 | 29 | |
Baytex Energy Corp.
Q3 2021 MD&A
Contractual Obligations
We have a number of financial obligations that are incurred in the ordinary course of business. These obligations are of a recurring nature and impact our adjusted funds flow in an ongoing manner. A significant portion of these obligations will be funded by adjusted funds flow. These obligations as of September 30, 2021 and the expected timing for funding these obligations are noted in the table below.
| Less than | ||||||||||||||||||||
| ($ thousands) | Total | 1 year | 1-3 years | 3-5 years | Beyond 5 years | |||||||||||||||
| Trade and other payables | $ | 195,230 | $ | 195,230 | $ | - | $ | - | ||||||||||||
| Credit facilities (1) (2) | 546,803 | - | 546,803 | - | - | |||||||||||||||
| Long-term notes (2) | 1,000,171 | - | 362,696 | - | 637,475 | |||||||||||||||
| Interest on long-term notes (3) | 361,400 | 76,181 | 145,542 | 111,558 | 28,119 | |||||||||||||||
| Lease agreements (2) | 9,055 | 3,663 | 3,901 | 1,413 | 78 | |||||||||||||||
| Processing agreements | 5,734 | 772 | 935 | 473 | 3,554 | |||||||||||||||
| Transportation agreements | 84,236 | 18,767 | 38,914 | 16,470 | 10,085 | |||||||||||||||
| Total | $ | 2,202,629 | $ | 294,613 | $ | 1,098,791 | $ | 129,914 | $ | 679,311 |
| (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. On September 9, 2021 Baytex submitted a redemption notice to redeem US$84.5 million of the 5.625% Notes on October 29, 2021. |
| (3) | Excludes interest on our credit facilities as interest payments fluctuate based on a floating rate of interest and changes in the outstanding balances. |
We also have ongoing obligations related to the abandonment and reclamation of well sites and facilities when they reach the end of their economic lives. Programs to abandon and reclaim well sites and facilities are undertaken regularly in accordance with applicable legislative requirements.
| 30 | Baytex Energy Corp. Third Quarter Report 2021 | |
Baytex Energy Corp.
Q3 2021 MD&A
QUARTERLY FINANCIAL INFORMATION
| 2021 | 2020 | 2019 | ||||||||||||||||||||||||||||||
| ($ thousands, except per common share amounts) | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | ||||||||||||||||||||||||
| Petroleum and natural gas sales | 488,736 | 442,354 | 384,702 | 233,636 | 252,538 | 152,689 | 336,614 | 445,895 | ||||||||||||||||||||||||
| Net income (loss) | 32,713 | 1,052,999 | (35,352 | ) | 221,160 | (23,444 | ) | (138,463 | ) | (2,498,217 | ) | (117,772 | ) | |||||||||||||||||||
| Per common share - basic | 0.06 | 1.87 | (0.06 | ) | 0.39 | (0.04 | ) | (0.25 | ) | (4.46 | ) | (0.21 | ) | |||||||||||||||||||
| Per common share - diluted | 0.06 | 1.85 | (0.06 | ) | 0.39 | (0.04 | ) | (0.25 | ) | (4.46 | ) | (0.21 | ) | |||||||||||||||||||
| Adjusted funds flow | 198,397 | 175,883 | 156,582 | 82,176 | 78,508 | 17,887 | 132,935 | 232,147 | ||||||||||||||||||||||||
| Per common share - basic | 0.35 | 0.31 | 0.28 | 0.15 | 0.14 | 0.03 | 0.24 | 0.42 | ||||||||||||||||||||||||
| Per common share - diluted | 0.35 | 0.31 | 0.28 | 0.15 | 0.14 | 0.03 | 0.24 | 0.42 | ||||||||||||||||||||||||
| Exploration and development | 94,235 | 61,485 | 83,588 | 77,809 | 15,902 | 9,852 | 176,777 | 153,117 | ||||||||||||||||||||||||
| Canada | 75,499 | 30,387 | 42,503 | 45,030 | 3,882 | 2,929 | 123,110 | 104,460 | ||||||||||||||||||||||||
| U.S. | 18,736 | 31,098 | 41,085 | 32,779 | 12,020 | 6,923 | 53,667 | 48,657 | ||||||||||||||||||||||||
| Acquisitions, net of divestitures | (612 | ) | (18 | ) | (203 | ) | (33 | ) | (98 | ) | (11 | ) | (40 | ) | 563 | |||||||||||||||||
| Net debt | 1,564,658 | 1,629,629 | 1,758,894 | 1,847,601 | 1,906,079 | 1,994,953 | 2,051,617 | 1,871,791 | ||||||||||||||||||||||||
| Total assets | 4,453,971 | 4,438,162 | 3,338,408 | 3,408,096 | 3,156,414 | 3,267,820 | 3,441,040 | 5,914,083 | ||||||||||||||||||||||||
| Common shares outstanding | 564,213 | 564,182 | 564,111 | 561,227 | 561,163 | 560,545 | 560,483 | 558,305 | ||||||||||||||||||||||||
| Daily production | ||||||||||||||||||||||||||||||||
| Total production (boe/d) | 79,872 | 81,162 | 78,780 | 70,475 | 77,814 | 72,508 | 98,452 | 96,360 | ||||||||||||||||||||||||
| Canada (boe/d) | 48,124 | 47,205 | 52,039 | 45,321 | 49,164 | 37,691 | 62,262 | 57,794 | ||||||||||||||||||||||||
| U.S. (boe/d) | 31,748 | 33,957 | 26,741 | 25,154 | 28,650 | 34,817 | 36,190 | 38,566 | ||||||||||||||||||||||||
| Benchmark prices | ||||||||||||||||||||||||||||||||
| WTI oil (US$/bbl) | 70.56 | 66.07 | 57.84 | 42.66 | 40.93 | 27.85 | 46.17 | 56.96 | ||||||||||||||||||||||||
| WCS heavy ($/bbl) | 71.81 | 67.03 | 57.46 | 43.46 | 42.40 | 22.70 | 34.48 | 54.29 | ||||||||||||||||||||||||
| Edmonton Light ($/bbl) | 83.78 | 77.28 | 66.58 | 50.24 | 49.83 | 29.85 | 51.43 | 58.10 | ||||||||||||||||||||||||
| CAD/USD avg exchange rate | 1.2601 | 1.2279 | 1.2663 | 1.3031 | 1.3316 | 1.3860 | 1.3445 | 1.3201 | ||||||||||||||||||||||||
| AECO gas ($/mcf) | 3.54 | 2.85 | 2.93 | 2.77 | 2.18 | 1.91 | 2.14 | 2.34 | ||||||||||||||||||||||||
| NYMEX gas (US$/mmbtu) | 4.01 | 2.83 | 2.69 | 2.66 | 1.98 | 1.72 | 1.95 | 2.50 | ||||||||||||||||||||||||
| Sales price ($/boe) | 63.85 | 57.19 | 51.84 | 34.35 | 33.79 | 22.31 | 35.19 | 48.25 | ||||||||||||||||||||||||
| Royalties ($/boe) | (12.32 | ) | (11.04 | ) | (9.44 | ) | (5.83 | ) | (5.59 | ) | (4.42 | ) | (6.33 | ) | (8.72 | ) | ||||||||||||||||
| Operating expense ($/boe) | (11.46 | ) | (11.22 | ) | (11.36 | ) | (12.30 | ) | (10.26 | ) | (11.17 | ) | (11.66 | ) | (11.23 | ) | ||||||||||||||||
| Transportation expense ($/boe) | (1.06 | ) | (1.01 | ) | (1.24 | ) | (1.03 | ) | (0.89 | ) | (0.76 | ) | (1.15 | ) | (1.00 | ) | ||||||||||||||||
| Operating netback ($/boe) | 39.01 | 33.92 | 29.80 | 15.19 | 17.05 | 5.96 | 16.05 | 27.30 | ||||||||||||||||||||||||
| Financial derivatives gain (loss) ($/boe) | (7.34 | ) | (5.28 | ) | (2.93 | ) | 2.64 | (1.36 | ) | 2.06 | 3.00 | 2.59 | ||||||||||||||||||||
| Operating netback after financial derivatives ($/boe) | 31.67 | 28.64 | 26.87 | 17.83 | 15.69 | 8.02 | 19.05 | 29.89 |
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 in Q4/2019 and 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 YTD 2021 which supported increased development activity and resulted in production of 79,872 boe/d for Q3/2021.
North American benchmark commodity prices were 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 strengthen in 2021 with WTI averaging US$70.56/bbl in Q3/2021 as the outlook for demand improved with increasing global mobility and supply growth was limited by OPEC production curtailments along with limited production growth from large independent producers. The impact of increased commodity prices is reflected in our realized sales price of $63.85/boe for Q3/2021 which is our strongest realized pricing in the previous eight quarters.
| Baytex Energy Corp. Third Quarter Report 2021 | 31 | |
Baytex Energy Corp.
Q3 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 Q3/2021 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 $1.87 billion at Q4/2019 to $1.56 billion at Q3/2021 as free cash flow of $375.2 million generated over the last eight quarters has been 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 1.2965 CAD/USD at Q4/2019 to 1.2750 CAD/USD at Q3/2021.
OFF BALANCE SHEET TRANSACTIONS
We do not have any financial arrangements that are excluded from the consolidated financial statements as at September 30, 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 nine months ended September 30, 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 a 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.
| 32 | Baytex Energy Corp. Third Quarter Report 2021 | |
Baytex Energy Corp.
Q3 2021 MD&A
The following table reconciles cash flow from operating activities to adjusted funds flow.
| Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||
| ($ thousands) | 2021 | 2020 | 2021 | 2020 | ||||||||||||
| Cash flow from operating activities | $ | 178,961 | $ | 93,688 | $ | 471,817 | $ | 302,079 | ||||||||
| Change in non-cash working capital | 17,631 | (16,391 | ) | 54,830 | (78,829 | ) | ||||||||||
| Asset retirement obligations settled | 1,805 | 1,211 | 4,215 | 6,080 | ||||||||||||
| Adjusted funds flow | $ | 198,397 | $ | 78,508 | $ | 530,862 | $ | 229,330 |
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 September 30 | Nine Months Ended September 30 | |||||||||||||||
| ($ thousands) | 2021 | 2020 | 2021 | 2020 | ||||||||||||
| Cash flow used in investing activities | $ | 92,763 | $ | 16,288 | $ | 214,796 | $ | 233,092 | ||||||||
| Change in non-cash working capital | 1,018 | (444 | ) | 24,248 | (28,683 | ) | ||||||||||
| Proceeds from dispositions | 701 | 98 | 947 | 149 | ||||||||||||
| Property acquisitions | (89 | ) | - | (114 | ) | - | ||||||||||
| Additions to other plant and equipment | (158 | ) | (40 | ) | (569 | ) | (2,027 | ) | ||||||||
| Exploration and development expenditures | $ | 94,235 | $ | 15,902 | $ | 239,308 | $ | 202,531 |
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 September 30 | Nine Months Ended September 30 | |||||||||||||||
| ($ thousands) | 2021 | 2020 | 2021 | 2020 | ||||||||||||
| Adjusted funds flow | $ | 198,397 | $ | 78,508 | $ | 530,862 | $ | 229,330 | ||||||||
| Exploration and development expenditures | (94,235 | ) | (15,902 | ) | (239,308 | ) | (202,531 | ) | ||||||||
| Payments on lease obligations | (1,142 | ) | (1,456 | ) | (3,143 | ) | (4,440 | ) | ||||||||
| Asset retirement obligations settled | (1,805 | ) | (1,211 | ) | (4,215 | ) | (6,080 | ) | ||||||||
| Free cash flow | $ | 101,215 | $ | 59,939 | $ | 284,196 | $ | 16,279 |
| Baytex Energy Corp. Third Quarter Report 2021 | 33 | |
Baytex Energy Corp.
Q3 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) | September 30, 2021 | December 31, 2020 | ||||||
| Credit facilities (1) | $ | 546,803 | $ | 651,173 | ||||
| Long-term notes (1) | 1,000,171 | 1,147,950 | ||||||
| Trade and other payables | 195,230 | 155,955 | ||||||
| Trade and other receivables | (177,546 | ) | (107,477 | ) | ||||
| Net debt | $ | 1,564,658 | $ | 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 September 30 | Nine Months Ended September 30 | |||||||||||||||
| ($ thousands) | 2021 | 2020 | 2021 | 2020 | ||||||||||||
| Petroleum and natural gas sales | $ | 488,736 | $ | 252,538 | $ | 1,315,792 | $ | 741,841 | ||||||||
| Blending and other expense | (19,581 | ) | (10,673 | ) | (56,668 | ) | (37,490 | ) | ||||||||
| Total sales, net of blending and other expense | 469,155 | 241,865 | 1,259,124 | 704,351 | ||||||||||||
| Royalties | (90,523 | ) | (40,052 | ) | (239,004 | ) | (125,928 | ) | ||||||||
| Operating expense | (84,196 | ) | (73,447 | ) | (247,645 | ) | (251,597 | ) | ||||||||
| Transportation expense | (7,818 | ) | (6,372 | ) | (24,092 | ) | (21,745 | ) | ||||||||
| Operating netback | 286,618 | 121,994 | 748,383 | 305,081 | ||||||||||||
| Realized financial derivative (loss) gain | (53,905 | ) | (9,743 | ) | (113,697 | ) | 30,731 | |||||||||
| Operating netback after realized financial derivatives | $ | 232,713 | $ | 112,251 | $ | 634,686 | $ | 335,812 |
| 34 | Baytex Energy Corp. Third Quarter Report 2021 | |
Baytex Energy Corp.
Q3 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 September 30 | ||||||||
| ($ thousands) | 2021 | 2020 | ||||||
| Net income (loss) | $ | 1,271,521 | $ | (2,777,896 | ) | |||
| Plus: | ||||||||
| Financing and interest | 111,861 | 126,228 | ||||||
| Unrealized foreign exchange (gain) loss | (15,670 | ) | 3,776 | |||||
| Unrealized financial derivatives loss | 217,333 | 32,470 | ||||||
| Current income tax expense | 588 | 1,382 | ||||||
| Deferred income tax expense (recovery) | 172,477 | (315,078 | ) | |||||
| Depletion and depreciation | 426,119 | 572,518 | ||||||
| Gain on dispositions | (6,747 | ) | (1,409 | ) | ||||
| Impairment (reversal) loss | (1,482,544 | ) | 2,904,171 | |||||
| Non-cash items (1) | 13,498 | 18,619 | ||||||
| Bank EBITDA | $ | 708,436 | $ | 564,781 |
| (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 September 30, 2021.
| Baytex Energy Corp. Third Quarter Report 2021 | 35 | |
Baytex Energy Corp.
Q3 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; the manner in which we fund our planned capital expenditures and monitor and manage our capital resources and liquidity; that a significant portion of our financial obligations will be funded by adjusted funds flow; our expectations with respect to the LIBOR transition and that we do not expect it to have a material impact on Baytex; and the circumstances in which we would be eligible to terminate our reporting obligations under the Securities Exchange Act of 1934, as amended.
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.
| 36 | Baytex Energy Corp. Third Quarter Report 2021 | |
Baytex Energy Corp.
Condensed Consolidated Interim Statements of Financial Position
(thousands of Canadian dollars) (unaudited)
| As at | |||||||||||
| Notes | September 30, 2021 | December 31, 2020 | |||||||||
| ASSETS | |||||||||||
| Current assets | |||||||||||
| Trade and other receivables | $ | 177,546 | $ | 107,477 | |||||||
| Financial derivatives | 16 | 7,040 | 5,057 | ||||||||
| 184,586 | 112,534 | ||||||||||
| Non-current assets | |||||||||||
| Exploration and evaluation assets | 4 | 176,469 | 191,865 | ||||||||
| Oil and gas properties | 5 | 4,076,375 | 3,077,548 | ||||||||
| Other plant and equipment | 7,487 | 7,996 | |||||||||
| Lease assets | 9,054 | 11,098 | |||||||||
| Deferred income tax asset | 13 | - | 7,055 | ||||||||
| $ | 4,453,971 | $ | 3,408,096 | ||||||||
| LIABILITIES | |||||||||||
| Current liabilities | |||||||||||
| Trade and other payables | $ | 195,230 | $ | 155,955 | |||||||
| Financial derivatives | 16 | 194,780 | 26,792 | ||||||||
| Lease obligations | 3,512 | 4,289 | |||||||||
| Asset retirement obligations | 8 | 11,719 | 11,820 | ||||||||
| 405,241 | 198,856 | ||||||||||
| Non-current liabilities | |||||||||||
| Financial derivatives | 16 | 13,403 | - | ||||||||
| Credit facilities | 6 | 545,302 | 649,221 | ||||||||
| Long-term notes | 7 | 987,225 | 1,132,868 | ||||||||
| Lease obligations | 5,247 | 6,787 | |||||||||
| Asset retirement obligations | 8 | 684,691 | 748,563 | ||||||||
| Deferred income tax liability | 13 | 160,716 | 93,588 | ||||||||
| 2,801,825 | 2,829,883 | ||||||||||
| SHAREHOLDERS' EQUITY | |||||||||||
| Shareholders' capital | 9 | 5,736,593 | 5,729,418 | ||||||||
| Contributed surplus | 11,773 | 14,345 | |||||||||
| Accumulated other comprehensive income | 637,945 | 618,976 | |||||||||
| Deficit | (4,734,165 | ) | (5,784,526 | ) | |||||||
| 1,652,146 | 578,213 | ||||||||||
| $ | 4,453,971 | $ | 3,408,096 |
Subsequent event (note 7 and 16)
See accompanying notes to the condensed consolidated interim financial statements.
| Baytex Energy Corp. Third Quarter Report 2021 | 37 | |
Baytex Energy Corp.
Condensed Consolidated Interim 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 September 30 | Nine Months Ended September 30 | ||||||||||||||||||
| Notes | 2021 | 2020 | 2021 | 2020 | |||||||||||||||
| Revenue, net of royalties | |||||||||||||||||||
| Petroleum and natural gas sales | 12 | $ | 488,736 | $ | 252,538 | $ | 1,315,792 | $ | 741,841 | ||||||||||
| Royalties | (90,523 | ) | (40,052 | ) | (239,004 | ) | (125,928 | ) | |||||||||||
| 398,213 | 212,486 | 1,076,788 | 615,913 | ||||||||||||||||
| Expenses | |||||||||||||||||||
| Operating | 84,196 | 73,447 | 247,645 | 251,597 | |||||||||||||||
| Transportation | 7,818 | 6,372 | 24,092 | 21,745 | |||||||||||||||
| Blending and other | 19,581 | 10,673 | 56,668 | 37,490 | |||||||||||||||
| General and administrative | 9,980 | 7,741 | 29,323 | 24,954 | |||||||||||||||
| Exploration and evaluation | 4 | 6,766 | 8,909 | 10,718 | 11,000 | ||||||||||||||
| Depletion and depreciation | 127,052 | 106,454 | 332,119 | 392,380 | |||||||||||||||
| Impairment (reversal) loss | 4, 5 | - | - | (1,126,415 | ) | 2,716,349 | |||||||||||||
| Share-based compensation | 10 | 2,511 | 2,949 | 8,262 | 8,725 | ||||||||||||||
| Financing and interest | 14 | 29,028 | 27,962 | 83,832 | 97,412 | ||||||||||||||
| Financial derivatives loss (gain) | 16 | 62,846 | 17,027 | 293,105 | (50,156 | ) | |||||||||||||
| Foreign exchange loss (gain) | 15 | 7,466 | (26,231 | ) | 2,405 | 27,688 | |||||||||||||
| Gain on dispositions | (2,112 | ) | (98 | ) | (6,092 | ) | (246 | ) | |||||||||||
| Other income | (366 | ) | (293 | ) | (2,092 | ) | (2,300 | ) | |||||||||||
| 354,766 | 234,912 | (46,430 | ) | 3,536,638 | |||||||||||||||
| Net income (loss) before income taxes | 43,447 | (22,426 | ) | 1,123,218 | (2,920,725 | ) | |||||||||||||
| Income tax expense (recovery) | 13 | ||||||||||||||||||
| Current income tax expense | 486 | 322 | 894 | 880 | |||||||||||||||
| Deferred income tax expense (recovery) | 10,248 | 696 | 71,963 | (261,481 | ) | ||||||||||||||
| 10,734 | 1,018 | 72,857 | (260,601 | ) | |||||||||||||||
| Net income (loss) | $ | 32,713 | $ | (23,444 | ) | $ | 1,050,361 | $ | (2,660,124 | ) | |||||||||
| Other comprehensive income (loss) | |||||||||||||||||||
| Foreign currency translation adjustment | 26,175 | (30,268 | ) | 18,969 | 90,219 | ||||||||||||||
| Comprehensive income (loss) | $ | 58,888 | $ | (53,712 | ) | $ | 1,069,330 | $ | (2,569,905 | ) | |||||||||
| Net income (loss) per common share | 11 | ||||||||||||||||||
| Basic | $ | 0.06 | $ | (0.04 | ) | $ | 1.86 | $ | (4.75 | ) | |||||||||
| Diluted | $ | 0.06 | $ | (0.04 | ) | $ | 1.84 | $ | (4.75 | ) | |||||||||
| Weighted average common shares (000's) | 11 | ||||||||||||||||||
| Basic | 564,211 | 561,128 | 563,492 | 560,484 | |||||||||||||||
| Diluted | 571,647 | 561,128 | 570,179 | 560,484 |
See accompanying notes to the condensed consolidated interim financial statements.
| 38 | Baytex Energy Corp. Third Quarter Report 2021 | |
Baytex Energy Corp.
Condensed Consolidated Interim 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 | 10,329 | (10,329 | ) | - | - | - | |||||||||||||||||
| Share-based compensation | - | 6,973 | - | - | 6,973 | ||||||||||||||||||
| Comprehensive income (loss) | - | - | 90,219 | (2,660,124 | ) | (2,569,905 | ) | ||||||||||||||||
| Balance at September 30, 2020 | $ | 5,729,164 | $ | 14,356 | $ | 646,443 | $ | (6,005,686 | ) | $ | 384,277 | ||||||||||||
| Balance at December 31, 2020 | $ | 5,729,418 | $ | 14,345 | $ | 618,976 | $ | (5,784,526 | ) | $ | 578,213 | ||||||||||||
| Vesting of share awards | 9 | 7,175 | (7,175 | ) | - | - | - | ||||||||||||||||
| Share-based compensation | 10 | - | 4,603 | - | - | 4,603 | |||||||||||||||||
| Comprehensive income | - | - | 18,969 | 1,050,361 | 1,069,330 | ||||||||||||||||||
| Balance at September 30, 2021 | $ | 5,736,593 | $ | 11,773 | $ | 637,945 | $ | (4,734,165 | ) | $ | 1,652,146 |
See accompanying notes to the condensed consolidated interim financial statements.
| Baytex Energy Corp. Third Quarter Report 2021 | 39 | |
Baytex Energy Corp.
Condensed Consolidated Interim Statements of Cash Flows
(thousands of Canadian dollars) (unaudited)
| Three Months Ended September 30 | Nine Months Ended September 30 | ||||||||||||||||||
| Notes | 2021 | 2020 | 2021 | 2020 | |||||||||||||||
| CASH PROVIDED BY (USED IN): | |||||||||||||||||||
| Operating activities | |||||||||||||||||||
| Net income (loss) for the period | $ | 32,713 | $ | (23,444 | ) | $ | 1,050,361 | $ | (2,660,124 | ) | |||||||||
| Adjustments for: | |||||||||||||||||||
| Non-cash share-based compensation | 10 | 1,453 | 2,336 | 4,603 | 6,973 | ||||||||||||||
| Unrealized foreign exchange loss (gain) | 15 | 7,545 | (25,880 | ) | 3,223 | 28,125 | |||||||||||||
| Exploration and evaluation | 4 | 6,766 | 8,909 | 10,718 | 11,000 | ||||||||||||||
| Depletion and depreciation | 127,052 | 106,454 | 332,119 | 392,380 | |||||||||||||||
| Impairment (reversal) loss | 4, 5 | - | - | (1,126,415 | ) | 2,716,349 | |||||||||||||
| Non-cash financing, accretion, and early redemption expense | 14 | 6,235 | 2,544 | 13,082 | 16,072 | ||||||||||||||
| Non-cash other income | 8 | (444 | ) | (293 | ) | (2,108 | ) | (293 | ) | ||||||||||
| Unrealized financial derivatives loss (gain) | 16 | 8,941 | 7,284 | 179,408 | (19,425 | ) | |||||||||||||
| Gain on dispositions | (2,112 | ) | (98 | ) | (6,092 | ) | (246 | ) | |||||||||||
| Deferred income tax expense (recovery) | 13 | 10,248 | 696 | 71,963 | (261,481 | ) | |||||||||||||
| Asset retirement obligations settled | 8 | (1,805 | ) | (1,211 | ) | (4,215 | ) | (6,080 | ) | ||||||||||
| Change in non-cash working capital | (17,631 | ) | 16,391 | (54,830 | ) | 78,829 | |||||||||||||
| 178,961 | 93,688 | 471,817 | 302,079 | ||||||||||||||||
| Financing activities | |||||||||||||||||||
| Increase (decrease) in credit facilities | 53,430 | (75,944 | ) | (107,230 | ) | 111,403 | |||||||||||||
| Payments on lease obligations | (1,142 | ) | (1,456 | ) | (3,143 | ) | (4,440 | ) | |||||||||||
| Net proceeds from issuance of long-term notes | - | - | - | 652,150 | |||||||||||||||
| Redemption of long-term notes | 7 | (139,861 | ) | - | (146,648 | ) | (833,672 | ) | |||||||||||
| (87,573 | ) | (77,400 | ) | (257,021 | ) | (74,559 | ) | ||||||||||||
| Investing activities | |||||||||||||||||||
| Additions to exploration and evaluation assets | 4 | (89 | ) | (484 | ) | (733 | ) | (4,344 | ) | ||||||||||
| Additions to oil and gas properties | 5 | (94,146 | ) | (15,418 | ) | (238,575 | ) | (198,187 | ) | ||||||||||
| Additions to other plant and equipment | (158 | ) | (40 | ) | (569 | ) | (2,027 | ) | |||||||||||
| Property acquisitions | (89 | ) | - | (114 | ) | - | |||||||||||||
| Proceeds from dispositions | 701 | 98 | 947 | 149 | |||||||||||||||
| Change in non-cash working capital | 1,018 | (444 | ) | 24,248 | (28,683 | ) | |||||||||||||
| (92,763 | ) | (16,288 | ) | (214,796 | ) | (233,092 | ) | ||||||||||||
| Change in cash | (1,375 | ) | - | - | (5,572 | ) | |||||||||||||
| Cash, beginning of period | 1,375 | - | - | 5,572 | |||||||||||||||
| Cash, end of period | $ | - | $ | - | $ | - | $ | - | |||||||||||
| Supplementary information | |||||||||||||||||||
| Interest paid | $ | 32,436 | $ | 3,365 | $ | 80,037 | $ | 55,145 | |||||||||||
| Income taxes paid | $ | - | $ | 1,155 | $ | - | $ | 1,155 |
See accompanying notes to the condensed consolidated interim financial statements.
| 40 | Baytex Energy Corp. Third Quarter Report 2021 | |
Baytex Energy Corp.
Notes to the Condensed Consolidated Interim Financial Statements
For the periods ended September 30, 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 November 4, 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 nine months ended September 30, 2021, the global economy continued to show signs of recovery from the impacts of the COVID-19 pandemic. Global spot prices for crude oil have recovered and now exceed pre-pandemic levels as optimism for demand recovery improves with limited production growth from independent producers and ongoing OPEC production curtailments. While we have benefited from these improvements in crude oil prices there is a degree of uncertainty related to COVID-19 that has been considered in our estimates for the period ended September 30, 2021.
| Baytex Energy Corp. Third Quarter Report 2021 | 41 | |
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 September 30 | 2021 | 2020 | 2021 | 2020 | 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||||||
| Revenue, net of royalties | ||||||||||||||||||||||||||||||||
| Petroleum and natural gas sales | $ | 292,723 | $ | 158,831 | $ | 196,013 | $ | 93,707 | $ | - | $ | - | $ | 488,736 | $ | 252,538 | ||||||||||||||||
| Royalties | (32,679 | ) | (12,297 | ) | (57,844 | ) | (27,755 | ) | - | - | (90,523 | ) | (40,052 | ) | ||||||||||||||||||
| 260,044 | 146,534 | 138,169 | 65,952 | - | - | 398,213 | 212,486 | |||||||||||||||||||||||||
| Expenses | ||||||||||||||||||||||||||||||||
| Operating | 63,301 | 57,557 | 20,895 | 15,890 | - | - | 84,196 | 73,447 | ||||||||||||||||||||||||
| Transportation | 7,818 | 6,372 | - | - | - | - | 7,818 | 6,372 | ||||||||||||||||||||||||
| Blending and other | 19,581 | 10,673 | - | - | - | - | 19,581 | 10,673 | ||||||||||||||||||||||||
| General and administrative | - | - | - | - | 9,980 | 7,741 | 9,980 | 7,741 | ||||||||||||||||||||||||
| Exploration and evaluation | 6,766 | 8,909 | - | - | - | - | 6,766 | 8,909 | ||||||||||||||||||||||||
| Depletion and depreciation | 82,241 | 68,727 | 43,440 | 35,820 | 1,371 | 1,907 | 127,052 | 106,454 | ||||||||||||||||||||||||
| Share-based compensation | - | - | - | - | 2,511 | 2,949 | 2,511 | 2,949 | ||||||||||||||||||||||||
| Financing and interest | - | - | - | - | 29,028 | 27,962 | 29,028 | 27,962 | ||||||||||||||||||||||||
| Financial derivatives loss | - | - | - | - | 62,846 | 17,027 | 62,846 | 17,027 | ||||||||||||||||||||||||
| Foreign exchange loss (gain) | - | - | - | - | 7,466 | (26,231 | ) | 7,466 | (26,231 | ) | ||||||||||||||||||||||
| (Gain) loss on dispositions | (2,302 | ) | (98 | ) | 190 | - | - | - | (2,112 | ) | (98 | ) | ||||||||||||||||||||
| Other (income) expense | (444 | ) | (694 | ) | - | - | 78 | 401 | (366 | ) | (293 | ) | ||||||||||||||||||||
| 176,961 | 151,446 | 64,525 | 51,710 | 113,280 | 31,756 | 354,766 | 234,912 | |||||||||||||||||||||||||
| Net income (loss) before income taxes | 83,083 | (4,912 | ) | 73,644 | 14,242 | (113,280 | ) | (31,756 | ) | 43,447 | (22,426 | ) | ||||||||||||||||||||
| Income tax expense (recovery) | ||||||||||||||||||||||||||||||||
| Current income tax expense | (57 | ) | - | 543 | 322 | - | - | 486 | 322 | |||||||||||||||||||||||
| Deferred income tax expense (recovery) | 20,064 | 10,589 | 10,248 | 696 | (20,064 | ) | (10,589 | ) | 10,248 | 696 | ||||||||||||||||||||||
| 20,007 | 10,589 | 10,791 | 1,018 | (20,064 | ) | (10,589 | ) | 10,734 | 1,018 | |||||||||||||||||||||||
| Net income (loss) | $ | 63,076 | $ | (15,501 | ) | $ | 62,853 | $ | 13,224 | $ | (93,216 | ) | $ | (21,167 | ) | $ | 32,713 | $ | (23,444 | ) | ||||||||||||
| Total oil and natural gas capital expenditures (1) | $ | 75,480 | $ | 3,784 | $ | 18,143 | $ | 12,020 | $ | - | $ | - | $ | 93,623 | $ | 15,804 |
(1) Includes additions to exploration and evaluation assets, oil and gas properties, and property acquisitions, net of proceeds from divestitures.
| 42 | Baytex Energy Corp. Third Quarter Report 2021 | |
| Canada | U.S. | Corporate | Consolidated | |||||||||||||||||||||||||||||
| Nine Months Ended September 30 | 2021 | 2020 | 2021 | 2020 | 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||||||
| Revenue, net of royalties | ||||||||||||||||||||||||||||||||
| Petroleum and natural gas sales | $ | 786,171 | $ | 427,000 | $ | 529,621 | $ | 314,841 | $ | - | $ | - | $ | 1,315,792 | $ | 741,841 | ||||||||||||||||
| Royalties | (83,536 | ) | (33,972 | ) | (155,468 | ) | (91,956 | ) | - | - | (239,004 | ) | (125,928 | ) | ||||||||||||||||||
| 702,635 | 393,028 | 374,153 | 222,885 | - | - | 1,076,788 | 615,913 | |||||||||||||||||||||||||
| Expenses | ||||||||||||||||||||||||||||||||
| Operating | 186,455 | 185,641 | 61,190 | 65,956 | - | - | 247,645 | 251,597 | ||||||||||||||||||||||||
| Transportation | 24,092 | 21,745 | - | - | - | - | 24,092 | 21,745 | ||||||||||||||||||||||||
| Blending and other | 56,668 | 37,490 | - | - | - | - | 56,668 | 37,490 | ||||||||||||||||||||||||
| General and administrative | - | - | - | - | 29,323 | 24,954 | 29,323 | 24,954 | ||||||||||||||||||||||||
| Exploration and evaluation | 10,718 | 11,000 | - | - | - | - | 10,718 | 11,000 | ||||||||||||||||||||||||
| Depletion and depreciation | 215,803 | 249,125 | 112,368 | 137,462 | 3,948 | 5,793 | 332,119 | 392,380 | ||||||||||||||||||||||||
| Impairment (reversal) loss | (684,000 | ) | 1,855,000 | (442,415 | ) | 861,349 | - | - | (1,126,415 | ) | 2,716,349 | |||||||||||||||||||||
| Share-based compensation | - | - | - | - | 8,262 | 8,725 | 8,262 | 8,725 | ||||||||||||||||||||||||
| Financing and interest | - | - | - | - | 83,832 | 97,412 | 83,832 | 97,412 | ||||||||||||||||||||||||
| Financial derivatives loss (gain) | - | - | - | - | 293,105 | (50,156 | ) | 293,105 | (50,156 | ) | ||||||||||||||||||||||
| Foreign exchange loss | - | - | - | - | 2,405 | 27,688 | 2,405 | 27,688 | ||||||||||||||||||||||||
| (Gain) loss on dispositions | (6,282 | ) | (246 | ) | 190 | - | - | - | (6,092 | ) | (246 | ) | ||||||||||||||||||||
| Other (income) expense | (2,108 | ) | (694 | ) | - | - | 16 | (1,606 | ) | (2,092 | ) | (2,300 | ) | |||||||||||||||||||
| (198,654 | ) | 2,359,061 | (268,667 | ) | 1,064,767 | 420,891 | 112,810 | (46,430 | ) | 3,536,638 | ||||||||||||||||||||||
| 901,289 | (1,966,033 | ) | 642,820 | (841,882 | ) | (420,891 | ) | (112,810 | ) | 1,123,218 | (2,920,725 | ) | ||||||||||||||||||||
| Income tax expense (recovery) | ||||||||||||||||||||||||||||||||
| Current income tax (recovery) expense | (353 | ) | 469 | 1,247 | 411 | - | - | 894 | 880 | |||||||||||||||||||||||
| Deferred income tax expense (recovery) | 89,040 | (74,687 | ) | 64,908 | (164,298 | ) | (81,985 | ) | (22,496 | ) | 71,963 | (261,481 | ) | |||||||||||||||||||
| 88,687 | (74,218 | ) | 66,155 | (163,887 | ) | (81,985 | ) | (22,496 | ) | 72,857 | (260,601 | ) | ||||||||||||||||||||
| Net income (loss) | $ | 812,602 | $ | (1,891,815 | ) | $ | 576,665 | $ | (677,995 | ) | $ | (338,906 | ) | $ | (90,314 | ) | $ | 1,050,361 | $ | (2,660,124 | ) | |||||||||||
| Total oil and natural gas capital expenditures (1) | $ | 148,149 | $ | 129,773 | $ | 90,326 | $ | 72,609 | $ | - | $ | - | $ | 238,475 | $ | 202,382 |
(1) Includes additions to exploration and evaluation assets, oil and gas properties, and property acquisitions, net of proceeds from divestitures.
| September 30, 2021 | December 31, 2020 | |||||||
| Canadian assets | $ | 2,242,931 | $ | 1,646,412 | ||||
| U.S. assets | 2,187,459 | 1,737,533 | ||||||
| Corporate assets | 23,581 | 24,151 | ||||||
| Total consolidated assets | $ | 4,453,971 | $ | 3,408,096 |
| Baytex Energy Corp. Third Quarter Report 2021 | 43 | |
4. EXPLORATION AND EVALUATION ASSETS
| September 30, 2021 | December 31, 2020 | |||||||
| Balance, beginning of period | $ | 191,865 | $ | 320,210 | ||||
| Capital expenditures | 733 | 4,490 | ||||||
| Divestitures | (97 | ) | - | |||||
| Property swaps | 247 | 468 | ||||||
| Impairment | - | (113,058 | ) | |||||
| Exploration and evaluation expense | (10,718 | ) | (14,011 | ) | ||||
| Transfer to oil and gas properties (note 5) | (5,458 | ) | (8,585 | ) | ||||
| Foreign currency translation | (103 | ) | 2,351 | |||||
| Balance, end of period | $ | 176,469 | $ | 191,865 |
At September 30, 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 loss of $127.9 million was recorded at March 31, 2020. The recoverable amount of each CGU was based on its fair value less costs of disposal ("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 loss booked for each CGU at March 31, 2020.
|
Impairment loss 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 loss 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 |
| 44 | Baytex Energy Corp. Third Quarter Report 2021 | |
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 | 238,575 | - | 238,575 | |||||||||
| Property acquisitions | 156 | - | 156 | |||||||||
| Transfers from exploration and evaluation assets (note 4) | 5,458 | - | 5,458 | |||||||||
| Change in asset retirement obligations (note 8) | (59,339 | ) | - | (59,339 | ) | |||||||
| Divestitures | (7,039 | ) | 5,148 | (1,891 | ) | |||||||
| Property swaps | (25,050 | ) | 24,704 | (346 | ) | |||||||
| Impairment reversal | - | 1,126,415 | 1,126,415 | |||||||||
| Foreign currency translation | (745 | ) | 18,715 | 17,970 | ||||||||
| Depletion | - | (328,171 | ) | (328,171 | ) | |||||||
| Balance, September 30, 2021 | $ | 11,575,692 | $ | (7,499,317 | ) | $ | 4,076,375 |
At September 30, 2021, there were no indicators of impairment or impairment reversal for oil and gas properties in any of the Company's CGUs. Baytex recorded an impairment reversal for its oil and gas properties of $1.1 billion for the nine months ended September 30, 2021 and a net impairment loss of $2.2 billion for the year ended December 31, 2020.
2021 Impairment Reversal
At June 30, 2021, we identified indicators of impairment reversal for oil and gas properties in each of our six CGU's due to the increase in forecasted commodity prices. The recoverable amount for each of our six CGUs exceeded their carrying amounts which resulted in an impairment reversal of $1.1 billion recorded at June 30, 2021. The recoverable amount for each CGU was based on its FVLCD which was estimated using a discounted cash flow model of proved plus probable cash flows from an independent reserve report prepared as at December 31, 2020 and was adjusted by management for operations between December 31, 2020 and June 30, 2021. The after-tax discount rates applied to the cash flows were between 10% and 16%.
At June 30, 2021, the recoverable amount of the Company's CGUs were calculated using the following benchmark reference prices for the years 2021 to 2030 adjusted for commodity differentials specific to the Company. The prices and costs subsequent to 2030 have been adjusted for inflation at an annual rate of 2.0%.
| 2021 | 2022 | 2023 | 2024 | 2025 | 2026 | 2027 | 2028 | 2029 | 2030 | |||||||||||
| WTI crude oil (US$/bbl) | 71.33 | 67.20 | 63.95 | 63.23 | 64.50 | 65.79 | 67.10 | 68.44 | 69.81 | 71.21 | ||||||||||
| WCS heavy oil (CA$/bbl) | 72.22 | 66.84 | 61.73 | 60.70 | 61.91 | 63.15 | 64.42 | 65.70 | 67.02 | 68.36 | ||||||||||
| LLS crude oil (US$/bbl) | 72.17 | 68.53 | 65.80 | 65.10 | 66.39 | 67.71 | 69.05 | 70.42 | 71.82 | 73.26 | ||||||||||
| Edmonton par oil (CA$/bbl) | 83.20 | 78.27 | 74.06 | 73.05 | 74.51 | 76.00 | 77.52 | 79.07 | 80.66 | 82.27 | ||||||||||
| Henry Hub gas (US$/mmbtu) | 3.42 | 3.19 | 2.92 | 2.96 | 3.02 | 3.08 | 3.14 | 3.21 | 3.27 | 3.34 | ||||||||||
| AECO gas (CA$/mmbtu) | 3.46 | 3.13 | 2.72 | 2.71 | 2.76 | 2.82 | 2.88 | 2.94 | 2.99 | 3.05 | ||||||||||
| Exchange rate (CAD/USD) | 1.24 | 1.25 | 1.25 | 1.25 | 1.25 | 1.25 | 1.25 | 1.25 | 1.25 | 1.25 |
| Baytex Energy Corp. Third Quarter Report 2021 | 45 | |
The following table summarizes the recoverable amount and impairment reversal at June 30, 2021 and demonstrates the sensitivity of the estimated recoverable amount of the Company's CGUs comprising oil and gas properties to reasonably possible changes in key assumptions inherent in the estimate.
| Recoverable | Impairment | Change in discount | Change in oil price | Change in gas | ||||||||||||||||
| amount | reversal | rate of 1% | of $2.50/bbl | price of $0.25/mcf | ||||||||||||||||
| Conventional CGU | $ | 57,891 | $ | 15,000 | $ | 1,000 | $ | 1,000 | $ | 8,000 | ||||||||||
| Peace River CGU | 238,714 | 154,000 | 4,000 | 40,000 | 2,500 | |||||||||||||||
| Lloydminster CGU | 340,730 | 154,000 | 12,500 | 52,000 | - | |||||||||||||||
| Duvernay CGU (1) | 115,157 | 5,000 | 45,000 | 44,500 | 44,500 | |||||||||||||||
| Viking CGU | 1,338,985 | 356,000 | 47,000 | 89,500 | 4,500 | |||||||||||||||
| Eagle Ford CGU | 2,015,118 | 442,415 | 109,400 | 103,900 | 24,400 | |||||||||||||||
| $ | 4,106,595 | $ | 1,126,415 | $ | 218,900 | $ | 330,900 | $ | 83,900 |
(1) The impairment reversal for the Duvernay CGU was limited to total accumulated impairments less subsequent depletion of $5.0 million.
2020 Impairments
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 $2.6 billion recorded at March 31, 2020. The recoverable amount of each CGU was based on its FVLCD which was estimated using a discounted cash flow model of proved plus probable cash flows from an independent reserve report prepared as at December 31, 2019 and was adjusted for operations between December 31, 2019 and March 31, 2020. The after-tax discount rates applied to the cash flows were between 8% and 14%.
At March 31, 2020, the recoverable amount of the Company's CGUs were calculated using the following benchmark reference prices for the years 2020 to 2029 adjusted for commodity differentials specific to the Company. The prices and costs subsequent to 2029 have been adjusted for inflation at an annual rate of 2%.
| 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | 2026 | 2027 | 2028 | 2029 | |||||||||||
| WTI crude oil (US$/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 |
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 | Change in discount | Change in oil price | Change in gas | |||||||||||||||||
| amount | Impairment loss | rate of 1% | of $2.50/bbl | 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 |
| 46 | Baytex Energy Corp. Third Quarter Report 2021 | |
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 $341.3 million recorded at December 31, 2020. The recoverable amount for each CGU was based on its FVLCD which was estimated using a discounted cash flow model of proved plus probable cash flows from an independent reserve report prepared as at December 31, 2020. The after-tax discount rates applied to the cash flows were between 10% and 17%.
At December 31, 2020, the recoverable amount of the Company's CGUs were calculated using the following benchmark reference prices for the years 2021 to 2030 adjusted for commodity differentials specific to the Company. The prices and costs subsequent to 2030 have been adjusted for inflation at an annual rate of 2%.
| 2021 | 2022 | 2023 | 2024 | 2025 | 2026 | 2027 | 2028 | 2029 | 2030 | |||||||||||
| WTI crude oil (US$/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 | Impairment | Change in discount | Change in oil price | Change in gas | ||||||||||||||||
| amount | reversal | rate of 1% | of $2.50/bbl | 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 |
6. CREDIT FACILITIES
| September 30, 2021 | December 31, 2020 | |||||||
| Credit facilities - U.S. dollar denominated (1) | $ | 239,433 | $ | 140,815 | ||||
| Credit facilities - Canadian dollar denominated | 307,370 | 510,358 | ||||||
| Credit facilities - principal | 546,803 | 651,173 | ||||||
| Unamortized debt issuance costs | (1,501 | ) | (1,952 | ) | ||||
| Credit facilities | $ | 545,302 | $ | 649,221 |
(1) U.S. dollar denominated credit facilities balance was US$188.0 million as at September 30, 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"). The Credit Facilities mature on April 2, 2024 and 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.
| Baytex Energy Corp. Third Quarter Report 2021 | 47 | |
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.
The weighted average interest rate on the Credit Facilities was 2.2% for the nine months ended September 30, 2021 (2.5% for nine months ended September 30, 2020).
At September 30, 2021, Baytex had $15.0 million of outstanding letters of credit (December 31, 2020 - $15.0 million) under the Credit Facilities.
At September 30, 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 September 30, 2021.
| Position as at | ||||||||
| Covenant Description | September 30, 2021 | Covenant | ||||||
| Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio) | 0.8:1.0 | 3.5:1.0 | ||||||
| Interest Coverage (3) (Minimum Ratio) | 7.4:1.0 | 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 September 30, 2021, the Company's Senior Secured Debt totaled $561.8 million which included $546.8 million of principal amounts outstanding and $15.0 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 September 30, 2021 was $708.4 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 September 30, 2021 was $95.7 million. |
7. LONG-TERM NOTES
| September 30, 2021 | December 31, 2020 | |||||||
| 5.625% notes (US$284,478 - principal) due June 1, 2024 | $ | 362,696 | $ | 510,200 | ||||
| 8.75% notes (US$500,000 - principal) due April 1, 2027 | 637,475 | 637,750 | ||||||
| Total long-term notes - principal (1) | 1,000,171 | 1,147,950 | ||||||
| Unamortized debt issuance costs | (12,946 | ) | (15,082 | ) | ||||
| Total long-term notes - net of unamortized debt issuance costs | $ | 987,225 | $ | 1,132,868 |
| (1) | The decrease in the principal amount of long-term notes outstanding from December 31, 2020 to September 30, 2021 is the result of principal repayments of $145.0 million and changes in the reported amount of U.S. denominated debt of $2.7 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.
During the nine months ended September 30, 2021, Baytex repurchased and cancelled principal notes totaling US$115.5 million of the 5.625% Notes and recorded early redemption expense of $0.9 million and an increase to unamortized debt issuance costs of $0.7 million. Subsequent to September 30, 2021, Baytex repurchased and cancelled US$84.5 million principal amount of the 5.625% Notes due 2024 at the call price of 100.938%, plus accrued interest, effective October 29, 2021. As at November 4, 2021, there was a total of US$200.0 million of the 5.625% Notes that remained outstanding.
| 48 | Baytex Energy Corp. Third Quarter Report 2021 | |
| 8. | ASSET RETIREMENT OBLIGATIONS |
| September 30, 2021 | December 31, 2020 | |||||||
| Balance, beginning of period | $ | 760,383 | $ | 667,974 | ||||
| Liabilities incurred | 10,744 | 15,189 | ||||||
| Liabilities settled | (4,215 | ) | (7,168 | ) | ||||
| Liabilities acquired from property acquisitions | 131 | - | ||||||
| Liabilities divested | (2,900 | ) | (721 | ) | ||||
| Property swaps | (4,421 | ) | (525 | ) | ||||
| Accretion (note 14) | 8,938 | 8,978 | ||||||
| Government grants (1) | (2,108 | ) | (2,128 | ) | ||||
| Change in estimate | 991 | (12,771 | ) | |||||
| Changes in discount rates and inflation rates (2) | (71,074 | ) | 92,576 | |||||
| Foreign currency translation | (59 | ) | (1,021 | ) | ||||
| Balance, end of period | $ | 696,410 | $ | 760,383 | ||||
| Less current portion of asset retirement obligations | 11,719 | 11,820 | ||||||
| Non-current portion of asset retirement obligations | $ | 684,691 | $ | 748,563 |
| (1) | During the nine months ended September 30, 2021, Baytex recognized $2.1 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 September 30, 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 September 30, 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 | 2,986 | 7,175 | ||||||
| Balance, September 30, 2021 | 564,213 | $ | 5,736,593 |
| 10. | SHARE AWARD INCENTIVE PLAN |
For the three and nine months ended September 30, 2021 the Company recorded total compensation expense related to the share awards of $2.5 million and $8.3 million respectively ($2.9 million and $8.7 million for the three and nine months ended September 30, 2020). Included in compensation expense related to share awards for the three and nine months ended September 30, 2021 is $1.1 million and $3.7 million of cash compensation expense related to the incentive award plan, deferred share unit plan and the associated equity total return swaps ($0.6 million and $1.8 million for the three and nine months ended September 30, 2020).
| Baytex Energy Corp. Third Quarter Report 2021 | 49 | |
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 $1.30 per restricted and performance award for the nine months ended September 30, 2021 ($1.48 per restricted and performance award for the nine months ended September 30, 2020).
The number of share awards outstanding is detailed below:
| (000s) |
Number of |
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 | - | 4,723 | 4,723 | |||||||||
| Vested and converted to common shares | (1,861 | ) | (1,152 | ) | (3,013 | ) | ||||||
| Forfeited | (128 | ) | (208 | ) | (336 | ) | ||||||
| Balance, September 30, 2021 | 2,133 | 7,451 | 9,584 |
| (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 nine months ended September 30, 2021, Baytex granted 5.0 million awards under the Incentive Award plan at a weighted average fair value of $1.32 per award (2.9 million awards granted at a fair value of $1.50 per incentive award for the nine months ended September 30, 2020). At September 30, 2021 there were 6.6 million awards outstanding under the Incentive Award plan.
Deferred Share Unit Plan
Baytex has a deferred share unit plan (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 nine months ended September 30, 2021, Baytex granted 0.9 million awards under the DSU plan at a fair value of $1.29 per award. At September 30, 2021, there were 0.8 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 an asset of $7.0 million at September 30, 2021 (December 31, 2020 - liability of $1.1 million).
| 11. | NET INCOME (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.
| 50 | Baytex Energy Corp. Third Quarter Report 2021 | |
| Three Months Ended September 30 | ||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||
| Net income |
Weighted average common shares (000s) |
Net income per share | Net loss |
Weighted average common shares (000s) |
Net loss per share | |||||||||||||||||||
| Net income (loss) - basic | $ | 32,713 | 564,211 | $ | 0.06 | $ | (23,444 | ) | 561,128 | $ | (0.04 | ) | ||||||||||||
| Dilutive effect of share awards | - | 7,436 | - | - | - | - | ||||||||||||||||||
| Net income (loss) - diluted | $ | 32,713 | 571,647 | $ | 0.06 | $ | (23,444 | ) | 561,128 | $ | (0.04 | ) |
| Nine Months Ended September 30 | ||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||
| Net income |
Weighted average common shares (000s) |
Net income per share | Net loss |
Weighted average common shares (000s) |
Net loss per share | |||||||||||||||||||
| Net income (loss) - basic | $ | 1,050,361 | 563,492 | $ | 1.86 | $ | (2,660,124 | ) | 560,484 | $ | (4.75 | ) | ||||||||||||
| Dilutive effect of share awards | - | 6,687 | - | - | - | - | ||||||||||||||||||
| Net income (loss) - diluted | $ | 1,050,361 | 570,179 | $ | 1.84 | $ | (2,660,124 | ) | 560,484 | $ | (4.75 | ) |
For the three and nine months ended September 30, 2021, no share awards were excluded from the calculation of diluted income per share as their effect was dilutive. For the three and nine months ended September 30, 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 September 30 | ||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||
| Canada | U.S. | Total | Canada | U.S. | Total | |||||||||||||||||||
| Light oil and condensate | $ | 124,930 | $ | 154,511 | $ | 279,441 | $ | 78,432 | $ | 75,620 | $ | 154,052 | ||||||||||||
| Heavy oil | 146,468 | - | 146,468 | 69,791 | - | 69,791 | ||||||||||||||||||
| NGL | 4,177 | 22,932 | 27,109 | 1,762 | 8,914 | 10,676 | ||||||||||||||||||
| Natural gas sales | 17,148 | 18,570 | 35,718 | 8,846 | 9,173 | 18,019 | ||||||||||||||||||
| Total petroleum and natural gas sales | $ | 292,723 | $ | 196,013 | $ | 488,736 | $ | 158,831 | $ | 93,707 | $ | 252,538 |
| Nine Months Ended September 30 | ||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||
| Canada | U.S. | Total | Canada | U.S. | Total | |||||||||||||||||||
| Light oil and condensate | $ | 342,744 | $ | 418,498 | $ | 761,242 | $ | 229,745 | $ | 257,818 | $ | 487,563 | ||||||||||||
| Heavy oil | 385,288 | - | 385,288 | 169,638 | - | 169,638 | ||||||||||||||||||
| NGL | 12,327 | 52,870 | 65,197 | 3,957 | 25,791 | 29,748 | ||||||||||||||||||
| Natural gas sales | 45,812 | 58,253 | 104,065 | 23,660 | 31,232 | 54,892 | ||||||||||||||||||
| Total petroleum and natural gas sales | $ | 786,171 | $ | 529,621 | $ | 1,315,792 | $ | 427,000 | $ | 314,841 | $ | 741,841 |
Included in accounts receivable at September 30, 2021 is $160.2 million of accrued production revenue related to delivered volumes (December 31, 2020 - $81.3 million).
| Baytex Energy Corp. Third Quarter Report 2021 | 51 | |
| 13. | INCOME TAXES |
The provision for income taxes has been computed as follows:
| Nine Months Ended September 30 | ||||||||
| 2021 | 2020 | |||||||
| Net income (loss) before income taxes | $ | 1,123,218 | $ | (2,920,725 | ) | |||
| Expected income taxes at the statutory rate of 25.12% (2020 - 25.95%) | 282,152 | (757,928 | ) | |||||
| (Increase) decrease in income tax recovery resulting from: | ||||||||
| Share-based compensation | 1,156 | 1,809 | ||||||
| Effect of foreign exchange | (292 | ) | 5,022 | |||||
| Effect of change in income tax rates | (65 | ) | 22,231 | |||||
| Effect of rate adjustments for foreign jurisdictions | (19,751 | ) | 35,982 | |||||
| Effect of change in deferred tax benefit not recognized | (191,611 | ) | 409,717 | |||||
| Effect of U.S. tax change | - | 19,996 | ||||||
| Adjustments and assessments | 1,268 | 2,570 | ||||||
| Income tax expense (recovery) | $ | 72,857 | $ | (260,601 | ) |
At September 30, 2021, a deferred tax asset of $279.2 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 September 30 | Nine Months Ended September 30 | |||||||||||||||
| 2021 | 2020 | 2021 | 2020 | |||||||||||||
| Interest on credit facilities | $ | 3,256 | $ | 3,366 | $ | 9,842 | $ | 11,749 | ||||||||
| Interest on long-term notes | 19,481 | 21,943 | 60,734 | 69,231 | ||||||||||||
| Interest on lease obligations | 56 | 109 | 174 | 360 | ||||||||||||
| Non-cash financing | 1,733 | 756 | 3,272 | 5,863 | ||||||||||||
| Accretion on asset retirement obligations (note 8) | 3,273 | 1,788 | 8,938 | 6,897 | ||||||||||||
| Early redemption expense (note 7) | 1,229 | - | 872 | 3,312 | ||||||||||||
| Financing and interest | $ | 29,028 | $ | 27,962 | $ | 83,832 | $ | 97,412 |
| 15. | FOREIGN EXCHANGE |
| Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||
| 2021 | 2020 | 2021 | 2020 | |||||||||||||
| Unrealized foreign exchange (gain) loss - intercompany notes (1) | $ | (25,909 | ) | $ | (11,115 | ) | $ | 411 | $ | (11,115 | ) | |||||
| Unrealized foreign exchange loss (gain) - long-term notes & credit facilities | 33,454 | (14,765 | ) | 2,812 | 39,240 | |||||||||||
| Realized foreign exchange gain | (79 | ) | (351 | ) | (818 | ) | (437 | ) | ||||||||
| Foreign exchange loss (gain) | $ | 7,466 | $ | (26,231 | ) | $ | 2,405 | $ | 27,688 |
| (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. |
| 52 | Baytex Energy Corp. Third 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:
| September 30, 2021 | December 31, 2020 | |||||||||||||||||||
| Carrying value | Fair value | Carrying value | Fair value |
Fair Value Measurement Hierarchy | ||||||||||||||||
| Financial Assets | ||||||||||||||||||||
| FVTPL | ||||||||||||||||||||
| Financial derivatives | $ | 7,040 | $ | 7,040 | $ | 5,057 | $ | 5,057 | Level 2 | |||||||||||
| Total | $ | 7,040 | $ | 7,040 | $ | 5,057 | $ | 5,057 | ||||||||||||
| Financial assets at amortized cost | ||||||||||||||||||||
| Trade and other receivables | $ | 177,546 | $ | 177,546 | $ | 107,477 | $ | 107,477 | - | |||||||||||
| Total | $ | 177,546 | $ | 177,546 | $ | 107,477 | $ | 107,477 | ||||||||||||
| Financial Liabilities | ||||||||||||||||||||
| FVTPL | ||||||||||||||||||||
| Financial derivatives | $ | (208,183 | ) | $ | (208,183 | ) | $ | (26,792 | ) | $ | (26,792 | ) | Level 2 | |||||||
| Total | $ | (208,183 | ) | $ | (208,183 | ) | $ | (26,792 | ) | $ | (26,792 | ) | ||||||||
| Financial liabilities at amortized cost | ||||||||||||||||||||
| Trade and other payables | $ | (195,230 | ) | $ | (195,230 | ) | $ | (155,955 | ) | $ | (155,955 | ) | - | |||||||
| Credit facilities | (545,302 | ) | (546,803 | ) | (649,221 | ) | (651,173 | ) | - | |||||||||||
| Long-term notes | (987,225 | ) | (1,027,213 | ) | (1,132,868 | ) | (761,129 | ) | Level 1 | |||||||||||
| Total | $ | (1,727,757 | ) | $ | (1,769,246 | ) | $ | (1,938,044 | ) | $ | (1,568,257 | ) |
There were no transfers between Level 1 and Level 2 during the nine months ended September 30, 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 | |||||||||||||||
| September 30, 2021 | December 31, 2020 | September 30, 2021 | December 31, 2020 | |||||||||||||
| U.S. dollar denominated | US$ | 750,431 | US$ | 759,508 | US$ | 1,132,170 | US$ | 934,731 |
| Baytex Energy Corp. Third Quarter Report 2021 | 53 | |
Commodity Price Risk
Financial Derivative Contracts
Baytex had the following financial derivative contracts outstanding as of November 4, 2021:
| Remaining Period | Volume | Price/Unit (1) | Index | |||||||||||
| Oil | ||||||||||||||
| Basis Swap | Oct 2021 to Dec 2021 | 8,000 bbl/d | WTI less US$13.41/bbl | WCS | ||||||||||
| Basis Swap | Jan 2022 to Dec 2022 | 12,000 bbl/d | WTI less US$12.40/bbl | WCS | ||||||||||
| Basis Swap | Oct 2021 to Dec 2021 | 7,500 bbl/d | WTI less US$5.03/bbl | MSW | ||||||||||
| Basis Swap | Jan 2022 to Dec 2022 | 4,000 bbl/d | WTI less US$4.43/bbl | MSW | ||||||||||
| Fixed Sell | Oct 2021 to Dec 2021 | 4,000 bbl/d | US$45.00/bbl | WTI | ||||||||||
| 3-way option (2) | Oct 2021 to Dec 2021 | 500 bbl/d | US$35.00/US$45.00/US$49.03 | WTI | ||||||||||
| 3-way option (2) | Oct 2021 to Dec 2021 | 1,500 bbl/d | US$35.00/US$45.00/US$49.10 | WTI | ||||||||||
| 3-way option (2) | Oct 2021 to Dec 2021 | 3,500 bbl/d | US$35.00/US$45.00/US$49.50 | WTI | ||||||||||
| 3-way option (2) | Oct 2021 to Dec 2021 | 10,000 bbl/d | US$35.00/US$45.00/US$55.00 | WTI | ||||||||||
| 3-way option (2) | Oct 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) | Jan 2022 to Dec 2022 | 2,500 bbl/d | US$47.00/US$57.00/US$67.00 | WTI | ||||||||||
| 3-way option (2) | Jan 2022 to Dec 2022 | 2,500 bbl/d | US$50.00/US$60.00/US$70.00 | WTI | ||||||||||
| 3-way option (2) | Jan 2022 to Dec 2022 | 2,000 bbl/d | US$53.00/US$63.50/US$72.90 | WTI | ||||||||||
| 3-way option (2)(4) | Jan 2023 to Dec 2023 | 2,000 bbl/d | US$55.00/US$66.00/US$84.00 | 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 | Oct 2021 to Dec 2021 | 16,000 GJ/d | $2.36/GJ | AECO 7A | ||||||||||
| Fixed Sell | Jan 2022 to Dec 2022 | 5,000 GJ/d | $2.53/GJ | AECO 7A | ||||||||||
| Fixed Sell | Oct 2021 to Dec 2021 | 2,500 GJ/d | $2.40/GJ | AECO 5A | ||||||||||
| Fixed Sell | Jan 2022 to Dec 2022 | 14,250 GJ/d | $2.84/GJ | AECO 5A | ||||||||||
| Fixed Sell | Oct 2021 to Dec 2021 | 12,000 mmbtu/d | US$2.70/mmbtu | NYMEX | ||||||||||
| Fixed Sell | Jan 2022 to Dec 2022 | 1,000 mmbtu/d | US$2.94/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 | 1,500 mmbtu/d | US$2.60/US$2.91/US$3.56 | NYMEX | ||||||||||
| 3-way option (2) | Jan 2022 to Dec 2022 | 2,500 mmbtu/d | US$2.60/US$3.00/US$3.83 | NYMEX | ||||||||||
| 3-way option (2) | Jan 2022 to Dec 2022 | 2,500 mmbtu/d | US$2.65/US$2.90/US$3.40 | NYMEX | ||||||||||
| 3-way option (2) | Jan 2022 to Dec 2022 | 2,500 mmbtu/d | US$3.00/US$3.75/US$4.40 | 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$50.00/US$60.00/US$70.00 contract, Baytex receives WTI plus US$10.00/bbl when WTI is at or below US$50.00/bbl; Baytex receives US$60.00/bbl when WTI is between US$50.00/bbl and US$60.00/bbl; Baytex receives the market price when WTI is between US$60.00/bbl and US$70.00/bbl; and Baytex receives US$70.00/bbl when WTI is above US$70.00/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 September 30, 2021. |
The following table sets forth the realized and unrealized gains and losses recorded on financial derivatives.
| Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||
| 2021 | 2020 | 2021 | 2020 | |||||||||||||
| Realized financial derivatives loss (gain) | $ | 53,905 | $ | 9,743 | $ | 113,697 | $ | (30,731 | ) | |||||||
| Unrealized financial derivatives loss (gain) | 8,941 | 7,284 | 179,408 | (19,425 | ) | |||||||||||
| Financial derivatives loss (gain) | $ | 62,846 | $ | 17,027 | $ | 293,105 | $ | (50,156 | ) |
| 54 | Baytex Energy Corp. Third Quarter Report 2021 | |
ABBREVIATIONS
| AECO | the natural gas storage facility located at Suffield, Alberta |
| bbl | barrel |
| bbl/d | barrel per day |
| boe* | barrels of oil equivalent |
| boe/d | barrels of oil equivalent per day |
| COSO | Committee of Sponsoring Organizations of the Treadway Commission |
| GAAP | generally accepted accounting principles |
| GJ | gigajoule |
| GJ/d | gigajoule per day |
| IAS | International Accounting Standard |
| IASB | International Accounting Standards Board |
| IFRS | International Financial Reporting Standards |
| LLS | Louisiana Light Sweet |
| mbbl | thousand barrels |
| mboe* | thousand barrels of oil equivalent |
| mcf | thousand cubic feet |
| mcf/d | thousand cubic feet per day |
| mmBtu | million British Thermal Units |
| mmBtu/d | million British Thermal Units per day |
| mmcf | million cubic feet |
| mmcf/d | million cubic feet per day |
| NGL | natural gas liquids |
| NYMEX | New York Mercantile Exchange |
| NYSE | New York Stock Exchange |
| TSX | Toronto Stock Exchange |
| WCS | Western Canadian Select |
| WTI | West 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. |
| Baytex Energy Corp. Third Quarter Report 2021 | 55 | |
CORPORATE INFORMATION
| BOARD OF DIRECTORS | OFFICERS |
| Mark R. Bly | Edward D. LaFehr |
| Chair of the Board | President and Chief Executive Officer |
| Edward D. LaFehr | Rodney D. Gray |
| Director | Executive Vice President and Chief Financial Officer |
| Trudy M. Curran(2)(4) | Chad E. Lundberg |
| Director | Chief Operating and Sustainability Officer |
| Don G. Hrap(1)(3) | Brian G. Ector |
| Director | Vice President, Capital Markets |
| Jennifer A. Maki(1)(2) | Kendall D. Arthur |
| Director | Vice President, Heavy Oil |
| Gregory K. Melchin(1)(4) | Chad L. Kalmakoff |
| Director | Vice President, Finance |
| David L. Pearce(2)(3) | Scott Lovett |
| Director | Vice President, Corporate Development |
| Steve D.L. Reynish(3)(4) | AUDITORS |
| Director | KPMG LLP |
| (1) Member of the Audit Committee | RESERVES ENGINEERS |
| (2) Member of the Human Resources and Compensation Committee | McDaniel & Associates Consultants |
| (3) Member of the Reserves and Sustainability Committee | |
| (4) Member of the Nominating and Governance Committee | TRANSFER AGENT |
| Odyssey Trust Company | |
| HEAD OFFICE | EXCHANGE LISTING |
|
Baytex Energy Corp. Centennial Place, East Tower 2800, 520 - 3rd Avenue SW Calgary, Alberta T2P 0R3 Toll-free: 1-800-524-5521 | Toronto Stock Exchange Symbol: BTE |
| T: 587-952-3000 | |
| F: 587-952-3001 |
www.baytexenergy.com
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Baytex Energy Corp. published this content on 08 November 2021 and is solely responsible for the information contained therein. Distributed by Public, unedited and unaltered, on 08 November 2021 17:57:05 UTC.
