Baytex Energy Corp.
Q1 2020 MD&A 1
Exhibit 99.2
BAYTEX ENERGY CORP.
Management’s Discussion and Analysis
For the three months ended March 31, 2020 and 2019
Dated May 7, 2020
The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three months ended March 31, 2020. This information is provided as of May 7, 2020. In this MD&A, references to “Baytex”, the “Company”, “we”, “us” and “our” and similar terms refer to Baytex Energy Corp. and its subsidiaries on a consolidated basis, except where the context requires otherwise. The results for the three months ended March 31, 2020 ("Q1/2020") have been compared with the results for the three months ended March 31, 2019 ("Q1/2019"). This MD&A should be read in conjunction with the Company’s condensed consolidated interim financial statements (“consolidated financial statements”) for the three months ended March 31, 2020, its audited comparative consolidated financial statements for the years ended December 31, 2019 and 2018, together with the accompanying notes, and its Annual Information Form for the year ended December 31, 2019. 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.
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", "net debt", and "Bank EBITDA" do not have any standardized meaning as prescribed by GAAP and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. We refer you to our advisory on forward-looking information and statements and a summary of our non-GAAP measures at the end of the MD&A.
BAYTEX ENERGY CORP.
Baytex Energy Corp. is a North American focused oil and gas company based in Calgary, Alberta. The company operates in Canada and the United States. 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.
CURRENT ENVIRONMENT
In March 2020, the World Health Organization declared a global pandemic related to the novel coronavirus ("COVID-19"). The emergence of COVID-19 and the steps taken by governments to control the spread of the virus has resulted in significant instability of the global economy. The oil and gas industry has been severely impacted as actions taken to limit the spread of COVID-19 have resulted in a sharp decline in demand for crude oil. This combined with the increased supply of crude oil due to the Russia and Saudi Arabia price war has resulted in an unprecedented collapse in global crude oil prices.
We have taken significant action in response to the uncertain outlook for our industry. With the health and safety of our personnel at the forefront, we have transitioned to a work-from-home program, where possible, that ensures the continuity of business as the COVID-19 pandemic evolves. In March, we established a COVID-19 response team to coordinate, establish and implement our response measures. We have restricted travel, adjusted work schedules and continue to adhere to recommendations from government and public health agencies. We have also taken steps to preserve our financial liquidity during this time of heightened uncertainty. We have taken action to achieve $135 million of cost reductions for 2020 relating to operating, transportation and general and administrative expenses. This includes a 10 percent reduction in salaries for all full time employees and a reduction of annual retainers paid to our directors effective April 1, 2020. Our 2020 exploration and development expenditures have been reduced with a suspension of drilling operations in Canada and a moderated pace of development in the U.S. We have also shut-in low or negative margin production and have the ability to shut-in additional volumes or quickly restart production in response to further changes in the commodity price environment.
The global health crisis surrounding COVID-19 has impacted our results for Q1/2020 and has resulted in heightened uncertainty regarding the outlook and future performance of our business. We do not know the extent and duration to which COVID-19 will impact the demand and price for oil. The overall effect on our business will depend on how quickly the world economy resumes activity which is highly dependent on the progression of the pandemic and the success of measures taken to prevent its spread.
We are expecting compliance with the financial covenants applicable to our credit facilities for at least the next twelve months. A decrease or a sustained period of low commodity prices may result in non-compliance with our financial covenants and reduced liquidity on our existing credit facilities. Non-compliance with the financial covenants in our credit facilities could result in our debt
Baytex Energy Corp.
Q1 2020 MD&A 2
becoming due and payable on demand. Should we anticipate non-compliance we will pro-actively approach our lending syndicate to amend the credit facilities to ensure their availability. There is no certainty that we will be successful in negotiating such amendments.
FIRST QUARTER HIGHLIGHTS
We had strong operating results for Q1/2020 despite the impact of COVID-19. We invested $176.8 million on exploration and development expenditures, generated production of 98,452 boe/d and adjusted funds flow of $132.9 million. Capital spending and production were reduced for Q1/2020 in response to the sharp decline in crude oil prices due to the COVID-19 health crisis and the OPEC+ price war. The decline in crude oil prices also resulted in an impairment being recorded in Q1/2020 which impacted our earnings. We also took significant actions to improve our financial liquidity with the issuance of senior notes due 2027 and extending the maturity date of our credit facilities to 2024.
Proceeds from the issuance of senior notes were used in conjunction with availability on our credit facilities to complete the early redemption of the US$400 million principal amount of 5.125% senior notes due in 2021 and the early redemption of the $300 million principal amount of 6.625% senior notes due in 2022. As a result of these actions we do not have any debt maturities until 2024 and we maintained over $400 million undrawn capacity on our credit facilities at March 31, 2020.
In Canada, production was 62,262 boe/d for Q1/2020 which is 4% higher than 60,018 boe/d in Q1/2019 and reflects our successful capital program. Exploration and development expenditures of $123.1 million in Q1/2020 were primarily focused on our Viking light oil property along with additional heavy oil development at Lloydminster and Peace River. Exploration and development expenditures included costs associated with drilling 72 (69.2 net) light oil wells in the Viking, 2 (2.0 net) light oil wells in the Duvernay and 33 (33.0 net) heavy oil wells during Q1/2020.
In the U.S., we invested $53.7 million on exploration and development activity during Q1/2020 and drilled 17 (3.8 net) wells and commenced production from 30 (6.1 net) wells. Production was 36,190 boe/d for Q1/2020 and reflects lower completion activity on our lands relative to Q1/2019 when production was 41,097 boe/d and we commenced production from 36 (8.9 net) wells.
Commodity prices were relatively strong as Q1/2020 began with the West Texas Intermediate ("WTI") benchmark price averaging US$57.53/bbl in January. Decisions made by the leaders of Saudi Arabia and Russia to increase production of crude oil as demand was falling due to the spread of COVID-19 resulted in a sharp decline in global crude oil prices with WTI averaging US$30.45/bbl in March. As a result the WTI benchmark price averaged US$46.17/bbl for Q1/2020 compared to US$54.90/bbl during Q1/2019.
Adjusted funds flow was $132.9 million in Q1/2020 compared to $220.8 million for Q1/2019. Strong production results in Q1/2020 were overshadowed by the beginning of an unprecedented decline in crude oil prices which was the key factor contributing to a $98.0 million decrease in operating netback relative to Q1/2019. Partially offsetting the decline in operating netback was a $4.4 million reduction in general administrative expenses along with an $8.0 million increase in realized gains on financial derivatives in Q1/2020 compared to Q1/2019.
In Q1/2020 we reported a net loss of $2.5 billion compared to net income of $11.3 million in Q1/2019. The net loss recorded for Q1/2020 includes impairment expense of $2.7 billion which is directly attributable to the significant decline in forecasted prices for crude oil at March 31, 2020 relative to December 31, 2019.
Net debt was $2.1 billion at March 31, 2020 compared to $1.9 billion at December 31, 2019. The increase in net debt is primarily the result of a $110.7 million increase in the reported amount of our U.S. dollar denominated net debt due to a weaker Canadian dollar at March 31, 2020 along with exploration and development expenditures that exceeded adjusted funds flow by $43.8 million.
2020 GUIDANCE
We have updated our production and cost assumptions to reflect the impact of voluntarily shutting-in approximately 25,000 boe/d of production. At current commodity prices, we expect the majority of shut-in volumes to remain off-line for the balance of this year. The shut-in of these barrels is expected to have a positive impact on our adjusted funds flow and improve our financial liquidity.
We continue to emphasize cost reductions across all facets of our organization. On a per unit basis, our operating expense guidance is unchanged as we drive further efficiencies in our business to mitigate the fixed costs associated with our field operations. In addition, we are realizing an approximate 25% reduction in transportation expenses due to reduced volumes.
We are reducing our general and administrative expense guidance by 11% to $40 million. As a continued cost control measure, all full-time employee salaries and all annual retainers paid to our directors were reduced by 10% effective April 1, 2020.
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Q1 2020 MD&A 3
The following table compares our updated 2020 guidance to our previously announced guidance and our Q1/2020 results.
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| Previous Annual Guidance (1) | Revised Annual Guidance | Q1/2020 Results |
| Exploration and development expenditures ($ millions) | $260 - $290 | no change | $176.8 |
| Production (boe/d) | 85,000 - 89,000 | 70,000 - 74,000 | 98,452 | |
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| Expenses: | | | |
| Royalty rate (%) | 19.0 - 19.5 | ~20.0 | 18.0 | |
| Operating ($/boe) | $11.75 - $12.50 | no change | $11.66 |
| Transportation ($/boe) | $1.10 - $1.20 | $0.80 - $0.90 | $1.15 |
| General and administrative ($ millions) | $45 ($1.42/boe) | $40 ($1.52/boe) | $9.8 ($1.09/boe) |
| Cash interest ($ millions) | $115 ($3.62/boe) | $120 ($4.57/boe) | $28.5 ($3.19/boe) |
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| Leasing expenditures ($ millions) | $7 | no change | $1.5 |
| Asset retirement obligations ($ millions) | $10 | no change | $4.2 |
(1)As announced on March 18, 2020.
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
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| Three Months Ended March 31 | | | | | |
| 2020 | | | 2019 | | |
| Canada | | U.S. | | Total | Canada | | U.S. | | Total | |
| Daily Production | | | | | | |
| Liquids (bbl/d) | | | | | | |
| Light oil and condensate | 24,241 | | 21,476 | | 45,717 | | 23,295 | | 21,753 | | 45,048 | |
| Heavy oil | 28,854 | | — | | 28,854 | | 26,891 | | — | | 26,891 | |
| Natural Gas Liquids (NGL) | 1,317 | | 6,505 | | 7,822 | | 1,608 | | 10,121 | | 11,729 | |
| Total liquids (bbl/d) | 54,412 | | 27,981 | | 82,393 | | 51,794 | | 31,874 | | 83,668 | |
| Natural gas (mcf/d) | 47,100 | | 49,256 | | 96,356 | | 49,346 | | 55,336 | | 104,682 | |
| Total production (boe/d) | 62,262 | | 36,190 | | 98,452 | | 60,018 | | 41,097 | | 101,115 | |
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| Production Mix | | | | | | |
| Light oil and condensate | 39 | % | 59 | % | 46 | % | 39 | % | 53 | % | 45 | % |
| Heavy oil | 46 | % | — | % | 29 | % | 45 | % | — | % | 27 | % |
| NGL | 2 | % | 18 | % | 8 | % | 3 | % | 25 | % | 12 | % |
| Natural gas | 13 | % | 23 | % | 17 | % | 13 | % | 22 | % | 16 | % |
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Production of 98,452 boe/d for Q1/2020 reflects strong operational performance in the U.S. and Canada. Production results were in line with our expectations prior to suspending our Canadian capital program and shutting-in production in response to the sharp decline in global crude oil prices in March. In mid-March we began shutting-in low or negative margin production which had a minimal impact on reported production for Q1/2020. With the extreme volatility in oil prices, we are making decisions to produce or shut-in volumes on a month-to-month basis. While we expect our production to be lower for the remainder of 2020 we have the ability to quickly restore production from shut-in wells when commodity prices are supportive. These actions are reflected in our revised annual guidance range of 70,000 - 74,000 boe/d for 2020.
In Canada, production was 62,262 boe/d for Q1/2020 compared to 60,018 boe/d in Q1/2019. The increase in production in Q1/2020 relative to Q1/2019 is primarily due to strong well performance from our development program. We were more active on our Canadian properties coming into Q1/2020 relative to Q1/2019 when our activity was reduced in response to a significant widening of Canadian light and heavy oil differentials in Q4/2018.
Baytex Energy Corp.
Q1 2020 MD&A 4
Production in the U.S. was 36,190 boe/d for Q1/2020 compared to 41,097 boe/d for Q1/2019. U.S. production for Q1/2020 was lower than for Q1/2019 due to lower completion activity on our lands relative to the same period of 2019. We initiated production from 30 (6.1 net) wells during Q1/2020 compared to 36 (8.9 net) wells in Q1/2019.
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 were relatively strong leading into Q1/2020 as stable demand and production outlooks continued from Q4/2019. Benchmark prices began to decline rapidly in March 2020 after members of the OPEC+ group began to increase the supply of crude oil to the global market and measures to limit the spread of COVID-19 resulted in a significant decrease in the demand for crude oil. The unprecedented volatility in global benchmark prices has continued into Q2/2020 despite a historic production curtailment agreement between members of the OPEC+ group to limit supply. Concerns about a lack of crude oil storage capacity along with decreased demand for crude oil as a result of the COVID-19 health crisis continues to weigh on crude oil prices.
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$49.54/bbl during Q1/2020 which is a US$3.37/bbl premium to WTI as compared to US$60.46/bbl or a US$5.56/bbl premium to WTI in Q1/2019. The MEH benchmark premium to WTI was lower in Q1/2020 compared to Q1/2019 as a result of an increase in supply at the Magellan East terminal due to higher oil production in Texas relative to Q1/2019.
Prices for Canadian oil trade at a discount due to a lack of egress to diversified markets from Western Canada. Canadian oil differentials were wider in Q1/2020 compared to Q1/2019. Production curtailments mandated by the Government of Alberta came into effect in January 2019 and resulted in a significant narrowing of differentials for light and heavy grades of Canadian oil. Reductions in curtailment volumes combined with additional production in Western Canada caused these differentials to widen in Q1/2020
We compare the price received for our light oil production in Canada to the Edmonton par benchmark oil price which is the representative benchmark for light grades of crude oil in Western Canada. The Edmonton par price averaged $51.43/bbl which is a US$7.92/bbl discount to WTI for Q1/2020 compared to $66.53/bbl which is a US$4.85/bbl discount to WTI for Q1/2019.
The price received for our heavy oil production in Canada is based on the WCS benchmark price which is the representative benchmark for heavy grades of crude oil in Western Canada. The WCS heavy oil price averaged $34.48/bbl or a US$20.53/bbl differential to WTI in Q1/2020 as compared to $56.64/bbl or a differential of US$12.29/bbl for Q1/2019.
Natural Gas
U.S. natural gas prices for Q1/2020 were lower than Q1/2019 as higher U.S. natural gas production has outpaced growth in natural gas demand. Canadian natural gas prices remained challenged during Q1/2020 as a lack of egress from Western Canada continues to impact natural gas prices in the region.
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$1.95/mmbtu in Q1/2020 which is lower compared to US$3.15/mmbtu in Q1/2019. Increasing natural gas production levels in the U.S. resulted in an oversupplied North American market and lower natural gas prices in Q1/2020 relative to Q1/2019.
In Canada, we receive natural gas pricing based on the AECO benchmark which continues to trade at a discount to NYMEX as a result of increasing supply and limited market access for Canadian natural gas production. The AECO benchmark averaged $2.14/mcf during Q1/2020 which is higher than $1.94/mcf for Q1/2019.
Baytex Energy Corp.
Q1 2020 MD&A 5
The following tables compare select benchmark prices and our average realized selling prices for the three months ended March 31, 2020 and 2019.
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| Three Months Ended March 31 | | | | | |
| 2020 | | 2019 | | Change | | | | |
| Benchmark Averages | | | | | | |
WTI oil (US$/bbl)(1) | 46.17 | | 54.90 | | (8.73) | | | | |
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MEH oil (US$/bbl)(2) | 49.54 | | 60.46 | | (10.92) | | | | |
| MEH oil differential to WTI (US$/bbl) | 3.37 | | 5.56 | | (2.19) | | | | |
| Edmonton par oil ($/bbl) | 51.43 | | 66.53 | | (15.10) | | | | |
| Edmonton par oil differential to WTI (US$/bbl) | (7.92) | | (4.85) | | (3.07) | | | | |
WCS heavy oil ($/bbl)(3) | 34.48 | | 56.64 | | (22.16) | | | | |
| WCS heavy oil differential to WTI (US$/bbl) | (20.53) | | (12.29) | | (8.24) | | | | |
AECO natural gas price ($/mcf)(4) | 2.14 | | 1.94 | | 0.20 | | | | |
NYMEX natural gas price (US$/mmbtu)(5) | 1.95 | | 3.15 | | (1.20) | | | | |
| CAD/USD average exchange rate | 1.3445 | | 1.3293 | | 0.0152 | | | | |
(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)WCS refers to the average posting price for the benchmark WCS heavy oil.
(4)AECO refers to the AECO arithmetic average month-ahead index price published by the Canadian Gas Price Reporter ("CGPR").
(5)NYMEX refers to the NYMEX last day average index price as published by the CGPR.
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| Three Months Ended March 31 | | | | | |
| 2020 | | | 2019 | | |
| Canada | U.S. | Total | Canada | U.S. | Total |
| Average Realized Sales Prices | | | | | | |
| Light oil and condensate ($/bbl) | $ | 49.45 | | $ | 61.99 | | $ | 55.34 | | $ | 63.14 | | $ | 76.06 | | $ | 69.38 | |
Heavy oil ($/bbl)(1) | 20.75 | | — | | 20.75 | | 41.69 | | — | | 41.69 | |
| NGL ($/bbl) | 11.25 | | 14.94 | | 14.31 | | 23.77 | | 22.84 | | 22.97 | |
| Natural gas ($/mcf) | 2.00 | | 2.63 | | 2.32 | | 2.37 | | 3.95 | | 3.21 | |
Weighted average ($/boe)(1) | $ | 30.62 | | $ | 43.05 | | $ | 35.19 | | $ | 45.77 | | $ | 51.20 | | $ | 47.98 | |
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(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 $35.19/boe for Q1/2020 compared to $47.98/boe for Q1/2019. Our realized price in the U.S. was $43.05/boe in Q1/2020 which is $8.15/boe lower than $51.20/boe in Q1/2019 due to the decrease in U.S. commodity benchmark prices. In Canada, our realized price of $30.62/boe for Q1/2020 was $15.15/boe lower than $45.77/boe for Q1/2019 due to the decrease in Canadian commodity benchmark prices.
We compare our light oil realized price in Canada to the Edmonton par benchmark price. Our realized light oil and condensate price was $49.45/bbl in Q1/2020 compared to $63.14/bbl in Q1/2019. Our realized light oil and condensate price for Q1/2020 represents a discount of $1.98/bbl to the Edmonton par price which is narrower than a discount of $3.39 in Q1/2019 due to improved price realizations on our Viking light oil production.
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 $61.99/bbl for Q1/2020 compared to $76.06/bbl for Q1/2019. Expressed in U.S. dollars, our realized light oil and condensate price of US$46.11/bbl for Q1/2020 reflects a US$3.43 discount to the MEH benchmark for Q1/2020 which is relatively consistent with the US$3.24 discount for Q1/2019.
Our realized heavy oil price, net of blending and other expense averaged $20.75/bbl in Q1/2020 compared to $41.69/bbl in Q1/2019. Our realized heavy oil price for Q1/2020 was $20.94/bbl lower than Q1/2019 which is relatively consistent with the $22.16/bbl decrease in the WCS benchmark price over the same period.
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 $14.31/bbl in Q1/2020 or 23% of WTI (expressed in Canadian dollars) compared to $22.97/bbl or 31% of WTI (expressed in Canadian dollars) in Q1/2019. The decrease
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Q1 2020 MD&A 6
in our NGL price realization as a percentage of WTI for Q1/2020 relative to Q1/2019 is a result of increased NGL production and supply which resulted in lower benchmark pricing for NGLs relative to WTI.
We compare our realized natural gas price in Canada to the AECO benchmark price. Our realized natural gas price of $2.00/mcf for Q1/2020 and $2.37/mcf in Q1/2019 is relatively consistent with the AECO benchmark price in both periods. In the U.S., our realized natural gas price was US$1.96/mcf for Q1/2020 compared to US$2.97/mcf in Q1/2019 which is relatively consistent with the NYMEX benchmark in both periods.
Petroleum and Natural Gas Sales
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| Three Months Ended March 31 | | | | | |
| 2020 | | | 2019 | | |
| ($ thousands) | Canada | | U.S. | | Total | | Canada | | U.S. | | Total | |
| Oil sales | | | | | | |
| Light oil and condensate | $ | 109,084 | | $ | 121,155 | | $ | 230,239 | | $ | 132,368 | | $ | 148,916 | | $ | 281,284 | |
| Heavy oil | 75,843 | | — | | 75,843 | | 117,686 | | — | | 117,686 | |
| NGL | 1,348 | | 8,842 | | 10,190 | | 3,441 | | 20,802 | | 24,243 | |
| Total oil sales | 186,275 | | 129,997 | | 316,272 | | 253,495 | | 169,718 | | 423,213 | |
| Natural gas sales | 8,569 | | 11,773 | | 20,342 | | 10,544 | | 19,667 | | 30,211 | |
| Total petroleum and natural gas sales | 194,844 | | 141,770 | | 336,614 | | 264,039 | | 189,385 | | 453,424 | |
| Blending and other expense | (21,357) | | — | | (21,357) | | (16,788) | | — | | (16,788) | |
| Total sales, net of blending and other expense | $ | 173,487 | | $ | 141,770 | | $ | 315,257 | | $ | 247,251 | | $ | 189,385 | | $ | 436,636 | |
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Total sales, net of blending and other expense, of $315.3 million for Q1/2020 decreased $121.4 million from $436.6 million reported for Q1/2019. The decrease in total sales in Q1/2020 relative to Q1/2019 is primarily due to lower realized pricing as a result of the decrease in benchmark pricing along with lower production for Q1/2020 relative to Q1/2019.
In Canada, total sales, net of blending and other expense, was $173.5 million for Q1/2020 which is a decrease of $73.8 million from Q1/2019. Total petroleum and natural gas sales decreased from lower realized pricing for Q1/2020. Our average realized price of $30.62/boe for Q1/2020 was lower than $45.77/boe for Q1/2019 due to the decrease in benchmark pricing for our production in Canada and resulted in a $85.9 million decrease in total sales, net of blending and other expense. Production in Canada was 2,244 boe/d higher in Q1/2020 which resulted in a $12.1 million increase in total sales, net of blending and other expense relative to Q1/2019.
In the U.S., petroleum and natural gas sales were $141.8 million for Q1/2020 which is a decrease of $47.6 million from $189.4 million reported for Q1/2019. Our realized price for Q1/2020 was $8.15/boe lower than Q1/2019 and resulted in a $26.9 million decrease in total petroleum and natural gas sales. Lower completion activity on our lands during Q1/2020 resulted in a 4,907 boe/d decrease in production and a $20.8 million decrease in total sales, net of blending and other expense relative to Q1/2019.
Royalties
Royalties are paid to various government entities and to land and mineral rights owners. Royalties are calculated based on gross revenues or on operating netbacks less capital investment for specific heavy oil projects, and are generally expressed as a percentage of total sales, net of blending and other expense. The actual royalty rates can vary for a number of reasons, including the commodity produced, royalty contract terms, commodity price level, royalty incentives and the area or jurisdiction. The following table summarizes our royalties and royalty rates for the three months ended March 31, 2020 and 2019.
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| Three Months Ended March 31 | | | | | |
| 2020 | | | 2019 | | |
| ($ thousands except for % and per boe) | Canada | | U.S. | | Total | Canada | | U.S. | | Total |
| Royalties | $ | 15,518 | | $ | 41,202 | | $ | 56,720 | | $ | 25,184 | | $ | 56,141 | | $ | 81,325 | |
Average royalty rate(1) | 8.9 | % | 29.1 | % | 18.0 | % | 10.2 | % | 29.6 | % | 18.6 | % |
| Royalties per boe | $ | 2.74 | | $ | 12.51 | | $ | 6.33 | | $ | 4.66 | | $ | 15.18 | | $ | 8.94 | |
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(1)Average royalty rate is calculated as royalties divided by total sales, net of blending and other expense.
Total royalties in Q1/2020 were $56.7 million or 18.0% of total sales, net of blending and other expense compared to $81.3 million or 18.6% in Q1/2019. A lower proportion of our production was from our U.S. properties in Q1/2020 compared to Q1/2019 which resulted in a lower royalty rate as our U.S. properties have a higher royalty rate than our Canadian properties. Total royalty expense is lower in Q1/2020 primarily due to the decrease in petroleum and natural gas sales relative to Q1/2019. Our revised
annual guidance of approximately 20% for 2020 reflects a higher proportion of our production coming from our U.S. assets for the remainder of the year.
Our Canadian royalty rate of 8.9% for Q1/2020 was lower than 10.2% for Q1/2019 due to lower benchmark pricing which resulted in a lower royalty rate on certain heavy oil production in Q1/2020 relative to Q1/2019. In the U.S., royalties for Q1/2020 were 29.1% of total petroleum and natural gas sales which is consistent with Q1/2019 as the royalty rate on our U.S. production does not vary with price but can vary across our acreage.
Operating Expense
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| Three Months Ended March 31 | | | | | |
| 2020 | | | 2019 | | |
| ($ thousands except for per boe) | Canada | | U.S. | | Total | Canada | | U.S. | | Total |
| Operating expense | $ | 78,922 | | $ | 25,548 | | $ | 104,470 | | $ | 74,102 | | $ | 26,190 | | $ | 100,292 | |
| Operating expense per boe | $ | 13.93 | | $ | 7.76 | | $ | 11.66 | | $ | 13.72 | | $ | 7.08 | | $ | 11.02 | |
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Operating expense was $104.5 million ($11.66/boe) for Q1/2020 compared to $100.3 million ($11.02/boe) in Q1/2019. The increase in total operating expense and operating expense per boe can be attributed to an increase in production from Canada in Q1/2020 relative to Q1/2019 and the decrease in U.S. production which has lower operating costs per boe. Operating expense of $11.66/boe is consistent with expectations and was slightly below our 2020 annual guidance range of $11.75 - $12.50/boe.
In Canada, operating expense was $78.9 million ($13.93/boe) for Q1/2020 compared to $74.1 million ($13.72/boe) for Q1/2019. Total operating expense in Canada has increased with higher production but has remained fairly consistent as per unit operating costs were $13.93/boe for Q1/2020 compared to $13.72/boe in Q1/2019.
U.S. operating expense was $25.5 million ($7.76/boe) for Q1/2020 compared to $26.2 million ($7.08/boe) for Q1/2019. Expressed in U.S. dollars, per unit operating expense was US$5.77/boe in Q1/2020 which reflects lower total production compared to Q1/2019 when per unit operating expense was US$5.33/boe as a portion of our operating costs in the U.S. are fixed and do not fluctuate with production.
Transportation Expense
Transportation expense includes the costs to move production from the field to the sales point. The largest component of transportation expense relates to the trucking of oil in Canada to pipeline and rail terminals which can vary from period to period depending on hauling distances as we seek to optimize sales prices and trucking rates. The following table compares our transportation expense for the three months ended March 31, 2020 and 2019.
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| Three Months Ended March 31 | | | | | |
| 2020 | | | 2019 | | |
| ($ thousands except for per boe) | Canada | | U.S. | | Total | Canada | | U.S. | | Total |
| Transportation expense | $ | 10,342 | | $ | — | | $ | 10,342 | | $ | 13,330 | | $ | — | | $ | 13,330 | |
| Transportation expense per boe | $ | 1.83 | | $ | — | | $ | 1.15 | | $ | 2.47 | | $ | — | | $ | 1.46 | |
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We reported transportation expense of $1.15/boe for Q1/2020 which is in line with expectations. Transportation expense was $10.3 million ($1.15/boe) for Q1/2020 compared to $13.3 million ($1.46/boe) for Q1/2019. The decrease in transportation expense for Q1/2020 is due to lower transportation costs for our light oil properties in Canada which resulted in lower aggregate and per unit transportation expense for Q1/2020. We expect transportation expense to be lower for the remainder of the year as we optimize our Canadian production in response to the low commodity price environment and have adjusted our annual guidance range to $0.80 - $0.90/boe for 2020.
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 $21.4 million for Q1/2020 compared to $16.8 million for Q1/2019. The increase in blending and other expense reflects the higher heavy oil production and volumes of blending condensate required in Q1/2020 relative to Q1/2019.
Baytex Energy Corp.
Q1 2020 MD&A 8
Financial Derivatives
As part of our normal operations, we are exposed to movements in commodity prices, foreign exchange rates and interest rates. In an effort to manage these exposures, we utilize various financial derivative contracts which are intended to partially reduce the volatility in our adjusted funds flow. Contracts settled in the period result in realized gains or losses based on the market price compared to the contract price and the notional volume outstanding. Changes in the fair value of unsettled contracts are reported as unrealized gains or losses in the period as the forward markets for commodities and currencies fluctuate and as new contracts are executed. The following table summarizes the results of our financial derivative contracts for the three months ended March 31, 2020 and 2019.
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| Three Months Ended March 31 | | | | | |
| ($ thousands) | 2020 | | 2019 | | Change | | | |
| Realized financial derivatives gain (loss) | | | | | | |
| Crude oil | $ | 26,645 | | $ | 17,812 | | $ | 8,833 | | | | |
| Natural gas | 210 | | 966 | | (756) | | | | |
| Interest and financing | (5) | | 36 | | (41) | | | | |
| Total | $ | 26,850 | | $ | 18,814 | | $ | 8,036 | | | | |
| Unrealized financial derivatives gain (loss) | | | | | | |
| Crude oil | $ | 99,809 | | $ | (51,166) | | $ | 150,975 | | | | |
| Natural gas | (122) | | (1,580) | | 1,458 | | | | |
| Interest and financing | (678) | | (515) | | (163) | | | | |
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| Equity total return swap ("Equity TRS") | (3,014) | | — | | (3,014) | | | | |
| Total | $ | 95,995 | | $ | (53,261) | | $ | 149,256 | | | | |
| Total financial derivatives gain (loss) | | | | | | |
| Crude oil | $ | 126,454 | | $ | (33,354) | | $ | 159,808 | | | | |
| Natural gas | 88 | | (614) | | 702 | | | | |
| Interest and financing | (683) | | (479) | | (204) | | | | |
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| Equity TRS | (3,014) | | — | | (3,014) | | | | |
| Total | $ | 122,845 | | $ | (34,447) | | $ | 157,292 | | | | |
We recorded total financial derivative gains of $122.8 million for Q1/2020 compared to total financial derivative losses of $34.4 million in Q1/2019. Realized financial derivatives gains of $26.9 million for Q1/2020 are primarily a result of the market prices for crude oil settling at levels below those set in our derivative contracts. The unrealized gain of $96.0 million for Q1/2020 reflects an increase in the fair value of unrealized derivative contracts due to a decrease in futures pricing for the remainder of 2020 at March 31, 2020 relative to December 31, 2019.
Realized gains on crude oil financial derivatives of $26.6 million in Q1/2020 are primarily a result of market prices for WTI settling at levels below the prices set in our contracts outstanding during the period. Our natural gas financial derivatives generated gains of $0.2 million in Q1/2020. These gains were a result of the NYMEX index for Q1/2020 averaging less than the fixed price on our NYMEX contracts in place.
Unrealized gains of $96.0 million in Q1/2020 are primarily a result of lower futures prices for crude oil for the remainder of 2020 relative to December 31, 2019 which resulted in unrealized gains of $99.8 million. We recorded an unrealized loss of $3.0 million on equity total return swaps used to fix the cost of certain employee incentive plans due to the decrease in our share price between the grant date of the associated awards and March 31, 2020. The fair value of our financial derivative contracts resulted in a net asset of $92.8 million at March 31, 2020 compared to a net liability of $3.2 million at December 31, 2019.
Baytex Energy Corp.
Q1 2020 MD&A 9
We had the following commodity financial derivative contracts as at May 7, 2020.
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| Period | Volume | Price/Unit(1) | Index |
| Oil | | | | | |
| Basis Swap | Apr 2020 to Dec 2020 | 6,500 bbl/d | WTI less US$16.27/bbl | | WCS |
Basis Swap(7) | Jan 2021 to Dec 2021 | 2,000 bbl/d | WTI less US$14.12/bbl | | WCS |
| Basis Swap | Apr 2020 to Dec 2020 | 5,000 bbl/d | WTI less US$6.15/bbl | | MSW |
MSW Stream(6)(7) | June 2020 | 800 bbl/d | $22.68/bbl | | Blended |
MSW Stream(6)(7) | July 2020 | 11,695 bbl/d | $27.17/bbl | | Blended |
| Fixed - Sell | Apr 2020 to Dec 2020 | 2,000 bbl/d | US$58.00/bbl | | WTI |
Fixed - Sell(7) | Apr 2020 to June 2020 | 6,000 bbl/d | US$25.62/bbl | | WTI |
Fixed - Sell(7) | May 2020 | 6,000 bbl/d | $40.72/bbl | | WTI-CAD |
Fixed - Sell(7) | June 2020 | 3,000 bbl/d | US$22.55/bbl | | WTI |
Fixed - Sell(7) | June 2020 | 6,000 bbl/d | $32.45/bbl | | WTI-CAD |
Fixed - Sell(7) | July 2020 | 4,000 bbl/d | US$24.73/bbl | | WTI |
Fixed - Sell(7) | July 2020 | 5,000 bbl/d | $34.05/bbl | | WTI-CAD |
3-way option(2) | Apr 2020 to Dec 2020 | 3,000 bbl/d | US$50.00/US$56.00/US$61.35 | | WTI |
3-way option(2) | Apr 2020 to Dec 2020 | 3,000 bbl/d | US$50.00/US$57.00/US$60.00 | | WTI |
3-way option(2) | Apr 2020 to Dec 2020 | 4,500 bbl/d | US$50.00/US$57.00/US$62.00 | | WTI |
3-way option(2) | Apr 2020 to Dec 2020 | 3,000 bbl/d | US$50.00/US$58.00/US$62.00 | | WTI |
3-way option(2) | Apr 2020 to Dec 2020 | 1,000 bbl/d | US$51.00/US$58.00/US$60.50 | | WTI |
3-way option(2) | Apr 2020 to Dec 2020 | 1,000 bbl/d | US$51.00/US$58.00/US$60.83 | | WTI |
3-way option(2) | Apr 2020 to Dec 2020 | 1,500 bbl/d | US$51.00/US$59.00/US$65.60 | | WTI |
3-way option(2) | Apr 2020 to Dec 2020 | 1,500 bbl/d | US$51.00/US$59.00/US$66.00 | | WTI |
3-way option(2) | Apr 2020 to Dec 2020 | 1,000 bbl/d | US$51.00/US$59.50/US$66.15 | | WTI |
3-way option(2) | Apr 2020 to Dec 2020 | 1,000 bbl/d | US$51.00/US$60.00/US$65.60 | | WTI |
3-way option(2) | Apr 2020 to Dec 2020 | 1,000 bbl/d | US$51.00/US$60.00/US$66.00 | | WTI |
3-way option(2) | Apr 2020 to Dec 2020 | 1,000 bbl/d | US$51.00/US$60.00/US$66.05 | | WTI |
3-way option(2) | Apr 2020 to Dec 2020 | 2,000 bbl/d | US$51.00/US$60.00/US$66.70 | | WTI |
Swaption(3) | Jan 2021 to Dec 2021 | 3,000 bbl/d | US$64.50/bbl | | Brent |
Swaption(4) | Jan 2021 to Dec 2021 | 3,000 bbl/d | US$70.00/bbl | | Brent |
Swaption(4) | Jan 2021 to Dec 2021 | 3,000 bbl/d | US$60.75/bbl | | WTI |
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| Natural Gas | | | | | |
| Fixed - Sell | Apr 2020 to Dec 2020 | 5,000 GJ/d | $1.77/GJ | | AECO 7A |
Fixed - Sell(7) | May 2020 to Dec 2020 | 5,500 GJ/d | $2.22/GJ | | AECO 7A |
| Fixed - Sell | Jan 2021 to Dec 2021 | 10,500 GJ/d | $2.31/GJ | | AECO 7A |
Fixed - Sell(7) | May 2020 to Dec 2020 | 2,500 GJ/d | $2.29/GJ | | AECO 5A |
Fixed - Sell(7) | Oct 2020 to Dec 2020 | 5,500 mmbtu/d | US$2.64/mmbtu | | NYMEX |
Fixed - Sell(7) | Jan 2021 to Dec 2021 | 9,000 mmbtu/d | US$2.72/mmbtu | | NYMEX |
3-way option(2) | Apr 2020 to Dec 2020 | 5,000 mmbtu/d | US$2.25/US$2.60/US$2.85 | | NYMEX |
Swaption(5) | Jan 2021 to Dec 2021 | 5,000 mmbtu/d | US$2.90/mmbtu | | 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$58.00/US$62.00 contract, Baytex receives WTI plus US$8.00/bbl when WTI is at or below US$50.00/bbl; Baytex receives US$58.00/bbl when WTI is between US$50.00/bbl and US$58.00/bbl; Baytex receives the market price when WTI is between US$58.00/bbl and US$62.00/bbl; and Baytex receives US$62.00/bbl when WTI is above US$62.00/bbl.
(3)For these contracts, the counterparty has the right, if exercised on September 30, 2020, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above.
(4)For these contracts, the counterparty has the right, if exercised on December 31, 2020, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above.
(5)For these contracts, the counterparty has the right, if exercised on December 23, 2020, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above.
(6)For these contracts, the contract price per unit is the sum of the average WTI price for the period and the average of the Edmonton SW blend differential (the average of TMX SW 1a index as determined by NGX and the NE Monthly Index for physical SW as determined by Net Energy), converted to CAD at the noon day average rate.
(7)Contracts entered subsequent to March 31, 2020.
Baytex Energy Corp.
Q1 2020 MD&A 10
Operating Netback
The following table summarizes our operating netback on a per boe basis for our Canadian and U.S. operations for the three months ended March 31, 2020 and 2019.
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| Three Months Ended March 31 | | | | | |
| 2020 | | | 2019 | | |
| ($ per boe except for volume) | Canada | | U.S. | | Total | | Canada | | U.S. | | Total | |
| Total production (boe/d) | 62,262 | | 36,190 | | 98,452 | | 60,018 | | 41,097 | | 101,115 | |
| Operating netback: | | | | | | |
| Total sales, net of blending and other expense | $ | 30.62 | | $ | 43.05 | | $ | 35.19 | | $ | 45.77 | | $ | 51.20 | | $ | 47.98 | |
| Less: | | | | | | |
| Royalties | (2.74) | | (12.51) | | (6.33) | | (4.66) | | (15.18) | | (8.94) | |
| Operating expense | (13.93) | | (7.76) | | (11.66) | | (13.72) | | (7.08) | | (11.02) | |
| Transportation expense | (1.83) | | — | | (1.15) | | (2.47) | | — | | (1.46) | |
| Operating netback | $ | 12.12 | | $ | 22.78 | | $ | 16.05 | | $ | 24.92 | | $ | 28.94 | | $ | 26.56 | |
| Realized financial derivatives gain | — | | — | | 3.00 | | — | | — | | 2.07 | |
| Operating netback after financial derivatives | $ | 12.12 | | $ | 22.78 | | $ | 19.05 | | $ | 24.92 | | $ | 28.94 | | $ | 28.63 | |
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Our operating netback after financial derivatives was $19.05/boe for Q1/2020 which was $9.58/boe lower than $28.63/boe for Q1/2019. Operating netback of $16.05/boe in Q1/2020 was lower than $26.56/boe in Q1/2019 due to the decrease in benchmark pricing in Canada and the U.S. which resulted in lower per unit sales net of royalties. Total operating and transportation expense of $12.81/boe in Q1/2020 is relatively consistent with $12.48/boe for the same period of 2019. Lower operating netback was partially offset by a $0.93/boe increase in realized gains on financial derivatives in Q1/2020 compared to Q1/2019.
General and Administrative Expense
General and administrative ("G&A") expense includes head office and corporate costs such as salaries and employee benefits, public company costs and administrative recoveries earned for operating exploration and development activities on behalf of our working interest partners. G&A expense fluctuates with head office staffing levels and the level of operated exploration and development activity during the period.
The following table summarizes our G&A expense for the three months ended March 31, 2020 and 2019.
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| Three Months Ended March 31 | | | | | |
| ($ thousands except for per boe) | 2020 | | 2019 | | Change | | | | |
| Gross general and administrative expense | $ | 11,888 | | $ | 15,619 | | $ | (3,731) | | | | |
| Overhead recoveries | (2,113) | | (1,483) | | (630) | | | | |
| General and administrative expense | $ | 9,775 | | $ | 14,136 | | $ | (4,361) | | | | |
| General and administrative expense per boe | $ | 1.09 | | $ | 1.55 | | $ | (0.46) | | | | |
G&A expense was $9.8 million ($1.09/boe) for Q1/2020 compared to $14.1 million ($1.55/boe) for Q1/2019. G&A expense for Q1/2020 was lower relative to Q1/2019 due to lower staffing and corporate administrative costs after we completed the integration of Raging River Exploration Inc. in early 2019. The decrease in G&A expense per boe in Q1/2020 relative to Q1/2019 reflects the efficiencies we were able to realize by combining the two organizations and is consistent with our expectations and guidance. Our revised annual guidance of $40 million ($1.52/boe) reflects a reduction in gross G&A expense from our cost savings initiatives along with lower overhead recoveries due to the reduction in exploration and development spending in Canada.
Baytex Energy Corp.
Q1 2020 MD&A 11
Financing and Interest Expense
Financing and interest expense includes interest on our credit facilities, long-term notes and lease obligations as well as non-cash financing costs and the accretion on our debt issue costs and asset retirement obligations. Financing and interest expense varies depending on debt levels outstanding during the period, the applicable borrowing rates, CAD/USD foreign exchange rates, along with the carrying amount of asset retirement obligations and the discount rates used to present value these obligations.
The following table summarizes our financing and interest expense for the three months ended March 31, 2020 and 2019.
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| Three Months Ended March 31 | | | | | |
| ($ thousands except for per boe) | 2020 | | 2019 | | Change | | | | |
| Interest on credit facilities | $ | 4,135 | | $ | 5,412 | | $ | (1,277) | | | | |
| Interest on long-term notes | 24,273 | | 22,602 | | 1,671 | | | | |
| Interest on lease obligations | 127 | | 170 | | (43) | | | | |
| Cash interest | $ | 28,535 | | $ | 28,184 | | $ | 351 | | | | |
| Accretion of debt issue costs | 4,442 | | 1,095 | | 3,347 | | | | |
| Accretion of asset retirement obligations | 2,931 | | 3,463 | | (532) | | | | |
| Early redemption expense | 3,312 | | — | | 3,312 | | | | |
| Financing and interest expense | $ | 39,220 | | $ | 32,742 | | $ | 6,478 | | | | |
| Cash interest per boe | $ | 3.19 | | $ | 3.10 | | $ | 0.09 | | | | |
| Financing and interest expense per boe | $ | 4.38 | | $ | 3.60 | | $ | 0.78 | | | | |
Financing and interest expense was $39.2 million in Q1/2020 compared to $32.7 million in Q1/2019. Cash interest of $28.5 million ($3.19/boe) in Q1/2020 is consistent with $28.2 million ($3.10/boe) in Q1/2019. During Q1/2020, we issued US$500 million principal amount of 8.75% senior unsecured notes on February 5, 2020. Proceeds from this issuance were used to reduce amounts outstanding on our credit facilities prior to the early redemption of the US$400 million principal amount of 5.125% senior unsecured notes on February 20, 2020 and the early redemption of the $300 million principal amount of the 6.625% senior unsecured note on March 5, 2020. Total cash interest for Q1/2020 was consistent with Q1/2019 as a result of these transactions.
Financing and interest expense for Q1/2020 includes accelerated amortization of debt issue costs and $3.3 million of early redemption expense associated with the early redemption of the $300 million principal amount of 6.625% senior unsecured notes which were redeemed at 101.104% of the principal amount.
We expect cash financing and interest expense of $120 million ($4.57/boe) which reflects lower production for the remainder of 2020.
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 lease expiries, the accumulated costs of expiring leases and the economic facts and circumstances related to the Company's exploration programs. Exploration and evaluation expense was $0.3 million for Q1/2020 and $1.8 million for Q1/2019.
Baytex Energy Corp.
Q1 2020 MD&A 12
Depletion and Depreciation
Depletion and depreciation expense varies with the carrying amount of the Company's oil and gas properties, the amount of proved plus probable reserves volumes and the rate of production for the period. The following table summarizes depletion and depreciation expense for the three months ended March 31, 2020 and 2019.
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| Three Months Ended March 31 | | | | | |
| ($ thousands except for per boe) | 2020 | 2019 | Change | | | |
| Depletion | $ | 179,418 | | $ | 184,844 | | $ | (5,426) | | | | |
| Depreciation | 1,968 | | 510 | | 1,458 | | | | |
| Depletion and depreciation | $ | 181,386 | | $ | 185,354 | | $ | (3,968) | | | | |
| Depletion and depreciation per boe | $ | 20.25 | | $ | 20.37 | | $ | (0.12) | | | | |
Depletion and depreciation expense was $181.4 million ($20.25/boe) for Q1/2020 compared to $185.4 million ($20.37/boe) for Q1/2019. Total depletion and depreciation expense was slightly lower in Q1/2020 due to a decrease in production in Q1/2020 compared to Q1/2019 as the depletion rate per boe was consistent in both periods.
Impairment
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 all of our cash generating units ("CGU"). We recorded total impairments of $2.7 billion in Q1/2020 as the carrying value of the E&E assets and oil and gas properties of our CGUs exceeded their estimated recoverable amounts. The total impairment includes $2,588.5 million related to the CGUs comprising oil and gas properties and $127.9 million related to the CGUs comprising E&E assets.
The recoverable amount of each CGU was calculated at March 31, 2020 using the following benchmark reference prices for the years 2020 to 2029 adjusted for commodity differentials specific to the Company.
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| 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | 2026 | 2027 | 2028 | 2029 |
| WTI crude oil (US$/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 | |
This data is combined with assumptions relating to long-term prices, inflation rates and exchange rates together with estimates of transportation costs and pricing of competing fuels to forecast long-term energy prices, consistent with external sources of information. The prices and costs subsequent to 2029 have been adjusted for inflation at an annual rate of 2.0%.
The following table summarizes the recoverable amount, impairment 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.
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| Recoverable amount | Impairment | Change in discount rate of 1% | Change in oil price of $2.50/bbl | Change in gas price of $0.25/mcf |
| Conventional CGU | $ | 37,444 | | $ | 41,000 | | $ | 3,000 | | $ | 3,500 | | $ | 8,500 | |
| Peace River CGU | 109,631 | | 345,000 | | 9,500 | | 53,500 | | 3,000 | |
| Lloydminster CGU | 227,967 | | 470,000 | | 25,000 | | 69,500 | | — | |
| Duvernay CGU | 61,197 | | 5,000 | | 5,500 | | 9,500 | | 1,500 | |
| Viking CGU | 962,134 | | 915,000 | | 57,000 | | 123,000 | | 4,000 | |
| Eagle Ford CGU | 1,576,423 | | 812,488 | | 120,750 | | 141,500 | | 32,000 | |
| $ | 2,974,796 | | $ | 2,588,488 | | $ | 220,750 | | $ | 400,500 | | $ | 49,000 | |
Baytex Energy Corp.
Q1 2020 MD&A 13
Share-Based Compensation Expense
Share-based compensation ("SBC") expense includes expense associated with our Share Award Incentive Plan and our Incentive Award 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 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 $2.8 million for Q1/2020 compared to $5.8 million for Q1/2019. Total SBC expense is lower in Q1/2020 as the total value of awards granted in 2020 was lower than prior years. The total expense for Q1/2020 is comprised of non-cash compensation expense of $2.3 million related to the Share Award Incentive Plan and cash compensation expense of $0.5 million related to the Incentive Award Plan.
Foreign Exchange
Unrealized foreign exchange gains and losses represent the change in value of the long-term notes and credit facilities denominated in U.S. dollars. The long-term notes and credit facilities are translated to Canadian dollars on the balance sheet date using the closing CAD/USD exchange rate. When the Canadian dollar strengthens against the U.S. dollar at the end of the current period compared to the previous period an unrealized gain is recorded and conversely when the Canadian dollar weakens at the end of the current period compared to the previous period an unrealized loss is recorded. Realized foreign exchange gains and losses are due to day-to-day U.S. dollar denominated transactions occurring in our Canadian functional currency entities.
| | | | | | | | | | | | | | |
| Three Months Ended March 31 | | | | | |
| ($ thousands except for exchange rates) | 2020 | | 2019 | | Change | | | | |
| Unrealized foreign exchange loss (gain) | $ | 99,521 | | $ | (26,941) | | $ | 126,462 | | | | |
| Realized foreign exchange loss (gain) | 371 | | (595) | | 966 | | | | |
| Foreign exchange loss (gain) | $ | 99,892 | | $ | (27,536) | | $ | 127,428 | | | | |
| CAD/USD exchange rates: | | | | | | |
| At beginning of period | 1.2965 | | 1.3646 | | | | | |
| At end of period | 1.4120 | | 1.3360 | | | | | |
We recorded an unrealized foreign exchange loss of $99.5 million for Q1/2020 due to the weakening of the Canadian dollar relative to the U.S. dollar at March 31, 2020 compared to December 31, 2019. This compares to an unrealized foreign exchange gain of $26.9 million in Q1/2019 due to the strengthening of the Canadian dollar relative to the U.S. dollar over Q1/2019.
Realized foreign exchange gains and losses will fluctuate depending on the amount and timing of day-to-day U.S. dollar denominated transactions for our Canadian operations. We recorded a realized foreign exchange loss of $0.4 million for Q1/2020 compared to a gain of $0.6 million for Q1/2019.
Income Taxes
| | | | | | | | | | | | | | |
| Three Months Ended March 31 | | | | | |
| ($ thousands) | 2020 | | 2019 | | Change | | | | |
| Current income tax expense | $ | 469 | | $ | 595 | | $ | (126) | | | | |
| Deferred income tax recovery | (283,179) | | (14,485) | | (268,694) | | | | |
| Total income tax recovery | $ | (282,710) | | $ | (13,890) | | $ | (268,820) | | | | |
Current income tax expense was $0.5 million for Q1/2020 compared to $0.6 million for Q1/2019.
We recorded a deferred income tax recovery of $283.2 million for Q1/2020 as compared to $14.5 million for Q1/2019. Our deferred income tax recovery was higher in Q1/2020 due to the impairment of assets recorded in the quarter.
As disclosed in the 2019 annual financial statements, certain indirect subsidiaries received reassessments from the Canada Revenue Agency (the "CRA”) that deny $591 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.
Q1 2020 MD&A 14
On April 7, 2020 the U.S. Department of the Treasury and the IRS published final regulations addressing “anti-hybrid” rules under section 267A of the U.S. tax code. Pursuant to these regulations, the Company will no longer be entitled to certain tax benefits previously recognized during Q1/2020 and 2019. Accordingly, a non-cash charge against deferred income taxes in the amount of $24.8 million will be recorded in the three months ended June 30, 2020.
Net Income (Loss) and Adjusted Funds Flow
The components of adjusted funds flow and net income or loss for the three months ended March 31, 2020 and 2019 are set forth in the following table.
| | | | | | | | | | | | | | |
| Three Months Ended March 31 | | | | | |
| ($ thousands) | 2020 | | 2019 | Change | | | |
| Petroleum and natural gas sales | $ | 336,614 | | $ | 453,424 | | $ | (116,810) | | | | |
| Royalties | (56,720) | | (81,325) | | 24,605 | | | | |
| Revenue, net of royalties | 279,894 | | 372,099 | | (92,205) | | | | |
| | | | | | |
| Expenses | | | | | | |
| Operating | (104,470) | | (100,292) | | (4,178) | | | | |
| Transportation | (10,342) | | (13,330) | | 2,988 | | | | |
| Blending and other | (21,357) | | (16,788) | | (4,569) | | | | |
| Operating netback | $ | 143,725 | | $ | 241,689 | | $ | (97,964) | | | | |
| General and administrative | (9,775) | | (14,136) | | 4,361 | | | | |
| Cash financing and interest | (28,535) | | (28,184) | | (351) | | | | |
| Realized financial derivatives gain | 26,850 | | 18,814 | | 8,036 | | | | |
| Realized foreign exchange (loss) gain | (371) | | 595 | | (966) | | | | |
| Other income | 2,031 | | 2,587 | | (556) | | | | |
| Current income tax expense | (469) | | (595) | | 126 | | | | |
| Share based compensation | (521) | | — | | (521) | | | | |
| | | | | | |
| Adjusted funds flow | $ | 132,935 | | $ | 220,770 | | $ | (87,835) | | | | |
| | | | | | |
| Exploration and evaluation | (260) | | (1,844) | | 1,584 | | | | |
| Depletion and depreciation | (181,386) | | (185,354) | | 3,968 | | | | |
| Share based compensation | (2,262) | | (5,843) | | 3,581 | | | | |
| Non-cash financing and accretion | (10,685) | | (4,558) | | (6,127) | | | | |
| Unrealized financial derivatives gain (loss) | 95,995 | | (53,261) | | 149,256 | | | | |
| Unrealized foreign exchange (loss) gain | (99,521) | | 26,941 | | (126,462) | | | | |
| Gain on dispositions | 137 | | — | | 137 | | | | |
| Impairment | (2,716,349) | | — | | (2,716,349) | | | | |
| Deferred income tax recovery | 283,179 | | 14,485 | | 268,694 | | | | |
| | | | | | |
| | | | | | |
| Net income (loss) for the period | $ | (2,498,217) | | $ | 11,336 | | $ | (2,509,553) | | | | |
We generated adjusted funds flow of $132.9 million for Q1/2020, a decrease of $87.8 million from $220.8 million reported in Q1/2019. The decrease in adjusted funds flow is primarily due to the decline in commodity benchmark prices which resulted in a $92.2 million decrease in revenue, net of royalties.
In Q1/2020 we reported a net loss of $2.5 billion compared to net income of $11.3 million in Q1/2019. The increase in net loss was driven by a $2.7 billion impairment expense, a $87.8 million decrease in adjusted funds flow and a $126.5 million increase in unrealized foreign exchange losses. These decreases to net income were partially offset by a $149.3 million increase in unrealized gains on financial derivatives in Q1/2020 and a $268.7 million increase in the deferred tax recovery.
Other Comprehensive Income (Loss)
Other comprehensive income or loss is comprised of the foreign currency translation adjustment on U.S. net assets which is not recognized in profit or loss. The foreign currency translation gain of $173.9 million for Q1/2020 relates to the change in value of our U.S. net assets expressed in Canadian dollars and is due to the weakening of the Canadian dollar relative to the U.S. dollar at March 31, 2020 compared to December 31, 2019. The CAD/USD exchange rate was 1.4120 CAD/USD as at March 31, 2020 compared to 1.2965 CAD/USD at December 31, 2019.
Baytex Energy Corp.
Q1 2020 MD&A 15
Capital Expenditures
Capital expenditures for the three months ended March 31, 2020 and 2019 are summarized as follows.
| | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31 | | | | | |
| 2020 | | | 2019 | | |
| ($ thousands) | Canada | U.S. | Total | Canada | U.S. | Total |
| Drilling, completion and equipping | $ | 99,537 | | $ | 53,072 | | $ | 152,609 | | $ | 88,881 | | $ | 46,059 | | $ | 134,940 | |
| Facilities | 19,003 | | 300 | | 19,303 | | 12,940 | | 2,662 | | 15,602 | |
| Land, seismic and other | 4,570 | | 295 | | 4,865 | | 3,049 | | 252 | | 3,301 | |
| Total exploration and development | $ | 123,110 | | $ | 53,667 | | $ | 176,777 | | $ | 104,870 | | $ | 48,973 | | $ | 153,843 | |
| Total acquisitions, net of proceeds from divestitures | $ | (40) | | $ | — | | $ | (40) | | $ | — | | $ | — | | $ | — | |
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Exploration and development expenditures were $176.8 million for Q1/2020 compared to $153.8 million for Q1/2019. Expenditures in Q1/2020 were lower than we previously indicated as we suspended our operated capital activity in mid-March as a result of the sharp decline in crude oil prices. Higher exploration and development expenditures in Q1/2020 relative to Q1/2019 reflects additional activity on our light and heavy oil properties in Canada and the timing of drilling and completion activity on our Eagle Ford properties in the U.S.
In Canada, we invested $123.1 million on exploration and development activities in Q1/2020 which is $18.2 million higher than $104.9 million in Q1/2019. Exploration and development expenditures of $123.1 million for Q1/2020 included costs associated with drilling 72 (69.2 net) light oil wells in the Viking, 2 (2.0 net) light oil wells in the Duvernay, 33 (33.0 net) heavy oil wells, 6 (6.0 net) stratigraphic exploration wells and investing $19.0 million on facilities. Exploration and development expenditures of $104.9 million for Q1/2019 included costs associated with 98 (78.3 net) light oil wells, 1 (1.0 net) heavy oil wells and 4 (4.0 net) stratigraphic exploration wells. Facility expenditures for Q1/2020 were higher than Q1/2019 due to the additional costs associated with our polymer flood operations at Lloydminster. Total exploration and development costs for Q1/2020 were $18.2 million higher than Q1/2019 due to the additional activity on our Viking light oil properties and heavy oil properties at Lloydminster.
Total U.S. exploration and development expenditures were $53.7 million for Q1/2020 which is higher than $49.0 million for Q1/2019. During Q1/2020 we participated in the drilling of 17 (3.8 net) wells and commenced production from 30 (6.1 net) wells compared to 23 (3.6 net) wells drilled and 36 (8.9 net) wells on production during Q1/2019. Exploration and development expenditures were higher in Q1/2020 relative to Q1/2019 due to the timing of drilling and completion activity on our lands along with a slight increase in the CAD/USD exchange rate used to translate amounts from U.S. dollars. The majority of the completion costs for wells to be brought on production in Q2/2020 have been incurred in Q1/2020.
Our 2020 annual guidance range of $260 - $290 million reflects suspended capital activity in Canada for the remainder of 2020 and a moderated pace of development on our Eagle Ford properties in the U.S. We have the flexibility to increase capital expenditures in Canada if the commodity price environment supports additional development in 2020.
CAPITAL RESOURCES AND LIQUIDITY
We took action to improve our capital structure and financial liquidity during Q1/2020. On February 5, 2020, we issued US$500 million of senior unsecured notes bearing interest at 8.75% which mature on April 1, 2027. Proceeds from the issuance were used in conjunction with availability on the credit facilities to complete the early redemption of the US$400 million principal amount of 5.125% senior unsecured notes due June 1, 2021 along with the early redemption of the $300 million principal amount of 6.625% senior unsecured notes due July 19, 2022. We also negotiated an extension of the maturity of our credit facilities from April 2, 2021 to April 2, 2024. As a result of these actions we do not have any debt maturities until 2024 and we had $417.0 million of undrawn capacity on our credit facilities at March 31, 2020.
Our objective for capital management involves maintaining a flexible capital structure and sufficient sources of liquidity to execute our capital programs, while meeting our short and long-term commitments. We strive to actively manage our capital structure in response to changes in economic conditions. At March 31, 2020, our capital structure was comprised of shareholders' capital, long-term notes, trade and other receivable, trade and other payables and the credit facilities.
In response to the collapse in oil prices and the global economic instability related to COVID-19, we have taken additional action to protect our financial liquidity. Our 2020 exploration and development expenditures have been reduced with a suspension of drilling operations in Canada and a moderated pace of development in the U.S.. We have also shut-in low or negative margin production and have the ability to shut-in additional volumes or quickly restart production in response to further changes in the commodity price environment. We remain focused on driving further efficiencies in our operations and have identified approximately $130 million of cost reductions for operating, transportation and G&A expenses in 2020. This includes reducing salaries for all full time employees and all annual retainers paid to our directors by 10% effective April 1, 2020.
We are expecting compliance with the financial covenants applicable to our credit facilities for at least the next twelve months. A decrease or a sustained period of low commodity prices may result in non-compliance with our financial covenants and reduced liquidity on our existing credit facilities. Non-compliance with the financial covenants in our credit facilities could result in our debt becoming due and payable on demand. Should we anticipate non-compliance we will pro-actively approach our lending syndicate to amend the credit facilities to ensure their availability. There is no certainty that we will be successful in negotiating such amendments.
The capital intensive nature of our operations requires us to maintain adequate sources of liquidity to fund ongoing exploration and development. 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 our internally generated adjusted funds flow and our existing undrawn credit facilities will provide sufficient liquidity to sustain our operations and 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 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.
At March 31, 2020, net debt of $2,051.6 million was $179.8 million higher than $1,871.8 million at December 31, 2019. The increase in net debt is primarily the result of a $110.7 million increase in the reported amount of our U.S. dollar denominated net debt due to a weaker Canadian dollar at March 31, 2020 along with exploration and development expenditures that exceeded adjusted funds flow by $43.8 million. We incurred total costs of $15.8 million including transaction costs on the issuance of the US$500 million senior notes due 2027 and the early redemption expense on redemption of the $300 million senior notes due 2022.
We monitor our capital structure and liquidity requirements using a net debt to adjusted funds flow ratio calculated on a twelve month trailing basis. At March 31, 2020, our net debt to adjusted funds flow ratio was 2.5 compared to a ratio of 2.1 as at December 31, 2019. The increase in the net debt to adjusted funds flow ratio relative to December 31, 2019 is attributed to lower adjusted funds flow due to lower commodity pricing combined with a $179.8 million increase in net debt at March 31, 2020.
Credit Facilities
At March 31, 2020, the principal amount of credit facilities and letters of credit outstanding was $694.9 million and we had $417.0 million of undrawn capacity under our credit facilities that total approximately $1.11 billion. Our credit facilities include US$575 million of revolving credit facilities and a $300 million non-revolving term loan (collectively, the "Credit Facilities").
On March 3, 2020, we amended our Credit Facilities to extend maturity from April 2, 2021 to April 2, 2024. These facilities 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, plus applicable margins. In the event that Baytex exceeds any of the covenants under the Credit Facilities, Baytex may be required to repay, refinance or renegotiate the loan terms and may be restricted from taking on further debt or paying dividends to shareholders.
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 3.4% for Q1/2020 compared to 4.2% for Q1/2019.
Financial Covenants
The following table summarizes the financial covenants applicable to the Credit Facilities and our compliance therewith at March 31, 2020.
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| Covenant Description | Position as at March 31, 2020 | | Covenant |
Senior Secured Debt(1) to Bank EBITDA(2) (Maximum Ratio) | 0.8:1.00 | | 3.50:1.00 |
Interest Coverage(3) (Minimum Ratio) | 8.6:1.00 | | 2.00:1.00 |
(1)"Senior Secured Debt" is defined as the principal amount of the credit facilities and other secured obligations identified in the credit agreement. As at March 31, 2020, the Company's Senior Secured Debt totaled $694.9 million which includes $678.7 million of principal amounts outstanding and $16.2 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, unrealized gains and losses on financial derivatives and foreign exchange and share-based compensation) and is calculated based on a trailing twelve month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended March 31, 2020 was $923.8 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 three months ended March 31, 2020 were $107.2 million.
Long-Term Notes
We have two series of long-term notes outstanding that total $1.27 billion as at March 31, 2020. The long-term notes do not contain any significant financial maintenance covenants. The long-term notes contain a debt incurrence covenant that restricts our ability to raise additional debt beyond our existing Credit Facilities and long-term notes unless we maintain a minimum fixed charge coverage ratio (computed as the ratio of Bank EBITDA to financing and interest expenses on a trailing twelve month basis) of 2.00:1.00. The fixed charge coverage ratio was 8.1:1.00 as at March 31, 2020.
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. As of June 1, 2019, the 5.625% Notes are redeemable at our option, in whole or in part, at specified redemption prices and will be redeemable at par from June 1, 2022 to maturity.
On February 5, 2020, we issued US$500 million aggregate principal amount of senior unsecured notes due April 1, 2027 bearing interest at a rate of 8.75% per annum payable semi-annually (the "8.75% Senior Notes)". The 8.75% Senior Notes are redeemable at our option, in whole or in part, at specified redemption prices after April 1, 2023 and will be redeemable at par from April 1, 2026 to maturity. Transaction costs of $12.5 million were incurred in conjunction with the issuance which resulted in net proceeds of $652.2 million.
On February 20, 2020, we used a portion of the net proceeds from the issuance of the 8.75% Senior Notes to complete the early redemption of the US$400 million principal amount of the 5.125% senior unsecured notes due June 1, 2021 at par plus accrued interest. The payment at redemption was $530.4 million.
On March 5, 2020, Baytex completed the early redemption of the $300 million principal amount of the 6.625% senior unsecured notes due July 19, 2022 at 101.104% of the principal amount plus accrued interest. The payment at redemption includes principal of $300.0 million plus early redemption expense of $3.3 million.
Shareholders’ Capital
We are authorized to issue an unlimited number of common shares and 10.0 million preferred shares. The rights and terms of preferred shares are determined upon issuance. During the three months ended March 31, 2020, we issued 2.2 million common shares pursuant to our share-based compensation program. As at May 7, 2020, we had 560.5 million common shares issued and outstanding and no preferred shares issued and outstanding.
Contractual Obligations
We have a number of financial obligations that are incurred in the ordinary course of business. These obligations are of a recurring nature and impact our adjusted funds flow in an ongoing manner. A significant portion of these obligations will be funded by adjusted funds flow. These obligations as of March 31, 2020 and the expected timing for funding these obligations are noted in the table below.
| | | | | | | | | | | | | | | | | |
| ($ thousands) | Total | Less than 1 year | 1-3 years | 3-5 years | Beyond 5 years |
| Trade and other payables | $ | 209,776 | | $ | 209,776 | | $ | — | | $ | — | | $ | — | |
Credit facilities(1) (2) | 678,740 | | — | | — | | 678,740 | | — | |
Long-term notes(2) | 1,270,800 | | — | | — | | 564,800 | | 706,000 | |
Interest on long-term notes(3) | 565,153 | | 93,545 | | 187,090 | | 160,630 | | 123,888 | |
| Lease agreements | 13,342 | | 6,269 | | 6,683 | | 390 | | — | |
| Processing agreements | 12,114 | | 6,583 | | 1,454 | | 670 | | 3,407 | |
| Transportation agreements | 116,237 | | 13,022 | | 43,027 | | 35,486 | | 24,702 | |
| Total | $ | 2,866,162 | | $ | 329,195 | | $ | 238,254 | | $ | 1,440,716 | | $ | 857,997 | |
(1)The credit facilities matures on April 2, 2024. Maturity will automatically be extended to June 4, 2024 providing Baytex has either refinanced, or has the ability to repay, the outstanding 2024 long-term notes with existing credit capacity as of April 1, 2024.
(2)Principal amount of instruments.
(3)Excludes interest on our credit facilities as interest payments fluctuate based on a floating rate of interest and changes in the outstanding balances.
We also have ongoing obligations related to the abandonment and reclamation of well sites and facilities when they reach the end of their economic lives. Programs to abandon and reclaim well sites and facilities are undertaken regularly in accordance with applicable legislative requirements.
Physical Delivery Commitments
We have commitments to deliver heavy oil volumes by rail. These contracts are held for the purpose of delivery of non-financial items in accordance with our expected sale requirements. Physical delivery contracts are not considered financial instruments and, as a result, no asset or liability has been recognized in the consolidated statements of financial position.
As at March 31, 2020, we had committed to deliver the following volumes of raw bitumen to market on rail. Pricing for these contracts is based on either the WTI benchmark or the WCS benchmark, less a discount.
| | | | | |
| Period | Volume (bbl/d) |
| April 2020 | 6,500 | |
| May 2020 | 3,250 | |
| June 2020 | 6,000 | |
| July 2020 - December 2020 | 11,500 | |
Baytex Energy Corp.
Q1 2020 MD&A 19
QUARTERLY FINANCIAL INFORMATION
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| 2020 | 2019 | | | | 2018 | | | | |
| ($ thousands, except per common share amounts) | Q1 | | Q4 | | Q3 | | Q2 | | Q1 | | Q4 | | Q3 | | Q2 | | | |
| Petroleum and natural gas sales | 336,614 | | 445,895 | | 424,600 | | 482,000 | | 453,424 | | 358,437 | | 436,761 | | 347,605 | | | |
| Net income (loss) | (2,498,217) | | (117,772) | | 15,151 | | 78,826 | | 11,336 | | (231,238) | | 27,412 | | (58,761) | | | |
| Per common share - basic | (4.46) | | (0.21) | | 0.03 | | 0.14 | | 0.02 | | (0.42) | | 0.07 | | (0.25) | | | |
| Per common share - diluted | (4.46) | | (0.21) | | 0.03 | | 0.14 | | 0.02 | | (0.42) | | 0.07 | | (0.25) | | | |
| Adjusted funds flow | 132,935 | | 232,147 | | 213,379 | | 236,130 | | 220,770 | | 110,828 | | 171,210 | | 106,690 | | | |
| Per common share - basic | 0.24 | | 0.42 | | 0.38 | | 0.42 | | 0.40 | | 0.20 | | 0.46 | | 0.45 | | | |
| Per common share - diluted | 0.24 | | 0.42 | | 0.38 | | 0.42 | | 0.40 | | 0.20 | | 0.45 | | 0.45 | | | |
| Exploration and development | 176,777 | | 153,117 | | 139,085 | | 106,246 | | 153,843 | | 184,162 | | 139,195 | | 78,830 | | | |
| Canada | 123,110 | | 104,460 | | 96,774 | | 68,259 | | 104,870 | | 125,507 | | 94,477 | | 30,608 | | | |
| U.S. | 53,667 | | 48,657 | | 42,311 | | 37,987 | | 48,973 | | 58,655 | | 44,718 | | 48,222 | | | |
| Acquisitions, net of divestitures | (40) | | 563 | | (30) | | 1,647 | | — | | 229 | | — | | (21) | | | |
| Net debt | 2,051,617 | | 1,871,791 | | 1,971,339 | | 2,028,686 | | 2,175,241 | | 2,265,167 | | 2,112,090 | | 1,784,835 | | | |
| Total assets | 3,441,040 | | 5,914,083 | | 6,233,875 | | 6,222,190 | | 6,359,157 | | 6,377,198 | | 6,491,303 | | 4,476,906 | | | |
| Common shares outstanding | 560,483 | | 558,305 | | 557,972 | | 556,798 | | 555,872 | | 554,060 | | 553,950 | | 236,662 | | | |
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| Daily production | | | | | | | | | | |
| Total production (boe/d) | 98,452 | | 96,360 | | 94,927 | | 98,402 | | 101,115 | | 98,890 | | 82,412 | | 70,664 | | | |
| Canada (boe/d) | 62,262 | | 57,794 | | 58,134 | | 58,580 | | 60,018 | | 60,453 | | 45,214 | | 34,042 | | | |
| U.S. (boe/d) | 36,190 | | 38,566 | | 36,793 | | 39,822 | | 41,097 | | 38,437 | | 37,198 | | 36,622 | | | |
| | | | | | | | | | |
| Benchmark prices | | | | | | | | | | |
| WTI oil (US$/bbl) | 46.17 | | 56.96 | | 56.45 | | 59.81 | | 54.90 | | 58.81 | | 69.50 | | 67.88 | | | |
| WCS heavy (US$/bbl) | 25.65 | | 41.13 | | 44.21 | | 49.14 | | 42.61 | | 19.39 | | 47.25 | | 48.61 | | | |
| CAD/USD avg exchange rate | 1.3445 | | 1.3201 | | 1.3207 | | 1.3376 | | 1.3293 | | 1.3215 | | 1.3070 | | 1.2911 | | | |
| AECO gas ($/mcf) | 2.14 | | 2.34 | | 1.04 | | 1.17 | | 1.94 | | 1.94 | | 1.35 | | 1.03 | | | |
| NYMEX gas (US$/mmbtu) | 1.95 | | 2.50 | | 2.23 | | 2.64 | | 3.15 | | 3.64 | | 2.90 | | 2.80 | | | |
| | | | | | | | | | |
| Sales price ($/boe) | 35.19 | | 48.25 | | 47.14 | | 51.49 | | 47.98 | | 37.89 | | 55.03 | | 51.22 | | | |
| Royalties ($/boe) | (6.33) | | (8.72) | | (8.59) | | (9.67) | | (8.94) | | (8.77) | | (12.13) | | (12.01) | | | |
| Operating expense ($/boe) | (11.66) | | (11.23) | | (11.15) | | (11.22) | | (11.02) | | (10.76) | | (10.25) | | (10.91) | | | |
| Transportation expense ($/boe) | (1.15) | | (1.00) | | (1.13) | | (1.33) | | (1.46) | | (1.21) | | (1.26) | | (1.22) | | | |
| Operating netback ($/boe) | 16.05 | | 27.30 | | 26.27 | | 29.27 | | 26.56 | | 17.15 | | 31.39 | | 27.08 | | | |
| Financial derivatives gain (loss) ($/boe) | 3.00 | | 2.59 | | 2.39 | | 1.45 | | 2.07 | | (0.34) | | (4.07) | | (4.57) | | | |
| Operating netback after financial derivatives ($/boe) | 19.05 | | 29.89 | | 28.66 | | 30.72 | | 28.63 | | 16.81 | | 27.32 | | 22.51 | | | |
Strong operating results for Q1/2020 were overshadowed by the emergence of COVID-19 and the impact the global health crisis has had on the outlook for future crude oil demand. We delivered production of 98,452 boe/d for Q1/2020 which reflects our successful exploration and development programs in the U.S. and Canada, and marks our sixth quarter of solid operational results following the strategic combination with Raging River Exploration Inc. on August 22, 2018.
Commodity prices were relatively strong as Q1/2020 began with the West Texas Intermediate ("WTI") benchmark price averaging US$57.53/bbl in January. 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$30.45/bbl in March. The impact of this sharp decline is reflected in our realized sales price of $35.19/boe for Q1/2020.
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 throughout 2019 following the strategic combination with Raging River Exploration Inc. due to increased production and higher realizations associated with the higher weighting of light oil production, as well as strong well performance. Adjusted funds flow of $132.9 million in Q1/2020 reflects the impact of lower commodity prices which resulted in lower revenue net of royalties.
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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 increased from $1,784.8 million at Q2/2018 to $2,051.6 million at Q1/2020 primarily due to the assumption of $363.6 million of net debt associated with the strategic combination with Raging River Exploration Inc. during Q3/2018. This increase in net debt was partially offset by free cash flow generated throughout 2019 which was directed towards debt repayment.
OFF BALANCE SHEET TRANSACTIONS
We do not have any financial arrangements that are excluded from the consolidated financial statements as at March 31, 2020, nor are any such arrangements outstanding as of the date of this MD&A.
CRITICAL ACCOUNTING ESTIMATES
There have been no changes in our critical accounting estimates in the three months ended March 31, 2020. 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, 2019.
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.
The following table reconciles cash flow from operating activities to adjusted funds flow.
| | | | | | | | | | |
| Three Months Ended March 31 | | | |
| ($ thousands) | 2020 | 2019 | | |
| Cash flow from operating activities | $ | 182,567 | | $ | 157,365 | | | |
| Change in non-cash working capital | (53,873) | | 58,477 | | | |
| Asset retirement obligations settled | 4,241 | | 4,928 | | | |
| | | | |
| Adjusted funds flow | $ | 132,935 | | $ | 220,770 | | | |
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
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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 is therefore analyzed separately from our evaluation of the performance of our exploration and development programs.
The following table reconciles cash flow used in investing activities to exploration and development expenditures.
| | | | | | | | | | |
| Three Months Ended March 31 | | | |
| ($ thousands) | 2020 | 2019 | | |
| Cash flow used in investing activities | $ | 161,022 | | $ | 187,588 | | | |
| Change in non-cash working capital | 16,327 | | (33,680) | | | |
| Proceeds from dispositions | 40 | | — | | | |
| | | | |
| | | | |
| Additions to other plant and equipment | (612) | | (65) | | | |
| Exploration and development expenditures | $ | 176,777 | | $ | 153,843 | | | |
Free Cash Flow
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. We use free cash flow to evaluate funds available for debt repayment, common share repurchases, potential future dividends and acquisition opportunities.
The follow table provides our computation of free cash flow.
| | | | | | | | | | |
| Three Months Ended March 31 | | | |
| ($ thousands) | 2020 | 2019 | | |
| Adjusted funds flow | $ | 132,935 | | $ | 220,770 | | | |
| Exploration and development expenditures | (176,777) | | (153,843) | | | |
| Payments on lease obligations | (1,516) | | (1,389) | | | |
| Asset retirement obligations settled | (4,241) | | (4,928) | | | |
| Free cash flow | $ | (49,599) | | $ | 60,610 | | | |
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. The current portion of financial derivatives is excluded as the valuation of the underlying contracts is subject to a high degree of volatility prior to the ultimate settlement. Onerous contracts are excluded from net debt as the underlying contracts do not represent an available source of liquidity. We use the principal amounts of the 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 liquidity or repayment obligation.
The following table summarizes our calculation of net debt.
| | | | | | | | |
| ($ thousands) | March 31, 2020 | December 31, 2019 |
Credit facilities(1) | $ | 678,740 | | $ | 506,471 | |
Long-term notes(1) | 1,270,800 | | 1,337,200 | |
| Trade and other payables | 209,776 | | 207,454 | |
| Cash | — | | (5,572) | |
| Trade and other receivables | (107,699) | | (173,762) | |
| Net debt | $ | 2,051,617 | | $ | 1,871,791 | |
(1)Principal amount of instruments expressed in Canadian dollars.
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Operating Netback
We define operating netback as petroleum and natural gas sales, less blending expense, royalties, operating expense and transportation expense. Operating netback per boe is the operating netback divided by barrels of oil equivalent production volume for the applicable period. We believe that this measure assists in assessing our ability to generate cash margin on a unit of production basis and is a key measure used to evaluate our operating performance.
| | | | | | | | | | |
| Three Months Ended March 31 | | | |
| ($ thousands) | 2020 | 2019 | | |
| Petroleum and natural gas sales | $ | 336,614 | | $ | 453,424 | | | |
| Blending and other expense | (21,357) | | (16,788) | | | |
| Total sales, net of blending and other expense | 315,257 | | 436,636 | | | |
| Royalties | (56,720) | | (81,325) | | | |
| Operating expense | (104,470) | | (100,292) | | | |
| Transportation expense | (10,342) | | (13,330) | | | |
| Operating netback | 143,725 | | 241,689 | | | |
| Realized financial derivative gain | 26,850 | | 18,814 | | | |
| Operating netback after realized financial derivatives | $ | 170,575 | | $ | 260,503 | | | |
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.
| | | | | | | | | | |
| Three Months Ended March 31 | | | |
| ($ thousands) | 2020 | 2019 | | |
| Net income (loss) | $ | (2,498,217) | | $ | 11,336 | | | |
| Plus: | | | | |
| Financing and interest | 39,220 | | 32,742 | | | |
| Unrealized foreign exchange (gain) loss | 99,521 | | (26,941) | | | |
| Unrealized financial derivatives (gain) loss | (95,995) | | 53,261 | | | |
| Current income tax expense | 469 | | 595 | | | |
| Deferred income tax recovery | (283,179) | | (14,485) | | | |
| Depletion and depreciation | 181,386 | | 185,354 | | | |
| Gain on dispositions | (137) | | — | | | |
| | | | |
| Impairment | 2,716,349 | | — | | | |
Non-cash items(1) | 2,522 | | 7,687 | | | |
| | | | |
| Bank EBITDA | $ | 161,939 | | $ | 249,549 | | | |
(1) Non-cash items include share-based compensation and exploration and evaluation expense.
INTERNAL CONTROL OVER FINANCIAL REPORTING
We are required to comply with Multilateral Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings". This instrument requires us to disclose in our interim MD&A any weaknesses in or changes to our internal control over financial reporting during the period that may have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. We confirm that no such weaknesses were identified in, or changes were made to, internal controls over financial reporting during the three months ended March 31, 2020.
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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 ability to shut-in and quickly restart production; that sustained low commodity prices may result in non-compliance with our financial covenants and reduced liquidity; that we will pro-actively negotiate amendments to our existing credit facilities; our capital budget and expected average daily production for 2020; our expected royalty rate and operating, transportation, general and administrative and interest expenses for 2020; the existence, operation and strategy of our risk management program; that management of our debt levels is a priority; the non-cash charge against deferred income tax we intend to take in Q2/2020; the reassessment of our tax filings by the Canada Revenue Agency; our intention to defend the reassessments; our view of our tax filing position; that we have flexibility to increase capital expenditures in Canada in 2020; that our internally generated adjusted funds flow and our existing undrawn credit facilities will provide sufficient liquidity to sustain our operations and planned capital expenditures; that a significant portion of our financial obligations will be funded by adjusted funds flow.
These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum and natural gas prices and differentials between light, medium and heavy oil prices (well production rates and reserve volumes; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; our ability to borrow under our credit agreements; the receipt, in a timely manner, of regulatory and other required approvals for our operating activities; the availability and cost of labour and other industry services; interest and foreign exchange rates; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; our ability to develop our crude oil and natural gas properties in the manner currently contemplated; and current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being adopted as anticipated). Readers are cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.
Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: the volatility of oil and natural gas prices and price differentials (including the impacts of COVID-19); availability and cost of gathering, processing and pipeline systems; failure to comply with the covenants in our debt agreements; the availability and cost of capital or borrowing; that our credit facilities may not provide sufficient liquidity or may not be renewed; risks associated with a third-party operating our Eagle Ford properties; the cost of developing and operating our assets; depletion of our reserves; risks associated with the exploitation of our properties and our ability to acquire reserves; new regulations on hydraulic fracturing; restrictions on or access to water or other fluids; changes in government regulations that affect the oil and gas industry; regulations regarding the disposal of fluids; changes in environmental, health and safety regulations; public perception and its influence on the regulatory regime; restrictions or costs imposed by climate change initiatives; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating oil and natural gas reserves; our inability to fully insure against all risks; risks of counterparty default; risks associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks associated with large projects; risks related to our thermal heavy oil projects; alternatives to and changing demand for petroleum products; risks associated with our use of information technology systems; risks associated with the ownership of our securities, including changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control. These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2019, as filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission.
The above summary of assumptions and risks related to forward-looking statements has been provided in order to provide shareholders and potential investors with a more complete perspective on Baytex’s current and future operations and such information may not be appropriate for other purposes.
There is no representation by Baytex that actual results achieved will be the same in whole or in part as those referenced in the forward-looking statements and Baytex does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities law.
