Baytex Energy Corp.
Q1 2018 MD&A Page 1
Exhibit 99.2
BAYTEX ENERGY CORP.
Management’s Discussion and Analysis
For the three months ended March 31, 2018 and 2017
Dated May 3, 2018
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, 2018. This information is provided as of May 3, 2018. 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, 2018 ("Q1/2018") have been compared with the results for the three months ended March 31, 2017 ("Q1/2017"). This MD&A should be read in conjunction with the Company’s condensed consolidated interim unaudited financial statements (“consolidated financial statements”) for the three months ended March 31, 2018, its audited comparative consolidated financial statements for the years ended December 31, 2017 and 2016, together with the accompanying notes, and its Annual Information Form for the year ended December 31, 2017. These documents and additional information about Baytex are accessible on the SEDAR website at www.sedar.com and through the U.S. Securities and Exchange Commission at www.sec.gov. All amounts are in Canadian dollars, unless otherwise stated, and all tabular amounts are in thousands of Canadian dollars, except for percentages, per common share amounts or as otherwise noted.
In this MD&A, barrel of oil equivalent (“boe”) amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil, which represents an energy equivalency conversion method applicable at the burner tip and does not represent a value equivalency at the wellhead. While it is useful for comparative measures, it may not accurately reflect individual product values and may be misleading if used in isolation.
This MD&A contains forward-looking information and statements along with certain measures which do not have any standardized meaning prescribed by Canadian Generally Accepted Accounting Principles ("GAAP"). We refer you to the end of the MD&A for our advisory on forward-looking information and statements and a summary of our non-GAAP measures.
FIRST QUARTER HIGHLIGHTS
Baytex delivered solid operating and financial results for Q1/2018, generating adjusted funds flow of $84.3 million while investing $93.5 million on exploration and development expenditures. Strong well performance in the U.S. and Canada resulted in average production of 69,522 boe/d which approximates the mid-point of our annual guidance range of 68,000 - 72,000 boe/d.
Daily production of 69,522 boe/d for Q1/2018 was consistent with Q4/2017 production of 69,556 boe/d and was slightly higher than 69,298 boe/d reported for Q1/2017. In the U.S., enhanced completion techniques continue to drive strong well performance while the timing of completion activity resulted in U.S. daily production that was slightly lower during Q1/2018 relative to Q4/2017. In Canada, our capital programs at Lloydminster and Peace River continue to deliver strong initial production results and contributed to slightly higher daily production for our Canadian operations in Q1/2018 as compared to Q4/2017.
Our capital program in Canada was focused on our Peace River and Lloydminster properties with a total of $51.5 million invested on exploration and development during Q1/2018. We drilled three (3.0 net) wells at Peace River and 33 (25.9 net) wells at Lloydminster during Q1/2018. Drilling activity at Lloydminster included three (3.0 net) well pairs and facility construction costs for steam-assisted gravity drainage ("SAGD") operations at our Kerrobert thermal project. Our Canadian capital program for Q1/2018 included $9.4 million for the construction of a gas plant and strategic infrastructure to support growth at Peace River.
In the U.S., we invested $42.0 million on development activity during Q1/2018 and drilled 25 (6.9 net) wells and commenced production from 27 (5.5 net) wells. Drilling and completion activity was lower in Q1/2018 relative to Q1/2017 as the operator of our Eagle Ford properties focused development activity on lands where we have a lower working interest. Despite the lower activity in Q1/2018, strong well performance from enhanced completions techniques utilizing higher proppant loading and increased frac stages resulted in U.S. production of 36,017 boe/d for Q1/2018 which is consistent with Q1/2017. U.S. production for Q1/2018 was lower than 37,362 boe/d reported for Q4/2017 due to the timing of completion activity on our lands.
During Q1/2018, strengthening global oil demand along with ongoing compliance with production curtailments by the Organization of Petroleum Exporting Countries ("OPEC") resulted in further reductions in global crude oil inventories. The West Texas Intermediate ("WTI") benchmark oil price averaged US$62.87/bbl for Q1/2018 which is an increase of 21% from US$51.91/bbl for Q1/2017. Pipeline outages in late 2017 compounded existing transportation bottlenecks for heavy grades of Canadian crude oil and resulted in a widening of the price differential for Canadian heavy oil relative to WTI from US$14.57/bbl in Q1/2017 to US$24.28/bbl in Q1/2018. The improvement in light oil market prices has been largely offset by wider heavy oil differentials in Canada resulting in an increase in our realized sales price to $42.96/boe in Q1/2018 from $40.16/boe in Q1/2017.
We generated adjusted funds flow of $84.3 million for the first quarter of 2018, an increase of $2.9 million from adjusted funds flow of $81.4 million reported for Q1/2017. The increase in adjusted funds flow in Q1/2018 was primarily due to higher realized prices which increased $2.80/boe and resulted in a $25.5 million increase in petroleum and natural gas sales relative to Q1/2017. The increase in realized prices for Q1/2018 was partially offset by higher royalties and higher operating, transportation and blending and
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Q1 2018 MD&A Page 2
other expenses, which were $17.1 million higher than Q1/2017. The $8.4 million increase in operating netback was offset by a $10.1 million increase in hedging losses recorded in Q1/2018 as benchmark prices were higher relative to our contract prices in the first quarter of 2018. Corporate costs, including general and administrative expenses and payments on onerous contracts, were $4.6 million lower in Q1/2018 relative to Q1/2017 and contributed to the $2.9 million increase in adjusted funds flow.
At March 31, 2018, net debt was $1,783.4 million, an increase of $49.1 million from $1,734.3 million at December 31, 2017. The increase in net debt is primarily due to the weakening of the Canadian dollar which resulted in a $36.0 million increase in the reported amount of our U.S. dollar denominated debt at March 31, 2018.
RESULTS OF OPERATIONS
The Canadian division includes our heavy oil assets in Peace River and Lloydminster and our conventional oil and natural gas assets in Western Canada. The U.S. division includes our Eagle Ford assets in Texas.
Production
Three Months Ended March 31 | ||||||||||||
2018 | 2017 | |||||||||||
Daily Production | Canada | U.S. | Total | Canada | U.S. | Total | ||||||
Liquids (bbl/d) | ||||||||||||
Heavy oil | 24,868 | — | 24,868 | 24,625 | — | 24,625 | ||||||
Light oil and condensate | 859 | 20,108 | 20,967 | 1,252 | 20,365 | 21,617 | ||||||
Natural Gas Liquids ("NGL") | 1,299 | 7,844 | 9,143 | 1,099 | 7,207 | 8,306 | ||||||
Total liquids (bbl/d) | 27,026 | 27,952 | 54,978 | 26,976 | 27,572 | 54,548 | ||||||
Natural gas (mcf/d) | 38,873 | 48,388 | 87,261 | 37,447 | 51,055 | 88,502 | ||||||
Total production (boe/d) | 33,505 | 36,017 | 69,522 | 33,217 | 36,081 | 69,298 | ||||||
Production Mix | ||||||||||||
Heavy oil | 74 | % | — | % | 36 | % | 74 | % | — | % | 36 | % |
Light oil and condensate | 3 | % | 56 | % | 30 | % | 4 | % | 56 | % | 31 | % |
NGL | 4 | % | 22 | % | 13 | % | 3 | % | 20 | % | 12 | % |
Natural gas | 19 | % | 22 | % | 21 | % | 19 | % | 24 | % | 21 | % |
Average production for Q1/2018 was 69,522 boe/d which approximates the mid-point of our annual guidance range of 68,000 - 72,000 boe/d. Our average daily production for Q1/2018 was slightly higher than 69,298 boe/d reported for Q1/2017 due to our successful 2017 capital development program combined with strong well performance in the U.S. and Canada. Higher production in Canada due to strong well performance offset lower production in the U.S. due to the timing of completion activity resulting in production for Q1/2018 that was consistent with 69,556 boe/d reported for Q4/2017. We expect our 2018 production to be within our annual guidance range of 68,000 - 72,000 boe/d.
Production in Canada averaged 33,505 boe/d for Q1/2018 which is slightly higher than average production of 33,217 boe/d reported for Q1/2017 and an increase of 4% from 32,194 boe/d reported for Q4/2017. Strong production results from operated wells brought online at Lloydminster during Q1/2018 contributed to the increase in average daily production from Q4/2017. Positive results from our 2017 Canadian development program have offset natural decline and resulted in slightly higher production for Q1/2018 relative to the comparative period of 2017.
In the U.S., production averaged 36,017 boe/d in Q1/2018 which is consistent with 36,081 boe/d reported for Q1/2017 and down 4% from 37,362 boe/d for Q4/2017. The timing of completion activity during the last two quarters resulted in a decline in average daily production for Q1/2018 relative to Q4/2017. During Q1/2018, we commenced production from 27 (5.5 net) wells as compared to 33 (9.4 net) during Q1/2017. Despite lower completion activity, average daily production for Q1/2018 was consistent with the comparative period of 2017 as a result of strong initial production rates for wells brought online during the first quarter of 2018 due to increased frac stages and higher proppant loading.
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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 have continued to improve in 2018 as global demand growth and sustained compliance with OPEC production curtailments continue to reduce elevated inventory levels. The WTI benchmark oil price is the representative index for inland North American light oil at Cushing, Oklahoma. During Q1/2018, the WTI benchmark price averaged US$62.87/bbl, an increase of 21% from US$51.91/bbl during the first quarter of 2017 and an increase of 13% from US$55.40/bbl during Q4/2017.
Our U.S. crude oil production is primarily priced off the Louisiana Light Sweet ("LLS") stream at St. James, Louisiana, which is the representative benchmark for light oil pricing at the U.S. Gulf coast. Increases in U.S. crude oil exports combined with an increase in global benchmark pricing have increased the premium received for LLS relative to WTI. The LLS benchmark price was US$67.07/bbl representing a US$4.20/bbl premium to WTI for Q1/2018 compared to US$52.50/bbl or a US$0.59/bbl premium to WTI for the same period of 2017.
The price received for our heavy oil sales in Canada is based on the Western Canadian Select ("WCS") benchmark price which trades at a discount to WTI due to the quality and lack of egress for Canadian grades of crude oil. Pipeline outages in late 2017 have compounded existing transportation constraints and have resulted in increased crude inventories in Western Canada and a widening of the WCS heavy oil differential during Q1/2018. The WCS heavy oil differential averaged US$24.28/bbl in Q1/2018 as compared to US$14.57/bbl in Q1/2017. Increased crude by rail volumes will help to mitigate this recent widening of the WCS differential which is now estimated to average approximately US$20/bbl for the remainder of 2018.
Natural Gas
Natural gas prices were lower in Q1/2018 relative to the same period of 2017 as maintenance downtime on pipeline systems in Western Canada during the second half of 2017 created transportation bottlenecks and a lower AECO benchmark relative to Q1/2017. Supply levels in the U.S. increased throughout 2017 which has resulted in a decline in U.S. natural gas benchmark prices in Q1/2018 as compared to early 2017.
Our U.S. natural gas production is priced in reference to the New York Mercantile Exchange ("NYMEX") natural gas index. During the first quarter of 2018, the NYMEX natural gas benchmark averaged US$3.00/mmbtu, a decrease of 9% from US$3.32/mmbtu for the same period of 2017.
In Canada, we receive natural gas pricing based on the AECO benchmark which averaged $1.85/mcf during Q1/2018 which is 37% lower than $2.94/mcf during Q1/2017. The AECO benchmark continues to trade at a significant discount to NYMEX as a result of increasing supply and limited market access for Canadian natural gas production.
The following tables compare selected benchmark prices and our average realized selling prices for the three months ended March 31, 2018 and 2017.
Three Months Ended March 31 | ||||||
2018 | 2017 | Change | ||||
Benchmark Averages | ||||||
WTI oil (US$/bbl)(1) | 62.87 | 51.91 | 21 | % | ||
WTI oil (CAD$/bbl) | 79.54 | 68.68 | 16 | % | ||
WCS heavy oil (US$/bbl)(2) | 38.59 | 37.34 | 3 | % | ||
WCS heavy oil (CAD$/bbl) | 48.83 | 49.39 | (1 | )% | ||
LLS oil (US$/bbl)(3) | 67.07 | 52.50 | 28 | % | ||
LLS oil (CAD$/bbl) | 84.85 | 69.45 | 22 | % | ||
CAD/USD average exchange rate | 1.2651 | 1.3229 | (4 | )% | ||
Edmonton par oil ($/bbl) | 72.06 | 63.98 | 13 | % | ||
AECO natural gas price ($/mcf)(4) | 1.85 | 2.94 | (37 | )% | ||
NYMEX natural gas price (US$/mmbtu)(5) | 3.00 | 3.32 | (9 | )% |
(1) | WTI refers to the arithmetic average of NYMEX prompt month WTI for the applicable period. |
(2) | WCS refers to the average posting price for the benchmark WCS heavy oil. |
(3) | LLS refers to the Argus trade month average for Louisiana Light Sweet 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 | ||||||||||||||||||
2018 | 2017 | |||||||||||||||||
Canada | U.S. | Total | Canada | U.S. | Total | |||||||||||||
Average Realized Sales Prices(1) | ||||||||||||||||||
Heavy oil ($/bbl)(2) | $ | 33.33 | $ | — | $ | 33.33 | $ | 35.96 | $ | — | $ | 35.96 | ||||||
Light oil and condensate ($/bbl) | 62.78 | 79.90 | 79.20 | 58.05 | 63.58 | 63.26 | ||||||||||||
NGL ($/bbl) | 28.72 | 25.75 | 26.17 | 30.06 | 25.78 | 26.35 | ||||||||||||
Natural gas ($/mcf) | 1.92 | 3.78 | 2.95 | 2.64 | 4.17 | 3.52 | ||||||||||||
Weighted average ($/boe)(2) | $ | 29.69 | $ | 55.30 | $ | 42.96 | $ | 32.81 | $ | 46.93 | $ | 40.16 |
(1) | Baytex's risk management strategy employs both oil and natural gas financial and physical forward contracts (fixed price forward sales and collars) and heavy oil differential physical delivery contracts (fixed price and percentage of WTI). The pricing information in this table excludes the impact of financial derivatives. |
(2) | 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 $42.96/boe for Q1/2018, up $2.80/boe from $40.16/boe reported for the first quarter of 2017. Higher crude oil pricing helped to increase the weighted average sales price for our U.S. production which was partially offset by a lower weighted average sales price received for our production in Canada due to a widening of the WCS heavy oil differential.
In Canada, our realized heavy oil sales price, net of blending and other expense averaged $33.33/bbl which is $2.63/bbl lower than realized pricing of $35.96/bbl for Q1/2017. The decrease in our realized heavy oil sales price for Q1/2018 is primarily a result of an increase in the cost and quantity of blending diluent required for pipeline transportation relative to Q1/2017. Our realized heavy oil price for Q1/2018 was also impacted by a decrease in WCS benchmark pricing (expressed in Canadian dollars) which was $0.56/bbl lower relative to the same period of 2017. Our Canadian heavy oil production requires blending with diluent in order to meet pipeline transportation specifications. The price received for the blended product is recorded as heavy oil sales revenue. We include the cost of blending diluent in our realized heavy oil sales price in order to compare our realized pricing on our produced volumes to the WCS benchmark.
Our realized Canadian light oil and condensate price averaged $62.78/bbl for Q1/2018, an increase of $4.73/bbl from $58.05/bbl for Q1/2017. The price received for Canadian light oil and condensate sales is discounted to benchmark oil prices with adjustments for quality and is net of fees and differentials that do not fluctuate with prices. During Q3/2017, we disposed of certain oil and natural gas properties in our Conventional business unit which produced a higher quality light oil than our remaining Canadian properties. As a result, our realized light oil and condensate price only increased $4.73/bbl relative to an $8.08/bbl increase in Edmonton par pricing for Q1/2018 relative to the same period of 2017.
In the U.S., our realized light oil and condensate price was $79.90/bbl for the first quarter of 2018. This represents an increase of $16.32/bbl from $63.58/bbl reported for Q1/2017, as compared to a $15.40/bbl increase in LLS benchmark (expressed in Canadian dollars) pricing over the same period. Improved contract pricing following the re-negotiation of certain marketing arrangements along with increased pipeline capacity has reduced the pricing differential on our U.S. light oil and condensate realized price relative to the LLS benchmark. These factors more than offset the impact that a stronger Canadian dollar had on the LLS benchmark expressed in Canadian dollars and our realized pricing in Q1/2018 relative to Q1/2017.
For Q1/2018, our realized NGL price was $26.17/bbl or 33% of WTI (expressed in Canadian dollars) compared to $26.35/bbl or 38% of WTI in Q1/2017. Our realized 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 of the underlying products. The decrease in our realized price is consistent with the decrease in the market prices for propane and butane which were lower relative to WTI in Q1/2018 as compared to Q1/2017.
Our realized natural gas price in Canada was $1.92/mcf for Q1/2018 compared to realized pricing of $2.64/mcf in Q1/2017. The decrease is primarily due to lower AECO benchmark pricing in Q1/2018 relative to the comparative period. A portion of our Canadian natural gas sales are referenced to the AECO daily index which was higher throughout Q1/2018 relative to the AECO monthly average index. Accordingly, our realized sales price for Q1/2018 decreased by $0.72/mcf from Q1/2017 relative to a $1.09/mcf decrease in the AECO monthly average over the same periods.
Our U.S. realized natural gas price was $3.78/mcf in Q1/2018, down from $4.17/mcf reported for the first three months of 2017. This represents a decrease of $0.39/mcf which is consistent with the decrease in the NYMEX natural gas benchmark (expressed in Canadian dollars) in Q1/2018 relative to Q1/2017.
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Petroleum and Natural Gas Sales
Three Months Ended March 31 | ||||||||||||||||||
2018 | 2017 | |||||||||||||||||
($ thousands) | Canada | U.S. | Total | Canada | U.S. | Total | ||||||||||||
Oil sales | ||||||||||||||||||
Heavy oil | $ | 91,883 | $ | — | $ | 91,883 | $ | 89,746 | $ | — | $ | 89,746 | ||||||
Light oil and condensate | 4,851 | 144,607 | 149,458 | 6,542 | 116,535 | 123,077 | ||||||||||||
NGL | 3,356 | 18,178 | 21,534 | 2,972 | 16,724 | 19,696 | ||||||||||||
Total liquids sales | 100,090 | 162,785 | 262,875 | 99,260 | 133,259 | 232,519 | ||||||||||||
Natural gas sales | 6,724 | 16,468 | 23,192 | 8,891 | 19,139 | 28,030 | ||||||||||||
Total petroleum and natural gas sales | 106,814 | 179,253 | 286,067 | 108,151 | 152,398 | 260,549 | ||||||||||||
Blending and other expense | (17,290 | ) | — | (17,290 | ) | (10,057 | ) | — | (10,057 | ) | ||||||||
Total sales, net of blending and other expense | $ | 89,524 | $ | 179,253 | $ | 268,777 | $ | 98,094 | $ | 152,398 | $ | 250,492 |
Total petroleum and natural gas sales were $286.1 million for Q1/2018, an increase of $25.5 million from $260.5 million reported for Q1/2017. The increase was primarily driven by higher realized pricing in Q1/2018 as production was fairly consistent during Q1/2018 and Q1/2017.
In Canada, petroleum and natural gas sales were $106.8 million for the first quarter of 2018, down 1% from $108.2 million in the same period of 2017. Total sales, net of blending and other expense, decreased as a result of a decline in Canadian benchmark prices which reduced our weighted average realized price by 10% from $32.81/boe in Q1/2017 to $29.69/boe in Q1/2018 combined with an increase in blending and other expense which was $7.2 million higher than Q1/2017. The impact of a lower weighted average realized price was partially offset by higher average daily production of 33,505 boe/d for the first quarter of 2018, which is slightly higher than 33,217 boe/d for the same period of 2017.
Petroleum and natural gas sales of $179.3 million in the U.S. increased 18% or $26.9 million from $152.4 million reported for the first quarter of 2017. The increase was driven by an 18% increase in our weighted average realized price of $55.30/boe for Q1/2018 as compared to $46.93/boe in Q1/2017. Average daily production in the U.S. was 36,017 boe/d in the first quarter of 2018 which is consistent with 36,081 boe/d reported for the comparative period of 2017.
Royalties
Royalties are paid to various government entities and to land and mineral rights owners. Royalties are calculated based on gross revenues or on operating netbacks less capital investment for specific heavy oil projects, and are generally expressed as a percentage of gross revenue. The actual royalty rates can vary for a number of reasons, including the commodity produced, royalty contract terms, commodity price level, royalty incentives and the area or jurisdiction. The following table summarizes our royalties and royalty rates for the three months ended March 31, 2018 and 2017.
Three Months Ended March 31 | ||||||||||||||||||
2018 | 2017 | |||||||||||||||||
($ thousands except for % and per boe) | Canada | U.S. | Total | Canada | U.S. | Total | ||||||||||||
Royalties | $ | 11,334 | $ | 53,505 | $ | 64,839 | $ | 12,633 | $ | 44,544 | $ | 57,177 | ||||||
Average royalty rate(1) | 12.7 | % | 29.8 | % | 24.1 | % | 12.9 | % | 29.2 | % | 22.8 | % | ||||||
Royalty rate per boe | $ | 3.76 | $ | 16.51 | $ | 10.36 | $ | 4.23 | $ | 13.72 | $ | 9.17 |
(1) | Average royalty rate is calculated as royalties divided by total sales, net of blending and other expense. |
Total royalties for Q1/2018 were $64.8 million and averaged 24.1% of total sales, net of blending and other expense, which is consistent with our 2018 annual guidance of approximately 23%. A higher portion of our petroleum and natural gas sales were from our U.S. operations during Q1/2018, which increases our corporate average royalty rate due to the higher royalty rate on our U.S. acreage relative to our Canadian properties. We have maintained our guidance for our royalty rate of approximately 23%. Our Canadian royalty rate averaged 12.7% of total sales, net of blending and other expense, for Q1/2018 which is consistent with 12.9% for the same period of 2017. In the U.S., royalties for the first quarter of 2018 averaged 29.8% of total sales, net of blending and other expense, which is slightly higher than 29.2% for Q1/2017 as the royalty rate on our U.S. production does not vary with price but can vary across our acreage. Total royalties of $64.8 million for Q1/2018 increased $7.7 million as compared to Q1/2017 due to higher realized pricing in combination with an increase in the portion of total petroleum and natural gas sales coming from our U.S operations.
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Operating Expense
Three Months Ended March 31 | ||||||||||||||||||
2018 | 2017 | |||||||||||||||||
($ thousands except for per boe) | Canada | U.S.(1) | Total | Canada | U.S.(1) | Total | ||||||||||||
Operating expense | $ | 45,420 | $ | 20,468 | $ | 65,888 | $ | 43,403 | $ | 20,727 | $ | 64,130 | ||||||
Operating expense per boe | $ | 15.06 | $ | 6.31 | $ | 10.53 | $ | 14.52 | $ | 6.38 | $ | 10.28 |
(1) | Operating expense related to the Eagle Ford assets includes transportation expense. |
Total operating expense was $65.9 million ($10.53/boe) for Q1/2018 as compared to $64.1 million ($10.28/boe) for Q1/2017 and is on the low end of our annual guidance for 2018. We expect operating expense to be within our annual guidance range of $10.50-$11.25/boe for the remainder of 2018.
In Canada, operating expense was $45.4 million ($15.06/boe) for Q1/2018, up $2.0 million or $0.54/boe from $43.4 million ($14.52/boe) for the same period of 2017. Operating expense per boe was slightly higher in Q1/2018 as a result of a slight increase in fuel and electricity costs relative to Q1/2017 in addition to planned repair and maintenance activity completed during the first three months of 2018.
U.S. operating expense of $20.5 million ($6.31/boe) for Q1/2018 was relatively consistent with $20.7 million ($6.38/boe) reported for Q1/2017. The Canadian dollar was stronger relative to the U.S. dollar in Q1/2018 which resulted in a slight decrease in our U.S. operating expense expressed in Canadian dollars compared to the first quarter of 2017.
Transportation Expense
Transportation expense includes the costs to move production from the field to the sales point. The largest component of transportation expense relates to the trucking of heavy oil in Canada to pipeline and rail terminals. The following table compares our transportation expense for the three months ended March 31, 2018 and 2017.
Three Months Ended March 31 | ||||||||||||||||||
2018 | 2017 | |||||||||||||||||
($ thousands except for per boe) | Canada | U.S.(1) | Total | Canada | U.S.(1) | Total | ||||||||||||
Transportation expense | $ | 8,519 | $ | — | $ | 8,519 | $ | 8,042 | $ | — | $ | 8,042 | ||||||
Transportation expense per boe | $ | 2.83 | $ | — | $ | 1.36 | $ | 2.69 | $ | — | $ | 1.29 |
(1) Transportation expense related to the Eagle Ford assets is included in operating expenses.
Transportation expense was $8.5 million ($1.36/boe) for Q1/2018 which is consistent with $8.0 million ($1.29/boe) for the comparative quarter of 2017 and on the low end of our annual guidance range of $1.35-$1.45/boe for 2018. Transportation expense will vary from period to period depending on hauling distances to optimize sales prices and trucking rates. We expect transportation expense to be in line with guidance for the remainder of 2018.
Blending and Other Expense
Blending and other expense primarily includes the cost of blending diluent purchased in order to reduce the viscosity of our heavy oil transported through pipelines to meet pipeline specifications. We purchase blending diluent to reduce the viscosity and record a blending and other expense. The sales price received for the blended product is recorded as heavy oil sales. Our heavy oil blending and other expense is netted against our heavy oil sales to compare the realized price on our produced volumes to benchmark pricing. Accordingly, our heavy oil sales price realization can fluctuate depending on the quantities and price of blending diluent required to meet pipeline specifications.
Blending and other expense for Q1/2018 was $17.3 million compared to $10.1 million for the first three months of 2017. The $7.2 million increase in blending and other expense during the first quarter of 2018 is due to higher diluent prices combined with an increase in the quantities of diluent required to meet pipeline specifications relative to the same period of 2017. The density of blending diluent available in Q1/2018 was higher relative to Q1/2017 which resulted in higher quantities being used to meet pipeline specifications.
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Financial Derivatives
As part of our normal operations, we are exposed to movements in commodity prices, foreign exchange rates and interest rates. In an effort to manage these exposures, we utilize various financial derivative contracts which are intended to partially reduce the volatility in our adjusted funds flow. Contracts settled in the period result in realized gains or losses based on the market price compared to the contract price and the notional volume outstanding. Changes in the fair value of unsettled contracts are reported as unrealized gains or losses in the period as the forward markets for commodities and currencies fluctuate and as new contracts are executed. The following table summarizes the results of our financial derivative contracts for the three months ended March 31, 2018 and 2017.
Three Months Ended March 31 | |||||||||
($ thousands) | 2018 | 2017 | Change | ||||||
Realized financial derivatives gain (loss) | |||||||||
Crude oil | $ | (10,265 | ) | $ | 1,084 | $ | (11,349 | ) | |
Natural gas | 424 | (810 | ) | 1,234 | |||||
Total | $ | (9,841 | ) | $ | 274 | $ | (10,115 | ) | |
Unrealized financial derivatives gain (loss) | |||||||||
Crude oil | $ | (17,659 | ) | $ | 25,890 | $ | (43,549 | ) | |
Natural gas | (50 | ) | 9,724 | (9,774 | ) | ||||
Total | $ | (17,709 | ) | $ | 35,614 | $ | (53,323 | ) | |
Total financial derivatives gain (loss) | |||||||||
Crude oil | $ | (27,924 | ) | $ | 26,974 | $ | (54,898 | ) | |
Natural gas | 374 | 8,914 | (8,540 | ) | |||||
Total | $ | (27,550 | ) | $ | 35,888 | $ | (63,438 | ) |
The realized financial derivatives loss of $9.8 million for Q1/2018 is primarily a result of crude oil market price indexes settling at levels above those set in our fixed price contracts. Realized losses of $10.3 million related to our crude oil financial derivatives in place for Q1/2018 were driven by $16.7 million of losses on 14,000 bbl/d of WTI swap contracts with an average fixed price of US$52.31/bbl and $2.7 million of losses on 4,000 bbl/d of Brent swap contracts with an average fixed price of US$61.31/bbl where the market price of WTI and Brent settled above our contract prices. We also recorded $0.7 million of realized losses on our 3-way option contract as the market price of WTI settled above the sold call price during Q1/2018. Losses on WTI and Brent contracts were partially offset by gains of $9.7 million on 8,000 bbl/d of WCS differential contracts with an average fixed differential of $14.24/bbl as the index was wider than the differentials set in our contracts throughout the first quarter of 2018. During Q1/2018, we recorded realized gains of $0.4 million on our natural gas financial derivatives. These gains were primarily a result of the AECO price index for the first quarter of 2018 averaging lower than the average fixed price of $2.67/GJ on 5,000 GJ/d of AECO contracts in place for Q1/2018.
At March 31, 2018, the fair value of our financial derivative contracts represent a net liability of $49.4 million compared to a net liability of $31.6 million at December 31, 2017. The net liability of $49.4 million as at March 31, 2018 is primarily a result of futures pricing for WTI and Brent crude oil indexes being higher than the prices set in our fixed price crude oil financial derivatives in place for 2018 and 2019.
Baytex Energy Corp.
Q1 2018 MD&A Page 8
We had the following commodity financial derivative contracts as at May 3, 2018.
Period | Volume | Price/Unit(1) | Index | |||
Oil | ||||||
Basis swap | Apr 2018 to Jun 2018 | 2,000 bbl/d | WTI less US$14.23/bbl | WCS | ||
Basis swap | Apr 2018 to Dec 2018 | 6,000 bbl/d | WTI less US$14.24/bbl | WCS | ||
Basis swap | May 2018 to July 2018 | 2,000 bbl/d | WTI less US$17.65/bbl | WCS | ||
Fixed - Sell | Apr 2018 to Dec 2018 | 14,000 bbl/d | US$52.31/bbl | WTI | ||
3-way option (2) | Apr 2018 to Dec 2018 | 2,000 bbl/d | US$60.00/US$54.40/US$40.00 | WTI | ||
Fixed - Sell | Apr 2018 to Dec 2018 | 4,000 bbl/d | US$61.31/bbl | Brent | ||
Fixed - Sell | Jan 2019 to Dec 2019 | 2,000 bbl/d | US$61.70/bbl | WTI | ||
Swaption (3) | Jan 2019 to Dec 2019 | 2,000 bbl/d | US$59.60/bbl | WTI | ||
Swaption (3) | Jan 2019 to Dec 2019 | 2,000 bbl/d | US$61.70/bbl | WTI | ||
3-way option (2) | Jan 2019 to Dec 2019 | 2,000 bbl/d | US$70.00/US$60.00/US$50.00 | WTI | ||
3-way option (2) | Jan 2019 to Dec 2019 | 1,000 bbl/d | US$75.50/US$65.50/US$55.50 | Brent | ||
Fixed - Sell | Jan 2019 to Jun 2019 | 2,000 bbl/d | US$62.85/bbl | WTI | ||
Natural Gas | ||||||
Fixed - Sell | Jan 2018 to Dec 2018 | 15,000 mmbtu/d | US$3.01 | NYMEX | ||
Fixed - Sell | Apr 2018 to Dec 2018 | 5,000 GJ/d | $2.67 | AECO |
(1) | Based on the weighted average price per unit for the period. |
(2) | Producer 3-way option consists of a sold call, a bought put and a sold put. To illustrate, in a US$60/US$54.40/US$40 contract, Baytex receives WTI plus US$14.40/bbl when WTI is at or below US$40/bbl; Baytex receives US$54.40/bbl when WTI is between US$40/bbl and US$54.40/bbl; Baytex receives the market price when WTI is between US$54.40/bbl and US$60/bbl; and Baytex receives US$60/bbl when WTI is above US$60/bbl. |
(3) | For these contracts, the counterparty has the right, if exercised on December 31, 2018, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above. |
Baytex Energy Corp.
Q1 2018 MD&A Page 9
Operating Netback
The following table summarizes our operating netback on a per boe basis for our Canadian and U.S. operations for the three months ended March 31, 2018 and 2017.
Three Months Ended March 31 | ||||||||||||||||||
2018 | 2017 | |||||||||||||||||
($ per boe except for volume) | Canada | U.S. | Total | Canada | U.S. | Total | ||||||||||||
Sales volume (boe/d) | 33,505 | 36,017 | 69,522 | 33,217 | 36,081 | 69,298 | ||||||||||||
Operating netback: | ||||||||||||||||||
Total sales, net of blending and other expense | $ | 29.69 | $ | 55.30 | $ | 42.96 | $ | 32.81 | $ | 46.93 | $ | 40.16 | ||||||
Less: | ||||||||||||||||||
Royalties | 3.76 | 16.51 | 10.36 | 4.23 | 13.72 | 9.17 | ||||||||||||
Operating expenses | 15.06 | 6.31 | 10.53 | 14.52 | 6.38 | 10.28 | ||||||||||||
Transportation expenses | 2.83 | — | 1.36 | 2.69 | — | 1.29 | ||||||||||||
Operating netback | $ | 8.04 | $ | 32.48 | $ | 20.71 | $ | 11.37 | $ | 26.83 | $ | 19.42 | ||||||
Realized financial derivatives (loss) gain | — | — | (1.57 | ) | — | — | 0.04 | |||||||||||
Operating netback after financial derivatives (loss) gain | $ | 8.04 | $ | 32.48 | $ | 19.14 | $ | 11.37 | $ | 26.83 | $ | 19.46 |
Operating netback after financial derivatives decreased by $0.32/boe to $19.14/boe reported for Q1/2018 from $19.46/boe for Q1/2017. The increase in our realized sales price per boe during the first quarter of 2018 was partially offset by higher royalties, operating expenses and transportation expenses compared to the same period of 2017. The increase in royalty expense per boe is due to a higher portion of our petroleum and natural gas sales being generated from our U.S. operations, which has a higher royalty rate than our Canadian operations. Operating expense per boe was slightly higher in Q1/2018 due to slightly higher fuel and electricity costs relative to Q1/2017 along with planned repair and maintenance activity completed during Q1/2018. We recorded realized losses on financial derivatives of $1.57/boe in Q1/2018 as losses recorded on our WTI and Brent contracts were partially offset by gains recorded on our WCS differential and natural gas contracts.
Exploration and Evaluation Expense
Exploration and evaluation ("E&E") expense is related to the expiry of leases and the derecognition 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 $2.0 million for Q1/2018 compared to $1.3 million for Q1/2017.
Depletion and Depreciation
Depletion and depreciation expense varies with the carrying amount of the Company's oil and gas properties, the amount of proved plus probable reserves volumes, and the rate of production for the period. The following table summarizes depletion and depreciation expense for the three months ended March 31, 2018 and 2017.
Three Months Ended March 31 | ||||||||||||||||||
2018 | 2017 | |||||||||||||||||
($ thousands except for per boe) | Canada | U.S. | Total | Canada | U.S. | Total | ||||||||||||
Depletion and depreciation(1) | $ | 47,169 | $ | 61,120 | $ | 108,289 | $ | 50,978 | $ | 71,353 | $ | 122,331 | ||||||
Depletion and depreciation per boe | $ | 15.64 | $ | 18.86 | $ | 17.31 | $ | 17.05 | $ | 21.97 | $ | 19.61 |
(1) | Canada includes corporate depreciation. |
Depletion and depreciation expense was $108.3 million ($17.31/boe) for Q1/2018 compared to $122.3 million ($19.61/boe) reported for Q1/2017. In Canada, depletion expense was lower in Q1/2018 compared to Q1/2017 primarily due to a lower depletion rate from increased reserve volumes in Q1/2018 recognized in Q4/2017. The U.S. depletion rate for 2018 is also lower than the comparative period due to a lower average CAD/USD exchange rate in Q1/2018 relative to Q1/2017 and from increased reserve volumes in Q1/2018 recognized in Q4/2017.
Baytex Energy Corp.
Q1 2018 MD&A Page 10
General and Administrative Expense
General and administrative ("G&A") expense includes head office and corporate costs such as salaries and employee benefits, public company costs, and administrative recoveries earned for operating capital and production activities on behalf of our working interest partners. G&A expense fluctuates with head office staffing levels and the level of operated capital and production activity during the period.
The following table summarizes our G&A expense for the three months ended March 31, 2018 and 2017.
Three Months Ended March 31 | |||||||||
($ thousands except for per boe) | 2018 | 2017 | Change | ||||||
General and administrative expense | $ | 11,008 | $ | 12,583 | $ | (1,575 | ) | ||
General and administrative expense per boe | $ | 1.76 | $ | 2.02 | $ | (0.26 | ) |
We reported G&A expense of $11.0 million or $1.76/boe for the first three months of 2018 compared to $12.6 million or $2.02/boe for the comparative period of 2017. Reduced staffing levels and our ongoing cost savings efforts have resulted in lower G&A expense in Q1/2018 relative to Q1/2017. G&A expense for the first quarter of 2018 was consistent with our annual guidance of approximately $44 million and $1.72/boe and we are maintaining our guidance for the year.
Share-Based Compensation Expense
Share-based compensation ("SBC") expense associated with the Share Award Incentive Plan is recognized in net income or loss over the vesting period of the share awards with a corresponding increase in contributed surplus. The issuance of common shares upon the conversion of share awards is recorded as an increase in shareholders' capital with a corresponding reduction in contributed surplus. SBC expense varies with the quantity of unvested share awards outstanding and the grant date fair value assigned to the share awards.
We recorded SBC expense of $3.9 million for Q1/2018 which is down from $4.5 million reported for Q1/2017. SBC expense is lower in 2018 due to a lower fair value assigned to share awards granted in 2018 as compared to awards granted in 2017.
Financing and Interest Expense
Financing and interest expense includes interest on our bank loan and long-term notes, non-cash financing costs and the accretion on our asset retirement obligations. Financing and interest expense varies depending on debt levels outstanding during the period and the applicable borrowing rates, CAD/USD foreign exchange rates, along with the carrying amount of asset retirement obligations and discount rates used to present value the obligations.
Financing and interest expense was $28.0 million for Q1/2018 which is slightly lower than $28.5 million reported for the same period of 2017. Cash interest expense of $24.5 million for the first three months of 2018 was slightly lower than $25.2 million reported for the same period of 2017 due to lower interest on our long-term notes as a result of a stronger Canadian dollar in Q1/2018 which reduced the amount of U.S. dollar interest reported in Canadian dollars. We are maintaining our full year guidance for cash interest of approximately $100 million and $3.92/boe as the Q1/2018 results are consistent with our expectations.
Foreign Exchange
Unrealized foreign exchange gains and losses represent the change in value of the long-term notes and bank loan denominated in U.S. dollars. The long-term notes and bank loan are translated to Canadian dollars on the balance sheet date using the closing CAD/USD exchange rate. When the Canadian dollar strengthens against the U.S. dollar at the end of the current period compared to the previous period an unrealized gain is recorded and conversely when the Canadian dollar weakens at the end of the current period compared to the previous period an unrealized loss is recorded. Realized foreign exchange gains and losses are due to day-to-day U.S. dollar denominated transactions occurring in the Canadian operations.
Three Months Ended March 31 | ||||||||
($ thousands except for exchange rates) | 2018 | 2017 | Change | |||||
Unrealized foreign exchange loss (gain) | $ | 36,046 | $ | (11,338 | ) | 47,384 | ||
Realized foreign exchange loss | 171 | 750 | (579 | ) | ||||
Foreign exchange loss (gain) | $ | 36,217 | $ | (10,588 | ) | 46,805 | ||
CAD/USD exchange rates: | ||||||||
At beginning of period | 1.2518 | 1.3427 | ||||||
At end of period | 1.2901 | 1.3322 |
Baytex Energy Corp.
Q1 2018 MD&A Page 11
We recorded an unrealized foreign exchange loss of $36.0 million for Q1/2018 due to a weakening of the Canadian dollar relative to the U.S. dollar. The CAD/USD exchange rate was 1.2901 as at March 31, 2018 compared to 1.2518 as at December 31, 2017.
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 $0.2 million for the first quarter of 2018 compared to a loss of $0.8 million for the same period of 2017.
Income Taxes
Three Months Ended March 31 | |||||||||
($ thousands) | 2018 | 2017 | Change | ||||||
Current income tax recovery | $ | (73 | ) | $ | (736 | ) | $ | 663 | |
Deferred income tax recovery | (22,917 | ) | (12,445 | ) | (10,472 | ) | |||
Total income tax recovery | $ | (22,990 | ) | $ | (13,181 | ) | $ | (9,809 | ) |
The current income tax recovery was $0.1 million for 2018, as compared to $0.7 million for 2017. Current income taxes were nominal for Q1/2018 and Q1/2017. During both periods tax pool claims were sufficient to shelter the income associated with our adjusted funds flow.
The 2018 deferred income tax recovery of $22.9 million increased $10.5 million from $12.4 million in 2017. The deferred income tax recovery for 2018 is higher compared to 2017 primarily due to higher unrealized losses recorded on our financial derivatives contracts.
In June 2016, certain indirect subsidiary entities received reassessments from the Canada Revenue Agency (the "CRA”) that deny non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2015. These reassessments followed a previously disclosed letter which we received in November 2014 from the CRA, proposing to issue such reassessments.
We remain confident that the tax filings of the affected entities are correct and are defending our tax filing positions. The reassessments do not require us to pay any amounts in order to participate in the appeals process.
In September 2016, we filed a notice of objection for each notice of reassessment received. These notices of objection will be reviewed by the Appeals Division of the CRA. We are waiting for an Appeals Officer to be assigned to our file, after which we estimate that the appeals process will take up to one year. If the Appeals Division upholds the notices of reassessment, we have the right to appeal to the Tax Court of Canada; a process that we estimate could take a further two years. Should we be unsuccessful at the Tax Court of Canada, additional appeals are available; a process that we estimate could take another two years and potentially longer.
By way of background, we acquired several privately held commercial trusts in 2010 with accumulated non-capital losses of $591 million (the “Losses”). The Losses were subsequently used to reduce the taxable income of those trusts. The reassessments disallow the deduction of the Losses under the general anti-avoidance rule of the Income Tax Act (Canada). If, after exhausting available appeals, the deduction of Losses continues to be disallowed, we will owe cash taxes for the years 2012 through 2015 and an additional amount for late payment interest. The amount of cash taxes owing and the late payment interest are dependent upon the amount of unused tax shelter available to offset the reassessed income, including tax shelter from future years available to recover taxes paid in the years 2012 through 2015.
Baytex Energy Corp. ��
Q1 2018 MD&A Page 12
Net Income (Loss) and Adjusted Funds Flow
The components of adjusted funds flow and net income or loss for the three months ended March 31, 2018 and 2017 are set forth in the following table.
Three Months Ended March 31 | |||||||||
($ thousands) | 2018 | 2017 | Change | ||||||
Petroleum and natural gas sales | $ | 286,067 | $ | 260,549 | $ | 25,518 | |||
Royalties | (64,839 | ) | (57,177 | ) | (7,662 | ) | |||
Revenue, net of royalties | 221,228 | 203,372 | 17,856 | ||||||
Expenses | |||||||||
Operating | (65,888 | ) | (64,130 | ) | (1,758 | ) | |||
Transportation | (8,519 | ) | (8,042 | ) | (477 | ) | |||
Blending and other | (17,290 | ) | (10,057 | ) | (7,233 | ) | |||
Operating netback | $ | 129,531 | $ | 121,143 | $ | 8,388 | |||
General and administrative | (11,008 | ) | (12,583 | ) | 1,575 | ||||
Cash financing and interest | (24,511 | ) | (25,192 | ) | 681 | ||||
Realized financial derivatives (loss) gain | (9,841 | ) | 274 | (10,115 | ) | ||||
Realized foreign exchange loss | (171 | ) | (750 | ) | 579 | ||||
Other income (expense) | 279 | (413 | ) | 692 | |||||
Current income tax recovery | 73 | 736 | (663 | ) | |||||
Payments on onerous contracts | (97 | ) | (1,846 | ) | 1,749 | ||||
Adjusted funds flow | $ | 84,255 | $ | 81,369 | $ | 2,886 | |||
Exploration and evaluation | (2,019 | ) | (1,322 | ) | (697 | ) | |||
Depletion and depreciation | (108,289 | ) | (122,331 | ) | 14,042 | ||||
Share based compensation | (3,915 | ) | (4,549 | ) | 634 | ||||
Non-cash financing and accretion | (3,499 | ) | (3,314 | ) | (185 | ) | |||
Unrealized financial derivatives (loss) gain | (17,709 | ) | 35,614 | (53,323 | ) | ||||
Unrealized foreign exchange (loss) gain | (36,046 | ) | 11,338 | (47,384 | ) | ||||
Gain on disposition of oil and gas properties | 1,486 | — | 1,486 | ||||||
Deferred income tax recovery | 22,917 | 12,445 | 10,472 | ||||||
Payments on onerous contracts | 97 | 1,846 | (1,749 | ) | |||||
Net income (loss) for the period | $ | (62,722 | ) | $ | 11,096 | $ | (73,818 | ) |
We generated adjusted funds flow of $84.3 million for Q1/2018, an increase of $2.9 million from adjusted funds flow of $81.4 million reported for Q1/2017. The increase in adjusted funds flow in the first quarter of 2018 was primarily due to a higher operating netback which increased by $8.4 million from the same period in 2017. The increase in operating netback was due to higher commodity prices which increased revenues, partially offset by higher royalties and higher operating and transportation expenses. The increase in operating netback was increased by $3.3 million due to lower general and administrative expenses and lower payments on onerous contracts and was offset by a $10.1 million increase in realized hedging losses.
In Q1/2018, we recorded a net loss of $62.7 million compared to income of $11.1 million for the same period of 2017. The net loss recorded for Q1/2018 includes an unrealized loss on financial derivatives of $17.7 million which is a $53.3 million change from an unrealized gain of $35.6 million recorded for Q1/2017. We also recorded an unrealized foreign exchange loss of $36.0 million in Q1/2018 as compared to an unrealized gain of $11.3 million in the same period of 2017. This was offset by a $14.0 million reduction in depletion and depreciation expense along with a $10.5 million increase in the deferred income tax recovery recorded for Q1/2018 relative to Q1/2017.
Other Comprehensive Income (Loss)
Other comprehensive income or loss is comprised of the foreign currency translation adjustment on U.S. net assets not recognized in profit or loss. The $72.3 million foreign currency translation gain for the three months ended March 31, 2018 relates to the change in value of our U.S. net assets expressed in Canadian dollars and is due to the weakening of the Canadian dollar against the U.S. dollar. The CAD/USD exchange rate was 1.2901 as at March 31, 2018 compared to 1.2518 as at December 31, 2017.
Baytex Energy Corp.
Q1 2018 MD&A Page 13
Capital Expenditures
Capital expenditures for the three months ended March 31, 2018 and 2017 are summarized as follows.
Three Months Ended March 31 | ||||||||||||||||||
2018 | 2017 | |||||||||||||||||
($ thousands except for # of wells drilled) | Canada | U.S. | Total | Canada | U.S. | Total | ||||||||||||
Land and seismic | $ | 2,058 | $ | — | $ | 2,058 | $ | 1,617 | $ | — | $ | 1,617 | ||||||
Drilling, completion and equipping | 33,543 | 35,171 | 68,714 | 35,278 | 55,357 | 90,635 | ||||||||||||
Facilities | 12,991 | 6,838 | 19,829 | 1,589 | 2,718 | 4,307 | ||||||||||||
Other | 2,933 | — | 2,933 | — | — | — | ||||||||||||
Total exploration and development | $ | 51,525 | $ | 42,009 | $ | 93,534 | $ | 38,484 | $ | 58,075 | $ | 96,559 | ||||||
Total acquisitions, net of proceeds from divestitures | (2,026 | ) | — | (2,026 | ) | 66,004 | — | 66,004 | ||||||||||
Total oil and natural gas expenditures | $ | 49,499 | $ | 42,009 | $ | 91,508 | $ | 104,488 | $ | 58,075 | $ | 162,563 | ||||||
Wells drilled (net) | 29.9 | 6.9 | 36.8 | 27.1 | 8.4 | 35.5 |
We invested $93.5 million in exploration and development activities during Q1/2018 which is $3.0 million less than exploration and development expenditures of $96.6 million for Q1/2017. Our Q1/2018 capital program was focused on maintaining the pace of development on our heavy oil properties in Canada and our properties in the Eagle Ford.
Total exploration and development expenditures in Canada were $51.5 million for Q1/2018 compared to $38.5 million in Q1/2017. We drilled 37 (29.9 net) wells and spent $33.5 million on drilling, completion and equipping costs during Q1/2018 compared to drilling 31 (27.1 net) wells during Q1/2017 for $35.3 million. Drilling, completion and equipping costs for Q1/2018 included costs associated with two (4.0 net) stratigraphic exploration wells and four (4.0 net) service wells to support development activity on our Lloydminster properties. Drilling activity at Lloydminster included three (3.0 net) wells and costs for facility construction to support SAGD operations at our Kerrobert thermal project. During the first quarter of 2018, we spent $9.4 million on the construction of a gas plant and strategic infrastructure projects including pipeline expansions to support growth at Peace River.
In the U.S., capital spending of $42.0 million in Q1/2018 decreased from $58.1 million in Q1/2017. We participated in the drilling of 25 (6.9 net) wells and initiated production from 27 (5.5 net) wells during Q1/2018 compared to 36 (8.4 net) wells drilled and 33 (9.4 net) wells on production in the same period of 2017. During Q1/2018, the operator of our Eagle Ford properties was active on our lower working interest lands relative to Q1/2017 which resulted in lower exploration and development expenditures for the first quarter of 2018.
We completed minor acquisition and disposition activity in Q1/2018 for net proceeds of $2.0 million compared to Q1/2017 when our acquisition and disposition activities were primarily comprised of the Peace River acquisition which totaled of $66.1 million.
CAPITAL RESOURCES AND LIQUIDITY
Our objective for capital management involves maintaining a flexible capital structure and sufficient sources of liquidity to execute our capital programs, while meeting our short and long-term commitments. We strive to actively manage our capital structure in response to changes in economic conditions and the risk characteristics of our oil and gas properties. At March 31, 2018, our capital structure was comprised of shareholders' capital, long-term debt, working capital and our bank loan.
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. Our adjusted funds flow is dependent 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.
Management of debt levels is a priority for Baytex in order to sustain operations and support our plans for long-term growth. At March 31, 2018, net debt was $1,783.4 million, an increase of $49.1 million from $1,734.3 million at December 31, 2017. The weakening of the Canadian dollar relative to the U.S. dollar increased the reported amount of our U.S. dollar denominated debt at March 31, 2018 by $36.0 million.
We monitor our capital structure and liquidity requirements using a net debt to adjusted funds flow ratio. At March 31, 2018, our net debt to adjusted funds flow ratio was 5.3 compared to a ratio of 5.0 as at December 31, 2017. The increase in the net debt to adjusted funds flow ratio relative to December 31, 2017 is attributed to lower adjusted funds flow from lower operating netbacks after derivatives along with an increase in net debt as at March 31, 2018 due to a weakening of the Canadian dollar relative to the U.S. dollar.
Bank Loan
At March 31, 2018, the principal amount of bank loan outstanding was $212.6 million and we had approximately $515 million of available capacity under the credit facility agreement.
On April 25, 2018, Baytex amended its credit facilities to extend maturity from June 4, 2019 to June 4, 2020 and elected to end the covenant relief period early to benefit from reduced borrowing costs. The amended revolving extendible secured credit facilities are comprised of a US$35 million operating loan (previously US$25 million) and a US$340 million syndicated loan (previously $350 million) for Baytex and a US$200 million syndicated loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc. (collectively, the "Revolving Facilities").
The Revolving Facilities are not borrowing base facilities and do not require annual or semi-annual reviews. The facilities contain standard commercial covenants, including the financial covenants detailed below, and do not require any mandatory principal payments prior to maturity on June 4, 2020. Baytex may request an extension of the Revolving Facilities which could extend the revolving period for up to four years (subject to a maximum four-year period at any time). Advances (including letters of credit) under the Revolving 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 Revolving 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 relating to the Revolving Facilities are accessible on the SEDAR website at www.sedar.com (filed under the category "Material contracts - Credit agreements" on April 13, 2016 and May 2, 2018).
The weighted average interest rate on the credit facilities for Q1/2018 was 4.79% as compared to 3.9% for Q1/2017.
Financial Covenants
On April 25, 2018, we amended the Revolving Facilities and elected to end the covenant relief period early. The following table summarizes the financial covenants applicable the the Revolving Facilities at March 31, 2018 and at April 25, 2018 and our compliance therewith at March 31, 2018.
Covenant Description | Position as at March 31, 2018 | March 31, 2018 | April 25, 2018 and thereafter |
Senior Secured Debt(1) to Bank EBITDA(2) (Maximum Ratio) | 0.50:1.00 | 5.00:1.00 | 3.50:1.00 |
Interest Coverage(3) (Minimum Ratio) | 4.56:1.00 | 1.25:1.00 | 2.00:1.00 |
(1) | "Senior Secured Debt" is defined as the principal amount of the bank loan and other secured obligations identified in the credit agreement. As at March 31, 2018, the Company's Senior Secured Debt totaled $227.2 million. |
(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, unrealized gains and losses on financial derivatives, income tax, 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. Bank EBITDA for the twelve months ended March 31, 2018 was $454.8 million. |
(3) | Interest coverage is computed as the ratio of Bank EBITDA to financing and interest expenses excluding non-cash interest and accretion on asset retirement obligations, and is calculated on a trailing twelve month basis. Financing and interest expenses for the twelve months ended March 31, 2018 were $99.8 million. |
Long-Term Notes
We have four series of long-term notes outstanding that total $1.53 billion as at March 31, 2018. 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 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 2.5:1.0. As at March 31, 2018, the fixed charge coverage ratio was 4.56:1.00.
On February 17, 2011, we issued US$150 million principal amount of senior unsecured notes bearing interest at 6.75% payable semi-annually with principal repayable on February 17, 2021. As of February 17, 2016, these notes are redeemable at our option, in whole or in part, at specified redemption prices.
On July 19, 2012, we issued $300 million principal amount of senior unsecured notes bearing interest at 6.625% payable semi-annually with principal repayable on July 19, 2022. As of July 19, 2017, these notes are redeemable at our option, in whole or in part, at specified redemption prices.
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") and US$400 million of 5.625% notes due June 1, 2024 (the "5.625% Notes"). The 5.125% Notes and the 5.625% Notes pay interest semi-annually with the principal amount repayable at maturity. As of June 1, 2017, the 5.125% Notes are redeemable at our option, in whole or in part, at specified redemption prices. The 5.625% Notes are redeemable at our option, in whole or in part, commencing on June 1, 2019 at specified redemption prices.
Shareholders’ Capital
We are authorized to issue an unlimited number of common shares and 10,000,000 preferred shares. The rights and terms of preferred shares are determined upon issuance. During the three months ended March 31, 2018, we issued 1.1 million common shares pursuant to our share-based compensation program. As at May 3, 2018, we had 236.6 million common shares issued and outstanding and no preferred shares issued and outstanding.
Contractual Obligations
We have a number of financial obligations that are incurred in the ordinary course of business. These obligations are of a recurring nature and impact our adjusted funds flow in an ongoing manner. A significant portion of these obligations will be funded by adjusted funds flow. These obligations as of March 31, 2018 and the expected timing for funding these obligations are noted in the table below.
($ thousands) | Total | Less than 1 year | 1-3 years | 3-5 years | Beyond 5 years | ||||||||||
Trade and other payables | $ | 155,779 | $ | 155,779 | $ | — | $ | — | $ | — | |||||
Bank loan(1) (2) | 212,571 | — | 212,571 | — | — | ||||||||||
Long-term notes(2) | 1,525,595 | — | 193,515 | 816,040 | 516,040 | ||||||||||
Interest on long-term notes(3) | 386,265 | 88,412 | 175,356 | 88,539 | 33,958 | ||||||||||
Operating leases | 26,803 | 6,955 | 12,692 | 7,156 | — | ||||||||||
Processing agreements | 39,220 | 5,539 | 9,104 | 9,004 | 15,573 | ||||||||||
Transportation agreements | 31,630 | 2,383 | 17,025 | 11,350 | 872 | ||||||||||
Total | $ | 2,377,863 | $ | 259,068 | $ | 620,263 | $ | 932,089 | $ | 566,443 |
(1) | The bank loan is covenant-based with a revolving period that is extendible annually for up to a four-year term. Unless extended, the revolving period will end on June 4, 2020, with all amounts to be repaid on such date. |
(2) | Principal amount of instruments. |
(3) | Excludes interest on bank loan as interest payments on bank loans fluctuate based on interest rate and bank loan balance. |
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.
Baytex Energy Corp.
Q1 2018 MD&A Page 14
QUARTERLY FINANCIAL INFORMATION
2018 | 2017 | 2016 | ||||||||||||||
($ thousands, except per common share amounts) | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | ||||||||
Petroleum and natural gas sales | 286,067 | 303,163 | 258,620 | 277,536 | 260,549 | 233,116 | 197,648 | 195,733 | ||||||||
Net income (loss) | (62,722 | ) | 76,038 | (9,228 | ) | 9,268 | 11,096 | (359,424 | ) | (39,430 | ) | (86,937 | ) | |||
Per common share - basic | (0.27 | ) | 0.32 | (0.04 | ) | 0.04 | 0.05 | (1.66 | ) | (0.19 | ) | (0.41 | ) | |||
Per common share - diluted | (0.27 | ) | 0.32 | (0.04 | ) | 0.04 | 0.05 | (1.66 | ) | (0.19 | ) | (0.41 | ) | |||
Adjusted funds flow | 84,255 | 105,796 | 77,340 | 83,136 | 81,369 | 77,239 | 72,106 | 81,261 | ||||||||
Per common share - basic | 0.36 | 0.45 | 0.33 | 0.35 | 0.35 | 0.36 | 0.34 | 0.39 | ||||||||
Per common share - diluted | 0.36 | 0.44 | 0.33 | 0.35 | 0.34 | 0.36 | 0.34 | 0.39 | ||||||||
Exploration and development | 93,534 | 90,156 | 61,544 | 78,007 | 96,559 | 68,029 | 39,579 | 35,490 | ||||||||
Canada | 51,525 | 41,864 | 14,487 | 18,439 | 38,484 | 12,151 | 6,120 | 2,747 | ||||||||
U.S. | 42,009 | 48,292 | 47,057 | 59,568 | 58,075 | 55,878 | 33,459 | 32,743 | ||||||||
Acquisitions, net of divestitures | (2,026 | ) | (3,937 | ) | (7,436 | ) | 5,226 | 66,004 | (322 | ) | (62,752 | ) | (37 | ) | ||
Net debt | 1,783,379 | 1,734,284 | 1,748,805 | 1,819,387 | 1,850,909 | 1,773,541 | 1,864,022 | 1,942,538 | ||||||||
Total assets | 4,433,074 | 4,372,111 | 4,353,637 | 4,582,049 | 4,702,423 | 4,594,085 | 4,995,876 | 5,089,280 | ||||||||
Common shares outstanding | 236,578 | 235,451 | 235,451 | 234,204 | 234,203 | 233,449 | 211,542 | 210,715 | ||||||||
Daily production | ||||||||||||||||
Total production (boe/d) | 69,522 | 69,556 | 69,310 | 72,812 | 69,298 | 65,136 | 67,167 | 70,031 | ||||||||
Canada (boe/d) | 33,505 | 32,194 | 34,560 | 34,284 | 33,217 | 31,704 | 33,615 | 31,722 | ||||||||
U.S. (boe/d) | 36,017 | 37,362 | 34,750 | 38,528 | 36,081 | 33,432 | 33,552 | 38,309 | ||||||||
Benchmark prices | ||||||||||||||||
WTI oil (US$/bbl) | 62.87 | 55.40 | 48.20 | 48.28 | 51.91 | 49.29 | 44.94 | 45.60 | ||||||||
WCS heavy (US$/bbl) | 38.59 | 43.14 | 38.26 | 37.16 | 37.34 | 34.97 | 31.44 | 32.29 | ||||||||
CAD/USD avg exchange rate | 1.2651 | 1.2717 | 1.2524 | 1.3447 | 1.3229 | 1.3339 | 1.3051 | 1.2885 | ||||||||
AECO gas ($/mcf) | 1.85 | 1.96 | 2.04 | 2.77 | 2.94 | 2.81 | 2.20 | 1.25 | ||||||||
NYMEX gas (US$/mmbtu) | 3.00 | 2.93 | 3.00 | 3.18 | 3.32 | 2.98 | 2.81 | 1.95 | ||||||||
Sales price ($/boe) | 42.96 | 44.75 | 38.04 | 39.41 | 40.16 | 38.16 | 31.73 | 30.52 | ||||||||
Royalties ($/boe) | 10.36 | 10.86 | 8.65 | 9.06 | 9.17 | 9.28 | 7.37 | 6.65 | ||||||||
Operating expense ($/boe) | 10.53 | 10.91 | 10.10 | 10.70 | 10.28 | 9.96 | 9.07 | 8.67 | ||||||||
Transportation expense ($/boe) | 1.36 | 1.20 | 1.46 | 1.35 | 1.29 | 1.30 | 1.38 | 0.81 | ||||||||
Operating netback ($/boe) | 20.71 | 21.78 | 17.83 | 18.30 | 19.42 | 17.62 | 13.91 | 14.39 | ||||||||
Financial derivatives (loss) gain ($/boe) | (1.57 | ) | 0.30 | 0.44 | 0.40 | 0.04 | 1.62 | 3.04 | 3.74 | |||||||
Operating netback after financial derivatives ($/boe) | 19.14 | 22.08 | 18.27 | 18.70 | 19.46 | 19.24 | 16.95 | 18.13 |
Our operating and financial results have improved as oil prices continue to recover from the multi-year lows experienced in early 2016. Compliance with OPEC's production quotas and increased global demand for crude oil have resulted in the WTI benchmark gradually increasing from US$45.60/bbl in Q2/2016 to US$62.87/bbl in Q1/2018. We increased our capital activity in Canada and the U.S. in Q4/2016 as the outlook for oil prices improved after reducing capital activity in response to the low commodity price environment. Our exploration and development expenditures continue to be focused on our Eagle Ford properties as these assets generate our highest netbacks and rates of return. In Canada, exploration and development activity increased in 2017 after deferring operated heavy oil drilling during the first three quarters of 2016. The increased level of activity has increased production into Q1/2018, after dispositions completed in 2016 and lower capital investment resulted in declining quarterly production through the end of 2016. 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 in late 2017 as commodity prices recovered and our daily production increased from 2016. Net debt has decreased from $1,942.5 million at Q2/2016 to $1,783.4 million at Q1/2018 due to non-core asset sales along with the strengthening of the Canadian dollar relative to the U.S. dollar which has decreased the reported amount of our U.S. dollar denominated debt.
Baytex Energy Corp.
Q1 2018 MD&A Page 15
2018 GUIDANCE
The following table compares our 2018 annual guidance compared to our Q1/2018 results.
Guidance (1) | Q1/2018 | Variance | |||
Exploration and development capital | $325-$375 million | $93.5 million | N/A | ||
Production (boe/d) | 68,000 to 72,000 | 69,522 | — | % | |
Expenses: | |||||
Royalty rate | ~ 23% | 24.1 | % | 1 | % |
Operating | $10.50-$11.25/boe | $10.53/boe | — | % | |
Transportation | $1.35-$1.45/boe | $1.36/boe | — | % | |
General and administrative | ~ $44 million ($1.72/boe) | $11.0 million ($1.76/boe) | — | % | |
Interest | ~ $100 million ($3.95/boe) | $24.5 million ($3.92/boe) | — | % |
OFF BALANCE SHEET TRANSACTIONS
We do not have any financial arrangements that are excluded from the consolidated financial statements as at March 31, 2018, 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, 2018. 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, 2017.
CHANGES IN ACCOUNTING STANDARDS
Revenue Recognition
Baytex adopted IFRS 15 Revenue from Contracts with Customers with a date of initial application of January 1, 2018. For the year ended December 31, 2017, $8.3 million of commodity purchases related to heavy oil sales have been reclassified from petroleum and natural gas sales to blending and other expense to conform with the requirements of IFRS 15. There were no adjustments made to the January 1, 2018 opening statement of financial position on adoption. The additional disclosures required by IFRS 15 are provided in note 11 to the consolidated financial statements.
The nature of the Company's performance obligations, including roles of third parties and partners, are evaluated to determine if the Company acts as a principal. Baytex recognizes revenue on a gross basis when it acts as the principal and has primary responsibility for the transaction. Revenue is recognized on a net basis if Baytex acts in the capacity of an agent rather than as a principal.
Revenue from the sale of heavy oil, light oil and condensate, natural gas liquids, and natural gas is recognized based on the consideration specified in contracts with customers. Baytex recognizes revenue when control of the product transfers to the customer and collection is reasonably assured. The amount of revenue recognized is based on the consideration specified in the contract. This is generally at the point in time when the customer obtains legal title to the product which is when it is physically transferred to the pipeline or other transportation method agreed upon and collection is reasonably assured.
The transaction price for variable price contracts in the Canada and U.S. segments is based on a representative commodity price index, and may be adjusted for quality, location, delivery method, or other factors depending on the agreed upon terms of the contract. The amount of revenue recorded can vary depending on the grade, quality and quantities of oil or natural gas transferred to customers. Market conditions, which impact the Company's ability to negotiate certain components of the transaction price, can also cause the amount of revenue recorded to fluctuate from period to period.
Tariffs, tolls and fees charged to other entities for use of pipelines and facilities owned by Baytex are evaluated by management to determine if these originate from contracts with customers or from incidental or collaborative arrangements. Tariffs, tolls and fees charged to other entities that are from contracts with customers are recognized in revenue when the related services are provided.
Baytex Energy Corp.
Q1 2018 MD&A Page 16
Financial Instruments
Baytex adopted IFRS 9 Financial Instruments, on January 1, 2018 using the retrospective method. The adoption of this standard did not result in a change in the recognition or measurement of any of the Company's financial instruments on transition.
IFRS 9 contains three principal classification categories for initial classification of financial assets: measured at amortized cost, fair value through other comprehensive income (“FVOCI”); or fair value through profit or loss (“FVTPL”). The previous IAS 39 categories of held to maturity, loans and receivables and available for sale are eliminated. Financial assets are categorized based on the Company’s objective for the asset and the subsequent cash flows. A financial asset is classified as amortized cost if the asset is held with the objective to collect contractual cash flows that are solely payments of principal and interest on principal amounts outstanding. A financial asset is classified as FVOCI if the asset is held with the objective to both collect contractual cash flows and sell the financial asset. All other financial assets are measured at FVTPL. Financial assets are assessed for impairment using an expected credit loss model. Trade and other receivables are classified and measured at amortized cost.
The initial classification of financial liabilities under IFRS 9 is fundamentally unchanged from the requirements under IAS 39. A financial liability is measured at amortized cost or FVTPL. A financial liability is measured at FVTPL if it is held-for-trading, a derivative, or designated as FVTPL at initial recognition. For liabilities measured at FVTPL, any change in value resulting from a change in Baytex’s credit-risk is recorded through other comprehensive income or loss rather than net income or loss. Trade and other payables, bank loan and long-term notes are classified and measured as amortized cost.
Future accounting pronouncements
A description of accounting standards that will be effective in the future is included in the notes to the consolidated financial statements.
NON-GAAP MEASURES
In this MD&A, we refer to certain measures (such as adjusted funds 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, 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 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 capital investments, 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 changes in non-cash working capital and 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. 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) | 2018 | 2017 | ||||
Cash flow from operating activities | $ | 87,612 | $ | 80,732 | ||
Change in non-cash working capital | (6,620 | ) | (4,790 | ) | ||
Asset retirement obligations settled | 3,263 | 5,427 | ||||
Adjusted funds flow | $ | 84,255 | $ | 81,369 |
Baytex Energy Corp.
Q1 2018 MD&A Page 17
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.
The following table summarizes our calculation of net debt.
($ thousands) | March 31, 2018 | December 31, 2017 | ||||
Bank loan(1) | $ | 212,571 | $ | 213,376 | ||
Long-term notes(1) | 1,525,595 | 1,489,210 | ||||
Working capital (surplus) deficiency(2) | 45,213 | 31,698 | ||||
Net debt | $ | 1,783,379 | $ | 1,734,284 |
(1) | Principal amount of instruments expressed in Canadian dollars. |
(2) | Working capital is current assets less current liabilities (excluding current financial derivatives and onerous contracts). |
Operating Netback
We define operating netback as petroleum and natural gas sales, less blending and other 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.
Three Months Ended March 31 | ||||||
($ thousands) | 2018 | 2017 | ||||
Petroleum and natural gas sales | $ | 286,067 | $ | 260,549 | ||
Blending and other expense | (17,290 | ) | (10,057 | ) | ||
Total sales, net of blending and other expense | 268,777 | 250,492 | ||||
Less: | ||||||
Royalties | 64,839 | 57,177 | ||||
Operating expense | 65,888 | 64,130 | ||||
Transportation expense | 8,519 | 8,042 | ||||
Operating netback | 129,531 | 121,143 | ||||
Realized financial derivative gain (loss) | (9,841 | ) | 274 | |||
Operating netback after realized financial derivatives gain (loss) | $ | 119,690 | $ | 121,417 |
Bank EBITDA
Bank EBITDA is used to assess compliance with certain financial covenants. The following table reconciles net income or loss to Bank EBITDA.
Three Months Ended March 31 | ||||||
($ thousands) | 2018 | 2017 | ||||
Net income (loss) | $ | (62,722 | ) | $ | 11,096 | |
Plus: | ||||||
Financing and interest | 28,010 | 28,506 | ||||
Unrealized foreign exchange (gain) loss | 36,046 | (11,338 | ) | |||
Unrealized financial derivatives (gain) loss | 17,709 | (35,614 | ) | |||
Current income tax recovery | (73 | ) | (736 | ) | ||
Deferred income tax recovery | (22,917 | ) | (12,445 | ) | ||
Depletion and depreciation | 108,289 | 122,331 | ||||
Gain on disposition of oil and gas properties | (1,486 | ) | — | |||
Non-cash items(1) | 5,934 | 5,871 | ||||
Bank EBITDA | $ | 108,790 | $ | 107,671 |
(1) Non-cash items include share-based compensation, exploration and evaluation expense and non-cash other expense.
Baytex Energy Corp.
Q1 2018 MD&A Page 18
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, 2018.
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 annual average production rate for 2018; that our investment in a gas plant and strategic infrastructure at Peace River will support future growth; crude oil and natural gas prices and the price differentials between light, medium and heavy oil prices; that increased crude by rail volumes will mitigate the recent widening of the price differential for WCS; our ability to reduce the volatility in our adjusted funds flow by utilizing financial derivative contracts; the reassessment of our tax filings by the Canada Revenue Agency; our intention to defend the reassessments; our view of our tax filing position; the length of time it would take to resolve the reassessments; that we would owe cash taxes and late payment interest if the reassessment is successful; 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; the existence, operation and strategy of our risk management program; our capital budget for 2018; our plans for developing our properties; and our expected royalty rate and operating, transportation, general and administrative and interest expenses for 2018. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future.
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; a decline or an extended period of the currently low oil and natural gas prices; uncertainties in the capital markets that may restrict or increase our cost of capital or borrowing; that our credit facilities may not provide sufficient liquidity or may not be renewed; failure to comply with the covenants in our debt agreements; risks associated with a third-party operating our Eagle Ford properties; changes in government regulations that affect the oil and gas industry; changes in environmental, health and safety regulations; restrictions or costs imposed by climate change initiatives; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; the cost of developing and operating our assets; availability and cost of gathering, processing and pipeline systems; depletion of our reserves; risks associated with the exploitation of our properties and our ability to acquire reserves; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating petroleum 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; we may lose access to our 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, 2017, 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.
Baytex Energy Corp.
Q1 2018 MD&A Page 19
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.