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Baytex announces second quarter 2020 financial and operating results


CALGARY, Alberta – Baytex Energy Corp. (“Baytex”)(TSX, NYSE: BTE) reports its operating and financial results for the three and six months ended June 30, 2020 (all amounts are in Canadian dollars unless otherwise noted).

“During the second quarter we took decisive steps to adjust our business model in the face of extremely volatile crude oil markets. We are now starting to benefit from the actions we have taken as we generated positive free cash flow during the quarter and maintained approximately $300 million of financial liquidity. We restarted approximately 80% of the previously announced shut-in volumes, which we expect will positively impact our adjusted funds flow for the remainder of the year,” commented Ed LaFehr, President and Chief Executive Officer.

Q2 2020 Highlights

  • Generated production of 72,508 boe/d (81% oil and NGL), consistent with our previously announced guidance range for the second quarter of 72,000 to 73,000 boe/d.
  • Delivered adjusted funds flow of $18 million ($0.03 per basic share).
  • Realized an operating netback (inclusive of realized financial derivatives gain) of $8.02/boe.
  • Reduced net debt by $57 million as the Canadian dollar strengthened relative to the U.S. dollar and we generated positive free cash flow of $6 million.
  • Maintained undrawn credit capacity of $363 million and liquidity, net of working capital, of approximately $300 million.
  • Achieved a 15% reduction in our GHG emissions intensity in 2019 and remain committed to our 30% target by the end of 2021.

2020 Outlook

We continue to forecast annual capital spending of $260 to $290 million, an approximate 50% reduction from our original plan of $500 to $575 million. With this revised capital program, we suspended drilling operations in Canada and moderated the pace of activity in the Eagle Ford.

We previously announced voluntary production shut-ins of approximately 25,000 boe/d. These volumes remained off-line for April and May. As operating netbacks improved in June, we initiated plans to bring approximately 80% of these volumes back on-line. At current commodity prices, the resumption of production from these previously shut-in barrels is expected to have a positive impact on our adjusted funds flow and improve our financial liquidity. For the second half of 2020, we currently project about 5,000 boe/d of heavy oil production to remain shut-in.

On June 25, we revised our production guidance range for 2020 to 78,000 to 82,000 boe/d, from 70,000 to 74,000 boe/d previously, taking into account the production brought back on-line. Should operating netbacks change, we have the ability to shut-in additional volumes or restart wells in short order.

We remain intensely focused on driving further efficiencies to capture or sustain cost reductions identified during this downturn, while protecting the health and safety of our personnel.

Three Months Ended Six Months Ended
June 30,
2020
March 31,
2020
June 30,
2019
June 30,
2020
June 30,
2019
FINANCIAL
(thousands of Canadian dollars, except per common share amounts)
Petroleum and natural gas sales $ 152,689 $ 336,614 $ 482,000 $ 489,303 $ 935,424
Adjusted funds flow (1) 17,887 132,935 236,130 150,822 456,900
Per share – basic 0.03 0.24 0.42 0.27 0.82
Per share – diluted 0.03 0.24 0.42 0.27 0.82
Net income (loss) (138,463 ) (2,498,217 ) 78,826 (2,636,680 ) 90,162
Per share – basic (0.25 ) (4.46 ) 0.14 (4.71 ) 0.16
Per share – diluted (0.25 ) (4.46 ) 0.14 (4.71 ) 0.16
Capital Expenditures
Exploration and development expenditures (1) $ 9,852 $ 176,777 $ 106,246 $ 186,629 $ 260,089
Acquisitions, net of divestitures (11 ) (40 ) 1,647 (51 ) 1,647
Total oil and natural gas capital expenditures $ 9,841 $ 176,737 $ 107,893 $ 186,578 $ 261,736
Net Debt
Bank loan (2) $ 704,135 $ 678,740 $ 414,691 $ 704,135 $ 414,691
Long-term notes (2) 1,225,395 1,270,800 1,543,645 1,225,395 1,543,645
Long-term debt 1,929,530 1,949,540 1,958,336 1,929,530 1,958,336
Working capital deficiency 65,423 102,077 70,350 65,423 70,350
Net debt (1) $ 1,994,953 $ 2,051,617 $ 2,028,686 $ 1,994,953 $ 2,028,686
Shares Outstanding – basic (thousands)
Weighted average 560,512 559,804 556,599 560,158 556,022
End of period 560,545 560,483 556,798 560,545 556,798
BENCHMARK PRICES
Crude oil
WTI (US$/bbl) $ 27.85 $ 46.17 $ 59.81 $ 37.01 $ 57.36
MEH oil (US$/bbl) 26.40 49.54 66.37 37.97 63.42
MEH oil differential to WTI (US$/bbl) (1.45 ) 3.37 6.56 0.96 6.06
Edmonton par ($/bbl) 29.85 51.43 73.84 40.64 70.19
Edmonton par differential to WTI (US$/bbl) (6.31 ) (7.92 ) (4.61 ) (7.24 ) (4.72 )
WCS heavy oil ($/bbl) 22.70 34.48 65.73 28.68 61.17
WCS differential to WTI (US$/bbl) (11.47 ) (20.53 ) (10.68 ) (16.00 ) (11.48 )
Natural gas
NYMEX (US$/mmbtu) $ 1.72 $ 1.95 $ 2.64 $ 1.83 $ 2.89
AECO ($/mcf) 1.91 2.14 1.17 2.03 1.56
CAD/USD average exchange rate 1.3860 1.3445 1.3376 1.3653 1.3334

 

Three Months Ended Six Months Ended
June 30,
2020
March 31,
2020
June 30,
2019
June 30,
2020
June 30,
2019
OPERATING
Daily Production
Light oil and condensate (bbl/d) 38,951 45,717 42,585 42,333 43,809
Heavy oil (bbl/d) 11,832 28,854 27,320 20,343 27,107
NGL (bbl/d) 7,634 7,822 10,986 7,728 11,356
Total liquids (bbl/d) 58,417 82,393 80,891 70,404 82,272
Natural gas (mcf/d) 84,546 96,356 105,065 90,451 104,874
Oil equivalent (boe/d @ 6:1) (3) 72,508 98,452 98,402 85,479 99,751
Netback (thousands of Canadian dollars)
Total sales, net of blending and other expense (4) $ 147,229 $ 315,257 $ 461,110 $ 462,486 $ 897,746
Royalties (29,156 ) (56,720 ) (86,617 ) (85,876 ) (167,942 )
Operating expense (73,680 ) (104,470 ) (100,474 ) (178,150 ) (200,766 )
Transportation expense (5,031 ) (10,342 ) (11,869 ) (15,373 ) (25,199 )
Operating netback (1) $ 39,362 $ 143,725  $ 262,150  $ 183,087 $ 503,839 
General and administrative (7,438 ) (9,775 ) (11,506 ) (17,213 ) (25,642 )
Cash financing and interest (27,387 ) (28,535 ) (28,092 ) (55,922 ) (56,276 )
Realized financial derivatives gain 13,624 26,850 12,993 40,474 31,807
Other (5) (274 ) 670 585 396 3,172
Adjusted funds flow (1) $ 17,887 $ 132,935  $ 236,130  $ 150,822 $ 456,900 
Netback (per boe)
Total sales, net of blending and other expense (4) $ 22.31 $ 35.19 $ 51.49 $ 29.73 $ 49.72
Royalties (4.42 ) (6.33 ) (9.67 ) (5.52 ) (9.30 )
Operating expense (11.17 ) (11.66 ) (11.22 ) (11.45 ) (11.12 )
Transportation expense (0.76 ) (1.15 ) (1.33 ) (0.99 ) (1.40 )
Operating netback (1) $ 5.96 $ 16.05  $ 29.27  $ 11.77 $ 27.90 
General and administrative (1.13 ) (1.09 ) (1.28 ) (1.11 ) (1.42 )
Cash financing and interest (4.15 ) (3.19 ) (3.14 ) (3.59 ) (3.12 )
Realized financial derivatives gain 2.06 3.00 1.45 2.60 1.76
Other (5) (0.03 ) 0.07 0.07 0.02 0.19
Adjusted funds flow (1) $ 2.71 $ 14.84  $ 26.37  $ 9.69 $ 25.31 

Notes:

  1. The terms “adjusted funds flow”, “exploration and development expenditures”, “net debt” and “operating netback” do not have any standardized meaning as prescribed by Canadian Generally Accepted Accounting Principles (“GAAP”) and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. See the advisory on non-GAAP measures at the end of this press release.
  2. Principal amount of instruments. The carrying amount of debt issue costs associated with the bank loan and long-term notes are excluded on the basis that these amounts have been paid by Baytex and do not represent an additional source of capital or repayment obligations.
  3. Barrel of oil equivalent (“boe”) amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. The use of boe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
  4. Realized heavy oil prices are calculated based on sales dollars, net of blending and other expense. We include the cost of blending diluent in our realized heavy oil sales price in order to compare the realized pricing on our produced volumes to the WCS benchmark.
  5. Other is comprised of realized foreign exchange gain or loss, other income or expense, and current income tax expense or recovery. Refer to the Q2/2020 MD&A for further information on these amounts.

 

Q2/2020 Results

During the second quarter we took decisive steps to adjust our business plan in the face of extremely volatile crude oil markets. In addition to voluntarily shutting-in production, we suspended drilling operations in Canada and moderated our pace of activity in the Eagle Ford. As a result, exploration and development spending totaled a modest $10 million during the second quarter.

Production during the second quarter averaged 72,508 boe/d (81% oil and NGL), as compared to 98,452 boe/d (83% oil and NGL) in Q1/2020. Production in Canada averaged 37,691 boe/d (83% oil and NGL), as compared to 62,262 boe/d in Q1/2020, while production in the Eagle Ford averaged 34,817 boe/d (77% oil and NGL), as compared to 36,190 boe/d in Q1/2020. Our second quarter production was reduced by approximately 20,000 boe/d due to the voluntary shut-ins.

We delivered adjusted funds flow of $18 million ($0.03 per basic share) in Q2/2020 and generated an operating netback of $5.96/boe ($8.02/boe inclusive of realized financial derivatives gain). The Eagle Ford generated an operating netback of $10.05/boe and our Canadian operations generated an operating netback of $2.19/boe.

We continue to emphasize cost reductions across all facets of our organization. We have identified approximately $98 million of cost reductions for 2020 (operating, transportation and general & administrative expenses). During the second quarter, our operating expense of $11.17/boe compared favorably to $11.66/boe in Q1/2020 as we strive to mitigate the costs associated with our field operations. In addition, we realized an approximate 35% reduction in our per boe transportation expense due to reduced volumes. General and administrative expense totaled $7.4 million ($1.13/boe) in Q2/2020, down from $9.8 million ($1.09/boe) in Q1/2020 as we implemented reductions to salaries and annual retainers and benefited from the Canadian Emergency Wage Subsidy.

Eagle Ford and Viking Light Oil

In the Eagle Ford, strong well performance continued across our acreage position. In Q2/2020, we commenced production from 17 (4.6 net) wells. These wells were brought on-stream in April and generated an average 30-day initial production rate of approximately 1,550 boe/d per well. We expect to bring approximately 16 to 18 net wells on production in the Eagle Ford in 2020, down from our original guidance of 22 net wells.

Production in the Viking averaged 19,717 boe/d (90% oil and NGL) during Q2/2020, as compared to 24,696 boe/d in Q1/2020. The quarterly impact of voluntary shut-ins in the Viking was approximately 2,000 boe/d. As operating netbacks improved in June, these volumes were brought back on-line. We suspended all drilling in the Viking, and as such, there was limited activity during the second quarter. In the first half of 2020, we invested $79 million on exploration and development in the Viking and commenced production from 83 (78.5 net) wells.

Heavy Oil

Our heavy oil assets at Peace River and Lloydminster produced a combined 13,082 boe/d (91% oil and NGL) during the second quarter, as compared to 31,211 boe/d in Q1/2020. The quarterly impact of voluntary shut-ins for heavy oil was approximately 17,000 boe/d. We suspended all heavy oil drilling, and as such, there was limited activity during the second quarter. In the first half of 2020, we invested $40 million on exploration and development and drilled 33 (33.0 net) wells. For the second half of 2020, we currently project about 5,000 boe/d of heavy oil production to remain shut-in.

Pembina Area Duvernay Light Oil

Production in the Pembina Duvernay averaged 717 boe/d (85% oil and NGL) during Q2/2020, as compared to 1,717 boe/d in Q1/2020. The quarterly impact of voluntary shut-ins for the Pembina Duvernay was approximately 1,000 boe/d. As operating netbacks improved in June, these volumes were brought back on-line.

In Q1/2020, we drilled two wells in the core of our Pembina acreage, bringing total wells drilled to nine in this area. Completion activities, originally scheduled for Q2/2020 have been deferred.

 

Financial Liquidity

Our credit facilities total approximately $1.1 billion and have a maturity date of April 2, 2024. These are not borrowing base facilities and do not require annual or semi-annual reviews. As of June 30, 2020, we had $363 million of undrawn capacity on our credit facilities, resulting in liquidity, net of working capital, of approximately $300 million. In addition, our first long-term note maturity of US$400 million is not until June 2024.

Our net debt, which includes our bank loan, long-term notes and working capital, totaled $2.0 billion at June 30, 2020. Based on the forward strip(1), we expect to maintain our financial liquidity and remain onside with our financial covenants through 2021.

Note:

  1. 2020 full year pricing assumptions: WTI – US$39/bbl; WCS differential – US$14/bbl; MSW differential – US$6/bbl, NYMEX Gas – US$1.90/mcf; AECO Gas – $2.05/mcf and Exchange Rate (CAD/USD) – 1.36. 2021 full year pricing assumptions: WTI – US$41/bbl; WCS differential – US$15/bbl; MSW differential – US$7/bbl, NYMEX Gas – US$2.60/mcf; AECO Gas – $2.35/mcf and Exchange Rate (CAD/USD) – 1.36.

Financial Covenants

The following table summarizes the financial covenants applicable to the credit facilities and Baytex’s compliance therewith as at June 30, 2020.

Covenant Description Position as at
June 30, 2020
Covenant
Senior Secured Debt(1) to Bank EBITDA(2) (Maximum Ratio) 1.0:1.0 3.5:1.0
Interest Coverage(3) (Minimum Ratio) 6.6:1.0 2.0:1.0

Notes:

  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 June 30, 2020, the Company’s Senior Secured Debt totaled $719.9 million which includes $704.1 million of principal amounts outstanding and $15.8 million of letters of credit.
  2. Bank EBITDA is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and interest expense, income tax, non-recurring losses, certain specific unrealized and non-cash transactions (including depletion, depreciation, exploration and evaluation expense, impairment, deferred income tax expense or recovery, unrealized gains and losses on financial derivatives and foreign exchange and share-based compensation) and is calculated based on a trailing twelve month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended June 30, 2020 was $704.4 million.
  3. Interest coverage is computed as the ratio of Bank EBITDA to financing and interest expense, excluding accretion of debt issue costs and asset retirement obligations, and is calculated on a trailing twelve month basis. Financing and interest expense, excluding accretion of debt issue costs and asset retirement obligations, for the twelve months ended June 30, 2020 was $106.5 million.

Risk Management

To manage commodity price movements, we utilize various financial derivative contracts and crude-by-rail to reduce the volatility of our adjusted funds flow. The following table summarizes our crude oil hedges in place.

  Q3/2020 Q4/2020 2021
WTI Fixed Hedges
Volumes (bbl/d) 23,732 8,000
Fixed Price (US$/bbl) $36.41 $42.78
WTI 3-Way Option (1)
Volumes (bbl/d) 24,500 24,500 5,000
Baytex Receives (2) (3) (4) WTI plus US$7.60 WTI plus US$7.60 US$45/bbl
Total Volumes (bbl/d) 48,232 32,500 5,000

Notes:

  1. WTI 3-way options consist of a sold put, a bought put and a sold call. Baytex’s average sold put, bought put and sold call for Q3/2020 and Q4/2020 are US$50.44/bbl, US$58.04/bbl and US$63.06/bbl, respectively. Baytex’s average sold put, bought put and sold call for 2021 are US$35/bbl, US$45/bbl and US$55/bbl, respectively.
  2. For Q3/2020 and Q4/2020, Baytex receives WTI plus US$7.60/bbl when WTI is at or below US$50.44/bbl; Baytex receives US$58.04/bbl when WTI is between US$50.44/bbl and US$58.04/bbl; Baytex receives WTI when WTI is between US$58.04/bbl and US$63.06/bbl; and Baytex receives US$63.06/bbl when WTI is above US$63.06/bbl.
  3. For 2021, Baytex receives WTI plus US$10/bbl when WTI is at or below US$35/bbl; Baytex receives US$45/bbl when WTI is between US$35/bbl and US$45/bbl; Baytex receives WTI when WTI is between US$45/bbl and US$55/bbl; and Baytex receives US$55/bbl when WTI is above US$55/bbl.
  4. Based on the forward strip for the balance of 2020, Baytex will receive WTI plus US$7.60/bbl. Based on the forward strip for 2021, Baytex will receive US$45/bbl.

For the remainder of 2020, we also have WTI-MSW basis differential swaps for 7,783 bbl/d of our light oil production in Canada at US$5.80/bbl and WCS differential hedges on 8,667 bbl/d at a WTI-WCS differential of US$14.57/bbl.

Crude-by-rail is an integral part of our egress and marketing strategy for our heavy oil production. For Q2/2020, we delivered approximately 5,250 bbl/d of our heavy oil volumes to market by rail.

A complete listing of our financial derivative contracts can be found in Note 17 to our Q2/2020 financial statements.

Sustainability

We are committed to managing the environmental and social impacts of our business and continual improvement is an important element of this commitment. In 2019, Baytex established for the first time a GHG emissions reduction target. Our objective is to reduce our corporate GHG emission intensity (tonnes of CO2 per boe) by 30% by 2021, relative to our 2018 baseline.

In 2019, we made significant improvements in our emissions profile, achieving a 15% reduction in our GHG emissions intensity as we commissioned our Peace River gas plant in mid-2018 and progressed our Viking gas conservation project. We remain committed to achieving our 30% target by the end of 2021.

2020 Guidance

There is no change to our guidance announced June 25, 2020.

2020 Guidance
Exploration and development expenditures $260 – $290 million
Production (boe/d) 78,000 – 82,000
Expenses:
Royalty rate ~ 18.5%
Operating $11.75 – $12.50/boe
Transportation $0.95 – $1.05/boe
General and administrative $38 million ($1.30/boe)
Interest $112 million ($3.84/boe)
Leasing expenditures $7 million
Asset retirement obligations $10 million

Additional Information

Our condensed consolidated interim unaudited financial statements for the three and six months ended June 30, 2020 and the related Management’s Discussion and Analysis of the operating and financial results can be accessed on our website at www.baytexenergy.com and will be available shortly through SEDAR at www.sedar.com and EDGAR at www.sec.gov/edgar.shtml.

Conference Call Tomorrow
9:00 a.m. MDT (11:00 a.m. EDT)
Baytex will host a conference call tomorrow, July 30, 2020, starting at 9:00am MDT (11:00am EDT). To participate, please dial toll free in North America 1-800-319-4610 or international 1-416-915-3239. Alternatively, to listen to the conference call online, please enter http://services.choruscall.ca/links/baytexq220200730.html in your web browser.An archived recording of the conference call will be available shortly after the event by accessing the webcast link above. The conference call will also be archived on the Baytex website at www.baytexenergy.com.


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