An anonymous director reports
BAYTEX ANNOUNCES SECOND QUARTER 2019 FINANCIAL AND OPERATING RESULTS
Baytex Energy Corp. has provided its operating and financial results for the three and six months ended June 30, 2019.
The company's strong operating performance continues, with its Eagle Ford, Viking and heavy oil assets each delivering robust production and free cash flow. Given the company's year-to-date results, it is tightening its 2019 production guidance range to 96,000 to 97,000 barrels of oil equivalent per day (previously 95,000 to 97,000 boe/d) and lowering its budgeted exploration and development capital expenditure range to $550-million to $600-million (previously $575-million to $625-million). The company generated a record level of free cash flow (approximately $200-million) in the first half of the year, which will allow it to redeem its $150-million (U.S.) senior unsecured notes during the third quarter.
In addition, the company is pleased to announce further exploration success in the East Duvernay shale with its (14-31) well brought on stream June 27. The well has generated a 30-day initial production rate of 1,360 boe/d (76 per cent liquids). This successful result in conjunction with a reduction in drilling and completion capital to approximately $7.0-million per well has solidified Pembina as a highly prospective region of the East Duvernay shale, in which the company has a dominant land position of 268 net sections.
Q2 2019 highlights
Generated production of 98,402 boe/d (82 per cent oil and natural gas liquids), exceeding the high end of the company's guidance;
Delivered adjusted funds flow of $236-million (42 cents per basic share), a 7-per-cent increase compared with $221-million (40 cents per basic share) in Q1 2019;
Reduced net debt by $147-million during the quarter ($236-million year to date) as adjusted funds flow exceeded capital expenditures and the Canadian dollar strengthened relative to the U.S. dollar;
Realized an operating netback (inclusive of hedging) of $30.72/boe, the company's highest level since 2014;
Eagle Ford production remained strong at 39,822 boe/d reflective of continued impressive well performance. The company established average 30-day initial production rates of approximately 2,045 boe/d per well from 29 (5.0 net) wells that commenced production during the quarter;
Production in Canada averaged 58,580 boe/d, down 2 per cent (compared with Q1 2019) reflective of the seasonal slowdown in light oil activity during the second quarter. Heavy oil production increased 2 per cent (compared with Q1 2019) due largely to the ramp-up of the company's Kerrobert thermal expansion project.
Based on the free cash flow generated in the first half of 2019, the company intends to redeem the $150-million (U.S.) principal amount of 6.75 per cent senior unsecured notes at par during the third quarter.
Using the forward strip for 2019 (1), the company is now forecasting adjusted funds flow for 2019 of approximately $875-million. Further deleveraging remains a top priority with adjusted funds flow exceeding the midpoint of the company's capital guidance by $300-million.
(1) Pricing assumptions: West Texas intermediate -- $59 (U.S.) per barrel; LLS -- $64 (U.S.)/bbl; WCS differential -- $14 (U.S.)/bbl; MSW differential -- $6 (U.S.)/bbl, NYMEX Gas -- $2.70 (U.S.) per thousand cubic feet; AECO Gas -- $1.50/mcf and exchange rate (Canadian/U.S. dollar) -- $1.32.
Three months ended Six months ended
June 30, 2019 March 31, 2019 June 30, 2018 June 30, 2019 June 30, 2018
(thousands of dollars)
Petroleum and natural gas sales $ 482,000 $ 453,424 $ 347,605 $ 935,424 $ 633,672
Adjusted funds flow 236,130 220,770 106,690 456,900 190,945
Per share -- basic 0.42 0.40 0.45 0.82 0.81
Per share -- diluted 0.42 0.40 0.45 0.82 0.81
Net income (loss) 78,826 11,336 (58,761) 90,162 (121,483)
Per share -- basic 0.14 0.02 (0.25) 0.16 (0.51)
Per share -- diluted 0.14 0.02 (0.25) 0.16 (0.51)
Exploration and development expenditures $ 106,246 $ 153,843 $ 78,830 $ 260,089 $ 172,364
Acquisitions, net of divestitures 1,647 - (21) 1,647 (2,047)
Total oil and natural gas capital expenditures $ 107,893 $ 153,843 $ 78,809 $ 261,736 $ 170,317
Bank loan $ 414,691 $ 550,751 $ 213,538 $ 414,691 $ 213,538
Long-term notes 1,543,645 1,569,153 1,548,490 1,543,645 1,548,490
Long-term debt 1,958,336 2,119,904 1,762,028 1,958,336 1,762,028
Working capital deficiency 70,350 55,337 22,807 70,350 22,807
Net debt $ 2,028,686 $ 2,175,241 $ 1,784,835 $ 2,028,686 $1,784,835
Three months ended Six months ended
June 30, 2019 March 31, 2019 June 30, 2018 June 30, 2019 June 30, 2018
Light oil and condensate (bbl/d) 42,585 45,048 21,100 43,809 21,034
Heavy oil (bbl/d) 27,320 26,891 25,544 27,107 25,208
NGL (bbl/d) 10,986 11,729 9,419 11,356 9,281
Total liquids (bbl/d) 80,891 83,668 56,063 82,272 55,523
Natural gas (mcf/d) 105,065 104,682 87,605 104,874 87,434
Oil equivalent (boe/d at 6:1) (2) 98,402 101,115 70,664 99,751 70,095
Netback (thousands of Canadian dollars)
Total sales, net of blending and other
expense (3) $ 461,110 $ 436,636 $ 329,366 $ 897,746 $598,143
Royalties (86,617) (81,325) (77,205) (167,942) (142,044)
Operating expense (100,474) (100,292) (70,149) (200,766) (136,037)
Transportation expen se (11,869) (13,330) (7,836) (25,199) (16,355)
Operating netback $ 262,150 $ 241,689 $ 174,176 $ 503,839 $303,707
General and administrative (11,506) (14,136) (10,563) (25,642) (21,571)
Cash financing and interest (28,092) (28,184) (25,530) (56,276) (50,041)
Realized financial derivatives gain (loss) 12,993 18,814 (29,408) 31,807 (39,249)
Other (4) 585 2,587 (1,985) 3,172 (1,901)
Adjusted funds flow $ 236,130 $ 220,770 $ 106,690 $ 456,900 $190,945
Netback (per boe)
Total sales, net of blending and other
expense (3) $ 51.49 $ 47.98 $ 51.22 $ 49.72 $ 47.15
Royalties (9.67) (8.94) (12.01) (9.30) (11.20)
Operating expense (11.22) (11.02) (10.91) (11.12) (10.72)
Transportation expense (1.33) (1.46) (1.22) (1.40) (1.29)
Operating netback $ 29.27 $ 26.56 $ 27.08 $ 27.90 $ 23.94
General and administrative (1.28) (1.55) (1.64) (1.42) (1.70)
Cash financing and interest (3.14) (3.10) (3.97) (3.12) (3.94)
Realized financial derivatives gain (loss) 1.45 2.07 (4.57) 1.76 (3.09)
Other (4) 0.07 0.28 (0.31) 0.19 (0.16)
Adjusted funds flow $ 26.37 $ 24.26 $ 16.59 $ 25.31 $ 15.05
(1) 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 liquidity or repayment obligations.
(2) Barrel of oil equivalent (boe) amounts have been calculated using a conversion rate of 6,000 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 6,000 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.
(3) Realized heavy oil prices are calculated based on sales dollars, net of blending and other expense. The company
includes the cost of blending diluent in its realized heavy oil sales price in order to compare the realized pricing
on its produced volumes to the WCS benchmark.
(4) Other comprises realized foreign exchange gain or loss, other income or expense, current income tax expense or
recovery and payments on onerous contracts. Refer to the Q2 2019 management's discussion and analysis for further
information on these amounts.
The company's operating results for the second quarter of 2019 were buoyed by an improved commodity price environment along with strong operating performance in the Eagle Ford and Canada. The company continued to realize the benefits of the Baytex and Raging River combination as it increased its operating netback, delivered meaningful free cash flow and strengthened its balance sheet.
Production during the second quarter averaged 98,402 boe/d (82 per cent oil and NGL), as compared with 101,115 boe/d (84 per cent oil and NGL) in Q1 2019. Production in the first half of 2019 averaged 99,751 boe/d, exceeding the high end of the company's full-year production guidance range.
Exploration and development expenditures totalled $106-million in Q2 2019, bringing aggregate spending in the first half of 2019 to $260-million. The company participated in the drilling of 67 (52.0 net) wells with a 98-per-cent success rate during the second quarter.
Eagle Ford and Viking light oil
Production in the Eagle Ford averaged 39,822 boe/d (76 per cent liquids) during Q2 2019, as compared with 41,097 boe/d in Q1 2019. The lower volumes during the quarter reflect the timing of completion activity. The company commenced production from 29 (5.0 net) wells during the second quarter, as compared with 36 (8.9 net) wells during the first quarter. The wells brought on stream generated an average 30-day initial production rate of approximately 2,045 boe/d per well.
During Q2 2019, production from the Viking averaged 22,565 boe/d, as compared with 23,387 boe/d in Q1 2019. The company's capital program in the second quarter included the seasonal slowdown, which resulted in the completion of 49 (40.0 net) wells, as compared with 79 (67.8 net) wells during the first quarter. The company currently has four drilling rigs and one frac crew executing its program and remains on track to drill approximately 250 net wells this year. Inventory enhancement continues to be a priority. The company has completed multiple deals and swaps year to date adding 160 net unbooked drilling opportunities.
The company's heavy oil assets at Peace River and Lloydminster produced a combined 29,983 boe/d during the second quarter, as compared with 29,341 boe/d in Q1 2019. The higher volumes reflect the completion of three previously deferred wells at Peace River along with the ramp-up of its Kerrobert thermal expansion project.
With WCS differentials returning to historical levels, the returns associated with continued development of the company's heavy oil assets are competitive to those of its other plays. The company expects to drill approximately 40 net heavy oil wells in the second half of 2019, as compared with nine net wells in the first half of the year.
East Duvernay shale light oil
The company continues to prudently advance the delineation of the East Duvernay shale, an early-stage, high operating netback light oil resource play. During the first half of 2019 the company drilled four wells that continued 45 sections of land and further confirmed the prospectivity of its Pembina acreage.
Two of these wells were completed and initial flow back rates are very encouraging. The first well (14-31) was brought on stream June 27 and generated a 30-day initial production rate of 1,360 boe/d (76 per cent liquids). The second well (3-19) was brought on stream July 26 and is currently producing 1,063 boe/d (89 per cent liquids). These two wells were fracture stimulated using a plug and perf system and were the first Baytex wells to utilize fracture diversion technology. The other two wells were drilled to depth and encountered thick, well-developed shale sections with highly favourable geological characteristics including natural fracturing. Unfortunately both of these wells had to be abandoned due to wellbore stability issues. Having conducted an in-depth review of these two wells, the company developed an improved drilling process and will redrill these locations in the future.
Well costs have significantly improved with the company's two successful wells drilled and completed for an average cost of approximately $7.0-million per well. This represents an approximate 20-per-cent reduction from the average cost of its previous wells. As the play moves from delineation to development, the efficiency from multiwell pad operations is expected to drive further cost reductions.
The success of the company's drilling program in the Pembina area has significantly derisked its approximately 38-kilometre-long acreage fairway, where it holds 268 sections (100-per-cent working interest) of Duvernay land.
The company's adjusted funds flow in Q2 2019 increased 7 per cent as compared with Q1 2019, driven by strong operating performance in an improved commodity price environment. The company generated adjusted funds flow of $236-million (42 cents per basic share) in Q2 2019, compared with $221-million (40 cents per basic share) in Q1 2019.
In Q2 2019, the price for West Texas intermediate light oil (WTI) averaged $59.81 (U.S.)/bbl, as compared with $54.90 (U.S.)/bbl in Q1 2019. The discount for Canadian light oil, as measured by the price differential between Canadian mixed sweet blend (MSW) and WTI, averaged $4.61 (U.S.)/bbl in Q2 2019 as compared with $4.85 (U.S.)/bbl in Q1/2019.
The discount for Canadian heavy oil, as measured by the price differential between Western Canadian select (WCS) and WTI, averaged $10.68 (U.S.)/bbl in Q2 2019 as compared with $12.29 (U.S.)/bbl in Q1 2019. In the Eagle Ford, the company's assets are proximal to Gulf Coast markets with light oil and condensate production priced off the LLS crude oil benchmark. In Q2 2019, the price for LLS averaged a $7.34 (U.S.)/bbl premium to WTI as compared with $6.70 (U.S.)/bbl in Q1 2019.
The company generated an operating netback of $29.27/boe in Q2 2019, as compared with $26.56/boe in Q1 2019 and $27.08/boe in Q2 2018. The company's Canadian operations generated an operating netback of $29.47/boe during Q2 2019 while its Eagle Ford asset generated an operating netback of $28.98/boe. The company's operating netback in Canada has improved meaningfully with the inclusion of the high operating netback Viking light oil production.
The attached table summarizes the company's operating netbacks for the periods noted.
Three months ended June 30, Three months ended June 30,
($ per boe except for production) Canada U.S. Total Canada U.S. Total
Production (boe/d) 58,580 39,822 98,402 34,042 36,622 70,664
Total sales, net of blending and other (1) $51.36 $51.69 $51.49 $41.61 $60.16 $51.22
Royalties (5.80) (15.37) (9.67) (5.81) (17.77) (12.01)
Operating expense (13.86) (7.34) (11.22) (15.15) (6.97) (10.91)
Transportation expense (2.23) - (1.33) (2.53) - (1.22)
Operating netback (2) $29.47 $28.98 $29.27 $18.12 $35.42 $27.08
Realized financial derivatives gain (loss) - - 1.45 - - (4.57)
Operating netback after financial derivatives $29.47 $28.98 $30.72 $18.12 $35.42 $22.51
(1) Realized heavy oil prices are calculated based on sales dollars, net of blending and other expense.
The company included the cost of blending diluent in its realized heavy oil sales price in order to
compare the realized pricing on its produced volumes with the WCS benchmark.
(2) The term operating netback does not have any standardized meaning as prescribed by Canadian generally
accepted accounting principles (GAAP) and therefore may not be comparable with similar measures
presented by other companies where similar terminology is used.
The company is delivering on its commitment to generate meaningful free cash flow and improve its balance sheet. In aggregate, the company reduced net debt by $147-million during the second quarter ($236-million year to date) as adjusted funds flow exceeded capital expenditures and the Canadian dollar strengthened relative to the U.S. dollar.
The company's net debt, which includes its bank loan, long-term notes and working capital, totalled $2.0-billion at June 30, 2019. The company maintains strong financial liquidity with its credit facilities approximately 60 per cent undrawn and its first long-term note maturity not until 2021.
On May 2, 2019, the company extended the maturity of its revolving credit facilities to April, 2021. The credit facilities are not borrowing base facilities and do not require annual or semi-annual reviews. The company's credit facilities total approximately $1.05-billion, comprising $575-million (U.S.) of revolving credit facilities and a $300-million non-revolving term loan.
Subsequent to quarter-end, the company initiated plans to redeem $150-million (U.S.) principal amount of 6.75 per cent senior unsecured notes due Feb. 17, 2021. Redemption of the notes is expected to occur during the third quarter and will be financed from the free cash flow generated during the first half of 2019.
As part of the company's normal operations, it is exposed to movements in commodity prices. In an effort to manage these exposures, the company utilizes various financial derivative contracts, crude-by-rail and capital allocation optimization to reduce the volatility in its adjusted funds flow. The company realized a financial derivatives gain of $13-million in Q2 2019.
For the balance of 2019, the company has entered into hedges on approximately 48 per cent of its net crude oil exposure. This includes 43 per cent of the company's net WTI exposure with 18 per cent fixed at $62.82 (U.S.)/bbl and 25 per cent hedged utilizing a three-way option structure that provides us with a $10-(U.S.)-per-barrel premium to WTI when WTI is at or below $55.64 (U.S.)/bbl and allows upside participation to $73.65 (U.S.)/bbl. In addition, the company has entered into a Brent-based three-way option structure for 3,000 bbl/d that provides a $10 (U.S.)/bbl premium to Brent when Brent is at or below $59.50 (U.S.)/bbl and allows upside participation to $78.68 (U.S.)/bbl. The company has also entered into hedges on approximately 22 per cent of its net natural gas exposure through a series of Nymex swaps at $3.10 (U.S.)/mmbtu. For 2020, the company has entered into hedges on approximately 15 per cent of its net crude oil exposure, utilizing a three-way option structure that provides the company with a $9 (U.S.)/bbl premium to WTI when WTI is at or below $51 (U.S.)/bbl and allows upside participation to $66.06 (U.S.)/bbl.
Crude-by-rail is an integral part of the company's egress and marketing strategy for its heavy oil production. For 2019, the company expects to deliver 11,500 bbl/d (approximately 40 per cent) of its heavy oil volumes to market by rail, up from 9,000 bbl/d in 2018. Approximately 70 per cent of the company's crude-by-rail commitments is WTI-based contracts with no WCS pricing exposure. In addition, for the balance of 2019, the company has entered into WCS differential hedges on approximately 13 per cent of its net heavy oil exposure at a WTI-WCS differential of $17.49 (U.S.)/bbl. The company has also entered into a WTI-MSW basis differential swap for 4,000 bbl/d of its light oil production in Canada at $8 (U.S.)/bbl for June, 2019, to December, 2019.
Outlook for 2019
Given the company's strong year-to-date operating performance, it is tightening its 2019 production guidance range to 96,000 to 97,000 boe/d (previously 95,000 to 97,000 boe/d) and lowering its budgeted exploration and development capital expenditure range to $550-million to $600-million (previously $575-million to $625-million).
Based on the forward strip for the balance of 2019 (1), the company is forecasting adjusted funds flow of approximately $875-million. Further deleveraging remains a top priority. For 2019, adjusted funds flow in excess of exploration and development expenditures, leasing expenditures and asset retirement obligations, will be used to reduce the company's indebtedness. The company's year-end 2019 net debt to trailing adjusted funds flow ratio is forecast to be 2.2 times.
As the company continues to drive debt levels down, it will be positioned to enhance shareholder returns through a combination of organic growth, disciplined capital allocation, the reinstatement of a dividend and/or share buybacks.
The attached table summarizes its 2019 annual guidance and compares it with its 2019 year-to-date actual results.
Guidance YTD 2019
Exploration and development capital ($ millions) (2) $550-$600 $260.1
Production (boe/d) (2) 96,000-97,000 99,751
Royalty rate (%) (2) 19% 18.7%
Operating ($/boe) $10.75-$11.25 $11.12
Transportation ($/boe) $1.25-$1.35 $1.40
General and administrative ($ millions) $46 ($1.30/boe) $25.6 ($1.42/boe)
Interest ($ millions) $112 ($3.23/boe) $56.3 ($3.12/boe)
Leasing expenditures ($ millions) $5 $3.0
Asset retirement obligations ($ millions) $17 $9.7
(1) Two thousand nineteen full year pricing assumptions: WTI -- $59 (U.S.)/bbl;
LLS -- $64 (U.S.)/bbl; WCS differential -- $14 (U.S.)/bbl; MSW differential --
$6 (U.S.)/bbl, NYMEX Gas -- $2.70 (U.S.)/mcf; AECO Gas -- $1.50/mcf and exchange
rate (Canadian/U.S. dollar) -- 1.32.
(2) The company's exploration and development capital and production guidance along
with the expected royalty rate for 2019 has been updated as of Aug. 1, 2019. Original
guidance from December, 2018: production -- 93,000 to 97,000 boe/d; exploration and
development capital -- $550-million to $650-million; royalty rate -- 20 per cent.
The attached table summarizes the company's annual adjusted funds flow sensitivities to changes in commodity prices and the Canadian/U.S.-dollar exchange rate.
Excluding hedges ($ millions) Including hedges ($ millions)
Change of US$1/bbl WTI crude oil $28.3 $18.2
Change of US$1/bbl WCS heavy oil differential $11.4 $9.5
Change of US$1/bbl MSW light oil differential $9.2 $7.7
Change of US$0.25/mcf NYMEX natural gas $9.4 $7.5
Change of $0.01 in the CAD/USD exchange rate $11.0 $11.0
The company's condensed consolidated interim unaudited financial statements for the three and six months ended June 30, 2019, and the related management's discussion and analysis of the operating and financial results can be accessed on the company's website and will be available shortly through SEDAR and EDGAR.
Conference call today at 9 a.m. MDT (11 a.m. EDT)
Baytex will host a conference call today, Aug. 1, 2019, starting at 9 a.m. MDT (11 a.m. 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 on-line, please go to the ChorusCall website. An archived recording of the conference call will be available shortly after the event by visiting the ChorusCall website. The conference call will also be archived on the Baytex website.
About Baytex Energy Corp.
Baytex Energy is an oil and gas corporation based in Calgary, Alta. The company is engaged in the acquisition, development and production of crude oil and natural gas in the Western Canadian sedimentary basin and in the Eagle Ford in the United States. Approximately 83 per cent of Baytex's production is weighted toward crude oil and natural gas liquids.
We seek Safe Harbor.
© 2020 Canjex Publishing Ltd. All rights reserved.