Baytex Energy Corp. (“Baytex”)(TSX, NYSE: BTE) reports its operating and financial results for the three and six months ended June 30, 2019 (all amounts are in Canadian dollars unless otherwise noted).
Our strong operating performance continues, with our Eagle Ford, Viking and heavy oil assets each delivering robust production and free cash flow. Given our year-to-date results, we are tightening our 2019 production guidance range to 96,000 to 97,000 boe/d (previously 95,000 to 97,000 boe/d) and lowering our budgeted exploration and development capital expenditure range to $550 to $600 million (previously $575 to $625 million). We generated a record level of free cash flow (approximately $200 million) in the first half of the year, which will allow us to redeem our US$150 million senior unsecured notes during the third quarter.
In addition, we are pleased to announce further exploration success in the East Duvernay shale with our (14-31) well brought on-stream June 27. The well has generated a 30-day initial production rate of 1,360 boe/d (76% 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 we have a dominant land position of 268 net sections.
Q2/2019 Highlights
- Generated production of 98,402 boe/d (82% oil and NGL), exceeding the high end of our guidance.
- Delivered adjusted funds flow of $236 million ($0.42 per basic share), a 7% increase compared to $221 million ($0.40 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, our highest level since 2014.
- Eagle Ford production remained strong at 39,822 boe/d reflective of continued impressive well performance. We 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% (compared to Q1/2019) reflective of the seasonal slowdown in light oil activity during the second quarter. Heavy oil production increased 2% (compared to Q1/2019) due largely to the ramp-up of our Kerrobert thermal expansion project.
- Based on the free cash flow generated in the first half of 2019, we intend to redeem the US$150 million principal amount of 6.75% senior unsecured notes at par during the third quarter.
- Using the forward strip for 2019(1), we are 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 our capital guidance by $300 million.
- Pricing assumptions: WTI – US$59/bbl; LLS – US$64/bbl; WCS differential – US$14/bbl; MSW differential – US$6/bbl, NYMEX Gas – US$2.70/mcf; AECO Gas – $1.50/mcf and Exchange Rate (CAD/USD) – 1.32.
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, 2019 |
March 31, 2019 | June 30, 2018 | June 30, 2019 |
June 30, 2018 | ||||||||||||
FINANCIAL (thousands of Canadian dollars, except per common share amounts) |
||||||||||||||||
Petroleum and natural gas sales | $ | 482,000 | $ | 453,424 | $ | 347,605 | $ | 935,424 | $ | 633,672 | ||||||
Adjusted funds flow (1) | 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 | ) | |||||||||
Capital Expenditures | ||||||||||||||||
Exploration and development expenditures (1) | $ | 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 | ||||||
Net Debt | ||||||||||||||||
Bank loan (2) | $ | 414,691 | $ | 550,751 | $ | 213,538 | $ | 414,691 | $ | 213,538 | ||||||
Long-term notes (2) | 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 (1) | $ | 2,028,686 | $ | 2,175,241 | $ | 1,784,835 | $ | 2,028,686 | $ | 1,784,835 | ||||||
Shares Outstanding – basic (thousands) | ||||||||||||||||
Weighted average | 556,599 | 555,438 | 236,628 | 556,022 | 236,472 | |||||||||||
End of period | 556,798 | 555,872 | 236,662 | 556,798 | 236,662 |
Three Months Ended | Six Months Ended | ||||||||||||||
June 30, 2019 |
March 31, 2019 | June 30, 2018 | June 30, 2019 |
June 30, 2018 | |||||||||||
OPERATING | |||||||||||||||
Daily Production | |||||||||||||||
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 @ 6:1) (3) | 98,402 | 101,115 | 70,664 | 99,751 | 70,095 | ||||||||||
Netback (thousands of Canadian dollars) | |||||||||||||||
Total sales, net of blending and other expense (4) | $ | 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 expense | (11,869 | ) | (13,330 | ) | (7,836 | ) | (25,199 | ) | (16,355 | ) | |||||
Operating netback (1) | $ | 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 (5) | 585 | 2,587 | (1,985 | ) | 3,172 | (1,901 | ) | ||||||||
Adjusted funds flow (1) | $ | 236,130 | $ | 220,770 | $ | 106,690 | $ | 456,900 | $ | 190,945 | |||||
Netback (per boe) | |||||||||||||||
Total sales, net of blending and other expense (4) | $ | 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 (1) | $ | 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 (5) | 0.07 | 0.28 | (0.31 | ) | 0.19 | (0.16 | ) | ||||||||
Adjusted funds flow (1) | $ | 26.37 | $ | 24.26 | $ | 16.59 | $ | 25.31 | $ | 15.05 |
Notes:
- 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.
- 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.
- 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.
- 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.
- Other is comprised of 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 MD&A for further information on these amounts.
Operating Results
Our 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. We continued to realize the benefits of the Baytex and Raging River combination as we increased our operating netback, delivered meaningful free cash flow and strengthened our balance sheet.
Production during the second quarter averaged 98,402 boe/d (82% oil and NGL), as compared to 101,115 boe/d (84% oil and NGL) in Q1/2019. Production in the first half of 2019 averaged 99,751 boe/d, exceeding the high end of our full-year production guidance range.
Exploration and development expenditures totaled $106 million in Q2/2019, bringing aggregate spending in the first half of 2019 to $260 million. We participated in the drilling of 67 (52.0 net) wells with a 98% success rate during the second quarter.
Eagle Ford and Viking Light Oil
Production in the Eagle Ford averaged 39,822 boe/d (76% liquids) during Q2/2019, as compared to 41,097 boe/d in Q1/2019. The lower volumes during the quarter reflect the timing of completion activity. We commenced production from 29 (5.0 net) wells during the second quarter, as compared to 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 to 23,387 boe/d in Q1/2019. Our capital program in the second quarter included the seasonal slowdown, which resulted in the completion of 49 (40.0 net) wells, as compared to 79 (67.8 net) wells during the first quarter. We currently have four drilling rigs and one frac crew executing our program and remain on track to drill approximately 250 net wells this year. Inventory enhancement continues to be a priority. We have completed multiple deals and swaps year-to-date adding 160 net unbooked drilling opportunities.
Heavy Oil
Our heavy oil assets at Peace River and Lloydminster produced a combined 29,983 boe/d during the second quarter, as compared to 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 our Kerrobert thermal expansion project.
With WCS differentials returning to historical levels, the returns associated with continued development of our heavy oil assets are competitive to those of our other plays. We expect to drill approximately 40 net heavy oil wells in the second half of 2019, as compared to nine net wells in the first half of the year.
East Duvernay Shale Light Oil
We continue 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 we drilled four wells that continued 45 sections of land and further confirmed the prospectivity of our 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% liquids). The second well (3-19) was brought on-stream July 26 and is currently producing 1,063 boe/d (89% 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 favorable 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, we developed an improved drilling process and will re-drill these locations in the future.
Well costs have significantly improved with our two successful wells drilled and completed for an average cost of approximately $7.0 million per well. This represents an approximate 20% reduction from the average cost of our previous wells. As the play moves from delineation to development, the efficiency from multi-well pad operations is expected to drive further cost reductions.
The success of our drilling program in the Pembina area has significantly de-risked our approximately 38 kilometer long acreage fairway, where we hold 268 sections (100% working interest) of Duvernay land.
Financial Review
Our adjusted funds flow in Q2/2019 increased 7% as compared to Q1/2019, driven by strong operating performance in an improved commodity price environment. We generated adjusted funds flow of $236 million ($0.42 per basic share) in Q2/2019, compared to $221 million ($0.40 per basic share) in Q1/2019.
In Q2/2019, the price for West Texas Intermediate light oil (“WTI”) averaged US$59.81/bbl, as compared to US$54.90/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 US$4.61/bbl in Q2/2019 as compared to US$4.85/bbl in Q1/2019.The discount for Canadian heavy oil, as measured by the price differential between Western Canadian Select (“WCS”) and WTI, averaged US$10.68/bbl in Q2/2019 as compared to US$12.29/bbl in Q1/2019. In the Eagle Ford, our 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 US$7.34/bbl premium to WTI as compared to US$6.70/bbl in Q1/2019.
We generated an operating netback of $29.27/boe in Q2/2019, as compared to $26.56/boe in Q1/2019 and $27.08/boe in Q2/2018. Our Canadian operations generated an operating netback of $29.47/boe during Q2/2019 while our Eagle Ford asset generated an operating netback of $28.98/boe. Our operating netback in Canada has improved meaningfully with the inclusion of the high operating netback Viking light oil production.
The following table summarizes our operating netbacks for the periods noted.
Three Months Ended June 30 | ||||||||||||||||||
2019 | 2018 | |||||||||||||||||
($ 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 |
Notes:
- 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.
- 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 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.
Financial Liquidity
We are delivering on our commitment to generate meaningful free cash flow and improve our balance sheet. In aggregate, we 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.
Our net debt, which includes our bank loan, long-term notes and working capital, totaled $2.0 billion at June 30, 2019. We maintain strong financial liquidity with our credit facilities approximately 60% undrawn and our first long-term note maturity not until 2021.
On May 2, 2019, we extended the maturity of our revolving credit facilities to April 2021. The credit facilities are not borrowing base facilities and do not require annual or semi-annual reviews. Our credit facilities total approximately $1.05 billion, comprised of US$575 million of revolving credit facilities and a $300 million non-revolving term loan.
Subsequent to quarter-end, we initiated plans to redeem US$150 million principal amount of 6.75% senior unsecured notes due February 17, 2021. Redemption of the notes is expected to occur during the third quarter and will be funded from the free cash flow generated during the first half of 2019.
Risk Management
As part of our normal operations, we are exposed to movements in commodity prices. In an effort to manage these exposures, we utilize various financial derivative contracts, crude-by-rail and capital allocation optimization to reduce the volatility in our adjusted funds flow. We realized a financial derivatives gain of $13 million in Q2/2019.
For the balance of 2019, we have entered into hedges on approximately 48% of our net crude oil exposure. This includes 43% of our net WTI exposure with 18% fixed at US$62.82/bbl and 25% hedged utilizing a 3-way option structure that provides us with a US$10/bbl premium to WTI when WTI is at or below US$55.64/bbl and allows upside participation to US$73.65/bbl. In addition, we have entered into a Brent-based 3-way option structure for 3,000 bbl/d that provides a US$10/bbl premium to Brent when Brent is at or below US$59.50/bbl and allows upside participation to US$78.68/bbl. We have also entered into hedges on approximately 22% of our net natural gas exposure through a series of NYMEX swaps at US$3.10/mmbtu. For 2020, we have entered into hedges on approximately 15% of our net crude oil exposure, utilizing a 3-way option structure that provides us with a US$9/bbl premium to WTI when WTI is at or below US$51.00/bbl and allows upside participation to US$66.06/bbl.
Crude-by-rail is an integral part of our egress and marketing strategy for our heavy oil production. For 2019, we expect to deliver 11,500 bbl/d (approximately 40%) of our heavy oil volumes to market by rail, up from 9,000 bbl/d in 2018. Approximately 70% of our crude by rail commitments are WTI based contracts with no WCS pricing exposure. In addition, for the balance of 2019, we have entered into WCS differential hedges on approximately 13% of our net heavy oil exposure at a WTI-WCS differential of US$17.49/bbl. We have also entered into a WTI-MSW basis differential swap for 4,000 bbl/d of our light oil production in Canada at US$8/bbl for June 2019 to December 2019.
A complete listing of our financial derivative contracts can be found in Note 18 to our Q2/2019 financial statements.
Outlook for 2019
Given our strong year-to-date operating performance, we are tightening our 2019 production guidance range to 96,000 to 97,000 boe/d (previously 95,000 to 97,000 boe/d) and lowering our budgeted exploration and development capital expenditure range to $550 to $600 million (previously $575 to $625 million).
Based on the forward strip for the balance of 2019(1), we are forecasting adjusted funds flow of approximately $875 million. Further deleveraging remains a top priority. For 2019, adjusted funds flow in excess of exploration and development expenditures, leasing expenditures and asset retirement obligations, will be used to reduce our indebtedness. Our year end 2019 net debt to trailing adjusted funds flow ratio is forecast to be 2.2x.
As we continue to drive debt levels down, we will be positioned to enhance shareholder returns through a combination of organic growth, disciplined capital allocation, the reinstatement of a dividend and/or share buybacks.
The following table summarizes our 2019 annual guidance and compares it to our 2019 year-to-date actual results.
Guidance | YTD 2019 | |||||
Exploration and development capital ($ millions) (2) | $550 – $600 | $260.1 | ||||
Production (boe/d) (2) | 96,000 – 97,000 | 99,751 | ||||
Expenses: | ||||||
Royalty rate (%) (2) | 19% | 18.7 | % | |||
Operating ($/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 |
- 2019 full year pricing assumptions: WTI – US$59/bbl; LLS – US$64/bbl; WCS differential – US$14/bbl; MSW differential – US$6/bbl, NYMEX Gas – US$2.70/mcf; AECO Gas – $1.50/mcf and Exchange Rate (CAD/USD) – 1.32.
- Our exploration and development capital and production guidance along with the expected royalty rate for 2019 has been updated as of August 1, 2019. Original guidance from December 2018: production – 93,000-97,000 boe/d; exploration and development capital – $550-$650 million; royalty rate – 20%.
The following table summarizes our annual adjusted funds flow sensitivities to changes in commodity prices and the CAD/USD exchange rate.
Excluding Hedges ($ millions) |
Including Hedges ($ millions) |
|||
Change of US$1.00/bbl WTI crude oil | $28.3 | $18.2 | ||
Change of US$1.00/bbl WCS heavy oil differential | $11.4 | $9.5 | ||
Change of US$1.00/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 |