Mr. Jason Skehar reports
BONAVISTA ENERGY CORPORATION ANNOUNCES 2019 FIRST QUARTER RESULTS
Bonavista Energy Corp. has provided to shareholders its financial and operating results for the three months ended March 31, 2019. The financial statements and notes, as well as management's discussion and analysis, are available on SEDAR and on Bonavista's website.
Through the first three months of 2019, the company directed a moderate 75 per cent of its adjusted funds flow to its capital program as it pragmatically navigated the current and future commodity price discounts created by regulatory uncertainty and inadequate pipeline capacity in the Canadian energy sector.
Capital expenditures, net of acquisition and divestiture activity in the quarter were $43.8-million. Seventy per cent of its exploration and development spending was allocated to drilling 10 gross (9.6 net) wells, primarily in its West Central core area. The remaining 30 per cent was allocated to support capital, the majority of which was directed to land and infrastructure spending.
Additional Duvernay mineral rights were acquired in the quarter, firmly establishing the company's presence in this emerging liquids-rich resource play with access now to approximately 190 prospective sections. Currently, the company plans to drill its first Duvernay horizontal well in the second half of this year.
Infrastructure projects initiated in the first quarter will lead to total spend of approximately $15-million on such projects in the first half of 2019, most of which are concentrated in its West Central core area. This will allow the company to redirect current and future production in the Willesden Green area to a lower-cost, efficient processing solution.
Production for the quarter was recorded modestly ahead of budget, despite severe cold temperatures in the later half of the first quarter leading to unanticipated production downtime. Natural gas liquids (NGL) and oil production account for 30 per cent of the total, marking a 4-per-cent increase in its oil and liquids weighting over the prior year period.
Natural gas prices were buoyed in the first quarter by the extended period of extreme cold in the province, providing the company an opportunity to hedge an incremental 28 million cubic feet (mmcf) per day for the summer period of 2019 at an average price of $1.31 per thousand cubic feet (mcf). When combined with other diversification initiatives, the company has less than 20 per cent of its forecasted natural gas production exposed to spot AECO pricing over the summer period of 2019.
2019 first quarter financial and operating highlights:
Sustained production at 66,937 barrels of oil equivalent (boe) per day within 2 per cent of prior quarter production rates while spending only 75 per cent of adjusted funds flow;
- Executed an exploration and development capital program of $49-million, drilling 10 gross (9.6 net) wells while completing eight gross (7.6 net) wells. The company's focus remains on drilling liquids-rich prospects, with seven of its 10 wells drilled in its West Central area;
- Divested of a sour natural gas non-core asset producing 442 boe per day at closing for net proceeds of $5.4-million;
- Generated $58.2-million (22 cents per share) in adjusted funds flow, 6 per cent ahead of forecast;
- Recorded cash costs of $9.55 per boe, slightly below forecast but in excess of prior quarter resulting from a modest increase in operating expenses due to the cold weather experienced in February and March;
- Strengthened its position in the emerging Duvernay play by acquiring land in the Pembina area, bringing its total prospective lands to over 121,000 acres within its core areas;
- Protected 2019 adjusted funds flow through the summer period, when NGTL maintenance activities escalate, with 75 per cent of the company's forecasted 2019 natural gas production hedged at an average price of $2.11 per mcf.
FINANCIAL AND OPERATING HIGHLIGHTS
(all dollar values in thousands of dollars, except per-share amounts)
Three months ended
Dec. 31, 2018 March 31, 2019 March 31, 2018
Production revenues $124,302 $120,636 $138,388
Net income (loss) 81,227 (40,135) (2,037)
Per share 0.31 (0.15) (0.01)
Cash flow from operating activities 77,581 54,485 76,048
Per share 0.30 0.21 0.30
Adjusted funds flow 61,075 58,181 69,128
Per share 0.23 0.22 0.27
Dividends declared 2,555 2,558 2,523
Per share 0.01 0.01 0.01
Total assets 2,923,709 2,867,965 2,933,854
Shareholders equity 1,552,184 1,512,870 1,539,073
Long-term debt 801,625 781,168 802,394
Net debt 835,905 811,440 839,619
Exploration and development 45,172 49,023 43,855
Acquisitions, net of dispositions 11,037 (5,378) 97
Corporate 221 119 145
Operating (boe conversion -- 6:1 basis)
Natural gas (mmcf/day) 281 282 322
Natural gas liquids (bbl/day) 19,131 17,945 16,480
Oil (bbl/day) 2,108 1,988 2,327
Total oil equivalent (boe/day) 68,011 66,937 72,417
Natural gas ($/mcf) 2.91 2.61 2.85
Natural gas liquids ($/bbl) 24.99 28.95 31.68
Oil ($/bbl) 28.47 60.21 59.81
Total oil equivalent ($/boe) 19.91 20.54 21.79
Operating expenses ($/boe) 5.66 5.85 5.64
Transportation expenses ($/boe) 1.37 1.44 1.23
General and administrative expenses ($/boe) 0.87 0.84 1.09
Cash costs ($/boe) 9.27 9.55 9.38
Operating netback ($/boe) 11.99 11.92 13.11
Two core areas
The company remains committed to disciplined reinvestment levels, generating free cash flows from its operating activities to allocate toward the reduction of its net debt. Net capital expenditures for the first quarter were $43.8-million, which equates to 75 per cent of its adjusted funds flow. Exploration and development expenditures were $49-million with $34.2-million allocated to drilling 9.6 net wells and completing 7.6 net wells. The remaining $14.8-million was spent on support capital, most notably a crown land acquisition in the Duvernay and infrastructure projects in West Central. Dispositions in the quarter totalled $5.4-million, with virtually no capital directed to acquisition expenditures.
Deep Basin operations
For Q1 2019, 32 per cent of exploration and development capital was invested in the company's Deep Basin core area. With exploration and development expenditures of $15-million, $14-million was allocated to value projects where the company drilled two Ansell Wilrich wells and participated in the drilling of one non-operated Cardium well. At Ansell, the company finished drilling a three-well pad, which it completed at the end of February. Unfortunately, excessive frac interference resulted in the initial 40-per-cent reduction in performance relative to expectations. The company will continue to monitor and anticipate performance to converge closer to expectations with time.
Despite the Ansell new well underperformance, Q1 2019 production in the company's Deep Basin core area averaged 24,097 boe per day, which was within 1 per cent of its forecast. This was achieved mainly due to increased production at its Edson area. The Notikewin well drilled at Edson in the final months of 2018 has averaged 8.4 million cubic feet (mmcf) per day over its first 90 days of production, which is similar to the initial Notikewin well on production in Q1 2018. To take advantage of the cold-weather-induced high pricing in February, modifications were made to the company's compression facilities at Edson to increase capacity and remove flowing pressure restrictions.
With its focus on liquids-rich development, the Deep Basin core are will have limited activity for the remainder of 2019. The plan is to drill two to four more wells targeting the Spirit River formations.
West Central operations
For Q1 2019, 66 per cent of exploration and development capital was invested in the company's West Central core area. With exploration and development expenditures of $33-million, $20-million was allocated to value capital and $13-million was allocated to support capital. During the quarter, the company drilled seven gross (seven net) wells comprising four in the Glauconite formation and three in the Falher formation. Of these wells, four wells have been completed in the quarter with three wells to be completed in the second quarter. The first two Falher wells have averaged 5.8 mmcf per day over the first 60 days on production, which exceeds the company's forecast by 38 per cent. The two Glauconite wells completed at the end of the quarter have just recently been brought on production and are meeting expectations.
Average Q1 2019 production in the company's West Central core area was 40,741 boe per day comprising 59 per cent natural gas and 41 per cent oil and liquids.
For the remainder of the year, the plan is to drill 12 to 18 wells in its West Central core area, mainly focused on the Glauconite play. To accommodate this development, the company is investing $20-million of support expenditures to expand pipeline and compression infrastructure at Strachan and Willesden Green in the second and third quarters of 2019.
In Q1 2019, the company invested $6.2-million in our West Central core area to further expand its Duvernay land position. This brings its total exposure in the Duvernay light oil and condensate rich gas windows to approximately 190 sections. Its initial appraisal of the Duvernay will be undertaken in the Pembina area with its first horizontal well to be drilled in the second half of 2019.
Q1 2019 production
Production for the quarter averaged 66,937 boe per day comprising 282 mmcf per day of natural gas, 17,945 bbl per day of natural gas liquids and 1,988 bbl per day of oil. This production rate was modestly ahead of forecasted volumes and was achieved despite the extreme cold weather impacting operations throughout the quarter. The company's commitment to allocating capital to liquids-rich projects over the past year has increased its oil and natural gas liquids ratio to 30 per cent of its total production volumes, 4 per cent higher than the same period last year.
Q1 2019 production revenue, marketing and risk management
Production revenues for the first quarter, inclusive of $3.1-million of realized gains on financial instrument commodity contracts, was $123.7-million, or $20.54 per boe, which was within 1 per cent of the prior quarter. Production revenues, excluding realized gains on financial instrument commodity contracts was $120.6-million, or $20.02 per boe. Realized pricing for natural gas was $2.61 per thousand cubic feet (mcf), a 10-per-cent reduction from the previous quarter but ahead of the average AECO daily spot price for the quarter of $2.49 per mcf and a 42-per-cent premium to the average AECO monthly index price of $1.84 per mcf. Financial hedging accounted for a premium of nine cents per mcf and 57 cents per barrel (bbl) for natural gas and natural gas liquids, respectively, and a discount of 32 cents per bbl on realized oil pricing.
Q1 2019 operating and transportation expenses
Operating expenses in the quarter were $5.85 per boe, in line with the company's forecast but an increase from $5.66 per boe from the prior quarter, reflecting the seasonal impact of increased operating expenses.
Transportation expenses were 1 per cent higher in the quarter at $8.7-million compared with $8.6-million in the previous quarter and, on a per-barrel basis, transportation expenses were $1.44 per boe as compared with $1.37 per boe. Natural gas transportation, on an absolute and per-barrel basis, in the quarter remained flat to the previous quarter but natural gas liquids and oil transportation came in higher on both an absolute and per-barrel basis due to one-time prior period adjustments. Unutilized firm natural gas transportation expenses on the NGTL system of $1-million were included in the first quarter transportation costs.
Q1 2019 general and administrative and interest expenses
First quarter general and administrative expenses were $5.1-million, or 84 cents per boe, 6 per cent lower than the fourth quarter of $5.4-million. The adoption of IFRS (international financial reporting standards) 16 (Leases) resulted in a decrease of $1-million due to the accounting treatment of the company's head office lease, which was offset by higher compensation costs typically associated in the beginning of the year, in addition to higher transaction cost due to the sale and potential sale of assets.
Interest expense for the quarter was $8.5-million, down slightly from the fourth quarter of 2018 at $8.6-million and in line with the company's budget.
Q1 2019 cash flow from operating activities and adjusted funds flow
Cash flow from operating activities was 30 per cent lower in the first quarter relative to the previous quarter at $54.5-million from $77.6-million primarily associated with a $18.8-million change in working capital quarter over quarter. Adjusted funds flow of $58.2-million for the quarter was 5 per cent lower than the $61.1-million recorded in the fourth quarter of 2018 due to higher royalty expenses and modestly higher cash costs.
Q1 2019 long-term debt
A $20.5-million reduction in long-term debt to $781.2-million over the fourth quarter can be attributed to debt repayment of $4.2-million and the strengthening Canadian dollar experienced in the first quarter of 2019 as compared with year-end 2018.
The short-term balance between the global supply and demand for energy remains far from certain as evidenced by the extreme volatility in the local and global price for oil and natural gas. In the past six months alone, Brent crude prices have fluctuated between $51 per bbl and $86 per bbl and WTI prices have swung between $43 per bbl and $76 per bbl, while the global spot price for LNG has oscillated between $5 per million British thermal unit (mmbtu) and $11 per mmbtu. The volatility in Western Canadian prices have been amplified even further with insufficient export capacity for both oil and natural gas. At times over the past six months, Western Canadian natural gas prices have traded at 70-per-cent discount to NYMEX, while Western Canadian Select oil price has been discounted as much as 88 per cent relative to WTI.
Notwithstanding this short-term uncertainty, long-term global demand for energy, is set to rise by nearly 30 per cent by 2040, according to IEA World Energy Outlook 2018. A growing population augmented by the urbanization and industrialization of emerging economies will lift the standard of living across the world, most notably in countries like China and India.
This same IEA outlook forecasts that global natural gas demand is set to rise by 43 per cent by 2040, overtaking coal as the world's second-largest energy source by 2030. More than half of this demand growth is forecasted in developing economies like China and Southeast Asia where bold air quality policies have recently been enacted. Across the globe, household and ambient air pollution is said to contribute to more than seven million premature deaths per year, 60 per cent of which occur in China, India and Southeast Asia where nearly two-thirds of the population rely on solid fuels such as dung, wood or charcoal as their primary fuel for cooking and heating.
China's commitment to replacing coal consumption with natural gas was resoundingly clear in 2017 with a 30-per-cent annual increase in LNG imports. Estimates show that by 2040, about 1,500 megatonnes of carbon dioxide equivalent emissions could be eliminated every year if new power plants in China, India and Southeast Asia are fueled by natural gas from LNG instead of coal. Global annual LNG trade in 2017 rose a staggering 14 per cent and solidifies the predictions that the Asia Pacific region will account for approximately 80 per cent of global LNG imports by 2040.
North America, with its proximity to South Asia, will undoubtedly play a role in this LNG demand forecast and Canada, with the fourth-largest natural gas reserves in the world, has an opportunity to participate. With LNG facilities on Canada's west coast being closer than any other North American LNG source, there is a window of opportunity emerging. This global opportunity is real and this demand will undeniably get met with production from another jurisdiction if Canada cannot find a way to create a stable and competitive fiscal environment with regulatory efficiency and excellence.
Today, Canadian natural gas growth is limited by pipeline infrastructure bottlenecks and a lack of LNG export infrastructure. This lack of egress from the world-class sedimentary basin has resulted in severe discounts to world prices. After 10 years and 20 LNG export proposals on the west coast, the company is grateful to have its first project, LNG Canada, to reach final investment decision (FID) with anticipation of an expansion project not far behind. Similarly, the company has line of sight to resolve the pipeline bottlenecks that currently prohibit Western Canada from consuming and exporting an incremental 3.1 billion cubic feet (bcf) per day with a final in-service date of 2021. Notwithstanding a broken regulatory system prohibiting projects like these to be completed, free from delay and incremental cost pressures, Western Canada will soon have the opportunity to better serve countries in need of the company's abundant natural gas resources, developed under leading social and environmental standards.
Estimates show that annually, for every one bcf per day of incremental production to serve LNG export in Canada, 10,000 direct and indirect jobs are created, $340-million in revenues are created for provincial and federal governments, and $2.4-billion of direct and indirect economic activity is created. LNG created in Canada presents both economic prosperity and global emission reduction provided the most robust and thoughtful energy policies are pursued by its federal and provincial governments. With a deliberate goal to become the most responsible and efficient provider of energy, Canada can be the natural gas provider of choice for many countries in need.
At Bonavista, the company remains committed to strengthening its foundation while the short-term egress challenges are forcing many producers in Western Canada to sell their molecules at some of the lowest natural gas prices in the world.
In 2019, the company will focus on enhancing revenue and reducing costs to maximize free cash flow. As demonstrated in 2018 and year to date in 2019, it will remain opportunistic as it strategically enhances its asset quality through acquisition and divestiture activity, land acquisition, and infrastructure development. Many of these opportunities may not result in immediate financial accretion but will undoubtedly result in long-term value creation.
As a result of the near-term outlook for commodity prices, the board of directors suspended Bonavista's quarterly dividend. The company estimates that this action will reduce annual cash outlays for 2019 by approximately $8-million. It will continue to review the dividend program on a quarterly basis; however, this suspension is a necessary step to support its financial flexibility in the current commodity price environment.
Two thousand nineteen guidance remains consistent with its message in February. The company expects to spend between $130-million and $170-million with plans to drill between 24 and 32 wells. This should result in production levels averaging between 65,000 and 69,000 boe per day, a function of the uncertainty surrounding the impact of NGTL maintenance activities and mid-stream turnaround activities this summer. The company expects to exit 2019 near 67,000 boe per day, a similar production levels as to where it entered the year.
Balance sheet flexibility will remain its No. 1 priority as it expects natural gas prices to remain volatile and unpredictable while export capacity for all products out of Western Canada remain constrained. It will continue to rely on the predictable and reliable performance of its asset base to exercise financial prudence as it builds a solid foundation for growth in value in the future.
The company thanks its employees for their commitment and dedication, its board of directors for its guidance, and its shareholders for their long-term support.
We seek Safe Harbor.
© 2020 Canjex Publishing Ltd. All rights reserved.