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Bonavista Energy Corporation Announces 2019 Third Quarter Results


Calgary, Alberta–(Newsfile Corp. – November 5, 2019) – Bonavista Energy Corporation (TSX: BNP) (“Bonavista”) is pleased to report to shareholders its financial and operating results for the three and nine months ended September 30, 2019. In the third quarter of 2019, we generated adjusted funds flow of $34.6 million and successfully drilled our first Duvernay horizontal well. The financial statements and notes, as well as management’s discussion and analysis, are available on the System for Electronic Document Analysis and Retrieval (“SEDAR”) at http://www.sedar.com and on Bonavista’s website at www.bonavistaenergy.com.

MESSAGE TO SHAREHOLDERS

Our third quarter results continue to demonstrate our commitment to building a sustainable path forward with our priorities clearly focused on improving financial flexibility and strengthening our asset base. For the quarter, we generated adjusted funds flow of $34.6 million and our net capital expenditures and decommissioning expenditures totaled $30.2 million allowing us to allocate the remaining 13% of adjusted funds flow to net debt reduction. Continued focus on the most prolific and profitable opportunities in our portfolio resulted in a modest increase in total production, with oil and natural gas liquids production up 11% over the second quarter of 2019 which represents 31% of total production volumes. The composition of our production volumes has returned to levels seen prior to the significant turnaround activities experienced in the second quarter, whereby the ratio of oil and natural gas liquids slipped to 28% of total production volumes. Twenty-seven percent, of our exploration and development (“E&D”) spending in the third quarter was allocated to investments in land and infrastructure reinforcing our commitment to building a foundation for a sustainable future.

Notwithstanding natural gas price instability throughout the quarter resulting from limited NGTL access to storage and export beyond western Canada, adjusted funds flow outperformed our expectations by approximately 10%. Fortunately, we were well hedged with 67% of natural gas and 71% of our oil and natural gas liquids revenue secured by a fixed price for the quarter.

Net capital expenditures in the quarter were $27.3 million, considerably lower than initially forecast, due to the disposition of a non-core asset in mid-September. Our E&D program was executed on strategy, with the highlight being the successful drilling of our first Duvernay horizontal well, cased with 3,260 meters of horizontal lateral and scheduled to be completed in the first half of 2020.

OPERATIONAL AND FINANCIAL ACCOMPLISHMENTS FOR THE THIRD QUARTER OF 2019

  • Achieved adjusted funds flow of $34.6 million ($0.13 per share), approximately 10% ahead of plan resulting from a modest improvement in commodity pricing and a reduction in royalty and operating expenses.
  • Produced 62,437 boe per day (69% weighted to natural gas), up two percent over the previous quarter and in line with our forecast. Natural gas liquids production increased 12% over the prior period to 17,310 boe per day, re-establishing premium natural gas liquid recovery efficiencies following significant turnaround activity experienced in the second quarter.
  • Executed a successful E&D program, spending $43.3 million to drill six (5.5 net) and complete eight (7.8 net) wells, including drilling our first Duvernay horizontal well. Of our third quarter E&D program, 27% of spending was directed to support capital that contributed to the expansion of our operated infrastructure in our West Central core area and our Duvernay land position.
  • Cash costs improved over the previous quarter by four percent on a per boe basis, with a five percent decrease in operating expenses being the largest contributor to this reduction.
  • Realized natural gas price of $2.02 per mcf, a 106% premium to the average AECO benchmark of $0.93 per GJ for the quarter the result of a prudent hedge and diversification program. We have approximately 15% of our natural gas production exposed to AECO spot prices for the fourth quarter with only 22% of our oil and natural gas liquids subject to daily commodity price volatility.
Three Months Ended
June 30,
2019
September 30,
2019
September 30,
2018
% Change
Financial
($ thousands, except per share)
Production revenues 81,485 69,542 131,175 (47)%
Net income (loss) 1,828 (307,489) (17,811) (1,626)%
   Per share(1) 0.01 (1.16) (0.07) (1,557)%
Cash flow from operating activities 56,186 37,113 73,720 (50)%
   Per share(1) 0.21 0.14 0.28 (50)%
Adjusted funds flow(2) 40,524 34,565 63,688 (46)%
   Per share(1) 0.15 0.13 0.25 (48)%
Dividends declared 2,554 (100)%
   Per share 0.01 (100)%
Total assets 2,896,501 2,547,412 2,845,288 (10)%
Shareholders’ equity 1,518,210 1,212,177 1,471,682 (18)%
Long-term debt 763,376 766,569 760,231 1%
Net debt(2) 795,987 801,921 795,023 1%
Net capital expenditures(2) 35,549 27,332 36,553 (25)%
   Exploration and development 35,277 43,284 42,317 2%
   Dispositions, net of acquisitions(3) (37) (16,299) (5,821) 180%
   Corporate 309 347 57 509%
Weighted average outstanding equivalent shares: (thousands)(1)
   Basic 261,923 264,991 259,897 2%
   Diluted 275,628 275,435 266,913 3%
Operating
(boe conversion – 6:1 basis)
Production:
   Natural gas (mmcf/day) 264 260 287 (9)%
   Natural gas liquids (bbls/day) 15,387 17,310 17,868 (3)%
   Oil (bbls/day)(4) 1,830 1,813 2,358 (23)%
   Total oil equivalent (boe/day) 61,186 62,437 68,036 (8)%
Product prices:(5)
   Natural gas ($/mcf) 2.24 2.02 2.76 (27)%
   Natural gas liquids ($/bbl) 23.22 19.98 28.90 (31)%
   Oil ($/bbl)(4) 61.93 63.24 58.84 7%
      Total oil equivalent ($/boe) 17.36 15.78 21.27 (26)%
Operating expenses ($/boe) 5.86 5.59 5.74 (3)%
Transportation expenses ($/boe) 1.43 1.38 1.42 (3)%
General and administrative expenses ($/boe) 0.96 0.90 0.92 (2)%
Cash costs ($/boe)(2) 9.78 9.42 9.46 -%
Operating netback ($/boe)(2) 9.82 8.49 12.48 (32)%

NOTES:

(1) Basic per share calculations include exchangeable shares which are convertible into common shares on certain terms and conditions.
(2) Non-GAAP measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other entities. Reference should be made to the section entitled “Non-GAAP Measures”.
(3) Proceeds on property dispositions, net of expenditures on property acquisitions.
(4) Oil includes light, medium and heavy oil.
(5) Product prices include realized gains and losses on financial instrument commodity contracts.

Share Trading Statistics Three months ended
September 30,
2019
June 30,
2019
March 31,
2019
December 31,
2018
($ per share, except volume)
High 0.86 1.20 1.39 1.60
Low 0.41 0.46 1.06 1.01
Close 0.61 0.49 1.11 1.20
Average Daily Volume – Shares 462,855 589,117 531,298 817,647

OPERATIONAL UPDATE

All of our activity for the quarter was in our West Central core area, where we drilled six wells, including our first Duvernay horizontal well. The remaining five liquids rich wells were comprised of three Strachan Glauconite wells and two wells on our Willesden Green Glauconite trend. The two Willesden Green wells were completed at the end of the quarter and came on production mid-October at restricted rates.

The main focus during the quarter was in Strachan where we completed four wells with two of the wells producing above-average free condensate rates of 40 to 60 bbl per mmcf during their first 30 days of production. The other two wells are producing at expected rates. To handle the new well production in the quarter, additional compression was installed that expanded our Strachan capacity by 23 mmcf per day to 60 mmcf per day. The final two wells at Strachan were completed in October and will be on production in November.

Our first Duvernay horizontal well was drilled over a 22-day period with a lateral length of 3,260 meters. This also included a pilot vertical well to log and sample the Duvernay formation. To allow time to analyze the vertical well information and leverage warmer weather to reduce completion costs specific to heating frac water, the plan is to complete this well in the second quarter of 2020.

FINANCIAL UPDATE

Production

Production volumes for the quarter averaged 62,437 boe per day, comprised of 260 mmcf per day of natural gas, 17,310 bbls per day of natural gas liquids and 1,813 bbls per day of oil. This production rate represents a two percent increase over the prior quarter following significant scheduled and unscheduled turnaround activity and was in spite of a loss in production due to the disposition of a non-core asset in mid-September. Notably the composition of production was restored to those levels seen prior to the turnaround activity experienced in the second quarter with oil and natural gas liquids representing 31% of overall production volumes.

Production Revenue, Marketing and Risk Management

Production revenues for the third quarter, including $21.1 million of realized gains on financial instrument commodity contracts, were $90.6 million, or $15.78 per boe, representing a nine percent decrease on a per boe basis from the prior quarter. Production revenues, excluding realized gains on financial instrument commodity contracts, were $69.5 million or $12.11 per boe. Commodity price instability continued to be a trend experienced through the third quarter resulting largely from limited egress off the NGTL system. Realized pricing for natural gas was $2.02 per mcf, a 10% reduction from the previous quarter but ahead of the average AECO daily spot price for the quarter of $0.86 per GJ and a 94% premium to the average AECO monthly index price of $0.99 per GJ. Financial hedging accounted for a pricing premium of $0.70 per mcf, $2.66 per bbl and $0.21 per bbl for natural gas, natural gas liquids and oil respectively.

Operating and Transportation Expenses

Operating expenses for the quarter were lower than the prior quarter and plan at $32.1 million, or $5.59 per boe. The decrease in operating expenses on an absolute and per boe basis was largely due to operating cost efficiencies and cost control within Bonavista’s core areas, resulting in a lower labour, service and utility costs.

Transportation expenses in the second quarter of 2019 were impacted by scheduled and unscheduled third party turnaround activity in addition to incremental trucking costs due to road bans and higher wait times as a result of unseasonably wet spring weather conditions and infrastructure constraints. With turnaround activity having less of an impact on third quarter production and weather conditions returning to normal, we realized a three percent reduction in transportation expenses to $1.38 per boe compared to $1.43 per boe in the prior quarter with absolute transportation expenses relatively unchanged at $7.9 million and $8.0 million respectively.

General and Administrative and Interest Expenses

Third quarter general and administrative expenses were $5.2 million or $0.90 per boe, three percent lower on an absolute basis than compared to the second quarter of $5.4 million. An increase in overhead recoveries contributed to the decrease in general and administrative expenses as E&D expenditures were 23% higher than in the previous quarter.

Interest expenses in the third quarter was $8.9 million or $1.55 per boe which was in line with our budget but represented a four percent increase on an absolute basis from the prior quarter. The increase was primarily a result of a weaker CDN dollar to US dollar exchange rate used to recognize interest expense which is paid on a semi-annual basis.

Net Loss and Comprehensive Loss

For the three months ended September 30, 2019, we reported net loss and comprehensive loss of $307.5 million ($1.16 per share, basic) compared to net income and comprehensive income of $1.8 million ($0.01 per share) reported in the prior quarter. The change from a net income position to a net loss position can be largely attributed to a $278.0 million impairment charge recognized as a result of a sustained decline in the forward commodity benchmark prices for natural gas and natural gas liquids. The benchmark prices referenced in our impairment test were based on the average price forecasts as prepared by four independent reserve evaluators effective on October 1, 2019. The results are sensitive to changes in any of the key estimates of which changes could decrease or increase the recoverable amounts of assets and result in impairment charges or in the recovery of previously recorded impairment charges.

Cash Flow from Operating Activities and Adjusted Funds Flow

Cash flow from operating activities was 34% lower in the third quarter relative to the previous quarter at $37.1 million from $56.2 million. Adjusted funds flow of $34.6 million for the quarter, was 15% lower than the $40.5 million generated in the second quarter of 2019 due to a six percent decline in production revenues, including realized gains on financial instrument commodity contracts.

Long-term Debt

Long-term debt was relatively unchanged at $766.6 million in the third quarter compared to $763.4 million in the second quarter. The slight increase was the result of the revaluation of US denominated debt as the Canadian dollar weakened in the third quarter of 2019 as compared to the second quarter. During the third quarter Bonavista directed $4.4 million towards a reduction of net debt.

OUTLOOK

We remain fully subscribed to a continued rise in global demand for energy, with a profound 25-30% increase in the coming two decades. World population is growing at an astonishing 80 million people per year; that is like adding another Canada to the global population every six months! More astonishing is the rapid expansion of the middle class around the world growing to more than 50% of the world’s population as of late. The middle class is the most rapidly growing segment of the global income distribution, growing at a pace of five people per second. This class of society will undoubtedly drive this growth in demand for energy in the global economy.

The rise in demand for energy is fueled by many aspects but worth noting, there have been clear and growing pressures on the power sector. With the rise of digital technologies, current data consumption accounts for two percent of electricity worldwide and could rise to eight percent of the global total by 2030, equivalent to the current share of light duty vehicles in global emissions. Online video represents the largest share of the global data traffic and generated over 300 million tons of CO2e in 2018, an amount that is roughly 40% of what all of Canada generated that same year.

In 2018, power generation around the world was sourced by fossil fuels (64%), hydro (19%), nuclear (10%), and renewable (7%). Technology has created an opportunity for renewable power generation to multiply numerous times over, however, reliability and adequate infrastructure will act as barriers for renewable supply to keep pace with demand growth in the coming decades.

The most populous region in the world, the Asia Pacific region, where nearly 90% of the next billion entrants to the middle class will take place, is dealing with a pollution crisis. Nearly 50% of their energy demands today are met with the burning of coal, most often used to generate electricity, and other forms of solid fuel for heating and cooking. Unfortunately, significant quantities of particulate matter, one of four leading causes of premature death around the world, are emitted with these fuel sources.

Natural gas can and will be transformative to regions like this, significantly improving health, the quality of life and the global environment. It can serve to decarbonizing the global power sector while meeting the rapidly expanding demand for power. This is perhaps the single most important climate challenge facing our society over the next 20 years.

Demand for natural gas in these fast-growing Asian economies serves as a catalyst to double the size of the international LNG market over the next 20 years, leading to 40 to 50% growth in demand for natural gas globally. Canada has an abundance of natural gas resources and Canadian LNG can have an enormous impact on the global challenge in front of us. Each LNG facility that exports natural gas off the west coast of Canada could eliminate up to 100 mtCO2e of emissions from coal-fired power generation in China.

It was one year ago that LNG Canada announced their intention to move forward with an LNG terminal in Kitimat, BC. Canadian LNG is designed to be among the lowest global carbon footprint, by relying on energy-efficient natural gas turbines and renewable-sourced electricity for liquefaction. LNG produced in Western Canada will have a greenhouse gas footprint that is five to eight times lower in intensity than the existing best-in-class facilities elsewhere in the world. To date, LNG Canada has awarded over $1 billion in contracts and procurement opportunities and construction activities are well underway, expecting to employ up to 7,500 people at its peak. The project remains on track to export approximately 1.7 bcf per day by 2025, however if we as Canadians are going to make a difference in this climate challenge, it cannot stop with just one Canadian LNG project.

Canada and our national leaders can make an oversized contribution to the global climate file at the upcoming United Nations Climate Change Convention of the Parties (“COP”) in December. Providing clean Canadian LNG to displace coal for power generation in the Asia Pacific region will eliminate incremental global GHG emissions and should earn offset credits as per Article 6 of the Paris agreement. We have an economic and environmental opportunity to be a world leader, one that we have never seen in the past century. The world needs more Canadian energy.

Notwithstanding the recent strength in short-term western Canadian natural gas pricing, we intend to remain disciplined and focused on our priorities as the supply and demand fundamentals in western Canada improve over the long-term. As we entered the second half of 2019, we moderated our spending plans to preserve our drilling inventory and reduce our planned drilling activity in the final quarter of 2019 due to continued uncertainty of short-term natural gas and NGL price forecasts. Hence, we expect to spend between $110 and $120 million with annual production to average between 62,000 and 63,000 boe per day and will generate adjusted funds flow of between approximately $165 to $175 million. Throughout 2019, we have focused on creating incremental financial flexibility by allocating adjusted funds flow in excess of capital and decommissioning expenditures to our balance sheet. As a result, we expect to pay down approximately $40 million of net debt in 2019.

We intend to remain disciplined with our 2020 capital program, much like we have in 2019, but will release further guidance for 2020 with our year end results in mid-February, once we have further clarity on 2020 commodity prices.

We are pleased to announce the appointment of Mr. George S. Armoyan to the Board of Directors, effective today. Mr. Armoyan has been an ardent supporter of Bonavista for many years and recently added to his share position to accumulate over 16% of our outstanding common shares. Mr. Armoyan is President of Geosam Capital Inc., President of Armco Capital Inc., and Executive Chairman of Clarke Inc. As an entrepreneur with extensive experience in various industries, Mr. Armoyan has successfully founded and grown numerous businesses and applied his common-sense approach to create shareholder value at multiple public companies.

We are grateful for the continued support of our shareholders and we thank our employees for consistently finding better ways to advance our business. As we continue to focus on financial flexibility through the remainder of the year and into next, we look forward to continuing to generate long-term value for all stakeholders.



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