August 1, 2019 - 5:08 PM EDT
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Bonavista Energy Corporation Announces 2019 Second Quarter Results

Canada NewsWire


CALGARY, Aug. 1, 2019 /CNW/ - Bonavista Energy Corporation ("Bonavista") is pleased to report to shareholders its financial and operating results for the three and six months ended June 30, 2019. In the second quarter of 2019, we generated adjusted funds flow of $40.5 million, allocating $35.3 million to our exploration and development program. 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 and on Bonavista's website at


Inadequate pipeline capacity and regulatory uncertainty in the Canadian energy sector continues to overshadow the operational success we have experienced as a sector, in the first six months of the year.

Our second quarter reported adjusted funds flow of $40.5 million was ahead of plan while production for the quarter averaged 61,186 boe per day with facility turnaround activity meaningfully curtailing production throughout the quarter.

Capital expenditures, net of acquisition and divestiture activity in the quarter were 15% below budget resulting from above average rainfall restricting access to numerous development projects. Notwithstanding these challenges, we remained focused on our liquids-rich development opportunities in the West Central region, drilling six wells and completing four. The majority of our second quarter activity was brought onstream late June and July.

Notwithstanding abrupt and unpredictable movements in AECO daily natural gas prices throughout the quarter, we mitigated price volatility with 68% of our natural gas production hedged and 29% diversified to alternative markets. Unfortunately though, our natural gas liquids ("NGLs") revenues have eroded by 30% in the quarter relative to the first quarter resulting from turnaround-induced recovery inefficiency and heavily discounted NGL purchase contracts coming into effect April 1. We remain well hedged and diversified for the balance of the year with less than 24% of H2 2019 natural gas production exposed to spot AECO pricing volatility.


  • Generated adjusted funds flow of $40.5 million ($0.15 per share), equivalent to $7.28 per boe, modestly ahead of expectations but burdened by discounted NGL pricing.

  • Produced 61,186 boe per day with approximately 2,000 boe per day, curtailed due to turnaround activity and approximately 2,000 boe per day curtailed due to delays in development caused by excessive rainfall and shut-ins due to uneconomic natural gas prices. Current production is approximately 64,000 boe per day.

  • Executed a successful exploration and development ("E&D") program, spending $35.3 million to drill six (5.9 net) and complete four (4.0 net) wells.

  • Directed 21% of our exploration and development program, or $7.3 million to infrastructure projects designed to redirect current and future production to lower cost, more efficient processing facilities.

  • Realized natural gas sales price of $2.24 per mcf, a 91% premium to the average AECO monthly index price.

  • Protected 2019 adjusted funds flow by limiting exposure to AECO through remainder of the year, with 76% of our natural gas production hedged at an average price of $1.94 per mcf.

Three Months Ended

March 31, 2019

June 30, 2019

June 30, 2018

% Change


($ thousands, except per share)

Production revenues






Net income (loss)






   Per share(1)






Cash flow from operating activities






   Per share(1)






Adjusted funds flow(2)






   Per share(1)






Dividends declared





   Per share





Total assets





Shareholders' equity






Long-term debt






Net debt(2)






Capital expenditures:

   Exploration and development






   Acquisitions, net of dispositions(3)












Weighted average outstanding equivalent shares: (thousands)(1)














(boe conversion – 6:1 basis)


   Natural gas (mmcf/day)






   Natural gas liquids (bbls/day)






   Oil (bbls/day)(4)






   Total oil equivalent (boe/day)






Product prices:(5)

   Natural gas ($/mcf)






   Natural gas liquids ($/bbl)






   Oil ($/bbl)(4)






      Total oil equivalent ($/boe)






Operating expenses ($/boe)






Transportation expenses ($/boe)






General and administrative expenses ($/boe)





Cash costs ($/boe)(2)






Operating netback ($/boe)(2)








Basic per share calculations include exchangeable shares which are convertible into common shares on certain terms and conditions. 


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".


Expenditures on property acquisitions, net of property dispositions.


Oil includes light, medium and heavy oil.


Product prices include realized gains and losses on financial instrument commodity contracts.


Share Trading Statistics

Three months ended

June 30, 2019

March 31, 2019

December 31, 2018

September 30, 2018

($ per share, except volume)
















Average Daily Volume - Shares







Q2 2019 Operational Update

Operations in the second quarter were concentrated in our West Central core area where we drilled four wells in the Strachan area and two wells in the Hoadley Glauconite trend. We completed four wells near the end of the second quarter with these wells coming on-stream late June and July.

Of the $35.3 million E&D expenditures, 66% or $23.3 million was allocated to value capital and 34% or $12 million was allocated to support capital. Of the support capital $7.3 million was allocated to facility projects which included the installation of nine miles of 6-inch pipe to connect our recently acquired assets and undeveloped acreage in Willesden Green to our operated infrastructure. We also commenced work on the expansion of a compression facility at Strachan that will increase capacity from 35 mmcf per day to 60 mmcf per day. This project is scheduled to be completed in the third quarter.

Lastly, we acquired approximately 10,000 acres of Duvernay in the second quarter and solidified our plans to drill our first Duvernay well in the third quarter. We remain encouraged with the recent results in and around our planned drilling location.

Q2 2019 Production

Production volumes for the quarter averaged 61,186 boe per day, comprised of 264 mmcf per day of natural gas, 15,387 bbls per day of natural gas liquids and 1,830 bbls per day of oil. This production rate represents a nine percent decrease over the prior quarter resulting from production curtailments related to facility turnarounds, excessive rainfall, less efficient NGL recovery and uneconomic natural gas prices.

Q2 2019 Production Revenue, Marketing and Risk Management

Production revenues for the second quarter, inclusive of $15.2 million of realized gains on financial instrument commodity contracts, was $96.7 million, or $17.36 per boe, a 15% decrease from the prior quarter. Production revenues, excluding realized gains on financial instrument commodity contracts, was $81.5 million or $14.64 per boe. Realized pricing for natural gas was $2.24 per mcf, a 14% reduction from the previous quarter but ahead of the average AECO daily spot price for the quarter of $0.98 per GJ and a 91% premium to the average AECO monthly index price of $1.11 per GJ. Financial hedging accounted for a premium of $0.64 per mcf and $0.58 per bbl for natural gas and natural gas liquids respectively, and a discount of $6.51 per bbl on realized oil pricing.

Q2 2019 Operating and Transportation Expenses

Operating expenses in the quarter were seven percent lower at $32.6 million compared to $35.2 million in the previous quarter, however on a per boe basis operating expenses of $5.86 were similar to the first quarter and in line with our forecast. Typically, we would see lower per boe operating expenses in the second quarter as compared to the first quarter but this current quarter we experienced significant planned and unplanned third party turnaround activity that impacted these results.

Transportation expenses were eight percent lower in the quarter at $8.0 million compared to $8.7 million in the previous quarter due mostly to the nine percent decrease in production volumes due largely to turnaround activity mentioned above. Transportation expenses were $1.43 per boe as compared to $1.44 per boe in the prior quarter, in addition natural gas, natural gas liquids and oil all had very similar per unit expenses as compared to the previous quarter.

Q2 2019 General and Administrative and Interest Expenses

Second quarter general and administrative expenses were $5.4 million or $0.96 per boe, five percent higher on an absolute basis than compared to the first quarter of $5.1 million. A significant reduction of overhead recoveries contributed to the increase in general and administrative expenses as exploration and development expenditures were 28% lower than in the previous quarter.

Interest expenses in the second quarter was $8.5 million in line with our budget and similar to the first quarter of 2019.

Q2 2019 Cash Flow from Operating Activities and Adjusted Funds Flow

Cash flow from operating activities was three percent higher in the second quarter relative to the previous quarter at $56.2 million from $54.5 million. Adjusted funds flow of $40.5 million for the quarter, was 30% lower than the $58.2 million generated in the first quarter of 2019 due to a 15% decline in production revenues per boe and a nine percent decrease in production volumes.

Q2 2019 Long-term Debt

Long-term debt was $763.4 million in the second quarter a reduction of $17.8 million over the first quarter results. This reduction resulted from debt repayment of $3.6 million and the revaluation of our US denominated debt as the Canadian dollar strengthened in the second quarter of 2019 as compared to the first quarter.


Signs of perpetual growth in natural gas demand are being observed around the globe. Chinese demand for natural gas is expected to grow by double digits in the coming years resulting from the government's strong initiatives to improve air quality. India is the second fastest growing gas market globally with over $30 billion allocated for pipelines, city infrastructure, fueling infrastructure and doubling its import LNG facilities. Canada's leadership in environmental stewardship and the short shipping distances to these markets perfectly position us to support these countries in their transition to a low carbon energy system.

As Canadians we are grateful that Shell has chosen to proceed with LNG Canada, the largest private sector infrastructure project in Canadian history, in support of reducing global emissions by making our natural resources available to the rest of the world. As well, the proposed Canadian Kitimat LNG facility recently announced expansion plans to nearly double export capacity, double the term of their export license and stake claim to the lowest emission LNG plant in the world. This speaks volumes to the quality of Canadian natural resources and represents a significant opportunity for Canada to build relationships with developing countries in need of our abundant natural gas resources.

Finally, with increased export commitments to Mexico and other LNG markets, US domestic supply could become challenged to meet growing domestic demand, largely due to continued growth in natural gas fired power generation. This will create the opportunity for Canadian natural gas supply to support this growing North American demand as incremental export infrastructure in western Canada is constructed over the coming two years.

Notwithstanding robust global demand fundamentals for natural gas, Canadian natural gas pricing remains heavily discounted in the short term, resulting from inadequate infrastructure and egress to these markets in need. With incremental egress and export solutions on their way we remain practical and value-oriented with the management of our excess adjusted funds flow and our future development inventory. We believe preserving our drilling inventory via a moderate and thoughtful development program to be the most prudent option available given the volatile and unpredictable short-term pricing we are currently experiencing. For the remainder of the year we intend to deliver on our previously announced guidance. However, if natural gas prices do not improve from current levels we will remain prudent and target capital spending and production at the low end of this range. We will remain persistent on creating incremental financial flexibility by allocating excess adjusted funds flow to our balance sheet.

As demonstrated over the past few years, we are committed to the philosophy of strengthening our foundation for the future as we invest in land and our infrastructure, enhance our asset quality and reduce cost. We have continuously engaged in strategic acquisition and divestiture activities to support this philosophy as we fully expect these transactions to create long-term value for our shareholders.

With regards to our financial flexibility, at the beginning of May, we engaged in formal covenant relief negotiations with our lenders. Although significant progress has been made to date, no agreements have been reached with the lenders as of the date of this report. We do, however, expect that this negotiation process will be successful and suitable terms for covenant relief reached.

We are a proud Canadian company with a 22 year history of providing energy to Canadians on their journey to continuously improve their way of life. Since our inception in 1997, our operations have supported our economy spanning from job creation across our nation to local and provincial community investment. We have invested over $5.3 billion in drilling and producing over 3,000 wells in Canada, we have paid over $2.2 billion in royalties and over $200 million in property taxes to government bodies. We believe we can have a healthy, vibrant economy in Canada that includes the economic benefits from resource development for all citizens while reducing global greenhouse gas emissions. We believe that regulation certainty and a patriotic commitment to infrastructure will accomplish this in positioning Canada to responsibly energize the globe for years to come.

We would like to once again thank Mr. Michael Kanovsky for serving for over 21 years on our Board of Directors having retired at our annual general meeting in May 2019 .  As one of our founders and lead director, Michael's vision was instrumental in the early-stage growth, the evolution and ultimately the responsible and sustainable energy provider we are today. We are grateful for his service and dedication to Bonavista and we wish him all the best with the next chapter of his life.

We would also like to welcome Ms. Mary Hemmingsen to our Board of Directors. Ms. Hemmingsen brings more than 25 years of energy and infrastructure experience across many aspects of both the North American and global energy sector. Ms. Hemmingsen currently serves on a number of publicly listed and private company boards in the energy, energy services and infrastructure sector including, Stuart Olson, InstarAGF Asset Management and is Executive Chair of Trace Water Solutions. Ms. Hemmingsen's previous executive roles included Executive Vice President and Chief Financial Officer of North West Innovation Works, a clean-tech natural gas to methanol development platform, KPMG Partner and Industry Lead of Power and Utilities for Canada as well as Global Head of Gas and LNG, and Senior Vice President of Business Development for Brookfield Power and Utilities. Ms. Hemmingsen is a Chartered Professional Accountant of British Columbia who holds a Bachelor of Business Administration Degree from Simon Fraser University and has completed the Harvard Business School Executive Management Program.

Mr. David Carey has succeeded Mr. Kanovsky in the position of lead director on our Board. Mr. Carey joined Bonavista in November 2017 bringing with him more than 35 years of diverse Canadian and international energy experience. A full listing of the composition of our Board committees can be found on our website at

We are ever grateful for the continued support of our stakeholders and we thank our employees for their consistent efforts in finding better ways to drive our business forward.


Throughout this document we have made reference to terms that are commonly used in the oil and natural gas industry, but do not have any standardized meaning as prescribed by IFRS and therefore may not be comparable with the calculations of similar measures for other entities. Management believes that the presentation of these non-GAAP measures provide useful information to investors and shareholders as the measures provide increased transparency and the ability to better analyze performance against prior periods on a comparable basis. The non-GAAP measures included in this document include:

  • "Adjusted funds flow" is based on cash flow from operating activities, excluding changes in non-cash working capital, decommissioning expenditures and including interest expense. Where working capital is equal to current assets less current liabilities.

    Certain non-cash charges and decommissioning expenditures have been excluded from the calculation of adjusted funds flow, as management believes the timing of collection, payment and incurrence is variable and by excluding them from the calculation management is able to provide a more meaningful measure of Bonavista's cash flow on a continuing basis. More specifically, expenditures on decommissioning liabilities may vary from period to period depending on Bonavista's capital programs and the maturity of its operating areas. The settlement of decommissioning obligations is managed through Bonavista's capital budgeting process which considers its available adjusted funds flow.

    Bonavista considers adjusted funds flow to be a key measure that provides a more complete understanding of Bonavista's ability to generate cash flow necessary to finance capital expenditures, expenditures on decommissioning obligations and meet its financial obligations. Bonavista considers its capital structure to include working capital (excluding associated assets and liabilities from financial instrument commodity contracts, lease liabilities and decommissioning liabilities), bank credit facility, senior unsecured notes and shareholders' equity. Bonavista monitors capital based on the ratio of net debt to adjusted funds flow (annualized current quarter).

  • "Operating netback" is equal to production revenues and realized gains and losses on financial instrument commodity contracts, less royalties, operating and transportation expenses. Operating netback per boe is calculated by dividing operating netback by total production volumes sold in the period.

    Bonavista's management believes that operating netback is a key industry benchmark and a measure of operating performance that assists management and investors in assessing Bonavista's profitability. Operating netback on a per boe basis assists Bonavista's management and investors in evaluating operating performance on a comparable basis.

  • "Cash costs" are equal to the total of operating, transportation, general and administrative, and interest expenses. Cash costs per boe are calculated by dividing cash costs by total production volumes sold in the period.

    Bonavista's management uses cash costs in assessing the Corporation's operating efficiency and controllable cost structure. Bonavista's management believes that cash costs is a useful measure used by investors when evaluating Bonavista's operating performance. Cash costs on a per boe basis also assists Bonavista's management and investors in evaluating Bonavista's cash costs on a comparable basis with prior periods.

  • "Net debt" is equal to Bonavista's bank credit facility and senior unsecured notes, net of working capital (excluding associated assets and liabilities from financial instrument commodity contracts, lease liabilities and decommissioning liabilities).

    Bonavista considers net debt to be a key measure in assessing the liquidity of the Corporation on a comparable basis with prior periods. Bonavista has calculated net debt based on the bank credit facility and senior unsecured notes, net of working capital. Working capital has been adjusted to exclude the current portion of financial instrument commodity contracts, lease liabilities and decommissioning liabilities. Management has excluded the current portion of financial instrument commodity contracts as they are subject to a high degree of volatility prior to ultimate settlement. Similarly, management has excluded the current portion of the decommissioning liability as this is an estimate based on management's assumptions and subject to volatility based on changes in cost and timing estimates, the risk-free discount rate and inflation rate.

  • "Net capital expenditures" is equal to cash flow used in investing activities, excluding changes in non-cash working capital.

    Bonavista considers net capital expenditures to be a useful measure of cash flow used for capital reinvestment.

Reference should be made to our second quarter 2019 condensed consolidated interim financial statements for additional disclosure on these non-GAAP measures, including reconciliations to the most comparable GAAP measure.


Any references to value capital, support capital and production efficiency have been prepared by management and are used to measure performance. These terms do not have standardized meanings or standard calculations and may not be comparable to similar measures used by other entities.

  • Value capital includes expenditures on drilling, completion, equipping and tie-in projects and recompletions. Value capital has been used to define capital expenditures, included in exploration and development expenditures, that are directly associated with generating incremental reserves and cash flow from operating activities.

  • Support capital includes expenditures on land, facilities and infrastructure and workovers. Support capital has been used to define capital expenditures, included in exploration and development expenditures, that are associated with the maintenance of existing operations and to support future development.

  • Production efficiency which is defined as a type of capital efficiency that measures the cost to add an incremental barrel of flowing production. Specifically, for the average production efficiencies of our plays, Bonavista uses the total actual/projected drill, complete and tie-in capital divided by the total of the wells' initial production rate.

Any reference made in this document to initial production rates are useful in confirming the presence  of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue  production and decline thereafter. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for Bonavista.

To provide a single unit of production for analytical purposes, natural gas production and reserves volumes are converted mathematically to equivalent barrels of oil (boe). We use the industry-accepted standard conversion of six thousand cubic feet of natural gas to one barrel of oil (6 mcf = 1 bbl). The 6:1 boe ratio is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead and is not based on either energy content or current prices. While the boe ratio is useful for comparative measures and observing trends, it does not accurately reflect individual product values and might be misleading, particularly if used in isolation. As well, given that the value ratio, based on the current price of crude oil to natural gas, is significantly different from the 6:1 energy equivalency ratio, using a 6:1 conversion ratio may be misleading as an indication of value.

The following abbreviations used in this news release have the meanings set forth below:




thousand barrels


barrels of oil equivalent


thousand cubic feet


million cubic feet


thousands of dollars



This document should be read in conjunction with the Management's Discussion and Analysis ("MD&A") and the condensed consolidated interim financial statements for the three months and six months ended June 30, 2019, together with notes related thereto, as well as in conjunction with the audited consolidated financial statements for the year ended December 31, 2018, together with the notes thereto, for a full understanding of the financial position and results of operations of Bonavista Energy Corporation ("Bonavista" or the "Corporation"). Additional information relating to Bonavista, including the audited consolidated financial statements for the year ended December 31, 2018, are available through SEDAR at or can be obtained from Bonavista's website at

This document contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "anticipate", "expect", "project", "plan", "estimate", "budget", "will", "strategy", "ongoing", "potential", "believe", "continue" and similar expressions are intended to identify forward-looking information. Any "financial outlook" or "future orientated financial information" in the document as defined by applicable securities laws, has been approved by our management. Such financial outlook or future orientated financial information is provided for the purpose of providing information about our current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes.

In particular, but without limiting the foregoing, this document contains forward-looking information and statements pertaining to the following:

  • our focus and plans to create maximum shareholder value;
  • expectations regarding our financial flexibility in the future;
  • expectations regarding our ability to negotiate suitable covenant relief with its lenders;
  • our ability to navigate current and future commodity prices;
  • expectations regarding the quality, predictability, resilience and sustainability of our asset base;
  • expectations regarding well performance;
  • the performance characteristics of our oil and natural gas properties;
  • our exploration and development plans and the results therefrom;
  • expectations regarding industry conditions, future commodity prices and demand for natural gas;
  • our 2019 capital expenditure budget;
  • our ability to be agile in responding to changes to commodity prices;
  • expectations for 2019 for production volumes, adjusted funds flow, net debt and payout ratio;
  • expectations of future production rates, volumes and production mixes;
  • our acquisition and infrastructure plans;
  • expectations regarding the number and quality of our undeveloped locations; and
  • our focus on creating incremental financial flexibility.

By their nature, forward-looking statements are subject to numerous risks and uncertainties; some of which are beyond our control, including the impact of general economic assumptions and conditions, industry assumptions and conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, changes in environmental tax and royalty legislation, access to market, production curtailment and ethane rejection, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and external sources. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Our actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements or if any of them do so, what benefits that we will derive there from. Bonavista disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

This document contains information from publicly available third party sources as well as industry data prepared by management on the basis of its knowledge of the industry in which Bonavista operates (including management's estimates and assumptions relating to the industry based on that knowledge). Management's knowledge of the oil and natural gas industry has been developed through its experience and participation in the industry. Management believes that its industry data is accurate and that its estimates and assumptions are reasonable, but Bonavista has not independently verified the accuracy or completeness of this data. Third-party sources generally state that the information contained therein has been obtained from sources believed to be reliable, but Bonavista has not independently verified the accuracy or completeness of included information. Although management believes it to be reliable, Bonavista has not independently verified any of the data from third-party sources referred to in this document or analyzed or verified the underlying studies or surveys relied upon or referred to by such sources, or ascertained the underlying economic assumptions relied upon or referred to by such sources.

Readers are cautioned that the foregoing lists of factors are not exhaustive. Additional information on these and other factors that could affect our operations or financial results are included in reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (

These forward-looking statements are made as of the date of this news release and we disclaim any intent or obligation to update publicly any forward-looking information, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.

SOURCE Bonavista Energy Corporation

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Jason E. Skehar, President & CEO or Dean M. Kobelka, Vice President, Finance & CFO; Bonavista Energy Corporation, 1500, 525 - 8th Avenue SW, Calgary, AB T2P 1G1, Phone: (403) 213-4300, Website: www.bonavistaenergy.comCopyright CNW Group 2019

Source: Canada Newswire (August 1, 2019 - 5:08 PM EDT)

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