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 $0.93 per GJ for the quarter the result of a prudent hedge and diversification program. We have approximately 15% of our natural gas production exposed to AECO spot prices for the fourth quarter with only 22% of our oil and natural gas liquids subject to daily commodity price volatility.
| ||Three Months Ended || |
| ||June 30, |
|September 30, |
|September 30, |
|% Change |
|Financial || || || || |
|($ 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 ($/boe)(2) ||9.82 ||8.49 ||12.48 ||(32)% |
(1) Basic per share calculations include exchangeable shares which are convertible into common shares on certain terms and conditions.
(2) Non-GAAP measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other entities. Reference should be made to the section entitled "Non-GAAP Measures".
(3) Proceeds on property dispositions, net of expenditures on property acquisitions.
(4) Oil includes light, medium and heavy oil.
(5) Product prices include realized gains and losses on financial instrument commodity contracts.
|Share Trading Statistics ||Three months ended |
|September 30, |
|June 30, |
|March 31, |
|December 31, |
|($ 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 |
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.
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 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.
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.
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 third quarter 2019 Management's Discussion and Analysis for additional disclosure on these non-GAAP measures, including reconciliations to the most comparable GAAP measure.
OIL AND GAS ADVISORIES
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:
|Bbls ||barrels |
|Mbbls ||thousand barrels |
|Boe ||barrels of oil equivalent |
|Mcf ||thousand cubic feet |
|MMcf ||million cubic feet |
|$000's ||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 nine months ended September 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 www.sedar.com or can be obtained from Bonavista's website at www.bonavistaenergy.com.
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 remain disciplined with our spending plans;
- our plans to build a sustainable path forward;
- 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; demand for energy and natural gas and the impact of LNG on GHG emissions;
- our expectations relating to the LNG facility at Kitimat, BC;
- our 2019 capital expenditure budget and plans;
- expectations for 2019 for production volumes, adjusted funds flow and net debt;
- expectations of future production rates, volumes and production mixes; and
- our focus on improving financial flexibility and strengthening our asset base.
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 relating to the demand for energy 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 (www.sedar.com).
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.
FOR FURTHER INFORMATION CONTACT
Jason E. Skehar
President & CEO
Dean M. Kobelka
Vice President, Finance & CFO
Bonavista Energy Corporation
1500, 525 - 8th Avenue SW
Calgary, AB T2P 1G1
Phone: (403) 213-4300
To view the source version of this press release, please visit https://www.newsfilecorp.com/release/49442
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