May 4, 2018
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Bonavista Energy Corp. Announces 2018 First Quarter Results – Technical Bulletin

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CALGARYMay 3, 2018 /TechBulletin/ – Bonavista Energy Corporation (“Bonavista”) is pleased to report to shareholders its financial and operating results for the three months ended March 31, 2018. Results for the first quarter of 2018 are highlighted by a 3% increase in production to 72,417 boe per day and a 6% reduction in total net debt when compared to the first quarter of 2017. The unaudited 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.

Highlights

Three months ended March 31,

2018

2017

% Change

Financial

($ thousands, except per share)

Production revenues

138,388

143,182

(3)%

Adjusted funds flow(1)

69,128

70,851

(2)%

Per share(1) (2)

0.27

0.28

(4)%

Dividends declared

2,523

2,503

1 %

Per share

0.01

0.01

— %

 

Net income (loss)

(2,037)

88,428

(102)%

Per share(3)

(0.01)

0.35

(103)%

Adjusted net income(4)

1,156

9,934

(88)%

Per share(3)

0.04

(100)%

Total assets

2,933,854

3,242,319

(10)%

Long-term debt, net of working capital

822,046

906,746

(9)%

Long-term debt, net of adjusted working capital(5)

839,619

891,737

(6)%

Shareholders’ equity

1,539,073

1,652,722

(7)%

Capital expenditures:

Exploration and development

43,855

92,274

(52)%

Acquisitions, net of dispositions

97

(7,540)

101 %

Weighted average outstanding equivalent shares: (thousands)(3)

Basic

257,030

254,586

1 %

Diluted

267,120

262,519

2 %

Operating

(boe conversion – 6:1 basis)

Production:

Natural gas (mmcf/day)

322

293

10%

Natural gas liquids (bbls/day)

16,480

18,888

(13)%

Oil (bbls/day)(6)

2,327

2,560

(9)%

Total oil equivalent (boe/day)

72,417

70,281

3 %

Product prices:(7)

Natural gas ($/mcf)

2.85

3.12

(9)%

Natural gas liquids ($/bbl)

31.68

26.52

19 %

Oil ($/bbl)(6)

59.81

58.50

2 %

Total oil equivalent ($/boe)

21.79

22.27

(2)%

Operating expenses ($/boe)

5.64

5.47

3 %

General and administrative expenses ($/boe)

1.09

0.99

10 %

Cash costs ($/boe)(8)

9.38

8.98

4 %

Operating netback ($/boe)(9)

13.11

13.75

(5)%

NOTES:

(1)

Management uses adjusted funds flow to analyze operating performance, dividend coverage and leverage. Adjusted funds flow as presented do not have any standardized meaning prescribed by IFRS and therefore it may not be comparable with the calculations of similar measures for other entities. Adjusted funds flow as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net income or other measures of financial performance calculated in accordance with IFRS. All references to adjusted funds flow throughout this report are based on cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures and interest expense. Adjusted funds flow per share is calculated based on the weighted average number of shares outstanding consistent with the calculation of net income (loss) per share.

(2)

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

(3)

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

(4)

Amounts have been adjusted to exclude unrealized gains and losses on financial instrument contracts and unrealized gains and losses associated with the revaluation of our US senior unsecured notes, net of tax.

(5)

Amounts have been adjusted to exclude associated current assets or liabilities from financial instrument commodity contracts and decommissioning liabilities. Also referenced as total net debt.

(6)

Oil includes light, medium and heavy oil.

(7)

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

(8)

Cash costs equal the total of operating, transportation, general and administrative and financing expenses.

(9)

Operating netback as presented does not have any standardized meaning prescribed by IFRS and therefore it may not be comparable with the calculations of similar measures for other entities. Operating netback is calculated using production revenues including realized gains and losses on financial instrument commodity contracts less royalties, operating and transportation expenses calculated on a per boe basis.

Share Trading Statistics

Three months ended

March 31, 2018

December 31, 2017

September 30, 2017

June 30, 2017

($ per share, except volume)

High

2.32

3.01

3.37

3.56

Low

1.11

1.77

2.55

2.22

Close

1.18

2.25

2.98

2.71

Average Daily Volume – Shares

1,070,659

860,422

617,169

822,516

MESSAGE TO SHAREHOLDERS

In 2018, the quality and sustainability of our asset portfolio will become even more evident as we remain on track to maintain production levels at approximately 70,000 boe per day while generating significant surplus adjusted funds flow, which will be used to reduce our total debt and enhance our financial flexibility. With strengthening oil and natural gas liquids (“NGL”) pricing, we will remain focused on sustaining our production with the development of NGL opportunities with compelling economics within our diverse asset portfolio.

During the quarter, we produced 72,417 boe per day which is modestly ahead of forecast and within one percent of our average production rate in the final six months of 2017. These sustainable production rates have been achieved while spending only 64% of adjusted funds flow and creating approximately $22 million of surplus funds, net of dividends, available to allocate to debt reduction. This achievement represents approximately 30% of our annual debt reduction goals for 2018.

For the remainder of 2018, our capital program will remain focused on developing NGL rich opportunities predominately within our West Central core area. The recent strength in crude oil and NGL pricing coupled with our solid natural gas hedging and diversification position in 2018 will support our goal to generate surplus adjusted funds flow of between $70 and $90 million in 2018.

Operational and financial accomplishments for the first quarter of 2018 include:

  • Production was aligned with our budget and averaged 72,417 boe per day representing a three percent increase over the prior year period, notwithstanding approximately 1,400 boe per day of unscheduled ethane curtailments at non-operated process facilities;
  • Enhanced our diversification with the first full quarter of the long term fixed price (“LTFP”) service agreement to sell natural gas to the premium priced Dawn market which averaged $3.82 per mcf, representing an 85% premium to AECO pricing. Approximately 14% of our forecasted 2018 natural gas production is contracted for sale at Dawn;
  • Operating costs of $5.64 per boe led to cash costs of $9.38 per boe, representing a four percent increase over the prior year period largely due to transportation costs required to access the Dawn market;
  • Executed a total capital spending program of $44.1 million, equal to 64% of adjusted funds flow, to drill seven (5.3 net) and complete 13 wells;
  • Reduced long-term debt, net of adjusted working capital by six percent to $839.6 million as compared to the prior year period;
  • Generated adjusted funds flow of $69.1 million ($0.27 per share) representing similar per share metrics as the prior year period;
  • Prudently protected 2018 adjusted funds flow with a commodity hedge portfolio resulting in 57% of our forecasted 2018 natural gas production hedged at an AECO price of $3.07 per mcf and approximately 32 mmcf per day hedged at $3.11 per mcf for 2019; and
  • Diversified our natural gas delivery points beyond AECO whereby when coupled with our hedge portfolio, we have less than 10% of our forecast summer natural gas production exposed to daily AECO volatility this year.

2018 YEAR-TO-DATE CORE AREA HIGHLIGHTS

DEEP BASIN CORE AREA

Our Deep Basin core area is characterized by stacked, resource-rich natural gas reservoirs with low cost and high margin operations. Our production base and development plans are supported by having ownership in approximately 260 mmcf per day of operated process capacity, and adequate firm receipt service on NOVA Gas Transmission Ltd. (“NGTL”) to accommodate all of our budgeted natural gas production for 2018.

During the first quarter of 2018, we produced approximately 30,000 boe per day, representing 17% growth relative to the prior year period. We spent $27.5 million on exploration and development (“E&D”) activities drilling four (2.3 net) and completing seven (6.0 net) wells. First quarter drilling activity was focused on high rate natural gas development in the Spirit River and Bluesky formations. Most of the first quarter activity was connected to our low cost Ansell facility that is now producing at its capacity of 100 mmcf per day and will continue to do so into the second quarter. For the remainder of the year, we forecast E&D spending of $21.2 million to drill five (4.4 net) wells, with three of the five wells targeting liquids rich natural gas and oil opportunities.

WEST CENTRAL CORE AREA

Our West Central core area has a predictable production base with approximately 745,000 net acres and a drilling inventory of approximately 720 horizontal locations. This area draws its strength from a low cost structure, extensive infrastructure and consistent well results.

During the first quarter of 2018, we spent $14.8 million on E&D activities to drill three (3.0 net) liquid rich natural gas wells at Morningside in the Falher formation, one of which was a step-out well that significantly extended the play.

At our Strachan Glauconite play, drilling commenced in April and the construction of our pipeline to an alternate processing facility is on track. Our new processing agreement for our Strachan production will take effect June 2018 and result in operating cost reductions of approximately 50%. This low cost processing solution combined with approximately 50 barrels per mmcf of natural gas liquids (weighted 50% to condensate) results in some of the most economic development opportunities for Bonavista in 2018. With approximately 100 drilling locations in our prospect inventory, 80% of which are unbooked, this area has significant capacity for meaningful capital allocation in the current price environment.

Our 2018 West Central spending will be focused on two of our most economic plays at Strachan Glauconite and Morningside Falher. For the remainder of the year, total forecasted E&D spending for our West Central core area is expected to be $73.8 million to drill 14 (13.8 net) wells, representing 78% of our remaining value capital for the year.

OUTLOOK

A colder and longer winter across much of North America resulted in record storage draws in the U.S. and Canada with inventory levels in both countries currently well below the five-year average and approaching the bottom end of the five-year range.

The longest reported withdrawal season on record has resulted in U.S. natural gas inventories approximately 900 bcf lower than this time last year. Storage withdrawals have continued into the third week of April, the largest decline for this time of year since 1994. The first storage injection will likely commence the last week of April, further widening the storage deficit which is currently approximately 30% below the five year average and 41% below the prior year period. Although production growth continues at a rapid pace, the rate at which storage needs to be refilled has only been achieved once over the past decade. At a time when the U.S. is exporting natural gas at a record pace, we may see incremental domestic demand act as a positive catalyst for natural gas prices.

Our summer outlook for AECO remains cautious as significant maintenance on the NGTL system is scheduled for May and June. Under the assumption of the revised methodology, this maintenance will curtail interruptible delivery service on the NGTL system this summer. This is expected to once again impact the flow of natural gas into storage, a mechanism which has historically been used to efficiently regulate summer prices. With less than 10% of our natural gas production exposed to AECO spot pricing throughout the summer period, we have prudently protected our exposure to this anticipated volatile AECO price environment.

Optimism in crude oil supply and demand fundamentals has recently increased. Rising geopolitical risk coupled with continued output curtailments by OPEC and other major producers has resulted in the leveling of surplus stockpiles. With lower oil inventories and soaring Asian demand (China is approaching record crude imports of 10 million barrels per day this month) and production challenges in U.S. plays emerging, it appears that oil prices have somewhat stabilized at near $70 per barrel. As a result, we intend on enhancing our revenues by allocating 81% of our 2018 value capital towards oil and NGL rich development opportunities.

As we have mentioned before, access to export markets is crucial for the longevity and well-being of Canada’s clean and abundant natural gas resource sector. Recently, the B.C. government’s provincial sales and carbon tax incentives have kept the prospects for liquefied natural gas (“LNG”) in Canada alive and strong. These incentives support and promote a positive final investment decision regarding Canada’s first west coast LNG export facility this fall. One of the final barriers for Canada to open its doors to the global LNG market appears to be the relief of the 48.5% tariff in place for fabricated imported steel components (“FISC”). We are optimistic that the leaders of our nation will recognize the tremendous opportunity to create thousands of Canadian middle class jobs for decades to come with the practical and prudent decision on FISC tariffs.

Most importantly, a positive Canadian LNG export outcome will result in Canada taking a leadership role in reducing Green House Gas (“GHG”) emissions globally, as GHG emissions have no borders. Simultaneously, Canadian LNG exports may aid in meeting our national emission reduction targets associated with the Paris Agreement. Article six of the Paris Agreement allows countries to mitigate GHG emissions through international carbon markets, referred to as the Internationally Transferred Mitigation Outcome (“ITMO”). This means that emission reduction measures can be implemented in one country, with the resulting emission reductions transferred to another and count towards their nationally determined contributions. Notwithstanding significant progress with our Canadian climate policy since the implementation of the Paris agreement, there remains a gap between our emission targets and what current domestic policies are expected to achieve. These ITMOs would serve to close this gap and simultaneously lower global GHG emissions.

Canada’s LNG exports can and will have a net global environmental benefit. We are in a strategic geographical location to export LNG to the countries that need it the most. These are also the same countries (ChinaTaiwanIndiaJapan and South Korea) where our LNG would displace coal and other high carbon emitting sources to serve as a backstop to renewable energy developments. Our world will continue to need more energy, and we as Canadians have a tremendous opportunity to become a global leader in meeting these energy demands with a low carbon solution that will help the world progress into our sustainable energy future. Canadian natural gas is abundant, it has been developed under the most stringent and compliant environmental regulations in the world and it is the obvious and logical bridge towards a decarbonized future.

Aligned with Canada’s aspirations to play a leadership role in a sustainable energy future, our aspirations to become one of the most efficient operators in western Canada has resulted in a more sustainable asset base here at Bonavista. With forecast 2018 full cycle capital efficiencies of $11,000 per boe per day and a modest decline rate of 24%, the capital we require to maintain our production is approximately $170 to $180 million or approximately 50% lower than it was five years ago, highlighting the quality of our assets and the ability to adapt our development initiatives to the current environment.

We remain firmly on track to create incremental financial flexibility by generating excess adjusted funds flow in 2018. Our capital spending program remains between $135 and $155 million and is intended to generate production of between 69,000 and 71,000 boe per day. We expect to achieve a total payout ratio, including the dividend, of between 60% and 70% and generate excess adjusted funds flow of between $70 and $90 million, which will be used to reduce our total debt.

After 36 years in the industry, Mr. Wayne Merkel, Vice President, Exploration has chosen to retire, effective May 3, 2018. Mr. Merkel joined Bonavista in 2002 as a Senior Geologist and held positions of increasing responsibility, culminating with his appointment to Vice President in 2011. Mr. Merkel has been instrumental in the success of our organization over the past 16 years, playing a vital role in our pursuit to create shareholder value. We wish Mr. Merkel much success in the next chapter of his life.

Consistent with our aspirations to adapt our asset portfolio for success in this ever-changing environment, we are pleased to announce the following changes to our leadership structure effective May 3, 2018:

Ms. Rochelle Estep has been promoted to the position of Vice President, Strategy and Planning. Rochelle, began her career at Bonavista as a Development Engineer in 2006 and was integral in the development of our Hoadley Glauconite play. In 2014, she was promoted to Manager, Development and Engineering and in 2017 she was promoted to Director, Business and Commercial Development. Rochelle will now play an instrumental role in the design and execution of our long-term strategy and planning initiatives as an organization. Rochelle is a Professional Engineer and holds an MBA degree.

Mr. Scott Shimek has assumed the role of Vice President, Resource Development. Scott has been with Bonavista since 2006 and has contributed to the success of our production, development and operations initiatives over the past 12 years. He was promoted to his previous position of Vice President, Operations in 2015. Scott will now lead the resource development team in their pursuit of best-in-class development within our asset portfolio.

Mr. Colin Ranger has assumed the expanded role of Vice President, Operations. Colin has been instrumental in the design and execution of our production and field operations success over the past 11 years. Colin will continue to lead our field operations team as he takes on the additional responsibility in our drilling, completions, and facility operations as well as our health, safety and environment initiatives.

We thank our shareholders for their continued support through this ever-changing business environment and our employees for their commitment to our long-term vision. We are excited to move forward within a transformed organizational structure as we aspire to be the most efficient provider of energy in western Canada. We are also confident that our strategies for 2018 are appropriate in the current environment and we look forward to delivering on our objectives over the course of the year.

FORWARD LOOKING INFORMATION

This document should be read in conjunction with the Management’s discussion and analysis (“MD&A”) and the unaudited condensed consolidated interim financial statements (the “financial statements”) for the three months ended March 31, 2018, together with notes related thereto, as well as in conjunction with the audited consolidated financial statements for the year ended December 31, 2017, 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, 2017, are available through SEDAR at www.sedar.com or can be obtained from Bonavista’s website at www.bonavistaenergy.com.

Non-GAAP Measures – Throughout this document, the Corporation uses 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.

Management uses the following terms to analyze operating performance on a comparable basis with prior periods. “Operating netbacks” is equal to production revenues and realized gains and losses on financial instrument commodity contracts, less royalties, operating and transportation expenses calculated on a per boe basis. “Operating margin” is equal to production revenues and realized gains and losses on financial instrument commodity contracts less royalties, operating expenses and transportation expenses; divided by production revenues and realized gains and losses on financial instrument commodity contracts. Realized gains and losses on financial instrument commodity contracts represent the portion of Bonavista’s financial instrument commodity contracts that have settled in cash during the period and disclosing this impact provides transparency on how Bonavista’s risk management program impacts the netback and operating margin metrics. “Cash costs” is equal to the total of operating, transportation, general and administrative, and financing expenses calculated on a per boe basis. “Total boe equivalent” is calculated by multiplying the daily production by the number of days in the period. “Adjusted funds flow per share” is equal to adjusted funds flow (described below in Additional Operational Measures), based on the number of shares outstanding consistent with the calculation of net income (loss) per share.

Additional Operational Measures – Management uses the following terms to analyze operating performance on a comparable basis with prior periods and to analyze the liquidity of the Corporation. “Adjusted funds flow” is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net income or other measures of financial performance calculated in accordance with IFRS. All references to adjusted funds flow are based on cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures and interest expense. “Total net debt” is equal to the long-term portion of Bonavista’s bank debt and senior unsecured notes, net of adjusted working capital. “Adjusted working capital” excludes the current assets and liabilities from financial instrument commodity contracts and decommissioning liabilities. “Total net debt to adjusted funds flow” is equal to total net debt divided by adjusted funds flow for the relevant period. “Annualized current quarter to adjusted funds flow” is equal to the identified quarters adjusted funds flow annualized for the year.

Oil and Gas Advisories – 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.

Forward-Looking Statements – This document contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words “anticipate”, “except”, “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 interim report, as defined by applicable securities laws, has been approved by the management of Bonavista. Such financial outlook or future orientated financial information is provided for the purpose of providing information about management’s 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 pertaining to the following:

  • Forecasted capital expenditures for 2018 including drilling, exploration and development plans;
  • Expected 2018 oil, natural gas and natural gas liquids production volumes;
  • Expected realized oil, natural gas and natural gas liquids prices and the differentials resulting from our financial risk management program in 2018;
  • The benefits of Bonavista’s hedging portfolio;
  • Anticipated rate of return and future payout ratio; and
  • The objective to manage net debt to adjusted funds flow to be well positioned to create shareholder value and organic growth.

References to 2018 drilling locations and future drilling locations do not provide certainty that Bonavista will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves or production. The drilling locations on which Bonavista actually drills wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While a certain number of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, some of our other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves or production.

By their nature, forward-looking statements are subject to numerous risks and uncertainties; some of which are beyond Bonavista’s 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, 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. Bonavista’s 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 Bonavista 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.

Bonavista is focused on creating premium shareholder value through the efficient development of high quality oil, natural gas liquids and natural gas assets in the Western Canadian Sedimentary Basin.

SOURCE Bonavista Energy Corporation

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

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