Bonavista Energy Corporation Announces 2014 Fourth Quarter and Year End Results

CALGARY, ALBERTA–(Marketwired – Feb. 26, 2015) – Bonavista Energy Corporation (TSX:BNP) is pleased to report to shareholders its results for the fourth quarter and year ended December 31, 2014. Highlights include fourth quarter production growth of 14% to a record 85,810 boe per day, 15% reduction in cash costs to $10.99 per boe and a 10% improvement in annual FD&A costs to $9.94 per boe. Bonavista’s Audited Consolidated Financial Statements and Notes, as well as Bonavista’s Management’s Discussion and Analysis (“MD&A”) for the years ended December 31, 2014 and 2013, are available on SEDAR at www.sedar.com or can be obtained from Bonavista’s website at www.bonavistaenergy.com.

MESSAGE TO SHAREHOLDERS

Our pursuit to become one of the most efficient operators in western Canada has resulted in 2014 being an outstanding year for Bonavista. Throughout, we remained focused on enhancing capital and operating efficiencies, while further concentrating our asset portfolio in the West Central and Deep Basin Core Areas.

This unwavering commitment to operational excellence and targeted development within our core areas has resulted in annual production of 77,211 boe per day, representing five percent growth over 2013, despite divesting of approximately 6,000 boe per day of non-core assets. Significant infrastructure investment in the first half of 2014 created incremental processing capacity resulting in profitable production growth in our key plays during the second half of the year. We exited 2014 with average production for December of 88,083 boe per day, representing 17% (eight percent per share) growth, relative to the same period in 2013. Overall, we added production at a cost of approximately $17,000 per boe per day on a trailing twelve month full cycle basis. This represents a 50% reduction in our cost of adding production over the past two years, reflecting our relentless focus on efficiency.

Similarly, we have grown our proved plus probable reserves by seven percent to 427 mmboe as at December 31, 2014. With profitable growth being paramount, we have reduced our 2014 finding, development and acquisition (“FD&A”) costs by 10% to $9.94 per boe, on a proved plus probable basis, including changes in future development costs (“FDC”), resulting in a recycle ratio of 2.3:1.

Our business plan remains focused on maximizing shareholder value through a balance of growth and income. In 2014, we delivered production growth of five percent and delivered an annualized yield of six percent, collectively exceeding our total return goal of 10%.

For 2015, we remain focused on prudent and sustainable spending levels in light of the current commodity price environment. Our goal is to spend within the limits of our forecasted funds from operations for 2015. Hence, we have revised our capital budget to reflect an “all-in” payout ratio (inclusive of dividends) of 100%. Our 2015 capital budget has been revised to between $300 and $320 million, drilling between 70 (60.4 net) and 80 (69.1 net) wells. Notwithstanding a curtailment of approximately 3,500 boe per day in our annual guidance due to planned facility turnaround activity, our annual production is expected to grow approximately five percent year-over-year to between 80,000 and 82,000 boe per day. This growth, combined with our current dividend yield of approximately five percent, should result in attaining our goal of a 10% total shareholder return again in 2015.

Operational and financial accomplishments for 2014 include:

• Grew fourth quarter production by 14% over last year to 85,810 boe per day, resulting in annual production growth of 5% to 77,211 boe per day, despite turnaround activities and net dispositions reducing production by 4,500 boe per day annually;
• Reduced fourth quarter operating costs by 16% over last year to $7.38 per boe, resulting in an annual reduction in operating costs of 8% to $8.25 per boe and cash costs by 6% to $12.20 per boe. This has generated an annual operating netback of $22.60 per boe, a 10% improvement from 2013;
• Invested $639.6 million in exploration and development (“E&D”) activities, drilling 134 (111.6 net) wells, adding on average 545 boe per day of production per well using the first 30 days of production. Consistent with our asset concentration strategy, 130 of the 134 wells were drilled within our core areas. Productivity peaked in the fourth quarter where $162.2 million was spent on E&D development, drilling 27 (24.2 net) wells averaging 710 boe per day per well in their first 30 days of production;
• Reduced FD&A costs by 10% to $9.94 per boe on a proved plus probable basis, including changes in FDC, resulting in a recycle ratio of 2.3:1. Similarly, our E&D program delivered a reduction in finding and development costs (“F&D”) by 9% to $10.85 per boe on a proved plus probable basis, including changes in FDC, resulting in a recycle ratio of 2.1:1;
• Replaced 2014 production by 200%, adding 56 mmboe of reserves on a proved plus probable basis, bringing year-end 2014 reserves to 427 mmboe, a 7% increase over year-end 2013;
• Generated production revenues of $1.1 billion, a 15% increase compared to 2013;
• Realized funds from operations of $561.1 million ($2.69 per share), a 17% increase from 2013;
• Hedged 248,000 gj per day of our natural gas at an average floor price of $3.54 per gj at AECO for 2015 and approximately 150,000 gj per day at an average floor price of $3.40 per gj for 2016. Additionally, we hedged 8,000 bbls per day of our oil and liquids at an average floor price of CDN$91.59 per bbl WTI for 2015. Overall for 2015, Bonavista has hedged approximately 70% of our forecasted revenues (net of royalties);
• Completed a bought deal financing for net proceeds of approximately $192 million, issuing 12.1 million common shares to fund our Ansell area acquisition and future development;
• Extended the term of our bank facility of $600 million to September 10, 2018 at reduced borrowing costs, with $442.8 million undrawn at December 31, 2014; and
• Delivered cumulative dividends of over $2.6 billion or $27.87 per common share since 2003, when Bonavista introduced an income component to our total shareholder return.

Acquisition and divestiture highlights:

• Completed 38 property transactions in 2014, resulting in net proceeds of $106.8 million;
• Completed acquisitions of $186.6 million adding production of 2,800 boe per day at closing and 1,300 boe per day on average for the year and 82 net future drilling locations in our core areas. The largest acquisition was at Ansell in our Deep Basin Core Area focusing on the Wilrich play, for $141.1 million. Since acquiring these assets, we have organically grown production at Ansell by 3.5 times to 8,850 boe per day in December; and
• Divested of $293.4 million representing 6,000 boe per day of non-core assets, reducing annual production by 3,500 boe per day. The disposed assets had operating costs in excess of $22.00 per boe.

2014 FOURTH QUARTER AND ANNUAL CORE AREA HIGHLIGHTS

WEST CENTRAL CORE AREA

Our West Central Core Area is characterized by liquids-rich natural gas and light oil resources in multiple prospective horizons, with year round access. It includes extensive infrastructure of over 2,800 kilometers of pipelines and 38 facilities, the majority of which are operated by Bonavista. In this core area, we have access to approximately 1.3 million acres, containing approximately 800 of our future drilling locations. Given our current development pace of drilling 50 to 60 locations per year, this represents a drilling inventory in excess of 14 years.

In 2014, we spent $380 million on E&D activities, drilling 98 (82.2 net) horizontal wells. In 2015, we plan to reduce E&D spending to $167 million, due to current commodity price weakness, drilling 54 (43.8 net) horizontal wells.

Production in this area averaged 46,796 boe per day in 2014 representing a 13% increase over 2013, despite significant third party turnaround activity in the second and third quarters.

Our Hoadley Glauconite play continues to be our engine of growth representing 71% of the total expenditures forecasted in this core area for 2015. Meanwhile, the emerging growth and profitability of our Falher play, even in this commodity price environment, has become a focal point of our planning given our recent drilling successes.

Glauconite Natural Gas

Bonavista conducted its most active year, drilling 69 (59.5 net) horizontal wells, representing a 78% increase in net wells from 2013, including 10 wells (9.4 net) in the fourth quarter. This increased activity has resulted in fourth quarter production of approximately 27,000 boe per day, equating to over 50% growth since the beginning of the year.

Well economics remain strong in spite of the decrease in natural gas and natural gas liquids pricing. With the addition of deep cut processing at the Rimbey facility during the second quarter of 2015, we expect a 40% improvement in the natural gas liquids recoveries, to approximately 100 bbls per mmcf. Using these improved recoveries, single well economics are slightly improved to a 30% internal rate of return (“IRR”), using a price of $3.00 per gj @ AECO for natural gas and a WTI price of US$60.00 per bbl for oil and condensate. This is a testament to the quality of this play and its ability to generate competitive returns in the current commodity price environment.

We remain encouraged with the results of our extended reach horizontal program. We have drilled 12 extended reach horizontal wells to date, averaging 1.9 times the length of a typical “one-mile” well. Using this horizontal length multiplier, these wells have demonstrated cost reductions averaging 19% and production capital efficiency improvements of six percent. Slick water completions for these wells have resulted in additional cost savings of 25% versus a standard completion technique. We plan to drill an additional eight extended reach wells in 2015.

Being the most active operator, with inventory of approximately 400 locations and strong economics, the Glauconite will continue to serve as the foundation of our development program. As such, we plan to drill 44 (33.8 net) wells in 2015.

Spirit River Falher Natural Gas

In 2014, our Falher E&D program at Morningside has yielded exciting results, drilling six horizontal wells, including one during the fourth quarter. First month production rates have averaged 1,070 boe per day, inclusive of natural gas liquids yield of approximately 50 bbls per mmcf.

This year, our production has grown seven-fold to 4,070 boe per day during December 2014 from 500 boe per day in January 2014. To support this rapid growth, we expanded our compression and gathering infrastructure in the second half of the year and have since reached capacity with results exceeding our expectations. We have 25 Falher drilling locations in our inventory at Morningside and development economics continue to compete with our flagship Glauconite play. Well costs are $3 million to drill, complete and equip, generating an internal rate of return of 36%, using prices of $3.00 per gj AECO for natural gas and a WTI price of US$60.00 per bbl. The low cost and high deliverability of the Falher enables this play to achieve competitive rates of return at current commodity prices. Consequently, we plan to drill eight (8.0 net) Falher wells in 2015, seven of which will be at Morningside.

Additional Highlights

Cardium activity in 2014 consisted of 16 (11.4 net) wells which performed above our expectations, averaging 295 boe per day in their first 30 days of production. This drilling program was supported by the installation of a multi-well oil battery with a capacity of 5,000 bbls per day at Lochend. In light of the current outlook on oil prices, we have scaled back our development program whereby only two Cardium wells will be drilled in 2015.

We drilled four Ellerslie wells in 2014, all of them during the first half of the year. During the second half, our capital allocation shifted away from the Ellerslie and over to our Deep Basin Wilrich play as a result of the Ansell acquisition. At current commodity prices, the Ellerslie does not compete with our Glauconite and Spirit River plays, as such we do not have any wells planned for 2015.

DEEP BASIN CORE AREA

Our Deep Basin Core Area contains multiple vertically stacked oil and natural gas reservoirs in a concentrated area, proximate to infrastructure and associated services. Over the past three years, we have been aggressively building our position in this core area. We have assembled approximately 300,000 net acres, identified 300 horizontal drilling locations, and we have achieved compounded annual growth in our reserve base of 62% to 111 mmboe proved plus probable reserves at December 31, 2014 during this period.

In 2014, we spent approximately $175 million on E&D activities, drilling 32 (25.3 net) horizontal wells and built $31 million of infrastructure. This resulted in average annual production growth of approximately 30% to 17,276 boe per day.

Bonavista had an active fourth quarter drilling program in the Deep Basin, drilling 11 (9.8 net) horizontal wells, seven of which were Wilrich wells at Ansell. Our Wilrich results continue to exceed expectations, as such, we plan to install additional processing infrastructure in 2015 and have secured incremental egress for our production. Our 2015 plans involve spending $106 million on E&D activities, drilling 19 (18.9 net) horizontal wells.

With compelling production performance, the Wilrich play provides solid economics in the current natural gas pricing environment, resulting in an attractive internal rate of return of 36%, using prices of $3.00 per gj AECO for natural gas and a WTI price of US$60.00 per bbl. Lastly, as we develop the extensive Notikewin and Falher channel systems deposited above the Wilrich reservoir, we anticipate significant inventory additions to our asset portfolio in this play.

Spirit River Natural Gas

Within the Wilrich zone at Ansell we drilled 15 (13.9 net) horizontal wells in 2014, including seven (7.0 net) in the fourth quarter. In 2014, our development plan at Ansell consisted of infrastructure investment with a goal to develop an unrestricted egress for our Ansell Wilrich development. During the first half of the year, we commissioned two 30 kilometer pipelines with 120 mmcf per day of capacity and constructed a 30 mmcf per day compressor station. In July, we acquired our non-operated partner, increasing our ownership from 51% to 100%, and during the fourth quarter, we expanded our compression capacity to 60 mmcf per day.

With our 2014 Ansell Wilrich drilling program, we continued to improve our understanding of the play as well as enhance our completion techniques. As a result, we have improved the initial 30 day production rate from 674 boe per day for our first quarter 2014 wells to 964 boe per day for our fourth quarter 2014 wells. Continuous improvement in the economic performance at Ansell has earned the allocation of 71% ($75 million) of our 2015 Deep Basin capital expenditures, consisting of 16 (16.0 net) wells.

In the Marlboro area, we drilled five horizontal wells (3.1 net) in 2014, including two (1.6 net) in the fourth quarter. We are pleased with our Marlboro program as the wells have achieved an average 30 day rate of 975 boe per day. With existing facility utilization near capacity at Marlboro, we do not plan to drill any wells in 2015.

The successful 2014 Wilrich programs at Ansell and Marlboro has resulted in our Wilrich production growing by over 170% in 2014 to approximately 13,000 boe per day in December.

In 2014, we identified numerous Notikewin and Falher opportunities using three dimensional seismic. Subsequent to the fourth quarter, we drilled our first Notikewin well at Ansell which recorded an initial 30 day rate of 710 boe per day. We are pleased with this initial result and remain optimistic about future development. The economics of the Notikewin and Falher will benefit from our existing infrastructure constructed for our Wilrich and Bluesky programs.

Additional Highlights

In 2014, we drilled five horizontal Bluesky wells on our Pine Creek acreage. In the fourth quarter we drilled two wells with an average 30 day rate of 810 boe per day per well. We also participated in an additional five non-operated wells with an average 30 day rate of 520 boe per day per well. Our operated Bluesky wells have exceeded our expectations, however given facility capacity constraints and the current commodity price environment, we will only drill one Bluesky well in 2015.

MONTNEY

Bonavista drilled two horizontal Montney wells in our Blueberry field in northeast British Columbia targeting the upper Montney. These wells had an average 30 day rate of 450 boe per day per well despite being restricted through non-operated facilities. The improved performance of our 2014 wells reflects our understanding of the reservoir characteristics and the use of enhanced completion techniques to maximize stimulated area and conductivity. Our Montney play remains an important component of our future growth. We plan to drill two wells in 2015 for the purposes of delineating the resource, exploring enhanced completion techniques and honoring our land retention program.

STRENGTHS OF BONAVISTA ENERGY CORPORATION

Throughout our eighteen year history, from an initial restructuring in 1997 to create a high growth junior exploration company, through the energy trust phase between July 2003 and December 2010, and since January 2011 as a dividend paying corporation, Bonavista has remained committed to the same operating philosophies despite the endless commodity price volatility and uncertainty inherent in the energy sector. We have consistently maintained a high level of investment activity on our asset base resulting in an increase in corporate production by approximately 125% since converting to an energy trust in July 2003. These results stem from the expertise of our people and their entrepreneurial approach to consistently generating profitable development projects in an unpredictable commodity price environment. Our experienced technical teams have a thorough understanding of our assets and the reservoirs within the Western Canadian Sedimentary Basin as they exercise the discipline and commitment required to deliver long-term value to our shareholders. The core operating and financial principles that guide our people have been with our organization from the beginning and remain solidly intact today.

Our production is approximately 70% weighted towards natural gas and is geographically focused in multi-zone regions, primarily in Alberta. We actively participate in undeveloped land purchases, property acquisitions and farm-in opportunities, which have all enhanced the quantity and quality of our extensive drilling inventory. Specifically over the past five years, technology coupled with North American natural gas supply/demand fundamentals has led to numerous opportunities to reposition the asset portfolio and drastically improve the quality of our development projects. These activities have led to low cost reserve additions and a reliable production base that continues to grow at a steady pace. Today, the predictable production performance and cost structure of our asset base ensures operating netbacks that compete favorably in most operating environments. Furthermore, our assets are predominantly operated by Bonavista, providing control over the pace of operations and a direct influence over our operating and capital cost efficiencies.

Our team brings a successful track record of executing low to medium risk scalable development programs with consistency and with precision. We continually strive for balance sheet flexibility and remain focused on prudent financial management. Our Board of Directors and management team possess extensive experience in the oil and natural gas business. They have successfully guided our organization through many different economic cycles utilizing a proven strategy underpinned with a set of consistent and reliable operating and financial principles. Directors, management and employees also own approximately 11% of the equity of Bonavista, aligning our interests with those of external shareholders.

OUTLOOK

North American natural gas markets remain oversupplied creating increased pricing uncertainty and volatility. Increasing US natural gas production has mitigated storage withdrawals normally anticipated during the winter season. The environment continues to be challenging at current prices given the supply/demand imbalance, and to be successful we remain focused on efficiencies and cost controls.

We remain committed to be the most efficient operator in western Canada. In 2014, our asset concentration strategy, coupled with our execution efficiency has resulted in 17% growth in our exit production over the same period in 2013. This resulted by adding production at a competitive cost of $17,000 per boe per day on a trailing twelve month full cycle basis. For 2015, we will remain on strategy with virtually all of our E&D spending allocated to our core areas. The economic resilience of both our Glauconite play and our Spirit River plays will attract the majority of this E&D budget given our expectations of 30 to 40% returns in this commodity price environment. We have approximately 700 locations in these two plays, which economically rank among the best natural gas plays in western Canada. Furthermore, the anticipated reduction in service provider utilization this year will improve the cost and efficiency of these services and enhance our economics in 2015 and beyond.

We have witnessed many commodity price cycles in our eighteen year history. In these environments, efficient companies with high quality assets and a low cost structure will succeed. We are confident that our asset portfolio and our proven ability to execute efficiently will enable us to deliver profitable returns through this cycle while maintaining or even improving financial flexibility.

We would like to thank our employees for their dedication and commitment to our strategy throughout the year and our shareholders for their continued support in these uncertain times. We are very pleased with our achievements in 2014 and remain confident in our strategy for 2015 and beyond.

On behalf of the Board of Directors

Keith A. MacPhail

Executive Chairman

Jason E. Skehar

President and Chief Executive Officer

February 26, 2015

Calgary, Alberta

[expand title=”Advisories & Contact”]FORWARD LOOKING INFORMATION

Forward-Looking Statements – Certain information set forth in this document, including management’s assessment of Bonavista’s future plans and operations, contains forward-looking statements including: (i) forecasted capital expenditures and plans; (ii) exploration, drilling and development plans; (iii) prospects and drilling inventory and locations; (iv) anticipated production rates; (v) anticipated operating and service costs; (vi) our financial strength; (vii) incremental development opportunities; (viii) total shareholder return; (ix) asset acquisition and disposition plans; (x) growth prospects; (xi) sources of funding, which are provided to allow investors to better understand our business. 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 conditions, industry 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.

Non-IFRS Measurements – Within Management’s discussion and analysis, references are made to terms commonly used in the oil and natural gas industry. Management uses “funds from operations” and the “ratio of debt to funds from operations” to analyze operating performance and leverage. Funds from operations as presented does not have any standardized meaning prescribed by IFRS and therefore it may not be comparable with the calculation of similar measures for other entities. Funds from operations 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 funds from operations throughout this report are based on cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures and interest expense. Basic funds from operations per share is calculated based on the weighted average number of common shares outstanding in accordance with International Financial Reporting Standards. Operating netbacks equal production revenues and realized gains and losses on financial instrument commodity contracts, less royalties, operating and transportation expenses calculated on a boe basis. Total boe is calculated by multiplying the daily production by the number of days in the period. Management uses these terms to analyze operating performance and leverage.

Conversion of Natural Gas to Barrels of Equivalent (BOE)

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.

Keith A. MacPhail
Executive Chairman

Jason E. Skehar
President & CEO

Glenn A. Hamilton
Senior Vice President & CFO

Bonavista Energy Corporation
1500, 525 – 8th Avenue SW
Calgary, AB T2P 1G1
(403) 213-4300
www.bonavistaenergy.com