Bonavista Energy Corporation Announces 2015 Fourth Quarter and Year End Results, Reduced Capital Spending and Dividend for 2016
(firmenpresse) - CALGARY, ALBERTA -- (Marketwired) -- 02/25/16 -- Bonavista Energy Corporation ("Bonavista") (TSX: BNP) is pleased to report to shareholders its financial and operating results for the fourth quarter and year ended December 31, 2015. Highlights include the reduction in fourth quarter operating costs by 21% to $5.85 per boe, decreased cash costs to $9.80 per boe and a 33% improvement in finding and development costs to $7.26 per boe, supporting Bonavista''s emphasis on cost reductions and efficiency improvements. 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, 2015 and 2014, are available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at and on Bonavista''s website at .
MESSAGE TO SHAREHOLDERS
Our operational and financial results in 2015 mark another milestone in our goal to re-establish Bonavista as a top decile producer in western Canada. Our cost structure is mirroring that of a decade ago, and our commitment to do more with less has resulted in modest growth in our 2015 production with capital spending less than half of that spent in 2014. This capital program consumed approximately 75% of our funds from operations in 2015 and when added to our dividend commitment, created a sustainable business plan with a total payout ratio of 94%.
Significant improvements in operating and capital efficiencies were realized for the third straight year. Operating costs per boe improved to $6.60 in 2015, a 20% improvement over last year, in addition, fourth quarter operating costs were $5.85 per boe, 21% improvement from the same period in 2014. Our proved and probable finding and development costs declined by 33% to $7.26 per boe when compared to 2014, generating a recycle ratio of 2.2:1. Lastly, our cost to add production from our exploration and development ("E&D") program in 2015 was reduced by approximately ten percent over 2014 and currently, we are adding production between $12,000 and $14,000 per boe per day.
A year ago, with the WTI oil price dropping below US$50.00 per bbl, and propane losing its monetary value, we committed to a total payout ratio being less than forecasted funds from operations for 2015. We delivered on that promise and are committed to that same approach in 2016, given the continued weakness in commodity prices.
Over the past 12 months, both spot natural gas and oil prices have decreased a further 30% to 40%, meaningfully impacting the economics of our key plays. However, strength in the forward curve beyond 2016 enhances those economics with the timing of capital expenditures being key to higher returns. This commodity price environment is also placing further downward pressure on service costs through reductions in capital budgets, while creating acquisition opportunities that are competing favourably with our E&D program. To be successful in the current economic environment, we will remain flexible with our 2016 capital program spending between $145 million and $190 million. We will target the lower end of this range as our base E&D budget, but will be prepared to increase spending on E&D activities should commodity prices strengthen. This flexibility will allow us to reinforce our financial position and/or take advantage of acquisition opportunities that compete favourably with our key play economics. This budget is expected to result in production between 69,000 and 73,000 boe per day. In addition, effective April 1, 2016, our Board of Directors has approved a 67% reduction in the dividend to $0.01 per share per quarter. Using the base E&D budget of $145 million our total payout ratio for 2016 will be approximately 70%, with the remaining funds, approximately $70 million, being applied to our long-term debt.
Operational and financial accomplishments for 2015 include:
2015 Acquisition and divestiture highlights:
2015 FOURTH QUARTER AND ANNUAL CORE AREA HIGHLIGHTS
WEST CENTRAL CORE AREA
Our West Central core area draws its strength from a low capital cost structure, resilient economics and consistent results. In 2015, we continued to enhance our execution improving our cost structure in the Glauconite and achieved excellent results from our Morningside drilling program. With over 900,000 net acres and approximately 800 drilling locations in our key plays, our West Central core area represents both reliable, low risk drilling opportunities and promising new key plays. We have built an extensive network of infrastructure including 2,800 kilometers of pipelines and 38 facilities, the majority of which are operated by Bonavista, to support our continued development of this core area.
In 2015, our E&D spending in this core area was $175.5 million, drilling 56 (48.2 net) wells resulting in production of approximately 48,300 boe per day. This stable production rate was achieved while spending only 77% of our operating income for 2015, demonstrating the sustainability of our West Central development program.
Our Glauconite play has been the foundation of this sustainability, while the future potential of our Falher play continues to impress.
Glauconite Natural Gas
We drilled 46 (38.2 net) horizontal wells in 2015 including four (4.0 net) in the fourth quarter resulting in fourth quarter production of approximately 26,200 boe per day.
Our capital costs have improved throughout the year, with the cost to drill and complete a "typical" Glauconite well improving by 25% to $2.3 million when compared to 2014, while operating costs have decreased to below $4.50 per boe in our Hoadley area. Reduced costs and enhanced execution has resulted in annual production addition costs of approximately $12,300 per boe per day, a 10% improvement relative to 2014. The continued strength of the Glauconite play was also demonstrated by the 2015 proved plus probable finding and development costs coming in at a record low $3.74 per boe.
We continue to evolve our completion techniques from nitrogen foam to slick water fracs at Hoadley, resulting in improved well performance. Slick water, when combined with longer reach horizontal wells, has outperformed our conventional type curve by 200% after 12 months of production performance. This is accomplished at a cost equal to approximately 165% of our conventional Glauconite horizontal well.
In 2015, the commissioning of the deep cut processing facility at Rimbey resulted in a potential 30 bbl per mmcf increase in natural gas liquids from the Glauconite play (mostly ethane and propane). Unfortunately though, the challenging price environment for natural gas liquids has resulted in the curtailment of 20% to 60% of our ethane production. Furthermore, with negative propane pricing, we have chosen to redirect some Glauconite production to a Bonavista operated process facility. The benefits of natural gas with higher heat content and a lower operating cost structure at this facility will result in incremental operating income despite the lower recovery rates and production rates realized utilizing this process.
The Glauconite play continues to showcase consistent results with resilient economics that rank amongst the top liquids rich natural gas plays in North America. Our inventory of approximately 370 locations allows for over 13 years of development at our current pace. Our 2016 program entails drilling 16 to 30 (14.2 to 25.5 net) wells.
Spirit River Falher Natural Gas
We drilled eight (8.0 net) Falher wells in 2015 including one (1.0 net) in the fourth quarter.
Our 2015 Morningside Falher program has exceeded our expectations. We drilled six (6.0 net) wells at Morningside and successfully extended the boundaries of the play to the south of our main development area. Our six wells drilled in 2015 demonstrated average production rates of approximately 700 boe per day in their first three months.
Our Morningside Falher play continues to compete equally for capital with our Hoadley Glauconite and Ansell Wilrich plays. With current costs to drill and complete of $2.0 million, annual production addition costs remain less than $8,000 per boe with IRR''s in excess of 25% at current commodity prices.
Our 2016 Falher program includes drilling between seven to nine (6.5 to 8.5 net) wells.
DEEP BASIN CORE AREA
In 2015, we continued to expand our foot-print in this liquids-rich natural gas core area. We have established a net land position of approximately 295,000 acres and have increased our inventory through swap and acquisition transactions. We currently have over 300 horizontal drilling locations of which approximately 30% are extended reach. We built additional infrastructure in 2015 by installing a processing facility and a metering station, resulting in further operating cost reductions and incremental egress.
In 2015, we spent $114.8 million on E&D activities drilling 21 (20.9 net) wells. Production has averaged approximately 21,500 boe per day representing a 24% increase from the same period last year despite drilling 34% fewer wells.
Spirit River Wilrich Natural Gas
We drilled 18 (18.0 net) Wilrich wells in 2015 including four (4.0 net) in the fourth quarter, which were our first extended reach (approximately 1.5 mile lateral length) wells.
Improvements to our cost structure have made a significant impact to our economics at Ansell. The commissioning of our new processing facility and metering station in the second half of 2015 will result in operating costs below $3.00 per boe.
The average cost to drill and complete our fourth quarter Ansell wells was $4.9 million, representing an improvement of approximately 14% from the prior year period, despite two of these wells being extended reach horizontal wells. Our annual cost to add production at Ansell is currently $11,000 per boe per day, a 25% reduction from the same period in 2014.
During the second half of 2015, we continued expanding our Wilrich inventory at Ansell through a strategic land swap which added approximately 45 locations, the majority being extended reach wells.
Our 2016 program contemplates drilling between nine and 13 extended reach horizontal wells. We anticipate further economic enhancements driven by improved capital and operating efficiencies as we develop our extended reach program.
STRENGTHS OF BONAVISTA ENERGY CORPORATION
Throughout our nineteen 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, to 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 profitable investment activity on our asset base. This activity stems from the expertise of our people and their entrepreneurial approach to design profitable development projects with resilience to 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.
As a result of our recent successful non-core disposition strategy, our production and development activity is now largely concentrated in two core areas in central Alberta. We create opportunity through undeveloped land purchases, asset swaps, acquisitions and farm-in opportunities in these areas. 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. Today, the predictable production performance and optimized cost structure of our high quality asset base ensures operating netbacks that compete favorably in most operating environments. Furthermore, our assets are predominantly operated by us, 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 reliable development programs with consistency and 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 10% of the equity of Bonavista, aligning our interests with those of external shareholders.
OUTLOOK
Elevated world oil production and above average North American natural gas inventories will continue to weigh on our industry in 2016. These supply pressures and corresponding low commodity prices have resulted in a 73% drop in total operating U.S. oil and natural gas rigs to approximately 514 from a recent high of 1,931 in September 2014. Reduced drilling activity has impacted production, with North American oil production declining while world oil demand is forecasted to grow in 2016. All of these signals are constructive and support the beginning of a correction to the current imbalance between oil supply and demand.
We are well positioned to succeed through this environment. We are focused on improving our financial flexibility and will continue to rationalize non-core assets and concentrate our capital spending in two core areas. Our key plays in these core areas rank among the best economic performers in western Canada. We remain protected from further commodity price volatility with approximately 83% of our budgeted natural gas revenues and 64% of budgeted total production hedged for 2016 on a boe basis. In addition, our cost structure continues to improve, creating the opportunity to improve capital efficiencies throughout 2016. Lastly, we do not forecast a covenant breach on our long-term debt in 2016.
We intend to be flexible with our 2016 capital budget in light of uncertain commodity prices. This uncertainty will create opportunities with capital allocation and reinvestment timing and as such, we plan capital spending of between $145 and $190 million. This will generate production between 69,000 and 73,000 boe per day, focused on those projects generating at least a 20% IRR in the current commodity price environment. With our revised dividend commitment for 2016, we are targeting a total payout ratio of approximately 70% utilizing our base E&D budget guidance of $145 million, and intend to apply the remaining funds from operations, of approximately $70 million, to improve our balance sheet.
As always, we thank our employees for their tireless dedication and commitment to our vision and our shareholders for their support through these uncertain times. We are confident of our strategies and are backed by a resilient asset base that continues to provide value in this challenging environment.
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. Operating netbacks 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. 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 this term to analyze operating performance and leverage.
Additional IFRS Measurements - Within management''s discussion and analysis, references are made to terms commonly used in the oil and natural gas industry. Additional IFRS measurements which are non-IFRS measurements that are referenced in the annual financial statements, do not have a standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other entities. Management uses "funds from operations" and the "ratio of net debt to funds from operations" to analyze operating performance and leverage. 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. Net debt is equal to 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. The annualized current quarter funds from operations is calculated as the current quarter funds from operations annualized for the year.
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.
Contacts:
Keith A. MacPhail
Executive Chairman
Jason E. Skehar
President & CEO
Dean M. Kobelka
Vice President, Finance & CFO
Bonavista Energy Corporation
1500, 525 - 8th Avenue SW
Calgary, AB T2P 1G1
(403) 213-4300
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Datum: 25.02.2016 - 17:41 Uhr
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