CALGARY, ALBERTA–(Marketwired – Nov. 3, 2016) – 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, 2016. Operating and cash costs improved to $5.31 per boe and $9.25 per boe in the third quarter of 2016 resulting in a 19% and 14% improvement relative to the prior year period, supporting Bonavista’s emphasis on cost reductions and efficiency improvements. The unaudited financial statements and notes, as well as management’s discussion and analysis, are available on the System for Electronic Document Analysis and Retrieval (“SEDAR”) at http://www.sedar.com and on Bonavista’s website at www.bonavistaenergy.com.
|Three months ended
|Nine months ended
|2016||2015||% Change||2016||2015||% Change|
|($ thousands, except per share)|
|Funds from operations(1)||66,812||96,407||(31||)%||185,649||289,559||(36||)%|
|Per share(1) (2)||0.26||0.44||(41||)%||0.80||1.33||(40||)%|
|Adjusted net loss(4)||(19,227||)||(203,707||)||91||%||(38,596||)||(252,841||)||85||%|
|Long-term debt, net of working capital||983,200||1,243,576||(21||)%|
|Long-term debt, net of adjusted working capital(5)||986,449||1,305,362||(24||)%|
|Exploration and development||32,072||88,016||(64||)%||95,297||257,821||(63||)%|
|Dispositions, net of acquisitions||(55,342||)||(9,084||)||509||%||(50,239||)||(25,012||)||(101||)%|
|Weighted average outstanding equivalent shares: (thousands)(3)|
|(boe conversion – 6:1 basis)|
|Natural gas (mmcf/day)||260||324||(20||)%||280||341||(18||)%|
|Natural gas liquids (bbls/day)||17,570||19,597||(10||)%||17,678||16,609||6||%|
|Total oil equivalent (boe/day)||64,160||78,599||(18||)%||68,285||79,094||(14||)%|
|Natural gas ($/mcf)||3.28||3.76||(13||)%||3.07||3.60||(15||)%|
|Natural gas liquids ($/bbl)||18.88||19.71||(4||)%||17.76||24.76||(28||)%|
|Operating expenses ($/boe)||5.31||6.52||(19||)%||5.55||6.85||(19||)%|
|General and administrative expenses ($/boe)||1.12||1.21||(7||)%||1.08||1.18||(8||)%|
|Cash costs ($/boe)(8)||9.25||10.75||(14||)%||9.40||11.00||(15||)%|
|Operating netback ($/boe)(9)||14.32||16.36||(12||)%||12.87||16.30||(21||)%|
|(1)||Management uses funds from operations to analyze operating performance, dividend coverage and leverage. Funds from operations 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. 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. Funds from operations per share is calculated based on the weighted average number of shares outstanding consistent with the calculation of net income per share.|
|(2)||Basic funds from operations per share calculations include exchangeable shares which are convertible into common shares on certain terms and conditions.|
|(3)||Basic net income (loss) 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 commodity contracts, net of tax.|
|(5)||Amounts have been adjusted to exclude associated assets or liabilities from financial instrument commodity contracts and decommissioning liabilities.|
|(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 equals production revenues including realized gains and losses on financial instrument commodity contracts, less royalties, operating and transportation expenses, calculated on a boe basis.|
|Share Trading Statistics||Three months ended|
|($ per share, except volume)|
|Average Daily Volume – Shares||1,135,181||1,492,555||1,317,618||1,210,201|
MESSAGE TO SHAREHOLDERS
2016 has been a year of transition for Bonavista. The weak commodity price environment has caused Bonavista to focus on strengthening our balance sheet with a muted capital program allocated solely to top tier development opportunities, strategic asset acquisitions and non-core asset divestitures (“A&D”). As a result of our efforts, our asset portfolio will be more efficient, we are forecasting debt reduction of $430 million or 33% by year-end 2016. Furthermore, we anticipate corporate production in January 2017 to be equal to production a year earlier despite net capital spending for the year being equal to zero. This progress has undoubtedly established a solid foundation for Bonavista to build upon in 2017 and beyond.
Specific to the third quarter, our disciplined approach to both capital and operating efficiencies has resulted in production and funds from operations exceeding guidance by three percent and four percent respectively despite exploration and development (“E&D”) spending being 30% under budget. Notably, operating costs improved 19% relative to the same period a year ago and the average cost to drill a lateral meter of horizontal wellbore has dropped by 18% when compared to the same period in 2015.
Subsequent to the third quarter, we closed our previously announced strategic asset exchange whereby we acquired liquids rich natural gas assets in our core regions in exchange for non-core assets in British Columbia. Current production from the assets we acquired in this transaction is 6,900 boe per day. We have begun consolidating and optimizing production and forecast spending approximately $7 million enhancing the operating efficiencies of the acquired assets this year. The cashless transaction will result in an incremental 8,500 boe per day of production in our core areas and $38 million of funds from operations forecasted for 2017. In addition and subsequent to the quarter, we have agreements to divest of approximately 2,900 boe per day of assets for total proceeds of approximately $118 million. These transactions are expected to close in December.
With current production at 71,000 boe per day, we anticipate 2016 production to average approximately 68,500 boe per day and capital expenditures, net of A&D, to be zero for the year. We are forecasting to generate funds from operations of approximately $265 million resulting in our year-end debt for 2016 totaling $882 million down from $1.3 billion at year-end 2015. Clearly, 2016 has been a year of distinct and successful transition to a position of greater balance sheet flexibility and hence, greater opportunity as we enter 2017.
Operational and financial accomplishments for the third quarter of 2016 include:
- Reduced third quarter operating costs to $5.31 per boe and cash costs to $9.25 per boe, representing improvements of 19% and 14% respectively, over the same period in 2015;
- Executed an E&D capital spending program of $32.1 million, being 48% of funds from operations generated in the quarter and a 64% reduction relative to the same period in 2015;
- Divested of approximately 1,250 boe per day (inclusive of acquisitions) of non-core, cost intensive assets, resulting net A&D proceeds for the quarter totaling $55.3 million. Our focus on non-core asset dispositions over the past year has resulted in an 18% decrease in our gross total well count, a 13% reduction in our inactive well count and a 32% reduction in our abandoned well count;
- Drilled seven (6.6 net) wells and produced 64,160 boe per day in the third quarter. Unfortunately, weather restricted our ability to drill and complete all wells planned for the quarter;
- Generated funds from operations of $66.8 million ($0.26 per share) equal to $11.32 per boe which represents a 17% increase over the previous quarter on a per unit basis;
- Repaid $80.1 million of debt net of total expenditures and dividend commitment;
- Monetized $48.1 million of foreign exchange contracts, proceeds were used for additional debt repayment;
- Enhanced our commodity hedge portfolio resulting in:
- 208,478 gjs per day of natural gas hedged at an average floor price of $3.19 per gj at AECO for the fourth quarter of 2016;
- 3,500 bbls per day of oil hedged at an average floor price of CDN$76.90 per bbl WTI for the fourth quarter of 2016; and
- In addition, for 2017 we have 224,546 gjs per day of natural gas, 3,248 boe per day of oil, 2,123 boe per day of propane and 1,749 boe per day of Butane hedged.
2016 YEAR-TO-DATE CORE AREA HIGHLIGHTS
WEST CENTRAL CORE AREA
Our West Central core area draws its strength from a low capital cost structure, year round access, resilient economics and consistent results. With approximately 800,000 net acres and a drilling inventory of over 840 locations, this core area represents both reliable low risk drilling opportunities and promising new key plays for many years to come. We have built an extensive network of infrastructure to support our continued development of this core area, including 2,800 kilometers of pipelines and 38 facilities, the majority of which are operated by Bonavista.
During the first nine months of 2016, we spent $54.8 million on E&D activities, which included drilling 22 (20.3 net) horizontal wells, supporting production rates averaging 44,285 boe per day or 65% of corporate production. As planned, ten wells which were drilled in the second quarter were completed and brought on production in the third quarter in parallel with rising natural gas prices. For the fourth quarter, we are planning on E&D spending of $18.6 million by drilling 4 (3.5 net) Glauconite and 3 (3.0 net) Falher wells.
Glauconite Natural Gas
We drilled three (2.8 net) horizontal wells at Hoadley in the third quarter of 2016. Over the first nine months of 2016, we drilled 17 (15.3 net) horizontal wells. By the end of the third quarter, all nine wells drilled in the second quarter and two third quarter wells were on production.
Our Glauconite play draws its strength from its low capital costs and efficient operating cost structure. Drilling and completion costs improved in the third quarter averaging $1.9 million, a 14% improvement relative to the same prior year period.
We have drilled over 320 horizontal wells in the Glauconite. With 357 locations left to drill, the predictable, reliable nature of this development, coupled with its resilient economics will serve as a dependable source of funds flow for many years to come. Our 2016 program will conclude with an additional four (3.3 net) wells in the fourth quarter.
Spirit River Falher Natural Gas
We drilled one (1.0 net) Falher well at Morningside during the third quarter. Capital cost reductions have continued to improve our efficiencies, our drilling and completion costs have improved 19% to $1.7 million as compared to the prior year quarter. Subsequent to the quarter, we acquired four sections offsetting our prolific Morningside Falher development including 50 boe per day of production and 11 drilling locations.
The Morningside Falher play remains competitive with the top plays in western Canada. We expect it will be a driver of production growth for us in 2017.
DEEP BASIN CORE AREA
In this liquids-rich natural gas core area we have established a net land position of over 260,000 net acres and continue to increase our inventory through swap and acquisition transactions. We currently have an inventory of over 550 horizontal drilling locations and we also own and operate our infrastructure, resulting in low cost operations and egress optionality.
During the first nine months of 2016, we spent $35.0 million on E&D activities drilling seven (6.9 net) horizontal wells supporting production rates averaging 18,458 boe per day or 27% of corporate production. Our focus for the remainder of the year will largely be at Ansell with eight (8.0 net) Wilrich wells and one (1.0 net) Falher well planned. Additionally, one (1.0 net) well is planned in the Bluesky at Pine Creek. We are planning on E&D spending of $45.2 million for the fourth quarter of 2016.
Spirit River (Wilrich, Falher, Notikewin) Natural Gas
In the third quarter we drilled our first two mile lateral length Wilrich horizontal well. The well has been on production for three weeks at a restricted rate of 6.5 mmcf per day representing a 35% improvement over our wells drilled earlier this year (1.5 mile horizontal length). The extended reach wells we have drilled in the first nine months of 2016 are performing at average rates of approximately 621 boe per day per well for the first 180 days of production. This represents a 65% increase over the wells drilled during the same period in 2015.
The Wilrich play at Ansell will be key to our future growth in the Deep Basin. We own and operate our infrastructure where our operating costs are expected to be approximately $2.50 per boe in 2016, a 33% reduction relative to 2015. We also have egress optionality with connections to both the TransCanada and Alliance pipelines. We are forecasting to expand our processing capability from 60 mmcf per day to 100 mmcf per day in 2017 to accommodate our future development.
Our 2016 program will conclude with an additional nine (9.0 net) Spirit River wells at Ansell in the fourth quarter. Eight of these wells will be extended reach Wilrich wells and one will be our first Falher horizontal well in this area.
Subsequent to the quarter, we acquired undeveloped land at Ansell with 6.5 net extended reach drilling locations.
Bluesky Natural Gas
We drilled two (1.9 net) horizontal Bluesky wells on our Pine Creek acreage in the third quarter. These wells came on-stream by mid-October and are meeting our expectations with an average rate of 600 boe per day during the first two weeks of production. Our Bluesky economics compete with our other key plays. The current cost to drill and complete these wells is $3.2 million which results in portfolio leading netbacks of $20.07 per boe.
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.
Our production and development activity is largely concentrated in two core areas in Alberta which together represent approximately 95% of current production. We create opportunities through undeveloped land purchases, asset swaps, asset acquisitions and farm-in opportunities in these areas. Specifically over the past five years, advanced 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 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. In 2016 year-to-date, this has resulted in a 19% improvement in operating costs and a 37% improvement in capital efficiencies relative to the same period in 2015.
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 eight percent of the equity of Bonavista, aligning our interests with those of external shareholders.
Warmer temperatures in the U.S. this summer has resulted in natural gas demand tracking above five year highs through the season. As a result, storage injections were consistently below seasonal averages which has modestly elevated North American natural gas prices as of late. The ambient temperature outlook this winter is cooler than last year supporting a case for an increase in natural gas demand. On the supply side, production declines in the U.S. combined with the continued reduction in drilled and uncompleted well inventories has set a positive tone for natural gas as we prepare for 2017.
Crude oil prices will be influenced by the compliance of OPEC members to the planned production limit, the pace of global demand and supply disruptions. We expect continued crude oil price volatility with a modest improvement in 2017. Natural gas liquids (“NGL”) pricing will be impacted by any positive developments in crude oil markets. NGL markets in 2017 are forecasted to be further supported by an increase in North American export capacity coupled with increased petrochemical demand.
Given the improvements in both our capital and operating efficiencies and the recent strength in commodities, we are encouraged with the economics of our development program as we plan for 2017. We have added significant flexibility to our balance sheet over the past year and as such, our Board of Directors has approved a preliminary 2017 E&D capital budget of between $280 and $300 million, drilling between 55 and 65 net wells. This level of investment is forecasted to generate production between 73,500 and 75,500 boe per day, representing annual growth in production of approximately nine percent and fourth quarter growth in production of approximately 12%. When coupled with our dividend, this capital program represents a total payout ratio of approximately 90% and results in debt to fourth quarter 2017 cash flow of approximately 2.4 times.
We thank our employees for their commitment to our strategy and our shareholders for their on-going support. We look forward to creating additional financial flexibility with our balance sheet while delivering profitable growth in 2017.