CALGARY, ALBERTA–(Marketwired – March 2, 2017) – Bonavista Energy Corporation (TSX:BNP) (“Bonavista”) is pleased to report to shareholders its financial and operating results for the three months and year ended December 31, 2016. A focused capital program supported by strategic non-core divestitures resulted in total net debt reduction of $433 million or 33% while maintaining entrance-to-exit production. Bonavista’s emphasis on cost reductions and efficiency improvements continued in 2016. Operating and cash costs improved to $5.60 per boe and $9.40 per boe resulting in a 15% and 12% improvement relative to the prior year. Bonavista’s Audited Consolidated Financial Statements and Notes, as well as Bonavista’s Management’s Discussion and Analysis (“MD&A”) for the years ended December 31, 2016 and 2015, are available on the System for Electronic Document Analysis and Retrieval (“SEDAR”) at http://www.sedar.com and on Bonavista’s website at www.bonavistaenergy.com.
| Highlights | ||||||||||||||
| Three months ended December 31, |
Years ended December 31, |
|||||||||||||
| 2016 | 2015 | % Change | 2016 | 2015 | % Change | |||||||||
| Financial | ||||||||||||||
| ($ thousands, except per share) | ||||||||||||||
| Production revenues | 141,842 | 137,260 | 3 | % | 445,434 | 599,999 | (26 | )% | ||||||
| Funds from operations(1) | 78,742 | 95,792 | (18 | )% | 264,391 | 385,351 | (31 | )% | ||||||
| Per share(1) (2) | 0.31 | 0.44 | (30 | )% | 1.11 | 1.77 | (37 | )% | ||||||
| Dividends declared | 2,493 | 11,664 | (79 | )% | 13,891 | 76,762 | (82 | )% | ||||||
| Per share | 0.01 | 0.055 | (82 | )% | 0.06 | 0.37 | (84 | )% | ||||||
| Net loss | (12,021 | ) | (454,616 | ) | 97 | % | (95,998 | ) | (751,545 | ) | 87 | % | ||
| Per share(3) | (0.05 | ) | (2.09 | ) | 98 | % | (0.40 | ) | (3.45 | ) | 88 | % | ||
| Adjusted net income (loss)(4) | 60,855 | (443,793 | ) | 114 | % | 22,259 | (696,634 | ) | 103 | % | ||||
| Per share(3) | 0.24 | (2.04 | ) | 112 | % | 0.09 | (3.20 | ) | 103 | % | ||||
| Total assets | 3,172,157 | 3,523,716 | (10 | )% | ||||||||||
| Long-term debt, net of working capital | 946,935 | 1,265,820 | (25 | )% | ||||||||||
| Long-term debt, net of adjusted working capital(5) | 877,523 | 1,310,663 | (33 | )% | ||||||||||
| Shareholders’ equity | 1,560,244 | 1,548,266 | 1 | % | ||||||||||
| Capital expenditures: | ||||||||||||||
| Exploration and development | 58,574 | 56,084 | 4 | % | 153,871 | 313,905 | (51 | )% | ||||||
| Dispositions, net of acquisitions | (117,666 | ) | (5,540 | ) | 2,024 | % | (167,905 | ) | (30,552 | ) | 450 | % | ||
| Weighted average outstanding equivalent shares: (thousands)(3) | ||||||||||||||
| Basic | 253,906 | 218,010 | 16 | % | 237,806 | 217,660 | 9 | % | ||||||
| Diluted | 258,729 | 220,924 | 17 | % | 242,106 | 220,117 | 10 | % | ||||||
| Operating | ||||||||||||||
| (boe conversion – 6:1 basis) | ||||||||||||||
| Production: | ||||||||||||||
| Natural gas (mmcf/day) | 278 | 325 | (14 | )% | 280 | 337 | (17 | )% | ||||||
| Natural gas liquids (bbls/day) | 19,941 | 20,804 | (4 | )% | 18,247 | 17,666 | 3 | % | ||||||
| Oil (bbls/day)(6) | 3,069 | 4,934 | (38 | )% | 3,708 | 5,445 | (32 | )% | ||||||
| Total oil equivalent (boe/day) | 69,339 | 79,862 | (13 | )% | 68,550 | 79,288 | (14 | )% | ||||||
| Product prices:(7) | ||||||||||||||
| Natural gas ($/mcf) | 3.31 | 3.44 | (4 | )% | 3.13 | 3.56 | (12 | )% | ||||||
| Natural gas liquids ($/bbl) | 25.83 | 19.39 | 33 | % | 19.97 | 23.17 | (14 | )% | ||||||
| Oil ($/bbl)(6) | 68.80 | 86.61 | (21 | )% | 61.89 | 81.23 | (24 | )% | ||||||
| Total oil equivalent ($/boe) | 23.75 | 24.39 | (3 | )% | 21.41 | 25.88 | (17 | )% | ||||||
| Operating expenses ($/boe) | 5.75 | 5.85 | (2 | )% | 5.60 | 6.60 | (15 | )% | ||||||
| General and administrative expenses ($/boe) | 1.09 | 0.97 | 12 | % | 1.08 | 1.12 | (4 | )% | ||||||
| Cash costs ($/boe)(8) | 9.40 | 9.80 | (4 | )% | 9.40 | 10.70 | (12 | )% | ||||||
| Operating netback ($/boe)(9) | 15.14 | 15.76 | (4 | )% | 13.44 | 16.16 | (17 | )% | ||||||
| Highlights (cont’d) | |||||||||
| Years ended December 31 | 2016 | 2015 | % Change | ||||||
| Drilling: | |||||||||
| Gross | 46 | 78 | (41 | )% | |||||
| Net | 43.1 | 70.1 | (39 | )% | |||||
| Land (net acres): | |||||||||
| Undeveloped | 568,051 | 705,610 | (19 | )% | |||||
| Total | 1,754,634 | 1,929,041 | (9 | )% | |||||
| Reserves:(10) | |||||||||
| Proved producing: | |||||||||
| Natural gas (bcf)(11) | 632.3 | 614.9 | 3 | % | |||||
| Oil and natural gas liquids (mbbls)(12) | 50,517 | 59,592 | (15 | )% | |||||
| Total oil equivalent (mboe) | 155,907 | 162,072 | (4 | )% | |||||
| Total proved: | |||||||||
| Natural gas (bcf)(11) | 1,128.1 | 1,026.0 | 10 | % | |||||
| Oil and natural gas liquids (mbbls)(12) | 85,159 | 91,230 | (7 | )% | |||||
| Total oil equivalent (mboe) | 273,183 | 262,224 | 4 | % | |||||
| Proved plus probable: | |||||||||
| Natural gas (bcf)(11) | 1,721.0 | 1,601.7 | 7 | % | |||||
| Oil and natural gas liquids (mbbls)(12) | 127,366 | 139,543 | (9 | )% | |||||
| Total oil equivalent (mboe) | 414,205 | 406,494 | 2 | % | |||||
| % Proved producing | 38 | % | 40 | % | (2 | )% | |||
| % Proved | 66 | % | 65 | % | 1 | % | |||
| % Probable | 34 | % | 35 | % | (1 | )% | |||
| Net present value of future cash flow before income taxes ($ millions, proved plus probable): | |||||||||
| 0% discount rate | 6,050 | 5,568 | 9 | % | |||||
| 5% discount rate | 3,876 | 3,492 | 11 | % | |||||
| 10% discount rate | 2,748 | 2,412 | 14 | % | |||||
| 15% discount rate | 2,092 | 1,788 | 17 | % | |||||
| Reserve life index (years):(13) | |||||||||
| Total proved | 10.5 | 9.7 | 8 | % | |||||
| Proved plus probable | 14.4 | 14.1 | 2 | % | |||||
| Reserves (boe per thousand shares – basic)(3): | |||||||||
| Total proved | 1,149 | 1,200 | (4 | )% | |||||
| Proved plus probable | 1,742 | 1,860 | (6 | )% | |||||
| Finding and development costs – proved plus probable ($/boe)(14) | 6.97 | 7.26 | (4 | )% | |||||
| Recycle ratio – proved plus probable(15) | 1.9 | 2.2 | (14 | )% | |||||
| Finding, development and acquisition costs – proved plus probable ($/boe)(14) | (0.55) | 9.84 | (106 | )% | |||||
| Recycle ratio – proved plus probable(15) | (24.4) | 1.6 | (1,625 | )% | |||||
| NOTES: |
| (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) | 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. 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. |
| (10) | Working interest reserves are gross reserves prior to deduction of royalties and without including any of Bonavista’s royalty interests. |
| (11) | Includes Conventional Natural Gas and Coal Bed Methane. |
| (12) | Includes Natural Gas Liquids; and Light, Medium and Heavy Oil. |
| (13) | Calculated based on the amount for the relevant reserve category divided by the production forecast prepared by the independent reserve evaluator (GLJ). |
| (14) | Includes changes in future development costs. |
| (15) | Recycle ratio is calculated using operating netback per boe divided by either finding and development or finding, development and acquisition costs per boe. |
| Share Trading Statistics | Three months ended | |||
| December 31, 2016 | September 30, 2016 | June 30, 2016 | March 31, 2016 | |
| ($ per share, except volume) | ||||
| High | 5.58 | 4.60 | 3.77 | 3.28 |
| Low | 3.95 | 3.15 | 2.23 | 0.94 |
| Close | 4.81 | 4.22 | 3.30 | 2.62 |
| Average Daily Volume – Shares | 877,141 | 1,135,181 | 1,492,555 | 1,317,618 |
MESSAGE TO SHAREHOLDERS
Bonavista entered 2017 in a remarkably stronger position relative to a year ago. The fragile commodity price environment in 2016 challenged the reinvestment economics of most oil and natural gas assets in North America. For Bonavista, we took the opportunity in this environment to strengthen our financial position, further concentrate the asset base, and reveal the exceptional capital and operating efficiencies of our portfolio that validate the sustainability of our business. We have reduced our total net debt by $433 million while we upgraded the performance and the potential of our asset portfolio to purposefully transition from defense to offense in 2017.
Today, we are positioned with two strategic core areas, each serving a different but invaluable purpose as we create shareholder value. First, our Deep Basin core area, characterized by stacked, resource-rich natural gas reservoirs, will experience 40% growth in production in 2017 while delivering top-decile operating margins with approximately 90% of our production being processed at our facilities. Second, our West Central core area, with over twenty years of predictable and reliable development inventory, will generate significant excess net operating income to fund our growth in the Deep Basin and to strengthen our financial position.
Overall, the flexibility created by generating surplus funds from operations provides us with several options in this environment. Accordingly, we intend to grow production between seven and 10%, and funds from operations between 10% to 20%, all while spending 90% to 100% of funds flow this year. This internally funded organic growth will result in forecasted debt to funds from operations of 2.5 times at year-end 2017.
Operational and financial accomplishments for 2016 include:
- Reduced our corporate total net debt by $433 million or 33%;
- Production for the fourth quarter averaged 69,339 boe per day, an 8% increase over third quarter production. Current production is 71,000 boe per day, notwithstanding the delay of completion operations on certain wells drilled in the fourth quarter of 2016 and first quarter of 2017;
- Underspent our exploration and development (“E&D”) budget resulting in a net capital credit of $14.0 million with proceeds from our acquisitions and divestitures (“A&D”) program exceeding capital expenditures from our E&D program for 2016;
- Reduced 2016 operating costs to $5.60 per boe and cash costs to $9.40 per boe, representing improvements of 15% and 12% respectively, when compared to 2015;
- Replaced 131% of 2016 production with the addition of 32.8 MMboe of proved plus probable reserves at no net cost;
- Added 30.8 MMboe of proved plus probable reserves replacing 123% of 2016 production with an E&D capital spending program of $153.9 million, being 58% of funds from operations generated in the year;
- Divested of approximately 5,000 boe per day of non-core assets resulting in a 14% reduction of inactive well count and $75 million of decommissioning liability;
- Maintained entrance to exit production at approximately 70,000 boe per day, notwithstanding a 51% reduction in E&D capital spending;
- Secured firm transportation on the Nova Gas Transmission Ltd. (“NGTL”) system north of the James River receipt point (“restricted area”) equal to 116% of our 2017 forecasted natural gas sales in this area; and
- Prudently protected 2017 funds from operations with a commodity hedge portfolio resulting in:
- 70% of our forecasted 2017 natural gas production hedged at an AECO price of $3.32 per mcf;
- 75% of oil and condensate volumes hedged at CDN$67.17 per bbl WTI; and
- 49% of our propane volumes hedged at CDN$28.37 per bbl.
2016 YEAR-TO-DATE CORE AREA HIGHLIGHTS
DEEP BASIN CORE AREA
The Deep Basin is clearly our vehicle for growth as we create shareholder value in 2017. In 2016, we increased our land position by 24% to 365,000 net acres and currently have approximately 550 horizontal drilling locations in this core area. Our Deep Basin is characterized by stacked, resource-rich natural gas reservoirs with low cost, high margin operations. We support our production base and development plans with 225 mmcf per day of operated processing capacity with plans to expand this capacity to 265 mmcf per day by the end of the first quarter. Egress certainty has been established with firm transportation secured on the NGTL system equal to 116% of our forecasted natural gas sales for 2017 in the area.
In 2016, we spent $75 million on E&D activities drilling 18 (17.4 net) horizontal wells supporting production rates averaging 19,273 boe per day or 28% of corporate production.
In 2017, we will increase drilling activity by 67% to 30 (26.4 net) wells growing production 40% to average 27,000 boe per day. We are currently producing approximately 25,000 boe per day in the Deep Basin.
Spirit River (Wilrich, Falher, Notikewin) Natural Gas
We drilled 13 (13.0 net) horizontal wells in 2016 including eight (8.0 net) wells in the fourth quarter, one of which was drilled to delineate the southern boundaries of our Ansell block. Six of these wells are currently on-stream and are performing similar to our first quarter 2016 program. Pressure pumping service availability delayed the start of completion operations for the last two wells of 2016 and our first quarter 2017 wells until the end of February. Two of these wells were completed recently and are our first extended reach wells drilled at Ansell in a NW-SE orientation. This two well pad has been on test for three days, and is currently being tested in-line at a combined rate of 35 mmcf per day, meaningfully outperforming our expectations. We have six wells currently drilled at Ansell and in the cue for completion before spring break-up.
Our Ansell facility will be expanded from 60 mmcf per day to 100 mmcf per day within the next month for a capital cost of approximately $8 million. Additionally, we have egress certainty with firm service commitments on the TransCanada pipeline equal to 116% of our forecasted 2017 production in this area, and optionality with a connection to the Alliance pipeline. Furthermore, we continue to expand our presence in the area and have acquired land to accommodate 6.5 net extended reach drilling locations.
Operating costs were $2.50 per boe in 2016, a 33% reduction relative to 2015. Capital efficiencies have also improved in 2016 by 35% to $10,200 per boe per day and proved plus probable finding and development costs were reduced by five percent to $6.55 per boe. Economics remain strong at Ansell where drilling and completion costs have continued to improve, our wells drilled year-to-date in 2017 have an average cost of $4.1 million, seven percent below our budget and an improvement from our 2016 program.
Our 2017 Wilrich program of 21 (20.8 net) wells, the majority of which are extended reach, will support production growth of approximately 69% to 16,300 boe per day from the fourth quarter of 2016 as compared to the same period in 2017.
In addition to our Ansell Wilrich program, we plan to drill three (2.0 net) Notikewin and Falher channel wells, including two extended reach horizontal wells. Numerous successful wells have been drilled by the industry offsetting our land base. As we delineate these additional zones, we expect to add future value, as no reserves have been currently booked on these locations.
Bluesky Natural Gas
We drilled three (2.9 net) horizontal Bluesky wells on our Pine Creek acreage in 2016 including one (1.0 net) in the fourth quarter. Our 2016 Bluesky program is performing to our expectations supporting fourth quarter 2016 production of 4,100 boe per day, 34% growth relative to the same period last year.
The Bluesky at Pine Creek is rich in natural gas liquids with 50% of its natural gas liquids (“NGL”) component being condensate. We plan to drill three (2.3 net) horizontal wells in 2017, including our first extended reach horizontal well, and will focus on acreage acquired in the recent asset exchange.
WEST CENTRAL CORE AREA
Our West Central core area is a reliable production base that is capable of generating significant excess funds from operations for many years to come. The area draws its strength from a low decline, optimized capital cost structure, year round access, resilient economics and predictable well results. With approximately 740,000 net acres and a drilling inventory of approximately 730 horizontal locations (more than 20 years of development), this core area offers predictable low risk development that will undeniably maintain production for many years as the area serves as a source of funding to enhance growth in the Deep Basin. We have built an extensive network of infrastructure to support our continued development of this core area, including over 2,200 kilometers of pipelines in service and 33 facilities, the majority of which are operated by Bonavista.
In 2016, we spent $71.2 million on E&D activities, which included drilling 28 (25.7 net) horizontal wells, supporting production rates averaging 44,236 boe per day or 65% of corporate production. In 2017, we plan to drill 33 (31.7 net) wells, with E&D spending of $133.9 million inclusive of incremental infrastructure spending. Our development is focused on Willesden Green, Strachan and Morningside, where we anticipate longer average horizontal lengths. This capital program maintains production between 43,000 and 44,000 boe per day while consuming only 56% of net operating income generated in this core area. Fortunately, with robust NGL production and the recent recovery in NGL prices, this core area will produce a notable $110 million of excess net operating income in 2017.
Glauconite Natural Gas
We drilled 22 (19.7 net) horizontal wells in 2016 including five (4.3 net) in the fourth quarter resulting in average 2016 production of 22,800 boe per day.
Our efficient operating structure continued to improve throughout 2016. Drilling and completion costs improved in the fourth quarter averaging $1.9 million, a 27% improvement relative to the same prior year period. We anticipate production efficiencies of between $8,000 and $10,000 per boepd in 2017.
Development economics have strengthened in the Glauconite resulting from improved NGL pricing. In 2017, the composite NGL barrel in the Glauconite is forecasted to generate revenue of $26.80 per barrel, a 45% increase over 2016.
Late in the fourth quarter of 2016, we completed the production redirects associated with the assets acquired through the asset exchange. This consolidation has enhanced our efficiencies by doubling liquid recoveries and reducing operating costs by approximately 50%. These improvements are anticipated to be captured in the first quarter of 2017.
We will continue to develop our Strachan area in 2017 by drilling four (3.95 net) wells out of our total 2017 Glauconite program. Continued success will provide an opportunity to create a long-term infrastructure solution in 2018 that will significantly enhance development economics.
We have drilled over 320 horizontal wells in the Glauconite and have another 350 drilling locations in inventory. The predictable, reliable nature of this development, coupled with its resilient economics continues to provide a dependable source of funds flow in 2017. We anticipate drilling 16 (15.7 net) wells in 2017.
Spirit River Falher Natural Gas
We drilled six (6.0 net) horizontal wells in 2016 at Morningside including one (1.0 net) in the fourth quarter. Our 2016 program successfully extended the boundaries of the play and we intend on delineating three new channels in 2017. In the fourth quarter of 2016, we closed a small acquisition adding 50 boe per day of production and four sections prospective for Falher development.
Capital cost reductions continue to improve our capital efficiencies, with our fourth quarter drilling and completion costs improving 20% to $1.6 million as compared to the prior year quarter.
The economics of our Morningside Falher play are impressive, with a forecasted 2017 internal rate of return (“IRR”) of 73% and a payout of 1.4 years, it remains competitive with the top plays in western Canada. As such, we are increasing our drilling activity by 150% in 2017 to 15 (14.5 net) wells and expect this development to deliver production growth in excess of 100% to approximately 7,000 boe per day from the fourth quarter of 2016 to the same period in 2017.
STRENGTHS OF BONAVISTA ENERGY CORPORATION
2017 marks our 20th year of operations. Throughout this period, 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 margins that compete favorably in most operating environments. Furthermore, our assets are predominantly operated by us, ensuring a sustainable pace of operations and a direct influence over our operating and capital cost efficiencies. In 2016, our E&D program consumed only 58% of our funds from operations to replace 123% of 2016 production with proved plus probable reserves. We also achieved a 15% improvement in operating costs and a 23% improvement in our cost to add production relative to 2015.
Our team brings a successful track record of executing reliable development programs with consistency and precision. We continually strive for financial 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 nine percent of the equity of Bonavista, aligning our interests with those of our external shareholders.
OUTLOOK
The fundamentals of our industry have improved throughout the second half of 2016 creating a more favourable economic investment environment. As a result, the industry including Bonavista will deploy incremental capital in 2017.
Undoubtedly, as commodity supply and demand seek equilibrium, pricing will remain volatile in 2017 and accordingly, for 2017, we have hedged approximately 70% of our natural gas, 75% of our crude oil and condensate, and 49% of our propane in excess of current forward pricing on average. Should we experience another tumultuous year of natural gas pricing whereby reinvestment economics become challenged, our strong hedge portfolio will enable us to maintain production at a minimum of 70,000 boe per day for 2017 at natural gas prices as low as $1.50 per gj at AECO and generate between $120 and $125 million of excess funds from operations to enhance financial flexibility.
Similarly, service cost inflation resulting from recently increased activity levels in western Canada will likely affect the availability of the service and could affect our profitability in 2017. Our capital and operating efficiencies have improved significantly throughout 2016 with numerous initiatives completed near the end of last year. This will serve as an opposing force to cost inflation preparing the foundation for continued capital efficient operations in 2017.
Lastly, concerns with access to the NGTL infrastructure has been topical as of late. With firm NGTL transportation contracts representing approximately 116% of our forecasted natural gas production in the constrained areas, we are confident we can deliver on our growth aspirations in 2017.
We will remain aware and agile with our development plans but clearly have taken numerous steps to strengthen our position in this environment. With constructive reinvestment economics still at play, we remain committed to continually enhancing the performance of our program to support our average daily production forecast of between 73,500 and 75,500 boe per day in 2017. This will be achieved through a disciplined and sustainable capital program of between $280 and $300 million drilling 55 to 65 net wells, resulting in seven to 10 percent production growth within funds flow from operations.
We thank our employees for their commitment and dedication, our Board of Directors for their guidance and our shareholders for their long-term support. We look forward to delivering profitable per share growth while creating additional financial flexibility in 2017.
On behalf of the Board of Directors
Keith A. MacPhail, Executive Chairman
Jason E. Skehar, President and Chief Executive Officer
March 2, 2017
Calgary, Alberta
| BONAVISTA ENERGY CORPORATION | |||||
| Supplemental Financial Information | |||||
| Consolidated Statements of Financial Position | |||||
| As at December 31 | 2016 | 2015 | |||
| ($ thousands) (unaudited) | |||||
| Assets | |||||
| Current assets | |||||
| Cash | 85,977 | – | |||
| Accounts receivable | 67,572 | 70,380 | |||
| Prepaid expenses | 4,851 | 8,333 | |||
| Other assets | 12,203 | 14,104 | |||
| Financial instrument commodity contracts | 5,361 | 66,213 | |||
| Financial instrument contracts | 2,488 | 2,013 | |||
| 178,452 | 161,043 | ||||
| Financial instrument commodity contracts | 3,030 | 19,390 | |||
| Financial instrument contracts | 2,343 | 68,754 | |||
| Property, plant and equipment | 2,843,763 | 3,064,335 | |||
| Exploration and evaluation assets | 144,569 | 210,194 | |||
| Total assets | 3,172,157 | 3,523,716 | |||
| Liabilities and Shareholders’ Equity | |||||
| Current liabilities | |||||
| Accounts payable and accrued liabilities | 117,900 | 137,722 | |||
| Current portion of long-term debt | 154,334 | 34,600 | |||
| Decommissioning liabilities | 20,936 | 18,559 | |||
| Dividends payable | 2,493 | 2,140 | |||
| Financial instrument commodity contracts | 53,837 | 2,811 | |||
| 349,500 | 195,832 | ||||
| Financial instrument commodity contracts | 35,981 | 2,289 | |||
| Financial instrument contracts | 469 | – | |||
| Long-term debt | 775,887 | 1,231,031 | |||
| Other long-term liabilities | 8,816 | 10,742 | |||
| Decommissioning liabilities | 416,986 | 470,342 | |||
| Deferred income taxes | 24,274 | 65,214 | |||
| Total liabilities | 1,611,913 | 1,975,450 | |||
| Shareholders’ equity | |||||
| Shareholders’ capital | 2,837,945 | 2,716,011 | |||
| Exchangeable shares | 93,859 | 94,550 | |||
| Contributed surplus | 53,449 | 52,825 | |||
| Deficit | (1,425,009 | ) | (1,315,120 | ) | |
| Total shareholders’ equity | 1,560,244 | 1,548,266 | |||
| Commitments | |||||
| Total liabilities and shareholders’ equity | 3,172,157 | 3,523,716 | |||
| BONAVISTA ENERGY CORPORATION | |||||||||
| Supplemental Financial Information | |||||||||
| Consolidated Statements of Loss and Comprehensive Loss | |||||||||
| Three months ended December 31, |
Years ended December 31, |
||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||
| ($ thousands, except per share amounts) (unaudited) | |||||||||
| Revenues | |||||||||
| Production | 141,842 | 137,260 | 445,434 | 599,999 | |||||
| Royalties | (12,767 | ) | (11,389 | ) | (36,903 | ) | (54,201 | ) | |
| Production revenues, net of royalties | 129,075 | 125,871 | 408,531 | 545,798 | |||||
| Realized gains on financial instrument commodity contracts | 9,683 | 41,924 | 91,772 | 149,153 | |||||
| Unrealized losses on financial instrument commodity contracts | (99,807 | ) | (14,231 | ) | (161,930 | ) | (73,370 | ) | |
| Production revenues, net of royalties and financial instrument commodity contracts | 38,951 | 153,564 | 338,373 | 621,581 | |||||
| Expenses | |||||||||
| Operating | 36,700 | 43,000 | 140,592 | 190,889 | |||||
| Transportation | 5,512 | 9,023 | 22,566 | 36,500 | |||||
| General and administrative | 6,948 | 7,120 | 27,138 | 32,495 | |||||
| Share-based compensation | 2,058 | 4,057 | 8,994 | 17,157 | |||||
| Gain on acquisition and disposition of property, plant and equipment | (63,645 | ) | 586 | (66,354 | ) | (19,946 | ) | ||
| Gain on disposition of exploration and evaluation assets | (28,540 | ) | 8,316 | (23,738 | ) | (14,534 | ) | ||
| Depletion, depreciation, amortization and impairment | 64,313 | 649,232 | 319,845 | 1,168,016 | |||||
| Total expenses | 23,346 | 721,334 | 429,043 | 1,410,577 | |||||
| Loss from operating activities | 15,605 | (567,770 | ) | (90,670 | ) | (788,996 | ) | ||
| Finance costs | 34,541 | 27,378 | 128,717 | 221,342 | |||||
| Finance income | (7,663 | ) | 14,721 | (84,460 | ) | (54,742 | ) | ||
| Net finance costs | 26,878 | 42,099 | 44,257 | 166,600 | |||||
| Loss before taxes | (11,273 | ) | (609,869 | ) | (134,927 | ) | (955,596 | ) | |
| Deferred income tax (recovery) | 748 | (155,253 | ) | (38,929 | ) | (204,051 | ) | ||
| Net loss and comprehensive loss | (12,021 | ) | (454,616 | ) | (95,998 | ) | (751,545 | ) | |
| Net loss and comprehensive loss per share | |||||||||
| Basic | (0.05 | ) | (2.09 | ) | (0.40 | ) | (3.45 | ) | |
| Diluted | (0.05 | ) | (2.09 | ) | (0.40 | ) | (3.45 | ) | |
| BONAVISTA ENERGY CORPORATION | ||||||||||
| Supplemental Financial Information | ||||||||||
| Consolidated Statements of Changes in Equity | ||||||||||
| For the years ended December 31 | Shareholders’ Capital | Exchangeable Shares | Contributed Surplus | Deficit | Total Shareholders’ Equity | |||||
| ($ thousands) (unaudited) | ||||||||||
| Balance as at December 31, 2014 | 2,514,006 | 272,900 | 57,613 | (486,813 | ) | 2,357,706 | ||||
| Net loss and comprehensive loss | – | – | – | (751,545 | ) | (751,545 | ) | |||
| Conversion of restricted incentive and share awards | 23,655 | – | (23,655 | ) | – | – | ||||
| Share-based compensation expense | – | – | 17,157 | – | 17,157 | |||||
| Share-based compensation capitalized | – | – | 1,710 | – | 1,710 | |||||
| Exchangeable shares exchanged for common shares | 178,350 | (178,350 | ) | – | – | – | ||||
| Dividends declared | – | – | – | (76,762 | ) | (76,762 | ) | |||
| Balance as at December 31, 2015 | 2,716,011 | 94,550 | 52,825 | (1,315,120 | ) | 1,548,266 | ||||
| Net loss and comprehensive loss | – | – | – | (95,998 | ) | (95,998) | ||||
| Issuance of equity | 115,001 | – | – | – | 115,001 | |||||
| Issue costs, net of future tax benefit | (3,630) | – | – | – | (3,630) | |||||
| Conversion of restricted incentive and performance incentive awards | 9,200 | – | (9,200 | ) | – | – | ||||
| Tax effect on conversion of restricted incentive and performance incentive awards | 672 | – | – | – | 672 | |||||
| Share-based compensation expense | – | – | 8,994 | – | 8,994 | |||||
| Share-based compensation capitalized | – | – | 830 | – | 830 | |||||
| Exchangeable shares exchanged for common shares | 691 | (691 | ) | – | – | – | ||||
| Dividends declared | – | – | – | (13,891 | ) | (13,891 | ) | |||
| Balance as at December 31, 2016 | 2,837,945 | 93,859 | 53,449 | (1,425,009 | ) | 1,560,244 | ||||
| BONAVISTA ENERGY CORPORATION | |||||||||
| Supplemental Financial Information | |||||||||
| Consolidated Statements of Cash Flows | |||||||||
| Three months ended December 31, |
Years ended December 31, |
||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||
| ($ thousands) (unaudited) | |||||||||
| Cash provided by (used in): | |||||||||
| Operating Activities | |||||||||
| Net loss and comprehensive loss | (12,021 | ) | (454,616 | ) | (95,998 | ) | (751,545 | ) | |
| Adjustments for: | |||||||||
| Depletion, depreciation, amortization and impairment | 64,313 | 649,232 | 319,845 | 1,168,016 | |||||
| Share-based compensation | 2,058 | 4,057 | 8,994 | 17,157 | |||||
| Unrealized losses on financial instrument commodity contracts | 99,807 | 14,231 | 161,930 | 73,370 | |||||
| Gain on acquisition and disposition of property, plant and equipment | (63,645 | ) | 586 | (66,354 | ) | (19,946 | ) | ||
| Gain on disposition of exploration and evaluation assets | (28,540 | ) | 8,316 | (23,738 | ) | (14,534 | ) | ||
| Net finance costs | 26,878 | 42,099 | 44,257 | 166,600 | |||||
| Deferred income tax recovery | 748 | (155,253 | ) | (38,929 | ) | (204,051 | ) | ||
| Decommissioning expenditures | (6,637 | ) | (3,281 | ) | (15,309 | ) | (18,925 | ) | |
| Changes in non-cash working capital items | (12,200 | ) | 21,364 | (33,906 | ) | (9,852 | ) | ||
| Cash flow from operating activities | 70,761 | 126,735 | 260,792 | 406,290 | |||||
| Financing Activities | |||||||||
| Issuance of equity, net of issue costs | (2 | ) | – | 110,032 | – | ||||
| Dividends paid | (2,492 | ) | (16,930 | ) | (13,538 | ) | (88,885 | ) | |
| Interest paid | (19,944 | ) | (23,240 | ) | (45,770 | ) | (48,946 | ) | |
| Proceeds from long-term debt | – | – | – | 66,578 | |||||
| Repayment of long-term debt | (43,879 | ) | (15,799 | ) | (258,035 | ) | – | ||
| Cash flow used in financing activities | (66,317 | ) | (55,969 | ) | (207,311 | ) | (71,253 | ) | |
| Investing Activities | |||||||||
| Exploration and development | (58,574 | ) | (56,084 | ) | (153,871 | ) | (313,905 | ) | |
| Property acquisitions | (2,555 | ) | (1,572 | ) | (12,166 | ) | (69,576 | ) | |
| Property dispositions | 120,221 | 7,112 | 180,071 | 100,128 | |||||
| Office equipment | (110 | ) | (74 | ) | (604 | ) | (1,203 | ) | |
| Changes in non-cash working capital items | 22,551 | (20,148 | ) | 19,066 | (50,481 | ) | |||
| Cash flow from (used in) investing activities | 81,533 | (70,766 | ) | 32,496 | (335,037 | ) | |||
| Change in cash | 85,977 | – | 85,977 | – | |||||
| Cash, beginning of year | – | – | – | – | |||||
| Cash, end of year | 85,977 | – | 85,977 | – | |||||
This document should be read in conjunction with the audited consolidated financial statements (the “financial statements”) for the year ended December 31, 2016, together with notes related thereto and the Management’s Discussion and Analysis, for a full understanding of the financial position and results of operations of Bonavista Energy Corporation’s (“Bonavista” or the “Corporation” ). Additional information relating to Bonavista, including the Corporation’s Annual Information Form, is available on 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 costs and transportation costs; 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. “Basic funds from operations per share” is equal to funds from operations (described below in Other Management Performance Measures) based on the weighted average number of common shares outstanding and includes the weighted average number of exchangeable shares which are convertible into common shares on certain terms and conditions.
Other Management Performance Measures – In addition to the Non-GAAP Measures described above, there are also terms that have been reconciled in Bonavista’s financial statements to their most comparable IFRS measures. These terms do not have any standardized meaning prescribed by IFRS and therefore may not be comparable with the calculations of similar measures for other entities. These terms have been referenced in this document and should be read in conjunction with Bonavista’s Annual Report. These terms are used by Bonavista’s management to analyze operating performance on a comparable basis with prior periods and to analyze the liquidity of the Corporation.
“Funds from operations” 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. “Total net debt” is equal to the long-term portion of Bonavista’s bank debt and senior unsecured notes, net of adjusted working capital deficiency. “Adjusted working capital deficiency” excludes the current assets and liabilities from financial instrument commodity contracts and decommissioning liabilities. “Total net debt to funds from operations” is equal to total net debt divided by funds from operations for the relevant period. “Annualized current quarter funds from operations” is equal to the identified quarters funds from operations annualized for the year.
Oil and Gas Advisories – Management also makes reference to the following oil and gas terms in this document: “finding and development costs” (“F&D costs”) and “finding, development and acquisition costs” (“FD&A costs”), “F&D recycle ratio”, “FD&A recycle ratio” and “reserve life index” which have been prepared by management and do not have standardized meanings or standard calculations and therefore such measures may not be comparable to similar measures used by other entities. These terms are used by Bonavista’s management to measure the success of replacing reserves and to compare operating performance to previous periods on a comparable basis. For additional information on these measures reference should also be made to Bonavista’s Annual Information Form. Finding and development costs are calculated on a per boe basis by dividing the aggregate of the change in future development costs from the prior year for the particular reserve category and the costs incurred on development and exploration activities in the year by the change in reserves from the prior year for the reserve category. Finding development and acquisition costs are calculated on a per boe basis by dividing the aggregate of the change in future development costs from the prior year for the particular reserve category and the costs incurred on development and exploration activities and property acquisitions (net of dispositions) in the year by the change in reserves from the year for the reserve category. Both finding and development costs and finding development and acquisition costs take into account reserve revisions during the year on a per boe basis. The F&D recycle ratio is calculated by dividing the operating netback (refer to Non-GAAP Measures) for the period by the F&D costs per boe for the particular reserve category. FD&A recycle ratio is calculated by dividing the operating netback (refer to Non-GAAP Measures) for the period by the FD&A costs per boe for the particular reserve category. Reserve life index is calculated based on the amount for the relevant reserve category divided by the production forecast as prepared by Bonavista’s reserve engineers GLJ
This document also refers to IRR (internal rate of return) and payout which have been prepared by management and are used to measure performance. These terms do not have standardized meanings or standard calculations and are not comparable to similar measures used by other entities. In this document internal rate of return refers to the discount rate that makes the net present value of all cash flows of a project equal zero and payout refers to the time required to pay back the capital expenditures (on a before tax basis) of a project. This document also refers to production efficiency which is defined as a type of capital efficiency that measures the cost to add an incremental barrel of flowing production. Specifically, for the average production efficiencies of our plays, Bonavista uses the total actual/projected drill, complete and tie-in capital divided by the total of the well initial twelve month production rate.
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 documents 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.
In particular, but without limiting the foregoing, this document contains forward-looking information pertaining to the following:
- Forecasted capital expenditures for 2017 including drilling, exploration and development plans, acquisition and disposition activities and expected future drilling locations;
- Expected development economics for certain properties in 2017;
- Expected 2017 total and fourth quarter average production volumes and anticipated product mix;
- Expected 2017 oil, gas and natural gas liquids production volumes;
- Expected realized oil, gas and natural gas liquids prices and the differentials resulting from our financial risk management program in 2017;
- The benefits of Bonavista’s hedging portfolio;
- Expected 2017 funds from operations;
- Anticipated rate of return and future payout;
- Expected exit 2017 net debt to flow of funds from operations;
- The objective to manage net debt to funds from operations to be well positioned to create shareholder value and organic growth;
- Expected impact of the MRF program on royalty rates and operations; and
- Expected impact of the Climate Leadership Plan on operating expenses and operations.
References to 2017 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. In addition, references made in this document to initial production rates, and other short-term production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. Additionally, such rates may also include recovered “load oil” fluids used in well completion stimulation. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for Bonavista. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, Bonavista cautions that the test results should be considered to be preliminary.
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.
This document also contains future-oriented financial information and financial outlook information (collectively, “FOFI”) about our prospective results of operations and funds from operations, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth above. 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 FOFI and forward-looking statements. Bonavista’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and FOFI, or if any of them do so, what benefits Bonavista will derive therefrom. Bonavista has included the forward-looking statements and FOFI in this document in order to provide readers with a more complete perspective on Bonavista’s future operations and such information may not be appropriate for other purposes. 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.
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
Phone: (403) 213-4300
Website: www.bonavistaenergy.com
