CALGARY, ALBERTA–(Marketwired – May 7, 2015) – Bonavista Energy Corporation (TSX:BNP) (“Bonavista”) is pleased to report to shareholders its financial and operating results for the three months ended March 31, 2015. Our production efficiencies have improved by 20% leading to production growth of 15% (7% per share) over the same period in 2014, to 85,017 boe per day. Operating costs of $6.99 boe per day represent a 25% reduction over the same period in 2014.The unaudited financial statements and notes, as well as management’s discussion and analysis, are available on the System for Electronic Document Analysis and Retrieval (“SEDAR”) at http://www.sedar.com and on Bonavista’s website at www.bonavistaenergy.com.
| Highlights | ||||||||
| Three months ended March 31 | ||||||||
| 2015 | 2014 | % Change | ||||||
| Financial | ||||||||
| ($ thousands, except per share) | ||||||||
| Production revenues | 164,287 | 315,033 | (48 | )% | ||||
| Funds from operations(1) | 97,148 | 160,794 | (40 | )% | ||||
| Per share(1) (2) | 0.45 | 0.80 | (44 | )% | ||||
| Dividends declared | 21,538 | 39,575 | (46 | )% | ||||
| Per share | 0.105 | 0.21 | (50 | )% | ||||
| Net loss | (78,860 | ) | (44,937 | ) | 75 | % | ||
| Per share(3) | (0.36 | ) | (0.22 | ) | 64 | % | ||
| Adjusted net income (loss) (4) | (70,621 | ) | 20,779 | (440 | )% | |||
| Per share(3) | (0.33 | ) | 0.10 | (430 | )% | |||
| Total assets | 4,453,709 | 4,239,008 | 5 | % | ||||
| Long-term debt, net of working capital | 1,157,448 | 1,215,085 | (5 | )% | ||||
| Long-term debt, net of adjusted working capital(5) | 1,267,655 | 1,100,583 | 15 | % | ||||
| Shareholders’ equity | 2,262,231 | 2,209,460 | 2 | % | ||||
| Capital expenditures: | ||||||||
| Exploration and development | 111,951 | 176,635 | (37 | )% | ||||
| Dispositions, net of acquisitions | (9,657 | ) | (99,468 | ) | (90 | )% | ||
| Weighted average outstanding equivalent shares: (thousands)(3) | ||||||||
| Basic | 216,539 | 200,920 | 8 | % | ||||
| Diluted | 220,199 | 203,629 | 8 | % | ||||
| Operating | ||||||||
| (boe conversion – 6:1 basis) | ||||||||
| Production: | ||||||||
| Natural gas (mmcf/day) | 369 | 287 | 29 | % | ||||
| Natural gas liquids (bbls/day) | 17,068 | 15,065 | 13 | % | ||||
| Oil (bbls/day)(6) | 6,515 | 11,117 | (41 | )% | ||||
| Total oil equivalent (boe/day) | 85,017 | 73,936 | 15 | % | ||||
| Product prices:(7) | ||||||||
| Natural gas ($/mcf) | 3.45 | 5.07 | (32 | )% | ||||
| Natural gas liquids ($/bbl) | 26.25 | 60.61 | (57 | )% | ||||
| Oil ($/bbl)(6) | 72.54 | 79.68 | (9 | )% | ||||
| Operating expenses ($/boe) | 6.99 | 9.26 | (25 | )% | ||||
| General and administrative expenses ($/boe) | 1.10 | 1.16 | (5 | )% | ||||
| Cash costs ($/boe)(8) | 10.95 | 13.37 | (18 | )% | ||||
| Operating netback ($/boe)(9) | 15.42 | 27.01 | (43 | )% | ||||
| 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) 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. |
| Three months ended | ||||||||
| Share Trading Statistics | March 31, 2015 | December 31, 2014 | September 30, 2014 | June 30, 2014 | ||||
| ($ per share, except volume) | ||||||||
| High | 8.15 | 12.99 | 16.36 | 17.85 | ||||
| Low | 5.62 | 6.66 | 12.61 | 15.79 | ||||
| Close | 6.38 | 7.30 | 12.88 | 16.37 | ||||
| Average Daily Volume – Shares | 763,522 | 999,646 | 728,707 | 545,585 | ||||
MESSAGE TO SHAREHOLDERS
Our first quarter results demonstrate our commitment to enhance our capital and operating efficiencies through concentrated development in both our West Central and Deep Basin Core Areas. We exceeded our production guidance resulting in average first quarter production of 85,017 boe per day, a 15% (seven percent per share) increase over the same period in 2014. More importantly, our costs to add and operate this production continue to decline with our trailing twelve month capital efficiencies improving by 20% relative to the same period a year ago and a 25% reduction in our first quarter operating costs to $6.99 per boe relative to the same period in 2014.
Capital spending, including acquisitions and divestitures (“A&D”) in the first quarter totaled $102.3 million, 14% below budget. E&D expenditures were $112.0 million resulting in the drilling of 29 (14.1 net) wells, of which 93% were in our two key plays, the Glauconite and Spirit River formations. We have experienced significant cost reductions which, when coupled with predictable well performance, generate solid internal rates of return (“IRR”) of 27% using forward strip pricing at April 28, 2015 for natural gas and WTI oil. Accordingly, we anticipate a similar concentration of capital spending towards these two plays for the remainder of the year.
Throughout the second quarter, production will be materially impacted by turnaround activity and delays in third-party facility modifications. Current production is approximately 64,000 boe per day, with approximately 18,000 boe per day curtailed due to turnaround activity. This activity will result in second quarter volumes averaging between 70,000 and 74,000 boe per day. Production at full capacity should resume by the end of July. Despite these production interruptions, we are maintaining our production guidance of between 80,000 and 82,000 boe per day in 2015 while spending between $300 and $320 million. This capital budget is designed to balance total spending, including dividends, with our funds from operations. Balance sheet flexibility through non-core asset divestitures and continuous improvement in capital and operating efficiency will remain our priority.
Operational and financial accomplishments for the first quarter of 2015 include:
2015 FIRST QUARTER CORE AREA HIGHLIGHTS
WEST CENTRAL CORE AREA
Our West Central core area is characterized by liquids-rich natural gas and light oil resources in multiple prospective horizons with year round access. It includes extensive infrastructure with over 2,800 kilometers of pipelines and 38 facilities, the majority of which are operated by Bonavista. In this core area, we have access to approximately 1.3 million acres, and have identified approximately 800 drilling locations. This represents a drilling inventory in excess of 14 years, given our current development pace of drilling 50 to 60 locations per year.
In the first quarter, we spent $48.5 million on E&D activities in this core area, drilling 18 (13.2 net) horizontal wells. Our 2015 plan is to spend $176 million on E&D activities drilling 56 (46.4 net) horizontal wells.
Production during the first quarter averaged 50,131 boe per day representing a 19% increase over the same period in 2014. This production growth was achieved by spending only 91% of the cash flow generated from this core area. Our drilling results in the first quarter continue to meet our expectations and solidifies the confidence we have in this play. Our Hoadley Glauconite play continues to be our foundation of development representing approximately 80% of the E&D expenditures forecasted in this core area for 2015.
Glauconite Natural Gas
During the quarter Bonavista drilled 16 (11.2 net) horizontal wells, supporting production levels of approximately 24,500 boe per day. This equates to production growth of 41% over the same period last year. Our operating costs for the Glauconite play remain competitive at approximately $4.00 per boe.
Well economics remain strong, driven in part to a reduction in drilling and completion costs. Relative to the same period in 2014, the average cost to drill, complete and equip a standard Glauconite well improved approximately nine percent this quarter to $2.8 million. With these lower capital costs and an efficient operating cost structure, single well economics generate a 26% IRR at $2.50 per gj at AECO for natural gas and WTI of US$60.00 per bbl. The Glauconite is capable of generating positive returns even with commodity prices near their lowest levels in the past decade, a testament to its economic resilience in a volatile commodity price environment.
Bonavista drilled two extended reach horizontal wells in the Strachan area during the quarter with the first well performing above expectations with current production in excess of 900 boe per day after two months on-stream. The second well is awaiting completion results. We have drilled 14 extended reach horizontal wells to date showing 13% to 15% efficiency improvements. We plan to drill an additional six extended reach wells in 2015.
Being the most active operator in the Glauconite, with inventory of approximately 400 locations and strong economics even in this price environment, the Glauconite will continue to serve as the foundation of our development program. As such, we plan to drill 46 (36.4 net) wells in 2015.
Spirit River Falher Natural Gas
Our Falher play at Morningside continues to deliver top-quartile economics with prolific production performance and on-stream costs decreasing by 10% to approximately $2.5 million per well. At AECO pricing of $2.50 per gj for natural gas and a WTI price of US$60.00 per bbl, the Falher generates an impressive IRR of approximately 39%. Consequently, we plan to drill an additional six (6.0 net) Falher wells in 2015, five of which will be at Morningside.
Following up on a successful 2014 program, we drilled two (2.0 net) wells in the northern portion of our Falher at Morningside in the first quarter of 2015. The results from these wells were effective at extending the boundaries of our Falher trend resulting in additional drilling locations being added to our inventory.
First quarter Falher production was approximately 3,100 boe per day, inclusive of natural gas liquids yields of approximately 50 bbls per mmcf.
DEEP BASIN CORE AREA
Our Deep Basin core area contains multiple vertically stacked oil and natural gas reservoirs in a concentrated region, proximate to infrastructure and associated services. We have assembled approximately 340,000 net acres and identified 360 horizontal drilling locations.
In the first quarter, we spent $56.0 million on E&D activities, which included drilling 11 (10.9 net) horizontal wells. Production in this core area averaged 23,864 boe per day, a 49% increase from the prior year period. Our 2015 plan contemplates E&D spending of $98.0 million drilling 19 (18.9 net) horizontal wells and $16 million on infrastructure.
The majority of our Deep Basin activity is focused on the Wilrich play at Ansell where 90% of first quarter Deep Basin spending was concentrated. We remain on schedule with the installation of additional processing infrastructure in the second half of 2015, and have secured incremental egress for our production.
Spirit River Natural Gas
First quarter Spirit River activity was dominated by our Wilrich program at Ansell where we drilled eight (8.0 net) wells. Well costs have improved 20% at Ansell compared to the same period in 2014, resulting in drilling and completion costs of $4.5 million per well.
The continued success at Ansell and Marlboro have resulted in record quarterly Wilrich production of approximately 12,700 boe per day. The economics of our Wilrich play at Ansell compete with our flagship Glauconite play as evidenced by an IRR of 24% at an AECO natural gas price of $2.50 per gj and WTI of US$60.00 per bbl. In the second half of 2015, we expect to complete the installation of our processing facility and our meter station providing us with independent processing capability and incremental egress which should result in a 25-30% reduction to our operating costs. As such, we plan on allocating 83% ($42 million) of our second half 2015 Deep Basin capital expenditures, drilling an additional 8 (8.0 net) wells in the second half of the year.
BLUEBERRY – MONTNEY
Our 2015 drilling program involves drilling one (1.0 net) well at Blueberry during the second half of the year. Our Montney play remains an important element of our five year business plan.
STRENGTHS OF BONAVISTA ENERGY CORPORATION
Throughout our eighteen year history, from an initial restructuring in 1997 to create a high growth junior exploration company, through the energy trust phase between July 2003 and December 2010, and since January 2011 as a dividend paying corporation, Bonavista has remained committed to the same operating philosophies despite the endless commodity price volatility and uncertainty inherent in the energy sector. We have consistently maintained a high level of investment activity on our asset base resulting in 150% growth in current corporate production since converting to an energy trust in July 2003. These results stem from the expertise of our people and their entrepreneurial approach to consistently generating profitable development projects in an unpredictable commodity price environment. Our experienced technical teams have a thorough understanding of our assets and the reservoirs within the Western Canadian Sedimentary Basin as they exercise the discipline and commitment required to deliver long-term value to our shareholders. The core operating and financial principles that guide our people have been with our organization from the beginning and remain solidly intact today.
Our production is approximately 72% weighted towards natural gas and is largely concentrated in two core areas in central Alberta. We actively participate in undeveloped land purchases, property acquisitions and farm-in opportunities in these areas, which have all enhanced the quantity and quality of our extensive drilling inventory. Specifically over the past five years, technology coupled with North American natural gas supply/demand fundamentals has led to numerous opportunities to reposition the asset portfolio and drastically improve the quality of our development projects. These activities have led to low cost reserve additions and a reliable production base that continues to grow at a steady pace. Today, the predictable production performance and 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.
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 11% of the equity of Bonavista, aligning our interests with those of external shareholders.
OUTLOOK
North American natural gas markets have now entered the shoulder season with the uncertainty of summer demand placing further pressure on pricing. Supply has continued to show resilience, in spite of the sharp decline in the US natural gas rig count since the beginning of the year. Although lower prices have resulted in increased natural gas demand for electricity generation, this North American supply resilience will continue to burden short-term pricing.
As volatility in our commodities continue, we remain focused on improving our capital and operating efficiencies, enabling our assets to compete profitably in this low price environment. We believe that these initiatives will continue to create shareholder value despite the current commodity price environments as we remain committed to our sustainable business plan. Our 2015 capital budget, derived from our aspirations to balance capital spending with our funds from operations, remains between $300 and $320 million, drilling between 70 (61.0 net) and 80 (69.8 net) wells. We are maintaining our annual production guidance of between 80,000 and 82,000 boe per day despite significant production curtailments due to turnaround activity in the second quarter.
As a result of lower industry utilization levels, we have realized capital cost reductions of approximately 10% to date in 2015. Continued under-utilization of services within western Canada may lead to further cost reductions, incrementally enhancing the economics of our development plans. At this time though, our forecasted 2015 capital budget is representative of the 10% reduction that we have realized to date.
We remain in a favourable hedging position whereby approximately 65% and 40% of our budgeted volumes net of royalties are hedged for 2015 and 2016 respectively. In addition, we continue to target and add incremental hedges for 2016 and beyond to provide revenue stability and mitigate future commodity price fluctuations.
As part of our management succession program, we are pleased to announce the following three leadership appointments, effective May 8, 2015:
Mr. Dean Kobelka has been promoted to the position of Vice President, Finance and Chief Financial Officer. Mr. Kobelka joined Bonavista in 2000 and has taken on positions of increasing responsibility leading to his current position as Vice President, Finance. Mr. Kobelka, a Certified General Accountant and a Chartered Financial Analyst charterholder, has been a member of our leadership team over the past seven years, working under the direct mentorship of Mr. Glenn Hamilton currently our Senior Vice President and Chief Financial Officer. We are pleased to have Mr. Hamilton continue with Bonavista as a corporate advisor to senior management, while remaining very involved in investor relations.
Mr. Scott Shimek has been promoted to the position of Vice President, Operations. Mr. Shimek joined Bonavista in 2007 and has taken on positions of increasing responsibility leading to his current role as Director, Drilling and Environment. Mr. Shimek is a Professional Engineer and has played an integral role in our Production and Development departments and most recently in our Operations department, working under the direct supervision of Mr. Hank Spence currently our Vice President, Operations. We are grateful to have Mr. Spence continue with Bonavista advising in our Safety and Facilities disciplines.
Mr. Scott Wilhelm has been promoted to the position of Vice President, Engineering. Mr. Wilhelm, a Professional Engineer, joined Bonavista in 2009 and has assumed incremental responsibilities since that time with his most recent position being Manager, Development Engineering. Mr. Wilhelm will assume these new responsibilities as part of the succession from the promotion of Mr. Bruce Jensen to Chief Operating Officer.
We would like to thank our employees for their commitment to consistently finding a better way, our directors for their guidance, and our shareholders for their on-going support. We are confident in the quality of our assets and our ability to execute our strategy as we move forward in this environment.
[expand title=”Advisories & Contact”]FORWARD LOOKING INFORMATION
Corporate information provided herein contains forward-looking information. The reader is cautioned that assumptions used in the preparation of such information, particularly those pertaining to cash dividends, production volumes, commodity prices, operating costs and drilling results, which are considered reasonable by Bonavista at the time of preparation, may be proven to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein and the variations may be material. There is no representation by Bonavista that actual results achieved during the forecast period will be the same in whole or in part as those forecast.
Bonavista is a mid-sized energy corporation committed to maintaining its emphasis on operating high quality oil and natural gas properties, providing moderate growth and delivering consistent dividends to its shareholders and ensuring financial strength and sustainability.[/expand]