CALGARY, ALBERTA–(Marketwired – July 30, 2015) – Bonavista Energy Corporation (“Bonavista”) (TSX:BNP) is pleased to report to shareholders its financial and operating results for the three and six months ended June 30, 2015. Exceeding the mid-point of our guidance, second quarter production averaged 73,736 boe per day and funds from operations was $96.0 million ($0.44 per share), resulting in a 12% improvement in our corporate netback to $17.22 per boe relative to the first quarter of this year. Continued improvement in efficiencies translated to a 15% reduction in operating costs and a 9% reduction in cash costs compared to the same period in 2014. The unaudited financial statements and notes, as well as management’s discussion and analysis, are available on the System for Electronic Document Analysis and Retrieval (“SEDAR”) at http://www.sedar.com and on Bonavista’s website at www.bonavistaenergy.com.
|Three months ended June 30,||Six months ended June 30,|
|2015||2014||% Change||2015||2014||% Change|
|($ thousands, except per share)|
|Funds from operations(1)||96,004||135,392||(29)%||193,152||296,186||(35)%|
|Per share(1) (2)||0.44||0.67||(34)%||0.89||1.47||(39)%|
|Net income (loss)||(1,882||)||86,576||(102)%||(80,742||)||41,639||(294)%|
|Adjusted net income (loss)(4)||21,487||55,706||(61)%||(49,134||)||76,485||(164)%|
|Long-term debt, net of working capital||1,158,488||1,126,873||3%|
|Long-term debt, net of adjusted working capital(5)||1,233,409||1,050,140||17%|
|Exploration and development||57,854||121,866||(53)%||169,805||298,501||(43)%|
|Dispositions, net of acquisitions||(6,271||)||(51,701||)||(88)%||(15,928||)||(151,169||)||(89)%|
|Weighted average outstanding equivalent shares: (thousands)(3)|
|(boe conversion – 6:1 basis)|
|Natural gas (mmcf/day)||332||300||11%||350||293||19%|
|Natural gas liquids (bbls/day)||13,133||15,349||(14)%||15,090||15,207||(1)%|
|Total oil equivalent (boe/day)||73,736||74,273||(1)%||79,345||74,105||7%|
|Natural gas ($/mcf)||3.61||4.29||(16)%||3.53||4.67||(24)%|
|Natural gas liquids ($/bbl)||30.48||52.85||(42)%||28.10||56.67||(50)%|
|Operating expenses ($/boe)||7.05||8.31||(15)%||7.02||8.78||(20)%|
|General and administrative expenses ($/boe)||1.22||1.19||3%||1.16||1.18||(2)%|
|Cash costs ($/boe)(8)||11.32||12.38||(9)%||11.12||12.88||(14)%|
|Operating netback ($/boe)(9)||17.22||22.83||(25)%||16.26||24.90||(35)%|
- 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.
- Basic funds from operations per share calculations include exchangeable shares which are convertible into common shares on certain terms and conditions.
- Basic net income (loss) per share calculations include exchangeable shares which are convertible into common shares on certain terms and conditions.
- Amounts have been adjusted to exclude unrealized gains and losses on financial instrument commodity contracts, net of tax.
- Amounts have been adjusted to exclude associated assets or liabilities from financial instrument commodity contracts and decommissioning liabilities.
- Oil includes light, medium and heavy oil.
- Product prices include realized gains and losses on financial instrument commodity contracts.
- Cash costs equal the total of operating, transportation, general and administrative, and financing expenses.
- 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||1,050,652||763,522||999,646||728,707|
Continued improvements in both capital and operating efficiencies have led to another successful quarter characterized by prudent production management and a focused development program. Funds from operations and production have both exceeded our forecasts while both capital and operating costs were below budget.
Funds from operations of $96.0 million ($0.44 per share) in the second quarter have resulted in a 12% improvement in our corporate netback to $17.22 per boe relative to the first quarter of this year. Second quarter production of 73,736 boe per day exceeded the mid-point of our guidance and was consistent with the same period last year, despite significant production curtailments throughout the quarter. Non-operated facility turnarounds and delays on facility modifications that took place throughout the quarter have resulted in nearly 7,000 boe per day of lost production. These infrastructure events have extended beyond our original forecast and as such, will impact our production performance in the third quarter. Current production is approximately 78,000 boe per day, with approximately 2,000 boe per day of remaining curtailment.
Capital spending, including acquisitions and divestitures (“A&D”), came in under budget at $51.6 million in the second quarter representing a 26% reduction from the same period in 2014. In addition, operating and cash costs continue to show steady improvement in the second quarter, when compared to the same period in 2014, resulting in a 15% reduction in operating costs to $7.05 per boe and a nine percent decrease in cash costs to $11.32 per boe. Year-to-date in 2015, we have experienced a 20% improvement in operating costs and a 14% improvement in cash costs per boe over the same period in 2014.
Sustainability remains our priority as evidenced by modest growth in average production of seven percent in the first six months of 2015 over 2014 while upholding a prudent total payout ratio of 102%. Given our success on this front, the remainder of 2015 will be characterized by focused capital spending on our highest return projects while pursuing non-core divestitures to reduce long-term debt.
Operational and financial accomplishments for the second quarter of 2015 include:
- Generated funds from operations of $96.0 million ($0.44 per share), in a period where realized commodity prices decreased 27% on a per boe basis and production revenues decreased 48% overall when compared to the same period in 2014;
- Produced 73,736 boe per day despite turnaround and modification activity in third-party facilities significantly impacting production. Production in the first half of 2015 has grown approximately seven percent relative to the same period in 2014;
- Executed a capital spending program (including A&D) of $51.6 million, a 26% reduction relative to the same period in 2014. E&D activities totaled $57.9 million, drilling 14 successful (12.8 net) wells, all in our Glauconite and Spirit River plays. The capital efficiency of our development program in the first half of 2015 has improved meaningfully with a 15% to 20% reduction in drilling costs and a 10% to15% reduction in completion costs when compared to the same period last year;
- Increased our land holdings prospective for Spirit River development by adding 25 net sections in Ansell through the swap of 17 net sections of low working interest, non-operated land in our Blueberry area;
- Reduced second quarter operating costs to $7.05 per boe and cash costs to $11.32 per boe, representing improvements of 15% and 9% respectively, over the same period in 2014; and
- Enhanced our commodity hedge portfolio resulting in:
- Approximately 253,000 gjs per day of natural gas hedged at an average floor price of $3.54 per gj at AECO for the remainder of 2015 and approximately 173,000 gjs per day at an average floor price of $3.36 per gj for 2016;
- Approximately 5,500 bbls per day of oil at an average floor price of CDN$91.59 per bbl WTI; and
- 2,500 bbls per day of propane hedged at 46% of US WTI pricing for 2015 and 1,375 bbls per day at 43% of US WTI pricing for 2016;
- Overall for 2015, Bonavista has approximately 73% of our forecasted revenues (net of royalties) and 66% of our budgeted volumes (net of royalties) hedged.
2015 YEAR-TO-DATE CORE AREA HIGHLIGHTS
WEST CENTRAL CORE AREA
Our West Central core area, with year round access, is characterized by liquids-rich natural gas and light oil resources in multiple prospective horizons. 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 in our key plays. This represents a drilling inventory in excess of 14 years, given our current pace of drilling 50 to 60 locations per year.
During the first half of 2015, our E&D spending in this core area totaled approximately $96.4 million, drilling 32 (25.2 net) wells. Despite a 41% reduction in spending and the impact of significant turnaround activity, West Central production has increased six percent relative to the same period in 2014 to 45,969 boe per day. Specific to the second quarter, 100% of our E&D program was in this core area with results continuing to meet our expectations. For the remainder of the year, we plan to spend $77.6 million on E&D activities drilling an additional 26 (20.7 net) horizontal wells, most of which will be allocated to our Glauconite play.
Glauconite Natural Gas
We drilled 12 (10.8 net) horizontal wells this quarter at Hoadley, bringing our total first half activity to 28 (21.2 net) horizontal wells. Production in the Glauconite was curtailed for the second quarter as a result of third-party turnaround activity. The commissioning of the deep cut facility at Rimbey remains ongoing and is expected to be completed by the beginning of August. Once fully operational, the deep cut infrastructure will enable the recovery of approximately 100 bbls of natural gas liquids per mmcf of natural gas, a 40% improvement over current recoveries, resulting in a modest improvement to our Glauconite economics. Current production is approximately 24,300 boe per day, representing a nine percent increase compared to the same period in 2014 despite drilling approximately seven percent fewer wells year-to-date.
Lower capital costs and an efficient operating cost structure remain the theme in the Glauconite trend. Drilling and completion costs have continued to improve, with the cost to drill, complete, equip and tie-in a “typical” Glauconite well improving by 16% to approximately $2.6 million as compared to the same period in 2014. Operating costs remain competitive at approximately $4.50 per boe. Collaboratively, this enhanced cost structure has offset the impact of falling commodity prices which supports the continued development of this play.
Bonavista’s extended reach horizontal well program continues to outperform our expectations. The two Strachan wells drilled in the first quarter of 2015 are currently producing at a combined rate of 1,300 boe per day after being on-stream for an average of 100 days. For the second half of the year we have one extended reach well planned at Strachan. Extended reach wells represent 22% of total wells in our 2015 Glauconite program.
The Glauconite play continues to showcase reliable, consistent results with resilient economics that rank amongst the top liquids rich natural gas plays in North America. Our inventory of approximately 400 locations allows for over eight years of development at our current pace. We plan on supporting our first half Glauconite program with an additional 21 (15.7 net) wells during the second half of 2015.
Spirit River Falher Natural Gas
We drilled 2 (2.0 net) additional Falher wells at Morningside in the second quarter of 2015, bringing our total activity to 4 (4.0 net) wells year-to-date. The second quarter wells are exceeding our expectations with a combined rate of approximately 2,350 boe per day for the first 30 days.
Current production at Morningside is approximately 4,000 boe per day, which includes natural gas yields of approximately 50 bbls per mmcf. Similar to the Glauconite, we expect natural gas liquids yields to increase by 50% once the deep cut facility at Rimbey is commissioned.
With a competitive drill, complete, equip and tie-in cost of $2.4 million per well, annual production addition costs are expected to cost less than $10,000 per boe per day in 2015, based on a 12 month production profile. The Morningside Falher play is an exciting addition to our development portfolio and we expect to expand our inventory with continued development of our acreage.
We plan on drilling five (5.0 net) additional wells in the second half of the year.
DEEP BASIN CORE AREA
Our Deep Basin core area contains multiple oil and natural gas reservoirs in a concentrated region, proximate to infrastructure and associated services. Over the past five years, we have assembled access to approximately 460,000 acres and identified 360 horizontal drilling locations.
Similar to prior years, seasonality has curtailed all of our capital activity in this core area in the second quarter. In the first half of 2015, we spent $63.3 million on E&D activities drilling 11 (10.9 net) wells supporting production rates averaging 23,335 boe per day in the area, a 43% increase from the prior year period. For the remainder of the year, we plan to spend $49.5 million on E&D activities drilling an additional eight (8.0 net) horizontal wells including eight million on additional processing infrastructure. We remain on schedule with this installation and have secured incremental egress for our production.
Spirit River Natural Gas
Commissioning of our new processing facility and metering station is expected in the fourth quarter of this year. This independent processing capability and incremental egress will result in a 25% to 30% reduction in operating costs which are currently between $4.00 per boe and $5.00 per boe. The full impact of these operating cost reductions will not be realized until 2016.
In the second half of the year, we will drill our first extended reach horizontal well at Ansell. With the experience gained from our extended reach program in the Glauconite, we anticipate improved capital and operating efficiencies leading to enhanced economics.
Throughout the first half of 2015 we added 36 net sections at Ansell through swap and acquisition transactions. We now have 91 net sections in Ansell with 150 to 200 locations in our prospect inventory. For the remainder of the year, we plan on allocating essentially all of our $49.5 million second half 2015 Deep Basin capital expenditures, including infrastructure expenditures of eight million, to the Ansell play, drilling an additional eight (8.0 net) wells.
BLUEBERRY – MONTNEY
During the quarter, we completed an asset swap by swapping 17 mainly low working interest, non-operated Montney net sections for 25 operated net sections in our Ansell Wilrich play.
We are currently drilling a horizontal Montney well at Blueberry, which we anticipate will be completed and tested by the end of the third quarter. We expect to drill an additional two wells by the end of 2016 to fulfill all land retention requirements. With large quantities of resource in place, continued positive industry results and its proximity for future LNG export facilities, our Montney play remains an important element of our five year business plan at this juncture.
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, 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 resulting in 116% 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 in the second quarter was 75% 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 10% of the equity of Bonavista, aligning our interests with those of external shareholders.
Uncertainty remains the dominant theme within the energy markets. Globally, geopolitical challenges continue to make headlines while the North American supply and demand imbalance persists as a result of increased output of oil and natural gas in the United States. Notwithstanding a reduction in rig count and an increase in weather related demand, indications point towards a continued abundance of both crude oil and natural gas inventories in North America. Closer to home, the recent change in the Alberta government has also added an element of uncertainty as it pertains to the energy business.
Having operated in this environment for many years, we are accustomed to the uncertainty inherent to our business and as a result, have positioned ourselves for success. To begin with, we are well-sheltered from continued commodity price erosion with 66% of our budgeted volumes net of royalties, hedged for the remainder of 2015 and 44% hedged for 2016. More importantly, over the past few years, we have been focusing our efforts on improving our capital and operating efficiencies by concentrating our asset base and continuously striving to find better ways to compete. Our efforts have led to steady improvements in our finding and development costs, a 50% reduction in our cost to add production and a reduction in our operating costs to their lowest level in over a decade. Inevitably, the most efficient operator will be the most profitable operator through these times of uncertainty.
We remain focused on balancing cash inflows with outflows for the remainder of 2015. Our capital budget, which is built on this philosophy of sustainability, remains between $300 and $320 million, drilling between 70 (60.4 net) and 80 (69.1 net) wells with production averaging between 80,000 and 82,000 boe per day.
We are thankful that we have employees that consistently strive to find a better way, our board of directors for their sage guidance and our shareholders for their trust and support. We remain confident in our strategy and our ability to adapt to continued uncertainty as we enhance our efficiencies to generate optimum returns for our shareholders.
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.
Bonavista Energy Corporation
Keith A. MacPhail
Jason E. Skehar
President & CEO
Dean M. Kobelka
Vice President, Finance & CFO