CALGARY, ALBERTA–(Marketwired – Nov. 5, 2015) – Bonavista Energy Corporation (“Bonavista”) (TSX:BNP) is pleased to report to shareholders its financial and operating results for the three and nine months ended September 30, 2015. Third quarter highlights demonstrate continued improvements in efficiency with production of 78,599 boe per day, funds from operations of $96.4 million ($0.44 per share) and operating costs of $6.52 per boe. Consistent with our commitment to sustainability, we have adjusted our dividend to $0.01 per common share to re-balance our dividend and capital programs with our funds from operation to maintain a total payout ratio less than 100%. The unaudited financial statements and notes, as well as management’s discussion and analysis, are available on the System for Electronic Document Analysis and Retrieval (“SEDAR”) at http://www.sedar.com and on Bonavista’s website at www.bonavistaenergy.com.
|Three months ended September 30,||Nine months ended September 30,|
|2015||2014||% Change||2015||2014||% Change|
|($ thousands, except per share)|
|Funds from operations(1)||96,407||129,074||(25||)%||289,559||425,260||(32||)%|
|Per share(1) (2)||0.44||0.60||(27||)%||1.33||2.06||(35||)%|
|Net income (loss)||(216,187||)||24,186||(994||)%||(296,929||)||65,825||(551||)%|
|Adjusted net income (loss)(4)||(203,707||)||(13,398||)||1,420||%||(252,841||)||63,087||(501||)%|
|Long-term debt, net of working capital||1,243,576||1,176,090||6||%|
|Long-term debt, net of adjusted working capital(5)||1,305,362||1,134,110||15||%|
|Exploration and development||88,016||178,904||(51||)%||257,821||477,405||(46||)%|
|Dispositions, net of acquisitions||(9,084||)||132,260||(107||)%||(25,012||)||(18,909||)||32||%|
|Weighted average outstanding equivalent shares: (thousands)(3)|
|(boe conversion – 6:1 basis)|
|Natural gas (mmcf/day)||324||310||5||%||341||299||14||%|
|Natural gas liquids (bbls/day)||19,597||15,267||28||%||16,609||15,227||9||%|
|Total oil equivalent (boe/day)||78,599||74,720||5||%||79,094||74,313||6||%|
|Natural gas ($/mcf)||3.76||4.00||(6||)%||3.60||4.44||(19||)%|
|Natural gas liquids ($/bbl)||19.71||50.87||(61||)%||24.76||54.71||(55||)%|
|Operating expenses ($/boe)||6.52||8.21||(21||)%||6.85||8.59||(20||)%|
|General and administrative expenses ($/boe)||1.21||1.19||2||%||1.18||1.18||–||%|
|Cash costs ($/boe)(8)||10.75||12.28||(12||)%||11.00||12.68||(13||)%|
|Operating netback ($/boe)(9)||16.32||21.54||(24||)%||16.28||23.76||(31||)%|
- 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|
|September 30, 2015||June 30, 2015||March 31, 2015||December 31, 2014|
|($ per share, except volume)|
|Average Daily Volume – Shares||1,047,494||1,050,652||763,522||999,646|
MESSAGE TO SHAREHOLDERS
Continued emphasis on both capital and operating efficiencies throughout the third quarter resulted in further improvements to our cost structure. Third quarter capital expenditures were $78.9 million, 25% below budget while funds from operations surpassed our forecast by 10% at $96.4 million ($0.44 per share).
Production has exceeded our budget for the third quarter at 78,599 boe per day, a five percent increase from 74,720 boe per day in the same period in 2014. Similarly, in the first nine months of 2015, production grew by six percent to 79,094 boe per day compared to the same period in 2014. Third quarter operating costs improved by 21% to $6.52 per boe when compared to $8.21 per boe in the same 2014 period. Cash costs improved by 12% to $10.75 per boe when compared to $12.28 per boe in the same in 2014. The operating and cash cost improvements demonstrate our emphasis on finding cost reductions and realizing capital efficiencies.
These improvements in efficiency have led to a five percent reduction in our forecasted capital expenditure program for 2015 to approximately $295 million. When combined with our dividend commitment, this capital program will result in modest annual production growth of three percent at a total payout ratio of 97%. We anticipate production will average between 79,000 and 80,000 boe per day, which incorporates production curtailment, weather delays and uneconomic production. This will in turn generate funds from operations between $375 and $385 million.
Operational and financial accomplishments for the third quarter of 2015 include:
- Spent $78.9 million on our capital program, a 75% reduction relative to the same period in 2014. Exploration and development (“E&D”) activities totaled $88.0 million, drilling 24 successful (22.2 net) wells. Dispositions, net of acquisitions were approximately $9.1 million;
- Produced 78,599 boe per day, a five percent increase when compared to the same period in 2014. Production in the first nine months of 2015 increased six percent to 79,094 boe per day relative to the same period in 2014;
- Generated funds from operations of $96.4 million ($0.44 per share), a 25% reduction when compared to the third quarter of 2014, notwithstanding a 46% reduction in commodity prices over the same period;
- Reduced third quarter operating costs to $6.52 per boe, a 21% reduction when compared to $8.21 per boe in the same period in 2014;
- Improved third quarter cash costs by 12% to $10.75 per boe relative to $12.28 per boe in the same period in 2014;
- Extended our existing bank credit facility of $600 million to a maturity date of September 10, 2019; and
- Expanded our commodity hedge portfolio resulting in:
- Approximately 236,000 gjs per day of natural gas hedged at an average floor price of $3.59 per gj at AECO for the remainder of 2015 and approximately 180,000 gjs per day at an average floor price of $3.35 per gj at AECO for 2016;
- Approximately 5,500 bbls per day of oil hedged at an average floor price of CDN$91.59 per bbl WTI for the remainder of 2015 and approximately 2,300 bbls per day at an average floor price of CDN$80.78 per bbl WTI for 2016; and
- Approximately 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 the fourth quarter of 2015, we have approximately 74% of our forecasted revenues (net of royalties) and 60% of our budgeted volumes (net of royalties) hedged.
- For 2016, we currently have 50% of our forecasted revenues (net of royalties) and 41% of our budgeted volumes (net of royalties) hedged.
These accomplishments have been achieved through prudent management of our asset portfolio and is based on balancing our funds from operations with our dividend and capital programs. This approach has resulted in a total payout ratio of 103% for the first nine months of 2015 and is forecasted to be approximately 97% for 2015.
Our realized revenues have been largely sheltered from the erosion in commodity prices in 2015. At current prices, 2016 revenues are forecasted to decrease by $3.00 to $3.50 per boe relative to 2015, notwithstanding 41% of our volumes hedged.
As a result, the range for our capital expenditure budget for 2016 has been set to $210 and $240 million. In addition, our Board of Directors has approved an adjustment to our monthly dividend to $0.01 per common share from $0.035 per common share, beginning with our dividend payable December 2015. This proposed capital spending program coupled with our reduced dividend demonstrates our commitment to balance these expenditures with our forecasted funds from operations.
We are targeting a total payout ratio of between 85% and 95% for 2016. This capital and dividend budget will result in a reduction of our long-term debt, which when coupled with our commitment to rationalize our non-core assets, will enhance the sustainability of our asset portfolio and strengthen our financial position.
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.
In the first nine months of 2015, our E&D spending in this core area totaled approximately $146.3 million, drilling 49 (41.2 net) wells. Specific to sustainability, production has been maintained at approximately 48,000 boe per day while spending only 75% our forecasted annual cash flow for 2015. Our Glauconite play has been the foundation of this sustainability, while the future potential of our Falher play continues to impress.
For the remainder of the year, we plan to drill seven (7.0 net) horizontal wells, of which two will target our Falher play.
Glauconite Natural Gas
We drilled 14 (12.2 net) horizontal wells this quarter, 13 at Hoadley and one at Strachan. Over the first nine months of 2015, we drilled 42 (34.2 net) horizontal wells. The deep cut facility at Rimbey was commissioned over the third quarter improving the recovery of natural gas liquids. As the facility operation is optimized throughout the fourth quarter, we anticipate recoveries to approach 100 bbls of natural gas liquids per mmcf of natural gas resulting in a 40% improvement over prior recoveries and modestly improving our Glauconite economics under current stressed liquids pricing.
Our capital cost structure continued to improve, with the cost to drill and complete a “typical” Glauconite well improving by approximately 25% to $2.3 million as compared to the same period in 2014, while operating costs have remained competitive at $4.50 per boe in our Hoadley area. Reduced costs and enhanced execution has resulted in capital efficiencies of approximately $10,500 per boe per day, based on a 12 month production profile, a 15% improvement relative to the same period last year. The Glauconite continues to be a resilient performer in this challenging commodity price environment.
At Strachan, we drilled one (1.0 net) extended reach well which is currently producing at a 30 day average rate of approximately 830 boe per day.
Current Glauconite production is approximately 26,500 boe per day, which is slightly higher compared to the same period in 2014 despite drilling 29% fewer wells, demonstrating the reliability of this play.
The Glauconite play continues to showcase consistent results with resilient economics that rank amongst the top liquids rich natural gas plays in North America. Our inventory of approximately 380 locations allows for over eight years of development at our current pace. Our 2015 program will conclude with an additional three (3.0 net) Glauconite wells in the fourth quarter.
Spirit River Falher Natural Gas
We drilled three (3.0 net) Falher wells in the third quarter. Our most recent Falher well at Strachan tested at a restricted rate of 3.5 mmcf per day and will be tied-in during the fourth quarter. At Morningside, we drilled one (1.0 net) well to follow up our successful second quarter program. This exceptional well has been on production for three months at an average rate of 1,200 boe per day. Our 2015 Morningside Falher program has been very successful with the five wells drilled demonstrating an average three month rate of 725 boe per day, 30% above our type curve.
With the commissioning of the deep cut facility at Rimbey, natural gas yields have increased by 50% to approximately 75 bbls per mmcf. Current Falher production is approximately 3,600 boe per day.
At current costs to drill and complete of $2.0 million, annual production addition costs remain less than $10,000 per boe, based on a 12 month production profile.
Our 2015 Falher program will be completed with two (2.0 net) additional wells in the fourth quarter.
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.
During the first nine months of the year we spent $89.9 million on E&D activities drilling 17 (16.9 net) wells. Production has averaged approximately 22,000 boe per day representing a 36% increase from the same period last year despite drilling 19% fewer wells. Our 2015 Deep Basin program will conclude with drilling an additional two (2.0 net) horizontal wells and completing and tying in five wells from our third quarter program.
Spirit River Wilrich Natural Gas
We commissioned our new processing facility and metering station at Ansell in the third quarter. This operated processing capability and incremental egress will result in a 30% reduction in operating costs. The full impact of these operating cost reductions will be realized in 2016.
We drilled six (6.0 net) Wilrich wells in the third quarter. The average cost to drill, complete and equip these wells was $4.2 million, representing an improvement of approximately 25% from the third quarter of 2014. The cost reductions have had a substantial impact on the internal rate of return (“IRR”) increasing by approximately 15% when compared to 2014 assuming constant pricing. Capital efficiencies, based on a 12 month production profile, are currently $10,600 per boe per day, a 28% reduction from the same period in 2014.
During the fourth quarter, we will drill our first two extended reach (1.5 mile lateral length) horizontal wells at Ansell. We anticipate further economic enhancements driven by improved capital and operating efficiencies as we develop our extended reach program.
BLUEBERRY – MONTNEY
We drilled one (1.0 net) horizontal well at Blueberry. Enhanced stimulation techniques resulted in a final restricted rate of 600 bbls per day of free condensate and three mmcf per day of natural gas. This encouraging result promotes a $3.3 million infrastructure commitment made in the first quarter of 2016 and continues to reaffirm the value of this significant resource.
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. 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 central Alberta. We create opportunity through undeveloped land purchases, asset swaps, asset acquisitions and farm-in opportunities in these areas. Specifically, over the past five years, technology coupled with North American natural gas supply/demand fundamentals has led to numerous opportunities to reposition the asset portfolio and drastically improve the quality of our development projects. These activities have led to low cost reserve additions and a reliable production base 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.
The second half of 2015 has continued to be challenging for our industry. In the third quarter, crude oil prices averaged US$46.50 WTI, down 20% from the second quarter and NYMEX natural gas prices continued to be range bound, averaging $2.73 per mmbtu. These commodity prices have resulted in negative returns for most energy equities. During the winter season, weather related demand becomes the focus of North American natural gas markets. As warmer temperatures are predicated throughout North America this winter, demand for natural gas may be tempered. This uncertainty will continue to put pressure on North American natural gas markets as we have witnessed with NYMEX natural gas prices declining 25% from an October high of US$2.54 per mmbtu to a recent October low of US$2.03 per mmbtu.
Year-to-date, our industry has taken significant strides by reducing our costs as commodities prices have deteriorated. Unfortunately, with prices falling more dramatically than our costs, returns have been impacted such that profitable reinvestment in our resources in western Canada has become challenging.
We remain focused on total payout and sustainability, the development of our highest quality inventory and improving our financial position. These continued efficiency improvements have led to a forecasted capital expenditure program for 2015 of approximately $295 million, five percent below our previous budget. Incorporating production curtailments in the fourth quarter annual production is expected to be between 79,000 and 80,000 boe per day, generating about $375 to $385 million of funds from operations, for a total payout ratio of approximately 97% for 2015.
Our Board of Directors has approved a preliminary 2016 capital budget of between $210 and $240 million, drilling between 50 and 60 net wells, which is forecasted to generate production of between 76,000 and 79,000 boe per day. Continued focus on capital and operating efficiencies will remain a high priority for 2016. This budget will remain flexible as we assess uncertain commodity prices and any potential impact of the Alberta royalty review and any changes to climate policies. When coupled with our reduced dividend, this capital budget is designed to achieve a total payout ratio of between 85% and 95% for 2016. The remaining funds from operations will be used to strengthen our financial position.
We thank our employees for their dedication and commitment and our shareholders for their continued support. We remain confident of our strategies in the current environment and have a quality asset base that will provide profitable development and long-term value creation.
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 dividend paying energy corporation focused on the efficient development of high quality oil and natural gas assets while providing sustainable value to shareholders.
Bonavista Energy Corporation
Keith A. MacPhail
Jason E. Skehar
President & CEO
Dean M. Kobelka
Vice President, Finance & CFO